Exhibit 99.1

DELTA PETROLEUM CORPORATION
Daniel Taylor, Chairman
Carl Lakey, CEO
Kevin Nanke, Treasurer and CFO
Broc Richardson, V.P. Corporate Development and IR
370 17th Street, Suite 4300
Denver, Colorado 80202

For Immediate Release

DELTA PETROLEUM CORPORATION
ANNOUNCES 2010 ANNUAL AND FOURTH QUARTER RESULTS

     DENVER, Colorado (March 16, 2011) — Delta Petroleum Corporation (“Delta” or the “Company”) (NASDAQ Capital Market: DPTR), an independent oil and gas exploration and development company, today announced its financial and operating results for the fourth quarter and full year 2010.

     Carl Lakey, Delta’s President and CEO stated, “We are very pleased with our results for the fourth quarter. Our EBITDAX is 20% higher than the third quarter driven by lower operating and overhead costs, despite lower production related to asset sales and lower average Henry Hub gas prices in the quarter. We have been committed to reducing our operating and overhead costs, and I’m pleased to state that we have been able to deliver such results. We drove our LOE/Mcfe down by 38% compared to the third quarter. Additionally, our overhead costs are down 25% from the third quarter. We remain focused on sustaining costs at or near these levels for 2011. We’ve also had very positive results from the well completion activity performed in the fourth quarter and to date in the first quarter of this year. The larger frac design, which we call Gen IV, has increased our initial production and our estimated reserves per well. We have completed a total of 16 wells with the Gen IV frac design and all have performed better than we would have expected under prior completion designs. Thus, we expect first quarter production to increase 4% to 7% over the fourth quarter. These new cost control measures substantially improve our EBITDAX and cash flow which, combined with increased production at the Vega Area, provide value to our shareholders.”

     Delta believes the presentation of EBITDAX (a non GAAP measure) provides useful information because it is commonly used by investors to assess financial performance and operating results of ongoing business operations. Reconciliations of EBITDAX to net income (loss) and cash provided by (used in) operating activities, the most directly comparable GAAP financial measures, are provided within the financial tables of this press release.

2010 YEAR-END RESERVES

     For the year ended December 31, 2010, total estimated proved reserves as prepared by an independent third party engineering firm were 134 billion cubic feet equivalents (“Bcfe”), an increase of 17% from the prior year when adjusted for the 39 Bcfe divesture in the third quarter of 2010. Estimated proved reserves were 91% natural gas, which includes related natural gas liquids, and were 92% proved developed, with a standardized measure of $192 million. Approximately 92% of proved reserves are located in the Rocky Mountain region. In addition to proved reserves, the Company estimates that total proved and probable reserves for the Vega Area, its core asset, have increased to 2.9 net trillion cubic feet equivalent (“Tcfe”) from the Williams Fork section and above.

     See “Reserve Disclosure” below for more explanation with respect to the Company’s probable reserves.

     Prices used to calculate the Company’s estimated proved reserves reflect the pricing methodology required under the SEC’s reserve reporting rules which uses the trailing 12-month average of the first of the month price,

or $3.95 per million British thermal units (“MMBtu”) priced at Colorado Interstate Gas (CIG) and $79.61 per barrel of West Texas Intermediate (WTI) oil for 2010, in each case adjusted for differentials, contractual deducts, and similar factors.

     Total costs incurred in oil and gas operations during 2010 were $44.7 million, of which $42.4 million were drilling and completion related.

		Total
		(MMcfe)
Estimated Proved Reserves: Balance at December 31, 2009			153,585
Revisions of quantity estimate			14,456
Extensions and discoveries			22,164
Purchase of properties			—
Sale of properties			(39,240	)
Production			(16,766	)
Estimated Proved Reserves: Balance at December 31, 2010			134,199
Proved developed reserves:
December 31, 2009			132,866
December 31, 2010			123,688

Future net cash flows presented below are computed using first of the month 12-month historical average and costs.

