DELTA PETROLEUM CORP/CO - 10-Q Quarterly Report

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended December 31, 2004

¨	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 x No ¨

40,837,000 shares of common stock $.01 par value were outstanding as of February 9, 2005.

INDEX

PART I FINANCIAL INFORMATION


		Page No.

Item 1.	Consolidated Financial Statements

	Consolidated Balance Sheets – December 31, 2004 and June 30, 2004 (unaudited)	1

	Consolidated Statements of Operations – Three Months Ended December 31, 2004 and 2003 (unaudited)	2

	Consolidated Statements of Operations – Six Months Ended December 31, 2004 and 2003 (unaudited)	3

	Consolidated Statement of Stockholders’ Equity and Comprehensive Income Six Months Ended December 31, 2004 (unaudited)	4

	Consolidated Statements of Cash Flows – Six Months Ended December 31, 2004 and 2003 (unaudited)	5

	Notes to Consolidated Financial Statements (unaudited)	6

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	20

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	29

Item 4.	Controls and Procedures	30

PART II OTHER INFORMATION

Item 1.	Legal Proceedings	31

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	31

Item 3.	Defaults upon Senior Securities	32

Item 4.	Submission of Matters to a Vote of Security Holders	32

Item 5.	Other Information	32

Item 6.	Exhibits	32

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

DELTA PETROLEUM CORPORATION

AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


	December 31, 2004			June 30, 2004
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	1,386		$	2,078
Marketable securities available for sale		1,255			912
Trade accounts receivable, net		9,350			9,092
Prepaid assets		1,285			1,136
Inventory		4,631			1,350
Other current assets		3,226			385

Total current assets		21,133			14,953


Property and Equipment:
Oil and gas properties, successful efforts method of accounting
Undeveloped		144,217			136,467
Developed		179,045			136,425
Drilling and trucking equipment		8,148			3,965
Other		2,100			1,147

Total property and equipment		333,510			278,004
Less accumulated depreciation and depletion		(30,148	)		(21,665	)

Net property and equipment		303,362			256,339


Long term assets:
Investment in LNG project		1,022			1,022
Deferred financing costs		441			131
Partnership net assets		142			259

Total long term assets		1,605			1,412

	$	326,100		$	272,704


LIABILITIES AND STOCKHOLDERS’ EQUITY

Current Liabilities:
Current portion of long-term debt	$	128		$	109
Accounts payable		21,903			12,326
Other accrued liabilities		1,588			1,855

Total current liabilities		23,619			14,290


Long-term Liabilities:
Bank debt, net		83,000			69,375
Asset retirement obligation		2,689			2,542
Other debt, net		236			255

Total long-term liabilities		85,925			72,172


Minority Interest		273			245


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 40,686,000 shares at December 31, 2004 and 38,447,000 at June 30, 2004		407			384
Additional paid-in capital		228,804			207,811
Accumulated other comprehensive income		859			342
Accumulated deficit		(13,786	)		(22,540	)

Total stockholders’ equity		216,284			185,997


Commitments	$	326,100		$	272,704

See accompanying notes to consolidated financial statements.

DELTA PETROLEUM CORPORATION

AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)


	Three Months Ended December 31,
	2004			2003
	(In thousands except per share amounts)
Revenue:
Oil and gas sales	$	20,441		$	7,714
Drilling and trucking		181			—
Realized loss on derivative instruments, net		(93	)		(68	)

Total revenue		20,529			7,646

Operating expenses:
Lease operating expense		4,920			2,242
Depreciation, depletion and amortization		3,678			2,240
Exploration expense		747			138
Dry hole costs		419			177
Drilling and trucking operations		640			—
Professional fees		501			308
General and administrative		3,513			1,555

Total operating expenses		14,418			6,660


Income from continuing operations		6,111			986


Other income and (expense):
Other income (expense)		(183	)		15
Minority interest		234			—
Interest and financing costs		(1,353	)		(576	)

Total other expense		(1,302	)		(561	)


Income before discontinued operations		4,809			425

Discontinued operations:
Income (loss) from operations of properties sold, net		—			255
Loss on sale of properties		—			(28	)

Net income	$	4,809		$	652


Basic income per common share:
Income before discontinued operations	$	0.12		$	0.02
Discontinued operation		—			0.01

Net income	$	0.12		$	0.03


Diluted income per common share:
Income before discontinued operations	$	0.11		$	0.02
Discontinued operation		—			0.01

Net income	$	0.11		$	0.03

See accompanying notes to consolidated financial statements.

DELTA PETROLEUM CORPORATION

AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)


	Six Months Ended December 31,
	2004			2003
	(In thousands except per share amounts)
Revenue:

Oil and gas sales	$	39,657		$	14,781
Drilling and trucking		300			—
Realized loss on derivative instruments, net		(93	)		(380	)


Total revenue		39,864			14,401


Operating expenses:
Lease operating expense		9,129			4,312
Depreciation, depletion and amortization		8,659			3,792
Exploration expense		1,283			268
Dry hole costs		2,673			177
Drilling and trucking operations		1,074			—
Professional fees		847			612
General and administrative		6,104			2,721


Total operating expenses		29,769			11,882


Income from continuing operations		10,095			2,519


Other income and (expense):
Other income (expense)		(149	)		35
Minority interest		315			—
Interest and financing costs		(2,236	)		(1,085	)


Total other expense		(2,070	)		(1,050	)


Income before discontinued operations		8,025			1,469

Discontinued operations:
Income (loss) from operations of properties sold, net		729			575
Loss on sale of properties		—			(28	)


Net income	$	8,754		$	2,016


Basic income per common share:
Income before discontinued operations	$	0.20		$	0.06
Discontinued operation		0.02			0.03

Net income	$	0.22		$	0.09


Diluted income per common share:
Income before discontinued operations	$	0.19		$	0.06
Discontinued operation		0.02			0.02

Net income	$	0.21		$	0.08

See accompanying notes to consolidated financial statements.

