Par Pacific Holdings - 10-Q quarterly report FY

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 September 30, 2005


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)


Colorado		84-1060803
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer 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 an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes þ No o

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

47,840,457 shares of common stock $.01 par value were outstanding as of November 1, 2005.

INDEX


	Page No.

PART I FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements

Consolidated Balance Sheets — September 30, 2005 and June 30, 2005 (unaudited)		1

Consolidated Statements of Operations — Three Months Ended September 30, 2005 and 2004 (unaudited)		2

Consolidated Statement of Stockholders’ Equity and Comprehensive Income (Loss) — Three Months Ended September 30, 2005 (unaudited)		3

Consolidated Statements of Cash Flows — Three Months Ended September 30, 2005 and 2004 (unaudited)		4

Notes to Consolidated Financial Statements (unaudited)		5

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk		35

Item 4. Controls and Procedures		36

PART II OTHER INFORMATION

Item 1. Legal Proceedings		37

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		37

Item 3. Defaults upon Senior Securities		40

Item 4. Submission of Matters to a Vote of Security Holders		40

Item 5. Other Information		40

Item 6. Exhibits		40
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO Pursuant to Section 18 U.S.C. Section 1350
Certification of CFO Pursuant to Section 18 U.S.C. Section 1350

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

i

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)


	September 30,			June 30,
	2005			2005
	(In thousands, except share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	24,077		$	2,241
Marketable securities available for sale		—			1,764
Trade accounts receivable, net of allowance for doubtful accounts of $100 and $100, respectively		18,770			10,512
Prepaid assets		5,510			2,980
Inventory		4,216			5,062
Deferred tax asset		9,013			2,676
Derivative instruments		137			378
Other current assets		2,253			1,421

Total current assets		63,976			27,034


Property and equipment:
Oil and gas properties, successful efforts method of accounting
Unproved		186,988			101,935
Proved		389,308			365,306
Drilling and trucking equipment, including deposits on equipment of $7.5 million		54,045			40,031
Other		10,469			10,412

Total property and equipment		640,810			517,684
Less accumulated depreciation and depletion		(53,157	)		(44,134	)

Net property and equipment		587,653			473,550


Long-term assets:
Investment in LNG project		1,022			1,022
Deferred financing costs		5,571			5,825
Deferred tax asset		7,240			4,887
Derivative instruments		321			469
Other long-term assets		630			196

Total long-term assets		14,784			12,399

	$	666,413		$	512,983


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt	$	7,072		$	3,477
Accounts payable		46,859			38,151
Other accrued liabilities		8,153			5,281
Derivative liabilities		23,489			7,241

Total current liabilities		85,573			54,150


Long-term liabilities:
7% senior unsecured notes		149,291			149,272
Credit facility		56,000			66,500
Term loan — DHS		28,000			—
Asset retirement obligation		2,920			2,975
Derivative liabilities		8,925			3,620
Other debt, net		99			229

Total long-term liabilities		245,235			222,596


Minority interest		15,215			14,614


Commitments

Stockholders’ equity:
Preferred stock, $.10 par value; authorized 3,000,000 shares, none issued
Common stock, $.01 par value; authorized 300,000,000 shares, issued 47,683,000 shares at September 30, 2005 and 42,017,000 at June 30, 2005		477			420
Additional paid-in capital		340,930			235,300
Unearned compensation		(3,517	)		(1,382	)
Accumulated other comprehensive loss		(7,847	)		(5,225	)
Accumulated deficit		(9,653	)		(7,490	)

Total stockholders’ equity		320,390			221,623

	$	666,413		$	512,983

See accompanying notes to consolidated financial statements.

1

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


	Three Months Ended
	September 30,
	2005			2004
	(In thousands, except per share amounts)
Revenue:
Oil and gas sales	$	31,560		$	18,098
Drilling income		3,110			119
Realized loss on derivative instruments, net		(2,692	)		—

Total revenue		31,978			18,217


Operating expenses:
Lease operating expense		4,798			2,534
Transportation expense		478			116
Production taxes		2,221			1,293
Depreciation, depletion and amortization — oil and gas		9,468			4,734
Depreciation and amortization — drilling		942			143
Exploration expense		851			536
Dry hole costs		1,764			2,254
Drilling expenses		2,115			436
Professional fees		734			346
General and administrative (includes compensation of $1,528 and zero, respectively)		6,638			2,590

Total operating expenses		30,009			14,982


Operating income		1,969			3,235

Other income and (expense):
Other income		64			34
Gain on sale of marketable securities, net		1,194			—
Unrealized loss on derivative contracts, net		(18,843	)		—
Minority interest		(531	)		81
Interest and financing costs		(4,019	)		(883	)


Total other expense		(22,135	)		(768	)


Income (loss) from continuing operations before income taxes, and discontinued operations		(20,166	)		2,467

Income tax benefit		7,721			—


Net income (loss) from continuing operations		(12,445	)		2,467
Income from discontinued operations of properties sold, net of tax		506			1,477
Gain on sale of oil and gas properties, net of tax		9,776			—


Net income (loss)	$	(2,163	)	$	3,944


Basic income (loss) per common share:
Net income (loss) from continuing operations	$	(0.29	)	$	.08
Discontinued operations		0.24			.02

Net income (loss)	$	(0.05	)	$	.10


Diluted income (loss) per common share:
Net income (loss) from continuing operations	$	(0.28	)	$	.07
Discontinued operations		0.23			.02

Net income (loss)	$	(0.05	)	$	.09

See accompanying notes to consolidated financial statements.

2

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


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

							(In thousands, except per share amounts)
Balance, July 1, 2005		42,017	$	420	$	235,300	$	(5,225	)				$	(1,382	)	$	(7,490	)	$	221,623

Comprehensive income (loss):
Net loss		—		—		—		—		$	(2,163	)		—			(2,163	)		(2,163	)
Other comprehensive transactions, net of tax
Realized gain on equity securities sold, net of tax expense of $458		—		—		—		(736	)		(736	)		—			—			(736	)
Hedging loss reclassified to income upon settlement, net of tax benefit of $1,035		—		—		—		1,657			1,657			—			—			1,657
Change in fair value of derivative hedging instruments, net of tax benefit of $2,249		—		—		—		(3,543	)		(3,543	)		—			—			(3,543	)

Comprehensive loss										$	(4,785	)

Shares issued for oil and gas properties		50		1		827		—						—			—			828
Shares issued for cash, net of offering costs		5,406		54		94,945		—						—			—			94,999
Shares issued for cash upon exercise of options		87		1		480		—						—			—			481
Tax benefit for options exercised		—		—		5,716		—						—			—			5,716
Amortization of unearned compensation		—		—		—		—						456			—			456
Compensation on options vested		—		—		1,072		—						—			—			1,072
Issuance of restricted stock		123		1		2,590		—						(2,591	)		—			—


Balance, September 30, 2005		47,683	$	477	$	340,930	$	(7,847	)				$	(3,517	)	$	(9,653	)	$	320,390

See accompanying notes to consolidated financial statements.

