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 March 31, 2010

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		1311		20-0700684
(State or other jurisdiction of incorporation or organization)		(Primary Standard Industrial Classification Code Number)		(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  o
Non-Accelerated Filer  o		(Do not check if a smaller reporting company)		Smaller Reporting Company  þ

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 1, 2010, 78,128,753 shares of the Registrant’s Common Stock were outstanding.

 

 

First Quarter 2010 Form 10-Q Report

TABLE OF CONTENTS

				Page
PART I — FINANCIAL INFORMATION
ITEM 1.		FINANCIAL STATEMENTS (unaudited)			3
		Condensed Consolidated Balance Sheets — March 31, 2010 and December 31, 2009			3
		Condensed Consolidated Statements of Operations — Three Months Ended March 31, 2010 and 2009			4
		Condensed Consolidated Statements of Cash Flows — Three Months Ended March 31, 2010 and 2009			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			18
ITEM 4.		CONTROLS AND PROCEDURES			20
PART II — OTHER INFORMATION					21
ITEM 1.		LEGAL PROCEEDINGS			21
ITEM 1A.		RISK FACTORS			21
ITEM 2.		UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS			21
ITEM 3.		DEFAULTS UPON SENIOR SECURITIES			21
ITEM 4.		[RESERVED]			21
ITEM 5.		OTHER INFORMATION			21
ITEM 6.		EXHIBITS			22
		SIGNATURES			25

ITEM 1 — FINANCIAL STATEMENTS

		March 31,				December 31,
		2010				2009
		(unaudited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	101			$	129
Accounts receivable:
Oil and natural gas sales, net of allowance of $50 ($50 at December 31, 2009)			12,473				12,585
Joint interest operations, net of allowance of $606 ($641 at December 31, 2009)			525				1,303
Other, net of allowance of $48 ($48 at December 31, 2009)			243				193
Prepaid expenses			1,835				1,970
Deferred tax asset			3,612				3,531
Inventory			3,762				3,900
Other current assets			29				27
Total current assets			22,580				23,638
PROPERTIES AND EQUIPMENT, AT COST:
Proved oil and natural gas properties and equipment, using full cost accounting			709,901				702,502
Other property and equipment			9,509				9,337
			719,410				711,839
Less accumulated depreciation, amortization and impairment			(469,177	)			(462,541	)
Total properties and equipment			250,233				249,298
OTHER ASSETS:
Deferred tax asset			29,938				31,573
Derivative assets			783				—
Deferred loan costs, net of accumulated amortization of $3,446 ($2,924 at December 31, 2009)			4,175				4,697
Other			1,955				1,956
Total assets		$	309,664			$	311,162
LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
CURRENT LIABILITIES:
Accounts payable:
Trade		$	12,546			$	15,697
Oil and natural gas proceeds due others			9,841				10,113
Other			409				636
Accrued liabilities:
Compensation			1,774				2,664
Interest			2,935				2,933
Income taxes			832				655
Other			10				10
Derivative liabilities			3,655				4,471
Asset retirement obligations			713				711
Long-term debt due within one year			149				126
Total current liabilities			32,864				38,016
DERIVATIVE LIABILITIES			—				358
LONG-TERM DEBT			246,880				246,041
ASSET RETIREMENT OBLIGATIONS			26,778				26,363
OTHER LONG-TERM LIABILITIES			10				10
COMMITMENTS AND CONTINGENCIES			900				900
STOCKHOLDERS’ EQUITY (DEFICIT):
Common stock, $0.0001 par value, 100,000,000 shares authorized, 82,086,674 and 80,748,674, shares issued, 78,128,753 and 76,951,883 shares outstanding at March 31, 2010 and December 31, 2009, respectively			8				8
Additional paid-in capital			223,643				222,979
Treasury stock - 3,957,921 shares (3,796,791 shares at December 31,2009) at cost			(6,513	)			(6,189	)
Accumulated deficit			(214,906	)			(217,324	)
Stockholders’ equity (deficit)			2,232				(526	)
Total liabilities and stockholders’ equity (deficit)		$	309,664			$	311,162

