Delta Petroleum Increases Reserves 20% to 269 Bcfe

Delta Petroleum reported its financial and operating results for the quarter and six months ended December 31, 2005. Effective December 31, 2005, Delta changed its fiscal year end from June 30th to December 31st.


For the quarter ended December 31, 2005, the Company reported net income of $1.6 million, or $0.03 per fully diluted share, compared with $4.8 million, or $0.11 per fully diluted share, for the same period a year earlier. Oil and gas revenue increased 42.3% to $29.1 million, versus $20.4 million in the prior-year quarter. For the six months ended December 31, 2005, the Company reported a net loss of ($590,000), or ($0.01) per share, compared with net income of $8.8 million, or $0.21 per fully diluted share, in the corresponding period of the previous year. Oil and gas revenue increased 53.0% to $60.7 million in the most recent six-month period from $39.7 million in the six months ended December 31, 2004.

Production from continuing operations for the quarter approximated 3.1 billion cubic feet equivalents (Bcfe), which was less than previously expected, as disclosed in a previous news release. Production fell short of expectations due to drilling and weather related delays. Production from continuing operations for the six months ended December 31, 2005 increased 7.6% to 6.6 Bcfe, compared with 6.1 Bcfe in the corresponding period of the previous year.

A number of items materially affected the Company's results for the six months ended December 31, 2005:

    * The Company recorded a pre-tax unrealized loss on ineffective derivative
      instruments of $9.9 million and a pre-tax realized loss of $8.0 million
      on settled derivative instruments.

    * Delta experienced higher exploration and dry hole expenses, totaling
      $7.5 million, that were related to increased seismic costs in the Newton
      Field in Southeastern Texas and abandonment/impairment costs associated
      with dry holes on certain non-operated prospects.

    * The Company recorded stock option compensation of approximately
      $2.0 million related to options granted prior to the adoption of FAS
      No. 123 ® "Accounting for Stock Based Compensation" that vested during
      the period.

    * An $11.8 million after-tax gain was recorded on the sale of oil and gas
      properties primarily related to the disposition of the Company's
      Deerlick Creek field in Tuscaloosa County, Alabama.

"Although a minor net loss was reported for the six-month transition period, many items were non-recurring, and average daily production has increased significantly in recent months," noted Roger A. Parker, Chairman and Chief Executive Officer of Delta Petroleum Corporation. "This should allow our results to improve noticeably in the current year."


A brief description of accomplishments during the calendar year ended December 31, 2005 is provided below. The following have positioned Delta for substantial organic growth in 2006:

    * The Company expanded its ownership in the Piceance Basin, has initiated
      a continuous drilling program in the Vega Unit, and is participating in
      the development of the Garden Gulch Field.  Combined drilling capital
      expenditures for the two areas will total $45 - $60 million during 2006.

    * Successful initial wells were drilled in the horizontal Austin Chalk
      prospect area in Polk and Tyler Counties, Texas, and in the deep Sligo
      formation at the Opossum Hollow Field in McMullen County, Texas.  Both
      areas possess the potential for meaningful production growth and will
      continue to be actively drilled.

    * Delta completed the acquisition and interpretation of 58 square miles of
      3D seismic surrounding the Newton Field in Southeast Texas, resulting in
      the identification of numerous additional drilling opportunities.

    * The Company increased its leasehold ownership in the Columbia River
      Basin by approximately 300% to over 375,000 net acres.

    * DHS Drilling Company expanded its fleet to 11 rigs by year-end, and an
      additional 4 rigs were under contract and expected to join the fleet in
      early 2006.  All of these rigs are available to support Delta's
      increased drilling activity.

    * The Company more than doubled its personnel in order to pursue an
      aggressive drilling program.

"We look forward to an exciting year in 2006," commented Parker. "We expect robust production and reserve growth from our current drilling programs in the Gulf Coast area of Texas and the Piceance and Wind River Basins in the Rocky Mountains. Additionally, we expect initial test results from the Columbia River Basin in Washington State and the central Utah Hingeline projects, both of which represent areas with exceptionally large reserve potential."