3

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


	Three Months Ended
	September 30,
	2005			2004
	(In thousands)
Cash flows operations activities:
Net income (loss)	$	(2,163	)	$	3,944
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion and amortization — oil and gas		9,418			4,664
Depreciation and amortization — drilling		942			143
Depreciation, depletion and amortization — discontinued operations		91			313
Accretion of abandonment obligation		50			70
Stock option and restricted stock compensation		1,528			—
Amortization of deferred financing costs		327			77
Unrealized loss on derivative contracts		18,843
Dry hole costs, previously capitalized in work in progress		530			258
Minority interest		531			(81	)
Deferred tax benefit		(7,405	)		—
Gain on sale of marketable securities		(1,194	)		—
Gain on sale of oil and gas properties — discontinued operations		(9,776	)		—
Other		89			831
Net changes in operating assets and operating liabilities:
Increase in trade accounts receivable		(8,258	)		(944	)
Increase in prepaid assets		(2,531	)		(313	)
Increase in inventory		(104	)		(1,519	)
(Increase) decrease in other current assets		(520	)		20
Decrease in accounts payable trade		(3,950	)		(3,376	)
Increase (decrease) in other accrued liabilities		3,123			(754	)


Net cash provided by (used in) operating activities		(429	)		3,333


Cash flows from investing activities:
Additions to property and equipment, net		(110,010	)		(14,146	)
Proceeds from sales of oil and gas properties		28,981			18,721
Drilling and trucking capital expenditures		(14,023	)		(1,236	)
Proceeds from sale of marketable securities		1,764			—
(Increase) decrease in long-term assets		(434	)		41


Net cash provided by (used in) investing activities		(93,722	)		3,380


Cash flows from financing activities:
Stock issued for cash upon exercise of options		481			289
Stock issued for cash, net		94,999			—
Proceeds from borrowings		54,728			60
Payment of financing fees		(458	)		—
Repayment of borrowings		(33,763	)		(8,915	)


Net cash provided by (used in) financing activities		115,987			(8,566	)


Net increase (decrease) in cash and cash equivalents		21,836			(1,853	)


Cash at beginning of period		2,241			2,078


Cash at end of period	$	24,077		$	225


Supplemental cash flow information —
Common stock issued for the acquisition of oil and gas properties	$	828		$	10,359


Common stock issued for drilling and trucking equipment	$	—		$	461


Cash paid for interest and financing costs	$	7,379		$	647

See accompanying notes to consolidated financial statements.

4

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended September 30, 2005 and 2004
(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 annual report on Form 10-K. 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, Company Management and the Board of Directors made the decision to change the Company’s 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 annual report on Form 10-K for the year ended June 30, 2005, previously filed with the Securities and Exchange Commission.

(2) Recent Accounting Pronouncements

Statement of Financial Accounting Standards No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies”, specifies that drilling costs for completed exploratory wells should be expensed if the related reserves cannot be classified as proved within one year unless certain criteria are met. In April 2005, the Financial Accounting Standards Board (“FASB”) issued Staff Position 19-1, (“FSP 19-1”) “Accounting for Suspended Well Costs”. FSP 19-1 provides guidance for evaluating whether sufficient progress is being made to determine whether reserves can be classified as proved. FSP 19-1 is effective for all reporting periods beginning after April 4, 2005, and accordingly, the Company adopted FSP 19-1 on July 1, 2005. The following table reflects the net changes in capitalized exploratory well costs for three months ended September 30, 2005:


	2005
	(In thousands)
Balance at beginning of period, July 1,	$	530
Additions to capitalized exploratory well costs pending the determination of proved reserves¹		—
Reclassified to proved oil and gas properties based on the determination of proved reserves		—
Capitalized exploratory well costs charged to dry hole expense		(530	)

Balance at end of period, September 30,	$	—


¹		The final FSP directs that costs suspended and expensed in the same period not be included in this analysis.

5

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended September 30, 2005 and 2004
(Unaudited)

(3) Nature of Organization

Delta Petroleum Corporation (“Delta” or the “Company”) was organized December 21, 1984 and is principally engaged in acquiring, exploring, developing and producing oil and gas properties. The core areas of operation are the Rocky Mountain and Gulf Coast regions, which comprise the majority of our 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 late fiscal 2005, owns a 49.5% (Delta effectively owns an additional portion of DHS’s interest until such time as the officers of DHS earn their 5.5% interest over the next five years) interest in DHS Drilling Company (“DHS”), an affiliated Colorado corporation that is headquartered in Casper, Wyoming. DHS currently has eight drilling rigs in operation that have depth ratings of approximately 7,500 to 20,000 feet. Two additional rigs are in the process of being acquired or assembled by DHS and are currently expected to become operational in early calendar 2006. The Company has the right to use all of the rigs on a priority basis, although approximately half will initially work for third party operators. The majority of the rigs will operate in the Rocky Mountain basins.

At September 30, 2005 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.

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

(4) Summary of Significant Accounting Policies

Principles of Consolidation and Basis of Presentation

The consolidated financial statements include the accounts of Delta, Amber, Piper and DHS (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. Certain reclassifications have been made to amounts reported in previous years to conform to the current year presentation. The Company has no interests in any other unconsolidated entities other than its investment in a liquid natural gas LLC which is recorded at its cost, 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. The Company includes its proportionate share of assets, liabilities, revenues and expenses from these entities in its consolidated financial statements.

6

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended September 30, 2005 and 2004
(Unaudited)

(4) Summary of Significant Accounting Policies, Continued

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.

Marketable Securities

The Company classifies its investment securities as available-for-sale securities. Pursuant to Statement of Financial Accounting Standards (“SFAS”) No. 115 (SFAS 115), such securities are measured at fair market value in the financial statements with unrealized gains or losses recorded in other comprehensive income. At the time securities are sold or otherwise disposed of, gains or losses are included in earnings. During the quarter ended September 30, 2005, the Company sold its investments as shown below.


			Realized			Proceeds
	Cost		Gain (Loss)			From Sale
	(In thousands)
September 30, 2005
Bion Environmental Technologies, Inc.	$	152	$	(140	)	$	12
Tipperary Oil & Gas Company		418		1,334			1,752

	$	570	$	1,194		$	1,764


			Accumulated
			Unrealized			Estimated
	Cost		Gain (Loss)			Market Value
As of June 30, 2005
Bion Environmental Technologies, Inc.	$	152	$	(140	)	$	12
Tipperary Oil & Gas Company		418		1,334			1,752

	$	570	$	1,194		$	1,764

Inventories

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

Minority Interest

Minority interest represents the 50.5% (45% Chesapeake Energy Corporation, 2.75% each for DHS executive officers William E. Sauer, Jr. and Harold D. Hastings) investors of DHS Drilling Company at September 30, 2005 and June 30, 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, LLC (“Shark”). The net assets of Big Dog and Shark were ultimately acquired and contributed to DHS.

7

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended September 30, 2005 and 2004
(Unaudited)

(4) Summary of Significant Accounting Policies, Continued

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 September 30, 2005 and June 30, 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 quarter ended September 30, 2005.

Drilling

We earn our contract drilling revenues under day-work arrangements. We recognize revenues on day-work contracts for the days completed based on the day-rate each contract specifies. Individual wells are usually completed in less than 60 days. The cost of drilling the Company’s own oil and gas properties are capitalized in oil and gas properties as the expenditures are incurred.

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 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.

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.

8

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended September 30, 2005 and 2004
(Unaudited)

(4) Summary of Significant Accounting Policies, Continued

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 September 30, 2005 and 2004.

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 September 30, 2005 and 2004.

9

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended September 30, 2005 and 2004
(Unaudited)

(4) 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 July 1, 2005 to September 30, 2005 (amounts in thousands).


