e8vk

Exhibit 99.1

DELTA PETROLEUM CORPORATION
Roger A. Parker, Chairman and CEO
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 2008 ANNUAL AND FOURTH QUARTER RESULTS

PROVED RESERVES INCREASE 135% TO 884 BCFE AND ALL-IN F&D
COSTS DECREASE TO $1.37 PER MCFE

DENVER, Colorado (March 2, 2009) – 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 fourth quarter and full year 2008 and that it has entered into a forbearance agreement and amendment to the Credit Facility with its bank group.

2008 HIGHLIGHTS

	•		Revenue from oil and gas sales increased 79% to $221 million

	•		Total revenue increased 39% to $271 million

	•		EBITDAX (a non-GAAP measure) increased 86% to $156 million

	•		Cash provided by operating activities of $141 million

	•		Production from continuing operations increased 48%

	•		Proved reserves increased 135% to 884 Bcfe

	•		Proved developed reserves increased 52% to 181 Bcfe

	•		All-in F&D costs per Mcfe totaled $1.37 for 2008 with a 3-year average of $1.84

Roger Parker, Delta’s Chairman and CEO said, “At the outset of 2008 we closed on a substantial investment of new equity capital from the Tracinda Corporation. Coinciding with the investment we significantly accelerated drilling activity and acquired adjacent leasehold interests and producing wells in the Piceance Basin. We also increased drilling in other areas of potential, including the Paradox Basin, Utah Hingeline, and Columbia River Basin. The increase in drilling activity was anticipated to achieve goals of 40% or more production growth, and 100% or more proved reserve growth. Today we are reporting 2008 production growth from continuing operations of 48%, proved reserve growth of 135%, and all-in finding and development costs of $1.37/Mcfe. These accomplishments were achieved due to significant decreases in drill time and completion costs, as well as meaningful economies of scale realized in the Piceance Basin where over 60% of our 2008 drilling capital expenditures were deployed.”

“In addition, the Company’s exploration program in the Columbia River Basin was marked by significant accomplishments during 2008. “We began drilling the Gray 31-23 well, secured a joint venture partner and acquired significant additional acreage. Exciting and recently obtained drilling information has strengthened our belief in the vast resource potential of this project and the role it can play in our Company’s future success.”

“While 2008 was a year of impressive operating results, dramatic declines in oil and gas prices during the past twelve months have presented Delta and many energy companies with liquidity challenges in recent months,” continued Parker. “Our goal is to address these issues through a combination of joint ventures and other capital raising transactions, while also implementing cost reduction measures. Additionally, the lenders on our senior credit facility have provided covenant relief for 2009 and 2010. The combination of our capital raising efforts, cost reductions and relief provided by our banks should provide the Company with the liquidity and flexibility necessary to endure

the current environment. We have weathered downturns before and I am confident that Delta will again realize its potential as a successful development and exploration company.”

2008 YEAR-END RESERVES AND RESERVE GROWTH

For the year-ended December 31, 2008, Delta reported total estimated proved reserves of 884 Bcfe, compared to 376 Bcfe at December 31, 2007. Increases in proved reserves were a result of a successful drilling program, the purchase of properties and upward revisions that were primarily related to ten acre downspacing in the Vega Area of the Piceance Basin. Estimated proved reserves were 94% natural gas and 6% oil. The reserves were prepared by an independent third party engineering firm.

The following table presents information regarding the change in oil and natural gas proved reserves from December 31, 2007 to December 31, 2008:


	Gas			Oil			Total
	(Mmcf)			(MBbl)			(Mmcfe)
	(In thousands)
Estimated Proved Reserves: Balance at December 31, 2007		309,473			11,025			375,623


Revisions of quantity estimate		191,002			(4,108	)		166,354
Extensions and discoveries		152,801			1,652			162,713
Purchase of properties		193,351			1,877			204,613
Sale of properties		—			—			—
Production		(18,950	)		(993	)		(24,908	)


Estimated Proved Reserves: Balance at December 31, 2008		827,677			9,453			884,395


Proved developed reserves:
December 31, 2006		65,026			6,287			102,748
December 31, 2007		92,194			4,548			119,482
December 31, 2008		161,552			3,274			181,196

Future net cash flows presented below are computed using year end prices and costs.

December 31, 2008 (in thousands)


Future net cash flows	$	3,542,332
Future costs:
Production		924,705
Development and abandonment		1,337,842
Income taxes		—

Future net cash flows		1,279,785
10% discount factor		(1,120,417	)

Standardized measure of discounted future net cash flows	$	159,368	*

Estimated future development cost anticipated for fiscal 2009 and 2010 on existing properties	$	216,000


*		The standardized measure discounted at 10% attributed to proved developed reserves is $289.8 million.

