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Delta Petroleum Corporation Announces Third Quarter 2007 Operating Results

Posted on: Thursday, 8 November 2007, 09:00 CST

DENVER, Nov. 8 /PRNewswire-FirstCall/ -- Delta Petroleum Corporation , an independent energy exploration and development company, today announced its financial and operating results for the third quarter and first nine months of 2007.

THIRD QUARTER HIGHLIGHTS -- Production from continuing operations increased 44% from third quarter 2006 levels. -- Company commenced drilling on North Vega acreage and now has a total of four rigs operating in Vega and North Vega. -- In the Vega area operational efficiencies continue to be realized with average drilling time decreasing and initial production rates increasing. RESULTS FOR THE THIRD QUARTER

For the quarter ended September 30, 2007, the Company reported total production of 4.58 billion cubic feet of natural gas equivalents (Bcfe), which was in the upper half of previously stated guidance. Production from continuing operations increased 44% when compared with the third quarter of 2006 and 9.1% from second quarter 2007 levels. Total revenue increased 22% to $51.9 million in the most recent quarter, compared with $42.7 million in the quarter ended September 30, 2006. Revenue from oil and gas sales increased 18% to $30.9 million, compared with $26.1 million in the prior year quarter. The increase in oil and gas revenue when compared with the corresponding period of the previous year was primarily due to higher production from continuing operations, offset by a 27% decrease in the average gas price, primarily in the Rocky Mountain region. Revenue from contract drilling and trucking fees decreased 13% to $14.9 million, versus $17.2 million in the third quarter of 2006. EBITDAX totaled $21.4 million during the three months ended September 30, 2007, compared with $18.9 million in the three months ended September 30, 2006. Discretionary cash flow increased 34% to $20.4 million, versus $15.2 million in the comparable 2006 quarter. (Note: EBITDAX and Discretionary Cash Flow are non-GAAP measures and are described in greater detail below.)

The Company reported a third quarter net loss of ($6.4 million), or ($0.10) per share, compared with a net loss of ($7.1 million), or ($0.13) per share, in the third quarter of 2006. The loss included exploration expense of $4.7 million, related to increased seismic activity in Utah, Wyoming and Texas, and $3.9 million of non-cash equity compensation, which expense is included in general and administrative expenses.

THIRD QUARTER PRODUCTION VOLUMES, UNIT PRICES AND COSTS

Production volumes, average prices received and cost per equivalent thousand cubic feet (Mcf) for the three months ended September 30, 2007 and 2006 were as follows:

Three Months Ended September 30, 2007 2006 Onshore Offshore Onshore Offshore Production -- Continuing Operations: Oil (MBbl) 225 35 230 39 Gas (MMcf) 2,869 -- 1,465 -- Production - Discontinued Operations: Oil (MBbl) 19 -- 66 -- Gas (MMcf) 38 -- 536 -- Total Production (MMcfe) 4,371 210 3,779 237 Average Price -- Continuing Operations: Oil (per barrel) $74.52 $57.26 $68.87 $43.48 Gas (per Mcf) $4.24 $-- $5.84 $-- Costs per Mcfe -- Continuing Operations: Hedge effect $ 1.42 $-- $(.23) $-- Lease operating expense $1.10 $5.10 $1.33 $4.28 Production taxes $.43 $.06 $.45 $.06 Transportation costs $.27 $-- $.15 $-- Depletion expense $4.42 $1.61 $5.50 $1.25

Lease operating expense for the three months ended September 30, 2007 totaled $5.7 million, compared with $4.8 million in the comparable prior year quarter. Lease operating expense from continuing operations for onshore properties approximated $1.10 per thousand cubic feet equivalents (Mcfe) in the most recent quarter, compared with $1.33 per Mcfe in the year earlier period, primarily due to additional volumes from new wells without significant additional operating costs.

