10-K

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2007

OR

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

Commission File No. 0-16203

DELTA PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

Delaware	84-1060803
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
370 17th Street, Suite 4300
Denver, Colorado	80202
(Address of principal executive offices)	(Zip Code)

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

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

Title of each class	Name of each exchange on which registered
Common Stock, $0.01 par value	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 x    No o

     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. o

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

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

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

     As of June 30, 2007, the aggregate market value of voting stock held by non-affiliates of the registrant was approximately $1.27 billion, based on the closing price of the Common Stock on the NASDAQ National Market of $20.08 per share. As of February 29, 2008, 102,829,856 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 2008 Annual Meeting of Stockholders.

TABLE OF CONTENTS

		PAGE
PART I
Item 1.	BUSINESS		4
Item 1A.	RISK FACTORS		11
Item 1B.	UNRESOLVED STAFF COMMENTS		22
Item 2.	PROPERTIES		22
Item 3.	LEGAL PROCEEDINGS		30
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		58
Item 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA		59
Item 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE		59
Item 9A.	CONTROLS AND PROCEDURES		59
Item 9B.	OTHER INFORMATION		60
PART III
Item 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE		60
Item 11.	EXECUTIVE COMPENSATION		60
Item 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS		60
Item 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE		60
Item 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES		60
PART IV
Item 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES		61

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

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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,” “predict,” “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; acquisition 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 or drilling activities; 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); our expectation that we will have adequate cash from operations and credit facility borrowings to meet future debt service, capital expenditure and working capital requirements in fiscal year 2008; 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 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, processing plant or pipeline capacity constraints beyond our control;

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

• plans with respect to divestiture of oil and gas properties;

• 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 operating loss and credit carry-forwards.

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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.

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 15 drilling rigs that operate primarily in the Rocky Mountain Region.

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.

Fiscal Year Change

On September 14, 2005, our Board of Directors approved the change of our fiscal year end from June 30 to December 31, effective December 31, 2005. This Form 10-K includes information for the years ended December 31, 2007 and 2006, the six-month transitional period ended December 31, 2005 and for the twelve-month period ended June 30, 2005. In this Form 10-K, when we refer to “fiscal 2008” we mean the twelve-month period ending December 31, 2008.

Overview and Strategy

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

Pursue concurrent development of our core areas

We plan to spend $350.0-$370.0 million on our drilling program during 2008. We expect that approximately 88% of the 2008 drilling capital expenditures will be incurred in our Rocky Mountain development and exploration projects. Many of our targeted development drilling locations are in reservoirs that demonstrate predictable geologic attributes and consistent reservoir characteristics, which typically lead to reliable drilling results.

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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 we achieved significant reserve and production increases as a result of our drilling program. We anticipate that the majority of our 2008 and future reserve and production growth will come through the execution of our drilling program on our large inventory of proved and unproved locations. Our 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 independent engineering evaluation 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 may have a significant effect on the quantities and future values of our reserves. Our reserves in the Rocky Mountain Region, where we plan to increasingly focus our drilling efforts and capital expenditures, are generally characterized as long-lived with low decline rates. We believe the balance of high-return Gulf Coast drilling and long-lived Rockies reserves will allow us to increase near term production rates and cash flow while building our reserve base and lengthening our average reserve life, which was 21.2 years as of December 31, 2007, based on 2007 production.

Maintain high percentage ownership and operational control over our asset base

As of December 31, 2007, we controlled approximately 871,000 net undeveloped acres, representing approximately 98% of our total net acreage position. We retain a high degree of operational control over our asset base, 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. 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. We believe this flexibility to opportunistically pursue exploration and development projects relating to our properties provides us with a meaningful competitive advantage. We also have a 50.0% interest in DHS Drilling Company (“DHS”), as well as a contractual right of priority access to DHS’ fifteen drilling rigs, which are deployed primarily in the Rocky Mountains.

Acquire and maintain acreage positions in high potential resource plays

We believe that our ongoing development of reserves in our core areas should be supplemented with exploratory efforts that may lead to new discoveries in the future. We continually evaluate our opportunities and pursue attractive potential opportunities that take advantage of our strengths. At December 31, 2007, we had significant undeveloped, unproved acreage positions in both the Columbia River Basin and the Central Utah Hingeline plays, 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 anticipate that meaningful drilling and completion results will become known in both areas during 2008.

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

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 February 26, 2008 approximately 12.2 Bcfe of our anticipated production is hedged for 2008.

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Experienced management and operational team with advanced exploration and development technology

Our senior management team has 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, normally associated with completions in the most advanced Rocky Mountain natural gas fields, to our largest Gulf Coast field to improve initial and ultimate production and returns.

Recent Developments

On February 20, 2008, we consummated the sale of 36 million shares of our common stock to Tracinda Corporation (“Tracinda”) for $684.0 million. As a result of the transaction, Tracinda owns approximately 35% of our outstanding common stock and named two members to our Board of Directors, James J. Murren and Daniel J. Taylor, bringing the Board to 12 members. Tracinda has the right to proportional representation on our Board, and based on their current ownership may add up to three additional members at its discretion in the future. It also has a right to proportional representation on all of our Board committees.

Operations

During the year ended December 31, 2007, 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, 2007:

	Proved		%						2007
	Reserves		Natural			% Proved			Production
Areas of Operations	(Bcfe) (1)		Gas			Developed			(MMcfe/d) (2)
Rocky Mountain Region		288.8		90.3	%		25.8	%		19.3
Gulf Coast Region		80.6		58.4	%		49.7	%		23.6
Offshore California		2.0		—	%		100.0	%		2.4
Other		4.2		37.9	%		72.7	%		3.4
Total		375.6		82.4	%		31.8	%		48.7

(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 development on two of our primary areas of operation in the Rocky Mountain and onshore Gulf Coast Regions. For the year ending December 31, 2008, we estimate that our drilling capital budget will range between $350.0 — $370.0 million.

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 fifteen (15) 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 Colorado, Utah, Texas and Wyoming.

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

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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 50.0% interest in DHS Holding Company, controls the board of directors of DHS and has priority access to all of DHS’ drilling rigs for Company use and operations.

At December 31, 2007, DHS owned 15 drilling rigs with depth ratings of approximately 10,000 to 20,000 feet. We have the right to use all of the rigs on a priority basis, although approximately half are currently working for third party operators.

The following table presents our average drilling revenue per day and rigs available for service for the years ended December 31, 2007 and 2006:

	Years Ended December 31,
	2007		2006
Average number of rigs owned during period		16.7		12.3
Total rig days available 1		5,020		4,482
Average drilling revenue per day	$	16,919	$	16,747

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

DHS also owns 100% of Chapman Trucking, which was acquired in November 2005. Employing its 28 trucks and 38 trailers, Chapman ensures DHS rig mobility and provides moving services 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 daywork 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 dayrate during drilling operations, with lower rates or no payment for periods of equipment breakdown. When a rig is mobilized or demobilizes from an operating area, a contract may provide for different dayrates 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.

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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 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 is 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 drills 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. A sustained increase or decrease in the price of natural gas or oil could have a material impact on exploration, development, and production activities by all of DHS’s customers, including us, and could also 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. Although equipment and supplies used in our business are usually available from multiple sources, there is currently a general shortage of drilling equipment and supplies. We believe that these shortages are likely to intensify. The costs and delivery times of equipment and supplies are substantially greater now than in prior periods and are currently escalating. In partial response to this trend, we engaged in a series of transactions during 2004 and 2005 which resulted in our current ownership interest in DHS which provides us with priority access to a fleet of 15 drilling rigs. We have also established arrangements via joint ventures to assure adequate availability of certain other necessary drilling equipment such as tubulars, pipe, frac tanks and supplies on satisfactory terms. There can be no assurance that these arrangements will prevent us from experiencing shortages of, or material price increases in, drilling equipment and supplies, including drill pipe, in the future. Any such shortages could delay and adversely affect our ability to complete or the economics of our planned drilling projects.

Major Customers

During the year ended December 31, 2007, we had two companies that individually accounted for 27% and 13% 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 Footnote 16 to our consolidated financial statements for additional information.

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During 2007, DHS had one major customer other than Delta. Absent a sustained decrease in the price of natural gas or oil as discussed above, we do not believe the loss of any one or several customers would have a material adverse effect on DHS.

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.

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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. At the present time, these laws do not have a material adverse effect on our business. However, during 2007, the state of Colorado, in which we conduct a significant portion of our business and have the majority of our drilling capital budgeted for 2008, passed legislation which requires the Colorado Oil and Gas Conservation Commission (“COGCC”) to promulgate new regulations to facilitate the inclusion of certain other public agencies, including the Colorado Department of Public Health and the Environment, and the Colorado Division of Wildlife, in the COGCC decision making processes related to oil and gas development which includes the permitting of new wells and establishing regulations to prevent or mitigate environmental impacts of oil and gas development. 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 2008, 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

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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 $5.2 million at December 31, 2007. 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, 2007 we had approximately 128 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 or incorporated by reference in this Annual Report on Form 10-K, including our consolidated financial statements and the related notes.

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Risks Related To Our Business And Industries.

Oil and natural gas prices are volatile, and a decrease could adversely affect our revenues, cash flows, profitability, access to capital and ability to grow.

Our revenues, profitability and future rate of growth depend substantially upon the prices we receive for the oil and natural gas we sell, which fluctuate widely. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. The amount we can borrow under our credit facility is subject to periodic re-determinations or our reserves based on prices specified by our bank group at the time of re-determination. Sustained declines in oil and gas prices may adversely affect our financial condition, liquidity and results of operations. Factors that can cause market prices of oil and natural gas to fluctuate include:

• relatively minor changes in the supply of and demand for oil and natural gas;

• market uncertainty;

• the level of consumer product demand;

• weather conditions;

• the proximity and capacity of natural gas pipelines and other transportation facilities;

• U.S. and foreign governmental regulations;

• the price and availability of alternative fuels;

• political and economic conditions in oil producing countries, particularly those in the Middle East, including actions by the Organization of Petroleum Exporting Countries;

• the foreign supply of oil and natural gas; and

• the price of oil and natural gas imports, consumer preferences and overall U.S. and foreign economic conditions.

We are not able to predict future oil and natural gas prices. At various times, excess domestic and imported supplies have depressed oil and natural gas prices. Lower prices may reduce the amount of oil and natural gas that we can produce economically and may also require us to write down the carrying value of our oil and gas properties. Additionally, the location of our producing wells may limit our ability to take advantage of spikes in regional demand and the resulting increase in price. Substantially all of our oil and natural gas sales are made in the spot market or pursuant to contracts based on spot market prices, not long-term fixed price contracts. Any substantial or extended decline in the prices of or demand for oil or natural gas would have a material adverse effect on our financial condition, results of operations and ability to grow.

We may not be able to fund our planned capital expenditures or acquisition activities.

We spend and will continue to spend a substantial amount of capital for the acquisition, exploration, exploitation, development and production of oil and natural gas reserves. Our drilling capital budget is expected to range between $350.0 and $370.0 million for the year ending December 31, 2008. We have historically addressed our short and long-term liquidity needs through the use of cash flow provided by operating activities, borrowings under bank credit facilities, the issuance of equity and debt securities and the sale of non-core assets. We received $684.0 million in gross proceeds from the issuance of 36 million shares to Tracinda Corporation in February 2008 which provides us significant flexibility to execute our plans. Without adequate financing, we may not be able to fully execute our operating and acquisition strategy in the timetable desired or pursue other opportunities. We continually examine the following sources of capital to supplement cash flow from operations, existing availability under our credit facility, and cash on hand:

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• bank borrowings or the issuance of debt securities;

• the issuance of common stock, preferred stock or other equity securities;

• divestiture of non-core properties; and

• joint ventures and similar arrangements.

The availability of these sources of capital will depend upon a number of factors, some of which are beyond our control. These factors include general economic and financial market conditions, oil and natural gas prices and our market value, the success of our exploration and development activities and operating performance. We may be unable to execute our operating strategy if we cannot obtain adequate capital if low oil and natural gas prices, lack of adequate gathering or transportation facilities, operating difficulties or other factors, many of which are beyond our control, cause our revenues and cash flows from operating activities to decrease, we may be limited in our ability to spend the capital necessary to complete our capital expenditures program. In addition, if our borrowing base under our credit facility is re-determined to a lower amount, this could adversely affect our ability to fund our planned capital expenditures through borrowings under our credit facility. After utilizing such sources of financing, we may be forced to raise additional capital through the issuance of equity or debt securities to fund such expenditures. Additional equity or debt financing may not be available to meet our capital expenditure requirements or may only be available on terms dilutive to our existing investors.

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 senior unsecured notes.

As of December 31, 2007, our total outstanding long term liabilities were $426.1 million, with $73.6 million of outstanding borrowings drawn under our credit facility. Our long term indebtedness represented 45% of our total book capitalization at December 31, 2007. As of December 31, 2007, we had $49.9 million additional availability under our credit facility. However, using a portion of the proceeds from our February 2008 equity issuance, we paid down our credit facility to zero. Our 7% senior notes indenture currently limits our incurrence of secured borrowings to $130.0 million. 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 senior 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 senior 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 may be vulnerable in a downturn in general economic conditions or in our business, or we may be unable to carry out capital spending and exploration activities that are important to our growth; and

• we may from time to time fail to be in compliance with covenants under our credit facility, which will require us to seek waivers from our banks.

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We may, under certain circumstances described in the indenture governing our 7% senior notes and our senior credit facility, be able to incur substantially more debt in the future, which may intensify the risks described herein.

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, 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 available data.

The estimated quantities of proved reserves and the discounted present value of future net cash flows attributable to those reserves as of December 31, 2007 and 2006, the six months ended December 31, 2005 and the fiscal year ended June 30, 2005 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. Based on our proved reserves at December 31, 2007, a 10% increase or decrease in oil and gas price used would increase or decrease our proved reserve quantities at that date by approximately +/- 2% and our PV10 by approximately +/- 20%.

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. During the year ended December 31, 2007, our proved reserve replacement rate was 512% (calculated by dividing our total proved reserve changes for the period by our total production for the same period as detailed in Footnote 17 to the accompanying financial statements). These reserve additions were primarily the result of successful developmental and exploratory drilling during 2007 which resulted primarily in proved undeveloped reserve additions mainly in the Rocky Mountain Region.

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:

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• 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 writedowns.

In the past, we have been required to write down the carrying value of our oil and gas properties. 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 fair value.

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. 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.

During the year ended December 31, 2007, impairments of $58.4 million were recorded primarily related to the Howard Ranch and Fuller fields in Wyoming ($37.5 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 2008, 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 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 $26.7 million. During 2006, we recorded a dry hole for our first Hingeline well in Central Utah ($2.4 million) and for several other unsuccessful non-operated projects ($1.9 million).

At December 31, 2007, we had $44.1 million classified as work in process related to exploratory projects. During 2008, these costs will be capitalized as successful wells if proved reserves are found or expensed as dry holes based on final drilling results.

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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:

• unexpected drilling conditions;

• pressure or irregularities in formations;

• equipment failures or accidents;

• adverse changes in prices;

• weather conditions;

• shortages in experienced labor; and

• shortages or delays in the delivery of equipment.

The cost to develop our proved reserves as of December 31, 2007 is estimated to be approximately $585.6 million. 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. 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. We currently own several wells that are capable of producing but are currently shut-in pending the construction of gas gathering systems, pipelines and processing facilities. 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, which include the degree to which pipeline and processing infrastructure exists in the region. Those factors result in basis differentials between the published indices

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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.

Acquisitions are a part of our business strategy and are subject to the risks and uncertainties of evaluating recoverable reserves and potential liabilities.

We could be subject to significant liabilities related to acquisitions by us. The successful acquisition of producing and non-producing properties requires an assessment of a number of factors, many of which are beyond our control. These factors include recoverable reserves, future oil and gas prices, operating costs and potential environmental and other liabilities, title issues and other factors. It generally is not feasible to review in detail every individual property included in an acquisition. Ordinarily, a review is focused on higher valued properties. Further, even a detailed review of all properties and records may not reveal existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. We do not always inspect every well we acquire, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is performed. We cannot assure you that our recent and/or future acquisition activity will not result in disappointing results.

In addition, there is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our strategy of completing acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Our ability to pursue our acquisition strategy may be hindered if we are not able to obtain financing or regulatory approvals.

Acquisitions often pose integration risks and difficulties. In connection with recent and future acquisitions, the process of integrating acquired operations into our existing operations may result in unforeseen operating difficulties and may require significant management attention and financial resources that would otherwise be available for the ongoing development or expansion of existing operations. Possible future acquisitions could result in our incurring additional debt, contingent liabilities and expenses, all of which could have a material adverse effect on our financial condition and operating results.

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.

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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 $14.8 million at December 31, 2007. 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 $200.0 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 $300.0 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.

We currently have a 50.0% ownership interest in and management control of 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.

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:

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• 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 net gains (losses) from effective hedging activities recognized in our statements of operations were $12.9 million, ($4.7 million), ($3.4 million), and ($630,000) for the years ended December 31, 2007, 2006, six months ended December 31, 2005 and year ended June 30, 2005, respectively. These gains and losses are recorded as an increase or decrease in revenues. At December 31, 2007, we had a hedging loss liability of $3.4 million reflected in our consolidated balance sheet based on market prices in effect on December 31, 2007. Our actual hedging results may differ materially from the amount recorded at December 31, 2007.

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. We do not attempt to obtain credit protections such as letters of credit, guarantees or prepayments from our purchasers. We are unable to predict, however, 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.

There is currently a shortage of available drilling rigs and equipment which could cause us to experience higher costs and delays that could adversely affect our operations.

Although equipment and supplies used in our business are usually available from multiple sources, there is currently a general shortage of drilling equipment and supplies. We believe that these shortages are likely to intensify. The costs and delivery times of equipment and supplies are substantially greater now than in prior periods and are currently escalating. In partial response to this trend, during 2004 and 2005 we acquired a controlling interest in a drilling company. Our ownership interest in the drilling company allows us to have priority access to drilling rigs. We have also established arrangements via joint ventures to assure adequate availability of certain other necessary drilling equipment such as tubulars, pipe, frac tanks and supplies on satisfactory terms. There can be no assurance that these arrangements will prevent us from experiencing shortages of, or material price increases in, drilling equipment and supplies, including drill pipe, in the future. Any such shortages could delay and adversely affect our ability to complete or the economics of our planned drilling projects.

Our industry is highly competitive, making our results uncertain.

We operate in the highly competitive areas of oil and gas exploration, development and production. We compete for the purchase of leases from the U.S. government and from other oil and gas companies. These leases include exploration prospects as well as properties with proved reserves. We face competition in every aspect of our business, including, but not limited to:

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• acquiring reserves and leases;

• obtaining goods, services and employees needed to operate and manage our business;

• access to the capital necessary to drill wells and acquire properties; and

• marketing oil and natural gas.

Competitors include multinational oil companies, independent production companies and individual producers and operators. Many of our competitors have greater financial, technological and other resources than we do.

New technologies may cause our current exploration and drilling methods to become obsolete, resulting in an adverse effect on our production.

The oil and natural gas industry is subject to rapid and significant advancements in technology, including the introduction of new products and services using new technologies. As competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. In addition, competitors may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. One or more of the technologies that we currently use or that we may implement in the future may become obsolete, and we may be adversely affected.

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 future 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.

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.

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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.

Risks Related To Our Stock.

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

As of February 20, 2008, our largest stockholder, Tracinda Corporation, beneficially owned 36,128,000 shares of our common stock, or approximately 35% 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 if, after February 20, 2009, Tracinda Corporation increases its percentage ownership of Delta), preemptive rights in connection with future equity issuances by us, and consent rights over certain types of actions. Further, while Tracinda Corporation may not 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.

Following the closing of the Tracinda investment, approximately 65% 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.

Although we have no current plans, arrangements, understandings or agreements to issue any preferred 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.

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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, 2007, we had outstanding options to purchase 2,157,000 shares of common stock at a weighted average exercise price of $9.04. Further, if we sell additional equity or convertible debt securities, such sales could result in increased dilution to our stockholders.

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, the common stock will not be 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, 2007, our directors and executive officers and their respective affiliates collectively and beneficially owned approximately 7.1% of our outstanding common stock.

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

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

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

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

Item 1B. Unresolved Staff Comments.

On December 3, 2007, we received written comments from the Commission staff regarding reserve and accounting information contained in our 2006 report on Form 10-K. We have responded to the comments and are still in the process of providing supplemental information to the Commission staff. While we are not aware of any

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disagreements with the staff and do not believe that any material adjustments will be necessary, the comments are still in the process of being resolved and the outcome of the staff’s review cannot be predicted with certainty.

Item 2. 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 1.8 million acres.

Rocky Mountain Region

The Rocky Mountain Region comprises approximately 77% of our estimated proved reserves as of December 31, 2007. The majority of our undeveloped acreage and drilling inventory is located in this region, where our drilling efforts and capital expenditures will be increasingly focused.

In the Rocky Mountains, our core development activities are centered on four basins that provide a multi-year inventory of development drilling locations. Our exploration ventures are located in two additional basins as well as those four basins that contain our development activity.

Piceance Basin. We are currently focusing our development efforts on the Vega Unit and surrounding leasehold in Mesa County, Colorado, which in combination is referred to as the Vega Area. 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 and the North Vega leasehold. We have a 100% working interest in the Vega Unit and in March of 2007 we entered into an earn-in agreement with another company that allows us to earn up to an additional 12,000 net acres with an average 50% working interest by drilling 128 wells over a 36 month period. This is referred to as the North Vega leasehold. During fiscal 2007 the Company increased proved reserves in the Vega Area almost 90% to 182.5 Bcfe. During 2007 production increased from approximately 3 Mmcf/d at the beginning of the year to approximately 30 Mmcf/d at the end of 2007. The new Collbran Valley natural gas pipeline was completed in late 2006 and provides the Company with 60 Mmcf/d of pipeline takeaway capacity. The increased takeaway capacity has allowed the Company to increase its drilling activity to four rigs running full time at year-end 2007 with the probability of further increases during 2008. We believe that the leasehold position will allow for the drilling of 1,500 – 2,000 locations, which is in excess of a ten year inventory based on our current rate of activity.

In February 2008, we closed a transaction in which we acquired over 1,700 drilling locations on 10-acre spacing and a 95% working interest in 18,250 net acres in the Vega Area. This transaction includes the remaining 50% working interest that we did not own in the North Vega leasehold and a 95% working interest in lands in the Buzzard Creek Federal Unit and acreage north of the Buzzard Creek Unit. Subsequent to this transaction the Company will have an approximate 95-100% working interest in over 20,000 net acres of leasehold in an almost contiguous block covering most of two townships. With the significantly increased acreage position, we have increased our drilling capital budget for the Vega Area to $210 — $215 million for the year ending December 31, 2008.

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 currently has three drilling rigs running full time and has communicated plans to increase activity in 2008. Our drilling capital budget for the year ending December 31, 2008 is approximately $40 — $45 million. At the current pace, this property has in excess of a 5 year drilling inventory.

Paradox Basin. In the Paradox Basin we have five prospect areas: Greentown, Salt Valley, Fisher Valley, Gypsum Valley and Cocklebur Draw. Two of the prospects, the Greentown and Salt Valley in Grand County, Utah, have been drilled with successful exploratory wells.

Greentown. The Greentown project area has three exploratory wells that encountered economic recoverable reserves as of December 31, 2007. The wells flow tested at rates between 2.0 Mmcf/d with 40 Bo/d and 4.0 Mmcf/d with 800 Bo/d. The wells were drilled across our acreage position and are located as far as seven miles apart. Even though

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these wells are widely spaced, they exhibited very consistent electric log characteristics and appear analogous and mapable over a large area. We are developing and delineating the field with a two-rig drilling program. The Greentown project also exhibits and supports the Company’s strategy of targeting reservoirs that demonstrate consistent geologic attributes and are present over large areas. The Company has a 70% working interest in 43,700 gross acres, 30,400 net acres. Assuming continued success at the Greentown project we anticipate accelerating Greentown development with additional rigs in 2008. We have budgeted approximately $40 million for drilling capital expenditures for the year ending December 31, 2008.

Subsequent to year-end we obtained permit approval for a 25 mile natural gas pipeline and processing plant that will service both the Greentown and Salt Valley project areas. Construction on the pipeline has begun and initial operations are projected to begin in mid-year 2008. We estimate the total cost of the pipeline to be $30 — $40 million.

Salt Valley. The Salt Valley project area has had one exploratory well drilled. Additional drilling plans are not expected in 2008 due to the increased effort at Greentown. We have a 70% working interest in 7,100 gross acres, 4,900 net acres. We have not budgeted any significant amount for drilling capital expenditures for the year ending December 31, 2008.

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. The prospects are based on similar geology as that we used in the discovery of the Greentown Field. We have a 70% working interest in 46,500 gross acres, 32,800 net acres, all of which were undeveloped at December 31, 2007.

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 will be focusing our efforts on the shallower Lower Fort Union Formation which produces in numerous fields throughout the Wind River Basin and will limit our activities to under 11,000 feet.

Howard Ranch. During 2007 we commenced our Lower Fort Union evaluation program which included new drilling and the recompletion of two of our deeper wells to the Lower Fort Union with commercially economic production results. We drilled a total of five wells targeting the Lower Fort Union in 2007 with varying results. The Lower Fort Union has a conventional gas component as well as an unconventional gas component, and the wells that experience better economics rely on gas contribution from both reservoirs. Less economic wells were encountered where only one of the reservoirs was present. We have revised our geologic model with the intention of focusing our drilling activity on areas where both conventional and unconventional gas is trapped. At year end we owned an interest in 47,100 net acres with an average working interest of 50%. Our 2008 drilling capital budget for the Howard Ranch is approximately $7- $8 million.

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 about 1,100 barrels of oil per day. We have since acquired and interpreted a 3D seismic survey to further delineate the field and plan to resume development at the end of the first quarter of 2008. Seismic data appears to have identified additional prospects on our acreage position that are similar in size to the Cowboy field. We have acquired a leasehold position of 21,800 net acres on six prospects, and anticipate testing three of these in 2008. We have an interest in 21,800 net acres with a 100% working interest. Our 2008 drilling capital budget for the D-J Basin is approximately $6 - $7 million.

Gulf Coast Region

The Gulf Coast Region comprises approximately 21% of our estimated proved reserves as of December 31, 2007. In the Gulf Coast Region, our primary activities include developing the Newton, Midway Loop and Opossum Hollow Fields.

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Development Projects – Newton, Midway Loop and Opossum Hollow Fields

Newton Field. The Newton Field is located in Newton County, Texas and represents an important asset for the Company in the Gulf Coast Region. 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. Currently, the Company is injecting water into a pilot waterflood that involves a small portion of the field. If the waterflood is successful the Newton Field could experience a significant increase in proven reserves. At year end, proved reserves in the Newton Field were 34.0 Bcfe.

We have also experienced successful exploratory drilling on seismically defined anomalies in the shallower Yegua and Frio formations and plan further drilling activities. Our 2008 capital budget is expected to be $9 — $10 million.

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, 2007 our proved reserves totaled 23.8 Bcfe. The capital budget for the field in the year ending December 31, 2008 is $6 — $7 million.

Opossum Hollow Field. The Opossum Hollow Field is located in McMullen County, Texas, and the Company has an average working interest of 98%. The field currently produces from the Wilcox Formation. In 2007, the Company acquired a 3D seismic survey on its adjacent 74 Ranch leasehold and plans to drill the initial test wells in early 2008. As of December 31, 2007 we had proved reserves of 6.4 Bcfe.

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 119,000 net acres. The Company has drilled two wells, the Joseph #1 and the Federal 23-44, to date. The Joseph #1 was drilled to a total depth of 13,500 feet and was plugged and abandoned as a dry hole. The Federal 23-44 reached total depth of 12,094 feet after drilling through its second primary objective. Operations have been suspended due to BLM-mandated restrictions for raptor nesting. The Federal 23-44 has been classified as a dry hole in the accompanying financial statements as there were no significant hydrocarbon shows encountered in the Navajo Sandstone or Kaibab Formation; however, drilling results confirmed the presence of a large structure. The Federal 23-44 did exhibit oil shows in the Twin Creek Limestone, a secondary objective above the Navajo, and wireline logs suggest the possibility of hydrocarbon saturation in this interval. Oil recovered from the sample cuttings from this limestone has been laboratory tested and typed as Mississippian-aged, which is the same age as the oil that produces from the original Hingeline discovery, the Covenant Field. We believe that the confirmation of Mississippian-aged oil validates our geologic model for hydrocarbon source and migration in the Central Utah Hingeline. We anticipate that the well will be production tested in the third quarter of 2008 after the raptor nesting restrictions have been lifted.

We and our partners control approximately 190,000 gross acres (123,500 net acres) within this play and numerous structural features have been identified on our leasehold. Delta’s recently acquired 110-mile seismic program covering previously generated prospects is currently being interpreted, and preliminary review appears to confirm and enhance original expectations. Final interpretation and drill site selection is expected in early 2008, and permitting of the next well should be underway by the second quarter of 2008. We plan to drill a third well in the third or fourth quarter of 2008. Our drilling capital budget is expected to be $7 — $8 million. The Central Utah Hingeline project is an exploratory area for the Company and does not account for any of our proved reserves at December 31, 2007.

Columbia River Basin. The Columbia River Basin is located in southeast Washington and northeast Oregon. The basin is characterized by over-pressured, tight sand gas formations. Based upon log evaluation of older wells, well testing and core analysis there appear to be multiple potentially productive hydrocarbon bearing sands which lie below a layer of volcanic basalt. We have an interest in 508,000 net acres in the basin, all of which are undeveloped. We plan to commence drilling operations on the Gray 31-23 which will be our first operated well in the basin during the second quarter of 2008. The Columbia River Basin is an exploration project area and does not account for any of our proved reserves as of December 31, 2007.

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Other Operations

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 the Company’s 2008 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 with aggregate carrying values of $14.8 million and $12.5 million at December 31, 2007 and December 31, 2006, 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. 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 has asserted that we 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 post-trial briefing is currently in process. We believe that the government’s assertion is without merit, but we cannot predict with certainty the ultimate outcome of this matter.

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 government has appealed the order and contends that, among other things, the Court erred in finding that it breached the leases, and in allowing the current lessees to stand in the shoes of their predecessors for the purposes of determining the amount of damages that they are entitled to receive. The current lessees are also appealing the order of final judgment to, among other things, challenge the Court’s rulings that they cannot recover their and their predecessors’ sunk costs as part of their restitution claim. 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 pay a portion to landowners and other owners of royalties and similar interests, to pay the litigation expenses and to fulfill certain pre-existing contractual commitments to third parties.

Other Fields

We derive meaningful oil and gas production from fields in non-core regions that will not constitute a significant portion of our capital budget in the future. Our interest in these fields had approximately 4.2 Bcfe in proved reserves as of December 31, 2007.

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DHS Drilling Company Rigs

The Company owns 50.0% of DHS, which as of December 31, 2007 owned fifteen rigs with depth ratings of 10,000 to 20,000 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	WY		2005		1,500		18,000
Rig No. 4	WY		2007		700		12,000
Rig No. 5	CO		2005		700		12,000
Rig No. 6	CO		2005		700		12,000
Rig No. 7	WY		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	TX		2006		1,000		15,000
Rig No. 11	UT		2006		750		11,000
Rig No. 12	UT		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	CO		2007		700		10,500

⁽ⁱ⁾ Rigs No. 2 and No. 3 were sold during the fourth quarter 2007.

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 payment approximates $135,000 per month and our lease will expire in December 2014.

Production

During the years ended December 31, 2007, 2006, six months ended December 31, 2005 and fiscal year ended June 30, 2005 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 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 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.

During the year ended December 31, 2007 the Company recorded an impairment provision of approximately $58.4 million to developed properties primarily related to the Howard Ranch and Fuller fields in Wyoming ($37.5 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 our 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.

During the six months ended December 31, 2005, a dry hole was drilled on a prospect located in Orange County, California. We determined that we would not pursue development in the prospect and accordingly an impairment of $1.3 million was recorded for the full impairment of the remaining leasehold costs related to the prospect.

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Any impairment provisions recognized for developed and undeveloped properties are permanent and may not be restored in future periods. We had no impairment provision attributed to producing properties during the fiscal year ended June 30, 2005.

Reserves Reported to Other Agencies

We did not file any reports during the year ended December 31, 2007 with any federal authority or agency with respect to our estimates of oil and natural gas reserves.

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, 2007 and December 31, 2006, six months ended December 31, 2005 and the fiscal year ended June 30, 2005.

										Six Months Ended					Year Ended
	Years Ended December 31,									December 31,					June 30,
	2007				2006(1)					2005(1)					2005(1)
	Onshore		Offshore		Onshore			Offshore		Onshore			Offshore		Onshore			Offshore
Production volume –
Total production (MMcfe)		16,888		875		15,172			975		6,285			485		13,073			934
Production from continuing operations:
Oil (MBbls)		703		146		856			162		264			81		404			156
Natural Gas (MMcf)		8,601		—		5,438			—		2,634			—		4,963			—
Total (MMcfe)		12,818		875		10,576			975		4,701			485		7,387			934
Net average daily production- continuing operations:
Oil (Bbl)		1,926		399		2,346			445		1,433			439		1,107			427
Natural Gas (Mcf)		23,563		—		14,899			—		14,314			—		13,597			—
Average sales price:
Oil (per barrel)	$	68.85	$	52.96	$	64.37		$	46.75	$	59.62		$	47.12	$	47.92		$	33.37
Natural Gas (per Mcf)	$	4.47	$	—	$	5.79		$	—	$	8.78		$	—	$	5.62		$	—
Hedge gain (loss) (per Mcfe)	$	1.00	$	—	$	(.45	)	$	—	$	(.81	)	$	—	$	(.09	)	$	—
Lease operating costs - (per Mcfe)	$	1.29	$	4.09	$	1.32		$	3.75	$	1.01		$	4.62	$	.76		$	3.90

⁽¹⁾ Revised for operations discontinued in 2007.

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Productive Wells and Acreage

The table below shows, as of December 31, 2007, 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. Productive wells are producing wells capable of production, including shut-in wells. 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		400		100
California:
Offshore		34		2.1		—		—		11,000		700
Onshore		2		.1		15		4.1		2,900		600
Colorado		357		11.6		121		78.8		1,800		1,500
Kansas		5		2.0		1		.6		—		—
Louisiana		12		2.5		3		—		1,400		600
Michigan		1		—		—		—		—		—
Mississippi		2		—		1		.4		600		100
New Mexico		2		—		1		.1		200		—
North Dakota		7		1.0		—		—		5,800		1,100
Oklahoma		205		2.0		9		.5		2,900		600
Texas (4)		260		56.1		51		15.6		21,100		12,000
Utah		—		—		—		—		200		100
Wyoming		13		11.5		24		19.1		3,100		2,300
		900		88.9		241		119.3		51,400		19,700

(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.

Undeveloped Acreage

At December 31, 2007, we held undeveloped acreage by state as set forth below:

	Undeveloped Acres (1) (2)
Location	Gross		Net
California, onshore		500		200
California, offshore		64,900		15,800
Colorado		79,500		54,800
Kansas		200		200
Montana		6,100		3,700
North Dakota		3,200		500
Oklahoma		100		—
Oregon		419,400		97,000
Texas		44,500		29,100
Utah		318,600		185,500
Washington		834,500		411,300
Wyoming		145,300		72,500
Total		1,916,800		870,600

(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.

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Drilling Activity

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

									Six Months Ended				Year Ended
	Years Ended December 31,								December 31,				June 30,
	2007				2006				2005				2005
	Gross		Net		Gross		Net		Gross		Net		Gross		Net
Exploratory Wells (1):
Productive:
Oil		5		4.75		4		3.15		2		1.42		5		3.94
Gas		4		3.09		4		4.00		—		—		3		1.15
Nonproductive		5		4.16		4		3.50		6		3.83		8		7.15
Total		14		12.00		12		10.65		8		5.25		16		12.24
Development Wells (1):
Productive:
Oil		10		9.55		14		11.83		11		9.90		6		4.90
Gas		89		58.48		37		20.12		5		5.00		82		68.80
Nonproductive		2		1.13		1		1.00		2		1.50		7		7.00
Total		101		69.16		52		32.95		18		16.40		95		80.70
Total Wells (1):
Productive:
Oil		15		14.30		18		14.98		13		11.32		11		8.84
Gas		93		61.57		41		24.12		5		5.00		85		69.95
Nonproductive		7		5.29		5		4.50		8		5.33		15		14.15
Total Wells		115		81.16		64		43.60		26		21.65		111		92.94

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

Present Drilling Activity

The following represents our planned exploration and development activities for the year ending December 31, 2008:

	Gross Drilling		Drilling
Areas of Operations	Locations		Budget
			(In millions)
Rocky Mountain Region		174 - 196	$	310 - $323
Gulf Coast Region		10 -   12	$	24 - $  27
Other		1 -     2	$	16 - $  20
Total		185 - 210	$	350 - $370

Item 3. Legal Proceedings

Offshore Litigation

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

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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 has asserted that we 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 post-trial briefing is currently in process. We believe that the government’s assertion is without merit, but we cannot predict with certainty the ultimate outcome of this matter.

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 government has appealed the order and contends that, among other things, the Court erred in finding that it breached the leases, and in allowing the current lessees to stand in the shoes of their predecessors for the purposes of determining the amount of damages that they are entitled to receive. The current lessees are also appealing the order of final judgment to, among other things, challenge the Court’s rulings that they cannot recover their and their predecessors’ sunk costs as part of their restitution claim. 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 pay a portion to landowners and other owners of royalties and similar interests, to pay the litigation expenses and to fulfill certain pre-existing contractual commitments to third parties.

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 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 Securities and Exchange Commission (“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. The stay will remain in effect until the Court rules on the motion.

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Castle/Longs Trust Litigation

As a result of the acquisition of Castle Energy in April 2006, our 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 in the amount of $964,000, plus prejudgment interest, have been granted by the trial court and upheld on appeal. We intend to vigorously defend the Longs Trust breach of contract claims. We have not accrued any recoveries associated with the judgment against the Longs Trust, but will do so when and if they are ultimately collected.

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.

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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		46	Chairman, Chief Executive Officer and a Director	May 1987 to Present
John R. Wallace		48	President, Chief Operating Officer and a Director	October 2003 to Present
Kevin K. Nanke		43	Treasurer and Chief Financial Officer	December 1999 to Present
Stanley F. Freedman		59	Executive Vice President, General Counsel and Secretary	January 2006 to Present
Hank Brown		68	Director	June 2007 to Present
Kevin R. Collins		51	Director	March 2005 to Present
Jerrie F. Eckelberger		63	Director	September 1996 to Present
Aleron H. Larson, Jr.		62	Director	May 1987 to Present
Russell S. Lewis		53	Director	June 2002 to Present
James J. Murren		46	Director	February 2008 to Present
Jordan R. Smith		73	Director	October 2004 to Present
Neal A. Stanley		60	Director	October 2004 to Present
Daniel J. Taylor		51	Director	February 2008 to Present
James B. Wallace		78	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

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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 us, 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. 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 currently serves as the President of the University of Colorado. Prior to joining CU in June 2005 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. 

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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 President and CEO 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 firms. He has been a member of the Board of Delta since June 2002. From February 2002 until January 2005 Mr. Lewis served as Executive Vice President and General Manager of VeriSign Name and Directory Services (VRSN) Group, which managed a significant portion of the internet’s critical .com and .net addressing infrastructure. 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 also served on the Boards 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 has a Bachelor of Arts degree in Economics from Haverford College and an MBA from the Harvard School of Business.

James J. Murren is the President and Chief Operating Officer of MGM Mirage. He is also a member of the Board of Directors and the Executive Committee. Mr. Murren has also served as the Chief Financial Officer of the MGM Mirage from January 1998 to August 2007 and Treasurer of MGM Mirage from November 2001 to August 2007. Prior to the 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.

Neal A. Stanley founded Teton Oil & Gas Corporation in Denver, Colorado and has served as President and sole shareholder since 1991.  From 1996 to June 2003, he was Senior Vice President – Western Region for Forest Oil Corporation, Denver, Colorado.  Since December 2005, Mr. Stanley has served as a member of the Board of Directors and Compensation Committee for Calgary based Pure Energy Services Ltd., which is listed on the Toronto Stock Exchange under the symbol PSV. Mr. Stanley has over thirty years of experience in the oil and gas business.  Since 1995, he has been a member of the Executive Committee of the Independent Petroleum Association of Mountain States, and served as its President from 1999 to 2001.  Mr. Stanley received a Bachelor of Science degree in Mechanical Engineering from the University of Oklahoma in 1975.

Daniel J. Taylor has been an executive of Tracinda Corporation since February 2007 and has served as a Director of the 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 Stanley serve as the Audit Committee; Messrs. Eckelberger, Collins, Lewis, Smith and Stanley serve as the Compensation Committee; and Messrs. Smith, Collins, Eckelberger, Lewis and Stanley serve as the Nominating & Governance Committee.

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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.

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

PART II

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

Market Information; Dividends

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

Quarter Ended	High		Low
September 30, 2005	$	20.82	$	14.01
December 31, 2005		22.31		15.07
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	$	17.57	$	23.12
June 30, 2007		18.62		24.94
September 30, 2007		14.40		20.35
December 31, 2007		21.58		13.06

On February 28, 2008, the closing price of our common stock was $24.86. We have not paid dividends on our common stock, and we do not expect to do so in the foreseeable future. Our current debt agreements restrict the payment of dividends.

Approximate Number of Holders of Common Stock

The number of holders of record of our common stock at February 28, 2008 was approximately 1,500 which does not include an estimated 8,200 additional holders whose stock is held in “street name.”

Recent Sales of Unregistered Securities

During the year ended December 31, 2007, we did not have any sale of securities in transactions that were not registered under the Securities Act of 1933, as amended (“Securities Act”) that have not been reported in a Form 8-K or Form 10-Q.

Issuer Purchases of Equity Securities

We did not repurchase any of our shares of common stock during the quarter ended December 31, 2007.

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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 December 31,						December 31,			Years Ended June 30,
	2007			2006				2005		2005			2004			2003
	(In thousands, except per share amounts)
Total Revenues	$	164,190		$	146,660		$	48,326		$	56,612		$	9,799		$	5,551
Income (loss) from Continuing Operations	$	(160,228	)	$	(33,623	)	$	(29,203	)	$	(10,353	)	$	(12,081	)	$	(8,156	)
Net Income (Loss)	$	(149,347	)	$	435		$	(590	)	$	15,050		$	5,056		$	1,257
Income/(Loss) Per Common Share
Basic	$	(2.44	)	$	.01		$	(.01	)	$	.37		$	.19		$	.05
Diluted	$	(2.44	)	$	.01		$	(.01	)	$	.36		$	.17		$	.05
Total Assets	$	1,105,195		$	929,323		$	693,393		$	512,983		$	272,704		$	86,847
Total Liabilities	$	569,494		$	473,700		$	357,442		$	276,746		$	86,462		$	38,944
Minority Interest	$	27,296		$	27,390		$	15,496		$	14,614		$	245		$	—
Stockholders’ Equity	$	508,405		$	428,233		$	320,455		$	221,623		$	185,997		$	47,903
Total Long-Term Liabilities	$	426,298		$	374,121		$	257,743		$	222,596		$	72,172		$	33,082

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, 2007, we had estimated proved reserves that totaled 375.6 Bcfe, of which 31.8% were proved developed, with an after-tax PV-10 value of $701.9 million. As of December 31, 2007, we achieved net production of 48.7 Mmcfe per day and net continuing production of 37.5 Mmcfe per day.

As of December 31, 2007, our reserves were comprised of approximately 309.5 Bcf of natural gas and 11.0 Mmbbls of crude oil, or 82.4% gas on an equivalent basis. Approximately 21% of our proved reserves were located in the Gulf Coast, 77% in the Rocky Mountains, and 2% in other locations. We expect that our drilling efforts and capital expenditures will focus increasingly on the Rockies, where approximately 87-89% of our fiscal 2008 drilling budget is allocated and more than one-half of our undeveloped acreage is located. As of December 31, 2007, we controlled approximately 871,000 net undeveloped acres, representing approximately 98% of our total acreage position. We retain a high degree of operational control over our asset base, with an average working interest in excess of 85% (excluding CRB properties) as of December 31, 2007. 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. We also have a controlling ownership interest in a drilling company, providing the benefit of access to 15 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.

2008 Outlook

We expect our 2008 oil and gas production to increase 45% to 60% due to the expected results of our budgeted drilling program. For calendar year 2008, we have preliminarily established a drilling budget of approximately $350.0 to $370.0 million. We are concentrating a substantial portion of this budget on the development of our Paradox, Piceance and Wind River Basin assets in the Rockies, and to a lesser extent, our Newton and Midway Loop fields in the Gulf Coast. State of the art geologic and seismic geophysical modeling indicates that these fields have targeted geologic formations containing substantial hydrocarbon deposits that can be economically developed. Recently completed successful wells in several of our Rocky Mountain development programs have found multiple

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accumulations of tight sand reservoirs at various depths, characterized by low permeability and high pressure. These types of reservoirs possess predictable geologic attributes and consistent reservoir characteristics which typically result in a higher drilling success rate and lower per well cost and risk.

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 by the natural production and reserve decline associated with oil and gas properties. In addition to developing new reserves, we compete to acquire additional reserves, which involves judgments regarding recoverable reserves, future oil and gas prices, operating costs and potential environmental and other liabilities, title issues and other factors. During periods of historically high oil and gas prices, third party contractor and material cost increases are more prevalent due to increased competition for goods and services. Other challenges we face include attracting and retaining qualified personnel, gaining access to equipment and supplies and maintaining access to capital on sufficiently favorable terms.

We have taken the following steps to mitigate the challenges we face. We actively 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 review of market conditions, available hedge prices and our operating strategy. As of February 26, 2008, our derivative contracts cover approximately 12.2 Bcfe of our estimated 2008 oil and gas production. Our interest in a drilling and trucking company allows us to mitigate the increasing challenge for rig availability in the Rocky Mountains and also helps to control third party contractor and material costs. Our business strengths include a multi-year inventory of attractive drilling locations and a diverse balance of high return Gulf Coast properties and long lived Rockies reserves, which we believe will allow us to grow reserves and replace and expand production organically without having to rely solely on acquisitions.

Recent developments

During the year ended December 31, 2007, we achieved the following:

• Increased proved reserves to 375.6 Bcfe at December 31, 2007, an increase of 24.2%, or 31.2% after considering current year sales and purchases, compared to proved reserves as of December 31, 2006 of 302.4 Bcfe.

• Our total production for the year ended December 31, 2007 was 17.8 Bcfe. Adjusted for asset dispositions, our production from continuing operations increased 19% to 13.7 Bcfe, compared to 11.6 Bcfe for the prior year period, primarily as a result of successful exploratory and development drilling during 2007.

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Results of Operations

The following discussion and analysis relates to items that have affected our results of operations for the years ended December 31, 2007, 2006 and 2005, six months ended December 31, 2005 and 2004, and the fiscal year ended June 30, 2005. During 2005, we changed our fiscal year end from June 30 to December 31, effective December 31, 2005. Accordingly, we have presented below for comparative purposes unaudited historical statements of operations for the year ended December 31, 2005 and six months ended December 31, 2004. 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.

										Six Months Ended						Year Ended
	Years Ended December 31,									December 31,						June 30,
	2007			2006			2005			2005			2004			2005
							(Unaudited)						(Unaudited)
Revenue:
Oil and gas sales	$	94,559		$	94,223		$	75,176		$	42,643		$	19,913		$	52,446
Contract drilling and trucking fees		56,777			57,149			13,592			9,096			300			4,796
Gain (loss) on effective derivative instruments, net		12,854			(4,712	)		(3,950	)		(3,413	)		(93	)		(630	)
Total Revenue		164,190			146,660			84,818			48,326			20,120			56,612
Operating Expenses:
Lease operating expense		20,142			17,655			12,606			6,507			3,193			9,291
Transportation expense		3,684			978			994			680			81			394
Production taxes		5,559			4,784			4,307			2,455			1,563			3,415
Depreciation, depletion and amortization — oil and gas		63,373			53,980			21,594			12,411			4,862			14,055
Depreciation and amortization — drilling and trucking		22,052			16,404			3,987			2,847			386			1,525
Exploration expense		9,062			4,690			6,933			2,061			1,283			6,155
Dry hole costs and impairments		85,084			15,682			5,521			5,423			2,673			2,771
Drilling and trucking operations		36,954			34,163			9,413			5,821			1,074			4,666
General and administrative		49,621			35,696			26,470			16,491			6,951			16,930
Gain on sale of oil and gas properties		—			(20,034	)		—			—			—			—
Total operating expenses		295,531			163,998			91,825			54,696			22,066			59,202
Operating loss		(131,341	)		(17,338	)		(7,007	)		(6,370	)		(1,946	)		(2,590	)
Other income and (expense):
Other income (expense)		376			(154	)		(427	)		(36	)		(179	)		(570	)
Gain on sale of marketable securities		—			—			1,194			1,194			—			—
Gain on sale of investment in LNG		—			1,058			—			—			—			—
Gain (loss) on ineffective derivative instruments, net		(2,902	)		11,722			(14,767	)		(14,437	)		—			(330	)
Minority interest		1,231			(2,595	)		14			(688	)		315			1,017
Losses from unconsolidated affiliates		(393	)		—			—			—			—			—
Interest and financing costs		(27,199	)		(26,316	)		(14,540	)		(8,866	)		(2,206	)		(7,880	)
Total other expense		(28,887	)		(16,285	)		(28,526	)		(22,833	)		(2,070	)		(7,763	)
Loss from continuing operations before income taxes and discontinued operations		(160,228	)		(33,623	)		(35,533	)		(29,203	)		(4,016	)		(10,353	)
Income tax benefit (expense)		(2,677	)		12,623			17,485			10,873			—			11,969
Net income (loss) from continuing operations		(162,905	)		(21,000	)		(18,048	)		(18,330	)		(4,016	)		1,616
Income from discontinued operations of properties sold, net of tax		17,556			9,163			11,966			5,952			12,770			13,434
Gain (loss) on sale of oil and gas properties, net of tax		(3,998	)		6,712			11,788			11,788			—			—
Extraordinary gain, net of tax		—			5,560			—			—			—			—
Net income (loss)	$	(149,347	)	$	435		$	5,706		$	(590	)	$	8,754		$	15,050

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

Net Income (Loss). Net loss was $149.3 million, or $2.44 per diluted common share, for the year ended December 31, 2007, compared to net income of $435,000 or $.01 per diluted common share, for the year ended December 31, 2006. Loss from continuing operations increased from $21.0 million for the year ended December 31, 2006 to a loss of $162.9 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.

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Oil and Gas Sales. During the year ended December 31, 2007, oil and gas sales from continuing operations were $94.6 million, as compared to $94.2 million for the comparable period a year earlier. During the year ended December 31, 2007, production from continuing operations increased by 19%, however, this was offset by a 23% decrease in the average gas price. The average onshore gas price received during the year ended December 31, 2007 was $4.47 per Mcf compared to $5.79 per Mcf for the year earlier period, primarily due to the increase in the basis differential applicable to Rocky Mountain natural gas. The average onshore oil price received during the year ended December 31, 2007 increased to $68.85 per Bbl compared to $64.37 per Bbl for the year earlier period and the offshore oil price increased to $52.96 per Bbl during the year ended December 31, 2007 compared to $46.75 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. At December 31, 2007 DHS owned 15 drilling rigs with depth ratings of approximately 10,000 to 20,000 feet. We have the right to use all of the rigs on a priority basis, although approximately half are currently working for third party operators.

