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, 2006


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, and 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 o		Accelerated filer þ		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 Noþ

52,907,951 shares of common stock $.01 par value were outstanding as of May 1, 2006.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS


	March 31,			December 31,
	2006			2005
	(Unaudited)
	(In thousands, except share amounts)
ASSETS

Current assets:
Cash and cash equivalents	$	17,274		$	5,519
Assets held for sale		—			19,215
Trade accounts receivable		24,329			22,202
Prepaid assets		3,171			3,442
Inventory		3,918			3,285
Deferred tax asset		3,226			5,237
Derivative instruments		155			89
Other current assets		2,363			2,600

Total current assets		54,436			61,589


Property and equipment:
Oil and gas properties, successful efforts method of accounting
Unproved		189,655			167,143
Proved		476,254			438,666
Drilling and trucking equipment, including deposits on equipment of
$2,500 and $5,000, respectively		87,987			64,129
Other		13,508			12,809

Total property and equipment		767,404			682,747
Less accumulated depreciation and depletion		(77,200	)		(61,593	)

Net property and equipment		690,204			621,154


Long-term assets:
Deferred financing costs		5,091			5,291
Deferred tax asset		—			1,322
Investment in LNG project		—			1,022
Derivative instruments		70			163
Goodwill		2,341			2,341
Other long-term assets		692			511

Total long-term assets		8,194			10,650

	$	752,834		$	693,393


LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Current portion of long-term debt	$	9,074		$	7,073
Accounts payable		50,823			67,772
Other accrued liabilities		11,096			19,462
Derivative instruments		8,395			12,465

Total current liabilities		79,388			106,772


Long-term liabilities:
7% Senior notes, unsecured		149,328			149,309
Credit facility		56,000			64,270
Term loan — DHS		34,250			28,000
Asset retirement obligation		2,904			3,002
Derivative liabilities		1,886			6,009
Deferred tax liability		6,880			—
Other debt, net		61			80

Total long-term liabilities		251,309			250,670


Minority interest		25,116			15,496


Commitments

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 51,106,000 shares at March 31, 2006 and 47,825,000 at December 31, 2005		511			478
Additional paid-in capital		395,162			333,054
Accumulated other comprehensive loss		(4,377	)		(4,997	)
Retained earnings (accumulated deficit)		5,725			(8,080	)

Total stockholders’ equity		397,021			320,455


	$	752,834		$	693,393

See accompanying notes to consolidated financial statements.

1

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


	Three Months Ended
	March 31,
	2006			2005
	(In thousands, except per share amounts)
Revenue:
Oil and gas sales	$	33,922		$	23,381
Contract drilling and trucking fees		10,114			2,332
Realized loss on derivative instruments, net		(2,370	)		(344	)


Total revenue		41,666			25,369


Operating expenses:
Lease operating expense		6,242			4,152
Transportation expense		624			113
Production taxes		1,877			1,402
Depreciation, depletion and amortization — oil and gas		13,129			5,117
Depreciation and amortization — drilling and trucking		2,524			224
Exploration expense		683			1,663
Dry hole costs		1,340			19
Drilling and trucking operations		5,903			2,012
General and administrative		8,411			4,613


Total operating expenses		40,733			19,315


Operating income		933			6,054


Other income and (expense):
Other income		136			(161	)
Gain on sale of oil and gas properties		18,869			—
Gain on sale of investment in LNG		1,058			—
Unrealized gain on derivative contracts, net		7,172			—
Minority interest		(531	)		403
Interest and financing costs		(5,494	)		(2,136	)


Total other income (expense)		21,210			(1,894	)


Income from continuing operations before income taxes and discontinued operations		22,143			4,160

Income tax expense		8,341			—


Income from continuing operations		13,802			4,160

Discontinued operations:
Income from discontinued operations of properties sold, net of tax		3			780


Net income	$	13,805		$	4,940


Basic income per common share:
Income from continuing operations	$	.28		$	.10
Discontinued operations		—			.02

Net income	$	.28		$	.12


Diluted income per common share:
Income from continuing operations	$	.27		$	.10
Discontinued operations		—			.02

Net income	$	.27		$	.12

See accompanying notes to consolidated financial statements.

2

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Consolidated Statement of Changes in Stockholders’ Equity and Comprehensive Income (Loss)
(Unaudited)


							Accumulated
					Additional		other
	Common stock				paid-in		comprehensive			Comprehensive			Accumulated
	Shares		Amount		capital		loss			income			deficit			Total

	(In thousands)
Balance, January 1, 2006		47,825	$	478	$	333,054	$	(4,997	)				$	(8,080	)	$	320,455

Comprehensive income (loss):
Net income		—		—		—		—		$	13,805			13,805			13,805
Other comprehensive transactions, net of tax
Hedging loss reclassified to income upon settlement, net of tax benefit of $669		—		—		—		1,105			1,105			—			1,105
Change in fair value of derivative hedging instruments, net of tax benefit of $294		—		—		—		(485	)		(485	)		—			(485	)

Comprehensive income										$	14,425

Shares issued for oil and gas properties		673		7		16,092		—						—			16,099
Shares issued for cash, net of offering costs		1,500		15		33,855		—						—			33,870
Shares issued for drilling rig assets		350		3		8,291		—						—			8,294
Shares issued for cash upon exercise of options		757		7		2,831		—						—			2,838
Issuance and amortization of non-vested stock		1		1		566		—						—			567
Compensation on options vested		—		—		473		—						—			473


Balance, March 31, 2006		51,106	$	511	$	395,162	$	(4,377	)				$	5,725		$	397,021

See accompanying notes to consolidated financial statements.

3

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)


	Three Months Ended
	March 31,
	2006			2005
	(In thousands)
Cash flows operations activities:
Net income	$	13,805		$	4,940
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation, depletion and amortization — oil and gas		13,083			4,972
Depreciation and amortization — drilling and trucking		2,524			300
Depreciation, depletion and amortization — discontinued operations		—			52
Accretion of abandonment obligation		46			69
Stock option and non-vested stock compensation		1,040			444
Amortization of deferred financing costs		309			147
Amortization of bond discount		19			—
Unrealized gain on derivative contracts		(7,172	)		—
Dry hole costs and impairment		292			—
Minority interest		531			(403	)
Gain on sale of oil and gas properties		(18,869	)		—
Gain on sale of investment in LNG		(1,058	)		—
DHS stock granted to management		70			—
Deferred income tax expense		8,343			—
Other		—			493
Net changes in operating assets and operating liabilities:
Increase in trade accounts receivable		(2,127	)		(17,214	)
Decrease in prepaid assets		270			2,530
Increase (decrease) in inventory		(633	)		1,048
(Increase) decrease in other current assets		323			(749	)
(Increase) decrease in accounts payable trade		(6,989	)		7,865
Increase in other accrued liabilities		3,312			902


Net cash provided by operating activities		7,119			5,396


Cash flows from investing activities:
Additions to property and equipment		(45,393	)		(81,043	)
Armstrong acquisition		(24,005	)		—
Proceeds from sales of oil and gas properties		42,810			—
Drilling and trucking capital expenditures		(13,893	)		(6,082	)
Minority interest holder contributions		9,018			—
(Increase) decrease in long-term assets		(266	)		17


Net cash used in investing activities		(31,729	)		(87,108	)


Cash flows from financing activities:
Stock issued for cash upon exercise of options		2,838			427
Stock issued for cash, net		33,870			—
Proceeds from borrowings		19,000			229,112
Payment of financing fees		(108	)		(6,345	)
Repayment of borrowings		(19,235	)		(135,018	)


Net cash provided by financing activities		36,365			88,176


Net increase in cash and cash equivalents		11,755			6,464

Cash at beginning of period		5,519			1,386


Cash at end of period	$	17,274		$	7,850


Supplemental cash flow information — Common stock issued for the acquisition of oil and gas properties	$	16,099		$	2,035


Common stock issued for drilling and trucking equipment	$	8,294		$	1,432


Cash paid for interest and financing costs	$	1,600		$	8,718

See accompanying notes to consolidated financial statements.

4

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2006 and 2005
(Unaudited)

(1) Basis of Presentation

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 most recent transition report on Form 10-KT. 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. On September 14, 2005, the Company’s management and the Board of Directors made the decision to change the Company’s fiscal year end to December 31. 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 transition report on Form 10-KT for the six months ended December 31, 2005, previously filed with the Securities and Exchange Commission.

