Exhibit 99.1

DELTA PETROLEUM CORPORATION
Daniel Taylor, Chairman
Carl Lakey, President and CEO
Kevin Nanke, Treasurer and CFO
Broc Richardson, V.P. Corporate Development and IR
370 17th Street, Suite 4300
Denver, Colorado 80202

For Immediate Release

DELTA PETROLEUM CORPORATION ANNOUNCES
SECOND QUARTER 2011 RESULTS

     DENVER, Colorado (August 4, 2011) – Delta Petroleum Corporation (“Delta” or the “Company”) (NASDAQ Capital Market: DPTRD), an independent oil and gas exploration and development company, today announced its financial and operating results for the second quarter 2011.

     Carl Lakey, Delta’s CEO and President stated, “We are pleased to provide our shareholders with another solid operating quarter coupled with the accomplishment of some very important strategic steps. We sold our remaining non-core assets, which reduced our leverage and provided sufficient liquidity to continue our deep shale evaluation and development in the Vega Area. While the strategic alternatives process, the 2C well results, and the Netherland Sewell report were all announced subsequent to the end of the quarter, much of the efforts that went into those steps occurred in the second quarter. The 2B and 2C well results and Netherland Sewell’s report are very important contributions that support Delta’s intrinsic value and aid our strategic alternatives process.”

VEGA AREA SHALE EVALUATION UPDATE

     As previously announced, the Delta 2C well began producing hydrocarbons on Wednesday, July 20, at a rate of 5.4 million cubic feet of gas per day (MMcf/d), which was choke-restricted with a 7/64 of an inch choke and 8,360 psi of flowing tubing pressure. Gas sales from the well began on Thursday, July 21 from the Niobrara and Frontier formations only. The well is currently producing between 2.5 – 3.5 MMcf/d with 6,100 psi of flowing tubing pressure. The well choke is currently set at 9/64 of an inch. The Mancos shale, Corcoran and Williams Fork formations remain uncompleted.

     The Delta 2B well in the Vega Area of the Piceance Basin drilled through a portion of the Mancos formation and reached total depth of 10,700 feet. Below the Williams Fork the well was completed in 1,200 feet of shale in the Corcoran and the upper portion of the Mancos formation. Gas production began on April 24 and sales commenced on April 29. As announced on May 10, the 2B well experienced sustained production of 3.3 MMcf/d from only the Mancos and Corcoran formations. The well is currently producing 0.6 MMcf/d. The information available indicates that the natural fractures in the 2B well may have prematurely closed by the high flow rate (6 MMcf/d) during initial flowback activities, which has subsequently hindered production. The Company is currently evaluating refracturing the well in the Mancos and Corcoran formations to reestablish higher production levels in the well.

     The Company is currently drilling the 12B well. The current depth is approximately 8,500 feet with a target depth of 13,000 feet. It is expected that the target depth will reach the Frontier formation. Total depth is expected to be reached during September. Once completed, this well will hold the acreage of the federal Sheep Creek Unit and bring the Company’s Vega leasehold up to 95% held by production.

STRAGETIC ALTERNATIVES UPDATE

     On July 6, 2011, Delta announced that it had engaged Macquarie Capital (USA) Inc. and Evercore Group, L.L.C. to act as advisors to the Company in conducting a strategic alternatives process aimed at maximizing shareholder value and dealing with the Company’s 2012 debt maturities. Through this process, the Board of Directors is evaluating all opportunities available, including a potential sale of the Company. The process is in its early stages and the Company does not expect to make further public comment regarding the process until the Board of Directors has approved a specific transaction or otherwise determines that disclosure of significant developments, if any, is appropriate.

OPERATIONS UPDATE

     Current production of the Company approximates 28 million cubic feet equivalent per day (MMcfe/d) net.

2011 CAPITAL EXPENDITURES AND PRODUCTION GUIDANCE

     Delta will focus its current available capital for the remainder of 2011 on drilling and completing the 12B well and completing the remaining two previously drilled Williams Fork wells. The completions of the remaining two previously drilled wells have been postponed to the fourth quarter of 2011; however, these plans could be altered depending on shale well results, with capital potentially being reallocated to additional shale activity. Developments related to the strategic alternatives process may also affect current capital spending plans.