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

(in thousands, except share and per share amounts)
(unaudited)

		Three months ended March 31,
		2010				2009
REVENUES AND OTHER OPERATING INCOME:
Oil and natural gas sales
Oil		$	19,488			$	11,258
Natural gas			6,429				6,050
NGLs			3,931				1,748
Total oil and natural gas sales			29,848				19,056
Realized gains (losses) on derivatives			(898	)			7,878
Unrealized gains (losses) on derivatives			1,935				(1,007	)
Other			36				85
Total revenues and other operating income			30,921				26,012
OPERATING EXPENSES:
Oil and natural gas production taxes			1,594				872
Oil and natural gas production expenses			7,920				10,085
Depreciation and amortization			6,714				8,282
Accretion expense			382				404
Impairment			—				47,613
Share-based compensation			686				541
General and administrative, overhead and other expenses, net of
operator’s overhead fees			3,770				4,345
Total operating expenses			21,066				72,142
Operating income (loss)			9,855				(46,130	)
OTHER INCOME (EXPENSE):
Interest expense			(5,635	)			(3,608	)
Interest income			2				20
Other expense			(9	)			(433	)
EARNINGS (LOSS) BEFORE INCOME TAXES			4,213				(50,151	)
INCOME TAX PROVISION (BENEFIT)			1,795				(20,793	)
Net earnings (loss)		$	2,418			$	(29,358	)
BASIC EARNINGS (LOSS) PER SHARE		$	0.03			$	(0.38	)
BASIC WEIGHTED AVERAGE SHARES OUTSTANDING			77,997,063				77,290,832
DILUTED EARNINGS (LOSS) PER SHARE		$	0.03			$	(0.38	)
DILUTED WEIGHTED AVERAGE SHARES OUTSTANDING			77,997,063				77,290,832

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

		Three months ended March 31,
		2010				2009
OPERATING ACTIVITIES:
Net income (loss)		$	2,418			$	(29,358	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities-
Depreciation and amortization			6,714				8,282
Amortization of deferred loan costs and Senior Notes discount			522				299
Non-cash interest			765				—
Accretion expense			382				404
Impairment			—				47,613
Unrealized (gain) loss on derivatives and premium amortization			(967	)			1,290
Deferred income tax provision (benefit)			1,554				(20,785	)
Share-based compensation			686				541
Gain on disposal of other property, equipment and subsidiary			(23	)			(15	)
Changes in operating assets and liabilities
Accounts receivable			840				1,756
Prepaid expenses, inventory and other assets			272				832
Derivative premiums			(990	)			(579	)
Accounts payable and proceeds due others			(3,650	)			(4,944	)
Accrued liabilities and other			(888	)			(1,903	)
Income taxes payable			177				(156	)
Asset retirement obligations			—				(112	)
Total adjustments			5,394				32,523
Net cash provided by operating activities			7,812				3,165
INVESTING ACTIVITIES:
Payments for oil and natural gas properties and equipment			(7,821	)			(13,258	)
Proceeds from sales of oil and natural gas properties			458				210
Payments for other property and equipment			(254	)			(127	)
Proceeds from sales of other property and equipment			4				23
Net cash used in investing activities			(7,613	)			(13,152	)
FINANCING ACTIVITIES:
Payments on long-term debt			(10,034	)			(5,042	)
Proceeds from borrowings on long-term debt			10,131				15,000
Stock repurchased			(324	)			(6	)
Net cash (used in) provided by financing activities			(227	)			9,952
DECREASE IN CASH AND CASH EQUIVALENTS			(28	)			(35	)
CASH AND CASH EQUIVALENTS, beginning of period			129				164
CASH AND CASH EQUIVALENTS, end of period		$	101			$	129
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for income taxes		$	64			$	149
Cash paid for interest		$	4,347			$	3,450
DISCLOSURE OF NON CASH INVESTING AND FINANCING ACTIVITIES:
Asset retirement obligations		$	35			$	1,002
Payment-in-kind interest		$	765			$	—

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, 2010 and December 31, 2009 and the results of operations and cash flows for the three month period ended March 31, 2010 and 2009 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, 2010 are not necessarily indicative of the results to be expected for the full year ending December 31, 2010. Reference is made to the Company’s consolidated financial statements for the year ended December 31, 2009 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, Louisiana and Oklahoma.

