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

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

Commission File Number: 000-50682

RAM Energy Resources, Inc.

(Exact name of registrant as specified in its charter)

Delaware		1311		20-0700684
(State or other jurisdiction of		(Primary Standard Industrial		(I.R.S. Employer Identification
incorporation or organization)		Classification Code Number)		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		Smaller Reporting Company o
				(Do not check if a smaller reporting company)

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 May 5, 2011, 78,353,803 shares of the Registrant’s Common Stock were outstanding.

 

 

First Quarter 2011 Form 10-Q Report

TABLE OF CONTENTS

		Page
PART I — FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS (unaudited)			3
Condensed Consolidated Balance Sheets — March 31, 2011 and December 31, 2010			3
Condensed Consolidated Statements of Operations — Three Months Ended March 31, 2011 and 2010			4
Condensed Consolidated Statements of Cash Flows — Three Months Ended March 31, 2011 and 2010			5
Notes to Condensed Consolidated Financial Statements			6
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			13
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			20
ITEM 4. CONTROLS AND PROCEDURES			21
PART II — OTHER INFORMATION			22
ITEM 1. LEGAL PROCEEDINGS			22
ITEM 1A. RISK FACTORS			22
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS			22
ITEM 3. DEFAULTS UPON SENIOR SECURITIES			22
ITEM 4. [RESERVED]			22
ITEM 5. OTHER INFORMATION			22
ITEM 6. EXHIBITS			23
SIGNATURES			27

ITEM 1 — FINANCIAL STATEMENTS

RAM Energy Resources, Inc.

Condensed Consolidated Balance Sheets
(In thousands, except share and per share amounts)

		March 31,				December 31,
		2011				2010
		(unaudited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	42			$	37
Accounts receivable:
Oil and natural gas sales, net of allowance of $50 ($50 at December 31, 2010)			10,631				9,797
Joint interest operations, net of allowance of $479 ($479 at December 31, 2010)			624				631
Other, net of allowance of $34 ($48 at December 31, 2010)			169				155
Derivative assets			—				1,340
Prepaid expenses			1,133				1,657
Deferred tax asset			5,786				3,526
Inventory			3,491				3,382
Other current assets			229				4
Total current assets			22,105				20,529
PROPERTIES AND EQUIPMENT, AT COST:
Proved oil and natural gas properties and equipment, using full cost accounting			694,759				689,472
Other property and equipment			10,203				10,072
			704,962				699,544
Less accumulated depreciation, amortization and impairment			(494,820	)			(489,634	)
Total properties and equipment			210,142				209,910
OTHER ASSETS:
Deferred tax asset			33,881				31,001
Derivative assets			124				—
Deferred loan costs, net of accumulated amortization of $53 ($5,012 at December 31, 2010)			6,659				2,609
Other			991				952
Total assets		$	273,902			$	265,001
LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
CURRENT LIABILITIES:
Accounts payable:
Trade		$	14,566			$	17,149
Oil and natural gas proceeds due others			9,039				9,414
Other			239				452
Accrued liabilities:
Compensation			1,716				1,948
Interest			563				2,448
Income taxes			784				699
Other			10				10
Derivative liabilities			7,101				—
Asset retirement obligations			536				639
Long-term debt due within one year			136				127
Total current liabilities			34,690				32,886
DERIVATIVE LIABILITIES			7,778				203
LONG-TERM DEBT			205,240				196,965
ASSET RETIREMENT OBLIGATIONS			31,173				30,770
OTHER LONG-TERM LIABILITIES			10				10
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS’ EQUITY (DEFICIT):
Common stock, $0.0001 par value, 100,000,000 shares authorized, 82,566,579 and 82,597,829 shares issued, 78,333,803 and 78,386,983 shares outstanding at March 31, 2011 and December 31, 2010, respectively			8				8
Additional paid-in capital			226,840				226,042
Treasury stock - 4,232,776 shares (4,210,846 shares at December 31, 2010) at cost			(7,019	)			(6,976	)
Accumulated deficit			(224,818	)			(214,907	)
Stockholders’ equity (deficit)			(4,989	)			4,167
Total liabilities and stockholders’ equity (deficit)		$	273,902			$	265,001

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 March 31,
		2011				2010
REVENUES AND OTHER OPERATING INCOME:
Oil and natural gas sales
Oil		$	20,412			$	19,488
Natural gas			2,892				6,429
NGLs			2,415				3,931
Total oil and natural gas sales			25,719				29,848
Realized gains (losses) on derivatives			836				(898	)
Unrealized gains (losses) on derivatives			(14,953	)			1,935
Other			51				36
Total revenues and other operating income			11,653				30,921
OPERATING EXPENSES:
Oil and natural gas production taxes			1,411				1,594
Oil and natural gas production expenses			8,375				7,920
Depreciation and amortization			5,273				6,714
Accretion expense			402				382
Share-based compensation			669				686
General and administrative, overhead and other expenses, net of operator’s overhead fees			3,878				3,770
Total operating expenses			20,008				21,066
Operating income (loss)			(8,355	)			9,855
OTHER INCOME (EXPENSE):
Interest expense			(6,550	)			(5,635	)
Interest income			—				2
Loss on interest rate derivatives			(133	)			—
Other income (expense)			48				(9	)
INCOME (LOSS) BEFORE INCOME TAXES			(14,990	)			4,213
INCOME TAX PROVISION (BENEFIT)			(5,079	)			1,795
Net income (loss)		$	(9,911	)		$	2,418
BASIC INCOME (LOSS) PER SHARE		$	(0.13	)		$	0.03
BASIC WEIGHTED AVERAGE SHARES OUTSTANDING			78,359,996				77,997,063
DILUTED INCOME (LOSS) PER SHARE		$	(0.13	)		$	0.03
DILUTED WEIGHTED AVERAGE SHARES OUTSTANDING			78,359,996				77,997,063

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)

