UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-K

(Mark One)

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

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

Commission File No. 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 (Address of principal executive offices)		80202 (Zip Code)

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

Securities registered under Section 12(b) of the Act:

Title of each class		Name of each exchange on which registered
Common Stock, $0.01 par value		NASDAQ Capital Market

Securities registered under to Section 12(g) of the Act: None

     Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þ

     Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ

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

     Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). o Yes o No

     Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

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

Large accelerated filer o		Accelerated filer þ		Non-accelerated filer o		Smaller reporting company o
				(Do not check if a smaller reporting company)

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

     As of June 30, 2010, the aggregate market value of voting stock held by non-affiliates of the registrant was approximately $159.7 million, based on the closing price of the Common Stock on the NASDAQ National Market of $0.86 per share. As of March 15, 2011, 286,125,705 shares of registrant’s Common Stock, $0.01 par value, were issued and outstanding.

     Documents incorporated by reference: The information required by Part III of this Form 10-K is incorporated by reference to the Company’s Definitive Proxy Statement for the Company’s 2010 Annual Meeting of Stockholders.

 

 

TABLE OF CONTENTS

				PAGE
		PART I
Item 1. BUSINESS					3
Item 1A. RISK FACTORS					12
Item 1B. UNRESOLVED STAFF COMMENTS					25
Item 2. PROPERTIES					26
Item 3. LEGAL PROCEEDINGS					31
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS					31
Item 4A. DIRECTORS AND EXECUTIVE OFFICERS					32
		PART II
Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES					35
Item 6. SELECTED FINANCIAL DATA					36
Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS					36
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK					59
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA					60
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE					60
Item 9A. CONTROLS AND PROCEDURES					60
Item 9B. OTHER INFORMATION					61
		PART III
Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE					61
Item 11. EXECUTIVE COMPENSATION					61
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS					61
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE					61
Item 14. PRINCIPAL ACCOUNTING FEES AND SERVICES					61
		PART IV
Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES					62
EX-10.16
EX-10.25
EX-10.36
EX-10.37
EX-10.38
EX-21.1
EX-23.1
EX-23.2
EX-31.1
EX-31.2
EX-32.1
EX-32.2
EX-99.1

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

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

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 Annual Report on Form 10-K are forward-looking statements. The forward-looking statements may appear in a number of places and include statements with respect to, among other things: business objectives and strategies, including our focus on the Vega Area of the Piceance Basin, as well as statements regarding intended value creation; operating strategies; our expectation that we will have adequate cash from operations, credit facility borrowings and other capital sources to satisfy our obligations under our senior credit facility, and to meet future debt service, capital expenditure and working capital requirements; expected announcements of 2011 drilling plans and capital expenditure budget; the availability of capital to fund our working capital needs, our drilling and leasehold acquisition programs, our required payments under our senior credit facility, or any required redemption of our convertible notes; anticipated operating costs, including improvements in our anticipated finding and development costs and overall per unit operating and development costs due to the new fracture stimulation design; impact on costs from use of subsurface injection for water disposal; potential sources of long-term capital or potential corporate transactions such as a sale of the company; 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); 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 Critical Accounting Policies and Risk Factors, as well as other possible factors not listed, could cause actual results to differ materially from those expressed in forward-looking statements, including, without limitation, the following:

	•		deviations in and volatility of the market prices of both crude oil and natural gas produced by us;
	•		the availability of capital on an economic basis, or at all, to fund our required payments under our senior credit facility, mandatory redemption of our convertible notes, our working capital needs, and drilling and leasehold acquisition programs, including through potential joint ventures and asset monetization transactions;
	•		lower natural gas and oil prices negatively affecting our ability to borrow or raise capital, or enter into joint venture arrangements and potentially requiring accelerated repayment of amounts borrowed under our revolving credit facility;
	•		declines in the values of our natural gas and oil properties resulting in write-downs;
	•		the impact of current economic and financial conditions on our ability to raise capital;
	•		a continued imbalance in the demand for and supply of natural gas in the U.S. as a result of depressed general economic conditions;
	•		the results of exploratory drilling activities;

	•		the outcome of the ongoing investigation of DHS and certain of its employees, among others, by the Office of the Inspector General, Office of Investigations, of the Export-Import Bank of the United States, and the U.S. Department of Justice;
	•		expiration of oil and natural gas leases that are not held by production;
	•		uncertainties in the estimation of proved reserves and in the projection of future rates of production;
	•		timing, amount, and marketability of production;
	•		third party curtailment, or processing plant or pipeline capacity constraints beyond our control;
	•		our ability to find, acquire, develop, produce and market production from new properties;
	•		the availability of borrowings under our credit facility;
	•		effectiveness of management strategies and decisions;
	•		the strength and financial resources of our competitors;
	•		climatic conditions;
	•		changes in the legal and/or regulatory environment and/or changes in accounting standards policies and practices or related interpretations by auditors or regulatory entities;
	•		unanticipated recovery or production problems, including cratering, explosions, fires and uncontrollable flows of oil, gas or well fluids;
	•		the timing, effects and success of our acquisitions, dispositions and exploration and development activities;
	•		our ability to fully utilize income tax net operating loss and credit carry-forwards; and
	•		the ability and willingness of counterparties to our commodity derivative contracts, if any, to perform their obligations.

Many of these factors are beyond our ability to control or predict. These factors are not intended to represent a complete list of the general or specific factors that may affect us.

All forward-looking statements speak only as of the date made. All subsequent written and oral forward-looking statements attributable to us, or persons acting on our behalf, are expressly qualified in their entirety by the cautionary statements above. Except as required by law, we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which it is made or to reflect the occurrence of anticipated or unanticipated events or circumstances.

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

PART I

Item 1. Business

General

Delta Petroleum Corporation (“Delta” or the “Company”) is an independent oil and gas company engaged primarily in the exploration for, and the acquisition, development, production, and sale of, natural gas and crude oil. Our core area of operations is the Rocky Mountain Region, where the majority of our proved reserves, production and long-term growth prospects are located. We have a significant development drilling inventory that consists of proved and unproved locations, the majority of which are located in our Rocky Mountain development projects.

Delta was incorporated in Colorado in 1984. Effective January 31, 2006, Delta reincorporated in Delaware, thereby changing our state of incorporation from Colorado to Delaware. Our principal executive offices are located at 370 17th Street, Suite 4300, Denver, Colorado 80202. Our telephone number is (303) 293-9133. We also maintain a website at http://www.deltapetro.com which contains information about us. Our website is not part of this Form 10-K. Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports are accessible free of charge at our website.

Recent Developments

Sale of Non-Core Assets

As a result of the strategic alternatives process that we commenced in late 2009, on July 30, 2010, we completed the $130.0 million sale of certain non-core properties to Wapiti Oil & Gas, L.L.C. (“Wapiti”). In conjunction with the completion of this transaction (the “Wapiti Transaction”), we repaid $108.5 million of amounts borrowed under our credit facility, and our borrowing base under the credit facility was reduced to $35.0 million.

Amended Credit Facility

On December 29, 2010, we amended and restated our credit agreement (the “MBL Credit Agreement”) whereby the former lenders assigned their interests to Macquarie Bank Limited (“MBL”). The MBL Credit Agreement provides for a revolving loan and a term loan each with a maturity date of January 31, 2012. The revolving loan has an initial borrowing base of $30.0 million and the term loan had an initial commitment of $20.0 million subject to a development plan that must be approved by MBL. See Note 7, “Long-Term Debt” to the accompanying consolidated financial statements.

On March 14, 2011, we entered into an amendment to the MBL Credit Agreement that increased the availability under the term loan at the time from $6.2 million to $25.0 million, and doesn’t require repayments of the term loan until the January 2012 maturity date. Specifically, among other changes, the amendment provided for an increase in the term loan commitment from $20.0 million to $25.0 million and removed the requirement that advances under the term loan be subject to approval of a development plan. In addition, so long as Delta is not in default under the MBL Credit Agreement, Delta is not required to comply with certain cash management provisions, including the previous requirement to repay any term loan advances outstanding on a monthly basis with 100% of net operating cash flows. See Note 20, “Subsequent Events” to the accompanying consolidated financial statements.

Proceeds from the Wapiti Transaction and the MBL Credit Agreement were used to substantially reduce amounts outstanding under our prior credit facility, as well as to extend the date from January 15, 2011 to January 31, 2012, and to fund capital expenditures.

Overview and Strategy

Our corporate strategy is to focus on increasing stockholder value, specifically by creating incremental value from our core asset, the Vega Area of the Piceance Basin.

Maintain a disciplined operational focus on our core asset

During 2010, we streamlined our business to focus on our core asset, the Vega Area of the Piceance Basin. As of December 31, 2010, the Vega Area comprised approximately 84% of our proved reserves and with its undeveloped leasehold potential comprises virtually all of our long-term growth prospects. We divested of many of our non-core assets and interests in producing fields in Texas and other non-core areas which allowed us to reduce our overhead and operating expenses, while also providing capital to deploy in the Vega Area. While we retain working interests in certain fields outside our core area, they are now operated by third parties and we expect limited capital expenditures in these areas in the future. We will continue to evaluate the divestiture of our remaining working interest in these non-operated assets.

Continue to utilize superior completion methodology to maximize the reserves per well

The Piceance Basin generally has consistent and predictable geology. The consistent and predictable geology throughout the Vega Area allows us to benefit from meaningful economies of scale in both our drilling and completion activities. During the past year we have utilized a larger well completion design that has improved our initial production rates and our expected reserve recovery per well. The revision to the completion method is in the fracture stimulation procedure, which is much larger than prior fracture stimulation designs. The new fracture stimulation design is referred to as “generation four” or “Gen IV” as it is the fourth iteration of our fracture stimulation design for wells in the Vega Area. The improved frac design increased our gross average well recoveries from 1.15 Bcfe to 1.60 Bcfe. This incremental improvement in reserves per well is expected to provide for a lower finding and development cost per Mcfe, which equates to lower overall per unit operating and development costs.

Maintain lower operating and overhead costs

In the latter half of 2010 we were able to reduce both our operating and overhead costs. As a result of the divestiture of non-core assets, we were able to reduce our staff and maintain a team solely focused on the development of Vega which enabled us to reduce our general and administrative expenses. We also substantially reduced our operating costs, particularly in the fourth quarter, both on an absolute basis and on a per Mcfe basis. Much of the operating cost reduction was achieved by using the water we produce from our wells in the completion activity. Water disposal is the largest single operating expense in the Vega Area. This efficient utilization of our produced water enabled us to significantly reduce our water disposal costs for the fourth quarter. Subsequent to year end we terminated a contract with a water treatment service provider for the Vega Area, which resulted in the elimination of an ongoing future expense of approximately $500,000 per month for a ten year period in exchange for a one-time payment of $1.5 million. The termination of this contract allows us to use alternative methods of water treatment and disposal that are more suitable for the amount of water that is currently being produced at the field, and management believes that the use of subsurface injection for water disposal is a much more viable and cost effective approach at the present time. In addition to the water disposal wells we currently utilize, we anticipate converting four wells in the field to water disposal wells and possibly drilling another. The existing wells that are targeted for water disposal are old wells that have minimal or no gas production. We are currently in the process of obtaining the necessary permits to inject our produced water into the four existing wells, which will help maintain our overall operating costs at the reduced levels.

Quantify reserve potential in the deeper zones beneath the Williams Fork section

During the fourth quarter of 2010 we spud a well in the Vega Area to drill to deeper, potentially productive, zones below the Williams Fork section of the Mesa Verde formation. Our interest in testing the deeper zones originated with our understanding that other third party operators in the Piceance Basin with analogous geology had experienced successful tests in formations beneath the Williams Fork. We began completion activities on the deep test well subsequent to year end 2010. We have also spud a second well that will target the section immediately beneath the

Williams Fork. As the drilling and completion activities are finished we will continue our evaluation of the reserve potential, if any, in these deeper zones.

Solidify our acreage position at the Vega Area

Our leasehold position at the Vega Area totals approximately 22,375 net acres. Over 86% of this acreage is not subject to lease expiration as it is held by production (HBP). During 2011, we have approximately 1,810 net acres subject to primary term expiration. However, approximately 1,600 net acres which are subject to 2011 expiration will be converted to HBP with the drilling and completion of a single well. We are planning on drilling this well during 2011 and will make all financially prudent efforts to limit other future lease expirations at the Vega Area.

Maximize Stockholder Value

We are currently exploring a variety of options to maximize value to our stockholders. We intend to continue to focus on increasing our reserves, production and revenues through improved frac technology and exploratory efforts at our Vega acreage, while at the same time reducing our expenses on a per unit basis. We believe that if we are able to meet these objectives, it is likely that opportunities to further increase shareholder value will become available to us, including, without limitation, access to capital markets, sales of assets for a premium or a sale of the entire company.

Experienced management and operational team

Our senior management team has, on average, over 25 years of experience in the oil and gas industry. Our management team is supported by an active board of directors with extensive experience in the capital markets and in the oil and gas industry. We retain highly experienced personnel in our production, drilling and land management teams. Our senior managers in our technical teams all have decades of experience in their respective disciplines.

Operations

During the year ended December 31, 2010, we were primarily engaged in two industry segments, namely the acquisition, exploration, development, and production of oil and natural gas properties and related business activities, and contract oil and natural gas drilling operations.

Oil and Gas Reserves

The following table presents reserve and production information regarding our primary oil and natural gas areas of operation as of December 31, 2010:

		Oil				Natural Gas				Total				2010 Production
		(Mbbl)				(Mmcf)				(Mmcfe)				(MMcfe/d) (1)
Proved Developed
Rocky Mountain Region			733				108,275				112,670				35.1
Gulf Coast Region			844				4,215				9,281				8.8
Other			282				44				1,737				2.0
Total			1,859				112,534				123,688				45.9
Proved Undeveloped
Rocky Mountain Region(2)			61				10,145				10,511
Gulf Coast Region			—				—				—
Other			—				—				—
Total			61				10,145				10,511
Total Proved Reserves(3)			1,920				122,679				134,199

We intend to focus our 2011 capital spending on the development of our core area of operations in the Rocky Mountains, the Piceance Basin, to the extent that cash on hand, cash flows and available capital through our credit facility, joint ventures or asset sales are adequate to fund our plans.

Our oil and gas operations have been comprised primarily of production of oil and natural gas, drilling exploratory and development wells and related operations and acquiring and selling oil and natural gas properties. Directly or through wholly-owned subsidiaries, and through Amber Resources Company of Colorado (“Amber”), our 91.68% owned subsidiary, and CRB Partners, LLC (“CRBP”), we currently own producing and non-producing oil and natural gas interests, undeveloped leasehold interests and related assets in ten states and interests in a producing Federal unit offshore California. We intend to continue our emphasis on the drilling of development wells, primarily in the Piceance Basin of Colorado.

We have oil and gas leases with governmental entities and other third parties who enter into oil and gas leases or assignments with us in the regular course of our business. We have no material patents, licenses, franchises or concessions that we consider significant to our oil and gas operations. The nature of our business is such that it is not seasonal, we do not engage in any research and development activities and we do not maintain or require a substantial amount of products, customer orders or inventory. Our oil and gas operations are not subject to renegotiations of profits or termination of contracts at the election of the federal government. We operate the properties that comprise the majority of our production and reserves, giving us more ability to control the costs incurred.

Contract Drilling Operations

Through a series of transactions in 2004 and 2005, we acquired and now own an interest in DHS, a contract drilling company that is headquartered in Casper, Wyoming. During the second quarter of 2006, DHS engaged in a reorganization transaction pursuant to which it became a subsidiary of DHS Holding Company, a Delaware corporation, and the Company’s ownership interest became an interest in DHS Holding Company. References to DHS herein shall be deemed to include both DHS Holding Company and DHS, unless the context otherwise requires. DHS is a consolidated entity of Delta. Delta currently owns a 49.8% interest in DHS Holding Company, controls the

board of directors of DHS and has priority access to all of DHS’s drilling rigs. At December 31, 2010, DHS owned 18 drilling rigs with depth ratings of approximately 10,000 to 25,000 feet, of which 10 are currently under contract.

The following table presents our average drilling revenue per day and rigs available for service for the years ended December 31, 2010, 2009 and 2008:

		Years Ended December 31,
		2010				2009				2008
Average number of rigs owned during period			18				18.5				16.7
Total rig days(1)			2,805				854				5,032
Average drilling revenue per day		$	15,511			$	16,730			$	18,188

During 2009, we experienced a significant reduction in rig utilization from 2008 (as reflected in rig days shown above) as operators cut their capital budgets and suspended drilling operations in response to the low commodity price environment that existed for the majority of the year. In view of the abundance of drilling rig capacity during 2009, drilling day rates were lower in 2009 than 2008. With Rockies gas prices recently increasing to more favorable levels, drilling day rates stabilized during 2010 and rig days under contract improved as compared to 2009.

DHS also owns 100% of Chapman Trucking, which was acquired in November 2005. Employing its 28 trucks and 38 trailers, Chapman provides moving services for DHS and for third party drilling rigs. Chapman Trucking continues to market trucking services in the Casper, Wyoming area.

Subsequent to year-end, the Board of Directors of DHS engaged transaction advisors to commence a strategic alternatives process, focused on a sale of the company or substantially all of its assets. There can be no assurance that the terms offered by a potential buyer, if any, will be acceptable to the DHS shareholders. Additionally, the consummation of certain transactions are subject to the approval of DHS’s senior lender and the proceeds received will be required to be used to pay down amounts outstanding under its DHS credit facility.

Contracts — Drilling

We earn our DHS contract drilling revenues under day work or turnkey contracts which vary depending upon the rig employed, equipment and services supplied, geographic location, term of the contract, competitive conditions and other variables. Our contracts generally provide for a basic day rate during drilling operations, with lower rates or no payment for periods of equipment breakdown. When a rig is mobilized or demobilized from an operating area, a contract may provide for different day rates during the mobilization or demobilization. Turnkey contracts are accounted for on a percentage-of-completion basis. Contracts to employ our drilling rigs have a term based on a specified period of time or the time required to drill a specified well or number of wells. The contract term in some instances may be extended by the customer exercising options for the drilling of additional wells or for an additional term, or by exercising a right of first refusal. Most contracts permit the customer to terminate the contract at the customer’s option without paying a termination fee.

Markets

The principal products produced by us are crude oil and natural gas. The products are generally sold at the wellhead to purchasers in the immediate area where the product is produced. The principal markets for oil and natural gas are refineries and transmission companies which have facilities near our producing properties.

DHS’s principal market is the drilling of oil and natural gas wells for us and others in the Rocky Mountain and onshore Gulf Coast Regions. To the extent that DHS rigs are not fully utilized by us, DHS typically contracts with other oil and gas companies on a single-well basis, with optional extensions.

Distribution

Oil and natural gas produced from our wells is normally sold to various purchasers as discussed below. Oil is picked up and transported by the purchaser from the wellhead. In some instances we are charged a fee for the cost of transporting the oil which is deducted from or accounted for in the price paid for the oil. Natural gas wells are connected to pipelines generally owned by the natural gas purchasers. A variety of pipeline transportation charges are usually included in the calculation of the price paid for the natural gas.