     Production for the third quarter 2011 is expected to be between 2.6 Bcfe and 2.7 Bcfe.

LIQUIDITY UPDATE

     At June 30, 2011, the Company had $3.9 million in cash and approximately $18.0 million available under its amended credit facility. During the second quarter, Delta received $43.2 million from the sale of non-core assets. The proceeds were used to pay down the facility, close out certain oil derivative positions and for development activity in the Company’s Piceance Basin projects. The Company expects to have sufficient capital under its credit facility, combined with proceeds from the non-core asset sale and net cash from operating activities, to fund Delta’s operating expenses and the current capital development described above and to maintain its debt service obligations through the remainder of 2011.

RESULTS FOR THE SECOND QUARTER 2011

     For the quarter ended June 30, 2011, the Company reported total production of 3.2 Bcfe. Production from continuing operations was 2.8 Bcfe, remaining flat when comparing second quarter 2011 to the prior year period. Revenue from oil and gas sales was $16.9 million, an increase of 14% when compared to the prior year period of $14.8 million. The average natural gas price received during the quarter ended June 30, 2011 increased to $5.31 per thousand cubic feet (Mcf) compared to $4.92 per Mcf for the prior year period. The average oil price received during the quarter ended June 30, 2011 increased to $86.87 per barrel compared to $58.29 per barrel for the prior year period.

     The Company reported a second quarter net loss attributable to Delta common stockholders of ($963,000), or ($0.03) per diluted share, compared to a net loss attributable to Delta common stockholders of ($149.8 million), or ($5.43) per diluted share, in the second quarter of 2010. The decrease in net loss is primarily due to a decrease in dry hole costs and impairments and a decrease in operating expenses, as well as discontinued operations.

SECOND QUARTER PRODUCTION VOLUMES, UNIT PRICES AND COSTS

     Production volumes, average prices received and costs per equivalent Mcf for the quarter ended June 30, 2011 and 2010 were as follows:

		Three Months Ended
		June 30,
		2011				2010
Production – Continuing Operations:
Oil (Mbbl)			38				41
Gas (Mmcf)			2,550				2,528
Total Production (Mmcfe) – Continuing Operations			2,781				2,774
Average Price – Continuing Operations:
Oil (per barrel)		$	86.87			$	58.29
Gas (per Mcf)		$	5.31			$	4.92
Costs (per Mcfe) – Continuing Operations:
Lease operating expense		$	1.28			$	2.19
Transportation expense		$	1.30			$	1.57
Production taxes		$	0.22			$	0.28
Depletion expense		$	3.54			$	4.03
Realized derivative losses (per Mcfe)		$	(1.80	)		$	(0.22	)

     Lease Operating Expense. Lease operating expenses for the three months ended June 30, 2011 decreased to $3.6 million from $6.1 million in the prior year period primarily due to lower water handling costs in the Vega Area as a result of the resumption of development activities and improved water handling facilities. As a result, lease operating expenses per Mcfe in the Vega Area declined from $2.18 per Mcfe for the three months ended June 30, 2010 to $0.87 per Mcfe for the three months ended June 30, 2011. Overall, lease operating expense per Mcfe from continuing operations for the three months ended June 30, 2011 decreased to $1.28 per Mcfe from $2.19 per Mcfe.

     Transportation Expense. Transportation expense for the three months ended June 30, 2011 decreased to $3.6 million from $4.4 million in the prior year. Transportation expense per Mcfe for the three months ended June 30, 2011 decreased 17% to $1.30 per Mcfe from $1.57 per Mcfe. The decrease on a per unit basis is primarily the result of adjustments in the prior year that did not recur in the current year.

     Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense decreased 13% to $10.5 million for the three months ended June 30, 2011, as compared to $12.1 million for the comparable year earlier period. Depletion expense for the three months ended June 30, 2011 decreased to $9.8 million from $11.2 million for the three months ended June 30, 2010 primarily due to higher reserves as a result of recent drilling and completion activity in the Vega Area. Accordingly, the Company’s depletion rate decreased from $4.03 per Mcfe for the three months ended June 30, 2010 to $3.54 per Mcfe for the current year period.

     Realized Loss on Derivative Instruments, Net. During the three months ended June 30, 2011, the Company recognized a $5.0 million loss associated with settlements on derivative contracts. Included in this loss was $3.3 million paid to settle a portion of Delta’s oil derivative contracts outstanding from July 2011 to December 2013 as a requirement to the amended MBL Credit Agreement completed in conjunction with the 2011 non-core asset sale. During the three months ended June 30, 2010, the Company recognized a $601,000 loss associated with settlements on derivative contracts.

     General and Administrative Expense. General and administrative expense decreased 39% to $6.5 million for the three months ended June 30, 2011, as compared to $10.6 million for the comparable prior year period. The decrease in general and administrative expenses is attributed to a decrease in non-cash stock compensation expense, lower corporate consulting fees and to reduced staffing as a result of attrition and a reduction in force since the second quarter of 2010 resulting in lower cash compensation expense.

RESULTS FOR THE SIX MONTHS ENDED JUNE 30, 2011

     The Company reported a six month net loss attributable to common stockholders of ($28.8 million), or ($1.03) per share, compared with a net loss attributable to common stockholders of ($162.5 million), or ($5.90) per share, in the six months ended June 30, 2010.

     For the six months ended June 30, 2011, the Company reported production from continuing operations of 5.78 Bcfe. Revenue from oil and gas sales was $34.6 million, remaining flat when compared to the prior year period. The average natural gas price received during the six months ended June 30, 2011 decreased to $5.31 per Mcf compared to $5.49 per Mcf for the year earlier period. The average oil price received during the six months ended June 30, 2011 increased to $82.31 per Bbl compared to $59.60 per Bbl for the year earlier period.

SIX MONTHS ENDED PRODUCTION VOLUMES, UNIT PRICES AND COSTS

     Production volumes, average prices received and cost per equivalent Mcf for the six months ended June 30, 2011 and 2010 are as follows:

		Six Months Ended
		June 30,
		2011				2010
Production – Continuing Operations:
Oil (Mbbl)			77				85
Gas (Mmcf)			5,323				5,352
Total Production (Mmcfe) – Continuing Operations			5,784				5,864
Average Price – Continuing Operations:
Oil (per barrel)		$	82.31			$	59.60
Gas (per Mcf)		$	5.31			$	5.49
Costs (per Mcfe) – Continuing Operations:
Lease operating expense		$	1.20			$	1.80
Transportation expense		$	1.31			$	1.30
Production taxes		$	0.25			$	0.29
Depletion expense		$	3.67			$	3.81
Realized derivative losses (per Mcfe)		$	(0.94	)		$	(0.80	)

     Lease Operating Expense. Lease operating expenses for the six months ended June 30, 2011 decreased 34% to $7.0 million as compared to $10.5 million in the year earlier period. The decrease is primarily due to lower water handling costs in the Vega Area as a result of the resumption of development activities and improved water handling facilities. As a result, lease operating expense per Mcfe in the Vega Area declined from $1.74 per Mcfe for the six months ended June 30, 2010 to $0.88 per Mcfe for the six months ended June 30, 2011. Overall, lease operating expense per Mcfe from continuing operations for the six months ended June 30, 2011 decreased to $1.20 per Mcfe from $1.80 per Mcfe for the comparable year earlier period.

     Transportation Expense. Transportation expense for the six months ended June 30, 2011 was $7.6 million comparable to $7.6 million in the prior year. Transportation expense per Mcfe for the six months ended June 30, 2011 increased slightly to $1.31 per Mcfe from $1.30 per Mcfe.

