exv99w1

Exhibit 99.1

DELTA PETROLEUM CORPORATION
Roger A. Parker, Chairman and CEO
John R. Wallace, President and COO
Kevin K. 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 THIRD QUARTER 2008 OPERATING RESULTS

DENVER, Colorado (November 6, 2008) — Delta Petroleum Corporation (Delta or the Company) (NASDAQ Global Market: DPTR), an independent oil and gas exploration and development company, today announced its financial and operating results for the third quarter and nine months of 2008.

THIRD QUARTER HIGHLIGHTS

	•		Revenue from oil and gas sales increased 112% to $49.0 million

	•		Total revenue increased 39% to $60.8 million

	•		EBITDAX (a non-GAAP measure) increased 98% to $42.9 million

	•		Production from continuing operations increased 64%

	•		Announced 50/50 joint venture in the Columbia River Basin

	•		Unaudited proved reserves increased to 657 billion cubic feet equivalents (Bcfe)

RESULTS FOR THE THIRD QUARTER

For the quarter ended September 30, 2008, the Company reported total production of 6.57 Bcfe, which was consistent with upper levels of previously stated guidance. Production from continuing operations increased 64%, when compared with the prior-year quarter, and rose 7% from the levels recorded during the second quarter of 2008. Total revenue increased 39% to $60.8 million in the third quarter, compared with $43.9 million in the quarter ended September 30, 2007. Revenue from oil and gas sales increased 112% to $49.0 million, versus $23.1 million in the prior-year quarter. The increase in oil and gas revenue when compared with the corresponding period of the previous year reflects higher production from continuing operations and higher commodity prices. Revenue from contract drilling and trucking fees decreased 24% to $11.8 million, versus $15.5 million in the third quarter of 2007, resulting from inter-company eliminations due to additional DHS rigs working for Delta. EBITDAX increased 98% to $42.9 million during the three months ended September 30, 2008, compared with $21.7 million in the three months ended September 30, 2007. Discretionary cash flow increased 81% to $37.5 million, versus $20.7 million in the comparable 2007 quarter. (Note: EBITDAX and Discretionary Cash Flow are non-GAAP measures that are described in greater detail below.)

For the quarter ended September 30, 2008, the Company reported net income of $49.8 million, or $0.48 per diluted share, compared with a net loss of ($5.0 million), or ($0.08) per share, in the year-earlier quarter. The current period results include a $54.8 million non-cash gain representing the unrealized mark-to-market change in the Company’s derivative contracts, and an $11.3 million realized gain from terminated derivative contracts.

THIRD 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 September 30, 2008 and 2007 were as follows:


	Three Months Ended
	September 30,
	2008			2007
Production — Continuing Operations:
Oil (MBbl)		201			215
Gas (MMcf)		4,581			2,233
Production — Discontinued Operations:
Oil (MBbl)		46			64
Gas (MMcf)		508			674

Total Production (MMcfe)		6,569			4,581

Average Price — Continuing Operations:
Oil (per barrel)	$	107.76		$	70.35
Gas (per Mcf)	$	5.97		$	3.58

Costs per Mcfe — Continuing Operations:
Lease operating expense	$	1.26		$	1.56
Production taxes	$	0.55		$	0.37
Transportation costs	$	0.61		$	0.24
Depletion expense	$	4.28		$	4.35

Realized derivative gain	$	1.87	¹	$	1.70


¹		Realized derivative gains for the three months ended September 30, 2008 include $11.3 million or $1.94 per Mcfe related to the cash settlement of the Company’s 2009 NYMEX gas derivative contracts.

RESULTS FOR THE NINE-MONTH PERIOD

During the nine months ended September 30, 2008, oil and gas sales from continuing operations increased 147% to $156.1 million, compared with $63.3 million in the comparable period a year earlier. The increase resulted from a 69% growth in production from continuing operations, a 69% increase in oil prices, and a 66% increase in gas prices. Drilling and trucking revenue decreased 35% to $30.4 million, from $46.5 million in the prior-year period, as a result of inter-company eliminations due to additional DHS rigs working for Delta. EBITDAX increased 97% and totaled $112.2 million in the first nine months of 2008, compared with $57.0 million in the nine months ended September 30, 2007. Discretionary cash flow increased 105% to $106.8 million in the nine months ended September 30, 2008, versus $52.1 million in the corresponding period of the previous year.

