- Quarterly Report (10-Q)

UNITED STATES
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 June 30, 2009


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

For the transition period from to

Commission file number 0-16203

DELTA PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)


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

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

(303) 293-9133

(Registrant’s telephone number, including area code)

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ___ No ___

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


Large accelerated filer X		Accelerated filer ___
Non-accelerated filer ___		Smaller reporting company ___

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

276,788,000 shares of common stock, $.01 par value per share, were outstanding as of August 1, 2009.

INDEX


		Page No.
PART I	FINANCIAL INFORMATION

Item 1.	Consolidated Financial Statements

	Consolidated Balance Sheets – June 30, 2009 and December 31, 2008 (unaudited)	1

	Consolidated Statements of Operations – Three Months Ended June 30, 2009 and 2008 (unaudited)	2

	Consolidated Statements of Operations – Six Months Ended June 30, 2009 and 2008 (unaudited)	3

	Consolidated Statements of Changes in Equity and Comprehensive Loss – Six Months Ended June 30, 2009 (unaudited)	4

	Consolidated Statements of Cash Flows – Six Months Ended June 30, 2009 and 2008 (unaudited)	5

	Notes to Consolidated Financial Statements (unaudited)	6

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	31

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	49

Item 4.	Controls and Procedures	49

PART II	OTHER INFORMATION

Item 1.	Legal Proceedings	50

Item 1A.	Risk Factors	51

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	60

Item 3.	Defaults upon Senior Securities	60

Item 4.	Submission of Matters to a Vote of Security Holders	61

Item 5.	Other Information	61

Item 6.	Exhibits	62

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

PART I FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


	June 30,			December 31,
	2009			2008
	(In thousands, except share data)
ASSETS
Current assets:
Cash and cash equivalents	$	5,744		$	65,475
Short-term restricted deposits		102,888			100,000
Trade accounts receivable, net of allowance for doubtful accounts of $631 and $652, respectively		13,569			30,437
Deposits and prepaid assets		3,717			11,253
Inventories		8,406			9,140
Deferred tax assets		-			231
Other current assets		6,729			6,221

Total current assets		141,053			222,757

Property and equipment:
Oil and gas properties, successful efforts method of accounting:
Unproved		313,513			415,573
Proved		1,406,953			1,365,440
Drilling and trucking equipment		182,193			194,223
Pipeline and gathering systems		96,656			86,076
Other		16,048			29,107

Total property and equipment		2,015,363			2,090,419
Less accumulated depreciation and depletion		(729,184	)		(658,279	)

Net property and equipment		1,286,179			1,432,140


Long-term assets:
Long-term restricted deposit		200,000			200,000
Marketable securities		1,977			1,977
Investments in unconsolidated affiliates		14,486			17,989
Deferred financing costs		4,242			7,640
Other long-term assets		14,587			12,460

Total long-term assets		235,292			240,066


Total assets	$	1,662,524		$	1,894,963


LIABILITIES AND EQUITY
Current liabilities:
Credit facility - Delta	$	83,038		$	294,475
Credit facility – DHS		83,268			-
Installments payable on property acquisition		98,719			97,453
Accounts payable		79,035			159,024
Executive severance payable		2,888			-
Other accrued liabilities		12,190			13,576
Derivative instruments		7,434			-

Total current liabilities		366,572			564,528

Long-term liabilities:
Installments payable on property acquisition, net of current portion		190,779			188,334
7% Senior notes		149,572			149,534
3 ³ / 4 % Senior convertible notes		101,780			99,616
Credit facility - DHS		-			93,848
Asset retirement obligations		8,066			6,585
Derivative instruments		13,677			-
Deferred tax liabilities		-			1,024

Total long-term liabilities		463,874			538,941

Commitments and contingencies

Equity:
Preferred stock, $.01 par value: authorized 3,000,000 shares, none issued		-			-
Common stock, $.01 par value; authorized 300,000,000 shares, issued 276,802,000 shares at June 30, 2009 and 103,424,000 shares at December 31, 2008		2,768			1,034
Additional paid-in capital		1,620,650			1,372,123
Treasury stock at cost; 1,036,000 shares at June 30, 2009 and 36,000 shares at December 31, 2008		(2,140)			(540)
Executive severance payable in common stock		1,700			-
Accumulated deficit		(808,098)			(610,227)

Total Delta stockholders’ equity		814,880			762,390

Non-controlling interest		17,198			29,104

Total equity		832,078			791,494


Total liabilities and equity	$	1,662,524		$	1,894,963

See accompanying notes to consolidated financial statements.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)


	Three Months Ended
	June 30,
	2009			2008
	(In thousands, except per share amounts)
Revenue:

Oil and gas sales	$	21,349		$	73,232
Contract drilling and trucking fees		1,674			7,875
Gain (loss) on offshore litigation award		(81	)		-


Total revenue		22,942			81,107


Operating expenses:

Lease operating expense		7,601			8,952
Transportation expense		2,505			2,449
Production taxes		1,025			4,263
Exploration expense		471			1,933
Dry hole costs and impairments		106,621			430
Depreciation, depletion, amortization and accretion – oil and gas		29,932			24,752
Drilling and trucking operating expenses		2,342			5,529
Depreciation and amortization – drilling and trucking		6,175			3,208
General and administrative		8,966			13,826
Executive severance expense, net		3,739			-


Total operating expenses		169,377			65,342


Operating income (loss)		(146,435	)		15,765


Other income and (expense):

Interest expense and financing costs		(15,883	)		(9,676	)
Interest income		108			3,388
Other income (expense)		1,256			(185	)
Realized loss on derivative instruments, net		-			(7,130	)
Unrealized loss on derivative instruments, net		(15,647	)		(27,072	)
Income (loss) from unconsolidated affiliates		(3,617	)		800


Total other expense		(33,783	)		(39,875	)


Loss from continuing operations before income taxes and discontinued operations		(180,218	)		(24,110	)

Income tax expense (benefit)		265			(860	)


Loss from continuing operations		(180,483	)		(23,250	)

Discontinued operations:

Loss on sale of discontinued operations, net of tax		-			(16	)


Net loss		(180,483	)		(23,266	)

Less net (income) loss attributable to non-controlling interest		8,165			(121	)


Net loss attributable to Delta common stockholders	$	(172,318	)	$	(23,387	)


Amounts attributable to Delta common stockholders:
Loss from continuing operations	$	(172,318	)	$	(23,371	)
Income (loss) from discontinued operations, net of tax		-			(16	)

Net loss	$	(172,318	)	$	(23,387	)


Basic income (loss) attributable to Delta common stockholders per common share:
Loss from continuing operations	$	(0.89	)	$	(0.23	)
Discontinued operations		-			-

Net loss	$	(0.89	)	$	(0.23	)


Diluted income (loss) attributable to Delta common stockholders per common share:
Loss from continuing operations	$	(0.89	)	$	(0.23	)
Discontinued operations		-			-

Net loss	$	(0.89	)	$	(0.23	)

See accompanying notes to consolidated financial statements.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)


	Six Months Ended
	June 30,
	2009			2008
	(In thousands, except per share amounts)
Revenue:

Oil and gas sales	$	43,507		$	126,992
Contract drilling and trucking fees		6,887			18,595
Gain on offshore litigation award		31,204			-


Total revenue		81,598			145,587


Operating expenses:

Lease operating expense		17,447			17,043
Transportation expense		5,760			4,272
Production taxes		2,605			7,804
Exploration expense		1,531			2,935
Dry hole costs and impairments		108,064			2,769
Depreciation, depletion, amortization and accretion – oil and gas		56,754			47,791
Drilling and trucking operating expenses		7,598			12,352
Depreciation and amortization – drilling and trucking		11,967			6,851
General and administrative		21,594			27,247
Executive severance expense, net		3,739			-


Total operating expenses		237,059			129,064


Operating income (loss)		(155,461	)		16,523


Other income and (expense):

Interest expense and financing costs		(32,957	)		(18,613	)
Interest income		756			5,258
Other income (expense)		1,408			272
Realized loss on derivative instruments, net		-			(8,765	)
Unrealized loss on derivative instruments, net		(21,111	)		(41,205	)
Income (loss) from unconsolidated affiliates		(2,870	)		692


Total other expense		(54,774	)		(62,361	)


Loss from continuing operations before income taxes and discontinued operations		(210,235	)		(45,838	)

Income tax benefit		(318	)		(1,457	)


Loss from continuing operations		(209,917	)		(44,381	)

Discontinued operations:

Gain on sale of discontinued operations, net of tax		-			4


Net loss		(209,917	)		(44,377	)

Less net loss attributable to non-controlling interest		12,046			208


Net loss attributable to Delta common stockholders	$	(197,871	)	$	(44,169	)


Amounts attributable to Delta common stockholders:
Loss from continuing operations	$	(197,871	)	$	(44,173	)
Income (loss) from discontinued operations, net of tax		-			4

Net loss	$	(197,871	)	$	(44,169	)


Basic income (loss) attributable to Delta common stockholders per common share:
Loss from continuing operations	$	(1.35	)	$	(0.49	)
Discontinued operations		-			-

Net loss	$	(1.35	)	$	(0.49	)


Diluted income (loss) attributable to Delta common stockholders per common share:
Loss from continuing operations	$	(1.35	)	$	(0.49	)
Discontinued operations		-			-

Net loss	$	(1.35	)	$	(0.49	)

See accompanying notes to consolidated financial statements.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY AND
COMPREHENSIVE LOSS

(Unaudited)


							Additional									Executive		Accu-			Total Delta			Non-
	Common stock						paid-in			Treasury stock						severance pay-		mulated			stockholders’			controlling			Total
	Shares			Amount			capital			Shares			Amount			able in Stock		deficit			equity			interest			equity
	(In thousands)
Balance, January 1, 2009		103,424		$	1,034		$	1,372,123			36		$	(540	)	$	-	$	(610,227	)	$	762,390		$	29,104		$	791,494

Net loss and comprehensive loss		-			-			-			-			-			-		(197,871	)		(197,871	)		(12,046	)		(209,917	)
Shares issued for cash, net of offering costs		172,500			1,725			245,443			-			-			-		-			247,168			-			247,168
Treasury stock acquired by subsidiary		-			-			-			12			(47	)		-		-			(47	)		47			-
Issuance of non-vested stock		802			8			(9	)		(18	)		165			-		-			164			(125	)		39
Shares repurchased for withholding taxes		(44	)		-			(196	)		6			(18	)		-		-			(214	)		(12	)		(226	)
Forfeiture of restricted shares		(195	)		(2	)		3			-			-			-		-			1			-			1
Cancellation of executive performance shares, tranches 2 and 3		(500	)		(5	)		5			-			-			-		-			-			-			-
Executive severance payable in common stock		1,000			10			1,690			1,000			(1,700	)		1,700		-			1,700			-			1,700
Executive severance – stock-based awards forfeited		(185	)		(2	)		(2,818	)		-			-			-		-			(2,820	)		-			(2,820	)
Stock based compensation		-			-			4,409			-			-			-		-			4,409			230			4,639


Balance, June 30, 2009		276,802		$	2,768		$	1,620,650			1,036		$	(2,140	)	$	1,700	$	(808,098	)	$	814,880		$	17,198		$	832,078

See accompanying notes to consolidated financial statements.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Six Months Ended
	June 30,
	2009			2008
	(In thousands)
Cash flows from operating activities:
Net loss	$	(209,917	)	$	(44,377	)
Adjustments to reconcile net loss to cash provided by operating activities:
Basis in offshore properties recovered through litigation		17,497			-
Gain on sale of drilling rig		(1,724	)		-
Gain on sale of discontinued operations		-			(4	)
Depreciation, depletion, amortization and accretion – oil and gas		56,754			47,791
Depreciation and amortization – drilling and trucking		11,967			6,851
Dry hole costs and impairments		108,064			2,501
Impairment on marketable securities		-			289
Stock based compensation		4,639			8,015
Executive severance payable in common stock		1,700			-
Executive severance – stock-based awards forfeited		(2,820	)		-
Amortization of deferred financing costs		7,717			3,842
Accretion of discount on installments payable		3,710			2,417
Unrealized loss on derivative instruments		21,111			41,205
(Income) loss from unconsolidated affiliates		3,204			(692	)
Deferred income tax benefit		(318	)		(1,457	)
Other		(21	)		2
Net changes in operating assets and liabilities:
(Increase) decrease in trade accounts receivable		16,998			(10,926	)
(Increase) decrease in deposits and prepaid assets		4,830			(14,499	)
(Increase) decrease in inventories		(1,252	)		223
Increase in other current assets		(2,641	)		(238	)
Increase (decrease) in accounts payable		(5,385	)		8,023
Increase (decrease) in other accrued liabilities		(1,264	)		417


Net cash provided by operating activities		32,849			49,383


Cash flows from investing activities:
Additions to property and equipment		(122,438	)		(224,484	)
Acquisitions		-			(136,485	)
Proceeds from sales of drilling rig and equipment		7,823			65
Increase in restricted deposit		-			(300,000	)
Increase in certificates of deposit		-			(35,480	)
Additions to drilling and trucking equipment		(601	)		(26,814	)
Proceeds from minority interest contributions		-			6,000
Investment in unconsolidated affiliates		295			(3,664	)
Loans to affiliate		-			(490	)
Increase in other long-term assets		(402	)		(46	)


Net cash used in investing activities		(115,323	)		(721,398	)


Cash flows from financing activities:
Proceeds from borrowings		37,000			128,500
Repayments of borrowings		(259,017	)		(127,613	)
Payment of deferred financing costs		(2,182	)		(2,117	)
Proceeds from sale of offshore litigation contingent payment rights		25,000			-
Repurchase of offshore litigation contingent payment rights		(25,000	)		-
Proceeds from note payable – DHS		-			6,000
Stock issued for cash, net		247,168			662,043
Stock issued for cash upon exercise of options		-			4,576
Shares repurchased for withholding taxes		(226	)		(568	)


Net cash provided by financing activities		22,743			670,821


Net decrease in cash and cash equivalents		(59,731	)		(1,194	)

Cash and cash equivalents at beginning of period		65,475			9,793


Cash and cash equivalents at end of period	$	5,744			8,599


Supplemental cash flow information:
Cash paid for interest and financing costs	$	12,631		$	11,931

See accompanying notes to consolidated financial statements.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES

Notes to Consolidated Financial Statements

Three and Six Months Ended June 30, 2009 and 2008
(Unaudited)

(1)

Nature of Organization and Basis of Presentation

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

The accompanying unaudited consolidated financial statements have been prepared in accordance with the instructions to Form 10-Q and, in accordance with those rules, do not include all the information and notes required by generally accepted accounting principles for complete financial statements. As a result, these unaudited consolidated financial statements should be read in conjunction with the Company’s audited consolidated financial statements and notes thereto previously filed with the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, as amended by the Current Report on Form 8-K filed May 6, 2009. In the opinion of management, all adjustments, consisting only of normal recurring accruals, considered necessary for a fair presentation of the financial position of the Company and the results of its operations have been included. Operating results for interim periods are not necessarily indicative of the results that may be expected for the complete fiscal year. For a more complete understanding of the Company’s operations and financial position, reference is made to the consolidated financial statements of the Company, and related notes thereto, filed with the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, as amended by the Current Report on Form 8-K filed May 6, 2009, previously filed with the Securities and Exchange Commission (“SEC”).

(2)

Going Concern

The accompanying financial statements have been prepared assuming the Company will continue as a going concern. At December 31, 2008, the Company was not in compliance with the current ratio and accounts payable covenants under its credit agreement. Pursuant to a redetermination made as of February 1, 2009, the borrowing base under the Company’s credit agreement was reduced to $225.0 million upon completion of the Company’s underwritten public offering on May 13, 2009 of 172.5 million shares of the Company’s common stock at $1.50 per share for net proceeds of $247.2 million, net of underwriting commissions and related offering expenses. The proceeds were used to reduce amounts outstanding under the Company’s credit agreement and to pay accounts payable.

The Company experienced a net loss attributable to Delta common stockholders of $197.9 million for the six months ended June 30, 2009, and at June 30, 2009 had a working capital deficiency of $225.5 million, including $83.0 million outstanding under its credit agreement and $83.3 million outstanding under the credit agreement of DHS Drilling Company (“DHS”), the Company’s 49.8% subsidiary (which are classified as current liabilities in the accompanying balance sheet), which raises substantial doubt about the Company’s ability to continue as a going concern.

At June 30, 2009, the Company was in compliance with its quarterly financial covenants under its credit agreement; however, projections indicate that without an increase in Rocky Mountain natural gas prices upon which the majority of the Company’s production is sold, the senior secured debt to EBITDAX ratio covenant in its credit agreement could be violated within the next twelve months. The borrowing base under the Company’s credit agreement is to be redetermined effective September 1, 2009. A decrease in the borrowing base determined by the lenders would decrease the Company’s remaining availability under the line of credit. At June 30, 2009,

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2009 and 2008
(Unaudited)

(2)

Going Concern, Continued

DHS was in not in compliance with its obligation to provide to Lehman Commercial Paper, Inc. (“LCPI”) by March 31 of each year audited financial statements reported on without a going concern qualification or exception by the independent auditor and DHS’s previous forbearance agreement with LCPI expired on June 15, 2009. In addition, DHS was not in compliance with its various financial covenants as of June 30, 2009. Although DHS is in ongoing negotiations with LCPI to modify the terms of the existing DHS credit facility, there can be no assurance that DHS will be able to renegotiate the terms of its debt agreement. The DHS facility is non-recourse to Delta.

The Company had $79.0 million of accounts payable at June 30, 2009, which if not timely paid could result in liens filed against the Company’s properties or withdrawal of trade credit provided by vendors, which in turn could limit the Company’s ability to conduct operations on its properties.

While the May 2009 public equity offering has substantially funded the Company’s near term liquidity needs, the Company continues to pursue other potential capital raising activities, such as joint ventures, or other industry partnerships, or non-core asset dispositions. In addition, the Company continues to limit its capital expenditure program and has implemented additional cost saving measures, including a second reduction in force during June 2009, that when combined with the March 2009 reduction in force, has reduced the Company’s total number of employees by approximately fifty percent.

Depending on changes in commodity prices, the outcome of the Company’s borrowing base re-determination scheduled for September 1, 2009 and developments related to the Company’s remaining offshore litigation, the Company will evaluate the need to raise additional capital. There can be no assurance that the actions undertaken by the Company will be sufficient to repay the obligations under the credit agreement, or, if not sufficient, or if additional defaults occur, that the lenders will be willing to waive the defaults or amend the agreement. In addition, there can be no assurance that cash flow from operations and other sources of liquidity, including asset sales or joint venture or other industry partnerships, will be sufficient to meet contractual, operating and capital obligations. The financial statements do not include any adjustments that might result from the outcome of uncertainty regarding the Company’s ability to raise additional capital, sell assets, or otherwise obtain sufficient funds to meet its obligations.

(3)

Summary of Significant Accounting Policies

Principles of Consolidation and Basis of Presentation

The consolidated financial statements include the accounts of Delta and its consolidated subsidiaries (collectively, the “Company”). All inter-company balances and transactions have been eliminated in consolidation. Certain of the Company’s oil and gas activities are conducted through partnerships and joint ventures, including CRB Partners, LLC (“CRBP”) and PGR Partners, LLC (“PGR”). The Company includes its proportionate share of assets, liabilities, revenues and expenses from these entities in its consolidated financial statements. As Amber Resources Company of Colorado (“Amber”) is in a net shareholders’ deficit position for the periods presented, the Company has recognized 100% of Amber’s earnings/losses for all periods presented. The Company does not have any off-balance sheet financing arrangements (other than operating leases) or any unconsolidated special purpose entities.

Certain reclassifications have been made to amounts reported in the previous periods to conform to the current presentation. Among other items, revenues and expenses on properties that were held for sale during the three months and six months ended June 30, 2008 but were not subsequently sold, have been reclassified from discontinued operations to continuing operations for all periods presented. Such reclassifications had no effect on net loss.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2009 and 2008
(Unaudited)

(3)		Summary of Significant Accounting Policies, Continued

		Cash Equivalents

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

Inventories

Inventories consist of pipe and other production equipment not yet in use. Inventories are stated at the lower of cost (principally first-in, first-out) or estimated net realizable value. During 2008, the Company pre-ordered and stockpiled significant amounts of tubing, casing and pipe inventory to ensure availability for its then aggressive Piceance Basin and Paradox Basin drilling program. Since then, with significantly lower commodity prices resulting in significant reductions in drilling capital expenditures and delays to drilling plans and with continued declines in steel prices, particularly during the second quarter of 2009, the value of these inventories has declined. As a result, during the three months ended June 30, 2009, the Company recorded an impairment of $4.3 million to the carrying value of its inventories, which is reflected in the accompanying consolidated statements of operations as a component of dry hole costs and impairments.

