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
THIRD QUARTER 2011 RESULTS AND UPDATE ON STRATEGIC ALTERNATIVES PROCESS

DENVER, Colorado (November 9, 2011) — Delta Petroleum Corporation (“Delta” or the “Company”) (NASDAQ Capital Market: DPTR), an independent oil and gas exploration and development company, today announced its financial and operating results for the third quarter 2011 and provided an update on the strategic alternatives process.

STRAGETIC ALTERNATIVES UPDATE

In July 2011, the Board of Directors of the Company 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 in order to maximize shareholder value and address the 2012 debt maturities. In the strategic alternatives process, the board of directors has considered a wide variety of possible transactions, including the sale of the company, issuances of equity or debt securities, sales of assets, joint ventures and volumetric production payment financing, as well as other potential corporate transactions. With respect to a potential sale of the company or its assets, the Company solicited offers from a significant number of potential purchasers, including domestic and foreign industry participants and private equity firms, and has engaged in substantive negotiations with several such potential purchasers. However, the Company has not received any definitive offer with respect to an acquisition of the company or its assets that implies a value of the assets that is greater than its aggregate indebtedness, and has not been able to identify any significant source of additional financing that is likely to be available on acceptable terms. Accordingly, based on the results of the process to date, the Company believes that a restructuring of the Company’s indebtedness is likely to be necessary. The Company is continuing to discuss potential transactions with potential purchasers and expects to engage in discussions with certain holders of its outstanding senior notes. There can be no assurance that these discussions will lead to a definitive agreement on acceptable terms, or at all, with any party. Any transaction that is agreed to could be highly dilutive to existing stockholders. If the Company is unsuccessful in consummating a transaction or transactions that address its liquidity issues, the Company will be required to seek protection under Chapter 11 of the U.S. Bankruptcy Code.

On November 2, 2011, Delta appointed John T. Young, Jr. as its Chief Restructuring Officer. Mr. Young is a Senior Managing Director at Conway MacKenzie, Inc., which Delta has retained to assist with its strategic alternatives process. Mr. Young has substantial knowledge and experience providing restructuring advisor services, including interim management and debtor advisory, bankruptcy preparation and management, litigation support, post-merger integration and debt restructuring and refinancing. Mr. Young’s experience also includes serving in a multitude of advisory capacities within the energy and oilfield services industries.

LIQUIDITY UPDATE

At September 30, 2011, $12.0 million was available under the Macquarie Bank Limited (MBL) revolving credit facility in addition to approximately $2.1 million in cash. The Company is current with all of its payables and debt obligations including its semiannual interest payments on its notes. The current availability on the revolving credit facility approximates $4.0 million. The MBL credit facility, which has a total capacity of $33 million, matures January 31, 2012. Additionally, the holders of the $115 million 3 ³/4% senior convertible notes can require the Company to repurchase the notes at par on or after May 1, 2012.

RESULTS FOR THE THIRD QUARTER 2011

For the quarter ended September 30, 2011, the Company reported production from continuing operations of 2.6 Bcfe, remaining flat when comparing third quarter 2011 to the prior year period. Revenue from oil and gas sales was $16.5 million, an increase of 31% when compared to the prior year period of $12.7 million. The average natural gas price received during the quarter ended September 30, 2011 increased to $5.91 per thousand cubic feet (Mcf) compared to $4.44 per Mcf for the prior year period. The average oil price received during the quarter ended September 30, 2011 increased to $71.45 per barrel compared to $58.71 per barrel for the prior year period.

The Company reported a third quarter net loss attributable to Delta common stockholders of ($429.4 million), or ($15.40) per diluted share, compared to net income attributable to Delta common stockholders of $13.9 million, or $0.49 per diluted share, in the third quarter of 2010. The increase in net loss is primarily due to an increase in dry hole costs and impairments as well as discontinued operations.

