Battalion Oil (BATL) 8-K Vice President - Corporate Development

Immediate Release	For Further Information Contact
Monday, August 8, 2011	Robert E. Phaneuf Vice President - Corporate Development (918) 632-0680

RAM ENERGY RESOURCES REPORTS SECOND QUARTER 2011 RESULTS

AND UPDATE TO OSAGE MISSISSIPPIAN PLAY

-   RAM Reports 2Q 2011 Net Income of $8.9 Million, or $0.11 Per share

-   2Q 2011 Free Cash Flow of $7.7 Million, or $0.10 Per Share

-   Sustained production in excess  of 100 BOE per day from the Surber #1-26 Well in the Company’s Osage Mississippian Play

Tulsa, Oklahoma – RAM Energy Resources, Inc. (Nasdaq: RAME) today announced second quarter 2011 earnings and financial highlights as well as an update on its testing of several wells in the Southern Surber area of the company’s Osage Mississippian exploration play.

RAM Reports 2Q 2011 Net Income of $8.9 Million vs. $2.7 Million in 2Q2010

For the quarter ended June 30, 2011, RAM reported net income of $8.9 million, or $0.11 per share, compared to $2.7 million, or $0.03 per share, in the year-ago quarter.

Modified EBITDA (a non-GAAP measure) was $11.6 million for the 2Q11, compared with $12.5 million in last year’s quarter. Similarly, free cash flow (a non-GAAP measure) was $7.7 million, or $0.10 per share, for this year’s second quarter compared to $7.2 million, or $0.09 per share, in last year’s second quarter.

Update to Osage Concession Activity

Southern Surber Area

Modifications to the company’s production facilities and salt water disposal well have been completed, and RAM has begun the process of testing previously drilled wells that have been shut in pending completion of these improvements.  In addition, the company is adding a natural gas powered electric generator to the central tank battery which will provide electricity to run submersible pumps in the Surber #1-26 and Rickets #3-26 wells and additional pumps, if needed, to increase the capacity of the water disposal facilities.   Plans are to permit a second salt water disposal well for fluid disposal from the recently drilled wells and to service future wells in this area.  The Surber #1-26 well, which was fracture stimulated in late March, continues to produce at rates well above the type curve, producing about 108 barrels of oil equivalent per day, or BOEPD (composed of 55 barrels of oil and 317 MCF of high BTU natural gas).  Initial production testing on the Surber #1-35, Ricketts #2-35 and Surber #2-T, after having been acidized but not fractured , currently aggregates to 17 BOEPD (composed of 8 barrels of oil and 52 MCF of high BTU natural gas).  As a result of the excellent response observed to date after fracturing the Surber #1-26 well, the company is evaluating plans to also apply a slick water frac treatment to the Surber #1-35, Ricketts #2-35 and Surber #2-T, with the expectation of achieving increased production volumes. The Rickets #3-26, which was drilled to the Mississippi Chat in late 2010 and fractured stimulated in April of this year, is scheduled for testing in mid-August.  The well is currently shut in pending installation of the field electric generator to enhance salt water disposal capacity.

Central Mashunkashey Area

The Farmland #2-16 well, drilled in mid-April and completed in the Bartlesville formation, is producing 5 BOPD while recovering load water from a small fracture stimulation treatment initiated in late July.  The Christenson #3-2, which initially tested at 750 MCFPD (125 BOEPD) of natural gas from the Arbuckle formation, is awaiting additional testing uphole in the Mississippi Dense (Lime) formation.

Additional Planned Activity

RAM plans to drill four wells targeting the Mississippi formation in the third quarter of 2011, including the Jones #1-33 and Kendrick #1-27 in the Northern Jones portion of the concession, the Cooper #3-35 (a recent replacement for the previously planned Stuart #1-28 well) in the Southern Surber area, and the Farmland #1-20 well in the Central Mashunkashey area.  RAM is tentatively planning to drill its first horizontal Mississippi well in the Southern Surber area in early 2012.

