DPTRD Delta Petroleum Corp. (MM)

 

 

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, 2011

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. Yes þ 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 þ 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.

Large accelerated filer o		Accelerated filer þ		Non-accelerated filer o		Smaller reporting company o

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

28,882,887 shares of common stock, $.01 par value per share, were outstanding as of August 1, 2011.

 

 

INDEX

		Page No.
PART I FINANCIAL INFORMATION
Item 1. Consolidated Financial Statements
Consolidated Balance Sheets — June 30, 2011 and December 31, 2010 (unaudited)			1
Consolidated Statements of Operations — Three Months Ended June 30, 2011 and 2010 (unaudited)			2
Consolidated Statements of Operations — Six Months Ended June 30, 2011 and 2010 (unaudited)			3
Consolidated Statement of Changes in Equity — Six Months Ended June 30, 2011 (unaudited)			4
Consolidated Statements of Cash Flows — Six Months Ended June 30, 2011 and 2010 (unaudited)			5
Notes to Consolidated Financial Statements (unaudited)			6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			28
Item 3. Quantitative and Qualitative Disclosures About Market Risk			43
Item 4. Controls and Procedures			44
PART II OTHER INFORMATION
Item 1. Legal Proceedings			44
Item 1A. Risk Factors			45
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			46
Item 5. Other Information			46
Item 6. Exhibits			47
Exhibit 10.2
Exhibit 10.4
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

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

PART I FINANCIAL INFORMATION

Item 1.		Consolidated Financial Statements

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

		June 30,				December 31,
		2011				2010
		(In thousands, except share data)
ASSETS
Current assets:
Cash and cash equivalents		$	3,894			$	14,190
Short-term restricted deposits			100,000				100,000
Trade accounts receivable, net of allowance for doubtful accounts of $100 and $100, respectively			7,510				7,373
Assets held for sale — DHS subsidiary and oil and gas properties			66,704				108,218
Deposits and prepaid assets			2,617				1,720
Inventories			642				3,446
Other current assets			2,836				4,821
Total current assets			184,203				239,768
Property and equipment:
Oil and gas properties, successful efforts method of accounting:
Unproved			229,623				229,943
Proved			695,189				671,041
Pipeline and gathering systems			92,461				93,558
Other			13,815				13,556
Total property and equipment			1,031,088				1,008,098
Less accumulated depreciation and depletion			(247,438	)			(232,493	)
Net property and equipment			783,650				775,605
Long-term assets:
Investments in unconsolidated affiliates			3,590				3,376
Deferred financing costs			1,432				1,832
Other long-term assets			2,970				3,531
Total long-term assets			7,992				8,739
Total assets		$	975,845			$	1,024,112
LIABILITIES AND EQUITY
Current liabilities:
Credit facility — Delta		$	15,000			$	—
Installment payable on property acquisition			99,144				97,874
3 3 / 4 % Senior convertible notes — current			110,953				—
Accounts payable			21,030				27,616
Liabilities related to assets held for sale — DHS subsidiary and oil and gas properties			76,112				82,852
Other accrued liabilities			8,281				11,066
Derivative instruments			2,123				574
Total current liabilities			332,643				219,982
Long-term liabilities:
7% Senior notes			149,722				149,684
3 3 / 4 % Senior convertible notes			—				108,593
Credit facility — Delta			—				29,130
Asset retirement obligations			3,299				2,709
Derivative instruments			3,482				2,419
Total long-term liabilities			156,503				292,535
Commitments and contingencies
Equity:
Preferred stock, $.01 par value: authorized 3,000,000 shares, none issued			—				—
Common stock, $.01 par value: authorized 200,000,000 shares, issued 29,095,000 shares at June 30, 2011 and 28,514,000 shares at December 31, 2010 (1)			291				285
Additional paid-in capital			1,640,295				1,635,783
Treasury stock at cost; zero shares at June 30, 2011 and 3,000 shares at December 31, 2010 (1)			—				(279	)
Accumulated deficit			(1,150,145	)			(1,121,342	)
Total Delta stockholders’ equity			490,441				514,447
Non-controlling interest			(3,742	)			(2,852	)
Total equity			486,699				511,595
Total liabilities and equity		$	975,845			$	1,024,112

See accompanying notes to consolidated financial statements.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

