BATTALION OIL CORP - FORM 10-Q

Attached files

file	filename
EX-31.1 - EX-31.1 - BATTALION OIL CORP	d82647exv31w1.htm
EXCEL - IDEA: XBRL DOCUMENT - BATTALION OIL CORP	Financial_Report.xls
EX-31.2 - EX-31.2 - BATTALION OIL CORP	d82647exv31w2.htm
EX-32.1 - EX-32.1 - BATTALION OIL CORP	d82647exv32w1.htm
EX-32.2 - EX-32.2 - BATTALION OIL CORP	d82647exv32w2.htm

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 June 30, 2011


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

For the transition period from to

Commission File Number: 000-50682

RAM Energy Resources, Inc.

(Exact name of registrant as specified in its charter)



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

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

(918) 663-2800
(Registrant’s telephone number, including area code)

(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding twelve months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.

Yes þ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes þ No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.


Large Accelerated Filer o		Accelerated Filer þ		Non-Accelerated Filer o (Do not check if a smaller reporting company)		Smaller Reporting Company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o No þ

At August 9, 2011, 79,087,298 shares of the Registrant’s Common Stock were outstanding.

Second Quarter 2011 Form 10-Q Report

TABLE OF CONTENTS


		Page
PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS (unaudited)		3

Condensed Consolidated Balance Sheets — June 30, 2011 and December 31, 2010		3

Condensed Consolidated Statements of Operations — Three and Six Months Ended June 30, 2011 and 2010		4

Condensed Consolidated Statements of Cash Flows — Six Months Ended June 30, 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		14

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		24

ITEM 4. CONTROLS AND PROCEDURES		25

PART II — OTHER INFORMATION		27

ITEM 1. LEGAL PROCEEDINGS		27

ITEM 1A. RISK FACTORS		27

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS		27

ITEM 3. DEFAULTS UPON SENIOR SECURITIES		27

ITEM 4. [RESERVED]		27

ITEM 5. OTHER INFORMATION		27

ITEM 6. EXHIBITS		28

SIGNATURES		32
EX-31.1
EX-31.2
EX-32.1
EX-32.2
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT


ITEM 1 — FINANCIAL STATEMENTS

RAM Energy Resources, Inc.

Condensed Consolidated Balance Sheets

(in thousands, except share and per share amounts)


	June 30,			December 31,
	2011			2010
	(unaudited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	454		$	37
Accounts receivable:
Oil and natural gas sales, net of allowance of $50 ($50 at December 31, 2010)		9,657			9,797
Joint interest operations, net of allowance of $479 ($479 at December 31, 2010)		724			631
Other, net of allowance of $34 ($48 at December 31, 2010)		152			155
Derivative assets		—			1,340
Prepaid expenses		1,030			1,657
Deferred tax asset		7,422			3,526
Inventory		3,812			3,382
Other current assets		384			4

Total current assets		23,635			20,529
PROPERTIES AND EQUIPMENT, AT COST:
Proved oil and natural gas properties and equipment, using full cost accounting		702,668			689,472
Other property and equipment		10,438			10,072

		713,106			699,544
Less accumulated depreciation, amortization and impairment		(499,994	)		(489,634	)

Total properties and equipment		213,112			209,910
OTHER ASSETS:
Deferred tax asset		29,058			31,001
Deferred loan costs, net of accumulated amortization of $381 ($5,012 at December 31, 2010)		6,622			2,609
Other		978			952

Total assets	$	273,405		$	265,001

LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
CURRENT LIABILITIES:
Accounts payable:
Trade	$	13,807		$	17,149
Oil and natural gas proceeds due others		9,455			9,414
Other		155			452
Accrued liabilities:
Compensation		1,794			1,948
Interest		502			2,448
Income taxes		334			699
Other		640			10
Derivative liabilities		1,576			—
Asset retirement obligations		352			639
Long-term debt due within one year		146			127

Total current liabilities		28,761			32,886
DERIVATIVE LIABILITIES		3,079			203
LONG-TERM DEBT		205,289			196,965
ASSET RETIREMENT OBLIGATIONS		31,504			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, 83,386,299 and 82,597,829 shares issued, 79,120,829 and 78,386,983 shares outstanding at June 30, 2011 and December 31, 2010, respectively		8			8
Additional paid-in capital		227,720			226,042
Treasury stock - 4,265,470 shares (4,210,846 shares at December 31,2010) at cost		(7,084	)		(6,976	)
Accumulated deficit		(215,882	)		(214,907	)

Stockholders’ equity		4,762			4,167

Total liabilities and stockholders’ equity	$	273,405		$	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 June 30,						Six months ended June 30,
	2011			2010			2011			2010
REVENUES AND OTHER OPERATING INCOME:
Oil and natural gas sales
Oil	$	22,783		$	19,120		$	43,195		$	38,608
Natural gas		2,812			4,818			5,704			11,247
NGLs		2,523			3,280			4,938			7,211

Total oil and natural gas sales		28,118			27,218			53,837			57,066
Realized losses on derivatives		(2,098	)		(707	)		(1,262	)		(1,605	)
Unrealized gains (losses) on derivatives		10,728			2,419			(4,225	)		4,354
Other		34			38			85			74

Total revenues and other operating income		36,782			28,968			48,435			59,889

OPERATING EXPENSES:
Oil and natural gas production taxes		1,478			1,453			2,889			3,047
Oil and natural gas production expenses		8,174			8,662			16,549			16,582
Depreciation and amortization		5,196			6,891			10,469			13,605
Accretion expense		412			454			814			836
Share-based compensation		686			785			1,355			1,471
General and administrative, overhead and other expenses, net of operator’s overhead fees		3,935			3,992			7,813			7,762

Total operating expenses		19,881			22,237			39,889			43,303

Operating income		16,901			6,731			8,546			16,586

OTHER INCOME (EXPENSE):
Interest expense		(3,563	)		(5,714	)		(10,113	)		(11,349	)
Interest income		3			2			3			4
Loss on interest rate derivatives		(362	)		—			(495	)		—
Other income (expense)		(801	)		570			(753	)		561

INCOME (LOSS) BEFORE INCOME TAXES		12,178			1,589			(2,812	)		5,802
INCOME TAX PROVISION (BENEFIT)		3,242			(1,140	)		(1,837	)		655

Net income (loss)	$	8,936		$	2,729		$	(975	)	$	5,147


BASIC INCOME (LOSS) PER SHARE	$	0.11		$	0.03		$	(0.01	)	$	0.07

BASIC WEIGHTED AVERAGE SHARES OUTSTANDING		78,834,159			78,446,305			78,598,387			78,222,925


DILUTED INCOME (LOSS) PER SHARE	$	0.11		$	0.03		$	(0.01	)	$	0.07

DILUTED WEIGHTED AVERAGE SHARES OUTSTANDING		78,834,159			78,446,305			78,598,387			78,222,925

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)


	Six months ended June 30,
	2011			2010
OPERATING ACTIVITIES:
Net income (loss)	$	(975	)	$	5,147
Adjustments to reconcile net income (loss) to net cash provided by operating activities-
Depreciation and amortization		10,469			13,605
Amortization of deferred loan costs		2,990			1,044
Non-cash interest		362			1,543
Accretion expense		814			836
Unrealized (gain) loss on commodity derivatives, net of premium amortization		5,474			(2,997	)
Unrealized loss on interest rate derivatives		418			—
Deferred income tax provision (benefit)		(1,953	)		268
Share-based compensation		1,355			1,471
Gain on disposal of other property and equipment		(22	)		(41	)
Other income		—			(550	)
Changes in operating assets and liabilities-
Accounts receivable		49			3,237
Prepaid expenses, inventory and other assets		(208	)		657
Derivative premiums		(111	)		(2,866	)
Accounts payable and proceeds due others		(3,553	)		1,028
Accrued liabilities and other		(1,459	)		(1,004	)
Income taxes payable		(365	)		(177	)
Asset retirement obligations		(242	)		—

