PXP Producing (PPP) 8-K Other Events

Exhibit 99.1

Northrock Resources Ltd.
Audited Consolidated Financial Statements
For the Years ended
December 31, 2004, 2003 and 2002

PricewaterhouseCoopers LLP

Chartered Accountants

111 5th Avenue SW, Suite 3100

Calgary Alberta

Canada T2P 5L3

Telephone +1 (403) 509 7500

Facsimile +1 (403) 781 1825

August 5, 2005

Auditors’ Report

To the Shareholder of
Northrock Resources Ltd.

We have audited the accompanying consolidated balance sheets of Northrock Resources Ltd. as at December 31, 2004 and 2003 and the related consolidated statements of income, shareholders’ equity, comprehensive income and cash flows for each of the three years in the period ended December 31, 2004. These financial statements are the responsibility of the company’s management. Our responsibility is to express an opinion on these 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 the company as at December 31, 2004 and 2003 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004, in conformity with U.S. generally accepted accounting principles.

Chartered Accountants

Calgary, Alberta, Canada

PricewaterhouseCoopers refers to the Canadian firm of PricewaterhouseCoopers LLP and the other member firms of PricewaterhouseCoopers International Limited, each of which is a separate and independent legal entity.

Northrock Resources Ltd.

Consolidated Balance Sheets

as at December 31, 2004 and 2003

(thousands of U.S. dollars)	2004		2003
ASSETS
Current Assets
CASH	$	9,603	$	(3,052	)
ACCOUNTS RECEIVABLE	48,868		40,181
INVENTORY (Note 3)	5,872		3,292
PREPAIDS	1,162		775
NOTE RECEIVABLE FROM RELATED COMPANY (Note 13)	123,129		38,565
DERIVATIVE ASSET	—		29,756
DEFERRED INCOME TAXES (Note 6)	—		6,300
	188,634		115,817
PROPERTY, PLANT, & EQUIPMENT (Note 5)	1,259,408		1,188,193
OTHER ASSETS
GOODWILL	55,291		50,256
DEPOSITS AND ADVANCES	1,736		1,159
DEFERRED CHARGES	2,548		3,011
	59,575		54,426
TOTAL ASSETS	$	1,507,617	$	1,358,436
LIABILITIES
Current Liabilities
ACCOUNTS PAYABLE & ACCRUED LIABILITIES	$	72,516	$	80,177
CURRENT TAX PAYABLE	5,506		5,402
DERIVATIVE LIABILITY	—		40,791
OTHER LONG TERM LIABILITIES - CURRENT PORTION (Note 8)	917		850
	78,939		127,220
LONG TERM LIABILITIES
DEFERRED INCOME TAXES (Note 6)	274,799		223,786
PREFERRED SECURITIES (Notes 11, 13)	415,975		385,655
OTHER LONG TERM LIABILITIES (Note 8)	3,022		3,011
ASSET RETIREMENT OBLIGATION (Note 9)	38,434		33,187
	732,230		645,639
TOTAL LIABILITIES	811,169		772,859
SHAREHOLDERS’ EQUITY
SHAREHOLDERS’ EQUITY (Note 11)	565,641		565,641
RETAINED EARNINGS	14,423		(39,202		)
OTHER COMPREHENSIVE INCOME	—		(5,662		)
FOREIGN CURRENCY TRANSLATION	116,384		64,800
TOTAL SHAREHOLDERS’ EQUITY	696,448		585,577
TOTAL LIABILITIES AND EQUITY	$	1,507,617	$	1,358,436

See accompanying notes to the consolidated financial statements

Approved on behalf of the Board of Directors:

/s/ David L. Pearce	/s/ John H. Van de Pol
David L. Pearce	John H. Van de Pol
Director	Director
President	Senior Vice President and
	Chief Financial Officer

Northrock Resources Ltd.

Consolidated Statements of Income

Years Ended December 31, 2004, 2003, and 2002

(thousands of U.S. dollars)	2004			2003			2002
REVENUES
PRODUCTION (Note 13)	$	342,274		$	302,881		$	210,856
OTHER	(13		)	8,644			(10,133		)
TOTAL REVENUE	342,261			311,525			200,723
EXPENSES
PRODUCTION	61,546			57,400			50,791
EXPLORATION	7,300			6,470			4,912
TRANSPORTATION	4,908			4,471			3,909
LEASE RENTALS	1,424			1,207			1,324
AMORTIZATION OF UNPROVEN LANDS	21,890			18,553			18,329
DEPLETION AND DEPRECIATION	115,634			112,707			94,143
DRY HOLES	13,906			5,560			8,966
ACCRETION EXPENSE	2,300			1,902			—
GENERAL AND ADMINISTRATIVE	21,816			18,218			15,816
INTEREST EXPENSE/(INCOME) (Note 13)	(2,461		)	(129		)	16,941
FOREIGN EXCHANGE GAIN / LOSS	(70		)	255			(919		)
TOTAL EXPENSE	248,193			226,614			214,212
EARNINGS (LOSS) BEFORE INCOME TAXES	94,068			84,911			(13,489		)
INCOME TAXES (Note 6)
CURRENT	7,671			6,578			5,788
DEFERRED	32,772			16,336			(3,761		)
	40,443			22,914			2,027
EARNINGS (LOSS) FROM CONTINUING OPERATIONS	53,625			61,997			(15,516		)
CUMULATIVE EFFECT OF ACCOUNTING	—			3,836			—
NET EARNINGS (LOSS)	$	53,625		$	65,833		$	(15,516	)
RETAINED EARNINGS - BEGINNING OF YEAR	$	(39,202	)	$	(105,035	)	$	(89,519	)
RETAINED EARNINGS - END OF YEAR	$	14,423		$	(39,202	)	$	(105,035	)

See accompanying notes to the consolidated financial statements

Northrock Resources Ltd.