		Three Months Ended
		June 30,
		2011				2010
		(In thousands, except per share amounts)
Revenue:
Oil and gas sales		$	16,882			$	14,822
Loss on property sales			—				(109	)
Total revenue			16,882				14,713
Operating expenses:
Lease operating expense			3,563				6,067
Transportation expense			3,625				4,359
Production taxes			611				786
Exploration expense			233				358
Dry hole costs and impairments			273				29,865
Depreciation, depletion, amortization and accretion			10,528				12,142
General and administrative expense			6,471				10,648
Total operating expenses			25,304				64,225
Operating loss			(8,422	)			(49,512	)
Other income and (expense):
Interest expense and financing costs, net			(7,997	)			(7,781	)
Other income			233				111
Realized loss on derivative instruments, net			(5,010	)			(601	)
Unrealized gain on derivative instruments, net			8,341				3,676
Income from unconsolidated affiliates			131				991
Total other expense			(4,302	)			(3,604	)
Loss from continuing operations before income taxes and discontinued operations			(12,724	)			(53,116	)
Income tax expense (benefit)			(3,938	)			203
Loss from continuing operations			(8,786	)			(53,319	)
Discontinued operations:
Gain (loss) from results of operations and sale of discontinued operations, net of tax			9,320				(99,161	)
Net income (loss)			534				(152,480	)
Less net (gain) loss attributable to non-controlling interest included in discontinued operations			(1,497	)			2,730
Net loss attributable to Delta common stockholders		$	(963	)		$	(149,750	)
Amounts attributable to Delta common stockholders:
Loss from continuing operations		$	(8,786	)		$	(53,319	)
Gain (loss) from discontinued operations, net of tax			7,823				(96,431	)
Net loss		$	(963	)		$	(149,750	)
Basic loss attributable to Delta common stockholders per common share: (1)
Loss from continuing operations		$	(0.31	)		$	(1.93	)
Discontinued operations			0.28				(3.50	)
Net loss		$	(0.03	)		$	(5.43	)
Diluted loss attributable to Delta common stockholders per common share: (1)
Loss from continuing operations		$	(0.31	)		$	(1.93	)
Discontinued operations			0.28				(3.50	)
Net loss		$	(0.03	)		$	(5.43	)

See accompanying notes to consolidated financial statements.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

		Six Months Ended
		June 30,
		2011				2010
		(In thousands, except per share amounts)
Revenue:
Oil and gas sales		$	34,597			$	34,484
Loss on property sales			—				(538	)
Total revenue			34,597				33,946
Operating expenses:
Lease operating expense			6,958				10,527
Transportation expense			7,568				7,642
Production taxes			1,461				1,691
Exploration expense			276				584
Dry hole costs and impairments			416				30,219
Depreciation, depletion, amortization and accretion			22,479				23,887
General and administrative expense			13,100				20,898
Total operating expenses			52,258				95,448
Operating loss			(17,661	)			(61,502	)
Other income and (expense):
Interest expense and financing costs, net			(14,803	)			(16,484	)
Other income			164				179
Realized loss on derivative instruments, net			(5,450	)			(4,714	)
Unrealized gain (loss) on derivative instruments, net			(2,612	)			20,948
Income from unconsolidated affiliates			214				983
Total other income and (expense)			(22,487	)			912
Loss from continuing operations before income taxes and discontinued operations			(40,148	)			(60,590	)
Income tax expense (benefit)			(4,633	)			478
Loss from continuing operations			(35,515	)			(61,068	)
Discontinued operations:
Gain (loss) from results of operations and sale of discontinued operations, net of tax			5,785				(107,404	)
Net loss			(29,730	)			(168,472	)
Less net loss attributable to non-controlling interest included in discontinued operations			927				5,925
Net loss attributable to Delta common stockholders		$	(28,803	)		$	(162,547	)
Amounts attributable to Delta common stockholders:
Loss from continuing operations		$	(35,515	)		$	(61,068	)
Gain (loss) from discontinued operations, net of tax			6,712				(101,479	)
Net loss		$	(28,803	)		$	(162,547	)
Basic loss attributable to Delta common stockholders per common share: (1)
Loss from continuing operations		$	(1.27	)		$	(2.22	)
Discontinued operations			0.24				(3.68	)
Net loss		$	(1.03	)		$	(5.90	)
Diluted loss attributable to Delta common stockholders per common share: (1)
Loss from continuing operations		$	(1.27	)		$	(2.22	)
Discontinued operations			0.24				(3.68	)
Net loss		$	(1.03	)		$	(5.90	)

See accompanying notes to consolidated financial statements.

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 (1)				Amount				capital				Shares (1)				Amount				deficit				equity				interest				equity
		(In thousands)
Balance, December 31, 2010			28,514			$	285			$	1,635,783				3			$	(279	)		$	(1,121,342	)		$	514,447			$	(2,852	)		$	511,595
Net loss			—				—				—				—				—				(28,803	)			(28,803	)			(927	)			(29,730	)
Employee vesting of treasury stock held by subsidiary			—				—				(135	)			(3	)			279				—				144				(59	)			85
Issuance of vested stock			591				6				(6	)			—				—				—				—				—				—
Shares repurchased for withholding taxes			(1	)			—				(7	)			—				—				—				(7	)			—				(7	)
Forfeitures			(9	)			—				—				—				—				—				—				—				—
Stock based compensation			—				—				4,660				—				—				—				4,660				96				4,756
Balance, June 30, 2011			29,095			$	291			$	1,640,295				—			$	—			$	(1,150,145	)		$	490,441			$	(3,742	)		$	486,699

See accompanying notes to consolidated financial statements.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

