e10vq
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
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þ |
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended September 30, 2009
OR
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o |
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
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For the transition period from to |
Commission File Number: 000-50682
RAM Energy Resources, Inc.
(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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1311
(Primary Standard Industrial
Classification Code Number)
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20-0700684
(I.R.S. Employer Identification Number)
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5100 East Skelly Drive, Suite 650, Tulsa, OK 74135
(Address of principal executive offices)
(918) 663-2800
(Registrants telephone number, including area code)
(Former name, former address and former fiscal year, if changed since last report)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by
Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding twelve months (or
for such shorter period that the registrant was required to file such reports) and (2) has been
subject to such filing requirements for the past 90 days.
Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its
corporate Web site, if any, every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of Regulation S-T (232.405 of this chapter) during the preceding 12 months (or
for such shorter period that the registrant was required to submit and post such files).
Yes o No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated
filer, a non-accelerated filer, or a smaller reporting company. See the definitions of large
accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the
Exchange Act.
Large Accelerated Filer o |
Accelerated Filer þ |
Non-Accelerated Filer o (Do not check if a smaller reporting company) |
Smaller Reporting Company o |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Exchange Act).
Yes o No þ
At November 5, 2009, 76,865,587 shares of the Registrants Common Stock were outstanding.
Third Quarter 2009 Form 10-Q Report
TABLE OF CONTENTS
2
ITEM 1 FINANCIAL STATEMENTS
RAM Energy Resources, Inc.
Condensed Consolidated Balance Sheets
(in thousands, except share and per share amounts)
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September 30, |
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December 31, |
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2009 |
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2008 |
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(unaudited) |
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ASSETS |
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CURRENT ASSETS: |
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Cash and cash equivalents |
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$ |
116 |
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$ |
164 |
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Cash, restricted |
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- |
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16,000 |
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Accounts receivable: |
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Oil and natural gas sales, net of allowance of $50 ($50 at December 31, 2008) |
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11,141 |
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8,702 |
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Joint interest operations, net of allowance of $515 ($515 at December 31, 2008) |
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795 |
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818 |
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Other, net of allowance of $35 ($35 at December 31, 2008) |
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1,329 |
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4,045 |
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Derivative assets |
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1,012 |
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21,006 |
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Prepaid expenses |
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1,568 |
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2,330 |
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Deferred tax asset |
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3,705 |
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- |
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Other current contingencies |
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- |
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2,816 |
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Other current assets |
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4,083 |
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4,141 |
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Total current assets |
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23,749 |
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60,022 |
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PROPERTIES AND EQUIPMENT, AT COST: |
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Proved oil and natural gas properties and equipment, using full cost accounting |
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699,162 |
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683,341 |
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Other property and equipment |
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9,237 |
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9,460 |
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708,399 |
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692,801 |
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Less accumulated depreciation, amortization and impairment |
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(478,839 |
) |
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(396,301 |
) |
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Total properties and equipment |
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229,560 |
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296,500 |
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OTHER ASSETS: |
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Deferred tax asset |
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48,823 |
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28,724 |
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Derivative assets |
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- |
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4,531 |
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Deferred loan costs, net of accumulated amortization of $2,402 ($1,282 at December 31, 2008) |
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5,219 |
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4,015 |
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Other |
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1,969 |
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2,053 |
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Total assets |
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$ |
309,320 |
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$ |
395,845 |
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LIABILITIES AND STOCKHOLDERS EQUITY (DEFICIT) |
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CURRENT LIABILITIES: |
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Accounts payable: |
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Trade |
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$ |
13,390 |
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$ |
26,370 |
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Oil and natural gas proceeds due others |
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8,015 |
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7,218 |
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Other |
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27 |
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982 |
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Accrued liabilities: |
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Compensation |
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1,760 |
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2,893 |
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Interest |
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2,889 |
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865 |
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Franchise taxes |
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942 |
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1,300 |
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Income taxes |
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224 |
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399 |
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Contingencies |
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- |
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16,000 |
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Deferred income taxes |
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- |
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5,779 |
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Asset retirement obligations |
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1,043 |
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1,093 |
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Long-term debt due within one year |
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142 |
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160 |
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Total current liabilities |
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28,432 |
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63,059 |
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OIL & NATURAL GAS PROCEEDS DUE OTHERS |
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1,740 |
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2,523 |
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DERIVATIVE LIABILITIES |
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936 |
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- |
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LONG-TERM DEBT |
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250,285 |
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250,536 |
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ASSET RETIREMENT OBLIGATIONS |
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30,430 |
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29,106 |
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COMMITMENTS AND CONTINGENCIES |
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900 |
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900 |
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STOCKHOLDERS EQUITY (DEFICIT): |
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Common stock, $0.0001 par value, 100,000,000 shares authorized, 80,648,674 and 79,423,574, shares issued,
76,865,587 and 78,532,134 shares outstanding at September 30, 2009 and December 31, 2008, respectively |
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8 |
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8 |
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Additional paid-in capital |
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222,432 |
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220,800 |
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Treasury stock - 3,783,087 shares (891,440 shares at December 31,2008) at cost |
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(6,167 |
) |
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(4,027 |
) |
Accumulated deficit |
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(219,676 |
) |
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(167,060 |
) |
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Stockholders equity (deficit) |
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(3,403 |
) |
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49,721 |
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Total liabilities and stockholders equity (deficit) |
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$ |
309,320 |
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$ |
395,845 |
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The accompanying notes are an integral part of these condensed consolidated financial statements.
3
RAM Energy Resources, Inc.
Condensed Consolidated Statements of Operations
(in thousands, except share and per share amounts)
(unaudited)
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Three months ended September 30, |
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Nine months ended September 30, |
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2009 |
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2008 |
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2009 |
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2008 |
REVENUES AND OTHER OPERATING INCOME: |
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Oil and natural gas sales |
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Oil |
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$ |
18,276 |
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$ |
34,483 |
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$ |
45,740 |
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$ |
100,127 |
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Natural gas |
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4,607 |
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13,980 |
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15,564 |
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40,207 |
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NGLs |
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2,999 |
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5,729 |
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7,134 |
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14,945 |
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Realized gains (losses) on derivatives |
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483 |
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(5,054 |
) |
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19,032 |
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(14,590 |
) |
Unrealized gains (losses) on derivatives |
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(1,283 |
) |
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34,302 |
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(26,085 |
) |
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(4,765 |
) |
Other |
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49 |
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69 |
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177 |
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280 |
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Total revenues and other operating income |
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25,131 |
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83,509 |
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61,562 |
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136,204 |
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OPERATING EXPENSES: |
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Oil and natural gas production taxes |
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1,320 |
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3,070 |
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3,119 |
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8,840 |
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Oil and natural gas production expenses |
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9,772 |
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9,727 |
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28,976 |
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28,507 |
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Depreciation and amortization |
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7,304 |
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10,955 |
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23,808 |
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32,757 |
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Accretion expense |
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513 |
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552 |
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1,449 |
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1,630 |
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Impairment |
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- |
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- |
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58,929 |
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- |
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Share-based compensation |
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539 |
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602 |
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1,632 |
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2,081 |
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General and administrative, overhead and other expenses, net of
operators overhead fees |
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4,247 |
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4,962 |
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12,337 |
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16,018 |
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Total operating expenses |
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23,695 |
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29,868 |
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130,250 |
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89,833 |
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Operating income (loss) |
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1,436 |
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53,641 |
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(68,688 |
) |
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46,371 |
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OTHER INCOME (EXPENSE): |
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Interest expense |
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(5,561 |
) |
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(4,817 |
) |
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(12,770 |
) |
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(19,176 |
) |
Interest income |
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40 |
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38 |
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69 |
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|
186 |
|
Other income (expense) |
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10 |
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|
(6,733 |
) |
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(529 |
) |
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(7,087 |
) |
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EARNINGS (LOSS) BEFORE INCOME TAXES |
|
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(4,075 |
) |
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42,129 |
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|
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(81,918 |
) |
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20,294 |
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INCOME TAX PROVISION (BENEFIT) |
|
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(1,358 |
) |
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13,641 |
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(29,302 |
) |
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(1,809 |
) |
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Net earnings (loss) |
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$ |
(2,717 |
) |
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$ |
28,488 |
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$ |
(52,616 |
) |
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$ |
22,103 |
|
|
|
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BASIC EARNINGS (LOSS) PER SHARE |
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$ |
(0.04 |
) |
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$ |
0.37 |
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$ |
(0.70 |
) |
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$ |
0.32 |
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BASIC WEIGHTED AVERAGE SHARES OUTSTANDING |
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|
74,505,534 |
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|
76,972,191 |
|
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|
75,487,262 |
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68,482,312 |
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DILUTED EARNINGS (LOSS) PER SHARE |
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$ |
(0.04 |
) |
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$ |
0.37 |
|
|
$ |
(0.70 |
) |
|
$ |
0.32 |
|
|
|
|
|
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DILUTED WEIGHTED AVERAGE SHARES OUTSTANDING |
|
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74,505,534 |
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|
77,287,370 |
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|
|
75,487,262 |
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|
68,788,850 |
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|
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|
|
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The accompanying notes are an integral part of these condensed consolidated financial statements.
4
RAM Energy Resources, Inc.
Condensed Consolidated Statements of Cash Flows
(in thousands)
(unaudited)
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Nine months ended September 30, |
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2009 |
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2008 |
OPERATING ACTIVITIES: |
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Net income (loss) |
|
$ |
(52,616 |
) |
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$ |
22,103 |
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities- |
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Depreciation and amortization |
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|
23,808 |
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|
32,757 |
|
Amortization of deferred loan costs and Senior Notes discount |
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1,120 |
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|
|
899 |
|
Non-cash interest |
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|
829 |
|
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|
- |
|
Accretion expense |
|
|
1,449 |
|
|
|
1,630 |
|
Impairment |
|
|
58,929 |
|
|
|
- |
|
Unrealized loss on derivatives and premium amortization |
|
|
27,242 |
|
|
|
4,765 |
|
Deferred income tax benefit |
|
|
(29,583 |
) |
|
|
(1,880 |
) |
Share-based compensation |
|
|
1,632 |
|
|
|
2,081 |
|
Loss on disposal of other property, equipment and subsidiary |
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|
89 |
|
|
|
174 |
|
Other expense |
|
|
448 |
|
|
|
6,917 |
|
Changes in operating assets and liabilities |
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|
|
|
|
|
|
|
Accounts receivable |
|
|
166 |
|
|
|
(2,825 |
) |
Prepaid expenses and other assets |
|
|
1,137 |
|
|
|
(575 |
) |
Derivative premiums |
|
|
(1,781 |
) |
|
|
(1,704 |
) |
Accounts payable and proceeds due others |
|
|
(13,915 |
) |
|
|
6,753 |
|
Accrued liabilities and other |
|
|
(15,468 |
) |
|
|
(2,180 |
) |
Restricted cash |
|
|
16,000 |
|
|
|
- |
|
Income taxes payable |
|
|
(176 |
) |
|
|
(309 |
) |
Asset retirement obligations |
|
|
(287 |
) |
|
|
(354 |
) |
|
|
|
|
|
Total adjustments |
|
|
71,639 |
|
|
|
46,149 |
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
19,023 |
|
|
|
68,252 |
|
|
|
|
|
|
INVESTING ACTIVITIES: |
|
|
|
|
|
|
|
|
Payments for oil and natural gas properties and equipment |
|
|
(21,728 |
) |
|
|
(66,739 |
) |
Proceeds from sales of oil and natural gas properties |
|
|
6,156 |
|
|
|
886 |
|
Payments for other property and equipment |
|
|
(504 |
) |
|
|
(1,086 |
) |
Proceeds from sales of other property and equipment |
|
|
433 |
|
|
|
19 |
|
Proceeds from sale of subsidiary, net of cash |
|
|
- |
|
|
|
308 |
|
Other |
|
|
- |
|
|
|
149 |
|
|
|
|
|
|
Net cash used in investing activities |
|
|
(15,643 |
) |
|
|
(66,463 |
) |
|
|
|
|
|
FINANCING ACTIVITIES: |
|
|
|
|
|
|
|
|
Payments on long-term debt |
|
|
(24,120 |
) |
|
|
(158,234 |
) |
Proceeds from borrowings on long-term debt |
|
|
23,022 |
|
|
|
69,253 |
|
Payments for deferred loan costs |
|
|
(2,324 |
) |
|
|
(60 |
) |
Stock repurchased |
|
|
(6 |
) |
|
|
(76 |
) |
Warrants exercised |
|
|
- |
|
|
|
86,614 |
|
|
|
|
|
|
Net cash used in financing activities |
|
|
(3,428 |
) |
|
|
(2,503 |
) |
|
|
|
|
|
DECREASE IN CASH AND CASH EQUIVALENTS |
|
|
(48 |
) |
|
|
(714 |
) |
CASH AND CASH EQUIVALENTS, beginning of period |
|
|
164 |
|
|
|
6,873 |
|
|
|
|
|
|
CASH AND CASH EQUIVALENTS, end of period |
|
$ |
116 |
|
|
$ |
6,159 |
|
|
|
|
|
|
SUPPLEMENTAL CASH FLOW INFORMATION: |
|
|
|
|
|
|
|
|
Cash paid for income taxes |
|
$ |
457 |
|
|
$ |
380 |
|
|
|
|
|
|
Cash paid for interest |
|
$ |
9,011 |
|
|
$ |
20,994 |
|
|
|
|
|
|
DISCLOSURE OF NON CASH INVESTING AND FINANCING ACTIVITIES: |
|
|
|
|
|
|
|
|
Asset retirement obligations |
|
$ |
115 |
|
|
$ |
1,846 |
|
|
|
|
|
|
Payment-in-kind interest |
|
$ |
829 |
|
|
$ |
- |
|
|
|
|
|
|
The accompanying notes are an integral part of these condensed consolidated financial statements.
5
RAM Energy Resources, Inc.
Notes to unaudited condensed consolidated financial statements
|
|
|
A |
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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES, ORGANIZATION AND BASIS OF PRESENTATION |
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1. |
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Basis of Financial Statements |
The accompanying unaudited condensed consolidated financial statements present the financial
position at September 30, 2009 and December 31, 2008 and the results of operations and cash flows
for the three and nine month periods ended September 30, 2009 and 2008 of RAM Energy Resources,
Inc. and its subsidiaries (the Company). These condensed consolidated financial statements
include all adjustments, consisting of normal and recurring adjustments, which, in the opinion of
management, are necessary for a fair presentation of the financial position and the results of
operations for the indicated periods. The results of operations for the three and nine months ended
September 30, 2009 are not necessarily indicative of the results to be expected for the full year
ending December 31, 2009. Reference is made to the Companys consolidated financial statements for
the year ended December 31, 2008, for an expanded discussion of the Companys financial disclosures
and accounting policies.
