Par Pacific Holdings - 10-Q quarterly report FY

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended June 30, 2010


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

For the transition period from to

Commission file number 0-16203

DELTA PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)


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

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

(303) 293-9133
(Registrant’s telephone number, including area code)

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

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 o No o

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. (Check one):


Large accelerated filer o	Accelerated filer þ	Non-accelerated filer o	Smaller reporting company o
		(Do not check if a 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 o No þ

281,407,100 shares of common stock, $.01 par value per share, were outstanding as of August 2, 2010.

INDEX


	Page No.
PART I FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements

Consolidated Balance Sheets — June 30, 2010 and December 31, 2009 (unaudited)		1

Consolidated Statements of Operations — Three Months Ended June 30, 2010 and 2009 (unaudited)		2

Consolidated Statements of Operations — Six Months Ended June 30, 2010 and 2009 (unaudited)		3

Consolidated Statement of Changes in Equity — Six Months Ended June 30, 2010 (unaudited)		4

Consolidated Statements of Cash Flows — Six Months Ended June 30, 2010 and 2009 (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		50

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		50

Item 5. Other Information		50

Item 6. Exhibits		51

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

I

PART I FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(Unaudited)


	June 30,			December 31,
	2010			2009
	(In thousands, except share data)
ASSETS
Current assets:
Cash and cash equivalents	$	11,051		$	61,918
Short-term restricted deposits		100,000			100,000
Trade accounts receivable, net of allowance for doubtful accounts of $100 and $100, respectively		17,757			16,654
Oil and gas properties held for sale		99,902			—
Deposits and prepaid assets		2,051			3,103
Inventories		4,150			5,588
Other current assets		3,169			5,189

Total current assets		238,080			192,452

Property and equipment:
Oil and gas properties, successful efforts method of accounting:
Unproved		236,096			280,844
Proved		944,163			1,379,920
Drilling and trucking equipment		175,844			177,762
Pipeline and gathering systems		96,446			92,064
Other		15,681			16,154

Total property and equipment		1,468,230			1,946,744
Less accumulated depreciation and depletion		(578,771	)		(800,501	)

Net property and equipment		889,459			1,146,243


Long-term assets:
Long-term restricted deposit		100,000			100,000
Investments in unconsolidated affiliates		4,928			7,444
Deferred financing costs		2,442			3,017
Other long-term assets		6,163			8,329

Total long-term assets		113,533			118,790


Total assets	$	1,241,072		$	1,457,485


LIABILITIES AND EQUITY
Current liabilities:
Credit facility — Delta	$	119,538		$	—
Credit facility — DHS		73,590			83,268
Installments payable on property acquisition		99,144			97,874
Accounts payable		31,175			44,225
Liabilities related to oil and gas properties held for sale		7,280			—
Offshore litigation payable		—			13,877
Other accrued liabilities		11,628			13,459
Derivative instruments		4,705			19,497

Total current liabilities		347,060			272,200

Long-term liabilities:
Installments payable on property acquisition, net of current portion		96,619			95,381
7% Senior notes		149,647			149,609
3³/4% Senior convertible notes		106,268			104,008
Credit facility — Delta		—			124,038
Asset retirement obligations		4,620			7,654
Derivative instruments		1,319			7,475

Total long-term liabilities		358,473			488,165

Commitments and contingencies

Equity:
Preferred stock, $.01 par value:
authorized 3,000,000 shares, none issued		—			—
Common stock, $.01 par value: authorized 600,000,000 shares, issued 282,760,000 shares at June 30, 2010 and 282,548,000 shares at December 31, 2009		2,828			2,825
Additional paid-in capital		1,631,517			1,625,035
Treasury stock at cost; 34,000 shares at June 30, 2010 and 42,000 shares at December 31, 2009		(75	)		(268	)
Accumulated deficit		(1,101,557	)		(939,010	)

Total Delta stockholders’ equity		532,713			688,582

Non-controlling interest		2,826			8,538

Total equity		535,539			697,120


Total liabilities and equity	$	1,241,072		$	1,457,485

See accompanying notes to consolidated financial statements.

1

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)


	Three Months Ended
	June 30,
	2010			2009
	(In thousands, except per share amounts)
Revenue:

Oil and gas sales	$	25,067		$	19,267
Contract drilling and trucking fees		11,064			1,674
Loss on offshore litigation award and property sales, net		(109	)		(81	)


Total revenue		36,022			20,860


Operating expenses:

Lease operating expense		8,015			6,845
Transportation expense		4,454			2,178
Production taxes		1,377			1,061
Exploration expense		358			471
Dry hole costs and impairments		30,767			106,621
Depreciation, depletion, amortization and accretion — oil and gas		15,920			23,846
Drilling and trucking operating expenses		8,123			2,342
Depreciation and amortization — drilling and trucking		5,226			6,175
General and administrative		11,640			8,966
Executive severance expense, net		—			3,739


Total operating expenses		85,880			162,244


Operating loss		(49,858	)		(141,384	)


Other income and (expense):

Interest expense and financing costs, net		(9,556	)		(15,775	)
Other income (expense), net		(299	)		1,256
Realized loss on derivative instruments, net		(601	)		—
Unrealized gain (loss) on derivative instruments, net		3,676			(15,647	)
Income (loss) from unconsolidated affiliates		991			(3,617	)


Total other expense		(5,789	)		(33,783	)


Loss from continuing operations before income taxes and discontinued operations		(55,647	)		(175,167	)

Income tax expense		203			265


Loss from continuing operations		(55,850	)		(175,432	)

Discontinued operations:

Loss from discontinued operations, net of tax		(96,630	)		(5,051	)


Net loss		(152,480	)		(180,483	)

Less net loss attributable to non-controlling interest		2,730			8,165


Net loss attributable to Delta common stockholders	$	(149,750	)	$	(172,318	)


Amounts attributable to Delta common stockholders:
Loss from continuing operations	$	(53,120	)	$	(167,267	)
Loss from discontinued operations, net of tax		(96,630	)		(5,051	)

Net loss	$	(149,750	)	$	(172,318	)


Basic income (loss) attributable to Delta common stockholders per common share:
Loss from continuing operations	$	(0.19	)	$	(0.86	)
Discontinued operations		(0.35	)		(0.03	)

Net loss	$	(0.54	)	$	(0.89	)


Diluted income (loss) attributable to Delta common stockholders per common share:
Loss from continuing operations	$	(0.19	)	$	(0.86	)
Discontinued operations		(0.35	)		(0.03	)

Net loss	$	(0.54	)	$	(0.89	)

See accompanying notes to consolidated financial statements.

2

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)


	Six Months Ended
	June 30,
	2010			2009
	(In thousands, except per share amounts)
Revenue:

Oil and gas sales	$	54,970		$	38,116
Contract drilling and trucking fees		20,996			6,887
Gain (loss) on offshore litigation award and property sales, net		(538	)		31,204


Total revenue		75,428			76,207


Operating expenses:

Lease operating expense		15,202			14,749
Transportation expense		7,807			4,626
Production taxes		2,821			2,550
Exploration expense		584			1,531
Dry hole costs and impairments		31,121			108,064
Depreciation, depletion, amortization and accretion — oil and gas		31,339			45,850
Drilling and trucking operating expenses		16,012			7,598
Depreciation and amortization — drilling and trucking		10,798			11,967
General and administrative		23,027			21,594
Executive severance expense, net		—			3,739


Total operating expenses		138,711			222,268


Operating loss		(63,283	)		(146,061	)


Other income and (expense):

Interest expense and financing costs, net		(20,116	)		(32,201	)
Other income (expense), net		(170	)		1,408
Realized loss on derivative instruments, net		(4,714	)		—
Unrealized gain (loss) on derivative instruments, net		20,948			(21,111	)
Income (loss) from unconsolidated affiliates		983			(2,870	)


Total other expense		(3,069	)		(54,774	)


Loss from continuing operations before income taxes and discontinued operations		(66,352	)		(200,835	)

Income tax expense (benefit)		478			(318	)


Loss from continuing operations		(66,830	)		(200,517	)

Discontinued operations:

Loss from discontinued operations, net of tax		(101,642	)		(9,400	)


Net loss		(168,472	)		(209,917	)

Less net loss attributable to non-controlling interest		5,925			12,046


Net loss attributable to Delta common stockholders	$	(162,547	)	$	(197,871	)


Amounts attributable to Delta common stockholders:
Loss from continuing operations	$	(60,905	)	$	(188,471	)
Loss from discontinued operations, net of tax		(101,642	)		(9,400	)

Net loss	$	(162,547	)	$	(197,871	)


Basic income (loss) attributable to Delta common stockholders per common share:
Loss from continuing operations	$	(0.22	)	$	(1.29	)
Discontinued operations		(0.37	)		(0.06	)

Net loss	$	(0.59	)	$	(1.35	)


Diluted income (loss) attributable to Delta common stockholders per common share:
Loss from continuing operations	$	(0.22	)	$	(1.29	)
Discontinued operations		(0.37	)		(0.06	)

Net loss	$	(0.59	)	$	(1.35	)

See accompanying notes to consolidated financial statements.

3

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
(Unaudited)


							Additional									Accu-			Total Delta			Non-
	Common stock						paid-in			Treasury stock						mulated			stockholders’			controlling			Total
	Shares			Amount			capital			Shares			Amount			deficit			equity			interest			equity
	(In thousands)
Balance, December 31, 2009		282,548		$	2,825		$	1,625,035			42		$	(268	)	$	(939,010	)	$	688,582		$	8,538		$	697,120

Net loss		—			—			—			—			—			(162,547	)		(162,547	)		(5,925	)		(168,472	)
Employee vesting of treasury stock held by subsidiary		—			—			—			(10	)		150			—			150			(150	)		—
Issuance of vested stock		481			5			(5	)		—			—			—			—			—			—
Shares repurchased for withholding taxes		(9	)		—			(4	)		2			43			—			39			—			39
Forfeiture of restricted shares		(260	)		(2	)		2			—			—			—			—			—			—
Stock based compensation		—			—			6,489			—			—			—			6,489			363			6,852


Balance, June 30, 2010		282,760		$	2,828		$	1,631,517			34		$	(75	)	$	(1,101,557	)	$	532,713		$	2,826		$	535,539

See accompanying notes to consolidated financial statements.

4

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)


	Six Months Ended
	June 30,
	2010			2009
	(In thousands)
Cash flows from operating activities:
Net loss	$	(168,472	)	$	(209,917	)
Adjustments to reconcile net loss to cash provided by (used in) operating activities:
Basis in offshore properties recovered through litigation		—			17,497
Loss on property sales		538			—
(Gain) loss on sale of drilling rig		256			(1,724	)
Depreciation, depletion, amortization and accretion — oil and gas		31,339			45,850
Depreciation and amortization — drilling and trucking		10,798			11,967
Depreciation, depletion, amortization and accretion — discontinued operations		13,594			10,904
Stock based compensation		6,852			4,639
Executive severance payable in common stock		—			1,700
Executive severance — stock-based awards forfeited		—			(2,820	)
Amortization of deferred financing costs		4,707			7,717
Accretion of discount on installments payable		2,508			3,710
Unrealized (gain) loss on derivative instruments, net		(20,948	)		21,111
Dry hole costs and impairments		31,121			108,064
Impairments — discontinued operations		92,162			—
(Income) loss from unconsolidated affiliates		(983	)		3,204
Deferred income tax expense (benefit)		478			(318	)
Other		48			(21	)
Net changes in operating assets and liabilities:
(Increase) decrease in trade accounts receivable		(1,103	)		16,998
Decrease in deposits and prepaid assets		686			4,830
Increase in inventories		—			(1,252	)
(Increase) decrease in other current assets		765			(2,641	)
Decrease in accounts payable		(12,863	)		(5,385	)
Decrease in other accrued liabilities and offshore litigation payable		(14,756	)		(1,264	)


Net cash provided by (used in) operating activities		(23,273	)		32,849


Cash flows from investing activities:
Additions to property and equipment		(18,861	)		(122,438	)
Additions to drilling and trucking equipment		(709	)		(601	)
Proceeds from sale of oil and gas properties		2,007			—
Proceeds from sale of drilling assets and other fixed assets		503			7,823
Proceeds from sale of unconsolidated affiliate		3,500			—
Investment in unconsolidated affiliates		—			295
Proceeds from escrow deposit		1,380			—
(Increase) decrease in other long-term assets		106			(402	)


Net cash used in investing activities		(12,074	)		(115,323	)


Cash flows from financing activities:
Proceeds from borrowings		66,500			37,000
Repayments of borrowings		(80,678	)		(259,017	)
Payment of deferred financing costs		(1,337	)		(2,182	)
Proceeds from sale of offshore litigation contingent payment rights		—			25,000
Repurchase of offshore litigation contingent payment rights		—			(25,000	)
Stock issued for cash, net		—			247,168
Shares repurchased for withholding taxes		(5	)		(226	)


Net cash provided by (used in) financing activities		(15,520	)		22,743


Net decrease in cash and cash equivalents		(50,867	)		(59,731	)

Cash at beginning of period		61,918			65,475


Cash at end of period	$	11,051		$	5,744


Supplemental cash flow information:
Cash paid for interest and financing costs	$	14,395		$	23,485

See accompanying notes to consolidated financial statements.

