e8vk

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 2009 ANNUAL AND FOURTH QUARTER RESULTS

DENVER, Colorado (March 11, 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 fourth quarter and full year 2009.

John Wallace, Delta’s President and COO stated, “We are pleased to report our financial results for the full year 2009 and for the fourth quarter of 2009. Clearly, 2009 proved to be a very challenging year for Delta beginning with the drop in natural gas prices during the first half of the year, and further compounded by liquidity and bank covenant concerns for much of the year. Yet, I am very pleased with how far we have come and, from an operational and liquidity perspective, how much we improved during the latter half of the year. Cash flow provided by operating activities totaled $61.0 million for the fourth quarter, which is up meaningfully over the third quarter. The fourth quarter of 2009 was the third consecutive quarter of substantial growth in EBITDAX (a non-GAAP measure), up 134% from third quarter levels. We have also been able to reduce our lease operating expenses to $1.26 per Mcfe for the fourth quarter, down 14% from the third quarter 2009. More importantly, the EBITDAX for the fourth quarter is sufficient to be in compliance with the leverage ratio covenant of our senior credit facility. While we obtained waivers for the first quarter of 2010, under the current commodity price forward curve, our current financial projections suggest that we will be in compliance with our financial covenants for the remainder of 2010.

“Our liquidity situation has also improved materially, aided in no small part by the offshore litigation settlement proceeds received from the federal government at the end of the year, which netted approximately $48.7 million to Delta. While the proceeds are shown as cash on the December 31, 2009 balance sheet, subsequent to year-end, the proceeds of the settlement were used to reduce borrowings under our senior credit facility. With borrowing base availability and cash on hand, our liquidity position at December 31, 2009 was $102 million and is approximately $84 million as of today. Once the semi-annual borrowing base redetermination and the strategic alternatives process are completed we will announce our plans to recommence our drilling program in the Vega Area.

“Regarding our proved reserves for year-end 2009, the base price used for the calculation was $3.03 per MMBtu for natural gas (the average of the first day of the month prices in 2009 for Colorado Interstate Gas), which resulted in proved reserves of 154 Bcfe. If we calculated our proved reserves based upon year-end CIG pricing of $5.54 per MMBtu for natural gas in accordance with the SEC’s former reserve reporting rules, our year-end proved reserves would have been approximately 830 Bcfe.

“Given how challenging our situation was, I can’t help but be proud of how far we’ve come and where we stand today.”

STRATEGIC ALTERNATIVES UPDATE

As previously announced on November 30, 2009, Delta retained Morgan Stanley and Evercore Partners to evaluate and advise the Board of Directors on strategic alternatives to enhance shareholder value. The process is in its advanced stages and the Company does not expect to make further public comment regarding the process until the Board of Directors has approved a specific transaction or otherwise determines that disclosure of significant developments, if any, is appropriate.

2009 YEAR-END RESERVES

For the year-ended December 31, 2009, Delta reported total estimated proved reserves of 154 billion cubic feet equivalents (Bcfe), compared to 884 Bcfe at December 31, 2008. Estimated proved reserves were 82% natural gas and 87% proved developed, with an after-tax PV-10 value of $156.7 million. Approximately 73% of proved reserves were located in the Rocky Mountains, 26% in the Gulf Coast and less than 1% in other locations. The reserves were prepared by an independent third party engineering firm.

Prices used to calculate the Company’s estimated proved reserves reflect the pricing methodology required to be employed under the SEC’s new reserve reporting rules which uses the trailing 12-month average of the first of the month price, or $3.03 per MMBtu priced at Colorado Interstate Gas (CIG) and $61.18 per barrel of West Texas Intermediate (WTI) oil for 2009.

Using the pricing methodology that applied under the old SEC reporting rules, total estimated proved reserves would have been 830 Bcfe, based on a single day year-end CIG price of $5.54 per MMBtu of natural gas and a WTI price of $79.36 per barrel of oil. The application of the new rules and their associated use of lower 12-month average prices in the calculation of reserves at December 31, 2009 resulted in a reduction in reported proved reserves of 677 Bcfe.