		Three months ended March 31,
		2011				2010
OPERATING ACTIVITIES:
Net income (loss)		$	(9,911	)		$	2,418
Adjustments to reconcile net income (loss) to net cash provided by operating activities-
Depreciation and amortization			5,273				6,714
Amortization of deferred loan costs			2,662				522
Non-cash interest			362				765
Accretion expense			402				382
Unrealized (gain) loss on commodity derivatives, net of premium amortization			15,870				(967	)
Unrealized loss on interest rate derivatives			122				—
Deferred income tax provision (benefit)			(5,140	)			1,554
Share-based compensation			669				686
Gain on disposal of other property, equipment and subsidiary			(17	)			(23	)
Changes in operating assets and liabilities, net of acquisitions-
Accounts receivable			(841	)			840
Prepaid expenses, inventory and other assets			152				272
Derivative premiums			(111	)			(990	)
Accounts payable and proceeds due others			(3,155	)			(3,650	)
Accrued liabilities and other			(2,107	)			(888	)
Income taxes payable			85				177
Asset retirement obligations			(111	)			—
Total adjustments			14,115				5,394
Net cash provided by operating activities			4,204				7,812
INVESTING ACTIVITIES:
Payments for oil and natural gas properties and equipment			(5,620	)			(7,821	)
Proceeds from sales of oil and natural gas properties			462				458
Payments for other property and equipment			(219	)			(254	)
Proceeds from sales of other property and equipment			11				4
Net cash used in investing activities			(5,366	)			(7,613	)
FINANCING ACTIVITIES:
Payments on long-term debt			(216,142	)			(10,034	)
Proceeds from borrowings on long-term debt			224,064				10,131
Payments for deferred loan costs			(6,712	)			—
Stock repurchased			(43	)			(324	)
Net cash provided by (used in) financing activities			1,167				(227	)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS			5				(28	)
CASH AND CASH EQUIVALENTS, beginning of period			37				129
CASH AND CASH EQUIVALENTS, end of period		$	42			$	101
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash (received) paid for income taxes		$	(23	)		$	64
Cash paid for interest		$	5,355			$	4,347
DISCLOSURE OF NON CASH INVESTING AND FINANCING ACTIVITIES:
Asset retirement obligations		$	5			$	35

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 March 31, 2011 and December 31, 2010 and the results of operations and cash flows for the three month periods ended March 31, 2011 and 2010 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 months ended March 31, 2011 are not necessarily indicative of the results to be expected for the full year ending December 31, 2011. Reference is made to the Company’s consolidated financial statements for the year ended December 31, 2010 included in the Company’s Annual Report on Form 10-K, 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, Oklahoma and Louisiana. We also own and operate oil and natural gas properties in New Mexico, Mississippi 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. Income (Loss) per Common Share

     Basic and diluted income (loss) per share is computed by dividing net income (loss) by the weighted average number of common shares outstanding for the period. A reconciliation of net income (loss) and weighted average shares used in computing basic and diluted net income (loss) per share are as follows (in thousands, except share and per share amounts):

		Three months ended March 31,
		2011				2010
		(unaudited)
Net income (loss)		$	(9,911	)		$	2,418
Weighted average shares — basic			78,359,996				77,997,063
Dilutive effect			—				—
Weighted average shares — dilutive			78,359,996				77,997,063
Basic income (loss) per share		$	(0.13	)		$	0.03
Diluted income (loss) per share		$	(0.13	)		$	0.03

5. Subsequent Events

     The Company evaluates events and transactions that occur after the balance sheet date but before the financial statements are filed with the U.S. Securities and Exchange Commission (“SEC”).

6. New Accounting Pronouncements

     In December 2010, the Financial Accounting Standards Board issued an update to authoritative guidance, as set forth in Topic 805 of the Accounting Standards Codification™ (the “Codification”), relating to business combinations. This update provides clarification requiring public companies that have completed material acquisitions to disclose the revenue and earnings of the combined business as if the acquisition took place at the beginning of the comparable prior annual reporting period, and also expands the supplemental pro forma disclosures to include a description of the nature and amount of material, non-recurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. The Company will be required to apply this guidance prospectively for business combinations for which the acquisition date is on or after January 1, 2011. The Company does not expect the adoption of this new guidance to have a material impact on its financial position or statement of operations.

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 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, 2011and 2010, 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):

		March 31,				December 31,
		2011				2010
		(unaudited)
Credit facilities		$	205,000			$	196,521
Accrued payment-in-kind interest			—				221
Installment loan agreements			376				350
			205,376				197,092
Less amount due within one year			136				127
		$	205,240			$	196,965

Credit Facilities

     Credit Facilities. In March 2011, the Company entered into new credit facilities. The new facilities, which replaced the Company’s previous facility, include a $250.0 million first lien revolving credit facility and a $75.0 million second lien term loan facility. SunTrust Bank is the administrative agent for the revolving facility, and Guggenheim Corporate Funding LLC is the agent for the term loan facility. The initial borrowing base under the revolving credit facility was $150.0 million. Funds advanced under the revolving credit facility may be paid down and re-borrowed during the five-year term of the revolver, and initially bear interest at LIBOR plus a margin ranging from 2.5% to 3.25% based on a percentage of usage. The term loan credit facility provides for payments of interest only during its 5.5-year term, with the initial interest rate being LIBOR plus 9.0% with a 2.0% LIBOR floor, or if in any period the Company elects to pay a portion of the interest under its term loan “in kind,” then the interest rate will be LIBOR plus 10.0% with a 2.0% LIBOR floor, and with 7.0% of the interest amount paid in cash and the remaining 3.0% paid in kind by being added to the principal. At March 31, 2011, $130.0 million was outstanding under the revolving credit facility and $75.0 million was outstanding under the term loan credit facility.

     Advances under the new facilities are secured by liens on substantially all properties and assets of the Company and its subsidiaries. The new credit facilities contain representations, warranties and covenants customary in transactions of this nature, including restrictions on the payment of dividends on our capital stock and financial covenants relating to current ratio, minimum interest coverage ratio, maximum leverage ratio and a required ratio of asset value to indebtedness. The Company was in compliance with all of its covenants in the credit facilities at March 31, 2011. The Company is required to maintain commodity hedges on a rolling basis for the first 12 months of not less than 60%, but not more than 85%, and for the next 18 months of not less than 50%, but not more than 85%, of projected quarterly production volumes, until the leverage ratio is less than or equal to 1.5 to 1.0.

     The Company’s previous credit facility entered into in November 2007, included a $500.0 million credit facility with Guggenheim Corporate Funding, LLC, for itself and on behalf of other institutional lenders. The facility included 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. Funds advanced under the revolving credit facility initially bore interest at LIBOR plus a margin ranging from 1.25% to 2.0% based on a percentage of usage. The term loan provided for payments of interest only during its term, with the initial interest rate being LIBOR plus 7.5%. The borrowing base under the revolving credit facility was $145.0 million at December 31, 2010.

     On June 26, 2009, the Company entered into the Second Amendment to the credit facility. The Second Amendment amended 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 term loans. Advances under the revolver bore 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 bore 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 was added to the term loan principal balance on a monthly basis and paid at maturity. The Company was in compliance with all of its covenants in the credit facility at December 31, 2010. At December 31, 2010, $116.5 million was outstanding under the revolving credit facility and $80.2 million was outstanding under the term facility, including $0.2 million accrued payment-in-kind interest. Due to refinancing of the Company’s outstanding debt prior to the issuance of the December 31, 2010 financial statements, the current portion of existing debt at December 31, 2010 was considered long-term. As previously noted, the Company entered into new credit facilities in March 2011. The proceeds from the new facilities were used to repay the previous facility. The Company expensed the remaining debt issuance cost associated with the previous facility totaling approximately $2.7 million in the quarter ended March 31, 2011.