		2010
Future net cash flows		$	793,556
Future costs:
Production			402,334
Development and abandonment			18,899
Income taxes*			—
Future net cash flows			372,323
10% discount factor			(180,229	)
Standardized measure of discounted future net cash flows		$	192,094
Estimated future development cost anticipated for following two years on existing properties		$	13,952

RESERVE SENSITIVITIES

     The Company internally performed price sensitivities to its reserve estimates using 2011 strip pricing as of December 31, 2010 with a four rig drilling program at its Vega asset and adding $1.00 and $2.00 to the NYMEX gas price. All reserves that were included are limited to locations that meet the five-year drilling requirements.

2010 SEC Reserves
Proved				Standardized						Estimated				Standardized
Reserves				Measure						Reserves				Measure
(Bcfe)				($MM)				2010 Reserve Sensitivities, Four Rig Drilling Program		(Bcfe)				($MM)
	134			$	192			2011 Strip Pricing as of 12/31/10			767			$	528
								2011 Strip Pricing as of 12/31/10 + $1.00 NYMEX gas price			767			$	873
								2011 Strip Pricing as of 12/31/10 + $2.00 NYMEX gas price			767			$	1,217

LIQUIDITY UPDATE

     At December 31, 2010, the Company had $15.7 million in cash and approximately $6.2 million available under its amended credit facility ($26.4 million available at March 16, 2011).

     On March 14, 2011, Delta entered into an amendment to the Macquarie Bank Limited (“MBL”) Credit Agreement that increased the availability under the term loan at the time from $6.2 million to $25.0 million, and does not require repayments of the term loan until the January 2012 maturity date. Specifically, among other changes, the amendment provided for an increase in the term loan commitment from $20.0 million to $25.0 million and removed the requirement that advances under the term loan be subject to approval of a development plan. In addition, so long as Delta is not in default under the MBL Credit Agreement, Delta is not required to comply with certain cash management provisions, including the previous requirement to repay any term loan advances outstanding on a monthly basis with 100% of net operating cash flows.

     At December 31, 2010, DHS Drilling Company (“DHS”) was out of compliance with debt covenants under its credit facility and entered into a Forbearance Agreement with its credit facility lender which expires on March 25, 2011. Although the DHS facility is non-recourse to Delta, amounts outstanding under the DHS credit facility are classified as a current liability in the accompanying consolidated balance sheet as of December 31, 2010 as the amounts outstanding under the facility are due on August 31, 2011. 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. The Board of Directors of DHS has directed DHS management to explore the possible sale of the company or its assets.

OPERATIONS UPDATE

     Current production from the Vega Area exceeds 30.0 million cubic feet equivalent per day (“Mmcfe/d”) net. During the fourth quarter 2010 the Company completed eight wells from its drilled and uncompleted inventory in the Vega Area. Since year end, the Company has completed three of the inventory wells and currently expects to complete the remaining two drilled and uncompleted wells in the second quarter of 2011. With the use of the Company’s improved frac technology, referred to as “Gen IV,” currently 16 wells, or 8% of Delta’s total producing wells in the Vega Area, are contributing approximately 39% of total production from the Vega Area. Based on third party engineering data, the new Gen IV fracs are producing at rates that equate to an average gross estimated ultimate recovery (“EUR”) of 1.6 Bcfe per well, an improvement from 1.15 Bcfe using Delta’s prior completion methods.

     As previously disclosed, the Company has drilled an exploratory test well in the Vega Area to explore potential below the Williams Fork section and is now conducting completion activities on the well. Additionally, during the current quarter Delta began drilling a second exploratory test well to continue to evaluate resource potential beneath the Williams Fork section. Delta will release results of the exploratory test wells when appropriate.