Costs incurred for oil and gas producing activities (in thousands) for the year ended December 31, 2008 are as follows:


Unproved property acquisition costs	$	180,149
Proved property acquisition costs		41,666
Developed costs incurred on proved undeveloped reserves		123,999
Development costs – other		261,588
Exploration and dry hole costs		122,827

Total costs incurred	$	730,229

Capital expenditures for the full year 2008 totaled $408.5 million. Total costs incurred in oil and gas operations during 2008, including acquisition, leasehold, drilling, completion, dry hole costs, seismic, asset retirement obligations and all other capitalized oil and gas related costs, approximated $730.2 million.


Reserve replacement percentage		2,143	%
F&D costs per Mmcfe of proved reserves added	$	1.37
Drillbit F&D costs per Mmcfe of proved reserves added	$	1.55

The principal sources of changes in the standardized measure of discounted net cash flows during the year ended December 31, 2008 are as follows:

Year ended December 31, 2008 (in thousands)


Beginning of the year	$	701,874
Sales of oil and gas production during the period, net of production costs		(164,755	)
Purchase of reserves in place		289,040
Net change in prices and production costs		(907,844	)
Changes in estimated future development costs		(27,087	)
Extensions, discoveries and improved recovery		242,079
Revisions of previous quantity estimates, estimated timing of development and other		(281,302	)
Previously estimated development and abandonment costs incurred during the period		123,999
Sales of reserves in place		—
Change in future income tax		113,177
Accretion of discount		70,187

End of year	$	159,368

OPERATIONS UPDATE

Piceance Basin, CO, 31% – 100% WI – Current production from the Piceance Basin approximates 57 Mmcfe/d gross and 46 Mmcfe/d net. The last ten wells drilled in the Vega Area averaged ten days, down from the third quarter 2008 average of 13 days. The Company has an inventory of approximately 35 wells that have been drilled but not yet completed. The Company will have a measured completion program based on available capital with the intention of maintaining current production levels throughout the remainder of 2009. As of mid-February, the Company does not have any drilling rigs active in the field. Throughout the first three quarters of 2008, Delta undertook a concerted effort to prepare for accelerated drilling activity that would ultimately accommodate an eight-rig drilling program. This included large-scale permitting that would allow for drilling 200 new wells per year in the Vega Area beginning in 2009. The Company commenced infrastructure construction necessary for these increased volumes, which included a 16’’ intrafield pipeline and additional compression facilities. Additionally, several drilling pads and roads were constructed to accommodate the expected increased rigs and activity. Accordingly, the field is set up for significant near-term

growth once drilling activity resumes. The Company is continuing with its marketing efforts in seeking a joint venture partner. Proved reserves in the Piceance Basin grew from 234 Bcfe to 820 Bcfe at December 31, 2008.

Columbia River Basin, WA, 50% WI – The Company continues to drill the Gray 31-23 well and expects to be at total depth within the next 30 days. On two separate occasions, Delta has stopped drilling to run electric logs and has also taken core samples. Thus far the well has encountered numerous sandstones that contain several hundred net feet of porous and permeable sands based on wireline logs and core analysis. Porosities range from 12% to 17% with an average of 14% and permeabilities are very good and range from 27 md to 107 md. These sandstone intervals required very high mud weights to control gas flows suggesting a highly over-pressured gas system. The gas column appears to be much higher in the stratigraphic section as compared to other wells in the basin. Volumetric calculations based solely on logs and cores indicate the potential for significant gas volumes, and completion results will provide the necessary information to generate reserve estimates. Although no additional capital commitments will be made until results from the Gray 31-23 well have been obtained, the Company has begun permitting efforts for an additional well.

Paradox Basin, UT, 70% WI – In the Greentown area, the Company initially targeted intra-salt clastic intervals on the Greentown Salt Anticline because several older wells experienced significant gas shows while drilling. Delta’s initial two wells experienced flow rates of 5 Mmcfe/d and 5.3 Mmcfe/d from the lower clastic intervals. The wells were located approximately seven miles apart and the clastic breaks correlated very well suggesting lateral continuity. The third well drilled in the project area tested 1,946 Bo/d and 11.6 Mmcfe/d during a 72 hour flow test. Subsequent wells were drilled and completion efforts of individual clastic intervals yielded mixed results. There are numerous individual clastic intervals yet to be completed.