     In 2010, the Company used $33.8 million in proceeds from asset sales to pay down the term facility and $24.0 million in proceeds from asset sales to pay down the revolving credit facility. Payment-in-kind interest of $3.0 million was added to the term facility in 2010, and $0.4 million was added to the term facility in the first quarter of 2011, bringing the balance of the term facility to $80.6 million at the date of the closing of the new credit facilities on March 14, 2011.

D — INCOME TAXES

     Under guidance contained in Topic 740 of the Codification, deferred taxes are determined by applying the provisions of enacted tax laws and rates for the jurisdictions in which the Company operates to the estimated future tax effects of the differences between the tax basis of assets and liabilities and their reported amounts in the Company’s financial statements. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.

     The Company estimates its annual effective income tax rate in recording its quarterly provision for income taxes in the various jurisdictions in which the Company operates. Statutory tax rate changes and other significant or unusual items are recognized as discrete items in the quarter in which they occur.

     The Company has calculated an estimated effective tax rate for the current annual reporting period, excluding any discrete items, of 34% as of March 31, 2011. The estimated annual rate differs from the statutory rate primarily due to the estimate of state income taxes and non-deductible expenses for the period. Based upon the estimated effective tax rate, the Company recorded an income tax benefit of $5.1 million on a pre-tax loss of $15.0 million for the three months ended March 31, 2011. For the three months ended March 31, 2010, the Company recorded income tax expense of $1.8 million on a pre-tax net income of $4.2 million, resulting in an effective tax rate of 43%.

E — COMMITMENTS AND CONTINGENCIES

     The Company is involved in 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. Topic 820 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. 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. The fair value of the Company’s net derivative liabilities as of March 31, 2011 was $14.8 million and the net derivative assets as of December 31, 2010 was $1.1 million, based on Level 2 criteria. See Note G.

     At March 31, 2011, the carrying value of cash, accounts receivables and accounts payables reflected in the Company’s consolidated financial statements approximates fair value due to their short-term nature. Additionally, the carrying value of the Company’s long-term debt under the credit facilities approximates fair value because the credit facilities carry 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 achieve a more predictable cash flow. Various derivative instruments are used to manage the price received for a portion of the Company’s future oil and natural gas production and interest rate swaps are used to manage the interest rate paid for a portion of the Company’s outstanding debt.

     During 2011 and 2010, 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 facilities. During 2011 the Company also entered into interest rate swaps to manage the impact of interest rate fluctuations. The Company did not designate these transactions as hedges. Accordingly, all gains and losses on the derivative instruments during 2011 and 2010 have been recorded in the statements of operations.

     The Company’s oil and natural gas derivative positions at March 31, 2011, 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
Year		Per Day				Price				Per Day				Price				Year				Per Day				Price				Per Day				Price
Q2’11			2,500			$	80.00				2,500			$	105.00				Q2’11				5,000			$	4.00				—				—
Q3’11			2,500			$	80.00				2,500			$	105.00				Q3’11				5,000			$	5.00				—				—
Q4’11			2,650			$	80.00				2,650			$	105.00				Q4’11				7,304			$	4.18				—				—
Q1’12			2,000			$	80.00				2,000			$	105.00				Q1'12				10,000			$	4.25				—				—
Q2’12			2,000			$	80.00				2,000			$	105.00				Q2’12				5,000			$	4.00				5,000			$	6.00
Q3’12			1,800			$	92.22				1,800			$	105.24				Q3’12				5,000			$	4.00				5,000			$	6.00
Q4’12			1,750			$	92.14				1,750			$	104.83				Q4’12				—				—				—				—
Q1’13			1,700			$	95.00				1,700			$	100.91				Q1’13				—				—				—				—
Q2’13			1,650			$	95.00				1,650			$	99.93				Q2’13				—				—				—				—
Q3’13			1,600			$	95.00				1,600			$	99.94				Q3’13				—				—				—				—
Q4’13			1,550			$	95.00				1,550			$	99.71				Q4’13				—				—				—				—
Q1’14			1,500			$	95.00				1,500			$	99.40				Q1’14				—				—				—				—
Q2’14			1,500			$	95.00				1,500			$	99.13				Q2’14				—				—				—				—

     The Company’s interest rate derivative positions at March 31, 2011, consisting of interest rate swaps, are shown in the following table:

Interest Rate Swaps (1)
		Notional
		Amount								Counterparty
Year		(in millions)				Fixed Rate				Floating Rate(2)				Months Covered
2011		$	50				2.51	%		3-Month LIBOR				April — December
2012		$	50				2.51	%		3-Month LIBOR				January — December
2013		$	50				2.51	%		3-Month LIBOR				January — December
2014		$	50				2.51	%		3-Month LIBOR				January — March

     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. The Company estimates the fair value of its derivatives using a pricing model which also considers market volatility, counterparty credit risk and additional criteria in determining discount rates. See Note F.

     To determine the fair value of the Company’s oil and natural gas derivative instruments, 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. The Company incorporates its credit risk when the derivative position is a liability by using its LIBOR spread rate.

     Gross fair values of the Company’s derivative instruments, prior to netting of assets and liabilities subject to a master netting arrangement, as of March 31, 2011 and December 31, 2010 and the consolidated statements of operations for the three months ended March 31, 2011 and 2010 are as follows (in thousands):

CONSOLIDATED BALANCE SHEETS

				Fair Value As of				Fair Value As of
				March 31,				December 31,
Gross Assets and Liabilities		Balance Sheet Location		2011				2010
				(unaudited)
Current Assets — Oil and natural gas derivative assets		Current Assets — Derivative assets		$	—			$	1,904
Current Assets — Oil and natural gas derivative assets		Current Liabilities — Derivative liabilities			625				—
Other Assets — Oil and natural gas derivative assets		Long-Term Liabilities — Derivative liabilities			—				207
Other Assets — Interest rate swaps derivative assets		Long-Term Assets — Derivative assets			124				—
Current Liabilities — Oil and natual gas derivative liabilities		Current Assets — Derivative assets			—				(564	)
Current Liabilities — Oil and natual gas derivative liabilities		Current Liabilities — Derivative liabilities			(7,469	)			—
Current Liabilities — Interest rate swaps derivative liabilities		Current Liabilities — Derivative liabilities			(257	)			—
Long-Term Liabilities — Oil and natural gas derivative liabilities		Long-Term Liabilities — Derivative liabilities			(7,778	)			(410	)
Total Derivatives Not Designated as Hedging Instruments				$	(14,755	)		$	1,137