     The Company recently terminated a contract with a water treatment service provider for the Vega Area, which resulted in the elimination of an ongoing future expense of approximately $500,000 per month for a ten year period in exchange for a one-time payment of $1.5 million. The termination of this contract allows Delta to

use alternative methods of water treatment and disposal that are more suitable for the amount of water that is currently being produced at the field, and management believes that the use of subsurface injection for water disposal is a much more viable and cost effective approach at the present time. In addition to the water disposal wells that are currently utilized, the Company anticipates converting four wells in the field to water disposal wells and possibly drilling another. The existing wells that are targeted for water disposal are old wells that have minimal or no gas production. Delta is currently in the process of obtaining the necessary permits to inject produced water into the four existing wells, which will help maintain overall operating costs at the reduced levels.

2011 CAPITAL EXPENDITURES AND PRODUCTION GUIDANCE

     Delta will focus its current available capital for 2011 on completing the remaining five previously drilled wells, completing the exploratory test well, drilling a second exploratory test well to continue to evaluate potential below the Williams Fork section, and drilling a lease preservation well, all in the Vega Area. The Company believes that the amounts available under its credit facility as recently amended, combined with net cash from operating activities, will provide it with sufficient liquidity to fund Delta’s operating expenses and the capital development described above and maintain current debt service obligations. The 2011 capital expenditure program, beyond those expenditures currently planned and described herein, will be dependent upon the commodity price environment, well results and the availability of capital to the Company.

     Production for the first quarter 2011 is expected to be between 3.5 Bcfe and 3.6 Bcfe, exceeding the fourth quarter 2010 by 4% to 7%.

RESULTS FOR THE FOURTH QUARTER 2010

     For the quarter ended December 31, 2010, the Company reported production from continuing operations of 3.35 Bcfe, a decrease of 19% when compared with the fourth quarter of 2009 due to the divestiture of assets in the third quarter of 2010. As a result, revenue from oil and gas sales declined 24% to $19.7 million from $26.0 million in the prior year quarter. The average oil price received during the three months ended December 31, 2010 increased to $74.44 per barrel compared to $68.13 per barrel for the year earlier period. The average natural gas price received during the three months ended December 31, 2010 decreased to $4.66 per thousand cubic feet (Mcf) compared to $4.74 per Mcf for the prior year period. Revenue from contract drilling and trucking fees increased 300% to $17.0 million in the fourth quarter of 2010, versus $4.3 million in the fourth quarter of 2009.

     The Company reported a fourth quarter net loss attributable to Delta common stockholders of ($33.7 million), or ($0.12) per diluted share, compared with net loss attributable to Delta common stockholders of ($34.1 million), or ($0.12) per diluted share, in the fourth quarter of 2009.

FOURTH QUARTER 2010 PRODUCTION VOLUMES, UNIT PRICES AND COSTS

     Production volumes, average prices received and costs per equivalent Mcf for the three months ended December 31, 2010 and 2009 were as follows:

		Three Months Ended December 31,
		2010				2009
Production — Continuing Operations:
Oil (MBbl)			87				164
Gas (MMcf)			2,828				3,134
Total (MMcfe)			3,350				4,115
Average Price — Continuing Operations:
Oil (per barrel)		$	74.44			$	68.13
Gas (per Mcf)		$	4.66			$	4.74
Costs per Mcfe — Continuing Operations:
Lease operating expense		$	1.09			$	1.28
Production taxes		$	(0.01	)		$	(0.04	)
Transportation costs		$	1.20			$	0.83
Depletion expense		$	3.56			$	4.29

     Lease Operating Expense. Lease operating expenses for the quarter ended December 31, 2010 were $3.7 million compared to $5.3 million for the prior year period. The 31% decrease was the result of a decrease in water handling costs in the Vega Area due to the resumption of a development program and to a reduced working interest in the properties sold in the third quarter of 2010. The average lease operating expense was $1.09 per Mcfe in the fourth quarter 2010 as compared to $1.28 per Mcfe for the year earlier period.