Asset retirement obligation — July 1, 2005	$	3,691
Accretion expense		50
Change in estimate		—
Obligations acquired		37
Obligations settled		—
Obligations on sold properties		(393	)

Asset retirement obligation — September 30, 2005		3,385
Less: Current asset retirement obligation		(465	)

Long-term asset retirement obligation	$	2,920

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 (Loss)

Comprehensive income (loss) includes all changes in equity during a period. The components of comprehensive income (loss) for the three months ended September 30, 2005 and 2004 are as follows:


	Three Months Ended
	September 30,
	2005			2004
	(In thousands)
Net income (loss)	$	(2,163	)	$	3,944
Other comprehensive income transactions
Realized gain on equity securities sold, net of tax expense of $458		(736	)		(587	)
Hedging instruments reclassified to income upon settlement, net of tax benefit of $1,035		1,657			—
Change in fair value of derivative hedging instruments, net of tax benefit of $2,249		(3,543	)		48

		(2,622	)		(539	)

Comprehensive income (loss)	$	(4,785	)	$	3,405

10

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended September 30, 2005 and 2004
(Unaudited)

(4) Summary of Significant Accounting Policies, Continued

Financial Instruments

The Company periodically enters into commodity price risk transactions to manage its exposure to oil and gas price volatility. These transactions may take the form of futures contracts, collar agreements, swaps or options. The purpose of the hedges is to provide a measure of stability to the Company’s cash flows in an environment of volatile oil and gas prices. All transactions are accounted for in accordance with requirements of Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”) 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 September 30, 2005, all of the Company’s derivative contracts are 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.

11

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended September 30, 2005 and 2004
(Unaudited)

(4) Summary of Significant Accounting Policies, Continued

The following table summarizes our open derivative contracts at September 30, 2005 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	Sept. 30, 2005
								(In thousands)
Contracts that qualify for hedge accounting
Crude oil		6,000	Bbls / month	$	35.00 / $49.75	Apr ’05 - Dec ’05	NYMEX-WTI	$	(298	)
Crude oil		40,000	Bbls / month	$	40.00 / $50.34	July ’05 - June ’06	NYMEX-WTI		(6,093	)
Crude oil		10,000	Bbls / month	$	45.00 / $56.90	July ’05 - June ’06	NYMEX-WTI		(1,007	)
Crude oil		25,000	Bbls / month	$	35.00 / $61.80	July ’06 - June ’07	NYMEX-WTI		(2,933	)

Contracts that do not qualify for hedge accounting
Natural gas		3,000	MMBtu / day	$	5.00 / $7.85	Apr ’05 - Oct ’05	NYMEX-H HUB		(447	)
Natural gas		10,000	MMBtu / day	$	5.00 / $9.60	July ’05 - June ’06	NYMEX-H HUB		(9,832	)
Natural gas		3,000	MMBtu / day	$	6.00 / $9.35	July ’05 - June ’06	NYMEX-H HUB		(3,116	)
Natural gas		13,000	MMBtu / day	$	5.00 / $10.20	July ’06 - June ’07	NYMEX-H HUB		(8,230	)

								$	(31,956	)

The net fair value of the Company’s derivative instruments obligation was a liability of approximately $32.0 million at September 30, 2005 and $21.6 million on November 1, 2005.

The net realized losses from hedging activities recognized in the Company’s statements of operations were $2.7 million and zero for the three months ended September 30, 2005 and 2004, respectively. These losses are recorded as a decrease in revenues.

During the three months ended September 30, 2005, the Company’s gas derivative contracts became ineffective under SFAS No. 133 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 the Company’s oil and gas production. The change in fair value of our gas contracts in the first quarter are reflected in earnings, as opposed to previously being disclosed in other comprehensive income (loss), a component of stockholder’s equity. As a result, the Company recognized an $18.8 million non-cash loss in its statement of operations as a component of other income (expense).

12

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended September 30, 2005 and 2004
(Unaudited)

(4) Summary of Significant Accounting Policies, Continued

Stock Option Plans

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, 2002 the FASB issued SFAS No. 148, “Accounting for Stock-based Compensation-Transition and Disclosure ”(“SFAS No. 148”). SFAS No. 148 amended FASB Statement No. 123, “Accounting for Stock-Based Compensation” (“SFAS No. 123”) to provide alternative methods of transition for a voluntary change to the fair-value based method of accounting for stock-based employee compensation. In addition, this Statement amended the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on the reported results. The provisions of SFAS No. 148 had no material impact on the Company, as the Company was not required to adopt the fair-value method of accounting for stock options previously. Accordingly, no compensation cost was recognized for options granted to employees at a price equal to or greater than the fair market value of the common stock prior to June 30, 2005.

However, 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 $1.1 million, relating to employee provided services during the quarter ended September 30, 2005.

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 supersedes 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 September 30, 2005 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 September 30, 2005, the Company had 830,000 unvested options. These options have a value of approximately $3.0 million and will be expensed during future periods through June 2007.

13

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended September 30, 2005 and 2004
(Unaudited)

(4) Summary of Significant Accounting Policies, Continued

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 comparable three months ended September 30, 2004 would have been as follows:


	Three Months Ended
	September 30, 2004
	(In thousands)
Net income	$	3,944
SFAS No. 123R compensation effect		(330	)¹


Net income after SFAS No. 123R implementation	$	3,614


Pro forma basic income per common share:	$	.09


1		During the quarter ended September 30, 2003 the Company granted to certain employees options to purchase 110,000 shares of its common stock at a price of $5.44 per share, which was the market price on the date of the grant. These options vested during the quarter ended September 30, 2004. The fair market value of each option granted was $3.67 and was calculated using a risk free rate of 4.29%, volatility factors of the expected market price of the Company’s common stock of 52.23% and an average expected life of 8.6 years.

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.

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).

14

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended September 30, 2005 and 2004
(Unaudited)

(4) 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, oil and gas properties, depletion and impairment, marketable securities, income taxes, derivatives, asset retirement obligations, contingencies and litigation. Actual results could differ from these estimates.

(5) Oil and Gas Properties

Unproved Undeveloped Offshore California Properties

The Company has direct and indirect ownership interests ranging from 2.49% to 75% in five unproved undeveloped offshore California oil and gas properties with aggregate carrying values of $11.0 million, at September 30, 2005. 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.

Based on indications of levels of hydrocarbons present from drilling operations conducted in the past, the Company believes the fair values of its property interests are in excess of their carrying values at September 30, 2005 and that no impairment in the carrying values has occurred. Pursuant to a ruling in California v. Norton, later affirmed by the 9th Circuit Court of Appeals, the U.S. Government is required to make a consistency determination relating to our 1999 lease suspension requests under a 1990 amendment to the Coastal Zone Management Act. In the event that there is some future adverse ruling under the Coastal Zone Management Act that we decide not to appeal or that we appeal without success, it is likely that some or all of our interests in these leases would become impaired and written off at that time. It is also possible that other events could occur during the Coastal Zone Management Act review or appellate process that would cause our interests in the leases to become impaired, and we will continuously evaluate those factors as they occur.

On January 9, 2002, the Company and several other plaintiffs filed a lawsuit 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 Federal Government has not yet filed an answer to this proceeding pending its motion to dismiss the lawsuit, which motion has been heard but has not yet been ruled upon by the court. We have filed a motion for partial summary Judgement which has been heard but has not yet been ruled upon by the court. See additional disclosure in Item 1 of Part II.

