UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-K

(Mark One)

x

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		80202
(Address of principal executive offices)		(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 Global Select 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 x

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 x

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

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 x
	Non-accelerated filer o (Do not check if a smaller reporting company)		Smaller reporting company o
	Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o     No x

As of June 30, 2009, the aggregate market value of voting stock held by non-affiliates of the registrant was approximately $263.4 million, based on the closing price of the Common Stock on the NASDAQ National Market of $1.93 per share. As of February 28, 2010, 282,844,446 shares of registrant’s Common Stock, $.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

PART I
				PAGE
Item 1.		BUSINESS		2
Item 1A.		RISK FACTORS		11
Item 1B.		UNRESOLVED STAFF COMMENTS		23
Item 2.		PROPERTIES		23
Item 3.		LEGAL PROCEEDINGS		30
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		58
Item 8.		FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA		59
Item 9.		CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE		59
Item 9A.		CONTROLS AND PROCEDURES		59
Item 9B.		OTHER INFORMATION		60
PART III
Item 10.		DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE		60
Item 11.		EXECUTIVE COMPENSATION		60
Item 12.		SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS		60
Item 13.		CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE		60
Item 14.		PRINCIPAL ACCOUNTING FEES AND SERVICES		60
PART IV
Item 15.		EXHIBITS, FINANCIAL STATEMENT SCHEDULES		61

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 strategic plans; operating strategies; our expectation that we will have adequate cash from operations, credit facility borrowings and other capital sources to satisfy our obligations under the Second Amendment to our Second Amended and Restated Credit Agreement, and to meet future debt service, capital expenditure and working capital requirements; expected announcements of 2010 drilling plans and capital expenditure budget; anticipated utilization of joint venture and partnership structures; acquisition and divestiture strategies; completion and drilling program expectations, processes and emphasis; oil and gas reserve estimates (including estimates of future net revenues associated with such reserves and the present value of such future net revenues); 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 the Second Amendment to our Second Amended and Restated Credit Agreement, our working capital needs, and drilling and leasehold acquisition programs, including through potential joint ventures and asset monetization transactions;
	•		lower natural gas and oil prices negatively affecting our ability to borrow or raise capital, or enter into joint venture arrangements and potentially requiring accelerated repayment of amounts borrowed under our revolving credit facility;
	•		declines in the values of our natural gas and oil properties resulting in write-downs;
	•		the impact of current economic and financial conditions on our ability to raise capital;
	•		a contraction in the demand for natural gas in the U.S. as a result of depressed general economic conditions;
	•		the ability and willingness of our joint venture partners to fund their obligations to pay a portion of our future drilling and completion costs;
	•		expiration of oil and natural gas leases that are not held by production;
	•		uncertainties in the estimation of proved reserves and in the projection of future rates of production;

	•		timing, amount, and marketability of production;
	•		third party curtailment, or processing plant or pipeline capacity constraints beyond our control;
	•		our ability to find, acquire, develop, produce and market production from new properties;
	•		the availability of borrowings under our credit facility;
	•		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;
	•		the risk that lenders under our revolving credit facilities will default in funding borrowings as requested; 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 areas of operation are the Rocky Mountain and onshore Gulf Coast Regions, which together comprise the majority of our proved reserves, production and long-term growth prospects. 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.

We generally concentrate our exploration and development efforts in fields where we can apply our technical expertise, and where we have accumulated significant operational control and experience. We also have an

ownership interest in a drilling company, providing the benefit of priority access to drilling rigs during high rig utilization periods.

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

Evaluation of Strategic Alternatives

In November 2009, we retained Morgan Stanley and Evercore Partners (collectively, “Strategic Advisors”) to evaluate and advise the Board of Directors on strategic alternatives to enhance shareholder value and the process is currently in advanced stages. Such alternatives are expected to include, but may not be limited to, exploring the sale of some or all of our assets, entering into partnerships or joint ventures, or the sale of the entire company (collectively, the “Potential Strategic Transactions”). There can be no assurance that this evaluation of strategic alternatives will result in changes to our company, operations or business plan. In addition, there can be no assurance that we will pursue any particular transaction or transactions, or, if we do pursue any such transaction, that it will be completed or successful.

Amendment to Credit Facility

On October 30, 2009, we entered into the Second Amendment (the “Second Amendment”) to the Second Amended and Restated Credit Agreement (as amended, the “Credit Agreement”), with JPMorgan Chase Bank, N.A., as agent, and certain of the financial institutions that are party to our credit agreement in which, among other changes, the lenders provided waivers from the December 31, 2009 and March 31, 2010 current ratio and consolidated secured debt to EBITDAX ratio covenants. In conjunction with the Second Amendment and as part of a scheduled redetermination, the borrowing base under the Credit Agreement was reduced from $225.0 million to $185.0 million. The next scheduled borrowing base redetermination under the Credit Agreement is currently in process. Also, the Second Amendment requires that we maintain minimum availability of $20.0 million essentially reducing our availability under the Credit Agreement. The minimum availability requirement will be released on the first date after delivery of the December 31, 2009 audited financial statements on which we are in compliance with our financial covenants as of the most recently completed quarter (without giving effect to any waiver of compliance with such covenants) and project pro forma compliance for each of the four following quarters. In addition, the Second Amendment imposed capital expenditures limitations of $10.0 million for the quarter ending December 31, 2009, $10.0 million for the quarter ending March 31, 2010, and $5.0 million for the quarter ending June 30, 2010, provided that any excess of the limitation over the amount of actual expenditures may be carried forward from an earlier quarter to a subsequent quarter. The Second Amendment also included a payables covenant whereby our trade payables (a sub-component of accounts payable on the accompanying consolidated balance sheet) may not exceed $30.0 million, exclusive of any amounts owed by us to DHS Drilling Company (“DHS”), our drilling subsidiary. We are currently in compliance with our financial ratio covenants and based on our current operating projections, we believe that we will remain in compliance with the debt covenants. However, depending on market conditions and the possibility of further economic deterioration, we may need to request amendments, or waivers for the covenants, or obtain refinancing in future periods. There can be no assurance that we will be able to obtain amendments or waivers, or negotiate agreeable refinancing terms should it become needed.

Overview and Strategy

Although we have undertaken an evaluation of strategic alternatives, our corporate strategy remains focused on increasing stockholder value, as follows:

Pursue development of our core areas independently and through joint ventures or other industry partnerships

Although our capital expenditure budget was reduced dramatically in 2009 due to significant declines in commodity prices and our capital availability, and remains limited in 2010 by our capital availability and by the limitations

imposed under the Second Amendment, our financial condition has improved and Rockies gas prices have recently begun to return to more attractive levels supporting additional development. We are unable to accurately predict our anticipated capital expenditures for fiscal year 2010, primarily due to the uncertainty relating to any Potential Strategic Transaction, including the likelihood of such a transaction occurring, the type of transaction and the timing of any such transaction. In addition, future redeterminations of our borrowing base under our credit facility, including the scheduled redetermination currently in process, may affect our liquidity available for capital expenditures making it difficult to accurately determine such amounts at the current time. We expect to announce our 2010 drilling plans once our strategic alternatives evaluation process and borrowing base redetermination are complete. It is our current belief that our 2010 capital deployment will be focused in the Rockies, which we believe will allow us to maintain approximately 90% of our 2009 production levels in 2010 until improved commodity prices and capital availability are able to support more aggressive drilling and completion activity.

In view of current market conditions and our capital expenditure constraints, we intend to more actively utilize joint ventures or other similar industry partnerships or participation arrangements to develop our asset base. In 2008, we announced the sale of 50% of our working interests in our Columbia River Basin acreage and are continuing to evaluate, among other alternatives, a joint venture or similar industry partnership transaction or transactions with the assistance of our Strategic Advisors. We are currently engaged in other joint venture focused discussions regarding development of several of our other unproved leasehold areas.

Achieve reserve growth through repeatable development

In 2009 we experienced a decrease in reserves due to the exclusion of our Piceance Basin proved undeveloped reserves given low Rockies gas prices over the course of the year as factored into the new SEC rules on pricing for year end reserve calculations. Prior to 2009, however, for a four-year period we experienced significant reserve growth through a combination of acquisitions and drilling successes. Although prior to 2006 the majority of our reserve and production growth came through acquisitions, in 2007 and 2008 we achieved reserve and production increases as a result of our drilling program. In 2009, we successfully focused on the efficient deployment of available capital to maintain production levels and experienced a decline of 11% in 2009 volumes relative to 2008. We anticipate that the majority of our future reserve and production growth will come through the execution of our development drilling program in our Piceance Basin projects, which contain a development drilling inventory generally consisting of locations in fields that demonstrate low variance in well performance, leading to predictable and repeatable field development.

Our reserve estimates change continuously and we evaluate such reserve estimates on a quarterly basis, with an independent engineering evaluation completed on an annual basis. Deviations in the market prices of both crude oil and natural gas and the effects of acquisitions, dispositions and exploratory development activities have a significant effect on the quantity and present and future values of our reserves.

Maintain high percentage ownership and operational control over our asset base

As of December 31, 2009, we controlled approximately 797,000 net undeveloped acres, representing approximately 98% of our total net acreage position. We retain a high degree of operational control over our asset base, as we generally have a high average working interest or act as the operator in our areas of significant activity. This provides us with controlling interests in a multi-year inventory of drilling locations, positioning us for reserve and production growth through our drilling operations when we are able to increase our drilling activity. This level of ownership and control also enables us to seek joint ventures or industry partnerships on the acreage. We plan to maintain this advantage to allow us to control the timing, level and allocation of our drilling capital expenditures and the technology and methods utilized in the planning, drilling and completion process, though our ability to control these matters may be diminished by the terms of joint venture or partnership arrangements we may enter into. We believe this flexibility to opportunistically pursue exploration and development projects relating to our properties is particularly valuable in view of the current lower commodity price and limited capital availability environment. We also have a 49.8% interest in DHS, as well as a contractual right of priority access to 18 drilling rigs owned by DHS.

Maintain and/or monetize acreage positions in high potential resource plays

We anticipate that like 2009 our exploratory drilling efforts during 2010 will be much more limited than in prior years. Although, we believe that our ongoing development of reserves in our core areas should be supplemented with exploratory efforts that may lead to new discoveries in the future, we will devote the vast majority of our capital resources to development of our existing core areas and seek carried, farmout or joint venture arrangements in pursuing exploratory opportunities. We continually evaluate our opportunities and pursue attractive potential opportunities that take advantage of our strengths. We have significant undeveloped, unproved acreage positions in the Columbia River Basin of Washington and Oregon, the Haynesville and Eagleford shales in Texas, and the Central Utah Hingeline, each of which has gained substantial interest within the exploration and production sector due to their relatively unexplored nature and the potential for meaningful hydrocarbon recoveries. There are other mid-size and large independent exploration and production companies conducting drilling activities in these plays. With increased commodity prices or the addition of joint venture partners to fund a portion or all of the drilling cost, our plans for 2010 could change with respect to these potentially rewarding exploratory plays.

Pursue a disciplined acquisition and disposition strategy

Historically we have been successful at growing through targeted acquisitions. Although our multi-year drilling inventory provides us with the opportunity to grow reserves and production organically without acquisitions, we continue to evaluate acquisition opportunities, primarily in our core areas of operation. In addition, as we did in the latter half of 2009 in particular, we will continue to look to divest of assets located in fully developed or non-core areas.

Maintain an active hedging program

We manage our exposure to commodity price fluctuations by hedging meaningful portions of our expected production through the use of derivatives. The level of our hedging activity and the duration of the instruments employed depend upon our view of market conditions, available hedge prices and our operating strategy. We use hedges to limit the risk of fluctuating cash flows used to fund our capital expenditure program. We also typically use hedges in conjunction with acquisitions to achieve expected economic returns during the payout period. During March 2009, we entered into derivative contracts that originally established a commodity floor price for our anticipated production of 40% for the last two quarters of 2009, 70% for the calendar year 2010 and 50% for the calendar year 2011. Depending upon the outcome of our assessment of Potential Strategic Transactions, we would expect to further evaluate our commodity price risks for the next 12 to 36 month period and periodically enter into derivative contracts to manage such risks.

Experienced management and operational team

Our senior management team has, on average, over 25 years of experience in the oil and gas industry, and has a proven track record of creating value both organically and through strategic acquisitions. Our management team is supported by an active board of directors with extensive experience in the oil and gas industry. Our experienced technical staff utilizes sophisticated geologic and 3-D seismic models to enhance predictability and reproducibility over significantly larger areas than historically possible. We also utilize multi-zone, multi-stage artificial stimulation (“frac”) technology in completing our wells to substantially increase near-term production, resulting in faster payback periods and higher rates of return and present values. Our team has successfully applied these techniques in the completions of our wells in our Rocky Mountain natural gas fields.