Results from activity at the Greentown project have been frustrating at best, but drilling by other operators continues on leasehold immediately adjacent to Delta’s. The Company’s Paradox pipeline and processing facility infrastructure are well positioned if additional production is established by Delta or others in the play. The Company has decided to temporarily suspend capital expenditures in this area, but outside operator activity should provide new and important information that will help determine the project’s potential. In the future, Delta plans to complete several clastic intervals requiring minimal capital investment in each of the five remaining wellbores.

Wind River Basin, WY, 100% WI – Over the last several years the Company drilled several wells in the A-Coal interval of the Waltman Shale. The better performing wells result from fracturing, and the orientation of the fractures appear to be vertical. The Company has generated an unconventional shale play in the Waltman Shale that will include horizontal wellbores directionally oriented to exploit the vertical fracture network in the A-Coal. The Company is attempting to secure a joint venture partner to develop its large leasehold throughout the Wind River Basin.

Central Utah Hingeline Project, UT, 65% WI – The Company did not experience any appreciable drilling success in its first three exploratory wells in the Utah Hingeline Play other than to establish that oil appears to have migrated through this region. The Company has impaired 90% of its acreage cost basis, but believes that of the 21 initially identified structural features only six have been condemned. As with other areas, the Company will likely seek additional joint venture participation in further exploration activities as the Company focuses a majority of its capital expenditures on lower risk projects.

Midway Loop Area, SE Gulf Coast, TX, ~ 15% – 80% WI – The Company finished drilling and completed the Carter A-144 (77% WI) well in early January 2009. The well had an initial production rate of 8.5 Mmcfe/d.

Haynesville Shale, East TX and LA, ~ 33 – 100% WI – The Company acquired rights to 16,000 gross acres in the Haynesville Shale during the second and third quarters of 2008. The acreage position is concentrated in Caddo Parish, Louisiana, and Harrison, Shelby and Nacogdoches counties, Texas, which are considered to be highly attractive regions in the play. The costs to acquire the leasehold rights have averaged approximately $3,500 per acre. The Company is attempting to obtain a joint venture partner to begin drilling its leasehold interests.

LIQUIDITY AND OUTLOOK

The economic and operating condition of the oil and gas exploration and production industry has changed dramatically. The decline in commodity prices has resulted in a significant decrease in Delta’s liquidity position. Total liquidity as of December 31, 2008 was principally the cash on hand of approximately $65 million as the Company was fully borrowed on its bank credit facility of $295 million. In August 2008, DHS closed a new $150 million credit facility with Lehman Brothers Commercial Paper, as administrative agent. As a result of the Lehman bankruptcy, DHS has no additional availability under its credit facility.

The Company’s auditors have issued their opinion on the Company’s 2008 financial statements which contains a “going concern” exploratory paragraph.

In an effort to address its liquidity situation and continue to develop its most promising opportunities, the Company has been successful in working with its bank group to modify the terms of its existing senior credit facility and expects to pursue a combination of initiatives including joint ventures, asset monetizations and other capital raising transactions, as well as cost reduction measures.

On March 2, 2009, the Company entered into the First Amendment to the Second Amended and Restated Credit Agreement (the “Amendment”) with JPMorgan Chase Bank, N.A. and certain other financial institutions in which, among other changes, the lenders provided the Company relief for a period ending April 15, 2009 at the earliest and no later than June 15, 2009, dependent upon the progress of the Company’s capital raising efforts, from acting upon their rights and remedies as a result of the Company’s violation of accounts payable and current ratio covenants. The Amendment waives the March 31, 2009 current ratio covenant requirement, and, if the Company successfully completes its capital raising efforts, replaced the previous consolidated net debt to consolidated EBITDAX covenant with a senior secured debt to consolidated EBITDAX covenant which would require that the ratio of the Company’s senior secured debt to consolidated EBITDAX for the preceding four consecutive fiscal quarters be less than 4.0 to 1.0. In accordance with the Amendment, the borrowing base will be reduced upon the successful completion of our capital raising efforts from $295 million to $225 million, with a conforming borrowing base of $185 million until the next scheduled redetermination date (September 1, 2009). The Amendment requires that the Company raise net proceeds of at least $140 million through its capital raising efforts on or before the forbearance termination date and that the Company reduce its amounts outstanding under the senior credit facility to not more than $225 million and pay accounts payable with such net proceeds. The revised variable interest rates on the senior credit facility are based on the ratio of outstanding credit to the conforming borrowing base and vary between Libor plus 2.5% to Libor plus 5.0% for Eurodollar loans and 1.625% to 4.125% for base rate loans. The Amendment will change the maturity date of the senior credit facility to January 15, 2011 upon the successful completion of our capital raising efforts.

