PARR 10-Q Quarterly Report March 31, 2010

PAR PACIFIC HOLDINGS, INC.

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10-Q 1 d72815e10vq.htm FORM 10-Q e10vq

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended March 31, 2010


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

For the transition period from to

Commission file number 0-16203

DELTA PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)


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

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

(303) 293-9133

(Registrant’s telephone number, including area code)

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

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

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


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

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

282,783,589 shares of common stock, $.01 par value per share, were outstanding as of May 1, 2010.

INDEX


PART I		FINANCIAL INFORMATION
			Page No.
Item 1.	Consolidated Financial Statements

		Consolidated Balance Sheets – March 31, 2010 and December 31, 2009 (unaudited)		1

		Consolidated Statements of Operations – Three Months Ended March 31, 2010 and 2009 (unaudited)		2

		Consolidated Statement of Changes in Equity – Three Months Ended March 31, 2010 (unaudited)		3

		Consolidated Statements of Cash Flows – Three Months Ended March 31, 2010 and 2009 (unaudited)		4

		Notes to Consolidated Financial Statements (unaudited)		5

Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations		24

Item 3.		Quantitative and Qualitative Disclosures About Market Risk		36

Item 4.		Controls and Procedures		37

PART II OTHER INFORMATION

Item 1.		Legal Proceedings		37

Item 1A.		Risk Factors		37

Item 2.		Unregistered Sales of Equity Securities and Use of Proceeds		37

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.

PART I FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(Unaudited)


	March 31,			December 31,
	2010			2009
	(In thousands, except share data)
ASSETS
Current assets:
Cash and cash equivalents	$	9,980		$	61,918
Short-term restricted deposits		100,000			100,000
Trade accounts receivable, net of allowance for doubtful accounts of $100 and $100, respectively		18,166			16,654
Deposits and prepaid assets		3,179			3,103
Inventories		4,623			5,588
Other current assets		3,498			5,189

Total current assets		139,446			192,452

Property and equipment:
Oil and gas properties, successful efforts method of accounting:
Unproved		279,725			280,844
Proved		1,336,131			1,379,920
Drilling and trucking equipment		178,434			177,762
Pipeline and gathering systems		96,139			92,064
Other		16,080			16,154

Total property and equipment		1,906,509			1,946,744
Less accumulated depreciation and depletion		(775,200	)		(800,501	)

Net property and equipment		1,131,309			1,146,243


Long-term assets:
Long-term restricted deposit		100,000			100,000
Investments in unconsolidated affiliates		3,936			7,444
Deferred financing costs		2,664			3,017
Other long-term assets		6,430			8,329

Total long-term assets		113,030			118,790


Total assets	$	1,383,785		$	1,457,485


LIABILITIES AND EQUITY
Current liabilities:
Credit facility – Delta	$	93,038		$	-
Credit facility – DHS		83,268			83,268
Installments payable on property acquisition		98,507			97,874
Accounts payable		42,544			44,225
Offshore litigation payable		-			13,877
Other accrued liabilities		15,074			13,459
Derivative instruments		6,777			19,497

Total current liabilities		339,208			272,200

Long-term liabilities:
Installments payable on property acquisition, net of current portion		95,998			95,381
7% Senior notes		149,628			149,609
3 ³ / 4 % Senior convertible notes		105,121			104,008
Credit facility – Delta		-			124,038
Asset retirement obligations		6,392			7,654
Derivative instruments		2,923			7,475

Total long-term liabilities		360,062			488,165

Commitments and contingencies

Equity:
Preferred stock, $.01 par value: authorized 3,000,000 shares, none issued		-			-
Common stock, $.01 par value: authorized 600,000,000 shares, issued 282,812,000 shares at March 31, 2010 and 282,548,000 shares at December 31, 2009		2,828			2,825
Additional paid-in capital		1,628,238			1,625,035
Treasury stock at cost; 34,000 shares at March 31, 2010 and 42,000 shares at December 31, 2009		(193)			(268)
Accumulated deficit		(951,807)			(939,010)

Total Delta stockholders’ equity		679,066			688,582

Non-controlling interest		5,449			8,538

Total equity		684,515			697,120


Total liabilities and equity	$	1,383,785		$	1,457,485

See accompanying notes to consolidated financial statements.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)


	Three Months Ended
	March 31,
	2010			2009
	(In thousands, except per share amounts)
Revenue:

Oil and gas sales	$	34,453		$	22,158
Contract drilling and trucking fees		9,932			5,213
Gain (loss) on offshore litigation award and property sales, net		(429	)		31,285


Total revenue		43,956			58,656


Operating expenses:

Lease operating expense		8,171			9,846
Transportation expense		3,927			3,255
Production taxes		1,681			1,580
Exploration expense		226			1,060
Dry hole costs and impairments		354			1,443
Depreciation, depletion, amortization and accretion – oil and gas		23,186			26,822
Drilling and trucking operating expenses		7,889			5,256
Depreciation and amortization – drilling and trucking		5,572			5,792
General and administrative		11,387			12,630


Total operating expenses		62,393			67,684


Operating loss		(18,437	)		(9,028	)


Other income and (expense):

Interest expense and financing costs, net		(10,560	)		(16,426	)
Other income, net		129			154
Realized loss on derivative instruments, net		(4,113	)		-
Unrealized gain (loss) on derivative instruments, net		17,272			(5,464	)
Income (loss) from unconsolidated affiliates		(8	)		747


Total other income (expense)		2,720			(20,989	)


Loss before income taxes		(15,717	)		(30,017	)

Income tax expense (benefit)		275			(583	)


Net loss		(15,992	)		(29,434	)

Less net loss attributable to non-controlling interest		3,195			3,880


Net loss attributable to Delta common stockholders	$	(12,797	)	$	(25,554	)


Basic income (loss) attributable to Delta common stockholders per common share:
Net loss	$	(0.05	)	$	(0.25	)


Diluted income (loss) attributable to Delta common stockholders per common share:
Net loss	$	(0.05	)	$	(0.25	)

See accompanying notes to consolidated financial statements.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
(Unaudited)


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

Net loss		-			-			-			-			-			(12,797	)		(12,797	)		(3,195	)		(15,992	)
Employee vesting of treasury stock held by subsidiary		-			-			-			(8	)		75			-			75			(75	)		-
Issuance of vested stock		481			5			(5	)		-			-			-			-			-			-
Shares repurchased for withholding taxes		(2	)		-			(2	)		-			-			-			(2	)		-			(2	)
Forfeiture of restricted shares		(215	)		(2	)		2			-			-			-			-			-			-
Stock based compensation		-			-			3,208			-			-			-			3,208			181			3,389


Balance, March 31, 2010		282,812		$	2,828		$	1,628,238			34		$	(193	)	$	(951,807	)	$	679,066		$	5,449		$	684,515

See accompanying notes to consolidated financial statements.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)


	Three Months Ended
	March 31,
	2010			2009
	(In thousands)
Cash flows from operating activities:
Net loss	$	(15,992	)	$	(29,434	)
Adjustments to reconcile net loss to cash used in operating activities:
Gain (loss) on offshore litigation award and property sales, net		429			(31,285	)
Depreciation, depletion, amortization and accretion – oil and gas		23,186			26,822
Depreciation and amortization – drilling and trucking		5,572			5,792
Stock based compensation		3,389			2,764
Amortization of deferred financing costs		2,550			4,251
Accretion of discount on installments payable		1,250			1,848
Unrealized (gain) loss on derivative instruments, net		(17,272	)		5,464
Dry hole costs and impairments		354			1,443
(Income) loss from unconsolidated affiliates		8			(410	)
Deferred income tax expense (benefit)		275			(583	)
Other		(69	)		(88	)
Net changes in operating assets and liabilities:
(Increase) decrease in trade accounts receivable		(1,512	)		11,807
(Increase) decrease in deposits and prepaid assets		(76	)		5,556
Increase in inventories		-			(1,275	)
Increase in other current assets		(36	)		(3,095	)
Decrease in accounts payable		(7,055	)		(7,814	)
Increase (decrease) in offshore litigation payable and other accrued liabilities		(11,942	)		2,329


Net cash used in operating activities		(16,941	)		(5,908	)


Cash flows from investing activities:
Additions to property and equipment		(9,349	)		(48,364	)
Additions to drilling and trucking equipment		(703	)		(691	)
Proceeds from sale of oil and gas properties		766			-
Proceeds from sale of drilling assets and other fixed assets		167			-
Proceeds from sale of unconsolidated affiliate		3,500			-
Distribution from unconsolidated affiliates		-			295
Proceeds from escrow deposit		1,380			-
(Increase) decrease in other long-term assets		244			(79	)


Net cash used in investing activities		(3,995	)		(48,839	)


Cash flows from financing activities:
Proceeds from borrowings		24,000			-
Repayments of borrowings		(55,000	)		(875	)
Proceeds from sale of offshore litigation contingent payment rights		-			14,900
Shares repurchased for withholding taxes		(2	)		(247	)


Net cash provided by (used in) financing activities		(31,002	)		13,778


Net decrease in cash and cash equivalents		(51,938	)		(40,969	)

Cash at beginning of period		61,918			65,475


Cash at end of period	$	9,980			24,506


Supplemental cash flow information:
Cash paid for interest and financing costs	$	2,893		$	5,603

See accompanying notes to consolidated financial statements.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES

Notes to Consolidated Financial Statements
Three Months Ended March 31, 2010 and 2009
(Unaudited)

(1)

Nature of Organization and Basis of Presentation

Delta Petroleum Corporation (“Delta” or the “Company”), a Delaware corporation, is principally engaged in acquiring, exploring, developing and producing oil and gas properties. The Company’s core areas of operation are the Rocky Mountain and Gulf Coast Regions, which comprise the majority of its proved reserves, production and long-term growth prospects.

