exv99w1

Exhibit 99.1

DELTA PETROLEUM CORPORATION
Daniel J. Taylor, Chairman
Kevin K. Nanke, Treasurer and CFO
John R. Wallace, President and COO
Broc Richardson, VP Corporate Development and Investor Relations
370 17th Street, Suite 4300
Denver, Colorado 80202

For Immediate Release

DELTA PETROLEUM CORPORATION
ANNOUNCES FIRST QUARTER 2010 RESULTS

DENVER, Colorado (May 10, 2010) – Delta Petroleum Corporation (Delta or the Company) (NASDAQ Global Market: DPTR), an independent oil and gas exploration and development company, today announced its financial and operating results for the first quarter of 2010.

John Wallace, Delta’s President and COO stated, “The first quarter of this year was a noteworthy quarter for Delta. We continue to work with our potential partner, Opon International, in moving toward the signing of definitive agreements and closing of the transaction. We believe this relationship is certainly in the best interests of both our shareholders and our bondholders. The capital from this transaction would allow for an aggressive development of our main asset in the Piceance Basin, which provides substantial upside in proved reserves.

“In the Vega Area of the Piceance Basin we continued with moderate completion activity that was measured to preserve our current liquidity position. This completion activity involves new procedures and we’ve experienced very encouraging results to date.”

LETTER OF INTENT (STRATEGIC ALTERNATIVES) UPDATE

As previously announced on March 18, 2010, Delta entered into a non-binding letter of intent with Opon International LLC (“Opon”) to sell a 37.5% non-operated working interest in the Vega Area assets located in the Piceance Basin for total consideration of $400 million and to issue Opon warrants to purchase 13.3 million shares of Delta common stock at $1.50 per share and 5.7 million shares at $3.50 per share. The consummation of the transaction is contingent upon Opon’s ability to arrange financing and is subject to customary due diligence, negotiation and execution of definitive binding agreements. The parties are continuing with the proposed transaction and the Company understands that Opon’s financing efforts are ongoing.

LIQUIDITY UPDATE

At March 31, 2010, the Company had $10 million in cash and $52.0 million available under its credit facility (based on the redetermined $145 million borrowing base described below).

On April 26, 2010, Delta entered into the Third Amendment (the “Amendment”) to the Second Amended and Restated Credit Agreement (as amended, the “Credit Agreement”), with JPMorgan Chase Bank, N.A., as agent, and certain of the financial institutions that are party to its credit agreement in which, among other changes, the lenders provided a waiver of Delta’s violation of the quarter ended March 31, 2010 capital expenditures limitation of $10.0 million. In conjunction with the Amendment and as part of a scheduled redetermination, the borrowing base was reduced from $185.0 million with a $20.0 million required minimum availability to $145.0 million with no required minimum availability for a net reduction in the borrowing base of $20.0 million. The next scheduled redetermination date is July 1, 2010. In addition, the Amendment imposed capital expenditures limitations of $20.0 million for the quarter ending June 30, 2010 and $15.0 million for the quarter ending September 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 Company was in compliance with the accounts payable covenant under its credit facility at March 31, 2010.

On April 1, 2010 DHS Drilling amended its credit facility with Lehman Commercial Paper Inc. and renegotiated certain terms of the agreement. The only financial covenant remaining in the DHS credit agreement is a minimum EBITDA covenant. The interest rate has been adjusted to LIBOR plus 625 basis points, subject to a LIBOR floor rate of 2.75%. DHS was in compliance with its amended minimum EBITDA covenant for the quarter ended March 31, 2010.

