Par Pacific Holdings - 10-Q quarterly report FY

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, 2007


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

370 17th Street, Suite 4300
Denver, Colorado		80202
(Address of principal executive offices)		(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, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act).

Large accelerated filer þ Accelerated filer o Non-accelerated filer o

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

65,687,000 shares of common stock, $.01 par value per share, were outstanding as of May 4, 2007.

INDEX


		Page No.
PART I	FINANCIAL INFORMATION

Item 1.	Consolidated Financial Statements

	Consolidated Balance Sheets – March 31, 2007 (unaudited) and December 31, 2006		1

	Consolidated Statements of Operations – Three Months Ended March 31, 2007 and 2006 (unaudited)		2

	Consolidated Statement of Changes in Stockholders’ Equity and Comprehensive Loss — Three Months Ended March 31, 2007 (unaudited)		3

	Consolidated Statements of Cash Flows — Three Months Ended March 31, 2007 and 2006 (unaudited)		4

	Notes to Consolidated Financial Statements (unaudited)		5

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		24

Item 3.	Quantitative and Qualitative Disclosures About Market Risk		37

Item 4.	Controls and Procedures		37

PART II	OTHER INFORMATION

Item 1.	Legal Proceedings		37

Item 1A.	Risk Factors		39

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		39

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		42

	Underwriting Agreement dated January 25, 2007 between Delta Petroleum Corporation and J.P. Morgan Securities Inc., acting on behalf of itself and Coker, Palmer, Phillips & Mullen, Inc.
	Restricted Stock Award Agreement dated February 5, 2007 Delta Petroleum Corporation and Roger A. Parker.
	Restricted Stock Award Agreement dated February 5, 2007 Delta Petroleum Corporation and John R. Wallace.
	Restricted Stock Award Agreement dated February 5, 2007 Delta Petroleum Corporation and Kevin K. Nanke.
	Restricted Stock Award Agreement dated February 5, 2007 Delta Petroleum Corporation and Stanley F. Freedman.
	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

The terms “Delta,” “Company,” “we,” “our,” and “us” refer to Delta Petroleum Corporation and its consolidated entities unless the context suggests otherwise.

i

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


	March 31,			December 31,
	2007			2006
	(Unaudited)
	(In thousands, except share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	13,032		$	7,666
Assets held for sale		288			5,397
Trade accounts receivable, net of allowance for doubtful accounts of $100 and $100, respectively		31,266			29,503
Prepaid assets		3,585			4,384
Inventory		3,135			2,851
Derivative instruments		6,466			10,799
Other current assets		2,770			2,769

Total current assets		60,542			63,369


Property and equipment:
Oil and gas properties, successful efforts method of accounting
Unproved		219,919			218,380
Proved		599,914			591,149
Drilling and trucking equipment		148,213			136,038
Pipeline and gathering system		16,919			14,909
Other		14,106			13,983

Total property and equipment		999,071			974,459
Less accumulated depreciation and depletion		(140,690	)		(132,814	)

Net property and equipment		858,381			841,645


Long-term assets:
Deferred financing costs		6,273			6,928
Goodwill		7,747			7,747
Other long-term assets		10,477			9,655
Deferred tax assets		5,338			—

Total long-term assets		29,835			24,330


Total assets	$	948,758		$	929,344


LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Current portion of long-term debt	$	947		$	816
Accounts payable		80,426			84,439
Other accrued liabilities		10,990			10,818
Deferred tax liability		2,136			2,893
Derivative instruments		—			613

Total current liabilities		94,499			99,579


Long-term liabilities:
7% Senior notes, unsecured		149,403			149,384
Credit facility		106,500			118,000
Unsecured term loan		—			25,000
Credit facility – DHS		84,700			74,050
Asset retirement obligation and other debt, net		3,433			4,048
Deferred tax liability		—			3,660

Total long-term liabilities		344,036			374,142


Minority interest		27,443			27,390

Commitments and contingencies		—			—

Stockholders’ equity:
Preferred stock, $.01 par value:
authorized 3,000,000 shares, none issued		—			—
Common stock, $.01 par value:
authorized 300,000,000 shares, issued 58,564,000 shares at March 31, 2007 and 53,439,000 at December 31, 2006		586			534
Additional paid-in capital		503,354			430,479
Accumulated other comprehensive income		5,229			4,865
Accumulated deficit		(26,389	)		(7,645	)

Total stockholders’ equity		482,780			428,233


Total liabilities and stockholders’ equity	$	948,758		$	929,344

See accompanying notes to consolidated financial statements.

1

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)


	Three Months Ended
	March 31,
	2007			2006
	(In thousands, except per share amounts)
Revenue:
Oil and gas sales	$	25,004		$	28,705
Contract drilling and trucking fees		16,294			10,114
Gain (loss) on effective derivative instruments, net		1,190			(1,774	)


Total revenue		42,488			37,045


Operating expenses:
Lease operating expense		4,429			4,755
Transportation expense		922			603
Production taxes		1,533			1,534
Depreciation, depletion and amortization – oil and gas		17,386			11,363
Depreciation and amortization – drilling and trucking		5,134			2,524
Exploration expense		624			683
Dry hole costs		3,517			1,340
Drilling and trucking operations		10,464			5,903
General and administrative		11,545			8,411
Gain on sale of oil and gas properties		—			(18,869	)


Total operating expenses		55,554			18,247


Operating income (loss)		(13,066	)		18,798


Other income and (expense):
Other income		151			136
Gain on sale of investment in LNG		—			1,058
Gain (loss) on ineffective derivative instruments, net		(1,663	)		6,576
Minority interest		17			(531	)
Interest and financing costs		(7,595	)		(5,494	)


Total other income (expense)		(9,090	)		1,745


Income (loss) from continuing operations before income taxes and discontinued operations		(22,156	)		20,543

Income tax expense (benefit)		(7,476	)		7,738


Income (loss) from continuing operations		(14,680	)		12,805

Discontinued operations:
Income from discontinued operations of properties sold, net of tax		598			1,000
Loss on sale of discontinued operations, net of tax		(4,662	)		—


Net income (loss)	$	(18,744	)	$	13,805


Basic income (loss) per common share:
Loss from continuing operations	$	(0.27	)	$	0.26
Discontinued operations		(0.07	)		0.02

Net income (loss)	$	(0.34	)	$	0.28


Diluted income (loss) per common share:
Loss from continuing operations	$	(0.27	)	$	0.25
Discontinued operations		(0.07	)		0.02

Net income (loss)	$	(0.34	)	$	0.27

See accompanying notes to consolidated financial statements.

2

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES

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


							Accumulated
					Additional		other
	Common stock				paid-in		comprehensive			Comprehensive			Accumulated
	Shares		Amount		capital		income			loss			deficit			Total
	(In thousands)
Balance, January 1, 2007		53,439	$	534	$	430,479	$	4,865					$	(7,645	)	$	428,233

Comprehensive loss:
Net loss		—		—		—		—		$	(18,744	)		(18,744	)		(18,744	)
Other comprehensive income transactions, net of tax
Hedging gains reclassified to income upon settlement, net of tax expense of $438		—		—		—		(751	)		(751	)		—			(751	)
Change in fair value of derivative hedging instruments, net of tax expense of $650		—		—		—		1,115			1,115			—			1,115

Comprehensive loss										$	(18,380	)

Shares issued for oil and gas properties		754		8		13,840		—						—			13,848
Shares issued for cash, net of offering costs		2,768		28		56,371		—						—			56,399
Shares issued for cash upon exercise of options		2		—		22		—						—			22
Issuance and amortization of non-vested stock		1,601		16		2,323		—						—			2,339
Compensation on options vested		—		—		319		—						—			319


Balance, March 31, 2007		58,564	$	586	$	503,354	$	5,229					$	(26,389	)	$	482,780

See accompanying notes to consolidated financial statements.

3

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)


	Three Months Ended
	March 31,
	2007			2006
	(In thousands)
Cash flows operations activities:
Net income (loss)	$	(18,744	)	$	13,805
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion and amortization – oil and gas		17,321			11,317
Depreciation and amortization – drilling and trucking		5,134			2,524
Depreciation, depletion and amortization – discontinued operations		810			1,766
Accretion of abandonment obligation		65			46
Stock option and non-vested stock compensation		2,719			1,040
Amortization of deferred financing costs		837			309
Amortization of bond discount		19			19
Gain loss on ineffective derivative contracts		1,663			(7,172	)
Dry hole costs and impairment		2,525			292
Minority interest		(17	)		531
Gain on sale of oil and gas properties		—			(18,869	)
Gain on sale of investment in LNG		—			(1,058	)
Loss on sale of discontinued operations		6,608			—
DHS stock granted to management		70			70
Deferred income tax expense (benefit)		(9,038	)		8,343
Other		2,635			—
Net changes in operating assets and operating liabilities:
Increase in trade accounts receivable		(1,439	)		(2,127	)
Decrease in prepaid assets		799			270
Decrease in inventory		(284	)		(633	)
(Increase) decrease in other current assets		(132	)		323
Increase (decrease) in accounts payable trade		808			(6,989	)
Increase in other accrued liabilities		169			3,312


Net cash provided by operating activities		12,528			7,119


Cash flows from investing activities:
Additions to property and equipment		(61,278	)		(45,393	)
Acquisitions, net of cash acquired		(4,500	)		(24,005	)
Proceeds from sales of oil and gas properties		40,277			42,810
Drilling and trucking capital expenditures		(12,175	)		(13,893	)
Minority interest holder contributions		—			9,018
Increase in long-term assets		(102	)		(266	)


Net cash used in investing activities		(37,778	)		(31,729	)


Cash flows from financing activities:
Stock issued for cash upon exercise of options		—			2,838
Stock issued for cash, net		56,399			33,870
Proceeds from borrowings		48,500			19,000
Payment of financing fees		(52	)		(108	)
Repayment of borrowings		(74,231	)		(19,235	)


Net cash provided by financing activities		30,616			36,365


Net increase in cash and cash equivalents		5,366			11,755

Cash at beginning of period		7,666			5,519


Cash at end of period	$	13,032		$	17,274


Supplemental cash flow information –
Common stock issued for the acquisition of oil and gas properties	$	13,848		$	16,099


Common stock issued for drilling and trucking equipment	$	—		$	8,294


Cash paid for interest and financing costs	$	4,124		$	1,600

See accompanying notes to consolidated financial statements.