Marketable Securities

Marketable securities include auction rate securities classified as available for sale securities. As of June 30, 2009, the marketable securities are recorded in long-term assets in the accompanying consolidated balance sheet with changes in their fair market value if any, recorded in accumulated other comprehensive loss. However, if declines in their fair market value are considered to be other than temporary impairments, then the loss recorded in accumulated other comprehensive loss must be reclassified to earnings and once recorded, an impairment cannot be reversed. If the issuers of the securities continue to be unable to successfully close future auctions and their credit ratings further deteriorate, the Company may be required to record additional impairment charges on these investments.

Non-Controlling Interest

Non-controlling interest represents the 50.2% (47.2% owned by Chesapeake Energy Corporation (“Chesapeake”) and 3.0% owned by DHS executives) interest in DHS at June 30, 2009 and December 31, 2008.

		Revenue Recognition

		*Oil and gas*

Revenues are recognized when title to the products transfers to the purchaser. The Company follows the “sales method” of accounting for its natural gas and crude oil revenue. Under that method, the Company recognizes sales revenue on all natural gas or crude oil sold to its purchasers. A 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 June 30, 2009 and December 31, 2008, the Company’s aggregate natural gas and crude oil imbalances were not material to its consolidated financial statements.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2009 and 2008
(Unaudited)

(3)		Summary of Significant Accounting Policies, Continued

		*Drilling and Trucking*

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

Property and Equipment

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

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

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

Drilling equipment is recorded at cost or estimated fair value upon acquisition and depreciated on a component basis using the straight-line method over its estimated useful life ranging from five to 15 years. Pipelines and gathering systems and other property and equipment are recorded at cost and depreciated using the straight-line method over their estimated useful lives ranging from three to 40 years.

Impairment of Long-Lived Assets

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

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

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2009 and 2008
(Unaudited)

(3)

Summary of Significant Accounting Policies, Continued

The Company assesses proved properties on an individual field basis for impairment on at least an annual basis. For proved 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. No impairments were recorded to proved properties as a result of such assessment for the three or six months ended June 30, 2009.

For unproved properties, the need for an impairment charge 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 unproved 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 impairment provisions attributable to unproved properties of $82.9 million for the three months ended June 30, 2009, including $38.6 million related to the Company’s non-operated Piceance leasehold in Garden Gulch, $26.7 million related to leasehold in the Haynesville Shale, $14.7 million related to leasehold in Lighthouse Bayou, and $2.3 million related to expired and expiring acreage in the Newton field. In addition, the Company recorded an impairment of $10.5 million to reduce the Company’s Vega area land carrying value to its estimated fair value. Lastly, the Company recorded an impairment of $1.9 million to reduce the Paradox pipeline carrying value to its estimated fair value. These impairments are included within dry hole costs and impairments in the accompanying statement of operations for the three months ended June 30, 2009. During the second quarter of 2009, the Company adjusted the timing of the development of the Garden Gulch properties to delay the drilling of additional wells. In addition, during the quarter, another working interest owner in the property sold its interest to an undisclosed buyer for an implied price less than the carrying value of the Company’s interests in the properties. With respect to the Company’s Haynesville Shale leasehold, during the second quarter of 2009, the Company began preparing prospect materials to support efforts to market the leasehold, including efforts to consolidate acreage blocks to optimize marketability, and received offers on certain portions of the leasehold at prices less than our carrying value. With respect to the Company’s Lighthouse Bayou leasehold, the Company was obligated under its exploration and development agreement, as amended, to spud an initial test well by July 1, 2009. In late May 2009, an amendment to the agreement was executed whereby the leases reverted to the original seller and the Company retained an option to participate in future transactions, if any, related to the leases contained in the area of mutual interest. With respect to the Vega area surface acreage, during the second quarter of 2009, the Company entered into negotiations to sell a portion of its surface acreage to an existing land owner in the area as part of an attempt to resolve access and right of way issues related to the development of the minerals and is in the process of marketing the remaining surface acreage. With respect to the Paradox pipeline, the Company received an offer for the associated gas plant for an amount less than the carrying value. In each case, as a result of the events and activities described, the Company evaluated its unproved leasehold or surface acreage and concluded that an impairment had occurred.

During the remainder of 2009, the Company will continue to evaluate its proved and unproved properties on which favorable or unfavorable results or changes in natural gas or crude oil prices may cause a revision to future estimates of those properties’ future cash flows. Such revisions of estimates could require the Company to record impairments in the period of such revisions.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2009 and 2008
(Unaudited)

(3)		Summary of Significant Accounting Policies, Continued

		Asset Retirement Obligations

The Company’s asset retirement obligations arise from the plugging and abandonment liabilities for its oil and gas wells. The Company has no obligation to provide for the retirement of most of its offshore properties as the obligations remained with the seller from whom the Company acquired the properties. The following is a reconciliation of the Company’s asset retirement obligations from January 1, 2009 to June 30, 2009 (amounts in thousands):


Asset retirement obligation – January 1, 2009	$	8,737
Accretion expense		258
Obligations assumed		1,193
Obligations settled		(84	)

Asset retirement obligation – June 30, 2009		10,104
Less: Current portion of asset retirement obligation		(2,038	)

Long-term asset retirement obligation	$	8,066

Comprehensive Loss

Comprehensive loss includes all changes in equity during a period except those resulting from investments by owners and distributions to owners, if any. The components of comprehensive loss for the three and six months ended June 30, 2009 and 2008 are as follows (amounts in thousands):


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008

Net loss attributable to Delta common stockholders	$	(172,318	)	$	(23,387	)	$	(197,871	)	$	(44,169	)
Other comprehensive income transactions –
Change in fair value of available for sale securities		-			30			-			(554	)
Loss on impairment of available for sale securities reclassified to earnings		-			-			-			289

Comprehensive loss	$	(172,318	)	$	(23,357	)	$	(197,871	)	$	(44,434	)

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. Effective July 1, 2007, the Company elected to discontinue cash flow hedge accounting on a prospective basis and recognize mark-to-market gains and losses in earnings currently instead of deferring those amounts in accumulated other comprehensive income for the contracts that qualify as cash flow hedges.

The Company is exposed to the fluctuations in natural gas or crude oil prices due to the nature of business in which the Company is primarily involved. In order to mitigate the risks associated with uncertain cash flows from volatile commodity prices and to provide stability and predictability in the Company’s future revenues, the Company periodically enters into commodity price risk management transactions to manage its exposure to gas and oil price volatility. During the first quarter of 2009, the Company was required by the Forbearance Agreement and Amendment to the Credit Facility to execute derivative contracts to hedge anticipated oil and gas production equal to minimums of 40% for the last two quarters of 2009, 70% for the calendar year 2010 and 50% for the calendar year 2011.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2009 and 2008
(Unaudited)

(3)

Summary of Significant Accounting Policies, Continued

At June 30, 2009, all of the Company’s outstanding derivative contracts were fixed price swaps. Under the swap agreements, the Company receives the fixed price and pays the floating index price. The Company’s swaps are settled in cash on a monthly basis. By entering into swaps, the Company effectively fixes the price that it will receive for the hedged production.

The following table summarizes the Company’s open derivative contracts at June 30, 2009:


									Net Fair Value
									Asset (Liability) at
Commodity	Volume			Fixed Price		Term		Index Price	June 30, 2009
									(In thousands)

Crude oil		1,000	Bbls / Day	$	52.25	Jul ’09	- Dec ’09	NYMEX – WTI		$ (3,443	)
Crude oil		1,000	Bbls / Day	$	52.25	Jan ’10	- Dec ’10	NYMEX – WTI		(7,065	)
Crude oil		500	Bbls / Day	$	57.70	Jan ’11	- Dec ’11	NYMEX – WTI		(2,660	)
Natural gas		4,000	MMBtu / Day	$	5.720	Aug ’09	- Dec ’09	NYMEX – HHUB		753
Natural gas		6,000	MMBtu / Day	$	5.720	Jan ’10	- Dec ’10	NYMEX – HHUB		(593	)
Natural gas		10,000	MMBtu / Day	$	4.105	Aug ’09	- Dec ’09	CIG		1,202
Natural gas		15,000	MMBtu / Day	$	4.105	Jan ’10	- Dec ’10	CIG		(4,641	)
Natural gas		4,373	MMBtu / Day	$	3.973	Aug ’09	- Dec ’09	CIG		439
Natural gas		5,367	MMBtu / Day	$	3.973	Jan ’10	- Dec ’10	CIG		(1,878	)
Natural gas		12,000	MMBtu / Day	$	5.150	Jan ’11	- Dec ’11	CIG		(2,464	)
Natural gas		3,253	MMBtu / Day	$	5.040	Jan ’11	- Dec ’11	CIG		(761	)

										$(21,111	)

The pre-credit risk adjusted fair value of the Company’s net derivative liabilities as of June 30, 2009 was $26.5 million. A credit risk adjustment of $5.4 million to the fair value of the derivatives required by Statement 157 reduced the reported amount of the net derivative liabilities on the Company’s consolidated balance sheet to $21.1 million.

The following table summarizes the fair values and location in the Company’s consolidated balance sheet of all derivatives held by the Company as of June 30, 2009:


Derivatives Not Designated as Hedging
Instruments under SFAS 133	Balance Sheet Classification	Fair Value
Liabilities
Commodity Swaps	Derivative Instruments – Current Liabilities, net		$ 7,434
Commodity Swaps	Derivative Instruments – Long-Term Liabilities, net		13,677

Total			$ 21,111

The following table summarizes the unrealized losses and the classification in the consolidated statement of operations of derivatives not designated as hedging instruments for the six months ended June 30, 2009:


		Amount of Gain
Derivatives Not Designated as Hedging	Location of Gain (Loss) Recognized in	(Loss) Recognized in
Instruments under SFAS 133	Income on Derivatives	Income on Derivatives

Commodity Swaps	Unrealized Loss on Derivative Instruments, net – Other Income and (Expense)		$(21,111	)

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2009 and 2008
(Unaudited)

(3)		Summary of Significant Accounting Policies, Continued

		Executive Severance Agreement

On May 26, 2009, the Company’s then Chairman of the Board of Directors and Chief Executive Officer, Roger A. Parker, resigned from the Company. In conjunction with Mr. Parker’s resignation, Delta entered into a Severance Agreement, effective as of the close of business on May 26, 2009, whereby Mr. Parker resigned from his positions as Chairman of the Board, Chief Executive Officer and as a director of Delta, as well as his positions as a director, officer and employee of Delta’s subsidiaries. In consideration for Mr. Parker’s resignation and his agreement to (a) relinquish all his rights under his employment agreement, his change-in-control agreement, certain stock agreements, bonuses relating to past and pending transactions benefiting Delta, and any other interests he might claim arising from his efforts as Chairman of our Board of Directors and/or Chief Executive Officer, and (b) stay on as a consultant to facilitate an orderly transition and to assist in certain pending transactions, Delta agreed to pay Mr. Parker $4,700,000 in cash (the “Cash Consideration”), issue to him 1,000,000 shares of Delta common stock (the “Shares”), pay him the aggregate of any accrued unpaid salary, vacation days and reimbursement of his reasonable business expenses incurred through the effective date of the agreement, and provide to him insurance benefits similar to his pre-resignation benefits for a thirty-six month period. The Severance Agreement also contains mutual releases and non-disparagement provisions, as well as other customary terms.

The table below summarizes the total executive severance expense included in the accompanying statements of operations for the three and six months ended June 30, 2009 (in thousands):


Cash consideration – immediately available funds	$	1,812
Cash consideration – rabbi trust		2,888
Stock consideration – rabbi trust		1,700

Subtotal		6,400
Performance shares forfeited		(2,293	)
Retention stock forfeited		(525	)
Health, medical and other benefits payable		75
Legal costs and other expenses		82

Total executive severance expense	$	3,739

In accordance with the terms of the Severance Agreement, Mr. Parker received a portion of the cash consideration in immediately available funds, and the remaining cash consideration and the shares were deposited in a rabbi trust to be distributed to Mr. Parker on or about November 27, 2009. The assets of the rabbi trust are required to be consolidated into the financial statements of the Company as such assets are subject to the claims of the Company’s creditors under federal and state law. The cash consideration deposited into the rabbi trust is included in restricted deposits on the accompanying consolidated balance sheet of the Company, with an offsetting obligation to pay Mr. Parker reflected as executive severance payable in current liabilities. Stock consideration deposited into the rabbi trust is reflected as treasury stock valued at the market value of the common shares on the date of issuance in the accompanying consolidated balance sheet of the Company, with an offsetting amount recorded as executive severance payable in common stock included as a component of stockholders’ equity.

Equity compensation costs previously recorded in the consolidated financial statements related to performance shares forfeited prior to their derived service period and retention stock forfeited prior to vesting as a result of the Severance Agreement were reversed and reflected as a reduction of executive severance expense.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2009 and 2008
(Unaudited)

(3)		Summary of Significant Accounting Policies, Continued

		Stock Based Compensation

The Company follows SFAS No. 123 (Revised 2004) “Share Based Payment” (“SFAS 123R”) to value stock options and other equity based compensation issued to employees. The cost of share based payments is recognized over the period the employee provides service and is included in general and administrative expense in the statements of operations.

Income (Loss) from Unconsolidated Affiliates

Income (loss) from unconsolidated affiliates includes the Company’s share of earnings or losses from equity method investments. In addition, during the quarter ended June 30, 2009, the Company recognized an impairment of the carrying value of its investment in Delta Oilfield Tank Company (“DOTC”) of $2.1 million, which reduced the carrying value of the Company’s investment in DOTC to approximately $1.0 million. The impairment was precipitated by DOTC’s increasing losses during the second quarter of 2009 compared to prior periods and deterioration of its operating results compared to its budgeted results. During the quarter, the Company engaged third party investment advisers to assist in evaluating strategic alternatives relating to the Company’s investment in DOTC. The Company also recorded an impairment of $917,000 to write-off its carrying value in the entity that was expected to operate the Paradox pipeline as other plans related to the future of the entity did not materialize during the second quarter of 2009.

Income Taxes

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

Income (Loss) per Common Share

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

Use of Estimates

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

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2009 and 2008
(Unaudited)

(3)		Summary of Significant Accounting Policies, Continued

		Recently Adopted Accounting Pronouncements

In March 2008, the FASB affirmed FASB Staff Position (“FSP”) APB 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash Upon Conversion (Including Partial Cash Settlement)”. The FSP requires the proceeds from the issuance of convertible debt instruments to be allocated between a liability component (debt issued at a discount) and an equity component. The resulting debt discount is amortized over the period the convertible debt is expected to be outstanding as additional non-cash interest expense. The FSP was adopted effective January 1, 2009. This FSP changes the accounting treatment for the Company’s 3 ³ / 4 % Senior Convertible Notes issued April 25, 2007 and was applied retrospectively upon adoption. The fair value of the liability and equity components were determined based on the Company’s estimated borrowing rate at the date of issuance and, as a result, the liability component was approximately $92.7 million and the equity component was approximately $22.3 million. Based on these components at the issue date the Company recorded a reduction to the carrying value of the Notes of $22.3 million upon adoption of the FSP, with a corresponding increase in additional paid in capital. The accompanying consolidated financial statements include accretion of the resulting debt discount of approximately $1.1 million and $2.2 million for the three and six months ended June 30, 2009 and approximately $1.1 million and $2.1 million for the three and six months ended June 30, 2008. The remaining discount will be amortized through May 2012 when the holders of the Notes can first require the Company to purchase all or a portion of the Notes. Combined with the amortization of debt discount, the Notes have an effective interest rate of approximately 7.6% and 7.4% with total interest costs of $2.2 million and $2.1 million for the three month periods ended June 30, 2009 and 2008, respectively, and interest costs of $4.3 million and $4.2 million for the six month periods ended June 30, 2009 and 2008, respectively.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133 (“SFAS 161”). This Statement requires enhanced disclosures for derivative and hedging activities. This statement was effective for the Company on January 1, 2009. The Company has included the new required disclosures in these financial statements.

In December 2007, the FASB issued SFAS No. 160, “Non-controlling Interests in Consolidated Financial Statements – an amendment of Accounting Research Bulletin No. 51” (“SFAS 160”), which establishes accounting and reporting standards for non-controlling interests (“minority interests”) in subsidiaries. SFAS 160 clarifies that a non-controlling interest in a subsidiary should be accounted for as a component of equity separate from the parent’s equity. SFAS 160 was effective for the Company on January 1, 2009 and must be applied prospectively, except for the presentation and disclosure requirements, which have been applied retrospectively. The adoption of this statement had the effect of increasing total equity by the amount of the non-controlling interest and changing other presentations in the accompanying financial statements.

In April 2009, the FASB issued Staff Position (“FSP”) No. FAS 157-4, “Determining Fair Value When the Volume or Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly” (“FSP 157-4”). The adoption of FSP 157-4 is not expected to have a material impact on the Company’s consolidated financial statements, other than additional disclosures. FSP 157-4 provides additional guidance for estimating fair value in accordance with SFAS No. 157 when the volume and level of activity for the asset or liability have significantly decreased and requires that companies provide interim and annual disclosures of the inputs and valuation technique(s) used to measure fair value. FSP 157-4 was effective for interim and annual reporting periods ending after June 15, 2009 with such disclosures included herein as applicable.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2009 and 2008
(Unaudited)

(3)

Summary of Significant Accounting Policies, Continued

In April 2009, the FASB issued FSP No. 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments” (“FSP 107-1”). The adoption of FSP 107-1 is not expected to have an impact on the Company’s consolidated financial statements, other than requiring additional disclosures. FSP 107-1 requires disclosures about fair value of financial instruments in financial statements for interim reporting periods of publicly traded companies as well as in annual financial statements. FSP 107-1 is effective for interim and annual reporting periods ending after June 15, 2009. Such disclosures have been included herein as applicable.

In May 2009, the FASB issued SFAS 165, “Subsequent Events.” The objective of this Statement is to establish general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. In particular, this Statement sets forth the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements; the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements; and the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. SFAS No. 165 was effective for the Company beginning with the Quarterly Report on Form 10-Q for the quarter ended June 30, 2009. The implementation of this standard did not have a material impact on the Company’s financial statements. Subsequent events were evaluated through the date of issuance of these consolidated financial statements on August 6, 2009 at the time this Quarterly Report on Form 10-Q was filed with the Securities and Exchange Commission.

Recently Issued Financial Reporting Pronouncements

On December 31, 2008, the SEC published final rules and interpretations updating its oil and gas reporting requirements. Many of the revisions are updates to definitions in the existing oil and gas rules to make them consistent with the Petroleum Resource Management System, which is a widely accepted standard for the management of petroleum resources that was developed by several industry organizations. Key revisions include the ability to include nontraditional resources in reserves, the use of new technology for determining reserves, permitting disclosure of probable and possible reserves, and changes to the pricing used to determine reserves based on a 12-month average price rather than a period end spot price. The average is to be calculated using the first-day-of-the-month price for each of the 12 months that make up the reporting period. The new rules are effective for annual reports for fiscal years ending on or after December 31, 2009. Early adoption is not permitted. The Company is currently assessing the impact that the adoption will have on its consolidated financial statements and disclosures.