DELTA PETROLEUM CORPORATION

AND SUBSIDIARIES

Consolidated Statement of Stockholders’ Equity and Comprehensive Income

(Unaudited)


	Common stock			Additional paid-in capital			Accumulated other comprehensive income/(loss)		Comprehensive income (loss)		Accumulated deficit			Total
	Shares	Amount		Additional paid-in capital			Accumulated other comprehensive income/(loss)		Comprehensive income (loss)		Accumulated deficit			Total
	(In thousands)
Balance, June 30, 2004	38,447	$	384	$	207,811		$	342			$	(22,540	)	$	185,997

Comprehensive income:
Net income	—		—		—			—		8,754		8,754			8,754
Other comprehensive gain, net of tax
Unrealized gain on equity securities, net	—		—		—			344		344					344
Change in fair value of derivative hedging instruments, net								173		173					173

Comprehensive income									$	9,271

Shares issued for oil and gas properties	1,435		15		20,141			—				—			20,156
Shares issued for drilling equipment	31		—		461			—				—			461
Shares issued for cash upon exercise of options	773		8		467			—				—			475
Stock option expense	—		—		(76	)		—				—			(76	)


Balance, December 31, 2004	40,686	$	407	$	228,804		$	859				(13,786	)	$	216,284

See accompanying notes to consolidated financial statements.

DELTA PETROLEUM CORPORATION

AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Six Months Ended December 31,
	2004			2003
	(In thousands)
Cash flows operations activities:
Net income	$	8,754		$	2,016
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and depletion		8,520			3,916
Depreciation and depletion – discontinued operations		208			111
Accretion of abandonment obligation		139			32
Stock compensation expense		(76	)		108
Amortization of financing costs		443			266
Loss on sale of oil and gas properties		—			28
Loss from minority’s interest investment		(315	)		—
Net changes in operating assets and operating liabilities:
Increase in trade accounts receivable		(84	)		(414	)
Increase in prepaid assets		(3,149	)		(674	)
Increase in inventory		(3,281	)		—
Decrease in other current assets		25			—
Increase in accounts payable trade		8,132			1,298
Increase in other accrued liabilities		(267	)		(541	)


Net cash provided by operating activities	$	19,049		$	6,146


Cash flows from investing activities:
Additions to property and equipment, net		(52,058	)		(14,690	)
Proceeds from sales of oil and gas properties		18,271			3,422
Payment on investment transaction		—			(307	)
Increase in long term assets		117			47


Net cash used in investing activities		(33,220	)		(11,528	)


Cash flows from financing activities:
Stock issued for cash upon exercise of options		475			1,004
Proceeds from borrowings		88,060			13,704
Payment of financing fees		(620	)		(205	)
Repayment of borrowings		(74,436	)		(10,681	)


Net cash provided by financing activities		13,479			3,822


Net decrease in cash and cash equivalents		(692	)		(1,560	)


Cash at beginning of period		2,078			2,271


Cash at end of period	$	1,386		$	711


Supplemental cash flow information –
Common stock issued for the acquisition of oil and gas properties	$	20,156		$	9,467


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


Cash paid for interest and financing costs	$	647		$	1,111

See accompanying notes to consolidated financial statements.

DELTA PETROLEUM CORPORATION

AND SUBSIDIARIES

Notes to Consolidated Financial Statements

Six Months Ended December 31, 2004 and 2003

(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. 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, 2004, previously filed with the Securities and Exchange Commission.

(2)

Nature of Organization

Delta Petroleum Corporation (“Delta”) was organized December 21, 1984 and is principally engaged in acquiring, exploring, developing and producing oil and gas properties. 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.

At December 31, 2004 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.

The Company’s results of operations are substantially dependent on the price received for its crude oil and natural gas products and the results of our exploration and development activities. Prices for these products are subject to fluctuations in response to changes in supply, market uncertainty and political instability.

DELTA PETROLEUM CORPORATION

AND SUBSIDIARIES

Notes to Consolidated Financial Statements

Six Months Ended December 31, 2004 and 2003

(Unaudited)

(3)

Summary of Significant Accounting Policies

Principles of Consolidation and Basis of Presentation

The consolidated financial statements include the accounts of Delta, Amber and Piper (collectively, the Company). All intercompany 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 2004 presentation.

In March 2004, the Company acquired a 50% interest in Big Dog Drilling, LLC (“Big Dog”) and a 50% interest in Shark Trucking Company, LLC (“Shark”). Delta controls both entities through a drilling contract agreement which entitles Delta first priority on the use of all assets. The Company has consolidated the activities of both BDDC and STC in fiscal 2005.

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 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.


	Cost		Accumulated Unrealized Gain (Loss)			Estimated Market Value
	(In thousands)
December 31, 2004
Bion Environmental Technologies, Inc.	$	152	$	(139	)	$	13
Tipperary Oil & Gas Company		418		824			1,242

	$	570	$	685		$	1,255

June 30, 2004
Bion Environmental Technologies, Inc.	$	152	$	(138	)	$	14
Tipperary Oil & Gas Company		418		480			898

	$	570	$	342		$	912

DELTA PETROLEUM CORPORATION

AND SUBSIDIARIES

Notes to Consolidated Financial Statements

Six Months Ended December 31, 2004 and 2003

(Unaudited)

(3)

Summary of Significant Accounting Policies, Continued

Inventories

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

Revenue Recognition

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 December 31, 2004 and 2003, the Company’s aggregate natural gas and crude oil imbalances were not material to its consolidated financial statements.

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.

Other property and equipment are recorded at cost or estimated fair value upon acquisition and depreciated using the straight-line method over their estimated useful lives.

