Par Pacific (PARR) 10-Q 2011 Q1 Quarterly report

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 March 31, 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. Yesþ Noo

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). Yeso Noo

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 filero	Accelerated filerþ	Non-accelerated filero	Smaller reporting companyo
		(Do not check if a smaller reporting company)

Indicate by a check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act): Yeso Noþ

286,027,476 shares of common stock, $.01 par value per share, were outstanding as of May 5, 2011.

INDEX

	Page No.
PART I FINANCIAL INFORMATION
Item 1. Consolidated Financial Statements
Consolidated Balance Sheets — March 31, 2011 and December 31, 2010 (unaudited)		1
Consolidated Statements of Operations — Three Months Ended March 31, 2011 and 2010 (unaudited)		2
Consolidated Statement of Changes in Equity — Three Months Ended March 31, 2011 (unaudited)		3
Consolidated Statements of Cash Flows — Three Months Ended March 31, 2011 and 2010 (unaudited)		4
Notes to Consolidated Financial Statements (unaudited)		5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		23
Item 3. Quantitative and Qualitative Disclosures About Market Risk		35
Item 4. Controls and Procedures		36
PART II OTHER INFORMATION
Item 1. Legal Proceedings		36
Item 1A. Risk Factors		37
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		38
Item 5. Other Information		38
Item 6. Exhibits		39

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)

	March 31,			December 31,
	2011			2010
	(In thousands, except share data)
ASSETS
Current assets:
Cash and cash equivalents	$	5,539		$	14,190
Short-term restricted deposits		100,000			100,000
Trade accounts receivable, net of allowance for doubtful accounts of $100 and $100, respectively		9,084			7,373
Assets held for sale — DHS subsidiary		69,300			74,093
Deposits and prepaid assets		1,617			1,720
Inventories		3,109			3,446
Other current assets		4,496			4,821
Total current assets		193,145			205,643
Property and equipment:
Oil and gas properties, successful efforts method of accounting:
Unproved		230,117			230,117
Proved		878,234			871,986
Pipeline and gathering systems		93,613			93,558
Other		13,766			14,452
Total property and equipment		1,215,730			1,210,113
Less accumulated depreciation and depletion		(406,342	)		(400,384	)
Net property and equipment		809,388			809,729
Long-term assets:
Investments in unconsolidated affiliates		3,460			3,377
Deferred financing costs		1,554			1,832
Other long-term assets		3,252			3,531
Total long-term assets		8,266			8,740
Total assets	$	1,010,799		$	1,024,112
LIABILITIES AND EQUITY
Current liabilities:
Credit facility — Delta	$	32,632		$	—
Installment payable on property acquisition		98,507			97,874
Accounts payable		23,853			27,615
Liabilities related to assets held for sale — DHS subsidiary		81,765			81,633
Other accrued liabilities		12,847			11,066
Derivative instruments		6,666			574
Total current liabilities		256,270			218,762
Long-term liabilities:
7% Senior notes		149,703			149,684
33/4% Senior convertible notes		109,756			108,593
Credit facility — Delta		—			29,130
Asset retirement obligations		4,034			3,929
Derivative instruments		7,280			2,419
Total long-term liabilities		270,773			293,755
Commitments and contingencies
Equity:
Preferred stock, $.01 par value: authorized 3,000,000 shares, none issued		—			—
Common stock, $.01 par value: authorized 600,000,000 shares, issued 286,126,000 shares at March 31, 2011 and 285,138,000 shares at December 31, 2010		2,861			2,851
Additional paid-in capital		1,635,390			1,633,217
Treasury stock at cost; 30,000 shares at March 31, 2011 and 33,000 shares at December 31, 2010		(55	)		(279	)
Accumulated deficit		(1,149,183	)		(1,121,342	)
Total Delta stockholders’ equity		489,013			514,447
Non-controlling interest		(5,257	)		(2,852	)
Total equity		483,756			511,595
Total liabilities and equity	$	1,010,799		$	1,024,112

See accompanying notes to consolidated financial statements.

1

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended
	March 31,
	2011			2010
	(In thousands, except per share amounts)
Revenue:
Oil and gas sales	$	23,056		$	29,599
Loss on property sales		—			(429	)
Total revenue		23,056			29,170
Operating expenses:
Lease operating expense		4,605			6,941
Transportation expense		3,952			3,353
Production taxes		932			1,410
Exploration expense		43			226
Dry hole costs and impairments		143			354
Depreciation, depletion, amortization and accretion		13,461			15,288
General and administrative expense		6,629			10,250
Total operating expenses		29,765			37,822
Operating loss		(6,709	)		(8,652	)
Other income and (expense):
Interest expense and financing costs, net		(6,806	)		(8,702	)
Other income (expense)		(69	)		69
Realized loss on derivative instruments, net		(440	)		(4,113	)
Unrealized gain (loss) on derivative instruments, net		(10,953	)		17,272
Income (loss) from unconsolidated affiliates		83			(8	)
Total other income and (expense)		(18,185	)		4,518
Loss from continuing operations before income taxes and discontinued operations		(24,894	)		(4,134	)
Income tax expense		239			275
Loss from continuing operations		(25,133	)		(4,409	)
Discontinued operations:
Loss from results of operations and sale of discontinued operations, net of tax		(5,132	)		(11,583	)
Net loss		(30,265	)		(15,992	)
Less net loss attributable to non-controlling interest included in discontinued operations		2,424			3,195
Net loss attributable to Delta common stockholders	$	(27,841	)	$	(12,797	)
Amounts attributable to Delta common stockholders:
Loss from continuing operations	$	(25,133	)	$	(4,409	)
Loss from discontinued operations, net of tax		(2,708	)		(8,388	)
Net loss	$	(27,841	)	$	(12,797	)
Basic loss attributable to Delta common stockholders per common share:
Loss from continuing operations	$	(0.09	)	$	(0.02	)
Discontinued operations		(0.01	)		(0.03	)
Net loss	$	(0.10	)	$	(0.05	)
Diluted loss attributable to Delta common stockholders per common share:
Loss from continuing operations	$	(0.09	)	$	(0.02	)
Discontinued operations		(0.01	)		(0.03	)
Net loss	$	(0.10	)	$	(0.05	)

See accompanying notes to consolidated financial statements.

2

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(Unaudited)

					Additional									Accu-			Total Delta			Non-
	Common stock				paid-in			Treasury stock						mulated			stockholders’			controlling			Total
	Shares		Amount		capital			Shares			Amount			deficit			equity			interest			equity
	(In thousands)
Balance, December 31, 2010		285,138	$	2,851	$	1,633,217			33		$	(279	)	$	(1,121,342	)	$	514,447		$	(2,852	)	$	511,595
Net loss		—		—		—			—			—			(27,841	)		(27,841	)		(2,424	)		(30,265	)
Employee vesting of treasury stock held by subsidiary		—		—		(135	)		(3	)		224			—			89			(29	)		60
Issuance of vested stock		988		10		(10	)		—			—			—			—			—			—
Shares repurchased for withholding taxes		—		—		(1	)		—			—			—			(1	)		—			(1	)
Stock based compensation		—		—		2,319			—			—			—			2,319			48			2,367
Balance, March 31, 2011		286,126	$	2,861	$	1,635,390			30		$	(55	)	$	(1,149,183	)	$	489,013		$	(5,257	)	$	483,756

See accompanying notes to consolidated financial statements.