		Six Months Ended
		June 30,
		2011				2010
		(In thousands)
Cash flows from operating activities:
Net loss		$	(29,730	)		$	(168,472	)
Adjustments to reconcile net loss to cash provided by (used in) operating activities:
Loss on property sales			—				538
Depreciation, depletion, amortization — oil and gas			22,479				23,887
Depreciation, depletion, amortization — discontinued operations			5,464				31,844
(Gain) loss on sale of drilling assets — discontinued operations			(2,438	)			256
Gain on sale of oil and gas assets — discontinued operations			(8,946	)			—
Impairments — discontinued operations			—				93,064
Dry hole costs and impairments			416				30,219
Stock based compensation			4,762				6,852
Amortization of deferred financing costs, bond discount, and installments payable discount			6,198				7,215
Unrealized (gain) loss on derivative contracts			2,612				(20,948	)
Income from unconsolidated affiliates			(214	)			(983	)
Deferred income tax expense			478				478
Other			(395	)			48
Net changes in operating assets and liabilities:
Increase in trade accounts receivable			(67	)			(1,103	)
(Increase) decrease in deposits and prepaid assets			(897	)			686
Increase in inventories			(64	)			—
(Increase) decrease in other current assets			(17	)			765
Increase (decrease) in accounts payable			112				(12,863	)
Decrease in offshore litigation payable			—				(14,756	)
Decrease in other accrued liabilities			(1,854	)			—
Increase in assets held for sale working capital, net			2,213				—
Net cash provided by (used in) operating activities			112				(23,273	)
Cash flows from investing activities:
Additions to property and equipment			(36,727	)			(18,861	)
Additions to drilling and trucking equipment — assets held for sale			(822	)			(709	)
Proceeds from sale of oil and gas properties			41,216				2,007
Proceeds from sale of drilling assets — assets held for sale			3,367				464
Proceeds from sale of other fixed assets			61				39
Proceeds from sale of unconsolidated affiliates			898				3,500
Proceeds from escrow deposit			—				1,380
Decrease in other long-term assets			—				106
Net cash provided by (used in) investing activities			7,993				(12,074	)
Cash flows from financing activities:
Proceeds from borrowings			49,202				66,500
Repayments of borrowings			(66,617	)			(80,678	)
Payment of deferred financing costs			(979	)			(1,337	)
Stock repurchased for withholding taxes			(7	)			(5	)
Net cash used in financing activities			(18,401	)			(15,520	)
Net decrease in cash and cash equivalents			(10,296	)			(50,867	)
Cash at beginning of period			14,190				61,918
Cash at end of period		$	3,894			$	11,051
Supplemental cash flow information:
Cash paid for interest and financing costs		$	10,011			$	14,395
DHS interest payable capitalized to principal balance (non-cash financing transaction)		$	3,566			$	—

See accompanying notes to consolidated financial statements.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES

Notes to Consolidated Financial Statements

Three and Six Months Ended June 30, 2011 and 2010

(Unaudited)

(1) Nature of Organization and Basis of Presentation

Delta Petroleum Corporation (“Delta”), a Delaware corporation, and its consolidated subsidiaries (collectively, the “Company”) are 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, 2010. 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, 2010, previously filed with the SEC.

(2) Going Concern

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

On December 29, 2010, the Company entered into a Third Amended and Restated Credit Agreement (the “MBL Credit Agreement”), with Macquarie Bank Limited (“MBL”) as administrative agent and issuing lender as more fully described in Note 6, “Long Term Debt.” Proceeds available from the MBL Credit Agreement were used to substantially reduce amounts outstanding under the Company’s prior credit facility, as well as to extend the maturity of the remaining balance under that credit facility from January 15, 2011 to January 31, 2012, and to fund capital expenditures. On June 28, 2011, the Company amended the MBL Credit Agreement to permit the 2011 Wapiti Transaction.

On June 28, 2011, the Company closed on a transaction with Wapiti Oil & Gas, L.L.C. (“Wapiti”) to sell its remaining interests in various non-core assets primarily located in Texas and Wyoming (the “2011 Wapiti Transaction”) for gross cash proceeds of approximately $43.2 million. Proceeds from the 2011 Wapiti Transaction were used to further reduce amounts outstanding under the MBL Credit Agreement, as well as to fund capital expenditures.

The MBL Credit Agreement, as amended, provides for a revolving loan and a term loan, each with a maturity date of January 31, 2012. At June 30, 2011, zero was outstanding under the revolving loan and $15.0 million was outstanding under the term loan. The Company was in compliance with its financial covenants under the MBL Credit Agreement as of June 30, 2011.

During the six months ended June 30, 2011, the Company experienced a net loss attributable to Delta common stockholders of $28.8 million, and at June 30, 2011 had a working capital deficiency, excluding discontinued operations, of $139.0 million, including $15.0 million outstanding under the MBL Credit Agreement (which is classified as a current liability in the accompanying balance sheet). In addition to the amounts outstanding under the Company’s credit facility which are due on January 31, 2012, the holders of the Company’s $115.0 million 3 ³ / ₄ % senior convertible notes have the option to require the Company to repurchase the notes at par on May 1, 2012.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES

Notes to Consolidated Financial Statements

Three and Six Months Ended June 30, 2011 and 2010

(Unaudited)

(2) Going Concern, Continued

While the 2011 Wapiti Transaction and the MBL Credit Agreement provided capital to the Company that helped to improve its financial position, the Company does not have adequate capital to repay its credit facility borrowings due on January 31, 2012 or fund the purchase of convertible notes if the holders of such notes elect to require the Company to repurchase such notes on May 1, 2012, as expected.