15

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended September 30, 2005 and 2004
(Unaudited)

(5) Oil and Gas Properties, Continued

Acquisition During the Quarter Ended September 30, 2005

On September 29, 2005 the Company acquired an undivided 50% working interest in approximately 145,000 net undeveloped acres in the Columbia River Basin in Washington, and an interest in undeveloped acreage in the Piceance Basin in Colorado from Savant Resources, LLC (“Savant”) for an aggregate purchase price of $85.0 million in cash. James Wallace, a director of Delta, owns approximately a 1.7% interest in Savant, and also serves as a director of Savant. The majority of the acquired acreage in the Columbia River Basin consolidates the Company’s current leasehold position. Delta now owns a 100% working interest in approximately 385,000 net acres. This acquisition included a small portion of acreage that is subject to an agreement with EnCana Oil & Gas (USA) Inc., whereby the Company has the right to convert an overriding royalty interest to a working interest at project payout. In the Piceance Basin, the Company acquired Savant’s interest in an entity that owns a 25% interest in approximately 6,314 gross acres that is currently being developed. The acquisition was funded through the issuance of securities discussed in Footnote 7, Stockholders’ Equity.

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
	September 30,
	2004
	(In thousands)
Oil and gas sales	$	30,975
Net earnings from continuing operations	$	13,766

Net earnings from continuing operations per common share:
Basic	$	.35

Diluted	$	.32

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.

16

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended September 30, 2005 and 2004
(Unaudited)

(5) Oil and Gas Properties, Continued

Fiscal 2005 — Disposition

On September 2, 2005, the Company completed the sale of its Deerlick Creek field in Tuscaloosa County, Alabama for $30.0 million with an effective date of July 1, 2005. The Company recorded an after tax gain on sale of oil and gas properties of $9.8 million on net proceeds of approximately $29.0 million after normal closing adjustments. The net profit earned on these assets during the quarter ended September 30, 2005 was $506,000 and has been presented in discontinued operations.

(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, 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 in compliance with these covenants as of September 30, 2005. (See Footnote 10, “Guarantee of Financial Information”). The fair value of the Company’s senior notes at September 30, 2005 was $143.2 million.

Credit Facility

At September 30, 2005, 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 September 30, 2005 approximated 5.7%. The loan is collateralized by substantially all of our oil and gas properties. Currently, we are 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 $23.4 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 covenants only include subsidiaries which the Company owns 100%. At September 30, 2005, the Company was in compliance with its quarterly debt covenants and restrictions.

17

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended September 30, 2005 and 2004
(Unaudited)

(6) Long Term Debt, Continued

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. The note bears interest at the Prime Rate plus 3.0%, or 9.75% at September 30, 2005. The note contains quarterly financial covenants applied to DHS on a stand-alone basis including a maximum leverage ratio of 2.5 to 1 (declining to 2.0 to 1.0 at June 30, 2006), a minimum current ratio of 1.25 to 1.0 and a minimum interest coverage ratio of 2.50 to 1, each as defined in the agreement. At September 30, 2005, DHS was in compliance with its covenants on the note.

Borrowing availability under these debt agreements at September 30, 2005 was $19 million. Maturities of long-term debt, in thousands of dollars based on contractual terms are as follows:


YEAR ENDING September 30,
2006	$	7,000
2007		7,000
2008		7,000
2009		63,000
2010		7,000
Thereafter		150,000

	$	241,000

(7) Stockholders’ Equity

On September 27, 2005, the Company sold 5,405,418 shares of common stock to twenty-seven institutional investors at a price of $18.50 per share in cash for gross proceeds of $100.0 million and net proceeds of approximately $95.0 million. The proceeds were used to finance the Savant acquisition discussed above and to fund drilling activities.

On July 25, 2005, the Company acquired certain interests in California’s Sacramento Basin from an unrelated individual. The Company issued 50,000 shares of the Company’s common stock valued at $828,000 using the average five-day closing price before and after the terms of the agreement were agreed upon and closed. The total purchase price of $799,000, as adjusted for normal purchase price items, was allocated to proved developed producing properties.

(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 benefit attributable to income (loss) from continuing operations was $7.7 million and zero for the three months ended September 30, 2005 and 2004, respectively. The Company also recorded income tax expense of $6.4 million related to discontinued operations during the three months ended September 30, 2005.

18

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended September 30, 2005 and 2004
(Unaudited)

(8) Income Taxes, Continued

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 September 30, and June 30, 2005. The valuation allowance at September 30, and June 30, 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 September 30, 2005, the Company had net operating loss carryforwards of approximately $78.4 million. Utilization of these losses will be limited to approximately $21.0 million for the six month period ended December 31, 2005 upon which the Company will file a stub period tax return as it transitions from a June 30 fiscal year to a December 31 calendar year for both GAAP and tax purposes. Approximately $42.0 million of net operating loss carryforwards will be available to offset taxable income during 2006.

(9) Earnings Per Share

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


	Three Months Ended
	September 30,
	2005			2004
	(In thousands)
Numerator:
Numerator for basic and diluted income (loss) per share — income (loss) available to common stockholders	$	(2,163	)	$	3,944


Denominator:
Denominator for basic income (loss) per share-weighted average shares outstanding		42,305			39,280
Effect of dilutive securities and stock options		1,944			3,122


Denominator for diluted income (loss) per common share		44,249			42,402


Basic income (loss) per common share	$	(.05	)	$	.10

Diluted income (loss) per common share	$	(.05	)	$	.09


Anti-dilutive securities outstanding		830			1,504

19

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended September 30, 2005 and 2004
(Unaudited)

(10) Guarantee of Financial Information

Delta (“Issuer”) issued 7% Senior Notes (“Bond Offering”) 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 proceeds were used to refinance debt outstanding under the Company’s credit facility. This Bond Offering is guaranteed by all of the 100% owned subsidiaries of the Company at the time of the Bond Offering and any subsequently acquired 100% owned subsidiaries (“Guarantors”). The Guarantors, fully, jointly and severally, irrevocably and unconditionally guarantee the performance and payment when due of all the obligations under the Bond Offering. Big Dog, Shark, DHS and Amber (“Non-guarantors” for their respective periods) are not guarantors of the indebtedness under the Bond Offering.

The following financial information sets forth the Company’s condensed consolidated balance sheets as of September 30, 2005 and June 30, 2005, the condensed consolidated statements of operations for the three months ended September 30, 2005 and 2004, and the condensed consolidated statements of cash flows the three months ended September 30, 2005 and 2004 (in thousands).