Depreciation, depletion and amortization expense -- oil and gas -- increased 19% to $19.5 million for the three months ended September 30, 2007, versus $16.5 million in the comparable year earlier period. Depletion expense increased due to a 44% rise in production from continuing operations. However, the depletion rate decreased by 20% to $4.42 per Mcfe, from $5.50 per Mcfe in the comparable quarter of 2006. The Howard Ranch impairments recorded in the second quarter of 2007 and greater production from the Vega Unit contributed to a lower depletion rate in the third quarter of 2007, when compared with the same period in 2006.

Exploration expense consists of geological and geophysical costs and lease rentals. The Company's exploration costs for the three months ended September 30, 2007 totaled $4.7 million, compared with $1.2 million in the prior year period. Current year exploration expense includes significant activity related to the Company's Utah, Wyoming and Texas projects.

General and administrative expense increased 31% to $12.8 million during the third quarter of 2007, versus $9.8 million in the three months ended September 30, 2006. The increase in general and administrative expense was primarily due to higher non-cash equity compensation costs of $2.9 million and an 18% increase in technical and administrative staff and related personnel costs.

RESULTS FROM THE NINE MONTH PERIOD

During the nine months ended September 30, 2007, oil and gas sales from continuing operations increased 4% to $84.7 million, compared with $81.4 million in the comparable period in the previous year. The increase resulted from a 23% rise in production from continuing operations, partially offset by a 15% decrease in average gas prices. Drilling and trucking revenue increased 13% to $45.3 million, from $40.2 million in the comparable prior year period.

The Company reported a net loss for the nine months ended September 30, 2007 of ($119.4 million), or ($1.98) per share, compared with net income of $10.9 million, or $0.21 per diluted share, in the nine months ended September 30, 2006. Net loss increased significantly due to impairment and dry hole expenses of approximately $69.1 million, primarily related to lower natural gas prices and marginally economic deep zones in the Rocky Mountain region and a $46.7 million valuation allowance on deferred tax assets. EBITDAX totaled $56.4 million during the first nine months of 2007, compared with $58.5 million in the nine months ended September 30, 2006. Discretionary cash flow totaled $52.4 million for the nine months ended September 30, 2007, versus $46.5 million in the comparable prior year period.

NINE MONTH PRODUCTION VOLUMES, UNIT PRICES AND COSTS

Production volumes, average prices received and cost per equivalent Mcf for the nine months ended September 30, 2007 and 2006 were as follows:

Nine Months Ended September 30, 2007 2006 Onshore Offshore Onshore Offshore Production -- Continuing Operations: Oil (MBbl) 624 110 710 124 Gas (MMcf) 7,440 -- 4,611 -- Production -- Discontinued Operations: Oil (MBbl) 84 -- 220 -- Gas (MMcf) 389 -- 1,455 -- Total Production (MMcfe) 12,076 658 11,651 744 Average Price -- Continuing Operations: Oil (per barrel) $64.59 $48.36 $66.18 $48.49 Gas (per Mcf) $5.25 $-- $6.15 $-- Costs per Mcfe -- Continuing Operations: Hedge effect $.94 $-- $(.61) $-- Lease operating expense $1.09 $3.74 $1.18 $4.14 Production taxes $.44 $.06 $.48 $.05 Transportation costs $.25 $-- $.13 $-- Depletion expense $4.56 $1.41 $4.14 $.95

Lease operating expense of $14.7 million for the nine months ended September 30, 2007 compared with $13.6 million in the corresponding period of the previous year. Lease operating expense from continuing operations for onshore properties approximated $1.09 per Mcfe for the nine months ended September 30, 2007, versus $1.18 per Mcfe in the comparable prior year period.

Depreciation, depletion and amortization expense -- oil and gas -- increased 37% to $53.2 million for the nine months ended September 30, 2007, compared with $38.8 million in the comparable year earlier period. The increase in depletion expense was due to an increase in production from continuing operations.

Depreciation and amortization expense related to DHS Drilling Company increased to $16.5 million for the nine months ended September 30, 2007, compared with $11.1 million a year earlier, due primarily to additional rigs placed in service by DHS.

Exploration expense for the nine months ended September 30, 2007 increased to $6.1 million, compared with $3.4 million in the year earlier period.