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2. |
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Nature of Operations and Organization |
The Company operates exclusively in the upstream segment of the oil and gas industry with
activities including the drilling, completion, and operation of oil and gas wells. The Company
conducts the majority of its operations in the states of Texas, Louisiana, Oklahoma, and West
Virginia.
The preparation of financial statements in conformity with accounting principles,
generally accepted in the United States of America, requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent
assets and liabilities at the date of the financial statements and the reported amounts of revenues
and expenses during the reporting period. Actual results could differ from those estimates.
Estimates and assumptions that, in the opinion of management of the Company, are significant
include oil and natural gas reserves, amortization relating to oil and natural gas properties,
asset retirement obligations, contingent litigation settlements, derivative instrument valuations
and income taxes. The Company evaluates its estimates and assumptions on a regular basis. Estimates
are based on historical experience and various other assumptions that are believed to be reasonable
under the circumstances, the results of which form the basis for making judgments about the
carrying values of assets and liabilities that are not readily apparent from other sources. Actual
results may differ from these estimates used in preparation of the Companys financial statements.
In addition, alternatives can exist among various accounting methods. In such cases, the choice of
accounting method can have a significant impact on reported amounts.
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4. |
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Earnings (loss) per Common Share |
Basic earnings (loss) per share are computed by dividing net income or loss by the
weighted average number of common shares outstanding for the period. Diluted earnings (loss) per
share reflect the potential dilution that could occur if unvested restricted stock awards became
totally vested, calculated using the treasury stock method. Potential common shares in the diluted
loss per share are excluded for the periods presented as their effect would be anti-dilutive. A
reconciliation of net income (loss) and weighted average shares used in computing basic and diluted
net income (loss) per share is as follows for the three and nine months ended September 30 (in
thousands, except share and per share amounts):
6
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Three months ended September 30, |
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Nine months ended September 30, |
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2009 |
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2008 |
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2009 |
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2008 |
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Net income (loss) |
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$ |
(2,717 |
) |
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$ |
28,488 |
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$ |
(52,616 |
) |
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$ |
22,103 |
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Weighted average shares - basic |
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74,505,534 |
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76,972,191 |
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75,487,262 |
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68,482,312 |
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Dilutive effect of unvested stock grants |
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- |
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315,179 |
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- |
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306,538 |
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Weighted average shares dilutive |
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74,505,534 |
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77,287,370 |
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75,487,262 |
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68,788,850 |
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Basic earnings (loss) per share |
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$ |
(0.04 |
) |
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$ |
0.37 |
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$ |
(0.70 |
) |
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$ |
0.32 |
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Diluted earnings (loss) per share |
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$ |
(0.04 |
) |
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$ |
0.37 |
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$ |
(0.70 |
) |
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$ |
0.32 |
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The Company evaluates events and transactions that occur after the balance sheet date but
before the financial statements are issued. The Company evaluated such events and transactions
through November 5, 2009 when the financial statements were filed electronically with the
Securities and Exchange Commission.
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6. |
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New Accounting Pronouncements |
In June 2009, the Financial Accounting Standards Board (the FASB) implemented the
Accounting Standards Codification TM (the Codification) establishing the Codification as
the single official source of authoritative accounting principles recognized by the FASB to be
applied by nongovernmental entities in the preparation of financial statements in conformity with
generally accepted accounting principles (GAAP), other than guidance issued by the Securities and
Exchange Commission. The Codification became effective for interim and annual periods ending after
September 15, 2009. As the Codification was not intended to change or alter existing GAAP,
adoption did not have any substantive impact on the Companys financial position or results of
operations. However, as a result of the Companys implementation of the Codification during the
quarter ended September 30, 2009, previous references to new accounting standards and literature
are no longer applicable in the footnotes to the consolidated financial statements and references
will now refer to the appropriate topic of the Codification.
In December 2007 the FASB revised authoritative guidance on business combinations, as set
forth in Topic 805 of the Codification. The revised guidance resulted in significant changes in
financial accounting and reporting of business combination transactions. The guidance establishes
principles and requirements for how an acquirer in a business combination: (i) recognizes and
measures in its financial statements the identifiable assets acquired, the liabilities assumed, and
any noncontrolling interest in the acquiree, (ii) recognizes and measures the goodwill acquired in
the business combination or a gain from a bargain purchase, and (iii) determines what information
to disclose to enable users of the financial statements to evaluate the nature and financial
effects of the business combination. Adoption of the revised guidance on January 1, 2009 did not
have an impact on current financial position or results of operations, but will impact the
accounting for any future acquisitions.
In December 2007, the FASB issued authoritative guidance on noncontrolling interest in
consolidated financial statements, as set forth in Topic 810 of the Codification. This guidance
established accounting and reporting standards for the noncontrolling interest in a subsidiary and
for the deconsolidation of a subsidiary. Additionally, the guidance clarifies that a noncontrolling
interest in a subsidiary, which is sometimes referred to as minority interest, is an ownership
interest in the consolidated entity that should be reported as a component of equity in the
consolidated financial statements. Among other requirements, consolidated net income is to be
reported at amounts that include the amounts attributable to both the parent and the noncontrolling
interest. Disclosure is also required on the face of the consolidated income statement, of the
amounts of consolidated net income attributable to the parent and to the noncontrolling interest.
Adoption of the guidance on January 1, 2009 did not impact the Companys financial position or
results of operations.
In March 2008, the FASB issued authoritative guidance changing the disclosure requirements for
derivative instruments and hedging activities, as set forth in Topic 815 of the Codification. Among
other requirements, the guidance requires enhanced disclosures about (i) how and why an entity uses
derivative instruments, (ii) how derivative instruments and related hedged items are accounted for,
and (iii) how derivative instruments and related hedged items affect an entitys financial
position, financial performance, and cash flows. Adoption of the guidance on January 1, 2009
required enhanced disclosures about the Companys derivative instruments as disclosed in Note G.
In April 2009, the FASB issued authoritative guidance on interim disclosures about the fair
value of financial instruments. The guidance requires quarterly disclosure of information about
the fair value of certain financial instruments, as set forth in Topic 825 of the Codification.
Adoption of the guidance during the second quarter of 2009 did not impact the Companys financial
position or results of operations.
7
In May 2009, the FASB issued authoritative guidance on subsequent events, which establishes
general standards of accounting for and disclosure of events that occur after the balance sheet
date, but before the financial statements are issued or available to be issued. The guidance is set
forth in Topic 855 of the Codification and is effective for fiscal years and interim periods after
June 15, 2009. Adoption of the guidance in the second quarter of 2009 did not impact the Companys
financial position or results of operations.
On December 31, 2008, the Securities and Exchange Commission (SEC) issued Release No.
33-8995, Modernization of Oil and Gas Reporting, which revises disclosure requirements for oil
and gas companies. In addition to changing the definition and disclosure requirements for oil and
gas reserves, the new rules change the requirements for determining oil and gas reserve quantities.
These rules permit the use of new technologies to determine proved reserves under certain criteria
and allow companies to disclose their probable and possible reserves. The new rules also require
companies to report the independence and qualifications of their reserves preparer or auditor and
file reports when a third party is relied upon to prepare reserves estimates or conducts a reserves
audit. The new rules also require that oil and gas reserves be reported and the full cost ceiling
limitation be calculated using a twelve-month average price rather than period-end prices. The new
rule is effective for annual reports on Form 10-K for fiscal years ending on or after December 31,
2009. The new rules may not be applied to quarterly reports prior to the first annual report in
which the revised disclosures are required. The Company plans to implement the new requirements in
its Annual Report on Form 10-K for the year ending December 31, 2009. The Company is currently
evaluating the impact of this new rule on its consolidated financial statements and related
disclosures. Additionally, the FASB issued its proposed updates to oil and gas accounting rules to
align the oil and gas estimation and disclosure requirements of Extractive Industries-Oil & Gas
Topic 932 of the Codification with the requirements of the SECs revised rule, Modernization of Oil
and Gas Reporting. The public comment period for the FASBs proposed updates ended October 15,
2009; however, no final guidance has been issued by the FASB. We will comply with any new
accounting and disclosure requirements once they become effective.
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B |
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PROPERTIES AND EQUIPMENT |
Under the full cost method of accounting, the net book value of oil and natural gas
properties, less related deferred income taxes, may not exceed the estimated after-tax future net
revenues from proved oil and natural gas properties, discounted at 10% (the Ceiling Limitation).
In arriving at estimated future net revenues, estimated lease operating expenses, development
costs, and certain production-related and ad valorem taxes are deducted. In calculating future net
revenues, prices and costs in effect at the time of the calculation are held constant indefinitely,
except for changes that are fixed and determinable by existing contracts. The net book value is
compared to the Ceiling Limitation on a quarterly and yearly basis. The excess, if any, of the net
book value above the Ceiling Limitation is charged to expense in the period in which it occurs and
is not subsequently reinstated. At March 31, 2009, the net book value of the Companys oil and
natural gas properties exceeded the Ceiling Limitation resulting in a reduction in the carrying
value of the Companys oil and natural gas properties of $58.9 million. The after-tax effect of
this reduction was $37.5 million. At September 30, 2009 the net book value of the Companys oil
and natural gas properties did not exceed the Ceiling Limitation.
Long-term debt consists of the following (in thousands):
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September 30, |
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December 31, |
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2009 |
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2008 |
Credit facility |
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$ |
249,963 |
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$ |
250,387 |
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Accrued payment-in-kind interest |
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|
252 |
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- |
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Installment loan agreements |
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212 |
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309 |
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250,427 |
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250,696 |
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Less amount due within one year |
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142 |
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160 |
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$ |
250,285 |
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$ |
250,536 |
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In November 2007, in conjunction with the Companys Ascent acquisition, the Company
entered into a new $500.0 million credit facility with Guggenheim Corporate Funding, LLC, for
itself and on behalf of other institutional lenders. The facility includes a $250.0 million
revolving credit facility and a $200.0 million term loan facility and an additional $50.0 million
8
available under the term loan as requested by the Company and approved by the lenders. The initial
amount of the $200.0 million term loan was advanced at closing. The borrowing base under the
revolving credit facility initially was set at $175.0 million, a portion of which was advanced at
the closing of the Ascent acquisition. Borrowings under the facility were used to refinance RAM
Energys existing indebtedness, fund the cash requirements in connection with the closing of the
Ascent acquisition, and for working capital and other general corporate purposes. Funds advanced
under the revolving credit facility may be paid down
and re-borrowed during the four-year term of the revolver, and initially bore interest at
LIBOR plus a margin ranging from 1.25% to 2.0% based on a percentage of usage. The term loan
provides for payments of interest only during its five-year term, with the initial interest rate
being LIBOR plus 7.5%. The $175.0 million borrowing base under the revolver was reaffirmed in
September 2009.
Advances under the facility are secured by liens on substantially all properties and assets of
the Company and its subsidiaries. The loan agreement contains representations, warranties and
covenants customary in transactions of this nature, including financial covenants relating to
current ratio, minimum interest coverage ratio, maximum leverage ratio and a required ratio of
asset value to total indebtedness. The Company is required to maintain commodity hedges with
respect to not less than 50%, but not more than 85%, of the Companys projected monthly production
volumes on a rolling 30-month basis, until the leverage ratio is less than or equal to 2.0 to 1.0.
During May 2008, the Company reduced its outstanding balance on the term facility by $86.6 million
out of the net proceeds received by the Company upon the exercise of 17,617,331 warrants to acquire
the Companys common stock. See Note D.
On June 26, 2009, the Company entered into the Second Amendment to the credit facility. The
Second Amendment amends certain definitions and certain financial and negative covenant terms
providing greater flexibility for the Company through the remaining term of the facility.
Additionally, the Second Amendment increased the interest rates applicable to borrowings under both
the revolver and the term loan. Advances under the revolver will bear interest at LIBOR, with a
minimum LIBOR rate, or floor, of 1.5%, plus a margin ranging from 2.25% to 3.0% based on a
percentage of usage. The term loan will bear interest at LIBOR, also with a floor of 1.5%, plus a
margin of 8.5%, and an additional 2.75% of payment-in-kind interest that will be added to the term
loan principal balance on a monthly basis and paid at maturity. The Company was in compliance with
all of the financial covenants under the credit facility at September 30, 2009. At September 30,
2009, $140.0 million was outstanding under the revolving credit
facility and $110.2 million was
outstanding under the term facility.
The Company had outstanding warrants to purchase 18,848,800 shares of its common stock at
an exercise price of $5.00 per share, of which 17,617,331 were exercised prior to the May 12, 2008
expiration date, resulting in net proceeds to the Company of $86.6 million. Proceeds of the
exercise were used to pay down the term loan portion of the Companys credit facility. The
remaining 1,231,469 warrants expired and are no longer outstanding.
The Company had outstanding options to purchase up to 275,000 units at any time on or prior to
May 11, 2009 at an exercise price of $9.90 per unit, with each unit consisting of one share of the
Companys common stock and two warrants. All of the unit purchase options expired unexercised.
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E |
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COMMITMENTS AND CONTINGENCIES |
Rathborne Land Company, et al., v. Ascent Energy Inc., et al. Ascent Energy Inc.
and its Ascent Energy Louisiana, LLC subsidiary were sued for lease cancellation and damages for
failure to explore and develop the plaintiffs lease. By Opinion dated December 31, 2008, the
court found in favor of the plaintiff and against the defendants. On June 1, 2009, the court
entered judgment against the defendants in the amount of $4.6 million and shortly thereafter the
Company filed an appeal with the United States Court of Appeals for the Fifth Circuit. The Company
also filed a motion to stay the judgment pending final disposition on appeal and to permit the
posting of a cash bond as security for the stay, which motion was granted by the court.
In conjunction with the Companys November 29, 2007 acquisition of Ascent, the former
stockholders and note holders of Ascent deposited $20.0 million in escrow to secure their
obligation to indemnify the Company with respect to certain liabilities and obligations of Ascent,
including any loss, cost, liability or expense incurred by the Company in connection with this and
other pending litigation, subject to a sharing arrangement. After giving effect to such sharing
arrangement with respect to previously settled litigation, the Company and the former Ascent owners
will share equally the first $1.8 million of any losses attributable to this lawsuit and the former
Ascent owners, out of the escrow, will bear the remaining portion of any loss so incurred, up to
the remaining balance in the escrow fund. On June 18, 2009, the defendants arranged for the
posting of a cash security bond with the registry of the trial court in the amount of $5.5 million,
being 120% of the amount of the judgment, as required by court rule. By agreement with the
representative of the former Ascent stockholders and note holders, the Company posted the sum of
$0.9 million toward the security deposit and the remaining sum of $4.6 million was posted out of
the escrow
9
fund. All remaining funds in the escrow account, less the sum of approximately $0.2
million (which was retained in the escrow account to cover additional and incidental fees and
expenses related to the Rathborne litigation), were distributed to the Ascent stockholders and note
holders per the terms of the escrow agreement. During the fourth quarter of 2008, the Company
recorded a contingent liability of $0.9 million related to this litigation.