RESULTS FOR THE FIRST QUARTER

For the quarter ended March 31, 2010, the Company reported production of 5.0 billion cubic feet equivalents (“Bcfe”), a decrease of 20% when compared with the first quarter of 2009. The production decrease was mostly related to expected production declines in the Rockies that have not been offset by additional drilling. Total revenue decreased 25% to $44.0 million in the quarter, versus revenue of $58.7 million in the quarter ended March 31, 2009, primarily related to a $31.3 million gain associated with the offshore California litigation in 2009, partially offset by a $12.3 million quarter-over-quarter increase in oil and gas sales. For the quarter ended March 31, 2010, oil and gas sales increased 55% to $34.5 million, as compared to $22.2 million for the prior year period. The increase was primarily the result of a 125% increase in oil prices and an 86% increase in natural gas prices, partially offset by the 20% decrease in production. The average oil price received during the quarter ended March 31, 2010 increased to $70.78 per Bbl compared to $31.44 per Bbl for the prior year period. The average natural gas price received during the quarter ended March 31, 2010 increased to $5.70 per thousand cubic feet (“Mcf”) compared to $3.07 per Mcf for the prior year period.

The Company reported a first quarter net loss attributable to common stockholders of ($12.8 million), or ($0.05) per share, compared with a net loss attributable to common stockholders of ($25.6 million), or ($0.25) per share, in the first quarter of 2009.

FIRST QUARTER PRODUCTION VOLUMES, UNIT PRICES AND COSTS

Production volumes, average prices received and cost per thousand cubic feet equivalents (“Mcfe”) for the quarter ended March 31, 2010 and 2009 are as follows:


	Three Months Ended
	March 31,
	2010		2009
Production:
Oil (Mbbl)		156		212
Gas (Mmcf)		4,112		5,050
Total Production (Mmcfe)		5,046		6,324

Average Price:
Oil (per barrel)	$	70.78	$	31.44
Gas (per Mcf)	$	5.70	$	3.07

Costs (per Mcfe):
Lease operating expense	$	1.62	$	1.56
Transportation costs	$	0.78	$	0.51
Production taxes	$	0.33	$	0.25
Depletion expense	$	4.46	$	4.13

Realized derivative losses (per Mcfe)	$	0.82	$	—

Lease Operating Expense. Lease operating expenses for the quarter ended March 31, 2010 decreased to $8.2 million from $9.8 million in the prior year period primarily due to the 20% decrease in production.

Transportation Expense. Transportation expense for the quarter ended March 31, 2010 was $3.9 million, comparable to prior year costs of $3.3 million, but increased 53% from $0.51 per Mcfe to $0.78 per Mcfe. The increase on a per unit basis is primarily the result of changes to the Vega gas marketing contract that went into effect in October 2009 whereby the gas is processed through a higher efficiency plant. The Vega gas marketing contract has resulted in higher revenues in the Vega area from improved natural gas liquids recoveries and a greater percentage of liquids proceeds retained.

Depreciation, Depletion, Amortization and Accretion – Oil and Gas. Depreciation, depletion and amortization expense decreased 14% to $23.2 million for the quarter ended March 31, 2010, as compared to $26.8 million for the prior year period. Depletion expense for the quarter ended March 31, 2010 decreased to $22.5 million from $26.1 million for the quarter ended March 31, 2009, due to lower production volumes partially offset by an increase in the per unit depletion rate. The depletion rate increased from $4.13 per Mcfe for the quarter ended March 31, 2009 to $4.46 per Mcfe for the current year period primarily due to non-operated Piceance reserve revisions made in the second quarter of 2009 to reduce proved developed reserves based on well performance.

General and Administrative Expense. General and administrative expense decreased 10% to $11.4 million for the quarter ended March 31, 2010, as compared to $12.6 million for the comparable prior year period. The decrease in general and administrative expenses is attributed to reduced staffing as a result reductions in force during the first half of 2009 resulting in lower cash compensation expense, partially offset by costs associated with the strategic alternatives evaluation process and by increased non-cash stock compensation expense related to restricted stock granted in December 2009.

ADDITIONAL FINANCIAL INFORMATION

The following table summarizes the Company’s open derivative contracts at March 31, 2010:

Remaining

Commodity

Volume

Fixed Price

Term

Index Price

Crude oil

1,000

Bbls / Day

52.25

Apr ’10 - Dec ’10

NYMEX – WTI

Crude oil

500

Bbls / Day

57.70

Jan ’11 - Dec ’11

NYMEX – WTI

Natural gas

6,000

MMBtu / Day

5.720

Apr ’10 - Dec ’10

NYMEX – HHUB

Natural gas

15,000

MMBtu / Day

4.105

Apr ’10 - Dec ’10

CIG

Natural gas

5,367

MMBtu / Day

3.973

Apr ’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 statements was a liability of approximately $9.7 million at March 31, 2010.