(2) Nature of Organization

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 Company, through a series of transactions in 2004 and 2005, owns a 49.4% interest in DHS Drilling Company (“DHS”), an affiliated Colorado corporation that is headquartered in Casper, Wyoming. Delta representatives currently constitute a majority of the members of the Board of DHS and Delta has the right to use all of the rigs on a priority basis, although approximately half are currently working for third party operators. DHS also owns 100% of Chapman Trucking which was acquired in November 2005 and which ensures DHS rig mobility. Subsequent to March 31, 2006, DHS engaged in a reorganization transaction pursuant to which it became a subsidiary of DHS Holding Company, a Delaware corporation, and the Company’s ownership interest became an interest in DHS Holding Company. References to DHS herein shall be deemed to include both DHS Holding Company and DHS, unless the context otherwise requires. DHS is a consolidated entity of Delta.

At March 31, 2006 the Company owns 4,277,977 shares of the common stock of Amber Resources Company (“Amber”), representing 91.68% of the outstanding common stock of Amber. Amber is a public company that owns undeveloped oil and gas properties in federal units offshore California, near Santa Barbara.

In late 2005 the Company transferred its ownership in approximately 64,000 net acres of non-operated interests in the Columbia River Basin to CRB Partners, LLC, which originally was a wholly-owned subsidiary (“CRBP”). These interests consist of the Company’s 1% overriding royalty interest convertible into a 15% back-in working interest after project payout. During the first quarter of 2006, we sold a 44% minority interest in CRBP. We have retained the majority ownership in, and are the manager of, CRBP. The non-Delta members of CRBP have certain limited consent rights with respect to, among other things, CRBP’s election to convert to a working interest prior to actual project payout, disposition of its assets or effecting certain transactions outside the ordinary course of CRBP’s business. Further, our ownership in CRBP is subject to certain rights of first refusal and co-sale rights. The sole asset of CRBP is oil and gas properties contributed by Delta, and therefore, the sale of the minority interest in CRBP was accounted for as a disposal of oil and gas properties. This sale did not involve any of our operated 100% working interests in approximately 332,000 net acres in the Columbia River Basin.

5

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2006 and 2005
(Unaudited)

In March 2006, the Company sold approximately 26% of PGR Partners, LLC (“PGR”). PGR owns a 25% non-operated working interest in 6,314 gross acres in the Piceance Basin. The assets included in the sale consisted of both proved and unproved properties. The Company retained a 74% interest in, and is the manager of, PGR. The non-Delta members of PGR have certain limited consent rights with respect to, among other things, amending the joint operating agreement to which PGR is subject, disposition of its assets or effecting certain transactions outside the ordinary course of PGR’s business.

On February 19, 2002, the Company acquired 100% of the outstanding shares of Piper Petroleum Corporation (“Piper”), a privately owned oil and gas company headquartered in Fort Worth, Texas. Piper was merged into a subsidiary wholly owned by Delta.

(3) 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 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. 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.

Assets Held for Sale

Assets held for sale as of December 31, 2005 represent the cost basis related to the 427,000 gross acres (64,000 net acres) of non-operated interests in the Columbia River Basin that were transferred during December 2005 to a newly created wholly owned subsidiary, CRBP. In January and March 2006, Delta sold a minority interest in CRBP to a small group of investors for aggregate 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, the Company recorded a $13.0 million gain, ($8.1 million net of tax) and an $11.2 million reduction to unproved oil and gas property during the first quarter of 2006 as a result of closing the transaction.

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.

6

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2006 and 2005
(Unaudited)

Investment in LNG project

On March 30, 2006, the Company sold its long-term minority investment in an 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).

(3) Summary of Significant Accounting Policies, Continued

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, 2006 and December 31, 2005. Prior to forming DHS, the Company owned a 50% interest in Big Dog Drilling Co., LLC (“Big Dog”) and a 50% interest in Shark Trucking Co., LLC (“Shark”). The remaining net assets of Big Dog were ultimately acquired and, together with the interest previously owned, were contributed to DHS.

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, 2006 and December 31, 2005, the Company’s aggregate natural gas and crude oil imbalances were not material to its consolidated financial statements except for an imbalance acquired during fiscal 2005 which was collected during the six months ended December 31, 2005.

Drilling and Trucking

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

7

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2006 and 2005
(Unaudited)

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.

(3) Summary of Significant Accounting Policies, Continued

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, 2006 and 2005.

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, 2006 and 2005.

8

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2006 and 2005
(Unaudited)

Goodwill

Goodwill represents the excess of the cost of the acquisition of Chapman Trucking by DHS in November 2005 over the fair value of the assets 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 SFAS No. 142.

(3) Summary of Significant Accounting Policies, Continued

Asset Retirement Obligations

The Company’s asset retirement obligations arise from the plugging and abandonment liabilities for its oil and gas wells. The Company has no obligation to provide for the retirement of most of its offshore properties as the obligations remained with the seller. The following is a reconciliation of the Company’s asset retirement obligations from January 1, 2006 to March 31, 2006 (amounts in thousands).


Asset retirement obligation — January 1, 2006	$	3,467
Accretion expense		46
Change in estimate		—
Obligations acquired		121
Obligations settled		—
Obligations on sold properties		—

Asset retirement obligation — March 31, 2006		3,634
Less: Current asset retirement obligation		(730	)

Long-term asset retirement obligation	$	2,904

In March 2005, the FASB issued FASB Interpretation 47 (“FIN 47”), an interpretation of SFAS No. 143, “Accounting for Asset Retirement Obligations” (“SFAS No. 143”). FIN 47 clarifies the term “conditional asset retirement obligation” as it is used in SFAS No. 143. The Company applied the guidance of FIN 47 beginning July 1, 2005 resulting in no impact on its financial statements.

Comprehensive Income

Comprehensive income includes all changes in equity during a period. The components of comprehensive income for the three months ended March 31, 2006 and 2005 are as follows:


	Three Months Ended
	March 31,
	2006			2005
	(In thousands)
Net income	$	13,805		$	4,940
Other comprehensive income (transactions)
Realized gain on equity securities sold, net of tax expense of zero		—			(9,738	)
Hedging losses reclassified to income upon settlement, net of tax benefit of $669		1,105			—
Change in fair value of derivative hedging instruments, net of tax benefit of $294 and zero		(485	)		(83	)

		620			(9,821	)

Comprehensive income	$	14,425		$	(4,881	)

9

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2006 and 2005
(Unaudited)

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”

(3) Summary of Significant Accounting Policies, Continued

(“SFAS No. 133”) which the Company adopted on January 1, 2001. 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 as 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, 2006, all of the Company’s 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 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, 2006 and indicates those that qualify for hedge accounting and those that do not qualify for hedge accounting:

Net Fair Value

Price Floor /

Asset (Liability) at

Commodity

Volume

Price Ceiling

Term

Index

March 31, 2006

(In thousands)

Contracts that qualify for hedge accounting

Crude oil

40,000 Bbls / month

$40.00 / $50.34

July '05 - June '06

NYMEX-WTI

$

(2,101

)

Crude oil

10,000 Bbls / month

$45.00 / $56.90

July '05 - June '06

NYMEX-WTI

(333

)

Crude oil

25,000 Bbls / month

$35.00 / $61.80

July '06 - June '07

NYMEX-WTI

(3,113

)

Contracts that do not qualify for hedge accounting

Natural gas

10,000 MMBtu / day

$5.00 / $9.60

July '05 - June '06

NYMEX-H HUB

(23

)

Natural gas

3,000 MMBtu / day

$6.00 / $9.35

July '05 - June '06

NYMEX-H HUB

(1

)

Natural gas

13,000 MMBtu / day

$5.00 / $10.20

July '06 - June '07

NYMEX-H HUB

(4,484

)

$

(10,055

)

The net fair value of the Company’s derivative instruments obligation was a liability of approximately $10.1 million at March 31, 2006 and $11.7 million on May 1, 2006.

10

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2006 and 2005
(Unaudited)

The net realized losses from hedging activities recognized in the Company’s statements of operations were $2.4 million and $344,000 for the three months ended March 31, 2006 and 2005, respectively. These losses are recorded as a decrease in revenues.

In April 2006, the Company purchased for $492,000 a natural gas put option with a NYMEX strike price of $7.50 per Mmbtu on 10,000 Mmbtu per day for July 2006 through September 2006. This derivative does not qualify for hedge accounting and accordingly any change in the contract’s fair value will be recorded on the consolidated balance sheet with a corresponding unrealized gain or loss recorded in the consolidated statement of operations.

(3) Summary of Significant Accounting Policies, Continued

Stock Option Plans

Prior to July 1, 2005, the Company previously 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, SFAS 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 $473,000, relating to employee provided services during the quarter ended March 31, 2006.