The Company is also involved in other legal proceedings and litigation in the ordinary course
of business. In the opinion of management, the outcome of such matters will not have a material
adverse effect on the Companys financial position or results of operations.
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F |
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FAIR VALUE MEASUREMENTS |
The Company measures the fair value of its derivative instruments according to the fair
value hierarchy as set forth in Topic 820 of the Codification. The hierarchy assigns the highest
priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level
1) and the lowest priority to unobservable inputs (Level 3). Level 2 measurements are inputs
that are observable for assets or liabilities, either directly or indirectly, other than quoted
prices included within Level 1. As of September 30, 2009, the fair value measurement of the
Companys net derivative assets was $0.1 million, based on Level 2 criteria. See Note G.
At September 30, 2009, the carrying value of cash, receivables and payables reflected in the
Companys financials approximates fair value due to their short-term nature. Additionally, the
carrying value of the Companys long-term debt under the credit facility approximates fair value
because the credit facility carries a variable interest rate based on market interest rates. See
Note C for discussion of long-term debt.
The Company periodically utilizes various hedging strategies to manage the price received
for a portion of its future oil and natural gas production to reduce exposure to fluctuations in
oil and natural gas prices and to achieve a more predictable cash flow.
During 2009 and 2008, the Company entered into numerous derivative contracts to manage the
impact of oil and natural gas price fluctuations and as required by the terms of its credit
facility.
The Company did not designate these transactions as hedges. Accordingly, all gains and losses
on the derivative instruments during 2009 and 2008 have been recorded in the statements of
operations.
The Companys derivative positions at September 30, 2009, consisting of put/call collars and
put options, also called bare floors as they provide a floor price without a corresponding
ceiling, are shown in the following table:
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Crude
Oil (Bbls) |
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Natural
Gas (Mmbtu) |
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Floors |
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Ceilings |
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Floors |
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Ceilings |
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Per
Day(1) |
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Price |
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Per
Day |
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Price |
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Months
Covered |
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Per
Day(1) |
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|
Price |
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Per
Day |
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Price |
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Collars
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2009
|
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1,168 |
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$ |
60.00 |
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|
1,168 |
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$ |
81.10 |
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October - December |
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|
11,989 |
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$ |
5.00 |
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|
11,989 |
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$ |
10.03 |
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October - December |
2010
|
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|
1,503 |
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|
$ |
53.74 |
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|
1,503 |
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$ |
80.57 |
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January - December |
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|
5,288 |
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|
$ |
5.00 |
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|
5,288 |
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|
$ |
9.23 |
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January - June, November - December |
2011
|
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|
- |
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$ |
- |
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|
- |
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|
$ |
- |
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|
4,959 |
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|
$ |
5.00 |
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|
4,959 |
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$ |
9.60 |
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January - June |
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Bare
Floors |
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Bare
Floors |
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Year |
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Per
Day(1) |
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|
Price |
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Months Covered |
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Per
Day(1) |
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|
Price |
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Months Covered |
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2009
|
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|
1,832 |
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|
$ |
68.19 |
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|
October - December
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|
- |
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$ |
- |
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2010
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|
1,121 |
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$ |
64.84 |
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January - March, July - December |
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|
5,452 |
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$ |
4.46 |
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April - December |
2011
|
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|
247 |
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|
$ |
60.00 |
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January - March |
|
|
- |
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$ |
- |
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(1) |
|
Per day amounts are calculated based on a 365-day year. |
10
The Company estimates the fair value of its derivative instruments based on published forward
commodity price curves as of the date of the estimate, less discounts to recognize present values.
For the year ended December 31, 2008 and subsequent periods, the Company estimated the fair value
of its derivatives using a pricing model which also considered market volatility, counterparty
credit risk and additional criteria in determining discount rates. See Note F. For the year ended
December 31, 2008 and subsequent periods the discount rate used in the discounted cash flow
projections was based on published LIBOR rates, Eurodollar futures rates and interest swap rates. The counterparty credit risk was determined
by calculating the difference between the derivative counterpartys bond rate and published bond
rates.
Gross fair values of the Companys derivative instruments, prior to netting of assets and
liabilities subject to a master netting arrangement, as of September 30, 2009 and the consolidated
statements of operations for the three and nine months ended September 30, 2009 and 2008 are as
follows (in thousands):
CONSOLIDATED BALANCE SHEETS
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Fair Value |
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As of |
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September 30, |
Gross Assets and Liabilities |
|
Balance Sheet Location |
|
2009 |
Current Assets - Derivative assets |
|
Current Assets - Derivative assets |
|
$ |
3,622 |
|
Other Assets - Derivative assets |
|
Long-Term Liabilities - Derivative liabilities |
|
|
359 |
|
Current Liabilities - Derivative liabilities |
|
Current Assets - Derivative assets |
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|
(2,610 |
) |
Long-Term Liabilities - Derivative liabilities |
|
Long-Term Liabilities - Derivative liabilities |
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|
(1,295 |
) |
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Total Derivatives Not Designated as
Hedging Instruments |
|
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|
$ |
76 |
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CONSOLIDATED STATEMENTS OF OPERATIONS
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Three Months Ended September 30, |
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Nine Months Ended September 30, |
|
Location |
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
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Revenue - Unrealized gains (losses) on
derivatives |
|
$ |
(1,283 |
) |
|
$ |
34,302 |
|
|
$ |
(26,085 |
) |
|
$ |
(4,765 |
) |
Revenue - Realized gains (losses) on derivatives |
|
$ |
483 |
|
|
$ |
(5,054 |
) |
|
$ |
19,032 |
|
|
$ |
(14,590 |
) |
|
|
|
H |
|
SHARE-BASED COMPENSATION |
The Company accounts for share-based payment accruals under authoritative guidance on
stock compensation, as set forth in Topic 718 of the Codification. The guidance requires all
share-based payments to employees, including grants of employee stock options, to be recognized in
the financial statements based on their fair values.
On May 8, 2006, the Companys stockholders approved its 2006 Long-Term Incentive Plan (the
Plan). The Company reserved a maximum of 2,400,000 shares of its common stock for issuances under
the Plan. The Plan includes a provision that, at the request of a grantee, the Company may
repurchase shares to satisfy the grantees federal and state income tax withholding requirements.
All repurchased shares will be held by the Company as treasury stock. On May 8, 2008, the Plan was
amended to increase the maximum authorized number of shares to be issued under the Plan from
2,400,000 to 6,000,000. As of September 30, 2009, a maximum of 2,509,426 shares of common stock
remained reserved for issuance under the Plan.
As of September 30, 2009, the Company had $4.9 million of unrecognized compensation cost
related to non-vested, share-based compensation awards granted under the Plan. That cost is
expected to be recognized over a weighted-average period of two years. The related compensation
expense recognized during the three and nine months ended September 30, 2009 was $0.5 million and
$1.6 million, respectively, and during the three and nine months ended September 30, 2008 was $0.6
million and $2.1 million, respectively.
11
ITEM 2 MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
BUSINESS
General
We are an independent oil and natural gas company engaged in the acquisition, development,
exploitation, exploration and production of oil and natural gas properties, primarily in Texas,
Oklahoma, Louisiana, and West Virginia. Our producing properties are located in highly prolific
basins with long histories of oil and natural gas operations.
Principal Properties
Our oil and natural gas assets are characterized by a combination of conventional and
unconventional reserves and prospects. We have conventional reserves and production in three main
onshore locations:
|
|
|
South TexasStarr, Wharton and Duval Counties, Texas (Developing Fields); |
|
|
|
|
Electra/BurkburnettWichita and Wilbarger Counties, Texas (Mature Oil Fields); and |
|
|
|
|
Pontotoc County, Oklahoma (Mature Oil Field). |
Our unconventional reserves and prospects are primarily shale plays in the following
areas:
|
|
|
North Texas Barnett ShaleJack and Wise Counties, Texas. This is
our Tier 1 Barnett shale acreage where we own interests in
approximately 27,018 gross (6,594 net) acres (Developing Field); |
|
|
|
|
Appalachian Devonian ShaleCabell and Mason Counties, West
Virginia. We own leasehold interests in approximately 60,313 gross
(49,101 net) acres (Developing Field); and |
|
|
|
|
North Texas Barnett ShaleBosque and Hamilton Counties, Texas. We
own interests in approximately 2,671 gross (2,425 net) acres in this
emerging Tier 2 region of the North Texas Barnett shale play
(Developing Field). |
12
Net Production, Unit Prices and Costs
The following table presents certain information with respect to our oil and natural gas
production, and prices and costs attributable to all oil and natural gas properties owned by us,
for the three and nine months ended September 30, 2009. Average realized prices reflect the actual
realized prices received by us, before and after giving effect to the results of our derivative
contract settlements. Our derivative activities are financial, and our production of oil, natural
gas liquids, or NGLs, and natural gas, and the average realized prices we receive from our
production, are not affected by our derivative arrangements.
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
|
Nine months ended |
|
|
|
|
September 30, 2009 |
|
|
|
September 30, 2009 |
|
|
|
|
|
|
|
|
Production volumes: |
|
|
|
|
|
|
|
|
Oil (MBbls) |
|
|
278 |
|
|
|
858 |
|
NGLs (MBbls) |
|
|
104 |
|
|
|
303 |
|
Natural gas (MMcf) |
|
|
1,488 |
|
|
|
4,658 |
|
Total (Mboe) |
|
|
630 |
|
|
|
1,938 |
|
|
|
|
|
|
|
|
|
|
Average sale prices received: |
|
|
|
|
|
|
|
|
Oil (per Bbl) |
|
|
$65.74 |
|
|
|
$53.31 |
|
NGLs (per Bbl) |
|
|
$28.84 |
|
|
|
$23.54 |
|
Natural gas (per Mcf) |
|
|
$3.10 |
|
|
|
$3.34 |
|
Total per Boe |
|
|
$41.08 |
|
|
|
$35.31 |
|
|
|
|
|
|
|
|
|
|
Cash effect of derivative contracts: |
|
|
|
|
|
|
|
|
Oil (per Bbl) |
|
|
($0.13) |
|
|
|
$7.11 |
|
NGLs (per Bbl) |
|
|
$0.00 |
|
|
|
$0.00 |
|
Natural gas (per Mcf) |
|
|
$0.35 |
|
|
|
$2.78 |
|
Total per Boe |
|
|
$0.77 |
|
|
|
$9.82 |
|
|
|
|
|
|
|
|
|
|
Average prices computed after cash effect
of settlement of derivative contracts: |
|
|
|
|
|
|
|
|
Oil (per Bbl) |
|
|
$65.61 |
|
|
|
$60.42 |
|
NGLs (per Bbl) |
|
|
$28.84 |
|
|
|
$23.54 |
|
Natural gas (per Mcf) |
|
|
$3.45 |
|
|
|
$6.12 |
|
Total per Boe |
|
|
$41.85 |
|
|
|
$45.13 |
|
|
|
|
|
|
|
|
|
|
Cash expenses (per Boe): |
|
|
|
|
|
|
|
|
Oil and natural gas production taxes |
|
|
$2.10 |
|
|
|
$1.61 |
|
Oil and natural gas production expenses |
|
|
$15.51 |
|
|
|
$14.95 |
|
General and administrative |
|
|
$6.74 |
|
|
|
$6.37 |
|
Interest |
|
|
$3.53 |
|
|
|
$4.65 |
|
Taxes |
|
|
$0.30 |
|
|
|
$0.24 |
|
Total per Boe |
|
|
$28.18 |
|
|
|
$27.82 |
|
|
|
|
|
|
|
|
|
|
Cash flow per Boe |
|
|
$13.67 |
|
|
|
$17.31 |
|
13
Acquisition, Development and Exploration Capital Expenditures
The following table presents information regarding our net costs incurred in our acquisitions
of proved and unproved properties, and our development and exploration activities during the three
and nine months ended September 30, 2009 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
|
Nine months ended |
|
|
|
|
September 30, 2009 |
|
|
|
September 30, 2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Development and exploratory costs |
|
$ |
3,898 |
|
|
$ |
20,677 |
|
Proved property acquisition costs |
|
|
84 |
|
|
|
1,051 |
|
Unproved property acquisition costs |
|
|
- |
|
|
|
- |
|
|
|
|
|
|
Total costs incurred |
|
$ |
3,982 |
|
|
$ |
21,728 |
|
|
|
|
|
|
During the quarter ended September 30, 2009, we participated in the drilling of 11 gross (ten
net) development wells. Five gross (five net) wells were completed and capable of commercial
production. Six gross (five net) wells were drilling or waiting on completion and two gross (0.2
net) wells drilled in previous quarters were waiting on completion at September 30, 2009.
Results of Operations
Quarter Ended September 30, 2009 Compared to Quarter Ended September 30, 2008
Oil and natural gas sales decreased $28.3 million, or 52%, to $25.9 million for the three
months ended September 30, 2009 as compared to $54.2 million for the same period in 2008. This
decrease was primarily driven by commodity price decreases, which decreased 51% for the three
months ended September 30, 2009 as compared to the same period last year. Production volumes
decreased 2% as compared to the same period last year. Approximately one-half of the decline in
production is attributable to asset sales representing approximately 140 Boe per day of production,
impacting two months in the third quarter of 2009. In late September, we reactivated our natural
gas drilling program in South Texas and project that our future natural gas production volumes will
improve as new wells are brought online.