General and administrative expense increased 39% to $37.3 million for the nine months ended September 30, 2007, versus $26.8 million in the corresponding period of the previous year. The increase was primarily due to higher non-cash equity compensation expense of $7.6 million and a 14% increase in technical and administrative staff and related personnel costs.

OPERATIONS UPDATE

Vega Unit and North Vega, Piceance Basin, CO, 50%-100% WI -- The Company is continuing to develop the Vega/North Vega area with four DHS rigs and expects to have approximately 70 wells producing by year end, with productive capacity of 40-45 million cubic feet per day (Mmcf/d). The economics of the Vega Unit and North Vega area continue to improve, as well costs have been reduced in response to more efficient drilling procedures and fracture ("frac") stimulations. In addition, the initial production rate of wells has increased as a result of improved frac stimulation design and more effective pay zone identification procedures. Additional pipeline capacity from the Collbran Valley Gas System should become operational late in the first quarter of 2008, at which time Company's production is projected to increase accordingly.

Garden Gulch Field, Piceance Basin, CO, 31% WI -- The operator is currently developing the Garden Gulch Field with three drilling rigs. Similar to the Vega Unit area, well costs have been declining and well economics have been improving. With the Company's additional ownership and numerous recent well completions, net production has increased to approximately 7 Mmcf/d.

Greentown Project, Paradox Basin, UT, 70% WI -- The Company is currently drilling two wells in the Greentown project, the Federal 28-11 and Federal 36-24. The Federal 28-11 is drilling and should reach total depth within the next few weeks. The Federal 36-24 is drilling and should reach total depth in approximately 30 days. Completion results from these wells are expected later this quarter.

The Company had previously been drilling the Federal 35-12 well. While drilling just below the base of the intermediate casing string at a depth of approximately 5,000 feet, the Company drilled into an interval that initially encountered gas, but quickly began flowing water. The bottom-hole pressure of this interval exceeded 6,000 pounds translating to a pressure gradient of 1.1 psi/foot. Pressure gradients of this magnitude are extremely rare and uncommon in the Rocky Mountain region. This degree of over-pressuring can cause an unsafe drilling environment and may result in downhole blowouts in other intervals. The Company was successful in containing the over-pressured zone and plans to produce the interval, thereby lowering the pressure in order to commence re-drilling the Federal 35-12 to the target objective intervals between 5,200 and 9,500 feet in depth.

None of the other 10 wells drilled in the immediate area of the Federal 35-12 encountered this degree of over-pressuring in this interval. Subsurface geologic evidence derived from these wells strongly suggests that this is a localized event. Most of the wells in this area, including the Greentown 36-11 and Greentown 32-42, exhibited good gas shows in this interval. The Greentown 36-11 also flowed hydrocarbons while drilling the same interval. Results from the Federal 35-12 do not change the Company's optimism and confidence for the Greentown Project, and management believes that all deeper intervals will be hydrocarbon-bearing, as they were in the first two wells.

Cowboy Field, DJ Basin, WY, 70%-100% WI -- The Company has acquired its 3D seismic survey over the Cowboy Field and surrounding leasehold and is processing the data. The interpreted data from the survey will be used to develop the field, which is expected to contain numerous additional locations. Drilling activity will resume in 2008. The field currently has 11 wells producing at a gross cumulative rate of approximately 1,100 Bo/d.

Howard Ranch Area, Wind River Basin, WY, 50-100% WI -- The Company recently reached total depth on the West Madden Federal 34-24 and is drilling the Copper Mountain Unit 4-33. Completion operations at the West Madden well will commence later this month. A third well will be drilled, and plans for 2008 will be determined based on results of the three new wells.

Midway Loop Area, SE Gulf Coast, TX, ~ 10%-55% WI -- The Company is currently drilling the Baxter A-141 1H (45% WI) and the BK Estes 01 (42% WI). Production results for both wells are expected later this quarter.

Central Utah Hingeline Project, UT, 65% WI -- The Company began drilling the Federal 23-44 well on the Parowan prospect located in Iron County, UT on October 9, 2007. The well is expected to reach its first primary objective (Navajo formation) in November and total depth later this year.