(4)

Oil and Gas Properties

Unproved Undeveloped Offshore California Properties

Prior to June 30, 2009, the Company owned direct and indirect ownership interests ranging from 2.49% to 100% in five unproved undeveloped offshore oil and gas properties near Santa Barbara, California with an aggregate carrying value of $17.0 million at December 31, 2008. These property interests represented the right to explore for, develop and produce oil and gas from offshore federal lease units. The ownership rights in each of these properties were retained under various suspension notices issued by the Mineral Management Service (MMS) of the U.S. federal government whereby, as long as the owners of each property were progressing toward defined milestone objectives, the owners’ rights with respect to the properties continued to be maintained. The issuance of the suspension notices was necessitated by the numerous delays in the exploration and development process resulting from regulatory requirements imposed on the property owners by federal, state and local agencies.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2009 and 2008
(Unaudited)

(4)

Oil and Gas Properties , Continued

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

Further actions to develop the leases were then delayed, however, pending the outcome of a separate lawsuit (the “Amber Case”) that was filed in the United States Court of Federal Claims (the “Court”) in Washington, D.C. by the Company, its 92%-owned subsidiary, Amber Resources Company of Colorado (“Amber”), and ten other property owners alleging that the U.S. government materially breached the terms of 40 undeveloped federal leases, some of which were part of the Company’s and Amber’s offshore California properties. On November 15, 2005 and October 31, 2006, the Court granted summary judgment as to liability and partial summary judgment as to damages with respect to 36 of the 40 total federal leases that are the subject of the litigation. Under a restitution theory of damages, the Court ruled that the government must return to the current lessees the more than $1.1 billion in lease bonuses it had received at the time of sale. On January 12, 2008, the Court entered an order of final judgment awarding the lessees restitution of the original lease bonuses paid for 35 of the 40 lawsuit leases. Under this order, in May of 2009 the Company received a gross amount of approximately $58.5 million and Amber received a gross amount of approximately $1.5 million as reimbursement for the lease bonuses paid for all lawsuit leases other than Lease 452, which is a single lease owned entirely by the Company and separated from the main body of the litigation by a motion for reconsideration, as discussed below. During May 2009, prior to receipt of the settlement proceeds, the Company purchased for $26.0 million contingent payment rights previously sold to Tracinda Corporation (“Tracinda”) that entitled Tracinda to receive up to $27.9 million of the litigation proceeds related to the Amber Case. Subsequent to the receipt of the litigation proceeds, the Company paid $11.3 million for overrides and other participating interests payable related to the judgment.

As mentioned above, Lease 452 was separated from the main body of the litigation by a motion filed by the government on January 19, 2006 seeking reconsideration of the Court’s ruling as it related to Lease 452. In seeking reconsideration, the government asserted that the Company should not be able to recover lease bonus payments for Lease 452 because, allegedly, a significant portion of the hydrocarbons had been drained by wells that were drilled on an immediately adjacent lease. The amount of lease bonus payments attributable to Lease 452 is approximately $91.4 million. A trial on the motion for reconsideration was completed in January 2008 and oral arguments were completed in June 2008. On February 25, 2009 the Court entered a judgment in the Company’s favor in the amount of $91.4 million with respect to its claim to recover lease bonus payments for Lease 452. On April 24, 2009 the government filed a notice of appeal of this judgment, but it has not yet filed its opening brief.

Overriding royalty interests in certain litigation proceeds were granted in connection with the acquisition and financing of Lease 452 (among others) in December 1999. As a result of these overrides, Kaiser-Francis Oil Company may be entitled to receive 5% of the net amount of the litigation proceeds received from Lease 452, BWAB Limited Liability Company may be entitled to receive 3%, and each of Aleron H. Larson, Jr. and Roger A. Parker may be entitled to receive 1%. Pursuant to an agreement dated November 2, 2000, the Company is also obligated to pay the owners of the Point Arguello Unit 20% of the net cash amount of litigation proceeds received from Lease 452 after deducting all compensation to be paid to attorneys and all reasonable and necessary expenses incurred. The net amount of these payments is currently estimated to be approximately $23.0 million.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2009 and 2008
(Unaudited)

(4)		Oil and Gas Properties , Continued

		Discontinued Operations

In accordance with SFAS No. 144, the results of operations and the gain (loss) relating to the sale of discontinued properties have been reflected as discontinued operations. For the three months ended June 30, 2009, there were no discontinued operations and for the three months ended June 30, 2008, gain on sale of discontinued operations includes a minor adjustment to the gain on a previously disposed of property.

(5)

DHS Drilling

During May 2009, DHS sold Rig #7 to Naknek Electric Association for cash proceeds of $7.8 million with a resulting gain of $1.6 million. The proceeds were used to reduce debt outstanding under the DHS credit facility (See Note 7, “Long Term Debt”).

The carrying value of DHS’s drilling rigs and related equipment are assessed for impairment whenever circumstances indicate an impairment may exist. During the quarter ended June 30, 2009, the fleet rig utilization rate declined approximately 68% from the first quarter of 2009 and the average period end contract day rate declined by approximately 29% from the first quarter of 2009. In addition, DHS’s efforts to market spare equipment and observations at industry auctions indicated that with industry-wide active rig counts in decline, spare equipment values had declined. As a result of these indicators of possible impairment, an analysis was performed and an impairment of $6.5 million was recorded to reduce the carrying value of three drilling rigs and other spare rig equipment to their respective fair values.

(6)

Fair Value Measurements

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

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

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

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

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

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

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2009 and 2008
(Unaudited)

(6)

Fair Value Measurements, Continued

The following table lists the Company’s fair value measurements by hierarchy as of June 30, 2009 (in thousands):


	Quoted Prices		Significant			Significant
	in Active Markets		Other Observable			Unobservable
	for Identical Assets		Inputs			Inputs		Total
Assets (Liabilities)	(Level 1)		(Level 2)			(Level 3)		June 30, 2009

Available for sale securities	$	-	$	-		$	1,977	$	1,977

Derivative liabilities	$	-	$	(21,111	)	$	-	$	(21,111	)

There was no change in the value of the Company’s Level 3 assets measured at fair value on a recurring basis using significant unobservable inputs for the three months ended June 30, 2009.

(7)		Long Term Debt

		Installments Payable on Property Acquisition

On February 28, 2008, the Company closed a transaction with EnCana to jointly develop a portion of EnCana’s leasehold in the Vega Area of the Piceance Basin. The remaining installments payable are recorded in the accompanying consolidated financial statements as current and long-term liabilities at a discounted value. The discount is being accreted on the effective interest method over the term of the installments, including accretion of $1.9 million and $3.7 million for the three and six months ended June 30, 2009, respectively.

7% Senior Unsecured Notes, due 2015

On March 15, 2005, the Company issued 7% senior unsecured notes for an aggregate principal amount of $150.0 million. The Company was in compliance with the covenants under the indenture as of June 30, 2009 (See Note 12, “Guarantor Financial Information”). The fair value of the Company’s senior unsecured notes at June 30, 2009 was approximately $83.0 million.

3 ³ / 4 % Senior Convertible Notes, due 2037

On April 25, 2007, the Company issued $115.0 million aggregate principal amount of 3 ³ / 4 % Senior Convertible Notes due 2037 (the “Notes”) for net proceeds of $111.6 million after underwriters’ discounts and commissions of approximately $3.4 million. The Notes were recorded based on the estimated fair value of the liability component and the equity component, initially $92.7 million for the liability component and $22.3 million for the equity component. The debt discount on the liability component is accreted over the expected life of the Notes, including $1.1 million of accretion for each of the three months ended June 30, 2009 and 2008, and $2.2 million and $2.1 million of accretion for the six months ended June 30, 2009 and 2008, respectively. Combined with the amortization of debt discount, the Notes have an effective interest rate of approximately 7.6% and 7.4% with total interest costs of $2.2 million and $2.1 million for the three month periods ended June 30, 2009 and 2008, respectively, and interest costs of $4.3 million and $4.2 million for the six month periods ended June 30, 2009 and 2008, respectively. The fair value of the Notes at June 30, 2009 was approximately $67.3 million.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2009 and 2008
(Unaudited)

(7)		Long Term Debt, Continued

		Credit Facility – Delta

On March 2, 2009, the Company entered into the First Amendment to the Second Amended and Restated Credit Agreement (the “Forbearance Agreement and Amendment to the Credit Facility”), as further amended on April 14, 2009 and on April 30, 2009, with JPMorgan Chase Bank, N.A., as agent, and certain of the financial institutions that are party to its credit agreement in which, among other changes, the lenders provided the Company relief for a period ended May 15, 2009 from acting upon their rights and remedies as a result of the Company’s violation of accounts payable and current ratio covenants. The Forbearance Agreement and Amendment to the Credit Facility replaced the previous consolidated net debt to consolidated EBITDAX covenant with a senior secured debt to consolidated EBITDAX requirement for the preceding four consecutive fiscal quarters to be less than 4.0 to 1.0. In accordance with the Forbearance Agreement and Amendment to the Credit Facility, the borrowing base was reduced upon the successful completion of the Company’s capital raising efforts from $295.0 million to $225.0 million, with a conforming borrowing base of $185.0 million until the next scheduled redetermination date (September 1, 2009). The revised variable interest rates are based on the ratio of outstanding borrowings to the conforming borrowing base and vary between Libor plus 2.5% to Libor plus 5.0% for Eurodollar loans and prime plus 1.625% to prime plus 4.125% for base rate loans. The Forbearance Agreement and Amendment to the Credit Facility changed the maturity date to January 15, 2011. The Forbearance Agreement and Amendment to the Credit Facility also required that the Company execute derivative contracts to put in place a commodity floor price for anticipated production equal to a minimum of 40% for the last two quarters of 2009, 70% for the calendar year 2010 and 50% for the calendar year 2011.

On May 13, 2009, the Company completed an underwritten stock offering resulting in $247.2 million of net proceeds. As a result, borrowings under the credit facility were reduced from $293.8 million at March 31, 2009 to $83.0 million at June 30, 2009, with remaining availability of $140.8 million based on the revised $225.0 million borrowing base, after allowing for outstanding letters of credit of $1.2 million.

Although the Company was in compliance with its financial covenants at June 30, 2009, the amounts outstanding under the credit facility have been classified as a current liability in the accompanying consolidated balance sheets, as projections indicate that without an increase in Rocky Mountain natural gas prices upon which the majority of the Company’s production is sold the senior secured debt to EBITDAX ratio covenant could be violated within the next twelve months. The Company is currently in discussions with its bank group regarding future covenant modifications or waivers, but there can be no assurance that the banks will agree to any such changes.

Credit Facility – DHS

On August 15, 2008, DHS entered into a new agreement with LCPI to amend its existing credit facility. The revised agreement increased the borrowing base from $75.0 million to $150.0 million. Total debt outstanding at June 30, 2009 under the facility was $83.3 million. Because of LCPI’s bankruptcy and default, DHS does not have any additional borrowing capacity under the LCPI facility. Under the revised agreement, DHS has an obligation to provide to LCPI by March 31 of each year audited financial statements reported on without a going concern qualification or exception by the independent auditor. DHS was not able to provide audited financial statements not containing an explanatory paragraph related to its ability to continue as a going concern, and, accordingly, DHS was not in compliance with this covenant at March 31, 2009.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2009 and 2008
(Unaudited)

(7)

Long Term Debt, Continued

On April 22, 2009, DHS entered into a Forbearance Agreement (the “DHS Forbearance”), as amended on May 21, 2009, with LCPI in which LCPI agreed to forbear until June 15, 2009 from exercising its rights and remedies under the credit agreement including, among other actions, acceleration of all amounts due under the credit facility or foreclosure on the DHS rigs and other assets pledged as collateral, including accounts receivable. The DHS facility is non-recourse to Delta.

In conjunction with the DHS Forbearance, DHS paid a fee of $250,000 and made a $1.25 million prepayment on the facility. During the forbearance period, DHS must use 75% of any accounts receivable collected as well as proceeds from asset dispositions to pay down its credit facility. As of June 30, 2009, DHS had customer receivables of $28.5 million, $25.8 million of which are due from Delta. At June 30, 2009, DHS was not in compliance with its minimum EBITDA, maximum leverage ratio, minimum interest coverage ratio and minimum current ratio financial covenants. As a result of these events, the Company has classified the entire $83.3 million of debt outstanding under the DHS credit facility as a current liability in the accompanying consolidated balance sheet as of June 30, 2009. In addition, due to the expiration of the DHS Forbearance and the June 30, 2009 financial covenant violations, LCPI currently has the right to demand payment of the amounts outstanding under the credit facility and if not paid, foreclose on the DHS assets pledged as collateral for the credit facility. Although LCPI has not exercised its right to foreclose on the DHS assets pledged as collateral and DHS is currently in negotiations with LCPI to amend the terms of the credit facility, there can be no assurance that LCPI will not exercise its right to foreclose on the DHS assets pledged as collateral. As a result of these events, DHS wrote off $643,000 of previously unamortized deferred financing costs related to its LCPI credit agreement.

(8)

Stockholders’ Equity

Preferred Stock

The Company has 3,000,000 shares of preferred stock authorized, issuable from time to time in one or more series. As of June 30, 2009 and December 31, 2008, no shares of preferred stock were outstanding.

Common Stock

On May 13, 2009, the Company completed an underwritten offering of 172.5 million shares of the Company’s common stock at $1.50 per share for net proceeds of $247.2 million, net of underwriting commissions and related offering expenses.

During the three months ended June 30, 2009, 12,000 shares of restricted common stock were issued to directors of the Company as a component of their annual compensation. In addition, in conjunction with the resignation of the Company’s former Chairman and Chief Executive Officer, 1.0 million shares were issued pursuant to a severance agreement which also resulted in the forfeiture of 100,000 performance shares and 85,000 unvested retention shares. Finally, approximately 99,000 shares of restricted common stock were forfeited during the quarter, the majority of which were forfeited by employees who were subject to a second reduction in force which occurred in mid June 2009.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2009 and 2008
(Unaudited)

(8)		Stockholders’ Equity, Continued

		Treasury Stock

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

On May 26, 2009, the Company’s then Chairman of the Board of Directors and Chief Executive Officer, Roger A. Parker, resigned from the Company. In conjunction with Mr. Parker’s resignation, Delta entered into a Severance Agreement and, among other terms, issued to a rabbi trust 1,000,000 shares of Delta common stock. Stock consideration deposited into the rabbi trust is reflected as treasury stock valued at the market value of the common shares on the date of issuance in the accompanying consolidated balance sheet of the Company, with an offsetting amount recorded as executive severance payable in common stock, included as a component of stockholders’ equity. The shares and cash in the rabbi trust will be distributed to Mr. Parker on or about November 27, 2009.

Stock Based Compensation

The Company recognized stock compensation included in general and administrative expense as follows (in thousands):


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2009		2008		2009		2008

Non-vested stock	$	1,157	$	2,205	$	2,935	$	4,163
Performance shares		717		1,772		1,704		3,687

Total	$	1,874	$	3,977	$	4,639	$	7,850

The Company recognizes the cost of share based payments over the period during which the employee provides service. As all outstanding stock options are vested, no compensation cost was recognized with respect to stock options in any of the periods shown in the table above. Exercise prices for options outstanding under the Company’s various plans as of June 30, 2009 ranged from $1.87 to $15.34 per share and the weighted-average remaining contractual life of those options was 4.79 years. The Company has not issued stock options since the adoption of SFAS 123R, although it has the discretion to issue options again in the future. At June 30, 2009, the Company had 1,427,750 options outstanding at a weighted average exercise price of $8.21. At June 30, 2009, the Company had 1,563,000 non-vested shares outstanding and 150,000 performance shares outstanding.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2009 and 2008
(Unaudited)

(9)

Income Taxes

The Company accounts for income taxes in accordance with the provisions of SFAS No. 109. Income tax expense (benefit) attributable to loss from continuing operations was approximately $265,000 and $(860,000) for the three months ended June 30, 2009 and 2008, respectively.

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future results of operations, and tax planning strategies in making this assessment. Based upon the level of historical taxable income, significant book losses during the current and prior periods, and projections for future results of operations over the periods in which the deferred tax assets are deductible, among other factors, management continues to conclude that the Company does not meet the “more likely than not” requirement of SFAS 109 in order to recognize deferred tax assets and a valuation allowance has been recorded for the Company’s net deferred tax assets at June 30, 2009. During the quarter ended June 30, 2009, DHS recorded significant net operating losses and as of June 30, 2009 DHS’s deferred tax assets exceeded its deferred tax liabilities. Accordingly, based on significant recent operating losses and projections for future results, a valuation allowance was recorded for DHS’s net deferred tax assets.

During the remainder of 2009 and thereafter, the Company will continue to assess the realizability of its deferred tax assets based on consideration of actual and projected operating results and tax planning strategies. Should actual operating results improve, the amount of the deferred tax asset considered more likely than not to be realizable could be increased. Such a change in the assessment of realizability could result in a decrease to the valuation allowance and corresponding income tax benefit, both of which could be significant.

The Company previously adopted the provisions of FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes – An Interpretation of FASB Statement No. 109 , or FIN 48. FIN 48 provides detailed guidance for the financial statement recognition, measurement and disclosure of uncertain tax positions recognized in the financial statements in accordance with SFAS No. 109. Tax positions must meet a “more-likely-than-not” recognition threshold at the effective date to be recognized upon the adoption of FIN 48 and in subsequent periods. Upon the adoption of FIN 48, the Company had no unrecognized tax benefits. During the three and six months ended June 30, 2009 and 2008, no adjustments were recognized for uncertain tax benefits.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2009 and 2008
(Unaudited)

(10)

Earnings Per Share

The following table sets forth the computation of basic and diluted earnings per share (in thousands, except per share amounts):


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008

Net loss attributable to Delta common stockholders	$	(172,318	)	$	(23,387	)	$	(197,871	)	$	(44,169	)

Basic weighted-average common shares outstanding		193,028			101,057			146,248			90,563
Add: dilutive effects of stock options and unvested stock grants		-			-			-			-

Diluted weighted-average common shares outstanding		193,028			101,057			146,248			90,563


Net income (loss) per common share attributable to Delta common stockholders
Basic	$	(0.89	)	$	(0.23	)	$	(1.35	)	$	(0.49	)

Diluted	$	(0.89	)	$	(0.23	)	$	(1.35	)	$	(0.49	)

Potentially dilutive securities excluded from the calculation of diluted shares outstanding include the following: 3,790,000 shares issuable upon conversion of the 3 ³ / 4 % Senior Convertible Notes for each period presented; 150,000 and 750,000 shares issuable pursuant to the February 9, 2008 performance share grants for the three months ended June 30, 2009 and 2008, respectively; 150,000 and 750,000 shares issuable pursuant to the February 9, 2008 performance share grants for the six months ended June 30, 2009 and 2008, respectively; 1,427,750 and 1,636,250 stock options for the three months ended June 30, 2009 and 2008, respectively; 1,427,750 and 1,636,250 stock options for the six months ended June 30, 2009 and 2008, respectively; 1,563,000 and 1,343,000 unvested shares issuable upon vesting under various employee restricted stock grants for the three months ended June 30, 2009 and 2008, respectively; and 1,563,000 and 1,343,000 unvested shares issuable upon vesting under various employee restricted stock grants for the six months ended June 30, 2009 and 2008, respectively.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2009 and 2008
(Unaudited)

(11)

Guarantor Financial Information

On March 15, 2005, Delta issued $150.0 million of 7% senior notes (“Senior Notes”) that mature in 2015. In addition, on April 25, 2007, the Company issued $115.0 million of 3 ³ / 4 % Convertible Senior Notes due in 2037 (“Convertible Notes”). Both the Senior Notes and the Convertible Notes are guaranteed by all of the Company’s wholly-owned subsidiaries (“Guarantors”). Each of the Guarantors, fully, jointly and severally, irrevocably and unconditionally guarantees the performance and payment when due of all the obligations under the Senior Notes and the Convertible Notes. DHS, CRBP, PGR, and Amber (“Non-guarantors”) are not guarantors of the indebtedness under the Senior Notes or the Convertible Notes.

The following financial information sets forth the Company’s condensed consolidated balance sheets as of June 30, 2009 and December 31, 2008, the condensed consolidated statements of operations for the three and six months ended June 30, 2009 and 2008, and the condensed consolidated statements of cash flows for the six months ended June 30, 2009 and 2008 (in thousands). For purposes of the condensed financial information presented below, the equity in the earnings or losses of subsidiaries is not recorded in the financial statements of the issuer.