The following table summarizes our oil and natural gas production volumes, average sales
prices (without regard to derivative contract settlements) and period-to-period comparisons for the
periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mature |
|
Mature |
|
|
|
|
|
|
|
|
|
Developing Fields |
|
|
|
|
|
|
Oil Fields* |
|
Natural Gas Fields |
|
|
|
|
|
South Texas |
|
|
Barnett Shale |
|
|
|
Appalachia |
|
Various |
|
Various |
|
Total |
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
September 30, 2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregate Net Production |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls) |
|
|
12 |
|
|
|
2 |
|
|
|
- |
|
|
|
233 |
|
|
|
31 |
|
|
|
278 |
|
NGLs (MBbls) |
|
|
31 |
|
|
|
32 |
|
|
|
- |
|
|
|
20 |
|
|
|
21 |
|
|
|
104 |
|
Natural Gas (MMcf) |
|
|
525 |
|
|
|
195 |
|
|
|
21 |
|
|
|
135 |
|
|
|
612 |
|
|
|
1,488 |
|
|
|
|
|
|
|
|
|
|
|
|
|
MBoe |
|
|
130 |
|
|
|
67 |
|
|
|
4 |
|
|
|
275 |
|
|
|
154 |
|
|
|
630 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
September 30, 2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregate Net Production |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls) |
|
|
17 |
|
|
|
2 |
|
|
|
- |
|
|
|
245 |
|
|
|
31 |
|
|
|
295 |
|
NGLs (MBbls) |
|
|
32 |
|
|
|
13 |
|
|
|
- |
|
|
|
21 |
|
|
|
21 |
|
|
|
87 |
|
Natural Gas (MMcf) |
|
|
691 |
|
|
|
141 |
|
|
|
20 |
|
|
|
238 |
|
|
|
490 |
|
|
|
1,580 |
|
|
|
|
|
|
|
|
|
|
|
|
|
MBoe |
|
|
164 |
|
|
|
39 |
|
|
|
3 |
|
|
|
305 |
|
|
|
134 |
|
|
|
645 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in MBoe |
|
|
(34 |
) |
|
|
28 |
|
|
|
1 |
|
|
|
(30 |
) |
|
|
20 |
|
|
|
(15 |
) |
Percentage Change in MBoe |
|
|
-20.7 |
% |
|
|
71.8 |
% |
|
|
33.3 |
% |
|
|
-9.8 |
% |
|
|
14.9 |
% |
|
|
-2.3 |
% |
* Includes Electra/Burkburnett, Allen/Fitts and Layton fields.
14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
|
|
|
|
September 30, |
|
|
|
|
|
|
2009 |
|
2008 |
|
Decrease |
|
|
|
|
|
|
|
|
|
|
|
|
|
Average sale prices: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl) |
|
|
$65.74 |
|
|
|
$116.81 |
|
|
|
-43.7 |
% |
NGL (per Bbl) |
|
|
$28.84 |
|
|
|
$66.16 |
|
|
|
-56.4 |
% |
Natural gas (per Mcf) |
|
|
$3.10 |
|
|
|
$8.85 |
|
|
|
-65.0 |
% |
Per Boe |
|
|
$41.08 |
|
|
|
$83.92 |
|
|
|
-51.0 |
% |
The average realized sales prices decreased substantially for the three months ended
September 30, 2009 as compared to the same period in 2008. The average realized sales price for
oil was $65.74 per barrel for the three months ended September 30, 2009, a decrease of 44%,
compared to $116.81 per barrel for the same period in 2008. The average realized sales price for
NGLs was $28.84 for the three months ended September 30, 2009, a decrease of 56%, compared to
$66.16 per barrel for the same period in 2008. The average realized sales price for natural gas was
$3.10 per Mcf for the three months ended September 30, 2009, a decrease of 65%, compared to $8.85
per Mcf for the same period in 2008.
Realized and Unrealized Gain (Loss) from Derivatives. For the quarter ended September 30,
2009, our loss from derivatives was $0.8 million, compared to a gain of $29.2 million for the
quarter ended September 30, 2008. Our gains and losses during these periods were the net result of
recording actual contract settlements, the premiums for our derivative contracts, and unrealized
losses attributable to mark-to-market values of our derivative contracts at the end of the periods.
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30, |
|
|
|
2009 |
|
2008 |
|
|
(in thousands) |
|
Contract settlements and premium costs: |
|
|
|
|
|
|
|
|
Oil |
|
$ |
(37 |
) |
|
$ |
(4,952 |
) |
Natural gas |
|
|
520 |
|
|
|
(102 |
) |
|
|
|
|
|
Realized gains (losses) |
|
|
483 |
|
|
|
(5,054 |
) |
Mark-to-market gains (losses): |
|
|
|
|
|
|
|
|
Oil |
|
|
(105 |
) |
|
|
28,368 |
|
Natural gas |
|
|
(1,178 |
) |
|
|
5,934 |
|
|
|
|
|
|
Unrealized gains (losses) |
|
|
(1,283 |
) |
|
|
34,302 |
|
|
|
|
|
|
Realized and unrealized gains (losses) |
|
$ |
(800 |
) |
|
$ |
29,248 |
|
|
|
|
|
|
Oil and Natural Gas Production Taxes. Our oil and natural gas production taxes were $1.3
million for the quarter ended September 30, 2009, compared to $3.1 million for the comparable
quarter of the previous year. Production taxes vary by state. Most are based on realized prices
at the wellhead, while Louisiana production taxes are based on volumes for natural gas and values
for oil. As revenues or volumes from oil and natural gas sales increase or decrease, production
taxes on these sales also increase or decrease directly. The decrease was due to a significant
reduction in oil and natural gas revenues for the quarter ended September 30, 2009 compared to the
same period during 2008. Additionally, retroactive severance tax refunds were granted during the
third quarter of 2009. As a percentage of oil and natural gas sales, our oil and natural gas
production taxes decreased to 5.1% for the third quarter ended September 30, 2009, as compared to
5.7% for the quarter ended September 30, 2008.
Oil and Natural Gas Production Expense. Our oil and natural gas production expense was $9.8
million for the quarter ended September 30, 2009, an increase of $0.1 million, from $9.7 million
for the quarter ended September 30, 2008. For the quarter ended September 30, 2009, our oil and
natural gas production expense was $15.51 per Boe compared to $15.08 per Boe for the quarter ended
September 30, 2008, an increase of 3%. As a percentage of oil and natural gas sales, oil and
natural gas production expense was 38% for the quarter ended September 30, 2009, as compared to 18%
for the quarter ended September 30, 2008. This increase results from a significant drop in average
sales prices per Boe, from $83.92 in 2008 to $41.08 in 2009, a 51% decrease.
Amortization and Depreciation Expense. Our amortization and depreciation expense decreased
$3.7 million, or 33%, for the quarter ended September 30, 2009, compared to the quarter ended
September 30, 2008. On an equivalent basis, our amortization of the full-cost pool of $7.1 million
was $11.21 per Boe for the quarter ended September 30, 2009, a decrease per Boe of 33% compared to
$10.7 million, or $16.64 per Boe for the quarter ended September 30, 2008. This rate decrease per
Boe resulted from lower capitalized costs subsequent to the asset impairment writedowns in the
fourth quarter of 2008 and the first quarter of 2009. The rate decrease was partially offset by a
rate increase resulting from a decrease in our net quantities of proved reserves of oil and natural
gas.
15
Accretion Expense. Topic 410 of the Codification includes, among other things, the reporting
of the fair value of asset retirement obligations. Accretion expense is a function of changes in
fair value from period-to-period. We recorded $0.5 million for the quarter ended September 30,
2009, a decrease of $0.1 million from $0.6 million for the quarter ended September 30, 2008.
Share-Based Compensation. From time to time, our Board of Directors grants restricted stock
awards under our 2006 Long-Term Incentive Plan. Each of these grants vests in equal increments over
the vesting period provided for the particular award. All currently unvested awards provide for
vesting periods of from one to five years. The share-based compensation expense attributable to
these grants is calculated using the closing price per share on each of the grant dates and will be
recognized over their respective vesting periods. For the quarter ended September 30, 2009, we
recognized a total of $0.5 million share-based compensation expense, compared to $0.6 million from
the quarter ended September 30, 2008.
General and Administrative Expense. For the quarter ended September 30, 2009, our general and
administrative expense was $4.2 million, compared to $5.0 million for the quarter ended September
30, 2008, a decrease of $0.8 million, or 14%. The decrease results from lower employee-related
costs, primarily due to a reduction of estimated bonuses, as well as lower professional fees in the
2009 period.
Interest Expense. We recorded interest expense of $5.6 million for the quarter ended September
30, 2009 as compared to $4.8 million for the third quarter of the previous year. The increase in
interest expense was primarily due to higher effective interest rates under the Second Amendment to
our credit facility executed June 26, 2009. Our blended interest rate was 8.9% in the third
quarter of 2009 compared to 7.8% in the 2008 period.
Other Expense. For the third quarter of 2009, other expense decreased $6.7 million as
compared to the third quarter of 2008. In September 2008, we entered into an agreement pursuant to
which we agreed to pay $16.0 million in settlement of a pending class action lawsuit. We placed
that amount in escrow in October 2008 in anticipation of a final court approved settlement in the
second quarter of 2009. In conjunction with our May 8, 2006 acquisition of RAM Energy, the former
stockholders of RAM Energy deposited in escrow 3,200,000 shares of their common stock to secure
their potential indemnity obligations to us, including any loss we might sustain in this litigation
or through an agreed settlement. At September 30, 2008, we recorded a contingent liability of
$16.0 million for the settlement and a receivable of $9.2 million representing the market value of
the escrowed shares based on the closing price of $2.89 per share on September 30, 2008. The $6.8
million charge to other expense represented the difference between the settlement liability and the
value of the escrowed shares.
Income Taxes. For the three months ended September 30, 2009, we recorded an income tax benefit
of $1.4 million, on a pre-tax loss of $4.1 million. For the quarter ended September 30, 2008, we
recorded an income tax provision of $13.6 million, on pre-tax income of $42.1 million. The
effective tax rate for the three months ended September 30, 2009 was 33%, compared to an effective
tax rate of 32% for the three months ended September 30, 2008.
Nine Months Ended September 30, 2009 Compared to the Nine Months Ended September 30, 2008
Oil and natural gas sales decreased $86.9 million, or 56% to $68.4 million for the nine months
ended September 30, 2009 as compared to $155.3 million for the same period in 2008. This decrease
was driven by commodity price decreases, which decreased 57% for the nine months ended September
30, 2009 as compared to the same period last year. Production volumes increased 2% for the nine
months ended September 30, 2009 as compared to the same period last year. Contributing to this
production increase was a 99% increase in Barnett Shale production. Offsetting our oil and natural
gas sales were derivative losses of $7.1 million for the nine months ended September 30, 2009.
16
The following table summarizes our oil and natural gas production volumes, average sales
prices (without regard to derivative contract settlements) and period to period comparisons,
including the effect on our oil and natural gas sales, for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mature |
|
|
Mature |
|
|
|
|
|
|
Developing Fields |
|
|
Oil Fields* |
|
|
Natural Gas Fields |
|
|
|
|
Nine Months Ended September 30, 2009 |
|
South Texas |
|
|
Barnett Shale |
|
|
Appalachia |
|
|
Various |
|
|
Various |
|
|
Total |
|
Aggregate Net Production |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls) |
|
|
45 |
|
|
|
6 |
|
|
|
1 |
|
|
|
726 |
|
|
|
80 |
|
|
|
858 |
|
NGLs (MBbls) |
|
|
87 |
|
|
|
94 |
|
|
|
- |
|
|
|
62 |
|
|
|
60 |
|
|
|
303 |
|
Natural Gas (MMcf) |
|
|
1,547 |
|
|
|
604 |
|
|
|
66 |
|
|
|
530 |
|
|
|
1,911 |
|
|
|
4,658 |
|
|
|
|
|
|
|
|
|
|
|
|
|
MBoe |
|
|
390 |
|
|
|
201 |
|
|
|
12 |
|
|
|
876 |
|
|
|
459 |
|
|
|
1,938 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
September 30, 2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregate Net Production |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls) |
|
|
38 |
|
|
|
4 |
|
|
|
- |
|
|
|
715 |
|
|
|
136 |
|
|
|
893 |
|
NGLs (MBbls) |
|
|
84 |
|
|
|
44 |
|
|
|
- |
|
|
|
60 |
|
|
|
58 |
|
|
|
246 |
|
Natural Gas (MMcf) |
|
|
1,999 |
|
|
|
318 |
|
|
|
30 |
|
|
|
591 |
|
|
|
1,628 |
|
|
|
4,566 |
|
|
|
|
|
|
|
|
|
|
|
|
|
MBoe |
|
|
456 |
|
|
|
101 |
|
|
|
5 |
|
|
|
874 |
|
|
|
465 |
|
|
|
1,901 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in MBoe |
|
|
(66 |
) |
|
|
100 |
|
|
|
7 |
|
|
|
2 |
|
|
|
(6 |
) |
|
|
37 |
|
Percentage Change in MBoe |
|
|
-14.5 |
% |
|
|
99.0 |
% |
|
|
140.0 |
% |
|
|
0.2 |
% |
|
|
-1.3 |
% |
|
|
1.9 |
% |
|
|
|
* |
Includes Electra/Burkburnett, Allen/Fitts and Layton fields. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended |
|
|
|
|
September 30, |
|
|
|
|
2009 |
|
2008 |
|
Decrease |
|
|
|
|
|
|
|
|
|
|
|
|
|
Average sale prices: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl) |
|
$ |
53.31 |
|
|
$ |
112.08 |
|
|
|
-52.4 |
% |
NGLs (per Bbl) |
|
$ |
23.54 |
|
|
|
$60.65 |
|
|
|
-61.2 |
% |
Natural gas (per Mcf) |
|
|
$3.34 |
|
|
|
$8.81 |
|
|
|
-62.1 |
% |
Per Boe |
|
$ |
35.31 |
|
|
|
$81.67 |
|
|
|
-56.8 |
% |
Production levels increased 2% for the nine months ended September 30, 2009 as compared
to the same period last year. Drilling activity in our mature oil fields, Barnett Shale and
Appalachia leaseholds increased the equivalent production volumes by 109 MBoe. These volumes
offset the 66 MBoe reduction in produced volumes in our developing fields of South Texas and loss
of 6 Mboe in our mature natural gas fields.
The average realized sales prices decreased substantially for the nine months ended September
30, 2009 as compared to the same period in 2008. The average realized sales price for oil was
$53.31 per barrel for the nine months ended September 30, 2009, a decrease of 52%, compared to
$112.08 per barrel for the same period in 2008. The average realized sales price for NGLs was
$23.54 for the nine months ended September 30, 2009, a decrease of 61%, compared to $60.65 per
barrel for the same period in 2008. The average realized sales price for natural gas was $3.34 per
Mcf for the nine months ended September 30, 2009, a decrease of 62%, compared to $8.81 per Mcf for
the same period in 2008.
17
Realized and Unrealized Gain (Loss) from Derivatives. For the nine months ended September 30,
2009, our loss from derivatives was $7.1 million compared to a loss of $19.4 million for the nine
months ended September 30, 2008. Our gains and losses during these periods were the net result of
recording actual contract settlements, the premiums for our derivative contracts, and unrealized
losses attributable to mark-to-market values of our derivative contracts at the end of the periods.