The Company believes that the amounts available under the Company’s credit facility, as amended, combined with projected net cash from operating activities, will provide sufficient liquidity to fund its operating expenses, the limited Vega Area capital development plan, and maintain current debt service obligations until the January 2012 maturity of the Company’s credit facility. In order to address the January 2012 maturity of the Company’s credit facility and the expected mandatory redemption in May 2012 of the $115.0 million senior convertible notes, the Company is in the process of seeking additional sources of long-term capital (including the issuance of equity, debt instruments, sales of assets and joint venture financing), as well as consider other potential corporate transactions such as a sale of the Company.

As a result, in July 2011, the Board of Directors of the Company announced that it had engaged Macquarie Capital (USA) Inc. and Evercore Group, L.L.C. to act as advisors to the Company in conducting a strategic alternatives process in order to maximize shareholder value and address the 2012 debt maturities. Through this process, the Board of Directors intends to evaluate all opportunities available, including a potential sale of the Company.

The timing, structure, terms, size, and pricing of any transaction consummated as a result of the strategic alternatives process will depend on investor interest and market conditions, as well as the Company’s drilling and completion results, and there can be no assurance that the Company will be able to obtain any such financing or consummate any such transaction, and if so, that it will be on terms satisfactory to the Company which raises substantial doubt about the Company’s ability to continue as a going concern. 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.

The DHS Drilling Company (“DHS”) credit facility debt of $69.9 million at June 30, 2011 is included in the accompanying consolidated balance sheets as a component of liabilities related to assets held for sale. DHS has entered into a forbearance agreement, as amended, that currently expires on August 8, 2011. Although DHS is in ongoing negotiations with its lender, Lehman Commercial Paper, Inc. (“LCPI”) to modify the terms of the existing DHS credit facility, there can be no assurance that DHS will be able to renegotiate the terms of its debt agreement or obtain any further extension to the forbearance agreement. If DHS is unable to extend the forbearance agreement or modify the terms of its debt agreement, and if LCPI exercises its default rights upon expiration of the forbearance period, including demanding immediate payment of all amounts outstanding under the debt agreement, DHS is not anticipated to have sufficient capital to repay the amounts due. The DHS facility is non-recourse to Delta. During the first quarter of 2011, the Board of Directors of DHS engaged transaction advisors to commence a strategic alternatives process, focused on a sale of DHS or substantially all of its assets. There can be no assurance that the terms offered by a potential buyer or buyers, if any, will be acceptable to the DHS shareholders, including Delta. Additionally, the consummation of certain transactions are subject to the approval of LCPI and the proceeds received will be required to be used to pay down amounts outstanding under its LCPI credit facility.

(3) Summary of Significant Accounting Policies

Principles of Consolidation and Basis of Presentation

The consolidated financial statements include the accounts of Delta and its consolidated subsidiaries (collectively, the “Company”). All inter-company balances and transactions have been eliminated in consolidation. Certain of the Company’s oil and gas activities are conducted through partnerships and joint ventures, including CRB Partners, LLC (“CRBP”) and through the date of the divestiture in 2010 to Wapiti, PGR Partners, LLC (“PGR”). The Company includes its proportionate share of assets, liabilities, revenues and expenses from these entities in its consolidated financial statements. The Company does not have any off-balance sheet financing arrangements (other than operating leases) or any unconsolidated special purpose entities.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES

Notes to Consolidated Financial Statements

Three and Six Months Ended June 30, 2011 and 2010

(Unaudited)

(3) Summary of Significant Accounting Policies, Continued

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 sold or held for sale during the three and six months ended June 30, 2011 have been reclassified from continuing operations to discontinued operations for all periods presented. In addition, the assets and liabilities of DHS, and oil and gas properties that were sold or held for sale, have been separately reflected in the accompanying consolidated balance sheets as assets held for sale and liabilities related to assets held for sale. Such reclassifications had no effect on net loss (See Note 4, “Discontinued Operations”).

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, then evaluated quarterly and charged to expense if and when the well is determined not to have found reserves in commercial quantities. The sale of a partial interest in a proved property is accounted for as a cost recovery and no gain or loss is recognized as long as this treatment does not significantly affect the units-of-production amortization rate. A gain or loss is recognized for all other sales of producing properties.

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

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

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

Impairment of Long-Lived Assets

Long-lived assets are reviewed for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable.

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

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES

Notes to Consolidated Financial Statements

Three and Six Months Ended June 30, 2011 and 2010

(Unaudited)

(3) Summary of Significant Accounting Policies, Continued

The Company assesses proved properties on an individual field basis for impairment on at least an annual basis. For proved properties, the review consists of a comparison of the carrying value of the asset with the asset’s expected future undiscounted cash flows without interest costs. For the three and six months ended June 30, 2011 and 2010, the expected future undiscounted cash flows of the assets exceeded the carrying value of the corresponding asset and as such no impairment provisions were recognized.

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. For the three and six months ended June 30, 2011, no significant impairments were recorded. For the three and six months ended June 30, 2010, the Company recorded impairment provisions attributable to unproved properties of $24.6 million and $25.5 million, 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.

During the remainder of 2011, 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.

