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, 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.

I

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
3³/4% 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
3³/4% 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


(1)		All common share amounts (except par value and par value per share amounts) have been retroactively restated as of June 30, 2011 to reflect the Company’s one-for-ten reverse common stock split effective July 13, 2011, as described in Note 10 — Stockholders’ Equity to these consolidated financial statements.

See accompanying notes to consolidated financial statements.

1

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	)


(1)		All common share amounts (except par value and par value per share amounts) have been retroactively restated as of June 30, 2011 to reflect the Company’s one-for-ten reverse common stock split effective July 13, 2011, as described in Note 10 — Stockholders’ Equity to these consolidated financial statements.

See accompanying notes to consolidated financial statements.

2

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	)


(1)		All common share amounts (except par value and par value per share amounts) have been retroactively restated as of June 30, 2011 to reflect the Company’s one-for-ten reverse common stock split effective July 13, 2011, as described in Note 10 — Stockholders’ Equity to these consolidated financial statements.

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⁽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


(1)		All common share amounts (except par value and par value per share amounts) have been retroactively restated as of June 30, 2011 to reflect the Company’s one-for-ten reverse common stock split effective July 13, 2011, as described in Note 10 — Stockholders’ Equity to these consolidated financial statements.

See accompanying notes to consolidated financial statements.

4

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.

5

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 3³/₄% senior convertible notes have the option to require the Company to repurchase the notes at par on May 1, 2012.

6

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.

7

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.

8

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.

9

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.

10

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	)


⁽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 zero for the three months ended June 30, 2011 as compared to $5.2 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 three months ended June 30, 2011, the Company recorded a tax benefit of $3.9 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.

⁽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 three 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.

11

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.

12

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.

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 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.

13

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.

14

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	)

15

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.

16

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

(9) Commitments and Contingencies

Convertible Notes — Right of Repurchase

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.

Decommissioning of Offshore California Leases

The Company formerly owned a 2.41934% working interest in OCS Lease 320 in the Sword Unit, Offshore California, and its 91.68% owned subsidiary, Amber Resources Company of Colorado (“Amber”) formerly owned a 0.97953% working interest in the same lease. Lease 320 was conveyed back to the United States at the conclusion of litigation with the government (Amber Resources Co., et al. vs. United States, Civ. Act. No. 2-30 filed in the United States Court of Federal Claims) when the courts determined that the government had breached that lease (among others) and was liable to the working interest owners for damages; however, the government now contends that the former working interest owners are still obligated to permanently plug and abandon an exploratory well that was drilled on the lease and to clear the well site. The former operator of the lease commenced litigation against the government in United States District Court for the District of Columbia (Noble Energy Corp. vs. Kenneth L. Salazar, Secretary United States Department of the Interior, et al No. 1:09-cv-02013-EGS) seeking a declaratory judgment that the former working interest owners are not responsible for these costs as a result of the government’s breach of the lease. On April 22, 2011, the Court entered a judgment in favor of the government, ruling that the working interest owners jointly and severally share the responsibility to permanently plug and abandon the subject well, and that this duty was not discharged by the government’s breach of contract. On May 11, 2011, the former operator filed an appeal of this ruling to the United States Court of Appeals for the District of Columbia Circuit. It is currently unknown whether or not the appeal will be successful, or what the actual costs of decommissioning the well would be if the former working interest owners are ultimately held liable. If the working interest owners are held liable, the Company and Amber would be responsible for the payment of their respective proportionate shares of the cost.

17

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

(9) Commitments and Contingencies, Continued

In addition, the Company formerly owned a 24.21692% interest in Lease 409 (Non-unitized), a 5.88682% interest in Lease 415 (Point Sal) and a 7.03049% interest in Lease 416 (Point Sal), all of which are located offshore California in the Santa Maria Basin and were assigned back to the government at the conclusion of the Amber litigation discussed above. These leases were operated by a different operator who has commissioned a site clearance study for the decommissioning of operations on the affected leases, but has reserved the right to possibly later take the position that there is no obligation to engage in decommissioning efforts for specified legal and/or regulatory reasons. It is currently unknown whether or not decommissioning efforts will ultimately be undertaken, or what the associated costs would be.

212 Resources

In the fiscal quarter ended March 31, 2011, the Company was engaged in an arbitration with 212 Resources Corporation (“212”) that was filed with the American Arbitration Association on October 27, 2009. The matter was settled pursuant to a final Settlement Agreement executed by the parties on January 25, 2011. In accordance with the Settlement Agreement, the Company paid $1.5 million to 212 in consideration of mutual releases of claims and the termination of the underlying agreement.

DHS Rig Matter

The Company’s indirect, 49.8% owned affiliate DHS and certain of its employees, among others, have been notified by the Office of the Inspector General, Office of Investigations, of the Export-Import Bank of the United States, and the U.S. Department of Justice, that DHS and certain of its and the Company’s employees are the subject of an investigation in connection with a loan guarantee sought from the Export-Import Bank in the first quarter of 2010 of a loan from a Mexican bank sought by a DHS customer in Mexico. DHS has cooperated and will continue to cooperate with the investigation. This investigation is subject to uncertainties, and, as such, DHS is unable to estimate the nature of any possible liability that may result. There has been no communication with the government regarding this matter since February 10, 2011.

(10) Stockholders’ Equity

Preferred Stock

The Company has 3.0 million shares of preferred stock authorized and issuable from time to time in one or more series. As of June 30, 2011 and December 31, 2010, no shares of preferred stock were outstanding.

Common Stock

On July 12, 2011, the shareholders of the Company approved a one-for-ten reverse split of the common stock of the Company which became effective on July 13, 2011. All references in these financial statements to the number of common shares or options, price per share and weighted average number of common shares outstanding prior to the 1:10 reverse stock split have been adjusted to reflect this stock split on a retroactive basis, unless otherwise noted.

Also on July 12, 2011, the shareholders of the Company approved an amendment to the Company’s Amended and Restated Certificate of Incorporation to reduce the number of authorized shares of common stock to 200,000,000 from 600,000,000 shares. Presentation of authorized shares of common stock has been adjusted on a retroactive basis.

18

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

(10) Stockholders’ Equity, Continued

During the three months ended March 31, 2011 and 2010, the Company issued 98,800 and 48,078 fully vested shares to the non-employee members of the Board of Directors in consideration for their service on the Board for the years ended December 31, 2010 and 2009, respectively. On June 10, 2011, the Company granted 3,308 fully vested shares in conjunction with the resignation of a member of the Board of Directors in consideration for service in 2011 through the date of his resignation. On June 21, 2011, the Company granted 489,227 shares of non-vested common stock to certain employees. The shares vest in full on the earlier of a change in control or July 1, 2012. In conjunction with this grant, the Company agreed to establish a “floor” price for the value of the shares on the date of vesting equal to the value of the shares on the grant date ($5.50 per share). In the event that the market price of the shares on the date of vesting is lower than the floor price on the date of vesting, the difference will be paid to the employees in cash. The compensation expense for the shares consists of a fixed equity component ($5.50 per share) and a variable liability component (based on the difference between the market price of the shares, if lower, and the floor price of the shares), both of which are included as a component of general and administrative expense in the accompanying consolidated statements of operations.