Contributing to the realized gains for the nine months ended September 30, 2009 was the sale of
natural gas contracts during the second quarter of 2009.
|
|
|
|
|
|
|
|
|
|
|
Nine months ended September 30, |
|
|
|
2009 |
|
|
2008 |
|
|
|
(in thousands) |
|
Contract settlements and premium costs: |
|
|
|
|
|
|
|
|
Oil |
|
$ |
6,103 |
|
|
$ |
(13,095 |
) |
Natural gas |
|
|
12,929 |
|
|
|
(1,495 |
) |
|
|
|
|
|
|
|
Realized gains (losses) |
|
|
19,032 |
|
|
|
(14,590 |
) |
Mark-to-market losses: |
|
|
|
|
|
|
|
|
Oil |
|
|
(19,316 |
) |
|
|
(4,348 |
) |
Natural gas |
|
|
(6,769 |
) |
|
|
(417 |
) |
|
|
|
|
|
|
|
Unrealized losses |
|
|
(26,085 |
) |
|
|
(4,765 |
) |
|
|
|
|
|
|
|
Realized and unrealized losses |
|
$ |
(7,053 |
) |
|
$ |
(19,355 |
) |
|
|
|
|
|
|
|
Oil and Natural Gas Production Taxes. Our oil and natural gas production taxes were $3.1
million for the nine months ended September 30, 2009, compared to $8.8 million for the comparable
nine months of the previous year. Production taxes vary by state. Most are based on realized
prices at the wellhead, while Louisiana production tax is based on volumes for natural gas and
value for oil. As revenues or volumes from oil and natural gas sales increase or decrease,
production taxes on these sales also increase or decrease directly. The decrease was due to a
significant decrease in oil and natural gas revenues and retroactive severance tax refunds granted
during the nine months ended September 30, 2009. As a percentage of oil and natural gas sales, oil
and natural gas production taxes were 4.6% for the nine months ended September 30, 2009, compared
to 5.7% for the nine months ended September 30, 2008.
Oil and Natural Gas Production Expense. Our oil and natural gas production expense was $29.0
million for the nine months ended September 30, 2009, an increase of $0.5 million, or 2%, from the
$28.5 million for the nine months ended September 30, 2008. For the nine months ended September
30, 2009, our oil and natural gas production expense was $14.95 per Boe compared to $15.00 per Boe
for the nine months ended September 30, 2008. As a percentage of oil and natural gas sales, oil
and natural gas production expense was 42% for the nine months ended September 30, 2009, as
compared to 18% for the nine months ended September 30, 2008. This increase results from a
significant drop in average sales prices per Boe, from $81.67 in 2008 to $35.31 in 2009, a 57%
decrease.
Amortization and Depreciation Expense. Our amortization and depreciation expense decreased
$8.9 million, or 27%, for the nine months ended September 30, 2009, compared to the nine months
ended September 30, 2008. The decrease was a result of a lower depletion rate per Boe, partially
offset by an increase in production. On an equivalent basis, our amortization of the full-cost
pool of $23.1 million was $11.91 per Boe for the nine months ended September 30, 2009, a decrease
per Boe of 29% compared to $32.1 million, or $16.87 per Boe for the nine months ended September 30,
2008. This rate decrease per Boe resulted from lower capitalized costs subsequent to the asset
impairment writedowns in the fourth quarter of 2008 and the first quarter of 2009. The rate
decrease was partially offset by a rate increase resulting from a decrease in our net quantities of
proved reserves of oil and natural gas.
Accretion Expense. Topic 410 of the Codification includes, among other things, the reporting
of the fair value of asset retirement obligations. Accretion expense is a function of changes in
fair value from period-to-period. We recorded $1.4 million for the nine months ended September 30,
2009, compared to $1.6 million for the first nine months in 2008.
Impairment Charge. We incurred a $58.9 million impairment of the carrying value of our oil
and gas properties during the first nine months of 2009. The impairment of our oil and gas
properties was solely due to a reduction in the tax-effected estimated present value of future net
revenues, caused by the dramatic decline in commodity prices, from our proved oil and gas reserves
between December 31, 2008 and March 31, 2009.
Share-Based Compensation. From time to time, our Board of Directors grants restricted stock
awards under our 2006
Long-Term Incentive Plan. Each of these grants vests in equal increments over the vesting
period provided for the particular award. All currently unvested awards provide for vesting
periods of from one to five years. The share-based compensation on these grants was calculated
using the closing price per share on each of the grant dates and the total share-based compensation
on
18
all these grants will be recognized over their respective vesting periods. For the nine months
ended September 30, 2009, we recognized a total of $1.6 million share-based compensation compared
to $2.1 million for the nine months ended September 30, 2008. This decrease is a result of the
April 2008 accelerated vesting of restricted stock grants to John Cox, our Senior Vice President,
who passed away in March 2008.
General and Administrative Expense. For the nine months ended September 30, 2009, our general
and administrative expense was $12.3 million, compared to $16.0 million for the nine months ended
September 30, 2008, a decrease of $3.7 million, or 23%. The decrease results from lower
employee-related costs, primarily due to a reduction of estimated bonuses, as well as lower
professional fees in the 2009 period.
Interest Expense. We recorded interest expense of $12.8 million for the nine months ended
September 30, 2009, compared to $19.2 million incurred for the first nine months of the previous
year. The decrease in interest expense was due to lower debt balances for the 2009 period and lower
effective interest rates in the first half of 2009 compared to 2008, partially offset by higher
interest rates during the third quarter of 2009 due to the Second Amendment to our credit facility
executed June 26, 2009. Our debt was lower in the first half of the 2009 period because in the
second quarter of 2008, we used $86.6 million in realized net proceeds from the exercise of
17,617,331 warrants in May 2008 to pay down the term facility, and $9.4 million in cash to pay down
the revolver. Our blended interest rate was 6.8% during the first nine months of 2009 compared to
10.4% in the 2008 period. As a result of this paydown and lower interest rates for the period, our
interest expense decreased by $6.4 million for the nine months ended September 30, 2009 compared to
the same period in 2008.
Other Expense. For the nine months ended September 30, 2009, other expense was $0.5 million
compared to $7.1 million for the nine months ended September 30, 2008. We recorded a charge to
other expense of $6.8 million in the 2008 period for expense related to settlement of litigation.
In September 2008, we entered into an agreement pursuant to which we agreed to pay $16.0 million in
settlement of a pending class action lawsuit. We placed that amount in escrow in October 2008 in
anticipation of a final court approved settlement in the second quarter of 2009. In conjunction
with our May 8, 2006 acquisition of RAM Energy, the former stockholders of RAM Energy deposited in
escrow 3,200,000 shares of their common stock to secure their potential indemnity obligations to
us, including any loss we might sustain in this litigation or through an agreed settlement. At
December 31, 2008, we recorded a contingent liability of $16.0 million for the settlement and a
receivable of $2.8 million representing the market value of the escrow shares based on the closing
price of $0.88 per share on December 31, 2008. On March 5, 2009, the court approved the settlement
and on April 6, 2009, the settlement became final. The $0.4 million charge to other expense in the
first quarter of 2009 represents the adjustment to fair market value of the escrowed shares on the
final settlement date of $0.74 per share.
Income Taxes. For the nine months ended September 30, 2009, we recorded an income tax benefit
of $29.3 million, on a pre-tax loss of $81.9 million. For the nine months ended September 30,
2008, our income tax benefit was $1.8 million, on a pre-tax income of $20.3 million, including a
$7.0 million benefit by reversing an uncertain tax position and related accrued interest.
Excluding the first quarter 2009 ceiling test impairment of $58.9 million and the related tax
benefit of $21.4 million, the effective tax rate was 34% for the first nine months of 2009.
Excluding the reversal of the uncertain tax position, the effective tax rate was 25% for the first
nine months of 2008.
Liquidity and Capital Resources
As of September 30, 2009, we had cash and cash equivalents of $0.1 million, and $35.0 million
of availability under our revolving credit facility; however, advances in excess of $163.3 million
at September 30, 2009 would have been restricted by a financial ratio covenant under our credit
facility. At that date, we had $250.4 million of indebtedness outstanding, including $110.2 million
under our term loan facility, $140.0 million under our revolving credit facility and $0.2 million
in other indebtedness. As of September 30, 2009, we had an accumulated deficit of $219.7 million
and a working capital deficit of $4.7 million.
Credit Facility. In November 2007, in conjunction with the Ascent acquisition, we entered into
a $500.0 million credit facility with Guggenheim Corporate Funding, LLC, for itself and on behalf
of other institutional lenders. The facility, which replaced our previous $300.0 million facility,
includes a $250.0 million revolving credit facility, a $200.0 million term loan facility, and an
additional $50.0 million available under the term loan as requested by us and approved by the
lenders. The entire amount of the $200.0 million term loan was advanced at closing. The borrowing
base under the revolving credit facility at the closing was $175.0 million, a portion of which was
advanced at the closing of the Ascent acquisition. Borrowings under the facility were used to
refinance RAM Energys existing indebtedness, fund the cash requirements in connection with the
closing of the Ascent acquisition, and for working capital and other general corporate purposes.
Funds advanced under the revolving credit facility may be paid down and re-borrowed during the
four-year term of the revolver, and initially bore interest at LIBOR
plus a margin ranging from 1.25% to 2.0% based on a percentage of usage. At September 30,
2009, the balance outstanding under our revolving credit facility was $140.0 million. The term
loan portion of our credit facility provides for payments of interest only during its five-year
term, with the initial interest rate being LIBOR plus 7.5%. The $175.0 million borrowing base under
our revolving credit facility was reaffirmed in September 2009 based on the value of our proved
reserves at June 30, 2009.
19
Advances under our credit facility are secured by liens on substantially all of our properties
and assets. The credit facility contains representations, warranties and covenants customary in
transactions of this nature, including financial covenants relating to current ratio, minimum
interest coverage ratio, maximum leverage ratio and a required ratio of asset value to total
indebtedness.
On June 26, 2009, we renegotiated certain terms of our credit facility to provide us greater
flexibility in complying with certain of the financial covenants under the loan agreement. In
exchange for the added flexibility afforded by these changes to the credit facility, we agreed to
increase the base cash interest rate on both the revolving credit facility and the term loan credit
facility by 1% per annum, establish a LIBOR floor of 1.5% and pay an additional 2.75% per annum of
non-cash, payment-in-kind, or PIK, interest on the term portion of the facility. Accrued PIK
interest will be added to the principal balance of the term loan on a monthly basis and paid at
maturity.
In May of 2008, we used $86.6 million in realized net proceeds from the exercise of 17,617,331
warrants to pay down the term facility to the existing level of $113.4 million.
Notwithstanding the recent amendments to our loan agreement, our ability to comply with the
financial covenants in our credit facility may be affected by events beyond our control and, as a
result, in future periods we may be unable to meet these ratios and financial condition tests.
These financial ratio restrictions and financial condition tests could limit our ability to obtain
future financings, make needed capital expenditures, withstand a future downturn in our business or
the economy in general or otherwise conduct necessary corporate activities. A breach of any of
these covenants or our inability to comply with the required financial ratios or financial
condition tests could result in a default under our credit facility. A default, if not cured or
waived, could result in acceleration of all indebtedness outstanding under our credit facility. The
accelerated debt would become immediately due and payable. If that should occur, we may be unable
to pay all such debt or to borrow sufficient funds to refinance it. Even if new financing were then
available, it may not be on terms that are acceptable to us. At September 30, 2009, we were in
compliance with all of the financial covenants under our credit facility.
We are required to maintain commodity hedges with respect to not less than 50%, but not more
than 85%, of our projected monthly production volumes on a rolling 30-month basis, until the
leverage ratio is less than or equal to 2.0 to 1.0. At September 30, 2009, our commodity hedging
represented approximately 55% of our projected production volumes through March 31, 2012.
Senior Notes. In February 1998, RAM Energy completed the sale of $115.0 million of 11.5%
Senior Notes due 2008 in a public offering of which $28.4 million remained outstanding at December
31, 2007. These notes were retired at maturity on February 15, 2008 using proceeds from our
revolving credit facility.
Cash Flow From Operating Activities. Our cash flow from operating activities is comprised of
three main items: net loss, adjustments to reconcile net loss to cash provided before changes in
operating assets and liabilities, and changes in operating assets and liabilities. For the nine
months ended September 30, 2009, our net loss was $52.6 million, as compared with a net income of
$22.1 million for the nine months ended September 30, 2008. Adjustments before changes in operating
assets and liabilities (primarily non-cash items such as amortization and depreciation, asset
impairment charge, unrealized losses on derivatives, and deferred income taxes) were $86.0 million
for the nine months ended September 30, 2009 compared to $47.3 million for the first nine months of
2008, an increase of $38.7 million. Asset impairment charge and unrealized loss on derivatives,
offset by deferred income taxes, caused most of this increase. Changes in operating assets and
liabilities for the nine months ended September 30, 2009 utilized $14.3 million of cash, compared
with utilizing $1.2 million for the nine months ended September 30, 2008. For the nine months
ended September 30, 2009, in total, net cash provided by operating activities was $19.0 million
compared to $68.3 million of net cash provided by operating activities for the first nine months of
the previous year.
Cash Flow From Investing Activities. For the nine months ended September 30, 2009, net cash
used in our investing activities was $15.6 million, consisting of $22.2 million in payments for oil
and gas properties and other equipment offset by $6.6 million in proceeds from sales of property
and equipment. For the nine months ended September 30, 2008, net cash used in our investing
activities was $66.5 million. The decrease results from a decreased capital expenditures budget,
from $80.0 million for 2008 to $30.0 - $35.0 million expected in 2009.
Cash Flow From Financing Activities. For the nine months ended September 30, 2009, net cash
used in our financing activities was $3.4 million, compared to net cash used of $2.5 million for
the nine months ended September 30, 2008. During the
first nine months of 2009, we received proceeds of $23.0 million from borrowings on long-term
debt, which was offset by $24.1 million to reduce our long term debt, and $2.3 million in payments
for deferred loan costs. During the nine months of 2008, we used $158.2 million to reduce our long
term debt. Other cash provided during the nine months of 2008 included $69.3 million in additional
long-term debt borrowings and $86.6 million in the exercise of outstanding warrants.
20
Capital Commitments
During the nine months ended September 30, 2009, we had capital expenditures of $21.7 million
relating to our oil and natural gas operations, of which $20.7 million was allocated to development
and exploratory costs, and $1.0 million was for acquisition costs.