     Depreciation, Depletion, Amortization and Accretion – Oil and Gas. Depreciation, depletion and amortization expense decreased 6% to $22.5 million for the six months ended June 30, 2011, as compared to $23.9 million for the comparable year earlier period. Depletion expense for the six months ended June 30, 2011 was $21.2 million compared to $22.3 million for the six months ended June 30, 2010. The Company’s depletion rate decreased from $3.81 per Mcfe for the six months ended June 30, 2010 to $3.67 per Mcfe for the current year period primarily due to higher reserves as a result of the Company’s recent drilling and completion activity in the Vega Area.

     Realized Loss on Derivative Instruments, Net. During the six months ended June 30, 2011, the Company recognized a $5.5 million loss associated with settlements on derivative contracts compared to a $4.7 million loss for the comparable prior year period. Included in the June 30, 2011 loss was $3.3 million paid to settle a portion of Delta’s oil derivative contracts outstanding from July 2011 to December 2013 as a requirement to the amended MBL Credit Agreement completed in conjunction with the 2011 non-core asset sale.

     General and Administrative Expense. General and administrative expense decreased 37% to $13.1 million for the six months ended June 30, 2011, as compared to $20.9 million for the comparable prior year period. The decrease in general and administrative expenses is attributed to a decrease in non-cash stock compensation expense, lower corporate consulting fees and to reduced staffing as a result of attrition and a reduction in force during 2010 resulting in lower cash compensation expense.

DHS DRILLING COMPANY

     The Board of Directors of DHS Drilling Company engaged transaction advisors to explore a strategic alternatives process focused on a sale of DHS or substantially all of its assets. In accordance with accounting standards, the financial position and results of operations relating to DHS have been reflected as assets and liabilities held for sale and discontinued operations in the accompanying consolidated balance sheets and statements of operations. The DHS credit facility debt of $69.9 million at June 30, 2011 is included in the consolidated balance sheets as a component of liabilities related to assets held for sale. The DHS credit facility debt is non-recourse to Delta.

ADDITIONAL FINANCIAL INFORMATION

     The following table summarizes the Company’s open derivative contracts at June 30, 2011:

Remaining

Commodity

Volume

Fixed Price

Term

Index Price

Crude oil

192

Bbls / Day

$

57.70

Jul ’11 - Dec ’11

NYMEX – WTI

Crude oil

79

Bbls / Day

$

91.05

Jul ’11 - Dec ’11

NYMEX – WTI

Crude oil

230

Bbls / Day

$

91.05

Jan ’12 - Dec ’12

NYMEX – WTI

Crude oil

162

Bbls / Day

$

91.05

Jan ’13 - Dec ’13

NYMEX – WTI

Natural gas

12,000

MMBtu / Day

$

5.150

Jul ’11 - Dec ’11

CIG

Natural gas

3,253

MMBtu / Day

$

5.040

Jul ’11 - Dec ’11

CIG

Natural gas

12,052

MMBtu / Day

$

4.440

Jan ’12 - Dec ’12

CIG

Natural gas

10,301

MMBtu / Day

$

4.440

Jan ’13 - Dec ’13

CIG

Natural gas liquids(1)

35,406

Gallons / Day

$

0.913

Jul ’11 - Dec ’11

MT. BELVIEU

Natural gas liquids(1)

30,617

Gallons / Day

$

0.832

Jan ’12 - Dec ’12

MT. BELVIEU

Natural gas liquids(1)

12,286

Gallons / Day

$

0.767

Jan ’13 - Dec ’13

MT. BELVIEU

INVESTOR CONFERENCE CALL

     The Company will host an investor conference call today, Thursday, August 4, 2011 at 12:00 noon Eastern Time (10:00 am Mountain Time) to discuss financial and operating results for the second quarter 2011.

     Shareholders and other interested parties may participate in the conference call by dialing 877-317-6789 (international callers dial 412-317-6789) and referencing the ID code “Delta Petroleum call,” a few minutes before 12:00 noon Eastern Time on August 4, 2011. The call will also be broadcast live and can be accessed through the Company’s website at http://www.deltapetro.com/eventscalendar.html. A replay of the conference call will be available one hour after the completion of the conference call from August 4, 2011 until August 12, 2011 by dialing 877-344-7529 (international callers dial 412-317-0088) and entering the conference ID 10002277.