THIRD QUARTER PRODUCTION VOLUMES, UNIT PRICES AND COSTS

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

		Three Months Ended
		September 30,
		2011				2010
Production — Continuing Operations:
Oil (Mbbl)			32				39
Gas (Mmcf)			2,418				2,327
Total Production (Mmcfe) — Continuing Operations			2,608				2,563
Average Price — Continuing Operations:
Oil (per barrel)		$	71.45			$	58.71
Gas (per Mcf)		$	5.91			$	4.44
Costs (per Mcfe) — Continuing Operations:
Lease operating expense		$	1.37			$	1.78
Transportation expense		$	1.29			$	1.29
Production taxes		$	0.24			$	0.26
Depletion expense		$	3.75			$	4.20
Realized derivative gain (loss) (per Mcfe)		$	0.03			$	(0.16	)

Lease Operating Expense. Lease operating expenses for the three months ended September 30, 2011 decreased to $3.6 million from $4.6 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 $1.63 per Mcfe for the three months ended September 30, 2010 to $1.12 per Mcfe for the three months ended September 30, 2011. Overall, lease operating expense per Mcfe from continuing operations for the three months ended September 30, 2011 decreased to $1.37 per Mcfe from $1.78 per Mcfe.

Transportation Expense. Transportation expense for the three months ended September 30, 2011 increased to $3.4 million from $3.3 million in the prior year. Transportation expense per Mcfe held constant at $1.29 per Mcfe for the quarters ended September 30, 2011 and 2010.

Dry Hole Costs and Impairments. Delta incurred dry hole and impairment costs of $420.4 million for the three months ended September 30, 2011 compared to ($1.2 million) for the comparable period a year ago. During the three months ended September 30, 2011, proved and unproved property impairments to the Rocky Mountain region of $420.1 million were recognized. During the three months ended September 30, 2011, the Company evaluated the fair value of its properties based on market indicators in conjunction with the progression of the strategic alternatives evaluation process. Delta has not received any definitive offer with respect to an acquisition of the company or its assets that implies a value of the assets that is greater than its aggregate indebtedness. As a result, the Company recorded an impairment of $157.5 million to its Vega unproved leasehold, $239.8 million to its Vega area proved properties, $20.5 million to its Vega area gathering system and facilities, and $2.1 million to its Vega area surface acreage. During the three months ended September 30, 2010, dry hole and impairment costs were a result of minor cost true-ups.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense decreased 7% to $10.7 million for the three months ended September 30, 2011, as compared to $11.5 million for the comparable year earlier period. Depletion expense for the three months ended September 30, 2011 decreased to $9.8 million from $10.8 million for the three months ended September 30, 2010 primarily due to higher reserves as a result of the Company’s recent drilling and completion activity in the Vega Area. Accordingly, the depletion rate decreased from $4.20 per Mcfe for the three months ended September 30, 2010 to $3.75 per Mcfe for the current year period.

General and Administrative Expense. General and administrative expense decreased 23% to $6.1 million for the three months ended September 30, 2011, as compared to $7.9 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 and to reduced staffing as a result of attrition and a reduction in force in the third quarter of 2010 resulting in lower cash compensation expense.

RESULTS FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2011

The Company reported a nine month net loss attributable to common stockholders of ($458.2 million), or ($16.33) per share, compared with a net loss attributable to common stockholders of ($148.6 million), or ($5.40) per share, in the nine months ended September 30, 2010.

For the nine months ended September 30, 2011, the Company reported total production of 9.2 Bcfe, including production from continuing operations of 8.4 Bcfe. Revenue from oil and gas sales increased 9% to $51.1 million when compared to the prior year period. The average natural gas price received during the nine months ended September 30, 2011 increased to $5.50 per Mcf compared to $5.17 per Mcf for the year earlier period. The average oil price received during the nine months ended September 30, 2011 increased to $79.13 per Bbl compared to $59.32 per Bbl for the year earlier period.