As of December 31, 2005, the Company's third-party engineering firm estimates Delta's proved reserves at approximately 269 Bcfe, which represents an increase of 20% when compared with proved reserves at June 30, 2005.

A summary of changes in estimated quantities of proved reserves for the six months ended December 31, 2005 is provided below.

                                                   Onshore            Offshore
                                               GAS          OIL          OIL
                                              (MMcf)       (MBbl)       (MBbl)
                                                       (In thousands)
    Estimated Proved Reserves:
     Balance at July 1, 2005                 141,041       12,373       1,498

       Revisions of quantity estimate         (4,683)        (506)       (468)
       Extensions and discoveries             58,725        2,542          --
       Purchase of properties                 11,816           --          --
       Sale of properties                    (22,025)        (221)         --
       Production                             (3,720)        (428)        (81)

    Estimated Proved Reserves:
     Balance at December 31, 2005            181,154       13,760         949

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.

                                            Onshore      Offshore   Combined
                                                      (In thousands)
    December 31, 2005
      Future net cash flows                $2,613,958     $45,420  $2,659,378
    Future costs:
      Production                              481,537      21,970     503,507
      Development and abandonment             318,704       2,950     321,654
      Income taxes                            471,125       5,325     476,450
    Future net cash flows                   1,342,592      15,175   1,357,767
      10% discount factor                    (604,355)     (3,788)   (608,143)
    Standardized measure of discounted
     future net cash flows after taxes       $738,237     $11,387    $749,624

    Standardized measure of discounted
     future net cash flows before taxes      $999,576     $15,383  $1,014,959

Total costs incurred, including acquisition, leasehold, drilling, completion, seismic, asset retirement obligations and all other capitalized oil and gas related costs, approximated $182.9 million.


The Company is revising production guidance downward for the quarter ending March 31, 2006 to 4.1 - 4.3 Bcfe. The primary factors in this revision include unforeseen delays related to the sale of the pipeline company responsible for building a new high-pressure pipeline to the Morrill Sligo #1 well, and a more lengthy review of the Castle Energy merger by the Securities and Exchange Commission. Originally, both were expected to begin contributing to quarterly production in early February. The Company's current production rate approximates 48 Mmcfe per day.


Newton Field, SE Gulf Coast, TX, 100% WI -- The Company continues to experience predictable success in the Newton Field. As a result of its development drilling program, Delta has increased the proved reserves in the field from 42 Bcfe as of December 31, 2004, to 66 Bcfe as of December 31, 2005, and additional proven reserve growth is anticipated for 2006. Net production at Newton more than doubled in calendar 2005, to 11.8 Mmcfe/day by year-end. In calendar 2005, drilling capital expenditures for the Newton Field approximated $40 million. For calendar 2006, the Company has budgeted $44 - $50 million in drilling capital expenditures for the field.

Vega Unit, Piceance Basin, CO, 100% WI -- Individual well production performance is meeting or exceeding pre-development expectations for the Vega Unit. Wells located throughout the unit have average initial production rates of 1.1 - 2.0 Mmcf/day. In calendar 2005, drilling capital expenditures were approximately $11 million, and such expenditures should increase to $30 - $35 million in 2006. As of March 1, 2006, the field was producing at a pipeline-restricted net rate of 3.5 Mmcf/day, with the capability of producing at a net rate of 6.5 Mmcf/day. A new pipeline is under construction and should be operational by mid-2006. Once completed, the pipeline will have sufficient capacity for full development of the Vega Unit. DHS rig #5 is currently drilling in the unit.

Garden Gulch Field, Piceance Basin, CO, 25% WI -- The Garden Gulch Field is targeting the same sequence of Williams Fork sands as the Vega Unit and results are encouraging, to date. The field is currently being developed with two rigs, and drilling is expected to accelerate significantly in 2006, when drilling capital expenditures should approximate $15 - $25 million.