3

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended
	March 31,
	2011			2010
	(In thousands)
Cash flows from operating activities:
Net loss	$	(30,265	)	$	(15,992	)
Adjustments to reconcile net loss to cash provided by (used in) operating activities:
Depreciation, depletion, amortization — oil and gas		13,461			15,288
Depreciation, depletion, amortization — discontinued operations		2,669			13,470
(Gain) loss on sale of drilling assets — discontinued operations		500			(62	)
Dry hole costs and impairments		143			354
Stock based compensation		2,367			3,389
Amortization of deferred financing costs, bond discount, and installments payable discount		2,699			3,800
Unrealized (gain) loss on derivative contracts		10,953			(17,272	)
(Income) loss from unconsolidated affiliates		(83	)		8
Deferred income tax expense		239			275
Other		(248	)		422
Net changes in operating assets and liabilities:
(Increase) in trade accounts receivable		(1,711	)		(237	)
(Increase) decrease in deposits and prepaid assets		103			(76	)
(Increase) in inventories		(64	)		—
(Increase) in other current assets		—			16
Increase (decrease) in accounts payable		925			(9,183	)
(Decrease) in offshore litigation payable		—			(13,877	)
Increase (decrease) in other accrued liabilities		2,128			1,927
Increase (decrease) in assets held for sale working capital, net		1,794			809
Net cash provided by (used in) operating activities		5,610			(16,941	)
Cash flows from investing activities:
Additions to property and equipment		(17,305	)		(9,349	)
Additions to drilling and trucking equipment		(158	)		(703	)
Proceeds from sale of oil and gas properties		—			766
Proceeds from sale of drilling assets		38			130
Proceeds from sale of other fixed assets		61			37
Proceeds from sale of unconsolidated affiliates		559			3,500
Proceeds from escrow deposit		—			1,380
Decrease in other long-term assets		7			244
Net cash used in investing activities		(16,798	)		(3,995	)
Cash flows from financing activities:
Proceeds from borrowings		30,202			24,000
Repayments of borrowings		(26,700	)		(55,000	)
Payment of deferred financing costs		(964	)		—
Stock repurchased for withholding taxes		(1	)		(2	)
Net cash provided by (used in) financing activities		2,537			(31,002	)
Net decrease in cash and cash equivalents		(8,651	)		(51,938	)
Cash at beginning of period		14,190			61,918
Cash at end of period	$	5,539		$	9,980
Supplemental cash flow information:
Cash paid for interest and financing costs	$	1,410		$	2,893
DHS interest payable capitalized to principal balance (non-cash financing transaction)	$	1,616		$	—

See accompanying notes to consolidated financial statements.

4

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES

Notes to Consolidated Financial Statements
Three Months Ended March 31, 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 July 30, 2010, the Company closed on a definitive Purchase and Sale Agreement with Wapiti Oil & Gas, L.L.C. (“Wapiti”) to sell all or a portion of its interests in various non-core assets primarily located in Colorado, Texas and Wyoming (the “Wapiti Transaction”) for cash proceeds of $130.0 million.

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 7, “Long-Term Debt.” The MBL Credit Agreement provides for a revolving loan and a term loan, each with a maturity date of January 31, 2012. The revolving loan has an initial borrowing base of $30.0 million. On March 14, 2011, the Company entered into an amendment to the MBL Credit Agreement that increased the availability under the term loan at the time from $6.2 million to $25.0 million, and does not require repayment of the term loan until the January 2012 maturity date. Specifically, among other changes, the amendment provided for an increase in the term loan commitment from $20.0 million to $25.0 million and 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. The Company was in compliance with its financial covenants under the MBL Credit Agreement as of March 31, 2011.

Proceeds from the Wapiti Transaction and 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. Despite these improvements to the financial position of the Company, during the first quarter of 2011, the Company experienced a net loss attributable to Delta common stockholders of $27.8 million, and at March 31, 2011 had a working capital deficiency, excluding discontinued operations, of $50.7 million, including $32.6 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.

5

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2011 and 2010
(Unaudited)

(2) Going Concern, Continued

The DHS Drilling Company (“DHS”) credit facility debt of $71.2 million at March 31, 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 that currently expires on May 13, 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 an extension to the forbearance agreement that expires on May 13, 2011. 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. Subsequent to year-end, 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.

While the Wapiti Transaction and the MBL Credit Agreement significantly improved the Company’s financial position, the Company does not have the capital on hand necessary 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.

The Company believes that the amounts available under the Company’s credit facility, as recently amended, combined with projected net cash from operating activities, will provide sufficient liquidity to fund its operating expenses, the limited Vega Area capital development planned, and maintain current debt service obligations. To the extent cash flows from operating activities are not sufficient to support future capital expenditures beyond those currently planned, and in order to address the January 2012 maturity of the Company’s credit facility and the potential mandatory redemption in May 2012 of the $115.0 million senior convertible notes, the Company will need to seek 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. The timing, structure, terms, size, and pricing of any such financing or transaction 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.

(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 Wapiti Transaction, 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.

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.

6

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2011 and 2010
(Unaudited)

(3) Summary of Significant Accounting Policies, Continued

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 months ended March 31, 2011 have been reclassified from continuing operations to discontinued operations for all periods presented. 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. 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.

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 months ended March 31, 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.

7

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2011 and 2010
(Unaudited)

(3) Summary of Significant Accounting Policies, Continued

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 months ended March 31, 2011 and 2010, no significant impairments were recorded.

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

	Three Months Ended
	March 31, 2011
Balance at beginning of year	$	6,200
Additions to capitalized exploratory well costs pending the determination of proved reserves		5,817
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	$	12,017
Exploratory well costs capitalized for one year or less after after completion of drilling		12,017
Exploratory well costs capitalized for greater than one year after completion of drilling		—
Balance at end of period	$	12,017

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. A second deep test well was spud during the three months ended March 31, 2011. Completion activities on the second well began during April 2011.

     Asset Retirement Obligations

The Company’s asset retirement obligations arise from the plugging and abandonment liabilities for its oil and gas wells. The Company has no obligation to provide for the retirement of most of its offshore properties as the obligations remained with the seller from whom the Company acquired the properties. The following is a reconciliation of the Company’s asset retirement obligations from January 1, 2011 to March 31, 2011 (in thousands):

Asset retirement obligation — January 1, 2011	$	5,146
Accretion expense		75
Change in estimate		(82	)
Obligations incurred (from new wells)		31
Obligations on sold properties		(118	)
Asset retirement obligation — March 31, 2011		5,052
Less: Current portion of asset retirement obligation		(1,018	)
Long-term asset retirement obligation	$	4,034

8

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2011 and 2010
(Unaudited)

(3) Summary of Significant Accounting Policies, Continued

     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 March 31, 2011 comprehensive loss attributable to Delta common stockholders was $27.8 million and for the three months ended March 31, 2010 comprehensive loss attributable to Delta common stockholders was $12.8 million.

     Use of Estimates

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

(4) Discontinued Operations

During the third quarter of 2010, the Company closed the Wapiti Transaction, selling all or a portion of its interest in various non-core assets primarily located in Colorado, Texas, and Wyoming for gross proceeds of $130.0 million. In accordance with accounting standards, the results of operations and impairment losses relating to certain of the Wapiti Transaction properties have been reflected as discontinued operations for all periods presented. Properties associated with the Wapiti Transaction in which the Company only sold half of its interest continue to be reported as a component of continuing operations. The fields classified as discontinued operations are fields in which the Company sold all of its interest including the Garden Gulch field, Baffin Bay field, and Bull Canyon field as well as the Company’s interest in its wholly-owned subsidiary Piper Petroleum. 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 as 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.