Competition

We encounter strong competition from major oil companies and independent operators in acquiring properties and leases for the exploration for, and the development and production of, natural gas and crude oil. Competition is particularly intense with respect to the acquisition of desirable undeveloped oil and gas leases. The principal competitive factors in the acquisition of undeveloped oil and gas leases include the availability and quality of staff and data necessary to identify, investigate and purchase such leases, and the financial resources necessary to acquire and develop such leases. Many of our competitors have substantially greater financial resources, and more fully developed staffs and facilities than ours. In addition, the producing, processing and marketing of natural gas and crude oil are affected by a number of factors which are beyond our control, the effect of which cannot be accurately predicted. See “Item 1A. Risk Factors.”

To the extent that the DHS drilling rigs are not fully utilized by us for any reason, DHS seeks to drill wells for our competitors in the oil and gas business in order to achieve revenues to sustain its operations. To a large degree, the success of DHS’s business is dependent upon the level of capital spending by oil and gas companies for exploration, development and production activities. Decreases in the price of natural gas and oil, particularly natural gas, during late 2008 and through late 2009 have had a material adverse impact on exploration, development, and production activities by all of DHS’s customers, including us, which materially affected and continue to affect DHS’s financial position, results of operations and cash flows.

Raw Materials

The principal raw materials and resources necessary for the exploration and development of natural gas and crude oil are leasehold prospects under which natural gas and oil reserves may be discovered, drilling rigs and related equipment to drill for and produce such reserves and knowledgeable personnel to conduct all phases of gas and oil operations. Decreases in demand for oil and gas in late 2008 through late 2009 have resulted in equipment and supplies used in our business being available from multiple sources.

Major Customers

During the year ended December 31, 2010, we had two companies that individually accounted for 45% and 18% of our total oil and gas sales. Although a substantial portion of production is purchased by these major customers, we do not believe the loss of any one or several customers would have a material adverse effect on our business as other customers or markets would be accessible to us. See Note 3 to our accompanying consolidated financial statements for additional information.

During the year ended December 31, 2010, DHS had two companies that individually accounted for 37% and 17% of total drilling revenues other than Delta. Our recent and projected reduced level of drilling activities and the loss of other customers has had and will have a material adverse effect on DHS if there is a sustained period of lower prices of natural gas and oil as discussed above.

Government Regulation of the Oil and Gas Industry

General

Our business is affected by numerous federal, state and local laws and regulations, including those relating to protection of the environment, public health, and worker safety. The technical requirements of these laws and

regulations may result in imposition of substantial liabilities, including civil and criminal penalties. In addition, certain laws impose strict liability for environmental remediation and other costs. Changes in any of these laws and regulations could have a material adverse effect on our business. In light of the many uncertainties with respect to future laws and regulations, we cannot predict the overall effect of such laws and regulations on our future operations. Nevertheless, the trend in environmental regulation is to place more restrictions and controls on activities that may affect the environment, and future expenditures for environmental compliance or remediation may be substantially more than we expect.

We believe that our operations comply in all material respects with all applicable laws and regulations and that the existence and enforcement of such laws and regulations have no more restrictive effect on our method of operations than on other similar companies in the energy industry. Accidental leaks and spills requiring cleanup may occur in the ordinary course of business, and the costs of preventing and responding to such releases are embedded in the normal costs of doing business. In addition to the costs of environmental protection associated with our ongoing operations, we may incur unforeseen investigation and remediation expenses at facilities we formerly owned and operated or at third-party owned waste disposal sites that we have used. Such expenses are difficult to predict and may arise at sites operated in compliance with past industry standards and procedures.

The following discussion contains summaries of certain laws and regulations and is qualified in its entirety by the foregoing.

Environmental regulation

Our operations are subject to numerous federal, state, and local environmental laws and regulations concerning our oil and gas operations, products and other activities. In particular, these laws and regulations govern, among other things, the issuance of permits associated with exploration, drilling and production activities, the types of activities that may be conducted in environmentally protected areas such as wetlands and wildlife habitats, the release of emissions into the atmosphere, the discharge and disposal of regulated substances and waste materials, offshore oil and gas operations, the reclamation and abandonment of well and facility sites, and the remediation of contaminated sites.

Governmental approvals and permits are currently, and will likely in the future be, required in connection with our operations, and in the construction and operation of gathering systems, storage facilities, pipelines and transportation facilities (midstream operations). The success of obtaining, and the duration of, such approvals are contingent upon a significant number of variables, many of which are not within our control, or those of others involved in midstream operations. To the extent such approvals are required and not granted, operations may be delayed or curtailed, or we may be prohibited from proceeding with planned exploration or operation of facilities.

Environmental laws and regulations are expected to have an increasing impact on our operations, although it is impossible to predict accurately the effect of future developments in such laws and regulations on our future earnings and operations. Some risk of environmental costs and liabilities is inherent in our operations and products, as it is with other companies engaged in similar businesses, and there can be no assurance that material costs and liabilities will not be incurred; however, we do not currently expect any material adverse effect upon our results of operations or financial position as a result of compliance with such laws and regulations.

Recent and future environmental regulations, including additional federal and state restrictions on greenhouse gas (“GHG”) emissions that have been or may be passed in response to climate change concerns, may increase our operating costs and also reduce the demand for the oil and natural gas we produce. The U.S. Environmental Protection Agency (the “EPA”) has issued a notice of finding and determination that emissions of carbon dioxide, methane and other GHGs present an endangerment to human health and the environment, which allows EPA to begin regulating emissions of GHGs under existing provisions of the federal Clean Air Act. The EPA has begun to implement GHG-related reporting and permitting rules. Similarly, the U.S. Congress is considering “cap and trade” legislation that would establish an economy-wide cap on emissions of GHGs in the United States and would require most sources of GHG emissions to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs. We will continue to monitor the establishment of these regulations through industry trade groups and other organizations in which we are a member. Similar regulations may be adopted by other states in which we operate or by the federal government.

Although future environmental obligations are not expected to have a material adverse effect on our results of operations or financial condition, there can be no assurance that future developments, such as increasingly stringent environmental laws or enforcement thereof, will not cause us to incur substantial environmental liabilities or costs.

Because we are engaged in acquiring, operating, exploring for and developing natural resources, in addition to federal laws we are subject to various state and local provisions regarding environmental and ecological matters. Compliance with environmental laws may necessitate significant capital outlays, may materially affect our earnings potential, and could cause material changes in our proposed business. In the past these laws have not had a material adverse effect on our business. However, during 2009, the Colorado Oil and Gas Conservation Commission (“COGCC”) adopted new regulations related to oil and gas development which are intended to prevent or mitigate environmental impacts of oil and gas development and include the permitting of wells. It should be noted in that regard that we conduct a significant portion of our business in Colorado and have the majority of our drilling capital budgeted there for 2011. Although we do not anticipate that expenditures to comply with existing environmental laws in any of the areas that we operate will change materially during 2011, we cannot be certain as to the nature and impact any new statutes implemented in Colorado or in other states in which we conduct our business may have on our operations.

Hazardous substances and waste disposal

We currently own or lease interests in numerous properties that have been used for many years for natural gas and crude oil production. Although the operator of such properties may have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us. In addition, some disposal sites that we have used have been operated by third parties over whom we had no control. The federal Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”) and comparable state statutes impose strict joint and several liability on current and former owners and operators of sites and on persons who disposed of or arranged for the disposal of “hazardous substances” found at such sites. The federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes govern the management and disposal of wastes. Although CERCLA currently excludes unaltered, raw petroleum from cleanup liability, petroleum constituents blended with other contaminants are not exempt, and many state laws affecting our operations impose separate clean-up liability regarding petroleum and petroleum-related products.

In addition, although RCRA currently classifies certain exploration and production wastes as “non-hazardous,” state agencies such as COGCC are increasingly regulating such non-hazardous waste under separate regulatory programs which impose tighter storage, handling, generation, disposal, and record keeping obligations. In addition, such wastes could be reclassified as hazardous wastes, thereby making such wastes subject to more stringent handling and disposal requirements. If such a change were to occur, it could have a significant impact on our operating costs, as well as on the oil and gas industry in general.

Oil spills

The federal Clean Water Act (“CWA”) and the federal Oil Pollution Act of 1990, as amended (“OPA”), impose significant penalties and other liabilities with respect to oil spills that damage or threaten navigable waters of the United States. Under the OPA, (i) owners and operators of onshore facilities and pipelines, (ii) lessees or permittees of an area in which an offshore facility is located, and (iii) owners and operators of tank vessels (“Responsible Parties”) are strictly liable on a joint and several basis for removal costs and damages that result from a discharge of oil into the navigable waters of the United States. These damages include, for example, natural resource damages, real and personal property damages and economic losses. OPA limits the strict liability of Responsible Parties for removal costs and damages that result from a discharge of oil to $350.0 million in the case of onshore facilities, $75.0 million plus removal costs in the case of offshore facilities, and in the case of tank vessels, an amount based on gross tonnage of the vessel; however, these limits do not apply if the discharge was caused by gross negligence or willful misconduct, or by the violation of an applicable Federal safety, construction or operating regulation by the Responsible Party, its agent or subcontractor or in certain other circumstances. To date, we have not had any such material spills.

In addition, with respect to certain offshore facilities, OPA requires evidence of financial responsibility in an amount of up to $150.0 million. Tank vessels must provide such evidence in an amount based on the gross tonnage of the vessel. Failure to comply with these requirements or failure to cooperate during a spill event may subject a Responsible Party to civil or criminal enforcement actions and penalties.

In light of the recent off-shore spill in the Gulf, these limits and related liability provisions are under significant scrutiny, and may be changed going forward. This could impose additional obligations on us, as well as on the oil and gas industry in general.

Under our various agreements, we have primary liability for oil spills that occur on properties for which we act as operator. With respect to properties for which we do not act as operator, we are generally liable for oil spills to the extent of our interest as a non-operating working interest owner.

Offshore production

Offshore oil and gas operations in U.S. waters are subject to regulations of the United States Department of the Interior (“DOI”), Bureau of Ocean Energy and Management, Regulation and Enforcement (“BOEMRE”). In response to the recent off-shore spill in the Gulf, the BOEMRE has been split into three separate agencies. One new agency — the Office of Natural Resources Revenue — began operations in October 2010. The two other new agencies — the Bureau of Ocean Energy Management and the Bureau of Safety and Environmental Enforcement — are expected to be fully implemented by October 1, 2011. The rules of the new agencies will be under significant scrutiny and may be changed from existing BOEMRE rules going forward. Currently, BOEMRE imposes strict liability upon the lessee under a federal lease for the cost of clean-up of pollution resulting from the lessee’s operations. As a result, such a lessee could be subject to possible liability for pollution damages. In the event of a serious incident of pollution, the DOI may require a lessee under federal leases to suspend or cease operations in the affected areas.

We do not act as operator for any of our offshore California properties. The operators of our offshore California properties are primarily liable for oil spills and are required by BOEMRE to carry certain types of insurance and to post bonds in that regard. There is no assurance that applicable insurance coverage is adequate to protect us.

Abandonment Obligations

We are responsible for costs associated with the plugging of wells, the removal of facilities and equipment and site restoration on our oil and natural gas properties according to our pro rata ownership. 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. We had a discounted asset retirement obligation of approximately $5.1 million at December 31, 2010. Estimates of abandonment costs and their timing may change due to many factors, including actual drilling and production results, inflation rates and changes to environmental laws and regulations. Estimated asset retirement obligations are added to net unamortized historical oil and gas property costs for purposes of computing depreciation, depletion and amortization expense charges.

Employees

At December 31, 2010 we had approximately 39 full-time employees. Additionally, certain operators, engineers, geologists, geophysicists, landmen, pumpers, draftsmen, title attorneys and others necessary for our operations are retained on a contract or fee basis as their services are required.

Item 1A. Risk Factors.

An investment in our securities involves a high degree of risk. You should carefully read and consider the risks described below before deciding to invest in our securities. The occurrence of any such risks may materially harm our business, financial condition, results of operations or cash flows. In any such case, the trading price of our common stock and other securities could decline, and you could lose all or part of your investment. When determining whether to invest in our securities, you should also refer to the other information contained in this Annual Report on Form 10-K, including our consolidated financial statements and the related notes, and in our subsequent filings with the Securities and Exchange Commission.

Risks Related To Our Business And Industries.

Inadequate liquidity could materially and adversely affect our business operations in the future.

Our efforts to improve our liquidity position will be challenging given the current economic climate and the Company’s financial condition. Current economic fundamentals portray an uncertain outlook for natural gas commodity prices in particular. These economic conditions have resulted in a decline in our revenues and available capital, and have caused us to significantly decrease our drilling activities and operations in 2009 and 2010 as compared to prior periods. Although we have entered into derivative contracts that reduce our exposure to changes in commodity prices, our ability to maintain adequate liquidity through 2011 will nevertheless depend significantly on adequate pipeline capacity, maintaining low operating expenses, focused capital spending, generation of additional working capital, and the availability of funding. We are committed to exploring all options because there is no assurance that industry commodity price or capital markets conditions will improve in the near term.

Consummation of a strategic transaction, which may include a sale of the company, a sale of assets, or joint venture or partnership arrangement may be necessary to fund our long-term capital expenditure and working capital needs.

In 2010, we successfully completed a non-core asset divestiture for gross proceeds of $130.0 million, as well as entered into an amended and restated credit facility thereby extending its maturity from January 2011 to January 2012. In late 2010 we resumed completion activities in the Piceance Basin and spud an exploratory test well to evaluate reservoir potential below the already proven Williams Fork section on our Piceance Basin leasehold. Our borrowings under our MBL Credit Agreement are due on January 31, 2012. Additionally, the holders of our 3³/4% senior convertible notes have the option to require the Company to purchase the notes held by them on May 1, 2012. If we are unable to complete any additional capital raising transactions, we may not be able to repay the amounts outstanding under the credit facility when due or redeem our convertible notes if required by the note holders without obtaining other sources of capital including a sale of the company, additional asset sales or other alternative financing.

Our level of indebtedness could adversely affect our ability to raise additional capital to fund our operations, limit our ability to react to changes in the economy or our industry and prevent us from meeting our obligations under our indebtedness, which would adversely affect our ability to operate as a going concern.

As of December 31, 2010, our total outstanding long-term liabilities were $357.0 million, including $69.6 million of outstanding borrowings drawn under DHS’s credit facility which are classified as current in the accompanying consolidated balance sheet. Our long-term indebtedness represented 41.1% of our total book capitalization at December 31, 2010. Based on our $30.0 million borrowing base and availability under our term loan, we had $7.1 million available under our credit facility as of December 31, 2010 and $26.4 million as of March 16, 2011. Our 7% senior unsecured notes indenture imposes limitations on our incurrence of additional secured borrowings. Our degree of leverage could have important consequences, including the following:

•

it may limit our ability to obtain additional debt or equity financing for working capital, capital expenditures, further exploration, debt service requirements, acquisitions and general corporate or other purposes;

•		a substantial portion of our cash flows from operations will be dedicated to the payment of principal and interest on our indebtedness and will not be available for other purposes, including our operations, capital expenditures and future business opportunities;
•		the debt service requirements of other indebtedness in the future could make it more difficult for us to satisfy our financial obligations;
•		certain of our borrowings, including borrowings under our credit facility, are at variable rates of interest, exposing us to the risk of increased interest rates;
•		as we have pledged most of our oil and natural gas properties and the related equipment, inventory, accounts and proceeds as collateral for the borrowings under our credit facility, they may not be pledged as collateral for other borrowings and would be at risk in the event of a default thereunder;
•		it may limit our ability to adjust to changing market conditions and place us at a competitive disadvantage compared to our competitors that have less debt;
•		we are vulnerable in the present downturn in general economic conditions and in our business, and we will likely be unable to carry out capital spending and exploration activities in excess of those that are currently planned; and
•		we have recently been, and may from time to time be, out of compliance with covenants under our credit facility, which will require us to seek waivers from our banks, which may be more difficult to obtain in the current economic environment.

We may incur additional debt, including secured indebtedness, or issue preferred stock in order to maintain adequate liquidity and develop our properties to the extent desired. A higher level of indebtedness and/or preferred stock increases the risk that we may default on our obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions, natural gas and oil prices and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. Factors that will affect our ability to raise cash through an offering of our capital stock or a refinancing of our debt include financial market conditions, the value of our assets, the number of shares of capital stock we have authorized, unissued and unreserved and our performance at the time we need capital.

In addition, our bank borrowing base is subject to periodic redetermination. Any reduction to our borrowing base could require us to repay indebtedness in excess of the borrowing base, or we might be required to provide the lenders with additional collateral. Further, our credit facility matures on January 31, 2012 at which time all amounts outstanding thereunder will be due and payable. At current commodity prices, we do not project that we will be able to repay such borrowings without completing one or more capital raising transactions, obtaining an extension of the credit facility from the lender, or entering into a new credit facility. Accordingly, we are currently engaged in seeking capital from a number of sources, including asset sales, potential joint ventures or similar industry partnerships, or an outright sale of the Company. Failure to obtain adequate capital may adversely affect our ability to operate as a going concern.

Natural gas and oil prices are volatile. Lower prices have adversely affected our financial position, financial results, cash flows, access to capital and ability to grow.

Our revenues, operating results, profitability and future rate of growth depend primarily upon the prices we receive for the natural gas and oil we sell. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. The amount we can borrow under our credit facility is subject to periodic redeterminations based on prices specified by our lender at the time of redetermination.

Historically, the markets for natural gas and oil have been volatile and they are likely to continue to be volatile. Wide fluctuations in natural gas and oil prices may result from relatively minor changes in the supply of and demand for natural gas and oil, market uncertainty and other factors that are beyond our control, including:

	•		worldwide and domestic supplies of natural gas and oil;
	•		weather conditions;
	•		the level of consumer demand;
	•		the price and availability of alternative fuels;
	•		the proximity and capacity of natural gas pipelines and other transportation facilities;
	•		the price and level of foreign imports;
	•		domestic and foreign governmental regulations and taxes;
	•		the nature and extent of regulation relating to carbon and other greenhouse gas emissions;
	•		the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
	•		political instability or armed conflict in oil-producing regions; and
	•		overall domestic and global economic conditions.

These factors and the volatility of the energy markets make it extremely difficult to predict future natural gas and oil price movements with any certainty. Declines in natural gas and oil prices not only reduce revenue, but also reduce the amount of natural gas and oil that we can produce economically and, as a result, have had, and could in the future have a material adverse effect on our financial condition, results of operations, cash flows and reserves. Further, natural gas and oil prices do not move in tandem. Because approximately 91% of our reserves at December 31, 2010 were natural gas reserves, we are more affected by movements in natural gas prices.

Further reduction of our credit ratings, or failure to restore our credit ratings to higher levels, could have a material adverse effect on our business and our ability to attract capital investment.

Our credit ratings have been downgraded to historically low levels. Our unsecured debt is currently assigned a non-investment grade rating by each of the four nationally recognized statistical rating organizations. The decline in our credit ratings reflects the agencies’ concerns over our financial strength. Our current credit ratings reduce our access to the unsecured debt markets and will unfavorably impact our overall cost of borrowing. Further downgrades of our current credit ratings or significant worsening of our financial condition could also result in increased demands by our suppliers for accelerated payment terms or other more onerous supply terms.

The current financial environment may have impacts on our business and financial condition that we cannot predict.