Condensed Consolidated Balance Sheet
September 30, 2005


				Guarantor			Non-Guarantor			Adjustments/
	Issuer			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Current assets	$	41,898		$	971		$	21,107		$	—		$	63,976
Property and equipment:
Oil and gas		521,631			49,658			5,007						576,296
Drilling rigs and trucks		—			—			54,045			—			54,045
Other		10,396			—			73			—			10,469

Total property and equipment		532,027			49,658			59,125			—			640,810

Accumulated DD&A		(50,107	)		(1,062	)		(1,988	)		—			(53,157	)


Net property and equipment		481,920			48,596			57,137			—			587,653

Investment in subsidiaries		3,903			—			—			(3,903	)		—
Other long-term assets		57,429			(43,000	)		355			—			14,784


Total assets	$	585,150		$	6,567		$	78,599		$	(3,903	)	$	666,413


Current liabilities	$	69,586		$	237		$	15,750		$	—		$	85,573

Long-term liabilities
Long-term debt and derivative liabilities		214,315			—			28,000			—			242,315
Asset retirement obligation		2,896			24			—			—			2,920


Total long-term liabilities		217,211			24			28,000			—			245,235

Minority interest		15,215			—			—			—			15,215

Shareholders’ equity		283,138			6,306			34,849			(3,903	)		320,390


Total liabilities and shareholders’ equity	$	585,150		$	6,567		$	78,599		$	(3,903	)	$	666,413

20

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended September 30, 2005 and 2004
(Unaudited)

(10) Guarantee of Financial Information, Continued

Condensed Consolidated Balance Sheet
June 30, 2005


				Guarantor			Non-Guarantor			Adjustments/
	Issuer			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Current assets	$	23,602		$	2,235		$	1,197		$	—		$	27,034

Property and equipment:
Oil and gas		455,678			6,556			5,007						467,241
Drilling rigs and trucks		—			—			40,031			—			40,031
Other		10,347			—			65			—			10,412

Total property and equipment		466,025			6,556			45,103			—			517,684

Accumulated DD&A		(42,003	)		(1,032	)		(1,099	)		—			(44,134	)


Net property and equipment		424,022			5,524			44,004			—			473,550

Investment in subsidiaries		26,322			—			—			(26,322	)		—
Other long-term assets		12,359			—			40			—			12,399


Total assets	$	486,305		$	7,759		$	45,241		$	(26,322	)	$	512,983


Current liabilities	$	42,294		$	215		$	11,641		$	—		$	54,150

Long-term liabilities
Long-term debt and derivative liabilities		219,437			—			184			—			219,621
Asset retirement obligation		2,951			24			—			—			2,975


Total long-term liabilities		222,388			24			184			—			222,596

Minority interest		14,614			—			—			—			14,614

Shareholders’ equity		207,009			7,520			33,416			(26,322	)		221,623


Total liabilities and shareholders’ equity	$	486,305		$	7,759		$	45,241		$	(26,322	)	$	512,983

Condensed Consolidated Statement of Operations
Three Months Ended September 30, 2005


				Guarantor		Non-Guarantor		Adjustments/
	Issuer			Subsidiaries		Subsidiaries		Eliminations			Consolidated
Total revenue	$	28,192		$	676	$	5,925	$	(2,815	)	$	31,978

Operating expenses:
Oil and gas expenses		7,419			78		—		—			7,497
Depreciation and depletion		9,438			30		942		—			10,410
Exploration expense		850			—		1		—			851
Drilling and trucking operations		—			—		3,445		(1,330	)		2,115
Dry hole, abandonment and impaired		1,764			—		—		—			1,764
General and administrative		6,849			1		522		—			7,372


Total expenses		26,320			109		4,910		(1,330	)		30,009


Operating income (loss)		1,872			567		1,015		(1,485	)		1,969

Other income and expenses		(21,616	)		2		10		(531	)		(22,135	)
Income tax benefit		7,721			—		—		—			7,721
Gain on sale of discontinued operations		9,776			—		—		—			9,776
Discontinued operations		506			—		—		—			506


Net income (loss)	$	(1,741	)	$	569	$	1,025	$	(2,016	)	$	(2,163	)

21

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended September 30, 2005 and 2004
(Unaudited)

(10) Guarantee of Financial Information, Continued

Condensed Consolidated Statement of Operations
Three Months Ended September 30, 2004


				Guarantor		Non-Guarantor			Adjustments/
	Issuer			Subsidiaries		Subsidiaries			Eliminations			Consolidated
Total revenue	$	17,663		$	435	$	736		$	(618	)	$	18,217

Operating expenses:
Oil and gas expenses		3,838			105		—			—			3,943
Depreciation and depletion		4,725			9		143			—			4,877
Exploration expense		538			—		(2	)		—			536
Drilling and trucking operations		2			—		929			(495	)		436
Dry hole, abandonment and impaired		2,254			—		—			—			2,254
General and administrative		2,753			—		183			—			2,936


Total expenses		14,110			114		1,253			(495	)		14,982


Operating income (loss)		3,553			321		(517	)		(123	)		3,235

Other income and expenses		(847	)		1		(3	)		81			(768	)
Income tax benefit		—			—		—			—			—
Gain on sale of discontinued operations		—			—		—			—			—
Discontinued operations		1,477			—		—			—			1,477


Net income (loss)	$	4,184		$	322	$	(520	)	$	(42	)	$	3,944

Condensed Consolidated Statement of Cash Flows
Three Months Ended September 30, 2005


				Guarantor			Non-Guarantor
	Issuer			Subsidiaries			Subsidiaries			Consolidated
Operating activities	$	(7,396	)	$	(1,368	)	$	8,335		$	(429	)
Investing activities		(55,681	)		1,463			(39,504	)		(93,722	)
Financing activities		66,244			—			49,743			115,987


Net increase (decrease) in cash and cash equivalents		3,167			95			18,574			21,836

Cash at beginning of the period		1,999			196			46			2,241


Cash at the end of the period	$	5,166		$	291		$	18,620		$	24,077

Condensed Consolidated Statement of Cash Flows
Three Months Ended September 30, 2004


				Guarantor			Non-Guarantor
	Issuer			Subsidiaries			Subsidiaries			Consolidated
Operating activities	$	3,305		$	314		$	(286	)	$	3,333
Investing activities		4,698			(6	)		(1,312	)		3,380
Financing activities		(9,888	)		(222	)		1,544			(8,566	)


Net increase (decrease) in cash and cash equivalents		(1,885	)		86			(54	)		(1,853	)

Cash at beginning of the period		1,987			40			51			2,078


Cash at the end of the period	$	102		$	126		$	(3	)	$	225

22

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended September 30, 2005 and 2004
(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 September 30, 2005 and 2004:


							Inter-segment
	Oil and Gas			Drilling			Eliminations			Consolidated
Three Months Ended September 30, 2005
Revenues from external customers	$	28,868		$	3,110		$	—		$	31,978
Inter-segment revenues		—			2,815			(2,815	)		—

Total revenues	$	28,868		$	5,925		$	(2,815	)	$	31,978

Operating income (loss)	$	2,411		$	1,044		$	(1,486	)	$	1,969

Other income and (expense)¹		(21,612	)		9			(531	)		(22,135	)

Income (loss) from continuing operations, before tax	$	(19,201	)	$	1,052		$	(2,017	)	$	(20,166	)

Three Months Ended September 30, 2004
Revenues from external customers	$	18,098		$	119		$	—		$	18,217
Inter-segment revenues		—			617			(617	)		—

Total revenues	$	18,098		$	736		$	(617	)	$	18,217

Operating income (loss)	$	3,852		$	(494	)	$	(123	)	$	3,235

Other income and (expense)¹		(846	)		(3	)		81			(768	)

Income (loss) from continuing operations, before tax	$	3,006		$	(497	)	$	(42	)	$	2,467

Total assets — June 30, 2005	$	473,510		$	39,473		$	—		$	512,983
Total assets — September 30, 2005	$	592,820		$	73,593		$	—		$	666,413


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

(12) Subsequent event

On November 8, 2005, the Company entered into a merger agreement with Castle Energy Corporation (“Castle”) that has been approved by both Boards of Directors. The Company would acquire Castle, which holds 6,700,000 shares of the Company’s common stock, and would issue 8,500,000 shares of the Company’s common stock to the Castle’s shareholder’s, for a net issuance of 1,800,000 shares of common stock. Castle also holds $40 million in net cash and producing oil and gas properties located in Western Pennsylvania. The merger is subject to the approval of the Castle Shareholders.