4

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES

Notes to Consolidated Financial Statements
Three Months Ended March 31, 2007 and 2006
(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 filed with the Company’s annual report on Form 10-K for the year ended December 31, 2006. 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, 2006, previously filed with the Securities and Exchange Commission.

(2) Summary of Significant Accounting Policies

Principles of Consolidation and Basis of Presentation

The consolidated financial statements include the accounts of Delta, Amber, Piper, CRBP, PGR, DHS, 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. The Company has no interests in any other unconsolidated entities nor does it have any off-balance sheet financing arrangements (other than operating leases) or any unconsolidated special purpose entities.

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.

Certain reclassifications have been made to amounts reported in previous years to conform to the current year presentation. Among other items, revenues and expenses on properties that were sold during the quarter ended March 31, 2007 have been reclassified to income from discontinued operations for all periods presented. Such reclassifications had no effect on net income.

Cash Equivalents

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

5

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2007 and 2006
(Unaudited)

(2) Summary of Significant Accounting Policies, Continued

Assets Held for Sale

Assets held for sale as of March 31, 2007 represent the certain interests in Oklahoma that were designated by our Board of Directors to be sold within one year.

Assets held for sale as of December 31, 2006 represented Kansas properties that were sold during the three months ended March 31, 2007 and certain interests in Oklahoma that are expected to be sold within one year.

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.

Investment in LNG project

On March 30, 2006, the Company sold its long-term minority investment in a LNG project for total proceeds of $2.1 million. The Company recorded a gain on sale of $1.1 million ($657,000 net of tax).

Minority Interest

Minority interest represents the 50.6% (45% for Chesapeake Energy Corporation, 5.6% for DHS executive officers and management) investors of DHS at March 31, 2007 and December 31, 2006.

Revenue Recognition

Oil and gas

Revenues are recognized when title to the products transfer to the purchaser. The Company follows the “sales method” of accounting for its natural gas and crude oil revenue, so that 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, 2007 and December 31, 2006, the Company’s aggregate natural gas and crude oil imbalances were not material to its consolidated financial statements.

Drilling and Trucking

We earn our contract drilling revenues under daywork or turnkey contracts. We recognize revenues on daywork contracts for the days completed based on the dayrate each contract specifies. 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

6

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2007 and 2006
(Unaudited)

(2) Summary of Significant Accounting Policies, Continued

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 and other property and equipment are 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.

Impairment of Long-Lived Assets

Statement of Financial Accounting Standards No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets” (“SFAS No. 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 No. 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 attributable to developed properties for the three months ended March 31, 2007 and 2006, respectively.

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 the three months ended March 31, 2007 and 2006.

During the remainder of 2007, we are continuing to develop and evaluate certain proved and unproved properties on which favorable or unfavorable results or commodity prices may cause us to revise in future quarters our estimates of those properties’ future cash flows. Such revisions of estimates could require us to record an impairment in the period of such revisions.

7

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2007 and 2006
(Unaudited)

(2) Summary of Significant Accounting Policies, Continued

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 will be performed at least annually in accordance with the provisions of Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets” (“SFAS No. 142”). No impairment of goodwill was indicated as a result of the Company’s impairment test performed during the third quarter of 2006.

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, 2007 to March 31, 2007 (amounts in thousands):


Asset retirement obligation – January 1, 2007	$	4,442
Accretion expense		65
Change in estimate		(7	)
Obligations acquired		140
Obligations settled		—
Obligations on sold properties		(877	)

Asset retirement obligation – March 31, 2007		3,763
Less: Current asset retirement obligation		(333	)

Long-term asset retirement obligation	$	3,430

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, 2007 and 2006 are as follows:


	Three Months Ended
	March 31,
	2007			2006
	(in thousands)
Net income (loss)	$	(18,744	)	$	13,805
Other comprehensive income (transactions)
Hedging (gains) losses reclassified to income upon settlement, net of tax expense (benefit) of $438 and ($669), respectively		(751	)		1,105
Change in fair value of derivative hedging instruments, net of tax expense (benefit) of ($650) and $294, respectively		1,115			(485	)

		364			620

Comprehensive income (loss)	$	(18,380	)	$	14,425

8

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2007 and 2006
(Unaudited)

(2) Summary of Significant Accounting Policies, Continued

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. All transactions are accounted for in accordance with requirements of Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”). Accordingly, unrealized gains and losses related to the change in fair market value of derivative contracts which qualify and are designated as cash flow hedges are recorded in accumulated other comprehensive income or loss, to the extent the hedge is effective, and such amounts are reclassified to realized gain (loss) on derivative instruments as the associated production occurs.

At March 31, 2007, 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.

Derivative contracts that do not qualify for hedge accounting treatment are recorded as derivative assets and liabilities at market value in the consolidated balance sheet, and the associated unrealized gains and losses are recorded as a component of other income or expense in the consolidated statement of operations. While such derivative contracts do not qualify for hedge accounting, management believes these contracts can be utilized as an effective component of commodity price risk activities.

The following table summarizes our open derivative contracts at March 31, 2007 and indicates those that qualify for hedge accounting and those that do not qualify for hedge accounting:

Net Fair Value

Price Floor /

Asset at

Commodity

Volume

Price Ceiling

Term

Index

March 31, 2007

(In thousands)

Contracts that qualify for hedge accounting

Natural gas

15,000 MMBtu / day

$6.00 / $7.55

Apr ’07 - June ’07

CIG

2,274

Natural gas

15,000 MMBtu / day

$6.00 / $8.45

July ’07 - Sept ’07

CIG

1,599

Natural gas

15,000 MMBtu / day

$7.00 / $9.15

Oct ’07 - Dec ’07

CIG

2,261

Contracts that do not qualify for hedge accounting

Natural gas

10,000 MMBtu / day

$7.00 / $11.40

July ’07 - Sept ’07

NYMEX-H HUB

144

Natural gas

10,000 MMBtu / day

$7.00 / $16.30

Oct ’07 - Dec ’07

NYMEX-H HUB

188

$

6,466

The net fair value of the Company’s derivative instruments obligation was an asset of approximately $6.5 million at March 31, 2007 and an asset of $5.1 million on May 3, 2007.

The net gains (losses) on effective derivative instruments recognized in the Company’s statements of operations were $1.2 million and ($1.8) million for the three months ended March 31, 2007 and 2006, respectively. These gains (losses) are recorded as an increase or (decrease) in revenues.

9

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2007 and 2006
(Unaudited)

(2) Summary of Significant Accounting Policies, Continued

In March 2007, the Company cash settled its remaining 2007 oil hedges for proceeds of approximately $2.3 million. This amount will be recorded as an increase to revenue during the remainder of 2007 in the time periods production was scheduled to occur. As a result, the Company currently has no outstanding oil derivative contracts.

In April 2007, the Company entered into CIG gas collar contracts for 2008 gas production with a floor of $6.50 and a ceiling of $8.30 on 15,000 MMBtus per day.

Stock Option Plans

Prior to July 1, 2005, the Company accounted for its stock option plans in accordance with the provisions of Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations. As such, compensation expense was recorded on the date of grant only if the current market price of the underlying stock exceeded the exercise price.

In December 2004, Statement of Financial Accounting Standards No. 123 (Revised 2004), “Share Based Payment” (“SFAS No. 123R”) was issued, which now 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 No. 123R effective July 1, 2005 using the modified prospective method and recognized compensation expense related to stock options of $319,000 and $473,000, relating to employee provided services during the three months ended March 31, 2007 and 2006, respectively.

Non-Qualified Stock Options — Directors and Employees

On December 14, 2004, the stockholders ratified the Company’s 2004 Incentive Plan (the “2004 Plan”) under which it reserved up to an additional 1,650,000 shares of common stock for issuance. Although grants of shares of common stock were made under the 2004 Plan during the 2006 fiscal year, no stock options were issued by the Company during that period.

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, 2007 ranged from $1.75 to $15.60 per share and the weighted-average remaining contractual life of those options was 4.2 years. The Company has not issued stock options since the adoption of SFAS No. 123R. At March 31, 2007, the Company had 2,357,776 options outstanding.

10

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2007 and 2006
(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 Statement of Financial Accounting Standards No. 109 (SFAS No. 109), “Accounting for Income Taxes.” 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 No. 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.

Earnings (Loss) per Share

Basic earnings (loss) per share is computed by dividing net earnings (loss) attributed to common stock by the weighted average number of common shares outstanding during each period, excluding treasury shares. Diluted earnings (loss) per share is computed by adjusting the average number of common shares outstanding for the dilutive effect, if any, of convertible preferred stock, stock options, restricted stock and warrants. (See Footnote 9, “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, marketable securities, income taxes, derivatives, asset retirement obligations, contingencies and litigation accruals. Actual results could differ from these estimates.