5

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES

Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2010 and 2009
(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 area of operations is the Rocky Mountain Region in which the majority of its proved reserves, production and long-term growth prospects are concentrated.

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, 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. Subsequent events were evaluated through the date of issuance of these consolidated financial statements at the time this quarterly report on Form 10-Q was filed with the Securities and Exchange Commission (“SEC”). 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, 2009, previously filed with the SEC.

(2) Going Concern

The accompanying financial statements have been prepared assuming the Company will continue as a going concern.

The Company experienced a net loss attributable to Delta common stockholders of $162.5 million for the six months ended June 30, 2010, and as of June 30, 2010 had a working capital deficiency of $109.0 million, including $119.5 million outstanding under Delta’s Second Amended and Restated Credit Agreement (the “Credit Agreement” or the “credit facility”) which is due on January 15, 2011 and $73.6 million outstanding under the credit agreement of DHS Drilling Company (“DHS”), the Company’s 49.8% subsidiary. In addition, the holders of the Company’s $115.0 million principal amount of 3³/4% Senior Convertible Notes due 2037 have the right to require the Company to purchase all or a portion of such notes on May 1, 2012 (or thereafter on each May 1 in 2017, 2022, 2027 and 2032). The ongoing losses, near term credit maturities, and working capital deficiency raise substantial doubt about the Company’s ability to continue as a going concern.

As of and for the six months ended June 30, 2010, the Company was in compliance with covenants under its credit facility related to its financial ratios and accounts payable. The Company had $25.5 million of availability under its credit agreement based upon the $145.0 million borrowing base in effect at June 30, 2010, and had cash on hand of $11.1 million.

On April 1, 2010, DHS amended its existing credit facility with Lehman Commercial Paper, Inc. (“LCPI”) and renegotiated certain terms of the agreement, to, among other changes more fully described in Note 7, “Long Term Debt,” bring DHS into compliance with the terms of the agreement, amend the principal repayment schedule, adjust the interest rate, and eliminate or amend certain financial covenants. The DHS facility is non-recourse to Delta.

6

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2010 and 2009
(Unaudited)

(2) Going Concern, Continued

In accordance with current terms of Delta’s credit facility, the Company is limited to capital expenditures of $18.0 million for the quarter ending September 30, 2010 and $10.0 million for the quarter ending December 31, 2010. Based on the Company’s development plan for the remainder of 2010, the Company does not expect to have the liquidity necessary to repay the borrowings under its credit facility when due on January 15, 2011 unless it completes a refinancing of the existing credit facility prior to that date.

In November 2009, the Company retained Morgan Stanley and Evercore Partners to evaluate and advise the Board of Directors on strategic alternatives to enhance shareholder value, including but not limited to the sale of some or all of the Company’s assets, entering into partnerships or joint ventures, or the sale of the entire Company.

On July 23, 2010, the Company entered into a definitive Purchase and Sale Agreement with Wapiti Oil & Gas, L.L.C. to sell various non-core assets (the “Wapiti Transaction”) for cash proceeds of $130.0 million. Also on July 23, 2010, the Company and its credit facility banks agreed to the Fourth Amendment to the Second Amended and Restated Credit Agreement (the “Fourth Amendment”) whereby the requisite banks consented to the Wapiti Transaction, subject to specified terms and conditions, including, among other amendments, that the net proceeds from the transaction be used to pay down the balance outstanding under the credit facility and that the borrowing base be reduced to $35.0 million upon consummation of the Wapiti Transaction. Additional amendments to the credit facility are described in Note 7, “Long Term Debt.” The Wapiti Transaction closed on July 30, 2010 with approximately $108.5 million used to reduce amounts outstanding under the credit facility, $3.7 million used to pay transaction related costs, and $17.8 million paid into escrow pending the receipt of third party consents required to transfer ownership of certain properties involved in the Wapiti Transaction. Upon receipt of these consents which are normal and customary in the industry and expected to be received during the third quarter of 2010, the funds in escrow are required to be used to further reduce amounts outstanding under the Company’s credit facility. The proceeds from the Wapiti Transaction allow the Company to substantially reduce its outstanding debt and when combined with the post Wapiti Transaction borrowing base, provide the liquidity necessary to fund the Company’s third and fourth quarter 2010 development plan. Under the credit facility there are no further scheduled or special borrowing base redeterminations before the maturity of the facility in January 2011, and thus, we anticipate having adequate liquidity to fund operations until such time that we refinance the existing credit facility.

The Wapiti Transaction was a part of a competitive process initiated in conjunction with the strategic alternatives process. This process has been concluded and the Company’s focus will return to creating value with its core assets through operations. The Board of Directors may reevaluate the renewal of the process at a later time.

Taking into consideration the assets sold and proceeds received to date as a result of the strategic evaluation process, the Company will need to raise additional cash capital or refinance its existing credit facility with new or existing lenders in order to pay its outstanding borrowings under the credit facility which are due January 15, 2011. As such, the Company is engaged in discussions with potential lenders and expects to replace the existing facility prior to its maturity, although it is expected that the interest terms and covenant requirements will be more expensive and restrictive, respectively, than the current facility’s rates and terms. The Company expects the initial term of any new credit facility to provide for maturity prior to May 1, 2012, when the holders of the Company’s $115.0 million principal amount of 3³/4% Senior Convertible Notes have the right to require the Company to purchase all or a portion of the notes. As a result, it is anticipated that prior to May 1, 2012, the Company will need to obtain additional capital in order to repay any amounts outstanding under any new credit facility and to purchase any 3 ³/4% Senior Convertible Notes required by the holders of such notes to be purchased by the Company.

There can be no assurance that the actions undertaken by the Company will be sufficient to repay the obligations under the credit agreement when due, 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

7

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2010 and 2009
(Unaudited)

(2) Going Concern, Continued

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 and PGR Partners, LLC. 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.

Investments in operating entities where the Company has the ability to exert significant influence, but does not control the operating and financial policies, are accounted for using the equity method. The Company’s share of net income of these entities is recorded as income (losses) from unconsolidated affiliates in the consolidated statements of operations. Investments in operating entities where the Company does not exert significant influence are accounted for using the cost method, and income is only recognized when a distribution is received.

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 certain properties that were held for sale and where there is no continuing involvement, during the six months ended June 30, 2010 have been reclassified to income from discontinued operations for all periods presented. Such reclassifications had no effect on net loss attributable to Delta common stockholders.

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 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.

8

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2010 and 2009
(Unaudited)

(3) Summary of Significant Accounting Policies, Continued

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, 2010 and December 31, 2009, the Company’s aggregate natural gas and crude oil imbalances were not material to its consolidated financial statements.

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.

9

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2010 and 2009
(Unaudited)

(3) Summary of Significant Accounting Policies, Continued

Impairment of Long-Lived Assets

Long-lived assets are reviewed for impairment at least annually, or more frequently 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 are permanent and may not be restored in the future.

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. For the three and six months ended June 30, 2010, the expected future undiscounted cash flows of the assets exceeded the carrying value of the corresponding asset and as such no impairment provision was recognized. As a result of such assessment, the Company recorded an impairment provision to proved properties of $265,000 for the three months ended June 30, 2009 and $1.2 million for the six months ended June 30, 2009. The impairment provisions for the three and six months ended June 30, 2009 are included within dry hole costs and impairments in the accompanying statement of operations.

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 $21.6 million and $82.9 million for the three months ended June 30, 2010 and 2009, respectively, and $22.5 million and $83.1 million for the six months ended June 30, 2010 and 2009, respectively. The $22.5 million impairment for the six months ended June 30, 2010 included $11.4 million related to the Company’s Columbia River Basin leasehold, $5.0 million related to the Company’s Hingeline leasehold, $3.8 million related to the Company’s Haynesville leasehold, $1.6 million related to the Company’s Delores River leasehold and $661,000 related to the Company’s Howard Ranch leasehold. For the three months ended June 30, 2009, 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 impairments of $4.8 million and $1.9 million to reduce the Paradox pipeline carrying value to its estimated fair value during the three months ended June 30, 2010 and 2009, respectively. These impairment provisions are included within dry hole costs and impairments in the accompanying statements of operations for the three and six months ended June 30, 2010 and 2009.

During the remainder of 2010, the Company plans to develop and evaluate certain proved and unproved properties. Favorable or unfavorable drilling results or changes in commodity prices may cause a revision to estimates of those properties’ future cash flows. Such revisions of estimates could require the Company to record additional impairment provisions in the period of such revisions.

10

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2010 and 2009
(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, 2010 to June 30, 2010 (in thousands):


Asset retirement obligation — January 1, 2010	$	10,539
Accretion expense		265
Change in estimate		(148	)
Obligations incurred (from new wells)		248
Obligations assumed		—
Obligations on sold properties		(910	)
Obligations settled		(1,044	)

Asset retirement obligation — June 30, 2010		8,950
Less: portion attributable to liabilities related to oil and gas properties held for sale		(2,397	)
Less: current portion of asset retirement obligation		(1,933	)

Long-term asset retirement obligation	$	4,620

Comprehensive Income (Loss)

Comprehensive income (loss) includes all changes in equity during a period except those resulting from investments by owners and distributions to owners, if any. For the three months ended June 30, 2010 and 2009, comprehensive loss was $152.5 million and $180.5 million, respectively. For the six months ended June 30, 2010 and 2009, comprehensive loss was $168.5 million and $209.9 million, respectively.

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. The Company has not elected hedge accounting and recognizes mark-to-market gains and losses in earnings currently.

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.

At June 30, 2010, 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 a portion of its production.

11

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2010 and 2009
(Unaudited)

(3) Summary of Significant Accounting Policies, Continued

The following table summarizes the Company’s open derivative contracts at June 30, 2010:


								Net Fair Value
						Remaining		Asset (Liability) at
Commodity	Volume			Fixed Price		Term	Index Price	June 30, 2010
								(In thousands)
Crude oil		1,000	Bbls / Day¹	$	52.25	July ’10 - Dec ’10	NYMEX — WTI	$	(4,403	)
Crude oil		500	Bbls / Day	$	57.70	Jan ’11 - Dec ’11	NYMEX — WTI		(3,565	)
Natural gas		6,000	MMBtu / Day	$	5.720	July ’10 - Dec ’10	NYMEX — HHUB		983
Natural gas		15,000	MMBtu / Day	$	4.105	July ’10 - Dec ’10	CIG		(292	)
Natural gas		5,367	MMBtu / Day	$	3.973	July ’10 - Dec ’10	CIG		(232	)
Natural gas		12,000	MMBtu / Day	$	5.150	Jan ’11 - Dec ’11	CIG		1,267
Natural gas		3,253	MMBtu / Day	$	5.040	Jan ’11 - Dec ’11	CIG		218

								$	(6,024	)


1		As a result of the closing of the Wapiti Transaction, for the period from August to December 2010, the Company expects its oil derivative contracts to equal 108% to 114% of forecast oil and condensate production sold on WTI based terms. Because derivative contract volumes are anticipated to exceed physical production volumes in certain months, the Company could be exposed to financial derivative losses in excess of oil revenue gains to the extent WTI oil prices rise from current levels.

The pre-credit risk adjusted fair value of the Company’s net derivative liabilities as of June 30, 2010 was $6.6 million. A credit risk adjustment of $578,000 to the fair value of the derivatives reduced the reported amount of the net derivative liabilities on the Company’s consolidated balance sheet to $6.0 million.

The Company classifies the fair value amounts of derivative assets and liabilities executed under master netting arrangements as net derivative assets or net derivative liabilities, whichever the case may be, by commodity and master netting counterparty. 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, 2010 (in thousands):


Derivatives Not Designated as
Hedging Instruments	Balance Sheet Classification	Fair Value
Liabilities
Commodity Swaps	Derivative Instruments — Current Liabilities, net	$	4,705
Commodity Swaps	Derivative Instruments — Long-Term Liabilities, net		1,319

Total		$	6,024

The following table summarizes the realized and unrealized gains and losses and the classification in the consolidated statement of operations of derivatives not designated as hedging instruments for the six months ended June 30, 2010 (in thousands):


		Amount of Gain
Derivatives Not Designated as	Location of Gain (Loss) Recognized in	(Loss) Recognized in
Hedging Instruments	Income on Derivatives	Income on Derivatives
Commodity Swaps	Realized Loss on Derivative Instruments, net — Other Income and (Expense)	$	(4,714	)
Commodity Swaps	Unrealized Gain on Derivative Instruments, net — Other Income and (Expense)		20,948

		$	16,234

12

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2010 and 2009
(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, issue to him 1,000,000 shares of Delta common stock, 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 contained 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 and distributed to Mr. Parker on November 27, 2009. The assets of the rabbi trust were required to be consolidated into the financial statements until disbursed.