     Transportation Expense. Transportation expense for the quarter ended December 31, 2010 was $4.0 million, compared to $3.4 million for the prior year period, up 45% on a per unit basis from $0.83 per Mcfe to $1.20 per Mcfe. The increase on a per unit basis is primarily the result of a change in production mix related to the divestiture of assets in the third quarter of 2010 and changes to the Vega gas marketing contract that went into effect in October 2009 whereby gas is processed through a higher efficiency plant with higher costs. Although the Vega area transportation costs increased on a per unit basis in the fourth quarter 2010 as a result of these operations, these costs were offset by higher revenues in the Vega area from improved natural gas liquids recoveries and a greater percentage of liquids proceeds retained.

     Depreciation, Depletion and Amortization — oil and gas. Depreciation, depletion and amortization expense decreased 31% to $12.7 million for the quarter ended December 31, 2010, as compared to $18.5 million for the prior year period. Depletion expense for the quarter ended December 31, 2010 was $11.9 million compared to $17.7 million for the quarter ended December 31, 2009. The 33% decrease in depletion expense was primarily due to a 19% decrease in production from continuing operations and a 17% decrease in the depletion rate. The unit-of-production depletion rate decreased to $3.56 per Mcfe for the quarter ended December 31, 2010 from $4.29 per Mcfe for the prior year period. The decrease is primarily due to improved economics from the use of improved fracturing methods and the changed mix of properties due to the divestiture of assets in the third quarter of 2010.

     General and Administrative Expense. General and administrative expense (“G&A”) decreased 21% to $7.8 million for the quarter ended December 31, 2010, as compared to $9.9 million for the 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 2010. For the quarter ended December 31, 2010 G&A expense included $2.7 million of non-cash equity based compensation and $1.1 million of G&A expense related to DHS. For the quarter ended December 31, 2009 G&A expense included $2.5 million of non-cash equity based compensation and $1.0 million G&A expense related to DHS. Stand alone Delta cash G&A from the quarter ended December 31, 2010 decreased 38% from the quarter ended December 31, 2009.

RESULTS FOR THE FULL YEAR 2010

     For the year ended December 31, 2010, the Company reported total production from continuing operations of 14.8 Bcfe, which was a decrease of 21% from the previous year due to the divestiture of assets in the third quarter of 2010 and production declines in the Piceance Basin. For the year ended December 31, 2010, oil and gas sales from continuing operations increased 14% to $94.4 million, compared with $82.7 million in the comparable period a year earlier. The increase resulted from a 62% increase in the average gas price and a 35% increase in the average oil price. Drilling and trucking revenue increased 289% to $53.2 million, from $13.7 million in the prior year period, as the result of the increase in third party rig utilization due to an increase in drilling activity attributable in particular to higher oil prices.

     For the year ended December 31, 2010, the Company reported a net loss of ($182.3) million, or ($0.66) per diluted share, compared with a net loss of ($328.8 million), or ($1.56) per diluted share, for the year ended December 31, 2009.

FULL YEAR 2010 PRODUCTION VOLUMES, UNIT PRICES AND COSTS

     Production volumes, average prices received and costs per equivalent Mcf for the years ended December 31, 2010 and 2009 are as follows:

		Years Ended December 31,
		2010				2009
Production — Continuing Operations:
Oil (MBbl)			500				734
Gas (MMcf)			11,759				14,319
Total (MMcfe)			14,759				18,727
Average Price — Continuing Operations:
Oil (per barrel)		$	70.90			$	52.45
Gas (per Mcf)		$	5.01			$	3.09
Costs per Mcfe — Continuing Operations:
Lease operating expense		$	1.66			$	1.41
Production taxes		$	0.25			$	0.16
Transportation costs		$	1.03			$	0.54
Depletion expense		$	3.73			$	4.19

     Lease Operating Expense. Lease operating expenses for the year ended December 31, 2010 were $24.6 million compared to $26.4 million for the year earlier period, a decrease of $1.8 million; however, lease operating expenses increased on a per unit basis primarily due to the effect of fixed costs spread over a 21% decline in production volumes. The average lease operating expense was $1.66 per Mcfe in 2010 as compared to $1.41 per Mcfe for the year earlier period.

