UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-K

(Mark One)

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

EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2011

OR

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

Commission File No. 0-16203

DELTA PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

Delaware	84-1060803
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

370 17th Street, Suite 4300 Denver, Colorado	80202
(Address of principal executive offices)	(Zip Code)

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

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

Title of each class	Name of each exchange on which registered
Common Stock, $0.01 par value	Not currently listed

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

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

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

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

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

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

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

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

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

As of June 30, 2011, the aggregate market value of voting stock held by non-affiliates of the registrant was approximately $95.0 million, based on the closing price of the Common Stock on the NASDAQ National Market of $0.50 per share. As of August 17, 2012, 28,576,067 shares of registrant’s Common Stock, $0.01 par value, were issued and outstanding.

TABLE OF CONTENTS

	PAGE
PART I
Item 1. BUSINESS		4
Item 1A. RISK FACTORS		12
Item 1B. UNRESOLVED STAFF COMMENTS		22
Item 2. PROPERTIES		22
Item 3. LEGAL PROCEEDINGS		26
Item 4. MINE SAFETY DISCLOSURES		27
PART II
Item  5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES		27
Item 6. SELECTED FINANCIAL DATA		29
Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		30
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		43
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA		43
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE		43
Item 9A. CONTROLS AND PROCEDURES		43
Item 9B. OTHER INFORMATION		46
PART III
Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE		46
Item 11. EXECUTIVE COMPENSATION		51
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		61
Item 14. PRINCIPAL ACCOUNTING FEES AND SERVICES		62
PART IV
Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES		63

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

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EXPLANATORY NOTE

Delta Petroleum Corporation is filing this Annual Report on Form 10-K for the fiscal year ended December 31, 2011 as part of its efforts to become current in its filing obligations under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). This report is being filed contemporaneously with the company’s Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2012, and June 30, 2012, which have not been previously filed. See “Business—Bankruptcy Matters” for a description of the company’s ongoing bankruptcy process.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

We are including the following discussion to inform our existing and potential security holders generally of some of the risks and uncertainties that can affect us and to take advantage of the “safe harbor” protection for forward-looking statements afforded under federal securities laws. From time to time, our management or persons acting on our behalf make forward-looking statements to inform existing and potential security holders about us. Forward-looking statements are generally accompanied by words such as “estimate,” “project,” “propose,” “potential,” “predict,” “forecast,” “believe,” “expect,” “anticipate,” “plan,” “goal” or other words that convey the uncertainty of future events or outcomes. Except for statements of historical or present facts, all other statements contained in this Annual Report on Form 10-K are forward-looking statements. The forward-looking statements may appear in a number of places and include statements with respect to, among other things: business objectives and strategies, including our focus on the Vega Area of the Piceance Basin; operating strategies; oil and gas reserve estimates (including estimates of future net revenues associated with such reserves and the present value of such future net revenues); estimates of future production of oil and natural gas; marketing of oil and natural gas; expected future revenues and earnings, and results of operations; future capital, development and exploration expenditures (including the amount and nature thereof); anticipated compliance with and impact of laws and regulations; and expected outcomes relating to our bankruptcy proceedings.

These statements by their nature are subject to certain risks, uncertainties and assumptions and will be influenced by various factors. Should any of the assumptions underlying a forward-looking statement prove incorrect, actual results could vary materially. In some cases, information regarding certain important factors that could cause actual results to differ materially from any forward-looking statement appears together with such statement. In addition, the factors described under Critical Accounting Policies and Risk Factors, as well as other possible factors not listed, could cause actual results to differ materially from those expressed in forward-looking statements, including, without limitation, the following:

• deviations in and volatility of the market prices of both crude oil and natural gas produced by us;

• the availability of capital on an economic basis, or at all, to fund our existing and future financial obligations;

• lower natural gas and oil prices negatively affecting our ability to generate cash from operations or borrow or otherwise raise capital;

• risks associated with bankruptcy process, including the risk that we will effectively assume unexpected liabilities as a result, or not obtain the expected benefits, of the transaction contemplated by the Contribution Agreement, and the risk that the Contribution Agreement will not close;

• declines in the values of our natural gas and oil properties resulting in write-downs;

• the impact of current economic and financial conditions on our ability to raise capital;

• a continued imbalance in the demand for and supply of natural gas in the U.S.;

• the results of exploratory drilling activities;

• expiration of oil and natural gas leases that are not held by production;

• uncertainties in the estimation of proved reserves and in the projection of future rates of production;

• timing, amount, and marketability of production;

• third party curtailment, or processing plant or pipeline capacity constraints beyond our control;

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

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• effectiveness of management strategies and decisions, including those of the management of Piceance Energy LLC, of which we will own a 33.34% interest following consummation of the transactions contemplated by the Contribution Agreement

• the strength and financial resources of our competitors;

• climatic conditions;

• changes in the legal and/or regulatory environment and/or changes in accounting standards policies and practices or related interpretations by auditors or regulatory entities;

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

• the timing, effects and success of our acquisition, disposition and exploration and development activities;

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

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

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

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

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

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PART I

Item 1. Business

General

Delta Petroleum Corporation (“we,” “us,” “our,” “Delta,” or the “Company”) is an independent oil and gas company engaged primarily in the exploration for, and the acquisition, development, production, and sale of, natural gas and crude oil. Our core area of operations is the Rocky Mountain Region, where the majority of our proved reserves and production are located.

Delta was incorporated in Colorado in 1984. On November 07, 2005, Delta reincorporated in 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.

Bankruptcy Matters

Bankruptcy Filing

On December 16, 2011, Delta and its subsidiaries Amber Resources Company of Colorado (“Amber”), DPCA, LLC, Delta Exploration Company, Inc., Delta Pipeline, LLC, DLC, Inc., CEC, Inc. and Castle Texas Production Limited Partnership filed voluntary petitions under Chapter 11 of the U.S. Bankruptcy Code in the United States Bankruptcy Court for the District of Delaware (the “Bankruptcy Court”). On January 6, 2012 Castle Exploration Company, Inc., a subsidiary of DPCA LLC, also filed a voluntary petition under Chapter 11 in the Bankruptcy Court. We refer to Delta and its subsidiaries included in the bankruptcy petitions collectively as the “Debtors.”

For the duration of our Chapter 11 proceedings, our operations, including our ability to develop and execute a business plan, are subject to the risks and uncertainties associated with the bankruptcy process as described below under “Risk Factors.” As such, and because our structure, the number of our outstanding shares, shareholders, majority shareholders, assets, liabilities, officers and/or directors will likely be significantly different following the outcome of the bankruptcy proceedings, the description of business operations, planned operations and properties included in this report may not accurately reflect our operations, properties and business plans following the bankruptcy process.

Contribution Agreement

On December 27, 2011, the Debtors filed a motion requesting an order to approve matters relating to a proposed sale of the company’s assets, including bidding procedures, establishment of a sale auction date and establishment of a sale hearing date. On January 11, 2012, the Bankruptcy Court issued an order approving these matters. On March 20, 2012, Delta announced that it was seeking court approval to amend the bidding procedures for its upcoming auction to allow bids relating to potential plans of reorganization as well as asset sales. On March 22, 2012, the Bankruptcy Court approved the revised procedures.

Following the auction, which was held between April 24 – 25, 2012, the Debtors obtained approval from the Bankruptcy Court to proceed with Laramie Energy II, LLC (“Laramie”) as the sponsor of a plan of reorganization (the “Plan”). In connection with the Plan, Delta entered into a non-binding term sheet describing a transaction by which Laramie and Delta intend to form a new joint venture called Piceance Energy, LLC (“Piceance Energy”). On June 4, 2012, Delta entered into a Contribution Agreement (the “Contribution Agreement”) with Piceance Energy and Laramie to effect the transactions contemplated by the term sheet. Under the Contribution Agreement, each of Delta and Laramie will contribute to Piceance Energy their respective assets in Mesa and Garfield Counties, Colorado. Following the contribution, Piceance Energy will be owned 66.66% by Laramie and 33.34% by Delta. We sometimes refer to Delta as it will exist following the closing of the transaction as “Reorganized Delta.” At the closing, Piceance Energy will enter into a new credit agreement, borrow $100 million under that agreement, and distribute $75 million to Reorganized Delta and $25 million to Laramie. Reorganized Delta will use its distribution to pay bankruptcy expenses and other administrative expense claims, secured debt, and priority claims. The distribution from Piceance Energy to Reorganized Delta and Laramie will be subject to adjustment to give effect to the transaction effective date of July 31, 2012. Reorganized Delta will also enter into a delayed draw term loan credit facility of up to $30 million. The closing transactions are described further in “Management’s Discussion and Analysis of Financial Condition and Results of Operation – Contribution Agreement and Related Credit Agreements.”

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Following the closing, Reorganized Delta will retain its interest in the Point Arguello unit offshore California and, other miscellaneous assets and certain tax attributes, including significant net operating losses. The common stock of Reorganized Delta will be owned by Delta’s creditors, and Delta’s current shareholders will not receive any consideration under the Plan. Delta may also retain its interest in Amber depending on how claims against Amber’s bankruptcy estate are reconciled.

Contemporaneously with the closing, we will enter into a Limited Liability Company Agreement with Laramie that will govern the operations of Piceance Energy. Under that agreement, Laramie will act as the manager of Piceance Energy, will control the day-to-day operations of Piceance Energy and will appoint a majority of the members of its board of managers. Reorganized Delta will have veto rights over certain matters and the right to appoint the remaining members of Piceance Energy’s board of managers. In addition, Laramie and Piceance Energy will enter into a Management Services Agreement pursuant to which Laramie will agree to provide certain services to Piceance Energy for a fee of $650,000 per month.

Also contemporaneously with the closing, we will amend and restate our Certificate of Incorporation and our Bylaws. Under the amended and restated documents, our name will be changed to “Par Petroleum Corporation.” In addition, the amended and restated Certificate of Incorporation will contain restrictions that will limit the ability of holders of five percent or more of our newly issued common stock as of the closing to acquire or dispose of shares in certain circumstances, limit the ability of other persons to become five percent holders and render void certain transfers of our stock that violate these restrictions. The purpose of these provisions is to preserve certain of our tax attributes, including net operating loss carryforwards that we believe may have value. Under the amended and restated bylaws, our board of directors will have either five or six members, each of whom will be appointed by current creditors of ours pursuant to a Stockholders’ Agreement they will enter into at closing.

The Contribution Agreement includes customary representations, warranties, covenants and indemnities by the parties as well as customary closing conditions and termination rights. Subject to satisfaction of the closing conditions, the transaction is expected to occur on or before August 31, 2012.

On June 4, 2012, the Debtors filed a disclosure statement and the Plan, and holders of Delta’s notes, representing approximately 79.7% of the total amount of claims of the noteholders (collectively, the Supporting Noteholders”), the Debtors and Laramie agreed in form and substance to the terms of a Plan Support Agreement. The Bankruptcy Court approved the disclosure statement on July 6, 2012. The Debtors solicited creditors eligible to vote on the Plan, and received sufficient votes to confirm the Plan. The Plan, as amended, was confirmed on August 16, 2012.

The foregoing description of the Contribution Agreement, the Limited Liability Company Agreement, the Management Services Agreement, the amended and restated Certificate of Incorporation and Bylaws, and the Stockholders’ Agreement is qualified in its entirety by the full text of the forms of those documents, which are attached as exhibits to this report. The finalized documents may differ from the attached forms, but we do not anticipate any material changes.

Under the Plan, Delta’s priority non-tax claims and secured claims will be unimpaired in accordance with section 1124(1) of the Bankruptcy Code. Each general unsecured claim and noteholder claims will receive its pro-rata share of new common stock of Par Petroleum in full satisfaction of its claims.

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Laramie Properties

Laramie is a Denver-based company primarily focused on finding and developing natural gas reserves from unconventional gas reservoirs within the Rocky Mountain Region. Its predecessor company, Laramie Energy, LLC (“Laramie I”), sold all of its oil and gas assets in May 2007 to Plains Exploration & Production Company, Inc. Laramie was formed in June 2007 by Laramie I executives and former employees and by affiliates of the private equity investors in Laramie I. Laramie is backed by equity capital commitments funded by Laramie’s management team, EnCap Investments, Avista Capital, and DLJ Merchant Banking Partners (an affiliate of Credit Suisse Securities).

All of the assets Laramie and Delta are contributing to Piceance Energy are located within Garfield and Mesa Counties, Colorado and are within a 10-mile radius in the Piceance Basin geologic province. All of Laramie’s and Delta’s oil and gas reserves produce from the same geologic formations, the Mesaverde and Mancos Formations, and some of the acreage is contiguous. Laramie and its predecessor company have drilled over 300 natural gas wells with over a 99% success rate in the Piceance Basin.

The foregoing description of the Laramie Properties was provided by Laramie.

As of April 30, 2012, the proven reserves that Laramie is contributing to Piceance Energy consist of the following (unaudited):

	Net Gas MMCF		Net Oil MBbls		Net NGLs MBbls		Equivalent Mmcfe
Proved Developed Producing		49,466		157		2,734		66,812
Proved Developed Behind Pipe		7,094		22		395		9,592
Proven Undeveloped		343,249		1,276		18,051		459,211
Total		399,809		1,455		21,180		535,615

Other Recent Events

Divestiture of Subsidiary

On October 31, 2011, we sold our stock in DHS, our 49.8% subsidiary, to DHS’s lender, Lehman Commercial Paper, Inc., for $500,000. We recognized a gain of approximately $5.1 million in connection with the divestiture of DHS during the three months ending December 31, 2011.

Sale of Non-Core Assets

On June 28, 2011, we closed a sale of various assets located primarily in Texas and Wyoming to Wapiti Oil & Gas, L.L.C. (the “2011 Wapiti Transaction”) for gross cash proceeds of approximately $43.2 million. A portion of the proceeds from the 2011 Wapiti Transaction was used to reduce amounts outstanding under the credit facility of the Company then in place, and a portion was used to fund capital development activities in the Piceance Basin.

Operations

During the year ended December 31, 2011, we were primarily engaged in the acquisition, exploration, development, and production of oil and natural gas properties.

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Oil and Gas Reserves

The following table presents reserve and production information regarding our primary oil and natural gas areas of operation as of December 31, 2011:

	Oil		Natural Gas(1)		Total		2011 Production
	(Mbbl)		(Mmcf)		(Mmcfe)		(MMcfe/d) (2)
Proved Developed
Rocky Mountain Region		303		87,209		89,027		27.9
Other		191		—		1,146		1.6
Total		494		87,209		90,173		29.5
Proved Undeveloped
Rocky Mountain Region(3)		—		—		—		—
Total Proved Reserves(4)		494		87,209		90,173

⁽¹⁾  Based on 70,982 MMCF of natural gas and 4,057 MBBL of natural gas liquids, with liquids converted to gas using a ratio of 4 MMCF to 1 barrel.

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

⁽³⁾  At December 31, 2011, based on our limited development plan given our current capital availability, we are unable to book as proved reserves substantially all of our undeveloped locations in the Piceance Basin that would otherwise qualify as proved.

⁽⁴⁾  Based on historical first of month twelve month average posted price of $92.71 per Bbl for WTI oil and spot price of $3.93 per MMBtu for CIG natural gas, in each case adjusted for differentials, contractual deducts and similar factors.

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. We currently own producing and non-producing oil and natural gas interests, undeveloped leasehold interests and related assets in Colorado and New Mexico and interests in a producing Federal unit offshore California.

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 in material respects, 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 currently operate the properties that comprise the majority of our production and reserves.

Contract Drilling Operations

Through a series of transactions in 2004 and 2005, we acquired an interest in DHS, a contract drilling company that is headquartered in Casper, Wyoming. During the second quarter of 2006, DHS engaged in a reorganization transaction pursuant to which it became a subsidiary of DHS Holding Company, a Delaware corporation, and the Company’s ownership interest became an interest in DHS Holding Company. References to DHS herein shall be deemed to include both DHS Holding Company and DHS, unless the context otherwise requires. DHS was a consolidated entity of Delta. Delta currently owns a 49.8% interest in DHS Holding Company, controls the board of directors of DHS and has priority access to all of DHS’s drilling rigs. Subsequent to our 2010 year-end, the Board of Directors of DHS engaged transaction advisors to commence a strategic alternatives process, focused on a sale of the company or substantially all of its assets.

During the fourth quarter of 2011, the Company sold its entire interest in DHS; DHS is reflected as a discontinued operation for all periods presented in our consolidated financial statements.

DHS also owned 100% of Chapman Trucking, which was acquired in November 2005. Employing its 28 trucks and 38 trailers, Chapman provides moving services for DHS and for third party drilling rigs. Chapman Trucking continues to market trucking services in the Casper, Wyoming area. DHS sold Chapman during 2011.

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Contracts — Drilling

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

Markets

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

Distribution

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

Competition

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

Major Customers

During the year ended December 31, 2011, we had two companies that individually accounted for 56% and 19% of our total oil and gas sales. Although a substantial portion of production is purchased by these major customers, we do not believe the loss of any one or several customers would have a material adverse effect on our business as other customers or markets would be accessible to us. See Note 4 our accompanying consolidated financial statements for additional information.

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.

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

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

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

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

Because we are engaged in acquiring, operating, exploring for and developing natural resources, in addition to federal laws we are subject to various state and local provisions regarding environmental and ecological matters. Compliance with environmental laws may necessitate significant capital outlays, may materially affect our earnings potential, and could cause material changes in our proposed business. In the past these laws have not had a material adverse effect on our business. However, during 2009, the Colorado Oil and Gas Conservation Commission (“COGCC”) adopted new regulations related to oil and gas development that are intended to prevent or mitigate environmental impacts of oil and gas development and include the permitting of wells. It should be noted in that regard that we have significant operations in Colorado through our minority interest in Piceance Energy. Although we do not anticipate that expenditures to comply with existing environmental laws in any of the areas that we operate will change materially during 2012, we cannot be certain as to the nature and impact any new statutes implemented in Colorado or in other states in which we conduct our business may have on our operations.

Hazardous substances and waste disposal

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

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

Oil spills

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

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

In light of the April 2010 BP/Macando oil spill, these limits and related liability provisions are under significant scrutiny, and may be changed going forward. This could impose additional obligations on us, as well as on the oil and gas industry in general.

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

Offshore production

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

We do not act as operator for any of our offshore California properties, which are subject to regulation by the California Coastal Commission (“Coastal Commission”) and the California Department of Fish and Game’s Office of Oil Spill Prevention and Response (“OSPR”), which has adopted oil-spill prevention regulations that overlap with federal regulations. The Coastal Commission works with local governments to make permitting decisions for new developments in certain coastal areas and reviews local coastal programs, such as land-use restrictions. The Coastal Commission also works with the OSPR to protect against and respond to coastal oil spills. The operators of our offshore California properties are primarily liable for oil spills and are required by BOEMRE to carry certain types of insurance and to post bonds in that regard. There is no assurance that applicable insurance coverage is adequate to protect us.

Abandonment Obligations

We are responsible for costs associated with the plugging of wells, the removal of facilities and equipment and site restoration on our oil and natural gas properties according to our pro rata ownership. We account for our asset retirement obligations under applicable FASB guidance which requires entities to record the fair value of a liability for retirement obligations of acquired assets. We had a discounted asset retirement obligation of approximately $3.8 million at December 31, 2011. 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.

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Employees

At December 31, 2011 we had approximately 32 full-time employees. Additionally, certain operators, engineers, geologists, geophysicists, landmen, pumpers, draftsmen, title attorneys and others necessary for our operations are retained on a contract or fee basis as their services are required.

Item 1A. Risk Factors

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

Risks Relating to the Bankruptcy Process and the Plan

We have filed for reorganization under Chapter 11 of the Bankruptcy Code and are subject to the risks and uncertainties associated with Chapter 11 proceedings. Based on the Plan confirmed by the Bankruptcy Court, our current shareholders will not receive any consideration upon the conclusion of the Chapter 11 proceedings.

For the duration of our Chapter 11 proceedings, our operations, including our ability to execute our business plan, are subject to the risks and uncertainties associated with bankruptcy. Risks and uncertainties associated with our Chapter 11 proceedings include the following:

• our ability to consummate the transactions contemplated by the Plan;

• the actions and decisions of our creditors and other third parties who have interests in our Chapter 11 proceedings that may be inconsistent with our plans;

• our ability to obtain court approval with respect to motions in the Chapter 11 proceedings from time to time;

• our ability to obtain and maintain normal terms with consultants, vendors and service providers;

• business risks that affect our operations during the pendency of the Chapter 11 proceedings;

• our ability to maintain contracts that are critical to our operations; and

• risks associated with third parties seeking and obtaining court approval to appoint a Chapter 11 trustee or to convert such Bankruptcy to a Chapter 7 proceeding.

These risks and uncertainties could affect our business and operations in various ways. For example, negative events associated with our Chapter 11 proceedings could adversely affect our revenues and our relationships with our customers, vendors and employees, which in turn could adversely affect our operations and financial condition. Also, transactions outside the ordinary course of business are subject to the prior approval of the Bankruptcy Court, which may limit our ability to respond timely to certain events or take advantage of certain opportunities. Because of the risks and uncertainties associated with our Chapter 11 proceedings, the ultimate impact of events that occur during these proceedings will have on our business, financial condition and results of operations cannot be accurately predicted or quantified.

The parties’ obligations to close the Contribution Agreement transaction are subject to a number of conditions and those conditions may not be satisfied. If the transaction does not close, the Debtors will be required to seek an alternative restructuring of their obligations. There can be no assurance that the terms of any such alternative restructuring would be similar to or as favorable to the Debtors’ stakeholders as the terms proposed in the Plan. In addition, pursuant to the terms of the Contribution Agreement, Laramie could choose to breach its obligations under the Contribution Agreement, and would only be liable to the Debtors for a reverse break-up fee of $5,000,000, and would not be required to close the transaction contemplated by the Contribution Agreement.

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The Plan, if consummated, will result in the cancellation of the shares held by our current shareholders. Even if the Plan is not consummated, it is likely that our bankruptcy proceedings will result in the cancellation of those shares without consideration.

In certain instances, a Chapter 11 case may be converted to a case under Chapter 7 of the Bankruptcy Code.

If the Bankruptcy Court finds that it would be in the best interest of creditors and/or the Debtors, the Bankruptcy Court may convert our Chapter 11 bankruptcy case to a case under Chapter 7 of the Bankruptcy Code. In such event, a Chapter 7 trustee would be appointed or elected to liquidate the Debtors’ assets for distribution in accordance with the priorities established by the Bankruptcy Code. The Debtors believe that liquidation under Chapter 7 would result in significantly smaller distributions being made to the Debtors’ creditors than those provided for in the Plan because of (i) the likelihood that the assets would have to be sold or otherwise disposed of in a disorderly fashion over a short period of time rather than reorganizing the Debtors’ businesses as a going concern; (ii) additional administrative expenses involved in the appointment of a Chapter 7 trustee; and (iii) additional expenses and claims, some of which would be entitled to priority, which would be generated during the liquidation and from the rejection of leases and other executory contracts in connection with a cessation of the operations.

The Contribution Agreement may not achieve its intended results and may result in Piceance Energy assuming unanticipated liabilities and properties of lower value than originally contemplated.

We have conducted environmental and title due diligence regarding the assets Laramie will contribute to Piceance Energy pursuant to the Contribution Agreement, but our diligence efforts may not discover all problems that may exist with respect to those assets. Environmental, title and other problems could reduce the value of the properties contributed to Piceance Energy, and, depending on the circumstances, we could have limited or no recourse to Laramie with respect to those problems. Piceance Energy would assume substantially all of the liabilities associated with the acquired Laramie assets, and Piceance Energy would be entitled to indemnification in connection with those liabilities in only limited circumstances and in limited amounts. We cannot assure that such potential remedies will be adequate for any liabilities incurred by Piceance Energy, and such liabilities could be significant. In addition, certain of the assets to be contributed to Piceance Energy are subject to consents to assign and preference rights. If Delta and Laramie cannot obtain all applicable consents or waivers, Piceance Energy may not be able to acquire certain properties as originally contemplated. Also, it is uncertain whether Delta’s and Laramie’s contributed properties and assets can be integrated in an efficient and effective manner.

If the Plan transactions are consummated, Reorganized Delta will be dependent on the results of Piceance Energy.

Following the consummation of the Plan, Reorganized Delta’s principal asset will be its 33.34% ownership interest in Piceance Energy. Reorganized Delta’s operating income will therefore depend heavily on the profitability of Piceance Energy and on the ability of Piceance Energy to make distributions to its owners, which will be severely limited by the terms of the Piceance Energy Credit Facility. See “Management Discussion and Analysis of Financial Condition and Results of Operations” for a description of the Piceance Energy Credit Facility. In addition, Piceance Energy will face similar risk factors to those that face other natural gas exploration and production companies, including us, as described herein. All disclosures in this report regarding operational risks facing us will also be risk factors faced by Piceance Energy. In addition, Laramie will control most decisions affecting Piceance Energy’s operations; Reorganized Delta will have veto rights over decisions of Piceance Energy in only a limited number of areas. Finally, Piceance Energy will pay to Laramie a monthly fee of $650,000 to operate and manage its assets. This will further limit Piceance Energy’s ability to make distributions to us.

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

If the Plan transactions are not consummated, we will not have sufficient liquidity to continue operations unless the maturity of the DIP Credit Facility is extended. See “Management Discussion and Analysis of Financial Condition and Results of Operations” for a description of the DIP Credit Facility. If the Plan transactions are consummated, our liquidity will be constrained by the restrictions on Piceance Energy’s ability to distribute cash to us under the Piceance Energy Credit Facility, by our need to satisfy our obligations under the Exit Credit Facility, and by potential capital contributions required to be made by us to Piceance Energy. Regardless of whether the Plan is consummated, our liquidity will be further constrained by the currently low level of natural gas prices, which reduces our cash flow from operations. A lack of liquidity may have a material adverse effect on our operations and financial condition, and may make it impossible for us to satisfy our existing or future obligations.

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

We have, and will continue to have (whether or not the Plan is consummated), a significant amount of indebtedness. 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;

• borrowings may be at variable rates of interest, exposing us to the risk of increased interest rates;

• it may limit our ability to adjust to changing market conditions and place us at a competitive disadvantage compared to our competitors that have less debt;

• we are vulnerable in the present downturn in general economic conditions and in our business, and we will likely be unable to carry out capital spending and exploration activities in excess of those that are currently planned; and

• we have recently been, and may from time to time be, out of compliance with covenants under our debt agreements, which may allow the lenders to accelerate the related debt and foreclose on assets securing that debt.

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

If the Plan transactions are consummated, our largest shareholders will control the composition of our board of directors, and trading in our shares will be subject to limitations set forth in our amended Certificate of Incorporation.

If the Plan transactions are consummated, our Certificate of Incorporation and Bylaws will be amended, our largest stockholders will enter into a Stockholder’s agreement and the collective effect of these changes will be to allow certain holders who currently hold Notes to appoint all or substantially all of the members of our board of directors for an indefinite period. Accordingly, other shareholders may be unable to influence the outcome of director elections. In addition, the amended Certificate of Incorporation will impose certain restrictions on trading in our shares. These trading restrictions are designed to preserve the potential benefit to us of certain tax attributes, but could also have the effect of limiting liquidity in the trading of our shares. Elimination of the trading restrictions or failure to comply with or properly implement such restrictions could cause us to lose our tax attributes which may increase our tax liability, possibly significantly.

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Risks Related To Our Business And Industry

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

Our revenues, operating results, profitability and future rate of growth depend primarily upon the prices we receive for the natural gas and oil we sell. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital.

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

• worldwide and domestic supplies of natural gas and oil;

• weather conditions;

• the level of consumer demand;

• the price and availability of alternative fuels;

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

• the price and level of foreign imports;

• domestic and foreign governmental regulations and taxes;

• the nature and extent of regulation relating to carbon and other greenhouse gas emissions;

• the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

• political instability or armed conflict in oil-producing regions; and

• overall domestic and global economic conditions.

These factors and the volatility of the energy markets make it extremely difficult to predict future natural gas and oil price movements. Declines in natural gas and oil prices not only reduce revenue, but also reduce the amount of natural gas and oil that we can produce economically and, as a result, have had, and could in the future have, a material adverse effect on our financial condition, results of operations, cash flows and reserves. Further, natural gas and oil prices do not move in tandem. Because approximately 79% of our reserves at December 31, 2011 were natural gas reserves, we are more affected by movements in natural gas prices. Following the completion of the transaction contemplated by the Contribution Agreement, Piceance Energy’s reserves (based on our and Laramie’s estimated reserves as of April 30, 2012) will be 72% natural gas. Natural gas prices have fallen to historic lows in recent periods.

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

The continued instability in the global financial system and related limitation on availability of credit may continue to have an impact on our business and our financial condition, and we may continue to face challenges if conditions in the financial markets do not improve. Our ability to access the capital markets has been restricted as a result of the economic downturn and related financial market conditions and may be restricted in the future when we would like, or need, to raise capital. The difficult financial environment may also limit the number of prospects for potential joint venture, asset monetization or other capital raising transactions that we may pursue in the future or reduce the values we are able to realize in those transactions, making these transactions uneconomic or difficult to consummate. The economic situation could also adversely affect the collectability of our trade receivables and cause our commodity hedging arrangements, if any, to be ineffective if our counterparties are unable to perform their obligations. Additionally, the current economic situation could lead to reduced demand for natural gas and oil, or lower prices for natural gas and oil, or both, which would have a negative impact on our revenues.

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Information concerning our reserves is uncertain.

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

The estimated quantities of proved reserves and the discounted present value of future net cash flows attributable to those reserves as of December 31, 2011, 2010 and 2009 included in our periodic reports filed with the SEC were prepared by our independent reserve engineers in accordance with the rules of the SEC, and are not intended to represent the fair market value of such reserves. As required by the SEC, the estimated discounted present value of future net cash flows from proved reserves is generally based on prices and costs as required by the SEC on the date of the estimate, while actual future prices and costs may be materially higher or lower. In addition, the 10% discount factor the SEC requires to be used to calculate discounted future net revenues for reporting purposes is not necessarily the most appropriate discount factor based on the cost of capital in effect from time to time and risks associated with our business and the oil and gas industry in general.

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

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

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

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

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

• unexpected drilling conditions;

• title problems;

• pressure or irregularities in formations;

• equipment failures or accidents;

• adverse weather conditions; and

• compliance with environmental and other governmental requirements.

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

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

We account for our crude oil and natural gas exploration and development activities utilizing the successful efforts method of accounting. Under this method, costs of productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized. Oil and gas lease acquisition costs are also capitalized. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities. If the carrying amount of our oil and gas properties exceeds the estimated undiscounted future net cash flows, we will adjust the carrying amount of the oil and gas properties to their estimated fair value.

We review our oil and gas properties for impairment quarterly or whenever events and circumstances indicate that the carrying value may not be recoverable. Once incurred, a writedown of oil and gas properties is not reversible at a later date even if gas or oil prices increase. Given the complexities associated with oil and gas reserve estimates and the history of price volatility in the oil and gas markets, events may arise that would require us to record an impairment of the recorded carrying values associated with our oil and gas properties.

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

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

• availability of capital;

• unexpected drilling conditions;

• pressure or irregularities in formations;

• equipment failures or accidents;

• adverse changes in prices;

• adverse weather conditions;

• title problems;

• shortages in experienced labor; and

• increases in the cost, or shortages or delays in the delivery, of equipment.

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We may drill wells that are unproductive or, although productive, do not produce oil and/or natural gas in economic quantities. Acquisition and completion decisions generally are based on subjective judgments and assumptions that are speculative. It is impossible to predict with certainty the production potential of a particular property or well. Furthermore, a successful completion of a well does not ensure a profitable return on the investment. A variety of geological, operational, or market-related factors, including, but not limited to, unusual or unexpected geological formations, pressures, equipment failures or accidents, fires, explosions, blowouts, cratering, pollution and other environmental risks, shortages or delays in the availability of drilling rigs and the delivery of equipment, loss of circulation of drilling fluids or other conditions may substantially delay or prevent completion of any well or otherwise prevent a property or well from being profitable. A productive well may become uneconomic in the event water or other deleterious substances are encountered which impair or prevent the production of oil and/or natural gas from the well, or in the event of lower than expected commodity prices. In addition, production from any well may be unmarketable if it is contaminated with water or other deleterious substances.

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

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

Prices may be affected by local and regional factors.

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

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

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

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

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

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

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

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

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

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

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

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

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

The environmental laws and regulations to which we are subject may, among other things:

• 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.

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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 whether the operations at the time of the release were standard industry practice.

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

Congress has considered legislation to amend the federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and natural gas industry in the hydraulic fracturing process, and other legislation regulating hydraulic fracturing has been considered, and in some cases adopted, at various levels of government. Hydraulic fracturing is an important and commonly used process in the completion of unconventional natural gas wells in shale formations, as well as tight conventional formations, including many of those that we complete and produce. This process involves the injection of water, sand and chemicals under pressure into rock formations to stimulate natural gas production. Sponsors of these bills have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies and/or that hydraulic fracturing could pose a variety of other risks. Any additional level of regulation could lead to operational delays or increased operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.

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

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

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

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

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

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

Changes contained in President Obama’s 2013 budget proposal include the elimination of certain key U.S. federal income tax preferences currently available to oil and gas exploration and production companies. Such changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; (iii) the elimination of the deduction for certain U.S. production activities; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear, however, whether any such changes will be enacted or how soon such changes could be effective.