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,
	2011		2010		2011		2010
Non-vested stock⁽¹⁾	$	2,346	$	3,105	$	4,610	$	6,136
Performance shares		49		358		152		716

Total	$	2,395	$	3,463	$	4,762	$	6,852


⁽¹⁾		Non-vested stock includes $48,000 and $182,000 for the three months ended June 30, 2011 and 2010, respectively, and $96,000 and $363,000 for the six months ended June 30, 2011 and 2010, respectively, that relates to DHS which is included as a component of discontinued operations in the accompanying consolidated statements of operations.

The Company recognizes the cost of share based payments over the period during which the employee provides service. Exercise prices for options outstanding under the Company’s various plans as of June 30, 2011 ranged from $7.90 to $153.40 per share. At June 30, 2011, there was no unrecognized compensation cost related to stock options as all outstanding options are vested. At June 30, 2011, the Company had 150,300 options outstanding at a weighted average exercise price of $75.00 per share. At June 30, 2011, the Company had 1,211,902 non-vested shares outstanding and no performance shares outstanding. At June 30, 2011, the total unrecognized compensation cost related to the performance shares and the non-vested portion of restricted stock was $4.9 million which is expected to be recognized over a weighted average period of 0.6 years.

19

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

(11) Income Taxes

Income tax expense (benefit) attributable to loss from continuing operations was approximately ($3.9) million and $203,000 for the three months ended June 30, 2011 and 2010, respectively, and ($4.6) million and $478,000 for the six months ended June 30, 2011 and 2010, respectively. Also included in the three months ended June 30, 2011 was a current tax benefit related to a tax refund received as a result of a tax law change that allowed us to carry-back operating losses to a period in which we previously paid tax.

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future results of operations, and tax planning strategies in making this assessment. Based upon the level of historical taxable income, significant book losses during the current and prior periods, and projections for future results of operations over the periods in which the deferred tax assets are deductible, among other factors, management continues to conclude that the Company does not meet the “more likely than not” requirement of ASC 740 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, 2011.

During the three months ended June 30, 2011 and 2010, DHS recorded net operating losses and as of June 30, 2011 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.

For the three and six months ended June 30, 2011, the Company recorded a tax benefit of $3.9 million and $4.8 million, respectively, 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 its loss from continuing operations, which was exactly offset by income tax expense on discontinued operations. The Company’s net deferred tax position at June 30, 2011 is not impacted by this tax allocation.

During the remainder of 2011 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, 2011 and 2010, no adjustments were recognized for uncertain tax benefits.

20

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

(12) 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,
	2011			2010			2011			2010

Net loss attributable to Delta common stockholders	$	(963	)	$	(149,750	)	$	(28,803	)	$	(162,547	)


Basic weighted-average common shares outstanding		27,873			27,583			27,878			27,565
Add: dilutive effects of stock options and unvested stock grants		—			—			—			—

Diluted weighted-average common shares outstanding		27,873			27,583			27,878			27,565


Net loss per common share attributable to Delta common stockholders
Basic	$	(0.03	)	$	(5.43	)	$	(1.03	)	$	(5.90	)

Diluted	$	(0.03	)	$	(5.43	)	$	(1.03	)	$	(5.90	)

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,
	2011		2010		2011		2010
Stock issuable upon conversion of convertible notes		379		379		379		379
Stock options		150		143		150		143
Performance share grants⁽¹⁾		—		15		—		15
Non-vested restricted stock		1,212		672		1,212		672

Total potentially dilutive securities		1,741		1,209		1,741		1,209


⁽¹⁾		During the three months ended June 30, 2011, the two remaining holders of the performance shares returned to the Company for no additional consideration the 8,000 unvested performance shares remaining at the time.

21

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

(13) Guarantor Financial Information

On March 15, 2005, Delta issued $150.0 million of 7% 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. Both the senior notes and the convertible notes are guaranteed by all of the Company’s wholly-owned subsidiaries. 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, and Amber 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, 2011 and December 31, 2010, the condensed consolidated statements of operations for the three and six months ended June 30, 2011 and 2010 and the condensed consolidated statements of cash flows for the six months ended June 30, 2011 and 2010. For purposes of the condensed financial information presented below, the equity in the earnings or losses of subsidiaries is not recorded in the financial statements of the issuer.

Condensed Consolidated Balance Sheet

June 30, 2011


				Guarantor			Non-Guarantor		Adjustments/
	Issuer			Entities			Entities		Eliminations			Consolidated

Current assets	$	116,297		$	311		$	67,595	$	—		$	184,203

Property and equipment:
Oil and gas properties		905,597			—			19,215		—			924,812
Other		73,638			32,638			—		—			106,276

Total property and equipment		979,235			32,638			19,215		—			1,031,088

Accumulated depletion and depreciation		(218,715	)		(28,723	)		—		—			(247,438	)


Net property and equipment		760,520			3,915			19,215		—			783,650

Investment in subsidiaries		85			—			—		(85	)		—
Other long-term assets		5,585			2,407			—		—			7,992


Total assets	$	882,487		$	6,633		$	86,810	$	(85	)	$	975,845


Current liabilities	$	256,559		$	(28	)	$	76,112	$	—		$	332,643

Long-term liabilities:
Long-term debt, derivative instruments and deferred taxes		151,403			1,801			—		—			153,204
Asset retirement obligations		3,299			—			—		—			3,299


Total long-term liabilities		154,702			1,801			—		—			156,503

Total Delta stockholders’ equity		474,968			4,860			10,698		(85	)		490,441

Non-controlling interest		(3,742	)		—			—		—			(3,742	)


Total equity		471,226			4,860			10,698		(85	)		486,699


Total liabilities and equity	$	882,487		$	6,633		$	86,810	$	(85	)	$	975,845

22

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

(13) Guarantor Financial Information, Continued

Condensed Consolidated Balance Sheet
December 31, 2010


				Guarantor			Non-Guarantor		Adjustments/
	Issuer			Subsidiaries			Subsidiaries		Eliminations			Consolidated

Current assets	$	164,377		$	322		$	75,069	$	—		$	239,768

Property and equipment:
Oil and gas properties		881,886			—			19,215		(118	)		900,983
Other		74,438			32,677			—		—			107,115

Total property and equipment		956,324			32,677			19,215		(118	)		1,008,098

Accumulated depletion, depreciation and amortization		(203,731	)		(28,762	)		—		—			(232,493	)


Net property and equipment		752,593			3,915			19,215		(118	)		775,605

Investment in subsidiaries		1,156			—			—		(1,156	)		—
Other long-term assets		6,332			2,407			—		—			8,739


Total assets	$	924,458		$	6,644		$	94,284	$	(1,274	)	$	1,024,112


Current liabilities	$	138,375		$	(26	)	$	81,633	$	—		$	219,982

Long-term liabilities
Long-term debt, derivative instruments and deferred taxes		288,025			1,801			—		—			289,826
Asset retirement obligation and other liabilities		2,709			—			—		—			2,709


Total long-term liabilities		290,734			1,801			—		—			292,535

Total Delta stockholders’ equity		498,201			4,869			12,651		(1,274	)		514,447

Non-controlling interest		(2,852	)		—			—		—			(2,852	)