Total adjustments		14,018			16,054

Net cash provided by operating activities		13,043			21,201


INVESTING ACTIVITIES:
Payments for oil and natural gas properties and equipment		(13,500	)		(18,666	)
Proceeds from sales of oil and natural gas properties		462			478
Payments for other property and equipment		(469	)		(358	)
Proceeds from sales of other property and equipment		11			4

Net cash used in investing activities		(13,496	)		(18,542	)

FINANCING ACTIVITIES:
Payments on long-term debt		(223,185	)		(24,576	)
Proceeds from borrowings on long-term debt		231,166			22,132
Payments for deferred loan costs		(7,003	)		—
Stock repurchased		(108	)		(326	)

Net cash provided by (used in) financing activities		870			(2,770	)

INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		417			(111	)
CASH AND CASH EQUIVALENTS, beginning of period		37			129

CASH AND CASH EQUIVALENTS, end of period	$	454		$	18

SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for income taxes	$	481		$	565

Cash paid for interest	$	8,706		$	9,107

DISCLOSURE OF NON CASH INVESTING AND FINANCING ACTIVITIES:
Asset retirement obligations	$	(129	)	$	118

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 June 30, 2011 and December 31, 2010 and the results of operations for the three and six month periods ended June 30, 2011 and 2010, and cash flows for the six month periods ended June 30, 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 and six months ended June 30, 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 natural gas industry with activities including the drilling, completion, and operation of oil and natural gas wells. The Company conducts the majority of its operations in the states of Texas, Oklahoma and Louisiana. The Company also owns and operates 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 June 30,				Six months ended June 30,
	2011		2010		2011			2010
Net income (loss)	$	8,936	$	2,729	$	(975	)	$	5,147

Weighted average shares — basic		78,834,159		78,446,305		78,598,387			78,222,925
Dilutive effect		—		—		—			—

Weighted average shares — dilutive		78,834,159		78,446,305		78,598,387			78,222,925

Basic income (loss) per share	$	0.11	$	0.03	$	(0.01	)	$	0.07

Diluted income (loss) per share	$	0.11	$	0.03	$	(0.01	)	$	0.07

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 May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and International Financial Reporting Standards (“IFRS”).” This pronouncement was issued to provide a consistent definition of fair value and ensure that the fair value measurement and disclosure requirements are similar between U.S. GAAP and IFRS. ASU 2011-04 changes certain fair value measurement principles and enhances the disclosure requirements particularly for level 3 fair value measurements. This update is effective for reporting periods beginning on or after December 15, 2011. The adoption of ASU 2011-04 is not expected to have a significant impact on the Company’s consolidated financial position or results of operations.

In June 2011, the FASB issued ASU No. 2011-05, “Presentation of Comprehensive Income.” ASU 2011-05 eliminates the option to report other comprehensive income and its components in the statement of changes in stockholders’ equity and requires an entity to present the total of comprehensive income, the components of net income and the components of other comprehensive income either in a single continuous statement or in two separate but consecutive statements. This update is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. Adoption of ASU 2011-05 will not have an impact on the Company’s consolidated financial position or results 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 June 30, 2011 and 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):


	June 30,		December 31,
	2011		2010
Credit facilities	$	205,000	$	196,521
Accrued payment-in-kind interest		—		221
Installment loan agreements		435		350

		205,435		197,092
Less amount due within one year		146		127

	$	205,289	$	196,965

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 credit facility, and Guggenheim Corporate Funding LLC is the agent for the term loan facility. The borrowing base under the revolving credit facility at June 30, 2011 was $150.0 million. The borrowing base is reviewed and redetermined effective March 31 and September 30 of each year, and between scheduled redeterminations upon request. Funds advanced under the revolving credit facility may be paid down and re-borrowed during the five-year term of the revolver, and 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 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 June 30, 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 credit 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 the Company’s 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 June 30, 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. During June 2011, the Company entered into the First Amendment to the revolving credit facility. The First Amendment amended certain definitions affecting covenant calculations and modified the terms of the Company’s natural gas derivative counterparty requirements.

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 previous credit 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 previous 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 previous 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 previous revolving credit facility was $145.0 million at December 31, 2010.

During June 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 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 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 costs associated with the previous facility totaling approximately $2.7 million in the first quarter of 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 bases 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. During the three and six months ended June 30, 2011, the Company analyzed and made no adjustment to the valuation allowance. During the three months ended June 30, 2010 the Company reduced the previously recorded valuation allowance by $4.0 million due to its estimate of taxable income that it projected would be generated in the near future and more likely than not result in the realization of its deferred tax assets. The reduction in the valuation allowance was recorded as a discrete item in the second quarter of 2010.

The Company has calculated an estimated effective tax rate for the current annual reporting period, excluding any discrete items, of 66% as of June 30, 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 income tax benefit of $1.8 million on pre-tax loss of $2.8 million for the six months ended June 30, 2011. For the six months ended June 30, 2010 the Company recorded an income tax expense of $4.7 million on a pre-tax income of $5.8 million.

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.

In May of 2008, the Company drilled the Woolley #1-23 well in Oklahoma. On July 21, 2008 the Oklahoma Corporation Commission (the “OCC”) entered a forced pooling order for the Woolley #1-23 well and the Company acquired all of the working interests attributable to those parties who did not elect to participate in the drilling of the Woolley #1-23 well. Subsequent to the pooling, certain predecessors in interest that were erroneously omitted from the forced pooling order disputed the pooling order and sought a determination that they were entitled to share in the pooled acreage. The OCC determined that the omitted predecessors in interest were not entitled to share in the pooled acreage; however, the ruling of the OCC was reversed on appeal. As a result, the Company lost a portion of its working interest in the Woolley #1-23 well and in the McAlester formation of the 40-acre tract in which the well is located. During the second quarter of 2011, the Company recorded a charge to other expense of $0.8 million, a reduction in proved oil and gas properties of $0.2 million and a liability of $0.6 million to record the estimated settlement of the dispute.

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 June 30, 2011 was $4.7 million and the fair value of the Company’s net derivative assets as of December 31, 2010 was $1.1 million, based on Level 2 criteria. See Note G.

At June 30, 2011, the carrying value of cash, accounts receivable and accounts payable 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 the first quarter of 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 June 30, 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
Period	Per Day		Price		Per Day		Price		Period		Per Day		Price		Per Day		Price
Q3’11		2,250	$	80.00		2,250	$	105.00		Q3’11		5,000	$	5.00		—		—
Q4’11		2,150	$	80.00		2,150	$	105.00		Q4’11		7,304	$	4.18		—		—

Q1’12		2,000	$	80.00		2,000	$	105.00		Q1’12		7,000	$	4.36		—		—
Q2’12		2,000	$	80.00		2,000	$	105.00		Q2’12		5,000	$	4.00		5,000	$	6.00
Q3’12		1,900	$	92.63		1,900	$	105.66		Q3’12		5,000	$	4.00		5,000	$	6.00
Q4’12		1,750	$	92.14		1,750	$	104.83		Q4’12		—		—		—		—

Q1’13		1,800	$	95.28		1,800	$	101.39		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		1,600	$	95.00		1,600	$	100.03		Q1’14		—		—		—		—
Q2’14		1,500	$	95.00		1,500	$	99.13		Q2’14		—		—		—		—

The Company’s interest rate derivative positions at June 30, 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	July — 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


⁽¹⁾		Settlement is paid to the Company if the counterparty floating rate exceeds the fixed rate and settlement is paid by the Company if the counterparty floating rate is below the fixed rate. Settlement is calculated as the difference in the fixed rate and the counterparty rate.

