e10vq

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2008


o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number 0-16203

DELTA PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)


Delaware (State or other jurisdiction of incorporation or organization)		84-1060803 (I.R.S. Employer Identification No.)

370 17th Street, Suite 4300 Denver, Colorado (Address of principal executive offices)		80202 (Zip Code)

(303) 293-9133
(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):


Large accelerated filer þ	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o
		(Do not check if a smaller reporting company)

Indicate by a check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act): Yes o No þ

102,534,849 shares of common stock, $.01 par value per share, were outstanding as of May 6, 2008.

PART I. FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(Unaudited)


	March 31,			December 31,
	2008			2007
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	37,881		$	9,793
Certificates of deposit		35,000			—
Assets held for sale		68,153			62,744
Trade accounts receivable, net of allowance for doubtful accounts of $664 and $664, respectively		51,272			38,761
Prepaid assets		8,829			3,943
Inventories		5,988			4,236
Derivative instruments		—			2,930
Deferred tax assets		150			150
Other current assets		11,853			10,214

Total current assets		219,126			132,771

Property and equipment:
Oil and gas properties, successful efforts method of accounting:
Unproved		534,553			247,466
Proved		929,467			740,408
Drilling and trucking equipment		170,933			146,097
Pipeline and gathering system		35,782			22,140
Other		22,806			19,069

Total property and equipment		1,693,541			1,175,180
Less accumulated depreciation and depletion		(271,494	)		(245,153	)

Net property and equipment		1,422,047			930,027


Long-term assets:
Long-term restricted deposit		301,174			—
Marketable securities		5,982			6,566
Investments in unconsolidated affiliates		10,976			10,281
Deferred financing costs		6,664			7,187
Goodwill		7,747			7,747
Other long-term assets		12,220			10,616

Total long-term assets		344,763			42,397


Total assets	$	1,985,936		$	1,105,195


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt	$	13,104		$	13
Accounts payable		125,266			119,783
Other accrued liabilities		17,423			17,105
Derivative instruments		17,498			6,295

Total current liabilities		173,291			143,196

Long-term liabilities:
Installments payable on property acquisition, net		280,724			—
7% Senior notes, unsecured		149,478			149,459
3³/4% Senior convertible notes		115,000			115,000
Credit facility – Delta		—			73,600
Credit facility – DHS		61,898			75,000
Asset retirement obligations		4,635			4,154
Deferred tax liabilities		8,716			9,085

Total long-term liabilities		620,451			426,298

Minority interest		33,835			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 102,278,000 shares at March 31, 2008, and 66,429,000 shares at December 31, 2007		1,023			664
Additional paid-in capital		1,336,471			664,733
Treasury stock at cost; 25,000 shares at March 31, 2008 and none at December 31, 2007		(495	)		—
Accumulated other comprehensive loss		(584	)		—
Accumulated deficit		(178,056	)		(156,992	)

Total stockholders’ equity		1,158,359			508,405


Total liabilities and stockholders’ equity	$	1,985,936		$	1,105,195

See accompanying notes to consolidated financial statements.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)


	Three Months Ended
	March 31,
	2008			2007
	(In thousands, except per share amounts)
Revenue:
Oil and gas sales	$	45,444		$	19,438
Contract drilling and trucking fees		10,547			16,294
Gain on hedging instruments, net		—			1,190


Total revenue		55,991			36,922


Operating expenses:
Lease operating expense		7,621			4,015
Transportation expense		1,740			851
Production taxes		3,012			1,121
Exploration expense		1,002			624
Dry hole costs and impairments		2,339			3,517
Depreciation, depletion, amortization and accretion – oil and gas		19,348			15,701
Drilling and trucking operations		6,725			10,464
Depreciation and amortization – drilling and trucking		5,563			5,134
General and administrative		13,421			11,545


Total operating expenses		60,771			52,972


Operating loss		(4,780	)		(16,050	)


Other income and (expense):
Other income		457			75
Realized loss on derivative instruments, net		(1,635	)		—
Unrealized loss on derivative instruments, net		(14,133	)		(1,663	)
Minority interest		329			17
Losses from unconsolidated affiliates		(108	)		—
Interest income		1,870			76
Interest and financing costs		(7,950	)		(7,595	)


Total other expense		(21,170	)		(9,090	)


Loss from continuing operations before income taxes and discontinued operations		(25,950	)		(25,140	)

Income tax benefit		(1,320	)		(8,575	)


Loss from continuing operations		(24,630	)		(16,565	)

Discontinued operations:
Income from discontinued operations of properties sold, net of tax		3,546			2,483
Gain (loss) on sale of discontinued operations, net of tax		20			(4,662	)


Net loss	$	(21,064	)	$	(18,744	)


Basic income (loss) per common share:
Loss from continuing operations	$	(0.31	)	$	(0.30	)
Discontinued operations		0.05			(0.04	)

Net income (loss)	$	(0.26	)	$	(0.34	)


Diluted income (loss) per common share:
Loss from continuing operations	$	(0.31	)	$	(0.30	)
Discontinued operations		0.05			(0.04	)

Net income (loss)	$	(0.26	)	$	(0.34	)

See accompanying notes to consolidated financial statements.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY AND
COMPREHENSIVE LOSS
(Unaudited)


																Accumulated
							Additional									other
	Common stock						paid-in			Treasury stock						comprehensive			Comprehensive			Accumulated
	Shares			Amount			capital			Shares			Amount			loss			loss			deficit			Total
	(In thousands)
Balance, January 1, 2008		66,429		$	664		$	664,733			—		$	—		$	—					$	(156,992	)	$	508,405

Comprehensive loss:
Net loss		—			—			—			—			—			—		$	(21,064	)		(21,064	)		(21,064	)
Other comprehensive income transactions, net of tax:
Unrealized loss on available for sale securities		—			—			—			—			—			(584	)		(584	)		—			(584	)

Comprehensive loss																			$	(21,648	)

Treasury stock		—			—			—			(25	)		(495	)		—						—			(495	)
Shares issued for cash, net of offering costs		36,263			363			666,734			—			—			—						—			667,097
Shares issued for cash upon exercise of options		155			2			1,660			—			—			—						—			1,662
Issuance of non-vested stock		198			2			(2	)		—			—			—						—			—
Shares repurchased for withholding taxes		(17	)		—			(240	)		—			—			—						—			(240	)
Cancellation of executive performance shares, tranches 4 and 5		(750	)		(8	)		8			—			—			—						—			—
Stock based compensation		—			—			3,578			—			—			—						—			3,578


Balance, March 31, 2008		102,278		$	1,023		$	1,336,471			(25	)	$	(495	)	$	(584	)				$	(178,056	)	$	1,158,359

See accompanying notes to consolidated financial statements.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)


	Three Months Ended
	March 31,
	2008			2007
	(In thousands)
Cash flows from operating activities:
Net loss	$	(21,064	)	$	(18,744	)
Adjustments to reconcile net loss to cash provided by operating activities:
Depreciation, depletion, amortization and accretion – oil and gas		19,348			15,701
Depreciation and amortization – drilling and trucking		5,563			5,134
Depreciation, depletion and amortization – discontinued operations		3,687			2,495
Stock based compensation		3,578			2,719
DHS stock granted to management		373			70
Amortization of deferred financing costs		790			856
Amortization of discount on installment payable		602			—
Unrealized loss on derivative instruments		14,133			1,663
Dry hole costs and impairments		2,071			2,525
Minority interest		(329	)		(17	)
Loss from unconsolidated affiliates		108			—
(Gain) loss on sale of discontinued operations		(20	)		6,608
Deferred income tax expense (benefit)		(1,320	)		(9,038	)
Other		(13	)		2,635
Net changes in operating assets and operating liabilities:
Increase in trade accounts receivable		(11,932	)		(1,439	)
Increase in prepaid assets		(4,942	)		799
Increase in inventory		(133	)		(284	)
Increase in other current assets		(255	)		(132	)
Increase (decrease) in accounts payable		(7,629	)		869
Increase in other accrued liabilities		4,405			169


Net cash provided by operating activities		7,021			12,589


Cash flows from investing activities:
Additions to property and equipment		(101,161	)		(61,278	)
Acquisitions, net of cash acquired		(114,749	)		(4,500	)
Proceeds from sales of oil and gas properties		—			40,277
Drilling and trucking capital expenditures		(13,723	)		(12,175	)
Increase in certificates of deposit		(35,000	)		—
Increase in restricted deposit		(301,174	)		—
Investment in unconsolidated affiliates		(804	)		—
Increase in note receivable from affiliate		(490	)		—
Increase in other long-term assets		(162	)		(102	)


Net cash used in investing activities		(567,263	)		(37,778	)


Cash flows from financing activities:
Stock issued for cash, net		662,097			56,399
Stock issued for cash upon exercise of options		1,662			—
Shares repurchased for withholding taxes		(240	)		(61	)
Proceeds from borrowings		44,500			48,500
Repayments of borrowings		(118,113	)		(74,231	)
Payment of deferred financing costs		(1,576	)		(52	)


Net cash provided by financing activities		588,330			30,555


Net increase in cash and cash equivalents		28,088			5,366

Cash at beginning of period		9,793			7,666


Cash at end of period	$	37,881		$	13,032

Supplemental cash flow information –
Common stock issued for the acquisition of oil and gas properties	$	—		$	13,848


Cash paid for interest	$	1,479		$	4,079

See accompanying notes to consolidated financial statements.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES

Notes to Consolidated Financial Statements
Three Months Ended March 31, 2008 and 2007
(Unaudited)

(1) Nature of Organization and Basis of Presentation

Delta Petroleum Corporation (“Delta” or the “Company”) was organized December 21, 1984 as a Colorado corporation and is principally engaged in acquiring, exploring, developing and producing oil and gas properties. On January 31, 2006, the Company reincorporated in the State of Delaware. The Company’s core areas of operation are the Rocky Mountain and Gulf Coast regions, which comprise the majority of its proved reserves, production and long-term growth prospects. The Company owns interests in developed and undeveloped oil and gas properties in federal units offshore California, near Santa Barbara, and developed and undeveloped oil and gas properties in the continental United States.

The accompanying unaudited consolidated financial statements have been prepared in accordance with the instructions to Form 10-Q and, in accordance with those rules, do not include all the information and notes required by generally accepted accounting principles for complete financial statements. As a result, these unaudited consolidated financial statements should be read in conjunction with the Company’s audited consolidated financial statements and notes thereto previously filed with the Company’s Annual Report on Form 10-K for the year ended December 31, 2007. In the opinion of management, all adjustments, consisting only of normal recurring accruals, considered necessary for a fair presentation of the financial position of the Company and the results of its operations have been included. Operating results for interim periods are not necessarily indicative of the results that may be expected for the complete fiscal year. For a more complete understanding of the Company’s operations and financial position, reference is made to the consolidated financial statements of the Company, and related notes thereto, filed with the Company’s Annual Report on Form 10-K for the year ended December 31, 2007, previously filed with the Securities and Exchange Commission (“SEC”).

(2) Summary of Significant Accounting Policies

Principles of Consolidation and Basis of Presentation

The consolidated financial statements include the accounts of Delta, Amber Resources Company of Colorado (“Amber”), Piper Petroleum Company (“Piper”), CRB Partners, LLC (“CRBP”), PGR Partners, LLC (“PGR”), DHS Holding Company and DHS Drilling Company (collectively “DHS”), DPCA LLC (“DPCA”) and other subsidiaries with minimal net assets or activity (collectively, the “Company”). All inter-company balances and transactions have been eliminated in consolidation. As Amber is in a net shareholders’ deficit position for the periods presented, the Company has recognized 100% of Amber’s earnings/losses for all periods presented. The Company does not have any off-balance sheet financing arrangements (other than operating leases) or any unconsolidated special purpose entities.

During June 2007, the Company acquired a 50% non-controlling ownership interest in Delta Oilfield Tank Company, LLC (“Delta Oilfield”) for cash consideration of $4.0 million. Delta Oilfield is accounted for using the equity method of accounting and is an unconsolidated affiliate of the Company. In conjunction with the investment, the Company entered into an agreement to finance up to $9.0 million for construction of a plant expansion. As of March 31, 2008, the Company had advanced $9.0 million to Delta Oilfield under this agreement, of which $7.5 million is included in other current assets in the accompanying consolidated balance sheets. The loan is payable quarterly, beginning after the expansion is complete, in an amount equal to 75% of distributable cash of Delta Oilfield, as defined in the agreement, with any remaining balance due December 31, 2010.

Certain of the Company’s oil and gas activities are conducted through partnerships and joint ventures, including CRBP and PGR. The Company includes its proportionate share of assets, liabilities, revenues and expenses from these entities in its consolidated financial statements.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2008 and 2007
(Unaudited)

(2) Summary of Significant Accounting Policies, Continued

Certain reclassifications have been made to amounts reported in the previous period to conform to the current presentation. Among other items, revenues and expenses on properties that were held for sale during the three months ended March 31, 2008 have been reclassified to income from discontinued operations for all periods presented. Such reclassifications had no effect on net loss.

Cash Equivalents

Cash equivalents consist of money market funds. The Company considers all highly liquid investments with maturities at the date of acquisition of three months or less to be cash equivalents.

Marketable Securities

Marketable securities include long-term investments classified as available for sale securities. During 2007, the Company classified these securities as trading securities; however, due to the marketplace changes in late 2007 affecting the liquidity of such investments, the Company reclassified the securities from trading to available for sale as of December 31, 2007. As of March 31, 2008, the marketable securities are recorded in long-term assets in the accompanying consolidated balance sheet and changes in their market value during the three months ended March 31, 2008 were recorded in accumulated other comprehensive loss. If the issuers of the securities are unable to successfully close future auctions and their credit ratings were to deteriorate, the Company may be required to record an impairment charge on these investments.

Oil and Gas Properties Held for Sale

Oil and gas properties held for sale as of March 31, 2008 and December 31, 2007 represent certain properties in Midway Loop, Texas that are for sale.

Inventories

Inventories consist of pipe and other production equipment. Inventories are stated at the lower of cost (principally first-in, first-out) or estimated net realizable value.

Minority Interest

Minority interest represents the 50.0% (47.0% owned by Chesapeake Energy Corporation and 3.0% owned by DHS executive officers and management) interest in DHS at March 31, 2008. During the fourth quarter 2007, the Company acquired the interests of one of the founding officers resulting in an increase in Delta’s ownership of DHS from 49.4% to 50.0%.

