Exhibit 99.1

DELTA PETROLEUM CORPORATION
Daniel Taylor, Chairman
John Wallace, President and COO
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 2009 OPERATING RESULTS

     DENVER, Colorado (November 5, 2009) — Delta Petroleum Corporation (NASDAQ Global Market: DPTR), an independent oil and gas exploration and development company, announced its financial and operating results for the third quarter of 2009.

GRAY 31-23 COMPLETION RESULTS

     Delta has finished completion efforts on the Gray well. As previously announced, while all zones encountered significant high pressure, they flowed primarily water with minor amounts of non-commercial associated gas. Additional testing was performed in the basalt section of the well with a similar outcome, and therefore the Gray well has been expensed as a dry hole in the Company’s third quarter financial statements.

     Delta’s Columbia River Basin team has reviewed available data in order to provide possible explanations regarding the lack of commercial gas from the Wenatchee sands of the Gray well. One of the challenges generally experienced in the industry is the fact that fresh water and hydrocarbons are almost indistinguishable on electric logs. Therefore the gas shows and over-pressured reservoir seen in the Gray well during drilling suggested a gas reservoir with some associated water; however, completion results instead revealed that the reservoir is a fresh water reservoir with some associated natural gas.

     The lessons learned from the drilling of the Gray well have provided the Company with important and strategic information that will be of benefit in any future drilling operations in the Columbia River Basin. Numerous issues related to drilling through the basalt formation were identified, analyzed and explained, and management believes that this information can be translated into potentially significant savings of both cost and time in the future. While gas was liberated, no source rock was drilled in this well, thus Delta’s primary objective, the deeper Roslyn formation, remains a viable target.

     John Wallace, the Company’s President and COO said, “We are extremely disappointed with the results of the Gray well, but exploration drilling carries with it significant risks. We continue to believe that the Roslyn formation, which has produced elsewhere in the Columbia River Basin, has significant potential and should be tested. In addition, data obtained during the drilling of the Gray well has allowed for better seismic interpretation that can now be applied to the Company’s leasehold in the basin. A more accurate representation of the structural configuration below the basalt section, including the Roslyn formation, will help direct us to more precise geologic prospects and potential future well locations.”

     “While much attention was paid to the drilling and completion of the Gray well, we want to highlight to our stockholders where the intrinsic value lies within Delta. Delta’s operational strength in the Rockies and go forward strategy focused on lower-risk development projects will allow the Company to realize consistent, efficient reserve and production growth in the Piceance Basin, once natural gas prices recover. We believe that we have the track record, experience and assets that will allow us to execute this strategy.”

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     Dan Taylor, the Company’s Chairman stated, “Delta will continue to strive to deliver value to our shareholders through the development of our core assets and the execution of our cost control strategy. I concur with John on the underlying value of Delta being our proved and probable reserves in the Piceance Basin, which are not adequately reflected in our current share price.”

BORROWING BASE REDETERMINATION

     On October 30, 2009, the Company and its senior lenders completed the borrowing base re-determination under the Company’s revolving credit facility. As part of the redetermination, the Company and its lenders entered into an amendment to the credit facility pursuant to which the lenders provided waivers from the December 31, 2009 and March 31, 2010 current ratio and consolidated secured debt to EBITDAX ratio covenants, and the borrowing base was reduced from $225.0 million to $185.0 million. The amendment requires that Delta maintain minimum availability of $20.0 million essentially reducing Delta’s availability under the credit facility. In addition, capital expenditures will be limited to $10.0 million for the quarter ended December 31, 2009, $10.0 million for the quarter ended March 31, 2010, and $5.0 million for the quarter ended June 30, 2010, provided that any excess of the limitation over the amount of actual expenditures may be carried forward from an earlier quarter to a subsequent quarter. The next scheduled re-determination is March 1, 2010.