The company’s Phase 2 seismic survey, which covers 31 square miles of the concession to the south and east of the 25 square mile Phase 1 seismic survey, has been completed.  Processing and interpretation are underway with initial results expected in mid-September.

1

Second Quarter Results

Crude oil and natural gas liquids (NGL) production remained consistently high in the second quarter of 2011, accounting for 71% of total company production.  Crude oil and NGL production in 2Q11 was 270 thousand barrels, up slightly compared to 269 thousand barrels of oil and NGL produced in the first quarter of 2011.  Total production in 2Q11 was 380 thousand BOE, down 31% from 549 thousand BOE in 2Q10.  Excluding production in the year ago quarter of 101 thousand BOE attributable to properties sold in December 2010, RAM’s  production would have decreased by 15%, as shown in the accompanying table, Components of Production Decline,  due  primarily to normal production declines and the shutting in of one well in Louisiana in conjunction with a major workover.   Given the company’s continuing outlook for lackluster natural gas prices in the intermediate term, capital spending has focused predominantly on the company’s substantial inventory of crude oil projects rather than those expected to be primarily natural gas.

The company’s realized price for oil increased 33% to an average of $100.81 per barrel in 2Q11 compared with last year’s second quarter average realized price of $75.57 per barrel. In addition, the price of NGLs grew 59% in 2Q11, averaging $57.34 per barrel, compared to the average of $36.04 per barrel for last year’s second quarter.   Similarly, the company’s realized price for natural gas rose 9% in 2Q11 to an average of $4.26 per Mcf compared to an average of $3.92 per Mcf  in the second quarter of 2010.  The positive impact from the 49% increase in total average price per BOE in 2Q11 more than offset the impact from asset sales and normal production declines, allowing oil and gas revenue for the second quarter to grow to $28.1 million, compared to $27.2 million in the year ago second quarter.  Oil and NGL production accounted for 90% of total oil and natural gas sales in 2Q11, up slightly from the 1Q11 level of 89%.

Derivative activity resulted in a $8.6 million net gain in the 2Q11, comprised of $10.7 million in unrealized mark-to-market gains, partially offset by realized losses from contract settlements and premium costs of $2.1 million (which included a $1.4 million charge associated with unwinding and novation of certain contracts in connection with the Company’s recent refinancing). As a result, total revenues for the quarter rose to $36.8 million.  Derivative activity in last year’s second quarter resulted in a $1.7 million net gain, raising total revenue to $29.0 million in 2Q10.

Production expenses were $8.2 million in 2Q11, down $0.5 million from $8.7 million in 2Q10; however, excluding expenses attributable to sold properties, production expenses for 2Q10 would have been level with the year ago quarter.  Production taxes were $1.5 million in 2Q11, up slightly compared to production taxes of $1.3 million, excluding asset sales, in the same quarter last year, primarily due to higher hydrocarbon prices during 2Q11.  Other expenses include an $0.8 million charge for a legal settlement relating to a disputed ownership interest in an Oklahoma well.

Six Month 2011 Results

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 production from the sale properties, 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.  Production volumes decreased 31% compared to the same period last year; however production from sold properties and the shutting in of one well in Louisiana for a major workover accounted for approximately 65%  of the decline.  Net loss for the six months ended June 30, 2011 was $1.0 million, or $0.01 per share, compared to net income of $5.1 million, or $0.07 per share, in the year-ago period.  Results for the June 30, 2011 period were negatively impacted by unrealized derivative losses and debt extinguishment costs.  Results of the June 30, 2010 period were positively impacted by unrealized derivative gains.

Modified EBITDA (a non-GAAP measure) was $24.6 million for the six months ended June 30, 2011 compared with $28.2 million in last year’s first half.   Similarly, free cash flow for the first half of 2011 totaled $15.4 million, or $0.20 a share, compared with $18.5 million, or $0.24 a share, for the six month period ending June 30, 2010.

Long-Term Debt and Liquidity

At June 30, 2011, RAM’s outstanding borrowings under its credit facility totaled $205.0 million, including $75.0 million outstanding under its second lien term loan and $130.0 million drawn on its revolver, which is currently subject to a $150.0 million borrowing base.  Total outstanding borrowings under the credit facility at June 30 last year totaled $245.0 million.