The continued instability in the global financial system and related limitation on availability of credit may continue to have an impact on our business and our financial condition, and we may continue to face challenges if conditions in the financial markets do not improve. Once adopted, our operating and capital budget for 2011 will most likely be funded with anticipated internally generated cash flow and other available sources of liquidity. Such sources historically have not been sufficient to fund all of our expenditures, and we have relied on the capital markets and asset monetization transactions to provide us with additional capital. Our ability to access the capital markets has been restricted as a result of the economic downturn and related financial market conditions and may be restricted in the future when we would like, or need, to raise capital. The difficult financial environment may also limit the number of prospects for our potential joint venture or asset monetization transactions that we are marketing or reduce the values we are able to realize in those transactions, making these transactions uneconomic or difficult to consummate and limit our ability to attract joint venture partners to develop our reserves. The economic situation could also adversely affect the collectability of our trade receivables and cause our commodity hedging arrangements, if any, to be ineffective if our counterparties are unable to perform their obligations. Additionally, the current

economic situation could lead to further reduced demand for natural gas and oil, or lower prices for natural gas and oil, or both, which would have a negative impact on our revenues.

Information concerning our reserves is uncertain.

There are numerous uncertainties inherent in estimating quantities of proved reserves and cash flows from such reserves, including factors beyond our control. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of an estimate of quantities of oil and natural gas reserves, or of cash flows attributable to such reserves, is a function of the available data, assumptions regarding future oil and natural gas prices, availability and terms of financing, expenditures for future development and exploitation activities, and engineering and geological interpretation and judgment. Reserves and future cash flows may also be subject to material downward or upward revisions based upon production history, development and exploitation activities, oil and natural gas prices and regulatory changes. Actual future production, revenue, taxes, development expenditures, operating expenses, quantities of recoverable reserves and value of cash flows from those reserves may vary significantly from our assumptions and estimates. In addition, reserve engineers may make different estimates of reserves and cash flows based on the same data. Further, the difficult financing environment may inhibit our ability to finance development of our reserves in the future.

The estimated quantities of proved reserves and the discounted present value of future net cash flows attributable to those reserves as of December 31, 2010, 2009 and 2008 included in our periodic reports filed with the SEC were prepared by our independent reserve engineers in accordance with the rules of the SEC, and are not intended to represent the fair market value of such reserves. As required by the SEC, the estimated discounted present value of future net cash flows from proved reserves is generally based on prices and costs as required by the SEC on the date of the estimate, while actual future prices and costs may be materially higher or lower. For 2008, in accordance with SEC rules at the time, proved reserves were based on single day year-end prices. For 2010 and 2009, in accordance with new SEC rules, proved reserves were prepared based on the twelve-month average first of month historical price. In addition, the 10% discount factor, which the SEC requires to be used to calculate discounted future net revenues for reporting purposes, is not necessarily the most appropriate discount factor based on the cost of capital in effect from time to time and risks associated with our business and the oil and gas industry in general.

We may not be able to replace production with new reserves.

Our reserves will decline significantly as they are produced unless we acquire properties with proved reserves or conduct successful development and exploration drilling activities. Our future oil and natural gas production is highly dependent upon our level of success in finding or acquiring additional reserves that are economically feasible and developing existing proved reserves, which is in turn dependent on the availability of capital to fund such acquisition and development activity.

Exploration and development drilling may not result in commercially productive reserves.

We do not always encounter commercially productive reservoirs through our drilling operations. The new wells we drill or participate in may not be productive and we may not recover all or any portion of our investment in wells we drill or participate in. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that oil or natural gas is present or may be produced economically. The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. Our efforts will be unprofitable if we drill dry wells or wells that are productive but do not produce enough reserves to return a profit after drilling, operating and other costs. Further, our drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

•		increases in the cost of, or shortages or delays in the availability of, drilling rigs and equipment;
•		unexpected drilling conditions;
•		title problems;
•		pressure or irregularities in formations;

•		equipment failures or accidents;
•		adverse weather conditions; and
•		compliance with environmental and other governmental requirements.

If oil or natural gas prices decrease or exploration and development efforts are unsuccessful, we may be required to take further writedowns.

In the past, we have been required to write down the carrying value of our oil and gas properties and other assets. There is a risk that we will be required to take additional writedowns in the future, which would reduce our earnings and stockholders’ equity. A writedown could occur when oil and natural gas prices are low or if we have substantial downward adjustments to our estimated proved reserves, increases in our estimates of development costs or deterioration in our exploration and development results.

We account for our crude oil and natural gas 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. 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. If the carrying amount of our oil and gas properties exceeds the estimated undiscounted future net cash flows, we will adjust the carrying amount of the oil and gas properties to their estimated fair value.

We review our oil and gas properties for impairment quarterly or whenever events and circumstances indicate that the carrying value may not be recoverable. Once incurred, a writedown of oil and gas properties is not reversible at a later date even if gas or oil prices increase. Given the complexities associated with oil and gas reserve estimates and the history of price volatility in the oil and gas markets, events may arise that would require us to record an impairment of the recorded carrying values associated with our oil and gas properties. As a result of this assessment, during the year ended December 31, 2010, we recorded impairment provisions related to our continuing operations attributable to our proved and unproved properties and other items of $43.5 million which primarily included proved impairments to our Opossum Hollow and Golden Prairie fields of $1.1 million and unproved impairments of $30.0 million related to our Columbia River Basin leasehold, Hingeline leasehold, Haynesville leasehold, Delores River leasehold, Howard Ranch leasehold, and our non-operated Garden Gulch field in the Piceance Basin. Other assets impairments during 2010 resulted from changes to our exploration and development efforts including $6.7 million for the produced water handling facility in Vega and $4.9 million to reduce the Paradox pipeline carrying value to its estimated fair value.

In 2009, we recorded impairment provisions related to continuing operations attributable to our proved and unproved properties totaling approximately $143.3 million primarily related to our non-operated Garden Gulch field in the Piceance Basin of $38.6 million, Haynesville Shale of $27.5 million, Columbia River Basin of $21.4 million, Lighthouse Bayou of $14.8 million, proved and unproved impairments in various Gulf Coast fields of $18.5 million, Vega surface land of $10.5 million, proved and unproved impairments in various non-Piceance fields of $5.4 million, and pipe and tubular inventory of $4.3 million. The impairments resulted primarily from the significant decline in commodity pricing for most of 2009 causing downward revisions to proved reserves which led to impairments. Lastly, we recorded an impairment of $1.9 million to reduce the Paradox pipeline carrying value to its estimated fair value.

In 2008, we recorded impairment provisions related to continuing operations attributable to our proved and unproved properties totaling approximately $277.7 million primarily related to the Newton, Midway Loop, Opossum Hollow and Angleton fields in Texas of $192.5 million, Paradox field in Utah of $30.5 million, Howard Ranch and Bull Canyon fields in the Rockies of $4.1 million, Utah Hingeline of $40.8 million and our offshore California field of $9.8 million. The impairments were primarily due to the significant decline in commodity pricing during the fourth quarter of 2008. In addition, we recorded impairments to our Paradox pipeline of $21.5 million, certain DHS rigs of $21.6 million and we wrote off DHS’s goodwill of $7.7 million.

We incurred dry hole costs on several less significant properties that totaled approximately $86,000 for the year ended December 31, 2010. We recorded dry hole costs totaling $33.6 million for the year ended December 31, 2009 related primarily to our Columbia River Basin exploratory well in Washington. During 2008, we recorded dry hole costs totaling $111.9 million for nine wells in Utah, four wells in Texas, two wells in Wyoming, two wells in California, one well in Louisiana and a non-operated project in the Columbia River Basin.

At December 31, 2009, we had no exploratory work in process. During 2009, we declared our exploratory Columbia River Basin well a dry hole and accordingly, at December 31, 2009, we had no remaining capitalized exploratory well costs. During 2010, we spud a deep exploratory test well in the Vega area to evaluate resource potential on our Piceance leasehold below the currently productive Williams Fork section. Completion activities on the well are currently in progress.

Lower natural gas and oil prices have negatively impacted, and could continue to negatively impact, our ability to borrow.

Our senior credit facility limits our borrowings to the lesser of the borrowing base and the total commitments. The borrowing base is determined periodically at the discretion of the banks and is based in part on natural gas and oil prices. Additionally, the indenture governing our 7% senior notes contains covenants imposing limitations on our ability to incur indebtedness in addition to that incurred under our senior credit facility. These agreements limit our ability to incur additional indebtedness unless we meet one of two alternative tests. The first alternative is based on our adjusted consolidated net tangible assets (as defined in our lending agreements), which is determined using discounted future net revenues from proved natural gas and oil reserves as of the end of each year. The second alternative is based on the ratio of our consolidated EBITDAX (as defined in the relevant indentures) to our adjusted consolidated interest expense over a trailing twelve-month period. Currently, we are permitted to incur additional indebtedness under both debt incurrence tests; however, our current borrowing base limits the amount of borrowing permitted under our credit facility. Lower natural gas and oil prices in the future could reduce our consolidated EBITDAX, as well as our adjusted consolidated net tangible assets, and thus could reduce our ability to incur additional indebtedness. Lower natural gas and oil prices could also further reduce the borrowing base under our revolving bank credit facility, and if such borrowing base were reduced below the amount of borrowings outstanding, we would be required to repay an amount of borrowings such that outstanding borrowings do not exceed the borrowing base.

The exploration, development and operation of oil and gas properties involve substantial risks that may result in a total loss of investment.

The business of exploring for and, to a lesser extent, developing and operating oil and gas properties involves a high degree of business and financial risk, and thus a substantial risk of investment loss that even a combination of experience, knowledge and careful evaluation may not be able to overcome. Oil and gas drilling and production activities may be shortened, delayed or canceled as a result of a variety of factors, many of which are beyond our control. These factors include:

•		availability of capital;
•		unexpected drilling conditions;
•		pressure or irregularities in formations;
•		equipment failures or accidents;
•		adverse changes in prices;
•		adverse weather conditions;
•		title problems;
•		shortages in experienced labor; and
•		increases in the cost of, or shortages or delays in the delivery of equipment.

The cost to develop our proved reserves as of December 31, 2010 is estimated to be approximately $18.9 million. In the current financing environment and given the significant capital we have raised in recent years, we expect it to be more difficult to obtain that capital than in the past and it may limit our success in attracting joint venture or industry partners to develop our reserves. We may drill wells that are unproductive or, although productive, do not produce oil and/or natural gas in economic quantities. Acquisition and completion decisions generally are based on subjective judgments and assumptions that are speculative. It is impossible to predict with certainty the production potential of a particular property or well. Furthermore, a successful completion of a well does not ensure a profitable return on the investment. A variety of geological, operational, or market-related factors, including, but not limited to, unusual or unexpected geological formations, pressures, equipment failures or accidents, fires, explosions, blowouts, cratering, pollution and other environmental risks, shortages or delays in the availability of drilling rigs and the delivery of equipment, loss of circulation of drilling fluids or other conditions may substantially delay or prevent completion of any well or otherwise prevent a property or well from being profitable. A productive well may become uneconomic in the event water or other deleterious substances are encountered which impair or prevent the production of oil and/or natural gas from the well, or in the event of lower than expected commodity prices. In addition, production from any well may be unmarketable if it is contaminated with water or other deleterious substances.

The marketability of our production depends mostly upon the availability, proximity and capacity of gas gathering systems, pipelines and processing facilities, which are owned by third parties.

The marketability of our production depends upon the availability, operation and capacity of gas gathering systems, pipelines and processing facilities, which are owned by third parties. The unavailability or lack of capacity of these systems and facilities could result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. United States federal, state and foreign regulation of oil and gas production and transportation, tax and energy policies, damage to or destruction of pipelines, general economic conditions and changes in supply and demand could adversely affect our ability to produce and market oil and natural gas. If market factors changed dramatically, the financial impact on us could be substantial. The availability of markets and the volatility of product prices are beyond our control and represent a significant risk.

Prices may be affected by regional factors.

The prices to be received for the natural gas production from our Rocky Mountain Region properties, where we are conducting a substantial portion of our development activities, will be determined to a significant extent by factors affecting the regional supply of and demand for natural gas, including the adequacy of the pipeline and processing infrastructure in the region to process, and transport, our production and that of other producers. Those factors result in basis differentials between the published indices generally used to establish the price received for regional natural gas production and the actual (frequently lower) price we receive for our production.

Our industry experiences numerous operating hazards that could result in substantial losses.

The exploration, development and operation of oil and gas properties also involve a variety of operating risks including the risk of fire, explosions, blowouts, cratering, pipe failure, abnormally pressured formations, natural disasters, acts of terrorism or vandalism, and environmental hazards, including oil spills, gas leaks, pipeline ruptures or discharges of toxic gases. These industry-operating risks can result in injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties, and suspension of operations which could result in substantial losses.

We maintain insurance against some, but not all, of the risks described above. Such insurance may not be adequate to cover losses or liabilities. Also, we cannot predict the continued availability of insurance at premium levels that justify its purchase. Terrorist attacks and certain potential natural disasters may change our ability to obtain adequate insurance coverage. The occurrence of a significant event that is not fully insured or indemnified against could materially and adversely affect our financial condition and operations.

We may be unable to compete effectively with larger companies, which could have a material adverse effect on our business, results of operations, and financial condition.

The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources than us. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Many of our larger competitors not only explore for and produce oil and natural gas, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than our financial resources permit. In addition, these companies may have a greater ability to continue exploration and development activities during periods of low oil and natural gas market prices and to absorb the burden of present and future federal, state, local and other laws and regulations. Our inability to compete effectively with larger companies could have a material adverse effect on our business, results of operations, and financial condition.

We depend on key personnel.

We currently have three employees that serve in executive management roles. In particular, Carl E. Lakey is our President and Chief Executive Officer, Kevin K. Nanke is our Treasurer and Chief Financial Officer, and Stanley F. Freedman is our Executive Vice President, General Counsel and Secretary. The loss of any one of these employees could severely harm our business. We do not have key man insurance on the lives of any of these individuals. Furthermore, competition for experienced personnel is intense. If we cannot retain our current personnel or attract additional experienced personnel, our ability to compete could be adversely affected.

We are exposed to additional risks through our drilling business, DHS.

We currently have a 49.8% ownership interest in and management control of DHS, a drilling business. The operations of that entity are subject to many additional hazards that are inherent to the drilling business, including, for example, blowouts, cratering, fires, explosions, loss of well control, loss of hole, damaged or lost drill strings and damage or loss from inclement weather. No assurance can be given that the insurance coverage maintained by that entity will be sufficient to protect it against liability for all consequences of well disasters, personal injury, extensive fire damage or damage to the environment. No assurance can be given that the drilling business will be able to maintain adequate insurance in the future at rates it considers reasonable or that any particular types of coverage will be available. The occurrence of events, including any of the above-mentioned risks and hazards that are not fully insured, could subject the drilling business to significant liability. It is also possible that we might sustain significant losses through the operation of the drilling business even if none of such events occurs.

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

DHS currently has only 10 of its 18 rigs in operation and expects to continue to incur liquidity pressures during 2011 based on its current cash flows and level of indebtedness. DHS is now highly leveraged relative to its cash flow and its senior lender, Lehman Commercial Paper, Inc., (“LCPI”) has filed for bankruptcy protection. DHS is in the process of attempting to procure amended financing terms from LCPI or alternative financing from other sources with more favorable debt terms, but there can be no assurance that its efforts will be successful. At December 31, 2010, DHS owed $69.6 million under its credit facility and was not in compliance with its financial covenants. DHS did not pay its scheduled principal and interest payment on January 1, 2011 and subsequently entered into a Forbearance Agreement that currently expires on March 25, 2011. In the event that DHS is not successful in obtaining alternative financing or making satisfactory arrangements with the LCPI bankruptcy trustee, it is likely that DHS will continue to be in default of its debt covenants under its credit facility unless and until market conditions improve significantly. In such event and upon expiration of the Forbearance Agreement, all of the amounts due under the credit facility would become immediately due and payable if LCPI exercised its rights under the terms of the credit facility. All of the DHS rigs are pledged as collateral for the credit facility, and would be subject to foreclosure in the event of a default under the credit facility. The DHS credit facility is non-recourse to Delta. At December 31, 2010, Delta had a net credit investment of approximately $2.8 million in DHS. Subsequent to year-end, the Board of Directors of DHS engaged transaction advisors to commence a strategic alternatives process, focused on a sale of the

company or substantially all of its assets. There can be no assurance that the terms offered by a potential buyer, if any, will be acceptable to the DHS shareholders. Additionally, the consummation of certain transactions are subject to the approval of DHS’s senior lender and the proceeds received will be required to be used to pay down amounts outstanding under its DHS credit facility.

Hedging transactions may limit our potential gains or cause us to lose money.

In order to manage our exposure to price risks in the marketing of oil and gas, we periodically enter into oil and gas price hedging arrangements, typically fixed price swaps. While intended to reduce the effects of volatile oil and gas prices, such transactions, depending on the hedging instrument used, may limit our potential gains if oil and gas prices were to rise substantially over the price established by the hedge. In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:

•		production is substantially less than expected;
•		the counterparties to our futures contracts fail to perform under the contracts; or
•		a sudden, unexpected event materially impacts gas or oil prices.

The total gains (losses) on derivative instruments recognized in our statements of operations were $18.1 million, ($28.1 million), and $21.7 million for the years ended December 31, 2010, 2009 and 2008, respectively. As of February 28, 2011, we had derivative contracts in place that hedge approximately 225 MBbls of oil, 5.7 Bbtu of natural gas and 13.2 MMgl of natural gas liquids. For 2012 we have approximately 181 MBbls of oil hedged, 4.4 Bbtu of natural gas hedged, and 11.2 MMgl of natural gas liquids hedged. For 2013 we have 145 MBbls of oil hedged, 3.8 Bbtu of natural gas hedged, and 4.5 MMgl of natural gas liquids hedged.

We may not receive payment for a portion of our future production.

Our revenues are derived principally from uncollateralized sales to customers in the oil and gas industry. The concentration of credit risk in a single industry affects our overall exposure to credit risk because customers may be similarly affected by changes in economic and other conditions. Although we have not been directly affected, we are aware that some refiners have filed for bankruptcy protection, which has caused the affected producers to not receive payment for the production that was delivered. If economic conditions deteriorate, it is likely that additional, similar situations will occur which will expose us to added risk of not being paid for oil or gas that we deliver. We do not attempt to obtain credit protections such as letters of credit, guarantees or prepayments from our purchasers. We are unable to predict what impact the financial difficulties of any of our purchasers may have on our future results of operations and liquidity.

We have no long-term contracts to sell oil and gas.

We do not have any long-term supply or similar agreements with governments or other authorities or entities for which we act as a producer. We are therefore dependent upon our ability to sell oil and gas at the prevailing wellhead market price. There can be no assurance that purchasers will be available or that the prices they are willing to pay will remain stable and not decline.

Terrorist attacks aimed at our facilities could adversely affect our business.

The United States has been the target of terrorist attacks of unprecedented scale. The U.S. government has issued warnings that U.S. energy assets may be the future targets of terrorist organizations. These developments have subjected our operations to increased risks. Any terrorist attack at our facilities, or those of our purchasers, could have a material adverse effect on our business.

We own properties in the Gulf Coast Region that could be susceptible to damage by severe weather.

Certain areas in and near the Gulf of Mexico experience hurricanes and other extreme weather conditions on a relatively frequent basis. Some of our properties in the Gulf Coast Region are located in areas that could cause them to be susceptible to damage by these storms. Damage caused by high winds and flooding could potentially cause us

to curtail operations and/or exploration and development activities on such properties for significant periods of time until damage can be repaired. Moreover, even if our properties are not directly damaged by such storms, we may experience disruptions in our ability to sell our production due to damage to pipelines, roads and other transportation and refining facilities in the area.