Condensed Consolidated Balance Sheet
June 30, 2009


				Guarantor			Non-Guarantor				Adjustments/
	Issuer			Entities				Entities			Eliminations			Consolidated

Current assets	$	105,168		$	520			$	35,365		$	-		$	141,053

Property and equipment:
Oil and gas properties		1,591,973			507				128,592			(606	)		1,720,466
Drilling rigs and trucks		594			-				181,599			-			182,193
Other		73,180			37,568				1,956			-			112,704

Total property and equipment		1,665,747			38,075				312,147			(606	)		2,015,363

Accumulated depletion, depreciation and amortization		(595,356	)		(23,914	)			(109,914	)		-			(729,184	)


Net property and equipment		1,070,391			14,161				202,233			(606	)		1,286,179

Investment in subsidiaries		97,321			-				-			(97,321	)		-
Other long-term assets		231,818			3,779				195			-			235,292


Total assets	$	1,504,198		$	18,460			$	237,793		$	(97,927	)	$	1,662,524


Current liabilities	$	329,545		$	157			$	36,870		$	-		$	366,572

Long-term liabilities
Long-term debt, derivative instruments, and deferred taxes		399,175			1,735				54,898			-			455,808
Asset retirement obligations and other liabilities		7,779			10				277			-			8,066


Total long-term liabilities		406,954			1,745				55,175			-			463,874

Total Delta stockholders’ equity		750,501			16,558				145,748			(97,927	)		814,880

Non-controlling interest		17,198			-				-			-			17,198


Total equity		767,699			16,558				145,748			(97,927	)		832,078


Total liabilities and equity	$	1,504,198		$	18,460			$	237,793		$	(97,927	)	$	1,662,524

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2009 and 2008
(Unaudited)

(11)

Guarantor Financial Information, Continued

Condensed Consolidated Balance Sheet
December 31, 2008


				Guarantor			Non-Guarantor				Adjustments/
	Issuer			Entities				Entities			Eliminations			Consolidated

Current assets	$	167,536		$	591			$	54,630		$	-		$	222,757

Property and equipment:
Oil and gas properties		1,681,804			503				110,650			(11,944	)		1,781,013
Drilling rigs and trucks		594			-				193,629			-			194,223
Other		76,932			36,359				1,892			-			115,183

Total property and equipment		1,759,330			36,862				306,171			(11,944	)		2,090,419

Accumulated depletion, depreciation and amortization		(544,154	)		(21,896	)			(92,229	)		-			(658,279	)


Net property and equipment		1,215,176			14,966				213,942			(11,944	)		1,432,140

Investment in subsidiaries		141,827			-				-			(141,827	)		-
Other long-term assets		235,560			3,825				681			-			240,066


Total assets	$	1,760,099		$	19,382			$	269,253		$	(153,771	)	$	1,894,963


Current liabilities	$	550,876		$	172			$	13,480		$	-		$	564,528

Long-term liabilities
Long-term debt, derivative instruments, and deferred taxes		435,684			1,800				94,872			-			532,356
Asset retirement obligations and other liabilities		6,307			10				268			-			6,585


Total long-term liabilities		441,991			1,810				95,140			-			538,941

Total Delta stockholders’ equity		738,128			17,400				160,633			(153,771	)		762,390

Non-controlling interest		29,104			-				-			-			29,104


Total equity		767,232			17,400				160,633			(153,771	)		791,494


Total liabilities and equity	$	1,760,099		$	19,382			$	269,253		$	(153,771	)	$	1,894,963

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2009 and 2008
(Unaudited)

(11)

Guarantor Financial Information, Continued

Condensed Consolidated Statement of Operations
Three Months Ended June 30, 2009


				Guarantor			Non-Guarantor				Adjustments/
	Issuer			Entities				Entities			Eliminations			Consolidated

Total revenue	$	16,579		$	120			$	6,908		$	(665	)	$	22,942

Operating expenses:
Oil and gas expenses		5,202			27				5,902			-			11,131
Exploration expense		471			-				-			-			471
Dry hole costs and impairments		98,217			1,896				6,508			-			106,621
Depreciation and depletion		(798	)		33,177				3,895			(167	)		36,107
Drilling and trucking operations		1			-				2,719			(378	)		2,342
General and administrative		7,846			28				1,092			-			8,966
Executive severance expense		3,739			-				-			-			3,739


Total operating expenses		114,678			35,128				20,116			(545	)		169,377


Operating income (loss)		(98,099	)		(35,008	)			(13,208	)		(120	)		(146,435	)

Other income and (expenses)		(31,819	)		20				(1,984	)		-			(33,783	)
Income tax benefit (expense)		(265	)		-				-			-			(265	)
Discontinued operations		-			-				-			-			-


Net loss		(130,183	)		(34,988	)			(15,192	)		(120	)		(180,483	)

Less loss attributable to non-controlling interest		8,165			-				-			-			8,165


Net income (loss) attributable to Delta common stockholders	$	(122,018	)	$	(34,988	)		$	(15,192	)	$	(120	)	$	(172,318	)

Condensed Consolidated Statement of Operations
Three Months Ended June 30, 2008


				Guarantor		Non-Guarantor				Adjustments/
	Issuer			Entities			Entities			Eliminations			Consolidated

Total revenue	$	69,473		$	251		$	25,897		$	(14,514	)	$	81,107

Operating expenses:
Oil and gas expenses		14,908			35			721			-			15,664
Exploration expense		1,933			-			-			-			1,933
Dry hole costs and impairments		430			-			-			-			430
Depreciation and depletion		23,627			6			6,997			(2,670	)		27,960
Drilling and trucking operations		(1	)		-			13,125			(7,595	)		5,529
General and administrative		12,527			25			1,274			-			13,826


Total operating expenses		53,424			66			22,117			(10,265	)		65,342


Operating income (loss)		16,049			185			3,780			(4,249	)		15,765

Other income and (expenses)		(37,991	)		10			(1,773	)		(121	)		(39,875	)
Income tax benefit (expense)		995			-			(135	)		-			860
Discontinued operations		(16	)		-			-			-			(16	)


Net loss		(20,963	)		195			1,872			(4,370	)		(23,266	)

Less (income) loss attributable to non-controlling interest		(121	)		-			-			-			(121	)


Net income (loss) attributable to Delta common stockholders	$	(21,084	)	$	195		$	1,872		$	(4,370	)	$	(23,387	)

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2009 and 2008
(Unaudited)

(11)

Guarantor Financial Information, Continued

Condensed Consolidated Statement of Operations
Six Months Ended June 30, 2009


				Guarantor			Non-Guarantor				Adjustments/
	Issuer			Entities				Entities			Eliminations			Consolidated

Total revenue	$	72,006		$	200			$	12,325		$	(2,933	)	$	81,598

Operating expenses:
Oil and gas expenses		17,988			72				7,752			-			25,812
Exploration expense		1,531			-				-			-			1,531
Dry hole costs and impairments		99,660			1,896				6,508			-			108,064
Depreciation and depletion		23,397			33,238				12,665			(579	)		68,721
Drilling and trucking operations		-			-				9,347			(1,749	)		7,598
General and administrative		19,248			35				2,311			-			21,594
Executive severance expense		3,739			-										3,739


Total operating expenses		165,563			35,241				38,583			(2,328	)		237,059


Operating income (loss)		(93,557	)		(35,041	)			(26,258	)		(605	)		(155,461	)

Other income and (expenses)		(50,829	)		20				(3,965	)		-			(54,774	)
Income tax benefit (expense)		(476	)		-				794			-			318
Discontinued operations		-			-				-			-			-


Net loss		(144,862	)		(35,021	)			(29,429	)		(605	)		(209,917	)

Less loss attributable to non-controlling interest		12,046			-				-			-			12,046


Net income (loss) attributable to Delta common stockholders	$	(132,816	)	$	(35,021	)		$	(29,429	)	$	(605	)	$	(197,871	)

Condensed Consolidated Statement of Operations
Six Months Ended June 30, 2008


				Guarantor		Non-Guarantor				Adjustments/
	Issuer			Entities			Entities			Eliminations			Consolidated

Total revenue	$	120,152		$	443		$	49,289		$	(24,297	)	$	145,587

Operating expenses:
Oil and gas expenses		27,931			68			1,120			-			29,119
Exploration expense		2,935			-			-			-			2,935
Dry hole costs and impairments		2,769			-			-			-			2,769
Depreciation and depletion		45,656			13			13,563			(4,590	)		54,642
Drilling and trucking operations		(1	)		-			25,781			(13,428	)		12,352
General and administrative		24,594			49			2,604			-			27,247


Total operating expenses		103,884			130			43,068			(18,018	)		129,064


Operating income (loss)		16,268			313			6,221			(6,279	)		16,523

Other income and (expenses)		(58,834	)		34			(3,769	)		208			(62,361	)
Income tax benefit (expense)		1,222			-			235			-			1,457
Discontinued operations		4			-			-			-			4


Net income (loss)		(41,340	)		347			2,687			(6,071	)		(44,377	)

Less loss attributable to non-controlling interest		208			-			-			-			208


Net income (loss) attributable to Delta common stockholders	$	(41,132	)	$	347		$	2,687		$	(6,071	)	$	(44,169	)

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2009 and 2008
(Unaudited)

(11)

Guarantor Financial Information, Continued

Condensed Consolidated Statement of Cash Flows
Six Months Ended June 30, 2009


				Guarantor			Non-Guarantor
	Issuer			Entities				Entities			Consolidated
Cash provided by (used in):
Operating activities	$	29,117		$	95			$	3,637		$	32,849
Investing activities		(119,797	)		(152	)			4,626			(115,323	)
Financing activities		33,313			-				(10,570	)		22,743


Net increase (decrease) in cash and cash equivalents		(57,367	)		(57	)			(2,307	)		(59,731	)

Cash at beginning of the period		60,993			151				4,331			65,475


Cash at the end of the period	$	3,626		$	94			$	2,024		$	5,744

Condensed Consolidated Statement of Cash Flows
Six Months Ended June 30, 2008


				Guarantor			Non-Guarantor
	Issuer			Entities				Entities			Consolidated
Cash provided by (used in):
Operating activities	$	40,190		$	317			$	8,876		$	49,383
Investing activities		(677,906	)		(412	)			(43,080	)		(721,398	)
Financing activities		635,496			-				35,325			670,821


Net increase (decrease) in cash and cash equivalents		(2,220	)		(95	)			1,121			(1,194	)

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


Cash at the end of the period	$	2,438		$	212			$	5,949		$	8,599

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2009 and 2008
(Unaudited)

(12)

Business Segments

The Company has two reportable segments: oil and gas exploration and production (“Oil and Gas”) and drilling and trucking operations (“Drilling”) through its ownership in DHS. Following is a summary of segment results for the three and six months ended June 30, 2009 and 2008:


							Inter-segment
	Oil and Gas			Drilling			Eliminations				Consolidated
	(In thousands)
Three Months Ended June 30, 2009
Revenues from external customers	$	21,268		$	1,674			$	-		$	22,942
Inter-segment revenues		-			665				(665	)		-

Total revenues	$	21,268		$	2,339			$	(665	)	$	22,942

Operating income (loss)	$	(126,611	)	$	(19,704	)		$	(120	)	$	(146,435	)

Other income (expense)		(31,798	)		(1,985	)			-			(33,783	)

Income (loss) from continuing operations, before tax	$	(158,409	)	$	(21,689	)		$	(120	)	$	(180,218	)


Three Months Ended June 20, 2008
Revenues from external customers	$	73,232		$	7,875			$	-		$	81,107
Inter-segment revenues		-			14,514				(14,514	)		-

Total revenues	$	73,232		$	22,389			$	(14,514	)	$	81,107

Operating income (loss)	$	17,872		$	2,142			$	(4,249	)	$	15,765

Other income (expense)		(37,987	)		(1,767	)			(121	)		(39,875	)

Income (loss) from continuing operations, before tax	$	(20,115	)	$	375			$	(4,370	)	$	(24,110	)


Six Months Ended June 30, 2009
Revenues from external customers	$	74,711		$	6,887			$	-		$	81,598
Inter-segment revenues		-			2,933				(2,933	)		-

Total revenues	$	74,711		$	9,820			$	(2,933	)	$	81,598

Operating income (loss)	$	(128,608	)	$	(26,248	)		$	(605	)	$	(155,461	)

Other income (expense)		(50,807	)		(3,967	)			-			(54,774	)

Income (loss) from continuing operations, before tax	$	(179,415	)	$	(30,215	)		$	(605	)	$	(210,235	)


Six Months Ended June 20, 2008
Revenues from external customers	$	126,992		$	18,595			$	-		$	145,587
Inter-segment revenues		-			24,297				(24,297	)		-

Total revenues	$	126,992		$	42,892			$	(24,297	)	$	145,587

Operating income (loss)	$	19,679		$	3,123			$	(6,279	)	$	16,523

Other income (expense)		(58,794	)		(3,775	)			208			(62,361	)

Income (loss) from continuing operations, before tax	$	(39,115	)	$	(652	)		$	(6,071	)	$	(45,838	)


June 30, 2009:
Total Assets	$	1,608,367		$	120,747			$	(66,590	)	$	1,662,524


December 31, 2008:
Total Assets	$	1,797,683		$	163,240			$	(65,960	)	$	1,894,963

Other income and expense includes interest and financing costs, gain on sale of marketable securities, unrealized losses on derivative instruments and other miscellaneous income. Non-controlling interests are included in inter-segment eliminations.


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

Forward Looking Statements

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

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

These statements by their nature are subject to certain risks, uncertainties and assumptions and will be influenced by various factors. Should any of the assumptions underlying a forward-looking statement prove incorrect, actual results could vary materially. In some cases, information regarding certain important factors that could cause actual results to differ materially from any forward-looking statement appears together with such statement. In addition, the factors described under “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2008, as well as other possible factors not listed, could cause actual results to differ materially from those expressed in forward-looking statements, including, without limitation, the following:

•

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

•

the availability of capital on an economic basis, or at all, to fund the required payments under our credit agreement, our working capital needs, and drilling and leasehold acquisition programs, including through potential joint ventures and asset monetization transactions;

•

lower natural gas and oil prices negatively affecting our ability to borrow or raise capital, or enter into joint venture arrangements and potentially requiring accelerated repayment of amounts borrowed under our revolving credit facility;

•

declines in the values of our natural gas and oil properties resulting in write-downs;

•

the impact of the current financial market instability and economic downturn on our ability to raise capital;

•

a contraction in the demand for natural gas in the U.S. as a result of deteriorating general economic conditions;

•

the risk that lenders under our credit agreements will default in funding borrowings as requested;

•

the ability and willingness of counterparties to our commodity derivative contracts, if any, to perform their obligations;

•

the ability and willingness of our joint venture partners to fund their obligations to pay a portion of our future drilling and completion costs;

•

expiration of oil and natural gas leases that are not held by production;

•

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

•

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

•

timing, amount, and marketability of production;

•

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

•

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

•

the availability of borrowings under our credit facility;

•

effectiveness of management strategies and decisions;

•

the strength and financial resources of our competitors;

•

climatic conditions;

•

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

•

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

•

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

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

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

Recent Developments

•

On May 13, 2009, we completed an underwritten public offering of 172.5 million shares of our common stock at $1.50 per share for net proceeds of $247.2 million, net of underwriting commissions and related offering expenses.

•

On May 19, 2009, we received from the U.S. government $60.0 million of offshore litigation proceeds related to the Amber Case and in early June 2009 we paid out $11.3 million of overrides payable related to this litigation. With respect to the remaining offshore litigation, on February 25, 2009 the Court entered a judgment in our favor in the amount of $91.4 million with respect to our claim to recover lease bonus payments for Lease 452. On April 24, 2009 the government filed a notice of appeal of this judgment, but it has not yet filed its opening brief in the appeal.

•

On May 15, 2009, we purchased for $26.0 million contingent payment rights previously sold to Tracinda Corporation that entitled Tracinda to receive up to $27.9 million of net proceeds from offshore litigation related to the Amber Case.

•

As of June 30, 2009, we have reduced borrowings under our credit facility to $83.0 million, with $140.8 million of availability based on the current $225.0 million borrowing base.

•

On April 22, 2009, DHS entered into the DHS Forbearance, as amended on May 21, 2009, with LCPI in which LCPI agreed to forbear until June 15, 2009 from exercising its rights and remedies under the credit agreement including, among other actions, acceleration of all amounts due under the credit agreement or foreclosure on the DHS rigs and other assets pledged as collateral, including accounts receivable. Because the forbearance period has expired and because of certain June 30, 2009 financial covenant violations by DHS, LCPI currently has the right to demand payment of the amounts outstanding under the credit facility and if not paid, foreclose on the DHS assets pledged as collateral under the credit agreement. As of June 30, 2009, borrowings outstanding under the DHS facility were $83.3 million.

2009 Outlook

We currently expect our 2009 oil and gas production to decline by approximately 16% as compared to 2008 levels due to the limited drilling program we expect for 2009 which was further reduced during the second quarter of 2009 to delay the completion of 23 wells in the Vega area until Rocky Mountain natural gas prices return to more favorable levels. Drilling and completion capital expenditures are currently expected to be approximately $60.0 million for 2009 which is an increase over our previous estimate of $52.0 million. The increase is due to the unexpected duration of drilling and completion operations in the Columbia River Basin and the now planned drilling of the Company’s second well in the basin. If the second well in the Columbia River Basin is not spud in 2009, the drilling and completion capital expenditures are expected to be approximately $58.0 million. These plans could be revised dependent upon our available capital resources and the outlook for natural gas prices.

The exploration for and the acquisition, development, production, and sale of, natural gas and crude oil are highly competitive and capital intensive. As in any commodity business, the market price of the commodity produced and the costs associated with finding, acquiring, extracting, and financing the operation are critical to our profitability and long-term value creation for stockholders. Generating long-term reserve and production growth represents an ongoing focus for management, and is made particularly important in our business given the natural production and reserve decline associated with producing oil and gas properties.

Our longer-term business strengths include a multi-year inventory of attractive lower risk drilling on long-lived Rockies properties, which we believe will allow us to grow reserves and replace and expand production organically without having to rely solely on acquisitions, and significant leasehold positions in high potential exploratory areas such as the Columbia River Basin.

Liquidity and Capital Resources

Liquidity is a measure of a company’s ability to access cash. On May 13, 2009, we completed an underwritten public offering of 172.5 million shares of our common stock at $1.50 per share for net proceeds of $247.2 million, net of underwriting commissions and related offering expenses. On May 19, 2009, we received from the U.S. government $60.0 million of offshore litigation proceeds related to the Amber Case and in early June 2009 we paid out $11.3 million for overrides and other participating interests in the judgment. With proceeds from these transactions, we have reduced our borrowings outstanding under our credit facility from $294.5 million at December 31, 2008 to $83.0 million at June 30, 2009, with $140.8 million of remaining availability based on our current $225.0 million borrowing base. The borrowing base is subject to a redetermination effective September 1, 2009 and could decrease if our lending banks lower their commodity price forecasts. In addition, we reduced our accounts payable from $159.0 million at December 31, 2008 to $79.0 million at June 30, 2009. During May 2009, DHS sold Rig #7 to Naknek Electric Association for cash proceeds of $7.8 million which, combined with proceeds from minor spare equipment sales and the collection of accounts receivable, were used to reduce borrowings outstanding under the DHS credit facility from $93.8 million at December 31, 2008 to $83.3 million at June 30, 2009.

In conjunction with our 2008 Annual Report on Form 10-K, we received a report from our independent registered public accounting firm on our consolidated financial statements for the year ended December 31, 2008, in which our auditors included an explanatory paragraph indicating that we had suffered recurring losses from operations, had a working capital deficiency and were not in compliance with our debt covenants as of December 31, 2008 which raises substantial doubt about our ability to continue as a going concern. As shown in the accompanying financial statements and discussed elsewhere herein, we experienced a net loss attributable to Delta common stockholders of $197.9 million for the six months ended June 30, 2009, and although we were in compliance with the debt covenants under our credit facility at June 30, 2009, our projections indicate that without an increase in Rocky Mountain natural gas prices upon which the majority of the Company’s production is sold, the senior secured debt to EBITDAX ratio covenant in the credit facility could be violated within the next twelve months. In addition, our DHS subsidiary remained out of compliance with the debt covenants under its credit facility and its forbearance agreement with LCPI expired on June 15, 2009. As a result, amounts outstanding under both credit facilities are classified as current liabilities in the accompanying consolidated balance sheet as of June 30, 2009. Further, DHS is facing significant, potentially immediate, requirements to fund obligations in excess of its existing sources of liquidity if LCPI exercises its right to demand payment of the amounts outstanding under DHS’s credit facility.

Our accompanying financial statements have been prepared assuming we will continue as a going concern. During the second quarter of 2009, significant improvements to our liquidity position were achieved through the equity transaction, receipt of the offshore litigation proceeds, and asset sales described above, which substantially improved our financial position. Nevertheless, due to our deficiency in short-term liquidity at DHS and our possible additional liquidity issues if we violate the covenants related to our credit facility in the future, our ability to continue as a going concern is dependent upon our lenders’ willingness to amend terms, grant waivers, or restructure existing agreements, or our success in generating additional sources of capital in the near future, the receipt of the remaining offshore litigation proceeds, sales of assets, or other capital raising transactions and/or an increase in commodity prices. We and DHS are both in discussions with our respective credit facility lenders regarding amendments, waivers or other restructuring of the credit facilities, but there can be no assurance that the lenders will agree to any such amendments.

