Exhibit 99.2

REMINGTON OIL AND GAS HISTORICAL FINANCIAL STATEMENTS

Audited Financial Statements
Report of Independent Registered Public Accounting Firm	1
Consolidated Balance Sheets as of December 31, 2005 and 2004	2
Consolidated Statements of Income for 2005, 2004, and 2003	3
Consolidated Statements of Stockholders’ Equity for 2005, 2004, and 2003	4
Consolidated Statements of Cash Flows for 2005, 2004, and 2003	5
Notes to Consolidated Financial Statements	6
Unaudited Interim Financial Statements
Condensed Consolidated Balance Sheets as of March 31, 2006 (Unaudited) and December 31, 2005	28
Condensed Consolidated Statements of Income for three months ended March 31, 2006 (Unaudited) and March 31, 2005 (Unaudited)	29
Condensed Consolidated Statements of Cash Flows for three months ended March 31, 2006 (Unaudited) and March 31, 2005 (Unaudited)	30
Notes to Condensed Consolidated Financial Statements (Unaudited)	31

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders of

Remington Oil and Gas Corporation:

We have audited the accompanying consolidated balance sheets of Remington Oil and Gas Corporation and subsidiaries (the “Company”) as of December 31, 2005 and 2004, and the related consolidated statements of income, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2005. 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 consolidated financial position of the Company at December 31, 2005 and 2004, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 1 to the consolidated financial statements, in 2003 the Company adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations.”

/s/ Ernst & Young LLP

Dallas, Texas

March 10, 2006

1

REMINGTON OIL AND GAS CORPORATION

CONSOLIDATED BALANCE SHEETS

	At December 31,
	2005			2004
	(In thousands, except per share data)
ASSETS
Current assets
Cash and cash equivalents	$	38,860		$	58,659
Accounts receivable		66,887			49,582
Insurance receivable		23,308			—
Income taxes receivable		5,767			—
Prepaid expenses and other current assets		5,466			5,199
Total current assets		140,288			113,440
Properties
Oil and gas properties (successful-efforts method)		908,437			744,215
Other properties		3,758			3,145
Accumulated depreciation, depletion and amortization		(468,290	)		(409,591	)
Total properties		443,905			337,769
Other assets
Other assets		1,872			1,905
Total other assets		1,872			1,905
Total assets	$	586,065		$	453,114
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable and accrued expenses	$	76,561		$	69,339
Current deferred income taxes		1,094			—
Total current liabilities		77,655			69,339
Long-term liabilities
Asset retirement obligations		21,375			16,030
Deferred income taxes		82,876			53,785
Total long-term liabilities		104,251			69,815
Total liabilities		181,906			139,154
Commitments and contingencies (Note 5)
Stockholders’ equity
Preferred stock, $0.01 par value, 25,000,000 shares authorized shares issued — none
Common stock, $.01 par value, 100,000,000 shares authorized, 28,790,997 shares issued and 28,756,638 shares outstanding in 2005, 27,883,698 shares issued and 27,849,339 shares outstanding in 2004		288			279
Additional paid-in capital		149,234			132,334
Restricted common stock		24,264			6,749
Unearned compensation		(20,385	)		(5,593	)
Retained earnings		250,758			180,191
Total stockholders’ equity		404,159			313,960
Total liabilities and stockholders’ equity	$	586,065		$	453,114

See accompanying Notes to Consolidated Financial Statements.

2

REMINGTON OIL AND GAS CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

	Years Ended December 31,
	2005		2004		2003
	(In thousands, except per-share amounts)
Revenues and other income
Gas sales	$	184,095	$	167,564	$	130,346
Oil sales		76,039		65,941		52,233
Interest income		1,806		349		161
Other income		8,589		275		312
Total revenues and other income		270,529		234,129		183,052
Costs and expenses
Operating costs and expenses		28,069		25,013		20,910
Exploration expenses		55,272		22,551		25,416
Depreciation, depletion, and amortization		60,351		72,810		55,694
Impairment of oil and gas properties		1,483		10,876		4,447
General and administrative		15,182		8,053		8,408
Interest and financing expense		613		894		1,635
Total costs and expenses		160,970		140,197		116,510
Income before taxes		109,559		93,932		66,542
Income taxes		38,992		32,936		23,618
Net income	$	70,567	$	60,996	$	42,924
Basic income per share	$	2.48	$	2.23	$	1.61
Diluted income per share	$	2.37	$	2.14	$	1.53

See accompanying Notes to Consolidated Financial Statements.