Operations

During the year ended December 31, 2009, 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, 2009:

		Oil				Natural Gas				Total				2009 Production
		(Mbbl)				(Mmcf)				(Mmcfe)				(MMcfe/d) (1)
Proved Developed
Rocky Mountain Region			927				100,104				105,666				43.3
Gulf Coast Region			1,838				14,792				25,820				14.8
Other			212				108				1,380				2.6
Total			2,977				115,004				132,866				60.7
Proved Undeveloped
Rocky Mountain Region			428				3,346				5,914
Gulf Coast Region			1,043				8,342				14,601
Other			34				—				204
Total			1,505				11,688				20,719
Total Proved Reserves(2)			4,482				126,692				153,585

In December 2008, the SEC approved new rules designed to modernize oil and gas reserve reporting requirements.

We adopted the rules effective December 31, 2009. The application of the new reserve rules resulted in the use of lower prices at December 31, 2009 for both oil and gas than would have been used under the previous rules. Use of new 12-month average pricing rules at December 31, 2009 resulted in a decrease in proved reserves of approximately 677 Bcfe as compared to proved reserves calculated using the year-end prices previously required. See “Reserve Sensitivities” included in Item 7. Management’s Discussion and Analysis.

We intend to focus our 2010 capital spending on the development of our core area of operation in the Rocky Mountains, the Piceance Basin, to the extent that cash on hand, cash flows and available capital through joint ventures or asset sales are adequate to fund our plans. The Second Amendment to our Credit Agreement limits our ability to make capital expenditures during the first and second quarters of 2010.

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, CRB Partners, LLC (“CRBP”) and PGR Partners, LLC (“PGR”), we currently own producing and non-producing oil and natural gas interests, undeveloped leasehold interests and related assets in nine 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 majority of our properties and 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, an affiliated Colorado corporation 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, 2009, DHS owned 18 drilling rigs with depth ratings of approximately 10,000 to 25,000 feet, of which seven are currently active. We have the right to use all of the rigs on a priority basis, although current economic conditions have resulted in an abundance of available drilling rigs in the Rocky Mountain area at the present time.

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

		Years Ended December 31,
		2009				2008
Average number of rigs owned during period			18.5				16.7
Total rig days1			854				5,032
Average drilling revenue per day		$	16,730			$	18,188

¹Total rig days includes the number of days each rig was under contract.

During 2009, we experienced a significant reduction in rig utilization (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, we expect drilling day rates to stabilize during 2010.

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.

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, although DHS currently has one rig operating in Mexico. 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 is permitted 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 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, 2009, we had two companies that individually accounted for 37% and 19% 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 19 to our consolidated financial statements for additional information.

During the year ended December 2009, DHS had two companies that individually accounted for 24% and 10% 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 are becoming increasingly expensive, complex, and stringent. Non-compliance with 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 2010. 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 2010, 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 petroleum from cleanup liability, many state laws affecting our operations impose clean-up liability regarding petroleum and petroleum-related products.

In addition, although RCRA currently classifies certain exploration and production wastes as “non-hazardous,” 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.

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, Mineral Management Service (“MMS”), which currently impose 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 Department of the Interior 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 MMS 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 $10.5 million at December 31, 2009. 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, 2009 we had approximately 79 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. Current economic fundamentals portray an uncertain outlook for the oil and natural gas exploration and development business for at least a significant portion of 2010 due to volatile oil and natural gas prices coupled with the global recession. 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. Our ability to maintain adequate liquidity through 2010

will depend significantly on consummation of a Potential Strategic Transaction and, if so, the terms thereof, sustained commodity price improvement, adequate pipeline capacity, curtailment of operating expenses and 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 or capital markets conditions will improve in the near term.

Consummation of a strategic transaction, sale of assets, or joint venture or partnership arrangement may be necessary to fund our capital expenditure and working capital needs in the near term.

In 2009, we successfully completed a public offering of our common stock in exchange for $246.9 million of net proceeds, as well as received net proceeds of $95.7 million from the settlement of litigation in which we were involved. In 2009, we also experienced reductions in our borrowing base and our borrowing availability under our Credit Agreement, as well as a decline in revenues due to general economic conditions and commodity prices. Accordingly, the proceeds from our capital-raising activities in 2009 were used for the repayment of debt as well as capital expenditures and general working capital. Although we have significantly decreased our drilling activities and operations in recent periods, any further reductions could materially and adversely affect our continuing operations. Thus, in response to these liquidity issues, in November 2009, we announced that we were exploring strategic alternatives, including a sale of some or all of our assets, entering into partnerships or joint ventures, or the sale of the entire company. Based on the current status of our balance sheet, the consummation of one or more of these types of transactions may be required to fund our drilling activities and operations in 2010 if adequate capital is not obtained from another source. Further, our borrowings under our Credit Agreement are currently due on January 15, 2011. If we are unable to complete any Potential Strategic Transaction, we may not be able to repay the amounts outstanding under the credit facility when due without obtaining other sources of capital from 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.

As of December 31, 2009, our total outstanding long term liabilities were $460.9 million, including $83.3 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 39.8% of our total book capitalization at December 31, 2009. Based on the revised $185.0 million borrowing base with a required availability cushion of $20.0 million and outstanding letters of credit totaling $1.2 million, we had $39.8 million available under our credit facility as of December 31, 2009 and $70.8 million as of February 28, 2010. 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 that are important to our growth; 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, develop our properties and make future acquisitions. 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, including a scheduled borrowing base redetermination currently in process. A further 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 existing credit facility matures on January 15, 2011 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 lenders, or entering into a new credit facility. As part of our consideration of Potential Strategic Transactions, 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.

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 from the lending banks in our credit facility is subject to periodic redeterminations based on prices specified by our bank group at the time of redetermination. In addition, we may have asset carrying value write-downs if prices fall, as was the case in 2009.

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 82% of our reserves at December 31, 2009 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 2010 will most likely allow us to fund our business with anticipated internally generated cash flow, cash resources and other 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, 2009, 2008 and 2007 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 and 2007, in accordance with SEC rules at the time, proved reserves were based on single day year-end prices. For 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.

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, 2009, we recorded impairment provisions to our proved and unproved properties totaling approximately $155.5 million primarily related to our non-operated Garden Gulch field in the Piceance Basin ($38.6 million), Haynesville Shale ($27.5 million), Columbia River Basin ($21.4 million), Lighthouse Bayou ($14.8 million), proved and unproved impairments in various Gulf Coast fields ($29.2 million), Vega surface land ($10.5 million), proved and unproved impairments in various Rockies fields ($6.9 million), and pipe and tubular inventory ($4.3 million). 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 to our proved and unproved properties totaling approximately $305.6 million primarily related to the Newton, Midway Loop, Opossum Hollow and Angleton fields in Texas ($192.5 million), Paradox field in Utah ($30.5 million), Howard Ranch and Bull Canyon fields in the Rockies ($32.0 million), Utah Hingeline ($40.8 million) and our offshore California field ($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 ($21.5 million), certain DHS rigs ($21.6 million) and we wrote off DHS’s goodwill ($7.7 million).

We incurred dry hole costs of approximately $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.

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

Our Credit Agreement 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 revolving bank 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 borrowing base has been redetermined at a level that will not permit additional borrowing 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. Pursuant to the Second Amendment to the Credit Facility, our borrowing base under the Credit Facility was reduced to $185.0 million, with a requirement that we maintain minimum availability of $20.0 million.

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, 2009 is estimated to be approximately $78.0 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 depend on key personnel.

We currently have four employees that serve in executive management roles. In particular, John R. Wallace, our President, and Carl Lakey, our Senior Vice President - Operations are responsible for the operation of our oil and gas business, 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 seven of its 18 rigs in operation and expects to continue to incur liquidity pressures during 2010 due to the industry-wide decrease in drilling activities. DHS is now highly leveraged relative to its currently reduced cash flow and its 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, 2009, DHS owed $83.3 million under its credit facility. 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 in 2010 unless market conditions improve significantly. In such event, 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. While the DHS credit facility is non-recourse to Delta, Delta is a significant creditor of DHS, with accounts payable to DHS of $20.5 million as of December 31, 2009. Delta has a net investment of approximately $8.5 million in DHS.

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 costless collars. 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 ($28.1 million), $21.7 million, and $10.0 million for the years ended December 31, 2009, 2008 and 2007, respectively. At December 31, 2009, we had derivative contracts in place that originally established a floor price for our anticipated production of 40% for the last two quarters of 2009, 70% for the calendar year 2010 and 50% for the calendar year 2011.

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 continue to 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.

We may be unable to draw funds from our existing credit facilities.

Our subsidiary, DHS Drilling Company, has a credit facility with Lehman Commercial Paper, Inc. (“Lehman”). During the year ended December 31, 2008, DHS paid a deposit of $1.3 million for the acquisition of a drilling rig that was expected to close in October 2008. Because of the bankruptcy of Lehman and the inability of Lehman to fund, DHS was unable to close on the acquisition and forfeited its deposit. We maintain a Credit Facility underwritten by a syndicate of financial institutions that we use to fund our capital expenditures and working capital requirements. If the financial institutions underwriting our credit facility file for bankruptcy or otherwise refuse our funding requests, we may incur unforeseen expenses, lose business opportunities, or become unable to make payments when due.

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.

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, 2010, our largest stockholder, Tracinda Corporation (“Tracinda”), beneficially owned 93,798,000 shares of our common stock, or approximately 34% of the outstanding shares of our common stock. Pursuant to the Company Stock Purchase Agreement that we entered into with Tracinda Corporation on December 29, 2007, Tracinda Corporation 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. While Tracinda Corporation agreed not to acquire more than 49% of our outstanding common stock until February 20, 2009, after such date there are 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.

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.

Approximately 40% of our common stock is held by institutional investors who now each have ownership of greater than 5% of our common stock. Sales by Tracinda Corporation, or other of our large institutional investors, 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 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 employees of the Company, holders of our common stock will experience dilution. As of December 31, 2009, we had outstanding options to purchase 1,427,750 shares of common stock at a weighted average exercise price of $8.21. 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, 2009, our directors and executive officers collectively and beneficially owned, directly or indirectly, approximately 1.3% 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.

Our primary areas of activity are in the Rocky Mountain and Gulf Coast Regions with additional unproved exploratory leaseholds in the Columbia River Basin in southeastern Washington, the Hingeline area of Central Utah, and the Haynesville Shale area of Texas, among others. Total oil and gas leasehold is approximately 813,000 acres.

Rocky Mountain Region

The Rocky Mountain Region comprises approximately 73% of our estimated proved reserves as of December 31, 2009. The majority of our undeveloped acreage and drilling inventory is located in this region, where our drilling efforts and capital expenditures have been focused.

In the Rocky Mountains, although we have significant acreage in three basins, we have dedicated the majority of our development efforts to our position in the Piceance Basin.

Piceance Basin. 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. In 2008 we acquired an additional 17,300 net acres, which increased our position to approximately

22,150 net acres, which has over 2,000 net drilling locations on 10-acre spacing. We also have a non-operated working interest in the Garden Gulch Field in Garfield County, Colorado. These fields are consistent with our strategy of targeting reservoirs that demonstrate predictable geology over large areas. The Williams Fork member of the Mesaverde formation is the primary producing interval and has been successfully developed throughout the Piceance Basin.

Vega Area. The Vega Area includes the Vega Unit, the North Vega leasehold, the Buzzard Creek Unit, and North Buzzard Creek leasehold. Our working interest in the Vega Area varies between 95-100%. During fiscal 2008, we increased proved reserves in the Vega Area over 295% to 719.9 Bcfe and increased production from approximately 25 Mmcf/d at the beginning of the year to approximately 48 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, proved reserves decreased to 84.7 Bcfe. Production decreased to 25.8 Mmcf/d at the end of 2009 due to the limited capital spending during 2009. The Collbran Valley natural gas pipeline provides us with approximately 100 Mmcf/d of pipeline takeaway capacity. The pipeline system is expandable to 290 MMcfd with additional compression at CVGG Anderson Gulch Facility. We ended 2009 with 188 wells producing. Despite our large inventory of over 2,000 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, 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 expect to continue completion activities in 2010 on wells awaiting completion, and to resume an active, continuous drilling program once commodity prices recover. Our drilling and completion capital budget for the Vega Area has not yet been determined pending the outcome of our borrowing base redetermination and the outcome of the previously discussed strategic alternatives process.

Garden Gulch. We have an interest in approximately 6,300 gross (2,000 net) acres with a 31.1% non-operated working interest. The operator of the project temporarily ceased drilling activity in 2009, but resumed completion activity in late 2009 and began a one rig drilling program in early 2010. Our capital budget for the year ending December 31, 2010 is driven by the activity level, which is determined by the operator.

Paradox Basin. In the Paradox Basin we have five prospect areas: Greentown, Salt Valley, Fisher Valley, Gypsum Valley and Cocklebur Draw. Over the past three years we focused primarily on the Greentown prospect, in Grand County, Utah. The objectives that were targeted in these prospects were reliant upon various geologic models, which included multiple stacked clastic intervals imbedded within an evaporate salt in the Paradox formation, and unconventional shales.