⁽²⁾		Subject to a minimum rate of 2%.

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 June 30, 2011 and December 31, 2010 and the consolidated statements of operations for the three and six months ended June 30, 2011 and 2010 are as follows (in thousands):

CONSOLIDATED BALANCE SHEETS


		Fair Value			Fair Value
		As of			As of
		June 30,			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		713			—
Other Assets — Oil and natural gas derivative assets	Long-Term Liabilities - Derivative liabilities		81			207

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		(2,021	)		—

Current Liabilities — Interest rate swaps derivative liabilities	Current Liabilities - Derivative liabilities		(268	)		—

Long-Term Liabilities — Oil and natural gas derivative liabilities	Long-Term Liabilities - Derivative liabilities		(2,999	)		(410	)

Long-Term Liabilities — Interest rate swaps derivative liabilities	Long-Term Liabilities - Derivative liabilities		(161	)		—


Total Derivatives Not Designated as Hedging Instruments		$	(4,655	)	$	1,137

CONSOLIDATED STATEMENTS OF OPERATIONS


	Three Months Ended June 30,						Six Months Ended June 30,
Income Statement Location	2011			2010			2011			2010			Type of Derivative
Revenue — Unrealized gains (losses) on derivatives	$	10,728		$	2,419		$	(4,225	)	$	4,354		Oil and natural gas derivatives - unrealized
Revenue — Realized losses on derivatives	$	(2,098	)	$	(707	)	$	(1,262	)	$	(1,605	)	Oil and natural gas derivatives - realized
Other Income (Expense) - Loss on interest rate derivatives	$	(296	)	$	—		$	(418	)	$	—		Interest rate derivatives - unrealized
Other Income (Expense) - Loss on interest rate derivatives	$	(66	)	$	—		$	(77	)	$	—		Interest rate derivatives - realized

During April 2011, pursuant to the Company’s new credit facilities entered into in March 2011, the Company was required to reduce the volume of its existing crude oil and natural gas derivatives so it would not exceed the maximum allowable volumes for future production periods and to novate derivative contracts to counterparties that are lenders within the new credit facilities. During the second quarter of 2011, the Company recognized $0.9 million in realized losses on the unwinding of the excess crude oil and natural gas derivatives and the $0.5 million in fees paid to complete the novation, both of which are included in realized gains and losses on derivatives in the income statement.

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 June 30, 2011, 1,171,801 shares of common stock remained reserved for issuance under the Plan.

As of June 30, 2011, the Company had $4.8 million of unrecognized compensation related to common stock awards granted under the Plan. That cost is expected to be recognized over a weighted-average period of two years. The related compensation expense recognized during the three and six months ended June 30, 2011 was $0.8 million and $1.6 million, respectively, and during the three and six months ended June 30, 2010 was $0.8 million and $1.5 million, respectively. During the three and six months ended June 30, 2011, $0.7 million and $1.4 million, respectively of recognized compensation expense was recorded as compensation expense and $0.1 million and $0.2 million, respectively was recorded as capitalized internal costs.

In May 2011, the Company granted 1,530,500 Stock Appreciation Rights (“SARs”) under the Plan. The exercise price of the SARs issued is the closing price of the Company’s stock on the date of grant, which was $1.73 per share on a weighted average basis. Compensation expense related to the SARs is based on fair value re-measured at each reporting period and recognized over the vesting period (generally four years). As of June 30, 2011, the fair value calculation resulted in no compensation expense recognized for the second quarter of 2011. The SARs expire ten years from date of grant and upon exercise. The Company will settle the SARs in cash, net of the applicable taxes.

The Company uses the Black-Scholes option pricing model to compute the fair value of the SARs. The following assumptions were used in calculating fair value:

•		The risk-free interest rate is based on the zero coupon United States Treasury yield for the expected life of the grant.

•		The dividend yield on the Company’s common stock is assumed to be zero since the Company does not pay dividends and has no current plans to do so in the future.

•		The volatility of the Company’s common stock is based on volatility of the market price of the Company’s common stock over a period of time equal to the expected term and ending on the grant date.

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 and six months ended June 30, 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			Six months ended
	June 30, 2011			June 30, 2011
Production volumes:
Oil (MBbls)		226			448
NGLs (MBbls)		44			91
Natural gas (MMcf)		660			1,370
Total (MBoe)		380			767

Average sale prices received:
Oil (per Bbl)	$	100.81		$	96.42
NGLs (per Bbl)	$	57.34		$	54.26
Natural gas (per Mcf)	$	4.26		$	4.16
Total per Boe	$	73.99		$	70.19

Cash effect of derivative contracts:
Oil (per Bbl)	$	(8.65	)	$	(6.63	)
NGLs (per Bbl)	$	—		$	—
Natural gas (per Mcf)	$	(0.22	)	$	1.25
Total per Boe	$	(5.52	)	$	(1.65	)

Average prices computed after cash effect of settlement of derivative contracts:
Oil (per Bbl)	$	92.16		$	89.79
NGLs (per Bbl)	$	57.34		$	54.26
Natural gas (per Mcf)	$	4.04		$	5.41
Total per Boe	$	68.47		$	68.54

Expenses (per Boe):
Oil and natural gas production taxes	$	3.89		$	3.77
Oil and natural gas production expenses	$	21.51		$	21.58
Amortization of full-cost pool	$	13.01		$	13.00
General and administrative	$	10.36		$	10.19
Cash interest	$	8.82		$	11.35
Cash taxes	$	1.33		$	0.63

Acquisition, Development and Exploration Capital Expenditures

The following table presents information regarding our net costs incurred in our acquisitions of proved and unproved properties, and our development and exploration activities during the three and six months ended June 30, 2011 (in thousands):


	Three months ended		Six months ended
	June 30, 2011		June 30, 2011
Development and exploratory costs	$	7,657	$	13,053
Proved property acquisition costs		223		447

Total costs incurred	$	7,880	$	13,500

During the quarter ended June 30, 2011, we participated in the drilling of ten gross (9.2 net) development wells and five gross (5.0 net) exploration wells. Nine gross (8.2 net) development wells were capable of production. One gross (1.0 net) development well was in the process of testing as of June 30, 2011. Five gross (5.0 net) exploration wells were either testing or waiting on completion and/or equipment at June 30, 2011.