RESULTS FOR THE THIRD QUARTER

     For the quarter ended September 30, 2009, the Company reported production of 5.14 billion cubic feet equivalents (Bcfe), a decrease of 22% when compared with the third quarter of 2008 and a decrease of 10% when compared with the second quarter of 2009. Total revenue decreased 67% to $23.9 million in the quarter, versus revenue of $72.0 million in the quarter ended September 30, 2008. Revenue from oil and gas sales declined 64% to $21.5 million, compared with $60.3 million in the prior year quarter. The decrease was principally the result of a 44% decrease in oil prices received, a 60% decrease in natural gas prices received, and a 22% decrease in production. The average oil price received during the three months ended September 30, 2009 decreased to $61.43 per Bbl compared to $110.49 per Bbl for the year earlier period. The average natural gas price received during the three months ended September 30, 2009 decreased to $2.59 per Mcf compared to $6.49 per Mcf for the year earlier period. The production decrease was primarily related to production declines in the Rockies that have not been offset by additional drilling. Revenue from contract drilling and trucking fees decreased 78% to $2.5 million in the current quarter, versus $11.8 million in the third quarter of 2008. The decrease is the result of lower third party rig utilization in the three months ended September 30, 2009 compared to the comparable year earlier period, resulting from a significant industry slowdown attributable to lower commodity prices.

     The Company reported a third quarter net loss attributable to Delta common stockholders of ($96.8 million), or ($0.35) per diluted share, compared with net income attributable to Delta common stockholders of $48.8 million, or $0.47 per diluted share, in the third quarter of 2008. The increased loss was primarily due to impairments recorded in the third quarter of 2009 and significantly lower natural gas and oil prices compared to the same period prior year.

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THIRD QUARTER PRODUCTION VOLUMES, UNIT PRICES AND COSTS

Production volumes, average prices received and cost per thousand cubic feet equivalent (Mcfe) for the three months ended September 30, 2009 and 2008 are as follows:

	Three Months Ended
	September 30,
	2009		2008
Production — Continuing Operations:
Oil (Mbbl)		180		247
Gas (Mmcf)		4,059		5,089
Total Production (Mmcfe)		5,137		6,569
Average Price — Continuing Operations:
Oil (per barrel)	$	61.43	$	110.49
Gas (per Mcf)	$	2.59	$	6.49
Costs per Mcfe — Continuing Operations:
Lease operating expense	$	1.47	$	1.17
Production taxes	$	0.23	$	0.59
Transportation costs	$	0.41	$	0.55
Depletion expense	$	4.86	$	4.40
Realized derivative gains	$	0.07	$	1.65

     Lease operating expense. Lease operating expense for the quarter ended September 30, 2009 decreased to $7.6 million from $7.7 million in the year earlier period. Lease operating expense from continuing operations per Mcfe for the three months ended September 30, 2009 increased to $1.47 per Mcfe from $1.17 per Mcfe for the comparable year earlier period, primarily as a result of lower production volumes.

     Depreciation, depletion and amortization expense. Oil and gas depreciation, depletion and amortization expense decreased 13% to $25.7 million for the three months ended September 30, 2009, as compared to $29.6 million for the same period prior year. Depletion expense for the three months ended September 30, 2009 was $25.0 million compared to $28.9 million for the three months ended September 30, 2008. Our depletion rate increased from $4.40 per Mcfe for the three months ended September 30, 2008 to $4.86 per Mcfe for the current year period primarily due to the effect of low spot commodity prices at September 30, 2009 on the reserves used in our depletion calculation, offset by the effect of impairments recorded in the fourth quarter of 2008.

     Dry Hole Costs and Impairments. Delta incurred dry hole and impairment costs of approximately $53.4 million for the three months ended September 30, 2009 compared to $8.1 million for the comparable period a year ago. During the three months ended September 30, 2009, dry hole and impairment costs primarily related to the Gray 31-23 in the Columbia River Basin which was completed during the third quarter of 2009, but found to be uneconomic resulting in dry hole costs of $31.0 million and Columbia River Basin unproved leasehold impairments of $20.4 million. In addition, $2.1 million of other impairments were recorded, most of which related to a proved property impairment for the Angleton property in Texas.

     The Company incurred dry hole costs of approximately $8.1 million for the three months ended September 30, 2008 primarily related to four wells, one well in Wyoming, one well in California, one well in Utah and a non-operated well in the Columbia River Basin. No impairments were recorded during the three months ended September 30, 2008.