The Company has obtained two judgments against the United States in its Offshore California litigation, one in the amount of $60 million and the other in the amount of $91.4 million. The $60 million judgment was affirmed by the United States Court of Appeals for the Federal Circuit on August 25, 2008 and the government’s petition seeking a rehearing of the decision was denied on December 24, 2008. Payment of this judgment is currently delayed while the government decides whether or not to seek review by the United States Supreme Court. The government was recently granted an extension until April 4, 2009 to elect to make its decision. If review is not sought, payment is expected to be received during the second quarter of 2009. The $91.4 million judgment was entered by the United States Court of Federal Claims on February 25, 2009.

NON-CASH IMPAIRMENT CHARGES

As a result of the decline in commodities prices, Delta recorded a non-cash impairment charge of approximately $236 million against its proved oil and gas properties and wrote down a portion of the cost of the Paradox pipeline during the year ended December 31, 2008. The impairments resulted primarily from the significant decline in commodity pricing during the fourth quarter of 2008.

For unproved properties, the impairment test is based on the Company’s plans for future development and other activities impacting the life of the property and the ability of the Company to recover its investment. When the Company believes the costs of the unproved property are no longer recoverable, an impairment charge is recorded based on the estimated fair value of the property. As a result of such assessment, during the year ended December 31, 2008 the Company recorded impairments on its unproved properties totaling $66.4 million. The Company recorded no impairment provision attributable to unproved properties for the years ended December 31, 2007 and 2006.

Delta performed an annual DHS goodwill impairment test during the quarter ended September 30, 2008, however, due to the change in the market conditions and decreased rig utilization, the Company re-evaluated the DHS goodwill and rig fair values as of December 31, 2008. Delta determined that the book value of the rigs was impaired by $21.5 million. As a result of the analysis performed at year-end, Delta also wrote off the entire carrying value of DHS’s goodwill of $7.7 million.

RESULTS FOR THE FOURTH QUARTER 2008

For the quarter ended December 31, 2008, the Company reported total production of 6.8 Bcfe, which was within the range of previously stated guidance. Revenue from oil and gas sales decreased 12% to $34.5 million, versus $39.1 million in the prior-year quarter. Revenue from contract drilling and trucking fees increased 61% to $19.1 million, versus $11.9 million in the fourth quarter of 2007, due to the decreased average number of rigs working for Delta (three rigs at December 31, 2008 compared to eight rigs at December 31, 2007). Drilling revenues earned on wells drilled for Delta have been eliminated in consolidation. EBITDAX increased 64% to $43.8 million during the quarter ended December 31, 2008, compared with $26.8 million in the quarter ended December 31, 2007. Discretionary cash flow increased 28% to $29.5 million, versus $23.1 million in the comparable 2007 quarter. (Note: EBITDAX and Discretionary Cash Flow are non-GAAP measures that are described in greater detail below.)

For the quarter ended December 31, 2008, the Company reported a net loss of ($459.7) million, or ($4.56) per diluted share, compared with a net loss of ($28.5 million), or ($0.44) per share, in the year-earlier quarter. The current period results include $327.1 million of impairments recorded due primarily to the significant decline in commodity prices and $100.9 million of dry hole costs.

FOURTH QUARTER 2008 PRODUCTION VOLUMES, UNIT PRICES AND COSTS

Production volumes, average prices received and cost per equivalent thousand cubic feet (Mcf) for the three months ended December 31, 2008 and 2007 were as follows:


	Three Months Ended December 31,
	2008		2007
Production – Continuing Operations:
Oil (MBbl)		233		267
Gas (Mmcf)		5,417		3,424
Total Production (Mmcfe)		6,817		5,028

Average Price – Continuing Operations:
Oil (per barrel)	$	49.62	$	81.66
Gas (per Mcf)	$	4.22	$	4.99

Costs per Mcfe – Continuing Operations:
Lease operating expense	$	1.29	$	1.23
Production taxes	$	.06	$	.51
Transportation costs	$	.51	$	.25
Depletion expense	$	3.06	$	4.01

Lease Operating Expense. Lease operating expenses for the quarter ended December 31, 2008 were $8.8 million compared to $6.2 million for the year earlier period. Lease operating expense from continuing operations for the quarter ended December 31, 2008 increased proportionately with production. The average lease operating expense per Mcfe was $1.29 per Mcfe as compared to $1.23 per Mcfe for the year earlier period.

Exploration Expense. Exploration expense consists of geological and geophysical costs and lease rentals. Delta’s exploration costs for the quarter ended December 31, 2008 were $5.2 million compared to $2.9 million for the year earlier period. Exploration activities in 2008 primarily included seismic shoots in two areas with possible future drilling opportunities.