CONSOLIDATED STATEMENTS OF OPERATIONS

		Three Months Ended March 31,
Income Statement Location		2011				2010				Type of Derivative
		(unaudited)
Revenue — Unrealized gains (losses) on derivatives		$	(14,953	)		$	1,935			Oil and natural gas derivatives — unrealized
Revenue — Realized gains (losses) on derivatives		$	836			$	(898	)		Oil and natural gas derivatives — realized
Other Income (Expense) — Loss on interest rate derivatives		$	(122	)		$	—			Interest rate derivatives — unrealized
Other Income (Expense) — Loss on interest rate derivatives		$	(11	)		$	—			Interest rate derivatives — realized

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. On May 3, 2010, the Plan was amended to increase the maximum authorized number of shares to be issued under the Plan from 6,000,000 to 7,400,000. As of March 31, 2011, a maximum of 1,991,521 shares of common stock remained reserved for issuance under the Plan.

     As of March 31, 2011, the Company had $4.3 million of unrecognized compensation related to awards granted under the Plan. That cost is expected to be recognized over a weighted-average period of two years. The related compensation recognized during the three months ended March 31, 2011 and 2010 was $0.8 million and $0.7 million, respectively. During the three months ended March 31, 2011, $0.7 million of recognized compensation was recorded as compensation expense and $0.1 million was recorded as capitalized internal costs.

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 development, acquisition, exploitation, exploration and production of oil and natural gas properties, primarily in Texas, Oklahoma and Louisiana. Our producing properties are located in highly prolific basins with long histories of oil and natural gas operations.

Principal Properties

     Our principal oil and natural gas properties are located in the following fields:

	•		Texas: La Copita (Starr County), Electra/Burkburnett (Wichita and Wilbarger Counties);
	•		Oklahoma: Fitts-Allen (Pontotoc and Seminole Counties); and
	•		Louisiana: Lake Enfermer (Lafourche Parish).

     We also own and operate other oil and natural gas properties in Texas, Oklahoma, Louisiana, New Mexico, Mississippi and West Virginia.

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 months ended March 31, 2011. 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
		March 31, 2011
Production volumes:
Oil (MBbls)			222
NGLs (MBbls)			47
Natural gas (MMcf)			710
Total (MBoe)			387
Average sale prices received:
Oil (per Bbl)		$	91.95
NGLs (per Bbl)		$	51.38
Natural gas (per Mcf)		$	4.07
Total per Boe		$	66.46
Cash effect of derivative contracts:
Oil (per Bbl)		$	(4.58	)
NGLs (per Bbl)		$	—
Natural gas (per Mcf)		$	2.61
Total per Boe		$	2.16
Average prices computed after cash effect of settlement of derivative contracts:
Oil (per Bbl)		$	87.37
NGLs (per Bbl)		$	51.38
Natural gas (per Mcf)		$	6.68
Total per Boe		$	68.62
Expenses (per Boe):
Oil and natural gas production taxes		$	3.65
Oil and natural gas production expenses		$	21.64
Amortization of full-cost pool		$	12.98
General and administrative		$	10.02
Cash interest		$	13.84
Cash taxes		$	(0.06	)

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 months ended March 31, 2011 (in thousands):

		Three
		months
		ended
		March 31,
		2011
Development and exploratory costs		$	5,396
Proved property acquisition costs			224
Total costs incurred		$	5,620

     During the quarter ended March 31, 2011, we participated in the drilling of 13 gross (10.3 net) development wells and two gross (2.0 net) exploration wells. Six gross (6.0 net) development wells were capable of production. Seven gross (4.3 net) development wells were either drilling, testing or waiting on completion as of March 31, 2011. One gross (1.0 net) exploration well was waiting on completion, and one gross (1.0 net) exploration well was drilling at March 31, 2011.

Results of Operations

Quarter Ended March 31, 2011 Compared to Quarter Ended March 31, 2010

     As we concentrate our holdings into areas that align with our objectives, we have determined to report our operations by state, rather than by field as was reported in previous years. The following tables summarize our oil and natural gas production volumes, average sale prices (without regard to derivative contract settlements) and period-to-period comparisons for the periods indicated:

		Texas				Oklahoma				Louisiana				Other				Total
Three Months Ended March 31, 2011
Aggregate Net Production
Oil (MBbls)			125				74				16				7				222
NGLs (MBbls)			41				3				—				3				47
Natural Gas (MMcf)			444				80				153				33				710
MBoe			240				90				42				15				387

		Texas				Oklahoma				Louisiana				Other				Total
Three Months Ended March 31, 2010
Aggregate Net Production
Oil (MBbls)			149				81				17				10				257
NGLs (MBbls)			92				3				—				3				98
Natural Gas (MMcf)			864				212				155				38				1,269
MBoe			385				119				43				19				566
Change in MBoe			(145	)			(29	)			(1	)			(4	)			(179	)
Percentage change in MBoe			-37.7	%			-24.4	%			-2.3	%			-21.1	%			-31.6	%

		Three months ended
		March 31,
		2011				2010				Increase
Average sale prices:
Oil (per Bbl)		$	91.95			$	75.83				21.3	%
NGL (per Bbl)		$	51.38			$	40.11				28.1	%
Natural gas (per Mcf)		$	4.07			$	5.07				(19.7	)%
Per Boe		$	66.46			$	52.73				26.0	%

          In December 2010, we sold assets located in Texas and Oklahoma for net proceeds including post-closing adjustments of $48.8 million. The following table provides pro forma results for 2010 excluding those sold properties to assist our description of results of operations:

		Three months ended March 31, 2010
						Sold
		Actual				Assets				Pro Forma
Oil and natural gas sales (in thousands):
Oil		$	19,488			$	331			$	19,157
Natural gas			6,429				1,630				4,799
NGLs			3,931				1,482				2,449
Total oil and natural gas sales		$	29,848			$	3,443			$	26,405
Production expenses (in thousands):
Oil and natural gas production taxes		$	1,594			$	128			$	1,466
Oil and natural gas production expenses		$	7,920			$	491			$	7,429
Production volumes:
Texas (Mboe)			385				85				300
Oklahoma (Mboe)			119				19				100
Other (Mboe)			62				—				62
Total production (Mboe)			566				104				462

          Oil and natural gas sales decreased $4.1 million, or 14%, to $25.7 million for the three months ended March 31, 2011, as compared to $29.8 million for the same period in 2010. Excluding asset sales, oil and natural gas sales would have decreased $0.7 million for the three months ended March 31, 2011, as compared to the same period in 2010. This decrease was driven by declines in production offset by higher commodity prices during the 2011 period.