Greentown. From 2006 through 2008, we drilled a total of eight wells in the Greentown project area. Delta observed encouraging hydrocarbon flows from three of the initial wells. The Greentown 36-11, 32-42 and 28-11 which all produced hydrocarbon from one or more of the clastic intervals at commercial rates. Although these first two exploration wells were lost due to casing failure, subsequent wells were drilled with improved casing designs and did not experience similar failure. Due to Delta’s need to devote its limited capital to the Piceance Basin properties in 2010, we have farmed out our interest in several of the Paradox wellbores to another firm and retained a carried 25% interest in the completion of each of the wellbores. The farmout specifically assigns operating rights to the Federal 28-11 and Greentown Federal 26-43D well along with associated abandonment responsibilities. The agreement also provides for the option to extend the agreement to other wellbores.

We have a 70% working interest in 34,000 gross acres, 23,400 net acres. The acreage remains prospective and we are hopeful that the farmout will prove successful. We have not budgeted any significant activity in Greentown for the year ending December 31, 2010.

Salt Valley. The Salt Valley project area has had one exploratory well drilled. Additional drilling plans are not expected in 2010. We have a 70% working interest in 7,065 gross acres, 4,900 net acres.

Fisher Valley, Gypsum Valley and Cocklebur Draw. We have three remaining prospects in the Paradox Basin located in San Miguel and Dolores Counties, Colorado and Grand County, Utah. We have a 70% working interest in 49,200 gross acres, 36,600 net acres, all of which were undeveloped at December 31, 2009.

Denver-Julesburg (“D-J”) Basin. Our leasehold in the Denver Julesburg Basin focuses on the “J” sand formation at depths of between 7,000 feet and 8,000 feet. In 2007 we drilled an exploratory well, the Cowboy 35-21 well, which was a discovery that began production at a rate of 200 Bo/d. Subsequent development of the Cowboy field included ten additional wells which allowed production to peak at approximately 1,100 barrels of oil per day. Production has since declined to 330 Bopd. We have identified numerous seismically defined structures, similar in size to the Cowboy field. We have 70,243 net acres with a 100% working interest. Our drilling capital expected for the D-J Basin in 2010 is primarily related to a well which spud in late January 2010 and is expected to be on production by the end of April 2010.

Gulf Coast Region

The Gulf Coast Region comprises approximately 26% of our estimated proved reserves as of December 31, 2009. In the Gulf Coast Region, our primary areas of operation are the Newton and Midway Loop Fields.

Development Projects – Newton, Midway Loop and Opossum Hollow Fields

Newton Field. The Newton Field is located in Newton County, Texas where we have an interest in 4,874 net acres with a 92% working interest. The wells in the Newton Field produce from 13 different sands in the Wilcox formation. The field is a large structural anticline that is defined by extensive well and seismic control. At year end, proved reserves in the Newton Field were 16.2 Bcfe. We do not currently anticipate allocating any significant drilling capital for the Newton Field in 2010.

Midway Loop Field. The Midway Loop Field is located in Polk and Tyler Counties, Texas. We have an interest in 12,674 gross acres, with an average 39% working interest. The wells in this field produce from the Austin Chalk and are drilled horizontally with either dual or single laterals that reach up to 8,000 feet of displaced in each lateral. As of December 31, 2009 our proved reserves totaled 12.2 Bcfe. Currently, there is no drilling capital anticipated for the field in 2010.

Caballos Creek / Opossum Hollow / 74 Ranch Areas. The leasehold is located in Atascosa and McMullen Counties, Texas. We have an interest in approximately 9,722 gross acres. The area has additional potential in the Wilcox sands, Eagleford shales, Sligo formation and Cotton Valley sands that are supported by acquired 3-D seismic programs. Delta is participating for 25% carried interest in a well currently drilling near the 74 Ranch area. We are currently evaluating additional farmout options in the 74 Ranch area.

Other Areas

Central Utah Hingeline. The central Utah Hingeline Region is an overthrust belt located in central Utah. We have an average 65% working interest in approximately 125,000 net acres. We have drilled three wells, the Joseph #1, the Federal 23-44, and the Beaver Federal 21-14. All three wells were plugged and abandoned as dry holes.

We and our partners control approximately 210,000 gross acres (125,000 net acres) within this play and numerous structural features have been identified on our leasehold. We have not budgeted any drilling capital for this area in 2010. The Central Utah Hingeline project is an exploratory area for us and does not account for any of our proved reserves at December 31, 2009.

Columbia River Basin. The Columbia River Basin is located in southeast Washington and northeast Oregon. The basin is characterized by over-pressured, gas sandstone formations. During 2009, we drilled the Gray 31-23 well in Klickitat County, Washington however the well did not reach the targeted Roslyn formation and was plugged and abandoned. We have an interest in approximately 420,000 net acres in the basin, all of which are undeveloped. The Columbia River Basin is an exploration project area and does not account for any of our proved reserves as of December 31, 2009 and we do not anticipate any drilling capital for this area in 2010.

Haynesville Shale. We acquired rights to 11,900 gross acres in the Haynesville Shale during the second and third quarters of 2008. The acreage position is concentrated in Caddo Parish, Louisiana, and Harrison, Shelby and Nacogdoches counties, Texas. The costs to acquire the leasehold rights have averaged approximately $3,500 per acre. We are in the process of seeking a joint venture partner to begin drilling our leasehold. No 2010 capital is expected to be allocated to this acreage.

Offshore California producing properties

Point Arguello Unit. 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) with approximately 1.0 Bcfe in proved reserves. No capital expenditures are anticipated for this area for 2010.

Rocky Point Unit. We own a 6.25% working interest in the development of the east half of OCS Block 451 in the Rocky Point Unit.

Unproved Undeveloped Offshore California Properties

We previously owned direct and indirect ownership interests ranging from 2.49% to 100% in five unproved undeveloped offshore California oil and gas properties. We and our 92% owned subsidiary, Amber, were among twelve plaintiffs in a lawsuit that was filed in the United States Court of Federal Claims (the “Court”) in Washington, D.C. alleging that the U.S. government materially breached the terms of forty undeveloped federal leases, some of which are part of our offshore California properties. During 2009, we received net proceeds of $95.8 million after contractual royalty obligations to third parties and conveyed our leases back to the United States. Accordingly, we no longer have any remaining unproved undeveloped offshore California property interests.

Other Fields

We derive a small portion of our oil and gas production from fields in non-core regions that are not expected to constitute a significant portion of our capital budget in the future. Our interest in these fields had approximately 0.6 Bcfe in proved reserves as of December 31, 2009. We divested of many of these fields in late 2009 generating net proceeds of $3.7 million.

Reserve Sensitivities

In December 2008, the SEC approved new rules designed to modernize oil and gas reserve reporting requirements. We adopted the rules effective December 31, 2009. The application of the new reserve rules resulted in the use of lower prices at December 31, 2009 for both oil and gas than would have been used under the previous rules. The table below compares our December 31, 2009 SEC reserves under the new rules with the December 31, 2009 proved reserves that would have been used from the use of the old rules:

						Old
		SEC Pricing (1)				SEC Pricing (2)
		(Mmcfe)				(Mmcfe)
Proved developed			132,866				165,420
Proved undeveloped			20,719				664,885
Total Proved			153,585				830,305

As shown above, use of new 12-month average pricing rules at December 31, 2009 resulted in a decrease in proved reserves of approximately 677 Bcfe as compared to proved reserves calculated using the year-end prices previously required.

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 Sr. Vice President of Corporate Engineering. 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 2009, 2008 and 2007, 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, 2009 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, 2009 with any federal authority or agency other than the SEC with respect to our estimates of oil and natural gas reserves.

DHS Drilling Company Rigs

The Company owns 49.8% of DHS, which as of December 31, 2009 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		UT		2005			1,500				18,000
Rig No. 4		WY		2007			700				11,000
Rig No. 5		NV		2005			700				12,000
Rig No. 6		CO		2005			700				12,000
Rig No. 8		WY		2005			800				12,500
Rig No. 9		TX		2006			1,000				15,000
Rig No. 10		ND		2006			1,000				15,000
Rig No. 11		UT		2006			750				11,000
Rig No. 12		ND		2006			1,000				15,000
Rig No. 14		Mexico		2006			800				12,500
Rig No. 15		CO		2006			700				10,000
Rig No. 16		WY		2006			700				10,000
Rig No. 17		WY		2006			1,000				12,500
Rig No. 18		UT		2007			700				10,500
Rig No. 19		WY		2008			700				12,500
Rig No. 20		WY		2008			1,000				12,500
Rig No. 23		TX		2008			2,000				25,000
Rig No. 24		NM		2008			1,300				12,500

Office Facilities

Our offices are located at 370 Seventeenth Street, Suite 4300, Denver, Colorado 80202. We lease approximately 32,000 square feet of office space. Our current lease payments are approximately $97,200 per month and our lease expires in December 2014.

Production

During the years ended December 31, 2009, 2008 and 2007, 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, 2009, we recorded impairment provisions to our proved and unproved properties totaling approximately $155.5 million primarily related to our non-operated Garden Gulch field in the Piceance Basin ($38.6 million), Haynesville Shale ($27.5 million), Columbia River Basin ($21.4 million), Lighthouse Bayou ($14.8 million), proved and unproved impairments in various Gulf Coast fields ($29.2 million), Vega surface land ($10.5 million), proved and unproved impairments in various Rockies fields ($6.9 million), pipe and tubular inventory ($4.3 million), and Paradox pipeline ($1.9 million).

In 2008, we recorded an impairment provision to our proved and unproved properties totaling approximately $305.6 million primarily related to the Newton, Midway Loop, Opossum Hollow and Angleton fields in Texas ($192.5 million), Paradox field in Utah ($30.5 million), Howard Ranch and Bull Canyon fields in the Rockies ($32.0 million), Hingeline field in Utah ($40.8 million) and our offshore California field ($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 ($21.5 million), certain DHS rigs ($21.6 million) and we wrote off DHS goodwill ($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, 2009, 2008, and 2007.

		Years Ended December 31,
		2009				2008				2007
Production volume –
Total production (MMcfe)			22,156				24,908				17,763
Production from continuing operations:
Oil (MBbls)			761				993				1,003
Natural Gas (MMcf)			17,590				18,948				10,866
Total (MMcfe)			22,156				24,908				16,882
Net average daily production-
continuing operations:
Oil (Bbl)			2,085				2,721				2,748
Natural Gas (Mcf)			48,192				51,912				29,770
Average sales price:
Oil (per barrel)		$	52.37			$	92.12			$	67.39
Natural Gas (per Mcf)		$	3.13			$	6.87			$	5.17
Hedge gain (loss) (per Mcfe)		$	(.05	)		$	.74			$	.82
Lease operating costs - (per Mcfe)		$	1.41			$	1.35			$	1.24

Productive Wells and Acreage

The table below shows, as of December 31, 2009, 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								Developed Acres
Location		Gross (2)				Net (3)				Gross (2) Net (3)								Gross (2)				Net (3)
California (onshore)			-				-				-				-				1,014				55
California (offshore)			34				2.1				-				-				2,422				269
Colorado			347				1.8				390				215.5				2,920				2,100
Kansas			2				-				-				-				-				-
Louisiana			43				2.0				-				-				773				501
Mississippi			2				-				-				-				-				-
Nebraska			3				1.2				-				-				120				48
New Mexico			2				-				2				.1				241				14
Oklahoma			-				-				-				-				560				110
Texas (4)			316				51.7				54				12.6				20,117				10,868
Utah			-				-				-				-				80				61
Wyoming			14				12.3				20				14.7				1,768				1,587
			763				71.1				466				242.9				30,015				15,613

Undeveloped Acreage

At December 31, 2009, we held undeveloped acreage by state as set forth below:

		Undeveloped Acres (1)
Location		Gross				Net
Colorado			100,848				77,899
Kansas			160				160
Louisiana			2,954				2,580
Nebraska			3,240				968
Oregon			393,948				45,160
Texas			23,171				18,165
Utah			287,979				183,353
Washington			1,245,634				375,900
Wyoming			133,424				92,959
Total			2,191,358				797,144

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,
		2009								2008								2007
		Gross				Net				Gross				Net				Gross				Net
Exploratory Wells (1):
Productive:
Oil			-				-				1				1.00				5				4.75
Gas			-				-				1				.70				4				3.09
Nonproductive			1				.50				19				14.01				5				4.16
Total			1				.50				21				15.71				14				12.00
Development Wells (1):
Productive:
Oil			-				-				7				5.40				10				9.55
Gas			113				32.89				141				82.37				89				58.48
Nonproductive			-				-				-				-				2				1.13
Total			113				32.89				148				87.77				101				69.16
Total Wells (1):
Productive:
Oil			-				-				8				6.40				15				14.30
Gas			113				32.89				142				83.07				93				61.57
Nonproductive			1				.50				19				14.01				7				5.29
Total Wells			114				33.39				169				103.48				115				81.16

Present Drilling Activity

We are unable to accurately predict our anticipated capital expenditures for fiscal year 2010, primarily due to the uncertainty relating to any Potential Strategic Transaction, including the likelihood of such a transaction occurring, the type of transaction and the timing of any such transaction. In addition, future redeterminations of our borrowing base under our credit facility, including the scheduled redetermination currently in process, may affect our liquidity available for capital expenditures making it difficult to accurately determine such amounts at the current time. We expect to announce our 2010 drilling plans once our strategic alternatives evaluation process and borrowing base redetermination are complete.

