Par Pacific Holdings - 10-Q quarterly report FY

 

 

(Exact name of registrant as specified in its charter)

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

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

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

Large accelerated filer o     Accelerated filer þ     Non-accelerated filer o

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

     53,007,000 shares of common stock $.01 par value were outstanding as of August 4, 2006.

 

INDEX

PART I FINANCIAL INFORMATION

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

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

See accompanying notes to consolidated financial statements.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

See accompanying notes to consolidated financial statements.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

See accompanying notes to consolidated financial statements.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES

Consolidated Statement of Changes in Stockholders’ Equity and Comprehensive Income

(Unaudited)

See accompanying notes to consolidated financial statements.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

See accompanying notes to consolidated financial statements.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES

Notes to Consolidated Financial Statements
Six Months Ended June 30, 2006 and 2005
(Unaudited)

The accompanying unaudited consolidated financial statements have been prepared in accordance with the instructions to Form 10-Q and, in accordance with those rules, do not include all the information and notes required by generally accepted accounting principles for complete financial statements. As a result, these unaudited consolidated financial statements should be read in conjunction with the Company’s audited consolidated financial statements and notes thereto filed with the Company’s most recent transition report on Form 10-KT. In the opinion of management, all adjustments, consisting only of normal recurring accruals, considered necessary for a fair presentation of the financial position of the Company and the results of its operations have been included. Operating results for interim periods are not necessarily indicative of the results that may be expected for the complete fiscal year. On September 14, 2005, the Company’s management and the Board of Directors made the decision to change the Company’s fiscal year end to December 31. For a more complete understanding of the Company’s operations and financial position, reference is made to the consolidated financial statements of the Company, and related notes thereto, filed with the Company’s transition report on Form 10-KT for the six months ended December 31, 2005, previously filed with the Securities and Exchange Commission.

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

The Company, through a series of transactions in 2004 and 2005, owns a 49.4% interest in DHS Drilling Company (“DHS”), an affiliated Colorado corporation that is headquartered in Casper, Wyoming. Delta representatives currently constitute a majority of the members of the Board of DHS and Delta has the right to use all of the rigs on a priority basis, although approximately half are currently working for third party operators. DHS also owns 100% of Chapman Trucking which was acquired in November 2005 and which ensures DHS rig mobility. In May 2006, DHS acquired two rigs in conjunction with the acquisition of C&L Drilling Company, Inc. (“C&L Drilling”). Also, during the second quarter of 2006, DHS engaged in a reorganization transaction pursuant to which it became a subsidiary of DHS Holding Company, a Delaware corporation, and the Company’s ownership interest became an interest in DHS Holding Company. References to DHS herein shall be deemed to include both DHS Holding Company and DHS, unless the context otherwise requires. DHS is a consolidated entity of Delta.

At June 30, 2006 the Company owned 4,277,977 shares of the common stock of Amber Resources Company of Colorado (“Amber”), representing 91.68% of the outstanding common stock of Amber. Amber is a public company that owns undeveloped oil and gas properties in federal units offshore California, near Santa Barbara.

In late 2005 the Company transferred its ownership in approximately 64,000 net acres of non-operated interests in the Columbia River Basin to CRB Partners, LLC, which originally was a wholly-owned subsidiary (“CRBP”). These interests consist of the Company’s 1% overriding royalty interest convertible into a 15% back-in working interest after project payout. During the first quarter of 2006, we sold a 44% minority interest in CRBP. We have retained the majority ownership in, and are the manager of, CRBP. The non-Delta members of CRBP have certain limited consent rights with respect to, among other things, CRBP’s election to convert to a working

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Six Months Ended June 30, 2006 and 2005
(Unaudited)

interest prior to actual project payout, disposition of its assets or effecting certain transactions outside the ordinary course of CRBP’s business. Further, our ownership in CRBP is subject to certain rights of first refusal and co-sale rights. The sole asset of CRBP is oil and gas properties contributed by Delta, and therefore, the sale of the minority interest in CRBP was accounted for as a disposal of oil and gas properties. This sale did not involve any of our operated 100% working interests in approximately 345,000 net acres in the Columbia River Basin.