          Production volumes decreased 32% as compared to the same period last year. Excluding the activities related to the asset divestitures, our production volume would have decreased 16% as compared to the same period last year primarily due to normal production declines and weather related problems in Oklahoma and Texas. Production from our Texas fields decreased 60 MBoe in the first quarter excluding asset sales due to a decline in well performance in our South Texas gas properties and from normal production declines. Drilling activity included six gross (6.0 net) development wells which were capable of production in our Texas fields. Production from our Oklahoma fields decreased 10 MBoe in the first quarter excluding asset sales primarily due to natural production declines. Drilling activity in Oklahoma included two gross (2.0 net) exploratory wells. Production from our Louisiana fields decreased one MBoe in the first quarter 2011 due to normal production declines. We did not drill any new wells in our Louisiana fields during the first quarter of 2011.

          The average realized sales prices on a Boe basis increased substantially for the three months ended March 31, 2011, as compared to the same period in 2010. The average realized sales price for oil was $91.95 per barrel for the three months ended March 31, 2011, an increase of 21%, compared to $75.83 per barrel for the same period in 2010. The average realized sales price for NGLs was $51.38 per barrel for the three

months ended March 31, 2011, an increase of 28%, compared to $40.11 per barrel for the same period in 2010. The average realized sales price for natural gas was $4.07 per Mcf for the three months ended March 31, 2011, a decrease of 20%, compared to $5.07 per Mcf for the same period in 2010. The positive impact from the 26% increase in total average price per Boe in the first quarter of 2011 did not fully offset the impact of asset sales and normal production declines, causing oil and natural gas sales for the first quarter to decline to $25.7 million compared to $29.8 million in the year-ago first quarter.

          We recorded loss before income taxes of $15.0 million for the quarter ended March 31, 2011, a decrease of $19.2 million, as compared to income before income taxes of $4.2 million for the quarter ended March 31, 2010. Excluding unrealized losses on derivatives of $15.1 million and debt extinguishment costs of $2.7 million, our adjusted income before income taxes for the quarter ended March 31, 2011 was $2.8 million. Excluding unrealized gains on derivatives of $1.9 million, our adjusted income before income taxes for the quarter ended March 31, 2010 was $2.3 million.

     Realized and Unrealized Gain (Loss) from Commodities Derivatives. For the quarter ended March 31, 2011, our loss from derivatives was $14.1 million, compared to a gain of $1.0 million for the quarter ended March 31, 2010. Our gains and losses during these periods were the net result of recording actual contract settlements, the premiums for our derivative contracts, and unrealized gains and losses attributable to mark-to-market values of our derivative contracts at the end of the periods.

		Three months ended
		March 31,
		2011				2010
		(in thousands)
Contract settlements and premium costs:
Oil		$	(1,017	)		$	(988	)
Natural gas			1,853				90
Realized gains (losses)			836				(898	)
Mark-to-market gains (losses):
Oil			(13,235	)			129
Natural gas			(1,718	)			1,806
Unrealized gains (losses)			(14,953	)			1,935
Realized and unrealized gains (losses)		$	(14,117	)		$	1,037

     Oil and Natural Gas Production Taxes. Our oil and natural gas production taxes were $1.4 million for the quarter ended March 31, 2011, compared to $1.5 million excluding asset sales for the comparable quarter of the previous year. Most production taxes 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 is due primarily to a reduction in oil and natural gas sales for the quarter ended March 31, 2011, compared to the same period during 2010. As a percentage of oil and natural gas sales, our oil and natural gas production taxes were approximately 5% for the quarter ended March 31, 2011 and 2010.

     Oil and Natural Gas Production Expense. Our oil and natural gas production expense was $8.4 million for the quarter ended March 31, 2011, an increase of $1.0 million, or 13%, from the $7.4 million excluding asset sales for the quarter ended March 31, 2010. The increase was due primarily to higher workover expenses during the quarter ended March 31, 2011 as compared to the 2010 period. Our oil and natural gas production expense was $21.64 per Boe compared to $13.99 per Boe for the quarter ended March 31, 2010, an increase of 55%. As a percentage of oil and natural gas sales, oil and natural gas production expense was 33% for the quarter ended March 31, 2011, as compared to 27% for the quarter ended March 31, 2010. This increase results from lower oil and natural gas sales caused by a decline in production in the 2011 period. Oil and natural gas production expense did not decline in proportion to assets sold in 2010 because the sold assets were predominantly shale gas producing assets which had relatively lower lease operating expenses.

     Amortization and Depreciation Expense. Our amortization and depreciation expense decreased $1.4 million, or 21%, for the quarter ended March 31, 2011, compared to the quarter ended March 31, 2010. The decrease was a result of a decrease in production during the 2011 period, offset by a higher depletion rate per Boe. On an equivalent basis, our amortization of the full-cost pool of $5.0 million was $12.98 per Boe for the quarter ended March 31, 2011, compared to $6.5 million, or $11.40 per Boe, for the quarter ended March 31, 2010.

     Accretion Expense. Topic 410 of the Codification, Accounting for Asset Retirement Obligations, 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 $0.4 million for each of the quarters ended March 31, 2011 and 2010.

     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 March 31, 2011, we recognized a total of $0.8 million share-based compensation compared to $0.7 million from the quarter ended March 31, 2010. The increase was primarily due to a higher number of shares outstanding in the 2011 period. During the three months ended March 31, 2011, $0.7 million of recognized compensation was recorded as compensation expense and $0.1 million was recorded as capitalized internal costs.

     General and Administrative Expense. For the quarter ended March 31, 2011, our general and administrative expense was $3.9 million, compared to $3.8 million for the quarter ended March 31, 2010, an increase of $0.1 million, or 3%. The increase results primarily from higher employee related fees offset by lower professional and office related costs in the 2011 period.

     Interest Expense. We recorded interest expense of $6.6 million for the quarter ended March 31, 2011, as compared to $5.6 million for the first quarter of the previous year. Of that $6.6 million, we incurred $2.7 million in debt extinguishment costs and $0.4 million in payment-in- kind interest related to our old credit facility in the first quarter of 2011. The decrease in interest expense was due to lower interest rates and lower average outstanding borrowings throughout the 2011 period. Our blended interest rate was 6.2% in the first quarter of 2011 compared to 8.1% in the 2010 period.

     Loss on Interest Rate Derivatives. We incurred $0.1 million net realized and unrealized loss attributable to mark-to-market value of interest rate swaps in the first quarter of 2011.