Interest expense for 2Q11 was $3.6 million compared to $5.7 million in the year-ago quarter.  The decrease is due to lower interest rates under the company’s new credit facility completed in the first quarter of this year and lower average outstanding borrowings during this year’s quarter.   The blended interest rate on borrowings was 6.2% in 2Q11 compared to 8.2% in last year’s quarter.

2

Capital Expenditures and Revised Plans for 2011

Capital expenditures during 2Q11 totaled $7.9 million, including $7.7 million attributable to development and exploration costs and $0.2 million for proved property acquisitions.  During 2Q11 RAM  participated in the drilling of 10 gross (9.2 net) development wells and 5 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 at the end of the quarter.  Five gross (5.0 net) exploration wells were either testing or waiting on completion and/or equipment at the end of the second quarter.  RAM has revised its non-acquisition capital budget for the 2011 year to $29.0 million, a decrease of $6.0 million from the previously announced level of $35.0 million.  Substantially all of the change is attributable to a reduction for development drilling and recompletions, primarily on our South Texas natural gas properties.  The total allocated to exploration as well as geological, geophysical and seismic remains the same at $17.0 million.  Consistent with prior years, the company expects all non-acquisition capital expenditures to be funded out of cash flow.

Pending the outcome of the proposed asset sale of a 90% interest in the Electra Burkburnett fields, RAM’s previously disclosed guidance of 1.7 million to 1.8 million BOE of production for 2011 and modified EBITDA of $52.0 to $55.0 million for 2011 is no longer valid.

RAM to Webcast Second Quarter 2011 Conference Call

The company’s teleconference call to review second quarter results will be broadcast live on a listen-only basis over the internet on Tuesday, August 9, 2011 at 11:00  a.m. Eastern Daylight Time.  Interested parties may access the webcast by visiting the RAM Energy Resources, Inc. website at www.ramenergy.com.  From the home page, select the Investor Relations tab and then Events and Presentations tab.   The teleconference may be accessed by dialing (877) 645-6210 (domestic) or (970) 315-0430 (international) and providing the ID number “87189296” to the operator. The webcast will be available for replay on the company’s website following the call’s completion.  An audio replay will be available until August 16, 2011 by dialing (855) 859-2056 and referencing the ID number  “87189296”.

Forward-Looking Statements

This release includes certain statements that may be deemed to be “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995.  All statements in this release, other than statements of historical facts, that address planned drilling, or other expected activities, well tests, anticipated production, the impact of oil and gas derivatives,  borrowing availability, and events or developments that the company expects or believes are forward-looking statements.  Although the company believes the expectations expressed in such forward-looking statements are based on reasonable assumptions, such statements are not guarantees of future performance and actual results or developments may differ materially from those in the forward-looking statements.  Factors that could cause actual results to differ materially from those in forward-looking statements include oil and gas prices, exploitation and exploration successes, actions taken and to be taken by the government as a result of political and economic conditions, continued availability of capital and financing, and general economic, market or business conditions as well as other risk factors described from time to time in the company’s filings with the SEC.  The company assumes no obligation to update publicly such forward-looking statements, whether as a result of new information, future events or otherwise.

About RAM Energy

RAM Energy Resources, Inc. is an independent energy company engaged in the acquisition, exploitation, exploration, and development of oil and natural gas properties and the marketing of crude oil and natural gas.  Company headquarters are in Tulsa, Oklahoma, and its common shares are traded on the Nasdaq under the symbol RAM.  For additional information, visit the company website at www.ramenergy.com.