Total equity		495,349			4,869			12,651		(1,274	)		511,595


Total liabilities and equity	$	924,458		$	6,644		$	94,284	$	(1,274	)	$	1,024,112

23

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

(13) Guarantor Financial Information, Continued

Condensed Consolidated Statement of Operations
Three Months Ended June 30, 2011


				Guarantor			Non-Guarantor			Adjustments/
	Issuer			Entities			Entities			Eliminations		Consolidated

Total revenue	$	16,882		$	—		$	—		$	—	$	16,882

Operating expenses:
Oil and gas expenses		7,799			—			—			—		7,799
Exploration expense		233			—			—			—		233
Dry hole costs and impairments		367			(94	)		—			—		273
Depreciation and depletion		10,528			—			—			—		10,528
General and administrative		6,424			21			26			—		6,471


Total operating expenses		25,351			(73	)		26			—		25,304


Operating income (loss)		(8,469	)		73			(26	)		—		(8,422	)

Other income and (expense)		(4,314	)		11			1			—		(4,302	)
Income tax benefit		3,938			—			—			—		3,938
Discontinued operations		6,698			—			2,622			—		9,320


Net income (loss)		(2,147	)		84			2,597			—		534

Net income attributable to non-controlling interest		(1,497	)		—			—			—		(1,497	)


Net income (loss) attributable to Delta common stockholders	$	(3,644	)	$	84		$	2,597		$	—	$	(963	)

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


				Guarantor			Non-Guarantor			Adjustments/
	Issuer			Entities			Entities			Eliminations		Consolidated

Total revenue	$	14,713		$	—		$	—		$	—	$	14,713

Operating expenses:
Oil and gas expenses		11,212						—			—		11,212
Exploration expense		358			—			—			—		358
Dry hole costs and impairments		24,474			4,805			586			—		29,865
Depreciation and depletion		12,140			2			—			—		12,142
General and administrative		10,608			14			26			—		10,648


Total operating expenses		58,792			4,821			612			—		64,225


Operating loss		(44,079	)		(4,821	)		(612	)		—		(49,512	)

Other income and (expense)		(3,683	)		78			1			—		(3,604	)
Income tax expense		(203	)		—			—			—		(203	)
Discontinued operations		(35,775	)		106			(63,492	)		—		(99,161	)


Net loss		(83,740	)		(4,637	)		(64,103	)		—		(152,480	)

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


Net loss attributable to Delta common stockholders	$	(81,010	)	$	(4,637	)	$	(64,103	)	$	—	$	(149,750	)

24

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

(13) Guarantor Financial Information, Continued

Condensed Consolidated Statement of Operations
Six Months Ended June 30, 2011


				Guarantor			Non-Guarantor			Adjustments/
	Issuer			Entities			Entities			Eliminations		Consolidated

Total revenue	$	34,597		$	—		$	—		$	—	$	34,597

Operating expenses:
Oil and gas expenses		15,987			—			—			—		15,987
Exploration expense		276			—			—			—		276
Dry hole costs and impairments		455			(39	)		—			—		416
Depreciation and depletion		22,479			—			—			—		22,479
General and administrative		13,028			21			51			—		13,100


Total operating expenses		52,225			(18	)		51			—		52,258


Operating income (loss)		(17,628	)		18			(51	)		—		(17,661	)

Other income and (expenses)		(22,500	)		11			2			—		(22,487	)
Income tax benefit		4,633			—			—			—		4,633
Discontinued operations		8,292			—			(2,507	)		—		5,785


Net income (loss)		(27,203	)		29			(2,556	)		—		(29,730	)

Less net loss attributable to non-controlling interest		927			—			—			—		927


Net income (loss) attributable to Delta common stockholders	$	(26,276	)	$	29		$	(2,556	)	$	—	$	(28,803	)

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


				Guarantor			Non-Guarantor			Adjustments/
	Issuer			Entities			Entities			Eliminations		Consolidated

Total revenue	$	33,946		$	—		$	—		$	—	$	33,946

Operating expenses:
Oil and gas expenses		19,860			—			—			—		19,860
Exploration expense		584			—			—			—		584
Dry hole costs and impairments		24,828			4,805			586			—		30,219
Depreciation and depletion		23,885			2			—			—		23,887
General and administrative		20,800			29			69			—		20,898


Total operating expenses		89,957			4,836			655			—		95,448


Operating loss		(56,011	)		(4,836	)		(655	)		—		(61,502	)

Other income and (expenses)		837			72			3			—		912
Income tax expense		(478	)		—			—			—		(478	)
Discontinued operations		(34,719	)		180			(72,865	)		—		(107,404	)


Net loss		(90,371	)		(4,584	)		(73,517	)		—		(168,472	)

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


Net loss attributable to Delta common stockholders	$	(84,446	)	$	(4,584	)	$	(73,517	)	$	—	$	(162,547	)

25

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

(13) Guarantor Financial Information, Continued

Condensed Consolidated Statement of Cash Flows
Six Months Ended June 30, 2011


				Guarantor		Non-Guarantor
	Issuer			Entities		Entities			Consolidated
Cash provided by (used in):
Operating activities	$	(680	)	$	1	$	791		$	112
Investing activities		5,345			1		2,647			7,993
Financing activities		(14,915	)		—		(3,486	)		(18,401	)


Net decrease in cash and cash equivalents		(10,250	)		2		(48	)		(10,296	)

Cash at beginning of the period		13,154			61		975			14,190


Cash at the end of the period	$	2,904		$	63	$	927		$	3,894

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

Guarantor

Non-Guarantor

Issuer

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

26

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

(14) 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. However, as DHS has been reported as discontinued operations (see Note 4, “Discontinued Operations”), drilling did not affect continuing operations and thus is excluded from the table below. Following is a summary of segment results impacting continuing operations for the three and six months ended June 30, 2011 and 2010:


				Inter-segment
	Oil and Gas			Drilling		Eliminations			Consolidated
	(In thousands)
Three Months Ended June 30, 2011
Revenues from external customers	$	16,882		$	—	$	—		$	16,882
Inter-segment revenues		—			—		—			—

Total revenues	$	16,882		$	—	$	—		$	16,882

Operating loss	$	(8,422	)	$	—	$	—		$	(8,422	)

Other expense ⁽¹⁾		(4,302	)		—		—			(4,302	)

Loss from continuing operations, before tax	$	(12,724	)	$	—	$	—		$	(12,724	)


Three Months Ended June 30, 2010
Revenues from external customers	$	14,713		$	—	$	—		$	14,713
Inter-segment revenues		—			—		—			—

Total revenues	$	14,713		$	—	$	—		$	14,713

Operating loss	$	(49,512	)	$	—	$	—		$	(49,512	)

Other expense ⁽¹⁾		(3,604	)		—		—			(3,604	)

Loss from continuing operations, before tax	$	(53,116	)	$	—	$	—		$	(53,116	)


Six Months Ended June 30, 2011
Revenues from external customers	$	34,597		$	—	$	—		$	34,597
Inter-segment revenues		—			—		—			—

Total revenues	$	34,597		$	—	$	—		$	34,597

Operating loss	$	(17,661	)	$	—	$	—		$	(17,661	)

Other expense ⁽¹⁾		(22,487	)		—		—			(22,487	)

Loss from continuing operations, before tax	$	(40,148	)	$	—	$	—		$	(40,148	)


Six Months Ended June 30, 2010
Revenues from external customers	$	33,946		$	—	$	—		$	33,946
Inter-segment revenues		—			—		—			—

Total revenues	$	33,946		$	—	$	—		$	33,946

Operating loss	$	(61,502	)	$	—	$	—		$	(61,502	)

Other income ⁽¹⁾		912			—		—			912

Loss from continuing operations, before tax	$	(60,590	)	$	—	$	—		$	(60,590	)


June 30, 2011
Total Assets	$	975,540		$	66,704	$	(66,399	)	$	975,845


December 31, 2010
Total Assets	$	1,016,635		$	74,093	$	(66,616	)	$	1,024,112


⁽¹⁾		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.