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 dilutive stock unit options were exercised, calculated using the treasury stock method. 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 months ended March 31 (in thousands, except share and per share amounts):

		Three months ended March 31,
		2010				2009
Net income (loss)		$	2,418			$	(29,358	)
Weighted average shares — basic			77,997,063				77,290,832
Dilutive effect of unit options			—				—
Weighted average shares — dilutive			77,997,063				77,290,832
Basic earnings (loss) per share		$	0.03			$	(0.38	)
Diluted earnings (loss) per share		$	0.03			$	(0.38	)

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 January 2009, the FASB issued guidance on fair value disclosures to enhance disclosures surrounding the transfers of assets in and out of level 1 and level 2, to present more detail surrounding asset activity for level 3 assets and to clarify existing disclosure requirements. The new guidance is set forth in Topic 820 of the Codification and was effective for the Company beginning January 1, 2010. Adoption of the guidance in the first quarter of 2010 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 was 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. However, in February 2010, the FASB amended the guidance to remove the requirement to disclose the date through which subsequent events were evaluated.

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, 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 $47.6 million. The after-tax effect of this reduction was $30.3 million. At March 31, 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,
		2010				2009
Credit facility		$	246,493			$	245,730
Accrued payment-in-kind interest			264				262
Installment loan agreements			272				175
			247,029				246,167
Less amount due within one year			149				126
		$	246,880			$	246,041

Credit Facility

          In November 2007, in conjunction with the 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 term, with the initial interest rate being LIBOR plus 7.5%. The $175.0 million borrowing base under the revolver was reaffirmed in April 2010.

          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 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. 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.

          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 March 31, 2010. At March 31, 2010, $135.0 million was outstanding under the revolving credit facility and $111.8 million was outstanding under the term facility, including $0.3 million accrued payment-in-kind interest.

D —

CAPITAL STOCK

          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

          Sacket v. Great Plains Pipeline Company, et al. This was a class action lawsuit on behalf of certain royalty owners in which RAM Energy, together with certain of its subsidiaries and affiliates, were defendants. In the lawsuit, the plaintiff alleged that the royalty payments to landowners for oil and natural gas produced from wells connected to a RAM Energy subsidiary’s natural gas, oil and saltwater pipeline system in Woods, Alfalfa and Major Counties, Oklahoma, were calculated on a price that was lower than the price at which the production from the related wells was resold by the subsidiary. On March 5, 2009, the Court approved a settlement of the lawsuit and on April 4, 2009, the settlement became final.

          During 2008, the Company recorded a contingent liability of $16.0 million for its share of the settlement amount and a receivable of $2.8 million in other current assets representing the value of escrowed shares, set aside by former stockholders of RAM Energy to cover this litigation, based on the closing price of $0.88 per share on December 31, 2008. The Company also recorded a charge to other expense of $13.2 million for the difference between the settlement liability and the value of the escrowed shares. During the first quarter of 2009, the Company recorded a charge to other expense of $0.4 million and adjusted the receivable from $2.8 million to $2.4 million to adjust the Fair Market Value of the escrowed shares to reflect the final settlement due of $0.74 per share.

          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. 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 our net derivative liabilities as of March 31, 2010 and December 31, 2009 was $2.9 million and $4.8 million, respectively, based on Level 2 criteria. See Note G.

          At March 31, 2010, the carrying value of cash, receivables and 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 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 2010 and 2009, 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 2010 and 2009 have been recorded in the statements of operations.