Consolidated Statements of Cash Flows

Years Ended December 31, 2004, 2003 and 2002

(thousands of U.S. dollars)	2004			2003			2002
CASH INFLOW (OUTFLOW) FROM THE FOLLOWING ACTIVITIES:
OPERATING
NET EARNINGS	$	53,625		$	65,833		$	(15,516	)
ADJUSTMENTS TO RECONCILE NET EARNINGS TO NET CASH FROM OPERATING ACTIVITIES
DEPLETION AND DEPRECIATION	115,634			112,707			94,143
DRY HOLES	13,906			5,560			8,966
AMORTIZATION OF UNPROVEN LANDS	21,890			18,553			18,329
ACCRETION EXPENSE	2,300			1,902			—
DEFERRED INCOME TAXES	32,736			17,813			(3,131		)
CUMULATIVE EFFECT OF ACCOUNTING CHANGE	—			(5,966		)	—
DEFERRED LOSS - UNREALIZED TRADE AND HEDGE	(7,271		)	(33,530		)	(15,380		)
OTHER	2,702			3,283			1,287
ASSET RETIREMENT OBLIGATIONS	(2,161		)	(2,612		)	(1,776		)
CHANGE IN NON-CASH WORKING CAPITAL (Note 15)	(15,210		)	(7,800		)	(3,697		)
NET CASH FLOW FROM OPERATING ACTIVITIES	218,151			175,743			83,225
FINANCING
LONG TERM FROM RELATED COMPANY (Note 13)	—			(28,749		)	157,054
LONG TERM DEBT	—			—			(75,000		)
NOTE RECEIVABLE FROM RELATED COMPANY (Note 13)	(76,052		)	(36,183		)	—
CAPITAL LEASE	—			(5,279		)	(765		)
FLOW THROUGH SHARES ISSUED TO RELATED COMPANY (Note 13)	—			2,308			—
NET CASH FROM FINANCING ACTIVITIES	(76,052		)	(67,903		)	81,289
CASH AVAILABLE FOR INVESTING	142,099			107,840			164,514
INVESTING
CAPITAL EXPENDITURES (INCLUDES DRY HOLE COSTS)	(135,987		)	(132,917		)	(130,759		)
CORPORATE ACQUISITIONS (Note 4)	—			—			(28,319		)
PROCEEDS FROM SALES OF ASSETS	7,001			20,390			5,424
OTHER INVESTMENTS	(458		)	(986		)	604
NET CASH USED IN INVESTING ACTIVITIES	(129,444		)	(113,513		)	(153,050		)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	12,655			(5,673		)	11,464
CASH, BEGINNING OF YEAR	(3,052		)	2,621			(8,843		)
CASH, END OF YEAR	$	9,603		$	(3,052	)	$	2,621

See accompanying notes to the consolidated financial statements

Northrock Resources Ltd.

Consolidated Statements of Shareholders’ Equity

Years Ended December 31, 2004, 2003, and 2002

(thousands of U.S. dollars)	2004			2003			2002
COMMON STOCK (Notes 11,13)
BALANCE AT BEGINNING OF YEAR	$	565,641		$	564,256		$	564,256
ISSUANCE OF FLOW THROUGH COMMON STOCK	—			1,385			—
BALANCE AT END OF YEAR	565,641			565,641			564,256
RETAINED EARNINGS
BALANCE AT BEGINNING OF YEAR	(39,202		)	(105,035		)	(89,519		)
NET EARNINGS FOR YEAR	53,625			65,833			(15,516		)
BALANCE AT END OF YEAR	14,423			(39,202		)	(105,035		)
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
BALANCE AT BEGINNING OF YEAR	59,138			(46,862		)	(54,512		)
FOREIGN CURRENCY TRANSLATION	51,584			97,990			4,182
OTHER COMPREHENSIVE INCOME	5,662			8,010			3,468
BALANCE AT END OF YEAR	116,384			59,138			(48,862		)
TOTAL SHAREHOLDERS’ EQUITY	$	696,448		$	585,577		$	412,359

See accompanying notes to the consolidated financial statements

Northrock Resources Ltd.

Consolidated Statements of Comprehensive Income

Years Ended December 31, 2004, 2003, and 2002

(thousands of U.S. dollars)	2004		2003		2002
NET EARNINGS (LOSS)	$	53,625	$	65,833	$	(15,516	)
CHANGE IN OTHER COMPREHENSIVE INCOME - HEDGING (a)	5,662		8,010		3,468
UNREALIZED FOREIGN CURRENCY TRANSLATION	51,584		97,990		4,182
TOTAL COMPREHENSIVE INCOME (LOSS)	$	110,871	$	171,833	$	(7,866	)
(a) Net of tax effect of:	3,325		4,704		2,037

See accompanying notes to the consolidated financial statements

Northrock Resources Ltd.

Notes to the Consolidated Financial Statements

(Thousands of U.S. dollars, except where noted)

For the Years Ended December 31, 2004, 2003 and 2002

NOTE 1 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation – The financial statements of Northrock Resources Ltd. (the “Company”) include the accounts of the Company and all of its subsidiaries. The Company’s principal business activity is the exploration for and development of natural resource properties. The Company’s operations are focused in Western Canada.

The Company is a wholly-owned subsidiary of Unocal Corporation (the “Parent”). In 1999, Unocal Corporation acquired an approximate 48 percent controlling interest in the Company with the remaining outstanding common shares acquired in 2000. The Company has been fully consolidated in Unocal Corporation’s financial results since its initial acquisition in May 1999. As a result of the acquisition the application of push-down accounting was applied. Accordingly, the financial statements reflect the amounts allocated to the Company’s assets.

Use of Estimates – The financial statements are prepared in conformity with accounting principles generally accepted in the United States of America, which require management to make estimates and assumptions that affect the amounts of assets and liabilities and the disclosures of contingent liabilities as of the financial statement date and the amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Revenue Recognition – Revenues associated with sales of crude oil, condensate, natural gas and natural gas liquids are recognized when products have been delivered.

Revenues from properties in which we have an interest with other producers are recognized on the basis of our working interest (“entitlement method of accounting”).

Inventories – Inventories are valued at the lower of cost or market. The costs of inventories are determined using the average cost method.

Impairment of Assets – Oil and gas developed and undeveloped properties are assessed for possible impairment on an area-by-area basis using the estimated undiscounted future cash flows of each area. Impairment losses are recognized when the estimated undiscounted future cash flows are less than the current net book values of the properties in an area. The measurement of the impairment amount to be recorded is based on expected discounted future cash flows or fair values. These expected future cash flows are estimated based on management’s plans to continue to produce and develop proved and associated risk-adjusted probable and possible reserves. Expected future cash flows from the sate of production or reserves are calculated based on management’s best estimate of future crude oil and natural gas prices using market-based information. The estimated future level of production is based on assumptions surrounding future commodity prices, lifting and development costs, field decline rates, market demand and supply, the economic regulatory climates and other factors.