Investment in and Earnings (Losses) from Unconsolidated Affiliates

Investments in operating entities where the Company has the ability to exert significant influence, but does not control the operating and financial policies, are accounted for using the equity method and include the Company’s 50% investment in Delta Oilfield and other minor investments. The Company’s share of the earnings or losses of these entities is recorded as earnings (losses) from unconsolidated affiliates in the consolidated statements of operations. Investments in operating entities where the Company does not exert significant influence are accounted for using the cost method, and income is only recognized when a distribution is received. Investments in unconsolidated affiliates were $11.0 million and $10.3 million as of March 31, 2008 and December 31, 2007, respectively.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2008 and 2007
(Unaudited)

(2) Summary of Significant Accounting Policies, Continued

Revenue Recognition

Oil and gas

Revenues are recognized when title to the products transfers to the purchaser. The Company follows the “sales method” of accounting for its natural gas and crude oil revenue. Under that method, the Company recognizes sales revenue on all natural gas or crude oil sold to its purchasers, regardless of whether the sales are proportionate to the Company’s ownership in the property. A receivable or liability is recognized only to the extent that the Company has an imbalance on a specific property greater than the expected remaining proved reserves. As of March 31, 2008 and December 31, 2007, the Company’s aggregate natural gas and crude oil imbalances were not material to its consolidated financial statements.

Drilling and Trucking

The Company earns its contract drilling revenues under daywork or turnkey contracts. The Company recognizes revenues on daywork contracts for the days completed based on the dayrate specified in the contract. Turnkey contracts are accounted for on a percentage-of-completion basis. The costs of drilling the Company’s own oil and gas properties are capitalized in oil and gas properties as the expenditures are incurred. Trucking and hauling revenues are recognized based on either an hourly rate or a fixed fee per mile depending on the type of vehicle, the services performed, and the contract terms.

Property and Equipment

The Company accounts for its natural gas and crude oil exploration and development activities under the successful efforts method of accounting. Under such method, costs of productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized. Oil and gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological or geophysical expenses and delay rentals for gas and oil leases, are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities. The sale of a partial interest in a proved property is accounted for as a cost recovery and no gain or loss is recognized as long as this treatment does not significantly affect the units-of-production amortization rate. A gain or loss is recognized for all other sales of producing properties.

Unproved properties with significant acquisition costs are assessed quarterly on a property-by-property basis and any impairment in value is charged to expense. If the unproved properties are determined to be productive, the related costs are transferred to proved gas and oil properties. Proceeds from sales of partial interests in unproved leases are accounted for as a recovery of cost without recognizing any gain or loss until all costs have been recovered.

Depreciation and depletion of capitalized acquisition, exploration and development costs is computed on the units-of-production method by individual fields as the related proved reserves are produced.

Drilling equipment is recorded at cost or estimated fair value upon acquisition and depreciated on a component basis using the straight-line method over their estimated useful lives. Pipelines and gathering systems and other property and equipment are recorded at cost and depreciated using the straight-line method over their estimated useful lives.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2008 and 2007
(Unaudited)

(2) Summary of Significant Accounting Policies, Continued

Impairment of Long-Lived Assets

Statement of Financial Accounting Standards No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets” (“SFAS 144”) requires that long-lived assets be reviewed for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable.

Estimates of expected future cash flows represent management’s best estimate based on reasonable and supportable assumptions and projections. If the expected future cash flows exceed the carrying value of the asset, no impairment is recognized. If the carrying value of the asset exceeds the expected future cash flows, an impairment exists and is measured by the excess of the carrying value over the estimated fair value of the asset. Any impairment provisions recognized in accordance with SFAS 144 are permanent and may not be restored in the future.

The Company assesses developed properties on an individual field basis for impairment on at least an annual basis. For developed properties, the review consists of a comparison of the carrying value of the asset with the asset’s expected future undiscounted cash flows without interest costs. As a result of such assessment, the Company recorded no impairment provision to developed properties for either the three months ended March 31, 2008 or 2007.

For undeveloped properties, the need for an impairment is based on the Company’s plans for future development and other activities impacting the life of the property and the ability of the Company to recover its investment. When the Company believes the costs of the undeveloped property are no longer recoverable, an impairment charge is recorded based on the estimated fair value of the property. As a result of such assessment, the Company recorded no impairment provision attributable to undeveloped properties for either the three months ended March 31, 2008 or 2007.

During the remainder of 2008, the Company is continuing to develop and evaluate certain proved and unproved properties on which favorable or unfavorable results or changes in commodity prices may cause a revision to future estimates of those properties’ future cash flows. Such revisions of estimates could require the Company to record impairments in the period of such revisions.

Goodwill

Goodwill represents the excess of the cost of the acquisitions by DHS of C&L Drilling in May 2006, Rooster Drilling in March 2006, and Chapman Trucking in November 2005 over the fair value of the assets and liabilities acquired. For goodwill and intangible assets recorded in the financial statements, an impairment test is performed at least annually in accordance with the provisions of Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”). No impairment of goodwill was indicated as a result of the Company’s impairment test performed during the third quarter of 2007.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2008 and 2007
(Unaudited)

(2) Summary of Significant Accounting Policies, Continued

Asset Retirement Obligations

The Company’s asset retirement obligations arise from the plugging and abandonment liabilities for its oil and gas wells. The Company has no obligation to provide for the retirement of most of its offshore properties as the obligations remained with the seller from whom the Company acquired the properties. The following is a reconciliation of the Company’s asset retirement obligations from January 1, 2008 to March 31, 2008 (amounts in thousands):


Asset retirement obligation – January 1, 2008	$	5,199
Accretion expense		97
Change in estimate		869
Obligations assumed		1,067
Obligations settled		(575	)
Obligations on sold properties		(62	)

Asset retirement obligation – March 31, 2008		6,595
Less: Current asset retirement obligation		(1,960	)

Long-term asset retirement obligation	$	4,635

Comprehensive Income (Loss)

Comprehensive income (loss) includes all changes in equity during a period except those resulting from investments by owners and distributions to owners, if any. The components of comprehensive income (loss) for the three months ended March 31, 2008 and 2007 are as follows (in thousands):


	Three Months Ended
	March 31,
	2008			2007
Net loss	$	(21,064	)	$	(18,744	)
Other comprehensive income (transactions)
Unrealized loss on available for sale securities		(584	)		—
Hedging (gains) losses reclassified to income upon settlement, net of tax expense of $448		—			(751	)
Change in fair value of derivative hedging instruments, net of tax benefit of $650		—			1,115

		(584	)		364

Comprehensive loss	$	(21,648	)	$	(18,380	)

Financial Instruments

The Company periodically enters into commodity price risk transactions to manage its exposure to oil and gas price volatility. These transactions may take the form of futures contracts, collar agreements, swaps or options. The purpose of the hedges is to provide a measure of stability to the Company’s cash flows in an environment of volatile oil and gas prices. Prior to July 1, 2007, these transactions were accounted for in accordance with requirements of Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”). Effective July 1, 2007, the Company elected to discontinue cash flow hedge accounting on a prospective basis and recognize mark-to-market gains and losses in earnings currently instead of deferring those amounts in accumulated other comprehensive income for the contracts that qualify as cash flow hedges.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2008 and 2007
(Unaudited)

(2) Summary of Significant Accounting Policies, Continued

At March 31, 2008, the Company’s outstanding derivative contracts were collars. Under a collar agreement the Company receives the difference between the floor price and the index price only when the index price is below the floor price; and the Company pays the difference between the ceiling price and the index price only when the index price is above the ceiling price. The Company’s collars are settled in cash on a monthly basis. By entering into collars, the Company effectively provides a floor for the price that it will receive for the hedged production; however, the collar also establishes a maximum price that the Company will receive for the hedged production when prices increase above the ceiling price. The Company enters into collars during periods of volatile commodity prices in order to protect against a significant decline in prices in exchange for foregoing the benefit of price increases in excess of the ceiling price on the hedged production.

The following table summarizes the Company’s open derivative contracts at March 31, 2008:


													Net Fair Value
				Price Floor /									Asset (Liability) at
Commodity	Volume			Price Ceiling					Term			Index	March 31, 2008
													(In thousands)
Crude oil		1,200	Bbls / day	$	65.00	/	$	79.77	Apr ’08	—	June ’08	NYMEX – WTI	$	(2,318	)
Crude oil		1,200	Bbls / day	$	65.00	/	$	79.86	July ’08	—	Sept ’08	NYMEX – WTI		(2,243	)
Crude oil		1,200	Bbls / day	$	65.00	/	$	79.83	Oct ’08	—	Dec ’08	NYMEX – WTI		(2,177	)
Natural gas		15,000	MMBtu / day	$	6.50	/	$	8.30	Apr ’08	—	Dec ’08	CIG		(2,840	)
Natural gas		10,000	MMBtu / day	$	6.00	/	$	7.25	Apr ’08	—	Sept ’08	CIG		(2,199	)
Natural gas		10,000	MMBtu / day	$	6.50	/	$	7.70	Apr ’08	—	June ’08	CIG		(581	)
Natural gas		10,000	MMBtu / day	$	6.50	/	$	8.15	July’08	—	Sept ’08	CIG		(729	)
Natural gas		10,000	MMBtu / day	$	6.50	/	$	7.90	Oct ’08	—	Dec ’08	CIG		(1,086	)
Natural gas		35,000	MMBtu / day	$	7.50	/	$	9.88	Jan ’09	—	Mar ’09	CIG		(2,819	)
Natural gas		10,000	MMBtu / day	$	9.00	/	$	11.53	Oct ’08	—	Dec ’08	NYMEX-H HUB		(506	)

													$	(17,498	)

The net fair value of the Company’s derivative instruments was a liability of approximately $17.5 million at March 31, 2008.

The net gains on effective derivative instruments recognized in the Company’s statements of operations were approximately $1.2 million for the three months ended March 31, 2007. These gains were recorded as an increase in revenues.

Stock Option Plans

In December 2004, Statement of Financial Accounting Standards No. 123 (Revised 2004), “Share Based Payment” (“SFAS 123R”) was issued, which requires the Company to recognize the grant-date fair value of stock options and other equity based compensation issued to employees in the statement of operations. The cost of share based payments is recognized over the period the employee provides service. The Company adopted SFAS 123R effective July 1, 2005 using the modified prospective method and recognized compensation expense related to stock options of $319,000, relating to employee provided services during the three months ended March 31, 2007.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2008 and 2007
(Unaudited)

(2) Summary of Significant Accounting Policies, Continued

Non-Qualified Stock Options — Directors and Employees

On January 29, 2007, the stockholders ratified the Company’s 2007 Performance and Equity Incentive Plan (the “2007 Plan”). Subject to adjustment as provided in the 2007 Plan, the number of shares of common stock that may be issued or transferred, plus the amount of shares of common stock covered by outstanding awards granted under the 2007 Plan, may not in the aggregate exceed 2,800,000. The 2007 Plan supplements the Company’s 1993, 2001 and 2004 Incentive Plans. The purpose of the 2007 Plan is to provide incentives to selected employees and directors of the Company and its subsidiaries, and selected non-employee consultants and advisors to the Company and its subsidiaries, who contribute and are expected to contribute to the Company’s success and to create stockholder value.

Incentive awards under the 2007 Plan may include non-qualified or incentive stock options, limited appreciation rights, tandem stock appreciation rights, phantom stock, stock bonuses or cash bonuses. Options issued to date under the Company’s various incentive plans have been non-qualified stock options as defined in such plans.

Exercise prices for options outstanding under the Company’s various plans as of March 31, 2008 ranged from $1.87 to $15.60 per share and the weighted-average remaining contractual life of those options was 4.15 years. The Company has not issued stock options since the adoption of SFAS 123R, though it has the discretion to issue options again in the future. At March 31, 2008, the Company had 2,157,000 options outstanding.

On February 9, 2007, the Company issued executive performance share grants to each of the Company’s four executive officers (Roger Parker — Chief Executive Officer, John Wallace — President, Kevin Nanke — Chief Financial Officer, and Ted Freedman — Executive Vice President, Secretary and General Counsel) that provide that the shares of common stock awarded will vest if the market price of Delta stock reaches and maintains certain price levels. The awards will vest in up to five tranches on the dates that the average daily closing price of Delta’s common stock equals or exceeds a defined price for a specified number of trading days within any period of 90 calendar days (a “Vesting Threshold”). The Vesting Threshold for the first tranche is $40, for the second tranche, $50, for the third tranche, $60, for the fourth tranche, $75 and for the fifth tranche, $90. Upon attaining the Vesting Threshold for each of the first, second and third tranches, 100,000 of Mr. Parker’s shares would vest for each such tranche, 70,000 of Mr. Wallace’s shares would vest for each such tranche and 40,000 of Mr. Nanke’s and Mr. Freedman’s shares would each vest for each such tranche. The $75 and $90 tranches lapsed effective March 31, 2008 and the $50 and $60 tranches will also lapse if the $40 tranche has not vested on or before March 31, 2009. In addition, the grants will lapse and be forfeited to the extent not vested prior to a termination of the executive’s employment, and will be forfeited to the extent not vested on or before January 29, 2017. The awards also provide for a minimum 364-day period between achievement of two vesting thresholds, subject to acceleration of vesting upon a change in control at a price in excess of one or more of the stock price thresholds, with proportional vesting should a change in control occur at a price in excess of one threshold, but below the next threshold.

The performance share grants were valued at $18.4 million, in the aggregate, with derived service periods over which the value of each tranche will be expensed ranging from 1 to 5 years. Equity compensation of $1.9 million and $774,000 related to the performance share grants was included in general and administrative expense for the three months ended March 31, 2008 and 2007, respectively.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2008 and 2007
(Unaudited)

(2) Summary of Significant Accounting Policies, Continued

Income Taxes

The Company uses the asset and liability method of accounting for income taxes as set forth in SFAS No. 109, “Accounting for Income Taxes” (“SFAS 109”). Under the asset and liability method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and net operating loss and tax credit carry-forwards. Deferred tax assets and liabilities are measured using enacted income tax rates expected to apply to taxable income in the years in which those differences are expected to be recovered or settled. Under SFAS 109, the effect on deferred tax assets and liabilities of a change in income tax rates is recognized in the results of operations in the period that includes the enactment date. Deferred tax assets are evaluated based on the “more likely than not” requirements of SFAS 109, and to the extent this threshold is not met, a valuation allowance is recorded. The Company is currently providing a full valuation allowance on its net deferred tax assets. DHS deferred tax assets and liabilities are recorded on the same basis of accounting, though no valuation allowance has been provided for its deferred tax assets.