On April 28, 2006, Castle Energy Corporation (“Castle”) shareholders approved the merger agreement between Delta and Castle. As of that date, Delta via its merger subsidiary DPCA LLC (“DPCA”), acquired Castle for a purchase price of $33.6 million comprised of 1.8 million net shares issued (8,500,000 shares issued net of 6,700,000 owned by Castle) valued at $31.2 million and $2.4 million of transaction costs. Delta obtained assets valued at $39.7 million which are comprised of cash, producing oil and gas properties located in Pennsylvania and West Virginia, and certain other assets. See Footnote 4 (“Oil and Gas Properties”).

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

     Principles of Consolidation and Basis of Presentation

The consolidated financial statements include the accounts of Delta, Amber, Piper, CRBP, PGR, DHS, DPCA and other subsidiaries with minimal net assets or activity (collectively, the “Company”). All inter-company balances and transactions have been eliminated in consolidation. As Amber is in a net shareholders’ deficit position for the periods presented, the Company has recognized 100% of Amber’s earnings/losses for all periods. The Company has no interests in any other unconsolidated entities nor does it have any off-balance sheet financing arrangements (other than operating leases) or any unconsolidated special purpose entities.

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

Certain reclassifications have been made to amounts reported in previous years to conform to the current year presentation. Such reclassifications had no effect on net income.

     Cash Equivalents

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

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Six Months Ended June 30, 2006 and 2005
(Unaudited)

     Assets Held for Sale

Assets held for sale as of June 30, 2006 represent the Pennsylvania oil and gas properties acquired in the Castle Acquisition in April 2006 and certain non-operated East Texas interests that were sold subsequent to quarter-end (See Footnote 13 “Subsequent Events”). Although the Pennsylvania properties were not sold during the quarter ended June 30, 2006, an extraordinary gain was recorded during the quarter as required by Statement of Financial Accounting Standards No. 141 “Business Combinations” (“SFAS No. 141”) due to the Company’s plan to dispose of the acquired properties in the near term and the excess fair value of the assets acquired compared to the purchase price of the transaction. A true-up of the gain based on actual final proceeds from the sale will be recorded in the period the sale occurs (See Footnote 4 “Oil and Gas Properties”).

Assets held for sale as of December 31, 2005 represent the cost basis related to the 427,000 gross acres (64,000 net acres) of non-operated interests in the Columbia River Basin that were transferred during December 2005 to a newly created wholly owned subsidiary, CRBP. In January and March 2006, Delta sold a minority interest in CRBP to a small group of investors for aggregate proceeds of $32.8 million. As the sale involved unproved properties, no gain on the partial sale of CRBP could be recognized until all of the cost basis of CRBP had been recovered. Accordingly, the Company recorded a $13.0 million gain ($8.1 million net of tax) and an $11.2 million reduction to unproved oil and gas property during the first quarter of 2006 as a result of closing the transaction.

     Inventories

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

     Investment in LNG project

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

     Minority Interest

Minority interest represents the 50.6% (45% for Chesapeake Energy Corporation, 5.6% for DHS executive officers and management) investors of DHS at June 30, 2006 and December 31, 2005. Prior to forming DHS, the Company owned a 50% interest in Big Dog Drilling Co., LLC (“Big Dog”) and a 50% interest in Shark Trucking Co., LLC (“Shark”). The remaining net assets of Big Dog were ultimately acquired and, together with the interest previously owned, were contributed to DHS.

     Revenue Recognition

     Oil and gas

Revenues are recognized when title to the products transfer to the purchaser. The Company follows the “sales method” of accounting for its natural gas and crude oil revenue, so that the Company recognizes sales revenue on all natural gas or crude oil sold to its purchasers, regardless of whether the sales are proportionate to the Company’s ownership in the property. A receivable or liability is recognized only to the extent that the Company has an imbalance on a specific property greater than the expected remaining proved reserves. As of June 30, 2006 and December 31, 2005, the Company’s aggregate natural gas and crude oil imbalances were not material to its consolidated financial statements except for an imbalance acquired during fiscal 2005 which was collected during the six months ended December 31, 2005.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Six Months Ended June 30, 2006 and 2005
(Unaudited)

     Drilling and Trucking

We earn our contract drilling revenues under daywork arrangements. We recognize revenues on daywork contracts for the days completed based on the dayrate each contract specifies. The costs of drilling the Company’s own oil and gas properties are capitalized in oil and gas properties as the expenditures are incurred. Trucking and hauling revenues are recognized based on either an hourly rate or a fixed fee per mile depending on the type of vehicle, the services performed, and the contract terms.