Impairment charges are also made for other long-lived assets when it is determined that the carrying values of the assets may not be recoverable. A long-lived asset is reviewed for impairment whenever events or changes in circumstances indicate that the carrying value of the asset may not be recoverable.

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Goodwill, which represents the excess of purchase price over fair value of net assets acquired, is not amortized but is reviewed for impairment on an annual basis and at other times when an event occurs or circumstances change that could negatively impact the fair value of the Company. Fair value is determined by taking into consideration such factors as current commodity prices in cases where the present value of discounted cash flows are used in the valuation as well as externally available valuation data for similar operations in like geographic areas. If the carrying amount of the Company exceeds the fair value, a purchase price type allocation is made to the identifiable assets and liabilities of the Company as if acquired in a business combination and the remaining unallocated value is compared to recorded goodwill to determine if a write-down is required.

Asset Retirement Obligations (“AROs”) – Effective January 1, 2003, the Company adopted Statement of Financial Accounting Standards (“SFAS”) No. 143, “Accounting for Asset Retirement Obligations,” (see note 9 for further details). This Statement requires that the Company recognize liabilities related to the legal obligations associated with the retirement of its tangible long-lived assets in the periods in which the obligations are incurred (typically when the assets are installed) if a reasonable estimate of fair value can be made. These obligations include the required plugging and abandonment of oil and gas wells and the restoration of certain sites at the time of abandonment.

Under SFAS No. 143, liabilities for asset retirement obligations are initially recorded at fair values and the carrying values of the related assets are increased by corresponding amounts. Over time, changes in the present value of the liabilities are accreted and expensed and the capitalized asset costs are depreciated over the useful lives of the corresponding assets. Recognized liability amounts are based upon future retirement cost estimates and incorporate many assumptions such as expected economic recoveries of crude oil and natural gas, time to abandonment, future inflation rates and the risk free rate of interest adjusted for the Company’s credit costs. Future revisions to ARO estimates will impact the present value of existing ARO liabilities and corresponding adjustments will be made to the capitalized asset retirement costs balance.

Oil and Gas Exploration and Development Costs – The Company follows the successful efforts method of accounting for oil and gas activities. Acquisition costs of exploratory acreage are capitalized when incurred. Such costs related to the portion of properties expected to be non-commercial, based on exploratory experience and judgement, are amortized for impairment over the shorter of the exploratory period or the lease/concession holding period. Costs of successful leases are transferred to proved properties. Geological and geophysical costs for exploration and leasehold rental for unproved properties are expensed.

Exploratory drilling costs are initially capitalized. If an exploratory well results in discovery of commercial reserves, the well investment is transferred to proved properties at the time reserves are booked. Exploratory wells that are non-commercial are expensed as dry holes. Costs of exploratory wells that have found commercially producible quantities of reserves that cannot be classified as proved remain capitalized while awaiting anticipated required major capital expenditures. Costs also remain capitalized for wells that have found sufficient quantities of reserves to justify their completion as long as we have firm plans to drill additional wells

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necessary to determine the existence of proved reserves. Costs of drilling other exploratory wells that do not require major expenditures are not carried on the books for more than one year following completion of drilling.

Development costs of proved properties, including unsuccessful development wells are capitalized.

Depreciation, Depletion and Amortization – Depreciation, depletion and amortization related to acquisition costs and development costs of proved properties, including capitalized abandonment and removal costs, are calculated at unit-of-production rates based upon total proved or proved developed reserves. Depreciation of other properties, including capitalized abandonment and removal costs, is generally on a straight-line method using various rates based on estimated useful lives.

Maintenance and Repairs – Expenditures for maintenance and repairs are expensed. In general, improvements are capitalized to the respective property accounts.

Income Taxes – The Company uses the liability method for reporting income taxes, under which current and deferred tax liabilities and assets are recorded in accordance with enacted tax laws and rates. Under this method, the amounts of deferred tax liabilities and assets at the end of each period are determined using the tax rate expected to be in effect when taxes are actually paid or recovered. Future tax benefits are recognized to the extent that realization of such benefits is more likely than not.

Deferred income taxes are provided for the estimated income tax effect of temporary differences between financial and tax bases in assets and liabilities. Deferred tax assets are also provided for certain tax credit carryforwards. A valuation allowance to reduce deferred tax assets is established when deemed appropriate.

Foreign Currency Translation – Foreign exchange translation adjustments as a result of translating a foreign entity’s financial statements from its functional currency into U.S. dollars are included as a separate component of other comprehensive income in shareholders’ equity on the consolidated balance sheet. The functional currency for all operations is the Canadian dollar. Gains or losses incurred on currency transactions in other than the Company’s functional currency are included in net earnings.

Risk Management – The Company’s risk management strategies include reducing overall volatility of our cash flows, preserving revenues and exploiting anticipated opportunities arising from commodity price fluctuations. As part of the overall risk management strategy, the Company enters into various derivative instrument contracts to offset portions of exposures to changes in interest rates, changes in foreign currency exchange rates, and fluctuations in crude oil and natural gas prices. In general, the Company enters into derivative instruments to hedge two types of exposures: cash flow exposures and fair value exposures. Hedges of cash flow exposures are generally undertaken to reduce cash flow volatility associated with forecasted transactions. They may also be used to reduce volatility associated with cash flows to be paid related to

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recognized liabilities. Hedges of fair value exposures are undertaken to hedge recognized assets or liabilities or unrecognized firm commitments against changes in value.

Interest Rates – From time to time, we enter into interest rate swap contracts to manage the interest cost of our debt with the objective of minimizing the volatility and magnitude of our borrowing costs.

Foreign Currency – Various foreign currency forward, option and swap contracts are entered into to manage our exposures to adverse impacts of foreign exchange fluctuations on recognized obligations and anticipated transactions.