We initially established a non-acquisition capital expenditures budget for 2009 of $40.0-$45.0
million; however, due to the decline in natural gas market prices since year end 2008 and the
persistence of lower prices into the third quarter of 2009, in August 2009, we revised to
$30.0-$35.0 million our 2009 non-acquisition capital expenditures budget as follows:
|
|
|
geological, geophysical and seismic costs ($4.0 million); |
|
|
|
|
developmental drilling and recompletions ($24.0-$29.0 million); and |
|
|
|
|
exploratory drilling, including leasehold acquisitions ($2.0 million). |
In our revised 2009 non-acquisition capital budget, we have allocated $6.0-$8.0 million
for drilling on our South Texas properties, $1.0-$2.0 million for our North Texas Barnett Shale,
$5.0-$7.0 million for continued development of our Electra/Burkburnett area, $10.0 million for
recompletion and production enhancement operations primarily in our Louisiana mature gas fields,
and $2.0 million to our Pontotoc properties in Oklahoma.
The amount and timing of our capital expenditures for calendar year 2009 may vary depending on
a number of factors, including prevailing market prices for oil and natural gas, the favorable or
unfavorable results of operations actually conducted, projects proposed by third party operators on
jointly owned acreage, development by third party operators on adjoining properties, rig and
service company availability, and other influences that we cannot predict.
Although we cannot provide any assurance, assuming successful implementation of our strategy,
including the future development of our proved reserves and realization of our cash flows as
anticipated, we believe that cash flows from operations will be sufficient to satisfy our budgeted
non-acquisition capital expenditures, working capital and debt service obligations for the next
twelve months. The actual amount and timing of our future capital requirements may differ
materially from our estimates as a result of, among other things, changes in product pricing and
regulatory, technological and competitive developments. Sources of additional financing available
to us may include commercial bank borrowings, vendor financing and the sale of equity or debt
securities. We cannot provide any assurance that any such financing will be available on acceptable
terms or at all.
The credit markets are undergoing significant volatility. Many financial institutions have
liquidity concerns, prompting government intervention to mitigate pressure on the credit markets.
Our exposure to the current credit market crisis includes our revolving credit facility,
counterparty risks related to our trade credit and risks related to our cash investments.
Our revolving credit facility matures in November 2011. Our term loan facility matures in
November 2012. Should current credit market volatility be prolonged for several years, future
extensions of our credit facility may contain terms that are less favorable than those of our
current credit facility.
Current market conditions also elevate the concern over our cash deposits, which total
approximately $0.1 million, and counterparty risks related to our trade credit. Our cash accounts
and deposits with any financial institution that exceed the amount insured by the Federal Deposit
Insurance Corporation are at risk in the event one of these financial institutions fail. We sell
our crude oil, natural gas and NGLs to a variety of purchasers. Some of these parties are not as
creditworthy as we are and may experience liquidity problems. Non-performance by a trade creditor
could result in losses.
21
ITEM 3 QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Exposure to market risk is managed and monitored by our senior management. Senior management
approves the overall investment strategy that we employ and has responsibility to ensure that the
investment positions are consistent with that strategy and the level of risk acceptable to us. The
carrying amounts reported in our consolidated balance sheets for cash and cash equivalents, trade
receivables and payables, installment notes and variable rate long-term debt approximate their fair
values.
Interest Rate Sensitivity
We are exposed to changes in interest rates. Changes in interest rates affect the interest
earned on our cash and cash equivalents and the interest rate paid on our borrowings. We have not
used interest rate derivative instruments to manage our exposure to interest rate changes.
Our long-term debt, as of September 30, 2009, is denominated in U.S. dollars. Our debt has
been issued at variable rates, and as such, our interest expense could be impacted by interest rate
shifts; however, under the recent amendment to our credit facility, which included a LIBOR floor
rate of 1.5% per annum, unless LIBOR rates exceed 1.5% per annum, an increase in LIBOR rates will
not affect the rate or amount of interest payable under the facility. If LIBOR rates increase to
greater than 1.5% per annum, then the impact of a 100-basis point increase in LIBOR interest rates
above such floor rate would result in an increase in interest expense of $2.5 million annually.
Absent an increase in LIBOR rates to a rate in excess of 1.5% per annum, a decrease in LIBOR rates
would not result in a decrease in our interest expense.
Commodity Price Risk
Our revenue, profitability and future growth depend substantially on prevailing prices for oil
and natural gas. Prices also affect the amount of cash flow available for capital expenditures and
our ability to borrow and raise additional capital. Lower prices may also reduce the amount of oil
and natural gas that we can economically produce. We currently sell most of our oil and natural gas
production under market price contracts.
During the nine months ended September 30, 2009, Shell Energy North America-US accounted for
$41.7 million, or approximately 61%, and Devon Energy Production Company accounted for $4.2
million, or approximately 6% of our revenue from the sales of oil and natural gas.
To reduce exposure to fluctuations in oil and natural gas prices, to achieve more predictable
cash flow, and as required by our lenders, we periodically utilize various derivative strategies to
manage the price received for a portion of our future oil and natural gas production. We have not
established derivatives in excess of our expected production.
Our open derivative positions at September 30, 2009, consisting of put/call collars and put
options, also called bare floors as they provide a floor price without a corresponding ceiling,
are shown in the following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil (Bbls) |
|
|
|
|
|
Natural Gas (Mmbtu) |
|
|
|
|
Floors |
|
Ceilings |
|
|
|
|
|
Floors |
|
Ceilings |
|
|
|
|
Per Day(1) |
|
|
Price |
|
Per Day |
|
Price |
|
|
Months Covered |
|
Per Day(1) |
|
|
Price |
|
Per Day |
|
Price |
|
Months Covered |
|
Collars |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
1,168 |
|
|
$ |
60.00 |
|
|
|
1,168 |
|
|
$ |
81.10 |
|
|
October - December |
|
|
11,989 |
|
|
$ |
5.00 |
|
|
|
11,989 |
|
|
$ |
10.03 |
|
|
October - December |
2010 |
|
|
1,503 |
|
|
$ |
53.74 |
|
|
|
1,503 |
|
|
$ |
80.57 |
|
|
January - December |
|
|
5,288 |
|
|
$ |
5.00 |
|
|
|
5,288 |
|
|
$ |
9.23 |
|
|
January - June, November - December |
2011 |
|
|
- |
|
|
$ |
- |
|
|
|
- |
|
|
$ |
- |
|
|
|
|
|
|
|
4,959 |
|
|
$ |
5.00 |
|
|
|
4,959 |
|
|
$ |
9.60 |
|
|
January - June |
|
|
|
Bare Floors |
|
|
|
|
|
|
|
|
|
|
|
|
|
Bare Floors |
|
|
Year |
|
Per Day(1) |
|
|
Price |
|
Months Covered |
|
Per Day(1) |
|
|
Price |
|
Months Covered |
|
2009 |
|
|
1,832 |
|
|
$ |
68.19 |
|
|
October - December |
|
|
- |
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
2010 |
|
|
1,121 |
|
|
$ |
64.84 |
|
|
January - March, July - December |
|
|
5,452 |
|
|
$ |
4.46 |
|
|
April - December |
2011 |
|
|
247 |
|
|
$ |
60.00 |
|
|
January - March |
|
|
- |
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
Per day amounts are calculated based on a 365-day year. |
22
ITEM 4 CONTROLS AND PROCEDURES
Under the supervision and with the participation of our management, including our principal
executive officer and principal financial officer, we evaluated the design and operation of our
disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities
Exchange Act of 1934, or the Exchange Act) as of September 30, 2009. On the basis of this review,
our management, including our principal executive officer and principal financial officer,
concluded that our disclosure controls and procedures are designed, and are effective, to give
reasonable assurance that the information required to be disclosed by us in reports that we file
under the Exchange Act is recorded, processed, summarized and reported within the time periods
specified in the rules and forms of the SEC and to ensure that information required to be disclosed
in the reports filed or submitted under the Exchange Act is accumulated and communicated to our
management, including our principal executive officer and principal financial officer, in a manner
that allows timely decisions regarding required disclosure.
We did not effect any change in our internal controls over financial reporting during the
quarter ended September 30, 2009 that has materially affected, or is reasonably likely to
materially affect, our internal control over financial reporting.
Forward-Looking Statements
The description of our plans and expectations set forth herein, including expected capital
expenditures and acquisitions, are forward-looking statements made pursuant to the safe harbor
provisions of the Private Securities Litigation Reform Act of 1995. These plans and expectations
involve a number of risks and uncertainties. Important factors that could cause actual capital
expenditures, acquisition activity or our performance to differ materially from the plans and
expectations include, without limitation, our ability to satisfy the financial covenants of our
outstanding debt instruments and to raise additional capital; our ability to manage our business
successfully and to compete effectively in our business against competitors with greater financial,
marketing and other resources; and adverse regulatory changes. Readers are cautioned not to place
undue reliance on these forward-looking statements, which speak only as of the date hereof. We
undertake no obligation to update or revise these forward-looking statements to reflect events or
circumstances after the date hereof including, without limitation, changes in our business strategy
or expected capital expenditures, or to reflect the occurrence of unanticipated events.
23
PART II OTHER INFORMATION
ITEM 1 LEGAL PROCEEDINGS
Reference is made to Part I, Item 3, Legal Proceedings, in our annual report on Form 10-K
for the year ended December 31, 2008 and to Part II, Item 1, Legal Proceedings, in our quarterly
report on Form 10-Q for the quarter ended June 30, 2009, for a discussion of pending legal
proceedings to which we are a party.
24
ITEM 1A RISK FACTORS
Possible regulation related to global warming and climate change could have an adverse effect on
our operations and demand for oil and natural gas.
Recent scientific studies have suggested that emissions of gases, commonly referred to as
greenhouse gases including carbon dioxide, methane and nitrous oxide among others, may be
contributing to warming of the earths atmosphere. In response to such studies, the U.S. Congress
is actively considering legislation to reduce emissions of greenhouse gases. In addition, several
states have already taken legal measures to reduce emissions of greenhouse gases. As a result of
the U.S. Supreme Courts decision on April 2, 2007 in Massachusetts, et al. v. EPA, 549 U.S. 497
(2007), finding that greenhouse gases fall within the Clean Air Act (CAA) definition of air
pollutant, EPA was required to determine whether emissions of greenhouse gases endanger public
health or welfare. In April 2009, EPA proposed a finding of such endangerment and has announced
plans to soon finalize its proposed endangerment finding. Consistent with its endangerment finding,
in September 2009, EPA proposed regulations to control greenhouse gas emissions from light duty
vehicles. EPA also announced that its action to control greenhouse gas emissions from light duty
vehicles automatically triggers application of the CAA prevention of significant deterioration and
Title V operating permit program to major stationary sources of greenhouse gas emissions. Thus, in
September 2009, EPA issued a proposed tailoring rule explaining how it would implement the CAA
permitting programs to major stationary source greenhouse gas emission sources. In September 2009,
EPA also adopted a mandatory greenhouse gas reporting rule which will assist EPA in implementing
the major stationary source permitting programs triggered by the mobile source rules. EPAs rules
may become final and effective even if Congress adopts new legislation addressing emissions of
greenhouse gases. Finally, in September 2009, the United States Court of Appeals for the Second
Circuit issued its decision in Connecticut v. AEP allowing plaintiffs claims that public utilities
greenhouse gas emissions created a public nuisance to go to trial over defendants objections
based upon political question, preemption and lack of standing. This case exposes other significant
emission sources of greenhouse gases to similar litigation risk. This effect of this recent caselaw
may be mitigated by Congresss adoption of greenhouse gas legislation and, or, EPAs final adoption
of greenhouse gas emission standards.
Other nations have already agreed to regulate emissions of greenhouse gases, pursuant to the
United Nations Framework Convention on Climate Change, also known as the Kyoto Protocol, an
international treaty pursuant to which participating countries (not including the United States)
have agreed to reduce their emissions of greenhouse gases to below 1990 levels by 2012.
International negotiations are currently underway to develop a new agreement, with the
participation of the United States. International developments, passage of state or federal climate
control legislation or other regulatory initiatives, the adoption of regulations by the EPA and
analogous state agencies that restrict emissions of greenhouse gases in areas in which Chaparral
conducts business, or further development of caselaw allowing claims based upon greenhouse gas
emissions, could have an adverse effect on our operations and demand for oil and natural gas.
Potential legislative and regulatory actions could increase our costs, reduce our revenue and cash
flow from oil and natural gas sales, reduce our liquidity or otherwise alter the way we conduct our
business.
Pending federal budget proposals would potentially increase and accelerate the payment of
federal income taxes of independent producers of oil and natural gas. Proposals that would
significantly affect us would repeal the expensing of intangible drilling costs, repeal the
percentage depletion allowance, repeal the manufacturing tax deduction for oil and natural gas
companies and increase the amortization period of geological and geophysical expenses. These
changes, if enacted, will make it more costly for us to explore for and develop our oil and natural
gas resources.
The U.S. Congress is considering measures aimed at increasing the transparency and stability
of the over-the-counter (OTC) derivative markets and preventing excessive speculation. We maintain
an active price and basis protection hedging program related to the oil and natural gas we produce.
Additionally, we have used the OTC market exclusively for our oil and natural gas derivative
contracts and rely on our hedging activities to manage the risk of low commodity prices and to
predict with greater certainty the cash flow from our hedged production. Proposals being considered
would impose clearing and standardization requirements for all OTC derivatives and restrict trading
positions in the energy futures markets. Such changes would likely materially reduce our hedging
opportunities and could negatively affect our revenues and cash flow during periods of low
commodity prices.
We may not be able to borrow the full amount of the borrowing base under our revolving credit
facility because of the amount of our EBITDA. The inability to fully borrow funds up to our
borrowing base could reduce our capital expenditures.
As of September 30, 2009, our borrowing base under our revolving credit facility was $175.0
million. As of the same date, we had outstanding advances under the revolving credit facility of
$140.0 million, leaving an aggregate availability under our revolver of $35.0 million. However,
because of the amount of our EBITDA, the financial covenants set forth in our credit facility would
have limited us to additional borrowings under our revolving credit facility as of September 30,
2009 of $23.3 million. We will be unable to borrow the full
amount of our borrowing base until our EBITDA for the preceding four fiscal quarters equals or exceeds $63.6 million. Our inability to borrow the full amount of our
borrowing base under our revolving credit facility could reduce our capital expenditures.
25
Reference is also made to Part I, Item 1A, Risk Factors, in our annual report on Form 10-K
for the year ended December 31, 2008, for a discussion of other risk factors which are the known,
material risks that could affect our business and our results of operations.