Equity compensation costs recorded prior to the June 30, 2009 consolidated financial statements related to performance shares forfeited prior to their derived service period being completed 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.

All transactions associated with the Parker Severance Agreement were recorded in fiscal year 2009.

13

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2010 and 2009
(Unaudited)

(3) Summary of Significant Accounting Policies, Continued

Stock Based Compensation

The Company recognizes the cost of share based payments over the period the employee provides service and includes such costs 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. During the six months ended June 30, 2010, Delta Oilfield Tank Company (“DOTC”) reported continuing losses from operations which, if recorded, would have created a deficit in the investment in DOTC. In accordance with accounting standards, the Company did not recognize its share of the losses for the six months ended June 30, 2010 as the Company is not obligated to make future capital contributions to DOTC. During the quarter ended June 30, 2009, the Company recorded a $2.1 million impairment provision to its investment in DOTC and a $917,000 impairment provision to its investment in the entity that was expected to operate the Paradox pipeline. These impairment provisions are included within income (loss) from unconsolidated affiliates for the three and six months ended June 30, 2009.

At December 31, 2009, the Company owned a 5% interest in Collbran Valley Gas Gathering, LLC (“CVGG”) which operates a pipeline in the Piceance Basin through which the Company transports its produced gas to the sales point. During the fourth quarter of 2009, the Company recorded an impairment of its investment in CVGG to reduce the carrying value to its fair value of $3.5 million. In January 2010, the Company divested its 5% interest in CVGG for cash proceeds of $3.5 million, plus an additional $2.0 million of proceeds contingent on volume deliveries through the CVGG system of Delta gas between January 1, 2010 and June 30, 2011. Based on current production levels, the Company is not likely to earn the contingent consideration without the initiation of a continuous drilling program which could only be undertaken with additional funding beyond the Company’s existing capital resources.

Income Taxes

The Company uses the asset and liability method of accounting for income taxes. Under the asset and liability method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and net operating loss and tax credit carry-forwards. Deferred tax assets and liabilities are measured using enacted income tax rates expected to apply to taxable income in the years in which those differences are expected to be recovered or settled. 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. The realizability of deferred tax assets is evaluated based on a “more likely than not” standard, 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 11, “Earnings Per Share”).

14

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2010 and 2009
(Unaudited)

(3) Summary of Significant Accounting Policies, Continued

Use of Estimates

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

Recently Issued and Adopted Accounting Pronouncements

In January 2010, the FASB issued Accounting Standards Update No. 2010-06, Improving Disclosures about Fair Value Measurements (“ASU 2010-06”), which provides amendments to FASB ASC Topic 820,Fair Value Measurements and Disclosures. The objective of ASU 2010-06 is to provide more robust disclosures about (i) the different classes of assets and liabilities measured at fair value, (ii) the valuation techniques and inputs used, (iii) the activity in Level 3 fair value measurements, and (iv) significant transfers between Levels 1, 2 and 3. ASU 2010-06 is effective for fiscal years and interim periods beginning after December 15, 2009. The Company adopted ASU 2010-06 effective January 1, 2010, which did not have an impact on its consolidated financial statements, other than additional disclosures.

(4) Oil and Gas Properties

Unproved Undeveloped Offshore California Properties

The Company previously owned direct and indirect ownership interests ranging from 2.49% to 100% in five unproved undeveloped offshore California oil and gas properties. Delta and its 92% owned subsidiary, Amber, were among twelve plaintiffs in a lawsuit that was filed in the United States Court of Federal Claims (the “Court”) in Washington, D.C. alleging that the U.S. government materially breached the terms of forty undeveloped federal leases, some of which are part of our offshore California properties. During 2009, the Company received net proceeds of $95.8 million after overrides and conveyed our leases back to the United States. Accordingly, the Company no longer has any remaining unproved undeveloped offshore California property interests.

2010 — Divestitures

During the six months ended June 30, 2010, the Company divested of its interests in certain non-core properties for gross proceeds of $965,000 and the assumption of plugging and abandonment obligations. Proved reserves attributable to these properties were insignificant.

Oil and Gas Properties Held for Sale

Oil and gas properties held for sale as of June 30, 2010 represent the lower of net book value or fair value of certain non-core properties that were expected to be sold, located in the following fields: Garden Gulch, Baffin Bay, DJ Basin, Caballos Creek, Opossum Hollow, Midway Loop, and Newton, as well as the Company’s interest in its wholly owned subsidiary Piper Petroleum and unproved acreage positions in the DJ Basin and South Texas. In addition to the lower of net book value or fair value of the non-core properties, oil and gas properties held for sale also includes prepaid cash calls associated with the Garden Gulch field. At June 30, 2010, the Company had liabilities related to oil and gas properties held for sale of $7.3 million which included $4.9 million for revenue payable to third parties and $2.4 million for asset retirement obligations.

15

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2010 and 2009
(Unaudited)

(4) Oil and Gas Properties, Continued

The Company considered the total purchase price in the Wapiti Transaction and allocated the purchase price to the properties using internal discounted cash flow calculations based upon the Company’s estimates of reserves and determined that impairment provisions of $93.2 million related to proved properties and $3.0 million related to unproved properties were required to be recognized during the three months ended June 30, 2010. Based upon the applicable accounting standards, $4.0 million of the impairment provision is included within dry hole costs and impairments in the accompanying statements of operations and the remaining $92.2 million is included within loss on sale of discontinued operations.

Discontinued Operations

In accordance with accounting standards, the results of operations and impairment loss relating to certain properties held for sale at June 30, 2010 in conjunction with the now completed Wapiti Transaction have been reflected as discontinued operations. Properties held for sale at June 30, 2010 in conjunction with the Wapiti Transaction in which the Company only sold half of its interest continue to be reported as a component of continuing operations. The fields classified as discontinued operations are fields in which the Company sold all of its interest including the Garden Gulch field, Baffin Bay field, and Bull Canyon field as well as the Company’s interest in its wholly-owned subsidiary Piper Petroleum.

The following table shows the total oil and gas segment revenues and expenses included in discontinued operations for the above mentioned oil and gas properties for the three and six months ended June 30, 2010 and 2009 (in thousands):


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
Revenues	$	3,259		$	2,082		$	7,809		$	5,391

Operating expenses:

Lease operating expense		995			756			1,979			2,698
Transportation expense		704			327			1,278			1,134
Production taxes		201			(36	)		438			55
Depreciation, depletion, amortization and accretion		5,827			6,086			13,594			10,904
Impairment provision		92,162			—			92,162			—

Total operating expenses		99,889			7,133			109,451			14,791


Loss from discontinued operations		(96,630	)		(5,051	)		(101,642	)		(9,400	)
Income tax expense		—			—			—			—


Loss from discontinued operations, net of tax	$	(96,630	)	$	(5,051	)	$	(101,642	)	$	(9,400	)

On July 30, 2010, the Company closed on the Wapiti Transaction for cash proceeds of $130.0 million, with approximately $108.5 million used to reduce amounts outstanding under the credit facility, $3.7 million used to pay transaction related costs, and $17.8 million paid into escrow pending the receipt of third party consents required to transfer ownership of certain properties involved in the Wapiti Transaction. The Company expects to recognize a gain on sale for the closing of Wapiti Transaction in the three months ended September 30, 2010 of approximately $29.4 million, subject to revision for normal and customary purchase price adjustments as provided for under the purchase and sale agreement.

16

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2010 and 2009
(Unaudited)

(5) DHS Drilling

On June 30, 2010, the Company owned a 49.8% ownership interest in DHS. The remaining interest is owned by Chesapeake Energy Corporation, 47.2%, and 3% by DHS executive officers and management. Delta has the right to use all of the DHS rigs on a priority basis.

The carrying value of DHS’s drilling rigs and related equipment is 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 provision 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. No such impairment provisions were recorded during the three and six months ended June 30, 2010.

(6) Fair Value Measurements

The Company follows accounting guidance 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, 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 or 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.

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).

Oil and gas properties held for sale — The fair values of the oil and gas properties held for sale were estimated using the total purchase price consideration from the Wapiti Transaction, allocated to the properties sold based on internal estimates consistent with the Company’s fair value measurement methods for proved property impairments. Impaired properties were reduced to their fair value.

Proved property impairments — The fair values of the proved properties are estimated using internal discounted cash flow calculations based upon the Company’s estimates of reserves and are considered to be level three fair value measurements.

Asset retirement obligations — The initial fair values of the asset retirement obligations are estimated using internal discounted cash flow calculations based upon the Company’s asset retirement obligations, including revisions of the estimated fair values during the six months ended June 30, 2010 and 2009.

17

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2010 and 2009
(Unaudited)

(6) Fair Value Measurements, Continued

The following table lists the Company’s fair value measurements by hierarchy as of June 30, 2010 (in thousands):


	Fair Value Measurements
	Quoted Prices		Significant			Significant
	in Active Markets		Other Observable			Unobservable
	for Identical Assets		Inputs			Inputs
Assets (Liabilities)	(Level 1)		(Level 2)			(Level 3)
Recurring
Derivative liabilities	$	—	$	(6,024	)	$	—

Non-recurring



Oil and gas properties held for sale	$	—	$	—		$	48,433

The oil and gas properties held for sale were remeasured to a fair value of $48.4 million resulting in a $93.2 million impairment.

(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 $1.3 million and $1.9 million for the three months ended June 30, 2010 and 2009, respectively, and accretion of $2.5 million and $3.7 million for the six months ended June 30, 2010 and 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, 2010 (See Note 12, “Guarantor Financial Information”). The fair value of the Company’s senior unsecured notes at June 30, 2010 was approximately $121.5 million.

3³/4% Senior Convertible Notes, due 2037

On April 25, 2007, the Company issued $115.0 million aggregate principal amount of 3³/4% Senior Convertible Notes due 2037 (the “Notes”) for net proceeds of $111.6 million after underwriters’ discounts and commissions of approximately $3.4 million. The Notes were recorded based on the estimated fair value of the liability component and 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, 2010 and 2009, and $2.3 million and $2.2 million of accretion for the six months ended June 30, 2010 and 2009, respectively. Combined with the amortization of debt discount, the Notes had an effective interest rate of approximately 7.7% and 7.6% with total interest costs of $2.2 million for each of the three months ended June 30, 2010 and 2009, respectively, and interest costs of $4.4 million and $4.3 million for the six months ended June 30, 2010 and 2009, respectively. The fair value of the Notes at June 30, 2010 was approximately $87.4 million.

18

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2010 and 2009
(Unaudited)

(7) Long Term Debt, Continued

Credit Facility — Delta

On July 23, 2010, Delta entered into the Fourth Amendment to the Second Amended and Restated Credit Agreement, 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 requisite lenders consented to the Wapiti Transaction, subject to specified terms and conditions, including that the net proceeds from the transaction be used to pay down the balance outstanding under the credit facility and that the borrowing base be reduced to $35.0 million upon consummation of the Wapiti Transaction. The Fourth Amendment eliminated all scheduled or special borrowing base redeterminations prior to the maturity of the facility in January 2011. In addition, the Fourth Amendment imposed capital expenditures limitations of $18.0 million for the quarter ending September 30, 2010, $10.0 million for the quarter ending December 31, 2010, and $2.0 million for the period from January 1, 2011 to January 15, 2011, provided that any excess of the limitation over the amount of actual expenditures may be carried forward from an earlier specified period to a subsequent specified period. The Fourth Amendment added a maximum cash on hand covenant which limits the Company’s cash and cash equivalents to $10.0 million at any time, with any excess above such limit required to be used to pay down borrowings under the credit facility within three business days. Finally, the Fourth Amendment requires cash disbursements for general and administrative expenses to be within a 10% variance of projected general and administrative expenses provided to the lending banks in conjunction with the execution of the Fourth Amendment.

The Company was in compliance with its financial ratio covenants and capital expenditures and accounts payable limitations under the Credit Agreement as of June 30, 2010. Based on the Company’s current operating projections, the Company believes it will remain in compliance with the debt covenants. However, there can be no assurance that the actions undertaken by the Company will be sufficient to repay the obligations under the credit agreement when due, or, if not sufficient, or if additional defaults occur, that the lenders will be willing to waive the defaults or amend the agreement.