Exploratory Well Costs

		Six Months Ended
		June 30, 2011
Balance at beginning of year		$	6,200
Additions to capitalized exploratory well costs pending the determination of proved reserves			13,445
Exploratory well costs included in property divestitures			—
Reclassified to proved oil and gas properties based on the determination of proved reserves			—
Capitalized exploratory well costs charged to dry hole expense			—
Balance at end of period		$	19,645
Exploratory well costs capitalized for one year or less after after completion of drilling			19,645
Exploratory well costs capitalized for greater than one year after completion of drilling			—
Balance at end of period		$	19,645

The table does not include amounts that were capitalized and either subsequently expensed or reclassified to producing well costs in the same period. During 2010, the Company spud a deep test well in the Vega Area to explore the Company’s Piceance leasehold below the currently productive Williams Fork zone. Completion activities on the well began in February 2011 and the well was completed as a producing well with proved reserves subsequent to June 30, 2011. A second deep test well was spud and completed as a producing well with proved reserves during the six months ended June 30, 2011 and therefore is not included in the table above. A third deep test well was spud during the three months ended June 30, 2011 and remains in progress.

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.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES

Notes to Consolidated Financial Statements

Three and Six Months Ended June 30, 2011 and 2010

(Unaudited)

(3) Summary of Significant Accounting Policies, Continued

The following is a reconciliation of the Company’s asset retirement obligations from January 1, 2011 to June 30, 2011 (in thousands):

Asset retirement obligation — January 1, 2011		$	5,146
Reclassification for assets held for sale			(1,215	)
Adjusted asset retirement obligation — January 1, 2011			3,931
Accretion expense			150
Change in estimate			(114	)
Obligations incurred (from new wells)			45
Obligations settled			(20	)
Obligations on sold properties			(118	)
Asset retirement obligation — June 30, 2011			3,874
Less: Current portion of asset retirement obligation			(575	)
Long-term asset retirement obligation		$	3,299

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, 2011 and 2010, comprehensive loss attributable to Delta common stockholders was $963,000 and $149.8 million, respectively. For the six months ended June 30, 2011 and 2010, comprehensive loss attributable to Delta common stockholders was $28.8 million and $162.5 million, respectively.

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.

(4) Discontinued Operations

During the third quarter of 2010, the Company closed a transaction with Wapiti (the “2010 Wapiti Transaction”), selling all or a portion of the Company’s interest in various non-core assets primarily located in Colorado, Texas, and Wyoming for gross proceeds of $130.0 million. During the three months ended June 30, 2011, the Company closed the 2011 Wapiti Transaction, selling the remaining portion of its interests in non-core assets primarily located in Texas and Wyoming for gross cash proceeds of approximately $43.2 million. In accordance with accounting standards, the results of operations relating to these properties have been reflected as discontinued operations for all periods presented. In addition, the assets and liabilities related to the oil and gas properties in the 2011 Wapiti Transaction have been separately reflected in the accompanying consolidated balance sheet as of December 31, 2010 as assets held for sale and liabilities related to assets held for sale.

In separate transactions in 2010, the Company sold its interest in the Howard Ranch field and the Laurel Ridge field and has included these properties in discontinued operations as well.

During the three months ended March 31, 2011, the Board of Directors of DHS engaged transaction advisors to commence a strategic alternatives process, focused on a sale of DHS or substantially all of its assets. As such, in accordance with accounting standards, the results of operations relating to DHS have been reflected as discontinued operations. In addition, the assets and liabilities of DHS have been separately reflected in the accompanying consolidated balance sheets as assets held for sale and liabilities related to assets held for sale.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES

Notes to Consolidated Financial Statements

Three and Six Months Ended June 30, 2011 and 2010

(Unaudited)

(4) Discontinued Operations, Continued

The following table shows the oil and gas segment and drilling segment revenues and expenses included in discontinued operations for the above mentioned oil and gas properties for the three months ended June 30, 2011 and 2010 (in thousands):

		Three Months Ended												Three Months Ended
		June 30, 2011												June 30, 2010
		Oil & Gas				Drilling				Total				Oil & Gas				Drilling				Total
Revenues:
Oil and gas sales		$	4,594			$	—			$	4,594			$	13,504			$	—			$	13,504
Contract drilling and trucking fees			—				12,129				12,129				—				11,064				11,064
Total Revenues			4,594				12,129				16,723				13,504				11,064				24,568
Operating Expenses:
Lease operating expense			1,307				—				1,307				2,943				—				2,943
Transportation expense			12				—				12				799				—				799
Production taxes			321				—				321				792				—				792
Depreciation, depletion, amortization and accretion — oil and gas			1,286				—				1,286				9,605				—				9,605
Impairment provision (1)			—				—				—				93,064				—				93,064
Drilling and trucking operating expenses			—				9,406				9,406				—				8,123				8,123
Depreciation and amortization — drilling and trucking (2)			—				—				—				—				5,226				5,226
General and administrative expense			—				1,051				1,051				—				992				992
Total operating expenses			2,926				10,457				13,383				107,203				14,341				121,544
Operating income (loss)			1,668				1,672				3,340				(93,699	)			(3,277	)			(96,976	)
Other income and (expense):
Interest expense and financing costs, net			—				(2,091	)			(2,091	)			—				(1,775	)			(1,775	)
Other income (expense)			—				124				124				—				(410	)			(410	)
Total other income and (expense)			—				(1,967	)			(1,967	)			—				(2,185	)			(2,185	)
Income (loss) from discontinued operations			1,668				(295	)			1,373				(93,699	)			(5,462	)			(99,161	)
Income tax expense (3)			(615	)			—				(615	)			—				—				—
Income (loss) from results of operations of discontinued operations, net of tax			1,053				(295	)			758				(93,699	)			(5,462	)			(99,161	)
Gain on sales of discontinued operations, net of tax (4)			5,645				2,917				8,562				—				—				—
Gain (loss) from results of operations and sale of discontinued operations, net of tax		$	6,698			$	2,622			$	9,320			$	(93,699	)		$	(5,462	)		$	(99,161	)