9

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 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 March 31, 2011 and 2010 (in thousands):

	Three Months Ended								Three Months Ended
	March 31, 2011								March 31, 2010
	Oil & Gas		Drilling			Total			Oil & Gas			Drilling			Total
Revenues:
Oil and gas sales	$	—	$	—		$	—		$	4,854		$	—		$	4,854
Contract drilling and trucking fees		—		14,263			14,263			—			9,932			9,932
Total Revenues		—		14,263			14,263			4,854			9,932			14,786
Operating Expenses:
Lease operating expense		—		—			—			1,230			—			1,230
Transportation expense		—		—			—			574			—			574
Production taxes		—		—			—			271			—			271
Depreciation, depletion, amortization and accretion — oil and gas		—		—			—			7,898			—			7,898
Drilling and trucking operating expenses		—		13,101			13,101			—			7,889			7,889
Depreciation and amortization — drilling and trucking(1)		—		2,669			2,669			—			5,572			5,572
General and administrative expense		—		1,033			1,033			—			1,137			1,137
Total operating expenses		—		16,803			16,803			9,973			14,598			24,571
Other income and (expense):
Interest expense and financing costs, net		—		(2,041	)		(2,041	)		—			(1,860	)		(1,860	)
Other income (expense)		—		(551	)		(551	)		—			62			62
Total other income and (expense)		—		(2,592	)		(2,592	)		—			(1,798	)		(1,798	)
Loss from discontinued operations		—		(5,132	)		(5,132	)		(5,119	)		(6,464	)		(11,583	)
Income tax expense		—		—			—			—			—			—
Loss from results of operations of discontinued operations, net of tax		—		(5,132	)		(5,132	)		(5,119	)		(6,464	)		(11,583	)
Gain on sales of discontinued operations		—		—			—			—			—			—
Loss from results of operations and sale of discontinued operations, net of tax	$	—	$	(5,132	)	$	(5,132	)	$	(5,119	)	$	(6,464	)	$	(11,583	)

⁽¹⁾ Depreciation and Amortization — Drilling and Trucking. Depreciation and amortization expense — drilling decreased to $2.7 million for the three months ended March 31, 2011 as compared to $5.6 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) 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 months ended March 31, 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.

10

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2011 and 2010
(Unaudited)

(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 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 March 31, 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 March 31, 2011 (See Note 13, “Guarantor Financial Information”). The fair value of the Company’s senior unsecured notes at March 31, 2011 was approximately $118.1 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 March 31, 2011 and 2010, respectively. Combined with the amortization of debt discount, the convertible notes had an effective interest rate of approximately 7.8% and 7.6% with total interest costs of $2.2 million for each of the three months ended March 31, 2011 and 2010, respectively. The fair value of the convertible notes at March 31, 2011 was approximately $94.2 million.

     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. The revolving loan has an initial borrowing base of $30.0 million and bears interest at prime plus 6% per annum for prime rate advances and LIBOR plus 7% per annum for LIBOR advances. The borrowing base for the revolving loan is subject to a semi-annual re-determination based on reserve reports as of each January 1 and July 1 as reported by the Company to MBL on or before each April 1 and October 1, respectively. At March 31, 2011, $7.6 million was outstanding under the revolving loan. On March 14, 2011, the Company entered into an amendment to the MBL Credit Agreement that increased the availability under the term loan at the time from $6.2 million to $25.0 million and 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. As a result of the amendment, amounts outstanding under the term loan bear 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. At March 31, 2011, $25.0 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.

11

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2011 and 2010
(Unaudited)

(6) Long Term Debt, Continued

In addition, the Company may not permit its trade payables to be outstanding more than 90 days following the receipt of applicable invoices. At March 31, 2011, the Company was in compliance with its financial covenants under the MBL Credit Agreement.

     Credit Facility — DHS

DHS did not pay its scheduled principal and interest payments due on January 3 and April 1, 2011 and as a result, entered into a forbearance agreement that currently expires on May 13, 2011. In conjunction with the forbearance agreement, the missed interest payments were capitalized to the principal balance of the loan on January 3 and April 1, 2011, respectively, 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 three months ended March 31, 2011. The DHS credit facility debt of $71.2 million at March 31, 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.

(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 three months ended March 31, 2011 and 2010, and are considered to be Level 3 fair value measurements.

12

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2011 and 2010
(Unaudited)

(7) Fair Value Measurements, Continued

The following table lists the Company’s fair value measurements by hierarchy as of March 31, 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 — March 31, 2011	$	—	$	(13,946	)	$	—	$	(13,946	)
Derivative liabilities — December 31, 2010		—		(2,993	)		—		(2,993	)

(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.

At March 31, 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 March 31, 2011:

								Net Fair Value
						Remaining		Asset (Liability) at
Commodity	Volume			Fixed Price		Term	Index Price	March 31, 2011
								(In thousands)
Crude oil		500	Bbls / Day	$	57.70	Apr ’11 - Dec ’11	NYMEX - WTI	$	(6,529	)
Crude oil		96	Bbls / Day	$	91.05	Apr ’11 - Dec ’11	NYMEX - WTI		(412	)
Crude oil		497	Bbls / Day	$	91.05	Jan ’12 - Dec ’12	NYMEX - WTI		(2,438	)
Crude oil		396	Bbls / Day	$	91.05	Jan ’13 - Dec ’13	NYMEX - WTI		(1,386	)
Natural gas		12,000	MMBtu / Day	$	5.150	Apr ’11 - Dec ’11	CIG		3,119
Natural gas		3,253	MMBtu / Day	$	5.040	Apr ’11 - Dec ’11	CIG		748
Natural gas		38	MMBtu / Day	$	4.440	Apr ’11 - Dec ’11	CIG		4
Natural gas		12,052	MMBtu / Day	$	4.440	Jan ’12 - Dec ’12	CIG		(844	)
Natural gas		10,301	MMBtu / Day	$	4.440	Jan ’13 - Dec ’13	CIG		(1,638	)
Natural gas liquids(1)		36,597	Gallons / Day	$	0.913	Apr ’11 - Dec ’11	MT. BELVIEU		(1,901	)
Natural gas liquids(1)		30,617	Gallons / Day	$	0.832	Jan ’12 - Dec ’12	MT. BELVIEU		(1,922	)
Natural gas liquids(1)		12,286	Gallons / Day	$	0.767	Jan ’13 - Dec ’13	MT. BELVIEU		(747	)
								$	(13,946	)

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

13

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2011 and 2010
(Unaudited)

(8) Commodity Derivative Instruments, Continued

The pre-credit risk adjusted fair value of the Company’s net derivative liabilities as of March 31, 2011 was $16.3 million. A credit risk adjustment of $2.4 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 $13.9 million.

The Company classifies the fair value amounts of derivative assets and liabilities executed under master netting arrangements as net derivative assets or net derivative liabilities, whichever the case may be, by commodity and master netting counterparty. The following table summarizes the fair values and location in the Company’s consolidated balance sheet of all derivatives held by the Company as of March 31, 2011 and December 31, 2010 (in thousands):

Derivatives Not Designated as		March 31, 2011			Dec. 31, 2010
Hedging Instruments	Balance Sheet Classification	Fair Value			Fair Value
Liabilities
Commodity Swaps	Derivative Instruments — Current Liabilities, net	$	(6,666	)	$	(574	)
Commodity Swaps	Derivative Instruments — Long-Term Liabilities, net		(7,280	)		(2,419	)
Total		$	(13,946	)	$	(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 three months ended March 31, 2011 and 2010 (in thousands):

		March 31, 2011			March 31, 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)	$	(440	)	$	(4,113	)
Commodity Swaps	Unrealized Gain (Loss) on Derivative Instruments, net — Other Income and (Expense)		(10,953	)		17,272
		$	(11,393	)	$	13,159

(9) Commitments and Contingencies

The $115.0 million in principal amount of 3³/4% Senior Convertible Notes due 2037 will mature on May 1, 2037 unless earlier converted, redeemed or repurchased. The holders of the Notes have the right to require the Company to purchase all or a portion of the Notes on May 1, 2012, May 1, 2017, May 1, 2022, May 1, 2027, and May 1, 2032 at a price which is required to be paid in cash, equal to 100% of the principal amount of the Notes to be repurchased.

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 alNo. 1:09-cv-02013-EGS) seeking a declaratory judgment that the former working

14

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2011 and 2010
(Unaudited)

(9) Commitments and Contingencies, Continued

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. The former operator has stated that it intends to appeal this ruling. 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.

