Edgar Filing: RAM ENERGY RESOURCES INC

e10vq

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2009


o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number: 000-50682

RAM Energy Resources, Inc.

(Exact name of registrant as specified in its charter)


Delaware (State or other jurisdiction of incorporation or organization)		1311 (Primary Standard Industrial Classification Code Number)		20-0700684 (I.R.S. Employer Identification Number)

5100 East Skelly Drive, Suite 650, Tulsa, OK 74135
(Address of principal executive offices)

(918) 663-2800
(Registrant’s 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 Registrant’s Common Stock were outstanding.

Third Quarter 2009 Form 10-Q Report

TABLE OF CONTENTS


		Page

	PART I – FINANCIAL INFORMATION

ITEM 1.	FINANCIAL STATEMENTS (unaudited)		3

	Condensed Consolidated Balance Sheets – September 30, 2009 and December 31, 2008		3

	Condensed Consolidated Statements of Operations - Three and Nine Months Ended September 30, 2009 and 2008		4

	Condensed Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2009 and 2008		5

	Notes to Condensed Consolidated Financial Statements		6

ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		12

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		22

ITEM 4.	CONTROLS AND PROCEDURES		23

	PART II - OTHER INFORMATION		24

ITEM 1.	LEGAL PROCEEDINGS		24

ITEM 1A.	RISK FACTORS		25

ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS		26

ITEM 3.	DEFAULTS UPON SENIOR SECURITIES		26

ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS		26

ITEM 5.	OTHER INFORMATION		26

ITEM 6.	EXHIBITS		27

	SIGNATURES		30

ITEM 1 – FINANCIAL STATEMENTS

RAM Energy Resources, Inc.
Condensed Consolidated Balance Sheets
(in thousands, except share and per share amounts)


	September 30,			December 31,
	2009			2008
	(unaudited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	116		$	164
Cash, restricted		-			16,000
Accounts receivable:
Oil and natural gas sales, net of allowance of $50 ($50 at December 31, 2008)		11,141			8,702
Joint interest operations, net of allowance of $515 ($515 at December 31, 2008)		795			818
Other, net of allowance of $35 ($35 at December 31, 2008)		1,329			4,045
Derivative assets		1,012			21,006
Prepaid expenses		1,568			2,330
Deferred tax asset		3,705			-
Other current contingencies		-			2,816
Other current assets		4,083			4,141

Total current assets		23,749			60,022
PROPERTIES AND EQUIPMENT, AT COST:
Proved oil and natural gas properties and equipment, using full cost accounting		699,162			683,341
Other property and equipment		9,237			9,460

		708,399			692,801
Less accumulated depreciation, amortization and impairment		(478,839	)		(396,301	)

Total properties and equipment		229,560			296,500
OTHER ASSETS:
Deferred tax asset		48,823			28,724
Derivative assets		-			4,531
Deferred loan costs, net of accumulated amortization of $2,402 ($1,282 at December 31, 2008)		5,219			4,015
Other		1,969			2,053

Total assets	$	309,320		$	395,845

LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
CURRENT LIABILITIES:
Accounts payable:
Trade	$	13,390		$	26,370
Oil and natural gas proceeds due others		8,015			7,218
Other		27			982
Accrued liabilities:
Compensation		1,760			2,893
Interest		2,889			865
Franchise taxes		942			1,300
Income taxes		224			399
Contingencies		-			16,000
Deferred income taxes		-			5,779
Asset retirement obligations		1,043			1,093
Long-term debt due within one year		142			160

Total current liabilities		28,432			63,059
OIL & NATURAL GAS PROCEEDS DUE OTHERS		1,740			2,523
DERIVATIVE LIABILITIES		936			-
LONG-TERM DEBT		250,285			250,536
ASSET RETIREMENT OBLIGATIONS		30,430			29,106
COMMITMENTS AND CONTINGENCIES		900			900

STOCKHOLDERS’ EQUITY (DEFICIT):
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		8			8
Additional paid-in capital		222,432			220,800
Treasury stock - 3,783,087 shares (891,440 shares at December 31,2008) at cost		(6,167	)		(4,027	)
Accumulated deficit		(219,676	)		(167,060	)

Stockholders’ equity (deficit)		(3,403	)		49,721

Total liabilities and stockholders’ equity (deficit)	$	309,320		$	395,845

The accompanying notes are an integral part of these condensed consolidated financial statements.