We may incur substantial costs to comply with the various federal, state and local laws and regulations that affect our oil and gas operations.

We are affected significantly by a substantial amount of governmental regulations that increase costs related to the drilling of wells and the transportation and processing of oil and gas. It is possible that the number and extent of these regulations, and the costs to comply with them, will increase significantly in the future. In Colorado, for example, significant new governmental regulations have been adopted that are primarily driven by concerns about wildlife and the environment. These government regulatory requirements complicate our plans for development and may result in substantial costs that are not possible to pass through to our customers and which could impact the profitability of our Colorado operations.

Our oil and gas operations are subject to stringent federal, state and local laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to health and safety, land use, environmental protection or the oil and gas industry generally. Legislation affecting the industry is under constant review for amendment or expansion, frequently increasing our regulatory burden. Compliance with such laws and regulations often increases our cost of doing business and, in turn, decreases our profitability. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the incurrence of investigatory or remedial obligations, or issuance of cease and desist orders.

The environmental laws and regulations to which we are subject may:

•		require applying for and receiving a permit before drilling commences;
•		restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production activities;
•		limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and
•		impose substantial liabilities for pollution resulting from our operations.

Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to maintain compliance, and may otherwise have a material adverse effect on our earnings, results of operations, competitive position or financial condition. Over the years, we have owned or leased numerous properties for oil and gas activities upon which petroleum hydrocarbons or other materials may have been released by us or by predecessor property owners or lessees who were not under our control. Under applicable environmental laws and regulations, including CERCLA, RCRA and analogous state laws, we could be held strictly liable for the removal or remediation of previously released materials or property contamination at such locations regardless of whether we were responsible for the release or if our operations were standard in the industry at the time they were performed.

Our gas drilling and production operations require adequate sources of water to facilitate the fracturing process and the disposal of that water when it flows back to the well-bore. If we are unable to dispose of the water we use or remove at a reasonable cost and within applicable environmental rules, our ability to produce gas commercially and in commercial quantities could be impaired.

New environmental regulations governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase operating costs and cause delays, interruptions or termination of operations, the extent of which cannot be predicted, all of which could have an adverse affect on our operations and financial performance.

Further, we must remove the water that we use to fracture our gas wells when it flows back to the well-bore. Our ability to remove and dispose of water will affect our production and the cost of water treatment and disposal may affect our profitability. The imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct hydraulic fracturing or disposal of waste, including produced water, drilling fluids and other wastes associated with the exploration, development and production of natural gas.

Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Congress has considered legislation to amend the federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and natural gas industry in the hydraulic fracturing process. Hydraulic fracturing is an important and commonly used process in the completion of unconventional natural gas wells in shale formations, as well as tight conventional formations, including many of those that we complete and produce. This process involves the injection of water, sand and chemicals under pressure into rock formations to stimulate natural gas production. Sponsors of these bills have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. In addition, some states have adopted and others are considering legislation to restrict hydraulic fracturing. Wyoming has adopted legislation requiring the disclosure of hydraulic fracturing chemicals. Further, a Congressional Committee is investigating hydraulic fracturing practices legislation that requires the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, any additional level of regulation could lead to operational delays or increased operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.

We are exposed to credit risk as it affects third parties with whom we have contracted.

Third parties with whom we have contracted may lose existing financing or be unable to obtain additional financing necessary to continue their businesses. The inability of a third party to make payments to us for our accounts receivable, or the failure of our third party suppliers to meet our demands because they cannot obtain sufficient credit to continue their operations, may cause us to experience losses and may adversely impact our liquidity and our ability to make our payments when due.

Certain federal income tax deductions currently available with respect to oil and natural gas exploration and development may be eliminated as a result of future legislation.

Changes contained in President Obama’s 2012 budget proposal include the elimination of certain key U.S. federal income tax preferences currently available to oil and gas exploration and production companies. Such changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; (iii) the elimination of the deduction for certain U.S. production activities; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear, however, whether any such changes will be enacted or how soon such changes could be effective.

The passage of any legislation as a result of the budget proposal, or any other similar change in U.S. federal income tax law, could eliminate certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could negatively affect our financial condition and results of operations.

Potential legislative and regulatory actions addressing climate change could increase our costs, reduce our revenue and cash flow from natural gas and oil sales or otherwise alter the way we conduct our business.

Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to warming of the earth’s atmosphere. In December 2009, the EPA issued proposed regulations that would require a reduction in emissions of greenhouse gases from motor vehicles and also could require permits for emitting greenhouse gas from certain stationary sources such as ours. Congress has also been considering various bills that would establish an economy-wide cap-and-trade program to reduce U.S. emissions of greenhouse gases and at least one-third of the states, either individually or through multi-

state regional initiatives, have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or greenhouse gas cap and trade programs. As an alternative to reducing emission of greenhouse gases under cap and trade programs, Congress may consider the implementation of a program to tax the emission of carbon dioxide and other greenhouse gases. The net effect of such legislation would be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products and natural gas. Passage of climate change legislation or other regulatory initiatives by Congress or various states of the U.S. or the adoption of regulations by the EPA or analogous state agencies that regulate or restrict emissions of greenhouse gases in areas in which we conduct business, could increase the costs of our operations, including new or increased costs to operate and maintain our equipment and facilities, install new emission controls on our equipment and facilities, acquire allowances to authorize our greenhouse gas emissions, pay taxes related to our greenhouse gas emissions and administer and manage a greenhouse gas emissions program. Moreover, incentives to conserve energy or use alternative energy sources could reduce demand for natural gas and oil. Reductions in our revenues or increases in our expenses as a result of climate control initiatives could have adverse effects on our business, financial position, results of operations and prospects.

Risks Related To Our Stock.

Our largest stockholder has the power to significantly influence the future of our Company.

As of February 28, 2011, our largest stockholder, Tracinda Corporation (“Tracinda”), beneficially owned approximately 93,798,000 shares of our common stock, or approximately 33% of the outstanding shares of our common stock. Pursuant to the Company Stock Purchase Agreement that we entered into with Tracinda on December 29, 2007, Tracinda has certain rights, including the right to designate a number of members of our Board of Directors proportional to their ownership in the Company, preemptive rights in connection with future equity issuances by us, and consent rights over certain types of actions. Tracinda has designated three out of the eleven members currently comprising our Board of Directors, one of whom serves as our Board Chairman. While Tracinda agreed not to acquire more than 49% of our outstanding common stock until February 20, 2009, there are currently no limitations as to the number of our outstanding shares of common stock that Tracinda Corporation may acquire. Consequently, Tracinda Corporation has the power to significantly influence matters requiring approval by our stockholders, including the election of directors, and the approval of mergers and other significant corporate transactions. The acquisition of 50% or more of our common stock by Tracinda or any other stockholder would require us to repurchase all of our senior notes and convertible notes per the terms of our indentures. This concentration of ownership may make it more difficult for other stockholders to effect substantial changes in our Company and may also have the effect of delaying, preventing or expediting, as the case may be, a change in control of our Company. Tracinda also has the right to sell its Delta stock if it chooses to do so and, as required by the terms of the Company Stock Purchase Agreement, all of its shares are currently registered for resale. In the event that Tracinda sells all or a substantial portion of its Delta shares, it is possible that the market price of our stock could be adversely affected.

Sales of a substantial number of shares of our common stock, or the perception that such sales might occur, could have an adverse effect on the price of our common stock.

As of December 31, 2010, approximately 33% of our common stock was held by Tracinda Corporation. No other investor held more than 5% of our common stock. Sales by Tracinda Corporation of a substantial number of shares of our common stock into the public market, or the perception that such sales might occur, could have an adverse effect on the price of our common stock.

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

Our common stock is currently traded on The NASDAQ Capital Market under the symbol “DPTR.” If we fail to meet any of the continued listing standards of The NASDAQ Capital Market, our common stock will be delisted from The NASDAQ Capital Market. These continued listing standards include specifically enumerated criteria, such as a $1.00 minimum closing bid price. On February 8, 2011, we received a letter from The NASDAQ Stock Market advising us that we did not meet the minimum $1.00 per share bid price requirement for continued inclusion on The

NASDAQ Capital Market pursuant to NASDAQ Marketplace Listing Rule 5550(a)(2). The letter stated that we have until August 8, 2011 to regain compliance. To regain compliance with the applicable listing rule, the closing bid price of our common stock must meet or exceed $1.00 per share for a minimum of ten consecutive business days during the 180 day grace period. If this occurs, NASDAQ will provide us with written notification of compliance. If we do not regain compliance by August 8, 2011, NASDAQ will provide written notice that our common stock is subject to delisting. In that event, we may appeal such determination to a hearings panel. There can be no guarantee that we will be able to regain compliance with the Listing Rule. Further, this deficiency notice relates exclusively to our bid price deficiency. We may be delisted during the applicable grace periods for failure to maintain compliance with any other listing requirement which may occur.

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

We may issue shares of preferred stock with greater rights than our common stock.

Our certificate of incorporation authorizes our board of directors to issue one or more series of preferred stock and set the terms of the preferred stock without seeking any further approval from our stockholders. Any preferred stock that is issued may rank ahead of our common stock, in terms of dividends, liquidation rights and voting rights.

There may be future dilution of our common stock.

To the extent options to purchase common stock under our employee and director stock option plans, outstanding warrants to purchase common stock are exercised or the price vesting triggers under the performance shares granted to our executive officers are satisfied, or additional shares of restricted stock are issued to our employees, holders of our common stock will experience dilution. As of December 31, 2010, we had outstanding options to purchase 1,608,000 shares of common stock at a weighted average exercise price of $7.26. Further, if we sell additional equity or convertible debt securities, such sales could result in increased dilution to our existing stockholders and cause the price of our outstanding securities to decline.

We do not expect to pay dividends on our common stock.

We have never paid dividends with respect to our common stock, and we do not expect to pay any dividends, in cash or otherwise, in the foreseeable future. We intend to retain any earnings for use in our business. In addition, the credit agreement relating to our credit facility prohibits us from paying any dividends and the indenture governing our senior notes restricts our ability to pay dividends. In the future, we may agree to further restrictions.

The common stock is an unsecured equity interest in our Company.

As an equity interest, our common stock is not secured by any of our assets. Therefore, in the event we are liquidated, the holders of the common stock will receive a distribution only after all of our secured and unsecured creditors have been paid in full. There can be no assurance that we will have sufficient assets after paying our secured and unsecured creditors to make any distribution to the holders of the common stock.

Our stockholders do not have cumulative voting rights.

Holders of our common stock are not entitled to accumulate their votes for the election of directors or otherwise. Accordingly, a plurality of holders of our outstanding common stock will be able to elect all of our directors. As of December 31, 2010, our directors and executive officers collectively and beneficially owned, directly or indirectly, approximately 2.5% of our outstanding common stock.

Anti-takeover provisions in our certificate of incorporation, Delaware law and certain of our contracts may have provisions that discourage corporate takeovers and could prevent stockholders from realizing a premium on their investment.

Certain provisions of our certificate of incorporation, the provisions of the Delaware General Corporation Law and certain of our contracts may discourage persons from considering unsolicited tender offers or other unilateral takeover proposals or require that such persons negotiate with our board of directors rather than pursue non-negotiated takeover attempts. These provisions may discourage acquisition proposals or delay or prevent a change in control. As a result, these provisions could have the effect of preventing stockholders from realizing a premium on their investment.

Our certificate of incorporation authorizes our board of directors to issue preferred stock without stockholder approval and to set the rights, preferences and other designations, including voting rights of those shares, as the board of directors may determine. In addition, our Certificate of Incorporation authorizes a substantial number of shares of common stock in excess of the shares outstanding. These provisions may discourage transactions involving actual or potential changes of control, including transactions that otherwise could involve payment of a premium over prevailing market prices to stockholders for their common stock.

Under our credit facility, a change in control is an event of default. Under the indenture governing our senior notes, upon the occurrence of a change in control, the holders of our senior notes will have the right, subject to certain conditions, to require us to repurchase their notes at a price equal to 101% of their principal amount, plus accrued and unpaid interest to the date of the repurchase.

Item 1B. Unresolved Staff Comments.

None.

Item 2. Properties.

Properties.

Piceance Basin

Our core asset and primary area of activity is in the Vega Area of the Piceance Basin in western Colorado. The Williams Fork member of the Mesa Verde formation is the primary producing interval and has been successfully developed throughout the Piceance Basin. The geology of the Piceance Basin is characterized as highly consistent and predictable over large areas, which generally equates to reliable timing and cost expectations during drilling and completion activities, as well as minimal well-to-well variance in production and reserves when completed with the same methodology.

Vega Area. Since 2005 we have dedicated significant financial capital and human resources to the development of our Vega Unit and surrounding leasehold in Mesa County, Colorado, which in combination is referred to as the Vega Area. The Vega Area is comprised of the Vega Unit, the Buzzard Creek Unit, the North Vega leasehold, and the North Buzzard Creek leasehold. Our working interest in the Vega Area varies between 95-100%. In 2008, we acquired an additional 17,300 net acres, which increased our position to approximately 22,375 net acres, which has over 1,900 net drilling locations based on 10-acre spacing. During fiscal 2008, we increased proved reserves in the Vega Area over 295% to 719.9 Bcfe and increased production from approximately 25.0 Mmcf/d at the beginning of the year to approximately 48.0 Mmcf/d at the end of 2008. However, during 2009, as a result of the combined effect of lower gas prices through the year and the new SEC reserve pricing rules and our limited capital development plan, proved reserves decreased to 84.7 Bcfe. At December 31, 2010, proved reserves in the Vega Area totaled 112.6 Bcfe. Net production in the Vega Area currently exceeds 30.0 Mmcfe/d. We ended 2010 with 190 wells producing. Despite our large inventory of over 1,900 drilling locations and efficient reserve growth, we decreased our drilling program from four rigs to one rig at year end 2008, and further to zero rigs in 2009 and 2010, primarily due to the decrease in natural gas prices and liquidity concerns. Since 2005 we have experienced significant reductions in drill time, and drilling and completion costs. We reinitiated completion activities in the latter half of 2010 on previously drilled wells. These recently completed wells utilized a larger fracture stimulation design, called “generation four” or “Gen IV”, which has proven to increase the initial production and recoverable reserves per well over our prior completion designs. Additionally, we drilled a well in the Vega Area to test the sections that are located deeper than the Williams Fork section. We began completion activities on this deep test well subsequent to year end. We also began drilling another well, which will target the section immediately beneath the Williams Fork section. Our drilling and completion capital budget for the Vega Area for 2011 has not yet been determined beyond the exploratory test wells, lease preservation well, and drilled but not completed wells described elsewhere, pending the results of the exploratory test wells.

Non-Operated Assets

Because of our continued focus in the Piceance Basin, we do not anticipate significant capital expenditures in 2011 on any of the properties described below. Collectively, as of December 31, 2010, these properties comprised 21.6 Bcfe, or 16% of our proved reserves.

South Piceance. We have a 5% working interest in 153 producing wells in the southern region of the Piceance Basin. We also have a 5% working interest in an additional 75 wells remaining to be drilled, but will not incur any capital expenditures on these wells in accordance with the carry provisions of the February 2008 agreement with Encana.

Cowboy Field. Our leasehold in the Denver Julesburg (“DJ”) Basin of northeastern Colorado and southeastern Wyoming focuses on the “J” sand formation at depths of between 7,000 feet and 8,000 feet. We have approximately 305 net acres with an average 47% working interest in the proved reserves of this field.

Newton Field. The Newton Field is located in Newton County, Texas where we have an interest in approximately 1,914 net acres with an average 50% working interest in the proved reserves of this field.

Midway Loop Field. The Midway Loop Field is located in Polk and Tyler Counties, Texas. We have an interest in approximately 2,470 net acres, with an average 32% working interest in the proved reserves of this field.

Caballos Creek / Opossum Hollow. The leasehold is located in Atascosa and McMullen Counties, Texas. We have an interest in approximately 392 net acres, with an average 48% working interest in the proved reserves of this field.

Point Arguello and Rocky Point Units. We own the equivalent of a 6.07% gross working interest in the Point Arguello Unit and related facilities located Offshore California in the Santa Barbara Channel. Within this unit there are three producing platforms (Hidalgo, Harvest and Hermosa). We also own a 6.25% working interest in the development of the east half of OCS Block 451 in the Rocky Point Unit.

Exploration/Undeveloped Assets

While we have significant undeveloped acreage positions in several basins and exploratory areas as listed below, we intend to dedicate all of our efforts and capital to the development of the Vega Area. Therefore, we have no planned capital expenditures in these areas for 2011. As of December 31, 2010 these areas do not contain any of our proved reserves.

Paradox Basin. In the Paradox Basin of southwest Colorado and southeast Utah we have a 66.1% working interest in approximately 17,599 net acres. In 2007 and 2008 we drilled a total of nine wells in the Paradox Basin. The results of these wells were mixed and in the latter half of 2008 we ceased all drilling and completion activity in the Paradox Basin after determining that the results were uneconomic.

Central Utah Hingeline. The central Utah Hingeline Region is an overthrust belt located in central Utah. We have an average 60.4% working interest in approximately 100,000 net acres. From 2006 through 2008 we drilled three exploration wells. All three wells were plugged and abandoned as dry holes.

Columbia River Basin. The Columbia River Basin is located in southeast Washington and northeast Oregon. During 2009, we drilled the Gray 31-23 well. The well did not reach the targeted Roslyn formation and was plugged and abandoned. We have an interest in approximately 184,000 net acres in the basin, all of which are undeveloped.

Internal Controls Over Reserve Estimates, Technical Qualifications and Technologies Used

Our policies regarding internal controls over reserve estimates requires reserves to be in compliance with the SEC definitions and guidance and for reserves to be prepared by an independent third party reserve engineering firm under the supervision of our Corporate Engineering Manager. Qualified petroleum engineers in our Denver office provide to our third party reserves engineers reserves estimate preparation material such as property interests, production, current costs of operation and development, current prices for production, geoscience and engineering data, and other information. This information is reviewed by knowledgeable members of our reserve engineering department to ensure accuracy and completeness of the data prior to submission to our third party reserve engineering firm. In each of the years 2010, 2009 and 2008, we retained Ralph E. Davis Associates, Inc. (“RDAI”), independent, third-party reserve engineers, to prepare our estimates of proved reserves. A letter which identifies the professional qualifications of the individual at RDAI who was responsible for overseeing the preparation of our reserve estimates as of December 31, 2010 has been filed as a part of Exhibit 99.1 to this report.

The SEC’s new rules expanded the technologies that a company can use to establish reserves. The SEC now allows use of techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. A variety of methodologies were used to determine our proved reserve estimates. The principal methodologies employed are decline curve analysis, analog type curve analysis, volumetrics, material balance, pressure transient analysis, petrophysics/log analysis and analogy. Some combination of these methods is used to determine reserve estimates in substantially all of our fields.

Reserves Reported to Other Agencies

We did not file any reports during the year ended December 31, 2010 with any federal authority or agency other than the SEC with respect to our estimates of oil and natural gas reserves.

We own 49.8% of DHS, which as of December 31, 2010 owned 18 rigs with depth ratings of 10,000 to 25,000 feet. The following table shows property information and location for the DHS rigs.