Columbia River Basin, WA -- The Company is continuing with the design for drilling and completion procedures for the Gray 33-23, which is located in the southern portion of the Columbia River Basin on the Company's Bronco prospect. The Bronco prospect is mapped as a large structural anticline with significant reserve potential, based on its structural height and aerial extent, and is projected to cover approximately one township.

The Company's primary objectives in the Columbia River Basin are the tight gas sands of the Roslyn formation, which is approximately 4,500 feet thick. The Roslyn formation is projected to be a basin-centered gas accumulation trapped on structural anticlines. During the past few years, EnCana Oil and Gas (USA) Inc. ("EnCana") has drilled three wells in the basin. Based on Delta's geologic interpretation and log analyses, two of the wells did not reach the Roslyn or encountered only a few hundred feet of the formation. Of the three wells drilled by EnCana, only the Anderville Farms 1-6 penetrated the Roslyn formation, and that well drilled less than 25% of the formation.

It is the Company's opinion that, in order to fully test the Roslyn formation, a well should be drilled on a structural high and completely through the formation, which will allow for all the tight gas sands to be completed and thereby benefit from the cumulative effect of gas contribution from numerous sands. The Shell BN 1-9, which was drilled in the early 1980s and prior to the advent of multiple-stage frac technology, completed only two sands, yet had a combined production of approximately 5 Mmcf/d. The Company remains optimistic as to the potential of the basin and is currently discussing participation with other companies within the industry to drill the Gray 33-23 well on the Bronco prospect.

PRODUCTION GUIDANCE

The Company reaffirms its production guidance for the fourth quarter of 2007 of 4.95 to 5.13 Bcfe. The Company also reaffirms its previously stated production guidance of 40% to 60% growth from 2007 to 2008.

ANALYST CONFERENCE

The Company will host an analyst conference on December 13, 2007 in Denver, Colorado. The conference will be made available by webcast and presentation materials will be posted on the Company's website beginning December 13, 2007. Additional details will be forthcoming.

EARNINGS RELEASE AND INVESTOR CONFERENCE CALL

An investor conference call has been scheduled for 12:00 noon EST today, Thursday, November 8, 2007.

Shareholders and other interested parties may participate in the conference call by dialing 800-688-0836 (international participants dial 617-614-4072) and referencing the ID code 65960471, a few minutes before 12:00 noon EST on November 8, 2007. The call will also be broadcast live on the Internet at http://phx.corporate-ir.net/playerlink.zhtml?c=117007&s=wm&e=1682339 or can be accessed through the Company's website at http://www.deltapetro.com/eventscalendar.html. A replay of the conference call will be available two hours after the completion of the conference call from November 8, 2007 until November 15, 2007 by dialing 888-286-8010 (international participants dial 617-801-6888) and entering the conference ID 27890543. The call will also be archived on the Internet through February 8, 2007 at http://phx.corporate-ir.net/playerlink.zhtml?c=117007&s=wm&e=1682339.