     Property and Equipment

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

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

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

Drilling equipment and other property and equipment are recorded at cost or estimated fair value upon acquisition and depreciated on a component basis using the straight-line method over their estimated useful lives.

     Impairment of Long-Lived Assets

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

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

The Company assesses developed properties on an individual field basis for impairment on at least an annual basis. For developed properties, the review consists of a comparison of the carrying value of the asset with the asset’s expected future undiscounted cash flows without interest costs. As a result of such assessment, the Company recorded no impairment provision attributable to developed properties for the three and six months ended June 30, 2006 and 2005. During the second half of 2006, we are continuing to develop certain properties on

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Six Months Ended June 30, 2006 and 2005
(Unaudited)

which favorable or unfavorable results may cause us to revise in future quarters our estimates of those properties’ future cash flows. Such revisions of estimates could require us to record an impairment in the period of such revisions.

For undeveloped properties, the need for an impairment is based on the Company’s plans for future development and other activities impacting the life of the property and the ability of the Company to recover its investment. When the Company believes the costs of the undeveloped property are no longer recoverable, an impairment charge is recorded based on the estimated fair value of the property. As a result of such assessment, the Company recorded no impairment provision attributable to undeveloped properties for the three and six months ended June 30, 2006 and 2005.

     Goodwill

Goodwill represents the excess of the cost of the acquisitions by DHS of C&L Drilling in May 2006, Rooster Drilling in March 2006, and Chapman Trucking in November 2005 over the fair value of the assets and liabilities acquired. For goodwill and intangible assets recorded in the financial statements, an impairment test will be performed at least annually in accordance with the provisions of Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets” (“SFAS No. 142”).

     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 from January 1, 2006 to June 30, 2006 (amounts in thousands):

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

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Six Months Ended June 30, 2006 and 2005
(Unaudited)

     Comprehensive Income

Comprehensive income includes all changes in equity during a period except those resulting from investments by owners and distributions to owners, if any. The components of comprehensive income for the three and six months ended June 30, 2006 and 2005 are as follows:

     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 hedges is to provide a measure of stability to the Company’s cash flows in an environment of volatile oil and gas prices. All transactions are accounted for in accordance with requirements of Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”) which the Company adopted on January 1, 2001. Accordingly, unrealized gains and losses related to the change in fair market value of derivative contracts which qualify and are designated as cash flow hedges are recorded in accumulated other comprehensive income or loss, to the extent the hedge is effective, and such amounts are reclassified to realized gain (loss) on derivative instruments as the associated production occurs.

At June 30, 2006, the Company’s derivative contracts were primarily collars but included one put option contract. Under a collar agreement the Company receives the difference between the floor price and the index price only when the index price is below the floor price; and the Company pays the difference between the ceiling price and the index price only when the index price is above the ceiling price. The Company’s collars are settled in cash on a monthly basis. By entering into collars, the Company effectively provides a floor for the price that it will receive for the hedged production; however, the collar also establishes a maximum price that the Company will receive for the hedged production when prices increase above the ceiling price. The Company enters into collars during periods of volatile commodity prices in order to protect against a significant decline in prices in exchange for foregoing the benefit of price increases in excess of the ceiling price on the hedged production. Under a put option agreement, the Company receives the difference between the floor price and the index price only when the index price is below the floor price. The Company’s put options are settled in cash on a monthly basis. By entering into put option agreements, the Company effectively provides a floor for the price that it will receive for the hedged production; however, the put must be purchased with cash at inception.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Six Months Ended June 30, 2006 and 2005
(Unaudited)

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

During the quarter ended June 30, 2006, the Company entered into additional derivative contracts as denoted by the * in the table below.

The following table summarizes our open derivative contracts at June 30, 2006 and indicates those that qualify for hedge accounting and those that do not qualify for hedge accounting:

The net fair value of the Company’s derivative instruments obligation was a liability of approximately $7.6 million at June 30, 2006 and $12.3 million on August 4, 2006.

The net realized losses from hedging activities recognized in the Company’s statements of operations were $2.9 million and $193,000 for the three months ended June 30, 2006 and 2005, respectively and $5.2 million and $537,000 for the six months ended June 30, 2006 and 2005, respectively. These losses are recorded as a decrease in revenues.

In April 2006, the Company purchased for $492,000 a natural gas put option with a CIG strike price of $7.50 per Mmbtu on 10,000 Mmbtu per day for July 2006 through September 2006. This derivative does not qualify for hedge accounting and accordingly changes in the contract’s fair value have been recorded on the consolidated balance sheet with a corresponding unrealized gain of approximately $861,000 recorded in the consolidated statement of operations.