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2011 and 2010
(Unaudited)

(4) Discontinued Operations, Continued

The following table shows the oil and gas segment and drilling segment revenues and expenses included in discontinued operations for the above mentioned oil and gas properties for the six months ended June 30, 2011 and 2010 (in thousands):

		Six Months Ended												Six Months Ended
		June 30, 2011												June 30, 2010
		Oil & Gas				Drilling				Total				Oil & Gas				Drilling				Total
Revenues:
Oil and gas sales		$	9,935			$	—			$	9,935			$	28,295			$	—			$	28,295
Contract drilling and trucking fees			—				26,393				26,393				—				20,996				20,996
Total Revenues			9,935				26,393				36,328				28,295				20,996				49,291
Operating Expenses:
Lease operating expense			2,517				—				2,517				6,654				—				6,654
Transportation expense			22				—				22				1,443				—				1,443
Production taxes			404				—				404				1,568				—				1,568
Depreciation, depletion, amortization and accretion — oil and gas			2,795				—				2,795				21,046				—				21,046
Impairment provision (1)			—				—				—				93,064				—				93,064
Drilling and trucking operating expenses			—				22,507				22,507				—				16,012				16,012
Depreciation and amortization — drilling and trucking (2)			—				2,669				2,669				—				10,798				10,798
General and administrative expense			—				2,084				2,084				—				2,129				2,129
Total operating expenses			5,738				27,260				32,998				123,775				28,939				152,714
Operating income (loss)			4,197				(867	)			3,330				(95,480	)			(7,943	)			(103,423	)
Other income and (expense):
Interest expense and financing costs, net			—				(4,129	)			(4,129	)			—				(3,632	)			(3,632	)
Other income (expense)			—				(428	)			(428	)			—				(349	)			(349	)
Total other income and (expense)			—				(4,557	)			(4,557	)			—				(3,981	)			(3,981	)
Income (loss) from discontinued operations			4,197				(5,424	)			(1,227	)			(95,480	)			(11,924	)			(107,404	)
Income tax expense (3)			(1,550	)			—				(1,550	)			—				—				—
Income (loss) from results of operations of discontinued operations, net of tax			2,647				(5,424	)			(2,777	)			(95,480	)			(11,924	)			(107,404	)
Gain on sales of discontinued operations (4)			5,645				2,917				8,562				—				—				—
Gain (loss) from results of operations and sale of discontinued operations, net of tax		$	8,292			$	(2,507	)		$	5,785			$	(95,480	)		$	(11,924	)		$	(107,404	)

(1)		Impairment provision . In accordance with accounting standards, the impairment loss relating to certain properties held for sale at June 30, 2010 in conjunction with the 2010 Wapiti Transaction were reflected as discontinued operations.
(2)		Depreciation and Amortization — Drilling and Trucking . Depreciation and amortization expense — drilling decreased to $2.7 million for the six months ended June 30, 2011 as compared to $10.8 million for the comparable year earlier period. The decrease is due to not recording depreciation expense beginning in March 2011 in accordance with accounting rules related to the asset held for sale treatment of DHS.
(3)		Income tax expense . For the six months ended June 30, 2011, the Company recorded a tax benefit of $4.8 million due to a non-cash income tax benefit related to gains from discontinued oil and gas operations. Generally accepted accounting principles, or GAAP, require all items be considered, including items recorded in discontinued operations, in determining the amount of tax benefit that results from a loss from continuing operations that should be allocated to continuing operations. In accordance with GAAP, the Company recorded a tax benefit on our loss from continuing operations, which was exactly offset by income tax expense on discontinued operations. Our net deferred tax position at June 30, 2011 is not impacted by this tax allocation.
(4)		Gain on sales of discontinued operations — oil and gas . On June 28, 2011, the Company closed on a transaction with Wapiti Oil & Gas to sell its remaining interests in various non-core assets primarily located in Texas and Wyoming (the “2011 Wapiti Transaction”) for gross cash proceeds of approximately $43.2 million. In accordance with accounting standards, the Company recognized a $5.6 million gain on sale ($8.9 million gain, net of $3.3 million of tax) for the six months ended June 30, 2011 that is reflected in discontinued operations. Gain on sales of discontinued operations — drilling . In June 2011, DHS sold substantially all of its Chapman Trucking assets for $3.3 million in proceeds and a gain of $2.9 million. Proceeds were used to reduce DHS bank debt.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2011 and 2010
(Unaudited)

(5) DHS Drilling

The carrying value of DHS’s drilling rigs and related equipment is assessed for impairment whenever circumstances indicate an impairment may exist. No such impairment provisions were recorded during the three and six months ended June 30, 2011 and 2010.