27


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 strategies, including our focus on the Vega Area of the Piceance Basin, as well as statements regarding intended value creation; operating strategies; anticipated use of proceeds from 2011 Wapiti Transaction; our strategic alternatives process; our expectation that we will have adequate cash from operations, credit facility borrowings and other capital sources to maintain current debt service obligations, capital expenditure and working capital requirements; anticipated operating costs; potential sources of long-term capital or potential corporate transactions such as a sale of the company; acquisition and divestiture strategies; completion and drilling activity and timing, expectations, processes and emphasis; expected future revenues and earnings, and results of operations; future capital, development and exploration expenditures (including the amount and nature thereof); 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; anticipated results and impact of litigation and other legal proceedings; 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 Critical Accounting Policies and Estimates and Risk Factors, 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:

•

uncertainty regarding the outcome of our strategic alternatives process;

•

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 senior credit facility, the expected mandatory redemption of our convertible notes, our working capital needs, and drilling and leasehold acquisition programs, including through potential joint ventures and asset monetization transactions;

•

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

•

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

•

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

•

the results of exploratory drilling activities;

28

•

the outcome of the investigation of DHS Drilling Company (“DHS”) and certain of its employees, among others, by the Office of the Inspector General, Office of Investigations, of the Export-Import Bank of the United States, and the U.S. Department of Justice;

•

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;

•

the availability of borrowings under our credit facility;

•

effectiveness of management strategies and decisions;

•

the strength and financial resources of our competitors;

•

climatic conditions;

•

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

•

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

•

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.

29

Recent Developments

•

On July 25, 2011, we announced that our 2C well drilled to evaluate deep potential on our Vega leasehold was successfully completed and brought on sales on July 21, 2011.

•

In May 2011, we retained Macquarie Tristone to provide advisory services relating to the potential sale of certain of our non-operated assets located in the Texas Gulf Coast and DJ Basin regions. On June 28, 2011, we closed on a transaction with Wapiti Oil & Gas, L.L.C. (“Wapiti”) to sell our 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. A portion of the proceeds from the 2011 Wapiti Transaction was used to further reduce amounts outstanding under the Company’s credit facility, and a portion will be used to fund our planned capital development activities in the Vega Area.

•

On June 28, 2011, the MBL Credit Agreement was amended in conjunction with the 2011 Wapiti Transaction to reduce the amounts available under the revolving and term loan portions of the credit facility to $18.0 million and $15.0 million, respectively. In addition, as required by the MBL Credit agreement amendment, we paid $3.3 million cash to settle a portion of our oil derivative contracts outstanding from July 2011 to December 2013.

•

In July 2011, our Board of Directors announced that it had engaged Macquarie Capital (USA) Inc. and Evercore Group, L.L.C. to act as advisors 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.

•

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.

•

DHS did not pay its scheduled principal and interest payments on January 1, 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.

•

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.

2011 Overview

During the first six months of 2011, we completed three previously drilled Williams Fork wells using Gen IV fracturing methods, continued drilling operations on our exploratory test well that was in progress at year-end, and spud, completed and began production on a second test well in an effort to continue to evaluate resource potential below the Williams Fork formation in the Vega Area. A third exploratory test well below the Williams Fork was spud in mid-May and will also serve as a lease preservation well. The completions of the remaining two previously drilled Williams Fork wells are currently scheduled for the fourth quarter of 2011; however, these plans could be altered depending on exploratory well results, with capital potentially being reallocated to additional drilling activities in the Vega Area targeting the deeper shale formations. Based on current commodity prices and our current sources of capital, we intend to continue to focus capital expenditures for the remainder of 2011 on completing the remaining two previously drilled wells and completing our exploratory test well in progress in order to continue to develop the Williams Fork and to evaluate resource potential below the Williams Fork formation in the Vega Area. Although our available capital is limited we expect it will be sufficient to allow for the funding of these development plans. These plans may be adjusted from time to time depending on commodity prices, exploratory well test results, capital availability or other factors.

30

Liquidity and Capital Resources

Our sources of liquidity and capital resources historically have been provided through the issuance of debt and equity securities when market conditions permit, operating activities, sales of oil and gas properties, and through borrowings under our credit facility. The primary uses of our liquidity and capital resources have been in the development and exploration of oil and gas properties. To address our liquidity needs, we sold certain non-core assets to Wapiti for $130.0 million in 2010 (the “2010 Wapiti Transaction”). In 2011, we closed the 2011 Wapiti Transaction, pursuant to which we sold our remaining interests in various non-core assets primarily located in Texas and Wyoming for gross cash proceeds of approximately $43.2 million.

We believe that the amounts available under our credit facility, as amended, combined with our net cash from operating activities, will provide us with sufficient funds to fund our planned operating expenses and capital development activities described herein and maintain current debt service obligations through the end of 2011. Significant changes in operating cash flow, drilling and completion costs, or capital development decisions could impact remaining liquidity and cause violations under our credit facility. As discussed above, our 2011 capital expenditure program, and in particular our drilling and completion capital budget for the Vega Area, is dependent on the results of our drilling and completion activities on the Vega Area exploratory test wells that are currently underway.

To support our future capital expenditure program, and in order to address the January 2012 maturity of our credit facility and the potential mandatory redemption in May 2012 of our $115.0 million convertible notes, we will need to seek 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 including, potentially, the sale of the Company. As discussed, we have announced and are pursuing a strategic alternatives process in that regard.

The timing, structure, terms, size, and pricing of any such financing or transaction will depend on investor interest and market conditions, as well as our drilling and completion results, and there can be no assurance that we 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.

Our Credit Facility

On December 29, 2010, we entered into the MBL Credit Agreement pursuant to which the former lenders assigned their interests to MBL. 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. At June 30, 2011, zero was outstanding under the revolving loan and $15.0 million was outstanding under the term loan. We were in compliance with our financial covenants under our credit facility at June 30, 2011.