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 set for arbitration on January 24, 2011, but was ultimately 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.

(10) Stockholders’ Equity

     Preferred Stock

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

     Common Stock

During the three months ended March 31, 2011 and 2010, the Company issued 988,000 and 480,778 fully vested shares to the non-employee members of the Board of Directors in consideration for their service on the Board for the years ended December 31, 2010 and 2009, respectively.

15

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2011 and 2010
(Unaudited)

(10) Stockholders’ Equity, Continued

     Stock Based Compensation

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

	Three Months Ended
	March 31,
	2011		2010
Non-vested stock(1)	$	2,264	$	3,031
Performance shares		103		358
Total	$	2,367	$	3,389

⁽¹⁾ Non-vested stock includes $48,000 and $181,000 for the three months ended March 31, 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 March 31, 2011 ranged from $0.79 to $15.34 per share. At March 31, 2011, there was no unrecognized compensation cost related to stock options as all outstanding options are vested. At March 31, 2011, the Company had 1,503,000 options outstanding at a weighted average exercise price of $7.50 per share. At March 31, 2011, the Company had 7,255,000 non-vested shares outstanding and 80,000 performance shares outstanding. At March 31, 2011, the total unrecognized compensation cost related to the performance shares and the non-vested portion of restricted stock was $4.6 million which is expected to be recognized over a weighted average period of 0.6 years.

(11) Income Taxes

Income tax expense (benefit) attributable to loss from continuing operations was approximately $239,000 and $275,000 for the three months ended March 31, 2011 and 2010, respectively.

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future results of operations, and tax planning strategies in making this assessment. Based upon the level of historical taxable income, significant book losses during the current and prior periods, and projections for future results of operations over the periods in which the deferred tax assets are deductible, among other factors, management continues to conclude that the Company does not meet the “more likely than not” requirement of 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 March 31, 2011.

During the three months ended March 31, 2011 and 2010, DHS recorded net operating losses and as of March 31, 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.

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 months ended March 31, 2011 and 2010, no adjustments were recognized for uncertain tax benefits.

16

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 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
	March 31,
	2011			2010
Net loss attributable to Delta common stockholders	$	(27,841	)	$	(12,797	)
Basic weighted-average common shares outstanding		278,772			275,691
Add: dilutive effects of stock options and unvested stock grants		—			—
Diluted weighted-average common shares outstanding		278,772			275,691
Net loss per common share attributable to Delta common stockholders
Basic	$	(0.10	)	$	(0.05	)
Diluted	$	(0.10	)	$	(0.05	)

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

	Three Months Ended
	March 31,
	2011		2010
Stock issuable upon conversion of convertible notes		3,790		3,790
Stock options		1,503		1,428
Performance share grants(1)		80		150
Non-vested restricted stock		7,255		6,801
Total potentially dilutive securities		12,628		12,169

⁽¹⁾ Subsequent to March 31, 2011, the two remaining holders of the performance shares returned to the Company for no additional consideration the 80,000 unvested performance shares.

17

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 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 March 31, 2011 and December 31, 2010, the condensed consolidated statements of operations for the three months ended March 31, 2011 and 2010 and the condensed consolidated statements of cash flows for the three months ended March 31, 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
March 31, 2011

				Guarantor			Non-Guarantor		Adjustments/
	Issuer			Entities			Entities		Eliminations			Consolidated
Current assets	$	122,571		$	322		$	71,095	$	(843	)	$	193,145
Property and equipment:
Oil and gas properties		1,089,437			—			19,215		(301	)		1,108,351
Other		74,647			32,732			—		—			107,379
Total property and equipment		1,164,084			32,732			19,215		(301	)		1,215,730
Accumulated depletion and depreciation		(377,525	)		(28,817	)		—		—			(406,342	)
Net property and equipment		786,559			3,915			19,215		(301	)		809,388
Investment in subsidiaries		(1,689	)		—			—		1,689			—
Other long-term assets		5,859			2,407			—		—			8,266
Total assets	$	913,300		$	6,644		$	90,310	$	545		$	1,010,799
Current liabilities	$	174,531		$	(26	)	$	82,608	$	(843	)	$	256,270
Long-term liabilities:
Long-term debt, derivative instruments and deferred taxes		264,938			1,801			—		—			266,739
Asset retirement obligations		4,034			—			—		—			4,034
Total long-term liabilities		268,972			1,801			—		—			270,773
Total Delta stockholders’ equity		475,054			4,869			7,702		1,388			489,013
Non-controlling interest		(5,257	)		—			—		—			(5,257	)
Total equity		469,797			4,869			7,702		1,388			483,756
Total liabilities and equity	$	913,300		$	6,644		$	90,310	$	545		$	1,010,799

18

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March, 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	$	130,252		$	322		$	75,069	$	—		$	205,643
Property and equipment:
Oil and gas properties		1,083,005			—			19,215		(117	)		1,102,103
Other		75,333			32,677			—		—			108,010
Total property and equipment		1,158,338			32,677			19,215		(117	)		1,210,113
Accumulated depletion, depreciation and amortization		(371,622	)		(28,762	)		—		—			(400,384	)
Net property and equipment		786,716			3,915			19,215		(117	)		809,729
Investment in subsidiaries		1,157			—			—		(1,157	)		—
Other long-term assets		6,333			2,407			—		—			8,740
Total assets	$	924,458		$	6,644		$	94,284	$	(1,274	)	$	1,024,112
Current liabilities	$	137,155		$	(26	)	$	81,633	$	—		$	218,762
Long-term liabilities
Long-term debt, derivative instruments and deferred taxes		288,025			1,801			—		—			289,826
Asset retirement obligation and other liabilities		3,929			—			—		—			3,929
Total long-term liabilities		291,954			1,801			—		—			293,755
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

19

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

(13) Guarantor Financial Information, Continued

Condensed Consolidated Statement of Operations
Three Months Ended March 31, 2011

				Guarantor			Non-Guarantor			Adjustments/
	Issuer			Entities			Entities			Eliminations			Consolidated
Total revenue	$	23,056		$	—		$	—		$	—		$	23,056
Operating expenses:
Oil and gas expenses		9,489			—			—			—			9,489
Exploration expense		43			—			—			—			43
Dry hole costs and impairments		88			55			—			—			143
Depreciation and depletion		13,461			—			—			—			13,461
General and administrative		6,604			—			25			—			6,629
Total operating expenses		29,685			55			25			—			29,765
Operating loss		(6,629	)		(55	)		(25	)		—			(6,709	)
Other income and (expense)		(18,186	)		—			1			—			(18,185	)
Income tax expense		(239	)		—			—			—			(239	)
Discontinued operations		—			—			(4,831	)		(301	)		(5,132	)
Net loss		(25,054	)		(55	)		(4,855	)		(301	)		(30,265	)
Less income (loss) attributable to non-controlling interest		—			—			2,424			—			2,424
Net loss attributable to Delta common stockholders	$	(25,054	)	$	(55	)	$	(2,431	)	$	(301	)	$	(27,841	)

Condensed Consolidated Statement of Operations
Three Months Ended March 31, 2010

				Guarantor			Non-Guarantor			Adjustments/
	Issuer			Entities			Entities			Eliminations			Consolidated
Total revenue	$	29,170		$	—		$	—		$	—		$	29,170
Operating expenses:
Oil and gas expenses		11,704			—			—			—			11,704
Exploration expense		226			—			—			—			226
Dry hole costs and impairments		354			—			—			—			354
Depreciation and depletion		15,288			—			—			—			15,288
General and administrative		10,193			15			42			—			10,250
Total operating expenses		37,765			15			42			—			37,822
Operating loss		(8,595	)		(15	)		(42	)		—			(8,652	)
Other income and (expenses)		4,524			(8	)		2			—			4,518
Income tax benefit (expense)		(275	)		—			—			—			(275	)
Discontinued operations		(5,119	)		—			(6,370	)		(94	)		(11,583	)
Net loss		(9,465	)		(23	)		(6,410	)		(94	)		(15,992	)
Less loss attributable to non-controlling interest		—			—			3,195			—			3,195
Net loss attributable to Delta common stockholders	$	(9,465	)	$	(23	)	$	(3,215	)	$	(94	)	$	(12,797	)