				Year
		Operating		Built or								Depth
		Region		Refurbished				Horsepower				Capacity
Rig No. 1		ND			2005				1,500				18,000
Rig No. 4		MT			2007				700				11,000
Rig No. 5		NV			2005				700				13,000
Rig No. 6		CO			2005				700				12,000
Rig No. 8		CO			2005				800				12,500
Rig No. 9		ND			2006				1,000				15,000
Rig No. 10		ND			2006				1,000				15,000
Rig No. 11		NV			2006				750				11,000
Rig No. 12		ND			2006				1,000				15,000
Rig No. 14		WY			2006				800				12,500
Rig No. 15		WY			2006				700				10,000
Rig No. 16		WY			2006				700				10,000
Rig No. 17		MT			2006				1,000				12,500
Rig No. 18		WY			2007				700				10,500
Rig No. 19		WY			2008				700				12,500
Rig No. 20		NE			2008				1,000				12,500
Rig No. 23		TX			2008				2,000				25,000
Rig No. 24		TX			2008				1,300				12,500

Office Facilities

Our offices are located at 370 Seventeenth Street, Suite 4300, Denver, Colorado 80202. We lease approximately 49,000 square feet of office space. Our current lease payments are approximately $97,900 per month and our lease expires in December 2014.

Production

During the years ended December 31, 2010, 2009 and 2008, we have not had, nor do we now have, any long-term supply or similar agreements with governments or authorities under which we acted as producer.

Impairment of Long Lived Assets

On a quarterly basis, we compare our historical cost basis of each proved developed and undeveloped oil and gas property to its expected future undiscounted net cash flow from each property (on a field by field basis). Estimates of expected future cash flows represent management’s best estimate based on reasonable and supportable assumptions and projections. If the expected future net cash flows exceed the carrying value of the property, no impairment is recognized. If the carrying value of the property 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. As a result of this assessment, during the year ended December 31, 2010, we recorded impairment provisions related to continuing operations attributable to our proved and unproved properties and other items of $43.5 million which primarily included proved impairments to our Opossum Hollow and Golden Prairie fields of $1.1 million and unproved impairments of $30.0 million related to our Columbia River Basin leasehold, Hingeline leasehold, Haynesville leasehold, Delores River leasehold, Howard Ranch leasehold, and our non-operated Garden Gulch field in the Piceance Basin. Other impairments primarily included $6.7 million for the produced water handling facility in Vega and $4.9 million to reduce the Paradox pipeline carrying value to its estimated fair value.

In 2009, we recorded impairment provisions related to continuing operations attributable to our proved and unproved properties totaling approximately $143.3 million primarily related to our non-operated Garden Gulch field in the Piceance Basin of $38.6 million, Haynesville Shale of $27.5 million, Columbia River Basin of $21.4 million, Lighthouse Bayou of $14.8 million, proved and unproved impairments in various Gulf Coast fields of $18.5 million, Vega surface land of $10.5 million, proved and unproved impairments in various Rockies fields of $5.4 million, pipe and tubular inventory of $4.3 million, and Paradox pipeline of $1.9 million.

In 2008, we recorded impairment provisions related to continuing operations attributable to our proved and unproved properties totaling approximately $277.7 million primarily related to the Newton, Midway Loop, Opossum Hollow and Angleton fields in Texas of $192.5 million, Paradox field in Utah of $30.5 million, Howard Ranch and Bull Canyon fields in the Rockies of $4.1 million, Hingeline field in Utah of $40.8 million and our offshore California field of $9.8 million. The impairments resulted primarily from the significant decline in commodity pricing during the fourth quarter of 2008. In addition, we recorded impairments to our Paradox pipeline of $21.5 million, certain DHS rigs of $21.6 million and we wrote off DHS goodwill of $7.7 million.

Production Volumes, Unit Prices and Costs

The following table sets forth certain information regarding our volumes of production sold and average prices received associated with our production and sales of natural gas and crude oil for the years ended December 31, 2010, 2009, and 2008.

		Years Ended December 31,
		2010				2009				2008
Production volume — Total production (MMcfe)			16,763				22,158				24,908
Production from continuing operations:
Oil (MBbls)			500				734				950
Natural Gas (MMcf)			11,759				14,319				15,164
Total (MMcfe)			14,759				18,727				20,863
Net average daily production-continuing operations:
Oil (Bbl)			1,370				2,013				2,602
Natural Gas (Mcf)			32,216				39,230				41,545
Average sales price:
Oil (per barrel)		$	70.90			$	52.45			$	92.47
Natural Gas (per Mcf)		$	5.01			$	3.09			$	6.92
Hedge gain (loss) (per Mcfe)		$	(0.40	)		$	(0.06	)		$	0.88
Lease operating costs - (per Mcfe)		$	1.66			$	1.41			$	1.34

Productive Wells and Acreage

The table below shows, as of December 31, 2010, the approximate number of gross and net producing oil and gas wells by state and their related developed acres owned by us. Calculations include 100% of wells and acreage owned by us and our subsidiaries. Developed acreage consists of acres spaced or assignable to productive wells.

		Oil (1)								Gas (1)								Developed Acres
Location		Gross (2)				Net (3)				Gross (2)				Net (3)				Gross (2)				Net (3)
California (onshore)			—				—				1				—				1,057				157
California (offshore)			34				2.1				—				—				2,422				269
Colorado			—				—				343				196.0				1,920				1,866
New Mexico			—				—				1				0.1				240				13
Oklahoma			—				—				—				—				560				110
Texas			51				13.0				25				4.1				14,550				4,047
Utah			—				—				1				0.3				40				28
Wyoming			16				6.9				—				—				640				285
Total			101				22.0				371				200.5				21,429				6,775

Undeveloped Acreage

At December 31, 2010, we held undeveloped acreage by state as set forth below:

		Undeveloped Acres (1)(2)
Location		Gross				Net
Colorado			36,701				30,384
Louisiana			220				193
Oregon			122,289				13,849
Texas			9,139				5,418
Utah			216,451				135,006
Washington			571,034				170,458
Wyoming			680				220
Total			956,514				355,528

Drilling Activity

During the years indicated, we drilled or participated in the drilling of the following productive and nonproductive exploratory and development wells:

		Years Ended December 31,
		2010								2009								2008
		Gross				Net				Gross				Net				Gross				Net
Exploratory Wells (2):
Productive:
Oil			—				—				—				—				1				1.00
Gas			—				—				—				—				1				0.70
Nonproductive			—				—				1				0.50				19				14.01
Total			—				—				1				0.50				21				15.71
Development Wells (1):
Productive:
Oil			1				1.00				—				—				7				5.40
Gas			66				16.10				113				32.89				141				82.37
Nonproductive			1				0.25				—				—				—				—
Total			68				17.35				113				32.89				148				87.77
Total Wells (1):
Productive:
Oil			1				1.00				—				—				8				6.40
Gas			66				16.10				113				32.89				142				83.07
Nonproductive			1				0.25				1				0.50				19				14.01
Total Wells			68				17.35				114				33.39				169				103.48

Present Drilling Activity

At December 31, 2010, we had five development wells in the Vega area which had been drilled but not yet completed and one exploratory well in progress. Subsequent to year-end, an additional exploratory well was spud in the Vega Area and is currently in progress. We are unable to accurately predict our anticipated capital expenditures for the full year of 2011, primarily due to the uncertainty relating to results from our in-progress exploratory efforts in the Piceance Basin and sources of capital sufficient to complete our desired level of drilling activity. We expect to announce our 2011 drilling plans once our well results have been evaluated.

Item 3. Legal Proceedings

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

During the fourth quarter 2010, we were engaged in an arbitration with 212 Resources Corporation (“212”) that was filed with the American Arbitration Association on October 27, 2009. The matter was set for arbitration on January 24, 2011, but was ultimately settled pursuant to a final Settlement Agreement executed by the parties on January 25, 2011, which required us to pay $1.5 million to 212 in consideration of mutual releases of claims and the termination of the underlying agreement.

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

We formerly owned a 2.41934% working interest in OCS Lease 320 in the Sword Unit, Offshore California, and Amber formerly owned a 0.97953% working interest in the same lease. Lease 320 was conveyed back to the United States at the conclusion of the Amber litigation when the courts determined that the government had breached that lease (among others) and was liable to the working interest owners for damages; however, the government now contends that the former working interest owners are still obligated to permanently plug and abandon an exploratory well that was drilled on the lease and to clear the well site. The former operator of the lease has commenced litigation against the United States seeking a declaratory judgment that the former working interest owners are not responsible for these costs as a result of the government’s breach of the lease. It is currently unknown whether or not the litigation will be successful, or what the costs of decommissioning the well would be if the former working interest owners are ultimately held liable.

Item 4. Submission of Matters to a Vote of Security Holders

No matters were submitted to a vote of security holders during the fourth quarter of 2010.

Item 4A. Directors and Executive Officers

Our executive officers and members of our Board of Directors, and their respective ages, are as follows:

Name		Age				Positions		Period of Service
Carl E. Lakey			49			President, Chief Executive Officer and Director		July 2010 to Present
Kevin K. Nanke			46			Treasurer and Chief Financial Officer		December 1999 to Present
Stanley F. Freedman			62			Executive Vice President, General Counsel and Secretary		January 2006 to Present
Hank Brown			71			Director		June 2007 to Present
Kevin R. Collins			54			Director		March 2005 to Present
Jerrie F. Eckelberger			66			Director		September 1996 to Present
Jean-Michel Fonck			69			Director		May 2009 to Present
Aleron H. Larson, Jr.			65			Director		May 1987 to Present
Russell S. Lewis			56			Director		June 2002 to Present
Anthony Mandekic			69			Director		May 2009 to Present
James J. Murren			49			Director		February 2008 to Present
Jordan R. Smith			76			Director		October 2004 to Present
Daniel J. Taylor			54			Chairman of the Board and Director		February 2008 to Present

The following is biographical information as to the business experience of each of our current executive officers and directors.

Executive Officers

Carl E. Lakey, President, Chief Executive Officer and Director, joined Delta in April 2007 as Senior Vice President of Operations prior to spending six years managing operations for El Paso’s Western Onshore Division and sixteen years at ExxonMobil in various operational and technical positions. He received a Bachelor of Science degree in Petroleum Engineering from Colorado School of Mines in 1985.

Kevin K. Nanke, Treasurer and Chief Financial Officer, joined Delta in April 1995 as our Controller and has served as the Treasurer and Chief Financial Officer of Delta and Amber Resources since 1999. Since April 1, 2005 he has also served as Chief Financial Officer, Treasurer and Director of DHS. Since 1989, he has been involved in public and private accounting with the oil and gas industry. Mr. Nanke received a Bachelor of Arts degree in Accounting from the University of Northern Iowa in 1989. Prior to working with Delta, he was employed by KPMG LLP. He is a member of the Colorado Society of CPA’s and the Council of Petroleum Accounting Society.

Stanley F. (“Ted”) Freedman has served as Executive Vice President, General Counsel and Secretary since January 1, 2006 and has also served in those same capacities for DHS since that same date. He also serves as Executive Vice President and Secretary of Amber Resources and formerly as a director of Direct Petroleum Exploration, Inc., a privately-held oil and gas company with projects in Morocco, Bulgaria, Russia and southeastern Colorado. He graduated from the University of Wyoming with a Bachelor of Arts degree in 1970 and a Juris Doctor degree in 1975. From 1975 to 1978, Mr. Freedman was a staff attorney with the United States Securities and Exchange Commission. From 1978 to December 31, 2005, he was engaged in the private practice of law, and was a shareholder and director of the law firm of Krys Boyle, P.C. in Denver, Colorado.

Board of Directors

Daniel J. Taylor has been an executive of Tracinda Corporation since February 2007 and has served as a Director of MGM Resorts International since March 2007. Mr. Taylor does not have a specific title at Tracinda but his primary responsibilities include assisting with the management of Tracinda’s investments. He was initially employed by Tracinda from May 1991 until July 1997, and has been employed in his current position at Tracinda since February 2007. During the interim period he was employed by Metro-Goldwyn-Mayer Inc., a then public corporation (“MGM”), first as Executive Vice President-Finance, then as Chief Financial Officer from August 1997 to April 2005, at which time MGM was sold. He then served as President of MGM until January 2006. Mr. Taylor received a Bachelor of Science degree in Business Administration with an emphasis in Accounting from Central Michigan University in 1978.

Hank Brown has served as the Senior Counsel to the law firm of Brownstein Hyatt Farber Schreck P.C. since June 1, 2008 and as a member of that firm’s Government Relations and Natural Resources groups. He served as the President of the University of Colorado from August 2005 to March 2008. Prior to joining CU, he was President and CEO of the Daniels Fund and served as the President of the University of Northern Colorado from 1998 to 2002. He served Colorado in the United States Senate (elected in 1990) and served five consecutive terms in the U.S. House representing Colorado’s 4th Congressional District (1980-1988). He also served in the Colorado Senate from 1972 to 1976. Mr. Brown was a Vice President of Monfort of Colorado from 1969 to 1980. He is both an attorney and a C.P.A. He earned a Bachelor’s degree in Accounting from the University of Colorado in 1961 and received his Juris Doctorate degree from the University of Colorado Law School in 1969. While in Washington, D.C., Mr. Brown earned a Master of Law degree in 1986 from George Washington University.

Kevin R. Collins currently serves as Executive Vice President and Chief Financial Officer of Bear Tracker Energy, a position he has held since July 1, 2010. Prior to his current position, Mr. Collins served as President and Chief Executive Officer of Evergreen Energy, Inc. from September 2006 until his retirement on June 1, 2009. He also served on Evergreen’s Board of Directors until he resigned effective July 1, 2009. Prior to that, he served as Evergreen’s Executive Vice President — Finance and Strategy from September 2005 to September 2006, and acting Chief Financial Officer from November 2005 until March 31, 2006. From 1995 until 2004, Mr. Collins was an executive officer of Evergreen Resources, Inc., serving as Executive Vice President and Chief Financial Officer until Evergreen Resources merged with Pioneer Natural Resources Co. in September 2004. Mr. Collins became a Certified Public Accountant in 1983 and has over 13 years’ public accounting experience. He has served as Vice President and a board member of the Colorado Oil and Gas Association, President of the Denver Chapter of the Institute of Management Accountants, and board member and Chairman of the Finance Committee of the Independent Petroleum Association of Mountain States. Mr. Collins received his Bachelor of Science degree in Business Administration and Accounting from the University of Arizona.

Jerrie F. Eckelberger is an investor, real estate developer and attorney who has practiced law in the State of Colorado since 1971. He graduated from Northwestern University with a Bachelor of Arts degree in 1966 and received his Juris Doctor degree in 1971 from the University of Colorado School of Law. From 1972 to 1975, Mr. Eckelberger was a staff attorney with the Eighteenth Judicial District Attorney’s Office in Colorado. From 1975 to the present, Mr. Eckelberger has been engaged in the private practice of law in the Denver area. Mr. Eckelberger previously served as an officer, director and corporate counsel for Roxborough Development Corporation. Since March, 1996, Mr. Eckelberger has engaged in the investment and development of Colorado real estate through several private companies in which he is a principal.

Jean-Michel Fonck is President of Geopartners SAS, a service company for petroleum studies located in France, and is consulting with the firm of JMF-Conseil SARL to various oil companies since 2001. Mr. Fonck was previously employed by TOTAL SA (“TOTAL”), serving in various capacities there from 1968 until 2000. During his tenure at TOTAL, he worked in Paris in mathematical applications to geology and exploration venture appraisals, in Indonesia as chief geologist, in Argentina and Egypt as exploration manager and in Paris again as division manager for Exploration New Ventures and International Exploration Coordination. In 1991, Mr. Fonck became President and CEO of the TOTAL exploration and production branch in Houston, and then returned to Paris in 1994 to serve as Vice President of Exploration and Reservoir Evaluation for the TOTAL group. Mr. Fonck graduated from Ecole des Mines (Nancy) in 1963.

Aleron H. Larson, Jr. has operated as an independent in the oil and gas industry individually and through public and private ventures since 1978. Mr. Larson served as Chairman of the Board, Secretary and Director of Delta, as well as Amber Resources, until his retirement on July 1, 2005, at which time he resigned as Chairman of the Board and as an executive officer of the Company. He ceased to be an officer or director of Amber Resources on January 3, 2006. Mr. Larson practiced law in Breckenridge, Colorado from 1971 until 1974. During this time he was a member of a law firm, Larson & Batchellor, engaged primarily in real estate law, land use litigation, land planning and municipal law. In 1974, he formed Larson & Larson, P.C., and was engaged primarily in areas of law relating to securities, real estate, and oil and gas until 1978. Mr. Larson received a Bachelor of Arts degree in Business Administration from the University of Texas at El Paso in 1967 and a Juris Doctor degree from the University of Colorado in 1970.

Russell S. Lewis is Executive Vice President, Strategic Development for VeriSign, Inc., located in Dulles, Virginia, which is the trusted provider of Internet infrastructure services. Mr. Lewis has held a variety of senior executive level roles at VeriSign since 1999, including the GM of VeriSign’s Naming and Directory Services Group and Senior Vice President of Corporate Development. Mr. Lewis has been a member of the Board of Directors of Delta Petroleum since June 2002. For the preceding 15 years Mr. Lewis was President and CEO of TransCore, a wireless transportation systems integration company. Prior to that Mr. Lewis managed an oil and gas exploration subsidiary of a publicly traded utility and was Vice President of EF Hutton in its Municipal Finance group. Mr. Lewis also serves on the Board of Directors of Braintech, Inc., NameMedia, Inc., and Dropps, Inc. Mr. Lewis has a Bachelors of Arts degree in Economics from Haverford College and an MBA from the Harvard School of Business.

Anthony Mandekic currently serves as the Secretary/Treasurer of Tracinda Corporation and has held such position since Tracinda Corporation’s inception in 1976. Mr. Mandekic also currently serves as Chairman of the Lincy Foundation, a charitable organization founded by Mr. Kerkorian, and has served as its Chief Financial Officer and a Director since 1989. Since May of 2006 he has served as a member of the Board of Directors of MGM Resorts International and as a member of its Executive Committee, Diversity Committee and Compensation Committee. In May of 2007 Mr. Mandekic became Chairman of the MGM Mirage Compensation Committee, and also became a member of the MGM Mirage Corporate Governance and Nominating Committee in 2009. Mr. Mandekic is a graduate of the University of Southern California with a bachelor’s degree in Science-Accounting and is a Certified Public Accountant.

James J. Murren is the Chairman and CEO of MGM Resorts International. He is also a member of the Board of Directors and the Executive Committee. Mr. Murren previously served in the following capacities for MGM Resorts: President (1999-2008), Chief Operating Officer (2007-2008), Chief Financial Officer (1998-2007), and Treasurer (2001-2007). Prior to his employment at MGM Resorts International, Mr. Murren spent 14 years on Wall Street as a top-ranked equity analyst and was appointed to Director of Research and Managing Director of Deutsche Bank. Mr. Murren received a Bachelor of Arts degree in Art History and Urban Studies from Trinity College in 1983.

Jordan R. Smith is President of Ramshorn Investments, Inc., a wholly owned subsidiary of Nabors Drilling USA LP that is located in Houston, Texas, where he is responsible for drilling and development projects in a number of producing basins in the United States. He has served in such capacity for more than the past five years. Mr. Smith has served on the Board of the University of Wyoming Foundation and the Board of the Domestic Petroleum Council, and is also Founder and Chairman of the American Junior Golf Association. Mr. Smith received Bachelor and Master degrees in Geology from the University of Wyoming in 1956 and 1957, respectively.