     Transportation expense. Transportation expense for the year ended December 31, 2010 was $15.2 million, compared to prior year costs of $10.1 million, up 91% on a per unit basis from $0.54 per Mcfe to $1.03 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 gas is processed through a higher efficiency plant. Although the Vega area transportation costs increased on a per unit basis in 2010 as a result of these operations, these costs were offset by higher revenues in the Vega area from improved natural gas liquids recoveries and a greater percentage of liquids proceeds retained.

     Depreciation, Depletion and Amortization — oil and gas. Depreciation, depletion and amortization expense decreased 28% to $58.3 million for the year ended December 31, 2010, as compared to $81.3 million for the year earlier period. Depletion expense for the year ended December 31, 2010 was $55.0 million compared to $78.4 million for the year ended December 31, 2009. The 30% decrease in depletion expense was primarily due to a 21% decrease in production from continuing operations and an 11% decrease in the depletion

rate. The depletion rate decreased to $3.73 per Mcfe for the year ended December 31, 2010 from $4.19 per Mcfe for the year earlier period. The decrease is primarily due to a change in the mix of Delta properties as a result of the divestiture of assets in the third quarter of 2010 and additional Rockies reserves recorded in 2010 as a result of completion activities and use of improved fracturing methods.

     General and Administrative Expense. General and administrative expense decreased slightly to $41.1 million for the year ended December 31, 2010, as compared to $41.4 million for the comparable prior year period. While the Company experienced a decrease in general and administrative expenses primarily attributable to lower expenses incurred on employee benefits and wages from reductions in force during 2010 and 2009, such decrease was offset by significant costs associated with Delta’s 2010 strategic alternatives process and bad debt expense recorded by DHS. The Company expects further reductions to full year cash general and administrative expenses in 2011 as cost saving measures implemented in 2010 take full effect in 2011.

ADDITIONAL FINANCIAL INFORMATION

     The following table summarizes the Company’s open derivative contracts at December 31, 2010, required pursuant to the Company’s credit agreement:

Commodity

Volume

Fixed Price

Term

Index Price

Crude oil

500

Bbls / Day

$

57.70

Jan ’11

- Dec ’11

NYMEX - WTI

Crude oil

116

Bbls / Day

$

91.05

Jan ’11

- Dec ’11

NYMEX - WTI

Crude oil

497

Bbls / Day

$

91.05

Jan ’12

- Dec ’12

NYMEX - WTI

Crude oil

396

Bbls / Day

$

91.05

Jan ’13

- Dec ’13

NYMEX - WTI

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

Natural gas

347

MMBtu / Day

$

4.440

Jan ’11

- Dec ’11

CIG

Natural gas

12,052

MMBtu / Day

$

4.440

Jan ’12

- Dec ’12

CIG

Natural gas

10,301

MMBtu / Day

$

4.440

Jan ’13

- Dec ’13

CIG

     The following table summarizes the Company’s current open derivative contracts for natural gas liquids that were put in place during the first quarter of 2011 required pursuant to the Company’s credit agreement:

				2011								2012								2013
				Volume								Volume								Volume
Commodity		Index Price		(Mgl)				Price				(Mgl)				Price				(Mgl)				Price
Isobutane		Mont Belvieu-OPIS			659			$	1.61				559			$	1.52				224			$	1.44
Normal Butane		Mont Belvieu-OPIS			790				1.56				671				1.49				269				1.41
Natural Gasoline		Mont Belvieu-OPIS			1,317				2.06				1,118				2.02				448				1.93
Propane		Mont Belvieu-OPIS			2,897				1.18				2,459				1.08				987				0.98
Purity Ethane		Mont Belvieu-OPIS			7,507				0.48				6,370				0.40				2,556				0.36
Total					13,170			$	0.91				11,177			$	0.83				4,484			$	0.77

INVESTOR CONFERENCE CALL

     The Company will host an investor conference call on Thursday, March 17, 2011 at 12:00 noon Eastern Time to discuss operating results for the fourth quarter and full year 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 March 17, 2011. 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 17, 2011 until March 25, 2011 by dialing 877-344-7529 (international callers dial 412-317-0088) and entering the conference ID 448373.