Non-Qualified Stock Options — Directors and Employees

On May 31, 2002 at the annual meeting of the shareholders, the shareholders ratified the Company’s 2002 Incentive Plan (the “Incentive Plan”) under which it reserved up to an additional 2,000,000 shares of common stock. This plan superseded the Company’s 1993 and 2001 Incentive Plans.

Incentive awards under the Incentive 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. Options are generally issued at market price at the date of grant with various vesting and expiration terms based on the discretion of the Incentive Plan Committee.

Exercise prices for options outstanding under the Company’s various plans as of March 31, 2006 ranged from $1.13 to $15.46 per share and the weighted-average remaining contractual life of those unvested options was 5.95 years. At March 31, 2006, the Company had 575,000 unvested options. These options have a value of approximately $1.29 million and will be expensed during future periods through March 31, 2007.

11

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2006 and 2005
(Unaudited)

Had compensation cost for the Company’s stock-based compensation plan been determined using the fair value of the options at the grant date prior to July 1, 2005, the Company’s net income for the three months ended March 31, 2005 would have been as follows:

(3) Summary of Significant Accounting Policies, Continued


	Three Months Ended
	March 31, 2005
	(In thousands, except per share amounts)
Net income	$	4,940
Equity compensation		85
SFAS No. 123R compensation effect		(1,908	)¹

Net income after SFAS No. 123R implementation	$	3,117

Pro forma basic income per common share:	$	.08


(1)		During the quarter ended December 31, 2004, the Company granted 420,000 options to officers and 98,000 options to directors to purchase shares of its common stock at an average price of $15.34 per share, which was the market price on the date of the grant. The officer’s options vest over a three year period and the director’s options vested on March 15, 2005. The fair market value of each option granted was $10.07 and was calculated using a risk free rate of 4.60%, volatility factors of the expected market price of the Company’s common stock of 48.76% and an average expected life of 8.0 years. During the quarter ended December 31, 2004, the Company granted 318,000 options to employees to purchase 318,000 shares of its common stock at an average price of $15.29 per share. Certain options were granted below market. For options granted below market, the Company recorded an expense for the difference between the option price and the grant price. The employee options vest over a year period. The average fair market value of each option granted was $7.10 and was calculated using a risk free rate of 4.60%, volatility factors of the expected market price of the Company’s common stock of 48.76% and an average expected life of 3.2 years. During the quarter ended March 31, 2005, the Company granted 105,700 options to employees to purchase 105,700 shares of its common stock at an average price of $14.75 per share. Certain options were granted below market. For options granted below market, the Company recorded an expense for the difference between the option price and the grant price. The employee options vest over a year period. The average fair market value of each option granted was $7.49 and was calculated using a risk free rate of 4.65%, volatility factors of the expected market price of the Company’s common stock of 61.23% and an average expected life of 2.0 years. The SFAS 123R compensation effect is calculated based on the options vesting period and includes additional grants from other periods.

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 basis 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.

12

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2006 and 2005
(Unaudited)

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).

(3) Summary of Significant Accounting Policies, Continued

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.

(4) 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 $11.4 million, at March 31, 2006. 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.

We and our majority-owned subsidiary, Amber Resources Company of Colorado, are among twelve plaintiffs in a lawsuit that was filed on January 9, 2002 in the United States Court of Federal Claims in Washington, D.C. alleging that the U.S. government has materially breached the terms of forty undeveloped federal leases, some of which are part of our offshore California properties. The Complaint is based on allegations by the collective plaintiffs that the United States has materially breached the terms of certain of their offshore California leases by attempting to deviate significantly from the procedures and standards that were in effect when the leases were entered into, and by failing to carry out its own obligations relating to those leases in a timely and fair manner. More specifically, the plaintiffs have alleged that the judicial determination in the California v. Norton case, that a 1990 amendment to the Coastal Zone Management Act that required the government to make a consistency determination prior to granting lease suspension requests in 1999, constitutes a material change in the procedures and standards that were in effect when the leases were issued. The plaintiffs have also alleged that the United States has failed to afford them the timely and fair review of their lease suspension requests which has resulted in significant, continuing and material delays to their exploratory and development operations.

The suit seeks compensation for the lease bonuses and rentals paid to the Federal government, exploration costs and related expenses. The total amount claimed by all lessees for bonuses and rentals exceeds $1.2 billion, with additional amounts for exploration costs and related expenses. We own approximately 12% of the lease bonus costs that are the subject of the lawsuit. In addition, our claim for exploration costs and related expenses will also be substantial. In the event, however, that we receive any proceeds as the result of such litigation, we will be obligated to pay a portion of any amount received by us to landowners and other owners of royalties and similar interests, to pay the litigation expenses and to fulfill certain pre-existing contractual commitments to third parties.

On November 15, 2005, the United States Court of Federal Claims issued a ruling in the suit granting the plaintiffs’ motion for 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’s ruling also denied the United States’ motion to dismiss and motion for summary judgment. The United States Court of Federal Claims ruled that the federal government’s imposition of new and onerous requirements that stood as a significant obstacle to oil and gas development breached agreements that it made when it sold thirty six out of the total forty offshore California federal leases that are the subject of the litigation. The Court further ruled that the government must give back to the current lessees the more than $1.1 billion in lease bonuses it had received at the time of sale.

We and Amber are among the current lessees of the thirty six leases that are the subject of the ruling. Together with Amber, our net share of the $1.1 billion award is approximately $121 million. The government has filed a motion for reconsideration of this ruling. The final ruling in the case will not be made until the Court addresses the plaintiffs’ additional claims regarding the four additional leases, as well as their claims regarding the hundreds of millions of dollars that have been spent in the successful efforts to find oil and gas in the disputed lease area, and other matters. The final ruling, including the ruling made on November 15, will be subject to appeal, and no payments will be made until all appeals have either been waived or exhausted.

13

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2006 and 2005
(Unaudited)

Acquisition 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 is expected to begin during 2006.

(4) Oil and Gas Properties, Continued

Significant Acquisition — Pro-forma Statements of Operations

On December 15, 2004, the Company entered into a purchase and sale agreement to acquire substantially all of the oil and gas assets owned by several entities related to Manti Resources, Inc., which was an unaffiliated, privately held Texas corporation (“Manti”). The adjusted purchase price of $59.7 million was paid in cash at the closing of the transaction, which occurred on January 21, 2005. The purchase price for the Manti properties was determined through arms-length negotiations. The purchase price was paid with increased borrowings on the Company’s bank credit facility. Substantially all of the assets that we acquired from Manti have been pledged as collateral for the bank credit facility.

The following unaudited pro forma condensed consolidated statements of operations assume that the Manti property acquisition occurred as of July 1, 2004:


	Three Months Ended March 31,
	2005

	(In thousands, except per share amounts)
Oil and gas sales	$	26,037
Net earnings from continuing operations	$	5,882

Net earnings from continuing operations per common share:
Basic	$	.15

Diluted	$	.14

The above unaudited condensed pro forma consolidated statements of operations, based on the historical producing property operating results of Manti and Delta, are not necessarily indicative of the results of operations if Delta would have acquired the Manti properties at July 1, 2004.

Fiscal 2006 — Disposition

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

14

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2006 and 2005
(Unaudited)

during the first quarter of 2006 as a result of closing the transaction. As a result of the transaction, Delta now owns a net interest of just over 36,000 acres in the Columbia River Basin through its remaining ownership of CRBP and additional interests in 332,000 net acres in the Columbia River Basin from previous transactions.

In March 2006, the Company 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. 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 retained a 74% interest in PGR.

(5) DHS Drilling Operations

In January 2006, the Company purchased Rooster Drilling Company (“Rooster Drilling”) for 350,000 shares of Delta common stock valued at $8.3 million. Rooster Drilling owns one drilling rig, an Oilwell 66 with a depth capacity of 12,000 feet. The rig is located in Wyoming and is currently under contract to drill 9 wells (or minimum 100 days), in the Big Piney area of Wyoming. Concurrent with the Company’s acquisition of Rooster Drilling, the Company and DHS entered into an operating agreement whereby DHS operated the rig (DHS Drilling Company “Rig 15”) on behalf of the Company. In March 2006, the Company contributed Rooster Drilling to DHS.

In March 2006, DHS purchased a Kremco 750G drilling rig for $4.75 million. The rig is a 500 horsepower rig with a depth rating of 10,000 feet. After upgrades, the rig is scheduled to commence work in the Rocky Mountain region in the second quarter of 2006.