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.

The following legal proceedings have been recently terminated:

On December 16, 2009 we entered into a settlement agreement with the United States of America with respect to our breach of contract claim against the United States in the case of Amber Resources Co., et al. v. United States, Civ. Act. No. 2-30 that was filed in the United States Court of Federal Claims with respect to Lease OCS P-452 9 (the “Lease 452 Case”). On February 25, 2009, the Court of Federal Claims entered a judgment in our favor in the amount of $91.4 million with respect to our claim to recover lease bonus payments for Lease 452. On April 24, 2009, the government filed a notice of appeal of this judgment, but never filed an opening brief pending the outcome of settlement discussions. Under the terms of the settlement agreement we received gross proceeds of $65.0 million, which resulted in net proceeds to us of approximately $48.7 million after making all contingent payments to third

parties. An order of dismissal was entered by the United States Court of Appeals for the Federal Circuit on January 12, 2010 which concluded the litigation.

On January 12, 2010 an Order of Dismissal was entered in the Tenth Circuit Court of Appeals which concluded the shareholders’ derivative options backdating litigation entitled Britton v. Parker, et al. The Order was entered pursuant to a Motion to Dismiss that was filed by the Plaintiffs after the parties reached a settlement agreement on November 6, 2009. On September 23, 2009, the United States District Court for the District of Colorado had entered an opinion and order dismissing the Plaintiff’s Complaint, but on October 22, 2009, the Plaintiffs filed a Notice of Appeal with the United States Court of Appeals for the Tenth Circuit. Pursuant to the terms of the settlement agreement, the Plaintiffs/appellants agreed to file a motion to voluntarily dismiss, with prejudice, the appeal, and the parties agreed that that each party would bear its own costs and no award of costs would be made to either party. In addition, the parties agreed that no party to the litigation would contend that any other party or its counsel had brought frivolous litigation in violation of the Federal Rules of Civil Procedure.

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

The following matters were submitted to a vote of security holders at a special meeting of stockholders held on December 22, 2009:

•		An amendment to our Certificate of Incorporation to increase the number of authorized shares of our Common Stock from 300,000,000 to 600,000,000 was approved, with 191,566,899 shares voting in favor, 29,120,833 shares voting against and 1,03,957 shares abstaining.
•		Our 2009 Performance and Equity Incentive Plan was approved with 125,933,694 shares voting in favor, 19,146,064 shares voting against and 359,865 shares abstaining.

No other matters were submitted to a vote of security holders during the fourth quarter of 2009.

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
John R. Wallace			50			President, Chief Operating Officer and a Director		October 2003 to Present
Kevin K. Nanke			45			Treasurer and Chief Financial Officer		December 1999 to Present
Stanley F. Freedman			61			Executive Vice President, General Counsel and Secretary		January 2006 to Present
Hank Brown			70			Director		June 2007 to Present
Kevin R. Collins			53			Director		March 2005 to Present
Jerrie F. Eckelberger			65			Director		September 1996 to Present
Jean-Michel Fonck			68			Director		May 2009 to Present
Aleron H. Larson, Jr.			64			Director		May 1987 to Present
Russell S. Lewis			55			Director		June 2002 to Present
Anthony Mandekic			68			Director		May 2009 to Present
James J. Murren			48			Director		February 2008 to Present
Jordan R. Smith			75			Director		October 2004 to Present
Daniel J. Taylor			53			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.

John R. Wallace, President and Chief Operating Officer, joined Delta in October 2003 as Executive Vice President of Operations and was appointed President in February 2006 and a Director in June 2007. Since April 1, 2005, he has also served as Executive Vice President and Director of DHS. Mr. Wallace was Vice President of Exploration and Acquisitions for United States Exploration, Inc. (“UXP”), a Denver-based publicly-held oil and gas exploration company, from May 1998 to October 2003. Prior to UXP, Mr. Wallace served as president of various privately held oil and gas companies engaged in producing property acquisitions and exploration ventures. He received a Bachelor of Science degree in Geology from Montana State University in 1981. He is a member of the American Association of Petroleum Geologists and the Independent Petroleum Association of the Mountain States.

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.

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 Chief Financial Officer of Bear Tracker Energy, a position he has held since December 2009. 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 2001. 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 Mirage 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 Mirage. He is also a member of the Board of Directors and the Executive Committee. Mr. Murren previously served in the following capacities for MGM Mirage: President (1999-2008), Chief Operating Officer (2007-2008), Chief Financial Officer (1998-2007), and Treasurer (2001-2007). Prior to his employment at MGM Mirage, 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.

Daniel J. Taylor has been an executive of Tracinda Corporation since February 2006 and has served as a Director of MGM Mirage 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 2006. 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.

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 our next annual meeting of 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 Global 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, 2008		$	25.19			$	17.80
June 30, 2008			28.37				21.50
September 30, 2008			26.19				12.35
December 31, 2008			13.75				3.75
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

On March 11, 2010, the closing price of our common stock was $1.42. 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 February 24, 2010 was approximately 1,450 which does not include an estimated 34,000 additional holders whose stock is held in “street name.”

Recent Sales of Unregistered Securities

During the year ended December 31, 2009, 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

We did not repurchase any of our shares of common stock during the quarter ended December 31, 2009.

Item 6.     Selected Financial Data

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

																		Six Months Ended				Year Ended
		Years Ended December 31,																December 31,				June 30,
		2009				2008				2007				2006				2005				2005
		(In thousands, except per share amounts)
Total Revenues		$	182,442			$	271,178			$	194,941			$	177,465			$	48,715			$	56,612
Loss from continuing operations		$	(349,684	)		$	(468,268	)		$	(148,962	)		$	(12,033	)		$	(27,205	)		$	(11,370	)
Net Income attributable to Delta common stockholders		$	(328,783	)		$	(456,064	)		$	(149,807	)		$	2,916			$	219			$	15,050
Income/(Loss) attributable to Delta common stockholders Per Common Share
Basic		$	(1.56	)		$	(4.77	)		$	(2.44	)		$	.06			$	-			$	.37
Diluted		$	(1.56	)		$	(4.77	)		$	(2.44	)		$	.05			$	-			$	.36
Total Assets		$	1,457,485			$	1,894,963			$	1,110,054			$	932,614			$	694,203			$	512,983
Total Long-Term debt, including current portion		$	460,923			$	637,473			$	393,468			$	367,263			$	248,733			$	219,478
Total Delta Stockholders’ Equity		$	688,582			$	762,390			$	532,855			$	431,523			$	321,264			$	221,623
Total Non-Controlling Interest		$	8,538			$	29,104			$	27,296			$	27,390			$	15,496			$	14,614
Total Equity		$	697,120			$	791,494			$	560,151			$	458,913			$	336,760			$	236,237

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 areas of operation are the Rocky Mountain and Gulf Coast Regions, which comprise 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, 2009, we had estimated proved reserves that totaled 153.6 Bcfe, of which 86.5% were proved developed, with an after-tax PV-10 value of $156.7 million. For the year ended December 31, 2009, we reported net production of 60.7 Mmcfe per day.

As of December 31, 2009, our proved reserves were comprised of approximately 126.7 Bcf of natural gas and 4.5 Mmbbls of crude oil, or 82.4% gas on an equivalent basis. Approximately 73% of our proved reserves were located in the Rocky Mountains, 26% in the Gulf Coast and less than 1% in other locations. We expect that our 2010 drilling efforts and capital expenditures, when announced, will focus primarily on our Piceance Basin assets in the Rockies, As of December 31, 2009, we controlled approximately 797,000 net undeveloped acres, representing approximately 98% 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% (excluding our Columbia River Basin properties) as of December 31, 2009. 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. We also have a controlling ownership interest in a drilling company, providing the benefit of access to 18 drilling rigs primarily located in the Rocky Mountain Region. We concentrate our exploration and development efforts in fields where we can apply our technical exploration and development expertise, and where we have accumulated significant operational control and experience.

2009 Developments

	•		On April 22, 2009, DHS entered into the DHS Forbearance, as amended on May 21, 2009, with LCPI in which LCPI agreed to forbear until June 15, 2009 from exercising its rights and remedies under the credit agreement including, among other actions, acceleration of all amounts due under the credit agreement or foreclosure on the DHS rigs and other assets pledged as collateral, including accounts receivable. Because the forbearance period has expired and because of December 31, 2009 financial covenant violations by DHS, LCPI currently has the right to demand payment of the amounts outstanding under the credit facility and, if not paid, foreclose on the DHS assets pledged as collateral under the credit agreement. As of December 31, 2009, borrowings outstanding under the DHS facility were $83.3 million.
	•		On May 13, 2009, we completed an underwritten public offering of 172.5 million shares of our common stock at $1.50 per share for net proceeds of $246.9 million, net of underwriting commissions and related offering expenses.
	•		On May 15, 2009, we purchased for $26.0 million contingent payment rights previously sold to Tracinda Corporation that entitled Tracinda to receive up to $27.9 million of net proceeds from offshore California litigation related to the Amber Case.
	•		On May 19, 2009, we settled litigation filed in the United States Court of Federal Claims in Washington, D.C. by us and our 92%-owned subsidiary, Amber Resources Company of Colorado, with respect to 40 undeveloped federal leases, some of which were part of our and Amber’s offshore California properties (the “Amber Case”), and received from the U.S. government $60.0 million of litigation proceeds. In early June 2009, we paid out $11.3 million of royalty payments to third parties related to the Amber Case.
	•		On September 21, 2009, Gray well completion results were announced. The well did not encounter commercial quantities of gas and was written off as a dry hole during the quarter ended September 30, 2009.
	•		In October 2009, we entered into a new marketing arrangement for the majority of our operated Piceance Basin gas. Although our new arrangement results in higher transportation costs (Vega gas transportation expense increased from approximately $0.60 per Mmbtu to $1.20 per Mmbtu), this increase is more than offset by higher revenues from improved natural gas liquids recoveries at a higher efficiency processing plant (liquids recovery factor increased from approximately 0.25 gallons per Mmbtu compared to 2.75 gallons per Mmbtu) and a greater percentage of liquid proceeds retained (increased from approximately 67% of proceeds to 100% of proceeds). As a result of these changes, based on current commodity prices, our net realized price prior to hedging in the Vega area has improved substantially.
	•		In November 2009, we retained Strategic Advisors to evaluate and advise the Board of Directors on strategic alternatives to enhance shareholder value and the process is currently in advanced stages. Such alternatives are expected to include, but may not be limited to, exploring the sale of some or all of our assets, entering into partnerships or joint ventures, or the sale of the entire company. There can be no assurance that this evaluation of strategic alternatives will result in changes to our company, operations or business plan. In addition, there can be no assurance that we will pursue any particular transaction or transactions, or, if we do pursue any such transaction, that it will be completed or successful.
	•		On December 29, 2009, we settled the Lease 452 Case and received from the U.S. government $65.0 million of offshore litigation proceeds related to that case. In December 2009 and January 2010, we paid out $16.4 million of royalty payments to third parties related to the Lease 452 Case.
	•		As of December 31, 2009, we had reduced borrowings under our credit facility to $124.0 million, with $39.8 million of availability based on the October 30, 2009 redetermined $185.0 million borrowing base with a required availability cushion of $20.0 million. At February 28, 2010, our availability was $70.8 million. In addition, we obtained financial covenant relief for the quarters ending on December 31, 2009 and March 31, 2010.

2010 Outlook

As announced in November 2009, we are working with our Strategic Advisors to analyze various alternatives to enhance stockholder value, which include a sale of some or all of our assets, entering into partnerships or joint ventures, or the sale of the entire company. The evaluation of any particular transaction will involve, among other considerations, an analysis of our capital expenditure and working capital requirements for 2010 in respect of such transaction and other sources of liquidity, including cash from operations and our credit facility. We do not intend to disclose developments with respect to this review until the Board of Directors has approved a course of action.

We are unable to accurately predict our anticipated capital expenditures for fiscal year 2010, primarily due to the uncertainty relating to any Potential Strategic Transaction, including the likelihood of such a transaction occurring, the type of transaction and the timing of any such transaction. In addition, future redeterminations of our borrowing base under our credit facility, including the scheduled redetermination currently in process, may affect our liquidity available for capital expenditures making it difficult to accurately determine such amounts at the current time. We expect to announce our 2010 drilling plans and expected oil and gas production once our strategic alternatives evaluation process and borrowing base redetermination are complete.

The exploration for and the acquisition, development, production, and sale of, natural gas and crude oil are highly competitive and capital intensive. As in any commodity business, the market price of the commodity produced and the costs associated with finding, acquiring, extracting, and financing the operation are critical to our profitability and long-term value creation for our stockholders. Generating long-term reserve and production growth represents an ongoing focus for management and is made particularly important in our business given the natural production and reserve decline associated with producing oil and gas properties.