     General and Administrative Expense. General and administrative expense decreased 33% to $10.0 million for the three months ended September 30, 2009, as compared to $14.9 million for the comparable prior year period. The decrease in general and administrative expense is attributed to reduced staffing as a result of reductions in force during the first half of 2009 resulting in lower cash compensation expense and a decrease in non-cash stock compensation expense from lower executive performance share costs, and also from forfeitures and modifications of salaries related to the reductions in force which affected approximately fifty percent of personnel.

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RESULTS FOR THE NINE MONTHS

     For the nine months ended September 30, 2009, the Company reported production of 17.2 Bcfe, a decrease of 5% when compared with the nine months ended September 30, 2008. Total revenue decreased 52% to $105.5 million in the nine months ended September 30, 2009, versus revenue of $217.6 million in the nine months ended September 30, 2008. Revenue from oil and gas sales declined 65% to $65.0 million, compared with $187.3 million in the prior year period. The decrease was principally the result of a 54% decrease in oil prices received, a 66% decrease in natural gas prices received and a 5% decrease in production. The average oil price received during the nine months ended September 30, 2009 decreased to $47.90 per Bbl compared to $105.17 per Bbl for the year earlier period. The average natural gas price received during the nine months ended September 30, 2009 decreased to $2.69 per Mcf compared to $7.93 per Mcf for the year earlier period. Revenue from contract drilling and trucking fees decreased to $9.4 million compared to $30.4 million for the same period in the prior year. The decrease is the result of lower third party rig utilization in the nine months ended September 30, 2009 compared to the comparable year earlier period, resulting from a significant industry slowdown attributable to lower commodity prices.

     The Company reported a nine month net loss attributable to common stockholders of ($294.7 million), or ($1.55) per diluted common share, compared with a net income attributable to common stockholders of $4.6 million, or $0.05 per diluted share, for the nine months ended September 30, 2008. The increased loss was due to dry holes costs and impairments recorded in the second and third quarters of 2009 and significantly lower oil and natural gas prices offset by an offshore litigation gain recorded in 2009.

NINE MONTHS PRODUCTION VOLUMES, UNIT PRICES AND COSTS

Production volumes, average prices received and cost per equivalent Mcf for the nine months ended September 30, 2009 and 2008 are as follows:

	Nine Months Ended
	September 30,
	2009		2008
Production — Continuing Operations:
Oil (Mbbl)		594		760
Gas (Mmcf)		13,591		13,531
Total Production (Mmcfe)		17,155		18,091
Average Price — Continuing Operations:
Oil (per barrel)	$	47.90	$	105.17
Gas (per Mcf)	$	2.69	$	7.93
Costs per Mcfe — Continuing Operations:
Lease operating expense	$	1.46	$	1.37
Production taxes	$	0.22	$	0.64
Transportation costs	$	0.46	$	0.44
Depletion expense	$	4.68	$	4.18
Realized derivative gains	$	0.02	$	0.11

     Lease operating expense. Lease operating expenses for the nine months ended September 30, 2009 of $25.0 million was comparable to $24.7 million in the year earlier period as both production and per unit cost rates remained consistent. Lease operating expense from continuing operations per Mcfe for the nine months ended September 30, 2009 increased to $1.46 per Mcfe from $1.37 per Mcfe for the comparable year earlier period.

     Depreciation, depletion and amortization expense. Oil and gas depreciation, depletion and amortization expense increased 7% to $82.5 million for the nine months ended September 30, 2009, as compared to $77.4 million for the comparable year earlier period. Depletion expense for the nine months ended September 30, 2009 was $80.3 million compared to $75.6 million for the nine months ended September 30, 2008. The depletion rate increased from $4.18 per Mcfe for the nine months ended September 30, 2008 to $4.68 per Mcfe for the current year period primarily due to the effect of low spot commodity prices at September 30, 2009 on the reserves used in the depletion calculation, offset by the effect of impairments recorded in the fourth quarter of 2008.

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     Dry Hole Costs and Impairments. Delta incurred dry hole and impairment costs of approximately $161.5 million for the nine months ended September 30, 2009 compared to $10.9 million for the comparable period a year ago. During the nine months ended September 30, 2009, dry hole and impairment costs primarily related to unproved leasehold impairments in Garden Gulch ($38.6 million), Haynesville ($26.7 million), Columbia River Basin ($20.6 million) and Lighthouse ($14.7 million), a $31.0 million dry hole for the Gray well in the Columbia River Basin, $10.5 million impairment of Vega area surface acres, $6.5 million of DHS equipment and rig impairments, $4.3 million of tubular inventory impairments, $1.9 million of proved property impairments in the Gulf Coast, and a $1.9 million impairment of the Paradox pipeline.