Borrowings under the credit facility were $119.5 million at June 30, 2010. Remaining pro-forma availability after the consummation of the Wapiti Transaction (including both the initial closing and amounts in escrow pending third party consents) and based on the revised $35.0 million borrowing base will be approximately $28.8 million.

Because the credit facility matures in January 2011, the debt is classified as a current liability in the June 30, 2010 consolidated balance sheet.

19

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2010 and 2009
(Unaudited)

(7) Long Term Debt, Continued

Credit Facility — DHS

On April 1, 2010, DHS amended its existing credit facility with LCPI and renegotiated certain terms of the agreement including obtaining waivers for all covenant violations through March 31, 2010. The terms of the amended agreement required principal payments of $7,677,713 paid on April 1, 2010 and $2,000,000 paid on May 1, 2010 and August 1, 2010, with remaining $2,000,000 principal payments due on each of November 1, 2010 and January 1, 2011, and a $5,000,000 principal payment on each of April 1, 2011 and July 1, 2011 with the remaining balance of $57,589,787 due at maturity (August 31, 2011). In addition to the required payments, DHS may be required to prepay any remaining outstanding principal with the “Net Cash Proceeds from any Asset Sale,” as defined by the credit facility, and any such prepayment shall be applied to, first, prepay the immediately succeeding Scheduled Installment in full, second, prepay all interest payable on the immediately succeeding Interest Payment Date in full, third, pay the second succeeding Scheduled Installment in full and fourth, prepay the remaining principal balance of the remaining loans. DHS is also required to prepay the principal amount of the loans in an amount equal to 75% of the “Excess Cash Flow,” as defined by the credit facility, for such fiscal quarter. The only financial covenant remaining in the DHS credit agreement is a minimum EBITDA covenant of $250,000 for the three months ending June 30, 2010, $1,000,000 for the three months ending September 30, 2010 and $1,500,000 for each subsequent quarter. In addition, the amendment imposed capital expenditures limitations of $1,200,000 for any fiscal quarter. Notwithstanding the $1,200,000 per quarter limitation on capital expenditures, the amendment imposes aggregate capital expenditure limitations of $3,500,000 for fiscal year 2010 and $2,330,137 for fiscal year 2011. The interest rate has been adjusted to LIBOR plus 625 basis points, subject to a LIBOR floor rate of 2.75%. DHS was in compliance with its amended minimum EBITDA covenant for the three months ended June 30, 2010.

(8) Commitments and Contingencies

The $115.0 million in principal amount of 3³/4% Senior Convertible Notes due 2037 will mature on May 1, 2037 unless earlier converted, redeemed or repurchased. The holders of the Notes have the right to require the Company 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 at a price which is required to be paid in cash, equal to 100% of the principal amount of the Notes to be repurchased.

(9) 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, 2010 and December 31, 2009, no shares of preferred stock were outstanding.

Common Stock

During the three months ended March 31, 2010, the Company issued 480,778 fully vested shares to the non-employee members of the Board of Directors in consideration for their service on the Board for the year ended December 31, 2009. No shares were issued during the three months ended June 30, 2010.

20

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2010 and 2009
(Unaudited)

(9) 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.

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,
	2010		2009		2010		2009
Non-vested stock	$	3,105	$	1,157	$	6,136	$	2,935
Performance shares		358		717		716		1,704

Total	$	3,463	$	1,874	$	6,852	$	4,639

The Company recognizes the cost of share based payments over the period during which the employee provides service. As the Company has not issued stock options since July 2005 and 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, 2010 ranged from $1.87 to $15.34 per share and the weighted-average remaining contractual life of those options was 3.29 years. At June 30, 2010, the Company had 1,427,750 options outstanding at a weighted average exercise price of $8.21 per share. At June 30, 2010, the Company had 6,721,000 non-vested shares outstanding and 150,000 performance shares outstanding. At June 30, 2010, the total unrecognized compensation cost related to the non-vested portion of restricted stock was $20.5 million which is expected to be recognized over a weighted average period of 1.8 years. See Note 14, “Subsequent Events” for the issuance of stock options associated with the promotion of Carl E. Lakey.

21

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2010 and 2009
(Unaudited)

(10) Income Taxes

Income tax expense (benefit) attributable to loss from continuing operations was approximately $203,000 and $265,000 for the three months ended June 30, 2010 and 2009, respectively, and $478,000 and $(318,000) for the six months ended June 30, 2010 and 2009, 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 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, 2010.

During the three months ended June 30, 2010, DHS recorded significant net operating losses and as of June 30, 2010 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 2010 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.

During the three and six months ended June 30, 2010 and 2009, no adjustments were recognized for uncertain tax benefits.

(11) 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,
	2010			2009			2010			2009
Net loss attributable to Delta common stockholders	$	(149,750	)	$	(172,318	)	$	(162,547	)	$	(197,871	)

Basic weighted-average common shares outstanding		275,832			193,028			275,652			146,248
Add: dilutive effects of stock options and unvested stock grants		—			—			—			—

Diluted weighted-average common shares outstanding		275,832			193,028			275,652			146,248


Net income (loss) per common share attributable to Delta common stockholders
Basic	$	(0.54	)	$	(0.89	)	$	(0.59	)	$	(1.35	)

Diluted	$	(0.54	)	$	(0.89	)	$	(0.59	)	$	(1.35	)

22

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2010 and 2009
(Unaudited)

(11) Earnings Per Share, Continued

Potentially dilutive securities excluded from the calculation of diluted shares outstanding include the following (in thousands):


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2010		2009		2010		2009
Stock issuable upon conversion of convertible notes		3,790		3,790		3,790		3,790
Stock options		1,428		1,428		1,428		1,428
Performance share grants		150		150		150		150
Non-vested restricted stock		6,721		1,563		6,721		1,563

Total potentially dilutive securities		12,089		6,931		12,089		6,931

(12) 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 3³/4% 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, 2010 and December 31, 2009, the condensed consolidated statements of operations for the three and six months ended June 30, 2010 and 2009, and the condensed consolidated statements of cash flows for the six months ended June 30, 2010 and 2009 (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.

23

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2010 and 2009
(Unaudited)

(12) Guarantor Financial Information, Continued

Condensed Consolidated Balance Sheet
June 30, 2010


				Guarantor			Non-Guarantor			Adjustments/
	Issuer			Entities			Entities			Eliminations			Consolidated
Current assets	$	180,135		$	712		$	57,233		$	—		$	238,080

Property and equipment:
Oil and gas properties		1,161,161			—			19,215			(117	)		1,180,259
Drilling rigs and trucking equipment		595			—			175,249			—			175,844
Other		77,758			32,588			1,781			—			112,127

Total property and equipment		1,239,514			32,588			196,245			(117	)		1,468,230

Accumulated depletion and depreciation		(440,664	)		(28,673	)		(109,434	)		—			(578,771	)


Net property and equipment		798,850			3,915			86,811			(117	)		889,459

Investment in subsidiaries		8,102			—			—			(8,102	)		—
Other long-term assets		110,931			2,407			195			—			113,533


Total assets	$	1,098,018		$	7,034		$	144,239		$	(8,219	)	$	1,241,072


Current liabilities	$	256,302		$	224		$	90,534		$	—		$	347,060

Long-term liabilities:
Long-term debt, derivative instruments and deferred taxes		352,052			1,801			—			—			353,853
Asset retirement obligations		4,620			—			—			—			4,620


Total long-term liabilities		356,672			1,801			—			—			358,473

Total Delta stockholders’ equity		482,218			5,009			53,705			(8,219	)		532,713

Non-controlling interest		2,826			—			—			—			2,826


Total equity		485,044			5,009			53,705			(8,219	)		535,539


Total liabilities and equity	$	1,098,018		$	7,034		$	144,239		$	(8,219	)	$	1,241,072

24

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2010 and 2009
(Unaudited)

(12) Guarantor Financial Information, Continued

Condensed Consolidated Balance Sheet
December 31, 2009


				Guarantor			Non-Guarantor			Adjustments/
	Issuer			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Current assets	$	160,408		$	448		$	31,596		$	—		$	192,452

Property and equipment:
Oil and gas properties		1,529,920			592			130,837			(585	)		1,660,764
Drilling rigs and trucking equipment		594			—			177,168			—			177,762
Other		73,383			32,916			1,919			—			108,218

Total property and equipment		1,603,897			33,508			309,924			(585	)		1,946,744

Accumulated depletion and depreciation		(652,432	)		(24,040	)		(124,029	)		—			(800,501	)

Net property and equipment		951,465			9,468			185,895			(585	)		1,146,243

Investment in subsidiaries		80,058			—			—			(80,058	)		—
Other long-term assets		114,820			3,787			183			—			118,790


Total assets	$	1,306,751		$	13,703		$	217,674		$	(80,643	)	$	1,457,485


Current liabilities	$	179,302		$	319		$	92,579		$	—		$	272,200

Long-term liabilities:
Long-term debt, derivative instruments and deferred taxes		478,710			1,801			—			—			480,511
Asset retirement obligations		7,358			11			285			—			7,654


Total long-term liabilities		486,068			1,812			285			—			488,165

Total Delta stockholders’ equity		632,843			11,572			124,810			(80,643	)		688,582

Non-controlling interest		8,538			—			—			—			8,538


Total equity		641,381			11,572			124,810			(80,643	)		697,120


Total liabilities and equity	$	1,306,751		$	13,703		$	217,674		$	(80,643	)	$	1,457,485

25

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2010 and 2009
(Unaudited)

(12) Guarantor Financial Information, Continued

Condensed Consolidated Statement of Operations
Three Months Ended June 30, 2010


				Guarantor			Non-Guarantor			Adjustments/
	Issuer			Entities			Entities			Eliminations			Consolidated
Total revenue	$	24,959		$	—		$	11,063		$	—		$	36,022

Operating expenses:
Oil and gas expenses		13,846			—			—			—			13,846
Exploration expense		358			—			—			—			358
Dry hole costs and impairments		25,376			4,805			586			—			30,767
Depreciation and depletion		15,918			2			5,226			—			21,146
Drilling and trucking operating expenses		—			—			8,100			23			8,123
General and administrative		10,608			13			1,019			—			11,640


Total operating expenses		66,106			4,820			14,931			23			85,880


Operating loss		(41,147	)		(4,820	)		(3,868	)		(23	)		(49,858	)

Other income and (expense)		(3,685	)		78			(2,182	)		—			(5,789	)
Income tax expense		(203	)		—			—			—			(203	)
Discontinued operations		(38,706	)		106			(58,030	)		—			(96,630	)


Net loss		(83,741	)		(4,636	)		(64,080	)		(23	)		(152,480	)

Less loss attributable to non-controlling interest		2,730			—			—			—			2,730


Net loss attributable to Delta common stockholders	$	(81,011	)	$	(4,636	)	$	(64,080	)	$	(23	)	$	(149,750	)

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


				Guarantor			Non-Guarantor			Adjustments/
	Issuer			Entities			Entities			Eliminations			Consolidated
Total revenue	$	15,676		$	—		$	5,849		$	(665	)	$	20,860

Operating expenses:
Oil and gas expenses		10,084			—			—			—			10,084
Exploration expense		471			—			—			—			471
Dry hole costs and impairments		98,217			1,896			6,508			—			106,621
Depreciation and depletion		23,789			57			6,342			(167	)		30,021
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		144,147			1,981			16,661			(545	)		162,244


Operating loss		(128,471	)		(1,981	)		(10,812	)		(120	)		(141,384	)

Other income and (expenses)		(31,819	)		20			(1,984	)		—			(33,783	)
Income tax expense		(265	)		—			—			—			(265	)
Discontinued operations		(2,292	)		86			(2,845	)		—			(5,051	)


Net loss		(162,847	)		(1,875	)		(15,641	)		(120	)		(180,483	)

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


Net loss attributable to Delta common stockholders	$	(154,682	)	$	(1,875	)	$	(15,641	)	$	(120	)	$	(172,318	)

26

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2010 and 2009
(Unaudited)

(12) Guarantor Financial Information, Continued

Condensed Consolidated Statement of Operations
Six Months Ended June 30, 2010


				Guarantor			Non-Guarantor			Adjustments/
	Issuer			Entities			Entities			Eliminations			Consolidated
Total revenue	$	54,432		$	—		$	21,790		$	(794	)	$	75,428