     Stock Option Plans

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

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Six Months Ended June 30, 2006 and 2005
(Unaudited)

In December 2004, Statement of Financial Accounting Standards No. 123 (Revised 2004), “Share Based Payment” (“SFAS No. 123R”) was issued, which now requires the Company to recognize the grant-date fair value of stock options and other equity based compensation issued to employees, in the statement of operations. The cost of share based payments is recognized over the period the employee provides service. The Company adopted SFAS No. 123R effective July 1, 2005 using the modified prospective method and recognized compensation expense related to stock options of $335,000 and $808,000, relating to employee provided services during the three and six months ended June 30, 2006, respectively.

     Non-Qualified Stock Options — Directors and Employees

On May 31, 2002, at the annual meeting of the shareholders, the shareholders ratified the Company’s 2002 Incentive Plan (the “Incentive Plan”) under which it reserved up to an additional 2,000,000 shares of common stock. This plan superseded the Company’s 1993 and 2001 Incentive Plans.

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

Exercise prices for options outstanding under the Company’s various plans as of June 30, 2006 ranged from $1.13 to $15.60 per share and the weighted-average remaining contractual life of those options was 4.92 years. These options have a stock based compensation value of approximately $958,000 and will be expensed during future periods through December 31, 2007. The Company has not issued stock options since the adoption of SFAS No. 123R, though it has the discretion to issue options again in the future. At June 30, 2006, the Company had 450,000 unvested options.

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

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Six Months Ended June 30, 2006 and 2005
(Unaudited)

     Income Taxes

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

     Earnings (Loss) per Share

Basic earnings (loss) per share is computed by dividing net earnings (loss) attributed to common stock by the weighted average number of common shares outstanding during each period, excluding treasury shares. Diluted earnings (loss) per share is computed by adjusting the average number of common shares outstanding for the dilutive effect, if any, of convertible preferred stock, stock options, restricted stock and warrants. (See Footnote 10, “Earnings Per Share”).

     Use of Estimates

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

     Recently Issued Accounting Pronouncement

In July 2006, the FASB issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109” (“FIN 48”). This interpretation clarifies the accounting for uncertainty in tax positions. FIN 48 requires that we recognize in our financial statements the impact of a tax position if that position is more likely than not of being sustained on audit, based on the technical merits of the position. FIN 48 is effective for our fiscal year commencing January 1, 2007. At this time, we have not completed our review and assessment of the impact on our financial statements of the adoption of FIN 48.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Six Months Ended June 30, 2006 and 2005
(Unaudited)

     Unproved Undeveloped Offshore California Properties

The Company has direct and indirect ownership interests ranging from 2.49% to 100% in five unproved undeveloped offshore California oil and gas properties with an aggregate carrying value of $11.4 million, at June 30, 2006. These property interests are located in proximity to existing producing federal offshore units near Santa Barbara, California and represent the right to explore for, develop and produce oil and gas from offshore federal lease units. Preliminary exploration efforts on these properties have occurred and the existence of substantial quantities of hydrocarbons has been indicated. The recovery of the Company’s investment in these properties will require extensive exploration and development activities (and costs) that cannot proceed without certain regulatory approvals that have been delayed and is subject to other substantial risks and uncertainties.

We and our majority-owned subsidiary, Amber Resources Company of Colorado, are among twelve plaintiffs in a lawsuit that was filed on January 9, 2002 in the United States Court of Federal Claims in Washington, D.C. alleging that the U.S. government has materially breached the terms of forty undeveloped federal leases, some of which are part of our offshore California properties. The Complaint is based on allegations by the collective plaintiffs that the United States has materially breached the terms of certain of their offshore California leases by attempting to deviate significantly from the procedures and standards that were in effect when the leases were
entered into, and by failing to carry out its own obligations relating to those leases in a timely and fair manner. More specifically, the plaintiffs have alleged that the judicial determination in the California v. Norton case, that a 1990 amendment to the Coastal Zone Management Act that required the government to make a consistency determination prior to granting lease suspension requests in 1999, constitutes a material change in the procedures and standards that were in effect when the leases were issued. The plaintiffs have also alleged that the United States has failed to afford them the timely and fair review of their lease suspension requests which has resulted in significant, continuing and material delays to their exploratory and development operations.