During the six months ended June 30, 2009, we had an operating loss of $155.5 million (or $78.6 million exclusive of dry holes and impairments and gain on offshore litigation settlement), net cash provided by operating activities of $32.8 million and net cash provided by financing activities of $22.7 million. During this period we spent $122.4 million on oil and gas development activities. At June 30, 2009, we had $5.7 million in cash and $140.8 million available under our credit facility, total assets of $1.7 billion and a debt to capitalization ratio of 33.4%. Debt, excluding installments payable on property acquisition which are secured by restricted cash deposits, at June 30, 2009 totaled $417.7 million, comprised of $166.3 million of bank debt ($83.0 million of our indebtedness under Delta’s Credit Facility and $83.3 million of DHS indebtedness, all of which was classified as current at June 30, 2009), $149.6 million of senior subordinated notes and $101.8 million of senior convertible notes. In accordance with applicable accounting rules, the senior convertible notes are recorded at a discount to their stated amount due of $115.0 million.

As of July 31, 2009, our corporate rating and senior unsecured debt rating were Caa3 and Ca, respectively, as issued by Moody’s Investors Service. Moody’s outlook was “negative.” As of July 31, 2009, our corporate credit and senior

unsecured debt ratings were CCC and CC, respectively, as issued by Standard and Poor’s (“S&P”). S&P’s outlook on its rating was “developing.”

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

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

There can be no assurance that the actions undertaken by us will be sufficient to repay the obligations under our credit facility, or, if not, or if additional defaults occur under that facility, that the lenders will be willing to waive further defaults or amend the facility. There can be no assurance that LCPI will not exercise its right to demand payment of the amounts outstanding under the DHS credit facility and if not paid, foreclose on the DHS assets pledged as collateral for the credit facility. In addition, there can be no assurance that results of operations and other sources of liquidity, including asset sales and offshore litigation proceeds, will be sufficient to meet contractual, operating and capital obligations. Our financial statements do not include any adjustments that might result from the outcome of uncertainty regarding our ability to raise additional capital, sell assets, otherwise obtain sufficient funds to meet our obligations or to continue as a going concern.

We continue to examine additional sources of long-term capital, including a restructured debt facility, the issuance of debt instruments, the sales of assets, and joint venture financing. Availability of these sources of capital and, therefore, our ability to execute our operating strategy and meet our liquidity challenges, will depend upon a number of factors, many of which are beyond our control.

Results of Operations

The following discussion and analysis relates to items that have affected our results of operations for the three months ended June 30, 2009 and 2008. This analysis should be read in conjunction with our consolidated financial statements and the accompanying notes thereto included in this Form 10-Q.

Quarter Ended June 30, 2009 Compared to Quarter Ended June 30, 2008

Net Loss Attributable to Delta Common Stockholders. Net loss attributable to Delta common stockholders was $172.3 million, or $0.89 per diluted common share, for the three months ended June 30, 2009, compared to a net loss attributable to Delta common stockholders of $23.4 million, or $0.23 per diluted common share, for the three months ended June 30, 2008. Losses from continuing operations increased from $23.3 million for the three months ended June 30, 2008 to a loss of $180.5 million for the three months ended June 30, 2009. The increased loss was primarily due to impairments recorded in the second quarter of 2009 and due to significantly lower natural gas and oil prices compared to the corresponding period in the previous year. Explanations of significant items affecting comparability between periods are discussed by financial statement caption below.

Oil and Gas Sales . During the three months ended June 30, 2009, oil and gas sales decreased 71% to $21.3 million, as compared to $73.2 million for the comparable period a year earlier. The decrease was principally the result of a 54% decrease in oil prices, a 75% decrease in natural gas prices, and an 8% decrease in production. The average oil price received during the three months ended June 30, 2009 decreased to $53.18 per Bbl compared to $115.05 per Bbl for the year earlier period. The average natural gas price received during the three months ended June 30, 2009 decreased to $2.37 per Mcf compared to $9.59 per Mcf for the year earlier period. The production decrease was primarily related to production declines in the Gulf Coast that have not been offset by additional drilling.

Contract Drilling and Trucking Fees . Contract drilling and trucking fees for the three months ended June 30, 2009 decreased to $1.7 million compared to $7.9 million for the comparable year earlier period. The decrease is the result of lower third party rig utilization in the three months ended June 30, 2009 compared to the comparable year earlier period, resulting from a significant industry slowdown attributable to lower commodity prices.

Production and Cost Information

Production volumes, average prices received and cost per equivalent Mcf for the three months ended June 30, 2009 and 2008 are as follows:


	Three Months Ended
	June 30,
	2009		2008
Production – Continuing Operations:
Oil (Mbbl)		202		247
Gas (Mmcf)		4,483		4,674

Total Production (Mmcfe)		5,692		6,156

Average Price – Continuing Operations:
Oil (per barrel)	$	53.18	$	115.05
Gas (per Mcf)	$	2.37	$	9.59

Costs per Mcfe – Continuing Operations:
Lease operating expense	$	1.34	$	1.45
Production taxes	$	0.18	$	0.69
Transportation costs	$	0.44	$	0.40
Depletion expense	$	5.13	$	3.93

Realized derivative losses	$	-	$	(1.16)

Lease Operating Expense. Lease operating expenses for the three months ended June 30, 2009 decreased to $7.6 million from $9.0 million in the year earlier period primarily due to lower production and lower costs in Howard Ranch and Newton. Lease operating expense from continuing operations per Mcfe for the three months ended June 30, 2009 decreased to $1.34 per Mcfe from $1.45 per Mcfe for the comparable year earlier period.

Exploration Expense. Exploration expense consists of geological and geophysical costs, lease rentals and abandoned leases. Our exploration costs for the three months ended June 30, 2009 were $471,000 compared to $1.9 million for the comparable year earlier period. Current period exploration activities primarily relate to delay rental payments while the 2008 period included significant seismic acquisition costs.

Dry Hole Costs and Impairments. We incurred dry hole and impairment costs of approximately $106.6 million for the three months ended June 30, 2009 compared to $430,000 for the comparable period a year ago. During the three months ended June 30, 2009, dry hole and impairment costs primarily related to unproved leasehold impairments in Garden Gulch ($38.6 million), Haynesville ($26.7 million), and Lighthouse ($14.7 million), a $10.5 million impairment of Vega area surface acres, $6.5 million of DHS equipment and rig impairments, $4.3 million of tubular inventory impairments and a $1.9 million impairment of the Paradox pipeline. During the second quarter of 2009, we adjusted the timing of the development of the Garden Gulch properties to delay the drilling of additional wells. In addition, during the quarter, another working interest owner in the property sold its interest to an undisclosed buyer for an implied price less than the carrying value of our properties. With respect to our Haynesville Shale leasehold, during the second quarter of 2009, we began preparing prospect materials to support efforts to market the leasehold, including efforts to consolidate acreage blocks to optimize marketability, and received offers on certain portions of the leasehold at prices less than our carrying value. With respect to our Lighthouse Bayou leasehold, we were obligated under our exploration and development agreement, as amended, to spud an initial test well by July 1, 2009. In late May 2009, an amendment to the agreement was executed whereby the leases reverted to the original seller and we retained an option to participate in future transactions, if any, related to the leases contained in the area of mutual

interest. With respect to the Vega area surface acreage, during the second quarter of 2009, we entered into negotiations to sell a portion of our surface acreage to an existing land owner in the area as part of an attempt to resolve access and right of way issues related to the development of the minerals and is in the process of marketing the remaining surface acreage. With respect to the Paradox pipeline, we received an offer for the associated gas plant for an amount less than the carrying value. With respect to the DHS equipment and rigs, during the quarter ended June 30, 2009, the fleet rig utilization rate declined approximately 68% from the first quarter of 2009 and the average period end contract day rate declined by approximately 29% from the first quarter of 2009. In addition, DHS’s efforts to market spare equipment and observations at industry auctions indicated that with industry-wide active rig counts in decline, spare equipment values had declined. With respect to tubular inventories, during 2008, we pre-ordered and stockpiled significant amounts of tubing, casing and pipe inventory to ensure availability for our then aggressive Piceance Basin and Paradox Basin drilling program. Since then, with significantly lower commodity prices resulting in significant reductions in drilling capital expenditures and delays to drilling plans and with continued declines in steel prices, particularly during the second quarter of 2009, the value of these inventories has declined. In each case, as a result of the events and activities described, we evaluated our unproved leasehold, surface acreage, rigs and equipment, and inventory and concluded that an impairment had occurred.

We incurred dry hole costs of approximately $430,000 for the three months ended June 30, 2008 primarily related to carry-over costs for work done in 2008 on a Hingeline well in Utah.

Depreciation, Depletion, Amortization and Accretion – oil and gas. Depreciation, depletion and amortization expense increased 21% to $29.9 million for the three months ended June 30, 2009, as compared to $24.8 million for the comparable year earlier period. Depletion expense for the three months ended June 30, 2009 was $29.2 million compared to $24.2 million for the three months ended June 30, 2008. Our depletion rate increased from $3.93 per Mcfe for the three months ended June 30, 2008 to $5.13 per Mcfe for the current year period primarily due to the effect of low spot commodity prices at June 30, 2009 on the reserves used in our depletion calculation, offset by the effect of impairments recorded in the fourth quarter of 2008.

Drilling and Trucking Operations . Drilling expense decreased to $2.3 million for the three months ended June 30, 2009 compared to $5.5 million for the comparable prior year period. This decrease is due to lower third party rig utilization during the current year period, but is not proportional to the decline in contract drilling and trucking fees due to fixed costs and costs associated with a large number of stacked rigs.

Depreciation and Amortization – drilling and trucking. Depreciation and amortization expense – drilling increased to $6.2 million for the three months ended June 30, 2009, as compared to $3.2 million for the comparable year earlier period. The increase is due to more rigs in the fleet in 2009 as compared to 2008 and due to less drilling done by DHS for us in 2009 as compared to 2008. Depreciation expense is recorded on a straight line basis and is not impacted by changes in the utilization rate.

General and Administrative Expense. General and administrative expense decreased 35% to $9.0 million for the three months ended June 30, 2009, as compared to $13.8 million for the comparable prior year period. The decrease in general and administrative expenses is attributed to a decrease in non-cash stock compensation expense from lower executive performance share costs, and also from forfeitures and modifications related to reductions in force in March and June 2009 affecting approximately fifty percent of our personnel. Due to cost savings from the reduction in force during the three months ended June 30, 2009, further reductions in cash general and administrative costs are expected in future periods.

Interest Expense and Financing Costs. Interest and financing costs increased 64% to $15.9 million for the three months ended June 30, 2009, as compared to $9.7 million for the comparable year earlier period. The increase is primarily related to higher average outstanding Delta and DHS credit facility balances and higher interest rates during the second quarter of 2009 as compared to the second quarter of 2008. In addition, the three months ended June 30, 2009, included $1.0 million of interest expense related to the repurchase from Tracinda of offshore litigation contingent payment rights and $643,000 for the write off of previously unamortized deferred financing costs related to the DHS credit agreement.

Interest Income. Interest income decreased to $108,000 for the three months ended June 30, 2009 compared to $3.4 million for the comparable prior year period. The decrease in income is primarily the result of lower investment balances in the current period and also due to lower average interest rates.

Realized Loss on Derivative Instruments, Net. Effective July 1, 2007, we discontinued cash flow hedge accounting. Other income and expense includes $7.1 million of realized losses for the three months ended June 30, 2008. During the quarter ended June 30, 2009 there were no derivative contract settlements.

Unrealized Loss on Derivative Instruments, Net . As a result of the discontinuation of cash flow hedge accounting, we recognize mark-to-market gains or losses in current earnings instead of deferring those amounts in accumulated other comprehensive income. Accordingly, we recognized $15.6 million of unrealized losses on derivative instruments in other income and expense during the three months ended June 30, 2009 compared to a loss of $27.1 million for the comparable prior year period.

Income (Loss) From Unconsolidated Affiliates. Income from unconsolidated affiliates during the three months ended June 30, 2008 primarily related to earnings from our tubular supply subsidiary. Loss from unconsolidated affiliates during the three months ended June 30, 2009 is primarily the result of $3.0 million of impairments recorded related to two of our investments.

Income Tax Benefit (Expense). Due to our continued losses, we were required by the “more likely than not” provisions of SFAS No. 109, “Accounting for Income Taxes” (“SFAS 109”), to record a valuation allowance for our deferred tax assets beginning with the second quarter of 2007. Our income tax expense for the three months ended June 30, 2009 of $265,000 relates only to DHS, as no benefit was provided for our net operating losses. In addition, during the quarter ended March 31, 2009, DHS reached a net deferred tax asset position and accordingly, based on significant recent and continuing book losses and projections for future results, a valuation allowance was recorded for DHS’s net deferred tax assets.

Non-Controlling Interest. Non-controlling interest represents the minority investors’ proportionate share of the income or loss of DHS in which they hold an interest. During the three months ended June 30, 2009, DHS reported significant losses from low rig utilization rates and impairments which resulted in a non-controlling interest credit to earnings.

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008

Net Loss Attributable to Delta Common Stockholders. Net loss attributable to Delta common stockholders was $197.9 million, or $1.35 per diluted common share, for the six months ended June 30, 2009, compared to a net loss attributable to Delta common stockholders of $44.2 million, or $0.49 per diluted common share, for the six months ended June 30, 2008. Losses from continuing operations increased from $44.4 million for the six months ended June 30, 2008 to a loss of $209.9 million for the six months ended June 30, 2009. The increased loss was due to impairments recorded in the second quarter of 2009 and significantly lower oil and natural gas prices offset by an offshore litigation gain recorded in 2009 and lower derivative losses in 2009. Explanations of significant items affecting comparability between periods are discussed by financial statement caption below.

Oil and Gas Sales . During the six months ended June 30, 2009, oil and gas sales decreased 66% to $43.5 million, as compared to $127.0 million for the comparable period a year earlier. The decrease was principally the result of a 59% decrease in oil prices and a 69% decrease in natural gas prices, partially offset by a slight 4% increase in production. The average oil price received during the six months ended June 30, 2009 decreased to $42.03 per Bbl compared to $102.62 per Bbl for the year earlier period. The average natural gas price received during the six months ended June 30, 2009 decreased to $2.74 per Mcf compared to $8.80 per Mcf for the year earlier period.

Contract Drilling and Trucking Fees . Contract drilling and trucking fees for the six months ended June 30, 2009 decreased to $6.9 million compared to $18.6 million for the comparable year earlier period. The decrease is the result of lower third party rig utilization in the six months ended June 30, 2009 compared to the comparable year earlier period, resulting from a significant industry slowdown attributable to lower commodity prices.

Gain on Offshore Litigation Award. During the six months ended June 30, 2009, we recorded a $31.2 million gain for an offshore litigation award. See Note 4, “Oil and Gas Properties,” to the accompanying financial statements.

Production and Cost Information

Production volumes, average prices received and cost per equivalent Mcf for the six months ended June 30, 2009 and 2008 are as follows:


	Six Months Ended
	June 30,
	2009		2008
Production – Continuing Operations:
Oil (Mbbl)		414		513
Gas (Mmcf)		9,532		8,442

Total Production (Mmcfe)		12,017		11,522

Average Price – Continuing Operations:
Oil (per barrel)	$	42.03	$	102.62
Gas (per Mcf)	$	2.74	$	8.80

Costs per Mcfe – Continuing Operations:
Lease operating expense	$	1.45	$	1.48
Production taxes	$	0.22	$	0.68
Transportation costs	$	0.48	$	0.37
Depletion expense	$	4.60	$	4.05

Realized derivative losses	$	-	$	(0.76)

Lease Operating Expense. Lease operating expenses for the six months ended June 30, 2009 of $17.4 million was comparable to $17.0 million in the year earlier period as both production and per unit cost rates remained consistent. Lease operating expense from continuing operations per Mcfe for the six months ended June 30, 2009 decreased to $1.45 per Mcfe from $1.48 per Mcfe for the comparable year earlier period.

Exploration Expense. Exploration expense consists of geological and geophysical costs, lease rentals and abandoned leases. Our exploration costs for the six months ended June 30, 2009 were $1.5 million compared to $2.9 million for the comparable year earlier period. Current period exploration activities primarily relate to delay rental payments and seismic acquisition costs, while the 2008 period included more significant seismic acquisition costs.

Dry Hole Costs and Impairments. We incurred dry hole and impairment costs of approximately $108.1 million for the six months ended June 30, 2009 compared to $2.8 million for the comparable period a year ago. During the six months ended June 30, 2009, dry hole and impairment costs primarily related to unproved leasehold impairments in Garden Gulch ($38.6 million), Haynesville ($26.7 million), and Lighthouse ($14.7 million), a $10.5 million impairment of Vega area surface acres, $6.5 million of DHS equipment and rig impairments, $4.3 million of tubular inventory impairments, and a $1.9 million impairment of the Paradox pipeline. During the second quarter of 2009, we adjusted the timing of the development of the Garden Gulch properties to delay the drilling of additional wells. In addition, during the quarter, another working interest owner in the property sold its interest to an undisclosed buyer for an implied price less than the carrying value of our properties. With respect to our Haynesville Shale leasehold, during the second quarter of 2009, we began preparing prospect materials to support efforts to market the leasehold, including efforts to consolidate acreage blocks to optimize marketability, and received offers on certain portions of the leasehold at prices less than our carrying value. With respect to our Lighthouse Bayou leasehold, we were obligated under our exploration and development agreement, as amended, to spud an initial test well by July 1, 2009. In late May 2009, an amendment to the agreement was executed whereby the leases reverted to the original seller and we retained an option to participate in future transactions, if any, related to the leases contained in the area of mutual interest. With respect to the Vega area surface acreage, during the second quarter of 2009, we entered into negotiations to sell a portion of our surface acreage to an existing land owner in the area as part of an attempt to

resolve access and right of way issues related to the development of the minerals and is in the process of marketing the remaining surface acreage. With respect to the Paradox pipeline, we received an offer for the associated gas plant for an amount less than the carrying value. With respect to the DHS equipment and rigs, during the quarter ended June 30, 2009, the fleet rig utilization rate declined approximately 68% from the first quarter of 2009 and the average period end contract day rate declined by approximately 29% from the first quarter of 2009. In addition, DHS’s efforts to market spare equipment and observations at industry auctions indicated that with industry-wide active rig counts in decline, spare equipment values had declined. With respect to tubular inventories, during 2008, we pre-ordered and stockpiled significant amounts of tubing, casing and pipe inventory to ensure availability for our then aggressive Piceance Basin and Paradox Basin drilling program. Since then, with significantly lower commodity prices resulting in significant reductions in drilling capital expenditures and delays to drilling plans and with continued declines in steel prices, particularly during the second quarter of 2009, the value of these inventories has declined. In each case, as a result of the events and activities described, we evaluated our unproved leasehold, surface acreage, rigs and equipment, and inventory and concluded that an impairment had occurred.

We incurred dry hole costs of approximately $2.8 million for the six months ended June 30, 2008 primarily related to carry-over costs for work done in 2008 on a Hingeline well in Utah.

Depreciation, Depletion, Amortization and Accretion – oil and gas. Depreciation, depletion and amortization expense increased 19% to $56.8 million for the six months ended June 30, 2009, as compared to $47.8 million for the comparable year earlier period. Depletion expense for the six months ended June 30, 2009 was $55.3 million compared to $46.7 million for the six months ended June 30, 2008. Our depletion rate increased from $4.05 per Mcfe for the six months ended June 30, 2008 to $4.60 per Mcfe for the current year period primarily due to the effect of low spot commodity prices at June 30, 2009 on the reserves used in our depletion calculation, offset by the effect of impairments recorded in the fourth quarter of 2008.

Drilling and Trucking Operations . Drilling expense decreased to $7.6 million for the six months ended June 30, 2009 compared to $12.4 million for the comparable prior year period. This decrease is due to lower third party rig utilization during the current year period, but is not proportional to the decline in contract drilling and trucking fees due to fixed costs and costs associated with a large number of stacked rigs.

Depreciation and Amortization – drilling and trucking. Depreciation and amortization expense – drilling increased to $12.0 million for the six months ended June 30, 2009, as compared to $6.9 million for the comparable year earlier period. The increase is due to more rigs in the fleet in 2009 as compared to 2008 and due to less drilling done by DHS for us in 2009 as compared to 2008. Depreciation expense is recorded on a straight line basis and is not impacted by changes in the utilization rate.