Drilling revenues for the year ended December 31, 2007 remained flat at $50.5 million compared to $50.0 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)
	Onshore		Offshore		Onshore			Offshore
Production – Continuing Operations:
Oil (MBbl)		703		146		856			162
Gas (MMcf)		8,600		—		5,438			—
Production – Discontinued Operations:
Oil (MBbl)		236		—		335			—
Gas (MMcf)		2,652		—		2,585			—
Total Production (MMcfe)		16,888		875		15,173			975
Average Price – Continuing Operations:
Oil (per barrel)	$	68.85	$	52.96	$	64.37		$	46.75
Gas (per Mcf)	$	4.47	$	—	$	5.79		$	—
Costs per Mcfe – Continuing Operations:
Hedge gain (loss)	$	1.00	$	—	$	(.45	)	$	—
Lease operating expense	$	1.29	$	4.09	$	1.32		$	3.75
Production taxes	$	.43	$	.07	$	.45		$	.05
Transportation costs	$	.29	$	—	$	.09		$	—
Depletion expense	$	4.69	$	1.47	$	4.85		$	1.08

⁽¹⁾ Revised for operations discontinued in 2007.

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Lease Operating Expense. Lease operating expenses for the year ended December 31, 2007 were $20.1 million compared to $17.7 million for the year earlier period. Lease operating expense from continuing operations for onshore properties for the year ended December 31, 2007 was $1.29 per Mcfe as compared to $1.32 per Mcfe for the year earlier period.

Depreciation, Depletion and Amortization – oil and gas. Depreciation, depletion and amortization expense increased 17% to $63.4 million for the year ended December 31, 2007, as compared to $54.0 million for the year earlier period. Depletion expense for the year ended December 31, 2007 was $61.5 million compared to $52.4 million for the year ended December 31, 2006. The 17% increase in depletion expense was due to a 19% increase in production from continuing operations, slightly offset by a 3% decrease in the onshore depletion rate. Our onshore depletion rate decreased to $4.69 per Mcfe for the year ended December 31, 2007 from $4.85 per Mcfe for the year earlier period. The decrease is partially due to lower finding costs per Mcfe on the Company’s extensive 2007 Rockies drilling program. Based on impairments recorded in 2007 and the Company’s continued focus in the Rockies which continues to result in better well economics, the Company anticipates its depletion rate will continue to decrease in 2008.

Depreciation and Amortization – drilling and trucking. Depreciation and amortization expense – drilling and trucking increased to $22.1 million for the year ended December 31, 2007 as compared to $16.4 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.

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. Current year 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 $26.7 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, 2007, the Company recorded impairments totaling approximately $58.4 million primarily related to the Howard Ranch and Fuller fields in Wyoming ($37.5 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 that are held for sale at December 31, 2007.

Drilling and Trucking Operations. We had drilling and trucking operations expense of $37.0 million during the year ended December 31, 2007 compared to $34.2 million during the year ended December 31, 2006. The significant increase in expenses was due to the greater average overall number of rigs in operation for DHS in 2007 than in 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.

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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.

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).

Gain (Loss) on Ineffective 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 $2.9 million for the year ended December 31, 2007 and a gain of $11.7 million for the year ended December 31, 2006.

Minority Interest. 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 decreased minority interest expense.

Interest and Financing Costs, Net. Interest and financing costs increased 3% to $27.2 million for the year ended December 31, 2007, as compared to $26.3 million for the comparable year earlier period. The increase is primarily related to higher average debt balances on DHS’ 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.

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 $2.7 million includes a valuation allowance of $57.4 million. During the year ended December 31, 2006, an income tax benefit of $12.6 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, the Washington County, Colorado properties sold in October 2007, and the Midway Loop, Texas properties held for sale at December 31, 2007. The results of operations on these assets, net of tax, during the years ended December 31, 2007 and 2006 were $17.6 million and $9.2 million, respectively. The significant increase in 2007 was primarily due to new wells in 2007 from the Company’s Midway Loop drilling program or wells drilled in 2006 impacting sales for the full year in 2007.

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”).

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Year Ended December 31, 2006 Compared to Year Ended December 31, 2005 (Unaudited)

Net Income. Net income decreased $5.3 million to $435,000, or $.01 per diluted common share, for the year ended December 31, 2006, as compared to net income of $5.7 million, or $.13 per diluted common share, for the year ended December 31, 2005. This decrease was primarily due to an $10.3 million increase in operating losses resulting from higher revenue and a $20.0 million gain on the sale of oil and gas properties, offset by higher depreciation, depletion, and amortization expense, higher exploration, dry hole and abandonment costs, and increased general and administrative expenses.

Oil and Gas Sales. During the year ended December 31, 2006, oil and natural gas revenue from continuing operations increased 25% to $94.2 million, as compared to $75.2 million for the year ended December 31, 2005. The increase was the result of a 19% increase in average daily production from continuing operations over the year ended December 31, 2005, an increase in average onshore oil price received in the year ended December 31, 2006 of $64.37 per Bbl compared to $54.77 per Bbl during the same period in 2005, and an increase in offshore oil price received of $46.75 per Bbl during the year ended December 31, 2006 compared to $41.46 during the year ended December 31, 2005, partially offset by a decrease in the average onshore gas price received during the year ended December 31, 2006 of $5.79 per Mcf compared to $7.09 per Mcf received in the year ended December 31, 2005.

Net realized losses from effective hedging activities were $4.7 million and $4.0 million for the years ended December 31, 2006 and 2005, respectively. The increase in 2006 in realized hedging losses is primarily due to higher oil prices. These losses are recorded as a decrease in total revenues.

Contract Drilling and Trucking Fees. At December 31, 2006 DHS owned 16 drilling rigs with depth ratings of approximately 7,500 to 20,000 feet. We have the right to use all of the rigs on a priority basis, although approximately three-fourths were working for third party operators at December 31, 2006.

Drilling revenues for the year ended December 31, 2006 increased to $50.0 million compared to $13.0 million for the prior year period. Drilling revenue is earned under daywork 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. 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. At December 31, 2006 there were 16 DHS rigs in operation compared to eight rigs in operation at December 31, 2005.

Trucking revenues for the year ended December 31, 2006 were $7.1 million compared to $630,000 for the prior year period. Trucking revenues were insignificant during the year ended December 31, 2005 as the acquisition of Chapman Trucking Company was completed in November, 2005.

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Production and Cost Information

Production volumes, average prices received and cost per equivalent Mcf for the years ended December 31, 2006 and 2005 are as follows:

	Year Ended December 31,
	2006(1)					2005(1)
	Onshore			Offshore		Onshore			Offshore
Production – Continuing Operations:
Oil (MBbl)		856			162		508			162
Gas (MMcf)		5,438			—		5,727			—
Production – Discontinued Operations:
Oil (MBbl)		335			—		387			—
Gas (MMcf)		2,585			—		2,371			—
Total Production (MMcfe)		15,173			975		13,474			972
Average Price – Continuing Operations:
Oil (per barrel)	$	64.37		$	46.75	$	54.77		$	41.46
Gas (per Mcf)	$	5.79		$	—	$	7.09		$	—
Costs per Mcfe – Continuing Operations:
Hedge gain (loss)	$	(.45	)	$	—	$	(.45	)	$	—
Lease operating expense	$	1.32		$	3.75	$	.95		$	4.42
Production taxes	$	.45		$	.05	$	.48		$	.06
Transportation costs	$	.09		$	—	$	.11		$	—
Depletion expense	$	4.85		$	1.08	$	2.27		$	.79

⁽¹⁾ Revised for operations discontinued in 2007.

Lease Operating Expense. Lease operating expenses for the year ended December 31, 2006 were $17.7 million compared to $12.6 million for the same period a year earlier. Lease operating expense increased due to our 19% increase in production and due to increased per unit costs. Lease operating expense from continuing operations for onshore properties for the year ended December 31, 2006 was $1.32 per Mcfe as compared to $.95 per Mcfe for the same period a year earlier. Lease operating expense from continuing operations for offshore properties was $3.75 per Mcfe for the year ended December 31, 2006 and $4.42 per Mcfe for the same period a year earlier. The increase in onshore per unit lease operating expenses is a result of generally rising field costs due to increased demand for services, and is also affected by overall infrastructure costs for some properties that were still experiencing limited production due to pipeline constraints.

Depreciation, Depletion and Amortization – oil and gas. Depreciation, depletion and amortization expense increased 130% to $54.0 million in the year ended December 31, 2006, as compared to $21.6 million for the year ended December 31, 2005. Depletion expenses for our onshore properties increased to $4.85 per Mcfe during the year ended December 31, 2006 from $2.27 per Mcfe for the year ended December 31, 2005. The depletion rate increase is partially due to certain deep, multi-stage completion projects in which the majority of our well costs are depleted over completed zones that have not met initial expectations. Also, during the year ended December 31, 2006, a $3.0 million developmental dry hole in South Angleton was added to the depletion pool.

Depreciation and Amortization – drilling and trucking. Depreciation and amortization expense – drilling and trucking increased to $16.4 million for the year ended December 31, 2006 as compared to $4.0 million for the prior year period. This increase can be attributed to additional rigs acquired by DHS Drilling Company.

Exploration Expense. Exploration expense consists of geological and geophysical costs and lease rentals. Our exploration costs for the year ended December 31, 2006 were $4.7 million compared to $6.9 million for the year ended December 31, 2005. Activities in the year ended December 31, 2006 included activities in our Columbia River Basin, Washington, Grand County, Utah and Newton County, Texas projects. During the year ended December 31, 2005, our most significant exploration cost was related to the $1.4 million Newton 3D seismic shoot covering 58 square miles which was completed and processed during 2005. In addition, we acquired 2D data in the Gulf Coast Region and also began acquiring geophysical data on the Columbia River Basin properties in the state of Washington.

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Dry Hole Costs and Impairments. We incurred dry hole costs of approximately $4.3 million for the year ended December 31, 2006 compared to $4.2 million for the same period in the prior year. During 2005, a significant portion of these costs were related to dry holes that were drilled in Utah and California. 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 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 that were held for sale at December 31, 2006. During 2007, 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 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.

During the year ended December 31, 2005, a dry hole was drilled on a prospect located in California. Based on drilling results and evaluation of the prospect, we determined that we would not pursue development and accordingly an impairment of $1.3 million was recorded for the full impairment of the remaining leasehold costs related to the prospect.

Drilling and Trucking Operations. We had drilling and trucking operations expense of $34.2 million during the year ended December 31, 2006 compared to $9.4 million during the year ended December 31, 2005. The significant increase in expenses was due to an increase in the number of rigs in operation, 16 rigs as of December 31, 2006 compared to eight rigs at December 31, 2005.

General and Administrative Expense. General and administrative expense increased 35% to $35.7 million for the year ended December 31, 2006 as compared to $26.5 million for the year ended December 31, 2005. The increase in general and administrative expenses is primarily attributed to an increase in non-cash equity compensation of $2.1 million, a 45% increase in technical and administrative staff and related personnel costs, and the expansion of our office facility. In addition, $2.1 million of the increase is related to DHS general and administrative expense. DHS general and administrative expense increased with added headcount for DHS growth during the year ended December 31, 2006 and a full year of operations in 2006 compared to nine months of operations in 2005.

Gain on Sale of Oil and Gas Properties. 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. Accordingly, the Company recorded a $13.0 million gain ($8.1 million, net of tax) and a $11.2 million reduction to property during the first quarter of 2006 as a result of the closing of the transaction.

In November 2006, the Company sold certain undeveloped property interests in the Columbia River Basin for proceeds of $2.0 million. The Company recorded a gain on the transaction of $1.1 million.

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 could be 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, and is the manager of, PGR.

Gain on Sale of Marketable Security. During the year ended December 31, 2005, the Company sold investment securities classified as available-for-sale securities resulting in a realized gain of $1.2 million.

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

Gain (Loss) on Ineffective Derivative Instruments, Net. During the year ended December 31, 2005, our gas derivative contracts became ineffective and no longer qualified for hedge accounting. Hedge ineffectiveness results from different changes in the NYMEX contract terms and the physical location, grade and quality of our oil and gas production. The change in fair value of our NYMEX gas contracts is reflected in earnings, as opposed to being

45

recorded in other comprehensive income (loss), a component of stockholders’ equity. As a result, we recognized an $11.7 million gain and a $14.8 million loss in our statements of operations for the years ended December 31, 2006 and 2005, respectively. As commodity prices fluctuate, we will record our NYMEX gas derivative contracts at market value with any changes in market value recorded through unrealized gain (loss) on derivative contracts in our statement of operations.

Minority Interest. 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, 2006 DHS generated a greater profit, resulting in increased minority interest expense.

Interest and Financing Costs. Interest and financing costs increased 81% to $26.3 million for the year ended December 31, 2006, as compared to $14.5 million for the year ended December 31, 2005. The increase is primarily related to the increase in the average amount outstanding under our credit facility, higher interest rates and the increased long term debt balance related to the DHS credit facility. In addition, during 2006, DHS incurred a pre-payment penalty of $820,000 and wrote-off deferred financing costs of $431,000 to pay-off a term loan that was replaced with a lower interest rate term loan.

Income tax benefit. During the year ended December 31, 2006, an income tax benefit of $12.6 million was recorded for continuing operations at an effective tax rate of 37.5% compared to an income tax benefit of $17.5 million and an effective tax rate of 49.2% for the year ended December 31, 2005. The 2005 rate was significantly affected by the reversal of a valuation allowance related to the Company’s deferred tax assets.

Discontinued Operations. Discontinued operations include the Deerlick Creek Field in Tuscaloosa County, Alabama, which was sold in September 2005, 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, and 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, the Washington County, Colorado properties sold in October 2007, and the Midway Loop, Texas properties held for sale at December 31, 2007. The results of operations on these assets, net of tax, during the years ended December 31, 2006 and 2005 were $9.2 million and $12.0 million, respectively.

Extraordinary Gain. An extraordinary gain was recorded during the year ended December 31, 2006 as required by SFAS 141. Due to the excess fair value of the assets compared to the purchase price of the transaction and the Company’s intention to sell the oil and gas properties, Delta recorded a $5.6 million extraordinary gain, net of tax, during the year ended December 31, 2006. The oil and gas properties acquired from Castle were in fact sold during August 2006.

Six Months Ended December 31, 2005 Compared to Six Months Ended December 31, 2004 (Unaudited)

Net Income. Net income decreased $9.5 million to a net loss of $590,000 or $.01 per diluted common share for the six months ended December 31, 2005, as compared to net income of $8.8 million or $.21 per diluted common share for the six months ended December 31, 2004. This decrease was primarily due to a $14.4 million loss for ineffective hedges, $3.4 million of realized losses on effective hedging contracts, higher exploration and dry hole costs, increased general and administrative expenses of $9.5 million due to the growth in the Company’s operations and activities, and increased interest and financing costs of $6.7 million due to higher average debt outstanding.

Revenue. During the six months ended December 31, 2005, oil and natural gas revenue from continuing operations increased 114% to $42.6 million, as compared to $19.9 million for the six months ended December 31, 2004. The increase was the result of an average onshore gas price received during the six months ended December 31, 2005 of $8.78 per Mcf compared to $5.56 per Mcf received in the six months ended December 31, 2004, an increase in average onshore oil price received in the six months ended December 31, 2005 of $59.62 per Bbl compared to $45.41 per Bbl during the same period in 2004, an increase in offshore oil price received of $47.12 per Bbl during the six months ended December 31, 2005 compared to $30.66 during the six months ended December 31, 2004, and a 44% increase in continuing average daily production over the six months ended December 31, 2004.

Cash payments required on our effective hedging activities impacted revenues during the six months ended December 31, 2005 and 2004. The cost of settling our effective hedging activities was $3.4 million and $93,000 during the six months ended December 31, 2005 and 2004, respectively.

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Contract Drilling and Trucking Fees. At December 31, 2005 DHS owned eleven drilling rigs with depth ratings of approximately 7,500 to 20,000 feet. In early 2006, two additional rigs were acquired. We have the right to use all of the rigs on a priority basis, although approximately half were working for third party operators at December 31, 2005.

Drilling revenues for the six months ended December 31, 2005 increased to $9.1 million compared to $300,000 for the prior year period. Drilling revenue is earned under daywork 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. 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. At December 31, 2005 there were eight DHS rigs in operation compared to four rigs in operation at June 30, 2005.

Trucking revenues were insignificant during the six months ended December 31, 2005 as the Chapman acquisition was completed in November 2005.

Production and Cost Information

Production volumes, average prices received and cost per equivalent Mcf for the six months ended December 31, 2005 and 2004 are as follows:

	Six Months Ended December 31,
	2005(1)						2004(1)
	Onshore			Offshore			Onshore			Offshore
Production – Continuing Operations:
Oil (MBbl)		264			81			159			74
Gas (MMcf)		2,634			—			1,870			—
Production – Discontinued Operations:
Oil (MBbl)		164			—			272			—
Gas (MMcf)		931			—			1,427			—
Total Production (MMcfe)		6,285			485			5,884			444
Average Price – Continuing Operations:
Oil (per barrel)	$	59.62		$	47.12		$	45.41		$	30.66
Gas (per Mcf)	$	8.78		$	—		$	5.56		$	—
Costs per Mcfe – Continuing Operations:
Hedge gain (loss)	$	(.81	)	$	—		$	(.03	)	$	—
Lease operating expense	$	1.01		$	4.62		$	0.57		$	3.56
Production taxes (benefit)	$	.61		$	(.23	)	$	.54		$	.06
Transportation costs	$	.16		$	—		$	.03		$	—
Depletion expense	$	2.73		$	.79		$	1.40		$	.75

⁽¹⁾ Revised for operations discontinued in 2007.

Lease Operating Expense. Lease operating expenses for the six months ended December 31, 2005 were $6.5 million compared to $3.2 million for the same period a year earlier. Lease operating expense from continuing operations for onshore properties for the six months ended December 31, 2005 was $1.01 per Mcfe as compared to $0.57 per Mcfe for the same period a year earlier. Lease operating expense from continuing operations for offshore properties was $4.62 per Mcfe for the six months ended December 31, 2005 and $3.56 per Mcfe for the same period a year earlier. This increase in lease operating costs from continuing operations per Mcfe can be primarily attributed to the increase in the percentage of wells owned in the Gulf Coast Region, largely due to the Manti acquisition in January 2005, as compared to our other regions. Our Gulf Coast properties typically have higher average lease operating costs. Newton also experienced substantial costs related to compression and salt water hauling and disposal.

Depreciation, Depletion and Amortization – oil and gas. Depreciation, depletion and amortization expense increased 155% to $12.4 million in the six months ended December 31, 2005, as compared to $4.9 million for the six months ended December 31, 2004. Depreciation expenses for our onshore properties increased to $2.73 per Mcfe during the six months ended December 31, 2005 from $1.40 per Mcfe for the six months ended December 31, 2004. Depletion rates have increased based on the higher amounts paid to acquire reserves in the ground and the increase in

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drilling costs relative to reserve additions. We also incurred higher depletion rates caused by lower proved developed producing reserves in our South Angleton field from unsuccessful drilling results.

Depreciation and Amortization – drilling and trucking. Depreciation and amortization expense – drilling and trucking increased to $2.8 million for the six months ended December 31, 2005 as compared to $386,000 for the prior year period. This increase can be attributed to additional rigs acquired by DHS Drilling Company.

Exploration Expense. Exploration expense consists of geological and geophysical costs and lease rentals. Our exploration costs for the six months ended December 31, 2005 were $2.1 million compared to $1.3 million for the six months ended December 31, 2004. The increase in exploration costs was primarily related to seismic costs and impairment of prospect acquisition costs. During the six months ended December 31, 2005, our most significant exploration cost related to the $1.4 million Newton 3D seismic shoot covering 58 square miles which was completed and processed during 2005 and which assisted us in prioritizing our drilling locations and identifying target formations. In addition, we acquired 2D data in the Gulf Coast Region and also began acquiring geophysical data on the Columbia River Basin properties in the state of Washington.

Dry Hole Costs and Impairments. We incurred dry hole costs of approximately $4.1 million for the six months ended December 31, 2005 compared to $2.7 million for the same period a year ago. During 2004, a significant portion of these costs related to our Trail Blazer prospect in Laramie County, Wyoming and four non-Niobrara formation dry holes in Washington County, Colorado. During the six months ended December 31, 2005, four dry holes were drilled including two in Washington County, Colorado, one in Utah, and one in Orange County, California.

During the six months ended December 31, 2005, a dry hole was drilled on a prospect located in Orange County, California. Based on drilling results and evaluation of the prospect, we determined that we would not pursue development and accordingly, an impairment of $1.3 million was recorded for the full impairment of the remaining leasehold costs related to the prospect.

Drilling and Trucking Operations. We had drilling and trucking operations of $5.8 million during the six months ended December 31, 2005 compared to $1.1 million during the six months ended December 31, 2004. The significant increase in expenses was due to an increase in the number of rigs in operation, eight rigs as of December 31, 2005 compared to two rigs at December 31, 2004.

General and Administrative Expense. General and administrative expense increased 137% to $16.5 million for the six months ended December 31, 2005 as compared to $7.0 million for the six months ended December 31, 2004. The increase in general and administrative expenses is primarily attributed to $2.1 million of stock option compensation expense related to the adoption of SFAS No. 123 (Revised 2004), “Share Based Payment” (“SFAS 123R”), $1.4 million increase in professional fees attributed largely to compliance with the Sarbanes-Oxley Act, a 60% increase in technical and administrative staff and related personnel costs, the expansion of our office facility and $715,000 of vested restricted stock and option awards granted to officers, directors and management.

Gain on Sale of Marketable Security. During the six months ended December 31, 2005, the Company sold investment securities classified as available-for-sale securities resulting in a realized gain of $1.2 million.

Losses on Ineffective Derivative Instruments, Net. During the six months ended December 31, 2005, our gas derivative contracts became ineffective and no longer qualified for hedge accounting. Hedge ineffectiveness results from different changes in the NYMEX contract terms and the physical location, grade and quality of our oil and gas production. The change in fair value of our gas contracts in the six month period are reflected in earnings, as opposed to being recorded in other comprehensive income (loss), a component of stockholders’ equity. As a result, we recognized a $14.4 million loss in our statement of operations. As commodity prices fluctuate, we will record our gas derivative contracts at market value with any changes in market value recorded through unrealized gain (loss) on derivative contracts in our statement of operations. Our oil derivative contracts continue to qualify for hedge accounting.

Minority Interest. Minority interest represents the minority investors’ percentage of their share of income or losses from Big Dog, Shark or DHS in which they hold an interest. During the six months ended December 31, 2004, Big Dog and Shark incurred operating losses. During the six months ended December 31, 2005, DHS generated an operating profit.

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Interest and Financing Costs. Interest and financing costs increased 302% to $8.9 million for the six months ended December 31, 2005, as compared to $2.2 million for the six months ended December 31, 2004. The increase is primarily related to interest on the $150.0 million senior notes that were issued in March 2005, the increase in the average amount outstanding under our credit facility, primarily as a result of the Manti acquisition completed in January 2005, and our increased investment in the Columbia River Basin prospect in Washington completed in April 2005. In addition, borrowings of $35.0 million by DHS in 2005 also resulted in increased interest expense.

Income tax benefit. Prior to June 30, 2005, the Company recorded a full valuation allowance on its deferred tax assets and accordingly, during the six months ended December 31, 2004, no income tax provision was recorded.

During the six months ended December 31, 2005, an income tax benefit of $10.9 million was recorded for continuing operations at an effective tax rate of 37.2%.

Discontinued Operations. On September 2, 2005, we completed the sale of our Deerlick Creek field in Tuscaloosa County, Alabama for $30.0 million with an effective date of July 1, 2005. We recorded a gain on sale of oil and gas properties of $10.2 million on net proceeds of $28.9 million after normal closing adjustments. Income from discontinued operations of properties sold has been restated to include the Deerlick Field sold in September 2005, Frisco Field sold in June 2006, East Texas properties and Pennsylvania properties acquired in the Castle acquisition which were sold in August 2006, the Company’s Kansas field 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, the Washington County, Colorado properties sold in October 2007, and the Midway Loop, Texas properties held for sale at December 31, 2007. The results of operations on these assets during the six months ended December 31, 2005 and 2004 were $6.0 million and $12.8 million, respectively.

Liquidity and Capital Resources

Liquidity is a measure of a company’s ability to access cash. In February 2008, we significantly improved our liquidity position with $684 million in gross proceeds from the sale of 36 million shares to Tracinda Corporation. As of December 31, 2007, 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, 2007, 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 the ratings on CreditWatch with positive implications following the announced investment by Tracinda Corporation. We have completed several equity, debt, and property transactions in the past year as described below. On January 25, 2007, we completed a public offering of 2,768,000 shares of our common stock for net proceeds of $56.4 million. During the year ended December 31, 2007, we sold non-core properties in Kansas, Texas, New Mexico, Australia, and North Dakota for combined net proceeds of $46.4 million. On April 25, 2007, we issued 7,130,000 shares of common stock at $20.50 per share and issued $115.0 million aggregate principal amount of 3³/4% Senior Convertible Notes due 2037 for total net proceeds of $251.9 million after underwriters’ discounts and commissions of $9.3 million.

Our 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.

During the year ended December 31, 2007, we had an operating loss of $131.3 million, but generated cash from operating activities of $84.4 million and obtained cash from financing activities of $243.1 million. During this period we spent $286.3 million on oil and gas development (or $332.5 million, net of $46.2 million proceeds from dispositions), $4.5 million on oil and gas acquisitions, and $15.2 million on drilling and trucking capital expenditures (or $22.3 million, net of $7.1 million proceeds from dispositions). At December 31, 2007, we had $10.1 million in cash, total assets of $1.1 billion and a debt to capitalization ratio of 44.9%. Long-term debt at December 31, 2007 totaled $413.1 million, comprised of $148.6 million of bank debt, $149.5 million of senior subordinated notes and $115.0 million of senior convertible notes. In April 2007 and again in February 2008, our credit facility was paid down in full with proceeds from our debt and equity offerings. Available borrowing capacity under our bank credit facility at December 31, 2007 was approximately $140.0 million with a balance outstanding of $73.6 million. In December 2007, DHS closed a new $75.0 million credit facility with Lehman Brothers Commercial Paper, as administrative agent. DHS has no additional availability under its credit facility.

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At December 31, 2007, we were in compliance with our quarterly financial covenants. Our covenants require a minimum current ratio of 1 to 1, net of derivative instruments, and a consolidated debt to EBITDAX (earnings before interest, taxes, depreciation, amortization and exploration) of less than 4.0 to 1 for the quarter ended December 31, 2007, and 3.75 to 1 for the end of each quarter thereafter. These financial covenant calculations only reflect wholly-owned subsidiaries.

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 additions to production.

Although we believe that through cash on hand, availability on our credit facility, and cash flows from operations, we have access to adequate capital to fund our development plans, 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, will depend upon a number of factors, many of which are beyond our control.

Company Acquisitions and Growth

We continue to evaluate potential acquisitions and property development opportunities. During the year ended December 31, 2007, we completed the following transactions:

On October 1, 2007, we completed an asset exchange transaction to acquire an additional 12.5% working interest in the Garden Gulch Field in the Piceance Basin, in exchange for our assets in Washington County, Colorado and $33.0 million in cash.

On June 8, 2007, we acquired a 50% non-controlling ownership interest in Delta Oilfield Tank Company, LLC (“Delta Oilfield”) for cash consideration of $4.0 million. Delta Oilfield will be accounted for using the equity method of accounting and is an unconsolidated affiliate of the Company.

On June 8, 2007, we issued 475,000 shares of common stock valued at approximately $9.9 million for additional interest in a well owned and operated by the Company, and additional interest in a non-operated well.

On March 9, 2007, we issued 754,000 shares of common stock valued at approximately $13.8 million for additional interests in two wells already owned and operated by us located in Polk County, Texas.

On March 5, 2007, DHS purchased a drilling rig (“Rig 18”) for $7.6 million. The rig is an 700 horsepower rig with a depth rating of 10,500 feet. The rig is currently operating in the Rocky Mountain Region.

On March 1, 2007, we paid $3.5 million for 39,000 net acres and interests in several wells in Fremont County, Wyoming.

Historical Cash Flow

Our cash flow from operating activities increased from $53.4 million for the year ended December 31, 2006 to $84.4 million for the year ended December 31, 2007, primarily as a result of changes in working capital. Our net cash used in investing activities increased to $325.0 million for the year ended December 31, 2007 compared to net cash used in investing activities of $203.1 million for the year earlier period, primarily due to our increased drilling activity. Cash provided by financing activities was $243.1 million for the year ended December 31, 2007 compared to $151.8 million for the comparable prior year period. Cash provided by financing activities was higher in 2007 primarily due to cash received in April from our convertible debt and equity offerings.

Our cash flow from operating activities increased 5% to $53.4 million for the year ended December 31, 2006 compared to $50.7 million for the same period a year earlier. Our net cash used in investing activities decreased by 32% to $203.1 million for the year ended December 31, 2006 compared to $297.2 million for the same period a year earlier. The decrease in cash used for investing activity can be attributed to a reduction in property acquisitions due to an increased focus on drilling activities. Cash flow from financing activities decreased to $151.8 million for the year

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ended December 31, 2006 compared to $250.6 million for the same period the prior year. During the year ended December 31, 2006, we financed our operations, acquisitions, and capital expenditures primarily with net proceeds of $33.9 million in newly issued equity and $118.3 million in net debt additions.

Capital and Exploration Expenditures and Financing

Our capital and exploration expenditures and sources of financing for the years ended December 31, 2007 and 2006, six months ended December 31, 2005 and year ended June 30, 2005 were as follows:

							Six Months		Year
	Years Ended						Ended		Ended
	December 31,						December 31,		June 30,
	2007			2006			2005		2005
				(In thousands)
CAPITAL AND EXPLORATION EXPENDITURES:
Acquisitions:
Garden Gulch	$	34,778		$	—		$	—	$	—
Austin Chalk incremental interests		23,765			—			—		—
Wyoming (Yates)		3,500			—			—		—
Washington County, South and North Tongue		1,000			—			828		10,571
Armstrong Acquisition		—			40,103			—		—
Castle		—			33,648			—		—
Savant Acquisition		—			—			85,000		—
Manti		—			—			—		59,700
Columbia River Basin		—			—			—		18,255
Sacramento Basin		—			—			—		10,400
Karnes County, Texas		—			—			—		5,000
Other		9,988			24,678			7,904		2,718
Other development costs		287,790			179,874			86,871		102,216
Drilling and trucking companies		22,292			63,848			25,733		32,690
Exploration costs		9,062			4,690			2,061		6,155
	$	392,175		$	346,841		$	208,397	$	247,705
FINANCING SOURCES:
Cash flow provided by operating activities		78,173		$	53,386		$	24,879	$	44,862
Stock issued for cash upon exercised options		137			3,711			1,166		132
Stock issued for cash, net		202,084			33,870			95,026		—
Net long-term borrowings		40,836			114,265			28,715		139,051
Proceeds from sale of oil and gas properties		46,193			82,716			34,178		18,721
Proceeds from sale of drilling assets		7,145			—			—		—
Investments in and notes issued to affiliates		(12,440	)		—			—		—
Minority interest contributions		(355	)		9,018			—		14,800
Other		(106	)		(3,646	)		2,566		63
	$	361,667		$	293,320		$	186,530	$	217,629

We anticipate our drilling expenditures to range between $350.0 and $370.0 million for the year ending December 31, 2008 based on expected cash flow from operations and anticipated other property or equity transactions during the course of 2008. 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 — Discontinued Operations

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.

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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 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 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 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.

Also included in discontinued operations are our Midway Loop, Texas oil and gas properties which are held for sale as of December 31, 2007.

Off-Balance Sheet Arrangements

     We have no off-balance sheet arrangements.

Contractual and Long-Term Debt Obligations

	Payments Due by Period
	Less than						More than
Contractual Obligations at December 31, 2007	1 year		1-3 Years		3-5 Years		5 Years		Total
					(In thousands)
7% Senior unsecured notes	$	—	$	—	$	—	$	150,000	$	150,000
Interest on 7% Senior unsecured notes		10,500		21,000		21,000		31,033		83,533
33/4% Senior convertible notes		—		—		—		115,000		115,000
Credit facility		—		73,600		—		—		73,600
Term loan – DHS		—		75,000		—		—		75,000
Derivative liability		6,295		—		—		—		6,295
Abandonment retirement obligation		1,045		431		454		10,449		12,379
Operating leases		3,527		5,331		2,997		2,394		14,249
Drilling commitments		3,500		14,000		—		—		17,500
Other debt obligations		13		—		—		—		13
Total contractual cash obligations	$	24,880	$	189,362	$	24,451	$	308,876	$	547,569

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 net proceeds were used to refinance debt outstanding under our credit facility which included the amount required to acquire the Manti properties located in the Gulf Coast Region. The notes were issued at 99.50% of par and the associated discount is being amortized to interest expense over the term of the notes. The indenture governing the notes contains various restrictive covenants that may limit our ability to, among other things, incur additional indebtedness, make certain investments, sell assets, consolidate, merge or transfer all or substantially all of our assets and the assets of our restricted subsidiaries. These covenants may limit management’s discretion in operating our business.

3³/4% Senior Convertible Notes, due 2037

On April 25, 2007, we issued $115.0 million aggregate principal amount of 3³/4% Senior Convertible Notes due 2037 (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

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initial conversion rate of 32.9598 shares of common stock per $1,000 principal amount of Notes (equivalent to a conversion price of approximately $30.34 per share) at any time prior to the close of business on the business day immediately preceding the final maturity date of the Notes, subject to prior repurchase of the Notes. The conversion rate may be adjusted from time to time in certain instances. Upon conversion of a Note, we will have the option to deliver shares of our common stock, cash or a combination of cash and shares of our common stock for the Notes surrendered. In addition, following certain fundamental changes that occur prior to maturity, we will increase the conversion rate for a holder who elects to convert its Notes in connection with such fundamental changes by a number of additional shares of common stock. Although the Notes do not contain any financial covenants, the Notes contain covenants that require us to properly make payments of principal and interest, provide certain reports, certificates and notices to the trustee under various circumstances, cause our wholly-owned subsidiaries to become guarantors of the debt, maintain an office or agency where the Notes may be presented or surrendered for payment, continue our corporate existence, pay taxes and other claims, and not seek protection from the debt under any applicable usury laws.

Credit Facility

At December 31, 2007, the $250.0 million credit facility had $73.6 million outstanding. On February 20, 2008, the credit facility was fully paid down with a portion of the proceeds from our equity offering. The facility has variable interest rates based upon the ratio of outstanding debt to the borrowing base. Rates vary between prime + .25% and 1.00% for base rate loans and between Libor + 1.5% and 2.25% for Eurodollar loans. We are required to meet certain financial covenants which include a current ratio of 1 to 1, net of derivative instruments, and a consolidated debt to EBITDAX (earnings before interest, taxes, depreciation, amortization and exploration) ratio of less than 4.0 to 1 for the quarter ended December 31, 2007, and 3.75 to 1 for the end of each quarter thereafter. The financial covenants only include subsidiaries which we own 100%. At December 31, 2007, we were in compliance with our quarterly debt covenants and restrictions.

The borrowing base is re-determined by the lending banks at least semi-annually on April 1 and October 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. There was no change to our borrowing base as a result of the October 2007 re-determination.

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.

Unsecured Term Loan

In December 2006 we entered into an agreement with JP Morgan Chase Bank N.A. for a $25.0 million unsecured term loan with interest at LIBOR plus a margin of 3.5% at December 31, 2006. The note was paid in full in January 2007 with the proceeds from the $56.4 million equity offering.

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Credit Facility – DHS

On December 20, 2007, DHS entered into a new $75.0 million credit agreement with Lehman Commercial Paper Inc. The proceeds were used to pay off the JP Morgan credit facility. The credit facility has a variable interest rate based on 90-day LIBOR plus a fixed margin of 5.50% and matures on December 31, 2010. Annual principal payments are based upon a calculation of excess cash flow (as defined) for the preceding year. DHS is required to meet certain financial covenants quarterly beginning March 31, 2008 including (i) consolidated EBITDA for four consecutive fiscal quarters must be greater than $20.0 million; (ii) Consolidated Leverage Ratio (as defined) for four consecutive fiscal quarters cannot exceed 3.50 to 1.00; (iii) Consolidated Interest Coverage Ratio (as defined) for four consecutive fiscal quarters must exceed 2.50 to 1.00 and (iv) the Current Ratio for any fiscal quarter must be greater than 1.0 to 1.0. DHS incurred $1.3 million of financing charges in conjunction with the agreement which will be amortized over the life of the loan.

On May 4, 2006, DHS entered into a $100.0 million senior secured credit facility with JP Morgan Chase Bank, N.A. Proceeds from the $75.0 million initial draw were used to pay off the Guggenheim term loan, complete the acquisition of C&L Drilling, finance additional capital expenditures and pay transaction expenses. In December 2007, DHS used proceeds from the Lehman credit agreement and the sale of Rigs 2 and 3 to pay off the $79.7 million outstanding balance of the JP Morgan senior secured credit facility.

Term Loan - DHS

On May 4, 2006, DHS used proceeds from the JP Morgan credit facility to pay off the remaining balance of the previously outstanding term loan of approximately $41.0 million.

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 $1.6 million over the life of the lease. We have additional operating lease commitments which represent office equipment leases and short term debt obligations primarily relating to field vehicles and equipment.

In March 2007, we executed an earn-in agreement with EnCana whereby we can earn up to 6,000 net acres in the Piceance Basin with the drilling of 128 wells during the next 36 months. We are committed to drill 64 total wells, eight of which were drilled by October 31, 2007. The remaining wells are required to be drilled by June 1, 2009. We are liable for $250,000 per undrilled well in the event the drilling obligations are not met.

Derivative instruments represent the net estimated unrealized losses for our oil and gas hedges at December 31, 2007. The ultimate settlement amounts of these hedges are unknown because they are subject to continuing market risk. See Item 7A, “Quantitative and Qualitative Disclosures About Market Risk.”

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The following table summarizes our derivative contracts outstanding at December 31, 2007:

							Net Fair Value
			Price Floor /				Asset (Liability) at
Commodity	Volume		Price Ceiling		Term	Index	December 31, 2007
							(In thousands)
Crude oil	1,200	Bbls / day	$	65.00 / $80.03	Jan ’08 - Mar ’08	NYMEX – WTI	$	(1,705	)
Crude oil	1,200	Bbls / day	$	65.00 / $79.77	Apr ’08 - June ’08	NYMEX – WTI		(1,620	)
Crude oil	1,200	Bbls / day	$	65.00 / $79.86	July ’08 - Sept ’08	NYMEX – WTI		(1,522	)
Crude oil	1,200	Bbls / day	$	65.00 / $79.83	Oct ’08 - Dec ’08	NYMEX – WTI		(1,448	)
Natural gas	15,000	MMBtu / day	$	6.50 / $8.30	Jan ’08 - Dec ’08	CIG		2,404
Natural gas	5,000	MMBtu / day	$	6.50 / $8.40	Jan ’08 - Mar ’08	CIG		211
Natural gas	10,000	MMBtu / day	$	6.00 / $7.25	Apr ’08 - Sept ’08	CIG		139
Natural gas	10,000	MMBtu / day	$	6.50 / $7.90	Oct ’08 - Dec ’08	CIG		176
							$	(3,365	)

The fair value of our derivative instruments liability was a $3.4 million loss at December 31, 2007. Subsequent to year-end, we entered into new CIG gas hedges for 10,000 Mmbtu per day for the second and third quarters of 2008 with a floor price of $6.50 and ceiling prices of $7.70 and $8.15 per Mmbtu, respectively. We also entered into new CIG gas hedges for 35,000 Mmbtu per day for the first quarter of 2009 with a floor price of $7.50 per Mmbtu and a ceiling price of $9.88 per Mmbtu. The fair value of our derivative liability at February 26, 2008 was $15.2 million.

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 2 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

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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, future operating costs, severance taxes, development costs and workover gas costs, all of which may in fact vary considerably from actual results. The future drilling costs associated with reserves assigned to proved undeveloped locations may ultimately increase to an extent that these reserves may be later determined to be uneconomic. For these reasons, estimates of the economically recoverable quantities of gas and oil attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected therefrom may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of our gas and oil properties and/or the rate of depletion of the gas and oil properties. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material.

Impairment of Gas and Oil Properties

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

Given the complexities associated with gas and oil reserve estimates and the history of price volatility in the gas and oil markets, events may arise that would require us to record an impairment of the recorded book values associated with gas and oil properties. For developed properties, the review consists of a comparison of the carrying value of the asset with the asset’s expected future undiscounted cash flows without interest costs. As a result of such assessment during the year ended December 31, 2007, an impairment of $58.4 million was recorded primarily related to the Howard Ranch and Fuller fields in Wyoming ($37.5 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. The Company recorded no impairment provision attributable to developed properties for the six months ended December 31, 2005 and the year ended June 30, 2005. For fiscal year 2008, 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.

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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. 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.

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. The Company’s asset retirement obligations arise from the plugging and abandonment liabilities for its oil and gas wells.

In March 2005, the FASB issued FASB Interpretation 47 (“FIN 47”), an interpretation of SFAS 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”). FIN 47 clarifies the term “conditional asset retirement obligation” as it is used in SFAS 143. The Company applied the guidance of FIN 47 beginning July 1, 2005, resulting in no impact on its financial statements.

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 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. We will evaluate how the new requirements could impact the accounting for any acquisitions completed beginning in fiscal 2009 and beyond, and the potential impact on our consolidated financial statements.

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 our fiscal year 2009, and must be applied prospectively, except for the presentation and disclosure requirements, which will apply retrospectively. We are currently evaluating the potential impact of the adoption of SFAS 160 on our consolidated financial statements.

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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 have not yet determined if we will elect to apply any of the provisions of SFAS 159 or what effect the adoption of the Statement would have, if any, on our consolidated financial statements.

Effective January 1, 2007, we 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, we had no unrecognized tax benefits. During the year ended December 31, 2007, no adjustments were recognized for uncertain tax benefits.

We recognize 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, 2007.

The tax years 2003 through 2006 for federal returns and 2002 through 2006 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.

In September 2006, the FASB issued SFAS 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 upholds the requirements of previously issued pronouncements concerning fair value measurements and expands the required disclosures. This Statement is effective for fiscal year commencing January 1, 2008. We do not expect the impact of SFAS 157 to be material to our financial condition or results of operations. We anticipate the primary impact of the standard will be additional disclosures related to the measurement of fair value in the Company’s recurring impairment test calculations related to oil and gas properties, drilling rigs, and goodwill, the valuation of oil and gas derivative financial instruments, and the valuation of assets acquired or liabilities assumed in future business combinations, if any.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Rate and Price Risk

We actively manage our exposure to commodity price fluctuations by hedging meaningful portions of our expected production through the use of derivatives, 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.

The net fair value of our derivative instruments was a $3.4 million liability at December 31, 2007 and a $15.2 million liability on February 26, 2008.

As of February 26, 2008, our derivative contracts cover approximately 12.2 Bcfe of our 2008 production. Assuming production and the percent of oil and gas sold remained unchanged from the year ended December 31, 2007, a hypothetical 10% decline in the average market price the Company realized during the year ended December 31, 2007 on unhedged production would reduce the Company’s oil and natural gas revenues by approximately $9.5 million on an annual basis.

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Interest Rate Risk

We were subject to interest rate risk on $148.6 million of variable rate debt obligations at December 31, 2007. The annual effect of a 10% change in interest rates would be approximately $1.3 million. The interest rate on these variable debt obligations approximates current market rates as of December 31, 2007.

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

None.

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, 2007. 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.

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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, 2007, 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, 2007, 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 internal control over financial reporting.

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

None.

PART III

The information required by Part III, Item 10 “Directors and Executive Officers and Corporate Governance,” Item 11 “Executive Compensation,” Item 12 “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters,” Item 13 “Certain Relationships and Related Transactions, and Director Independence” and Item 14 “Principal Accounting Fees and Services” is incorporated by reference to the Company’s definitive Proxy Statement which will be filed with the Securities and Exchange Commission in connection with the 2008 Annual Meeting of Stockholders. For certain information concerning Item 10 “Directors, Executive Officers and Corporate Governance,” see Part I – “Directors and Executive Officers.”

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PART IV

Item 15. Exhibits, Financial Statement Schedules

     (a)(1) Financial Statements.

	Page No.
Reports of Independent Registered Public Accounting Firm	F-1,2
Consolidated Balance Sheets as of December 31, 2007 and December 31, 2006	F-3
Consolidated Statements of Operations for the years ended December 31, 2007 and 2006, six months ended December 31, 2005 and year ended June 30, 2005	F-4
Consolidated Statements of Stockholders’ Equity and Comprehensive Income (Loss) for the years ended December 31, 2007 and 2006, six months ended December 31, 2005 and year ended June 30, 2005	F-5
Consolidated Statements of Cash Flows for the year ended December 31, 2007 and 2006, six months ended December 31, 2005 and year ended June 30, 2005	F-6
Notes to Consolidated Financial Statements	F-7

(a)(2) Financial Statement Schedules. None.

(a)(3) Exhibits. The Exhibits listed in the Index to Exhibits appearing at page 62 are filed as part of this report. Management contracts and compensatory plans required to be filed as exhibits are marked with a “*”.

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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 8-K dated January 31, 2006.
3.2	Amended and Restated By-laws of the Company. Incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K, dated February 9, 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 dated March 15, 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 dated March 15, 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 dated March 15, 2005.
4.4	Form of 7% Series A Senior Notes due 2015 with attached notation of Guarantees.
	Incorporated by reference from Exhibit 4.4 to the Company’s Form 8-K dated March 15, 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 dated April 19, 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 dated April 19, 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 to the Company’s Notice of Annual Meeting and Proxy Statement dated July 26, 2001 for fiscal year 2000 ended June 30, 2000.*
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.

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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 dated October 25, 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 dated June 17, 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 dated June 17, 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 dated May 5, 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 dated May 5, 2005.*
10.10	Employment Agreement with John R. Wallace dated May 5, 2005. Incorporated by reference from Exhibit 10.2 to the Company’s Form 8-K dated May 5, 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 dated January 11, 2006.*
10.12	Delta Petroleum Corporation 2004 Incentive Plan. Incorporated by reference from Appendix A to the Company’s Definitive Proxy Statement filed on 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 dated June 20, 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 dated November 17, 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 dated November 17, 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 dated November 17, 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 on 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 dated February 5, 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 dated April 30, 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 dated April 30, 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 dated April 30, 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 dated April 30, 2007. *

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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 dated December 31, 2007.
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. 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.
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.
23.3	Consent of Mannon Associates. 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.

* Management contracts and compensatory plans.

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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, 2007 and 2006, and the related consolidated statements of operations, changes in stockholders’ equity and comprehensive income (loss), and cash flows for the years ended December 31, 2007 and 2006, the six months ended December 31, 2005 and the year ended June 30, 2005. 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, 2007 and 2006, and the results of their operations and their cash flows for the years ended December 31, 2007 and 2006, the six months ended December 31, 2005 and the year ended June 30, 2005, in conformity with U.S. generally accepted accounting principles.

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, 2007, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 28, 2008 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

As discussed in note 2 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 and Statement of Financial Accounting Standards No. 123(R), Share-Based Payment, effective July 1, 2005.

/s/ KPMG LLP

Denver, Colorado
February 28, 2008

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, 2007, 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.

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 our opinion, Delta Petroleum Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, 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, 2007 and 2006, and the related consolidated statements of operations, changes in stockholders’ equity and comprehensive income (loss), and cash flows for the years ended December 31, 2007 and 2006, the six months ended December 31, 2005 and the year ended June 30, 2005, and our report dated February 28, 2008 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

Denver, Colorado
February 28, 2008

F-2

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS

	December 31,			December 31,
	2007			2006
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	10,091		$	7,666
Assets held for sale		62,744			31,822
Trade accounts receivable, net of allowance for doubtful accounts, of $664 and $100, respectively		38,761			29,503
Prepaid assets		3,943			4,384
Inventory		4,236			2,851
Derivative instruments		2,930			10,799
Deferred tax asset		150			—
Other current assets		10,214			2,769
Total current assets		133,069			89,794
Property and equipment:
Oil and gas properties, successful efforts method of accounting:
Unproved		247,466			217,573
Proved		740,408			564,242
Drilling and trucking equipment		146,097			136,038
Pipeline and gathering system		22,140			14,909
Other		19,069			13,983
Total property and equipment		1,175,180			946,745
Less accumulated depreciation and depletion		(245,153	)		(131,545	)
Net property and equipment		930,027			815,200
Long-term assets:
Marketable securities		6,268			—
Deferred financing costs		7,187			6,928
Goodwill		7,747			7,747
Other long-term assets		10,616			6,722
Investment in unconsolidated affiliates		10,281			2,932
Total long-term assets		42,099			24,329
Total assets	$	1,105,195		$	929,323
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt	$	13		$	816
Accounts payable		119,783			84,439
Other accrued liabilities		17,105			10,818
Deferred tax liability		—			2,893
Derivative instruments		6,295			613
Total current liabilities		143,196			99,579
Long-term liabilities:
7% Senior notes, unsecured		149,459			149,384
3 3/4% Senior convertible notes		115,000			—
Credit facility		73,600			118,000
Unsecured term loan		—			25,000
Credit facility/Term loan - DHS		75,000			74,050
Asset retirement obligation		4,154			4,013
Deferred tax liability		9,085			3,660
Other debt, net		—			14
Total long-term liabilities		426,298			374,121
Minority interest		27,296			27,390
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 66,429,000 shares at December 31, 2007, and 53,439,000 shares at December 31, 2006		664			534
Additional paid-in capital		664,733			430,479
Accumulated other comprehensive income		—			4,865
Accumulated deficit		(156,992	)		(7,645	)
Total stockholders’ equity		508,405			428,233
Total liabilities and stockholders’ equity	$	1,105,195		$	929,323

See accompanying notes to consolidated financial statements.

F-3

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS

							Six Months Ended			Year Ended
	Years Ended December 31,						December 31,			June 30,
	2007			2006			2005			2005
				(In thousands, except per share amounts)
Revenue:
Oil and gas sales	$	94,559		$	94,223		$	42,643		$	52,446
Contract drilling and trucking fees		56,777			57,149			9,096			4,796
Gain (loss) on effective derivative instruments, net		12,854			(4,712	)		(3,413	)		(630	)
Total revenue		164,190			146,660			48,326			56,612
Operating expenses:
Lease operating expense		20,142			17,655			6,507			9,291
Transportation expense		3,684			978			680			394
Production taxes		5,559			4,784			2,455			3,415
Depreciation, depletion, accretion and amortization – oil and gas		63,373			53,980			12,411			14,055
Depreciation and amortization – drilling and trucking		22,052			16,404			2,847			1,525
Exploration expense		9,062			4,690			2,061			6,155
Dry hole costs and impairments		85,084			15,682			5,423			2,771
Drilling and trucking operations		36,954			34,163			5,821			4,666
General and administrative		49,621			35,696			16,491			16,930
Gain on sale of oil and gas properties		—			(20,034	)		—			—
Total operating expenses		295,531			163,998			54,696			59,202
Operating income (loss)		(131,341	)		(17,338	)		(6,370	)		(2,590	)
Other income and (expense):
Other income (expense)		376			(154	)		(36	)		(570	)
Gain (loss) on ineffective derivative instruments, net		(2,902	)		11,722			(14,437	)		(330	)
Gain on sale of marketable securities, net		—			—			1,194			—
Gain on sale of investment in LNG		—			1,058			—			—
Minority interest		1,231			(2,595	)		(688	)		1,017
Losses from unconsolidated affiliates		(393	)		—			—			—
Interest and financing costs		(27,199	)		(26,316	)		(8,866	)		(7,880	)
Total other expense		(28,887	)		(16,285	)		(22,833	)		(7,763	)
Loss from continuing operations before income taxes and discontinued operations		(160,228	)		(33,623	)		(29,203	)		(10,353	)
Income tax benefit (expense)		(2,677	)		12,623			10,873			11,969
Income (loss) from continuing operations		(162,905	)		(21,000	)		(18,330	)		1,616
Discontinued operations:
Income from discontinued operations of properties sold, net of tax		17,556			9,163			5,952			13,434
Gain (loss) on sale of discontinued operations, net of tax		(3,998	)		6,712			11,788			—
Income (loss) before extraordinary gain, net of tax		(149,347	)		(5,125	)		(590	)		15,050
Extraordinary gain, net of tax		—			5,560			—			—
Net income (loss)	$	(149,347	)	$	435		$	(590	)	$	15,050
Basic income (loss) per common share:
Income (loss) from continuing operations	$	(2.66	)	$	(.41	)	$	(.41	)	$	.04
Discontinued operations		.22			.31			.40			.33
Extraordinary gain, net of tax		—			.11			—			—
Net income (loss)	$	(2.44	)	$	.01		$	(.01	)	$	.37
Diluted income (loss) per common share:
Income (loss) from continuing operations	$	(2.66	)	$	(.39	)	$	(.41	)	$	.04
Discontinued operations		.22			.30			.40			.32
Extraordinary gain, net of tax		—			.10			—			—
Net income (loss)	$	(2.44	)	$	.01		$	(.01	)	$	.36

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			comprehensive			Comprehensive			Unearned			Accumulated
	Shares		Amount		capital			income/(loss)			income (loss)			Compensation			deficit			Total
								(In thousands, except per share amounts)
Balance, July 1, 2004		38,447	$	384	$	207,811		$	342								$	(22,540	)	$	185,997
Comprehensive income:
Net income		—		—		—			—		$	15,050						15,050			15,050
Other comprehensive gain, net of tax
Change in fair value of derivative hedging instruments, net of tax benefit of $3,722		—		—		—			(5,961	)		(5,961	)					—			(5,961	)
Unrealized gain on marketable securities, net of tax expense of $458		—		—		—			394			394						—			394
Comprehensive income											$	9,483
Shares issued for oil and gas properties		1,571		16		22,175			—									—			22,191
Shares issued for drilling equipment		131		1		1,892			—									—			1,893
Shares issued for cash upon exercise of options, net		1,793		18		114			—									—			132
Tax benefit on options exercised		—		—		1,255			—									—			1,255
Issuance of options below market		—		—		346			—					$	(346	)		—			—
Issuance of restricted options		75		1		1,707			—						(1,708	)		—			—
Amortization of unearned option compensation		—		—		—			—						672			—			672
Balance, June 30, 2005		42,017		420		235,300			(5,225	)					(1,382	)		(7,490	)		221,623
Comprehensive income:
Net loss		—		—		—			—		$	(590	)					(590	)		(590	)
Other comprehensive income transactions, net of tax
Realized gain on equity securities sold, net of tax expense of $458		—		—		—			(736	)		(736	)					—			(736	)
Hedging loss reclassified to income upon settlement, net of tax benefit of $1,733		—		—		—			2,398			2,398						—			2,398
Change in fair value of derivative hedging instruments, net of tax benefit of $1,036		—		—		—			(1,434	)		(1,434	)					—			(1,434	)
Comprehensive loss											$	(362	)
Shares issued for oil and gas properties		50		1		827			—									—			828
Shares issued for cash, net of offering costs		5,405		54		94,917			—									—			94,971
Shares issued for cash upon exercise of options		200		2		623			—									—			625
Reclassification of unearned compensation upon adoption of SFAS 123R		—		—		(1,382	)		—						1,382			—			—
Issuance and amortization of unearned compensation		153		1		766			—						—			—			767
Compensation on options vested		—		—		2,003			—						—			—			2,003
Balance, December 31, 2005		47,825		478		333,054			(4,997	)					—			(8,080	)		320,455
Comprehensive income:
Net loss		—		—		—			—		$	435						435			435
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											$	10,297
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						—			(7,645	)		428,233
Comprehensive income:
Net loss		—		—		—			—		$	(149,347	)					(149,347	)		(149,347	)
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											$	(154,212	)
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		$	—					$	—		$	(156,992	)	$	508,405

See accompanying notes to consolidated financial statements.

F-5

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS

	Years Ended						Six Months Ended			Year Ended
	December 31,						December 31,			June 30,
	2007			2006			2005			2005
				(In thousands)
Cash flows from operating activities:
Net Income (loss)	$	(149,347	)	$	435		$	(590	)	$	15,050
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion, and amortization – oil and gas		63,054			53,783			12,315			13,802
Depreciation and amortization – drilling and trucking		22,052			16,404			2,847			1,525
Depreciation, depletion, and amortization – discontinued operations		12,990			12,212			5,257			7,835
Accretion of abandonment obligation		319			197			96			253
Stock option and non-vested stock compensation		15,590			4,882			2,770			672
Amortization of deferred financing costs		4,429			2,396			669			858
Unrealized (gain) loss on derivative contracts		5,816			(12,205	)		9,872			330
Dry hole costs and impairment		84,091			11,897			1,872			—
Minority Interest		(1,231	)		2,595			688			(1,017	)
Gain on sale of oil and gas properties		—			(20,034	)		—			—
Gain on sale of marketable securities		—			—			(1,194	)		—
Gain on sale of investment in LNG		—			(1,058	)		—			—
Loss (Gain) on sale of discontinued operations		2,644			(10,775	)		(11,788	)		—
Extraordinary gain on Castle acquisition		—			(8,776	)		—			—
DHS stock granted to management		245			280			140			—
Deferred income tax expense (benefit)		4,113			(502	)		(7,336	)		(3,045	)
Other gain (loss)		141			319			—			394
Net changes in operating assets and liabilities:
Increase in trade accounts receivable		(4,316	)		(4,501	)		(10,454	)		(1,586	)
(Increase) decrease in prepaid assets		441			(731	)		(457	)		(1,844	)
(Increase) decrease in inventory		(1,385	)		434			947			(5,062	)
(Increase) decrease in other current assets		713			(438	)		(1,968	)		(225	)
Increase in accounts payable trade		23,838			4,477			6,688			14,004
Increase in other accrued liabilities		195			2,095			14,505			2,918
Net cash provided by operating activities		84,392			53,386			24,879			44,862
Cash flows from investing activities:
Additions to property and equipment,		(332,450	)		(218,761	)		(157,519	)		(186,669	)
Additions to drilling and trucking equipment,		(22,292	)		(63,848	)		(21,828	)		(30,797	)
Acquisitions, net of cash acquired		(4,500	)		(8,564	)		(3,905	)		—
Proceeds from sale of oil and gas properties		46,193			82,716			34,178			18,721
Proceeds from sale of drilling assets		7,145			—			—			—
Proceeds from sale of marketable securities		—			—			1,764			—
Increase in marketable securities		(6,219	)		—			—			—
Investment in unconsolidated affiliates		(3,929	)		—			—			—
Loan to affiliate		(8,511	)		—			—			—
Minority interest holder contributions (distributions)		(355	)		9,018			—			14,800
(Increase) decrease in long term assets		(106	)		(3,646	)		802			63
Net cash used in investing activities		(325,024	)		(203,085	)		(146,508	)		(183,882	)
Cash flows from financing activities:
Stock issued for cash upon exercise of options		137			3,711			1,166			132
Stock issued for cash, net		202,084			33,870			95,026			—
Proceeds from borrowings		343,600			220,035			72,998			361,016
Payment of financing fees		(4,897	)		(3,994	)		(502	)		(7,370	)
Repayment of borrowings		(297,867	)		(101,776	)		(43,781	)		(214,595	)
Net cash provided by financing activities		243,057			151,846			124,907			139,183
Net increase in cash and cash equivalents		2,425			2,147			3,278			163
Cash at beginning of period		7,666			5,519			2,241			2,078
Cash at end of period	$	10,091		$	7,666		$	5,519		$	2,241
Supplemental cash flow information:
Cash paid for interest and financing costs	$	13,926		$	28,438		$	8,149		$	11,420
Non-cash financing activities:
Common stock issued for the purchase of Castle and oil and gas properties	$	23,765		$	47,332		$	828		$	22,191
Common stock issued for the purchase of drilling and trucking equipment	$	—		$	8,294		$	—		$	1,893

See accompanying notes to consolidated financial statements.

F-6

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005

(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, through a series of transactions in 2004, 2005, and 2007, owns a 50.0% 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, although approximately half of the rigs are currently working for third party operators. DHS also owns 100% of Chapman Trucking which was acquired in November 2005 and which ensures DHS rig mobility. In May 2006, DHS acquired two rigs in conjunction with the acquisition of C&L Drilling Company, Inc. (“C&L Drilling”). Also, 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.

At December 31, 2007, 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.

On February 19, 2002, the Company acquired 100% of the outstanding shares of Piper Petroleum Company (“Piper”), a privately owned oil and gas company headquartered in Fort Worth, Texas. Piper was merged into a subsidiary wholly owned by Delta.

In late 2005, the Company transferred its ownership in approximately 64,000 net acres of non-operated interests in the Columbia River Basin to CRB Partners, LLC, which originally was a wholly-owned subsidiary (“CRBP”). These interests consist of the Company’s 1% overriding royalty interest convertible into a 15% back-in working interest after project payout. During the first quarter of 2006, the Company sold a 44% minority interest in CRBP. Delta has retained the majority ownership in, and is the manager of, CRBP. The non-Delta members of CRBP have certain limited consent rights with respect to, among other things, CRBP’s election to convert to a working interest prior to actual project payout, disposition of its assets or effecting certain transactions outside the ordinary course of CRBP’s business. Further, Delta’s ownership in CRBP is subject to certain rights of first refusal and co-sale rights. The sole asset of CRBP is oil and gas properties contributed by Delta, and therefore, the sale of the minority interest in CRBP was accounted for as a disposal of oil and gas properties.

In March 2006, the Company sold approximately 26% of PGR Partners, LLC (“PGR”). PGR owns a 25% non-operated working interest in 6,314 gross acres in the Piceance Basin. The assets included in the sale consisted of both proved and unproved properties. The Company retained a 74% interest in, and is the manager of, PGR. The non-Delta members of PGR have certain limited consent rights with respect to, among other things, amending the joint operating agreement to which PGR is subject, disposition of its assets or effecting certain transactions outside the ordinary course of PGR’s business.

F-7

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005

(1) Nature of Organization, Continued

On April 28, 2006, Castle Energy Corporation shareholders approved the merger agreement between Delta and Castle Energy Corporation and subsidiaries (collectively, “Castle”). As of that date, Delta, via its merger subsidiary DPCA LLC (“DPCA”), acquired Castle. On August 21, 2006, the Company sold the Pennsylvania and West Virginia properties acquired with the Castle merger. DPCA now holds only minor non-oil and gas property assets of Castle. See Footnote 3 (“Oil and Gas Properties”).

(2) Summary of Significant Accounting Policies

     Principles of Consolidation and Basis of Presentation

The consolidated financial statements include the accounts of Delta, Amber Resources Company of Colorado (“Amber”), Piper Petroleum Company (“Piper”), CRB Partners, LLC (“CRBP”), PGR Partners, LLC (“PGR”), DHS Holding Company and DHS Drilling Company (collectively “DHS”), DPCA LLC (“DPCA”) and other subsidiaries with minimal net assets or activity (collectively, the “Company”). All inter-company balances and transactions have been eliminated in consolidation. As Amber is in a net shareholders’ deficit position for the periods presented, the Company has recognized 100% of Amber’s earnings/losses for all periods presented. The Company does not have any off-balance sheet financing arrangements (other than operating leases) or any unconsolidated special purpose entities.

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, 2007, the Company had advanced $8.5 million to Delta Oilfield under this agreement, of which $7.5 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.

Certain of the Company’s oil and gas activities are conducted through partnerships and joint ventures, including CRBP and PGR. The Company includes its proportionate share of assets, liabilities, revenues and expenses from these entities in its consolidated financial statements.

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 were sold during the year ended December 31, 2007 have been reclassified to income from discontinued operations for all periods presented. Such reclassifications had no effect on net income.

     Fiscal Year Change

On September 14, 2005, the Board of Directors approved the change of the fiscal year end from June 30 to December 31, effective December 31, 2005. This Form 10-K includes information for the years ended December 31, 2007 and 2006, six-month transitional period ended December 31, 2005 and for the twelve-month period ended June 30, 2005. The unaudited financial information for the twelve months ended December 31, 2005 is as follows:

F-8

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005

(2) Summary of Significant Accounting Policies, Continued

	Twelve Months Ended
	December 31, 2005
	(In thousands, except per share data)
Total Revenues	$	84,818
Operating Loss		(7,007	)
Loss from continuing operations before income taxes and discontinued operations		(35,533	)
Net Income		5,706
Net income per common share:
Basic	$	.13
Diluted	$	.13

     Cash Equivalents

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

     Marketable Securities

For the six months ended December 31, 2005 and the year ended June 30, 2005, the Company had investments classified as available-for-sale securities. Pursuant to Statement of Financial Accounting Standards (“SFAS”) No. 115, “Accounting for Certain Investments in Debt and Equity Securities” (“SFAS 115”), such securities are measured at fair market value in the financial statements with unrealized gains or losses recorded in other comprehensive income. At the time securities are sold or otherwise disposed of, gains or losses are included in earnings. During the six months ended December 31, 2005, the Company sold its investments as shown below.

			Realized			Proceeds
	Cost		Gain (Loss)			From Sale
			(In thousands)
December 31, 2005
Bion Environmental Technologies, Inc.	$	152	$	(140	)	$	12
Tipperary Oil & Gas Company		418		1,334			1,752
	$	570	$	1,194		$	1,764

			Unrealized			Estimated
	Cost		Gain (Loss)			Market Value
			(In thousands)
June 30, 2005
Bion Environmental Technologies, Inc.	$	152	$	(140	)	$	12
Tipperary Oil & Gas Company		418		1,334			1,752
	$	570	$	1,194		$	1,764

During 2007, the Company held investments in securities that were classified as trading securities and thus recorded at estimated fair market 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 and future changes in their fair market value will be recorded in accumulated other comprehensive income until the securities are sold. If issuers of the securities we hold are unable to successfully close future auctions and their credit ratings deteriorate, we may in future periods be required to record an impairment charge to earnings on these investments.

F-9

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005

(2) Summary of Significant Accounting Policies, Continued

     Oil and Gas Properties Held for Sale

Oil and Gas Properties held for sale as of December 31, 2007 represent the Company’s Texas Midway Loop oil and gas properties that are for sale. Accordingly, current and prior years’ operating revenue and expense have been reclassified as a component of discontinued operations.

Oil and Gas Properties held for sale as of December 31, 2006 represent the Company’s Kansas oil and gas properties that were sold in January 2007 and the Midway Loop assets mentioned above which were reclassified to conform to current presentation.

     Inventories

Inventories consist of pipe and other production equipment. Inventories are stated at the lower of cost (principally first-in, first-out) or estimated net realizable value.

     Investment in LNG project

On March 30, 2006, the Company sold its long-term minority investment in a liquid natural gas (“LNG”) project for total proceeds of $2.1 million. The Company recorded a gain on sale of $1.1 million ($657,000 net of tax).

     Minority Interest

Minority interest represents the 50.0% (47% for Chesapeake Energy Corporation and 3.0% for DHS executive officers and management) investors of DHS at December 31, 2007. 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, one of the founding officers was bought out, resulting in a slight increase in Delta’s ownership of DHS.

     Investment in and Earnings (Losses) From Unconsolidated Affiliates

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 and include the Company’s 50% investment in Delta Oilfield and other minor investments. The Company’s share of net income of these entities is recorded as earnings (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. These investments in unconsolidated affiliates are carried as a single amount in our consolidated balance sheets totaling $10.3 million and $2.9 million as of December 31, 2007 and December 31, 2006, respectively.

     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 receivable or 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 year ended December 31, 2007 and 2006, six months ended December 31, 2005 and the year ended June 30, 2005, the Company’s aggregate natural gas and crude oil imbalances were not material to its consolidated financial statements except for an imbalance acquired during fiscal 2005 which was collected during the six months ended December 31, 2005.

F-10

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005

(2) Summary of Significant Accounting Policies, Continued

     Drilling and Trucking

The Company earns its contract drilling revenues under daywork or turnkey contracts. The Company recognizes revenues on daywork contracts for the days completed based on the dayrate each contract specifies. 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, 2007 and 2006, six months ended December 31, 2005 and the fiscal year ended June 30, 2005 were $63.4 million, $54.0 million, $12.4 million, and $14.1 million, respectively.

     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.

F-11

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005

(2) Summary of Significant Accounting Policies, Continued

The Company assesses developed properties on an individual field basis for impairment on at least an annual basis. 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 such assessment, the Company recorded no impairment provision attributable to producing properties for the six months ended December 31, 2005 and the fiscal year ended June 30, 2005. During the year ended December 31, 2007, an impairment of $58.4 million was recorded primarily related to the Howard Ranch and Fuller fields in Wyoming ($37.5 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 the latter part of the year. In addition, during 2006, an impairment of $1.0 million was recorded on certain Oklahoma properties that were held for sale at December 31, 2007.

For undeveloped 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 undeveloped property are no longer recoverable, an impairment charge is recorded based on the estimated fair value of the property. As a result of such assessment, the Company recorded no impairment provision attributable to undeveloped properties for the years ended December 31, 2007 and 2006, and June 30, 2005.

However, during the six months ended December 31, 2005, a dry hole was drilled on the Company’s prospect located in Orange County, California. Based on drilling results and the Company’s evaluation of the prospect, the Company determined that it would not pursue development of the field and accordingly an impairment was recorded. Included in the Company’s consolidated statement of operations for the six months ended December 31, 2005 are $2.0 million for the dry hole that was drilled and $1.3 million for the full impairment of the remaining leasehold costs related to the prospect.

For the fiscal year 2008, the Company is continuing to develop and evaluate certain proved and unproved properties on which favorable or unfavorable results or commodity prices may cause a revision to future quarters’ estimates of those properties’ future cash flows. Such revisions of estimates could require the Company to record an impairment in the period of such revisions.

     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”). No impairment of goodwill was indicated as a result of the Company’s impairment test performed during the third quarter of 2007.

F-12

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005

(2) Summary of Significant Accounting Policies, Continued

     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. The following is a reconciliation of the Company’s asset retirement obligations for the years ended December 31, 2007 and 2006, six months ended December 31, 2005 and fiscal year ended June 30, 2005:

	Years Ended						Six Months Ended			Year Ended
	December 31,						December 31,			June 30,
	2007			2006			2005			2005
				(In thousands)
Asset retirement obligation — beginning of period	$	4,421		$	3,467		$	3,691		$	2,647
Accretion expense		278			199			96			253
Change in estimate		313			639			(19	)		—
Obligations acquired		1,743			850			160			1,153
Obligations settled		(224	)		(139	)		—			—
Obligations on sold properties		(1,332	)		(595	)		(461	)		(362	)
Asset retirement obligation — end of period		5,199			4,421			3,467			3,691
Less: Current asset retirement obligation		(1,045	)		(408	)		(465	)		(716	)
Long-term asset retirement obligation	$	4,154		$	4,013		$	3,002		$	2,975

In March 2005, the FASB issued FASB Interpretation 47 (“FIN 47”), an interpretation of SFAS No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”). FIN 47 clarifies the term “conditional asset retirement obligation” as it is used in SFAS 143. The Company applied the guidance of FIN 47 beginning July 1, 2005 resulting in no impact on its financial statements.

     Comprehensive Income (Loss)

Comprehensive income (loss) includes all changes in equity during a period except those resulting from investments by owners and distributions to owners, if any. The components of comprehensive income (loss) for the years ended December 31, 2007 and 2006, six months ended December 31, 2005 and fiscal year ended June 30, 2005 are as follows (in thousands):

						Six Months Ended			Year Ended
	Years Ended December 31,					December 31,			June 30,
	2007			2006		2005			2005
Net income (loss)	$	(149,347	)	$	435	$	(590	)	$	15,050
Other comprehensive income (transactions):
Realized gain on equity securities sold, net of tax benefit of $458		—			—		(736	)		—
Unrealized gain on marketable securities, net of tax expense of zero, zero, zero and $458, respectively		—			—		—			394
Hedging instruments reclassified to income upon settlement, net of tax benefit of zero, $1,738 and $1,733, respectively		(13,920	)		2,860		2,398			—
Change in fair value of derivative hedging instruments, net of tax (expense) benefit of zero, ($4,315), $1,036, and $3,722, respectively		6,025			7,002		(1,434	)		(5,961	)
Tax effect of valuation allowance		3,030			—		—			—
Comprehensive income (loss)	$	(154,212	)	$	10,297	$	(362	)	$	9,483

F-13

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005

(2) Summary of Significant Accounting Policies, Continued

     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 cash investments 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 market 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 marketable securities and the fair value of long-term debt were estimated based on quoted market prices. The fair values of derivative instruments were estimated based on discounted future net cash flows.

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 Other Comprehensive Income 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 hedge instruments at December 31, 2007.

     Stock Option Plans

Prior to July 1, 2005, the Company accounted for its stock option plans in accordance with the provisions of Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations. As such, compensation expense was recorded on the date of grant only if the current market price of the underlying stock exceeded the exercise price.

In December 2004, SFAS No. 123 (Revised 2004), “Share Based Payment” (“SFAS 123R”) was issued, which now requires the Company to recognize the grant-date fair value of stock options and other equity based compensation issued to employees, in the statement of operations. The cost of share based payments is recognized over the period the employee provides service. The Company adopted SFAS 123R effective July 1, 2005 using the modified prospective method and recognized compensation expense related to stock options of $319,000, $1.4 million and $2.0 million, relating to employee provided services during the years ended December 31, 2007 and 2006 and six months ended December 31, 2005, respectively.

     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.

F-14

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005

(2) Summary of Significant Accounting Policies, Continued

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 and to create stockholder value.

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.

Exercise prices for options outstanding under the Company’s various plans as of December 31, 2007 ranged from $1.75 to $15.60 per share, and the weighted-average remaining contractual life of those options was 4.18 years. All compensation expense related to these options has been recorded as of December 31, 2007. 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. At December 31, 2007, all remaining options outstanding were fully vested.

Had compensation cost for the Company’s stock-based compensation plan been determined using the fair value of the options at the grant date prior to July 1, 2005, the Company’s net income for the year ended June 30, 2005 would have been as follows:

	Year Ended
	June 30, 2005
	(In thousands, except per share amounts)
Net income (loss)	$	15,050
Equity compensation booked		306
FAS 123 compensation effect		(2,759	)1
Pro forma net income after FAS 123 implementation	$	12,597
Pro forma income per common share:
Basic	$	.31
Diluted	$	.30

1 During the quarter ended December 31, 2004, the Company granted 420,000 options to officers and 98,000 options to directors to purchase shares of its common stock at an average price of $15.34 per share, which was the market price on the date of the grant. The officers’ options vest over a three year period and the directors’ options vested on March 15, 2005. The fair market value of each option granted was $10.07 and was calculated using a risk free rate of 4.60%, volatility factors of the expected market price of the Company’s common stock of 48.76% and an average expected life of 8.0 years. During the quarter ended December 31, 2004, the Company granted 318,000 options to employees to purchase 318,000 shares of its common stock at an average price of $15.29 per share. Certain options were granted below market price. For options granted below market price, the Company recorded an expense for the difference between the option price and the grant price. The employee options vested over a year period. The average fair market value of each option granted was $7.10 and was calculated using a risk free rate of 4.60%, volatility factors of the expected market price of the Company’s common stock of 48.76% and an average expected life of 3.2 years. During the quarter ended March 31, 2005, the Company granted 105,700 options to employees to purchase 105,700 shares of its common stock at an average price of $14.75 per share. The employee options vested over a year period. The average fair market value of each option granted was $7.49 and was calculated using a risk free rate of 4.65%, volatility factors of the expected market price of the Company’s common stock of 61.23% and an average expected life of 2.0 years. The SFAS 123R compensation effect is calculated based on the options’ vesting period and includes additional grants from other periods.

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 it is $50, for the third tranche it is $60, for the fourth tranche it is $75 and for the fifth tranche it is $90. Upon attaining the Vesting Threshold for each of the

F-15

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005

(2) Summary of Significant Accounting Policies, Continued

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. Upon attaining the Vesting Thresholds for each of the fourth and fifth tranches, 150,000 of Mr. Parker’s shares would vest for each such tranche, 105,000 of Mr. Wallace’s shares would vest for each such tranche and 60,000 of Mr. Nanke’s and Mr. Freedman’s shares would each vest for each such tranche. Each award provides for the lapse of the $75 and $90 tranches if the $40 tranche has not vested on or before March 31, 2008, and the lapse of the $50 and $60 tranches 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 will be expensed ranging from 1 to 5 years. Equity compensation of $6.9 million related to the performance share grants was included in general and administrative expense during the year ended December 31, 2007.

     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. DHS deferred tax assets and liabilities are recorded on the same basis of accounting, though no valuation allowance has been provided.

     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, marketable securities, income taxes, derivatives, asset retirement obligations, contingencies and litigation accruals. Actual results could differ from these estimates.

F-16

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005

(2) Summary of Significant Accounting Policies, Continued

               Recently Issued Accounting Standards and Pronouncements

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. The Company will evaluate how the new requirements could impact the accounting for any acquisitions completed beginning in fiscal 2009 and beyond, and the potential impact on its consolidated financial statements.

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. The Company is currently evaluating the potential impact of the adoption of SFAS 160 on its consolidated financial statements.

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 has not yet determined if it will elect to apply any of the provisions of SFAS 159 or what effect the adoption of the Statement would have, if any, on its consolidated financial statements.

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 upholds the requirements of previously issued pronouncements concerning fair value measurements and expands the required disclosures. This Statement is effective for fiscal year commencing January 1, 2008. The Company does not expect the impact of SFAS 157 to be material to the Company’s financial condition or results of operations. The Company anticipates the primary impact of the standard will be additional disclosures related to the measurement of fair value in the Company’s recurring impairment test calculations related to oil and gas properties, drilling rigs, and goodwill, the valuation of oil and gas derivative instruments, and the valuation of assets acquired or liabilities assumed in future business combinations, if any.

               Recently Adopted Accounting Standards and Pronouncements

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, 2007, no adjustments were recognized for uncertain tax benefits.

F-17

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005

(2) Summary of Significant Accounting Policies, Continued

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, 2007.

The tax years 2003 through 2007 for federal returns and 2002 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.

In September 2006, the Securities and Exchange Commission issued Staff Accounting Bulletin No. 108 (“SAB 108”). SAB 108 was issued to provide interpretive guidance on how the effects of the carryover reversal of prior year misstatements should be considered in quantifying a current year misstatement. The provisions of SAB 108 were effective for the December 31, 2006 year-end. The adoption of SAB 108 had no impact on our financial position or results of operations.

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections—a replacement of APB Opinion No. 20 and FASB Statement No. 3” (“SFAS 154”). SFAS 154 requires retrospective application to prior periods’ financial statements for changes in accounting principles, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. SFAS 154 also requires that a change in depreciation, amortization, or depletion method for long-lived, non-financial assets be accounted for as a change in accounting estimate affected by a change in accounting principle. SFAS 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The implementation of SFAS 154 did not have a material impact on the Company’s consolidated results of operations, financial position or cash flows.

In April 2005, the FASB issued Staff Position 19-1, “Accounting for Suspended Well Costs” (“FSP 19-1”). FSP 19-1 provides guidance for evaluating whether sufficient progress is being made to determine whether reserves can be classified as proved and specifies that drilling costs for completed exploratory wells should be expensed if the related reserves cannot be classified as proved within one year unless certain criteria are met. FSP 19-1 is effective for all reporting periods beginning after April 4, 2005, and accordingly, the Company adopted FSP 19-1 on July 1, 2005. The following table reflects the net changes in capitalized exploratory well costs for the periods presented below:

							Six Months Ended			Year Ended
	Years Ended December 31,						December 31,			June 30,
	2007			2006			2005			2005
Balance at beginning of period	$	27,453		$	357		$	1,033		$	10
Additions to capitalized exploratory well costs pending the determination of proved reserves1		30,797			27,744			10,151			10,991
Exploratory well costs included in property divestitures		(2,941	)		—			—			—
Reclassified to proved oil and gas properties based on the determination of proved reserves		—			(357	)		(6,754	)		(7,197	)
Capitalized exploratory well costs charged to dry hole expense		(11,218	)		(291	)		(4,073	)		(2,771	)
Balance at end of period	$	44,091		$	27,453		$	357		$	1,033
Exploratory well costs capitalized for one year or less		35,649			27,453			357			1,033
Exploratory well costs capitalized for greater than one year after completion of drilling		8,442			—			—			—
Balance at end of period	$	44,091		$	27,453		$	357		$	1,033

1	The final FSP directs that costs suspended and expensed in the same period not be included in this analysis.
2	Capitalized exploratory well costs for fiscal years ended June 30, 2005 are presented based on the Company’s previous accounting policy.

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 is non-operated and pending connection to a new field gathering system. During 2007, permitting for the infrastructure was obtained and construction began. The second project representing $6.8 million of the costs is related to the Company’s Paradox Basin properties. In early 2008, permitting was obtained and construction began for the necessary pipeline infrastructure.

F-18

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005

(3) 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 $14.8 million and $12.5 million at December 31, 2007 and 2006, 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 will 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.

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, 2007, 2006 and 2005 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 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 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

F-19

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005

(3) Oil and Gas Properties, Continued

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 post-trial briefing is currently in process. The Company believes that the government’s assertion is without merit, but it cannot predict with certainty the ultimate outcome of this matter.

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 government has appealed the order and contends that, among other things, the Court erred in finding that it breached the leases, and in allowing the current lessees to stand in the shoes of their predecessors for the purposes of determining the amount of damages that they are entitled to receive. The current lessees are also appealing the order of final judgment to, among other things, challenge the Court’s rulings that they cannot recover their and their predecessors’ sunk costs as part of their restitution claim. 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 pay a portion to landowners and other owners of royalties and similar interests, to pay the litigation expenses and to fulfill certain pre-existing contractual commitments to third parties.

If new activities are commenced on the 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 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, 2007 — Acquisitions

On October 1, 2007, the Company completed a transaction involving an exchange of Washington County, Colorado properties and cash consideration of $33.0 million, prior to 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.

F-20

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005

(3) Oil and Gas Properties, Continued

On March 1, 2007, the Company paid $3.5 million for interests in producing properties and 39,000 undeveloped net acres in Fremont County, Wyoming.

In March 2007, the Company executed an earn-in agreement with EnCana whereby the Company can earn up to 6,000 net acres in the Piceance Basin with the drilling of 128 wells during the next 36 months. The Company is committed to drill 64 total wells, eight of which were drilled by October 31, 2007. The remaining wells are required to be drilled by June 1, 2009. The Company is liable for $250,000 per undrilled well in the event the drilling obligations are not met.

     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 will be the operator of the majority of the acreage, and drilling of the first well commenced in November 2006.

     Six Months Ended December 31, 2005 — Acquisitions

On September 29, 2005 the Company acquired an undivided 50% working interest in approximately 145,000 net undeveloped acres in the Columbia River Basin in Washington, and an interest in undeveloped acreage in the Piceance Basin in Colorado from Savant Resources, LLC (“Savant”) for an aggregate purchase price of $85.0 million in cash. James Wallace, a director of Delta, owns approximately a 1.7% interest in Savant, and also serves as a director of Savant. The majority of the acquired acreage in the Columbia River Basin consolidated the Company’s leasehold position at that time. Subsequent to the acquisition, Delta owned a 100% working interest in approximately 385,000 net acres. This acquisition included a small portion of acreage that is subject to an agreement with EnCana Oil & Gas (USA) Inc., whereby the Company has the right to convert an overriding royalty interest to a working interest at project payout. In the Piceance Basin, the Company acquired Savant’s interest in an entity that owns a 25% interest in approximately 6,314 gross acres that is currently being developed. The acquisition was funded through the issuance of securities discussed in Footnote 6, “Stockholders’ Equity.”

F-21

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005

     (3) Oil and Gas Properties, Continued

     Fiscal 2005 — Acquisitions

On May 4, 2005, the Company purchased from an unrelated private company a 14.25% back-in working interest in approximately 427,000 acres in the Columbia River Basin for $18.2 million in cash. The acreage is in close proximity to many of its existing leasehold interests in the basin and includes a lease on which another operator is currently drilling. The interest acquired is a non-cost bearing interest with a back-in after project payout. The Company can, however, at any time and at its discretion, convert the interest to a cost-bearing working interest by paying its proportionate share of the costs incurred in the project.

On December 15, 2004, the Company entered into a purchase and sale agreement to acquire substantially all of the oil and gas assets owned by several entities related to Manti Resources, Inc., which was an unaffiliated, privately held Texas corporation (“Manti”). The adjusted purchase price of $59.7 million was paid in cash at the closing of the transaction, which occurred on January 21, 2005. Substantially all of the assets that were acquired from Manti have been pledged as collateral on the Company’s bank credit facility.

On September 15, 2004, the Company acquired seven wells in Karnes County, Texas from an unrelated entity and an unrelated individual for $5.0 million in cash.

On July 1, 2004, the Company acquired certain interests in California’s Sacramento Basin and a 7.5% reversionary working interest in the South Tongue interests in Washington County, Colorado from Edward Mike Davis, LLC, a greater than 5% stockholder, for 760,000 shares of the Company’s common stock valued at $10.4 million using the average five-day closing price before and after the terms of the agreement were agreed upon and closed. The total acquisition cost was allocated $4.3 million to proved developed producing and $6.1 million to proved undeveloped.

     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 could be 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.

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 could be 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 retains a 74% interest in PGR.

     Six Months Ended December 31, 2005 — Dispositions

During October 2005, the Company sold its interest in various insignificant fields that were not strategic to the Company for proceeds of $5.3 million. The Company recorded a gain of $1.6 million, net of a $1.0 million provision for income taxes.

F-22

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005

     (3) Oil and Gas Properties, Continued

     Discontinued 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. Also included in discontinued operations are the Company’s Midway Loop, Texas oil and gas properties which are held for sale at December 31, 2007.

On October 1, 2007, the Company completed a transaction involving an exchange of Washington County, Colorado properties and cash consideration of $33.0 million, prior to customary purchase price adjustments, to acquire a 12.5% working interest in the Garden Gulch field in the Piceance Basin.

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.

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.

On August 11, 2006, the Company sold certain non-operated East Texas interests for sales proceeds of $14.6 million and a gain of $9.8 million ($6.1 million net of tax).

On June 1, 2006, the Company completed the sale of certain properties located in Pointe Coupee Parish, Louisiana, for cash consideration of $8.9 million with an effective date of May 1, 2006. The transaction resulted in an after-tax gain on sale of oil and gas properties of $596,000.

On September 2, 2005, the Company completed the sale of its Deerlick Creek field in Tuscaloosa County, Alabama for $30.0 million with an effective date of July 1, 2005. The Company recorded an after tax gain on sale of oil and gas properties of $10.2 million on net proceeds of approximately $28.9 million after normal closing adjustments.

F-23

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005

     (3) 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, 2007 and 2006, the six months ended December 31, 2005, and the year ended June 30, 2005:

							Six Months Ended			Year Ended
	Years Ended December 31,						December 31,			June 30,
	2007			2006			2005			2005
				(In thousands)
Revenues	$	36,084		$	36,956		$	18,012		$	38,425
Income from discontinued operations	$	17,642		$	14,743		$	8,686		$	21,630
Income tax expense		(86	)		(5,580	)		(2,734	)		(8,196	)
Income from discontinued operations, net of tax	$	17,556		$	9,163		$	5,952		$	13,434

(4) DHS Drilling Company

On April 15, 2005, the Company acquired a 49.4% ownership interest in DHS Drilling Company. The investment included the contribution of all of the net assets of the then 100% owned subsidiary, Big Dog, and certain drilling assets acquired by the Company. Previously, on March 31, 2005, the Company had purchased the remaining 50% interest of Big Dog owned by Davis for 100,000 shares of Delta’s common stock valued at $1.4 million based on the closing stock price on March 31, 2005, its 50% interest in Shark, another 100% owned subsidiary, and certain drilling equipment. Delta has the right to use all of the DHS rigs on a priority basis, although approximately one-half are currently working for third party operators.

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.

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. The rig is currently operating in the Rocky Mountain Region.

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. The rig commenced work in the Rocky Mountain Region in June 2006.

F-24

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005

(4) DHS Drilling Company , Continued

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. The rigs are currently under contract to third party operators and working in California and Utah.

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 and is working in Fremont County, Wyoming.

In December 2007, DHS sold Rigs 2 and 3 for proceeds of $6.3 million and a net loss of $31,000. The proceeds from the rigs sold were used to pay-off the JP Morgan credit facility balance in conjunction with the new Lehman facility. (See Footnote 5, “Long Term Debt”).

(5) Long Term Debt

     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 net proceeds were used to refinance debt outstanding under its credit facility which included the amount required to acquire the Manti properties. 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 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, 2007. (See Footnote 12, “Guarantor Financial Information”). The fair value of the Company’s senior notes at December 31, 2007 was $134.6 million.

     3³/4% Senior Convertible Notes, due 2037

On April 25, 2007, the Company issued $115.0 million aggregate principal amount of 3³/4% Senior Convertible Notes due 2037 (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, 2007 was approximately $110.7 million.

F-25

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005

(5) Long Term Debt, Continued

     Credit Facility

During the year ended December 31, 2007, the Company’s borrowing base under its $250.0 million credit facility was $140.0 million. At December 31, 2007, the Company had $73.6 million outstanding under the facility. Borrowing availability under this credit facility at December 31, 2007 was approximately $49.9 million after reduction for the outstanding balance and $16.5 million of outstanding letters of credit. The borrowing base is redetermined semiannually and can be increased with future drilling success. The facility has variable interest rates based upon the ratio of outstanding debt to the borrowing base. Rates vary between prime + .25% and 1.00% for base rate loans and between Libor + 1.5% and 2.25% for Eurodollar loans. The LIBOR and prime rates at December 31, 2007 approximated 6.35% and 7.25%, respectively. The loan is collateralized by substantially all of the Company’s oil and gas properties. The Company is required to meet certain financial covenants for the quarter ended December 31, 2007 which include a current ratio of 1 to 1, net of derivative instruments and deferred taxes, as defined, and a consolidated debt to EBITDAX (earnings before interest, taxes, depreciation, amortization and exploration) of less than 4.0 to 1 for the quarter ended December 31, 2007, and 3.75 to 1 for the end of each quarter thereafter. The financial covenants only include subsidiaries which the Company owns 100%. At December 31, 2007, the Company was in compliance with its quarterly debt covenants and restrictions under the facility. The facility matures on December 31, 2010. Subsequent to year-end, the Company paid down its borrowing base in full with proceeds from an equity offering completed in February (See Footnote 18 “Subsequent Events”).

     Unsecured Term Loan

In December 2006 the Company entered into an agreement with JP Morgan Chase Bank N.A., for a $25.0 million unsecured term loan with interest at LIBOR plus a margin of 3.5% at December 31, 2006. The note was paid in full in January 2007 with the proceeds from an equity offering.

     Credit Facility — DHS

On December 20, 2007, DHS entered into a new $75.0 million credit agreement with Lehman Commercial Paper Inc. The proceeds were used to pay off the JP Morgan credit facility discussed below. The Lehman credit facility has 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. The note matures on December 31, 2010. Annual principal payments are based upon a calculation of excess cash flow (as defined) for the preceding year. DHS is required to meet certain financial covenants quarterly beginning March 31, 2008 including (i) consolidated EBITDA for four consecutive fiscal quarters must be greater than $20.0 million; (ii) Consolidated Leverage Ratio (as defined) for four consecutive fiscal quarters cannot exceed 3.50 to 1.00; (iii) Consolidated Interest Coverage Ratio (as defined) for four consecutive fiscal quarters must exceed 2.50 to 1.00 and (iv) the Current Ratio for any fiscal quarter must be greater than 1.0 to 1.0. DHS incurred $1.3 million of financing charges in conjunction with the agreement which will be amortized over the life of the loan.

On May 4, 2006, DHS entered a $100.0 million senior secured credit facility with JP Morgan Chase Bank, N.A. Proceeds from the $75.0 million initial draw were used to pay off the Guggenheim term loan, complete the acquisition of C&L Drilling, finance additional capital expenditures and pay transaction expenses. In December 2007, DHS used proceeds from the Lehman credit agreement and the sale of Rigs 2 and 3 to pay off the $79.7 million outstanding balance of the JP Morgan senior secured credit facility.

F-26

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005

(5) Long Term Debt, Continued

     Term Loan — DHS

On May 4, 2006, DHS used proceeds from the JP Morgan credit facility to pay off the remaining balance of the previously outstanding term loan of approximately $41.0 million and prepayment penalties of approximately $820,000. In addition, $431,000 of unamortized deferred financing costs associated with the repaid term loan were written-off during the quarter ended June 30, 2006. Borrowing availability at December 31, 2007 was zero under the DHS facility.

     Maturities

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

YEAR ENDING December 31,
2008	$	13
2009		—
2010		148,600
2011		—
2012		—
Thereafter		265,000
	$	413,613

(6) Stockholders’ Equity

     Preferred Stock

The Company has 3,000,000 shares of preferred stock authorized, par value $.10 per share, issuable from time to time in one or more series. As of December 31, 2007 and 2006, no preferred stock was issued. As part of the reincorporation on January 31, 2006, the Company reduced the par value of the preferred stock to $.01 per share.

     Common Stock

During the years ended December 31, 2007 and 2006, six months ended December 31, 2005 and fiscal year ended June 30, 2005, the Company acquired oil and gas properties for 1,229,000 shares, 673,000 shares, 50,000 shares, and 1,571,000 shares of the Company’s common stock, respectively. The shares were valued at $23.7 million, $16.1 million, $799,000, and $22.2 million, respectively, based on the market price of the shares at the time of issuance.

On June 8, 2007, the Company issued 475,000 shares of common stock valued at approximately $9.9 million 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 April 25, 2007, the Company received net proceeds of $140.3 million from a public offering of 7,130,000 shares of the Company’s common stock.

On March 9, 2007, the Company issued 754,000 shares of common stock valued at approximately $13.8 million to acquire additional interests in two wells already owned and operated by the Company located in Polk County, Texas.

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 that provide that the shares of common stock awarded will vest if the market price of Delta stock reaches and maintains certain price levels (See Footnote 2, “Summary of Significant Accounting Policies”).

F-27

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005

(6) Stockholders’ Equity, Continued

On January 25, 2007, the Company received net proceeds of $56.4 million from a public offering of 2,768,000 shares of the Company’s common stock.

On October 2, 2006, the Company granted 334,500 shares of restricted common stock to certain non-executive employees. These shares will vest over a three year service period.

On April 28, 2006, Castle shareholders approved the merger agreement between Delta and Castle as announced on November 8, 2005. 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 upon and announced.

On February 1, 2006, the Company acquired a 65% working interest in approximately 88,000 gross acres in the central Utah hingeline play from Armstrong Resources, LLC for 673,401 shares and $24.0 million in cash. The shares of the Company’s common stock were valued at $16.1 million using the average five-day closing price before and after the terms of the agreement were agreed upon and announced. The total purchase price of $40.1 million was allocated to unproved undeveloped properties.

On February 1, 2006, the Company received net proceeds of $33.9 million from a public offering of 1.5 million shares of the Company’s common stock.

In January 2006, the Company purchased Rooster Drilling for 350,000 shares of Delta common stock valued at $8.3 million based on the value of the stock when the transaction closed (See Footnote 4 “DHS Drilling Company”).

On September 27, 2005, the Company sold 5,405,418 shares of common stock to twenty-seven institutional investors at a price of $18.50 per share in cash for gross proceeds of $100.0 million and net proceeds of approximately $95.0 million. The proceeds were used to finance the Savant acquisition discussed above and to fund drilling activities.

During fiscal 2005, the Company acquired drilling equipment for 131,000 shares of the Company’s common stock valued at $1.9 million.

     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 and to create stockholder value.

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.

F-28

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005

(6) Stockholders’ Equity, Continued

A summary of the stock option activity under the Company’s various plans and related information for the year ended December 31, 2007 follows:

	Year Ended
	December 31, 2007
				Weighted-Average			Weighted-Average		Aggregate
				Exercise			Remaining Contractual		Intrinsic
	Options			Price			Term		Value
Outstanding-beginning of year		2,359,776		$	7.85
Granted		—			—
Exercised		(202,510	)		(4.86	)
Expired / Returned		—			—
Outstanding-end of year		2,157,266		$	9.04			4.18	$	21,153,000
Exercisable-end of year		2,157,266		$	9.04			4.18	$	21,153,000

The total intrinsic value of options exercised during the years ended December 31, 2007 and 2006, six months ended December 31, 2005 and the year ended June 30, 2005 were $2.8 million, $12.3 million, $3.2 million, and $24.9 million, respectively.

A summary of the Company’s non-vested stock options and related information for the year ended December 31, 2007 follows:

	Year Ended
	December 31, 2007
				Weighted-Average
				Grant-Date
	Options			Fair Value
Nonvested-beginning of year		166,667		$	7.67
Granted		—			—
Vested		(166,667	)		(7.67	)
Forfeited / Returned		—			—
Nonvested-end of year		—		$	—

The fair value for these options was estimated at the date of grant using a Black-Scholes option pricing model with the following weighted-average assumptions for the year ended June 30, 2005, risk-free interest rate of 4.28%, dividend yield of 0%, volatility factor of the expected market price of the Company’s common stock of 43.97%, and a weighted-average expected life of the options of 4.76 years. The fair value of the options granted at the grant date was $8.0 million for the year ended June 30, 2005. No options were granted during the years ended December 31, 2007 and 2006 or six months ended December 31, 2005.

A summary of the restricted stock (nonvested stock) activity under the Company’s plan and related information for the year ended December 31, 2007 follows:

	Year Ended
	December 31, 2007
				Weighted-Average			Weighted-Average		Aggregate
	Nonvested			Grant-Date			Remaining Contractual		Intrinsic
	Stock			Fair Value			Term		Value
Nonvested-beginning of year		627,500		$	20.78
Granted		1,780,787			21.56
Vested		(266,493	)		(20.76	)
Expired / Returned		(27,173	)		(18.32	)
Nonvested-end of year		2,114,621		$	21.47			6.90	$	39,861,000

F-29

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005

(6) Stockholders’ Equity, Continued

     Restricted Stock — Directors and Employees

The total fair value of restricted stock vested during the years ended December 31, 2007 and 2006, and the six months ended December 31, 2005 was $5.2 million, $2.4 million and $697,000, respectively.

At December 31, 2007, 2006 and 2005, the total unrecognized compensation cost related to the non-vested portion of restricted stock and stock options was $20.8 million, $11.4 million and $5.8 million which is expected to be recognized over a weighted average period of 6.90, 2.08 and 4.75 years, respectively.

Cash received from exercises under all share-based payment arrangements for the years ended December 31, 2007 and 2006, six months ended December 31, 2005 and year ended June 30, 2005, was $686,000, $3.6 million, $625,000, and $132,000, respectively. Tax benefits realized from the stock options exercised during the years ended December 31, 2007 and 2006, six months ended December 31, 2005 and year ended June 30, 2005, was zero, zero, zero, and $1.3 million, respectively. During the years ended December 31, 2007 and 2006 and six months ended December 31, 2005, $8.0 million, $4.6 million and $6.6 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 that these amounts decrease taxes payable.

(7) 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, 2007 and 2006, six months ended December 31, 2005 and fiscal year ended June 30, 2005, the Company contributed $632,000, $528,000, $240,000, and $291,000, respectively, under 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.

(8) 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.

F-30

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005

(8) Commodity Derivative Instruments and Hedging Activities, Continued

At December 31, 2007, the Company’s outstanding derivative contracts were collars. Under a collar agreement the Company receives the difference between the floor price and the index price only when the index price is below the floor price, and the Company pays the difference between the ceiling price and the index price only when the index price is above the ceiling price. The Company’s collars are settled in cash on a monthly basis. By entering into collars, the Company effectively provides a floor for the price that it will receive for the hedged production; however, the collar also establishes a maximum price that the Company will receive for the hedged production when prices increase above the ceiling price. The Company enters into collars during periods of volatile commodity prices in order to protect against a significant decline in prices in exchange for foregoing the benefit of price increases in excess of the ceiling price on the hedged production.

The following table summarizes our derivative contracts outstanding at December 31, 2007:

										Net Fair Value
				Price Floor/						Asset (Liability) at
Commodity	Volume			Price Ceiling				Term	Index	December 31, 2007
										(In thousands)
Crude oil		1,200	Bbls / day	$	65.00 /	$	80.03	Jan ’08 - Mar ’08	NYMEX – WTI	$	(1,705	)
Crude oil		1,200	Bbls / day	$	65.00 /	$	79.77	Apr ’08 - June ’08	NYMEX – WTI		(1,620	)
Crude oil		1,200	Bbls / day	$	65.00 /	$	79.86	July ’08 - Sept ’08	NYMEX – WTI		(1,522	)
Crude oil		1,200	Bbls / day	$	65.00 /	$	79.83	Oct ’08 - Dec ’08	NYMEX – WTI		(1,448	)
Natural gas		15,000	mMBtu / day	$	6.50 /	$	8.30	Jan ’08 - Dec ’08	CIG		2,404
Natural gas		5,000	mMBtu / day	$	6.50 /	$	8.40	Jan ’08 - Mar ’08	CIG		211
Natural gas		10,000	mMBtu / day	$	6.00 /	$	7.25	Apr ’08 - Sept ’08	CIG		139
Natural gas		10,000	mMBtu / day	$	6.50 /	$	7.90	Oct ’08 - Dec ’08	CIG		176
										$	(3,365	)

The fair value of the Company’s derivative instruments liability was $3.4 million at December 31, 2007. Subsequent to year-end, the Company entered into new CIG gas hedges for 10,000 Mmbtu per day for the second and third quarters of 2008 with a floor price of $6.50 and ceiling prices of $7.70 and $8.15 per Mmbtu, respectively. The Company also entered into new CIG gas hedges for 35,000 Mmbtu per day for the first quarter of 2009 with a floor price of $7.50 per Mmbtu and a ceiling price of $9.88 per Mmbtu. The fair value of the derivative liability at February 26, 2008 was $15.2 million.

The net gains (losses) from effective hedging activities recognized in the Company’s statements of operations were $12.9 million, ($4.7 million), ($3.4 million), and ($630,000), for the years ended December 31, 2007 and 2006, six months ended December 31, 2005 and year ended June 30, 2005, respectively. These gains (losses) are recorded as an increase or decrease in revenues.

F-31

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005

(9) Income Taxes

The Company accounts for income taxes in accordance with the provisions of SFAS No. 109, “Accounting for Income Taxes” (“SFAS 109”). Income tax expense (benefit) attributable to income from continuing operations consisted of the following for the years ended December 31, 2007 and 2006, six months ended December 31, 2005 and fiscal year ended June 30, 2005:

							Six Months Ended			Year Ended
	Years Ended December 31,						December 31,			June 30,
	2007			2006			2005			2005
	(In thousands)
CURRENT:
U.S. — Federal	$	47		$	192		$	—		$	—
U.S. — State		(5	)		—			—			—
Foreign		—			—			—			—
DEFERRED:
U.S. — Federal		2,452			(11,052	)		(9,458	)		(10,898	)
U.S. — State		183			(1,763	)		(1,415	)		(1,071	)
Foreign		—			—			—			—
	$	2,677		$	(12,623	)	$	(10,873	)	$	(11,969	)

Income from continuing operations before taxes consists of the following for the years ended December 31, 2007 and 2006, six months ended December 31, 2005 and the fiscal year ended June 30, 2005:

U.S.	$	(160,228	)	$	(33,623	)	$	(29,203	)	$	(10,353	)
Foreign		—			—			—			—
Income (loss) from continuing operations before taxes	$	(160,228	)	$	(33,623	)	$	(29,203	)	$	(10,353	)

Income tax expense attributable to income from continuing operations was different from the amounts computed by applying U.S. Federal income tax rate of 35% to pretax income from continuing operations as a result of the following:

							Six Months Ended			Year Ended
	Years Ended December 31,						December 31,			June 30,
	2007			2006			2005			2005
Federal statutory rate		(35.0)	%		(35.0)	%		(35.0)	%		35.0	%
State income taxes, net of federal benefit		(2.1	)		(2.7	)		(3.1	)		3.4
Investment in DHS		—			—			(5.8	)		3.5
Change in valuation allowance		40.6			—			1.0			(69.6	)
Other		(1.8	)		0.2			5.7			(1.8	)
Actual income tax rate		1.7	%		(37.5)	%		(37.2)	%		(29.5)	%

F-32

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005

(9) Income Taxes, Continued

Included in the consolidated statement of operations as a component of discontinued operations for the year ended December 31, 2006 is a $5.0 million deferred tax provision on the sale and operations of properties that were sold during the period. Also included in the consolidated statement of operations as a component of extraordinary gain for the year ended December 31, 2006 is a $3.2 million deferred tax provision on the sale of properties acquired in the Castle acquisition.

Deferred tax assets (liabilities) are comprised of the following at December 31, 2007, December 31, 2006, December 31, 2005, and June 30, 2005:

							Six Months Ended			Year Ended
	Years Ended December 31,						December 31,			June 30,
	2007			2006			2005			2005
	(In thousands)
Current deferred tax asset (liability)
Derivative instruments	$	1,249		$	(3,844	)	$	4,665		$	2,638
Accrued bonuses		1,737			1,138			452			—
Allowance for doubtful accounts		236			38			38			38
Accrued vacation liability		212			140			82			—
Prepaid insurance and other		(394	)		(365	)		—			—
Total current deferred tax assets		3,040			(2,893	)		5,237			2,676
Less valuation allowance		(2,890	)		—			—			—
Net current deferred tax asset (liability)	$	150		$	(2,893	)	$	5,237		$	2,676
Long-term deferred tax asset (liability):
Deferred tax assets:
Net operating loss 1	$	56,649		$	15,306		$	16,074		$	14,544
Asset retirement obligation		1,976			1,754			1,306			1,419
Derivative instruments		—			—			2,204			1,211
Percentage depletion		596			531			530			541
Drilling equipment		—			—			792			403
Equity compensation		4,807			2,142			942			—
Minimum tax credit		1,221			1,368			—			—
Other		153			558			152			66
Total long-term deferred tax assets		65,402			21,659			22,000			18,184
Valuation allowance		(55,187	)		(661	)		(712	)		(1,139	)
Net deferred tax asset		10,215			20,998			21,288			17,045
Deferred tax liabilities:
Property and equipment		(19,261	)		(23,081	)		(17,879	)		(11,256	)
Investment in DHS		—			—			(2,001	)		(399	)
Investments — available for sale		—			—			—			(503	)
Other		(39	)		(1,577	)		(86	)		—
Total long-term deferred tax liabilities		(19,300	)		(24,658	)		(19,966	)		(12,158	)
Net long-term deferred tax asset (liability)	$	(9,085	)	$	(3,660	)	$	1,322		$	4,887
Total deferred tax assets before valuation allowance	$	68,836		$	22,975		$	27,237		$	20,860
Total deferred tax liabilities	$	19,694		$	28,867		$	19,966		$	12,158

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, 2007 and 2006 is approximately $7.9 million and $11.4 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 $38.1 million tax deduction is included in the table of net operating losses shown below.

F-33

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005

(9) Income Taxes, Continued

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, 2007, and projections for 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, 2007, the Company recorded in income tax expense an increase to the valuation allowance of $57.4 million offsetting the Company’s deferred tax assets.

At December 31, 2007, the Company had net operating loss carryforwards for regular and alternative minimum tax purposes as follows:

Regular tax net operating loss	$	191,918
Alternative minimum tax net operating loss		176,617

If not utilized, the tax net operating loss carryforwards will expire from 2008 through 2027.

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

2008	$	720
2009		3,914
2010		6,004
2011		5,939
2012		994
2013 and thereafter		174,347
	$	191,918

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 for federal income taxes.

(10) Related Party Transactions

     Transactions with Directors and Officers

On September 29, 2005 we acquired an undivided 50% working interest in approximately 145,000 net undeveloped acres in the Columbia River Basin in Washington and purchased an interest in undeveloped acreage in the Piceance Basin in Colorado from Savant Resources, LLC (“Savant”) for an aggregate purchase price of $85.0 million in cash. At the time of the transaction, James Wallace, one of our directors, owned approximately a 1.7% interest in and served as a director of Savant. The majority of the acquired acreage in the Columbia River Basin consolidates our current leasehold position.

During the quarter ended September 30, 2005, DHS borrowed $8.0 million from Chesapeake, a related party who owns approximately a 45% interest in DHS. The loan was subsequently paid in full.

During fiscal 2001 and 2000, Mr. Larson and Mr. Parker guaranteed certain borrowings which have subsequently been paid in full. 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 $110,000, $142,000, $58,000, and $100,000, for their respective 1% ORRI during the years ended December 31, 2007 and 2006, six months ended December 31, 2005 and fiscal year ended June 30, 2005, respectively.

F-34

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005

(10) Related Party Transactions, Continued

As of December 31, 2007, the Company’s executive officers had employment agreements which, among other things, include clauses that provide for the payment of certain amounts to the executives upon termination of employment and for the continuation of group medical benefits after such termination.

     Accounts Receivable Related Parties

At December 31, 2007 and 2006, the Company had $276,000 and $30,000 of receivables from related parties, respectively. These amounts include drilling costs and lease operating expense on wells owned by the related parties and operated by the Company.

(11) Earnings Per Share

The following table sets forth the computation of basic and diluted earnings per share:

	Years Ended					Six Months Ended			Year Ended
	December 31,					December 31,			June 30,
	2007			2006		2005			2005
				(In thousands, except per share amounts)
Net income (loss)	$	(149,347	)	$	435	$	(590	)	$	15,050
Basic weighted-average shares outstanding		61,297			51,702		44,959			40,327
Add: dilutive effects of stock options and unrestricted stock grants		—			1,611		—			1,693
Add: dilutive effect of 33/4% Convertible Notes using the if-converted method		—			—		—			—
Diluted weighted-average common shares outstanding		61,297			53,313		44,959			42,020
Basic net income (loss) per common share	$	(2.44	)	$	.01	$	(.01	)	$	.37
Diluted net income (loss) per common share1	$	(2.44	)	$	.01	$	(.01	)	$	.36

¹ The denominator for diluted net income (loss) per common share for the year ended December 31, 2007 and the six months ended December 31, 2005 excludes 7,951,000 and 3,231,000, respectively, of potentially dilutive shares because such shares were anti-dilutive.

F-35

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005

(12) Guarantor Financial Information

On March 15, 2005 Delta issued 7% Senior Notes (“Senior Notes”) that mature in 2015 for an aggregate amount of $150.0 million and on which interest is paid semiannually on April 1st and October 1st. The net proceeds from the Senior Notes were used to refinance debt outstanding under the Company’s credit facility. In addition, on April 25, 2007 the Company issued 3 ³/4% Convertible Senior Notes due in 2037 (“Convertible Notes”) for aggregate proceeds of $111.6 million and on which interest is paid semiannually on May 1 and November 1. The proceeds of the Convertible Notes were used for capital expenditures. Both the Senior Notes and the Convertible Notes are guaranteed by Piper Petroleum Company and 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, 2007 and 2006, the condensed consolidated statements of operations for the years ended December 31, 2007 and 2006, six months ended December 31, 2005 and the year ended June 30, 2005, and the condensed consolidated statements of cash flows for the years ended December 31, 2007 and 2006, six months ended December 31, 2005, and year ended June 30, 2005 (in thousands):

Condensed Consolidated Balance Sheet
December 31, 2007

				Guarantor			Non-Guarantor			Adjustments/
	Issuer			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Current assets	$	98,918		$	898		$	33,253		$	—		$	133,069
Property and equipment:
Oil and gas		918,247			487			80,784			(11,644	)		987,874
Drilling rigs and trucks		595			—			145,502			—			146,097
Other		35,444			4,316			1,449			—			41,209
Total property and equipment		954,286			4,803			227,735			(11,644	)		1,175,180
Accumulated DD&A		(203,091	)		(125	)		(41,937	)		—			(245,153	)
Net property and equipment		751,195			4,678			185,798			(11,644	)		930,027
Investment in subsidiaries		87,961			—			—			(87,961	)		—
Other long-term assets		29,786			3,800			8,513			—			42,099
Total assets	$	967,860		$	9,376		$	227,564		$	(99,605	)	$	1,105,195
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		464,182			7,379			136,449			(99,605	)		508,405
Total liabilities and stockholders’ equity	$	967,860		$	9,376		$	227,564		$	(99,605	)	$	1,105,195

F-36

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005

(12) Guarantor Financial Information, Continued

Condensed Consolidated Statement of Operations
Year Ended December 31, 2007

				Guarantor			Non-Guarantor			Adjustments/
	Issuer			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Total revenue	$	102,735		$	577		$	95,288		$	(34,410	)	$	164,190
Operating expenses:
Lease operating expense		28,207			118			1,060			—			29,385
Depreciation and depletion		59,461			11			25,953			—			85,425
Exploration expense		9,062			—			—			—			9,062
Drilling and trucking operations		—			—			59,720			(22,766	)		36,954
Dry hole, abandonment and impaired		85,084			—			—			—			85,084
General and administrative		44,543			(1	)		5,079			—			49,621
Total expenses		226,357			128			91,812			(22,766	)		295,531
Operating income (loss)		(123,622	)		449			3,476			(11,644	)		(131,341	)
Other income and expenses		(21,500	)		88			(8,705	)		1,230			(28,887	)
Income tax (expense) benefit		(4,486	)		—			1,809			—			(2,677	)
Discontinued operations		13,558			—			—			—			13,558
Net income (loss)	$	(136,050	)	$	537		$	(3,420	)	$	(10,414	)	$	(149,347	)

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

				Guarantor			Non-Guarantor
	Issuer			Subsidiaries			Subsidiaries			Consolidated
Operating activities	$	67,669		$	208		$	16,515		$	84,392
Investing activities		(284,900	)		(1,538	)		(38,586	)		(325,024	)
Financing activities		219,904			—			23,153			243,057
Net increase (decrease) in cash and cash equivalents		2,673			(1,330	)		1,082			2,425
Cash at beginning of the period		2,282			1,637			3,747			7,666
Cash at the end of the period	$	4,955		$	307		$	4,829		$	10,091

F -37

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005

(12) Guarantor Financial Information, Continued

Condensed Consolidated Balance Sheet
December 31, 2006

				Guarantor			Non-Guarantor			Adjustments/
	Issuer			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Current assets	$	61,946		$	2,447		$	25,401		$	—		$	89,794
Property and equipment:
Oil and gas		735,412			444			58,078			(12,119	)		781,815
Drilling rigs and trucks		595			—			135,443			—			136,038
Other		23,435			4,320			1,137			—			28,892
Total property and equipment		759,442			4,764			194,658			(12,119	)		946,745
Accumulated DD&A		(111,422	)		(119	)		(20,004	)		—			(131,545	)
Net property and equipment		648,020			4,645			174,654			(12,119	)		815,200
Investment in subsidiaries		66,366			—			—			(66,366	)		—
Other long-term assets		11,423			3,521			9,385			—			24,329
Total assets	$	787,755		$	10,613		$	209,440		$	(78,485	)	$	929,323
Current liabilities	$	88,344		$	1,200		$	10,035		$	—		$	99,579
Long-term liabilities
Long-term debt and deferred taxes		283,709			1,600			84,799			—			370,108
Asset retirement obligation		3,921			9			83			—			4,013
Total long-term liabilities		287,630			1,609			84,882			—			374,121
Minority interest		27,390			—			—			—			27,390
Stockholders’ equity		384,391			7,804			114,523			(78,485	)		428,233
Total liabilities and stockholders’ equity	$	787,755		$	10,613		$	209,440		$	(78,485	)	$	929,323

Condensed Consolidated Statement of Operations
Year Ended December 31, 2006

				Guarantor			Non-Guarantor			Adjustments/
	Issuer			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Total revenue	$	85,025		$	1,362		$	85,306		$	(25,033	)	$	146,660
Operating expenses:
Lease operating expense		22,553			471			393			—			23,417
Depreciation and depletion		52,742			112			17,530			—			70,384
Exploration expense		4,687			—			3			—			4,690
Drilling and trucking operations		—			—			47,077			(12,914	)		34,163
Dry hole, abandonment and impaired		15,682			—			—			—			15,682
General and administrative		32,266			86			3,344			—			35,696
Gain on sale of oil and gas properties		(20,034	)		—			—			—			(20,034	)
Total expenses		107,896			669			68,347			(12,914	)		163,998
Income (loss) from continuing operations		(22,871	)		693			16,959			(12,119	)		(17,338	)
Other income and expenses		(6,402	)		(23	)		(7,264	)		(2,596	)		(16,285	)
Income tax benefit		15,687			—			(3,064	)		—			12,623
Discontinued operations		15,875			—			—			—			15,875
Extraordinary gain		—			5,560			—			—			5,560
Net income (loss)	$	2,289		$	6,230		$	6,631		$	(14,715	)	$	435

F-38

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005

(12) Guarantor Financial Information, Continued

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

				Guarantor			Non-Guarantor
	Issuer			Subsidiaries			Subsidiaries			Consolidated
Operating activities	$	35,617		$	(237	)	$	18,006		$	53,386
Investing activities		(148,788	)		20,941			(75,238	)		(203,085	)
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

Condensed Consolidated Statement of Operations
Six Months Ended December 31, 2005

				Guarantor			Non-Guarantor			Adjustments/
	Issuer			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Total revenue	$	37,614		$	1,616		$	16,316		$	(7,220	)	$	48,326
Operating expenses:
Lease operating expense		9,464			178			—			—			9,642
Depreciation and depletion		12,254			158			2,846			—			15,258
Exploration expense		2,058			(1	)		4			—			2,061
Drilling and trucking operations		—			—			9,545			(3,724	)		5,821
Dry hole, abandonment and impaired		5,423			—			—			—			5,423
General and administrative		15,263			7			1,221			—			16,491
Total expenses		44,462			342			13,616			(3,724	)		54,696
Income (loss) from continuing operations		(6,848	)		1,274			2,700			(3,496	)		(6,370	)
Other income and expenses		(21,146	)		4			(1,003	)		(688	)		(22,833	)
Income tax benefit		10,873			—			—			—			10,873
Discontinued operations		17,740			—			—			—			17,740
Net income (loss)	$	619		$	1,278		$	1,697		$	(4,184	)	$	(590	)

Condensed Consolidated Statement of Cash Flows
Six Months Ended December 31, 2005

				Guarantor			Non-Guarantor
	Issuer			Subsidiaries			Subsidiaries			Consolidated
Operating activities	$	21,477		$	(1,244	)	$	4,646		$	24,879
Investing activities		(96,840	)		1,472			(51,140	)		(146,508	)
Financing activities		75,314			(209	)		49,802			124,907
Net increase (decrease) in cash and cash equivalents		(49	)		19			3,308			3,278
Cash at beginning of the period		1,999			196			46			2,241
Cash at the end of the period	$	1,950		$	215		$	3,354		$	5,519

F -39

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005

(12) Guarantor Financial Information, Continued

Condensed Consolidated Statement of Operations
Year Ended June 30, 2005

				Guarantor		Non-Guarantor			Adjustments/
	Issuer			Subsidiaries		Subsidiaries			Eliminations			Consolidated
Total revenue	$	50,159		$	1,657	$	7,319		$	(2,523	)	$	56,612
Operating expenses:
Lease operating expense		12,611			489		—			—			13,100
Depreciation and depletion		13,907			148		1,525			—			15,580
Exploration expense		6,155			—		—			—			6,155
Drilling and trucking operations		—			—		6,799			(2,133	)		4,666
Dry hole, abandonment and impaired		2,771			—		—			—			2,771
General and administrative		15,788			9		1,133			—			16,930
Total expenses		51,232			646		9,457			(2,133	)		59,202
Income (loss) from continuing operations		(1,073	)		1,011		(2,138	)		(390	)		(2,590	)
Other income and expenses		(7,792	)		31		(2	)		—			(7,763	)
Income tax benefit		11,969			—		—			—			11,969
Discontinued operations		13,434			—		—			—			13,434
Net income (loss)	$	16,538		$	1,042	$	(2,140	)	$	(390	)	$	15,050

Condensed Consolidated Statement of Cash Flows
Year Ended June 30, 2005

				Guarantor			Non-Guarantor
	Issuer			Subsidiaries			Subsidiaries			Consolidated
Operating activities	$	37,057		$	707		$	7,098		$	44,862
Investing activities		(158,273	)		(551	)		(25,058	)		(183,882	)
Financing activities		121,262			—			17,921			139,183
Net increase (decrease) in cash and cash equivalents		46			156			(39	)		163
Cash at beginning of the period		1,992			40			46			2,078
Cash at the end of the period	$	2,038		$	196		$	7		$	2,241

F-40

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005

(13) Commitments and Contingencies

The Company leases office space in Denver, Colorado and certain other locations in North America and also leases equipment and autos under non-cancelable operating leases. Rent expense for the years ended December 31, 2007 and 2006, six months ended December 31, 2005 and year ended June 30, 2005, was approximately $1,150,000, $856,000, $432,000, and $491,000, respectively. The following table summarizes the future minimum payments under all non-cancelable operating lease obligations:

	(In thousands)
2008	$	3,527
2009		3,413
2010		1,918
2011		1,796
2012		1,201
2013 and thereafter		2,394
	$	14,249

On April 30, 2007, the Company entered into agreements with four executive officers which provide for severance payments, three times the calculated average of the officer’s combined annual salary and bonus, benefit continuation and accelerated vesting of options and stock grants in the event there is a change in control of the Company. These agreements replace 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 post-trial briefing is currently in process. The Company believes that the government’s assertion is without merit, but it cannot predict with certainty the ultimate outcome of this matter.

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 government has appealed the order and contends that, among other things, the Court erred in finding that it breached the leases, and in allowing the current lessees to stand in the shoes of their predecessors for the purposes of determining the amount of damages that they are entitled to receive. The current lessees are also appealing the order of final judgment to, among other things, challenge the Court’s rulings that they cannot recover their and their predecessors’ sunk costs as part of their restitution claim. 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 pay a portion to landowners and other owners of royalties and similar interests, to pay the litigation expenses and to fulfill certain pre-existing contractual commitments to third parties.

F -41

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005

(13) 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

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 in the amount of $964,000, plus prejudgment interest, 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.

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 -42

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005

(14) Business Segments

The Company has two reportable segments: oil and gas exploration and production (“Oil and Gas”) and drilling operations (“Drilling”) through its ownership in DHS. Following is a summary of segment results for the years ended December 31, 2007 and 2006, six months ended December 31, 2005 and year ended June 30, 2005.

							Inter-segment
	Oil and Gas			Drilling			Eliminations			Consolidated
				(In thousands)
Year Ended December 31, 2007
Revenues from external customers	$	107,413		$	56,777		$	—		$	164,190
Inter-segment revenues		—			34,410			(34,410	)		—
Total revenues		107,413			91,187			(34,410	)		164,190
Operating income (loss)		(124,135	)		4,438			(11,644	)		(131,341	)
Other income and (expense) 1		(21,413	)		(8,705	)		1,231			(28,887	)
Income (loss) from continuing operations, before tax	$	(145,548	)	$	(4,267	)	$	(10,413	)	$	(160,228	)
Total Assets	$	996,549		$	146,314		$	(37,668	)	$	1,105,195
Year Ended December 31, 2006
Revenues from external customers	$	89,511		$	57,149		$	—		$	146,660
Inter-segment revenues		—			25,033			(25,033	)		—
Total revenues		89,511			82,182			(25,033	)		146,660
Operating income (loss)		(20,685	)		15,467			(12,120	)		(17,338	)
Other income and (expense) 1		(6,426	)		(7,264	)		(2,595	)		(16,285	)
Income (loss) from continuing operations, before tax	$	(27,111	)	$	8,203		$	(14,715	)	$	(33,623	)
Total Assets	$	819,470		$	148,869		$	(39,016	)	$	929,323
Six Months Ended December 31, 2005
Revenues from external customers	$	39,230		$	9,096		$	—		$	48,326
Inter-segment revenues		—			7,220			(7,220	)		—
Total revenues		39,230			16,316			(7,220	)		48,326
Operating income (loss)		(5,631	)		2,757			(3,496	)		(6,370	)
Other income and (expense) 1		(21,142	)		(1,003	)		(688	)		(22,833	)
Income (loss) from continuing operations, before tax	$	(26,773	)	$	1,754		$	(4,184	)	$	(29,203	)
Year Ended June 30, 2005
Revenues from external customers	$	51,816		$	4,796		$	—		$	56,612
Inter-segment revenues		—			2,523			(2,523	)		—
Total revenues		51,816			7,319			(2,523	)		56,612
Operating income (loss)		(174	)		(2,028	)		(388	)		(2,590	)
Other income and (expense) 1		(8,778	)		(2	)		1,017			(7,763	)
Income (loss) from continuing operations, before tax	$	(8,952	)	$	(2,030	)	$	629		$	(10,353	)

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.

F -43

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005

(15) Selected Quarterly Financial Data (Unaudited)

	Quarter Ended
	March 31,			June 30,			September 30,			December 31,
	(In thousands, except per share amounts)
Year Ended December 31, 2007
Total revenue	$	36,913		$	38,200		$	44,019		$	45,058
Income (loss) from continuing operations before income taxes, discontinued operations and cumulative effect		(25,135	)		(83,869	)		(15,056	)		(36,168	)
Net income (loss)		(18,744	)		(94,205	)		(6,418	)		(29,980	)
Net income (loss) per common share: 1
Basic	$	(.34	)	$	(1.51	)	$	(.10	)	$	(.47	)
Diluted	$	(.34	)	$	(1.51	)	$	(.10	)	$	(.47	)
Year Ended December 31, 2006
Total revenue	$	31,717		$	36,564		$	41,034		$	37,345
Income (loss) from continuing operations before income taxes, discontinued operations and cumulative effect		17,554			(8,365	)		(23,425	)		(19,387	)
Net income (loss)		13,805			4,210			(7,080	)		(10,500	)
Net income (loss) per common share: 1
Basic	$	.28		$	.08		$	(.13	)	$	(.20	)
Diluted	$	.27		$	.08		$	(.13	)	$	(.20	)

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.

F-44

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005

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

Capitalized costs related to oil and gas activities are as follows:

	December 31,			December 31,			December 31,			June 30,
	2007			2006			2005			2004
	(In thousands)
Unproved offshore California properties	$	14,789		$	12,484		$	10,960		$	10,925
Unproved onshore domestic properties		232,677			205,089			156,183			91,010
Proved offshore California properties		17,733			16,906			13,678			12,207
Proved onshore domestic properties		722,675			547,336			424,988			353,099
		987,874			781,815			605,809			467,241
Accumulated depreciation and depletion		(204,014	)		(116,151	)		(57,922	)		(43,034	)
	$	783,860		$	665,664		$	547,887		$	424,207

Costs incurred¹ in oil and gas activities are as follows:

									Six Months Ended				Year Ended
	Years Ended December 31,								December 31,				June 30,
	2007				2006				2005				2005
	(In thousands)
	Onshore		Offshore		Onshore		Offshore		Onshore		Offshore		Onshore		Offshore
Unproved property acquisition costs	$	26,408	$	2,305	$	60,002	$	1,525	$	88,116	$	35	$	25,383	$	81
Proved property acquisition costs		45,857		301		2,972		283		4,386		82		81,190		—
Developed costs incurred on undeveloped reserves		143,630		526		43,198		2,946		30,891		1,389		72,413		3,104
Development costs – other		119,607		—		159,807		—		54,591		—		36,369		—
Exploration costs		9,062		—		4,690		—		2,061		—		6,155		—
	$	344,564	$	3,132	$	270,669	$	4,754	$	180,045	$	1,506	$	221,510	$	3,185

¹ Included in costs incurred are asset retirement obligation costs for all periods presented.

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

											Six Months Ended				Year Ended
	Years Ended December 31,										December 31,				June 30,
	2007					2006					2005				2005
	(In thousands)
	Onshore			Offshore		Onshore			Offshore		Onshore		Offshore		Onshore		Offshore
Revenue:
Oil and gas revenues	$	86,838		$	7,721	$	86,627		$	7,596	$	38,833	$	3,810	$	47,255	$	5,191
Expenses:
Production costs		25,747			3,638		19,711			3,705		7,517		2,128		9,260		3,840
Depletion		62,088			1,285		53,190			1,049		11,593		382		12,544		720
Exploration		9,062			—		4,690			—		2,061		—		6,155		—
Abandonment and impaired properties		58,411			—		11,359			—		—		—		—		—
Dry hole costs		26,673			—		4,323			—		5,423		—		2,771		—
Results of operations of oil and gas producing activities	$	(95,143	)	$	2,798	$	(6,646	)	$	2,842	$	12,239	$	1,300	$	16,525	$	631
Income from operations of properties sold, net		17,556			—		9,163			—		5,952		—		13,434		—
Gain (loss) on sale of properties		(3,998	)		—		6,712			—		11,788		—		—		—
Results of discontinued operations of oil and gas producing activities	$	13,558		$	—	$	15,875		$	—	$	17,740	$	—	$	13,434	$	—

F- 45

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005

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

During the year ended December 31, 2007, two customers accounted individually for 27% and 13% of the Company’s total oil and gas sales. During the year ended December 31, 2006, two customers individually accounted for 24% and 15% of the Company’s total oil and gas sales. During the six months ended December 31, 2005, three customers individually accounted for 15%, 14% and 12% of the Company’s total oil and gas sales. During the fiscal year ended June 30, 2005, one customer individually accounted for 10% of the Company’s total oil and gas sales.

(17) 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.

     (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.

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.

F- 46

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005

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

“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, 2007, December 31, 2006, December 31, 2005, and June 30, 2005 were prepared by Ralph E. Davis Associates, Inc., the Company’s independent reserve engineers with respect to onshore reserves for all periods presented and with respect to offshore reserves as of December 31, 2007 and 2006.

Estimates of the Company’s offshore reserves were prepared by Mannon Associates Inc. as of December 31, 2005 and June 30, 2005.

A summary of changes in estimated quantities of proved reserves for the years ended December 31, 2007 and 2006, six months ended December 31, 2005 and the year ended June 30, 2005 is as follows:

	Onshore						Offshore
	GAS			OIL			OIL
	(MMcf)			(MBbl)			(MBbl)
	(In thousands)
Estimated Proved Reserves: Balance at June 30, 2004		88,479			11,378			1,827
Revisions of quantity estimate		(3,850	)		(512	)		(173	)
Extensions and discoveries		39,459			1,162			—
Purchase of properties		32,282			1,397			—
Sale of properties		(7,654	)		(153	)		—
Production		(7,675	)		(899	)		(156	)
Estimated Proved Reserves: Balance at June 30, 2005		141,041			12,373			1,498
Revisions of quantity estimate		(4,683	)		(506	)		(468	)
Extensions and discoveries		58,725			2,542			—
Purchase of properties		11,816			—			—
Sale of properties		(22,025	)		(221	)		—
Production		(3,720	)		(428	)		(81	)
Estimated Proved Reserves: Balance at December 31, 2005		181,154			13,760			949
Revisions of quantity estimate		(23,050	)		(2,943	)		(328	)
Extensions and discoveries		90,738			3,533			—
Purchase of properties		7,590			3			—
Sale of properties		(23,706	)		(673	)		—
Production		(8,022	)		(1,192	)		(162	)
Estimated Proved Reserves: Balance at December 31, 2006		224,704			12,488			459
Revisions of quantity estimate		23,932			(2,126	)		25
Extensions and discoveries		86,269			2,423			—
Purchase of properties		10,559			266			—
Sale of properties		(24,738	)		(1,425	)		—
Production		(11,253	)		(940	)		(145	)
Estimated Proved Reserves: Balance at December 31, 2007		309,473			10,686			339

F- 47

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005

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

     Proved developed reserves:

June 30, 2004	55,786	6,240	695
June 30, 2005	70,568	6,947	585
December 31, 2005	56,852	7,171	657
December 31, 2006	65,026	5,828	459
December 31, 2007	92,194	4,209	339

F- 48

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005

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

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.

	Onshore			Offshore			Combined
	(In thousands)
December 31, 2007
Future net cash flows	$	2,923,129		$	28,352		$	2,951,481
Future costs:
Production		723,689			11,921			735,610
Development and abandonment		585,622			—			585,622
Income taxes		224,073			2,281			226,354
Future net cash flows		1,389,745			14,150			1,403,895
10% discount factor		(699,896	)		(2,125	)		(702,021	)
Standardized measure of discounted future net cash flows	$	689,849		$	12,025		$	701,874
Estimated future development cost anticipated for fiscal 2008 and 2009 on existing properties	$	334,326		$	—		$	334,326
December 31, 2006
Future net cash flows	$	1,743,639		$	21,695		$	1,765,334
Future costs:
Production		466,919			14,727			481,646
Development and abandonment		329,355			—			329,355
Income taxes		76,373			562			76,935
Future net cash flows		870,992			6,406			877,398
10% discount factor		(393,249	)		(915	)		(394,164	)
Standardized measure of discounted future net cash flows	$	477,743		$	5,491		$	483,234
Estimated future development cost anticipated for fiscal 2007 and 2008 on existing properties	$	250,224		$	—		$	250,224
December 31, 2005
Future net cash flows	$	2,613,958		$	45,420		$	2,659,378
Future costs:
Production		481,537			21,970			503,507
Development and abandonment		318,704			2,950			321,654
Income taxes		471,125			5,325			476,450
Future net cash flows		1,342,592			15,175			1,357,767
10% discount factor		(604,355	)		(3,788	)		(608,143	)
Standardized measure of discounted future net cash flows	$	738,237		$	11,387		$	749,624
June 30, 2005
Future net cash flows	$	1,724,986		$	64,516		$	1,789,502
Future costs:
Production		366,453			19,286			385,739
Development and abandonment		183,416			8,934			192,350
Income taxes		294,754			—			294,754
Future net cash flows		880,363			36,296			916,659
10% discount factor		(387,874	)		(11,415	)		(399,289	)
Standardized measure of discounted future net cash flows	$	492,489		$	24,881		$	517,370

F- 49

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005

(17) 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, 2007 and 2006, six months ended December 31, 2005 and the fiscal year ended June 30, 2005 are as follows:

							Six Months Ended			Year Ended
	Years Ended December 31,						December 31,			June 30,
	2007			2006			2005			2005
	(In thousands)
Beginning of the year	$	483,234		$	749,624		$	517,370		$	288,037
Sales of oil and gas production during the period, net of production costs		(95,976	)		(98,340	)		(47,746	)		(68,602	)
Purchase of reserves in place		38,364			14,716			58,790			201,693
Net change in prices and production costs		286,255			(567,435	)		170,831			90,938
Changes in estimated future development costs		(106,678	)		(35,041	)		(50,676	)		19,345
Extensions, discoveries and improved recovery		135,868			213,741			336,920			93,624
Revisions of previous quantity estimates, estimated timing of development and other		(83,240	)		(82,456	)		(164,632	)		(91,002	)
Previously estimated development and abandonment costs incurred during the period		144,156			46,144			32,280			72,413
Sales of reserves in place		(77,631	)		(55,640	)		(56,276	)		(42,508	)
Change in future income tax		(70,801	)		222,959			(98,974	)		(75,371	)
Accretion of discount		48,323			74,962			51,737			28,803
End of year	$	701,874		$	483,234		$	749,624		$	517,370

(18) Subsequent Events

In early February, the Company added CIG collars for 10,000 Mmbtu/day with a $6.50 per Mmbtu floor and a $7.70 per Mmbtu ceiling in the second quarter of 2008 and a $6.50 per Mmbtu floor and an $8.15 per Mmbtu ceiling in the third quarter of 2008. The Company also entered into new CIG gas hedges for 35,000 Mmbtu per day for the first quarter of 2009 with a floor price of $7.50 per Mmbtu and a ceiling price of $9.88 per Mmbtu. The fair value of the derivative liability at February 26, 2008 was $15.2 million.

On February 19, 2008, the Company’s shareholders approved a transaction between the Company and Tracinda Corporation (“Tracinda”) to issue 36.0 million shares of the Company’s common stock at $19.00 per share for proceeds of $684.0 million. The transaction closed on February 20, 2008 and a portion of the proceeds was immediately used to pay down to zero all amounts outstanding under the Company’s revolving credit facility. As a result of the transaction, Tracinda owns approximately 35% of our outstanding common stock and named two members to our Board of Directors, bringing the Board to 12 members. Tracinda has the right to proportional representation on our Board, and based on their current ownership may add up to three additional members at its discretion in the future. It also has a right to proportional representation on all of our Board committees.

F- 50

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005, and June 30, 2005

(18) Subsequent Events, Continued

     On February 28, 2008, the Company closed a transaction with EnCana Oil & Gas (USA) Inc., (“EnCana”) to jointly develop a portion of EnCana’s leasehold in the Vega Area of the Piceance Basin. In addition, Delta has acquired over 1,700 drilling locations on approximately 18,250 gross acres with a 95% working interest. The transaction increases the Company’s working interest in the North Vega project leasehold to 95% from an average 50%, with additional acquired acreage that includes the Buzzard Creek federal unit (4,300 acres) and approximately 6,000 acres immediately adjacent to the Buzzard Creek Unit. With this agreement, the Company’s acreage position in the Vega Area totals over 20,250 net acres. The effective date of the transaction is March 1, 2008. Under terms of the agreement the Company has committed to fund $410.5 million, $110.5 million paid at closing and three $100 million installments over the next four years that have been guaranteed with a Letter of Credit.

F- 51

Glossary of Oil and Gas Terms

     The terms defined in this section are used throughout this Form 10-K.

     Bbl. Barrel (of oil or natural gas liquids).

     Bcf. Billion cubic feet (of natural gas).

     Bcfe. Billion cubic feet equivalent.

     Bbtu. One billion British Thermal Units.

     Developed acreage. The number of acres which are allocated or held by producing wells or wells capable of production.

     Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

     Dry hole; dry well. A well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

     Equivalent volumes. Equivalent volumes are computed with oil and natural gas liquid quantities converted to Mcf on an energy equivalent ratio of one barrel to six Mcf.

     Exploratory well. A well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir.

     Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

     Liquids. Describes oil, condensate, and natural gas liquids.

     MBbls. Thousands of barrels.

     Mcf. Thousand cubic feet (of natural gas).

     Mcfe. Thousand cubic feet equivalent.

     MMBtu. One million British Thermal Units, a common energy measurement.

     MMcf. Million cubic feet.

     MMcfe. Million cubic feet equivalent.

     NGL. Natural gas liquids.

     Net acres or net wells. The sum of the fractional working interest owned in gross acres or gross wells expressed in whole numbers.

     NYMEX. New York Mercantile Exchange.

     Present value or PV10% or “SEC PV10%.”     When used with respect to oil and gas reserves, present value or PV10% or SEC PV10% means the estimated future gross revenue to be generated from the production of net proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, without giving effect to non-property related expenses such as general and administrative expenses, debt service, accretion, and future income tax expense or to depreciation, depletion, and amortization, discounted using monthly end-of-period discounting at a nominal discount rate of 10% per annum.

     Productive wells. Producing wells and wells that are capable of production, including injection wells, salt water disposal wells, service wells, and wells that are shut-in.

     Proved developed reserves. Estimated proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

     Proved reserves. Estimated quantities of crude oil, natural gas, and natural gas liquids which, upon analysis of geologic and engineering data, appear with reasonable certainty to be recoverable in the future from known oil and gas reservoirs under existing economic and operating conditions.

     Proved undeveloped reserves. Estimated proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required.

     Undeveloped acreage. Acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains estimated proved reserves.

     Working interest. An operating interest which gives the owner the right to drill, produce, and conduct operating activities on the property and a share of production.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange of Act of 1934, we have caused this Form 10-K to be signed on our behalf by the undersigned, thereunto duly authorized, in the City of Denver and State of Colorado on the 29^th day of February, 2008.

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

Pursuant to the requirements of the Securities Exchange Act of 1934, this Form 10-K has been signed below by the following persons on our behalf and in the capacities and on the dates indicated.

Signature and Title	Date
/s/ Roger A. Parker Roger A. Parker, Director	February 29, 2008
/s/ Hank Brown Hank Brown, Director	February 29, 2008
/s/ Kevin R. Collins Kevin R. Collins, Director	February 29, 2008
/s/ Jerrie F. Eckelberger Jerrie F. Eckelberger, Director	February 29, 2008
/s/ Aleron H. Larson, Jr. Aleron H. Larson, Jr., Director	February 29, 2008
/s/ Russell S. Lewis Russell S. Lewis, Director	February 29, 2008
/s/ James J. Murren James J. Murren, Director	February 29, 2008
/s/ Jordan R. Smith Jordan R. Smith, Director	February 29, 2008
/s/ Neal A. Stanley Neal A. Stanley, Director	February 29, 2008
/s/ Daniel J. Taylor Daniel J. Taylor, Director	February 29, 2008
/s/ James B. Wallace James B. Wallace, Director	February 29, 2008
/s/ John R. Wallace John R. Wallace, Director	February 29, 2008

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 8-K dated January 31, 2006.
3.2	Amended and Restated By-laws of the Company. Incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K, dated February 9, 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 dated March 15, 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 dated March 15, 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 dated March 15, 2005.
4.4	Form of 7% Series A Senior Notes due 2015 with attached notation of Guarantees.
	Incorporated by reference from Exhibit 4.4 to the Company’s Form 8-K dated March 15, 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 dated April 19, 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 dated April 19, 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 to the Company’s Notice of Annual Meeting and Proxy Statement dated July 26, 2001 for fiscal year 2000 ended June 30, 2000.*
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 dated October 25, 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 dated June 17, 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 dated June 17, 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 dated May 5, 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 dated May 5, 2005.*
10.10	Employment Agreement with John R. Wallace dated May 5, 2005. Incorporated by reference from Exhibit 10.2 to the Company’s Form 8-K dated May 5, 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 dated January 11, 2006.*
10.12	Delta Petroleum Corporation 2004 Incentive Plan. Incorporated by reference from Appendix A to the Company’s Definitive Proxy Statement filed on 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 dated June 20, 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 dated November 17, 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 dated November 17, 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 dated November 17, 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 on 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 dated February 5, 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 dated April 30, 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 dated April 30, 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 dated April 30, 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 dated April 30, 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 dated December 31, 2007.
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. 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.
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.
23.3	Consent of Mannon Associates. 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.

* Management contracts and compensatory plans.

EX-10.24

Exhibit 10.24

$75,000,000

CREDIT AGREEMENT

among

DHS HOLDING COMPANY,

DHS DRILLING COMPANY,

as Borrower,

The Several Lenders

from Time to Time Parties Hereto,

LEHMAN BROTHERS INC.,

as Sole Arranger,

and

LEHMAN COMMERCIAL PAPER INC.,

as Syndication Agent and Administrative Agent

Dated as of December 20, 2007

TABLE OF CONTENTS

	Page
ARTICLE I DEFINITIONS		1
1.1 Defined Terms		1
1.2 Other Definitional Provisions		18
1.3 Computation of Time Periods		19
ARTICLE II AMOUNT AND TERMS OF COMMITMENTS		19
2.1 Loan Commitments		19
2.2 Procedures for Borrowing		19
2.3 Maturity Date		19
2.4 Repayment of Loans; Evidence of Debt		19
2.5 Fees		20
2.6 Optional Prepayments		20
2.7 Mandatory Prepayments		21
2.8 Interest Rates, Payment Dates and Computation of Interest and Fees		22
2.9 Application of Payments		22
2.10 Requirements of Law		24
2.11 Taxes		25
2.12 Indemnity		27
2.13 Change of Lending Office		27
ARTICLE III REPRESENTATIONS AND WARRANTIES		27
3.1 Financial Condition		27
3.2 No Change		28
3.3 Corporate Existence; Compliance with Law		28
3.4 Entity Power; Authorization; Enforceable Obligations		29
3.5 No Legal Bar		29
3.6 No Indebtedness; No Material Litigation		29
3.7 No Default		29
3.8 Ownership of Property; Liens		29
3.9 Insurance		30
3.10 Intellectual Property		30
3.11 Taxes		30
3.12 Federal Regulations		30
3.13 Labor Matters		31
3.14 ERISA		31
3.15 Regulations		31
3.16 Capital Stock; Subsidiaries		31
3.17 Use of Proceeds		32
3.18 Customers and Suppliers		32
3.19 Environmental Matters		32
3.20 Accuracy of Information, Etc		33
3.21 Security Documents		33
3.22 Solvency		34
3.23 Drilling Rig Assets		34
3.24 Contingent Obligations		34
3.25 Bank Accounts		35

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	Page
3.26 Access Agreements		35
3.27 Customers and Suppliers		35
ARTICLE IV CONDITIONS PRECEDENT		35
4.1 Conditions to Initial Loan		35
4.2 Conditions Deemed Fulfilled		38
ARTICLE V AFFIRMATIVE COVENANTS		39
5.1 Financial Statements		39
5.2 Collateral Reporting		40
5.3 Certificates; Other Information		40
5.4 Payment of Obligations		42
5.5 Conduct of Business and Maintenance of Existence, etc		42
5.6 Operation and Maintenance of Property; Insurance		42
5.7 Inspection of Property; Books and Records; Discussions		43
5.8 Notices		43
5.9 Environmental Laws		44
5.10 Additional Collateral, etc		45
5.11 Use of Proceeds		46
5.12 ERISA Documents		46
5.13 Further Assurances		47
5.14 Patriot Act Compliance		47
5.15 Post-Closing Delivery		47
ARTICLE VI NEGATIVE COVENANTS		47
6.1 Financial Condition Covenants		47
6.2 Indebtedness		48
6.3 Liens		48
6.4 Fundamental Changes		49
6.5 Disposition of Property		50
6.6 Restricted Payments		50
6.7 Capital Expenditures		51
6.8 Investments		51
6.9 Transactions with Affiliates		51
6.10 Sales and Leasebacks		52
6.11 Changes in Fiscal Periods		52
6.12 Negative Pledge Clauses		52
6.13 Restrictions on Subsidiary Distributions		52
6.14 Lines of Business		52
6.15 Amendments of Certain Documents		52
6.16 Activities of Holdings		52
6.17 New Subsidiaries		53
6.18 Use of Proceeds		53
6.19 New Bank Accounts		53
6.20 Storage of Drilling Rig Assets		53
6.21 Hedging Agreements		53
ARTICLE VII EVENTS OF DEFAULT		53
7.1 Events of Default		53
7.2 Remedies		55

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	Page
ARTICLE VIII THE AGENTS		55
8.1 Appointment		55
8.2 Delegation of Duties		56
8.3 Exculpatory Provisions		56
8.4 Reliance by Agents		56
8.5 Notice of Default		56
8.6 Non Reliance on the Agents and Other Lenders		57
8.7 Indemnification		57
8.8 Agents in their Individual Capacities		57
8.9 Successor Administrative Agent		58
8.10 Authorization to Release Liens and Guarantees		58
8.11 Arranger; Syndication Agent		58
8.12 Withholding Tax		58
ARTICLE IX MISCELLANEOUS		59
9.1 Amendments and Waivers		59
9.2 Notices		60
9.3 No Waiver; Cumulative Remedies		61
9.4 Survival of Representations and Warranties		61
9.5 Payment of Expenses		61
9.6 Successors and Assigns; Participations and Assignments		62
9.7 Adjustments; Set off		64
9.8 Counterparts		65
9.9 Severability		65
9.10 Integration; Construction		65
9.11 GOVERNING LAW		65
9.12 Submission To Jurisdiction; Waivers		66
9.13 Acknowledgments		66
9.14 Confidentiality		66
9.15 Release of Collateral and Guarantee Obligations		67
9.16 Accounting Changes		67
9.17 WAIVERS OF JURY TRIAL		68
9.18 Customer Identification – USA PATRIOT Act Notice		68

iii

SCHEDULES:
1.1	Commitments
1.2	Real Property
3.1(b)	Dispositions
3.4	Consents, Authorizations, Filings and Notices
3.16	Capital Stock Ownership
3.21(a)-1	Security Agreement UCC Filing Jurisdictions
3.21(a)-2	UCC Financing Statements to Remain on File
3.21(a)-3	UCC Financing Statements to be Terminated
3.23	Drilling Rig Assets
3.25	Bank Accounts
EXHIBITS:
A	Form of Access Agreement
B	Form of Borrowing Notice
C	Form of Compliance Certificate
D	Form of Deposit Account Control Agreement
E	Form of Guarantee and Security Agreement
F	Form of Solvency Certificate
G	Form of Note
H	Form of Exemption Certificate
I	Form of Closing Certificate
J	Form of Assignment and Acceptance

iv

     This CREDIT AGREEMENT, dated as of December 20, 2007 , is by and among DHS HOLDING COMPANY, a Delaware corporation (“Holdings”), DHS DRILLING COMPANY, a Colorado corporation (“Borrower”), the several banks and other financial institutions or entities from time to time parties to this Agreement (the “Lenders”), LEHMAN BROTHERS INC., as sole arranger and sole bookrunner (in such capacity, the “Arranger”), and LEHMAN COMMERCIAL PAPER INC., as syndication agent and as administrative agent (in such capacity, the “Administrative Agent”).

W I T N E S S E T H:

     WHEREAS, Borrower has requested that the Lenders make term loans to Borrower in the aggregate principal amount of up to $75,000,000;

     WHEREAS, Holdings and Borrower are party to that certain Credit Agreement dated as of May 4, 2006 (as amended to the date hereof, the “Existing Credit Agreement”) with JPMorgan Chase Bank, N.A., as administrative agent and the other lenders party thereto are parties to that certain; and

     WHEREAS, Holdings and Borrower desire to refinance Indebtedness outstanding under the Existing Credit Agreement; and the Lenders are willing to make term loans to Borrower on the terms and conditions of this Agreement;

     NOW, THEREFORE, in consideration of the premises and the agreements hereinafter set forth, the parties hereto hereby agree as follows:

ARTICLE I
DEFINITIONS

     1.1 Defined Terms. As used in this Agreement, the terms listed in this Section 1.1 shall have the respective meanings set forth in this Section 1.1.

     Access Agreement: each access agreement to be executed and delivered by each Person on whose premises any Loan Party maintains a material portion of any Collateral, including any Drilling Rig Assets and any books and records of the Loan Parties, such Loan Party and the Administrative Agent, substantially in the form of Exhibit A.

     Accounting Change: as defined in Section 9.16.

     Administrative Agent: as defined in the preamble hereto.

     Affiliate: as to any Person, any other Person that, directly or indirectly, is in control of, is controlled by, or is under common control with, such Person. For purposes of this definition, “control” of a Person means the power, directly or indirectly, either to (a) vote 10% or more of the securities having ordinary voting power for the election of directors (or persons performing similar functions) of such Person or (b) direct or cause the direction of the management and policies of such Person, whether by contract or otherwise. Notwithstanding the foregoing, no Lender shall be deemed to be an Affiliate of the Loan Parties.

     Agents: the collective reference to the Arranger, the Syndication Agent and the Administrative Agent.

1

     Aggregate Exposure: with respect to any Lender at any time, an amount equal to (a) until the funding of the Loans on the Closing Date, such Lender’s Commitment at such time; (b) thereafter, the aggregate then unpaid principal amount of such Lender’s Loans.

     Aggregate Exposure Percentage: with respect to any Lender at any time, the ratio (expressed as a percentage) of such Lender’s Aggregate Exposure at such time to the sum of the Aggregate Exposures of all Lenders at such time.

     Agreement: this Credit Agreement, as amended, restated, replaced, supplemented or otherwise modified from time to time.

     Applicable Premium: as defined in Section 2.6(a).

     Approved Appraiser: Superior Asset Management or such other independent appraiser reasonably acceptable to the Administrative Agent having issued an appraisal report after March 1, 2006.

     Arranger: as defined in the preamble hereto.

     Asset Sale: any Disposition of Property or series of related Dispositions of Property (excluding any such Disposition permitted by Sections 6.5(b) and (e)) which yields aggregate gross proceeds to any Loan Party or any of its Subsidiaries (valued at the initial principal amount thereof in the case of non-cash proceeds consisting of notes or other debt securities and valued at fair market value in the case of other non-cash proceeds) in excess of $500,000.

     Assignee: as defined in Section 9.6(c).

     Assignment and Acceptance: as defined in Section 9.6(c).

     Assignor: as defined in Section 9.6(c).

     Benefit Plan: at a particular time, any employee benefit plan that is covered by ERISA and in respect of which any Loan Party or a Commonly Controlled Entity is (or, if such Benefit Plan were terminated at such time, would under Section 4069 of ERISA be deemed to be) an “employer” as defined in Section 3(5) of ERISA.

     Benefitted Lender: as defined in Section 9.7(a).

     Board: the Board of Governors of the Federal Reserve System of the United States (or any successor).

     Borrower: as defined in the preamble hereto.

     Borrower’s knowledge: the best knowledge (after due and diligent investigation) of Borrower or Holdings, as applicable.

     Borrowing Date: any Business Day specified by Borrower as a date on which Borrower requests the relevant Lenders to make Loans hereunder.

     Borrowing Notice: with respect to any request for borrowing of Loans hereunder, a notice from Borrower, substantially in the form of, and containing the information prescribed by, Exhibit B, delivered to the Administrative Agent.

2

     Business Day: a day other than a Saturday, Sunday or other day on which commercial banks in New York City, New York, or Houston, Texas are authorized or required by law to close.

     Capital Expenditures: for any period, with respect to any Person, the aggregate of all expenditures by such Person and its Subsidiaries for the direct or indirect acquisition or leasing (pursuant to a Capital Lease) fixed or capital assets or additions to equipment (including replacements, capitalized repairs and improvements) during such period which are required to be capitalized under GAAP on a balance sheet of such Person; provided that Capital Expenditures shall exclude expenditures made with any portion of any Reinvestment Deferred Amount relating to any Reinvestment Event in compliance with Sections 2.7(b) and Section 6.7(b).

     Capital Lease: any lease (or other arrangement conveying the right to use) of a Person with respect to any Property or a combination thereof, the obligations under which are required to be classified and accounted for as a capital lease on a balance sheet of such Person under GAAP.

     Capital Lease Obligations: with respect to any Person, the obligations of such Person to pay rent or other amounts under any Capital Lease and, for the purposes of this Agreement, the amount of such obligations at any time shall be the capitalized amount thereof at such time determined in accordance with GAAP.

     Capital Stock: any and all shares, interests, participations or other equivalents (however designated) of capital stock of a corporation, any and all equivalent membership, partnership or other ownership interests in a Person (other than a corporation) and any and all warrants, rights or options to purchase any of the foregoing.

     Cash Equivalents: (a) marketable direct obligations issued by, or unconditionally guaranteed by, the United States government or issued by any agency thereof and backed by the full faith and credit of the United States, in each case maturing within one year from the date of acquisition; (b) certificates of deposit, time deposits, Eurodollar time deposits or overnight bank deposits having maturities of six months or less from the date of acquisition issued by any Lender or by any commercial bank organized under the laws of the United States of America or any state thereof having combined capital and surplus of not less than $500,000,000; (c) commercial paper of an issuer rated at least A-2 by S&P or P-2 by Moody’s, or carrying an equivalent rating by a “nationally recognized statistical rating organization” (within the meaning of proposed Rule 3b-10 promulgated by the SEC under the Exchange Act), if both of the two named rating agencies cease publishing ratings of commercial paper issuers generally, and maturing within six months from the date of acquisition; (d) repurchase obligations of any Lender or of any commercial bank satisfying the requirements of clause (b) of this definition, having a term of not more than 30 days with respect to securities issued or fully guaranteed or insured by the United States government; (e) securities with maturities of one year or less from the date of acquisition issued or fully guaranteed by any state, commonwealth or territory of the United States, by any political subdivision or taxing authority of any such state, commonwealth or territory, the securities of which state, commonwealth, territory, political subdivision or taxing authority (as the case may be) are rated at least A by S&P or A by Moody’s; (f) securities with maturities of six months or less from the date of acquisition backed by standby letters of credit issued by any Lender or any commercial bank satisfying the requirements of clause (b) of this definition; and (g) shares of money market mutual or similar funds which invest exclusively in assets satisfying the requirements of clauses (a) through (f) of this definition.

     Change of Control: the occurrence of any of the following events: (a) Delta Petroleum Corporation and the Management Investors shall cease to have the power to vote or direct the voting of securities having a majority of the ordinary voting power for the election of directors of Holdings (determined on a fully diluted basis); (b) Delta Petroleum Corporation and the Management Investors

3

shall cease to own of record and beneficially a majority of the outstanding common stock of Holdings; (c) any “person” or “group” (as such terms are used in Sections 13(d) and 14(d) of the Exchange Act), excluding Delta Petroleum Corporation and Chesapeake Energy Corporation, shall become, or obtain rights (whether by means or warrants, options or otherwise) to become, the “beneficial owner” (as defined in Rules 13(d)-3 and 13(d)-5 under the Exchange Act), directly or indirectly, of more than 20% on a fully diluted basis, of the outstanding Capital Stock of Holdings entitled to vote for the members of the board of directors of Holdings; (d) ) any “person” or “group” (as such terms are used in Sections 13(d) and 14(d) of the Exchange Act) shall become, or obtain rights (whether by means or warrants, options or otherwise) to become, the “beneficial owner” (as defined in Rules 13(d)-3 and 13(d)-5 under the Exchange Act), directly or indirectly, of more than 50% on a fully diluted basis, of the outstanding Capital Stock of Delta Petroleum Corporation; (e) the board of directors of Borrower or Delta Petroleum Corporation shall cease to consist of a majority of Continuing Directors; or (f) Holdings shall cease to own and control, of record and beneficially, directly, 100% of each class of outstanding Capital Stock of Borrower or Borrower shall cease to own and control, of record and beneficially, directly or indirectly, 100% of each class of outstanding Capital Stock of each Subsidiary Guarantor or other Subsidiary of Borrower, in each case free and clear of all Liens (except Liens created by the Guarantee and Security Agreement).

     Closing Date: the date on which the conditions precedent set forth in Section 4.1 shall have been satisfied, which date shall be not later than December 31, 2007.

     Code: the Internal Revenue Code of 1986, as amended from time to time, the regulations thereunder and publicly available interpretations thereof.

     Collateral: all Property of the Loan Parties, now owned or hereafter acquired, upon which a Lien is purported to be created by any Security Document.

     Collateral Value Deficiency: at any point in time, the amount, if any, by which the aggregate Obligations exceed the aggregate Rig Asset Value.

     Commitment: as to any Lender, the obligation of such Lender, if any, to make a Loan to Borrower hereunder in a principal amount not to exceed the amount set forth under the heading “Commitment” opposite such Lender’s name on Schedule 1 hereto, or, as the case may be, in the Assignment and Acceptance pursuant to which such Lender became a party hereto, as the same may be reduced pursuant to Section 2.1. The original aggregate amount of the Commitments is $75,000,000.

     Commitment Letter: that certain Letter Agreement, dated as of December 14, 2007, among Borrower, Lehman Brothers Inc. and Lehman Commercial Paper Inc.

     Commonly Controlled Entity: an entity, whether or not incorporated, that is under common control with Borrower within the meaning of Section 4001 of ERISA or is part of a group that includes Borrower and that is treated as a single employer under Section 414 of the Code.

     Compliance Certificate: a certificate duly executed by a Responsible Officer, substantially in the form of Exhibit C.

     Consolidated Current Assets: at any date, the total consolidated current assets of Borrower and its Subsidiaries at such date, adjusted for non-cash assets, determined in conformity with GAAP.

     Consolidated Current Liabilities: at any date, all liabilities of Borrower and its Subsidiaries at such date which should, in conformity with GAAP, be classified as current liabilities adjusted for non-

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cash liabilities, on a consolidated balance sheet of Borrower and its Subsidiaries prepared in conformity with GAAP.

     Consolidated EBITDA: of any Person for any period, Consolidated Net Income of such Person and its Subsidiaries for such period plus, without duplication and to the extent reflected as a charge in the statement of such Consolidated Net Income for such period, the sum of (a) income tax expense, (b) Consolidated Interest Expense of such Person and its Subsidiaries, amortization or write-off of debt discount and debt issuance costs and commissions, discounts and other fees and charges associated with Indebtedness, (c) depreciation and amortization expense, (d) amortization of intangibles (including, but not limited to, goodwill) and organization costs, (e) any extraordinary, unusual or non-recurring expenses or losses (including, whether or not otherwise includable as a separate item in the statement of such Consolidated Net Income for such period, losses on sales of assets outside of the ordinary course of business) provided that the amounts referred to in this clause (e) shall not, in the aggregate, exceed for any fiscal year of Borrower $5,000,000 and (f) any other non-cash charges, including (in case of clauses (e) and (f), charges representing (i) accruals of or reserves for cash expenditures in a future period and (ii) amortization of prepaid items paid in cash in a prior period; minus, to the extent included in the statement of such Consolidated Net Income for such period, the sum of (A) interest income (except to the extent deducted in determining Consolidated Interest Expense), (B) any extraordinary, unusual or non-recurring income or gains (including, whether or not otherwise includable as a separate item in the statement of such Consolidated Net Income for such period, gains on the sales of assets outside of the ordinary course of business), (C) income tax credits (to the extent not netted from income tax expense) and (D) any other non-cash income, all as determined on a consolidated basis and (E) whether or not included in the statement of such Consolidated Net Income for such period, all cash expenditures in such period for previously accrued or reserved for charges or prepaid items to be amortized in future periods; provided that for purposes of calculating Consolidated EBITDA of Borrower for any period, (i) the Consolidated EBITDA of any Person or business acquired by Borrower or its Subsidiaries during such period shall be included on a pro forma basis for such period (assuming the consummation of such acquisition and the incurrence or assumption of any Indebtedness in connection therewith occurred on the first day of such period) if the consolidated balance sheet of such acquired Person and its consolidated Subsidiaries as at the end of the period preceding the acquisition of such Person and the related consolidated statements of income and stockholders’ equity and of cash flows for the period in respect of which Consolidated EBITDA is to be calculated (1) have been previously provided to the Administrative Agent and the Lenders and (2) either (x) have been reported on without a qualification arising out of the scope of the audit by independent certified public accountants of nationally recognized standing or (y) have been found acceptable by the Administrative Agent and (ii) the Consolidated EBITDA of any Person or business Disposed of by Borrower or its Subsidiaries during such period shall be excluded for such period (assuming the consummation of such Disposition and the repayment of any Indebtedness in connection therewith occurred on the first day of such period).

     Consolidated Interest Coverage Ratio: for any period, the ratio of (a) Consolidated EBITDA of Borrower and its Subsidiaries for such period to (b) Consolidated Interest Expense of Borrower and its Subsidiaries for such period.

     Consolidated Interest Expense: of any Person for any period, total cash interest expense (including that attributable to Capital Lease Obligations) of such Person and its Subsidiaries for such period with respect to all outstanding Indebtedness of such Person and its Subsidiaries (including all commissions, discounts and other fees and charges owed by such Person with respect to letters of credit and bankers’ acceptance financing); provided that for purposes of calculating Consolidated Interest of Borrower for any period, (i) the Consolidated Interest of any Person or business acquired by Borrower or its Subsidiaries during such period shall be included on a pro forma basis for such period (assuming the consummation of such acquisition and the incurrence or assumption of any Indebtedness in connection

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therewith occurred on the first day of such period) if the consolidated balance sheet of such acquired Person and its consolidated Subsidiaries as at the end of the period preceding the acquisition of such Person and the related consolidated statements of income and stockholders’ equity and of cash flows for the period in respect of which Consolidated Interest is to be calculated (x) have been previously provided to the Administrative Agent and the Lenders and (y) either (1) have been reported on without a qualification arising out of the scope of the audit by independent certified public accountants of nationally recognized standing or (2) have been found acceptable by the Administrative Agent and (ii) the Consolidated Interest of any Person or business Disposed of by Borrower or its Subsidiaries during such period shall be excluded for such period (assuming the consummation of such Disposition and the repayment of any Indebtedness in connection therewith occurred on the first day of such period).

     Consolidated Leverage Ratio: as at the last day of any period of four consecutive fiscal quarters of Borrower, the ratio of (a) Consolidated Total Debt on such day to (b) Consolidated EBITDA of Borrower for such period.

     Consolidated Net Income: of any Person for any period, the consolidated net income (or loss) of such Person and its Subsidiaries for such period, determined on a consolidated basis in accordance with GAAP; provided that in calculating Consolidated Net Income of Borrower and its consolidated Subsidiaries for any period, there shall be excluded (a) the income (or deficit) of any Person accrued prior to the date it becomes a Subsidiary of Borrower or is merged into or consolidated with Borrower or any of its Subsidiaries, (b) the income (or deficit) of any Person (other than a Subsidiary of Borrower) in which Borrower or any of its Subsidiaries has an ownership interest, except to the extent that any such income is actually received by Borrower or such Subsidiary in the form of dividends or similar distributions, (c) the undistributed earnings of any Subsidiary of Borrower to the extent that the declaration or payment of dividends or similar distributions by such Subsidiary is not at the time permitted by the terms of any Contractual Obligation (other than under any Loan Document) or Requirement of Law applicable to such Subsidiary, and (d) any one-time increase or decrease to such consolidated net income (or loss) which is required to be recorded because of the adoption of new accounting policies, practices or standards required by GAAP.

     Consolidated Total Debt: at any date, the aggregate principal amount of all Indebtedness of Borrower and its Subsidiaries at such date, determined on a consolidated basis in accordance with GAAP, less the aggregate amount of all Cash and Cash Equivalents in excess of $1,000,000.

     Consolidated Working Capital: at any date, the difference of (a) Consolidated Current Assets of Borrower on such date less (b) Consolidated Current Liabilities of Borrower on such date.

     Constituent Documents: with respect to any Person, (a) the articles or certificate of incorporation, certificate of formation or partnership, articles of organization, limited liability company agreement or agreement of limited partnership (or the equivalent organizational documents) of such Person, (b) the by-laws (or the equivalent governing documents) of such Person and (c) any document setting forth the manner of election and duties of the directors or managing members of such Person (if any) and the designation, amount or relative rights, limitations and preferences of any class or series of such Person’s Capital Stock.

     Contingent Obligation: of a Person, any agreement, undertaking or arrangement by which such Person assumes, guarantees, endorses, contingently agrees to purchase or provide funds for the payment of, or otherwise becomes or is contingently liable upon, the obligation or liability of any other Person, or agrees to maintain the net worth or working capital or other financial condition of any other Person, or otherwise assures any creditor of such other Person against loss, including any comfort letter, operating

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agreement, take or pay contract or the obligations of any such Person as general partner of a partnership with respect to the liabilities of the partnership.

     Continuing Directors: the directors of Borrower or Delta Petroleum Corporation, as applicable, on the Closing Date, and each other director if, in each case, such other director’s nomination for election to the board of directors of Borrower or Delta Petroleum Corporation, as applicable, is recommended by at least 66-2/3% of the then Continuing Directors or, in the case of Borrower, such other director receives the vote of the Permitted Investors in his or her election by the shareholders of Borrower or Delta Petroleum Corporation, as applicable.

     Contractual Obligation: with respect to any Person, any term, condition or provision of any security issued by such Person or of any agreement, instrument or other undertaking to which such Person is a party or by which it or any of its Property is bound.

     Control Investment Affiliate: with respect to any Person, any other Person that (a) directly or indirectly, is in control of, is controlled by, or is under common control with, such Person and (b) is organized by such Person primarily for the purpose of making equity or debt investments in one or more companies. For purposes of this definition, “control” of a Person means the power, directly or indirectly, to direct or cause the direction of the management and policies of such Person, whether by contract or otherwise.

     Loan Parties: Borrower and each Guarantor.

     Current Ratio: as of any date of determination, the ratio of (a) Consolidated Current Assets at such date to (b) Consolidated Current Liabilities at such date.

     Daywork Drilling Contracts: collectively, those certain operating contracts for utilization of the Rigs entered into by Borrower which have a primary term of greater than six months, together with any amendments thereto, shall be in form and substance acceptable to the Lenders.

     Default: any of the events specified in Article VII, whether or not any requirement for the giving of notice, the lapse of time, or both, has been satisfied.

     Default Rate: as defined in Section 2.8(b).

     Defensible Title: good and indefeasible title, free and clear of all Liens other than Permitted Liens.

     Deposit Account Control Agreement: a Deposit Account Control Agreement to be executed and delivered among any Loan Party, the Administrative Agent and each bank at which such Loan Party maintains any bank account, in each case, substantially in the form of Exhibit D or such other form as may be acceptable to the Administrative Agent in its sole discretion, as the same may be amended, restated, replaced, supplemented or otherwise modified from time to time.

     Derivatives Counterparty: as defined in Section 6.6.

     Disposition: with respect to any Property, any sale, lease, Sale and Leaseback Transaction, assignment, conveyance, transfer or other disposition (including by way of a merger or consolidation) of such Property or any interest therein (excluding the creation of any Permitted Lien on such Property but including the sale or factoring at maturity or collection of any accounts or permitting or suffering any other Person to acquire any interest (other than a Permitted Lien) in such Property) or the entering into

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any agreement to do any of the foregoing; and the terms “Dispose” and “Disposed of” shall have correlative meanings.

     Disqualified Stock: as to any Person, any Capital Stock of such Person that by its terms (or by the terms of any security into which it is convertible or for which it is exchangeable) or otherwise (including upon the occurrence of an event) requires the payment of dividends (other than dividends payable solely in Capital Stock which does not otherwise constitute Disqualified Stock) or matures or is required to be redeemed (pursuant to any sinking fund obligation or otherwise) or is convertible into or exchangeable for Indebtedness or is redeemable at the option of the holder thereof, in whole or in part, at any time on or prior to the date six months after the Maturity Date.

     Dollars and $: lawful currency of the United States of America.

     Drilling Rig Assets: as defined in Section 3.23.

     Environmental Laws: any and all applicable laws, rules, orders, regulations, statutes, ordinances, codes, decrees or other legally enforceable requirements (including common law) of any Governmental Authority regulating, relating to or imposing liability or standards of conduct concerning pollution, protection of the environment, natural resources or of human health, or employee health and safety, as has been, is now, or may at any time hereafter be, in effect, including the Comprehensive Environmental Response, Compensation and Liability Act, 42 U.S.C. § 9601 et seq., the Hazardous Materials Transportation Act, 49 U.S.C. § 5101 et seq., the Resource Conservation and Recovery Act, 42 U.S.C. § 6901 et seq., the Clean Water Act, 33 U.S.C. § 1251 et seq., the Clean Air Act, 42 U.S.C. § 7401 et seq., the Toxic Substances Control Act, 15 U.S.C. § 2601 et seq., the Federal Insecticide, Fungicide, and Rodenticide Act, 7 U.S.C. § 136 et seq., the Oil Pollution Act of 1990, 33 U.S.C. § 2701 et seq., the Occupational Safety and Health Act, 29 U.S.C. § 651 et seq., and the regulations promulgated pursuant thereto, and all analogous state or local statutes and regulations.

     Environmental Permits: any and all permits, licenses, approvals, registrations, notifications, exemptions and other authorizations required or obtained under any Environmental Law.

     ERISA: the Employee Retirement Income Security Act of 1974, as amended from time to time and the rules and regulations promulgated thereunder.

     Event of Default: any of the events specified in Article VII; provided that any requirement for the giving of notice, the lapse of time, or both, has been satisfied.

     Excess Cash Flow: with respect to Borrower for any period, the Consolidated EBITDA of Borrower for such period plus (a) the excess, if any, of the Consolidated Working Capital at the beginning of such period over the Consolidated Working Capital at the end of such period minus (b) the sum of (without duplication) (i) scheduled and mandatory cash principal payments on the Loans during such period and optional cash principal payments on the Loans during such period, (ii) scheduled cash principal payments made by Borrower or any of its Subsidiaries during such period on other Indebtedness to the extent such other Indebtedness and payments are permitted by this Agreement, (iii) scheduled payments made by Borrower or any of its Subsidiaries on Capital Lease Obligations to the extent such Capital Lease Obligations and payments are permitted by this Agreement, (iv) Capital Expenditures made by Borrower or any of its Subsidiaries during such period to the extent permitted by this Agreement, (v) the excess, if any, of the Consolidated Working Capital at the end of such period over the Consolidated Working Capital at the beginning of such period, (vi) expenditures made with any portion of the Reinvestment Deferred Amount and (vii) Consolidated Interest Expense for such period.

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     Exchange Act: the Securities Exchange Act of 1934, as amended.

     Existing Credit Agreement: as defined in the recitals hereto.

     Existing Credit Documents: the Existing Credit Agreement, together with all other agreements, instruments, financing statements or other documents executed or delivered thereunder.

     Existing Indebtedness: all Indebtedness outstanding under the Existing Credit Documents.

     Federal Funds Effective Rate: for any day, the weighted average of the rates on overnight federal funds transactions with members of the Federal Reserve System arranged by federal funds brokers, as published on the next succeeding Business Day by the Federal Reserve Bank of New York, or, if such rate is not so published for any day which is a Business Day, the average of the quotations for the day of such transactions received by the Administrative Agent from three federal funds brokers of recognized standing selected by the Administrative Agent.

     Fee Letter: that certain Letter Agreement, dated as of December 14, 2007, among Borrower, Lehman Brothers Inc. and Lehman Commercial Paper Inc.

     Funding Office: the office specified from time to time by the Administrative Agent as its funding office by notice to Borrower and the Lenders.

     GAAP: generally accepted accounting principles in the United States of America as in effect from time to time, applied in a manner consistent with that used in preparation of the Pro Forma Balance Sheet.

     Governmental Authority: any nation or government, any state or other political subdivision thereof and any entity exercising executive, legislative, judicial, taxing, regulatory or administrative functions of or pertaining to government, any province, commonwealth, territory, possession, county, parish, town, township, village or municipality, whether now existing or hereafter constituted or existing.

     Granting Lender: as defined in Section 9.6(g).

     Guarantee and Security Agreement: the Guarantee and Security Agreement to be executed and delivered by Holdings, Borrower and each Subsidiary of Borrower and the Administrative Agent, substantially in the form of Exhibit E, as the same may be amended, restated, replaced, supplemented or otherwise modified from time to time.

     Guarantee Obligation: as to any Person (the “guaranteeing person”), any obligation of (a) the guaranteeing person or (b) another Person (including any bank under any letter of credit), if to induce the creation of such obligation of such other Person, the guaranteeing person has issued a reimbursement, counterindemnity or similar obligation, in either case guaranteeing or in effect guaranteeing any Indebtedness, leases, dividends or other obligations (the “primary obligations”) of any other third Person (the “primary obligor”) in any manner, whether directly or indirectly, including any obligation of the guaranteeing person, whether or not contingent, (w) to purchase any such primary obligation or any Property constituting direct or indirect security therefor, (x) to advance or supply funds (i) for the purchase or payment of any such primary obligation or (ii) to maintain working capital or equity capital of the primary obligor or otherwise to maintain the net worth or solvency of the primary obligor, (y) to purchase Property, securities or services, in each case, primarily for the purpose of assuring the owner of any such primary obligation of the ability of the primary obligor to make payment of such primary obligation or (z) otherwise to assure or hold harmless the owner of any such primary obligation against

9

loss in respect thereof; provided that the term Guarantee Obligation shall not include endorsements of instruments for deposit or collection in the ordinary course of business. The amount of any Guarantee Obligation of any guaranteeing person shall be deemed to be the lower of (I) an amount equal to the stated or determinable amount of the primary obligation in respect of which such Guarantee Obligation is made and (II) the maximum amount for which such guaranteeing person may be liable pursuant to the terms of the instrument embodying such Guarantee Obligation, unless such primary obligation and the maximum amount for which such guaranteeing person may be liable are not stated or determinable, in which case the amount of such Guarantee Obligation shall be such guaranteeing person’s maximum reasonably anticipated liability in respect thereof as determined by Borrower in good faith.

     Guarantor: each Person who is a party as a “Guarantor” and “Grantor” to a Guarantee and Security Agreement.

     Hedging Agreement: with respect to any Person, any agreement or arrangement, or any combination thereof, consisting of interest rate or currency swaps, caps or collar agreements, foreign exchange agreements, commodity contracts or similar arrangements entered into by such Person providing for protection against fluctuations in interest rates, currency exchange rates or the exchange of nominal interest obligations, either generally or under specific contingencies.

     Indebtedness: of any Person at any date, without duplication (a) all indebtedness of such Person for borrowed money, (b) all obligations of such Person for the deferred purchase price of Property or services, (c) all obligations of such Person evidenced by notes, bonds, debentures or other similar instruments, (d) all indebtedness created or arising under any conditional sale or other title retention agreement with respect to Property acquired by such Person (even though the rights and remedies of the seller or lender under such agreement in the event of default are limited to repossession or sale of such Property), (e) all Capital Lease Obligations of such Person, (f) all obligations of such Person, contingent or otherwise, as an account party or applicant under acceptance, letter of credit or similar facilities, (g) all obligations of such Person, contingent or otherwise, to purchase, redeem, retire or otherwise acquire for value any Capital Stock of such Person, (h) all Guarantee Obligations of such Person in respect of obligations of the kind referred to in clauses (a) through (g) above; and (i) all obligations of the kind referred to in clauses (a) through (h) above secured by (or for which the holder of such obligation has an existing right, contingent or otherwise, to be secured by) any Lien on Property (including accounts and contract rights) owned by such Person, whether or not such Person has assumed or become liable for the payment of such obligation. The Indebtedness of a Person shall include the Indebtedness of any other Person (including any partnership in which such Person is a general partner) to the extent such Person is liable therefor as a result of such Person’s ownership interest in or other relationship with such entity, except to the extent the terms of such Indebtedness expressly provide that such Person is not liable therefor.

     Indemnified Liabilities: as defined in Section 9.5.

     Indemnitee: as defined in Section 9.5.

     Independent Accountant: KPMG LLP or such other independent certified public accountants reasonably acceptable to the Administrative Agent.

     Insolvency: with respect to any Multiemployer Plan, the condition that such Benefit Plan is insolvent within the meaning of Section 4245 of ERISA.

     Insolvent: pertaining to a condition of Insolvency.

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     Intellectual Property: the collective reference to all rights, priorities and privileges relating to intellectual property, whether arising under United States, state, multinational or foreign laws or otherwise, including, copyrights, copyright licenses, patents, patent licenses, trademarks, trademark licenses, service-marks, technology, know-how and processes, licenses or rights to use databases, geological data, geophysical data, engineering data, seismic data, maps, interpretations and other technical information, recipes, formulas, trade secrets and all rights to sue at law or in equity for any infringement or other impairment thereof, including the right to receive all proceeds and damages therefrom.

     Interest Margin: 5.50%.

     Interest Payment Date: (a) the first Business Day immediately following the end of each calendar quarter, commencing with March 31, 2008 and the Maturity Date and (b) the date of any repayment or prepayment made with respect to any Loan.

     Interest Rate: subject to Section 2.10, for each LIBOR Period, a rate per annum equal to the LIBOR Rate plus the Interest Margin.

     Investment: for any Person (a) the acquisition (whether for cash, Property of such Person, services or securities or otherwise) of Capital Stock, bonds, notes, debentures, debt securities, partnership or other ownership interests or other securities of, or any Property constituting an ongoing business of, or the making of any capital contribution to, any other Person or any agreement to make any such acquisition or capital contribution, (b) the making of any deposit with, or advance, loan or other extension of credit to, any other Person (including the purchase of Property from another Person subject to an understanding or agreement, contingent or otherwise, to resell such Property to such Person, but excluding any such advance, loan or extension of credit having a term not exceeding 90 days representing the purchase price of inventory or supplies sold in the ordinary course of business), (c) the entering into of any Guarantee of, or other contingent obligation with respect to, Indebtedness or other liability of any other Person, and (d) any other investment that would be classified as such on a balance sheet of such Person in accordance with GAAP.

     Lehman Entity: any of Lehman Commercial Paper Inc. or any of its Affiliates.

     Lenders: as defined in the preamble hereto.

     LIBOR Business Day: a Business Day on which banks in the city of London, England are generally open for dealings in Dollar deposits in the London interbank market.

     LIBOR Period: each period commencing on a LIBOR Business Day and ending on the first LIBOR Business Day of the month beginning three months thereafter; provided that the first LIBOR Period shall begin on the Closing Date and end on April 1, 2008, and each successive LIBOR Period shall begin on the last LIBOR Business Day of the immediately preceding LIBOR Period.

     LIBOR Rate: for each LIBOR Period, a rate of interest determined by the Administrative Agent equal to:

     (a) the offered rate for deposits in United States Dollars for the applicable LIBOR Period that appears on Telerate Page 3750 (or any successor thereto) as of 11:00 a.m. (London time) on the second full LIBOR Business Day preceding the first day of each LIBOR Period (unless such date is not a Business Day, in which event the next succeeding Business Day will be used); divided by

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     (b) a number equal to 1.0 minus the aggregate (but without duplication) of the rates (expressed as a decimal fraction) of reserve requirements in effect on the day that is two LIBOR Business Days prior to the beginning of such LIBOR Period (including basic, supplemental, marginal and emergency reserves under any regulations of the Board or other Governmental Authority having jurisdiction with respect thereto, as now and from time to time in effect) for Eurocurrency funding (currently referred to as “Eurocurrency Liabilities” in Regulation D of the Board) that are required to be maintained by a member bank of the Federal Reserve System.

     If such interest rates shall cease to be available from Telerate News Service, the LIBOR Rate shall be determined from such comparable publicly available financial reporting service for displaying Eurodollar rates as shall be selected by the Administrative Agent.

     Lien: any mortgage, pledge, hypothecation, assignment, deposit arrangement, encumbrance, lien (statutory or other), charge or other security interest or any preference, priority or other security agreement or preferential arrangement of any kind or nature whatsoever intended to assure payment or performance of any Indebtedness or other obligation (including any conditional sale or other title retention agreement, the interest of a lessor under a Capital Lease, any financing lease having substantially the same economic effect as any of the foregoing and the filing of any financing statement under the UCC or comparable law of any jurisdiction naming the owner of the asset to which such Lien relates as debtor).

     Loans: as defined in Section 2.1.

     Loan Documents: this Agreement, the Commitment Letter, the Fee Letter, the Security Documents, the Notes and each certificate, agreement, waiver, consent or document executed by a Loan Party and delivered to the Administrative Agent or any Lender in connection with or pursuant to any of the foregoing.

     Loan Parties: Holdings, Borrower and each Subsidiary of Borrower.

     Management Investors: collectively, Bill Sauer, Jr. and Gregg Tubbs.

     Material Adverse Effect: a material adverse effect on any of (a) the business, assets, property, condition (financial or otherwise) or prospects of the Loan Parties taken as a whole, (b) the value of the Collateral (except when such value is affected by then-current market conditions), (c) the legality, validity or enforceability of this Agreement or any of the other Loan Documents or the rights or remedies of the Agents or the Lenders hereunder or thereunder, (d) the perfection or priority of the Liens granted pursuant to the Security Documents or (e) the ability of Borrower to repay the Obligations or of the Loan Parties to perform their obligations under the Loan Documents.

     Material Environmental Amount: an amount or amounts payable or reasonably likely to become payable by any Loan Party or any of its Subsidiaries, in the aggregate in excess of $100,000, for costs to comply with or any liability under any Environmental Law, failure to obtain or comply with any Environmental Permit, costs of any investigation, and any remediation, of any Material of Environmental Concern, and any other cost or liability, including compensatory damages (including damages to natural resources), punitive damages, fines, and penalties pursuant to any Environmental Law.

     Materials of Environmental Concern: any gasoline or petroleum (including crude oil or any fraction thereof) or petroleum products, polychlorinated biphenyls, natural gas or natural gas products, mercury, hydrogen sulfide, drilling fluids, produced water, asbestos, pollutants, contaminants, radioactivity, and any other substances or forces of any kind, whether or not any such substance or force

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is defined as hazardous or toxic under any Environmental Law, that is regulated pursuant to or could give rise to liability under any Environmental Law.

     Maturity Date: as defined in Section 2.3.

     Moody’s: Moody’s Investors Service, Inc.

     Mortgaged Properties: the Real Property listed on Schedule 1.2, together with any additional Real Properties which Borrower or any Subsidiary may hereafter acquire, in each case as to which the Administrative Agent for the benefit of the Secured Parties shall be granted a Lien pursuant to one or more Mortgages.

     Mortgages: each of the mortgages and deeds of trust, if any, made by any Loan Party in favor of, or for the benefit of, the Administrative Agent for the benefit of the Secured Parties, in each case, in form and substance acceptable to the Administrative Agent, as the same may be amended, restated, replaced, supplemented or otherwise modified from time to time.

     Multiemployer Plan: a Benefit Plan that is a multiemployer plan as defined in Section 4001(a)(3) of ERISA.

     Net Cash Proceeds: (a) in connection with any Asset Sale or any Recovery Event, the proceeds thereof in the form of cash and Cash Equivalents (including any such proceeds received by way of deferred payment of principal pursuant to a note or installment receivable or purchase price adjustment receivable or otherwise, but only as and when received) of such Asset Sale or Recovery Event, net of (i) amounts required to be applied to the repayment of Indebtedness secured by a Lien expressly permitted hereunder on any asset that is the subject of such Asset Sale or Recovery Event (other than any Lien pursuant to a Security Document), (ii) in the case of an Asset Sale, attorneys’ fees, accountants’ fees, investment bank fees and other reasonable and customary fees and expenses actually incurred in connection therewith and (iii) taxes paid or reasonably estimated to be payable as a result thereof (after taking into account any available tax credits or deductions and any tax sharing arrangements); provided that the evidence of each of (i), (ii) and (iii) is provided to the Administrative Agent in form and substance reasonably satisfactory to it, and (b) in connection with any issuance or sale of Capital Stock or debt securities or instruments or the incurrence of Indebtedness for borrowed money, the cash proceeds received from such issuance, sale or incurrence, net of attorneys’ fees, investment banking fees, accountants’ fees, underwriting discounts and commissions and other reasonable and customary fees and expenses actually incurred in connection therewith; provided, that in the case of this clause (b), evidence of such costs is provided to the Administrative Agent in form and substance reasonably satisfactory to it.

     Non-Excluded Taxes: as defined in Section 2.11(a).

     Non-U.S. Lender: as defined in Section 2.11(d).

     Notes: as defined in Section 2.4(e).

     Obligations: the unpaid principal of and interest on (including, interest accruing after the maturity of the Loans and interest accruing after the filing of any petition in bankruptcy, or the commencement of any insolvency, reorganization or like proceeding, relating to any Loan Party, whether or not a claim for post-filing or post-petition interest is allowed in such proceeding) the Loans and all other obligations and liabilities of any Loan Party to the Administrative Agent or to any Lender, whether direct or indirect, absolute or contingent, due or to become due, or now existing or hereafter incurred, which may arise under, out of, or in connection with, this Agreement, any other Loan Document or any

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other document made, delivered or given in connection herewith or therewith, whether on account of principal, interest, fees, reimbursement obligations, indemnities, costs, expenses (including, all fees, charges and disbursements of counsel to the Administrative Agent or to any Lender that are required to be paid by any Loan Party pursuant hereto) or otherwise.

     Other Taxes: any and all present or future stamp or documentary taxes or any other excise or property taxes, charges or similar levies arising from any payment made hereunder or from the execution, delivery or enforcement of, or otherwise with respect to, this Agreement or any other Loan Document.

     Participant: as defined in Section 9.6(b).

     Patriot Act: as defined in Section 9.18.

     Payment Office: the office specified from time to time by the Administrative Agent as its payment office by notice to Borrower and the Lenders.

     PBGC: the Pension Benefit Guaranty Corporation established pursuant to Subtitle A of Title IV of ERISA (or any successor).

     Permits: the collective reference to (i) Environmental Permits, and (ii) any and all other franchises, licenses, leases, permits, approvals, consents, notifications, certifications, registrations, authorizations, exemptions, variances, qualifications, easements and rights of way of any Governmental Authority or third party.

     Permitted Capital Expenditures: as defined in Section 6.7.

     Permitted Capex Amount: as defined in Section 6.7.

     Permitted Equity Financing: any sale or issuance of the Capital Stock of Holdings for cash not resulting in a Change of Control and any cash contribution to the capital of Holdings by a Permitted Investor, in each case, (i) the sole purposes of which is to fund Capital Expenditures by Borrower or any Subsidiary Guarantor within the fiscal quarter in which such sale, issuance or contribution is made and (ii) the net proceeds of which Holdings contributes in full to Borrower concurrently with the consummation of such sale, issuance of contribution.

     Permitted Indebtedness: as defined in Section 6.2.

     Permitted Investors: the collective reference to Delta Petroleum Corporation, Chesapeake Energy Corporation and the Management Investors.

     Permitted Liens: the collective reference to (i) in the case of Collateral other than Pledged Stock, Liens permitted by Section 6.3 and (ii) in the case of Collateral consisting of Pledged Stock, non-consensual Liens permitted by Section 6.3 to the extent arising by operation of law.

     Person: an individual, partnership, corporation, limited liability company, business trust, joint stock company, trust, unincorporated association, joint venture, Governmental Authority or other entity of whatever nature.

     Pledged Stock: as defined in the Guarantee and Security Agreement.

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     Prepayment Date: (a) with respect to any mandatory prepayment pursuant to Section 2.7, the date of such mandatory prepayment and (b) with respect to any optional prepayment pursuant to Section 2.6, the date of such optional prepayment.

     Pro Forma Balance Sheet: as defined in Section 3.1(a).

     Projections: as defined in Section 5.3(c).

     Property: any right or interest in or to property of any kind whatsoever, whether real, personal or mixed and whether tangible or intangible.

     Purchase Price Refund: any amount received by any Loan Party after the Closing Date as a result of a purchase price adjustment or similar event in connection with any acquisition of Property by such Loan Party.

     Qualified Investment: expenditures incurred (i) to acquire or repair similar assets owned (or to be owned) by Borrower or any Wholly Owned Subsidiary Guarantor of the same type as those subject to such Reinvestment Event or equipment (or to be owned) by and useful in the business of Borrower or any Wholly Owned Subsidiary Guarantor or (ii) to reimburse Borrower or such Wholly Owned Subsidiary Guarantor for amounts paid from the operating cash flow of such Person in advance of the receipt of Net Cash Proceeds with respect to any Recovery Event in order to repair or replace the assets of Borrower or any Wholly Owned Subsidiary Guarantor that have been damaged, destroyed or lost as a result of any casualty event or condemnation; provided that Borrower or such Wholly Owned Subsidiary Guarantor shall not be reimbursed in an amount exceeding the Net Cash Proceeds actually received in connection with such Recovery Event.

     Real Property: the surface, subsurface and mineral rights, buildings and interests and any appurtenances thereto owned, leased or otherwise held by any Loan Party or its Subsidiaries.

     Recovery Event: any settlement of or payment in respect of any property or casualty insurance claim or any condemnation proceeding (or proceeding in lieu thereof) relating to any asset of any Loan Party.

     Register: as defined in Section 9.6(d).

     Regulation U: Regulation U of the Board as in effect from time to time.

     Reinvestment Deferred Amount: with respect to any Reinvestment Event, the aggregate Net Cash Proceeds received by any Loan Party in connection therewith that are duly specified in a Reinvestment Notice as not being required to be initially applied to prepay the Loans pursuant to Section 2.7(b) as a result of the delivery of a Reinvestment Notice.

     Reinvestment Event: any Asset Sale, Purchase Price Refund or Recovery Event in respect of which Borrower has delivered a Reinvestment Notice.

     Reinvestment Notice: a written notice executed by a Responsible Officer stating that no Default or Event of Default has occurred and is continuing and stating that Borrower (directly or indirectly through a Wholly Owned Subsidiary Guarantor) intends and expects to use all or a specified portion of the Net Cash Proceeds of a Reinvestment Event specified in such notice to make a Qualified Investment.

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     Reinvestment Prepayment Amount: with respect to any Reinvestment Event, the Reinvestment Deferred Amount relating thereto less the portion, if any, thereof expended prior to the relevant Reinvestment Prepayment Date to make a Qualified Investment.

     Reinvestment Prepayment Date: with respect to any Reinvestment Event, the earlier of (a) the date occurring six months after such Reinvestment Event and (b) the date on which Borrower shall have determined not to, or shall have otherwise ceased to, make a Qualified Investment with all or any portion of the relevant Reinvestment Deferred Amount.

     Related Fund: with respect to any Lender, any fund that (a) invests in commercial loans and (b) is managed or advised by the same investment advisor as such Lender, by such Lender or an Affiliate of such Lender.

     Reorganization: with respect to any Multiemployer Plan, the condition that such Benefit Plan is in reorganization within the meaning of Section 4241 of ERISA.

     Reportable Event: any of the events set forth in Section 4043(c) of ERISA, other than those events as to which the thirty day notice period is waived under subsections .27, .28, .29, .30, .31, .32, .34 or .35 of PBGC Reg. § 4043.

     Required Lenders: at any time, Lenders having Aggregate Exposure Percentages of more than 66 2/3%.

     Requirement of Law: as to any Person, the Constituent Documents of such Person, and any law, treaty, rule or regulation or determination of an arbitrator or a court or other Governmental Authority, in each case applicable to or binding upon such Person or any of its Property or to which such Person or any of its Property is subject.

     Responsible Officer: as to any Loan Party, the chief executive officer, president or chief financial officer of such Loan Party, but in any event, with respect to financial matters, the chief financial officer of such Loan Party. Unless otherwise qualified, all references to a “Responsible Officer” shall refer to a Responsible Officer of Borrower.

     Restricted Payments: as defined in Section 6.6.

     Rig: any of the land-based drilling and workover rigs owned by any Loan Party.

     Rig Appraisal: a written appraisal in form, content and detail reasonably satisfactory to the Administrative Agent prepared by an Approved Appraiser.

     Rig Accessories: all pumps, drilling equipment, machinery, equipment and parts.

     Rig Asset Value: the “as is, where is” six month, orderly liquidation value of the Drilling Rig Assets.

     S&P: Standard & Poor’s Ratings Services, a division of McGraw-Hill Companies, Inc.

     Sale and Leaseback Transaction: any sale or other transfer of Property by any Person with the intent of such Person or an Affiliate thereof to lease such Property as lessee.

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     SEC: the Securities and Exchange Commission (or successor thereto or an analogous Governmental Authority).

     Secured Parties: collectively, the Administrative Agent and any Lender.

     Security Documents: the collective reference to the Guarantee and Security Agreement, the Mortgages, each Deposit Account Control Agreement, each Access Agreement and all other security documents hereafter delivered to the Administrative Agent granting a Lien on any Property of any Person to secure any of the Obligations.

     Single Employer Plan: any Benefit Plan that is covered by Title IV of ERISA, but which is not a Multiemployer Plan.

     Solvency Certificate: a solvency certificate and analysis by the chief financial officer of Borrower substantially in the form of Exhibit F.

     Solvent: with respect to any Person, as of any date of determination, (a) the amount of the “present fair saleable value” of the assets of such Person will, as of such date, exceed the amount of all “liabilities of such Person, contingent or otherwise”, as of such date, as such quoted terms are determined in accordance with applicable federal and state laws governing determinations of the insolvency of debtors, (b) the present fair saleable value of the assets of such Person will, as of such date, be greater than the amount that will be required to pay the liability of such Person on its debts as such debts become absolute and matured, (c) such Person will not have, as of such date, an unreasonably small amount of capital with which to conduct its business, (d) such Person will be able to pay its debts as they mature and (e) such Person is not insolvent within the meaning of any applicable Requirement of Law. For purposes of this definition, (i) “debt” means liability on a “claim”, and (ii) “claim” means any (x) right to payment, whether or not such a right is reduced to judgment, liquidated, unliquidated, fixed, contingent, matured, unmatured, disputed, undisputed, legal, equitable, secured or unsecured or (y) right to an equitable remedy for breach of performance if such breach gives rise to a right to payment, whether or not such right to an equitable remedy is reduced to judgment, fixed, contingent, matured or unmatured, disputed, undisputed, secured or unsecured.

     SPC: as defined in Section 9.6(g).

     Specified Vehicles: is defined in the Guarantee and Security Agreement.

     Subsidiary: as to any Person, a corporation, partnership, limited liability company or other entity of which shares of Capital Stock having ordinary voting power (other than stock or such other ownership interests having such power only by reason of the happening of a contingency) to elect a majority of the board of directors or other managers of such corporation, partnership, limited liability company or other entity are at the time owned, or the management of which is otherwise controlled, in each case, directly or indirectly through one or more intermediaries, or both, by such Person. Unless otherwise qualified, all references to a “Subsidiary” or to “Subsidiaries” in this Agreement shall refer to a Subsidiary or Subsidiaries of Borrower.

     Subsidiary Guarantor: each Subsidiary of Borrower that is a Guarantor.

     Tax Affiliate: with respect to any Person, (a) any Subsidiary of such Person, and (b) any Affiliate of such Person with which such Person files or is eligible to file consolidated, combined or unitary tax returns.

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     Tax Return: as defined in Section 3.11.

     Transferee: as defined in Section 9.14.

     UCC: the Uniform Commercial Code, as in effect from time to time in the State of New York or other applicable jurisdiction.

     Wholly Owned Subsidiary: as to any Person, any other Person all of the Capital Stock of which (other than directors’ qualifying shares required by law) is owned by such Person directly and/or through other Wholly Owned Subsidiaries.

     Wholly Owned Subsidiary Guarantor: any Subsidiary Guarantor that is a Wholly Owned Subsidiary of Borrower.

     1.2 Other Definitional Provisions.

     (a) Unless otherwise specified therein, all terms defined in this Agreement shall have the defined meanings when used in the other Loan Documents or any certificate or other document made or delivered pursuant hereto or thereto.

     (b) As used herein and in the other Loan Documents, and any certificate or other document made or delivered pursuant hereto or thereto, accounting terms relating to Borrower and its Subsidiaries not defined in Section 1.1 and accounting terms partly defined in Section 1.1, to the extent not defined, shall have the respective meanings given to them under GAAP; provided that for purposes of Section 6.1, any non-cash items arising under FAS 133, 142, 143 or 144 shall be excluded from the relevant calculation.

     (c) The words “hereof”, “herein” and “hereunder” and words of similar import when used in this Agreement shall refer to this Agreement as a whole and not to any particular provision of this Agreement, and Section, Schedule and Exhibit references are to this Agreement unless otherwise specified.

     (d) The meanings given to terms defined herein shall be equally applicable to both the singular and plural forms of such terms.

     (e) All calculations of financial ratios set forth in Section 6.1 shall be calculated to the same number of decimal places as the relevant ratios are expressed in and shall be rounded upward if the number in the decimal place immediately following the last calculated decimal place is five or greater. For example, if the relevant ratio is to be calculated to the hundredth decimal place and the calculation of the ratio is 5.126, the ratio will be rounded up to 5.13.

     (f) Each agreement defined in this Agreement shall include all appendices, exhibits and schedules thereto, and references thereto shall be to such agreement as amended, restated, replaced, supplemented or otherwise modified; provided that if the prior written consent of the Required Lenders is required hereunder for an amendment, restatement, replacement, supplement or other modification to any such agreement and such consent is obtained, references in this Agreement to such agreement shall be to such agreement as so amended, restated, replaced, supplemented or modified.

     (g) References in this Agreement to any statute shall be to such statute as amended or modified and in effect at the time any such reference is operative.

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     (h) The term “including” when used in any Loan Document means “including without limitation” except when used in the computation of time periods.

     (i) The term “or” has, except where otherwise indicated, the inclusive meaning represented by the phrase “and/or”.

     (j) The terms “Lender” and “Administrative Agent” include their respective successors.

     (k) The words “asset” and “property” shall be construed to have the same meaning and effect and to refer to any and all tangible and intangible assets and properties, including cash, Capital Stock, securities (as such term is defined in the Securities Act), revenues, accounts, leasehold interests and contract rights.

     (l) Each reference to “Loan Party” in Article III shall include any Subsidiary of Borrower that is or, pursuant to Section 5.10 or Section 6.17, is required to be a Guarantor.

     1.3 Computation of Time Periods. In this Agreement, in the computation of periods of time from a specified date to a later specified date, the word “from” means “from and including” and the words “to” and “until” each mean “to but excluding” and the word “through” means “to and including.”

ARTICLE II
AMOUNT AND TERMS OF COMMITMENTS

     2.1 Loan Commitments. Subject to the terms and conditions hereof, each of the Lenders severally agrees to make loans (each, a “Loan”) to Borrower on the Closing Date in an aggregate principal amount not to exceed such Lender’s Commitment. Once borrowed or repaid, the Loans may not be reborrowed and any Commitment, once terminated or reduced, may not be reinstated. The Commitment shall automatically and without notice be reduced to zero immediately after the funding of the Loans on the Closing Date.

     2.2 Procedures for Borrowing.

     (a) Borrower shall deliver to the Administrative Agent a Borrowing Notice (which Borrowing Notice must be received by the Administrative Agent prior to 10:00 A.M., New York City time, one Business Day prior to the anticipated borrowing date) requesting that the Lenders make the Loans on the Borrowing Date and specifying the amount to be borrowed. Upon receipt of such Borrowing Notice the Administrative Agent shall promptly notify each Lender thereof. Not later than 12:00 Noon, New York City time, on the Borrowing Date for the Loans specified hereunder, each Lender shall make available to the Administrative Agent at the Funding Office an amount in immediately available funds equal to the Loan to be made by such Lender. The Administrative Agent shall make available to Borrower the aggregate of the amounts made available to the Administrative Agent by the Lenders, in like funds as received by the Administrative Agent.

     (b) The Borrower shall not deliver a Borrowing Notice, and no Lender shall be under any obligation to make available any funds, for Loans in an aggregate amount for all Lenders less than $75,000,000.

     2.3 Maturity Date. The Loans of each Lender shall mature on December 31, 2010 (the “Maturity Date”).

     2.4 Repayment of Loans; Evidence of Debt.

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     (a) Borrower hereby unconditionally promises to pay to the Administrative Agent for the account of the appropriate Lender the entire principal amount of each Loan of such Lender on the Maturity Date or on such earlier date on which the Loans become due and payable pursuant to Sections 2.6 or 2.7 or Article VII. Borrower hereby further agrees to pay interest on the unpaid principal amount of the Loans from time to time outstanding from the date hereof until payment in full thereof at the rates per annum, and on the dates, set forth in Section 2.8.

     (b) Each Lender shall maintain in accordance with its usual practice an account or accounts evidencing Indebtedness of Borrower to such Lender resulting from each Loan of such Lender from time to time, including the amounts of principal and interest payable and paid to such Lender from time to time under this Agreement.

     (c) The Administrative Agent, on behalf of Borrower, shall maintain the Register pursuant to Section 9.6(d), and a subaccount therein for each Lender, in which shall be recorded (i) the amount of each Loan made hereunder and any Note evidencing such Loan, (ii) the amount of any principal or interest due and payable or to become due and payable from Borrower to each Lender hereunder and (iii) both the amount of any sum received by the Administrative Agent hereunder from Borrower and each Lender’s share thereof.

     (d) The entries made in the Register and the accounts of each Lender maintained pursuant to this Section 2.4 shall, to the extent permitted by applicable law, be prima facie evidence of the existence and amounts of the obligations of Borrower therein recorded; provided, however, that the failure of any Lender or the Administrative Agent to maintain the Register or any such account, or any error therein, shall not in any manner affect the obligation of Borrower to repay (with applicable interest) the Loans made to Borrower by such Lender in accordance with the terms of this Agreement.

     (e) Borrower agrees that, upon the request to the Administrative Agent by any Lender, Borrower will promptly execute and deliver to such Lender a promissory note of Borrower evidencing any Loans of such Lender, substantially in the form of Exhibit G (a “Note”), with appropriate insertions as to date and principal amount; provided that delivery of Notes shall not be a condition precedent to the occurrence of the Closing Date or the making of the Loans on any Borrowing Date.

     2.5 Fees.

     (a) On the Closing Date, Borrower shall pay the Administrative Agent for the account of each Lender a fee equal to 1.0% of the aggregate principal amount of the Loan made by such Lender.

     (b) On the first anniversary of the Closing Date, Borrower shall pay the Administrative Agent for the account of the Lenders as of such first anniversary a fee equal to 0.50% of the aggregate principal amount of the Loans made by the Lenders on the Closing Date, which fee shall be fully earned on the Closing Date.

     (c) Borrower shall pay to the Administrative Agent for its own account an annual nonrefundable administration fee equal to $50,000, such fee to be paid in advance on the Closing Date and thereafter on each anniversary of the Closing Date (other than the Maturity Date) or, if any such date is not a Business Day, on the first Business Day thereafter.

     (d) Borrower agrees to pay to the Administrative Agent the fees in the amounts and on the dates from time to time agreed to in writing by Borrower and the Administrative Agent.

     2.6 Optional Prepayments.

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     (a) Subject to the concurrent payment of the Applicable Premium, Borrower may, upon at least three Business Days’ prior notice to the Administrative Agent stating the Prepayment Date and aggregate principal amount of the prepayment, prepay on any date the outstanding principal amount of the Loans, in whole or in part, at Borrower’s option at 100% of the principal amount thereof, together with accrued interest through the Prepayment Date on the principal amount prepaid, in accordance with the provisions of this Agreement.

     (b) For purposes hereof, the “Applicable Premium” shall be a cash amount equal to the percentages of principal amount of the Loans being prepaid set forth below:

If prepaid on or prior to December 31, 2008	1.0	%
If prepaid at any time after December 31, 2008	0.0	%

     (c) Each partial prepayment shall be in an aggregate amount not less than $1,000,000 or integral multiples of $100,000 in excess thereof, and any such prepayment must be accompanied by payment of Agent’s and each Lender’s reasonable out-of-pocket expenses and payment of any LIBOR funding breakage costs in accordance with Section 2.12. Upon the giving of such notice of prepayment, the principal amount of the Loans specified to be prepaid and at the applicable price specified therefor, together with the accrued interest through the Prepayment Date and, if applicable, the Applicable Premium, shall become due and payable on the Prepayment Date.

     (d) Upon the giving of any such notice of prepayment, the principal amount of the Loans specified to be prepaid, together with the accrued interest thereon through the Prepayment Date shall become due and payable on the Prepayment Date.

     (e) Any optional prepayment under this Section 2.6 shall be applied to the Loans as set forth in Section 2.9 below.

     2.7 Mandatory Prepayments.

     (a) Unless the Required Lenders shall otherwise agree, if any Capital Stock shall be issued (excluding any Permitted Equity Financing), or any Indebtedness (excluding any Permitted Indebtedness) incurred, by any Loan Party or any Person shall make any contribution to the capital of any Loan Party (excluding any Permitted Equity Financing, contributions by Holdings to the capital of Borrower, or by Borrower to the capital of any Wholly Owned Subsidiary Guarantor), then on the date of such issuance, incurrence or capital contribution, Borrower shall prepay the principal amount of the Loans in an amount equal to the amount of the Net Cash Proceeds of such issuance, incurrence or capital contribution. The provisions of this Section 2.7(a) do not constitute a consent to the issuance of any Capital Stock by any Person whose Capital Stock is pledged pursuant to any Security Document, or a consent to the incurrence of any Indebtedness or the making of any capital contribution by any Loan Party.

     (b) Unless the Required Lenders shall otherwise agree, if on any date any Loan Party shall receive a Purchase Price Refund or Net Cash Proceeds from any Asset Sale or Recovery Event then, on the date of receipt by such Person of such Net Cash Proceeds or such Purchase Price Refund, Borrower shall prepay the principal amount of the Loans in an amount equal to the amount of such Net Cash Proceeds or such Purchase Price Refund; provided, however, that in the case of any Net Cash Proceeds constituting the Reinvestment Deferred Amount with respect to a Reinvestment Event, Borrower shall prepay the Loans in an amount equal to the Reinvestment Prepayment Amount applicable to such Reinvestment Event, if any, on the Reinvestment Prepayment Date with respect to such Reinvestment Event; provided further that the aggregate Net Cash Proceeds of Reinvestment Events that may be

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specified as Reinvestment Deferred Amounts in one or more Reinvestment Notices shall not exceed $250,000 in the case of any Reinvestment Event and $500,000 in the aggregate in the case of all Reinvestment Events. The provisions of this Section do not constitute a consent to the consummation of any Disposition not permitted by Section 6.5.

     (c) If on any date, a Collateral Value Deficiency exists, Borrower shall immediately (and in any event no later than the date five Business Days after such date), and without the necessity of demand by the Administrative Agent, prepay the principal amount of the Loans by an amount equal to the amount of such Reserve Value Deficiency.

     (d) Not later than 75 days after the last day of each fiscal year beginning with fiscal year 2008, Borrower shall prepay the principal amount of the Loans in an amount equal to 75% of Excess Cash Flow for such fiscal year;

     (e) Upon the occurrence of a Change of Control, the Required Lenders, at their sole discretion, may require Borrower to immediately prepay the outstanding principal amount of the Loans (after considering any prepayments by Borrower pursuant to Section 2.6), together with all other amounts owing under this Agreement or any Loan Document including any fees and expenses earned or then due and payable under any Loan Document.

     (f) Each prepayment of the Loans pursuant to this Section 2.7 shall be applied in accordance with Section 2.9 below and shall be accompanied by payment of accrued interest to the Prepayment Date on the principal amount prepaid. Each prepayment of the Loans pursuant to Section 2.7(a), (b), (c) or (e) shall include a concurrent payment of the Applicable Premium.

     2.8 Interest Rates, Payment Dates and Computation of Interest and Fees.

     (a) Each Loan shall bear interest for each day on which it is outstanding at the Interest Rate.

     (b) (i) If all or a portion of the principal amount of any Loan shall not be paid when due (whether at the stated maturity, by acceleration or otherwise) or there shall occur and be continuing any other Event of Default, all outstanding Loans (whether or not overdue) (to the extent legally permitted) shall bear interest at a rate per annum that is equal to the Interest Rate plus 2.0% the (“Default Rate”), from the date of such nonpayment of principal or occurrence of such Event of Default, respectively, until such amount of principal is paid in full (after as well as before judgment) or until such Event of Default is no longer continuing, respectively, and (ii) if all or a portion of any interest payable on any Loan or any fee or other amount payable hereunder shall not be paid when due (whether at the stated maturity, by acceleration or otherwise), such overdue amount shall bear interest at a rate per annum equal to the Default Rate, in each case, with respect to clauses (i) and (ii) above, from the date of such non payment until such amount is paid in full (after as well as before judgment).

     (c) Subject to Section 2.7(f) and Section 2.9(h), interest shall be payable in arrears on each Interest Payment Date, provided that interest accruing pursuant to Section 2.8(b) shall be payable from time to time on demand.

     (d) Interest, fees and commissions payable pursuant hereto shall be calculated on the basis of a year of 360 days.

     2.9 Application of Payments.

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     (a) The borrowing by Borrower from the Lenders hereunder, any reduction of the Commitments of the Lenders and, subject to Section 2.9(c), each payment by Borrower on account of any commitment fee, shall be made pro rata according to the Aggregate Exposure Percentages of the relevant Lenders. Each payment (including any prepayment) in respect of principal or interest in respect of any Loans and each payment in respect of fees or expenses payable hereunder shall be applied to the amounts of such obligations owing to the Lenders pro rata according to the respective amounts then due and owing to the Lenders. Amounts prepaid on account of the Loans may not be reborrowed.

     (b) So long as no Event of Default shall have occurred and be continuing all payments and any other amounts received by the Administrative Agent from or for the benefit of Borrower shall be applied: (i) first, to pay all Obligations then due and payable and (ii) second, as Borrower so designates.

     (c) After the occurrence and during the continuance of any Event of Default, Borrower hereby irrevocably waives the right to direct the application of any and all payments in respect of the Obligations and any proceeds of Collateral, and agrees that the Administrative Agent may, and shall upon either (A) the written direction of the Required Lenders or (B) the acceleration of the Obligations pursuant to Section 7.1, apply all payments in respect of any Obligations and all proceeds of Collateral in the following order:

     (i) first, to the payment or reimbursement of the Administrative Agent for all costs, expenses, disbursements and losses incurred by the Administrative Agent and which any Loan Party is required to pay or reimburse pursuant to the Loan Documents;

     (ii) second, to the payment or reimbursement of the Lenders for all costs, expenses, disbursements and losses incurred by such Persons and which any Loan Party is required to pay or reimburse pursuant to the Loan Documents;

     (iii) third, to the payment of interest on the Loans which is then due;

     (iv) fourth, to the payment of principal of the Loans which is then due;

     (v) fifth, to the payment or prepayment to the Lenders of all other Obligations; and

     (vi) sixth, to whomsoever shall be legally entitled thereto.

     (d) If any Lender owes payments to the Administrative Agent hereunder, any amounts otherwise distributable under this Section 2.9 to such Lender shall be deemed to belong to the Administrative Agent to the extent of such unpaid payments, and the Administrative Agent shall apply such amounts to make such unpaid payments rather than distribute such amounts to such Lender. All distributions of amounts described in paragraphs second and fifth above shall be made by the Administrative Agent to each Lender on a pro rata basis determined by the amount such Obligations owed to such Lender represents of the aggregate amount of all such Obligations.

     (e) All payments (including prepayments) to be made by Borrower hereunder, whether on account of principal, interest, premium, fees or otherwise, shall be made without setoff or counterclaim and shall be made prior to 12:00 Noon, New York City time, on the due date thereof to the Administrative Agent, for the account of the relevant Lenders, at the Payment Office, in Dollars and in immediately available funds. Any payment made by Borrower after 12:00 Noon, New York City time, on any Business Day shall be deemed to have been made on the next following Business Day. The Administrative Agent shall distribute such payments to the Lenders promptly upon receipt in like funds as received. If any payment hereunder becomes due and payable on a day other than a Business Day, such

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payment shall be extended to the next succeeding Business Day. In the case of any extension of any payment of principal pursuant to the preceding sentence, interest thereon shall be payable at the then-applicable rate during such extension.

     (f) Unless the Administrative Agent shall have been notified in writing by any Lender prior to the borrowing that such Lender will not make the amount that would constitute its share of such borrowing available to the Administrative Agent, the Administrative Agent may assume that such Lender is making such amount available to the Administrative Agent, and the Administrative Agent may, in reliance upon such assumption, make available to Borrower a corresponding amount. If such amount is not made available to the Administrative Agent by the required time on any Borrowing Date, such Lender shall pay to the Administrative Agent, on demand, such amount with interest thereon at a rate equal to the average Federal Funds Effective Rate for the period until such Lender makes such amount immediately available to the Administrative Agent. A certificate of the Administrative Agent submitted to any Lender with respect to any amounts owing under this Section 2.9(f) shall be conclusive in the absence of manifest error. If such Lender’s share of such borrowing is not made available to the Administrative Agent by such Lender within three Business Days after such Borrowing Date, the Administrative Agent shall also be entitled to recover such amount with interest thereon at the Interest Rate, on demand, from Borrower.

     (g) Unless the Administrative Agent shall have been notified in writing by Borrower prior to the date of any payment due to be made by Borrower hereunder that Borrower will not make such payment to the Administrative Agent, the Administrative Agent may assume that Borrower is making such payment, and the Administrative Agent may, but shall not be required to, in reliance upon such assumption, make available to the Lenders their respective pro rata shares of a corresponding amount. If such payment is not made to the Administrative Agent by Borrower within three Business Days after such due date, the Administrative Agent shall be entitled to recover, on demand, from each Lender to which any amount which was made available pursuant to the preceding sentence, such amount with interest thereon at the rate per annum equal to the daily average Federal Funds Effective Rate. Nothing herein shall be deemed to limit the rights of the Administrative Agent or any Lender against Borrower.

     (h) Each payment of the Loans shall be accompanied by accrued interest to the date of such payment on the amount paid.

     2.10 Requirements of Law.

     (a) If the adoption of or any change in any Requirement of Law or in the interpretation or application thereof or compliance by any Lender with any request or directive (whether or not having the force of law) from any central bank or other Governmental Authority made subsequent to the date hereof:

     (i) shall subject any Lender to any tax of any kind whatsoever with respect to this Agreement, any Application or any LIBOR Loan made by it, or change the basis of taxation of payments to such Lender in respect thereof (except for Non-Excluded Taxes covered by Section 2.11 and changes in the rate of tax on the overall net income of such Lender);

     (ii) shall impose, modify or hold applicable any reserve, special deposit, compulsory loan or similar requirement against assets held by, deposits or other liabilities in or for the account of, advances, loans or other extensions of credit by, or any other acquisition of funds by, any office of such Lender that is not otherwise included in the determination of the LIBOR Rate hereunder; or

     (iii) shall impose on such Lender any other condition;

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and the result of any of the foregoing is to increase the cost to such Lender, by an amount which such Lender deems to be material, of making, continuing or maintaining Loans bearing interest by reference to the LIBOR Rate, or to reduce any amount receivable hereunder in respect thereof, then, in any such case, Borrower shall promptly pay such Lender, upon its demand, any additional amounts necessary to compensate such Lender on an after-tax basis for such increased cost or reduced amount receivable. If any Lender becomes entitled to claim any additional amounts pursuant to this Section 2.10, it shall promptly notify Borrower (with a copy to the Administrative Agent) of the event by reason of which it has become so entitled.

     (b) If any Lender shall have determined that the adoption of or any change in any Requirement of Law regarding capital adequacy, reserve requirements or similar requirements generally acceptable to lending institutions or in the interpretation or application thereof or compliance by such Lender or any corporation controlling such Lender with any request or directive regarding capital adequacy, reserve requirements or similar requirements (whether or not having the force of law) from any Governmental Authority made subsequent to the Closing Date shall have the effect of reducing the rate of return on such Lender’s or such corporation’s capital as a consequence of its obligations hereunder to a level below that which such Lender or such corporation could have achieved but for such adoption, change or compliance (taking into consideration such Lender’s or such corporation’s policies with respect to capital adequacy) by an amount deemed by such Lender to be material, then from time to time, after submission by such Lender to Borrower (with a copy to the Administrative Agent) of a written request therefor, Borrower shall promptly pay to such Lender such additional amount or amounts as will compensate such Lender or such corporation for such reduction on an after-tax basis.

     (c) A certificate as to any additional amounts payable pursuant to this Section submitted by any Lender to Borrower (with a copy to the Administrative Agent) shall be conclusive in the absence of manifest error. The obligations of Borrower pursuant to this Section shall survive the termination of this Agreement and the payment of the Loans and all other amounts payable hereunder.

     (d) Notwithstanding anything to the contrary contained herein, if the introduction of or any change in any law or regulation (or any change in the interpretation thereof) after the Closing Date shall make it unlawful, or any central bank or other Governmental Authority shall assert after the Closing Date that it is unlawful, for any Lender to agree to make or to make or to continue to fund or maintain any Loan bearing interest by reference to the LIBOR Rate, then, unless that Lender is able to make or to continue to fund or to maintain such Loan at another branch or office of that Lender without, in that Lender’s opinion, adversely affecting it or its Loans or the income obtained therefrom, on notice thereof and demand therefor by such Lender to Borrower through the Administrative Agent, (i) the obligation of such Lender to agree to make or to make or to continue to fund or maintain Loans bearing interest by reference to the LIBOR Rate shall terminate, and (ii) all of such Lender’s Loans shall automatically convert at the end of the then-current LIBOR Period with respect thereto or sooner, if required by such law, regulation or interpretation, into Loans bearing interest with respect to such Lender from and after the date of such conversion at a rate per annum equal to the sum of (x) the Federal Funds Effective Rate in effect from time to time plus 0.50% and (y) the Interest Margin.

     2.11 Taxes.

     (a) All payments made by any Loan Party under this Agreement or any other Loan Documents shall be made free and clear of, and without deduction or withholding for or on account of, any present or future income, stamp or other taxes, levies, imposts, duties, charges, fees, deductions or withholdings, now or hereafter imposed, levied, collected, withheld or assessed by any Governmental Authority, excluding net income taxes and franchise taxes (imposed in lieu of net income taxes) imposed on any Agent or any Lender as a result of a present or former connection between such Agent or such

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Lender and the jurisdiction of the Governmental Authority imposing such tax or any political subdivision or taxing authority thereof or therein (other than any such connection arising solely from such Agent’s or such Lender’s having executed, delivered or performed its obligations or received a payment under, or enforced, this Agreement or any other Loan Document). If any such non-excluded taxes, levies, imposts, duties, charges, fees, deductions or withholdings (“Non-Excluded Taxes”) or any Other Taxes are required to be withheld from any amounts payable to any Agent or any Lender hereunder, the amounts so payable to such Agent or such Lender shall be increased to the extent necessary to yield to such Agent or such Lender (after payment of all Non-Excluded Taxes and Other Taxes) interest or any such other amounts payable hereunder at the rates or in the amounts specified in this Agreement; provided, however, that Borrower or any Guarantor shall not be required to increase any such amounts payable to any Agent or any Lender with respect to any Non-Excluded Taxes (i) that are attributable to such Agent’s or such Lender’s failure to comply with the requirements of Sections 2.11(d) or (e) or (ii) that are United States withholding taxes imposed on amounts payable to such Agent or such Lender at the time such Agent or such Lender becomes a party to this Agreement, except to the extent that such Agent’s or such Lender’s assignor (if any) was entitled, at the time of assignment, to receive additional amounts from Borrower with respect to such Non-Excluded Taxes pursuant to this Section 2.11(a). Borrower or the applicable Guarantor shall make any required withholding and pay the full amount withheld to the relevant tax authority or other Governmental Authority in accordance with applicable Requirements of Law.

     (b) In addition, Borrower shall pay any Other Taxes to the relevant Governmental Authority in accordance with applicable law.

     (c) Whenever any Non-Excluded Taxes or Other Taxes are payable by Borrower, as promptly as possible thereafter Borrower shall send to the Administrative Agent for the account of the relevant Agent or Lender, as the case may be, a certified copy of an original official receipt received by Borrower showing payment thereof. If Borrower fails to pay any Non-Excluded Taxes or Other Taxes when due to the appropriate taxing authority or fails to remit to the Administrative Agent the required receipts or other required documentary evidence, Borrower shall indemnify the Agents and the Lenders for any incremental taxes, interest or penalties that may become payable by any Agent or any Lender as a result of any such failure. The agreements in this Section 2.11 shall survive the termination of this Agreement and the payment of the Loans and all other amounts payable hereunder.

     (d) Each Lender (or Transferee) that is not a citizen or resident of the United States of America, a corporation, partnership or other entity created or organized in or under the laws of the United States of America (or any jurisdiction thereof), or any estate or trust that is subject to federal income taxation regardless of the source of its income (a “Non U.S. Lender”) shall deliver to Borrower and the Administrative Agent (or, in the case of a Participant, to the Lender from which the related participation shall have been purchased) two copies of either U.S. Internal Revenue Service Form W-8BEN or Form W-8ECI, or, in the case of a Non U.S. Lender claiming exemption from U.S. federal withholding tax under Section 871(h) or 881(c) of the Code with respect to payments of “portfolio interest” a statement substantially in the form of Exhibit H to the effect that such Lender is eligible for a complete exemption from withholding of U.S. taxes under Section 871(h) or 881(c) of the Code and a Form W-8BEN, or any subsequent versions thereof or successors thereto properly completed and duly executed by such Non U.S. Lender claiming complete exemption from, or a reduced rate of, U.S. federal withholding tax on all payments by Borrower under this Agreement and the other Loan Documents. Such forms shall be delivered by each Non U.S. Lender on or before the date it becomes a party to this Agreement (or, in the case of any Participant, on or before the date such Participant purchases the related participation). In addition, each Non U.S. Lender shall deliver such forms promptly upon the obsolescence or invalidity of any form previously delivered by such Non U.S. Lender. Each Non-U.S. Lender shall promptly notify Borrower at any time it determines that it is no longer in a position to provide any previously delivered certificate to Borrower (or any other form of certification adopted by the U.S. taxing authorities for such

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purpose). Notwithstanding any other provision of this Section 2.11(d), a Non U.S. Lender shall not be required to deliver any form pursuant to this Section 2.11(d) that such Non U.S. Lender is not legally able to deliver.

     (e) A Lender that is entitled to an exemption from or reduction of non-U.S. withholding tax under the law of the jurisdiction in which Borrower is located, or any treaty to which such jurisdiction is a party, with respect to payments under this Agreement shall deliver to Borrower (with a copy to the Administrative Agent), at the time or times prescribed by applicable law or reasonably requested by Borrower, such properly completed and executed documentation prescribed by applicable law as will permit such payments to be made without withholding or at a reduced rate, provided that such Lender is legally entitled to complete, execute and deliver such documentation and in such Lender’s reasonable judgment such completion, execution or submission would not materially prejudice the legal position of such Lender.

     2.12 Indemnity. Borrower agrees promptly to indemnify each Lender for, and to hold each Lender harmless from, any loss or expense that such Lender may sustain or incur as a consequence of (a) the failure to make any prepayment of a Loan after Borrower has given a notice thereof in accordance with the provisions of this Agreement; (b) the repayment of any Loans that are repaid in whole or in part prior to the last day of a LIBOR Period (whether such repayment is made pursuant to any provision of this Agreement or any other Loan Document or occurs as a result of acceleration, mandatory prepayment, by operation of law or otherwise); or (c) a default in payment when due of the principal amount of or interest on any Loan; or (d) a default in making any borrowing of Loans after Borrower has given notice requesting the same in accordance herewith. Such indemnification shall include any loss (excluding loss of margin) or expense arising from the reemployment of funds obtained by it or from fees payable to terminate deposits from which such funds were obtained. For the purpose of calculating amounts payable to a Lender under this Section 2.12, each Lender shall be deemed to have actually funded its relevant Loan through the purchase of a deposit bearing interest at the LIBOR Rate in an amount equal to the amount of that Loan and having a maturity comparable to the LIBOR Period; provided that each Lender may fund each of its Loans in any manner it deems appropriate, and the foregoing assumption shall be utilized only for the calculation of amounts payable under this Section 2.12. A certificate as to any amounts payable pursuant to this Section submitted to Borrower by any Lender shall be conclusive in the absence of manifest error. This covenant shall survive the termination of this Agreement and the repayment of the Loans and all other amounts payable hereunder.

     2.13 Change of Lending Office. Each Lender agrees that, upon the occurrence of any event giving rise to the operation of Section 2.10 or 2.11(a) with respect to such Lender, it will, if requested by Borrower, use reasonable efforts (subject to overall policy considerations of such Lender) to designate another lending office for any Loans affected by such event with the object of avoiding the consequences of such event; provided that such designation is made on terms that, in the sole judgment of such Lender, cause such Lender and its lending office(s) to suffer no economic, legal or regulatory disadvantage, and provided, further, that nothing in this Section 2.13 shall affect or postpone any of the obligations of Borrower or the rights of any Lender pursuant to Section 2.10 or 2.11(a).

ARTICLE III
REPRESENTATIONS AND WARRANTIES

     To induce the Agents and the Lenders to enter into this Agreement and to make the Loans, each of Holdings and Borrower hereby represents and warrants, jointly and severally, to each Agent and each Lender that on the date hereof and on the Closing Date:

     3.1 Financial Condition.

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     (a) The unaudited pro forma consolidated balance sheet of Holdings and its consolidated Subsidiaries as at September 30, 2007 (including the notes thereto) (the “Pro Forma Balance Sheet”), copies of which have heretofore been furnished to the Administrative Agent, has been prepared giving effect (as if such events had occurred on such date) to (i) the Loans to be made on the Closing Date and the use of proceeds thereof and (ii) the payment of fees and expenses in connection with the foregoing. The Pro Forma Balance Sheet has been prepared based on the best information available to Holdings as of the date of delivery thereof, and presents fairly on a pro forma basis the estimated financial position of Holdings and its consolidated Subsidiaries as at September 30, 2007, assuming that the events specified in the preceding sentence had actually occurred at such date.

     (b) The audited consolidated balance sheets of Holdings as at December 31, 2005 and December 31, 2006, and the related consolidated statements of income and of cash flows for the fiscal years ended on such dates, reported on by and accompanied by an unqualified report from the Independent Accountant, present fairly the consolidated financial condition of Holdings as at such date, and the consolidated results of its operations and its consolidated cash flows for the respective fiscal years then ended. The unaudited consolidated balance sheet of Holdings as at September 30, 2007, and the related unaudited consolidated statements of income and cash flows for the nine-month period ended on such date, present fairly the consolidated financial condition of Holdings as at such date, and the consolidated results of its operations and its consolidated cash flows for the nine-month period then ended (subject to normal year end audit adjustments). All such financial statements, including the related schedules and notes thereto, have been prepared in accordance with GAAP applied consistently throughout the periods involved (except as approved by the aforementioned firm of accountants and disclosed therein). No Loan Party has any material Guarantee Obligations, contingent liabilities and liabilities for taxes, or any long term leases or unusual forward or long term commitments, including, any interest rate or foreign currency swap or exchange transaction or other obligation in respect of derivatives, that are not reflected in the most recent financial statements referred to in this paragraph. During the period from October 1, 2007 to and including the date hereof there has been no Disposition by any Loan Party of any material part of its business or Property except as described on Schedule 3.1(b).

     3.2 No Change. Except as set forth on Schedule 3.2, since December 31, 2006, there has been no development or event that has had or could reasonably be expected to have a Material Adverse Effect.

     3.3 Corporate Existence; Compliance with Law.

     (a) Each of the Loan Parties (i) is duly incorporated, organized or formed, as applicable, validly existing and (if relevant) in good standing under the laws of the jurisdiction of its incorporation, organization or formation, as the case may be, (ii) has the corporate, company or partnership power and authority, as applicable, and the legal right, to own and operate its Property, to lease the Property it operates as lessee and to conduct the business in which it is currently engaged, (iii) is duly qualified as a foreign corporation, company or partnership, as applicable, and (if relevant) in good standing under the laws of each jurisdiction where its ownership, lease or operation of Property or the conduct of its business requires such qualification except to the extent that the failure to comply therewith could not, in the aggregate, reasonably be expected to have a Material Adverse Effect, (iv) is in compliance with its Constituent Documents and (v) is in compliance with all Requirements of Law (other than its Constituent Documents) except to the extent that the failure to comply therewith could not, individually or in the aggregate, reasonably be expected to have a Material Adverse Effect.

     (b) Each Loan Party has all Permits necessary for the ownership and, if any Loan Party is the operator, operation of its Properties and the conduct of its businesses except for those Permits the failure

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of which to have could not reasonably be expected to have a Material Adverse Effect, and is in compliance in all material respects with the terms and conditions of all such Permits.

     3.4 Entity Power; Authorization; Enforceable Obligations. Each Loan Party has the power and authority (corporate or otherwise), and the legal right, to make, deliver and perform the Loan Documents to which it is a party and, in the case of Borrower, to borrow hereunder. Each Loan Party has taken all necessary corporate or other action to authorize the execution, delivery and performance of the Loan Documents to which it is a party and, in the case of Borrower, to authorize the borrowings on the terms and conditions of this Agreement. No consent or authorization of, filing with, notice to or other act by or in respect of, any Governmental Authority or any other Person is required in connection with the borrowings hereunder or the execution, delivery, performance, validity or enforceability of this Agreement or any of the other Loan Documents except (i) consents, authorizations, filings and notices described in Schedule 3.4, which consents, authorizations, filings and notices have been obtained or made and are in full force and effect and (ii) the filings referred to in Section 3.21. Each Loan Document has been duly executed and delivered on behalf of each Loan Party that is a party thereto. This Agreement constitutes, and each other Loan Document upon execution will constitute, a legal, valid and binding obligation of each Loan Party that is a party thereto, enforceable against each such Loan Party in accordance with its terms, except as enforceability may be limited by applicable bankruptcy, insolvency, reorganization, moratorium or similar laws affecting the enforcement of creditors’ rights generally and by general equitable principles (whether enforcement is sought by proceedings in equity or at law).

     3.5 No Legal Bar. The execution, delivery and performance of this Agreement and the other Loan Documents, the borrowings hereunder and the use of the proceeds thereof will not violate any Requirement of Law or any Contractual Obligation of any Loan Party and will not result in, or require, the creation or imposition of any Lien on any of their respective properties or revenues pursuant to any Requirement of Law or any such Contractual Obligation (other than the Liens created by the Security Documents). No Requirement of Law or Contractual Obligation applicable to any Loan Party could reasonably be expected to have a Material Adverse Effect. No performance of a Contractual Obligation by any Loan Party, either unconditionally or upon the happening of an event, would result in the creation of a Lien (other than a Permitted Lien) on the Property of any Loan Party.

     3.6 No Indebtedness; No Material Litigation.

     (a) After giving effect to the making of the Loans and application of the proceeds thereof on the Closing Date, no Loan Party shall have outstanding any Indebtedness other than the Loans.

     (b) No litigation, investigation or proceeding of or before any arbitrator or Governmental Authority is pending or, to Borrower’s knowledge, threatened by or against any Loan Party or against any of their respective properties or revenues (a) with respect to any of the Loan Documents or any of the transactions contemplated hereby or thereby, or (b) that could reasonably be expected to have a Material Adverse Effect.

     3.7 No Default. No Loan Party is in default under or with respect to any of its Contractual Obligations in any respect that could reasonably be expected to have a Material Adverse Effect. No Default or Event of Default has occurred and is continuing.

     3.8 Ownership of Property; Liens.

     (a) No Loan Party holds any Real Property in fee simple. Schedule 1.2 describes all Real Property in which any Loan Party holds a leasehold interest. The Loan Parties have valid leasehold interests in all such Real Property and Defensible Title to, or a valid leasehold interest in, all other

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Property material to its business, and none of such Property is subject to any Lien other than Permitted Liens.

     (b) The Rigs are (i) mobile equipment which are not designed to be permanently used in any one location; (ii) not property subject to Revised Colorado Statue §§ 42-6-120 or 42-6-121 or any comparable statute, law, regulation or rule of any state in which any of the Rigs is located and not certificated as motor vehicles under the laws of any jurisdiction; and (iii) not fixtures under the laws of any jurisdiction in which any of the Rigs is located.

     3.9 Insurance. All policies of insurance of any kind or nature of any Loan Party, including policies of fire, theft, product liability, public liability, property damage, other casualty, employee fidelity, workers’ compensation and employee health and welfare insurance, are in full force and effect and are of a nature and provide such coverage as is customarily carried by businesses of the size and character such Loan Party. No Loan Party has been refused insurance for any material coverage for which it had applied or had any policy of insurance terminated (other than at its request).

     3.10 Intellectual Property. Each Loan Party owns, or is licensed to use, all Intellectual Property necessary for the conduct of its business as currently conducted. No material claim has been asserted and is pending by any Person challenging or questioning the use by any Loan Party of any Intellectual Property or the validity or effectiveness of any Intellectual Property, nor, to Borrower’s knowledge, is there any valid basis for any such claim. The use of Intellectual Property by any Loan Party does not infringe on the rights of any Person in any material respect.

     3.11 Taxes. Each Loan Party has filed or caused to be filed all federal, state and other material tax returns, reports and statements (collectively, “Tax Returns”) that are required to be filed by such Loan Party or any of its Tax Affiliates with the appropriate Governmental Authorities in all jurisdictions in which such Tax Returns are required to be filed; all such Tax Returns are true and correct in all material respects and correctly reflect the facts regarding the income, business, assets, operations, activities, status or other matters of such Loan Party and any other information required to be shown thereon; each Loan Party has paid, prior to the date on which any fine, penalty, interest, late charge or loss may be added thereto for non-payment thereof, all taxes shown to be due and payable on said returns or on any assessments made against it or any of its Property and all other taxes, fees or other charges imposed on it or any of its Property by or otherwise due and payable to any Governmental Authority (other than any the amount or validity of which are currently being contested in good faith by appropriate proceedings and with respect to which reserves in conformity with GAAP have been provided on the books of such Loan Party); and no tax Lien has been filed against the Property of any Loan Party, and, to Borrower’s knowledge, no claim is being asserted, with respect to any such tax, fee or other charge. No Tax Return is under audit or examination by any Governmental Authority and no notice of such an audit or examination or any assertion of any claim for taxes has been given or made by any Governmental Authority. Proper and accurate amounts have been withheld by each Loan Party and each of its Tax Affiliates from their respective employees for all periods in full and complete compliance with the tax, social security and unemployment withholding provisions of applicable Requirements of Law and such withholdings have been timely paid to the respective Governmental Authorities. No Loan Party (i) intends to treat the Loans or any other transaction contemplated hereby as being a “reportable transaction” (within the meaning of Treasury Regulation 1.6011-4) or (ii) is aware of any facts or events that would result in such treatment.

     3.12 Federal Regulations. No part of the proceeds of any Loans will be used for “buying” or “carrying” any “margin stock” within the respective meanings of each of the quoted terms under Regulation U as now and from time to time hereafter in effect or for any purpose that violates the provisions of the Regulations of the Board.

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     3.13 Labor Matters. There are no strikes, stoppages or slowdowns or other labor disputes against any Loan Party pending or, to Borrower’s knowledge, threatened that (individually or in the aggregate) could reasonably be expected to have a Material Adverse Effect. Hours worked by and payment made to employees of any Loan Party have not been in violation of the Fair Labor Standards Act of 1938, as amended, or any other applicable Requirement of Law dealing with such matters that (individually or in the aggregate) could reasonably be expected to have a Material Adverse Effect. All payments due from any Loan Party on account of employee health and welfare insurance that (individually or in the aggregate) could reasonably be expected to have a Material Adverse Effect if not paid have been paid or accrued as a liability on the books of such Loan Party.

     3.14 ERISA. Neither a Reportable Event nor an “accumulated funding deficiency” (within the meaning of Section 412 of the Code or Section 302 of ERISA) has occurred during the five year period prior to the date on which this representation is made or deemed made with respect to any Benefit Plan, and each Benefit Plan has complied in all material respects with the applicable provisions of ERISA and the Code. No termination of a Single Employer Plan has occurred, and no Lien in favor of the PBGC or a Benefit Plan has arisen, during such five-year period. The present value of all accrued benefits under each Single Employer Plan (based on those assumptions used to fund such Benefit Plans) did not, as of the last annual valuation date prior to the date on which this representation is made or deemed made, exceed the value of the assets of such Plan allocable to such accrued benefits by a material amount. Neither any Loan Party nor any Commonly Controlled Entity has had a complete or partial withdrawal from any Multiemployer Plan that has resulted or could reasonably be expected to result in a material liability under ERISA, and neither any Loan Party nor any Commonly Controlled Entity would become subject to any material liability under ERISA if such Loan Party or any such Commonly Controlled Entity were to withdraw completely from all Multiemployer Plans as of the valuation date most closely preceding the date on which this representation is made or deemed made. No such Multiemployer Plan is in Reorganization or Insolvent.

     3.15 Regulations.

     (a) No Loan Party is an “investment company”, or a company “controlled” by an “investment company”, within the meaning of the Investment Company Act of 1940, as amended.

     (b) No Loan Party is subject to regulation under any Requirement of Law (other than Regulation X of the Board) which limits its ability to incur Indebtedness.

     (c) No Loan Party is a “holding company” or a “subsidiary company” of a “holding company”, or an “affiliate” of a “holding company” or of a “subsidiary company” of a “holding company”, within the meaning of the Public Utility Holding Company Act of 1935, as amended.

     (d) No Mortgage encumbers improved Real Property that is located in an area that has been identified by the Secretary of Housing and Urban Development as an area having special flood hazards and in which flood insurance has been made available under the National Flood Insurance Act of 1968.

     3.16 Capital Stock; Subsidiaries.

     (a) All of the outstanding Capital Stock of each Loan Party has been duly authorized and validly issued and is fully paid and non-assessable and, in the case of each Loan Party other than Holdings, has been duly pledged as Collateral under the Guarantee and Security Agreement and is free and clear of all Liens (except Liens pursuant to the Security Documents).

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     (b) The Subsidiaries listed on Schedule 3.16 constitute all the Subsidiaries of each Loan Party as of the Closing Date. Schedule 3.16 sets forth as of the Closing Date the exact legal name (as reflected on the certificate of incorporation (or formation) and jurisdiction of incorporation (or formation) of each Subsidiary of any Loan Party and, as to each such Subsidiary, the percentage and number of each class of Capital Stock owned by each Loan Party.

     (c) There are no outstanding subscriptions, options, warrants, calls, rights or other agreements or commitments (other than stock options with respect to Capital Stock of Holdings granted to employees or directors and directors’ qualifying shares) of any nature relating to any Capital Stock of any Loan Party, except as disclosed on Schedule 3.16.

     (d) Holdings owns directly all of the outstanding Capital Stock of Borrower. No Loan Party owns or holds, directly or indirectly, any Capital Stock of any Person other than any Subsidiary. Borrower owns, directly or indirectly through other Subsidiaries, all of the outstanding Capital Stock of its Subsidiaries. Each Loan Party is a party to the Guarantee and Security Agreement.

     (e) There are no agreements or understandings (other than the Loan Documents): (i) to which any Loan Party is a party with respect to the voting, sale or transfer of any shares of Capital Stock of Holdings or any Loan Party or restricting the transfer or hypothecation of any such shares or (ii) with respect to the voting, sale or transfer of any shares of Capital Stock of any Loan Party (other than Holdings) or restricting the transfer or hypothecation of any such shares.

     3.17 Use of Proceeds. The proceeds of the Loans shall be used to repay the Existing Indebtedness and to pay related fees and expenses and for general corporate purposes.

     3.18 Customers and Suppliers. There exists no actual or threatened termination, cancellation or limitation of, or modification to or change in (a) any Daywork Drilling Contract, or (b)  the business relationship between (i) either Loan Party, on the one hand, and any customer or any group thereof, on the other hand, whose agreements with either Loan Party is individually or in the aggregate material to the business or operations of Borrower, or (ii) either Loan Party, on the one hand, and any material supplier thereof, on the other hand; and there exists no present state of facts or circumstances that could give rise to or result in any such termination, cancellation, limitation, modification or change. No Person providing any materials or services to either Loan Party has filed, or threatened to file, a mechanics’, materialmen’s, repairmen’s or other like Lien on any Drilling Rig Assets.

     3.19 Environmental Matters. Other than exceptions to any of the following that could not, individually or in the aggregate, reasonably be expected to result in the payment of a Material Environmental Amount:

     (a) Each Loan Party: (i) is, and within the period of all applicable statutes of limitation has been, in compliance with all applicable Environmental Laws; (ii) holds all Environmental Permits (each of which is in full force and effect) required for any of their current or intended operations or for any property owned, leased, or otherwise operated by any of them; (iii) is, and within the period of all applicable statutes of limitation has been, in compliance with all of their Environmental Permits; and (iv) reasonably believes that: each of their Environmental Permits will be timely renewed and complied with, without material expense; any additional Environmental Permits that may be required of any of them will be timely obtained and complied with, without material expense; and compliance with any Environmental Law that is or is expected to become applicable to any of them will be timely attained and maintained, without material expense.

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     (b) Materials of Environmental Concern are not present at, on, under, in, or about any Real Property now or formerly owned, leased or operated by any Loan Party, or at any other location (including, any location to which Materials of Environmental Concern have been sent for re-use or recycling or for treatment, storage, or disposal) which could reasonably be expected to (i) give rise to liability of any Loan Party under any applicable Environmental Law or otherwise result in costs to any Loan Party, or (ii) interfere with the continued operations of any Loan Party, or (iii) impair the fair saleable value of any Property owned or leased by any Loan Party

     (c) There is no judicial, administrative, or arbitral proceeding (including any notice of violation or alleged violation) under or relating to any Environmental Law or Environmental Permit to which any Loan Party is, or to Borrower’s knowledge, or any of its Subsidiaries will be, named as a party that is pending or, to Borrower’s knowledge, threatened.

     (d) No Loan Party has received any written request for information, or been notified that it is a potentially responsible party under or relating to the federal Comprehensive Environmental Response, Compensation, and Liability Act or any similar Environmental Law, or with respect to any Materials of Environmental Concern.

     (e) No Loan Party has entered into or agreed to any consent decree, order, or settlement or other agreement, or is subject to any judgment, decree, or order or other agreement, in any judicial, administrative, arbitral, or other forum for dispute resolution, relating to compliance with or liability under any Environmental Law.

     (f) No Loan Party has assumed or retained, by contract or operation of law, any liabilities of any kind, fixed or contingent, known or unknown, under any Environmental Law or with respect to any Material of Environmental Concern.

     (g) Borrower has made available to the Administrative Agent and the Lenders copies of all significant reports, correspondence and other documents in its possession, custody or control regarding compliance by any Loan Party with or potential liability of any Loan party under Environmental Laws or Environmental Permits.

     3.20 Accuracy of Information, Etc. No statement or information contained in this Agreement, any other Loan Document or any other document, certificate or statement furnished to the Agents or the Lenders or any of them, by or on behalf of any Loan Party for use in connection with the transactions contemplated by this Agreement or the other Loan Documents, contained as of the date such statement, information, document or certificate was so furnished, any untrue statement of a material fact or omitted to state a material fact necessary in order to make the statements contained herein or therein not misleading. The projections and pro forma financial information contained in the materials referenced above are based upon good faith estimates and assumptions believed by management of Holdings and Borrower to be reasonable at the time made, it being recognized by the Lenders that such financial information as it relates to future events is not to be viewed as fact and that actual results during the period or periods covered by such financial information may differ from the projected results set forth therein by a material amount. There is no fact known to any Loan Party that could reasonably be expected to have a Material Adverse Effect that has not been expressly disclosed herein, in the other Loan Documents or in any other documents, certificates and statements furnished to the Agents and the Lenders for use in connection with the transactions contemplated hereby and by the other Loan Documents.

     3.21 Security Documents.

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     (a) The Guarantee and Security Agreement is effective to create in favor of the Administrative Agent, for the benefit of the Secured Parties, a legal, valid, binding and enforceable security interest in the Collateral described therein and proceeds and products thereof. In the case of the Pledged Stock described in the Guarantee and Security Agreement, when any stock certificates representing such Pledged Stock are delivered to the Administrative Agent, and, in the case of Pledged Stock that is a “security” (as defined in the UCC) but is not evidenced by a certificate, when an Instructions Agreement, substantially in the form of Annex A to the Guarantee and Security Agreement, has been delivered to the Administrative Agent, and in the case of any other Collateral described in the Guarantee and Security Agreement, when financing statements in appropriate form are filed in the offices specified on Schedule 3.21(a)-1 (which financing statements may be filed by the Administrative Agent) at any time and such other filings as are specified on Schedule 3 to the Guarantee and Security Agreement have been completed (all of which filings may be filed by the Administrative Agent) at any time, the Guarantee and Security Agreement shall constitute a fully perfected Lien on, and security interest in, all right, title and interest of the Loan Parties in such Collateral and the proceeds and products thereof, as security for the Obligations (as defined in the Guarantee and Security Agreement), in each case prior and superior in right to any other Person (except (in the case of Collateral other than securities pledged by any Loan Party) Permitted Liens). Schedule 3.21(a)-2 lists each UCC Financing Statement that (i) names any Loan Party as debtor and (ii) will remain on file after the Closing Date. Schedule 3.21(a)-3 lists each UCC Financing Statement that (i) names any Loan Party as debtor and (ii) will be terminated on or prior to the Closing Date; and on or prior to the Closing Date, Borrower will have delivered to the Administrative Agent, or caused to be filed, duly completed UCC termination statements, signed by the relevant secured party, in respect of each such UCC Financing Statement.

     (b) The Mortgaged Properties constitute all of the Real Property owned by the Loan Parties. Each of the Mortgages is effective to create in favor of the Administrative Agent, for the benefit of the Secured Parties, a legal, valid, binding and enforceable Lien on the Mortgaged Properties described therein and proceeds and products thereof; and when the Mortgages are filed in the offices specified on Schedule 3.21(b) (in the case of Mortgages to be executed and delivered on the Closing Date) or in the recording office designated by Borrower (in the case of any Mortgage to be executed and delivered pursuant to Section 5.10(a)), each Mortgage shall constitute a fully perfected Lien on, and security interest in, all right, title and interest of the Loan Parties in the Mortgaged Properties described therein and the proceeds and products thereof, as security for the Obligations (as defined in the relevant Mortgage), in each case prior and superior in right to any other Person (other than Persons holding Liens or other encumbrances or rights permitted by the relevant Mortgage).

     3.22 Solvency. Each Loan Party is, and after giving effect to the incurrence of all Indebtedness and obligations being incurred in connection herewith will be and will continue to be, Solvent.

     3.23 Drilling Rig Assets. Set forth on Schedule 3.23 is a complete and accurate list and description of (a) each Rig (including, on a Rig by Rig basis, (i) identification of the rig number of each Rig and the owner thereof and (ii) identification of the location of each Rig (by county, state and country)), (b) each Rig Accessory and (c) each contract right of any Loan Party relating to the use, operation, refurbishment, upgrade or purchase of any Rig or Rig Accessories (collectively, the “Drilling Rig Assets”), and such Drilling Rig Assets constitute all of the land-based drilling rigs, Rig Accessories and related contracts rights owned or held by any Loan Party on the Closing Date.

     3.24 Contingent Obligations. There will be no material Contingent Obligations of any Loan Party existing at the Closing Date.

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     3.25 Bank Accounts. Schedule 3.25 lists all accounts maintained by or for the benefit of any Loan Party with any bank or financial institution.

     3.26 Access Agreements. No books or records of any Loan Party are located or maintained on any premises owned by a third party or leased by a third party to any Loan Party other than such premises as to which the Administrative Agent has received an Access Agreement from such Loan Party.

     3.27 Customers and Suppliers. There exists no actual or threatened termination, cancellation or limitation of, or modification to or change in the business relationship between (i) any Loan Party, on the one hand, and any customer or any group thereof, on the other hand, whose agreements with such Loan Party is individually or in the aggregate material to the business or operations of the Loan Parties, or (ii) any Loan Party, on the one hand, and any material supplier thereof, on the other hand; and there exists no present state of facts or circumstances that could reasonably be expected to give rise to or result in any such termination, cancellation, limitation, modification or change.

ARTICLE IV
CONDITIONS PRECEDENT

     4.1 Conditions to Initial Loan. The agreement of each Lender to make the Loan requested to be made by it hereunder is subject to the satisfaction, prior to or concurrently with the making of such Loan on the Closing Date, of the following conditions precedent:

     (a) Loan Documents. The Administrative Agent shall have received the following documents, in each case executed and delivered by a duly authorized officer of each of the parties thereto: (i) this Agreement, (ii) the Guarantee and Security Agreement for each Loan Party and (iii) a financing statement on Form UCC-1 for each Loan Party.

     (b) Constituent Documents. All documents establishing or implementing the ownership, capital and corporate, organizational, tax and legal structure of each Loan Party shall be reasonably satisfactory to the Administrative Agent.

     (c) Pro Forma Balance Sheet; Financial Statements. The Lenders shall have received (i) the Pro Forma Balance Sheet, (ii) audited consolidated financial statements for the 2005 and 2006 fiscal years and (iii) unaudited interim consolidated financial statements of Borrower since September 30, 2007 for each fiscal month and quarterly period ended subsequent to the date of the latest applicable financial statements delivered pursuant to clause (ii) of this paragraph as to which such financial statements are available; and such financial statements shall not, in the reasonable judgment of the Administrative Agent or the Lenders, reflect any Material Adverse Effect since December 31, 2006.

     (d) Approvals. Permits and third party approvals necessary or, in the sole discretion of the Administrative Agent, advisable to be obtained by a Loan Party in connection with this Agreement, the Security Documents and the continuing operations of Holdings, Borrower and its Subsidiaries and the transactions contemplated hereby shall have been obtained and be in full force and effect, and all applicable waiting periods shall have expired without any action being taken or threatened by any competent authority which would restrain, prevent or otherwise impose adverse conditions on the financing contemplated hereby.

     (e) Related Agreements. The Administrative Agent shall have received (in a form reasonably satisfactory to the Administrative Agent), true and correct copies, certified to be true, correct and complete as of the Closing Date by a Responsible Officer of Borrower, of fully executed versions of such other documents or instruments as may be reasonably requested by the Administrative Agent,

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including, a copy of any debt instrument, security agreement or other material contract to which the Loan Parties may be a party.

     (f) Termination of Existing Credit Documents. The Administrative Agent shall have received evidence satisfactory to the Administrative Agent that the Existing Credit Documents shall be simultaneously terminated, all amounts thereunder shall be simultaneously paid in full and arrangements satisfactory to the Administrative Agent shall have been made for the termination of Liens and security interests granted in connection therewith.

     (g) Fees. The Lenders and the Agents shall have received all fees required to be paid, and all expenses for which invoices have been presented (including reasonable fees, disbursements and other charges of counsel to the Agents), on or before the Closing Date; provided that the Administrative Agent shall have advised Borrower at such time that its attorney’s fees have reached $75,000 together with a remaining estimate of the legal fees through the completion of the transaction. All such amounts will be paid with proceeds of Loans made on the Closing Date and will be reflected in the funding instructions given by Borrower to the Administrative Agent on or before the Closing Date.

     (h) Solvency. The Lenders shall have received a reasonably satisfactory Solvency Certificate which shall document the solvency of the Loan Parties considered as a whole after giving effect to the transactions contemplated hereby.

     (i) Budget. The Lenders shall have received a budget for Borrower and its Subsidiaries for the 2008 fiscal year which budget shall be reasonably acceptable to the Administrative Agent and the Lenders.

     (j) Lien Searches. The Administrative Agent shall have received the results of a recent lien, search in each of the jurisdictions or offices in which UCC financing statements or other filings or recordations should be made to evidence or perfect (with the priority required under the Loan Documents) security interests in all assets of the Loan Parties (or would have been made at any time during the five years immediately preceding the Closing Date to perfect Liens on any assets owned on the Closing Date by any Loan Party), and such search shall reveal no Liens on any of the assets of the Loan Party, except for Permitted Liens or Liens set forth on Schedule 3.21(a)-3 that were terminated, released or otherwise discharged on or prior to the Closing Date pursuant to documentation satisfactory to the Administrative Agent.

     (k) Closing Certificate. The Administrative Agent shall have received a certificate of each Loan Party, dated the Closing Date, substantially in the form of Exhibit I, with appropriate insertions and attachments.

     (l) Other Certifications. The Administrative Agent shall have received the following:

     (i) a copy of the charter of each Loan Party and each amendment thereto, certified (as of a date reasonably near the date of the initial extension of credit) as being a true and correct copy thereof by the Secretary of State or other applicable Governmental Authority of the jurisdiction in which each such Loan Party is organized;

     (ii) a copy of a certificate of the Secretary of State or other applicable Governmental Authority of the jurisdiction in which each Loan Party is organized, dated reasonably near the date of the initial extension of credit, listing the charter such Loan Party and each amendment thereto on file in such office and certifying that (A) such amendments are the only amendments to such Loan Party’s charter on file in such office, (B) such Loan Party has

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paid all franchise taxes to the date of such certificate and (C) such Loan Party is duly organized and in good standing under the laws of such jurisdiction;

     (iii) an electronic confirmation from the Secretary of State or other applicable Governmental Authority of each jurisdiction in which each such Loan Party is organized certifying that such Loan Party is duly organized and in good standing under the laws of such jurisdiction on the date of the initial extension of credit; prepared by, or on behalf of, a filing service acceptable to the Administrative Agent; and

     (iv) a copy of a certificate of the Secretary of State or other applicable Governmental Authority of the States of Colorado, and Nevada, as applicable, dated reasonably near the date of the initial extension of credit, stating that each Loan Party is duly qualified and in good standing as a foreign corporation or entity in each such jurisdiction and has filed all annual reports required to be filed to the date of such certificate; and electronic confirmation, from the Secretary of State or other applicable Governmental Authority of each such jurisdiction on the date of the initial extension of credit as to the due qualification and continued good standing of each such Person as a foreign corporation or entity in each such jurisdiction on or about such date, prepared by, or on behalf of, a filing service acceptable to the Administrative Agent.

     (m) Legal Opinions. The Administrative Agent shall have received the following executed legal opinions:

     (i) the legal opinion of Krys Boyle, PC, counsel to the Loan Parties, with respect to such matters as may be reasonably requested by the Administrative Agent, and in form and substance satisfactory to the Administrative Agent; and

     (ii) the legal opinion of special Wyoming counsel to the Loan Parties, with respect to such matters as may be reasonably requested by the Administrative Agent, and in form and substance satisfactory to the Administrative Agent.

     (n) Pledged Stock; Stock Powers; Acknowledgment and Consent; Pledged Notes. The Administrative Agent shall have received (i) the certificates representing the shares of Capital Stock pledged pursuant to the Guarantee and Security Agreement, together with an undated stock power for each such certificate executed in blank by a duly authorized officer of the pledgor thereof, (ii) in the case of Capital Stock that is a “security” (as defined in the UCC) but is not evidenced by a certificate, an Instructions Agreement, substantially in the form of Annex I to the Guarantee and Security Agreement, duly executed by any issuer of Capital Stock pledged pursuant to the Guarantee and Security Agreement and (iii) each promissory note pledged pursuant to the Guarantee and Security Agreement endorsed (without recourse) in blank (or accompanied by an executed transfer form in blank satisfactory to the Administrative Agent) by the pledgor thereof.

     (o) Specified Vehicles. The Administrative Agent shall have received certificates of title for each of the Specified Vehicles.

     (p) Lender Consents. Each of the Lenders shall have received all internal consents and approvals necessary for the consummation of the transactions contemplated by this Agreement and the Security Documents.

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     (q) No Material Adverse Effect. Except as set forth on Schedule 3.2, since December 31, 2006, no development, event or circumstance that has had or could reasonably be expected to have a Material Adverse Effect shall have occurred and be continuing.

     (r) Filings, Registrations and Recordings. Each document (including any Uniform Commercial Code financing statement) required by the Security Documents or under law or reasonably requested by the Administrative Agent to be filed, registered or recorded in order to create in favor of the Administrative Agent, for the benefit of the Secured Parties, a perfected Lien on the Collateral described therein, prior and superior in right to any other Person (other than with respect to Permitted Liens), shall have been filed, registered or recorded or shall have been delivered to the Administrative Agent in proper form for filing, registration or recordation.

     (s) Insurance. The Administrative Agent shall have received a summary of the insurance carried in respect of each Loan Party and its Properties, including copies of all relevant insurance policies (which insurance shall be for such amounts, against such risk, covering such liabilities and with such deductibles or self-insured retentions as are acceptable to the Administrative Agent) and certificates of insurance, satisfying the requirements of Section 5.3 of the Guarantee and Security Agreement and otherwise reasonably satisfactory to the Administrative Agent, naming the Administrative Agent, for the ratable benefit of the Secured Parties, as “lender loss payee” under its property loss policies and as “additional insured” on its comprehensive and general policies.

     (t) Due Diligence. The Administrative Agent shall have completed a satisfactory due diligence review of the Loan Parties, including business prospects, title to properties, tax, legal and accounting issues. The Lenders shall have completed a satisfactory due diligence review of Borrower, including its business prospects, title to its properties and tax, legal and accounting issues.

     (u) Material Agreements. The Administrative Agent shall have received a true, correct and complete copy, certified as to such by a Responsible Officer of the applicable Loan Parties, of each material agreement.

     (v) Representations and Warranties. Each of the representations and warranties made by any Loan Party in or pursuant to any Loan Document or Acquisition Document shall be true and correct on and as of the Closing Date or, with respect to any representations and warranties that are by their express terms made as of a specified earlier date, on and as of such earlier date.

     (w) No Default. No Default or Event of Default shall have occurred and be continuing on such date or after giving effect to the Loans requested to be made under this Agreement on the Closing Date.

     (x) No Collateral Value Deficiency. No Collateral Value Deficiency shall exist as of the Closing Date nor would any Collateral Value Deficiency exist after giving effect to the extensions of credit requested to be made on such date.

     (y) Additional Documents. The Administrative Agent and the Lenders shall have received such other documents, agreements, certificates and information as such Persons shall reasonably request.

     4.2 Conditions Deemed Fulfilled. Except to the extent that Borrower has disclosed in the Borrowing Notice that an applicable condition specified in Section 4.1 will not be satisfied as of the requested time for the making of any Loan, Borrower shall be deemed to have made a representation and warranty as of such time that the conditions specified in Section 4.1 have been satisfied. No such disclosure by Borrower that a condition specified in Section 4.1 will not be satisfied as of the requested

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time for the making of the requested Loans shall affect the right of each Lender not to make the Loans requested to be made by it if such condition has not been satisfied at such time.

ARTICLE V
AFFIRMATIVE COVENANTS

     Each of Holdings and Borrower hereby jointly and severally agree that, so long as the Commitments remain in effect, or any Loan or other amount is owing to any Lender or any Agent hereunder, each of Holdings and Borrower shall, and shall cause each of its Subsidiaries to:

     5.1 Financial Statements. Furnish to each Agent and each Lender by physical means or, if requested by the Administrative Agent, electronically via the Administrative Agent’s proprietary transmission software and date collection method:

     (a) as soon as available, but in any event within 90 days after the end of each fiscal year of Holdings, commencing with the 2007 fiscal year, a copy of the audited consolidated balance sheet of Holdings and its consolidated Subsidiaries as at the end of such year and the related audited consolidated statements of income and of cash flows for such year, setting forth in each case in comparative form the figures as of the end of and for the previous year, reported on without a “going concern” or like qualification or exception, or qualification arising out of the scope of the audit, by the Independent Accountants;

     (b) as soon as available, but in any event not later than 45 days after the end of each quarterly period of each fiscal year of Holdings, the unaudited consolidated balance sheet of Holdings and its consolidated Subsidiaries as at the end of such quarter and the related unaudited consolidated statements of income and of cash flows for such quarter and the portion of the fiscal year through the end of such quarter, setting forth in each case in comparative form the figures as of the end of and for the corresponding period in the previous year, certified by a Responsible Officer as being fairly stated in all material respects (subject to normal year-end audit adjustments); and

     (c) as soon as available, but in any event not later than 30 days after the end of each calendar month commencing on January 30, 2008, the unaudited consolidated balance sheets of Borrower and its Subsidiaries as at the end of such month and the related unaudited consolidated statements of income and of cash flows for such month and the portion of the fiscal year through the end of such month, setting forth in each case in comparative form the figures as of the end of and for the corresponding period in the previous year, certified by a Responsible Officer as being fairly stated in all material respects (subject to normal year-end audit adjustments);

     (d) as soon as available, but in any event not later than 30 days after the end of each calendar month commencing on January 30, 2008, a schedule of the contract status of each Rig which schedule shall include in sufficient detail the marketing prospects for each Rig; and

     (e) promptly upon Borrower’s having knowledge that a Collateral Value Deficiency exists, or is likely to exist, written notice thereof (if not previously provided in a certificate delivered pursuant to Section 5.3(a)), together with a written plan to cure such deficiency by the end of the fiscal quarter in which such plan was delivered, which plan shall be satisfactory in form and substance to the Administrative Agent;

all such financial statements to be complete and correct in all material respects and to be prepared in reasonable detail and in accordance with GAAP applied consistently throughout the periods reflected therein and with prior periods (except as approved by the Independent Accountants or officer, as the case

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may be, and disclosed therein, and quarterly financial statements shall be subject to normal year-end audit adjustments and need not be accompanied by footnotes).

     5.2 Collateral Reporting. Furnish to the Administrative Agent:

     (a) (i) on or before each June 30 of each year, beginning June 30, 2008, a Rig Appraisal dated as of each preceding May 1 (or dated later if available) and (ii) promptly upon written request by the Administrative Agent, a Rig Appraisal; provided that unless a Default or an Event of Default shall then exist, the Administrative Agent may request, at Borrower’s cost and expense, no more than one such Rig Appraisals during any 12-month period, with any additional requests for updated Rig Appraisal during any such period to be at the Administrative Agent’s cost and expense, and after the occurrence and during the continuance of a Default or Event of Default, the Administrative Agent may, from time to time, request a Rig Appraisal at the sole cost and expense of Borrower, in each case dated as of the first day of the month during which Borrower receives such request;

     (b) reports, certifications, engineering studies, environmental assessments or other written material or data requested by, and in form, scope and substance reasonably satisfactory to, the Administrative Agent or the Required Lenders, in the event that Administrative Agent or the Required Lenders at any time have a reasonable basis to believe that there may be a material violation of any Environmental Law or a condition at any Property owned, operated or leased by any Loan Party that could reasonably give rise to a Material Adverse Effect, or if an Event of Default has occurred and is continuing; provided that if any Loan Party fails to provide such reports, certifications, engineering studies or other written material or data within 75 days after the request of the Administrative Agent or the Required Lenders, the Administrative Agent shall have the right, at such Loan Party’s sole cost and expense, to conduct such environmental assessments or investigations as may reasonably be required to enable the Administrative Agent and the Required Lenders to determine whether each of the Loan Parties is in material compliance with Environmental Laws;

     (c) prior to any Asset Sale, a notice (i) describing such Asset Sale or the nature and material terms and conditions of such transaction and (ii) stating the estimated Net Cash Proceeds anticipated to be received by any Loan Party;

     (d) as soon as is practicable following the written request of the Administrative Agent and in any event within 60 days after the end of each fiscal year, (i) a report in form and substance satisfactory to the Administrative Agent and the Lenders outlining all material insurance coverage maintained as of the date of such report by each Loan Party and the duration of such coverage and (ii) an insurance broker’s statement that all premiums then due and payable with respect to such coverage have been paid and confirming that the Administrative Agent has been named as loss payee or additional insured, as applicable; and

     (e) upon reasonable request by the Administrative Agent, such other reports as to the Collateral or the financial condition of the Loan Parties as may be so requested.

     5.3 Certificates; Other Information. Furnish to each Agent and each Lender or, in the case of clause (h) to the relevant Lender or Agent or, in the case of clause (i), to the relevant Lender:

     (a) concurrently with the delivery of the financial statements referred to in Section 5.1(a), a certificate of the independent certified public accountants reporting on such financial statements stating that in making the examination necessary therefor no knowledge was obtained of any Default or Event of Default, except as specified in such certificate (it being understood that such certificate shall be limited to

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the items that independent certified public accountants are permitted to cover in such certificates pursuant to their professional standards and customs of the profession);

     (b) concurrently with the delivery of any financial statements pursuant to Section 5.1, (i) a certificate of a Responsible Officer stating that, to the best of such Responsible Officer’s knowledge, each Loan Party during such period has observed or performed all of its covenants and other agreements, and satisfied every condition, contained in this Agreement and the other Loan Documents to which it is a party to be observed, performed or satisfied by such Loan Party, and that such Responsible Officer has obtained no knowledge of (A) any Default or Event of Default or (B) the existence of a Collateral Value Deficiency, in each case except as specified in such certificate and (ii) in the case of quarterly or annual financial statements, a Compliance Certificate containing all information and calculations necessary for determining compliance by the Loan Parties with the provisions of this Agreement referred to therein as of the last day of the fiscal quarter or fiscal year of Holdings, as the case may be, and authorization to file any UCC financing statements or other filings specified in such Compliance Certificate as being required to be delivered therewith;

     (c) as soon as available, and in any event no later than 45 days after the end of each fiscal year of Borrower, a detailed consolidated budget for the following fiscal year (including a projected consolidated balance sheet of Borrower and its Subsidiaries as of the end of the following fiscal year, and the related consolidated statements of projected cash flow, projected changes in financial position and projected income and a description of the underlying assumptions applicable thereto), and, as soon as available, significant revisions, if any, of such budget and projections with respect to such fiscal year (collectively, the “Projections”), which Projections shall in each case be accompanied by a certificate of a Responsible Officer stating that such Projections are based on reasonable estimates, information and assumptions and that such Responsible Officer has no reason to believe that such Projections are incorrect or misleading in any material respect;

     (d) as soon as possible and in any event within five days of obtaining knowledge thereof: (i) notice of any development, event, or condition that, individually or in the aggregate with other developments, events or conditions that, individually or in the aggregate, could reasonably be expected to result in the payment by the Loan Parties in the aggregate, of a Material Environmental Amount; and (ii) any notice that any Governmental Authority has taken action to or may deny any application for an Environmental Permit or other Material Permit sought by, or revoke or refuse to renew any such Permit held by any Loan Party or condition approval of any such Permit on terms and conditions if the effect of any such action would have a material adverse effect on any Loan Party, or to the operation of any of its businesses or any property owned, leased or otherwise operated by such Person;

     (e) promptly after becoming aware of the same, written notice of (i) any material labor dispute to which either Loan Party is or may become a party, including any strikes, lockouts or other disputes relating to any of such Person’s plants and other facilities, and (ii) any Worker Adjustment and Retraining Notification Act or related liability incurred with respect to the closing of any plant or other facility of any of such Person that would reasonably be expected to have a Material Adverse Effect;

     (f) within five Business Days after receipt thereof by any Loan Party, copies of each final management letter, exception report or similar letter or report received by such Loan Party from its Independent Accountant;

     (g) within 45 days after the end of each fiscal quarter of Borrower, a narrative discussion and analysis of the financial condition and results of operations of Borrower and its Subsidiaries for such fiscal quarter and for the period from the beginning of the then current fiscal year to the end of such fiscal

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quarter, as compared to the portion of the Projections covering such periods and to the comparable periods of the previous year;

     (h) if requested by any Lender or Agent, a statement to the effect specified in Section 3.12 in conformity with the requirements of FR Form G-3 or FR Form U 1 referred to in Regulation U; and

     (i) promptly, such additional financial and other information as the Administrative Agent or any Lender may from time to time reasonably request.

     5.4 Payment of Obligations. Pay, discharge or otherwise satisfy at or before maturity or before they become delinquent, as the case may be, all its material obligations of whatever nature, except where the amount or validity thereof is currently being contested in good faith by appropriate proceedings and reserves in conformity with GAAP with respect thereto have been provided on the books of the Loan Party obligated therefor.

     5.5 Conduct of Business and Maintenance of Existence, etc.

     (a) (i) Preserve, renew and keep in full force and effect its corporate or other existence and (ii) take all reasonable action to maintain all rights, privileges, franchises, Permits and licenses necessary or desirable in the normal conduct of its business, except, in each case, as otherwise permitted by Section 6.4 and except, in the case of clause (ii) above, to the extent that failure to do so could not reasonably be expected to have a Material Adverse Effect.

     (b) To the extent not in conflict with this Agreement or the other Loan Documents, comply with all (i) Contractual Obligations and Constituent Documents and (ii) Permits and Requirements of Law, and use its reasonable efforts to cause all employees, crew members, agents, contractors and subcontractors of any Loan Party to comply with all Permits and Requirements of Law as may be necessary or appropriate to enable such Loan Party so to comply, except, in the case of Contractual Obligations, Permits and Requirements of Law, where the failure to comply could not reasonably be expected to result in a Material Adverse Effect.

     5.6 Operation and Maintenance of Property; Insurance.

     (a) Keep, preserve and maintain all Property and systems, including all improvements, personal property and equipment, useful and necessary in its business in good working order and condition in accordance with the general practice of other businesses of similar character and size (ordinary wear and tear excepted) and make all necessary repairs, renewals and replacements so that its business may be property conducted at all times

     (b) Operate or cause to be operated the Drilling Rig Assets in a good and workman-like manner.

     (c) Maintain with financially sound and reputable insurance companies insurance on all its Property meeting the requirements of the Guarantee and Security Agreement and in at least such amounts and against at least such risks (but including in any event general liability) as are usually insured against in the same general area by companies engaged in the same or a similar business, with such deductibles as are reasonably acceptable to the Administrative Agent.

     (d) Name the Administrative Agent, for the ratable benefit of the Secured Parties, as “loss payee” under its casualty loss policies and the Administrative Agent as “additional insured” on its comprehensive and general liability policies and cause all such casualty loss policies to be reasonably

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satisfactory to the Administrative Agent in all respects and provide that they shall not be canceled, amended or changed without at least 30 days’ (ten days for nonpayment) written notice to the Administrative Agent, it being understood, however, that, so long as no Event of Default has occurred and is continuing, Net Cash Proceeds of any insurance policies shall be applied in accordance with Sections 2.7 and 2.9.

     (e) Renew all insurance policies referred to in this Section 5.6 on terms no less favorable to the Administrative Agent for the ratable benefit of the Secured Parties during the term of this Agreement and cause any substitute underwriter to be, in Borrower’s reasonable opinion, as financially sound as Borrower’s existing underwriters.

     5.7 Inspection of Property; Books and Records; Discussions.

     (a) Keep proper books of records and account in which full, true and correct entries in conformity with GAAP and all Requirements of Law shall be made of all dealings and transactions in relation to its business and activities.

     (b) Permit the Administrative Agent and the Lenders, or any agents or representatives thereof, from time to time during Borrower’s normal business hours, as often as may be reasonably requested and upon two Business Days notice (except that, during the continuance of an Event of Default, no such notice shall be required) to (i) go upon, examine, inspect and remain on the Properties of any Loan Party, (ii) during any such visit, inspect and verify the amount, character and condition of any of the Property of any Loan Party, (iii) during any such visit, examine and, at Borrower’s cost and expense, make copies of and abstracts from the records and books of account of any Loan Party, and (iv) discuss the affairs, finances and accounts of any Loan Party with any of their respective officers, directors, employees or Independent Accountants, it being understood that, except as otherwise stated in clause (iii) above, the Administrative Agent and each Lender will pay the costs and expenses incurred by it in exercising its rights under this Section 5.7(b); provided that after the occurrence of an Event of Default, Borrower shall reimburse the Administrative Agent and each Lender promptly after a request therefor for the reasonable costs and expenses incurred by it in connection with the exercise of its rights under this Section 5.7(b).

     (c) Authorize the Independent Accountants of Holdings or Borrower to disclose to the Administrative Agent or any Lender any and all financial statements and other information of any kind, as the Administrative Agent or any Lender reasonably requests from of Holdings or Borrower and which the Independent Accountants may have with respect to the business, financial condition, results of operations or other affairs of any Loan Party.

     5.8 Notices. Promptly, and in any event within three Business Days after Borrower’s knowledge thereof, give notice to the Administrative Agent and each Lender of:

     (a) the occurrence of any Default or Event of Default;

     (b) any (i) default or event of default (or alleged default) under any Contractual Obligation of any Loan Party or (ii) litigation, investigation or proceeding which may exist at any time between any Loan Party and any Governmental Authority, that in case of clause (i) or (ii), if not cured or if adversely determined, as the case may be, could reasonably be expected to have a Material Adverse Effect;

     (c) any litigation or proceeding affecting any Loan Party in which the amount involved that is not covered by insurance is $100,000 or more or in which injunctive or similar relief is sought;

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     (d) the following events, as soon as possible and in any event within 30 days after Holdings or Borrower knows or has reason to know thereof: (i) the occurrence of any Reportable Event with respect to any Benefit Plan, a failure to make any required contribution to a Benefit Plan, the creation of any Lien in favor of the PBGC or a Benefit Plan or any withdrawal from, or the termination, Reorganization or Insolvency of, any Multiemployer Plan, (ii) the institution of proceedings or the taking of any other action by the PBGC or any Loan Party or any Commonly Controlled Entity or any Multiemployer Plan with respect to the withdrawal from, or the termination, Reorganization or Insolvency of, any Benefit Plan or (iii) proceedings that have been instituted pursuant to Section 515 of ERISA to collect a delinquent contribution to a Benefit Plan, that Borrower or any Commonly Controlled Entity will or may incur any material liability (including any indirect, contingent or secondary liability) to or on account of a termination or withdrawal from a Benefit Plan under Title IV of ERISA or with respect to a Benefit Plan under Section 401(a)(29) or 4971, 4975, or 4980 of the Code or Section 409, 502(i) or 503(l) of ERISA or with respect to a group health plan (as defined in Section 607(1) of ERISA or Section 4980B of the Code) under Section 4890B of the Code, or that Borrower or a Commonly Controlled Entity will incur any material liability pursuant to an employee welfare benefit plan that provides benefits to retired employees or former employees (other than as required under Section 601 of ERISA) or any Benefit Plan;

     (e) any development or event that has had or could reasonably be expected to have a Material Adverse Effect; and

     (f) the audit or examination of any Tax Return by any Governmental Authority, the receipt by any Loan Party of notice of any such audit or examination or the assertion of any claim for taxes against any Loan Party by any Governmental Authority.

Each notice pursuant to this Section 5.8 shall be accompanied by a statement of a Responsible Officer setting forth details of the occurrence referred to therein and stating what action any Loan Party proposes to take with respect thereto.

     5.9 Environmental Laws.

     (a) Comply in all material respects with, and ensure compliance in all material respects at any Property owned, leased or operated by any Loan Party by all tenants, subtenants, lessees, sub-lessees, operators and contractors, if any, with, all applicable Environmental Laws and Environmental Permits, and obtain and comply in all material respects with and maintain, and ensure that all tenants, subtenants, lessees, sub-lessees, operators and contractors to obtain and comply in all material respects with and maintain, any and all Environmental Permits required by applicable Environmental Laws with respect to any Property owned, leased or operated by any Loan Party.

     (b) Conduct and complete all investigations, studies, sampling and testing, and all reporting, investigative, remedial, removal and other actions required under Environmental Laws as a result of a release of or the discovery of Materials of Environmental Concern, and promptly comply in all material respects with all lawful orders and directives of all Governmental Authorities regarding Environmental Laws.

     (c) As soon as available, and in any case within five Business Days prior to the closing of any acquisition of Property by a Loan Party for which Borrower reasonably believes that liability of any Loan Party for environmental remediation potentially associated with the ownership or operation of all such Property (exclusive of usual and customary platform maintenance, refurbishment and abandonment obligations) is expected to exceed a Material Environmental Amount, deliver to the Administrative Agent

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an environmental report covering such Property to be acquired, in form and substance reasonably satisfactory to the Administrative Agent and the Required Lenders.

     (d) Promptly, but in no event later than five days of the occurrence of a triggering event, notify the Administrative Agent in writing of any threatened action, investigation or inquiry by any Governmental Authority or any demand or threatened lawsuit by any landowner or other third party against any Loan Party or its Properties of which Holdings or Borrower has knowledge in connection with any Environmental Laws (excluding routine testing and corrective action) if Holdings or Borrower reasonably anticipates that such action may result in liability (whether individually or in the aggregate) in excess of $100,000.

     (e) Establish and implement such procedures as may be necessary to continuously determine and assure that the obligations of each Loan Party under this Section 5.9 are timely and fully satisfied.

     5.10 Additional Collateral, etc.

     (a) With respect to any Property (other than Real Property) acquired after the Closing Date by any Loan Party as to which the Administrative Agent, for the benefit of the Secured Parties, does not have a perfected Lien and security interest, promptly (i) execute and deliver to the Administrative Agent such Security Documents or amendments to Security Documents as the Administrative Agent deems necessary or advisable to grant to the Administrative Agent, for the benefit of the Secured Parties, a security interest in such Property, (ii) take all actions necessary or advisable to grant to the Administrative Agent, for the benefit of the Secured Parties, a perfected first priority Lien and security interest in such Property (subject only to Permitted Liens), including the execution and delivery by all necessary third parties of any Deposit Account Control Agreements and Mortgages, the filing of UCC financing statements in such jurisdictions as may be required by the Security Documents or by law, the filing of any Mortgages in appropriate filing offices and the making of any other filings required by law or as may be reasonably requested by the Administrative Agent and (iii) deliver to the Administrative Agent such legal opinions relating to the matters described in clauses (i) and (ii) immediately preceding as the Administrative Agent may reasonably request, which opinions shall be in form and substance, and from counsel, reasonably satisfactory to the Administrative Agent; provided that unless a Property is acquired for a purchase price or other consideration in excess of $250,000, Borrower shall not be required to take the actions specified in this Section 5.10(a) prior to the end of the fiscal quarter in which the acquisition occurs, or if earlier, the date at which the cumulative amount of purchase price or other consideration for all Property acquired in such quarter equals or exceeds $250,000, at which time all Property theretofore acquired and not previously made subject to a Lien in favor of the Administrative Agent shall be made so subject.

     (b) With respect to any fee interest in any Real Property acquired after the Closing Date by any Loan Party (other than any such real property acquired for an aggregate consideration valued at less than $100,000), promptly (i) execute and deliver a first priority Mortgage (subject only to Permitted Liens) in favor of the Administrative Agent, for the benefit of the Secured Parties, covering such real property and designating thereon the appropriate recording office, (ii) if requested by the Administrative Agent, provide the Administrative Agent with (A) title and extended coverage insurance covering such real property in an amount at least equal to the purchase price of such real property (or such other amount as shall be reasonably specified by the Administrative Agent) as well as a current ALTA or ALTAX survey thereof, together with a surveyor’s certificate, (B) any consents or estoppels reasonably deemed necessary or advisable by the Administrative Agent in connection with such Mortgage, each of the foregoing in form and substance reasonably satisfactory to the Administrative Agent and (C) if requested by the Administrative Agent, deliver to the Administrative Agent legal opinions relating to the matters

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described above, which opinions shall be in form and substance, and from counsel, reasonably satisfactory to the Administrative Agent.

     (c) With respect to any new Subsidiary created or acquired by any Loan Party or otherwise becoming a Subsidiary after the Closing Date, concurrently with such creation, acquisition or becoming a Subsidiary, (i) execute and deliver to the Administrative Agent such Security Documents or amendments to Security Documents as the Administrative Agent deems necessary or advisable to grant to the Administrative Agent, for the benefit of the Secured Parties, a perfected first priority Lien and security interest in the Capital Stock of such new Subsidiary that is owned by any Loan Party, (ii) deliver to the Administrative Agent (A) the certificates (if any) representing such Capital Stock, together with undated powers, in blank, executed and delivered by a duly authorized officer of the Loan Party owning such Capital Stock and (B) in the case of a Subsidiary whose Capital Stock is a security that is not evidenced by certificates, an Instructions Agreement, substantially in the form of Annex A to the Guarantee and Security Agreement, duly executed by such Subsidiary and each Loan Party owning such Capital Stock, (iii) cause such new Subsidiary (A) to become a party to the Guarantee and Security Agreement and any other applicable Security Documents (including Mortgages and Deposit Account Control Agreements) and (B) to take such other actions as are necessary or advisable to grant to the Administrative Agent for the benefit of the Secured Parties a perfected first priority Lien and security interest in the Collateral described in the Guarantee and Security Agreement with respect to such new Subsidiary and, pursuant to Mortgages and Deposit Account Control Agreements, all bank accounts owned by such Subsidiary, subject in each case only to Permitted Liens, including the execution and delivery by all necessary third parties of any Deposit Account Control Agreements and Mortgages, the filing of UCC financing statements in such jurisdictions as may be required by the Guarantee and Security Agreement or by law, the filing of any Mortgages in appropriate filing offices and the making of any other filings required by law or as may be requested by the Administrative Agent, and (iv) if requested by the Administrative Agent, deliver to the Administrative Agent legal opinions (including Title Opinions) relating to the matters described above, which opinions shall be in form and substance, and from counsel, reasonably satisfactory to the Administrative Agent.

     (d) Notwithstanding anything to the contrary in this Section 5.10, paragraphs (a), (b) and (c) of this Section 5.10 shall not apply to any Property or new Subsidiary created or acquired after the Closing Date, as applicable, as to which the Administrative Agent has determined in its sole discretion that the collateral value thereof is insufficient to justify the difficulty, time or expense of obtaining a perfected security interest therein.

     5.11 Use of Proceeds. Use the proceeds of the Loans only for the purposes specified in Section 3.17.

     5.12 ERISA Documents. Cause to be delivered to the Administrative Agent, promptly upon the Administrative Agent’s request, any or all of the following: (i) a copy of each Benefit Plan (or, where any such Benefit Plan is not in writing, a complete description thereof) and, if applicable, related trust agreements or other funding instruments and all amendments thereto, and all written interpretations thereof and written descriptions thereof that have been distributed to employees or former employees of any Loan Party; (ii) the most recent determination letter issued by the Internal Revenue Service with respect to each Benefit Plan; (iii) for the three most recent plan years preceding the Administrative Agent’s request, Annual Reports on Form 5500 Series required to be filed with any governmental agency for each Benefit Plan; (iv) a listing of all Multiemployer Plans, with the aggregate amount of the most recent annual contributions required to be made by any Loan Party or any Commonly Controlled Entity to each such Benefit Plan and copies of the collective bargaining agreements requiring such contributions; (v) any information that has been provided to any Loan Party or any Commonly Controlled Entity regarding withdrawal liability under any Multiemployer Plan; (vi) the aggregate amount of payments

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made under any employee welfare benefit plan (as defined in Section 3(1) of ERISA) to any retired employees of any Loan party (or any dependents thereof) during the most recently completed fiscal year; and (vii) documents reflecting any agreements between the PBGC and any Loan Party or any Commonly Controlled Entity with respect to any Benefit Plan.

     5.13 Further Assurances.

     (a) From time to time execute and deliver, or cause to be executed and delivered, such additional instruments, certificates or documents, and take all such actions, as the Administrative Agent may reasonably request for the purposes of implementing or effectuating the provisions of this Agreement and the other Loan Documents, or of more fully perfecting or renewing the rights of the Administrative Agent and the Lenders with respect to the Collateral (or with respect to any additions thereto or replacements or proceeds or products thereof or with respect to any other Property hereafter acquired by any Loan Party, which may be deemed to be part of the Collateral) pursuant hereto or thereto.

     (b) Upon the exercise by the Administrative Agent or any Lender of any power, right, privilege or remedy pursuant to this Agreement or the other Loan Documents which requires any consent, approval, recording, qualification or authorization of any Governmental Authority, execute and deliver, or cause the execution and delivery of, all applications, certifications, instruments and other documents and papers that the Administrative Agent or such Lender may be required to obtain from Borrower or any of its Subsidiaries for such governmental consent, approval, recording, qualification or authorization.

     (c) Preserve and protect the Lien status of each respective Mortgage and, if any Lien (other than unrecorded Liens permitted under Section 6.3 that arise by operation of law) is asserted against a Mortgaged Property, promptly and at its expense, give the Administrative Agent a detailed written notice of such Lien and pay the underlying claim in full or take such other action so as to cause it to be released or bonded over in a manner satisfactory to the Administrative Agent.

     5.14 Patriot Act Compliance. Provide such information and take such actions as are reasonably required by the Agents or any Lender in order to assist the Agents and Lenders with compliance with the Patriot Act.

     5.15 Post-Closing Delivery. As soon as available and in any event on or prior to January 30, 2008, Borrower shall deliver, or cause to be delivered, to the Administrative Agent each of the following:

     (a) an executed legal opinion from special Wyoming counsel to the Loan Parties, reasonably acceptable to the Administrative, with respect to such matters, and in form and substance, reasonably acceptable to the Administrative Agent; (b) each Access Agreement; and each Deposit Account Control Agreement.

NEGATIVE COVENANTS

     Unless the Administrative Agent has provided Holdings and Borrower with prior written consent for such actions, each of Holdings and Borrower hereby jointly and severally agree that, so long as the Commitments remain in effect, any Loan or other amount is owing to any Lender or any Agent hereunder, each of Holdings and Borrower shall not, and shall not permit any of its Subsidiaries to, directly or indirectly:

     6.1 Financial Condition Covenants.

     (a) Minimum Consolidated EBITDA. Permit the Consolidated EBITDA for any period of four consecutive fiscal quarters of Borrower ending with any fiscal quarter to be less than $20,000,000.

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     (b) Consolidated Leverage Ratio. Permit the Consolidated Leverage Ratio as at the last day of any period of four consecutive fiscal quarters of Borrower to exceed 3.5:1.0.

     (c) Consolidated Interest Coverage Ratio. Permit the Consolidated Interest Coverage Ratio for any period of four consecutive fiscal quarters of Borrower to be less than 2.5:1.0.

     (d) Minimum Current Ratio. Permit the Current Ratio at the end of any fiscal quarter to be less than 1.0 to 1.0.

     6.2 Indebtedness. Create, incur, assume, issue, guaranty or suffer to exist any Indebtedness, except for the following (“Permitted Indebtedness”):

     (a) Indebtedness of any Loan Party pursuant to any Loan Document;

     (b) Indebtedness of Borrower to any Subsidiary Guarantor and of any Wholly Owned Subsidiary Guarantor to Borrower or any other Subsidiary Guarantor;

     (c) Indebtedness of Borrower or any Subsidiary Guarantor (including Capital Lease Obligations) secured by Liens permitted by Section 6.3(f) in an aggregate principal amount not to exceed $500,000 at any one time outstanding;

     (d) Guarantee Obligations made in the ordinary course of business by Borrower or any of its Subsidiaries of obligations of Borrower or any Subsidiary Guarantor;

     (e) unsecured current accounts payable incurred in the ordinary course of business which are (i) outstanding for not more than 90 days past the original invoice or billing date thereof or (ii) being contested in good faith by appropriate proceedings, if such reserve as may be required by GAAP shall have been made therefor;

     (f) extensions of credit from suppliers or contractors who are not Affiliates of Borrower for the performance of labor or services or the provision of supplies or materials under applicable contracts or agreements in connection with Borrower’s or any Subsidiary’s oil and gas exploration and development activities, which are not more than 60 days overdue or are being contested in good faith by appropriate proceedings, if such reserves as may be required by GAAP shall have been made therefor; and

     (g) Indebtedness subordinated in all respects to the Obligations and otherwise on terms and provisions acceptable to the Administrative Agent.

     6.3 Liens. Create, incur, assume or suffer to exist any Lien upon any of its Property, whether now owned or hereafter acquired, except for:

     (a) Liens for taxes not yet due or which are being contested in good faith by appropriate proceedings, provided that adequate reserves with respect thereto are maintained on the books of the applicable Loan Party in conformity with GAAP;

     (b) carriers’, warehousemen’s, mechanics’, materialmen’s, repairmen’s or other like Liens arising in the ordinary course of business which are not overdue for a period of more than 30 days or that are being contested in good faith by appropriate proceedings and for which adequate reserves with respect thereto are maintained in the books of the applicable Loan Party in conformity with GAAP; provided that at no time shall such sums being contested exceed individually or in the aggregate $250,000;

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     (c) pledges or deposits in connection with workers’ compensation, unemployment insurance and other social security legislation;

     (d) deposits by or on behalf of Borrower or any of its Subsidiaries to secure the performance of bids, trade contracts (other than for borrowed money), leases, statutory obligations, plugging and abandoning surety and appeal bonds, performance bonds and other obligations of a like nature incurred in the ordinary course of business, so long as the aggregate amount of such deposits at any one time does not exceed $250,000;

     (e) encumbrances consisting of easements, restrictions, servitudes, permits, conditions, covenants, exceptions or reservations in any Property of Borrower or any of its Subsidiaries for the purpose of roads, pipelines, transmission lines, transportation lines, distribution lines for the removal of gas, oil, coal or other minerals and other like purposes, that, do not secure Indebtedness or other monetary obligations and, in the aggregate, are not substantial in amount and do not materially impairs the use of such property by any Loan Party in the operation of its business and which do not in any case materially detract from the value of the Property subject thereto are or would be violated in any material respect by existing or proposed operations of any Loan Party;

     (f) Liens securing Indebtedness of Borrower or any of its Subsidiaries incurred pursuant to Section 6.2(c) to finance the acquisition, construction or improvement of fixed or capital assets (other than Drilling Rig Assets); provided that (i) such Liens and the Indebtedness secured thereby shall be created substantially simultaneously with the acquisition, construction or improvement of such fixed or capital assets, (ii) such Liens do not at any time encumber any Property other than the Property financed by such Indebtedness, (iii) the amount of Indebtedness secured thereby is not increased and (iv) the amount of Indebtedness initially secured thereby is not more than 100% of the purchase price or cost of construction or improvement of such fixed or capital asset;

     (g) Liens created pursuant to the Security Documents;

     (h) any interest or title of a lessor under any lease entered into by Borrower or any of its Subsidiaries in the ordinary course of its business and covering only the assets so leased;

     Liens not securing Indebtedness arising solely by virtue of any statutory or common law provision relating to banker’s liens, rights of set-off or similar rights and remedies and burdening only deposit accounts or other funds maintained with a creditor depository institution, provided that no such deposit account is a dedicated cash collateral account or is subject to restrictions against access by the depositor in excess of those set forth by regulations promulgated by the Board and no such deposit account is intended by any Loan Party to provide collateral to the depository institution.

     6.4 Fundamental Changes. Enter into any merger, consolidation, restructuring, recapitalization, reorganization or amalgamation, or liquidate, wind up or dissolve itself (or suffer any liquidation or dissolution), Dispose of all or substantially all of its Property or business or amend, modify or otherwise change its name, jurisdiction of organization, organizational number, identification number or FEIN, except that, if no Default shall have occurred and be continuing:

     (a) any Subsidiary of Borrower may be merged or consolidated with or into Borrower (provided that Borrower shall be the continuing or surviving entity) or with or into any Wholly Owned Subsidiary Guarantor (provided that (i) such Subsidiary Guarantor shall be the continuing or surviving entity or (ii) simultaneously with such transaction, the continuing or surviving entity shall become a Subsidiary Guarantor and Borrower shall comply with Section 5.10 in connection therewith); and

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     (b) any Subsidiary of Borrower may Dispose of any or all of its assets (upon voluntary liquidation or otherwise) to Borrower or any Wholly Owned Subsidiary Guarantor; and

     (c) the Capital Stock of any Subsidiary may be transferred to Borrower or any other Wholly-Owned Subsidiary Guarantor.

     6.5 Disposition of Property. Dispose of any of its Property (including, receivables and leasehold interests), whether now owned or hereafter acquired, or, in the case of any direct or indirect Subsidiary of Holdings, issue or sell any shares of such Subsidiary’s Capital Stock (including pursuant to any merger, consolidation, restructuring, recapitalization, reorganization or amalgamation) to any Person, except:

     (a) the Disposition of obsolete or worn out property in the ordinary course of business;

     (b) Dispositions permitted by Section 6.4(b);

     (c) the sale or issuance of any Subsidiary’s Capital Stock to Borrower or any Wholly Owned Subsidiary Guarantor;

     (d) subject to compliance with Section 2.7(a), the issuance of Capital Stock of Holdings for cash;

     (e) Dispositions of claims against customers, other industry partners or any other Person in connection with workouts or bankruptcy, insolvency or other similar proceedings with respect thereto; and

     (f) any Recovery Event, provided that the requirements of Section 2.7(b) are complied with in connection therewith.

     6.6 Restricted Payments. Declare or pay any dividend on, or make any payment on account of, or set apart assets for a sinking or other analogous fund for, the purchase, redemption, defeasance, retirement or other acquisition of, any Capital Stock of any Loan Party, whether now or hereafter outstanding, or make any other distribution in respect thereof, either directly or indirectly, whether in cash or property or in obligations of Loan Party, or enter into any derivatives or other transaction with any financial institution, commodities or stock exchange or clearinghouse (a "Derivatives Counterparty”) obligating any Loan Party to make payments to such Derivatives Counterparty as a result of any change in market value of any such Capital Stock, or make or offer to make any payment or prepayment of principal, premium (if any), interest, fees (including fees to obtain any waiver or consent) or other charges on, or effect any repurchase, redemption, purchase, retirement, defeasance, sinking fund or similar payment with respect to, any Indebtedness (other than the Obligations) of any Loan Party (the payments or other transactions described in this Section 6.6 collectively, “Restricted Payments”), except that:

     (a) any Subsidiary may make Restricted Payments to Borrower or any Subsidiary Guarantor;

     (b) Holdings may make Restricted Payments in the form of the common stock of Holdings;

     (c) Borrower or any Subsidiary Guarantor may make any required payment, prepayment, repurchase redemption, purchase, retirement or other payment of other Permitted Indebtedness, in each case to the extent required to be made by the terms thereof and permitted by such terms after giving effect to any applicable subordination provisions; and

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     (d) Borrower or any Subsidiary Guarantor may prepay Capital Leases or purchase money financing comprising Permitted Indebtedness upon the sale or exchange of the equipment subject thereto;

provided, however, that the Restricted Payments described in clauses (c) and (d) above shall not be permitted if a Default or Event of Default shall have occurred and be continuing at the date of declaration or payment thereof or would result therefrom.

     6.7 Capital Expenditures. Make or commit to make any Capital Expenditure, except (a) Capital Expenditures of Borrower and its Subsidiaries in the ordinary course of business made with the proceeds of any Permitted Equity Financing, (b) Capital Expenditures not exceeding the Permitted Capex Amount in any fiscal year; provided that (i) up to $2,000,000 of any such amount referred to above, if not so expended in the fiscal year for which it is permitted, may be carried over for expenditure in the next succeeding fiscal year and (ii) Capital Expenditures made pursuant to this clause (a) during any fiscal year shall be deemed made, first, in respect of amounts permitted for such fiscal year as provided above and second, in respect of amounts carried over from the prior fiscal year pursuant to subclause (i) above and (c) Capital Expenditures constituting Qualified Investments made with the proceeds of any Reinvestment Deferred Amount (any such Capital Expenditures permitted hereunder, a “Permitted Capital Expenditure”). For purposes hereof, "Permitted Capex Amount” means an aggregate amount equal to the sum of (i) $7,000,000 and (ii) an amount equal to 25% of the Consolidated EBITDA of Borrower for the prior quarter in excess of $6.25 million.

     6.8 Investments. Make any Investment in any other Person, except:

     (a) extensions of trade credit and advances to non-operators under operating agreements in the ordinary course of business;

     (b) Investments in Cash Equivalents;

     (c) Investments arising in connection with the incurrence of Indebtedness permitted by Section 6.2(b) or Section 6.2(d);

     (d) Qualified Investments made by Borrower or any Wholly Owned Subsidiary Guarantor with any Reinvestment Deferred Amount;

     (e) Investments (other than those relating to the incurrence of Indebtedness permitted by Section 6.8(c)) by Holdings, Borrower or any of its Subsidiaries in Borrower or any Person that, prior to such Investment, is a Wholly Owned Subsidiary Guarantor;

     (f) subject to the provisions of Section 6.7, Investments constituting Permitted Capital Expenditures; and

     (g) Investments received by Borrower or any Subsidiary in connection with workouts with, or bankruptcy, insolvency or other similar proceedings with respect to, customers, working interest owners, other industry partners or any other Person.

     6.9 Transactions with Affiliates. Enter into any transaction, including, any purchase, sale, lease or exchange of Property, the rendering of any service or the payment of any management, advisory or similar fees, with any Affiliate (other than any Loan Party) unless such transaction is (a) otherwise permitted under this Agreement, (b) in the ordinary course of business of the Loan Party party to such transaction and (c) upon fair and reasonable terms no less favorable to such Loan Party than it would obtain in a comparable arm’s length transaction with a Person that is not an Affiliate; provided that, for

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the avoidance of doubt, no transaction with any Affiliate effected pursuant to an agreement existing on the date hereof shall be prohibited by this Section 6.9.

     6.10 Sales and Leasebacks. Enter into any Sale and Leaseback Transaction.

     6.11 Changes in Fiscal Periods. Permit the fiscal year of any Loan Party to end on a day other than December 31 or change the method of determining its fiscal year for any Loan party.

     6.12 Negative Pledge Clauses. Enter into or suffer to exist or become effective any agreement that prohibits or limits the ability of any Loan Party to create, incur, assume or suffer to exist any Lien upon any of its Property or revenues, whether now owned or hereafter acquired, to secure the Obligations or, in the case of any Guarantor, its obligations under the Guarantee and Security Agreement, other than (a) this Agreement and the other Loan Documents and (b) in the case of Borrower or any Subsidiary Guarantor any agreements governing any purchase money Liens or Capital Lease Obligations otherwise permitted hereby (in which case, any prohibition or limitation shall only be effective against the assets financed thereby).

     6.13 Restrictions on Subsidiary Distributions. Enter into or suffer to exist or become effective any consensual encumbrance or restriction on the ability of any Subsidiary to (a) make Restricted Payments in respect of any Capital Stock of such Subsidiary held by, or pay or subordinate any Indebtedness owed to, any Loan Party, (b) make Investments in any Loan Party or (c) transfer any of its assets to any Loan Party, except for such encumbrances or restrictions existing under or by reason of (i) any restrictions existing under the Loan Documents and (ii) any restrictions with respect to a Subsidiary imposed pursuant to an agreement that has been entered into in connection with the Disposition of all or substantially all of the Capital Stock or assets of such Subsidiary.

     6.14 Lines of Business. Enter into any business, either directly or through any Subsidiary, except for those businesses in which the Loan Parties are engaged on the date of this Agreement or that are reasonably related thereto.

     6.15 Amendments of Certain Documents. Amend, modify or otherwise change, or permit any amendment, modification or other change to (pursuant to a waiver or otherwise), any Constituent Documents (including by the filing or modification of any certificate of designation, or any agreement or arrangement (including any shareholders’ agreement) entered into, with respect to any of its Capital Stock) or enter into any new agreement with respect to any of its Capital Stock, in each case, except any such amendments, modifications or changes or any such agreements or arrangements that do not adversely affect any right, privilege or interest of the Administrative Agent or the Lenders under the Loan Documents or in the Collateral.

     6.16 Activities of Holdings. In the case of Holdings, notwithstanding anything to the contrary in this Agreement or any other Loan Document, (a) conduct, transact or otherwise engage in, or commit to conduct, transact or otherwise engage in, any business or operations other than those incidental to its ownership of the Capital Stock of Borrower, (b) incur, create, assume or suffer to exist any Indebtedness or other liabilities or financial obligations, except (i) nonconsensual obligations imposed by operation of law, (ii) pursuant to the Loan Documents to which it is a party and (iii) obligations with respect to its Capital Stock, or (c) own, lease, manage or otherwise operate any properties or assets (including cash (other than cash received by Holdings in connection with dividends made by Borrower in accordance with Section 6.6 pending application in the manner contemplated by Section 6.6) and Cash Equivalents) other than the ownership of shares of Capital Stock of Borrower.

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     6.17 New Subsidiaries. Acquire, form, incorporate or organize any Subsidiary or permit to exist any Subsidiary (i) having any Capital Stock that is not wholly owned by Borrower directly or through other Wholly-Owned Subsidiaries or (ii) that is not a Guarantor.

     6.18 Use of Proceeds. Use or permit the use of all or any portion of the proceeds of the Loans for any purpose other than as permitted pursuant to Section 5.11.

     6.19 New Bank Accounts. Open or otherwise establish, or deposit or otherwise transfer funds into, any bank account (other than the bank accounts listed on Schedule 3.25) in the name or otherwise for the benefit of Borrower or any Subsidiary unless the Administrative Agent shall have received a Deposit Account Control Agreement, in form and substance satisfactory to the Administrative Agent in its sole discretion, executed and delivered by Borrower and the bank or other financial institution at which such account is maintained.

     6.20 Storage of Drilling Rig Assets. Store or permit any Drilling Rig Assets to remain at any location (other than any drill site) for more than 60 days other than on real property to which Borrower has title in fee simple unless the Administrative Agent shall have received an Access Agreement duly executed and delivered by the owner of such location.

     6.21 Hedging Agreements. Enter into, or suffer to exist, any Hedging Agreement unless approved in advance in writing by the Administrative Agent.

ARTICLE VII
EVENTS OF DEFAULT

     7.1 Events of Default. If any of the following events shall occur and be continuing:

     (a) Borrower shall fail to pay when due and payable or when declared due and payable (in each case whether at the stated maturity, by acceleration or otherwise), including, pursuant to Section 2.7, all or any portion of the Obligations (whether of principal, interest, fees and charges due to the Lenders or other amounts constituting Obligations); or

     (b) Any representation or warranty made or deemed made by any Loan Party herein or in any other Loan Document or that is contained in any certificate, document or financial or other statement furnished by it at any time under or in connection with this Agreement or any such other Loan Document shall prove to have been inaccurate in any material respect on or as of the date made or deemed made or furnished; or

     (c) Any Loan Party shall default in the observance or performance of any agreement contained in clause (i) or (ii) of Section 5.5(a) (with respect to Holdings or Borrower only), Section 5.6(e), Section 5.7, Section 5.8(a), Section 5.10, Section 5.15 or Article VI, or in Section 5 of the Guarantee and Security Agreement; or an “Event of Default” under and as defined in any Mortgage shall have occurred and be continuing; provided that notwithstanding anything to the contrary in this Agreement, Borrower shall be permitted to cure any breach of Section 6.1(c) (Consolidated Interest Coverage Ratio), and the same shall not constitute an Event of Default hereunder, by making an optional prepayment on or prior to the date of determination of the Consolidated Interest Coverage Ratio sufficient in principal amount such that, upon exclusion from the calculation of such ratio of the interest expense attributable to such prepayment amount, no such default would exist; or

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     (d) Any Loan Party shall default in the observance or performance of any other agreement contained in this Agreement or any other Loan Document (other than as provided in paragraphs (a) through (c) of this Section 7.1), and such default shall continue unremedied for a period of 30 days; or

     (e) Any Loan Party shall (i) default in making any payment of any principal or interest of any Indebtedness (including, any Guarantee Obligation, but excluding the Loans and other Obligations) on the scheduled or original due date with respect thereto; or (ii) default in the observance or performance of any other agreement or condition relating to any such Indebtedness (including any Guarantee Obligation but excluding the Obligations) or contained in any instrument or agreement evidencing, securing or relating thereto, or any other event shall occur or condition exist, the effect of which default or other event or condition is to cause, or to permit the holder or beneficiary of such Indebtedness (or a trustee or agent on behalf of such holder or beneficiary) to cause, with the giving of notice if required, such Indebtedness to become due prior to its stated maturity or to become subject to a mandatory offer to purchase by the obligor thereunder or (in the case of any such Indebtedness constituting a Guarantee Obligation) to become payable; provided that a default, event or condition described in clause (i) or (ii) of this paragraph (e) shall not at any time constitute an Event of Default unless, at such time, one or more defaults, events or conditions of the type described in clauses (i) and (ii) of this paragraph (e) shall have occurred and be continuing with respect to Indebtedness the outstanding principal amount of which exceeds in the aggregate $100,000; or

     (f) (i) Any Loan Party shall commence any case, proceeding or other action (A) under any existing or future law of any jurisdiction, domestic or foreign, relating to bankruptcy, insolvency, reorganization or relief of debtors, seeking to have an order for relief entered with respect to it, or seeking to adjudicate it a bankrupt or insolvent, or seeking reorganization, arrangement, adjustment, winding up, liquidation, dissolution, composition or other relief with respect to it or its debts, or (B) seeking appointment of a receiver, trustee, custodian, conservator or other similar official for it or for all or any substantial part of its assets, or such Loan Party shall make a general assignment for the benefit of its creditors; or (ii) there shall be commenced against any Loan Party any case, proceeding or other action of a nature referred to in clause (i) above that (A) results in the entry of an order for relief or any such adjudication or appointment or (B) remains undismissed, undischarged or unbonded for a period of 60 days; or (iii) there shall be commenced against any Loan Party any case, proceeding or other action seeking issuance of a warrant of attachment, execution, distraint or similar process against all or any substantial part of its assets that results in the entry of an order for any such relief that shall not have been vacated, discharged, or stayed or bonded pending appeal within 60 days from the entry thereof; or (iv) any Loan Party shall take any action in furtherance of, or indicating its consent to, approval of, or acquiescence in, any of the acts set forth in clause (i), (ii), or (iii) above; or (v) any Loan Party shall generally not, or shall be unable to, or shall admit in writing its inability to, pay its debts as they become due; or

     (g) (i) Any Person shall engage in any “prohibited transaction” (as defined in Section 406 of ERISA or Section 4975 of the Code) involving any Benefit Plan, (ii) any “accumulated funding deficiency” (as defined in Section 302 of ERISA), whether or not waived, shall exist with respect to any Benefit Plan, or any Lien in favor of the PBGC or a Benefit Plan shall arise on the assets of any Loan Party any Commonly Controlled Entity, (iii) a Reportable Event shall occur with respect to, or proceedings shall commence to have a trustee appointed, or a trustee shall be appointed, to administer or to terminate, any Single Employer Plan, which Reportable Event or commencement of proceedings or appointment of a trustee is, in the reasonable opinion of the Required Lenders, likely to result in the termination of such Benefit Plan for purposes of Title IV of ERISA, (iv) any Single Employer Plan shall terminate for purposes of Title IV of ERISA, (v) any Loan Party or any Commonly Controlled Entity shall, or in the reasonable opinion of the Required Lenders shall be likely to, incur any liability in connection with a withdrawal from, or the Insolvency or Reorganization of, a Multiemployer Plan or (vi)

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any other event or condition shall occur or exist with respect to a Benefit Plan; and in each case in clauses (i) through (vi) above, such event or condition, together with all other such events or conditions, if any, could, in the sole judgment of the Required Lenders, reasonably be expected to have a Material Adverse Effect; or

     (h) One or more judgments or decrees shall be entered against any Loan Party involving for the Loan Parties taken as a whole a liability (not paid or fully covered by insurance as to which the relevant insurance company has acknowledged coverage) of $100,000 or more, and all such judgments or decrees shall not have been vacated, discharged, stayed or bonded pending appeal within 30 days from the entry thereof; or

     (i) Any of the Security Documents shall cease, for any reason (other than by reason of the express release thereof pursuant to Section 9.15), to be in full force and effect or any Loan Party or any Affiliate of any Loan Party shall so assert, or any Lien created by any of the Security Documents shall cease to be enforceable and of the same effect and priority purported to be created thereby; or

     (j) The guarantee contained in Section 2 of the Guarantee and Security Agreement shall cease, for any reason (other than by reason of the express release thereof pursuant to Section 9.15), to be in full force and effect or any Loan Party or any Affiliate of any Loan Party shall so assert; or

     (k) Any Change of Control shall occur; or

     (l) There shall occur any event or circumstance which has had, or would reasonably be expected to have, a Material Adverse Effect; or

then, and in any such event, (A) if such event is an Event of Default specified in clause (i) or (ii) of paragraph (f) above with respect to Borrower, automatically the Commitments shall immediately terminate and the Loans hereunder (with accrued interest thereon) and all other amounts owing under this Agreement and the other Loan Documents shall immediately become due and payable, and (B) if such event is any other Event of Default, either or both of the following actions may be taken: (i) at any time prior to the Commitment Expiration Date, with the consent of the Required Lenders, the Administrative Agent may, or upon the request of the Required Lenders, the Administrative Agent shall, by notice to Borrower declare the Commitments to be terminated forthwith, whereupon the Commitments shall immediately terminate; and (ii) with the consent of the Required Lenders, the Administrative Agent may, or upon the request of the Required Lenders, the Administrative Agent shall, by notice to Borrower, declare the Loans hereunder (with accrued interest thereon) and all other amounts owing under this Agreement and the other Loan Documents to be due and payable forthwith, whereupon the same shall immediately become due and payable.

     7.2 Remedies. Upon the occurrence and during the continuance of an Event of Default, the Administrative Agent and the Lenders shall be entitled to exercise any and all remedies available under the Security Documents or otherwise available under applicable law or otherwise.

ARTICLE VIII
THE AGENTS

     8.1 Appointment. Each Lender hereby irrevocably designates and appoints the Agents as the agents of such Lender under this Agreement and the other Loan Documents, and each Lender irrevocably authorizes each Agent, in such capacity, to take such action on its behalf under the provisions of this Agreement and the other Loan Documents and to exercise such powers and perform such duties as are expressly delegated to such Agent by the terms of this Agreement and the other Loan Documents,

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together with such other powers as are reasonably incidental thereto. Notwithstanding any provision to the contrary elsewhere in this Agreement, no Agent shall have any duties or responsibilities, except those expressly set forth herein, or any fiduciary relationship with any Lender, and no implied covenants, functions, responsibilities, duties, obligations or liabilities shall be read into this Agreement or any other Loan Document or otherwise exist against any Agent.

     8.2 Delegation of Duties. Each Agent may execute any of its duties under this Agreement and the other Loan Documents by or through agents or attorneys in fact and shall be entitled to advice of counsel concerning all matters pertaining to such duties. No Agent shall be responsible for the negligence or misconduct of any agents or attorneys-in fact selected by it with reasonable care.

     8.3 Exculpatory Provisions. Neither any Agent nor any of its officers, directors, employees, agents, attorneys in fact or affiliates shall be (i) liable for any action lawfully taken or omitted to be taken by it or such Person under or in connection with this Agreement or any other Loan Document (except to the extent that any of the foregoing are found by a final and nonappealable decision of a court of competent jurisdiction to have resulted solely and proximately from its or such Person’s own gross negligence or willful misconduct) or (ii) responsible in any manner to any of the Lenders for any recitals, statements, representations or warranties made by any Loan Party or any officer thereof contained in this Agreement or any other Loan Document or in any certificate, report, statement or other document referred to or provided for in, or received by the Agents under or in connection with, this Agreement or any other Loan Document or for the value, validity, effectiveness, genuineness, enforceability or sufficiency of this Agreement or any other Loan Document or for any failure of any Loan Party to perform its obligations hereunder or thereunder. The Agents shall not be under any obligation to any Lender to ascertain or to inquire as to the observance or performance of any of the agreements contained in, or conditions of, this Agreement or any other Loan Document, or to inspect the properties, books or records of any Loan Party.

     8.4 Reliance by Agents. Each Agent shall be entitled to rely, and shall be fully protected in relying, upon any instrument, writing, resolution, notice, consent, certificate, affidavit, letter, telecopy, telex or teletype message, statement, order or other document or conversation believed by it to be genuine and correct and to have been signed, sent or made by the proper Person or Persons and upon advice and statements of legal counsel (including, counsel to the Loan Parties), independent accountants and other experts selected by such Agent. The Agents may deem and treat the payee of any Note as the owner thereof for all purposes unless such Note shall have been transferred in accordance with Section 9.6 and all actions required by such Section in connection with such transfer shall have been taken. Each Agent shall be fully justified in failing or refusing to take any action under this Agreement or any other Loan Document unless it shall first receive such advice or concurrence of the Required Lenders (or, if so specified by this Agreement, all Lenders or any other instructing group of Lenders specified by this Agreement) as it deems appropriate or it shall first be indemnified to its satisfaction by the Lenders against any and all liability and expense that may be incurred by it by reason of taking or continuing to take any such action. Each Agent shall in all cases be fully protected in acting, or in refraining from acting, under this Agreement and the other Loan Documents in accordance with a request of the Required Lenders (or, if so specified by this Agreement, all Lenders or any other instructing group of Lenders specified by this Agreement), and such request and any action taken or failure to act pursuant thereto shall be binding upon all the Lenders and all future holders of the Loans.

     8.5 Notice of Default. No Agent shall be deemed to have knowledge or notice of the occurrence of any Default or Event of Default hereunder unless such Agent shall have received notice from a Lender or Borrower referring to this Agreement, describing such Default or Event of Default and stating that such notice is a “notice of default”. In the event that the Administrative Agent shall receive such a notice, the Administrative Agent shall give notice thereof to the Lenders. The Administrative Agent shall take such action with respect to such Default or Event of Default as shall be reasonably

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directed by the Required Lenders (or, if so specified by this Agreement, all Lenders or any other instructing group of Lenders specified by this Agreement); provided that unless and until the Administrative Agent shall have received such directions, the Administrative Agent may (but shall not be obligated to) take such action, or refrain from taking such action, with respect to such Default or Event of Default as it shall deem advisable in the best interests of the Lenders.

     8.6 Non Reliance on the Agents and Other Lenders. Each Lender expressly acknowledges that neither any of the Agents nor any of their respective officers, directors, employees, agents, attorneys and other advisors, partners, attorneys in fact or affiliates have made any representations or warranties to it and that no act by any Agent hereafter taken, including any review of the affairs of a Loan Party or any affiliate of a Loan Party, shall be deemed to constitute any representation or warranty by any Agent to any Lender. Each Lender represents to the Agents that it has, independently and without reliance upon any Agent or any other Lender, and based on such documents and information as it has deemed appropriate, made its own appraisal of and investigation into the business, operations, property, financial and other condition and creditworthiness of the Loan Parties and their affiliates and made its own decision to make its Loans hereunder and enter into this Agreement. Each Lender also represents that it will, independently and without reliance upon any Agent or any other Lender, and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit analysis, appraisals and decisions in taking or not taking action under this Agreement and the other Loan Documents, and to make such investigation as it deems necessary to inform itself as to the business, operations, property, financial and other condition and creditworthiness of the Loan Parties and their affiliates. Except for notices, reports and other documents expressly required to be furnished to the Lenders by the Administrative Agent hereunder, no Agent shall have any duty or responsibility to provide any Lender with any credit or other information concerning the business, operations, property, condition (financial or otherwise), prospects or creditworthiness of any Loan Party or any affiliate of a Loan Party that may come into the possession of any Agent or any of its officers, directors, employees, agents, attorneys and other advisors, partners, attorneys in fact or affiliates.

     8.7 Indemnification. The Lenders agree to indemnify each Agent in its capacity as such (to the extent not reimbursed by any Loan Party and without limiting the obligation of any Loan Party to do so), ratably according to their respective Aggregate Exposure Percentages in effect on the date on which indemnification is sought under this Section (or, if indemnification is sought after the date upon which the Commitments shall have terminated and the Loans shall have been paid in full, ratably in accordance with such Aggregate Exposure Percentages immediately prior to such date), for, and to save each Agent harmless from and against, any and all liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements of any kind whatsoever that may at any time (including, at any time following the payment of the Loans) be imposed on, incurred by or asserted against such Agent in any way relating to or arising out of, the Commitments, this Agreement, any of the other Loan Documents or any documents contemplated by or referred to herein or therein or the transactions contemplated hereby or thereby or any action taken or omitted by such Agent under or in connection with any of the foregoing; provided that no Lender shall be liable for the payment of any portion of such liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements that are found by a final and nonappealable decision of a court of competent jurisdiction to have resulted solely and proximately from such Agent’s gross negligence or willful misconduct. The agreements in this Section shall survive the payment of the Loans and all other amounts payable hereunder.

     8.8 Agents in their Individual Capacities. Each Agent and its affiliates may make loans to, accept deposits from and generally engage in any kind of business with any Loan Party as though such Agent were not an Agent. With respect to its Loans made or renewed by it, each Agent shall have the same rights and powers under this Agreement and the other Loan Documents as any Lender and may

57

exercise the same as though it were not an Agent, and the terms “Lender” and “Lenders” shall include each Agent in their individual capacities.

     8.9 Successor Administrative Agent. The Administrative Agent may resign as Administrative Agent upon 10 days’ notice to the Lenders and Borrower. If the Administrative Agent shall resign as Administrative Agent under this Agreement and the other Loan Documents, then the Required Lenders shall appoint from among the Lenders a successor agent for the Lenders, which successor agent shall (unless an Event of Default shall have occurred and be continuing) be subject to approval by Borrower (which approval shall not be unreasonably withheld, conditioned or delayed), whereupon such successor agent shall succeed to the rights, powers and duties of the Administrative Agent, and the term “Administrative Agent” shall mean such successor agent effective upon such appointment and approval, and the former Administrative Agent’s rights, powers and duties as Administrative Agent shall be terminated, without any other or further act or deed on the part of such former Administrative Agent or any of the parties to this Agreement or any holders of the Loans. If no successor agent has accepted appointment as Administrative Agent by the date that is 10 days following a retiring Administrative Agent’s notice of resignation, the retiring Administrative Agent’s resignation shall nevertheless thereupon become effective, and the Lenders shall assume and perform all of the duties of the Administrative Agent hereunder until such time, if any, as the Required Lenders appoint a successor agent as provided for above. After any retiring Administrative Agent’s resignation as Administrative Agent, the provisions of this Article VIII shall inure to its benefit as to any actions taken or omitted to be taken by it while it was Administrative Agent under this Agreement and the other Loan Documents.

     8.10 Authorization to Release Liens and Guarantees. The Administrative Agent is hereby irrevocably authorized by each of the Lenders to effect any release of Liens or guarantee obligations contemplated by Section 9.15.

     8.11 Arranger; Syndication Agent. Each of the Syndication Agent and the Arranger, in its respective capacity as such, shall have no duties or responsibilities, and shall incur no liability, under this Agreement and the other Loan Documents.

     8.12 Withholding Tax.

     (a) To the extent required by any applicable law, the Administrative Agent may withhold from any interest payment to any Lender an amount equivalent to any applicable withholding tax. If the forms or other documentation required by Section 2.11(f) are not delivered to the Administrative Agent, then the Administrative Agent may withhold from any interest payment to any Lender not providing such forms or other documentation, a maximum amount of the applicable withholding tax.

     (b) If the Internal Revenue Service or any authority of the United States or other jurisdiction asserts a claim that the Administrative Agent did not properly withhold tax from amounts paid to or for the account of any Lender (because the appropriate form was not delivered, was not properly executed, or because such Lender failed to notify the Administrative Agent of a change in circumstances which rendered the exemption from, or reduction of, withholding tax ineffective, or for any other reason), such Lender shall indemnify the Administrative Agent fully for all amounts paid, directly or indirectly, by the Administrative Agent as tax or otherwise, including penalties and interest, together with all expenses incurred, including legal expenses, allocated staff costs and any out of pocket expenses.

     (c) If any Lender sells, assigns, grants a participation in, or otherwise transfers its rights under this Agreement, the purchaser, assignee, participant or transferee, as applicable, shall comply and be bound by the terms of Sections 2.11(f) and 8.12; provided that with respect to any Participant, as set

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forth in Section 9.6(b), such Participant shall only be required to comply with the requirements of Sections 2.11(f) and 8.12 if such Participant seeks to obtain the benefits of Section 2.11.

ARTICLE IX
MISCELLANEOUS

     9.1 Amendments and Waivers. Neither this Agreement nor any other Loan Document nor any terms hereof or thereof may be amended, supplemented or modified except in accordance with the provisions of this Section 9.1. The Required Lenders and each Loan Party that is party to the relevant Loan Document may, or (with the written consent of the Required Lenders) the Administrative Agent and each Loan Party that is party to the relevant Loan Document may, from time to time, (a) enter into written amendments, supplements or modifications hereto and to the other Loan Documents (including amendments and restatements hereof or thereof) for the purpose of adding any provisions to this Agreement or the other Loan Documents or changing in any manner the rights of the Lenders or of the Loan Parties hereunder or thereunder or (b) waive, on such terms and conditions as may be specified in the instrument of waiver, any of the requirements of this Agreement or the other Loan Documents or any Default or Event of Default and its consequences; provided, however, that no such waiver and no such amendment, supplement or modification shall:

     (i) forgive the principal amount or extend the final scheduled date of maturity of any Loan, reduce the stated rate of any interest or fee payable hereunder or extend the scheduled date of any payment thereof, or increase the amount or extend the expiration date of any Commitment of any Lender, in each case without the consent of each Lender directly affected thereby;

     (ii) amend, modify or waive any provision of this Section or reduce any percentage specified in the definition of Required Lenders, consent to the assignment or transfer by Borrower of any of its rights and obligations under this Agreement and the other Loan Documents, or (except as specified in Section 9.15) release all or substantially all of the Collateral or release all or substantially all of the Subsidiary Guarantors from their Guarantee Obligations under the Guarantee and Security Agreement, in each case without the consent of all Lenders;

     (iii) amend, modify or waive any provision of Article VIII or any other provision affecting the rights, duties and obligations of any Agent without the consent of the Agent directly affected thereby;

     (iv) amend, modify or waive the pro rata provisions of Section 2.9 without the consent of each Lender directly affected thereby; or

     (v) impose restrictions on assignments and participations that are more restrictive than, or additional to, those set forth in Section 9.6.

Any such waiver and any such amendment, supplement or modification shall apply equally to each of the Lenders and shall be binding upon the Loan Parties, the Lenders, the Agents and all future holders of the Loans. In the case of any waiver, the Loan Parties, the Lenders, the Agents shall be restored to their former position and rights hereunder and under the other Loan Documents, and any Default or Event of Default waived shall be deemed to be cured and not continuing; but no such waiver shall extend to any subsequent or other Default or Event of Default, or impair any right consequent thereon. Any such waiver, amendment, supplement or modification shall be effected by a written instrument signed by the parties required to sign pursuant to the foregoing provisions of this Section 9.1; provided, however, that delivery of an executed signature page of any such instrument by facsimile transmission shall be effective as delivery of a manually executed counterpart thereof.

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     9.2 Notices. Notwithstanding anything to the contrary set forth in this Agreement, all notices, requests and demands to or upon the respective parties hereto to be effective shall be in writing (including by telecopy), and, unless otherwise expressly provided herein, shall be deemed to have been duly given or made when delivered, or three Business Days after being deposited in the mail, postage prepaid, or, in the case of telecopy notice, when received, addressed (a) in the case of Holdings, Borrower or the Agents, as follows and (b) in the case of the Lenders, as set forth in an administrative questionnaire delivered to the Administrative Agent or, in the case of a Lender which becomes a party to this Agreement pursuant to an Assignment and Acceptance, in such Assignment and Acceptance or (c) in the case of any party, to such other address as such party may hereafter notify to the other parties hereto:

Holdings:	DHS Drilling Company
	P.O. Box 277
	1813 Coleman Circle
	Casper, Wyoming 8260
	Attention: Bill Sauer, Jr.
	Facsimile: (307) 473-5377
Borrower	DHS Drilling Company
	P.O. Box 277
	1813 Coleman Circle
	Casper, Wyoming 8260
	Attention: Bill Sauer, Jr.
	Facsimile: (307) 473-5377
with a copy to:	DHS Drilling Company
	370 17th Street, Suite 4300
	Denver, CO 80202
	Attention: Gregg Tubbs
	Facsimile: (303) 575-0403
with a copy to:	Krys Boyle, P.C.
	600 Seventeenth Street, Suite 2700
	Denver, Colorado 80202
	Attention: Peter T. Morre
	Facsimile: (303) 893-2882
Agent(s):	Lehman Commercial Paper Inc.
	745 Seventh Avenue, 16th Floor
	New York, New York 10019
	Attention: Yvonne Lin-Lu
	Facsimile: (212) 299-0202
with a copy to:	Lehman Brothers Inc.
	600 Travis Street, Suite 7200
	Houston, Texas 77002
	Attention: Mathew Verghese
	Facsimile: (713) 236-3912

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with a copy to:	Akin Gump Strauss Hauer & Feld LLP
	1111 Louisiana Street, Suite 4400
	Houston, Texas 77002
	Attention: J. Michael Chambers
	Facsimile: (713) 236-0822

provided that any notice, request or demand to or upon any Agent or any Lender shall not be effective until received.

The Administrative Agent or Borrower may, in its discretion, agree to accept notices and other communications to it hereunder by electronic communications pursuant to procedures approved by it; provided that approval of such procedures may be limited to particular notices or communications.

     9.3 No Waiver; Cumulative Remedies. No failure to exercise and no delay in exercising, on the part of any Agent or any Lender, any right, remedy, power or privilege hereunder or under the other Loan Documents shall operate as a waiver thereof; nor shall any single or partial exercise of any right, remedy, power or privilege hereunder preclude any other or further exercise thereof or the exercise of any other right, remedy, power or privilege. The rights, remedies, powers and privileges herein provided are cumulative and not exclusive of any rights, remedies, powers and privileges provided by law.

     9.4 Survival of Representations and Warranties. All representations and warranties made herein, in the other Loan Documents and in any document, certificate or statement delivered pursuant hereto or in connection herewith shall survive the execution and delivery of this Agreement and the making of the Loans and other extensions of credit hereunder.

     9.5 Payment of Expenses. Borrower agrees (a) to pay or reimburse the Agents for all their reasonable out of pocket costs and expenses incurred in connection with the syndication of the Loans and the development, preparation and execution of, and any amendment, supplement or modification to, this Agreement and the other Loan Documents and any other documents prepared in connection herewith or therewith, and the consummation and administration of the transactions contemplated hereby and thereby, including, the reasonable fees and disbursements and other charges of counsel and consultants to the Administrative Agent and the charges of Intralinks, (b) to pay or reimburse each Lender and the Agents for all their costs and expenses incurred in connection with the enforcement or preservation of any rights under this Agreement, the other Loan Documents and any other documents prepared in connection herewith or therewith, including, the fees and disbursements of counsel (including the allocated fees and disbursements and other charges of in-house counsel) to each Lender and of counsel to the Agents, (c) to pay, indemnify, or reimburse each Lender and the Agents for, and hold each Lender and the Agents harmless from, any and all recording and filing fees and any and all liabilities with respect to, or resulting from any delay in paying, stamp, excise and other taxes, if any, which may be payable or determined to be payable in connection with the execution and delivery of, or consummation or administration of any of the transactions contemplated by, or any amendment, supplement or modification of, or any waiver or consent under or in respect of, this Agreement, the other Loan Documents and any such other documents, and (d) to pay, indemnify or reimburse each Lender, each Agent, their respective affiliates, and their respective officers, directors, trustees, employees, affiliates, shareholders, attorneys and other advisors, agents and controlling persons (each, an “Indemnitee”) for, and hold each Indemnitee harmless from and against any and all other liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements of any kind or nature whatsoever with respect to the execution, delivery, enforcement, performance and administration of this Agreement, the other Loan Documents and any such other documents, including, any of the foregoing relating to the use of proceeds of the Loans or the violation of, noncompliance with or liability under, any Environmental Law applicable to the operations

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of any Loan Party or the use by unauthorized persons of information or other materials sent through electronic, telecommunications or other information transmission systems that are intercepted by such persons and the fees and disbursements and other charges of legal counsel in connection with claims, actions or proceedings by any Indemnitee against Borrower hereunder (all the foregoing in this clause (d), collectively, the “Indemnified Liabilities”); provided that Borrower shall have no obligation hereunder to any Indemnitee with respect to Indemnified Liabilities to the extent such Indemnified Liabilities are found by a final and nonappealable decision of a court of competent jurisdiction to have resulted solely and proximately from the gross negligence or willful misconduct of such Indemnitee. No Indemnitee shall be liable for any damages arising from the use by unauthorized persons of information or other materials sent through electronic, telecommunications or other information transmission systems that are intercepted by such persons or for any special, indirect, consequential or punitive damages in connection with the Loans. Without limiting the foregoing, and to the extent permitted by applicable law, each of Holdings and Borrower agrees not to assert and to cause its Subsidiaries not to assert, and hereby waives and agrees to cause its Subsidiaries so to waive, all rights for contribution or any other rights of recovery with respect to all claims, demands, penalties, fines, liabilities, settlements, damages, costs and expenses of whatever kind or nature, under or related to Environmental Laws, that any of them might have by statute or otherwise against any Indemnitee. All amounts due under this Section 9.5 shall be payable not later than ten days after written demand therefor. Statements payable by Borrower pursuant to this Section shall be submitted to Borrower at the address of Borrower set forth in Section 9.2, or to such other Person or address as may be hereafter designated by Borrower in a notice to the Administrative Agent. The agreements in this Section 9.5 shall survive repayment of the Loans and all other amounts payable hereunder.

     9.6 Successors and Assigns; Participations and Assignments.

     (a) This Agreement shall be binding upon and inure to the benefit of Holdings, Borrower, the Lenders, the Agents, all future holders of the Loans and their respective successors and assigns, except that neither Holdings nor Borrower may assign or transfer any of its respective rights or obligations under this Agreement without the prior written consent of the Agents and each Lender (and any attempted assignment or transfer by the Borrower without such consent shall be null and void).

     (b) Any Lender may, without the consent of Borrower or any other Person, in accordance with applicable law, at any time sell to one or more banks, financial institutions or other entities (each, a “Participant”) participating interests in any Loan owing to such Lender, any Commitment of such Lender or any other interest of such Lender hereunder and under the other Loan Documents. In the event of any such sale by a Lender of a participating interest to a Participant, such Lender’s obligations under this Agreement to the other parties to this Agreement shall remain unchanged, such Lender shall remain solely responsible for the performance thereof, such Lender shall remain the holder of any such Loan for all purposes under this Agreement and the other Loan Documents, and Borrower and the Agents shall continue to deal solely and directly with such Lender in connection with such Lender’s rights and obligations under this Agreement and the other Loan Documents. In no event shall any Participant under any such participation have any right to approve any amendment or waiver of any provision of any Loan Document, or any consent to any departure by any Loan Party therefrom, except to the extent that such amendment, waiver or consent would require the consent of all Lenders pursuant to Section 9.1. Borrower agrees that if amounts outstanding under this Agreement and the Loans are due or unpaid, or shall have been declared or shall have become due and payable upon the occurrence of an Event of Default, each Participant shall, to the maximum extent permitted by applicable law, be deemed to have the right of setoff in respect of its participating interest in amounts owing under this Agreement to the same extent as if the amount of its participating interest were owing directly to it as a Lender under this Agreement, provided that, in purchasing such participating interest, such Participant shall be deemed to have agreed to share with the Lenders the proceeds thereof as provided in Section 9.7(a) as fully as if such

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Participant were a Lender hereunder. Borrower also agrees that each Participant shall be entitled to the benefits of Sections 2.10 and 2.11 with respect to its participation in the Commitments and the Loans outstanding from time to time as if such Participant were a Lender; provided that, in the case of Section 2.11, such Participant shall have complied with the requirements of Section 2.11 and Section 8.12, and; provided, further, that no Participant shall be entitled to receive any greater amount pursuant to any such Section than the transferor Lender would have been entitled to receive in respect of the amount of the participation transferred by such transferor Lender to such Participant had no such transfer occurred.

     (c) Any Lender (an “Assignor”) may, without the consent of any Loan Party, in accordance with applicable law and upon written notice to the Administrative Agent, at any time and from time to time assign to any Lender or any affiliate, Related Fund or Control Investment Affiliate thereof or, with the consent of the Administrative Agent (which, in each case, shall not be unreasonably withheld, conditioned or delayed) (provided that no such consent need be obtained by the Administrative Agent or its affiliates), to an additional bank, financial institution or other entity (an “Assignee”) all or any part of its rights and obligations under this Agreement pursuant to an Assignment and Acceptance, substantially in the form of Exhibit J (an “Assignment and Acceptance”), executed by such Assignee and such Assignor (and, where the consent of Borrower or the Administrative Agent is required pursuant to the foregoing provisions, by Borrower and such other Persons) and delivered to the Administrative Agent for its acceptance and recording in the Register; provided that no such assignment to an Assignee (other than any Lender or any affiliate thereof) shall be in an aggregate principal amount of less than $5,000,000 (other than, in each case, in the case of an assignment of all of a Lender’s interests under this Agreement), unless otherwise agreed by Borrower and the Administrative Agent. Upon such execution, delivery, acceptance and recording, from and after the effective date determined pursuant to such Assignment and Acceptance, (x) the Assignee thereunder shall be a party hereto and, to the extent provided in such Assignment and Acceptance, have the rights and obligations of a Lender hereunder with Commitments or Loans as set forth therein, and (y) the Assignor thereunder shall, to the extent provided in such Assignment and Acceptance, be released from its obligations under this Agreement (and, in the case of an Assignment and Acceptance covering all of an Assignor’s rights and obligations under this Agreement, such Assignor shall cease to be a party hereto, except as to Sections 2.10, 2.11, 8.12 and 9.5 in respect of the period prior to such effective date). For purposes of the minimum assignment amounts set forth in this Section 9.6(c), multiple assignments by two or more Related Funds shall be aggregated.

     (d) The Administrative Agent shall, on behalf of Borrower, maintain at its address referred to in Section 9.2 a copy of each Assignment and Acceptance delivered to it and a register (the “Register”) for the recordation of the names and addresses of the Lenders and the Commitment of, and principal amount of the Loans owing to, each Lender from time to time. The entries in the Register shall be conclusive, in the absence of manifest error, and Borrower, each Agent and the Lenders shall treat each Person whose name is recorded in the Register as the owner of the Loans and any Note evidencing such Loans recorded therein for all purposes of this Agreement. Any assignment of any Loan, whether or not evidenced by a Note, shall be effective only upon appropriate entries with respect thereto being made in the Register (and each Note shall expressly so provide). Any assignment or transfer of all or part of a Loan evidenced by a Note shall be registered on the Register only upon surrender for registration of assignment or transfer of the Note evidencing such Loan, accompanied by a duly executed Assignment and Acceptance; thereupon one or more new Notes in the same aggregate principal amount shall be issued to the designated Assignee, and the old Notes shall be returned by the Administrative Agent to Borrower marked “canceled”. The Register shall be available for inspection by Borrower or any Lender (with respect to any entry relating to such Lender’s Loans) at any reasonable time and from time to time upon reasonable prior notice.

     (e) Upon its receipt of an Assignment and Acceptance executed by an Assignor and an Assignee (and, in any case where the consent of any other Person is required by Section 9.6(c), by each

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such other Person), the Administrative Agent shall (i) promptly accept such Assignment and Acceptance and (ii) on the effective date determined pursuant thereto record the information contained therein in the Register and give notice of such acceptance and recordation to Borrower. On or prior to such effective date, Borrower, at its own expense, upon request, shall execute and deliver to the Administrative Agent (in exchange for the applicable Note, if any, of the assigning Lender) new Note or Notes to the order of such Assignee in an amount equal to the Commitment or Loan assumed or acquired by it pursuant to such Assignment and Acceptance and, if the Assignor has retained a Commitment or Loan, as the case may be, upon request, a new Note or Notes to the order of the Assignor in an amount equal to the Commitment or Loans, as the case may be, retained by it hereunder. Such new Note or Notes shall be dated the Closing Date and shall otherwise be in the form of the Note or Notes replaced thereby.

     (f) For avoidance of doubt, the parties to this Agreement acknowledge that the provisions of this Section concerning assignments of Loans and Notes relate only to absolute assignments and that such provisions do not prohibit assignments creating security interests in Loans and Notes, including, any pledge or assignment by a Lender of any Loan or Note to any Federal Reserve Bank in accordance with applicable law.

     (g) Notwithstanding anything to the contrary contained herein, any Lender (a “Granting Lender”) may grant to a special purpose funding vehicle (an “SPC”), identified as such in writing from time to time by the Granting Lender to the Administrative Agent and Borrower, the option to provide to Borrower all or any part of any Loan that such Granting Lender would otherwise be obligated to make to Borrower pursuant to this Agreement; provided that (i) nothing herein shall constitute a commitment by any SPC to make any Loan and (ii) if an SPC elects not to exercise such option or otherwise fails to provide all or any part of such Loan, the Granting Lender shall be obligated to make such Loan pursuant to the terms hereof. The making of a Loan by an SPC hereunder shall utilize the Commitment of the Granting Lender to the same extent, and as if, such Loan were made by such Granting Lender. Each party hereto hereby agrees that no SPC shall be liable for any indemnity or similar payment obligation under this Agreement (all liability for which shall remain with the Granting Lender). In furtherance of the foregoing, each party hereto hereby agrees (which agreement shall survive the termination of this Agreement) that, prior to the date that is one year and one day after the payment in full of all outstanding commercial paper or other indebtedness of any SPC, it will not institute against, or join any other person in instituting against, such SPC any bankruptcy, reorganization, arrangement, insolvency or liquidation proceedings under the laws of the United States or any state thereof. In addition, notwithstanding anything to the contrary in this Section 9.6(g), any SPC may (x) with notice to, but without the prior written consent of, Borrower and the Administrative Agent and without paying any processing fee therefor, assign all or a portion of its interests in any Loans to the Granting Lender, or with the prior written consent of Borrower and the Administrative Agent (which consent shall not be unreasonably withheld, conditioned or delayed) to any financial institutions providing liquidity or credit support to or for the account of such SPC to support the funding or maintenance of Loans, and (y) disclose on a confidential basis any non-public information relating to its Loans to any rating agency, commercial paper dealer or provider of any surety, guarantee or credit or liquidity enhancement to such SPC; provided that non-public information with respect to Borrower may be disclosed only with Borrower’s consent which will not be unreasonably withheld, conditioned or delayed. This Section 9.6(g) may not be amended without the written consent of any SPC with Loans outstanding at the time of such proposed amendment.

     9.7 Adjustments; Set off

     (a) If any Lender (a “Benefitted Lender”) shall at any time receive any payment of all or part of the Obligations owing to it, or receive any collateral in respect thereof (whether voluntarily or involuntarily, by set off, pursuant to events or proceedings of the nature referred to in clause (f) of Article

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VII, or otherwise), in a greater proportion than any such payment to or collateral received by any other Lender, if any, in respect of such other Lender’s Obligations, such Benefitted Lender shall purchase for cash from the other Lenders a participating interest in such portion of each such other Lender’s Obligations, or shall provide such other Lenders with the benefits of any such collateral, as shall be necessary to cause such Benefitted Lender to share the excess payment or benefits of such collateral ratably with each of the Lenders; provided, however, that if all or any portion of such excess payment or benefits is thereafter recovered from such Benefitted Lender, such purchase shall be rescinded, and the purchase price and benefits returned, to the extent of such recovery, but without interest.

     (b) In addition to any rights and remedies of the Lenders provided by law, each Lender shall have the right, without prior notice to Holdings or Borrower, any such notice being expressly waived by Holdings and Borrower to the extent permitted by applicable law, upon any amount becoming due and payable by Holdings or Borrower hereunder (whether at the stated maturity, by acceleration or otherwise), to set off and appropriate and apply against such amount any and all deposits (general or special, time or demand, provisional or final), in any currency, and any other credits, indebtedness or claims, in any currency, in each case whether direct or indirect, absolute or contingent, matured or unmatured, at any time held or owing by such Lender or any branch or agency thereof to or for the credit or the account of Holdings or Borrower, as the case may be. Each Lender agrees to notify promptly Borrower and the Administrative Agent after any such setoff and application made by such Lender, provided that the failure to give such notice shall not affect the validity of such setoff and application.

     9.8 Counterparts. This Agreement may be executed by one or more of the parties to this Agreement on any number of separate counterparts, and all of said counterparts taken together shall be deemed to constitute one and the same instrument. Delivery of an executed signature page of this Agreement by facsimile transmission shall be effective as delivery of a manually executed counterpart hereof. A set of the copies of this Agreement signed by all the parties shall be lodged with Borrower and the Administrative Agent.

     9.9 Severability. Any provision of this Agreement that is prohibited or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such prohibition or unenforceability without invalidating the remaining provisions hereof, and any such prohibition or unenforceability in any jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction.

     9.10 Integration; Construction.

     (a) This Agreement and the other Loan Documents represent the entire agreement of Borrower, Holdings, the Agents and the Lenders with respect to the subject matter hereof and thereof, and there are no promises, undertakings, representations or warranties by any Agent or any Lender relative to the subject matter hereof not expressly set forth or referred to herein or in the other Loan Documents.

     (b) Each covenant contained herein shall be construed (absent express provision to the contrary) as being independent of each other covenant contained herein, so that compliance with any one covenant shall not (absent such an express contrary provision) be deemed to excuse compliance with any other covenant. Where any provision herein refers to action to be taken by any Person, or which such Person is prohibited from taking, such provision shall be applicable whether such action is taken directly or indirectly by such Person.

     9.11 GOVERNING LAW. THIS AGREEMENT AND THE RIGHTS AND OBLIGATIONS OF THE PARTIES UNDER THIS AGREEMENT SHALL BE GOVERNED BY, AND

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CONSTRUED AND INTERPRETED IN ACCORDANCE WITH, THE LAW OF THE STATE OF NEW YORK.

     9.12 Submission To Jurisdiction; Waivers. Each of Holdings and Borrower hereby irrevocably and unconditionally:

     (a) submits for itself and its Property in any legal action or proceeding relating to this Agreement and the other Loan Documents to which it is a party, or for recognition and enforcement of any judgment in respect thereof, to the non exclusive general jurisdiction of the courts of the State of New York located in the County of New York, the courts of the United States of America for the Southern District of New York, and appellate courts from any thereof;

     (b) consents that any such action or proceeding may be brought in such courts and waives any objection that it may now or hereafter have to the venue of any such action or proceeding in any such court or that such action or proceeding was brought in an inconvenient court and agrees not to plead or claim the same;

     (c) agrees that service of process in any such action or proceeding may be effected by mailing a copy thereof by registered or certified mail (or any substantially similar form of mail), postage prepaid, to Holdings or Borrower, as the case may be, at its address set forth in Section 9.2 or at such other address of which the Administrative Agent shall have been notified pursuant thereto;

     (d) agrees that nothing herein shall affect the right to effect service of process in any other manner permitted by law or shall limit the right to sue in any other jurisdiction; and

     (e) waives, to the maximum extent not prohibited by law, any right it may have to claim or recover in any legal action or proceeding referred to in this Section any special, exemplary, punitive or consequential damages.

     9.13 Acknowledgments. Each of Holdings and Borrower hereby acknowledges that:

     (a) it has been advised by counsel in the negotiation, execution and delivery of this Agreement and the other Loan Documents;

     (b) neither any Agent nor any Lender has any fiduciary relationship with or duty to Holdings or Borrower arising out of or in connection with this Agreement or any of the other Loan Documents, and the relationship between the Agents and the Lenders, on one hand, and Holdings and Borrower, on the other hand, in connection herewith or therewith is solely that of debtor and creditor; and

     (c) no joint venture is created hereby or by the other Loan Documents or otherwise exists by virtue of the transactions contemplated hereby among the Arranger, the Agents and the Lenders or among Holdings, Borrower and the Lenders.

     9.14 Confidentiality. Each of the Agents and the Lenders agrees to keep confidential all non-public information provided to it by any Loan Party pursuant to this Agreement that is designated by such Loan Party as confidential; provided that nothing herein shall prevent any Agent or any Lender from disclosing any such information (a) to any Agent, any other Lender or any affiliate of any thereof, (b) to any Participant or Assignee (each, a “Transferee”) or prospective Transferee that agrees to comply with the provisions of this Section or substantially equivalent provisions, (c) to any of its employees, directors, agents, attorneys, accountants and other professional advisors, (d) upon the request or demand of any Governmental Authority having jurisdiction over it, (e) in response to any order of any court or other

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Governmental Authority or as may otherwise be required pursuant to any Requirement of Law, (f) if requested or required to do so in connection with any litigation or similar proceeding, (g) that has been publicly disclosed other than in breach of this Section, (h) to the National Association of Insurance Commissioners or any similar organization or any nationally recognized rating agency that requires access to information about a Lender’s investment portfolio in connection with ratings issued with respect to such Lender or (i) in connection with the exercise of any remedy hereunder or under any other Loan Document. Notwithstanding anything to the contrary in the foregoing sentence or any other express or implied agreement, arrangement or understanding, the parties hereto hereby agree that, from the commencement of discussions with respect to the financing provided hereunder, any party hereto (and each of its employees, representatives, or agents) is permitted to disclose to any and all persons, without limitation of any kind, the tax structure and tax aspects of the transactions contemplated hereby, and all materials of any kind (including opinions or other tax analyses) related to such tax structure and tax aspects.

     9.15 Release of Collateral and Guarantee Obligations.

     (a) Notwithstanding anything to the contrary contained herein or in any other Loan Document, upon request of Borrower in connection with any Disposition of Property permitted by the Loan Documents (other than to a Loan Party), the Administrative Agent shall (without notice to, or vote or consent of, any Lender) take such actions as shall be required to release its security interest in any Collateral that is, or owned by any Person all the Capital Stock of which is, being Disposed of in such Disposition, and to release any Guarantee Obligations under any Loan Document of any Person being Disposed of in such Disposition, to the extent necessary to permit consummation of such Disposition in accordance with the Loan Documents; provided that Borrower shall have delivered to the Administrative Agent, at least ten Business Days prior to the date of the proposed release (or such shorter period agreed to by the Administrative Agent), a written request for release identifying the relevant Collateral being Disposed of in such Disposition and the terms of such Disposition in reasonable detail, including the date thereof, the price thereof and any expenses in connection therewith, together with a certification by Borrower stating that such transaction is in compliance with this Agreement and the other Loan Documents and that the proceeds of such Disposition will be applied in accordance with this Agreement and the other Loan Documents.

     (b) Notwithstanding anything to the contrary contained herein or any other Loan Document, when all Obligations have been paid in full, all Commitments have terminated or expired, upon request of Borrower, the Administrative Agent shall (without notice to, or vote or consent of, any Lender) take such actions as shall be required to release its security interest in all Collateral, and to release all Guarantee Obligations provided for in any Loan Document. Any such release of Guarantee Obligations shall be deemed subject to the provision that such Guarantee Obligations shall be reinstated if after such release any portion of any payment in respect of the Obligations guaranteed thereby shall be rescinded or must otherwise be restored or returned upon the insolvency, bankruptcy, dissolution, liquidation or reorganization of Borrower or any Guarantor, or upon or as a result of the appointment of a receiver, intervenor or conservator of, or trustee or similar officer for, Borrower or any Guarantor or any substantial part of its Property, or otherwise, all as though such payment had not been made.

     9.16 Accounting Changes. In the event that any “Accounting Change” (as defined below) shall occur and such change results in a change in the method of calculation of financial covenants, standards or terms in this Agreement, then Holdings, Borrower and the Administrative Agent agree to enter into negotiations in order to amend such provisions of this Agreement so as to equitably reflect such Accounting Change with the desired result that the criteria for evaluating the consolidated financial condition of Holdings and Borrower shall be the same after such Accounting Change as if such Accounting Change had not been made. Until such time as such an amendment shall have been executed

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and delivered by Holdings, Borrower, the Administrative Agent and the Required Lenders, all financial covenants, standards and terms in this Agreement shall continue to be calculated or construed as if such Accounting Change had not occurred. “Accounting Change” refers to any change in accounting principles required by the promulgation of any rule, regulation, pronouncement or opinion by the Financial Accounting Standards Board of the American Institute of Certified Public Accountants or, if applicable, the SEC.

     9.17 WAIVERS OF JURY TRIAL. THE BORROWER, HOLDINGS, THE ARRANGER, THE AGENTS AND THE LENDERS HEREBY IRREVOCABLY AND UNCONDITIONALLY WAIVE TRIAL BY JURY IN ANY LEGAL ACTION OR PROCEEDING RELATING TO THIS AGREEMENT OR ANY OTHER LOAN DOCUMENT AND FOR ANY COUNTERCLAIM THEREIN (IN EACH CASE, WHETHER FOR CLAIMS SOUNDING IN CONTRACT OR IN TORT OR OTHERWISE).

     9.18 Customer Identification – USA PATRIOT Act Notice. The Administrative Agent (for itself and not on behalf of any other party) and each Lender hereby notifies the Loan Parties that, pursuant to the requirements of the USA PATRIOT Act, Title III of Pub. L. 107-56, signed into law October 26, 2001 (the “Patriot Act”), it is required to obtain, verify and record information that identifies the Loan Parties, which information includes the name and address of the Loan Parties and other information that will allow the Administrative Agent or such Lender, as applicable, to identify the Loan Parties in accordance with the Patriot Act.

[Signature Page to Follow]

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     IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be duly executed and delivered by their proper and duly authorized officers as of the day and year first above written.

DHS HOLDINGS COMPANY
By:	/s/ Gregg Tubbs
	Name: Gregg Tubbs
	Title: Exec, V.P.
DHS DRILLING COMPANY
By:	/s/ Gregg Tubbs
	Name: Gregg Tubbs
	Title: Exec V.P.
LEHMAN BROTHERS INC., as Arranger
By:	/s/ J. Robert Chambers
	J. Robert Chambers
	Managing Director
LEHMAN COMMERCIAL PAPER INC.,
as Administrative Agent, Syndication Agent
and as a Lender
By:	/s/ J. Robert Chambers
	J. Robert Chambers
	Authorized Signatory

[Signature Page to DHS Drilling Company Credit Agreement]

SCHEDULE 1.1

COMMITMENTS

Lender	Commitment
Lehman Commercial Paper Inc.	$75,000,000
745 Seventh Avenue
New York, New York 10019
Attention:
Facsimile:

EX-21

Exhibit 21

SUBSIDIARIES OF THE REGISTRANT

	State of Incorporation
Name	or Organization
Amber Resources Company of Colorado	Delaware
Piper Petroleum Company	Colorado
Delta Exploration Company, Inc.	Colorado
Castle Texas Exploration Limited Partnership	Texas
DPCA, LLC	Delaware
DLC, Inc.	Colorado
DHS Holding Company	Delaware
DHS Drilling Company	Colorado
C&L Drilling Company	Colorado
Chapman Trucking Company	Wyoming
PGR Partners, LLC	Colorado
CRB Partners, LLC	Delaware
Delta Risk Management, LLC	Colorado
Vega Piceance, LLC	Colorado

EX-23.1

Exhibit 23.1

 

Consent of Independent Registered Public Accounting Firm

 

The Board of Directors
Delta Petroleum Corporation
 

We consent to the incorporation by reference in the registration statements (Nos. 333-142180, 333-141303, 333-131854, 333-131425, and 333-129071) on Form S-3; and (Nos. 333-141247, 333-137361, 333-127654, 333-108866, 333-103585, and 333-73324) on Form S-8 of Delta Petroleum Corporation of our reports dated February 28, 2008, with respect to the consolidated balance sheets of Delta Petroleum Corporation and subsidiaries as of December 31, 2007 and 2006, and the related consolidated statements of operations, changes in stockholders’ equity and comprehensive income (loss), and cash flows for the year ended December 31, 2007 and 2006, the six months ended December 31, 2005 and the year ended June 30, 2005 and management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2007, and the effectiveness of internal control over financial reporting as of December 31, 2007, which reports appear in the December 31, 2007 annual report on Form 10-K of Delta Petroleum Corporation.  

Our report refers to the Company's adoption of FASB Interpretation No. 48, Accounting for the Uncertainty in Income Taxes -an Interpretation of FASB statement No. 109, effective January 1, 2007 and the adoption of Statement of Financial Accounting Standards No. 123(R), Share Based Payment, effective July 1, 2005.  

/s/ KPMG LLP
Denver, Colorado
February 28, 2008

EX-23.2

Exhibit 23.2

Consent of Ralph E. Davis Associates, Inc.

 

The Board of Directors
Delta Petroleum Corporation
 

We hereby consent to the use of our name and the information regarding our review of the reserve estimates of Delta Petroleum Corporation contained in its Annual Report on Form 10-K for period ended December 31, 2007, and to the incorporation by reference thereof in the registration statements (Nos. 333-142180, 333-141303, 333-131854, 333-131425, and 333-129071) on Form S-3; (Nos. 333-141247, 333-137361, 333-127654, 333-108866, 333-103585, and 333-73324) on Form S-8 of Delta Petroleum Corporation.  

/s/ Allen C. Barron Allen C. Barron, P.E.

President

Ralph E. Davis Associates, Inc.

Houston, Texas

February 27, 2008

EX-23.3

Exhibit 23.3

Consent of Mannon Associates, Inc.

The Board of Directors
Delta Petroleum Corporation

We hereby consent to the use of our name and the information regarding our review of the reserve estimates of Delta Petroleum Corporation contained in its Annual Report on Form 10-K for year ended December 31, 2007, and to the incorporation by reference thereof in the registration statements (Nos. 333-142180, 333-141303, 333-131854, 333-131425, and 333-129071) on Form S-3; (Nos. 333-141247, 333-137361, 333-127654, 333-108866, 333-103585, and 333-73324) on Form S-8 of Delta Petroleum Corporation.

/s/ Robert W. Mannon  

Robert W. Mannon 

President
Mannon Associates, Inc. 

Santa Barbara, California
February 26, 2008

EX-31.1

EXHIBIT 31.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER
OF DELTA PETROLEUM CORPORATION
PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Roger A. Parker, certify that:

1. I have reviewed this annual report on Form 10-K of Delta Petroleum Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 29, 2008

/s/ Roger A. Parker

Roger A. Parker

Chief Executive Officer

EX-31.2

EXHIBIT 31.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER
OF DELTA PETROLEUM CORPORATION
PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Kevin K. Nanke, certify that:

1. I have reviewed this annual report on Form 10-K of Delta Petroleum Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 29, 2008

/s/ Kevin K. Nanke

Kevin K. Nanke

Chief Financial Officer

EX-32.1

EXHIBIT 32.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER
OF DELTA PETROLEUM CORPORATION
PURSUANT TO 18 U.S.C. SECTION 1350

I certify that, to the best of my knowledge, the Annual Report on Form 10-K of Delta Petroleum Corporation for the year ended December 31, 2007 (the “Report”):

(1) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Delta Petroleum Corporation.

/s/ Roger A. Parker

Roger A. Parker

Chief Executive Officer

February 29, 2008

A signed original of this written statement required by Section 906 of the Sarbanes-Oxley Act of 2002 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission upon request.

EX-32.2

EXHIBIT 32.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER
OF DELTA PETROLEUM CORPORATION
PURSUANT TO 18 U.S.C. SECTION 1350

I certify that, to the best of my knowledge, the Annual Report on Form 10-K of Delta Petroleum Corporation for the year ended December 31, 2007 (the “Report”):

(1) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Delta Petroleum Corporation.

/s/ Kevin K. Nanke  

Kevin K. Nanke

Chief Financial Officer

February 29, 2008

A signed original of this written statement required by Section 906 of the Sarbanes-Oxley Act of 2002 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission upon request.