Depreciation, Depletion and Amortization – oil and gas. Depreciation, depletion and amortization expense increased 5% to $21.7 million for the quarter ended December 31, 2008, as compared to $20.7 million for the year earlier period. Depletion expense for the quarter ended December 31, 2008 was $20.9 million compared to $20.2 million for the quarter ended December 31, 2007. The 3% increase in depletion expense was due to a 36% increase in production from continuing operations, slightly offset by a 24% decrease in the depletion rate. The depletion rate decreased to $3.06 per Mcfe for the quarter ended December 31, 2008 from $4.01 per Mcfe for the year earlier period. The decrease is partially due to lower finding costs per Mcfe on the extensive 2008 Rockies drilling program and impairments recorded in 2008.

RESULTS FOR THE FULL YEAR 2008

For the year ended December 31, 2008, the Company reported total production of 24.9 Bcfe, which was an increase of 40% over the previous year and within the lower range of previously stated guidance. For the year ended December 31 2008, oil and gas sales from continuing operations increased 79% to $221.7 million, compared with $123.7 million in the comparable period a year earlier. The increase resulted from a 48% growth in production from continuing operations, a 33% increase in the average natural gas price received and a 37% increase in the average oil price received. The production increase was almost exclusively the result of Piceance Basin drilling. Drilling and trucking revenue decreased 15% to $49.4 million, from $58.4 million in the prior-year period, due to the increase in the number of average rigs operating for Delta and an increase in DHS Drilling Company revenues from Delta which are eliminated in consolidation. EBITDAX increased 86% and totaled $156 million for the year of 2008, compared with $83.8 million for the year of 2007. Discretionary cash flow increased 89% to $142.4 million for the year ended December 31, 2008, versus $75.2 million for the previous year.

For the year ended December 31, 2008, the Company reported a net loss of ($452) million, or ($4.73) per diluted share, compared with a net loss of ($147.2 million), or ($2.40) per diluted share, for the year ended December 31, 2007. Results for the year ended December 31, 2008 included dry hole costs of $111.9 million

compared to $28.1 million for the comparable period a year ago. Dry hole costs are related primarily to Greentown and Hingeline exploratory projects in Utah. During the year ended December 31, 2008, Delta recorded impairments totaling approximately $327.1 million, primarily related to the Newton Field, Midway Loop, Opossum Hollow and Angleton fields in Texas ($191.3 million), Greentown Field in Utah ($29.2 million), various fields in the Rockies ($31.9 million), Utah Hingeline ($40.2 million), Offshore California ($9.8 million) and a portion of the cost of the Paradox pipeline ($21.5 million). The impairments were primarily the result of the significant decline in commodity pricing during the fourth quarter of 2008.

FULL YEAR 2008 PRODUCTION VOLUMES, UNIT PRICES AND COSTS

Production volumes, average prices received and cost per equivalent thousand cubic feet (Mcf) for the year ended December 31, 2008 and 2007 were as follows:


	Years Ended December 31,
	2008		2007
Production — Continuing Operations:
Oil (MBbl)		993		1,003
Gas (Mmcf)		18,948		10,866
Production — Discontinued Operations:
Oil (MBbl)		—		82
Gas (Mmcf)		—		387

Total Production (Mmcfe)		24,908		17,763

Average Price — Continuing Operations:
Oil (per barrel)	$	92.12	$	67.39
Gas (per Mcf)	$	6.87	$	5.17

Costs per Mcfe — Continuing Operations:
Lease operating expense	$	1.35	$	1.24
Production taxes	$	.48	$	.44
Transportation costs	$	.46	$	.24
Depletion expense	$	3.87	$	4.26

Lease Operating Expense. Lease operating expenses for the year ended December 31, 2008 were $33.5 million compared to $20.9 million for the year earlier period. Lease operating expense from continuing operations for the year ended December 31, 2008 increased proportionately with production. The average lease operating expense per Mcfe was $1.35 per Mcfe as compared to $1.24 per Mcfe for the year earlier period.

Exploration Expense. Exploration expense consists of geological and geophysical costs and lease rentals. Delta’s exploration costs for the year ended December 31, 2008 were $11 million compared to $9.1 million for the year earlier period. Exploration activities in 2008 primarily included seismic shoots in two areas with possible future drilling opportunities.

Depreciation, Depletion and Amortization — oil and gas. Depreciation, depletion and amortization expense increased 34% to $99.1 million for the year ended December 31, 2008, as compared to $73.9 million for the year earlier period. Depletion expense for the year ended December 31, 2008 was $96.5 million compared to $71.9 million for the year ended December 31, 2007. The 34% increase in depletion expense was due to a 48% increase in production from continuing operations, slightly offset by a 9% decrease in the depletion rate. The depletion rate decreased to $3.87 per Mcfe for the year ended December 31, 2008 from $4.26 per Mcfe for the year earlier period. The decrease is partially due to lower finding costs per Mcfe on the extensive 2008 Rockies drilling program and impairments recorded in 2008.