ITEM 2 UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
None.
ITEM 3 DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4 SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
ITEM 5 OTHER INFORMATION
26
ITEM 6 EXHIBITS
|
|
|
|
|
Exhibit |
|
Description |
|
Method of Filing |
3.1
|
|
Amended and Restated Certificate of Incorporation of the Registrant.
|
|
(1) [3.1] |
|
|
|
|
|
3.2
|
|
Amended and Restated Bylaws of the Registrant.
|
|
(13) [3.2] |
|
|
|
|
|
4.1
|
|
Specimen Unit Certificate.
|
|
(1) [4.1] |
|
|
|
|
|
4.2
|
|
Specimen Common Stock Certificate.
|
|
(1) [4.2] |
|
|
|
|
|
4.3
|
|
Amended Specimen Warrant Certificate.
|
|
(12) [4.3] |
|
|
|
|
|
4.4
|
|
Amended Form of Unit Purchase Option granted to EarlyBirdCapital, Inc.
|
|
(2) [4.4] |
|
|
|
|
|
4.5
|
|
Form of Warrant Agreement between Continental Stock Transfer & Trust Company and the Registrant.
|
|
(12) [4.5] |
|
|
|
|
|
4.6
|
|
Indenture dated as of February 24, 1998 among RAM Energy, Inc., the Subsidiary Guarantors named therein, and United States Trust Company of New York, Trustee.
|
|
(7) [4.1] |
|
|
|
|
|
4.6.1
|
|
Supplemental Indenture dated February 24, 1998 among RAM Energy, Inc., the Subsidiary Guarantors named therein, and United States Trust Company of New York,
Trustee.
|
|
(8) [4.6.1] |
|
|
|
|
|
4.6.2
|
|
Second Supplemental Indenture dated as of November 22, 2002 among RAM Energy, Inc., the Subsidiary Guarantors and The Bank of New York, Successor to United
States Trust Company of New York, as trustee.
|
|
(8) [4.6.2] |
|
|
|
|
|
4.6.3
|
|
Third Supplemental Indenture dated as of April 29, 2004 among RAM Energy, Inc., the Subsidiary Guarantors and The Bank of New York, Successor to United
States Trust Company of New York, as trustee.
|
|
(8) [4.6.3] |
|
|
|
|
|
4.6.4
|
|
Fourth Supplemental Indenture dated as of December 17, 2004 among RAM Energy, Inc., The Bank of New York, Successor to United States Trust Company of New
York, as trustee, RWG Energy, Inc., WG Operating, Inc., WG Royalty Company, Wise County Construction Company, LLC, and WG Pipeline LLC, as Additional
Subsidiary Guarantors.
|
|
(8) [4.6.4] |
|
|
|
|
|
10.1
|
|
Form of Stock Escrow Agreement between the Registrant, Continental Stock Transfer & Trust Company and the Initial Stockholders.
|
|
(2) [10.6] |
|
|
|
|
|
10.2
|
|
Form of Registration Rights Agreement among the Registrant and the Initial Stockholders.
|
|
(2) [10.9] |
|
|
|
|
|
10.2.1
|
|
Amendment to Registration Rights Agreement among this Registrant and the Founders dated May 8, 2006.
|
|
(1) [10.9.1] |
|
|
|
|
|
10.3
|
|
Agreement and Plan of Merger dated October 20, 2005 among Registrant, RAM Acquisition, Inc., RAM Energy, Inc. and the Stockholders of RAM Energy, Inc.
|
|
(3) [10.11] |
|
|
|
|
|
10.3.1
|
|
Amendment No. 1, dated November 11, 2005, to Agreement and Plan of Merger dated October 20, 2005 among the Registrant, RAM Acquisition, Inc., RAM Energy,
Inc. and the Stockholders of RAM Energy, Inc.
|
|
(4) [10.11] |
|
|
|
|
|
10.3.2
|
|
Amendment No. 2, dated February 15, 2006, to Agreement and Plan of Merger dated October 20, 2005 among the Registrant, RAM Acquisition, Inc., RAM Energy,
Inc. and the Stockholders of RAM Energy, Inc.
|
|
(6) [10.11] |
|
|
|
|
|
10.4
|
|
Voting Agreement dated October 20, 2005 among the Registrant, the stockholders of RAM Energy, Inc. and certain security holders of the Registrant.
|
|
(3) [10.2] |
|
|
|
|
|
10.4.1
|
|
Second Amended and Restated Voting Agreement included as Annex D of the Registrants Definitive Proxy Statement (No. 000-50682), dated April 10, 2006 and
incorporated by reference herein.
|
|
(5) [Annex D] |
|
|
|
|
|
10.5
|
|
Lock-Up Agreement dated October 20, 2005 executed by the stockholders of RAM Energy, Inc.
|
|
(3) [10.4] |
|
|
|
|
|
10.6
|
|
Employment Agreement between Registrant and Larry E. Lee dated May 8, 2006.*
|
|
(1) [10.15] |
|
|
|
|
|
10.6.1
|
|
First Amendment to Employment Agreement between Registrant and Larry E. Lee dated
October 18, 2006. *
|
|
(9) [10.1] |
|
|
|
|
|
10.6.2
|
|
Second Amendment to Employment Agreement of Larry E. Lee dated February 25, 2008.*
|
|
(17) [10.6.2] |
27
|
|
|
|
|
10.6.3
|
|
Third Amendment to Employment Agreement of Larry E. Lee, dated December 30, 2008.*
|
|
(20) [10.6.3] |
|
|
|
|
|
10.6.4
|
|
Fourth Amendment to Employment Agreement of Larry E. Lee dated March 24, 2009.*
|
|
(21) [10.6.4] |
|
|
|
|
|
10.7
|
|
Escrow Agreement by and among the Registrant, Larry E. Lee and Continental Stock Transfer & Trust
Company dated May 8, 2006.
|
|
(1) [10.16] |
|
|
|
|
|
10.8
|
|
Registration Rights Agreement among Registrant and the investors signatory thereto dated May 8, 2006.*
|
|
(1) [10.17] |
|
|
|
|
|
10.9
|
|
Form of Registration Rights Agreement among the Registrant and the Investors party thereto.
|
|
(3) [10.17] |
|
|
|
|
|
10.10
|
|
Agreement between RAM and Shell Trading-US dated February 1, 2006.
|
|
(1) [10.22] |
|
|
|
|
|
10.11
|
|
Agreement between RAM and Targa dated January 30, 1998.
|
|
(1) [10.23] |
|
|
|
|
|
10.11.1
|
|
Amendment to Agreement between RAM Energy and Targa dated effective as of April 1, 2006, filed as
an exhibit to Registrants Form 8-K dated June 5, 2006 and incorporated by reference herein.
|
|
(10) [10.23.1] |
|
|
|
|
|
10.12
|
|
Long-Term Incentive Plan of the Registrant. Included as Annex C of the Registrants Definitive
Proxy Statement (No. 000-50682), dated April 12, 2006 and incorporated by reference herein.*
|
|
(5) [Annex C] |
|
|
|
|
|
10.12.1
|
|
First Amendment to RAM Energy Resources, Inc. 2006 Long-Term Incentive Plan effective May 8, 2008.*
|
|
(18) [Exhibit A] |
|
|
|
|
|
10.13
|
|
Third Amended and Restated Loan Agreement dated as of April 3, 2006, between RAM Energy, Inc., the
lenders described therein, Guggenheim Corporate Funding, LLC as the Arranger and Administrative
Agent, Wells Fargo Foothill, Inc., as the Documentation Agent, and WESTLB AG, New York Branch, as
the Syndication Agent.
|
|
(11) [10.14] |
|
|
|
|
|
10.13.1
|
|
First Amendment to Third Amended and Restated Loan Agreement between RAM Energy, Inc., the lenders
described therein, Guggenheim Corporate Funding, LLC, as the Arranger and Administrative Agent,
Wells Fargo Foothill, Inc., as the Documentation Agent, and WEST LB AG, New York Branch, as the
Syndication Agent, dated as of August 8, 2007.
|
|
(14) [10.13.1] |
|
|
|
|
|
10.14
|
|
Deferred Bonus Compensation Plan of RAM Energy, Inc. dated as of April 21, 2004.*
|
|
(12) [10.14] |
|
|
|
|
|
10.15
|
|
Purchase and Sale Agreement dated May 10, 2007 between Layton Enterprises, Inc. and the Registrant
(exhibits and schedules intentionally omitted).
|
|
(14) [10.15] |
|
|
|
|
|
10.16
|
|
Agreement and Plan of Merger dated October 16, 2007 among RAM Energy Resources Corporation, Ascent
Energy Inc. and Ascent Acquisition Corp.
|
|
(15) [2.1] |
|
|
|
|
|
10.17
|
|
Loan Agreement dated November 29, 2007, by and between RAM Energy Resources, Inc., as Borrower, and
Guggenheim Corporate Funding, LLC, as the Arranger and Administrative Agent, Wells Fargo Foothill,
Inc., as the Documentation Agent and WestLB AG, New York Branch and CIT Capital USA Inc., as the
Co-Syndication Agents, and the financial institutions named therein as the Lenders.
|
|
(16) [10.1] |
|
|
|
|
|
10.17.1
|
|
First Amendment to Loan Agreement dated November 29, 2007, by and between RAM Energy Resources, Inc.,
as Borrower, and Guggenheim Corporate Funding, LLC, as the Arranger and Administrative Agent, Wells
Fargo Foothill, Inc., as the Documentation Agent and WestLB AG, New York Branch and CIT Capital USA
Inc., as the Co-Syndication Agents, and the financial institutions named therein as the Lenders.
|
|
(22) [10.17.1] |
|
|
|
|
|
10.17.2
|
|
Second Amendment to Loan Agreement dated November 29, 2007, by and between RAM Energy Resources, Inc.,
as Borrower, and Guggenheim Corporate Funding, LLC, as the Arranger and Administrative Agent, Wells
Fargo Foothill, Inc., as the Documentation Agent and WestLB AG, New York Branch and CIT Capital USA
Inc., as the Co-Syndication Agents, and the financial institutions named therein as the Lenders.
|
|
(23) [10.17.2] |
|
|
|
|
|
10.18
|
|
Description of Compensation Arrangement with G. Les Austin.*
|
|
(19) [10.18] |
|
|
|
|
|
10.18.1
|
|
First Amendment to Employment Agreement of G. Les Austin, dated December 30, 2008.*
|
|
(20) [10.18.1] |
|
|
|
|
|
10.19
|
|
Change in Control Separation Benefit Plan of RAM Energy Resources, Inc. and Participating Subsidiaries.*
|
|
(22) [10.19] |
|
|
|
|
|
31.1
|
|
Rule 13(A) 14(A) Certification of our Principal Executive Officer.
|
|
** |
|
|
|
|
|
31.2
|
|
Rule 13(A) 14(A) Certification of our Principal Financial Officer.
|
|
** |
28
|
|
|
|
|
32.1
|
|
Section 1350 Certification of our Principal Executive Officer.
|
|
** |
|
|
|
|
|
32.2
|
|
Section 1350 Certification of our Principal Financial Officer.
|
|
** |
|
|
|
* |
|
Management contract or compensatory plan or arrangement. |
|
** |
|
Filed herewith. |
|
(1) |
|
Filed as an exhibit to the Registrants Current Report on Form 8-K
filed on May 12, 2006, as the exhibit number indicated in brackets and
incorporated by reference herein. |
|
(2) |
|
Filed as an exhibit to the Registrants Registration Statement on Form
S-1 (SEC File No. 333-113583) as the exhibit number indicated in
brackets and incorporated by reference herein. |
|
(3) |
|
Filed as an exhibit to the Registrants Current Report on Form 8-K
filed on October 26, 2005, as the exhibit number indicated in brackets
and incorporated by reference herein. |
|
(4) |
|
Filed as an exhibit to the Registrants Current Report on Form 8-K
filed on November 14, 2005, as the exhibit number indicated in
brackets and incorporated by reference herein. |
|
(5) |
|
Included as an annex to the Registrants Definitive Proxy Statement
(No. 000-50682), dated April 12, 2006, as the annex letter indicated
in brackets and incorporated by reference herein. |
|
(6) |
|
Filed as an exhibit to the Registrants Current Report on Form 8-K
filed on February 21, 2006, as the exhibit number indicated in
brackets and incorporated by reference herein. |
|
(7) |
|
Filed as an exhibit to the Registration Statement on Form S-1 (SEC
File No. 333-42641) of RAM Energy, Inc., as the exhibit number
indicated in brackets and incorporated by reference herein. |
|
(8) |
|
Filed as an exhibit to the Registrants Quarterly Report on Form 10-Q
filed on August 14, 2006, as the exhibit number indicated in brackets
and incorporated by reference herein. |
|
(9) |
|
Filed as an exhibit to the Registrants Current Report on Form 8-K on
October 20, 2006, as the exhibit number indicated in brackets and
incorporated by reference herein. |
|
(10) |
|
Filed as an exhibit to the Registrants Current Report on Form 8-K on
June 5, 2006, as the exhibit number indicated in brackets and
incorporated by reference herein. |
|
(11) |
|
Filed as an exhibit to Registrants amended Quarterly Report on Form
10-Q/A filed on December 20, 2006, as the exhibit number indicated in
brackets and incorporated by reference herein. |
|
(12) |
|
Filed as an exhibit to the Registrants Registration Statement on
Form S-1 (SEC File No. 333-138922) as the exhibit number indicated in
brackets and incorporated by reference herein. |
|
(13) |
|
Filed as an exhibit to the Registrants Current Report on Form 8-K
filed on February 2, 2007, as the exhibit number indicated in
brackets and incorporated by reference herein. |
|
(14) |
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Filed as an exhibit to the Registrants Quarterly Report on Form 10-Q
filed on August 10, 2007, as the exhibit number indicated in brackets
and incorporated by reference herein. |
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(15) |
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Filed as an exhibit to Registrants Form 8-K dated October 18, 2007
as the exhibit number indicated in brackets and incorporated by
reference herein. |
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(16) |
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Filed as an exhibit to Registrants Form 8-K dated November 29, 2007
as the exhibit number indicated in brackets and incorporated by
reference herein. |
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(17) |
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Filed as an exhibit to Registrants Form 8-K dated February 26, 2008 as the exhibit number indicated in brackets and incorporated by reference
herein. |
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(18) |
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Filed as an exhibit to Registrants Definitive Proxy Statement (No. 000-50682) dated April 14, 2008, as the exhibit number indicated in the
brackets and incorporated herein by reference. |
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(19) |
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Filed as an exhibit to the Registrants Quarterly Report on Form 10-Q filed on May 9, 2008, as the exhibit number indicated in brackets and
incorporated by reference herein. |
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(20) |
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Filed as an exhibit to Registrants Form 8-K filed January 5, 2009 as the exhibit number indicated in brackets and incorporated by reference herein. |
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(21) |
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Filed as an exhibit to Registrants Form 8-K filed March 25, 2009 as the exhibit number indicated in brackets and incorporated by reference herein. |
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(22) |
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Filed as an exhibit to Registrants Annual Report on Form 10-K filed on March 12, 2009 as the exhibit number indicated in brackets and incorporated
by reference herein. |
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(23) |
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Filed as an exhibit to Registrants Form 8-K filed July 2, 2009 as the exhibit number indicated in brackets and incorporated by reference herein. |
29
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly
caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
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RAM ENERGY RESOURCES, INC.
