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Delta Petroleum Corporation Announces Second Quarter 2008 Operating Results

Posted on: Thursday, 7 August 2008, 09:00 CDT

DENVER, Aug. 7 /PRNewswire-FirstCall/ -- Delta Petroleum Corporation (Delta or the Company) , an independent oil and gas exploration and development company, today announced its financial and operating results for the second quarter and first half of 2008.

SECOND QUARTER HIGHLIGHTS

-- Revenue increased 81% to $69.5 million and discretionary cash flow (a non-GAAP measure) increased 127% to $40.7 million, when compared with the prior-year quarter.

-- Production from continuing operations increased 75% for the second quarter of 2008 as compared to the prior-year quarter.

-- Proved reserves (unaudited) increased 8% in the current quarter to 649 billion cubic feet of natural gas equivalents (Bcfe) as of June 30, 2008, compared with 603 Bcfe on March 31, 2008, and 376 Bcfe as of December 31, 2007.

-- The Company's borrowing base increased from $140.0 million to $250.0 million due to growth in production and proved reserves.

-- The Greentown pipeline became operational and began accepting gas from the Greentown Federal 28-11 well.

RESULTS FOR THE SECOND QUARTER

For the quarter ended June 30, 2008, the Company reported total production of 6.2 Bcfe, which was consistent with the upper half of previously stated guidance. Production from continuing operations increased 75% when compared with the prior-year quarter and rose 16% from the levels recorded during the first quarter of 2008. Total revenue increased 81% to $69.5 million in the most recent quarter, compared with $38.4 million in the quarter ended June 30, 2007. Revenue from oil and gas sales increased 197% to $61.7 million, compared with $20.7 million in the prior-year quarter. The increase in oil and gas revenue when compared with the corresponding period of the previous year was due to higher production from continuing operations and higher commodity prices. Revenue from contract drilling and trucking fees decreased 45% to $7.9 million, versus $14.3 million in the second quarter of 2007, as a result of inter-company eliminations due to additional DHS rigs working for Delta.

EBITDAX increased 101% to $39.5 million during the three months ended June 30, 2008, compared with $19.6 million in the three months ended June 30, 2007. Discretionary cash flow increased 127% to $40.7 million, versus $18.0 million in the comparable 2007 quarter. (Note: EBITDAX and Discretionary Cash Flow are non-GAAP measures and are described in greater detail below.)

After adjusting for selected items, primarily the non-cash impact of unrealized derivative losses, net income for the second quarter 2008 approximated $4.7 million, or $0.04 per diluted share, versus an adjusted net loss of ($26.8 million), or ($0.43) per share, in the 2007 quarter (see reconciliation of net income (loss) (GAAP) to adjusted net income (loss) (non- GAAP) table for additional information). Before adjusting for the selected items, the Company reported a second quarter net loss of ($22.4 million), or ($0.22) per share, compared with a net loss of ($95.3 million), or ($1.53) per share, in the year-earlier quarter.

SECOND QUARTER PRODUCTION VOLUMES, UNIT PRICES AND COSTS

Production volumes, average prices received and cost per equivalent thousand cubic feet (Mcfe) for the three months ended June 30, 2008 and 2007 were as follows:

Three Months Ended June 30, 2008 2007 Production - Continuing Operations: Oil (MBbl) 209 206 Gas (MMcf) 4,158 1,857 Production - Discontinued Operations: Oil (MBbl) 38 67 Gas (MMcf) 516 738 Total Production (MMcfe) 6,156 4,230 Average Price - Continuing Operations: Oil (per barrel) $113.06 $58.38 Gas (per Mcf) $9.15 $4.70 Costs per Mcfe - Continuing Operations: Lease operating expense $1.58 $1.52 Production taxes $.71 $.34 Transportation costs $.44 $.21 Depletion expense $3.73 $4.44 Realized derivative gain (loss) $ (1.32) $1.09

The depletion rate decreased to $3.73 per Mcfe for the three months ended June 30, 2008, from $4.44 per Mcfe in the prior-year period, primarily as a result of increased reserve additions and lower costs per well in the Piceance Basin capital development program and a higher mix of production from Rocky Mountain properties.

The Company recognized $27.1 million in unrealized losses on derivative instruments during the three months ended June 30, 2008, compared with $1.0 million in unrealized gains during the prior-year period, primarily due to higher commodity prices.

