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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-K

(Mark One)


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

For the fiscal year ended December 31, 2006


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: None

Securities registered under to Section 12(g) of the Act:
Common Stock, $.01 par value

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ 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 þ

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, 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 þ Accelerated filer o Non-accelerated filer o

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

As of June 30, 2006, the aggregate market value of voting stock held by non-affiliates of the registrant was approximately $879,386,000, based on the closing price of the Common Stock on the NASDAQ National Market of $17.13 per share. As of March 2, 2007, 57,752,620 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 2007 Annual Meeting of Stockholders.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

We are including the following discussion to inform our existing and potential security holders generally of some of the risks and uncertainties that can affect us and to take advantage of the “safe harbor” protection for forward-looking statements afforded under federal securities laws. From time to time, our management or persons acting on our behalf make forward-looking statements to inform existing and potential security holders about us. Forward-looking statements are generally accompanied by words such as “estimate,” “project,” “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 our recent acquisitions; marketing of oil and natural gas; expected future revenues, 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 2007; 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 controls 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;

	•		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; and

	•		unanticipated recovery or production problems, including cratering, explosions, fires and uncontrollable flows of oil, gas or well fluids.

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 energy 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 indirect ownership interest in a drilling company, providing the benefit of priority access to 16 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 year ended December 31, 2006, the six-month transitional period ended December 31, 2005 and for the twelve-month periods ended June 30, 2005 and 2004. In this Form 10-K, when we refer to “fiscal 2007” we mean the twelve-month period ending December 31, 2007.

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 $175-$215 million on our drilling program during 2007. We expect that approximately 80% of the 2007 drilling capital expenditures will be 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.

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 historically has come through acquisitions, we anticipate that the majority of our 2007 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 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 18.7 years as of December 31, 2006.

Maintain high percentage ownership and operational control over our asset base

As of December 31, 2006, we controlled approximately 1,240,000 net undeveloped acres, representing approximately 97% of our total net acreage position. We retain a high degree of operational control over our asset base, with an average working interest of approximately 85% (excluding our Columbia River Basin (“CRB”) properties) as of December 31, 2006. 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 49.4% indirect interest in DHS Drilling Company (“DHS”), as well as a contractual right of priority access to DHS’ sixteen 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, 2006, we had a significant undeveloped, unproved acreage position 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 its 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 2007.

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 ability 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. Approximately 14.7 Bcfe of our anticipated production is hedged for 2007.

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 January 30, 2007, Delta closed an offering of 2,768,000 shares of common stock priced at $20.98 per share. The equity offering resulted in net proceeds of approximately $56.6 million. The proceeds were used to repay our $25.0 million unsecured term loan and reduce outstanding indebtedness under our credit facility. The Company intends to redraw all or some of the amounts paid down on the credit facility for exploration and development of oil and natural gas properties, working capital and other general corporate purposes.

On January 10, 2007, we sold non-core properties located in Padgett Field, Kansas for proceeds of $5.6 million. These properties are included in assets held for sale in the accompanying financial statements as of December 31, 2006.

On February 13, 2007, we entered into a purchase and sale agreement to divest of certain non-core properties located in the Permian Basin and the onshore Gulf Coast region of Texas. The transaction is expected to close during March 2007, with net proceeds to us of $31.5 million and an estimated after-tax loss of approximately $6.25 million.

Operations

During the year ended December 31, 2006, 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 operations as of December 31, 2006:


	Proved		%						2006
	Reserves		Natural			% Proved			Production
Areas of Operations	(Bcfe)₍₁₎		Gas			Developed			(MMcfe/d)₍₂₎
Rocky Mountain Region		159.7		88.9	%		20.1	%		9.2
Gulf Coast Region		111.0		55.3	%		44.3	%		25.4
Offshore California		2.8		—	%		100.0	%		2.7
Other		28.9		74.0	%		64.7	%		6.9

Total		302.4		74.3	%		34.0	%		44.2


(1)		Bcfe means billion cubic feet of gas equivalent

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

We intend to focus our development on two of our primary areas of operations in the Rocky Mountain and onshore Gulf Coast regions. For the year ending December 31, 2007, we estimate our exploration and development capital budget to range between $175.0 — $215.0 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 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 indirect interest in DHS, an affiliated Colorado corporation that is headquartered in Casper, Wyoming. During the second quarter of 2006, DHS engaged in a reorganization transaction pursuant to which it became a subsidiary of DHS Holding Company, a Delaware corporation, and the Company’s ownership interest became an interest in DHS Holding Company. References to DHS herein shall be deemed to include both DHS Holding Company and DHS, unless the context otherwise requires. DHS is a consolidated entity of Delta. Delta currently owns a 49.4% 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, 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 are currently working for third party operators.

The following table presents our average drilling revenue per day and rigs available for service for the year ended December 31, 2006 and the six months ended December 31, 2005:


	Year Ended		Six Months Ended
	December 31, 2006		December 31, 2005
Average number of rigs owned during period		12.3		6.4
Total rig days available¹		4,482		1,178
Average drilling revenue per day	$	16,747	$	13,312


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 18 trucks and 37 trailers, Chapman Trucking continues to market trucking services in the Casper, Wyoming area, ensures DHS rig mobility and provides moving services for third party drilling rigs.

Contracts — Drilling

All DHS drilling contracts are on a dayrate basis and 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. 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 gas are refineries and transmission companies which have facilities near our producing properties.

DHS’s principal market is the drilling of oil and natural gas wells for us and others in the Rocky Mountain and onshore Gulf Coast regions, although it currently has one rig operating in the Columbia River Basin of Washington. 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 financial resources, staffs and facilities substantially greater 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 to provide us with priority access to several large drilling rigs. We are also attempting to establish arrangements with others to assure adequate availability of certain other necessary drilling equipment and supplies on satisfactory terms, but there can be no assurance that we will be able to do so. Accordingly, there can be no assurance that we will not experience 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 our planned drilling projects.

Major Customers

During the year ended December 31, 2006, we had two companies that purchased greater than 10% of our oil and natural gas production. 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.

During 2006, 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 may in the future be, required in connection with our 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. To the extent such approvals are required and not granted, operations may be delayed or curtailed, or we may be prohibited from proceeding with planned exploration or operation of facilities.

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

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

Because we are engaged in acquiring, operating, exploring for and developing natural resources, in addition to federal laws, we are subject to various state and local provisions regarding environmental and ecological matters. Compliance with environmental laws may necessitate significant capital outlays, may materially affect our earnings potential, and could cause material changes in our proposed business. At the present time, however, these laws do not have a material adverse effect on our business. In addition, we do not anticipate that such expenditures will be materially significant during 2007.

Hazardous substances and waste disposal

We currently own or lease interests in numerous properties that have been used for many years for natural gas and crude oil production. Although the operator of such properties may have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us. In addition, some disposal sites that we have used have been operated by third parties over whom we had no control. The federal Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”) and comparable state statutes impose strict joint and several liability on current and former owners and operators of sites and on persons who disposed of or arranged for the disposal of “hazardous substances” found at such sites. The federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes govern the management and disposal of wastes. Although CERCLA currently excludes petroleum from cleanup liability, many state laws affecting our operations impose clean-up liability regarding petroleum and petroleum-related products.

In addition, although RCRA currently classifies certain exploration and production wastes as “non-hazardous,” such wastes could be reclassified as hazardous wastes, thereby making such wastes subject to more stringent handling and disposal requirements. If such a change were to occur, it could have a significant impact on our operating costs, as well as on the oil and gas industry in general.

Oil spills

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

of an applicable Federal safety, construction or operating regulation by the Responsible Party, its agent or subcontractor or in certain other circumstances. To date, we have not had any such material spills.

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

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

Offshore production

Offshore oil and gas operations in U.S. waters are subject to regulations of the United States Department of the Interior, Mineral Management Service (“MMS”), which currently impose strict liability upon the lessee under a federal lease for the cost of clean-up of pollution resulting from the lessee’s operations. As a result, such a lessee could be subject to possible liability for pollution damages. In the event of a serious incident of pollution, the Department of the Interior may require a lessee under federal leases to suspend or cease operations in the affected areas.

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

Abandonment Obligations

We are responsible for costs associated with the plugging of wells, the removal of facilities and equipment and site restoration on our oil and natural gas properties according to our pro rata ownership. As of July 1, 2002, we adopted SFAS No. 143 “Accounting for Asset Retirement Obligations.” SFAS No. 143 requires entities to record the fair value of liabilities for retirement obligations of acquired assets. We have an asset retirement obligation of approximately $4.4 million at December 31, 2006. 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, 2006 we had approximately 122 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 could 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.

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 redeterminations based on prices specified by our bank group at the time of redetermination. 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.

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 exploration and development capital budget is expected to range between $175.0 and $215.0 million for the year ending December 31, 2007. 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. Without adequate financing, we may not be able to successfully execute our operating strategy. We continue to examine the following sources of capital to supplement cash flow from operations:

•		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, 2006, our total outstanding long term liabilities were $374.1 million, with $118.0 million of outstanding borrowings drawn under our credit facility and $25.0 million outstanding on an unsecured term loan drawn in December, which was fully repaid in January 2007. Our long term indebtedness represented 46% of our total book capitalization at December 31, 2006. As of December 31, 2006, we had $12.0 million additional availability under our credit facility. Our 7% senior notes’ indenture currently limits our incurrence of secured borrowings to $130 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.

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, 2006, the six months ended December 31, 2005 and the fiscal years ended June 30, 2005 and 2004 included in our periodic reports filed with the SEC were prepared by our 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, 2006, a 10% increase or decrease in oil and gas price used would increase or decrease our proved reserve quantities at that date by approximately +/- 1% and our PV10 by approximately +/- 23%.

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, 2006, our reserve replacement rate was 429% (calculated by dividing our total reserve changes before sales for the period by our total production for the same period).

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

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

•		increases in the cost of, or shortages or delays in the availability of, drilling rigs and equipment;

•		unexpected drilling conditions;

•		title problems;

•		pressure or irregularities in formations;

•		equipment failures or accidents;

•		adverse weather conditions; and

•		compliance with environmental and other governmental requirements.

If oil or natural gas prices decrease or exploration and development efforts are unsuccessful, we may be required to take 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, 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, 2006. For 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 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 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 our evaluation of that prospect, we determined that we would not pursue development and accordingly an impairment was recorded. Included in our 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 in impairment costs for the remaining leasehold costs related to the prospect.

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 insignificant projects ($1.9 million). Additional costs will be expensed to dry hole during the first quarter of 2007 related to the Hingeline well as drilling continued into January 2007.

At December 31, 2006, we had $27.5 million classified as work in process related to exploratory projects. Included in that amount is $13.1 million related to wells determined to be successful in the first quarter of 2007. During 2007, the remaining costs will be capitalized as successful wells or expensed as dry holes based on final drilling results.

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, 2006 is estimated to be approximately $329.4 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 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 generally used to establish the price received for regional natural gas production and the actual 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. The terrorist attacks on September 11, 2001 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.

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 $12.5 million at December 31, 2006. 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 49.4% 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:

•		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 realized losses from effective hedging activities recognized in our statements of operations were $4.7 million, $3.4 million, $630,000 and $859,000 for the year ended December 31, 2006, six months ended December 31, 2005 and years ended June 30, 2005 and 2004, respectively. These losses are recorded as a decrease in revenues. At December 31, 2006, we had hedging gains of $10.2 million reflected in our consolidated balance sheet based on market prices in effect on December 31, 2006. Our actual hedging results may differ materially from the amount recorded at December 31, 2006.

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. We believe that our ownership interest in the drilling company will allow us to have priority access to drilling rigs. We are also attempting to establish arrangements with others to assure adequate availability of certain other necessary drilling equipment and supplies on satisfactory terms, but there can be no assurance that we will be able to do so. Accordingly, there can be no assurance that we will not experience 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 meet our drilling commitments.

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:

•		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. Our production was negatively impacted as certain wells were shut in during Hurricane Rita.

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, environmental protection or the oil and gas industry generally. Legislation affecting the industry is under constant review for amendment or expansion, frequently increasing our regulatory burden. Compliance with such laws and regulations often increases our cost of doing business and, in turn, decreases our profitability. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the incurrence of investigatory or remedial obligations, or issuance of cease and desist orders.

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

•		require applying for and receiving a permit before drilling commences;

•		restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production activities;

•		limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and

•		impose substantial liabilities for pollution resulting from our operations.

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

Risks Related To Our 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.

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, 2006, we had outstanding options to purchase 2,360,000 shares of common stock at a weighted average exercise price of $8.68. 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, 2006, our directors and executive officers and their respective affiliates collectively and beneficially owned approximately 6.0% of our outstanding common stock.

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

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

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

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

Item 1B. Unresolved Staff Comments.

None

Item 2. Properties.

Our primary areas of activity are in the Rocky Mountain Region, Gulf Coast Region and the Columbia River Basin in southeastern Washington. Total oil and gas leasehold in these areas comprises approximately 1.25 million acres.

Rocky Mountain Region

The Rocky Mountain Region comprises approximately 53% of our estimated proved reserves as of December 31, 2006. A large portion of our undeveloped acreage and drilling inventory is located in this region, where drilling efforts and capital expenditures will be increasingly focused.

In the Rocky Mountains, our primary activities are currently focused in five basins that provide a multi year inventory of core development drilling locations and exploration ventures.

Paradox Basin. In the Paradox Basin there are 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 and are now development projects.

Greentown. The Greentown project area has had two exploratory wells drilled that encountered economic recoverable reserves totaling 8.5 Bcfe gross in proved developed producing reserves as of December 31, 2006. These two wells resulted in gross proven reserves of 42 Bcfe (24 Bcfe net) over a 400 acre area. The wells are seven and a half miles apart, yet appear very analogous. The Greentown project is representative of the Company’s strategy of targeting reservoirs that demonstrate consistent geologic attributes that exist over large areas. The Company has a 70% working interest in 43,000 gross acres, 29,100 net acres virtually all of which are prospective. We have budgeted $15 — $20 million for drilling capital expenditures for the year ending December 31, 2007. In addition, we are currently planning for and staking a 25 mile natural gas pipeline that will service both the Greentown and Salt Valley project areas. We will construct, own and operate the pipeline and may cost $20 — $30 million.

Salt Valley. The Salt Valley project area has had one exploratory well drilled and encountered gross proved producing reserves totaling 200 Mbo (117 Mbo net) and total proven reserves of 1 MMbo (585 Mbo net) over a 200 acre area as of December 31, 2006. We have a 70% working interest in 7,100 gross acres, 4,900 net acres. Additional subsurface information suggests that this project area should have consistent geologic characteristics across the Company’s leasehold. We have budgeted $5 — $10 million for drilling capital expenditures for the year ending December 31, 2007.

Fisher Valley, Gypsum Valley and Cocklebur Draw. We are currently focusing our exploration efforts on the three remaining project areas which are located in San Miguel and Dolores Counties, Colorado and Grand County, Utah. We have a 70% working interest in 38,000 gross acres, 26,500 net acres, all of which were undeveloped at December 31, 2006. We plan to drill initial exploratory wells in 2007 with a capital budget of $5 million.

Piceance Basin. We are currently focusing our development efforts on the Vega Unit in Mesa County and the Garden Gulch Field in Garfield County, Colorado. These fields are consistent with our strategy of targeting reservoirs that demonstrate predictable geology over a large area. The Williams Fork member of the Mesaverde formation is the primary producing interval and has been successfully developed throughout the Piceance Basin.

Vega Unit. We have an interest in 3,800 net acres with a 100% working interest. During fiscal 2006 the Company increased proved reserves almost 100% to 97.6 Bcfe. During 2006 production from the field was curtailed due to a lack of pipeline capacity. The new Collbran Valley pipeline was completed in late 2006 and has provided an additional 60 MMcfg per day of pipeline capacity. This will allow us to increase current drilling activity to two DHS rigs running full time with the intention of further increases during 2007. The capital budget for the year ending December 31, 2007 is $82 — $90 million.

Garden Gulch. We have an interest in 1,200 net acres with an 18.74% non-operated working interest. The operator of the project currently has two rigs running full time and has identified plans to increase activity in the second half of 2007. Our capital budget for the year ending December 31, 2007 is approximately $10 million.

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.

Howard Ranch. In 2006 we recompleted two of our deeper wells to the Lower Fort Union reservoir with economic production results. As of December 31, 2006 the two wells had proved reserves of 1.3 Bcfge and 1.9 Bcfge from the Lower Fort Union. This formation exhibits consistent geologic characteristics across a large area. At year end we owned an interest in 6,300 net acres with an average working interest of 90%. Subsequent to year end we have acquired an additional 38,570 net acres, most of which is concentrated in the Howard Ranch area. Our 2007 capital budget for the Howard Ranch is approximately $25 – $30 million.

Central Utah Hingeline. The central Utah Hingeline region is an overthrust belt located in central Utah. We have an average 55% working interest in approximately 118,000 net acres. The Company drilled the first of its 21 geologic features in late 2006. The Joseph #1 well was drilled to a total depth of 13,500 and was plugged and abandoned as a dry hole. We are acquiring additional geophysical and aero magnetic data on the remaining 20 geologic features and plan to drill a second well later this year. Our 2007 capital budget is expected to be $8 — $10 million.

Denver-Julesburg (“D-J”) Basin. Our leasehold in the D-J Basin focuses on the Niobrara, “D” sand and “J” sand formations at depths of between 2,800’ and 8,000’. We have an interest in 480,500 net acres with a 100% working interest. Our proved reserves in this project area are 1.9 Bcfe as of December 31, 2006.

Gulf Coast Region

The Gulf Coast Region comprises approximately 37% of our estimated proved reserves as of December 31, 2006. In the Gulf Coast Region, our primary activities include developing the Newton, Midway Loop and Opossum Hollow Fields.

Development Projects — Newton, Midway Loop and Opossum Hollow Fields

Newton Field. The Newton Field is located in Newton County, Texas and represents an important growth platform for the Company in the Gulf Coast Region. We have an interest in 21,000 net acres with a 100% 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 identifying that the Wilcox sands are consistent across the structure. At year end, proved reserves in the Newton Field were 43.6 Bcfe.
We have experienced successful exploratory drilling on a seismically defined Wilcox structure north of the Newton Field. We will drill three wells on this new feature targeting the Lower Wilcox sands. In addition, we have targeted shallow seismic anomalies in the Yegua and Frio formations and plan further drilling activities. Our 2007 capital budget is expected to be $11 — $15 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 38% working interest. The wells in this field produce from the Austin Chalk and are drilled horizontally with dual laterals that reach up to 6,000’ of displacement in each lateral. As of December 31, 2006 our proved reserves totaled 28.5 Bcfe. The capital budget for the field in the year ending December 31, 2007 is $10 — $15 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 2006 we drilled a successful deep Sligo formation test and have identified additional locations. As of December 31, 2006 we had proved reserves of 1.4 Bcfe.

Other Areas

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, which fall into our core competency of multi-zone, multi-stage frac completion technologies. Based upon log evaluation of older wells, well testing and core analysis, there appear to be multiple productive zones with many hydrocarbon bearing sands which lie below thick layers of basalt. We have an interest in 467,500 net acres in the basin, all of which are undeveloped. The Company has a 100% working interest in 343,500 net acres, a 23% working interest in 403,000 gross acres (91,700 net acres) and a 1% overriding royalty interest convertible to a 15% back-in after project payout working interest under an additional 413,000 gross acres (32,300 net acres). The Columbia River Basin will be a long term project area and does not account for any of our proved reserves as of December 31, 2006.

In late 2005 we transferred our ownership in the above referenced convertible overriding royalty interest to CRB Partners, LLC (“CRBP”), which originally was a wholly owned subsidiary. In early 2006 we sold a minority interest in CRBP, but we retained the majority ownership and are the manager of CRBP.

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 2007 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. Drilling activities in 2006 proved to be uneconomic and further development is unknown.

Offshore California non-producing properties

We have ownership interests ranging from 2.49% to 100% in five unproved undeveloped offshore California oil and gas units in which we have recorded aggregate carrying values of $12.5 million and $11.0 million at December 31, 2006 and December 31, 2005, respectively. These non-operated property interests are located in close 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. Based on indications of levels of hydrocarbons present from drilling operations conducted in the past, we believe that the fair values of our property interests are in excess of their carrying values at December 31, 2006, and that no impairment in the carrying values has occurred. The recovery of our investment in these properties will require extensive exploration and development activities (and costs) which 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 Resources Company of Colorado (“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.

entirely by us. The value attributed to this lease represents significantly more than half of the net amount that would be received by us under the summary judgment. In its motion for reconsideration, the government has asserted that the affected lease is not being returned in substantially the same condition that it was in at the time it was initially granted because, allegedly, a significant portion of the hydrocarbons has been drained by wells that were drilled on an immediately adjacent lease. Although discovery is continuing on this issue, we currently believe that the government’s assertion is without merit and we are vigorously contesting it; however, 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, and the government filed a Notice of Appeal of the final judgment on that same date. The lease owned by us that is subject to the motion for reconsideration is not included in this order. The government’s appeal of the order of final judgment may contend 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 may appeal 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. See Item 3 “Legal Proceedings.”

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 67.1 Bcfe in proved reserves as of December 31, 2006.

DHS Drilling Company Rigs

The Company owns 49.4% of DHS which as of December 31, 2006 owned sixteen rigs with depth ratings of 7,500 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. 2	WY		2005		525		7,500
Rig No. 3	UT		2005		525		7,500
Rig No. 4	CO		2004		700		10,000
Rig No. 5	CO		2005		700		12,000
Rig No. 6	WY		2005		700		12,000
Rig No. 7	WA		2005		1,500		20,000
Rig No. 8	WY		2005		800		12,500
Rig No. 9	TX		2006		1,000		15,000
Rig No. 10	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	CA		2006		800		12,500
Rig No. 15	UT		2006		700		10,000
Rig No. 16	WY		2006		700		10,000
Rig No. 17	WY		2006		1,000		12,500

Office Facilities

Our offices are located at 370 Seventeenth Street, Suite 4300, Denver, Colorado 80202. We lease approximately 32,000 square feet of office space. Our current payment approximates $80,000 per month and our lease will expire in December 2014.

Production

During the year ended December 31, 2006, six months ended December 31, 2005 and fiscal years ended June 30, 2005 and 2004 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, 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 that were held for sale at December 31, 2006.

During the six months ended December 31, 2005, a dry hole was drilled on a prospect located in Orange County, California. We have determined that we will 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.

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 years ended June 30, 2005 and 2004.

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 year ended December 31, 2006, six months ended December 31, 2005 and each of the fiscal years ended June 30, 2005 and 2004.


						Six Months Ended
	Year Ended December 31,					December 31,					Years Ended June 30,
	2006					2005(1)					2005(1)					2004(1)
	Onshore			Offshore		Onshore			Offshore		Onshore			Offshore		Onshore			Offshore
Production volume –
Total production (MMcfe)		15,172			975		6,285			485		13,073			934		6,519			1,078

Production from continuing operations:
Oil (MBbls)		1,113			162		370			81		672			156		265			180
Natural Gas (MMcf)		7,713			—		3,391			—		6,221			—		1,610			—
Total (MMcfe)		14,390			975		5,609			485		10,255			934		3,200			1,078
Net average daily production-continuing operations:
Oil (Bbl)		3,049			445		2,009			439		1,842			427		726			493
Natural Gas (Mcf)		21,131			—		18,430			—		17,043			—		4,411			—
Average sales price:
Oil (per barrel)	$	63.71		$	46.75	$	59.44		$	47.12	$	47.07		$	33.37	$	32.96		$	22.11
Natural Gas (per Mcf)	$	5.93		$	—	$	8.78		$	—	$	5.72		$	—	$	5.32		$	—
Hedge effect (per Mcfe)	$	(.33	)	$	—	$	(1.42	)	$	—	$	(.06	)	$	—	$	(.27	)	$	—
Lease operating costs - (per Mcfe)	$	1.34		$	3.75	$	1.11		$	4.62	$	.90		$	3.90	$	.76		$	2.98


(1)		2004 and 2005 information has changed to comply with FAS 144 “Accounting for the Impairment or Disposal of Long-Lived Assets.”

Productive Wells and Acreage

The table below shows, as of December 31, 2006, 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		14		4.0		2,900		600
Colorado		363		16.6		54		36.6		4,700		2,700
Kansas		26		22.4		1		.6		900		900
Louisiana		10		2.3		5		—		1,400		600
Michigan		1		—		—		—		—		—
Mississippi		3		—		1		.4		600		100
New Mexico		2		—		21		7.9		6,100		2,700
North Dakota		27		2.1		—		—		11,300		1,300
Oklahoma		95		2.0		4		.4		2,900		500
Texas (4)		377		74.6		116		37.2		48,600		20,300
Utah		—		—		—		—		200		100
Wyoming		2		2		14		12.7		2,300		1,800

		942		124.2		245		99.9		93,300		32,400


(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, 2006, 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		659,700		529,700
Kansas		500		500
Montana		9,900		7,200
Oklahoma		200		200
Oregon		403,200		91,700
Texas		55,000		31,800
Utah		302,700		176,900
Washington		842,800		375,800
Wyoming		18,300		10,200

Total		2,357,700		1,240,000


(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.

Drilling Activity

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


	Year Ended				Six Months Ended				Years Ended June 30,
	December 31, 2006				December 31, 2005				2005				2004
	Gross		Net		Gross		Net		Gross		Net		Gross		Net

Exploratory Wells (1):
Productive:
Oil		4		3.15		2		1.42		5		3.94		3		1.40
Gas		4		4.00		—		—		3		1.15		1		.25
Nonproductive		4		3.50		6		3.83		8		7.15		5		3.25

Total		12		10.65		8		5.25		16		12.24		9		4.90

Development Wells (1):
Productive:
Oil		14		11.83		11		9.90		6		4.90		3		2.81
Gas		37		20.12		5		5.00		82		68.80		22		9.46
Nonproductive		1		1.00		2		1.50		7		7.00		3		3.00

Total		52		32.95		18		16.40		95		80.70		28		15.27

Total Wells (1):
Productive:
Oil		18		14.98		13		11.32		11		8.84		6		4.21
Gas		41		24.12		5		5.00		85		69.95		23		9.71
Nonproductive		5		4.00		8		5.33		15		14.15		8		6.25

Total Wells		64		43.60		26		21.65		111		92.94		37		20.17


(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, 2007:


	Gross Drilling		Drilling
Areas of Operations	Locations		Budget
			(In millions)
Rocky Mountain Region		75 - 95	$	140 - $162
Gulf Coast Region		4 - 7	$	20 - $30
Other		1 - 3	$	15 - $23

Total		80 - 105	$	175 - $215

Item 3. Legal Proceedings

Offshore Litigation

We and our 92% owned subsidiary, Amber Resources Company of Colorado (“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.

The Court has further ruled under a restitution theory of damages 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. Together with Amber, our net share of the $1.1 billion award is approximately $120 million. This award is subject to appeal and the government has filed a motion for reconsideration of the ruling as it relates to a single lease owned entirely by us. The value attributed to this lease represents significantly more than half of the net amount that would be received by us under the summary judgment. In its motion for reconsideration, the government has asserted that the affected lease is not being returned in substantially the same condition that it was in at the time it was initially granted because, allegedly, a significant portion of the hydrocarbons has been drained by wells that were drilled on an immediately adjacent lease. Although discovery is continuing on this issue, we currently believe that the government’s assertion is without merit and we are vigorously contesting it; however, 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, and the government filed a Notice of Appeal of the final judgment on that same date. The lease owned by us that is subject to the motion for reconsideration is not included in this order. The government’s appeal of the order of final judgment may contend 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 may appeal 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.

Options Inquiries

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’s office and to the SEC in August 2006 and intend to continue to cooperate fully with the U.S. Attorney and the SEC if they should request any additional information concerning this matter in the future.

Shareholder Derivative Suits

During September and October of 2006, three separate shareholder derivative actions were filed on our behalf in US District Court for the District of Colorado relating to the options backdating issue, all of which have been consolidated into a single action. The consolidated complaint alleges that certain of our executive officers and directors engaged in various types of misconduct in connection with certain stock option grants. Specifically, the plaintiffs allege 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 allege 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 seeks 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. A discovery stay has been granted while the court considers various motions to dismiss the action.

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

An Annual Meeting of our shareholders was held on October 17, 2006. At the Annual Meeting the following persons, constituting the entire board of directors, were elected as directors of the Company to serve until the next annual meeting:


Name	For		Against
Roger A. Parker		37,885,794		75,340
Aleron H. Larson, Jr.		37,936,708		24,426
Jerrie F. Eckelberger		37,879,276		81,858
James B. Wallace		37,936,485		24,649
Russell S. Lewis		37,934,825		26,309
Kevin R. Collins		37,935,028		26,106
Jordan R. Smith		37,935,134		26,000
Neal A. Stanley		37,939,217		21,917
James P. Van Blarcom		37,934,999		26,135

The appointment of KPMG, LLP as our auditors for the year ended December 31, 2006, was ratified with 37,869,034 affirmative votes, 37,129 negative votes, and 54,971 abstentions.

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		45	Chairman, Chief Executive Officer and a Director	May 1987 to Present

John R. Wallace		47	President and Chief Operating Officer	October 2003 to Present

Kevin K. Nanke		42	Treasurer and Chief Financial Officer	December 1999 to Present

Stanley F. Freedman		58	Executive Vice President, General Counsel and Secretary	January 2006 to Present

Kevin R. Collins		50	Director	March 2005 to Present

Jerrie F. Eckelberger		62	Director	September 1996 to Present

Aleron H. Larson, Jr.		61	Director	May 1987 to Present

Russell S. Lewis		52	Director	June 2002 to Present

Jordan R. Smith		72	Director	October 2004 to Present

Neal A. Stanley		59	Director	October 2004 to Present

James P. Van Blarcom		45	Director	July 2005 to Present

James B. Wallace		77	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 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. Since April 1, 2005, he has also served as Executive Vice President and Director of DHS Drilling Company. Mr. Wallace was Vice President of Exploration and Acquisitions for United States Exploration, Inc. (“UXP”), a Denver-based publicly-held oil and gas exploration company, from May 1998 to October 2003. Prior to UXP, Mr. Wallace served as president of various privately held oil and gas companies engaged in producing property acquisitions and exploration ventures. He received a Bachelor of Science 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 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 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.

Kevin R. Collins currently serves as Executive Vice President – Chief Operating Officer of Evergreen Energy Inc. Prior to his current position, Mr. Collins served as 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 B.S. 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, until his retirement on July 1, 2005, at which time he resigned as Chairman of the Board and as an executive officer of the Company. He ceased to be an officer or director of Amber Resources on January 3, 2006. Mr. Larson practiced law in Breckenridge, Colorado from 1971 until 1974. During this time he was a member of a law firm, Larson & Batchellor, engaged primarily in real estate law, land use litigation, land planning and municipal law. In 1974, he formed Larson & Larson, P.C., and was engaged primarily in areas of law relating to securities, real estate, and oil and gas until 1978. Mr. Larson received a Bachelor of Arts degree in Business Administration from the University of Texas at El Paso in 1967 and a Juris Doctor degree from the University of Colorado in 1970.

Russell S. Lewis is 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 BA degree in Economics from Haverford College and an MBA from the Harvard School of Business.

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 Bachelors and Masters 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 approximately 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 B.S. degree in Mechanical Engineering from the University of Oklahoma in 1975.

James P. Van Blarcom has been Managing Director of The Payne Castle Group, LLC, which is located in Blue Bell, Pennsylvania and has provided sales solutions, business development and government affairs services in the cable, high-speed internet and communications industries since 2004. From 1998 to 2004, he was employed by Comcast Cable Communications Management, LLC, a division of Comcast Corporation, where he served as National Telecommunications Manager, Corporate Telecommunications Manager, and finally as Commercial Development Manager, Comcast High-Speed Internet. Mr. Van Blarcom received a B.A. degree in History from Hobart College in 1984. Health issues are currently preventing Mr. Van Blarcom from active participation on the Board.

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 B.S. Degree in Business Administration from the University of Southern California in 1951. James B. Wallace is the father of John R. Wallace, the President of Delta.

At the present time Messrs. Collins, Eckelberger, Lewis, and Smith serve as the Audit Committee; Messrs. Eckelberger, Collins, Lewis, and Smith serve as the Compensation Committee; and Messrs. Smith, Collins, Eckelberger, Lewis and Stanley serve as the Nominating & Governance Committee.

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, 2004	$	15.47	$	10.01
December 31, 2004		16.11		12.67
March 31, 2005		17.07		12.87
June 30, 2005		14.95		8.99

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

On March 7, 2007, the closing price of our common stock was $18.27. 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 20, 2007 was approximately 1,550 which does not include an estimated 10,300 additional holders whose stock is held in “street name.”

Recent Sales of Unregistered Securities

During the year ended December 31, 2006, 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, 2006.

Item 6. Selected Financial Data

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


	Year Ended						Six Months Ended
	December 31,						December 31,			Years Ended June 30,
	2006			2005			2005			2005			2004			2003			2002
				(Unaudited)
	(In thousands, except per share amounts)
Total Revenues	$	176,649		$	107,472		$	61,228		$	76,574		$	20,414		$	11,770		$	7,514
Income (loss) from Continuing Operations	$	(21,226	)	$	(24,855	)	$	(22,696	)	$	(389	)	$	(8,106	)	$	(5,446	)	$	(6,377	)
Net Income (Loss)	$	435		$	5,706		$	(590	)	$	15,050		$	5,056		$	1,257		$	(6,253	)
Income/(Loss) Per Common Share
Basic	$	.01		$	.13		$	(.01	)	$	.37		$	.19		$	.05		$	(.49	)
Diluted	$	.01		$	.13		$	(.01	)	$	.36		$	.17		$	.05		$	(.49	)
Total Assets	$	929,344		$	693,393		$	693,393		$	512,983		$	272,704		$	86,847		$	74,077
Total Liabilities	$	473,721		$	357,442		$	357,442		$	276,746		$	86,462		$	38,944		$	29,161
Minority Interest	$	27,390		$	15,496		$	15,496		$	14,614		$	245		$	—		$	—
Stockholders’ Equity	$	428,233		$	320,455		$	320,455		$	221,623		$	185,997		$	47,903		$	44,916
Total Long-Term Liabilities	$	374,958		$	257,743		$	257,743		$	222,596		$	72,172		$	33,082		$	24,939


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

Overview

We are a Denver, Colorado based independent energy 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, 2006, we had estimated proved reserves that totaled 302.4 Bcfe, of which 34.0% were proved developed, with an after-tax PV-10 value of $483.2 million. As of December 31, 2006, we achieved net continuing production of 42.1 Mmcfe per day.

As of December 31, 2006, our reserves were comprised of approximately 224.7 Bcf of natural gas and 12.9 Mmbbls of crude oil, or 74.3% gas on an equivalent basis. Approximately 37% of our proved reserves were located in the Gulf Coast, 53% in the Rocky Mountains, and 10% in other locations. We expect that our drilling efforts and capital expenditures will focus increasingly on the Rockies, where approximately 75-80% of our fiscal 2007 drilling budget is allocated and more than one-half of our undeveloped acreage is located. As of December 31, 2006, we controlled approximately 1,240,000 net undeveloped acres, representing approximately 97% of our total acreage position. We retain a high degree of operational control over our asset base, with an average working interest in excess of 85% (excluding CRB properties) as of December 31, 2006. 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 16 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.

For calendar year 2007, we have preliminarily established a drilling budget of approximately $175.0 to $215.0 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 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 is 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 while containing costs 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 involve 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. Our current derivative contracts cover approximately 14.7 Bcfe% of our estimated 2007 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, 2006, we achieved the following:

•		Increased reserves to 302.4 Bcfe at December 31, 2006, an increase of 12.2% or 19.7% after considering current year sales and purchases, compared to reserves as of December 31, 2005 of 269.4 Bcfe.

•		During the fourth quarter of 2006, three successful exploratory wells were drilled in the Paradox Basin establishing a new significant area for the Company. Total reserve additions were 28.0 Bcfe and $20 to $30 million of the Company’s 2007 drilling budget has been allocated to the Greentown and Salt Valley projects.

•		Our total production for the year ended December 31, 2006 was 16.1 Bcfe. Adjusted for asset dispositions, our production from continuing operations increased 23% to 15.4 Bcfe, compared to 12.5 Bcfe for the prior year period, primarily as a result of exploratory and developmental drilling during 2006.

Results of Operations

The following discussion and analysis relates to items that have affected our results of operations for the years ended December 31, 2006 and 2005, six months ended December 31, 2005 and 2004, and the fiscal years ended June 30, 2005 and 2004. 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 operation 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.


	Years Ended						Six Months Ended						Years Ended
	December 31,						December 31,						June 30,
	2006			2005			2005			2004			2005			2004
				(Unaudited)						(Unaudited)
Revenue:
Oil and gas sales	$	124,212		$	97,830		$	55,545		$	30,123		$	72,408		$	21,273
Contract drilling and trucking fees		57,149			13,592			9,096			300			4,796			—
Realized loss on derivative instruments, net		(4,712	)		(3,950	)		(3,413	)		(93	)		(630	)		(859	)

Total Revenue		176,649			107,472			61,228			30,330			76,574			20,414

Operating Expenses:
Lease operating expense		22,935			16,738			8,483			4,599			12,854			5,643
Transportation expense		1,231			1,194			808			154			539			231
Production taxes		6,755			5,674			3,133			2,327			4,868			1,212
Depreciation, depletion and amortization — oil and gas		64,068			27,871			16,024			7,035			18,892			7,031
Depreciation and amortization — drilling and trucking		16,404			3,987			2,847			386			1,525			14
Exploration expense		4,690			6,933			2,061			1,283			6,155			2,406
Dry hole costs		4,323			4,171			4,073			2,673			2,771			2,132
Abandoned and impaired properties		11,359			1,350			1,350			—			—			—
Drilling and trucking operations		34,163			9,413			5,821			1,074			4,666			232
General and administrative		35,696			26,470			16,491			6,951			16,930			8,049
Gain on sale of oil and gas properties		(20,034	)		—			—			—			—			—

Total operating expenses		181,590			103,801			61,091			26,482			69,200			26,950


Operating income (loss)		(4,941	)		3,671			137			3,848			7,374			(6,536	)

Other income and (expense):
Other income (expense)		421			(170	)		173			(149	)		(492	)		122
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		11,722			(14,767	)		(14,437	)		—			(330	)		—
Minority interest		(2,595	)		14			(688	)		315			1,017			70
Interest and financing costs		(26,891	)		(14,797	)		(9,075	)		(2,236	)		(7,958	)		(1,762	)

Total other expense		(16,285	)		(28,526	)		(22,833	)		(2,070	)		(7,763	)		(1,570	)


Income (loss) from continuing operations before income taxes and discontinued operations		(21,226	)		(24,855	)		(22,696	)		1,778			(389	)		(8,106	)

Income tax benefit		7,931			13,510			8,451			—			7,987			—


Net income (loss) from continuing operations		(13,295	)		(11,345	)		(14,245	)		1,778			7,598			(8,106	)
Income from discontinued operations of properties sold, net of tax		1,458			5,263			1,867			6,976			7,452			11,275
Gain on sale of oil and gas properties, net of tax		6,712			11,788			11,788			—			—			1,887
Extraordinary gain, net of tax		5,560			—			—			—			—			—


Net income (loss)	$	435		$	5,706		$	(590	)	$	8,754		$	15,050		$	5,056

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 $8.6 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 27% to $124.2 million, as compared to $97.8 million for the year ended December 31, 2005. The increase was the result of a 23% 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 $63.71 per Bbl compared to $54.34 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 $5.93 per Mcf compared to $7.17 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 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 are currently working for third party operators. Drilling revenues earned on wells drilled for Delta have been eliminated through consolidation.

Drilling revenues for the year ended December 31, 2006 increased to $50.0 million compared to $13.6 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 8 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.

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					2005
	Onshore			Offshore		Onshore			Offshore
Production – Continuing Operations:
Oil (MBbl)		1,113			162		736			162
Gas (MMcf)		7,713			—		7,131			—
Production – Discontinued Operations:
Oil (MBbl)		79			—		160			—
Gas (MMcf)		309			—		967			—

Total Production (MMcfe)		15,172			975		13,474			972

Average Price – Continuing Operations:
Oil (per barrel)	$	63.71		$	46.75	$	54.34		$	41.46
Gas (per Mcf)	$	5.93		$	—	$	7.17		$	—

Costs per Mcfe – Continuing Operations:
Hedge effect	$	(0.33	)	$	—	$	(.73	)	$	—
Lease operating expense	$	1.34		$	3.75	$	1.08		$	4.42
Production taxes	$	.47		$	.05	$	.49		$	.06
Transportation costs	$	.09		$	—	$	.10		$	—
Depreciation, depletion and amortization expense	$	3.98		$	1.08	$	2.35		$	.79

Lease Operating Expense. Lease operating expenses for the year ended December 31, 2006 were $22.9 million compared to $16.7 million for the same period a year earlier. Lease operating expense increased due to our 22% 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 $1.34 per Mcfe as compared to

$1.08 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 $64.1 million in the year ended December 31, 2006, as compared to $27.9 million for the year ended December 31, 2005. Depreciation, depletion and amortization expenses for our onshore properties increased to $3.98 per Mcfe during the year ended December 31, 2006 from $2.35 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. Current year activities include 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.

Dry Hole Costs. 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 a year ago. 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.

Abandoned and Impaired Properties. 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, 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 has increased with added headcount for DHS growth during the past year 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. As a result of the transaction, Delta now owns a net interest of 32,300 acres in the Columbia River Basin through its remaining ownership of CRBP and a direct 100% interest in 343,500 net acres in the Columbia River Basin from previous transactions.

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 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 years ended December 31, 2006 DHS generated a greater profit resulting in increased minority interest expense.

Interest and Financing Costs. Interest and financing costs increased 82% to $26.9 million for the year ended December 31, 2006, as compared to $14.8 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 $7.9 million was recorded for continuing operations at an effective tax rate of 37.4% compared to an income tax benefit of $13.5 million and an effective tax rate of 54.4% 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 results of operations on these assets, net of tax, during the years ended December 31, 2006 and 2005 were $1.5 million and $5.3 million, respectively.

Extraordinary Gain. An extraordinary gain was recorded during the year as required by Statement of Financial Accounting Standards No. 141 “Business Combinations” (“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 $6.8 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 84% to $55.5 million, as compared to $30.1 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 $5.73 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 $59.44 per Bbl compared to $44.52 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 28.0% 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.

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.

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)		370			81			306			74
Gas (MMcf)		3,391			—			2,481			—
Production – Discontinued Operations:
Oil (MBbl)		58			—			125			—
Gas (MMcf)		329			—			817			—

Total Production (MMcfe)		6,285			485			5,884			444

Average Price – Continuing Operations:
Oil (per barrel)	$	59.44		$	47.12		$	44.52		$	30.66
Gas (per Mcf)	$	8.78		$	—		$	5.73		$	—

Costs per Mcfe – Continuing Operations:
Hedge effect	$	(.61	)	$	—		$	(.02	)	$	—
Lease operating expense	$	1.11		$	4.62		$	0.70		$	3.56
Production taxes	$	.58		$	(.23	)	$	.53		$	.06
Transportation costs	$	.14		$	—		$	.04		$	—
Depreciation, depletion and amortization expense	$	2.79		$	.79		$	1.55		$	.75


(1)		2005 and 2004 information has changed to comply with FAS 144 “Accounting for the Impairment or Disposal of Long-Lived Assets.”

Lease Operating Expense. Lease operating expenses for the six months ended December 31, 2005 were $8.5 million compared to $4.6 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 $1.11 per Mcfe as compared to $0.70 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 128% to $16.0 million in the six months ended December 31, 2005, as compared to $7.0 million for the six months ended December 31, 2004. Depreciation, depletion and amortization expenses for our onshore properties increased to $2.79 per Mcfe during the six months ended December 31, 2005 from $1.55 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 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 will assist us in prioritizing our drilling locations and identifying new target formations in 2006. 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. 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.

Abandoned and Impaired Properties. 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. 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.

Interest and Financing Costs. Interest and financing costs increased 306% to $9.1 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 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 $8.5 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, and certain Oklahoma properties which were held for sale at December 31, 2006. The results of operations on these assets during the six months ended December 31, 2005 and 2004 were $1.9 million and $7.0 million, respectively.

Fiscal 2005 Compared to Fiscal 2004

Net Income. Net income increased $10.0 million to $15.1 million or $.36 per diluted common share for fiscal 2005, an increase of 198% as compared to $5.1 million or $.17 per diluted common share for fiscal 2004. This increase was primarily due to a 91% increase in production relating to the Alpine acquisition completed during fiscal 2004, the Manti acquisition completed during fiscal 2005 and the development of our undeveloped properties.

Revenue. During fiscal 2005, oil and natural gas revenue from continuing operations increased 240% to $72.4 million, as compared to $21.3 million in fiscal 2004. The increase was the result of an average onshore gas price received in fiscal 2005 of $5.72 per Mcf compared to $5.32 per Mcf in 2004, an increase in average onshore oil price received in fiscal 2005 of $47.07 per Bbl compared to $32.96 per Bbl in 2004, an increase in offshore oil price received of $33.37 per Bbl in fiscal 2005 compared to $22.11 in 2003, and a 161% increase in average daily production over the prior year.

Cash payments required on our hedging activities impacted revenues in 2005 and 2004. The cost of settling our hedging activities was $630,000 in fiscal 2005 and $859,000 in fiscal 2004.

Production volumes, average prices received and cost per equivalent Mcf for the years ended June 30, 2005 and 2004 are as follows:


	Years Ended June 30,
	2005⁽¹⁾					2004⁽¹⁾
	Onshore			Offshore		Onshore			Offshore
Production – Continuing Operations:
Oil (MBbl)		672			156		265			180
Gas (MMcf)		6,221			—		1,610			—
Production – Discontinued Operations:
Oil (MBbl)		227			—		303			—
Gas (MMcf)		1,455			—		1,500			—

Total Production (MMcfe)		13,073			934		6,519			1,078

Average Price – Continuing Operations:
Oil (per barrel)	$	47.07		$	33.37	$	32.96		$	22.11
Gas (per Mcf)	$	5.72		$	—	$	5.32		$	—

Costs per Mcfe – Continuing Operations:
Hedge effect	$	(.06	)	$	—	$	(.26	)	$	—
Lease operating expense	$	.90		$	3.90	$	.76		$	2.98
Production taxes	$	.46		$	.21	$	.36		$	.04
Transportation costs	$	.05		$	—	$	.07		$	—
Depreciation, depletion and amortization expense	$	1.77		$	.77	$	1.98		$	.65


(1)		2005 and 2004 information has changed to comply with FAS 144 “Accounting for the Impairment or Disposal of Long-Lived Assets.”

Lease Operating Expense. Lease operating expenses for the year ended June 30, 2005 were $12.9 million compared to $5.6 million for the same period a year earlier. Lease operating expense from continuing operations for onshore properties for the year ended June 30, 2005 was $.90 per Mcfe as compared to $.76 per Mcfe for the same period a year earlier. Lease operating expense from continuing operations for offshore properties was $3.90 per Mcfe for the year ended June 30, 2005 and $2.98 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 completion of the Manti acquisition in January 2005 and the Alpine acquisition in June 2004. The assets acquired in these two transactions have higher production costs than the asset base previously owned.

Depreciation and Depletion Expense. Depreciation and depletion expense increased 169% to $18.9 million in fiscal 2005, as compared to $7.0 million in fiscal 2004. Depreciation and depletion expenses for our onshore properties decreased to $1.77 per Mcfe during fiscal 2005 from $1.98 per Mcfe in fiscal 2004. Depletion rates have decreased based on the relative mix of production during 2005, with greater amounts of production from lower depletion rate properties.

Exploration Expense. Exploration expense consists of geological and geophysical costs and lease rentals. Our exploration costs for the year ended June 30, 2005 were $6.2 million compared to $2.4 million for the prior year. Fiscal 2005 activities include newly acquired seismic information in Washington County, Colorado, Polk County, Texas and Laramie County, Wyoming.

Dry Hole Costs. We incurred dry hole costs of approximately $2.8 million for the year ended June 30, 2005 compared to $2.1 million for the same period a year ago. A significant portion of these costs relate to our Trail Blazer prospect in Laramie County, Wyoming. Included in the dry holes were four non-Niobrara formation dry holes in Washington County, Colorado.

Drilling and Trucking Operations. We had drilling and trucking operations of $4.7 million during the year ended June 30, 2005 compared to $232,000 during the year ended June 30, 2004. The significant increase in expenses was due to an increase in the number of rigs in operation.

General and Administrative Expense. General and administrative expense increased 110% to $16.9 million in fiscal 2005, as compared to $8.0 million in fiscal 2004. The increase in general and administrative expenses is primarily attributed to the 95% increase in technical and administrative staff and related personnel costs, the expansion of our office facility, $824,000 of vested restricted stock and option awards granted to officers, directors and management and an $800,000 increase in professional fees attributed largely to compliance with the Sarbanes-Oxley Act.

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.

Interest and Financing Costs. Interest and financing costs increased 352% to $8.0 million in fiscal 2005, as compared to $1.8 million in fiscal 2004. The increase is primarily related to the $150.0 million senior note offering completed in March 2005 and 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.

Liquidity and Capital Resources

Liquidity is a measure of a company’s ability to access cash. Our cash requirements are largely dependent upon the number and timing of projects included in our capital development plan, most of which is 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 and sales of oil and gas properties, and through borrowings under our credit facility.

During the year ended December 31, 2006, we had an operating loss of $4.9 million, generated cash from operating activities of $53.4 million and obtained cash from financing activities of $151.8 million. During this year we spent $136.0 million on oil and gas development (or $218.8 million, net of $82.7 million proceeds from dispositions), $8.6 million on oil and gas acquisitions, and $54.8 million on drilling and trucking capital expenditures (or $63.8 million, net of $9.0 million contributed by minority interest partners). At December 31, 2006, we had $7.7 million in cash, total assets of $929.3 million and a debt to total capitalization ratio of 46.1%. Long-term debt at December 31, 2006 totaled $370.5 million, comprised of $221.1 million combined bank debt and $149.4 million of senior subordinated notes. In May 2006, DHS closed a new $100.0 million Senior Secured Credit Facility with JP Morgan Chase Bank, N.A., as administrative agent, of which $75.0 million was initially drawn. In June 2006, the borrowing base on Delta’s credit facility was increased by $45.0 million to $120.0 million, and again increased to $130.0 million in November 2006. Also in December 2006, we entered into an unsecured term loan with JP Morgan Chase Bank, N.A. for $25.0 million which was subsequently repaid in January 2007 with proceeds from an equity offering. Available borrowing capacity under the Delta bank credit facility at December 31, 2006 was approximately $12.0 million, and $25.0 million was available for DHS under its credit facility.

Beginning with the quarter ending March 31, 2007, 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) of less than 4.25 to 1 for the quarters ending March 31 and June 30, 2007, 4.0 to 1 for the quarters ending September 30 and December 31, 2007, and 3.75 to 1 for the end of each quarter thereafter. These financial covenant calculations only reflect wholly-owned subsidiaries. We expect to meet our covenants at March 31, 2007 and for the remainder of the year.

Although we expect to continue with development of our properties, a significant portion of our planned capital expenditures are discretionary and can be delayed or curtailed, if necessary, given adequate lead time. If we do not meet our covenants in the future and we are unable to obtain a waiver from the banks, we would be in default of the terms of our credit facility, our long-term debt would be reclassified to a current liability in our consolidated balance sheet and the outstanding principal balance could be called by the banks, thereby becoming immediately due and payable. During the fourth quarter of 2006, our credit facility was amended to contain covenant requirements that better match our development plans and operating strategy.

During 2006, we have completed several equity, debt, and property transactions as described below. On February 1, 2006, we completed a public offering of 1.5 million shares of our common stock for net proceeds of $33.9 million, a portion of which were used to fund the cash portion of the purchase price in an acquisition of certain oil and gas property interests in Central Utah from Armstrong Resources, LLC (“Armstrong”). During the first quarter of 2006, we sold minority interests in CRBP and PGR for proceeds of $32.8 million and $20.4 million, respectively. In April 2006, the Company closed its acquisition of Castle Energy Corporation with the net issuance of 1.8 million shares of common stock. The Company received approximately $21.0 million in cash in connection with the Castle acquisition. In June 2006, the Company

sold its Frisco properties for proceeds of $9.0 million. In addition, during August 2006, the Company sold certain East Texas properties and the Pennsylvania properties acquired in the Castle acquisition for proceeds of $14.6 million and $15.9 million, respectively.