NINE MONTHS ENDED PRODUCTION VOLUMES, UNIT PRICES AND COSTS

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

		Nine Months Ended
		September 30,
		2011				2010
Production — Continuing Operations:
Oil (Mbbl)			108				125
Gas (Mmcf)			7,741				7,678
Total Production (Mmcfe) — Continuing Operations			8,392				8,428
Average Price — Continuing Operations:
Oil (per barrel)		$	79.13			$	59.32
Gas (per Mcf)		$	5.50			$	5.17
Costs (per Mcfe) — Continuing Operations:
Lease operating expense		$	1.26			$	1.79
Transportation expense		$	1.30			$	1.30
Production taxes		$	0.25			$	0.28
Depletion expense		$	3.69			$	3.93
Realized derivative losses (per Mcfe)		$	(0.64	)		$	(0.61	)

Lease Operating Expense. Lease operating expenses for the nine months ended September 30, 2011 decreased 30% to $10.5 million as compared to $15.1 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 $1.70 per Mcfe for the nine months ended September 30, 2010 to $0.95 per Mcfe for the nine months ended September 30, 2011. Overall, lease operating expense per Mcfe from continuing operations for the nine months ended September 30, 2011 decreased to $1.26 per Mcfe from $1.79 per Mcfe for the comparable year earlier period.

Transportation Expense. Transportation expense for the nine months ended September 30, 2011 and 2010 was $10.9 million. Transportation expense per Mcfe for the nine months ended September 30, 2011 held constant at $1.30 per Mcfe.

Dry Hole Costs and Impairments. Delta incurred dry hole and impairment costs of $420.9 million for the nine months ended September 30, 2011 compared to $29.8 million for the comparable period a year ago. During the three months ended September 30, 2011, proved and unproved property impairments to the Rocky Mountain region of $420.1 million were recognized. During the three months ended September 30, 2011, the Company evaluated the fair value of its properties based on market indicators in conjunction with the progression of the strategic alternatives evaluation process. Delta has not received any definitive offer with respect to an acquisition of the company or its assets that implies a value of the assets that is greater than its aggregate indebtedness. As a result, the Company recorded an impairment of $157.5 million to its Vega unproved leasehold, $239.8 million to its Vega area proved properties, $20.5 million to its Vega area gathering system and facilities, and $2.1 million to its Vega area surface acreage. During the nine months ended September 30, 2010, dry hole and impairment costs primarily related to unproved property impairments of $25.7 million for the Columbia River Basin, Hingeline, Howard Ranch, Bull Canyon, Garden Gulch, Delores River and Haynesville shale prospects and a $4.8 million impairment of the Paradox pipeline.

Depreciation, Depletion, Amortization and Accretion. Depreciation, depletion and amortization expense decreased 6% to $33.2 million for the nine months ended September 30, 2011, as compared to $35.4 million for the comparable year earlier period. Depletion expense for the nine months ended September 30, 2011 was $31.0 million compared to $33.1 million for the nine months ended September 30, 2010. The Company’s depletion rate decreased from $3.93 per Mcfe for the nine months ended September 30, 2010 to $3.69 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.

General and Administrative Expense. General and administrative expense decreased 33% to $19.2 million for the nine months ended September 30, 2011, as compared to $28.8 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

On October 31, 2011, Delta sold its stock in DHS Drilling Company to DHS’s lender, Lehman Commercial Paper, Inc., for $500,000. Delta expects to recognize a gain of approximately $6.1 million in connection with the divestiture of DHS during the fourth quarter of 2011.