23

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Forward Looking Statements

The statements contained in this report which are not historical fact are “forward looking statements” that involve various important risks, uncertainties and other factors which could cause our actual results to differ materially from those expressed in such forward looking statements reported in our quarterly report on Form 10-Q. These factors include, without limitation, the risks and factors included in the following text and those identified in the Company’s annual report on Form 10K for the year ended June 30, 2005.

Quarter Ended September 30, 2005 Accomplishments

	•		Successfully closed $100.0 million private placement to fund acquisition discussed below

	•		Acquired 145,000 net undeveloped acres in the Columbia River Basin in Washington and 6,314 gross acres that are currently being developed in the Piceance Basin in Colorado for $85.0 million.

	•		Successfully divested of the Deerlick Creek field in Tuscaloosa County, Alabama for net proceeds of $29.0 million resulting in a gain on sale of oil and gas properties of $9.8 million, net of tax.

	•		Successfully closed bank financing arrangement for DHS Drilling Company (“DHS”), a consolidated subsidiary of Delta, with Guggenheim Corporate Funding, LLC (“Guggenheim”) for $35.0 million.

The following discussion and analysis relates to items that have affected our results of operations for the three months ended September 30, 2005 and 2004. 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 September 30, 2005 Compared to Quarter Ended September 30, 2004

Net Income. Net income decreased $6.1 million to a loss of $2.2 million or $.05 per diluted common share for the three months ended September 30, 2005, from income of $3.9 million or $.09 per diluted common share for the same period a year earlier. Income from continuing operations declined $14.9 million from $2.5 million for the three months ended September 30, 2004 to a loss of $12.4 million for the three months ended September 30, 2005 due primarily to unrealized losses on derivative contracts that do not qualify for hedge accounting, higher expense related to DHS drilling operations, equity compensation expense, and interest expense. Income from discontinued operations and gain on sale of discontinued operations for the three months ended September 30, 2005 was $10.3 million, an increase of $8.8 million over the year earlier period due to the $9.8 million gain on the sale of the Company’s Deerlick Creek Field.

Revenue. During the three months ended September 30, 2005, oil and natural gas revenue from continuing operations increased 74% to $31.6 million, as compared to $18.1 million for the same period a year earlier. The increase was the result of an average onshore gas price received during the three months ended September 30, 2005 of $8.25 per Mcf compared to $5.45 per Mcf for the same period a year earlier, an increase in average onshore oil price received during the three months ended September 30, 2005 of $60.39 per Bbl compared to $42.27 per Bbl for the same period a year earlier, an increase in offshore oil price received of $49.93 per Bbl during the three months ended September 30, 2005 compared to $30.90 for the same period a year earlier, and a 20% increase in average daily production over the prior year.

24

The net realized losses from hedging activities were $2.7 million and zero for the three months ended September 30, 2005 and 2004, respectively. These losses are recorded as a decrease in revenues.

Drilling Revenue. In March 2004, we acquired a 50% interest in both the Big Dog Drilling Company and Shark Trucking Company to enable us to have access to drilling rigs and rig transportation facilities on a priority basis. On March 31, 2005, we purchased the remaining interest in Big Dog Drilling Co., LLC (“Big Dog”) for our interest in Shark Trucking, LLC (“Shark”), one of Big Dog’s rigs and related equipment and 100,000 shares of our stock valued at $1.4 million. On April 15, 2005, we conveyed our interest in Big Dog to DHS Drilling Company in exchange for 4,500,000 shares of DHS Drilling Company’s restricted stock, or 90% of its issued and outstanding shares. The remaining 10% was then owned by two officers of DHS who will earn their interest over five years of employment. Effective May 1, 2005, DHS sold 45% of its restricted stock in the Company to Chesapeake Energy, Inc. for $15.0 million. Delta currently owns 49.5% of DHS, controls the board of directors and has access to all drilling rigs for Company use and operations.

Drilling revenues for the three months ended September 30, 2005 increased to $3.1 million compared to $119,000 for the same period a year earlier. 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 September 30, 2005 and 2004 are as follows:


	Three Months Ended September 30,
	2005					2004
	Onshore			Offshore		Onshore		Offshore
Production:
Oil (MBbl)		214			36		222		35
Gas (MMcf)		2,041			—		1,401		—
Production — Discontinued Operations:
Oil (MBbl)		—			—		2		—
Gas (MMcf)		155			—		378		—
Average Price — Continuing Operations:
Oil (per barrel)	$	60.39		$	49.93	$	42.27	$	30.90
Gas (per Mcf)	$	8.25		$	—	$	5.45	$	—

Costs per Mcfe
Hedge effect	$	(1.83	)	$	—	$	—	$	—
Lease operating expense	$	1.05		$	6.05	$	.64	$	3.75
Production taxes	$	.71		$	.21	$	.47	$	.05
Transportation costs	$	.14		$	—	$	.04	$	—
Depletion expense	$	2.70		$	.85	$	1.62	$	.77

25

Lease Operating Expense. Lease operating expenses for the three months ended September 30, 2005 were $4.8 million compared to $2.5 million for the same period a year earlier. Lease operating expense from continuing operations for onshore properties for the three months ended September 30, 2005 was $1.05 per Mcfe as compared to $.64 per Mcfe for the same period a year earlier. Lease operating expense from continuing operations for offshore properties was $6.05 per Mcfe for the three months ended September 30, 2005 and $3.75 per Mcfe for the same period a year earlier. This increase in lease operating expenses can be attributed to the percentage of wells owned in the Gulf Coast region compared to our other regions. Our Gulf Coast region wells, primarily in our Newton field, cost more to produce. 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 compared to a year earlier.

Depreciation, Depletion and Amortization — oil and gas. Depreciation, depletion and amortization expense increased 100% to $9.5 million for the three months ended September 30 2005, as compared to $4.7 million for the same period a year earlier. Our onshore depletion rate increased to $2.70 per Mcfe for the three months ended September 30, 2005 from $1.62 per Mcfe for the same period a year earlier. 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. As additional zones are completed up-hole, the depletion rate will decrease. In addition, our depletion rate increase has been significantly impacted by disappointing drilling results in our South Angleton field. Based on these results, our engineers decreased the ultimate recovery for this field which increased our depletion rate. The high commodity prices increased the South Angleton field’s ultimate recoverable value at September 30, 2005, so no impairment was required. If commodity prices fall and drilling results do not improve, this field may be at risk for future impairments.

Depreciation and Amortization — drilling. Depreciation and amortization expense — drilling increased to $942,000 for the three months ended September 30, 2005, as compared to $143,000 for the same period a year earlier. This increase can be attributed to the increase in utilization rates from additional rigs.

Dry Hole Costs. We incurred dry hole costs of approximately $1.8 million for the three months ended September 30, 2005 compared to $2.3 million 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.