Results of Operations

Quarter Ended June 30, 2011 Compared to Quarter Ended June 30, 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 June 30, 2011
Aggregate Net Production
Oil (MBbls)		128		74		16		8		226
NGLs (MBbls)		38		2		—		4		44
Natural Gas (MMcf)		412		107		105		36		660


MBoe		234		94		33		19		380


	Texas			Oklahoma			Louisiana			Other			Total
Three Months Ended June 30, 2010
Aggregate Net Production
Oil (MBbls)		142			82			22			7			253
NGLs (MBbls)		85			2			—			4			91
Natural Gas (MMcf)		774			224			192			40			1,230


MBoe		356			121			54			18			549


Change in MBoe		(122	)		(27	)		(21	)		1			(169	)
Percentage change in MBoe		-34.3	%		-22.3	%		-38.9	%		5.6	%		-30.8	%


	Three months ended
	June 30,
	2011		2010		Increase
Average sale prices:
Oil (per Bbl)	$	100.81	$	75.57		33.4	%
NGL (per Bbl)	$	57.34	$	36.04		59.1	%
Natural gas (per Mcf)	$	4.26	$	3.92		8.7	%
Per Boe	$	73.99	$	49.58		49.2	%

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 June 30, 2010
			Sold
	Actual		Assets		Pro Forma
Oil and natural gas sales (in thousands):
Oil	$	19,120	$	346	$	18,774
Natural gas		4,818		1,244		3,574
NGLs		3,280		1,291		1,989


Total oil and natural gas sales	$	27,218	$	2,881	$	24,337

Production expenses (in thousands):
Oil and natural gas production taxes	$	1,453	$	125	$	1,328
Oil and natural gas production expenses	$	8,662	$	454	$	8,208

Production volumes:
Texas (Mboe)		356		86		270
Oklahoma (Mboe)		121		15		106
Other (Mboe)		72		—		72


Total production (Mboe)		549		101		448

Oil and natural gas sales increased $0.9 million, or 3%, to $28.1 million for the three months ended June 30, 2011, as compared to $27.2 million for the three months ended June 30, 2010. Excluding asset sales, oil and natural gas sales would have increased by $3.8 million for the three months ended June 30, 2011, as compared to the same period in 2010. This increase was driven by higher commodity prices during the 2011 period, partially offset by decreased production.

Production volumes decreased 31% as compared to the same period last year. Excluding the activities related to the asset divestitures, our production volume would have decreased 15% as compared to the same period last year primarily due to shut-in of one well as a result of a major workover in Louisiana and normal production declines. Production from our Texas fields decreased 36 MBoe in the second 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 eight gross (8.0 net) development wells which were capable of production in our Texas fields. Production from our Oklahoma fields decreased 12 MBoe in the second quarter, excluding asset sales, primarily due to natural production declines. Drilling activity in Oklahoma included one gross (0.2 net) development well and five gross (5.0 net) exploratory wells. Production from our Louisiana fields decreased 21 MBoe in the second quarter 2011 due to a shut-in of one well and normal production declines. We did not drill any new wells in our Louisiana fields during the second quarter of 2011.

The average realized sales prices on a Boe basis increased substantially for the three months ended June 30, 2011, as compared to the same period in 2010. The average realized sales price for oil was $100.81 per barrel for the three months ended June 30, 2011, an increase of 33%, compared to $75.57 per barrel for the same period in 2010. The average realized sales price for NGLs was $57.34 per barrel for the three months ended June 30, 2011, an increase of 59%, compared to $36.04 per barrel for the same period in 2010. The average realized sales price for natural gas was $4.26 per Mcf for the three months ended June 30, 2011, an increase of 9%, compared to $3.92 per Mcf for the same period in 2010. The positive impact from the 49% increase in total average price per Boe in the second quarter of 2011 more than offset the impact of asset sales and normal production declines, allowing oil and natural gas sales for the second quarter to grow to $28.1 million compared to $27.2 million in the prior year period.

We recorded income before income taxes of $12.2 million for the quarter ended June 30, 2011, an increase of $10.6 million, as compared to income before income taxes of $1.6 million for the quarter ended June 30, 2010. Excluding unrealized gains on derivatives of $10.7 million, our adjusted income before income taxes for the quarter ended June 30, 2011 was $1.5 million. Excluding unrealized gains on derivatives of $2.4 million, our adjusted loss before income taxes for the quarter ended June 30, 2010 was $0.8 million.

Realized and Unrealized Gain (Loss) from Commodities Derivatives. For the quarter ended June 30, 2011, our gain from derivatives was $8.6 million, compared to $1.7 million for the quarter ended June 30, 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. During the quarter ended June 30, 2011, we recognized $0.9 million in realized losses on the unwinding of the excess crude oil and natural gas derivatives and $0.5 million in fees paid to complete the novation of derivative contracts to counterparties that are lenders within our new credit facilities, both of which are included in realized gains and losses on derivatives and required under the terms of the new credit facilities.


	Three months ended June 30,
	2011			2010
	(in thousands)
Contract settlements and premium costs:
Oil	$	(1,955	)	$	(943	)
Natural gas		(143	)		236


Realized losses		(2,098	)		(707	)
Mark-to-market gains (losses):
Oil		10,508			3,350
Natural gas		220			(931	)


Unrealized gains		10,728			2,419


Realized and unrealized gains	$	8,630		$	1,712

Oil and Natural Gas Production Taxes. Our oil and natural gas production taxes were $1.5 million for the quarter ended June 30, 2011, compared to $1.3 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 increase is due primarily to higher commodity prices in the 2011 period. As a percentage of oil and natural gas sales, our oil and natural gas production taxes were approximately 5% for each of the quarters ended June 30, 2011 and 2010.

Oil and Natural Gas Production Expense. Our oil and natural gas production expense was $8.2 million for each of the quarters ended June 30, 2011 and 2010, excluding asset sales for the quarter ended June 30, 2010. Our oil and natural gas production expense was $21.51 per Boe compared to $15.78 per Boe for the quarter ended June 30, 2010, an increase of 36%. The increase per Boe is primarily due to the asset sales, as the sold assets in 2010 were predominantly shale gas producing assets which had relatively lower lease operating expenses per Boe. As a percentage of oil and natural gas sales, oil and natural gas production expense was 29% for the quarter ended June 30, 2011, as compared to 32% for the quarter ended June 30, 2010. This decrease is due to higher oil and natural gas sales due to higher commodity prices in the 2011 period.

Amortization and Depreciation Expense. Our amortization and depreciation expense decreased $1.7 million, or 25%, for the quarter ended June 30, 2011, compared to the quarter ended June 30, 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 $4.9 million was $13.01 per Boe for the quarter ended June 30, 2011, compared to $6.6 million, or $12.06 per Boe, for the quarter ended June 30, 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 the quarter ended June 30, 2011, compared to $0.5 million for the quarter ended June 30, 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. In May 2011, our Board of Directors awarded stock appreciation rights (“SARs”) under our 2006 Long-Term Incentive Plan. Share-based compensation expense attributable to these awards is based on the fair value re-measured at each reporting period and recognized over the four-year vesting period. The fair value calculation resulted in no compensation expense recognized for the three months ended June 30, 2011. For the quarter ended June 30, 2011, we recognized a total of $0.8 million share-based compensation related to restricted stock awards, the same as the year ago quarter. During the three months ended June 30, 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 June 30, 2011, our general and administrative expense was $3.9 million, compared to $4.0 million for the quarter ended June 30, 2010, a decrease of $0.1 million, or 1%. The decrease was primarily due to lower employee related expenses in the 2011 period.

Interest Expense. We recorded interest expense of $3.6 million for the quarter ended June 30, 2011, as compared to $5.7 million for the second quarter of the previous year. 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 second quarter of 2011 compared to 8.2% in the 2010 period.

Loss on Interest Rate Derivatives. We incurred $0.4 million net realized and unrealized loss attributable to mark-to-market value of interest rate swaps in the second quarter of 2011. We had no interest rate derivatives in effect in the year ago quarter.

Other Income (Expense). For the three months ended June 30, 2011, our other expense was $0.8 million, compared to other income of $0.6 million for the three months ended June 30, 2010. For the quarter ended June 30, 2011, we were party to a lawsuit and incurred approximately $0.8 million in litigation expenses. For the three months ended June 30, 2010, we reduced a contingency accrual by $0.6 million related to settlement of pending litigation.