     Income Taxes. For the three months ended March 31, 2011, we recorded income tax benefit of $5.1 million on a pre-tax loss of $15.0 million. For the three months ended March 31, 2010, we recorded income tax expense of $1.8 million on a pre-tax net income of $4.2 million. Our effective tax rate for the three months ended March 31, 2011, was 34% compared to an effective tax rate of 43% for the three months ended March 31, 2010. The estimated annual rate differs from the statutory rate primarily due to the estimate of state income taxes and non-deductible expenses for the period.

Liquidity and Capital Resources

          As of March 31, 2011, we had cash and cash equivalents of $0.04 million, and $20.0 million of nominal availability under our revolving credit facility. In March 2011, we entered into new credit facilities including a $250.0 million first lien revolving credit facility with an initial $150.0 million borrowing base and a $75.0 million second lien term loan facility. Under our new credit facilities, through September 30, 2011, additional borrowings will not be limited by the leverage ratio covenant in our revolving loan agreement provided our Modified EBITDA for the preceding four fiscal quarters exceeds $47.4 million. Our Modified EBITDA for the four fiscal quarters ending March 31, 2011 was $48.3 million. Management believes that borrowings currently available to us under our credit facilities and anticipated cash flows from operations will be sufficient to satisfy our currently expected capital expenditures, working capital, and debt service obligations for the foreseeable future. At March 31, 2011, we had $205.4 million of indebtedness outstanding, including $130.0 million under our revolving credit facility, $75.0 million under our term loan credit facility and $0.4 million in other indebtedness. As of March 31, 2011, we had an accumulated deficit of $224.8 million and a working capital deficit of $12.6 million.

          Credit Facilities. In March 2011, we entered into new credit facilities. The new facilities, which replaced our previous facility, include a $250.0 million first lien revolving credit facility and a $75.0 million second lien term loan facility. SunTrust Bank is the administrative agent for the revolving facility, and Guggenheim Corporate Funding, LLC is the agent for the term loan facility. The initial borrowing base under the revolving credit facility was $150.0 million. Funds advanced under the revolving credit facility may be paid down and re-borrowed during the five-year term of the revolver, and initially bear interest at LIBOR plus a margin ranging from 2.5% to 3.25% based on a percentage of usage. The term loan credit facility provides for payments of interest only during its 5.5-year term, with the initial interest rate being LIBOR plus 9.0% with a 2.0% LIBOR Floor, or if in any period we elect to pay a portion of the interest under our term loan “in kind,” then the interest rate will be LIBOR plus 10.0% with a 2.0% LIBOR floor, and with 7.0% of the interest amount paid in cash and the remaining 3.0% paid in kind by being added to principal.

          Advances under our credit facilities are secured by liens on substantially all of our properties and assets. The credit facilities contain representations, warranties and covenants customary in transactions of this nature, including restrictions on the payment of dividends on our capital stock and financial covenants relating to current ratio, minimum interest coverage ratio, maximum leverage ratio and a required ratio of asset value to total indebtedness. We are required to maintain commodity hedges on a rolling basis for the first 12 months of not less than 60%, but not more than 85%, and for the next 18 months of not less than 50% but not more than 85%, of our projected quarterly production volumes, until the leverage ratio is less than or equal to 1.5 to 1.0. At March 31, 2011, our commodity hedging represented approximately 71% of our projected production volumes through June 30, 2014.

          Our previous credit facility entered into November 2007 included a $500.0 million credit facility with Guggenheim Corporate Funding, LLC, for itself and on behalf of other institutional lenders. This facility included 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 our previous revolving credit facility was $145.0 million at December 31, 2010. Funds advanced under the revolving credit facility initially bore interest at LIBOR plus a margin

ranging from 1.25% to 2.0% based on a percentage of usage. The term loan portion of our credit facility initially provided for payments of interest only during its five-year term, with the initial interest rate being LIBOR plus 7.5%.

          On June 26, 2009, we renegotiated certain terms of our previous 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 was added to the principal balance of the term loan on a monthly basis and was paid in connection with the closing of the new credit facilities in March 2011.

          In 2010, we used $33.8 million in proceeds from asset sales to pay down the term facility and $24.0 million in proceeds from asset sales to pay down the revolving credit facility. PIK interest of $3.0 million was added to the term facility in 2010, and $0.4 million was added to the term facility in the first quarter of 2011, bringing the balance of the term facility to $80.6 million at the date of the closing of the new credit facilities on March 14, 2011.

          Our ability to comply with the financial covenants in our new credit facilities 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 facilities. A default, if not cured or waived, could result in acceleration of all indebtedness outstanding under our credit facilities. 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 March 31, 2011, we were in compliance with all of the financial covenants under our credit facilities.

     At-The-Market Program. On March 17, 2011, we filed a prospectus supplement under which we may, from time to time, sell up to $25.0 million of our common stock through an “at-the-market” equity distribution program (the “At-The-Market Program”). Shares would be offered pursuant to the prospectus supplement dated March 17, 2011 to our base prospectus dated February 24, 2010, which was filed as part of our effective shelf registration statement. As of March 31, 2011, we had made no sales of common stock through the At-The-Market Program.

     Cash Flow From Operating Activities. Our cash flow from operating activities is comprised of three main items: net income (loss), adjustments to reconcile net income to cash provided (used) before changes in working capital, and changes in working capital. For the three months ended March 31, 2011, our net loss was $9.9 million, as compared to a net income of $2.4 million for the three months ended March 31, 2010. Adjustments (primarily non-cash items such as depreciation and amortization, unrealized (gains) losses and deferred income taxes) were $20.2 million for the three months ended March 31, 2011, compared to $9.6 million for the first three months of 2010, an increase of $10.6 million. The change in unrealized (gains) losses partially offset by deferred income taxes caused most of this increase. Working capital changes for the three months ended March 31, 2011 and 2010, were a negative $6.1 million and $4.2 million, respectively. For the three months ended March 31, 2011 and 2010, in total, net cash provided by operating activities was $4.2 million and $7.8 million, respectively.

     Cash Flow From Investing Activities. For the three months ended March 31, 2011, net cash used in our investing activities was $5.4 million, consisting of $5.8 million in payments for oil and gas properties and other equipment offset by $0.4 million in proceeds from sales of property and equipment. For the three months ended March 31, 2010, net cash used in our investing activities was $7.6 million.

     Cash Flow From Financing Activities. For the three months ended March 31, 2011, net cash provided by our financing activities was $1.2 million, compared to $0.2 million of net cash used in our financing activities for the previous comparable period. During the first three months of 2011, we received proceeds of $224.0 million from borrowings on long-term debt. We also reduced our long-term debt by $216.1 million and paid $6.7 for deferred loan costs. During the first three months of 2010, we received proceeds of $10.1 million from borrowings on long-term debt, which was offset by $10.0 million to reduce our long term debt and $0.3 million in common stock repurchased from participants under our 2006 Long-Term Incentive Plan to net settle withholding tax liability.