2009 CAPITAL EXPENDITURES AND PRODUCTION GUIDANCE

As previously stated, the Company plans 2009 drilling capital expenditures to be within the Company’s operating cash flow and proceeds from capital raising transactions. Therefore 2009 drilling capital expenditures are expected to approximate $52 million, which may be reduced further depending upon fluctuations in oil and natural gas prices. The revised budget is primarily allocated to completion activities in the Piceance Basin and the remaining cost of drilling and testing of the Gray well in the Columbia River Basin. With operational control over its asset base, no significant drilling obligations and minimal leasehold expirations, the Company will be able to maintain ownership of its core assets.

Forecasted full year 2009 production is expected to be relatively flat to 2008 levels. The Company currently has no production hedged for 2009, but it expects to hedge 40% of current production for the second half of 2009 and additional amounts in 2010 and beyond in accordance with the requirements of the Amendment.

CHANGES IN DELTA’S BOARD OF DIRECTORS

The Company has announced that one of the members of its board of directors, Neal A. Stanley, has decided to resign from the board of Delta Petroleum to pursue other oil and gas interests. Mr. Stanley offered his resignation without any conflict or disagreement with the Company’s direction or management. Mr. Parker commented, “Neal has been a very valuable contributor to the Company’s board for the past four years. His experience of over 30 years in the industry has been a tremendous asset to our board and management team. His insight and perspective will be missed.” Mr. Stanley’s resignation was effective February 28, 2009.

The Company has also been informed that its largest shareholder, Tracinda Corporation, will be nominating two additional board members for election at the Company’s upcoming annual shareholder meeting. Tracinda has the right to board membership proportionate to its ownership in the Company, which is approximately 40%.

EARNINGS RELEASE AND INVESTOR CONFERENCE CALL

The Company will host an investor conference call, Tuesday, March 3, 2009 at 12:00 noon EST to discuss operating results for the fourth quarter and full year 2008.

Shareholders and other interested parties may participate in the conference call by dialing 1-800-860-2442 (international callers dial 1-412-858-4600) and asking to be connected to the “Delta Petroleum Conference Call” a few minutes before 12:00 noon Eastern time on March 3, 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 March 3, 2009 until March 11, 2009 by dialing 1-877-344-7529 (international callers dial 1-412-317-0088) and entering the conference ID 427964.

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 contraction in 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, 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 disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. 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 or RJ Falkner & Company, Inc., Investor Relations Counsel, at (800) 377-9893 or via email at info@rjfalkner.com

SOURCE: Delta Petroleum Corporation

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)


	December 31,			December 31,
	2008			2007
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	65,475		$	9,793
Short-term restricted deposit		100,000			—
Trade accounts receivable, net of allowance for doubtful accounts, of $652 and $664, respectively		30,437			38,761
Deposits and prepaid assets		11,253			3,943
Inventories		9,140			4,236
Derivative instruments		—			2,930
Deferred tax assets		231			150
Assets held for sale		—			63,749
Other current assets		6,360			10,214

Total current assets		222,896			133,776

Property and equipment:
Oil and gas properties, successful efforts method of accounting:
Unproved		415,573			247,466
Proved		1,365,440			749,393
Drilling and trucking equipment		194,223			146,097
Pipeline and gathering systems		86,076			25,264
Other		29,107			15,945

Total property and equipment		2,090,419			1,184,165
Less accumulated depreciation and depletion		(658,279	)		(245,153	)

Net property and equipment		1,432,140			939,012


Long-term assets:
Long-term restricted deposit		200,000			—
Marketable securities		1,977			6,566
Investments in unconsolidated affiliates		17,989			10,281
Deferred financing costs		7,952			7,187
Goodwill		—			7,747
Other long-term assets		12,460			6,075

Total long-term assets		240,378			37,856


Total assets	$	1,895,414		$	1,110,644


LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Credit facility — Delta	$	294,475		$	—
Installments payable on property acquisition		97,453			—
Accounts payable		159,024			119,783
Other accrued liabilities		13,576			17,118
Derivative instruments		—			6,295

Total current liabilities		564,528			143,196

Long-term liabilities:
Installments payable on property acquisition, net of current portion		188,334			—
7% Senior notes		149,534			149,459
3³/4% Senior convertible notes		115,000			115,000
Credit facility — Delta		—			73,600
Credit facility — DHS		93,848			75,000
Asset retirement obligations		6,585			4,154
Deferred tax liabilities		1,024			9,085