Operating expenses:
Oil and gas expenses		25,830			—			—			—			25,830
Exploration expense		584			—			—			—			584
Dry hole costs and impairments		25,730			4,805			586			—			31,121
Depreciation and depletion		31,337			2			10,862			(64	)		42,137
Drilling and trucking operations		—			—			16,625			(613	)		16,012
General and administrative		20,800			29			2,198			—			23,027


Total operating expenses		104,281			4,836			30,271			(677	)		138,711


Operating loss		(49,849	)		(4,836	)		(8,481	)		(117	)		(63,283	)

Other income and (expenses)		837			72			(3,978	)		—			(3,069	)
Income tax expense		(478	)		—			—			—			(478	)
Discontinued operations		(40,881	)		180			(60,941	)		—			(101,642	)


Net loss		(90,371	)		(4,584	)		(73,400	)		(117	)		(168,472	)

Less loss attributable to non-controlling interest		5,925			—			—			—			5,925


Net loss attributable to Delta common stockholders	$	(84,446	)	$	(4,584	)	$	(73,400	)	$	(117	)	$	(162,547	)

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


				Guarantor			Non-Guarantor			Adjustments/
	Issuer			Entities			Entities			Eliminations			Consolidated
Total revenue	$	69,320		$	—		$	9,820		$	(2,933	)	$	76,207

Operating expenses:
Oil and gas expenses		21,925			—			—			—			21,925
Exploration expense		1,531			—			—			—			1,531
Dry hole costs and impairments		99,660			1,896			6,508			—			108,064
Depreciation and depletion		45,739			111			12,546			(579	)		57,817
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		191,842			2,042			30,712			(2,328	)		222,268


Operating loss		(122,522	)		(2,042	)		(20,892	)		(605	)		(146,061	)

Other income and (expenses)		(50,829	)		20			(3,965	)		—			(54,774	)
Income tax benefit (expense)		(476	)		—			794			—			318
Discontinued operations		(3,699	)		114			(5,815	)		—			(9,400	)


Net loss		(177,526	)		(1,908	)		(29,878	)		(605	)		(209,917	)

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


Net loss attributable to Delta common stockholders	$	(165,480	)	$	(1,908	)	$	(29,878	)	$	(605	)	$	(197,871	)

27

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2010 and 2009
(Unaudited)

(12) Guarantor Financial Information, Continued

Condensed Consolidated Statement of Cash Flows
Six Months Ended June 30, 2010


				Guarantor			Non-Guarantor
	Issuer			Entities			Entities			Consolidated
Cash provided by (used in):
Operating activities	$	(37,302	)	$	51		$	13,978		$	(23,273	)
Investing activities		(8,900	)		(31	)		(3,143	)		(12,074	)
Financing activities		(5,378	)		—			(10,142	)		(15,520	)


Net increase (decrease) in cash and cash equivalents		(51,580	)		20			693			(50,867	)

Cash at beginning of the period		58,533			74			3,311			61,918


Cash at the end of the period	$	6,953		$	94		$	4,004		$	11,051

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 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

28

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2010 and 2009
(Unaudited)

(13) 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, 2010 and 2009:


							Inter-segment
	Oil and Gas			Drilling			Eliminations			Consolidated
	(In thousands)
Three Months Ended June 30, 2010
Revenues from external customers	$	24,958		$	11,064		$	—		$	36,022
Inter-segment revenues		—			—			—			—

Total revenues	$	24,958		$	11,064		$	—		$	36,022

Operating loss	$	(46,581	)	$	(3,254	)	$	(23	)	$	(49,858	)

Other income (expense)		(3,606	)		(2,183	)		—			(5,789	)

Loss from continuing operations, before tax	$	(50,187	)	$	(5,437	)	$	(23	)	$	(55,647	)


Three Months Ended June 30, 2009
Revenues from external customers	$	19,186		$	1,674		$	—		$	20,860
Inter-segment revenues		—			665			(665	)		—

Total revenues	$	19,186		$	2,339		$	(665	)	$	20,860

Operating loss	$	(121,560	)	$	(19,704	)	$	(120	)	$	(141,384	)

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

Loss from continuing operations, before tax	$	(153,358	)	$	(21,689	)	$	(120	)	$	(175,167	)


Six Months Ended June 30, 2010
Revenues from external customers	$	54,432		$	20,996		$	—		$	75,428
Inter-segment revenues		—			794			(794	)		—

Total revenues	$	54,432		$	21,790		$	(794	)	$	75,428

Operating loss	$	(55,340	)	$	(7,826	)	$	(117	)	$	(63,283	)

Other income (expense)		912			(3,981	)		—			(3,069	)

Loss from continuing operations, before tax	$	(54,428	)	$	(11,807	)	$	(117	)	$	(66,352	)


Six Months Ended June 30, 2009
Revenues from external customers	$	69,320		$	6,887		$	—		$	76,207
Inter-segment revenues		—			2,933			(2,933	)		—

Total revenues	$	69,320		$	9,820		$	(2,933	)	$	76,207

Operating loss	$	(119,208	)	$	(26,248	)	$	(605	)	$	(146,061	)

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

Loss from continuing operations, before tax	$	(170,015	)	$	(30,215	)	$	(605	)	$	(200,835	)


June 30, 2010:
Total Assets	$	1,223,951		$	83,751		$	(66,630	)	$	1,241,072


December 31, 2009:
Total Assets	$	1,419,754		$	104,287		$	(66,556	)	$	1,457,485

Other income and expense includes interest and financing costs, realized losses on derivative instruments, unrealized gains and losses on derivative instruments, interest income, income and loss from unconsolidated affiliates and other miscellaneous income. Non-controlling interests are included in inter-segment eliminations.

29

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2010 and 2009
(Unaudited)

(14) Subsequent Events

The Company’s then President and Chief Operating Officer, John R. Wallace, resigned on July 6, 2010 and it is expected that he will receive severance in accordance with the terms of his employment agreement.

On July 7, 2010, the Company announced that Carl E. Lakey was named President and Chief Executive Officer, effective immediately. Mr. Lakey most recently served as Senior Vice President of Operations for Delta and has been with the Company since 2007. On July 6, 2010, Mr. Lakey was granted 250,000 options to purchase Delta common stock at an exercise price of $0.79 per share. The options were fully vested upon issuance and have a 10 year contractual life. The estimated fair value of the options will be included as a component of general and administrative expense in the Company’s third quarter financial statements.

On July 7, 2010, the Company announced that it had terminated discussions regarding entering into a definitive Purchase and Sale Agreement with Opon International LLC. Delta terminated the discussions after Opon was unable to obtain financing for the transaction on the agreed-upon terms.

On July 23, 2010, the Company entered into a definitive Purchase and Sale Agreement with Wapiti Oil & Gas, L.L.C. to sell various non-core assets (the “Wapiti Transaction”) for cash proceeds of $130.0 million. Also on July 23, 2010, the Company and its credit facility banks entered into the Fourth Amendment to the Second Amended and Restated Credit Agreement (the “Fourth Amendment”) whereby the requisite banks consented to the Wapiti Transaction, subject to specified terms and conditions, including, among other amendments, that the net proceeds from the transaction be used to pay down the balance outstanding under the credit facility and that the borrowing base be reduced to $35.0 million upon consummation of the Wapiti Transaction. Additional amendments to the credit facility are described in Note 7, “Long Term Debt.” The Wapiti Transaction closed on July 30, 2010.

In conjunction with the transaction, and in accordance with applicable accounting rules which require evaluation of impairment of assets held for sale on a property-by-property basis, the Company recorded impairment losses associated with assets held for sale during the three months ended June 30, 2010 of $96.1 million ($92.2 million included in loss from discontinued operations and $3.9 million included in dry holes and impairments in the accompanying consolidated results of operations). The Company expects to recognize a gain on sale for the closing of the Wapiti Transaction in the three months ended September 30, 2010 of approximately $29.4 million, subject to revision for normal and customary purchase price adjustments as provided for under the purchase and sale agreement. In total, the Wapiti Transaction is expected to result in a $66.7 million loss when the second quarter asset held for sale impairments are considered in conjunction with the third quarter gain on sale.

30

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; our expectations with respect to amending or replacing our existing credit facility with a new credit facility; operating strategies; anticipated borrowing capacity; our expectation that we will have adequate cash from operations, credit facility borrowings and other capital sources to satisfy our obligations under our Second Amended and Restated Credit Agreement, as amended, and to meet future debt service, capital expenditure and working capital requirements; expected announcements of 2010 drilling plans and capital expenditure budget; anticipated utilization of joint venture and partnership structures; acquisition and divestiture strategies; ability to obtain third party consents and anticipated timing with respect to release of escrow in Wapiti Transaction; completion and drilling program expectations, processes and emphasis; oil and gas reserve estimates (including estimates of future net revenues associated with such reserves and the present value of such future net revenues); availability of capital to develop our reserves; estimates of future production of oil and natural gas; 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; anticipated compliance with and impact of laws and regulations; 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, as well as other possible factors not listed, could cause actual results to differ materially from those expressed in forward-looking statements, including, without limitation, the following:

•

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

•

the availability of capital on an economic basis, or at all, to fund our required payments under our Second Amended and Restated Credit Agreement, as amended, 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 or similar industry 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 availability of borrowings under our credit facility and the ability to obtain a new or replacement credit facility;

31

•

the impact of current economic and financial conditions on our ability to raise capital;

•

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

•

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;

•

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;

•

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;

•

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

•

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

•

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

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.

We caution you not to place undue reliance on these forward-looking statements. We urge you to carefully review and consider the disclosures made in this Form 10-Q and our reports filed with the SEC that attempt to advise interested parties of the risks and factors that may affect our business.

32

Recent Developments

	•		On July 23, 2010, we entered into a definitive Purchase and Sale Agreement with Wapiti Oil & Gas, L.L.C. (“Wapiti”) to sell various non-core assets (the “Wapiti Transaction”) for cash proceeds of $130.0 million. The Wapiti Transaction closed on July 30, 2010.

	•		Also on July 23, 2010, we entered into the Fourth Amendment to the Second Amended and Restated Credit Agreement (the “Fourth Amendment”) whereby the requisite banks consented to the Wapiti Transaction, subject to specified terms and conditions, including, among others, that the net proceeds from the Wapiti Transaction be used to pay down the balance outstanding under the credit facility and that the borrowing base be reduced to $35.0 million upon consummation of the Wapiti Transaction. Additional amendments to the credit facility are described in Note 7, “Long Term Debt” to the accompanying consolidated financial statements. The proceeds from the Wapiti Transaction allow us to substantially reduce our outstanding debt and when combined with the post Wapiti Transaction borrowing base, provide the liquidity necessary to fund our third and fourth quarter 2010 development plan. There are no scheduled or special borrowing base redeterminations before the maturity of the facility in January 2011 and thus we anticipate having adequate liquidity to fund operations until such time that we refinance the existing credit facility.

	•		On April 1, 2010, DHS Drilling Company (“DHS”), the Company’s 49.8% subsidiary, amended its existing credit facility with Lehman Commercial Paper, Inc. and renegotiated certain terms of the agreement, to, among other changes more fully described in Note 7, “Long Term Debt” to the accompanying financial statements, bring DHS into compliance with the terms of the agreement, amend the principal repayment schedule, adjust the interest rate, and eliminate or amend certain financial covenants.

2010 Outlook

Since November 2009, we have been working with Morgan Stanley and Evercore Partners to analyze various alternatives to enhance stockholder value, including a sale of some or all of our assets, entering into partnerships or joint ventures, or the sale of the entire company. The evaluation of any particular transaction has involved, among other considerations, an analysis of our capital expenditure and working capital requirements for 2010 in respect of such transaction and other sources of liquidity, including cash from operations and our credit facility.

As a result of the strategic process described above, on July 30, 2010, we completed the $130.0 million sale of certain non-core properties to Wapiti. In conjunction with the completion of this transaction, our credit facility borrowing base was reduced to $35.0 million and capital expenditure limitations under the credit facility for the third and fourth quarters of 2010 were set at $18.0 million and $10.0 million, respectively.

The Wapiti Transaction was a part of a competitive process initiated in conjunction with the strategic alternatives process. This process has been concluded and our focus will return to creating value with our core assets through operations. The Board of Directors may reevaluate the renewal of the process at a later time.

Based on current commodity prices, the Wapiti Transaction, and our amended credit facility terms, we currently expect to focus our capital expenditures for the remainder of the year on completing up to 15 previously drilled wells in the Vega field and may initiate limited drilling in 2010. The capital expenditure limitations provided for in conjunction with our borrowing base redetermination are expected to be adequate to allow for the funding of these development plans. Based on this level of development and considering production sold in the Wapiti Transaction, we expect oil and gas equivalent production for the remainder of the year to range between 6.9 Bcfe and 7.2 Bcfe. These plans may be adjusted from time to time depending on commodity prices, status of our credit facility refinancing efforts or other factors.