For the nine months ended September 30, 2008, the Company reported net income of $7.7 million, or $0.08 per diluted share, compared with a net loss of ($118.7 million), or ($1.97) per diluted share, in the nine months ended September 30, 2007. Results for the nine months ended September 30, 2008 included a $13.6 million non-cash gain representing the unrealized mark-to-market change in the Company’s derivative contracts, and dry hole costs of $10.9 million. During the nine months ended September 30, 2007, the Company reported $75.0 million of dry hole costs and impairments.

NINE MONTH PRODUCTION VOLUMES, UNIT PRICES AND COSTS

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


	Nine Months Ended
	September 30,
	2008			2007
Production — Continuing Operations:
Oil (MBbl)		639			618
Gas (MMcf)		12,032			5,692
Production — Discontinued Operations:
Oil (MBbl)		121			200
Gas (MMcf)		1,498			2,137

Total Production (MMcfe)		18,091			12,735

Average Price — Continuing Operations:
Oil (per barrel)	$	103.07		$	60.82
Gas (per Mcf)	$	7.50		$	4.51

Costs per Mcfe — Continuing Operations:
Lease operating expense	$	1.48		$	1.51
Production taxes	$	0.63		$	0.37
Transportation costs	$	0.48		$	0.25
Depletion expense	$	4.02		$	4.70

Realized derivative gain	$	0.13	¹	$	1.12


¹		Realized derivative gains for the nine months ended September 30, 2008 include $11.3 million or $0.71 per Mcfe related to the cash settlement of the Company’s 2009 NYMEX gas derivative contracts.

The depletion rate decrease to $4.02 per Mcfe for the nine months ended September 30, 2008, from $4.70 per Mcfe in the year-earlier period, primarily reflects increased reserve additions and lower costs per well in the Piceance Basin capital development program, along with a higher mix of production from Rocky Mountain properties.

DERIVATIVE CONTRACTS

The following table summarizes the Company’s open derivative contracts as of November 6, 2008:


		Price Floor /
Commodity	Volume	Price Ceiling	Term	Index
Natural gas	15,000 MMBtu / day	$6.50 / $8.30	Oct ‘08 — Dec ‘08	CIG
Natural gas	10,000 MMBtu / day	$6.50 / $7.90	Oct ‘08 — Dec ‘08	CIG

The Company closed many of its derivative contracts at the end of the third quarter and the beginning of the fourth quarter of 2008 for total realized cash gains of $20.5 million. Approximately $11.3 million of the gains were realized in the third quarter, while the remaining $9.2 million in gains were realized early in the fourth quarter.

OPERATIONS UPDATE

Piceance Basin, CO, 31% — 100% WI — Current production from the Piceance Basin approximates 63 Mmcfe/d gross and 51.5 Mmcfe/d net. In the Vega area, the Company continues to realize increased initial production rates on the recently completed wells due to improved frac design and thicker pay columns, with some wells having initial rates in excess of 3 Mmcfe/d. Average drilling time has decreased to 13 days for new wells. As previously announced, 2009 drilling capital expenditures will be reduced, and as such the Company will continually monitor its active drilling rig count in the Piceance Basin. Due to drilling multiple wells on specific drilling pads, the Company will have an inventory of approximately 30 drilled but not yet completed wells at year end. The combination of reduced drilling activity, but consistent completion activity is expected to allow for overall production growth for all of 2009.

The Company also previously announced that it is exploring joint venture alternatives for its Piceance Basin assets. The Company believes that its current market capitalization does not adequately reflect true value for its Piceance Basin properties. Drilling results continue to support the expectation that the total resource potential of the Company’s approximate 25,000 net acres of leasehold in the Piceance Basin may exceed 2.5 trillion cubic feet of natural gas equivalents (Tcfe).

Paradox Basin, UT, 70% WI — The Company continues to produce from the Greentown Federal 28-11, which had an initial production rate of 7.4 Mmcfe/d and is currently producing over 1.5 Mmcfe/d. The Company estimates that the initial six-month production trend demonstrates that the well will recover approximately 2.0 Bcfe. The Company recently drilled the Greentown Federal 11-24 and redrilled the Greentown Federal 26-43D through the “O” interval. Additionally, the Company had previously drilled the Greentown State 31-36 and Greentown State 36-24H horizontally in the “O.” The Greentown Federal 26-43D has been fracture stimulated and is currently flowing back. For various reasons, completion attempts in the “O” interval in each of the other three wells have experienced inconclusive results and are the subject of further review for effective completion techniques. As previously announced the Company experienced significant production testing results from both the initial wells drilled in the prospect, and despite geologic challenges and mixed results from the “O” interval, the Company believes the “O” interval is a viable target and will contribute commercial hydrocarbons in future completion attempts.