DELTA PETROLEUM CORPORATION

AND SUBSIDIARIES

Notes to Consolidated Financial Statements

Six Months Ended December 31, 2004 and 2003

(Unaudited)

(3)

Summary of Significant Accounting Policies, Continued

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. Partnership net assets represent the Company’s share of net working capital in such entities.

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.

Additionally, the Company assesses developed properties on an individual field basis for impairment at least quarterly or when the oil and gas reserve estimates reflect significant negative revisions. 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 certain producing properties for the six months ended December 31, 2004 and 2003.

For undeveloped properties, the need for an impairment reserve 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 certain undeveloped properties for the three and six months ended December 31, 2004 and 2003.

DELTA PETROLEUM CORPORATION

AND SUBSIDIARIES

Notes to Consolidated Financial Statements

Six Months Ended December 31, 2004 and 2003

(Unaudited)

(3)

Summary of Significant Accounting Policies, Continued

Asset Retirement Obligations

In July 2001, the Financial Accounting Standards Board approved for issuance 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 was 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 of $20,000, net of tax effects, 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. 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 change in the Company’s asset retirement obligations from July 1, 2004 to December 31, 2004 (amounts in thousands).


Asset retirement obligation – July 1, 2004	$	2,647
Accretion expense		139
Change in estimate		(110	)
Obligations acquired		601
Obligations settled		—
Obligations on sold properties		(362	)

Asset retirement obligation – December 31, 2004		2,915
Less: Current asset retirement obligation		(226	)

Long-term asset retirement obligation	$	2,689

Comprehensive Income

Comprehensive income includes all changes in equity during a period. The components of comprehensive income for the six months ended December 31, 2004 and 2003 are as follows:


	Six Months Ended December 31,
	2004		2003
	(In thousands)
Net income	$	8,754	$	2,016
Other comprehensive income
Change in fair value of derivative hedging instruments		344		325
Unrealized gain (loss) on marketable securities	$	173	$	106

		517		431

Comprehensive income	$	9,271	$	2,447

DELTA PETROLEUM CORPORATION

AND SUBSIDIARIES

Notes to Consolidated Financial Statements

Six Months Ended December 31, 2004 and 2003

(Unaudited)

(3)

Summary of Significant Accounting Policies, Continued

Derivative Financial Instruments

The Company periodically enters into commodity derivative contracts and fixed-price physical contracts to manage its exposure to oil and natural gas price volatility. The Company primarily utilizes future contracts, swaps or options which are generally placed with major financial institutions or with counterparties of high credit quality that the Company believes are minimal credit risks. The oil and natural gas reference prices of these commodity derivatives contracts are based upon crude oil and natural gas futures which have a high degree of historical correlation with actual prices received by the Company.

In June 1998, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities.” SFAS 133 established accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its fair value. It also requires that changes in the derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument be reported as a component of Other Comprehensive Income and be reclassified into earnings in the same period or periods during which the hedged forecasted transaction affects earnings.

The following table summarizes our current hedge positions:


Commodity	Volume	Price Floor/Price Ceiling	Term
Crude oil	40,000 Bbls/month	$35.00 / $50.80	Jan ‘05 – June ‘05
Crude oil	6,000 Bbls/month	$35.00 / $49.75	April ‘05 – Dec ‘05
Crude oil	40,000 Bbls/month	$40.00 / $50.34	July ‘05 – June ‘06
Natural gas	3,000 MMBtu/day	$5.00 / $7.85	Apr ‘05 – Oct ‘05
Natural gas	10,000 MMBtu/day	$5.00 / $9.25	Jan. ‘05 – June ‘05
Natural gas	10,000 MMBtu	$5.00 / $9.60	July ‘05 – June ‘06

The fair value of the derivatives at December 31, 2004 was an asset to the Company of $173,000.

The realized net losses from hedging activities were $93,000 for the three and six months ended December 31, 2004 and $68,000 and $380,000 for the three and six month period ended December 31, 2003.

DELTA PETROLEUM CORPORATION

AND SUBSIDIARIES

Notes to Consolidated Financial Statements

Six Months Ended December 31, 2004 and 2003

(Unaudited)

(3)

Summary of Significant Accounting Policies, Continued

Stock Option Plans

The Company accounts 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 is recorded on the date of grant only if the current market price of the underlying stock exceeds the exercise price. In December, 2002 the FASB issued SFAS No. 148, “Accounting for Stock-based Compensation-Transition and Disclosure.” SFAS 148 amended FASB Statement No. 123, “Accounting for Stock-Based Compensation” 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 amends the disclosure requirements of Statement 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 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 at the current time. Accordingly, no compensation cost is recognized for options granted to employees at a price equal to or greater than the fair market value of the common stock.

However, in December, 2004, SFAS 123 (Revised 2004), “Share Based Payment” was issued, which will require the Company 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. While the Company has not made a determination of the impact of adoption on its financial statements, it is expected that the impact will be based on the grant-date fair value of the awards calculated under SFAS 123 as in the following disclosures.