RESULTS FOR THE SIX-MONTH PERIOD

During the six months ended June 30, 2008, oil and gas sales from continuing operations increased 167% to $107.1 million, compared with $40.2 million in the comparable period a year earlier. The increase was the result of a 71% growth in production from continuing operations, an 81% increase in oil prices, and a 65% increase in gas prices. Drilling and trucking revenue decreased 40% to $18.6 million, from $30.9 million in the prior-year period, as a result of inter-company eliminations due to additional DHS rigs working for Delta.

EBITDAX increased 96% and totaled $69.3 million in the first half of 2008, compared with $35.3 million in the six months ended June 30, 2007. Discretionary cash flow increased 121% to $69.3 million in the six months ended June 30, 2008, versus $31.4 million in the corresponding period of the previous year.

After adjusting for selected items, primarily the non-cash impact of unrealized derivative losses, net loss for the six months ended June 30, 2008 was ($966,000), or ($0.01) per diluted share, versus an adjusted net loss of ($38.8 million), or ($0.66) per share in the 2007 period. Before adjusting for the selected items, the Company reported a net loss for the six months ended June 30, 2008 of ($42.2 million), or ($0.47) per share, compared with a net loss of ($113.7 million), or ($1.95) per diluted share, in the six months ended June 30, 2007.

SIX MONTH PRODUCTION VOLUMES, UNIT PRICES AND COSTS

Production volumes, average prices received and cost per Mcfe for the six months ended June 30, 2008 and 2007 were as follows:

Six Months Ended June 30, 2008 2007 Production - Continuing Operations: Oil (MBbl) 438 403 Gas (MMcf) 7,452 3,459 Production - Discontinued Operations: Oil (MBbl) 75 136 Gas (MMcf) 990 1,463 Total Production (MMcfe) 11,522 8,154 Average Price - Continuing Operations: Oil (per barrel) $100.92 $55.74 Gas (per Mcf) $8.44 $5.12 Costs per Mcfe - Continuing Operations: Lease operating expense $1.61 $1.48 Production taxes $.68 $.37 Transportation costs $.41 $.25 Depletion expense $3.87 $4.94 Realized derivative gain (loss) $(.87) $ .77

The depletion rate decreased to $3.87 per Mcfe for the six months ended June 30, 2008, from $4.94 per Mcfe in the year-earlier period, primarily due to increased reserve additions and lower costs per well in the Piceance Basin capital development program and a higher mix of production from Rocky Mountain properties.

The Company recognized $41.2 million in unrealized losses on derivative instruments during the six months ended June 30, 2008, versus $674,000 in unrealized losses on derivative instruments during the prior-year period, primarily due to higher commodity prices.

DERIVATIVE CONTRACTS

The following table summarizes the Company's open derivative contracts as of June 30, 2008:

Price Floor/ Commodity Volume Price Ceiling Term Index Crude oil 1,200 Bbls/day $65.00/$79.86 July '08-Sept '08 NYMEX - WTI Crude oil 1,200 Bbls/day $65.00/$79.83 Oct '08-Dec '08 NYMEX - WTI Natural gas 15,000MMBtu/day $6.50/$8.30 July '08-Dec '08 CIG Natural gas 10,000MMBtu/day $6.00/$7.25 July '08-Sept '08 CIG Natural gas 10,000MMBtu/day $6.50/$8.15 July '08-Sept '08 CIG Natural gas 10,000MMBtu/day $6.50/$7.90 Oct '08-Dec '08 CIG Natural gas 35,000MMBtu/day $7.50/$9.88 Jan '09-Mar '09 CIG Natural gas 10,000MMBtu/day $9.00/$11.53 Oct '08-Dec '08 NYMEX-H HUB Natural gas 10,000MMBtu/day $9.00/$10.58 Apr '09-June '09 NYMEX-H HUB Natural gas 10,000MMBtu/day $9.50/$12.55 Apr '09-June '09 NYMEX-H HUB Natural gas 15,000MMBtu/day $9.00/$10.70 Apr '09-June '09 NYMEX-H HUB Natural gas 10,000MMBtu/day $9.00/$10.82 July'09-Sept '09 NYMEX-H HUB Natural gas 10,000MMBtu/day $9.50/$13.00 July'09-Sept '09 NYMEX-H HUB Natural gas 15,000MMBtu/day $9.00/$10.90 July'09-Sept '09 NYMEX-H HUB Natural gas 10,000MMBtu/day $9.00/$12.05 Oct '09-Dec '09 NYMEX-H HUB Natural gas 15,000MMBtu/day $9.00/$11.95 Oct '09-Dec '09 NYMEX-H HUB Natural gas 15,000MMBtu/day $10.00/$13.10 Oct '09-Dec '09 NYMEX-H HUB OPERATIONS UPDATE