ABOUT DELTA PETROLEUM

     Delta Petroleum Corporation is an oil and gas exploration and development company based in Denver, Colorado. The Company’s core area of operation is in the Rocky Mountain region, where the majority of its proved reserves, production and long-term growth prospects are located. Its common stock is listed on the NASDAQ Capital Market System under the symbol “DPTR.”

RESERVE DISCLOSURE

     The Company does not plan to include probable reserve estimates in its filings with the SEC. The Company has provided internally generated estimates for probable reserves in this release. The estimates conform to SEC guidelines. They are not prepared or reviewed by third party engineers. Delta’s probable reserve estimates are determined using strip pricing which it uses internally for planning and budgeting purposes. The Company’s estimate of probable reserves is provided in this release because management believes it is useful additional information that is widely used by the investment community in the valuation, comparison and analysis of companies.

FORWARD-LOOKING STATEMENTS

     Forward-looking statements in this announcement are made pursuant to the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements include, without limitation, anticipated future operating and overhead costs, cost control measures, liquidity requirements and availability of capital, drilling and completion activity, anticipated impact of new frac designs, expected decreases in general and administrative expenses and anticipated production for 2011. 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 the Company’s credit facility and its 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, 2010 and subsequent reports on Forms 10-Q and 8-K as filed with the Securities and Exchange Commission for additional information. The Company is under no obligation (and expressly disclaims any obligation) to update or alter its forward-looking statements, whether as a result of new information, future events or otherwise.

For further information contact the Company at (303) 293-9133 or via email at info@deltapetro.com.

SOURCE: Delta Petroleum Corporation

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS

		December 31,				December 31,
		2010				2009
		(In thousands, except share data)
ASSETS
Current assets:
Cash and cash equivalents		$	15,653			$	61,918
Short-term restricted deposits			100,000				100,000
Trade accounts receivable, net of allowance for doubtful accounts of $2,348 and $100, respectively			20,446				16,654
Deposits and prepaid assets			1,720				3,103
Inventories			3,446				5,588
Other current assets			5,541				5,189
Total current assets			146,806				192,452
Property and equipment:
Oil and gas properties, successful efforts method of accounting:
Unproved			230,117				280,844
Proved			871,986				1,379,920
Drilling and trucking equipment			174,680				177,762
Pipeline and gathering systems			93,558				92,064
Other			15,639				16,154
Total property and equipment			1,385,980				1,946,744
Less accumulated depreciation and depletion			(517,414	)			(800,501	)
Net property and equipment			868,566				1,146,243
Long-term assets:
Long-term restricted deposit			—				100,000
Investments in unconsolidated affiliates			3,377				7,444
Deferred financing costs			1,832				3,017
Other long-term assets			3,531				8,329
Total long-term assets			8,740				118,790
Total assets		$	1,024,112			$	1,457,485
LIABILITIES AND EQUITY
Current liabilities:
Credit facility — DHS		$	69,590			$	83,268
Installments payable on property acquisition			97,874				97,874
Accounts payable			36,185				44,225
Offshore litigation payable			—				13,877
Other accrued liabilities			14,539				13,459
Derivative instruments			574				19,497
Total current liabilities			218,762				272,200
Long-term liabilities:
Installments payable on property acquisition, net of current portion			—				95,381
7% Senior notes			149,684				149,609
33/4% Senior convertible notes			108,593				104,008
Credit facility — Delta			29,130				124,038
Asset retirement obligations			3,929				7,654
Derivative instruments			2,419				7,475
Total long-term liabilities			293,755				488,165
Commitments and contingencies
Equity:
Preferred stock, $0.01 par value:
authorized 3,000,000 shares, none issued			—				—
Common stock, $0.01 par value; authorized 600,000,000 shares, issued 285,138,000 shares at December 31, 2010 and 282,548,000 shares at December 31, 2009			2,851				2,825
Additional paid-in capital			1,633,217				1,625,035
Treasury stock at cost; 33,000 shares at December 31, 2010 and 42,000 shares at December 31, 2009			(279	)			(268	)
Accumulated deficit			(1,121,342	)			(939,010	)
Total Delta stockholders’ equity			514,447				688,582
Non-controlling interest			(2,852	)			8,538
Total equity			511,595				697,120
Total liabilities and equity		$	1,024,112			$	1,457,485