DELTA PETROLEUM CORPORATION

AND SUBSIDIARIES

Notes to Consolidated Financial Statements

Six Months Ended December 31, 2004 and 2003

(Unaudited)

(3)

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, the Company’s net income (loss) for the three and six months ended December 31, 2004 and 2003 would have been as follows:


	Three Months Ended December 31,					Six Months Ended December 31,
	2004			2003		2004			2003
	(In thousands)					(In thousands)
Net income	$	4,809		$	652	$	8,754		$	2,016
FAS 123 compensation effect		(297	)¹		—		(297	)¹		(4,316	)²

Net income (loss) after FAS 123 compensation effect	$	4,512		$	652	$	8,457		$	(2,300	)

Income (loss) per common share:	$	.11		$	.03	$	.21		$	(.10	)

During the quarter ended December 31, 2004, the Company granted 420,000 options to officers and 84,000 options to directors to purchase 504,000 shares of its common stock at an average price of $15.34 per share, which was the market price on the date of the grant. The officer’s options vest over a four year period and the director’s options vest over one year. The fair market value of each option granted was $10.07 and was calculated using a risk free rate of 4.60%, volatility factors of the expected market price of the Company’s common stock of 48.76% and an average expected life of 8.0 years. Also during the quarter ended December 31, 2004, the Company granted 318,000 options to employees to purchase 318,000 shares of its common stock at an average price of $15.29 per share. Certain options were granted below market. For options granted below market, the Company recorded an expense for the difference between the option price and the grant price. The employee options vest over a four year period. The average fair market value of each option granted was $7.10 and was calculated using a risk free rate of 4.60%, volatility factors of the expected market price of the Company’s common stock of 48.76% and an average expected life of 3.2 years. The FAS 123 compensation effect is calculated based on the options vesting period and includes additional grants from other periods.

During the quarter ended September 30, 2003 the Company granted to its officers options to purchase 1,250,000 shares of its common stock at a price of $5.29 per share, which was the market price on the date of the grant. All of these options vested immediately upon issuance. The fair market value of each option granted was $3.45 and was calculated using a risk free rate of 4.34%, volatility factors of the expected market price of the Company’s common stock of 48.94% and an average expected life of 10 years, the life of the option.

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 carryforwards. 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.

DELTA PETROLEUM CORPORATION

AND SUBSIDIARIES

Notes to Consolidated Financial Statements

Six Months Ended December 31, 2004 and 2003

(Unaudited)

(3)

Summary of Significant Accounting Policies, Continued

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 and warrants. See footnote 8 disclosures.

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 made by management impact oil and gas reserves, bad debts, oil and gas properties, depletion and impairment, drilling and lease operating expense accruals, income taxes, derivatives, asset retirement obligations, contingencies and litigation. Actual results could differ from these estimates.

(4)

Oil and Gas Properties

Unproved Undeveloped Offshore California Properties

The Company has ownership interests ranging from 2.49% to 75% in five unproved undeveloped offshore California oil and gas properties with aggregate carrying values of $10.9 million, at December 31, 2004. 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.

DELTA PETROLEUM CORPORATION

AND SUBSIDIARIES

Notes to Consolidated Financial Statements

Six Months Ended December 31, 2004 and 2003

(Unaudited)

(4)

Oil and Gas Properties, Continued

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 December 31, 2004 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. See disclosure in Item 1 of Part II.

Fiscal 2005—Acquisition

On July 1, 2004, the Company acquired certain interests in California’s Sacramento Basin and a 7.5% reversionary working interest in the South Tongue interests in Washington County, Colorado from Edward Mike Davis, LLC, a greater than 5% shareholder, (“Davis”) for 760,000 shares of the Company’s common stock valued at $10.4 million using the five-day closing price before and after the terms of the agreement were agreed and closed. The total acquisition cost was allocated $4.0 million to proved developed producing and $6.4 million to proved undeveloped.

On September 15, 2004, the Company acquired seven wells in Karnes County, Texas from an unrelated entity and unrelated individual for $5.0 million in cash.

On November 4, 2004, the Company entered into an agreement with Davis to acquire the balance of his back-in working interest and his overriding royalty interest in all of his ownership to the base of the Niobrara formation in the South Tongue interests in Washington County, Colorado. This agreement eliminates all future drilling commitments in Washington County. This includes approximately 260,000 acres of leasehold. In addition, we acquired a 100% working interest with a 70% net revenue interest in the Magers 1-9 well which is a newly drilled well in Colusa County, California. Total consideration was 650,000 shares of the Company’s common stock valued at approximately $9.4 million. Also on November 4, 2004, the Company entered into an agreement with Davis to acquire and possibly develop certain areas in Elbert County, Colorado. Initial cost of this transaction was 25,000 shares of the Company’s common stock valued at approximately $363,000. Both transactions were based upon the five day closing price average before and after the closing date, which was $14.51 and included in undeveloped properties.

DELTA PETROLEUM CORPORATION

AND SUBSIDIARIES

Notes to Consolidated Financial Statements

Six Months Ended December 31, 2004 and 2003

(Unaudited)

(4)

Oil and Gas Properties, Continued

Fiscal 2005—Disposition

On August 19, 2004, the Company completed the sale of certain interests in five fields in Louisiana and South Texas previously acquired in the Alpine acquisition, which closed on June 29, 2004, to Whiting Petroleum Corporation for $18.7 million, net of certain commissions. The Company paid $8.8 million toward its credit facility from the proceeds of the sale of these properties. There was no gain or loss on this sale transaction and the net profit earned on these assets during the quarter, since the acquisition, of $729,000 has been shown in discontinued operations.

(5)

Long Term Debt

Bank Debt

During the quarter ended December 31, 2004, the Company had a $200 million facility with Bank One, N.A., Bank of Oklahoma N.A., U.S. Bank National Association and Hibernia National Bank (the “Banks”) which has been amended subsequent to quarter end. At December 31, 2004, the Company had an available borrowing base of $90 million and $83 million outstanding. The facility has variable interest rates based upon the ratio of outstanding debt to the borrowing base. Rates vary between .25% and 1.00% for base rate loans and between 1.5% and 2.25% for Eurodollar loans. The loan was collateralized by substantially all of Delta’s oil and gas properties. Currently, the Company is required to have a current ratio of .8 to 1 and a consolidated debt to EBITDAX (Earnings before interest, taxes, depreciation, amortization and exploration) of less than 3 to 1. At December 31, 2004, the Company was in compliance with its quarterly debt covenants and restrictions. See Subsequent Events footnote for information on the new credit facility established on January 21, 2005.