Commodities – Hydrocarbon derivatives such as futures, swaps, collars and options are used to mitigate the overall exposure to fluctuations in hydrocarbon commodity prices. The Company also trades hydrocarbon derivative financial instruments subject to certain limits.

In accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” all derivative instruments are recorded as assets or liabilities on the balance sheet at their fair values. We routinely enter into various purchase and sale contracts that will ultimately result in the physical delivery of hydrocarbon commodities. We have determined that the normal purchase and normal sale exception included in paragraph 10(b) of SFAS No. 133 applies to such contracts, so we do not account for them as derivatives pursuant to SFAS No. 133.

At the inception of a derivative contract, the Company may choose to designate and document a derivative as a cash flow hedge or a fair value hedge. Changes in the values of derivatives not designated and documented as hedges are recorded in current-period earnings.

Changes in the values of derivatives that qualify for, and are designated and effective as, cash flow hedges are deferred and recorded as components of accumulated other comprehensive income until the hedged transactions occur and are then recognized in earnings. Any ineffectiveness that is related to changes in the values of cash flow hedge derivatives is recognized immediately in earnings as a component of sales revenues. Changes in the value of derivatives that qualify for, and are designated and effective as, fair value hedges are recognized in current-period earnings as components of the line items reflecting the underlying hedged transactions. Changes in the fair values of the underlying hedged items (e.g., recognized assets, liabilities or unrecognized firm commitments) are also recognized in current-period earnings and offset the changes in values of the corresponding hedging derivatives. Any resulting fair value hedge ineffectiveness is recognized in current-period earnings as the difference between the offsetting changes in values of the derivative and the underlying hedged item.

We document our risk management objectives, our strategies for undertaking various hedge transactions and the relationships between hedging instruments and hedged items. Derivatives designated as cash flow hedges are linked to forecasted transactions. Derivatives identified as fair value hedges are linked to specific assets, liabilities or firm commitments. At hedge inception and on an on-going basis, we assess whether changes in the values of derivatives used in hedging activities are highly effective in offsetting changes in the values of the hedged items. We discontinue hedge accounting prospectively when either (1) we determine that a derivative is not

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highly effective as a hedge, (2) the derivative is sold, exercised or otherwise terminated, (3) management elects to remove the derivative’s hedge designation, (4) the hedged transaction is no longer expected to occur, or (5) a hedged item no longer meets the definition of a firm commitment. When a hedged forecasted transaction is no longer expected to occur, the derivative continues to be carried on the balance sheet at its fair value and all unrealized gains and losses that were previously deferred in accumulated other comprehensive income are recognized immediately in earnings. When a hedged item no longer meets the definition of a firm commitment, the derivative continues to be carried on the balance sheet at its fair value and any asset or liability that was recorded on the balance sheet for the change in value of the hedged firm commitment is removed from the balance sheet and recognized immediately in the current-period earnings. In all other situations where hedge accounting is discontinued, the derivatives continue to be carried on the balance sheet at their fair values and any prospective changes in their fair values are recognized in current-period earnings. Deferred gains and losses already recorded in accumulated other comprehensive income remain until the forecasted transactions occur, at which time those gains and losses are recognized in earnings.

Stock-Based Compensation – The Company applies Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees”, and related interpretations in accounting for stock-based compensation. Stock-based compensation expense recognized in the Company’s consolidated earnings includes expenses related to the Company’s various cash incentive plans that are paid to certain employees based upon defined measures of the Company’s performance and net asset value.

Cash and Cash Equivalents – Cash comprises cash on hand and demand deposits. Cash equivalents are highly liquid investments purchased with a maturity of three months or less.

Transportation Costs – Expenses incurred for transporting crude oil and natural gas are included as a component of operating expense.

NOTE 2 – ACCOUNTING CHANGES

SFAS No. 143: Effective January 1, 2003, the Company adopted SFAS No. 143, “Accounting for Asset Retirement Obligations.” If a reasonable estimate of fair value can be made, this Statement requires that the Company recognize liabilities related to the legal obligations associated with the retirement of its tangible long-lived assets in the periods in which the obligations are incurred (typically when the assets are installed). These obligations include the required plugging and abandonment of oil and gas wells and the restoration of certain sites at the time of abandonment. The recognized liability amounts are based upon future retirement cost estimates and incorporate many assumptions such as expected economic recoveries of crude oil and natural gas, time to abandonment, future inflation rates and the risk free rate of interest adjusted for the Company’s credit costs.

Prior to January 1, 2003, the Company was required under SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies,” to accrue its abandonment and restoration costs ratably over the productive lives of its assets using the units-of-production method. SFAS No. 19 resulted in higher costs being accrued early in the fields’ lives when production was at its

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highest levels and abandonment and restoration costs accruals were matched with the revenues as oil and gas were produced.

Under SFAS No. 143, when the liabilities for asset retirement obligations are initially recorded at their fair value, capital costs of the related assets will be increased by equal corresponding amounts. Over time, changes in the present value of the liabilities will be accreted and expensed and the capitalized asset costs will be depreciated over the useful lives of the corresponding assets. Because SFAS no. 143 requires the use of interest accretion for revaluing asset retirement obligation liabilities as a result of the passage of time, associated accretion costs will be disproportionately higher near the end of the fields’ lives when oil and gas production and related revenues are at their lowest levels.

APB Opinion No. 20, “Accounting Changes” required that the Company calculate the retroactive impact of adopting SFAS No. 143 from the inception of its asset retirement obligations to its January 1, 2003 adoption date. APB Opinion No. 20 required that this impact be quantified and reported as a cumulative effect of an accounting change on the earnings statement. This cumulative effect included the catch up of SFAS No. 143 accretion expense related to the fair value of the liabilities as well as the catch up of associated depreciation expense related to the increased capital costs of the corresponding assets. The cumulative effect also included the reversal of abandonment and restoration costs previously charged to earnings under SFAS No. 19.

In the first quarter of 2003, the Company recognized a one time after-tax gain of $3.8 million as the cumulative effect of an accounting change related to the adoption of SFAS No. 143. The company also increased its accrued abandonment and restoration liabilities by $13.6 million and increased its net properties by $19.3 million on the consolidated balance sheet as a result of the adoption of SFAS No. 143 as of January 1, 2003. The impact of adopting SFAS No. 143 on the Company’s 2003 operating earnings was an incremental charge of approximately $2.4 million after tax.

FASB Staff Position No. 142-2: In 2004, the FASB issued Staff Position No. 142-2, “Application of FASB Statement No. 142, Goodwill and Other Intangible Assets, to Oil- and Gas- Producing Entities,” that clarified that oil and gas drilling rights are tangible assets. This position is consistent with our classification of the cost of acquiring oil and gas drilling rights in property, plant and equipment on our consolidated balance sheet. Therefore, adoption of this rule had no impact on either our earnings or consolidated balance sheet.

EITF Issue 04-9 and FASB Staff Position (“FSP”) FAS 19-a: SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies” requires the cost of drilling an exploratory well to be capitalized pending determination of whether the well has found proved reserves. If this determination cannot be made at the conclusion of drilling, SFAS No. 19 sets out additional requirements for continuing to carry the cost of the well as an asset. These requirements include firm plans for further drilling and a one-year time limitation on continued capitalization in certain instances. The EITF in their discussion of this issue noted that as a result of the increasing complexity of oil and gas projects due to drilling in remote and deepwater offshore locations, companies increasingly require more than one year to complete all of the

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activities that permit recognition of proved reserves. Furthermore, because of new technologies, additional exploratory wells may no longer be required before a project can commence. EITF Issue 04-9, “Accounting for Suspended Well Costs,” sought to determine whether SFAS No. 19 should be clarified to recognize the industry changes that have taken place in the past quarter century. This issue was discussed by the EITF and it was determined that a formal amendment to SFAS No. 19 would be required if the FASB concurs with broadening the requirements for continued capitalization of exploratory well costs. In April 2005, the FASB issued FSP FAS 19-a. This FSP amends SFAS No. 19, to allow continued capitalization when (a) the well has found a sufficient quantity of reserves to justify proceeding with the project plan and (b) the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the project which may include more than one exploratory well if the reserves are intended to be extracted in a single integrated operation. Most of the additional FSP disclosures are presented in note 6 – Property, Plant and Equipment. If this FSP had been applied to 2004, 2003 and 2002, it would not have a material impact on our net earnings in any of those years.

SFAS No. 151: In 2004, the FASB issued SFAS No. 151, “Inventory Costs – an amendment of ARB No. 43, Chapter 4,” which is effective for inventory costs incurred after December 31, 2005. This statement requires that items such as idle facility expense, excessive spoilage, double freight, and rehandling costs be recognized as current-period charges regardless of whether they meet the criterion of “so abnormal” as stipulated in Chapter 4 of ARB No. 43. In addition, this statement requires that fixed production overhead allocated to inventory be based on the normal capacity of the production facilities. Adoption of this pronouncement is not expected to have a significant impact on either our earnings or consolidated balance sheet.

SFAS No. 123 (revised 2004): In 2004, the FASB issued SFAS No. 123 (revised 2004) “Share-Based Payment,” an amendment of FASB Statement Nos. 123 and 95, which is effective July 1, 2005. This pronouncement requires use of the fair value method to account for share-based awards and potentially increases the number of grants considered liability awards. In addition to more disclosures and a change in reporting the cash flows of certain stock option excess realized income tax benefits, it also requires liability awards to be reported at fair value rather than intrinsic value. Equity awards will continue to be recorded at grant-date fair value and recognized over the vesting period. Liability awards will be reported at fair value until settlement or expiration.

SFAS No. 123R, “Accounting for Stock-Based Compensation,” is effective prospectively July 1, 2005. All of the forms of stock-based compensation for the Company to which this standard would apply after July 1, 2005 are all based on the Stock of the Company’s Parent. The following table illustrates the effect on net earnings if the company had applied the fair value based recognition provisions of SFAS No. 123, “Accounting for Stock-Based Compensation,” to all outstanding and unvested stock option awards in each period:

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	December 31, 2004			December 31, 2003			December 31, 2002
Net earnings, as reported	$	53,625		$	65,833		$	(15,516	)
Deduct: Total stock-based employee compensation expense determined under the fair value method for all awards, net of related tax effects (a)	(350		)	(403		)	(186		)
Pro forma net earnings	$	53,275		$	65,430		$	(15,702	)

(a) The fair value of stock option awards is estimated using the Black-Scholes option pricing model.

SFAS No. 153: In 2004, the FASB issued SFAS No. 153, “Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29,” which is effective prospectively July 1, 2005.  With certain exceptions, this will require exchanges of nonmonetary assets to be recorded at fair value. Currently these transactions are generally recorded at book value. This pronouncement will result in reporting in earnings, gains and losses on future exchanges of nonmonetary assets. Because we operate in a capital-intensive industry, future exchanges of nonmonetary assets may materially impact our future earnings or consolidated balance sheet.

NOTE 3 – INVENTORIES

	2004		2003
Crude oil	$	2,164	$	1,030
Natural Gas	3,708		2,262
Total Inventory	$	5,872	$	3,292

NOTE 4 – CORPORATE ACQUISITION

In June 2002, the Company acquired all the outstanding shares of common stock of Corsair Exploration Inc. (“Corsair”), a Canadian exploration and production company primarily engaged in activity in West Central Alberta. The acquisition was funded with cash on hand.

Purchase price:
Cash consideration	$	28,319
Non-cash working capital deficit assumed	1,014
Debt assumed	5,898
Total Purchase price	$	35,231
Purchase price allocated as follows:
Property and equipment	$	34,186
Goodwill	10,105
Site Restoration	(138		)
Deferred Income Tax	(8,922		)
	$	35,231

No other significant corporate acquisitions were made by the Company in 2004, 2003 and 2002.

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NOTE 5 – PROPERTY PLANT AND EQUIPMENT

	Cost		2004 Accumulated depletion and depreciation		Net		Cost		2003 Accumulated depletion and depreciation		Net
Exploration	$	289,995	$	126,683	$	163,312	$	261,530	$	95,540	$	165,990
Production and Development	1,806,221		714,537		1,091,684		1,565,321		547,901		1,017,420
Furniture, Fixtures and Other	14,959		10,547		4,412		13,372		8,589		4,783
Total property, plant and Equipment	$	2,111,175	$	851,767	$	1,259,408	$	1,840,223	$	652,030	$	1,188,193

Included in property, plant and equipment are asset retirement costs, net of amortization, of $22.3 million (2003 - $20.3 million).