3

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

4

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

5

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

6

RAM ENERGY RESOURCES, INC.
PRODUCTION BY AREA
(unaudited)
	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
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%
	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
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%

7

RAM Energy Resources, Inc.
Components of Production Decline
(unaudited)
		Three months ended	Six months ended
		June 30	June 30
		(MBOE)	(MBOE)
Total production,  2010		549	1,115
Declines due to:
	RAM Texas and Oklahoma gas properties sold in 2010	(101)	(205)
	Natural production declines in South Texas gas production	(24)	(71)
	Lousiana well shut-in	(12)	(17)
	Other	(32)	(55)
	Total declines	(169)	(348)
Total production, 2011		380	767

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2010 Pro Forma Selected Results Excluding Sold Properties (a)

(unaudited)

	Three months ended June 30, 2010
	Actual		Sold 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

	Six months ended June 30, 2010
	Actual		Sold 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

(a)   In December 2010 RAM sold assets in Texas and Oklahoma for net proceeds of $48 million. The table above provides actual and pro forma results for the three and six months ending June 30, 2010 to assist our description of results of operations.

9

RAM Energy Resources, Inc.
Production and Prices Summary
	Three Months Ended	Six Months Ended
	June 30, 2011	June 30, 2011
Production volumes:
Oil (MBbls)	226	448
NGL (MBbls)	44	91
Natural gas (MMcf)	660	1,370
Total (Mboe)	380	767
Average sale prices received:
Oil (per Bbl)	$                             100.81	$                               96.42
NGL (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)
NGL (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
NGL (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
General and administrative	$                               10.36	$                               10.19
Cash interest	$                                 8.82	$                               11.35
Cash taxes	$                                 1.33	$                                 0.63
Total Cash Expenses per Boe	$                               45.91	$                               47.52

10

RAM Energy Resources, Inc.

Modified EBITDA and Free Cash Flow

(non-GAAP measures)

(unaudited)

Non-GAAP Financial Measures

Modified EBITDA, a non-GAAP measure, is determined by adding the following to net income (loss): interest expense, income taxes, depreciation, amortization, accretion, share-based compensation, impairment charges, unrealized gains or losses on derivatives.  Free cash flow is also a non-GAAP measure representing Modified EBITDA after adjustments for the cash portion of interest and income taxes.  These non-GAAP measures are presented because management believes it is a useful adjunct to cash provided by operating activities under accounting principles generally accepted in the United States (GAAP).  These non-GAAP measures are widely accepted as financial indicators of an oil and gas company’s ability to generate cash used to internally fund exploration and development activities and fund debt service costs. These non-GAAP measures are not a measure of financial performance under GAAP and should not be considered as an alternative to cash provided (used) by operating, investing, or financing activities as an indicator of cash flows, or as a measure of liquidity.

$000s, except per share amounts
		Three Months Ended		Six Months Ended
		6/30/2011	6/30/2010	6/30/2011	6/30/2010
Modified EBITDA:
	Net income (loss)	$             8,936	$             2,729	$            (975)	$           5,147
	Plus:  Interest expense	$             3,291	$             4,414	$           6,675	$           8,762
	Plus:  PIK interest	$                     -	$                778	$              448	$           1,543
	Plus:  Amortization of deferred loan costs	$                272	$                522	$           2,990	$           1,044
	Plus:  Depreciation, amortization and accretion	$             5,608	$             7,345	$         11,283	$         14,441
	Plus:  Share-based compensation	$                686	$                785	$           1,355	$           1,471
	Plus:  Income tax provision (benefit)	$             3,242	$           (1,140)	$         (1,837)	$              655
	Plus:  MTM legal settlement	$                     -	$              (550)	$                  -	$            (550)
	Less:  Unrealized (gain) loss on derivatives	$          (10,432)	$           (2,419)	$          4,643	$         (4,354)
Modified EBITDA		$           11,603	$           12,464	$         24,582	$         28,159
Less:
	Cash paid for interest	$             3,351	$             4,760	$           8,706	$           9,107
	Cash paid for income tax	$                504	$                501	$              481	$              565
Free cash flow		$             7,748	$             7,203	$         15,395	$         18,487
Weighted average shares outstanding - basic		78,834	78,446	78,598	78,223
Weighted average shares outstanding - diluted		78,834	78,446	78,598	78,223
Free cash flow per share - basic		$               0.10	$               0.09	$             0.20	$             0.24
Free cash flow per share - diluted		$               0.10	$               0.09	$             0.20	$             0.24