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 and projections in this announcement are made pursuant to the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Any such projections or statements reflect Delta Petroleum's current views about future events and operating and financial performance. Investors are cautioned that no assurances can be given that such events or performance will occur as projected, and actual results may differ materially from those projected. Important factors that could cause the actual results to differ materially from those projected include, without limitation, the volatility in commodity prices for oil and natural gas, including basis differentials in product pricing among different producing regions, the presence or recoverability of estimated reserves, the ability to replace reserves, environmental risks, drilling and operating risks, exploration and development risks, and the inherent uncertainties in interpreting engineering data relating to underground accumulations of oil and gas; unsuccessful exploratory drilling activities; lack of exploration success competition, government regulation or other action, the ability of management to execute its plans to meet its goals and other risks inherent in Delta Petroleum's business that are detailed in its Securities and Exchange Commission filings on Forms 10-K, 10-Q and 8-K. Delta Petroleum is under no obligation (and expressly disclaims any such 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 September 30, December 31, 2007 2006 (Unaudited) (In thousands, except share amounts) ASSETS Current assets: Cash and cash equivalents $21,902 $7,666 Marketable securities 12,700 -- Oil and gas properties held for sale 243 5,397 Trade accounts receivable, net of allowance for doubtful accounts of $100 and $100, respectively 31,065 29,503 Prepaid assets 6,155 4,384 Inventory 3,807 2,851 Derivative instruments 8,129 10,799 Other current assets 2,912 2,769 Total current assets 86,913 63,369 Property and equipment: Oil and gas properties, successful efforts method of accounting Unproved 224,897 218,380 Proved 734,823 591,149 Drilling and trucking equipment 153,549 136,038 Pipeline and gathering system 23,909 14,909 Other 14,762 13,983 Total property and equipment 1,151,940 974,459 Less accumulated depreciation and depletion (243,675) (132,814) Net property and equipment 908,265 841,645 Long-term assets: Derivative instruments 645 -- Deferred financing costs 8,197 6,928 Goodwill 7,747 7,747 Other long-term assets 15,260 6,723 Investment in unconsolidated affiliates 9,694 2,932 Total long-term assets 41,543 24,330 Total assets $1,036,721 $929,344 LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Current portion of long-term debt $989 $816 Accounts payable 89,890 84,439 Other accrued liabilities 14,746 10,818 Deferred tax liability -- 2,893 Derivative instruments 977 613 Total current liabilities 106,602 99,579 Long-term liabilities: 7% Senior notes, unsecured 149,441 149,384 3 3/4% Senior convertible notes 115,000 -- Credit facility 5,000 118,000 Unsecured term loan -- 25,000 Credit facility - DHS 79,034 74,050 Asset retirement obligation and other debt, net 4,143 4,048 Derivative instruments 145 -- Deferred tax liability 10,762 3,660 Total long-term liabilities 363,525 374,142 Minority interest 27,611 27,390 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 66,421,000 shares at September 30, 2007 and 53,439,000 at December 31, 2006 664 534 Additional paid-in capital 661,167 430,479 Accumulated other comprehensive income 4,166 4,865 Accumulated deficit (127,014) (7,645) Total stockholders' equity 538,983 428,233 Total liabilities and stockholders' equity $1,036,721 $929,344 DELTA PETROLEUM CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) Three Months Ended Nine Months Ended September 30, September 30, 2007 2006 2007 2006 (In thousands, except per share amounts) Revenue: Oil and gas sales $30,938 $26,123 $84,670 $81,373 Contract drilling and trucking fees 14,915 17,194 45,317 40,239 Gain (loss) on effective derivative instruments, net 5,998 (653) 10,543 (5,434) Total revenue 51,851 42,664 140,530 116,178 Operating expenses: Lease operating expense 5,712 4,806 14,692 13,568 Transportation expense 1,142 434 2,816 1,169 Production taxes 1,814 1,287 4,909 4,285 Depreciation, depletion and amortization -- oil and gas 19,547 16,466 53,217 38,800 Depreciation and