ADDITIONAL FINANCIAL INFORMATION

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

Remaining

Commodity

Volume

Fixed Price

Term

Index Price

Crude oil

203

Bbls / Day

$

57.70

Oct ’11 - Dec ’11

NYMEX – WTI

Crude oil

62

Bbls / Day

$

91.05

Oct ’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

Oct ’11 - Dec ’11

CIG

Natural gas

3,253

MMBtu / Day

$

5.040

Oct ’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)

34,367

Gallons / Day

$

0.913

Oct ’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

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 “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, and anticipated sources and uses of capital. 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 availability of capital to fund required payments on the Company’s indebtedness, its working capital needs, its ability to sell the Company or its assets at a value greater than its aggregate indebtedness, its ability to obtain financing from any source or the viability of any attempted restructuring efforts or bankruptcy proceedings, effects of oil and natural gas prices, 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

		September 30,				December 31,
		2011				2010
		(In thousands, except share data)
ASSETS
Current assets:
Cash and cash equivalents		$	2,101			$	14,190
Short-term restricted deposits			100,000				100,000
Trade accounts receivable, net of allowance for doubtful accounts of $175 and $100, respectively			7,598				7,373
Assets held for sale — DHS subsidiary			70,819				108,218
Deposits and prepaid assets			1,790				1,720
Inventories			153				3,446
Derivative instruments			1,463				—
Other current assets			1,344				4,821
Total current assets			185,268				239,768
Property and equipment:
Oil and gas properties, successful efforts method of accounting:
Unproved			72,190				229,943
Proved			684,539				671,041
Pipeline and gathering systems			63,842				93,558
Other			11,713				13,556
Total property and equipment			832,284				1,008,098
Less accumulated depreciation and depletion			(469,762	)			(232,493	)
Net property and equipment			362,522				775,605
Long-term assets:
Investments in unconsolidated affiliates			3,599				3,376
Deferred financing costs			1,299				1,832
Other long-term assets			1,583				3,531
Total long-term assets			6,481				8,739
Total assets		$	554,271			$	1,024,112
LIABILITIES AND EQUITY
Current liabilities:
Credit facility — Delta		$	21,000			$	—
Installment payable on property acquisition			99,785				97,874
33/4% Senior convertible notes — current			112,167				—
Accounts payable			18,152				27,616
Liabilities related to assets held for sale — DHS subsidiary			78,829				82,852
Other accrued liabilities			12,662				11,066
Derivative instruments			—				574
Total current liabilities			342,595				219,982
Long-term liabilities:
7% Senior notes			149,741				149,684
33/4% Senior convertible notes			—				108,593
Credit facility — Delta			—				29,130
Asset retirement obligations			3,354				2,709
Derivative instruments			319				2,419
Total long-term liabilities			153,414				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 28,870,000 shares at September 30, 2011 and 28,513,800 shares at December 31, 2010 (1)			289				285
Additional paid-in capital			1,640,591				1,635,783
Treasury stock at cost; zero shares at September 30, 2011 and 3,300 shares at December 31, 2010 (1)			—				(279	)
Accumulated deficit			(1,579,578	)			(1,121,342	)
Total Delta stockholders’ equity			61,302				514,447
Non-controlling interest			(3,040	)			(2,852	)
Total equity			58,262				511,595
Total liabilities and equity		$	554,271			$	1,024,112