General and Administrative Expense. General and administrative expense decreased 21% to $21.6 million for the six months ended June 30, 2009, as compared to $27.2 million for the comparable prior year period. The decrease in general and administrative expenses is primarily attributed to a decrease in non-cash stock compensation expense from lower executive performance share costs, and also from forfeitures and modifications related to reductions in force in March and June 2009 affecting approximately fifty percent of our personnel. Due to cost savings from the reductions in force during the six months ended June 30, 2009, reductions in cash general and administrative costs are expected in future periods.

Interest Expense and Financing Costs. Interest and financing costs increased 77% to $33.0 million for the six months ended June 30, 2009, as compared to $18.6 million for the comparable year earlier period. The increase is primarily related to higher average outstanding Delta and DHS credit facility balances with higher interest rates during the first half of 2009 as compared to the first half of 2008. The increase is also related to the write-off of unamortized deferred financing costs and waiver fees related to the amendments to our credit facilities in 2009 coupled with six months of non-cash amortization of the discount on the installments payable to EnCana compared to only four months in the prior year period. In addition, the six months ended June 30, 2009, included $1.0 million of interest expense related to the repurchase from Tracinda of the offshore litigation contingent payment rights and $643,000 for the write off of previously unamortized deferred financing costs related to the DHS credit agreement.

Interest Income. Interest income decreased to $756,000 for the six months ended June 30, 2009 compared to $5.3 million for the comparable prior year period. The decrease in income is primarily the result of lower investment balances in the current period and lower interest rates.

Realized Loss on Derivative Instruments, Net. Effective July 1, 2007, we discontinued cash flow hedge accounting. Beginning July 1, 2007, we recognize realized gains or losses in other income and expense instead of as a component of revenue. As a result, other income and expense includes $8.8 million of realized losses for the six months ended June 30, 2008. During the six months ended June 30, 2009 there were no derivative contract settlements.

Unrealized Loss on Derivative Instruments, Net . As a result of the discontinuation of cash flow hedge accounting, we recognize mark-to-market gains or losses in current earnings instead of deferring those amounts in accumulated other comprehensive income. Accordingly, we recognized $21.1 million of unrealized losses on derivative instruments in other income and expense during the six months ended June 30, 2009 compared to a loss of $41.2 million for the comparable prior year period.

Income (Loss) From Unconsolidated Affiliates. Income from unconsolidated affiliates during the six months ended June 30, 2008 primarily related to earnings from our tubular supply subsidiary. Loss from unconsolidated affiliates during the six months ended June 30, 2009 is primarily the result of $3.0 million of impairments recorded related to two of our investments.

Income Tax Benefit (Expense). Due to our continued losses, we were required by the “more likely than not” provisions of SFAS No. 109, “Accounting for Income Taxes” (“SFAS 109”), to record a valuation allowance for our deferred tax assets beginning with the second quarter of 2007. Our income tax benefit for the six months ended June 30, 2009 of $318,000 relates only to DHS, as no benefit was provided for our net operating losses. In addition, during the six months ended June 30, 2009, DHS reached a net deferred tax asset position and accordingly, based on significant recent and continuing book losses and projections for future results, a valuation allowance was recorded for DHS’s net deferred tax assets.

Non-Controlling Interest. Non-controlling interest represents the minority investors’ proportionate share of the income or loss of DHS in which they hold an interest. During the six months ended June 30, 2009, DHS reported significant losses from low rig utilization rates and impairments which resulted in a non-controlling interest credit to earnings.

Historical Cash Flow

Our cash flow from operating activities decreased from $49.4 million for the six months ended June 30, 2008 to cash provided by operating activities of $32.8 million for the six months ended June 30, 2009. The significant decrease in cash flow is primarily a result of lower commodity prices. Our net cash used in investing activities decreased to $115.3 million for the six months ended June 30, 2009 compared to net cash used in investing activities of $721.4 million for the comparable prior year period primarily due to our significant reduction in drilling and acquisition activity. Cash provided by financing activities decreased from $670.8 million for the six months ended June 30, 2008 to cash provided by financing activities of $22.7 million for the current year period. During the six months ended June 30, 2008, $662.0 million of cash was provided by the issuance of stock. During the six months ended June 30, 2009, $247.2 million of cash was received from the issuance of stock, and $222.0 million of cash was used to repay amounts outstanding under our credit facilities.

Capital and Exploration Expenditures

Our capital and exploration expenditures for the six months ended June 30, 2009 and 2008 are as follows:


	2009		2008
	(In thousands)
CAPITAL AND EXPLORATION EXPENDITURES:

Property acquisitions:
Unproved	$	1,713	$	312,790
Proved		-		103,327
Oil and gas properties		40,518		194,999
Drilling and trucking equipment		3,128		26,976
Pipeline and gathering systems		6,802		36,943

Total ⁽¹⁾	$	52,161	$	675,035

¹ Capital expenditures in the table above are presented on an accrual basis. Additions to property and equipment in the consolidated statement of cash flows reflect capital expenditures on a cash basis, when payments are made.

Contractual and Long-term Debt Obligations

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 semi-annually on April 1 and October 1 and mature in 2015. The notes were issued at 99.50% of par and the associated discount is being amortized to interest expense over the term of the notes. The indenture governing the notes contains various restrictive covenants that 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.

3 ³ / 4 % Senior Convertible Notes, due 2037

On April 25, 2007, we issued $115.0 million aggregate principal amount of 3 ³ / 4 % Senior Convertible Notes due 2037 (the “Notes”) for net proceeds of $111.6 million after underwriters’ discounts and commissions of approximately $3.4 million. The remaining discount will be amortized through May 2012 when the holders of the Notes can first require us to purchase all or a portion of the Notes. The Notes bear interest at a rate of 3 ³ / 4 % per annum, payable semi-annually in arrears, on May 1 and November 1 of each year, beginning November 1, 2008. Combined with the amortization of debt discount, the Notes have an effective interest rate of approximately 7.6% and 7.4% with total interest costs of $2.2 million and $2.1 million for the three month periods ended June 30, 2009 and 2008, respectively, and interest costs of $4.3 million and $4.2 million for the six month periods ended June 30, 2009 and 2008, respectively. The Notes will mature on May 1, 2037 unless earlier converted, redeemed or repurchased. The holders of the Notes have the right to require us to purchase all or a portion of the Notes on May 1, 2012, May 1, 2017, May 1, 2022, May 1, 2027, and May 1, 2032. The Notes will be convertible at the holder’s option, in whole or in part, at an initial conversion rate of 32.9598 shares of common stock per $1,000 principal amount of Notes (equivalent to a conversion price of approximately $30.34 per share) at any time prior to the close of business on the business day immediately preceding the final maturity date of the Notes, subject to prior repurchase of the Notes. The conversion rate may be adjusted from time to time in certain instances. Upon conversion of a Note, we will have the option to deliver shares of our common stock, cash or a combination of cash and shares of our common stock for the Notes surrendered. In addition, following certain fundamental changes that occur prior to maturity, we will increase the conversion rate for a holder who elects to convert its Notes in connection with such fundamental changes by a number of additional shares of common stock. Although the Notes do not contain any financial covenants, the Notes contain covenants that require us to properly make payments of principal and interest, provide certain reports, certificates and notices to the trustee under various circumstances, cause our wholly-owned subsidiaries to become guarantors of the debt, maintain an office or agency where the Notes may be presented or surrendered for payment,

continue our corporate existence, pay taxes and other claims, and not seek protection from the debt under any applicable usury laws.

Credit Facility – Delta

On March 2, 2009, we entered into the First Amendment to the Second Amended and Restated Credit Agreement (the “Forbearance Agreement and Amendment to the Credit Facility”), as further amended on April 14, 2009 and on April 30, 2009, with JPMorgan Chase Bank, N.A., as agent, and certain of the financial institutions that are party to its credit agreement in which, among other changes, the lenders provided us relief for a period ended May 15, 2009 from acting upon their rights and remedies as a result of our violation of accounts payable and current ratio covenants. The Forbearance Agreement and Amendment to the Credit Facility replaced the previous consolidated net debt to consolidated EBITDAX covenant with a senior secured debt to consolidated EBITDAX requirement for the preceding four consecutive fiscal quarters to be less than 4.0 to 1.0. In accordance with the Forbearance Agreement and Amendment to the Credit Facility, the borrowing base was reduced upon the successful completion of our capital raising efforts from $295.0 million to $225.0 million, with a conforming borrowing base of $185.0 million until the next scheduled redetermination date (September 1, 2009). The revised variable interest rates are based on the ratio of outstanding borrowings to the conforming borrowing base and vary between Libor plus 2.5% to Libor plus 5.0% for Eurodollar loans and prime plus 1.625% to prime plus 4.125% for base rate loans. The Forbearance Agreement and Amendment to the Credit Facility changed the maturity date to January 15, 2011. The Forbearance Agreement and Amendment to the Credit Facility also required that we execute derivative contracts to put in place a commodity floor price for anticipated production equal to a minimum of 40% for the last two quarters of 2009, 70% for the calendar year 2010 and 50% for the calendar year 2011.

The borrowing base is re-determined by the lending banks at least semiannually (September 1, 2009 is the next scheduled redetermination), or by special re-determinations if requested by us based on drilling success. If, as a result of any reduction in the amount of our borrowing base, the total amount of the outstanding debt were to exceed the amount of the borrowing base in effect, then, within 30 days after we are notified of the borrowing base deficiency, we would be required to (1) make a mandatory payment of principal to reduce our outstanding indebtedness so that it would not exceed our borrowing base, (2) eliminate the deficiency by making three equal monthly principal payments, (3) provide additional collateral for consideration to eliminate the deficiency within 90 days or (4) eliminate the deficiency through a combination of (1) through (3). If for any reason we were unable to pay the full amount of the mandatory prepayment within the requisite 30-day period, we would be in default of our obligations under our credit facility.

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 various 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 would 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 would result in acceleration of the indebtedness at the option of the lending banks. Such other events of default include non-payment, breach of warranty, non-performance of obligations under the credit facility (including financial covenants), default on other indebtedness, certain pension plan events, certain adverse judgments, change of control, and a failure of the liens securing the credit facility.

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

Credit Facility – DHS

On August 15, 2008, DHS entered into a new agreement with Lehman Commercial Paper, Inc. (“LCPI”) to amend its existing LCPI credit facility. The revised agreement increased the borrowing base from $75.0 million to $150.0 million. Total debt outstanding at June 30, 2009 under the facility is $83.3 million. Because of LCPI’s bankruptcy and default, DHS does not have any additional borrowing capacity under the LCPI facility. Under the revised agreement, DHS has an obligation to provide to LCPI by March 31 of each year audited financial statements reported on without a going concern qualification or exception by the independent auditor. DHS was not able to provide audited financial statements not containing an explanatory paragraph related to its ability to continue as a going concern, and, accordingly, DHS was not in compliance with this covenant at March 31, 2009. In addition, at June 30, 2009, DHS was not in compliance with its minimum EBITDA, maximum leverage ratio, minimum interest coverage ratio and minimum current ratio financial covenants.

On April 22, 2009, DHS entered into the DHS Forbearance, as amended on May 21, 2009, with LCPI in which LCPI agreed to forbear until June 15, 2009 from exercising its rights and remedies under the credit agreement including, among other actions, acceleration of all amounts due under the credit facility or foreclosure on the DHS rigs and other assets pledged as collateral, including accounts receivable. The DHS facility is non-recourse to Delta. Due to the lapsing of the DHS Forbearance as well as the June 30, 2009 financial covenant violations by DHS, LCPI currently has the right to demand payment of the amounts outstanding under the credit facility and if not paid, foreclose on the DHS assets pledged as collateral for the credit facility. Although LCPI has not exercised its right to foreclose on the DHS assets pledged as collateral and DHS in currently in negotiations with LCPI to amend the terms of the credit facility, there can be no assurance that LCPI will not exercise its right to foreclose on the DHS assets pledged as collateral.

Other Contractual Obligations

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

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

We had a net derivative liability of $21.1 million at June 30, 2009. The ultimate settlement amounts of these derivative instruments are unknown because they are subject to continuing market fluctuations. See Item 3. “Quantitative and Qualitative Disclosures about Market Risk” for more information regarding our derivative instruments.

On May 15, 2009, we repurchased for $26.0 million the contingent payment rights previously sold to Tracinda Corporation that entitled Tracinda to receive up to $27.9 million of net proceeds from the offshore litigation related to the Amber Case.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations were based on the consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. Our significant accounting policies are described in Note 3 to our consolidated financial statements. We have identified certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by management. We analyze our estimates, including those related to oil and gas reserves, bad debts, oil and gas properties, marketable securities, income taxes, derivatives, contingencies and litigation, and base our estimates on historical experience and various other assumptions that we believe are reasonable under the

circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of our financial statements.

Successful Efforts Method of Accounting

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

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

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

Reserve Estimates

Estimates of gas and oil reserves, by necessity, are projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of gas and oil that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable gas and oil reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions governing future gas and oil prices, the availability and cost of capital to develop the reserves, 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. With the further decline in commodity pricing since year end, the proved undeveloped reserves attributable to our Piceance Basin properties are uneconomic using the spot natural gas price as of June 30, 2009. The Piceance Basin properties contain nearly all of our proved undeveloped reserves.

Impairment of Gas and Oil Properties

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

Given the complexities associated with gas and oil reserve estimates and the history of price volatility in the gas and oil markets, events may arise that would require us to record an impairment of the recorded book values associated with gas and oil properties. For developed properties, the review consists of a comparison of the carrying value of the asset with the asset’s expected future undiscounted cash flows without interest costs. As a result of such assessment, we recorded no impairment provisions to developed properties for the three or six months ended June 30, 2009.

For unproved properties, the need for an impairment charge is based on our plans for future development and other activities impacting the life of the property and our ability to recover our investment. When we believe the costs of the unproved 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 recorded impairment provisions attributable to unproved properties of $82.9 million for the three months ended June 30, 2009, including $38.6 million related to our non-operated Piceance leasehold in Garden Gulch, $26.7 million related to leasehold in the Haynesville Shale, $14.7 million related to leasehold in Lighthouse Bayou, and $2.3 million related to expired and expiring acreage in the Newton field. In addition, we recorded an impairment of $10.5 million to reduce our Vega area land carrying value to its estimated fair value. Lastly, we recorded an impairment of $1.9 million to reduce the Paradox pipeline carrying value to its estimated fair value. These impairments are included within dry hole costs and impairments in the accompanying statement of operations for the three months ended June 30, 2009.

During the remainder of 2009, we are continuing to evaluate certain proved and unproved properties on which favorable or unfavorable results or fluctuations in commodity prices may cause us to revise in future periods our estimates of future cash flows from those properties. Such revisions of estimates could require us to record an impairment in the period of such revisions.

Commodity Derivative Instruments and Hedging Activities

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

All derivative instruments are recorded on the balance sheet at fair value which must be estimated using complex valuation models. Effective July 1, 2007, we elected to discontinue cash flow hedge accounting prospectively. Beginning July 1, 2007, we recognize mark-to-market gains and losses in current earnings instead of deferring those amounts in accumulated other comprehensive income. As of June 30, 2009, we had a total of seven oil and gas derivative contracts outstanding. The fair value of our oil derivative instruments was a liability of $13.2 million and the fair value of our gas derivative instruments was a liability of $7.9 million at June 30, 2009. The liability is discounted based on our credit-worthiness and accordingly the liability reflected is less than the actual cash expected to be paid upon settlement based on forward prices as of June 30, 2009. The pre-credit risk adjusted fair value of our net derivative liabilities as of June 30, 2009 was $26.5 million. A credit risk adjustment of $5.4 million to the fair

value of the derivatives required by Statement 157 reduced the reported amount of the net derivative liabilities on our consolidated balance sheet to $21.1 million.

Asset Retirement Obligation

We account for our asset retirement obligations under SFAS 143. SFAS 143 requires entities to record the fair value of a liability for retirement obligations of acquired assets. Our asset retirement obligations arise from the plugging and abandonment liabilities for our oil and gas wells. The fair value is estimated based on a variety of assumptions including discount and inflation rates and estimated costs and timing to plug and abandon wells.

Deferred Tax Asset Valuation Allowance

We follow SFAS 109 to account for our deferred tax assets and liabilities. Under SFAS 109, deferred tax assets and liabilities are recognized for the estimated future tax effects attributable to temporary differences and carryforwards. Ultimately, realization of a deferred tax benefit depends on the existence of sufficient taxable income within the carryback/carryforward period to absorb future deductible temporary differences or a carryforward. In assessing the realizability of deferred tax assets, management must consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. Management considers all available evidence (both positive and negative) in determining whether a valuation allowance is required. Such evidence includes the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment, and judgment is required in considering the relative weight of negative and positive evidence. As a result of management’s current assessment, we maintain a significant valuation allowance against our deferred tax assets. We will continue to monitor facts and circumstances in our reassessment of the likelihood that operating loss carryforwards and other deferred tax attributes will be utilized prior to their expiration. As a result, we may determine that the deferred tax asset valuation allowance should be increased or decreased. Such changes would impact net income through offsetting changes in income tax expense or benefit.

Recently Adopted Accounting Pronouncements

In March 2008, the FASB affirmed FASB Staff Position (“FSP”) APB 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash Upon Conversion (Including Partial Cash Settlement)”. The FSP requires the proceeds from the issuance of convertible debt instruments to be allocated between a liability component (debt issued at a discount) and an equity component. The resulting debt discount is amortized over the period the convertible debt is expected to be outstanding as additional non-cash interest expense. The FSP was adopted effective January 1, 2009. This FSP changes the accounting treatment for our 3 ³ / 4 % Senior Convertible Notes issued April 25, 2007 and was applied retrospectively upon adoption. The fair value of the liability and equity components were determined based on our estimated borrowing rate at the date of issuance and, as a result, the liability component was approximately $92.7 million and the equity component was approximately $22.3 million. Based on these components at the issue date we recorded a reduction to the carrying value of the Notes of $22.3 million upon adoption of the FSP, with a corresponding increase in additional paid in capital. The accompanying consolidated financial statements include accretion of the resulting debt discount of approximately $1.1 million and $2.2 million for the three and six months ended June 30, 2009 and approximately $1.1 million and $2.1 million for the three and six months ended June 30, 2008. The remaining discount will be amortized through May 2012 when the holders of the Notes can first require us to purchase all or a portion of the Notes. Combined with the amortization of debt discount, the Notes have an effective interest rate of approximately 7.6% and 7.4% with total interest costs of $2.2 million and $2.1 million for the three month periods ended June 30, 2009 and 2008, respectively, and interest costs of $4.3 million and $4.2 million for the six month periods ended June 30, 2009 and 2008, respectively.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities - an amendment of FASB Statement No. 133 (“SFAS 161”). This Statement requires enhanced disclosures for derivative and hedging activities. This statement was effective for us on January 1, 2009. We have included the new required disclosures in these financial statements.

In December 2007, the FASB issued SFAS No. 160, “Non-Controlling Interests in Consolidated Financial Statements – an amendment of Accounting Research Bulletin No. 51” (“SFAS 160”), which establishes accounting and reporting standards for non-controlling interests (“minority interests”) in subsidiaries. SFAS 160 clarifies that a non-controlling interest in a subsidiary should be accounted for as a component of equity separate from the parent’s equity. SFAS 160 was effective for us on January 1, 2009 and must be applied prospectively, except for the presentation and disclosure requirements, which have been applied retrospectively. The adoption of this statement had the effect of increasing total equity by the amount of the non-controlling interest and changing other presentations in the accompanying financial statements.

In April 2009, the FASB issued FSP No. 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments” (“FSP 107-1”). The adoption of FSP 107-1 is not expected to have an impact on the Company’s consolidated financial statements, other than requiring additional disclosures. FSP 107-1 requires disclosures about fair value of financial instruments in financial statements for interim reporting periods of publicly traded companies as well as in annual financial statements. FSP 107-1 is effective for interim and annual reporting periods ending after June 15, 2009 with such disclosures included herein as applicable

In May 2009, the FASB issued SFAS 165, “Subsequent Events.” The objective of this Statement is to establish general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. In particular, this Statement sets forth the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements; the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements; and the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. SFAS No. 165 was effective for us beginning with the Quarterly Report on Form 10-Q for the quarter ended June 30, 2009. The implementation of this standard did not have a material impact on our financial statements. Subsequent events were evaluated through the date of issuance of these consolidated financial statements on August 6, 2009 at the time this Quarterly Report on Form 10-Q was filed with the Securities and Exchange Commission.