RAM Energy Resources, Inc.
Condensed Consolidated Statements of Operations
(in thousands, except share and per share amounts)
(unaudited)


	Three months ended September 30,						Nine months ended September 30,
	2009			2008			2009			2008
REVENUES AND OTHER OPERATING INCOME:
Oil and natural gas sales
Oil	$	18,276		$	34,483		$	45,740		$	100,127
Natural gas		4,607			13,980			15,564			40,207
NGLs		2,999			5,729			7,134			14,945
Realized gains (losses) on derivatives		483			(5,054	)		19,032			(14,590	)
Unrealized gains (losses) on derivatives		(1,283	)		34,302			(26,085	)		(4,765	)
Other		49			69			177			280

Total revenues and other operating income		25,131			83,509			61,562			136,204

OPERATING EXPENSES:
Oil and natural gas production taxes		1,320			3,070			3,119			8,840
Oil and natural gas production expenses		9,772			9,727			28,976			28,507
Depreciation and amortization		7,304			10,955			23,808			32,757
Accretion expense		513			552			1,449			1,630
Impairment		-			-			58,929			-
Share-based compensation		539			602			1,632			2,081
General and administrative, overhead and other expenses, net of operator’s overhead fees		4,247			4,962			12,337			16,018

Total operating expenses		23,695			29,868			130,250			89,833

Operating income (loss)		1,436			53,641			(68,688	)		46,371

OTHER INCOME (EXPENSE):
Interest expense		(5,561	)		(4,817	)		(12,770	)		(19,176	)
Interest income		40			38			69			186
Other income (expense)		10			(6,733	)		(529	)		(7,087	)

EARNINGS (LOSS) BEFORE INCOME TAXES		(4,075	)		42,129			(81,918	)		20,294
INCOME TAX PROVISION (BENEFIT)		(1,358	)		13,641			(29,302	)		(1,809	)

Net earnings (loss)	$	(2,717	)	$	28,488		$	(52,616	)	$	22,103


BASIC EARNINGS (LOSS) PER SHARE	$	(0.04	)	$	0.37		$	(0.70	)	$	0.32

BASIC WEIGHTED AVERAGE SHARES OUTSTANDING		74,505,534			76,972,191			75,487,262			68,482,312


DILUTED EARNINGS (LOSS) PER SHARE	$	(0.04	)	$	0.37		$	(0.70	)	$	0.32

DILUTED WEIGHTED AVERAGE SHARES OUTSTANDING		74,505,534			77,287,370			75,487,262			68,788,850

The accompanying notes are an integral part of these condensed consolidated financial statements.

RAM Energy Resources, Inc.
Condensed Consolidated Statements of Cash Flows
(in thousands)
(unaudited)


	Nine months ended September 30,
	2009			2008
OPERATING ACTIVITIES:
Net income (loss)	$	(52,616	)	$	22,103
Adjustments to reconcile net income (loss) to net cash provided by operating activities-
Depreciation and amortization		23,808			32,757
Amortization of deferred loan costs and Senior Notes discount		1,120			899
Non-cash interest		829			-
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		89			174
Other expense		448			6,917
Changes in operating assets and liabilities
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.

RAM Energy Resources, Inc.

Notes to unaudited condensed consolidated financial statements


A –		SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES, ORGANIZATION AND BASIS OF PRESENTATION


1.		*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 Company’s consolidated financial statements for the year ended December 31, 2008, for an expanded discussion of the Company’s financial disclosures and accounting policies.


2.		*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.


3.		*Use of Estimates*

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 Company’s 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.


4.		*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):


	Three months ended September 30,					Nine months ended September 30,
	2009			2008		2009			2008

Net income (loss)	$	(2,717	)	$	28,488	$	(52,616	)	$	22,103

Weighted average shares - basic		74,505,534			76,972,191		75,487,262			68,482,312
Dilutive effect of unvested stock grants		-			315,179		-			306,538

Weighted average shares – dilutive		74,505,534			77,287,370		75,487,262			68,788,850

Basic earnings (loss) per share	$	(0.04	)	$	0.37	$	(0.70	)	$	0.32

Diluted earnings (loss) per share	$	(0.04	)	$	0.37	$	(0.70	)	$	0.32


5.		*Subsequent Events*

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.


6.		*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 Company’s financial position or results of operations. However, as a result of the Company’s 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 Company’s 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 entity’s financial position, financial performance, and cash flows. Adoption of the guidance on January 1, 2009 required enhanced disclosures about the Company’s 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 Company’s financial position or results of operations.