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November 5, 2009
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By: /s/ Larry E. Lee
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Name: Larry E. Lee |
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Title: Chairman, President and Chief Executive Officer |
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November 5, 2009
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By: /s/ G. Les Austin
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Name: G. Les Austin |
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Title: Senior Vice President and Chief Financial Officer |
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30
INDEX TO EXHIBITS
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Exhibit |
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Description |
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Method of Filing |
3.1
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Amended and Restated Certificate of Incorporation of the Registrant.
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(1) [3.1] |
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3.2
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Amended and Restated Bylaws of the Registrant.
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(13) [3.2] |
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4.1
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Specimen Unit Certificate.
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(1) [4.1] |
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4.2
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Specimen Common Stock Certificate.
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(1) [4.2] |
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4.3
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Amended Specimen Warrant Certificate.
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(12) [4.3] |
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4.4
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Amended Form of Unit Purchase Option granted to EarlyBirdCapital, Inc.
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(2) [4.4] |
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4.5
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Form of Warrant Agreement between Continental Stock Transfer & Trust Company and the Registrant.
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(12) [4.5] |
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4.6
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Indenture dated as of February 24, 1998 among RAM Energy, Inc., the Subsidiary Guarantors named
therein, and United States Trust Company of New York, Trustee.
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(7) [4.1] |
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4.6.1
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Supplemental Indenture dated February 24, 1998 among RAM Energy, Inc., the Subsidiary
Guarantors named therein, and United States Trust Company of New York, Trustee.
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(8) [4.6.1] |
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4.6.2
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Second Supplemental Indenture dated as of November 22, 2002 among RAM Energy, Inc., the
Subsidiary Guarantors and The Bank of New York, Successor to United States Trust Company of New
York, as trustee.
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(8) [4.6.2] |
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4.6.3
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Third Supplemental Indenture dated as of April 29, 2004 among RAM Energy, Inc., the Subsidiary
Guarantors and The Bank of New York, Successor to United States Trust Company of New York, as
trustee.
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(8) [4.6.3] |
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4.6.4
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Fourth Supplemental Indenture dated as of December 17, 2004 among RAM Energy, Inc., The Bank of New
York, Successor to United States Trust Company of New York, as trustee, RWG Energy, Inc., WG
Operating, Inc., WG Royalty Company, Wise County Construction Company, LLC, and WG Pipeline LLC, as
Additional Subsidiary Guarantors.
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(8) [4.6.4] |
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10.1
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Form of Stock Escrow Agreement between the Registrant, Continental Stock Transfer & Trust Company
and the Initial Stockholders.
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(2) [10.6] |
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10.2
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Form of Registration Rights Agreement among the Registrant and the Initial Stockholders.
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(2) [10.9] |
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10.2.1
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Amendment to Registration Rights Agreement among this Registrant and the Founders dated May 8, 2006.
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(1) [10.9.1] |
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10.3
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Agreement and Plan of Merger dated October 20, 2005 among Registrant, RAM Acquisition, Inc., RAM
Energy, Inc. and the Stockholders of RAM Energy, Inc.
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(3) [10.11] |
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10.3.1
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Amendment No. 1, dated November 11, 2005, to Agreement and Plan of Merger dated October 20, 2005
among the Registrant, RAM Acquisition, Inc., RAM Energy, Inc. and the Stockholders of RAM Energy,
Inc.
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(4) [10.11] |
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10.3.2
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Amendment No. 2, dated February 15, 2006, to Agreement and Plan of Merger dated October 20, 2005
among the Registrant, RAM Acquisition, Inc., RAM Energy, Inc. and the Stockholders of RAM Energy,
Inc.
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(6) [10.11] |
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10.4
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Voting Agreement dated October 20, 2005 among the Registrant, the stockholders of RAM Energy, Inc. and certain security holders of
the Registrant.
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(3) [10.2] |
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10.4.1
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Second Amended and Restated Voting Agreement included as Annex D of the Registrants Definitive Proxy Statement (No. 000-50682),
dated April 10, 2006 and incorporated by reference herein.
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(5) [Annex D] |
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10.5
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Lock-Up Agreement dated October 20, 2005 executed by the stockholders of RAM Energy, Inc.
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(3) [10.4] |
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10.6
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Employment Agreement between Registrant and Larry E. Lee dated May 8, 2006.*
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(1) [10.15] |
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10.6.1
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First Amendment to Employment Agreement between Registrant and Larry E. Lee dated
October 18, 2006. *
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(9) [10.1] |
31
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10.6.2
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Second Amendment to Employment Agreement of Larry E. Lee dated February 25, 2008.*
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(17) [10.6.2] |
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10.6.3
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Third Amendment to Employment Agreement of Larry E. Lee, dated December 30, 2008.*
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(20) [10.6.3] |
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10.6.4
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Fourth Amendment to Employment Agreement of Larry E. Lee dated March 24, 2009.*
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(21) [10.6.4] |
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10.7
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Escrow Agreement by and among the Registrant, Larry E. Lee and Continental Stock
Transfer & Trust Company dated May 8, 2006.
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(1) [10.16] |
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10.8
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Registration Rights Agreement among Registrant and the investors signatory thereto dated May 8, 2006.*
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(1) [10.17] |
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10.9
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Form of Registration Rights Agreement among the Registrant and the Investors party thereto.
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(3) [10.17] |
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10.10
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Agreement between RAM and Shell Trading-US dated February 1, 2006.
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(1) [10.22] |
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10.11
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Agreement between RAM and Targa dated January 30, 1998.
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(1) [10.23] |
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10.11.1
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Amendment to Agreement between RAM Energy and Targa dated effective as of April 1, 2006, filed as an
exhibit to Registrants Form 8-K dated June 5, 2006 and incorporated by reference herein.
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(10) [10.23.1] |
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10.12
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Long-Term Incentive Plan of the Registrant. Included as Annex C of the Registrants Definitive Proxy
Statement (No. 000-50682), dated April 12, 2006 and incorporated by reference herein.*
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(5) [Annex C] |
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10.12.1
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First Amendment to RAM Energy Resources, Inc. 2006 Long-Term Incentive Plan effective May 8, 2008.*
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(18) [Exhibit A] |
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10.13
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Third Amended and Restated Loan Agreement dated as of April 3, 2006, between RAM Energy, Inc., the
lenders described therein, Guggenheim Corporate Funding, LLC as the Arranger and Administrative
Agent, Wells Fargo Foothill, Inc., as the Documentation Agent, and WESTLB AG, New York Branch, as the
Syndication Agent.
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(11) [10.14] |
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10.13.1
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First Amendment to Third Amended and Restated Loan Agreement between RAM Energy, Inc., the lenders
described therein, Guggenheim Corporate Funding, LLC, as the Arranger and Administrative Agent, Wells
Fargo Foothill, Inc., as the Documentation Agent, and WEST LB AG, New York Branch, as the Syndication
Agent, dated as of August 8, 2007.
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(14) [10.13.1] |
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10.14
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Deferred Bonus Compensation Plan of RAM Energy, Inc. dated as of April 21, 2004.*
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(12) [10.14] |
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10.15
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Purchase and Sale Agreement dated May 10, 2007 between Layton Enterprises, Inc. and the Registrant
(exhibits and schedules intentionally omitted).
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(14) [10.15] |
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10.16
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Agreement and Plan of Merger dated October 16, 2007 among RAM Energy Resources Corporation, Ascent
Energy Inc. and Ascent Acquisition Corp.
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(15) [2.1] |
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10.17
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Loan Agreement dated November 29, 2007, by and between RAM Energy Resources, Inc., as Borrower, and
Guggenheim Corporate Funding, LLC, as the Arranger and Administrative Agent, Wells Fargo Foothill,
Inc., as the Documentation Agent and WestLB AG, New York Branch and CIT Capital USA Inc., as the
Co-Syndication Agents, and the financial institutions named therein as the Lenders.
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(16) [10.1] |
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10.17.1
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First Amendment to Loan Agreement dated November 29, 2007, by and between RAM Energy Resources, Inc.,
as Borrower, and Guggenheim Corporate Funding, LLC, as the Arranger and Administrative Agent, Wells
Fargo Foothill, Inc., as the Documentation Agent and WestLB AG, New York Branch and CIT Capital USA
Inc., as the Co-Syndication Agents, and the financial institutions named therein as the Lenders.
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(22) [10.17.1] |
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10.17.2
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Second Amendment to Loan Agreement dated November 29, 2007, by and between RAM Energy Resources, Inc.,
as Borrower, and Guggenheim Corporate Funding, LLC, as the Arranger and Administrative Agent, Wells
Fargo Foothill, Inc., as the Documentation Agent and WestLB AG, New York Branch and CIT Capital USA
Inc., as the Co-Syndication Agents, and the financial institutions named therein as the Lenders.
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(23)[10.17.2] |
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10.18
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Description of Compensation Arrangement with G. Les Austin.*
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(19) [10.18] |
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10.18.1
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First Amendment to Employment Agreement of G. Les Austin, dated December 30, 2008.*
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(20) [10.18.1] |
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10.19
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Change in Control Separation Benefit Plan of RAM Energy Resources, Inc. and Participating Subsidiaries.*
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(22) [10.19] |
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31.1
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Rule 13(A) 14(A) Certification of our Principal Executive Officer.
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** |
32
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31.2
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Rule 13(A) 14(A) Certification of our Principal Financial Officer.
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** |
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32.1
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Section 1350 Certification of our Principal Executive Officer.
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** |
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32.2
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Section 1350 Certification of our Principal Financial Officer.
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** |
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* |
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Management contract or compensatory plan or arrangement. |
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** |
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Filed herewith. |
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(1) |
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Filed as an exhibit to the Registrants Current Report on Form 8-K
filed on May 12, 2006, as the exhibit number indicated in brackets and
incorporated by reference herein. |
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(2) |
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Filed as an exhibit to the Registrants Registration Statement on Form
S-1 (SEC File No. 333-113583) as the exhibit number indicated in
brackets and incorporated by reference herein. |
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(3) |
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Filed as an exhibit to the Registrants Current Report on Form 8-K
filed on October 26, 2005, as the exhibit number indicated in brackets
and incorporated by reference herein. |
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(4) |
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Filed as an exhibit to the Registrants Current Report on Form 8-K
filed on November 14, 2005, as the exhibit number indicated in
brackets and incorporated by reference herein. |
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(5) |
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Included as an annex to the Registrants Definitive Proxy Statement
(No. 000-50682), dated April 12, 2006, as the annex letter indicated
in brackets and incorporated by reference herein. |
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(6) |
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Filed as an exhibit to the Registrants Current Report on Form 8-K
filed on February 21, 2006, as the exhibit number indicated in
brackets and incorporated by reference herein. |
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(7) |
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Filed as an exhibit to the Registration Statement on Form S-1 (SEC
File No. 333-42641) of RAM Energy, Inc., as the exhibit number
indicated in brackets and incorporated by reference herein. |
|
(8) |
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Filed as an exhibit to the Registrants Quarterly Report on Form 10-Q
filed on August 14, 2006, as the exhibit number indicated in brackets
and incorporated by reference herein. |
|
(9) |
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Filed as an exhibit to the Registrants Current Report on Form 8-K on
October 20, 2006, as the exhibit number indicated in brackets and
incorporated by reference herein. |
|
(10) |
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Filed as an exhibit to the Registrants Current Report on Form 8-K on
June 5, 2006, as the exhibit number indicated in brackets and
incorporated by reference herein. |
|
(11) |
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Filed as an exhibit to Registrants amended Quarterly Report on Form
10-Q/A filed on December 20, 2006, as the exhibit number indicated in
brackets and incorporated by reference herein. |
|
(12) |
|
Filed as an exhibit to the Registrants Registration Statement on
Form S-1 (SEC File No. 333-138922) as the exhibit number indicated in
brackets and incorporated by reference herein. |
|
(13) |
|
Filed as an exhibit to the Registrants Current Report on Form 8-K
filed on February 2, 2007, as the exhibit number indicated in
brackets and incorporated by reference herein. |
|
(14) |
|
Filed as an exhibit to the Registrants Quarterly Report on Form 10-Q
filed on August 10, 2007, as the exhibit number indicated in brackets
and incorporated by reference herein. |
|
(15) |
|
Filed as an exhibit to Registrants Form 8-K dated October 18, 2007
as the exhibit number indicated in brackets and incorporated by
reference herein. |
|
(16) |
|
Filed as an exhibit to Registrants Form 8-K dated November 29, 2007
as the exhibit number indicated in brackets and incorporated by
reference herein. |
|
(17) |
|
Filed as an exhibit to Registrants Form 8-K dated February 26, 2008 as the exhibit number indicated in brackets and incorporated by reference
herein. |
|
(18) |
|
Filed as an exhibit to Registrants Definitive Proxy Statement (No. 000-50682) dated April 14, 2008, as the exhibit number indicated in the
brackets and incorporated herein by reference. |
|
(19) |
|
Filed as an exhibit to the Registrants Quarterly Report on Form 10-Q filed on May 9, 2008, as the exhibit number indicated in brackets and
incorporated by reference herein. |
|
(20) |
|
Filed as an exhibit to Registrants Form 8-K filed January 5, 2009 as the exhibit number indicated in brackets and incorporated by reference herein. |
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(21) |
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Filed as an exhibit to Registrants Form 8-K filed March 25, 2009 as the exhibit number indicated in brackets and incorporated by reference herein. |
|
(22) |
|
Filed as an exhibit to Registrants Annual Report on Form 10-K filed on March 12, 2009 as the exhibit number indicated in brackets and incorporated
by reference herein. |
|
(23) |
|
Filed as an exhibit to Registrants Form 8-K filed July 2, 2009 as the exhibit number indicated in brackets and incorporated by reference herein. |
33