The geologic model defining the Greentown area continues to be one of multiple stacked clastic zones encased in a salt formation, and although efforts have been focused on the “O” interval, there remain numerous clastic zones to be targeted and completed. The initial uphole completion efforts of five of the 20 total clastic intervals in the Greentown State 32-42 yielded substantial hydrocarbons before the well experienced collapsed casing. Additionally, there are several drill stem tests from older wells in the area that tested meaningful rates from various clastic intervals. The Company continues to be optimistic that many of the clastic intervals will contribute additional hydrocarbons and therefore add to the economic viability of future drilling. Delta plans to attempt up to 35 separate completions in the four most recently drilled wells over the course of the next several

months. Due to the previously stated intent to reduce drilling capital expenditures, the Company has elected to release the drilling rigs for the near term, although completion rigs will remain on location for the testing of multiple clastic intervals.

Columbia River Basin, WA, 50% WI — The Company is drilling the Gray 31-23 well (Bronco Prospect) in Klickitat County, Washington. Drilling penetration rates have recently been encouraging and previous geophysical interpretations appear to be reliable. Due to existing agreements and the confidential nature of this well, more detailed information will not be released at this time.

Central Utah Hingeline Project, UT, 65% WI — The Company has drilled the Beaver Federal 21-14 to its initial permitted depth without reaching the prospect-defining thrust fault. The current operation is running electric logs and performing a borehole seismic procedure to determine if the well should be drilled deeper.

The Company has performed completion activities on the Federal 23-44 in the Parowan prospect. No commercial accumulations of hydrocarbons were encountered and the well is being plugged and abandoned. The well was initially expensed as a dry hole in the fourth quarter of 2007, with additional completion costs expensed in the third quarter of 2008 for recent activities.

Midway Loop Area, SE Gulf Coast, TX, ~ 15% — 80% WI — The Company is drilling the Carter A-144 (77% WI) well and participating in the Black Stone A-319 (25% WI). Both wells are expected to reach total depth within the next 30 days. Divestiture efforts for the Midway Loop project continue.

HAYNESVILLE SHALE

Haynesville Shale, East TX and LA, ~ 33 — 100% WI — The Company acquired rights to 16,000 net acres in the Haynesville Shale during the second and third quarters of 2008. The acreage position is concentrated in Caddo Parish, Louisiana, and Harrison, Shelby and Nacogdoches counties, Texas. The costs to acquire the leasehold rights have totaled approximately $35 million, most of which were incurred during the third quarter of 2008. The Company will use existing personnel from its southeast Texas operations and expects to begin drilling an initial well in early 2009.

DRILLING CAPITAL EXPENDITURE GUIDANCE FOR 2009

As previously stated, the Company plans 2009 drilling capital expenditures to be within the Company’s operating cash flow and proceeds from properties already held for sale. Therefore 2009 drilling capital expenditures are expected range between $150 — 175 million. Areas of activity for 2009 are likely to include the Piceance Basin, Paradox Basin, Utah Hingeline, Columbia River Basin and the Haynesville Shale.

PRODUCTION GUIDANCE

Production for the third quarter totaled 6.57 Bcfe, despite approximately 0.22 Bcfe of curtailed production due to hurricane-related factors. As previously announced, the Company has begun to reduce drilling and completion activities in accordance with its plans to lower capital expenditures and as such, the Company is projecting fourth quarter production to increase to 6.7 to 6.9 Bcfe. Forecasted full year 2008 production is expected to be 24.8 to 25.0 Bcfe, which is at the lower end of the Company’s original 2008 guidance of a 40% to 60% production increase over 2007 levels. Due to hurricane-related factors and reduced fourth quarter 2008 drilling capital expenditures, 2008 production will be slightly below the Company’s previously revised guidance of 45% to 60% over 2007.

INVESTOR CONFERENCE CALL

An investor conference call has been scheduled for 12:00 noon EST today, Thursday, November 6, 2008.

Shareholders and other interested parties may participate in the conference call by dialing 800-860-2442 (international callers dial 412-858-4600) and asking to be connected to the “Delta Petroleum Conference Call” a few minutes before 12:00 noon Eastern time on November 6, 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 November 6, 2008 until November 14, 2008 by dialing 877-344-7529 (international callers dial 412-317-0088) and entering the conference ID 424757#.