OPERATIONS UPDATE

Piceance Basin, CO, 31% – 100% WI – Current production from the Piceance Basin approximates 34 million cubic feet equivalent per day (Mmcfe/d) net. During the first quarter 2010 the Company completed three wells from its drilled and uncompleted inventory in the Vega Area. The Company expects to complete the remaining 16 drilled and uncompleted wells in 2010 utilizing its redesigned completion techniques. Additionally, the operator of Garden Gulch has a one rig drilling program ongoing.

2010 CAPITAL EXPENDITURES AND PRODUCTION GUIDANCE

As previously announced, the Company expects to announce its 2010 drilling and completion plans and production guidance once the strategic alternatives evaluation process is complete.

INVESTOR CONFERENCE CALL

The Company will host an investor conference call Tuesday, May 11, 2010 at 12:00 noon Eastern Time (10:00 am Mountain Time) to discuss financial and operating results for the first quarter 2010.

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 May 11, 2010. 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 May 11, 2010 until May 19, 2010 by dialing 877-344-7529 (international callers dial 412-317-0088) and entering the conference ID 440157.

ABOUT DELTA PETROLEUM CORPORATION

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. 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 our credit facility and our working capital needs, the outcome of our strategic alternatives process, the closing of the pending transaction with Opon, the contraction in demand for natural gas in the United States, the impact of current economic and financial conditions on our ability to raise capital, availability of borrowings under our credit facility and the ability to obtain a new or replacement credit facility, 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, 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, 2009 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

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(Unaudited)


	March 31,			December 31,
	2010			2009
	(In thousands, except share data)
ASSETS
Current assets:
Cash and cash equivalents	$	9,980		$	61,918
Short-term restricted deposits		100,000			100,000
Trade accounts receivable, net of allowance for doubtful accounts of $100 and $100, respectively		18,166			16,654
Deposits and prepaid assets		3,179			3,103
Inventories		4,623			5,588
Other current assets		3,498			5,189

Total current assets		139,446			192,452

Property and equipment:
Oil and gas properties, successful efforts method of accounting:
Unproved		279,725			280,844
Proved		1,336,131			1,379,920
Drilling and trucking equipment		178,434			177,762
Pipeline and gathering systems		96,139			92,064
Other		16,080			16,154

Total property and equipment		1,906,509			1,946,744
Less accumulated depreciation and depletion		(775,200	)		(800,501	)

Net property and equipment		1,131,309			1,146,243


Long-term assets:
Long-term restricted deposit		100,000			100,000
Investments in unconsolidated affiliates		3,936			7,444
Deferred financing costs		2,664			3,017
Other long-term assets		6,430			8,329

Total long-term assets		113,030			118,790


Total assets	$	1,383,785		$	1,457,485


LIABILITIES AND EQUITY
Current liabilities:
Credit facility — Delta	$	93,038		$	—
Credit facility — DHS		83,268			83,268
Installments payable on property acquisition		98,507			97,874
Accounts payable		42,544			44,225
Offshore litigation payable		—			13,877
Other accrued liabilities		15,074			13,459
Derivative instruments		6,777			19,497

Total current liabilities		339,208			272,200

Long-term liabilities:
Installments payable on property acquisition, net of current portion		95,998			95,381
7% Senior notes		149,628			149,609
3³/4% Senior convertible notes		105,121			104,008
Credit facility — Delta		—			124,038
Asset retirement obligations		6,392			7,654
Derivative instruments		2,923			7,475