20

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

(13) Guarantor Financial Information, Continued

Condensed Consolidated Statement of Cash Flows
Three Months Ended March 31, 2011

				Guarantor			Non-Guarantor
	Issuer			Entities			Entities			Consolidated
Cash provided by (used in):
Operating activities	$	5,568		$	(55	)	$	97		$	5,610
Investing activities		(16,733	)		55			(120	)		(16,798	)
Financing activities		2,537			—			—			2,537
Net decrease in cash and cash equivalents		(8,628	)		—			(23	)		(8,651	)
Cash at beginning of the period		13,154			61			975			14,190
Cash at the end of the period	$	4,526		$	61		$	952		$	5,539

Condensed Consolidated Statement of Cash Flows
Three Months Ended March 31, 2010

				Guarantor			Non-Guarantor
	Issuer			Entities			Entities			Consolidated
Cash provided by (used in):
Operating activities	$	(17,661	)	$	(20	)	$	740		$	(16,941	)
Investing activities		(3,816	)		8			(187	)		(3,995	)
Financing activities		(31,002	)		—			—			(31,002	)
Net increase (decrease) in cash and cash equivalents		(52,479	)		(12	)		553			(51,938	)
Cash at beginning of the period		58,533			74			3,311			61,918
Cash at the end of the period	$	6,054		$	62		$	3,864		$	9,980

21

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March, 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 months ended March 31, 2011 and 2010:

						Inter-segment
	Oil and Gas			Drilling		Eliminations			Consolidated
				(In thousands)
Three Months Ended March 31, 2011
Revenues from external customers	$	23,056		$	—	$	—		$	23,056
Inter-segment revenues		—			—		—			—
Total revenues	$	23,056		$	—	$	—		$	23,056
Operating loss	$	(6,709	)	$	—	$	—		$	(6,709	)
Other income (expense)(1)		(18,185	)		—		—			(18,185	)
Loss from continuing operations, before tax	$	(24,894	)	$	—	$	—		$	(24,894	)
Three Months Ended March 31, 2010
Revenues from external customers	$	29,170		$	—	$	—		$	29,170
Inter-segment revenues		—			—		—			—
Total revenues	$	29,170		$	—	$	—		$	29,170
Operating loss	$	(8,652	)	$	—	$	—		$	(8,652	)
Other income (expense)(1)		4,518			—		—			4,518
Loss from continuing operations, before tax	$	(4,134	)	$	—	$	—		$	(4,134	)
March 31, 2011
Total Assets	$	1,007,928		$	69,300	$	(66,429	)	$	1,010,799
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.

(15) Subsequent Events

DHS did not pay its scheduled principal and interest payment due on April 1, 2011. In conjunction with the forbearance agreement that currently expires on May 13, 2011, the missed interest payment was capitalized to the principal balance of the loan on April 1, 2011.

In May 2011, the Company retained Macquarie Tristone to provide advisory services relating to the potential sale of certain of the Company’s non-operated assets located in the Texas Gulf Coast and DJ Basin regions. The Company intends to use the net proceeds from any such sale to reduce indebtedness and for additional drilling activities in the Vega Area.

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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; our expectation that we will have adequate cash from operations, credit facility borrowings and other capital sources to satisfy our obligations under our senior credit facility, in respect of the convertible notes, and to meet future debt service, capital expenditure and working capital requirements; the availability of capital to fund our working capital needs, our drilling and leasehold acquisition programs, our required payments under our senior credit facility, or any required redemption of our convertible notes; 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 activity and drilling program timing, expectations, processes and emphasis; intended use of proceeds from potential sale of Texas Gulf Coast and DJ Basin assets; 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:

• 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;

• a continued imbalance in the demand for and supply of natural gas in the U.S. as a result of uncertain general economic conditions and expanded drilling activity;

23

• the results of exploratory drilling activities;

• the outcome of the ongoing 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.

24

Recent Developments

• On March 14, 2011, we entered into an amendment to the Third Amended and Restated Credit Agreement (the “MBL Credit Agreement”) with Macquarie Bank Limited (“MBL”) as administrative agent and issuing lender, dated December 29, 2010, that increased the availability under the term loan at the time from $6.2 million to $25.0 million, and extended the term loan repayment obligation to the January 2012 maturity date. Specifically, among other changes, the amendment provided for an increase in the term loan commitment from $20.0 million to $25.0 million and removed the requirement that advances under the term loan be subject to approval of a development plan. In addition, so long as we are not in default under the MBL Credit Agreement, we are 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. As a result of the amendment, amounts outstanding under the term loan bear 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.

• 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 3 and April 1, 2011 and as a result, entered into a forbearance agreement that currently expires on May 13, 2011. In conjunction with the forbearance agreement, the missed interest payments were capitalized to the principal balance of the loan on January 3 and April 1, 2011, respectively, and the loan now bears interest at the default rate of 11% per annum.

• 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. We intend to use the net proceeds from any such sale to reduce indebtedness and for our planned capital development activities in the Vega Area.

2011 Overview

During the first quarter 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 a second test well to continue to evaluate resource potential below the Williams Fork formation in the Vega Area. Subsequent to quarter end, we successfully completed the second test well and brought the well on line on April 29, 2011. In addition, the first exploratory test well is scheduled to begin fracturing operations in mid-May. A third exploratory test well to evaluate potential below the Williams Fork is scheduled to be 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 June 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 wells 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.

Liquidity and Capital Resources

Our sources of liquidity and capital resources historically have been net cash 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. In the past, these sources of liquidity and capital have been sufficient to meet our needs. In 2010, to address our liquidity needs, we sold certain non-core assets to Wapiti Oil & Gas, LLC for $130.0 million (the “Wapiti Transaction”). The March 2011 amendment to the MBL Credit Agreement increased the availability under the term loan at the time from $6.2 million to $25.0 million and, so long as we are not in default, eliminated the requirement to repay any term loan advances outstanding on a monthly basis with 100% of net operating cash flows.

25

We believe that the amounts available under our credit facility as recently 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. 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 completion activities on the Vega Area exploratory test wells that are currently underway. In addition, we have recently 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. It is likely that a sale of such assets will reduce the borrowing base under our revolving credit facility, but after giving effect to any such reduction, we intend to use the net proceeds from any such sale for additional drilling activities in the Vega Area targeting the deeper shale formations.

To the extent cash flow from operating activities is not sufficient 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. 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. On March 14, 2011, we entered into an amendment to the MBL Credit Agreement as described above under “Recent Developments.” The MBL Credit Agreement provides for a revolving loan and a term loan, each with a maturity date of January 31, 2012. The revolving loan has an initial borrowing base of $30.0 million with $7.6 million outstanding and $22.4 million available as of March 31, 2011. At March 31, 2011, $25.0 million was outstanding under the term loan. We were in compliance with our financial covenants under our credit facility at March 31, 2011.

DHS Credit Facility

At March 31, 2011, DHS remained out of compliance with the debt covenants under its credit facility and is currently subject to a forbearance agreement with LCPI which expires on May 13, 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 March 31, 2011 as a component of liabilities related to assets held for sale. Accordingly, DHS is facing significant requirements to fund obligations 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.

Capital Resources and Requirements

Our accompanying financial statements have been prepared assuming we will continue as a going concern. During the year ended December 31, 2010 and with the amendment to our MBL Credit Agreement in March 2011, significant improvements to our liquidity position were achieved. 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.