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 657 Bcfe and that our drilling results in the Piceance Basin continue to support the expectation that the total resource potential of our acreage may exceed 2.5 Tcfe. These are internally prepared estimates that have 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 September 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
SOURCE: Delta Petroleum Corporation

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)


	September 30,			December 31,
	2008			2007
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	79,230		$	9,793
Trade accounts receivable, net of allowance for doubtful accounts of $619 and $644, respectively		50,611			38,761
Prepaid assets		13,295			3,943
Derivative instruments		8,622			2,930
Deferred tax assets		150			150
Assets held for sale		88,159			63,749
Other current assets		6,161			10,214

Total current assets		246,228			129,540

Property and equipment:
Oil and gas properties, successful efforts method of accounting:
Unproved		528,612			247,466
Proved		1,208,140			749,393
Drilling and trucking equipment		188,209			146,097
Inventories		7,123			4,236
Pipeline and gathering system		61,152			22,140
Other		43,238			19,069

Total property and equipment		2,036,474			1,188,401
Less accumulated depreciation and depletion		(327,440	)		(245,153	)

Net property and equipment		1,709,034			943,248


Long-term assets:
Long-term restricted deposit		300,000			—
Marketable securities		3,520			6,566
Investments in unconsolidated affiliates		16,740			10,281
Deferred financing costs		6,443			7,187
Derivative instruments		3,948			—
Goodwill		7,747			7,747
Other long-term assets		15,278			6,075

Total long-term assets		353,676			37,856


Total assets	$	2,308,938		$	1,110,644


LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Current portion of long-term debt	$	—		$	13
Accounts payable		139,341			119,783
Other accrued liabilities		20,736			17,105
Derivative instruments		2,362			6,295

Total current liabilities		162,439			143,196

Long-term liabilities:
Installments payable on property acquisition, net		283,938			—
7% Senior notes, unsecured		149,516			149,459
3³/4% Senior convertible notes		115,000			115,000
Credit facility — Delta		244,500			73,600
Credit facility — DHS		95,988			75,000
Asset retirement obligations		5,531			4,154
Deferred tax liabilities		8,686			9,085

Total long-term liabilities		903,159			426,298

Minority interest		39,879			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 103,378,000 shares at September 30, 2008, and 66,429,000 shares at December 31, 2007		1,034			664
Additional paid-in capital		1,346,801			664,733
Treasury stock at cost; 25,000 shares at September 30, 2008 and none at December 31, 2007		(495	)		—
Accumulated deficit		(143,879	)		(151,543	)

Total stockholders’ equity		1,203,461			513,854


Total liabilities and stockholders’ equity	$	2,308,938		$	1,110,644

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
				(In thousands, except per share amounts)
Revenue:
Oil and gas sales	$	49,025		$	23,106		$	156,128		$	63,272
Contract drilling and trucking fees		11,760			15,549			30,355			46,468
Gain on hedging instruments, net		—			5,210			—			9,755


Total revenue		60,785			43,865			186,483			119,495


Operating expenses:
Lease operating expense		7,278			5,482			23,471			14,194
Transportation expense		3,548			828			7,648			2,324
Production taxes		3,196			1,301			10,067			3,476
Exploration expense		2,870			4,742			5,805			6,138
Dry hole costs and impairments		8,148			273			10,917			74,984
Depreciation, depletion, amortization and accretion — oil and gas		25,458			15,859			65,618			45,712
Drilling and trucking operations		8,245			9,972			20,597			30,217
Depreciation and amortization — drilling and trucking		2,722			4,038			9,574			12,844
General and administrative		14,890			12,816			42,138			37,289


Total operating expenses		76,355			55,311			195,835			227,178


Operating loss		(15,570	)		(11,446	)		(9,352	)		(107,683	)


Other income and (expense):
Other income (expense)		(3,897	)		32			(3,624	)		619
Realized gain on derivative instruments, net		10,820			788			2,055			788
Unrealized gain on derivative instruments, net		54,779			3,153			13,574			2,479
Minority interest		147			(319	)		355			(11	)
Income (loss) from unconsolidated affiliates		2,122			(51	)		2,813			(51	)
Interest income		3,142			1,084			8,400			2,055
Interest expense and financing costs		(10,573	)		(6,203	)		(27,182	)		(20,110	)