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

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

Future changes in the laws and regulations to which we are subject may make it more difficult or expensive to conduct our operations and may have other adverse effects on us. For example, the EPA has issued a notice of finding and determination that emissions of carbon dioxide, methane and other greenhouse gas (“GHG”) present an endangerment to human health and the environment, which allows EPA to begin regulating emissions of GHGs under existing provisions of the federal Clean Air Act. EPA has begun to implement GHG-related reporting and permitting rules. Similarly, the U.S. Congress has considered and may in the future consider “cap and trade” legislation that would establish an economy-wide cap on emissions of GHGs in the United States and would require most sources of GHG emissions to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs. Any laws or regulations that may be adopted to restrict or reduce emissions of GHGs would likely require us to incur increased operating costs and could have an adverse effect on demand for our production.

We could be adversely affected by regulatory changes resulting from the Dodd-Frank Wall Street Reform and Consumer Protection Act.

The Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Reform Act, among other things, imposes restrictions on the use and trading of certain derivatives, including energy derivatives. The nature and scope of those restrictions will be determined in significant part through implementing regulations adopted by the SEC, the Commodities Futures Trading Commission and other regulators. If, as a result of the Reform Act or its implementing regulations, capital or margin requirements or other limitations relating to commodity derivative activities are imposed, this could have an adverse effect on our ability to secure hedges. In addition, requirements and limitations imposed on our derivative counterparties could increase the costs of hedges.

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Item 1B. Unresolved Staff Comments.

None.

Item 2. Properties.

Properties

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

Vega Area

Since 2005 we have dedicated significant financial capital and human resources to the development of our Vega Unit and surrounding leasehold in Mesa County, Colorado, which in combination is referred to as the Vega Area. The Vega Area is comprised of the Vega Unit, the Buzzard Creek Unit, the North Vega leasehold, and the North Buzzard Creek leasehold. Our working interests in the Vega Area vary between 95-100%. In 2008, we acquired an additional 17,300 net acres, which increased our position to approximately 22,375 net acres. At December 31, 2011, proved reserves in the Vega Area totaled 89 Bcfe. Production in the Vega Area averaged 27.9 Mmcfe/d in 2011.

South Piceance

We have a 5% working interest in 163 producing wells in the southern region of the Piceance Basin. We also have a 5% working interest in additional wells drilled pursuant to the February 2008 agreement with Encana, but will not incur any capital expenditures on these wells in accordance with the carry provisions of the agreement. Most of our interests in the South Piceance assets will be contributed to Piceance Energy pursuant to the Contribution Agreement; however we will retain a direct economic interest in certain wells in the South Piceance area.

Point Arguello and Rocky Point Units

We own the equivalent of a 6.07% gross working interest in the Point Arguello Unit and related facilities located Offshore California in the Santa Barbara Channel. Within this unit there are three producing platforms (Hidalgo, Harvest and Hermosa). This interest will not be contributed to Piceance Energy. We also own a 6.25% working interest in the development of the east half of OCS Block 451 in the Rocky Point Unit.

Internal Controls Over Reserve Estimates, Technical Qualifications and Technologies Used

Our policies regarding internal controls over reserve estimates requires reserves to be in compliance with the SEC definitions and guidance and for reserves to be prepared by an independent third party reserve engineering firm under the supervision of our Corporate Engineering Manager. Delta’s Corporate Engineering Manager has a Bachelor of Science degree in Petroleum Engineering with over 19 years of industry experience, and with positions of increasing responsibility within Delta’s corporate reservoir engineering department. The Corporate Engineering Manager reports directly to our President and Chief Executive Officer. Qualified petroleum engineers in our Denver office provide to our third party reserves engineers reserves estimate preparation material such as property interests, production, current costs of operation and development, current prices for production, geoscience and engineering data, and other information. This information is reviewed by knowledgeable members of our reserve engineering department to ensure accuracy and completeness of the data prior to submission to our third party reserve engineering firm. To prepare our reserve estimates, we retained Ralph E. Davis Associates, Inc. in 2009 and 2010, and Netherland, Sewell & Associates, Inc. (“NSAI”) in 2011. The individual at RDAI who was responsible for overseeing the preparation of our reserve estimates as of December 31, 2010 is a Licensed Professional Engineer by the State of Texas, and graduated in 1968 with a Bachelor of Science Degree in Chemical Engineering with a Petroleum Engineering option. The individual has in excess of forty years’ experience in the Petroleum Industry including the preparation of reserve evaluation studies and reserve audits for public and private companies for the purpose of reserve certification filings in foreign countries, domestic regulatory filings, financial disclosures and corporate strategic planning. The individuals at NSAI who are responsible for overseeing the preparation of our reserve estimates as of December 31, 2011 include: a Licensed Professional Engineer by the State of Texas, who graduated in 1973 with a Bachelor of Science Degree in Petroleum Engineering. This individual has in excess of thirty years’ experience in the Petroleum Industry including the preparation of reserve evaluation studies. The other individual at NSAI responsible for overseeing our reserve estimates is a Licensed Professional Geologist in the State of Texas who graduated in 1976 with a Bachelor of Science Degree in Geology. This individual also has in excess of thirty years’ experience in the Petroleum Industry including the preparation of reserve evaluation studies. A letter which identifies the professional qualifications of the individual at NSAI who was responsible for overseeing the preparation of our reserve estimates as of December 31, 2011 has been filed as a part of Exhibit 99.1 to this report.

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A variety of methodologies were used to determine our proved reserve estimates. The principal methodologies employed are decline curve analysis, analog type curve analysis, volumetrics, material balance, pressure transient analysis, petrophysics/log analysis and analogy. Some combination of these methods is used to determine reserve estimates in substantially all of our fields.

Reserves Reported to Other Agencies

We did not file any reports during the year ended December 31, 2011 with any federal authority or agency other than the SEC with respect to our estimates of oil and natural gas reserves.

Proved Undeveloped Reserves

Our proved undeveloped reserves declined from 10.5 Bcfe at December 31, 2010 to zero at December 31, 2011 due to our limited capital availability and low gas prices. During the year eleven Piceance wells that had been proved undeveloped reserves at December 31, 2010 were moved to proved developed.

Impairment of Long Lived Assets

We periodically compare our historical cost basis of each proved developed and undeveloped oil and gas property to its expected future undiscounted net cash flow from each property (on a field by field basis). Estimates of expected future cash flows represent management’s best estimate based on reasonable and supportable assumptions and projections. If the expected future net cash flows exceed the carrying value of the property, no impairment is recognized. If the carrying value of the property exceeds the expected future cash flows, an impairment exists and is measured by the excess of the carrying value over the estimated fair value of the asset. As a result of this assessment, during the year ended December 31, 2011, we recorded impairment provisions related to continuing operations attributable to our proved and unproved properties and other items of $420 million which primarily included impairments of $399.4 million related to Vega area proved and unproved properties.

At December 31, 2011 our oil and gas assets were classified as held for use and no impairment charges resulted from the analysis performed at December 31, 2011 as the estimated undiscounted net cash flows exceeded carrying amounts for all properties. Subsequent to the end of the reporting period, in August 2012, the Bankruptcy Court approved a plan of sale of substantially all of our assets and accordingly these assets will be classified as held for sale in reporting periods subsequent to June 30, 2012 and will be subject to a material write-down to fair value at that time. Our assets may be further adjusted in the future due to the outcome of the Chapter 11 Cases or the application of “fresh start” accounting upon the Company’s emergence from Chapter 11.

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Production Volumes, Unit Prices and Costs

The following table sets forth certain information regarding our volumes of production sold and average prices received associated with our production and sales of natural gas and crude oil for the years ended December 31, 2011, 2010, and 2009.

	Years Ended December 31,
	2011			2010			2009
Production volume –
Total production (MMcfe)		11,682			16,763			22,158
Production from continuing operations:
Oil (MBbls)		140			161			175
Natural Gas (MMcf)		9,948			10,265			11,652
Total (MMcfe)		10,788			11,231			12,702
Net average daily production-continuing operations:
Oil (Bbl)		385			442			480
Natural Gas (Mcf)		27,254			28,127			31,924
Average sales price:
Oil (per barrel)	$	80.16		$	60.75		$	43.09
Natural Gas (per Mcf)	$	5.29		$	5.06		$	3.00
Hedge gain (loss) (per Mcfe)	$	(0.04	)	$	(0.52	)	$	(0.09	)
Lease operating costs — (per Mcfe)	$	1.27		$	1.57		$	1.40

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Productive Wells and Acreage

The table below shows, as of December 31, 2011, the approximate number of gross and net producing oil and gas wells by state and their related developed acres owned by us. Calculations include 100% of wells and acreage owned by us and our subsidiaries. Developed acreage consists of acres spaced or assignable to productive wells.

	Oil (1)				Gas (1)				Developed Acres
Location	Gross (2)		Net (3)		Gross (2)		Net (3)		Gross (2)		Net (3)
California (offshore)		34		2.1		—		—		2,422		269
Colorado		—		—		343		196.0		1,920		1,866
New Mexico		—		—		1		0.1		240		13
Total		34		2.1		344		196.1		4,582		2.148

(1) Some of the wells classified as “oil” wells also produce minor amounts of natural gas. Likewise, some of the wells classified as “gas” wells also produce minor amounts of oil.

(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.

Undeveloped Acreage

At December 31, 2011, we held undeveloped acreage by state as set forth below:

	Undeveloped Acres (1)(2)
Location	Gross		Net
Colorado		36,701		30,384

(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) There are no material near-term lease expirations for which the carrying value at December 31, 2011 has not already been impaired in consideration of these expirations or capital budgeted to convert acreage to HBP.

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Drilling Activity

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

	Years Ended December 31,
	2011				2010				2009
	Gross		Net		Gross		Net		Gross		Net
Exploratory Wells (2):
Productive:
Oil		—		—		—		—		—		—
Gas		1		1		—		—		—		—
Nonproductive		1		1		—		—		1		0.50
Total		2		2		—		—		1		0.50
Development Wells (1):
Productive:
Oil		—		—		1		1.00		—		—
Gas		41		1.96		66		16.10		113		32.89
Nonproductive		—		—		1		0.25		—		—
Total		41		1.96		68		17.35		113		32.89
Total Wells (1):
Productive:
Oil		—				1		1.00		—		—
Gas		42		2.96		66		16.10		113		32.89
Nonproductive		1		1.00		1		0.25		1		0.50
Total Wells		43		3.96		68		17.35		114		33.39

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

(2) Does not include exploratory wells in progress.

Present Drilling Activity

At December 31, 2011, we had two development wells in the Vega area which had been drilled but not yet completed. Additionally, we drilled one exploratory well which was waiting to be completed and we started work on another well. In July 2012, we entered into an agreement with Laramie Energy to complete the first exploratory well. That work has been started, but a completion date is not known at this time. Pad location work has been started on the second exploratory well prior to drilling. It’s unknown when drilling activity will begin on that well.

Delivery Commitments

We had no material delivery commitments as of December 31, 2011 or August 28, 2012.

Item 3. Legal Proceedings

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

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

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M.J. Farms, LTD vs. Exxon Mobile Corp., et al (Docket No. 24,055-B Div A) filed in the 7th Judicial District Court in Catahoula Parish, Louisiana on April 27, 2006 is an action against the named defendants for environmental damages. The action was settled against the main defendant and as part of the settlement, the main defendants acquired the rights to sue all of the other companies that formerly owned interests in the affected properties. There are over 50 companies named as third party defendants in the action, two of which are Castle Exploration Company, Inc., a subsidiary of Borrower’s wholly-owned subsidiary, DPCA LLC, and the Borrower. A Motion for Relief of Stay, has been filed in the United States Bankruptcy Court by Missiana, LLC, Benedict Corporation and L.W. Wickes requesting the Bankruptcy Court to lift the stay so that the litigation can proceed in the Louisiana Court. Should any liability on behalf of the Delta Petroleum be determined, any claims of Missiana, LLC, Benedict Corporation and L.W. Wickes, would be enforced through the Bankruptcy Court in accordance with Delta Petroleum’s confirmed plan. It is currently unknown if the Borrower has any liability and to the extent the Borrower is liable, what costs the Borrower may be obligated to contribute towards a settlement.

Item 4. Mine Safety Disclosures

Not applicable.

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 “DPTRQ” on the OTC Bulletin Board. The Company’s common stock was delisted from the NASDAQ Capital Market on December 28, 2011 following its Chapter 11 filing. On July 12, 2011, the shareholders of the Company approved a one-for-ten reverse split of the common stock of the Company which became effective on July 13, 2011. The following quotations reflect inter-dealer high and low sales prices, without retail mark-up, mark-down or commission (price per share of common shares prior to the 1:10 reverse stock split have been adjusted to reflect this stock split on a retroactive basis) and may not represent actual transactions.

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Quarter Ended	High		Low
March 31, 2010	$	17.70	$	11.40
June 30, 2010		17.10		8.60
September 30, 2010		8.70		6.90
December 31, 2010		8.60		7.20
March 31, 2011	$	11.70	$	7.20
June 30, 2011		9.20		4.80
September 30, 2011		4.57		0.42
December 31, 2011		2.41		0.10

On August 17, 2012, the closing price of our common stock was $0.05 on the OTC Bulletin Board. 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.

Recent Sales of Unregistered Securities

During the year ended December 31, 2011, 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.

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Issuer Purchases of Equity Securities

We did not purchase any of our own common stock during the year ended December 31, 2011.

Item 6. Selected Financial Data

The following selected financial information should be read in conjunction with our financial statements and the accompanying notes. During the second quarter of 2011, the Company closed the 2011 Wapiti Transaction, selling the remaining portion of its interests in non-core assets primarily located in Texas and Wyoming for gross cash proceeds of approximately $43.2 million. On October 31, 2011, Delta sold its stock, representing a 49.8% ownership interest, in DHS Drilling to DHS Drilling’s lender, LCPI, for $500,000. In accordance with accounting standards, the results of operations relating to these properties have been reflected as discontinued operations for all periods presented.

	Years Ended December 31,
	2011			2010			2009			2008			2007
	(In thousands, except per share amounts)
Total Revenues	$	63,880		$	60,996		$	116,316		$	88,498		$	24,475
Loss from continuing operations	$	(483,202	)	$	(104,674	)	$	(117,085	)	$	(31,517	)	$	(56,240	)
Net loss attributable to Delta common stockholders	$	(470,111	)	$	(182,332	)	$	(328,783	)	$	(456,064	)	$	(149,807	)
Loss attributable to Delta common stockholders Per Common Share
Basic	$	(16.30	)	$	(6.63	)	$	(15.58	)	$	(47.74	)	$	(24.44	)
Diluted	$	(16.30	)	$	(6.63	)	$	(15.58	)	$	(47.74	)	$	(24.44	)
Total Assets	$	387,897		$	1,024,112		$	1,457,485		$	1,894,963		$	1,110,054
Total Long-Term debt, including current portion	$	3,507		$	292,535		$	460,923		$	637,473		$	393,468
Total Delta Stockholders’ Equity	$	50,225		$	514,447		$	688,582		$	762,390		$	532,855
Total Non-Controlling Interest	$	—			(2,852	)	$	8,538		$	29,104		$	27,296
Total Equity	$	50,225		$	511,595		$	697,120		$	791,494		$	560,151

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

Overview

We are a Denver, Colorado based independent oil and gas company engaged primarily in the exploration for, and the acquisition, development, production, and sale of, natural gas and crude oil. Our core area of operations is the Rocky Mountain Region, which comprises virtually all of our proved reserves, production and long-term growth prospects. At December 31, 2011, we had estimated proved developed reserves that totaled 90 Bcf, with a standardized measure of $129.7 million. As of December 31, 2011, our proved reserves were comprised of approximately 87 Bcf of natural gas and natural gas liquids and 0.49 Mmbbls of crude oil. For the year ended December 31, 2011, we reported total net production of 29.6 Mmcfe per day related to continuing operations. See “Business—Bankruptcy Matters” for a description of our ongoing bankruptcy process.

Liquidity and Capital Resources and Requirements

Our sources of liquidity and capital resources historically have been cash provided through the issuance of debt and equity securities when market conditions permit, operating activities, sales of oil and gas properties, and borrowings under our credit facilities. Since the bankruptcy filing, our principal sources of liquidity have been borrowings under the DIP Credit Facility described below and cash flows from operating activities. The primary uses of our capital resources have been in the operation of oil and gas properties, professional fees, and bankruptcy expenses.

MBL Credit Agreement and DIP Credit Facility

Prior to the entry into the DIP Credit Facility as described below, we maintained a credit agreement with Macquarie Bank Limited (“MBL”) as administrative agent and issuing lender (the “MBL Credit Agreement”). The MBL Credit Agreement provided for a revolving loan and a term loan each with a maturity date of January 31, 2012. The revolving loan bore interest at prime plus 6% per annum for prime rate advances and LIBOR plus 7% per annum for LIBOR advances. Advances under the term loan bore interest at prime plus 8% per annum for prime rate advances and LIBOR plus 9% for LIBOR advances.

On December 21, 2011, we entered into a senior secured debtor-in-possession credit facility (the “DIP Credit Facility”) in December 2011 in connection with the bankruptcy filing. Up to $57.5 million may be borrowed under the DIP Credit Facility, of which approximately $45 million was initially drawn by the Company to repay all amounts outstanding under the previous Credit Agreement, which was then terminated. The DIP credit facility was amended in March 2012 to increase the maximum borrowing capacity by $1.4 million to $58.9 million. All of the loans under the DIP Credit Facility are term loans. The interest rate under the DIP Credit Facility is 13% plus 6% per annum in payment-in-kind interest. The initial maturity date of the DIP Credit Facility was June 30, 2012. The Company has subsequently entered into a series of forbearance agreements extending maturity date to August 30, 2012 As of December 31, 2011 $45.0 million in borrowings and $74,000 in accrued PIK interest were outstanding under the facility.

The Company is the borrower under the DIP Credit Facility and certain of its wholly-owned subsidiaries are guarantors of the Company’s obligations thereunder. Borrowings under the DIP Credit Facility are secured by substantially all of the assets of the Company and the guarantors. The DIP Credit Facility includes certain covenants relating to the bankruptcy process and other operational and financial covenants, including covenants that limit the Company’s ability to (or to permit any subsidiaries to) (i) merge with other companies; (ii) create liens on its property; (iii) incur additional indebtedness; (iv) enter into transactions with affiliates, except on an arms-length basis; (v) enter into sale leaseback transactions; (vi) pay dividends or make certain other restricted payments; (vii) make certain investments; or (viii) sell its assets.

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Notes

The bankruptcy filing constituted an event of default under the Company’s 7% Series A Senior Notes due 2015 (the “7% Notes”) and the Company’s 3 3/4% Convertible Senior Note due 2037 (the “3 3/4% Notes” and, together with the 7% Notes, the “Notes”). Under the indentures governing the Notes, all principal, interest and other amounts due relating to the Notes became immediately due and payable. The ability of the holders of the Notes to seek remedies to enforce their rights under the indentures was automatically stayed as a result of the filing of the bankruptcy filings, and the creditors’ rights of enforcement are subject to the applicable provisions of the Bankruptcy Code.

Contribution Agreement and Related Credit Agreements

As described in “Business – Bankruptcy Matters – Contribution Agreement,” we entered into the Contribution Agreement in June 2012 in connection with the bankruptcy process. Following the closing of the transaction contemplated by the Contribution Agreement, our principal source of liquidity will be borrowings under the Exit Credit Facility. The Exit Credit Facility is a four year delayed draw term loan that allows for five separate draws of up to $30 million. The Exit Credit Facility will charge 9.75% annual interest payable quarterly in either cash or paid-in-kind at the Company’s option. The loan will be secured by (i) a perfected, first-priority security interest in all of the Company’s assets other than its equity interest in Piceance Energy, and (ii) a perfected, second-lien security interest in all of the Company’s equity interest in Piceance Energy. The loan is also subject to certain prepayment penalties. As consideration for granting the loan, we have also issued warrants to the Exit Credit Facility lenders in amounts ranging from 5.1% to 6.1% of total equity outstanding depending upon the total amounts drawn under the facility. The Exit Credit Facility lenders will be parties who currently hold notes and will be major stockholders following consummation of the Plan.

Our principal asset following the closing of the Contribution Agreement transaction will be a minority interest in Piceance Energy. Piceance Energy’s primary sources of liquidity will be cash from operations and borrowings under its credit facility, which we refer to as the “Piceance Energy Credit Facility.” We also expect to have modest cash flows from certain assets not being contributed to Piceance Energy pursuant to the Contribution Agreement.

Under the terms of the Piceance Energy Credit Facility, Piceance Energy will generally be prohibited from distributing cash to its owners, including Par Petroleum Corporation. The Piceance Energy Credit Facility is a $400 million secured revolving credit facility secured by a lien on Piceance Energy’s oil and gas properties and related assets and our interests in Piceance Energy. Availability will be limited to the lesser of $400 million and the borrowing base in effect from time to time (anticipated to be $140 million as of August 31, 2012). The Piceance Energy Credit Facility will mature on the fourth anniversary of the effective date. Amounts borrowed under the facility will bear interest at rates ranging from Libor plus 1.75% to Libor plus 2.75% per annum for Eurodollar loans and the prime rate plus 0.75% to prime rate plus 1.75% per annum for Base Rate loans, depending upon the ratio of outstanding credit to the borrowing base. The agreement governing the facility contains customary operational and financial covenants, including a current ratio covenant, a total debt to consolidated EBITDAX covenant and a borrowing base covenant. Upon the closing of the Contribution Agreement transaction, Piceance Energy will borrow $100 million under the Piceance Energy Credit Facility and distribute $75 million of that amount to us. We will use that amount, plus cash on hand and borrowings under the Exit Credit Facility, to repay all amounts outstanding under the DIP Credit Facility, priority claims, administrative claims and fund various recovery trusts.

As contemplated by the Contribution Agreement, Reorganized Delta will enter into a Limited Liability Company Agreement with Laramie at the closing. Pursuant to that agreement, among other things, Reorganized Delta may have to contribute significant amounts to Piceance Energy to fund its operations or its interest would be diluted potentially affecting the availability of our net operating leases.

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The foregoing descriptions of the Exit Credit Facility and the Piceance Energy Credit Facilities are qualified in their entirety.

Cash Flows

	Years Ended December 31,
	2011			2010			2009
	(in thousands)
Cash provided by (used in) operating activities	$	990		$	(33,001	)	$	81,144
Cash provided by (used in) investing activities	$	87,649		$	197,838		$	(47,367	)
Cash provided by (used in) financing activities	$	(89,967	)	$	(212,565	)	$	(37,334	)

Net cash provided by operating activities was $990,000 in 2011 compared with $33 million used in operating activities in 2010 and $81 million provided in 2009. Cash flows from operating activities in 2011 as compared to 2010 were primarily impacted by less of a decrease in operating liabilities. Cash flows from operating activities in 2010 as compared to 2009 were primarily due to a significant decline in natural gas prices and changes in current liabilities.

Net cash provided by investing activities was $88 million in 2011 compared with net cash provided by investing activities of $198 million in 2010 and net cash used in investing activities of $47 million in 2009. The primary investing activities in 2011 and 2010 were proceeds from the sale of properties, and the primary activities in 2009 were additions to property and equipment. Cash provided by restricted deposits was used to repay the associated installment note from property acquisitions

Net cash used in financing activities was $90 million in 2011 compared to net cash used in financing activities of $213 million in 2010 and net cash used in financing activities of $37 million in 2009. The primary financing activities in 2011 were a $100 million installment payment on property acquisitions, the primary activities in 2010 were reduction of debt and an installment payment on property acquisitions and the primary activities in 2009 were proceeds from stock and repayment of borrowings.

32

Results of Operations

The following discussion and analysis relates to items that have affected our results of operations for the years ended December 31, 2011, 2010 and 2009. The following table sets forth (in thousands), for the periods presented, selected historical statements of operations data. The information contained in the table below should be read in conjunction with our consolidated financial statements and accompanying notes included in this Annual Report on Form 10-K.

	Years Ended December 31,
	2011			2010			2009
	(In thousands, except per share amounts)
Revenue:
Oil and gas sales	$	63,880		$	61,791		$	42,516
Gain on offshore litigation settlement, net of loss on property sales		—			(795	)		73,800
Total revenue		63,880			60,996			116,316
Operating expenses:
Lease operating expense		13,755			17,656			17,742
Transportation expense		13,867			14,862			9,324
Production taxes		1,535			2,197			1,556
Exploration expense		338			1,337			2,604
Dry hole costs and impairments		420,402			37,362			16,606
Depreciation, depletion, amortization and accretion – oil and gas		39,088			46,881			57,102
General and administrative expense		28,124			35,394			37,284
Executive severance expense, net		—			(674	)		3,739
Total operating expenses		517,109			155,015			145,957
Operating loss		(453,229	)		(94,019	)		(29,641	)
Other income and (expense):
Interest expense and financing costs, net		(32,324	)		(30,168	)		(43,599	)
Other income (expense)		(1,947	)		174			(70	)
Realized loss on derivative instruments, net		(375	)		(5,835	)		(1,115	)
Unrealized gain (loss) on derivative instruments, net		—			23,979			(26,972	)
Income (loss) from unconsolidated affiliates		344			1,738			(15,473	)
Total other expense		(34,302	)		(10,112	)		(87,229	)
Loss from continuing operations before income taxes and discontinued operations		(487,531	)		(104,131	)		(116,870	)
Income tax expense (benefit)		(4,329	)		543			215
Loss before reorganization items and discontinued operations		(483,202	)		(104,674	)		(117,085	)
Reorganizational items Professional fees and administrative costs		932			—			—
Discontinued operations:
Gain from results of operations and sale of discontinued operations, net of tax		14,094			(89,340	)		(232,599	)
Net loss		(470,040	)		(194,014	)		(349,684	)
Less net (gain) loss attributable to non-controlling interest included in discontinued operations		(71	)		11,682			20,901
Net loss attributable to Delta common stockholders	$	(470,111	)	$	(182,332	)	$	(328,783	)

33

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

Net Income (Loss) Attributable to Delta Common Stockholders. Net loss attributable to Delta common stockholders was $470.1 million, or $16.30 per diluted common share, for the year ended December 31, 2011, compared to a net loss of $182.3 million or $6.63 per diluted common share, for the year ended December 31, 2010. Loss from continuing operations increased from a loss of $104.7 million for the year ended December 31, 2010 to a loss of $483.2 million for the year ended December 31, 2011. The increase was primarily due to $420.4 million in dry hole costs and impairments recognized during 2011. Explanations of significant items affecting comparability between periods are discussed by the financial statement captions below.

Oil and Gas Sales. During the year ended December 31, 2011, oil and gas sales from continuing operations were $63.9 million, as compared to $61.8 million for 2010. During the year ended December 31, 2011, production from continuing operations decreased by 4% and the average natural gas and oil price increased 4% and 32%, respectively. The average gas price received during the year ended December 31, 2011 was $5.29 per Mcf compared to $5.06 per Mcf for 2010, and the average oil price received during the year ended December 31, 2011 was $80.16 per Bbl compared to $60.75 per Bbl for 2010. The production decrease was primarily related to natural production declines and the lack of capital to enhance existing production and undertake new drilling.

Production and Cost Information. Production volumes, average prices received and cost per equivalent Mcf for the years ended December 31, 2011 and 2010 are as follows:

	Years Ended December 31,
	2011		2010
Production – Continuing Operations:
Oil (MBbl)		140		161
Gas (MMcf)		9,948		10,265
Total (MMcfe)		10,788		11,231
Average Price – Continuing Operations:
Oil (per barrel)	$	80.16	$	60.75
Gas (per Mcf)	$	5.29	$	5.06
Costs per Mcfe – Continuing Operations:
Lease operating expense	$	1.27	$	1.57
Production taxes	$	0.14	$	0.20
Transportation costs	$	1.29	$	1.32
Depletion expense	$	3.37	$	3.90

Lease Operating Expense. Lease operating expenses for the year ended December 31, 2011 were $13.8 million compared to $17.7 million for 2010. The change resulted primarily due to lower water handling costs in the Vega Area as a result of the resumption of development activities and improved water handling facilities.

Production Taxes. Production taxes for the year ended December 31, 2011 were $1.5 million, or 30% lower than prior year costs of $2.2 million. Production taxes as a percentage of oil and gas sales were 2.4% and 3.6% for the years ended December 31, 2011 and 2010, respectively. The decrease in the 2011 percentage was primarily due to a decrease in the effective Colorado severance tax rate and county ad valorem tax rates.

Transportation Expense. Transportation expense for the year ended December 31, 2011 was $13.9 million compared to $14.9 million for 2010. Transportation expense per Mcfe for the years ended December 31, 2011 and 2010 are comparable.

34

Dry Hole Costs and Impairments. We incurred impairment provisions of approximately $420.4 million for the year ended December 31, 2011 compared to $37.4 million for the year ended December 31, 2010. During 2011 we evaluated the fair value of our properties based on market indicators in conjunction with the progression of the strategic alternatives evaluation process. As a result, we recorded an impairment during the quarter ended September 30, 2011 of $157.5 million to our Vega unproved leasehold, $239.8 million to our Vega area proved properties, $20.5 million to our Vega area gathering system and facilities, and $2.1 million to our Vega area surface acreage.

Depreciation, Depletion and Amortization – Oil and Gas. Depreciation, depletion and amortization expense decreased 17% to $39.1 million for the year ended December 31, 2011 compared to $46.9 million for 2010. The change resulted primarily from higher reserves as a result of our recent drilling and completion activity in the Vega Area.

General and Administrative Expense. General and administrative expense decreased to $28.1 million for the year ended December 31, 2011 compared to $35.4 million for 2010. The decrease in general and administrative expenses is attributed to a decrease in non-cash stock compensation expense, lower corporate consulting fees and to reduced staffing as a result of attrition and a reduction in force during 2010 resulting in lower cash compensation expense.

Interest Expense and Financing Costs, Net. Interest expense and financing costs increased 5% to $32.3 million for the year ended December 31, 2011 compared to $30.2 million for 2010. The change resulted primarily from recognizing $2.1 million of pre-petition deferred financing costs when we filed for bankruptcy offset by $340,000 of interest income.

Realized Gain on Derivative Instruments, Net. During the year ended December 31, 2011, we recognized $3.4 million of realized losses associated with settlements on derivative contracts. All derivative contracts were settled prior to the end of 2011.

Unrealized Gain on Derivative Instruments, Net. We recognize mark-to-market gains or losses in current earnings instead of deferring those amounts in accumulated other comprehensive income. Our unrealized gain for the year ended December 31, 2011 was 3.0 million.

Income (Loss) From Unconsolidated Affiliates. Income from unconsolidated affiliates during the year ended December 31, 2011 is the result of our pro-rata share of net income of our unconsolidated affiliate Oilfield Tubulars and Supply, we recognized $344,000 of income.

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

Income Tax Benefit (Expense). Due to our continuing losses, we were required by the “more likely than not” threshold for assessing the realizability of deferred tax assets to record a valuation allowance for our deferred tax assets beginning in 2007. Our subsidiary DHS was similarly required to record a valuation allowance for its deferred tax assets beginning in 2009. Our income tax expense for the years ended December 31, 2011 and 2010 primarily relates to the amortization of other tax assets generated for Delta by work performed for Delta by DHS. No benefit was provided in either period for Delta or DHS net operating losses.

For the year ended December 31, 2011, we recorded a tax benefit of $5.0 million due to a non-cash income tax benefit related to gains from discontinued oil and gas operations. Generally accepted accounting principles, or GAAP, require all items be considered, including items recorded in discontinued operations, in determining the amount of tax benefit that results from a loss from continuing operations that should be allocated to continuing operations. In accordance with GAAP, we recorded a tax benefit on our loss from continuing operations, which was exactly offset by income tax expense on discontinued operations.

Net Loss Attributable to Non-Controlling Interest. Non-controlling interest represents the minority investors’ proportionate share of the income or loss of DHS in which they held an interest until October 2011.

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Discontinued Operations. The results of operations relating to property interests sold in the 2011 and 2010 Wapiti Transactions and the sale of DHS Drilling are reflected as discontinued operations. During 2010, we sold our interests in the Howard Ranch and Laurel Ridge fields which are also included in discontinued operations.

The following table shows the oil and gas segment and drilling segment revenues and expenses included in discontinued operations for the above mentioned oil and gas properties for the years ended December 31, 2011 and 2010 (dollar amounts in thousands):

	Years Ended
	2011								2010
	Oil & Gas		Drilling			Total			Oil & Gas			Drilling			Total
Revenues:
Oil and gas sales	$	10,276	$	—		$	10,276		$	42,321		$	—		$	42,321
Contract drilling and trucking fees		—		45,241			45,241			—			53,212			53,212
Total Revenues		10,276		45,241			55,517			42,321			53,212			95,533
Operating Expenses:
Lease operating expense		2,481		—			2,481			9,691			—			9,691
Transportation expense		16		—			16			1,810			—			1,810
Production taxes		371		—			371			2,141			—			2,141
Dry hole costs and impairments(1)		608		—			608			98,372			—			98,372
Depreciation, depletion, amortization and accretion – oil and gas		2,796		—			2,796			25,227			—			25,227
Drilling and trucking operating Expenses		—		35,617			35,617			—			42,248			42,248
Depreciation and amortization –drilling and trucking		—		2,669			2,669			—			19,964			19,964
General and administrative expense		—		3,014			3,014			—			5,736			5,736
Total operating expenses		6,272		41,300			47,572			137,241			67,948			205,189
Other income and (expense):
Interest expense and financing costs, net		—		(6,911	)		(6,911	)		—			(7,079	)		(7,079	)
Other income (expense)		—		2,734			2,734			—			(1,583	)		(1,583	)
Total other income and (expense)		—		(4,177	)		(4,177	)		—			(8,662	)		(8,662	)
Income (loss) from discontinued operations		4,004		(236	)		3,768			(94,920	)		(23,398	)		(118,318	)
Income tax expense		1,724		—			1,724			—			—			—
Income (loss) from results of operations before discontinued operations,		2,280		(236	)		2,044			(94,920	)		(23,398	)		(118,318	)
Gain on sales of discontinued Operations, net of tax (2)		6,874		5,176			12,050			28,978			—			28,978
Income (loss) from results of operations and sale of discontinued operations, net of tax	$	9,154	$	4,940		$	14,094		$	(65,942	)	$	(23,398	)	$	(89,340	)

⁽¹⁾  Dry Hole Costs and Impairments. In 2011 we recorded impairments on the Columbia River, Greentown and Gulf Coast properties prior to their sale for $491,000. In accordance with accounting standards, the impairment loss relating to certain properties held for sale at June 30, 2010 in conjunction with the 2010 Wapiti Transaction were reflected as discontinued operations.