          The Company’s derivative positions at March 31, 2010, 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
2010			2,079			$	53.99				2,079			$	83.10			April — December			2,764			$	5.00				2,764			$	8.16			April — June, November — December
2011			—			$	—				—			$	—						6,219			$	5.00				6,219			$	9.48			January — September

		Bare Floors										Bare Floors
Year		Per Day(1)				Price				Months Covered		Per Day(1)				Price				Months Covered
2010			920			$	60.00			July — December			7,236			$	4.46			April — December
2011			1,870			$	60.00			January — September			—			$	—

          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. The discount rate used in the discounted cash flow projections is based on published LIBOR rates, Eurodollar futures rates and interest swap rates. The counterparty credit risk is 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, 2010 and December 31, 2009 and the amounts recorded in the consolidated statements of operations for the three months ended March 31, 2010 and 2009 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		2010				2009
Current Assets — Derivative assets		Current Liabilities — Derivative liabilities		$	1,705			$	413
Other Assets — Derivative assets		Other Assets — Derivative assets			1,678				—
Other Assets — Derivative assets		Long-Term Liabilities — Derivative liabilities			—				200
Current Liabilities — Derivative liabilities		Current Liabilities — Derivative liabilities			(5,360	)			(4,884	)
Long-Term Liabilities — Derivative liabilities		Other Assets — Derivative assets			(895	)			—
Long-Term Liabilities — Derivative liabilities		Long-Term Liabilities — Derivative liabilities			—				(558	)
Total Derivatives Not Designated as Hedging Instruments				$	(2,872	)		$	(4,829	)

CONSOLIDATED STATEMENTS OF OPERATIONS

		Three Months Ended March 31,
Location		2010				2009
Revenue — Unrealized gains (losses) on derivatives		$	1,935			$	(1,007	)
Revenue — Realized gains (losses) on derivatives		$	(898	)		$	7,878

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 March 31, 2010, a maximum of 1,071,426 shares of common stock remained reserved for issuance under the Plan.

          As of March 31, 2010, the Company had $6.5 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 three years. The related compensation expense recognized during the three months ended March 31, 2010 and 2009 was $0.7 million and $0.5 million, respectively.

          The Company held its 2010 Annual Meeting of Stockholders on May 3, 2010. At the meeting, the following amendments to the Company’s 2006 Long-Term Incentive Plan were adopted to:

	•		Increase the maximum authorized number of shares to be awarded under the 2006 plan from 6,000,000 to 7,400,000;
	•		Remove the limitations in the 2006 plan that limit to 100,000 the number of shares of common stock that may be made subject to the grant of stock options, stock appreciation rights, restricted stock awards and performance unit awards to any eligible employee in any calendar year; and
	•		Remove the limitations in the 2006 plan that limit to 20,000 the number of shares of common stock that may be made subject to the grant of stock options and restricted stock awards to any eligible director in any calendar year.

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, Louisiana and Oklahoma. 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 Fields).

          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 46,550 gross (37,043 net) acres (Developing Field); and
	•		North Texas Barnett Shale—Bosque and Hamilton Counties, Texas. We own interests in approximately 1,079 gross (833 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 the prices and costs attributable to all oil and natural gas properties owned by us, for the three months ended March 31, 2010. 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, 2010
Production volumes:
Oil (MBbls)			257
NGLs (MBbls)			98
Natural gas (MMcf)			1,269
Total (MBoe)			566
Average sale prices received:
Oil (per Bbl)		$	75.83
NGLs (per Bbl)		$	40.11
Natural gas (per Mcf)		$	5.07
Total per Boe		$	52.73
Cash effect of derivative contracts:
Oil (per Bbl)		$	(3.84	)
NGLs (per Bbl)		$	0.00
Natural gas (per Mcf)		$	0.07
Total per Boe		$	(1.59	)
Average prices computed after cash effect
of settlement of derivative contracts:
Oil (per Bbl)		$	71.99
NGLs (per Bbl)		$	40.11
Natural gas (per Mcf)		$	5.14
Total per Boe		$	51.14
Cash expenses (per Boe):
Oil and natural gas production taxes		$	2.82
Oil and natural gas production expenses		$	13.99
General and administrative		$	6.66
Interest		$	7.68
Taxes		$	0.11
Total per Boe		$	31.26
Cash flow per Boe		$	19.88