Total other income (expense), net		56,540			(1,516	)		(3,609	)		(14,231	)


Income (loss) from continuing operations before income taxes and discontinued operations		40,970			(12,962	)		(12,961	)		(121,914	)

Income tax expense (benefit)		(2,174	)		(65	)		(3,632	)		6,185


Income (loss) from continuing operations		43,144			(12,897	)		(9,329	)		(128,099	)

Discontinued operations:
Income from discontinued operations of properties sold or held for sale, net of tax		5,972			3,544			16,274			13,622
Gain (loss) on sale of discontinued operations, net of tax		716			4,313			719			(4,229	)


Net income (loss)	$	49,832		$	(5,040	)	$	7,664		$	(118,706	)


Basic income (loss) per common share:
Income (loss) from continuing operations	$	0.43		$	(0.20	)	$	(0.10	)	$	(2.12	)
Discontinued operations		0.06			0.12			0.18			0.15

Net income (loss)	$	0.49		$	(0.08	)	$	0.08		$	(1.97	)


Diluted income (loss) per common share:
Income (loss) from continuing operations	$	0.42		$	(0.20	)	$	(0.10	)	$	(2.12	)
Discontinued operations		0.06			0.12			0.18			0.15

Net income (loss)	$	0.48		$	(0.08	)	$	0.08		$	(1.97	)


Weighted average common shares outstanding:
Basic		101,227			64,930			95,365			60,299
Diluted		102,790			64,930			96,994			60,299

DELTA PETROLEUM CORPORATION
RECONCILIATION OF DISCRETIONARY CASH FLOW AND EBITDAX
(in thousands)
(unaudited)


	September 30,			September 30,
THREE MONTHS ENDED:	2008			2007
CASH PROVIDED BY OPERATING ACTIVITIES	$	44,159		$	17,835

Changes in assets and liabilities		(9,549	)		(1,858	)
Exploration expense		2,870			4,742

Discretionary Cash Flow*	$	37,480		$	20,719


	September 30,		September 30,
NINE MONTHS ENDED:	2008		2007
CASH PROVIDED BY OPERATING ACTIVITIES	$	93,318	$	43,258

Changes in assets and liabilities		7,674		2,707
Exploration expense		5,805		6,138

Discretionary Cash Flow*	$	106,797	$	52,103


*		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.


	September 30,			September 30,
THREE MONTHS ENDED:	2008			2007
Net income (loss)	$	49,832		$	(5,040	)

Income tax expense (benefit)		(2,174	)		(65	)
Interest income		(3,142	)		(1,084	)
Interest and financing costs		10,573			6,203
Depletion, depreciation and amortization		32,327			24,140
Loss on sale of oil and gas properties and other investments		(716	)		(4,313	)
Unrealized (gain) loss on derivative contracts		(54,779	)		(3,153	)
Exploration and dry hole costs		11,018			5,015

EBITDAX**	$	42,939		$	21,703


	September 30,			September 30,
THREE MONTHS ENDED:	2008			2007
CASH PROVIDED BY OPERATING ACTIVITIES	$	44,159		$	17,835

Changes in assets and liabilities		(9,549	)		(1,858	)
Interest net of financing costs		4,488			4,338
Exploration and dry hole costs		8,788			4,742
Other non-cash items		(4,947	)		(3,354	)

EBITDAX**	$	42,939		$	21,703


	September 30,			September 30,
NINE MONTHS ENDED:	2008			2007
Net income (loss)	$	7,664		$	(118,706	)

Income tax expense (benefit)		(3,632	)		8,190
Interest income		(8,400	)		(2,055	)
Interest and financing costs		27,182			20,110
Depletion, depreciation and amortization		86,969			68,545
(Gain) loss on sale of oil and gas properties and other investments		(719	)		2,310
Unrealized loss on derivative contracts		(13,574	)		(2,479	)
Exploration and dry hole costs		16,722			81,122

EBITDAX**	$	112,212		$	57,037


	September 30,			September 30,
NINE MONTHS ENDED:	2008			2007
CASH PROVIDED BY OPERATING ACTIVITIES	$	93,318		$	43,258

Changes in assets and liabilities		7,674			2,707
Interest net of financing costs		11,583			15,935
Exploration and dry hole costs		11,991			7,131
Other non-cash items		(12,354	)		(11,994	)

EBITDAX**	$	112,212		$	57,037


**		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.