Maturities of long-term debt, in thousands of dollars based on contractual terms are as follows:

YEAR ENDING December 31,


2005	$	128
2006		132
2007		83
2008		83,017
2009		4

	$	83,364

(6)

Stockholders’ Equity

On July 12, 2004, the Company acquired its third drilling rig from an unrelated individual for 31,000 shares of the Company’s common stock valued at $461,000. The Company contributed this drilling rig to Big Dog at its cost.

DELTA PETROLEUM CORPORATION

AND SUBSIDIARIES

Notes to Consolidated Financial Statements

Six Months Ended December 31, 2004 and 2003

(Unaudited)

(7)

Income Taxes

For income tax purposes, the Company has net operating loss carryforwards expiring at various dates through 2023. As a result of the acquisitions and other issuances of stock, the utilization of the net operating loss carryforwards is subject to an annual limitation by the provisions of Section 382 of the Internal Revenue Code.

The Company recognized no tax expense in the first six months of fiscal 2005 primarily due to recognition of deferred tax assets for which a valuation allowance had previously been provided and recognized no tax benefit in fiscal 2004 because realization was not more likely than not. The remaining deferred tax asset at December 31, 2004, for which a valuation allowance has been recorded, will be recognized in the financial statements when its realization is determined to be more likely than not.

DELTA PETROLEUM CORPORATION

AND SUBSIDIARIES

Notes to Consolidated Financial Statements

Six Months Ended December 31, 2004 and 2003

(Unaudited)

(8)

Earnings Per Share

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


	Three Months Ended December 31,				Six Months Ended December 31,
	2004		2003		2004		2003
Numerator:
Numerator for basic and diluted earnings per share – income available to common stockholders	$	4,809	$	652	$	8,754	$	2,016


Denominator:
Denominator for basic earnings per share-weighted average shares outstanding		39,999		23,560		39,724		23,651
Effect of dilutive securities – stock options and warrants		2,931		2,183		2,720		2,127


Denominator for diluted earnings per common share		42,930		25,743		42,444		25,778


Basic earnings per common share	$	12	$	03	$	22	$	09


Diluted earnings per common share	$	11	$	03	$	21	$	08


Anti-dilutive securities outstanding		1,236		3,547		1,308		3,318

(9)

Reclassifications

Certain amounts in the fiscal 2004 financial statements have been reclassified to conform to the fiscal 2005 financial statement presentation.

(10)

Subsequent Events

Credit Facility

On January 21, 2005, the Company amended its $200 million credit facility with Bank One, NA; Bank of Oklahoma, N.A.; U.S. Bank National Association and Hibernia National Bank. In order to obtain this facility, the Company granted first and prior liens to the lending banks on most of its oil and gas properties and the related equipment, inventory, accounts and proceeds. The credit facility has variable interest rates based upon the ratio of outstanding debt to the borrowing base. Rates vary between .25% and 1.00% for base rate loans and between 1.5% and 2.25% for Eurodollar loans. The loan matures on November 5, 2008.

The borrowing base, which determines the amounts that the Company is allowed to borrow or have outstanding under the credit facility has been amended to $160 million. Subsequent determinations of the borrowing base will be made by the lending banks at least semi-annually on February 15 and August 31 of each year or as special redeterminations. If, as a result of any such reduction in the amount of the borrowing base, the total amount of the outstanding debt exceeds the amount of the borrowing base in effect, then, within 30 days after notification of the borrowing base deficiency, the Company would be required to make a mandatory payment of principal to reduce the outstanding indebtedness so that it would not exceed the borrowing base. If for any reason Delta was unable to pay the full amount of the mandatory prepayment within the requisite 30-day period, Delta would be in default of its obligations under the credit agreement.

Acquisitions

On January 4, 2005 the Company acquired additional interests in the South Tongue area of Washington County and also entered into an exploration agreement with Davis in Los Angeles and Orange Counties, California. The Company paid Davis $400,000 in cash and 135,836 shares of the Company’s common stock valued at $2.0 million. The stock was valued at the five day closing price before and after the closing date.

On January 21, 2005 the Company acquired properties located in Texas from Manti Resources, Inc. for approximately $60.4 million in cash, net of downward purchase price adjustments. As of December 31, 2004 the Company estimates that the Manti assets had approximately 28.1 Bcfe of proved reserves, and have additional unproved development opportunities.

Item 2. 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.

Critical Accounting Policies and Estimates

The discussion and analysis of the Company’s financial condition and results of operations were based upon 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 included in our annual report on Form 10-K. In response to SEC Release No. 33-8040, “Cautionary Advice Regarding Disclosure About Critical Accounting Policies,” 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, drilling and lease operating expense accrual, income taxes, derivatives, contingencies and litigation, and base our estimates on historical experience and various other assumptions that we believe are reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of the Company’s 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. Gas and oil 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 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.

The successful efforts method of accounting can have a significant impact on the operational results reported when the Company is 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. We reevaluate our reserves quarterly.

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 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 the Company to record an impairment of the recorded book values associated with gas and oil properties. We did not record an impairment during the three and six months ended December 31, 2004 and 2003.

For undeveloped properties, the need for an impairment reserve is based on our plans for future development and other activities impacting the life of the property and the ability to recover our investment. When we believe 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, we did not record an impairment provision attributable to certain undeveloped properties for the three and six months ended December 31, 2004 and 2003.

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. The oil and natural gas reference prices of these commodity derivatives contracts are based upon crude oil and natural gas futures, which have a high degree of historical correlation with actual prices we receive.

We follow SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” Under SFAS No. 133 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 current expense or income in the consolidated statements of income. 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 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.