Total long-term liabilities		554,325			426,298

Minority interest		29,104			27,296

Commitments and contingencies

Stockholders’ equity:
Preferred stock, $.01 par value; authorized 3,000,000 shares, none issued		—			—
Common stock, $.01 par value; authorized 300,000,000 shares, issued 103,424,000 shares at December 31, 2008, and 66,429,000 shares at December 31, 2007		1,034			664
Additional paid-in capital		1,350,502			664,733
Treasury stock at cost; 36,000 shares at December 31, 2008 and none at December 31, 2007		(540	)		—
Accumulated deficit		(603,539	)		(151,543	)

Total stockholders’ equity		747,457			513,854


Total liabilities and stockholders’ equity	$	1,895,414		$	1,110,644

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


	Three Months Ended						Year Ended
	December 31,						December 31,
	2008			2007			2008			2007
	(In thousands, except per share amounts)
Revenue:
Oil and gas sales	$	34,453		$	39,060		$	221,733		$	123,729
Contract drilling and trucking fees		19,090			11,890			49,445			58,358
Gain on hedging instruments, net		—			3,099			—			12,854


Total revenue		53,543			54,049			271,178			194,941


Operating expenses:
Lease operating expense		8,786			6,191			33,508			20,882
Transportation expense		3,493			1,259			11,395			4,074
Production taxes		409			2,553			12,075			7,463
Exploration expense		5,170			2,924			10,975			9,062
Dry hole costs and impairments		428,046			12,475			438,963			87,459
Depreciation, depletion, amortization and accretion – oil and gas		21,734			20,655			99,125			73,875
Drilling and trucking operating expenses		11,997			7,479			32,594			37,698
Goodwill and drilling equipment impairments		29,349			—			29,349			—
Depreciation and amortization – drilling and trucking		4,561			3,177			14,134			16,021
General and administrative expense		11,468			12,332			53,607			49,621


Total operating expenses		525,013			69,045			735,725			306,155


Operating loss		(471,470	)		(14,996	)		(464,457	)		(111,214	)


Other income and (expense):
Interest expense and financing costs		(14,239	)		(9,169	)		(41,421	)		(29,279	)
Interest income		1,732			25			10,132			2,080
Other income (expense)		(1,584	)		(245	)		(5,210	)		376
Realized gain on derivative instruments, net		16,328			129			18,383			917
Unrealized gain (loss) on derivative instruments, net		(10,209	)		(6,298	)		3,365			(3,819	)
Minority interest in losses (income) of subsidiary		11,131			1,242			11,486			1,231
Income (loss) from unconsolidated affiliates		562			(342	)		3,375			(393	)


Total other income (expense), net		3,721			(14,658	)		110			(28,887	)

Loss from continuing operations before income taxes and discontinued operations		(467,749	)		(29,654	)		(464,437	)		(140,101	)

Income tax expense (benefit)		(8,091	)		(1,175	)		(11,723	)		5,010


Loss from continuing operations		(459,658	)		(28,479	)		(452,714	)		(145,111	)

Discontinued operations:
Income (loss) from discontinued operations of properties sold or held for sale, net of tax		—			(233	)		—			1,922
Gain (loss) on sale of discontinued operations, net of tax		(1	)		231			718			(3,998	)


Net loss	$	(459,659	)	$	(28,481	)	$	(451,996	)	$	(147,187	)


Basic income (loss) per common share:
Income (loss) from continuing operations	$	(4.56	)	$	(0.44	)	$	(4.74	)	$	(2.37	)
Discontinued operations		—			—			0.01			(0.03	)

Net income (loss)	$	(4.56	)	$	(0.44	)	$	(4.73	)	$	(2.40	)


Diluted income (loss) per common share:
Income (loss) from continuing operations	$	(4.56	)	$	(0.44	)	$	(4.74	)	$	(2.37	)
Discontinued operations		—			—			0.01			(0.03	)

Net income (loss)	$	(4.56	)	$	(0.44	)	$	(4.73	)	$	(2.40	)


Weighted average common shares outstanding:
Basic		100,865			64,930			95,530			61,297
Diluted		100,865			64,930			95,530			61,297

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

(In thousands)


	December 31,			December 31,
THREE MONTHS ENDED:	2008			2007
CASH PROVIDED BY OPERATING ACTIVITIES	$	63,820		$	43,745

Changes in assets and liabilities		(39,525	)		(23,574	)
Exploration expense		5,170			2,924

Discretionary Cash Flow*	$	29,465		$	23,095


	December 31,			December 31,
YEAR ENDED:	2008			2007
CASH PROVIDED BY OPERATING ACTIVITIES	$	140,676		$	87,003

Changes in assets and liabilities		(9,205	)		(20,867	)
Exploration expense		10,975			9,062

Discretionary Cash Flow*	$	142,446		$	75,198


*		Discretionary cash flow represents net cash provided by operating activities before changes in assets and liabilities 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.