DHS Credit Facility

At June 30, 2011, DHS remained out of compliance with the debt covenants under its credit facility and is currently subject to a forbearance agreement, as amended, with LCPI which currently expires on August 8, 2011. The DHS credit facility matures on August 31, 2011 and, as such, all amounts outstanding under the DHS credit facility are classified as a current liability in the accompanying consolidated balance sheet as of June 30, 2011 as a component of liabilities related to assets held for sale. Accordingly, DHS has an immediate debt obligation in an amount in excess of its existing sources of liquidity when the forbearance agreement expires. DHS is in discussions with its credit facility lender regarding further amendments, waivers or other restructuring of the credit facility, but there can be no assurance that the lender will agree to any such amendments. In addition, 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 the company or substantially all of its assets. There can be no assurance that the terms offered by a potential buyer, if any, will be acceptable to the DHS shareholders. Additionally, the consummation of certain transactions are subject to the approval of DHS’s senior lender and the proceeds received will be required to be used to pay down amounts outstanding under its DHS credit facility.

31

Capital Resources and Requirements

Our accompanying financial statements have been prepared assuming we will continue as a going concern. The 2010 Wapiti Transaction and the 2011 Wapiti Transaction provided capital to reduce debt and fund our development program. However, the MBL Credit Agreement matures in January 2012 and the holders of our $115.0 million convertible notes can require us to repurchase the notes at par on May 1, 2012. Thus, our ability to continue as a going concern will be dependent upon our lender’s willingness to amend the terms or extend the maturity of our credit facility, the convertible note holders’ willingness to amend or restructure the convertible notes, or our success in generating additional sources of capital in the near future.

As of June 30, 2011, 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 June 30, 2011, 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 also largely dependent upon the number and timing of projects included in our capital development plan, most of which are discretionary. 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. Beyond the volumes for which we have entered into derivative contracts, we are unable to predict with any degree of certainty the prices we will receive for our future oil and gas production or the success of our exploration and development activities in generating additional production.

Cash Flows

During the six months ended June 30, 2011, we had an operating loss of $29.7 million, net cash provided by operating activities of $112,000, net cash provided by investing activities of $8.0 million, and net cash used by financing activities of $18.4 million. During this period we spent $36.7 million on oil and gas development activities. At June 30, 2011, we had $3.9 million in cash and $18.0 million available under our credit facility, total assets of $975.8 million and a debt to capitalization ratio of 36.2%. Debt, excluding installments payable on property acquisition which are secured by restricted cash deposits and the DHS credit facility which is non-recourse to Delta, at June 30, 2011 totaled $275.7 million, comprised of $15.0 million of bank debt, $149.7 million of senior subordinated notes and $111.0 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.

Results of Operations

The following discussion and analysis relates to items that have affected our results of operations for the three and six months ended June 30, 2011 and 2010. 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, 2011 Compared to Three Months Ended June 30, 2010

Net Loss Attributable to Delta Common Stockholders. Net loss attributable to Delta common stockholders was $1.0 million, or $0.03 per diluted common share, for the three months ended June 30, 2011, compared to a net loss attributable to Delta common stockholders of $149.8 million, or a loss of $5.43 per diluted common share, for the three months ended June 30, 2010. There were a number of items affecting comparability between periods including dry hole costs and impairments, operating expenses, and discontinued operations, among others. 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, 2011, oil and gas sales increased 14% to $16.9 million, as compared to $14.8 million for the comparable period a year earlier. The increase was principally the result of an 8% increase in the natural gas price and a 49% increase in the oil price. The average natural gas price received during the three months ended June 30, 2011 increased to $5.31 per Mcf compared to $4.92 per Mcf for the year earlier period. The average oil price received during the three months ended June 30, 2011 increased to $86.87 per Bbl compared to $58.29 per Bbl for the prior year period.

32

Production and Cost Information

Production volumes, average prices received and cost per equivalent Mcf for the three months ended June 30, 2011 and 2010 are as follows:


	Three Months Ended
	June 30,
	2011			2010
Production — Continuing Operations:
Oil (Mbbl)		38			41
Gas (Mmcf)		2,550			2,528
Total Production (Mmcfe) — Continuing Operations		2,781			2,774

Average Price — Continuing Operations:
Oil (per barrel)	$	86.87		$	58.29
Gas (per Mcf)	$	5.31		$	4.92

Costs (per Mcfe) — Continuing Operations:
Lease operating expense	$	1.28		$	2.19
Transportation expense	$	1.30		$	1.57
Production taxes	$	0.22		$	0.28
Depletion expense	$	3.54		$	4.03

Realized derivative losses (per Mcfe)	$	(1.80	)	$	(0.22	)

Lease Operating Expense. Lease operating expenses for the three months ended June 30, 2011 decreased to $3.6 million from $6.1 million in the prior year period primarily due to lower water handling costs in the Vega Area as a result of the resumption of development activities and improved water handling facilities. As a result, lease operating expenses per Mcfe in the Vega Area declined from $2.18 per Mcfe for the three months ended June 30, 2010 to $0.87 per Mcfe for the three months ended June 30, 2011. Overall, lease operating expense per Mcfe from continuing operations for the three months ended June 30, 2011 decreased to $1.28 per Mcfe from $2.19 per Mcfe.

Transportation Expense. Transportation expense for the three months ended June 30, 2011 decreased to $3.6 million from $4.4 million in the prior year. Transportation expense per Mcfe for the three months ended June 30, 2011 decreased 17% to $1.30 per Mcfe from $1.57 per Mcfe. The decrease on a per unit basis is primarily the result of true up adjustments in the prior year.

Production Taxes. Production taxes for the three months ended June 30, 2011 were $611,000, as compared to prior year costs of $786,000. Production taxes as a percentage of oil and gas sales were 3.6% and 5.3% for the three months ended June 30, 2011 and 2010, respectively.

Dry Hole Costs and Impairments. We incurred dry hole and impairment costs of $273,000 for the three months ended June 30, 2011 compared to $29.9 million for the comparable period a year ago. During the three months ended June 30, 2010, dry hole and impairment costs primarily related to unproved property impairments of $24.6 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.

Depreciation, Depletion, Amortization and Accretion. Depreciation, depletion and amortization expense decreased 13% to $10.5 million for the three months ended June 30, 2011, as compared to $12.1 million for the comparable year earlier period. Depletion expense for the three months ended June 30, 2011 decreased to $9.8 million from $11.2 million for the three months ended June 30, 2010 primarily due to higher reserves as a result of our recent drilling and completion activity in the Vega Area. Accordingly, our depletion rate decreased from $4.03 per Mcfe for the three months ended June 30, 2010 to $3.54 per Mcfe for the current year period.

General and Administrative Expense. General and administrative expense decreased 39% to $6.5 million for the three months ended June 30, 2011, as compared to $10.6 million for the comparable prior year period. The decrease in general and administrative expenses is attributed to a decrease in non-cash stock compensation expense, lower corporate consulting fees and to reduced staffing as a result of attrition and a reduction in force since the second quarter of 2010 resulting in lower cash compensation expense.

33

Interest Expense and Financing Costs, Net. Interest expense and financing costs, net increased 3% to $8.0 million for the three months ended June 30, 2011, as compared to $7.8 million for the comparable year earlier period. The increase is primarily related to a decrease in interest income between comparable periods.