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

(2)

Going Concern

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

The Company experienced a net loss attributable to Delta common stockholders of $12.8 million for the three months ended March 31, 2010, and had a working capital deficiency of $199.8 million, including $93.0 million outstanding under Delta’s credit facility which is due on January 15, 2011 and $83.3 million outstanding under the credit agreement of DHS Drilling Company (“DHS”), the Company’s 49.8% subsidiary. The ongoing losses, near term credit maturities, and working capital deficiency raise substantial doubt about the Company’s ability to continue as a going concern.

As of and for the three months ended March 31, 2010, the Company was in compliance with covenants related to its financial ratios and accounts payable. The Company had $52.0 million of availability under its Delta credit agreement based upon the redetermined $145.0 million borrowing base (effective April 26, 2010, see Note 7, “Long Term Debt”) and had cash on hand of $10.0 million.

Pursuant to a scheduled redetermination effective as of April 26, 2010, among other changes more fully described in Note 7, “Long Term Debt,” the borrowing base under the Company’s credit agreement was reduced to $145.0 million; however, the requirement to maintain the $20.0 million of minimum availability was deleted such that the effective credit capacity was reduced by $20.0 million.

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

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2010 and 2009
(Unaudited)

(2)

Going Concern, Continued

The Company does not currently have the capital on hand necessary to repay its credit facility borrowings due on January 15, 2011 or develop its properties at the pace desired based on current commodity prices. Further, in conjunction with the April 2010 borrowing base redetermination of Delta’s credit facility, the Company is limited to capital expenditures of $20.0 million in the quarter ending June 30, 2010 and $15.0 million for the quarter ending September 30, 2010.

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

On March 18, 2010, the Company announced it had entered into a non-binding letter of intent with Opon International LLC (“Opon”) to sell a 37.5% non-operated working interest in the Company’s Vega Area assets located in the Piceance Basin for total consideration of $400 million. It is expected that $225 million of the total consideration will be used by the Company for the development of the Vega Area over the next three years. The Company intends to use the remainder of the total consideration for its balance sheet obligations and general working capital purposes. The Company has also agreed to issue to Opon at closing, warrants to purchase 13.3 million shares of Delta common stock at $1.50 per share and 5.7 million shares at $3.50 per share. The consummation of the transaction is contingent upon Opon’s ability to arrange financing and is subject to customary due diligence, negotiation and execution of definitive binding agreements. The parties are continuing with the proposed transaction and the Company understands that Opon’s financing efforts are ongoing. The Company will retain operations of the Vega Area subject to a joint venture agreement with Opon. There can be no assurance that the transaction with Opon will be successfully consummated.

In addition to the strategic evaluation process described above, and in consideration of the results of the recently completed borrowing base redetermination also described above, the Company continues to be in discussions with other lenders in an effort to refinance or replace the existing facility prior to its January 15, 2011 maturity.

If the pending Vega Area transaction with Opon is not consummated, the Company will need to raise additional capital in order to pay its outstanding borrowings under Delta’s credit facility which are due January 15, 2011. There can be no assurance that the actions undertaken by the Company will be sufficient to repay the obligations under the credit agreement when due, or, if not sufficient, or if additional defaults occur, that the lenders will be willing to waive the defaults or amend the agreement. In addition, there can be no assurance that cash flow from operations and other sources of liquidity, including asset sales or joint venture or other industry partnerships, will be sufficient to meet contractual, operating and capital obligations. The financial statements do not include any adjustments that might result from the outcome of uncertainty regarding the Company’s ability to raise additional capital, sell assets, or otherwise obtain sufficient funds to meet its obligations.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2010 and 2009
(Unaudited)

(3)		Summary of Significant Accounting Policies

		Principles of Consolidation and Basis of Presentation

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

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

Certain reclassifications have been made to amounts reported in the previous periods to conform to the current presentation. Such reclassifications had no effect on net loss.

Cash Equivalents

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

Inventories

Inventories consist of pipe and other production equipment not yet in use. Inventories are stated at the lower of cost (principally first-in, first-out) or estimated net realizable value.

		Revenue Recognition

		*Oil and Gas*

Revenues are recognized when title to the products transfers to the purchaser. The Company follows the “sales method” of accounting for its natural gas and crude oil revenue. Under that method, the Company recognizes sales revenue on all natural gas or crude oil sold to its purchasers. A liability is recognized only to the extent that the Company has an imbalance on a specific property greater than the expected remaining proved reserves. As of March 31, 2010 and December 31, 2009, the Company’s aggregate natural gas and crude oil imbalances were not material to its consolidated financial statements.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2010 and 2009
(Unaudited)

(3)		Summary of Significant Accounting Policies, Continued

		*Drilling and Trucking*

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

Property and Equipment

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

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

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

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

Impairment of Long-Lived Assets

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

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

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2010 and 2009
(Unaudited)

(3)

Summary of Significant Accounting Policies, Continued

The Company assesses proved properties on an individual field basis for impairment on at least an annual basis. For proved properties, the review consists of a comparison of the carrying value of the asset with the asset’s expected future undiscounted cash flows without interest costs. As a result of such assessment, the Company recorded an impairment provision to developed properties of $895,000 for the three months ended March 31, 2009. For the three months ended March 31, 2010, the expected future undiscounted cash flows of the assets exceeded the carrying value of the corresponding asset and as such no impairment provision was recognized. The impairment for the three months ended March 31, 2009 is included within dry hole costs and impairments in the accompanying statement of operations.

For unproved properties, the need for an impairment charge is based on the Company’s plans for future development and other activities impacting the life of the property and the ability of the Company to recover its investment. When the Company believes the costs of the unproved property are no longer recoverable, an impairment charge is recorded based on the estimated fair value of the property. As a result of such assessment, the Company recorded impairment provisions attributable to unproved properties of $897,000 and $350,000 for the three months ended March 31, 2010 and 2009, respectively. These impairments are included within dry hole costs and impairments in the accompanying statements of operations for the three months ended March 31, 2010 and 2009.

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

Asset Retirement Obligations

The Company’s asset retirement obligations arise from the plugging and abandonment liabilities for its oil and gas wells. The Company has no obligation to provide for the retirement of most of its offshore properties as the obligations remained with the seller from whom the Company acquired the properties. The following is a reconciliation of the Company’s asset retirement obligations from January 1, 2010 to March 31, 2010 (amounts in thousands):


Asset retirement obligation – January 1, 2010	$	10,539
Accretion expense		133
Change in estimate		(304	)
Obligations incurred (from new wells)		60
Obligations assumed		-
Obligations on sold properties		(865	)
Obligations settled		(700	)

Asset retirement obligation – March 31, 2010		8,863
Less: current portion of asset retirement obligation		(2,471	)

Long-term asset retirement obligation	$	6,392

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, 2010 and 2009, comprehensive loss was $16.0 million and $29.4 million, respectively.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2010 and 2009
(Unaudited)

(3)		Summary of Significant Accounting Policies, Continued

		Financial Instruments

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

The purpose of the hedges is to provide a measure of stability to the Company’s cash flows in an environment of volatile oil and gas prices. The Company has not elected hedge accounting and recognizes mark-to-market gains and losses in earnings currently.

The Company is exposed to the fluctuations in natural gas or crude oil prices due to the nature of business in which the Company is primarily involved. In order to mitigate the risks associated with uncertain cash flows from volatile commodity prices and to provide stability and predictability in the Company’s future revenues, the Company periodically enters into commodity price risk management transactions to manage its exposure to gas and oil price volatility.

At March 31, 2010, all of the Company’s outstanding derivative contracts were fixed price swaps. Under the swap agreements, the Company receives the fixed price and pays the floating index price. The Company’s swaps are settled in cash on a monthly basis. By entering into swaps, the Company effectively fixes the price that it will receive for a portion of its production.