Piceance Basin, CO, 31% - 100% WI - The Company continues to develop the Vega Area with four DHS drilling rigs. Current plans include an increase in the number of operating rigs to eight by the first quarter of 2009. Current net production from the Piceance Basin approximates 46.5 million cubic feet equivalents per day (Mmcfe/d). The Company has continued to experience significant drilling cost reductions by decreasing the drilling time required for new wells from an average of 15 days in the first quarter of 2008 to an average of 13 days in the most recent quarter. Drilling results continue to support the Company's expectation that the total resource potential of the Company's approximate 24,000 net acres of leasehold in the Piceance Basin may exceed 2.4 trillion cubic feet of natural gas equivalents (Tcfe). Proved reserves are unaudited and estimated to approximate 515 Bcfe as of June 30, 2008.

In addition, Delta and its partners in the Collbran Valley Gas Gathering, LLC (CVGG) will participate in the construction of a 20-mile, 24-inch pipeline, with an ultimate capacity of 600 Mmcf/d. This pipeline will interconnect with a new 22-mile, 24-inch pipeline that will provide access to the Meeker processing facility. Initial deliveries are expected in the first quarter of 2009. CVGG will provide the Company with significant takeaway capacity for the development of its properties in the Vega Area.

Paradox Basin, UT, 70% WI - To date the Company has drilled six wells in the Greentown project area. The Company is in the process of drilling two wells, completing three wells, and has one producing well. During the past five months, the Company has experimented with numerous drilling and completion procedures that have included artificial stimulation of various clastic zones in vertical wellbores and the drilling of six separate horizontal laterals in three wellbores. The Company's activities were primarily focused on two geologic intervals, the "O" zone and Cane Creek.

The Company continues its completion activities at the recently drilled Greentown Federal 26-43D (83% WI), which included a 269' horizontal lateral section in the "O" zone. The well had excellent shows while drilling and required mud weights exceeding 19 pounds, which is indicative of very high pressures. The wellbore has experienced numerous downhole mechanical complications but is expected to be completed and flow tested soon.

In addition, the Company has drilled a 2,049' horizontal lateral (with 871' of lateral in the "O" zone) in the Greentown State 36-24H (75% WI) and a 2,533' horizontal lateral (all in the "O" zone) in the Greentown State 31-36 (83% WI). The Company is preparing to "frac" these laterals in mid-August and expects initial sales by the end of the month.

Three of the wells - the Greentown Federal 26-43D, Greentown State 31-36 and Greentown State 36-24H - have been drilled horizontally in the Cane Creek member of the Paradox Formation, with laterals of 1,439', 2,725' and 1,647', respectively. These wells exhibited oil and gas shows while drilling or testing, but did not provide any indication of fracturing and were not accompanied by the over pressuring seen in the "O" zone, where pressure gradients approach 0.9 psi/foot. The shows indicate that hydrocarbons were present in the Cane Creek but that the lack of a bottom seal (salt) on the western edge of the project area, where most of the wells have been drilled to date, caused an ineffective trap. The eastern side of the Greentown area would be at least five to six miles away from the Cane Creek subcrop and should allow for commercial accumulations similar to the historic production in the Big Flats/Bartlett Flats area to the southeast, where wells along the western subcrop of the Cane Creek have been either non-productive or marginally productive. The larger Cane Creek wells in the Big Flats Field are located in excess of five miles to the east of the Cane Creek subcrop.

The Company is preparing to drill the Federal 11-24 with DHS rig #10. This well site is located approximately halfway between the Greentown State 36-11 and the Greentown State 32-42 discovery wells. Simultaneously, the Company is expected to commence drilling the Greentown Federal 33-12, which is located one-half mile east of the Greentown State 32-42 discovery well, with DHS rig #1.

Management believes that the drilling and production results to date confirm that the "O" interval of the Greentown project area is a commercial oil and natural gas bearing zone that is prospective over the majority of the Company's acreage position. Management also believes that the Cane Creek is a potentially commercial zone that is prospective over approximately half of the Company's acreage position.