⁽²⁾  Gain on Sales of Discontinued Operations – Oil and Gas. During the second quarter of 2011, the Company closed the 2011 Wapiti Transaction, selling the remaining portion of its interests in non-core assets primarily located in Texas and Wyoming for gross cash proceeds of approximately $43.2 million. On July 23, 2010, we entered into a definitive Purchase and Sale Agreement with Wapiti to sell all or a portion of our interest in various non-core assets primarily located in Colorado, Texas, and Wyoming for gross cash proceeds of $130.0 million resulting in a net loss of $66.5 million (including impairment losses of $96.2 million). For financial reporting purposes, a $4.0 million impairment loss is included within dry hole costs and impairments in continuing operations, $92.2 million of impairments are included within loss from discontinued operations, and a $29.7 million gain on sale is included in gain on sale of discontinued operations. During 2010, we also sold our Howard Ranch properties for $550,000, recognizing a loss on the sale of $687,000. During the fourth quarter of 2011, we sold all of our stock in DHS at a net gain of $5.2 million.

36

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

Net Income (Loss) Attributable to Delta Common Stockholders. Net loss attributable to Delta common stockholders was $182.3 million, or $6.63 per diluted common share, for the year ended December 31, 2010, compared to net loss of $328.8 million or $15.58 per diluted common share for the year ended December 31, 2009. Loss from continuing operations decreased from $117.1 million for the year ended December 31, 2009 to a loss of $104.7 million for the year ended December 31, 2010. The decreased loss was primarily due to fewer impairments recorded in 2010 as compared to 2009, improved oil and gas operations, changes in unrealized gains (losses) on derivative instruments, and lower interest and financing costs. Explanations of significant items affecting comparability between periods are discussed by the financial statement captions below.

Oil and Gas Sales. During the year ended December 31, 2010, oil and gas sales from continuing operations were $61.8 million, as compared to $42.5 million for the comparable period a year earlier. During the year ended December 31, 2010, production from continuing operations decreased by 12% and the average natural gas and oil price increased 69% and 41%, respectively. The average gas price received during the year ended December 31, 2010 was $5.06 per Mcf compared to $3.00 per Mcf for the year earlier period and the average oil price received during the year ended December 31, 2010 was $60.75 per Bbl compared to $43.09 per Bbl for the year earlier period. The production decrease was primarily related to divestitures in the Gulf Coast area in 2010 and production declines in the Rocky Mountain Region where completion activity did not resume until late 2010.

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

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

	Years Ended December 31,
	2010		2009
Production – Continuing Operations:
Oil (MBbl)		161		175
Gas (MMcf)		10,265		11,652
Total (MMcfe)		11,231		12,702
Average Price – Continuing Operations:
Oil (per barrel)	$	60.75	$	43.09
Gas (per Mcf)	$	5.06	$	3.00
Costs per Mcfe – Continuing Operations:
Lease operating expense	$	1.57	$	1.40
Production taxes	$	0.20	$	0.12
Transportation costs	$	1.32	$	0.73
Depletion expense	$	3.90	$	4.48

Lease Operating Expense. Lease operating expenses for the year ended December 31, 2010 were $17.7 million compared to $17.7 million for the year earlier period. Lease operating expense from continuing operations for the year ended December 31, 2010 decreased $87,000 from the year earlier period. However, lease operating expenses increased on a per unit basis primarily due to the effect of fixed costs spread over a 12% decline in production volumes. The average lease operating expense was $1.57 per Mcfe in 2010 as compared to $1.40 per Mcfe for the year earlier period.

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Transportation Expense. Transportation expense for the year ended December 31, 2010 was $14.9 million, comparable to prior year costs of $9.3 million, up 81% on a per unit basis from $0.73 per Mcfe to $1.32 per Mcfe. The increase on a per unit basis is primarily the result of changes to our Vega gas marketing contract that went into effect in October 2009 whereby our gas is processed through a higher efficiency plant. Although the Vega area transportation costs increased on a per unit basis in 2010 as a result of these operations, this was more than offset by higher revenues in the Vega area from improved natural gas liquids recoveries and a greater percentage of liquids proceeds retained.

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

Dry Hole Costs and Impairments. We incurred zero dry hole costs for the year ended December 31, 2010 compared to $16.6 million for the prior year. As of December 31, 2010, we had one exploratory well in progress. For the year ended December 31, 2009, our dry hole costs related primarily to our Columbia River Basin exploratory well (the Gray Well) in Washington.

During the year ended December 31, 2010, we recorded impairment provisions related to continuing operations attributable to our proved and unproved properties and other items totaling approximately $37.7 million primarily related to our unproved impairments of $23.8 million related to our Columbia River Basin leasehold, Hingeline leasehold, Haynesville leasehold, Delores River leasehold, Howard Ranch leasehold, and our non-operated Garden Gulch field in the Piceance Basin. Other impairments primarily included $6.8 million for the produced water handling facility in Vega and $4.9 million to reduce the Paradox pipeline carrying value to its estimated fair value. These impairments generally resulted from the lack of success in marketing these non-core assets combined with our lack of plans to develop the acreage.

During the year ended December 31, 2009, we recorded impairment provisions related to continuing operations attributable to our proved and unproved properties totaling approximately $16.6 million primarily related to our non-operated Garden Gulch field in the Piceance Basin Vega surface land, various Rockies fields, pipe and tubular inventory. These impairments generally resulted from sustained lower commodity prices for most of 2009, near term expiring leasehold, unsuccessful drilling results, or our inability to meet contractual drilling obligations.

Depreciation, Depletion and Amortization – Oil and Gas. Depreciation, depletion and amortization expense decreased 18% to $46.9 million for the year ended December 31, 2010, as compared to $57.1 million for the year earlier period. Depletion expense for the year ended December 31, 2010 was $43.8 million compared to $56.9 million for the year ended December 31, 2009. The 23% decrease in depletion expense was primarily due to a 12% decrease in production from continuing operations and a 13% decrease in the depletion rate. Our depletion rate decreased to $3.90 per Mcfe for the year ended December 31, 2010 from $4.48 per Mcfe for the year earlier period. The decrease is primarily due to a change in the mix of our properties as a result of the Wapiti Transaction and additional Rockies reserves recorded in 2010 as a result of completion activities and use of improved fracturing methods.

General and Administrative Expense. General and administrative expense decreased slightly to $35.4 million for the year ended December 31, 2010, as compared to $37.3 million for the comparable prior year period. The decrease in general and administrative expenses is primarily attributed to lower expenses incurred on employee benefits and wages from reductions in force during 2010 and 2009 but was offset by significant costs associated with a strategic alternatives process.

Executive Severance Expense, Net. On May 26, 2009, our then Chairman of the Board of Directors and Chief Executive Officer, Roger A. Parker, resigned from Delta. In consideration for Mr. Parker’s resignation and his agreement to (a) relinquish all his rights under his employment agreement, his change-in-control agreement, certain stock agreements, bonuses relating to past and pending transactions benefiting Delta, and any other interests he might claim arising from his efforts as Chairman of our Board of Directors and/or Chief Executive Officer, and (b) stay on as a consultant to facilitate an orderly transition and to assist in certain pending transactions, Delta agreed to pay Mr. Parker $4.7 million in cash, issue to him 100,000 shares of Delta common stock, pay him the aggregate of any accrued unpaid salary, vacation days and reimbursement of his reasonable business expenses incurred through the effective date of the agreement, and provide to him insurance benefits similar to his pre-resignation benefits for a thirty-six month period. The severance agreement also contained mutual releases and non-disparagement provisions, as well as other customary terms. In addition, $2.8 million of equity compensation costs previously recorded in the consolidated financial statements related to shares which were forfeited as a result of the severance agreement were reversed and reflected as a reduction of executive severance expense.

38

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

Interest Expense and Financing Costs, Net. Interest expense and financing costs decreased 31% to $30.2 million for the year ended December 31, 2010, as compared to $43.6 million for the comparable year earlier period. The decrease is primarily related to a lower average outstanding Delta credit facility balance during 2010 as compared to 2009. The decrease is also related to a greater write-off of unamortized deferred financing costs and waiver fees related to the amendments to our credit facility in 2009 compared to 2010. In addition, the year ended December 31, 2009 included $1.0 million of interest expense related to the repurchase of certain offshore litigation contingent payment rights.

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

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

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

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

39

Income Tax Benefit (Expense). Due to our continuing losses, we were required by the “more likely than not” threshold for assessing the realizability of deferred tax assets to record a valuation allowance for our deferred tax assets beginning in 2007. Our subsidiary DHS was similarly required to record a valuation allowance for its deferred tax assets beginning in 2009. Our income tax expense for the years ended December 31, 2010 and 2009 primarily relates to the amortization of other tax assets generated for Delta by work performed for Delta by DHS. No benefit was provided in either period for Delta or DHS net operating losses.

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

During the three months ended March 31, 2011, DHS engaged transaction advisors to commence a strategic alternatives process, focused on a sale of DHS or substantially all of its assets. As such, in accordance with accounting standards, the results of operations relating to DHS have been reflected as discontinued operations for all periods presented.

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

	Years Ended
	2010									2009
	Oil & Gas			Drilling			Total			Oil & Gas			Drilling			Total
Revenues:
Oil and gas sales	$	42,321		$	—		$	42,321		$	52,446		$	—		$	52,446
Contract drilling and trucking fees(1)		—			53,212			53,212			—			13,680			13,680
Total Revenues		42,321			53,212			95,533			52,446			13,680			66,126
Operating Expenses:
Lease operating expense		9,691			—			9,691			13,560			—			13,560
Transportation expense		1,810			—			1,810			2,288			—			2,288
Production taxes		2,142			—			2,142			2,296			—			2,296
Dry hole costs and impairments(2)		98,371			—			98,371			172,466			—			172,466
Depreciation, depletion, amortization and accretion – oil and gas		25,227			—			25,227			51,403			—			51,403
Drilling and trucking operating expenses(3)		—			42,248			42,248			—			15,293			15,293
Goodwill and drilling equipment impairments		—			—			—			—			6,508			6,508
Depreciation and amortization –drilling and trucking(4)		—			19,964			19,964			—			22,917			22,917
General and administrative expense		—			5,736			5,736			—			4,130			4,130
Total operating expenses		137,241			67,948			205,189			242,013			48,848			290,861
Other income and (expense):
Interest expense and financing costs, net		—			(7,079	)		(7,079	)		—			(8,983	)		(8,983	)
Other income (expense)		—			(1,583	)		(1,583	)		—			1,119			1,119
Total other income and (expense)		—			(8,662	)		(8,662	)		—			(7,864	)		(7,864	)
Loss from discontinued operations		(94,920	)		(23,398	)		(118,318	)		(189,567	)		(43,032	)		(232,598	)
Income tax benefit		—			—			—			—			—			—
Loss from results of operations of discontinued operations, net of tax		(94,920	)		(23,398	)		(118,318	)		(189,567	)		(43,032	)		(232,599	)
Gain on sales of discontinued operations(5)		28,978			—			28,978			—			—			—
Loss from results of operations and sale of discontinued operations, net of tax	$	(65,942	)	$	(23,398	)	$	(89,340	)	$	(189,567	)	$	(43,032	)	$	(232,599	)

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⁽¹⁾  Contract Drilling and Trucking Fees. Drilling and trucking revenues for the year ended December 31, 2010 increased to $53.2 million compared to $13.7 million for the prior year period. Drilling and trucking revenues increased significantly in 2010 due to higher third party rig utilization in 2010 compared to the prior year, resulting from increased drilling activity attributable in particular to higher oil prices.

⁽²⁾  Dry Hole Costs and Impairments. In accordance with accounting standards, the impairment loss relating to certain properties held for sale at June 30, 2010 in conjunction with the 2010 Wapiti Transaction were reflected as discontinued operations. During 2009, we recorded impairments on the Newton, Opossum Hollow, Golden Prairie, Howard Ranch and Laurel Ridge fields of $18.4 million, as a result of the significant decline in commodity pricing for most of 2009 causing downward revision to proved reserves.

⁽³⁾  Drilling and Trucking Operating Expenses. We had drilling and trucking operating expenses of $42.2 million during the year ended December 31, 2010 compared to $15.3 million during the year ended December 31, 2009. The increase is due to higher third party rig utilization during 2010.

⁽⁴⁾  Depreciation and Amortization – Drilling and Trucking. Depreciation and amortization expense – drilling and trucking decreased to $20.0 million for the year ended December 31, 2010 as compared to $22.9 million for the prior year period. The decrease is due to the full year effect of impairments taken in 2009 and sales of rig equipment. Depreciation expense is recorded on a straight line basis and is not impacted by changes in the utilization rate.

⁽⁵⁾  Gain on Sales of Discontinued Operations – Oil and Gas. On July 23, 2010, we entered into a definitive Purchase and Sale Agreement with Wapiti to sell all or a portion of our interest in various non-core assets primarily located in Colorado, Texas, and Wyoming for gross cash proceeds of $130.0 million resulting in a net loss of $66.5 million (including impairment losses of $96.2 million). For financial reporting purposes, a $4.0 million impairment loss is included within dry hole costs and impairments in continuing operations, $92.2 million of impairments are included within loss from discontinued operations, and a $29.7 million gain on sale is included in gain on sale of discontinued operations. During 2010, we also sold our Howard Ranch properties for $550,000, recognizing a loss on the sale of $687,000.

Net Loss Attributable to Non-Controlling Interest. Non-controlling interest represents the minority investors’ proportionate share of the income or loss of DHS in which they hold an interest. During the years ended December 31, 2010 and 2009, DHS reported significant losses from low rig utilization rates which resulted in a non-controlling interest credit to earnings.

Off-Balance Sheet Arrangements

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

Contractual Obligations

	For the years ending December 31,
	2012		2013- 2014		2015- 2016		Thereafter		Total
	(In thousands)
Contractual Obligations at December 31, 2011
Not Subject to Compromise
Debtor in Possession Credit Facility	$	45,047	$	—	$	—	$	—	$	45,047
Abandonment retirement obligation		409		458		650		2,283		3,800
Subject to compromise
Senior unsecured notes		150,000		—		—		—		150,000
Senior convertible notes		115,000		—		—		—		115,000
Operating leases		969		528		528		418		2,443
Total contractual cash obligations	$	311,425	$	986	$	1,178	$	2,701	$	316,290

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 4 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, income taxes, derivatives, contingencies and litigation, and base our estimates on historical experience and various other assumptions that we believe are reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of our financial statements.

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Successful Efforts Method of Accounting

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

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

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

Reserve Estimates

Estimates of gas and oil reserves, by necessity, are projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of gas and oil that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable gas and oil reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions governing future gas and oil prices, the availability and cost of capital to develop the reserves, future operating costs, severance taxes, development costs and workover gas costs, all of which may in fact vary considerably from actual results. The future drilling costs associated with reserves assigned to proved undeveloped locations may ultimately increase to an extent that these reserves may be later determined to be uneconomic. For these reasons, estimates of the economically recoverable quantities of gas and oil attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected therefrom may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of our gas and oil properties and/or the rate of depletion of the gas and oil properties. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material.

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Impairment of Gas and Oil Properties

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

Given the complexities associated with gas and oil reserve estimates and the history of price volatility in the gas and oil markets, events may arise that would require us to record an impairment of the recorded book values associated with gas and oil properties. For proved properties, the review consists of a comparison of the carrying value of the asset with the asset’s expected future undiscounted cash flows without interest costs. As a result of this assessment, during the year ended December 31, 2011, we recorded impairment provisions attributable to our Vega area proved properties of $239.8 million. For unproved properties, the need for an impairment charge is based on our plans for future development and other activities impacting the life of the property and our ability to recover our investment. When we believe the costs of the unproved property are no longer recoverable, an impairment charge is recorded based on the estimated fair value of the property. During the three months ended September 30, 2011, we evaluated the fair value of our properties based on market indicators in conjunction with the progression of the strategic alternatives evaluation process. We did not receive any definitive offer with respect to an acquisition of the Company or its assets that implied a value of the assets greater than our aggregate indebtedness. As a result, we recorded an impairment of $157.5 million to our Vega unproved leasehold and $2.1 million to our Vega area surface acreage. Other impairments primarily included $20.5 million to our Vega area gathering system and facilities.

In 2010 we recorded impairment provisions to our proved and unproved properties and other items of $43.5 million which primarily included proved impairments to our Opossum Hollow and Golden Prairie fields of $1.1 million and unproved impairments of $30.0 million related to our Columbia River Basin leasehold, Hingeline leasehold, Haynesville leasehold, Delores River leasehold, Howard Ranch leasehold, and our non-operated Garden Gulch field in the Piceance Basin. Other impairments primarily included $6.7 million for the produced water handling facility in Vega and $4.9 million to reduce the Paradox pipeline carrying value to its estimated fair value. In addition to the impairment provisions discussed above, we utilized various fair value techniques related to our Garden Gulch, Baffin Bay, DJ Basin, Caballos Creek, Opossum Hollow, Midway Loop, and Newton fields, as well as our interest in our wholly owned subsidiary Piper Petroleum and unproved acreage positions in the DJ Basin and South Texas assets which were held for sale at June 30, 2010 and determined that impairment provisions of $93.2 million related to proved properties and $3.0 million related to unproved properties were required to be recognized during the three months ended June 30, 2010. Based upon the applicable accounting standards, $4.0 million of the impairment provision is included within dry hole costs and impairments in the accompanying statement of operations for the year ended December 31, 2010 and $92.2 million is included in loss from discontinued operations for the year ended December 31, 2010.

Asset Retirement Obligation

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

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Deferred Tax Asset Valuation Allowance

We use the asset and liability method of accounting for income taxes. Under the asset and liability method, deferred tax assets and liabilities are recognized for the estimated future tax effects attributable to temporary differences and carryforwards. Ultimately, realization of a deferred tax benefit depends on the existence of sufficient taxable income within the carryback/carryforward period to absorb future deductible temporary differences or a carryforward. In assessing the realizability of deferred tax assets, management must consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. Management considers all available evidence (both positive and negative) in determining whether a valuation allowance is required. Such evidence includes the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment, and judgment is required in considering the relative weight of negative and positive evidence. As a result of management’s current assessment, we maintain a significant valuation allowance against our deferred tax assets. We will continue to monitor facts and circumstances in our reassessment of the likelihood that operating loss carryforwards and other deferred tax attributes will be utilized prior to their expiration. As a result, we may determine that the deferred tax asset valuation allowance should be increased or decreased. Such changes would impact net income through offsetting changes in income tax expense or benefit.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Rate and Price Risk

We historically managed our exposure to commodity price fluctuations by hedging meaningful portions of our expected production through the use of derivatives, which may from time to time include costless collars, swaps, or puts. The level of our hedging activity and the duration of the instruments employed depended upon our view of market conditions, available hedge prices and our operating strategy. We had no open derivative positions at December 31, 2011.

Item 8. Financial Statements and Supplementary Data

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

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

Not applicable.

Item 9A. Controls and Procedures

a. Background

On December 16, 2011, Delta and its subsidiaries filed voluntary petitions under Chapter 11 of the U.S. Bankruptcy Code in the United States Bankruptcy Court for the District of Delaware (the “Bankruptcy Court”). For the duration of our Chapter 11 proceedings, our operations, including our ability to maintain adequate internal control over financial reporting, have been weakened during the bankruptcy process.

As a result of the significant reduction in business operations as a result of the bankruptcy proceedings and the related lack of liquidity, the Company experienced considerable turnover of accounting staff. This made it difficult for the Company to maintain a sufficient number of financial and accounting personnel with the appropriate level of accounting knowledge and experience in order to prepare timely, accurate and reliable financial statements. As a result, the Company became delinquent in its required periodic filings with the SEC, and failed to file this report and reports on Form 10-Q for the quarters ended March 31, 2012 and June 30, 2012. Also because of these issues, management was unable to complete its assessment of its internal controls over financial reporting as of December 31, 2011.

Notwithstanding the assessment that the Company’s disclosure controls and procedures were not effective as of December 31, 2011, the Company believes that the financial statements contained in this report fairly and accurately present the financial condition, results of operations and cash flows for the periods presented, in all material respects.

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b. Evaluation of Disclosure Controls and Procedures

Management, with the participation of our Chief Executive Officer and Chief Financial Officer, was unable to complete its evaluation of the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of December 31, 2011. Similarly, the Company was unable to complete its assessment of internal control over financial reporting. However, management did identify material weaknesses in internal control over financial reporting as described below in Management’s Report on Internal Control Over Financial Reporting, and therefore the CEO and CFO concluded that, as of December 31, 2011, the Company’s disclosure controls and procedures (a subset of financial reporting controls) were not effective. Additional matters impacting disclosure controls and procedures may have been identified had the Company completed its evaluation.

c. Management’s Report on Internal Control Over Financial Reporting

Overview of Internal Control Over Financial Reporting. Management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. The Company’s internal control over financial reporting is intended to be 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 (GAAP). The Company’s internal control over financial reporting is expected to include those policies and procedures that management believes are necessary and:

(i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company;

(ii) provide reasonable assurance that transactions are recorded to permit the preparation of financial statements in accordance with GAAP, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and the Board; and

(iii) 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.

The effectiveness of any system of internal control over financial reporting is subject to inherent limitations, including the exercise of judgment in designing, implementing, operating and evaluating the controls and procedures. Because of these inherent limitations, internal control over financial reporting cannot provide absolute assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with GAAP and may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that internal control over financial reporting may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management’s Assessment of the Effectiveness of Internal Control Over Financial Reporting. Management did not complete its assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2011, based on the criteria for effective internal control over financial reporting established in Internal Control–Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. However, in preparing these financial statements, management identified certain material weaknesses which are described below. Because of these material weaknesses, management concluded that we did not maintain effective internal control over financial reporting as of December 31, 2011, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Had we completed our assessment additional material weaknesses may have been identified.

A material weakness is a deficiency or combination of deficiencies in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of annual or interim financial statements will not be prevented or detected. In connection with the incomplete assessment described above, management identified the following internal control over financial reporting deficiencies that represent material weaknesses as of December 31, 2011.

• Financial Reporting and Closing Process: We did not maintain an effective financial reporting and closing process to prepare financial statements in accordance with GAAP. We determined that controls over timely and complete financial statement reviews, effective journal entry controls, and appropriate reconciliation processes were missing or ineffective. This material weakness resulted in material misstatements in the cash flow statement and accounting for deferred taxes that were corrected prior to the issuance of the financial statements. Further, we were unable to complete regulatory filings timely as required by the rules of the SEC.

• Qualified Personnel: We lacked a sufficient number of qualified accounting personnel in key financial reporting positions to operate processes and controls over the year end close process. As a result, a reasonable possibility exists that material misstatements in our financial statements will not be prevented or detected on a timely basis.

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• Risk Assessment: Our risk assessment controls did not address the impact of significant events, such as the filing of the bankruptcy petition, when evaluating the design and operating effectiveness of controls and the impact of such events on their financial statements. This material weakness resulted in misstatements in accounting for deferred financing costs and pre-petition liabilities that were corrected prior to the issuance of the financial statements. Furthermore, a reasonable possibility exists that material misstatements in our financial statements will not be prevented or detected on a timely basis.

• Control Monitoring: Our controls for monitoring the adequacy of the design and operating effectiveness of internal control over financial reporting across the Company were ineffective. As a result, a reasonable possibility exists that material misstatements in our financial statements will not be prevented or detected on a timely basis.

• Significant Estimates: Our controls related to the review of various financial statement accounts involving significant estimates and judgments, including impairment testing for oil and gas properties, accounting for income taxes, asset retirement obligations, and oil & gas reserve assumptions were missing or ineffective. As a result, a reasonable possibility exists that material misstatements in our financial statements will not be prevented or detected on a timely basis.

• Information and Communication: Our controls for communicating employees’ internal control responsibilities, providing employees with information in sufficient detail and on time to enable them to carry out their responsibilities, and establishing adequate lines of communication across the organization to enable employees to discharge their financial reporting responsibilities were ineffective. As a result, a reasonable possibility exists that material misstatements in our financial statements will not be prevented or detected on a timely basis.

The Company’s financial statements have been audited by KPMG LLP, an independent registered public accounting firm. KPMG LLP’s attestation report on the Company’s internal control over financial reporting, which disclaims an opinion on the effectiveness of the Company’s internal control over financial reporting, is included in Exhibit 15 herein.

d. Changes in Internal Controls over Financial Reporting

Management has reported to the Audit Committee material weaknesses described above and we are committed to continually improving our internal control processes. Other than the material weaknesses discussed in management’s assessment, which arose during the year end reporting period in connection with the preparation of the financial statements contained in this Form 10-K, we are not aware of any changes in our internal controls over financial reporting that occurred that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. Had we completed our assessment, additional changes in internal control may have been identified.

Following the Company’s emergence from bankruptcy proceedings, which is expected to be in September 2012, a new management team will be appointed. In particular, it is expected that new management will be given the responsibility to design and install internal control systems and procedures that provide the necessary level of assurance regarding the accuracy of the Company’s financial reporting.

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Item 9B. Other Information

None.

PART III

Item 10. Directors and Executive Officers and Corporate Governance

Executive Officers and Directors

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

Name	Age	Positions	Period of Service
Carl E. Lakey	50	President, Chief	July 2010 to Present
		Executive Officer and Director
John T. Young, Jr.	39	Chief Financial Officer	July 2012 to Present
		Chief Restructuring Officer	November 2011 to Present
Kevin R. Collins	55	Director	March 2005 to Present
Jerrie F. Eckelberger	67	Director	September 1996 to Present
Jordan R. Smith	77	Director	October 2004 to Present
Daniel J. Taylor	55	Chairman of the Board and Director	February 2008 to Present

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

Executive Officers

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

John T. Young, Jr. Delta appointed Mr. Young as its Chief Restructuring Officer in November 2011, and appointed him as Chief Financial Officer in July 2012. Mr. Young also currently serves as Senior Managing Director at Conway MacKenzie, Inc., which the Company retained in late 2011 to assist with its strategic alternatives process. Mr. Young has served as Senior Managing Director at Conway MacKenzie, Inc. since December 2008. From 1999 through December 2008, Mr. Young served as a principal of XRoads Solutions Group, LLC. Mr. Young has substantial knowledge and experience providing restructuring advisor services, including interim management and debtor advisory, bankruptcy preparation and management, litigation support, post-merger integration and debt restructuring and refinancing. Mr. Young’s experience also includes serving in a multitude of advisory capacities within the energy and oilfield services industries.

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Board of Directors

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

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

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

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

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

At the present time Messrs. Collins, Eckelberger, Smith, and Taylor serve on the Audit Committee; Messrs. Eckelberger, Collins, and Smith serve on the Compensation Committee; Messrs. Smith, Collins, Eckelberger, and Taylor serve on the Nominating & Governance Committee, and Messrs. Collins, Lakey, and Taylor serve on our Restructuring Committee.

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In conjunction with the February 2008 equity issuance to Tracinda Corporation, and in accordance with the related Company Stock Purchase Agreement, Tracinda designated Mr. Taylor (and two other persons who have since resigned) to serve on our Board of Directors.

All directors will hold office until the next annual meeting of stockholders unless the Plan transaction is consummated as described below. All of our officers will hold office until such time as they resign or are terminated by our Board of Directors or consummation of the Plan transaction. 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.

Executive Officers and Directors Following Plan Consummation

If the Plan transaction is consummated, our Board of Directors will initially have five members, each of which will be appointed by designated entities that currently hold Notes and will be significant stockholders following Plan consummation. The terms and conditions of such appointment will be governed by the Stockholders Agreement to be entered into contemporaneously with Plan consummation, and the terms of our amended and restated Certificate of Incorporation and Bylaws, each of which will also become effective contemporaneously with Plan consummation. Each of the Stockholders Agreement, the amended and restated Certificate of Incorporation and the amended and restated Bylaws is attached as an exhibit to this report.

Board Membership and Director Independence

Our Board of Directors has determined that each of Messrs. Collins, Eckelberger, Smith and Taylor qualifies as an independent director under applicable rules promulgated by the United States Securities and Exchange Commission (the “SEC”) and The NASDAQ Stock Market listing standards (although our common stock is no longer listed on NASDAQ), and has concluded that none of these directors has a material relationship with the Company that would interfere with the exercise of independent judgment in carrying out the responsibilities of a director.

During the fiscal year ended December 31, 2011, our Board of Directors met on 16 occasions, either in person or by telephone conference call. Each of our current directors attended at least 75% of the aggregate total of meetings of the Board of Directors and committees on which he served during his service term.

Directors standing for election are encouraged to attend the annual meeting of stockholders. No annual meeting of stockholders has been held in 2012.

Committees of the Board of Directors

Our Board of Directors has established an Audit Committee, a Compensation Committee and a Nominating and Corporate Governance Committee. The full text of all of the charters of the Board Committees is available on the Company’s website at www.deltapetro.com. The Board has determined that each of the directors who serve on these Committees is “independent” under applicable SEC standards. The directors who currently serve on each of these Committees are described above.

Audit Committee. We have a standing Audit Committee established in accordance with applicable SEC rules. The Audit Committee oversees and monitors our independent audit process and assists the Board of Directors in fulfilling its responsibilities with respect to matters involving the accounting, financial reporting and internal control functions of the Company and its subsidiaries. It is also charged with the responsibility for reviewing all related party transactions for potential conflicts of interest. A discussion of the role of the Audit Committee is provided under “Report of the Audit Committee.”

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The Board has determined that Mr. Collins is an “audit committee financial expert” as defined by rules adopted by the SEC.

The Audit Committee met six times in fiscal year 2011.

Compensation Committee. The Compensation Committee reviews the performance of our executives, sets compensation and compensation-related policies and makes recommendations to the Board of Directors in the area of executive compensation and for all employees, on bonus and equity incentives. The specific nature of the Compensation Committee’s roles and responsibilities as they relate to executive officers is set forth under “Compensation Discussion and Analysis.”

The Compensation Committee met on seven occasions either in person or by telephone conference call in fiscal year 2011.

Nominating and Corporate Governance Committee. The Nominating and Corporate Governance Committee makes recommendations to the Board of Directors regarding the persons who shall be nominated for election as directors. Given the bankruptcy process and the governance arrangements contemplated by the Plan as described above, we do not expect the Nominating and Corporate Governance Committee to play a further role in selecting director candidates for the company. For the same reasons, although the committee has maintained a policy regarding the procedures through which stockholders may recommend director candidates to the committee, the committee does not believe that the policy is currently relevant.

The Nominating and Corporate Governance Committee met one time in fiscal year 2011.

Restructuring Committee. The Restructuring Committee was formed in November 2011 to assist the Board of Directors in considering the Company’s strategic alternatives. Following the Company’s chapter 11 filing in December 2011, the Restructuring Committee has assisted the Board of Directors in considering the Company’s restructuring options through the bankruptcy process, as well as hiring legal, financial and other advisers to assist with the restructuring process.

The Restructuring Committee met two times in fiscal year 2011.

Code of Ethics

Our Board of Directors adopted a Code of Business Conduct and Ethics in November 2003 (amended in October 2004 and January 2007), which applies to all of our executive officers, directors and employees. A copy of the Code of Business Conduct and Ethics is available on our website at www.deltapetro.com or by writing to our Treasurer at 370 Seventeenth Street, Suite 4300, Denver, Colorado 80202.

Compensation Committee Interlocks and Insider Participation

No member of the Compensation Committee has ever been an officer of Delta or any of its subsidiaries, and no Delta employee served on the Compensation Committee during the last fiscal year. The Company does not have any interlocking relationships between its executive officers and the compensation committee and the executive officers and compensation committee of any other entities, nor has any such interlocking relationship existed in the most recently completed fiscal year.

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Board Leadership Structure

The Board’s current leadership structure separates the positions of Chairman of the Board and principal executive officer. Mr. Taylor, a designee of Tracinda Corporation, serves as our Chairman of the Board and Mr. Lakey serves as our President. The Board has determined our leadership structure based on factors such as the experience of the applicable individuals, the current business and financial environment faced by the Company, particularly in view of its financial condition and industry conditions generally, Mr. Taylor’s role on the Board since the consummation of the Tracinda investment in February 2008, and other relevant factors. After considering these factors, the Company determined that separating the positions of Chairman of the Board and principal executive officer is the appropriate leadership structure at this time. The Board, through the Chairman, is currently responsible for the strategic direction of the Company. The President is currently responsible for the day to day leadership and performance of the Company, while the Chairman of the Board provides guidance to the President, sets the agenda for the Board meetings and presides over meetings of the Board. The Board believes that this structure is appropriate under current circumstances because it allows management to make the operating decisions necessary to manage the business, while helping to keep a measure of independence between the oversight function of our Board of Directors and operating decisions. The Board feels that this structure provides an appropriate balance of strategic direction, operational focus, flexibility and oversight.