     General and Administrative Expense. General and administrative expense decreased 25% to $31.5 million for the nine months ended September 30, 2009, as compared to $42.1 million for the comparable prior year period. The decrease in general and administrative expenses is attributed to reduced staffing as a result of reductions in force during the first half of 2009 resulting in lower cash compensation expense and a decrease in non-cash stock compensation expense from lower executive performance share costs, and also from forfeitures and modifications of salaries related to the reductions in force which affected approximately fifty percent of personnel.

ADDITIONAL FINANCIAL INFORMATION

     The following table summarizes the Company’s open derivative contracts at September 30, 2009, required pursuant to the Company’s credit agreement:

Commodity	Volume			Fixed Price		Term		Index Price
Crude oil		1,000	Bbls / Day	$	52.25	Oct ’09	- Dec ’09	NYMEX – WTI
Crude oil		1,000	Bbls / Day	$	52.25	Jan ’10	- Dec ’10	NYMEX – WTI
Crude oil		500	Bbls / Day	$	57.70	Jan ’11	- Dec ’11	NYMEX – WTI
Natural gas		4,000	MMBtu / Day	$	5.720	Oct ’09	- Dec ’09	NYMEX – HHUB
Natural gas		6,000	MMBtu / Day	$	5.720	Jan ’10	- Dec ’10	NYMEX – HHUB
Natural gas		10,000	MMBtu / Day	$	4.105	Oct ’09	- Dec ’09	CIG
Natural gas		15,000	MMBtu / Day	$	4.105	Jan ’10	- Dec ’10	CIG
Natural gas		4,373	MMBtu / Day	$	3.973	Oct ’09	- Dec ’09	CIG
Natural gas		5,367	MMBtu / Day	$	3.973	Jan ’10	- Dec ’10	CIG
Natural gas		12,000	MMBtu / Day	$	5.150	Jan ’11	- Dec ’11	CIG
Natural gas		3,253	MMBtu / Day	$	5.040	Jan ’11	- Dec ’11	CIG

     The net fair value of the Company’s derivative instruments recorded in the financial statement was a liability of approximately $27.0 million at September 30, 2009.

OPERATIONS UPDATE

     Columbia River Basin, WA, 50% WI — As previously announced, Delta’s plans for additional drilling activity originally scheduled for later this year and in 2010 in the vicinity of the Gray well in the southern portion of the Columbia River Basin have been suspended. Delta currently has approximately 424,000 net acres, and will reassess its drilling plans based upon future geophysical acquisition and interpretation.

     Piceance Basin, CO, 31% — 100% WI — Current production from the Piceance Basin approximates 36.5 million cubic feet equivalent per day (Mmcfe/d) net. The Company has begun completion activity on 24 drilled and uncompleted wells in the Vega Area. Additionally, the operator of Garden Gulch has begun completion operations on the uncompleted inventory of eight wells. The pace of completion activity will be measured to maintain compliance with the capital expenditures covenant under the amendment to the senior credit agreement, and is expected to continue at such pace through the second quarter of 2010.

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     The Company has tested additional sands in the upper-portion of the Williams Fork formation in three existing wells. Initial results are encouraging and management believes there may be 26 additional producing wells that may exhibit incremental production from this section of the Williams Fork.

     The Company is constructing a new water treatment facility that is anticipated to reduce water hauling and disposal costs over the long term development of the field. The new water treatment facility is a patented distillation process that will allow the Company to surface discharge its treated water, thereby reducing the water hauling costs in the field. Additionally, Delta has completed its new compression facility that will allow for significant increased production volumes in the future. The Company continues to assess the current gas price environment to determine when to resume drilling activity.