Income (Loss) per Common Share

Basic income (loss) per share is computed by dividing net income (loss) attributed to common stock by the weighted average number of common shares outstanding during each period, excluding treasury shares. Diluted income (loss) per share is computed by adjusting the average number of common shares outstanding for the dilutive effect, if any, of convertible preferred stock, convertible debt, stock options, restricted stock and warrants. (See Note 10, “Earnings Per Share”).

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates include oil and gas reserves, bad debts, depletion and impairment of oil and gas properties, valuations of marketable securities, income taxes, derivatives, asset retirement obligations, contingencies and litigation accruals. Actual results could differ from these estimates.

Recently Issued Accounting Pronouncements

In March 2008, the FASB affirmed FASB Staff Position (“FSP”) APB 14-a, “Accounting for Convertible Debt Instruments That May Be Settled in Cash Upon Conversion (Including Partial Cash Settlement)”. The proposed FSP would require the proceeds from the issuance of convertible debt instruments to be allocated between a liability component (debt issued at a discount) and an equity component. The resulting debt discount would be amortized over the period the convertible debt is expected to be outstanding as additional non-cash interest expense. As of the date of filing of this Form 10-Q, the FASB had not finalized this FSP. If finalized, the FSP would be effective for fiscal years beginning after December 15, 2008, or first quarter 2009 for the Company. If adopted, this FSP would change the accounting treatment for the Company’s 3³/4% Senior Convertible Notes since it is to be applied retrospectively upon adoption. The Company is currently evaluating the potential impact of this proposed interpretation on the consolidated financial statements in the event that this pronouncement is adopted by the FASB.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2008 and 2007
(Unaudited)

(2) Summary of Significant Accounting Policies, Continued

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities-an amendment of FASB Statement No.133” (“SFAS 161”). This Statement requires enhanced disclosures for derivative and hedging activities. This statement is effective for financial statements issued for fiscal years beginning after November 15, 2008, or fiscal year 2009. The Company is currently evaluating the potential impact of the adoption of SFAS 161 on its consolidated financial statements.

In December 2007, the FASB issued SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS 141R”), which replaces SFAS 141. SFAS 141R establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any resulting goodwill, and any noncontrolling interest in the acquiree. The Statement also provides for disclosures to enable users of the financial statements to evaluate the nature and financial effects of the business combination. SFAS 141R is effective for financial statements issued for fiscal years beginning after December 15, 2008, or fiscal year 2009, and must be applied prospectively to business combinations completed on or after that date. The Company will evaluate how the new requirements could impact the accounting for any acquisitions completed beginning in fiscal year 2009 and beyond, and the potential impact on its consolidated financial statements.

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements – an amendment of Accounting Research Bulletin No. 51” (“SFAS 160”), which establishes accounting and reporting standards for noncontrolling interests (“minority interests”) in subsidiaries. SFAS 160 clarifies that a noncontrolling interest in a subsidiary should be accounted for as a component of equity separate from the parent’s equity. SFAS 160 is effective for financial statements issued for fiscal years beginning after December 15, 2008, or fiscal year 2009, and must be applied prospectively, except for the presentation and disclosure requirements, which will apply retrospectively. The Company is currently evaluating the potential impact of the adoption of SFAS 160 on its consolidated financial statements.

Recently Adopted Accounting Standards and Pronouncements

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS 159”). SFAS 159 permits companies to choose to measure many financial instruments and certain other items at fair value. SFAS 159 is effective for financial statements issued for fiscal years beginning after November 15, 2007, or fiscal year 2008. The Company adopted SFAS 159 effective January 1, 2008, but did not elect to apply the SFAS 159 fair value option to eligible assets and liabilities during the three months ended March 31, 2008.

In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, “Fair Value Measurements” (“SFAS 157”), which defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and requires additional disclosures about fair value measurements. SFAS 157 aims to improve the consistency and comparability of fair value measurements by creating a single definition of fair value. The Statement emphasizes that fair value is not entity-specific, but instead is a market-based measurement of an asset or liability. SFAS 157 reaffirms the requirements of previously issued pronouncements concerning fair value measurements and expands the required disclosures. In February 2008, the FASB issued FASB Staff Position (“FSP”) No. 157-2. FSP No. 157-2 delays the effective date of SFAS 157 for one year for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). The Company has not yet applied the provisions of SFAS 157 which relate to non-recurring nonfinancial assets and nonfinancial liabilities.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2008 and 2007
(Unaudited)

(2) Summary of Significant Accounting Policies, Continued

Effective January 1, 2008, the Company adopted SFAS 157 for fair value measurements not delayed by FSP No. 157-2. The adoption resulted in additional disclosures as required by the pronouncement (See Note 5, “Fair Value Measurements”) related to our fair value measurements for oil and gas derivatives and marketable securities but no change in our fair value calculation methodologies. Accordingly, the adoption had no impact on our financial condition or results of operations.

(3) Oil and Gas Properties

Unproved Undeveloped Offshore California Properties

The Company has direct and indirect ownership interests ranging from 2.49% to 100% in five unproved undeveloped offshore California oil and gas properties with aggregate carrying values of $16.4 million and $14.8 million at March 31, 2008 and December 31, 2007, respectively. These property interests are located in proximity to existing producing federal offshore units near Santa Barbara, California and represent the right to explore for, develop and produce oil and gas from offshore federal lease units. The recovery of the Company’s investment in these properties through the sale of hydrocarbons will require extensive exploration and development activities (and costs) that cannot proceed without certain regulatory approvals that have been delayed, and is therefore subject to substantial risks and uncertainties.

The Company is not the designated operator of any of these properties but is an active participant in the ongoing activities of each property along with the designated operator and other interest owners. If the designated operator elected not to or was unable to continue as the operator, the other property interest owners would have the right to designate a new operator as well as share in additional property returns prior to the replaced operator being able to receive returns. Based on the Company’s size, it would be difficult for the Company to proceed with exploration and development plans should other substantial interest owners elect not to proceed; however, to the best of its knowledge, the Company believes the designated operators and other major property interest owners would proceed with exploration and development plans under the terms and conditions of the operating agreement if they were permitted to do so by regulators.

Based on indications of levels of hydrocarbons present from drilling operations conducted in the past, the Company believes the fair values of its property interests are in excess of their carrying values at March 31, 2008 and 2007, and that no impairment in the carrying value has occurred. Should the required regulatory approvals not be obtained or plans for exploration and development of the properties not continue, the carrying value of the properties would likely be impaired and written off.

The ownership rights in each of these properties have been retained under various suspension notices issued by the Mineral Management Service (“MMS”) of the U.S. federal government whereby, as long as the owners of each property were progressing toward defined milestone objectives, the owners’ rights with respect to the properties will continue to be maintained. The issuance of the suspension notices has been necessitated by the numerous delays in the exploration and development process resulting from regulatory requirements imposed on the property owners by federal, state and local agencies.

In 2001, however, a Federal Court in the case of California v. Norton, et al. ruled that the MMS does not have the power to grant suspensions on the subject leases without first making a consistency determination under the Coastal Zone Management Act (“CZMA”), and ordered the MMS to set aside its approval of the suspensions of the Company’s offshore leases and to direct suspensions for a time sufficient for the MMS to provide the State of

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2008 and 2007
(Unaudited)

(3) Oil and Gas Properties, Continued

California with the required consistency determination. In response to the ruling in the Norton case, the MMS made a consistency determination under the CZMA and the leases are still valid.

Further actions to develop the leases have been delayed, however, pending the outcome of a separate lawsuit (the “Amber case”) that was filed in the United States Court of Federal Claims (the “Court”) in Washington, D.C. by the Company, its 92%-owned subsidiary, Amber Resources Company of Colorado, and ten other property owners alleging that the U.S. government materially breached the terms of forty undeveloped federal leases, some of which are part of the Company’s and Amber’s offshore California properties. On November 15, 2005 and October 31, 2006, the Court granted summary judgment as to liability and partial summary judgment as to damages with respect to thirty six of the forty total federal leases that are the subject of the litigation. Under a restitution theory of damages, the Court ruled that the government must give back to the current lessees the more than $1.1 billion in lease bonuses it had received at the time of sale. On January 19, 2006, the government filed a motion for reconsideration of the Court’s ruling as it relates to a single lease owned entirely by the Company (“Lease 452”). In its motion for reconsideration, the government has asserted that the Company should not be able to recover lease bonus payments for Lease 452 because, allegedly, a significant portion of the hydrocarbons has been drained by wells that were drilled on an immediately adjacent lease. The amount of lease bonus payments attributable to Lease 452 is approximately $92.0 million. A trial on the motion for reconsideration was completed in January 2008 and post-trial briefing is currently in process. The Company believes that the government’s assertion is without merit, but it cannot predict with certainty the ultimate outcome of this matter.

On January 12, 2007, the Court entered an order of final judgment awarding the lessees restitution of the original lease bonuses paid for thirty-five of the forty lawsuit leases. Under this order the Company is entitled to receive a gross amount of approximately $58.5 million and Amber is entitled to receive a gross amount of approximately $1.5 million as reimbursement for the lease bonuses paid for all lawsuit leases other than Lease 452. The government has appealed the order and contends that, among other things, the Court erred in finding that it breached the leases, and in allowing the current lessees to stand in the shoes of their predecessors for the purposes of determining the amount of damages that they are entitled to receive. The current lessees are also appealing the order of final judgment to, among other things, challenge the Court’s rulings that they cannot recover their and their predecessors’ sunk costs as part of their restitution claim. No payments will be made until all appeals have either been waived or exhausted. No amounts have been recorded for any amounts that may ultimately be received. In the event that the Company ultimately receives any proceeds as the result of this litigation, it will be obligated to pay a portion to landowners and other owners of royalties and similar interests, to pay the litigation expenses and to fulfill certain pre-existing contractual commitments to third parties.

If new activities are commenced on any of the leases, the requisite exploration and development plans will be subject to review by the California Coastal Commission for consistency with the CZMA and by the MMS for other technical requirements. None of the leases is currently impaired, but in the event that they are found not to be valid for some reason in the future, it would appear that they would become impaired. For example, if there is a future adverse ruling by the California Coastal Commission under the CZMA and the Company decides not to appeal such ruling to the Secretary of Commerce, or the Secretary of Commerce either refuses to hear the Company’s appeal of any such ruling or ultimately makes an adverse determination, it is likely that some or all of these leases would become impaired and written off at that time. It is also possible that other events could occur that would cause the leases to become impaired. The Company continuously evaluates those events as they occur.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2008 and 2007
(Unaudited)

(3) Oil and Gas Properties, Continued

Acquisitions During the Quarter Ended March 31, 2008

On February 28, 2008, the Company closed a transaction with EnCana Oil & Gas (USA) Inc. (“EnCana”) to jointly develop a portion of EnCana’s leasehold in the Vega Area of the Piceance Basin. Delta acquired over 1,700 drilling locations on approximately 18,250 gross acres with a 95% working interest. The effective date of the transaction was March 1, 2008. Under the terms of the agreement, the Company has committed to fund $410.5 million, of which $110.5 million was paid at the closing and three $100 million installments are payable November 1, 2009, 2010, and 2011. These remaining installments are collateralized by a letter of credit. The installment payments are recorded in the accompanying consolidated financial statements as long-term liabilities at a discounted value, initially of $280.1 million, based on an imputed interest rate. The discount will be amortized on the effective interest method over the term of the installments, including amortization of $602,000 during the three months ended March 31, 2008. The related agreement supersedes the March 2007 agreement with EnCana and accordingly, the Company has no further drilling commitment to EnCana under the March 2007 agreement.

Discontinued Operations

In accordance with SFAS No. 144, the results of operations and the gain (loss) relating to the sale of the following property interests have been reflected as discontinued operations. Also included in discontinued operations are the results of operations of the Company’s Midway Loop, Texas oil and gas properties that are held for sale at March 31, 2008.

On March 30, 2007, the Company completed the sale of certain non-core properties located in New Mexico and East Texas for cash consideration of approximately $31.7 million. The sale resulted in a loss of approximately $10.8 million.

On March 27, 2007, the Company completed the sale of certain non-core properties located in Australia for cash consideration of approximately $6.0 million. The sale resulted in an after-tax gain of $2.0 million.

On January 10, 2007, the Company completed the sale of certain non-core properties located in Padgett field in Kansas for cash consideration of $5.6 million. The transaction resulted in a gain on sale of the properties of $297,000.

The following table shows the total revenues and income included in discontinued operations for the three months ended March 31, 2008 and 2007 (in thousands):


	Three Months Ended
	March 31,
	2008		2007
Revenues	$	8,315	$	8,392


Income from discontinued operations	$	3,546	$	3,965
Income tax expense		—		(1,482	)


Income from discontinued operations, net of tax	$	3,546	$	2,483

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2008 and 2007
(Unaudited)

(4) DHS Drilling Operations

In March 2008, DHS acquired three rigs and spare equipment for a purchase price of $23.3 million, of which $12.0 million had been paid as of March 31, 2008 and the remainder of which was paid in early April 2008. The transaction was funded by the proceeds from two notes payable issued to Delta and Chesapeake of $6.0 million each and of proceeds of $6.0 million each from Delta and Chesapeake for additional shares of common stock issued by DHS. The proceeds from the note payable to Chesapeake and the common stock issued to Chesapeake were received subsequent to March 31, 2008. The note payable issued to Delta by DHS is eliminated in consolidation.

(5) Fair Value Measurements

Effective January 1, 2008, the Company adopted SFAS 157 which defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and requires additional disclosures about fair value measurements. As required by SFAS 157, the Company applied the following fair value hierarchy:

Level 1 – Assets or liabilities for which the item is valued based on quoted prices (unadjusted) for identical assets or liabilities in active markets.

Level 2 – Assets and liabilities valued based on observable market data for similar instruments.

Level 3 – Assets or liabilities for which significant valuation assumptions are not readily observable in the market; instruments valued based on the best available data, some of which is internally-developed, and considers risk premiums that a market participant would require.

The level in the fair value hierarchy within which the fair value measurement in its entirety falls shall be determined based on the lowest level input that is significant to the fair value measurement in its entirety.