The following table summarizes the Company’s open derivative contracts at March 31, 2010:


									Net Fair Value
						Remaining			Asset (Liability) at
Commodity	Volume			Fixed Price		Term		Index Price	March 31, 2010
									(In thousands)

Crude oil		1,000	Bbls / Day	$	52.25	Apr ’10	- Dec ’10	NYMEX – WTI		(8,704	)
Crude oil		500	Bbls / Day	$	57.70	Jan ’11	- Dec ’11	NYMEX – WTI		(4,688	)
Natural gas		6,000	MMBtu / Day	$	5.720	Apr ’10	- Dec ’10	NYMEX – HHUB		2,370
Natural gas		15,000	MMBtu / Day	$	4.105	Apr ’10	- Dec ’10	CIG		577
Natural gas		5,367	MMBtu / Day	$	3.973	Apr ’10	- Dec ’10	CIG		16
Natural gas		12,000	MMBtu / Day	$	5.150	Jan ’11	- Dec ’11	CIG		671
Natural gas		3,253	MMBtu / Day	$	5.040	Jan ’11	- Dec ’11	CIG		58

									$	(9,700	)

The pre-credit risk adjusted fair value of the Company’s net derivative liabilities as of March 31, 2010 was $10.5 million. A credit risk adjustment of $817,000 to the fair value of the derivatives reduced the reported amount of the net derivative liabilities on the Company’s consolidated balance sheet to $9.7 million.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2010 and 2009
(Unaudited)

(3)

Summary of Significant Accounting Policies, Continued

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


Derivatives Not Designated as
Hedging Instruments	Balance Sheet Classification	Fair Value
Liabilities
Commodity Swaps	Derivative Instruments – Current Liabilities, net	$	6,777
Commodity Swaps	Derivative Instruments – Long-Term Liabilities, net		2,923

Total		$	9,700

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, 2010 (in thousands):


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

Commodity Swaps	Realized Loss on Derivative Instruments, net – Other Income and (Expense)	$	(4,113	)
Commodity Swaps	Unrealized Gain on Derivative Instruments, net – Other Income and (Expense)	$	17,272

		$	13,159

Stock Based Compensation

The Company recognizes the cost of share based payments over the period the employee provides service and includes such costs in general and administrative expense in the statements of operations.

Income (Loss) from Unconsolidated Affiliates

Income (loss) from unconsolidated affiliates includes the Company’s share of earnings or losses from equity method investments. During the first quarter of 2010, DOTC reported continuing losses from operations which, if recorded, would have created a deficit in the investment in DOTC. In accordance with accounting standards, the Company did not recognize its share of the losses for the first quarter of 2010 as the Company is not obligated to make future capital contributions to DOTC.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2010 and 2009
(Unaudited)

(3)

Summary of Significant Accounting Policies, Continued

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

Income Taxes

The Company uses the asset and liability method of accounting for income taxes. Under the asset and liability method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and net operating loss and tax credit carry-forwards. Deferred tax assets and liabilities are measured using enacted income tax rates expected to apply to taxable income in the years in which those differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in income tax rates is recognized in the results of operations in the period that includes the enactment date. The realizability of deferred tax assets is evaluated based on a “more likely than not” standard, and to the extent this threshold is not met, a valuation allowance is recorded. The Company is currently providing a full valuation allowance on its net deferred tax assets, including the net deferred tax assets of DHS.

Income (Loss) per Common Share

Basic income (loss) per share is computed by dividing net income (loss) attributed to common stock by the weighted average number of common shares outstanding during each period, excluding treasury shares. Diluted income (loss) per share is computed by adjusting the average number of common shares outstanding for the dilutive effect, if any, of convertible preferred stock, convertible debt, stock options, restricted stock and warrants. (See Note 11, “Earnings Per Share”).

Use of Estimates

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

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2010 and 2009
(Unaudited)

(3)

Summary of Significant Accounting Policies, Continued

Recently Issued and Adopted Accounting Pronouncements

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

(4)

Oil and Gas Properties

2010 – Divestitures

During the three months ended March 31, 2010, the Company divested of its interests in two non-core properties for $50,000 in cash and the assumption of plugging and abandonment obligations. Proved reserves attributable to these properties were insignificant.

(5)

DHS Drilling

On March 31, 2010, the Company owned a 49.8% ownership interest in DHS Drilling Company. The remaining interest is owned by Chesapeake Energy Corporation, 47.2%, and 3% by DHS executive officers and management. Delta has the right to use all of the DHS rigs on a priority basis.

The carrying value of DHS’s drilling rigs and related equipment is assessed for impairment whenever circumstances indicate an impairment may exist. No such impairment provisions were recorded during the three months ended March 31, 2010 and 2009.

(6)

Fair Value Measurements

Effective January 1, 2008, 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.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2010 and 2009
(Unaudited)

(6)

Fair Value Measurements, Continued

Derivative liabilities consist of future oil and gas commodity swap contracts valued using both quoted prices for identically traded contracts and observable market data for similar contracts (NYMEX WTI oil, NYMEX Henry Hub gas and CIG gas swaps – Level 2).

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, 2010 and 2009.

The following table lists the Company’s fair value measurements by hierarchy as of March 31, 2010 (in thousands):

Quoted Prices

Significant

in Active Markets

Other Observable

Unobservable

for Identical Assets

Inputs

Total

Assets (Liabilities)

(Level 1)

(Level 2)

(Level 3)

March 31, 2010

Derivative liabilities

(9,700

)

(9,700

)

(7)

Long Term Debt

Installments Payable on Property Acquisition

On February 28, 2008, the Company closed a transaction with EnCana to jointly develop a portion of EnCana’s leasehold in the Vega Area of the Piceance Basin. The remaining installments payable are recorded in the accompanying consolidated financial statements as current and long-term liabilities at a discounted value. The discount is being accreted on the effective interest method over the term of the installments, including accretion of $1.3 million and $1.8 million for the three months ended March 31, 2010 and 2009, respectively.

7% Senior Unsecured Notes, due 2015

On March 15, 2005, the Company issued 7% senior unsecured notes for an aggregate principal amount of $150.0 million. The Company was in compliance with the covenants under the indenture as of March 31, 2010 (See Note 12, “Guarantor Financial Information”). The fair value of the Company’s senior unsecured notes at March 31, 2010 was approximately $128.3 million.

3 ³ / 4 % Senior Convertible Notes, due 2037

On April 25, 2007, the Company issued $115.0 million aggregate principal amount of 3 ³ / 4 % Senior Convertible Notes due 2037 (the “Notes”) for net proceeds of $111.6 million after underwriters’ discounts and commissions of approximately $3.4 million. The Notes were recorded based on the estimated fair value of the liability component and the equity component. The debt discount on the liability component is accreted over the expected life of the Notes, including $1.1 million of accretion for each of the three months ended March 31, 2010 and 2009. Combined with the amortization of debt discount, the Notes had an effective interest rate of approximately 7.6% and 8.2% with total interest costs of $2.2 million and $3.2 million for the three months ended March 31, 2010 and 2009, respectively. The fair value of the Notes at March 31, 2010 was approximately $91.7 million.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2010 and 2009
(Unaudited)

(7)		Long Term Debt, Continued

		Credit Facility – Delta

On April 26, 2010, Delta entered into the Third Amendment (the “Third Amendment”) to the Second Amended and Restated Credit Agreement (as amended, the “Credit Agreement”), with JPMorgan Chase Bank, N.A., as agent, and certain of the financial institutions that are party to its credit agreement in which, among other changes, the lenders provided a waiver from Delta’s violations of the capital expenditure limitation of $10.0 million for the quarter ended March 31, 2010. In conjunction with the Third Amendment and as part of a scheduled redetermination, the borrowing base was reduced from $185.0 million with a $20.0 million required minimum availability to $145.0 million with no required minimum availability for a net reduction in the borrowing base of $20.0 million. The next scheduled redetermination date is July 1, 2010. In addition, the Third Amendment imposed capital expenditures limitations of $20.0 million for the quarter ending June 30, 2010 and $15.0 million for the quarter ending September 30, 2010, provided that any excess of the limitation over the amount of actual expenditures may be carried forward from an earlier quarter to a subsequent quarter. The Company is currently in compliance with its financial debt covenants and based on the Company’s current operating projections, the Company believes it will remain in compliance with the debt covenants. However, depending on market conditions and the possibility of further economic deterioration, the Company may need to request amendments, or waivers for the covenants, or obtain refinancing in future periods. There can be no assurance that the Company will be able to obtain amendments or waivers, or negotiate agreeable refinancing terms should it become needed.

Borrowings under the credit facility were $93.0 million at March 31, 2010, with remaining availability of $52.0 million based on the revised $145.0 million borrowing base.

Because the credit facility matures in January 2011, the debt is classified as a current liability in the March 31, 2010 consolidated balance sheet.

Credit Facility – DHS

On April 1, 2010, DHS amended its existing credit facility with LCPI and renegotiated certain terms of the agreement including obtaining waivers for all covenant violations through March 31, 2010. The terms of the amended agreement required principal payments of $7,677,713 paid on April 1, 2010 and $2,000,000 paid on May 1, 2010, with remaining $2,000,000 principal payments due on each of August 1, 2010, November 1, 2010 and January 1, 2011, and a $5,000,000 principal payment on each of April 1, 2011 and July 1, 2011 with the remaining balance of $57,589,787 due at maturity (August 31, 2011). In addition to the required payments, DHS may be required to prepay any remaining outstanding principal with the “Net Cash Proceeds from any Asset Sale,” as defined by the credit facility, and any such prepayment shall be applied to, first, prepay the immediately succeeding Scheduled Installment in full, second, prepay all interest payable on the immediately succeeding Interest Payment Date in full, third, pay the second succeeding Scheduled Installment in full and fourth, prepay the remaining principal balance of the remaining loans. DHS is also required to prepay the principal amount of the loans in an amount equal to 75% of the “Excess Cash Flow,” as defined by the credit facility, for such fiscal quarter. The only financial covenant remaining in the DHS credit agreement is a minimum EBITDA covenant of $100,000 for the three months ended March 31, 2010, $250,000 for the three months ending June 30, 2010, $1,000,000 for the three months ending September 30, 2010 and $1,500,000 for each subsequent quarter. In addition, the amendment imposed capital expenditures limitations of $1,200,000 for any fiscal quarter. Notwithstanding the $1,200,000 per quarter limitation on capital expenditures, the amendment imposes aggregate capital expenditure limitations of $3,500,000 for fiscal year 2010 and $2,330,137 for fiscal year 2011. The interest rate has been adjusted to LIBOR plus 625 basis points, subject to a LIBOR floor rate of 2.75%. DHS was in compliance with its amended minimum EBITDA covenant for the three months ended March 31, 2010.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2010 and 2009
(Unaudited)

(8)

Commitments and Contingencies

The $115.0 million in principal amount of 3 ³ / 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 us to purchase all or a portion of the Notes on May 1, 2012, May 1, 2017, May 1, 2022, May 1, 2027, and May 1, 2032 at a price which is required to be paid in cash, equal to 100% of the principal amount of the Notes to be repurchased.