The Board’s Role in Risk Oversight

It is management’s responsibility to manage risk and bring to the Board of Directors’ attention any material risks to the Company. The Board of Directors has oversight responsibility through its Audit Committee which oversees the Company’s risk policies and processes relating to the financial statements and financial reporting processes and the guidelines, policies and processes for mitigating those risks.

Report of the Audit Committee

The following report of the Audit Committee does not constitute soliciting material and should not be deemed filed or incorporated by reference into any other Company filing under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent the Company specifically incorporates this Report.

The Audit Committee is currently comprised of Kevin R. Collins (Chairman), Jerrie F. Eckelberger, Jordan R. Smith and Daniel J. Taylor. The Audit Committee is responsible for overseeing and evaluating the Company’s financial reporting process on behalf of the Board of Directors, selecting and retaining the independent auditors, and overseeing and reviewing the internal audit function of the Company.

Management has the primary responsibility for the Company’s financial reporting process, accounting principles, and internal controls, as well as preparation of the Company’s financial statements in accordance with generally accepted accounting principles in the United States (“GAAP”). The independent auditors are responsible for performing audits of the Company’s consolidated financial statements and the effectiveness of the Company’s internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States) and issuing reports thereon. The Audit Committee is responsible for overseeing the conduct of these activities. It is not the Audit Committee’s duty or responsibility to conduct auditing or accounting reviews or procedures or to independently verify the representations made by management and the independent auditors. The Audit Committee’s considerations and discussions with management and the independent auditors do not assure that the Company’s financial statements are presented in accordance with GAAP or that the audits of the annual financial statements and the effectiveness of the Company’s internal control over financial reporting have been carried out in accordance with the standards of the Public Company Accounting Oversight Board (United States), or that the independent auditors are, in fact, “independent.”

The Audit Committee has met and held discussions with management and the independent auditors on a regular basis. The Audit Committee plans and schedules its meetings with a view to ensuring that it devotes appropriate attention to all of its responsibilities. The Audit Committee’s meetings include, whenever appropriate, executive sessions with the independent auditors without the presence of the Company’s management. The Audit Committee has reviewed and discussed with both management and the independent auditors the Company’s consolidated financial statements as of and for the year ended December 31, 2011, including a discussion of the quality, not just the acceptability, of the accounting principles, the reasonableness of significant judgments and the clarity of the disclosures in the financial statements. Management advised the Audit Committee that the financial statements were prepared in accordance with GAAP. The Audit Committee has relied on this representation, without independent verification, and on the representations of the independent auditors included in their report on the consolidated financial statements.

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The Audit Committee discussed with the independent auditors the matters required to be discussed pursuant to Statement of Auditing Standards No. 61, as amended. The independent auditors have provided to the Audit Committee the written disclosures and the letter required applicable requirements of the Public Company Accounting Oversight Board (PCAOB), and the Audit Committee has discussed with the independent auditors their independence. The Audit Committee has also considered whether the independent auditors’ provision of other non-audit services to the Company is compatible with maintaining auditor independence. The Audit Committee has concluded that the provision of non-audit services by the independent auditors was compatible with the maintenance of independence in the conduct of their auditing functions.

Based upon its review and discussions with management and the independent auditors and the reports of the independent auditors, and in reliance upon such information, representations, reports and opinions, the Audit Committee recommended that the Board of Directors approve the audited financial statements for inclusion in the Company’s annual report on Form 10-K for the year ended December 31, 2011, and the Board of Directors accepted the Audit Committee’s recommendations.

Members of the Audit Committee:

Kevin R. Collins (Chairman)

Jerrie F. Eckelberger

Jordan R. Smith

Daniel J. Taylor

Item 11. Executive Compensation

Plan Information

We maintain the following equity-based compensation plans: 2008 New-Hire Equity Incentive Plan and 2009 Performance and Equity Incentive Plan. Our stockholders approved the 2009 Plan, and the 2008 New-Hire Equity Incentive Plan was approved solely by our Board of Directors.

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The following table sets forth our equity compensation plans in the aggregate, the number of shares of our Common Stock subject to outstanding options and rights under these plans, the weighted-average exercise price of outstanding options, and the number of shares remaining available for future award grants under these plans as of December 31, 2011:

					Number of Securities
					Remaining Available
	Number of Securities		Weighted-Average		for Issuance Under
	to be Issued Upon		Exercise Price of		Equity Compensation
	Exercise of Outstanding		Outstanding		Plans (Excluding
	Options, Warrants and		Options, Warrants		Securities Reflected
	Rights		and Rights		in Column (a))
Plan Category	(a)		(b)		(c)
Equity compensation plans approved by security holders		150,300	$	75.00		19,826,710
Equity compensation plans not approved by security holders		—		—		472,109
Total		150,300				20,298,819

Compensation Discussion and Analysis

Overview

The following Compensation Discussion and Analysis describes the material elements of compensation for the named executive officers identified in the Summary Compensation Table below.

Compensation Philosophy and Objectives

Our compensation philosophy in recent years has been to encourage growth in our oil and natural gas reserves and production, encourage growth in cash flow and profitability, and enhance stockholder value through the creation and maintenance of compensation opportunities that attract and retain highly qualified executive officers. Based on these objectives, the Compensation Committee recommended an executive compensation program that includes the following components:

• a base salary at a level that is competitive with the base salaries being paid by other oil and natural gas exploration and production enterprises that have some characteristics similar to Delta and could compete with Delta for executive officer level employees;

• annual incentive compensation to reward achievement of Company objectives, individual responsibility and productivity, high quality work, reserve growth, performance and profitability and that is competitive with that provided by other oil and natural gas exploration and production enterprises that have some characteristics similar to Delta; and

• long-term incentive compensation in the form of stock-based awards that is competitive with that provided by other oil and natural gas exploration and production enterprises that have some characteristics similar to Delta.

Because of our bankruptcy filing and the events leading up to it, including a reduction in cash flow from operations due to low natural gas prices and a lack of liquidity in general, our executive compensation programs in 2011 were generally limited to the payment of base salaries under our executive officers’ employment agreements and the equity grants discussed below. As a continuing part of the bankruptcy process, we effected reductions in force in June and July of 2012, which included Kevin Nanke, our then-Chief Financial Officer, and Stanley Freedman, our then-General Counsel. We entered into consulting arrangements with Messrs. Nanke and Freedman in August 2012.

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Elements of Delta’s Compensation Program

The three principal components of Delta’s compensation program for its executive officers, base salary, annual incentive compensation and long-term incentive compensation in the form of stock-based awards, are discussed below.

Base Salary. Base salaries (paid in cash) for our executive officers have been established based on the scope of their responsibilities, taking into account competitive market compensation paid by the peer companies for similar positions. Base salaries are reviewed annually, and typically are adjusted from time to time to realign salaries with market levels after taking into account individual responsibilities, performance, experience and other criteria. For the reasons discussed above, no changes to executive officers’ base salaries were made in 2011.

Annual Incentive Compensation. In prior years, we utilized a performance-based annual incentive plan referred to as the Annual Bonus Award Plan. The Annual Bonus Award Plan was a discretionary bonus plan that gave the Board of Directors full discretion as to whether bonuses were to be paid. If it was determined bonuses were to be paid under the plan, the amounts of such bonuses for named executive officers were 25% tied to fixed metrics and 75% discretionary. For the reasons discussed above, no bonuses were awarded in 2011 under the plan.

Stock Awards. In June 2011, we granted a total of 489,227 shares of non-vested common stock to certain employees, including 240,000 shares to our executive officers. The shares vested in full in July 2012. In conjunction with this grant, we agreed to establish a “floor” price for the value of the shares on the date of vesting equal to the value of the shares on the grant date ($5.50 per share). Because the market price of the shares on the date of vesting was lower than the floor price on the date of vesting, we are obligated to pay the difference to the employees in cash.

Change in Control and Severance. We have an employment agreement with Mr. Lakey pursuant to which he will receive benefits if his employment is terminated (other than for misconduct) due to death, disability, and certain employment terminations following a change in control. The details and amount of such benefits are described in “Employment Agreements” and “Change in Control Agreements” below. We had similar agreements with Messrs. Nanke and Freedman prior to their separation from service in 2012.

Other Benefits. All employees may participate in our 401(k) Retirement Savings Plan, or 401(k) Plan. Each employee may make before tax contributions in accordance with the Internal Revenue Service limits. We provide this 401(k) Plan to help our employees save a portion of their cash compensation for retirement in a tax efficient manner. Effective January 1, 2010, Delta agreed to make a matching contribution in an amount equal to 100% of the employee’s elective deferral contribution below 3% of the employee’s compensation and 50% of the employee’s elective deferral that exceeds 3% of the employee’s compensation but does not exceed 6% of the employee’s compensation.

All full time employees, including our executive officers, may participate in our health and welfare benefit programs, including medical, dental and vision care coverage, disability insurance and life insurance.

Accounting and Tax Considerations

Our restricted stock award policies have been impacted by the implementation of Statement of Financial Accounting Standards No. 123(R), which we adopted on July 1, 2005.

We have structured our compensation program to comply with Internal Revenue Code Sections 162(m) and 409A. Under Section 162(m) of the Internal Revenue Code, a limitation is placed on tax deductions of any publicly-held corporation for individual compensation to certain executives of such corporation exceeding $1,000,000 in any taxable year, unless the compensation is performance-based. If an executive officer is entitled to nonqualified deferred compensation benefits that are subject to Section 409A, and such benefits do not comply with Section 409A, then the benefits are taxable in the first year they are not subject to a substantial risk of forfeiture. In such case, the executive officer is subject to regular federal income tax, interest and an additional federal income tax of 20% of the benefit included in income. Delta has no individuals with non-performance based compensation paid in excess of the Internal Revenue Code Section 162(m) tax deduction limit.

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Compensation Committee Report

The following Compensation Committee Report does not constitute soliciting material and should not be deemed filed or incorporated by reference into any other Company filing under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent the Company specifically incorporates this Report.

The Compensation Committee of the Board of Directors has reviewed and discussed the Compensation Discussion and Analysis required by Item 402(b) of SEC Regulation S-K with management. The Compensation Committee recommended to the Board of Directors that the Compensation Discussion and Analysis be included in the Company’s Annual Report on Form 10-K.

Respectfully submitted by the Compensation Committee of the Board of Directors:

Jerrie F. Eckelberger (Chairman)

Kevin R. Collins

Jordan R. Smith

Summary Compensation Table

The following table sets forth summary information concerning compensation awarded to, earned by, or accrued for services rendered to the Company in all capacities by our principal executive officer, principal financial officer and our one other executive officer (collectively, the “named executive officers”), for fiscal years 2009, 2010 and 2011. As discussed above, Messrs. Nanke and Freedman were included in reductions in force effected in 2012.

Name and Principal Position	Year		Salary ($)		Bonus ($)		Stock Awards ($)(1)		Option Awards ($)(1)		Non-Equity Incentive Plan Compensation ($)(2)		All Other Compensation ($)(3)		Total ($)
Carl E. Lakey,		2011	$	398,970				660,000				329,162		30,744		1,418,876
President and Chief		2010		338,585		—		700,000		—		480,500		19,768		1,538,853
Executive Officer*
Kevin K. Nanke,		2011		337,144				396,000				182,311		26,350		968,155
Former Treasurer and Chief		2010		328,600		—		560,000		—		395,000		25,339		1,308,939
Financial Officer		2009		297,083		—		793,637		—		169,900		25,939		1,286,559
Stanley F. Freedman,		2011		300,245				264,000				162,358		29,436		756,039
Former Executive Vice President,		2010		293,750		—		490,000		—		323,500		21,259		1,128,509
General Counsel and Secretary		2009		263,542		—		703,930		—		141,800		21,859		1,131,131

* Mr. Lakey became President and Chief Executive Officer on July 6, 2010.

(1) These amounts shown represent the aggregate grant date fair value for stock awards and option awards granted to the named executive officers computed in accordance with FASC ASC Topic 718.

(2) The amounts reflect the cash bonus awards to the named executive officers, discussed above under the heading “Elements of Delta’s Compensation Program” under the caption “Annual Incentive Compensation.” Awards under the Company’s bonus plans were accrued and earned in the year represented and paid in the following year.

(3) Amounts in the “All Other Compensation” column consist of the following payments we paid to or on behalf of the named executive officers:

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Name	Year		Company Contributions to Retirement Plans ($)		Auto Allowance ($)		Auto Maintenance and Insurance ($)		Health Club ($)		Severance Agreement Payments ($)		Total ($)
Carl E. Lakey*		2011	$	8,977		19,800		1,967		—		—		30,744
		2010		5,961		9,000		4,807		—		—		19,768
		2009		—		—		—		—		—		—
Kevin K. Nanke		2011		—		19,800		4,150		2,400		—		26,350
		2010		—		18,000		4,939		2,400		—		25,339
		2009		—		18,000		5,539		2,400		—		25,939
Stanley F. Freedman		2011		6,756		19,800		—		2,880		—		29,436
		2010		—		18,000		3,259		—		—		21,259
		2009		—		18,000		3,859		—		—		21,859

* Mr. Lakey became President and Chief Executive Officer on July 6, 2010.

Grants of Plan-Based Awards

The following table provides additional information about restricted stock awards and equity and non-equity incentive plan awards granted to our named executive officers during fiscal 2011.

	Grant Date or		Estimated Future Payouts Under Non-Equity Incentive Plan  Awards						Option Awards Number of Shares of Stock or		Stock Awards Number of Shares of Stock or		Grant Date Fair Value of Stock and Option
Name	Performance Period		Threshold ($)		Target ($)		Max ($)		Units (#)		Units (#)		Awards ($)
Carl E. Lakey, President and Chief Executive Officer*		6/21/2011		68,250		273,000		546,000		—		120,000		660,000
Kevin K. Nanke, Former Treasurer and Chief Financial Officer		6/21/2011		47,200		236,000		472,000		—		72,000		396,000
Stanley F. Freedman, Former Executive Vice President, General Counsel and Secretary		6/21/2011		52,550		210,200		420,400		—		48,000		264,000

* Mr. Lakey became President and Chief Executive Officer on July 6, 2010.

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Outstanding Equity Awards at Fiscal Year-End

	Option Awards								Stock Awards
Name	Number of Securities Underlying Unexercised Options (#) Exercisable		Number of Securities Underlying Unexercised Options (#) Unexercisable		Option Exercise Price ($)		Option Expiration Date		Number of Shares or Units of Stock that have not Vested (#)		Market Value of Shares or Units of Stock that have not Vested(6) ($)		Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights that have Not Vested (#)		Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights that have Not Vested ($)
Carl E. Lakey, President and Chief Executive Officer*		25,000		—		7.90		7/06/2020		134,787		13,479		—		—
Kevin K. Nanke,		13,750		—		52.90		8/26/2013		87,124		8,712
Former Treasurer and Chief Financial Officer		8,750				153.40		12/21/2014
Stanley F. Freedman, Former Executive Vice President, General Counsel and Secretary		—		—		—		—		61,414		6,141		—		—

* Mr. Lakey became President and Chief Executive Officer on July 6, 2010.

Option Exercises and Stock Vested

The following table provides information about the value realized by the named executive officers for option award exercises and stock award vesting during fiscal 2011.

Name	Option Awards Number of Shares Acquired on Exercise (#)		Value Realized on Exercise ($)		Stock Awards Number of Shares Acquired on Vesting (#)		Value Realized on Vesting ($)
Carl E. Lakey*		—		—		115,387		537,880
Kevin K. Nanke		—		—		96,790		445,234
Stanley F. Freedman		—		—		85,080		391,368

* Mr. Lakey became President and Chief Executive Officer on July 6, 2010.

Employment Agreements

Carl Lakey. On July 15, 2010, we entered into an Amended and Restated Employment Agreement with Carl Lakey, who was appointed as the Company’s Chief Executive Officer on July 6, 2010. The Amended and Restated Employment Agreement amended Mr. Lakey’s previous employment agreement dated as of October 1, 2009. The initial term of Mr. Lakey’s amended agreement was through December 31, 2010, and such term automatically extends for additional one year terms thereafter unless notice of termination is given by either party at least sixty days prior to the end of the then-applicable term. The base annual salary for Mr. Lakey provided for in the amended agreement is $390,000.

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In the event Mr. Lakey’s employment is terminated other than for “cause” or if he resigns for “good reason” (both as defined in the agreement), then Mr. Lakey will be entitled to receive a payment equal to two times the sum of his annual base salary and his average annual bonus. In the event that Mr. Lakey’s agreement is not renewed at the end of any term, then at the time that his employment is terminated Mr. Lakey will receive the same severance payment as stated above, reduced proportionately by the number of months that Mr. Lakey continues to be employed by the Company after expiration of the applicable term. The agreement also includes non-solicitation and non-competition obligations on the part of Mr. Lakey that survive for one year following the date of termination.

Kevin K. Nanke. On May 5, 2005, we entered into an employment agreement with Kevin K. Nanke, our Chief Financial Officer. As discussed above, Mr. Nanke was included in a reduction in force effected in 2012. In connection with his separation from service, an affiliate of his entered into a Consulting Agreement with the Company pursuant to which the affiliate agreed to provide consulting services to us at a rate of $12,500 per month for 80 hours of work and $550 per hour for work in excess of 80 hours. The agreement terminates on August 31, 2012.

Stanley F. Freedman. On January 11, 2006, we entered into an employment agreement with Stanley F. Freedman, who became Executive Vice President, General Counsel and Secretary of Delta on January 3, 2006. As discussed above, Mr. Freedman was included in a reduction in force effected in 2012. In connection with his separation from service, he entered into a Consulting Agreement with the Company pursuant to which he agreed to provide consulting services to us on the same terms as Mr. Nanke’s affiliate described above.

We may enter into severance agreements with Messrs. Nanke and Freedman following the expiration of the Consulting Agreements.

Change in Control Agreements

On April 30, 2007, we entered into Change in Control Executive Severance Agreements (“CIC Agreements”) with Messrs. Nanke and Freedman, and on October 1, 2009, we entered into a CIC Agreement with Mr. Lakey, which provide that, following a change in control of the Company as defined in the CIC Agreements and the termination of employment of the executive officer during the period beginning 6 months prior to and ending 24 months after the change in control, the executive officer would not receive a payment under the Employment Agreement. Instead, he would receive a payment equal to three times his annual base salary, annual automobile allowance and his average annual bonus for the three years preceding the fiscal year in which the change in control occurs, but not less than the greater of that executive officer’s (i) highest annual target bonus during any of these three preceding fiscal years or (ii) target bonus for the fiscal year in which the change in control occurs, in addition to the continuation of certain benefits including medical insurance and other benefits provided to the executive officer for a period of three years. The CIC Agreements also include non-solicitation and non-competition obligations on the part of the executive officer that survive for one year following the date of termination. The CIC Agreements also provide that if a payment under the CIC Agreements would be subject to excise tax payments, the executive officer will receive a gross-up payment equal to such excise tax imposed by Section 4999 of the Internal Revenue Code of 1986, as amended, and all taxes, including any interest, penalties or income tax imposed on the gross-up payment.

The CIC Agreements define a change in control as the occurrence of any of the following: (1) any Person becomes a beneficial owner of 35% or more of Delta’s voting securities, except as the result of any acquisition of voting securities by Delta or any acquisition of voting securities of Delta directly from Delta (as authorized by the Board); (2) the persons who constitute the incumbent Board cease for any reason to constitute at least a majority of the Board unless such change was approved by at least two-thirds (2/3) of the incumbent Board; (3) the consummation of a reorganization, merger, share exchange, consolidation, or sale or disposition of all or substantially all of the assets of Delta unless the persons who beneficially own the voting securities of Delta immediately before that transaction beneficially own, immediately after the transaction, at least 70% of the voting securities of Delta or any other corporation or other entity resulting from or surviving the transaction; or (4) Delta’s stockholders approve a complete liquidation or dissolution of Delta or a sale of substantially all of its assets.

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Potential Payments upon Termination or Change in Control

The following table reflects the potential payments and benefits upon termination (i) for cause, and (ii) other than for cause or death, disability or retirement, within and not within the period beginning six months prior to and ending 24 months following a change in control (“Measurement Period”) of Delta under the respective CIC Agreement for each named executive officer. The amounts payable assume termination of employment on December 31, 2011.

			Within the Measurement Period								Not Within the Measurement Period
	Severance & Bonus ($)		Acceleration of Options & Stock Awards ($)		Benefits ($)		Excise Tax & Gross-Ups ($)		Total ($)		Severance & Bonus ($)		Acceleration of Options & Stock Awards ($)		Benefits ($)		Excise Tax & Gross-Ups ($)		Total ($)
Carl E. Lakey For Cause Not For Cause		3,028,182		660,000		64,680		1,591,177		5,344,039		3,458,737		660,000		64,680		1,591,177		5,774,594
Kevin K. Nanke For Cause Not For Cause		1,749,778		396,000		64,680				2,210,458		2,089,337		396,000		64,680		—		2,550,017
Stanley F. Freedman For Cause Not For Cause		1,558,273		264,000		64,680		744,766		1,860,671		1,860,671		264,000		64,680		744,766		2,934,117

* “Cause” is defined in the CIC Agreement, and “Not For Cause” means resignation by the executive for Good Reason (as defined in the CIC Agreement) or termination of the executive by the Company without Cause.

Director Compensation

The following table sets forth a summary of the compensation we paid to our non-employee directors in 2011:

Name	Fees Earned or Paid  in Cash ($)		Stock Awards ($)		Total ($)
Kevin R. Collins		69,000		66,120		135,120
Jerrie F. Eckelberger		69,000		66,120		135,120
Jordan R. Smith		62,500		66,120		128,620
Daniel J. Taylor		61,500		155,800		217,300

Annual Retainers

In 2011, each non-employee director of the Company received an annual retainer of $50,000, paid on a monthly basis.

Each Board Committee chair also receives an additional retainer each year in the following amounts: chair of the Audit Committee and chair of the Compensation Committee, $10,000; and chair of the Nominating and Corporate Governance Committee, $5,000. In addition, each non-employee director who is not a chairman but serves on one or more Committees of the Board receives an annual retainer of $2,500. The additional retainer amounts are also paid to the directors in cash in equal monthly installments. The Company reimburses the directors for costs incurred by them in traveling to Board and Committee meetings. Restructuring Committee members receive $1,500 for each meeting attended.

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Stock Grants

In addition, at the discretion of the Board of Directors, each non-employee director is eligible to receive an annual grant of shares of Common Stock. During 2011, the Company awarded 109,608 shares to members of the board of directors.

Indemnification of Directors

Pursuant to the Company’s certificate of incorporation, the Company generally provides indemnification of its directors and officers to the fullest extent permitted under the Delaware General Corporation Law and provides certain indemnification to its executive officers under their employment agreements.

Narrative Disclosure of Compensation Policies and Practices as they Relate to Risk Management

In accordance with the requirements of Regulation S-K, Item 402(s), to the extent that risks may arise from the Company’s compensation policies and practices that are reasonably likely to have a material adverse effect on the Company, we are required to discuss those policies and practices for compensating the employees of the Company (including employees that are not named executive officers) as they relate to the Company’s risk management practices and the possibility of incentivizing risk-taking. We have determined that the compensation policies and practices established with respect to the Company’s employees are not reasonably likely to have a material adverse effect on the Company and, therefore, no such disclosure is necessary.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Security Ownership of Certain Beneficial Owners

The following table presents information concerning persons known by us to own beneficially 5% or more of our issued and outstanding Common Stock as of August 22, 2012.

Name and Address	Amount and Nature of Beneficial Ownership		Percent of Class(1)
Tracinda Corporation(2) 150 South Rodeo Drive, Suite 250 Beverly Hills, CA 90212		9,379,770		32.5	%

(1) We have authorized 200,000,000 shares of $.01 par value Common Stock, of which 28,576,067 shares were issued and outstanding as of August 17, 2012. We also have authorized 3,000,000 shares of $.01 par value preferred stock, of which no shares are outstanding.

(2) This disclosure is based on an amendment to Schedule 13D filed with the SEC on April 4, 2012]. The Schedule 13D was filed on behalf of Tracinda Corporation and Kirk Kerkorian, both of which reported having sole voting and dispositive power over 93,797,701 shares. Tracinda Corporation is wholly owned by Kirk Kerkorian.

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Security Ownership of Management

The following table contains information about the beneficial ownership (unless otherwise indicated) of our Common Stock as of August 17, 2012 by:

• each of our current directors;

• each named executive officer; and

• all current directors and current executive officers as a group.

Name and Address of Beneficial Owner(1)	Amount and Nature of Beneficial Ownership(2)			Percent of Class(3)
Carl E. Lakey		170,451	(4)		*
John T. Young		—			*
R. Seth Bullock		—			*
Daniel J. Taylor		52,986	(5)		*
Kevin R. Collins		21,901	(6)		*
Jerrie F. Eckelberger		20,277	(7)		*
Jordan R. Smith		20,277	(8)		*
All current executive officers and directors as a Group (7 persons)		285,892	(9)		1	%

* Represents beneficial ownership of less than one percent 1.0% of the outstanding shares of our Common Stock.

(1) The address of these persons is c/o Delta Petroleum Corporation, 370 17th Street, Suite 4300, Denver, Colorado 80202.

(2) If a stockholder holds options or other securities that are exercisable or otherwise convertible into our Common Stock within 60 days of August 17, 2012, we treat the Common Stock underlying those securities as owned by that stockholder, and as outstanding shares when we calculate the stockholder’s percentage ownership of our Common Stock. However, we do not consider that Common Stock to be outstanding when we calculate the percentage ownership of any other stockholder.

(3) We have 200,000,000 shares of $.01 par value Common Stock, of which 28,576,067 shares were issued and outstanding as of August 17, 2012. We also have an authorized capital of 3,000,000 shares of $.01 par value preferred stock, of which no shares are outstanding.

(4) Includes 128,691 shares of Common Stock owned directly by Mr. Carl E. Lakey. Also includes options to purchase 22,500 shares of Common Stock that are currently exercisable or exercisable within 60 days of August 17, 2012.

(5) Includes 19,254 shares of Common Stock owned directly and 34,242 shares of Common Stock held by a trust held by Mr. Taylor.

(6) Includes 21,901 shares of Common Stock owned directly by Mr. Collins

61

(7) Includes 18,877 shares of Common Stock owned directly by Mr. Eckelberger. Also includes options to purchase 1,400 shares of Common Stock that are currently exercisable or exercisable within 60 days of August 17, 2012.

(8) Includes 18,877 shares of Common Stock owned directly by Mr. Smith. Also includes options to purchase 1,400 shares of Common Stock that are currently exercisable or exercisable within 60 days of August 17, 2012.

(9) Includes all warrants, options and shares referenced in footnotes (4) through (8) above as if all warrants and options had been exercised and as if all resulting shares were voted as a group.

Item 13. Certain Relationships and Related Transactions, and Director Independence

Review, Approval or Ratification of Transactions with Related Persons

The Board of Directors has recognized that transactions between the Company and certain related persons present a heightened risk of conflicts of interest. In order to ensure that the Company acts in the best interests of its stockholders, the Board has delegated the review and approval of related party transactions to the Audit Committee in accordance with the Company’s written Audit Committee Charter. After its review, the Audit Committee will only approve or ratify transactions that are fair to the Company and not inconsistent with the best interests of the Company and its stockholders. Any director who may be interested in a related party transaction shall recuse himself from any consideration of such related party transaction.

Stockholder Communications with the Board of Directors

Stockholders wishing to contact the Board of Directors or specified members or Committees of the Board should send correspondence to Secretary, Delta Petroleum Corporation, 370 Seventeenth Street, Suite 4300, Denver, Colorado 80202. All communications so received from stockholders of the Company will be forwarded to the members of the Board of Directors or to a specific director or Committee if so designated by the stockholder. A stockholder who wishes to communicate with a specific director or Committee should send instructions asking that the material be forwarded to the director or to the appropriate committee chairman.

COMPLIANCE WITH SECTION 16(A) OF THE SECURITIES EXCHANGE ACT OF 1934

Section 16(a) of the Securities Exchange Act of 1934, as amended, requires our executive officers, directors and persons who beneficially own more than ten percent (10%) of a registered class of our equity securities, to file initial reports of ownership of Delta securities and reports of changes in ownership of Delta securities with the SEC.

Based solely on a review of the copies of such reports furnished to us by our officers and directors and their written representations that such reports accurately reflect all reportable transactions, the late filings for fiscal year 2011 and the current year through August 10, 2012 are as follows:

Name	Form 3/# of Transactions	Form 4/# of Transactions	Form 5/#of Transactions
Carl E. Lakey President, Chief Executive Officer and Director	N/A	Late/1	N/A
John T. Young Chief Financial Officer and Chief Restructuring Officer	Late/1	N/A	N/A
Daniel J. Taylor Chairman of the Board and Director	N/A	Late/1	N/A
R. Seth Bullock Treasurer	Late/1	N/A	N/A

62

Item 14. Principal Accounting Fees and Services.

The following table summarizes the aggregate fees billed by KPMG LLP for the 2011 and 2010 fiscal years:

	Fiscal Year Ended
	December 31, 2011		December 31, 2010
Audit fees	$	671,958	$	684,000
Audit-related fees		—		5,000
Tax fees		255,826		195,652
Total	$	927,784	$	884,652

Audit Fees. Fees for audit services consisted of the audit of our annual financial statements and reports on internal controls required by the Sarbanes-Oxley Act of 2002 and reviews of our quarterly financial statements.

Audit Related Fees. Fees billed for audit related services related to professional services rendered by KPMG LLP for assurance and related services that are reasonably related to the performance of the audit or review of Delta’s financial statements but are not included in audit fees above.

Tax Fees. Fees for tax services consisted of tax preparation for Delta and its subsidiaries.

Audit Committee Pre-Approval Policy

The Company’s independent registered public accounting firm may not be engaged to provide non-audit services that are prohibited by law or regulation to be provided by it, nor may the Company’s independent registered public accounting firm be engaged to provide any other non-audit service unless it is determined that the engagement of the principal accountant provides a business benefit resulting from its inherent knowledge of the Company while not impairing its independence. Our Audit Committee must pre-approve permissible non-audit services. During fiscal year 2011, our Audit Committee approved 100% of the non-audit services provided to Delta by its independent registered public accounting firm.

63

PART IV

Item 15. Exhibits, Financial Statement Schedules

(a)(1) Financial Statements.

	Page No.
Reports of Independent Registered Public Accounting Firm		F-1
Consolidated Balance Sheets as of December 31, 2011 and December 31, 2010		F-4
Consolidated Statements of Operations for the years ended December 31, 2011, 2010 and 2009		F-5
Consolidated Statements of Stockholders’ Equity and Comprehensive Income (Loss) for the years ended December 31, 2011, 2010 and 2009		F-6
Consolidated Statements of Cash Flows for the years ended December 31, 2011, 2010 and 2009		F-7
Notes to Consolidated Financial Statements		F-8

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

(a)(3) Exhibits. The Exhibits listed in the Index to Exhibits appearing at page 67 are filed as part of this report. Management contracts and compensatory plans required to be filed as exhibits are marked with a “*”.

64

Glossary of Oil and Gas Terms

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

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.

Completion. Installation of permanent equipment for production of oil or gas, or, in the case of a dry well, to reporting to the appropriate authority that the well has been abandoned.

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.

HBP. Held by production.

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

MBbls. Thousands of barrels.

Mcf. Thousand cubic feet (of natural gas).

Mcfe. Thousand cubic feet equivalent.

Mgl. Thousand gallons (of natural gas liquids).

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

MMcf. Million cubic feet.

MMcfe. Million cubic feet equivalent.

MMgl. Million gallons.

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.

65

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.