3

REMINGTON OIL AND GAS CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

	Common
	Stock			Additional			Restricted
	$0.01			Paid in			Common			Unearned			Treasury			Retained
	Par Value			Capital			Stock			Compensation			Stock			Earnings
	(In thousands)
Balance December 31, 2002	$	263		$	115,827		$	5,468		$	(3,192	)	$	(977	)	$	76,271
Net income																	42,924
Amortization of unearned compensation											1,318
Forfeit contingent stock grant shares								(206	)		206
Common stock issued		7			4,998			(2,106	)					(808	)
Tax benefit from exercise of stock options					1,884
Treasury stock retired		(1	)		(1,784	)								1,785
Balance December 31, 2003		269			120,925			3,156			(1,668	)		—			119,195
Net income																	60,996
Amortization of unearned compensation											1,251
Stock grant								5,176			(5,176	)
Common stock issued		11			7,970			(1,583	)					(645	)
Tax benefit from exercise of stock options					4,083
Treasury stock retired		(1	)		(644	)								645
Balance December 31, 2004		279			132,334			6,749			(5,593	)		—			180,191
Net income																	70,567
Amortization of unearned compensation											4,639
Stock grant								19,431			(19,431	)
Common stock issued		10			12,166			(1,916	)					(691	)
Tax benefit from exercise of stock options					5,425
Treasury stock retired		(1	)		(691	)								691
Balance December 31, 2005	$	288		$	149,234		$	24,264		$	(20,385	)		—		$	250,758

See accompanying Notes to Consolidated Financial Statements.

4

REMINGTON OIL AND GAS CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Years Ended December 31,
	2005			2004			2003
	(In thousands)
Cash flow provided by operations
Net income	$	70,567		$	60,996		$	42,924
Adjustments to reconcile net income
Depreciation, depletion, and amortization		60,351			72,810			55,694
Deferred income tax expense		30,185			25,034			23,443
Amortization of deferred finance charges		155			183			207
Impairment of oil and gas properties		1,483			10,876			4,447
Dry hole costs		48,666			12,787			23,993
Net settlement for dismantlement and restoration liability		645			(1,712	)		(1,631	)
Stock based compensation		4,639			1,427			1,565
Tax benefit from exercise of employee stock options		5,425			4,083			—
Changes in working capital
(Increase) in accounts receivable		(16,793	)		(6,570	)		(10,483	)
(Increase) in insurance receivable		(23,308	)		—			—
(Increase) in income taxes receivable		(5,767	)		—			—
(Increase) decrease in prepaid expenses and other assets		(121	)		(2,360	)		2,313
Increase (decrease) in accounts payable and accrued expenses		(15,308	)		11,028			10,743
Net cash flow provided by operations		160,819			188,582			153,215
Cash from investing activities
Payments for capital expenditures		(189,906	)		(148,908	)		(115,714	)
Net cash (used in) investing activities		(189,906	)		(148,908	)		(115,714	)
Cash from financing activities
Payments on other long-term payables		—			(18,000	)		(22,573	)
Treasury stock acquired and retired		(691	)		(645	)		(808	)
Commitment fee on line of credit		(280	)		—			(294	)
Common stock issued		10,259			6,222			2,653
Net cash provided by (used in) financing activities		9,288			(12,423	)		(21,022	)
Net increase (decrease) in cash and cash equivalents		(19,799	)		27,251			16,479
Cash and cash equivalents at beginning of period		58,659			31,408			14,929
Cash and cash equivalents at end of period	$	38,860		$	58,659		$	31,408
Cash paid for interest	$	436		$	948		$	1,702
Cash paid for taxes	$	12,387		$	580		$	175

See accompanying Notes to Consolidated Financial Statements.