2009 CAPITAL EXPENDITURES AND PRODUCTION GUIDANCE

     The Company is slightly increasing its previously provided production guidance for 2009 to a range of 21-22 Bcfe. Drilling and completion related capital expenditures for the year are currently expected to be approximately $56 million. As described above, in conjunction with the October 30, 2009 borrowing base redetermination the Company agreed to limit its capital expenditures to $10.0 million in the quarter ending December 31, 2009, $10.0 million in the quarter ending March 31, 2010 and $5.0 million in the quarter ending June 30, 2010.

CHANGES IN DELTA’S BOARD OF DIRECTORS

     The Company has announced that one of the members of its board of directors, James B. Wallace, has decided to resign from the board of Delta Petroleum. Mr. Wallace offered his resignation without any conflict or disagreement with the Company’s direction or management. Dan Taylor commented, “Jim has been a significant contributor to the Company’s board for the past eight years. His expertise and knowledge from having over 50 years of experience in the industry has been of tremendous value to our board and management team. His insight and advice will be greatly missed.” Mr. Wallace’s resignation was effective November 4, 2009.

INVESTOR CONFERENCE CALL

     An investor conference call has been scheduled for 12:00 noon Eastern Time on Thursday, November 5, 2009. Stockholders and other interested parties may participate in the conference call by dialing 800-860-2442 (international callers dial 412-858-4600) and reference the ID code “Delta Petroleum call,” a few minutes before 12:00 noon Eastern Time on November 5, 2009. 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 November 5, 2009 until November 13, 2009 by dialing 877-344-7529 (international callers dial 412-317-0088) and entering the conference ID 435005#.

ABOUT DELTA PETROLEUM

     Delta Petroleum Corporation is an oil and gas exploration and development company based in Denver, Colorado. The Company’s core areas of operations are the Rocky Mountain and Gulf Coast Regions, which comprise the majority of its proved reserves, production and long-term growth prospects. Its common stock is listed on the NASDAQ Global 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, viability of the Roslyn formation, operational strengths and strategies, expected reserve and production growth, drilling plans and activity, pace of completion activity, anticipated drilling and production results and volumes, expected decreases in costs including water hauling and disposal costs and anticipated capital expenditures. 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, uncertainties in the projection of future rates of production, unanticipated

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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, as well as general market conditions, competition and pricing. Please refer to the Company’s report on Form 10-K for the year ended December 31, 2008 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 info@deltapetro.com

SOURCE: Delta Petroleum Corporation

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DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)

	September 30,			December 31,
	2009			2008
	(In thousands, except share data)
ASSETS
Current assets:
Cash and cash equivalents	$	10,683		$	65,475
Short-term restricted deposits		102,898			100,000
Trade accounts receivable, net of allowance for doubtful accounts of $100 and $652, respectively		13,698			30,437
Deposits and prepaid assets		4,682			11,253
Inventories		7,880			9,140
Deferred tax assets		—			231
Other current assets		5,955			6,221
Total current assets		145,796			222,757
Property and equipment:
Oil and gas properties, successful efforts method of accounting:
Unproved		292,317			415,573
Proved		1,387,612			1,365,440
Drilling and trucking equipment		181,229			194,223
Pipeline and gathering systems		98,452			86,076
Other		16,095			29,107
Total property and equipment		1,975,705			2,090,419
Less accumulated depreciation and depletion		(760,682	)		(658,279	)
Net property and equipment		1,215,023			1,432,140
Long-term assets:
Long-term restricted deposit		200,000			200,000
Marketable securities		1,977			1,977
Investments in unconsolidated affiliates		14,032			17,989
Deferred financing costs		3,861			7,640
Other long-term assets		14,339			12,460
Total long-term assets		234,209			240,066
Total assets	$	1,595,028		$	1,894,963
LIABILITIES AND EQUITY
Current liabilities:
Credit facility — Delta	$	—		$	294,475
Credit facility — DHS		83,268			—
Installments payable on property acquisition		99,356			97,453
Accounts payable		56,567			159,024
Executive severance payable		2,898			—
Other accrued liabilities		16,724			13,576
Derivative instruments		14,551			—
Total current liabilities		273,364			564,528
Long-term liabilities:
Installments payable on property acquisition, net of current portion		192,013			188,334
7% Senior notes		149,591			149,534
33/4% Senior convertible notes		102,894			99,616
Credit facility — Delta		123,038			—
Credit facility — DHS		—			93,848
Asset retirement obligations		8,197			6,585
Derivative instruments		12,483			—
Deferred tax liabilities		—			1,024
Total long-term liabilities		588,216			538,941
Commitments and contingencies
Equity:
Preferred stock, $.01 par value: authorized 3,000,000 shares, none issued		—			—
Common stock, $.01 par value; authorized 300,000,000 shares, issued 276,728,000 shares at September 30, 2009 and 103,424,000 shares at December 31, 2008		2,767			1,034
Additional paid-in capital		1,622,808			1,372,123
Treasury stock at cost; 1,038,000 shares at September 30, 2009 and 36,000 shares at December 31, 2008		(2,057	)		(540	)
Executive severance payable in common stock		1,700			—
Accumulated deficit		(904,925	)		(610,227	)
Total Delta stockholders’ equity		720,293			762,390
Non-controlling interest		13,155			29,104
Total equity		733,448			791,494
Total liabilities and equity	$	1,595,028		$	1,894,963