Income Taxes. For the three months ended June 30, 2011, we recorded income tax expense of $3.2 million on a pre-tax income of $12.2 million. For the three months ended June 30, 2010, we recorded income tax expense of $2.9 million on a pre-tax net income of $1.6 million. In addition, we recorded a $4.0 million tax benefit resulting from a decrease in our valuation allowance as a discrete item during the three months ended June 30, 2010.

Six Months Ended June 30, 2011 Compared to the Six Months Ended June 30, 2010

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
Six Months Ended June 30, 2011
Aggregate Net Production
Oil (MBbls)		253		148		32		15		448
NGLs (MBbls)		79		5		—		7		91
Natural Gas (MMcf)		856		187		258		69		1,370


MBoe		474		184		75		34		767


	Texas			Oklahoma			Louisiana			Other			Total
Six Months Ended June 30, 2010
Aggregate Net Production
Oil (MBbls)		291			163			39			17			510
NGLs (MBbls)		177			5			—			7			189
Natural Gas (MMcf)		1,638			436			347			78			2,499


MBoe		741			240			97			37			1,115


Change in MBoe		(267	)		(56	)		(22	)		(3	)		(348	)
Percentage change in MBoe		-36.0	%		-23.3	%		-22.7	%		-8.1	%		-31.2	%


	Six months ended June 30,				Increase/
	2011		2010		(Decrease)
Average sale prices:
Oil (per Bbl)	$	96.42	$	75.70		27.4	%
NGLs (per Bbl)	$	54.26	$	38.15		42.2	%
Natural gas (per Mcf)	$	4.16	$	4.50		-7.6	%
Per Boe	$	70.19	$	51.18		37.1	%

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 six months ended June 30, 2010 excluding those sold properties to assist our description of results of operations:


	Six months ended June 30, 2010
			Sold
	Actual		Assets		Pro Forma
Oil and natural gas sales (in thousands):
Oil	$	38,608	$	677	$	37,931
Natural gas		11,247		2,874		8,373
NGLs		7,211		2,773		4,438


Total oil and natural gas sales	$	57,066	$	6,324	$	50,742

Production expenses (in thousands):
Oil and natural gas production taxes	$	3,047	$	253	$	2,794
Oil and natural gas production expenses	$	16,582	$	945	$	15,637

Production volumes:
Texas (Mboe)		741		171		570
Oklahoma (Mboe)		240		34		206
Other (Mboe)		134		—		134


Total production (Mboe)		1,115		205		910

Oil and natural gas sales decreased $3.2 million, or 6% to $53.8 million for the six months ended June 30, 2011, as compared to $57.1 million for the same period in 2010. Excluding asset sales, oil and natural gas sales would have increased $3.1 million for the six months ended June 30, 2011 as compared to the same period in 2010. This increase was driven primarily by higher commodity prices during the 2011 period, partially offset by decreased production.

Production volumes decreased 31% 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 shut-in of one well as a result of a major workover in Louisiana and normal production declines. Production from our Texas fields decreased 96 MBoe for the first six months of 2011, excluding asset sales, due to a decline in well performance in our South Texas gas properties and from normal production declines. Drilling activity included 20 gross (19.3 net) development wells in our Texas fields. Of the 20 development wells in our Texas fields, 18 gross (18.0 net) wells were capable of production. Production from our Oklahoma fields decreased 22 MBoe for the first six months of 2011, excluding asset sales, primarily due to natural production declines. Drilling activity in Oklahoma included one gross (0.2 net) development well and seven gross (7.0 net) exploratory wells. Production from our Louisiana fields decreased 22 MBoe for the first six months of 2011 due to a shut-in of one well and normal production declines. We did not drill any new wells in our Louisiana fields during the six months ended June 30, 2011.

The average realized sales prices increased substantially for the six months ended June 30, 2011, as compared to the same period in 2010. The average realized sales price for oil was $96.42 per barrel for the six months ended June 30, 2010, an increase of 27%, compared to $75.70 per barrel for the same period in 2010. The average realized sales price for NGLs was $54.26 for the six months ended June 30, 2011, an increase of 42%, compared to $38.15 per barrel for the same period in 2010. The average realized sales price for natural gas was $4.16 per Mcf for the six months ended June 30, 2011, a decrease of 8%, compared to $4.50 per Mcf for the same period in 2010. The positive impact from the 37% increase in total average price per Boe in the first six months of 2011 did not fully offset the impact of asset sales and normal production declines, causing oil and natural gas sales for the first six months of 2011 to decline to $53.8 million compared to $57.1 million in the same period in 2010.

We recorded loss before income taxes of $2.8 million for the six months ended June 30, 2011, a decrease of $8.6 million, as compared to income before income taxes of $5.8 million for the six months ended June 30, 2010. Excluding unrealized losses on derivatives of $4.2 million and debt extinguishment and loan amortization costs of $2.7 million, our adjusted income before income taxes for the six months ended June 30, 2011 was $4.1 million. Excluding unrealized gains on derivatives of $4.4 million, our adjusted income before income taxes for the six months ended June 30, 2010 was $1.4 million.

Realized and Unrealized Gain (Loss) from Commodities Derivatives. For the six months ended June 30, 2011, our loss from derivatives was $5.5 million compared to a gain of $2.7 million for the six months ended June 30, 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. During the six months ended June 30, 2011, we recognized $0.9 million in realized losses on the unwinding of the excess crude oil and natural gas derivatives and $0.5 million in fees paid to complete the novation of derivative contracts to counterparties that are lenders within our new credit facilities, both of which are included in realized gains and losses on derivatives and required under the terms of the new credit facilities.


	Six months ended June 30,
	2011			2010
	(in thousands)
Contract settlements and premium costs:
Oil	$	(2,972	)	$	(1,931	)
Natural gas		1,710			326

Realized losses		(1,262	)		(1,605	)
Mark-to-market gains (losses):
Oil		(2,727	)		3,479
Natural gas		(1,498	)		875

Unrealized gains (losses)		(4,225	)		4,354

Realized and unrealized gains (losses)	$	(5,487	)	$	2,749

Oil and Natural Gas Production Taxes. Our oil and natural gas production taxes were $2.9 million for the six months ended June 30, 2011, compared to $2.8 million, excluding asset sales, for the comparable six months of the previous year. The increase is due principally to higher commodity prices in the 2011 period. Production taxes vary by state. Most production taxes are based on realized prices at the wellhead, while Louisiana production tax is based on volumes for natural gas and value for oil. As revenues or volumes from oil and natural gas sales increase or decrease, production taxes on these sales also increase or decrease directly. As a percentage of oil and natural gas sales, oil and natural gas production taxes were 5% for the six months ended June 30, 2011 and 2010.

Oil and Natural Gas Production Expense. Our oil and natural gas production expense was $16.5 million for the six months ended June 30, 2011, an increase of $0.9 million, or 6%, from the $15.6 million excluding asset sales for the six months ended June 30, 2010. For the six months ended June 30, 2011, our oil and natural gas production expense was $21.58 per Boe compared to $14.87 per Boe for the six months ended June 30, 2010, an increase of 45%. The increase per Boe is primarily due to the asset sales, as the sold assets in 2010 were predominantly shale gas producing assets which had relatively lower lease operating expenses per Boe. As a percentage of oil and natural gas sales, oil and natural gas production expense was 31% for the six months ended June 30, 2011, as compared to 29% for the six months ended June 30, 2010. This increase results from the decrease in oil and natural gas sales due to a decline in production in the 2011 period.