In January 2010, DHS entered into a daywork drilling contract with Desarrollos y Perforaciones De Mexico (“DPM”) to drill geothermal wells for the benefit of the Mexican national electric company (“CFE”) in the state of Puebla. The rig was released in July after drilling two wells. A total of $3.7 million has been invoiced to DPM for the project with $1.6 million being collected to date. The balance of $2.1 million has been reserved as a doubtful account due to concerns regarding collection, which is included as a component of assets held for sale — DHS subsidiary. Legal action is being taken to collect the amount owed to DHS and the rig is currently under contract.

(6) 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 installment payable due in November 2011 is recorded in the accompanying consolidated financial statements as a current liability at a discounted value. The discount is being accreted on the effective interest method over the term of the installments, including accretion of $600,000 and $1.3 million for the three months ended June 30, 2011 and 2010, respectively, and accretion of $1.3 million and $2.5 million for the six months ended June 30, 2011 and 2010, 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, 2011 (See Note 13, “Guarantor Financial Information”). The fair value of the Company’s senior unsecured notes at June 30, 2011 was approximately $114.0 million.

3 ³ / 4 % Senior Convertible Notes, due 2037

On April 25, 2007, the Company issued $115.0 million aggregate principal amount of 3 ³ / 4 % Senior Convertible Notes due 2037 for net proceeds of $111.6 million after underwriters’ discounts and commissions of approximately $3.4 million. The convertible notes will mature on May 1, 2037 unless earlier converted, redeemed or repurchased, but each holder of convertible notes has the option to require the Company to purchase any outstanding convertible notes on each of May 1, 2012, May 1, 2017, May 1, 2022, May 1, 2027 and May 1, 2032 at a price equal to 100% of the principal amount of the convertible notes to be purchased, payable in cash. The convertible 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 convertible notes, including $1.2 million and $1.1 million of accretion for the three months ended June 30, 2011 and 2010, respectively, and $2.4 million and $2.3 million of accretion for the six months ended June 30, 2011 and 2010, respectively. Combined with the amortization of debt discount, the convertible notes had an effective interest rate of approximately 7.9% and 7.7% with total interest costs of $2.3 million and $2.2 million for the three months ended June 30, 2011 and 2010, respectively, and interest costs of $4.5 million and $4.4 million for the six months ended June 30, 2011 and 2010, respectively. The fair value of the convertible notes at June 30, 2011 was approximately $102.4 million.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2011 and 2010
(Unaudited)

(6) Long Term Debt, Continued

Credit Facility — Delta

On December 29, 2010, the Company entered into the MBL Credit Agreement, which provides for a revolving loan and a term loan, each with a maturity date of January 31, 2012. As a combined result of amendments on March 14, 2011 to increase the amount available under the term loan and June 28, 2011 to reduce the borrowing base for the revolving loan and reduce the amount available under the term loan in conjunction with the divestiture of assets, the revolving loan currently has a borrowing base of $18.0 million and the term loan is limited to $15.0 million. The revolving loan bears interest at prime plus 6% per annum for prime rate advances and LIBOR plus 7% per annum for LIBOR advances, while the term loan bears interest at prime plus 9.5% through September 30, 2011 and prime plus 11.0% thereafter for prime rate advances and at LIBOR plus 10.5% for LIBOR advances through September 30, 2011 and LIBOR plus 12.0% thereafter for LIBOR advances. The March 14, 2011 amendment removed the requirement that advances under the term loan be subject to approval of a development plan. In addition, so long as Delta is not in default under the MBL Credit Agreement, Delta is not required to comply with certain cash management provisions, including the previous requirement to repay any term loan advances outstanding on a monthly basis with 100% of net operating cash flows.

At June 30, 2011, zero was outstanding under the revolving loan and $15.0 million was outstanding under the term loan. The revolving loan and the term loan are subject to quarterly financial covenants, in each case as defined in the MBL Credit Agreement and described in summary here, including maintenance of a minimum current ratio of 1:1, minimum quarterly net operating cash flow of $8.6 million, and maximum quarterly general and administrative expenses (excluding equity based compensation) of $5.0 million.

In addition, the Company may not permit its trade payables to be outstanding more than 90 days following the receipt of applicable invoices. At June 30, 2011, the Company was in compliance with its financial covenants under the MBL Credit Agreement, as adjusted by the lender for certain one-time effects of the 2011 Wapiti Transaction.