Drilling and completion capital expenditures for the full year 2009 totaled $59.3 million. Total costs incurred in oil and gas operations during 2009, including acquisition, leasehold, drilling, completion, dry hole costs, seismic, asset retirement obligations and all other capitalized oil and gas related costs, approximated $97.7 million.


	Total
	(MMcfe)
Estimated Proved Reserves: Balance at December 31, 2008		884,395

Revisions of quantity estimate		(725,536	)
Extensions and discoveries		20,381
Purchase of properties		—
Sale of properties		(3,499	)
Production		(22,156	)


Estimated Proved Reserves: Balance at December 31, 2009		153,585


Proved developed reserves:
December 31, 2008		181,196
December 31, 2009		132,866

Future net cash flows presented below are computed using year-end prices and costs and are net of all overriding royalty revenue interests.

Future corporate overhead expenses and interest expense have not been included.


	2009
Future net cash flows	$	662,029
Future costs:
Production		125,108
Development and abandonment		77,965
Income taxes*		—

Future net cash flows		458,956
10% discount factor		(302,272	)

Standardized measure of discounted future net cash flows	$	156,684

Estimated future development cost anticipated for following two years on existing properties	$	59,313


*		No income tax provision is included in the standardized measure calculation shown above as the Company does not project to be taxable or pay cash income taxes based on its available tax assets and additional tax assets generated in the development of its reserves because the tax basis of its oil and properties and NOL carryforwards exceeds the amount of discounted future net earnings.

The principal sources of changes in the standardized measure of discounted net cash flows during the year-ended December 31, 2009 is as follows (in thousands):


Beginning of the year	$	159,368
Sales of oil and gas production during the period, net of production costs		(48,195	)
Purchase of reserves in place		—
Net change in prices and production costs		(64,282	)
Changes in estimated future development costs		741,318
Extensions, discoveries and improved recovery		17,509
Revisions of previous quantity estimates, estimated timing of development and other		(674,560	)
Previously estimated development and abandonment costs incurred during the period		15,556
Sales of reserves in place		(5,967	)
Change in future income tax		—
Accretion of discount		15,937

End of year	$	156,684

LIQUIDITY UPDATE

At December 31, 2009, the Company had $61.9 million in cash and approximately $41 million available under its credit facility (based on the borrowing base as re-determined on October 30, 2009). On May 13, 2009, Delta completed an underwritten public offering of 172.5 million shares of common stock at $1.50 per share for net proceeds of $246.9 million, net of underwriting commissions and related offering expenses. On May 19, 2009, the Company received from the U.S. government approximately $47.0 million in net offshore litigation proceeds related to the Amber Case and on December 29, 2009 received an additional $48.7 million in net proceeds related to the offshore California lease 452 litigation. With proceeds from these transactions, Delta reduced its borrowings outstanding under the credit facility from $294.5 million at December 31, 2008 to $124.0 million at December 31, 2009, with $39.8 million of remaining availability based on the current $185.0 million borrowing base with a required minimum availability of $20.0 million and outstanding letters of credit totaling $1.2 million. The semi-annual scheduled borrowing base redetermination is currently in process, and the borrowing base could change depending on the lending banks’ commodity price forecasts as well as changes in

their calculations of Delta’s producing reserve base. In addition, the Company reduced its accounts payable from $159.0 million at December 31, 2008 to $44.2 million at December 31, 2009.

The Company was in compliance with the capital expenditure and accounts payables covenants under its credit facility at December 31, 2009, and was also in compliance with the financial ratio covenants contained therein (although they had previously been waived for December 31, 2009 and March 31, 2010 in conjunction with the Second Amendment in October 2009). Although waivers were obtained for its financial ratio covenants for the quarter ending March 31, 2010, the Company anticipates being in compliance with its financial ratio covenants.