Amortization and Depreciation Expense. Our amortization and depreciation expense decreased $3.1 million, or 23%, for the six months ended June 30, 2011, compared to the six months ended June 30, 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 $10.0 million was $13.00 per Boe for the six months ended June 30, 2011, an increase per Boe of 11% compared to $13.1 million, or $11.73 per Boe for the six months ended June 30, 2010.

Accretion Expense. Topic 410, 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 $0.8 million for the six months ended June 30, 2011 and 2010.

In May 2011, our Board of Directors awarded stock appreciation rights (“SARs”) under our 2006 Long-Term Incentive Plan. Share-based compensation expense attributable to these awards is based on the fair value re-measured at each reporting period and recognized over the four-year vesting period. The fair value calculation resulted in no compensation expense recognized for the six months ended June 30, 2011. For the six months ended June 30, 2011, we recognized a total of $1.6 million share-based compensation related to restricted stock awards compared to $1.5 million for the six months ended June 30, 2010. The increase was primarily due to a higher number of shares outstanding in the 2011 period. During the six months ended June 30, 2011, $1.4 million of recognized compensation was recorded as compensation expense and $0.2 million was recorded as capitalized internal costs.

General and Administrative Expense. For the six months ended June 30, 2011 and 2010, our general and administrative expense was recorded at $7.8 million.

Interest Expense. We recorded interest expense of $10.1 million for the six months ended June 30, 2011, as compared to $11.3 million for the first six months of the previous year. Of that $10.1 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 six months 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% for the six months ended June 30, 2011as compared to 8.2% in the 2010 period.

Loss on Interest Rate Derivatives. We incurred $0.5 million net realized and unrealized loss attributable to interest rate swaps for the six months ended June 30, 2011. Our realized and unrealized loss was the net result of recording an actual contract settlement and unrealized losses attributable to the mark-to-market values of our interest rate swap contract at the end of the period. We had no interest rate derivatives in effect in the six months ended June 30, 2010.

Other Income (Expense). For the six months ended June 30, 2011, our other expense was $0.8 million, compared to other income of $0.6 million for the six months ended June 30, 2010. For the six months ended June 30, 2011, we were party to a lawsuit and incurred approximately $0.8 million in litigation expenses. For the six months ended June 30, 2010, we reduced a contingency accrual by $0.6 million related to settlement of pending litigation.

Income Taxes. For the six months ended June 30, 2011, we recorded income tax benefit of $1.8 million on pre-tax loss of $2.8 million. For the six months ended June 30, 2010, we recorded income tax expense of $4.7 million on pre-tax income of $5.8 million. In addition, we recorded a $4.0 million tax benefit resulting from a decrease in our valuation allowance as a discrete item during the six months ended June 30, 2010.

Liquidity and Capital Resources

As of June 30, 2011, we had cash and cash equivalents of $0.5 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 June 30, 2011 was $47.4 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 June 30, 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 June 30, 2011, we had an accumulated deficit of $215.9 million and a working capital deficit of $5.1 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 current borrowing base under the revolving credit facility is $150.0 million. The borrowing base is reviewed and redetermined effective March 31 and September 30 of each year, and between scheduled redeterminations upon request. Funds advanced under the revolving credit facility may be paid down and re-borrowed during the five-year term of the revolver, and 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 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 June 30, 2011, our commodity hedging represented approximately 67% of our projected production volumes through June 30, 2014. On June 10, 2011, we entered into the First Amendment to the revolving credit facility.

The First Amendment amended certain definitions affecting covenant calculations and modified the terms of our natural gas derivative counterparty requirements.

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 December 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 June 30, 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 June 30, 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 six months ended June 30, 2011, our net loss was $1.0 million, as compared to a net income of $5.1 million for the six months ended June 30, 2010. Adjustments (primarily non-cash items such as depreciation and amortization, unrealized (gains) losses and deferred income taxes) were $19.9 million for the six months ended June 30, 2011, compared to $15.2 million for the first six months of 2010, an increase of $4.7 million. The change in unrealized (gains) losses partially offset by depreciation and amortization and deferred income taxes caused most of this increase. Working capital changes for the six months ended June 30, 2011 were a negative $5.9 million compared to working capital changes of $0.9 million for the six months ended June 30, 2010. For the six months ended June 30, 2011 and 2010, in total, net cash provided by operating activities was $13.0 million and $21.2 million, respectively.

Cash Flow From Investing Activities. For the six months ended June 30, 2011, net cash used in our investing activities was $13.5 million, consisting of $14.0 million in payments for oil and gas properties and other equipment offset by $0.5 million in proceeds from sales of property and equipment. For the six months ended June 30, 2010, net cash used in our investing activities was $18.5 million.

Cash Flow From Financing Activities. For the six months ended June 30, 2011, net cash provided by our financing activities was $0.9 million, compared to net cash used of $2.8 million in our financing activities for the six months ended June 30, 2010. During the first six months of 2011, we received proceeds of $231.2 million from borrowings on long-term debt. We also reduced our long-term debt by $223.2 million, paid $7.0 million for deferred loan costs, and incurred $0.1 million in common stock repurchased from participants under our 2006 Long-Term Incentive Plan to net settle withholding tax liability. During the first six months of 2010, we received proceeds of $22.1 million from borrowings on long-term debt, which was offset by $24.6 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 six months ended June 30, 2011, we had capital expenditures of $13.5 million relating to our oil and natural gas operations, of which $13.1 million was allocated to drilling new exploration and development wells and recompletion operations in existing wells and $0.4 million was for acquisition costs.

We have revised our budget to $29.0 million for non-acquisition capital expenditures in 2011 related to:

	•		developmental drilling and recompletions ($12.0 million);

	•		exploration, including leasehold acquisition, seismic and exploratory drilling ($7.8 million); and

	•		geological, geophysical and contingencies ($9.2 million).

In our 2011 non-acquisition capital budget for developmental drilling and recompletions, we have allocated $6.9 million for continued development of our Electra/Burkburnett area, $1.5 million for recompletions in our Louisiana properties, $1.2 million for recompletions in our South Texas properties and $2.4 million for reworking and production enhancement operations in other 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 $3.8 million at June 30, 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 March 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 June 30, 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 June 30, 2011. LIBOR rates were less than 100-basis points as of June 30, 2011, so any decrease in interest rates would have resulted in a nominal decrease in interest expense under our revolver as of June 30, 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 June 30, 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 June 30, 2011, Shell Energy North America-US accounted for $20.0 million, or approximately 71%, 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 June 30, 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 June 30, 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
Q3’11		2,250	$	80.00		2,250	$	105.00		Q3’11		5,000	$	5.00		—		—
Q4’11		2,150	$	80.00		2,150	$	105.00		Q4’11		7,304	$	4.18		—		—

Q1’12		2,000	$	80.00		2,000	$	105.00		Q1’12		7,000	$	4.36		—		—
Q2’12		2,000	$	80.00		2,000	$	105.00		Q2’12		5,000	$	4.00		5,000	$	6.00
Q3’12		1,900	$	92.63		1,900	$	105.66		Q3’12		5,000	$	4.00		5,000	$	6.00
Q4’12		1,750	$	92.14		1,750	$	104.83		Q4’12		—		—		—		—

Q1’13		1,800	$	95.28		1,800	$	101.39		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		1,600	$	95.00		1,600	$	100.03		Q1’14		—		—		—		—
Q2’14		1,500	$	95.00		1,500	$	99.13		Q2’14		—		—		—		—

Based on June 30, 2011, NYMEX forward curves of natural gas and crude oil futures prices, adjusted for volatility by 300 basis points for crude oil derivative contracts and 55 basis points for natural gas derivative contracts, we would expect to pay future cash payments of $4.3 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 $10.2 million, and if future prices were to increase by 10%, we would expect to pay future cash payments of $20.2 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 June 30, 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 June 30, 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.