Our short-term liquidity needs at December 31, 2006, were aided by certain cash generating transactions in the first quarter of 2007. In January 2007, we sold non-core properties in Kansas which accounted for 1.3 Bcfe of proved reserves at December 31, 2006, for proceeds of $5.6 million and in February 2007, we executed a purchase and sale agreement to sell non-core Gulf coast and Permian Basin properties which accounted for 22.6 Bcfe of proved reserves at December 31, 2006, for net proceeds of $31.5 million. Also, in January 2007, we raised net proceeds of $56.6 million through a public offering of 2,768,000 shares of common stock.

The prices we receive for future oil and natural gas production and the level of production have a significant impact on 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.

We believe that borrowings under our Revolving Credit Facility, projected operating cash flows, proceeds from additional debt and equity financings and cash on hand will be sufficient to meet the requirements of our business; however, future cash flows are subject to a number of variables, including the level of production and oil and natural gas prices. We cannot give assurance that operations and other capital resources will provide cash in sufficient amounts to maintain planned levels of capital expenditures or that increased capital expenditures will not be undertaken. Most of our capital expenditures are discretionary, and actual levels of capital expenditures may vary significantly due to a variety of factors, including but not limited to, drilling results, product pricing and future acquisitions and divestitures of properties.

Although we believe we have access to adequate capital to fund our development plans, we continue to examine alternative 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, some 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, 2006, we completed the following transactions:

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 in November 2006 and is currently under contract to a third party operator in Wyoming.

In May 2006, DHS acquired two rigs (“Rig 12” and “Rig 14”) in conjunction with the acquisition of C&L Drilling Company, Inc. for a purchase price of approximately $16.7 million. The rigs are currently under contract to third party operators and working in California and Utah.

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, through its 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 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 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.

On February 1, 2006, we entered into a purchase and sale agreement with Armstrong to acquire a 65% working interest in approximately 88,000 gross acres in the central Utah hingeline play for a purchase price of $24 million in cash and 673,401 shares of common stock. The Company funded the cash portion of the purchase price with proceeds from a $33.9 million stock offering. Armstrong initially retained the remaining

35% working interest in the acreage. As part of the transaction, Delta agreed to pay 100% of the drilling costs for the first three wells in the project. Delta is the operator of the majority of the acreage. The first well commenced drilling in November 2006 and was determined to be a dry hole.

In January 2006, we purchased Rooster Drilling Company for 350,000 shares of Delta common stock valued at $8.3 million. Rooster Drilling owned one drilling rig, (“Rig 15”). The rig is an Oilwell 66, with a depth apacity of 12,000 feet. In March 2006, the Company contributed Rooster Drilling (renamed “Hastings Drilling Company”) to DHS.

Historical Cash Flow

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 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.

Our cash flow from operating activities increased 28% to $24.9 million for the six months ended December 31, 2005 compared to $19.0 million for the same period a year earlier, primarily as a result of a 101% increase in revenue and a 127% increase in non cash depletion expense. Our net cash used in investing activities increased by 341% to $146.5 million for the six months ended December 31, 2005 compared to $33.2 million for the same period a year earlier. The increase in cash used for investing activity can be attributed to the expansion of our drilling programs in both the Rocky Mountain and Gulf Coast regions along with additional drilling rig acquisitions. Cash flow from financing was $124.9 million for the six months ended December 31, 2005 compared to $13.5 for the same period the prior year. During the six months ended December 31, 2005 we financed our operations, acquisitions, and capital expenditures primarily with net proceeds of $95.0 million in newly issued equity and $29.2 million in net debt additions.

Capital and Exploration Expenditures and Financing

Our capital and exploration expenditures and sources of financing for the year ended December 31, 2006, six months ended December 31, 2005 and years ended June 30, 2005 and 2004 are as follows:


	Year			Six Months		Year
	Ended			Ended		Ended
	December 31,			December 31,		June 30,
	2006			2005		2005		2004
	(In thousands)
CAPITAL AND EXPLORATION EXPENDITURES:
Acquisitions:
Armstrong Acquisition	$	40,103		$	—	$	—	$	—
Castle		33,648			—		—		—
Savant Acquisition		—			85,000		—		—
Manti		—			—		59,700		—
Columbia River Basin		—			—		18,255		—
Washington County, South and North Tongue		—			828		10,571		30,406
Sacramento Basin		—			—		10,400		—
Karnes County, Texas		—			—		5,000		—
Alpine Resources		—			—		—		120,655
Other		24,678			7,904		2,718		—
Other development costs		179,874			86,871		102,216		37,969
Drilling and trucking companies		63,848			25,733		32,690		3,965
Exploration costs		4,690			3,411		6,155		2,406

	$	346,841		$	209,747	$	247,705	$	195,401


FINANCING SOURCES:
Cash flow provided by operating activities		53,386		$	24,879	$	44,862	$	9,623
Stock issued for cash upon exercised options		3,711			1,166		132		3,563
Stock issued for cash, net		33,870			95,026		—		97,902
Net long-term borrowings		114,265			28,715		139,051		37,157
Proceeds from sale of oil and gas properties		82,716			34,178		18,721		10,787
Minority interest contributions		9,018			—		14,800		315
Other		(3,646	)		2,566		63		(1,036	)

	$	293,320		$	186,530	$	217,629	$	158,311

We anticipate our capital and exploration expenditures to range between $175.0 and $215.0 million for the year ending December 31, 2007 based on expected cash-flow from operations, the proceeds of our stock issuance and sale of properties in the first quarter of 2007, and anticipated other property or equity transactions during the course of 2007. 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

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 a newly created wholly owned subsidiary, CRBP. In January and March 2006, Delta 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, 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. As a result of the transaction, Delta now owns a net interest of just over 32,300 acres in the Columbia River Basin through its remaining ownership of CRBP and additional 100% interests in 345,000 net acres in the Columbia River Basin from previous transactions.

In March 2006, the Company 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. The Company 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. The Company has retained a 74% interest in PGR.

In June 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 a net gain on sale of oil and gas properties of $596,000. The pre-tax income from discontinued operations of these oil and gas properties was $607,000 and $1.9 million for the years ended December 31, 2006 and 2005, respectively. In accordance with Statement of Financial Accounting Standards 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 Louisiana property interests have been reflected as discontinued operations.

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). The pre-tax income from discontinued operations of these assets was $861,000 and $2.1 million for the years ended December 31, 2006 and 2005, respectively.

On August 21, 2006, the Company completed the sale of the properties acquired with the Castle acquisition in April 2006. During the three months ended June 30, 2006 the Company recorded a $6.1 million extraordinary gain in accordance with SFAS No. 141. During the year ended December 31, 2006 the extraordinary gain was adjusted by $515,000 to true-up the gain for final proceeds and settlement statement items. The net pre-tax loss from discontinued operations of these assets was $195,000 for the year ended December 31, 2006 and zero for the same period in the prior year.

Also included in discontinued operations are the results from the Company’s Kansas properties and certain properties in Oklahoma that were held for sale at December 31, 2006. The pre-tax income from discontinued operations of these oil and gas properties was approximately $1.1 million and $2.0 million for the years ended December 31, 2006 and 2005, respectively.

Contractual and Long-Term Debt Obligations


	Payments Due by Period
	Less than						After
Contractual Obligations at December 31, 2006	1 year		2-3 Years		4-5 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		36,283		88,783
Credit facility		—		—		118,000		—		118,000
Unsecured term loan		—		—		25,000		—		25,000
Term loan – DHS		750		26,812		21,247		25,991		74,800
Abandonment retirement obligation		407		441		551		8,929		10,328
Operating leases		2,950		5,678		3,010		3,088		14,726
Drilling commitments		6,000		—		—		—		6,000
Other debt obligations		64		15		—		—		79

Total contractual cash obligations	$	20,671	$	53,946	$	188,808	$	224,291	$	487,716

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 semiannually 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. 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.

Credit Facility

In November 2006, the Company amended its credit facility with JP Morgan Chase Bank, N.A. At December 31, 2006, the $250.0 million credit facility has an available borrowing base of approximately $130.0 million and $118.0 million outstanding. 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 facility is collateralized by substantially all of our oil and gas properties. Beginning with the quarter ending March 31, 2007, 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) of less than 4.25 to 1 for the quarters ending March 31 and June 30, 2007, 4.0 to 1 for the quarters ending September 30 and 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%.

Subsequent determinations of the borrowing base will be made by the lending banks at least semi-annually on April 1 and October 1 of each year, or as special re-determinations. 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. The April 1 and October 1 redeterminations resulted in no changes to our borrowing base; however, in June 2006 a special redetermination resulted in an increase of our borrowing base to $120.0 million.

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 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 (See “Subsequent Events” footnote in the accompanying notes to consolidated financial statements).

Credit Facility – DHS

On May 4, 2006, DHS entered into a new $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. Borrowings on the facility bear interest at LIBOR plus 300 basis points. The facility includes financial covenants which require a maximum debt to EBITDA ratio of 2.50 to 1.00 (with such ratio decreasing to 2.25 to 1.00 for the quarters ending March 31, 2008 through December 31, 2008 and 2.00 to 1.00 for the fiscal quarters ending March 31, 2009 through March 31, 2012) and a minimum EBITDA to interest expense ratio of 4.00 to 1.00 (increasing to 4.50 to 1.00 for the fiscal quarters ending June 30, 2007 through December 31, 2007 and increasing again to 5.00 to 1.00 for fiscal quarters ending March 31, 2008 and thereafter). Financing fees of $2.3 million were incurred in conjunction with the facility and will be amortized over the life of the loan. The facility has a $25 million mandatory delayed draw feature which expires in May 2007 and on which DHS pays a 1% commitment fee until drawn. The facility matures in 2012 and requires quarterly principal payments of 0.25% of the amount outstanding. In addition, an annual mandatory prepayment is required each April based on a percentage of excess cash flow (as defined) during the preceding fiscal year. The facility is non-recourse to Delta. No mandatory prepayment is expected to be due in April 2007 due to capital expenditures. At December 31, 2006, DHS was in compliance with its quarterly debt covenants and restrictions.

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 $994,000 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.

Derivative instruments had a positive fair market value at December 31, 2006 and thus no obligation was shown. 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.”

The following table summarizes our derivative contracts outstanding at December 31, 2006:

Net Fair Value

Price Floor /

Asset (Liability) at

Commodity

Volume

Price Ceiling

Term

Index

December 31, 2006

(In thousands)

Contracts that qualify for hedge accounting

Crude oil

25,000 Bbls / month

35.00 / $61.80

July ’06 - June ’07

NYMEX-WTI

(613

)

Crude oil

75,000 Bbls / month

65.00 / $84.00

Jan ’07 - Dec ’07

NYMEX-WTI

3,455

Crude oil

25,000 Bbls / month

65.00 / $82.65

July ‘07 - Dec ’07

NYMEX-WTI

558

Natural gas

15,000 MMBtu / day

6.00 / $7.55

Apr ’07 - June ’07

CIG

1,617

Natural gas

15,000 MMBtu / day

6.00 / $8.45

July ’07 - Sept ’07

CIG

1,600

Natural gas

15,000 MMBtu / day

7.00 / $9.15

Oct ’07 - Dec ’07

CIG

2,192

Contracts that do not qualify for hedge accounting

Natural gas

13,000 MMBtu / day

5.00 / $10.20

July ’06 - Mar ’07

NYMEX-H HUB

Natural gas

10,000 MMBtu / day

7.00 / $11.40

July ’07 - Sept ’07

NYMEX-H HUB

739

Natural gas

10,000 MMBtu / day

7.00 / $16.30

Oct ’07 - Dec ’07

NYMEX-H HUB

616

10,186

The fair value of our derivative instruments net asset was $10.2 million at December 31, 2006 and $8.4 million on March 2, 2007.

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 1 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 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 a development cost and capitalized, but often these seismic programs extend beyond the reserve area considered proved and management must estimate the portion of the seismic costs to expense. The evaluation of gas and oil leasehold acquisition costs requires managerial judgment to estimate the fair value of these costs with reference to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.

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

Reserve Estimates

Estimates of gas and oil reserves, by necessity, are projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of gas and oil that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable gas and oil reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions governing future gas and oil prices, 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 at least annually 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, the Company recorded no impairment provision attributable to developed properties for the six months ended December 31, 2005 and the years ended June 30, 2005 and 2004. However, 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. For fiscal year 2007, we are continuing to develop and evaluate certain proved and unproved properties on which favorable or unfavorable results or commodity prices may cause us to revise in future quarters our estimates of those properties’ future cash flows. Such revisions of estimates could require us to record an impairment in the period of such revisions.

Commodity Derivative Instruments and Hedging Activities

We may periodically enter into commodity derivative contracts or fixed-price physical contracts to manage our exposure to oil and natural gas price volatility. We primarily utilize future 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. Changes in the derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met. Due to the hedge effectiveness dependence upon future cash flows, production and reserve estimates and market price conditions, the hedges are continually re-evaluated for effectiveness. If at any time the hedges are determined to be ineffective, we could lose qualification for hedge accounting which could have a material impact on our statement of operations. For qualifying cash flow hedges, the gain or loss on the derivative is deferred in accumulated other comprehensive income (loss) to the extent the hedge is effective. Gains and losses on hedging instruments included in accumulated other comprehensive income (loss) are reclassified to oil and natural gas sales revenue in the period that the related production is delivered. Derivative contracts that do not qualify for hedge accounting treatment are recorded as derivative assets and liabilities at market value in the consolidated balance sheet, and the associated unrealized and realized gains and losses are recorded as other expense or income in the consolidated statement of operations.

Asset Retirement Obligation

We account for our asset retirement obligations under SFAS No. 143 “Accounting for Asset Retirement Obligations.” SFAS No. 143 requires entities to record the fair value of a liability for retirement obligations of acquired assets. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002. The Company adopted SFAS No. 143 on July 1, 2002 and recorded a cumulative effect of a change in accounting principle on prior years related to the depreciation and accretion expense that would have been reported had the fair value of the asset retirement obligations, and corresponding increase in the carrying amount of the related long-lived assets, been recorded when incurred. 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 No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”). FIN 47 clarifies the term “conditional asset retirement obligation” as it is used in SFAS No. 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

The Company follows SFAS No. 109, “Accounting for Income Taxes,” to account for its deferred tax assets and liabilities. Under SFAS No. 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, the Company maintains a valuation allowance against a portion of its deferred tax assets. The Company will continue to monitor facts and circumstances in its reassessment of the likelihood that operating loss carryforwards and other deferred tax attributes will be utilized prior to their expiration. As a result, the Company 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.

Recently Issued Accounting Standards and Pronouncements

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 has not yet completed its assessment of how adoption of this pronouncement may impact the Company’s financial position or results of operations.

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 are 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 July 2006, the FASB issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109” (“FIN 48”). This interpretation clarifies the accounting for uncertainty in tax positions. FIN 48 requires that we recognize in our financial statements the impact of a tax position if that position is more likely than not of being sustained on audit, based on the technical merits of the position. FIN 48 is effective for our fiscal year commencing January 1, 2007. At this time, we do not expect the adoption of FIN 48 to have an 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 (“Statement 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 FAS 154 did not have a material impact on the Company’s consolidated results of operations, financial position or cash flows.

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 $10.2 million asset at December 31, 2006 and a $8.4 million asset on March 2, 2007.

The current derivative contracts cover approximately 14.7 Bcfe of our estimated 2007 production. Assuming production and the percent of oil and gas sold remained unchanged from the year ended December 31, 2006, a hypothetical 10% decline in the average market price the Company realized during the year ended December 31, 2006 on unhedged production would reduce the Company’s oil and natural gas revenues by approximately $12.4 million on an annual basis.

Interest Rate Risk

We were subject to interest rate risk on $217.8 million of variable rate debt obligations at December 31, 2006. The annual effect of a ten percent change in interest rates would be approximately $1.7 million. The interest rate on these variable debt obligations approximates current market rates as of December 31, 2006.

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, 2006. Based upon this evaluation, the chief executive officer and chief financial officer concluded that our disclosure controls and procedures were effective in ensuring that material information required to be disclosed is included in the reports that we file with the Securities and Exchange Commission.

Management’s Report on Internal Control Over Financial Reporting

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

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

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

In connection with the preparation of our annual consolidated financial statements, management has undertaken an assessment of the effectiveness of our internal control over financial reporting as of December 31, 2006, 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, 2006, 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 management’s assessment 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.

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.

9.		Voting Trust Agreement.

9.1		Voting Agreement and Irrevocable Proxy dated as of November 8, 2005 by and among Delta Petroleum Corporation, DPCA LLC, and certain stockholders of Castle Energy Corporation, as amended. Incorporated by reference to Appendix B to the proxy Statement/prospectus included in the Company’s Form S-4 registration statement, SEC File No. 333-130672.

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 to 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		Change in Control Executive Severance Agreement with Roger A. Parker dated May 5, 2005. Incorporated by reference from Exhibit 10.2 to the Company’s Form 8-K dated May 5, 2005.*

10.13		Change in Control Executive Severance 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.*

10.14		Change in Control Executive Severance 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.*

10.15		Change in Control Executive Severance Agreement with Stanley F. Freedman dated January 11, 2006. Incorporated by reference from Exhibit 10.2 to the Company’s Form 8-K dated January 11, 2006. *

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

10.17		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.*

10.18		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.
10.19		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.

10.20		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.

10.21		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.*


10.22		Form of Restricted Stock Award Agreement. Incorporated by reference from Exhibit 10.2 to the Company’s Form 8-K dated January 5, 2007.*

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.

Report of Independent Registered Public Accounting Firm

The Board of Directors
Delta Petroleum Corporation:

We have audited the accompanying consolidated balance sheets of Delta Petroleum Corporation and subsidiaries as of December 31, 2006 and December 31, 2005, and the related consolidated statements of operations, stockholders’ equity and comprehensive income (loss) and cash flows for the year ended December 31, 2006, six months ended December 31, 2005 and years ended June 30, 2005 and 2004. 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, 2006 and December 31, 2005, and the results of their operations and their cash flows for the year ended December 31, 2006, six months ended December 31, 2005 and each of the years ended June 30, 2005 and 2004, 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), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of the Sponsoring Organizations of the Treadway Commission, and our report dated March 7, 2007 expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.

As discussed in footnote 2 to the consolidated financial statements, Delta Petroleum Corporation adopted Statement of Financial Accounting Standards No. 123(R), Share Based Payment, as of July 1, 2005.

KPMG
Denver, Colorado
March 7, 2007

F-1

Report of Independent Registered Public Accounting Firm

The Board of Directors
Delta Petroleum Corporation:

We have audited management’s assessment, included in Item 9A, Management’s Report on Internal Control over Financial Reporting, that Delta Petroleum Corporation and subsidiaries (Delta or the Company) maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Delta’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. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of 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, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

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

In our opinion, management’s assessment that Delta maintained effective internal control over financial reporting as of December 31, 2006 is fairly stated, in all material respects, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, Delta maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Delta and subsidiaries as of December 31, 2006 and December 31, 2005, and the related consolidated statements of operations, stockholders’ equity and comprehensive income (loss), and cash flows for the year ended December 31, 2006, six months ended December 31, 2005 and the years ended June 30, 2005, and 2004 and our report dated March 7, 2007 expressed an unqualified opinion on those consolidated financial statements.

KPMG
Denver, Colorado
March 7, 2007

F-2

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


	December 31,			December 31,
	2006			2005
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	7,666		$	5,519
Assets held for sale		5,397			19,215
Trade accounts receivable, net of allowance for doubtful accounts, of $100 and $100, respectively		29,503			22,202
Prepaid assets		4,384			3,442
Inventory		2,851			3,285
Deferred tax asset		—			5,237
Derivative instruments		10,799			89
Other current assets		2,769			2,600

Total current assets		63,369			61,589

Property and equipment:
Oil and gas properties, successful efforts method of accounting:
Unproved		218,380			167,143
Proved		591,149			438,666
Drilling and trucking equipment, including deposits on equipment of zero and $5,000, respectively		136,038			64,129
Pipeline and gathering system		14,909			7,828
Other		13,983			4,981

Total property and equipment		974,459			682,747
Less accumulated depreciation and depletion		(132,814	)		(61,593	)

Net property and equipment		841,645			621,154


Long-term assets:
Deferred financing costs		6,928			5,291
Derivative instruments		—			163
Goodwill		7,747			2,341
Other long-term assets		9,655			511
Deferred tax assets		—			1,322
Investment in LNG project		—			1,022

Total long-term assets		24,330			10,650


Total assets	$	929,344		$	693,393


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt	$	816		$	7,073
Accounts payable		84,439			67,772
Other accrued liabilities		10,818			19,462
Deferred tax liability		2,893			—
Derivative instruments		613			12,465

Total current liabilities		99,579			106,772

Long-term liabilities:
7% Senior notes, unsecured		149,384			149,309
Credit facility		118,000			64,270
Unsecured term loan		25,000			—
Credit facility/Term loan — DHS		74,050			28,000
Asset retirement obligation		4,034			3,002
Derivative instruments		—			6,009
Deferred tax liability		3,660			—
Other debt, net		14			80

Total long-term liabilities		374,142			250,670

Minority interest		27,390			15,496

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 54,439,000 shares at December 31, 2006, and 47,825,000 shares at December 31, 2005		534			478
Additional paid-in capital		430,479			333,054
Accumulated other comprehensive (loss) income		4,865			(4,997	)
Accumulated deficit		(7,645	)		(8,080	)

Total stockholders’ equity		428,233			320,455


Total liabilities and stockholders’ equity	$	929,344		$	693,393

See accompanying notes to consolidated financial statements.

F-3

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS


	Year Ended			Six Months Ended
	December 31,			December 31,			Years Ended June 30,
	2006			2005			2005			2004
				(In thousands, except per share amounts)
Revenue:
Oil and gas sales	$	124,212		$	55,545		$	72,408		$	21,273
Contract drilling and trucking fees		57,149			9,096			4,796			—
Realized loss on derivative instruments, net		(4,712	)		(3,413	)		(630	)		(859	)

Total revenue		176,649			61,228			76,574			20,414

Operating expenses:
Lease operating expense		22,935			8,483			12,854			5,643
Transportation expense		1,231			808			539			231
Production taxes		6,755			3,133			4,868			1,212
Depreciation, depletion, accretion and amortization — oil and gas		64,068			16,024			18,892			7,031
Depreciation and amortization — drilling and trucking		16,404			2,847			1,525			14
Exploration expense		4,690			2,061			6,155			2,406
Dry hole costs		4,323			4,073			2,771			2,132
Abandoned and impaired properties		11,359			1,350			—			—
Drilling and trucking operations		34,163			5,821			4,666			232
General and administrative		35,696			16,491			16,930			8,049
Gain on sale of oil and gas properties		(20,034	)		—			—			—

Total operating expenses		181,590			61,091			69,200			26,950


Operating income (loss)		(4,941	)		137			7,374			(6,536	)

Other income and (expense):
Other income (expense)		421			173			(492	)		122
Gain on sale of marketable securities, net		—			1,194			—			—
Gain on sale of investment in LNG		1,058			—			—			—
Gain (loss) on ineffective derivative instruments, net		11,722			(14,437	)		(330	)		—
Minority interest		(2,595	)		(688	)		1,017			70
Interest and financing costs		(26,891	)		(9,075	)		(7,958	)		(1,762	)

Total other expense		(16,285	)		(22,833	)		(7,763	)		(1,570	)


Loss from continuing operations before income taxes and discontinued operations		(21,226	)		(22,696	)		(389	)		(8,106	)

Income tax benefit		7,931			8,451			7,987			—


Income (loss) from continuing operations		(13,295	)		(14,245	)		7,598			(8,106	)

Discontinued operations:
Income from discontinued operations of properties sold, net of tax		1,458			1,867			7,452			11,275
Gain on sale of discontinued operations, net of tax		6,712			11,788			—			1,887


Income (loss) before extraordinary gain, net of tax		(5,125	)		(590	)		15,050			5,056

Extraordinary gain, net of tax		5,560			—			—			—


Net income (loss)	$	435		$	(590	)	$	15,050		$	5,056


Basic income (loss) per common share:
Income (loss) from continuing operations	$	(.26	)	$	(.31	)	$	.19		$	(.30	)
Discontinued operations		.16			.30			.18			.49
Extraordinary gain, net of tax		.11			—			—			—

Net income (loss)	$	.01		$	(.01	)	$	.37		$	.19


Diluted income (loss) per common share:
Income (loss) from continuing operations	$	(.26	)	$	(.31	)	$	.18		$	(.27	)
Discontinued operations		.16			.30			.18			.44
Extraordinary gain, net of tax		.11			—			—			—

Net income (loss)	$	.01		$	(.01	)	$	.36		$	.17

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, 2003		23,286	$	233	$	75,642		$	(376	)							$	(27,596	)	$	47,903
Comprehensive income:
Net income		—		—		—			—		$	5,056						5,056			5,056
Other comprehensive gain, net of tax Change in fair value of derivative hedging instruments		—		—		—			468			468						—			468
Unrealized gain on marketable securities, net		—		—		—			250			250						—			250

Comprehensive income											$	5,774

Stock options granted as compensation		—		—		329			—									—			329
Shares issued for cash, net		10,000		100		97,802			—									—			97,902
Shares issued for oil and gas properties		3,728		37		30,489			—									—			30,526
Shares issued for cash upon exercise of options		1,433		14		3,549			—									—			3,563

Balance, June 30, 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 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			—						—			—			2003

Balance, December 31, 2005		47,825		478		333,054			(4,997	)					—			(8,080	)		320,455

Comprehensive income:
Net loss		—		—		—			—		$	435						435			435
Other comprehensive 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		54,439	$	534	$	430,479		$	4,865					$	—		$	(7,645	)	$	428,233

See accompanying notes to consolidated financial statements.

F-5

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS


	Year Ended			Six Months Ended
	December 31,			December 31,			Years Ended June 30,
	2006			2005			2005			2004
	(In thousands)
Cash flows from operating activities:

Net Income (loss)	$	435		$	(590	)	$	15,050		$	5,056
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion, and amortization – oil and gas		63,871			15,929			18,639			6,971
Depreciation and amortization – drilling and trucking		16,404			2,847			1,525			14
Depreciation, depletion, and amortization – discontinued operations		2,124			1,643			2,998			3,197
Accretion of abandonment obligation		197			96			253			60
Stock option and non-vested stock compensation		4,882			2,770			672			329
Amortization of deferred financing costs		2,396			669			858			324
Unrealized (gain) loss on derivative contracts		(12,205	)		9,872			330			—
Dry hole costs and impairment		11,897			1,872			—			—
Minority Interest		2,595			688			(1,017	)		(70	)
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	)		—			—			—
Gain on sale of discontinued operations		(10,775	)		(11,788	)		—			(1,887	)
Extraordinary gain on Castle acquisition		(8,776	)		—			—			—
DHS stock granted to management		280			140			—			—
Deferred income tax expense (benefit)		(502	)		(7,336	)		(3,045	)		—
Other		319			—			394			—
Net changes in operating assets and liabilities:
Increase in trade accounts receivable		(4,501	)		(10,454	)		(1,586	)		(4,878	)
(Increase) decrease in prepaid assets		(731	)		(457	)		(1,844	)		(372	)
(Increase) decrease in inventory		434			947			(5,062	)		(1,350	)
(Increase) decrease in other current assets		(438	)		(1,968	)		(225	)		205
Increase in accounts payable trade		4,477			6,688			14,004			1,361
Increase in other accrued liabilities		2,095			14,505			2,918			663


Net cash provided by operating activities		53,386			24,879			44,862			9,623


Cash flows from investing activities:
Additions to property and equipment,		(218,761	)		(157,519	)		(186,669	)		(158,504	)
Additions to drilling and trucking equipment,		(63,848	)		(21,828	)		(30,797	)		—
Acquisitions, net of cash acquired		(8,564	)		(3,905	)		—			—
Proceeds from sale of oil and gas properties		82,716			34,178			18,721			10,787
Proceeds from sale of marketable securities		—			1,764			—			—
Minority interest holder contributions		9,018			—			14,800			315
Payment on investment transaction		—			—			—			(1,022	)
(Increase) decrease in long term assets		(3,646	)		802			63			(14	)


Net cash used in investing activities		(203,085	)		(146,508	)		(183,882	)		(148,438	)


Cash flows from financing activities:
Stock issued for cash upon exercise of options		3,711			1,166			132			3,563
Stock issued for cash, net		33,870			95,026			—			97,902
Proceeds from borrowings		220,035			72,998			361,016			69,979
Payment of financing fees		(3,994	)		(502	)		(7,370	)		(368	)
Repayment of borrowings		(101,776	)		(43,781	)		(214,595	)		(32,454	)


Net cash provided by financing activities		151,846			124,907			139,183			138,622


Net increase (decrease) in cash and cash equivalents		2,147			3,278			163			(193	)


Cash at beginning of period		5,519			2,241			2,078			2,271


Cash at end of period	$	7,666		$	5,519		$	2,241		$	2,078


Supplemental cash flow information:
Cash paid for interest and financing costs	$	28,438		$	8,149		$	11,420		$	1,818


Non-cash financing activities:
Common stock issued for the purchase of Castle and oil and gas properties	$	47,332		$	828		$	22,191		$	30,526

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, 2006 and 2005, and June 30, 2005 and 2004

(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 and 2005, owns a 49.4% 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 three-fourths 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, 2006, 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, we sold a 44% minority interest in CRBP. We have retained the majority ownership in, and are 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, our 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. This sale did not involve any of our operated 100% working interests in approximately 345,000 net acres in the Columbia River Basin.

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, 2006 and 2005, and June 30, 2005 and 2004

(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 4 (“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, Piper, CRBP, PGR, DHS, 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 stockholders’ deficit position for the periods presented, the Company has recognized 100% of Amber’s earnings/losses for all periods. The Company has no interests in any unconsolidated entities nor does it have any off-balance sheet financing arrangements (other than operating leases) or any unconsolidated special purpose entities.

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, 2006 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 year ended December 31, 2006, six-month transitional period ended December 31, 2005 and for the twelve-month periods ended June 30, 2005 and 2004. The unaudited financial information for the year ended December 31, 2005 is as follows:


	Year Ended
	December 31, 2005
	(In thousands, except per share data)
Total Revenues	$	107,472
Operating Income		3,671
Income from continuing operations before income taxes and discontinued operations		(24,855	)
Net Income		5,706

Net income per common share:
Basic	$	.13
Diluted	$	.13

F-8

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2006 and 2005, and June 30, 2005 and 2004

(2) Summary of Significant Accounting Policies, Continued

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

The Company classifies its investment securities as available-for-sale securities. Pursuant to Statement of Financial Accounting Standards (“SFAS”) No. 115 (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

Assets Held for Sale

Assets held for sale as of December 31, 2006 represent the Company’s Kansas oil and gas properties that were sold in January 2007 and certain interests in Oklahoma that are expected to be sold within one year.

Assets held for sale as of December 31, 2005 represent the cost basis related to the 427,000 gross acres (64,000 net acres) of non-operated interests in the Columbia River Basin that were transferred during December 2005 to a newly created wholly owned subsidiary, CRBP. In January and March 2006, Delta sold a minority interest in CRBP to a small group of investors for aggregate proceeds of $32.8 million. As the sale involved unproved properties, no gain could be recognized on the partial sale of CRBP until the full basis 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 unproved oil and gas property during the first quarter of 2006 as a result of closing the transaction.

Inventories

Inventories consist of pipe, other production equipment and natural gas placed in storage. 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 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).

F-9

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2006 and 2005, and June 30, 2005 and 2004

(2) Summary of Significant Accounting Policies, Continued

Minority Interest

Minority interest represents the 50.6% (45% for Chesapeake Energy Corporation, 5.6% for DHS executive officers and management) investors of DHS at December 31, 2006 and December 31, 2005. Prior to forming DHS, the Company owned a 50% interest in Big Dog Drilling Co., LLC (“Big Dog”) and a 50% interest in Shark Trucking Co., LLC (“Shark”). The remaining net assets of Big Dog were ultimately acquired and, together with the interest previously owned, were contributed to DHS.

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 December 31, 2006 and 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.

Drilling and Trucking

We earn our contract drilling revenues under daywork. We recognize revenues on daywork contracts for the days completed based on the dayrate each contract specifies. 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 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 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.

F-10

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2006 and 2005, and June 30, 2005 and 2004

(2) Summary of Significant Accounting Policies, Continued

Depreciation, depletion and amortization of oil and gas property and equipment for the year ended December 31, 2006, six months ended December 31, 2005 and the fiscal years ended June 30, 2005 and 2004 were $64.1 million, $16.0 million, $18.9 million, and $7.0 million, respectively.

Drilling equipment and other property and equipment are 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.

Impairment of Long-Lived Assets

Statement of Financial Accounting Standards No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets” (SFAS No. 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 No. 144 are permanent and may not be restored in the future.

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 years ended June 30, 2005 and 2004. However, 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, an impairment of $1.0 million was recorded on certain Oklahoma properties that were held for sale at December 31, 2006.

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, 2006, June 30, 2005 and 2004.

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.

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. No impairment of goodwill was indicated as a result of the Company’s impairment test performed during the third quarter of 2006.

F-11

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2006 and 2005, and June 30, 2005 and 2004

(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 year ended December 31, 2006, six months ended December 31, 2005 and fiscal years ended June 30, 2005 and 2004:


	Year Ended			Six Months Ended
	December 31,			December 31,			Years Ended June 30,
	2006			2005			2005			2004
				(In thousands)
Asset retirement obligation — beginning of period	$	3,467		$	3,691		$	2,647		$	868
Accretion expense		199			96			253			60
Change in estimate		639			(19	)		—			438
Obligations acquired		850			160			1,153			1,522
Obligations settled		(139	)		—			—			(3	)
Obligations on sold properties		(574	)		(461	)		(362	)		(238	)

Asset retirement obligation — end of period		4,442			3,467			3,691			2,647
Less: Current asset retirement obligation		(408	)		(465	)		(716	)		(105	)

Long-term asset retirement obligation	$	4,034		$	3,002		$	2,975		$	2,542

In March 2005, the FASB issued FASB Interpretation 47 (“FIN 47”), an interpretation of SFAS No. 143, “Accounting for Asset Retirement Obligations” (“SFAS No. 143”). FIN 47 clarifies the term “conditional asset retirement obligation” as it is used in SFAS No. 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 year ended December 31, 2006, six months ended December 31, 2005 and fiscal years ended June 30, 2005 and 2004 are as follows (in thousands):


			Six Months
	Year Ended		Ended			Years Ended
	December 31,		December 31,			June 30,
	2006		2005			2005			2004
Net income (loss)	$	435	$	(590	)		15,050			5,056
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, $458 and zero, respectively		—		—			394			250
Hedging instruments reclassified to income upon settlement, net of tax benefit of $1,738 and $1,733, respectively		2,860		2,398			—			—
Change in fair value of derivative hedging instruments, net of tax (expense) benefit of ($4,315), $1,036, $3,722, and zero, respectively		7,002		(1,434	)		(5,961	)		468

Comprehensive income (loss)	$	10,297	$	(362	)	$	9,483		$	5,774

F-12

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2006 and 2005, and June 30, 2005 and 2004

(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 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 long-term debt was estimated based on quoted market prices. The fair values of derivative instruments were estimated based on discounted future net cash flows.

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.

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 No. 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 No. 123R effective July 1, 2005 using the modified prospective method and recognized compensation expense related to stock options of $1.4 million and $2.0 million, relating to employee provided services during the year ended December 31, 2006 and six months ended December 31, 2005, respectively.

F-13

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2006 and 2005, and June 30, 2005 and 2004

(2) Summary of Significant Accounting Policies, Continued

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.

Exercise prices for options outstanding under the Company’s various plans as of December 31, 2006 ranged from $1.75 to $15.60 per share, and the weighted-average remaining contractual life of those options was 4.37 years. These options have a stock based compensation value of approximately $319,000 and will be expensed through March 31, 2007. The Company has not issued stock options since the adoption of SFAS No. 123R, though it has the discretion to issue options again in the future. At December 31, 2006, the Company had 166,667 unvested options.

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 years ended June 30, 2005 and 2004 would have been as follows:


	Years Ended June 30,
	2005			2004
	(In thousands, except per share amounts)
Net income (loss)	$	15,050		$	5,056
Equity compensation booked		306			—
FAS 123 compensation effect		(2,759	)¹		(4,316	)

Pro forma net income after FAS 123 implementation	$	12,597		$	740


Pro forma income per common share:

Basic	$	.31		$	.03

Diluted	$	.30		$	.02


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 No. 123R compensation effect is calculated based on the options’ vesting period and includes additional grants from other periods.

F-14

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2006 and 2005, and June 30, 2005 and 2004

(2) Summary of Significant Accounting Policies, Continued

Income Taxes

The Company uses the asset and liability method of accounting for income taxes as set forth in Statement of Financial Accounting Standards No. 109 (SFAS No. 109), “Accounting for Income Taxes.” Under the asset and liability method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and net operating loss and tax credit carry-forwards. Deferred tax assets and liabilities are measured using enacted income tax rates expected to apply to taxable income in the years in which those differences are expected to be recovered or settled. Under SFAS No. 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.

Earnings (Loss) per Common Share

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

Recently Issued Accounting Standards and Pronouncements

(2) Summary of Significant Accounting Policies, Continued

F-15

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2006 and 2005, and June 30, 2005 and 2004

effective for our fiscal year commencing January 1, 2007. At this time, we do not expect the adoption of FIN 48 to have an impact on our financial position or results of operations.

In April 2005, the FASB issued Staff Position 19-1, (“FSP 19-1”) “Accounting for Suspended Well Costs.” 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
	Year Ended			Ended			Year Ended
	December 31,			December 31,			June 30,²
	2006			2005			2005			2004
Balance at beginning of period	$	357		$	1,033		$	10		$	—
Additions to capitalized exploratory well costs pending the determination of proved reserves¹		27,744			10,151			10,991			2,811
Reclassified to proved oil and gas properties based on the determination of proved reserves		(357	)		(6,754	)		(7,197	)		(669	)
Capitalized exploratory well costs charged to dry hole expense		(291	)		(4,073	)		(2,771	)		(2,132	)

Balance at end of period	$	27,453		$	357		$	1,033		$	10


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 and 2004 are presented based on the Company’s previous accounting policy.

(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 $12.5 million and $11.0 million at December 31, 2006 and 2005, 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.

(3) Oil and Gas Properties, Continued

The Company is not the designated operator of any of these properties but is an active participant in the ongoing activities of each property along with the designated operator and other interest owners. If the designated operator elected not to or was unable to continue as the operator, the other property interest owners would have the right to designate a new operator as well as share in additional property returns prior to the replaced operator being able to receive returns. Based on the Company’s size, it would be difficult for the Company to proceed with exploration and

F-16

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2006 and 2005, and June 30, 2005 and 2004

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, 2006, December 31, 2005 and June 30, 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 forty undeveloped leases are located in the Offshore Santa Maria Basin off the coast of Santa Barbara and San Luis Obispo counties, and in the Santa Barbara Channel off Santa Barbara and Ventura counties. 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 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 in the Amber case 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.

The Court in the Amber case further ruled under a restitution theory of damages 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. Together with Amber, the Company’s net share of the $1.1 billion award is approximately $120 million. This award is subject to appeal and the government has filed a motion for reconsideration of the ruling as it relates to a single lease owned entirely by the Company. The value attributed to this lease represents significantly more than half of the net amount that would be received by the Company under the summary judgment. In its motion for reconsideration, the government has asserted that the affected lease is not being returned in substantially the same condition that it was in at the time it was initially granted because, allegedly, a significant portion of the hydrocarbons has been drained by wells that were drilled on an immediately adjacent lease. Although discovery is continuing on this issue, management currently believes that the government’s assertion is without merit and the Company is vigorously contesting it; however, the ultimate outcome of this matter cannot be predicted with certainty.

(3) Oil and Gas Properties, Continued

On January 12, 2007, the Court in the Amber case entered an order of final judgment awarding the lessees restitution of the original lease bonuses paid for thirty five of the forty lawsuit leases, and the government filed a Notice of Appeal of the final judgment later the same date. The lease owned by us that is subject to the motion for reconsideration is not included in this order. The government’s appeal of the order of final judgment may contend 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 purposes of receiving restitution of the original lease bonuses.

F-17

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2006 and 2005, and June 30, 2005 and 2004

The current lessees may appeal the order of final judgment to, among other things, challenge the Court’s rulings that they cannot recover their and their predecessors’ sunk costs (exploratory, development and related expenses) as part of their restitution claim. No payments will be made until all relevant appeals have either been waived or exhausted.

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.

Significant Acquisitions — Pro-forma Statements of Operations

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 June 29, 2004, the Company completed the acquisition of substantially all of the oil and gas assets owned by several entities controlled by Alpine Resources, Inc. (“Alpine”) for $122.5 million, which was funded with $68.4 million in net proceeds that the Company received from a $72.0 million private placement of six million shares of its restricted common stock to institutional investors at $12.00 per share, and from borrowings of $54.1 million under its senior credit facility. Shortly thereafter, the Company sold a portion of these assets to Whiting Petroleum Corporation for $18.7 million in net proceeds. There was no gain or loss on the sale of these assets.

The following unaudited pro forma condensed consolidated statement of operations information assumes that the Manti and Alpine property acquisitions occurred as of July 1, 2003:


	Years Ended June 30,
	2005		2004
	(In thousands)
Oil and gas sales	$	94,596	$	70,319
Net earnings from continuing operations, net of tax	$	12,139	$	5,111

Net earnings from continuing operations per common share, net of tax:
Basic	$	.30	$	.15
Diluted	$	.29	$	.14

The above unaudited condensed pro forma consolidated statements of operations information, based on the historical producing property operating results of Manti, Alpine and Delta, are not necessarily indicative of the results of operations if Delta would have acquired the Manti and Alpine properties at July 1, 2003.

(3) Oil and Gas Properties, Continued

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

F-18

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2006 and 2005, and June 30, 2005 and 2004

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”.

Fiscal 2005 — Acquisitions

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.

(3) Oil and Gas Properties, Continued

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.

F-19

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2006 and 2005, and June 30, 2005 and 2004

Fiscal 2004 — Acquisitions

During fiscal 2004 the Company made other producing property acquisitions in North Dakota of approximately 2.4 Bcfe for a total consideration of $4.2 million through the issuance of 773,500 shares of the Company’s common stock.

During the period from September of 2003 through July of 2004 the Company completed a series of transactions with Edward Mike Davis and certain unrelated individuals which resulted in an acquisition of a producing property and approximately 360,000 acres of undeveloped properties in the Company’s North and South Tongue prospects located in Washington and Yuma Counties, Colorado, and an interest in producing and non-producing properties located in Colusa, Orange and Los Angeles Counties, California. Through these acquisitions the Company obtained an aggregate of approximately 6 Bcfe in proved producing reserves and a significant drilling inventory for a total consideration of approximately $8.0 million in cash and 2,551,000 shares of the Company’s common stock.

During fiscal 2004, the Company invested an aggregate of $1.0 million for a 6.25% interest as a member of Crystal Energy, LLC, which is an unaffiliated Delaware limited liability company that is currently in the process of attempting to obtain the rights to own and operate a liquid natural gas facility from Platform Grace, which is an existing platform located offshore California. If the limited liability company is successful in obtaining these rights, it intends to engage in the business of accepting and vaporizing liquid natural gas delivered by liquid natural gas tankers, transporting the vaporized liquid natural gas through proprietary gas pipelines and selling the vaporized natural gas to third party customers located in California. As of December 31, 2006, the limited liability company had not yet engaged in any revenue producing activities.

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. Delta now owns a net interest of just over 32,300 acres in the Columbia River Basin through its remaining ownership of CRBP and additional interests in 345,000 net acres in the Columbia River Basin from previous transactions.

(3) Oil and Gas Properties, Continued

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.

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.

F-20

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2006 and 2005, and June 30, 2005 and 2004

Included in discontinued operations are the results from the Company’s Kansas properties that were sold in January 2007 and certain properties in Oklahoma that were held for sale at December 31, 2006. The total revenues and pre-tax income from discontinued operations of these oil and gas properties were approximately $3.5 million and $1.1 million, $2.5 million and $427,000, $6.5 million and $4.0 million, and $7.3 million and $5.2 million for the year ended December 31, 2006, six months ended December 31, 2005, and fiscal years ended June 30, 2005 and 2004, respectively.

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. The total revenues and net pre-tax loss from discontinued operations of these assets were $766,000 and $195,000, respectively, for the year ended December 31, 2006 and zero for all other prior periods.

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). The total revenues and pre-tax income from discontinued operations of these assets were $1.4 million and $861,000, $1.7 million and $1.3 million, $2.4 million and $1.7 million, and $2.7 million and $1.9 million for the year ended December 31, 2006, six months ended December 31, 2005 and years ended June 30, 2005 and 2004, respectively.

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. The total revenues and pre-tax income from discontinued operations of these oil and gas properties were approximately $1.4 million and $608,000, $996,000 and $493,000, $4.2 million and $2.7 million, and $2.4 million and $1.2 million for the year ended December 31, 2006, six months ended December 31, 2005 and years ended June 30, 2005 and 2004, respectively.

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. The total revenues and net profit earned on these assets during the six months ended December 31, 2005, and fiscal years ended June 30, 2005 and 2004, were $1.3 million and $501,000, $5.4 million and $3.3 million, and $3.5 million and $2.1 million, respectively, and has been presented in discontinued operations.

On August 19, 2004, the Company completed the sale of certain interests in five fields in Louisiana and South Texas previously acquired in the Alpine acquisition, which closed on June 29, 2004, to Whiting Petroleum Corporation for $18.7 million, net of certain commissions. There was no gain or loss on this sale transaction and the total revenues and net profit earned on these assets during the year ended June 30, 2004 was $1.1 million and $729,000, respectively.

(3) Oil and Gas Properties, Continued

On March 31, 2004, the Company completed the sale of all of its Pennsylvania properties to Castle Energy Corporation, a 25% stockholder of Delta at March 31, 2004, for cash consideration of $8 million with an effective date of January 1, 2004 which resulted in a gain on sale of oil and gas properties of $1.9 million. Total revenues and net profit earned from the sale of these oil and gas properties were approximately $1.2 million and $749,000, respectively, for the year ended June 30, 2004.

On December 5, 2003, the Company completed the sale of certain properties located in Texas to Sovereign Holdings, LLC for cash consideration of $2.6 million. The effective date of the transaction was January 1, 2004 and it resulted in a loss on the sale of oil and gas properties of $28,000. Revenues and net profit attributed to the sale of these oil and gas properties were approximately $537,000 and $40,000, respectively, for the year ended June 30, 2004.

F-21

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2006 and 2005, and June 30, 2005 and 2004

(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 and certain drilling equipment. Delta has the right to use all of the DHS rigs on a priority basis, although approximately three-fourths 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.

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.

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.

(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 our 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, 2006. (See Footnote 12, “Guarantor Financial Information”). The fair value of the Company’s senior notes at December 31, 2006 was $138.8 million.

F-22

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2006 and 2005, and June 30, 2005 and 2004

Credit Facility

In November 2006, the Company amended its credit facility with JP Morgan Chase Bank, N.A. At December 31, 2006, the $250.0 million credit facility had an available borrowing base of approximately $130.0 million with $118.0 million outstanding. 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, 2006 approximated 5.35% and 8.25%, 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 beginning March 31, 2007 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) of less than 4.25 to 1 for the quarters ending March 31 and June 30, 2007, 4.0 to 1 for the quarters ending September 30 and 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%.

Unsecured Term Loan

Credit Facility — DHS

On May 4, 2006, DHS entered into a new $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 previously outstanding term loan, complete the acquisition of C&L Drilling, finance additional capital expenditures and pay transaction expenses. Borrowings on the facility bear interest at LIBOR plus 300 basis points. The facility includes financial covenants which require a maximum debt to EBITDA ratio of 2.50 to 1.00 (with such ratio decreasing to 2.25 to 1.00 for the quarters ending March 31, 2008 through December 31, 2008 and 2.00 to 1.00 for the fiscal quarters ending March 31, 2009 through March 31, 2012) and a minimum EBITDA to interest expense ratio of 4.00 to 1.00 (increasing to 4.50 to 1.00 for the fiscal quarters ending June 30, 2007 through December 31, 2007, and increasing again to 5.00 to 1.00 for the fiscal quarters ending March 31, 2008 and thereafter). Financing fees of $2.3 million were incurred in conjunction with the facility and are being amortized over the life of the loan. The facility has a $25 million mandatory delayed draw feature which expires in May 2007 and on which DHS pays a 1% commitment fee until

(5) Long Term Debt, Continued

drawn. The facility matures on May 4, 2012 and requires quarterly principal payments of 0.25% of the amount outstanding. In addition, an annual mandatory prepayment is required each April based on a percentage of excess cash flow (as defined) during the preceding fiscal year. No mandatory prepayment is expected to be due in April 2007 due to capital expenditures. The facility is non-recourse to Delta. At December 31, 2006, DHS was in compliance with its quarterly debt covenants and restrictions.

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 under the Delta bank credit facility at December 31, 2006 was approximately $12.0 million and $25.0 million under the DHS facility. Maturities of long-term debt, in thousands of dollars based on contractual terms, are as follows:

F-23

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2006 and 2005, and June 30, 2005 and 2004


YEAR ENDING December 31,
2007	$	750
2008		14,600
2009		12,200
2010		154,900
2011		9,300
Thereafter		176,000

	$	367,750

(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, 2006 and 2005, 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 year ended December 31, 2006, six months ended December 31, 2005 and fiscal years ended June 30, 2005 and 2004, the Company acquired oil and gas properties for 673,000, 50,000, 1,571,000, and 3,728,000 shares of the Company’s common stock, respectively. The shares were valued at $16.1 million, $799,000, $22.2 million and $30.5 million, respectively, based on the market price of the shares at the time of issuance.

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.

(6) Stockholders’ Equity, Continued

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.

F-24

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2006 and 2005, and June 30, 2005 and 2004

The Company raised additional capital through the sale of 10,000,000 shares of its common stock, net of commissions, of $97.9 million for the year ended June 30, 2004. Offering costs of $6.1 million consisted of cash commissions and legal services relating to the transactions and were accounted for as an adjustment to stockholders’ equity.

Non-Qualified Stock Options — Directors and Employees

(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, 2006 follows:


	Year Ended
	December 31, 2006
				Weighted-Average			Weighted-Average		Aggregate
				Exercise			Remaining Contractual		Intrinsic
	Options			Price			Term		Value
Outstanding-beginning of year		3,231,287		$	7.85
Granted		—			—
Exercised		(871,511	)		(5.57	)
Expired / Returned		—			—


Outstanding-end of year		2,359,776		$	8.69			4.68	$	34,156,000


Exercisable-end of year		2,193,110		$	8.81			4.36	$	30,586,000

The total intrinsic value of options exercised during the year ended December 31, 2006, six months ended December 31, 2005 and the years ended June 30, 2005 and 2004 were $12.3 million, $3.2 million, $24.9 million, and $3.4 million, respectively.

F-25

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2006 and 2005, and June 30, 2005 and 2004

A summary of the Company’s non-vested stock options and related information for the year ended December 31, 2006 follows:


	Year Ended
	December 31, 2006
				Weighted-Average
				Grant-Date
	Options			Fair Value
Nonvested-beginning of year		616,700		$	6.97
Granted		—			—
Vested		(450,033	)		(6.72	)
Forfeited / Returned		—			—


Nonvested-end of year		166,667		$	7.67

The weighted average remaining requisite service period of the non-vested stock options is less than one 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 years ended June 30, 2005 and 2004, respectively, risk-free interest rates of 4.28% and 4.32%, dividend yields of 0% and 0%, volatility factors of the expected market price of the Company’s common stock of 43.97% and 50.43%, and a weighted-average expected life of the options of 4.76 and 5.56 years. The fair value of the options granted at the grant date is $8.0 million and $10.2 million for the years ended June 30, 2005 and 2004, respectively. No options were granted during the year ended December 31, 2006 or six months ended December 31, 2005.

The Company issued options to its non-employee directors and recorded stock option expense in the amount of $329,000 for the year ended June 30, 2004 for options issued below market prices.

(6) Stockholders’ Equity, Continued

Restricted Stock — Directors and Employees

A summary of the restricted stock (nonvested stock) activity under the Company’s plan and related information for the year ended December 31, 2006 follows:


	Year Ended
	December 31, 2006
				Weighted-Average			Weighted-Average		Aggregate
	Nonvested			Grant-Date			Remaining Contractual		Intrinsic
	Stock			Fair Value			Term		Value
Nonvested-beginning of year		229,233		$	17.93
Granted		522,781			21.64
Vested		(112,753	)		(18.68	)
Expired / Returned		(11,761	)		(19.32	)


Nonvested-end of year		627,500		$	19.52			2.38	$	14,533,000

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

F-26

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2006 and 2005, and June 30, 2005 and 2004

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

Cash received from exercises under all share-based payment arrangements for the year ended December 31, 2006, six months ended December 31, 2005 and years ended June 30, 2005, and 2004 was $3.6 million, $625,000, $132,000, and $3.6 million, respectively. Tax benefits realized from the stock options exercised during the year ended December 31, 2006, six months ended December 31, 2005 and years ended June 30, 2005, and 2004, was zero, zero, $1.3 million, and zero, respectively. During the year ended December 31, 2006 and six months ended December 31, 2005, $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.

Non-Qualified Stock Options — Non-Employees

Previously, the Company had also issued options to non-employees and recorded stock option expense in the amount of $10,000 to non-employees for the year ended June 30, 2003. As of June 30, 2005, all such options had expired or been exercised.

(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 year ended December 31, 2006, six months ended December 31, 2005 and fiscal years ended June 30, 2005, and 2004, the Company contributed $528,000, $240,000, $291,000, and $262,000, 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 SFAS No. 133. Accordingly, unrealized gains and losses related to the change in fair market value of derivative contracts which qualify and are designated as cash flow hedges are recorded as other comprehensive income or loss, to the extent the hedge is effective, and such amounts are reclassified to realized gain (loss) on derivative instruments as the associated production occurs.

At December 31, 2006, all of the Company’s derivative contracts are 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 forgoing the benefit of price increases in excess of the ceiling price on the hedged production.

Derivative contracts that do not qualify for hedge accounting treatment are recorded as derivative assets and liabilities at market value in the consolidated balance sheet, and the associated unrealized gains and losses are recorded as other income or expense in the consolidated statement of operations. When these contracts are settled, any adjustment to the previously recorded unrealized amounts is also recorded in other income or expense. While such derivative contracts do not qualify for hedge accounting, management believes these contracts can be utilized as an effective component of commodity price risk management.

The following table summarizes our derivative contracts outstanding at December 31, 2006:

Net Fair Value

Price Floor /

Asset (Liability) at

Commodity

Volume

Price Ceiling

Term

Index

December 31, 2006

(In thousands)

Contracts that qualify for hedge accounting

Crude oil

25,000 Bbls / month

35.00 / $61.80

July ’06 - June ’07

NYMEX-WTI

(613

)

Crude oil

75,000 Bbls / month

65.00 / $84.00

Jan ’07 - Dec ’07

NYMEX-WTI

3,455

Crude oil

25,000 Bbls / month

65.00 / $82.65

July ‘07 - Dec ’07

NYMEX-WTI

558

Natural gas

15,000 MMBtu / day

6.00 / $7.55

Apr ’07 - June ’07

CIG

1,617

Natural gas

15,000 MMBtu / day

6.00 / $8.45

July ’07 - Sept ’07

CIG

1,600

Natural gas

15,000 MMBtu / day

7.00 / $9.15

Oct ’07 - Dec ’07

CIG

2,192

Contracts that do not qualify for hedge accounting

Natural gas

13,000 MMBtu / day

5.00 / $10.20

July ’06 - Mar ’07

NYMEX-H HUB

Natural gas

10,000 MMBtu / day

7.00 / $11.40

July ’07 - Sept ’07

NYMEX-H HUB

739

Natural gas

10,000 MMBtu / day

7.00 / $16.30

Oct ’07 - Dec ’07

NYMEX-H HUB

616

10,186

The fair value of our derivative instruments asset was $10.2 million at December 31, 2006 and $8.4 million on March 2, 2007.

The net realized losses from effective hedging activities recognized in the Company’s statements of operations were $4.7 million, $3.4 million, $630,000, and $859,000 for the year ended December 31, 2006, six months ended December 31, 2005 and years ended June 30, 2005, and 2004, respectively. These losses are recorded as a decrease in revenues.

F-27

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2006 and 2005, and June 30, 2005 and 2004

During the six months ended December 31, 2005, the Company’s gas derivatives became ineffective under SFAS No. 133 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 the Company’s oil and gas production. The change in fair value of our gas contracts during the year ended December 31, 2006 are reflected in earnings, as opposed to previously being disclosed in other comprehensive income (loss), a component of stockholders’ equity. As a result, the Company recorded an $11.7 million gain and a $14.4 million loss in its statement of operations as a component of other income (expense) for the year ended December 31, 2006 and the six months ended December 31, 2005, respectively. Based on the estimated fair value of the derivative contracts at December 31, 2006, the Company expects to reclassify net gains of $7.9 million into earnings related to derivative contracts during the next twelve months; however, actual gains and losses recognized may differ materially.

(9) Income Taxes

The Company accounts for income taxes in accordance with the provisions of Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes” (“SFAS” 109). Income tax expense (benefit) attributable to income from continuing operations consisted of the following for the year ended December 31, 2006, six months ended December 31, 2005 and fiscal years ended June 30, 2005, and 2004:


	Year Ended			Six Months Ended
	December 31,			December 31,			Years Ended June 30,
	2006			2005			2005			2004
	(In thousands)
CURRENT:
U.S. — Federal	$	192		$	—		$	—		$	—
U.S. — State		—			—			—			—
Foreign		—			—			—			—
DEFERRED:
U.S. — Federal		(7,222	)		(7,351	)		(7,272	)		—
U.S. — State		(901	)		(1,100	)		(715	)		—
Foreign		—			—			—			—

	$	(7,931	)	$	(8,451	)	$	(7,987	)	$	—

Income from continuing operations before taxes consists of the following for the year ended December 31, 2006, six months ended December 31, 2005 and the fiscal years ended June 30, 2005 and 2004:


U.S.		(21,397	)		(22,894	)		(389	)		(8,106	)
Foreign		171			198			—			—

Income (loss) from continuing operations before taxes	$	(21,226	)	$	(22,696	)	$	(389	)	$	(8,106	)

F-28

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2006 and 2005, and June 30, 2005 and 2004

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:


	Year Ended			Six Months Ended
	December 31,			December 31,			Years Ended June 30,
	2006			2005			2005			2004
Federal statutory rate		(35.00	)%		(35.00	)%		35.00	%		35.00	%
State income taxes, net of federal benefit		(2.69	)		(3.15	)		3.44			3.10
Investment in DHS		—			(5.81	)		3.53			0.25
Change in valuation allowance		—			0.99			(69.63	)		(38.35	)
Other		0.33			5.74			(1.83	)		—

Actual income tax rate		(37.36	)%		(37.23	)%		(29.49	)%		0.00	%

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.

(9) Income Taxes, Continued

Deferred tax assets (liabilities) are comprised of the following at December 31, 2006, December 31, 2005, June 30, 2005 and June 30, 2004:


	Year Ended			Six Months Ended
	December 31,			December 31,			Years Ended June 30,
	2006			2005			2005			2004
				(In thousands)
Current deferred tax asset (liability)
Derivative instruments	$	(3,844	)	$	4,665		$	2,638		$	—
Accrued bonuses		1,138			452			—			—
Allowance for doubtful accounts		38			38			38			19
Accrued vacation liability		140			82			—			—
Prepaid insurance and other		(365	)		—			—			—


Total current deferred tax assets		(2,893	)		5,237			2,676			19
Less valuation allowance		—			—			—			(19	)

Net current deferred tax asset (liability)	$	(2,893	)	$	5,237		$	2,676		$	—


Long-term deferred tax asset (liability):
Deferred tax assets:
Net operating loss ¹	$	15,306		$	16,074		$	14,544		$	13,278
Asset retirement obligation		1,754			1,306			1,419			1,009
Derivative instruments		—			2,204			1,211			—
Percentage depletion		531			530			541			—
Drilling equipment		—			792			403			—
Equity compensation		2,142			942			—			—
Minimum tax credit		1,368			—			—			—
Other		558			152			66			—

Total long-term deferred tax assets		21,659			22,000			18,184			14,287
Valuation allowance		(661	)		(712	)		(1,139	)		(8,971	)

Net deferred tax asset		20,998			21,288			17,045			5,316
Deferred tax liabilities:
Oil and gas properties		(23,081	)		(17,879	)		(11,256	)		(5,316	)
Investment in DHS		—			(2,001	)		(399	)		—
Investments – available for sale		—			—			(503	)		—
Other		(1,577	)		(86	)		—			—

Total long-term deferred tax liabilities		(24,658	)		(19,966	)		(12,158	)		(5,316	)

Net long-term deferred tax asset (liability)	$	(3,660	)	$	1,322		$	4,887		$	—


Total deferred tax assets before valuation allowance	$	22,975		$	27,237		$	20,860		$	14,306

Total deferred tax liabilities	$	28,867		$	19,966		$	12,158		$	5,316


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, 2006 is approximately $11.4 million 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 $30.1 million tax deduction is included in the table of net operating losses shown below.

F-29

DELTA PERTROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2006 and 2005, and June 30, 2005 and 2004

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 taxable income, and tax planning strategies in making this assessment. Based upon the level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, management believes it is more likely than not that the Company will realize the benefits of these deductible differences, net of the

(9) Income Taxes, Continued

existing valuation allowances at December 31, 2006. The valuation allowance at December 31, 2006 relates primarily to a subsidiary’s net operating loss that cannot be used to reduce taxable income generated by other members of the consolidated tax group and a deferred tax asset generated by a subsidiary that is not consolidated for tax purposes and does not have a history of earnings. The amount of the deferred tax asset considered realizable could be reduced if estimates of future taxable income during the carry-forward period are reduced.

At December 31, 2006, the Company had net operating loss carryforwards for regular and alternative minimum tax purposes as follows:


Regular tax net operating loss	$	62,895
Alternative minimum tax net operating loss		65,043

If not utilized, the tax net operating loss carryforwards will expire from 2007 through 2026. At December 31, 2006, the Company had $1.0 million of net operating loss carryforwards in Australia with no expiration date.

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


2007	$	1,827
2008		720
2009		3,913
2010		6,004
2011		5,939
2012 and thereafter		44,492

	$	62,895

F-30

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2006 and 2005, and June 30, 2005 and 2004

(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. James Wallace, one of our directors, 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 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 $142,000, $58,000, $100,000, and $66,000 for their respective 1% ORRI during the year ended December 31, 2006, six months ended December 31, 2005 and fiscal 2005 and 2004, respectively.

As of December 31, 2006, 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.

(10) Related Party Transactions, Continued

Accounts Receivable Related Parties

At December 31, 2006, the Company had $30,000 of receivables from related parties. 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:


	Year Ended		Six Months Ended
	December 31,		December 31,			Years Ended June 30,
	2006		2005			2005		2004
	(In thousands, except per share amounts)
Numerator:
Numerator for basic and diluted earnings per share - income (loss) available to common stockholders	$	435	$	(590	)	$	15,050	$	5,056
Denominator:
Denominator for basic earnings per share-weighted average shares outstanding		51,702		44,959			40,327		27,041
Effect of dilutive securities, stock options		1,611		—¹			1,693		2,591


Denominator for diluted earnings per common share		53,313		44,959			42,020		29,632


Basic earnings per common share	$	.01	$	(.01	)	$	.37	$	.19

Diluted earnings per common share	$	.01	$	(.01	)	$	.36	$	.17


¹		The denominator for diluted earnings per common share for the six months ended December 31, 2005 excludes 1,944,000 potentially dilutive shares because such shares were anti-dilutive.

F-31

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2006 and 2005, and June 30, 2005 and 2004

(12) Guarantor Financial Information

Delta issued 7% Senior Notes (“Notes”) on March 15, 2005, for the aggregate amount of $150.0 million, which pay interest semiannually on April 1st and October 1st and mature in 2015. The net proceeds were used to refinance debt outstanding under the Company’s credit facility. The Notes are guaranteed by Piper Petroleum Company and certain other 100% owned subsidiaries of the Company at the time of the bond offering (“Guarantors”). The Guarantors, fully, jointly and severally, irrevocably and unconditionally guarantee the performance and payment when due of all the obligations under the Notes. Big Dog, Shark, DHS, CRBP, PGR, DPCA and Amber (“Non-guarantors”) are not guarantors of the indebtedness under the Notes.

The following financial information sets forth the Company’s condensed consolidating balance sheets as of December 31, 2006 and 2005, the condensed consolidating statements of operations for the year ended December 31, 2006, six months ended December 31, 2005 and the years ended June 30, 2005 and 2004, and the condensed consolidating statements of cash flows for the year ended December 31, 2006, six months ended December 31, 2005 and years ended June 30, 2005, and 2004 (in thousands):

Condensed Consolidated Balance Sheet
December 31, 2006


				Guarantor			Non-Guarantor			Adjustments/
	Issuer			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Current assets	$	35,521		$	2,447		$	25,401		$	—		$	63,369

Property and equipment:
Oil and gas		763,126			444			58,078			(12,119	)		809,529
Drilling rigs and trucks		595			—			135,443			—			136,038
Other		23,435			4,320			1,137			—			28,892

Total property and equipment		787,156			4,764			194,658			(12,119	)		974,459

Accumulated DD&A		(112,691	)		(119	)		(20,004	)		—			(132,814	)


Net property and equipment		674,465			4,645			174,654			(12,119	)		841,645
Investment in subsidiaries		66,366			—			—			(66,366	)		—
Other long-term assets		11,424			3,521			9,385			—			24,330


Total assets	$	787,776		$	10,613		$	209,440		$	(78,485	)	$	929,344


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		3,942			9			83			—			4,034


Total long-term liabilities		287,651			1,609			84,882			—			374,142

Minority interest		27,390			—			—			—			27,390

Stockholders’ equity		384,391			7,804			114,523			(78,485	)		428,233


Total liabilities and stockholders’ equity	$	787,776		$	10,613		$	209,440		$	(78,485	)	$	929,344

F-32

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2006 and 2005, and June 30, 2005 and 2004

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

(12) Guarantor Financial Information, Continued

Condensed Consolidated Balance Sheet
December 31, 2005


				Guarantor			Non-Guarantor			Adjustments/
	Issuer			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Current assets	$	50,518		$	657		$	10,414		$	—		$	61,589

Property and equipment:
Oil and gas		554,414			6,838			48,052			(3,496	)		605,808
Drilling rigs and trucks		—			—			64,130			—			64,130
Other		12,266			—			543			—			12,809

Total property and equipment		566,680			6,838			112,725			(3,496	)		682,747

Accumulated DD&A		(56,733	)		(1,088	)		(3,772	)		—			(61,593	)

Net property and equipment		509,947			5,750			108,953			(3,496	)		621,154

Investment in subsidiaries		69,164			—			—			(69,164	)		—
Other long-term assets		8,027			—			2,623			—			10,650


Total assets	$	637,656		$	6,407		$	121,990		$	(72,660	)	$	693,393


Current liabilities	$	92,426		$	188		$	14,158		$	—		$	106,772

Long-term liabilities
Long-term debt		218,304			—			29,364			—			247,668
Asset retirement obligation		2,975			25			2			—			3,002


Total long-term liabilities		221,279			25			29,366			—			250,670

Minority interest		15,496			—			—			—			15,496

Stockholders’ equity		308,455			6,194			78,466			(72,660	)		320,455


Total liabilities and stockholders’ equity	$	637,656		$	6,407		$	121,990		$	(72,660	)	$	693,393

F-34

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2006 and 2005, and June 30, 2005 and 2004

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


				Guarantor			Non-Guarantor			Adjustments/
	Issuer			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Total revenue	$	50,516		$	1,616		$	16,316		$	(7,220	)	$	61,228

Operating expenses:
Lease operating expense		12,245			178			—			—			12,423
Depreciation and depletion		15,868			158			2,846			—			18,872
Exploration expense		3,408			(1	)		4			—			3,411
Drilling and trucking operations		—			—			9,545			(3,724	)		5,821
Dry hole, abandonment and impaired		4,073			—			—			—			4,073
General and administrative		15,263			7			1,221			—			16,491


Total expenses		50,857			342			13,616			(3,724	)		61,091


Income (loss) from continuing operations		(341	)		1,274			2,700			(3,496	)		137

Other income and expenses		(21,146	)		4			(1,003	)		(688	)		(22,833	)
Income tax benefit		8,451			—			—			—			8,451
Discontinued operations		13,655			—			—			—			13,655


Net income (loss)	$	619		$	1,278		$	1,697		$	(4,184	)	$	(590	)

(12) Guarantor Financial Information, Continued

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

Condensed Consolidated Statement of Operations
Year Ended June 30, 2005


				Guarantor		Non-Guarantor			Adjustments/
	Issuer			Subsidiaries		Subsidiaries			Eliminations			Consolidated
Total revenue	$	70,121		$	1,657	$	7,319		$	(2,523	)	$	76,574

Operating expenses:
Lease operating expense		17,772			489		—			—			18,261
Depreciation and depletion		18,744			148		1,525			—			20,417
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		61,230			646		9,457			(2,133	)		69,200


Income (loss) from continuing operations		8,891			1,011		(2,138	)		(390	)		7,374

Other income and expenses		(7,792	)		31		(2	)		—			(7,763	)
Income tax benefit		7,987			—		—			—			7,987
Discontinued operations		7,452			—		—			—			7,452


Net income (loss)	$	16,538		$	1,042	$	(2,140	)	$	(390	)	$	15,050

F-35

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2006 and 2005, and June 30, 2005 and 2004

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

(12) Guarantor Financial Information, Continued

Condensed Consolidated Statement of Operations
Year Ended June 30, 2004


				Guarantor		Non-Guarantor			Adjustments/
	Issuer			Subsidiaries		Subsidiaries			Eliminations			Consolidated
Total revenue	$	18,985		$	1,429	$	33		$	(33	)	$	20,414

Operating expenses:
Lease operating expense		6,687			399		—			—			7,086
Depreciation and depletion		6,768			263		14			—			7,045
Exploration expense		2,405			—		1			—			2,406
Drilling and trucking operations		—			—		265			(33	)		232
Dry hole, abandonment and impaired		2,132			—		—			—			2,132

General and administrative		7,906			19		124			—			8,049


Total expenses		25,898			681		404			(33	)		26,950


Income (loss) from continuing operations		(6,913	)		748		(371	)		—			(6,536	)

Other income and expenses		(1,643	)		4		(1	)		70			(1,570	)
Discontinued operations		13,162			—		—			—			13,162

Net income (loss)	$	4,606		$	752	$	(372	)	$	70		$	5,056

Condensed Consolidated Statement of Cash Flows
Year Ended June 30, 2004


				Guarantor			Non-Guarantor
	Issuer			Subsidiaries			Subsidiaries			Consolidated
Operating activities	$	9,263		$	518		$	(158	)	$	9,623
Investing activities		(144,232	)		(370	)		(3,836	)		(148,438	)
Financing activities		134,795			(218	)		4,045			138,622


Net increase (decrease) in cash and cash equivalents		(174	)		(70	)		51			(193	)

Cash at beginning of the period		2,160			110			1			2,271

Cash at the end of the period	$	1,986		$	40		$	52		$	2,078

F-36

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2006 and 2005, and June 30, 2005 and 2004

(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 year ended December 31, 2006, six months ended December 31, 2005 and years ended June 30, 2005, and 2004 was approximately $856,000, $432,000, $491,000, and $311,000, respectively. The following table summarizes the future minimum payments under all non-cancelable operating lease obligations:


	(In thousands)
2007	$	2,950
2008		2,901
2009		2,777
2010		1,868
2011		1,142
2012 and thereafter		3,088

	$	14,726

During the year ended December 31, 2006, the Company had 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. The agreements expired by their terms on December 31, 2006. It is likely that the Company will enter into similar agreements with the same executive officers during the current fiscal year.