5

REMINGTON OIL AND GAS CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 — Summary of Significant Accounting Policies

Basis of Presentation and Principles of Consolidation

Remington Oil and Gas Corporation is an independent oil and gas exploration and production company incorporated in Delaware. We have working interest ownership rights in properties in the offshore Gulf of Mexico and onshore Gulf Coast. We acquired the following subsidiaries in 1998: CKB Petroleum, Inc., CKB & Associates, Inc., Box Brothers Realty Investments Company, CB Farms, Inc., and Box Resources, Inc. We consolidate 100% of the assets, liabilities, equity, income and expense of the subsidiaries and eliminate all inter-company transactions and account balances for the periods of consolidation. We own 100% of the outstanding capital stock of all of the subsidiaries. The primary operating subsidiary, CKB Petroleum, Inc., owns an undivided interest in a pipeline that transports our oil from our South Pass blocks, offshore Gulf of Mexico, to Venice, Louisiana. We account for our undivided interests in properties using the proportionate consolidation method, whereby our share of assets, liabilities, revenues and expenses are included in our financial statements.

Use of Estimates in the Preparation of Financial Statements

Management prepares the financial statements in conformity with accounting principles generally accepted in the United States. This requires estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reported periods. Some of the more significant estimates include oil and gas reserves, useful lives of assets, impairment of oil and gas properties, and future dismantlement and restoration liabilities. Actual results could differ from those estimates.

Cash and Cash Equivalents

Cash equivalents consist of highly liquid investments that mature within three months or less when purchased. Our cash equivalents consist primarily of institutional money market funds. We record cash equivalents at cost, which approximates their market value at the balance sheet date.

Concentration of Credit Risk

Our financial instruments that are potentially subject to a concentration of credit risk are principally cash and trade receivables. Our accounts receivable and accounts payable book values approximate fair value at the balance sheet date. Substantially all of our cash and cash equivalents at December 31, 2005 and 2004 exceeded the $100,000 federally insured limit for amounts deposited at financial institutions. At December 31, 2005, two companies accounted for approximately 70% of our total accounts receivable, and at December 31, 2004, three companies accounted for approximately 59% of our total accounts receivable. Oil and gas are fungible commodities in high demand from numerous customers; however, during 2005 we sold oil and gas to three major customers who accounted for 37%, 25% and 15% of our total revenues. The sale of oil and gas to four major customers accounted for 27%, 20%, 18% and 12% of our total oil and gas revenues in 2004. We do not believe that the loss of any of these customers would have a material adverse effect on our financial position or results of operations because we believe that they can be replaced due to the high demand for oil and gas.

Property and Equipment

We follow the successful-efforts method to account for oil and gas exploration and development expenditures. Under this method, we capitalize expenditures for leasehold acquisitions, drilling costs for productive wells and unsuccessful development wells. We amortize the capitalized costs using the units-of-production method, converting to gas equivalent units by using the ratio of 1 barrel of oil equal to 6 Mcf of gas.

Workovers that establish new production are capitalized and workovers that restore production are charged to operating expense.

6

REMINGTON OIL AND GAS CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) 

Prior to 2003, we capitalized a discounted total of scheduled payments related to our license to use a library of 3-D seismic data. The amount capitalized was amortized to expense over the estimated minimum useful life of 4 years using a straight line method. In the fourth quarter of 2003, we completed a further review of the contracts and it was determined that as of the fourth quarter 2003, we would charge exploration expense as the invoices are paid. This change in our method of accounting for 3-D seismic data license did not have a material effect on our current or prior financial statements. During the second quarter of 2004, we acquired an additional license to access a library of 3-D seismic data covering the deeper water trends of the Gulf of Mexico. The agreement provides for a schedule of payments beginning with the delivery of the first data in May 2004 and ending in July 2008. Because of our unilateral right to terminate the license agreement, we do not consider any of the payments scheduled in the contract to be an incurred liability until the scheduled invoice date.

We review our oil and gas properties for impairment whenever events or circumstances indicate that the net book value of these properties may not be recoverable. If the net book value of a property is greater than the estimated undiscounted future net cash flow from the same property, the property is considered impaired. We base our assessment of possible impairment using our best estimate of future prices, costs and expected net cash flow generated by a property. The impairment expense is equal to the difference between the net book value and the fair value of the asset. We estimate fair value by discounting, at an appropriate rate, the future net cash flows from the property.