Capital Commitments

     During the three months ended March 31, 2011, we had capital expenditures of $5.6 million relating to our oil and natural gas operations, of which $5.4 million was allocated to drilling new exploration and development wells and recompletion operations in existing wells and $0.2 million was for acquisition costs.

     Our $35.0 million capital budget for 2011 non-acquisition capital expenditures includes the following:

	•		developmental drilling and recompletions ($18.0 million);
	•		exploration, including leasehold acquisition, seismic and exploratory drilling ($9.0 million); and
	•		geological, geophysical and contingencies ($8.0 million).

     In our 2011 non-acquisition capital budget for developmental drilling and recompletions, we have allocated $8.0 million for continued development of our Electra/Burkburnett area, $2.0 million for drilling on our South Texas properties and $8.0 million for reworking and production enhancement operations in our mature fields, including our Fitts and Allen fields in Oklahoma.

     The amount and timing of our capital expenditures for calendar year 2011 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 and the availability under our revolving credit facility will be sufficient to satisfy our budgeted non-acquisition capital expenditures, working capital and debt service obligations for the foreseeable future. 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, asset sales 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 March 2016. Our term loan facility matures in September 2016. Should the current tightness in the credit markets continue, 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 totaled approximately $1.5 million at March 31, 2011, but fluctuate throughout the year, 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 fails. 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. In the first quarter of 2011, we entered into an interest rate swap agreement to manage our cash flow on refinanced debt. Under the agreement, $50.0 million of our debt is subject to a fixed rate of 2.51%, with a swap floating rate of 3-month LIBOR, subject to a 2.0% floor.

          Our long-term debt as of March 31, 2011, is denominated in U.S. dollars. Our debt has been issued at variable rates, and as such, interest expense would be impacted by interest rate changes. The new revolving credit facility entered into March 2011 is not subject to LIBOR floors, and the impact of 100-basis point increase in LIBOR interest rates would have resulted in an increase in interest expense of approximately $1.3 million annually based on the $130.0 million balance of our revolver as of March 31, 2011. LIBOR rates were less than 100-basis points as of March 31, 2011, so any decrease in interest rates would have resulted in a nominal decrease in interest expense under our revolver as of March 31, 2011. The term loan portion of our new credit facility includes a 2.0% LIBOR floor. The impact of a 100-basis point increase in LIBOR rates above our 2.0% floor would result in an increase in interest expense under our term loan of $0.3 million annually based on the $25.0 million balance of our term loan which is not subject to the interest rate swap as of March 31, 2011. A 100-basis point decrease would have no effect on interest expense under our term loan until the LIBOR rate exceeds 2.0%.

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 quarter ended March 31, 2011, Shell Energy North America-US accounted for $17.9 million, or approximately 70%, of our revenue from the sales of oil and natural gas. No other purchaser accounted for 10% or more of our oil and natural gas revenue for the quarter ended March 31, 2011.

     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 March 31, 2011, 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
Year		Per Day				Price				Per Day				Price					Year			Per Day				Price				Per Day				Price
Q2’11			2,500			$	80.00				2,500			$	105.00				Q2’11				5,000			$	4.00				—				—
Q3’11			2,500			$	80.00				2,500			$	105.00				Q3’11				5,000			$	5.00				—				—
Q4’11			2,650			$	80.00				2,650			$	105.00				Q4’11				7,304			$	4.18				—				—
Q1’12			2,000			$	80.00				2,000			$	105.00				Q1’12				10,000			$	4.25				—				—
Q2’12			2,000			$	80.00				2,000			$	105.00				Q2’12				5,000			$	4.00				5,000			$	6.00
Q3’12			1,800			$	92.22				1,800			$	105.24				Q3’12				5,000			$	4.00				5,000			$	6.00
Q4’12			1,750			$	92.14				1,750			$	104.83				Q4’12				—				—				—				—
Q1’13			1,700			$	95.00				1,700			$	100.91				Q1’13				—				—				—				—
Q2’13			1,650			$	95.00				1,650			$	99.93				Q2’13				—				—				—				—
Q3’13			1,600			$	95.00				1,600			$	99.94				Q3’13				—				—				—				—
Q4’13			1,550			$	95.00				1,550			$	99.71				Q4’13				—				—				—				—
Q1’14			1,500			$	95.00				1,500			$	99.40				Q1’14				—				—				—				—
Q2’14			1,500			$	95.00				1,500			$	99.13				Q2’14				—				—				—				—

     Based on March 31, 2011, NYMEX forward curves of natural gas and crude oil futures prices, adjusted for volatility by 300 basis points, we would expect to pay future cash payments of $14.6 million under our natural gas and crude oil derivative arrangements as they mature. If future prices of natural gas and crude oil were to decline by 10%, we would expect to receive future cash payments under our natural gas and crude oil derivative arrangements of $3.5 million, and if future prices were to increase by 10%, we would expect to pay future cash payments of $35.1 million.

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 March 31, 2011. 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 March 31, 2011, 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, 2010, for a discussion of pending legal proceedings to which we are a party.

ITEM 1A — RISK FACTORS

     Previously reported. Reference is made to Part I, Item 1A, “Risk Factors,” in our annual report on Form 10-K for the year ended December 31, 2010, for a discussion of the risk factors which could materially affect our business, financial condition or future results.

ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

     None.

ITEM 3 — DEFAULTS UPON SENIOR SECURITIES

     None.

ITEM 4 — [RESERVED]

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.		(8) [3.2]
10.1		Form of Registration Rights Agreement among the Registrant and the Initial Stockholders.		(2) [10.9]
10.1.1		Amendment to Registration Rights Agreement among this Registrant and the Founders dated May 8, 2006.		(1) [10.9.1]
10.2		Employment Agreement between Registrant and Larry E. Lee dated May 8, 2006.*		(1) [10.15]
10.2.1		First Amendment to Employment Agreement between Registrant and Larry E. Lee dated October 18, 2006.*		(5) [10.1]
10.2.2		Second Amendment to Employment Agreement of Larry E. Lee dated February 25, 2008.*		(10) [10.6.2]
10.2.3		Third Amendment to Employment Agreement of Larry E. Lee, dated December 30, 2008.*		(13) [10.6.3]
10.2.4		Fourth Amendment to Employment Agreement of Larry E. Lee dated March 24, 2009.*		(14) [10.6.4]
10.2.5		Fifth Amendment to Employment Agreement of Larry E. Lee dated March 17, 2010.*		(17) [10.6.5]
10.2.6		Sixth Amendment to Employment Agreement of Larry E. Lee dated March 8, 2011.*		(21) [10.2.6]
10.3		Escrow Agreement by an among the Registrant, Larry E. Lee and Continental Stock Transfer & Trust Company dated May 8, 2006.		(1) [10.16]
10.4		Registration Rights Agreement among Registrant and the investors signatory thereto dated May 8, 2006.		(1) [10.7]
10.5		Form of Registration Rights Agreement among the Registrant and the Investors party thereto.		(3) [10.17]
10.6		Agreement between RAM and Shell Trading-US dated February 1, 2006.		(1) [10.22]
10.7		Agreement between RAM and Targa dated January 30, 1998.		(1) [10.23]
10.7.1		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.		(6) [10.23.1]
10.8		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.*		(4) [Annex C]
10.8.1		First Amendment to RAM Energy Resources, Inc. 2006 Long-Term Incentive Plan effective May 8, 2008.*		(11) [Exhibit A]
10.8.2		Second Amendment to RAM Energy Resources, Inc. 2006 Long-Term Incentive Plan effective May 3, 2010.*		(18) [10.8.2]
10.9		Deferred Bonus Compensation Plan of RAM Energy, Inc. dated as of April 21, 2004.*		(7) [10.14]
10.10		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.		(9) [10.1]