Offshore Litigation

F-37

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2006 and 2005, and June 30, 2005 and 2004

attributed to this lease represents significantly more than half of the net amount that would be received by us under the summary judgment. In its motion for reconsideration, the government has asserted that the affected lease is not being returned in substantially the same condition that it was in at the time it was initially granted because, allegedly, a significant portion of the hydrocarbons has been drained by wells that were drilled on an immediately adjacent lease. Although discovery is continuing on this issue, we currently believe that the government’s assertion is without merit and we are vigorously contesting it; however, we cannot predict with certainty the ultimate outcome of this matter.

(13) Commitments and Contingencies, Continued

Options Inquiries

In the past year, 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 Securities and Exchange Commission (“SEC”) related to the Company’s stock option grants and related practices. The special committee of the Company’s Board of Directors has 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 the SEC in August 2006 and intends to continue to cooperate fully with the U.S. Attorney and the SEC if they should request any additional information concerning this matter in the future.

Shareholder Derivative Suits

During September and October of 2006, three separate shareholder derivative actions were filed on the Company’s behalf in US District Court for the District of Colorado relating to the options backdating issue, all of which have been consolidated into a single action. The consolidated complaint alleges 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 allege 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 allege 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 seeks 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. A discovery stay has been granted while the court considers various motions to dismiss the action.

F-38

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2006 and 2005, and June 30, 2005 and 2004

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.

(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 year ended December 31, 2006, six months ended December 31, 2005 and year ended June 30, 2005. Prior to the fiscal year ended June 30, 2005, the Company only operated in its Oil and Gas segment.


							Inter-segment
	Oil and Gas			Drilling			Eliminations			Consolidated
				(In thousands)
Year Ended December 31, 2006

Revenues from external customers	$	119,500		$	57,149		$	—		$	176,649
Inter-segment revenues		—			25,033			(25,033	)		—

Total revenues	$	119,500		$	82,182		$	(25,033	)	$	176,649

Operating income (loss)	$	(8,288	)	$	15,467		$	(12,120	)	$	(4,941	)

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

Income (loss) from continuing operations, before tax	$	(14,714	)	$	8,203		$	(14,715	)	$	(21,226	)

Six Months Ended December 31, 2005
Revenues from external customers	$	52,132		$	9,096		$	—		$	61,228
Inter-segment revenues		—			7,220			(7,220	)		—

Total revenues	$	52,132		$	16,316		$	(7,220	)	$	61,228

Operating income (loss)	$	876		$	2,757		$	(3,496	)	$	137

Other income and (expense)¹		(21,142	)		(1,003	)		(688	)		(22,833	)

Income (loss) from continuing operations, before tax	$	(20,266	)	$	1,754		$	(4,184	)	$	(22,696	)

Year Ended June 30, 2005
Revenues from external customers	$	71,778		$	4,796		$	—		$	76,574
Inter-segment revenues		—			2,523			(2,523	)		—

Total revenues	$	71,778		$	7,319		$	(2,523	)	$	76,574
Operating income (loss)	$	9,790		$	(2,028	)	$	(388	)	$	7,374
Other income and (expense)¹		(8,778	)		(2	)		1,017			(7,763	)

Income (loss) from continuing operations, before tax	$	1,012		$	(2,030	)	$	629		$	(389	)


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-39

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2006 and 2005, and June 30, 2005 and 2004

(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, 2006

Total revenue	$	40,223		$	43,833		$	48,477		$	44,116
Income (loss) from continuing operations before income taxes, discontinued operations and cumulative effect		21,460			(5,238	)		(20,752	)		(16,696	)
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	)

Six Months Ended December 31, 2005

Total revenue		N/A			N/A		$	30,075		$	31,152
Income (loss) from continuing operations before income taxes, discontinued operations and cumulative effect								(21,180	)		(1,518	)
Net income (loss)								(2,163	)		1,573
Net income (loss) per common share:(1)
Basic							$	(.05	)	$	.03
Diluted							$	(.05	)	$	.03

Year Ended June 30, 2005

Total revenue	$	22,387		$	23,523		$	14,750		$	15,583
Income (loss) from continuing operations before income taxes, discontinued operations and cumulative effect		2,225			(4,393	)		5			1,772
Net income		4,940			1,357			3,944			4,809
Net income per common share:(1)
Basic	$	.12		$	.04		$	.10		$	.12
Diluted	$	.12		$	.04		$	.09		$	.11

Year Ended June 30, 2004

Total revenue	$	5,778		$	7,003		$	3,087		$	4,546
Income from continuing operations before income taxes, discontinued operations and cumulative effect		(2,624	)		(2,707	)		(1,300	)		(1,475	)
Net income		2,454			586			1,364			652
Net income per common share:(1)
Basic	$	.09		$	.02		$	.06		$	.03
Diluted	$	.08		$	.02		$	.05		$	.03


⁽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-40

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2006 and 2005, and June 30, 2005 and 2004

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

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


	December 31,			December 31,			June 30,
	2006			2005			2005			2004
				(In thousands)
Unproved offshore California properties	$	12,484		$	10,960		$	10,925		$	10,844
Unproved onshore domestic properties		205,896			156,183			91,010			38,903
Proved offshore California properties		16,906			13,678			12,207			9,103
Proved onshore domestic properties		574,243			424,988			353,099			214,042

		809,529			605,809			467,241			272,892
Accumulated depreciation and depletion		(117,419	)		(57,922	)		(43,034	)		(21,317	)

	$	692,110		$	547,887		$	424,207		$	251,575

Costs incurred⁽¹⁾ in oil and gas activities are as follows:


	Year Ended				Six Months Ended
	December 31,				December 31,				Years Ended June 30,
	2006				2005				2005				2004
						(In thousands)
	Onshore		Offshore		Onshore		Offshore		Onshore		Offshore		Onshore		Offshore
Unproved property acquisition costs	$	60,002	$	1,525	$	88,116	$	35	$	25,383	$	81	$	37,223	$	680
Proved property acquisition costs		2,972		283		4,386		82		81,190		—		128,587		—
Developed costs incurred on undeveloped reserves		43,198		2,946		30,891		1,389		72,413		3,104		3,789		1,070
Development costs — other		159,807		—		54,591		—		36,369		—		20,986		—
Exploration costs		4,690		—		2,061		—		6,155		—		2,406		—

	$	270,669	$	4,754	$	180,045	$	1,506	$	221,510	$	3,185	$	192,991	$	1,750


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

F-41

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2006 and 2005, and June 30, 2005 and 2004

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

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


	Year Ended				Six Months Ended
	December 31,				December 31,				Years Ended June 30,
	2006				2005				2005				2004
							(In thousands)
	Onshore		Offshore		Onshore		Offshore		Onshore		Offshore		Onshore		Offshore
Revenue Oil and gas revenues	$	116,616	$	7,596	$	51,735	$	3,810	$	67,217	$	5,191	$	17,298	$	3,975
Expenses:
Production costs		27,215		3,705		10,297		2,128		14,421		3,840		3,829		3,257

Depletion		63,278		1,049		15,207		382		17,381		720		6,109		705
Exploration		4,688		—		3,411		—		6,155		—		2,406		—
Abandonment and impaired properties		11,359		—		—		—		—		—		—		—
Dry hole costs		4,323		—		4,073		—		2,771		—		2,132		—

Results of operations of oil and gas producing activities	$	5,753	$	2,842	$	18,747	$	1,300	$	26,489	$	631	$	2,822	$	13


Income from operations of properties sold, net		1,458		—		1,867		—		7,452		—		11,275		—

Gain on sale of properties		6,712		—		11,788		—		—		—		1,887		—

Cumulative effect on change in accounting and principle		—		—		—		—		—		—		—		—


Results of discontinued operations of oil and gas producing activities	$	8,170	$	—	$	13,655	$	—	$	7,452	$	—	$	13,162	$	—

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. During the fiscal year ended June 30, 2004, four customers individually accounted for 17%, 17%, 14%, and 10% of the Company’s total oil and gas sales.

F-42

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2006 and 2005, and June 30, 2005 and 2004

(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.

Estimates of our oil and natural gas reserves and present values as of December 31, 2006, December 31, 2005, and June 30, 2005 and 2004 are derived from reserve reports prepared by Ralph E. Davis Associates, Inc., our independent reserve engineers with respect to onshore reserves, or Mannon Associates Inc., our independent reserve engineers with respect to offshore reserves.

F-43

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2006 and 2005, and June 30, 2005 and 2004

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

A summary of changes in estimated quantities of proved reserves for the year ended December 31, 2006, six months ended December 31, 2005 and the years ended June 30, 2005 and 2004 is as follows:


	Onshore						Offshore
	GAS			OIL			OIL
	(MMcf)			(MBbl)			(MBbl)
				(In thousands)
Estimated Proved Reserves: Balance at June 30, 2003		55,200			3,698			2,051
Revisions of quantity estimate		(3,136	)		469			(44	)
Extensions and discoveries		6,560			69			—
Purchase of properties		39,782			8,306			—
Sale of properties		(6,817	)		(596	)		—
Production		(3,110	)		(568	)		(180	)


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


Proved developed reserves:

June 30, 2003		28,611			2,608			919
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

F-44

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2006 and 2005, and June 30, 2005 and 2004

(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, 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


June 30, 2004
Future net cash flows	$	953,532		$	51,625		$	1,005,157
Future costs:
Production		225,046			23,558			248,604
Development and abandonment		55,845			11,054			66,899
Income taxes		165,492			—			165,492

Future net cash flows		507,149			17,013			524,162
10% discount factor		(230,540	)		(5,585	)		(236,125	)

Standardized measure of discounted future net cash flows	$	276,609		$	11,428		$	288,037

F-45

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2006 and 2005, and June 30, 2005 and 2004

(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 year ended December 31, 2006, six months ended December 31, 2005 and the fiscal years ended June 30, 2005 and 2004 are as follows:


	Year Ended			Six Months Ended
	December 31,			December 31,			Years Ended June 30,
	2006			2005			2005			2004
	(In thousands)
Beginning of the year	$	749,624		$	517,370		$	288,037		$	107,211
Sales of oil and gas production during the period, net of production costs		(98,340	)		(47,746	)		(68,602	)		(27,459	)
Purchase of reserves in place		14,716			58,790			201,693			248,478
Net change in prices and production costs		(567,435	)		170,831			90,938			26,088
Changes in estimated future development costs		(35,041	)		(50,676	)		19,345			8,592
Extensions, discoveries and improved recovery		213,741			336,920			93,624			11,599
Revisions of previous quantity estimates, estimated timing of development and other		(82,456	)		(164,632	)		(91,002	)		(25,807	)
Previously estimated development and abandonment costs incurred during the period		46,144			32,280			72,413			4,859
Sales of reserves in place		(55,640	)		(56,276	)		(42,508	)		(17,934	)
Change in future income tax		222,959			(98,974	)		(75,371	)		(58,311	)
Accretion of discount		74,962			51,737			28,803			10,721

End of year	$	483,234		$	749,624		$	517,370		$	288,037

(18) Subsequent Events

On January 10, 2007, we sold non-core properties located in Padgett Field, Kansas for proceeds of $5.6 million. These properties are included in assets held for sale as of December 31, 2006.

On January 25, 2007, Delta announced an offering of 2,768,000 shares of common stock priced at $20.98 per share. The equity offering resulted in net proceeds of approximately $56.6 million. The proceeds were used to repay the $25.0 million unsecured term loan and reduce outstanding indebtedness under the Company’s credit facility. The Company then intends to redraw all or some of the amounts paid on the credit facility for exploration and development of oil and gas properties, working capital and other general corporate purposes.

On February 9, 2007, the Company issued executive performance share grants to each of 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. 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 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 365-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.

(18) Subsequent Events, Continued

On February 13, 2007, Delta entered into a purchase and sale agreement to divest of certain non-core properties located in the Permian Basin and the Gulf Coast. The transaction is expected to close during March 2007 for proceeds of $31.5 million for an estimated after-tax loss of approximately $6.25 million.

F-46

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.

F-47

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.

F-48

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.

9.		Voting Trust Agreement.

9.1		Voting Agreement and Irrevocable Proxy dated as of November 8, 2005 by and among Delta Petroleum Corporation, DPCA LLC, and certain stockholders of Castle Energy Corporation, as amended. Incorporated by reference to Appendix B to the proxy Statement/prospectus included in the Company’s Form S-4 registration statement, SEC File No. 333-130672.

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 to 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.

F-50

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		Change in Control Executive Severance Agreement with Roger A. Parker dated May 5, 2005. Incorporated by reference from Exhibit 10.2 to the Company’s Form 8-K dated May 5, 2005.*

10.13		Change in Control Executive Severance 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.*

10.14		Change in Control Executive Severance 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.*

10.15		Change in Control Executive Severance Agreement with Stanley F. Freedman dated January 11, 2006. Incorporated by reference from Exhibit 10.2 to the Company’s Form 8-K dated January 11, 2006. *

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

10.17		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.* 10.18 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.

10.19		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.

10.20		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.

10.21		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.*

F-51

10.22		Form of Restricted Stock Award Agreement. Incorporated by reference from Exhibit 10.2 to the Company’s Form 8-K dated January 5, 2007.*

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.

F-52


		Page No.
Reports of Independent Registered Public Accounting Firm		F-1,2

Consolidated Balance Sheets as of December 31, 2006 and December 31, 2005		F-3

Consolidated Statements of Operations for the year ended December 31, 2006, six months ended December 31, 2005 and years ended June 30, 2005 and 2004		F-4

Consolidated Statements of Stockholders’ Equity and Comprehensive Income (Loss) for the year ended December 31, 2006, six months ended December 31, 2005 and years ended June 30, 2005 and 2004		F-5

Consolidated Statements of Cash Flows for the year ended December 31, 2006, six months ended December 31, 2005 and years ended June 30, 2005 and 2004		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 61 are filed as part of this report. Management contracts and compensatory plans required to be filed as exhibits are marked with a “*”.


		PAGE
PART I

Item 1.	BUSINESS		4
Item 1A.	RISK FACTORS		11
Item 1B.	UNRESOLVED STAFF COMMENTS		22
Item 2.	PROPERTIES		23
Item 3.	LEGAL PROCEEDINGS		30
Item 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS		31
Item 4A.	DIRECTORS AND EXECUTIVE OFFICERS		32

PART II

Item 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES		35
Item 6.	SELECTED FINANCIAL DATA		36
Item 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		36
Item 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		56
Item 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA		57
Item 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE		57
Item 9A.	CONTROLS AND PROCEDURES		57

PART III

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

PART IV

Item 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES		60
Subsidiaries
Consent of KPMG LLP
Consent of Ralph E. Davis Associates, Inc.
Consent of Mannon Associates
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO Pursuant to Section 1350
Certification of CFO Pursuant to Section 1350


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


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


Signature and Title		Date

/s/ Roger A. Parker		March 7, 2007
Roger A. Parker, Director

/s/ Kevin R. Collins		March 1, 2007
Kevin R. Collins, Director

/s/ Jerrie F. Eckelberger		March 1, 2007
Jerrie F. Eckelberger, Director

/s/ Aleron H. Larson, Jr.		March 1, 2007
Aleron H. Larson, Jr., Director

/s/ Russell S. Lewis		March 1, 2007
Russell S. Lewis, Director

/s/ Jordan R. Smith		March 1, 2007
Jordan R. Smith, Director

/s/ Neal A. Stanley		March 1, 2007
Neal A. Stanley, Director

/s/ James B. Wallace		March 1, 2007
James B. Wallace, Director

James P. Van Blarcom, Director


		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

The Bonds Company		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


/s/ Robert W. Mannon
Robert W. Mannon
President
Santa Barbara, California
February 28, 2007