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, 2010 (in thousands):

		Three months ended
		March 31, 2010
Development and exploratory costs		$	7,513
Proved property acquisition costs			308
Unproved property acquisition costs			—
Total costs incurred		$	7,821

          During the quarter ended March 31, 2010, we participated in the drilling of 21.0 gross (16.1 net) development wells. Ten gross (10.0 net) wells were completed and capable of commercial production and 11.0 gross (6.1 net) wells were drilling or waiting on completion.

Results of Operations

Quarter Ended March 31, 2010 Compared to Quarter Ended March 31, 2009

          Oil and natural gas sales increased $10.8 million, or 57%, to $29.8 million for the three months ended March 31, 2010 as compared to $19.1 million for the same period in 2009. This increase was driven by commodity price increases, which increased 81% for the three months ended March 31, 2010 as compared to the same period last year. Production volumes decreased 14% for the three months ended March 31, 2010 as compared to the same period last year. The production decrease is primarily attributed to a reduction in drilling activity in 2009 as a result of low natural gas prices, and to unplanned downtime due to severe weather during the first quarter of 2010. Drilling and workover delays, weather-related well shut-ins and natural production declines caused decreased production in most of our fields.

          Production from our developing fields of South Texas, Barnett Shale, and Appalachia in West Virginia decreased 13 MBoe in the first quarter. Drilling activity included 8.0 gross (3.2 net) development wells. Production from our mature oil fields of Electra/Burkburnett in North Texas and Allen/Fitts in Pontotoc County, Oklahoma decreased 51 MBoe in the first quarter. Drilling activity included 13.0 gross (12.9 net) development wells. Production from our mature gas fields decreased 25 MBoe in the first quarter of 2010. We did not drill any new wells in our mature gas fields during this quarter.

          The following tables summarize our oil and natural gas production volumes, average sales prices and period to period comparisons for the periods indicated:

														Mature				Mature
		Developing Fields												Oil Fields*				Natural Gas Fields
Three Months Ended March 31, 2010		South Texas				Barnett Shale				Appalachia				Various				Various				Total
Aggregate Net Production
Oil (MBbls)			13				2				—				218				24				257
NGLs (MBbls)			35				31				—				13				19				98
Natural Gas (MMcf)			541				172				14				56				486				1,269
MBoe			139				61				2				240				124				566
Three Months Ended March 31, 2009
Aggregate Net Production
Oil (MBbls)			19				2				—				251				18				290
NGLs (MBbls)			29				35				—				20				20				104
Natural Gas (MMcf)			519				238				23				119				668				1,567
MBoe			134				77				4				291				149				655
Change in MBoe			5				(16	)			(2	)			(51	)			(25	)			(89	)
Percentage Change in MBoe			3.7	%			-20.8	%			-50.0	%			-17.5	%			-16.8	%			-13.6	%

		Three months ended
		March 31,
		2010				2009				Increase
Average sale prices:
Oil (per Bbl)		$	75.83			$	38.75				95.7	%
NGL (per Bbl)		$	40.11			$	16.86				137.9	%
Natural gas (per Mcf)		$	5.07			$	3.86				31.3	%
Per Boe		$	52.73			$	29.08				81.3	%

          The average realized sales prices increased substantially for the three months ended March 31, 2010 as compared to the same period in 2009. The average realized sales price for oil was $75.83 per barrel for the three months ended March 31, 2010, an increase of 96%, compared to $38.75 per barrel for the same period in 2009. The average realized sales price for NGLs was $40.11 for the three months ended March 31, 2010, an increase of 138%, compared to $16.86 per barrel for the same period in 2009. The average realized sales price for natural gas was $5.07 per Mcf for the three months ended March 31, 2010, an increase of 31%, compared to $3.86 per Mcf for the same period in 2009.