Our long-term business strengths include a multi-year inventory of attractive lower risk drilling on long-lived Rockies properties, which we believe will allow us to grow reserves and replace and expand production organically without having to rely solely on acquisitions, and significant leasehold positions in several high potential exploratory areas.

Liquidity and Capital Resources

Cash Flows

On May 13, 2009, we completed an underwritten public offering of 172.5 million shares of our common stock at $1.50 per share for net proceeds of $246.9 million, net of underwriting commissions and related offering expenses. On May 19, 2009, we received from the U.S. government $60.0 million of offshore litigation proceeds related to the Amber Case and in early June 2009 we paid out $11.3 million for third party contractual obligations and other participating interests related to the judgment. Further, on December 29, 2009 we received from the U.S. government an additional $65.0 million of litigation proceeds related to the offshore California lease 452 and in late December 2009 and early January 2010, we paid out a total of $16.4 million for third party contractual obligations and other participating interests related to the judgment. With proceeds from these transactions, we have reduced our borrowings outstanding under our credit facility from $294.5 million at December 31, 2008 to $124.0 million at December 31, 2009, with $39.8 million of remaining availability based on our current $185.0 million borrowing base with a required minimum availability of $20.0 million and outstanding letters of credit totaling $1.2 million. The borrowing base is subject to a redetermination currently in process and could increase or decrease based on our reserves at such time. In addition, we reduced our accounts payable from $159.0 million at December 31, 2008 to $44.2 million at December 31, 2009. During May 2009, DHS sold Rig #7 to Naknek Electric Association for cash proceeds of $7.8 million which, combined with proceeds from minor spare equipment sales and the collection of accounts receivable, were used to reduce borrowings outstanding under the DHS credit facility from $93.8 million at December 31, 2008 to $83.3 million at December 31, 2009.

As shown in the accompanying financial statements and discussed elsewhere herein, we experienced a net loss attributable to Delta common stockholders of $328.8 million for the year ended December 31, 2009. We were in compliance with the capital expenditure and accounts payables covenants under our credit facility at December 31, 2009. In the Second Amendment, we obtained waivers of our financial ratio covenants for periods ending December 31, 2009 and March 31, 2010. In addition, our DHS subsidiary remained out of compliance with the debt covenants under its credit facility and its forbearance agreement with LCPI expired on June 15, 2009. As a result, amounts outstanding under the DHS credit facility are classified as a current liability in the accompanying consolidated

balance sheet as of December 31, 2009. Further, DHS is facing significant, potentially immediate, requirements to fund obligations in excess of its existing sources of liquidity if its senior lender exercises its right to demand payment of the amounts outstanding under DHS’s credit facility. DHS is in discussions with its credit facility lender regarding amendments, waivers or other restructuring of the credit facility, but there can be no assurance that the lender will agree to any such amendments.

Our accompanying financial statements have been prepared assuming we will continue as a going concern. During the year ended December 31, 2009, significant improvements to our liquidity position were achieved through the equity transaction, receipt of the offshore litigation proceeds, and asset sales described above, which substantially improved our financial position. Nevertheless, we have a deficiency in short-term liquidity at DHS and possible additional liquidity issues if commodity prices remain at low levels and our banks further reduce our borrowing base as part of our next scheduled redetermination which is currently in process. Further, our Credit Agreement matures in January 2011. Thus, our ability to continue as a going concern could be dependent upon our lenders’ willingness to amend terms, grant waivers, or restructure existing agreements, or our success in generating additional sources of capital in the near future, and/or an increase in commodity prices. We are in discussions with our lenders regarding an amendment or restructuring of the existing credit facility, as well as discussions regarding a possible new credit facility.

During the year ended December 31, 2009, we had an operating loss of $254.4 million, net cash provided by operating activities of $81.1 million and net cash provided by financing activities of $62.7 million. During this period we spent $165.9 million on oil and gas development activities. At December 31, 2009, we had $61.9 million in cash and $39.8 million available under our credit facility (based on the borrowing base as re-determined on October 30, 2009), total assets of $1.5 billion and a debt to capitalization ratio of 39.8%. Debt, excluding installments payable on property acquisition which are secured by restricted cash deposits, at December 31, 2009 totaled $460.9 million, comprised of $207.3 million of bank debt ($124.0 million of our indebtedness under our Credit Agreement and $83.3 million of DHS indebtedness, of which the DHS indebtedness was classified as current at September 30, 2009), $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.

Capital Resources and Requirements

On March 2, 2009, we entered into the First Amendment to the Second Amended and Restated Credit Agreement (the “Forbearance Agreement and Amendment to the Credit Facility”), as further amended on April 14, 2009 and on April 30, 2009, with JPMorgan Chase Bank, N.A., as administrative agent, and certain of the financial institutions that are party to our credit agreement in which, among other changes, the lenders provided us relief for a period ended May 15, 2009 from acting upon their rights and remedies as a result of our violation of accounts payable and current ratio covenants. The Forbearance Agreement and Amendment to the Credit Facility replaced the previous consolidated net debt to consolidated EBITDAX covenant with a senior secured debt to consolidated EBITDAX requirement for the preceding four consecutive fiscal quarters to be less than 4.0 to 1.0. In accordance with the Forbearance Agreement and Amendment to the Credit Facility, the borrowing base was reduced upon the successful completion of our capital raising efforts from $295.0 million to $225.0 million, with a conforming borrowing base of $185.0 million.

On October 30, 2009, we entered into the Second Amendment in which, among other changes, the lenders provided waivers from the December 31, 2009 and March 31, 2010 current ratio and consolidated secured debt to EBITDAX ratio covenants. In conjunction with the Second Amendment and as part of a scheduled redetermination, the borrowing base was reduced from $225.0 million to $185.0 million. The next scheduled semi-annual redetermination is currently in progress. Also, the Second Amendment requires that we maintain minimum availability of $20.0 million essentially reducing our borrowing availability under the Credit Agreement. The minimum availability requirement will be released on the first date after delivery of the December 31, 2009 audited financial statements on which we are in compliance with our financial covenants as of the most recently completed quarter (without giving effect to any waiver of compliance with such covenants) and project pro forma compliance for each of the four following quarters. In addition, the Second Amendment imposed capital expenditures limitations of $10.0 million for the quarter ending December 31, 2009, $10.0 million for the quarter ending March 31, 2010, and $5.0 million for the quarter ending June 30, 2010, provided that any excess of the limitation over the amount of actual expenditures may

be carried forward from an earlier quarter to a subsequent quarter. The Second Amendment also included a payables covenant whereby our trade payables (a sub-component of accounts payable on the accompanying consolidated balance sheet) may not exceed $30.0 million, exclusive of any amounts owed by us to our subsidiary DHS. As of December 31, 2009, we were in compliance with our capital expenditures and accounts payable limitations.

As of December 31, 2009, 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, 2009, our corporate credit and senior unsecured debt ratings were CCC and CCC, respectively, as issued by Standard and Poor’s (“S&P”). S&P’s outlook on its rating was “developing.”

Our future cash requirements are largely dependent upon the number and timing of projects included in our capital development plan, most of which are discretionary. We have historically addressed our long-term liquidity requirements through the issuance of debt and equity securities when market conditions permit, through cash provided by operating activities, sales of oil and gas properties, and through borrowings under our credit facility.

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

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

As part of our consideration of Potential Strategic Transactions, we continue to examine additional sources of long-term capital (including a restructured debt facility, the issuance of debt instruments, sales of assets and joint venture financing), as well as other potential corporate transactions. The availability of additional sources of capital, which will impact our ability to execute our operating strategy and meet our liquidity challenges, will depend upon a number of factors, many of which are beyond our control.

Results of Operations

The following discussion and analysis relates to items that have affected our results of operations for the years ended December 31, 2009, 2008 and 2007. 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,
		2009				2008				2007
Revenue:
Oil and gas sales		$	94,962			$	221,733			$	123,729
Contract drilling and trucking fees			13,680				49,445				58,358
Gain on offshore litigation settlement, net of property sales			73,800				-				-
Gain (loss) on hedging instruments, net			-				-				12,854
Total revenue			182,442				271,178				194,941
Operating Expenses:
Lease operating expense			31,303				33,508				20,882
Transportation expense			11,612				11,395				4,074
Production taxes			3,852				12,075				7,463
Exploration expense			2,604				10,975				9,062
Dry hole costs and impairments			189,072				438,963				87,459
Depreciation, depletion and amortization – oil and gas			108,505				99,125				73,875
Drilling and trucking operating expenses			15,293				32,594				37,698
Goodwill and drilling equipment impairments			6,508				29,349				-
Depreciation and amortization – drilling and trucking			22,917				14,134				16,021
General and administrative expense			41,414				53,607				49,621
Executive severance expense			3,739				-				-
Total operating expenses			436,819				735,725				306,155
Operating loss			(254,377	)			(464,547	)			(111,214	)
Other income and (expense):
Interest expense and financing costs			(55,035	)			(45,489	)			(31,899	)
Interest income			2,454				10,132				2,080
Other income (expense)			1,049				(5,210	)			376
Realized gain (loss) on derivative instruments, net			(1,115	)			18,383				917
Unrealized gain (loss) on derivative instruments, net			(26,972	)			3,365				(3,819	)
Income (loss) from unconsolidated affiliates			(15,473	)			3,375				(393	)
Total other expense			(95,092	)			(15,444	)			(32,738	)
Loss from continuing operations before income taxes and discontinued operations			(349,469	)			(479,991	)			(143,952	)
Income tax expense (benefit)			215				(11,723	)			5,010
Loss from continuing operations			(349,684	)			(468,268	)			(148,962	)
Income from discontinued operations of properties sold or held for sale, net of tax			-				-				1,922
Gain (loss) on sale of discontinued operations, net of tax			-				718				(3,998	)
Net loss			(349,684	)			(467,550	)			(151,038	)
Less net loss attributable to non-controlling interest			20,901				11,486				1,231
Net loss attributable to Delta common stockholders		$	(328,783	)		$	(456,064	)		$	(149,807	)

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 $468.3 million for the year ended December 31, 2008 to a loss of $349.7 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 $95.0 million, as compared to $221.7 million for the comparable period a year earlier. During the year ended December 31, 2009, production from continuing operations decreased by 11% and the average natural gas and oil price decreased 54% and 43% respectively. The average gas price received during the year ended December 31, 2009 was $3.13 per Mcf compared to $6.87 per Mcf for the year earlier period and the average oil price received during the year ended December 31, 2009 was $52.37 per Bbl compared to $92.12 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. At December 31, 2009 DHS owned 18 drilling rigs with depth ratings of approximately 10,000 to 25,000 feet. We have the right to use all of the rigs on a priority basis, although currently only one is working on a Delta operated well. 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 and Property Sales, Net. 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)			761				993
Gas (MMcf)			17,590				18,948
Total Production (MMcfe)			22,156				24,908
Average Price – Continuing Operations:
Oil (per barrel)		$	52.37			$	92.12
Gas (per Mcf)		$	3.13			$	6.87
Costs per Mcfe – Continuing Operations:
Lease operating expense		$	1.41			$	1.35
Production taxes		$	.17			$	.48
Transportation costs		$	.52			$	.46
Depletion expense		$	4.76			$	3.87

Lease Operating Expense. Lease operating expenses for the year ended December 31, 2009 were $31.3 million compared to $33.5 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 declining production. The average lease operating expense was $1.41 per Mcfe in 2009 as compared to $1.35 per Mcfe for the year earlier period.

Transportation expense. Transportation expense for the year ended December 31, 2009 was $11.6 million, comparable to prior year costs of $11.4 million, but up 13% from $0.46 per Mcfe to $0.52 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 we expect Vega area transportation costs to increase on a per unit basis in 2010 as a result of these operations, based on current commodity prices, this increase is expected to be 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. 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 period a year ago. 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 to our proved and unproved properties totaling approximately $155.5 million primarily related to our non-operated Garden Gulch field in the Piceance Basin ($38.6 million), Haynesville Shale ($27.5 million), Columbia River Basin ($21.4 million), Lighthouse Bayou ($14.8 million), various Gulf Coast fields ($29.2 million), Vega surface land ($10.5 million), various Rockies fields ($6.9 million), pipe and tubular inventory ($4.3 million) and Paradox pipeline ($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 to our proved and unproved properties totaling approximately $305.6 million primarily related to the Newton, Midway Loop, Opossum Hollow and Angleton fields in Texas ($192.5 million), Paradox field in Utah ($30.5 million), Howard Ranch and Bull Canyon fields in the Rockies ($32.0 million), Utah Hingeline ($40.8 million) and our offshore California field ($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 9% to $108.5 million for the year ended December 31, 2009, as compared to $99.1 million for the year earlier period. Depletion expense for the year ended December 31, 2009 was $105.4 million compared to $96.5 million for the year ended December 31, 2008. The 9% increase in depletion expense was primarily due to a 23% increase in the depletion rate. Our depletion rate increased to $4.76 per Mcfe for the year ended December 31, 2009 from $3.87 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. Based on current commodity prices, we expect our depletion rate to decline in 2010 due to additional Rockies undeveloped reserves that can be recorded as proved as higher prices from more recent quarters replace lower prices from earlier in 2009 in the SEC required 12-month average historical price.