DHS remained out of compliance with the debt covenants under its credit facility and its forbearance agreement with LCPI expired on June 15, 2009. As a result, amounts outstanding under the DHS credit facility are classified as a current liability in the accompanying consolidated balance sheet as of December 31, 2009. DHS continues discussions with its credit facility lender regarding amendments, waivers or other restructuring of the credit facility, but there can be no assurance that the lender will agree to any such amendments.

RESULTS FOR THE FOURTH QUARTER 2009

For the quarter ended December 31, 2009, the Company reported production of 5.0 Bcfe, a decrease of 27% when compared with the fourth quarter of 2008. Total revenue increased 44% to $76.9 million in the quarter, versus revenue of $53.5 million in the quarter ended December 31, 2008, primarily, due to the gain on offshore litigation settlement. Revenue from oil and gas sales declined 13% to $29.9 million, compared with $34.5 million in the prior year quarter. The decrease was due to a 27% decrease in production partially offset by a 10% increase in the average gas price and a 38% increase in the average oil price. The average oil price received during the three months ended December 31, 2009 increased to $68.24 per barrel compared to $49.62 per barrel for the year earlier period. The average natural gas price received during the three months ended December 31, 2009 increased to $4.63 per thousand cubic feet (Mcf) compared to $4.22 per Mcf for the year earlier period. Revenue from contract drilling and trucking fees decreased 78% to $4.3 million in the current quarter, versus $19.1 million in the fourth quarter of 2008.

The Company reported a fourth quarter net loss attributable to Delta common stockholders of ($34.1 million), or ($0.12) per diluted share, compared with net loss attributable to Delta common stockholders of ($460.7 million), or ($4.55) per diluted share, in the fourth quarter of 2008. The decreased loss was primarily due to fewer dry holes and impairments recorded in 2009 as compared to 2008, and offshore litigation gains offset by lower oil and gas sales in 2009.

FOURTH QUARTER 2009 PRODUCTION VOLUMES, UNIT PRICES AND COSTS

Production volumes, average prices received and cost per equivalent Mcf for the three months ended December 31, 2009 and 2008 were as follows:


	Three Months Ended December 31,
	2009		2008
Production – Continuing Operations:
Oil (MBbl)		167		233
Gas (MMcf)		4,000		5,417

Total Production (MMcfe)		5,003		6,817

Average Price – Continuing Operations:
Oil (per barrel)	$	68.24	$	49.62
Gas (per Mcf)	$	4.63	$	4.22

Costs per Mcfe – Continuing Operations:
Lease operating expense	$	1.26	$	1.29
Production taxes	$	0.02	$	0.06
Transportation costs	$	0.75	$	0.51
Depletion expense	$	5.03	$	3.06

Lease Operating Expense. Lease operating expenses for the quarter ended December 31, 2009 were $6.3 million compared to $8.8 million for the year earlier period. The average lease operating expense per Mcfe was $1.26 per Mcfe as compared to $1.29 per Mcfe for the year earlier period.

Transportation Costs. Transportation costs increased 8% to $3.8 million for the quarter ended December 31, 2009, as compared to $3.5 million for the year earlier period and 47% on a per Mcfe basis. This increase is due to a new marketing arrangement for the majority of the operated Piceance Basin gas in the Vega area. Although the Company’s new marketing agreement results in higher transportation costs, this increase is more than offset by higher revenues from improved natural gas liquids recoveries at the higher efficiency plant and a greater percentage of natural gas liquids retained. As a result of these changes, based on current oil, gas and NGL prices, the net profitability has improved substantially.

Depreciation, Depletion and Amortization – oil and gas. Depreciation, depletion and amortization expense increased 20% to $26.0 million for the quarter ended December 31, 2009, as compared to $21.7 million for the year earlier period. Depletion expense for the quarter ended December 31, 2009 was $25.2 million compared to $20.9 million for the quarter ended December 31, 2008. The depletion rate increased to $5.03 per Mcfe for the quarter ended December 31, 2009 from $3.06 per Mcfe for the year earlier period.