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Liquidity and Capital Resources

On July 30, 2010, we completed the $130.0 million sale of certain non-core properties to Wapiti. Our pro-forma credit facility balance after the consummation of the Wapiti Transaction (including both the initial closing and amounts in escrow pending third party consents) amounted to approximately $6.2 million.

On July 23, 2010, we entered into the Fourth Amendment to the Second Amended and Restated Credit Agreement (as amended, the “Credit Agreement”), with JPMorgan Chase Bank, N.A., as agent, and certain of the financial institutions that are party to the Credit Agreement in which, among other changes, the requisite lenders consented to the Wapiti Transaction, subject to specified terms and conditions, including that the net proceeds from the transaction be used to pay down the balance outstanding under the Credit Agreement and that the borrowing base be reduced to $35.0 million upon consummation of the Wapiti Transaction. The Fourth Amendment eliminated all scheduled or special borrowing base redeterminations prior to the maturity of the facility in January 2011. In addition, the Fourth Amendment imposed capital expenditures limitations of $18.0 million for the quarter ending September 30, 2010, $10.0 million for the quarter ending December 31, 2010, and $2.0 million for the period from January 1, 2011 to January 15, 2011, provided that any excess of the limitation over the amount of actual expenditures may be carried forward from an earlier specified period to a subsequent specified period. The Fourth Amendment added a maximum cash on hand covenant which limits our cash and cash equivalents to $10.0 million at any time, with any excess above such limit required to be used to pay down borrowings under the credit facility within three business days. Finally, the Fourth Amendment requires cash disbursements for general and administrative expenses to be within a 10% variance of projected general and administrative expenses provided to the lending banks in conjunction with the execution of the Fourth Amendment.

We were in compliance with the financial ratio, capital expenditures and accounts payables covenants under the Credit Agreement at June 30, 2010.

On April 1, 2010 DHS amended its existing credit facility with Lehman Commercial Paper, Inc. and renegotiated certain terms of the agreement, as described in “Recent Developments,” above.

Our accompanying financial statements have been prepared assuming we will continue as a going concern. We experienced a net loss attributable to Delta common stockholders of $162.5 million for the six months ended June 30, 2010, and as of June 30, 2010 had a working capital deficiency of $109.0 million, including $119.5 million outstanding under Delta’s credit facility which matures on January 15, 2011 and $73.6 million outstanding under DHS’s credit agreement. In addition, the holders of our $115.0 million principal amount of 3³/4% Senior Convertible Notes due 2037 have the right to require us to purchase all or a portion of such notes on May 1, 2012 (or thereafter on each May 1 in 2017, 2022, 2027 and 2032). The ongoing losses, near term credit maturities, and working capital deficiency raise substantial doubt about our ability to continue as a going concern.

Taking into consideration the assets sold and proceeds received to date as a result of the strategic evaluation process, we will need to raise additional cash or refinance our existing credit facility with new or existing lenders in order to pay our outstanding borrowings under the Credit Agreement which are due January 15, 2011. As such, we are engaged in discussions with potential lenders and expect to replace the existing facility prior to its maturity, although it is expected that the interest terms and covenant requirements will be more expensive and restrictive, respectively, than the current facility’s rates and terms. We expect the initial term of any new credit facility to provide for maturity prior to May 1, 2012, when the holders of our $115.0 million principal amount of 3³/4% Senior Convertible Notes have the right to require us to purchase all or a portion of the notes. As a result, it is anticipated that prior to May 1, 2012, we will need to obtain additional capital in order to repay any amounts outstanding under any new credit facility and to purchase any 3 ³/4% Senior Convertible Notes required by the holders of such notes to be purchased by us.

As shown in the accompanying financial statements and discussed elsewhere herein, we experienced a net loss attributable to Delta common stockholders of $162.5 million for the six months ended June 30, 2010. During the six months ended June 30, 2010, we had an operating loss of $63.3 million, net cash used in operating activities of $23.3 million and net cash used in financing activities of $15.5 million. During this period we invested $18.9 million on oil and gas development activities. At June 30, 2010, we had $11.1 million in cash and remaining availability under the

34

Credit Agreement pro-forma for the consummation of the Wapiti Transaction (including both the initial closing and amounts in escrow pending receipt of third party consents) and based on the revised $35.0 million borrowing base of approximately $28.8 million, total assets of $1.2 billion and a debt to capitalization ratio of 45.6%. Debt, excluding installments payable on property acquisition which are secured by restricted cash deposits, at June 30, 2010 totaled $449.0 million, comprised of $193.1 million of bank debt ($119.5 million of our indebtedness under our Credit Agreement and $73.6 million of DHS credit facility indebtedness, all of which is classified as current in the accompanying consolidated financial statements), $149.6 million of senior notes and $106.3 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 30, 2010, 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 30, 2010, our corporate credit and senior unsecured debt ratings were CCC and CCC, respectively, as issued by Standard and Poor’s (“S&P”). S&P’s outlook on its rating was “negative.”

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. Although our current level of borrowing capacity under the Credit Agreement is expected to remain the same through maturity because the Fourth Amendment provided that no scheduled or special redetermination will occur prior to the maturity of the facility, there can be no assurance that our current level of borrowing capacity will be maintained under a new credit agreement, or that we will be successful in negotiating an extension to the Credit Agreement, or a replacement thereto, upon its scheduled maturity in January 2011. There can similarly be no assurance that DHS will be successful in negotiating an extension to the DHS credit facility, or a replacement thereto, upon its scheduled maturity in August 2011. In addition, there can be no assurance that results of operations and other sources of liquidity, including asset sales, 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, or 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, sales of assets and joint venture financing), as well as other potential corporate transactions. The availability of additional sources of capital, which will impact 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.

35

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, 2010 and 2009. This analysis should be read in conjunction with our consolidated financial statements and the accompanying notes thereto included in this Form 10-Q.

Three Months Ended June 30, 2010 Compared to Three Months Ended June 30, 2009

Net Loss Attributable to Delta Common Stockholders. Net loss attributable to Delta common stockholders was $149.8 million, or $0.54 per diluted common share, for the three months ended June 30, 2010, compared to a net loss attributable to Delta common stockholders of $172.3 million, or $0.89 per diluted common share, for the three months ended June 30, 2009. There were a number of items affecting comparability between periods including oil and gas sales, contract drilling and trucking fees, impairments, depletion expense, interest and financial costs, and realized and unrealized gains and losses on derivative instruments. 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, 2010, oil and gas sales increased 30% to $25.1 million, as compared to $19.3 million for the comparable period a year earlier. The increase was principally the result of a 110% increase in natural gas prices and a 31% increase in oil prices, partially offset by a 21% decrease in production. The average natural gas price received during the three months ended June 30, 2010 increased to $4.86 per Mcf compared to $2.31 per Mcf for the year earlier period. The average oil price received during the three months ended June 30, 2010 increased to $69.88 per Bbl compared to $53.22 per Bbl for the year earlier period. The production decrease was primarily related to expected production declines in the Rockies 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, 2010 increased to $11.1 million compared to $1.7 million in the prior year. The increase is the result of improved third party rig utilization in the three months ended June 30, 2010 resulting from an increased industry demand attributable to improved commodity prices.

Production and Cost Information

Production volumes, average prices received and cost per equivalent Mcf for the three months ended June 30, 2010 and 2009 are as follows:


	Three Months Ended
	June 30,
	2010		2009
Production — Continuing Operations:
Oil (Mbbl)		150		198
Gas (Mmcf)		3,004		3,776
Total Production (Mmcfe) — Continuing Operations		3,902		4,964

Average Price — Continuing Operations:
Oil (per barrel)	$	69.88	$	53.22
Gas (per Mcf)	$	4.86	$	2.31

Costs (per Mcfe) — Continuing Operations:
Lease operating expense	$	2.05	$	1.38
Transportation expense	$	1.14	$	0.44
Production taxes	$	0.35	$	0.21
Depletion expense	$	3.82	$	4.66

Realized derivative losses (per Mcfe)	$	0.15	$	—

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Lease Operating Expense. Lease operating expenses for the three months ended June 30, 2010 increased to $8.0 million from $6.8 million in the year earlier period primarily due to increased water handling costs in the Vega area partially offset by lower offshore lease operating costs. Lease operating expense per Mcfe for the three months ended June 30, 2010 increased to $2.05 per Mcfe from $1.38 per Mcfe. The quarter-over-quarter increase on a per unit basis was primarily due to the increased water handling costs in the Vega area and the effect of fixed costs spread over a 21% decline in production volumes.

Transportation Expense. Transportation expense for the three months ended June 30, 2010 increased to $4.5 million from $2.2 million in the prior year. Transportation expense per Mcfe for the three months ended June 30, 2010 increased 159% to $1.14 per Mcfe from $0.44 per Mcfe. The increase on a per unit basis is primarily the result of changes to our Vega gas marketing contract that went into effect in October 2009 whereby our gas is processed through a higher efficiency plant. The Vega gas marketing contract has resulted in higher revenues in the Vega area from improved natural gas liquids recoveries and a greater percentage of liquids proceeds retained.

Production Taxes. Production taxes for the three months ended June 30, 2010 were $1.4 million, as compared to prior year costs of $1.1 million. Production taxes as a percentage of oil and gas sales were 5.5% for each of the three months ended June 30, 2010 and 2009.

Exploration Expense. Exploration expense consists primarily of geological and geophysical costs and delay lease rentals. Our exploration costs for the three months ended June 30, 2010 were $358,000 compared to $471,000 for the comparable year earlier period. Exploration activities in both periods primarily relate to delay rental payments.

Dry Hole Costs and Impairments. We incurred dry hole costs and impairments of $30.8 million for the three months ended June 30, 2010 compared to $106.6 million for the comparable period a year ago. During the three months ended June 30, 2010, dry hole and impairment costs primarily related to proved property impairments of $991,000 for the Opossum Hollow and Golden Prairie fields, unproved property impairments of $24.6 million for the Columbia River Basin, Hingeline, Haynesville, Howard Ranch, Bull Canyon, Garden Gulch and Delores River prospects and a $4.8 million impairment of our Paradox pipeline. These impairments were primarily related to either the result of the asset sales portion of the strategic alternatives process or the assets held for sale at June 30, 2010 pending the completion of the Wapiti Transaction.

We incurred dry hole costs and impairments of approximately $106.6 million for the three months ended June 30, 2009 primarily related to $82.9 million of impairments for unproved leaseholds in Garden Gulch, Haynesville, Lighthouse, Newton, Caballos Creek and Opossum Hollow, $6.5 million of DHS equipment and rigs impairments, $10.5 million of Vega surface acreage impairments, $4.3 million of inventory impairments, and a $1.9 million impairment of our Paradox pipeline.

Depreciation, Depletion, Amortization and Accretion — Oil and Gas. Depreciation, depletion and amortization expense decreased 33% to $15.9 million for the three months ended June 30, 2010, as compared to $23.8 million for the comparable year earlier period. Depletion expense for the three months ended June 30, 2010 decreased to $14.9 million from $23.1 million for the three months ended June 30, 2009 due to lower production volumes and a decrease in the per unit depletion rate. Our depletion rate decreased from $4.66 per Mcfe for the three months ended June 30, 2009 to $3.82 per Mcfe for the current year period primarily due to the effect of impairments recorded during late 2009 on high depletion rate properties and Vega area proved undeveloped reserves added as a result of higher Piceance gas prices.

Drilling and Trucking Operations. Drilling expense increased to $8.1 million for the three months ended June 30, 2010 compared to $2.3 million for the comparable prior year period. This increase is due to additional third party rig utilization during the current year period.

Depreciation and Amortization — Drilling and Trucking. Depreciation and amortization expense — drilling decreased to $5.2 million for the three months ended June 30, 2010, as compared to $6.2 million for the comparable year earlier period. The decrease is due to the effect on the depreciation rate of rig impairments recorded during 2009. Depreciation expense is recorded on a straight line basis and is not impacted by changes in the utilization rate.

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General and Administrative Expense. General and administrative expense increased 30% to $11.6 million for the three months ended June 30, 2010, as compared to $9.0 million for the comparable prior year period. The increase in general and administrative expenses is attributed to costs associated with the strategic alternatives evaluation process and by increased non-cash stock compensation expense related to restricted stock granted in December 2009, partially offset by reduced staffing as a result of reductions in force during the first half of 2009 resulting in lower cash compensation expense.

Executive Severance Expense, Net. On May 26, 2009, our then Chairman of the Board of Directors and Chief Executive Officer, Roger A. Parker, resigned from Delta. 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 contained mutual releases and non-disparagement provisions, as well as other customary terms.