(9)

Stockholders’ Equity

Preferred Stock

The Company has 3,000,000 shares of preferred stock authorized, issuable from time to time in one or more series. As of March 31, 2010 and December 31, 2009, no shares of preferred stock were outstanding.

Common Stock

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

Treasury Stock

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

Stock Based Compensation

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


	Three Months Ended
	March 31,
	2010		2009

Non-vested stock	$	3,031	$	1,778
Performance shares		358		987

Total	$	3,389	$	2,765

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2010 and 2009
(Unaudited)

(9)

Stockholders’ Equity, Continued

The Company recognizes the cost of share based payments over the period during which the employee provides service. As all outstanding stock options are vested, no compensation cost was recognized with respect to stock options in any of the periods shown in the table above. Exercise prices for options outstanding under the Company’s various plans as of March 31, 2010 ranged from $1.87 to $15.34 per share and the weighted-average remaining contractual life of those options was 3.54 years. The Company has not issued stock options since July 2005, although it has the discretion to issue options again in the future. At March 31, 2010, the Company had 1,427,750 options outstanding at a weighted average exercise price of $8.21 per share. At March 31, 2010, the Company had 6,801,000 non-vested shares outstanding and 150,000 performance shares outstanding. At March 31, 2010, the total unrecognized compensation cost related to the non-vested portion of restricted stock was $21.4 million which is expected to be recognized over a weighted average period of 2.0 years.

(10)

Income Taxes

Income tax expense (benefit) attributable to loss from continuing operations was approximately $275,000 and $(583,000) for the three months ended March 31, 2010 and 2009, respectively.

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future results of operations, and tax planning strategies in making this assessment. Based upon the level of historical taxable income, significant book losses during the current and prior periods, and projections for future results of operations over the periods in which the deferred tax assets are deductible, among other factors, management continues to conclude that the Company does not meet the “more likely than not” requirement in order to recognize deferred tax assets and a valuation allowance has been recorded for the Company’s net deferred tax assets at March 31, 2010.

During the three months ended March 31, 2010, DHS recorded significant net operating losses and as of March 31, 2010 DHS’s deferred tax assets exceeded its deferred tax liabilities. Accordingly, based on significant recent operating losses and projections for future results, a valuation allowance was recorded for DHS’s net deferred tax assets.

During the remainder of 2010 and thereafter, the Company will continue to assess the realizability of its deferred tax assets based on consideration of actual and projected operating results and tax planning strategies. Should actual operating results improve, the amount of the deferred tax asset considered more likely than not to be realizable could be increased. Such a change in the assessment of realizability could result in a decrease to the valuation allowance and corresponding income tax benefit, both of which could be significant.

During the three months ended March 31, 2010 and 2009, no adjustments were recognized for uncertain tax benefits.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2010 and 2009
(Unaudited)

(11)

Earnings Per Share

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


	Three Months Ended
	March 31,
	2010			2009

Net loss attributable to Delta common stockholders	$	(12,797	)	$	(25,554	)


Basic weighted-average common shares outstanding		275,691			101,502
Add: dilutive effects of stock options and unvested stock grants		-			-

Diluted weighted-average common shares outstanding		275,691			101,502


Net income (loss) per common share attributable to Delta common stockholders
Basic	$	(0.05	)	$	(0.25	)

Diluted	$	(0.05	)	$	(0.25	)

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


	Three Months Ended
	March 31,
	2010		2009

Stock issuable upon conversion of convertible notes		3,790		3,790
Stock options		1,428		1,498
Performance share grants		150		250
Non-vested restricted stock		6,801		1,022

Total potentially dilutive securities		12,169		6,560

(12)

Guarantor Financial Information

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

The following financial information sets forth the Company’s condensed consolidated balance sheets as of March 31, 2010 and December 31, 2009, the condensed consolidated statements of operations for the three months ended March 31, 2010 and 2009, and the condensed consolidated statements of cash flows for the three months ended March 31, 2010 and 2009 (in thousands). For purposes of the condensed financial information presented below, the equity in the earnings or losses of subsidiaries is not recorded in the financial statements of the issuer.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2010 and 2009
(Unaudited)

(12)

Guarantor Financial Information, Continued

Condensed Consolidated Balance Sheet
March 31, 2010


				Guarantor			Non-Guarantor			Adjustments/
	Issuer			Entities			Entities			Eliminations			Consolidated

Current assets	$	101,774		$	407		$	37,265		$	-		$	139,446

Property and equipment:
Oil and gas properties		1,482,414			505			133,032			(95	)		1,615,856
Drilling rigs and trucking equipment		594			-			177,840			-			178,434
Other		77,383			32,949			1,887			-			112,219

Total property and equipment		1,560,391			33,454			312,759			(95	)		1,906,509

Accumulated depletion and depreciation		(617,114	)		(24,059	)		(134,027	)		-			(775,200	)


Net property and equipment		943,277			9,395			178,732			(95	)		1,131,309

Investment in subsidiaries		75,269			-			-			(75,269	)		-
Other long-term assets		110,440			2,407			183			-			113,030


Total assets	$	1,230,760		$	12,209		$	216,180		$	(75,364	)	$	1,383,785


Current liabilities	$	241,427		$	200		$	97,581		$	-		$	339,208

Long-term liabilities:
Long-term debt and derivative instruments		351,869			1,801			-			-			353,670
Asset retirement obligations		6,090			11			291			-			6,392


Total long-term liabilities		357,959			1,812			291			-			360,062

Total Delta stockholders’ equity		625,925			10,197			118,308			(75,364	)		679,066

Non-controlling interest		5,449			-			-			-			5,449


Total equity		631,374			10,197			118,308			(75,364	)		684,515


Total liabilities and equity	$	1,230,760		$	12,209		$	216,180		$	(75,364	)	$	1,383,785

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2010 and 2009
(Unaudited)

(12)

Guarantor Financial Information, Continued

Condensed Consolidated Balance Sheet
December 31, 2009


				Guarantor			Non-Guarantor			Adjustments/
	Issuer			Subsidiaries			Subsidiaries			Eliminations			Consolidated

Current assets	$	160,408		$	448		$	31,596		$	-		$	192,452

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

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

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

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

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


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


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

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


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

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

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


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


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

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2010 and 2009
(Unaudited)

(12)

Guarantor Financial Information, Continued

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


				Guarantor			Non-Guarantor			Adjustments/
	Issuer			Entities			Entities			Eliminations			Consolidated

Total revenue	$	31,402		$	212		$	13,136		$	(794	)	$	43,956

Operating expenses:
Oil and gas expenses		12,736			120			923			-			13,779
Exploration expense		226			-			-			-			226
Dry hole costs and impairments		354			-			-			-			354
Depreciation and depletion		18,771			18			10,033			(64	)		28,758
Drilling and trucking operating expenses		-			-			8,525			(636	)		7,889
General and administrative		10,192			16			1,179			-			11,387


Total operating expenses		42,279			154			20,660			(700	)		62,393


Operating income (loss)		(10,877	)		58			(7,524	)		(94	)		(18,437	)

Other income and (expense)		4,522			(6	)		(1,796	)		-			2,720
Income tax benefit (expense)		(275	)		-			-			-			(275	)


Net income (loss)		(6,630	)		52			(9,320	)		(94	)		(15,992	)

Less loss attributable to non-controlling interest		3,195			-			-			-			3,195


Net income (loss) attributable to Delta common stockholders	$	(3,435	)	$	52		$	(9,320	)	$	(94	)	$	(12,797	)

Condensed Consolidated Statement of Operations
Three Months Ended March 31, 2009


				Guarantor			Non-Guarantor			Adjustments/
	Issuer			Entities			Entities			Eliminations			Consolidated

Total revenue	$	55,427		$	80		$	5,417		$	(2,268	)	$	58,656

Operating expenses:
Oil and gas expenses		12,786			45			1,850			-			14,681
Exploration expense		1,060			-			-			-			1,060
Dry hole costs and impairments		1,443			-			-			-			1,443
Depreciation and depletion		24,195			61			8,770			(412	)		32,614
Drilling and trucking operating expenses		-			-			6,627			(1,371	)		5,256
General and administrative		11,404			7			1,219			-			12,630


Total operating expenses		50,888			113			18,466			(1,783	)		67,684


Operating income (loss)		4,539			(33	)		(13,049	)		(485	)		(9,028	)

Other income and (expense)		(19,008	)		-			(1,981	)		-			(20,989	)
Income tax benefit (expense)		(211	)		-			794			-			583