The impairment of unproved leasehold costs includes an amortization of the aggregate individually insignificant properties (adjusted by an estimated rate of future successful development) over an average lease term or, if events or circumstances indicate, a specific impairment of individually significant properties.

Other properties include improvements on the leased office space and office computers and equipment. We depreciate these assets using the straight-line method over their estimated useful lives, which range from 3 to 12 years.

Capitalization of Exploration Drilling Costs

We drill exploratory wells with the expectation that the final well bore will be capable of producing oil and gas reserves. The costs of drilling an exploratory well are capitalized as uncompleted wells pending the determination of whether the well has found proved reserves. If proved reserves are not found, these capitalized costs are charged to expense. On the other hand, the determination that proved reserves have been found results in the continued capitalization of the drilling costs of the well and its reclassification as a well containing proved reserves. It may be determined that an exploratory well may have found hydrocarbons at the time drilling is completed, but it may not be possible to classify the reserves at that time. In this case, we may continue to capitalize the drilling costs as an uncompleted well beyond one year when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the company is making sufficient progress assessing the reserves and the economic and operating viability of the project, or the reserves are deemed to be proved. At that time the well is either reclassified as a proved well or is considered impaired and its costs, net of any salvage value, are charged to expense.

Occasionally, we may salvage a portion of an unsuccessful exploratory well in order to continue exploratory drilling in an effort to reach the target geological structure/formation. In such cases, we charge only the unusable portion of the well bore to dry hole expense. We will continue to capitalize the costs associated with the salvageable portion of the well bore and add the costs to the new exploratory well. In certain situations, drilling is temporarily suspended and the well bore may be carried for more than one year because drilling to the depth of the target reserves is not yet complete. This may be due to the need to obtain, and/or analyze the availability of, equipment or crews or other activities necessary to pursue the targeted reserves or evaluate new or reprocessed seismic and geological data. If, after we analyze the new information and conclude that we will not reuse the well bore or if the well is determined to be unsuccessful after we complete drilling, we will charge the capitalized costs to dry hole expense. Total capitalized exploratory drilling costs charged to dry hole expense were $48.7 million for the year ended December 31, 2005, and $12.8 million for the year ended December 31, 2004.

7

REMINGTON OIL AND GAS CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) 

The following table shows the number of wells and the associated capitalized costs for wells in areas requiring a major capital expenditure before production can begin, where additional drilling efforts are not underway or firmly planned for the future and wells in areas not requiring major capital expenditures before production can begin, where more than one year has elapsed since the completion of drilling as of the end of December 31, 2005 and 2004. We are in the process of completing the infrastructure required to produce the reserves associated with this well.

	At December 31,
	2005				2004
	Wells		Cost		Wells		Cost
	(In thousands, except well numbers)
Exploration wells requiring major capital expenditures		1	$	2,067		—	$	—
Exploration wells not requiring major capital expenditures and capitalized for more than one year		—		—		1		4,445
Total		1	$	2,067		1	$	4,445

The following table presents exploratory costs deferred by year as of December 31, 2005.

	At December 31, 2005
	Costs Deferred by Period
		Less than		2 or more
	Total	1 Year	1 Year	Years
	(In thousands)
Capitalized exploration costs	$12,952	$10,885	$2,067	—

The following table shows the changes in capitalized exploratory drilling costs pending the determination of proved reserves, capitalized exploratory drilling costs that have been capitalized to wells and equipment, and the capitalized exploratory drilling costs charged to dry hole expense.

	At December 31,
	2005						2004					2003
	Wells			Cost			Wells		Cost			Wells		Cost
	(In thousands, except well numbers)
Beginning balance		3		$	12,777			2	$	7,778			—	$	—
Reclassified to wells & facilities		—			—			—		—			—		—
Dry hole expense		—			—			—		(2,861	)		—		—
Additions to capitalized costs		2			10,885			1		7,860			2		7,778
Other(1)		(2	)		(10,710	)
Total		3		$	12,952			3	$	12,777			2	$	7,778

(1) Other includes 2 wells withdrawn from suspended well status for utilization of the well bores for future identified exploration prospects.