          Realized and Unrealized Gain (Loss) from Derivatives. For the quarter ended March 31, 2010, our gain from derivatives was $1.0 million, compared to a gain of $6.9 million for the quarter ended March 31, 2009. Our gains and losses during these periods were the net result of recording actual contract settlements, the premiums paid 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,
		2010				2009
		(in thousands)
Contract settlements and amortization of premium costs:
Oil		$	(988	)		$	4,345
Natural gas			90				3,533
Realized gains (losses)			(898	)			7,878
Mark-to-market gains (losses):
Oil			129				(5,097	)
Natural gas			1,806				4,090
Unrealized gains (losses)			1,935				(1,007	)
Realized and unrealized gains		$	1,037			$	6,871

          Oil and Natural Gas Production Taxes. Our oil and natural gas production taxes were $1.6 million for the quarter ended March 31, 2010, compared to $0.9 million for the comparable quarter of the previous year. The increase is due principally to higher commodity prices in the 2010 period. 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. As a percentage of oil and natural gas sales, oil and natural gas production taxes were 5.3% for the quarter ended March 31, 2010. We received a retroactive severance tax refund of $0.2 million during the first quarter of 2009 on a non-operated property causing our oil and natural gas production taxes as a percentage of oil and natural gas sales to decrease to 4.6% for the quarter ended March 31, 2009.

          Oil and Natural Gas Production Expense. Our oil and natural gas production expense was $7.9 million for the quarter ended March 31, 2010, a decrease of $2.2 million, or 21%, from the $10.1 million for the quarter ended March 31, 2009. The decrease was due primarily to decreased production volumes caused by weather-related shut-ins. For the quarter ended March 31, 2010, our oil and natural gas production expense was $13.99 per Boe compared to $15.39 per Boe for the quarter ended March 31, 2009, a decrease of 9%. The decrease per Boe resulted from a decrease in workover costs and repairs, which are not directly related to production. As a percentage of oil and natural gas sales, oil and natural gas production expense was 27% for the quarter ended March 31, 2010, as compared to 53% for the quarter ended March 31, 2009. This decrease results from a significant rise in average sales prices per Boe, from $29.08 in 2009 to $52.73 in 2010, an 81% increase.

          Amortization and Depreciation Expense. Our amortization and depreciation expense decreased $1.6 million, or 19%, for the quarter ended March 31, 2010, compared to the quarter ended March 31, 2009. On an equivalent basis, our amortization of the full-cost pool of $6.5 million was $11.40 per Boe for the quarter ended March 31, 2010, a decrease per Boe of 7% compared to $8.0 million, or $12.26 per Boe for the quarter ended March 31, 2009. This rate decrease per Boe resulted primarily from lower capitalized costs subsequent to the asset impairment writedown in the first quarter of 2009.

          Accretion Expense. Topic 410 of the Codification includes, among other things, the accounting for “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 the quarter ended March 31, 2010, unchanged from the quarter ended March 31, 2009.

          Impairment Charge. No impairment was incurred for the first quarter of 2010. We incurred a $47.6 million impairment on the carrying value of our oil and natural gas properties during the first quarter of 2009. The impairment of our oil and natural gas properties was primarily due to a reduction in the estimated present value of future net revenues from our proved oil and natural gas reserves resulting from a decline in commodity prices from December 31, 2008 to March 31, 2009.

          Share-Based Compensation. From time to time, our Board of Directors grants restricted stock awards under our 2006 Long-Term Incentive Plan. Each of these grants vests in equal increments over the vesting period provided for the particular award. All currently unvested awards provide for vesting periods of from one to five years. The share-based compensation 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, 2010, we recognized a total of $0.7 million share-based compensation expense, compared to $0.5 million for the quarter ended March 31, 2009. The increase was primarily due to additional grants during the 2010 and 2009 periods.