66

INDEX TO EXHIBITS

3.1	Certificate of Incorporation of the Company, as amended. Incorporated by reference to Exhibit 3.1 to our Form 8-K filed July 13, 2011.
3.2	Amended and Restated By-laws of the Company. Incorporated by reference to Exhibit 3.1 to our Form 8-K filed February 13, 2006.
4.1	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 to Exhibit 4.3 to our Form 8-K filed March 21, 2005.
4.2	Form of 7% Series A Senior Notes due 2015 with attached notation of Guarantees. Incorporated by reference to Exhibit 4.3 to our Form 8-K filed March 21, 2005.
4.3	Indenture, dated as of April 25, 2007, by and between our and the subsidiary guarantors named therein and U.S. Bank National Association, as trustee (including Form of 33/4% Convertible Senior Note due 2037). Incorporated by reference to Exhibit 4.1 to our Form 8-K filed April 25, 2007.
4.4	Form of 33/4% Convertible Senior Note due 2037. Incorporated by reference to Exhibit 4.2 to our Form 8-K filed April 25, 2007.
10.1	Delta Petroleum Corporation 1993 Incentive Plan. Incorporated by reference to Exhibit 28.1 to our Form 8-K filed May 21, 1993.*
10.2	Delta Petroleum Corporation 1993 Incentive Plan, as amended June 30, 1999. Incorporated by reference to our Definitive Proxy Statement filed May 21, 1999.*
10.3	Delta Petroleum Corporation 2001 Incentive Plan. Incorporated by reference to Exhibit B to our Definitive Proxy Statement filed June 30, 2001.*
10.4	Delta Petroleum Corporation 2002 Incentive Plan. Incorporated by reference to Exhibit A to our Definitive Proxy Statement filed May 1, 2002.*
10.5	Delta Petroleum Corporation 2004 Incentive Plan. Incorporated by reference to Appendix B to our Definitive Proxy Statement filed November 22, 2004.*
10.6	Amendment No. 1 to Delta Petroleum Corporation 2004 Incentive Plan. Incorporated by reference to Exhibit 10.2 to our Form 8-K filed June 22, 2005.*
10.7	Delta Petroleum Corporation 2005 New-Hire Equity Incentive Plan. Incorporated by reference to Exhibit 10.1 to our Form 8-K filed June 22, 2005.*
10.8	Delta Petroleum Corporation 2006 New-Hire Equity Incentive Plan. Incorporated by reference to Exhibit 10.1 to our Form 8-K filed June 26, 2006.*
10.9	Delta Petroleum Corporation 2007 Performance and Equity Incentive Plan. Incorporated by reference to Appendix A to our Definitive Proxy Statement filed December 28, 2006.*
10.10	Delta Petroleum Corporation 2009 Performance and Equity Incentive Plan. Incorporated by reference to Exhibit 10.1 to our Form 8-K filed December 24, 2009. *

67

10.11	Delta Petroleum Corporation 2008 New-Hire Equity Incentive Plan. Incorporated by reference to Exhibit 10.2 to our Quarterly Report on Form 10-Q filed August 7, 2008.*
10.12	Form of restricted stock award agreement for awards under the Delta Petroleum Corporation 2009 Performance and Equity Incentive Plan. Incorporated by reference to Exhibit 10.12 to our Form 10-K for the year ended December 31, 2009 and filed March 12, 2010.*
10.13	Amended and Restated Employment Agreement with Carl Lakey dated July 15, 2010. Incorporated by reference to Exhibit 10.1 to our Form 8-K filed July 21, 2010.
10.14	Employment Agreement with Kevin K. Nanke dated May 5, 2005. Incorporated by reference to Exhibit 10.2 to our Form 8-K filed May 11, 2005.*
10.15	Employment Agreement with Stanley F. Freedman dated January 11, 2006. Incorporated by reference to Exhibit 10.1 to our Form 8-K filed January 12, 2006.*
10.16	Change in Control Executive Severance Agreement with Carl Lakey dated October 1, 2009. Incorporated by reference to Exhibit 10.16 to our Form 10-K filed March 16, 2011.*
10.17	Change in Control Executive Severance Agreement with Kevin K. Nanke dated April 30, 2007. Incorporated by reference to Exhibit 10.3 to our Form 8-K filed May 2, 2007.*
10.18	Change in Control Executive Severance Agreement with Stanley F. Freedman dated April 30, 2007. Incorporated by reference to Exhibit 10.4 to our Form 8-K filed May 2, 2007.*
10.19	Amendment to Amended and Restated Employment Agreement and Change-in-Control Employee Severance Agreement, dated December 29, 2010, among Delta Petroleum Corporation and Carl Lakey. Incorporated by reference to Exhibit 10.2 to our Form 8-K filed January 5, 2011.*
10.20	Amendment to Employment Agreement and Change-in-Control Executive Severance Agreement, dated December 29, 2010, among Delta Petroleum Corporation and Kevin Nanke. Incorporated by reference to Exhibit 10.3 to our Form 8-K filed January 5, 2011.*
10.21	Amendment to Employment Agreement and Change-in-Control Executive Severance Agreement, dated December 29, 2010, among Delta Petroleum Corporation and Stanley Freedman. Incorporated by reference to Exhibit 10.4 to our Form 8-K filed January 5, 2011.*
10.22	Consulting Agreement, dated August 2, 2012, by and between Delta Petroleum Corporation and KN Consulting, Inc. Incorporated by reference to Exhibit 10.1 to our Form 8-K filed August 8, 2012.
10.23	Consulting Agreement, dated August 2, 2012, by and between Delta Petroleum Corporation and Stanley F. Freedman. Incorporated by reference to Exhibit 10.2 to our Form 8-K filed August 8, 2012.*
10.24	Third Amended and Restated Credit Agreement, dated December 29, 2010, among Delta Petroleum Corporation, the lenders party thereto, and Macquarie Bank Limited, as administrative agent and as issuing lender. Incorporated by reference to Exhibit 10.1 to our Form 8-K filed January 5, 2011.
10.25	First Amendment to Third Amended and Restated Credit Agreement, dated March 14, 2011, among Delta Petroleum Corporation, the lenders party thereto, and Macquarie Bank Limited, as administrative agent and as issuing lender. Incorporated by reference to Exhibit 10.25 to our Form 10-K filed March 16, 2011.
10.26	Second Amendment to Third Amended and Restated Credit Agreement, dated June 28, 2011, among Delta Petroleum Corporation, the lenders party thereto, and Macquarie Bank Limited, as administrative agent and as issuing lender. Incorporated by reference to Exhibit 10.1 to our Form 8-K filed June 29, 2011.

68

10.27	Third Amendment to Third Amended and Restated Credit Agreement, dated December 12, 2011, among Delta Petroleum Corporation, the lenders party thereto, and Macquarie Bank Limited, as administrative agent and as issuing lender. Incorporated by reference to Exhibit 10.1 to our Form 8-K filed December 16, 2011.
10.28	Carry and Earning Agreement dated February 28, 2008 between the Company and EnCana Oil & Gas (USA) Inc. Incorporated by reference to Exhibit 10.1 to our Form 8-K filed March 5, 2008.
10.29	Agreement between Delta Petroleum Corporation and Amber Resources Company dated July 1, 2001. Incorporated by reference to Exhibit 10.3 to our Form 8-K filed December 20, 2001.
10.30	Company Stock Purchase Agreement, dated December 29, 2007, by and between Delta Petroleum Corporation and Tracinda Corporation. Incorporated by reference to Exhibit 10.1 to our Form 8-K filed January 25, 2008.
10.31	Purchase and Sale Agreement, dated September 15, 2008, between the Company and EnCana Oil & Gas (USA) Inc. Incorporated by reference to Exhibit 10.1 to our Form 8-K filed October 2, 2008.
10.32	Sale Agreement dated August 19, 2008 between the Company and Husky Refining Company. Incorporated by reference to Exhibit 10.2 to our Form 8-K filed October 2, 2008.
10.33	Purchase and Sale Agreement, dated as of July 23, 2010, by and between Delta Petroleum Corporation and Wapiti Oil & Gas, L.L.C. Incorporated by reference to Exhibit 10.1 to our Form 8-K filed July 27, 2010.
10.34	Forbearance Agreement, dated December 31, 2010, among DHS Holding Company, DHS Drilling Company and Lehman Commercial Paper Inc., as administrative agent and issuing lender. Incorporated by reference to Exhibit 10.36 to our Form 10-K filed March 16, 2011.
10.35	Forbearance Agreement No. 2, dated February 1, 2011, among DHS Holding Company, DHS Drilling Company and Lehman Commercial Paper Inc., as administrative agent and issuing lender. Incorporated by reference to Exhibit 10.37 to our Form 10-K filed March 16, 2011.
10.36	Amended and Restated Forbearance Agreement No. 2, dated March 15, 2011, among DHS Holding Company, DHS Drilling Company and Lehman Commercial Paper Inc., as administrative agent and issuing lender. Incorporated by reference to Exhibit 10.38 to our Form 10-K filed March 16, 2011.
10.37	Second Amended and Restated Forbearance Agreement No. 2, dated March 25, 2011, among DHS Holding Company, DHS Drilling Company and Lehman Commercial Paper Inc. under that certain Amended and Restated Credit Agreement dated as of August 15, 2008, as amended by that certain Amendment No. 1, dated as of September 19, 2008, and further amended by that certain Waiver and Amendment No. 2, dated as of April 1, 2010. Incorporated by reference to Exhibit 10.5 to our Form 10-Q filed May 10, 2011.
10.38	Third Amended and Restated Forbearance Agreement No. 2, dated April 12, 2011, among DHS Holding Company, DHS Drilling Company and Lehman Commercial Paper Inc. under that certain Amended and Restated Credit Agreement dated as of August 15, 2008, as amended by that certain Amendment No. 1, dated as of September 19, 2008, and further amended by that certain Waiver and Amendment No. 2, dated as of April 1, 2010. Incorporated by reference to Exhibit 10.4 to our Form 10-Q filed May 10, 2011.
10.39	Forbearance Agreement dated as of April 15, 2011 among DHS Holding Company, DHS Drilling Company and Lehman Commercial Paper, Inc. Incorporated by reference to Exhibit 10.5 to our Form 10-Q filed May 10, 2011.
10.40	Purchase and Sale Agreement, dated as of June 15, 2011, among Delta Petroleum Corporation and Wapiti Oil & Gas, L.L.C. Incorporated by reference to Exhibit 10.1 to our Form 8-K filed June 20, 2011.

69

10.41	Forbearance Agreement dated as of August 3, 2011 among DHS Holding Company, DHS Drilling Company and Lehman Commercial Paper, Inc. Incorporated by reference to Exhibit 10.4 to our Form 10-Q filed August 4, 2011.
10.42	Amended and Restated Senior Secured Debtor-in-Possession Credit Agreement, dated as of December 21, 2011. Incorporated by reference to Exhibit 10.1 to our Form 8-K filed December 22, 2011.
10.43	Forbearance Agreement, dated July 3, 2012. Filed herewith electronically.
10.44	Forbearance Extension Letter, dated as of July 16, 2012. Filed herewith electronically.
10.45	Second Forbearance Extension Letter, dated as of July 30, 2012. Filed herewith electronically.
10.46	Third Forbearance Extension Letter, dated as of August 16, 2012. Filed herewith electronically.
10.47	Contribution Agreement, dated as of June 4, 2012, between Piceance Energy, LLC, Laramie Energy, LLC and Delta Petroleum Corporation. Incorporated by reference to Exhibit 10.1 to our Form 8-K filed June 8, 2012.
21.1	Subsidiaries of the Registrant. Filed herewith electronically.
23.1	Consent of KPMG LLP. Filed herewith electronically.
23.2	Consent of Netherland, Sewell & Associates, Inc. Filed herewith electronically.
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.
32.1	Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 350. Filed herewith electronically.
32.2	Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350. Filed herewith electronically.
99.1	Report of Netherland, Sewell & Associates, Inc. regarding the registrants Proved Reserves as of December 31, 2011. Filed herewith electronically.
99.2	Form of Amended and Restated Certificate of Incorporation to be adopted upon completion of the Plan. Filed herewith electronically.
99.3	Form of Amended and Restated By-laws to be adopted upon completion of the Plan. Filed herewith electronically.
99.4	Form of Limited Liability Company Agreement to be adopted upon completion of the Plan. Filed herewith electronically.
99.5	Form of Management Services Agreement to be entered into upon completion of the Plan. Filed herewith electronically.
99.6	Form of Stockholders Agreement to be entered into upon completion of the Plan. Filed herewith electronically.
101.INS	XBRL Instance Document.**
101.SCH	XBRL Taxonomy Extension Schema Documents.**
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document.**
101.LAB	XBRL Taxonomy Extension Label Linkbase Document.**
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.**
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document.**

* Management contracts and compensatory plans.

** These interactive data files are furnished and deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise are not subject to liability under those sections.

70

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Delta Petroleum Corporation (Debtor in Possession):

We have audited the accompanying consolidated balance sheets of Delta Petroleum Corporation and subsidiaries (Debtor in Possession) (the Company) as of December 31, 2011 and 2010, and the related consolidated statements of operations, stockholders’ equity and comprehensive loss, and cash flows for each of the years in the three-year period ended December 31, 2011. 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 (Debtor in Possession) as of December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2011, in conformity with U.S. generally accepted accounting principles.

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in notes 2 and 3 to the financial statements, the Company is currently operating pursuant to Chapter 11 of the U.S. Bankruptcy Code having filed voluntary petitions in the United States Bankruptcy Court for the District of Delaware. There are no assurances as to management’s ability to construct and obtain confirmation of a plan of reorganization under the Bankruptcy Code, which raises substantial doubt about the Company’s ability to continue as a going concern. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

We also were engaged to audit, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Delta Petroleum Corporation’s (Debtor in Possession) internal control over financial reporting as of December 31, 2011, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated August 31, 2012, indicates that the scope of our work was not sufficient to enable us to express, and we did not express, an opinion on Delta Petroleum Corporation’s (Debtor in Possession) internal control over financial reporting.

(signed) KPMG LLP

Denver, Colorado

August 31, 2012

F-1

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Delta Petroleum Corporation (Debtor in Possession):

We were engaged to audit Delta Petroleum Corporation’s (Debtor in Possession) (the Company) internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the Management’s Report on Internal Control over Financial Reporting.

As described in Management’s Report on Internal Control over Financial Reporting, the Company was unable to complete and support its evaluation of internal control over financial reporting with sufficient documentation to enable us to satisfactorily complete our audit to express an opinion on the effectiveness of internal control over financial reporting.

A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the Company’s annual or interim financial statements will not be prevented or detected. The following material weaknesses have been identified and included in management’s assessment:

• Financial Reporting and Closing Process: The Company did not maintain an effective financial reporting and closing process to prepare financial statements in accordance with generally accepted accounting principles (GAAP). The Company determined that controls over timely and complete financial statement reviews, effective journal entry controls, and appropriate reconciliation processes were missing or ineffective. This material weakness resulted in material misstatements in the cash flow statement and accounting for deferred taxes that were corrected prior to the issuance of the financial statements. Further, the Company was unable to complete regulatory filings timely as required by the rules of the SEC.

• Qualified Personnel: The Company lacked a sufficient number of qualified accounting personnel in key financial reporting positions to operate processes and controls over the year end close process. As a result, a reasonable possibility exists that material misstatements in the Company’s financial statements will not be prevented or detected on a timely basis.

• Risk Assessment: The Company’s risk assessment controls did not address the impact of significant events, such as the filing of the bankruptcy petition, when evaluating the design and operating effectiveness of controls and the impact of such events on their financial statements. This material weakness resulted in misstatements in accounting for deferred financing costs and pre-petition liabilities that were corrected prior to the issuance of the financial statements. Furthermore, a reasonable possibility exists that material misstatements in the Company’s financial statements will not be prevented or detected on a timely basis.

• Control Monitoring: The Company’s controls for monitoring the adequacy of the design and operating effectiveness of internal control over financial reporting across the Company were ineffective. As a result, a reasonable possibility exists that material misstatements in the Company’s financial statements will not be prevented or detected on a timely basis.

• Significant Estimates: The Company’s controls related to the review of various financial statement accounts involving significant estimates and judgments, including impairment testing for oil and gas properties, accounting for income taxes, asset retirement obligations, and oil & gas reserve assumptions were missing or ineffective. As a result, a reasonable possibility exists that material misstatements in the Company’s financial statements will not be prevented or detected on a timely basis.

• Information and Communication: The Company’s controls for communicating employees’ internal control responsibilities, providing employees with information in sufficient detail and on time to enable them to carry out their responsibilities, and establishing adequate lines of communication across the organization to enable employees to discharge their financial reporting responsibilities were ineffective. As a result, a reasonable possibility exists that material misstatements in the Company’s financial statements will not be prevented or detected on a timely basis.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) the consolidated balance sheets of Delta Petroleum Corporation (Debtor in Possession) as of December 31, 2011 and 2010, and the related consolidated statements of operations, Stockholders’ equity and comprehensive loss, and cash flows for each of the years in the three-year period ended December 31, 2011. These material weaknesses were considered in determining the nature, timing and extent of audit tests applied in our audit of the 2011 consolidated financial statements, and this report does not affect our report dated August 31, 2012, which expressed an unqualified opinion on those financial statements.

Our report contains an explanatory paragraph that states that the Company is currently operating pursuant to Chapter 11 of the U.S. Bankruptcy Code having filed voluntary petitions in the United States Bankruptcy Court for the District of Delaware and there are no assurances as to management’s ability to construct and obtain confirmation of a plan of reorganization under the Bankruptcy Code, which raises substantial doubt about the Company’s ability to continue as a going concern.

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.

F-2

Delta Petroleum Corporation (Debtor in Possession)

August 31, 2012

Page 2 of 2

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.

Since management did not complete and support its evaluation of internal control over financial reporting with sufficient evidence, including documentation, and we were unable to apply other procedures to satisfy ourselves as to the effectiveness of the Company’s internal control over financial reporting, the scope of our work was not sufficient to enable us to express, and we do not express, an opinion on the effectiveness of the Company’s internal control over financial reporting.

(signed) KPMG LLP

Denver, Colorado

August 31, 2012

F-3

DELTA PETROLEUM CORPORATION

AND SUBSIDIARIES

(Debtor in Possession)

CONSOLIDATED BALANCE SHEETS

	December 31,			December 31,
	2011			2010
	(In thousands, except share data)
ASSETS
Current assets:
Cash and cash equivalents	$	12,862		$	14,190
Short-term restricted deposits		—			100,000
Trade accounts receivable, net of allowance for doubtful accounts of $254 and $100, respectively		5,606			7,373
Assets held for sale		—			108,218
Prepaid assets		3,399			1,720
Prepaid reorganization costs		1,301			—
Inventories		180			3,446
Other current assets		—			4,821
Total current assets		23,348			239,768
Property and equipment:
Oil and gas properties, successful efforts method of accounting:
Unproved		72,081			229,943
Proved		688,521			671,041
Land		4,000			6,106
Other		71,567			101,008
Total property and equipment		836,169			1,008,098
Less accumulated depreciation and depletion		(475,609	)		(232,493	)
Net property and equipment		360,560			775,605
Long-term assets:
Investments in unconsolidated affiliates		3,649			3,376
Deferred financing costs		—			1,832
Other long-term assets		340			3,531
Total long-term assets		3,989			8,739
Total assets	$	387,897		$	1,024,112
LIABILITIES AND EQUITY
Current liabilities:
Liabilities not subject to compromise
Debtor in possession financing	$	45,047		$	—
Installments payable on property acquisition current		—			97,874
Accounts payable		2,582			27,616
Liabilities related to assets held for sale		—			82,852
Other accrued liabilities		149			11,066
Accrued reorganization and trustee expense		851			—
Derivative instruments		—			574
Liabilities subject to compromise
7% Senior notes		115,000			—
3 3/4% Senior convertible notes		150,000			—
Accounts payable		13,597			—
Other accrued liabilities		6,939			—
Total current liabilities		334,165			219,982
Long-term liabilities:
Liabilities not subject to compromise
Asset retirement obligations		3,507			2,709
7% Senior notes		—			149,684
3 3/4% Senior convertible notes		—			108,593
Credit facility—Delta		—			29,130
Derivative instruments		—			2,419
		—			—
Total long-term liabilities		3,507			292,535
Commitments and contingencies
Equity:
Preferred stock, $0.01 par value:
authorized 3,000,000 shares, none issued		—			—
Common stock, $0.01 par value; authorized 200,000,000 shares, issued 28,841,177 shares at December 31, 2011 and 28,513,800 shares at December 31, 2010		288			285
Additional paid-in capital		1,641,390			1,635,783
Treasury stock at cost; 0 shares at December 31, 2011 and 3,300 shares at December 31, 2010		—			(279	)
Accumulated deficit		(1,591,453	)		(1,121,342	)
Total Delta stockholders’ equity		50,225			514,447
Non-controlling interest		—			(2,852	)
Total equity		50,225			511,595
Total liabilities and equity	$	387,897		$	1,024,112

See accompanying notes to consolidated financial statements.

F-4

DELTA PETROLEUM CORPORATION

AND SUBSIDIARIES

(Debtor in Possession)

CONSOLIDATED STATEMENTS OF OPERATIONS

	Years Ended December 31,
	2011			2010			2009
	(In thousands, except per share amounts)
Revenue:
Oil and gas sales	$	63,880		$	61,791		$	42,516
Gain on offshore litigation settlement, net of loss on property sales		—			(795	)		73,800
Total revenue		63,880			60,996			116,316
Operating expenses:
Lease operating expense		13,755			17,656			17,742
Transportation expense		13,867			14,862			9,324
Production taxes		1,535			2,197			1,556
Exploration expense		338			1,337			2,604
Dry hole costs and impairments		420,402			37,362			16,606
Depreciation, depletion, amortization and accretion – oil and gas		39,088			46,881			57,102
General and administrative expense		28,124			35,394			37,284
Executive severance expense, net		—			(674	)		3,739
Total operating expenses		517,109			155,015			145,957
Operating loss		(453,229	)		(94,019	)		(29,641	)
Other income and (expense):
Interest expense and financing costs, net		(32,324	)		(30,168	)		(43,599	)
Other income (expense)		(1,947	)		174			(70	)
Realized loss on derivative instruments, net		(3,368	)		(5,835	)		(1,115	)
Unrealized gain (loss) on derivative instruments, net		2,993			23,979			(26,972	)
Income (loss) from unconsolidated affiliates		344			1,738			(15,473	)
Total other expense		(34,302	)		(10,112	)		(87,229	)
Loss from continuing operations before income taxes, reorganization items, and discontinued operations		(487,531	)		(104,131	)		(116,870	)
Income tax expense (benefit)		(4,329	)		543			215
Loss before reorganization items and discontinued operations		(483,202	)		(104,674	)		(117,085	)
Reorganizational items
Professional fees and administrative costs		932			—			—
Discontinued operations:
Gain (loss) from results of operations and sale of discontinued operations, net of tax		14,094			(89,340	)		(232,599	)
Net loss		(470,040	)		(194,014	)		(349,684	)
Less net loss (gain) attributable to non-controlling interest included in discontinued operations		(71	)		11,682			20,901
Net loss attributable to Delta common stockholders	$	(470,111	)	$	(182,332	)	$	(328,783	)
Amounts attributable to Delta common stockholders:
Loss from continuing operations	$	(484,134	)	$	(104,674	)	$	(117,085	)
Loss from discontinued operations, net of tax		14,023			(77,658	)		(211,698	)
Net loss	$	(470,111	)	$	(182,332	)	$	(328,783	)
Basic loss attributable to Delta common stockholders per common share:
Loss from continuing operations	$	(16.79	)	$	(3.81	)	$	(5.55	)
Discontinued operations		0.49			(2.82	)		(10.03	)
Net loss	$	(16.30	)	$	(6.63	)	$	(15.58	)
Diluted loss attributable to Delta common stockholders per common share:
Loss from continuing operations	$	(16.79	)	$	(3.81	)	$	(5.55	)
Discontinued operations		0.49			(2.82	)		(10.03	)
Net loss	$	(16.30	)	$	(6.63	)	$	(15.58	)

See accompanying notes to consolidated financial statements.

F-5

DELTA PETROLEUM CORPORATION AND SUBSIDIARIES

(Debtor in Possession)

CONSOLIDATED STATEMENTS OF CHANGES IN

EQUITY AND COMPREHENSIVE LOSS

							Additional														Total Delta			Non-
	Common Stock						paid-in			Treasury Stock						Accumulated					stockholders’			controlling			Total
	Shares			Amount			capital			Shares			Amount			Deficit					Equity			Interests			Equity
	(In thousands)
Balance, December 31, 2008		10,342		$	103		$	1,373,054			4		$	(540	)	$	—	$	(610,227	)	$	762,390		$	29,104		$	791,494
Net loss		—			—			—			—			—			—		(328,783	)		(328,783	)		(20,901	)		(349,684	)
Treasury stock acquired by subsidiary		—			—			—			1			(47	)		—		—			(47	)		47			—
Shares issued for cash, net of offering costs		17,250			172			246,733			—			—			—		—			246,905			—			246,905
Issuance of non-vested stock		676			7			(8	)		(2	)		248			—		—			247			(247	)		—
Forfeitures of non-vested stock		(10	)		—			—			—			—			—		—			—			—			—
Shares repurchased for withholding taxes		(16	)		(—	)		(313	)		1			71			—		—			(242	)		(195	)		(437	)
Cancellation of executive performance shares, tranches 4 and 5		(50	)		(1	)		1			—			—			—		—			—			—			—
Cancellation of restricted shares due to reductions in force		(19	)		—			—			—			—			—		—			—			—			—
Executive severance – issuance		100			1			1,699			—			—			—		—			1,700			—			1,700
Executive severance – forfeiture		(18	)		—			(2,819	)		—			—			—		—			(2,819	)		—			(2,819	)
Stock based compensation		—			—			9,231			—			—			—		—			9,231			730			9,961
Balance, December 31, 2009		28,255		$	282		$	1,627,578			4		$	(268	)	$	—	$	(939,010	)	$	688,582		$	8,538		$	697,120
Net loss		—			—			—			—			—			—		(182,332	)		(182,332	)		(11,682	)		(194,014	)
Issuance of non-vested stock		565			6			145			(2	)		104			—		—			255			(247	)		8
Forfeitures of non-vested stock		(215	)		(2	)		2			—			—			—		—			—			—			—
Shares repurchased for withholding taxes		(91	)		(1	)		(745	)		1			(115	)		—		—			(861	)		—			(861	)
Executive severance – forfeiture		—			—			(2,274	)		—			—			—		—			(2,274	)		—			(2,274	)
Stock based compensation		—			—			11,077			—			—			—		—			11,077			539			11,616
Balance, December 31, 2010		28,514		$	285		$	1,635,783			3		$	(279	)	$	—	$	(1,121,342	)	$	514,447		$	(2,852	)	$	511,595
Net loss		—			—			—			—			—			—		(470,111	)		(470,111	)		71			(470,040	)
Employee vesting of treasury stock held by Subsidiary		—			—			(135	)		(3	)		279			—		—			144			(59	)		85
Issuance of non-vested stock		598			6			(6	)					—			—		—			—			—			—
Forfeitures		(55	)		—			—			—			—			—		—			—			—			—
Shares repurchased for withholding taxes		(216	)		(3	)		(993	)		—			—			—		—			(996	)		—			(996	)
Sale of minority interest		—			—			—			—			—			—		—			—			2,744			2,744
Stock based compensation		—			—			6,741			—			—			—		—			6,741			96			6,837
Balance, December 31, 2011		28,841		$	288		$	1,641,390			—		$	—		$	—	$	(1,591,453	)	$	50,225		$	—		$	50,225

See accompanying notes to consolidated financial statements.

F-6

DELTA PETROLEUM CORPORATION

AND SUBSIDIARIES

(Debtor in Possession)

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Years Ended December 31,
	2011			2010			2009
	(In thousands)
Cash flows from operating activities:
Net loss	$	(470,040	)	$	(194,014	)	$	(349,684	)
Adjustments to reconcile net loss to cash provided by operating activities:
Basis in offshore properties recovered through litigation		—			—			17,904
(Gain) loss on sale of other assets		85			1,547			(1,156	)
Gain on sale of discontinued operations		(14,699	)		(28,184	)		5,655
Depreciation, depletion, and amortization – oil and gas		39,082			46,431			60,758
Interest capitalized into principal balance		74			—			—
Depreciation, depletion, and amortization – discontinued operations		5,348			45,640			70,664
Dry hole costs and impairments		420,402			37,362			16,604
Impairments – discontinued operations		608			98,372			178,974
Stock based compensation		8,003			11,467			9,961
Executive severance – stock		—			(2,274	)		(1,120	)
Amortization of deferred financing costs		13,805			9,148			12,151
Accretion of discount on installments payable		2,126			4,619			7,038
Increase in allowance for bad debt		154			1,437			—
Unrealized (gain) loss on derivative contracts		(2,993	)		(23,979	)		26,972
Gain on marketable securities		—			(300	)		(53	)
(Income) loss from unconsolidated affiliates		344			(1,738	)		15,809
Deferred income tax expense		956			610			215
Other		1,940			1,043			(64	)
Net changes in operating assets and liabilities:
Decrease in trade accounts receivable		1,535			4,601			13,913
(Increase) decrease in deposits and prepaid assets		(3,018	)		(511	)		5,216
Increase in inventories		(68	)		(175	)		(1,225	)
(Increase) decrease in other current assets		(285	)		626			(1,639	)
Increase (decrease) in accounts payable		861			(45,387	)		(18,924	)
Increase in accrued reorganization costs		851			—			—
Increase (decrease) in offshore litigation payable		—			(13,877	)		13,877
Increase (decrease) in other accrued liabilities		(3,722	)		629			(702	)
Increase (decrease) in assets held for sale working capital, net		(359	)		13,906			—
Net cash provided by (used in) operating activities		990			(33,001	)		81,144
Cash flows from investing activities:
Additions to property and equipment		(56,058	)		(41,639	)		(165,855	)
Proceeds from sale of oil and gas properties		40,229			132,945			8,393
Proceeds from sale of drilling assets and other fixed assets		3,429			665			9,111
Proceeds from sale of marketable securities		61			300			2,030
Decrease in restricted deposit		100,000			100,000			100,000
Additions to drilling and trucking equipment – assets held for sale		(1,529	)		(2,549	)		(1,785	)
Investment in unconsolidated affiliates		—			—			295
Proceeds from sales of unconsolidated affiliates		1,517			6,654			—
Proceeds from escrow deposit		—			1,380			—
Decrease in other long-term assets		—			82			444
Net cash provided by (used in) investing activities		87,649			197,838			(47,367	)
Cash flows from financing activities:
Proceeds from borrowings		117,550			139,630			100,000
Repayment of borrowings		(104,992	)		(248,216	)		(281,017	)
Installments paid on property acquisition		(100,000	)		(100,000	)		(100,000	)
Payment of deferred financing costs		(1,529	)		(3,232	)		(2,842	)
Proceeds from sale of offshore litigation contingent payment rights		—			—			25,000
Repurchase of offshore litigation contingent payment rights		—			—			(25,000	)
Stock issued for cash, net		—			—			246,905
Stock repurchased for withholding taxes		(996	)		(747	)		(380	)
Net cash used in financing activities		(89,967	)		(212,565	)		(37,334	)
Net decrease in cash and cash equivalents		(1,328	)		(47,728	)		(3,557	)
Cash at beginning of year		14,190			61,918			65,475
Cash at end of year	$	12,862		$	14,190		$	61,918
Supplemental cash flow information:
Cash paid for interest and financing costs	$	19,384		$	27,639		$	39,953
DHS interest payable capitalized to principal balance (non-cash financing transaction)	$	5,573		$	—		$	—

See accompanying notes to consolidated financial statement

F-7

DELTA PETROLEUM CORPORATION AND SUBSIDIARIES

(Debtor in Possession)

Notes to Consolidated Financial Statements

December 31, 2011, 2010 and 2009

1) Nature of Organization

Delta Petroleum Corporation (“Delta” or the “Company”) is principally engaged in acquiring, exploring, developing and producing oil and gas properties. The Company’s core area of operations is the Rocky Mountain Region in which the majority of its proved reserves, production and long-term growth prospects are concentrated.

On December 16, 2011, Delta Petroleum Corporation (the “Debtor”), filed voluntary petitions under Chapter 11 of the U.S. Bankruptcy Code, in the United States Bankruptcy Court for the District of Delaware (Case No. 11-0006). The bankruptcy filing was filed in connection with other filings made by the Company’s consolidating entities; DPCA, LLC; Delta Exploration Company, inc.; Delta Pipeline, LLC; DLC, Inc.; DEC, Inc.; Castle Texas Production LP; Castle Exploration Company, Inc.; and Amber Resources Company of Colorado.

At December 31, 2011, 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 owned undeveloped oil and gas properties in federal units offshore California, near Santa Barbara prior to the resolution of litigation with the United States government (see Note 4, “Oil and Gas Properties”). In conjunction with the settlement of such litigation, the leases owned by Amber were conveyed to the United States. As a result, Amber’s only remaining asset is cash on hand and there are no ongoing operations. It is currently anticipated that Amber will remain in existence until the outcome of litigation involving one of the offshore California leases that was assigned back to the U.S. government is resolved (See Note 17, “Commitments and Contingencies”).

(2) Reorganization under Chapter 11

On December 16, 2011 Delta and certain of its subsidiaries filed voluntary petitions under Chapter 11 of the U.S. Bankruptcy Code, in the United States Bankruptcy Court for the District of Delaware. Accordingly, the Company urges that caution be exercised with respect to existing and future investments in the Company’s equity securities.

For the duration of the Company’s Chapter 11 proceedings, the Company’s operations, including the Company’s ability to develop and execute a business plan, are subject to the risks and uncertainties associated with the bankruptcy process. As such, and because the Company’s structure, including its number of outstanding shares, shareholders, majority shareholders, assets, liabilities, officers and/or Directors may be significantly different following the outcome of its pending bankruptcy proceedings as compared to its status immediately prior to filing for Chapter 11 bankruptcy, the description of business operations, planned operations and properties described may not accurately reflect the Company’s operations and business plans following its bankruptcy reorganization.

On December 16, 2011, the Company filed a motion in the United States Bankruptcy Court for the District of Delaware (the “Court” or “Bankruptcy Court”) for joint administration of the Delta Petroleum Corporation case, the Amber Resources Company of Colorado case, the DPCA, LLC case, the Delta Exploration Company, Inc. case, the Delta Pipeline, LLC case, the DLC, Inc. case, the CEC, Inc. case, the Castle Texas Production Limited Partnership case and the Castle Exploration Company, Inc. case. The Court approved the Order for Joint Administration and the cases are jointly administered under the caption In re Delta Petroleum Corporation, Case No. 11-14006.

On December 27, 2011, the Debtors filed a motion (the “Sale Motion”) pursuant to Sections 105, 363, and 365 of the Bankruptcy Code for an order authorizing the sale, free and clear of all liens, claims and encumbrances and for the assumption and assignment of executory contracts. The Sale Motion requested an order to approve bid procedures, approves form and manner of notice of the sales, approval of the form and manner of notice of the assumption and assignment including any cure amounts of executory contracts and unexpired leases, establishment of a sale auction date, establishment of a sale hearing date and grants of related relief. On January 11, 2012, the Bankruptcy Court issued an order approving these matters. On March 20, 2012, Delta announced that it was seeking court approval to amend the bidding procedures for its upcoming auction. On March 22, 2012, the Bankruptcy Court approved the revised procedures.