Net loss		(14,680	)		(33	)		(14,236	)		(485	)		(29,434	)

Less loss attributable to non-controlling interest		3,880			-			-			-			3,880


Net loss attributable to Delta common stockholders	$	(10,800	)	$	(33	)	$	(14,236	)	$	(485	)	$	(25,554	)

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2010 and 2009
(Unaudited)

(12)

Guarantor Financial Information, Continued

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

Condensed Consolidated Statement of Cash Flows
Three Months Ended March 31, 2009


				Guarantor			Non-Guarantor
	Issuer			Entities			Entities			Consolidated

Cash provided by (used in):
Operating activities	$	(10,628	)	$	49		$	4,671		$	(5,908	)
Investing activities		(47,986	)		(101	)		(752	)		(48,839	)
Financing activities		13,984			-			(206	)		13,778


Net increase (decrease) in cash and cash equivalents		(44,630	)		(52	)		3,713			(40,969	)

Cash at beginning of the period		61,058			86			4,331			65,475


Cash at the end of the period	$	16,428		$	34		$	8,044		$	24,506

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three Months Ended March 31, 2010 and 2009
(Unaudited)

(13)

Business Segments

The Company has two reportable segments: oil and gas exploration and production (“Oil and Gas”) and drilling and trucking operations (“Drilling”) through its ownership in DHS. Following is a summary of segment results for the three months ended March 31, 2010 and 2009:


							Inter-segment
	Oil and Gas			Drilling			Eliminations			Consolidated
	(In thousands)
Three Months Ended March 31, 2010
Revenues from external customers	$	34,024		$	9,932		$	-		$	43,956
Inter-segment revenues		-			794			(794	)		-

Total revenues	$	34,024		$	10,726		$	(794	)	$	43,956

Operating loss	$	(13,771	)	$	(4,572	)	$	(94	)	$	(18,437	)

Other income (expense)		4,518			(1,798	)		-			2,720

Loss before tax	$	(9,253	)	$	(6,370	)	$	(94	)	$	(15,717	)


Three Months Ended March 31, 2009

Revenues from external customers	$	53,443		$	5,213		$	-		$	58,656
Inter-segment revenues		-			2,268			(2,268	)		-

Total revenues	$	53,443		$	7,481		$	(2,268	)	$	58,656

Operating loss	$	(1,999	)	$	(6,544	)	$	(485	)	$	(9,028	)

Other income (expense)		(19,007	)		(1,982	)		-			(20,989	)

Loss before tax	$	(21,006	)	$	(8,526	)	$	(485	)	$	(30,017	)

March 31, 2010:
Total assets	$	1,350,161		$	100,274		$	(66,650	)	$	1,383,785


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

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

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

Forward Looking Statements

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

We are including the following discussion to inform our existing and potential security holders generally of some of the risks and uncertainties that can affect us and to take advantage of the “safe harbor” protection for forward-looking statements afforded under federal securities laws. From time to time, our management or persons acting on our behalf make forward-looking statements to inform existing and potential security holders about us. Forward-looking statements are generally accompanied by words such as “estimate,” “project,” “propose,” “potential,” “predict,” “forecast,” “believe,” “expect,” “anticipate,” “plan,” “goal” or other words that convey the uncertainty of future events or outcomes. Except for statements of historical or present facts, all other statements contained in this Quarterly Report on Form 10-Q are forward-looking statements. The forward-looking statements may appear in a number of places and include statements with respect to, among other things: business objectives and strategic plans; our expectations with respect to the transaction with Opon International LLC, including transaction timing and anticipated use of proceeds; 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 Second Amended and Restated Credit Agreement, as amended, and to meet future debt service, capital expenditure and working capital requirements; status of a new or replacement credit facility; expected announcements of 2010 drilling plans and capital expenditure budget; anticipated utilization of joint venture and partnership structures; acquisition and divestiture strategies; completion and drilling program expectations, processes and emphasis; oil and gas reserve estimates (including estimates of future net revenues associated with such reserves and the present value of such future net revenues); availability of capital to develop our reserves; estimates of future production of oil and natural gas; marketing of oil and natural gas; expected future revenues and earnings, and results of operations; future capital, development and exploration expenditures (including the amount and nature thereof); nonpayment of dividends; expectations regarding competition and our competitive advantages; impact of the adoption of new accounting standards and our financial and accounting systems and analysis programs; anticipated compliance with and impact of laws and regulations; and effectiveness of our internal control over financial reporting.

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

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

•		the availability of capital on an economic basis, or at all, to fund our required payments under our Second Amended and Restated Credit Agreement, as amended, our working capital needs, and drilling and leasehold acquisition programs, including through potential joint ventures and asset monetization transactions;

•		lower natural gas and oil prices negatively affecting our ability to borrow or raise capital, or enter into joint venture 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 contraction in the demand for natural gas in the U.S. as a result of depressed general economic conditions;

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

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

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

•		timing, amount, and marketability of production;

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

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

•		the availability of borrowings under our credit facility and the ability to obtain a new or replacement 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.

Recent Developments

	•		On March 18, 2010 we announced that we had entered into a non-binding letter of intent with Opon International LLC (“Opon”) to sell a 37.5% non-operated working interest in our Vega Area assets located in the Piceance Basin for total consideration of $400 million. It is expected that $225 million of the total consideration will be used for the development of the Vega Area over the next three years. We intend to use the remainder of the total consideration to address our balance sheet obligations and for general working capital purposes. We have also agreed to issue to Opon at closing, warrants to purchase 13.3 million shares of Delta common stock at $1.50 per share and 5.7 million shares at $3.50 per share. The consummation of the transaction is contingent upon Opon’s ability to arrange financing and is subject to customary due diligence, negotiation and execution of definitive binding agreements. The parties are continuing with the proposed transaction and we understand that Opon’s financing efforts are ongoing. We will retain operations of the Vega Area subject to a joint venture agreement with Opon.

	•		On January 1, 2010, we sold our 5% interest in Collbran Valley Gas Gathering, LLC (“CVGG”) which operates a pipeline in the Piceance Basin through which we transport our produced gas to the sales point for cash proceeds of $3.5 million, plus an additional $2.0 million of proceeds contingent on volume deliveries through the CVGG system of Delta gas between January 1, 2010 and June 30, 2011. Based on current production levels, we are not likely to earn the contingent consideration without the initiation of a continuous drilling program which will most likely only be undertaken with additional funding beyond our existing capital resources.

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

	•		Pursuant to a scheduled redetermination effective as of April 26, 2010, among other changes more fully described in Note 7, “Long Term Debt” to the accompanying financial statements, the borrowing base under Delta’s credit agreement was reduced to $145.0 million; however, the requirement to maintain the $20.0 million of minimum availability was deleted such that the effective credit capacity was reduced by $20.0 million.

2010 Outlook

As announced in November 2009, we are working with Morgan Stanley and Evercore Partners to analyze various alternatives to enhance stockholder value, which include a sale of some or all of our assets, entering into partnerships or joint ventures, or the sale of the entire company. The evaluation of any particular transaction will involve, among other considerations, an analysis of our capital expenditure and working capital requirements for 2010 in respect of such transaction and other sources of liquidity, including cash from operations and our credit facility. As a result of the evaluation by Morgan Stanley and Evercore Partners, on March 18, 2010 we announced that we had entered into a non-binding letter of intent with Opon to sell a 37.5% non-operated working interest in our Vega Area assets located in the Piceance Basin for total consideration of $400 million, as described above.

We are unable to accurately predict our anticipated capital expenditures for fiscal year 2010, primarily due to the uncertainty relating to any potential strategic transaction, including the likelihood of such a transaction occurring, the type of transaction and the timing of any such transaction. Future redeterminations of our borrowing base under our credit facility may also affect our liquidity available for capital expenditures making it difficult to accurately determine such amounts at the current time. In addition, in conjunction with the recently completed scheduled redetermination of our borrowing base effective April 26, 2010, our credit facility was amended to limit our capital expenditures to $20.0 million for the quarter ending June 30, 2010 and $15.0 million for the quarter ending September 30, 2010. We expect to announce our 2010 drilling plans and expected oil and gas production once our strategic alternatives evaluation process is complete.

Liquidity and Capital Resources

On December 29, 2009 we received from the U.S. government $65.0 million of settlement proceeds related to litigation involving the offshore California lease 452 and in late December 2009 and early January 2010, we paid out a total of $16.4 million for third party contractual obligations and other participating interests related thereto. With such proceeds, we reduced our borrowings outstanding under our credit facility from $124.0 million at December 31, 2009 to $93.0 million at March 31, 2010.

On April 26, 2010, Delta entered into the Third Amendment (the “Third Amendment”) to the Second Amended and Restated Credit Agreement (as amended, the “Credit Agreement”) with JPMorgan Chase Bank, N.A., as agent, and certain of the financial institutions that are party to its credit agreement in which, among other changes, the lenders provided a waiver from Delta’s violation of the capital expenditure limitation of $10.0 million for the quarter ended March 31, 2010. In conjunction with the Third Amendment and as part of a scheduled redetermination, the borrowing base was reduced from $185.0 million with a $20.0 million required minimum availability to $145.0 million with no required minimum availability for a net reduction in the borrowing base of $20.0 million. The next scheduled redetermination date is July 1, 2010. In addition, the Third Amendment imposed capital expenditures limitations of $20.0 million for the quarter ending June 30, 2010 and $15.0 million for the quarter ending September 30, 2010, provided that any excess of the limitation over the amount of actual expenditures may be carried forward from an earlier quarter to a subsequent quarter. We were in compliance with the accounts payables covenant under our credit facility at March 31, 2010.