In March 2006, DHS issued additional common stock to Delta, Chesapeake, and officers and management of DHS in exchange for assets, cash and notes as described below. The Company contributed Rooster Drilling and additional cash totaling $9.9 million to DHS in exchange for 2.7 million shares of DHS common stock. Chesapeake contributed approximately $9.0 million to DHS in exchange for 2.4 million shares of DHS common stock. Two executive officers executed promissory notes for $549,000 in exchange for 150,000 shares each. An officer of DHS paid $33,000 for 9,000 shares of DHS common stock. Subsequent to these transactions there were 14.6 million shares of DHS common stock outstanding.

(6) 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 contain 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 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, 2006. (See Footnote 10, “Guarantor Financial Information”). The fair value of the Company’s senior notes at March 31, 2006 was $137.3 million.

15

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2006 and 2005
(Unaudited)

(6) Long Term Debt, Continued

Credit Facility

At March 31, 2006, the $200.0 million credit facility had an available borrowing base of $75.0 million and $56.0 million outstanding. 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 rate at March 31, 2006 approximated 6.75%. The loan is collateralized by substantially all of our oil and gas properties. We are normally required to meet certain financial covenants which include a current ratio of 1 to 1, net of availability under the facility and current derivative instruments of $25.5 million, and a consolidated debt to adjusted EBITDAX (Earnings before interest, taxes, depreciation, amortization and exploration) ratio of less than 3.5 to 1. The financial maintenance covenants only include subsidiaries which the Company owns 100%. At December 31, 2005, the Company was not in compliance with its quarterly debt covenants and restrictions, but obtained a waiver from the banks for the quarter ended December 31, 2005. In addition, the credit agreement was amended to exclude the current ratio requirement for the quarter ended March 31, 2006. At March 31, 2006, the Company was in compliance with its remaining quarterly debt covenants and restrictions.

Term Loan — DHS

On September 30, 2005, DHS completed a financing arrangement with Guggenheim Corporate Funding, LLC (“Guggenheim”) for $35.0 million due September 30, 2010, with principal and interest payments due on the first calendar day of each quarter. On January 6, 2006, DHS amended its Guggenheim note to provide for an additional $10.0 million in borrowings and amend certain of the financial covenants as follows. The covenant for Maximum Consolidated Leverage Ratio of 2.5 to 1 (declining to 2.0 to 1.0 at June 30, 2006) was amended to a ratio of 3.0 to 1, 2.75 to 1, and 2.50 to 1 for the quarters ending December 31, 2005, March 31, 2006, and June 30, 2006 respectively. For subsequent quarters, the ratio is 2.00 to 1, as per the original covenants. Additionally, the current ratio covenant was modified, eliminating the current portion of long term debt from the current liabilities component of the ratio. The Minimum Consolidated Interest Coverage Ratio was not amended. The amended note remains due on September 30, 2010, with quarterly principal payments of $2.25 million beginning April 1, 2006, and one balloon payment on September 30, 2010 of $2.75 million. The interest rate on the note was modified to Prime Rate plus 3.5%, (11.25% at March 31, 2006), until such time as (1) the Maximum Consolidated Leverage Ratios complies with the original ratios, and (2) the ratio of the long term debt to the appraised value of the Company’s equipment is equal to or less than 55%. When the ratios on the original covenant are achieved and the appraised value ratio is 55% or lower, the interest rate will change to the original rate (Prime Rate plus 3.0%). Financing costs of $100,000 were incurred in conjunction with the amendment, and will be amortized over the remaining life of the note. At March 31, 2006, DHS was in compliance with its covenants on the note. Subsequently, in May 2006, DHS paid off the Term Loan with proceeds from borrowings under a new $100 million credit facility with JP Morgan Chase Bank, N.A. as administrator agent, See Footnote 12, Subsequent Events.

16

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2006 and 2005
(Unaudited)

Borrowing availability under its bank credit facility at March 31, 2006 was $19.0 million. Maturities of long-term debt, in thousands of dollars based on contractual terms are as follows:


YEAR ENDING March 31,
2007	$	9,000
2008		9,000
2009		65,000
2010		9,000
2011		7,250
Thereafter		150,000

	$	249,250

(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, 2006 and December 31, 2005, no preferred stock was issued. As part of the reincorporation on January 31, 2006, the Company reduced the par value of the preferred stock from $.10 per share to $.01 per share.

Common Stock

In January 2006, the Company purchased Rooster Drilling Company (“Rooster Drilling”) for 350,000 shares of Delta common stock valued at $8.3 million on the value of the stock when the transaction closed (See Footnote 5 DHS Drilling Operations).

On February 1, 2006, the Company acquired a 65% working interest in approximately 88,000 gross acres in the central Utah hingeline play from Armstrong Resources, LLC for 673,401 shares and $24.0 million in cash. The shares of the Company’s common stock were valued at $16.1 million using the average five-day closing price before and after the terms of the agreement were agreed upon and announced. The total purchase price of $40.1 million was allocated to proved undeveloped properties.

On February 1, 2006, the Company received net proceeds of $33.9 million from a public offering of 1.5 million shares of the Company’s common stock.

On April 28, 2006, Castle shareholders approved the merger agreement between Delta and Castle Energy Corporation (“Castle”) as announced on November 8, 2005. Delta acquired Castle, which held 6,700,000 shares of Delta, and issued 8,500,000 shares of its common stock to Castle’s stockholders, for a net issuance of 1,800,000 shares of common stock.

(8) Income Taxes

The Company accounts for income taxes in accordance with the provisions of Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes (“SFAS” 109). Income tax expense attributable to income from continuing operations was $8.3 million and zero for the three months ended March 31, 2006 and 2005, respectively.

17

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2006 and 2005
(Unaudited)

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 differences, net of the existing valuation allowances at March 31, 2006 and December 31, 2005. The valuation allowance at March 31, 2006 and December 31, 2005 relates 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. 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.

At March 31, 2006, the Company had net operating loss carryforwards of approximately $59.9 million, which expire between 2006 and 2025.

(9) Earnings Per Share

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


	Three Months Ended
	March 31,
	2006		2005
	(In thousands, except per share amounts)
Numerator:
Numerator for basic and diluted income per share — income available to common stockholders	$	13,805	$	4,940


Denominator:
Denominator for basic income per share-weighted average shares outstanding		49,769		40,282
Effect of dilutive securities and stock options		1,565		2,256


Denominator for diluted income per common share		51,334		42,538


Basic income per common share	$	.28	$	.12

Diluted income per common share	$	.27	$	.12


Anti-dilutive securities outstanding		—		551

18

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2006 and 2005
(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 and certain 100% owned subsidiaries of the Company at the time of the Bond Offering (“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 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, 2006 and December 31, 2005, the condensed consolidated statements of operations for the three months ended March 31, 2006 and 2005, and the condensed consolidated statements of cash flows for the three months ended March 31, 2006 and 2005 (in thousands).

Condensed Consolidated Balance Sheet
March 31, 2006


				Guarantor			Non-Guarantor			Adjustments/
	Issuer			Entities			Entities			Eliminations			Consolidated
Current assets	$	33,766		$	805		$	19,865		$	—		$	54,436

Property and equipment:
Oil and gas		593,856			6,846			67,270			(2,063	)		665,909
Drilling rigs and trucks		594			—			87,393			—			87,987
Other		12,716			—			792			—			13,508

Total property and equipment		607,166			6,846			155,455			(2,063	)		767,404

Accumulated DD&A		(69,890	)		(1,129	)		(6,181	)		—			(77,200	)


Net property and equipment		537,276			5,717			149,274			(2,063	)		690,204

Investment in subsidiaries		(14,948	)		—			—			14,948			—
Other long-term assets		5,511			—			2,683			—			8,194


Total assets	$	561,605		$	6,522		$	171,822		$	12,885		$	752,834


Current liabilities	$	62,908		$	237		$	16,243		$	—		$	79,388

Long-term liabilities
Long-term debt, derivative liabilities, and deferred taxes		211,258			—			37,147			—			248,405
Asset retirement obligation		2,876			25			3			—			2,904


Total long-term liabilities		214,134			25			37,150			—			251,309

Minority interest		25,116			—			—			—			25,116

Shareholders’ equity		259,447			6,260			118,429			12,885			397,021


Total liabilities and shareholders’ equity	$	561,605		$	6,522		$	171,822		$	12,885		$	752,834

19

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2006 and 2005
(Unaudited)

(10) Guarantor Financial Information, Continued

Condensed Consolidated Balance Sheet
December 31, 2005


				Guarantor			Non-Guarantor			Adjustments/
	Issuer			Entities			Entities			Eliminations			Consolidated
Current assets	$	50,519		$	657		$	10,414		$	—		$	61,590

Property and equipment:
Oil and gas		554,412			6,838			48,053			(3,496	)		605,807
Drilling rigs and trucks		—			—			64,130			—			64,130
Other		12,266			—			543			—			12,809