Realized Loss on Derivative Instruments, Net. During the three months ended June 30, 2011, we recognized a $5.0 million loss associated with settlements on derivative contracts. Included in this loss was $3.3 million paid to settle a portion of our oil derivative contracts outstanding from July 2011 to December 2013 as a requirement to the amended MBL Credit Agreement completed in conjunction with the 2011 Wapiti Transaction. During the three months ended June 30, 2010, we recognized a $601,000 loss associated with settlements on derivative contracts.

Unrealized Gain 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 $8.3 million of unrealized gains on derivative instruments in other income and expense during the three months ended June 30, 2011 compared to $3.7 million of unrealized gains for the comparable prior year period.

Income Tax Expense (Benefit). 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 three months ended June 30, 2011 and 2010 of ($3.9 million) and $203,000, respectively, relates primarily to DHS, as no benefit was provided for our net operating losses. Included in the three months ended June 30, 2011 was a current tax benefit related to a tax refund received as a result of a tax law change that allowed us to carry-back operating losses to a period in which we previously paid tax.

For the three months ended June 30, 2011, we recorded a tax benefit of $3.9 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, we recorded a tax benefit on our loss from continuing operations, which was exactly offset by income tax expense on discontinued operations.

Discontinued Operations. During the third quarter of 2010, we closed the 2010 Wapiti Transaction to sell all or a portion of our 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, we closed the 2011 Wapiti Transaction, selling the remaining portion of our interests in non-core assets 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 separate transactions, we sold our interest in the Howard Ranch field and the Laurel Ridge field and have included these properties as discontinued operations as well.

During the three months ended March 31, 2011, 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.

34

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⁽¹⁾		—			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⁽²⁾		—			—			—			93,064			—			93,064
Drilling and trucking operating expenses⁽³⁾		—			9,406			9,406			—			8,123			8,123
Depreciation and amortization — drilling and trucking⁽⁴⁾		—			—			—			—			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 benefit⁽⁵⁾		(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⁽⁶⁾		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	)


⁽¹⁾		Contract Drilling and Trucking Fees. Contract drilling and trucking fees for the three months ended June 30, 2011 increased to $12.1 million compared to $11.1 million in the prior year. The increase is the result of improved third party rig utilization in the three months ended June 30, 2011 resulting from an increased industry demand attributable to improved commodity prices.

⁽²⁾		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.

⁽³⁾		Drilling and Trucking Operations. Drilling expense increased to $9.4 million for the three months ended June 30, 2011 compared to $8.1 million for the comparable prior year period. This increase is due to improved third party rig utilization during the current year period.

⁽⁴⁾		Depreciation and Amortization — Drilling and Trucking. Depreciation and amortization expense — drilling decreased to zero for the three months ended June 30, 2011 as compared to $5.2 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.

⁽⁵⁾		Income tax benefit. For the three months ended June 30, 2011, we recorded a tax benefit of $3.9 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, we recorded a tax benefit on our loss from continuing operations, which was exactly offset by income tax expense on discontinued operations.

⁽⁶⁾		Gain on sales of discontinued operations — oil and gas. On June 28, 2011, we closed on a transaction with Wapiti Oil & Gas to sell our 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, we recognized a $5.6 million gain on sale ($8.9 million gain, net of $3.3 million of tax) for the three 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.

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Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010

Net Loss Attributable to Delta Common Stockholders. Net loss attributable to Delta common stockholders was $28.8 million, or $1.03 per diluted common share, for the six months ended June 30, 2011, compared to a net loss attributable to Delta common stockholders of $162.5 million, or $5.90 per diluted common share, for the six months ended June 30, 2010. There were a number of items affecting comparability between periods including dry hole costs and impairments, operating expenses, unrealized gains and losses on derivative instruments, and discontinued operations. 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, 2011, oil and gas sales were consistent between periods at $34.6 million, as compared to $34.5 million for the comparable period a year earlier. The slight increase in oil and gas sales was the result of a 38% increase in oil prices, offset by a 3% decrease in gas prices, and a 1% decrease in production. The average natural gas price received during the six months ended June 30, 2011 decreased to $5.31 per Mcf compared to $5.49 per Mcf for the year earlier period. The average oil price received during the six months ended June 30, 2011 increased to $82.31 per Bbl compared to $59.60 per Bbl for the year earlier period.

Production and Cost Information

Production volumes, average prices received and cost per equivalent Mcf for the six months ended June 30, 2011 and 2010 are as follows:


	Six Months Ended
	June 30,
	2011			2010
Production — Continuing Operations:
Oil (Mbbl)		77			85
Gas (Mmcf)		5,323			5,352
Total Production (Mmcfe) — Continuing Operations		5,784			5,864

Average Price — Continuing Operations:
Oil (per barrel)	$	82.31		$	59.60
Gas (per Mcf)	$	5.31		$	5.49

Costs (per Mcfe) — Continuing Operations:
Lease operating expense	$	1.20		$	1.80
Transportation expense	$	1.31		$	1.30
Production taxes	$	0.25		$	0.29
Depletion expense	$	3.67		$	3.81

Realized derivative losses (per Mcfe)	$	(0.94	)	$	(0.80	)

Lease Operating Expense. Lease operating expenses for the six months ended June 30, 2011 decreased 34% to $7.0 million as compared to $10.5 million in the year earlier period. The decrease is primarily due to lower water handling costs in the Vega Area as a result of the resumption of development activities and improved water handling facilities. As a result, lease operating expense per Mcfe in the Vega Area declined from $1.74 per Mcfe for the six months ended June 30, 2010 to $0.88 per Mcfe for the six months ended June 30, 2011. Overall, lease operating expense per Mcfe from continuing operations for the six months ended June 30, 2011 decreased to $1.20 per Mcfe from $1.80 per Mcfe for the comparable year earlier period.

Transportation Expense. Transportation expense for the six months ended June 30, 2011 and 2010 was $7.6 million. Transportation expense per Mcfe for the six months ended June 30, 2011 increased slightly to $1.31 per Mcfe from $1.30 per Mcfe.

Production Taxes. Production taxes for the six months ended June 30, 2011 were $1.5 million, or 14% lower than prior year costs of $1.7 million. Production taxes as a percentage of oil and gas sales were 4.2% and 4.9% for the six months ended June 30, 2011 and 2010, respectively. The decrease in the 2011 percentage was primarily due to a decrease in the effective Colorado severance tax rate.

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Dry Hole Costs and Impairments. We incurred dry hole and impairment costs of $416,000 for the six months ended June 30, 2011 compared to $30.2 million for the comparable period a year ago. During the six months ended June 30, 2010, dry hole and impairment costs primarily related to 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.

Depreciation, Depletion, Amortization and Accretion. Depreciation, depletion and amortization expense decreased 6% to $22.5 million for the six months ended June 30, 2011, as compared to $23.9 million for the comparable year earlier period. Depletion expense for the six months ended June 30, 2011 was $21.2 million compared to $22.3 million for the six months ended June 30, 2010. Our depletion rate decreased from $3.81 per Mcfe for the six months ended June 30, 2010 to $3.67 per Mcfe for the current year period primarily due to higher reserves as a result of our recent drilling and completion activity in the Vega Area.