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 Company’s 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 SEC’s revised rule, Modernization of Oil and Gas Reporting. The public comment period for the FASB’s 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.


B –		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 Company’s oil and natural gas properties exceeded the Ceiling Limitation resulting in a reduction in the carrying value of the Company’s 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 Company’s oil and natural gas properties did not exceed the Ceiling Limitation.


C –		LONG-TERM DEBT

Long-term debt consists of the following (in thousands):


	September 30,		December 31,
	2009		2008
Credit facility	$	249,963	$	250,387
Accrued payment-in-kind interest		252		-
Installment loan agreements		212		309

		250,427		250,696
Less amount due within one year		142		160

	$	250,285	$	250,536

Credit Facility

In November 2007, in conjunction with the Company’s 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

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 Energy’s 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 Company’s 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 Company’s 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.


D –		CAPITAL STOCK

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 Company’s 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 Company’s common stock and two warrants. All of the unit purchase options expired unexercised.


E –		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 plaintiff’s 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 Company’s 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

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 Company’s financial position or results of operations.


F –		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 Company’s 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 Company’s financials approximates fair value due to their short-term nature. Additionally, the carrying value of the Company’s 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.


G –		DERIVATIVE CONTRACTS

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 Company’s 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.

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 counterparty’s bond rate and published bond rates.

Gross fair values of the Company’s 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


		Fair Value
		As of
		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		(2,610	)
Long-Term Liabilities - Derivative liabilities	Long-Term Liabilities - Derivative liabilities		(1,295	)

Total Derivatives Not Designated as Hedging Instruments		$	76

CONSOLIDATED STATEMENTS OF OPERATIONS


	Three Months Ended September 30,						Nine Months Ended September 30,
Location	2009			2008			2009			2008

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 Company’s 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 grantee’s 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.

ITEM 2 – MANAGEMENT’S 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 Texas—Starr, Wharton and Duval Counties, Texas (Developing Fields);

	•		Electra/Burkburnett—Wichita 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 Shale—Jack 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 Shale—Cabell and Mason Counties, West Virginia. We own leasehold interests in approximately 60,313 gross (49,101 net) acres (Developing Field); and

	•		North Texas Barnett Shale—Bosque 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).

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

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.


	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.

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.

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.

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.

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 Energy’s 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.

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.

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.

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.

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.

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.

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 earth’s 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 Court’s 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. EPA’s 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 Congress’s adoption of greenhouse gas legislation and, or, EPA’s 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.

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

None.

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 Registrant’s 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]


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 Registrant’s 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 Registrant’s 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.	**


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 Registrant’s 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 Registrant’s 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 Registrant’s 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 Registrant’s 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 Registrant’s 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 Registrant’s 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 Registrant’s 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 Registrant’s 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 Registrant’s 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 Registrant’s 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 Registrant’s 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 Registrant’s 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 Registrant’s 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 Registrant’s 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 Registrant’s 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 Registrant’s 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 Registrant’s 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 Registrant’s 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 Registrant’s Form 8-K filed January 5, 2009 as the exhibit number indicated in brackets and incorporated by reference herein.

(21)		Filed as an exhibit to Registrant’s 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 Registrant’s 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 Registrant’s Form 8-K filed July 2, 2009 as the exhibit number indicated in brackets and incorporated by reference herein.

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.


	RAM ENERGY RESOURCES, INC.
November 5, 2009	By: /s/ Larry E. Lee
	Name: Larry E. Lee
	Title: Chairman, President and Chief Executive Officer


November 5, 2009	By: /s/ G. Les Austin
	Name: G. Les Austin
	Title: Senior Vice President and Chief Financial Officer

INDEX TO 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 Registrant’s 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]

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 Registrant’s 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 Registrant’s 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.	**

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 Registrant’s 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 Registrant’s 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 Registrant’s 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 Registrant’s 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 Registrant’s 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 Registrant’s 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 Registrant’s 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 Registrant’s 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 Registrant’s 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 Registrant’s 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 Registrant’s 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 Registrant’s 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 Registrant’s 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 Registrant’s 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 Registrant’s 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 Registrant’s 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 Registrant’s 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 Registrant’s 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 Registrant’s Form 8-K filed January 5, 2009 as the exhibit number indicated in brackets and incorporated by reference herein.

(21)		Filed as an exhibit to Registrant’s 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 Registrant’s 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 Registrant’s Form 8-K filed July 2, 2009 as the exhibit number indicated in brackets and incorporated by reference herein.

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents