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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2008

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		The NASDAQ Stock Market, LLC

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 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 a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):


	Large accelerated filer x		Accelerated filer o

	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, 2008, the aggregate market value of voting stock held by non-affiliates of the registrant was approximately $1.6 billion, based on the closing price of the Common Stock on the NASDAQ National Market of $25.52 per share. As of February 27, 2009, 103,443,368 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 2009 Annual Meeting of Stockholders.

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 First Amendment to our Second Amended and Restated Credit Agreement, and to meet future debt service, capital expenditure and working capital requirements; acquisition and divestiture strategies; drilling wells; 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; expected results or benefits associated with recent acquisitions; 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; 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 First 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 the current financial crisis on our ability to raise capital;

	•		a contraction in the demand for natural gas in the U.S. as a result of deteriorating general economic conditions;

	•		the risk that lenders under our revolving credit facilities will default in funding borrowings as requested;

	•		the ability and willingness of counterparties to our commodity derivative contracts, if any, to perform their obligations;

	•		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;

	•		the timing, effects and success of our acquisitions, dispositions and exploration and development activities;

	•		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; and

	•		our ability to fully utilize income tax net operating loss and credit carry-forwards.

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 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 exploration and development 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.

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

On March 2, 2009, we entered into the First Amendment to our Second Amended and Restated Credit Agreement (the “Forbearance Agreement and Amendment to the Credit Facility”). Under the terms of the Forbearance Agreement and Amendment to the Credit Facility, the lenders under our Second Amended and Restated Credit Agreement (the “Credit Facility”) agreed to forebear from taking certain actions (including accelerating the amounts due under the Credit Facility) in respect of violations of Credit Facility covenants as of December 31, 2008. The Forbearance Agreement and Amendment to the Credit Facility also established a new Borrowing Base of $225 million, representing a decrease of $70 million from the previously existing Borrowing Base, increased the applicable interest rates payable, and requires that we raise substantial additional capital in the next 45 to 105 days (depending on our success) to reduce by not less than $68.8 million the amounts outstanding under the Credit Facility and pay other accounts payable. We are pursuing additional capital from a variety of potential sources, including sales of debt or equity securities, asset sales, joint ventures or other similar industry partnerships.

Overview and Strategy

Our focus is to increase stockholder value by pursuing our corporate strategy, as follows:

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

Although our capital expenditure budget has been reduced dramatically due to significant declines in commodity prices during the second half of 2008, we currently plan to spend $52 million on our drilling program during 2009. This plan is dependent upon our ability to first raise sufficient capital to comply with our obligations under the Forbearance Agreement and Amendment to the Credit Facility which is described in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and in Note 21 to the accompanying consolidated financial statements and to pay existing obligations. It is our intention to make further adjustments to this plan as necessary depending upon our liquidity, economic conditions and commodity prices.

In view of current market conditions 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, which will be jointly developed going forward; we also announced that we were seeking partners for the development of our Piceance Basin assets, and are continuing to pursue a transaction or transactions with the assistance of Merrill Lynch and JPMorgan. We are currently engaged in other joint venture focused discussions regarding development of several of our other asset areas.

Achieve consistent reserve growth through repeatable development

We have experienced significant reserve growth over the past four years 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 significant reserve and production increases as a result of our drilling program. In 2009, we are focused on the efficient deployment of available capital to maintain current reserves and production levels. We anticipate that the majority of our future reserve and production growth will come through the execution of our development drilling program. Our Piceance Basin development drilling inventory generally consists of locations in fields that demonstrate low variance in well performance, which leads 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 quantities and present and future values of our reserves. Subject to capital availability as noted above, we believe our capital deployment focused in the Rockies will allow us to maintain our 2008 production levels in 2009 until improved commodity prices support more aggressive drilling activity.

Maintain high percentage ownership and operational control over our asset base

As of December 31, 2008, we controlled approximately 893,000 net undeveloped acres, representing approximately 97% of our total net acreage position. We retain a high degree of operational control over our asset base, through a high average working interest or acting 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 continued reserve and production growth through our drilling operations when commodity pricing supports greater growth focused 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 Drilling Company (“DHS”), as well as a contractual right of priority access to 19 drilling rigs owned by DHS.

Acquire and maintain acreage positions in high potential resource plays

Although we anticipate that our exploratory drilling efforts during 2009 will be much more limited than in the past, we believe that to the extent permitted by our cash flow 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 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 shale in Texas, Lighthouse Point in Louisiana 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. We are currently drilling our first operated well in the Columbia River Basin and expect to be at total depth in the coming months. Currently, our $52 million 2009 capital budget has limited allocation to our other exploratory projects, including a small amount in the Haynesville shale. However, with increased commodity prices or the addition of joint venture partners to fund a portion of the development cost, our plans for 2009 could change with respect to these potentially rewarding exploratory plays.

Pursue a disciplined acquisition strategy in our core areas of operation

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, we will continue to look to divest assets located in fully developed or non-core areas.

Maintain an active hedging program

Although we liquidated a significant portion of our 2009 hedges for a profit in order to reduce counterparty credit risk, from time to time we manage our exposure to commodity price fluctuations by hedging meaningful portions of our expected production through the use of derivatives, typically costless collars. 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. As of March 2, 2009, we are unhedged with respect to our 2009 production. However, in accordance with the terms of the Forbearance Agreement and Amendment to the Credit Facility, we expect to put derivative contracts in place to establish a commodity floor price for our anticipated production of a minimum of 40% for the last two quarters of 2009, 70% for the calendar year 2010 and 50% for the calendar year 2011.

Experienced management and operational team with advanced exploration and development technology

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, 2008, 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 Operations

The following table presents information regarding our primary oil and natural gas areas of operation as of December 31, 2008:


	Proved		%						2008
	Reserves		Natural			% Proved			Production
Areas of Operations	(Bcfe) (1)		Gas			Developed			(MMcfe/d) (2)

Rocky Mountain Region		836.5		95.3	%		17.9	%		46.1
Gulf Coast Region		45.6		64.0	%		63.1	%		19.0
Other		2.3		54.7	%		100.0	%		3.1

Total		884.4		93.6	%		20.5	%		68.2


(1)		Bcfe means billion cubic feet of gas equivalent

(2)		MMcfe/d means million cubic feet of gas equivalent per day

We intend to focus our 2009 capital spending on development of our core area of operation in the Rocky Mountains, the Piceance Basin, and to a lesser extent on our exploratory efforts in the Columbia River Basin. For the year ending December 31, 2009, we currently plan to spend $52 million on our drilling program, but may adjust this plan depending on our liquidity, economic conditions and commodity prices. The Forbearance Agreement and Amendment to the Credit Facility limits our ability to make capital expenditures beyond this level until we have successfully reduced the amounts outstanding under our credit facility as well as other payables.

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 17 states, interests in a producing Federal unit offshore California and undeveloped offshore Federal leases near Santa Barbara, California. We intend to continue our emphasis on the drilling of exploratory and development wells, primarily in the Piceance Basin of Colorado and the Columbia River Basin in Washington.

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. We have never been a debtor in any bankruptcy, receivership, reorganization or similar proceeding.

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, 2008, DHS owned 19 drilling rigs with depth ratings of approximately 10,000 to 25,000 feet, only three of which 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, 2008 and 2007:


	Years Ended December 31,
	2008		2007
Average number of rigs owned during period		16.7		16.7
Total rig days available¹		5,032		5,020
Average drilling revenue per day	$	18,188	$	16,919

^¹ Total rig days available includes the number of days each rig was either under contract or available for contract.

In view of the current abundance of drilling rig capacity, we would expect drilling day rates to be substantially lower in 2009, assuming industry conditions remain in their current state.

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. 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 are 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. Recent decreases in the price of natural gas and oil have had a material adverse impact on exploration, development, and production activities by all of DHS’s customers, including us, which will materially affect its 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. Recent decreases in demand for oil and gas have resulted in equipment and supplies used in our business being available from multiple sources.

Major Customers

During the year ended December 31, 2008, we had two companies that individually accounted for 31% and 25% 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 2008, DHS had one major customer other than Delta. Our projected reduction in drilling activities and the loss of other customers 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.

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 2008, the Colorado Oil and Gas Conservation Commission (“COGCC”) promulgated 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 2009. 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 2009, 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 follow the accounting

required by the Statement of Financial Accounting Standard (“SFAS”) No. 143 “Accounting for Asset Retirement Obligations” (“SFAS 143”). SFAS 143 requires entities to record the fair value of liabilities for retirement obligations of acquired assets. We had a discounted asset retirement obligation of approximately $8.7 million at December 31, 2008. 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, 2008 we had approximately 160 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.

The terms of our Forbearance Agreement and Amendment to the Credit Facility require us to raise significant capital and take other actions to repay indebtedness and a portion of our existing payables in the near future.

The Forbearance Agreement and Amendment to the Credit Facility includes provisions that will require us to raise at least $140.0 million through capital raising transactions, including potentially asset sales, joint ventures or other similar industry partnerships in the next 45 to 105 days in order to reduce amounts outstanding under our Credit Facility and to pay amounts currently due to suppliers and other third party contractors. In connection with the redetermination of our Borrowing Base, and our current accounts payable situation, our auditors have issued an audit report on our financial statements which contains a “going concern” explanatory paragraph which may be perceived adversely in our effort to attract capital. There can be no assurance that we will successfully raise the amount of capital required to meet our obligations under the Forbearance Agreement and Amendment to the Credit Facility. If we fail to do so, the lenders under our Credit Facility will be entitled to accelerate the amounts due thereunder and take other actions to collect such amounts. Any such acceleration would result in a cross-acceleration of amounts due under the Indentures for our 7% Senior Notes and our 3³/4% Convertible Notes.

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

Our efforts to improve our liquidity position will be very challenging given the current economic climate. Current economic fundamentals portray a dismal outlook for the oil and natural gas exploration and development business for at least a significant portion of 2009 due to extremely low and volatile oil and natural gas prices coupled with a global recession that is projected to be the longest and most severe in the post war period. 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. Moreover, the full effect of many of the actions that we have taken to improve our liquidity will not be realized until later in 2009, even if they are successfully implemented. Our ability to maintain adequate liquidity through 2009 will depend significantly on our ability to raise capital, commodity prices increases, adequate pipeline capacity, completion of some of our potential asset sales and joint venture efforts, curtailment of operating expenses and capital spending, generation of additional working capital and the availability of funding. We are committed to exploring all of these options because there is no assurance that industry or capital markets conditions will improve in the near term. Even if we implement the planned capital raising transactions and the operating actions that are substantially within our control, our estimated liquidity during the first half of 2009 will be at or near the minimum amount necessary to operate our business and to satisfy the requirements of the Forbearance Agreement and Amendment to the Credit Facility.

Natural gas and oil prices are volatile. Declining 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 banks 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 has been the case in the past three months.

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 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 necessarily move in tandem. Because approximately 94% of our reserves at December 31, 2008 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.

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.

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 and to third parties generally.

As of December 31, 2008, our total outstanding long term liabilities were $841.2 million, including $294.5 million of outstanding borrowings drawn under our Credit Facility which are classified as current in the accompanying consolidated balance sheet. Our long term indebtedness represented 47% of our total book capitalization at December 31, 2008. As of December 31, 2008, we had no additional availability under our credit facility. Our borrowing base will be reduced upon the successful completion of our capital raising efforts to $225 million, which will require repayments of at least $68.8 million in accordance with the terms of the Forbearance Agreement and Amendment to the Credit Facility entered into subsequent to year end. Our 7% senior unsecured notes indenture currently limits 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. As discussed above, the Forbearance Agreement and Amendment to the Credit Facility requires us to repay significant amounts outstanding under our Credit Facility in the near term, and failure to do so could result in acceleration of amounts due thereunder.

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. 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. We are currently engaged in seeking capital from a number of sources, including sales of debt or equity securities, asset sales, and potential joint ventures or similar industry partnerships directed, in part, to raising

capital needed to repay indebtedness that is due as a result of the borrowing base redetermination as contemplated by the Forbearance Agreement and Amendment to the Credit Facility.

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

The continued credit crisis and related turmoil in the global financial system 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. Although we believe we have developed an operating and capital budget for 2009 and 2010 that, assuming we are successful in meeting our obligations under the Forbearance Agreement and Amendment to the Credit Facility, will 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 this crisis and may be restricted in the future when we would like, or need, to raise capital. The financial crisis 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 or seek bankruptcy protection. 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.

We have recently engaged in, and marketed certain of our assets in, joint venture transactions that monetize, or would monetize, a portion of our investment in certain plays and provide drilling cost carries for our retained interest. If our joint venture partners in these transactions and proposed transactions, if completed, were not able to meet their obligations under these arrangements, we may be required to fund these expenditures from other sources or reduce our drilling activities.

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, 2008, 2007 and 2006 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 of the date of the estimate, while actual future prices and costs may be materially higher or lower. 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.

With the further decline in commodity pricing since year end, the proved undeveloped reserves attributable to our Piceance Basin properties are uneconomic using the spot natural gas price as of February 28, 2009. The Piceance Basin properties contain nearly all of our proved undeveloped reserves. Further development of these properties depends on higher commodity prices in the future, reductions in future drilling costs, or a combination of both.

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, we recorded an

impairment provision to our proved and unproved properties for the year ended December 31, 2008 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, impairments of $59.4 million were 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. For 2009, we are continuing to develop and evaluate certain properties on which favorable or unfavorable results or commodity prices may cause us to revise in future years 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.

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. During 2007, we recorded dry hole costs for three wells located in Texas, two wells in Wyoming, one well in Colorado and one well in Utah totaling approximately $28.1 million.

At December 31, 2008, we had $13.8 million classified as exploratory work in process related primarily to our Columbia River Basin well currently being drilled. During 2009, these costs will be capitalized as successful wells if proved reserves are found or expensed as dry holes based on final drilling results.

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

Our revolving bank Credit Facility limits our borrowings to the lesser of the borrowing base and the total commitments. The borrowing base is determined periodically at the discretion of the banks and is based in part on natural gas and oil prices. Additionally, the indenture governing our 7% senior notes contains covenants limiting 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 Forbearance Agreement and Amendment to the Credit Facility, our borrowing base under the Credit Facility was reduced to $225.0 million, and we are required to pay down the $68.8 million difference between the amount borrowed under the prior $295.0 million borrowing base from the proceeds of our anticipated capital raising efforts, asset sales and other cash sources.

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, 2008 is estimated to be approximately $1.3 billion. In the current financing environment, we expect it to be difficult to obtain that capital 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 only four employees that serve in senior management roles. In particular, Roger A. Parker and John R. Wallace 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 may not be permitted to develop some of our offshore California properties or, if we are permitted, the substantial cost to develop these properties could result in a reduction of our interest in these properties or cause us to incur penalties.

Certain of our offshore California undeveloped properties, in which we have ownership interests ranging from 2.49% to 100.00%, are attributable to our interests in four of our five federal units (plus one additional lease) located offshore of California near Santa Barbara. These properties had a cost basis of approximately $17.0 million at December 31, 2008. The development of these properties is subject to extensive regulation and is currently the subject of litigation. Further actions to develop these properties have been delayed pending the outcome of a lawsuit that was filed in the United States Court of Federal Claims in Washington, D.C. by us, our 92%-owned subsidiary, Amber Resources Company of Colorado, and ten other property owners 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. None of these leases is currently impaired, but in the event that they are found not to be valid for some reason, in the future it would appear that they would become impaired. For example, if there is a future adverse ruling by the California Coastal Commission under the Coastal Zone Management Act and we decide not to appeal such ruling to the Secretary of Commerce, or the Secretary of Commerce either refuses to hear our appeal of any such ruling or ultimately makes an adverse determination, it is likely that some or all of these leases would become impaired and written off at that time. It is also possible that other events could occur that would cause the leases to become impaired, and we will continuously evaluate those factors as they occur.

In addition, the cost to develop these properties will be substantial. The cost to develop all of the offshore California properties in which we own an interest, including delineation wells, environmental mitigation, development wells, fixed platforms, fixed platform facilities, pipelines and power cables, onshore facilities and platform removal over the life of the properties (assumed to be 38 years), is estimated to be in excess of $3.0 billion. Our share of such costs, based on our current ownership interest, is estimated to be over $200 million. Operating expenses for the same properties over the same period of time, including platform operating costs, well maintenance and repair costs, oil, gas and water treating costs, lifting costs and pipeline transportation costs, are estimated to be approximately $3.5 billion, with our share, based on our current ownership interest, estimated to be approximately $300 million. There will be additional costs of a currently undetermined amount to develop the Rocky Point Unit. Each working interest owner will be required to pay its proportionate share of these costs based upon the amount of the interest that it owns. If we are unable to fund our share of these costs or otherwise cover them through farm-outs or other arrangements,

then we could either forfeit our interest in certain wells or properties or suffer other penalties in the form of delayed or reduced revenues under our various unit operating agreements, which could impact the ultimate realization of this investment. The estimates discussed above may differ significantly from actual results.

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 not be able to meet its debt covenants under its credit facility.

DHS currently has only three of its nineteen rigs currently in operation and expects to incur liquidity pressures during 2009 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., has filed for bankruptcy protection. DHS is in the process of attempting to procure 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, 2008, DHS owed $93.8 million under its credit facility. In the event that DHS is not successful in obtaining alternative financing or making satisfactory arrangements with the Lehman Commercial Paper, Inc. bankruptcy trustee, it is likely that DHS will be in default of its debt covenants under its credit facility in 2009 unless market conditions improve significantly. In such event, all of the amounts due under the credit facility would become immediately due and payable. 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 $33.7 million as of December 31, 2008.

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 on derivative instruments recognized in our statements of operations were $21.7 million, $10.0 million, and $7.0 million for the years ended December 31, 2008, 2007 and 2006, respectively. At December 31, 2008, we had no outstanding hedging arrangements. However, in accordance with the terms of our Forbearance Agreement and Amendment to the Credit Facility, we expect to put derivative contracts in place to establish a floor price for our anticipated production of a minimum 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.

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.

Risks Related To Our Stock.

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

As of February 27, 2009, our largest stockholder, Tracinda Corporation, beneficially owned 40,464,000 shares of our common stock, or approximately 39% 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 five members (33%) of our Board of Directors (which number will increase after February 20, 2009 to equal its percentage ownership of Delta), preemptive rights in connection with future equity issuances by us, and consent rights over certain types of actions. Tracinda has informed us that they intend to nominate two additional directors at our next meeting of stockholders. 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. 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 73% 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 or outstanding warrants to purchase common stock are exercised or the price vesting triggers under the performance shares granted to our executive officers are satisfied, holders of our common stock will experience dilution. As of December 31, 2008, we had outstanding options to purchase 1,528,250 shares of common stock at a weighted average exercise price of $8.62. 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, 2008, our directors and executive officers and their respective affiliates collectively and beneficially owned approximately 4.0% 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.

Item 2. Properties.

Properties.

Our primary areas of activity are in the Rocky Mountain and Gulf Coast Regions with additional strategic exploration projects in the Columbia River Basin in southeastern Washington and the Hingeline area of Central Utah. Total oil and gas leasehold in these areas comprises approximately 911,000 acres.

Rocky Mountain Region

The Rocky Mountain Region comprises approximately 95% of our estimated proved reserves as of December 31, 2008. 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 four 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. During 2008 production increased from approximately 25 Mmcf/d at the beginning of the year to approximately 48 Mmcf/d at the end of 2008. The Collbran Valley natural gas pipeline provides us with approximately 60 Mmcf/d of pipeline takeaway capacity. A new pipeline is currently under construction that will provide us with takeaway capacity up to 60 Mmcf/d. We ended 2008 with 155 wells producing. Despite our large inventory of over 2,000 drilling locations and efficient reserve growth, we have decreased our drilling program from four rigs to one rig at year end 2008, primarily due to the decrease of natural gas prices and liquidity concerns. Since 2005 we have experienced significant reductions in drill time, and drilling and completion costs, which have allowed us to grow reserves even in a depressed commodity price environment. We expect to continue completion activities in 2009 on wells awaiting completion, and to resume its more aggressive drilling program once commodity prices recover. Our drilling and completion capital budget is $35 – $45 million for the year ending December 31, 2009.

Garden Gulch. We have an interest in approximately 6,000 gross (2,000 net) acres with a 31.1% non-operated working interest. The operator of the project has temporarily ceased drilling activity, but expects to complete an inventory of approximately 20 wells that were drilled, but not completed in 2008. Our capital budget for the year ending December 31, 2009 is approximately $4 - $6 million.

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 targeted objectives in these prospects are reliant upon various geologic models, which include multiple stacked clastic intervals imbedded within an evaporate salt in the Paradox formation, and unconventional shales.

Greentown. We have drilled a total of eight wells in the Greentown project area. The first two wells flow tested at rates between 2.0 Mmcf/d with 40 Bo/d and 4.0 Mmcf/d with 800 Bo/d, primarily from the 21^st clastic interval, or “O” zone. These first two exploration wells were located approximately along the axis of the anticline, about seven miles apart. Even though these wells are widely spaced, they exhibited very consistent electric log characteristics and appear analogous and mapable over a large area. Although these first two exploration wells were lost due to casing failure, the flow rates and log characteristics drove our initial assessment was that the geology was

consistent and predictable over much of our leasehold. We revised our casing design in the subsequent wells, and continued to experience multiple hydrocarbon-bearing zones while drilling. Each of the subsequent wells tested gas and oil, two of which tested at significant rates of up to 10 Mmcf/d. Most of the gas and oil tested in these wells came from the “O” interval, but some also produced from the 23^rd clastic interval, also known as the Cane Creek. Despite the indications of economically productive reserves during drilling and initial completion activity, the wells failed to produce at the flow-tested rates after casing and completion activities. We assessed that the limited productivity was primarily due to a lack of naturally occurring fractures in the clastics. In order to encounter more naturally occurring fractures we drilled multiple laterals in three of the wells, within the “O” and Cane Creek intervals. In one of the first laterals in the Greentown Federal 26-43D well, in the “O” interval, we encountered significant hydrocarbon accumulation with high pressures. While trying to complete the lateral we encountered significant mechanical problems that made the potentially productive section inaccessible. The other laterals encountered limited hydrocarbon accumulations. Based upon the results from the laterals and limited production on the western portion of the acreage, we have determined that despite good correlation of the clastic intervals along the crest of the Greentown anticline, there exists discontinuity in the clastic intervals, which may limit the hydrocarbon drainage area on the western portion.

We have a 70% working interest in 43,700 gross acres, 30,400 net acres. We believe the eastern portion of its acreage, where the wells with letter drilling shows were located, remains prospective. We have not budgeted any significant activity in Greentown for the year ending December 31, 2009.

Salt Valley. The Salt Valley project area has had one exploratory well drilled. Additional drilling plans are not expected in 2009. We have a 70% working interest in 7,100 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 46,500 gross acres, 32,800 net acres, all of which were undeveloped at December 31, 2008.

Wind River Basin. The Wind River Basin is characterized by a depositional environment that resulted in thick packages of tight gas sands producing at depths that range from 7,000 to 20,000 feet. We have focused our efforts on the shallower Lower Fort Union Formation which produces in numerous fields throughout the Wind River Basin.

Howard Ranch. During 2008 we performed a reevaluation of our acreage position in the Howard Ranch project area. We have determined that much of our leasehold is likely prospective in the Waltman shale formation, which is an unconventional play. At year end we owned an interest in 47,100 net acres with an average working interest of 50%. We have not budgeted any capital in the Wind River Basin for 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. We have identified numerous seismically defined structures, similar in size to the Cowboy field. We have an interest in 21,800 net acres with a 100% working interest. There is no drilling capital budgeted for the D-J Basin for 2009.

Gulf Coast Region

The Gulf Coast Region comprises approximately 5% of our estimated proved reserves as of December 31, 2008. 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 21,000 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 11.6 Bcfe. We do not have any drilling capital planned for the Newton Field in 2009.

Midway Loop Field. The Midway Loop Field is located in Polk and Tyler Counties, Texas. We have an interest in

21,400 gross acres, with an average 28% 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 displacement in each lateral. As of December 31, 2008 our proved reserves totaled 16.2 Bcfe. There is no drilling capital budget for the field in 2009.

Caballos Creek / Opossum Hollow / 74 Ranch Areas. The leashold is located in Atascosa and McMullen Counties, Texas. We have an interest in approximately 20,000 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.

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 130,000 net acres. We have drilled three wells, the Joseph #1, the Federal 23-44, and the Beaver Federal 21-14. The Federal 23-44 provided us with positive indications of hydrocarbon-bearing zones, and critical geologic information, however all three wells were plugged and abandoned as dry holes.

We and our partners control approximately 200,000 gross acres (130,000 net acres) within this play and numerous structural features have been identified on our leasehold. We have a 110-mile seismic program covering previously generated prospects, which in our interpretation appear to confirm and enhance original expectations. We have not budgeted any drilling capital for this area in 2009. The Central Utah Hingeline project is an exploratory area for us and does not account for any of our proved reserves at December 31, 2008.

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. We are currently drilling the Gray 31-23 well in Klickitat County, Washington. Completion activities are expected to begin after reaching total depth. Drilling results have been encouraging and we have begun permitting a well near the Gray well. We have an interest in approximately 424,000 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, 2008. Our budget for the Columbia River Basin is $7 – $10 million in 2009.

Haynesville Shale. We acquired rights to 16,000 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, which are considered to be highly attractive regions in the play. 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.

Offshore California producing properties

Point Arguello Unit. We own the equivalent of a 6.07% 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). No capital expenditures are in our 2009 fiscal budget.

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 have direct and indirect ownership interests ranging from 2.49% to 100% in five unproved undeveloped offshore California oil and gas properties. These property interests are located in proximity to existing producing federal offshore units near Santa Barbara, California and represent the right to explore for, develop and produce oil and gas from offshore federal lease units. Preliminary exploration efforts on these properties have occurred and the existence of substantial quantities of hydrocarbons has been indicated. The recovery of our investment in these properties will require extensive exploration and development activities (and costs) that cannot proceed without certain regulatory approvals that have been delayed and is subject to other substantial risks and uncertainties.

We and our 92% owned subsidiary, Amber, are 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. On November 15, 2005 and October 31, 2006, the Court granted summary judgment as to liability and partial summary judgment as to damages with respect to thirty six of the forty total federal leases that are the subject of the litigation. Under a restitution theory of damages, the Court ruled that the government must give back to the current lessees the more than $1.1 billion in lease bonuses it had received at the time of sale. On January 19, 2006, the government filed a motion for reconsideration of the Court’s ruling as it relates to a single lease owned entirely by us (“Lease 452”). In its motion for reconsideration, the government asserted that we should not be able to recover lease bonus payments for Lease 452 because, allegedly, a significant portion of the hydrocarbons had been drained by wells that were drilled on an immediately adjacent lease. The amount of lease bonus payments attributable to Lease 452 is approximately $92.0 million. A trial on the motion for reconsideration was completed in January 2008 and on February 25, 2009 the Court entered a judgment in our favor in the amount of $91,431,300. This judgment is subject to appeal by the government.

On January 12, 2007, the Court entered an order of final judgment awarding the lessees restitution of the original lease bonuses paid for thirty five of the forty lawsuit leases. Under this order we are entitled to receive a gross amount of approximately $58.5 million, and Amber is entitled to receive a gross amount of approximately $1.5 million as reimbursement for the lease bonuses paid for all lawsuit leases other than Lease 452. The order of final judgment was affirmed in all respects by the United States Court of Appeals for the Federal Circuit on August 25, 2008, and the government’s petition seeking a rehearing of that decision was denied on December 5, 2008; however, on December 24, 2008, the Federal Circuit entered an order imposing a stay of the issuance of its mandate for a period of 90 days pending consideration of and the possible filing by the government of a petition for writ of certiorari with the United States Supreme Court. On February 23, 2009, the Supreme Court granted the government’s application for a thirty day extension, to and including April 4, 2009, to file a petition for a writ of certiorari. The government asserts in its application that it has not yet determined whether it will ultimately file such a petition in this case.

No payments will be made until all appeals have either been waived or exhausted. In the event that we ultimately receive any proceeds as the result of this litigation, we will be obligated to use a portion to pay the litigation expenses and to fulfill certain contractual commitments to third parties that grant them an overriding royalty on the litigation proceeds in an aggregate amount of approximately 8% of the proceeds.

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 2.3 Bcfe in proved reserves as of December 31, 2008.

DHS Drilling Company Rigs

The Company owns 49.8% of DHS, which as of December 31, 2008 owned 19 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	CO		2007		700		11,000
Rig No. 5	CO		2005		700		12,000
Rig No. 6	CO		2005		700		12,000
Rig No. 7	WA		2005		1,500		20,000
Rig No. 8	WY		2005		800		12,500
Rig No. 9	TX		2006		1,000		15,000
Rig No. 10	WY		2006		1,000		15,000
Rig No. 11	WY		2006		750		11,000
Rig No. 12	WY		2006		1,000		15,000
Rig No. 14	NV		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	CO		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 74,000 square feet of office space. Our current lease payments are approximately $133,000 per month and our lease expires in December 2014.

Production

During the years ended December 31, 2008, 2007 and 2006, 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, we recorded an impairment provision to our proved and unproved properties for the year ended December 31, 2008 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).

During the year ended December 31, 2007, we recorded an impairment provision of approximately $59.4 million to developed properties primarily related to the Howard Ranch and Fuller fields in Wyoming ($38.4 million and $10.3

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, 2008 December 31, 2007, and December 31, 2006.


	Years Ended December 31,
	2008		2007		2006
Production volume –
Total production (MMcfe)		24,908		17,763		16,147

Production from continuing operations:
Oil (MBbls)		993		1,003		1,073
Natural Gas (MMcf)		18,948		10,866		6,076
Total (MMcfe)		24,908		16,882		12,511
Net average daily production- continuing operations:
Oil (Bbl)		2,721		2,748		2,940
Natural Gas (Mcf)		51,912		29,770		16,647
Average sales price:
Oil (per barrel)	$	92.12	$	67.39	$	61.74
Natural Gas (per Mcf)	$	6.87	$	5.17	$	5.98
Hedge gain (loss) (per Mcfe)	$	.74	$	.82	$	(.38	)
Lease operating costs - (per Mcfe)	$	1.35	$	1.24	$	1.42

Productive Wells and Acreage

The table below shows, as of December 31, 2008, 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⁾

Alabama		-		-		15		.1		440		130
California:
Offshore		34		2.1		-		-		2,420		270
Onshore		2		.1		12		1.1		2,440		330
Colorado		356		10.4		277		186.4		3,080		2,370
Kansas		5		2.0		-		-		-		-
Louisiana		48		2.3		5		.9		1,400		550
Michigan		1		-		-		-		40		-
Mississippi		2		-		1		.4		630		60
Nebraska		3		3		-		-		120		120
New Mexico		2		-		3		.1		240		10
North Dakota		8		1.0		-		-		800		150
Oklahoma		205		2.0		9		.5		2,950		690
Texas ⁽⁴⁾		266		56.6		58		16.3		20,780		11,110
Utah		-		-		-		-		80		60
Wyoming		14		12.3		25		20.1		2,130		1,730

		946		91.8		405		225.9		37,550		17,580


⁽¹⁾		All of the wells classified as “oil” wells also produce various amounts of natural gas.

⁽²⁾		A “gross well” or “gross acre” is a well or acre in which a working interest is held. The number of gross wells or acres is the total number of wells or acres in which a working interest is owned.

⁽³⁾		A “net well” or “net acre” is deemed to exist when the sum of fractional ownership interests in gross wells or acres equals one. The number of net wells or net acres is the sum of the fractional working interests owned in gross wells or gross acres expressed as whole numbers and fractions thereof.

⁽⁴⁾		This does not include varying very small interests in approximately 666 gross wells (5.2 net) located primarily in Texas which are owned by our subsidiary, Piper Petroleum Company.

Present Drilling Activity

The following represents our planned exploration and development activities for the year ending December 31, 2009:


Areas of Operations	Drilling Budget
	(In millions)
Rocky Mountain Region		$	43.0
Gulf Coast Region			1.0
Other			8.0

Total		$	52.0

Item 3. Legal Proceedings

Offshore Litigation

Shareholder Derivative Suit

Within the past few years, there has been significant focus on corporate governance and accounting practices in the grant of equity based awards to executives and employees of publicly traded companies, including the use of market hindsight to select award dates to favor award recipients. After being identified in a third-party report as statistically being at risk for possibly backdating option grants, in May 2006 our Board of Directors created a special committee comprised of outside directors. The special committee, which was advised by independent legal counsel and advisors,

undertook a comprehensive review of our historical stock option practices and related accounting treatment. In June 2006 we received a subpoena from the U.S. Attorney for the Southern District of New York and an inquiry from the staff of the SEC related to our stock option grants and related practices. The special committee of our Board of Directors reported to the Board that, while its review revealed deficiencies in the documentation of our option grants in prior years, there was no evidence of option backdating or other misconduct by our executives or directors in the timing or selection of our option grant dates, or that would cause us to conclude that our prior accounting for stock option grants was incorrect in any material respect. We provided the results of the internal investigation to the U.S. Attorney and to the SEC in August of 2006, and were subsequently informed by both agencies that the matter had been closed.

During September and October of 2006, three separate shareholder derivative actions were filed on our behalf in U.S. District Court for the District of Colorado relating to the options backdating issue, all of which were consolidated into a single action. The consolidated complaint alleged that certain of our executive officers and directors engaged in various types of misconduct in connection with certain stock option grants. Specifically, the plaintiffs alleged that the defendant directors, in their capacity as members of our Board of Directors and our Audit or Compensation Committee, at the behest of the defendants who are or were officers and to benefit themselves, backdated our stock option grants to make it appear as though they were granted on a prior date when our stock price was lower. They alleged that these backdated options unduly benefited the defendants who are or were officers and/or directors, resulted in our issuing materially inaccurate and misleading financial statements and caused us to incur substantial damages. The action also sought to have the current and former officers and directors who are defendants disgorge to us certain options they received, including the proceeds of options exercised, as well as certain equitable relief and attorneys’ fees and costs. On September 26, 2007, the Court entered an Order dismissing the action for failing to plead sufficient facts to support the claims that were made in the complaint, and stayed the dismissal for ten days to allow the Plaintiffs to file a motion for leave to file an amended complaint. Extensions were granted and the Plaintiffs filed such a motion on October 29, 2007. On September 29, 2008, the Court entered an Order granting Plaintiff’s motion for leave to amend. On October 14, 2008, the defendants (including us as a nominal defendant) filed a joint motion to dismiss the Second Amended Complaint. No ruling has yet been made on the joint motion.

Castle/Longs Trust Litigation

As a result of the acquisition of Castle Energy in April 2006, the Company’s wholly-owned subsidiary, DPCA LLC, as successor to Castle, became party to Castle’s ongoing litigation with the Longs Trust in District Court in Rusk County, Texas. The Longs Trust litigation, which was originally the subject of a jury trial in November 2000, has been separated into two pending suits, one in which the Longs Trust is seeking relief on contract claims regarding oil and gas sales and gas balancing under joint operating agreements with various Castle entities, and the other in which Castle’s claims for unpaid joint interest billings and attorneys’ fees have been granted by the trial court and upheld on appeal. The Company intends to vigorously defend the Longs Trust breach of contract claims. The Company has not accrued any recoveries associated with the judgment against the Longs Trust, but will do so when and if they are ultimately collected.

Our management does not believe that these proceedings, individually or in the aggregate, will have a material adverse effect on our financial position, results of operations or cash flows.

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

None.

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
Roger A. Parker	47	Chairman, Chief Executive Officer and a Director	May 1987 to Present

John R. Wallace	49	President, Chief Operating Officer and a Director	October 2003 to Present

Kevin K. Nanke	44	Treasurer and Chief Financial Officer	December 1999 to Present

Stanley F. Freedman	60	Executive Vice President, General Counsel and Secretary	January 2006 to Present

Hank Brown	69	Director	June 2007 to Present

Kevin R. Collins	52	Director	March 2005 to Present

Jerrie F. Eckelberger	64	Director	September 1996 to Present

Aleron H. Larson, Jr.	63	Director	May 1987 to Present

Russell S. Lewis	54	Director	June 2002 to Present

James J. Murren	47	Director	February 2008 to Present

Jordan R. Smith	74	Director	October 2004 to Present

Daniel J. Taylor	52	Director	February 2008 to Present

James B. Wallace	79	Director	November 2001 to Present

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

Roger A. Parker has been a Director since May 1987 and Chief Executive Officer since April 2002. He served as our President from May 1987 until February 2006 when he resigned to accommodate the appointment of John R. Wallace to that position. He was named Chairman of the Board on July 1, 2005. Since April 1, 2005, he has also served as Executive Vice President and Director of DHS. Mr. Parker also serves as President, Chief Executive Officer and Director of Amber Resources. He received a Bachelor of Science degree in Mineral Land Management from the University of Colorado in 1983. He is a board member of the Independent Petroleum Association of the Mountain States (IPAMS). He also serves on other boards, including Community Banks of Colorado.

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. Mr. Wallace is the son of James B. Wallace, a Director of the Company.

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 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 also currently serves as an adjunct professor at the University of Colorado law school. 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 President, Chief Executive Officer and a Director of Evergreen Energy Inc. Prior to his current position, Mr. Collins 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. Mr. Collins also serves as a director of Quest Midstream Partners, L.P. 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.

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 2002, including EVP and 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 managed 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 is also currently the Managing Member of Lewis Capital, LLC, located in Harrisburg, Pennsylvania which makes private investments in, and provides general business and M&A consulting services to, growth oriented companies. Mr. Lewis also served on the Board of Directors of Castle Energy Corporation prior to its merger with the Company in April 2006 and Advanced Aerations Systems, a privately held firm engaged in subsurface soil treatment. 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.

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 2007 and has served as a Director of MGM Mirage since March 2007. Mr. Taylor previously was the President of Metro-Goldwyn-Mayer Inc. (“MGM Studios”) from April 2005 to January 2006 and Senior Executive Vice President and Chief Financial Officer of MGM Studios from June 1998 to April 2005. Mr. Taylor received a Bachelor of Science degree in Business Administration with an emphasis in Accounting from Central Michigan University in 1978.

James B. Wallace has been involved in the oil and gas business for over 40 years and has been a partner of Brownlie, Wallace, Armstrong and Bander Exploration in Denver, Colorado since 1992. From 1980 to 1992 he was Chairman of the Board and Chief Executive Officer of BWAB Incorporated. Mr. Wallace formerly served as a member of the Board of Directors of Ellora Energy, Inc., a public oil and gas exploration company listed on the NASDAQ. He received a Bachelor of Science degree in Business Administration from the University of Southern California in 1951. James B. Wallace is the father of John R. Wallace, the President, Chief Operating Officer and a Director of Delta.

At the present time Messrs. Collins, Eckelberger, Lewis, Smith, and Taylor serve as the Audit Committee; Messrs. Eckelberger, Collins, Lewis, Murren, Smith and serve as the Compensation Committee; and Messrs. Collins, Eckelberger, Lewis, Smith, and Taylor serve as 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. Murren and Taylor to our Board of Directors.

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			Years Ended
	Years Ended December 31,									December 31,				June 30,
	2008			2007			2006			2005			2005			2004

	(In thousands, except per share amounts)

Total Revenues	$	271,178		$	194,941		$	157,431		$	48,715		$	56,612		$	9,799
Income (loss) from Continuing Operations	$	(452,714	)	$	(145,111	)	$	(14,628	)	$	(27,893	)	$	(10,353	)	$	(12,081	)
Net Income (Loss)	$	(451,996	)	$	(147,187	)	$	2,916		$	219		$	15,050		$	5,056
Income/(Loss)
Per Common Share
Basic	$	(4.73	)	$	(2.40	)	$	.06		$	–		$	.37		$	.19
Diluted	$	(4.73	)	$	(2.40	)	$	.05		$	–		$	.36		$	.17
Total Assets	$	1,895,414		$	1,110,644		$	932,614		$	694,203		$	512,983		$	272,704
Total Long-Term Liabilities	$	848,800		$	426,298		$	374,121		$	250,671		$	222,596		$	72,172
Total Liabilities	$	1,118,853		$	569,494		$	473,701		$	357,443		$	276,746		$	86,462
Minority Interest	$	29,104		$	27,296		$	27,390		$	15,496		$	14,614		$	245
Stockholders’ Equity	$	747,457		$	513,854		$	431,523		$	321,264		$	221,623		$	185,997

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 the majority 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, 2008, we had estimated proved reserves that totaled 884.4 Bcfe, of which 20.5% were proved developed, with an after-tax PV-10 value of $159.4 million. For the year ended December 31, 2008, we reported net production of 68.2 Mmcfe per day.

As of December 31, 2008, our reserves were comprised of approximately 827.7 Bcf of natural gas and 9.5 Mmbbls of crude oil, or 93.6% gas on an equivalent basis. Approximately 95% of our proved reserves were located in the Rocky Mountains, 5% in the Gulf Coast and less than 1% in other locations. We expect that our drilling efforts and capital expenditures will focus increasingly on the Rockies, where approximately 80% of our fiscal 2009 drilling budget is allocated and more than one-half of our undeveloped acreage is located. As of December 31, 2008, we controlled approximately 893,000 net undeveloped acres, representing approximately 97% of our total acreage position. We retain a high degree of operational control over our asset base, with an average working interest in excess of 85% (excluding our Columbia River Basin properties) as of December 31, 2008. 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 19 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.

Recent developments

During the year ended December 31, 2008:

•

We increased proved reserves to 884.4 Bcfe at December 31, 2008, an increase of 135.4%, or 81.0% before considering current year purchases, compared to proved reserves as of December 31, 2007 of 375.6 Bcfe.

•

Continued success from our Rocky Mountain drilling activities has increased our production from continuing operations by 48% for the year ended December 31, 2008 to 24.9 Mcfe, compared to 16.9 Mcfe for the prior year period.

•

We commenced drilling of our first operated Columbia River Basin well and attracted a joint venture partner, selling a 50% working interest participation in all of our Columbia River Basin leasehold interests, including our current exploration project.

•

We recorded an impairment provision to our proved and unproved properties and other assets for the year ended December 31, 2008 totaling approximately $327.1 million, primarily related to Texas, Utah, and our offshore California field. 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 Basin pipeline, certain DHS rigs and we wrote off DHS’s goodwill.

•

Subsequent to year-end, on March 2, 2009, we entered into the Forbearance Agreement and Amendment to the Credit Facility pursuant to which the lenders under our Credit Facility agreed to forbear from taking certain actions (including accelerating amounts due under the Credit Facility) as a result of our violations of certain of our covenants under the Credit Facility. In addition, the agreement amends our 2009 debt to EBITDAX covenant to a senior secured debt to EBITDAX covenant, reduces the borrowing base from $295.0 million to $225.0 million, thereby requiring us to repay the $68.8 million borrowed in excess of the borrowing base, as discussed below, and increases our variable interest rates. The Forbearance Agreement and Amendment to the Credit Facility requires that we raise net proceeds of at least $140.0 million through our capital raising efforts on or before the forbearance termination date.

2009 Outlook

We expect our 2009 oil and gas production to stay relatively flat to 2008 levels due to the limited drilling program we expect for 2009. For calendar year 2009, we have preliminarily established a drilling and completion budget of approximately $52.0 million. We are concentrating a substantial portion of this budget on the development of our Piceance Basin assets in the Rockies, and to a lesser extent, our Columbia River Basin exploration.

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 profitability and long-term value creation for stockholders. Generating 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. In the current depressed commodity price and general economic environment, we, and others in our industry, face major short-term challenges, including our continued ability to satisfy our debt covenants, to meet our obligations as they become due, and to sustain ourselves as a going concern.

We have taken the following steps to mitigate the challenges we face. We have entered into the Forbearance Agreement and Amendment to the Credit Facility, and are actively engaged in pursuing potential capital raising activities such as sales of debt or equity securities, asset sales and potential joint ventures or other industry partnerships in order to pay down our debt outstanding and reduce our payables, we have reduced our capital expenditure program, and we intend to implement additional cost saving measures.

Our longer-term business strengths include a multi-year inventory of attractive 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.

Liquidity and Capital Resources

Liquidity is a measure of a company’s ability to access cash. As shown in the accompanying financial statements, we experienced a net loss of $452.0 million for the year ended December 31, 2008, we were not in compliance with certain of the debt covenants under our Credit Facility, and are facing significant immediate requirements to fund obligations in excess of our existing sources of liquidity. Our accompanying financial statements have been prepared assuming we will continue as a going concern; however, due to our deficiency in short-term and long-term liquidity, our ability to continue as a going concern is dependent on our success in generating additional sources of capital in the near future. We have received a report from our independent registered certified public accounting firm on our consolidated financial statements for the year ended December 31, 2008, in which our auditors have included an explanatory paragraph indicating that the we have suffered recurring losses from operations, have a working capital deficiency and were not in compliance with our debt covenants as of December 31, 2008 which raises substantial doubt about our ability to continue as a going concern.

During the year ended December 31, 2008, we had an operating loss of $464.5 million, but generated cash from operating activities of $140.7 million and obtained cash from financing activities of $897.6 million. During this period we spent $457.9 million on oil and gas development, $221.8 million on oil and gas acquisitions (or $179.8 million, net of $42.0 million proceeds from dispositions) and $53.0 million on drilling and trucking capital expenditures (or $49.8 million, net of $3.2 million proceeds from dispositions). At December 31, 2008, we had $65.5 million in cash, total assets of $1.9 billion and a debt to capitalization ratio of 47.0%. Debt at December 31, 2008 totaled $841.2 million, comprised of $388.3 million of bank debt ($295 million of which was classified as current at December 31, 2008), $188.3 million of long-term installments payable, $149.5 million of senior subordinated notes and $115.0 million of senior convertible notes.

In November 2008, we refinanced our senior Credit Facility increasing our total borrowing base to $590.0 million, of which $295.0 million was initially available. Our covenants require a minimum current ratio of 1 to 1, excluding the fair value of derivative instruments, and a consolidated debt to EBITDAX (earnings before interest, taxes, depreciation, amortization and exploration) of less than 4.5 to 1.0 for the quarter ended December 31, 2008, and 4.25 to 1.0 for the period ended March 31, 2009, 4.0 to 1.0 for the period ended June 30, 2009, 3.75 to 1.0 for the period ended September 30, 2009 and 3.5 to 1.0 for the period ended December 31, 2009 and each quarter thereafter. This consolidated debt to EBITDAX covenant was modified by the Forbearance Agreement and Amendment to the Credit Facility to require that senior secured debt to consolidated EBITDAX for the preceding four consecutive quarters be less than 4.0 to 1.0. These financial covenant calculations include only wholly-owned subsidiaries. At December 31, 2008, we were not in compliance with our minimum current ratio and accounts payable covenants under the Credit Facility and accordingly we have classified the $294.5 million of debt outstanding under the bank Credit Facility at December 31, 2008 as current in the accompanying consolidated balance sheet.

In addition, pursuant to the Forbearance Agreement and Amendment to the Credit Facility, the borrowing base under our Credit Facility will be reduced upon the successful completion of our capital raising efforts to $225.0 million, which will require a repayment of $68.8 million based on outstanding borrowings of $293.8 million at March 2, 2009. Under the Forbearance Agreement and Amendment to the Credit Facility the lenders have provided us relief for a period ending April 15, 2009 at the earliest and no longer than June 15, 2009 depending on the progress of our capital raising efforts, 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 requires that we raise net proceeds of at least $140.0 million through our capital raising efforts on or before the forbearance termination date in order to reduce our outstanding Credit Facility borrowings and reduce accounts payable. It also limits our capital expenditures in the second and third quarter of 2009, though these limitations are consistent with our capital expenditure plans. (See Note 21 in the accompanying consolidated financial statements).

We have approximately $159.0 million of accounts payable at December 31, 2008, which if not timely paid could result in liens filed against our properties or withdrawal of trade credit provided by vendors, which in turn could limit our availability to conduct operations on our properties. We are pursuing additional capital from a variety of potential sources, including sales of debt or equity securities, asset sales, joint ventures and other similar industry partnerships.

In August 2008, DHS closed a new $150.0 million credit facility with Lehman Brothers Commercial Paper, Inc. (Lehman) as administrative agent. At December 31, 2008, DHS owed $93.8 million under its credit facility and as a result of the Lehman bankruptcy, DHS has no additional availability under its credit facility. In the event that DHS is not successful in obtaining alternative financing or making satisfactory arrangements with the Lehman bankruptcy trustee, it likely that DHS will be in default of its debt covenants under its credit facility in 2009 unless market conditions improve significantly. In such event, all of the amounts due under the credit facility would become immediately due and payable.

As of December 31, 2008, our corporate rating and senior unsecured debt rating were Caa1 and Caa2, respectively, as issued by Moody’s Investors Service. Moody’s outlook is “stable.” As of December 31, 2008, our corporate credit and senior unsecured debt ratings were B- and CCC+, respectively, as issued by Standard and Poor’s (“S&P”). S&P’s outlook on the rating was “stable.” Subsequent to year-end, S&P placed our corporate rating on “credit watch” due to liquidity and debt concerns. Further, Moody’s downgraded our corporate rating and senior unsecured debt rating to Caa2 and Caa3, respectively. In addition, Moody’s outlook on the rating was changed to “negative.”

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 production activities in generating additional production.

There can be no assurance that the actions undertaken by us will be sufficient to repay the obligations under the Credit Facility as required by the Forbearance Agreement and Amendment to the 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. In addition, there can be no

assurance that results of operations and other sources of liquidity, including asset sales, will be sufficient to meet contractual, operating and capital obligations. The financial statements do not include any adjustments that might result from the outcome of uncertainty regarding our ability to raise additional capital, sell assets, obtain sufficient funds to meet our obligations or to continue as a going concern.

Although we believe that through cash on hand, cash flows from operations, and assuming the success of our capital raising efforts as discussed above, we will have access to adequate capital to meet our obligations as they come due and fund our limited development plan for the next 12 months, we continue to examine additional sources of long-term capital, including a restructured debt facility, the issuance of debt instruments, the sale of preferred and common stock, the sales of non-strategic assets, and joint venture financing. Availability of these sources of capital and, therefore, our ability to execute our operating strategy and meet our near term 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, 2008, 2007 and 2006. 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,
	2008			2007			2006
Revenue:
Oil and gas sales	$	221,733		$	123,729		$	102,540
Contract drilling and trucking fees		49,445			58,358			59,603
Gain (loss) on hedging instruments, net		-			12,854			(4,712	)

Total revenue		271,178			194,941			157,431

Operating Expenses:
Lease operating expense		33,508			20,882			17,811
Transportation expense		11,395			4,074			1,089
Production taxes		12,075			7,463			5,308
Exploration expense		10,975			9,062			4,690
Dry hole costs and impairments		438,963			87,459			16,001
Depreciation, depletion and amortization – oil and gas		99,125			73,875			55,245
Drilling and trucking operating expenses		32,594			37,698			35,504
Goodwill and drilling equipment impairments		29,349			-			-
Depreciation and amortization – drilling and trucking		14,134			16,021			13,010
General and administrative expense		53,607			49,621			35,696
Gain on sale of oil and gas properties		-			-			(20,034	)

Total operating expenses		735,725			306,155			164,320


Operating loss		(464,547	)		(111,214	)		(6,889	)

Other income and (expense):
Interest expense and financing costs		(41,421	)		(29,279	)		(26,891	)
Interest income		10,132			2,080			575
Other income (expense)		(5,210	)		376			(154	)
Realized gain on derivative instruments, net		18,383			917			-
Unrealized gain (loss) on derivative instruments, net		3,365			(3,819	)		11,722
Gain on sale of investment in LNG		-			-			1,058
Minority interest in losses (income) of subsidiary		11,486			1,231			(2,595	)
Income (loss) from unconsolidated affiliates		3,375			(393	)		-

Total other income (expense)		110			(28,887	)		(16,285	)


Loss from continuing operations before income taxes and discontinued operations		(464,437	)		(140,101	)		(23,174	)
Income tax expense (benefit)		(11,723	)		5,010			(8,546	)


Loss from continuing operations		(452,714	)		(145,111	)		(14,628	)
Income from discontinued operations of properties sold or held for sale, net of tax		-			1,922			5,272
Gain (loss) on sale of discontinued operations, net of tax		718			(3,998	)		6,712
Extraordinary gain, net of tax		-			-			5,560


Net income (loss)	$	(451,996	)	$	(147,187	)	$	2,916

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

Net Income (Loss). Net loss was $452.0 million, or $4.73 per diluted common share, for the year ended December 31, 2008, compared to net loss of $147.2 million or $2.40 per diluted common share, for the year ended December 31, 2007. Loss from continuing operations increased from $145.1 million for the year ended December 31, 2007 to a loss of $452.7 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 hedging 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 41% to $41.4 million for the year ended December 31, 2008, as compared to $29.3 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).

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.

Minority Interest in Losses (Income) of Subsidiary. Minority interest represents the minority 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 minority interest credit to earnings.

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.

Year Ended December 31, 2007 Compared to Year Ended December 31, 2006

Net Income (Loss). Net loss was $147.2 million, or $2.40 per diluted common share, for the year ended December 31, 2007, compared to net income of $2.9 million or $.05 per diluted common share, for the year ended December 31, 2006. Loss from continuing operations increased from $14.6 million for the year ended December 31, 2006 to a loss of $145.1 million for the year ended December 31, 2007, due primarily to dry hole costs and impairments, first half 2006 gains on undeveloped property sales and gains on ineffective derivative instruments that did not occur during 2007, and due to higher depreciation, depletion, and amortization expense, and increased general and administrative expense in 2007. Net loss increased significantly due to the valuation allowance required to be recorded against the Company’s deferred tax assets during the second quarter of 2007.

Oil and Gas Sales. During the year ended December 31, 2007, oil and gas sales from continuing operations were $123.7 million, as compared to $102.5 million for the comparable period a year earlier. During the year ended December 31, 2007, production from continuing operations increased by 35%, however, this was offset by a 14%

decrease in the average gas price. The average gas price received during the year ended December 31, 2007 was $5.17 per Mcf compared to $5.98 per Mcf for the year earlier period, primarily due to the increase in the basis differential applicable to Rocky Mountain natural gas. The average oil price received during the year ended December 31, 2007 increased to $67.39 per Bbl compared to $61.74 per Bbl for the year earlier period.

Net gains (losses) from effective hedging activities were a $12.9 million gain and a $4.7 million loss for the year ended December 31, 2007 and 2006, respectively. The gain in 2007 realized hedges is primarily due to lower oil and gas prices. These gains (losses) are recorded as an increase or decrease in revenues.

Contract Drilling and Trucking Fees. Drilling revenues for the year ended December 31, 2007 remained flat at $52.1 million compared to $52.5 million for the prior year period. Drilling revenue is earned under daywork or turnkey contracts where we provide a drilling rig with required personnel to our third party customers who supervise the drilling of the well. We are paid based on a negotiated fixed rate per day while the rig is in use or on a negotiated fixed rate for drilling to a certain depth. During the mobilization period we typically earn a fixed amount of revenue based on the mobilization rate set in the contract. Drilling revenues earned on wells drilled for Delta have been eliminated through consolidation.

Trucking revenues for the year ended December 31, 2007 were $6.3 million compared to $7.1 million for the prior year period. Trucking revenues decreased in 2007 due to fewer rigs being transported in Wyoming where C&L Drilling operates.

Production and Cost Information

Production volumes, average prices received and cost per equivalent Mcf for the years ended December 31, 2007 and 2006 are as follows:


	Years Ended December 31,
	2007		2006⁽¹⁾
Production – Continuing Operations:
Oil (MBbl)		1,003		1,073
Gas (MMcf)		10,866		6,076
Production – Discontinued Operations:
Oil (MBbl)		82		282
Gas (MMcf)		387		1,947

Total Production (MMcfe)		17,763		16,147

Average Price – Continuing Operations:
Oil (per barrel)	$	67.39	$	61.74
Gas (per Mcf)	$	5.17	$	5.98

Costs per Mcfe – Continuing Operations:
Lease operating expense	$	1.24	$	1.42
Production taxes	$	.44	$	.42
Transportation costs	$	.24	$	.09
Depletion expense	$	4.26	$	4.29

⁽¹⁾ Revised for operations discontinued in 2007.

Lease Operating Expense. Lease operating expenses for the year ended December 31, 2007 were $20.9 million compared to $17.8 million for the year earlier period. Lease operating expense from continuing operations for the year ended December 31, 2007 was $1.24 per Mcfe as compared to $1.42 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, 2007 were $9.1 million compared to $4.7 million for the year earlier period. The year ended December 31, 2007 exploration activities increased and included the acquisition and processing of the seismic program related to acreage in Opossum Hollow, Texas, processing for 2D seismic costs in the central Utah Hingeline, and 3D seismic costs to evaluate leasehold positions for additional drilling locations in Wyoming.

Dry Hole Costs and Impairments. We incurred dry hole costs of approximately $28.1 million for the year ended December 31, 2007 compared to $4.3 million for the comparable period a year ago. For the year ended December 31, 2007, our dry hole costs related primarily to seven exploratory projects, three in Texas, two in Wyoming, one well in Colorado and one in Utah. For the year ended December 31, 2006, the dry hole costs related primarily to exploratory projects in Texas and Utah.

During the year ended December 31, 2006, an impairment of $10.4 million was recorded on certain of our eastern Colorado properties primarily due to lower Rocky Mountain natural gas prices.

Depreciation, Depletion and Amortization – oil and gas. Depreciation, depletion and amortization expense increased 34% to $73.9 million for the year ended December 31, 2007, as compared to $55.2 million for the year earlier period. Depletion expense for the year ended December 31, 2007 was $71.9 million compared to $53.7 million for the year ended December 31, 2006. The 34% increase in depletion expense was due to a 35% increase in production from continuing operations, slightly offset by a 1% decrease in the depletion rate. Our depletion rate decreased to $4.26 per Mcfe for the year ended December 31, 2007 from $4.29 per Mcfe for the year earlier period. The decrease is partially due to lower finding costs per Mcfe on our extensive 2007 Rockies drilling program.

Drilling and Trucking Operating Expenses. We had drilling and trucking operating expenses of $37.7 million during the year ended December 31, 2007 compared to $35.5 million during the year ended December 31, 2006. The increase in expenses was due to the greater average overall number of rigs in operation for DHS in 2007 than in the prior year.

Depreciation and Amortization – drilling and trucking. Depreciation and amortization expense – drilling and trucking increased to $16.0 million for the year ended December 31, 2007 as compared to $13.0 million for the prior year period. This increase can be attributed to a greater average number of rigs that DHS owned in 2007 compared to the prior year.

General and Administrative Expense. General and administrative expense increased 39% to $49.6 million for the year ended December 31, 2007, as compared to $35.7 million for the comparable prior year period. The increase in general and administrative expenses is primarily attributed to an increase in non-cash equity compensation of $10.7 million and a 23% increase in technical and administrative staff and related personnel costs.

Gain on Sale of Oil and Gas Properties. In January and March 2006, Delta sold a combined 44% minority interest in CRBP. As the sale involved unproved properties, no gain on the partial sale of CRBP could be recognized until all of the cost basis of CRBP had been recovered. Accordingly, we recorded a $13.0 million gain ($8.1 million net of tax), and an $11.2 million reduction to property during the first quarter of 2006 as a result of closing the transaction.
In November 2006, we sold certain undeveloped property interests in the Columbia River Basin for proceeds of $2.0 million. We recorded a gain on the transaction of $1.1 million.

In March 2006, we sold approximately 26% of PGR. This transaction involved both proved and unproved property interests and accordingly, to the extent the sale of PGR related to unproved properties, no gain could be recognized as all of the unproved cost basis was not yet recovered. We recorded a gain of $5.9 million, $3.7 million net of tax, and a $3.4 million offset to property during the first quarter of 2006 as a result of the transaction. We retained a 74% interest in, and are the manager of, PGR.

Interest and Financing Costs. Interest and financing costs increased 9% to $29.3 million for the year ended December 31, 2007, as compared to $26.9 million for the comparable year earlier period. The increase is primarily related to higher average debt balances on DHS’s credit facility during the year and costs related to the refinancing of DHS credit facilities in May and December, offset by lower average balances outstanding on Delta’s credit facility.

Unrealized Gain (Loss) on Derivative Instruments, Net. Effective July 1, 2007, we discontinued cash flow hedge accounting. 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 for the contracts that qualify as cash flow hedges. As a result, we recognized in our statements of operations a loss of $3.8 million for the year ended December 31, 2007 and a gain of $11.7 million for the year ended December 31, 2006.

Gain on Sale of Investment in LNG Project. On March 30, 2006, we sold our long-term minority interest investment in an LNG project for total proceeds of $2.1 million. We recorded a gain on sale of $1.1 million ($657,000 net of tax).

Minority Interest in Losses (Income) of Subsidiary. Minority interest represents the minority investors’ percentage of their share of income or losses from DHS in which they hold an interest. During the year ended December 31, 2007 DHS generated a loss resulting in minority credit to earnings.

Income Tax 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 on our deferred tax assets beginning with the second quarter of 2007. As a result, our income tax expense for the year ended December 31, 2007 of $5.0 million includes a valuation allowance of $57.4 million. During the year ended December 31, 2006, an income tax benefit of $8.5 million was recorded for continuing operations at an effective tax rate of 37.5%.

Discontinued Operations. Discontinued operations include the Frisco field in Pointe Coupee Parish, Louisiana, which was sold in June 2006, the Panola and Rusk County, Texas properties, which were sold in August 2006, the East Texas and Pennsylvania properties, which were sold in August 2006, 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 on these assets, net of tax, during the years ended December 31, 2007 and 2006 were $1.9 million and $5.3 million, respectively.

Gain (Loss) on Sale of Discontinued Operations. 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 and a combined net loss of $4.0 million. During the year ended December 31, 2006, we sold certain non-core properties located in Louisiana and East Texas for combined proceeds of $23.8 million and an after-tax gain of $6.7 million.

Extraordinary Gain. On August 21, 2006, the Company completed the sale of the properties acquired with the Castle acquisition in April 2006. During the year ended December 31, 2006 the Company recorded a $5.6 million extraordinary gain, net of tax in accordance with SFAS No. 141 “Business Combinations” (“SFAS 141”).

Company Acquisitions, Divestitures and Financings

We plan to continue as financing allows to evaluate potential acquisitions and property development opportunities. During the year ended December 31, 2008, we completed the following transactions:

On February 20, 2008, we issued 36.0 million shares of common stock to Tracinda Corporation (“Tracinda”) at $19.00 per share for gross proceeds of approximately $684 million. As a result of the transaction and subsequent purchases in the open market, Tracinda currently owns approximately 39% 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 are obligated to drill an initial appraisal well by July 1, 2009. If we do not commence drilling by July 1, 2009, the leasehold interests we acquired for $14.1 million revert to the previous owner.

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.

Capital and Exploration Expenditures and Financing

Our capital and exploration expenditures and sources of financing for the years ended December 31, 2008, 2007 and 2006 were as follows:


	Years Ended December 31,
	2008			2007			2006
	(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			-
Armstrong Acquisition		-			-			40,103
Castle		-			-			33,648
Columbia River Basin		25,000			-			-
Other		8,050			9,988			24,678
Other development costs		458,067			287,790			179,874
Drilling and trucking companies		52,970			22,292			63,848
Exploration costs		10,975			9,062			4,690

	$	743,827		$	392,175		$	346,841


FINANCING SOURCES:
Cash provided by operating activities	$	140,676		$	87,003		$	54,499
Stock issued for cash upon exercised options		4,827			137			3,711
Stock issued for cash, net		662,043			202,084			33,870
Net long-term borrowings		232,120			40,836			114,265
Proceeds from sale of oil and gas properties		42,000			46,193			82,716
Proceeds from sale of drilling assets		3,201			7,145			-
Investments in and notes issued to affiliates		(6,965	)		(12,833	)		-
Increase in restricted deposit		(300,000	)		-			-
Minority interest contributions		12,000			(355	)		9,018
Other		(120	)		(106	)		(3,646	)

	$	789,782		$	370,104		$	294,433

For the year ending December 31, 2009, we currently plan to spend $52 million on our drilling program, but may adjust this plan depending on our liquidity, economic conditions and commodity prices. The timing of a portion of our capital expenditures is discretionary and could be delayed or curtailed, if necessary.

Sale of Oil and Gas Properties

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.

In March 2006, we sold approximately 26% of PGR for $20.4 million. This transaction involved both proved and unproved property interests and accordingly, to the extent the sale of PGR related to unproved properties, no gain was recognized as all of the unproved cost basis was not yet recovered. We recorded a gain of $5.9 million, $3.7 million net of tax, and a $3.4 million reduction to property during the first quarter of 2006 as a result of the transaction. We have retained a 74% interest in PGR.

During December 2005, we transferred our ownership in approximately 427,000 gross acres (64,000 net acres) of non-operated interests in the Columbia River Basin to a newly created wholly owned subsidiary, CRBP. In January and March 2006, we sold a combined 44% minority interest in CRBP for total proceeds of $32.8 million. As the sale involved unproved properties, no gain on the partial sale of CRBP was recognized until all of the cost basis of CRBP has been recovered. Accordingly, we recorded a $13.0 million gain, ($8.1 million net of tax) and an $11.2 million reduction to property during the first quarter of 2006 upon closing the transaction.

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, 2008	2009		2010 - 2011		2012 - 2013		Thereafter		Total
	(In thousands)
Credit facility¹	$	294,475	$	-	$	-	$	-	$	294,475
Installments payable on property acquisitions²		99,570		200,000		-		-		299,570
7% Senior unsecured notes		-		-		-		150,000		150,000
Interest on 7% Senior unsecured notes		10,500		21,000		21,000		15,283		67,783
3³/4% Senior convertible notes		-		-		-		115,000		115,000
Credit facility – DHS		-		93,848		-		-		93,848
Abandonment retirement obligation		2,151		723		678		16,631		20,183
Operating leases		3,870		4,016		2,853		2,436		13,175
Drilling commitments³		-		-		-		-		-

Total contractual cash obligations	$	410,566	$	319,587	$	24,531	$	299,350	$	1,054,034

¹ Amounts outstanding under our credit facility are classified as current due to our covenant violations at December 31, 2008. See Credit Facility below for additional information regarding our Forbearance Agreement and Amendment to the Credit Facility with the lenders.

² Amounts due will be funded with restricted cash deposits on hand.

³ The Company has no significant drilling commitments, other than to drill one well on a Gulf Coast property by July 1, 2009. If we do not commence drilling by July 1, 2009, the leasehold interest we acquired for $14.1 million reverts to the previous owner.

Credit Facility

On November 3, 2008, we entered into a Second Amended and Restated Credit Agreement with JP Morgan Chase Bank, N.A. and certain other financial institutions, which, among other changes, increased the amount of our revolving credit facility up to $590.0 million subject to borrowing base limitations. As of December 31, 2008 the borrowing base under our revised facility was $295.0 million with an outstanding balance of $294.5 million. Borrowings under the amended credit agreement are available to finance the acquisition, exploration and development of oil and gas interests and related assets and activities, refinance certain existing debt and provide for working capital and general corporate purposes.

We were required to meet certain financial covenants for the quarter ended December 31, 2008 including a current ratio of greater than 1 to 1 and consolidated net debt to consolidated EBITDAX (as defined in the amended credit agreement) for the preceding four consecutive fiscal quarters of less than 4.50 to 1.0 for the period ending December 31, 2008. At December 31, 2008, we were in compliance with our maximum debt to EBITDAX ratio but did not meet our minimum current ratio and accounts payable covenants and accordingly we have classified the $294.5 million of debt outstanding under the bank credit facility at December 31, 2008 as current in the accompanying consolidated balance sheet.

On March 2, 2009, we entered into the First Amendment to our Second Amended and Restated Credit Agreement with JPMorgan Chase Bank, N.A. and certain other financial institutions in which, among other changes, the lenders provided us a forbearance period from acting upon their rights as a result of our violation of accounts payable and current ratio covenants for a period ending April 15, 2009 at the earliest and no later than June 15, 2009 dependent upon the progress of our capital raising efforts. The Forbearance Agreement and Amendment to the Credit Facility waives our covenant violations existing at December 31, 2008, waives the March 31, 2009 current ratio covenant requirement and replaces 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 beginning December 31, 2008. The borrowing base under the Credit Facility has been reduced from $295.0 million to $225.0 million, with a conforming borrowing base of $185.0 million until the next redetermination date (September 1, 2009). The Forbearance Agreement and Amendment to the Credit Facility requires that we raise net proceeds of at least $140.0 million through our capital raising efforts on or before the forbearance termination date and that we reduce our amounts outstanding under the facility to not more than $225.0 million and pay accounts payable with such net proceeds. The Forbearance Agreement and Amendment to the Credit Facility revised the variable interest rates payable under the Credit Facility based on the ratio of outstanding credit to the conforming borrowing base to vary between Libor plus 2.5% to Libor plus 5.0% for Eurodollar loans and 1.625% to 4.125% for base rate loans. The Forbearance Agreement and Amendment to the Credit Facility changes the maturity date of the Credit Facility to January 15, 2011 upon the successful completion of our capital raising efforts. In addition, the Forbearance Agreement and Amendment to the Credit Facility requires us to put derivative contracts in place to establish a floor price for our anticipated production of a minimum of 40% for the last two quarters of 2009, 70% for the calendar year 2010 and 50% for the calendar year 2011.

As a result of capital raising efforts and the amendment to the agreement, we project we will meet our covenant requirements during 2009. However, because our operations are subject to a number of risks beyond management’s control, including but not limited to, commodity price declines and third party production curtailment, there can be no assurance that we will in fact meet our 2009 covenant requirements. If such an event of default were to occur, the lenders would be entitled to accelerate our outstanding debt in accordance with the provisions of the credit agreement.

The borrowing base is re-determined by the lending banks at least semi-annually on April 1 and September 1 of each year, or by special re-determinations if requested by the Company based on drilling success. If, as a result of any reduction in the amount of our borrowing base, the total amount of the outstanding debt were to exceed the amount of the borrowing base in effect, then, within 30 days after we are notified of the borrowing base deficiency, we would be required (1) to make a mandatory payment of principal to reduce our outstanding indebtedness so that it would not exceed our borrowing base, (2) to eliminate the deficiency by making three equal monthly principal payments, (3) within 90 days, to provide additional collateral for consideration to eliminate the deficiency or (4) to 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 our credit facility. Subsequent to year end, the borrowing base under our credit facility will be reduced upon the successful completion of our capital raising efforts to $225.0 million, which will require a repayment of $68.8 million based on outstanding borrowings of $293.8 million at March 2, 2009.

The credit facility 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 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 will 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 will 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, oil and gas inventory, and certain bank accounts and proceeds.

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 and installments of $99.6 million, $100.0 million, and $100.0 million are payable November 1, 2009, 2010, and 2011, respectively. 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 for the year ended December 31, 2008.

7% Senior Unsecured Notes, due 2015

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

fourth quarter due to Lehman’s failure to fund additional borrowing requests. The remaining financing costs are being amortized over the term of the loan. At December 31, 2008, DHS was in compliance with its quarterly debt covenants and restrictions under the facility.

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 $1.3 million over the term of the lease. We have additional operating lease commitments which represent office equipment leases and lease obligations primarily relating to field vehicles and equipment.

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. With the further decline in commodity pricing since year end, the proved undeveloped reserves attributable to our Piceance Basin properties are uneconomic using the spot natural gas price as of February 28, 2009. The Piceance Basin properties contain nearly all of our proved undeveloped reserves. 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, we recorded an impairment provision to our proved and unproved properties for the year ended December 31, 2008 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 resulted primarily due to the significant decline in commodity pricing during the fourth quarter of 2008.

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 2009, 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

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

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, 2008, we had no outstanding derivative contracts. However, in accordance with the terms of our Forbearance Agreement and Amendment to the Credit Facility, we expect to put derivative contracts in place to establish a floor price for our anticipated production of a minimum of 40% for the last two quarters of 2009, 70% for the calendar year 2010 and 50% for the calendar year 2011.

Asset Retirement Obligation

We account for our asset retirement obligations under SFAS 143. SFAS 143 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 Issued Accounting Standards and Pronouncements

In March 2008, the FASB affirmed FASB Staff Position (“FSP”) APB 14-a, “Accounting for Convertible Debt Instruments That May Be Settled in Cash Upon Conversion (Including Partial Cash Settlement)”. The FSP 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. The FSP is effective for fiscal years beginning after December 15, 2008, or our first quarter 2009. This FSP changes the accounting treatment for our 3³/4% Senior Convertible Notes since it is to be applied retrospectively upon adoption. Based on our stock price on the date of the original issuance, the terms of the Notes, and other inputs, the liability component of the issuance was approximately $54.9 million and the equity component was approximately $60.1 million. Based on these

components at the issue date we will record accretion of debt discount for 2007 and 2008 of approximately $0.9 million and $1.4 million, respectively, and a reduction to the carrying value of the Notes of $57.7 million upon the adoption of the FSP.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133” (SFAS 161). This Statement requires enhanced disclosures for derivative and hedging activities. This statement is effective for financial statements issued for fiscal years beginning after November 15, 2008, or fiscal year 2009. We are currently evaluating the potential impact of the adoption of SFAS 161 on the disclosures in our consolidated financial statements.

In December 2007, the FASB issued SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS 141R”), which replaces SFAS 141. SFAS 141R establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any resulting goodwill, and any noncontrolling interest in the acquiree. The Statement also provides for disclosures to enable users of the financial statements to evaluate the nature and financial effects of the business combination. SFAS 141R is effective for financial statements issued for fiscal years beginning after December 15, 2008, or our fiscal year 2009, and must be applied prospectively to business combinations completed on or after that date.

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements – an amendment of Accounting Research Bulletin No. 51” (“SFAS 160”), which establishes accounting and reporting standards for noncontrolling interests (“minority interests”) in subsidiaries. SFAS 160 clarifies that a noncontrolling interest in a subsidiary should be accounted for as a component of equity separate from the parent’s equity. SFAS 160 is effective for financial statements issued for fiscal years beginning after December 15, 2008, or fiscal year 2009, and must be applied prospectively, except for the presentation and disclosure requirements, which will apply retrospectively. We adopted the provisions of SFAS 160 on January 1, 2009. Beginning with our first quarter 2009 reporting period and for prior comparative periods, we will present noncontrolling interests, currently referred to as minority interests in the accompanying consolidated balance sheets, as a component of stockholders’ equity. The adoption of SFAS 160 will not have a material impact on our consolidated financial statements; however, it could impact our accounting for future transactions.

Recently Adopted Accounting Pronouncements

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS 159”). SFAS 159 permits companies to choose to measure many financial instruments and certain other items at fair value. SFAS 159 is effective for financial statements issued for fiscal years beginning after November 15, 2007, or fiscal year 2008. We adopted SFAS 159 effective January 1, 2008, but did not elect to apply the SFAS 159 fair value option to eligible assets and liabilities during the year ended December 31, 2008.

In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, “Fair Value Measurements” (“SFAS 157”), which defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and requires additional disclosures about fair value measurements. SFAS 157 aims to improve the consistency and comparability of fair value measurements by creating a single definition of fair value. The Statement emphasizes that fair value is not entity-specific but instead is a market-based measurement of an asset or liability. SFAS 157 reaffirms the requirements of previously issued pronouncements concerning fair value measurements and expands the required disclosures. In February 2008, the FASB issued FASB Staff Position (“FSP”) No. 157-2. FSP No. 157-2 delays the effective date of SFAS 157 for one year for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually).

We adopted the provisions of SFAS 157 for fair value measurements not delayed by FSP No. 157-2. The adoption resulted in additional disclosures as required by the pronouncement related to our fair value measurements for oil and gas derivatives and marketable securities, but did not change our fair value calculation methodologies. Accordingly, the adoption had no impact on our financial condition or results of operations.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Rate and Price Risk

We, at times, actively manage our exposure to commodity price fluctuations by hedging meaningful portions of our expected production through the use of derivatives, including costless collars, swaps, and 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.

At December 31, 2008, we had no outstanding derivative agreements.

Assuming production and the percent of oil and gas sold remained unchanged from the year ended December 31, 2008, a hypothetical 10% decline in the average market price we realized during the year ended December 31, 2008 on unhedged production would reduce our oil and natural gas revenues by approximately $22.2 million on an annual basis.

Interest Rate Risk

We were subject to interest rate risk on $388.3 million of variable rate debt obligations at December 31, 2008. The annual effect of a 10% change in interest rates would be approximately $2.5 million. The interest rate on these variable debt obligations approximates current market rates as of December 31, 2008.

As of December 31, 2007, we have fixed rate debt totaling $264.5 million. The fair value of the fixed rate debt as of December 31, 2008 was approximately $84.4 million.

Item 8. Financial Statements and Supplementary Data

Financial Statements are included and begin on page F-1. There are no financial statement schedules since they are either not applicable or the information is included in the notes to the financial statements.

Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosures

Not applicable.

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Exchange Act reports is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms, and that such information is accumulated and communicated to management, including the chief executive officer and chief financial officer, as appropriate, to allow timely decisions regarding required disclosure. Management necessarily applied its judgment in assessing the costs and benefits of such controls and procedures, which, by their nature, can provide only reasonable assurance regarding management’s control objectives.

With the participation of management, our chief executive officer and chief financial officer evaluated the effectiveness of the design and operation of our disclosure controls and procedures at the conclusion of the period ended December 31, 2008. Based upon this evaluation, the chief executive officer and chief financial officer concluded that our disclosure controls and procedures were effective in ensuring that material information required to be disclosed is included in the reports that we file with the Securities and Exchange Commission.

Management’s Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting and for the assessment of the effectiveness of internal control over financial reporting for Delta. As defined by the Securities and Exchange Commission (Rule 13a-15(f) under the Exchange Act), internal control over financial reporting is a process designed by, or under the supervision of, our principal executive and principal financial officers and effected by our Board of Directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the consolidated financial statements in accordance with U.S. generally accepted accounting principles.

Our internal control over financial reporting is supported by written policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect our transactions and dispositions of our assets; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of the consolidated financial statements in accordance with U.S. generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorization of our management and directors; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the consolidated financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In connection with the preparation of our annual consolidated financial statements, management has undertaken an assessment of the effectiveness of our internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO Framework). Management’s assessment included an evaluation of the design of our internal control over financial reporting and testing of the operational effectiveness of those controls.

Based on this assessment, management has concluded that as of December 31, 2008, our internal control over financial reporting was effective to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. generally accepted accounting principles.

KPMG LLP, the independent registered public accounting firm that audited our consolidated financial statements included in this report, has issued an attestation report on the effectiveness of our internal control over financial reporting as of December 31, 2008.

Changes in Internal Controls

There were no significant changes in our internal controls or, to the knowledge of our management, in other factors that could significantly affect internal controls subsequent to the date of the most recent evaluation of our disclosure controls and procedures utilized to compile information included in this filing.

Item 9B. Other Information

On February 25, 2009, Neal A. Stanley, a member of our Board of Directors, advised us that he was resigning as a Director effective February 28, 2009. Mr. Stanley resigned to pursue a business opportunity with a privately held oil and gas company and not as a result of a disagreement on any matters relating to our operations, policies or practices. The Board of Directors has not yet decided if it will appoint a new Director to fill the vacancy created by Mr. Stanley’s resignation prior to our next annual meeting of stockholders.

INDEX TO EXHIBITS


2.		Plans of Acquisition, Reorganization, Arrangement, Liquidation, or Succession.

2.1		Agreement and Plan of Merger, dated as of November 8, 2005, among Delta Petroleum Corporation, a Colorado corporation, Delta Petroleum Corporation, and as amended a Delaware corporation, DPCA LLC, a Delaware limited liability company and a wholly owned subsidiary of Delta Colorado, and Castle Energy Corporation, a Delaware corporation. Incorporated by reference to Appendix A to the proxy statement/prospectus contained in the Company’s Form S-4 registration statement, SEC File No. 333-130672.

3.		Articles of Incorporation and By-laws.

3.1		Certificate of Incorporation of the Company, as amended. Incorporated by reference to Exhibit 3.1 to the Company’s Form 10-Q for the quarterly period ended March 31, 2008 and filed May 8, 2008.

3.2		Amended and Restated By-laws of the Company. Incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K filed February 13, 2006.

4.		Instruments Defining the Rights of Security Holders.

4.1		Purchase Agreement dated March 9, 2005, among Delta Petroleum Corporation, the Guarantors named therein and the Initial Purchasers named therein. Incorporated by reference from Exhibit 4.1 to the Company’s Form 8-K filed March 21, 2005.

4.2		Registration Rights Agreement dated March 15, 2005, among Delta Petroleum Corporation, the Guarantors named therein and the Initial Purchasers named therein. Incorporated by reference from Exhibit 4.2 to the Company’s Form 8-K filed March 21, 2005.

4.3		Indenture dated as of March 15, 2005, among Delta Petroleum Corporation, the Guarantors named therein and US Bank National Association, as Trustee. Incorporated by reference from Exhibit 4.3 to the Company’s Form 8-K filed March 21, 2005.

4.4		Form of 7% Series A Senior Notes due 2015 with attached notation of Guarantees. Incorporated by reference from Exhibit 4.3 to the Company’s Form 8-K filed March 21, 2005.

4.5		Indenture, dated as of April 25, 2007, by and between the Company and the subsidiary guarantors named therein and U.S. Bank National Association, as trustee (including Form of 3³/₄% Convertible Senior Note due 2037). Incorporated by reference from Exhibit 4.1 to the Company’s Form 8-K filed April 25, 2007.

4.6		Form of 3³/₄% Convertible Senior Note due 2037. Incorporated by reference from Exhibit 4.2 to the Company’s Form 8-K filed April 25, 2007.

10.		Material Contracts.

10.1		Delta Petroleum Corporation 1993 Incentive Plan, as amended. Incorporated by reference from Exhibit 99.1 to the Company’s Form 8-K dated November 1, 1996. *

10.2		Delta Petroleum Corporation 1993 Incentive Plan, as amended June 30, 1999. Incorporated by reference from the Company’s Notice of Annual Meeting and Proxy Statement dated June 1, 1999. *

10.3		Delta Petroleum Corporation 2001 Incentive Plan. Incorporated by reference from Exhibit B to the Company’s definitive proxy statement filed June 30, 2001.*

10.4		Delta Petroleum Corporation 2002 Incentive Plan incorporated by reference from Exhibit A to the Company’s definitive proxy statement filed May 1, 2002. *



10.5		Agreement between Delta Petroleum Corporation and Amber Resources Company dated July 1, 2001, incorporated by reference from Exhibit 10.3 to the Company’s Form 8-K filed December 20, 2001.

10.6		Delta Petroleum Corporation 2005 New-Hire Equity Incentive Plan. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K filed June 22, 2005.*

10.7		Amendment No. 1 to Delta Petroleum Corporation 2004 Incentive Plan. Incorporated by reference from Exhibit 10.2 to the Company’s Form 8-K filed June 22, 2005.*

10.8		Employment Agreement with Roger A. Parker dated May 5, 2005. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K filed May 11, 2005.*

10.9		Employment Agreement with Kevin K. Nanke dated May 5, 2005. Incorporated by reference from Exhibit 10.2 to the Company’s Form 8-K filed May 11, 2005.*

10.10		Employment Agreement with John R. Wallace dated May 5, 2005. Incorporated by reference from Exhibit 10.3 to the Company’s Form 8-K filed May 11, 2005.*

10.11		Employment Agreement with Stanley F. Freedman dated January 11, 2006. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K filed January 12, 2006.*

10.12		Delta Petroleum Corporation 2004 Incentive Plan. Incorporated by reference from Appendix B to the Company’s Definitive Proxy Statement filed November 22, 2004.*

10.13		Delta Petroleum Corporation 2006 New-Hire Equity Incentive Plan. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K filed June 26, 2006.*

10.14		Amended and Restated Credit Agreement, dated November 17, 2006, by and among Delta Petroleum Corporation, JPMorgan Chase Bank, N.A. and certain other financial institutions named therein. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K filed December 12, 2006.

10.15		First Amendment to Amended and Restated Credit Agreement, dated December 4, 2006, by and among Delta Petroleum Corporation, JPMorgan Chase Bank, N.A. and certain other financial institutions named therein. Incorporated by reference from Exhibit 10.2 to the Company’s Form 8-K filed, 2006.

10.16		Promissory Note, dated December 4, 2006, by and between Delta Petroleum Corporation and JPMorgan Chase Bank, N.A. Incorporated by reference from Exhibit 10.3 to the Company’s Form 8-K filed December 6, 2006.

10.17		Delta Petroleum Corporation 2007 Performance and Equity Incentive Plan. Incorporated by reference from Appendix A to the Company’s Definitive Proxy Statement filed December 28, 2006.*

10.18		Form of Restricted Stock Award Agreement. Incorporated by reference from Exhibit 10.2 to the Company’s Form 8-K filed February 9, 2007.*

10.19		Change in Control Executive Severance Agreement with Roger A. Parker dated April 30, 2007. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K filed May 2, 2007.*

10.20		Change in Control Executive Severance Agreement with John R. Wallace dated April 30, 2007. Incorporated by reference from Exhibit 10.2 to the Company’s Form 8-K filed May 2, 2007.*

10.21		Change in Control Executive Severance Agreement with Kevin K. Nanke dated April 30, 2007. Incorporated by reference from Exhibit 10.3 to the Company’s Form 8-K filed May 2, 2007.*

10.22		Change in Control Executive Severance Agreement with Stanley F. Freedman dated April 30, 2007. Incorporated by reference from Exhibit 10.4 to the Company’s Form 8-K filed May 2, 2007. *



10.23		Company Stock Purchase Agreement, dated December 29, 2007, by and between Delta Petroleum Corporation and Tracinda Corporation. Incorporated by reference from Exhibit 1.1 to the Company’s Form 8-K filed January 25, 2008.

10.24		$75,000,000 Credit Agreement dated as of December 19, 2007 among DHS Holding Company and DHS Drilling Company as borrowers, and Lehman Brothers Inc. as sole arranger and Lehman Brothers Commercial Paper Inc. as syndication agent and administrative agent. Incorporated by reference from Exhibit 10.24 to the Company’s Form 10-K for the annual period ended December 31, 2007 and filed February 29, 2008.

10.25		Carry and Earning Agreement dated February 28, 2008 between the Company and EnCana Oil & Gas (USA) Inc. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K filed March 5, 2008.

10.26		Fifth Amendment to Amended and Restated Credit Agreement dated as of May 16, 2008 among the Company, JPMorgan Chase Bank, N.A. as Administrative Agent and each of the financial institutions named therein. Incorporated by reference from Exhibit 10.1 to the Company’s Form 10-Q for the quarterly period ended June 30, 2008 and filed August 7, 2008.

10.27		Purchase and Sale Agreement dated September 15, 2008 between the Company and EnCana Oil & Gas (USA) Inc. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K filed October 2, 2008.

10.28		Sale Agreement dated August 19, 2008 between the Company and Husky Refining Company. Incorporated by reference from Exhibit 10.2 to the Company’s Form 8-K filed October 2, 2008.

10.29		Amended and Restated Credit Agreement dated as of August 15, 2008, among DHS Holding Company, DHS Drilling Company, the several banks and other financial institutions or entities from time to time parties to such Agreement, Lehman Brothers, Inc. as sole arranger and sole bookrunner and Lehman Commercial Paper, Inc. as syndication agent. Incorporated by reference from Exhibit 10.3 to the Company’s Form 10-Q for the quarterly period ended September 30, 2008 and filed November 6, 2008.

10.30		Amendment Number One to Amended and Restated Credit Agreement dated effective September 19, 2008, among DHS Holding Company, DHS Drilling Company, the several banks and other financial institutions or entities from time to time parties to such Agreement, Lehman Brothers, Inc. as sole arranger and sole bookrunner and Lehman Commercial Paper, Inc. as syndication agent. Incorporated by reference from Exhibit 10.4 to the Company’s Form 10-Q for the quarterly period ended September 30, 2008 and filed November 6, 2008.

10.31		Second Amended and Restated Credit Agreement dated November 3, 2008, among the Company, JPMorgan Chase Bank, N.A. as Administrative Agent, Bank of Montreal as Syndication Agent, U.S. Bank National Association as Documentation Agent and the financial institutions named therein. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K dated November 3, 2008.

10.32		First Amendment to Second Amended and Restated Credit Agreement dated effective March 2, 2009, among the Company, JPMorgan Chase Bank, N.A. as Administrative Agent, and the financial institutions named therein. Filed herewith electronically.

11.		Statement Regarding Computation of Per Share Earnings. Not applicable.

12.		Statement Regarding Computation of Ratios. Not applicable.

14.		Code of Ethics. The Company’s Code of Business Conduct and Ethics is posted on the Company’s website at www.deltapetro.com.

16.		Letter re: change in certifying accountant. Not applicable.

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders
Delta Petroleum Corporation:

We have audited the accompanying consolidated balance sheets of Delta Petroleum Corporation and subsidiaries as of December 31, 2008, and 2007, and the related consolidated statements of operations, changes in stockholders’ equity and comprehensive income (loss), and cash flows for each of the years in the three year period ended December 31, 2008. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Delta Petroleum Corporation and subsidiaries as of December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the years in the three year period ended December 31, 2008, in conformity with U.S. generally accepted accounting principles.

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in note 2 to the consolidated financial statements, the Company has suffered recurring losses from operations, has a working capital deficiency, and was not in compliance with its debt covenants at December 31, 2008 which raise substantial doubt about its ability to continue as a going concern. Management’s plans in regard to these matters are also described in note 2. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Delta Petroleum Corporation’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated March 2, 2009 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

As discussed in note 3 to the consolidated financial statements, Delta Petroleum Corporation adopted FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes – an Interpretation of FASB Statement No. 109, effective January 1, 2007.

KPMG LLP

Denver, Colorado
March 2, 2009

F-1

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders
Delta Petroleum Corporation:

We have audited Delta Petroleum Corporation’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Delta Petroleum Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

In our opinion, Delta Petroleum Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Delta Petroleum as of December 31, 2008 and 2007, and the related consolidated statements of operations, changes in stockholders’ equity and comprehensive income (loss), and cash flows for each of the years in the three-year period ended December 31, 2008, and our report dated March 2, 2009 expressed an unqualified opinion on those consolidated financial statements.

KPMG LLP

Denver, Colorado
March 2, 2009

F-2

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


	December 31,			December 31,
	2008			2007
	(In thousands, except for shares)
ASSETS
Current assets:
Cash and cash equivalents	$	65,475		$	9,793
Short-term restricted deposit		100,000			-
Trade accounts receivable, net of allowance for doubtful accounts, of $652 and $664, respectively		30,437			38,761
Deposits and prepaid assets		11,253			3,943
Inventories		9,140			4,236
Derivative instruments		-			2,930
Deferred tax assets		231			150
Assets held for sale		-			63,749
Other current assets		6,360			10,214

Total current assets		222,896			133,776

Property and equipment:
Oil and gas properties, successful efforts method of accounting:
Unproved		415,573			247,466
Proved		1,365,440			749,393
Drilling and trucking equipment		194,223			146,097
Pipeline and gathering systems		86,076			25,264
Other		29,107			15,945

Total property and equipment		2,090,419			1,184,165
Less accumulated depreciation and depletion		(658,279	)		(245,153	)

Net property and equipment		1,432,140			939,012


Long-term assets:
Long-term restricted deposit		200,000			-
Marketable securities		1,977			6,566
Investments in unconsolidated affiliates		17,989			10,281
Deferred financing costs		7,952			7,187
Goodwill		-			7,747
Other long-term assets		12,460			6,075

Total long-term assets		240,378			37,856


Total assets	$	1,895,414		$	1,110,644


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Credit facility - Delta	$	294,475		$	-
Installments payable on property acquisition		97,453			-
Accounts payable		159,024			119,783
Other accrued liabilities		13,576			17,118
Derivative instruments		-			6,295

Total current liabilities		564,528			143,196

Long-term liabilities:
Installments payable on property acquisition, net of current portion		188,334			-
7% Senior notes		149,534			149,459
3³/4% Senior convertible notes		115,000			115,000
Credit facility - Delta		-			73,600
Credit facility - DHS		93,848			75,000
Asset retirement obligations		6,585			4,154
Deferred tax liabilities		1,024			9,085

Total long-term liabilities		554,325			426,298

Minority interest		29,104			27,296

Commitments and contingencies

Stockholders’ equity:
Preferred stock, $.01 par value; authorized 3,000,000 shares, none issued		-			-
Common stock, $.01 par value; authorized 300,000,000 shares, issued 103,424,000 shares at December 31, 2008, and 66,429,000 shares at December 31, 2007		1,034			664
Additional paid-in capital		1,350,502			664,733
Treasury stock at cost; 36,000 shares at December 31, 2008 and none at December 31, 2007		(540	)		-
Accumulated deficit		(603,539	)		(151,543	)

Total stockholders’ equity		747,457			513,854


Total liabilities and stockholders’ equity	$	1,895,414		$	1,110,644

See accompanying notes to consolidated financial statements.

F-3

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS


	Years Ended December 31,
	2008			2007			2006
	(In thousands, except per share amounts)
Revenue:
Oil and gas sales	$	221,733		$	123,729		$	102,540
Contract drilling and trucking fees		49,445			58,358			59,603
Gain (loss) on hedging instruments, net		-			12,854			(4,712	)

Total revenue		271,178			194,941			157,431

Operating expenses:
Lease operating expense		33,508			20,882			17,811
Transportation expense		11,395			4,074			1,089
Production taxes		12,075			7,463			5,308
Exploration expense		10,975			9,062			4,690
Dry hole costs and impairments		438,963			87,459			16,001
Depreciation, depletion, amortization and accretion – oil and gas		99,125			73,875			55,245
Drilling and trucking operating expenses		32,594			37,698			35,504
Goodwill and drilling equipment impairments		29,349			-			-
Depreciation and amortization – drilling and trucking		14,134			16,021			13,010
General and administrative expense		53,607			49,621			35,696
Gain on sale of oil and gas properties		-			-			(20,034	)

Total operating expenses		735,725			306,155			164,320


Operating loss		(464,547	)		(111,214	)		(6,889	)

Other income and (expense):
Interest expense and financing costs		(41,421	)		(29,279	)		(26,891	)
Interest income		10,132			2,080			575
Other income (expense)		(5,210	)		376			(154	)
Realized gain on derivative instruments, net		18,383			917			-
Unrealized gain (loss) on derivative instruments, net		3,365			(3,819	)		11,722
Gain on sale of investment in LNG		-			-			1,058
Minority interest in losses (income) of subsidiary		11,486			1,231			(2,595	)
Income (loss) from unconsolidated affiliates		3,375			(393	)		-

Total other income (expense)		110			(28,887	)		(16,285	)


Loss from continuing operations before income taxes and discontinued operations		(464,437	)		(140,101	)		(23,174	)

Income tax expense (benefit)		(11,723	)		5,010			(8,546	)


Loss from continuing operations		(452,714	)		(145,111	)		(14,628	)

Discontinued operations:
Income from discontinued operations of properties sold or held for sale, net of tax		-			1,922			5,272
Gain (loss) on sale of discontinued operations, net of tax		718			(3,998	)		6,712


Loss before extraordinary gain, net of tax		(451,996	)		(147,187	)		(2,644	)

Extraordinary gain, net of tax		-			-			5,560


Net income (loss)	$	(451,996	)	$	(147,187	)	$	2,916


Basic income (loss) per common share:
Income (loss) from continuing operations	$	(4.74	)	$	(2.37	)	$	(0.28	)
Discontinued operations		0.01			(0.03	)		0.23
Extraordinary gain, net of tax		-			-			0.11

Net income (loss)	$	(4.73	)	$	(2.40	)	$	0.06


Diluted income (loss) per common share:
Income (loss) from continuing operations	$	(4.74	)	$	(2.37	)	$	(0.28	)
Discontinued operations		0.01			(0.03	)		0.23
Extraordinary gain, net of tax		-			-			0.10

Net income (loss)	$	(4.73	)	$	(2.40	)	$	0.05

See accompanying notes to consolidated financial statements.

F-4

DELTA PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’
EQUITY AND COMPREHENSIVE INCOME (LOSS)


															Accumulated
							Additional								other
	Common stock						paid-in			Treasury stock					comprehensive			Comprehensive			Accumulated
	Shares			Amount			capital			Shares		Amount			income (loss)			income (loss)			deficit			Total
										(In thousands)
Balance, December 31, 2005		47,825		$	478		$	333,054			–	$	–		$	(4,997	)				$	(7,272	)	$	321,263

Comprehensive income:
Net income		–			–			–			–		–			–		$	2,916			2,916			2,916
Other comprehensive income transactions, net of tax
Hedging loss reclassified to income upon settlement, net of tax benefit of $1,738		–			–			–			–		–			2,860			2,860			–			2,860
Change in fair value of derivative hedging instruments, net of tax expense of $4,315		–			–			–			–		–			7,002			7,002			–			7,002

Comprehensive income																		$	12,778

Shares issued for acquisition of Castle and oil and gas properties		2,473			25			47,307			–		–			–						–			47,332
Shares issued for cash, net of offering costs		1,500			15			33,855			–		–			–						–			33,870
Shares issued for drilling rig assets		350			3			8,291			–		–			–						–			8,294
Shares issued for cash or return of shares upon exercise of options or vesting of restricted stock		779			8			3,095			–		–			–						–			3,103
Issuance and amortization of non-vested stock		512			5			3,430			–					–						–			3,435
Compensation on options vested		–			–			1,447			–		–			–						–			1,447

Balance, December 31, 2006		53,439			534			430,479			–		–			4,865						(4,356	)		431,522

Comprehensive income:
Net loss		–			–			–			–		–			–		$	(147,187	)		(147,187	)		(147,187	)
Other comprehensive income transactions, net of tax
Hedging gains reclassified to income upon settlement		–			–			–			–		–			(13,920	)		(13,920	)		–			(13,920	)
Change in fair value of derivative hedging instruments,		–			–			–			–		–			6,025			6,025			–			6,025
Tax effect of valuation allowance		–			–			–			–		–			3,030			3,030			–			3,030

Comprehensive loss																		$	(152,052	)

Shares issued for oil and gas properties		1,229			12			23,753			–		–			–						–			23,765
Shares issued for cash, net of offering costs		9,898			99			196,435			–		–			–						–			196,534
Shares issued for cash or return of shares upon exercise of options or vesting of restricted stock		155			3			137			–		–			–						–			140
Issuance and amortization of non-vested stock		1,708			16			13,610			–		–			–						–			13,626
Compensation on options vested		–			–			319			–		–			–						–			319

Balance, December 31, 2007		66,429			664			664,733			–		–			–						(151,543	)		513,854

Comprehensive income:
Net loss		–			–			–			–		–			–		$	(451,996	)		(451,996	)		(451,996	)
Other comprehensive income transactions, net of tax Change in fair value of available for sale securities		–			–			–			–		–			(4,589	)		(4,589	)		–			(4,589	)
Loss on impairment of available for sale securities reclassified to earnings,		–			–			–			–		–			4,589			4,589			–			4,589

Comprehensive loss																		$	(451,996	)

Treasury stock acquired by subsidiary		–			–			–			36		(540	)		–						–			(540	)
Shares issued for cash, net of offering costs		36,263			363			666,680			–		–			–						–			667,043
Shares issued for cash upon exercise of options		540			5			4,822			–		–			–						–			4,827
Issuance of non-vested stock		1,089			11			(11	)		–		–			–						–			–
Shares repurchased for withholding taxes		(147	)		(1	)		(1,368	)		–		–			–						–			(1,369	)
Cancellation of executive performance shares, tranches 4 and 5		(750	)		(8	)		8			–		–			–						–			–
Stock based compensation		–			–			15,638			–		–			–						–			15,638

Balance, December 31, 2008		103,424		$	1,034		$	1,350,502			36	$	(540	)	$	–					$	(603,539	)	$	747,457

See accompanying notes to consolidated financial statements.

F-5

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Years Ended December 31,
	2008			2007			2006
				(In thousands)
Cash flows from operating activities:
Net Income (loss)	$	(451,996	)	$	(147,187	)	$	2,916
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion, and amortization – oil and gas		99,125			73,875			55,245
Depreciation and amortization – drilling and trucking		14,134			16,021			13,010
Depreciation, depletion, and amortization – discontinued operations		-			2,488			10,947
Stock option and non-vested stock compensation		15,638			15,590			4,882
Amortization of deferred financing costs		5,248			4,429			2,396
Unrealized (gain) loss on derivative contracts		(3,365	)		5,816			(12,205	)
Dry hole costs and impairments		438,963			86,466			12,216
Drilling equipment and goodwill impairment		29,349			-			-
Amortization of discount on installment payable		6,082			-			-
Minority interest in (losses) income of subsidiary		(11,486	)		(1,231	)		2,595
Gain on sale of oil and gas properties		-			-			(20,034	)
Equity (income) loss from equity method investments		(2,909	)		393			-
Unrealized loss on marketable securities		4,590			-			-
Gain on sale of investment in LNG		-			-			(1,058	)
Loss (gain) on sale of discontinued operations		(718	)		2,644			(10,775	)
Extraordinary gain on Castle acquisition		-			-			(8,776	)
DHS stock granted to management as compensation		478			245			280
Deferred income tax expense (benefit)		(11,723	)		6,446			1,205
Other non-cash items, net		61			141			319
Net changes in operating assets and liabilities:
Increase in trade accounts receivable		1,337			(4,316	)		(4,501	)
(Increase) decrease in prepaid assets		(7,381	)		441			(731	)
(Increase) decrease in inventories		(2,922	)		(1,385	)		434
(Increase) decrease in other current assets		(114	)		713			(438	)
Increase in accounts payable		17,590			25,219			4,477
Increase in other accrued liabilities		695			195			2,095


Net cash provided by operating activities		140,676			87,003			54,499


Cash flows from investing activities:
Additions to oil and gas properties		(457,947	)		(333,287	)		(219,874	)
Additions to drilling and trucking equipment		(52,970	)		(22,292	)		(63,848	)
Acquisitions, net of cash acquired		(221,815	)		(4,500	)		(8,564	)
Proceeds from sale of oil and gas properties		42,000			46,193			82,716
Proceeds from sale of drilling assets		3,201			7,145			-
Increase in marketable securities		-			(6,517	)		-
Increase in restricted deposit		(300,000	)		-			-
Investment in unconsolidated affiliates		(6,475	)		(4,322	)		-
Loans to affiliate		(490	)		(8,511	)		-
Minority interest holder contributions (distributions), net		12,000			(355	)		9,018
(Increase) decrease in other long-term assets		(120	)		(106	)		(3,646	)


Net cash used in investing activities		(982,616	)		(326,552	)		(204,198	)


Cash flows from financing activities:
Stock issued for cash upon exercise of options		4,827			137			3,711
Stock repurchased for withholding taxes		(1,368	)		(1,381	)		-
Stock issued for cash, net		662,043			202,084			33,870
Proceeds from borrowings		375,463			343,600			220,035
Payment of financing fees		(7,590	)		(4,897	)		(3,994	)
Repayment of borrowings		(135,753	)		(297,867	)		(101,776	)


Net cash provided by financing activities		897,622			241,676			151,846


Net increase in cash and cash equivalents		55,682			2,127			2,147


Cash at beginning of year		9,793			7,666			5,519


Cash at end of year	$	65,475		$	9,793		$	7,666


Supplemental cash flow information:
Cash paid for interest and financing costs	$	27,588		$	23,351		$	24,640


Non-cash financing activities:
Common stock issued for the purchase of Castle and oil and gas properties	$	-		$	23,765		$	47,332


Common stock issued for the purchase of drilling and trucking equipment	$	-		$	-		$	8,294

See accompanying notes to consolidated financial statements.

F-6

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES

Notes to Consolidated Financial Statements
December 31, 2008, 2007 and 2006

(1) Nature of Organization

Delta Petroleum Corporation (“Delta” or the “Company”) was organized December 21, 1984 as a Colorado corporation and is principally engaged in acquiring, exploring, developing and producing oil and gas properties. On January 31, 2006, the Company reincorporated in the state of Delaware. The Company’s core areas of operation are the Rocky Mountain and Gulf Coast Regions, which comprise the majority of its proved reserves, production and long-term growth prospects. The Company owns interests in developed and undeveloped oil and gas properties in federal units offshore California, near Santa Barbara, and developed and undeveloped oil and gas properties in the continental United States.

The Company owns a 49.8% interest in DHS Drilling Company (“DHS”), an affiliated Colorado corporation that is headquartered in Casper, Wyoming. Delta representatives currently constitute a majority of the members of the Board of DHS and Delta has the right to use all of the rigs owned by DHS on a priority basis. 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 include both DHS Holding Company and DHS, unless the context otherwise requires. DHS is a consolidated subsidiary of Delta.

At December 31, 2008, the Company owned 4,277,977 shares of the common stock of Amber Resources Company of Colorado (“Amber”), representing 91.68% of the outstanding common stock of Amber. Amber is a public company that owns undeveloped oil and gas properties in federal units offshore California, near Santa Barbara.

(2) Going Concern

The accompanying financial statements have been prepared assuming the Company will continue as a going concern. As shown in the accompanying financial statements, the Company experienced a net loss of $452.0 million for the year ended December 31, 2008, has a working capital deficiency of $341.6 million, including $294.5 million outstanding under its credit facility, and is facing significant immediate and long-term obligations in excess of its existing sources of liquidity, which raise substantial doubt about the Company’s ability to continue as a going concern.

At December 31, 2008, the Company was not in compliance with the current ratio and accounts payable covenants under its senior credit facility. In addition, pursuant to a redetermination made as of February 1, 2009, the borrowing base under the senior credit facility will be reduced upon the successful completion of our capital raising efforts to $225.0 million, which will require a repayment of $68.8 million based on outstanding borrowings of $293.8 million at March 2, 2009. The lenders have entered into the First Amendment to the Company’s Second Amended and Restated Credit Agreement (the “Forbearance Agreement and Amendment to the Credit Facility”) dated March 2, 2009 under which they have agreed not to take action with respect to ongoing defaults or borrowing base deficiencies for a period of at least 45 days, or longer dependent on the progress of the Company’s capital raising efforts, and to amend the terms of the credit facility for 2009 (see Note 21).

The Company is subject to contractual obligations to jointly develop a portion of EnCana’s leasehold in the Vega Area of the Piceance Basin. Under the terms of the agreement dated February 28, 2008, the Company has committed to fund $410.1 million, of which $110.5 million was paid at the closing and installments of $99.6 million, $100.0 million, and $100.0 million are payable November 1, 2009, 2010, and 2011, respectively. These remaining installments are collateralized by a letter of credit, which in turn are collateralized by cash on deposit in a restricted account. The installment payments are 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 Company had $159.0 million of accounts payable at December 31, 2008, which if not timely paid could result in liens filed against the Company’s properties or withdrawal of trade credit provided by vendors, which in turn could limit the Company’s availability to conduct operations on its properties.

F-7

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2008, 2007 and 2006

(2) Going Concern, Continued

As contemplated by the Forbearance Agreement and Amendment to the Credit Facility, the Company is engaged in capital raising efforts to raise net proceeds of at least $140.0 million on or before the forbearance termination date. The Company would use such net proceeds to reduce its amounts outstanding under the facility to not more than $225.0 million and pay accounts payable. Such efforts include potential sales of equity or debt securities, asset sales, joint ventures or similar industry partnerships. The Company has reduced its capital expenditure budget for 2009 to $52.0 million.

Depending on the amount of proceeds obtained from capital raising efforts, the Company will evaluate the need to raise additional capital. There can be no assurance that the actions undertaken by the Company will be sufficient to repay the obligations under the senior credit facility at the conclusion of the periods contemplated by the Forbearance Agreement and Amendment to the Credit Facility, or, if not sufficient, or if additional defaults occur under that facility, that the lenders will be willing to waive the defaults or amend the facility. In addition, there can be no assurance that cash flow from operations and other sources of liquidity, including asset sales or joint venture or other industry partnerships, will be sufficient to meet contractual, operating and capital obligations. The financial statements do not include any adjustments that might result from the outcome of uncertainty regarding the Company’s ability to raise additional capital, sell assets, or otherwise obtain sufficient funds to meet its obligations.

(3) Summary of Significant Accounting Policies

Principles of Consolidation and Basis of Presentation

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

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

During June 2007, the Company acquired a 50% non-controlling ownership interest in Delta Oilfield Tank Company, LLC (“Delta Oilfield”) for cash consideration of $4.0 million. Delta Oilfield is accounted for using the equity method of accounting and is an unconsolidated affiliate of the Company. In conjunction with the investment, the Company entered into an agreement to finance up to $9.0 million for construction of a plant expansion. As of December 31, 2008, the Company had advanced $9.0 million to Delta Oilfield under this agreement, of which $2.2 million is included in other current assets in the accompanying consolidated balance sheets. The loan is payable quarterly, beginning after the expansion is complete, in an amount equal to 75% of distributable cash of Delta Oilfield, as defined, with any remaining balance due December 31, 2010.

F-8

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2008, 2007 and 2006

(3) Summary of Significant Accounting Policies, Continued

Certain reclassifications have been made to amounts reported in previous years to conform to the current year presentation. Among other items, revenues and expenses on properties that are held for sale at December 31, 2008 have been reclassified to income from discontinued operations for all periods presented. Such reclassifications had no effect on net income.

Cash Equivalents

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

Marketable Securities

During 2007, the Company held investments in securities that were classified as trading securities and thus recorded at estimated fair value with interest, dividend income, and changes in market value recognized in earnings. The Company recorded $334,000 of losses related to these securities during the year ended December 31, 2007. Due to the marketplace changes in late 2007 affecting the liquidity of such investments, the Company reclassified the securities from trading to available for sale as of December 31, 2007. Accordingly, the marketable securities are recorded in long term assets in the accompanying consolidated balance sheet with changes in their fair value initially recorded in accumulated other comprehensive loss. During 2008, the Company determined that the securities had incurred an other than temporary loss and an impairment charge of $4.6 million was recorded in other expense during the year ended December 31, 2008. If the issuers of the securities continue to unsuccessfully close future auctions and their credit ratings deteriorate, the Company may be required to record additional impairment charges on these investments.

Oil and Gas Properties Held for Sale

Oil and Gas Properties held for sale as of December 31, 2007 represent the Company’s Midway Loop oil and gas properties in Texas that were for sale. As a result of the significant decline in commodity prices and substantial changes in other marketplace conditions, the Company subsequently determined not to sell these properties and accordingly the properties have been reclassified to property and equipment in the accompanying consolidated balance sheet as of December 31, 2008 and to continuing operations in the consolidated statements of operations for all periods presented. The Company recorded an impairment charge of $52.7 million to reduce the carrying value of the properties to their estimated fair value upon the determination.

Inventories

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

Minority Interest

Minority interest represents the 49.8% (47.2% for Chesapeake Energy Corporation and 3% for DHS executive officers and management) investors of DHS at December 31, 2008 and 2007, respectively. Minority interest for December 31, 2006 represents 50.6% (45% for Chesapeake Energy Corporation and 5.6% for DHS executive officers and management) investors of DHS at December 31, 2006. During 2007, the ownership interest of one of the founding officers was repurchased by DHS, resulting in a slight increase in Delta’s ownership of DHS.

F-9

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2008, 2007 and 2006

(3) Summary of Significant Accounting Policies, Continued

Revenue Recognition

Oil and Gas

Revenues are recognized when title to the products transfers to the purchaser. The Company follows the “sales method” of accounting for its natural gas and crude oil revenue, so that the Company recognizes sales revenue on all natural gas or crude oil sold to its purchasers, regardless of whether the sales are proportionate to the Company’s ownership in the property. A liability is recognized only to the extent that the Company has an imbalance on a specific property greater than the expected remaining proved reserves. As of the years ended December 31, 2008 and 2007, the Company’s aggregate natural gas and crude oil imbalances were not material to its consolidated financial statements.

Drilling and Trucking

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

Property and Equipment

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

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

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

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

Depreciation, depletion and amortization of oil and gas property and equipment for the years ended December 31, 2008, 2007 and 2006 were $99.1 million, $73.9 million, and $55.2 million, respectively.

F-10

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2008, 2007 and 2006

(3) Summary of Significant Accounting Policies, Continued

Impairment of Long-Lived Assets

Statement of Financial Accounting Standards No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets” (“SFAS 144”) requires that long-lived assets be reviewed for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable.

Estimates of expected future cash flows represent management’s best estimate based on reasonable and supportable assumptions and projections. If the expected future cash flows exceed the carrying value of the asset, no impairment is recognized. If the carrying value of the asset exceeds the expected future cash flows, an impairment exists and is measured by the excess of the carrying value over the estimated fair value of the asset. Any impairment provisions recognized in accordance with SFAS 144 are permanent and may not be restored in the future.

The Company assesses proved properties on an individual field basis for impairment on at least an annual basis. During the year ended December 31, 2008, the Company recorded impairments on proved properties totaling approximately $236.0 million primarily related to the Newton, Midway Loop, and Opossum Hollow fields in Texas ($172.1 million), the Paradox field in Utah ($26.2 million), the Howard Ranch and Bull Canyon fields in the Rockies ($27.9 million) and the Company’s 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, the Company recorded an impairment to the Paradox pipeline ($21.5 million) in 2008.

For unproved properties, the need for an impairment is based on the Company’s plans for future development and other activities impacting the life of the property and the ability of the Company to recover its investment. When the Company believes the costs of the unproved property are no longer recoverable, an impairment charge is recorded based on the estimated fair value of the property. As a result of such assessment, during the year ended December 31, 2008, the Company recorded impairments of its unproved properties totaling $66.4 million, primarily related to Utah Hingeline ($40.2 million), Opossum Hollow, Newton and Angleton in Texas ($19.2 million), certain prospects in Colorado ($4.0 million), and the Paradox basin in Utah ($3.0 million). The Company recorded no impairment provision attributable to unproved properties for the years ended December 31, 2007 and 2006.

For the fiscal year 2009, the Company plans to develop and evaluate certain proved and unproved properties. Favorable or unfavorable drilling results or changes in commodity prices may cause a revision to estimates of those properties’ future cash flows. Such revisions of estimates could require the Company to record additional impairments in the period of such revisions.

F-11

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2008, 2007 and 2006

(3) Summary of Significant Accounting Policies, Continued

Goodwill

Goodwill represents the excess of the cost of the acquisitions by DHS of C&L Drilling in May 2006, Rooster Drilling in March 2006, and Chapman Trucking in November 2005 over the fair value of the assets and liabilities acquired. For goodwill and intangible assets recorded in the financial statements, an impairment test is performed at least annually in accordance with the provisions of SFAS No. 142, “Goodwill and Other Intangible Assets,” (“SFAS 142”). Although no impairment of goodwill was indicated as a result of the Company’s annual impairment test performed during the third quarter of 2008, an impairment for the full amount of goodwill ($7.7 million) was recorded during the fourth quarter of 2008 as a result of impairment testing prompted by the decline in commodity prices resulting in the deteriorating utilization rate of the Company’s rig fleet in the fourth quarter.

Asset Retirement Obligations

The Company’s asset retirement obligations arise from the plugging and abandonment liabilities for its oil and gas wells. The Company has no obligation to provide for the retirement of most of its offshore properties as the obligations remained with the seller from whom the Company acquired the properties. The following is a reconciliation of the Company’s asset retirement obligations for the years ended December 31, 2008, 2007 and 2006:


	Years Ended December 31,
	2008			2007			2006
	(In thousands)
Asset retirement obligation – beginning of period	$	5,199		$	4,421		$	3,467
Accretion expense		436			278			199
Change in estimates		1,883			313			639
Obligations acquired		2,579			1,743			850
Obligations settled		(1,065	)		(224	)		(139	)
Obligations on sold properties		(296	)		(1,332	)		(595	)

Asset retirement obligation – end of period		8,736			5,199			4,421
Less: Current asset retirement obligation		(2,151	)		(1,045	)		(408	)

Long-term asset retirement obligation	$	6,585		$	4,154		$	4,013

Financial Instruments

The Company’s financial instruments that are exposed to concentrations of credit risk consist primarily of cash equivalents, marketable securities and accounts receivable. The Company’s cash equivalents are funds that are placed with major financial institutions. The Company manages and controls market and credit risk through established formal internal control procedures, which are reviewed on an ongoing basis. The Company attempts to minimize credit risk exposure to purchasers of the Company’s oil and natural gas through formal credit policies, monitoring procedures, and letters of credit.

The Company used various assumptions and methods in estimating fair value disclosures for financial instruments. The carrying amounts of cash and cash equivalents and accounts receivable approximated their fair value due to the short maturity of these instruments. The carrying amount of the Company’s credit facility approximated fair value because the interest rates on the credit facility are variable. The fair value of long-term debt was estimated based on quoted market prices. The fair values of derivative instruments were estimated based on discounted future net cash flows or market quotes.

Accounting and reporting standards require that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its fair value. Those standards also require that changes in the derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument be reported as a component of Accumulated Other Comprehensive Income (Loss) and be reclassified into earnings in the same period or periods during which the hedged forecasted transaction affects earnings. The Company had no such qualifying hedging instruments at December 31, 2008 and 2007.

F-12

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2008, 2007 and 2006

(3) Summary of Significant Accounting Policies, Continued

Stock Based Compensation

The Company follows SFAS No. 123 (Revised 2004) “Share Based Payment” (“SFAS 123R”) to value stock options and other equity based compensation issued to employees. The cost of share based payments is recognized over the period the employee provides service and is included in general and administrative expense in the statements of operations.

Non-Qualified Stock Options - Directors and Employees

On February 9, 2007, the Company issued executive performance share grants to each of the Company’s four executive officers (Roger Parker — Chief Executive Officer, John Wallace — President, Kevin Nanke — Chief Financial Officer, and Ted Freedman — Senior Vice President and General Counsel) that provide that the shares of common stock awarded will vest if the market price of Delta stock reaches and maintains certain price levels. The awards will vest in five tranches on the dates that the average daily closing price of Delta’s common stock equals or exceeds a defined price for a specified number of trading days within any period of 90 calendar days (a “Vesting Threshold”).

The Vesting Threshold for the first tranche is $40, for the second tranche, $50, for the third tranche, $60, for the fourth tranche, $75 and for the fifth tranche, $90. Upon attaining the Vesting Threshold for each of the first, second and third tranches, 100,000 of Mr. Parker’s shares would vest for each such tranche, 70,000 of Mr. Wallace’s shares would vest for each such tranche and 40,000 of Mr. Nanke’s and Mr. Freedman’s shares would each vest for each such tranche. The $75 and $90 tranches lapsed effective March 31, 2008 and the $50 and $60 tranches will also lapse if the $40 tranche has not vested on or before March 31, 2009. In addition, the grants will lapse and be forfeited to the extent not vested prior to a termination of the executive’s employment, and will be forfeited to the extent not vested on or before January 29, 2017. The awards also provide for a minimum 364-day period between achievement of two vesting thresholds, subject to acceleration of vesting upon a change in control at a price in excess of one or more of the stock price thresholds, with proportional vesting should a change in control occur at a price in excess of one threshold, but below the next threshold.

The performance share grants were valued at $18.4 million, in the aggregate, with derived service periods over which the value of each tranche is expensed ranging from 1 to 5 years. Equity compensation of $5.7 and $6.9 million related to the performance share grants was included in general and administrative expense during the years ended December 31, 2008 and 2007, respectively.

Income Taxes

The Company uses the asset and liability method of accounting for income taxes as set forth in SFAS No. 109, “Accounting for Income Taxes” (“SFAS 109”). Under the asset and liability method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and net operating loss and tax credit carry-forwards. Deferred tax assets and liabilities are measured using enacted income tax rates expected to apply to taxable income in the years in which those differences are expected to be recovered or settled. Under SFAS 109, the effect on deferred tax assets and liabilities of a change in income tax rates is recognized in the results of operations in the period that includes the enactment date. Deferred tax assets are recorded based on the “more likely than not” requirements of SFAS 109, and to the extent this threshold is not met, a valuation allowance is recorded. The Company is currently providing a full valuation allowance on its net deferred tax assets. Deferred tax assets and liabilities are recorded by DHS on the same basis of accounting, although no valuation allowance has been provided for its deferred tax assets.

F-13

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2008, 2007 and 2006

(3) Summary of Significant Accounting Policies, Continued

Income (Loss) per Common Share

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

Use of Estimates

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

Recently Issued Accounting Standards and Pronouncements

In March 2008, the FASB affirmed FASB Staff Position (“FSP”) APB 14-a, “Accounting for Convertible Debt Instruments That May Be Settled in Cash Upon Conversion (Including Partial Cash Settlement)”. The FSP 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. The FSP is effective for fiscal years beginning after December 15, 2008, or first quarter 2009 for the Company. This FSP changes the accounting treatment for the Company’s 3³/4% Senior Convertible Notes issued April 25, 2007 since it is to be applied retrospectively upon adoption. Based on the Company’s stock price on the date of the original issuance, the terms of the Notes, and other inputs, the liability component of the issuance was approximately $54.9 million and the equity component of the issuance was approximately $60.1 million. Based on these components at the issue date the Company will record accretion of debt discount for 2007 and 2008 of approximately $0.9 million and $1.4 million, respectively, and a reduction to the carrying value of the Notes of $57.7 million upon adoption of the FSP.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133 (“SFAS 161”). This Statement requires enhanced disclosures for derivative and hedging activities. This statement is effective for financial statements issued for fiscal years beginning after November 15, 2008, or fiscal year 2009. The Company is currently evaluating the potential impact of the adoption of SFAS 161 on the disclosures in its consolidated financial statements.

In December 2007, the FASB issued SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS 141R”), which replaces SFAS 141. SFAS 141R establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any resulting goodwill, and any noncontrolling interest in the acquiree. The Statement also provides for disclosures to enable users of the financial statements to evaluate the nature and financial effects of the business combination. SFAS 141R is effective for financial statements issued for fiscal years beginning after December 15, 2008, or fiscal year 2009, and must be applied prospectively to business combinations completed on or after that date.

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements — an amendment of Accounting Research Bulletin No. 51” (“SFAS 160”), which establishes accounting and reporting standards for noncontrolling interests (“minority interests”) in subsidiaries. SFAS 160 clarifies that a noncontrolling interest in a subsidiary should be accounted for as a component of equity separate from the parent’s equity. SFAS 160 is effective for financial statements issued for fiscal years beginning after December 15, 2008, or fiscal year

F-14

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2008, 2007 and 2006

(3) Summary of Significant Accounting Policies, Continued

2009, and must be applied prospectively, except for the presentation and disclosure requirements, which will apply retrospectively. The Company adopted the provisions of SFAS 160 on January 1, 2009. Beginning with the first quarter 2009 reporting period and for prior comparative periods, the Company will present noncontrolling interests, currently referred to as minority interests in the accompanying consolidated balance sheets, as a component of stockholders’ equity. The adoption of SFAS 160 will not have a material impact on the consolidated financial statements; however, it could impact our accounting for future transactions.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS 159”). SFAS 159 permits companies to choose to measure many financial instruments and certain other items at fair value. SFAS 159 is effective for financial statements issued for fiscal years beginning after November 15, 2007, or fiscal year 2008. The Company adopted SFAS 159 effective January 1, 2008, but did not elect to apply the SFAS 159 fair value option to eligible assets and liabilities during the year ended December 31, 2008.

In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, “Fair Value Measurements” (“SFAS 157”), which defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and requires additional disclosures about fair value measurements. SFAS 157 aims to improve the consistency and comparability of fair value measurements by creating a single definition of fair value. The Statement emphasizes that fair value is not entity-specific, but instead is a market-based measurement of an asset or liability. SFAS 157 reaffirms the requirements of previously issued pronouncements concerning fair value measurements and expands the required disclosures. In February 2008, the FASB issued FSP No. 157-2. FSP No. 157-2 delays the effective date of SFAS 157 for one year for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). The Company has not yet applied the provisions of SFAS 157 which relate to non-recurring nonfinancial assets and nonfinancial liabilities.

Effective January 1, 2008, the Company adopted the provisions of SFAS 157 for fair value measurements not delayed by FSP No. 157-2. The adoption resulted in additional disclosures as required by the pronouncement (See Note 5, “Fair Value Measurements”) related to the fair value measurements for oil and gas derivatives and marketable securities but did not change the fair value calculation methodologies. Accordingly, the adoption had no impact on the Company’s financial condition or results of operations.

(4) Oil and Gas Properties

Unproved Undeveloped Offshore California Properties

The Company has direct and indirect ownership interests ranging from 2.49% to 100% in five unproved undeveloped offshore California oil and gas properties with aggregate carrying values of $17.0 million and $14.8 million at December 31, 2008 and 2007, respectively. These property interests are located in proximity to existing producing federal offshore units near Santa Barbara, California and represent the right to explore for, develop and produce oil and gas from offshore federal lease units. The recovery of the Company’s investment in these properties through the sale of hydrocarbons would require extensive exploration and development activities (and costs) that cannot proceed without certain regulatory approvals that have been delayed, and is therefore subject to other substantial risks and uncertainties.

F-15

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2008, 2007 and 2006

(4) Oil and Gas Properties, Continued

The Company is not the designated operator of any of these properties but is an active participant in the ongoing activities of each property along with the designated operator and other interest owners. If the designated operator elected not to or was unable to continue as the operator, the other property interest owners would have the right to designate a new operator as well as share in additional property returns prior to the replaced operator being able to receive returns. Based on the Company’s size, it would be difficult for the Company to proceed with exploration and development plans should other substantial interest owners elect not to proceed; however, to the best of its knowledge, the Company believes the designated operators and other major property interest owners would proceed with exploration and development plans under the terms and conditions of the operating agreement if they were permitted to do so by regulators.

Based on indications of levels of hydrocarbons present from drilling operations conducted in the past, the Company believes the fair values of its property interests are in excess of their carrying values at December 31, 2008 and that no impairment in the carrying value has occurred. Should the required regulatory approvals not be obtained or plans for exploration and development of the properties not continue, the carrying value of the properties would likely be impaired and written off.

The ownership rights in each of these properties have been retained under various suspension notices issued by the Mineral Management Service (MMS) of the U.S. federal government whereby, as long as the owners of each property were progressing toward defined milestone objectives, the owners’ rights with respect to the properties will continue to be maintained. The issuance of the suspension notices has been necessitated by the numerous delays in the exploration and development process resulting from regulatory requirements imposed on the property owners by federal, state and local agencies.

In 2001, however, a Federal Court in the case of California v. Norton, et al. ruled that the MMS does not have the power to grant suspensions on the subject leases without first making a consistency determination under the Coastal Zone Management Act (“CZMA”), and ordered the MMS to set aside its approval of the suspensions of the Company’s offshore leases and to direct suspensions for a time sufficient for the MMS to provide the State of California with the required consistency determination. In response to the ruling in the Norton case, the MMS made a consistency determination under the CZMA and the leases are still valid.

Further actions to develop the leases have been delayed, however, pending the outcome of a separate lawsuit (the “Amber case”) that was filed in the United States Court of Federal Claims (the “Court”) in Washington, D.C. by the Company, its 92%-owned subsidiary, Amber, and ten other property owners alleging that the U.S. government materially breached the terms of forty undeveloped federal leases, some of which are part of the Company’s and Amber’s offshore California properties. On November 15, 2005 and October 31, 2006, the Court granted summary judgment as to liability and partial summary judgment as to damages with respect to thirty six of the forty total federal leases that are the subject of the litigation. Under a restitution theory of damages, the Court ruled that the government must give back to the current lessees the more than $1.1 billion in lease bonuses it had received at the time of sale. On January 19, 2006, the government filed a motion for reconsideration of the Court’s ruling as it relates to a single lease owned entirely by the Company (“Lease 452”). In its motion for reconsideration, the government asserted that the Company should not be able to recover lease bonus payments for Lease 452 because, allegedly, a significant portion of the hydrocarbons had been drained by wells that were drilled on an immediately adjacent lease. The amount of lease bonus payments attributable to Lease 452 is approximately $92.0 million. A trial on the motion for reconsideration was completed in January 2008 and on February 25, 2009 the Court entered a judgment in the Company’s favor in the amount of $91.4 million. This judgment is subject to appeal by the government.

F-16

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2008, 2007 and 2006

(4) Oil and Gas Properties, Continued

On January 12, 2007, the Court entered an order of final judgment awarding the lessees restitution of the original lease bonuses paid for thirty five of the forty lawsuit leases. Under this order, the Company is entitled to receive a gross amount of approximately $58.5 million, and Amber is entitled to receive a gross amount of approximately $1.5 million as reimbursement for the lease bonuses paid for all lawsuit leases other than Lease 452. The order of final judgment was affirmed in all respects by the United States Court of Appeals for the Federal Circuit on August 25, 2008, and the government’s petition seeking a rehearing of that decision was denied on December 5, 2008; however, on December 24, 2008, the Federal Circuit entered an order imposing a stay of the issuance of its mandate for a period of 90 days pending consideration of and the possible filing by the government of a petition for writ of certiorari with the United States Supreme Court. On February 23, 2009, the Supreme Court granted the government’s application for a thirty day extension, to and including April 4, 2009, to file a petition for a writ of certiorari. The government asserts in its application that it has not yet determined whether it will ultimately file such a petition in this case.

No payments will be made until all appeals have either been waived or exhausted. In the event that the Company ultimately receives any proceeds as the result of this litigation, it will be obligated to use a portion to pay the litigation expenses and to fulfill certain contractual commitments to third parties that grant them an overriding royalty on the litigation proceeds in an aggregate amount of approximately 8%.

If new activities are commenced on any of the leases, the requisite exploration and development plans will be subject to review by the California Coastal Commission for consistency with the CZMA and by the MMS for other technical requirements. None of the leases is currently considered impaired, but in the event that they are found not to be valid for some reason in the future, it would appear that they would become impaired. For example, if there is a future adverse ruling by the California Coastal Commission under the CZMA and the Company decides not to appeal such ruling to the Secretary of Commerce, or the Secretary of Commerce either refuses to hear the Company’s appeal of any such ruling or ultimately makes an adverse determination, it is likely that some or all of these leases would become impaired and written off at that time. It is also possible that other events could occur that would cause the leases to become impaired, and the Company will continuously evaluate those factors as they occur.

Year Ended December 31, 2008 – Acquisitions

On September 15, 2008, the Company entered into an agreement with EnCana Oil & Gas (USA), Inc. (“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, the Company completed a separate transaction related to the Columbia River Basin wherein the Company sold a 50% working interest participation in all of the Company’s Columbia River Basin leaseholds and wells for cash consideration of $42.0 million plus one half of the drilling costs incurred to date on the Company’s well currently drilling in the area. This transaction included a 50% working interest in the leaseholds acquired from EnCana on September 15, 2008.

On August 25, 2008, the Company completed an asset exchange agreement in which the Company 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 on the exchange during the three months ended September 30, 2008.

In July and August 2008, the Company 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, the Company is obligated to spud an initial appraisal well by July 1, 2009.

On February 28, 2008, the Company closed a transaction with EnCana to jointly develop a portion of EnCana’s leasehold in the Vega Area of the Piceance Basin. Delta 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.

F-17

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2008, 2007 and 2006

(4) Oil and Gas Properties, Continued

Year Ended December 31, 2007 – Acquisitions

On October 1, 2007, the Company completed a transaction involving an exchange of Washington County, Colorado properties and cash consideration of $34.8 million, including customary purchase price adjustments, to acquire a 12.5% working interest in the Garden Gulch field in the Piceance Basin. The transaction was accounted for as a non-monetary transaction in relation to the exchange of assets with a nominal loss recorded on the divestiture of the Washington County assets equal to the fair value of the asset relinquished less its net book value. The acquisition basis of the Garden Gulch asset acquired was recorded equal to the fair value of the Washington County assets relinquished plus the additional cash consideration paid.

On June 8, 2007, the Company issued 475,000 shares of common stock valued at approximately $9.9 million using a 5-day average closing price to acquire an additional interest in one well already owned and operated by the Company, and an additional interest in a non-operated property, both located in Polk County, Texas.

On March 9, 2007, the Company issued 754,000 shares of common stock valued at approximately $13.8 million using a 5-day average closing price for additional interests in two wells already owned and operated by the Company located in Polk County, Texas.

Year Ended December 31, 2006 – Acquisitions

On April 28, 2006, Castle shareholders approved the merger agreement between Delta and Castle. As of that date, Delta via its merger subsidiary DPCA, acquired Castle for a purchase price of $33.6 million comprised of 1.8 million net shares issued (8,500,000 shares issued net of 6,700,000 Delta shares owned by Castle) valued at $31.2 million and $2.4 million of transaction costs. Delta obtained assets valued at $39.7 million which were comprised of cash, producing oil and gas properties located in Pennsylvania and West Virginia, and certain other assets. Due to the excess fair value of the assets acquired compared to the purchase price of the transaction and in accordance with SFAS No. 141 when acquired assets are held for sale in the near term, Delta recorded a $6.1 million extraordinary gain ($9.6 million, net of $3.5 million of deferred taxes) during the quarter ended June 30, 2006. The properties were actually sold during August 2006 and a true-up of the gain based on actual final proceeds from the sale was recorded. No pro forma information is presented because discontinued operations are not reported in revenue and earnings from continuing operations, and the information related to the acquisition would be the same as the amounts reported.

On February 1, 2006 Delta entered into a purchase and sale agreement with Armstrong Resources, LLC (“Armstrong”) to acquire a 65% working interest in approximately 88,000 undeveloped gross acres in the central Utah hingeline play for a purchase price of $24 million in cash and 673,401 shares of common stock valued at $16.1 million. The closing of the transaction was effective as of January 26, 2006. Armstrong retained the remaining 35% working interest in the acreage. As part of the transaction, Delta agreed to pay 100% of the drilling costs for the first three wells in the project. Delta is the operator of the majority of the acreage, and drilling of the first well commenced in November 2006, and the remaining two wells were drilled during the years ended December 31, 2007 and 2008.

Fiscal 2006 – Dispositions

During December 2005, Delta transferred its ownership in approximately 427,000 gross acres (64,000 net acres) of non-operated interests in the Columbia River Basin to CRBP. In January and March 2006, Delta sold a combined 44% minority interest in CRBP. As the sale involved unproved properties, no gain on the partial sale of CRBP is recognized until all of the cost basis of CRBP had been recovered. Accordingly, the Company recorded a $13.0 million gain ($8.1 million net of tax) and an $11.2 million reduction to property during the first quarter of 2006 as a result of closing the transaction.

F-18

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2008, 2007 and 2006

(4) Oil and Gas Properties, Continued

In March 2006, the Company sold approximately 26% of PGR. This transaction involved both proved and unproved property interests and accordingly, to the extent the sale of PGR related to unproved properties, no gain was recognized as all of the unproved cost basis was not yet recovered. The Company recorded a gain of $5.9 million, $3.7 million net of tax, and a $3.4 million offset to property during the first quarter of 2006 as a result of the transaction. The Company retained a 74% interest in PGR.

Discontinued Operations

The annual report on Form 10-K for the year ended December 31, 2007 and quarterly periods filed through September 30, 2008 included the Midway Loop, Texas properties in discontinued operations as they were previously classified as held for sale. Due to the decline in commodity prices and substantial changes in marketplace conditions, the Company determined not to sell these properties. As a result, for the year ended December 31, 2008 and for all prior periods presented, operating income and expenses for the Midway Loop properties are included in continuing operations in the consolidated statements of operations.

In accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” the results of operations and gain (loss) relating to the sale of the following property interests have been reflected as discontinued operations.

On September 4, 2007, the Company completed the sale of certain non-core properties located in North Dakota for cash consideration of approximately $6.2 million. The transaction resulted in a gain on sale of properties of $4.3 million.

On March 30, 2007, the Company 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, the Company 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, the Company 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.

Through a series of transactions during the year ended December 31, 2006, the Company completed the sale of certain non-core properties in East Texas and Louisiana for proceeds of $23.5 million and a combined after-tax gain of $6.7 million.

On August 21, 2006, the Company completed the sale of the properties acquired with the Castle acquisition in April 2006. During the year ended December 31, 2006, the Company recorded a $5.6 million extraordinary gain in accordance with SFAS No. 141.

F-19

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2008, 2007 and 2006

(4) Oil and Gas Properties, Continued

The following table shows the total revenues and income included in discontinued operations for the above mentioned oil and gas properties for the years ended December 31, 2008, 2007 and 2006 (in thousands):


	Years Ended December 31,
	2008		2007			2006

Revenues	$	-	$	6,914		$	28,639


Income from discontinued operations	$	-	$	2,008		$	8,481
Income tax expense		-		(86	)		(3,209	)


Income from discontinued operations, net of tax	$	-	$	1,922		$	5,272

(5) DHS Drilling Company

On December 31, 2008, the Company owned a 49.8% ownership interest in DHS Drilling Company. The remaining interest is owned by Chesapeake Energy Corporation, 47.2%, and 3% by DHS executive officers and management. Delta has the right to use all of the DHS rigs on a priority basis.

In January 2006, the Company purchased Rooster Drilling Company (“Rooster Drilling”) for 350,000 shares of Delta common stock valued at $8.3 million. Rooster Drilling owned one drilling rig, an Oilwell 66 with a depth capacity of 12,000 feet. Concurrent with the Company’s acquisition of Rooster Drilling, the Company and DHS entered into an operating agreement whereby DHS operated the rig (“Rig 15”) on behalf of the Company. In March 2006, the Company contributed Rooster Drilling (renamed “Hastings Drilling Company”) to DHS.

In March 2006, DHS issued additional common stock to Delta, Chesapeake, and officers and management of DHS in exchange for assets, cash and notes as described below. The Company contributed Rooster Drilling and additional cash totaling $9.9 million to DHS in exchange for 2.7 million shares of DHS common stock. Chesapeake contributed approximately $9.0 million in cash to DHS in exchange for 2.4 million shares of DHS common stock. Two executive officers purchased 150,000 shares each by execution and delivery of promissory notes for $549,000. An officer of DHS paid $33,000 for 9,000 shares of DHS common stock. Subsequent to these transactions there were 14.6 million shares of DHS common stock outstanding.

During the fourth quarter 2007, the Company acquired an additional interest for $354,000 from one of the DHS founding officers, increasing the Company’s total ownership interest to 50.0% as of December 31, 2007.

In March 2006, DHS purchased a Kremco 750G drilling rig (“Rig 16”) for $4.75 million. The rig is a 500 horsepower rig with a depth rating of 10,000 feet.

In May 2006, DHS acquired two rigs (“Rig 12” and “Rig 14”) and certain other assets in conjunction with the acquisition of C&L Drilling for a purchase price of approximately $16.7 million. Rigs 12 and 14 have depth ratings of 15,000 and 12,500 feet, respectively.

On July 18, 2006, DHS purchased a National 55 drilling rig (“Rig 17”) for $7.25 million. The rig is a 1,000 horsepower rig with a depth rating of 12,500 feet. The rig was placed into service during the fourth quarter 2006.

On March 5, 2007, DHS purchased a drilling rig (“Rig 18”) for cash consideration of $7.6 million, funded with borrowings under the DHS credit facility. The rig is a 700 horsepower rig with a depth rating of 10,500 feet.

F-20

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2008, 2007 and 2006

(5) DHS Drilling Company, Continued

In December 2007, DHS sold Rigs 2 and 3 for proceeds of $6.3 million and recorded a loss of $31,000 on the sale.

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 to Delta and Chesapeake of $6.0 million each and from proceeds of $6.0 million each from Delta and Chesapeake for additional shares of common stock issued by DHS. The notes issued to both Delta and Chesapeake were converted to DHS common shares in August 2008.

During the quarter ended September 30, 2008, DHS paid a deposit of $1.3 million for the acquisition of a drilling rig which was expected to close in October 2008. Because of the bankruptcy of Lehman Commercial Paper and the inability of Lehman to fund DHS’s credit facility, DHS was unable to close on the acquisition and the Company forfeited its deposit. Accordingly, other expense for the year ended December 31, 2008 includes the $1.3 million loss on the forfeiture of the deposit.

The Company performed the annual DHS goodwill impairment test during the quarter ended September 30, 2008; however, due to the deterioration in the market conditions and decreased utilization, the DHS goodwill and the fair values of the rigs were re-evaluated as of December 31, 2008. The Company determined that the book value of the rigs was impaired by $21.6 million and also wrote off the entire amount of goodwill of $7.7 million.

(6) Fair Value Measurements

Effective January 1, 2008, the Company adopted SFAS 157 which defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and requires additional disclosures about fair value measurements. As required by SFAS 157, the Company applied the following fair value hierarchy:

Level 1 – Assets or liabilities for which the item is valued based on quoted prices (unadjusted) for identical assets or liabilities in active markets.

Level 2 – Assets and liabilities valued based on observable market data for similar instruments.

Level 3 – Assets or liabilities for which significant valuation assumptions are not readily observable in the market; instruments valued based on the best available data, some of which is internally-developed, and considers risk premiums that a market participant would require.

The level in the fair value hierarchy within which the fair value measurement in its entirety falls shall be determined based on the lowest level input that is significant to the fair value measurement in its entirety.

The Company’s available for sale securities include investments in auction rate debt securities. Due to the lack of liquidity of these investments, the valuation assumptions are not readily observable in the market and are valued based on broker models using internally developed unobservable inputs (Level 3).

F-21

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2008, 2007 and 2006

(6) Fair Value Measurements, Continued

The following table lists the Company’s fair value measurements by hierarchy as of December 31, 2008 (in thousands):

Quoted Prices

Significant

in Active Markets

Other Observable

Unobservable

for Identical Assets

Inputs

Assets (Liabilities)

(Level 1)

(Level 2)

(Level 3)

Total

Available for sale securities

1,977

The following is a reconciliation of the Company’s Level 3 assets measured at fair value on a recurring basis using significant unobservable inputs (amounts in thousands):


	Available for Sale
			Securities


Balance at January 1, 2008		$	6,566
Impairment loss reported in earnings			(4,589	)
Unrealized losses relating to instruments held at the reporting date			-

Balance at December 31, 2008		$	1,977

(7) Long-Term Debt

Installments Payable on Property Acquisition

On February 28, 2008, the Company closed a transaction with EnCana to jointly develop a portion of EnCana’s leasehold in the Vega Area of the Piceance Basin. Under the terms of the agreement, the Company has committed to fund $410.1 million, of which $110.5 million was paid at the closing and installments of $99.6 million, $100.0 million, and $100.0 million are payable November 1, 2009, 2010, and 2011, respectively. These remaining installments are collateralized by a letter of credit, which in turn are collateralized by cash on deposit in a restricted account. The installment payments are 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 for the year ended December 31, 2008.

7% Senior Unsecured Notes, due 2015

On March 15, 2005, the Company issued 7% senior unsecured notes for an aggregate amount of $150.0 million, which pay interest semiannually on April 1 and October 1 and mature in 2015. The notes were issued at 99.50% of par and the associated discount is being amortized to interest expense over the term of the notes. The indenture governing the notes contains various restrictive covenants that limit the Company’s and its subsidiaries’ ability to, among other things, incur additional indebtedness, repurchase capital stock, pay dividends, make certain investments, sell assets, consolidate, merge or transfer all or substantially all of the assets of the Company and its restricted subsidiaries. These covenants may limit the discretion of the Company’s management in operating the Company’s business. The Company was not in default (as defined in the indenture) under the indenture as of December 31, 2008. (See Note 14, “Guarantor Financial Information”). The fair value of the Company’s senior notes at December 31, 2008 was approximately $31.6 million.

F-22

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2008, 2007 and 2006

(7) Long-Term Debt, Continued

3³/4% Senior Convertible Notes, due 2037

On April 25, 2007, the Company issued $115.0 million aggregate principal amount of 3³/4% Senior Convertible Notes due 2037 (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. 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, the Company will have the option to deliver shares of common stock, cash or a combination of cash and shares of common stock for the Notes surrendered. In addition, following certain fundamental changes that occur prior to maturity, the Company will increase the conversion rate for a holder who elects to convert its Notes in connection with such fundamental changes by a number of additional shares of common stock. Although the Notes do not contain any financial covenants, the Notes contain covenants that require the Company to properly make payments of principal and interest, provide certain reports, certificates and notices to the trustee under various circumstances, cause its 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 its corporate existence, pay taxes and other claims, and not seek protection from the debt under any applicable usury laws. The fair value of the Notes at December 31, 2008 was approximately $52.8 million.

Credit Facility

On November 3, 2008, the Company entered into a Second Amended and Restated Credit Agreement with JP Morgan Chase Bank, N.A. and certain other financial institutions, which, among other changes, increased the amount of its revolving credit facility to $590.0 million. As of December 31, 2008 the borrowing base under the revised facility was $295.0 million with an outstanding balance of $294.5 million. The borrowing base is redetermined semiannually. The revised facility has variable interest rates based on the ratio of outstanding debt to the borrowing base. Interest rates vary between Libor plus 1.5% to Libor plus 3.5% for Eurodollar loans and 0% to 2.0% for base rate loans. The applicable base rate is the greater of the daily federal funds rate plus 0.5%, the one month Libor rate plus 2.5% or the prime rate as of such day. The LIBOR based and prime based rates as of December 31, 2008 were approximately 5.38% and 5.25%, respectively. The weighted average interest rate payable on borrowings under on the facility was 5.37% at December 31, 2008. The amended credit agreement also provided for a conforming borrowing base that will take effect on the earlier of November 3, 2009 or, if they are consummated, the dates upon which certain defined asset sales are completed, and adds a mandatory prepayment provision for the sale or other disposition of certain assets. In addition, the amended credit agreement changed the maturity date of the credit facility to November 3, 2011. Borrowings under the amended credit agreement are available to finance the acquisition, exploration and development of oil and gas interests and related assets and activities, refinance certain existing debt and provide for working capital and general corporate purposes.

The Company was required to meet certain financial covenants beginning with the quarter ended December 31, 2008 including a current ratio of greater than 1 to 1 and consolidated net debt to consolidated EBITDAX (as defined in the amended credit agreement) for the preceding four consecutive fiscal quarters of less than 4.50 to 1.0 for the period ending December 31, 2008. At December 31, 2008, the Company was in compliance with its maximum debt to EBITDAX ratio, but did not meet its minimum current ratio and accounts payable covenants and, accordingly, the Company has classified the $294.5 million of debt outstanding under the bank credit facility at December 31, 2008 as current in the accompanying consolidated balance sheet.

F-23

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2008, 2007 and 2006

(7) Long-Term Debt, Continued

Subsequently on March 2, 2009, the Company entered into the First Amendment to the Company’s Second Amended and Restated Credit Agreement (see Note 21) with JPMorgan and certain other financial institutions which waived the Company’s covenant violations existing at December 31, 2008, waived the March 31, 2009 current ratio covenant requirement and 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.

At December 31, 2007, the Company had $73.6 million outstanding under its credit facility with interest payable at variable rates based upon the ratio of outstanding debt to the borrowing base between prime + .25% and 1.00% for base rate loans and between Libor + 1.5% and 2.25% for Eurodollar loans. The weighted average interest rate payable on amounts outstanding under the line of credit at December 31, 2007 was approximately 7.25%.

Credit Facility – DHS

On August 15, 2008, DHS entered into a new agreement with Lehman Commercial Paper to amend the December 20, 2007 Lehman credit facility. The revised agreement increased the borrowing base from $75.0 million to $150.0 million. The Lehman credit facility has a variable interest rate based on 90-day LIBOR plus a fixed margin of 5.50% which approximated 9.39% as of December 31, 2008 on the first $75.0 million (Term A) and a variable interest rate of 90 day LIBOR plus a fixed margin of 9.0% on the second $75.0 million (Term B) which approximated 12.89% as of December 31, 2008. Quarterly principal payments are required beginning April 1, 2010. The note matures on August 31, 2011. Although DHS has $54.0 million remaining available under its revised credit facility with Lehman Commercial Paper (Lehman), such amounts are not anticipated to be available due to Lehman’s bankruptcy and failure to fund prior draw requests on the facility. Annual principal payments are based upon a calculation of excess cash flow (as defined) for the preceding year and the first quarterly principal payment is due on April 1, 2010. DHS is required to meet certain quarterly financial covenants including maintaining (i) a Leverage Ratio (as defined) not to exceed 3.50 to 1.00 for the term of the loan; (ii) an Interest Coverage Ratio (as defined) to be greater than 2.50 to 1.00 for the term of the loan; (iii) minimum EBITDA amount of $20.0 million is required for twelve month periods ending prior to March 31, 2009, $25.0 million for periods ending prior to October 1, 2010 and for periods ending after October 1, 2010, the greater of $30.0 million plus the product of $1.4 million times the number of additional rigs purchased with proceeds from the Term B loan; and (iv) a Current Ratio at the end of each fiscal quarter of greater than 1.0 to 1.0. DHS incurred $980,000 of financing costs in conjunction with the revised agreement. Because of Lehman’s default, DHS does not have any additional borrowing capacity under the Lehman facility. As a result, the deferred financing costs attributable to the additional borrowing capacity of $54.0 million were written off in the fourth quarter of 2008. At December 31, 2008, DHS was in compliance with its quarterly debt covenants and restrictions under the facility. However, in the event that DHS is not successful in obtaining alternative financing or making satisfactory arrangements with the Lehman Commercial Paper, Inc. bankruptcy trustee, it is likely that DHS will be in default of its debt covenants under its credit facility in 2009 unless market conditions improve significantly. In such event, all of the amounts due under the credit facility would become immediately due and payable. 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.

At December 31, 2007, $75.0 million was outstanding under the credit agreement with Lehman with interest payable at a variable interest rate based on 90-day LIBOR plus a fixed margin of 5.50% which approximated 10.43% as of December 31, 2007.

F-24

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2008, 2007 and 2006

(7) Long-Term Debt, Continued

Maturities

Maturities of long-term debt, in thousands of dollars, based on contractual terms are as follows:


Year ending December 31,
2009	$	394,045
2010		125,985
2011		167,863
2012		-
2013		-
Thereafter		265,000

	$	952,893

(8) Stockholders’ Equity

Preferred Stock

The Company has 3,000,000 shares of preferred stock authorized, par value $.01 per share, issuable from time to time in one or more series. As of December 31, 2008 and 2007, no preferred stock was outstanding. As part of the reincorporation on January 31, 2006, the Company reduced the par value of its preferred stock to $.01 per share.

Common Stock

On February 20, 2008, the Company issued 36.0 million shares of the Company’s common stock to Tracinda Corporation (“Tracinda”) at $19.00 per share for net proceeds of $667.1 million (including a $5.0 million deposit on the transaction received in December 2007), representing approximately 35% of the Company’s outstanding common stock. In conjunction with the transaction, a finder’s fee of 263,158 shares of common stock valued at $5.0 million based on the transaction’s $19.00 per share price was issued to an unrelated third party.

Subsequent to this initial transaction, Tracinda acquired an additional 4.5 million shares in the open market, increasing its ownership to approximately 39% of the Company’s outstanding common stock. In accordance with the initial stock purchase agreement, Tracinda agreed not to acquire more than 49% of the Company’s common stock prior to February 19, 2009.

During the years ended December 31, 2007 and 2006, the Company acquired oil and gas properties for 1,229,000 shares and 673,000 shares of the Company’s common stock, respectively. The shares were valued at $23.7 million and $16.1 million, respectively, based on the market price of the shares at the time of issuance.

During the years ended December 31, 2007 and 2006, the Company received net proceeds from public offerings of the Company’s common stock of $196.7 million for 9,898,000 shares, and $33.9 million for 1,500,000 shares, respectively.

On February 9, 2007, the Company issued 1.5 million non-vested shares as executive performance share grants to the Company’s four executive officers. The shares of common stock awarded will vest if the market price of Delta stock reaches and maintains certain price levels (See Note 3, “Summary of Significant Accounting Policies”).

On April 28, 2006, Castle stockholders approved the merger agreement between Delta and Castle. Delta, via its merger subsidiary DPCA, acquired Castle which held 6,700,000 shares of Delta, and issued 8,500,000 shares of its common stock to Castle’s stockholders, for a net issuance of 1,800,000 shares of common stock. The shares of the Company’s common stock were valued at $31.2 million using the average five-day closing price before and after the terms of the agreement were agreed to and announced.

F-25

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2008, 2007 and 2006

(8) Stockholders’ Equity, Continued

Treasury Stock

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

Non-Qualified Stock Options - Directors and Employees

On December 14, 2004, the stockholders ratified the Company’s 2004 Incentive Plan (the “2004 Plan”) under which it reserved up to an additional 1,650,000 shares of common stock for issuance. Although grants of shares of common stock were made under the 2004 Plan during the 2006 fiscal year, no stock options were issued by the Company during that period.

On January 29, 2007, the stockholders ratified the Company’s 2007 Performance and Equity Incentive Plan (the “2007 Plan”). Subject to adjustment as provided in the 2007 Plan, the number of shares of Common Stock that may be issued or transferred, plus the amount of shares of Common Stock covered by outstanding awards granted under the 2007 Plan, may not in the aggregate exceed 2,800,000. The 2007 Plan supplements the Company’s 1993, 2001 and 2004 Incentive Plans. The purpose of the 2007 Plan is to provide incentives to selected employees and directors of the Company and its subsidiaries, and selected non-employee consultants and advisors to the Company and its subsidiaries, who contribute and are expected to contribute to the Company’s success.

Incentive awards under the 2007 Plan may include non-qualified or incentive stock options, limited appreciation rights, tandem stock appreciation rights, phantom stock, stock bonuses or cash bonuses. Options issued to date under the Company’s various incentive plans have been non-qualified stock options as defined in such plans.

A summary of the stock option activity under the Company’s various plans and related information for the year ended December 31, 2008 follows:


	Year Ended
	December 31, 2008
				Weighted-Average			Weighted-Average		Aggregate
				Exercise			Remaining Contractual		Intrinsic
	Options			Price			Term		Value
Outstanding-beginning of year		2,157,266		$	9.04
Granted		-			-
Exercised		(560,016	)		(9.49	)
Expired / Returned		(69,000	)		(14.79	)


Outstanding-end of year		1,528,250		$	8.62			4.49	$	382,000


Exercisable-end of year		1,528,250		$	8.62			4.49	$	382,000

The Company recognizes the cost of share based payments over the period during which the employee provides service. Exercise prices for options outstanding under the Company’s various plans as of December 31, 2008 ranged from $1.87 to $15.46 per share and the weighted-average remaining contractual life of those options was 4.49 years. The Company has not issued stock options since the adoption of SFAS 123R, though it has the discretion to issue options again in the future.

F-26

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2008, 2007 and 2006

(8) Stockholders’ Equity, Continued

The total intrinsic value of options exercised during the years ended December 31, 2008, 2007 and 2006 were $5.3 million, $2.8 million and $12.3 million, respectively. No options were granted during the years ended December 31, 2008, 2007 and 2006.

A summary of the restricted stock (nonvested stock) activity under the Company’s plan and related information for the year ended December 31, 2008 follows:


	Year Ended
	December 31, 2008
				Weighted-Average			Weighted-Average	Aggregate
	Nonvested			Grant-Date			Remaining Contractual	Intrinsic
	Stock			Fair Value			Term	Value

Nonvested-beginning of year		2,114,621		$	21.47
Granted		1,104,140			21.44
Vested		(830,382	)		(21.83	)
Expired / Returned		(365,267	)		(20.32	)


Nonvested-end of year		2,023,112		$	21.51		2.37	$	9,630,000

Stock Based Compensation

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


	Years Ended December 31,
	2008		2007		2006

Stock options	$	-	$	319	$	1,447
Non-vested stock		10,218		8,347		3,435
Performance shares		5,662		6,924		-

Total	$	15,880	$	15,590	$	4,882

Restricted Stock - Directors and Employees

The total fair value of restricted stock vested during the years ended December 31, 2008, 2007 and 2006 was $6.2 million, $5.2 million and $2.4, respectively.

At December 31, 2008, 2007 and 2006, the total unrecognized compensation cost related to the non-vested portion of restricted stock and stock options was $22.2 million, $20.8 million and $11.4 million which is expected to be recognized over a weighted average period of 2.37, 6.90 and 2.08 years, respectively.

Cash received from exercises under all share-based payment arrangements for the years ended December 31, 2008, 2007 and 2006, was $5.1 million, $686,000, and $3.6 million, respectively. There were no tax benefits realized from the stock options exercised during the years ended December 31, 2008, 2007 and 2006. During the years ended December 31, 2008, 2007 and 2006, $8.4 million, $8.0 million and $4.6 million, respectively, of tax benefits were generated from the exercise of stock options; however, such benefit will not be recognized in stockholders’ equity until the period in which these amounts decrease current taxes payable.

F-27

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2008, 2007 and 2006

(9) Employee Benefits

The Company adopted a profit sharing plan on January 1, 2002. All employees are eligible to participate and contributions to the profit sharing plan are voluntary and must be approved by the Board of Directors. Amounts contributed to the Plan vest over a six year service period.

For the years ended December 31, 2008, 2007 and 2006, the Company expensed $914,000, $590,000, and $310,000, respectively, related to its profit sharing plan.

The Company adopted a 401(k) plan effective May 1, 2005. All employees are eligible to participate and make employee contributions once they have met the plan’s eligibility criteria. Under the 401(k) plan, the Company’s employees make salary reduction contributions in accordance with the Internal Revenue Service guidelines. The Company’s matching contribution is an amount equal to 100% of the employee’s elective deferral contribution which cannot exceed 3% of the employee’s compensation, and 50% of the employee’s elective deferral which exceeds 3% of the employee’s compensation but does not exceed 5% of the employee’s compensation.

(10) Commodity Derivative Instruments and Hedging Activities

The Company periodically enters into commodity price risk transactions to manage its exposure to oil and gas price volatility. These transactions may take the form of futures contracts, collar agreements, swaps or options. The purpose of the hedges is to provide a measure of stability to the Company’s cash flows in an environment of volatile oil and gas prices. All transactions are accounted for in accordance with requirements of Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”). Effective July 1, 2007, the Company elected to discontinue cash flow hedge accounting on a prospective basis. Beginning July 1, 2007, the Company recognizes mark-to-market gains and losses in current earnings instead of deferring those amounts in accumulated other comprehensive income. As a result of the Company’s election to discontinue hedge accounting, the amount recorded in accumulated other comprehensive income for hedges that were effective as of June 30, 2007 was fixed until the period those derivatives were settled, with all subsequent changes in fair value recorded in gain (loss) from ineffective derivative contracts. All amounts in accumulated other comprehensive income as of June 30, 2007 were reclassified to gain (loss) on effective derivative contracts as of December 31, 2007, as all such derivatives had settled.

At December 31, 2008, the Company did not have any outstanding derivative contracts. During late third quarter and early fourth quarter 2008, the Company cash settled the majority of its then outstanding derivative contracts in order to reduce counterparty credit risk. Contracts that were not terminated early settled in accordance with their original terms by December 31, 2008.

The net gains from all hedging activities recognized in the Company’s statements of operations were $21.7 million, $10.0 million, and $7.0 million for the years ended December 31, 2008, 2007 and 2006, respectively.

F-28

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2008, 2007 and 2006

(11) Income Taxes, Continued

Deferred tax assets (liabilities) are comprised of the following at December 31, 2008 and 2007 (in thousands):


	2008			2007
Current deferred tax assets (liabilities)
Derivative instruments	$	-		$	1,249
Accrued bonuses		116			1,737
Allowance for doubtful accounts		234			236
Accrued vacation liability		287			212
Prepaid insurance and other		(314	)		(394	)

Total current deferred tax assets		323			3,040

Less valuation allowance		(92	)		(2,890	)

Net current deferred tax asset	$	231		$	150


Long-term deferred tax assets (liabilities):
Deferred tax assets:
Net operating loss ¹	$	136,934		$	56,649
Asset retirement obligation		3,218			1,976
Percentage depletion		592			596
Property and equipment		81,837			-
Equity compensation		10,800			4,807
Marketable securities		1,690			-
Equity investments		421			-
Foreign taxes		478			-
Minimum tax credit		1,221			1,221
Other		481			153

Total long-term deferred tax assets		237,672			65,402
Valuation allowance		(219,071	)		(55,187	)

Net deferred tax asset		18,601			10,215

Deferred tax liabilities:
Property and equipment		(19,625	)		(19,261	)
Other		-			(39	)

Total long-term deferred tax liabilities		(19,625	)		(19,300	)

Net long-term deferred tax liability	$	(1,024	)	$	(9,085	)


^¹		Included in net operating loss carryforwards is $1.25 million at June 30, 2005 that related to the tax effect of stock options exercised and restricted stock for which the benefit was recognized in stockholders’ equity rather than in operations in accordance with FAS 109. Not included in the deferred tax asset for net operating loss at December 31, 2008 and 2007 is approximately $14.7 million and $7.9 million, respectively, that relates to the tax effect of stock options exercised for which the benefit will not be recognized in stockholders’ equity until the period that these amounts decrease taxes payable. The related $52.8 million tax deduction is included in the table of net operating losses shown below.

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future results of operations, and tax planning strategies in making this assessment. Based upon the level of historical taxable income, significant book losses during the year ended December 31, 2008, and projections of future results of operations over the periods in which the deferred tax assets are deductible, among other factors, management concluded during the second quarter of 2007, and continues to conclude, that the Company does not meet the “more likely than not” requirement of SFAS 109 in order to recognize deferred tax assets. Accordingly, for the year ended December 31, 2008, the Company recorded in income tax expense an increase in the valuation allowance of $161.1 million offsetting the Company’s deferred tax assets.

F-30

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2008, 2007 and 2006

(11) Income Taxes, Continued

At December 31, 2008, the Company had net operating loss carryforwards for regular and alternative minimum tax purposes as follows:


Regular tax net operating loss carryforwards	$	425,343
Alternative minimum tax net operating loss carryforwards		419,611

If not utilized, the tax net operating loss carryforwards will expire from 2009 through 2028.

The Company’s net operating losses are scheduled to expire as follows (in thousands):


2009	$	3,914
2010		6,004
2011		5,939
2012		994
2013 and thereafter		408,492

	$	425,343

In August 2007, the Company experienced cumulative ownership changes as defined by the Internal Revenue Code (“IRC”) 382 and as a result, a portion of the Company’s net operating loss utilization after the change date will be subject to IRC 382 limitations of approximately $45.0 million annually for federal income taxes.

Effective January 1, 2007, the Company adopted provisions of FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes - An Interpretation of FASB Statement No. 109” (“FIN 48”). FIN 48 provides detailed guidance for the financial statement recognition, measurement and disclosure of uncertain tax positions recognized in the financial statements in accordance with SFAS 109. Tax positions must meet a “more-likely-than-not” recognition threshold at the effective date to be recognized upon the adoption of FIN 48 and in subsequent periods. Upon the adoption of FIN 48, the Company had no unrecognized tax benefits. During the year ended December 31, 2008, no adjustments were recognized for uncertain tax benefits.

The Company recognizes interest and penalties related to uncertain tax positions in income tax (benefit)/expense. No interest and penalties related to uncertain tax positions were accrued at December 31, 2008.

The tax years 2005 through 2007 for federal returns and 2004 through 2007 for state returns remain open to examination by the major taxing jurisdictions in which we operate, although no material changes to unrecognized tax positions are expected within the next twelve months.

(12) Related Party Transactions

Transactions with Directors and Officers

During fiscal 2001 and 2000, Mr. Larson and Mr. Parker, officers of the Company at the time, guaranteed certain borrowings which have subsequently been repaid. As consideration for the guarantee of the Company’s indebtedness, each officer was assigned a 1% overriding royalty interest (“ORRI”) in the properties acquired with the proceeds of the borrowings. Each of Mr. Larson and Mr. Parker earned approximately $154,000, $110,000, and $142,000, for their respective 1% ORRI during the years ended December 31, 2008, 2007 and 2006, respectively.

Accounts Receivable Related Parties

At December 31, 2008 and 2007, the Company had $331,000 and $276,000 of receivables from related parties, respectively. These amounts include drilling costs and lease operating expenses on wells owned by the related parties and operated by the Company.

F-31

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2008, 2007 and 2006

(14) Guarantor Financial Information

On March 15, 2005, Delta issued $150.0 million of 7% Senior Notes (“Senior Notes”) that mature in 2015. In addition, on April 25, 2007, the Company issued $115.0 million of 3³/4% Convertible Senior Notes due in 2037 (“Convertible Notes”). Both the Senior Notes and the Convertible Notes are guaranteed by all of the Company’s other wholly-owned subsidiaries (“Guarantors”). Each of the Guarantors, fully, jointly and severally, irrevocably and unconditionally guarantees the performance and payment when due of all the obligations under the Senior Notes and the Convertible Notes. DHS, CRBP, PGR, and Amber (“Non-guarantors”) are not guarantors of the indebtedness under the Senior Notes or the Convertible Notes.

The following financial information sets forth the Company’s condensed consolidated balance sheets as of December 31, 2008, and 2007, the condensed consolidated statements of operations for the years ended December 31, 2008, 2007 and 2006, and the condensed consolidated statements of cash flows for the years ended December 31, 2008, 2007 and 2006 (in thousands). For purposes of the condensed financial information presented below, the equity in the earnings or losses of subsidiaries is not recorded in the financial statements of the issuer.

Condensed Consolidated Balance Sheet
December 31, 2008


				Guarantor			Non-Guarantor			Adjustments/
	Issuer			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Current assets	$	167,675		$	591		$	54,630		$	-		$	222,896

Property and equipment:
Oil and gas		1,681,804			503			110,650			(11,944	)		1,781,013
Drilling rigs and trucks		594			-			193,629			-			194,223
Other		76,932			36,359			1,892			-			115,183

Total property and equipment		1,759,330			36,862			306,171			(11,944	)		2,090,419

Accumulated DD&A		(544,154	)		(21,896	)		(92,229	)		-			(658,279	)


Net property and equipment		1,215,176			14,966			213,942			(11,944	)		1,432,140

Investment in subsidiaries		141,827			-			-			(141,827	)		-
Other long-term assets		235,872			3,825			681			-			240,378


Total assets	$	1,760,550		$	19,382		$	269,253		$	(153,771	)	$	1,895,414


Current liabilities	$	550,876		$	172		$	13,480		$	-		$	564,528

Long-term liabilities
Long-term debt and deferred taxes		451,068			1,800			94,872			-			547,740
Asset retirement obligation		6,307			10			268			-			6,585


Total long-term liabilities		457,375			1,810			95,140			-			554,325

Minority interest		29,104			-			-			-			29,104

Stockholders’ equity		723,195			17,400			160,633			(153,771	)		747,457


Total liabilities and stockholders’ equity	$	1,760,550		$	19,382		$	269,253		$	(153,771	)	$	1,895,414

F-33

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2008, 2007 and 2006

(14) Guarantor Financial Information, Continued

Condensed Consolidated Balance Sheet
December 31, 2007


				Guarantor			Non-Guarantor			Adjustments/
	Issuer			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Current assets	$	99,625		$	898		$	33,253		$	-		$	133,776

Property and equipment:
Oil and gas		917,242			487			80,784			(1,654	)		996,859
Drilling rigs and trucks		595			-			145,502			-			146,097
Other		35,444			4,316			1,449			-			41,209

Total property and equipment		953,281			4,803			227,735			(1,654	)		1,184,165

Accumulated DD&A		(203,091	)		(125	)		(41,937	)		-			(245,153	)


Net property and equipment		750,190			4,678			185,798			(1,654	)		939,012

Investment in subsidiaries		87,961			-			-			(87,961	)		-
Other long-term assets		25,543			3,800			8,513			-			37,856


Total assets	$	963,319		$	9,376		$	227,564		$	(89,615	)	$	1,110,644


Current liabilities	$	135,997		$	188		$	7,011		$	-		$	143,196

Long-term liabilities
Long-term debt and deferred taxes		336,409			1,800			83,935			-			422,144
Asset retirement obligation		3,976			9			169			-			4,154


Total long-term liabilities		340,385			1,809			84,104			-			426,298

Minority interest		27,296			-			-			-			27,296

Stockholders’ equity		459,641			7,379			136,449			(89,615	)		513,854


Total liabilities and stockholders’ equity	$	963,319		$	9,376		$	227,564		$	(89,615	)	$	1,110,644


Condensed Consolidated Statement of Operations Year Ended December 31, 2007

				Guarantor			Non-Guarantor			Adjustments/
	Issuer			Subsidiaries			Subsidiaries			Eliminations			Consolidated

Total revenue	$	131,905		$	577		$	95,288		$	(32,829	)	$	194,941

Operating expenses:
Lease operating expense		31,241			118			1,060			-			32,419
Depreciation and depletion		69,963			11			25,953			(6,031	)		89,896
Exploration expense		9,062			-			-			-			9,062
Drilling and trucking operating expenses		-			-			59,720			(22,022	)		37,698
Dry hole costs and impairments		85,084			-			-			2,375			87,459
General and administrative		44,543			(1	)		5,079			-			49,621


Total expenses		239,893			128			91,812			(25,678	)		306,155


Operating income (loss)		(107,988	)		449			3,476			(7,151	)		(111,214	)

Other income and expenses		(21,500	)		88			(8,705	)		1,230			(28,887	)
Income tax (expense) benefit		(4,486	)		-			1,809			(2,333	)		(5,010	)
Discontinued operations		(2,076	)		-			-			-			(2,076	)


Net income (loss)	$	(136,050	)	$	537		$	(3,420	)	$	(8,254	)	$	(147,187	)

F-35

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2008, 2007 and 2006

(14) Guarantor Financial Information, Continued

Condensed Consolidated Statement of Cash Flows
Year Ended December 31, 2007


				Guarantor			Non-Guarantor
	Issuer			Subsidiaries			Subsidiaries			Consolidated

Operating activities	$	70,280		$	208		$	16,515		$	87,003
Investing activities		(286,428	)		(1,538	)		(38,586	)		(326,552	)
Financing activities		218,523			-			23,153			241,676


Net increase (decrease) in cash and cash equivalents		2,375			(1,330	)		1,082			2,127

Cash at beginning of the period		2,282			1,637			3,747			7,666


Cash at the end of the period	$	4,657		$	307		$	4,829		$	9,793

Condensed Consolidated Statement of Operations
Year Ended December 31, 2006


				Guarantor			Non-Guarantor			Adjustments/
	Issuer			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Total revenue	$	93,342		$	1,362		$	85,306		$	(22,579	)	$	157,431

Operating expenses:
Lease operating expense		23,344			471			393			-			24,208
Depreciation and depletion		54,007			112			17,530			(3,394	)		68,255
Exploration expense		4,687			-			3			-			4,690
Drilling and trucking operating expenses		-			-			47,077			(11,573	)		35,504
Dry hole, abandonment and impaired		15,682			-			-			319			16,001
General and administrative		32,266			86			3,344			-			35,696
Gain on sale of oil and gas properties		(20,034	)		-			-			-			(20,034	)


Total expenses		109,952			669			68,347			(14,648	)		164,320


Income (loss) from continuing operations		(16,610	)		693			16,959			(7,931	)		(6,889	)

Other income and expenses		(6,402	)		(23	)		(7,264	)		(2,596	)		(16,285	)
Income tax benefit		13,317			-			(3,064	)		(1,707	)		8,546
Discontinued operations		11,984			-			-			-			11,984
Extraordinary gain		-			5,560			-			-			5,560


Net income (loss)	$	2,289		$	6,230		$	6,631		$	(12,234	)	$	2,916

Condensed Consolidated Statement of Cash Flows
Year Ended December 31, 2006


				Guarantor			Non-Guarantor
	Issuer			Subsidiaries			Subsidiaries			Consolidated

Operating activities	$	36,730		$	(237	)	$	18,006		$	54,499
Investing activities		(149,901	)		20,941			(75,238	)		(204,198	)
Financing activities		113,505			(19,283	)		57,624			151,846


Net increase (decrease) in cash and cash equivalents		334			1,421			392			2,147

Cash at beginning of the period		1,949			216			3,354			5,519


Cash at the end of the period	$	2,283		$	1,637		$	3,746		$	7,666

F-36

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2008, 2007 and 2006

(15) Commitments and Contingencies

The Company leases office space in Denver, Colorado and certain other locations in the states in which the Company operates and also leases equipment and autos under non-cancelable operating leases. Rent expense for the years ended December 31, 2008, 2007 and 2006, was approximately $1,596,000, $1,150,000, and $856,000, respectively. The following table summarizes the future minimum payments under all non-cancelable operating lease obligations (in thousands):


2009	$	3,870
2010		2,447
2011		1,569
2012		1,422
2013		1,431
2014 and thereafter		2,436

	$	13,175

On April 30, 2007, the Company entered into agreements with four executive officers which provide for severance payments equal to three times the average of the officer’s combined annual salary and bonus, benefits continuation and accelerated vesting of options and stock grants in the event that there is a change in control of the Company. These agreements replaced similar agreements that expired on December 31, 2006.

Offshore Litigation

The Company and its 92% owned subsidiary, Amber, are 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 the Company’s offshore California properties. On November 15, 2005 and October 31, 2006, the Court granted summary judgment as to liability and partial summary judgment as to damages with respect to thirty six of the forty total federal leases that are the subject of the litigation. Under a restitution theory of damages, the Court ruled that the government must give back to the current lessees the more than $1.1 billion in lease bonuses it had received at the time of sale. On January 19, 2006, the government filed a motion for reconsideration of the Court’s ruling as it relates to a single lease owned entirely by the Company (“Lease 452”). In its motion for reconsideration, the government has asserted that the Company should not be able to recover lease bonus payments for Lease 452 because, allegedly, a significant portion of the hydrocarbons has been drained by wells that were drilled on an immediately adjacent lease. The amount of lease bonus payments attributable to Lease 452 is approximately $92.0 million. A trial on the motion for reconsideration was completed in January 2008 and on February 25, 2009 the Court entered a judgment in the Company’s favor in the amount of $91.4 million. This judgment is subject to appeal by the government.

On January 12, 2007, the Court entered an order of final judgment awarding the lessees restitution of the original lease bonuses paid for thirty five of the forty lawsuit leases. Under this order, the Company is entitled to receive a gross amount of approximately $58.5 million, and Amber is entitled to receive a gross amount of approximately $1.5 million as reimbursement for the lease bonuses paid for all lawsuit leases other than Lease 452. The order of final judgment was affirmed in all respects by the United States Court of Appeals for the Federal Circuit on August 25, 2008, and the government’s petition seeking a rehearing of that decision was denied on December 5, 2008; however, on December 24, 2008, the Federal Circuit entered an order imposing a stay of the issuance of its mandate for a period of 90 days pending consideration of and the possible filing by the government of a petition for writ of certiorari with the United States Supreme Court. On February 23, 2009, the Supreme Court granted the government’s application for a thirty day extension, to April 4, 2009, to file a petition for a writ of certiorari. The government asserts in its application that it has not yet determined whether it will ultimately file such a petition in this case.

F-37

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2008, 2007 and 2006

(15) Commitments and Contingencies, Continued

Shareholder Derivative Suit

Within the past two years, there has been significant focus on corporate governance and accounting practices in the grant of equity based awards to executives and employees of publicly traded companies, including the use of market hindsight to select award dates to favor award recipients. After being identified in a third-party report as statistically being at risk for possibly backdating option grants, in May 2006 the Company’s Board of Directors created a special committee comprised of outside directors of the Company. The special committee, which was advised by independent legal counsel and advisors, undertook a comprehensive review of the Company’s historical stock option practices and related accounting treatment. In June 2006 the Company received a subpoena from the U.S. Attorney for the Southern District of New York and an inquiry from the staff of the SEC related to the Company’s stock option grants and related practices. The special committee of the Company’s Board of Directors reported to the Board that, while its review revealed deficiencies in the documentation of the Company’s option grants in prior years, there was no evidence of option backdating or other misconduct by the Company’s executives or directors in the timing or selection of the Company’s option grant dates, or that would cause the Company to conclude that its prior accounting for stock option grants was incorrect in any material respect. The Company provided the results of the internal investigation to the U.S. Attorney and to the SEC in August of 2006, and was subsequently informed by both agencies that the matter had been closed.

During September and October of 2006, three separate shareholder derivative actions were filed on the Company’s behalf in U.S. District Court for the District of Colorado relating to the options backdating issue, all of which were consolidated into a single action. The consolidated complaint alleged that certain of the Company’s executive officers and directors engaged in various types of misconduct in connection with certain stock option grants. Specifically, the plaintiffs alleged that the defendant directors, in their capacity as members of the Company’s Board of Directors and its Audit or Compensation Committee, at the behest of the defendants who are or were officers and to benefit themselves, backdated the Company’s stock option grants to make it appear as though they were granted on a prior date when the Company’s stock price was lower. They alleged that these backdated options unduly benefited the defendants who are or were officers and/or directors, resulted in the Company issuing materially inaccurate and misleading financial statements and caused the Company to incur substantial damages. The action also sought to have the current and former officers and directors who are defendants disgorge to the Company certain options they received, including the proceeds of options exercised, as well as certain equitable relief and attorneys’ fees and costs. On September 26, 2007, the Court entered an Order dismissing the action for failing to plead sufficient facts to support the claims that were made in the complaint, and stayed the dismissal for ten days to allow the Plaintiffs to file a motion for leave to file an amended complaint. Extensions were granted and the Plaintiffs filed such a motion on October 29, 2007. The stay will remain in effect until the Court rules on the motion.

Castle/Longs Trust Litigation

Management does not believe that these proceedings, individually or in the aggregate, will have a material adverse effect on the Company’s financial position, results of operations or cash flows.

F-38

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2008, 2007 and 2006

(18) Immaterial Corrections in Prior Periods

During the year ended December 31, 2008, the Company identified an immaterial correction related to the calculation of the intercompany profit to be eliminated in consolidation on drilling services performed by DHS for Delta. Historically, the Company has eliminated intercompany profit on the total cost of the wells rather than only on Delta’s working interest share of the cost of the wells drilled. Additionally, no allocation of rig depreciation expense was included in the calculation of the intercompany profit to be eliminated. These corrections affected the Company’s previously reported interim and annual financial statements for the six months ended December 31, 2005, the years ended December 31, 2006 and 2007, and the quarter ended March 31, 2008. The Company does not consider these corrections to be material to these previously filed financial statements. These corrections have been reflected in the financial statements for the prior periods included in this annual report on Form 10-K. The following summarizes the effect of the immaterial corrections on the financial statements for the prior periods presented in this Form 10-K (in thousands, except per share data):


	Year Ended December 31, 2007							Year Ended December 31, 2006
	Previously Reported(1)				As Revised			Previously Reported (1)				As Revised
Total Revenues		$	193,360		$	194,941			$	154,977		$	157,431
Operating expenses			309,067			306,155				166,054			164,320

Operating loss		$	(115,707	)	$	(111,214	)		$	(11,077	)	$	(6,889	)

Income (loss) from continuing operations		$	(147,271	)	$	(145,111	)		$	(17,109	)	$	(14,628	)
Net income (loss)		$	(149,347	)	$	(147,187	)		$	435		$	2,916

Basic income (loss) per common share:
Loss from continuing operations		$	(2.40	)	$	(2.37	)		$	(.33	)	$	(.28	)
Net income (loss)		$	(2.44	)	$	(2.40	)		$	.01		$	.06
Diluted income (loss) per common share:
Loss from continuing operations		$	(2.40	)	$	(2.37	)		$	(.33	)	$	(.28	)
Net income (loss)		$	(2.44	)	$	(2.40	)		$	.01		$	.05

Oil and gas properties		$	987,874		$	996,859
Total long-term assets		$	42,397		$	37,856
Total assets		$	1,105,195		$	1,110,644
Stockholders’ equity		$	508,405		$	513,854
Total liabilities and stockholders’ equity		$	1,105,195		$	1,110,644


(1)		Reclassified for discontinued operations.

F-41

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2008, 2007 and 2006

(19) Disclosures About Capitalized Costs, Costs Incurred and Major Customers (Unaudited)

Capitalized costs related to oil and gas activities are as follows (in thousands):


	December 31,			December 31,			December 31,
	2008			2007			2006
Unproved properties	$	415,573		$	247,466		$	217,573
Proved properties		1,365,440			749,393			564,242

		1,781,013			996,859			781,815
Accumulated depreciation and depletion		(548,618	)		(204,014	)		(116,151	)

	$	1,232,395		$	792,845		$	665,664

Costs incurred in oil and gas activities are as follows (in thousands):


	December 31,		December 31,		December 31,
	2008		2007		2006
Unproved property acquisition costs	$	180,149	$	28,713	$	61,527
Proved property acquisition costs		41,666		46,158		3,255
Development costs incurred on proved undeveloped reserves		123,999		144,156		46,144
Development costs - other		261,588		119,607		159,807
Exploration and dry hole costs		122,827		35,735		9,013

	$	730,229	$	374,369	$	279,746


Included in costs incurred are asset retirement obligation costs for all periods presented.

Changes in capitalized exploratory well costs are as follows (in thousands):


	Years Ended December 31,
	2008			2007			2006
Balance at beginning of year	$	44,091		$	27,453		$	357
Additions to capitalized exploratory well costs pending the determination of proved reserves		12,397			30,797			27,744
Exploratory well costs included in property divestitures		(1,677	)		(2,941	)		-
Reclassified to proved oil and gas properties based on the determination of proved reserves		(563	)		-			(357	)
Capitalized exploratory well costs charged to dry hole expense		(40,436	)		(11,218	)		(291	)

Balance at end of year	$	13,812		$	44,091		$	27,453


Exploratory well costs capitalized for one year or less		13,812			35,649			27,453
Exploratory well costs capitalized for greater than one year after completion of drilling		-			8,442			-

Balance at end of year	$	13,812		$	44,091		$	27,453


The table does not include amounts that were capitalized and either subsequently expensed or reclassified to producing well costs in the same period.

Included in capitalized exploratory well costs capitalized for greater than one year at December 31, 2007 were two projects. One project representing $1.7 million of the costs was non-operated and pending connection to a new field gathering system. During 2008, the field that included the project was sold. The second project representing $6.8 million of the costs capitalized for greater than one year at December 31, 2007 was related to the Company’s Paradox Basin properties. During 2008, substantial additional work was performed, but in the fourth quarter of 2008, as a result of drilling results and the decline in commodity prices, the costs were charged to dry hole expense.

F-42

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2008, 2007 and 2006

(19) Disclosures About Capitalized Costs, Costs Incurred and Major Customers (Unaudited), Continued

A summary of the results of operations for oil and gas producing activities, excluding general and administrative cost, is as follows:


	Years Ended December 31,
	2008			2007			2006
Revenue:
Oil and gas revenues	$	221,733		$	123,729		$	102,540
Expenses:
Production costs		56,978			32,419			24,208
Depletion and amortization		96,490			71,867			53,657
Exploration		10,975			9,062			4,690
Abandoned and impaired properties		327,112			58,411			11,359
Dry hole costs		111,851			29,048			4,642

Results of operations of oil and gas producing activities	$	(381,673	)	$	(77,078	)	$	3,984


Income from operations of properties sold, net		-			1,922			5,272
Gain (loss) on sale of properties		-			(3,998	)		6,712


Results of discontinued operations of oil and gas producing activities	$	-		$	(2,076	)	$	11,984

During the year ended December 31, 2008, customer A and customer B accounted individually for 31% and 25%, respectively, of the Company’s total oil and gas sales. During the year ended December 31, 2007, customer B and customer C accounted individually for 27% and 13%, respectively, of the Company’s total oil and gas sales. During the year ended December 31, 2006, customer B and customer D individually accounted for 24% and 15%, respectively, of the Company’s total oil and gas sales.

(20) Information Regarding Proved Oil and Gas Reserves (Unaudited)

Proved Oil and Gas Reserves. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions; i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. For the purposes of this disclosure, the Company has included reserves it is committed to and anticipates drilling. Substantially all of the Company's proved undeveloped reserves are attributable to its properties in the Piceance Basin. The Company's reserves have been calculated assuming an aggregate cost to develop the reserves over a 10 year period of approximately $1.3 billion. The Company previously announced its intention to seek a joint venture partner to jointly develop the properties. Based on the interest expressed by potential industry partners, after reviewing the data presented to them, the Company is reasonably certain that it will be successful in attracting other financing for, or entering into a joint venture arrangement for, the development of the properties, and therefore has the ability and intent to develop proved undeveloped reserves disclosed in the table below.

(i) Reservoirs are considered proved if economic producability is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

(ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

(iii) Estimates of proved reserves do not include the following: (A) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves;” (B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (C) crude oil, natural gas, and natural gas liquids that may occur in underlaid prospects; and (D) crude oil, natural gas, and natural gas liquids that may be recovered from oil shales, coal, gilsonite and other such sources.

F-43

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2008, 2007 and 2006

(20) Information Regarding Proved Oil and Gas Reserves (Unaudited), Continued

Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other un-drilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

“Prepared” reserves are those quantities of reserves which were prepared by an independent petroleum consultant. “Audited” reserves are those quantities of revenues which were estimated by the Company’s employees and audited by an independent petroleum consultant. An audit is an examination of a company’s proved oil and gas reserves and net cash flow by an independent petroleum consultant that is conducted for the purpose of expressing an opinion as to whether such estimates, in aggregate, are reasonable and have been estimated and presented in conformity with generally accepted petroleum engineering and evaluation principles.

Estimates of the Company’s oil and natural gas reserves and present values as of December 31, 2008, December 31, 2007, and December 31, 2006 were prepared by Ralph E. Davis Associates, Inc., the Company’s independent reserve engineers.

F-44

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2008, 2007 and 2006

(20) Information Regarding Proved Oil and Gas Reserves (Unaudited), Continued

A summary of changes in estimated quantities of proved reserves for the years ended December 31, 2008, 2007, and 2006 is as follows (in thousands):


	Gas			Oil			Total
	(MMcf)			(MBbl)			(MMcfe)

Estimated Proved Reserves: Balance at December 31, 2005		181,154			14,709			269,408

Revisions of quantity estimate		(23,050	)		(3,271	)		(42,676	)
Extensions and discoveries		90,738			3,533			111,936
Purchase of properties		7,590			3			7,608
Sale of properties		(23,706	)		(673	)		(27,744	)
Production		(8,022	)		(1,354	)		(16,146	)


Estimated Proved Reserves: Balance at December 31, 2006		224,704			12,947			302,386

Revisions of quantity estimate		23,932			(2,101	)		11,326
Extensions and discoveries		86,269			2,423			100,807
Purchase of properties		10,559			266			12,155
Sale of properties		(24,738	)		(1,425	)		(33,288	)
Production		(11,253	)		(1,085	)		(17,763	)


Estimated Proved Reserves: Balance at December 31, 2007		309,473			11,025			375,623

Revisions of quantity estimate		191,002			(4,108	)		166,354
Extensions and discoveries		152,801			1,652			162,713
Purchase of properties		193,351			1,877			204,613
Sale of properties		-			-			-
Production		(18,950	)		(993	)		(24,908	)


Estimated Proved Reserves: Balance at December 31, 2008		827,677			9,453			884,395


Proved developed reserves:

December 31, 2006		65,026			6,287			102,748
December 31, 2007		92,194			4,548			119,482
December 31, 2008		161,552			3,274			181,196

Future net cash flows presented below are computed using year end prices and costs and are net of all overriding royalty revenue interests.

Future corporate overhead expenses and interest expense have not been included.
	2008			2007			2006
	(in thousands)
Future net cash flows	$	3,542,332		$	2,951,481		$	1,765,334
Future costs:
Production		924,705			735,610			481,646
Development and abandonment		1,337,842			585,622			329,355
Income taxes		-			226,354			76,935

Future net cash flows		1,279,785			1,403,895			877,398
10% discount factor		(1,120,417	)		(702,021	)		(394,164	)

Standardized measure of discounted future net cash flows	$	159,368		$	701,874		$	483,234

Estimated future development cost anticipated for following two years on existing properties	$	216,293		$	334,326		$	250,224

F-45

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2008, 2007 and 2006

(20) Information Regarding Proved Oil and Gas Reserves (Unaudited), Continued

The principal sources of changes in the standardized measure of discounted net cash flows during the years ended December 31, 2008, 2007 and 2006 are as follows (in thousands):


	Years Ended December 31,
	2008			2007			2006

Beginning of the year	$	701,874		$	483,234		$	749,624
Sales of oil and gas production during the period, net of production costs		(164,755	)		(95,976	)		(98,340	)
Purchase of reserves in place		289,040			38,364			14,716
Net change in prices and production costs		(907,844	)		286,255			(567,435	)
Changes in estimated future development costs		(27,087	)		(106,678	)		(35,041	)
Extensions, discoveries and improved recovery		242,079			135,868			213,741
Revisions of previous quantity estimates, estimated timing of development and other		(281,302	)		(83,240	)		(82,456	)
Previously estimated development and abandonment costs incurred during the period		123,999			144,156			46,144
Sales of reserves in place		-			(77,631	)		(55,640	)
Change in future income tax		113,177			(70,801	)		222,959
Accretion of discount		70,187			48,323			74,962

End of year	$	159,368		$	701,874		$	483,234

(21) Subsequent Events

On March 2, 2009, the Company entered into the First Amendment to the Second Amended and Restated Credit Agreement (the “Forbearance Agreement and Amendment to the Credit Facility”) with JPMorgan Chase Bank, N.A., as agent, and certain of the financial institutions that are party to its credit agreement in which, among other changes, the lenders provided the Company relief for a period ending April 15, 2009 at the earliest and no later than June 15, 2009, dependent upon the progress of the Company’s capital raising efforts, from acting upon their rights and remedies as a result of the Company’s violation of accounts payable and current ratio covenants. The Forbearance Agreement and Amendment to the Credit Facility waives the March 31, 2009 current ratio covenant requirement, and, if the Company successfully completes its capital raising efforts, replaces 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 will be reduced upon the successful completion of the Company’s capital raising efforts from $295.0 million to $225.0 million, with a conforming borrowing base of $185.0 million until the next scheduled redetermination date (September 1, 2009). The Forbearance Agreement and Amendment to the Credit Facility requires that the Company raise net proceeds of at least $140.0 million through its capital raising efforts on or before the forbearance termination date and that the Company reduce its amounts outstanding under the facility to not more than $225.0 million and pay accounts payable with such net proceeds. The revised variable interest rates are based on the ratio of outstanding credit to conforming borrowing base and vary between Libor plus 2.5% to Libor plus 5.0% for Eurodollar loans and 1.625% to 4.125% for base rate loans. The Forbearance Agreement and Amendment to the Credit Facility changes the maturity date to January 15, 2011. The Forbearance Agreement and Amendment to the Credit Facility also requires that the Company execute derivative contracts to put in place a commodity floor price for anticipated production equal to a minimum of 40% for the last two quarters of 2009, 70% for the calendar year 2010 and 50% for the calendar year 2011.

F-46


		Undeveloped Acres ^(1) (2)
Location	Gross		Net
California, onshore		540	80
California, offshore		58,090	10,270
Colorado		110,550	87,320
Kansas		160	160
Louisiana		19,340	12,940
Nebraska		3,240	2,420
North Dakota		7,990	890
Oregon		419,660	48,130
Texas		48,480	30,660
Utah		337,450	205,100
Washington		1,252,230	375,880
Wyoming		187,070	119,600

Total		2,444,800	893,450


	Years Ended December 31,
	2008				2007				2006

	Gross		Net		Gross		Net		Gross		Net
Exploratory Wells ⁽¹⁾:
Productive:
Oil		1		1.00		5		4.75		4		3.15
Gas		1		.70		4		3.09		4		4.00
Nonproductive		19		14.01		5		4.16		4		3.50

Total		21		15.71		14		12.00		12		10.65
Development Wells ⁽¹⁾:
Productive:
Oil		7		5.40		10		9.55		14		11.83
Gas		141		82.37		89		58.48		37		20.12
Nonproductive		-		-		2		1.13		1		1.00

Total		148		87.77		101		69.16		52		32.95
Total Wells ⁽¹⁾:
Productive:
Oil		8		6.40		15		14.30		18		14.98
Gas		142		83.07		93		61.57		41		24.12
Nonproductive		19		14.01		7		5.29		5		4.50

Total Wells		169		103.48		115		81.16		64		43.60


Quarter Ended	High		Low
March 31, 2006	$	24.95	$	17.82
June 30, 2006		22.71		13.79
September 30, 2006		23.27		15.02
December 31, 2006		30.68		20.81

March 31, 2007	$	23.12	$	17.57
June 30, 2007		24.94		18.62
September 30, 2007		20.35		14.40
December 31, 2007		21.58		13.06

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


	Page No.

Reports of Independent Registered Public Accounting Firm		F-1,2

Consolidated Balance Sheets as of December 31, 2008 and December 31, 2007		F-3

Consolidated Statements of Operations for the years ended December 31, 2008, 2007 and 2006		F-4

Consolidated Statements of Stockholders’ Equity and Comprehensive Income (Loss) for the years ended December 31, 2008 2007 and 2006		F-5

Consolidated Statements of Cash Flows for the years ended December 31, 2008, 2007 and 2006		F-6

Notes to Consolidated Financial Statements		F-7



18.		Letter re: change in accounting principles. Not applicable.

21.		Subsidiaries of the Registrant. Filed herewith electronically.

22.		Published report regarding matters submitted to vote of security holders. Not applicable.

23.		Consents of experts and counsel.

23.1		Consent of KPMG LLP. Filed herewith electronically.

23.2		Consent of Ralph E. Davis Associates, Inc. Filed herewith electronically.

24.		Power of attorney. Not applicable.

31.		Rule 13a-14(a) /15d-14(a) Certifications.

31.1		Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. Filed herewith electronically.

31.2		Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. Filed herewith electronically.

32.		Section 1350 Certifications.

32.1		Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350. Filed herewith electronically.

32.2		Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350. Filed herewith electronically.



PART I

		PAGE

Item 1.	BUSINESS	2
Item 1A.	RISK FACTORS	10
Item 1B.	UNRESOLVED STAFF COMMENTS	22
Item 2.	PROPERTIES	23
Item 3.	LEGAL PROCEEDINGS	31
Item 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS	32
Item 4A.	DIRECTORS AND EXECUTIVE OFFICERS	33

PART II

Item 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	36
Item 6.	SELECTED FINANCIAL DATA	37
Item 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	37
Item 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	57
Item 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	57
Item 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	57
Item 9A.	CONTROLS AND PROCEDURES	57
Item 9B.	OTHER INFORMATION	58

PART III

Item 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	59
Item 11.	EXECUTIVE COMPENSATION	59
Item 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	59
Item 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	59
Item 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	59

PART IV

Item 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	60


⁽¹⁾		Undeveloped acreage is considered to be those lease acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether such acreage contains proved reserves.

⁽²⁾		Includes acreage owned by Amber.


⁽¹⁾		Does not include wells in which we had only a royalty interest.


(a)(3)		Exhibits. The Exhibits listed in the Index to Exhibits appearing at page 61 are filed as part of this report. Management contracts and compensatory plans required to be filed as exhibits are marked with a “*”.


							Inter-segment
	Oil and Gas			Drilling			Eliminations			Consolidated
	(In thousands)
Year Ended December 31, 2008
Revenues from external customers	$	221,733		$	49,445		$	-		$	271,178
Inter-segment revenues		-			51,074			(51,074	)		-

Total revenues		221,733			100,519			(51,074	)		271,178

Operating income (loss)		(432,650	)		(19,953	)		(11,944	)		(464,547	)

Other income and (expense)¹		(667	)		(11,083	)		11,860			110

Income (loss) from continuing operations, before tax	$	(433,317	)	$	(31,036	)	$	(84	)	$	(464,437	)


Year Ended December 31, 2007
Revenues from external customers	$	136,583		$	58,358		$	-		$	194,941
Inter-segment revenues		-			34,410			(34,410	)		-

Total revenues		136,583			92,768			(34,410	)		194,941

Operating income (loss)		(108,501	)		8,931			(11,644	)		(111,214	)

Other income and (expense)¹		(21,413	)		(8,705	)		1,231			(28,887	)

Income (loss) from continuing operations, before tax	$	(129,914	)	$	226		$	(10,413	)	$	(140,101	)


Year Ended December 31, 2006
Revenues from external customers	$	97,828		$	59,603		$	-		$	157,431
Inter-segment revenues		-			25,033			(25,033	)		-

Total revenues		97,828			84,636			(25,033	)		157,431

Operating income (loss)		(14,424	)		19,655			(12,120	)		(6,889	)

Other income and (expense)¹		(6,426	)		(7,264	)		(2,595	)		(16,285	)

Income (loss) from continuing operations, before tax	$	(20,850	)	$	12,391		$	(14,715	)	$	(23,174	)


December 31, 2008
Total Assets	$	1,798,134		$	163,240		$	(65,960	)	$	1,895,414


December 31, 2007:
Total Assets	$	1,005,884		$	146,314		$	(41,554	)	$	1,110,644


¹		Includes interest and financing costs, gain on sale of marketable securities, unrealized losses on derivative contracts and other miscellaneous income for Oil and Gas, and other miscellaneous income for Drilling. Minority interest is included in inter-segment eliminations.


	Quarter Ended
	March 31,			June 30,			September 30,			December 31,
				(In thousands, except per share amounts)
Year Ended December 31, 2008
Total revenue	$	64,480		$	81,107		$	72,048		$	53,543
Income (loss) from continuing operations before income taxes, discontinued operations and cumulative effect		(20,412	)		(23,217	)		46,941			(467,749	)
Net income (loss)		(19,795	)		(22,373	)		49,831			(459,659	)
Net income (loss) per common share: ¹
Basic	$	(.25	)	$	(.22	)	$	.49		$	(4.56	)
Diluted	$	(.25	)	$	(.22	)	$	.46		$	(4.56	)

Year Ended December 31, 2007
Total revenue	$	41,480		$	47,715		$	51,697		$	54,049
Income (loss) from continuing operations before income taxes, discontinued operations and cumulative effect		(21,728	)		(78,855	)		(9,864	)		(29,654	)
Net income (loss)		(18,341	)		(95,325	)		(5,040	)		(28,481	)
Net income (loss) per common share: ¹
Basic	$	(.33	)	$	(1.53	)	$	(.08	)	$	(.44	)
Diluted	$	(.33	)	$	(1.53	)	$	(.08	)	$	(.44	)


		¹ The sum of individual quarterly net income per share may not agree with year-to-date net income per share as each period’s computation is based on the weighted average number of common shares outstanding during the period.


	DELTA PETROLEUM CORPORATION
	By:	/s/ Roger A. Parker
		Roger A. Parker, Chairman and
		Chief Executive Officer

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


Signature and Title		Date

/s/ Roger A. Parker		March 2, 2009
Roger A. Parker, Director

/s/ Hank Brown		March 2, 2009
Hank Brown, Director

/s/ Kevin R. Collins		March 2, 2009
Kevin R. Collins, Director

/s/ Jerrie F. Eckelberger		March 2, 2009
Jerrie F. Eckelberger, Director

/s/ Aleron H. Larson, Jr.		March 2, 2009
Aleron H. Larson, Jr., Director

/s/ Russell S. Lewis		March 2, 2009
Russell S. Lewis, Director

/s/ James J. Murren		March 2, 2009
James J. Murren, Director

/s/ Jordan R. Smith		March 2, 2009
Jordan R. Smith, Director

/s/ Daniel J. Taylor		March 2, 2009
Daniel J. Taylor, Director

/s/ James B. Wallace		March 2, 2009
James B. Wallace, Director

/s/ John R. Wallace		March 2, 2009
John R. Wallace, Director