Liquidity and Capital Resources

Liquidity is a measure of a company’s ability to access cash. We have historically addressed our long-term liquidity requirements through the issuance of debt and equity securities when market conditions permit, and through cash provided by operating activities and sale of oil and gas properties. During fiscal 2004, we raised approximately $98 million in additional capital through the sale of our common stock and subsequent to quarter end, we amended our $200 million credit facility. Our current available borrowing base is $160 million. The prices we receive for future oil and natural gas production and the level of production have significant impacts 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.

We continue to examine alternative sources of long-term capital, including bank borrowings, the issuance of debt instruments, the sale of common stock and the sales of non-strategic assets. 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 the 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 assure you 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 acquisition and divestitures of properties.

Company Acquisitions and Growth

On July 1, 2004, we acquired certain interests in California’s Sacramento Basin and 7.5% reversionary working interest in the South Tongue interests in Washington County, Colorado from Edward Mike Davis, LLC, a greater than 5% shareholder, (“Davis”) for 760,000 shares of our common stock valued at $10.4 million using the five-day closing price before and after the terms of the agreement were agreed and closed, which was $13.63.

On September 15, 2004, we acquired seven wells in Karnes County, Texas from an unrelated entity and unrelated individual for $5.0 million in cash.

On November 4, 2004, we entered into an agreement with Davis to acquire the balance of his back-in working interest and his overriding royalty interest in all of his ownership to the base of the Niobrara formation in the South Tongue interests in Washington County, Colorado. This agreement eliminates all future drilling commitments in Washington County. This includes approximately 260,000 acres of leasehold. In addition, we acquired a 100% working interest with a 70% net revenue interest in the Magers 1-9 well which is a newly drilled well in Colusa County, California. Total consideration will be 650,000 shares of our common stock valued at approximately $9.4 million. Also on November 4, 2004, we entered into an agreement with Davis to acquire and possibly develop certain areas in Elbert County, Colorado. Initial cost of this transaction was 25,000 shares of our common stock valued at approximately $363,000.

On January 4, 2005 we acquired additional interests in the South Tongue area of Washington County and also entered into an exploration agreement with Davis in Los Angeles and Orange Counties, California. We paid Davis $400,000 in cash and 135,836 shares of the Company’s common stock valued at $2.0 million.

Cash Provided by Operations and Working Capital

Cash generated from operating activities increased 210% to $19.0 million for the six months ended December 31, 2004 compared to $6.1 million for the same period a year earlier. This increase is primarily the result of increased revenue, the Alpine acquisition which we completed on June 28, 2004, drilling success and a substantial increase in oil and gas prices. At December 31, 2004, we had a working capital deficit of approximately $2.5 million. This anticipated deficit was caused by our increased drilling and the inability to put numerous completed Washington County wells on line waiting for ability to tap into the Cheyenne pipeline which should be occur in late February. In anticipation of this, in November 2004, we obtained a temporary reduction in the current ratio in our current ratio requirement under our credit facility to .8 to 1 through March 31, 2005. After March 31, 2005 the current ratio requirement will return to 1 to 1.

Capital and Exploration Expenditures and Financing

Our capital and exploration expenditures and sources of financing for the six months ended December 31, 2004 and 2003 are as follows:


	2004		2003
	(In thousands)
CAPITAL AND EXPLORATION EXPENDITURES:
Acquisitions:
Washington County South and North Tongue	$	19,794	$	13,370
Karnes County, Texas		5,000		—
Other		362		4,233

Other development costs		46,335		6,554
Drilling and trucking companies		1,184		—
Dry hole costs		2,673		177
Exploration costs		1,283		268

	$	76,631	$	24,602

FUNDING SOURCES:
Cash flow provided by operating activities	$	19,049	$	6,146
Stock issued for cash upon exercised options		475		1,004
Net long term borrowings		13,004		2,818
Proceeds from sale of oil and gas properties		18,721		3,422
Other		117		47

	$	51,366	$	13,437

We anticipate our capital and exploration expenditures to range between $60 and $80 million for fiscal 2005. The timing of most of our capital expenditures is discretionary.

Sale of Oil and Gas Properties—Discontinued Operations

On August 19, 2004, we completed the sale of our interests in five fields in Louisiana and South Texas previously acquired in the Alpine acquisition, which closed on June 29, 2004, to Whiting Petroleum Corporation for $18.7 million, net of commission. We paid $8.8 million on our credit facility balance from the sale of these properties. No gain or loss was recognized on this transaction.

Contractual and Long Term Debt Obligations


	Payments Due by Period
Contractual Obligations at December 31, 2004	Less than 1 year		2-3 Years		4-5 Years		After 5 Years		Total
	(In thousands)
Bank credit facility	$	—	$	—	$	83,000	$	—	$	83,000
Abandonment retirement obligation		227		449		254		6,716		7,646
Operating leases and other debt obligations		963		1,887		1,432		3,232		7,514

Total contractual cash obligations	$	1190	$	2,336	$	84,687	$	9,948	$	98,160

Credit Facility

On January 21, 2005, the Company amended its credit facility with Bank One, NA; Bank of Oklahoma, N.A.; U.S. Bank National Association and Hibernia National Bank. In order to obtain this facility, the Company granted first and prior liens to the lending banks on most of its oil and gas properties and the related equipment, inventory, accounts and proceeds. The maximum amount that may be secured under our senior credit facility is $200.0 million. The total commitments under our senior credit facility, and the maximum amount that we are permitted to borrow under our senior credit facility pursuant to current borrowing base limitation, is $160.0 million. The credit facility has a variable interest rate tied to the prime rate and/or an adjusted LIBOR rate, plus 0.25% to 2.25% based on the total bank debt outstanding. The loan matures on November 5, 2008.

Subsequent determinations of the borrowing base will be made by the lending banks at least semi-annually on February 15 and August 15 of each year or as special redeterminations. 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, Delta 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 and (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 Delta was unable to pay the full amount of the mandatory prepayment within the requisite 30-day period, Delta would be in default of our obligations under our the 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 its 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. At December 31, 2004 we had an available borrowing base of $90 million and $83 million outstanding.