Recently Issued Accounting Pronouncements

In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, “Fair Value Measurements” (“SFAS No. 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 No. 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 No. 157 upholds the requirements of previously issued pronouncements concerning fair value measurements and expands the required disclosures. This Statement is effective for fiscal year commencing January 1, 2008. The Company has not yet completed its assessment of how adoption of this pronouncement may impact the Company’s financial position or results of operations.

In September 2006, the Securities and Exchange Commission issued Staff Accounting Bulletin No. 108 (“SAB 108”). SAB 108 was issued to provide interpretive guidance on how the effects of the carryover reversal of prior year misstatements should be considered in quantifying a current year misstatement. The provisions of SAB 108 are effective for the December 31, 2006 year-end. The adoption of SAB 108 had no impact on our financial position or results of operations.

11

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2007 and 2006
(Unaudited)

(2) Summary of Significant Accounting Policies, Continued

Effective January 1, 2007, the Company adopted 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 first quarter of 2007, no adjustments were recognized for uncertain tax benefits.

The Company recognizes interest and penalties related to uncertain tax positions in income tax benefit/expense. No interest and penalties related to uncertain tax positions were accrued at March 31, 2007.

The tax years 2004 through 2006 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.

(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 $13.2 million and $12.5 million at March 31, 2007 and December 31, 2006, 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. Preliminary exploration efforts on these properties have occurred and the existence of substantial quantities of hydrocarbons has been indicated. The recovery of the Company’s investment in these properties will require extensive exploration and development activities (and costs) that cannot proceed without certain regulatory approvals that have been delayed and is subject to other substantial risks and uncertainties.

The Company and its 92% owned subsidiary, Amber Resources Company of Colorado (“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 the Company’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.

The Court has further ruled under a restitution theory of damages 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. Together with Amber, the Company’s net share of the $1.1 billion award is approximately $120 million. This award is subject to appeal and the government has filed a motion for reconsideration of the ruling as it relates to a single lease owned entirely by the Company. The value attributed to this lease represents significantly more than half of the net amount that would be received by the Company under the summary judgment. In its motion for reconsideration, the government has asserted that the affected lease is not being returned in substantially the same condition that it was in at the time it was initially granted because, allegedly, a significant portion of the hydrocarbons has been drained by wells that were drilled on an immediately adjacent lease. Although discovery is continuing on this issue, the Company currently believes that the government’s assertion is without merit and is vigorously contesting it; however, the Company cannot predict with certainty the ultimate outcome of this matter.

12

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2007 and 2006
(Unaudited)

(3) Oil and Gas Properties, Continued

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. The government has appealed this 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.

Acquisitions During the Quarter Ended March 31, 2007

On March 9, 2007, the Company issued 754,000 shares of common stock valued at approximately $13.8 million using the 5-day average closing price for additional interests in two wells already owned and operated by the Company located in Polk County, Texas.

On March 1, 2007, the Company paid $3.5 million for 39,000 undeveloped net acres in Fremont County, Wyoming.

In March 2007, the Company executed an earn-in agreement with Encana whereby the Company can earn up to 6,000 net acres in the Piceance Basin with the drilling of 128 wells during the next 36 months. The Company is committed to drill 64 total wells, eight of which must be completed by October 31, 2007. The remaining wells are required to be completed by June 1, 2009. The Company is liable for $250,000 per undrilled well in the event the drilling obligations are not met.

Acquisitions During the Quarter Ended March 31, 2006

On February 1, 2006 Delta entered into a purchase and sale agreement with Armstrong Resources, LLC (“Armstrong”) to acquire a 65% working interest in approximately 88,000 undeveloped gross acres in the central Utah Hingeline play for a purchase price of $24 million in cash and 673,401 shares of common stock valued at $16.1 million. The closing of the transaction was effective as of January 26, 2006. Armstrong retained the remaining 35% working interest in the acreage. As part of the transaction, Delta agreed to pay 100% of the drilling costs for the first three wells in the project. Delta will be the operator of the majority of the acreage, and drilling of the first well commenced in November 2006.

Fiscal 2006 – Dispositions

During December 2005, Delta transferred its ownership in approximately 427,000 gross acres (64,000 net acres) of non-operated interests in the Columbia River Basin to CRBP. In January and March 2006, Delta sold a combined 44% minority interest in CRBP. As the sale involved unproved properties, no gain on the partial sale of CRBP could be recognized until all of the cost basis of CRBP had been recovered. Accordingly, the Company recorded a $13.0 million gain, ($8.1 million net of tax) and an $11.2 million reduction to property during the first quarter of 2006 as a result of closing the transaction. Delta now owns a net interest of just over 32,300 acres in the Columbia River Basin through its remaining ownership of CRBP and additional interests in 345,000 net acres in the Columbia River Basin from previous transactions.

13

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2007 and 2006
(Unaudited)

(3) Oil and Gas Properties, Continued

In March 2006, the Company sold approximately 26% of PGR. This transaction involved both proved and unproved property interests and accordingly, to the extent the sale of PGR related to unproved properties, no gain could be recognized as all of the unproved cost basis was not yet recovered. The Company recorded a gain of $5.9 million, $3.7 million net of tax, and a $3.4 million offset to property during the first quarter of 2006 as a result of the transaction. The Company retains a 74% interest in PGR.

Discontinued Operations

In accordance with SFAS No. 144, the results of operations and gain (loss) relating to the sale of the following property interests have been reflected as discontinued operations.

On June 1, 2006, the Company completed the sale of certain properties located in Pointe Coupee Parish, Louisiana, for cash consideration of $8.9 million with an effective date of May 1, 2006. The transaction resulted in an after-tax gain on sale of oil and gas properties of $596,000. The total revenues and pre-tax income from discontinued operations of these oil and gas properties were approximately $588,000 and $172,000 for the three months ended March 31, 2006 and are included in income from discontinued operations of properties sold in the consolidated statements of operations.

On January 10, 2007, the Company completed the sale of certain non-core properties located in Padgett field, Kansas for cash consideration of $5.6 million. The transaction resulted in an after-tax gain on sale of properties of $175,000. The total revenues and pre-tax income from discontinued operations for these assets were $96,000 and $85,000 for the three months ended March 31, 2007, respectively, and $871,000 and $176,000 for the three months ended March 31, 2006, respectively.

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. The total revenues and pre-tax income from discontinued operations for these assets were $187,000 and $174,000 for the three months ended March 31, 2007, respectively, and $158,000 and $146,000 for the three months ended March 31, 2006, respectively.

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 $31.5 million, prior to customary purchase price adjustments. The sale resulted in an after-tax loss of $6.8 million. The total revenues and pre-tax income from discontinued operations for these assets were $2.5 million and $760,000 for the three months ended March 31, 2007, respectively, and $3.0 million and $771,000 for the three months ended March 31, 2006, respectively.

(4) DHS Drilling Operations

On March 5, 2007, DHS purchased a Mid Continent Unit 36AE drilling rig (“Rig 18”) for cash consideration of $7.6 million funded with borrowings on the DHS credit facility. The rig is an 800 horsepower rig with a depth rating of 10,500 feet. The rig is currently operating in the Rocky Mountain Region.

14

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2007 and 2006
(Unaudited)

(5) Long Term Debt

7% Senior Unsecured Notes, due 2015

On March 15, 2005, the Company issued 7% senior unsecured notes for an aggregate amount of $150.0 million, which pay interest semiannually on April 1 and October 1 and mature in 2015. The net proceeds were used to refinance debt outstanding under our credit facility which included the amount required to acquire the Manti properties. 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 may 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, 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 Company was not in default (as defined in the indenture) under the indenture as of March 31, 2007. (See Footnote 10, “Guarantor Financial Information”). The fair value of the Company’s senior notes at March 31, 2007 was approximately $135.0 million.

Credit Facility

In November 2006, the Company amended its credit facility with JP Morgan Chase Bank, N.A. At March 31, 2007, the $250.0 million credit facility had an available borrowing base of approximately $130.0 million with $106.5 million outstanding. 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 + .25% and 1.00% for base rate loans and between Libor + 1.5% and 2.25% for Eurodollar loans. The Company’s effective LIBOR and prime rates at March 31, 2007 approximated 7.07% and 8.50%, 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, 2007 which include a current ratio of 1 to 1, net of derivative instruments, and a consolidated debt to EBITDAX (earnings before interest, taxes, depreciation, amortization and exploration) of less than 4.25 to 1 for the quarters ending March 31 and June 30, 2007, 4.0 to 1 for the quarters ending September 30 and December 31, 2007, and 3.75 to 1 for the end of each quarter thereafter. The financial covenants only include subsidiaries which the Company owns 100%. At March 31, 2007, the Company was not in compliance with its current ratio covenant, but obtained a waiver from the banks for that non-compliance. On April 25, 2007, the credit facility was fully paid down with a portion of the proceeds from the Company’s equity and debt offerings (See Footnote 12, “Subsequent Event”).

Unsecured Term Loan

In December 2006 the Company entered into an agreement with JP Morgan Chase Bank N.A., for a $25.0 million unsecured term loan with interest at LIBOR plus a margin of 3.5% at December 31, 2006. The note was paid in full in January 2007 with the proceeds from the $56.4 million equity offering.