RESULTS FOR THE FULL YEAR 2009

For the year-ended December 31, 2009, the Company reported total production of 22.2 Bcfe, which was a decrease of 11% from the previous year, but exceeded the previously stated guidance given for 2009. For the year-ended December 31 2009, oil and gas sales from continuing operations decreased 57% to $95.0 million, compared with $221.7 million in the comparable period a year earlier. The decrease resulted from a 54% decrease in the average gas price and a 43% decrease in the average oil price, in addition to an 11% decrease in total production. Drilling and trucking revenue decreased 72% to $13.7 million, from $49.4 million in the prior-year period, due to the decrease in the number of rigs operating during the year.

For the year-ended December 31, 2009, the Company reported a net loss of ($328.8) million, or ($1.56) per diluted share, compared with a net loss of ($456.1 million), or ($4.77) per diluted share, for the year-ended December 31, 2008.

FULL YEAR 2009 PRODUCTION VOLUMES, UNIT PRICES AND COSTS

Production volumes, average prices received and cost per equivalent Mcf for the years ended December 31, 2009 and 2008 are as follows:


	Years Ended December 31,
	2009		2008
Production – Continuing Operations:
Oil (MBbl)		761		993
Gas (MMcf)		17,590		18,948

Total Production (MMcfe)		22,156		24,908

Average Price – Continuing Operations:
Oil (per barrel)	$	52.37	$	92.12
Gas (per Mcf)	$	3.13	$	6.87

Costs per Mcfe – Continuing Operations:
Lease operating expense	$	1.41	$	1.35
Production taxes	$	0.17	$	0.48
Transportation costs	$	0.52	$	0.46
Depletion expense	$	4.76	$	3.87

Lease Operating Expense. Lease operating expenses for the year-ended December 31, 2009 were $31.3 million compared to $33.5 million for the year earlier period. Lease operating expense from continuing operations for the year-ended December 31, 2009 remained relatively flat from the year earlier period. However, lease operating expenses increased on a per unit basis primarily due to declining production. The average lease operating expense was $1.41 per Mcfe in 2009 as compared to $1.35 per Mcfe for the year earlier period.

Depreciation, Depletion and Amortization – oil and gas. Depreciation, depletion and amortization expense increased 9% to $108.5 million for the year-ended December 31, 2009, as compared to $99.1 million for the year earlier period. Depletion expense for the year-ended December 31, 2009 was $105.4 million compared to $96.5 million for the year-ended December 31, 2008. The 9% increase in depletion expense was primarily due to a 23% increase in the depletion rate. The depletion rate increased to $4.76 per Mcfe for the year-ended December 31, 2009 from $3.87 per Mcfe for the year earlier period. The increase is primarily due to the effect of low Rockies gas prices throughout most of 2009 and low 12-month average historical prices at December 31, 2009 on the reserves used in the depletion calculation. Based on current commodity prices, the Company expects its depletion rate to decline in 2010 due to additional Rockies proved undeveloped reserves that can be recorded at higher prices.

General and Administrative Expense. General and administrative expense decreased 23% to $41.4 million for the year-ended December 31, 2009, as compared to $53.6 million for the comparable prior year period. The decrease in general and administrative expenses is primarily attributed to lower expenses incurred on employee benefits and wages from reductions in force during 2009 and a decrease in non-cash stock compensation expense. We would expect further reductions to full year cash general and administrative expenses in 2010 as changes implemented in 2009 take full effect.

ADDITIONAL FINANCIAL INFORMATION

The following table summarizes the Company’s open derivative contracts at December 31, 2009, required pursuant to the Company’s credit agreement:

Commodity

Volume

Fixed Price

Term

Index Price

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

6,000

MMBtu / Day

5.720

Jan ’10

- Dec ’10

NYMEX – HHUB

Natural gas

15,000

MMBtu / Day

4.105

Jan ’10

- Dec ’10

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 pre-credit risk adjusted fair value of the Company’s net derivative liabilities as of December 31, 2009 was $29.5 million. A credit risk adjustment of $2.5 million to the fair value of the derivatives reduced the reported amount of the net derivative liabilities on the Company’s consolidated balance sheet to $27.0 million.