Interest Expense and Financing Costs, Net. Interest expense and financing costs, net decreased 39% to $9.6 million for the three months ended June 30, 2010, as compared to $15.8 million for the comparable year earlier period. The decrease is primarily related to lower average outstanding Delta and DHS credit facility balances coupled with lower interest rates during the second quarter of 2010 as compared to the second quarter of 2009. In addition, the three months ended June 30, 2009, included $1.0 million of interest expense related to the repurchase from Tracinda Corporation of offshore litigation contingent payment rights.

Realized Loss on Derivative Instruments, Net. During the three months ended June 30, 2010, we recognized a $601,000 loss associated with settlements on derivative contracts. During the three months ended June 30, 2009 there were no derivative contract settlements.

Unrealized Gain (Loss) on Derivative Instruments, Net. We recognize mark-to-market gains or losses in current earnings instead of deferring those amounts in accumulated other comprehensive income. Accordingly, we recognized $3.7 million of unrealized gains on derivative instruments in other income and expense during the three months ended June 30, 2010 compared to $15.6 million of unrealized losses for the comparable prior year period.

Income (Loss) From Unconsolidated Affiliates. Loss from unconsolidated affiliates during the three months ended June 30, 2009 primarily related to $3.0 million of impairments recorded on two of our investments. Income from unconsolidated affiliates during the three months ended June 30, 2010 is comprised of our pro-rata share of net income of our unconsolidated affiliates.

Income Tax Benefit (Expense). Due to our continued losses, we were required by the “more likely than not” threshold for assessing the realizability of deferred tax assets 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, 2010 and 2009 of $203,000 and $265,000, respectively, relates only to DHS, as no benefit was provided for our net operating losses.

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Discontinued Operations. The results of operations and impairment loss relating to the pending sale of the non-core property interests in the Garden Gulch field, Baffin Bay field, and Bull Canyon field as well as our interest in our wholly-owned subsidiary Piper Petroleum have been reflected as discontinued operations.

The following table shows the total revenues and expenses included in discontinued operations for the above mentioned oil and gas properties for the three ended June 30, 2010 and 2009 (dollar amounts in thousands):


	Three Months Ended
	June 30,
	2010			2009
Production — Discontinued Operations:
Oil (Mbbl)		4			4
Gas (Mmcf)		773			707
Total Production (Mmcfe) — Discontinued Operations		795			731

Revenues	$	3,259		$	2,082

Operating expenses:

Lease operating expense		995			756
Transportation expense		704			327
Production taxes		201			(36	)
Depreciation, depletion, amortization and accretion		5,827			6,086
Impairment provision		92,162			—

Total operating expenses		99,889			7,133


Loss from discontinued operations		(96,630	)		(5,051	)
Income tax expense		—			—


Loss from discontinued operations, net of tax	$	(96,630	)	$	(5,051	)

On July 30, 2010, the Company closed on the sale of non-core properties to Wapiti for cash proceeds of $130.0 million. We expect to recognize a gain on sale for the closing of Wapiti Transaction in the three months ended September 30, 2010 of approximately $29.4 million, subject to revision for normal and customary purchase price adjustments as provided for under the purchase and sale agreement. In total, the Wapiti Transaction is expected to result in a $66.7 million loss when the second quarter asset held for sale impairments are considered in conjunction with the third quarter gain on sale.

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, 2010 and 2009, DHS reported significant losses from low rig utilization rates which resulted in a non-controlling interest credit to earnings.

Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2009

Net Loss Attributable to Delta Common Stockholders. Net loss attributable to Delta common stockholders was $162.5 million, or $0.59 per diluted common share, for the six months ended June 30, 2010, compared to a net loss attributable to Delta common stockholders of $197.9 million, or $1.35 per diluted common share, for the six months ended June 30, 2009. There were a number of items affecting comparability between periods including oil and gas sales, contract drilling and trucking fees, gain on offshore litigation award, impairments, depletion expense, interest and financial costs, and realized and unrealized gains and losses on derivative instruments. 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, 2010, oil and gas sales increased 44% to $55.0 million, as compared to $38.1 million for the comparable period a year earlier. The increase was principally the result of a 102% increase in natural gas prices and a 68% increase in oil prices, partially offset by a 22% decrease in production. The average natural gas price received during the six months ended June 30, 2010 increased to $5.38 per Mcf compared to

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$2.66 per Mcf for the year earlier period. The average oil price received during the six months ended June 30, 2010 increased to $70.54 per Bbl compared to $41.99 per Bbl for the year earlier period.

Contract Drilling and Trucking Fees. Contract drilling and trucking fees for the six months ended June 30, 2010 increased to $21.0 million compared to $6.9 million for the comparable year earlier period. The increase is the result of improved third party rig utilization in the six months ended June 30, 2010 compared to the comparable year earlier period, resulting from an increased industry demand attributable to improved commodity prices.

Gain (Loss) on Offshore Litigation Award and Property Sales, Net. During the six months ended June 30, 2009, we recorded a $31.2 million gain for an offshore litigation award. During the six months ended June 30, 2010, we recorded a $538,000 loss primarily associated with the divestiture of non-core properties. See Note 4, “Oil and Gas Properties,” to the accompanying financial statements for information regarding our 2010 divestitures.

Production and Cost Information

Production volumes, average prices received and cost per equivalent Mcf for the six months ended June 30, 2010 and 2009 are as follows:


	Six Months Ended
	June 30,
	2010		2009
Production — Continuing Operations:
Oil (Mbbl)		299		405
Gas (Mmcf)		6,299		7,934
Total Production (Mmcfe) — Continuing Operations		8,093		10,364

Average Price — Continuing Operations:
Oil (per barrel)	$	70.54	$	41.99
Gas (per Mcf)	$	5.38	$	2.66

Costs (per Mcfe) — Continuing Operations:
Lease operating expense	$	1.88	$	1.42
Transportation expense	$	0.96	$	0.45
Production taxes	$	0.35	$	0.25
Depletion expense	$	3.67	$	4.29

Realized derivative losses (per Mcfe)	$	0.58	$	—

Lease Operating Expense. Lease operating expenses for the six months ended June 30, 2010 of $15.2 million was comparable to $14.7 million in the year earlier period. Lease operating expense per Mcfe for the six months ended June 30, 2010 increased to $1.88 per Mcfe from $1.42 per Mcfe for the comparable year earlier period. The increase on a per unit basis was primarily due to increased water handling costs in the Vega area and the effect of fixed costs spread over a 22% decline in production volumes.

Transportation Expense. Transportation expense for the six months ended June 30, 2010 increased to $7.8 million from $4.6 million in the prior year. Transportation expense per Mcfe for the six months ended June 30, 2010 increased to $0.96 per Mcfe from $0.45 per Mcfe. The increase on a per unit basis is primarily the result of changes to our Vega gas marketing contract that went into effect in October 2009 whereby our gas is processed through a higher efficiency plant. The Vega gas marketing contract has resulted in higher revenues in the Vega area from improved natural gas liquids recoveries and a greater percentage of liquids proceeds retained.

Production Taxes. Production taxes for the six months ended June 30, 2010 were $2.8 million, comparable to prior year costs of $2.6 million. Production taxes as a percentage of oil and gas sales were 5.1% and 6.7% for the six months ended June 30, 2010 and 2009, respectively. The decrease in the 2010 percentage was primarily due to a decrease in the effective Colorado severance tax rate.

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Exploration Expense. Exploration expense primarily consists of geological and geophysical costs and delay lease rentals. Our exploration costs for the six months ended June 30, 2010 were $584,000, compared to $1.5 million for the comparable year earlier period. Current period exploration activities primarily relate to delay rental payments, while the 2009 period was related to delay rental payments and seismic acquisition costs.

Dry Hole Costs and Impairments. We incurred dry hole and impairment costs of $31.1 million for the six months ended June 30, 2010 compared to $108.1 million for the comparable period a year ago. During the six months ended June 30, 2010, dry hole and impairment costs primarily related to proved property impairments of $991,000 for the Opossum Hollow and Golden Prairie fields, unproved property impairments of $25.5 million for the Columbia River Basin, Hingeline, Howard Ranch, Bull Canyon, Garden Gulch, Delores River and Haynesville shale prospects and a $4.8 million impairment of our Paradox pipeline.

We incurred dry hole costs and impairments of approximately $108.1 million for the six months ended June 30, 2009 primarily related to $83.1 million of impairments for unproved leaseholds in Garden Gulch, Haynesville, Lighthouse, Newton, Caballos Creek, and Opossum Hollow, $6.5 million of DHS equipment and rigs impairments, $10.5 million of Vega surface acreage impairments, $4.3 million of inventory impairments, and a $1.9 million impairment of our Paradox pipeline.

Depreciation, Depletion, Amortization and Accretion — Oil and Gas. Depreciation, depletion and amortization expense decreased 32% to $31.3 million for the six months ended June 30, 2010, as compared to $45.9 million for the comparable year earlier period. Depletion expense for the six months ended June 30, 2010 was $29.7 million compared to $44.4 million for the six months ended June 30, 2009. Our depletion rate decreased from $4.29 per Mcfe for the six months ended June 30, 2009 to $3.67 per Mcfe for the current year period primarily due to the effect of impairments recorded during late 2009 on high depletion rate properties and Vega area proved undeveloped reserves added as a result of higher Piceance gas prices.

Drilling and Trucking Operations. Drilling expense increased to $16.0 million for the six months ended June 30, 2010 compared to $7.6 million for the comparable prior year period. This increase is due to additional third party rig utilization during the current year period.

Depreciation and Amortization — Drilling and Trucking. Depreciation and amortization expense — drilling decreased to $10.8 million for the six months ended June 30, 2010, as compared to $12.0 million for the comparable year earlier period. The decrease is due to the effect on the depreciation rate of rig impairments recorded during 2009. 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 increased 7% to $23.0 million for the six months ended June 30, 2010, as compared to $21.6 million for the comparable prior year period. The increase in general and administrative expenses is attributed to costs associated with the strategic alternatives evaluation process and by increased non-cash stock compensation expense related to restricted stock granted in December 2009, partially offset by reduced staffing as a result of reductions in force during the first half of 2009 resulting in lower cash compensation expense.

Executive Severance Expense, Net. On May 26, 2009, our then Chairman of the Board of Directors and Chief Executive Officer, Roger A. Parker, resigned from Delta. 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, issue to him 1,000,000 shares of Delta common stock, 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 contained mutual releases and non-disparagement provisions, as well as other customary terms.

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Interest Expense and Financing Costs, Net. Interest and financing costs, net decreased 38% to $20.1 million for the six months ended June 30, 2010, as compared to $32.2 million for the comparable year earlier period. The decrease is primarily related to lower average outstanding Delta and DHS credit facility balances coupled with lower interest rates during the first half of 2010 as compared to the first half of 2009. The decrease is also related to a greater write-off of unamortized deferred financing costs and waiver fees related to the amendments to our credit facilities in 2009 compared to 2010. In addition, the six 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.

Realized Loss on Derivative Instruments, Net. During the six months ended June 30, 2010, we recognized a $4.7 million loss associated with settlements on derivative contracts. During the six months ended June 30, 2009 there were no derivative contract settlements.

Unrealized Loss on Derivative Instruments, Net. We recognize mark-to-market gains or losses in current earnings instead of deferring those amounts in accumulated other comprehensive income. Accordingly, we recognized $20.9 million of unrealized gains on derivative instruments in other income and expense during the six months ended June 30, 2010 compared to a loss of $21.1 million for the comparable prior year period.

Income (Loss) From Unconsolidated Affiliates. 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 from unconsolidated affiliates during the six months ended June 30, 2010 is comprised of our pro-rata share of net income of our unconsolidated affiliates.

Income Tax Benefit (Expense). Due to our continued losses, we were required by the “more likely than not” threshold for assessing the realizability of deferred tax assets, to record a valuation allowance for our deferred tax assets beginning with the second quarter of 2007. Our income tax expense (benefit) for the six months ended June 30, 2010 and 2009 of $478,000 and $(318,000), respectively, relates only to DHS, as no benefit was provided for our net operating losses.

Discontinued Operations. The results of operations and impairment loss relating to the pending sale of the non-core property interests in the Garden Gulch field, Baffin Bay field, and Bull Canyon field as well as our interest in our wholly-owned subsidiary Piper Petroleum have been reflected as discontinued operations.