The Company’s available for sale securities include investments in auction rate debt securities. Due to the recent market decline affecting the liquidity of these investments, the valuation assumptions are not readily observable in the market and are valued based on broker models using internally developed unobservable inputs (Level 3). Derivative liabilities consist of future oil and gas collar contracts valued using both quoted prices for identically traded contracts and observable market data for similar contracts (NYMEX WTI oil and NYMEX Henry Hub gas collars and CIG gas collar contracts – Level 2).

The following table lists the Company’s fair value measurements by hierarchy as of March 31, 2008 (in thousands):


	Quoted Prices		Significant			Significant
	in Active Markets		Other Observable			Unobservable
	for Identical Assets		Inputs			Inputs		Total
Assets (Liabilities)	(Level 1)		(Level 2)			(Level 3)		March 31, 2008
Available for sale securities	$	—	$	—		$	5,982	$	5,982

Derivative liabilities	$	—	$	(17,498	)	$	—	$	(17,498	)

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2008 and 2007
(Unaudited)

(5) Fair Value Measurements, Continued

The following is a reconciliation of the Company’s Level 3 assets measured at fair value on a recurring basis using significant unobservable inputs (amounts in thousands):


	Available for Sale
	Securities
Balance at January 1, 2008	$	6,566
Unrealized losses relating to instruments held at the reporting date		(584	)

Balance at March 31, 2008	$	5,982

The unrealized loss attributable to the Level 3 assets is included in other comprehensive loss for the three months ended March 31, 2008.

(6) Long Term Debt

7% Senior Unsecured Notes, due 2015

On March 15, 2005, the Company issued 7% senior unsecured notes for an aggregate principal amount of $150.0 million. Interest is payable semiannually on April 1 and October 1 and the notes mature in 2015. The notes were issued at 99.50% of par and the associated discount is being accreted to interest expense over the term of the notes. The indenture governing the notes contains various restrictive covenants that limit the Company’s and its subsidiaries’ ability to, among other things, incur additional indebtedness, repurchase capital stock, pay dividends, make certain investments, sell assets, and consolidate, merge or transfer all or substantially all of the assets of the Company and its restricted subsidiaries. These covenants may limit the discretion of the Company’s management in operating the Company’s business. The fair value of the Company’s senior unsecured notes at March 31, 2008 was approximately $131.8 million. At March 31, 2008, the Company was in compliance with its covenants and restrictions.

3³/4% Senior Convertible Notes, due 2037

On April 25, 2007, the Company issued $115.0 million aggregate principal amount of 3³/4% Senior Convertible Notes due 2037 (the “Notes”) for net proceeds of $111.6 million after underwriters’ discounts and commissions of approximately $3.4 million. The Notes bear interest at a rate of 3³/4% per annum, payable semiannually in arrears, on May 1 and November 1 of each year, beginning November 1, 2007. The Notes mature on May 1, 2037 unless earlier converted, redeemed or repurchased. The Notes are convertible at the holder’s option, in whole or in part, at an initial conversion rate of 32.9598 shares of common stock per $1,000 principal amount of Notes (equivalent to a conversion price of approximately $30.34 per share) at any time prior to the close of business on the business day immediately preceding the final maturity date of the Notes, subject to prior repurchase of the Notes. The conversion rate may be adjusted from time to time in certain instances. Upon conversion of a Note, the Company will have the option to deliver shares of common stock, cash or a combination of cash and shares of common stock for the Notes surrendered. In addition, following certain fundamental changes that occur prior to maturity, the Company will increase the conversion rate for a holder who elects to convert its Notes in connection with such fundamental changes by a number of additional shares of common stock. Although the Notes do not contain any financial covenants, the Notes contain covenants that require the Company to properly make payments of principal and interest, provide certain reports, certificates and notices to the trustee under various circumstances, cause its wholly-owned subsidiaries to become guarantors of the debt, maintain an office or agency where the Notes may be presented or surrendered for payment, continue its corporate existence, pay taxes and other claims, and not seek protection from the debt under any applicable usury laws. The fair value of the Notes at March 31, 2008 was approximately $131.8 million.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2008 and 2007
(Unaudited)

(6) Long Term Debt, Continued

Credit Facility — Delta

During the quarter ended March 31, 2008, the Company paid in full the outstanding balance of its credit facility. The available borrowing base under the $250.0 million credit facility was $140.0 million at March 31, 2008. The borrowing base is redetermined semiannually and can be increased with future drilling success. The facility has variable interest rates based upon the ratio of outstanding debt to the borrowing base. Rates vary between prime plus .25% and prime plus .50% for base rate loans and between Libor plus 1.25% and Libor plus 2.00% for Eurodollar loans. The LIBOR and prime rates at March 31, 2008 approximated 3.95% and 5.25%, respectively. The loan is collateralized by substantially all of the Company’s oil and gas properties. The Company is required to meet certain financial covenants for the quarter ended March 31, 2008 which include a current ratio of 1 to 1, excluding the fair value of derivative instruments and deferred taxes, as defined, and a consolidated debt to EBITDAX (earnings before interest, taxes, depreciation, amortization and exploration) of less than 3.75 to 1. The financial covenants only include subsidiaries in which the Company owns 100% of the outstanding voting stock. At March 31, 2008, the Company was in compliance with its quarterly debt covenants and restrictions under the facility.

Credit Facility – DHS

On December 20, 2007, DHS entered into a new $75.0 million credit agreement with Lehman Commercial Paper Inc. The Lehman credit facility has a variable interest rate based on 90-day LIBOR plus a fixed margin of 5.50% which approximated 10.43% as of March 31, 2008. The note matures on December 31, 2010. There is no additional borrowing availability under the DHS facility at March 31, 2008. Annual principal payments are based upon a calculation of excess cash flow (as defined) for the preceding year. DHS is required to meet certain financial covenants quarterly beginning March 31, 2008 including (i) consolidated EBITDA for four consecutive fiscal quarters must be greater than $20.0 million; (ii) Consolidated Leverage Ratio (as defined) for four consecutive fiscal quarters cannot exceed 3.50 to 1.00; (iii) Consolidated Interest Coverage Ratio (as defined) for four consecutive fiscal quarters must exceed 2.50 to 1.00 and (iv) the Current Ratio for any fiscal quarter must be greater than 1.0 to 1.0. DHS incurred $1.3 million of financing charges in conjunction with the agreement which are being amortized over the life of the loan. At March 31, 2008, DHS was in compliance with its quarterly debt covenants and restrictions under the facility.

(7) Commitments and Contingencies

Shareholder Derivative Suit

Within the past few years, there has been significant focus on corporate governance and accounting practices in the grant of equity based awards to executives and employees of publicly traded companies, including the use of market hindsight to select award dates to favor award recipients. After being identified in a third-party report as statistically being at risk for possibly backdating option grants, in May 2006 the Company’s Board of Directors created a special committee comprised of outside directors of the Company. The special committee, which was advised by independent legal counsel and advisors, undertook a comprehensive review of the Company’s historical stock option practices and related accounting treatment. In June 2006, the Company received a subpoena from the U.S. Attorney for the Southern District of New York and an inquiry from the staff of the SEC related to the Company’s stock option grants and related practices. The special committee of the Company’s Board of Directors reported to the Board that, while its review revealed deficiencies in the documentation of the Company’s option grants in prior years, there was no evidence of option backdating or other misconduct by the Company’s executives or directors in the timing or selection of the Company’s option grant dates, or that would cause the Company to conclude that its prior accounting for stock option grants was incorrect in any material respect. The Company provided the results of the internal investigation to the U.S. Attorney and to the SEC in August of 2006, and was subsequently informed by both agencies that the matter had been closed.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2008 and 2007
(Unaudited)

(7) Commitments and Contingencies, Continued

During September and October of 2006, three separate shareholder derivative actions were filed on the Company’s behalf in U.S. District Court for the District of Colorado relating to the options backdating issue, all of which were consolidated into a single action. The consolidated complaint alleged that certain of the Company’s executive officers and directors engaged in various types of misconduct in connection with certain stock option grants. Specifically, the plaintiffs alleged that the defendant directors, in their capacity as members of the Company’s Board of Directors and its Audit or Compensation Committee, at the behest of the defendants who are or were officers and to benefit themselves, backdated the Company’s stock option grants to make it appear as though they were granted on a prior date when the Company’s stock price was lower. They alleged that these backdated options unduly benefited the defendants who are or were officers and/or directors, resulted in the Company issuing materially inaccurate and misleading financial statements and caused the Company to incur substantial damages. The action also sought to have the current and former officers and directors who are defendants disgorge to the Company certain options they received, including the proceeds of options exercised, as well as certain equitable relief and attorneys’ fees and costs. On September 26, 2007, the Court entered an Order dismissing the action for failing to plead sufficient facts to support the claims that were made in the complaint, and stayed the dismissal for ten days to allow the Plaintiffs to file a motion for leave to file an amended complaint. Extensions were granted and the Plaintiffs filed such a motion on October 29, 2007. The stay will remain in effect until the Court rules on the motion.

Castle/Longs Trust Litigation

As a result of the acquisition of Castle Energy in April 2006, the Company’s wholly-owned subsidiary, DPCA LLC, as successor to Castle, became party to Castle’s ongoing litigation with the Longs Trust in District Court in Rusk County, Texas. The Longs Trust litigation, which was originally the subject of a jury trial in November 2000, has been separated into two pending suits, one in which the Longs Trust is seeking relief on contract claims regarding oil and gas sales and gas balancing under joint operating agreements with various Castle entities, and the other in which Castle’s claims for unpaid joint interest billings and attorneys’ fees in the amount of $964,000, plus prejudgment interest, have been granted by the trial court and upheld on appeal. The Company intends to vigorously defend the Longs Trust breach of contract claims. The Company has not accrued any recoveries associated with the judgment against the Longs Trust, but will do so when and if they are ultimately collected.

Management does not believe that these proceedings, individually or in the aggregate, will have a material adverse effect on the Company’s financial position, results of operations or cash flows.

(8) Stockholders’ Equity

Preferred Stock

The Company has 3,000,000 shares of preferred stock authorized, issuable from time to time in one or more series. As of March 31, 2008 and December 31, 2007, no shares of preferred stock were issued.

Common Stock

On February 20, 2008, the Company issued 36.0 million shares of the Company’s common stock to Tracinda Corporation (“Tracinda”) at $19.00 per share for net proceeds of $667.1 million (including a $5.0 million deposit on the transaction received in December 2007). As a result of the transaction, Tracinda owns approximately 35% of the Company’s outstanding common stock. In conjunction with the transaction, a finders fee of 263,158 shares of common stock valued at $5.0 million based on the transaction’s $19.00 per share price were issued.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2008 and 2007
(Unaudited)

(8) Stockholders’ Equity, Continued

Treasury Stock

During the three months ended March 31, 2008, DHS implemented a retention bonus plan whereby certain key managers of DHS were granted shares of Delta common stock, one-third of which vest on each one year anniversary of the grant date. The shares of Delta common stock to fund the plan were proportionally provided by Delta’s issuance of new shares and Chesapeake’s contribution of shares purchased in the open market. The Delta shares contributed by Chesapeake are recorded at historical cost in the accompanying consolidated balance sheet as treasury stock and will be carried as such until vested. The Delta shares contributed by Delta are treated as non-vested stock issued to employees and therefore recorded to additional paid in capital over the vesting period.

(9) Income Taxes

The Company accounts for income taxes in accordance with the provisions of SFAS No. 109. Income tax expense (benefit) attributable to income (loss) from continuing operations was approximately ($1.3) million and ($8.6) million, for the three months ended March 31, 2008 and 2007, respectively.

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future results of operations, and tax planning strategies in making this assessment. Based upon the level of historical taxable income, significant book losses during the year ended December 31, 2007, and projections for future results of operations over the periods in which the deferred tax assets are deductible, among other factors, management concluded during the second quarter of 2007 and continues to conclude that the Company does not meet the “more likely than not” requirement of SFAS 109 in order to recognize deferred tax assets. Accordingly, for the three months ended March 31, 2008, the Company did not record a tax benefit for its net deferred tax assets.

The Company’s deferred tax assets consist primarily of net operating loss carryforwards that expire between 2008 and 2027. The recognition of the valuation allowance does not affect the Company’s ability to utilize its net operating loss carryforwards to offset future taxable income.

During the remainder of 2008 and beyond, the Company will continue to assess the realizability of its deferred tax assets based on consideration of actual and projected operating results and tax planning strategies. Should actual operating results improve, the amount of the deferred tax asset considered more likely than not to be realizable could be increased. Such a change in the assessment of realizability could result in a decrease to the valuation allowance and corresponding income tax benefit, both of which could be significant.

Effective January 1, 2007, the Company adopted the provisions of FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes – An Interpretation of FASB Statement No. 109, or FIN 48. FIN 48 provides detailed guidance for the financial statement recognition, measurement and disclosure of uncertain tax positions recognized in the financial statements in accordance with SFAS No. 109. Tax positions must meet a “more-likely-than-not” recognition threshold at the effective date to be recognized upon the adoption of FIN 48 and in subsequent periods. Upon the adoption of FIN 48, the Company had no unrecognized tax benefits. During the three months ended March 31, 2008 and 2007, no adjustments were recognized for uncertain tax benefits.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2008 and 2007
(Unaudited)

(9) Income Taxes, Continued

The Company recognizes interest and penalties related to uncertain tax positions in general and administrative expense. No interest and penalties related to uncertain tax positions were accrued at March 31, 2008 or December 31, 2007.

The tax years 2003 through 2007 for federal returns and 2002 through 2007 for state returns remain open to examination by the major taxing jurisdictions in which we operate, although no material changes to unrecognized tax positions are expected within the next twelve months.