26

As of March 31, 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 March 31, 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 three months ended March 31, 2011, we had an operating loss of $6.7 million, net cash provided by operating activities of $5.6 million, net cash used in investing activities of $16.8 million, and net cash provided by financing activities of $2.5 million. During this period we spent $17.3 million on oil and gas development activities. At March 31, 2011, we had $5.5 million in cash and $22.4 million available under our credit facility, total assets of $1.0 billion and a debt to capitalization ratio of 37.6%. 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 March 31, 2011 totaled $292.1 million, comprised of $32.6 million of bank debt, $149.7 million of senior subordinated notes and $109.8 million of senior convertible notes. In accordance with applicable accounting rules, the senior convertible notes are recorded at a discount to their stated amount due of $115.0 million.

Results of Operations

The following discussion and analysis relates to items that have affected our results of operations for the three months ended March 31, 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 March 31, 2011 Compared to Three Months Ended March 31, 2010

Net Income (Loss) Attributable to Delta Common Stockholders.Net loss attributable to Delta common stockholders was $27.8 million, or $0.10 per diluted common share, for the three months ended March 31, 2011, compared to a net loss attributable to Delta common stockholders of $12.8 million, or $0.05 per diluted common share, for the three months ended March 31, 2010. There were a number of items affecting comparability between periods including unrealized gains and losses on derivative instruments and operating expenses. Explanations of significant items affecting comparability between periods are discussed by financial statement caption below.

Oil and Gas Sales.During the three months ended March 31, 2011, oil and gas sales decreased 22% to $23.1 million, as compared to $29.6 million for the comparable period a year earlier. The decrease was principally the result of a 16% production decrease primarily related to lower volumes as a result of the Wapiti Transaction. The average natural gas price received during the three months ended March 31, 2011 decreased to $5.26 per Mcf compared to $5.85 per Mcf for the year earlier period. The average oil price received during the three months ended March 31, 2011 increased to $86.26 per Bbl compared to $71.26 per Bbl for the prior year period.

27

Production and Cost Information

Production volumes, average prices received and cost per equivalent Mcf for the three months ended March 31, 2011 and 2010 are as follows:

	Three Months Ended
	March 31,
	2011			2010
Production — Continuing Operations:
Oil (Mbbl)		87			148
Gas (Mmcf)		2,952			3,262
Total Production (Mmcfe) — Continuing Operations		3,475			4,147
Average Price — Continuing Operations:
Oil (per barrel)	$	86.26		$	71.26
Gas (per Mcf)	$	5.26		$	5.85
Costs (per Mcfe) — Continuing Operations:
Lease operating expense	$	1.33		$	1.67
Transportation expense	$	1.14		$	0.81
Production taxes	$	0.27		$	0.34
Depletion expense	$	3.70		$	3.53
Realized derivative losses (per Mcfe)	$	(0.13	)	$	(0.99	)

Lease Operating Expense.Lease operating expenses for the three months ended March 31, 2011 decreased to $4.6 million from $6.9 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 due to the Wapiti Transaction. Lease operating expense per Mcfe for the three months ended March 31, 2011 decreased to $1.33 per Mcfe from $1.67 per Mcfe.

Transportation Expense.Transportation expense for the three months ended March 31, 2011 increased to $4.0 million from $3.4 million in the prior year. Transportation expense per Mcfe for the three months ended March 31, 2011 increased 41% to $1.14 per Mcfe from $0.81 per Mcfe. The increase on a per unit basis is primarily the result of a change in production mix related to the divestiture of assets in the third quarter of 2010 and changes to our Vega gas marketing contract.

Production Taxes.Production taxes for the three months ended March 31, 2011 were $932,000, as compared to prior year costs of $1.4 million. Production taxes as a percentage of oil and gas sales were 4.0% and 4.8% for the three months ended March 31, 2011 and 2010, respectively.

Depreciation, Depletion, Amortization and Accretion.Depreciation, depletion and amortization expense decreased 12% to $13.5 million for the three months ended March 31, 2011, as compared to $15.3 million for the comparable year earlier period. Depletion expense for the three months ended March 31, 2011 decreased to $12.9 million from $14.6 million for the three months ended March 31, 2010 due to lower production volumes as a result of the Wapiti Transaction. Our depletion rate increased from $3.53 per Mcfe for the three months ended March 31, 2010 to $3.70 per Mcfe for the current year period primarily due to a decrease in reserves primarily attributable to the Wapiti Transaction.

General and Administrative Expense.General and administrative expense decreased 36% to $6.6 million for the three months ended March 31, 2011, as compared to $10.3 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 and to reduced staffing as a result of attrition and a reduction in force since the first quarter of 2010 resulting in lower cash compensation expense.

Interest Expense and Financing Costs, Net.Interest expense and financing costs, net decreased 22% to $6.8 million for the three months ended March 31, 2011, as compared to $8.7 million for the comparable year earlier period. The decrease is primarily related to lower average outstanding Delta credit facility balances.

Realized Loss on Derivative Instruments, Net.During the three months ended March 31, 2011, we recognized a $440,000 loss associated with settlements on derivative contracts. During the three months ended March 31, 2010, we recognized a $4.1 million loss associated with settlements on derivative contracts.

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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 $11.0 million of unrealized losses on derivative instruments in other income and expense during the three months ended March 31, 2011 compared to $17.3 million of unrealized gains for the comparable prior year period.

Income Tax Benefit (Expense).Due to our continued losses, we were required by the “more likely than not” threshold for assessing the realizability of deferred tax assets to record a valuation allowance for our deferred tax assets beginning with the second quarter of 2007. Our income tax expense for the three months ended March 31, 2011 and 2010 of $239,000 and $275,000, respectively, relates only to DHS, as no benefit was provided for our net operating losses.

Discontinued Operations.During the third quarter of 2010, we closed the 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. In accordance with accounting standards, the results of operations and impairment loss relating to certain of the Wapiti Transaction properties have been reflected as discontinued operations for all periods presented. Properties associated with the Wapiti Transaction in which we only sold half of our interest continue to be reported as a component of continuing operations. The fields classified as discontinued operations are fields in which we sold all of our interest including the Garden Gulch field, Baffin Bay field, and Bull Canyon field as well as our interest in our wholly-owned subsidiary Piper Petroleum. 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 three months ended March 31, 2011 and 2010 (in thousands):

	Three Months Ended								Three Months Ended
	March 31, 2011								March 31, 2010
	Oil & Gas		Drilling			Total			Oil & Gas			Drilling			Total
Revenues:
Oil and gas sales	$	—	$	—		$	—		$	4,854		$	—		$	4,854
Contract drilling and trucking fees(1)		—		14,263			14,263			—			9,932			9,932
Total Revenues		—		14,263			14,263			4,854			9,932			14,786
Operating Expenses:
Lease operating expense		—		—			—			1,230			—			1,230
Transportation expense		—		—			—			574			—			574
Production taxes		—		—			—			271			—			271
Depreciation, depletion, amortization and accretion — oil and gas		—		—			—			7,898			—			7,898
Drilling and trucking operating expenses(2)		—		13,101			13,101			—			7,889			7,889
Depreciation and amortization — drilling and trucking(3)		—		2,669			2,669			—			5,572			5,572
General and administrative expense		—		1,033			1,033			—			1,137			1,137
Total operating expenses		—		16,803			16,803			9,973			14,598			24,571
Other income and (expense):
Interest expense and financing costs, net		—		(2,041	)		(2,041	)		—			(1,860	)		(1,860	)
Other income (expense)		—		(551	)		(551	)		—			62			62
Total other income and (expense)		—		(2,592	)		(2,592	)		—			(1,798	)		(1,798	)
Loss from discontinued operations		—		(5,132	)		(5,132	)		(5,119	)		(6,464	)		(11,583	)
Income tax expense		—		—			—			—			—			—
Loss from results of operations of discontinued operations, net of tax		—		(5,132	)		(5,132	)		(5,119	)		(6,464	)		(11,583	)
Gain on sales of discontinued operations		—		—			—			—			—			—
Loss from results of operations and sale of discontinued operations, net of tax	$	—	$	(5,132	)	$	(5,132	)	$	(5,119	)	$	(6,464	)	$	(11,583	)

(1)	Contract Drilling and Trucking Fees. Contract drilling and trucking fees for the three months ended March 31, 2011 increased to $14.3 million compared to $9.9 million in the prior year. The increase is the result of improved third party rig utilization in the three months ended March 31, 2011 resulting from an increased industry demand attributable to improved commodity prices.
(2)	Drilling and Trucking Operations. Drilling expense increased to $13.1 million for the three months ended March 31, 2011 compared to $7.9 million for the comparable prior year period. This increase is due to improved third party rig utilization during the current year period.
(3)	Depreciation and Amortization — Drilling and Trucking. Depreciation and amortization expense — drilling decreased to $2.7 million for the three months ended March 31, 2011 as compared to $5.6 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.