Total property and equipment		566,678			6,838			112,726			(3,496	)		682,746

Accumulated DD&A		(56,733	)		(1,088	)		(3,772	)		—			(61,593	)


Net property and equipment		509,945			5,750			108,954			(3,496	)		621,153

Investment in subsidiaries		(4,295	)		—			—			4,295			—
Other long-term assets		8,028			—			2,622			—			10,650


Total assets	$	564,197		$	6,407		$	121,990		$	799		$	693,393


Current liabilities	$	92,426		$	188		$	14,158		$	—		$	106,772

Long-term liabilities
Long-term debt		218,304			—			29,364			—			247,668
Asset retirement obligation		2,975			25			2			—			3,002


Total long-term liabilities		221,279			25			29,366			—			250,670

Minority interest		15,496			—			—			—			15,496

Stockholders’ equity		234,996			6,194			78,466			799			320,455


Total liabilities and stockholders’ equity	$	564,197		$	6,407		$	121,990		$	799		$	693,393

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


				Guarantor		Non-Guarantor			Adjustments/
	Issuer			Entities		Entities			Eliminations			Consolidated

Total revenue	$	30,730		$	540	$	14,573		$	(4,177	)	$	41,666

Operating expenses:
Oil and gas expenses		8,624			90		29			—			8,743
Depreciation and depletion		13,117			42		2,494			—			15,653
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


Total expenses		31,199			150		11,498			(2,114	)		40,733


Operating income (loss)		(469	)		390		3,075			(2,063	)		933

Other income and expenses		22,897			1		(1,157	)		(531	)		21,210
Income tax expense		(8,341	)		—		—			—			(8,341	)
Discontinued operations		3			—		—			—			3


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

20

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2006 and 2005
(Unaudited)

(10) Guarantor Financial Information, Continued

Condensed Consolidated Statement of Operations
Three Months Ended March 31, 2005


				Guarantor		Non-Guarantor			Adjustments/
	Issuer			Entities		Entities			Eliminations		Consolidated

Total revenue	$	22,672		$	365	$	2,332		$	—	$	25,369

Operating expenses:
Oil and gas expenses		5,524			143		—			—		5,667
Depreciation and depletion		4,998			43		300			—		5,341
Exploration expense		1,663			—		—			—		1,663
Drilling and trucking operations		—			—		2,012			—		2,012
Dry hole, abandonment and impaired		19			—		—			—		19
General and administrative		4,367			10		236			—		4,613


Total expenses		16,571			196		2,548			—		19,315


Operating income (loss)		6,101			169		(216	)		—		6,054

Other income and expenses		(2,318	)		25		(4	)		403		(1,894	)
Income tax benefit		—			—		—			—		—
Discontinued operations		780			—		—			—		780


Net income (loss)	$	4,563		$	194	$	(220	)	$	403	$	4,940

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

Condensed Consolidated Statement of Cash Flows
Three Months Ended March 31, 2005


				Guarantor			Non-Guarantor
	Issuer			Entities			Entities			Consolidated

Operating activities	$	4,964		$	385		$	47		$	5,396
Investing activities		(86,797	)		(185	)		(126	)		(87,108	)
Financing activities		88,396			(250	)		30			88,176


Net increase (decrease) in cash and cash equivalents		6,563			(50	)		(49	)		6,464

Cash at beginning of the period		1,079			234			73			1,386


Cash at the end of the period	$	7,642		$	184		$	24		$	7,850

21

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2006 and 2005
(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, 2006 and 2005:


							Inter-segment
	Oil and Gas			Drilling			Eliminations			Consolidated
Three Months Ended March 31, 2006
Revenues from external customers	$	31,552		$	10,114		$	—		$	41,666
Inter-segment revenues		—			4,177			(4,177	)		—

Total revenues	$	31,552		$	14,291		$	(4,177	)	$	41,666

Operating income (loss)	$	171		$	2,825		$	(2,063	)	$	933

Other income and (expense)¹		22,897			(1,156	)		(531	)		21,210

Income (loss) from continuing operations, before tax	$	23,068		$	1,669		$	(2,594	)	$	22,143

Three Months Ended March 31, 2005
Revenues from external customers	$	23,037		$	2,332		$	—		$	25,369
Inter-segment revenues		—			—			—			—

Total revenues	$	23,037		$	2,332		$	—		$	25,369

Operating income (loss)	$	10,905		$	(4,851	)	$	—		$	6,054

Other income and (expense)¹		(2,288	)		(9	)		403			(1,894	)

Income (loss) from continuing operations, before tax	$	8,617		$	(4,860	)	$	403		$	4,160


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 Events

On April 28, 2006, Castle shareholders approved the merger agreement between Delta and Castle Energy Corporation (“Castle”) as announced on November 8, 2005. Delta acquired Castle, which held 6,700,000 shares of Delta, and issued 8,500,000 shares of its common stock to Castle’s stockholders, for a net issuance of 1,800,000 shares of common stock. Castle also had additional assets of approximately $40.0 million which are comprised of cash, producing oil and gas properties located in Pennsylvania and West Virginia, and certain other assets.

In early May 2006, DHS closed a new $100.0 million Senior Secured Credit Facility syndicated by JP Morgan Chase Bank, N.A., as administrative agent, of which $75 million was initially drawn. The initial borrowing will be used to pay off the Guggenheim term loan ($41 million), acquire additional rigs and equipment (approximately $25 million), pay transaction expenses (approximately $3 million), and leave approximately $6 million in general corporate funds. 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 (with such ratio decreasing to 2.25 to 1.00 for the quarters ending March 31, 2008 through December 31, 2008 and to 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 March 31, 2008 through March 31, 2012). The facility has a $25 million delayed draw feature which expires twelve months after closing of the Senior Secured Credit Facility and on which DHS pays commitment fees; this facility is expected to be used to acquire additional rigs at some time in the future.

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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 and Section 21E of the 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 prospectus supplement 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 2006; 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 period ended December 31, 2005, 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 development activities;

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

	•		timing, amount, and marketability of production;

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

	•		effectiveness of management strategies and decisions;

	•		the strength and financial resources of our competitors;

23

	•		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.

Quarter Ended March 31, 2006 Accomplishments

	•		Our production from continuing operations for the quarter was 4.06 Mmcfe, compared to 3.60 Mmcfe in the comparable prior year quarter, an increase of 13%.

	•		We acquired a 65% interest in 88,000 acres in the central Utah hingeline play from Armstrong Resources, LLC for $24.0 million in cash and approximately 673,000 shares Delta common stock valued at $16.1 million. We funded the cash portion of this purchase through a public offering of common stock from which we received net cash proceeds of $33.9 million.

	•		We formed CRB Partners, LLC (“CRBP”) to hold the Company’s non-operated interest in 427,000 gross (64,000 net) acres in Columbia River Basin. We then sold 44% of CRBP to institutional investors for total proceeds of $32.8 million. A pre-tax gain of $13.0 million was recorded, $8.1 million net of tax.

	•		We sold 26% of our subsidiary PGR Partners, LLC (“PGR”), which holds a 25% interest in 6,000+ gross acres in the Piceance Basin, to institutional investors for total proceeds of $20.4 million. A pretax gain of $5.9 million was recorded, $3.7 million net of tax.

	•		During the three months ended March 31, 2006 we acquired two drilling rigs, one rig from Rooster Drilling for approximately 350,000 shares of Delta common stock, and an additional rig for $4.5 million in cash. These rigs are being operated by our 49.4% owned affiliate DHS.

The following discussion and analysis relates to items that have affected our results of operations for the three months ended March 31, 2006 and 2005. 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, 2006 Compared to Quarter Ended March 31, 2005

Net Income. Net income increased $8.8 million to $13.8 million or $.27 per diluted common share for the three months ended March 31, 2006, from income of $4.9 million or $.12 per diluted common share for the comparable period a year earlier. Income from continuing operations increased $9.6 million from $4.2 million for the three months ended March 31, 2005 to $13.8 million for the three months ended March 31, 2006 due primarily to the $13.0 million gain on the CRBP sale, the $5.9 million gain related to the PGR sale, and a $5.1 million increase in net

24

realized and unrealized gains and losses on derivative instruments, partially offset by higher depreciation, depletion and amortization expense, interest expense, and income tax expense. Income from discontinued operations for the three months ended March 31, 2006 was $3,000, a decrease of $777,000 over the year earlier period.