General and Administrative Expense. General and administrative expense decreased 37% to $13.1 million for the six months ended June 30, 2011, as compared to $20.9 million for the comparable prior year period. The decrease in general and administrative expenses is attributed to a decrease in non-cash stock compensation expense, lower corporate consulting fees and to reduced staffing as a result of attrition and a reduction in force during 2010 resulting in lower cash compensation expense.

Interest Expense and Financing Costs, Net. Interest and financing costs, net decreased 10% to $14.8 million for the six months ended June 30, 2011, as compared to $16.5 million for the comparable year earlier period. The decrease is primarily related to lower average outstanding Delta and DHS credit facility balances during the first half of 2011 as compared to the first half of 2010.

Realized Loss on Derivative Instruments, Net. During the six months ended June 30, 2011, we recognized a $5.5 million loss associated with settlements on derivative contracts compared to a $4.7 million loss for the comparable prior year period. Included in the June 30, 2011 loss was $3.3 million paid to settle a portion of our oil derivative contracts outstanding from July 2011 to December 2013 as a requirement to the amended MBL Credit Agreement completed in conjunction with the 2011 Wapiti Transaction.

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 $2.6 million of unrealized losses on derivative instruments in other income and expense during the six months ended June 30, 2011 compared to a gain of $20.9 million for the comparable prior year period.

Income Tax Expense (Benefit). 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, 2011 and 2010 of $(4.6 million) and $478,000, respectively, relates primarily to DHS, as no benefit was provided for our net operating losses. Included in the six months ended June 30, 2011 was a current tax benefit related to a tax refund received as a result of a tax law change that allowed us to carry-back operating losses to a period in which we previously paid tax.

For the six months ended June 30, 2011, we 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, we 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.

Discontinued Operations. During the third quarter of 2010, we closed the 2010 Wapiti Transaction to sell all or a portion of our 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, we closed the 2011 Wapiti Transaction, selling the remaining portion of our interests in non-core assets 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 separate transactions, we sold our interest in the Howard Ranch field and the Laurel Ridge field and have included these properties as discontinued operations as well.

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During the three months ended March 31, 2011, 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.

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⁽¹⁾		—			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⁽²⁾		—			—			—			93,064			—			93,064
Drilling and trucking operating expenses⁽³⁾		—			22,507			22,507			—			16,012			16,012
Depreciation and amortization — drilling and trucking⁽⁴⁾		—			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 benefit⁽⁵⁾		(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⁽⁶⁾		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⁾		Contract Drilling and Trucking Fees. Contract drilling and trucking fees for the six months ended June 30, 2011 increased to $26.4 million compared to $21.0 million in the prior year. The increase is the result of improved third party rig utilization in the six months ended June 30, 2011 resulting from an increased industry demand attributable to improved commodity prices.

⁽²⁾		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.

⁽³⁾		Drilling and Trucking Operations. Drilling expense increased to $22.5 million for the six months ended June 30, 2011 compared to $16.0 million for the comparable prior year period. This increase is due to improved third party rig utilization during the current year period.

⁽⁴⁾		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.

⁽⁵⁾		Income tax benefit. For the six months ended June 30, 2011, we 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, we 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.

⁽⁶⁾		Gain on sales of discontinued operations — oil and gas. On June 28, 2011, we 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, we 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.

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Historical Cash Flow

Our cash provided by (used in) operating activities increased to $112,000 provided by operating activities for the six months ended June 30, 2011 from cash used in operating activities of $23.3 million for the six months ended June 30, 2010. The significant increase in operating cash flow is primarily the result of changes in working capital. Our net cash provided by investing activities increased to $8.0 million for the six months ended June 30, 2011 compared to net cash used in investing activities of $12.1 million for the comparable prior year period primarily due to a significant increase in proceeds received from the sale of oil and gas properties partially offset by an increase in drilling and completion cost. Cash used in financing activities increased to $18.4 million for the six months ended June 30, 2011 from cash used in financing activities of $15.5 million for the six months ended June 30, 2010. During the six months ended June 30, 2011, we made net bank debt payments of $17.4 million. During the six months ended June 30, 2010, we made net bank debt payments of $14.2 million.

Capital and Exploration Expenditures

Our capital and exploration expenditures for the six months ended June 30, 2011 and 2010 were as follows (in thousands):


	2011			2010
CAPITAL AND EXPLORATION EXPENDITURES:

Property acquisitions:
Unproved	$	24		$	285
Proved		—			—
Oil and gas properties		31,266			18,917
Drilling and trucking equipment		821			995
Pipeline and gathering systems		(39	)		5,764

Total ⁽¹⁾	$	32,072		$	25,961


⁽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.

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 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 convertible notes can first require us to purchase all or a portion of the convertible notes. The convertible 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 convertible notes have 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 convertible notes will mature on May 1, 2037 unless earlier converted, redeemed or repurchased. The holders of the convertible notes have the right to require us to purchase all or a portion of the convertible notes on May 1, 2012, May 1, 2017, May 1, 2022, May 1, 2027, and May 1, 2032. The convertible notes will be convertible at the holder’s option, in whole or in part, at an initial conversion rate of 3.296 shares of common stock per $1,000 principal amount of convertible notes (equivalent to a conversion price of approximately $303.40 per share) at any time prior to the close of business on the business day immediately preceding the final maturity date of the convertible notes, subject to prior repurchase of the convertible notes. The conversion rate may be adjusted from

39

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 convertible 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 convertible notes in connection with such fundamental changes by a number of additional shares of common stock. Although the convertible notes do not contain any financial covenants, the convertible 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 convertible 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

The MBL Credit Agreement, as amended, provides for a revolving loan and a term loan, each with a maturity date of January 31, 2012, as described above. The MBL 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 (excluding DHS) 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 bank on most of our oil and gas properties, certain related equipment, and oil and gas inventory.

Credit Facility — DHS

DHS did not pay its scheduled principal and interest payments due on January 1, 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.

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 expenditures 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 $1.2 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 $5.6 million at June 30, 2011. 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.

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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 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.

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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 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 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 our plans for future development and other activities impacting the life of the property and our ability to recover our investment. When we believe the costs of the unproved property are no longer recoverable, an impairment charge is recorded based on the estimated fair value of the property. For the six months ended June 30, 2011 and 2010, no significant impairments were recorded.

During the remainder of 2011, 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, natural gas, and natural gas liquids 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. The fair value of our oil derivative instruments was a liability of $2.4 million, the fair value of our gas derivative instruments was an asset of $1.6 million, and the fair value of our natural gas liquids derivative instruments was a liability of $4.8 million at June 30, 2011. 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, 2011. The pre-credit risk adjusted fair value of our 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 caused the reported amount of the net derivative liabilities on our consolidated balance sheet to be $5.6 million.

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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.

Deferred Tax Asset Valuation Allowance

We use 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.


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, 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.

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Assuming production and the percent of oil and gas sold remained unchanged for the six months ended June 30, 2011, a hypothetical 10% decline in the average market price we realized during the six months ended June 30, 2011 on unhedged production would reduce our oil and natural gas revenues by approximately $4.4 million.

Interest Rate Risk

We were subject to interest rate risk on $15.0 million of variable rate debt obligations at June 30, 2011. The annual effect of a 10% change in interest rates on the debt would be approximately $190,000.