(10) Earnings Per Share

The following table sets forth the computation of basic and diluted earnings per share:


	Three Months Ended
	March 31,
	2008			2007
	(In thousands, except per share amounts)
Net loss	$	(21,064	)	$	(18,744	)

Basic weighted-average common shares outstanding		80,726			54,933
Add: dilutive effects of stock options and unrestricted stock grants		3,465			3,555
Add: dilutive effect of 3³/4% Convertible Notes using the if-converted method		3,790			3,790


Diluted weighted-average common shares outstanding		87,981			62,278


Basic net income (loss) per common share	$	(.26	)	$	(.34	)

Diluted net income (loss) per common share	$	(.26	)	$	(.34	)

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2008 and 2007
(Unaudited)

(11) Guarantor Financial Information

On March 15, 2005, Delta issued its 7% Senior Notes (“Senior Notes”) that mature in 2015 for an aggregate amount of $150.0 million. Interest is payable semiannually on April 1st and October 1st. In addition, on April 25, 2007, the Company issued its 3 ³/4% Convertible Senior Notes due in 2037 (“Convertible Notes”) for aggregate proceeds of $111.6 million. Interest is payable semiannually on May 1 and November 1. Both the Senior Notes and the Convertible Notes are guaranteed by all of the Company’s other wholly-owned subsidiaries (“Guarantors”). Each of the Guarantors, fully, jointly and severally, irrevocably and unconditionally guarantees the performance and payment when due of all the obligations under the Senior Notes and the Convertible Notes. DHS, CRBP, PGR, and Amber (“Non-guarantors”) are not guarantors of the indebtedness under the Senior Notes or the Convertible Notes.

The following financial information sets forth the Company’s condensed consolidated balance sheets as of March 31, 2008 and December 31, 2007, the condensed consolidated statements of operations for the three months ended March 31, 2008 and 2007, and the condensed consolidated statements of cash flows for the three months ended March 31, 2008 and 2007 (in thousands). For purposes of the condensed financial information presented below, the equity in the earnings or losses of subsidiaries is not recorded in the financial statements of the issuer.

Condensed Consolidated Balance Sheet
March 31, 2008


				Guarantor			Non-Guarantor			Adjustments/
	Issuer			Entities			Entities			Eliminations			Consolidated
Current assets	$	171,367		$	797		$	46,962		$	—		$	219,126

Property and equipment:
Oil and gas properties		1,379,686			488			87,872			(4,026	)		1,464,020
Drilling rigs and trucks		594			—			170,339			—			170,933
Other		52,668			4,314			1,606			—			58,588

Total property and equipment		1,432,948			4,802			259,817			(4,026	)		1,693,541

Accumulated depletion, depreciation and amortization		(222,914	)		(130	)		(48,450	)		—			(271,494	)


Net property and equipment		1,210,034			4,672			211,367			(4,026	)		1,422,047

Investment in subsidiaries		100,778			—			—			(100,778	)		—
Other long-term assets		338,053			3,809			8,908			(6,007	)		344,763


Total assets	$	1,820,232		$	9,278		$	267,237		$	(110,811	)	$	1,985,936


Current liabilities	$	138,568		$	170		$	34,560		$	(7	)	$	173,291

Long-term liabilities
Long-term debt, derivative instruments, and deferred taxes		543,403			1,800			76,613			(6,000	)		615,816
Asset retirement obligations and other liabilities		4,448			9			178			—			4,635


Total long-term liabilities		547,851			1,809			76,791			(6,000	)		620,451

Minority interest		33,835			—			—			—			33,835

Stockholders’ equity		1,099,978			7,299			155,886			(104,804	)		1,158,359


Total liabilities and stockholders’ equity	$	1,820,232		$	9,278		$	267,237		$	(110,811	)	$	1,985,936

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2008 and 2007
(Unaudited)

(11) Guarantor Financial Information, Continued

Condensed Consolidated Balance Sheet
December 31, 2007


				Guarantor			Non-Guarantor			Adjustments/
	Issuer			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Current assets	$	98,620		$	898		$	33,253		$	—		$	132,771

Property and equipment:
Oil and gas		918,247			487			80,784			(11,644	)		987,874
Drilling rigs and trucks		595			—			145,502			—			146,097
Other		35,444			4,316			1,449			—			41,209

Total property and equipment		954,286			4,803			227,735			(11,644	)		1,175,180

Accumulated depletion, depreciation and amortization		(203,091	)		(125	)		(41,937	)		—			(245,153	)


Net property and equipment		751,195			4,678			185,798			(11,644	)		930,027

Investment in subsidiaries		87,961			—			—			(87,961	)		—
Other long-term assets		30,084			3,800			8,513			—			42,397


Total assets	$	967,860		$	9,376		$	227,564		$	(99,605	)	$	1,105,195


Current liabilities	$	135,997		$	188		$	7,011		$	—		$	143,196

Long-term liabilities
Long-term debt and deferred taxes		336,409			1,800			83,935			—			422,144
Asset retirement obligations and Other liabilities		3,976			9			169			—			4,154


Total long-term liabilities		340,385			1,809			84,104			—			426,298

Minority interest		27,296			—			—			—			27,296

Stockholders’ equity		464,182			7,379			136,449			(99,605	)		508,405


Total liabilities and stockholders’ equity	$	967,860		$	9,376		$	227,564		$	(99,605	)	$	1,105,195

Condensed Consolidated Statement of Operations
Three Months Ended March 31, 2008


				Guarantor		Non-Guarantor			Adjustments/
	Issuer			Entities		Entities			Eliminations			Consolidated
Total revenue	$	42,364		$	192	$	23,391		$	(9,956	)	$	55,991

Operating expenses:
Oil and gas expenses		11,941			33		399			—			12,373
Exploration expense		1,002			—		—			—			1,002
Dry hole costs and impairments		2,339			—		—			—			2,339
Depreciation and depletion		18,338			7		6,566			—			24,911
Drilling and trucking operations		—			—		12,655			(5,930	)		6,725
General and administrative		12,067			24		1,330			—			13,421


Total operating expenses		45,687			64		20,950			(5,930	)		60,771


Operating income (loss)		(3,323	)		128		2,441			(4,026	)		(4,780	)

Other income and (expenses)		(19,527	)		24		(1,996	)		329			(21,170	)
Income tax benefit (expense)		950			—		370			—			1,320
Discontinued operations		3,566			—		—			—			3,566


Net income (loss)	$	(18,334	)	$	152	$	815		$	(3,697	)	$	(21,064	)

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2008 and 2007
(Unaudited)

(11) Guarantor Financial Information, Continued

Condensed Consolidated Statement of Operations
Three Months Ended March 31, 2007


				Guarantor			Non-Guarantor			Adjustments/
	Issuer			Entities			Entities			Eliminations			Consolidated
Total revenue	$	19,734		$	177		$	21,591		$	(4,580	)	$	36,922

Operating expenses:
Oil and gas expenses		5,364			44			579			—			5,987
Exploration expense		624			—			—			—			624
Dry hole costs and impairments		3,517			—			—			—			3,517
Depreciation and depletion		15,092			6			5,737			—			20,835
Drilling and trucking operations		—			—			13,152			(2,688	)		10,464
General and administrative		10,664			(1	)		882			—			11,545


Total operating expenses		35,261			49			20,350			(2,688	)		52,972


Operating income (loss)		(15,527	)		128			1,241			(1,892	)		(16,050	)

Other income and (expenses)		(7,366	)		44			(1,785	)		17			(9,090	)
Income tax (expense) benefit		8,555			—			20			—			8,575
Loss from discontinued operations, net of tax		(2,179	)		—			—			—			(2,179	)


Net income (loss)	$	(16,517	)	$	172		$	(524	)	$	(1,875	)	$	(18,744	)

Condensed Consolidated Statement of Cash Flows
Three Months Ended March 31, 2008


				Guarantor			Non-Guarantor
	Issuer			Entities			Entities			Consolidated
Operating activities	$	(71	)	$	221		$	6,871		$	7,021
Investing activities		(544,931	)		(234	)		(22,098	)		(567,263	)
Financing activities		570,616			—			17,714			588,330


Net increase in cash and cash equivalents		25,614			(13	)		2,487			28,088

Cash at beginning of the period		4,658			307			4,828			9,793


Cash at the end of the period	$	30,272		$	294		$	7,315		$	37,881

Condensed Consolidated Statement of Cash Flows
Three Months Ended March 31, 2007


				Guarantor			Non-Guarantor
	Issuer			Entities			Entities			Consolidated
Operating activities	$	9,455		$	225		$	2,909		$	12,589
Investing activities		(20,635	)		(1,303	)		(15,840	)		(37,778	)
Financing activities		15,002			—			15,553			30,555


Net increase (decrease) in cash and cash equivalents		3,822			(1,078	)		2,622			5,366

Cash at beginning of the period		2,282			1,637			3,747			7,666


Cash at the end of the period	$	6,104		$	559		$	6,369		$	13,032

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2008 and 2007
(Unaudited)

(12) Business Segments

The Company has two reportable segments: oil and gas exploration and production (“Oil and Gas”) and drilling and trucking operations (“Drilling”) through its ownership in DHS. Following is a summary of segment results for the three months ended March 31, 2008 and 2007:


							Inter-segment
	Oil and Gas			Drilling			Eliminations			Consolidated
	(In thousands)
Three Months Ended March 31, 2008
Revenues from external customers	$	45,444		$	10,547		$	—		$	55,991
Inter-segment revenues		—			9,956			(9,956	)		—

Total revenues	$	45,444		$	20,503		$	(9,956	)	$	55,991

Operating income (loss)	$	(1,735	)	$	981		$	(4,026	)	$	(4,780	)

Other expense		(19,491	)		(2,008	)		329			(21,170	)

Income (loss) from continuing operations, before tax	$	(21,226	)	$	(1,027	)	$	(3,697	)	$	(25,950	)


Three Months Ended March 31, 2007
Revenues from external customers	$	20,628		$	16,294		$	—		$	36,922
Inter-segment revenues		—			4,580			(4,580	)		—

Total revenues	$	20,628		$	20,874		$	(4,580	)	$	36,922

Operating income (loss)	$	(15,890	)	$	1,732		$	(1,892	)	$	(16,050	)

Other income and (expense)		(7,322	)		(1,785	)		17			(9,090	)

Income (loss) from continuing operations, before tax	$	(23,212	)	$	(53	)	$	(1,875	)	$	(25,140	)


March 31, 2008:
Total Assets	$	1,852,540		$	175,169		$	(41,773	)	$	1,985,936


December 31, 2007:
Total Assets	$	996,549		$	146,314		$	(37,668	)	$	1,105,195

Other income and expense includes interest and financing costs, gain on sale of marketable securities, unrealized losses on derivative contracts and other miscellaneous income for Oil and Gas, and other miscellaneous income for Drilling. Minority interest is included in inter-segment eliminations.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Forward Looking Statements

This Quarterly Report on Form 10-Q contains forward-looking statements, within the meaning of Section 27A of the Securities Act of 1933, as amended (“Securities Act”) and Section 21E of the Securities Exchange Act of 1934, as amended (“Exchange Act”).

We are including the following discussion to inform our existing and potential security holders generally of some of the risks and uncertainties that can affect us and to take advantage of the “safe harbor” protection for forward-looking statements afforded under federal securities laws. From time to time, our management or persons acting on our behalf make forward-looking statements to inform existing and potential security holders about us. Forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “plan,” “goal” or other words that convey the uncertainty of future events or outcomes. Except for statements of historical or present facts, all other statements contained in this Form 10-Q are forward-looking statements. The forward-looking statements may appear in a number of places and include statements with respect to, among other things: business objectives and strategic plans; operating strategies; acquisition strategies; drilling wells; oil and gas reserve estimates (including estimates of future net revenues associated with such reserves and the present value of such future net revenues); estimates of future production of oil and natural gas; expected results or benefits associated with recent acquisitions; marketing of oil and natural gas; expected future revenues and earnings, and results of operations; future capital, development and exploration expenditures (including the amount and nature thereof); our expectation that we will have adequate cash from operations and credit facility borrowings to meet future debt service, capital expenditure and working capital requirements; nonpayment of dividends; expectations regarding competition and our competitive advantages; impact of the adoption of new accounting standards and our financial and accounting systems and analysis programs; and effectiveness of our internal control over financial reporting.

These statements by their nature are subject to certain risks, uncertainties and assumptions and will be influenced by various factors. Should any of the assumptions underlying a forward-looking statement prove incorrect, actual results could vary materially. In some cases, information regarding certain important factors that could cause actual results to differ materially from any forward-looking statement appears together with such statement. In addition, the factors described under “Risk Factors” in our Form 10-K for the year ended December 31, 2007, as well as other possible factors not listed, could cause actual results to differ materially from those expressed in forward-looking statements, including, without limitation, the following:

	•		deviations in and volatility of the market prices of both crude oil and natural gas produced by us;

	•		the timing, effects and success of our acquisitions, dispositions and exploration and development activities;

	•		uncertainties in the estimation of proved reserves and in the projection of future rates of production;

	•		timing, amount, and marketability of production;

	•		third party curtailment, processing plant or pipeline capacity constraints beyond our control;

	•		our ability to find, acquire, develop, produce and market production from new properties;

	•		plans with respect to divestiture of oil and gas properties;

	•		effectiveness of management strategies and decisions;

	•		the strength and financial resources of our competitors;

	•		climatic conditions;

	•		changes in the legal and/or regulatory environment and/or changes in accounting standards policies and practices or related interpretations by auditors or regulatory entities;

	•		unanticipated recovery or production problems, including cratering, explosions, fires and uncontrollable flows of oil, gas or well fluids; and

	•		our ability to fully utilize income tax net operating loss and credit carry-forwards.

Many of these factors are beyond our ability to control or predict. These factors are not intended to represent a complete list of the general or specific factors that may affect us.

All forward-looking statements speak only as of the date made. All subsequent written and oral forward-looking statements attributable to us, or persons acting on our behalf, are expressly qualified in their entirety by the cautionary statements above. Except as required by law, we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which it is made or to reflect the occurrence of anticipated or unanticipated events or circumstances.

Recent Developments

	•		Primarily due to continued success from our Rocky Mountain drilling activities, our production from continuing operations increased 68% to 4.7 Mmcfe, compared to 2.8 Mmcfe for the comparable prior year quarter.

	•		Proved reserves increased 60% to 603 Bcfe at March 31, 2008 as compared to 376 Bcfe at year-end as a result of our property acquisition and drilling results.

	•		The Company completed the sale of 36 million common shares in February resulting in $684 million in proceeds, significantly strengthening the Company’s balance sheet and providing the capital to accelerate the development of key properties, particularly in the Rocky Mountain region.

	•		The Company completed a $410.5 million transaction that significantly increases the Company’s acreage position in the Piceance Basin by adding incremental interests in existing properties and by obtaining interests in adjoining acreage. The transaction significantly increases the Company’s drilling inventory of lower-risk repeatable projects.

The following discussion and analysis relates to items that have affected our results of operations for the three months ended March 31, 2008 and 2007. This analysis should be read in conjunction with our consolidated financial statements and accompanying notes included in this Form 10-Q.