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Historical Cash Flow

Our cash provided by (used in) operating activities increased from $16.9 million used in operating activities for the three months ended March 31, 2010 to cash provided by operating activities of $5.6 million for the three months ended March 31, 2011. The significant increase in operating cash flow is primarily the result of changes in working capital. Our net cash used in investing activities increased to $16.8 million for the three months ended March 31, 2011 compared to net cash used in investing activities of $4.0 million for the comparable prior year period primarily due to our significant increase in drilling and completion activity as well as a decrease in proceeds received from the sale of oil and gas properties and interests in unconsolidated affiliates. Cash provided by (used in) financing activities increased from $31.0 million used in financing activities for the three months ended March 31, 2010 to cash provided by financing activities of $2.5 million for the current year period. During the three months ended March 31, 2011, we received net bank borrowings of $3.5 million. During the three months ended March 31, 2010, we made net bank payments of $31.0 million.

Capital and Exploration Expenditures

Our capital and exploration expenditures for the three months ended March 31, 2011 and 2010 were as follows (in thousands):

	2011		2010
CAPITAL AND EXPLORATION EXPENDITURES:
Property acquisitions:
Unproved	$	66	$	1
Proved		—		—
Oil and gas properties		13,185		10,373
Drilling and trucking equipment		158		950
Pipeline and gathering systems		55		4,095
Total(1)	$	13,464	$	15,419

⁽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 7.8% and 7.6% with total interest costs of $2.2 million for each of the three month periods ended March 31, 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 32.9598 shares of common stock per $1,000 principal amount of convertible notes (equivalent to a conversion price of approximately $30.34 per share) at any time prior to the close of business on the business day immediately preceding the final maturity date of the convertible notes, subject to prior repurchase of the convertible notes. The conversion rate may be

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adjusted from time to time in certain instances. Upon conversion of a note, we will have the option to deliver shares of our common stock, cash or a combination of cash and shares of our common stock for the 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 3 and April 1, 2011 and as a result, entered into a forbearance agreement that currently expires on May 13, 2011. In conjunction with the Forbearance Agreement, the missed interest payments were capitalized to the principal balance of the loan on January 3 and April 1, 2011, respectively, 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 three months ended March 31, 2011. The DHS credit facility debt of $71.2 million at March 31, 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 $13.9 million at March 31, 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

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reasons, estimates of the economically recoverable quantities of gas and oil attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected therefrom may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of our gas and oil properties and/or the rate of depletion of the gas and oil properties. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material.

Impairment of Gas and Oil Properties

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

Given the complexities associated with gas and oil reserve estimates and the history of price volatility in the gas and oil markets, events may arise that would require us to record an impairment of the recorded book values associated with gas and oil properties. For 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 months ended March 31, 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 three months ended March 31, 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 $10.8 million, the fair value of our gas derivative instruments was an asset of $1.4 million, and the fair value of our natural gas liquids derivative instruments was a liability of $4.6 million at March 31, 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 March 31, 2011. The pre-credit risk adjusted fair value of our net derivative liabilities as of March 31, 2011 was $16.3 million. A credit risk adjustment of $2.4 million to the fair value of the derivatives caused the reported amount of the net derivative liabilities on our consolidated balance sheet to be $13.9 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 March 31, 2011:

								Net Fair Value
						Remaining		Asset (Liability) at
Commodity	Volume			Fixed Price		Term	Index Price	March 31, 2011
								(In thousands)
Crude oil		500	Bbls / Day	$	57.70	Apr ’11 - Dec ’11	NYMEX - WTI	$	(6,529	)
Crude oil		96	Bbls / Day	$	91.05	Apr ’11 - Dec ’11	NYMEX - WTI		(412	)
Crude oil		497	Bbls / Day	$	91.05	Jan ’12 - Dec ’12	NYMEX - WTI		(2,438	)
Crude oil		396	Bbls / Day	$	91.05	Jan ’13 - Dec ’13	NYMEX - WTI		(1,386	)
Natural gas		12,000	MMBtu / Day	$	5.150	Apr ’11 - Dec ’11	CIG		3,119
Natural gas		3,253	MMBtu / Day	$	5.040	Apr ’11 - Dec ’11	CIG		748
Natural gas		38	MMBtu / Day	$	4.440	Apr ’11 - Dec ’11	CIG		4
Natural gas		12,052	MMBtu / Day	$	4.440	Jan ’12 - Dec ’12	CIG		(844	)
Natural gas		10,301	MMBtu / Day	$	4.440	Jan ’13 - Dec ’13	CIG		(1,638	)
Natural gas liquids(1)		36,597	Gallons / Day	$	0.913	Apr ’11 - Dec ’11	MT. BELVIEU		(1,901	)
Natural gas liquids(1)		30,617	Gallons / Day	$	0.832	Jan ’12 - Dec ’12	MT. BELVIEU		(1,922	)
Natural gas liquids(1)		12,286	Gallons / Day	$	0.767	Jan ’13 - Dec ’13	MT. BELVIEU		(747	)
								$	(13,946	)

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

Assuming production and the percent of oil and gas sold remained unchanged for the three months ended March 31, 2011, a hypothetical 10% decline in the average market price we realized during the three months ended March 31, 2011 on unhedged production would reduce our oil and natural gas revenues by approximately $2.3 million.

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Interest Rate Risk

We were subject to interest rate risk on $32.6 million of variable rate debt obligations at March 31, 2011. The annual effect of a 10% change in interest rates on the debt would be approximately $281,000.

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 March 31, 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:

During the first quarter of 2011, we were engaged in an arbitration with 212 Resources Corporation (“212”) that was filed with the American Arbitration Association on October 27, 2009. The matter was set for arbitration on January 24, 2011, but was ultimately settled pursuant to a final Settlement Agreement executed by the parties on January 25, 2011. In accordance with the Settlement Agreement, we paid $1.5 million to 212 in consideration of mutual releases of claims and the termination of the underlying agreement.

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 alNo. 1:09-cv-02013-EGS) seeking a

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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. The former operator has stated that it intends to appeal this ruling. 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.

Item 1A. Risk Factors

Our business has many risks. Factors that could materially adversely affect our business, financial condition, operating results or liquidity and the trading price of our common stock, senior notes or convertible notes are described below and under “Risk Factors” in Item 1A of our 2010 Annual Report on Form 10-K for the year ended December 31, 2010 filed with the SEC on March 16, 2011. This information should be considered carefully, together with other information in this report and other reports and materials we file with the SEC.

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 March 31, 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 March 31, 2011, DHS owed $73.1 million under its credit facility ($71.2 million principal and $1.9 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 the earlier of May 13, 2011 or the fifth business day following receipt by DHS of notice from a specified third party who has provided a written expression of interest that it will no longer pursue the acquisition of DHS and/or substantially all or a portion of its rig assets. 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 March 31, 2011, Delta had a net credit investment of approximately $5.3 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.