Columbia River Basin, WA, 100% WI - The Company is drilling the Gray 31-23 well (Bronco Prospect) in Klickitat County, Washington. On July 25, 2008 the well experienced a fire on DHS rig #7 that injured four workers. It is suspected that a pocket of natural gas encountered while drilling ignited on the rig floor. Although the fire caused some damage to the rig, it has been repaired and is expected to recommence drilling within the next few days. Although a natural gas accumulation within the basalt is generally a positive indication of the existence of a natural gas source, it does not necessarily translate into the presence of economic natural gas zones beneath the basalt. The Company still expects to reach total depth early this fall.

Central Utah Hingeline Project, UT, 65% WI - The Company has received a permit and is building a location for the Beaver Federal 21-14 in Beaver County, Utah. DHS rig #11 should arrive on location in mid-August, and the well should spud immediately thereafter. This prospect is a large seismically defined structural feature located approximately midway between the Covenant oil field to the north and the Company's Parowan prospect (Federal 23-44 well) to the south.

The Company has also received approval to commence completion activities on the Federal 23-44 in the Parowan prospect. The Company plans to begin testing various formations beginning the week of August 11, 2008.

Midway Loop Area, SE Gulf Coast, TX, ~ 10% - 55% WI - During the second quarter, the Company completed the Baxter A-141, which had an initial production rate of 15.3 Mmcf/d and 1,100 Bo/d. The Company is currently drilling the Carter A-144, which is expected to reach total depth within the next two months. The Midway Loop project wells and acreage are currently held for sale.

Other Properties - The Company continues to develop and pursue opportunities on its properties in the DJ Basin, Wind River Basin and southeast Texas areas.

PRODUCTION GUIDANCE

The previously announced hydro-testing of the Rockies Express Pipeline during the month of September 2008 may materially impact production for the third quarter. As such, the Company is projecting a third quarter production increase of 4% to 7% over the second quarter of 2008 to 6.4 - 6.6 Bcfe. The Company also reaffirms its full year 2008 guidance that production should increase 45% to 60% over 2007 levels, to a range of 25.8 - 28.4 Bcfe.

INVESTOR CONFERENCE CALL

An investor conference call has been scheduled for 12:00 noon EDT today, Thursday, August 7, 2008.

Shareholders and other interested parties may participate in the conference call by dialing 800-860-2442 (international callers dial 412-858- 4600) and reference the ID code "Delta Petroleum call", a few minutes before 12:00 noon Eastern time on August 7, 2008. 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 August 7, 2008 until August 15, 2008 by dialing 877-344-7529 (international callers dial 412-317-0088) and entering the conference ID 421773#.