Exhibit		Description		Method of Filing
10.10.1		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.		(15)[10.17.1]
10.10.2		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.		(16)[10.17.2]
10.10.3		Third Amendment to Loan Agreement dated November 29, 2010, effective December 3, 2010, 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.		(20)[10.8.3]
10.11		Description of Compensation Arrangement with G. Les Austin.*		(12)[10.18]
10.11.1		First Amendment to Employment Agreement of G. Les Austin, dated December 30, 2008.*		(13)[10.18.1]
10.11.2		Second Amendment to Employment Agreement of G. Les Austin, dated March 23, 2011.*		(24)[10.11.2]
10.12		Change in Control Separation Benefit Plan of RAM Energy Resources, Inc. and Participating Subsidiaries.*		(15)[10.19]
10.13		Purchase and Sale Agreement dated October 29, 2010, by and between RWG Energy, Inc., as Seller, and Milagro Producing, LLC, as Buyer.		(19)[10.13]
10.14		Revolving Credit Agreement dated March 14, 2011, among RAM Energy Resources, Inc., as Borrower, Sun Trust Bank, as Administrative Agent, Capital One, N.A., as Syndication Agent, and the financial institutions named therein as the Lenders.		(22)[10.14]
10.15		Second Lien Term Loan Agreement dated March 14, 2011, among RAM Energy Resources, Inc., as Borrower, Guggenheim Corporate Funding, LLC as Administrative Agent, and the financial institutions named therein as the Lenders.		(22)[10.15]
10.16		Equity Distribution Agreement, dated March 17, 2011.		(23)[1.1]
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.		**

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.

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.		(8) [3.2]
10.1		Form of Registration Rights Agreement among the Registrant and the Initial Stockholders.		(2) [10.9]
10.1.1		Amendment to Registration Rights Agreement among this Registrant and the Founders dated May 8, 2006.		(1) [10.9.1]
10.2		Employment Agreement between Registrant and Larry E. Lee dated May 8, 2006.*		(1) [10.15]
10.2.1		First Amendment to Employment Agreement between Registrant and Larry E. Lee dated October 18, 2006.*		(5) [10.1]
10.2.2		Second Amendment to Employment Agreement of Larry E. Lee dated February 25, 2008.*		(10) [10.6.2]
10.2.3		Third Amendment to Employment Agreement of Larry E. Lee, dated December 30, 2008.*		(13) [10.6.3]
10.2.4		Fourth Amendment to Employment Agreement of Larry E. Lee dated March 24, 2009.*		(14) [10.6.4]
10.2.5		Fifth Amendment to Employment Agreement of Larry E. Lee dated March 17, 2010.*		(17) [10.6.5]
10.2.6		Sixth Amendment to Employment Agreement of Larry E. Lee dated March 8, 2011.*		(21) [10.2.6]
10.3		Escrow Agreement by an among the Registrant, Larry E. Lee and Continental Stock Transfer & Trust Company dated May 8, 2006.		(1) [10.16]
10.4		Registration Rights Agreement among Registrant and the investors signatory thereto dated May 8, 2006.		(1) [10.7]
10.5		Form of Registration Rights Agreement among the Registrant and the Investors party thereto.		(3) [10.17]
10.6		Agreement between RAM and Shell Trading-US dated February 1, 2006.		(1) [10.22]
10.7		Agreement between RAM and Targa dated January 30, 1998.		(1) [10.23]
10.7.1		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.		(6) [10.23.1]
10.8		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.*		(4) [Annex C]
10.8.1		First Amendment to RAM Energy Resources, Inc. 2006 Long-Term Incentive Plan effective May 8, 2008.*		(11) [Exhibit A]
10.8.2		Second Amendment to RAM Energy Resources, Inc. 2006 Long-Term Incentive Plan effective May 3, 2010.*		(18) [10.8.2]
10.9		Deferred Bonus Compensation Plan of RAM Energy, Inc. dated as of April 21, 2004.*		(7) [10.14]
10.10		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.		(9) [10.1]

Exhibit		Description		Method of Filing
10.10.1		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.		(15) [10.17.1]
10.10.2		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.		(16) [10.17.2]
10.10.3		Third Amendment to Loan Agreement dated November 29, 2010, effective December 3, 2010, 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.		(20) [10.8.3]
10.11		Description of Compensation Arrangement with G. Les Austin.*		(12) [10.18]
10.11.1		First Amendment to Employment Agreement of G. Les Austin, dated December 30, 2008.*		(13) [10.18.1]
10.11.2		Second Amendment to Employment Agreement of G. Les Austin, dated March 23, 2011.		(24) [10.11.2]
10.12		Change in Control Separation Benefit Plan of RAM Energy Resources, Inc. and Participating Subsidiaries.*		(15) [10.19]
10.13		Purchase and Sale Agreement dated October 29, 2010, by and between RWG Energy, Inc., as Seller, and Milagro Producing, LLC, as Buyer.		(19) [10.13]
10.14		Revolving Credit Agreement dated March 14, 2011, among RAM Energy Resources, Inc., as Borrower, Sun Trust Bank, as Administrative Agent, Capital One, N.A., as Syndication Agent, and the financial institutions named therein as the Lenders.		(22) [10.14]
10.15		Second Lien Term Loan Agreement dated March 14, 2011, among RAM Energy Resources, Inc., as Borrower, Guggenheim Corporate Funding, LLC as Administrative Agent, and the financial institutions named therein as the Lenders.		(22) [10.15]
10.16		Equity Distribution Agreement, dated March 17, 2011.		(23) [1.1]
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.		**