Results of Operations

Quarter Ended March 31, 2008 Compared to Quarter Ended March 31, 2007

Net Loss. Net loss was $21.1 million, or $0.26 per diluted common share, for the three months ended March 31, 2008, compared to net loss of $18.7 million, or $.34 per diluted common share, for the three months ended March 31, 2007. Loss from continuing operations increased from $16.6 million for the three months ended March 31, 2007 to $24.6 million for the three months ended March 31, 2008, due primarily to $14.1 million in unrealized losses on derivative instruments.

Oil and Gas Sales. During the three months ended March 31, 2008, oil and gas sales from continuing operations increased 134% to $45.4 million, as compared to $19.4 million for the comparable period a year earlier. The increase was the result of a 68% increase in production from continuing operations, a 70% increase in oil prices, and a 35% increase in gas prices. The average gas price received during the three months ended March 31, 2008 increased to $7.55 per Mcf compared to $5.61 per Mcf for the year earlier period due to increased natural gas prices generally, as well as a decrease in the Rockies natural gas “basis differential”. The average oil price received during the three months ended March 31, 2008 increased to $89.84 per Bbl compared to $52.99 per Bbl

for the year earlier period. Net gains from hedging instruments were $1.2 million for the three months ended March 31, 2007. The gain in 2007 was primarily due to lower gas prices. These gains were recorded as an increase in revenues.

Contract Drilling and Trucking Fees. Contract drilling and trucking fees for the three months ended March 31, 2008 decreased to $10.5 million compared to $16.3 million for the year earlier period. The decrease is primarily the result of additional rigs operating for Delta in 2008 compared to 2007. Revenues on such rigs are eliminated in consolidation.

Production and Cost Information

Production volumes, average prices received and cost per equivalent Mcf for the three months ended March 31, 2008 and 2007 are as follows:


	Three Months Ended
	March 31,
	2008			2007
Production — Continuing Operations:
Oil (MBbl)		229			197
Gas (MMcf)		3,294			1,602
Production — Discontinued Operations:
Oil (MBbl)		37			69
Gas (MMcf)		475			725

Total Production (MMcfe)		5,366			3,924

Average Price — Continuing Operations:
Oil (per barrel)	$	89.84		$	52.99
Gas (per Mcf)	$	7.55		$	5.61

Costs per Mcfe — Continuing Operations:
Realized derivative gain (loss)	$	(.37	)	$	.43
Lease operating expense	$	1.63		$	1.44
Production taxes	$	.65		$	.40
Transportation costs	$	.37		$	.31
Depletion expense	$	4.03		$	5.49

Lease Operating Expense. Lease operating expenses for the three months ended March 31, 2008 were $7.6 million compared to $4.0 million for the year earlier period. Lease operating expense from continuing operations per Mcfe for the three months ended March 31, 2008 was $1.63 per Mcfe as compared to $1.44 per Mcfe for the year earlier period primarily due to abnormally high snow removal costs in the Piceance Basin and an increase for a non-recurring offshore workover expense at the Point Arguello Unit in the Santa Barbara Channel.

Exploration Expense. Exploration expense consists of geological and geophysical costs and lease rentals. Our exploration costs for the three months ended March 31, 2008 were $1.0 million compared to $624,000 for the year earlier period. Current year exploration activities include activities in our Columbia River Basin, central Utah Hingeline, the Cowboy Prospect in Wyoming, and Newton County, Texas projects.

Dry Hole Costs and Impairments. We incurred dry hole costs of approximately $2.3 million for the three months ended March 31, 2008 compared to $3.5 million for the comparable period a year ago. During the three months ended March 31, 2008, dry hole costs primarily related to carry-over costs for work done in 2008 on the most recent Hingeline well in Utah. During the three months ended March 31, 2007, we recorded dry hole costs of approximately $3.5 million related to two exploratory projects, one in Texas and one in Utah.

Depreciation, Depletion, Amortization and Accretion — oil and gas. Depreciation, depletion and amortization expense increased 23% to $19.3 million for the three months ended March 31, 2008, as compared to $15.7 million for the year earlier period. Depletion expense for the three months ended March 31, 2008 was $18.8 million compared to $15.3 million for the three months ended March 31, 2007. The 23% increase in depletion expense was due to a 68% increase in production from continuing operations partially offset by a 27% decrease in the per Mcfe depletion rate. Our depletion rate decreased to $4.03 per Mcfe for the three months ended March 31, 2008 from $5.49 per Mcfe for the year earlier period, primarily as a result of increased reserve additions and lower costs per well from our Piceance Basin capital development program.

Drilling and Trucking Operations. Drilling expenses decreased to $6.7 million for the three months ended March 31, 2008 compared to $10.5 million for the comparable prior year period. This decrease can be attributed to lower utilization during the current year period, coupled with greater usage of DHS rigs by Delta, as intercompany expenses are eliminated in consolidation.

Depreciation and Amortization — drilling and trucking. Depreciation and amortization expense - drilling increased to $5.6 million for the three months ended March 31, 2008, as compared to $5.1 million for the year earlier period. Because depreciation is a period expense, depreciation increased despite lower utilization.

General and Administrative Expense. General and administrative expense increased 16.5% to $13.4 million for the three months ended March 31, 2008, as compared to $11.5 million for the comparable prior year period. The increase in general and administrative expenses is primarily attributed to an increase in non-cash equity compensation of $1.2 million and a 17% increase in technical and administrative staff and related personnel costs.

Realized Loss on Derivative Instruments, Net. Effective July 1, 2007, we discontinued cash flow hedge accounting. Beginning July 1, 2007, we recognize realized gains or losses in other income and expense instead of as a component of revenue. As a result, other income and expense includes $1.6 million of realized losses for the three months ended March 31, 2008.

Unrealized Loss on Derivative Instruments, Net. As a result of the discontinuation of cash flow hedge accounting, we recognize mark-to-market gains or losses in current earnings instead of deferring those amounts in accumulated other comprehensive income. Accordingly, we recognized $14.1 million of unrealized losses on derivative instruments in other income and expense during the three months ended March 31, 2008 compared to $1.7 million for the prior year period primarily due to higher commodity prices.

Minority Interest. Minority interest represents the minority investors’ percentage of their share of income or losses from DHS in which they hold an interest. During the three months ended March 31, 2008, DHS reported lower earnings resulting in a decrease in minority interest.

Interest Income. Interest income increased to $1.9 million for the three months ended March 31, 2008 compared to $76,000 for the prior year period. The increase is primarily due to interest earned on our $300.0 million restricted deposit and invested cash received from the Tracinda transaction during the first quarter of 2008.

Interest and Financing Costs. Interest and financing costs increased 5% to $8.0 million for the three months ended March 31, 2008, as compared to $7.6 million for the comparable year earlier period. The increase is primarily related to an increase in the outstanding DHS credit facility balance and the non-cash amortization of discount on the installments payable to EnCana.

Income Tax Expense (Benefit). Due to our continued losses, we were required by the “more likely than not” provisions of SFAS No. 109 to record a valuation allowance on our Delta stand-alone deferred tax assets beginning with the second quarter of 2007. As a result, our income tax benefit for the three months ended March 31, 2008 of $1.3 million relates only to DHS, as no benefit was provided for Delta’s pre-tax losses. During the three months ended March 31, 2007, an income tax benefit of $8.6 million was recorded for continuing operations at an effective tax rate of 36.8%.

Discontinued Operations. Discontinued operations for the three months ended March 31, 2008 and March 31, 2007 include the Midway Loop, Texas properties that are held for sale as of March 31, 2008. Discontinued operations for the three months ended March 31, 2007 include the North Dakota properties sold in September 2007 and the Washington County, Colorado properties sold in October 2007.

Gain on Sale of Discontinued Operations. During the three months ended March 31, 2007, we sold non-core properties in Kansas, Texas, New Mexico and Australia for combined proceeds of $40.3 million and reported a combined net loss of $4.7 million on the sales.

Liquidity and Capital Resources

Liquidity is a measure of a company’s ability to access cash. On February 20, 2008, we completed the Tracinda equity transaction, issuing 36.0 million shares of our common stock for net proceeds of $667.1 million and used the proceeds to, among other things, pay off our credit facility.

Our cash requirements are largely dependent upon the number and timing of projects included in our capital development plan, most of which are discretionary. We have historically addressed our long-term liquidity requirements through the issuance of debt and equity securities when market conditions permit, through cash provided by operating activities, sales of oil and gas properties, and through borrowings under our credit facility.

During the three months ended March 31, 2008, we had an operating loss of $4.8 million, but we generated cash from operating activities of $7.0 million and obtained cash from financing activities of $588.3 million. During this period we spent $101.2 million on oil and gas development, $114.8 million on oil and gas acquisitions, and $13.7 million on drilling and trucking capital expenditures. At March 31, 2008, we had $37.9 million in cash, $35.0 million in certificates of deposit, $301.2 million in long-term deposits, total assets of $2.0 billion and a debt to capitalization ratio of 34.9%. Long-term debt at March 31, 2008 totaled $607.1 million, comprised of $61.9 million of DHS bank debt, $149.5 million of senior subordinated notes and $115.0 million of senior convertible notes. In addition, the Company has $280.7 million of installments payable on a recently completed property acquisition. In February, our credit facility was repaid with proceeds from the Tracinda equity transaction. Available borrowing capacity under our bank credit facility at March 31, 2008 was approximately $140.0 million. DHS has no additional availability under its credit facility.

At March 31, 2008, we were in compliance with our quarterly financial covenants. Our covenants require a minimum current ratio of 1 to 1, excluding the fair value of derivative instruments, and a consolidated debt to EBITDAX (earnings before interest, taxes, depreciation, amortization and exploration) of less than 3.75 to 1. These financial covenant calculations are based on the financial statements of Delta and its wholly-owned subsidiaries.

The prices we receive for future oil and natural gas production and the level of production have a significant impact on operating cash flows. We are unable to predict with any degree of certainty the prices we will receive for our future oil and gas production and the success of our exploration and production activities in generating additional production.

Although we believe that through cash on hand, availability from our credit facility, and cash flows from operations we have access to adequate capital to fund our development plans, we continue to examine additional sources of long-term capital, including a restructured debt facility, the issuance of debt instruments, the sale of preferred and common stock, the sales of non-strategic assets, and joint venture financing. Availability of these

sources of capital and, therefore, our ability to execute our operating strategy, will depend upon a number of factors, many of which are beyond our control.

Company Acquisitions and Growth

We continue to evaluate potential acquisitions and property development opportunities. During the three months ended March 31, 2008, we completed the following transactions:

On February 28, 2008, we closed a transaction with EnCana Oil & Gas (USA) Inc., (“EnCana”) to jointly develop a portion of EnCana’s leasehold in the Vega Area of the Piceance Basin. We acquired over 1,700 drilling locations on approximately 18,250 gross acres with a 95% working interest. The effective date of the transaction was March 1, 2008. The related agreement supersedes the March 2007 agreement with EnCana and accordingly we have no further drilling commitment to EnCana under the March 2007 agreement.

Historical Cash Flow

Our cash flow from operating activities decreased from $12.6 million for the three months ended March 31, 2007 to $7.0 million for the three months ended March 31, 2008, primarily as a result of changes in working capital. Our net cash used in investing activities increased to $567.3 million for the three months ended March 31, 2008 compared to net cash used in investing activities of $37.8 million for the same year earlier period, primarily due to our increased drilling activity and the above-referenced transaction with EnCana. Cash provided by financing activities was $588.3 million for the three months ended March 31, 2008 compared to $30.6 million for the comparable prior year period. Cash provided by financing activities was higher in 2008 primarily due to cash received in February from the Tracinda equity transaction.

Capital and Exploration Expenditures and Financing

Our capital and exploration expenditures and sources of financing for the three months ended March 31, 2008 and 2007 are as follows:


	2008			2007
	(In thousands)
CAPITAL AND EXPLORATION EXPENDITURES:
Acquisitions:
Piceance Basin, CO	$	110,499		$	—
Polk County, TX (non-cash)		—			13,848
Fremont County, WY		—			3,500
Other		4,250			5,741

Other development costs		101,323			50,225
Drilling and trucking costs		13,723			12,175
Dry hole costs		2,071			3,517
Exploration costs		1,002			624

	$	232,868		$	89,630


FUNDING SOURCES:
Cash flow provided by operating activities	$	7,021		$	12,528
Stock issued for cash upon exercise of stock options		1,662			—
Stock issued for cash, net		662,097			56,399
Long-term borrowings (repayments), net		(73,613	)		(25,731	)
Increase in restricted deposit		(301,174	)		—
Proceeds from sale of oil and gas properties		—			40,277
Other		(162	)		(102	)

	$	295,831		$	83,371

Sales of Oil and Gas Properties

On October 1, 2007, we divested our Washington County, Colorado properties in conjunction with an asset exchange transaction to acquire additional working interest in the Garden Gulch Field in the Piceance Basin.

On September 4, 2007, we completed the sale of certain non-core properties located in North Dakota for cash consideration of approximately $6.2 million. The sale resulted in a gain of $4.3 million.

On March 30, 2007, we completed the sale of certain non-core properties located in New Mexico and East Texas for cash consideration of approximately $31.7 million. The sale resulted in a loss of approximately $10.8 million.

On March 27, 2007, we completed the sale of certain non-core properties located in Australia for cash consideration of approximately $6.0 million. The sale resulted in an after-tax gain of $2.0 million.

On January 10, 2007, we completed the sale of certain non-core properties located in Padgett Field, Kansas for cash consideration of $5.6 million. The transaction resulted in a gain on sale of properties of $297,000.

7% Senior Unsecured Notes, due 2015

On March 15, 2005, we issued 7% senior unsecured notes for an aggregate principal amount of $150.0 million. The notes accrue interest semiannually on April 1 and October 1 and the notes mature in 2015. The notes were issued at 99.50% of par and the associated discount is being amortized to interest expense over the term of the notes. The indenture governing the notes contains various restrictive covenants that limit our ability to, among other things, incur additional indebtedness, make certain investments, sell assets, and consolidate, merge or transfer all or substantially all of our assets and the assets of our restricted subsidiaries. These covenants may limit management’s discretion in operating our business. At March 31, 2008, we were in compliance with our covenants and restrictions.