During the year ended December 31, 2004, the Company capitalized administrative overhead of $2.9 million (2003 - $2.5 million).

Exploration costs represent unproved land and major exploration projects. Unproved land costs are amortized straight-line over 5 years. Major exploration projects are not subject to depletion or depreciation. Included in the exploration caption of the above table are capitalized exploratory drilling costs for suspended wells. The total exploratory drilling costs for suspended wells capitalized in 2004 was $11.2 million and $14.8 million in 2003. All wells included in the December 31, 2004 ending balance had drilling activity in the area during 2004. The Company had no projects that had been suspended for more than one year at December 31, 2004.

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NOTE 6 – INCOME TAXES

The provision for income taxes in the statement of earnings differs from that which would be expected by applying the applicable statutory tax rates. The reasons for the difference are as follows;

	December 31, 2004			December 31, 2003			December 31, 2002
Canadian statutory income tax rate	39.83		%	41.55		%	42.12		%
Income tax provision at statutory rate	$	37,467		$	37,759		$	(5,681	)
Effect on income taxes of:
Non deductible crown payments	25,357			27,492			23,229
Resource allowance	(19,786		)	(19,264		)	(21,417		)
Large corporations tax and resource tax	7,821			6,610			5,507
Rate reductions and reconciliations	(7,639		)	(26,362		)	—
Previously unrecognized royalty tax credit	(951		)	—			—
Attributed Canadian Royalty Income	(973		)	—			—
Other	(853		)	(1,191		)	389
Tax on accounting change	—			(2,130		)	—
Income Tax	$	40,443		$	22,914		$	2,027

The net deferred income tax liability is comprised of:

	December 31, 2004		December 31, 2003
Deferred tax liabilities
Property, plant and equipment	$	281,948	$	243,102
Timing of partnership items	8,772		—
Other	4,557		2,816
	295,277		245,918
Deferred tax assets
Current
Derivative liability	—		6,300
Long term
Attributed Canadian royalty income & royalty tax credits	14,880		16,732
Asset retirement obligation	5,598		4,611
Other	—		789
	20,478		28,432
Deferred income tax liability (net)	$	274,799	$	217,486

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NOTE 7 – LONG-TERM DEBT AND CREDIT AGREEMENTS

	2004		2003
Bank credit facilities	$	—	$	—
	$	—	$	—

In November 2004, the Company and its Canadian affiliate, Unocal Canada Limited, also a wholly owned subsidiary of Unocal Corporation, entered into a new $295 million Canadian dollar-denominated credit agreement with five commercial banks with a maturity date of December 2009. The credit agreement is composed of a $200 million Canadian dollar-denominated term loan and a $95 million Canadian dollar-denominated revolving loan facility. Both loans provide for the payment of a variable rate of interest on borrowed amounts. This new agreement replaced an existing $295 million Canadian dollar-denominated non-revolving credit facility with a variable rate of interest, which was terminated before it was due to expire on December 19, 2005.

Under this new agreement, the Company is named as an alternative borrower and co-guarantor. At December 31, 2003 and 2004, the Company did not have any borrowings under the credit agreement. At December 31, 2003 and 2004, Unocal Canada Limited had borrowings amounting to $294 million.

NOTE 8 – OTHER LONG-TERM LIABILITIES

	2004		2003
Stock-based compensation (Note 12 (d))	$	473	$	—
Storage gas purchase commitment (Note 10)	3,466		3,861
	3,939		3,861
Less: current portion	917		850
	$	3,022	$	3,011

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NOTE 9 – ASSET RETIREMENT OBLIGATION

At December 31, 2004, the Company’s total estimated undiscounted costs to settle its asset retirement obligations with respect to crude oil and natural gas properties and facilities was $72.6 million (2003 - $ 66.6 million). These costs will be incurred over several years and have been discounted using a credit-adjusted risk-free interest rate of 6.03%. A reconciliation of the discounted asset retirement obligation is as follows;

	2004			2003
Asset retirement obligation
Balance – beginning of year	$	35,991		$	33,756
Liabilities incurred	2,336			—
Liabilities settled	(2,066		)	(2,471		)
Accretion expense	2,300			1,902
Revisions recorded during the year	(127		)	—
Balance – end of year	$	38,434		$	33,187

NOTE 10 – COMMITMENTS AND CONTRACTUAL OBLIGATIONS

As at December 31, 2004	2005		2006		2007		2008		2009		Thereafter		Total
Pipeline Transportation	$	783	$	1,752	$	3,331	$	—	$	295	$	—	$	6,161
Storage Gas Purchases	636		579		526		478		434		813		3,466
Purchases of Goods and	1,595												1,595
Services
Office Lease (a)	2,038		2,065		2,093		—		—		—		6,196
Total	$	5,052	$	4,396	$	5,950	$	478	$	729	$	813	$	17,418

(a) The above noted office lease isan operating lease.

NOTE 11 – SHARE CAPITAL

Authorized

The authorized share capital of the Company is comprised of;

An unlimited number of Class A Common Shares without par value.

An unlimited number of Class B Common Shares without par value.

An unlimited number of Class A Preferred Shares without par value.

Issued and Outstanding at December 31, 2004

761,247 Class A Common shares.

62,886,476 Class B Common shares.

5,000 Class A Preferred shares.

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100% of all classes of shares are held by the Parent through related Canadian companies. All class A common shares and class A preferred shares hold voting rights. Class B common shares hold no voting rights.

The Class A Preferred shares require redemption at a fixed amount and pursuant to SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity,” are therefore recognized as debt and included in long term liabilities on the consolidated balance sheet.

	“A” Common	“B” Common	“A” Preferred
Balance at December 31, 2001	750,616	62,886,476	—
Flowthrough shares issued	—	—	—
Other shares issued	—	—	5,000
Balance at December 31, 2002	750,616	62,886,476	5,000
Flowthrough shares issued	10,631	—	—
Other shares issued	—	—	—
Balance at December 31, 2003 & 2004	761,247	62,886,476	5,000

NOTE 12 – STOCK BASED COMPENSATION

The Company and the Parent have adopted incentive programs for management and certain employees to provide incentives and rewards to strengthen commitment and maximize profitability.