ABOUT DELTA PETROLEUM

     Delta Petroleum Corporation is an oil and gas exploration and development company based in Denver, Colorado. The Company’s core area of operation is the Rocky Mountain Region, where the majority of its proved reserves, production and long-term growth prospects are located. Its common stock is listed on the NASDAQ Capital Market System under the symbol “DPTRD” until on or around August 10, 2011, when the symbol will return to “DPTR.”

FORWARD-LOOKING STATEMENTS

     Forward-looking statements in this announcement are made pursuant to the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements include, without limitation, business objectives and strategies, including our focus on the Vega Area of the Piceance Basin, as well as statements regarding our strategic alternatives process, possible value creation and resource potential, anticipated future operating and overhead costs, liquidity requirements and availability of capital, drilling and completion activity and anticipated timing, anticipated sources and uses of capital, and anticipated production for third quarter 2011. Readers are cautioned that all forward-looking statements are based on management’s present expectations, estimates and projections, but involve risks and uncertainty, including without limitation, the effects of oil and natural gas prices, availability of capital to fund required payments on the Company’s credit facility, its working capital needs and in respect of the possible redemption of its senior convertible notes, the demand for natural gas in the United States, uncertainties in the projection of future rates of production, unanticipated recovery or production problems, unanticipated results from wells being drilled or completed, the effects of delays in completion of gas gathering systems, pipelines and processing facilities, regulations that might be adopted in the future that could, among other things, significantly limit or curtail hydraulic fracturing techniques used in the Piceance Basin, as well as general market conditions, competition and pricing. The United States Securities and Exchange Commission permits oil and gas companies, in their filings with the SEC, to characterize as proved reserves only those accumulations that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions, and that are part of an approved five-year development plan. Please refer to the Company’s report on Form 10-K for the year ended December 31, 2010 and subsequent reports on Forms 10-Q and 8-K as filed with the Securities and Exchange Commission for additional information. The Company is under no obligation (and expressly disclaims any obligation) to update or alter its forward-looking statements, whether as a result of new information, future events or otherwise.

For further information contact the Company at (303) 293-9133 or via email at investorrelations@deltapetro.com.

SOURCE: Delta Petroleum Corporation

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

		June 30,				December 31,
		2011				2010
		(In thousands, except share data)
ASSETS
Current assets:
Cash and cash equivalents		$	3,894			$	14,190
Short-term restricted deposits			100,000				100,000
Trade accounts receivable, net of allowance for doubtful accounts of $100 and $100, respectively			7,510				7,373
Assets held for sale – DHS subsidiary and oil and gas properties			66,704				108,218
Deposits and prepaid assets			2,617				1,720
Inventories			642				3,446
Other current assets			2,836				4,821
Total current assets			184,203				239,768
Property and equipment:
Oil and gas properties, successful efforts method of accounting:
Unproved			229,623				229,943
Proved			695,189				671,041
Pipeline and gathering systems			92,461				93,558
Other			13,815				13,556
Total property and equipment			1,031,088				1,008,098
Less accumulated depreciation and depletion			(247,438	)			(232,493	)
Net property and equipment			783,650				775,605
Long-term assets:
Investments in unconsolidated affiliates			3,590				3,376
Deferred financing costs			1,432				1,832
Other long-term assets			2,970				3,531
Total long-term assets			7,992				8,739
Total assets		$	975,845			$	1,024,112
LIABILITIES AND EQUITY
Current liabilities:
Credit facility – Delta		$	15,000			$	—
Installment payable on property acquisition			99,144				97,874
33/4% Senior convertible notes – current			110,953				—
Accounts payable			21,030				27,616
Liabilities related to assets held for sale - DHS subsidiary and oil and gas properties			76,112				82,852
Other accrued liabilities			8,281				11,066
Derivative instruments			2,123				574
Total current liabilities			332,643				219,982
Long-term liabilities:
7% Senior notes			149,722				149,684
33/4% Senior convertible notes			—				108,593
Credit facility – Delta			—				29,130
Asset retirement obligations			3,299				2,709
Derivative instruments			3,482				2,419
Total long-term liabilities			156,503				292,535
Commitments and contingencies
Equity:
Preferred stock, $.01 par value:
authorized 3,000,000 shares, none issued			—				—
Common stock, $.01 par value: authorized 200,000,000 shares, issued 29,095,000 shares at June 30, 2011 and 28,514,000 shares at December 31, 2010 (1)			291				285
Additional paid-in capital			1,640,295				1,635,783
Treasury stock at cost; zero shares at June 30, 2011 and 3,000 shares at December 31, 2010 (1)			—				(279	)
Accumulated deficit			(1,150,145	)			(1,121,342	)
Total Delta stockholders’ equity			490,441				514,447
Non-controlling interest			(3,742	)			(2,852	)
Total equity			486,699				511,595
Total liabilities and equity		$	975,845			$	1,024,112