Other Contractual Obligations

Our abandonment retirement obligation arises from the plugging and abandonment liabilities for our oil and gas wells. The majority of this obligation will not occur over 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 $581,000. We have additional operating lease commitments which represent office equipment leases and short term debt obligations primarily relating to field vehicles and equipment. Subsequent to year end, we expanded our corporate office taking an additional 12,000 square feet.

Off balance sheet arrangements

We do not have any off balance sheet arrangements.

Results of Operations

The following discussion and analysis relates to items that have affected our results of operations for the three and six months ended December 31, 2004 and 2003. This analysis should be read in conjunction with our consolidated financial statements and accompanying notes included in this Form 10-Q.

Fiscal 2005 Compared to Fiscal 2004

Net income. Net income for the three and six months ended December 31, 2004 were $4.8 million and $8.8 million compared to a net income of $652,000 and $2.0 million for the comparable periods a year earlier. The increase in net income from the periods ended December 31, 2004 compared to December 31, 2003 were effected by the items described in detail below.

Revenue. Total revenues from oil and gas sales for the three and six months ended December 31, 2004 were $20.4 million and $39.7 million compared to $7.7 million and $14.8 million for the same period a year earlier. The increase was the result of the completion of the Alpine acquisition on June 28, 2004, successful drilling and higher oil prices for both onshore and offshore oil production and also higher gas prices.

Cash payments required on our hedging activities impacted revenues during the three and six months ended December 31, 2004 in the amount of $93,000 and by $68,000 and $380,000 for the periods a year earlier.

Production volumes, average prices received and cost per equivalent Mcf for the three months ended December 31, 2004 and 2003 are as follows:


	2004					2003 (1)
	Onshore			Offshore		Onshore			Offshore
Production – Continuing Operations:
Oil (MBbl) (2)		207			40		128			48
Gas (Mmcf) (3)		1,519			—		642			—
Production – Discontinued Operations:
Oil (MBbl)		—			—		8			—
Gas (Mmcf)		—			—		90			—
Average Sales Price – Continuing Operations:
Oil (per barrel)	$	47.18		$	30.46	$	29.76		$	19.94
Gas (per Mcf)	$	6.23		$	—	$	4.59		$	—
Hedge effect
(per Mcf equivalent)	$	(.03	)	$	—	$	(.05	)	$	—
Production Costs:
(per Mcf equivalent)	$	1.47		$	3.57	$	1.46		$	2.49
Depletion Expense
(per Mcf equivalent)	$	1.11		$	0.73	$	1.08		$	0.41

Production volumes, average prices received and cost per equivalent Mcf for the six months ended December 31, 2004 and 2003 are as follows:


	2004					2003 (1)
	Onshore			Offshore		Onshore			Offshore
Production – Continuing Operations:
Oil (MBbl) (2)		430			74		230			96
Gas (Mmcf) (3)		3,123			—		1,282			—
Production – Discontinued Operations:
Oil (MBbl)		19			—		16			—
Gas (Mmcf)		174			—		191			—
Average Sales Price – Continuing Operations:
Oil (per barrel)	$	44.64		$	30.66	$	29.59		$	19.98
Gas (per Mcf)	$	5.83		$	—	$	4.72		$	—
Hedge effect
(per Mcf equivalent)	$	(0.02	)	$	—	$	(.14	)	$	—
Production Costs:
(per Mcf equivalent)	$	1.31		$	3.68	$	1.04		$	2.68
Depletion Expense:
(per Mcf equivalent)	$	1.33		$	0.75	$	1.28		$	0.51

(1)

2003 information has changed to comply with FAS 144 “Accounting for the Impairment or Disposal of Long-Lived Assets.”

(2)

MBbl means thousand barrels of oil.

(3)

Mmcf means million cubic feet of gas.

Production Costs. Production costs for the three and six months ended December 31, 2004 were $4.9 million and $9.1 million respectively as compared to $2.2 million and $4.3 for the same periods a year earlier. Production costs from continuing operations for onshore properties per equivalent Mcf for the three and six month periods ended December 31, 2004 were $1.47 per Mcf equivalent and $1.31 per Mcf equivalent as compared to $1.08 per Mcf equivalent and $1.04 per Mcf equivalent for the periods ended in 2003. Production costs from continuing operations for offshore properties per equivalent Mcf were $3.57 per Mcf equivalent for the three month period and $3.68 per Mcf equivalent for the six month period ended December 31, 2004. Onshore production costs for the three and six month periods ending December 31, 2003 were $2.49 per Mcf equivalent and $2.68 per Mcf equivalent respectively. This increase in production costs from continuing operations per Mcfe can primarily be attributed to the Alpine assets, which have higher production costs, work over costs on our non-operated properties and lower production in our Newton Field, which was temporarily curtailed during the 2^nd quarter of fiscal 2004. We removed two compressors and installed a larger compressor to handle the anticipated increase in production from our current drilling program. New Texas Railroad Commission admission standards caused the new compressor to be configured in such a way that we could not efficiently process our high BTU gas. The Newton Field produces very rich gas, with an associated high BTU content, and therefor our new facility did not process out the natural gas liquids effectively and caused inefficiencies within existing well bores, and was evidenced in the temporary reduction in the November and December production. In response to this, we have set up a fuel gas distribution system that will allow for the delivery of dry gas to the primary compressor facility so that future production can be maximized.

Drilling and Trucking Operations. 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. We began drilling a well with the first Big Dog rig in August 2004, and we now have a second Big Dog rig also drilling wells for us on a full time basis with a third Big Dog rig nearing completion. We anticipate that all three of these rigs will be used primarily to drill on our acreage for the foreseeable future. We incurred approximately $1.1 million of drilling and trucking expenses during the six months ended December 31, 2004, a portion of which represents downtime between drilling engagements and refurbishing trucking equipment.