F-8

DELTA PETROLEUM CORPORATION AND SUBSIDIARIES

(Debtor in Possession)

Notes to Consolidated Financial Statements

December 31, 2011, 2010 and 2009

(2) Reorganization under Chapter 11, Continued

On May 8, 2012, the Debtors obtained approval from the bankruptcy court to select Laramie Energy II, LLC (“Laramie”) as the sponsor of a plan of reorganization. Delta entered into a non-binding term sheet describing a transaction by which Laramie and Delta intend to form a new joint venture, to be called Piceance Energy LLC (“Piceance Energy”). The assets of Piceance Energy are anticipated to consist of both Laramie’s and Delta’s current Piceance Basin assets. Piceance Energy would be owned 66.66% by Laramie and 33.34% by a newly reorganized Delta Petroleum (“Reorganized Delta”). In addition to the 33.34% membership interest, Piceance Energy would distribute $75 million to Reorganized Delta to be used to pay bankruptcy expenses and to repay secured debt. Reorganized Delta would retain its interest in the Point Arguello unit of offshore California and other miscellaneous assets and certain tax attributes, and may retain its interest in Amber depending on how Amber’s Chapter 11 bankruptcy proceedings and claims reconciliation are resolved. Based upon the Plan as confirmed by the Bankruptcy Court, the common stock of Reorganized Delta would be owned by Delta’s creditors, and Delta’s current shareholders would not receive any consideration under the Plan.

Under the Plan, Delta’s priority non-tax claims and secured claims will be unimpaired in accordance with section 1124(1) of the Bankruptcy Code. Each general unsecured claim and noteholder claims will receive its pro-rata share of new common stock of Par Petroleum in full satisfaction of its claims.

The deadline for the submission of most claims in the Company’s bankruptcy case expired on March 23, 2012. Total claims submitted against the Company amounted to $3,694 million including duplicate claims filed against each entity, unsupported claims, and other adjustments, netting to a reconciled claim total of approximately $350.5 million.

(3) Going Concern

The Company is operating pursuant to Chapter 11 of the Bankruptcy Code and its continuation as a going concern is contingent upon, among other things, its ability to consummate the transactions under the Plan. These matters create substantial doubt about the Company’s ability to continue as a going concern. The accompanying financial statements do not reflect any adjustments relating to the recoverability of assets and the classification of liabilities that might result from the outcome of these uncertainties. In addition, the Plan could materially change the amounts and classifications reported in the consolidated financial statements which do not give effect to any adjustments to the carrying values of assets or amounts of liabilities that might be necessary as a consequence of consummation of the transactions under the Plan.

As a result of the Chapter 11 Cases, the realization of assets and the satisfaction of liabilities are subject to uncertainty. While operating as debtors-in-possession under Chapter 11, the Company may sell or otherwise dispose of or liquidate assets or settle liabilities, subject to the approval of the Bankruptcy Court or as otherwise permitted in the ordinary course of business (and subject to restrictions contained in the DIP Credit Agreement), in amounts other than those reflected in the accompanying consolidated financial statements. Further, a plan of reorganization could materially change the amounts and classifications in the historical consolidated financial statements. The accompanying consolidated financial statements do not include any direct adjustments related to the recoverability and classification of assets or the amounts and classification of liabilities or any other adjustments that might be necessary should the Company be unable to continue as a going concern or as a consequence of the Chapter 11 Cases.

The Reorganizations Topic of the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (the “ASC”), which is applicable to companies in Chapter 11, generally does not change the manner in which financial statements are prepared. However, it does require that the financial statements for periods subsequent to the filing of the Chapter 11 Cases distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Amounts that can be directly associated with the reorganization and restructuring of the business must be reported separately as reorganization items in the statements of operations beginning in the quarter ending December 31, 2011. The balance sheet must distinguish pre-petition liabilities subject to compromise from both those pre-petition liabilities that are not subject to compromise and from post-petition liabilities. Liabilities that may be affected by a plan of reorganization must be reported at the amounts expected to be allowed, even if they may be settled for lesser amounts. In addition, cash provided by and used for reorganization items must be disclosed separately. The Company has applied the Reorganizations Topic of the ASC 852 effective as of the Petition Date (as defined herein), and has segregated those items as outlined above for all reporting periods subsequent to such date.

F-9

DELTA PETROLEUM CORPORATION AND SUBSIDIARIES

(Debtor in Possession)

Notes to Consolidated Financial Statements

December 31, 2011, 2010 and 2009

(4) Summary of Significant Accounting Policies

Principles of Consolidation and Basis of Presentation

The consolidated financial statements include the accounts of Delta and its consolidated subsidiaries (collectively, the “Company”). All inter-company balances and transactions have been eliminated in consolidation. Certain of the Company’s oil and gas activities are conducted through partnerships and joint ventures, including CRB Partners, LLC (“CRBP”) and through the date of the Wapiti Transaction, PGR Partners, LLC (“PGR”). The Company includes its proportionate share of assets, liabilities, revenues and expenses from these entities in its consolidated financial statements. The Company does not have any off-balance sheet financing arrangements (other than operating leases) or any unconsolidated special purpose entities.

Until November 2011, the Company owned a 49.8% interest in DHS Drilling Company (“DHS”), an affiliated Colorado corporation that is headquartered in Casper, Wyoming. Delta representatives constituted a majority of the members of the Board of DHS and Delta had the right to use all of the rigs owned by DHS on a priority basis and, accordingly, DHS was consolidated in these financial statements until we disposed of DHS in 2011. During the second quarter of 2006, DHS engaged in a reorganization transaction pursuant to which it became a subsidiary of DHS Holding Company, a Delaware corporation, and the Company’s ownership interest became an interest in DHS Holding Company. References to DHS include both DHS Holding Company and DHS, unless the context otherwise requires.

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

Certain reclassifications have been made to amounts reported in the previous periods to conform to the current presentation. Among other items, revenues and expenses on certain oil and gas properties and DHS that were sold during the year ended December 31, 2011 have been reclassified from continuing operations to discontinued operations for all periods presented. In addition, the assets and liabilities of DHS have been separately reflected in the accompanying 2010 consolidated balance sheet as assets held for sale and liabilities related to assets held for sale. Such reclassifications had no effect on net loss (See Note 6, “Discontinued Operations”).

Cash Equivalents

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

F-10

DELTA PETROLEUM CORPORATION AND SUBSIDIARIES

(Debtor in Possession)

Notes to Consolidated Financial Statements

December 31, 2011, 2010 and 2009

(4) Summary of Significant Accounting Policies, Continued

Marketable Securities

During 2009, marketable securities were sold for proceeds of $2.0 million and the Company recorded a gain of $52,000. During 2010, all remaining marketable securities were sold for proceeds of $300,000 resulting in a gain of $300,000, as the carrying value had been fully impaired in 2008. The Company had no marketable securities transactions in 2011.

Inventories

Inventories consist of pipe and other production equipment not yet in use. Inventories are stated at the lower of cost (principally first-in, first-out) or estimated net realizable value. During 2008, the Company pre-ordered and stockpiled significant amounts of tubing, casing and pipe inventory to ensure availability for its then aggressive Piceance Basin and Paradox Basin drilling programs. Subsequently, with significantly lower commodity prices resulting in significant reductions in drilling capital expenditures and delays to drilling plans and with continued declines in steel prices, particularly during the second quarter of 2009, the value of these inventories declined. As a result, during 2009, the Company recorded an impairment of $4.3 million to the carrying value of its inventories, which is reflected in the accompanying consolidated statement of operations for the year ended December 31, 2009 as a component of dry hole costs and impairments.

Non-Controlling Interest

Non-controlling interest represents the 50.2% (47.2% for Chesapeake Energy Corporation and 3% for DHS executive officers and management) investors of DHS until its sale in November 2011.

Revenue Recognition

Oil and Gas

Revenues are recognized when title to the products transfers to the purchaser. The Company follows the “sales method” of accounting for its natural gas and crude oil revenue, so that the Company recognizes sales revenue on all natural gas or crude oil sold to its purchasers, regardless of whether the sales are proportionate to the Company’s ownership in the property. A liability is recognized only to the extent that the Company has an imbalance on a specific property greater than the expected remaining proved reserves. As of the years ended December 31, 2011 and 2010, the Company’s aggregate natural gas and crude oil imbalances were not material to its consolidated financial statements.

F-11

DELTA PETROLEUM CORPORATION AND SUBSIDIARIES

(Debtor in Possession)

Notes to Consolidated Financial Statements

December 31, 2011, 2010 and 2009

(4) Summary of Significant Accounting Policies, Continued

Property and Equipment

The Company accounts for its natural gas and crude oil exploration and development activities under the successful efforts method of accounting. Under such method, costs of productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized. Oil and gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological or geophysical expenses and delay rentals for gas and oil leases, are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but evaluated quarterly and 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 are computed on the units-of-production method by individual fields as the related proved reserves are produced.

Gathering systems and other property and equipment are recorded at cost and depreciated using the straight-line method over their estimated useful lives ranging from three to 40 years.

Depreciation, depletion, amortization and accretion of oil and gas property and equipment for the years ended December 31, 2011, 2010 and 2009 were $39.1 million, $46.9 million, and $57.1 million, respectively.

Impairment of Long-Lived Assets

Long-lived assets are 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. For proved properties, 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 are permanent and may not be restored in the future.

The Company assesses proved properties on an individual field basis for impairment on at least an annual basis. For proved 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.

F-12

DELTA PETROLEUM CORPORATION AND SUBSIDIARIES

(Debtor in Possession)

Notes to Consolidated Financial Statements

December 31, 2011, 2010 and 2009

(4) Summary of Significant Accounting Policies, Continued

During the year ended December 31, 2011, the Company evaluated the fair value of its properties based on market indicators in conjunction with the progression of the strategic alternatives evaluation process. The Company has not received any definitive offer with respect to an acquisition of the company or its assets that implies a value of the assets that is greater than the Company’s aggregate indebtedness. As a result, the Company recorded an impairment during the quarter ended September 30, 2011 of $239.8 million to its Vega area proved properties.

For the twelve months ended 2010, the expected future undiscounted cash flows of the assets exceeded the carrying value of the corresponding asset and as such no impairment provisions were recognized.

During the year ended December 31, 2009, the Company recorded impairments related to continuing operations attributable to proved properties totaling approximately $7.4 million primarily related to the Angleton field in Texas of $4.4 million and other miscellaneous fields of $3.0 million. The impairments resulted primarily from the significant decline in commodity pricing for most of 2009 causing downward revisions to proved reserves which led to impairments. These impairment provisions are included within loss from discontinued operations in the accompanying statements of operations for the year ended December 31, 2009.

For unproved properties, the need for an impairment charge is based on the Company’s plans for future development and other activities impacting the life of the property and the ability of the Company to recover its investment. When the Company believes the costs of the unproved property are no longer recoverable, an impairment charge is recorded based on the estimated fair value of the property.

As discussed above, the Company evaluated the fair value of its properties during the third quarter of 2011 based on market indicators in conjunction with the progression of the strategic alternatives evaluation process. As a result of such assessment, the Company recorded impairment provisions attributable to unproved properties of $159.6 million for the year ended December 31, 2011 which included $157.5 million to its Vega unproved leasehold and $2.1 million to its Vega area surface acreage.

In 2010, the Company recorded impairment provisions attributable to unproved properties of $42.4 million for the year ended December 31, 2010 which primarily included $13.2 million related to the Company’s Columbia River Basin leasehold, $6.2 million related to the Company’s Hingeline leasehold, $3.8 million related to the Company’s Haynesville leasehold, $4.0 million related to the Company’s Delores River leasehold, $1.6 million related to the Company’s non-operated Garden Gulch leasehold, and $661,000 related to the Company’s Howard Ranch leasehold. These impairment provisions are included within loss from discontinued operations in the accompanying statements of operations for the year ended December 31, 2010.

The Company also recorded impairments of $20.5 million to its Vega area gathering system and facilities during the year ended December 31, 2011. In 2010, The Company recorded impairments of $6.7 million related to the produced water handling facility in Vega, and $4.9 million to reduce the Paradox pipeline carrying value to its estimated fair value. These impairment provisions are included within dry hole costs and impairments in the accompanying statements of operations for the years ended December 31, 2011 and 2010. These impairments generally resulted from the lack of success in marketing these non-core assets combined with our lack of plans to develop the acreage.

As a result of such assessment, the Company recorded impairment provisions attributable to unproved properties of $123.5 million for the year ended December 31, 2009, including $38.6 million related to the Company’s non-operated Piceance leasehold in Garden Gulch, $27.5 million related to leasehold in the Haynesville Shale, $21.4 million related to the Company’s Columbia River Basin leasehold due to a dry hole drilled on this acreage, $14.8 million related to leasehold in Lighthouse Bayou, $8.3 million primarily associated with the Company’s development plans for certain Gulf Coast properties and near-term expiring leases not expected to be renewed, and $2.4 million related to expired and expiring acreage in the Newton field. These impairment provisions are included within loss from discontinued operations in the accompanying statements of operations for the year ended December 31, 2009.

F-13

DELTA PETROLEUM CORPORATION AND SUBSIDIARIES

(Debtor in Possession)

Notes to Consolidated Financial Statements

December 31, 2011, 2010 and 2009

(4) Summary of Significant Accounting Policies, Continued

In addition, the Company recorded an impairment of $10.5 million to reduce the Company’s Vega area surface land carrying value to its estimated fair value. These impairments are included within dry hole costs and impairments in the accompanying statement of operations for the year ended December 31, 2009. These impairments generally resulted from sustained lower commodity prices for most of 2009, near term expiring leasehold, unsuccessful drilling results, or our inability to meet contractual drilling obligations.

At December 31, 2011 the Company’s oil and gas assets were classified as held for use and no impairment charges resulted from the analysis performed at December 31, 2011 as the estimated undiscounted net cash flows exceeded carrying amounts for all properties. Subsequent to the end of the reporting period, in August 2012, the Bankruptcy Court approved a plan of sale of substantially all of the Company’s assets and accordingly these assets will be classified as held for sale in reporting periods subsequent to June 30, 2012 and will be subject to a material write-down to fair value at that time. The Company’s assets may be further adjusted in the future due to the outcome of the Chapter 11 Cases or the application of “fresh start” accounting upon the Company’s emergence from Chapter 11.

Asset Retirement Obligations

The Company’s asset retirement obligations arise from the plugging and abandonment liabilities for its oil and gas wells. The Company has no obligation to provide for the retirement of most of its offshore properties as the obligations remained with the seller from whom the Company acquired the properties. The following is a reconciliation of the Company’s asset retirement obligations for the years ended December 31, 2011, 2010 and 2009:

	Years Ended December 31,
	2011			2010			2009
	(In thousands)
Asset retirement obligation – January 1	$	5,146		$	10,539		$	8,737
Reclassification for assets held for sale		(1,215	)		—			—
Adjusted asset retirement obligation – January 1		3,931			10,539			8,737
Accretion expense		273			445			517
Change in estimate		(135	)		(252	)		465
Obligations incurred (from new wells)		385			382			1,908
Obligation assumed		—			—			375
Obligations settled		(296	)		(1,532	)		(564	)
Obligations on sold properties		(359	)		(4,436	)		(899	)
Asset retirement obligation – end of period		3,799			5,146			10,539
Less: Current asset retirement obligation		(292	)		(1,217	)		(2,885	)
Long-term asset retirement obligation	$	3,507		$	3929		$	7,654

Financial Instruments

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 transactions is to provide a measure of stability to the Company’s cash flows in an environment of volatile oil and gas prices. The Company has not elected hedge accounting and recognizes mark-to-market gains and losses in earnings currently. See Note 10, “Commodity Derivative Instruments” for additional information.

Executive Severance Agreements

On May 26, 2009, the Company’s then Chairman of the Board of Directors and Chief Executive Officer, Roger A. Parker, resigned from the Company. In conjunction with Mr. Parker’s resignation, Delta entered into a severance agreement, effective as of the close of business on May 26, 2009, whereby Mr. Parker resigned from his positions as Chairman of the Board, Chief Executive Officer and as a director of Delta, as well as his positions as a director, officer and employee of Delta’s subsidiaries. In consideration for Mr. Parker’s resignation and his agreement to (a) relinquish all his rights under his employment agreement, his change-in-control agreement, certain stock agreements, bonuses relating to past and pending transactions benefiting Delta, and any other interests he might claim arising from his efforts as Chairman of the Company’s Board of Directors and/or Chief Executive Officer, and (b) stay on as a consultant to facilitate an orderly transition and to assist in certain pending transactions, the Company agreed to pay Mr. Parker $4.7 million in cash (the “Cash Consideration”), issue to him 100,000 shares of Delta common stock (the “Shares”), pay him the aggregate of any accrued unpaid salary, vacation days and reimbursement of his reasonable business expenses incurred through the effective date of the agreement, and provide to him insurance benefits similar to his pre-resignation benefits for a thirty-six month period. The Severance Agreement also contains mutual releases and non-disparagement provisions, as well as other customary terms.

F-14

DELTA PETROLEUM CORPORATION AND SUBSIDIARIES

(Debtor in Possession)

Notes to Consolidated Financial Statements

December 31, 2011, 2010 and 2009

(4) Summary of Significant Accounting Policies, Continued

The table below summarizes the total executive severance expense included in the accompanying statements of operations for the year ended December 31, 2009 (in thousands):

Cash consideration – immediately available funds	$	1,812
Cash consideration – rabbi trust		2,888
Stock consideration – rabbi trust		1,700
Subtotal		6,400
Performance shares forfeited		(2,293	)
Retention stock forfeited		(525	)
Health, medical and other benefits payable		75
Legal costs and other expenses		82
Total executive severance expense	$	3,739

In accordance with the terms of the severance agreement, Mr. Parker received a portion of the cash consideration in immediately available funds, and the remaining cash consideration and the shares were deposited in a rabbi trust which was then distributed to Mr. Parker on or about November 27, 2009. The assets of the rabbi trust were required to be consolidated into the financial statements of the Company as such assets were subject to the claims of the Company’s creditors under federal and state law. Stock consideration deposited into the rabbi trust was reflected as treasury stock valued at the market value of the common shares on the date of issuance in the accompanying consolidated balance sheet of the Company, with an offsetting amount recorded as executive severance payable in common stock included as a component of stockholders’ equity.

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

The table below summarizes the total executive severance expense included in the accompanying statements of operations for the year ended December 31, 2010 (in thousands):

Cash consideration – immediately available funds	$	1,600
Performance shares forfeited		(2,274	)
Total executive severance expense (benefit)	$	(674	)

Equity compensation costs previously recorded in the consolidated financial statements related to performance shares forfeited prior to their derived service period and retention stock forfeited prior to vesting as a result of the severance agreements for Mr. Parker and Mr. Wallace were reversed and reflected as a reduction of executive severance expense.

F-15

DELTA PETROLEUM CORPORATION AND SUBSIDIARIES

(Debtor in Possession)

Notes to Consolidated Financial Statements

December 31, 2011, 2010 and 2009

(4) Summary of Significant Accounting Policies, Continued

Stock Based Compensation

The Company recognizes the cost of share based payments over the period the employee provides service and includes such costs in general and administrative expense in the statements of operations.

Income (Loss) from Unconsolidated Affiliates

Income (loss) from unconsolidated affiliates includes the Company’s share of earnings or losses from equity method investments. In addition, during 2009, the Company recognized impairments to the carrying value of its investment in Delta Oilfield Tank Company (“DOTC”) of $3.3 million to reduce the carrying value of the Company’s investment in DOTC to zero. The impairments were precipitated by DOTC’s increasing losses during 2009 compared to prior periods and deterioration of its operating results compared to its budgeted results. During 2009, the Company engaged third party investment advisers to assist in evaluating strategic alternatives relating to the Company’s investment in DOTC. Subsequently, a planned transaction did not occur and the remaining equity carrying value was reduced to zero. As a result of these events, the Company also recorded a bad debt reserve of $5.0 million to reduce the carrying value of the Company’s note receivable from DOTC to the amount estimated to be collectible.

At December 31, 2009, the Company owned a 5% interest in Collbran Valley Gas Gathering, LLC (“CVGG”) which operates a pipeline in the Piceance Basin through which the Company transports its produced gas to the sales point. In early 2010, the Company divested of this interest for cash proceeds of $3.5 million, plus an additional $2.0 million of proceeds contingent on volume deliveries through the CVGG system of Delta gas between January 1, 2010 and June 30, 2011. Based on current production levels, the Company is not likely to earn the contingent consideration without the initiation of a continuous drilling program which could only be undertaken with additional funding beyond the Company’s existing capital resources. As a result of this transaction, the Company recorded an impairment during the year ended December 31, 2009 of its investment in CVGG of $1.4 million to reduce the carrying value to its fair value.

In addition, during the quarter ended December 31, 2009, the Company recognized an impairment of the carrying value of its investment in Ally Equipment Company, LLC (“Ally”) of $3.4 million, which reduced the carrying value of the Company’s investment in Ally to approximately $1.0 million. The impairment was precipitated by Ally’s increasing losses during the year ended 2009 compared to prior periods and the outlook for 2010.

The Company also recorded an impairment of $917,000 to write-off its carrying value in the entity that was expected to operate the Paradox pipeline as other plans related to the future of the entity did not materialize during the second quarter of 2009. These impairments are included within income (loss) from unconsolidated affiliates in the accompanying statement of operations for the year ended December 31, 2009.

In September 2010, the Company sold its 50% interest in Ally for $1.5 million, including $250,000 received during the third quarter, $250,000 received in January 2011 and four remaining $250,000 quarterly installments to be paid each quarter end commencing on March 31, 2011. The Company recognized a loss of $522,000 on the transaction which is included as a component of income (loss) from unconsolidated affiliates for the year ended December 31, 2010.

In December 2010, the Company sold its 50% interest in DOTC for $4.9 million, including $2.8 million received in 2010, with the remaining $2.1 million due in equal monthly installments of $29,500 for 72 months commencing in February 2011. The Company recognized a gain of $676,000 on the transaction which is included as a component of income (loss) from unconsolidated affiliates for the year ended December 31, 2010.

F-16

DELTA PETROLEUM CORPORATION AND SUBSIDIARIES

(Debtor in Possession)

Notes to Consolidated Financial Statements

December 31, 2011, 2010 and 2009

(4) Summary of Significant Accounting Policies, Continued

Non-Qualified Stock Options—Directors and Employees

On December 22, 2009, the stockholders approved the Company’s 2009 Performance and Equity Plan (the “2009 Plan”). Subject to adjustment as provided in the 2009 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 2009 Plan, may not in the aggregate exceed 3 million. The 2009 Plan supplements the Company’s 1993, 2001, 2004 and 2007 Incentive Plans. The purpose of the 2009 Plan is to provide incentives to selected employees and directors of the Company and its subsidiaries, and selected non-employee consultants and advisors to the Company and its subsidiaries, who contribute and are expected to contribute to the Company’s success.

Incentive awards under the 2009 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.

Income Taxes

The Company uses the asset and liability method of 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. 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. The realizability of deferred tax assets is evaluated based on a “more likely than not” standard, and to the extent this threshold is not met, a valuation allowance is recorded.

Income (Loss) per Common Share

Basic income (loss) per share is computed by dividing net income (loss) attributed to common stock by the weighted average number of common shares outstanding during each period, excluding treasury shares. Diluted income (loss) per share is computed by adjusting the average number of common shares outstanding for the dilutive effect, if any, of convertible preferred stock, convertible debt, stock options, restricted stock and warrants. (See Note 15, “Earnings Per Share”).

Major Customers

During the year ended December 31, 2011, customer A and customer B accounted individually for 56% and 19%, respectively, of the Company’s total oil and gas sales. During the year ended December 31, 2010, customer A and customer B accounted individually for 45% and 18%, respectively, of the Company’s total oil and gas sales. During the year ended December 31, 2009, customer A and customer C individually accounted for 37% and 19%, respectively, of the Company’s total oil and gas sales.

Use of Estimates

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

F-17

DELTA PETROLEUM CORPORATION AND SUBSIDIARIES

(Debtor in Possession)

Notes to Consolidated Financial Statements

December 31, 2011, 2010 and 2009

(5) Oil and Gas Properties

Unproved Undeveloped Offshore California Properties

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

Year Ended December 31, 2009 – Divestitures

During the fourth quarter of 2009, in a series of transactions the Company divested certain non-operated properties in North Dakota, Alabama, California, Colorado, Louisiana, North Dakota, Oklahoma, Texas, and Wyoming. Proceeds were $4.7 million and a loss of $2.1 million was recorded as a component of gain on offshore litigation and property sales, net, in the accompanying consolidated statement of operations. Minimal production and reserves were attributable to the properties.

(6) Discontinued Operations

During the third quarter of 2010, the Company closed a transaction with Wapiti (the “2010 Wapiti Transaction”), selling all or a portion of the Company’s interest in various non-core assets primarily located in Colorado, Texas, and Wyoming for gross proceeds of $130.0 million. During the second quarter of 2011, the Company closed the 2011 Wapiti Transaction, selling the remaining portion of its interests in non-core assets primarily located in Texas and Wyoming for gross cash proceeds of approximately $43.2 million. On October 31, 2011, Delta sold its stock, representing a 49.8% ownership interest, in DHS Drilling to DHS Drilling’s lender, LCPI, for $500,000. In accordance with accounting standards, the results of operations relating to these properties have been reflected as discontinued operations for all periods presented. In addition, the assets and liabilities related to the oil and gas properties in the 2011 Wapiti Transaction have been separately reflected in the accompanying consolidated balance sheet as of December 31, 2010 as assets held for sale and liabilities related to assets held for sale. In separate transactions in 2010, the Company sold its interest in the Howard Ranch field and the Laurel Ridge field and has included these properties in discontinued operations as well.

F-18

DELTA PETROLEUM CORPORATION AND SUBSIDIARIES

(Debtor in Possession)

Notes to Consolidated Financial Statements

December 31, 2011, 2010 and 2009

(6) Discontinued Operations, Continued

The following table shows the oil and gas segment and drilling segment revenues and expenses included in discontinued operations as described above for the years ended December 31, 2011, 2010 and 2009 (in thousands):

	Years Ended
	2011								2010									2009
	Oil & Gas		Drilling			Total			Oil & Gas			Drilling			Total			Oil & Gas			Drilling			Total
Revenues:
Oil and gas sales	$	10,276	$	—		$	10,276		$	42,321		$	—		$	42,321		$	52,446		$	—		$	52,446
Contract drilling and trucking fees		—		45,241			45,241			—			53,212			53,212			—			13,680			13,680
Total Revenues		10,276		45,241			55,517			42,321			53,212			95,533			52,446			13,680			66,126
Operating Expenses:
Lease operating expense		2,481		—			2,481			9,691			—			9,691			13,560			—			13,560
Transportation expense		16		—			16			1,810			—			1,810			2,288			—			2,288
Production taxes		370		—			370			2,142			—			2,142			2,296			—			2,296
Dry hole costs and impairments(1)		608		—			608			98,372			—			98,372			172,466			—			172,466
Depreciation, depletion, amortization and accretion – oil and gas		2,796		—			2,796			25,227			—			25,227			51,403			—			51,403
Drilling and trucking operating expenses		—		35,617			35,617			—			42,248			42,248			—			15,293			15,293
Goodwill and drilling equipment impairments(2)		—		—			—			—			—			—			—			6,508			6,508
Depreciation and amortization – drilling and trucking		—		2,669			2,669			—			19,964			19,964			—			22,917			22,917
General and administrative expense		—		3,014			3,014			—			5,736			5,736			—			4,130			4,130
Total operating expenses		6,272		41,300			47,571			137,242			67,948			205,190			242,013			48,848			290,861
Other income and (expense):
Interest expense and financing costs, net		—		(6,911	)		(6,911	)		—			(7,079	)		(7,079	)		—			(8,983	)		(8,983	)
Other income (expense)		—		2,734			2,734			—			(1,583	)		(1,583	)		—			1,119			1,119
Total other income and (expense)		—		(4,177	)		(4,177	)		—			(7,863	)		(8,662	)		(8,662	)		(7,864	)		(7,864	)
Income (loss) from discontinued operations		4,004		(236	)		3,768			(94,920	)		(23,398	)		(118,318	)		(189,567	)		(43,032	)		(232,599	)
Income tax expense		1,724		—			1,724			—			—			—			—			—			—
Income (loss) from results of operations of discontinued operations, net of tax		2,280		(236	)		2,044			(94,920	)		(23,398	)		(118,318	)		(189,567	)		(43,032	)		(232,599	)
Gain on sales of discontinued operations(3)		6,874		5,176			12,050			28,978			—			28,978			—			—			—
Income (loss) from results of operations and sale of discontinued operations, net of tax	$	9,154	$	4,940		$	14,094		$	(65,942	)	$	(23,398	)	$	(89,340	)	$	(189,567	)	$	(43,032	)	$	(232,599	)

⁽¹⁾  Dry Hole Costs and Impairments. In 2011 we recorded impairments on the Columbia River, Greentown and Gulf Coast properties of $491,000 prior their sale. In accordance with accounting standards, the impairment loss relating to certain properties held for sale at June 30, 2010 in conjunction with the 2010 Wapiti Transaction were reflected as discontinued operations. During 2009, we recorded impairments on the Angleton, Newton, Opossum Hollow, Garden Gulch, Columbia River, Haynesville, Golden Prairie, Howard Ranch and Laurel Ridge fields of $139 million, as a result of the significant decline in commodity pricing for most of 2009 causing downward revision to proved reserves. We incurred dry hole costs of approximately $33.6 million for the year ended December 31, 2009 primarily related to our Columbia River Basin exploratory well (the Gray Well) in Washington.

⁽²⁾  Goodwill and Drilling Equipment Impairments. During the second quarter 2009 we concluded that DHS spare equipment required impairments of approximately $6.5 million.

⁽³⁾  Gain on Sales of Discontinued Operations – Oil and Gas. During the second quarter of 2011, the Company closed the 2011 Wapiti Transaction, selling the remaining portion of its interests in non-core assets primarily located in Texas and Wyoming for gross cash proceeds of approximately $43.2 million and a net gain of approximately $8.9 million. On July 23, 2010, we entered into a definitive Purchase and Sale Agreement with Wapiti to sell all or a portion of our interest in various non-core assets primarily located in Colorado, Texas, and Wyoming for gross cash proceeds of $130.0 million resulting in a net loss of $66.5 million (including impairment losses of $96.2 million). For financial reporting purposes, a $4.0 million impairment loss is included within dry hole costs and impairments in continuing operations, $92.2 million of impairments are included within loss from discontinued operations, and a $29.7 million gain on sale is included in gain on sale of discontinued operations. During 2010, we also sold our Howard Ranch properties for $550,000, recognizing a loss on the sale of $687,000. Drilling- During the fourth quarter 2011 we sold all of our stock in DHS drilling at a net gain of approximately $ 5.2 million.

F-19

DELTA PETROLEUM CORPORATION AND SUBSIDIARIES

(Debtor in Possession)

Notes to Consolidated Financial Statements

December 31, 2011, 2010 and 2009

(7) Fair Value Measurements

The Company follows accounting guidance which defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and requires additional disclosures about fair value measurements. As required, the Company applied the following fair value hierarchy:

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

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

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

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

Derivative liabilities consist of future oil and gas commodity swap contracts valued using both quoted prices for identically traded contracts and observable market data for similar contracts (NYMEX WTI oil, NYMEX Henry Hub gas and CIG gas swaps – Level 2).

Proved property impairments—The fair values of the proved properties are estimated using internal discounted cash flow calculations based upon the Company’s estimates of reserves and are considered to be level three fair value measurements.

Asset retirement obligations—The initial fair values of the asset retirement obligations are estimated using internal discounted cash flow calculations based upon the Company’s asset retirement obligations, including revisions of the estimated fair values in 2010 and 2009.

The following table lists the Company’s fair value measurements by hierarchy as of December 31, 2011 (in thousands):

Assets (Liabilities)	Quoted Prices in Active  Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total December 31, 2011
Recurring
Derivative liabilities	$	—	$	—	$	—	$	—

The following table lists the Company’s fair value measurements by hierarchy as of December 31, 2010 (in thousands):

Assets (Liabilities)	Quoted Prices in Active  Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total December 31, 2010
Recurring
Derivative liabilities	$	—	$	(2,993	)	$	—	$	(2,993	)

F-20

DELTA PETROLEUM CORPORATION AND SUBSIDIARIES

(Debtor in Possession)

Notes to Consolidated Financial Statements

December 31, 2011, 2010 and 2009

(8) Liabilities Subject to Compromise

As a result of the Chapter 11 Filings, the payment of prepetition indebtedness may be subject to compromise or other treatment under the Debtors’ Plan. Generally, actions to enforce or otherwise effect payment of prepetition liabilities are stayed. Refer to Note 2, Reorganization Under Chapter 11. Although prepetition claims are generally stayed, at hearings held in December 2011, the Court granted approval for the Company to pay prepetition fixed, liquidated and undisputed claims of certain suppliers of materials, goods and services which whom the Company continues to do business and whose goods and services are essential to the continued operations of the Company.

The Debtors have been paying and intend to continue to pay undisputed postpetition claims in the ordinary course of business. In addition, the Debtors may reject prepetition executory contracts and unexpired leases with respect to the Debtors’ operations, with the approval of the Court. Damages resulting from rejection of executory contracts and unexpired leases are treated as general unsecured claims and will be classified as liabilities subject to compromise.

ASC 852 requires prepetition liabilities that are subject to compromise to be reported at the amounts expected to be allowed, even if they may be settled for lesser amounts. The amounts currently classified as liabilities subject to compromise may be subject to future adjustments depending on Court actions, further developments with respect to disputed claims, determinations of the secured status of certain claims, the values of any collateral securing such claims, or other events.

	December 31, 2011
Liabilities subject to compromise consist of the following:
Senior notes payable	$	115,000,000
Convertible notes payable		150,000,000
Accounts payable and accrued expenses		20,536,000
Total liabilities subject to compromise	$	285,536,000

(9) Debt

Debtor in Possession Credit Agreement

On December 21, 2011, the Company entered into a senior secured debtor-in-possession credit facility (the “DIP Credit Facility”) in December 2011 in connection with the bankruptcy filing. Up to $57.5 million may be borrowed under the DIP Credit Facility, of which approximately $45 million was initially drawn by the Company to repay all amounts outstanding under the previous Credit Agreement, which was then terminated. The DIP credit facility was amended in March 2012 to increase the maximum borrowing capacity by $1.4 million to $58.9 million. All of the loans under the DIP Credit Facility are term loans. The interest rate under the DIP Credit Facility is 13% plus 6% per annum in payment-in-kind interest. The initial maturity date of the DIP Credit Facility was June 30, 2012. The Company has subsequently entered into a series of forbearance agreements extending maturity date to August 30, 2012 As of December 31, 2011 $45.0 million in borrowings and $74,000 in accrued PIK interest were outstanding under the facility.

The Company is the borrower under the DIP Credit Facility and certain of its wholly-owned subsidiaries are guarantors of the Company’s obligations thereunder. Borrowings under the DIP Credit Facility are secured by substantially all of the assets of the Company and the guarantors. The DIP Credit Facility includes certain covenants relating to the bankruptcy process and other operational and financial covenants, including covenants that limit the Company’s ability to (or to permit any subsidiaries to) (i) merge with other companies; (ii) create liens on its property; (iii) incur additional indebtedness; (iv) enter into transactions with affiliates, except on an arms-length basis; (v) enter into sale leaseback transactions; (vi) pay dividends or make certain other restricted payments; (vii) make certain investments; or (viii) sell its assets.

F-21

DELTA PETROLEUM CORPORATION AND SUBSIDIARIES

(Debtor in Possession)

Notes to Consolidated Financial Statements

December 31, 2011, 2010 and 2009

(9) Debt, Continued

7% Senior Unsecured Notes

On March 15, 2005, the Company issued 7% senior unsecured notes for an aggregate amount of $150.0 million which pay interest semi-annually on April 1 and October 1 and mature in 2015 (the “Senior Notes”). The Senior Notes were issued at 99.50% of par and the associated discount is being amortized to interest expense over their term. The indenture governing the Senior Notes contains various restrictive covenants that may limit the Company’s ability to, among other things, incur additional indebtedness, make certain investments, sell assets, consolidate, merge or transfer all or substantially all of its assets and the assets of its restricted subsidiaries. These covenants may limit management’s discretion in operating the Company’s business. In addition, in the event that a Change of Control should occur (as such term is defined in the indenture), each holder of the Senior Notes would have the right to require the Company to repurchase all or any part of such holder’s notes at a purchase price in cash equal to 101% of the principal amount of the notes plus accrued and unpaid interest, if any, to the date of purchase. The bankruptcy filing constituted an event of default on the notes resulting in all principal, interest and other amounts due relating to the Notes becoming immediately due and payable. The notes are reported in liabilities subject to compromise at December 31, 2011.

3 ³/₄% Senior Convertible Notes

On April 25, 2007, the Company issued $115.0 million aggregate principal amount of 3 ³/₄% Senior Convertible Notes due 2037 (the “Notes”) for net proceeds of $111.6 million after underwriters’ discounts and commissions of approximately $3.4 million. The bankruptcy filing constituted an event of default on the notes resulting in all principal, interest and other amounts due relating to the Notes becoming immediately due and payable. The notes are reported in liabilities subject to compromise at December 31, 2011.

The Notes bear interest at a rate of 3 ³/₄% per annum, payable semi-annually in arrears, on May 1 and November 1 of each year, beginning November 1, 2007. The Notes mature on May 1, 2037 unless earlier converted, redeemed or repurchased, but each holder of Notes had the option to require the Company to purchase any outstanding Notes on each of May 1, 2012, May 1, 2017, May 1, 2022, May 1, 2027 and May 1, 2032 at a price which is required to be paid in cash, equal to 100% of the principal amount of the Notes to be purchased. The Notes are convertible at the holder’s option, in whole or in part, at an initial conversion rate of 3.296 shares of common stock per $1,000 principal amount of Notes at any time prior to the close of business on the business day immediately preceding the final maturity date of the Notes, subject to prior repurchase of the Notes.

In the event that a fundamental change occurs (as defined in the Indenture, but generally including a tender offer for a majority of the Company’s securities, an acquisition by anyone of 50% or more of the Company’s stock, a change in the majority of the Company’s Board of Directors, the approval of a plan of liquidation or being delisted from a national securities exchange), each holder of Notes would have the right to require the Company to purchase all or a portion of its Notes for the price specified in the Indenture. In addition, following certain fundamental changes that occur prior to maturity, the Company will increase the conversion rate for a holder who elects to convert its Notes in connection with such fundamental changes by a number of additional shares of common stock. Also, the Company is not permitted to consolidate with or merge with or into, or convey, transfer, sell, lease or dispose of all or substantially all of its assets unless the successor company meets certain requirements and assumes all of the Company’s obligations under the Notes. If as a result of such transaction, the Notes become convertible into common stock or other securities issued by another issuer, the other issuer must fully and unconditionally guarantee all of the Company’s obligations under the Notes. Although the Notes do not contain any financial covenants, the Notes contain covenants that require the Company to properly make payments of principal and interest, provide certain reports, certificates and notices to the trustee under various circumstances, cause its wholly-owned subsidiaries to become guarantors of the debt, maintain an office or agency where the Notes may be presented or surrendered for payment, continue the Company’s corporate existence, pay taxes and other claims, and not seek protection from the debt under any applicable usury laws.

F-22

DELTA PETROLEUM CORPORATION AND SUBSIDIARIES

(Debtor in Possession)

Notes to Consolidated Financial Statements

December 31, 2011, 2010 and 2009

(9) Debt, Continued

Pre-Petition Credit Facility

On December 29, 2010, the Company entered into the Third Amended and Restated Credit Agreement (the “MBL Credit Agreement”), with Macquarie Bank Limited (“MBL”), as administrative agent and issuing lender. The MBL Credit Agreement provided for a revolving loan and a term loan each with a maturity date of January 31, 2012. The revolving loan had an initial borrowing base of $30.0 million and stated interest at prime plus 6% per annum for prime rate advances and LIBOR plus 7% per annum for LIBOR advances. The borrowing base for the revolving loan was subject to a semi-annual re-determination based on reserve reports as of each January 1 and July 1 as reported by the Company to MBL on or before each April 1 and October 1, respectively. At December 31, 2010, $29.1 million was outstanding under the revolving loan. The term loan had an initial commitment of $20.0 million subject to a development plan that must be approved by MBL. Advances under the term loan bore interest at prime plus 8% per annum for prime rate advances and LIBOR plus 9% for LIBOR advances. At December 31, 2010, no amounts had been borrowed under the term loan. The revolving loan and the term loan were subject to quarterly financial covenants, in each case as defined in the MBL Credit Agreement and described in summary here, including maintenance of a minimum current ratio of 1:1, minimum quarterly net operating cash flow of $8.6 million, and maximum quarterly general and administrative expenses (excluding equity based compensation) of $5.0 million. At December 31, 2010, the Company was in compliance with its financial covenants under the MBL Credit Agreement.

On March 14, 2011, the Company entered into an amendment to the MBL Credit Agreement that increased the availability under the term loan at the time from $6.2 million to $25.0 million, and did not require repayments of the term loan until the January 2012 maturity date. Specifically, among other changes, the amendment provided for an increase in the term loan commitment from $20.0 million to $25.0 million and removed the requirement that advances under the term loan be subject to approval of a development plan. In addition, so long as Delta was not in default under the MBL Credit Agreement, Delta was not required to comply with certain cash management provisions, including the previous requirement to repay any term loan advances outstanding on a monthly basis with 100% of net operating cash flows. As a result of the amendment, amounts outstanding under the term loan bore interest at prime plus 9.5% through September 30, 2011 and prime plus 11.0% thereafter for prime rate advances and at LIBOR plus 10.5% for LIBOR advances through September 30, 2011 and LIBOR plus 12% thereafter for LIBOR advances. This loan was paid off by the Debtor in Possession financing agreement in December 2011. Borrowings under the MBL Credit Agreement were $29.1 million at December 31, 2010.

Prior to the MBL Credit Agreement, on July 23, 2010, the Company entered into the Fourth Amendment to the Second Amended and Restated Credit Agreement, with JPMorgan Chase Bank, N.A., as agent, and certain of the financial institutions that were party to this credit agreement in which, among other changes, the requisite lenders consented to the Wapiti Transaction, subject to specified terms and conditions, including that the net proceeds from the transaction be used to pay down the balance outstanding under the credit facility and that the borrowing base be reduced to $35.0 million upon consummation of the Wapiti Transaction.

On April 26, 2010, the Company entered into the Third Amendment to the Second Amended and Restated Credit Agreement with JPMorgan Chase Bank, N.A., as agent, and certain of the financial institutions that were party to this credit agreement in which, among other changes, the borrowing base was reduced from $185.0 million with a $20.0 million required minimum availability to $145.0 million with no required minimum availability for a net reduction in the borrowing base of $20.0 million.

Installment obligations

In 2008, the Company closed a transaction with EnCana to jointly develop a portion of EnCana’s leasehold interests in the Vega Area of the Piceance Basin. Under the terms of the agreement, the Company committed to fund $410.1 million, of which $110.5 million was paid at the closing, $99.6 million was paid on November 1, 2009, $100.0 million was paid on October 28, 2010, and $100.0 million was paid on November 1, 2011.

F-23

DELTA PETROLEUM CORPORATION AND SUBSIDIARIES

(Debtor in Possession)

Notes to Consolidated Financial Statements

December 31, 2011, 2010 and 2009

(9) Debt, Continued

The installment payment obligations were recorded in the accompanying consolidated financial statements as current and long-term liabilities at a discounted value, initially of $280.1 million, based on an imputed interest rate of 2.58%. The discount was accreted on the effective interest method over the term of the installments, including accretion of $2.1 million, $4.6 million and $7.0 million for the years ended December 31, 2011, 2010 and 2009, respectively.

Credit Facility – DHS

On April 1, 2010, DHS amended its existing credit facility with LCPI and renegotiated certain terms of the agreement including obtaining waivers for all covenant violations through March 31, 2010. The terms of the amended agreement required principal payments of approximately $7.7 million paid on April 1, 2010 and $2.0 million paid on each of May 1, 2010, August 1, 2010 and November 1, 2010, with a remaining $2.0 million principal payment due on January 1, 2011, and a $5.0 million principal payment due on each of April 1, 2011 and July 1, 2011 with the remaining balance of approximately $57.6 million due at maturity (August 31, 2011). On October 31, 2011, Delta sold its stock in DHS to DHS’s lender, LCPI, for $500,000 in consideration relieving the Company of further obligations under the DHS note.

(10) Stockholders’ Equity

The Plan, if consummated, will result in the cancellation of the shares held by our current shareholders.

Preferred Stock

The Company has 3.0 million shares of preferred stock authorized, par value $0.01 per share, issuable from time to time in one or more series. As of December 31, 2011 and 2010, no preferred stock was outstanding. As part of the reincorporation on January 31, 2006, the Company reduced the par value of its preferred stock to $0.01 per share.

Common Stock

On July 12, 2011, the shareholders of the Company approved a one-for-ten reverse split of the common stock of the Company which became effective on July 13, 2011. All references in these financial statements to the number of common shares or options, price per share and weighted average number of common shares outstanding prior to the 1:10 reverse stock split have been adjusted to reflect this stock split on a retroactive basis, unless otherwise noted.

Also on July 12, 2011, the shareholders of the Company approved an amendment to the Company’s Amended and Restated Certificate of Incorporation to reduce the number of authorized shares of common stock to 200,000,000 from 600,000,000 shares. Presentation of authorized shares of common stock and basic and diluted loss per share has been adjusted on a retroactive basis.

The Company has 200.0 million shares of common stock authorized, par value $0.01 per share, issuable at the discretion of the Company’s Board of Directors. As of December 31, 2011 and 2010, there were 28.8 million and 28.5 million shares issued and outstanding, respectively, not counting shares that are held as treasury shares.

On February 20, 2008, the Company issued 3.6 million shares of the Company’s common stock to Tracinda Corporation at $190.00 per share for net proceeds of $667.1 million (including a $5.0 million deposit on the transaction received in December 2007), representing approximately 35% of the Company’s outstanding common stock at the time. In conjunction with the transaction, a finder’s fee of 26,316 shares of common stock valued at $5.0 million based on the transaction’s $190.00 per share price was issued to an unrelated third party.

Subsequent to this initial transaction, Tracinda acquired additional shares in the open market and participated in the May 2009 equity offering, described below. As a result, Tracinda currently owns approximately 33% of the Company’s outstanding common stock.

On May 13, 2009, the Company completed an underwritten offering of 1.72 million shares of the Company’s common stock at $15.00 per share for net proceeds of $246.9 million, net of underwriting commissions and related offering expenses.

F-24

DELTA PETROLEUM CORPORATION AND SUBSIDIARIES

(Debtor in Possession)

Notes to Consolidated Financial Statements

December 31, 2011, 2010 and 2009

(10) Stockholders’ Equity, Continued

On December 22, 2009, the Company granted 570,000 shares of non-vested restricted stock to employees of the Company. The shares vested in equal thirds on July 1, 2010, 2011, and 2012. In conjunction with the resignation of the Company’s former Chairman and Chief Executive Officer, 100,000 shares of common stock were issued pursuant to a severance agreement more fully described in Note 3, “Summary of Significant Accounting Policies – Executive Severance Agreements”.

During the year ended December 31, 2011, the Company issued 98,800 fully vested shares to the non-employee members of the Board of Directors in consideration for their service on the Board for the year ended December 31, 2010 and 10,808 fully vested shares to resigning non-employee members of the Board of Directors for their past services. The Company also and also granted 489,228 shares of non-vested restricted stock to certain employees.

During the year ended December 31, 2010, the Company issued 48,078 fully vested shares to the non-employee members of the Board of Directors in consideration for their service on the Board for the year ended December 31, 2009 and also granted 510,000 shares of non-vested restricted stock which vests in full on July 1, 2011 to certain employees.

Treasury Stock

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

Non-Qualified Stock Options—Directors and Employees

On December 22, 2009, the stockholders approved the Company’s 2009 Performance and Equity Plan (the “2009 Plan”). Subject to adjustment as provided in the 2009 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 2009 Plan, may not in the aggregate exceed 3 million. The 2009 Plan supplements the Company’s 1993, 2001, 2004 and 2007 Incentive Plans. The purpose of the 2009 Plan is to provide incentives to selected employees and directors of the Company and its subsidiaries, and selected non-employee consultants and advisors to the Company and its subsidiaries, who contribute and are expected to contribute to the Company’s success.

Incentive awards under the 2009 Plan may include non-qualified or incentive stock options, limited appreciation rights, tandem stock appreciation rights, phantom stock, stock bonuses or cash bonuses. Options issued to date under the Company’s various incentive plans have been non-qualified stock options as defined in such plans.

F-25

DELTA PETROLEUM CORPORATION AND SUBSIDIARIES

(Debtor in Possession)

Notes to Consolidated Financial Statements

December 31, 2011, 2010 and 2009

(10) 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, 2011 follows:

	Year Ended
	December 31, 2011
				Weighted-Average			Weighted-Average		Aggregate
				Exercise			Remaining Contractual		Intrinsic
	Options			Price			Term		Value
Outstanding-beginning of year		160,800		$	72.60
Granted		—			—
Exercised		—			—
Expired		(10,500	)		(38.96	)
Outstanding-end of year		150,300		$	75.00			2.64 years		—
Exercisable-end of year		150,300		$	75.00			2.64 years		—

The Company recognizes the cost of share based payments over the period during which the employee provides service. Exercise prices for options outstanding under the Company’s various plans as of December 31, 2011 ranged from $7.96 to $153.40 per share and the weighted-average remaining contractual life of those options was 3.25 years. During 2010, 25,000 fully vested options were issued with an exercise price of $7.90 per share and $109,000 of related stock based compensation expense was recorded. No options were granted during the years ended December 31, 2009 and 2008. The total intrinsic value of options exercised during the years ended December 31, 2011, 2010 and 2009, were zero, zero, and zero million, respectively.

A summary of the restricted stock (nonvested stock) activity under the Company’s plan and related information for the year ended December 31, 2011 follows:

	Year Ended
	December 31, 2011
				Weighted-Average			Weighted-Average		Aggregate
	Nonvested			Grant-Date			Remaining Contractual		Intrinsic
	Stock			Fair Value			Term		Value
Nonvested-beginning of year		734,376		$	15.27
Granted		598,836			5.92
Vested		(719,350	)		(11.74	)
Expired / Forfeited		(55,561	)		(36.22	)
Nonvested-end of year		558,301		$	7.45			0.48 years	$	3,307,291

Stock Based Compensation

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

	Years Ended December 31,
	2011		2010		2009
Stock options	$	—	$	109	$	—
Non-vested stock		7,754		10,399		7,541
Performance shares		249		959		2,420
Total	$	8,003	$	11,467	$	9,961

The total grant date fair value of restricted stock vested during the years ended December 31, 2011, 2010, and 2009 was $8.4 million, $9.0 million and $12.7 million, respectively.

F-26

DELTA PETROLEUM CORPORATION AND SUBSIDIARIES

(Debtor in Possession)

Notes to Consolidated Financial Statements

December 31, 2011, 2010 and 2009

(10) Stockholders’ Equity, Continued

At December 31, 2011, 2010 and 2009 the total unrecognized compensation cost related to the non-vested portion of restricted stock and stock options was $2.0 million, $6.3 million and $16.5 million which is expected to be recognized over a weighted average period of 0.48, 0.88 and 2.33 years, respectively.

Cash received from exercises under all share-based payment arrangements for the years ended December 31, 2011, 2010 and 2009 was zero, zero, and zero, respectively. There were no tax benefits realized from the stock options exercised during the years ended December 31, 2011, 2010 and 2009. During the years ended December 31, 2011, 2010 and 2009 zero, zero, and zero, respectively, of tax benefits were generated from the exercise of stock options; however, such benefit will not be recognized in stockholders’ equity until the period in which these amounts decrease current taxes payable.

(11) Employee Benefits

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

For the years ended December 31, 2011, 2010 and 2009, the Company expensed zero, zero and $49,000, respectively, related to its profit sharing plan.

The Company adopted a 401(k) plan effective May 1, 2005. All employees are eligible to participate and make employee contributions once they have met the plan’s eligibility criteria. Under the 401(k) plan, the Company’s employees make salary reduction contributions in accordance with the Internal Revenue Service guidelines. The Company’s matching contribution is an amount equal to 100% of the employee’s elective deferral contribution which cannot exceed 3% of the employee’s compensation, and 50% of the employee’s elective deferral which exceeds 3% of the employee’s compensation but does not exceed 5% of the employee’s compensation. The expense recognized in relation to the Company’s 401(k) plan was $176,000, $292,000 and $165,000 in 2011, 2010 and 2009, respectively. The 401(k) matching contribution was suspended in April 2009, but was subsequently reinstated January 1, 2010.

(12) Commodity Derivative Instruments

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 and predictability to the Company’s future revenues and cash flows in an environment of volatile oil and gas prices. All transactions are accounted for in accordance with requirements of applicable FASB guidance. The Company recognizes mark-to-market gains and losses in current earnings.

At December 31, 2011, the Company did not have any outstanding derivative contracts.

At December 31, 2010, all of the Company’s outstanding derivative contracts were fixed price swaps. Under the swap agreements, the Company receives the fixed price and pays the floating index price. The Company’s swaps are settled in cash on a monthly basis. By entering into swaps, the Company effectively fixes the price that it will receive for the hedged production.

F-27

DELTA PETROLEUM CORPORATION AND SUBSIDIARIES

(Debtor in Possession)

Notes to Consolidated Financial Statements

December 31, 2011, 2010 and 2009

(12) Commodity Derivative Instruments, Continued

The following table summarizes the Company’s open derivative contracts at December 31, 2010:

								Net Fair Value
								Asset (Liability) at
Commodity	Volume			Fixed Price		Term	Index Price	December 31, 2010
								(In thousands)
Crude oil		500	Bbls / Day	$	57.70	Jan ’ 11 - Dec ’ 11	NYMEX – WTI		(5,946	)
Crude oil		116	Bbls / Day	$	91.05	Jan ’ 11 - Dec ’ 11	NYMEX – WTI		(70	)
Crude oil		497	Bbls / Day	$	91.05	Jan ’ 12 - Dec ’ 12	NYMEX – WTI		(408	)
Crude oil		396	Bbls / Day	$	91.05	Jan ’ 13 - Dec ’ 13	NYMEX – WTI		(181	)
Natural gas		12,000	MMBtu / Day	$	5.150	Jan ’ 11 - Dec ’ 11	CIG		4,337
Natural gas		3,253	MMBtu / Day	$	5.040	Jan ’ 11 - Dec ’ 11	CIG		1,047
Natural gas		347	MMBtu / Day	$	4.440	Jan ’ 11 - Dec ’ 11	CIG		58
Natural gas		12,052	MMBtu / Day	$	4.440	Jan ’ 12 - Dec ’ 12	CIG		(771	)
Natural gas		10,301	MMBtu / Day	$	4.440	Jan ’ 13 - Dec ’ 13	CIG		(1,059	)
Total								$	(2,993	)

The following table summarizes the fair values and location in the Company’s consolidated balance sheet of all derivatives held by the Company as of December 31, 2010 (in thousands):

Derivatives Not Designated as
Hedging Instruments	Balance Sheet Classification	Fair Value
Liabilities
Commodity Swaps	Derivative Instruments – Current Liabilities, net	$	(574	)
Commodity Swaps	Derivative Instruments – Long-Term Liabilities, net		(2,419	)
Total		$	(2,993	)

The following table summarizes the realized and unrealized losses and the classification in the consolidated statement of operations of derivatives not designated as hedging instruments for the year ended December 31, 2010 (in thousands):

		Amount of Gain
Derivatives Not Designated as	Location of Gain (Loss) Recognized in	(Loss) Recognized in
Hedging Instruments	Income on Derivatives	Income on Derivatives
Commodity Swaps	Realized Loss on Derivative Instruments, net – Other   Income and (Expense)	$	(5,835	)
Commodity Swaps	Unrealized Gain on Derivative Instruments, net – Other   Income and (Expense)	$	23,979
Total		$	18,144

F-28

DELTA PETROLEUM CORPORATION AND SUBSIDIARIES

(Debtor in Possession)

Notes to Consolidated Financial Statements

December 31, 2011, 2010 and 2009

The following table summarizes the realized and unrealized losses and the classification in the consolidated statement of operations of derivatives not designated as hedging instruments for the year ended December 31, 2011 (in thousands):

		Amount of Gain
Derivatives Not Designated as	Location of Gain (Loss) Recognized in	(Loss) Recognized in
Hedging Instruments	Income on Derivatives	Income on Derivatives
Commodity Swaps	Realized Loss on Derivative Instruments, net – Other   Income and (Expense)	$	(3,368	)
Commodity Swaps	Unrealized Gain on Derivative Instruments, net – Other   Income and (Expense)	$	2,993
Total		$	375

The net gains (losses) from all hedging activities recognized in the Company’s statements of operations were $(375,000), $18.1 million, and ($28.1 million) for the years ended December 31, 2011, 2010 and 2009, respectively. All derivative contracts were settled prior to the end of 2011.

F-29

DELTA PETROLEUM CORPORATION AND SUBSIDIARIES

(Debtor in Possession)

Notes to Consolidated Financial Statements

December 31, 2011, 2010 and 2009

(13) Income Taxes

The Company accounts for income taxes in accordance with the provisions of ASC 740, “Accounting for Income Taxes.” Income tax expense (benefit) attributable to income from continuing operations consisted of the following for the years ended December 31, 2011, 2010 and 2009:

	Years Ended December 31,
	2011			2010			2009
	(In thousands)
Current:
U.S. - Federal	$	—		$	(67	)	$	—
U.S. - State		—			—			—
Foreign		—			—			—
Deferred:
U.S. - Federal		(4,329	)		580			190
U.S. - State		—			30			25
Total	$	(4,329	)	$	543		$	215

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:

	Years Ended December 31,
	2011			2010			2009
Federal statutory rate		(35.0	)%		(35.0	)%		(35.0	)%
State income taxes, net of federal benefit		(1.9	)		(1.9	)		(1.9	)
Change in valuation allowance		34.3			33.2			35.3
Other		1.8			4.2			1.7
Actual income tax rate		0.8	%		0.5	%		0.1	%

For the year ended December 31, 2011, we recorded a tax benefit of $5.0 million due to a non-cash income tax benefit related to gains from discontinued oil and gas operations. Generally accepted accounting principles, or GAAP, require all items be considered, including items recorded in discontinued operations, in determining the amount of tax benefit that results from a loss from continuing operations that should be allocated to continuing operations. In accordance with GAAP, we recorded a tax benefit on our loss from continuing operations, which was exactly offset by income tax expense on discontinued operations.

F-30

DELTA PETROLEUM CORPORATION AND SUBSIDIARIES

(Debtor in Possession)

Notes to Consolidated Financial Statements

December 31, 2011, 2010 and 2009

(13) Income Taxes, Continued

Deferred tax assets (liabilities) are comprised of the following at December 31, 2011 and 2010 (in thousands):

	2011			2010
Deferred tax assets:
Net operating loss	$	450,632		$	314,480
Capital loss carry forwards		35,919			27,964
Asset retirement obligation		1,398			1,896
Percentage depletion		—			73
Property and equipment		39,912			72,529
Equity compensation		10,448			7,912
Equity investments		329			3,669
Derivative instruments		—			1,102
Minimum tax credit		1,045			1,152
Contribution carryforwards		517			517
Accrued bonuses		517			832
Allowance for doubtful accounts		93			856
Accrued vacation		125			85
Other		69			5
Total deferred tax assets		541,004			433,072
Valuation allowance		(540,724	)		(417,236	)
Net deferred tax assets	$	280		$	15,836
Deferred tax liabilities:
Property and equipment	$	—		$	(15,484	)
Prepaid insurance, marketable securities and other		280			(352	)
Total deferred tax liabilities	$	280		$	15,836

The Company has net operating loss carryovers as of December 31, 2011 of $1,274 million for federal income tax purposes and $1,244 million for financial reporting purposes. The difference of $30 million relates to tax deductions for compensation expense for financial reporting purposes for which the benefit will not be recognized until the related deductions reduce taxes payable.

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future results of operations, and tax planning strategies in making this assessment. Based upon the level of historical taxable income, significant book losses during the year ended December 31, 2011, and projections for future results of operations over the periods in which the deferred tax assets are deductible, among other factors, management concluded during the second quarter of 2007 and continues to conclude that the Company does not meet the “more likely than not” requirement of ASC 740 in order to recognize deferred tax assets. Accordingly, for the year ended December 31, 2011, the Company recorded in income tax expense a valuation allowance of $123.4 million offsetting the Company’s deferred tax assets.

F-31

DELTA PETROLEUM CORPORATION AND SUBSIDIARIES

(Debtor in Possession)

Notes to Consolidated Financial Statements

December 31, 2011, 2010 and 2009

(13) Income Taxes, Continued

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

2012	$	994
2013		868
2014		3,132
2015		106
2016		6,916
2017 and thereafter		1,262,862
Total	$	1,274,878

If not utilized, the tax net operating loss carryforwards will expire during the period 2012 through 2031.

Effective January 1, 2007, the Company adopted applicable provisions of ASC 740 to recognize, measure, and disclose uncertain tax positions in the financial statements. Under ASC 740, tax positions must meet a “more-likely-than-not” recognition threshold at the effective date to be recognized upon the adoption and in subsequent periods. During the year ended December 31, 2011, no adjustments were recognized for uncertain tax benefits.

The Company recognizes interest and penalties related to uncertain tax positions in income tax (benefit)/expense. No interest and penalties related to uncertain tax positions were accrued as of December 31, 2011.

The tax years 2008 through 2011 for federal returns and 2007 through 2011 for state returns remain open to examination by the major taxing jurisdictions in which the Company operates.

(14) Related Party Transactions

Transactions with Directors, Officers and Affiliates

During fiscal 2001 and 2000, Mr. Larson and Mr. Parker, officers of the Company at the time, guaranteed certain borrowings which have subsequently been repaid. As consideration for the guarantee of the Company’s indebtedness, each officer was assigned a 1% overriding royalty interest (“ORRI”) in the properties acquired with the proceeds of the borrowings. Each of Mr. Larson and Mr. Parker earned approximately $113,000, $91,000 and $67,000 for their respective 1% ORRI during the years ended December 31, 2011, 2010 and 2009, respectively. In addition, in December 1999, Mr. Larson and Mr. Parker, officers of the Company at the time, guaranteed certain other borrowings which have subsequently been repaid, the proceeds of which were utilized by the Company to purchase interests in certain Offshore California leases that later became the subject of litigation with the United States. As consideration for the guarantee of the Company’s indebtedness, each officer was assigned a 1% overriding royalty interest in the properties acquired with the proceeds of the borrowings, as well as a 1% overriding royalty interest in compensation received for the properties from the United States. Because the Company received payments from the United States with respect to these leases as a result of the conclusion of its Offshore California litigation (See Note 15, “Commitments and Contingencies”), each of Mr. Larson and Mr. Parker received approximately $814,341 during the year ended December 31, 2009 pursuant to the terms of his agreement with the Company. As a result of the litigation, the Company no longer owns any interest in the Offshore California leases.

During May 2009, subsequent to receipt of the offshore litigation award related to the Amber Case, the Company purchased for $26.0 million contingent payment rights previously sold to Tracinda Corporation for $25.0 million that entitled Tracinda to receive up to $27.9 million of the litigation proceeds related to the Amber Case.

F-32

DELTA PETROLEUM CORPORATION AND SUBSIDIARIES

(Debtor in Possession)

Notes to Consolidated Financial Statements

December 31, 2011, 2010 and 2009

(14) Related Party Transactions, Continued

Accounts Receivable Related Parties

At December 31, 2011 and 2010, the Company had $13,000 and $14,000 of receivables from related parties, respectively. These amounts include drilling costs and lease operating expenses on wells owned by the related parties and operated by the Company.

(15) Earnings Per Share

The following table sets forth the computation of basic and diluted earnings per share (in thousands, except per share amounts):

	Years Ended December 31,
	2011			2010			2009
Net loss attributable to Delta common stockholders	$	(470,111	)	$	(182,332	)	$	(328,783	)
Basic weighted-average shares outstanding		28,841			27,504			21,103
Add: dilutive effects of stock options and unvested stock grants		—			—			—
Diluted weighted-average common shares outstanding		28,841			27,504			21,103
Basic net loss per common share	$	(16.30	)	$	(6.63	)	$	(15.58	)
Diluted net loss per common share	$	(16.30	)	$	(6.63	)	$	(15.58	)

Potentially dilutive securities excluded from the calculation of diluted shares outstanding include the following (in thousands):

	Years Ended December 31,
	2011		2010		2009
Stock issuable upon conversion of convertible notes		379		379		379
Stock options		150		161		143
Non-vested restricted stock		558		734		717
Total potentially dilutive securities		1,087		1,274		1,239

F-33

DELTA PETROLEUM CORPORATION AND SUBSIDIARIES

(Debtor in Possession)

Notes to Consolidated Financial Statements

December 31, 2011, 2010 and 2009

(16) Guarantor Financial Information

On March 15, 2005, Delta issued $150.0 million of 7% Senior Notes (“Senior Notes”) that mature in 2015. In addition, on April 25, 2007, the Company issued $115.0 million of 3 ³/₄% Convertible Senior Notes due in 2037 (“Convertible Notes”). On December 21, 2011, the Company entered into a senior secured debtor-in-possession credit facility (the “DIP Credit Facility”) in December 2011 in connection with the bankruptcy filing. The DIP Credit Facility, Senior Notes and the Convertible Notes are guaranteed by all of the Company’s other wholly-owned subsidiaries (“Guarantors”). Each of the Guarantors, fully, jointly and severally, irrevocably and unconditionally guarantees the performance and payment when due of all the obligations under the DIP Credit Facility, Senior Notes and the Convertible Notes. CRBP, PGR, and Amber (“Non-guarantors”) are not guarantors of the indebtedness under the Senior Notes or the Convertible Notes.

The following financial information sets forth the Company’s condensed consolidated balance sheets as of December 31, 2011, and 2010, the condensed consolidated statements of operations for the years ended December 31, 2011, 2010 and 2009, and the condensed consolidated statements of cash flows for the years ended December 31, 2011, 2010 and 2009 (in thousands). For purposes of the condensed financial information presented below, the equity in the earnings or losses of subsidiaries is not recorded in the financial statements of the issuer.