In May of 2008, we drilled the Woolley #1-23 well in Oklahoma. On July 21, 2008 the Oklahoma Corporation Commission (the “OCC”) entered a forced pooling order for the Woolley #1-23 well and we acquired all of the working interests attributable to those parties who did not elect to participate in the drilling of the Woolley #1-23 well. Subsequent to the pooling, certain predecessors in interest that were erroneously omitted from the forced pooling order disputed the pooling order and sought a determination that they were entitled to share in the pooled acreage. The OCC determined that the omitted predecessors in interest were not entitled to share in the pooled acreage; however, the ruling of the OCC was reversed on appeal. As a result, we lost a portion of our working interest in the Woolley #1-23 well and in the McAlester formation of the 40-acre tract in which the well is located. During the second quarter of 2011, we recorded a charge to other expense of $0.8 million, a reduction in proved oil and gas properties of $0.2 million and a liability of $0.6 million to record the estimated settlement of the dispute.

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.

Due to recent actions at the federal level, we are updating and restating the following risk factor previously set forth in our 2010 Form 10-K:

Regulation related to global warming and climate change could have an adverse effect on our operations and demand for oil and natural gas.

The U.S. Congress has previously considered legislation to reduce emissions of greenhouse gases, including carbon dioxide, methane, and nitrous oxide among others, which some studies have suggested may be contributing to warming of the earth’s atmosphere. However, legislation to reduce greenhouse gases appears less likely in the near term. As a result, regulation of greenhouse gases will continue to result primarily from regulatory action by EPA or by the several states that have already taken legal measures to reduce emissions of greenhouse gases.

Federal regulation. The Environmental Protection Agency (EPA) has adopted regulations requiring Clean Air Act (CAA) permitting of greenhouse gas emissions from stationary sources. As a result of the U.S. Supreme Court’s decision in Massachusetts, et al. v. EPA finding that greenhouse gases fall within the CAA’s definition of “air pollutant,” the EPA was required to determine whether concentrations of greenhouse gases in the atmosphere “endanger” public health or welfare, and whether emissions of greenhouse gases from motor vehicles may “cause or contribute” to this endangerment. On December 15, 2009, EPA promulgated its final rule, “Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air Act”. On May 7, 2010, EPA and the Department of Transportation’s National Highway Traffic and Safety Administration, or NHTSA, promulgated a final action establishing a national program providing new standards for certain motor vehicles to reduce greenhouse gas emissions and improve fuel economy. While these motor vehicle regulations do not directly impact oil and natural gas production operations, they automatically trigger application of the Prevention of Significant Deterioration (“PSD”) and Title V Operating Permit programs for stationary sources of greenhouse gas emission sources, potentially including oil and natural gas production operations. On June 3, 2010, EPA promulgated its “Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule,” to add new higher thresholds of 75,000 tons per year carbon dioxide equivalents (“CO₂e”) for modifications and 100,000 tons per year CO₂e for new sources.

Additionally, EPA has promulgated separate regulations requiring greenhouse gas emission reporting from certain industry sectors, including natural gas production. On October 30, 2009, EPA promulgated a final mandatory greenhouse gas reporting rule which will assist EPA in developing policy approaches to greenhouse gas regulation. This reporting rule became effective on December 29, 2009. On November 30, 2010, EPA promulgated additional mandatory greenhouse gas reporting rules that apply specifically to oil and natural gas production for implementation in 2011.

Though under review by the D.C. Circuit, EPA’s rules promulgated thus far have survived petitions for stay, and thus are currently final and effective, and will remain so unless vacated or remanded by the court, or unless Congress adopts legislation preempting EPA’s regulatory authority to address greenhouse gases under the CAA.

International treaties. Other nations have already agreed to regulate emissions of greenhouse gases pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol,” an international treaty pursuant to which participating countries (not including the United States) agreed to reduce their emissions of greenhouse gases to below 1990 levels by 2012. Though the 16th meeting of the Council of the Parties in Mexico in November and December 2010 did not produce a legally binding final agreement, international negotiations continue, with the participation of the United States.

International developments, passage of state or federal climate control legislation or other regulatory initiatives, the adoption of regulations by EPA and analogous state agencies that restrict emissions of greenhouse gases in areas in which we conduct business, or development of caselaw allowing claims based upon greenhouse gas emissions, could have an adverse effect on our operations and financial condition as a result of material increases in operating and production costs and litigation expense due to expenses associated with monitoring, reporting, permitting and controlling greenhouse gas emissions or litigating claims related to emissions of greenhouse gases, as well as reduced demand for fossil fuels generally.

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]

10.4	Registration Rights Agreement among Registrant and the investors signatory thereto dated May 8, 2006.	(1) [10.17]

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]

10.14.1	First Amendment to Revolving Credit Agreement dated as of June 10, 2011, by and between RAM Energy Resources, Inc., as Borrower, and Sun Trust Bank, as Administrative Agent, Capital One, N.A., as Syndication Agent, and the financial institutions named therein as the Lenders.	(25) [10.14.1]

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.	**

101.INS	XBRL Instance Document	***

101.SCH	XBRL Taxonomy Extension Schema Document	***

101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document	***

101.LAB	XBRL Taxonomy Extension Label Linkbase Document	***

101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document	***


*		Management contract or compensatory plan or arrangement.


**		Filed herewith.

***		Furnished with this report. In accordance with Rule 406T of Regulation S-T, the information in these exhibits shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to liability under that section, and shall not be incorporated by reference into any registration statement or other document filed under the Securities Act of 1933, as amended, except as expressly set forth by specific reference in such filing.

(1)		Filed as an exhibit to the Registrant’s Current Report on Form 8-K filed on May 12, 2006, as the exhibit number indicated in brackets and incorporated by reference herein.

(2)		Filed as an exhibit to the Registrant’s Registration Statement on Form S-1 (SEC File No. 333-113583) as the exhibit number indicated in brackets and incorporated by reference herein.

(3)		Filed as an exhibit to the Registrant’s Current Report on Form 8-K filed on October 26, 2005, as the exhibit number indicated in brackets and incorporated by reference herein.

(4)		Included as an annex to the Registrant’s Definitive Proxy Statement (No. 000-50682), dated April 12, 2006, as the annex letter indicated in brackets and incorporated by reference herein.

(5)		Filed as an exhibit to the Registrant’s Current Report on Form 8-K on October 20, 2006, as the exhibit number indicated in brackets and incorporated by reference herein.

(6)		Filed as an exhibit to the Registrant’s Current Report on Form 8-K on June 5, 2006, as the exhibit number indicated in brackets and incorporated by reference herein.

(7)		Filed as an exhibit to the Registrant’s Registration Statement on Form S-1 (SEC File No. 333-138922) as the exhibit number indicated in brackets and incorporated by reference herein.

(8)		Filed as an exhibit to the Registrant’s Current Report on Form 8-K filed on February 2, 2007, as the exhibit number indicated in brackets and incorporated by reference herein.

(9)		Filed as an exhibit to Registrant’s Form 8-K dated November 29, 2007, as the exhibit number indicated in brackets and incorporated by reference herein.