The following table shows the total revenues and expenses included in discontinued operations for the above mentioned oil and gas properties for the six months ended June 30, 2010 and 2009 (dollar amounts in thousands):


	Six Months Ended
	June 30,
	2010			2009
Production — Discontinued Operations:
Oil (Mbbl)		10			9
Gas (Mmcf)		1,590			1,598
Total Production (Mmcfe) — Discontinued Operations		1,650			1,652

Revenues	$	7,809		$	5,391

Operating expenses:

Lease operating expense		1,979			2,698
Transportation expense		1,278			1,134
Production taxes		438			55
Depreciation, depletion, amortization and accretion		13,594			10,904
Impairment provision		92,162			—

Total operating expenses		109,451			14,791


Loss from discontinued operations		(101,642	)		(9,400	)
Income tax expense		—			—


Loss from discontinued operations, net of tax	$	(101,642	)	$	(9,400	)

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On July 30, 2010, the Company closed on the sale of non-core properties to Wapiti for cash proceeds of $130.0 million. We expect to recognize a gain on sale for the closing of Wapiti Transaction in the three months ended September 30, 2010 of approximately $29.4 million, subject to revision for normal and customary purchase price adjustments as provided for under the purchase and sale agreement. In total, the Wapiti Transaction is expected to result in a $66.7 million loss when the second quarter asset held for sale impairments are considered in conjunction with the third quarter gain on sale.

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, 2010 and 2009, DHS reported significant losses from low rig utilization rates which resulted in a non-controlling interest credit to earnings.

Historical Cash Flow

Our cash flow from operating activities decreased from $32.8 million for the six months ended June 30, 2009 to cash used in operating activities of $23.3 million for the six months ended June 30, 2010. The significant decrease in cash flow is primarily the result of changes in working capital and proceeds from the offshore litigation awarded in 2009 partially offset by higher commodity prices. Our net cash used in investing activities decreased to $12.1 million for the six months ended June 30, 2010 compared to net cash used in investing activities of $115.3 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 $22.7 million for the six months ended June 30, 2009 to cash used in financing activities of $15.5 million for the current year period. During the six months ended June 30, 2010, we made net bank payments of $14.2 million. During the six months ended June 30, 2009, $247.2 million of cash was received from the issuance of stock and we made net bank payments of $222.0 million.

Capital and Exploration Expenditures

Our capital and exploration expenditures for the six months ended June 30, 2010 and 2009 were as follows (in thousands):


	2010		2009
CAPITAL AND EXPLORATION EXPENDITURES:

Property acquisitions:
Unproved	$	285	$	1,713
Proved		—		—
Oil and gas properties		18,917		40,518
Drilling and trucking equipment		995		3,128
Pipeline and gathering systems		5,764		6,802

Total ⁽¹⁾	$	25,961	$	52,161


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.

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3³/4% Senior Convertible Notes, due 2037

On April 25, 2007, we issued $115.0 million aggregate principal amount of 3³/4% Senior Convertible Notes due 2037 (the “Notes”) for net proceeds of $111.6 million after underwriters’ discounts and commissions of approximately $3.4 million. The remaining discount will be amortized through May 1, 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 3³/4% per annum, payable semi-annually in arrears, on May 1 and November 1 of each year. Combined with the amortization of debt discount, the Notes have an effective interest rate of approximately 7.7% and 7.6% with total interest costs of $2.2 million for each of the three month periods ended June 30, 2010 and 2009, respectively, and interest costs of $4.4 million and $4.3 million for the six month periods ended June 30, 2010 and 2009, 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

Pursuant to the Fourth Amendment dated as of July 23, 2010, among other changes more fully described in Note 7, “Long Term Debt” to the accompanying financial statements, the borrowing base under our Credit Agreement was reduced to $35.0 million upon the consummation of the Wapiti Transaction.

The Fourth Amendment eliminated all scheduled or special borrowing base redeterminations prior to the maturity of the facility in January 2011.

The Credit Agreement 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.

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Credit Facility — DHS

On April 1, 2010 DHS amended its existing credit facility with Lehman Commercial Paper, Inc. and renegotiated certain terms of the agreement, to, among other changes more fully described in Note 7, “Long Term Debt” to the accompanying financial statements, bring DHS into compliance with the terms of the agreement, amend the principal repayment schedule, adjust the interest rate, and eliminate or amend certain financial covenants.

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 $6.0 million at June 30, 2010. 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.

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, 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

45

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.

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. For the six months ended June 30, 2010, the expected future undiscounted cash flows of the assets exceeded the carrying value of the corresponding asset and as such no impairment provision was recognized.

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

46

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 $22.5 million for the six months ended June 30, 2010. The $22.5 million impairment included $11.4 million related to our Columbia River Basin leasehold, $5.0 million related to our Hingeline leasehold, $3.8 million related to our Haynesville leasehold, $1.6 million related to our Delores River leasehold and $661,000 related to our Howard Ranch leasehold. In addition, we recorded an impairment of $4.8 million to reduce the Paradox pipeline carrying value to its estimated fair value during the six months ended June 30, 2010. These impairments are included within dry hole costs and impairments in the accompanying statement of operations for the six months ended June 30, 2010.

In addition to the impairment provisions discussed above, we utilized various fair value techniques related to our Garden Gulch, Baffin Bay, DJ Basin, Caballos Creek, Opossum Hollow, Midway Loop, and Newton fields, as well as our interest in our wholly owned subsidiary Piper Petroleum and unproved acreage positions in the DJ Basin and South Texas assets which were held for sale at June 30, 2010 and determined that impairment provisions of $93.2 million related to proved properties and $3.0 million related to unproved properties were required to be recognized during the six months ended June 30, 2010. Based upon the applicable accounting standards, $4.0 million of the impairment provision is included within dry hole costs and impairments in the accompanying statement of operations for the six months ended June 30, 2010 and $92.2 million is included in loss from discontinued operations for the six months ended June 30, 2010.

During the remainder of 2010, 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 provision 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. 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, 2010, we had a total of seven oil and gas derivative contracts outstanding. The fair value of our oil derivative instruments was a liability of $8.0 million and the fair value of our gas derivative instruments was an asset of $2.0 million at June 30, 2010. We classify the fair value amounts of derivative assets and liabilities executed under master netting arrangements as net derivative assets or net derivative liabilities, whichever the case may be, by commodity and master netting counterparty. The discount rates used to determine the fair value of these derivative instruments include a measure of non-performance risk by both Delta and the counterparty, 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, 2010. The pre-credit risk adjusted fair value of our net derivative liabilities as of June 30, 2010 was $6.6 million. A credit risk adjustment of $578,000 to the fair value of the derivatives reduced the reported amount of the net derivative liabilities on our consolidated balance sheet to $6.0 million.

Asset Retirement Obligation

We account for our asset retirement obligations under applicable FASB guidance which 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.

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Deferred Tax Asset Valuation Allowance

The Company uses the asset and liability method of accounting for income taxes. Under the asset and liability method, 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 Issued and Adopted Accounting Pronouncements

In January 2010, the FASB issued Accounting Standards Update No. 2010-06, Improving Disclosures about Fair Value Measurements (“ASU 2010-06”), which provides amendments to FASB ASC Topic 820,Fair Value Measurements and Disclosures. The objective of ASU 2010-06 is to provide more robust disclosures about (i) the different classes of assets and liabilities measured at fair value, (ii) the valuation techniques and inputs used, (iii) the activity in Level 3 fair value measurements, and (iv) significant transfers between Levels 1, 2 and 3. ASU 2010-06 is effective for fiscal years and interim periods beginning after December 15, 2009. We adopted ASU 2010-06 effective January 1, 2010, which did not have an impact on our consolidated financial statements, other than additional disclosures.

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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, 2010:


								Net Fair Value
						Remaining		Asset (Liability) at
Commodity	Volume			Fixed Price		Term	Index Price	June 30, 2010
								(In thousands)
Crude oil		1,000	Bbls / Day¹	$	52.25	July ’10 - Dec ’10	NYMEX — WTI	$	(4,403	)
Crude oil		500	Bbls / Day	$	57.70	Jan ’11 - Dec ’11	NYMEX — WTI		(3,565	)
Natural gas		6,000	MMBtu / Day	$	5.720	July ’10 - Dec ’10	NYMEX — HHUB		983
Natural gas		15,000	MMBtu / Day	$	4.105	July ’10 - Dec ’10	CIG		(292	)
Natural gas		5,367	MMBtu / Day	$	3.973	July ’10 - Dec ’10	CIG		(232	)
Natural gas		12,000	MMBtu / Day	$	5.150	Jan ’11 - Dec ’11	CIG		1,267
Natural gas		3,253	MMBtu / Day	$	5.040	Jan ’11 - Dec ’11	CIG		218

								$	(6,024	)


1		As a result of the closing of the Wapiti Transaction, for the period from August to December 2010, we expect our oil derivative contracts to equal 108% to 114% of forecast oil and condensate production sold on WTI based terms. Because derivative contract volumes are anticipated to exceed physical production volumes in certain months, we could be exposed to financial derivative losses in excess of oil revenue gains to the extent WTI oil prices rise from current levels.

Assuming production and the percent of oil and gas sold remained unchanged for the six months ended June 30, 2010, a hypothetical 10% decline in the average market price we realized during the six months ended June 30, 2010 on unhedged production would reduce our oil and natural gas revenues by approximately $5.5 million.

Interest Rate Risk

We were subject to interest rate risk on $193.1 million of variable rate debt obligations at June 30, 2010. The annual effect of a 10% change in interest rates on the debt would be approximately $1.1 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, 2010, 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.

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PART II — OTHER INFORMATION

Item 1. Legal Proceedings

From time to time, we may be involved in litigation relating to claims arising out of our operations in the normal course of our business. As of the date of this report, no legal proceedings are pending against us that we believe individually or collectively could have a materially adverse effect upon our financial condition, results of operations or cash flows.

Item 1A. Risk Factors

Our business has many risks. Factors that could materially adversely affect our business, financial condition, operating results or liquidity and the trading price of our common stock, senior notes or convertible notes are described under “Risk Factors” in Item 1A of our 2009 Annual Report on Form 10-K for the year ended December 31, 2009 filed with the SEC on March 12, 2010. This information should be considered carefully, together with other information in this report and other reports and materials we file with the SEC.

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

The table below provides a summary of our purchases of our own common stock during the three months ended June 30, 2010.


							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, 2010		6,700	$	1.55		—		—
May 1 – May 31, 2010		—		—		—		—
June 1 – June 30, 2010		—		—		—		—

Total		6,700	$	1.55		—		—


(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 5. Other Information

None.

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Item 6. Exhibits.

Exhibits are as follows:

	10.1		Waiver and Amendment No. 2 to Amended and Restated Credit Agreement, dated as of April 1, 2010, among DHS Holding Company and Lehman Commercial Paper, Inc. Incorporated by reference from Exhibit 10.1 to the Company’s Form 10-Q filed May 10, 2010.

	10.2		Third Amendment to Second Amended and Restated Credit Agreement, dated as of April 26, 2010, by and among the Company, JPMorgan Chase Bank, N.A., and each of the financial institutions named therein. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K filed April 30, 2010.

	10.3		Amended and Restated Employment Agreement with Carl Lakey dated July 15, 2010. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K filed July 21, 2010.

	10.4		Purchase and Sale Agreement, dated as of July 23, 2010, by and between Delta Petroleum Corporation and Wapiti Oil & Gas, L.L.C. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K filed July 27, 2010.

	10.5		Fourth Amendment to Second Amended and Restated Credit Agreement, dated as of July 23, 2010, by and among the Company, JPMorgan Chase Bank, N.A., and each of the financial institutions named therein. Filed herewith electronically.

	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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SIGNATURES

Pursuant to the requirements 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/ Carl E. Lakey
		Carl E. Lakey, President and
		Chief Executive Officer


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

Date: August 9, 2010

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EXHIBIT INDEX:

	10.1		Waiver and Amendment No. 2 to Amended and Restated Credit Agreement, dated as of April 1, 2010, among DHS Holding Company and Lehman Commercial Paper, Inc. Incorporated by reference from Exhibit 10.1 to the Company’s Form 10-Q filed May 10, 2010.

	10.2		Third Amendment to Second Amended and Restated Credit Agreement, dated as of April 26, 2010, by and among the Company, JPMorgan Chase Bank, N.A., and each of the financial institutions named therein. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K filed April 30, 2010.

	10.3		Amended and Restated Employment Agreement with Carl Lakey dated July 15, 2010. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K filed July 21, 2010.

	10.4		Purchase and Sale Agreement, dated as of July 23, 2010, by and between Delta Petroleum Corporation and Wapiti Oil & Gas, L.L.C. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K filed July 27, 2010.

	10.5		Fourth Amendment to Second Amended and Restated Credit Agreement, dated as of July 23, 2010, by and among the Company, JPMorgan Chase Bank, N.A., and each of the financial institutions named therein. Filed herewith electronically.

	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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