15

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2007 and 2006
(Unaudited)

(5) Long Term Debt, Continued

Credit Facility – DHS

On May 4, 2006, DHS entered into a new $100.0 million senior secured credit facility with JP Morgan Chase Bank, N.A and initially borrowed $75.0 million. The facility had a delayed draw feature that was utilized during the three months ended March 31, 2007 to borrow an additional $15 million of which $4.2 million was subsequently repaid. Borrowings on the facility bear interest at LIBOR plus 300 basis points. The facility includes financial covenants which require a maximum debt to EBITDA ratio of 2.50 to 1.00 (with such ratio decreasing to 2.25 to 1.00 for the quarters ending March 31, 2008 through December 31, 2008 and 2.00 to 1.00 for the fiscal quarters ending March 31, 2009 through March 31, 2012) and a minimum EBITDA to interest expense ratio of 4.00 to 1.00 (increasing to 4.50 to 1.00 for the fiscal quarters ending June 30, 2007 through December 31, 2007, and increasing again to 5.00 to 1.00 for the fiscal quarters ending March 31, 2008 and thereafter). The facility matures on May 4, 2012 and requires quarterly principal payments of 0.25% of the amount outstanding. In addition, an annual mandatory prepayment is required each April based on a percentage of excess cash flow (as defined) during the preceding fiscal year, although no such payment was required in April 2007. The facility is non-recourse to Delta. At March 31, 2007, DHS was in compliance with its quarterly debt covenants and restrictions.

Five Year Maturities of Long-Term Debt

Borrowing availability under the Delta bank credit facility at March 31, 2007 was approximately $23.5 million and zero under the DHS facility. Maturities of long-term debt, in thousands of dollars based on contractual terms, are as follows:


YEAR ENDING March 31,
2008	$	947
2009		11,549
2010		9,504
2011		115,408
2012		7,559
Thereafter		197,183

	$	342,150

(6) Commitments and Contingencies

Change in Control Agreements

On April 30, 2007, the Company entered into agreements with its four executive officers which provide for severance payments equal to three times the calculated average of the officer’s combined annual salary and bonus, benefit continuation and accelerated vesting of options and stock grants in the event there is a change in control of the Company. These agreements contain terms that are similar to prior agreements that expired by their terms on December 31, 2006.

Shareholder Derivative Suits

In the past year, 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

16

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2007 and 2006
(Unaudited)

(6) Commitments and Contingencies, Continued

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 Securities and Exchange Commission (“SEC”) related to the Company’s stock option grants and related practices. The special committee of the Company’s Board of Directors has 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 the SEC in August 2006 and intends to continue to cooperate fully with the U.S. Attorney and the SEC if they should request any additional information concerning this matter in the future.

During September and October of 2006, three separate shareholder derivative actions were filed on the Company’s behalf in US District Court for the District of Colorado relating to the options backdating issue, all of which have been consolidated into a single action. The consolidated complaint alleges 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 allege 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 allege 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 seeks 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. A discovery stay has been granted while the court considers various motions to dismiss the action.

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.

17

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2007 and 2006
(Unaudited)

(7) 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, 2007 and December 31, 2006, no preferred stock was issued.

Common Stock

On March 9, 2007, the Company issued 754,000 shares of common stock valued at approximately $13.8 million for additional interests in two wells already owned and operated by the Company located in Polk County, Texas.

On February 9, 2007, the Company issued executive performance share grants to each of the Company’s four executive officers 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 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 it is $50, for the third tranche it is $60, for the fourth tranche it is $75 and for the fifth tranche it is $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. Upon attaining the Vesting Thresholds for each of the fourth and fifth tranches, 150,000 of Mr. Parker’s shares would vest for each such tranche, 105,000 of Mr. Wallace’s shares would vest for each such tranche and 60,000 of Mr. Nanke’s and Mr. Freedman’s shares would each vest for each such tranche. Each award provides for the lapse of the $75 and $90 tranches if the $40 tranche has not vested on or before March 31, 2008, and the lapse of the $50 and $60 tranches 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.

On January 25, 2007, the Company received net proceeds of $56.4 million from a public offering of 2,768,000 shares of the Company’s common stock.

(8) 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 ($7.5) million and $7.7 million, for the three months ended March 31, 2007 and 2006, 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 taxable income, and tax planning strategies in making this assessment. Based upon the level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, management believes it is more likely than not that the Company will realize the benefits of these deductible

18

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2007 and 2006
(Unaudited)

(8) Income Taxes, Continued

differences, net of the existing valuation allowances at March 31, 2007 and December 31, 2006. The valuation allowance at December 31, 2006 related primarily to a subsidiary’s net operating loss that cannot be used to reduce taxable income generated by other members of the consolidated tax group and a deferred tax asset generated by a subsidiary that is not consolidated for tax purposes and does not have a history of earnings. During the quarter ended March 31, 2007, the Company sold its Australian properties for a taxable gain and accordingly released the valuation allowance previously recorded on the related deferred tax assets. In addition, the Company recorded a valuation allowance on the deferred tax asset related to net operating loss carryforwards that expire in 2007. The amount of the deferred tax asset considered realizable could be reduced if estimates of future taxable income during the carry-forward period are reduced.

Effective January 1, 2007, the Company adopted 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 first quarter of 2007, no adjustments were recognized for uncertain tax benefits.

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, 2007.

The tax years 2003 through 2006 for federal returns and 2002 through 2006 remain open for state returns 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.

(9) Earnings Per Share

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


	Three Months Ended
	March 31,
	2007			2006
	(In thousands, except per share amounts)
Numerator:
Numerator for basic and diluted income per share – income (loss) available to common stockholders	$	(18,744	)	$	13,805

Denominator:
Denominator for basic income per share – weighted average shares outstanding		54,933			49,769
Effect of dilutive stock options and unrestricted stock grants		*			1,565


Denominator for diluted income per common share		54,933			51,334


Basic income (loss) per common share	$	(.34	)	$	.28

Diluted income (loss) per common share	$	(.34	)	$	.27


*		Potentially dilutive securities outstanding of 1,474 at March 31, 2007 were anti-dilutive.

19

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2007 and 2006
(Unaudited)

(10) Guarantor Financial Information

Delta issued 7% Senior Notes (“Notes”) on March 15, 2005, for the aggregate amount of $150.0 million, which pay interest semiannually on April 1st and October 1st and mature in 2015. The net proceeds were used to refinance debt outstanding under the Company’s credit facility. The Notes are guaranteed by Piper Petroleum Company and certain other 100% owned subsidiaries of the Company (“Guarantors”). The Guarantors, fully, jointly and severally, irrevocably and unconditionally guarantee the performance and payment when due of all the obligations under the Notes. Big Dog, Shark, DHS, CRBP, PGR, DPCA and Amber (“Non-guarantors”) are not guarantors of the indebtedness under the Notes.

The following financial information sets forth the Company’s condensed consolidated balance sheets as of March 31, 2007 and December 31, 2006, the condensed consolidated statements of operations for the three months ended March 31, 2007 and 2006, and the condensed consolidated statements of cash flows for the three months ended March 31, 2007 and 2006 (in thousands).

Condensed Consolidated Balance Sheet
March 31, 2007


				Guarantor			Non-Guarantor			Adjustments/
	Issuer			Entities			Entities			Eliminations			Consolidated
Current assets	$	29,303		$	1,188		$	30,051		$	—		$	60,542

Property and equipment:
Oil and gas properties		759,220			446			62,059			(1,892	)		819,833
Drilling rigs and trucks		594			—			147,619			—			148,213
Other		25,480			4,320			1,225			—			31,025

Total property and equipment		785,294			4,766			210,903			(1,892	)		999,071

Accumulated DD&A		(114,825	)		(124	)		(25,741	)		—			(140,690	)


Net property and equipment		670,469			4,642			185,162			(1,892	)		858,381

Investment in subsidiaries		70,187			—			—			(70,187	)		—
Other long-term assets		16,806			3,739			9,290			—			29,835


Total assets	$	786,765		$	9,569		$	224,503		$	(72,079	)	$	948,758


Current liabilities	$	83,935		$	379		$	10,185		$	—		$	94,499

Long-term liabilities
Long-term debt, derivative instruments, and deferred taxes		243,374			1,800			95,429			—			340,603
Asset retirement obligation and other debt		3,356			9			68			—			3,433


Total long-term liabilities		246,730			1,809			95,497			—			344,036

Minority interest		27,443			—			—			—			27,443

Stockholders’ equity		428,657			7,381			118,821			(72,079	)		482,780


Total liabilities and stockholders’ equity	$	786,765		$	9,569		$	224,503		$	(72,079	)	$	948,758

20

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2007 and 2006
(Unaudited)

(10) Guarantor Financial Information, Continued

Condensed Consolidated Balance Sheet
December 31, 2006


				Guarantor			Non-Guarantor			Adjustments/
	Issuer			Entities			Entities			Eliminations			Consolidated
Current assets	$	35,521		$	2,447		$	25,401		$	—		$	63,369

Property and equipment:
Oil and gas properties		763,126			444			58,078			(12,119	)		809,529
Drilling rigs and trucks		595			—			135,443			—			136,038
Other		23,435			4,320			1,137			—			28,892

Total property and equipment		787,156			4,764			194,658			(12,119	)		974,459

Accumulated DD&A		(112,691	)		(119	)		(20,004	)		—			(132,814	)


Net property and equipment		674,465			4,645			174,654			(12,119	)		841,645

Investment in subsidiaries		66,366			—			—			(66,366	)		—
Other long-term assets		11,424			3,521			9,385			—			24,330


Total assets	$	787,776		$	10,613		$	209,440		$	(78,485	)	$	929,344


Current liabilities	$	88,344		$	1,200		$	10,035		$	—		$	99,579

Long-term liabilities
Long-term debt, derivative instruments, and other		283,695			1,600			84,799			—			370,094
Asset retirement obligation and other debt		3,956			9			83			—			4,048