Condensed Consolidated Balance Sheet

December 31, 2011

				Guarantor		Non-Guarantor		Adjustments/
	Issuer			Subsidiaries		Subsidiaries		Eliminations			Consolidated
Current assets	$	22,354		$	88	$	906	$	—		$	23,348
Property and equipment:
Oil and gas properties		741,387			—		19,215					760,602
Other		73,007			2,560		—		—			75,567
Total property and equipment		814,394			2,560		19,215					836,169
Accumulated depletion, depreciation and amortization		(475,609	)		—		—		—			(475,609	)
Net property and equipment		338,785			2,560		19,215		—			360,560
Investment in subsidiaries		4,154			—		—		(4,154	)		—
Other long-term assets		1,582			2,407		—		—			3,989
Total assets	$	366,875		$	5,055	$	20,121	$	(4,154	)	$	387,897
Liabilities not subject to compromise:	$	48,625		$	—	$	4	$	—		$	48,629
Liabilities subject to compromise		283,732			1,804							285,536
Long-term liabilities
Asset retirement obligation and other liabilities		3,507			—		—		—			3,507
Total liabilities		335,864			1,804		4		—			337,672
Total Delta stockholders’ equity		31,010			3,251		20,118		(4,154	)		50,225
Total equity		31,010			3.251		20,118		(4,154	)		50,225
Total liabilities and equity	$	366,874		$	5,055	$	20,122	$	(4,154	)	$	387,897

F-34

DELTA PETROLEUM CORPORATION AND SUBSIDIARIES

(Debtor in Possession)

Notes to Consolidated Financial Statements

December 31, 2011, 2010 and 2009

(16) Guarantor Financial Information, Continued

Condensed Consolidated Statement of Operations

Year Ended December 31, 2011

				Guarantor			Non-Guarantor			Adjustments/
	Issuer			Subsidiaries			Subsidiaries			Eliminations		Consolidated
Total revenue	$	63,880		$	—		$	—		$	—	$	63,880
Operating expenses:
Oil and gas expense		29,140			17			—			—		29,157
Exploration expense		338			—			—			—		338
Dry hole costs and impairments		419,083			1,319			—			—		420,402
Depreciation and depletion		39,088			—			—			—		39,088
General and administrative		27,742			299			83			—		28,124
Total operating expenses		515,391			1,635			83			—		517,109
Operating loss		(451,511	)		(1,635	)		(83	)		—		(453,229	)
Other income and expenses		(34,265	)		31			(68	)		—		(34,302	)
Reorganization costs		(932	)		—			—			—		(932	)
Income tax expense		4,329			—			—			—		4,329
Discontinued operations		14,330			—			(236	)		—		14,094
Net loss		(468,049	)		(1,604	)		(387	)		—		(470,040	)
Less gain attributable to non-controlling interest		—			—			(71	)		—		(71	)
Net loss attributable to Delta common stockholders	$	(468,049	)	$	(1,604	)	$	(458	)	$	—	$	(470,111	)

Condensed Consolidated Statement of Cash Flows

Year Ended December 31, 2011

				Guarantor		Non-Guarantor
	Issuer			Subsidiaries		Subsidiaries			Consolidated
Cash provided by (used in):
Operating activities	$	1,050		$	16	$	(76	)	$	990
Investing activities		87,649			—		—			87,649
Financing activities		(89,974	)		—		7			(89,967	)
Net decrease in cash and cash equivalents		(1,275	)		16		(69	)		(1,328	)
Cash at beginning of the period		13,154			61		975			14,190
Cash at the end of the period	$	11,879		$	77	$	906		$	12,862

F-35

DELTA PETROLEUM CORPORATION AND SUBSIDIARIES

(Debtor in Possession)

Notes to Consolidated Financial Statements

December 31, 2011, 2010 and 2009

December 31, 2010

				Guarantor			Non-Guarantor		Adjustments/
	Issuer			Subsidiaries			Subsidiaries		Eliminations			Consolidated
Current assets	$	164,377		$	322		$	75,069	$	—		$	239,768
Property and equipment:
Oil and gas properties		881,887			—			19,215		(118	)		900,984
Other		74,437			32,677			—		—			107,114
Total property and equipment		956,324			32,677			19,215		(118	)		1,008,098
Accumulated depletion, depreciation and amortization		(203,731	)		(28,762	)		—		—			(232,493	)
Net property and equipment		752,593			3,915			19,215		(118	)		775,605
Investment in subsidiaries		1,156			—			—		(1,156	)		—
Other long-term assets		6,332			2,407			—		—			8,739
Total assets	$	924,458		$	6,644		$	94,284	$	(1,274	)	$	1,024,112
Current liabilities	$	138,375		$	(26	)	$	81,633	$	—		$	219,982
Long-term liabilities
Long-term debt, derivative instruments and deferred taxes		288,025			1,801			—		—			289,826
Asset retirement obligation and other liabilities		2,709			—			—		—			2,709
Total long-term liabilities		290,734			1,801			—		—			292,535
Total Delta stockholders’ equity		498,201			4,869			12,651		(1,274	)		514,447
Non-controlling interest		(2,852	)		—			—		—			(2,852	)
Total equity		495,349			4,869			12,651		(1,274	)		511,595
Total liabilities and equity	$	924,458		$	6,644		$	94,284	$	(1,274	)	$	1,024,112

F-36

DELTA PETROLEUM CORPORATION AND SUBSIDIARIES

(Debtor in Possession)

Notes to Consolidated Financial Statements

December 31, 2011, 2010 and 2009

(16) Guarantor Financial Information, Continued

Condensed Consolidated Statement of Operations

Year Ended December 31, 2010

				Guarantor			Non-Guarantor			Adjustments/
	Issuer			Subsidiaries			Subsidiaries			Eliminations		Consolidated
Total revenue	$	60,919		$	77		$	—		$	—	$	60,996
Operating expenses:
Oil and gas expense		34,715			—			—			—		34,715
Exploration expense		1,337			—			—			—		1,337
Dry hole costs and impairments		31,882			4,894			586			—		37,362
Depreciation and depletion		46,879			2			—			—		46,881
General and administrative		35,221			54			119			—		35,394
Executive severance expense		(674	)		—			—			—		(674	)
Total operating expenses		149,360			4,950			705			—		155,015
Operating loss		(88,441	)		(4,873	)		(705	)		—		(94,019	)
Other income and expenses		(10,152	)		34			6			—		(10,112	)
Income tax expense		(543	)		—			—			—		(543	)
Discontinued operations		27,049			(133	)		(116,256	)		—		(89,340	)
Net loss		(72,087	)		(4,972	)		(116,955	)		—		(194,014	)
Less loss attributable to non-controlling interest		11,682			—			—			—		11,682
Net loss attributable to Delta common stockholders	$	(60,405	)	$	(4,972	)	$	(116,955	)	$	—	$	(182,332	)

Condensed Consolidated Statement of Cash Flows

Year Ended December 31, 2010

				Guarantor			Non-Guarantor
	Issuer			Subsidiaries			Subsidiaries			Consolidated
Cash provided by (used in):
Operating activities	$	(48,918	)	$	(635	)	$	16,552		$	(33,001	)
Investing activities		202,049			622			(4,833	)		197,838
Financing activities		(198,510	)		—			(14,055	)		(212,565	)
Net decrease in cash and cash equivalents		(45,379	)		(13	)		(2,336	)		(47,728	)
Cash at beginning of the period		58,533			74			3,311			61,918
Cash at the end of the period	$	13,154		$	61		$	975		$	14,190

F-37

DELTA PETROLEUM CORPORATION AND SUBSIDIARIES

(Debtor in Possession)

Notes to Consolidated Financial Statements

December 31, 2011, 2010 and 2009

(16) Guarantor Financial Information, Continued

Condensed Consolidated Statement of Operations

Year Ended December 31, 2009

				Guarantor			Non-Guarantor			Adjustments/
	Issuer			Subsidiaries			Subsidiaries			Eliminations		Consolidated
Total revenue	$	119,336		$	(3,020	)	$	—		$	—	$	116,316
Operating expenses:
Oil and gas expense		28,622			—			—			—		28,622
Exploration expense		2,604			—			—			—		2,604
Dry hole costs and impairments		14,710			1,896			—			—		16,606
Depreciation and depletion		56,878			223			1			—		57,102
General and administrative		37,114			75			95			—		37,284
Executive severance expense		3,739			—			—			—		3,739
Total operating expenses		143,667			2,194			96			—		145,957
Operating loss		(24,331	)		(5,214	)		(96	)		—		(29,641	)
Other expenses		(87,202	)		(33	)		6			—		(87,229	)
Income tax (expense) benefit		(215	)		—			—			—		(215	)
Discontinued operations		(179,391	)		110			(53,318	)		—		(232,599	)
Net loss		(291,139	)		(5,137	)		(53,408	)		—		(349,684	)
Less loss attributable to non-controlling interest		20,901			—			—			—		20,901
Net loss attributable to Delta common stockholders	$	(270,238	)	$	(5,137	)	$	(53,408	)	$	—	$	(328,783	)

Condensed Consolidated Statement of Cash Flows

Year Ended December 31, 2009

				Guarantor			Non-Guarantor
	Issuer			Subsidiaries			Subsidiaries			Consolidated
Cash provided by (used in):
Operating activities	$	79,428		$	(2,736	)	$	4,452		$	81,144
Investing activities		(53,980	)		2,659			3,954			(47,367	)
Financing activities		(26,838	)		—			(10,496	)		(37,334	)
Net decrease in cash and cash equivalents		(1,390	)		(77	)		(2,090	)		(3,557	)
Cash at beginning of the period		60,993			151			4,331			65,475
Cash at the end of the period	$	59,603		$	74		$	2,241		$	61,918

F-38

DELTA PETROLEUM CORPORATION AND SUBSIDIARIES

(Debtor in Possession)

Notes to Consolidated Financial Statements

December 31, 2011, 2010 and 2009

(17) Commitments and Contingencies

The Company leases office space in Denver, Colorado and certain other locations in the states in which the Company operates and also leases equipment and autos under non-cancelable operating leases. Rent expense for the years ended December 31, 2011, 2010 and 2009, was approximately $1.1 million, $1.1 million, and $1.7 million, respectively. The following table summarizes the future minimum payments under all non-cancelable operating lease obligations (in thousands):

2011		1,596
2012		1,444
2013		1,431
2014		1,490
2015		264
2016 and thereafter		682
Total	$	6,907

The Company had, as of December 31, 2011, agreements with its three executive officers which provide for severance payments equal to three times the average of the officer’s combined annual salary and bonus, benefits continuation and accelerated vesting of options and stock grants in the event that there is a change in control of the Company. These agreements were amended on December 29, 2010 to bring them into compliance with Section 409A of the Internal Revenue Code. These executory agreements were neither assumed nor rejected in Delta’s chapter 11 case, though two of them became nonexecutory upon the termination of the executives in question.

Offshore Litigation

On December 16, 2009 the Company entered into a settlement agreement with the United States of America with respect to its breach of contract claim against the United States in the case of Amber Resources Co., et al. v. United States, Civ. Act. No. 2-30 that was filed in the United States Court of Federal Claims with respect to Lease OCS P-452. On February 25, 2009, the Court of Federal Claims entered a judgment in the Company’s favor in the amount of $91.4 million with respect to its claim to recover lease bonus payments for Lease 452. On April 24, 2009, the government filed a notice of appeal of this judgment, but never filed an opening brief pending the outcome of settlement discussions. Under the terms of the settlement agreement the Company received gross proceeds of $65.0 million, which resulted in net proceeds to it of approximately $50.0 million after making all contingent payments to third parties. An order of dismissal was entered by the United States Court of Appeals for the Federal Circuit on January 12, 2010 which concluded the litigation.

The Company formerly owned a 2.41934% working interest in OCS Lease 320 in the Sword Unit, Offshore California, and Amber formerly owned a 0.97953% working interest in the same lease. Lease 320 was conveyed back to the United States at the conclusion of its previous litigation with the government (Amber Resources Co., et al. vs. United States, Civ. Act. No. 2-30 filed in the United States Court of Federal Claims) when the courts determined that the government had breached that lease (among others) and was liable to the working interest owners for damages; however, the government now contends that the former working interest owners are still obligated to permanently plug and abandon an exploratory well that was drilled on the lease and to clear the well site. The former operator of the lease commenced litigation against the government in United States District Court for the District of Columbia (Noble Energy Corp. vs. Kenneth L. Salazar, Secretary United States Department of the Interior, et al No. 1:09-cv-02013-EGS) seeking a declaratory judgment that the former working interest owners are not responsible for these costs as a result of the government’s breach of the lease. On April 22, 2011, the Court entered a judgment in favor of the government, ruling that the working interest owners jointly and severally share the responsibility to permanently plug and abandon the subject well, and that this duty was not discharged by the government’s breach of contract. On May 11, 2011, the former operator filed an appeal of this ruling to the United States Court of Appeals for the District of Columbia Circuit. The Court of Appeals did not rule in either party’s favor, but instead issued an order on March 2, 2012 vacating the judgment and sending the case back to the District Court with instructions to vacate the previous order by the government to permanently plug and abandon the well, and to remand the case to the Department of the Interior for a more extensive explanation as to why it interprets its regulations to require that the

F-39

DELTA PETROLEUM CORPORATION AND SUBSIDIARIES

(Debtor in Possession)

Notes to Consolidated Financial Statements

December 31, 2011, 2010 and 2009

(17) Commitments and Contingencies, Continued

former owners permanently plug and abandon the well notwithstanding the government’s breach of the lease. It is currently unknown whether or not the former operator will ultimately be successful in the litigation. In September 2011, however, the Company received an estimate from the operator indicating that, based on available information of resources to mobilize and demobilize a rig to the well, the Company’s pro rata share of the estimated cost of decommissioning the well would be approximately $756,000. The estimate that was provided does not contain any anticipated expenditures for the preparation of an environmental impact study, regulatory permitting matters at any level or any expenditure estimates for potentially required costs of containment equipment. The operator has indicated that the estimate is subject to material fluctuations in cost based upon rig mobilization costs and other factors. The actual costs of decommissioning the well could be materially different from the estimate provided by the operator. As a non-operator in this well the Company is unable to determine a reasonable estimate of the liability, if any, at this time. If the former working interest owners are ultimately held liable, it is likely that the former operator will assert that the Company is responsible for the payment of its proportionate share of the actual cost of any decommissioning operation, and the former operator has filed a claim in the Company’s bankruptcy case seeking reimbursement in such event. The Company believes that if the former operator’s claim is allowed, it would be treated as a pre-petition unsecured claim that would be dealt with as part of the plan of reorganization.

(18) 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, 2011
Total revenue	$	17,715		$	16,882		$	16,546		$	12,737
Loss from continuing operations before income taxes, discontinued operations and cumulative effect		(27,424	)		(12,724	)		(429,973	)		(17,411	)
Net loss		(27,841	)		(963	)		(429,430	)		(11,877	)
Net income (loss) per common share: (1)
Basic	$	(1.00	)	$	(.03	)	$	(15.40	)	$	(.43	)
Diluted	$	(1.00	)	$	(.03	)	$	(15.40	)	$	(.43	)
Year Ended December 31, 2010
Total revenue	$	19,050		$	14,581		$	12,522		$	14,740
Loss from continuing operations before income taxes, discontinued operations and cumulative effect		(7,795	)		(35,673	)		(11,747	)		(28,179	)
Net income (loss)		(12,797	)		(149,750	)		13,941			(33,726	)
Net income (loss) per common share: (1)
Basic	$	(0.46	)	$	(5.43	)	$	0.51		$	(1.23	)
Diluted	$	(0.46	)	$	(5.43	)	$	0.49		$	(1.23	)

⁽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

(Debtor in Possession)

Notes to Consolidated Financial Statements

December 31, 2011, 2010 and 2009

(19) Disclosures About Capitalized Costs, Costs Incurred (Unaudited)

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

	December 31,			December 31,			December 31,
	2011			2010			2009
Unproved properties	$	72,081		$	230,117		$	280,844
Proved properties		688,521			871,986			1,379,920
		760,602			1,102,103			1,660,764
Accumulated depreciation and depletion		(442,169	)		(360,577	)		(661,851	)
	$	318,433		$	741,526		$	998,913

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

	December 31,			December 31,		December 31,
	2011			2010		2009
Unproved property acquisition costs	$	452		$	909	$	2,083
Proved property acquisition costs		(51	)		—		—
Development costs incurred on proved undeveloped reserves		4,858			6,477		15,556
Development costs—other		39,980			35,883		43,892
Exploration and dry hole costs		98			1,423		36,216
Total	$	45,337		$	44,692	$	97,747

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

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

	Years Ended December 31,
	2011			2010		2009
Balance at beginning of year	$	6,200		$	—	$	13,812
Additions to capitalized exploratory well costs pending the determination of proved reserves		29,226			6,200		—
Exploratory well costs included in property divestitures		—			—		—
Reclassified to proved oil and gas properties based on the determination of proved reserves		(26,656	)		—		—
Capitalized exploratory well costs charged to dry hole expense					—		(13,812	)
Balance at end of year	$	8,770		$	6,200	$	—
Exploratory well costs capitalized for one year or less after after completion of drilling		8,770			6,200		—
Exploratory well costs capitalized for greater than one year after completion of drilling		—			—		—
Balance at end of year	$	8,770		$	6,200	$	—

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

During 2009, the Company declared its exploratory Columbia River Basin well a dry hole and accordingly, at December 31, 2009, the Company had no remaining capitalized exploratory well costs. During 2010, the Company spud a deep test well in the Vega area to explore the Company’s Piceance leasehold below the currently productive Williams Fork zone. Completion activities on the well began in February 2011.

F-41

DELTA PETROLEUM CORPORATION AND SUBSIDIARIES

(Debtor in Possession)

Notes to Consolidated Financial Statements

December 31, 2011, 2010 and 2009

(19) Disclosures About Capitalized Costs, Costs Incurred (Unaudited), Continued

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

	Years Ended December 31,
	2011			2010			2009
Revenue:
Oil and gas revenues	$	63,880		$	61,791		$	42,516
Expenses:
Production costs		29,157			34,715			28,623
Depletion and amortization		36,624			44,008			57,102
Exploration		338			1,337			2,604
Abandoned and impaired properties		419,851			37,362			16,606
Dry hole costs		355			—			—
Results of operations of oil and gas producing activities	$	(422,445	)	$	(55,631	)	$	(62,419	)
Income (loss) from operations of properties sold, net		2,280			(94,920	)		(189,567	)
Gain on sale of properties		6,874			28,978			—
Income (loss) from results of discontinued operations of oil and gas producing activities	$	9,154		$	(65,942	)	$	(189,567	)

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

There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. Crude oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be precisely measured. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserves estimates are often different from the quantities of crude oil and natural gas that are ultimately recovered.

Recent SEC and FASB Rule-Making Activity. In December 2008, the SEC approved new rules designed to modernize oil and gas reserve reporting requirements. In addition, in January 2010 the FASB issued Accounting Standards Update 2010-03, “Oil and Gas Reserve Estimation and Disclosures”, to provide consistency with the SEC rules. The Company adopted these rules effective December 31, 2009 and the rule changes, including those related to pricing and technology, are included in its reserves estimates.

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 using the 12-month historical first of month average and costs as of the date the estimate was made for all years presented. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

(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.

F-42

DELTA PETROLEUM CORPORATION AND SUBSIDIARIES

(Debtor in Possession)

Notes to Consolidated Financial Statements

December 31, 2011, 2010 and 2009

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

(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 undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

“Prepared” reserves are those quantities of reserves which were prepared by an independent petroleum consultant. “Audited” reserves are those quantities of revenues which were estimated by the Company’s employees and audited by an independent petroleum consultant. An audit is an examination of a company’s proved oil and gas reserves and net cash flow by an independent petroleum consultant that is conducted for the purpose of expressing an opinion as to whether such estimates, in aggregate, are reasonable and have been determined using methods and procedures widely accepted within the industry and in accordance with SEC rules.

Estimates of the Company’s oil and natural gas reserves and present values as of December 31, 2011 were prepared by Netherland, Sewell & Associates, Inc., independent reserve engineers. Estimates for December 31, 2010 and 2009 were prepared by Ralph E. Davis Associates, Inc., independent reserve engineers.

F-43

DELTA PETROLEUM CORPORATION AND SUBSIDIARIES

(Debtor in Possession)

Notes to Consolidated Financial Statements

December 31, 2011, 2010 and 2009

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

A summary of changes in estimated quantities of proved reserves for the years ended December 31, 2011, 2010 and 2009 is as follows (in thousands):

	Gas (MMcf)			Oil (MBbl)			Total (MMcfe)
Estimated Proved Reserves: Balance at December 31, 2008		827,677			9,453			884,395
Revisions of quantity estimate (1)		(701,626	)		(3,985	)		(725,536	)
Extensions and discoveries (2)		19,607			129			20,381
Purchase of properties		—			—			—
Sale of properties (3)		(1,375	)		(354	)		(3,499	)
Production		(17,591	)		(761	)		(22,156	)
Estimated Proved Reserves: Balance at December 31, 2009		126,692			4,482			153,585
Revisions of quantity estimate (4)		15,123			(111	)		14,456
Extensions and discoveries (5)		21,132			172			22,164
Purchase of properties		—			—			—
Sale of properties (6)		(26,598	)		(2,107	)		(39,240	)
Production		(13,670	)		(516	)		(16,766	)
Estimated Proved Reserves: Balance at December 31, 2010		122,679			1,920			134,199
Revisions of quantity estimate (7)		(20,795	)		(232	)		(22,187	)
Extensions and discoveries		—			—			—
Purchase of properties		—			—			—
Sale of properties (8)		(4,259	)		(983	)		(10,157	)
Production		(10,416	)		(211	)		(11,682	)
Estimated Proved Reserves: Balance at December 31, 2011		87,209			494			90,173
Proved developed reserves:
December 31, 2009		115,004			2,977			132,866
December 31, 2010		112,534			1,859			123,688
December 31, 2011		87,209			494			90,173
Proved undeveloped reserves:
December 31, 2009		11,688			1,505			20,719
December 31, 2010		10,145			61			10,511
December 31, 2011					—			—
Base Pricing, before adjustments for contractual differentials:

	CIG per Mmbtu		WTI per Bbl
December 31, 2009	$	3.03	$	61.18
December 31, 2010	$	3.95	$	79.61
December 31, 2011	$	3.99	$	83.33

Proved reserves are required to be calculated based on the 12-month, first day of the month historical average price in accordance with SEC rules. The prices shown above are base index prices to which adjustments are made for contractual deducts and other factors.

F-44

DELTA PETROLEUM CORPORATION AND SUBSIDIARIES

(Debtor in Possession)

Notes to Consolidated Financial Statements

December 31, 2011, 2010 and 2009

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

⁽¹⁾  The 2009 negative revisions were primarily related to the loss of Piceance Basin undeveloped reserves as a result of lower pricing from utilizing the 12-month historical average required by the new SEC rules for use in the December 31, 2009 reserve report and the Company’s more limited capital development plan at the time based on capital resources.

⁽²⁾  The 2009 increase in proved reserves was primarily comprised of Rocky Mountain proved reserve increases primarily from the Company’s Piceance Basin drilling program and related offset wells.

⁽³⁾  During 2009, proved reserves located in various states were sold in a series of transactions described in Note 5, “Oil and Gas Properties – Year Ended December 31, 2009 – Divestitures.”

⁽⁴⁾  The 2010 revisions consists primarily of increased Piceance Basin proved reserves from the incorporation of improved fracturing technology, partially offset by Gulf Coast proved undeveloped reserves removed as a result of drilling plan modifications in conjunction with the Wapiti Transaction.

⁽⁵⁾  The 2010 extensions and discoveries related primarily to Piceance locations added as proved reserves in 2010 offset to wells previously drilled.

⁽⁶⁾  The 2010 proved reserves located in Texas, Colorado, and Wyoming were sold in conjunction with the Wapiti Transaction described in Note 5, “Oil and Gas Properties – Year Ended December 31, 2010 – Divestitures.”

⁽⁷⁾  During 2011, negative revisions were related to limited capital to develop reserves.

⁽⁸⁾  During 2011, proved reserves located in Texas, Colorado, and Wyoming were sold in conjunction with the Wapiti Transaction described in Note 5, “Oil and Gas Properties – Year Ended December 31, 2011 – Divestitures.”

Future net cash flows presented below are computed using applicable prices (as summarized above) and costs and are net of all overriding royalty revenue interests.

	2011			2010			2009
				(in thousands)
Future net cash flows	$	492,152		$	793,556		$	662,029
Future costs:
Production		252,532			402,334			125,108
Development and abandonment		319			18,899			77,965
Income taxes1		—			—			—
Future net cash flows		239,301			372,323			458,956
10% discount factor		(109,606	)		(180,229	)		(302,272	)
Standardized measure of discounted future net cash flows	$	129,695		$	192,094		$	156,684
Estimated future development cost anticipated for following two years on existing properties	$	—		$	13,952		$	59,313

¹ No income tax provision is included in the standardized measure calculation shown above as the Company does not project to be taxable or pay cash income taxes based on its available tax assets and additional tax assets generated in the development of its reserves because the tax basis of its oil and gas properties and NOL carryforwards exceeds the amount of discounted future net earnings.

F-45

DELTA PETROLEUM CORPORATION AND SUBSIDIARIES

(Debtor in Possession)

Notes to Consolidated Financial Statements

December 31, 2011, 2010 and 2009

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

The principal sources of changes in the standardized measure of discounted net cash flows during the years ended December 31, 2011, 2010 and 2009 are as follows (in thousands):

	Years Ended December 31,
	2011			2010			2009
Beginning of the year	$	192,094		$	156,684		$	159,368
Sales of oil and gas production during the period, net of production costs		(42,187	)		(55,755	)		(48,195	)
Purchase of reserves in place		—			—			—
Net change in prices and production costs		7,906			96,145			(64,282	)
Changes in estimated future development costs		8,319			10,395			741,318
Extensions, discoveries and improved recovery		—			20,687			17,509
Revisions of previous quantity estimates, estimated timing of development and other		(17,130	)		26,508			(674,560	)
Previously estimated development and abandonment costs incurred during the period		2,453			6,477			15,556
Sales of reserves in place		(40,969	)		(84,715	)		(5,967	)
Change in future income tax		—			—			—
Accretion of discount		19,209			15,668			15,937
End of year	$	129,695		$	192,094		$	156,684

(21) Subsequent Events

On December 16, 2011, Delta and its subsidiaries Amber Resources Company of Colorado (“Amber”), DPCA, LLC, Delta Exploration Company, Inc., Delta Pipeline, LLC, DLC, Inc., CEC, Inc. and Castle Texas Production Limited Partnership filed voluntary petitions under Chapter 11 of the U.S. Bankruptcy Code in the United States Bankruptcy Court for the District of Delaware (the “Bankruptcy Court”). On January 6, 2012 Castle Exploration Company, Inc., a subsidiary of DPCA, LLC, also filed a voluntary petition under Chapter 11 in the Bankruptcy Court. Delta and its subsidiaries included in the bankruptcy petitions collectively as the “Debtors.”

F-46

DELTA PETROLEUM CORPORATION AND SUBSIDIARIES

(Debtor in Possession)

Notes to Consolidated Financial Statements

December 31, 2011, 2010 and 2009

On December 27, 2011, the Debtors filed a motion requesting an order to approve matters relating to a proposed sale of Delta’s assets, including bidding procedures, establishment of a sale auction date and establishment of a sale hearing date. On January 11, 2012, the Bankruptcy Court issued an order approving these matters. On March 20, 2012, Delta announced that it was seeking court approval to amend the bidding procedures for its upcoming auction to allow bids relating to potential plans of reorganization as well as asset sales. On March 22, 2012, the Bankruptcy Court approved the revised procedures.

Following the auction, the Debtors obtained approval from the Bankruptcy Court to select Laramie Energy II, LLC (“Laramie”) as the sponsor of a plan of reorganization (the “Plan”). In connection with the Plan, Delta entered into a non-binding term sheet describing a transaction by which Laramie and Delta intend to form a new joint venture called Piceance Energy LLC (“Piceance Energy”). On June 4, 2012, Delta entered into a Contribution Agreement (the “Contribution Agreement”) with Piceance Energy and Laramie to effect the transactions contemplated by the term sheet. Under the Contribution Agreement, each of Delta and Laramie will contribute to Piceance Energy their respective assets in the Piceance Basin. Following the contribution, Piceance Energy will be owned 66.66% by Laramie and 33.34% by Delta (referred to after the closing of the transaction as “Reorganized Delta”). At the closing, Piceance Energy will enter into a new credit agreement, borrow $100 million under that agreement, and distribute $75 million to Reorganized Delta and $25 million to Laramie. Reorganized Delta will use its distribution to pay bankruptcy expenses and to repay secured debt. The distribution from Piceance Energy to Reorganized Delta and Laramie will be subject to adjustment to give effect to the transaction effective date of July 31, 2012. Reorganized Delta will also enter into a new credit facility and will borrow an estimated $15 million under that facility at closing, and will use those funds primarily to pay bankruptcy claims and expenses.

Following the closing, Reorganized Delta will retain its interest in the Point Arguello unit offshore California and other miscellaneous assets and certain tax attributes, including significant net operating losses, and may retain its interest in Amber depending upon the outcome of Amber’s own Chapter 11 bankruptcy proceedings and claims reconciliation process. Based upon the Plan as confirmed by the Bankruptcy court the common stock of Reorganized Delta will be owned by Delta’s creditors, and Delta’s current shareholders will not receive any consideration under the Plan.

Contemporaneously with the closing, Delta will enter into a Limited Liability Company Agreement with Laramie that will govern the operations of Piceance Energy. Under that agreement, Laramie will act as the manager of Piceance Energy, and will control the day-to-day operations of Piceance Energy and will appoint a majority of the members of its board of managers. Reorganized Delta will have veto rights over certain matters and the right to appoint the remaining members of Piceance Energy’s board of managers. In addition, Laramie and Piceance Energy will enter into a Management Services Agreement pursuant to which Laramie will agree to provide certain services to Piceance Energy for a fee of $650,000 per month.

Also contemporaneously with the closing, Delta will amend and restate its Certificate of Incorporation and Bylaws. Under the amended and restated documents, Delta’s name will be changed to “Par Petroleum Corporation.” In addition, the amended and restated Certificate of Incorporation will contain restrictions that will limit the ability of holders of five percent or more of Reorganized Delta’s shares as of the closing to acquire or dispose of shares in certain circumstances, limit the ability of other persons to become five percent shareholders and render void certain transfers of Reorganized Delta’s stock violate these restrictions. The purpose of these provisions is to preserve Reorganized Delta’s tax attributes, including net operating loss carryforwards, that may have value. Under the amended and restated Bylaws, Reorganized Delta’s board of directors will have either five or six members, each of whom will be appointed by current creditors pursuant to a Stockholders’ Agreement they will enter into at closing.

On June 4, 2012, the Debtors filed a disclosure statement and the Plan. The disclosure statement was approved by the Bankruptcy Court on July 6, 2012 and the Plan, as amended, was confirmed by the Bankruptcy Court on August 16, 2012, and is expected to be consummated on or about August 31, 2012.

F-47

DELTA PETROLEUM CORPORATION AND SUBSIDIARIES

(Debtor in Possession)

Notes to Consolidated Financial Statements

December 31, 2011, 2010 and 2009

(21) Subsequent Events, Continued

Upon satisfaction of the remaining material contingencies to complete the implementation of the Plan, under the Reorganization Topic of the ASC, the Company will be required to apply the provisions of fresh start accounting to its financial statements on the Effective Date because (i) the reorganization value of the assets of the emerging entity immediately before the date of confirmation was less than the total of all post-petition liabilities and allowed claims and (ii) the holders of the existing voting shares of the Predecessor Company’s common stock immediately before confirmation received less than 50 percent of the voting shares of the emerging entity.

The adoption of fresh start accounting will result in a new reporting entity. All of the new entity’s assets and liabilities will be recorded at their estimated fair values upon the Effective Date and the Predecessor Company’s retained deficit and accumulated other comprehensive income will be eliminated. Under the Plan, Delta’s priority non-tax claims and secured claims will be unimpaired in accordance with section 1124(1) of the Bankruptcy Code. Each general unsecured claim and noteholder claims will receive its pro rata share of new common stock of Par Petroleum in full satisfaction of its claims.

In accordance with fresh start accounting, the Company will record the debt and equity at fair value utilizing the total enterprise value of approximately $176 million, which was determined in conjunction with the confirmation of the Plan in part based on a set of financial projections for the post-emergence entity. The enterprise value was dependent upon achieving the future financial results set forth in the Company’s projections, as well as the realization of certain other assumptions. These projections were prepared in connection with the Plan and the Bankruptcy Cases. The projections were based on information available to the Company and assumptions known to the Company. Projections are inherently subject to uncertainties and risks and the Company’s actual results and financial condition will likely vary from those contemplated by the projections and other financial information provided to the Bankruptcy Court.

F-48

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange of Act of 1934, we have caused this Form 10-K to be signed on our behalf by the undersigned, thereunto duly authorized, in the City of Denver and State of Colorado on the 31^st day of August, 2012.

DELTA PETROLEUM CORPORATION
By:	/s/ Carl E. Lakey
	Carl E. Lakey, President and Chief
	Executive Officer
By:	/s/ John T. Young, Jr.
	John T. Young, Jr., Principal Financial Officer

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

Signature and Title	Date
/s/ Kevin R. Collins Kevin R. Collins, Director	August 31, 2012
/s/ Jerrie F. Eckelberger Jerrie F. Eckelberger, Director	August 31, 2012
/s/ Jordan R. Smith Jordan R. Smith, Director	August 31, 2012
/s/ Daniel J. Taylor Daniel J. Taylor, Director	August 31, 2012
/s/ Carl E. Lakey Carl E. Lakey, Director	August 31, 2012