amortization -- drilling and trucking 5,803 4,637 16,518 11,101 Exploration expense 4,742 1,226 6,138 3,402 Dry hole costs and impairments 273 11,256 72,851 12,642 Drilling and trucking operations 9,655 10,680 29,671 24,173 General and administrative 12,816 9,792 37,289 26,849 Loss (gain) on sale of oil and gas properties -- 67 -- (18,849) Total operating expenses 61,504 60,651 238,101 117,140 Operating loss (9,653) (17,987) (97,571) (962) Other income and (expense): Other income 32 (52) 619 (85) Gain on sale of investment in LNG -- -- -- 1,058 Gain on ineffective derivative instruments, net 3,153 2,962 2,479 11,504 Minority interest (319) (716) (11) (1,575) Earnings (losses) from unconsolidated affiliates (51) -- (51) -- Interest and financing costs, net (5,119) (6,350) (18,055) (18,852) Total other expense (2,304) (4,156) (15,019) (7,950) Loss from continuing operations before income taxes and discontinued operations (11,957) (22,143) (112,590) (8,912) Income tax expense (benefit) (769) (8,329) 4,702 (3,365) Loss from continuing operations (11,188) (13,814) (117,292) (5,547) Discontinued operations: Income from discontinued operations of properties sold, net of tax 457 1,004 2,152 4,040 Gain (loss) on sale of discontinued operations, net of tax 4,313 6,053 (4,229) 6,689 Income (loss) before extraordinary gain, net of tax (6,418) (6,757) (119,369) 5,182 Extraordinary gain (loss), net of tax -- (323) -- 5,753 Net income (loss) $(6,418) $(7,080) $(119,369) $10,935 Basic income (loss) per common share: Income (loss) from continuing operations $(0.17) $(0.25) $(1.95) $(0.10) Discontinued operations 0.07 0.13 (0.03) 0.20 Extraordinary gain, net of tax -- (0.01) -- 0.11 Net income (loss) $(0.10) $(0.13) $(1.98) $0.21 Diluted income (loss) per common share: Income (loss) from continuing operations $(0.17) $(0.25) $(1.95) $(0.10) Discontinued operations 0.07 0.13 (0.03) 0.20 Extraordinary gain, net of tax -- (0.01) -- 0.11 Net income (loss) $(0.10) $(0.13) $(1.98) $0.21 Weighted average common shares outstanding: Basic 64,930 52,990 60,299 51,687 Diluted 64,930 54,106 60,299 52,833 DELTA PETROLEUM CORPORATION RECONCILIATION OF DISCRETIONARY CASH FLOW AND EBITDAX (in thousands) (unaudited) THREE MONTHS ENDED: September 30, September 30, 2007 2006 CASH PROVIDED BY OPERATING ACTIVITIES $17,079 $(474) Changes in assets and liabilities (1,470) 14,428 Exploration and dry hole costs 4,742 1,226 Discretionary Cash Flow* $20,351 $15,180 NINE MONTHS ENDED: September 30, September 30, 2007 2006 CASH PROVIDED BY OPERATING ACTIVITIES $41,791 $28,224 Changes in assets and liabilities 3,518 13,789 Exploration and dry hole costs 7,131 4,496 Discretionary Cash Flow* $52,440 $46,509 * 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: September 30, September 30, 2007 2006 Net income (loss) $(6,418) $(7,080) Income tax expense (benefit) (769) (4,844) Interest and financing costs 5,119 6,350 Depletion, depreciation and amortization 25,904 24,197 (Gain) loss on sale of oil and gas properties and other investments (4,313) (9,162) Unrealized (gain) loss on derivative contracts (3,153) (3,038) Exploration and dry hole costs 5,015 12,482 EBITDAX** $21,385 $18,905 THREE MONTHS ENDED: September 30, September 30, 2007 2006 CASH PROVIDED BY OPERATING ACTIVITIES $17,079 $(474) Changes in assets and liabilities (1,470) 14,428 Interest net of financing costs 4,338 5,918 Exploration and dry hole costs 4,742 1,226 Other non-cash items (3,304) (2,193) EBITDAX** $21,385 $18,905 NINE MONTHS ENDED: September 30, September 30, 2007 2006 Net income (loss) $(119,369) $10,935 Income tax expense (benefit) 6,707 5,869 Interest and financing costs 18,055 18,852 Depletion, depreciation and amortization 72,219 58,587 (Gain) loss on sale of oil and gas properties and other investments 2,310 (39,748) Unrealized (gain) loss on derivative contracts (2,479) (12,026) Exploration and dry hole costs 78,989 16,044 EBITDAX** $56,432 $58,513 NINE MONTHS ENDED: September 30, September 30, 2007 2006 CASH PROVIDED BY OPERATING ACTIVITIES $41,791 $28,224 Changes in assets and liabilities 3,518 13,789 Interest net of financing costs 15,935 17,295 Exploration and dry hole costs 7,131 4,496 Other non-cash items (11,943) (5,291) EBITDAX** $56,432 $58,513 ** 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.

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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