Total long-term liabilities		287,651			1,609			84,882			—			374,142

Minority interest		27,390			—			—			—			27,390

Stockholders’ equity		384,391			7,804			114,523			(78,485	)		428,233


Total liabilities and stockholders’ equity	$	787,776		$	10,613		$	209,440		$	(78,485	)	$	929,344

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


				Guarantor			Non-Guarantor			Adjustments/
	Issuer			Entities			Entities			Eliminations			Consolidated
Total revenue	$	26,066		$	(589	)	$	21,591		$	(4,580	)	$	42,488

Operating expenses:
Oil and gas expenses		6,434			(129	)		579			—			6,884
Depreciation and depletion		16,943			(160	)		5,737			—			22,520
Exploration expense		624			—			—			—			624
Drilling and trucking operations		—			—			13,152			(2,688	)		10,464
Dry hole, abandonment and impaired		3,517			—			—			—			3,517
General and administrative		11,286			(623	)		882			—			11,545


Total expenses		38,804			(912	)		20,350			(2,688	)		55,554


Operating income (loss)		(12,738	)		323			1,241			(1,892	)		(13,066	)

Other income and (expenses)		(7,366	)		44			(1,785	)		17			(9,090	)
Income tax benefit (expense)		7,456			—			20			—			7,476
Income from discontinued operations, net of tax		598			—			—			—			598
Loss on sale of discontinued operations, net of tax		(4,662	)		—			—			—			(4,662	)


Net income (loss)	$	(16,712	)	$	367		$	(524	)	$	(1,875	)	$	(18,744	)

21

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2007 and 2006
(Unaudited)

(10) Guarantor Financial Information, Continued

Condensed Consolidated Statement of Operations
Three Months Ended March 31, 2006


				Guarantor		Non-Guarantor			Adjustments/
	Issuer			Entities		Entities			Eliminations			Consolidated
Total revenue	$	26,109		$	540	$	14,573		$	(4,177	)		37,045

Operating expenses:
Oil and gas expenses		6,773			90		29			—			6,892
Depreciation and depletion		11,351			42		2,494			—			13,887
Exploration expense		680			—		3			—			683
Drilling and trucking operations		—			—		8,017			(2,114	)		5,903
Dry hole, abandonment and impaired		1,340			—		—			—			1,340
General and administrative		7,438			18		955			—			8,411
Gain on sale of oil and gas properties		(18,869	)		—		—			—			(18,869	)


Total expenses		8,713			150		11,498			(2,114	)		18,247


Operating income (loss)		17,396			390		3,075			(2,063	)		18,798

Other income and (expenses)		3,432			1		(1,157	)		(531	)		1,745
Income tax expense		(7,738	)		—		—			—			(7,738	)
Income from discontinued operations, net of tax		1,000			—		—			—			1,000


Net income (loss)	$	14,090		$	391	$	1,918		$	(2,594	)	$	13,805

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


				Guarantor			Non-Guarantor
	Issuer			Entities			Entities			Consolidated
Operating activities	$	9,394		$	225		$	2,909		$	12,528
Investing activities		(20,635	)		(1,303	)		(15,840	)		(37,778	)
Financing activities		15,063			—			15,553			30,616


Net increase 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

Condensed Consolidated Statement of Cash Flows
Three Months Ended March 31, 2006


				Guarantor			Non-Guarantor
	Issuer			Entities			Entities			Consolidated
Operating activities	$	6,459		$	219		$	441		$	7,119
Investing activities		(17,578	)		(8	)		(14,143	)		(31,729	)
Financing activities		18,048			(283	)		18,600			36,365


Net increase (decrease) in cash and cash equivalents		6,929			(72	)		4,898			11,755

Cash at beginning of the period		1,949			216			3,354			5,519


Cash at the end of the period	$	8,878		$	144		$	8,252		$	17,274

22

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2007 and 2006
(Unaudited)

(11) Business Segments

The Company has two reportable segments: oil and gas exploration and production (“Oil and Gas”) and drilling operations (“Drilling”) through its ownership in DHS. Following is a summary of segment results for the three months ended March 31, 2007 and 2006:


							Inter-segment
	Oil and Gas			Drilling			Eliminations			Consolidated
Three Months Ended March 31, 2007
Revenues from external customers	$	26,194		$	16,294		$	—		$	42,488
Inter-segment revenues		—			4,580			(4,580	)		—

Total revenues	$	26,194		$	20,874		$	(4,580	)	$	42,488

Operating income (loss)	$	(12,906	)	$	1,732		$	(1,892	)	$	(13,066	)

Other expense¹		(7,322	)		(1,785	)		17			(9,090	)

Income (loss) from continuing operations, before tax	$	(20,228	)	$	(53	)	$	(1,875	)	$	(22,156	)


Three Months Ended March 31, 2006
Revenues from external customers	$	26,931		$	10,114		$	—		$	37,045
Inter-segment revenues		—			4,177			(4,177	)		—

Total revenues	$	26,931		$	14,291		$	(4,177	)	$	37,045

Operating income (loss)	$	18,036		$	2,825		$	(2,063	)	$	18,798

Other income and (expense)¹		3,432			(1,156	)		(531	)		1,745

Income (loss) from continuing operations, before tax	$	21,468		$	1,669		$	(2,594	)	$	20,543


1		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.

(12) Subsequent Event

On April 25, 2007, the Company issued 7,130,000 shares of common stock at $20.50 per share and issued $115.0 million aggregate principal amount of 3³/4% Senior Convertible Notes due 2037 (the “Notes”) for net proceeds of $251.9 million after underwriters’ discounts and commissions of $9.3 million.

The Notes bear interest at a rate of 3³/4% per annum, payable semi-annually in arrears, on May 1 and November 1 of each year, beginning November 1, 2007. The Notes will mature on May 1, 2037 unless earlier converted, redeemed or repurchased.

The Notes will be 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 its common stock, cash or a combination of cash and shares of its 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.

The combined net proceeds from these offerings of $251.9 million were used to pay down the Company’s credit facility to zero and will be used to fund the Company’s capital development program.

23

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 in fiscal year 2007; 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, 2006, 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;

	•		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, market, develop and produce 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;

24

	•		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; and

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

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

	•		Our total production for the three months ended March 31, 2007 was 3.9 Bcfe. Adjusted for asset dispositions, our production from continuing operations increased 4% to 3.5 Bcfe, compared to 3.4 Bcfe for the comparable prior year quarter.

	•		On January 30, 2007, we completed an equity offering for net proceeds of $56.4 million, of which $25 million was used to repay in full the $25 million unsecured term loan.

	•		In three different transactions, we divested of various non-core assets in Kansas, Texas/New Mexico and Australia for net cash proceeds of approximately $40.3 million.

The following discussion and analysis relates to items that have affected our results of operations for the three months ended March 31, 2007 and 2006. 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, 2007 Compared to Quarter Ended March 31, 2006

Net Income. Net loss was $18.7 million, or $.34 per diluted common share, for the three months ended March 31, 2007, compared to net income of $13.8 million, or $.27 per diluted common share, for the three months ended March 31, 2006. Income from continuing operations decreased from $12.8 million for the three months ended March 31, 2006 to a loss of $14.7 million for the three months ended March 31, 2007, due primarily to first quarter 2006 gains on undeveloped property sales and ineffective derivative instruments that did not occur during the first quarter 2007, and due to higher depreciation, depletion, and amortization expense, higher dry hole costs, and increased general and administrative expense.

Oil and Gas Sales. During the three months ended March 31, 2007, oil and natural gas revenue from continuing operations decreased 13% to $25.0 million, as compared to $28.7 million for the comparable period a year earlier. The decrease was the result of a 13% decrease in gas prices and a 10% decrease in oil prices, partially offset by a 4% increase in production from continuing operations. The average onshore gas price received during the three months ended March 31, 2007 of $5.86 per Mcf compared to $6.77 per Mcf for the year earlier period, a decrease in average onshore oil price received during the three months ended March 31, 2007 of $55.18 per Bbl compared to $60.82 per Bbl for the year earlier period, and a decrease in offshore oil price received of $40.76 per Bbl during the three months ended March 31, 2007 compared to $48.42 for the year earlier period.

Net gains (losses) from effective hedging activities were $1.2 million gain and $1.8 million loss for the three months ended March 31, 2007 and 2006, respectively. The gain in 2007 realized hedges is primarily due to lower oil prices. These gains (losses) are recorded as an increase or decrease in revenues.

25

Contract Drilling and Trucking Fees. Contract drilling and trucking fees for the three months ended March 31, 2007 increased to $16.3 million compared to $10.1 million for the year earlier period. The increase is the result of the increase from 11 to 17 rigs in operation by DHS.

Production and Cost Information

Production volumes, average prices received and cost per equivalent Mcf for the three months ended March 31, 2007 and 2006 are as follows:


	Three Months Ended March 31,
	2007					2006
	Onshore			Offshore		Onshore			Offshore
Production – Continuing Operations:
Oil (MBbl)		208			36		271			46
Gas (MMcf)		2,045			—		1,475			—
Production – Discontinued Operations:
Oil (MBbl)		21			—		47			—
Gas (MMcf)		282			—		398			—

Total Production (MMcfe)		3,704			219		3,782			278

Average Price – Continuing Operations:
Oil (per barrel)	$	55.18		$	40.76	$	60.82		$	48.42
Gas (per Mcf)	$	5.86		$	—	$	6.77		$	—

Costs per Mcfe – Continuing Operations:
Hedge effect	$	(.36	)	$	—	$	(.57	)	$	—
Lease operating expense	$	1.22		$	1.85	$	1.14		$	4.33
Production taxes	$	.46		$	.05	$	.49		$	.04
Transportation costs	$	.28		$	—	$	.19		$	—
Depletion, depreciation and amortization expense	$	5.20		$	1.40	$	3.59		$	.80

Lease Operating Expense. Lease operating expenses for the three months ended March 31, 2007 were $4.4 million compared to $4.8 million for the year earlier period. The decrease in lease operating expenses was primarily related to a one-time credit received during the three months ended March 31, 2007 on our offshore properties. Lease operating expense from continuing operations for onshore properties for the three months ended March 31, 2007 was $1.22 per Mcfe as compared to $1.14 per Mcfe for the year earlier period.