Recently Issued Financial Reporting Pronouncements

On December 31, 2008, the SEC published final rules and interpretations updating its oil and gas reporting requirements. Many of the revisions are updates to definitions in the existing oil and gas rules to make them consistent with the Petroleum Resource Management System, which is a widely accepted standard for the management of petroleum resources that was developed by several industry organizations. Key revisions include the ability to include nontraditional resources in reserves, the use of new technology for determining reserves, permitting disclosure of probable and possible reserves, and changes to the pricing used to determine reserves based on a 12-month average price rather than a period end spot price. The average is to be calculated using the first-day-of-the-month price for each of the 12 months that make up the reporting period. The new rules are effective for annual reports for fiscal years ending on or after December 31, 2009. Early adoption is not permitted. We are currently assessing the impact that the adoption will have on our consolidated financial statements and disclosures.

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, which may from time to time include costless collars, swaps, or puts. The level of our hedging activity and the duration of the instruments employed depend upon our view of market conditions, available hedge prices and our operating strategy. We use hedges to limit the risk of fluctuating cash flows that fund our capital expenditure program. We also may use hedges in conjunction with acquisitions to achieve expected economic returns during the payout period.

The following table summarizes our open derivative contracts at June 30, 2009:


									Net Fair Value
									Asset (Liability) at
Commodity	Volume			Fixed Price		Term		Index Price	June 30, 2009
									(In thousands)

Crude oil		1,000	Bbls / Day	$	52.25	Jul ’09	- Dec ’09	NYMEX – WTI		$ (3,443	)
Crude oil		1,000	Bbls / Day	$	52.25	Jan ’10	- Dec ’10	NYMEX – WTI		(7,065	)
Crude oil		500	Bbls / Day	$	57.70	Jan ’11	- Dec ’11	NYMEX – WTI		(2,660	)
Natural gas		4,000	MMBtu / Day	$	5.720	Aug ’09	- Dec ’09	NYMEX – HHUB		753
Natural gas		6,000	MMBtu / Day	$	5.720	Jan ’10	- Dec ’10	NYMEX – HHUB		(593	)
Natural gas		10,000	MMBtu / Day	$	4.105	Aug ’09	- Dec ’09	CIG		1,202
Natural gas		15,000	MMBtu / Day	$	4.105	Jan ’10	- Dec ’10	CIG		(4,641	)
Natural gas		4,373	MMBtu / Day	$	3.973	Aug ’09	- Dec ’09	CIG		439
Natural gas		5,367	MMBtu / Day	$	3.973	Jan ’10	- Dec ’10	CIG		(1,878	)
Natural gas		12,000	MMBtu / Day	$	5.150	Jan ’11	- Dec ’11	CIG		(2,464	)
Natural gas		3,253	MMBtu / Day	$	5.040	Jan ’11	- Dec ’11	CIG		(761	)

										$(21,111	)

Assuming production and the percent of oil and gas sold remained unchanged for the three months ended June 30, 2009, a hypothetical 10% decline in the average market price we realized during the three months ended June 30, 2009 on unhedged production would reduce our oil and natural gas revenues by approximately $2.1 million.

Interest Rate Risk

We were subject to interest rate risk on $166.3 million of variable rate debt obligations at June 30, 2009. The annual effect of a 10% change in interest rates on the debt would be approximately $1.3 million.

Item 4. Controls and Procedures

Disclosure Controls and Procedures

Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rule 13a-15(e) under the Exchange Act. Based on this evaluation, our management, including our principal executive officer and our principal financial officer, concluded that our disclosure controls and procedures were effective as of June 30, 2009, to ensure that information required to be disclosed by us in the reports filed or submitted by us under the Exchange Act (i) is recorded, processed, summarized and reported within the time period specified in SEC rules and forms, and (ii) is accumulated and communicated to our management, including our principal executive officer and our principal financial officer, as appropriate to allow appropriate decisions on a timely basis regarding required disclosure.

Internal Control over Financial Reporting

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

PART II - OTHER INFORMATION

Item 1. Legal Proceedings.

Offshore Litigation

Prior to June 30, 2009, we owned direct and indirect ownership interests ranging from 2.49% to 100% in five unproved undeveloped offshore oil and gas properties near Santa Barbara, California with an aggregate carrying value of $17.0 million at December 31, 2008. These property interests represented the right to explore for, develop and produce oil and gas from offshore federal lease units. The ownership rights in each of these properties were retained under various suspension notices issued by the Mineral Management Service (MMS) of the U.S. federal government whereby, as long as the owners of each property were progressing toward defined milestone objectives, the owners’ rights with respect to the properties continued to be maintained. The issuance of the suspension notices was necessitated by the numerous delays in the exploration and development process resulting from regulatory requirements imposed on the property owners by federal, state and local agencies.

In 2001, however, a Federal Court in the case of California v. Norton, et al. ruled that the MMS did not have the power to grant suspensions on the subject leases without first making a consistency determination under the Coastal Zone Management Act (“CZMA”), and ordered the MMS to set aside its approval of the suspensions of our offshore leases and to direct suspensions for a time sufficient for the MMS to provide the State of California with the required consistency determination. In response to the ruling in the Norton case, the MMS made a consistency determination under the CZMA and the leases were then still valid.

Further actions to develop the leases were then delayed, however, pending the outcome of a separate lawsuit (the “Amber Case”) that was filed in the United States Court of Federal Claims (the “Court”) in Washington, D.C. by us, our 92%-owned subsidiary, Amber Resources Company of Colorado (“Amber”), and ten other property owners alleging that the U.S. government materially breached the terms of 40 undeveloped federal leases, some of which are part of our and Amber’s offshore California properties. On November 15, 2005 and October 31, 2006, the Court granted summary judgment as to liability and partial summary judgment as to damages with respect to 36 of the 40 total federal leases that are the subject of the litigation. Under a restitution theory of damages, the Court ruled that the government must return to the current lessees the more than $1.1 billion in lease bonuses it had received at the time of sale. On January 12, 2008, the Court entered an order of final judgment awarding the lessees restitution of the original lease bonuses paid for 35 of the 40 lawsuit leases. Under this order, in May of 2009 we received a gross amount of approximately $58.5 million and Amber received a gross amount of approximately $1.5 million as reimbursement for the lease bonuses paid for all lawsuit leases other than Lease 452, which is a single lease owned entirely by us and separated from the main body of the litigation by a motion for reconsideration, as discussed below.

As mentioned above, Lease 452 was separated from the main body of the litigation by a motion filed by the government on January 19, 2006 seeking reconsideration of the Court’s ruling as it related to Lease 452. In seeking reconsideration, the government asserted that we should not be able to recover lease bonus payments for Lease 452 because, allegedly, a significant portion of the hydrocarbons had been drained by wells that were drilled on an immediately adjacent lease. The amount of lease bonus payments attributable to Lease 452 is approximately $91.4 million. A trial on the motion for reconsideration was completed in January 2008 and oral arguments were completed in June 2008. On February 25, 2009 the Court entered a judgment in our favor in the amount of $91.4 million with respect to our claim to recover lease bonus payments for Lease 452. On April 24, 2009 the government filed a notice of appeal of this judgment, but it has not yet filed its opening brief in the appeal.

Overriding royalty interests in certain litigation proceeds were granted in connection with the acquisition and financing of Lease 452 (among others) in December of 1999. As a result of these overrides, Kaiser-Francis Oil Company may be entitled to receive 5% of the net amount of the litigation proceeds received from Lease 452, BWAB Limited Liability Company may be entitled to receive 3%, and each of Aleron H. Larson, Jr. and Roger A. Parker may be entitled to receive 1%. Pursuant to an agreement dated November 2, 2000, we are also obligated to pay the owners of the Point Arguello Unit 20% of the net cash amount of litigation proceeds received from Lease 452 after deducting all compensation to be paid to attorneys and all reasonable and necessary expenses incurred. The net amount of these payments is currently estimated to be approximately $23.0 million.

Item 1A. Risk Factors

A description of the risk factors associated with our business is contained in Item 1A, “Risk Factors,” of our 2008 Annual Report on Form 10-K for the year ended December 31, 2008 filed with the SEC on February 29, 2009 and is incorporated herein by reference. In addition, we are subject to the following risks:

Risks relating to our business and industries

We incurred operating and net losses in 2008 and the first six months of 2009, and may continue to be adversely affected by low natural gas prices.

We incurred an operating loss of $464.5 million and a net loss attributable to Delta common stockholders of $456.1 million in 2008. For the six month period ended June 30, 2009, our operating loss was $155.5 million and our net loss attributable to Delta common stockholders was $197.9 million. Our results of operations are affected by changes in natural gas and oil prices, which declined significantly during the fourth quarter of 2008 and the first six months of 2009 and remain at low levels. There is a significant glut of natural gas production in the United States, and it may continue to depress prices regardless of general economic conditions. In addition, current economic fundamentals portray a dismal outlook for natural gas prices for at least the remainder of 2009. Until natural gas and oil prices increase significantly, our results will continue to be adversely affected.

We are not in compliance with certain financial covenants in our credit agreement, and we face significant immediate requirements to fund obligations in excess of our existing sources of liquidity.

Prior to the consummation of our equity offering in May 2009, we were not in compliance with certain covenants in our credit agreement. As a result of the covenant defaults, we classified the debt outstanding under our credit agreement as of December 31, 2008 as a current liability in our consolidated balance sheet. Because of our net loss attributable to Delta common stockholders of $456.1 million for the year ended December 31, 2008, our working capital deficiency of $341.8 million at that date, including the debt outstanding under our credit agreement, and our significant immediate and long-term obligations in excess of our existing sources of liquidity, our auditors have issued an audit report on our 2008 annual financial statements that contains a “going concern” explanatory paragraph.

We have taken several steps to mitigate our liquidity concerns, including entering into two forbearance agreements with our lenders and completing an equity offering. In addition, we have reduced our capital expenditure program and implemented additional cost saving measures, including two reductions in force affecting approximately one-half of our personnel. While these steps and receipt of the net proceeds from the favorable litigation judgment described above have mitigated our immediate liquidity concerns, we can provide no assurances that we will have sufficient resources to fund our cash needs in the future. Our ability to fund our cash needs in the future will be dependent on some combination of improved natural gas and oil prices, decreased operating costs, and success in our efforts to access additional capital markets funding, make non-core assets dispositions or receive financial support from new joint venture partners for which no assurances can be given. There can be no assurance that we will in fact meet our covenant requirements in the foreseeable future. If we do not meet these covenants, our lenders would be entitled to accelerate our outstanding debt in accordance with the terms of the credit agreement, and we may be unable to negotiate another forbearance agreement with them. If we are unsuccessful in negotiating a forbearance agreement, we cannot assure you that we will not have to seek bankruptcy protection.

Sources of liquidity sufficient to fund our current operations may be unavailable to us.

Our efforts to improve our liquidity position will be very challenging given the current economic climate. Current economic fundamentals portray a dismal outlook for the oil and natural gas exploration and development business for at least the remainder of 2009 due to extremely low and volatile oil and natural gas prices, in particular natural gas prices, since natural gas production represents approximately 80% of our total production for the six months ended June 30, 2009, coupled with a global recession that is projected to be the longest and most severe in the post- World War II period. These economic conditions have resulted in a decline in our revenues, cash flow, and available capital, and have caused us to significantly decrease our drilling activities and operations. Moreover, the full effect of many of

the actions that we have taken to improve our liquidity will not be realized until later in 2009, even if they are successfully implemented.

There is no assurance that industry or capital markets conditions will improve in the near term. Even if we are successful in completing capital raising transactions, and implement the operating actions that are substantially within our control, our liquidity in the future may not be sufficient to operate our business and to satisfy the requirements of our credit agreements.

DHS has significant near-term liquidity issues.

DHS is currently not in compliance with its financial covenants in its credit agreement, pursuant to which it had $83.3 million outstanding as of June 30, 2009.

On August 15, 2008, DHS entered into an agreement with Lehman Commercial Paper, Inc. (“LCPI”) to amend its existing LCPI credit facility. The revised agreement increased the borrowing base from $75.0 million to $150.0 million. Because of LCPI’s bankruptcy and default, DHS does not have any additional borrowing capacity under the LCPI facility. Under the revised agreement, DHS has an obligation to provide to LCPI by March 31 of each year audited financial statements reported on without a going concern qualification or exception by the independent auditor. DHS was not able to provide audited financial statements not containing an explanatory paragraph related to its ability to continue as a going concern, and accordingly, DHS was not in compliance with this covenant June 30, 2009. As a result of this and additional financial covenant violations as of June 30, 2009, we have classified the entire $83.3 million of debt outstanding under the DHS credit agreement as a current liability in our consolidated balance sheet as of June 30, 2009.

In conjunction with the DHS Forbearance, DHS paid a fee of $250,000 and made a $1.25 million prepayment on the credit agreement. During the forbearance period, DHS was required to use 75% of any accounts receivable collected to pay down its credit agreement. Delta is a significant debtor of DHS, with accounts payable to DHS of approximately $27.0 million as of June 30, 2009.

At June 30, 2009, DHS was not in compliance with its minimum EBITDA, maximum leverage ratio, minimum interest coverage ratio and minimum current ratio financial covenants. As a result of these events, we have classified the entire $83.3 million of debt outstanding under the DHS credit facility as a current liability in the accompanying consolidated balance sheet as of June 30, 2009. Since the DHS Forbearance has expired, LCPI currently has the right to demand payment of the amounts outstanding under the credit facility and if not paid, foreclose on the DHS assets pledged as collateral for the credit facility. Although LCPI has not exercised its right to foreclose on the DHS assets pledged as collateral and DHS in currently in negotiations with LCPI to amend the terms of the credit facility, there can be no assurance that LCPI will not exercise its right to foreclose on the DHS assets pledged as collateral, including all of the DHS rigs. In the event DHS is deemed insolvent, we may need to writedown or write-off our investment in DHS.

Natural gas and oil prices are volatile. Declining prices have adversely affected our financial position, financial results, cash flows, access to capital and ability to grow.

Our revenues, operating results, profitability and future rate of growth depend primarily upon the prices we receive for the natural gas and oil we sell. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. The amount we can borrow from banks is subject to periodic redeterminations based on prices specified by our lenders at the time of redetermination. In addition, we may have asset carrying value writedowns if prices fall, as was the case in 2008 and the second quarter of 2009.

Historically, the markets for natural gas and oil have been volatile and they are likely to continue to be volatile. Wide fluctuations in natural gas and oil prices may result from relatively minor changes in the supply of and demand for natural gas and oil, market uncertainty and other factors that are beyond our control, including:

•

worldwide and domestic supplies of natural gas and oil;

•

the level of consumer demand;

•

overall domestic and global economic conditions;

•

the price and availability of alternative fuels;

•

the proximity and capacity of natural gas pipelines and other transportation facilities;

•

the price and level of foreign imports;

•

weather conditions;

•

domestic and foreign governmental regulations and taxes;

•

the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls; and

•

political instability or armed conflict in oil-producing regions.

These factors and the volatility of the energy markets make it extremely difficult to predict future natural gas and oil price movements with any certainty. Declines in natural gas and oil prices not only reduce revenue, but also reduce the amount of natural gas and oil that we can produce economically and, as a result, have had, and could in the future have a material adverse effect on our financial condition, results of operations, cash flows and reserves.

Further, natural gas and oil prices do not necessarily move in tandem. Because approximately 94% of our reserves at December 31, 2008 were natural gas reserves, we are more affected by movements in natural gas prices.

Further reduction of our credit ratings, or failure to restore our credit ratings to higher levels, could have a material adverse effect on our business.

Our credit ratings have been downgraded to historically low levels. As of June 30, 2009, our corporate rating and senior unsecured debt rating were Caa3 and Ca, respectively, as issued by Moody’s Investors Service. Moody’s outlook is “negative.” As of June 30, 2009, our corporate credit and senior unsecured debt ratings were CCC and CC, respectively, as issued by Standard and Poor’s. S&P’s outlook is “developing.” Our credit ratings reflect the agencies’ concerns over our financial strength. Our current credit ratings reduce our access to the unsecured debt markets and will unfavorably impact our overall cost of borrowing. Further downgrades of our current credit ratings or significant worsening of our financial condition could adversely affect our borrowing costs, reduce our access to capital and increase interest costs on our borrowings, and could also result in increased demands by our suppliers for accelerated payment terms or other more onerous supply terms.

Our level of indebtedness could adversely affect our ability to raise additional capital to fund our operations, limit our ability to react to changes in the economy or our industry and prevent us from meeting our obligations under our indebtedness and to third parties generally.

As of June 30, 2009, our total outstanding indebtedness was $417.7 million, including $83.0 million of outstanding borrowings drawn under our credit agreement which are classified as a current liability in our consolidated balance sheet. In addition, as of June 30, 2009, $83.3 million of outstanding borrowings by our subsidiary DHS under its credit facility were classified as a current liability. Our indebtedness (excluding installments payable on property

acquisitions secured by restricted cash deposits) represented 33.4% of our total book capitalization (total debt, excluding installments payable, plus total equity) at June 30, 2009. As of June 30, 2009, we had $140.8 million of additional availability under our credit agreement. Our 7% senior notes’ indenture currently limits our incurrence of additional secured borrowings.

Our degree of leverage could have important consequences, including the following:

•

it may limit our ability to obtain additional debt or equity financing for working capital, capital expenditures, further exploration, debt service requirements, acquisitions and general corporate or other purposes;

•

a substantial portion of any cash flows from operations will be dedicated to the payment of principal and interest on our indebtedness and will not be available for other purposes, including our operations, capital expenditures and future business opportunities;

•

the debt service requirements of other indebtedness in the future could make it more difficult for us to satisfy our financial obligations;

•

certain of our borrowings, including borrowings under our credit agreement, are at variable rates of interest, exposing us to the risk of increased interest rates;

•

as we have pledged most of our natural gas and oil properties and the related equipment, inventory, accounts and proceeds as collateral for the borrowings under our credit agreement, they may not be pledged as collateral for other borrowings and would be at risk of foreclosure in the event of a default thereunder;

•

it may limit our ability to adjust to changing market conditions and place us at a competitive disadvantage compared to our competitors that have less debt;

•

our business is vulnerable in the present downturn to general economic conditions, and we will be unable to carry out capital spending and exploration activities that are important to our growth; and

•

we have recently been out of compliance with covenants under our credit agreement, which has required us to seek waivers and/or forbearance agreements from our lenders. In the future, waivers and/or forbearance agreements may be more difficult to obtain because of the current economic environment. As discussed above, the credit agreement requires us to repay significant amounts outstanding under our credit agreement in the near term, and failure to do so could result in acceleration of amounts due thereunder.

We may incur additional debt, including secured indebtedness, or issue preferred stock in order to maintain adequate liquidity, develop our properties and make future acquisitions. A higher level of indebtedness increases the risk that we may default on our obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions, natural gas and oil prices and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. Factors that will affect our ability to raise cash through an offering of our capital stock or a refinancing of our debt include financial market conditions, the value of our assets, the number of shares of capital stock we have authorized, unissued and unreserved, and our performance at the time we need capital.

In addition, our bank borrowing base is subject to periodic redetermination, with the next determination date scheduled for September 1, 2009. A further reduction to our borrowing base could require us to repay indebtedness of amounts outstanding above the borrowing base, or we might be required to provide the lenders with additional collateral. We are currently engaged in seeking capital from a number of sources, including potential joint ventures or similar industry partnerships or asset dispositions to enhance our liquidity. We may not be able to complete some or any of these steps. Even if we do, we cannot assure you that the terms will be satisfactory to us or sufficiently enhance our liquidity.

The current financial crisis may impact our business and financial condition in ways we cannot predict.

The continued credit crisis and related turmoil in the global financial system may continue to have an impact on our business and our financial condition, and we may continue to face challenges if conditions in the financial markets do not improve. Anticipated internally generated cash flow, cash resources and other sources of liquidity historically have not been sufficient to fund all of our expenditures, and we have relied on the capital markets and asset monetization transactions to provide us with additional capital. Our ability to access the capital markets has been restricted as a result of this crisis and may be restricted in the future when we would like, or need, to raise capital. The financial crisis may also limit the number of prospects for our potential joint venture or asset monetization transactions or reduce the values we are able to realize in those transactions, making these transactions uneconomic or difficult to consummate. The economic situation could also adversely affect the collectability of our trade receivables and cause our commodity hedging arrangements, if any, to be ineffective if our counterparties are unable to perform their obligations or seek bankruptcy protection. Additionally, the current economic situation could lead to further reduced demand for natural gas and oil, or lower prices for natural gas and oil, or both, which would have a negative impact on our revenues.