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF OPERATIONS

		Three Months Ended								Twelve Months Ended
		December 31,								December 31,
		2010				2009				2010				2009
		(In thousands, except per share amounts)
Revenue:
Oil and gas sales		$	19,652			$	26,007			$	94,388			$	82,723
Contract drilling and trucking fees			17,012				4,255				53,212				13,680
Gain on offshore litigation settlement, net of loss on property sales			(256	)			42,746				(795	)			73,800
Total revenue			36,408				73,008				146,805				170,203
Operating expenses:
Lease operating expense			3,662				5,281				24,566				26,439
Transportation expense			4,016				3,403				15,211				10,057
Production taxes			(33	)			(163	)			3,727				3,032
Exploration expense			385				182				1,337				2,604
Dry hole costs and impairments			12,713				34,110				43,572				176,871
Depreciation, depletion, amortization and accretion — oil and gas			12,725				18,492				58,265				81,335
Drilling and trucking operating expenses			14,195				4,877				42,248				15,293
Goodwill and drilling equipment impairments			—				—				—				6,508
Depreciation and amortization — drilling and trucking			4,365				5,405				19,964				22,917
General and administrative expense			7,758				9,867				41,130				41,414
Executive severance expense, net			—				—				(674	)			3,739
Total operating expenses			59,786				81,454				249,346				390,209
Operating loss			(23,378	)			(8,446	)			(102,541	)			(220,006	)
Other income and (expense):
Interest expense and financing costs, net			(7,821	)			(10,674	)			(37,247	)			(52,581	)
Other income (expense)			(1,203	)			(581	)			(1,409	)			1,049
Realized loss on derivative instruments, net			(703	)			(1,485	)			(5,835	)			(1,115	)
Unrealized gain (loss) on derivative instruments, net			(4,093	)			62				23,979				(26,972	)
Income (loss) from unconsolidated affiliates			845				(12,149	)			1,738				(15,473	)
Total other expense			(12,975	)			(24,827	)			(18,774	)			(95,092	)
Loss from continuing operations before income taxes and discontinued operations			(36,353	)			(33,273	)			(121,315	)			(315,098	)
Income tax expense (benefit)			(21	)			268				543				215
Loss from continuing operations			(36,332	)			(33,541	)			(121,858	)			(315,313	)
Discontinued operations:
Income (loss) from results of operations and sale of discontinued operations, net of tax			57				(5,253	)			(72,156	)			(34,371	)
Net loss			(36,275	)			(38,794	)			(194,014	)			(349,684	)
Less net loss attributable to non-controlling interest			2,548				4,710				11,682				20,901
Net loss attributable to Delta common stockholders		$	(33,727	)		$	(34,084	)		$	(182,332	)		$	(328,783	)
Amounts attributable to Delta common stockholders:
Loss from continuing operations		$	(33,784	)		$	(28,831	)		$	(110,176	)		$	(294,412	)
Income (loss) from discontinued operations, net of tax			57				(5,253	)			(72,156	)			(34,371	)
Net loss		$	(33,727	)		$	(34,084	)		$	(182,332	)		$	(328,783	)
Basic loss attributable to Delta common stockholders per common share:
Loss from continuing operations		$	(0.12	)		$	(0.10	)		$	(0.40	)		$	(1.40	)
Discontinued operations			—				(0.02	)			(0.26	)			(0.16	)
Net loss		$	(0.12	)		$	(0.12	)		$	(0.66	)		$	(1.56	)
Diluted loss attributable to Delta common stockholders per common share:
Loss from continuing operations		$	(0.12	)		$	(0.10	)		$	(0.40	)		$	(1.40	)
Discontinued operations			—				(0.02	)			(0.26	)			(0.16	)
Net loss		$	(0.12	)		$	(0.12	)		$	(0.66	)		$	(1.56	)
Weighted average common shares outstanding:
Basic			277,394				274,878				275,042				211,033
Diluted			277,394				274,878				275,042				211,033