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

Our accompanying financial statements have been prepared assuming we will continue as a going concern. We have a deficiency in short-term liquidity and possible additional liquidity issues if commodity prices remain at low levels and our banks further reduce our borrowing base as part of our next scheduled redetermination. Further, our Credit Agreement matures in January 2011. Thus, our ability to continue as a going concern could be dependent upon our lenders’ willingness to amend terms, grant waivers, or restructure existing agreements, or our success in generating additional sources of capital in the near future, and/or an increase in commodity prices. We continue to be in discussions with other lenders in an effort to refinance or replace the existing facility prior to its January 15, 2011 maturity.

As shown in the accompanying financial statements and discussed elsewhere herein, we experienced a net loss attributable to Delta common stockholders of $12.8 million for the three months ended March 31, 2010. During the three months ended March 31, 2010, we had an operating loss of $18.4 million, net cash used in operating activities of $16.9 million and net cash used in financing activities of $31.0 million. During this period we invested $9.3 million on oil and gas development activities. At March 31, 2010, we had $10.0 million in cash and $52.0 million available under our credit facility (based on the borrowing base as re-determined effective April 26, 2010), total assets of $1.4 billion and a debt to capitalization ratio of 38.6%. Debt, excluding installments payable on property acquisition which are secured by restricted cash deposits, at March 31, 2010 totaled $431.1 million, comprised of $176.3 million of bank debt ($93.0 million of our indebtedness under our Credit Agreement and $83.3 million of DHS indebtedness, all of which is classified as current in the accompanying consolidated financial statements), $149.6 million of senior subordinated notes and $105.1 million of senior convertible notes. In accordance with applicable accounting rules, the senior convertible notes are recorded at a discount to their stated amount due of $115.0 million.

As of April 30, 2010, our corporate rating and senior unsecured debt rating were Caa3 and Ca, respectively, as issued by Moody’s Investors Service. Moody’s outlook was “negative.” As of April 30, 2010, our corporate credit and senior unsecured debt ratings were CCC and CCC, respectively, as issued by Standard and Poor’s (“S&P”). S&P’s outlook on its rating was “developing.”

Our future cash requirements are largely dependent upon the number and timing of projects included in our capital development plan, most of which are discretionary. We have historically addressed our long-term liquidity

requirements through the issuance of debt and equity securities when market conditions permit, through cash provided by operating activities, sales of oil and gas properties, and through borrowings under our credit facility.

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

There can be no assurance that the actions undertaken by us will be sufficient to repay the obligations under our credit facility, or, if not, or if additional defaults occur under that facility, that the lenders will be willing to waive further defaults or amend the facility. There can similarly be no assurance that our current levels of borrowing capacity under the Credit Agreement will remain in place, or that we will be successful in negotiating an extension to the Credit Agreement, or a replacement thereto, upon its scheduled maturity in January 2011. There can similarly be no assurance that DHS will be successful in negotiating an extension to the DHS credit facility, or a replacement thereto, upon its scheduled maturity in August 2011. In addition, there can be no assurance that results of operations and other sources of liquidity, including asset sales, will be sufficient to meet contractual, operating and capital obligations. Our financial statements do not include any adjustments that might result from the outcome of uncertainty regarding our ability to raise additional capital, sell assets, otherwise obtain sufficient funds to meet our obligations or to continue as a going concern.

As part of our consideration of potential strategic transactions, we continue to examine additional sources of long-term capital (including a restructured debt facility, the issuance of debt instruments, sales of assets and joint venture financing), as well as other potential corporate transactions. The availability of additional sources of capital, which will impact our ability to execute our operating strategy and meet our liquidity challenges, will depend upon a number of factors, many of which are beyond our control. Even though we entered into a non-binding letter of intent with Opon with respect to a proposed joint venture for total consideration of $400 million, the offer is contingent upon Opon’s ability to arrange financing.

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

Three Months Ended March 31, 2010 Compared to Three Months Ended March 31, 2009

Net Loss Attributable to Delta Common Stockholders. Net loss attributable to Delta common stockholders was $12.8 million, or $0.05 per diluted common share, for the three months ended March 31, 2010, compared to a net loss attributable to Delta common stockholders of $25.6 million, or $0.25 per diluted common share, for the three months ended March 31, 2009. There were a number of items affecting comparability between periods including oil and gas sales, contract drilling and trucking fees, gain on offshore litigation award, depletion expense, interest and financial costs, and realized and unrealized gains and losses on derivative instruments. Explanations of significant items affecting comparability between periods are discussed by financial statement caption below.

Oil and Gas Sales. During the three months ended March 31, 2010, oil and gas sales increased 55% to $34.5 million, as compared to $22.2 million for the comparable period a year earlier. The increase was principally the result of a 125% increase in oil prices and an 86% increase in natural gas prices, partially offset by a 20% decrease in production. The average oil price received during the three months ended March 31, 2010 increased to $70.78 per Bbl compared to $31.44 per Bbl for the year earlier period. The average natural gas price received during the three months ended March 31, 2010 increased to $5.70 per Mcf compared to $3.07 per Mcf for the year earlier period. The production decrease was primarily related to expected production declines in the Rockies that have not been offset by additional drilling.

Contract Drilling and Trucking Fees. Contract drilling and trucking fees for the three months ended March 31, 2010 increased to $9.9 million compared to $5.2 million in the prior year. The increase is the result of improved third party rig utilization in the three months ended March 31, 2010 resulting from an increased industry demand attributable to improved commodity prices.

Gain (Loss) on Offshore Litigation Award and Property Sales, Net. During the three months ended March 31, 2009, we recorded a $31.3 million gain for an offshore litigation award. During the three months ended March 31, 2010, we recorded a $0.4 million loss primarily associated with the divestiture of our non-core Angleton and Fuller properties. See Note 4, “Oil and Gas Properties,” to the accompanying financial statements for information regarding our 2010 divestitures.

Production and Cost Information

Production volumes, average prices received and cost per equivalent Mcf for the three months ended March 31, 2010 and 2009 are as follows:


	Three Months Ended
	March 31,
	2010		2009
Production:
Oil (Mbbl)		156		212
Gas (Mmcf)		4,112		5,050
Total Production (Mmcfe)		5,046		6,324

Average Price:
Oil (per barrel)	$	70.78	$	31.44
Gas (per Mcf)	$	5.70	$	3.07

Costs (per Mcfe):
Lease operating expense	$	1.62	$	1.56
Transportation costs	$	0.78	$	0.51
Production taxes	$	0.33	$	0.25
Depletion expense	$	4.46	$	4.13

Realized derivative losses (per Mcfe)	$	0.82	$	-

Lease Operating Expense. Lease operating expenses for the three months ended March 31, 2010 decreased to $8.2 million from $9.8 million in the year earlier period primarily due to the 20% decrease in production. Lease operating expense per Mcfe for the three months ended March 31, 2010 increased moderately to $1.62 per Mcfe from $1.56 per Mcfe for the comparable year earlier period, primarily as a result of increased workovers in the Gulf Coast region in the first quarter of 2010.

Transportation Expense. Transportation expense for the three months ended March 31, 2010 was $3.9 million, comparable to prior year costs of $3.3 million, but increased 53% from $0.51 per Mcfe to $0.78 per Mcfe. The increase on a per unit basis is primarily the result of changes to our Vega gas marketing contract that went into effect in October 2009 whereby our gas is processed through a higher efficiency plant. The Vega gas marketing contract has resulted in higher revenues in the Vega area from improved natural gas liquids recoveries and a greater percentage of liquids proceeds retained.

Production Taxes. Production taxes for the three months ended March 31, 2010 were $1.7 million, comparable to prior year costs of $1.6 million. Production taxes as a percentage of oil and gas sales were 4.9% and 7.1% for the three months ended March 31, 2010 and 2009, respectively. The decrease in the 2010 percentage was primarily due to a decrease in the effective Colorado severance tax rate.

Exploration Expense. Exploration expense consists of geological and geophysical costs, lease rentals and abandoned leases. Our exploration costs for the three months ended March 31, 2010 were $0.2 million compared to $1.1 million

for the comparable year earlier period. Current period exploration activities primarily relate to delay rental payments while the 2009 period included delay rental payments and seismic acquisition costs.

Dry Hole Costs and Impairments. We incurred dry hole costs and impairments of approximately $0.4 million for the three months ended March 31, 2010 compared to $1.4 million for the comparable period a year ago. During the three months ended March 31, 2010, dry hole and impairment costs primarily related to unproved property impairments on the Delores River and Haynesville shale prospects with near term lease expirations.

We incurred dry hole costs and impairments of approximately $1.4 million for the three months ended March 31, 2009 primarily related to minor write-offs for lease expirations and proved property impairments on miscellaneous California properties where well performance had recently declined.