OPERATIONS UPDATE

Piceance Basin, CO, 31% – 100% WI – Current production from the Piceance Basin approximates 27.4 million cubic feet equivalent per day (Mmcfe/d) net. During the fourth quarter 2009 the Company completed 4 wells from its drilled and uncompleted inventory in the Vega Area. The Company expects to complete the remaining 19 drilled and uncompleted wells in 2010. Additionally, the operator of Garden Gulch has a one rig drilling program ongoing. As mentioned previously, the Company’s liquidity position is sufficient to recommence continuous drilling activity in the Piceance Basin.

The Company’s new water treatment facility is under construction and is expected to be operational by the middle of the second quarter. Additionally, Delta has completed and commenced operations of its new compression facility that will allow for significant increased production volumes in the future.

2010 CAPITAL EXPENDITURES AND PRODUCTION GUIDANCE

Although Delta’s capital expenditure budget was reduced dramatically in 2009 due to significant declines in commodity prices and the availability of capital, the Company’s financial condition has improved and Rockies gas prices have recently begun to return to more attractive levels for additional development. The Company expects to announce its 2010 drilling plans and production guidance once the strategic alternatives evaluation process and borrowing base redetermination are complete.

INVESTOR CONFERENCE CALL

The Company will host an investor conference call, Thursday, March 11, 2010 at 12:00 noon EST to discuss operating results for the fourth quarter and full year 2009.

Shareholders and other interested parties may participate in the conference call by dialing 800-860-2442 (international callers dial 412-858-4600) and referencing the ID code “Delta Petroleum call,” a few minutes before 12:00 noon Eastern Time on March 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 March 11, 2010 until March 19, 2010 by dialing 877-344-7529 (international callers dial 412-317-0088) and entering the conference ID 438003.

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 outcome of our borrowing base redetermination, 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

SOURCE: Delta Petroleum Corporation

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)


	December 31,			December 31,
	2009			2008
	(In thousands, except share data)
ASSETS
Current assets:
Cash and cash equivalents	$	61,918		$	65,475
Short-term restricted deposits		100,000			100,000
Trade accounts receivable, net of allowance for doubtful accounts of $100 and $652, respectively		16,654			30,437
Deposits and prepaid assets		3,103			11,253
Inventories		5,588			9,140
Deferred tax assets		—			231
Other current assets		5,189			6,221

Total current assets		192,452			222,757

Property and equipment:
Oil and gas properties, successful efforts method of accounting:
Unproved		280,844			415,573
Proved		1,379,920			1,365,440
Drilling and trucking equipment		177,762			194,223
Pipeline and gathering systems		92,064			86,076
Other		16,154			29,107

Total property and equipment		1,946,744			2,090,419
Less accumulated depreciation and depletion		(800,501	)		(658,279	)

Net property and equipment		1,146,243			1,432,140

Long-term assets:
Long-term restricted deposit		100,000			200,000
Marketable securities		—			1,977
Investments in unconsolidated affiliates		7,444			17,989
Deferred financing costs		3,017			7,640
Other long-term assets		8,329			12,460

Total long-term assets		118,790			240,066


Total assets	$	1,457,485		$	1,894,963


LIABILITIES AND EQUITY
Current liabilities:
Credit facility – Delta	$	—		$	294,475
Credit facility – DHS		83,268			—
Installments payable on property acquisition		97,874			97,453
Accounts payable		44,225			159,024
Offshore litigation payable		13,877			—
Other accrued liabilities		13,459			13,576
Derivative instruments		19,497			—

Total current liabilities		272,200			564,528

Long-term liabilities:
Installments payable on property acquisition, net of current portion		95,381			188,334
7% Senior notes		149,609			149,534
3³/4% Senior convertible notes		104,008			99,616
Credit facility — Delta		124,038			—
Credit facility — DHS		—			93,848
Asset retirement obligations		7,654			6,585
Derivative instruments		7,475			—
Deferred tax liabilities		—			1,024