Total long-term liabilities		360,062			488,165

Commitments and contingencies

Equity:
Preferred stock, $.01 par value: authorized 3,000,000 shares, none issued		—			—
Common stock, $.01 par value; authorized 600,000,000 shares, issued 282,812,000 shares at March 31, 2010 and 282,548,000 shares at December 31, 2009		2,828			2,825
Additional paid-in capital		1,628,238			1,625,035
Treasury stock at cost; 34,000 shares at March 31, 2010 and 42,000 shares at December 31, 2009		(193	)		(268	)
Accumulated deficit		(951,807	)		(939,010	)

Total Delta stockholders’ equity		679,066			688,582

Non-controlling interest		5,449			8,538

Total equity		684,515			697,120


Total liabilities and equity	$	1,383,785		$	1,457,485

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)


	Three Months Ended
	March 31,
	2010			2009
	(In thousands, except per share amounts)
Revenue:

Oil and gas sales	$	34,453		$	22,158
Contract drilling and trucking fees		9,932			5,213
Gain (loss) on offshore litigation award and property sales, net		(429	)		31,285


Total revenue		43,956			58,656


Operating expenses:

Lease operating expense		8,171			9,846
Transportation expense		3,927			3,255
Production taxes		1,681			1,580
Exploration expense		226			1,060
Dry hole costs and impairments		354			1,443
Depreciation, depletion, amortization and accretion — oil and gas		23,186			26,822
Drilling and trucking operating expenses		7,889			5,256
Depreciation and amortization — drilling and trucking		5,572			5,792
General and administrative		11,387			12,630


Total operating expenses		62,393			67,684


Operating loss		(18,437	)		(9,028	)


Other income and (expense):

Interest expense and financing costs, net		(10,560	)		(16,426	)
Other income, net		129			154
Realized loss on derivative instruments, net		(4,113	)		—
Unrealized gain (loss) on derivative instruments, net		17,272			(5,464	)
Income (loss) from unconsolidated affiliates		(8	)		747


Total other income (expense)		2,720			(20,989	)


Loss before income taxes		(15,717	)		(30,017	)

Income tax expense (benefit)		275			(583	)


Net loss		(15,992	)		(29,434	)

Less net loss attributable to non-controlling interest		3,195			3,880


Net loss attributable to Delta common stockholders	$	(12,797	)	$	(25,554	)


Basic income (loss) attributable to Delta common stockholders per common share:
Net loss	$	(0.05	)	$	(0.25	)


Diluted income (loss) attributable to Delta common stockholders per common share:
Net loss	$	(0.05	)	$	(0.25	)

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

(In thousands)


	March 31,			March 31,
THREE MONTHS ENDED	2010			2009
CASH PROVIDED BY OPERATING ACTIVITIES	$	(16,941	)	$	(5,908	)
Changes in assets and liabilities		20,621			(7,508	)
Exploration costs		226			1,060

Discretionary cash flow (deficiency)*	$	3,906		$	(12,356	)


*		Discretionary cash flow represents net cash provided by 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 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.


	March 31,			March 31,
THREE MONTHS ENDED	2010			2009
Net loss	$	(15,992	)	$	(29,434	)
Minority interest		3,195			3,880
Income tax expense (benefit)		275			(583	)
Interest expense and financing costs, net		10,560			16,426
Depletion, depreciation and amortization		28,758			32,614
(Gain) loss on offshore litigation award, property sales and other		361			(31,285	)
Unrealized (gain) loss on derivative instruments, net		(17,272	)		5,464
Exploration, dry hole and impairment costs		580			2,503

EBITDAX**	$	10,465		$	(415	)


	March 31,			March 31,
THREE MONTHS ENDED	2010			2009
CASH PROVIDED BY OPERATING ACTIVITIES	$	(16,941	)	$	(5,908	)
Changes in assets and liabilities		20,621			(7,508	)
Interest net of financing costs		6,760			10,328
Exploration costs		226			1,060
Other non-cash items		(201	)		1,613

EBITDAX**	$	10,465		$	(415	)


**		EBITDAX represents net loss before income tax expense (benefit), interest expense and financing costs, net, depreciation, depletion and amortization expense, gain and loss on sale of oil and gas properties, offshore litigation and other investments, net unrealized gains and losses 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.