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Delta Talks Piceance/Mancos Drilling; Vega Shale Evaluation

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August 5, 2011

Delta Petroleum Corp., Denver, (Nasdaq: DPTRD) has reported its financial and operating results for the second quarter 2011.  

"We are pleased to provide our shareholders with another solid operating quarter coupled with the accomplishment of some very important strategic steps," says Carl Lakey, president and CEO. "We sold our remaining non-core assets, which reduced our leverage and provided sufficient liquidity to continue our deep shale evaluation and development in the Vega Area.  While the strategic alternatives process, the 2C well results, and the Netherland Sewell report were all announced subsequent to the end of the quarter, much of the efforts that went into those steps occurred in the second quarter.  The 2B and 2C well results and Netherland Sewell's report are very important contributions that support Delta's intrinsic value and aid our strategic alternatives process."

Vega Area Shale Evaluation Update

As previously announced, the Delta 2C well began producing hydrocarbons on Wednesday, July 20, at a rate of 5.4 million cubic feet of gas per day (MMcf/d), which was choke-restricted with a 7/64 of an inch choke and 8,360 psi of flowing tubing pressure.  Gas sales from the well began on Thursday, July 21 from the Niobrara and Frontier formations only.  The well is currently producing between 2.5 – 3.5 MMcf/d with 6,100 psi of flowing tubing pressure.  The well choke is currently set at 9/64 of an inch.  The Mancos shale, Corcoran and Williams Fork formations remain uncompleted.

The Delta 2B well in the Vega Area of the Piceance Basin drilled through a portion of the Mancos formation and reached total depth of 10,700 feet.  Below the Williams Fork the well was completed in 1,200 feet of shale in the Corcoran and the upper portion of the Mancos formation.  Gas production began on April 24 and sales commenced on April 29.  As announced on May 10, the 2B well experienced sustained production of 3.3 MMcf/d from only the Mancos and Corcoran formations.  The well is currently producing 0.6 MMcf/d.  The information available indicates that the natural fractures in the 2B well may have prematurely closed by the high flow rate (6 MMcf/d) during initial flowback activities, which has subsequently hindered production.  The Company is currently evaluating refracturing the well in the Mancos and Corcoran formations to reestablish higher production levels in the well.

The Company is currently drilling the 12B well.  The current depth is approximately 8,500 feet with a target depth of 13,000 feet.  It is expected that the target depth will reach the Frontier formation.  Total depth is expected to be reached during September.  Once completed, this well will hold the acreage of the federal Sheep Creek Unit and bring the company's Vega leasehold up to 95% held by production.  

Strategic Alternatives Update

On July 6, 2011, Delta announced that it had engaged Macquarie Capital (USA) Inc. and Evercore Group, L.L.C. to act as advisors to the Company in conducting a strategic alternatives process aimed at maximizing shareholder value and dealing with the Company's 2012 debt maturities. Through this process, the Board of Directors is evaluating all opportunities available, including a potential sale of the Company.  The process is in its early 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.

Operations Update

Current production of the company approximates 28 million cubic feet equivalent per day (MMcfe/d) net.

2011 Capital Expenditures

Delta will focus its current available capital for the remainder of 2011 on drilling and completing the 12B well and completing the remaining two previously drilled Williams Fork wells.  The completions of the remaining two previously drilled wells have been postponed to the fourth quarter of 2011; however, these plans could be altered depending on shale well results, with capital potentially being reallocated to additional shale activity.  Developments related to the strategic alternatives process may also affect current capital spending plans.

Production for the third quarter 2011 is expected to be between 2.6 Bcfe and 2.7 Bcfe.

Liquidity Update

At June 30, 2011, the company had $3.9 million in cash and approximately $18.0 million available under its amended credit facility.  During the second quarter, Delta received $43.2 million from the sale of non-core assets.  The proceeds were used to pay down the facility, close out certain oil derivative positions and for development activity in the company's Piceance Basin projects.  The company expects to have sufficient capital under its credit facility, combined with proceeds from the non-core asset sale and net cash from operating activities, to fund Delta's operating expenses and the current capital development described above and to maintain its debt service obligations through the remainder of 2011.  

Second Quarter 2011 Results

For the quarter ended June 30, 2011, the company reported total production of 3.2 Bcfe.  Production from continuing operations was 2.8 Bcfe, remaining flat when comparing second quarter 2011 to the prior year period.  Revenue from oil and gas sales was $16.9 million, an increase of 14% when compared to the prior year period of $14.8 million.  The average natural gas price received during the quarter ended June 30, 2011 increased to $5.31 per thousand cubic feet (Mcf) compared to $4.92 per Mcf for the prior year period.  The average oil price received during the quarter ended June 30, 2011 increased to $86.87 per barrel compared to $58.29 per barrel for the prior year period.  

The company reported a second quarter net loss attributable to Delta common stockholders of ($963,000), or ($0.03) per diluted share, compared to a net loss attributable to Delta common stockholders of ($149.8 million), or ($5.43) per diluted share, in the second quarter of 2010.  The decrease in net loss is primarily due to a decrease in dry hole costs and impairments and a decrease in operating expenses, as well as discontinued operations.  

Delta Petroleum Corp.

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