Total long-term liabilities		488,165			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 282,548,000 shares at December 31, 2009 and 103,424,000 shares at December 31, 2008		2,825			1,034
Additional paid-in capital		1,625,035			1,372,123
Treasury stock at cost; 42,000 shares at December 31, 2009 and 36,000 shares at December 31, 2008		(268	)		(540	)
Accumulated deficit		(939,010	)		(610,227	)

Total Delta stockholders’ equity		688,582			762,390

Non-controlling interest		8,538			29,104

Total equity		697,120			791,494


Total liabilities and equity	$	1,457,485		$	1,894,963

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


	Three Months Ended						Twelve Months Ended
	December 31,						December 31,
	2009			2008			2009			2008
	(In thousands, except per share amounts)
Revenue:
Oil and gas sales	$	29,921		$	34,453		$	94,962		$	221,733
Contract drilling and trucking fees		4,255			19,090			13,680			49,445
Gain on offshore litigation settlement, net of property sales		42,746			—			73,800			—


Total revenue		76,922			53,543			182,442			271,178


Operating expenses:
Lease operating expense		6,290			8,786			31,303			33,508
Transportation expense		3,763			3,493			11,612			11,395
Production taxes		91			409			3,852			12,075
Exploration expense		182			5,170			2,604			10,975
Dry hole costs and impairments		34,109			428,046			189,072			438,963
Depreciation, depletion, amortization and accretion — oil and gas		26,036			21,734			108,505			99,125
Drilling and trucking operating expenses		4,877			11,997			15,293			32,594
Goodwill and drilling equipment impairments		—			29,349			6,508			29,349
Depreciation and amortization — drilling and trucking		5,405			4,561			22,917			14,134
General and administrative expense		9,869			11,468			41,414			53,607
Executive severance expense, net		—			—			3,739			—

Total operating expenses		90,622			525,013			436,819			735,725


Operating Loss		(13,700	)		(471,470	)		(254,377	)		(464,547	)


Other income and (expense):
Interest expense and financing costs		(11,349	)		(15,273	)		(55,035	)		(45,489	)
Interest income		675			1,732			2,454			10,132
Other income (expense)		(580	)		(1,584	)		1,049			(5,210	)
Realized gain (loss) on derivative instruments, net		(1,485	)		16,328			(1,115	)		18,383
Unrealized gain (loss) on derivative instruments, net		62			(10,209	)		(26,972	)		3,365
Income (loss) from unconsolidated affiliates		(12,149	)		562			(15,473	)		3,375


Total other expense		(24,826	)		(8,444	)		(95,092	)		(15,444	)


Loss from continuing operations before income taxes and discontinued operations		(38,526	)		(479,914	)		(349,469	)		(479,991	)

Income tax expense (benefit)		268			(8,091	)		215			(11,723	)


Loss from continuing operations		(38,794	)		(471,823	)		(349,684	)		(468,268	)

Discontinued operations:

Gain (loss) on sale of discontinued operations, net of tax		—			(1	)		—			718


Net Loss		(38,794	)		(471,824	)		(349,684	)		(467,550	)

Less net loss attributable to non-controlling interest		4,710			11,131			20,901			11,486


Net loss attributable to Delta common stockholders	$	(34,084	)	$	(460,693	)	$	(328,783	)	$	(456,064	)


Amounts attributable to Delta common stockholders:
Loss from continuing operations	$	(34,084	)	$	(460,692	)	$	(328,783	)	$	(456,782	)
Income (loss) from discontinued operations, net of tax		—			(1	)		—			718

Net loss	$	(34,084	)	$	(460,693	)	$	(328,783	)	$	(456,064	)


Basic income (loss) attributable to Delta common stockholders per common share:
Loss from continuing operations	$	(0.12	)	$	(4.55	)	$	(1.56	)	$	(4.78	)
Discontinued operations		—			—			—			0.01

Net loss	$	(0.12	)	$	(4.55	)	$	(1.56	)	$	(4.77	)