Depreciation, Depletion, Amortization and Accretion – Oil and Gas. Depreciation, depletion and amortization expense decreased 14% to $23.2 million for the three months ended March 31, 2010, as compared to $26.8 million for the comparable year earlier period. Depletion expense for the three months ended March 31, 2010 decreased to $22.5 million from $26.1 million for the three months ended March 31, 2009 due to lower production volumes partially offset by an increase in the per unit depletion rate. Our depletion rate increased from $4.13 per Mcfe for the three months ended March 31, 2009 to $4.46 per Mcfe for the current year period primarily due to non-operated Piceance reserve revisions made in the second quarter of 2009 to reduce proved developed reserves based on well performance.

Drilling and Trucking Operations. Drilling expense increased to $7.9 million for the three months ended March 31, 2010 compared to $5.3 million for the comparable prior year period. This increase is due to improved third party rig utilization during the current year period.

Depreciation and Amortization – Drilling and Trucking. Depreciation and amortization expense – drilling decreased to $5.6 million for the three months ended March 31, 2010, as compared to $5.8 million for the comparable year earlier period. The decrease is due to the effect on the depreciation rate of rig impairments recorded during 2009. Depreciation expense is recorded on a straight line basis and is not impacted by changes in the utilization rate.

General and Administrative Expense. General and administrative expense decreased 10% to $11.4 million for the three months ended March 31, 2010, as compared to $12.6 million for the comparable prior year period. The decrease in general and administrative expenses is attributed to reduced staffing as a result of reductions in force during the first half of 2009 resulting in lower cash compensation expense, partially offset by costs associated with the strategic alternatives evaluation process and by increased non-cash stock compensation expense related to restricted stock granted in December 2009.

Interest Expense and Financing Costs, Net. Interest expense and financing costs, net decreased 36% to $10.6 million for the three months ended March 31, 2010, as compared to $16.4 million for the comparable year earlier period. The decrease is primarily related to lower average outstanding Delta and DHS credit facility balances, partially offset by higher interest rates during the first quarter of 2010 as compared to the first quarter of 2009. The decrease is also related to the write-off of unamortized deferred financing costs and waiver fees related to the amendment to our credit facility during the first quarter of 2009.

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 $17.3 million of unrealized gains on derivative instruments in other income and expense during the three months ended March 31, 2010 compared to $5.5 million of unrealized losses for the comparable prior year period.

Income (Loss) From Unconsolidated Affiliates. Income from unconsolidated affiliates during the three months ended March 31, 2009 primarily related to earnings from our tubular supply subsidiary.

Income Tax Benefit (Expense). Due to our continued losses, we were required by the “more likely than not” threshold for assessing the realizability of deferred tax assets to record a valuation allowance for our deferred tax assets beginning with the second quarter of 2007. Our income tax expense (benefit) for the three months ended March

31, 2010 and 2009 of $275,000 and $(583,000), respectively, relates only to DHS, as no benefit was provided for our net operating losses.

Non-Controlling Interest. Non-controlling interest represents the minority investors’ proportionate share of the income or loss of DHS in which they hold an interest. During the three months ended March 31, 2010 and 2009, DHS reported significant losses from low rig utilization rates which resulted in a non-controlling interest credit to earnings.

Historical Cash Flow

Our cash flow used in operating activities increased from $5.9 million for the three months ended March 31, 2009 to cash used in operating activities of $16.9 million for the three months ended March 31, 2010. The significant decrease in cash flow is primarily due to the payment of the offshore litigation payable partially offset by higher commodity prices. Our net cash used in investing activities decreased to $4.0 million for the three months ended March 31, 2010 compared to net cash used in investing activities of $48.8 million for the comparable prior year period primarily due to our significant reduction in drilling and acquisition activity. Cash provided by financing activities decreased from $13.8 million for the three months ended March 31, 2009 to cash used in financing activities of $31.0 million for the current year period. During the three months ended March 31, 2009, $14.9 million of cash was provided by the proceeds from the sale of offshore litigation contingent payments. 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, 2010 and 2009 were as follows (in thousands):


	2010		2009
CAPITAL AND EXPLORATION EXPENDITURES:

Property acquisitions:
Unproved	$	1	$	1,631
Proved		-		-
Oil and gas properties		10,373		29,421
Drilling and trucking equipment		950		691
Pipeline and gathering systems		4,095		5,747

Total ⁽¹⁾	$	15,419	$	37,490


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

Contractual and Long-term Debt Obligations

7% Senior Unsecured Notes, due 2015

On March 15, 2005, we issued 7% senior unsecured notes for an aggregate amount of $150.0 million which pay interest semi-annually on April 1 and October 1 and mature in 2015. The notes were issued at 99.50% of par and the associated discount is being amortized to interest expense over the term of the notes. The indenture governing the notes contains various restrictive covenants that may limit our ability to, among other things, incur additional indebtedness, make certain investments, sell assets, consolidate, merge or transfer all or substantially all of our assets and the assets of our restricted subsidiaries. These covenants may limit management’s discretion in operating our business.

3 ³ / 4 % Senior Convertible Notes, due 2037

On April 25, 2007, we issued $115.0 million aggregate principal amount of 3 ³ / 4 % Senior Convertible Notes due 2037 (the “Notes”) for net proceeds of $111.6 million after underwriters’ discounts and commissions of approximately $3.4 million. The remaining discount will be amortized through May 2012 when the holders of the Notes can first require us to purchase all or a portion of the Notes. The Notes bear interest at a rate of 3 ³ / 4 % per annum, payable semi-annually in arrears, on May 1 and November 1 of each year, beginning November 1, 2008. Combined with the amortization of debt discount, the Notes have an effective interest rate of approximately 7.6% and 8.2% with total interest costs of $2.2 million and $3.2 million for the three month periods ended March 31, 2010 and 2009, respectively. The Notes will mature on May 1, 2037 unless earlier converted, redeemed or repurchased. The holders of the Notes have the right to require us to purchase all or a portion of the Notes on May 1, 2012, May 1, 2017, May 1, 2022, May 1, 2027, and May 1, 2032. The Notes will be convertible at the holder’s option, in whole or in part, at an initial conversion rate of 32.9598 shares of common stock per $1,000 principal amount of Notes (equivalent to a conversion price of approximately $30.34 per share) at any time prior to the close of business on the business day immediately preceding the final maturity date of the Notes, subject to prior repurchase of the Notes. The conversion rate may be adjusted from time to time in certain instances. Upon conversion of a Note, we will have the option to deliver shares of our common stock, cash or a combination of cash and shares of our common stock for the Notes surrendered. In addition, following certain fundamental changes that occur prior to maturity, we will increase the conversion rate for a holder who elects to convert its Notes in connection with such fundamental changes by a number of additional shares of common stock. Although the Notes do not contain any financial covenants, the Notes contain covenants that require us to properly make payments of principal and interest, provide certain reports, certificates and notices to the trustee under various circumstances, cause our wholly-owned subsidiaries to become guarantors of the debt, maintain an office or agency where the Notes may be presented or surrendered for payment, continue our corporate existence, pay taxes and other claims, and not seek protection from the debt under any applicable usury laws.

Credit Facility – Delta

Pursuant to a scheduled redetermination effective as of April 26, 2010, among other changes more fully described in Note 7, “Long Term Debt” to the accompanying financial statements, the borrowing base under our credit agreement was reduced to $145.0 million; however, the requirement to maintain the $20.0 million of minimum availability was deleted such that the effective credit capacity was reduced by $20.0 million.

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

The Credit Agreement includes terms and covenants that place limitations on certain types of activities, including restrictions or requirements with respect to additional debt, liens, asset sales, hedging activities, investments, dividends, mergers and acquisitions, and includes various financial covenants.

Under certain conditions, amounts outstanding under the credit facility may be accelerated. Bankruptcy and insolvency events with respect to us or certain of our subsidiaries would result in an automatic acceleration of the indebtedness under the credit facility. Subject to notice and cure periods in certain cases, other events of default under the credit facility would result in acceleration of the indebtedness at the option of the lending banks. Such other events of default include non-payment, breach of warranty, non-performance of obligations under the credit facility (including financial covenants), default on other indebtedness, certain pension plan events, certain adverse judgments, change of control, and a failure of the liens securing the credit facility.

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

Credit Facility – DHS

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

Other Contractual Obligations

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

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

We had a net derivative liability of $9.7 million at March 31, 2010. The ultimate settlement amounts of these derivative instruments are unknown because they are subject to continuing market fluctuations. See Item 3. “Quantitative and Qualitative Disclosures about Market Risk” for more information regarding our derivative instruments.

Critical Accounting Policies and Estimates

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

Successful Efforts Method of Accounting

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

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

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

Reserve Estimates

Estimates of gas and oil reserves, by necessity, are projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of gas and oil that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable gas and oil reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions governing future gas and oil prices, the availability and cost of capital to develop the reserves, future operating costs, severance taxes, development costs and workover gas costs, all of which may in fact vary considerably from actual results. The future drilling costs associated with reserves assigned to proved undeveloped locations may ultimately increase to an extent that these reserves may be later determined to be uneconomic. For these reasons, estimates of the economically recoverable quantities of gas and oil attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected therefrom may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of our gas and oil properties and/or the rate of depletion of the gas and oil properties. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material.

Impairment of Gas and Oil Properties

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

Given the complexities associated with gas and oil reserve estimates and the history of price volatility in the gas and oil markets, events may arise that would require us to record an impairment of the recorded book values associated with gas and oil properties. For developed properties, the review consists of a comparison of the carrying value of the

asset with the asset’s expected future undiscounted cash flows without interest costs. For the three months ended March 31, 2010, the expected future undiscounted cash flows of the assets exceeded the carrying value of the corresponding asset and as such no impairment provision was recognized.