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 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, 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. In this press release we say that we estimate our proved reserves to be 649 Bcfe. This is an internally prepared estimate that has not been reviewed by our third party reserve engineers. Proved reserve increases were a function of increased drilling activity and NYMEX based commodity prices less applicable differentials as of June 30, 2008. Please refer to the Company's report on Form 10-K for the year ended December 31, 2007 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 DELTA PETROLEUM CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Unaudited) June 30, December 31, 2008 2007 ASSETS (In thousands) Current assets: Cash and cash equivalents $8,599 $9,793 Certificates of deposit 35,480 - Trade accounts receivable, net of allowance for doubtful accounts of $664 44,265 38,761 Prepaid assets 16,032 3,943 Inventories 5,632 4,236 Derivative instruments - 2,930 Deferred tax assets 150 150 Assets held for sale 67,621 63,749 Other current assets 6,322 10,214 Total current assets 184,101 133,776 Property and equipment: Oil and gas properties, successful efforts method of accounting: Unproved 532,763 247,466 Proved 1,067,286 749,393 Drilling and trucking equipment 172,495 146,097 Pipeline and gathering system 49,676 22,140 Other 36,905 19,069 Total property and equipment 1,859,125 1,184,165 Less accumulated depreciation and depletion (296,388) (245,153) Net property and equipment 1,562,737 939,012 Long-term assets: Long-term restricted deposit 300,000 - Marketable securities 6,012 6,566 Investments in unconsolidated affiliates 14,635 10,281 Deferred financing costs 6,387 7,187 Goodwill 7,747 7,747 Other long-term assets 13,135 6,075 Total long-term assets 347,916 37,856 Total assets $2,094,754 $1,110,644 LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Current portion of long-term debt $10,676 $13 Accounts payable 136,519 119,783 Other accrued liabilities 13,574 17,105 Derivative instruments 35,718 6,295 Total current liabilities 196,487 143,196 Long-term liabilities: Installments payable on property acquisition, net 282,540 - 7% Senior notes, unsecured 149,497 149,459 3-3/4% Senior convertible notes 115,000 115,000 Credit facility - Delta 74,500 73,600 Credit facility - DHS 64,324 75,000 Note Payable - DHS 6,000 - Asset retirement obligations 5,127 4,154 Derivative instruments 8,853 - Deferred tax liabilities 8,851 9,085 Total long-term liabilities 714,692 426,298 Minority interest 33,991 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 103,299,000 shares at June 30, 2008, and 66,429,000 shares at December 31, 2007 1,033 664 Additional paid-in capital 1,343,022 664,733 Treasury stock at cost; 25,000 shares at June 30, 2008 and none at December 31, 2007 (495) - Accumulated other comprehensive loss (265) - Accumulated deficit (193,711) (151,543) Total stockholders' equity 1,149,584 513,854 Total liabilities and stockholders' equity $2,094,754 $1,110,644 DELTA PETROLEUM CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) Three Months Ended Six Months Ended June 30, June 30, 2008 2007 2008 2007 (In thousands, except per share amounts) Revenue: Oil and gas sales $61,659 $20,728 $107,103 $40,166 Contract drilling and trucking fees 7,875 14,299 18,595 30,919 Gain on hedging instruments, net - 3,355 - 4,545 Total revenue 69,534 38,382 125,698 75,630 Operating expenses: Lease operating expense 8,572 4,697 16,193 8,713 Transportation expense 2,360 645 4,100 1,496 Production taxes 3,859 1,055 6,871 2,175 Exploration expense 1,933 772 2,935 1,396 Dry hole costs and impairments 430 70,988 2,769 74,711 Depreciation, depletion, amortization and accretion - oil and gas 20,807 14,152 40,160 29,853 Drilling and trucking operations 5,530 9,643 12,353 20,245 Depreciation and amortization - drilling and trucking 3,209 4,442 6,852 8,806 General and administrative 13,827 12,928 27,247 24,473 Total operating expenses 60,527 119,322 119,480 171,868 Operating income (loss) 9,007 (80,940) 6,218 (96,238) Other income and (expense): Other income (186) 436 273 587 Realized loss on derivative instruments, net (7,130) - (8,765) - Unrealized gain (loss) on derivative instruments, net (27,072) 989 (41,205) (674) Minority interest (121) 291 208 308 Income from unconsolidated affiliates 800 - 691 - Interest income 3,388 895 5,258 971 Interest expense and financing costs (8,659) (6,236) (16,609) (13,907) Total other expense (38,980) (3,625) (60,149) (12,715) Loss from continuing operations before income taxes and discontinued operations (29,973) (84,565) (53,931) (108,953) Income tax expense (benefit) (860) 14,474 (1,458) 6,249 Loss from continuing operations (29,113) (99,039) (52,473) (115,202) Discontinued operations: Income from discontinued operations of properties sold, net of tax 6,756 7,596 10,302 10,079 Gain (loss) on sale of discontinued operations, net of tax (16) (3,880) 3 (8,542) Net loss $(22,373) $(95,323) $(42,168) $(113,665) Basic income (loss) per common share: Loss from continuing operations $(0.29) $(1.59) $(0.58) $(1.97) Discontinued operations 0.07 0.06 0.11 0.02 Net loss $(0.22) $(1.53) $(0.47) $(1.95) Diluted income (loss) per common share: Loss from continuing operations $(0.29) $(1.59) $(0.58) $(1.97) Discontinued operations 0.07 0.06 0.11 0.02 Net loss $(0.22) $(1.53) $(0.47) $(1.95) Weighted average common shares outstanding: Basic 101,057 62,417 90,563 58,348 Diluted 101,057 62,417 90,563 58,348 DELTA PETROLEUM CORPORATION RECONCILIATION OF DISCRETIONARY CASH FLOW AND EBITDAX (in thousands) (unaudited) THREE MONTHS ENDED: June 30, June 30, 2008 2007 CASH PROVIDED BY OPERATING ACTIVITIES $42,287 $12,646 Changes in assets and liabilities (3,486) 4,547 Exploration expense 1,933 772 Discretionary Cash Flow* $40,734 $17,965 SIX MONTHS ENDED: June 30, June 30, 2008 2007 CASH PROVIDED BY OPERATING ACTIVITIES $49,383 $25,423 Changes in assets and liabilities 17,000 4,565 Exploration expense 2,935 1,396 Discretionary Cash Flow* $69,318 $31,384

* 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.