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2009			2008			2009			2008
	(In thousands, except per share amounts)
Revenue:
Oil and gas sales	$	21,534		$	60,288		$	65,041		$	187,280
Contract drilling and trucking fees		2,538			11,760			9,425			30,355
Gain (loss) on offshore litigation award		(150	)		—			31,054			—
Total revenue		23,922			72,048			105,520			217,635
Operating expenses:
Lease operating expense		7,566			7,679			25,013			24,722
Transportation expense		2,089			3,630			7,849			7,902
Production taxes		1,156			3,862			3,761			11,666
Exploration expense		891			2,870			2,422			5,805
Dry hole costs and impairments		53,406			8,149			161,471			10,918
Depreciation, depletion, amortization and accretion — oil and gas		25,715			29,600			82,469			77,391
Drilling and trucking operating expenses		2,818			8,245			10,416			20,597
Depreciation and amortization — drilling and trucking		5,545			2,722			17,512			9,573
General and administrative expense		9,951			14,892			31,545			42,139
Executive severance expense, net		—			—			3,739			—
Total operating expenses		109,137			81,649			346,197			210,713
Operating income (loss)		(85,215	)		(9,601	)		(240,677	)		6,922
Other income and (expense):
Interest expense and financing costs		(10,729	)		(11,605	)		(43,686	)		(30,218	)
Interest income		1,023			3,142			1,779			8,400
Other income (expense)		220			(3,896	)		1,630			(3,624	)
Realized gain (loss) on derivative instruments, net		370			10,820			370			2,055
Unrealized gain (loss) on derivative instruments, net		(5,923	)		54,779			(27,034	)		13,574
Income (loss) from unconsolidated affiliates		(454	)		2,122			(3,324	)		2,814
Total other income (expense)		(15,493	)		55,362			(70,265	)		(6,999	)
Income (loss) from continuing operations before income taxes and discontinued operations		(100,708	)		45,761			(310,942	)		(77	)
Income tax expense (benefit)		265			(2,175	)		(53	)		(3,632	)
Income (loss) from continuing operations		(100,973	)		47,936			(310,889	)		3,555
Discontinued operations:
Gain (loss) on sale of discontinued operations, net of tax		—			715			—			719
Net income (loss)		(100,973	)		48,651			(310,889	)		4,274
Less net loss attributable to non-controlling interest		4,146			147			16,191			355
Net income (loss) attributable to Delta common stockholders	$	(96,827	)	$	48,798		$	(294,698	)	$	4,629
Amounts attributable to Delta common stockholders:
Gain (loss) from continuing operations	$	(96,827	)	$	48,083		$	(294,698	)	$	3,910
Income (loss) from discontinued operations, net of tax		—			715			—			719
Net income (loss)	$	(96,827	)	$	48,798		$	(294,698	)	$	4,629
Basic income (loss) attributable to Delta common stockholders per common share:
Gain (loss) from continuing operations	$	(0.35	)	$	0.47		$	(1.55	)	$	0.04
Discontinued operations		—			0.01			—			0.01
Net income (loss)	$	(0.35	)	$	0.48		$	(1.55	)	$	0.05
Diluted income (loss) attributable to Delta common stockholders per common share:
Gain (loss) from continuing operations	$	(0.35	)	$	0.46		$	(1.55	)	$	0.04
Discontinued operations		—			0.01			—			0.01
Net income (loss)	$	(0.35	)	$	0.47		$	(1.55	)	$	0.05
Weighted average common shares outstanding:
Basic		275,465			101,277			189,740			95,365
Diluted		275,465			102,790			189,740			96,994