Depletion, Depreciation and Amortization – oil and gas. Depreciation, depletion and amortization expense increased 53% to $17.4 million for the three months ended March 31 2007, as compared to $11.4 million for the year earlier period. Our onshore depletion, depreciation and amortization rate increased to $5.20 per Mcfe for the three months ended March 31, 2007 from $3.59 per Mcfe for the year earlier period. Our depletion rate increase from the first quarter of 2006 is related to higher than expected drilling costs on certain Austin Chalk wells drilled since March 31, 2006, a reduction of reserves in certain targeted zones in the Howard Ranch field that were determined to be uneconomic during the second half of 2006, and to a lesser extent, the addition of a $3.0 million developmental dry hole in the South Angleton field to the depletion pool.

Depreciation and Amortization – drilling and trucking. Depreciation and amortization expense – drilling increased to $5.1 million for the three months ended March 31, 2007, as compared to $2.5 million for the year earlier period. This increase can be attributed to the additional rigs placed in service through DHS.

Exploration Expense. Exploration expense consists of geological and geophysical costs and lease rentals. Our exploration costs for the three months ended March 31, 2007 were $624,000 compared to $683,000 for the year

26

earlier period. Current year exploration activities include activities in our Columbia River Basin, central Utah Hingeline, and Newton County, Texas projects.

Dry Hole Costs. We incurred dry hole costs of approximately $3.5 million for the three months ended March 31, 2007 compared to $1.3 million for the comparable period a year ago. Our dry hole costs during 2006 related primarily to three exploratory projects, one in Orange County, California, one in Texas, and one in Utah. For the three months ended March 31, 2007, our dry hole costs related primarily to two exploratory projects, one in Texas and one in Utah.

Drilling and Trucking Operations. Drilling expenses increased to $10.5 million for the three months ended March 31, 2007 compared to $5.9 million for the comparable prior year period. This increase can be attributed to the increase in the number of rigs in operation, 17 rigs as of March 31, 2007 compared to 11 rigs at March 31, 2006.

General and Administrative Expense. General and administrative expense increased 37% to $11.5 million for the three months ended March 31, 2007, as compared to $8.4 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 $1.7 million and our 20% increase in technical and administrative staff and related personnel costs.

Gain on Sale of Oil and Gas Properties. In January and March 2006, Delta sold a combined 44% minority interest in CRBP. As the sale involved unproved properties, no gain on the partial sale of CRBP could be recognized until all of the cost basis of CRBP had been recovered. Accordingly, we recorded a $13.0 million gain, ($8.1 million net of tax) and an $11.2 million reduction to property during the first quarter of 2006 as a result of closing the transaction.

In March 2006, we sold approximately 26% of PGR Partners, LLC (“PGR”). This transaction involved both proved and unproved property interests and accordingly, to the extent the sale of PGR related to unproved properties, no gain could be recognized as all of the unproved cost basis was not yet recovered. We recorded a gain of $5.9 million, $3.7 million net of tax, and a $3.4 million offset to property during the first quarter of 2006 as a result of the transaction. We retained a 74% interest in, and are the manager of, PGR.

Gain on Sale of Investment in LNG Project. On March 30, 2006, we sold our long-term minority investment in an LNG project for total proceeds of $2.1 million. We recorded a gain on sale of $1.1 million ($657,000 net of tax).

Gain (Loss) on Ineffective Derivative Instruments, Net. During the three months ended September 30, 2005, our gas derivative contracts became ineffective and no longer qualified for hedge accounting. Hedge ineffectiveness results from different changes in the NYMEX contract terms and the physical location, grade and quality of our oil and natural gas production. The change in fair value of our NYMEX gas contracts is reflected in earnings, as opposed to being recorded in other comprehensive income (loss), a component of stockholders’ equity. As a result, we recognized a $1.7 million non-cash loss and a $6.6 million non-cash gain in our statement of operations during the three months ended March 31, 2007 and 2006, respectively. As commodity prices fluctuate, we will record our NYMEX gas derivative contracts at market value with any changes in market value recorded through unrealized gain (loss) on derivatives contracts in our statement of operations.

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, 2007, DHS generated greater profit resulting in increased minority interest expense.

Interest and Financing Costs. Interest and financing costs increased 38% to $7.5 million for the three months ended March 31, 2007, as compared to $5.5 million for the comparable year earlier period. The increase is primarily related to the increase in the average amount outstanding under our credit facility, higher interest rates, and the increased long term debt balance related to the DHS credit facility.

27

Income Tax Expense. During the three months ended March 31, 2007 an income tax benefit of $7.5 million was recorded and during the three months ended March 31, 2006 an income tax provision of $7.7 million was recorded for continuing operations at effective tax rates of 36.8% and 37.7%, respectively.

Discontinued Operations. Discontinued operations include the Frisco field in Pointe Coupee Parish, Louisiana, which was sold in June 2006, the Panola and Rusk County, Texas properties, which were sold in August 2006, the East Texas and Pennsylvania properties, which were sold in August 2006, the Kansas field, which was sold in January 2007, the Australia field and the New Mexico and East Texas properties, which were sold in March 2007.

Loss on Sale of Discontinued Operations. During the first quarter of 2007, we sold non-core properties in Kansas, Texas and New Mexico, and Australia for combined proceeds of $40.3 million and a combined net loss of $4.7 million ($6.6 million pre-tax).

Liquidity and Capital Resources

Liquidity is a measure of a company’s ability to access cash. Since December 31, 2006, we have completed several equity, debt, and property transactions as described below. On January 25, 2007, we completed a public offering of 2,768,000 shares of our common stock for net proceeds of $56.4 million. During the first quarter of 2007, we sold non-core properties in Kansas, Texas and New Mexico, and Australia for combined net proceeds of $40.3 million. On April 25, 2007, we issued 7,130,000 shares of common stock at $20.50 per share and issued $115.0 million aggregate principal amount of 3³/4% Senior Convertible Notes due 2037 for total net proceeds of $251.9 million after underwriters’ discounts and commissions of $9.3 million.

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, 2007, we had an operating loss of $13.1 million, but generated cash from operating activities of $12.5 million and obtained cash from financing activities of $30.6 million. During this period we spent $61.3 million on oil and gas development (or $21.0 million, net of $40.3 million proceeds from dispositions), $4.5 million on oil and gas acquisitions, and $12.2 million on drilling and trucking capital expenditures. At March 31, 2007, we had $13.0 million in cash, total assets of $949.0 million and a debt to capitalization ratio of 41.4%. Long-term debt at March 31, 2007 totaled $340.6 million, comprised of $191.2 million of combined bank debt and $149.4 million of senior subordinated notes. In May 2006, DHS closed a new $100.0 million Senior Secured Credit Facility with JP Morgan Chase Bank, N.A., as administrative agent, of which $75.0 million was initially drawn. In November, the borrowing base on our credit facility was increased by $10.0 million to $130.0 million. Available borrowing capacity under our bank credit facility at March 31, 2007 was approximately $23.5 million. DHS had no additional availability under its credit facility.

At March 31, 2007, we were not in compliance with our current ratio covenant, but obtained a waiver from the banks for that non-compliance. Our covenants require a minimum current ratio of 1 to 1, net of derivative instruments, and a consolidated debt to EBITDAX (earnings before interest, taxes, depreciation, amortization and exploration) of less than 4.25 to 1 for the quarters ending March 31 and June 30, 2007, 4.0 to 1 for the quarters ending September 30 and December 31, 2007, and 3.75 to 1 for the end of each quarter thereafter. These financial covenant calculations only reflect wholly-owned subsidiaries. On April 25, 2007, the credit facility was fully paid down with a portion of the proceeds from our equity and debt offerings.

Although we expect to continue with development of our properties, a significant portion of our planned capital expenditures are discretionary and can be delayed or curtailed, if necessary, given adequate lead time. If we do not meet our covenants in the future and we are unable to obtain a waiver from the banks, we would be in default of the terms of our credit facility, our long-term debt would be reclassified to a current liability in our consolidated balance sheet and the outstanding principal balance could be called by the banks, thereby becoming

28

immediately due and payable. During the fourth quarter of 2006, our credit facility was amended to contain covenant requirements that we believe better match our development plans and operating strategy.

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 additions to production.

Although we believe we have access to adequate capital to fund our development plans, we continue to examine alternative 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, 2007, we completed the following transactions:

On March 9, 2007, we issued 754,000 shares of common stock valued at approximately $13.8 million for additional interests in two wells already owned and operated by us located in Polk County, Texas.

On March 5, 2007, DHS purchased a Mid Continent Unit 36AE drilling rig (“Rig 18”) for $7.6 million. The rig is an 800 horsepower rig with a depth rating of 10,500 feet. The rig is currently operating in the Rocky Mountain Region.

On March 1, 2007, we paid $3.5 million for 39,000 net acres and interests in several wells in Fremont County, Wyoming.