At the present time Messrs. Collins, Eckelberger, Lewis, Smith, and Taylor serve on the Audit Committee; Messrs. Eckelberger, Brown, Collins, Lewis, Mandekic, Murren, and Smith serve on the Compensation Committee; and Messrs. Smith, Collins, Eckelberger, Lewis, Murren, and Taylor serve on the Nominating & Governance Committee.

In conjunction with the February 2008 equity issuance to Tracinda Corporation, and in accordance with the related Company Stock Purchase Agreement, Tracinda designated Messrs. Mandekic, Murren and Taylor to serve on our Board of Directors.

All directors will hold office until the next annual meeting of stockholders. All of our officers will hold office until such time as they resign or are terminated by our Board of Directors. There is no arrangement or understanding among or between any such officers or any persons pursuant to which such officer is to be selected as one of our officers.

PART II

Item 5.		Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities

Market Information; Dividends

Delta’s common stock currently trades under the symbol “DPTR” on the NASDAQ Capital Market. The following quotations reflect inter-dealer high and low sales prices, without retail mark-up, mark-down or commission and may not represent actual transactions.

Quarter Ended		High				Low
March 31, 2009		$	6.17			$	0.88
June 30, 2009			4.63				1.05
September 30, 2009			4.68				1.46
December 31, 2009			1.85				0.73
March 31, 2010		$	1.77			$	1.14
June 30, 2010			1.71				0.86
September 30, 2010			0.87				0.69
December 31, 2010			0.86				0.72

On March 15, 2011, the closing price of our common stock was $0.96. We have not paid dividends on our common stock, and we do not expect to do so in the foreseeable future. Our current debt agreements restrict the payment of dividends.

Approximate Number of Holders of Common Stock

The number of holders of record of our common stock at March 4, 2011 was approximately 1,392 which does not include an estimated 32,266 additional holders whose stock is held in “street name.”

Recent Sales of Unregistered Securities

During the year ended December 31, 2010, we did not have any sale of securities in transactions that were not registered under the Securities Act of 1933, as amended (“Securities Act”) that have not been reported in a Form 8-K or Form 10-Q.

Issuer Purchases of Equity Securities

The table below provides a summary of our purchases of our own common stock during the three months ended December 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)
October 1 — October 31, 2010			2,153			$	0.80				—				—
November 1 — November 30, 2010			—				—				—				—
December 1 — December 31, 2010			—				—				—				—
Total			2,153			$	0.80				—				—

Item 6.		Selected Financial Data

The following selected financial information should be read in conjunction with our financial statements and the accompanying notes.

		Years Ended December 31,
		2010				2009				2008				2007				2006
		(In thousands, except per share amounts)
Total Revenues		$	146,805			$	170,203			$	242,260			$	183,251			$	163,184
Loss from continuing operations		$	(121,858	)		$	(315,313	)		$	(440,447	)		$	(103,718	)		$	(3,887	)
Net Income/(Loss) attributable to Delta common stockholders		$	(182,332	)		$	(328,783	)		$	(456,064	)		$	(149,807	)		$	2,916
Income/(Loss) attributable to
Delta common stockholders
Per Common Share
Basic		$	(0.66	)		$	(1.56	)		$	(4.77	)		$	(2.44	)		$	0.06
Diluted		$	(0.66	)		$	(1.56	)		$	(4.77	)		$	(2.44	)		$	0.05
Total Assets		$	1,024,112			$	1,457,485			$	1,894,963			$	1,110,054			$	932,614
Total Long-Term debt, including current portion		$	356,997			$	460,923			$	637,473			$	393,468			$	367,263
Total Delta Stockholders’ Equity		$	514,447			$	688,582			$	762,390			$	532,855			$	431,523
Total Non-Controlling Interest		$	(2,852	)		$	8,538			$	29,104			$	27,296			$	27,390
Total Equity		$	511,595			$	697,120			$	791,494			$	560,151			$	458,913

Item 7.		Management’s Discussion and Analysis of Financial Condition and Results of Operations

Overview

We are a Denver, Colorado based independent oil and gas company engaged primarily in the exploration for, and the acquisition, development, production, and sale of, natural gas and crude oil. Our core area of operations is the Rocky Mountain Region, which comprises virtually all of our proved reserves, production and long-term growth prospects. We have a significant drilling inventory that consists of proved and unproved locations, the majority of which are located in our Rocky Mountain development projects. At December 31, 2010, we had estimated proved reserves that totaled 134.2 Bcfe, of which 92.2% were proved developed, with a standardized measure of $192.1 million. For the year ended December 31, 2010, we reported total net production of 45.9 Mmcfe per day related to continuing operations.

As of December 31, 2010, our proved reserves were comprised of approximately 122.7 Bcf of natural gas and 1.9 Mmbbls of crude oil, or 91.4% gas on an equivalent basis. Approximately 92% of our proved reserves were located in the Rocky Mountains, 7% in the Gulf Coast and 1% in other locations. We expect that our 2011 drilling efforts and capital expenditures, when announced, will focus primarily on our Piceance Basin assets in the Rockies. As of December 31, 2010, through our position as operator, we controlled approximately 349,697 of our net undeveloped acres, representing approximately 97% of our total acreage position. We retain a high degree of operational control over our asset base, with an average working interest in excess of 85% of our proved reserve properties as of December 31, 2010. This provides us with controlling interests in a multi-year inventory of drilling locations, positioning us for continued reserve and production growth through our drilling operations when commodity prices support such activity.

2010 Developments

	•		On December 29, 2010, we amended and restated our credit agreement with MBL as more fully described in Note 7, “Long-Term Debt” to the accompanying consolidated financial statements. The MBL Credit Agreement provides for a revolving loan and a term loan each with a maturity date of January 31, 2012. The revolving loan has an initial borrowing base of $30.0 million and the term loan has an initial commitment of $20.0 million subject to a development plan that must be approved by MBL. The MBL Credit Agreement was amended on March 14, 2011 to provide for additional availability under the term loan, among other changes more fully described in Note 20, “Subsequent Events” to the accompanying consolidated financial statements.
	•		On July 30, 2010, we sold all or a portion of our interest in various non-core assets primarily located in Colorado, Texas, and Wyoming for gross cash proceeds of $130.0 million. In conjunction with the completion of the Wapiti Transaction, we repaid $108.5 million of amounts borrowed under our credit facility, and our borrowing base under the credit facility was reduced to $35.0 million. The proceeds from the Wapiti Transaction allowed us to substantially reduce our outstanding debt and when combined with the post-Wapiti Transaction borrowing base, provided the liquidity necessary to fund our third and fourth quarter 2010 development plan.
	•		On April 1, 2010, DHS, our 49.8% subsidiary, amended its existing credit facility with Lehman Commercial Paper, Inc. and renegotiated certain terms of the agreement to, among other changes more fully described in Note 7, “Long-Term Debt” to the accompanying financial statements, bring DHS into compliance with the terms of the agreement, amend the principal repayment schedule, adjust the interest rate, and eliminate or amend certain financial covenants. However, DHS was not in compliance with its minimum EBITDA covenant and quarterly capital expenditures limitation as of December 31, 2010. On January 1, 2011, DHS failed to pay its scheduled principal and interest payment and subsequently entered into a forbearance agreement that currently expires on March 25, 2011. Subsequent to year-end, the Board of Directors of DHS engaged transaction advisors to commence a strategic alternatives process, focused on a sale of the company or substantially all of its assets. There can be no assurance that the terms offered by a potential buyer, if any, will be acceptable to the DHS shareholders. Additionally, the consummation of certain transactions are subject to the approval of DHS’s senior lender and the proceeds received will be required to be used to pay down amounts outstanding under its DHS credit facility.
	•		During 2010, we divested of our equity interest in several unconsolidated affiliates. We sold our 5% interest in Collbran Valley Gas Gathering, LLC (“CVGG”) for cash proceeds of $3.5 million, our 50% investment interest in Delta Oilfield Tank Company (“DOTC”) for cash proceeds of $2.8 million and a note receivable of $2.1 million, and our 50% investment interest in Ally Equipment for cash proceeds of $250,000 and a note receivable of $1.3 million.

2011 Outlook

Based on current commodity prices and our current sources of capital, we intend to focus capital expenditures for 2011 on completing the remaining five previously drilled wells, completing our exploratory test well that was in progress at year-end 2010, drilling a second test well to continue to evaluate resource potential below the Williams Fork formation in the Vega Area, and drilling a Vega Area lease preservation well. Although our available capital is limited we expect it will be sufficient to allow for the funding of these development plans. These plans may be adjusted from time to time depending on commodity prices, exploratory well test results, capital availability or other factors.

Liquidity and Capital Resources

Our sources of liquidity and capital resources historically have been net cash provided through the issuance of debt and equity securities when market conditions permit, operating activities, sales of oil and gas properties, and through borrowings under our credit facility. The primary uses of our liquidity and capital resources have been in the development and exploration of oil and gas properties. In the past, these sources of liquidity and capital have been sufficient to meet our needs. In 2010, to address our liquidity needs, we sold certain non-core assets to Wapiti Oil & Gas, LLC for $130.0 million.

We believe that the amounts available under our credit facility as recently amended, combined with our net cash from operating activities, will provide us with sufficient funds to fund our operating expenses planned and capital development activities described herein and maintain current debt service obligations. As discussed above, our 2011 capital expenditure program, and in particular our drilling and completion capital budget for the Vega Area, is dependent on the results of our completion activities on the Vega Area exploratory test wells that are currently underway. To the extent cash flow from operating activities are not sufficient to support our future capital expenditure program, and in order to address the January 2012 maturity of our credit facility and the potential mandatory redemption in May 2012 of our $115.0 million convertible notes, it is likely that we will need to seek sources of long-term capital (including the issuance of equity, debt instruments, sales of assets and joint venture financing), as well as consider other potential corporate transactions such as a sale of the company. The timing, term, size, and pricing of any such financing or transaction will depend on investor interest and market conditions, as well as the Company’s drilling and completion results, and there can be no assurance that we will be able to obtain any such financing or consummate any such transaction, and if so, that it will be on terms satisfactory to the Company.

Our Credit Facility

On December 29, 2010, we amended and restated our credit agreement (the “MBL Credit Agreement”) whereby the former lenders assigned their interests to Macquarie Bank Limited (“MBL”). The MBL Credit Agreement provides for a revolving loan and a term loan each with a maturity date of January 31, 2012. The revolving loan has an initial borrowing base of $30.0 million and the term loan had an initial commitment of $20.0 million subject to a development plan that must be approved by MBL. As of December 31, 2010, we had approximately $6.2 million of availability under the term loan based on the MBL approved development plan. See Note 7, “Long-Term Debt” to the accompanying consolidated financial statements. At December 31, 2010, we were in compliance with the financial covenants under the MBL Credit Agreement.

On March 14, 2011, we entered into an amendment to the MBL Credit Agreement that increased the availability under the term loan at the time from $6.2 million to $25.0 million, and doesn’t require repayments of the term loan until the January 2012 maturity date. Specifically, among other changes, the amendment provided for an increase in the term loan commitment from $20.0 million to $25.0 million and removed the requirement that advances under the term loan be subject to approval of a development plan. In addition, so long as Delta is not in default under the MBL Credit Agreement, Delta is not required to comply with certain cash management provisions, including the previous requirement to repay any term loan advances outstanding on a monthly basis with 100% of net operating cash flows. See Note 20, “Subsequent Events” to the accompanying consolidated financial statements.

DHS Credit Facility

At December 31, 2010, DHS was out of compliance with the debt covenants under its credit facility and subsequently entered into a Forbearance Agreement with LCPI which expires on March 25, 2011. The DHS credit facility matures on August 31, 2011 and, as such, all amounts outstanding under the DHS credit facility are classified as a current liability in the accompanying consolidated balance sheet as of December 31, 2010. Accordingly, DHS is facing significant requirements to fund obligations in excess of its existing sources of liquidity when the forbearance agreement expires. DHS is in discussions with its credit facility lender regarding further amendments, waivers or other restructuring of the credit facility, but there can be no assurance that the lender will agree to any such amendments. In addition, subsequent to year-end, the Board of Directors of DHS engaged transaction advisors to commence a strategic alternatives process, focused on a sale of the company or substantially all of its assets. There can be no assurance that the terms offered by a potential buyer, if any, will be acceptable to the DHS shareholders. Additionally, the consummation of certain transactions are subject to the approval of DHS’s senior lender and the proceeds received will be required to be used to pay down amounts outstanding under its DHS credit facility.

Capital Resources and Requirements

Our accompanying financial statements have been prepared assuming we will continue as a going concern. During the year ended December 31, 2010, significant improvements to our liquidity position were achieved through the Wapiti Transaction described above and the amendment of our credit facility. However, the MBL Credit Agreement matures in January 2012 and the holders of our $115.0 million convertible notes can require us to repurchase the notes at par on May 1, 2012. Thus, our ability to continue as a going concern could be dependent upon our lender’s willingness to amend the terms or extend the maturity of our credit facility, the convertible note holders’ willingness to amend or restructure the convertible notes, or our success in generating additional sources of capital in the near future.

As of December 31, 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 December 31, 2010, our corporate credit and senior unsecured debt ratings were CCC and CCC-, respectively, as issued by Standard and Poor’s (“S&P”). S&P’s outlook on its rating was “negative.”

Our future cash requirements are also largely dependent upon the number and timing of projects included in our capital development plan, most of which are discretionary. The prices we receive for future oil and natural gas production and the level of production have a significant impact on our operating cash flows. Beyond the volumes for which we have entered into derivative contracts, we are unable to predict with any degree of certainty the prices we will receive for our future oil and gas production or the success of our exploration and development activities in generating additional production.

Cash Flows

On July 30, 2010, we completed the $130.0 million sale of certain non-core properties to Wapiti. Proceeds were used to reduce credit facility borrowings and fund development. During 2010, we divested of our equity interests in certain unconsolidated affiliates for proceeds of $6.7 million. With proceeds from these transactions, we have reduced our borrowings outstanding under our credit facility from $124.0 million at December 31, 2009 to $29.1 million at December 31, 2010. In addition, we reduced our accounts payable and offshore litigation payable from $58.1 million at December 31, 2009 to $36.2 million at December 31, 2010.

As shown in the accompanying financial statements and discussed elsewhere herein, we experienced a net loss attributable to Delta common stockholders of $182.3 million for the year ended December 31, 2010. We were in compliance with our financial covenants under our credit facility at December 31, 2010.

During the year ended December 31, 2010, we had an operating loss of $102.5 million, net cash used in operating activities of $31.5 million and net cash used in financing activities of $212.6 million. During this period we spent $41.6 million on oil and gas development activities. At December 31, 2010, we had $15.7 million in cash and $7.1 million available under our credit facility, total assets of $1.0 billion and a debt to capitalization ratio of 41.1%. Debt, excluding installments payable on property acquisition which are

secured by restricted cash deposits, at December 31, 2010 totaled $357.0 million, comprised of $98.7 million of bank debt ($29.1 million of our indebtedness under our MBL Credit Agreement and $69.6 million of DHS indebtedness, of which the DHS indebtedness was classified as current at December 31, 2010), $149.6 million of senior subordinated notes and $104.0 million of senior convertible notes. In accordance with applicable accounting rules, the senior convertible notes are recorded at a discount to their stated amount due of $115.0 million.

Results of Operations

The following discussion and analysis relates to items that have affected our results of operations for the years ended December 31, 2010, 2009 and 2008. The following table sets forth (in thousands), for the periods presented, selected historical statements of operations data. The information contained in the table below should be read in conjunction with our consolidated financial statements and accompanying notes included in this Annual Report on Form 10-K.

		Years Ended December 31,
		2010				2009				2008
Revenue:
Oil and gas sales		$	94,388			$	82,723			$	192,815
Contract drilling and trucking fees			53,212				13,680				49,445
Gain on offshore litigation settlement, net of loss on property sales			(795	)			73,800				—
Total revenue			146,805				170,203				242,260
Operating Expenses:
Lease operating expense			24,566				26,439				27,896
Transportation expense			15,211				10,057				7,925
Production taxes			3,727				3,032				11,185
Exploration expense			1,337				2,604				10,975
Dry hole costs and impairments			43,572				176,871				411,103
Depreciation, depletion, amortization and accretion — oil and gas			58,265				81,335				80,218
Drilling and trucking operating expenses			42,248				15,293				32,594
Goodwill and drilling equipment impairments			—				6,508				29,349
Depreciation and amortization — drilling and trucking			19,964				22,917				14,134
General and administrative expense			41,130				41,414				53,607
Executive severance expense, net			(674	)			3,739				—
Total operating expenses			249,346				390,209				678,986
Operating loss			(102,541	)			(220,006	)			(436,726	)
Other income and (expense):
Interest expense and financing costs, net			(37,247	)			(52,581	)			(35,357	)
Other income (expense)			(1,409	)			1,049				(5,210	)
Realized gain (loss) on derivative instruments, net			(5,835	)			(1,115	)			18,383
Unrealized gain (loss) on derivative instruments, net			23,979				(26,972	)			3,365
Income (loss) from unconsolidated affiliates			1,738				(15,473	)			3,375
Total other expense			(18,774	)			(95,092	)			(15,444	)
Loss from continuing operations before income taxes and discontinued operations			(121,315	)			(315,098	)			(452,170	)
Income tax expense (benefit)			543				215				(11,723	)
Loss from continuing operations			(121,858	)			(315,313	)			(440,447	)
Loss from results of operations and sale of discontinued operations, net of tax			(72,156	)			(34,371	)			(27,103	)
Net loss			(194,014	)			(349,684	)			(467,550	)
Less net loss attributable to non-controlling interest			11,682				20,901				11,486
Net loss attributable to Delta common stockholders		$	(182,332	)		$	(328,783	)		$	(456,064	)

Year Ended December 31, 2010 Compared to Year Ended December 31, 2009

Net Income (Loss) Attributable to Delta Common Stockholders. Net loss attributable to Delta common stockholders was $182.3 million, or $0.66 per diluted common share, for the year ended December 31, 2010, compared to net loss of $328.8 million or $1.56 per diluted common share, for the year ended December 31, 2009. Loss from continuing operations decreased from $315.3 million for the year ended December 31, 2009 to a loss of $121.9 million for the year ended December 31, 2010. The decreased loss was primarily due to fewer dry holes and impairments recorded in 2010 as compared to 2009, improved oil and gas operations, changes in unrealized gains (losses) on derivative instruments, and lower interest and financing costs. Explanations of significant items affecting comparability between periods are discussed by the financial statement captions below.

Oil and Gas Sales. During the year ended December 31, 2010, oil and gas sales from continuing operations were $94.4 million, as compared to $82.7 million for the comparable period a year earlier. During the year ended December 31, 2010, production from continuing operations decreased by 21% and the average natural gas and oil price increased 62% and 35%, respectively. The average gas price received during the year ended December 31, 2010 was $5.01 per Mcf compared to $3.09 per Mcf for the year earlier period and the average oil price received during the year ended December 31, 2010 was $70.90 per Bbl compared to $52.45 per Bbl for the year earlier period. The production decrease was primarily related to divestitures in the Gulf Coast area in 2010 and production declines in the Rocky Mountain Region where completion activity did not resume until late 2010.

Contract Drilling and Trucking Fees. Drilling and trucking revenues for the year ended December 31, 2010 increased to $53.2 million compared to $13.7 million for the prior year period. Drilling and trucking revenues increased significantly in 2010 due to higher third party rig utilization in 2010 compared to the prior year, resulting from increased drilling activity attributable in particular to higher oil prices. Drilling and trucking revenues earned on wells drilled for Delta have been eliminated in consolidation.