Revenue. During the three months ended March 31, 2006, oil and natural gas revenue from continuing operations increased 45% to $33.9 million, as compared to $23.4 million for the comparable period a year earlier. The increase was the result of an average onshore gas price received during the three months ended March 31, 2006 of $6.58 per Mcf compared to $5.52 per Mcf for the year earlier period, an increase in average onshore oil price received during the three months ended March 31, 2006 of $60.85 per Bbl compared to $47.97 per Bbl for the year earlier period, an increase in offshore oil price received of $50.62 per Bbl during the three months ended March 31, 2006 compared to $33.31 for the year earlier period, and a 13% increase in average daily production over the comparable prior year period.

Net realized losses from hedging activities were $2.4 million and $344,000 for the three months ended March 31, 2006 and 2005, respectively. These losses are recorded as a decrease in revenues.

Contract Drilling and Trucking Fees. Contract drilling and trucking fees for the three months ended March 31, 2006 increased to $10.1 million compared to $2.3 million for the year earlier period. The increase is the result of the increase from three to 11 rigs in operation by DHS, whose results are consolidated with ours. Drilling revenue is earned under day-work contracts where we provide a drilling rig with required personnel to our third party customers, who supervise the drilling of the well. We are paid based on a negotiated fixed rate per day while the rig is in use. During the mobilization period we typically earn a fixed amount of revenue based on the mobilization rate stated in the contract. Drilling revenues earned on wells drilled for Delta have been eliminated through consolidation.

Production and Cost Information

Production volumes, average prices received and cost per equivalent Mcf for the three months ended March 31, 2006 and 2005 are as follows:


	Three Months Ended March 31,
	2006					2005
	Onshore			Offshore		Onshore			Offshore
Production:
Oil (MBbl)		318			46		236			42
Gas (MMcf)		1,873			—		1,929			—
Production — Discontinued Operations:
Oil (MBbl)		—			—		—			—
Gas (MMcf)		—			—		218			—
Average Price — Continuing Operations:
Oil (per barrel)	$	60.85		$	50.62	$	47.97		$	33.31
Gas (per Mcf)	$	6.58		$	—	$	5.52		$	—

Costs per Mcfe
Hedge effect	$	(.58	)	$	—	$	(.10	)	$	—
Lease operating expense	$	1.33		$	4.33	$	.96		$	3.77
Production taxes	$	.49		$	.04	$	.42		$	.06
Transportation costs	$	.17		$	—	$	.03		$	—
Depletion expense	$	3.32		$	.80	$	1.38		$	.77

25

Lease Operating Expense. Lease operating expenses for the three months ended March 31, 2006 were $6.2 million compared to $4.2 million for the year earlier period. Lease operating expense from continuing operations for onshore properties for the three months ended March 31, 2006 was $1.33 per Mcfe as compared to $.96 per Mcfe for the year earlier period. Lease operating expense from continuing operations for offshore properties was $4.33 per Mcfe for the three months ended March 31, 2006 and $3.77 per Mcfe for the year earlier period. This increase in lease operating expenses can be attributed to our 13% increase in production and the percentage of production from wells owned in the Gulf Coast region, which cost, on average more to produce than those in our other regions. In addition, lease operating costs have increased due to generally rising field costs associated with the increased demand for services during the current period of higher commodity prices.

Depreciation, Depletion and Amortization — oil and gas. Depreciation, depletion and amortization expense increased 156% to $13.1 million for the three months ended March 31 2006, as compared to $5.1 million for the year earlier period. Our onshore depletion rate increased to $3.32 per Mcfe for the three months ended March 31, 2006 from $1.38 per Mcfe for the year earlier period. Our depletion rate increase can be attributed to our focus on deep, multi-stage completion projects. Since it takes several months to conclude our completion process procedures, the majority of our well costs are depleted over initially completed zones.

Depreciation and Amortization — drilling and trucking. Depreciation and amortization expense — drilling increased to $2.5 million for the three months ended March 31, 2006, as compared to $224,000 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, 2006 were $683,000 compared to $1.7 million for the year earlier period. Current year activities include activities in our Columbia River Basin and Newton County, Texas projects.

Dry Hole Costs. We incurred dry hole costs of approximately $1.3 million for the three months ended March 31, 2006 compared to $19,000 for the same period a year ago. Our dry hole costs during 2005 were primarily comprised of two exploratory projects, one in Utah County, Utah and the other in Montrose County, Colorado. Dry hole costs for the three months ended March 31, 2006 related primarily to three exploratory projects, one in Orange County, California, one in Texas, and one in Utah.

Drilling and Trucking Operations. Drilling expenses increased to $5.9 million for the three months ended March 31, 2006 compared to $2.0 million for the year earlier period. This increase can be attributed to the increase in utilization from additional rigs.

26

General and Administrative Expense. General and administrative expense increased 82% to $8.4 million for the three months ended March 31, 2006, as compared to $4.6 million for the year earlier period. The increase in general and administrative expenses is primarily attributed to the adoption of SFAS No. 123R, increased professional fees, our 60% increase in technical and administrative staff and related personnel costs and the expansion of our office facility.

In December, 2004, SFAS No. 123 (Revised 2004), “Share Based Payment” was issued, requiring us to recognize the grant-date fair value of stock options and other equity based compensation issued to employees in the income statement. The cost of share based payments will be recognized over the period the employee provides service. We recognized non-cash compensation expense related to stock options of approximately $473,000 relating to employee provided services during the quarter ended March 31, 2006. In addition, we issued unvested stock to officers, directors and employees as additional compensation. Unvested stock grants are valued at the closing price on the date issued and expensed as they vest, usually over a three year period. We also recorded $567,000 of non-cash unvested stock compensation expense for the three months ended March 31, 2006.

Gain on Sale of Oil and Gas Properties. 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. As a result of the transaction, Delta now owns a net interest of just over 36,000 acres in the Columbia River Basin through its remaining ownership of CRBP and additional direct 100% interests in 332,000 net acres in the Columbia River Basin from previous transactions.

In March 2006, the Company 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. 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 retained a 74% interest in, and is the manager of, PGR.

Gain on Sale of Investment in LNG Project. On March 30, 2006, the Company sold its long-term minority investment in an 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).

Unrealized Gains on Derivative Contracts, 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 gas contracts in the first quarter are reflected in earnings, as opposed to being recorded in other comprehensive income (loss), a component of stockholders’ equity. Gas prices declined following December 31, 2005 and as a result, we recognized a $7.2 million non-cash gain in our statement of operations during the three months ended March 31, 2006. As commodity prices fluctuate, we will record our 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. Our oil derivative contracts continue to qualify for hedge accounting.

Minority Interest. Minority interest represents the minority investors’ percentage of their share of income or losses from Big Dog and Shark in the three months ended March 31, 2005 and from DHS in the three months ended March 31, 2006.

27

Interest and Financing Costs. Interest and financing costs increased 157% to $5.5 million for the three months ended March 31, 2006, as compared to $2.1 million for the year earlier period. The increase is primarily related to the $150.0 million senior note offering completed in March 2005, the increase in the average amount outstanding under our credit facility incurred to fund the Manti acquisition completed in January 2005 and our increased investments in the Columbia River Basin prospect in Washington completed in April and September 2005.

Income Tax Expense. Prior to June 30, 2005, the Company recorded a full valuation allowance on its deferred tax assets and accordingly, during the three months ended March 31, 2005, no income tax provision was recorded. During the three months ended March 31, 2006, an income tax provision of $8.3 million was recorded for continuing operations at an effective tax rate of 37.85%.

Discontinued Operations. Discontinued operations during the three months ended March 31, 2005 related to Deerlick Field, which was sold in September 2005.

28

Liquidity and Capital Resources

Liquidity is a measure of a company’s ability to access cash. 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 and sale of oil and gas properties, and through borrowings under our credit facility.

During the three months ended March 31, 2006, our cash provided by operating activities was $7.1 million and cash provided by financing activities was $36.4 million. During this period we spent $31.7 million on capital expenditures (net of dispositions). At March 31, 2006, we had $17.3 million in cash, total assets of $752.8 million and a debt to capitalization ratio of 38.5%. Long-term debt at March 31, 2006 totaled $248.7 million comprised of $99.3 million of combined bank debt and $149.3 million of senior subordinated notes. Available borrowing capacity under the bank credit facility at March 31, 2006 was approximately $19.0 million.

Since December 31, 2005, we have been able to complete several recent equity, debt, and property transactions as described below. On February 1, 2006, we completed a public offering of 1.5 million shares of our common stock for net proceeds of $33.9 million, a portion of which were used to fund the cash portion of the purchase price in the Armstrong acquisition. During the first quarter of 2006 we sold minority interests in CRBP and PGR for proceeds of $32.8 million and $20.4 million, respectively. In addition, in April 2006, the Company closed its acquisition of Castle Energy Corporation with the net issuance of 1.8 million shares of common stock. The Company received approximately $20.4 million in cash in connection with the Castle acquisition. Also, 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 million was initially drawn.