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 decreased 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. We expect further reductions to full year cash general and administrative expenses in 2010 as cost saving measures implemented in 2009 take full effect in 2010.

Interest and Financing Costs. Interest and financing costs increased 21% to $55.0 million for the year ended December 31, 2009, as compared to $45.5 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, and non-cash accretion of discount on an installment obligation payable to EnCana Oil and Gas (USA) Inc. (“EnCana”).

Interest Income. Interest income decreased to $2.5 million for the year ended December 31, 2009 compared to $10.1 million for the comparable prior year period. The decrease is a result of lower interest earned on lower investment balances.

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 on Derivative Instruments, Net. Effective July 1, 2007, we discontinued cash flow hedge accounting. Beginning July 1, 2007, we recognize realized gains or losses in other income and expense instead of as a component of revenue. As a result, other income and expense includes $1.1 million of realized losses and $18.4 million of realized gains on derivative instruments for the years ended December 31, 2009 and 2008, respectively.

Unrealized Gain on Derivative Instruments, Net. As a result of the discontinuation of cash flow hedge accounting, 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 loss 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 lower commodity prices in the current year period.

Income (Loss) From Unconsolidated Affiliates. Loss from unconsolidated affiliates during the year ended December 31, 2009 is 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 are 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 continued losses, we were required by the “more likely than not” provisions of SFAS No. 109, “Accounting for Income Taxes” (“SFAS 109”), to record a valuation allowance for our deferred tax assets beginning with the second quarter of 2007. Our income tax benefit for the year ended December 31, 2009 of $215,000 relates only to DHS, as no benefit was provided for Delta’s net operating losses.

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.

Year Ended December 31, 2008 Compared to Year Ended December 31, 2007

Net Income (Loss) Attributable to Delta Common Stockholders. Net loss attributable to Delta common stockholders was $456.1 million, or $4.77 per diluted common share, for the year ended December 31, 2008, compared to net loss of $149.8 million or $2.44 per diluted common share, for the year ended December 31, 2007. Loss from continuing operations attributable to Delta common stockholders increased from $147.7 million for the year ended December 31, 2007 to a loss of $456.8 million for the year ended December 31, 2008, due primarily to $327.1 million of impairments recorded during the fourth quarter due to the significant decline in commodity prices. In addition, we recognized $111.9 million of dry hole costs in the Paradox, Hingeline and other areas.

Oil and Gas Sales. During the year ended December 31, 2008, oil and gas sales from continuing operations were $221.7 million, as compared to $123.7 million for the comparable period a year earlier. During the year ended December 31, 2008, production from continuing operations increased by 48% and the average gas price increased 33%. The average gas price received during the year ended December 31, 2008 was $6.87 per Mcf compared to $5.17 per Mcf for the year earlier period. The average oil price received during the year ended December 31, 2008 increased to $92.12 per Bbl compared to $67.39 per Bbl for the year earlier period.

Net gains from effective hedging activities were $12.9 million for the year ended December 31, 2007. The gain in 2007 relates to effective hedging instruments during the period. These gains are recorded as an increase in revenues. For the year ended December 31, 2008, all realized derivative gains are included in other income.

Contract Drilling and Trucking Fees. At December 31, 2008 DHS owned 19 drilling rigs with depth ratings of approximately 10,000 to 25,000 feet. We have the right to use all of the rigs on a priority basis, although currently only two are working on Delta operated wells. Drilling and trucking revenues for the year ended December 31, 2008 decreased to $49.4 million compared to $58.4 million for the prior year period. Drilling and trucking revenues decreased in 2008 due to the average number of rigs working for Delta from 9 average rigs in 2008 compared to 6 average rigs for the prior year. Drilling and trucking revenues earned on wells drilled for Delta have been eliminated in consolidation.

Production and Cost Information

Production volumes, average prices received and cost per equivalent Mcf for the years ended December 31, 2008 and 2007 are as follows:

		Years Ended December 31,
		2008				2007
Production – Continuing Operations:
Oil (MBbl)			993				1,003
Gas (MMcf)			18,948				10,866
Production – Discontinued Operations:
Oil (MBbl)			-				82
Gas (MMcf)			-				387
Total Production (MMcfe)			24,908				17,763
Average Price – Continuing Operations:
Oil (per barrel)		$	92.12			$	67.39
Gas (per Mcf)		$	6.87			$	5.17
Costs per Mcfe – Continuing Operations:
Lease operating expense		$	1.35			$	1.24
Production taxes		$	.48			$	.44
Transportation costs		$	.46			$	.24
Depletion expense		$	3.87			$	4.26

Lease Operating Expense. Lease operating expenses for the year ended December 31, 2008 were $33.5 million compared to $20.9 million for the year earlier period. Lease operating expense from continuing operations for the year ended December 31, 2008 increased proportionately with production. The average lease operating expense per Mcfe was $1.35 per Mcfe as compared to $1.24 per Mcfe for the year earlier period.

Exploration Expense. Exploration expense consists of geological and geophysical costs and lease rentals. Our exploration costs for the year ended December 31, 2008 were $11.0 million compared to $9.1 million for the year earlier period. 2008 exploration activities primarily include seismic shoots in two areas.

Dry Hole Costs and Impairments. We incurred dry hole costs of approximately $111.9 million for the year ended December 31, 2008 compared to $28.1 million for the comparable period a year ago. For the year ended December 31, 2008, our dry hole costs related primarily to Greentown and Hingeline exploratory projects in Utah. For the year ended December 31, 2007, the dry hole costs related primarily to seven exploratory projects, three in Texas, two in Wyoming, one in Colorado and one in Utah.

During the year ended December 31, 2008, we recorded an impairment provision to our proved and unproved properties totaling approximately $305.6 million primarily related to the Newton, Midway Loop, Opossum Hollow and Angleton fields in Texas ($192.5 million), Paradox field in Utah ($30.5 million), Howard Ranch and Bull Canyon fields in the Rockies ($32.0 million), Utah Hingeline ($40.8 million) and our offshore California field ($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.

During the year ended December 31, 2007, we recorded impairments totaling approximately $59.4 million primarily related to the Howard Ranch and Fuller fields in Wyoming ($38.4 million and $10.3 million, respectively), and the South Angleton field in Texas ($9.7 million), primarily due to lower Rocky Mountain natural gas prices and marginally economic deep zones on the Howard Ranch Prospect.

Depreciation, Depletion and Amortization – oil and gas. Depreciation, depletion and amortization expense increased 34% to $99.1 million for the year ended December 31, 2008, as compared to $73.9 million for the year earlier period. Depletion expense for the year ended December 31, 2008 was $96.5 million compared to $71.9 million for the year ended December 31, 2007. The 34% increase in depletion expense was due to a 48% increase in production from continuing operations, slightly offset by a 9% decrease in the depletion rate. Our depletion rate decreased to $3.87 per Mcfe for the year ended December 31, 2008 from $4.26 per Mcfe for the year earlier period.

The decrease is partially due to lower finding costs per Mcfe on our 2008 Rockies drilling program and the effect of impairments recorded in 2008.

Drilling and Trucking Operating Expenses. We had drilling and trucking operating expenses of $32.6 million during the year ended December 31, 2008 compared to $37.7 million during the year ended December 31, 2007. The significant decrease in expenses was due to the increase in the average number of rigs working for Delta in 2008 than in the prior year.

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, we also wrote off the entire amount of DHS’s goodwill of $7.7 million.

Depreciation and Amortization - drilling and trucking. Depreciation and amortization expense - drilling and trucking decreased to $14.1 million for the year ended December 31, 2008 as compared to $16.0 million for the prior year period. This decrease can be attributed to a greater average number of rigs working for Delta in 2008 compared to the prior year.

General and Administrative Expense. General and administrative expense increased 8% to $53.6 million for the year ended December 31, 2008, as compared to $49.6 million for the comparable prior year period. The increase in general and administrative expenses is primarily attributed to an increase in staff and related personnel costs.

Interest and Financing Costs. Interest and financing costs increased 43% to $45.5 million for the year ended December 31, 2008, as compared to $31.9 million for the comparable year earlier period. The increase is primarily related to higher average debt balances on the Delta and DHS credit facilities and the non-cash accretion of discount on an installment obligation payable to EnCana Oil and Gas (USA) Inc. (“EnCana”). In addition, the year ended December 31, 2008 includes $4.2 million of non-cash accretion of debt discount compared to $2.7 million in the prior year period related to the 3³/4% convertible notes issued in April 2007.

Interest Income. Interest income increased to $10.1 million for the year ended December 31, 2008 compared to $2.1 million for the comparable prior year period. The increase is primarily due to interest earned on our $300 million restricted deposit in connection with a joint development transaction with EnCana and invested cash received from the Tracinda transaction during the first quarter of 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.

Realized Gain on Derivative Instruments, Net. Effective July 1, 2007, we discontinued cash flow hedge accounting. Beginning July 1, 2007, we recognize realized gains or losses in other income and expense instead of as a component of revenue. As a result, other income and expense includes $18.4 million and $917,000 of realized gains on derivative instruments for the years ended December 31, 2008 and 2007, respectively.

Unrealized Gain on Derivative Instruments, Net. As a result of the discontinuation of cash flow hedge accounting, we recognize mark-to-market gains or losses in current earnings instead of deferring those amounts in accumulated other comprehensive income. Accordingly, we recognized $3.4 million of unrealized gains on derivative instruments in other income and expense during the year ended December 31, 2008 compared to a loss of $3.8 million for the comparable prior year period, primarily due to lower commodity prices in the current year period.

Income Tax Benefit (Expense). Due to our continued losses, we were required by the “more likely than not” provisions of SFAS No. 109, “Accounting for Income Taxes” (“SFAS 109”), to record a valuation allowance for our deferred tax assets beginning with the second quarter of 2007. Our income tax benefit for the year ended December 31, 2008 of $11.7 million relates only to DHS, as no benefit was provided for Delta’s net operating losses.

Discontinued Operations. Discontinued operations for the year ended December 31, 2007 include the Kansas field, which was sold in January 2007, the Australia field and the New Mexico and East Texas properties, which were sold in March 2007, the North Dakota properties sold in September 2007, and the Washington County, Colorado properties sold in October 2007. The results of operations from these assets during the year ended December 31, 2007 was an income of $1.9 million, net of tax.

Gain (Loss) on Sale of Discontinued Operations. 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. During the year ended December 31, 2007, we sold non-core properties in Colorado, Kansas, Texas, New Mexico, Australia and North Dakota for combined proceeds of $46.4 million at a combined net loss of $4.0 million.

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, 2008 and 2007, DHS generated a loss resulting in a non-controlling interest credit to earnings.

Historical Cash Flow

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 $147.4 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 provided by financing activities was $62.7 million for the year ended December 31, 2009 compared to $897.6 million for the comparable prior year period. Cash provided by 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 was higher in 2008 primarily due to cash received from the Tracinda transaction and additional bank borrowings.

Our cash flow from operating activities increased from $87.0 million for the year ended December 31, 2007 to $140.7 million for the year ended December 31, 2008, primarily as a result of increased production and higher commodity prices for most of the year. Our net cash used in investing activities increased to $982.6 million for the year ended December 31, 2008 compared to net cash used in investing activities of $326.6 million for the year earlier period, primarily due to our increased drilling and acquisition activity and the investment of cash received in the Tracinda transaction. Cash provided by financing activities was $897.6 million for the year ended December 31, 2008 compared to $241.7 million for the comparable prior year period. Cash provided by financing activities was higher in 2008 primarily due to cash received from the Tracinda transaction.

Capital and Exploration Expenditures and Financing

Our capital and exploration expenditures and sources of financing for the years ended December 31, 2009, 2008 and 2007 were as follows:

		Years Ended December 31,
		2009				2008				2007
		(In thousands)
CAPITAL AND EXPLORATION EXPENDITURES:
Acquisitions:
Piceance		$	-			$	128,848			$	-
Haynesville			-				31,550				-
Lighthouse Bayou			-				14,512				-
Austin Chalk incremental interests			-				13,855				23,765
Garden Gulch			-				-				34,778
Wyoming (Yates)			-				-				3,500
Washington County, South and North Tongue			-				-				1,000
Columbia River Basin			-				25,000				-
Other			2,083				8,050				9,988
Other development costs			165,854				458,067				287,790
Drilling and trucking companies			1,785				52,970				22,292
Exploration costs			2,604				10,975				9,062
		$	172,326			$	743,827			$	392,175
FINANCING SOURCES:
Cash provided by operating activities		$	81,144			$	140,676			$	87,003
Stock issued for cash upon exercised options			-				4,827				137
Stock issued for cash, net			246,905				662,043				202,084
Net long-term borrowings			(183,859	)			232,120				40,836
Proceeds from sale of oil and gas properties			8,393				42,000				46,193
Proceeds from sale of drilling assets			9,111				3,201				7,145
Proceeds from sale of marketable securities			2,030				-				-
Investments in and notes issued to affiliates			295				(6,965	)			(12,833	)
Increase in restricted deposit			430				(300,000	)			-
Minority interest contributions			-				12,000				(355	)
Other			14				(120	)			(106	)
		$	164,463			$	789,782			$	370,104

We are unable to accurately predict our anticipated capital expenditures for fiscal year 2010, primarily due to the uncertainty relating to any Potential Strategic Transaction, including the likelihood of such a transaction occurring, the type of transaction and the timing of any such transaction. In addition, future redeterminations of our borrowing base under our credit facility, including the scheduled redetermination currently in process, may affect our liquidity available for capital expenditures making it difficult to accurately determine such amounts at the current time. We expect to announce our 2010 drilling plans once our strategic alternatives evaluation process and borrowing base redetermination are complete.