(a) Stock Options

Certain employees of the Company hold stock options which entitle the holder to purchase common shares of the Parent. Option exercise prices approximate the market price for the common shares on the date the options were issued. Options granted under the plans are generally fully exercisable after three years and expire ten years after the grant date. Stock options vest immediately upon change of control.

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	Number of Stock Options		Weighted Average Stock Option Exercise Price Per Share*		Weighted Average Grant Date Market Price Per Share*
Stock options outstanding at January 1, 2002	130,507		$	32.33	$	—
Stock options granted during year	39,321		34.73		34.73
Stock options exercised during year	—		—
Stock options cancelled/forfeited during year	(1,276	)	34.73
Stock options outstanding at December 31, 2002	168,552		32.87
Stock options exercisable at December 31, 2002	75,084		32.64
Stock options outstanding at January 1, 2003	168,552		$	32.87	$	—
Stock options granted during year	156,173		27.07		27.07
Stock options exercised during year	(539	)	27.07
Stock options cancelled/forfeited during year	(10,025	)	30.01
Stock options outstanding at December 31,2003	314,161		30.09
Stock options exercisable at December 31, 2003	154,972		31.16
Stock options outstanding at January 1, 2004	314,161		$	30.09	$	—
Stock options granted during year	84,617		36.87		36.87
Stock options exercised during year	(132,127	)	30.46
Stock options cancelled/forfeited during year	(13,177	)	31.84
Stock options outstanding at December 31, 2004	253,474		32.07
Stock options exercisable at December 31, 2004	97,718		31.50

*Weighted average price per share in USD

	2004			2003			2002
Weighted-average fair value of common stock options granted during the year*	$	7.98		$	6.20		$	9.35
Assumptions:
Expected life (years)	4.4			4.4			4.4
Expected volatility	27.4		%	31.7		%	32.7		%
Expected dividend yield	2.2		%	3.0		%	2.2		%
Risk-free interest rate	2.9		%	2.9		%	4.3		%

*Weighted average price per share in USD

(b) Performance Shares

Certain employees of the Company were granted performance share awards. Outstanding performance share awards issued prior to 2004 have four-year terms and can be paid out in common stock of the Parent and/or cash. The amount of the payout for these awards is based on a percentile ranking of the Parent’s common stock total return relative to the total returns on the common stock of a peer group of companies.

Outstanding performance share awards issued in 2004 under the Parent’s 2004 Management Incentive program have three-year terms and can be paid out in common stock of the Parent and/or cash. The payout for the 2004 awards is based on a composite percentile ranking of selected financial and operational performance measures relative to the same performance measures for a peer group of companies. Payouts under all performance share awards are subject

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to downward adjustments at the discretion of the Parent’s Management Development and Compensation Committee. All performance share awards become vested upon a change of control.

	Number of Performance Shares	Weighted Average Grant Date Market Price Per Share*
Performance shares awarded
2002	5,956	$	33.88
2003	8,742	30.39
2004	9,356	36.93

*Price per performance share granted in USD

(c) Special Stock Options

The Company maintains a stock option plan whereby options can be granted to certain employees. The options vest over a period of 4 years and have a term of 5 years from the date of grant. Effective January 1, 2002 the stock option plan was terminated for new employees and no new options were granted. Vested options exercised entitle the option holder to purchase a share of the Company at the Exercise Price, or to dispose of the option and receive the Cash-Out Value of those options. The Cash-Out Value of the option is determined as the product of the difference, if positive, between the Current Value per Share less the Exercise Price of the applicable option and the number of options being disposed. All options exercised under this option plan were disposed for the Cash-Out Value and no shares were issued.

Changes in the number of outstanding stock options were as follows:

	Number of Options	Weighted-Average Exercise Price (CDN)
Options outstanding at January 1, 2002	6,044,881	$	10.92
Options granted during year	—	—
Options exercised during year	2,114,444	$	11.35
Options cancelled during year	258,185	$	11.92
Options outstanding at December 31, 2002	3,672,252	$	10.60
Options granted during year	—	—
Options exercised during year	1,448,434	$	10.36
Options cancelled during year	342,838	$	10.46
Options outstanding at December 31, 2003	1,880,980	$	10.81
Options granted during year	—	—
Options exercised during year	1,615,500	$	10.64
Options cancelled during year	72,706	$	11.70
Options outstanding at December 31, 2004	192,774	$	11.87

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The following Stock options were outstanding as at December 31, 2004:

Price	Options Outstanding	Weighted- Average Exercise Price (CDN)		Options Exercisable	Weighted- Average Exercise Price (CDN)		Weighted- Average Life
$10.10	20,897	$	10.10	19,832	$	10.10	1.03
$11.44	16,390	$	11.44	12,975	$	11.44	1.83
$11.50	86,182	$	11.50	70,022	$	11.50	1.75
$12.41	6,043	$	12.41	5,540	$	12.41	1.67
$12.56	20,501	$	12.56	17,511	$	12.56	1.58
$12.59	2,829	$	12.59	2,593	$	12.59	1.33
$12.98	26,404	$	12.98	20,353	$	12.98	1.92
$13.86	13,528	$	13.86	11,837	$	13.86	1.50
$10.10 to $13.86	192,774	$	11.87	160,663	$	11.85	1.67

During 2004, the Company recorded compensation expense of $3.8 million (2003 - $4.9 million, 2002 - $2.3 million) relating to stock options.

(d) Phantom Restricted Stock Units

Effective 2004, the Company has in place a program whereby certain employees are granted Phantom Restricted Stock Units (“PRSU”) which entitle the employee to receive the value of one outstanding share of the common stock of the Parent. PRSU granted in 2004 will vest on October 1, 2007, or upon a change of control. Amounts are recorded as compensation expense over the vesting period and valued using the weighted average market price for the period in which the expense is recorded.

	Number of Performance Shares	Weighted Average Grant Date Market Price Per Share*
Phantom Restricted Stock Units Awarded
2002	—	—
2003	—	—
2004	45,564	$	37.19

*Price per share granted stated in USD

During 2004, the Company recorded compensation expense of $0.5 million relating to phantom restricted stock units.