Howard Ranch Area, Wind River Basin, WY, 50-100% WI -- The Copper Mountain Unit 35-13 reached total depth of 19,100 feet and is the first well in the field to drill through the entire Mesaverde section. The well experienced significant gas shows and comparatively high reservoir pressures. We expect to initiate completion activities on the Copper Mountain 35-13 this month. The Company has completed 6 of the 16 sands in the Mesaverde section in the Diamond State 36-13 well, and the well should be fully completed in this section later this spring. Recent changes in frac design appear to be improving initial production results, with the last two stages producing in excess of 3 Mmcf/day with very limited water. Drilling capital expenditures have been budgeted at approximately $20 million for calendar 2006.


Midway Loop Area, SE Gulf Coast, TX, ~ 40% WI -- The Best Kenneson well has been on line since late December and is currently producing at a gross rate of 10 Mmcf/day and 825 barrels of condensate per day (4.1 Mmcfe/day net) from dual horizontal wellbores in the Austin Chalk formation. The Company is currently drilling the BP America Delta #1, which is south of the Best Kenneson well. This area is being developed with DHS rig #9, and Delta has budgeted $12 - $16 million in drilling capital expenditures for 2006.

Paradox Basin, CO & UT, 70% WI -- The Company plans to drill three separate prospects in the Paradox Basin, all of which target unconventional reservoirs. Numerous permitting challenges have delayed start up, but activity should be underway this month. Each of the prospect areas requires an appraisal well which, if successful, will allow DHS rig #6 to remain in this area for future development. In 2006, the Company has budgeted $6 - $8 million for the drilling of three initial test wells in the Paradox Basin.

Opossum Hollow, Central Gulf Coast, TX, WI 98% -- At the end of January, the Company reached total depth on the Morrill Sligo #1, which tested a deep Sligo feature beneath the shallow producing Wilcox Field. The well will be completed later this week and connected to a new high-pressure sales pipeline in April. The Company has budgeted up to $14 million in capital expenditures for calendar 2006.

Newton 3D Seismic Shoot, SE Gulf Coast, TX, 100% WI -- The Company has completed and interpreted a 58 square mile 3D seismic survey centered over the Newton Field and has identified two Wilcox features similar to the Newton Field, along with numerous shallow prospects. The Company has budgeted $10 million in capital expenditures for 2006.

Central Utah Hingeline Project, UT, 65% WI -- This summer, the Company plans to drill the first of three exploration wells budgeted for 2006. It is anticipated that all the wells will be drilled with a DHS rig, and the first well will be an 8,000-foot test that should require 30 days to drill. Capital expenditures for calendar 2006 are projected at $8 - $12 million.

Columbia River Basin, WA -- The Anderville Farms 1-6 is awaiting the relocation of DHS rig #7 from Wyoming, which will drill the remaining portion of the well. The Anderson 11-5 is the second new well to spud and is 20 miles to the southwest of the Anderville Farms 1-6. Drilling results are expected later this spring and completion results this summer. Delta has not budgeted any drilling capital expenditures for the Columbia River Basin in 2006.


DHS Drilling Company

Delta owns 49.5% of DHS Drilling Company, a contract land drilling and trucking company, and the Company has priority access to all drilling rigs for its use and operations. DHS' financial results are consolidated into Delta's financial statements. As of December 31, 2005, DHS owned eleven drilling rigs with depth capacities ranging from 7,500' to 20,000'. DHS currently owns or has committed to acquire a total of fifteen drilling rigs. Approximately half of the rigs in operation are currently working for Delta, with the balance being utilized by other operators.

Castle Energy Corporation Merger

As announced on November 8, 2005, Delta has entered into a merger agreement with Castle Energy Corporation ("Castle") that has been approved by both Boards of Directors. The merger is subject to the approval of Castle stockholders and is expected to close early in the second quarter of 2006.