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

($ in thousands)

THREE MONTHS ENDED

		December 31,				December 31,
		2010				2009
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		$	(5,580	)		$	61,596
Changes in assets and liabilities			9,553				3,863
Less net proceeds from offshore litigation settlement			—				(62,534	)
Exploration costs			385				182
Discretionary cash flow*		$	4,358			$	3,107

TWELVE MONTHS ENDED

		December 31,				December 31,
		2010				2009
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		$	(31,538	)		$	81,144
Changes in assets and liabilities			38,725				3,361
Less net proceeds from offshore litigation settlement			—				(111,235	)
Exploration costs			1,337				2,604
Discretionary cash flow (deficiency)*		$	8,524			$	(24,126	)

THREE MONTHS ENDED

		December 31,				December 31,
		2010				2009
Net loss		$	(36,275	)		$	(38,795	)
Non-controlling interest			2,548				4,710
Income tax expense			46				268
Interest expense and financing costs, net			7,821				10,674
Depletion, depreciation and amortization			17,096				31,441
Gain on offshore litigation settlement, net of loss on property sales			1,017				(42,238	)
Gain on sale of discontinued operations			(68	)			—
Unrealized (gain) loss on derivative instruments, net			4,093				(62	)
Exploration, dry hole and impairment costs			14,098				45,323
EBITDAX**		$	10,376			$	11,321

THREE MONTHS ENDED

		December 31,				December 31,
		2010				2009
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		$	(5,580	)		$	61,596
Changes in assets and liabilities			9,553				3,863
Net proceeds from offshore litigation			—				(62,534	)
Interest net of financing costs			4,984				7,096
Exploration costs			385				182
Impairment of unconsolidated affiliates			—				11,032
Other non-cash items			1,034				(9,914	)
EBITDAX**		$	10,376			$	11,321

TWELVE MONTHS ENDED

		December 31,				December 31,
		2010				2009
Net loss		$	(194,014	)		$	(349,684	)
Non-controlling interest			11,682				20,901
Income tax expense			610				215
Interest expense and financing costs, net			37,247				52,581
Depletion, depreciation and amortization			92,070				131,422
Gain on offshore litigation settlement, net of loss on property sales			2,341				(74,955	)
Gain on sale of discontinued operations			(28,978	)			—
Unrealized (gain) loss on derivative instruments, net			(23,979	)			26,972
Exploration, dry hole and impairment costs			139,508				212,247
EBITDAX**		$	36,487			$	19,699

TWELVE MONTHS ENDED

		December 31,				December 31,
		2010				2009
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		$	(31,538	)		$	81,144
Changes in assets and liabilities			38,725				3,361
Less net proceeds from offshore litigation settlement			—				(111,235	)
Interest net of financing costs			23,480				33,392
Exploration costs			1,337				2,604
Impairment of unconsolidated affiliates			—				14,063
Other non-cash items			4,483				(3,630	)
EBITDAX**		$	36,487			$	19,699