Credit Facility — DHS

DHS did not pay its scheduled principal and interest payments due on January 3, April 1, and July 1, 2011 and as a result, entered into a forbearance agreement, as amended, that currently expires on August 8, 2011. In conjunction with the forbearance agreement, the January 3 and April 1 missed interest payments were capitalized to the principal balance of the loan on April 1, 2011 and the July 1 interest payment was capitalized to the principal balance of the loan on July 1, 2011, and the loan now bears interest at the default rate of 11% per annum. The DHS credit agreement financial covenants require a minimum EBITDA of $1.5 million per quarter and a capital expenditures limitation of $1.2 million for any fiscal quarter and $2.3 million in the aggregate for fiscal year 2011. DHS was not in compliance with its minimum EBITDA covenant and capital expenditures limitation for the six months ended June 30, 2011. The DHS credit facility debt of $69.9 million at June 30, 2011 is included in the accompanying consolidated balance sheets as a component of liabilities related to assets held for sale. The DHS credit facility is non-recourse to Delta.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2011 and 2010
(Unaudited)

(7) 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, gas, and natural gas liquids commodity swap contracts valued using both quoted prices for identically traded contracts and observable market data for similar contracts (NYMEX WTI oil, CIG gas, and Mont Belvieu natural gas liquids swaps — Level 2).

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, 2011 and 2010, and are considered to be Level 3 fair value measurements.

The following table lists the Company’s fair value measurements by hierarchy as of June 30, 2011 and December 31, 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)				Total
Recurring
Derivative liabilities — June 30, 2011		$	—			$	(5,605	)		$	—			$	(5,605	)
Derivative liabilities — December 31, 2010			—				(2,993	)			—				(2,993	)

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2011 and 2010
(Unaudited)

(8) Commodity Derivative Instruments

The Company periodically enters into commodity price risk transactions to manage its exposure to oil, gas, and natural gas liquids price volatility. These transactions may take the form of futures contracts, collar agreements, swaps or options. The purpose of the transactions 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, natural gas liquids, 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.

On June 28, 2011, as required by the amendment to the MBL Credit Agreement completed in conjunction with the 2011 Wapiti Transaction, the Company paid $3.3 million cash to settle a portion of its oil derivative contracts outstanding from July 2011 to December 2013. The table below reflects the remaining open derivative contracts after consideration of this early termination.

At June 30, 2011, 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.

The following table summarizes the Company’s open derivative contracts at June 30, 2011:

												Net Fair Value
								Remaining				Asset (Liability) at
Commodity		Volume		Fixed Price				Term		Index Price		June 30, 2011
												(In thousands)
Crude oil		192 Bbls / Day		$	57.70			Jul ’11 - Dec ’11		NYMEX – WTI		$	(1,307	)
Crude oil		79 Bbls / Day		$	91.05			Jul ’11 - Dec ’11		NYMEX – WTI			(68	)
Crude oil		230 Bbls / Day		$	91.05			Jan ’12 - Dec ’12		NYMEX – WTI			(632	)
Crude oil		162 Bbls / Day		$	91.05			Jan ’13 - Dec ’13		NYMEX – WTI			(444	)
Natural gas		12,000 MMBtu / Day		$	5.150			Jul ’11 - Dec ’11		CIG			2,064
Natural gas		3,253 MMBtu / Day		$	5.040			Jul ’11 - Dec ’11		CIG			494
Natural gas		12,052 MMBtu / Day		$	4.440			Jan ’12 - Dec ’12		CIG			(66	)
Natural gas		10,301 MMBtu / Day		$	4.440			Jan ’13 - Dec ’13		CIG			(890	)
Natural gas liquids (1)		35,406 Gallons / Day		$	0.913			Jul ’11 - Dec ’11		MT. BELVIEU			(1,698	)
Natural gas liquids (1)		30,617 Gallons / Day		$	0.832			Jan ’12 - Dec ’12		MT. BELVIEU			(2,317	)
Natural gas liquids (1)		12,286 Gallons / Day		$	0.767			Jan ’13 - Dec ’13		MT. BELVIEU			(741	)
												$	(5,605	)

(1)		Natural gas liquids includes purity ethane, propane, natural gasoline, normal butane and isobutene derivatives and the weighted average price is used.

The pre-credit risk adjusted fair value of the Company’s net derivative liabilities as of June 30, 2011 was $6.9 million. A credit risk adjustment of $1.3 million to the fair value of the derivatives increased the reported amount of the net derivative liabilities on the Company’s consolidated balance sheet to $5.6 million.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Six Months Ended June 30, 2011 and 2010
(Unaudited)

(8) Commodity Derivative Instruments, Continued

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, 2011 and December 31, 2010 (in thousands):

Derivatives Not Designated as				June 30, 2011				Dec. 31, 2010
Hedging Instruments		Balance Sheet Classification		Fair Value				Fair Value
Liabilities
Commodity Swaps		Derivative Instruments – Current Liabilities, net		$	(2,123	)		$	(574	)
Commodity Swaps		Derivative Instruments – Long-Term Liabilities, net			(3,482	)			(2,419	)
Total				$	(5,605	)		$	(2,993	)

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, 2011 and 2010 (in thousands):

				June 30, 2011				June 30, 2010
				Amount of				Amount of Gain
				Loss Recognized				(Loss) Recognized
Derivatives Not Designated as		Location of Gain (Loss) Recognized in		in Income				in Income
Hedging Instruments		Income on Derivatives		on Derivatives				on Derivatives
Commodity Swaps		Realized Loss on Derivative Instruments, net – Other Income and (Expense)		$	(5,450	)		$	(4,714	)
Commodity Swaps		Unrealized Gain (Loss) on Derivative Instruments, net – Other Income and (Expense)			(2,612	)			20,948
				$	(8,062	)		$	16,234