Depreciation, Depletion and Amortization Expense. Depreciation, depletion and amortization expense for the three and six months ended December 31, 2004 was $3.7 million and $8.7 million as compared to $2.2 million and $3.8 million for the same periods a year earlier. Depreciation, depletion and amortization expenses per equivalent Mcf for our onshore properties was $1.11 per Mcf equivalent for the three months and $1.33 for the six months ended December 31, 2004 as compared to $1.46 and $1.28 for the respective periods in the prior year. This increase can be attributed to the acquisition of the Alpine assets completed at the end of fiscal 2004. The Alpine assets are generally short lived causing higher depletion rates.

Dry Hole Costs. We incurred dry hole costs of approximately $0.4 and $2.7 million for the three and six month periods ended December 31, 2004 as compared to approximately $0.2 for both the three and six month periods ended December 31, 2003. A significant portion of these costs relate to our Trail Blazer prospect in Laramie County, Wyoming. Included in the dry holes were four non-Niobrara formation dry holes in Washington County, Colorado.

Exploration Expenses. Exploration expenses consist of geological and geophysical costs and lease rentals. Our exploration costs for the three months and six months ended December 31, 2004 were $747,000 and $1.3 million respectively and primarily include newly acquired seismic information in Washington County, Colorado, Polk County, Texas and Laramie County, Wyoming. Exploration expenses for the three and six months ended December 31, 2003 were $138,000 and $268,000. Currently, we are obtaining seismic information on 22.75 square miles in Washington County, Colorado on our North Tongue Prospect and will be expanding our South Tongue Prospect shoot to include a 46 square mile shoot during fiscal 2005.

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 for the three and six month periods ended December 31, 2004 were $501,000 and $847,000 as compared to $308,000 and $612,000 for the respective periods ended December 31, 2003. The increase in professional fees can be attributed largely to compliance with the Sarbanes-Oxley Act.

General and Administrative Expenses. General and administrative expenses for the three and six month periods ended December 31, 2004 were $3.5 million and $6.1 million. Respective amounts for the periods ended December 31, 2003 were $1.6 million and $2.7 million. The increase in general and administrative expenses is primarily attributed to the increase in technical and administrative staff and related personnel costs and the expansion of our office facility necessary to support our acquisitions and increased exploration efforts.

Interest and Financing Costs. Interest and financing costs were $1.4 million and $2.2 million for the three and six month periods ended December 31, 2004 as compared to $576,000 and $1.1 million for the comparable periods in the prior year. The increase for the periods ended in December, 2004 over those of the respective periods in 2003 result from increased debt relating to acquisitions completed during fiscal 2004 and increased exploration activities.

Discontinued Operations. Included in discontinued operations are income from operations of properties sold and (losses) on sale of oil and gas properties. We are required to re-class related revenue and expenses relating to sales of our oil and gas properties for all periods presented. During fiscal 2005 we sold certain properties in Louisiana and South Texas which had $729,000 in income from operations. No gain or loss was recognized on this transaction as the assets had only been acquired a month and a half earlier. During fiscal 2004, we sold non-strategic properties which had $255,000 and $575,000 of income from operations for the three and six month periods ended December 31, 2003. A sale of properties in fiscal 2004 resulted in a $28,000 loss reflected in both the three and six month periods ended December 31, 2003.

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:


Commodity	Volume	Price Floor /Price Ceiling	Term
Crude oil	40,000 Bbls /month month	$35.00 / $50.80	Jan ‘05– June ‘05
Crude oil	6,000 Bbls / month	$35.00 / $49.75	April ‘05 – Dec ‘05
Crude oil	40,000 Bbls / month	$40.00 / $50.34	July ‘05 – June ‘06
Natural gas	3,000 MMBtu / day	$5.00 / $7.85	Apr ‘05 – Oct ‘05
Natural gas	10,000 MMBtu /day day	$5.00 / $9.25	Jan. ‘05 – June ‘05
Natural gas	10,000 MMBtu /day day	$5.00 / $9.60	July ‘05 – June ‘06

The current derivative contracts cover approximately 40% of our current daily production. A $1.00 change in the oil and gas price received for our production would have an immaterial impact on our oil and gas revenue as the change in price would still fall within our hedge positions.

Interest Rate Risk

We were subject to interest rate risk on $83 million of variable rate debt obligations at December 31, 2004. The annual effect of a ten percent change in interest rates would be approximately $415,000. The interest rate on these variable debt obligations approximates current market rates as of December 31, 2004.

Item 4. Controls and Procedures

As of December 31, 2004, 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 December 31, 2004. 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.

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 not yet been heard by the court.

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

During the quarter ended December 31, 2004, we issued securities in transactions that were not registered under the Securities Act of 1933 as follows:

On November 4, 2004, we issued a total of 650,000 shares of our common stock to Edward Mike Davis and his related entities (“Davis”) in connection with the execution of the Fourth Amendment to our Purchase and Sale Agreement with him. Also on November 4, 2004, we issued an additional 25,000 shares of our common stock to Davis in connection with a letter agreement relating to an area of mutual interest in Elbert County, Colorado. All of these shares have been subsequently registered for re-sale by Davis under the Securities Act of 1933, as amended.

In connection with these transactions we relied on the exemption provided by Section 4(2) of the Securities Act of 1933. We reasonably believe that the investors are “Accredited Investors” as such term is defined in Rule 501 of Regulation D promulgated under the Securities Act of 1933 at the time the transactions occurred. Davis had access to complete information about Delta. Davis acquired the shares for investment purposes. Restrictive legends were placed on the certificates issued to Davis and stop transfer orders were given to our transfer agent.

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

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: February 9, 2005

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