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, 2007, positive gas revisions of 23.9 Bcf were primarily related to longer lived Piceance Basin wells due to higher gas pricing at year-end 2007 and the increase in proved reserves from extensions and discoveries of 100.8 Bcfe was primarily comprised of Rocky Mountain proved reserve increases primarily from the Company’s Piceance Basin drilling program and related offset wells. In addition, during 2007, the Company purchased incremental interests in its existing Piceance Basin acreage and in its existing Gulf Coast Austin Chalk acreage totaling 12.2 Bcfe. Finally, during 2007, proved reserves totaling 33.3 Bcfe located in various states were sold in a series of transactions described in Note 4, “Oil and Gas Properties – Discontinued Operations” to the 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 the Company’s 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 the Company’s Piceance Basin drilling program and related offset wells. Also, during 2008, the Company purchased incremental interests in its existing Piceance Basin acreage and acquired new interests in adjacent leasehold to expand its 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. 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 the Company’s 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.

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, 2007, 2008 and 2009, we completed the following transactions:

On October 1, 2007, we divested our Washington County, Colorado assets in conjunction with an asset exchange transaction to acquire additional working interest in the Garden Gulch Field in the Piceance Basin. On September 4, 2007, we completed the sale of certain non-core properties located in North Dakota for cash consideration of approximately $6.2 million. The sale resulted in a gain of $4.3 million. On March 30, 2007, we completed the sale of certain non-core properties located in New Mexico and East Texas for cash consideration of approximately $31.5 million, prior to customary purchase price adjustments. The sale resulted in a loss of approximately $10.8 million. On March 27, 2007, we completed the sale of certain non-core properties located in Australia for cash consideration of approximately $6.0 million. The sale resulted in an after-tax gain of $2.0 million. On January 10, 2007, we completed the sale of certain non-core properties located in Padgett field, Kansas for cash consideration of $5.6 million. The transaction resulted in a gain on sale of properties of $297,000.

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 34% of the Company’s 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 the Company 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 leaseholds interests acquired from EnCana on September 15, 2008.

During the fourth quarter of 2009 through a series of transactions, the Company 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, the Company sold the amine unit from its 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.

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, 2009		2010				2011 - 2012				2013 - 2014				Thereafter				Total
		(In thousands)
Credit facility		$	-			$	124,038			$	-			$	-			$	124,038
Installments payable on property acquisitions1			100,000				100,000				-				-				200,000
7% Senior unsecured notes			-				-				-				150,000				150,000
Interest on 7% Senior unsecured notes			10,500				21,000				21,000				10,500				63,000
33/4% Senior convertible notes2			-				115,000				-				-				115,000
Credit facility – DHS3			83,268				-				-				-				83,268
Derivative liability			19,497				7,475				-				-				26,972
Abandonment retirement obligation			2,913				592				365				16,869				20,739
Operating leases			2,447				2,992				2,922				946				9,307
Total contractual cash obligations		$	218,625			$	371,097			$	24,287			$	178,315			$	792,324

Credit Facility

On October 30, 2009, we entered into the Second Amendment in which, among other changes, our lender banks provided waivers from the December 31, 2009 and March 31, 2010 current ratio and consolidated secured debt to EBITDAX ratio covenants. In conjunction with the Second Amendment and as part of a scheduled redetermination, the borrowing base was reduced from $225.0 million to $185.0 million. The next scheduled redetermination date is March 1, 2010. Also, the Second Amendment requires that we maintain minimum availability of $20.0 million essentially reducing our borrowing availability under the Credit Agreement. Under the terms of the Second Amendment, the minimum availability requirement will be released on the first date after delivery of the December 31, 2009 audited financial statements on which we are in compliance with our financial covenants as of the most recently completed quarter (without giving effect to any waiver of compliance with such covenants) and project pro forma compliance for each of the four following quarters. In addition, the Second Amendment imposed capital expenditures limitations of $10.0 million for the quarter ending December 31, 2009, $10.0 million for the quarter

ending March 31, 2010, and $5.0 million for the quarter ending June 30, 2010, provided that any excess of the limitation over the amount of actual expenditures may be carried forward from an earlier quarter to a subsequent quarter. The Second Amendment also included a payables covenant whereby our trade payables (a sub-component of accounts payable on the accompanying consolidated balance sheet) may not exceed $30.0 million, exclusive of any amounts owed by us to our subsidiary DHS. As of December 31, 2009, we were in compliance with our capital expenditures and trade payables covenants.

The borrowing base is redetermined by the lending banks at least semiannually or by special redeterminations if requested by us based on drilling success. The March 2010 scheduled redetermination is in process. If, as a result of any reduction in the amount of our borrowing base, the total amount of the outstanding debt were to exceed the amount of the borrowing base in effect, then, within 30 days after we are notified of the borrowing base deficiency, we would be required to (1) make a mandatory payment of principal to reduce our outstanding indebtedness so that it would not exceed our borrowing base, (2) eliminate the deficiency by making three equal monthly principal payments, (3) provide additional collateral for consideration to eliminate the deficiency within 90 days or (4) eliminate the deficiency through a combination of (1) through (3). If for any reason we were unable to pay the full amount of the mandatory prepayment within the requisite 30-day period, we would be in default of our obligations under the Credit Agreement.

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

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

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

Installments Payable on Property Acquisition

On February 28, 2008, we closed a transaction with EnCana to jointly develop a portion of EnCana’s leasehold interests in the Vega Area of the Piceance Basin. Under the terms of the agreement we have committed to fund $410.1 million, of which $110.5 million was paid at the closing, $99.6 million was paid on November 1, 2009 and the remaining balance is due in two $100.0 million installments due November 1, 2010, and 2011. These remaining installments are collateralized by a letter of credit, which in turn is collateralized by cash on deposit in a restricted account. The installment payment obligation is recorded in the accompanying consolidated financial statements as current and long-term liabilities at a discounted value, initially of $280.1 million, based on an imputed interest rate of 2.58%. The discount is being accreted on the effective interest method over the term of the installments, including accretion of $6.1 million and $7.0 million for the years ended December 31, 2008 and 2009, respectively.

7% Senior Unsecured Notes, due 2015

On March 15, 2005, we issued 7% senior unsecured notes for an aggregate amount of $150.0 million which pay interest semi-annually on April 1 and October 1 and mature in 2015 (the “Senior Notes”). The Senior Notes were issued at 99.50% of par and the associated discount is being amortized to interest expense over their term. The indenture governing the Senior Notes contains various restrictive covenants that may limit our ability to, among other things, incur additional indebtedness, make certain investments, sell assets, consolidate, merge or transfer all or substantially all of our assets and the assets of our restricted subsidiaries. These covenants may limit management’s discretion in operating our business. In addition, in the event that a Change of Control should occur (as such term is defined in the indenture), each holder of the Senior Notes would have the right to require us to repurchase all or any

part of such holder’s notes at a purchase price in cash equal to 101% of the principal amount of the notes plus accrued and unpaid interest, if any, to the date of purchase.

3³/4% Senior Convertible Notes, due 2037

On April 25, 2007, we issued $115.0 million aggregate principal amount of 3³/4% Senior Convertible Notes due 2037 (the “Notes”) for net proceeds of $111.6 million after underwriters’ discounts and commissions of approximately $3.4 million. The Notes bear interest at a rate of 3³/4% per annum, payable semi-annually in arrears, on May 1 and November 1 of each year, beginning November 1, 2007. The Notes will mature on May 1, 2037 unless earlier converted, redeemed or repurchased, but each holder of Notes has the option to require us to purchase any outstanding Notes on each of May 1, 2012, May 1, 2017, May 1, 2022, May 1, 2027 and May 1, 2032 at a price which is required to be paid in cash, equal to 100% of the principal amount of the Notes to be purchased. The Notes will be convertible at the holder’s option, in whole or in part, at an initial conversion rate of 32.9598 shares of common stock per $1,000 principal amount of Notes (equivalent to a conversion price of approximately $30.34 per share) at any time prior to the close of business on the business day immediately preceding the final maturity date of the Notes, subject to prior repurchase of the Notes. The conversion rate may be adjusted from time to time in certain instances. Upon conversion of a Note, we will have the option to deliver shares of our common stock, cash or a combination of cash and shares of our common stock for the Notes surrendered. In the event that a fundamental change occurs (as defined in the Indenture, but generally including a tender offer for a majority of our securities, an acquisition by anyone of 50% or more of our stock, a change in the majority of our Board of Directors, the approval of a plan of liquidation or being delisted from a national securities exchange), each holder of Notes would have the right to require us to purchase all or a portion of its Notes for the price specified in the Indenture. In addition, following certain fundamental changes that occur prior to maturity, we will increase the conversion rate for a holder who elects to convert their Notes in connection with such fundamental changes by a number of additional shares of common stock. Also, we are not permitted to consolidate with or merge with or into, or convey, transfer, sell, lease or dispose of all or substantially all of our assets unless the successor company meets certain requirements and assumes all of our obligations under the Notes. If as a result of such transaction, the Notes become convertible into common stock or other securities issued by another issuer, the other issuer must fully and unconditionally guarantee all of our obligations under the Notes. Although the Notes do not contain any financial covenants, the Notes contain covenants that require us to properly make payments of principal and interest, provide certain reports, certificates and notices to the trustee under various circumstances, cause our wholly-owned subsidiaries to become guarantors of the debt, maintain an office or agency where the Notes may be presented or surrendered for payment, continue our corporate existence, pay taxes and other claims, and not seek protection from the debt under any applicable usury laws.

Credit Facility – DHS

On August 15, 2008, DHS entered into a new agreement with Lehman Commercial Paper, Inc. (“LCPI”) to amend its existing LCPI credit facility. The revised agreement increased the borrowing base from $75.0 million to $150.0 million. Total debt outstanding at December 31, 2009 under the facility was $83.3 million. Because of LCPI’s bankruptcy and default, DHS does not have any additional borrowing capacity under the LCPI facility. Under the revised agreement, DHS has an obligation to provide to LCPI by March 31 of each year audited financial statements reported on without a going concern qualification or exception by the independent auditor. DHS was not able to provide audited financial statements not containing an explanatory paragraph related to its ability to continue as a going concern, and, accordingly, DHS was not in compliance with this covenant at March 31, 2009. In addition, at December 31, 2009, DHS was not in compliance with its minimum EBITDA, maximum leverage ratio, minimum interest coverage ratio and minimum current ratio financial covenants.

On April 22, 2009, DHS entered into the DHS Forbearance, as amended on May 21, 2009, with LCPI in which LCPI agreed to forbear until June 15, 2009 from exercising its rights and remedies under the credit agreement including, among other actions, acceleration of all amounts due under the credit facility or foreclosure on the DHS rigs and other assets pledged as collateral, including accounts receivable. The DHS facility is non-recourse to Delta. Due to the lapsing of the DHS Forbearance as well as the September 30, 2009 and December 31, 2009 financial covenant violations by DHS, LCPI currently has the right to demand payment of the amounts outstanding under the credit facility and if not paid, foreclose on the DHS assets pledged as collateral for the credit facility. Although LCPI has not exercised its right to foreclose on the DHS assets pledged as collateral and DHS in currently in negotiations with

LCPI to amend the terms of the credit facility, there can be no assurance that LCPI will not exercise its right to foreclose on the DHS assets pledged as collateral.

Other Contractual Obligations

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

We lease our corporate office in Denver, Colorado under an operating lease which will expire in 2014. Our average yearly payments approximate $1.2 million over the remaining term of the lease. We have additional operating lease commitments which represent office equipment leases and lease obligations primarily relating to field vehicles and equipment.

We had a net derivative liability of $27.0 million at December 31, 2009. The ultimate settlement amounts of these derivative instruments are unknown because they are subject to continuing market fluctuations. See Item 3. “Quantitative and Qualitative Disclosures about Market Risk” for more information regarding our derivative instruments.

Critical Accounting Policies and Estimates

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

Successful Efforts Method of Accounting

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

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

expense. The evaluation of gas and oil leasehold acquisition costs requires managerial judgment to estimate the fair value of these costs with reference to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.