The suit seeks compensation for the lease bonuses and rentals paid to the Federal government, exploration costs and related expenses. The total amount claimed by all lessees for bonuses and rentals exceeds $1.2 billion, with additional amounts for exploration costs and related expenses. We own approximately 12% of the lease bonus costs that are the subject of the lawsuit. In addition, our claim for exploration costs and related expenses will also be substantial. In the event, however, that we receive any proceeds as the result of such litigation, we will be obligated to pay a portion of any amount received by us to landowners and other owners of royalties and similar interests, to pay the litigation expenses and to fulfill certain pre-existing contractual commitments to third parties.

On November 15, 2005, the United States Court of Federal Claims issued a ruling in the suit granting the plaintiffs’ motion for summary judgment as to liability and partial summary judgment as to damages with respect to thirty-six of the forty total federal leases that are the subject of the litigation. The court’s ruling also denied the United States’ motion to dismiss and motion for summary judgment. The United States Court of Federal Claims ruled that the federal government’s imposition of new and onerous requirements that stood as a significant obstacle to oil and gas development breached agreements that it made when it sold thirty-six out of the total forty offshore California federal leases that are the subject of the litigation. The Court further ruled that the government must give back to the current lessees the more than $1.1 billion in lease bonuses it had received at the time of sale.

We and Amber are among the current lessees of the thirty-six leases that are the subject of the ruling. The government has filed a motion for reconsideration of this ruling. The final ruling in the case will not be made until the Court addresses the plaintiffs’ additional claims regarding the four additional leases, as well as their claims regarding the hundreds of millions of dollars that have been spent in the successful efforts to find oil and gas in the disputed lease area, and other matters. The final ruling, including the ruling made on November 15, will be subject to appeal, and no payments will be made until all appeals have either been waived or exhausted.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Six Months Ended June 30, 2006 and 2005
(Unaudited)

     Significant Acquisition — Pro-forma Statements of Operations

On April 28, 2006, Castle shareholders approved the merger agreement between Delta and Castle. As of that date, Delta via its merger subsidiary DPCA, acquired Castle for a purchase price of $33.6 million comprised of 1.8 million net shares issued (8,500,000 shares issued net of 6,700,000 owned by Castle) valued at $31.2 million and $2.4 million of transaction costs. Delta obtained assets valued at $39.7 million which are comprised of cash, producing oil and gas properties located in Pennsylvania and West Virginia, and certain other assets. Due to the excess fair value of the assets acquired compared to the purchase price of the transaction and in accordance with SFAS No. 141 when acquired assets are held for sale in the near term, Delta recorded a $6.1 million extraordinary gain ($9.6 million, net of $3.5 million of deferred taxes) during the quarter ended June 30, 2006. A true-up of the gain based on actual final proceeds from the sale will be recorded in the period the sale occurs (See Footnote 13, “Subsequent Events”).

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

The following unaudited pro forma condensed consolidated statements of operations assume that the Manti and Castle acquisitions occurred as of January 1, 2005:

The above unaudited pro forma condensed consolidated statements of operations, based on the historical producing property operating results of Manti, Castle and Delta, are not necessarily indicative of the results of operations if Delta would have acquired the properties at January 1, 2005.

     Acquisition During the Quarter Ended March 31, 2006

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

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Six Months Ended June 30, 2006 and 2005
(Unaudited)

     Fiscal 2006 — Dispositions

During December 2005, Delta transferred its ownership in approximately 427,000 gross acres (64,000 net acres) of non-operated interests in the Columbia River Basin to CRBP. In January and March 2006, Delta sold a combined 44% minority interest in CRBP. As the sale involved unproved properties, no gain on the partial sale of CRBP could be recognized until all of the cost basis of CRBP had been recovered. Accordingly, the Company recorded a $13.0 million gain, ($8.1 million net of tax) and an $11.2 million reduction to property during the first quarter of 2006 as a result of closing the transaction. As a result of the transaction, Delta now owns a net interest of just over 35,000 acres in the Columbia River Basin through its remaining ownership of CRBP and additional interests in 345,000 net acres in the Columbia River Basin from previous transactions.

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

     Discontinued Operations

In accordance with SFAS No. 144, the results of operations and gain (loss) relating to the sale of the following property interests have been reflected as discontinued operations.