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

We continue to examine alternative sources of long-term capital, including bank borrowings, 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, some of which are beyond our control.

We believe that borrowings under our Revolving Credit Facility, projected operating cash flows, proceeds from additional debt and equity financings and cash on hand will be sufficient to meet the requirements of our business; however, future cash flows are subject to a number of variables, including the level of production and oil and natural gas prices. We cannot give assurance that operations and other capital resources will provide cash in sufficient amounts to maintain planned levels of capital expenditures or that increased capital expenditures will not be undertaken. Most of our capital expenditures are discretionary, and actual levels of capital expenditures may vary significantly due to a variety of factors, including but not limited to, drilling results, product pricing and future acquisitions and divestitures of properties.

Company Acquisitions and Growth

We continue to evaluate potential acquisitions and property development opportunities. During the three months ended March 31, 2006, we completed the following transactions:

In January 2006, we purchased Rooster Drilling Company for 350,000 shares of Delta common stock valued at $8.3 million. Delta contributed Rooster Drilling to DHS during the quarter ended March 31, 2006. Rooster Drilling owns one drilling rig which was named DHS Drilling Company

29

Rig 15. The rig is an Oilwell 66, with a depth capacity of 12,000 feet. The rig is located in Wyoming and is under contract with a third party to drill 9 wells (or minimum 100 days), in the Big Piney area of Wyoming.

On February 1, 2006, we entered into a purchase and sale agreement with Armstrong Resources, LLC (“Armstrong”) to acquire a 65% working interest in approximately 88,000 gross acres in the central Utah hingeline play for a purchase price of $24 million in cash and 673,401 shares of common stock. The Company funded the cash portion of the purchase price with proceeds from a $33.9 million stock offering. 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 is expected to begin during summer 2006, subject to successful permitting.

Historical Cash Flow

Our cash flow from operating activities increased from $5.4 million for three months ended March 31, 2005 to $7.1 million for the three months ended March 31, 2006, primarily as a result of increased production and higher realized oil and natural gas prices. Our net cash used in investing activities decreased to $31.7 million for the three months ended March 31, 2006 compared to net cash used in investing activities of $87.1 million for the year earlier period. The decrease in cash used in investing activities is primarily due to the $42.8 million in proceeds received for sales of oil and gas properties. Cash provided by financing activities was $36.4 million for the three months ended March 31, 2006 compared to $88.2 million for the comparable prior year period.

Capital and Exploration Expenditures and Financing

Our capital and exploration expenditures and sources of financing for the three months ended March 31, 2006 and 2005 are as follows:


	2006			2005
	(In thousands)
CAPITAL AND EXPLORATION EXPENDITURES:
Acquisitions:
Armstrong acquisition	$	40,103			—
Manti		—			59,500
Washington County South and North Tongue		—			1,177
Other		2,103			1,230

Other development costs		43,557			21,707
Drilling and trucking costs		13,893			6,791
Dry hole costs		1,340			19
Exploration costs		683			1,663

	$	101,679		$	92,087


FUNDING SOURCES:
Cash flow provided by operating activities	$	7,119		$	5,396
Stock issued for cash upon exercised options		2,838			427
Stock issued for cash, net		33,870			—
Net long-term borrowings		(235	)		87,749
Minority interest contributions		9,018			—
Proceeds from sale of oil and gas properties		42,810			—
Other		(266	)		17

	$	95,154		$	93,589

30

We anticipate our drilling capital and exploration expenditures to range between $150.0 and $195.0 million for the full year 2006, depending on capital availability. However, the timing of most of our capital expenditures is discretionary.

Sale of Oil and Gas Properties

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 a newly created wholly owned subsidiary, CRBP. In January and March 2006, Delta 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, 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. As a result of the transaction, Delta now owns a net interest of just over 36,000 acres in the Columbia River Basin through its remaining ownership of CRBP and additional 100% interests in 332,000 net acres in the Columbia River Basin from previous transactions.

In March 2006, the Company sold approximately 26% of PGR Partners, LLC (“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. The Company 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. The Company has retained a 74% interest in PGR.

Contractual and Long Term Debt Obligations


	Payments Due by Period
	Less than						After
Contractual Obligations at March 31, 2006	1 year		2-3 Years		4-5 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		46,783		99,283
Credit facility		—		56,000		—		—		56,000
DHS term loan		9,000		18,000		16,250		—		43,250
Derivative liability		8,240		1,816		—		—		10,056
Abandonment retirement obligation		730		341		238		6,598		7,907
Operating leases		2,025		4,030		3,072		3,847		12,974
Other debt obligations		74		61		—		—		135

Total contractual cash obligations	$	30,569	$	101,248	$	40,560	$	207,228	$	379,605

7% Senior Unsecured Notes, due 2015

On March 15, 2005, we 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 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.

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Credit Facility

At March 31, 2006, our $200.0 million credit facility had an available borrowing base of approximately $75.0 million and $56.0 million outstanding. 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 loan is collateralized by substantially all of our oil and gas properties. We are required to meet certain financial covenants which include a current ratio of 1 to 1, net of availability under our credit facility and current derivative instruments of $25.5 million and a consolidated debt to adjusted EBITDAX (Earnings before interest, taxes, depreciation, amortization and exploration) ratio of less than 3.5 to 1. For calculation purposes, the financial maintenance covenants only include the results of subsidiaries which we own 100%. At December 31, 2005, the Company was not in compliance with its quarterly debt covenants and restrictions, but obtained a waiver from the banks for the quarter ended December 31, 2005. In addition, the credit agreement was amended to exclude the quarter ended March 31, 2006 from the current ratio requirement. At March 31, 2006, we were in compliance with our quarterly debt covenants and restrictions. At June 30, 2006, our financial covenants will include a current ratio of 1 to 1 and a consolidated debt to adjusted EBITDAX of less than 3.5 to 1 (declining to 3.0 to 1 for the quarters ended September 30 and December 31, 2006). The Company expects to be in compliance at June 30, 2006. However, if we are not in compliance, the Company will be required to request a waiver or an amendment to the credit agreement from the lenders, or obtain alternative financing, none of which can be assured.

Subsequent determinations of the borrowing base will be made 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 1, 2006 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.

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Term Loan — DHS

On September 30, 2005, DHS completed a financing arrangement with Guggenheim Corporate Funding, LLC (“Guggenheim”) for $35.0 million due September 30, 2010, with principal and interest payments due on the first calendar day of each quarter. On January 6, 2006, DHS amended its Guggenheim note to provide for an additional $10.0 million in borrowings and amend certain of the financial covenants as follows. The covenant for Maximum Consolidated Leverage Ratio of 2.5 to 1 (declining to 2.0 to 1.0 at June 30, 2006) was amended to a ratio of 3.0 to 1, 2.75 to 1, and 2.50 to 1 for the quarters ending December 31, 2005, March 31, 2006, and June 30, 2006 respectively. For subsequent quarters, the ratio is 2.00 to 1, as per the original covenants. Additionally, the current ratio covenant was modified, eliminating the current portion of long term debt from the current liabilities component of the ratio. The Minimum Consolidated Interest Coverage Ratio was not amended. The amended note remains due on September 30, 2010, with quarterly principal payments of $2.25 million beginning April 1, 2006, and one balloon payment on September 30, 2010 of $2.75 million. The interest rate on the note was modified to Prime plus 3.5%, 11.25% at March 31, 2006, until such time as, one, the Maximum Consolidated Leverage Ratios complies with the original ratios, and, two, the ratio of the long term debt to the appraised value of the Company’s equipment is equal to or less than 55%. When the ratios on the original covenant are achieved and the appraised value ratio is 55% or lower, the interest rate will change to the original rate (Prime plus 3.0%). Financing costs of $100,000 were incurred in conjunction with the amendment, and will be amortized over the remaining life of the note. At March 31, 2006, DHS was in compliance with its covenants on the note. In May 2006, DHS paid off the Term Loan with the proceeds from borrowings under a new $100 million credit facility with JP Morgan Chase Bank, N.A. as administrative agent, (See Footnote 12, Subsequent Events).

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 fiscal 2015. Our average yearly payments approximate $864,000 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.

Derivative instruments represent the net estimated unrealized losses for our oil and gas hedges at March 31, 2006. 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 reasonable under the

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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.

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 that 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

34

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.

Impairment of Gas and Oil Properties

We review our oil and gas properties for impairment 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 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. We did not record an impairment during the three months ended March 31, 2006 and 2005.