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

		Three Months Ended								Six months Ended
		June 30,								June 30,
		2011				2010				2011				2010
		(In thousands, except per share amounts)
Revenue:
Oil and gas sales		$	16,882			$	14,822			$	34,597			$	34,484
Loss on property sales			—				(109	)			—				(538	)
Total revenue			16,882				14,713				34,597				33,946
Operating expenses:
Lease operating expense			3,563				6,067				6,958				10,527
Transportation expense			3,625				4,359				7,568				7,642
Production taxes			611				786				1,461				1,691
Exploration expense			233				358				276				584
Dry hole costs and impairments			273				29,865				416				30,219
Depreciation, depletion, amortization and accretion			10,528				12,142				22,479				23,887
General and administrative expense			6,471				10,648				13,100				20,898
Total operating expenses			25,304				64,225				52,258				95,448
Operating loss			(8,422	)			(49,512	)			(17,661	)			(61,502	)
Other income and (expense):
Interest expense and financing costs, net			(7,997	)			(7,781	)			(14,803	)			(16,484	)
Other income			233				111				164				179
Realized loss on derivative instruments, net			(5,010	)			(601	)			(5,450	)			(4,714	)
Unrealized gain (loss) on derivative instruments, net			8,341				3,676				(2,612	)			20,948
Income from unconsolidated affiliates			131				991				214				983
Total other income and (expense)			(4,302	)			(3,604	)			(22,487	)			912
Loss from continuing operations before income taxes and discontinued operations			(12,724	)			(53,116	)			(40,148	)			(60,590	)
Income tax expense (benefit)			(3,938	)			203				(4,633	)			478
Loss from continuing operations			(8,786	)			(53,319	)			(35,515	)			(61,068	)
Discontinued operations:
Gain (loss) from results of operations and sale of discontinued operations, net of tax			9,320				(99,161	)			5,785				(107,404	)
Net income (loss)			534				(152,480	)			(29,730	)			(168,472	)
Less net (gain) loss attributable to non-controlling interest included in discontinued operations			(1,497	)			2,730				927				5,925
Net loss attributable to Delta common stockholders		$	(963	)		$	(149,750	)		$	(28,803	)		$	(162,547	)
Amounts attributable to Delta common stockholders:
Loss from continuing operations		$	(8,786	)		$	(53,319	)		$	(35,515	)		$	(61,068	)
Income (loss) from discontinued operations, net of tax			7,823				(96,431	)			6,712				(101,479	)
Net loss		$	(963	)		$	(149,750	)		$	(28,803	)		$	(162,547	)
Basic income (loss) attributable to Delta common stockholders
per common share:
Loss from continuing operations		$	(0.31	)		$	(1.93	)		$	(1.27	)		$	(2.22	)
Discontinued operations			0.28				(3.50	)			0.24				(3.68	)
Net loss		$	(0.03	)		$	(5.43	)		$	(1.03	)		$	(5.90	)
Diluted income (loss) attributable to Delta common stockholders per common share:
Loss from continuing operations		$	(0.31	)		$	(1.93	)		$	(1.27	)		$	(2.22	)
Discontinued operations			0.28				(3.50	)			0.24				(3.68	)
Net loss		$	(0.03	)		$	(5.43	)		$	(1.03	)		$	(5.90	)
Weighted average common shares outstanding(1):
Basic			27,873				27,583				27,878				27,565
Diluted			27,873				27,583				27,878				27,565