For unproved properties, the need for an impairment charge is based on our plans for future development and other activities impacting the life of the property and our ability to recover our investment. When we believe the costs of the unproved property are no longer recoverable, an impairment charge is recorded based on the estimated fair value of the property. As a result of such assessment, we recorded impairment provisions attributable to unproved properties of approximately $0.9 million for the three months ended March 31, 2010, including $0.6 million related to our Delores River prospect and $0.3 million related to our Haynesville shale prospect. These impairments are included within dry hole costs and impairments in the accompanying statement of operations for the three months ended March 31, 2010.

During the remainder of 2010, we are continuing to evaluate certain proved and unproved properties on which favorable or unfavorable results or fluctuations in commodity prices may cause us to revise in future periods our estimates of future cash flows from those properties. Such revisions of estimates could require us to record an impairment provision in the period of such revisions.

Commodity Derivative Instruments and Hedging Activities

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

All derivative instruments are recorded on the balance sheet at fair value which must be estimated using complex valuation models. We recognize mark-to-market gains and losses in current earnings instead of deferring those amounts in accumulated other comprehensive income. As of March 31, 2010, we had a total of seven oil and gas derivative contracts outstanding. The fair value of our oil derivative instruments was a liability of $13.4 million and the fair value of our gas derivative instruments was an asset of $3.7 million at March 31, 2010. 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, 2010. The pre-credit risk adjusted fair value of our net derivative liabilities as of March 31, 2010 was $10.5 million. A credit risk adjustment of $0.8 million to the fair value of the derivatives reduced the reported amount of the net derivative liabilities on our consolidated balance sheet to $9.7 million.

Asset Retirement Obligation

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

Deferred Tax Asset Valuation Allowance

The Company uses the asset and liability method of accounting for income taxes. Under the asset and liability method, deferred tax assets and liabilities are recognized for the estimated future tax effects attributable to temporary differences and carryforwards. Ultimately, realization of a deferred tax benefit depends on the existence of sufficient taxable income within the carryback/carryforward period to absorb future deductible temporary differences or a carryforward. In assessing the realizability of deferred tax assets, management must consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. Management considers all available evidence (both positive and negative) in determining whether a valuation allowance is required. Such evidence includes the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies

in making this assessment, and judgment is required in considering the relative weight of negative and positive evidence. As a result of management’s current assessment, we maintain a significant valuation allowance against our deferred tax assets. We will continue to monitor facts and circumstances in our reassessment of the likelihood that operating loss carryforwards and other deferred tax attributes will be utilized prior to their expiration. As a result, we may determine that the deferred tax asset valuation allowance should be increased or decreased. Such changes would impact net income through offsetting changes in income tax expense or benefit.

Recently Issued and Adopted Accounting Pronouncements

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

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, 2010:

Net Fair Value

Remaining

Asset (Liability) at

Commodity

Volume

Fixed Price

Term

Index Price

March 31, 2010

(In thousands)

Crude oil

1,000

Bbls / Day

$ 52.25

Apr ’10

- Dec ’10

NYMEX – WTI

(8,704)

Crude oil

500

Bbls / Day

$ 57.70

Jan ’11

- Dec ’11

NYMEX – WTI

(4,688)

Natural gas

6,000

MMBtu / Day

$ 5.720

Apr ’10

- Dec ’10

NYMEX – HHUB

2,370

Natural gas

15,000

MMBtu / Day

$ 4.105

Apr ’10

- Dec ’10

CIG

577

Natural gas

5,367

MMBtu / Day

$ 3.973

Apr ’10

- Dec ’10

CIG

Natural gas

12,000

MMBtu / Day

$ 5.150

Jan ’11

- Dec ’11

CIG

671

Natural gas

3,253

MMBtu / Day

$ 5.040

Jan ’11

- Dec ’11

CIG

(9,700

)

Assuming production and the percent of oil and gas sold remained unchanged for the three months ended March 31, 2010, a hypothetical 10% decline in the average market price we realized during the three months ended March 31, 2010 on unhedged production would reduce our oil and natural gas revenues by approximately $3.4 million.

Interest Rate Risk

We were subject to interest rate risk on $176.3 million of variable rate debt obligations at March 31, 2010. The annual effect of a 10% change in interest rates on the debt would be approximately $1.0 million.

Item 4. Controls and Procedures

Disclosure Controls and Procedures

Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rule 13a-15(e) under the Exchange Act. Based on this evaluation, our management, including our principal executive officer and our principal financial officer, concluded that our disclosure controls and procedures were effective as of March 31, 2010, to ensure that information required to be disclosed by us in the reports filed or submitted by us under the Exchange Act (i) is recorded, processed, summarized and reported within the time period specified in SEC rules and forms, and (ii) is accumulated and communicated to our management, including our principal executive officer and our principal financial officer, as appropriate to allow appropriate decisions on a timely basis regarding required disclosure.

Internal Control over Financial Reporting

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

PART II - OTHER INFORMATION

Item 1. Legal Proceedings.

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

Item 1A. Risk Factors

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

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

The table below provides a summary of our purchases of our own common stock during the three months ended March 31, 2010.


							Maximum Number
					Total Number of		(or Approximate Dollar
					Shares (or Units)		Value) of Shares
	Total Number of		Average Price		Purchased as Part of		(or Units) that May Yet
	Shares (or Units)		Paid Per Share		Publicly Announced		Be Purchased Under
Period	Purchased (1)		(or Unit) (2)		Plans or Programs (3)		the Plans or Programs (3)
January 1 – January 31, 2010		1,985		$1.04		-		-
February 1 – February 28, 2010		-		-		-		-
March 1 – March 31, 2010		-		-		-		-

Total		1,985		$1.04		-		-

	(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.

Amendment to Credit Agreement – DHS

On April 1, 2010, DHS amended its existing credit facility with Lehman Commercial Paper, Inc. and renegotiated certain terms of the agreement including obtaining waivers for all covenant violations through March 31, 2010. The terms of the amended agreement required principal payments of $7,677,713 paid on April 1, 2010 and $2,000,000 paid on May 1, 2010, with $2,000,000 remaining principal payments due on each of August 1, 2010, November 1, 2010 and January 1, 2011, and a $5,000,000 principal payment on each of April 1, 2011 and July 1, 2011 with the remaining balance of $57,589,787 due at maturity (August 31, 2011). In addition to the required payments, DHS is required to prepay any remaining outstanding principal with the “Net Cash Proceeds from any Asset Sale,” as defined by the credit facility, and any such prepayment shall be applied to, first, prepay the immediately succeeding Scheduled Installment in full, second, prepay all interest payable on the immediately succeeding Interest Payment Date in full, third, pay the second succeeding Scheduled Installment in full and fourth, prepay the remaining principal balance of the remaining loans. DHS is also required to prepay the principal amount of the loans in an amount equal to 75% of the “Excess Cash Flow,” as defined by the credit facility, for such fiscal quarter. The only financial covenant remaining in the DHS credit agreement is a minimum EBITDA covenant of $100,000 for the three months ended March 31, 2010, $250,000 for the three months ending June 30, 2010, $1,000,000 for the three months ending September 30, 2010 and $1,500,000 for each subsequent quarter. In addition, the amendment imposed capital expenditures limitations of $1,200,000 for any fiscal quarter. Notwithstanding the $1,200,000 per quarter limitation on capital expenditures, the amendment imposes aggregate capital expenditure limitations of $3,500,000 for fiscal year 2010 and $2,330,137 for fiscal year 2011. The interest rate has been adjusted to LIBOR plus 625 basis points, subject to a LIBOR floor rate of 2.75%. DHS was in compliance with its amended minimum EBITDA covenant for the three months ended March 31, 2010.

The foregoing description of the DHS amendment to its credit facility with Lehman Commercial Paper, Inc. does not purport to be complete and is qualified in its entirety by reference to the DHS amendment to its credit facility with Lehman Commercial Paper, Inc., which is filed as Exhibit 10.1 hereto and incorporated by reference herein.

Item 6. Exhibits.

Exhibits are as follows:

	10.1		Waiver and Amendment No. 2 to Amended and Restated Credit Agreement, dated as of April 1, 2010, among DHS Holding Company and Lehman Commercial Paper, Inc. 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.

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/ John R. Wallace
		John R. Wallace, President and
		Chief Operating Officer



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



Date: May 10, 2010

EXHIBIT INDEX:

	10.1		Waiver and Amendment No. 2 to Amended and Restated Credit Agreement, dated as of April 1, 2010, among DHS Holding Company and Lehman Commercial Paper, Inc. 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.

TABLE OF CONTENTS

Part I Financial Information Item 1. Consolidated Financial Statements Item 2. Management S Discussion and Analysis Of Financial Condition and Results Of Operations Item 3. Quantitative and Qualitative Disclosures About Market Risk Item 4. Controls and Procedures Part II - Other Information Item 1. Legal Proceedings Item 1A. Risk Factors Item 2. Unregistered Sales Of Equity Securities and Use Of Proceeds Item 5. Other Information Item 6. Exhibits

PARR 10-Q Quarter ended March 31, 2010