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, 2011, to ensure that information required to be disclosed by us in the reports filed or submitted by us under the Exchange Act (i) is recorded, processed, summarized and reported within the time period specified in SEC rules and forms, and (ii) is accumulated and communicated to our management, including our principal executive officer and our principal financial officer, as appropriate to allow appropriate decisions on a timely basis regarding required disclosure.

Internal Control over Financial Reporting

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

PART II — OTHER INFORMATION


Item 1.		Legal Proceedings

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, except as follows:

Our indirect, 49.8% owned affiliate DHS and certain of its employees, among others, have been notified by the Office of the Inspector General, Office of Investigations, of the Export-Import Bank of the United States, and the U.S. Department of Justice, that DHS and certain of its and the Company’s employees are the subject of an investigation in connection with a loan guarantee sought from the Export-Import Bank in the first quarter of 2010 of a loan from a Mexican bank sought by a DHS customer in Mexico. DHS has cooperated and will continue to cooperate with the investigation. This investigation is subject to uncertainties, and, as such, DHS is unable to estimate the nature of any possible liability that may result.

We formerly owned a 2.41934% working interest in OCS Lease 320 in the Sword Unit, offshore California, and Amber Resources Company (“Amber”) formerly owned a 0.97953% working interest in the same lease. Lease 320 was conveyed back to the United States at the conclusion of the previous litigation with the government (Amber Resources Co., et al. vs. United States, Civ. Act. No. 2-30 filed in the United States Court of Federal Claims) when the courts determined that the government had breached that lease (among others) and was liable to the working interest owners for damages; however, the government now contends that the former working interest owners are still obligated to permanently plug and abandon an exploratory well that was drilled on the lease and to clear the well site. The former operator of the lease commenced litigation against the government in United States District Court for the District of Columbia (Noble Energy Corp. vs. Kenneth L. Salazar, Secretary United States Department of the Interior, et al No. 1:09-cv-02013-EGS) seeking a declaratory judgment that the former working interest owners are not responsible for these costs as a result of the government’s breach of the lease. On April 22, 2011, the Court entered a judgment in favor of the government, ruling that the

44

working interest owners jointly and severally share the responsibility to permanently plug and abandon the subject well, and that this duty was not discharged by the government’s breach of contract. On May 11, 2011, the former operator filed an appeal of this ruling to the United States of Appeals for the District of Columbia Circuit. It is currently unknown whether or not the appeal will be successful, or what the actual costs of decommissioning the well would be if the former working interest owners are ultimately held liable. If the working interest owners are held liable, we and Amber would be responsible for the payment of our respective proportionate shares of the cost.

Company and may also have the effect of delaying, preventing or expediting, as the case may be, a change in control of our Company. Tracinda also has the right to sell its Delta stock if it chooses to do so. In the event that Tracinda sells all or a substantial portion of its Delta shares, it is possible that the market price of our stock could be adversely affected.

DHS has significant near-term liquidity issues. There is a significant risk that DHS will continue to not be able to meet its debt covenants under its credit facility.

As of June 30, 2011, DHS had only nine of its 18 rigs in operation and it expects to continue to incur liquidity pressures during 2011 based on its current cash flows and level of indebtedness. DHS is now highly leveraged relative to its cash flow and its senior lender, Lehman Commercial Paper, Inc., (“LCPI”), has filed for bankruptcy protection. DHS is in the process of attempting to procure amended financing terms from LCPI or alternative financing from other sources with more favorable debt terms, but there can be no assurance that its efforts will be successful. At June 30, 2011, DHS owed $71.9 million under its credit facility ($69.9 million principal and $2.0 million accrued interest) and was not in compliance with its financial covenants. DHS has not paid its scheduled principal and interest payments in 2011, and has entered into a series of forbearance agreements with LCPI, the most recent of which expires on August 8, 2011. In the event that DHS is not successful in obtaining alternative financing or making satisfactory arrangements with the LCPI bankruptcy trustee, it is likely that DHS will continue to be in default of its debt covenants under its credit facility unless and until market conditions improve significantly. In such event and upon expiration of the current forbearance agreement, all of the amounts due under the credit facility would become immediately due and payable if LCPI exercised its rights under the terms of the credit facility. All of the DHS rigs are pledged as collateral for the credit facility, and would be subject to foreclosure in the event of a default under the credit facility. The DHS credit facility is non-recourse to Delta. At June 30, 2011, Delta had a net credit investment of approximately $3.7 million in DHS. Subsequent to year-end, the Board of Directors of DHS engaged transaction advisors to commence a strategic alternatives process, focused on a sale of the company or substantially all of its assets. There can be no assurance that the terms offered by a potential buyer, if any, will be acceptable to the DHS shareholders. 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 DHS credit facility.


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, 2011 (shares and price adjusted to reflect the July 13, 2011 1-for-10 reverse stock split).


							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, 2011		679	$	8.36		—		—
May 1 — May 31, 2011		—		—		—		—
June 1 — June 30, 2011		—		—		—		—

Total		679	$	8.36		—		—


(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:


	3.1			Certificate of Incorporation, as amended. Incorporated by reference to Exhibit 3.1 to our Form 8-K filed July 13, 2011.

	10.1			Purchase and Sale Agreement, dated June 15, 2011, among Delta Petroleum Corporation and Wapiti Oil & Gas, L.L.C. Incorporated by reference to Exhibit 10.1 to our Form 8-K filed June 20, 2011.

	10.2			Forbearance Agreement dated as of June 28, 2011 among DHS Holding Company, DHS Drilling Company and Lehman Commercial Paper, Inc. Filed herewith electronically.

	10.3			Second Amendment to Third Amended and Restated Credit Agreement, dated June 28, 2011, between Delta Petroleum Corporation and Macquarie Bank Limited, as administrative agent. Incorporated by reference to Exhibit 10.1 to our Form 8-K filed June 29, 2011.

	10.4			Forbearance Agreement dated as of August 3, 2011 among DHS Holding Company, DHS Drilling Company and Lehman Commercial Paper, Inc. 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 4, 2011

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EXHIBIT INDEX:


	3.1			Certificate of Incorporation, as amended. Incorporated by reference to Exhibit 3.1 to our Form 8-K filed July 13, 2011.

	10.1			Purchase and Sale Agreement, dated June 15, 2011, among Delta Petroleum Corporation and Wapiti Oil & Gas, L.L.C. Incorporated by reference to Exhibit 10.1 to our Form 8-K filed June 20, 2011.

	10.2			Forbearance Agreement dated as of June 28, 2011 among DHS Holding Company, DHS Drilling Company and Lehman Commercial Paper, Inc. Filed herewith electronically.

	10.3			Second Amendment to Third Amended and Restated Credit Agreement, dated June 28, 2011, between Delta Petroleum Corporation and Macquarie Bank Limited, as administrative agent. Incorporated by reference to Exhibit 10.1 to our Form 8-K filed June 29, 2011.

	10.4			Forbearance Agreement dated as of August 3, 2011 among DHS Holding Company, DHS Drilling Company and Lehman Commercial Paper, Inc. 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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