          General and Administrative Expense. For the quarter ended March 31, 2010, our general and administrative expense was $3.8 million, compared to $4.3 million for the quarter ended March 31, 2009, a decrease of $0.5 million, or 13%. The decrease results from the collection of certain past due receivables and lower health and welfare costs in the 2010 period.

          Interest Expense. We recorded interest expense of $5.6 million for the quarter ended March 31, 2010 as compared to $3.6 million for the first quarter of the previous year. The increase in interest expense was due to higher interest rates in the 2010 period due to the Second Amendment to our credit facility executed June 26, 2009. Our blended interest rate was 8.1% in the first quarter of 2010 compared to 4.9% in the 2009 period.

          Other Expense. We recorded a charge to other expense of $0.01 million for the quarter ended March 31, 2010. We recorded a charge to other expense of $0.4 million for the quarter ended March 31, 2009 for expense related to settlement of pending litigation.

          Income Taxes. For the three months ended March 31, 2010, we recorded an income tax expense of $1.8 million, on pre-tax income of $4.2 million. For the quarter ended March 31, 2009, we recorded an income tax benefit of $20.8 million, on a pre-tax loss of $50.2 million. Our effective tax rate for the three months ended March 31, 2010 was 43%. Excluding the first quarter 2009 ceiling test impairment of $47.6 million and the related tax benefit of $17.3 million, the effective tax rate for the three months ended March 31, 2009 was a benefit of 138%. The high effective tax rate in the 2009 period resulted from increased estimated state tax expense caused by the limitation on the use of certain deductions for state tax purposes.

Liquidity and Capital Resources

          As of March 31, 2010, we had cash and cash equivalents of $0.1 million, and $40.0 million of nominal availability under our revolving credit facility; however, because of the amount of our Modified EBITDA for the preceding four fiscal quarters, the financial covenants in our credit facility would have limited us to $36.1 million of additional borrowings as of March 31, 2010. We will be unable to borrow the full amount of our borrowing base until our Modified EBITDA for the preceding four fiscal quarters equals or exceeds $63.6 million. At March 31, 2010, we had $247.0 million of indebtedness outstanding, including $111.8 million under our term loan facility (which includes $0.3 million of accrued payment-in-kind interest), $135.0 million under our revolving credit facility and $0.2 million in other indebtedness. As of March 31, 2010, we had an accumulated deficit of $214.9 million and a working capital deficit of $10.3 million.

          Credit Facility. In November 2007, in conjunction with the Ascent acquisition, we entered into a new $500.0 million credit facility with Guggenheim Corporate Funding, LLC, for itself and on behalf of other institutional lenders. The new 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 new 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 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%. The $175.0 million borrowing base was reaffirmed in April 2010 based on the value of our proved reserves at December 31, 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 is added to the principal balance of the term loan on a monthly basis and will be paid at maturity.

          In 2009 we used $4.0 million in proceeds from asset sales to pay down the term facility. PIK interest of $1.6 million was added to the term facility in 2009, bringing the balance to $111.0 million at December 31, 2009. In the first quarter of 2010, PIK interest of $0.8 million was added to the term facility, bringing the balance to $111.8 million at March 31, 2010.

          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 March 31, 2010, 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 March 31, 2010, our commodity hedging represented approximately 53% of our projected production volumes through September 30, 2012.

          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, 2010, our net income was $2.4 million, as compared to a net loss of $29.4 million for the three months ended March 31, 2009. Adjustments (primarily non-cash items such as asset impairment charge, depreciation and amortization, and deferred income taxes) were $9.6 million for the three months ended March 31, 2010 compared to $37.6 million for the first three months of 2009, a decrease of $28.0 million. Asset impairment charge, depreciation, amortization and unrealized (gains) losses offset by a change in deferred income taxes caused most of this decrease. Working capital changes for the three months ended March 31, 2010 were a negative $4.2 million compared with negative changes of $5.1 million for the three months ended March 31, 2009. For the three months ended March 31, 2010, in total, net cash provided by operating activities was $7.8 million compared to $3.2 million of net cash provided by operations for the previous year.