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DELTA PETROLEUM CORPORATION
RECONCILIATION OF DISCRETIONARY CASH FLOW AND EBITDAX

	(in thousands)
	(unaudited)
	September 30,			September 30,
	2009			2008
THREE MONTHS ENDED
CASH PROVIDED BY OPERATING ACTIVITIES	$	(12,690	)	$	43,935
Changes in assets and liabilities		10,173			(9,326	)
Exploration costs		891			2,870
Discretionary cash flow (deficiency)*	$	(1,626	)	$	37,479

	September 30,			September 30,
	2009			2008
NINE MONTHS ENDED:
CASH PROVIDED BY OPERATING ACTIVITIES	$	20,159		$	93,318
Changes in assets and liabilities		(1,113	)		7,674
Less net proceeds from offshore litigation award		(48,701	)		—
Exploration costs		2,422			5,805
Discretionary cash flow (deficiency)*	$	(27,233	)	$	106,797

* Discretionary cash flow represents net cash provided by operating activities before changes in assets and liabilities and offshore litigation plus exploration costs. Discretionary cash flow is presented as a supplemental financial measurement in the evaluation of our business. We believe that it provides additional information regarding our ability to meet our 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,
	2009			2008
THREE MONTHS ENDED
Net income (loss)	$	(100,973	)	$	48,651
Minority Interest		4,146			147
Income tax expense (benefit)		265			(2,175	)
Interest income		(1,023	)		(3,142	)
Interest and financing costs		10,729			11,605
Depletion, depreciation and amortization		31,260			32,322
Gain on offshore litigation award, sale of drilling rig and other		212			(715	)
Unrealized loss on derivative instruments		5,923			(54,779	)
Exploration, dry hole and impairment costs		54,298			11,019
EBITDAX**	$	4,837		$	42,933

	September 30,			September 30,
	2009			2008
THREE MONTHS ENDED
CASH PROVIDED BY OPERATING ACTIVITIES	$	(12,690	)	$	43,935
Changes in assets and liabilities		10,173			(9,326	)
Less Interest net of financing costs		5,522			4,485
Exploration costs		891			2,870
Other non-cash items		941			969
EBITDAX**	$	4,837		$	42,933

	September 30,			September 30,
	2009			2008
NINE MONTHS ENDED
Net income (loss)	$	(310,889	)	$	4,274
Minority Interest		16,191			355
Income tax benefit		(53	)		(3,632	)
Interest income		(1,779	)		(8,400	)
Interest and financing costs		43,686			30,218
Depletion, depreciation and amortization		99,981			86,964
Gain on offshore litigation award, sale of drilling rig and other		(32,717	)		(719	)
Unrealized loss on derivative instruments		27,034			(13,574	)
Exploration, dry hole and impairment costs		163,893			16,723
EBITDAX**	$	5,347		$	112,209

	September 30,			September 30,
	2009			2008
NINE MONTHS ENDED
CASH PROVIDED BY OPERATING ACTIVITIES	$	20,159		$	93,318
Changes in assets and liabilities		(1,113	)		7,674
Less net proceeds from offshore litigation award		(48,701	)		—
Interest net of financing costs		26,296			11,581
Exploration costs		2,422			5,805
Other non-cash items		6,284			(6,169	)
EBITDAX**	$	5,347		$	112,209

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** EBITDAX represents net income (loss) attributable to Delta common stockholders before income tax expense (benefit), interest and financing costs, depreciation, depletion and amortization expense, gain on sale of oil and gas properties, offshore litigation and other investments, unrealized gains (loss) on derivative contracts and exploration and impairment and dry hole costs. EBITDAX is presented as a supplemental financial measurement in the evaluation of our business. We believe that it provides additional information regarding our ability to meet our 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 our lenders pursuant to our bank credit agreement and is used in the financial covenants in our bank credit agreement and our 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.

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