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

Reserve Estimates

Estimates of gas and oil reserves, by necessity, are projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of gas and oil that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable gas and oil reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions governing future gas and oil prices, the availability and cost of capital to develop the reserves, future operating costs, severance taxes, development costs and workover gas costs, all of which may in fact vary considerably from actual results. The future drilling costs associated with reserves assigned to proved undeveloped locations may ultimately increase to an extent that these reserves may be later determined to be uneconomic. For these reasons, estimates of the economically recoverable quantities of gas and oil attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected therefrom may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of our gas and oil properties and/or the rate of depletion of the gas and oil properties. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material. Based on the 12-month average historical first of month prices required to be used under the new SEC reserve reporting rules in determining proved reserves, none of our undeveloped locations in the Piceance Basin were able to be classified as proved undeveloped reserves at December 31, 2009. However, based on the old SEC rules, we would be able to report our Piceance Basin proved undeveloped reserves (see Reserve Sensitivities in Item 2. Properties above) as a result of higher prices at year-end 2009. Further development of these properties depends on expected higher commodity prices in the future, reductions in future drilling costs, or a combination of both.

Impairment of Gas and Oil Properties

We review our oil and gas properties for impairment quarterly or whenever events and circumstances indicate a decline in the recoverability of their carrying value. We estimate the expected future cash flows of our developed proved properties and compare such future cash flows to the carrying amount of the proved properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and gas properties to their fair value. The primary factors used to determine fair value include estimates of proved reserves, future production estimates, future commodity pricing, anticipated capital expenditures and production costs, and a discount rate commensurate with the risk associated with realizing the expected cash flows projected.

Given the complexities associated with gas and oil reserve estimates and the history of price volatility in the gas and oil markets, events may arise that would require us to record an impairment of the recorded book values associated with gas and oil properties. For developed properties, the review consists of a comparison of the carrying value of the asset with the asset’s expected future undiscounted cash flows without interest costs. As a result of this assessment, during the year ended December 31, 2009, we recorded impairment provisions to our proved and unproved properties totaling approximately $155.5 million primarily related to our non-operated Garden Gulch field in the Piceance Basin ($38.6 million), Haynesville Shale ($27.5 million), Columbia River Basin ($21.4 million), Lighthouse Bayou ($14.8 million), proved and unproved impairments in various Gulf Coast fields ($29.2 million), Vega surface land ($10.5 million), proved and unproved impairments in various Rockies fields ($6.9 million), pipe and tubular inventory ($4.3 million) and Paradox pipeline ($1.9 million).

In 2008, we recorded impairment provisions to our proved and unproved properties totaling approximately $305.6 million primarily related to the Newton, Midway Loop, Opossum Hollow and Angleton fields in Texas ($192.5 million), Paradox field in Utah ($30.5 million), Howard Ranch and Bull Canyon fields in the Rockies ($32.0 million), Utah Hingeline ($40.8 million) and our offshore California field ($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 ($21.5 million), certain DHS rigs ($21.6 million) and we wrote off DHS’s goodwill ($7.7 million).

During the year ended December 31, 2007, an impairment of $59.4 million was recorded primarily related to the Howard Ranch and Fuller fields in Wyoming ($38.4 million and $10.3 million, respectively), and the South Angleton field in Texas ($9.7 million), primarily due to lower Rocky Mountain natural gas prices and marginally economic deep zones on the Howard Ranch Prospect. During the year ended December 31, 2006, an impairment of $10.4 million was recorded on certain of the Company’s eastern Colorado properties primarily due to lower Rocky Mountain natural gas prices. In addition, an impairment of $1.0 million was recorded on certain Oklahoma properties.

For fiscal year 2010, we are continuing to develop and evaluate certain proved and unproved properties on which favorable or unfavorable results or commodity prices may cause us to revise in future quarters our estimates of those properties’ future cash flows. Such revisions of estimates could require us to record an impairment in the period of such revisions.

Commodity Derivative Instruments and Hedging Activities

All derivative instruments are recorded on the balance sheet at fair value which must be estimated using complex valuation models. Effective July 1, 2007, we elected to discontinue cash flow hedge accounting prospectively. Beginning July 1, 2007, we recognize mark-to-market gains and losses in current earnings instead of deferring those amounts in accumulated other comprehensive income.

As of December 31, 2009, we had a total of seven oil and gas derivative contracts outstanding. The fair value of our oil derivative instruments was a liability of $14.7 million and the fair value of our gas derivative instruments was a liability of $12.3 million at December 31, 2009. The liability is discounted based on our credit-worthiness and accordingly, the liability reflected is less than the actual cash expected to be paid upon settlement based on forward strip prices as of December 31, 2009. The pre-credit risk adjusted fair value of our net derivative liabilities as of December 31, 2009 was $29.5 million. A credit risk adjustment of $2.5 million to the fair value of the derivatives reduced the reported amount of the net derivative liabilities on our consolidated balance sheet to $27.0 million.

Asset Retirement Obligation

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

Deferred Tax Asset Valuation Allowance

We follow SFAS 109 to account for our deferred tax assets and liabilities. Under SFAS 109, deferred tax assets and liabilities are recognized for the estimated future tax effects attributable to temporary differences and carryforwards. Ultimately, realization of a deferred tax benefit depends on the existence of sufficient taxable income within the carryback/carryforward period to absorb future deductible temporary differences or a carryforward. In assessing the realizability of deferred tax assets, management must consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. Management considers all available evidence (both positive and negative) in determining whether a valuation allowance is required. Such evidence includes the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment, and judgment is required in considering the relative weight of negative and positive evidence. As a result of management’s current assessment, we maintain a significant valuation allowance against our deferred tax assets. We

will continue to monitor facts and circumstances in our reassessment of the likelihood that operating loss carryforwards and other deferred tax attributes will be utilized prior to their expiration. As a result, we may determine that the deferred tax asset valuation allowance should be increased or decreased. Such changes would impact net income through offsetting changes in income tax expense or benefit.

Recently Adopted Accounting Pronouncements

In December 2008, the SEC approved new rules designed to modernize oil and gas reserve reporting requirements. The most significant amendments to the requirements included the following:

	•		Commodity Prices – Economic producibility of reserves and discounted cash flows is now based on a 12-month average commodity price unless contractual arrangements designate the price to be used.
	•		Disclosure of Unproved Reserves – Probable and possible reserves may be disclosed separately on a voluntary basis.
	•		Proved Undeveloped Reserves Guidelines – Reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities will be recovered and they are scheduled to be drilled within the next five years.
	•		Reserves Estimation Using New Technologies – Reserves may be estimated through the use of reliable technology in addition to flow tests and production history.
	•		Reserves Personnel and Estimation Process – Additional disclosure is required regarding the qualifications of the chief technical person who oversees the reserves estimation process. We are also required to provide a general discussion of our internal controls used to assure the objectivity of the reserves estimate.
	•		Non-Traditional Resources – The definition of oil and gas producing activities has expanded and focuses on the marketable product rather than the method of extraction.

We adopted the rules effective December 31, 2009. In addition, in January 2010, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (Update) 2010-03, “Oil and Gas Reserve Estimation and Disclosures”, to provide consistency with the new SEC rules. The Update amends existing standards to align the reserves calculation and disclosure requirements under US GAAP with the requirements in the SEC rules. We adopted the new standards effective December 31, 2009. The new standards are applied prospectively as a change in estimate. See also Note 19, “Information Regarding Proved Oil and Gas Reserves (Unaudited)”, to our accompanying consolidated financial statements.

In March 2008, the FASB issued authoritative guidance related to the accounting for convertible debt instruments that may be settled in cash upon conversion (including partial cash settlement). The guidance requires the proceeds from the issuance of convertible debt instruments to be allocated between a liability component (debt issued at a discount) and an equity component. The resulting debt discount is amortized over the period the convertible debt is expected to be outstanding as additional non-cash interest expense. This guidance was adopted effective January 1, 2009. This guidance changes the accounting treatment for our 3³/4% Senior Convertible Notes issued April 25, 2007 and was applied retrospectively upon adoption. The fair value of the liability and equity components was determined based on our estimated borrowing rate at the date of issuance and, as a result, the liability component was approximately $92.7 million and the equity component was approximately $22.3 million. Based on these components at the issue date we recorded a reduction to the carrying value of the Notes of $22.3 million upon adoption of the guidance, with a corresponding increase in additional paid in capital. The accompanying consolidated financial statements include accretion of the resulting debt discount of approximately $1.1 million and $4.4 million for the three months and year ended December 31, 2009 and approximately $1.0 million and $4.2 million for the three months and year ended December 31, 2008. The remaining discount will be amortized through May 2012 when the holders of the Notes can first require us to purchase all or a portion of the Notes. Combined with the amortization of debt discount, the Notes have an effective interest rate of approximately 7.6% and 7.4% with total interest costs of $8.7 million and $8.5 million for the years ended December 31, 2009 and 2008, respectively.

In March 2008, the FASB issued new rules related to disclosures about derivative instruments and hedging activities which required enhanced disclosures for derivative and hedging activities. These rules were effective for us on January 1, 2009. We have included the new required disclosures in these financial statements.

In December 2007, the FASB issued new rules which established accounting and reporting standards for non-controlling interests (“minority interests”) in subsidiaries. These rules clarified that a non-controlling interest in a subsidiary should be accounted for as a component of equity separate from the parent’s equity. The rules were effective for us on January 1, 2009 and must be applied prospectively, except for the presentation and disclosure requirements, which have been applied retrospectively. The adoption of these rules had the effect of increasing total equity by the amount of the non-controlling interest and changing other presentations in the accompanying financial statements.

In April 2009, the FASB issued revised authoritative guidance requiring disclosures about fair value of financial instruments. The adoption of this guidance did not have a material impact on our consolidated financial statements, other than additional disclosures. The guidance provided additional clarification for estimating fair value when the volume and level of activity for the asset or liability have significantly decreased and requires that companies provide interim and annual disclosures of the inputs and valuation technique(s) used to measure fair value. This guidance was effective for interim and annual reporting periods ending after June 15, 2009 with such disclosures included herein as applicable.

In April 2009, the FASB issued revised authoritative guidance related to interim disclosures about fair value of financial instruments. The adoption of this guidance did not have an impact on our consolidated financial statements, other than requiring additional disclosures. The guidance required disclosures about fair value of financial instruments in financial statements for interim reporting periods of publicly traded companies as well as in annual financial statements and was effective for interim and annual reporting periods ending after June 15, 2009. Such disclosures have been included herein as applicable.

In May 2009, the FASB issued authoritative guidance which incorporated the principles and accounting guidance for recognizing and disclosing subsequent events that originated as auditing standards into the body of authoritative literature issued by the FASB, and prescribes disclosures regarding the date through which subsequent events have been evaluated. In particular, the guidance set forth the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements; the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements; and the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. The guidance was effective for us beginning with the Quarterly Report on Form 10-Q for the quarter ended June 30, 2009. The implementation of this guidance did not have a material impact on our financial statements. Subsequent events were evaluated through the date of issuance of these consolidated financial statements at the time this Annual Report on Form 10-K was filed with the Securities and Exchange Commission.

Recently Issued Accounting Pronouncements

Applicable recently issued accounting pronouncements have been adopted as of December 31, 2009. Please refer to “recently adopted accounting pronouncements” disclosure above for further information.

Item 7A.		Quantitative and Qualitative Disclosures About Market Risk

Market Rate and Price Risk

We actively manage our exposure to commodity price fluctuations by hedging meaningful portions of our expected production through the use of derivatives, which may from time to time include costless collars, swaps, or puts. The level of our hedging activity and the duration of the instruments employed depend upon our view of market conditions, available hedge prices and our operating strategy. We use hedges to limit the risk of fluctuating cash flows that fund our capital expenditure program. We also may use hedges in conjunction with acquisitions to achieve expected economic returns during the payout period.

The following table summarizes our open derivative contracts at December 31, 2009:

																						Net Fair Value
																						Asset (Liability) at
Commodity		Volume								Fixed Price				Term				Index Price				December 31, 2009
																						(In thousands)
Crude oil			1,000			Bbls / Day				$	52.25			Jan ’10 - Dec ’10				NYMEX – WTI					(10,338	)
Crude oil			500			Bbls / Day				$	57.70			Jan ’11 - Dec ’11				NYMEX – WTI					(4,374	)
Natural gas			6,000			MMBtu / Day				$	5.720			Jan ’10 - Dec ’10				NYMEX – HHUB					(135	)
Natural gas			15,000			MMBtu / Day				$	4.105			Jan ’10 - Dec ’10				CIG					(6,467	)
Natural gas			5,367			MMBtu / Day				$	3.973			Jan ’10 - Dec ’10				CIG					(2,558	)
Natural gas			12,000			MMBtu / Day				$	5.150			Jan ’11 - Dec ’11				CIG					(2,352	)
Natural gas			3,253			MMBtu / Day				$	5.040			Jan ’11 - Dec ’11				CIG					(748	)
																						$	(26,972	)