(10)		Filed as an exhibit to Registrant’s Form 8-K dated February 26, 2008, as the exhibit number indicated in brackets and incorporated by reference herein.

(11)		Filed as an exhibit to Registrant’s Definitive Proxy Statement (No. 000-50682) dated April 14, 2008, as the exhibit number indicated in the brackets and incorporated herein by reference.

(12)		Filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q filed on May 9, 2008, as the exhibit number indicated in brackets and incorporated by reference herein.

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

(14)		Filed as an exhibit to Registrant’s Form 8-K filed March 25, 2009, as the exhibit number indicated in brackets and incorporated by reference herein.

(15)		Filed as an exhibit to Registrant’s Annual Report on Form 10-K filed on March 12, 2009, as the exhibit number indicated in brackets and incorporated by reference herein.

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

(17)		Filed as an exhibit to Registrant’s Form 8-K filed March 18, 2010, as the exhibit number indicated in brackets and incorporated by reference herein.


(18)		Filed as an exhibit to Registrant’s Form 8-K filed May 7, 2010, as the exhibit number indicated in brackets and incorporated by reference herein.

(19)		Filed as an exhibit to Registrant’s Form 8-K filed November 2, 2010, as the exhibit number indicated in brackets and incorporated by reference herein.

(20)		Filed as an exhibit to Registrant’s Form 8-K filed December 8, 2010, as the exhibit number indicated in brackets and incorporated by reference herein.

(21)		Filed as an exhibit to Registrant’s Form 8-K filed March 10, 2011, as the exhibit number indicated in brackets and incorporated by reference herein.

(22)		Filed as an exhibit to Registrant’s Form 10-K filed March 16, 2011, as the exhibit number indicated in brackets and incorporated by reference herein.

(23)		Filed as an exhibit to Registrant’s Form 8-K filed March 17, 2011, as the exhibit number indicated in brackets and incorporated by reference herein.

(24)		Filed as an exhibit to Registrant’s Form 8-K filed March 24, 2011, as the exhibit number indicated in brackets and incorporated by reference herein.

(25)		Filed as an exhibit to Registrant’s Form 8-K filed June 15, 2011, as the exhibit number indicated in brackets and incorporated by reference herein.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.


	RAM ENERGY RESOURCES, INC.
August 9, 2011	By:	/s/ Larry E. Lee
	Name:		Larry E. Lee
	Title:		Chairman, President and Chief Executive Officer


August 9, 2011	By:	/s/ G. Les Austin
	Name:		G. Les Austin
	Title:		Senior Vice President and Chief Financial Officer

INDEX TO EXHIBITS


Exhibit	Description	Method of Filing
3.1	Amended and Restated Certificate of Incorporation of the Registrant.	(1) [3.1]

3.2	Amended and Restated Bylaws of the Registrant.	(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]

10.4	Registration Rights Agreement among Registrant and the investors signatory thereto dated May 8, 2006.	(1) [10.17]

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]

10.14.1	First Amendment to Revolving Credit Agreement dated as of June 10, 2011, by and between RAM Energy Resources, Inc., as Borrower, and Sun Trust Bank, as Administrative Agent, Capital One, N.A., as Syndication Agent, and the financial institutions named therein as the Lenders.	(25) [10.14.1]

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.	**

101.INS	XBRL Instance Document	***

101.SCH	XBRL Taxonomy Extension Schema Document	***

101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document	***

101.LAB	XBRL Taxonomy Extension Label Linkbase Document	***

101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document	***


*		Management contract or compensatory plan or arrangement.


**		Filed herewith.

***		Furnished with this report. In accordance with Rule 406T of Regulation S-T, the information in these exhibits shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to liability under that section, and shall not be incorporated by reference into any registration statement or other document filed under the Securities Act of 1933, as amended, except as expressly set forth by specific reference in such filing.

(1)		Filed as an exhibit to the Registrant’s Current Report on Form 8-K filed on May 12, 2006, as the exhibit number indicated in brackets and incorporated by reference herein.

(2)		Filed as an exhibit to the Registrant’s Registration Statement on Form S-1 (SEC File No. 333-113583) as the exhibit number indicated in brackets and incorporated by reference herein.

(3)		Filed as an exhibit to the Registrant’s Current Report on Form 8-K filed on October 26, 2005, as the exhibit number indicated in brackets and incorporated by reference herein.

(4)		Included as an annex to the Registrant’s Definitive Proxy Statement (No. 000-50682), dated April 12, 2006, as the annex letter indicated in brackets and incorporated by reference herein.

(5)		Filed as an exhibit to the Registrant’s Current Report on Form 8-K on October 20, 2006, as the exhibit number indicated in brackets and incorporated by reference herein.

(6)		Filed as an exhibit to the Registrant’s Current Report on Form 8-K on June 5, 2006, as the exhibit number indicated in brackets and incorporated by reference herein.

(7)		Filed as an exhibit to the Registrant’s Registration Statement on Form S-1 (SEC File No. 333-138922) as the exhibit number indicated in brackets and incorporated by reference herein.

(8)		Filed as an exhibit to the Registrant’s Current Report on Form 8-K filed on February 2, 2007, as the exhibit number indicated in brackets and incorporated by reference herein.

(9)		Filed as an exhibit to Registrant’s Form 8-K dated November 29, 2007, as the exhibit number indicated in brackets and incorporated by reference herein.

(10)		Filed as an exhibit to Registrant’s Form 8-K dated February 26, 2008, as the exhibit number indicated in brackets and incorporated by reference herein.

(11)		Filed as an exhibit to Registrant’s Definitive Proxy Statement (No. 000-50682) dated April 14, 2008, as the exhibit number indicated in the brackets and incorporated herein by reference.

(12)		Filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q filed on May 9, 2008, as the exhibit number indicated in brackets and incorporated by reference herein.

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

(14)		Filed as an exhibit to Registrant’s Form 8-K filed March 25, 2009, as the exhibit number indicated in brackets and incorporated by reference herein.

(15)		Filed as an exhibit to Registrant’s Annual Report on Form 10-K filed on March 12, 2009, as the exhibit number indicated in brackets and incorporated by reference herein.

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

(17)		Filed as an exhibit to Registrant’s Form 8-K filed March 18, 2010, as the exhibit number indicated in brackets and incorporated by reference herein.


(18)		Filed as an exhibit to Registrant’s Form 8-K filed May 7, 2010, as the exhibit number indicated in brackets and incorporated by reference herein.

(19)		Filed as an exhibit to Registrant’s Form 8-K filed November 2, 2010, as the exhibit number indicated in brackets and incorporated by reference herein.

(20)		Filed as an exhibit to Registrant’s Form 8-K filed December 8, 2010, as the exhibit number indicated in brackets and incorporated by reference herein.

(21)		Filed as an exhibit to Registrant’s Form 8-K filed March 10, 2011, as the exhibit number indicated in brackets and incorporated by reference herein.

(22)		Filed as an exhibit to Registrant’s Form 10-K filed March 16, 2011, as the exhibit number indicated in brackets and incorporated by reference herein.

(23)		Filed as an exhibit to Registrant’s Form 8-K filed March 17, 2011, as the exhibit number indicated in brackets and incorporated by reference herein.

(24)		Filed as an exhibit to Registrant’s Form 8-K filed March 24, 2011, as the exhibit number indicated in brackets and incorporated by reference herein.

(25)		Filed as an exhibit to Registrant’s Form 8-K filed June 15, 2011, as the exhibit number indicated in brackets and incorporated by reference herein.

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