Gain on Offshore Litigation Settlement, Net of Loss on Property Sales. During 2009, we recorded gains of $79.5 million related to two offshore litigation awards. See Note 4, “Oil and Gas Properties,” to the accompanying financial statements. In addition, during the fourth quarter of 2009, we recorded losses of $5.7 million on several non-core property divestiture transactions. During 2010, minor losses of $795,000 were recorded on several non-core property divestitures.

Production and Cost Information

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

		Years Ended December 31,
		2010				2009
Production — Continuing Operations:
Oil (MBbl)			500				734
Gas (MMcf)			11,759				14,319
Total (MMcfe)			14,759				18,727
Average Price — Continuing Operations:
Oil (per barrel)		$	70.90			$	52.45
Gas (per Mcf)		$	5.01			$	3.09
Costs per Mcfe — Continuing Operations:
Lease operating expense		$	1.66			$	1.41
Production taxes		$	0.25			$	0.16
Transportation costs		$	1.03			$	0.54
Depletion expense		$	3.73			$	4.19

Lease Operating Expense. Lease operating expenses for the year ended December 31, 2010 were $24.6 million compared to $26.4 million for the year earlier period. Lease operating expense from continuing operations for the year ended December 31, 2010 decreased $1.8 million from the year earlier period. However, lease operating expenses increased on a per unit basis primarily due to the effect of fixed costs spread over a 21% decline in

production volumes. The average lease operating expense was $1.66 per Mcfe in 2010 as compared to $1.41 per Mcfe for the year earlier period.

Transportation Expense. Transportation expense for the year ended December 31, 2010 was $15.2 million, comparable to prior year costs of $10.1 million, up 91% on a per unit basis from $0.54 per Mcfe to $1.03 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. Although the Vega area transportation costs increased on a per unit basis in 2010 as a result of these operations, this was more than offset by higher revenues in the Vega area from improved natural gas liquids recoveries and a greater percentage of liquids proceeds retained.

Exploration Expense. Exploration expense consists of geological and geophysical costs and lease rentals. Our exploration costs for the year ended December 31, 2010 were $1.3 million compared to $2.6 million for the year earlier period. Exploration activities in 2010 were limited due to our funding constraints and primarily consisted of delay rental payments. In contrast, significant amounts were spent in 2009 on seismic shoots in several areas of exploration activity and delay rental payments were nearly double the 2010 level.

Dry Hole Costs and Impairments. We incurred dry hole costs of approximately $86,000 for the year ended December 31, 2010 compared to $33.6 million for the comparable period a year ago. As of December 31, 2010, we had one exploratory well in progress, the results of which could, if unsuccessful, impact dry hole costs in future periods. For the year ended December 31, 2009, our dry hole costs related primarily to our Columbia River Basin exploratory well (the Gray Well) in Washington.

During the year ended December 31, 2010, we recorded impairment provisions related to continuing operations attributable to our proved and unproved properties and other items totaling approximately $43.5 million primarily related to proved impairments to our Opossum Hollow and Golden Prairie fields of $1.1 million and unproved impairments of $30.0 million related to our Columbia River Basin leasehold, Hingeline leasehold, Haynesville leasehold, Delores River leasehold, Howard Ranch leasehold, and our non-operated Garden Gulch field in the Piceance Basin. Other impairments primarily included $6.7 million for the produced water handling facility in Vega and $4.9 million to reduce the Paradox pipeline carrying value to its estimated fair value. These impairments generally resulted from the lack of success in marketing these non-core assets combined with our lack of plans to develop the acreage.

During the year ended December 31, 2009, we recorded impairment provisions related to continuing operations attributable to our proved and unproved properties totaling approximately $143.3 million primarily related to our non-operated Garden Gulch field in the Piceance Basin of $38.6 million, Haynesville Shale of $27.5 million, Columbia River Basin of $21.4 million, Lighthouse Bayou of $14.8 million, various Gulf Coast fields of $18.5 million, Vega surface land of $10.5 million, various Rockies fields of $5.4 million, pipe and tubular inventory of $4.3 million and Paradox pipeline of $1.9 million. These impairments generally resulted from sustained lower commodity prices for most of 2009, near term expiring leasehold, unsuccessful drilling results, or our inability to meet contractual drilling obligations.

Depreciation, Depletion and Amortization — Oil and Gas. Depreciation, depletion and amortization expense decreased 28% to $58.3 million for the year ended December 31, 2010, as compared to $81.3 million for the year earlier period. Depletion expense for the year ended December 31, 2010 was $55.0 million compared to $78.4 million for the year ended December 31, 2009. The 30% decrease in depletion expense was primarily due to a 21% decrease in production from continuing operations and an 11% decrease in the depletion rate. Our depletion rate decreased to $3.73 per Mcfe for the year ended December 31, 2010 from $4.19 per Mcfe for the year earlier period. The decrease is primarily due to a change in the mix of our properties as a result of the Wapiti Transaction and additional Rockies reserves recorded in 2010 as a result of completion activities and use of improved fracturing methods.

Drilling and Trucking Operating Expenses. We had drilling and trucking operating expenses of $42.2 million during the year ended December 31, 2010 compared to $15.3 million during the year ended December 31, 2009. The increase is due to higher third party rig utilization during 2010.

Depreciation and Amortization — Drilling and Trucking. Depreciation and amortization expense — drilling and trucking decreased to $20.0 million for the year ended December 31, 2010 as compared to $22.9 million for the prior year period. The decrease is due to the full year effect of impairments taken in 2009 and sales of rig equipment. 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 slightly to $41.1 million for the year ended December 31, 2010, as compared to $41.4 million for the comparable prior year period. The decrease in general and administrative expenses is primarily attributed to lower expenses incurred on employee benefits and wages from reductions in force during 2010 and 2009 but was offset by significant costs associated with the strategic alternatives process and bad debt expense recorded by DHS. We expect further reductions to full year cash general and administrative expenses in 2011 as cost saving measures implemented in 2010 take full effect in 2011.

Executive Severance Expense, Net. On May 26, 2009, our then Chairman of the Board of Directors and Chief Executive Officer, Roger A. Parker, resigned from Delta. In consideration for Mr. Parker’s resignation and his agreement to (a) relinquish all his rights under his employment agreement, his change-in-control agreement, certain stock agreements, bonuses relating to past and pending transactions benefiting Delta, and any other interests he might claim arising from his efforts as Chairman of our Board of Directors and/or Chief Executive Officer, and (b) stay on as a consultant to facilitate an orderly transition and to assist in certain pending transactions, Delta agreed to pay Mr. Parker $4.7 million in cash, issue to him 1.0 million shares of Delta common stock, pay him the aggregate of any accrued unpaid salary, vacation days and reimbursement of his reasonable business expenses incurred through the effective date of the agreement, and provide to him insurance benefits similar to his pre-resignation benefits for a thirty-six month period. The Severance Agreement also contained mutual releases and non-disparagement provisions, as well as other customary terms. In addition, $2.8 million of equity compensation costs previously recorded in the consolidated financial statements related to shares which were forfeited as a result of the severance agreement were reversed and reflected as a reduction of executive severance expense.

On July 6, 2010, John Wallace, our then President, Chief Operating Officer and a Director, resigned from all of his positions as director, officer and employee of Delta and any of our subsidiaries. In conjunction with such resignation, we entered into a severance agreement with Mr. Wallace pursuant to which he agreed to (a) relinquish certain rights under his employment agreement, his change-in-control agreement, certain stock agreements, bonuses relating to past and pending transactions benefiting Delta, and certain other interests he might claim arising from his efforts in his previous capacities with us and our subsidiaries, and (b) make himself reasonably available to answer questions to facilitate an orderly transition. Under the terms of his severance arrangement, we paid Mr. Wallace a lump sum of $1.6 million, paid him his salary for the full month in which his resignation occurred and for his accrued vacation days, reimbursed him for his reasonable business expenses incurred through the effective date of the agreement, and agreed to provide to him insurance benefits similar to his pre-resignation benefits for the period in which Mr. Wallace is entitled to receive COBRA coverage under applicable law. The severance agreement also contained mutual releases and non-disparagement provisions, as well as other customary terms. In addition, $2.3 million of equity compensation costs previously recorded in the consolidated financial statements related to performance shares forfeited prior to their derived service period being completed as a result of the severance agreement were reversed and reflected as a reduction of executive severance expense.

Interest Expense and Financing Costs, Net. Interest expense and financing costs decreased 29% to $37.2 million for the year ended December 31, 2010, as compared to $52.6 million for the comparable year earlier period. The decrease is primarily related to lower average outstanding Delta and DHS credit facility balances during 2010 as compared to 2009. The decrease is also related to a greater write-off of unamortized deferred financing costs and waiver fees related to the amendments to our credit facilities in 2009 compared to 2010. In addition, the year ended December 31, 2009 included $1.0 million of interest expense related to the repurchase from Tracinda of offshore litigation contingent payment rights and $643,000 for the write off of previously unamortized deferred financing costs related to the DHS credit agreement.

Realized Gain on Derivative Instruments, Net. During the year ended December 31, 2010, we recognized $5.8 million of realized losses associated with settlements on derivative contracts and $1.1 million of realized losses on derivative instruments for the year ended December 31, 2009.

Unrealized Gain on Derivative Instruments, Net. We recognize mark-to-market gains or losses in current earnings instead of deferring those amounts in accumulated other comprehensive income. Accordingly, we recognized $24.0 million of unrealized gain on derivative instruments in other income and expense during the year ended December 31, 2010 compared to an unrealized loss of $27.0 million for the comparable prior year period, primarily due to changes in the movement of commodity prices in the respective years.

Income (Loss) From Unconsolidated Affiliates. Income from unconsolidated affiliates during the year ended December 31, 2010 is primarily the result of our pro-rata share of net income of our unconsolidated affiliates. During 2010, we sold our investment in Ally Equipment for a loss of $522,000 and we sold our investment in Delta Oilfield Tank Company (“DOTC”) for a gain of $676,000.

Loss from unconsolidated affiliates during the year ended December 31, 2009 was primarily the result of $3.4 million of impairments to the carrying value of our investment in Ally Equipment, $3.3 million in Delta Oilfield Tank Company (“DOTC”), $1.4 million in Collbran Valley Gas Gathering, LLC (“CVGG”) and $1.0 million in Arista in addition to the bad debt reserve of $5.0 million to reduce the carrying value of our note receivable from DOTC to the amount estimated to be collectible. These impairments were generally the result of the industry wide downturn caused by the significant decline in commodity prices and the limitation on availability of credit in 2008 and through late 2009 which had a material adverse impact on our investments.

Income Tax Benefit (Expense). Due to our continuing 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 in 2007. Our subsidiary, DHS, was similarly required to record a valuation allowance for its deferred tax assets beginning in 2009. Our income tax expense for the years ended December 31, 2010 and 2009 primarily relates to the amortization of other tax assets generated for Delta by work performed for Delta by DHS. No benefit was provided in either period for Delta or DHS net operating losses.

Discontinued Operations. The results of operations and impairment loss related to non-core property interests sold in the Garden Gulch field, Baffin Bay field, and Bull Canyon field as well as our interest in our wholly-owned subsidiary Piper Petroleum have been reflected as discontinued operations as a result of the sale to Wapiti. In separate transactions, we sold our interests in the Howard Ranch and Laurel Ridge fields which are also included in discontinued operations.

The following table shows the total revenues and expenses included in discontinued operations for the above mentioned oil and gas properties for the years ended December 31, 2010 and 2009 (dollar amounts in thousands):

		Years Ended
		December 31,
		2010				2009
Production — Discontinued Operations:
Oil (Mbbl)			15				27
Gas (Mmcf)			1,911				3,272
Total Production (Mmcfe) — Discontinued Operations			2,001				3,434
Revenues		$	9,724			$	12,239
Operating expenses:
Lease operating expense			2,781				4,864
Transportation expense			1,461				1,555
Production taxes			612				820
Depreciation, depletion, amortization and accretion			13,842				27,170
Impairments			92,162				12,201
Total operating expenses			110,858				46,610
Loss from discontinued operations			(101,134	)			(34,371	)
Income tax expense			—				—
Loss from results of operations of discontinued properties, net of tax			(101,134	)			(34,371	)
Gain on sales of discontinued operations, net			28,978				—
Total loss from discontinued operations		$	(72,156	)		$	(34,371	)

On July 23, 2010, we entered into a definitive Purchase and Sale Agreement with Wapiti to sell all or a portion of our interest in various non-core assets primarily located in Colorado, Texas, and Wyoming for gross cash proceeds of $130.0 million resulting in a net loss of $66.5 million (including impairment losses of $96.2 million). For financial reporting purposes, a $4.0 million impairment loss is included within dry hole costs and impairments in continuing operations, $92.2 million of impairments are included within loss from discontinued operations, and a $29.7 million gain on sale is included in gain on sale of discontinued operations.

During 2010, we also sold our Howard Ranch properties for $550,000, recognizing a loss on the sale of $687,000. During 2009, we recorded impairments on the Howard Ranch and Laurel Ridge fields of $1.5 million and $10.7 million, respectively, as a result of the significant decline in commodity pricing for most of 2009 causing downward revisions to proved reserves which led to impairments.

Net Loss Attributable to 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 years ended December 31, 2010 and 2009, DHS reported significant losses from low rig utilization rates which resulted in a non-controlling interest credit to earnings.

Year Ended December 31, 2009 Compared to Year Ended December 31, 2008

Net Income (Loss) Attributable to Delta Common Stockholders. Net loss attributable to Delta common stockholders was $328.8 million, or $1.56 per diluted common share, for the year ended December 31, 2009, compared to net loss of $456.1 million or $4.77 per diluted common share, for the year ended December 31, 2008. Loss from continuing operations decreased from $440.4 million for the year ended December 31, 2008 to a loss of $315.3 million for the year ended December 31, 2009. The decreased loss was primarily due to fewer dry holes and impairments recorded in 2009 as compared to 2008, offset by lower oil and gas sales. Explanations of significant items affecting comparability between periods are discussed by the financial statement captions below.

Oil and Gas Sales. During the year ended December 31, 2009, oil and gas sales from continuing operations were $82.7 million, as compared to $192.8 million for the comparable period a year earlier. During the year ended December 31, 2009, production from continuing operations decreased by 10% and the average natural gas and oil price decreased 55% and 43%, respectively. The average gas price received during the year ended December 31, 2009 was $3.09 per Mcf compared to $6.92 per Mcf for the year earlier period and the average oil price received during the year ended December 31, 2009 was $52.45 per Bbl compared to $92.47 per Bbl for the year earlier period. The production decrease was primarily related to production declines in the Rockies and Gulf Coast areas that were not offset by additional drilling or completion activities due to the limited capital budget in 2009.

Contract Drilling and Trucking Fees. Drilling and trucking revenues for the year ended December 31, 2009 decreased to $13.7 million compared to $49.4 million for the prior year period. Drilling and trucking revenues decreased in 2009 due to lower third party rig utilization in 2009 compared to the prior year, resulting from a significant industry slowdown attributable to lower commodity prices. Drilling and trucking revenues earned on wells drilled for Delta have been eliminated in consolidation.

Gain on Offshore Litigation Settlement Net of Loss on Property Sales. During 2009, we recorded gains of $79.5 million related to two offshore litigation awards. See Note 4, “Oil and Gas Properties,” to the accompanying financial statements. In addition, during the fourth quarter of 2009, we recorded losses of $5.7 million on several non-core property divestiture transactions.

Production and Cost Information

Production volumes, average prices received and cost per equivalent Mcf for the years ended December 31, 2009 and 2008 are as follows:

		Years Ended December 31,
		2009				2008
Production — Continuing Operations:
Oil (MBbl)			734				950
Gas (MMcf)			14,319				15,164
Total (MMcfe)			18,727				20,863
Average Price — Continuing Operations:
Oil (per barrel)		$	52.45			$	92.47
Gas (per Mcf)		$	3.09			$	6.92
Costs per Mcfe — Continuing Operations:
Lease operating expense		$	1.41			$	1.34
Production taxes		$	0.16			$	0.54
Transportation costs		$	0.54			$	0.38
Depletion expense		$	4.19			$	3.72

Lease Operating Expense. Lease operating expenses for the year ended December 31, 2009 were $26.4 million compared to $27.9 million for the year earlier period. Lease operating expense from continuing operations for the year ended December 31, 2009 remained relatively flat from the year earlier period. However, lease operating expenses increased on a per unit basis primarily due to the effect of fixed costs spread over declining production volumes. The average lease operating expense was $1.41 per Mcfe in 2009 as compared to $1.34 per Mcfe for the year earlier period.

Transportation Expense. Transportation expense for the year ended December 31, 2009 was $10.1 million, comparable to prior year costs of $7.9 million, but up 42% from $0.38 per Mcfe to $0.54 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. This increase in cost was more than offset by higher revenues in the Vega area from improved natural gas liquids recoveries and a greater percentage of liquids proceeds retained.

Exploration Expense. Exploration expense consists of geological and geophysical costs and lease rentals. Our exploration costs for the year ended December 31, 2009 were $2.6 million compared to $11.0 million for the year earlier period. Exploration activities in 2009 were limited due to our funding constraints and primarily consisted of delay rental payments and limited seismic activity. In contrast, significant amounts were spent in 2008 on seismic shoots in several areas of exploration activity.

Dry Hole Costs and Impairments. We incurred dry hole costs of approximately $33.6 million for the year ended December 31, 2009 compared to $111.9 million for the comparable 2008 period. For the year ended December 31, 2009, our dry hole costs related primarily to our Columbia River Basin exploratory well (the Gray Well) in Washington. For the year ended December 31, 2008, our dry hole costs related primarily to Greentown and Hingeline exploratory projects in Utah.

During the year ended December 31, 2009, we recorded impairment provisions related to continuing operations attributable to our proved and unproved properties totaling approximately $143.3 million primarily related to our non-operated Garden Gulch field in the Piceance Basin of $38.6 million, Haynesville Shale of $27.5 million, Columbia River Basin of $21.4 million, Lighthouse Bayou of $14.8 million, various Gulf Coast fields of $18.5 million, Vega surface land of $10.5 million, various Rockies fields of $5.4 million, pipe and tubular inventory of $4.3 million and Paradox pipeline of $1.9 million. These impairments generally resulted from sustained lower commodity prices for most of 2009, near term expiring leasehold, unsuccessful drilling results, or our inability to meet contractual drilling obligations.

During the year ended December 31, 2008, we recorded impairment provisions related to continuing operations attributable to our proved and unproved properties totaling approximately $277.7 million primarily related to the Newton, Midway Loop, Opossum Hollow and Angleton fields in Texas of $192.5 million, Paradox field in Utah of $30.5 million, Howard Ranch and Bull Canyon fields in the Rockies of $4.1 million, Utah Hingeline of $40.8 million and our offshore California field of $9.8 million. In addition, we recorded impairments to our Paradox pipeline of $21.5 million. The impairments resulted primarily from the significant decline in commodity pricing during the fourth quarter of 2008 and unsuccessful drilling results.