Exploration Expense. Exploration expense consists of geological and geophysical costs and lease rentals. Our exploration costs for the three months ended September 30, 2005 were $851,000 compared to $536,000 for the same period a year earlier. Current year activities include newly acquired seismic information in Polk County, Texas and a 60 square mile shoot in Newton County, Texas.

Drilling Expenses. Drilling expenses increased to $2.1 million for the three months ended September 30, 2005 compared to $436,000 for the same period a year earlier. This increase can be attributed to the increase in utilization rates from additional rigs.

Professional Fees. Professional fees include corporate legal costs, accounting fees, shareholder relations consultants and legal fees for representation in negotiations and discussions with various state and federal governmental agencies relating to our undeveloped offshore California leases. Our professional fees increased 112% to $734,000 for the three months ended September 30, 2005, as compared to $346,000 for the same period a year earlier. The increase in professional fees can be attributed largely to compliance with the Sarbanes-Oxley Act and general increases in corporate activity.

26

General and Administrative Expense. General and administrative expense increased 156% to $6.6 million for the three months ended September 30, 2005, as compared to $2.6 million for the same period a year earlier. The increase in general and administrative expenses is primarily attributed to the adoption of SFAS No. 123R, the 77% increase in technical and administrative staff and related personnel costs, the expansion of our office facility and an increase in travel primarily relating to investor relations.

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 compensation expense related to stock options of approximately $1.1 million relating to employee provided services during the quarter ended September 30, 2005. In addition, we issued restricted stock to officers, directors and employees as additional compensation. Restricted stock grants are recorded at the closing price on the date issued and expensed as they vest, usually over a three year period. We also recorded $456,000 of restricted stock compensation expense for the three months ended September 30, 2005.

Unrealized Losses 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 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. As a result, we recognized an $18.8 million non-cash loss in our statement of operations. 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 September 30, 2004 and from DHS in the three months ended September 30, 2005.

Interest and Financing Costs. Interest and financing costs increased 355% to $4.0 million for the three months ended September 30, 2005, as compared to $883,000 for the same period a year earlier. The increase is primarily related to the $150.0 million senior note offering completed in March 2005 and 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 prospect in Washington completed in April and September 2005.

Discontinued Operations. On September 2, 2005, we completed the sale of our Deerlick Creek field in Tuscaloosa County, Alabama for $30.0 million with an effective date of July 1, 2005. We recorded a gain on sale of oil and gas properties of $9.8 million on net proceeds of $29.0 million after normal closing adjustments. The net after tax profit earned on these assets during the quarter ended September 30, 2005 was $506,000.

27

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 permitted, and through cash provided by operating activities and sale of oil and gas properties. On March 15, 2005, we issued $150.0 million in 7% senior unsecured notes, for aggregate net proceeds of $149.3 million. At the same time, we also increased our credit facility to $200.0 million with an initial borrowing base of $75.0 million, $19.0 million of which is not drawn at September 30, 2005. On September 27, 2005, we completed a private placement of 5,405,418 shares of our common stock to twenty-seven institutional investors at a price of $18.50 per share in cash for gross proceeds of $100.0 million and net proceeds of $95.0 million. The majority of the proceeds were immediately used to acquire additional oil and gas properties. On September 2, 2005 we sold our non-core Deerlick Field located in Tuscaloosa, Alabama for $29.0 million, subject to certain normal closing adjustments and on September 30, 2005, DHS completed a five year financing arrangement for $35.0 million.

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

We continue to examine alternative sources of long-term capital, including bank borrowings, the issuance of debt instruments, the sale of 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 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. 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 September 30, 2005, we completed the following transactions:

On September 29, 2005 we acquired an undivided 50% working interest in approximately 145,000 net undeveloped acres in the Columbia River Basin in Washington, and purchased an interest in undeveloped acreage in the Piceance Basin in Colorado from Savant Resources, LLC (“Savant”) for an aggregate purchase price of $85.0 million in cash. James Wallace, one of our directors, owns approximately a 1.7% interest in Savant, and also serves as a director of Savant. The majority of the acquired acreage in the Columbia River Basin consolidates our current leasehold position. We now own a 100% working interest in approximately 385,000 net acres. This acquisition included a small portion of acreage that is subject to an agreement with EnCana Oil & Gas (USA) Inc., whereby we have the right to convert an overriding royalty interest to a working interest at project payout. In the Piceance Basin, we acquired Savant’s interest in an entity that owns a 25% interest in approximately 6,314 gross acres that is currently being developed. This acquisition was funded through the issuance of securities discussed below.

28

On September 27, 2005, we completed a private placement of 5,405,418 shares of our common stock to twenty-seven institutional investors at a price of $18.50 per share in cash for gross proceeds of $100.0 million and net proceeds of $95.0 million.

Historical Cashflow

Our cashflow from operating activities decreased from $3.3 million for three months ended September 30, 2004 to cash used in operating activities of $429,000, primarily as a result of a 77% net reduction in working capital. Our net cash used in investing activities increased to $93.7 million for the three months ended September 30, 2005 compared to net cash provided by investing activities of $3.4 million for the same period a year earlier. The increase in cash used for investing activity can be attributed to the 607% increase in capital expenditures and drilling programs in both the Rocky Mountain and Gulf Coast regions along with a $14.0 million investment in drilling rigs. Cash provided from financing was $116.0 million for the three months ended September 30, 2005 compared with cash used in financing activities of $8.6 million for the same period the prior year. During the three months ended September 30, 2005, we financed our operations with the issuance of $95.0 million in newly issued equity and $21.0 million in net debt additions.

Capital and Exploration Expenditures and Financing

Our capital and exploration expenditures and sources of financing for the three months ended September 30, 2005 and 2004 are as follows:


	2005			2004
	(In thousands)
CAPITAL AND EXPLORATION EXPENDITURES:
Acquisitions:
Savant acquisition	$	85,810			—
Washington County South and North Tongue		828			9,900
Karnes County, Texas		—			5,000
Other		2,035

Other development costs		34,823			10,157
Drilling and trucking companies		14,023			1,145
Exploration costs		851			536

	$	138,370		$	26,738


FUNDING SOURCES:
Cash flow provided by (used in) operating activities	$	(429	)	$	3,333
Stock issued for cash upon exercised options		481			289
Stock issued for cash, net		94,999			—
Net long-term borrowings		20,507			(8,855	)
Proceeds from sale of oil and gas properties		28,981			18,721
Other		1,330			41

	$	145,869		$	13,529

We anticipate our drilling capital and exploration expenditures to range between $35.0 and $40.0 million for the three months ending December 31, 2005. However, the timing of most of our capital expenditures is discretionary.

29

Sale of Oil and Gas Properties — Discontinued Operations

On September 2, 2005, the Company completed the sale of its Deerlick Creek field in Tuscaloosa County, Alabama for $30.0 million with an effective date of July 1, 2005. The Company recorded a gain on sale of oil and gas properties of $9.8 million on net proceeds of $29.0 million after normal closing adjustments. The net profit earned on these assets during the quarter ended September 30, 2005 of $506,000 has been shown in discontinued operations.

Contractual and Long Term Debt Obligations


	Payments Due by Period
	Less than						After
Contractual Obligations at September 30, 2005	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		46,784		99,284
Credit facility		—		—		56,000		—		56,000
DHS Note		7,000		14,000		14,000		—		35,000
Derivative liability		23,488		8,925		—		—		32,413
Abandonment retirement obligation		466		340		478		6,049		7,333
Operating leases		1,691		3,265		2,727		3,373		11,056
Other debt obligations		72		99		—		—		171

Total contractual cash obligations	$	43,217	$	47,629	$	94,205	$	206,206	$	391,257

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.