3³/4% Senior Convertible Notes, due 2037

On April 25, 2007, we issued $115.0 million aggregate principal amount of 3³/4% Senior Convertible Notes due 2037 (the “Notes”) for net proceeds of $111.6 million after underwriters’ discounts and commissions of approximately $3.4 million. The Notes bear interest at a rate of 3³/4% per annum, payable semiannually in arrears, on May 1 and November 1 of each year, beginning November 1, 2007. The Notes mature on May 1, 2037 unless earlier converted, redeemed or repurchased. The Notes are convertible at the holder’s option, in whole or in part, at an initial conversion rate of 32.9598 shares of common stock per $1,000 principal amount of Notes (equivalent to a conversion price of approximately $30.34 per share) at any time prior to the close of business on the business day immediately preceding the final maturity date of the Notes, subject to prior repurchase of the Notes. The conversion rate may be adjusted from time to time in certain instances. Upon conversion of a Note, we will have the option to deliver shares of our common stock, cash or a combination of cash and shares of our common stock for the Notes surrendered. In addition, following certain fundamental changes that occur prior to maturity, we will increase the conversion rate for a holder who elects to convert its Notes in connection with such fundamental changes by a number of additional shares of common stock. Although the Notes do not contain any financial covenants, the Notes contain covenants that require us to properly make payments of principal and interest, provide certain reports, certificates and notices to the trustee under various circumstances, cause our wholly-owned subsidiaries to become guarantors of the debt, maintain an office or agency where the Notes may be presented or surrendered for payment, continue our corporate existence, pay taxes and other claims, and not seek protection from the debt under any applicable usury laws.

Credit Facility — Delta

At March 31, 2008, the $250.0 million credit facility had zero outstanding. In February 2008, the credit facility was repaid with a portion of the proceeds from our Tracinda equity offering. The facility provides for variable interest rates based upon the ratio of outstanding debt to the borrowing base. Rates vary between prime plus .25% and prime plus .50% for base rate loans and between Libor plus 1.25% and Libor plus 2.00% for Eurodollar loans. We are required to meet certain financial covenants which include a current ratio of 1 to 1, excluding the fair value of derivative instruments, and a consolidated debt to EBITDAX (earnings before interest, taxes, depreciation, amortization and exploration) ratio of 3.75 to 1. The financial covenants are based on the financial statements of Delta and only its wholly-owned subsidiaries. At March 31, 2008, we were in compliance with our quarterly debt covenants and restrictions.

The borrowing base is re-determined by the lending banks at least semiannually on April 1 and October 1 of each year, or by special re-determinations if requested by the Company based on drilling success. If, as a result of any reduction in the amount of our borrowing base, the total amount of the outstanding debt were to exceed the amount of the borrowing base in effect, then, within 30 days after we are notified of the borrowing base deficiency, we would be required to (1) make a mandatory payment of principal to reduce our outstanding indebtedness so that it would not exceed our borrowing base, (2) eliminate the deficiency by making three equal monthly principal payments, (3) provide additional collateral for consideration to eliminate the deficiency within

90 days or (4) eliminate the deficiency through a combination of (1) through (3). If for any reason we were unable to pay the full amount of the mandatory prepayment within the requisite 30-day period, we would be in default of our obligations under our credit facility. There was no change to our borrowing base as a result of the October 2007 redetermination.

The credit facility includes terms and covenants that place limitations on certain types of activities, including restrictions or requirements with respect to additional debt, liens, asset sales, hedging activities, investments, dividends, mergers and acquisitions, and includes financial covenants.

Under certain conditions, amounts outstanding under the credit facility may be accelerated. Bankruptcy and insolvency events with respect to us or certain of our subsidiaries will result in an automatic acceleration of the indebtedness under the credit facility. Subject to notice and cure periods in certain cases, other events of default under the credit facility will result in acceleration of the indebtedness at the option of the lending banks. Such other events of default include non-payment, breach of warranty, non-performance of obligations under the credit facility (including financial covenants), default on other indebtedness, certain pension plan events, certain adverse judgments, change of control, and a failure of the liens securing the credit facility.

This facility is secured by a first and prior lien to the lending banks on most of our oil and gas properties, certain related equipment, and oil and gas inventory.

Credit Facility — DHS

On December 20, 2007, DHS entered into a new $75.0 million credit agreement with Lehman Commercial Paper Inc. The proceeds were used to pay off the JP Morgan credit facility. The credit facility has a variable interest rate based on 90-day LIBOR plus a fixed margin of 5.50% and matures on December 31, 2010. Annual principal payments are based upon a calculation of excess cash flow (as defined) for the preceding year. DHS is required to meet certain financial covenants quarterly beginning March 31, 2008 including (i) consolidated EBITDA for four consecutive fiscal quarters must be greater than $20.0 million; (ii) Consolidated Leverage Ratio (as defined) for four consecutive fiscal quarters cannot exceed 3.50 to 1.00; (iii) Consolidated Interest Coverage Ratio (as defined) for four consecutive fiscal quarters must exceed 2.50 to 1.00 and (iv) the Current Ratio for any fiscal quarter must be greater than 1.0 to 1.0. DHS incurred $1.3 million of financing charges in conjunction with the agreement which are being amortized over the life of the loan. At March 31, 2008, DHS was in compliance with its quarterly debt covenants and restrictions.

Other Contractual Obligations

Our asset retirement obligation arises from the costs necessary to plug and abandon our oil and gas wells. The majority of this obligation will not occur during the next five years.

Our corporate office in Denver, Colorado is under an operating lease which will expire in 2014. Our average yearly payments approximate $1.3 million over the life of the lease. We have additional operating lease commitments that represent office equipment leases and short-term debt obligations primarily relating to field vehicles and equipment.

We had a current derivative liability of $17.5 million at March 31, 2008. The ultimate settlement amounts of these hedges are unknown because they are subject to continuing market fluctuations. See Item 3. “Quantitative and Qualitative Disclosures about Market Risk” for more information regarding our derivative instruments.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations were based on the consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. Our significant accounting policies are

described in Note 2 to our consolidated financial statements. We have identified certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by management. We analyze our estimates, including those related to oil and gas reserves, bad debts, oil and gas properties, marketable securities, income taxes, derivatives, contingencies and litigation, and base our estimates on historical experience and various other assumptions that we believe are reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the application of the following critical accounting policies affect our more significant judgments and estimates used in the preparation of our financial statements.

Successful Efforts Method of Accounting

We account for our natural gas and crude oil exploration and development activities utilizing the successful efforts method of accounting. Under this method, costs of productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized. Oil and gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for gas and oil leases, are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities. The sale of a partial interest in a proved property is accounted for as a cost recovery and no gain or loss is recognized as long as this treatment does not significantly affect the unit-of-production amortization rate. A gain or loss is recognized for all other sales of producing properties.

The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as developmental or exploratory which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze and the determination that commercial reserves have been discovered requires both judgment and industry experience. Wells may be completed that are assumed to be productive and actually deliver gas and oil in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. Wells are drilled that have targeted geologic structures that are both developmental and exploratory in nature and an allocation of costs is required to properly account for the results. Delineation seismic costs incurred to select development locations within an oil and gas field is typically considered a development cost and capitalized, but often these seismic programs extend beyond the reserve area considered proved and management must estimate the portion of the seismic costs to expense. The evaluation of gas and oil leasehold acquisition costs requires judgment to estimate the fair value of these costs with reference to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.

The successful efforts method of accounting can have a significant impact on the operational results reported when we are entering a new exploratory area in hopes of finding a gas and oil field that will be the focus of future development drilling activity. The initial exploratory wells may be unsuccessful and will be expensed. Seismic costs can be substantial which will result in additional exploration expenses when incurred.

Reserve Estimates

Estimates of gas and oil reserves, by necessity, are projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of gas and oil that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable gas and oil reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions governing future gas and oil prices, future operating costs, severance taxes, development costs and workover gas costs, all of which may in fact vary considerably from actual results. The future drilling costs associated with reserves assigned to proved undeveloped locations may ultimately increase to an extent that these reserves may later be determined to be uneconomic. For these reasons, estimates of the economically recoverable quantities of gas and oil attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and

estimates of the future net cash flows expected therefrom may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of our gas and oil properties and/or the rate of depletion of the gas and oil properties. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material.

Impairment of Gas and Oil Properties

We review our oil and gas properties for impairment quarterly or whenever events and circumstances indicate a decline in the recoverability of their carrying value. We estimate the expected future cash flows of our developed proved properties and compare such future cash flows to the carrying amount of the proved properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and gas properties to their fair value. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures and production costs, and a discount rate commensurate with the risk associated with realizing the expected cash flows projected.

Given the complexities associated with gas and oil reserve estimates and the history of price volatility in the gas and oil markets, events may arise that would require us to record an impairment of the recorded book values associated with gas and oil properties. For developed properties, the review consists of a comparison of the carrying value of the asset with the asset’s expected future undiscounted cash flows without interest costs. As a result of such assessment, we recorded no impairment provision of proved properties for the three months ended March 31, 2008. During the remainder of 2008, we are continuing to develop and evaluate certain proved and unproved properties on which favorable or unfavorable results or fluctuations in commodity prices may cause us to revise in future periods our estimates of future cash flows from those properties. Such revisions of estimates could require us to record an impairment in the period of such revisions.

Commodity Derivative Instruments and Hedging Activities

We may periodically enter into commodity derivative contracts or fixed-price physical contracts to manage our exposure to oil and natural gas price volatility. We primarily utilize futures contracts, swaps or options, which are generally placed with major financial institutions or with counterparties of high credit quality that we believe represent minimal credit risks.

All derivative instruments are recorded on the balance sheet at fair value. Effective July 1, 2007, we elected to discontinue cash flow hedge accounting prospectively. Beginning July 1, 2007, we recognize mark-to-market gains and losses in current earnings instead of deferring those amounts in accumulated other comprehensive income for the contracts that qualify as cash flow hedges.

Asset Retirement Obligation

We account for our asset retirement obligations under Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (“SFAS No. 143”). SFAS No. 143 requires entities to record the fair value of a liability for retirement obligations of acquired assets. We adopted SFAS No. 143 on July 1, 2002 and recorded a cumulative effect of a change in accounting principle on prior years related to the depreciation and accretion expense that would have been reported had the fair value of the asset retirement obligations, and corresponding increase in the carrying amount of the related long-lived assets, been recorded when incurred. Our asset retirement obligations arise from the plugging and abandonment obligations for our gas and oil wells.

In March 2005, the FASB issued FASB Interpretation 47 (“FIN 47”), an interpretation of SFAS No. 143. FIN 47 clarifies the term “conditional asset retirement obligation” as it is used in SFAS No. 143. We applied the guidance of FIN 47 beginning July 1, 2005, which has not had an impact on our financial statements.

Deferred Tax Asset Valuation Allowance

We follow SFAS No. 109 to account for our deferred tax assets and liabilities. Under SFAS No. 109, deferred tax assets and liabilities are recognized for the estimated future tax effects attributable to temporary differences and carryforwards. Ultimately, realization of a deferred tax benefit depends on the existence of sufficient taxable income within the carryback/carryforward period to absorb future deductible temporary differences or a carryforward. In assessing the realizability of deferred tax assets, management must consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. Management considers all available evidence (both positive and negative) in determining whether a valuation allowance is required. Such evidence includes the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment, and judgment is required in considering the relative weight of negative and positive evidence. As a result of management’s current assessment, we maintain a significant valuation allowance against our deferred tax assets. We will continue to monitor facts and circumstances in our reassessment of the likelihood that operating loss carryforwards and other deferred tax attributes will be utilized prior to their expiration. As a result, we may determine that the deferred tax asset valuation allowance should be increased or decreased. Such changes would impact net income through offsetting changes in income tax expense or benefit.

Recently Issued Accounting Pronouncements

In March 2008, the FASB affirmed FASB Staff Position (“FSP”) APB 14-a, “Accounting for Convertible Debt Instruments That May Be Settled in Cash Upon Conversion (Including Partial Cash Settlement)”. The proposed FSP would require the proceeds from the issuance of convertible debt instruments to be allocated between a liability component (debt issued at a discount) and an equity component. The resulting debt discount would be amortized over the period the convertible debt is expected to be outstanding as additional non-cash interest expense. As of the date of filing of this Form 10-Q, the FASB had not finalized this FSP. If finalized, the FSP would be effective for fiscal years beginning after December 15, 2008, or our first quarter 2009. If adopted, this FSP would change the accounting treatment for our 3³/4% Senior Convertible Notes since it is to be applied retrospectively upon adoption. We are currently evaluating the potential impact of this proposed interpretation on our consolidated financial statements in the event that this pronouncement is adopted by the FASB.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities-an amendment of FASB Statement No.133” (SFAS 161). This Statement requires enhanced disclosures for derivative and hedging activities. This statement is effective for financial statements issued for fiscal years beginning after November 15, 2008, or fiscal year 2009. We are currently evaluating the potential impact of the adoption of SFAS 161 on our consolidated financial statements.

In December 2007, the FASB issued SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS 141R”), which replaces SFAS 141. SFAS 141R establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any resulting goodwill, and any noncontrolling interest in the acquiree. The Statement also provides for disclosures to enable users of the financial statements to evaluate the nature and financial effects of the business combination. SFAS 141R is effective for financial statements issued for fiscal years beginning after December 15, 2008, or fiscal year 2009, and must be applied prospectively to business combinations completed on or after that date. We will evaluate how the new requirements could impact the accounting for any acquisitions completed beginning in fiscal year 2009 and beyond, and the potential impact on our consolidated financial statements

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements — an amendment of Accounting Research Bulletin No. 51” (“SFAS 160”), which establishes accounting and reporting standards for noncontrolling interests (“minority interests”) in subsidiaries. SFAS 160 clarifies that a noncontrolling interest in a subsidiary should be accounted for as a component of equity separate from the parent’s equity. SFAS 160 is effective for financial statements issued for fiscal years beginning after December 15, 2008, or fiscal year 2009, and must be applied prospectively, except for the presentation and

disclosure requirements, which will apply retrospectively. We are currently evaluating the potential impact of the adoption of SFAS 160 on our consolidated financial statements.

Recently Adopted Accounting Pronouncements

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS 159”). SFAS 159 permits companies to choose to measure many financial instruments and certain other items at fair value. SFAS 159 is effective for financial statements issued for fiscal years beginning after November 15, 2007, or fiscal year 2008. We adopted SFAS 159 effective January 1, 2008, but did not elect to apply the SFAS 159 fair value option to eligible assets and liabilities during the three months ended March 31, 2008.