Depreciation, Depletion and Amortization — Oil and Gas. Depreciation, depletion and amortization expense increased 1% to $81.3 million for the year ended December 31, 2009, as compared to $80.2 million for the year earlier period. Depletion expense for the year ended December 31, 2009 was $78.4 million compared to $77.7 million for the year ended December 31, 2008. The 1% increase in depletion expense was primarily due to a 13% increase in the depletion rate. Our depletion rate increased to $4.19 per Mcfe for the year ended December 31, 2009 from $3.72 per Mcfe for the year earlier period. The increase is primarily due to the effects of low Rockies gas prices throughout most of 2009 and low 12-month average historical prices at December 31, 2009 on the reserves used in our depletion calculation.

Drilling and Trucking Operating Expenses. We had drilling and trucking operating expenses of $15.3 million during the year ended December 31, 2009 compared to $32.6 million during the year ended December 31, 2008. The decrease is due to lower third party rig utilization during 2009 but is not proportional to the decline in contract drilling and trucking fees due to fixed costs and costs associated with a large number of stacked rigs.

Goodwill and Drilling Equipment Impairments. We performed our annual DHS goodwill impairment test during the quarter ended September 30, 2008; however, due to the deterioration in the market conditions and decreased utilization, we re-evaluated the DHS goodwill and the fair values of our rigs as of December 31, 2008. We determined that the book value of the rigs was impaired by $21.6 million. As a result of the analysis performed at year-end 2008, we also wrote off the entire amount of DHS’s goodwill of $7.7 million. During the second quarter of 2009, we concluded that DHS spare equipment required impairments of approximately $6.5 million.

Depreciation and Amortization — Drilling and Trucking. Depreciation and amortization expense — drilling and trucking increased to $22.9 million for the year ended December 31, 2009 as compared to $14.1 million for the prior year period. The increase is due to less drilling done by DHS for us in 2009 as compared to 2008. 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 23% to $41.4 million for the year ended December 31, 2009, as compared to $53.6 million for the comparable prior year period. The decrease in general and administrative expenses is primarily attributed to lower expenses incurred on employee benefits and wages from reductions in force during 2009 and a decrease in non-cash stock compensation expense.

Executive Severance Expense, Net. On May 26, 2009, our then Chairman of the Board of Directors and Chief Executive Officer, Roger A. Parker, resigned from Delta. In consideration for Mr. Parker’s resignation and his agreement to (a) relinquish all his rights under his employment agreement, his change-in-control agreement, certain stock agreements, bonuses relating to past and pending transactions benefiting Delta, and any other interests he might claim arising from his efforts as Chairman of our Board of Directors and/or Chief Executive Officer, and (b) stay on as a consultant to facilitate an orderly transition and to assist in certain pending transactions, Delta agreed to pay Mr. Parker $4.7 million in cash, issue to him 1.0 million shares of Delta common stock, pay him the aggregate of any accrued unpaid salary, vacation days and reimbursement of his reasonable business expenses incurred through the effective date of the agreement, and provide to him insurance benefits similar to his pre-resignation benefits for a thirty-six month period. The Severance Agreement also contained mutual releases and non-disparagement provisions, as well as other customary terms. In addition, $2.8 million of equity compensation costs previously recorded in the consolidated financial statements related to shares which were forfeited as a result of the severance agreement were reversed and reflected as a reduction of executive severance expense.

Interest Expense and Financing Costs, Net. Interest expense and financing costs, net increased 49% to $52.6 million for the year ended December 31, 2009, as compared to $35.4 million for the comparable year earlier period. The increase is primarily related to the write-off of deferred financing costs in conjunction with our reduced

borrowing base, offshore litigation contingent payment financing costs, higher average debt balances and interest rates on the Delta and DHS credit facilities, non-cash accretion of discount on an installment obligation payable to EnCana Oil and Gas (USA) Inc. (“EnCana”), and a decrease in interest income to $2.5 million in 2009 from $10.1 million in 2008.

Other Income and (Expense). Other expense for the year ended December 31, 2008 includes $4.6 million of impairment charges related to our auction rate securities and $1.3 million related to a forfeited deposit for a rig acquisition that DHS was unable to close due to Lehman’s failure to fund under the DHS credit facility. Other income in 2009 was insignificant.

Realized Gain (Loss) on Derivative Instruments, Net. During the years ended December 31, 2009 and 2008, we recognized $1.1 million of realized losses and $18.4 million of realized gains, respectively, associated with settlements on derivative contracts.

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 $27.0 million of unrealized losses on derivative instruments in other income and expense during the year ended December 31, 2009 compared to an unrealized gain of $3.4 million for the comparable prior year period, primarily due to changes in the movement of commodity prices in the respective years.

Income (Loss) From Unconsolidated Affiliates. Loss from unconsolidated affiliates during the year ended December 31, 2009 was primarily the result of $3.4 million of impairments to the carrying value of our investment in Ally Equipment, $3.3 million in Delta Oilfield Tank Company (“DOTC”), $1.4 million in Collbran Valley Gas Gathering, LLC (“CVGG”) and $1.0 million in Arista in addition to the bad debt reserve of $5.0 million to reduce the carrying value of our note receivable from DOTC to the amount estimated to be collectible. These impairments were generally the result of the industry wide downturn caused by the significant decline in commodity prices and the limitation on availability of credit in 2008 and through late 2009 which had a material adverse impact on our investments.

Income from unconsolidated affiliates during 2008 is comprised of our pro-rata share of net income from our unconsolidated affiliates.

Income Tax Benefit (Expense). Due to our continuing 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 in 2007. Our subsidiary, DHS, was similarly required to record a valuation allowance for its deferred tax assets beginning in 2009. Income tax expense for the year ended December 31, 2009 primarily relates to the amortization of other tax assets generated for Delta by work performed for Delta by DHS. No benefit was provided in 2009 for Delta or DHS net operating losses. Income tax benefit for the year ended December 31, 2008 primarily related to the deferred tax benefit recorded on DHS net operating losses.

Discontinued Operations. The results of operations and impairment loss related to non-core property interests sold in the Garden Gulch field, Baffin Bay field, and Bull Canyon field, as well as our interest in our wholly-owned subsidiary Piper Petroleum, have been reflected as discontinued operations as a result of the sale to Wapiti in 2010. In separate transactions in 2010, we also sold our interest in the Howard Ranch and Laurel Ridge fields which are also included in discontinued operations.

The following table shows the total revenues and expenses included in discontinued operations for the above mentioned oil and gas properties for the years ended December 31, 2009 and 2008 (dollar amounts in thousands):

		Years Ended
		December 31,
		2009				2008
Production — Discontinued Operations:
Oil (Mbbl)			27				43
Gas (Mmcf)			3,272				3,784
Total Production (Mmcfe) — Discontinued Operations			3,434				4,042
Revenues		$	12,239			$	28,918
Operating expenses:
Lease operating expense			4,864				5,612
Transportation expense			1,555				3,470
Production taxes			820				890
Depreciation, depletion, amortization and accretion			27,170				18,907
Impairments			12,201				27,860
Total operating expenses			46,610				56,739
Loss from discontinued operations			(34,371	)			(27,821	)
Income tax expense			—				—
Loss from results of operations of discontinued properties, net of tax			(34,371	)			(27,821	)
Gain on sale of discontinued operations			—				718
Total loss from discontinued operations		$	(34,371	)		$	(27,103	)

During 2009, we recorded impairments on the Howard Ranch and Laurel Ridge fields of $1.5 million and $10.7 million, respectively, as a result of the significant decline in commodity pricing for most of 2009 causing downward revision to proved reserves. During 2008, we recorded impairments on the Howard Ranch and Bull Canyon fields of $21.8 million and $6.1 million, respectively, as a result of the significant decline in commodity pricing during the fourth quarter of 2008 and unsuccessful drilling results.

During the year ended December 31, 2008, we completed an asset exchange agreement where we acquired additional interests in our Midway Loop properties in exchange for cash and certain non-core properties. The transaction resulted in a gain on the disposition of the non-core properties of $718,000.

Net (Income) Loss Attributable to Non-Controlling Interest. Net (income) loss attributable to non-controlling interest represents the non-controlling investors’ percentage of their share of income or losses from DHS in which they hold an interest. During the years ended December 31, 2009 and 2008, DHS generated a loss resulting in a non-controlling interest credit to earnings.

Historical Cash Flow

Our net cash used in operating activities was $31.5 million for the year ended December 31, 2010 compared to net cash provided by operating activities of $81.1 million for the year ended December 31, 2009. The decrease is primarily a result of offshore litigation proceeds received in 2009 and an increase in cash used for working capital purposes during 2010. Our net cash provided by investing activities increased to $197.8 million for the year ended December 31, 2010 compared to net cash used in investing activities of $47.4 million for the year earlier period, primarily due to proceeds from the Wapiti Transaction and our decreased drilling activity. Cash used in financing activities was $212.6 million for the year ended December 31, 2010 compared to net cash used in financing activities of $37.3 million for the comparable prior year period. Cash used in financing activities in 2010 was primarily comprised of a net $108.6 million of repayment of borrowings and $100.0 million of installments paid on property acquisition, primarily with funds from the Wapiti Transaction. Cash used in financing activities was lower in 2009 primarily due to net proceeds of $246.9 million received from the stock offering completed in May 2009.

Our cash flow from operating activities decreased from $140.7 million for the year ended December 31, 2008 to $81.1 million for the year ended December 31, 2009, primarily as a result of decreased production and lower commodity prices for most of the year. Our net cash used in investing activities decreased to $47.4 million for the year ended December 31, 2009 compared to net cash used in investing activities of $982.6 million for the year earlier period, primarily due to our decreased drilling and acquisition activity. Cash used in financing activities was $37.3 million for the year ended December 31, 2009 compared to $897.6 million for the comparable prior year period. Cash used in financing activities in 2009 was primarily comprised of $246.9 million of proceeds from the stock offering, offset by $181.0 million of repayment of borrowings and $100.0 million of installments paid on property acquisition and was higher in 2008 primarily due to cash received from the Tracinda transaction and additional bank borrowings.

Capital and Exploration Expenditures and Financing

Our capital and exploration expenditures and sources of financing for the years ended December 31, 2010, 2009 and 2008 were as follows:

		Years Ended December 31,
		2010				2009				2008
		(In thousands)
CAPITAL AND EXPLORATION EXPENDITURES:
Acquisitions:
Piceance		$	—			$	—			$	128,848
Haynesville			—				—				31,550
Columbia River Basin			—				—				25,000
Lighthouse Bayou			—				—				14,512
Austin Chalk incremental interests			—				—				13,855
Other			909				2,083				8,050
Other development costs			40,730				163,772				457,947
Drilling and trucking companies			2,549				1,785				52,970
Exploration costs			1,337				2,604				10,975
		$	45,525			$	170,244			$	743,707
FINANCING SOURCES:
Cash provided by (used in) operating activities		$	(31,538	)		$	81,144			$	140,676
Stock issued for cash upon exercised options			—				—				4,827
Stock issued for cash, net			—				246,905				662,043
Net long-term borrowings (repayments)			(111,818	)			(183,859	)			232,120
Installments paid on property acquisition			(100,000	)			(100,000	)			—
Proceeds from sale of oil and gas properties			132,945				8,393				42,000
Proceeds from sale of drilling assets			665				9,111				3,201
Proceeds from sale of marketable securities			300				2,030				—
Investments in and notes issued to affiliates			—				295				(6,965	)
Proceeds from sales of unconsolidated affiliates			6,654				—				—
Increase in restricted deposit			100,000				100,000				(300,000	)
Minority interest contributions			—				—				12,000
Other			715				64				(1,488	)
		$	(2,077	)		$	164,083			$	788,414

We are unable to accurately predict our anticipated capital expenditures for fiscal year 2011, primarily due to the uncertainty relating to capital availability. We expect to announce our 2011 drilling plans once our well results have been evaluated.

Changes in Proved Reserve Quantities

Significant changes to our proved reserves are described below. See also Note 19, “Information Regarding Proved Oil and Gas Reserves (Unaudited)” in our accompanying consolidated financial statements.

During the year ended December 31, 2008, positive revisions totaling 166.4 Bcfe were primarily related to 10-acre downspacing of our Piceance Basin proved undeveloped reserves and the increase in proved reserves from extensions and discoveries of 162.7 Bcfe was comprised of Rocky Mountain proved reserve increases primarily from our Piceance Basin drilling program and related offset wells. Also, during 2008, we purchased incremental interests in our existing Piceance Basin acreage and acquired new interests in adjacent leasehold to expand our Vega Area

totaling approximately 204.6 Bcfe. See Note 4, “Oil and Gas Properties — Year Ended December 31, 2008 Acquisitions” in the accompanying consolidated financial statements for a description of the February 2008 transaction with EnCana.

During the year ended December 31, 2009, negative revisions totaling 725.5 Bcfe were primarily related to the loss of Piceance Basin undeveloped reserves as a result of lower pricing from utilizing the 12-month historical average required by the new SEC rules for use in the December 31, 2009 reserve report and our more limited capital development plan at the time based on capital resources. The 2009 increase in proved reserves from extensions and discoveries totaling 20.4 Bcfe was primarily comprised of Rocky Mountain proved reserve increases primarily from our Piceance Basin drilling program and related offset wells. Also, during 2009, proved reserves totaling 3.5 Bcfe located in various states were sold in a series of transactions described in Note 4, “Oil and Gas Properties — Year Ended December 31, 2009 — Divestitures” in the accompanying consolidated financial statements.

During the year ended December 31, 2010, positive revisions totaling 14.5 Bcfe were primarily related to increased Piceance Basin proved reserves from the incorporation of improved fracturing technology, partially offset by Gulf Coast proved undeveloped reserves removed as a result of drilling plan modifications in conjunction with the Wapiti Transaction. The 2010 increase in extensions and discoveries of 22.2 Bcfe is primarily related to Piceance locations added as proved reserves in 2010 offset to wells previously drilled. Also, during 2010, proved reserves totaling 39.2 Bcfe located in Texas, Colorado, and Wyoming were sold in conjunction with the Wapiti Transaction described in Note 4, “Oil and Gas Properties — Year Ended December 31, 2010 — Divestitures.”

Company Acquisitions, Divestitures and Financings

We plan to continue to evaluate potential acquisitions and property development opportunities, as well as divestitures of non-core assets. During the years ended December 31, 2008, 2009 and 2010, we completed the following transactions:

On February 20, 2008, we issued 36.0 million shares of common stock to Tracinda Corporation at $19.00 per share for gross proceeds of approximately $684 million. As a result of the transaction, subsequent purchases in the open market, and the May equity offering, Tracinda currently owns approximately 33% of our outstanding common stock.

On February 28, 2008, we closed a $410.1 million transaction with EnCana Oil & Gas (USA) Inc. (“EnCana”) to jointly develop a portion of EnCana’s leasehold interests in the Vega Area of the Piceance Basin. We acquired over 1,700 drilling locations on approximately 18,250 gross acres with a 95% working interest. The effective date of the transaction was March 1, 2008. The related agreement superseded a March 2007 agreement with EnCana and accordingly we have no further drilling commitment to EnCana under the March 2007 agreement.

In March 2008, DHS acquired three rigs and spare equipment for a purchase price of $23.3 million. The transaction was funded by the proceeds from two notes payable issued by DHS to Delta and Chesapeake of $6.0 million each and of proceeds of $6.0 million each from Delta and Chesapeake for additional shares of common stock issued by DHS. On August 15, 2008 the $6.0 million notes payable from both Delta and Chesapeake were converted into shares of DHS stock.

In July and August 2008, we completed several transactions to acquire unproved leasehold interests in two prospect areas. The total cost of the acquisitions was approximately $41.6 million. Pursuant to one of the agreements, we were obligated to drill an initial appraisal well by July 1, 2009 but due to our inability drill such well, in late May 2009, an amendment to the agreement was executed whereby the leases reverted to the original seller and we retained an option to participate in future transactions, if any, related to the leases contained in the area of mutual interest.

In August 2008, DHS acquired a 2,000 horsepower drilling rig with a 25,000 foot depth rating for a purchase price of $12.3 million (Rig #23). The acquisition was financed by an increase in the DHS credit facility.

On August 25, 2008, we completed an asset exchange agreement in which we acquired additional incremental interests in certain Midway Loop properties in exchange for $15.1 million in cash and non-core undeveloped properties in Divide Creek. The transaction resulted in a gain of $715,000 during the year ended December 31, 2008.

On September 15, 2008, we entered into an agreement with EnCana to acquire all of EnCana’s net leasehold position and interest in wells in the Columbia River Basin of Washington and Oregon. The purchase price for the leasehold properties was $25.0 million and the transaction closed on September 26, 2008. On September 26, 2008, we completed a separate transaction related to the Columbia River Basin wherein we sold a 50% working interest participation in all of our Columbia River Basin leasehold interests and wells for cash consideration of $42.0 million plus one half of the drilling costs incurred to date on our well currently drilling in the area. This transaction included one half of the leasehold interests acquired from EnCana on September 15, 2008.

During the fourth quarter of 2009 through a series of transactions, we divested of certain non-operated properties in Alabama, California, Colorado, Louisiana, North Dakota, Oklahoma, Texas and Wyoming and certain non-strategic operated properties in Colorado and Wyoming for cash consideration of $4.7 million. In addition, we sold the amine unit from our Paradox Pipeline gas plant for $1.8 million and various pipe and tubular inventory for proceeds of $1.8 million. These transactions resulted in a combined loss of $5.7 million.

During the year ended December 31, 2010, we divested of our interests in certain non-core properties for gross proceeds of $980,000 and the assumption of plugging and abandonment obligations. Proved reserves attributable to these properties were insignificant.

On July 23, 2010, we entered into a definitive Purchase and Sale Agreement with Wapiti to sell all or a portion of our interest in various non-core assets primarily located in Colorado, Texas, and Wyoming for gross cash proceeds of $130.0 million resulting in a net loss of $66.5 million (including impairment losses of $96.2 million). For financial reporting purposes, a $4.0 million impairment loss is included within dry hole costs and impairments in continuing operations, $92.2 million of impairments are included within loss from discontinued operations, and a $29.7 million gain on sale is included in gain on sale of discontinued operations.

Discontinued Operations

In accordance with accounting standards, the results of operations and impairment loss relating to certain of the Wapiti Transaction properties have been reflected as discontinued operations. Properties associated with the Wapiti Transaction in which we only sold half of our interest continue to be reported as a component of continuing operations. The fields classified as discontinued operations are fields in which we sold all of our interest including the Garden Gulch field, Baffin Bay field, and Bull Canyon field as well as our interest in our wholly-owned subsidiary Piper Petroleum. In separate transactions, we sold our interests in the Howard Ranch and Laurel Ridge fields which are also included in discontinued operations.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements other than operating leases.

Contractual Obligations

		For the years ending December 31,
Contractual Obligations at December 31, 2010		2011				2012 - 2013				2014 - 2015				Thereafter				Total
		(In thousands)
Credit facility(1)		$	—			$	29,130			$	—			$	—			$	29,130
Installments payable on property acquisitions(2)			100,000				—				—				—				100,000
7% Senior unsecured notes			—				—				150,000				—				150,000
Interest on 7% Senior unsecured notes			10,500				21,000				13,125				—				44,625
33/4% Senior convertible notes(3)			—				115,000				—				—				115,000
Interest on 33/4% Senior convertible notes(3)			4,313				1,418				—				—				5,731
Credit facility — DHS(1)			69,590				—				—				—				69,590
Derivative liability			574				2,419				—				—				2,993
Abandonment retirement obligation			1,099				49				296				8,749				10,193
Operating leases			1,596				2,875				1,754				682				6,907
Total contractual cash obligations		$	187,672			$	171,891			$	165,175			$	9,431			$	534,169