Diluted income (loss) attributable to Delta common stockholders per common share:
Loss from continuing operations	$	(0.12	)	$	(4.55	)	$	(1.56	)	$	(4.78	)
Discontinued operations		—			—			—			0.01

Net loss	$	(0.12	)	$	(4.55	)	$	(1.56	)	$	(4.77	)


Weighted average common shares outstanding:
Basic		274,878			101,272			211,033			95,530
Diluted		274,878			101,272			211,033			95,530

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

(In thousands)


THREE MONTHS ENDED	December 31,			December 31,
	2009			2008
CASH PROVIDED BY OPERATING ACTIVITIES	$	60,985		$	47,358
Changes in assets and liabilities		(9,403	)		(16,879	)
Less net proceeds from offshore litigation award		(48,657	)		—
Exploration costs		182			5,170

Discretionary cash flow (deficiency)*	$	3,107		$	35,649


TWELVE MONTHS ENDED:	December 31,			December 31,
	2009			2008
CASH PROVIDED BY OPERATING ACTIVITIES	$	81,144		$	140,676
Changes in assets and liabilities		(10,516	)		(9,205	)
Less net proceeds from offshore litigation award		(97,358	)		—
Exploration costs		2,604			10,975

Discretionary cash flow (deficiency)*	$	(24,126	)	$	142,446


*		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.


THREE MONTHS ENDED	December 31,			December 31,
	2009			2008
Net income (loss)	$	(38,794	)	$	(471,824	)
Minority Interest		4,710			11,131
Income tax expense (benefit)		268			(8,091	)
Interest income		(675	)		(1,732	)
Interest and financing costs		11,349			15,273
Depletion, depreciation and amortization		31,441			26,295
Gain on offshore litigation award, sale of drilling rig and other		(42,238	)		1
Unrealized loss on derivative instruments		(62	)		10,209
Exploration, dry hole and impairment costs		45,322			462,562

EBITDAX**	$	11,321		$	43,824


THREE MONTHS ENDED	December 31,			December 31,
	2009			2008
CASH PROVIDED BY OPERATING ACTIVITIES	$	60,985		$	47,358
Changes in assets and liabilities		(9,403	)		(16,879	)
Net proceeds from offshore litigation award		(48,657	)		—
Less Interest net of financing costs		7,096			8,378
Exploration costs		182			(1,016	)
Impairment of unconsolidated affiliates		11,032			—
Other non-cash items		(9,914	)		5,983

EBITDAX**	$	11,321		$	43,824


TWELVE MONTHS ENDED	December 31,			December 31,
	2009			2008
Net income (loss)	$	(349,684	)	$	(467,550	)
Minority Interest		20,901			11,486
Income tax benefit		215			(11,723	)
Interest income		(2,454	)		(10,132	)
Interest and financing costs		55,035			45,489
Depletion, depreciation and amortization		131,422			113,259
Gain on offshore litigation award, sale of drilling rig and other		(74,955	)		(718	)
Unrealized loss on derivative instruments		26,972			(3,365	)
Exploration, dry hole and impairment costs		212,247			479,287

EBITDAX**	$	19,699		$	156,033


TWELVE MONTHS ENDED	December 31,			December 31,
	2009			2008
CASH PROVIDED BY OPERATING ACTIVITIES	$	81,144		$	140,676
Changes in assets and liabilities		(10,516	)		(9,205	)
Less net proceeds from offshore litigation award		(97,358	)		—
Interest net of financing costs		33,392			19,959
Exploration costs		2,604			10,975
Impairment of unconsolidated affiliates		14,063			—
Other non-cash items		(3,630	)		(6,372	)

EBITDAX**	$	19,699		$	156,033


**		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.


Exhibit
No.		Description
	99.1	Delta Petroleum Corporation Press Release, dated March 11, 2010.


	Delta Petroleum Corporation
	By:	/s/ Kevin K. Nanke
		Kevin K. Nanke
		Treasurer and Chief Financial Officer


Exhibit
No.		Description
	99.1	Delta Petroleum Corporation Press Release, dated March 11, 2010.


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