We have recently engaged in, and marketed certain of our assets in, joint venture transactions that monetize, or would monetize, a portion of our investment in certain plays and provide drilling cost carries for our retained interest. If our joint venture partners in these transactions and proposed transactions, if completed, were not able to meet their obligations under these arrangements, we may be required to fund these expenditures from other sources or further reduce our drilling activities. In addition, we cannot assure you that we will complete any such proposed transaction.

Information concerning our reserves is uncertain.

There are numerous uncertainties inherent in estimating quantities of proved reserves and cash flows from such reserves, including factors beyond our control. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of an estimate of quantities of oil and natural gas reserves, or of cash flows attributable to such reserves, is a function of the available data, assumptions regarding future oil and natural gas prices, availability and terms of financing, expenditures for future development and exploitation activities, and engineering and geological interpretation and judgment. Reserves and future cash flows may also be subject to material downward or upward revisions based upon production history, development and exploitation activities, oil and natural gas prices and regulatory changes. Actual future production, revenue, taxes, development expenditures, operating expenses, quantities of recoverable reserves and value of cash flows from those reserves may vary significantly from our assumptions and estimates. In addition, reserve engineers may make different estimates of reserves and cash flows based on the same data. Further, the difficult financing environment may inhibit our ability to finance development of our reserves in the future.

The estimated quantities of proved reserves and the discounted present value of future net cash flows attributable to those reserves as of December 31, 2008, 2007 and 2006 included in our periodic reports filed with the SEC were prepared by our independent reserve engineers in accordance with the rules of the SEC, and are not intended to represent the fair market value of such reserves. As required by the SEC, the estimated discounted present value of future net cash flows from proved reserves is generally based on prices and costs as of the date of the estimate, while actual future prices and costs may be materially higher or lower. In addition, the 10% discount factor, which the SEC requires to be used to calculate discounted future net revenues for reporting purposes, is not necessarily the most appropriate discount factor based on the cost of capital in effect from time to time and risks associated with our business and the oil and gas industry in general.

Although the proved undeveloped reserves attributable to our Piceance Basin properties are not economic using spot natural gas prices as of June 30, 2009, we believe they are economically recoverable based on applicable current quoted natural gas and crude oil futures prices. The Piceance Basin properties contain nearly all of our proved undeveloped reserves. Further development of these properties depends on higher commodity prices in the future, reductions in future drilling costs, or a combination of both, and availability of capital from internal or external sources, such as joint venture partners.

If we are not able to replace reserves, we may not be able to sustain production.

Our future success depends largely upon our ability to find, develop or acquire additional natural gas and oil reserves that are economically recoverable. Unless we replace the reserves we produce through successful development, exploration or acquisition activities, our proved reserves and production will decline over time. In addition, approximately 80% of our total estimated proved reserve quantities at December 31, 2008 were undeveloped. By their nature, estimates of undeveloped reserves are less certain. Recovery of such reserves will require significant capital expenditures and successful drilling operations. Thus our future natural gas and oil reserves and production and, therefore, our cash flow and income are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves.

Exploration and development drilling may not result in commercially productive reserves.

We do not always encounter commercially productive reservoirs through our drilling operations. The new wells we drill or participate in may not be productive and we may not recover all or any portion of our investment in wells we drill or participate in. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that oil or natural gas is present or may be produced economically. The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. Our efforts will be unprofitable if we drill dry wells or wells that are productive but do not produce enough reserves to return a profit after drilling, operating and other costs. Further, our drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

•

increases in the cost of, or shortages or delays in the availability of, drilling rigs and equipment;

•

unexpected drilling conditions;

•

title problems;

•

pressure or irregularities in formations;

•

equipment failures or accidents;

•

adverse weather conditions; and

•

compliance with environmental and other governmental requirements.

If natural gas or oil prices continue to decrease or exploration and development efforts are unsuccessful, we may be required to take further writedowns.

We have been required to write down the carrying value of our oil and gas properties and other assets. For example, we recorded impairment provisions attributable to unproved properties of $82.9 million for the three months ended June 30, 2009, including $38.6 million related to our non-operated Piceance leasehold in Garden Gulch, $26.7 million related to leasehold in the Haynesville Shale, $14.7 million related to leasehold in Lighthouse Bayou, and $2.3 million related to expired and expiring acreage in the Newton field. In addition, we recorded an impairment of $10.5 million to reduce our Vega area land carrying value to its estimated fair value. Lastly, we recorded an impairment of $1.9 million to reduce the Paradox pipeline carrying value to its estimated fair value. These impairments are included within dry hole costs and impairments in the accompanying statement of operations for the three months ended June 30, 2009. During the second quarter of 2009, we adjusted the timing of the development of the Garden Gulch properties to delay the drilling of additional wells. In addition, during the quarter, another working interest owner in the property sold their interest to an undisclosed buyer for an implied price less than the carrying value of our properties. With respect to our Haynesville Shale leasehold, during the second quarter of 2009, we began preparing prospect materials to support efforts to market the leasehold, including efforts to consolidate acreage blocks to optimize marketability, and received offers on certain portions of the leasehold at prices less than our carrying value. With respect to our Lighthouse Bayou leasehold, we were obligated under our exploration and development agreement, as amended, to spud an initial test well by July 1, 2009. In late May 2009, an amendment to the

agreement was executed whereby the leases reverted to the original seller and we retained an option to participate in future transactions, if any, related to the leases contained in the area of mutual interest. With respect to the Vega area surface acreage, during the second quarter of 2009, we entered into negotiations to sell a portion of our surface acreage to an existing land owner in the area as part of an attempt to resolve access and right of way issues related to the development of the minerals and are in the process of the marketing the remaining surface acreage. With respect to the Paradox pipeline, we received an offer for the associated gas plant for an amount less than the carrying value. In each case, as a result of the events and activities described, we evaluated our unproved leasehold or surface acreage and concluded that an impairment had occurred.

There is a risk that we will be required to take additional writedowns in the future, which would reduce our earnings and stockholders’ equity. A writedown could occur when oil and natural gas prices are low or if we have substantial downward adjustments to our estimated proved reserves, increases in our estimates of development costs or deterioration in our exploration and development results.

We account for our crude oil and natural gas exploration and development activities utilizing the successful efforts method of accounting. Under this method, costs of productive exploratory wells (wells 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), development dry holes (wells found to be incapable of producing either oil or gas in sufficient quantities to justify completion as oil or gas wells) and productive wells and undeveloped leases are capitalized. Oil and gas lease acquisition costs are also capitalized. 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. If the carrying amount of our oil and gas properties exceeds the estimated undiscounted future net cash flows, we will adjust the carrying amount of the oil and gas properties to their estimated fair value.

We review our oil and gas properties for impairment quarterly or whenever events and circumstances indicate that the carrying value may not be recoverable. Once incurred, a writedown of oil and gas properties is not reversible at a later date even if gas or oil prices increase. Given the complexities associated with oil and gas reserve estimates and the history of price volatility in the oil and gas markets, events may arise that would require us to record an impairment of the recorded carrying values associated with our oil and gas properties.

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

At June 30, 2009, we had $24.0 million classified as exploratory work in process related primarily to our Columbia River Basin well currently being drilled. During 2009, these costs will be capitalized as successful wells if proved reserves are found or expensed as dry holes based on final drilling results.

Lower natural gas and oil prices have negatively impacted, and could continue to negatively impact, our ability to borrow.

Our credit agreement limits our borrowings to the lesser of the borrowing base and the total commitments. The borrowing base is determined periodically and is based in part on natural gas and oil prices. Additionally, the indenture governing our 7% senior notes contains covenants limiting our ability to incur indebtedness in addition to that incurred under our credit agreement. These agreements limit our ability to incur additional indebtedness unless we meet one of two alternative tests. The first alternative is based on our adjusted consolidated net tangible assets (as defined in our lending agreements), which is determined using discounted future net revenues from proved natural gas and oil reserves as of the end of each year. The second alternative is based on the ratio of our consolidated EBITDAX (as defined in the relevant indentures) to our adjusted consolidated interest expense over a trailing 12 month period. Currently our borrowing base has been redetermined at a level that will not permit additional borrowing under our credit agreement. Lower natural gas and oil prices in the future could reduce our consolidated EBITDAX, as well as our adjusted consolidated net tangible assets, and thus could reduce our ability to incur additional indebtedness. Lower natural gas and oil prices could also further reduce the borrowing base under our credit agreement, and if such borrowing base were reduced below the amount of borrowings outstanding, we would be required to repay an amount of borrowings such that outstanding borrowings do not exceed the borrowing base. Pursuant to the credit agreement,

our borrowing base under the credit agreement was reduced in May 2009 to $225.0 million with a $185.0 million conforming base, which will be redetermined effective September 1, 2009.

The exploration, development and operation of oil and gas properties involve substantial risks that may result in a total loss of investment.

The business of exploring for and, to a lesser extent, developing and operating oil and gas properties involves a high degree of business and financial risk, and thus a substantial risk of investment loss that even a combination of experience, knowledge and careful evaluation may not be able to overcome. Oil and gas drilling and production activities may be shortened, delayed or canceled as a result of a variety of factors, many of which are beyond our control. These factors include:

•

availability of capital;

•

unexpected drilling conditions;

•

pressure or irregularities in formations;

•

equipment failures or accidents;

•

adverse changes in prices;

•

adverse weather conditions;

•

title problems;

•

shortages in experienced labor; and

•

increases in the cost of, or shortages or delays in the delivery of equipment.

The cost to develop our proved reserves as of December 31, 2008 was estimated to be approximately $1.3 billion. In the current financing environment, we expect it to be difficult to obtain capital, which may limit our success in attracting joint venture or industry partners to develop our reserves. We may drill wells that are unproductive or, although productive, do not produce oil and/or natural gas in economic quantities. Acquisition and completion decisions generally are based on subjective judgments and assumptions that are speculative. It is impossible to predict with certainty the production potential of a particular property or well. Furthermore, a successful completion of a well does not ensure a profitable return on the investment. A variety of geological, operational, or market-related factors, including, but not limited to, unusual or unexpected geological formations, pressures, equipment failures or accidents, fires, explosions, blowouts, cratering, pollution and other environmental risks, shortages or delays in the availability of drilling rigs and the delivery of equipment, loss of circulation of drilling fluids or other conditions may substantially delay or prevent completion of any well or otherwise prevent a property or well from being profitable. A productive well may become uneconomic in the event water or other deleterious substances are encountered which impair or prevent the production of oil and/or natural gas from the well, or in the event of lower than expected commodity prices. In addition, production from any well may be unmarketable if it is contaminated with water or other deleterious substances.

Prices may be affected by regional factors.

The prices to be received for the natural gas production from our Rocky Mountain Region properties, where we are conducting a substantial portion of our development activities, will be determined to a significant extent by factors affecting the regional supply of and demand for natural gas, including the adequacy of the pipeline and processing infrastructure in the region to process, and transport, our production and that of other producers. Those factors result in basis differentials between the published indices generally used to establish the price received for regional natural gas production and the actual (frequently lower) price we receive for our production.

We are exposed to additional risks through our drilling business, DHS.

We currently have a 49.8% ownership interest in and management control of DHS, a drilling business. The operations of that entity are subject to many additional hazards that are inherent to the drilling business, including, for example, blowouts, cratering, fires, explosions, loss of well control, loss of hole, damaged or lost drill strings and damage or loss from inclement weather. No assurance can be given that the insurance coverage maintained by that entity will be sufficient to protect it against liability for all consequences of well disasters, personal injury, extensive fire damage or damage to the environment. No assurance can be given that the drilling business will be able to maintain adequate insurance in the future at rates it considers reasonable or that any particular types of coverage will be available. The occurrence of events, including any of the above-mentioned risks and hazards that are not fully insured, could subject the drilling business to significant liability. It is also possible that we might sustain significant losses through the operation of the drilling business even if none of such events occurs.

Hedging transactions may limit our potential gains or expose us to other risks.

In order to manage our exposure to price risks in the marketing of oil and gas, we periodically enter into oil and gas price hedging arrangements. While intended to reduce the effects of volatile oil and gas prices, such transactions, depending on the hedging instrument used, may limit our potential gains if oil and gas prices were to rise substantially over the price established by the hedge. In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:

•

production is substantially less than expected;

•

the counterparties to our futures contracts fail to perform under the contracts; or

•

a sudden, unexpected event materially impacts gas or oil prices.

The total gains on derivative instruments recognized in our statements of operations were $21.7 million, $10.0 million, and $7.0 million for the years ended December 31, 2008, 2007 and 2006, respectively. In accordance with the terms of our credit agreement, we have entered into derivative contracts which establish a floor price for 40% our anticipated production for the last two quarters of 2009, 70% for the calendar year 2010 and 50% for the calendar year 2011. For the six months ended June 30, 2009 we recorded approximately $21.1 million of unrealized noncash losses, and in the future we will record non-cash gains or losses depending on changes in the natural gas and oil prices between now and when we settle the derivative contracts.

Certain of our hedges may be ineffective due to basis differential.

Although the majority of our currently outstanding derivative contracts are based on the CIG index on which our Rocky Mountain natural gas is sold, certain of our derivative contracts are based on the NYMEX Henry Hub index. Whereas the Henry Hub is located in Texas, the natural gas production from our Rocky Mountain region properties, which comprises a significant percentage of our natural gas production, is not sold at the Henry Hub but rather in the Rocky Mountain region. Prices for natural gas are determined to a significant extent by factors affecting the regional supply of and demand for natural gas, which include quality, grade, and the degree to which pipeline and processing infrastructure exists in the region. Those factors result in basis differentials between the published indices generally used to establish the price received for regional natural gas production, such as the NYMEX Henry Hub index, and the actual (frequently lower) price we receive for our production. If the basis differential is significant, those particular hedges may not be effective.

We may not receive payment for a portion of our future production.

Our revenues are derived principally from uncollateralized sales to customers in the oil and gas industry. The concentration of credit risk in a single industry affects our overall exposure to credit risk because customers may be similarly affected by changes in economic and other conditions. Although we have not been directly affected, we are aware that some refiners have filed for bankruptcy protection, which has caused the affected producers to not receive payment for the production that was delivered. If economic conditions continue to deteriorate, it is likely that

additional, similar situations will occur which will expose us to added risk of not being paid for oil or gas that we deliver. We do not attempt to obtain credit protections such as letters of credit, guarantees or prepayments from our purchasers. We are unable to predict what impact the financial difficulties of any of our purchasers may have on our future results of operations and liquidity.

We are exposed to credit risk as it affects third parties with whom we have contracted.

Third parties with whom we have contracted may lose existing financing or be unable to obtain additional financing necessary to continue their businesses. The inability of a third party to make payments to us for our accounts receivable, or the failure of our third party suppliers to meet our demands because they cannot obtain sufficient credit to continue their operations, may cause us to experience losses and may adversely impact our liquidity and our ability to make our payments when due.

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

On May 26, 2009, our then Chairman of the Board of Directors and Chief Executive Officer, Roger A. Parker, resigned. In conjunction with Mr. Parker’s resignation, we entered into a Severance Agreement, effective as of the close of business on May 26, 2009, whereby Mr. Parker resigned from his positions as Chairman of the Board, Chief Executive Officer and as a director of Delta, as well as his positions as a director, officer and employee of Delta’s subsidiaries. In addition to cash consideration, we issued Mr. Parker 1,000,000 shares of Delta common stock that were deposited in a rabbi trust to be distributed to Mr. Parker on or about November 27, 2009. The shares were issued to Mr. Parker under Section 4(2) of the Securities Act.

The table below provides a summary of our purchases of our own common stock during the three months ended June 30, 2009.


							Maximum Number
					Total Number of		(or Approximate Dollar
					Shares (or Units)		Value) of Shares
	Total Number of		Average Price		Purchased as Part of		(or Units) that May Yet
	Shares (or Units)		Paid Per Share		Publicly Announced		Be Purchased Under
Period	Purchased (1)		(or Unit) (2)		Plans or Programs (3)		the Plans or Programs (3)
April 1 – April 30, 2009		6,734		$2.53		-		-
May 1 – May 31, 2009		-		-		-		-
June 1 – June 30, 2009		-		-		-		-

Total		6,734		$2.53		-		-

	(1)		Consists of shares delivered back to us by employees and/or directors to satisfy tax withholding obligations that arise upon the vesting of the stock awards. We, pursuant to our equity compensation plans, give participants the opportunity to turn back to us the number of shares from the award sufficient to satisfy the person’s tax withholding obligations that arise upon the termination of restrictions.

	(2)		The stated price does not include any commission paid.

	(3)		These sections are not applicable as we have no publicly announced stock repurchase plans.

Item 3. Defaults Upon Senior Securities. None.

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

The Annual Meeting of our stockholders was held on May 27, 2009. At the Annual Meeting, John R. Wallace, Hank Brown, Kevin R. Collins, Jerrie F. Eckelberger, Aleron H. Larson, Jr., Russell S. Lewis, James J. Murren, Jordan R. Smith, Daniel J. Taylor and James B. Wallace were reelected, and Anthony Mandekic and Jean-Michel Fonck were elected to serve as directors until the next annual meeting of stockholders.


			Withheld/
Name	For		Against

Roger A. Parker		72,088,452		1,353,440
John R. Wallace		72,087,847		1,354,045
Hank Brown		72,134,294		1,307,598
Kevin R. Collins		68,676,425		4,765,467
Jerrie F. Eckelberger		68,672,525		4,769,367
Aleron H. Larson, Jr.		72,124,371		1,317,521
Russell S. Lewis		68,675,281		4,766,611
James J. Murren		51,295,124		22,146,768
Jordan R. Smith		68,649,747		4,792,145
Daniel J. Taylor		72,965,663		476,229
James B. Wallace		72,111,560		1,330,332
Anthony Mandekic		72,945,980		495,912
Jean-Michel Fonck		72,947,785		494,107

The appointment of KPMG LLP as our independent registered public accounting firm for the year ending December 31, 2009 was ratified with 73,074,508 affirmative votes, 293,711 negative votes, and 73,673 abstentions.

Item 5. Other Information. None .

Item 6. Exhibits.

Exhibits are as follows:

10.1

Contingent Payment Rights Purchase Agreement by and between the Company and Tracinda Corporation, dated as of March 26, 2009. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K filed April 1, 2009.

10.2

Amendment Letter to First Amendment to Second Amended and Restated Credit Agreement dated April 14, 2009, among Delta Petroleum Corporation, JPMorgan Chase Bank, N.A. and certain other financial institutions named therein. Incorporated by reference from Exhibit 10.3 to the Company’s Form 8-K filed April 15, 2009.

10.3

Second Amendment Letter to First Amendment to Second Amended and Restated Credit Agreement dated April 30, 2009, by and among Delta Petroleum Corporation, JPMorgan Chase Bank, N.A. and certain other financial institutions named therein. Incorporated by reference from Exhibit 10.4 to the Company’s Form 8-K filed May 1, 2009.

10.4

Underwriting Agreement dated May 7, 2009. Incorporated by reference from Exhibit 1.1 to the Company’s Form 8-K filed May 13, 2009.

10.5

Contingent Payment Rights Repurchase Agreement by and between the Company and Tracinda Corporation, dated May 15, 2009. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K filed May 21, 2009.

10.6

Severance Agreement by and between Delta Petroleum Corporation and Roger Parker, dated May 26, 2009. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K filed June 1, 2009.

31.1

Certification of principal executive officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. Filed herewith electronically.

31.2

Certification of principal financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. Filed herewith electronically.

32.1

Certification of principal executive officer pursuant to 18 U.S.C. Section 1350. Filed herewith electronically.

32.2

Certification of principal 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/ John R. Wallace
		John R. Wallace, President and
		Chief Operating Officer


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

Date: August 6, 2009

EXHIBIT INDEX:

10.1

10.2

10.3

10.4

Underwriting Agreement dated May 7, 2009. Incorporated by reference from Exhibit 1.1 to the Company’s Form 8-K filed May 13, 2009.

10.5

10.6

Severance Agreement by and between Delta Petroleum Corporation and Roger Parker, dated May 26, 2009. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K filed June 1, 2009.

31.1

Certification of principal executive officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. Filed herewith electronically.

31.2

Certification of principal financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. Filed herewith electronically.

32.1

Certification of principal executive officer pursuant to 18 U.S.C. Section 1350. Filed herewith electronically.

32.2

Certification of principal financial officer pursuant to 18 U.S.C. Section 1350. Filed herewith electronically.

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