Credit Facility

At September 30, 2005, the $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. Currently, 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 $23.4 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 covenants only include subsidiaries which we own 100%. At September 30, 2005, we were in compliance with our quarterly debt covenants and restrictions.

30

Subsequent determinations of the borrowing base will be made by the Banks at least semi-annually on April 1 and October 1 of each year or as special re-determinations. If, as a result of any reduction in the amount of our borrowing base, the total amount of the outstanding debt were to exceed the amount of the borrowing base in effect, then, within 30 days after we are notified of the borrowing base deficiency, we would be required (1) to make a mandatory payment of principal to reduce our outstanding indebtedness so that it would not exceed our borrowing base, (2) to eliminate the deficiency by making three equal monthly principal payments, (3) within 90 days to provide additional collateral for consideration to eliminate the deficiency or (4) to eliminate the deficiency through a combination of (1) through (3). If for any reason we were unable to pay the full amount of the mandatory prepayment within the requisite 30-day period, we would be in default of our obligations under our credit facility.

The 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.

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. The note bears interest at the Prime Rate plus 3.0%, or 9.75% at September 30, 2005. The note contains quarterly financial covenants applied to DHS on a stand-alone basis including a maximum leverage ratio of 2.5 to 1 (declining to 2.0 to 1.0 at June 30, 2006), a minimum current ratio of 1.25 to 1.0 and a minimum interest coverage ratio of 2.50 to 1, each as defined in the agreement. At September 30, 2005, DHS was in compliance with its covenants on the note.

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 $772,000 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.

31

Derivative instruments represent the net estimated unrealized losses for our oil and gas hedges at September 30, 2005. 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 1 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 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 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.

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

Reserve Estimates

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

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 September 30, 2005 and 2004.

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 future 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.

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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. 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 management (CPRM) activities.

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.

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.

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Recently Issued Accounting Standards and Pronouncements

Statement of Financial Accounting Standards No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies”, specifies that drilling costs for completed exploratory wells should be expensed if the related reserves cannot be classified as proved within one year unless certain criteria are met. In April 2005, the Financial Accounting Standards Board (“FASB”) issued Staff Position 19-1, (“FSP 19-1”) “Accounting for Suspended Well Costs”. FSP 19-1 provides guidance for evaluating whether sufficient progress is being made to determine whether reserves can be classified as proved. FSP 19-1 is effective for all reporting periods beginning after April 4, 2005, and accordingly, we adopted FSP 19-1 on July 1, 2005. The following table reflects the net changes in capitalized exploratory well costs for three months ended September 30, 2005:


	2005
	(In thousands)
Balance at beginning of period, July 1,	$	530
Additions to capitalized exploratory well costs pending the determination of proved reserves¹		—
Reclassified to proved oil and gas properties based on the determination of proved reserves		—
Capitalized exploratory well costs charged to dry hole expense		(530	)

Balance at end of period, September 30,	$	—


¹		The final FSP directs that costs suspended and expensed in the same period not be included in this analysis.

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 following table summarizes our current hedge positions:


								Net Fair Value
				Price Floor /				Asset (Liability) at
Commodity	Volume			Price Ceiling		Term	Index	Sept. 30, 2005
								(In thousands)
Contracts that qualify for hedge accounting
Crude oil		6,000	Bbls/month	$	35.00 / $49.75	Apr ’05 - Dec ’05	NYMEX-WTI	$	(298	)
Crude oil		40,000	Bbls/month	$	40.00 / $50.34	July ’05 - June ’06	NYMEX-WTI		(6,093	)
Crude oil		10,000	Bbls/month	$	45.00 / $56.90	July ’05 - June ’06	NYMEX-WTI		(1,007	)
Crude oil		25,000	Bbls/month	$	35.00 / $61.80	July ’06 - June ’07	NYMEX-WTI		(2,933	)
Contracts that do not qualify for hedge accounting
Natural gas		3,000	MMBtu/day	$	5.00 / $7.85	Apr ’05 - Oct ’05	NYMEX-H HUB		(447	)
Natural gas		10,000	MMBtu/day	$	5.00 / $9.60	July ’05 - June ’06	NYMEX-H HUB		(9,832	)
Natural gas		3,000	MMBtu/day	$	6.00 / $9.35	July ’05 - June ’06	NYMEX-H HUB		(3,116	)
Natural gas		13,000	MMBtu/day	$	5.00 / $10.20	July ’06 - June ’07	NYMEX-H HUB		(8,230	)

									(31,956	)

The net fair value of our derivative instruments obligation was $32.0 million at September 30, 2005 and $21.6 million on November 1, 2005.

A $1.00 change in oil and gas received for our production would have an impact of approximately $1.6 million on our oil and gas revenue for the three months ended September 30, 2005.

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Interest Rate Risk

We were subject to interest rate risk from our credit facility of $56.0 million which had variable rate debt obligations at September 30, 2005. The annual effect of a ten percent change in interest rates would be approximately $780,000. The interest rate on these variable debt obligations approximates current market rates as of September 30, 2005.

Item 4. Controls and Procedures

As of September 30, 2005, under the supervision and with the participation of the Company’s Chief Executive Officer and the Chief Financial Officer, management has evaluated the effectiveness of the design and operation of the Company’s disclosure controls and procedures. Based on that evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of September 30, 2005. 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 affect, the Company’s internal control over financial reporting.

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PART II — OTHER INFORMATION

Item 1. Legal Proceedings.

On January 9, 2002, we and several other plaintiffs filed a lawsuit 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 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. Our claim for lease bonuses and rentals paid by us and our predecessors is in excess of $152 million. 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, and to pay expenses of litigation and to fulfill certain pre-existing contractual commitments to third parties. Although the computation of the various amounts that we would be required to pay to landowners and other owners of royalties and similar interests is dependent upon facts and circumstances that are not yet known, it is possible that they may be as much as twenty percent of any proceeds that we might ultimately obtain.

The Federal Government has not yet filed an answer in this proceeding pending its motion to dismiss the lawsuit, which motion has been heard but has not yet been ruled upon by the court. We have filed a motion for partial summary judgment which has been heard but has not yet been ruled upon by the court.

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

During the quarter ended September 30, 2005, we issued securities that were not registered under the Securities Act of 1933 and have not been reported in report on Form 8-K as follows:

On July 15, 2005, we issued a total of 50,000 shares of our common stock to Joy S. Bell in exchange for certain oil and gas interests that were owned by her. All of these shares have been subsequently registered for re-sale by her under the Securities Act of 1933, as amended.

We reasonably believe that the above investor was an “Accredited Investor” as such term is defined in Rule 501 of Regulation D at the time each of the issuances occurred. The investor acquired the shares for investment purposes. A restrictive legend was placed on the certificate issued to the investor, and stop transfer orders were given to our transfer agent. A Forms D reporting the offering was filed with the Securities and Exchange Commission.

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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.

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NYMEX. New York Mercantile Exchange.

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 President and Chief Executive Officer

	By:	/s/ Kevin K. Nanke

		Kevin K. Nanke, Treasurer and Chief Financial Officer

Date: November 9, 2005

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EXHIBIT INDEX


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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