THREE MONTHS ENDED: June 30, June 30, 2008 2007 Net loss $(22,373) $(95,323) Income tax expense (benefit) (860) 16,944 Interest income (3,388) (895) Interest and financing costs 8,659 6,236 Depletion, depreciation and amortization 27,960 21,845 Loss on sale of oil and gas properties and other investments 17 16 Unrealized (gain) loss on derivative contracts 27,072 (989) Exploration and dry hole costs 2,363 71,760 EBITDAX** $39,450 $19,594 THREE MONTHS ENDED: June 30, June 30, 2008 2007 CASH PROVIDED BY OPERATING ACTIVITIES $42,287 $12,646 Changes in assets and liabilities (3,486) 4,547 Interest net of financing costs 2,407 4,858 Exploration and dry hole costs 1,933 772 Other non-cash items (3,691) (3,229) EBITDAX** $39,450 $19,594 SIX MONTHS ENDED: June 30, June 30, 2008 2007 Net loss $(42,168) $(113,665) Income tax expense (benefit) (1,458) 8,255 Interest income (5,258) (971) Interest and financing costs 16,609 13,907 Depletion, depreciation and amortization 54,643 44,405 (Gain) loss on sale of oil and gas properties and other investments (3) 6,623 Unrealized loss on derivative contracts 41,205 674 Exploration and dry hole costs 5,704 76,107 EBITDAX** $69,274 $35,335 SIX MONTHS ENDED: June 30, June 30, 2008 2007 CASH PROVIDED BY OPERATING ACTIVITIES $49,383 $25,423 Changes in assets and liabilities 17,000 4,565 Interest net of financing costs 7,095 11,597 Exploration and dry hole costs 3,202 2,389 Other non-cash items (7,406) (8,639) EBITDAX** $69,274 $35,335

** 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.

ADJUSTED NET INCOME RECONCILIATION OF NET INCOME (GAAP) TO ADJUSTED NET INCOME (NON-GAAP) (In thousands, except per share amounts) (unaudited) Three Months Ended Six Months Ended June 30, June 30, 2008 2007 2008 2007 Net loss $(22,373) $(95,323) $(42,168) $(113,665) Adjustments, net of tax Unrealized (gain) loss on derivative instruments, net 27,072 (989) 41,205 674 Impairment costs - 58,407 - 58,435 Loss (gain) on sale of discontinued properties 16 3,880 (3) 8,542 Valuation allowance adjustment - 15,365 - 7,225 Total adjustments 27,088 76,663 41,202 74,876 Adjusted net income (loss)*** $4,715 $(18,660) $(966) $(38,789) Adjusted net income per share (non-GAAP) Basic .05 (.30) (.01) (.66) Diluted .04 (.30) (.01) (.66) Average number of shares outstanding Basic 101,057 62,417 90,563 58,348 Diluted(1) 107,694 62,417 90,563 58,348

*** Adjusted net income (loss) should not be considered a substitute for net income (loss) as reported in accordance with GAAP. Adjusted net income is provided for comparison to earnings forecasts prepared by analysts and other third parties. Management uses adjusted net income in evaluating our operational trends and performance relative to other oil and gas producing companies. Items excluded are generally items whose timing or amount cannot be reasonably estimated.

(1) The adjusted diluted net income per share calculation for the three months ended June 30, 2008 includes an increase in diluted shares of approximately 6.6 million shares representing the incremental dilutive shares that would be included if not for our net loss in the period.

Delta Petroleum Corporation

CONTACT: Delta Petroleum Corporation, +1-303-293-9133,info@deltapetro.com; or RJ Falkner & Company, Inc., Investor RelationsCounsel, 1-800-377-9893, info@rjfalkner.com, for Delta Petroleum Corporation

Web site: http://www.deltapetro.com/

Source: PRNewswire-FirstCall

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