(1)		All common share amounts (except par value and par value per share amounts) have been retroactively restated to reflect the Company’s one-for-ten reverse common stock split effective July 13, 2011.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2011				2010				2011				2010
		(In thousands, except per share amounts)
Revenue:
Oil and gas sales		$	16,546			$	12,653			$	51,143			$	47,138
Loss on property sales			—				(1	)			—				(539	)
Total revenue			16,546				12,652				51,143				46,599
Operating expenses:
Lease operating expense			3,577				4,555				10,535				15,082
Transportation expense			3,367				3,298				10,935				10,940
Production taxes			633				667				2,094				2,358
Exploration expense			53				368				329				952
Dry hole costs and impairments			420,447				(1,164	)			420,863				29,762
Depreciation, depletion, amortization and accretion			10,701				11,522				33,180				35,410
General and administrative expense			6,065				7,872				19,165				28,770
Executive severance expense, net			—				(674	)			—				(674	)
Total operating expenses			444,843				26,444				497,101				122,600
Operating loss			(428,297	)			(13,792	)			(445,958	)			(76,001	)
Other income and (expense):
Interest expense and financing costs, net			(6,727	)			(7,567	)			(21,530	)			(24,050	)
Other income (expense)			(1,857	)			508				(1,693	)			686
Realized gain (loss) on derivative instruments, net			79				(418	)			(5,371	)			(5,132	)
Unrealized gain on derivative instruments, net			6,749				7,124				4,137				28,072
Income (loss) from unconsolidated affiliates			80				(90	)			294				893
Total other income and (expense)			(1,676	)			(443	)			(24,163	)			469
Loss from continuing operations before income taxes and discontinued operations			(429,973	)			(14,235	)			(470,121	)			(75,532	)
Income tax expense (benefit)			64				86				(4,568	)			564
Loss from continuing operations			(430,037	)			(14,321	)			(465,553	)			(76,096	)
Discontinued operations:
Gain (loss) from results of operations and sale of discontinued operations, net of tax			1,309				25,054				7,092				(81,644	)
Net income (loss)			(428,728	)			10,733				(458,461	)			(157,740	)
Less net (gain) loss attributable to non-controlling interest included in discontinued operations			(702	)			3,209				225				9,134
Net income (loss) attributable to Delta common stockholders		$	(429,430	)		$	13,942			$	(458,236	)		$	(148,606	)
Amounts attributable to Delta common stockholders:
Loss from continuing operations		$	(430,037	)		$	(14,321	)		$	(465,553	)		$	(76,096	)
Income (loss) from discontinued operations, net of tax			607				28,263				7,317				(72,510	)
Net loss		$	(429,430	)		$	13,942			$	(458,236	)		$	(148,606	)
Basic loss attributable to Delta common stockholders per common share:
Loss from continuing operations		$	(15.42	)		$	(0.52	)		$	(16.59	)		$	(2.76	)
Discontinued operations			0.02				1.03				0.26				(2.64	)
Net loss		$	(15.40	)		$	0.51			$	(16.33	)		$	(5.40	)
Diluted loss attributable to Delta common stockholders per common share:
Loss from continuing operations		$	(15.42	)		$	(0.51	)		$	(16.59	)		$	(2.76	)
Discontinued operations			0.02				1.00				0.26				(2.64	)
Net loss		$	(15.40	)		$	0.49			$	(16.33	)		$	(5.40	)
Weighted average common shares outstanding(1):
Basic			27,883				27,530				28,055				27,544
Diluted			27,883				28,206				28,055				27,544

(1)		All common share amounts (except par value and par value per share amounts) have been retroactively restated as of September 30, 2011 to reflect the Company’s one-for-ten reverse common stock split effective July 13, 2011.

DELTA PETROLEUM CORPORATION
RECONCILIATION OF DISCRETIONARY CASH FLOW AND EBITDAX
(Unaudited)

($ in thousands)

		September 30,				September 30,
THREE MONTHS ENDED		2011				2010
CASH USED IN OPERATING ACTIVITIES		$	5,651			$	(7,427	)
Changes in assets and liabilities			(5,398	)			1,901
Exploration costs			53				368
Discretionary cash flow* — continuing operations			306				(5,158	)
Discretionary cash flow* — discontinued operations			1,478				4,742
Total discretionary cash flow*		$	1,784			$	(416	)

		September 30,				September 30,
NINE MONTHS ENDED		2011				2010
CASH USED IN OPERATING ACTIVITIES		$	(1,425	)		$	(49,611	)
Changes in assets and liabilities			(2,611	)			29,172
Exploration costs			329				952
Discretionary cash flow* — continuing operations			(3,707	)			(19,487	)
Discretionary cash flow* — discontinued operations			6,453				23,738
Total discretionary cash flow*		$	2,746			$	4,251

*		Discretionary cash flow represents net cash provided by (used in) operating activities before changes in assets and liabilities and exploration costs. Discretionary cash flow is presented as a supplemental financial measurement in the evaluation of Delta’s business. The Company believes that it provides additional information regarding its ability to meet future debt service, capital expenditures and working capital requirements. This measure is widely used by investors and rating agencies in the valuation, comparison, rating and investment recommendations of companies. Discretionary cash flow is not a measure of financial performance under GAAP. Accordingly, it should not be considered as a substitute for cash flows from operating, investing or financing activities as an indicator of cash flows, or as a measure of liquidity.