Historical Cash Flow

Our cash flow from operating activities increased from $7.1 million for the three months ended March 31, 2006 to $12.5 million for the three months ended March 31, 2007, primarily as a result of changes in working capital which reduced 2006 operating cash flows. Our net cash used in investing activities increased to $37.8 million for the three months ended March 31, 2007 compared to net cash used in investing activities of $31.7 million for the year earlier period. The increase in cash used in investing activities is primarily due to the $9.0 million in minority interest contributions received during the quarter ended March 31, 2006. Cash provided by financing activities was $30.6 million for the three months ended March 31, 2007 compared to $36.4 million for the comparable prior year period. Cash provided by financing activities was lower in 2007 primarily due to significant repayments of borrowings during the quarter ended March 31, 2007.

29

Capital and Exploration Expenditures and Financing

Our capital and exploration expenditures and sources of financing for the three months ended March 31, 2007 and 2006 are as follows:


	2007			2006
	(In thousands)
CAPITAL AND EXPLORATION EXPENDITURES:
Acquisitions:
Polk County, TX (non-cash)	$	13,848		$	—
Fremont County, WY		3,500			—
Other		5,741			2,103
Armstrong acquisition		—			40,103

Other development costs		50,225			43,557
Drilling and trucking costs		12,175			13,893
Dry hole costs		3,517			1,340
Exploration costs		624			683

	$	89,360		$	101,679


FUNDING SOURCES:
Cash flow provided by operating activities	$	12,528		$	7,119
Stock issued for cash upon exercised options		—			2,838
Stock issued for cash, net		56,399			33,870
Net long-term borrowings (repayments)		(25,731	)		(235	)
Minority interest contributions		—			9,018
Proceeds from sale of oil and gas properties		40,277			42,810
Other		(102	)		(266	)

	$	83,371		$	95,154

Sales of Oil and Gas Properties

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 $31.5 million, prior to customary purchase price adjustments. The sale resulted in an after-tax loss of $6.8 million. The total revenues and pre-tax income from discontinued operations for these assets were $2.5 million and $760,000 for the three months ended March 31, 2007, respectively, and $3.0 million and $771,000 for the three months ended March 31, 2006, respectively.

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. The total revenues and pre-tax income from discontinued operations for these assets were $187,000 and $174,000 for the three months ended March 31, 2007, respectively, and $158,000 and $146,000 for the three months ended March 31, 2006, respectively.

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 an after-tax gain on sale of properties of $175,000. The total revenues and pre-tax income from discontinued operations for these assets were $96,000 and $85,000 for the three months ended March 31, 2007, respectively, and $871,000 and $176,000 for the three months ended March 31, 2006, respectively.

In March 2006, we sold approximately 26% of PGR for $20.4 million. This transaction involved both proved and unproved property interests and accordingly, to the extent the sale of PGR related to unproved properties, no gain could be recognized as all of the unproved cost basis was not yet recovered. We recorded a gain of $5.9 million, $3.7 million net of tax, and a $3.4 million reduction to property during the first quarter of 2006 as a result of the transaction. We have retained a 74% interest in PGR.

30

During December 2005, we transferred our ownership in approximately 427,000 gross acres (64,000 net acres) of non-operated interests in the Columbia River Basin to a newly created wholly owned subsidiary, CRBP. In January and March 2006, we sold a combined 44% minority interest in CRBP for total proceeds of $32.8 million. As the sale involved unproved properties, no gain on the partial sale of CRBP could be recognized until all of the cost basis of CRBP had been recovered. Accordingly, we recorded a $13.0 million gain, ($8.1 million net of tax) and an $11.2 million reduction to property during the first quarter of 2006 as a result of closing the transaction. As a result of the transaction, we now own a net interest of just over 32,300 acres in the Columbia River Basin through our remaining ownership of CRBP and additional 100% interests in 345,000 net acres in the Columbia River Basin from previous transactions.

Contractual and Long Term Debt Obligations


	Payments Due by Period
	Less than							After
Contractual Obligations at March 31, 2007	1 year		1-3 Years			3-5 Years		5 Years		Total
					(In thousands)
7% Senior unsecured notes	$	—	$	—		$	—	$	150,000	$	150,000
Interest on 7% Senior unsecured notes		10,500		21,000			21,000		36,283		88,783
Credit facility		—		—			106,500		—		106,500
DHS credit facility		900		21,050			16,467		47,183		85,600
Abandonment retirement obligation		333		448			371		7,955		9,107
Operating leases		3,009		5,796			2,906		3,262		14,973
Drilling commitments		8,000		14,000			—		—		22,000
Other debt obligations		47		3			—		—		50

Total contractual cash obligations	$	22,789	$	62,297		$	147,244	$	244,683	$	477,013

3³/4% Senior Convertible Notes

Subsequent to quarter-end 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 semi-annually in arrears, on May 1 and November 1 of each year, beginning November 1, 2007. The Notes will mature on May 1, 2037 unless earlier converted, redeemed or repurchased. The Notes will be 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.

7% Senior Unsecured Notes, due 2015

On March 15, 2005, we issued 7% senior unsecured notes for an aggregate face amount of $150.0 million which pay interest semiannually on April 1 and October 1 and mature in 2015. The net proceeds were used to refinance debt outstanding under our credit facility which included the amount required to acquire the Manti properties. 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 may limit our ability to, among other things, incur additional indebtedness, make certain investments, sell assets, 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.

31

Credit Facility

In November 2006, we amended our credit facility with JP Morgan Chase Bank, N.A. At March 31, 2007, the $250.0 million credit facility has an available borrowing base of approximately $130.0 million and $106.5 million outstanding. 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 + .25% and 1.00% for base rate loans and between Libor + 1.5% and 2.25% for Eurodollar loans. The facility is collateralized by substantially all of our oil and gas properties. Beginning with the quarter ended March 31, 2007, we are required to meet certain financial covenants which include a current ratio of 1 to 1, net of derivative instruments, and a consolidated debt to EBITDAX (earnings before interest, taxes, depreciation, amortization and exploration) of less than 4.25 to 1 for the quarters ending March 31 and June 30, 2007, 4.0 to 1 for the quarters ending September 30 and December 31, 2007, and 3.75 to 1 for the end of each quarter thereafter. The financial covenants only include subsidiaries which we own 100%. At March 31, 2007, we were not in compliance with our current ratio covenant, but we obtained a waiver from the banks for that non-compliance. On April 25, 2007, the credit facility was fully repaid with a portion of the proceeds from our equity and debt offerings.

Subsequent determinations of the borrowing base will be made by the lending banks at least semi-annually on April 1 and October 1 of each year, or as special re-determinations. 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 (1) to make a mandatory payment of principal to reduce our outstanding indebtedness so that it would not exceed our borrowing base, (2) to eliminate the deficiency by making three equal monthly principal payments, (3) within 90 days, to provide additional collateral for consideration to eliminate the deficiency or (4) to 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. The April 2007 redetermination resulted in no changes to our borrowing base.

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, oil and gas inventory, and certain bank accounts and proceeds.

Unsecured Term Loan

In December 2006 we entered into an agreement with JP Morgan Chase Bank N.A., for a $25.0 million unsecured term loan with interest at LIBOR plus a margin of 3.5% at December 31, 2006. The note was paid in full in January 2007 with the proceeds from the $56.4 million equity offering.

32

Credit Facility – DHS

On May 4, 2006, DHS entered into a new $100.0 million senior secured credit facility with JP Morgan Chase Bank, N.A and initially borrowed $75.0 million. The facility had a delayed draw feature that was utilized during the three months ended March 31, 2007 to borrow an additional $15 million of which $4.2 million was subsequently repaid. Borrowings on the facility bear interest at LIBOR plus 300 basis points. The facility includes financial covenants which require a maximum debt to EBITDA ratio of 2.50 to 1.00 (with such ratio decreasing to 2.25 to 1.00 for the quarters ending March 31, 2008 through December 31, 2008 and 2.00 to 1.00 for the fiscal quarters ending March 31, 2009 through March 31, 2012) and a minimum EBITDA to interest expense ratio of 4.00 to 1.00 (increasing to 4.50 to 1.00 for the fiscal quarters ending June 30, 2007 through December 31, 2007 and increasing again to 5.00 to 1.00 for fiscal quarters ending March 31, 2008 and thereafter). The facility matures in 2012 and requires quarterly principal payments of 0.25% of the amount outstanding. In addition, an annual mandatory prepayment is required each April based on a percentage of excess cash flow (as defined) during the preceding fiscal year. The facility is non-recourse to us. No mandatory prepayment is expected to be due in April 2007 due to capital expenditures. At March 31, 2007, 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 $1.1 million over the life of the lease. We have additional operating lease commitments which represent office equipment leases and short term debt obligations primarily relating to field vehicles and equipment.

In March 2007, we executed an earn-in agreement with Encana whereby we can earn up to 6,000 net acres in the Piceance Basin with the drilling of 128 wells during the next 36 months. We are committed to drill 64 total wells, eight of which must be completed by October 31, 2007. The remaining wells are required to be completed by June 1, 2009. We are liable for $250,000 per undrilled well in the event the drilling obligations are not met.

Derivative instruments had a positive fair market value at March 31, 2007 and thus no obligation was shown. The ultimate settlement amounts of these hedges are unknown because they are subject to continuing market risk. See Item 3. “Quantitative and Qualitative Disclosures about Market Risk” for more information regarding our hedges.

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 3 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 following critical accounting policies affect our more significant judgments and estimates used in the preparation of our financial statements.

33

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 managerial 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 be later 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.