DELTA PETROLEUM CORPORATION

RECONCILIATION OF DISCRETIONARY CASH FLOW AND EBITDAX

(Unaudited)

($ in thousands)

		June 30,				June 30,
THREE MONTHS ENDED		2011				2010
CASH USED IN OPERATING ACTIVITIES		$	(8,686	)		$	(15,829	)
Changes in assets and liabilities			4,168				6,650
Exploration costs			233				358
Discretionary cash flow* – continuing operations			(4,285	)			(8,821	)
Discretionary cash flow* – discontinued operations			2,768				9,497
Total discretionary cash flow*		$	(1,517	)		$	676

		June 30,				June 30,
SIX MONTHS ENDED		2011				2010
CASH USED IN OPERATING ACTIVITIES		$	(7,076	)		$	(41,548	)
Changes in assets and liabilities			2,787				27,271
Exploration costs			276				584
Discretionary cash flow* – continuing operations			(4,013	)			(13,693	)
Discretionary cash flow* – discontinued operations			4,975				18,275
Total discretionary cash flow*		$	962			$	4,582

		June 30,				June 30,
THREE MONTHS ENDED		2011				2010
Net loss from continuing operations		$	(8,786	)		$	(53,318	)
Income tax expense (benefit)			(3,938	)			203
Interest expense and financing costs, net			7,998				7,782
Depletion, depreciation and amortization			10,527				12,142
Stock based compensation			2,346				3,281
Loss on sale of oil and gas properties and other			—				109
Unrealized gain on derivative instruments, net			(8,341	)			(3,676	)
Realized loss on derivative instruments			3,295				—
Exploration, dry hole and impairment costs			506				30,223
EBITDAX** – continuing operations			3,607				(3,254	)
EBITDAX **– discontinued operations			3,866				9,956
Total EBITDAX**		$	7,473			$	6,702

		June 30,				June 30,
THREE MONTHS ENDED		2011				2010
CASH USED IN OPERATING ACTIVITIES		$	(8,686	)		$	(15,829	)
Changes in assets and liabilities			4,168				6,650
Interest net of financing costs			4,581				4,369
Exploration costs			233				358
Realized loss on derivative instruments			3,295				—
Other non-cash items			16				1,198
EBITDAX** – continuing operations			3,607				(3,254	)
EBITDAX** – discontinued operations			3,866				9,956
Total EBITDAX**		$	7,473			$	6,702

		June 30,				June 30,
SIX MONTHS ENDED		2011				2010
Net loss from continuing operations		$	(35,515	)		$	(61,068	)
Income tax expense (benefit)			(4,633	)			478
Interest expense and financing costs, net			14,807				16,484
Depletion, depreciation and amortization			22,478				23,887
Stock based compensation			4,666				6,489
Loss on sale of oil and gas properties and other			—				538
Unrealized (gain) loss on derivative instruments, net			2,612				(20,948	)
Realized loss on derivative instruments			3,295				—
Exploration, dry hole and impairment costs			692				30,803
EBITDAX** – continuing operations			8,402				(3,337	)
EBITDAX **– discontinued operations			7,966				20,161
Total EBITDAX**		$	16,368			$	16,824

		June 30,				June 30,
SIX MONTHS ENDED		2011				2010
CASH USED IN OPERATING ACTIVITIES		$	(7,076	)		$	(41,548	)
Changes in assets and liabilities			2,787				27,271
Interest net of financing costs			8,773				9,355
Exploration costs			276				584
Realized loss on derivative instruments			3,295				—
Other non-cash items			347				1,001
EBITDAX** – continuing operations			8,402				(3,337	)
EBITDAX** – discontinued operations			7,966				20,161
Total EBITDAX**		$	16,368			$	16,824