		September 30,				September 30,
THREE MONTHS ENDED		2011				2010
Net loss from continuing operations		$	(430,037	)		$	(14,321	)
Income tax expense (benefit)			64				86
Interest expense and financing costs, net			6,727				7,567
Depletion, depreciation and amortization			10,701				11,522
Stock based compensation			1,735				1,883
Gain (loss) on sale of discontinued operations oil and gas properties			—				(20	)
Unrealized gain on derivative instruments, net			(6,749	)			(7,124	)
Realized loss on derivative instruments			—				—
Exploration, dry hole and impairment costs			422,124				(796	)
EBITDAX** — continuing operations			4,565				(1,203	)
EBITDAX **— discontinued operations			2,013				6,745
Total EBITDAX**		$	6,578			$	5,542

		September 30,				September 30,
THREE MONTHS ENDED		2011				2010
CASH USED IN OPERATING ACTIVITIES		$	5,651			$	(7,427	)
Changes in assets and liabilities			(5,398	)			1,901
Interest net of financing costs			4,177				3,848
Exploration costs			53				368
Other non-cash items			82				107
EBITDAX** — continuing operations			4,565				(1,203	)
EBITDAX** — discontinued operations			2,013				6,745
Total EBITDAX**		$	6,578			$	5,542

		September 30,				September 30,
NINE MONTHS ENDED		2011				2010
Net income (loss) from continuing operations		$	(465,553	)		$	(76,096	)
Income tax expense (benefit)			(4,568	)			564
Interest expense and financing costs, net			21,530				24,050
Depletion, depreciation and amortization			33,180				35,410
Stock based compensation			6,401				8,372
Loss on property sales			—				539
Unrealized loss on derivative instruments, net			(4,137	)			(28,072	)
Realized loss on derivative instruments			3,295				—
Exploration, dry hole and impairment costs			422,816				30,714
EBITDAX** — continuing operations			12,964				(4,519	)
EBITDAX **— discontinued operations			9,979				26,930
Total EBITDAX**		$	22,943			$	22,411

		September 30,				September 30,
NINE MONTHS ENDED		2011				2010
CASH USED IN OPERATING ACTIVITIES		$	(1,425	)		$	(49,611	)
Changes in assets and liabilities			(2,611	)			29,172
Interest net of financing costs			12,946				13,284
Exploration costs			329				952
Realized loss on derivative instruments			3,295				—
Other non-cash items			430				1,684
EBITDAX** — continuing operations			12,964				(4,519	)
EBITDAX** — discontinued operations			9,979				26,930
Total EBITDAX**		$	22,943			$	22,411

**		EBITDAX represents net income (loss) before non-controlling interest, income tax expense (benefit), interest expense and financing costs, net, depreciation, depletion and amortization expense, stock based compensation, gain and loss on sale of oil and gas properties and other investments, net, gain on discontinued operations, unrealized gains and losses on derivative contracts, realized losses on early termination of derivative instruments and exploration and impairment and dry hole costs. EBITDAX is presented as a supplemental financial measurement in the evaluation of the Company’s business. Delta believes that it provides additional information regarding its ability to meet future debt service, capital expenditures and working capital requirements. This measure is widely used by investors and rating agencies in the valuation, comparison, rating and investment recommendations of companies. EBITDAX is also a financial measurement that, with certain negotiated adjustments, is reported to the Company’s lenders pursuant to its bank credit agreement and is used in the financial covenants in its bank credit agreement and Delta’s senior note indentures. EBITDAX is not a measure of financial performance under GAAP. Accordingly, it should not be considered as a substitute for net income, income from operations, or cash flow provided by (used in) operating activities prepared in accordance with GAAP.