We adopted SFAS 157 for fair value measurements not delayed by FSP No. 157-2. The adoption resulted in additional disclosures as required by the pronouncement related to our fair value measurements for oil and gas derivatives and marketable securities, but no change in our fair value calculation methodologies. Accordingly, the adoption had no impact on our financial condition or results of operations.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Market Rate and Price Risk

We actively manage our exposure to commodity price fluctuations by hedging meaningful portions of our expected production through the use of derivatives, including costless collars, swaps, and puts. The level of our hedging activity and the duration of the instruments employed depend upon our view of market conditions, available hedge prices and our operating strategy. We use hedges to limit the risk of fluctuating cash flows that fund our capital expenditure program. We also may use hedges in conjunction with acquisitions to achieve expected economic returns during the payout period.

The following table summarizes our open derivative contracts at March 31, 2008:


											Net Fair Value
				Price Floor /							Asset (Liability) at
Commodity	Volume			Price Ceiling					Term	Index	March 31, 2008
											(In thousands)
Crude oil		1,200	Bbls / day	$	65.00	/	$	79.77	Apr ’08 - June ’08	NYMEX – WTI	$	(2,318	)
Crude oil		1,200	Bbls / day	$	65.00	/	$	79.86	July ’08 - Sept ’08	NYMEX – WTI		(2,243	)
Crude oil		1,200	Bbls / day	$	65.00	/	$	79.83	Oct ’08 - Dec ’08	NYMEX – WTI		(2,177	)
Natural gas		15,000	MMBtu / day	$	6.50	/	$	8.30	Apr ’08 - Dec ’08	CIG		(2,840	)
Natural gas		10,000	MMBtu / day	$	6.00	/	$	7.25	Apr ’08 - Sept ’08	CIG		(2,199	)
Natural gas		10,000	MMBtu / day	$	6.50	/	$	7.70	Apr ’08 - June ’08	CIG		(581	)
Natural gas		10,000	MMBtu / day	$	6.50	/	$	8.15	July’08 - Sept ’08	CIG		(729	)
Natural gas		10,000	MMBtu / day	$	6.50	/	$	7.90	Oct ’08 - Dec ’08	CIG		(1,086	)
Natural gas		35,000	MMBtu / day	$	7.50	/	$	9.88	Jan ’09 - Mar ’09	CIG		(2,819	)
Natural gas		10,000	MMBtu / day	$	9.00	/	$	11.53	Oct ’08 - Dec ’08	NYMEX-H HUB		(506	)

											$	(17,498	)

Subsequent to March 31, 2008, we entered into the following additional derivative contracts:


				Price Floor /
Commodity	Volume			Price Ceiling					Term	Index
Natural gas		10,000	MMBtu / day	$	9.00	/	$	10.58	Apr ’09 - June ’09	NYMEX-H HUB
Natural gas		15,000	MMBtu / day	$	9.00	/	$	10.70	Apr ’09 - June ’09	NYMEX-H HUB
Natural gas		10,000	MMBtu / day	$	9.00	/	$	10.82	July’09 - Sept ’09	NYMEX-H HUB
Natural gas		15,000	MMBtu / day	$	9.00	/	$	10.90	July’09 - Sept ’09	NYMEX-H HUB
Natural gas		10,000	MMBtu / day	$	9.00	/	$	12.05	Oct ’09 - Dec ’09	NYMEX-H HUB
Natural gas		15,000	MMBtu / day	$	9.00	/	$	11.95	Oct ’09 - Dec ’09	NYMEX-H HUB

The net fair value of our derivative instruments was a $17.5 million liability at March 31, 2008 and a $27.6 million liability on May 6, 2008.

Assuming production and the percent of oil and gas sold remained unchanged for the three months ended March 31, 2008, a hypothetical 10% decline in the average market price we realized during the three months ended March 31, 2008 on unhedged production would reduce our oil and natural gas revenues by approximately $4.5 million.

Interest Rate Risk

We were subject to interest rate risk on $75.0 million of variable rate debt obligations at March 31, 2008. The annual effect of a 10% change in interest rates would be approximately $782,000. The interest rate on these variable debt obligations approximates current market rates as of March 31, 2008.

Item 4. Controls and Procedures

Disclosure Controls and Procedures

Under the supervision and with the participation of our management, including our Chief Executive Officer (CEO) and Chief Financial Officer (CFO), we conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rule 13a-15(e) under the Exchange Act. Based on this evaluation, our management, including our CEO and our CFO, concluded that our disclosure controls and procedures were effective as of March 31, 2008, to ensure that information required to be disclosed by us in the reports filed or submitted by us under the Exchange Act (i) is recorded, processed, summarized and reported within the time period specified in SEC rules and forms, and (ii) is accumulated and communicated to our management, including our CEO and our CFO, as appropriate to allow timely decisions regarding required disclosure.

Internal Control over Financial Reporting

There were no changes in internal control over financial reporting that occurred during the fiscal quarter covered by this report that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II — OTHER INFORMATION

Item 1. Legal Proceedings.

Offshore Litigation

We and our 92% owned subsidiary, Amber, are among twelve plaintiffs in a lawsuit that was filed in the United States Court of Federal Claims (the “Court”) in Washington, D.C. alleging that the U.S. government materially breached the terms of forty undeveloped federal leases, some of which are part of our offshore California properties. On November 15, 2005 and October 31, 2006, the Court granted summary judgment as to liability and

partial summary judgment as to damages with respect to thirty six of the forty total federal leases that are the subject of the litigation. Under a restitution theory of damages, the Court ruled that the government must give back to the current lessees the more than $1.1 billion in lease bonuses it had received at the time of sale. On January 19, 2006, the government filed a motion for reconsideration of the Court’s ruling as it relates to a single lease owned entirely by us (“Lease 452”). In its motion for reconsideration, the government has asserted that we should not be able to recover lease bonus payments for Lease 452 because, allegedly, a significant portion of the hydrocarbons has been drained by wells that were drilled on an immediately adjacent lease. The amount of lease bonus payments attributable to Lease 452 is approximately $92.0 million. A trial on the motion for reconsideration was completed in January 2008 and post-trial briefing is currently in process. We believe that the government’s assertion is without merit, but we cannot predict with certainty the ultimate outcome of this matter.

On January 12, 2007, the Court entered an order of final judgment awarding the lessees restitution of the original lease bonuses paid for thirty-five of the forty lawsuit leases. Under this order we are entitled to receive a gross amount of approximately $58.5 million, and Amber is entitled to receive a gross amount of approximately $1.5 million as reimbursement for the lease bonuses paid for all lawsuit leases other than Lease 452. The government has appealed the order and contends that, among other things, the Court erred in finding that it breached the leases, and in allowing the current lessees to stand in the shoes of their predecessors for the purposes of determining the amount of damages that they are entitled to receive. The current lessees are also appealing the order of final judgment to, among other things, challenge the Court’s rulings that they cannot recover their and their predecessors’ sunk costs as part of their restitution claim. No payments will be made until all appeals have either been waived or exhausted. In the event that we ultimately receive any proceeds as the result of this litigation, we will be obligated to pay a portion to landowners and other owners of royalties and similar interests, to pay the litigation expenses and to fulfill certain pre-existing contractual commitments to third parties.

Shareholder Derivative Suit

Within the past few years, there has been significant focus on corporate governance and accounting practices in the grant of equity based awards to executives and employees of publicly traded companies, including the use of market hindsight to select award dates to favor award recipients. After being identified in a third-party report as statistically being at risk for possibly backdating option grants, in May 2006 our Board of Directors created a special committee comprised of outside directors. The special committee, which was advised by independent legal counsel and advisors, undertook a comprehensive review of our historical stock option practices and related accounting treatment. In June 2006, we received a subpoena from the U.S. Attorney for the Southern District of New York and an inquiry from the staff of the Securities and Exchange Commission (“SEC”) related to our stock option grants and related practices. The special committee of our Board of Directors reported to the Board that, while its review revealed deficiencies in the documentation of our option grants in prior years, there was no evidence of option backdating or other misconduct by our executives or directors in the timing or selection of our option grant dates, or that would cause us to conclude that our prior accounting for stock option grants was incorrect in any material respect. We provided the results of the internal investigation to the U.S. Attorney and to the SEC in August of 2006, and were subsequently informed by both agencies that the matter had been closed.

During September and October of 2006, three separate shareholder derivative actions were filed on our behalf in U.S. District Court for the District of Colorado relating to the options backdating issue, all of which were consolidated into a single action. The consolidated complaint alleged that certain of our executive officers and directors engaged in various types of misconduct in connection with certain stock option grants. Specifically, the plaintiffs alleged that the defendant directors, in their capacity as members of our Board of Directors and our Audit or Compensation Committee, at the behest of the defendants who are or were officers and to benefit themselves, backdated our stock option grants to make it appear as though they were granted on a prior date when our stock price was lower. They alleged that these backdated options unduly benefited the defendants who are or were officers and/or directors, resulted in our issuing materially inaccurate and misleading financial statements and caused us to incur substantial damages. The action also sought to have the current and former officers and directors who are defendants disgorge to us certain options they received, including the proceeds of options exercised, as well as certain equitable relief and attorneys’ fees and costs. On September 26, 2007, the Court entered an Order dismissing the action for failing to plead sufficient facts to support the claims that were made in

the complaint, and stayed the dismissal for ten days to allow the Plaintiffs to file a motion for leave to file an amended complaint. Extensions were granted and the Plaintiffs filed such a motion on October 29, 2007. The stay will remain in effect until the Court rules on the motion.

Castle/Longs Trust Litigation

As a result of the acquisition of Castle Energy in April 2006, our wholly-owned subsidiary, DPCA LLC, as successor to Castle, became party to Castle’s ongoing litigation with the Longs Trust in District Court in Rusk County, Texas. The Longs Trust litigation, which was originally the subject of a jury trial in November 2000, has been separated into two pending suits, one in which the Longs Trust is seeking relief on contract claims regarding oil and gas sales and gas balancing under joint operating agreements with various Castle entities, and the other in which Castle’s claims for unpaid joint interest billings and attorneys’ fees in the amount of $964,000, plus prejudgment interest, have been granted by the trial court and upheld on appeal. We intend to vigorously defend the Longs Trust breach of contract claims. We have not accrued any recoveries associated with the judgment against the Longs Trust, but will do so when and if they are ultimately collected.

Management does not believe that these proceedings, individually or in the aggregate, will have a material adverse effect on our financial position, results of operations or cash flows.

Item 1A. Risk Factors

A description of the risk factors associated with our business is contained in Item 1A, “Risk Factors,” of our 2007 Annual Report on Form 10-K for the year ended December 31, 2007 filed with the SEC on February 29, 2008 and incorporated herein by reference. There have been no material changes in our Risk Factors disclosed in our Annual Report on Form 10-K.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

During the quarter ended March 31, 2008, we did not have any sales of securities in transactions that were not registered under the Securities Act of 1933, as amended (“Securities Act”), that have not been reported in a Form 8-K.

Item 3. Defaults Upon Senior Securities. None.

Item 4. Submission of Matters to a Vote of Security Holders.

A special meeting of our stockholders was held on February 19, 2008 for the purpose of voting on the following two proposals recommended by our Board of Directors: (1) the issuance of 36,000,000 shares of our common stock to Tracinda Corporation pursuant to a Company Stock Purchase Agreement dated as of December 29, 2007 by and between us and Tracinda Corporation, and (2) the adoption of a second amendment to our certificate of incorporation to increase the maximum authorized number of directors from eleven to fifteen. The issuance of shares to Tracinda Corporation was approved with 47,374,487 affirmative votes, 131,893 negative votes, and 27,349 abstentions, and the adoption of a second amendment to our certificate of incorporation was approved with 60,100,771 affirmative votes, 338,381 negative votes, and 33,825 abstentions.

Item 5. Other Information. None.

	3.1		Certificate of Incorporation of the Company, as amended. Filed herewith electronically

	10.1		Carry and Earning Agreement between EnCana Oil & Gas (USA) Inc. and the Company, dated February 28, 2008. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K dated February 28, 2008.

	31.1		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. Filed herewith electronically

	31.2		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. Filed herewith electronically

	32.1		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350. Filed herewith electronically

	32.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350. Filed herewith electronically


	DELTA PETROLEUM CORPORATION (Registrant)
	By:	/s/ Roger A. Parker
		Roger A. Parker
		Chairman and Chief Executive Officer


	By:	/s/ Kevin K. Nanke
		Kevin K. Nanke, Treasurer and
		Chief Financial Officer

	3.1		Certificate of Incorporation of the Company, as amended. Filed herewith electronically

	10.1		Carry and Earning Agreement between EnCana Oil & Gas (USA) Inc. and the Company, dated February 28, 2008. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K dated February 28, 2008.

	31.1		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. Filed herewith electronically

	31.2		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. Filed herewith electronically

	32.1		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350. Filed herewith electronically

	32.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350. Filed herewith electronically


	Page No.
PART I FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements

Consolidated Balance Sheets – March 31, 2008 and December 31, 2007 (unaudited)		1

Consolidated Statements of Operations – Three Months Ended March 31, 2008 and 2007 (unaudited)		2

Consolidated Statement of Changes in Stockholders’ Equity and Comprehensive Loss — Three Months Ended March 31, 2008 (unaudited)		3

Consolidated Statements of Cash Flows — Three Months Ended March 31, 2008 and 2007 (unaudited)		4

Notes to Consolidated Financial Statements (unaudited)		5

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		27

Item 3. Quantitative and Qualitative Disclosures About Market Risk		39

Item 4. Controls and Procedures		40

PART II OTHER INFORMATION

Item 1. Legal Proceedings		40

Item 1A. Risk Factors		42

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		42

Item 3. Defaults upon Senior Securities		42

Item 4. Submission of Matters to a Vote of Security Holders		42

Item 5. Other Information		42

Item 6. Exhibits		43

Certificate of Incorporation of the Company, as amended

Carry and Earning Agreement, dated February 28, 2008, between EnCana Oil and Gas (USA) Inc. and the Company

Certification of CEO Pursuant to Section 302

Certification of CFO Pursuant to Section 302

Certification of CEO Pursuant to Section 18 USC Section 1350

Certification of CFO Pursuant to Section 18 USC Section 1350