On September 2, 2005, the Company completed the sale of its Deerlick Creek field in Tuscaloosa County, Alabama for $30.0 million with an effective date of July 1, 2005. The Company recorded an after tax gain on sale of oil and gas properties of $10.2 million on net proceeds of approximately $28.9 million after normal closing adjustments. The net profit earned on these assets was zero for the three and six month periods ended June 30, 2006, and $825,000 and $1.6 million for the three and six month periods ended June 30, 2005, respectively.

On June 1, 2006, the Company completed the sale of certain properties located in Pointe Coupee Parish, Louisiana, for cash consideration of $8.9 million with an effective date of May 1, 2006. The transaction resulted in an after-tax gain on sale of oil and gas properties of $636,000. Income attributed to the operations of these oil and gas properties was approximately $261,000 and $372,000 for the three and six month periods ended June 30, 2006, respectively, and $825,000 and $1.4 million for the three and six month periods ended June 30, 2005, respectively, and are included in income from discontinued operations of properties sold in the consolidated statements of operations.

Included in the three and six months ended June 30, 2005 discontinued operations is a $280,000 loss from discontinued operations related to other insignificant properties.

     (5) DHS Drilling Operations

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

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Six Months Ended June 30, 2006 and 2005
(Unaudited)

In March 2006, DHS purchased a Kremco 750G drilling rig for $4.75 million. The rig is a 500 horsepower rig with a depth rating of 10,000 feet. The rig commenced work in the Rocky Mountain region in June 2006.

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

In May 2006, DHS acquired two rigs (“Rig 12” and “Rig 14”) and other certain assets in conjunction with the acquisition of C&L Drilling for a purchase price of approximately $16.7 million. Rigs 12 and 14 have depth ratings of 15,000 and 12,500 feet, respectively. The rigs are currently under contract to third party operators and working in California and Utah.

     7% Senior Unsecured Notes, due 2015

On March 15, 2005, the Company issued 7% senior unsecured notes for an aggregate amount of $150.0 million which pay interest semiannually on April 1 and October 1 and mature in 2015. The net proceeds were used to refinance debt outstanding under our credit facility, which included the amount required to acquire the Manti properties. The notes were issued at 99.50% of par, and the associated discount is being amortized to interest expense over the term of the notes. The indenture governing the notes contains various restrictive covenants that may limit the Company’s and its subsidiaries’ ability to, among other things, incur additional indebtedness, repurchase capital stock, pay dividends, make certain investments, sell assets, consolidate, merge or transfer all or substantially all of the assets of the Company and restricted subsidiaries. These covenants may limit the discretion of the Company’s management in operating the Company’s business. The Company was not in default (as defined in the indenture) under the indenture as of June 30, 2006. (See Footnote 11, “Guarantor Financial Information”). The fair value of the Company’s senior notes at June 30, 2006 was $139.5 million.

     Credit Facility

During the quarter ended June 30, 2006, the Company’s borrowing base was increased to $120.0 million. At June 30, 2006, the $200.0 million credit facility had $74.0 million outstanding. The facility has variable interest rates based upon the ratio of outstanding debt to the borrowing base. Rates vary between prime + .25% and 1.00% for base rate loans and between Libor + 1.5% and 2.25% for Eurodollar loans. The Libor and prime rates at June 30, 2006 approximated 7.04% and 8.75%, respectively. The loan is collateralized by substantially all of our oil and gas properties. The Company is required to meet certain financial covenants which include a current ratio of 1 to 1 (adjusted for availability under the facility and excluding current derivative instruments) and a consolidated debt to adjusted EBITDAX (Earnings before interest, taxes, depreciation, amortization and exploration) ratio of less than 3.5 to 1. At June 30, 2006, the Company was in compliance with its quarterly debt covenants and restrictions.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Six Months Ended June 30, 2006 and 2005
(Unaudited)