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NOTE 13 – RELATED PARTY TRANSACTIONS

A substantial portion of the natural gas produced by the Company is sold to Unocal Canada Limited, a Canadian affiliate within the Parent’s midstream and trade business segment. Total gas sales amounted to $137.8 million in 2004, $143.1 million in 2003 and $33.6 million in 2002. Unocal Canada Limited, purchases the Company’s natural gas at market prices

In 2004, the Company and Unocal Canada Limited, a Canadian affiliate, entered into a $295 million Canadian dollar-denominated credit agreement with a maturity date of December 2009. The credit agreement is composed of a $200 million Canadian dollar-denominated term loan and a $95 million Canadian dollar-denominated revolving loan facility.  Under this agreement, the Company is named as an alternative borrower and co-guarantor.  At December 31, 2003 and 2004, the Company did not have any borrowings under the credit agreement.

In 2003, the Company issued an interest bearing revolving, demand note to Unocal Canada Limited, a Canadian affiliate, for a maximum authorization amount of $400 million US (or equivalent Canadian dollar). At December 31, 2004, the balance receivable was $123 million (2003 - $39 million). During the year, the Company recognized interest on the note amounting to $2.7 million (2003 - $0.7 million, 2002 - nil)

In 2003, the Company paid off the balance relating to an interest bearing note to Unocal Canada Limited, a Canadian affiliate. This repayment amounted to $28.7 million (2002 - $164.0 million). Total interest paid during 2003 on this debt was $0.2 million (2002 - $9.1 million).

In 2003, the Company issued flow through shares for total consideration of CDN $3.4 million to Unocal Canada Alberta Hub Ltd., and Cal Ven Limited, both Canadian affiliates. The Company renounced Canadian exploration expenditure (“CEE”) tax deductions in 2003 of CDN $3.4 million to the subscribing companies.

In 2002, the Company issued to Unocal Canada Limited, a Canadian affiliate, preferred shares in exchange for debt amounting to CDN $500 million (U.S. $321.0 million). The preferred shareholders are entitled to a fixed preferential non-cumulative dividend at the rate of 5.5%, payable annually in cash or Class A Common shares. No dividends have been declared to date.

NOTE 14 – FINANCIAL INSTRUMENTS AND COMMODITY HEDGING

We do not generally hold or issue financial instruments for trading purposes other than those that are hydrocarbon based. The counterparties to the financial instruments we hold include regulated exchanges, international and domestic financial institutions and other industrial companies. All of the counterparties to our financial instruments must pass certain credit requirements deemed sufficient by management of our Parent before trading physical commodities or financial instruments with us.

Interest rate contracts – From time to time, the Company has entered into interest rate swap contracts to manage our debt with the objective of minimizing the volatility and magnitude of our borrowing costs. We may also enter into interest rate option contracts to protect our interest rate

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positions, depending on market conditions. At December 31, 2004, 2003 and 2002 we had no deferred amounts in accumulated other comprehensive income on the consolidated balance sheet related to interest rate contracts.

Foreign currency contracts – From time to time, the Company has entered into various foreign exchange currency forward, option and swap contracts to manage our exposures to adverse impacts of foreign currency fluctuations on recognized obligations and anticipated transactions. At December 31, 2004 and 2003 we had no deferred amounts in accumulated other comprehensive income on the consolidated balance sheet related to foreign currency contracts.

Commodity hedging activities – The Company uses hydrocarbon derivatives to mitigate the overall exposure to fluctuations in hydrocarbon commodity prices. The Company reported a gain of $1.2 million in 2004 (2003 - $1.9 million, 2002 - $0.3 million) due to ineffectiveness for cash flow and fair value hedges. At December 31, 2004 we had no outstanding derivative contracts and therefore had no deferred amounts in accumulated other comprehensive income on the consolidated balance sheet related to cash flow hedges for future commodity sales.

Concentration of credit risks – Financial instruments that potentially subject us to concentrations of credit risk primarily consist of temporary cash investments and trade receivables. We place our temporary cash investments with high credit quality financial institutions. The concentration of trade receivable credit risk is generally limited due to our customers being spread across industries in several countries. Our management has established certain credit requirements that our customers must meet before sales credit is extended. We monitor the financial condition of our customers to help ensure collections and to minimize losses.

The majority of our trade receivables balance at December 31, 2004 was attributable to the sale of crude oil and natural gas we produce.

As noted in Note 13 – Related Party Transactions at December 31, 2004, we had a $123 million note receivable from Unocal Canada Limited, a Canadian affiliate.

NOTE 15 –SUPPLEMENTAL CASH FLOW INFORMATION

Net Change in Non-Cash Working Capital from Continuing Operations

	2004			2003			2002
Decrease (increase) in non-cash working capital
Accounts receivable	$	(4,276	)	$	2,672		$	—
Accounts payable and accrued liabilities	(12,977		)	(14,585		)	(3,755		)
Working capital deficiency assumed from Corsair	—			—			(1,024		)
Other	2,043			4,113			1,082
Change in non-cash working capital	$	(15,210	)	$	(7,800	)	$	(3,697	)

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Supplemental Cash Flow Information – Continuing Operations

	2004		2003		2002
Income taxes paid during the period (net of refunds)	$	7,912	$	6,267	$	4,110
Interest paid during the period (expense)	$	306	$	374	$	16,414

NOTE 16 – SUBSEQUENT EVENT NOTE

On July 11, 2005, the Parent, Unocal Corporation entered into a definitive agreement to sell all of the outstanding stock of its wholly owned Canadian subsidiary, Northrock Resources Ltd., to Pogo Producing Company.

On July 19, 2005, the Parent, Unocal Corporation announced that its board of directors recommended that Unocal stockholders vote in favour of adopting the amended Chevron merger agreement at the special meeting of stockholders scheduled for August 10, 2005. Upon the successful completion of this proposed merger, all of the stock-based compensation plans of the Company, and its Parent, will be terminated. See Note 12 Stock Based Compensation.

On July 29, 2005, the Company and its Canadian affiliate, Unocal Canada Limited, terminated the $295 million Canadian dollar-denominated credit agreement with five commercial banks scheduled to mature in December 2009. See Note 7 Long-Term Debt And Credit Agreements and Note 13 Related Party Transactions.

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