	December 31,			December 31,
THREE MONTHS ENDED:	2008			2007
Net loss	$	(459,659	)	$	(28,481	)

Income tax benefit		(8,091	)		(1,744	)
Interest income		(1,732	)		(25	)
Interest and financing costs		14,239			9,169
Depletion, depreciation and amortization		26,295			23,839
Loss on sale of oil and gas properties and other investments		—			334
Unrealized loss on derivative contracts		10,209			8,295
Exploration, dry hole costs and impairments		462,565			15,399

EBITDAX**	$	43,826		$	26,786


	December 31,			December 31,
THREE MONTHS ENDED:	2008			2007
CASH PROVIDED BY OPERATING ACTIVITIES	$	63,820		$	43,745

Changes in assets and liabilities		(39,525	)		(23,574	)
Interest net of financing costs		8,376			6,835
Exploration costs		5,170			2,924
Other non-cash items		5,985			(3,144	)

EBITDAX**	$	43,826		$	26,786


	December 31,			December 31,
YEAR ENDED:	2008			2007
Net loss	$	(451,996	)	$	(147,187	)

Income tax expense (benefit)		(11,723	)		6,446
Interest income		(10,132	)		(2,080	)
Interest and financing costs		41,421			29,279
Depletion, depreciation and amortization		113,259			92,384
(Gain) loss on sale of oil and gas properties and other investments		(718	)		2,644
Unrealized loss (gain) on derivative contracts		(3,365	)		5,816
Exploration, dry hole costs and impairments		479,287			96,521

EBITDAX**	$	156,033		$	83,823


	December 31,			December 31,
YEAR ENDED:	2008			2007
CASH PROVIDED BY OPERATING ACTIVITIES	$	140,676		$	87,003

Changes in assets and liabilities		(9,205	)		(20,867	)
Interest net of financing costs		19,959			22,770
Exploration costs		10,975			10,055
Other non-cash items		(6,372	)		(15,138	)

EBITDAX**	$	156,033		$	83,823


**		EBITDAX represents net income before income tax expense (benefit), interest and financing costs, depreciation, depletion and amortization expense, gain on sale of oil and gas properties 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 operating activities prepared in accordance with GAAP.

ABBREVIATIONS


Bo/d		barrels of oil per day
Lbs/gal		pounds per gallon
Mcf		thousand cubic feet
MBbl		thousand barrels of oil
Mmcf		million cubic feet
Mmcfe		million cubic feet equivalent
Mmcfe/d		million cubic feet equivalent per day
Bcfe		billion cubic feet equivalent
Mmbtu		million British Thermal Units
WTI		West Texas Intermediate
NYMEX		New York Mercantile Exchange
LIBOR		London Interbank Offered Rate

TERMS


Capital Expenditures		Includes capitalized administrative expenses and capitalized interest but does no include proceeds or other assets

Cash Flow from Operations		Earnings from operations plus non-cash charges before settlement of asset retirement obligations and change in non-cash working capital

Drillbit F&D costs per Mcfe		Costs incurred excluding acquisitions divided by the summation of annual proved reserves on a Mcfe basis, attributable to revisions of previous estimates, and discoveries and extensions. Consistent with industry practice, future capital costs to develop proved undeveloped reserves are not included in costs incurred.

Equity		Shares, retained earnings and accumulated other comprehensive income

All-in F&D costs per Mcfe		Total costs incurred divided by the summation of annual proved reserves, on a Mcfe basis, attributable to revisions of previous estimates, purchases of minerals-in-place and discoveries and extensions. Consistent with industry practice, future capital costs to develop proved undeveloped reserves are not included in costs incurred.

Total Debt		Long-term debt including current portion and bank operating loans


DELAWARE	0-16203	84-1060803
(State or other jurisdiction of incorporation or organization)	(Commission File Number)	(I.R.S. Employer Identification Number)


Exhibit
No.		Description
99.1		Delta Petroleum Corporation Press Release, dated March 2, 2009.


	Delta Petroleum Corporation
	By:	/s/ Stanley F. Freedman
		Stanley F. Freedman
		Executive Vice President and Secretary


Exhibit
No.		Description
99.1		Delta Petroleum Corporation Press Release, dated March 2, 2009.