          Cash Flow From Investing Activities. For the three months ended March 31, 2010 net cash used in our investing activities consisted of $8.1 million in payments for oil and natural gas properties and other equipment, offset by $0.5 million in proceeds from sales of oil and natural gas properties. For the three months ended March 31, 2009, net cash used in our investing activities was $13.2 million. The change is primarily due to lower capital expenditures in the 2010 period.

          Cash Flow From Financing Activities. For the three months ended March 31, 2010, net cash used in our financing activities was $0.2 million, compared to net cash provided of $10.0 million for the three months ended March 31, 2009. During the first three months of 2010, we received proceeds of $10.1 million from borrowings on long-term debt. We also reduced our long-term debt by $10.0 million, using $4.0 million in proceeds from asset sales and $6.0 million in cash flows from operations. In the first quarter of 2009, our net borrowings were $10.0 million.

Capital Commitments

          During the first quarter of 2010, we had capital expenditures of $7.8 million relating to our oil and natural gas operations, of which $7.5 million was allocated to drilling new development wells and recompletion operations in existing wells and $0.3 million was for acquisition costs.

          We have budgeted $50.0 million for non-acquisition capital expenditures in 2010 related to:

	•		geological, geophysical and seismic costs ($6.0 million);
	•		developmental drilling and recompletions ($38.0 million); and
	•		exploratory drilling, including leasehold acquisitions ($6.0 million).

          In our 2010 non-acquisition capital budget for developmental drilling and recompletions, we have allocated $22.0 million for drilling on our South Texas properties, $3.0 million for our North Texas Barnett Shale, $9.0 million for continued development of our Electra/Burkburnett area, $2.0 million for reworking and production enhancement operations in our other mature fields, and $2.0 million to our Pontotoc properties in Oklahoma.

          The amount and timing of our capital expenditures for calendar year 2010 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 2010. 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 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 $0.1 million at March 31, 2010 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. We have not used interest rate derivative instruments to manage our exposure to interest rate changes.

          Our long-term debt as of March 31, 2010 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 shifts. The impact of a 100-basis point increase in LIBOR interest rates above our current floor of 1.5% would result in an increase in interest expense of $2.5 million annually. A 100-basis point decrease would have no effect on interest expense until the market rate of LIBOR is above our current floor of 1.5%.

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 three months ended March 31, 2010, Shell Energy North America-US accounted for $17.6 million, or approximately 59%, 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, 2010.

          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, 2010, 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
2010			2,079			$	53.99				2,079			$	83.10			April — December			2,764			$	5.00				2,764			$	8.16			April — June, November — December
2011			—			$	—				—			$	—						6,219			$	5.00				6,219			$	9.48			January - September

		Bare Floors										Bare Floors
Year		Per Day(1)				Price				Months Covered		Per Day(1)				Price				Months Covered
2010			920			$	60.00			July - December			7,236			$	4.46			April - December
2011			1,870			$	60.00			January - September			—			$	—

          Based on March 31, 2010 NYMEX forward curves of natural gas and crude oil futures prices, adjusted for volatility by 530 basis points, we would expect to pay future cash payments of $2.9 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 $1.0 million, and if future prices were to increase by 10%, we would pay future cash payments of $6.9 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, 2010. 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, 2010 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, 2009, 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, 2009, 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]
10.3		Escrow Agreement by and 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]
10.9		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]
10.11		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]
10.12		Change in Control Separation Benefit Plan of RAM Energy Resources, Inc. and Participating Subsidiaries.*		(15) [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.		**

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]
10.3		Escrow Agreement by and 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]
10.9		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]
10.11		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]
10.12		Change in Control Separation Benefit Plan of RAM Energy Resources, Inc. and Participating Subsidiaries.*		(15) [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.		**