Commodity Derivative Instruments and Hedging Activities

We periodically enter into commodity derivative contracts and 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. 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. For qualifying fair value hedges, the gain or loss on the derivative is offset by related results of the hedged item in the income statement. 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 SFAS No. 143 “Accounting for Asset Retirement Obligations.” SFAS No. 143 requires entities to record the fair value of a liability for retirement obligations of acquired assets. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002. The Company 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. The Company’s asset retirement obligations arise from the plugging and abandonment liabilities for its oil and gas wells.

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In March 2005, the FASB issued FASB Interpretation 47 (“FIN 47”), an interpretation of SFAS No. 143, Accounting for Asset Retirement Obligations (SFAS No. 143”). FIN 47 clarifies the term “conditional asset retirement obligation” as it is used in SFAS No. 143. The Company applied the guidance of FIN 47 beginning July 1, 2005 resulting in no impact on its financial statements.

Deferred Tax Asset Valuation Allowance

The Company follows SFAS No. 109, “Accounting for Income Taxes,” to account for its 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 carry forwards. 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, the Company maintains a valuation allowance against a portion of its deferred tax assets. The Company will continue to monitor facts and circumstances in its reassessment of the likelihood that operating loss carryforwards and other deferred tax attributes will be utilized prior to their expiration. As a result, the Company 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.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Market Rate and Price Risk

We actively manage our exposure to commodity price fluctuations by hedging meaningful portions of our expected production through the use of derivatives, typically costless collars. 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 typically use hedges in conjunction with acquisitions to achieve expected economic returns during the payout period.

The net fair value of our derivative instruments obligation was $10.1 million at March 31, 2006 and $11.7 million on May 1, 2006.

In April 2006, the Company purchased for $492,000 a natural gas put option with a NYMEX strike price of $7.50 per Mmbtu on 10,000 Mmbtu per day for July 2006 through September 2006. This derivative does not qualify for hedge accounting and accordingly any change in the contract’s fair value will be recorded on the consolidated balance sheet with a corresponding unrealized gain or loss recorded in the consolidated statement of operations.

Assuming production and the percent of oil and gas sold remained unchanged for the quarter ended March 31, 2006, a hypothetical 10% decline in the average market price the Company realized during the three months ended March 31, 2006 on unhedged production would reduce the Company’s oil and natural gas revenues by approximately $3.4 million on a quarterly basis.

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Interest Rate Risk

We were subject to interest rate risk on $99.3 million of variable rate debt obligations at March 31, 2006. The annual effect of a ten percent change in interest rates would be approximately $865,000. The interest rate on these variable debt obligations approximates current market rates as of March 31, 2006.

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 or our disclosure controls and procedures, as defined in Rules 13a-15(e) under the Securities Exchange Act of 1934 (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, 2006, 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 the Company’s 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, the Company’s internal control over financial reporting.

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PART II — OTHER INFORMATION

Item 1. Legal Proceedings.

We and our majority-owned subsidiary, Amber Resources Company of Colorado, are among twelve plaintiffs in a lawsuit that was filed on January 9, 2002 in the United States Court of Federal Claims in Washington, D.C. alleging that the U.S. government has materially breached the terms of forty undeveloped federal leases, some of which are part of our offshore California properties. The Complaint is based on allegations by the collective plaintiffs that the United States has materially breached the terms of certain of their offshore California leases by attempting to deviate significantly from the procedures and standards that were in effect when the leases were entered into, and by failing to carry out its own obligations relating to those leases in a timely and fair manner. More specifically, the plaintiffs have alleged that the judicial determination in the California v. Norton case, that a 1990 amendment to the Coastal Zone Management Act that required the government to make a consistency determination prior to granting lease suspension requests in 1999, constitutes a material change in the procedures and standards that were in effect when the leases were issued. The plaintiffs have also alleged that the United States has failed to afford them the timely and fair review of their lease suspension requests which has resulted in significant, continuing and material delays to their exploratory and development operations.

The suit seeks compensation for the lease bonuses and rentals paid to the Federal government, exploration costs and related expenses. The total amount claimed by all lessees for bonuses and rentals exceeds $1.2 billion, with additional amounts for exploration costs and related expenses. We own approximately 12% of the lease bonus costs that are the subject of the lawsuit. In addition, our claim for exploration costs and related expenses will also be substantial. In the event, however, that we receive any proceeds as the result of such litigation, we will be obligated to pay a portion of any amount received by us to landowners and other owners of royalties and similar interests, to pay the litigation expenses and to fulfill certain pre-existing contractual commitments to third parties.

On November 15, 2005, the United States Court of Federal Claims issued a ruling in the suit granting the plaintiffs’ motion for 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’s ruling also denied the United States’ motion to dismiss and motion for summary judgment. The United States Court of Federal Claims ruled that the federal government’s imposition of new and onerous requirements that stood as a significant obstacle to oil and gas development breached agreements that it made when it sold thirty six out of the total forty offshore California federal leases that are the subject of the litigation. The Court further ruled that the government must give back to the current lessees the more than $1.1 billion in lease bonuses it had received at the time of sale.

We and Amber are among the current lessees of the thirty six leases that are the subject of the ruling. Together with Amber, our net share of the $1.1 billion award is approximately $121 million. The government has filed a motion for reconsideration of this ruling. The final ruling in the case will not be made until the Court addresses the plaintiffs’ additional claims regarding the four additional leases, as well as their claims regarding the hundreds of millions of dollars that have been spent in the successful efforts to find oil and gas in the disputed lease area, and other matters. The final ruling, including the ruling made on November 15, will be subject to appeal, and no payments will be made until all appeals have either been waived or exhausted.

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

During the quarter ended March 31, 2006, we did not have any sale 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 January 27, 2006, we issued 350,000 shares of our common stock to Edward Mike Davis in connection with our acquisition for DHS of Rooster Drilling Company, which owned a operating drilling rig and related equipment and inventory.

In connection with this transaction we relied on the exemption provided by Section 4(2) of the Securities Act. We reasonably believe that the investor is an “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 investor acquired the shares for investment purposes. A restrictive legend was placed on the stock certificate issued to Mr. Davis, and a stop transfer order was given to our transfer agent, however, on February 14, 2006, the offer and sale of all 350,000 shares were registered under the Securities Act pursuant to our Form S-3ASR (333-131854).

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Glossary of Oil and Gas Terms

The terms defined in this section are used throughout this Form 10-Q.

Bbl. Barrel (of oil or natural gas liquids).

Bcf. Billion cubic feet (of natural gas).

Bcfe. Billion cubic feet equivalent.

Bbtu. One billion British Thermal Units.

Developed acreage. The number of acres which are allocated or held by producing wells or wells capable of production.

Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry hole; dry well. A well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

Equivalent volumes. Equivalent volumes are computed with oil and natural gas liquid quantities converted to Mcf on an energy equivalent ratio of one barrel to six Mcf.

Exploratory well. A well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir.

Farmout. An assignment of an interest in a drilling location and related acreage conditional upon the drilling of a well on that location.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

Liquids. Describes oil, condensate, and natural gas liquids.

MBbls. Thousands of barrels.

Mcf. Thousand cubic feet (of natural gas).

Mcfe. Thousand cubic feet equivalent.

MMBtu. One million British Thermal Units, a common energy measurement.

MMcf. Million cubic feet.

MMcfe. Million cubic feet equivalent.

NGL. Natural gas liquids.

Net acres or net wells. The sum of the fractional working interest owned in gross acres or gross wells expressed in whole numbers.

NYMEX. New York Mercantile Exchange.

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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.

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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:


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

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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
Date: May 4, 2006		Chief Financial Officer

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EXHIBIT INDEX


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

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

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

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


		Page No.
Item 1.	Consolidated Financial Statements

	Consolidated Balance Sheets — March 31, 2006 (unaudited)
	December 31, 2005		1

	Consolidated Statements of Operations — Three Months Ended
	March 31, 2006 and 2005 (unaudited)		2

	Consolidated Statement of Changes in Stockholders' Equity and Comprehensive
	Income (Loss) — Three Months Ended March 31, 2006 (unaudited)		3

	Consolidated Statements of Cash Flows — Three Months Ended
	March 31, 2006 and 2005 (unaudited)		4

	Notes to Consolidated Financial Statements (unaudited)		5

Item 2.	Management's Discussion and Analysis of Financial Condition and
	Results of Operations		23

Item 3.	Quantitative and Qualitative Disclosures About Market Risk		36

Item 4.	Controls and Procedures		37

PART II OTHER INFORMATION

Item 1.	Legal Proceedings		38

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
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO Pursuant to Section 906
Certification of CFO Pursuant to Section 906

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