34

We review our oil and gas properties for impairment at least annually 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 attributable to developed properties for the three months ended March 31, 2007. During the remainder of 2007, we are continuing to develop and evaluate certain proved and unproved properties on which favorable or unfavorable results or commodity prices may cause us to revise in future quarters our estimates of those properties’ future cash flows. 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 are minimal credit risks.

All derivative instruments are recorded on the balance sheet at fair value. Changes in the derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met. Due to the hedge effectiveness dependence upon future cash flows, production and reserve estimates and market price conditions, the hedges are continually re-evaluated for effectiveness. If at any time the hedges are determined to be ineffective, we could lose qualification for hedge accounting which could have a material impact on our statement of operations. For qualifying cash flow hedges, the gain or loss on the derivative is deferred in accumulated other comprehensive income (loss) to the extent the hedge is effective. Gains and losses on hedging instruments included in accumulated other comprehensive income (loss) are reclassified to oil and natural gas sales revenue in the period that the related production is delivered. Derivative contracts that do not qualify for hedge accounting treatment are recorded as derivative assets and liabilities at market value in the consolidated balance sheet, and the associated unrealized gains and losses are recorded as other expense or income in the consolidated statement of operations.

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 liabilities for our oil and gas 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 resulting in no impact on our financial statements.

35

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 valuation allowance against a portion of 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.

Recently Issued Accounting Pronouncements

In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, “Fair Value Measurements” (“SFAS No. 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 No. 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 No. 157 upholds the requirements of previously issued pronouncements concerning fair value measurements and expands the required disclosures. This Statement is effective for fiscal year commencing January 1, 2008. We have not yet completed our assessment of how adoption of this pronouncement may impact our financial position or results of operations.

In September 2006, the Securities and Exchange Commission issued Staff Accounting Bulletin No. 108 (“SAB 108”). SAB 108 was issued to provide interpretive guidance on how the effects of the carryover reversal of prior year misstatements should be considered in quantifying a current year misstatement. The provisions of SAB 108 are effective for the December 31, 2006 year-end. The adoption of SAB 108 had no impact on our financial position or results of operations.

Effective January 1, 2007, we adopted 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, we had no unrecognized tax benefits. During the first quarter of 2007, no adjustments were recognized for uncertain tax benefits.

We recognize interest and penalties related to uncertain tax positions in income tax benefit/expense. No interest and penalties related to uncertain tax positions were accrued at March 31, 2007.

The tax years 2004 through 2006 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.

36

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 net fair value of our derivative instruments was a $6.5 million asset at March 31, 2007 and a $5.1 million asset on May 3, 2007.

Assuming production and the percent of oil and gas sold remained unchanged for the three months ended March 31, 2007, a hypothetical 10% decline in the average market price we realized during the three months ended March 31, 2007 on unhedged production would reduce our oil and natural gas revenues by approximately $2.5 million on a quarterly basis.

Interest Rate Risk

We were subject to interest rate risk on $192.1 million of variable rate debt obligations at March 31, 2007. The annual effect of a 10% change in interest rates would be approximately $1.5 million. The interest rate on these variable debt obligations approximates current market rates as of March 31, 2007.

Item 4. 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 Rules 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, 2007, 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. 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 Resources Company of Colorado (“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.

The Court has further ruled under a restitution theory of damages 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. Together with Amber, our net share of the $1.1 billion award is approximately $120 million. This award is subject to appeal and the government has filed a motion for reconsideration of the ruling as it relates to a single lease owned entirely by us. The value attributed to this lease represents significantly more than half of the net amount that would be

37

received by us under the summary judgment. In its motion for reconsideration, the government has asserted that the affected lease is not being returned in substantially the same condition that it was in at the time it was initially granted because, allegedly, a significant portion of the hydrocarbons has been drained by wells that were drilled on an immediately adjacent lease. Although discovery is continuing on this issue, we currently believe that the government’s assertion is without merit and we are vigorously contesting it; however, 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. The government has appealed this 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.

Shareholder Derivative Suits

In the past year, 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 has 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’s office and to the SEC in August 2006 and intend to continue to cooperate fully with the U.S. Attorney and the SEC if they should request any additional information concerning this matter in the future.

During September and October of 2006, three separate shareholder derivative actions were filed on our behalf in US District Court for the District of Colorado relating to the options backdating issue, all of which have been consolidated into a single action. The consolidated complaint alleges that certain of our executive officers and directors engaged in various types of misconduct in connection with certain stock option grants. Specifically, the plaintiffs allege 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 allege 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 seeks 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. A discovery stay has been granted while the court considers various motions to dismiss the action.

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.

38

A description of the risk factors associated with our business is contained in Item 1A, “Risk Factors,” of our 2006 Annual Report on Form 10-K for the year ended December 31, 2006 filed with the Securities and Exchange Commission on March 7, 2007 and incorporated herein by reference. Except as set forth below, there have been no material changes in our Risk Factors disclosed in our Annual Report on Form 10-K.

Risks Related to Options Inquiries

As discussed in Footnote 6 “Commitments and Contingencies” of the accompanying financial statements, and “Item 1. Legal Proceedings,” we are cooperating with inquiries commenced by the U.S. Attorney and the SEC into matters related to our stock option grant practices, and we are the subject of a shareholder derivative suit related to these historical practices. Any adverse determination in these matters could adversely affect our business and results of operations. Further, the costs associated with this activity have been and may be expected to be significant, and the diversion of management time and attention from revenue generating activities to these matters may adversely affect our results of operations.

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

During the quarter ended March 31, 2007, 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, except as follows:

On March 12, 2007 we sold 754,000 shares of our common stock to WillSource Enterprise, LLC, Karl D. Smith, Ray A. Melvin, Thomas J. Wolf, Jr. and Enfield Energy Company in exchange for their collective interests in certain producing oil and gas properties located in Texas.

In connection with this transaction we relied on the exemption provided by Section 4(2) of the Securities Act. We reasonably believe that the investors are “Accredited Investors” as such term is defined in Rule 501 of Regulation D promulgated under the Securities Act at the time the transactions occurred. The investors acquired the shares for investment purposes. A restrictive legend was placed on the stock certificates issued in connection with the transaction and a stop transfer order was given to our transfer agent; however, on March 14, 2006, the offer and sale of all 350,000 shares were registered under the Securities Act pursuant to our Form S-3ASR (333-141303).

39

Present value or PV10% or “SEC PV10%.” When used with respect to oil and gas reserves, present value or PV10% or SEC PV10% means the estimated future gross revenue to be generated from the production of net proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, without giving effect to non-property related expenses such as general and administrative expenses, debt service, accretion, and future income tax expense or to depreciation, depletion, and amortization, discounted using monthly end-of-period discounting at a nominal discount rate of 10% per annum.

Productive wells. Producing wells and wells that are capable of production, including injection wells, salt water disposal wells, service wells, and wells that are shut-in.

Proved developed reserves. Estimated proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved reserves. Estimated quantities of crude oil, natural gas, and natural gas liquids which, upon analysis of geologic and engineering data, appear with reasonable certainty to be recoverable in the future from known oil and gas reservoirs under existing economic and operating conditions.

Proved undeveloped reserves. Estimated proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required.

Undeveloped acreage. Acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains estimated proved reserves.

Working interest. An operating interest which gives the owner the right to drill, produce, and conduct operating activities on the property and a share of production.

41

Item 3. Defaults Upon Senior Securities. None.

Item 4. Submission of Matters to a Vote of Security Holders. None.

Item 5. Other Information. None.

Item 6. Exhibits.

Exhibits are as follows:


10.1		Underwriting Agreement dated January 25, 2007 between Delta Petroleum Corporation and J.P. Morgan Securities Inc., acting on behalf of itself and Coker, Palmer, Phillips & Mullen, Inc. Incorporated by reference from Exhibit 1.1 to the Company’s Form 8-K dated January 25, 2007.

10.2.		Restricted Stock Award Agreement dated February 5, 2007 Delta Petroleum Corporation and Roger A. Parker. Filed herewith electronically

10.3.		Restricted Stock Award Agreement dated February 5, 2007 Delta Petroleum Corporation and John R. Wallace. Filed herewith electronically

10.4.		Restricted Stock Award Agreement dated February 5, 2007 Delta Petroleum Corporation and Kevin K. Nanke. Filed herewith electronically

10.5.		Restricted Stock Award Agreement dated February 5, 2007 Delta Petroleum Corporation and Stanley F. Freedman. Filed herewith electronically

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

42

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.


	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

Date: May 8, 2007

43

EXHIBIT INDEX


Exhibit No.		Description

10.1		Underwriting Agreement dated January 25, 2007 between Delta Petroleum Corporation and J.P. Morgan Securities Inc., acting on behalf of itself and Coker, Palmer, Phillips & Mullen, Inc. Incorporated by reference from Exhibit 1.1 to the Company’s Form 8-K dated January 25, 2007.

10.2.		Restricted Stock Award Agreement dated February 5, 2007 Delta Petroleum Corporation and Roger A. Parker. Filed herewith electronically

10.3.		Restricted Stock Award Agreement dated February 5, 2007 Delta Petroleum Corporation and John R. Wallace. Filed herewith electronically

10.4.		Restricted Stock Award Agreement dated February 5, 2007 Delta Petroleum Corporation and Kevin K. Nanke. Filed herewith electronically

10.5.		Restricted Stock Award Agreement dated February 5, 2007 Delta Petroleum Corporation and Stanley F. Freedman. Filed herewith electronically

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

Par Pacific Holdings - 10-Q quarterly report FY

What is the market capitalization of a company?

DISCLAIMER

Contact

Links