     Credit Facility — DHS

On May 4, 2006, DHS entered into a new $100.0 million senior secured credit facility with JP Morgan Chase Bank, N.A. Proceeds from the $75.0 million initial draw were used to pay off the previously outstanding term loan, complete the acquisition of C&L Drilling, finance additional capital expenditures and pay transaction expenses. Borrowings on the facility bear interest at LIBOR plus 300 basis points. The facility includes financial covenants which require a maximum debt to EBITDA ratio of 2.50 to 1.00 (with such ratio decreasing to 2.25 to 1.00 for the quarters ending March 31, 2008 through December 31, 2008 and 2.00 to 1.00 for the fiscal quarters ending March 31, 2009 through March 31, 2012) and a minimum EBITDA to interest expense ratio of 4.00 to 1.00 (increasing to 4.50 to 1.00 for the fiscal quarters ending June 30, 2007 through December 31, 2007, and increasing again to 5.00 to 1.00 for the fiscal quarters ending March 31, 2008 and thereafter). Financing fees of $2.3 million were incurred in conjunction with the facility and will be amortized over the life of the loan. The facility has a $25 million mandatory delayed draw feature which expires in May 2007 and on which DHS pays commitment fees until drawn. The facility matures on May 4, 2012 and requires quarterly principal payments of 0.25% of the amount outstanding. In addition, an annual mandatory prepayment is required each April based on a percentage of excess cash flow (as defined) during the preceding fiscal year. The facility is non-recourse to Delta.

     Term Loan — DHS

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

     Five Year Maturities of Long-Term Debt

Borrowing availability under the Delta bank credit facility at June 30, 2006 was $46.0 million and $25.0 million under the DHS facility. Maturities of long-term debt, in thousands of dollars based on contractual terms, are as follows:

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Six Months Ended June 30, 2006 and 2005
(Unaudited)

On June 16, 2006 we received a subpoena from the U.S. Attorney for the Southern District of New York requesting records from 1996 to the present relating to our granting of stock options. On June 28, 2006 the Securities and Exchange Commission asked for our voluntary cooperation in connection with the staff’s informal inquiry into our stock option grants and stock option practices. We believe that these inquiries are the result of having been identified in a third party report dated May 16, 2006 as statistically being at risk for possibly backdating option grants to executive officers. On May 22, 2006, in response to the third party report, our Board of Directors created a special committee comprised of independent directors to conduct an independent review of our historical stock option practices and related accounting as they pertain to possible backdating of options. The special committee is being assisted by independent legal counsel and advisors. The independent counsel reported its findings to the special committee on August 4, 2006. Results of the independent counsel’s investigation will be provided to the U.S. Attorney in the Southern District of New York and the local office of the Securities and Exchange Commission in Denver, Colorado.

     Preferred Stock

The Company has 3,000,000 shares of preferred stock authorized, issuable from time to time in one or more series. As of June 30, 2006 and December 31, 2005, no preferred stock was issued. As part of the reincorporation on January 31, 2006, the Company reduced the par value of the preferred stock from $.10 per share to $.01 per share.

     Common Stock

In January 2006, the Company purchased Rooster Drilling for 350,000 shares of Delta common stock valued at $8.3 million based on the value of the stock when the transaction closed (See Footnote 5 “DHS Drilling Operations”).

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

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

On April 28, 2006, Castle shareholders approved the merger agreement between Delta and Castle as announced on November 8, 2005. Delta, via its merger subsidiary DPCA, acquired Castle which held 6,700,000 shares of Delta, and issued 8,500,000 shares of its common stock to Castle’s stockholders, for a net issuance of 1,800,000 shares of common stock. The shares of the Company’s common stock were valued at $31.2 million using the average five-day closing price before and after the terms of the agreement were agreed upon and announced.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Six Months Ended June 30, 2006 and 2005
(Unaudited)

The Company accounts for income taxes in accordance with the provisions of SFAS No. 109. Income tax benefit attributable to income from continuing operations was $1.7 million, $3.3 million, and $3.3 million, for the three months ended June 30, 2006 and 2005 and the six months ended June 30, 2005, respectively, and income tax expense of $6.6 million for the six months ended June 30, 2006.

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. Based upon the level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, management believes it is more likely than not that the Company will realize the benefits of these deductible differences, net of the existing valuation allowances at June 30, 2006 and December 31, 2005. The valuation allowance at June 30, 2006 and December 31, 2005 relates primarily to a subsidiary’s net operating loss that cannot be used to reduce taxable income generated by other members of the consolidated tax group and a deferred tax asset generated by a subsidiary that is not consolidated for tax purposes and does not have a history of earnings. The amount of the deferred tax asset considered realizable could be reduced if estimates of future taxable income during the carry-forward period are reduced.

At December 31, 2005, the Company had net operating loss carryforwards of approximately $57.7 million, which expire between 2006 and 2025.

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

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Six Months Ended June 30, 2006 and 2005
(Unaudited)

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

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

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Six Months Ended June 30, 2006 and 2005
(Unaudited)