We are not currently in compliance with The NASDAQ Capital Market $1.00 minimum bid price requirement, and failure to regain and maintain compliance with this standard could result in delisting and adversely affect the market price and liquidity of our common stock.

Our common stock is currently traded on The NASDAQ Capital Market under the symbol “DPTR.” If we fail to meet any of the continued listing standards of The NASDAQ Capital Market, our common stock will be delisted from The NASDAQ Capital Market. These continued listing standards include specifically enumerated criteria, such as a $1.00 minimum closing bid price. On February 8, 2011, we received a letter from The NASDAQ Stock Market advising us that we did not meet the minimum $1.00 per share bid price requirement for continued inclusion on The NASDAQ Capital Market pursuant to NASDAQ Marketplace Listing Rule 5550(a)(2). The letter stated that we have until August 8, 2011 to regain compliance. To regain compliance with the applicable listing rule, the closing bid price of our common stock must meet or exceed $1.00 per share for a minimum of ten consecutive business days during the 180 day grace period. If this occurs, NASDAQ will provide us with written notification of compliance. If we do not regain compliance by August 8, 2011,

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NASDAQ will provide written notice that our common stock is subject to delisting. In that event, we would have the right to appeal such determination to a hearings panel. Although our Board of Directors is recommending to our stockholders that they authorize the implementation of a one share for ten shares reverse stock split at our Annual Meeting of Stockholders which is currently scheduled to occur on July 12, 2011, there can be no guarantee that the reverse stock split will be approved or that we will be able to regain compliance with the Listing Rule. Further, the February 8, 2011 deficiency notice relates exclusively to our bid price deficiency. We may be delisted during the applicable grace periods for failure to maintain compliance with any other listing requirement which may occur.

If our common stock were to be delisted from The NASDAQ Capital Market^®, trading of our common stock most likely will be conducted in the over-the-counter market on an electronic bulletin board established for unlisted securities such as the OTC Bulletin Board. Such trading will reduce the market liquidity of our common stock. As a result, an investor would find it more difficult to dispose of, or obtain accurate quotations for the price of, our common stock. If our common stock is delisted from The NASDAQ Capital Market^® and the trading price remains below $5.00 per share, trading in our common stock might also become subject to the requirements of certain rules promulgated under the Exchange Act which require additional disclosure by broker-dealers in connection with any trade involving a stock defined as a “penny stock” (generally, any equity security not listed on a national securities exchange or quoted on NASDAQ that has a market price of less than $5.00 per share, subject to certain exceptions). Many brokerage firms are reluctant to recommend low-priced stocks to their clients. Moreover, various regulations and policies restrict the ability of shareholders to borrow against or “margin” low-priced stocks, and declines in the stock price below certain levels may trigger unexpected margin calls. Additionally, because brokers’ commissions on low-priced stocks generally represent a higher percentage of the stock price than commissions on higher priced stocks, the current price of the common stock can result in an individual shareholder paying transaction costs that represent a higher percentage of total share value than would be the case if our share price were higher. This factor may also limit the willingness of institutions to purchase our common stock. Finally, the additional burdens imposed upon broker-dealers by these requirements could discourage broker-dealers from facilitating trades in our common stock, which could severely limit the market liquidity of the stock and the ability of investors to trade our common stock.

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 March 31, 2011.

							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)
January 1 – January 31, 2011		680	$	0.76		—		—
February 1 – February 28, 2011		—		—		—		—
March 1 – March 31, 2011		—		—		—		—
Total		680	$	0.76		—		—

(1)	Consists of shares delivered back to us by employees and/or directors to satisfy tax withholding obligations that arise upon the vesting of the stock awards. We, pursuant to our equity compensation plans, give participants the opportunity to turn back to us the number of shares from the award sufficient to satisfy the person’s tax withholding obligations that arise upon the termination of restrictions.
(2)	The stated price does not include any commission paid.
(3)	These sections are not applicable as we have no publicly announced stock repurchase plans.

Item 5. Other Information

None.

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Item 6. Exhibits.

     Exhibits are as follows:

10.3	Forbearance Agreement No. 2 dated as of February 1, 2011 among DHS Holding Company, DHS Drilling Company and Lehman Commercial Paper, Inc. under that certain Amended and Restated Credit Agreement dated as of August 15, 2008, as amended by that certain Amendment No. 1, dated as of September 19, 2008, and further amended by that certain Waiver and Amendment No. 2, dated as of April 1, 2010. Incorporated by reference to Exhibit 10.37 to our Form 10-K filed March 16, 2011.
10.4	Amended and Restated Forbearance Agreement No. 2 dated as of March 15, 2011 among DHS Holding Company, DHS Drilling Company and Lehman Commercial Paper, Inc. under that certain Amended and Restated Credit Agreement dated as of August 15, 2008, as amended by that certain Amendment No. 1, dated as of September 19, 2008, and further amended by that certain Waiver and Amendment No. 2, dated as of April 1, 2010. Incorporated by reference to Exhibit 10.38 to our Form 10-K filed March 16, 2011.
10.5	Second Amended and Restated Forbearance Agreement No. 2 dated as of March 25, 2011 among DHS Holding Company, DHS Drilling Company and Lehman Commercial Paper, Inc. under that certain Amended and Restated Credit Agreement dated as of August 15, 2008, as amended by that certain Amendment No. 1, dated as of September 19, 2008, and further amended by that certain Waiver and Amendment No. 2, dated as of April 1, 2010. Filed herewith electronically.
10.4	Third Amended and Restated Forbearance Agreement No. 2 dated as of April 12, 2011 among DHS Holding Company, DHS Drilling Company and Lehman Commercial Paper, Inc. under that certain Amended and Restated Credit Agreement dated as of August 15, 2008, as amended by that certain Amendment No. 1, dated as of September 19, 2008, and further amended by that certain Waiver and Amendment No. 2, dated as of April 1, 2010. Filed herewith electronically.
10.5	Forbearance Agreement dated as of April 15, 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: May 10, 2011

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EXHIBIT INDEX:

10.1	Forbearance Agreement No. 2 dated as of February 1, 2011 among DHS Holding Company, DHS Drilling Company and Lehman Commercial Paper, Inc. under that certain Amended and Restated Credit Agreement dated as of August 15, 2008, as amended by that certain Amendment No. 1, dated as of September 19, 2008, and further amended by that certain Waiver and Amendment No. 2, dated as of April 1, 2010. Incorporated by reference to Exhibit 10.37 to our Form 10-K filed March 16, 2011.
10.2	Amended and Restated Forbearance Agreement No. 2 dated as of March 15, 2011 among DHS Holding Company, DHS Drilling Company and Lehman Commercial Paper, Inc. under that certain Amended and Restated Credit Agreement dated as of August 15, 2008, as amended by that certain Amendment No. 1, dated as of September 19, 2008, and further amended by that certain Waiver and Amendment No. 2, dated as of April 1, 2010. Incorporated by reference to Exhibit 10.38 to our Form 10-K filed March 16, 2011.
10.3	Second Amended and Restated Forbearance Agreement No. 2 dated as of March 25, 2011 among DHS Holding Company, DHS Drilling Company and Lehman Commercial Paper, Inc. under that certain Amended and Restated Credit Agreement dated as of August 15, 2008, as amended by that certain Amendment No. 1, dated as of September 19, 2008, and further amended by that certain Waiver and Amendment No. 2, dated as of April 1, 2010. Filed herewith electronically.
10.4	Third Amended and Restated Forbearance Agreement No. 2 dated as of April 12, 2011 among DHS Holding Company, DHS Drilling Company and Lehman Commercial Paper, Inc. under that certain Amended and Restated Credit Agreement dated as of August 15, 2008, as amended by that certain Amendment No. 1, dated as of September 19, 2008, and further amended by that certain Waiver and Amendment No. 2, dated as of April 1, 2010. Filed herewith electronically.
10.5	Forbearance Agreement dated as of April 15, 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.