Asset Retirement Obligations

We adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations,” effective January 1, 2003. The statement requires that we estimate the fair value for our asset retirement obligations (dismantlement and abandonment of oil and gas wells and offshore platforms) in the periods the assets are first placed in service. We then adjust the current estimated obligation for estimated inflation and market risk contingencies to the projected settlement date of the liability. The result is then discounted to a present value from the projected settlement date to the date the asset was first placed in service. As of January 1, 2003, we record the present value of the asset retirement obligation as an additional property cost and as an asset retirement

8

REMINGTON OIL AND GAS CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) 

liability. We recorded a combination of the amortization of the additional property cost (using the unit-of-production method) and the accretion of the discounted liability as a component of our depreciation, depletion and amortization of oil and gas properties.

We base our initial liability on estimates of current costs to dismantle and abandon our existing platforms and wells on historical experience, industry practice, and external estimates of the cost to abandon similar platforms and wells subject to federal and state regulatory requirements. We increase the current liability estimate using a 3% annual inflation factor over the estimated productive life of the individual property and further increase the inflated liability by 5% for market cost risk. The liability is discounted using United States Treasury Securities with constant maturities that approximate the number of years of productive life for the property plus a 2.5% adjustment for credit risk. Revisions to the liability could occur due to changes in estimated abandonment costs or well economic lives, or if federal or state regulators enact new requirements regarding abandonment of wells.

Prior to our adoption of SFAS No. 143, we accrued an estimated dismantlement, restoration and abandonment liability using the unit-of-production method over the life of a property and included the accrued amount in depreciation, depletion and amortization expense. The total accrued liability ($5.5 million at December 31, 2002) was reflected as additional accumulated depreciation, depletion and amortization of oil and gas properties on our balance sheet.

In conformity with SFAS 143 we recorded the cumulative effect of this accounting change as of January 1, 2003, as if we had used this method in the prior years. At January 1, 2003, we increased our oil and gas properties by $9.0 million, recorded $11.8 million as an Asset Retirement Obligation liability and reduced our accumulated depreciation by $2.8 million ($5.5 million accrued dismantlement in prior years less accumulated depreciation, depletion and amortization of $2.7 million on the increased property costs). The adoption of the new standard had no material effect on our net income. The following pro forma data summarize our net income and net income per share for the year ended December 31, 2003, as if we had adopted the provisions of SFAS 143 on January 1, 2001, including aggregate pro forma asset retirement obligations on that date:

	Year Ended
	December 31, 2003
(In thousands, except per share amounts)
Net income, as reported	$	42,924
Pro forma adjustment to reflect retroactive adoption of SFAS 143		34
Pro forma net income	$	42,958
Net income per share:
Basic — as reported	$	1.61
Basic — pro forma	$	1.61
Diluted — as reported	$	1.53
Diluted — pro forma	$	1.53

Other Assets

Other assets include the long-term portion of prepaid pension expenses (see Note 8 — Employee Benefit Plans — Pension Plan), and the long-term portion of net unamortized credit facility origination fees. The origination fees are amortized on a straight-line basis over the term of the credit facility. We charge the amortized amount to interest and financing costs. In addition, other assets also include a long-term account receivable totaling approximately $397,000 and $385,000 at December 31, 2005 and 2004, respectively, which is CKB Petroleum’s claim under Collateral Assignment Split Dollar Insurance Agreements among CKB Petroleum and Don D. Box (a former officer and member of the Board) and two of his brothers.

9

REMINGTON OIL AND GAS CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) 

Accounts Payable and Accrued Expenses

Accounts payable and accrued expenses were as follows:

	At December 31,
	2005		2004
	(In thousands)
Accounts payable — trade	$	13,962	$	28,214
Accrued payables		55,191		31,442
Income taxes payable		—		3,240
Advance billings		3,721		1,970
Royalties and other revenue payable		3,687		4,473
Total accounts payable and accrued expenses	$	76,561	$	69,339

Oil and Gas Revenues

When oil and gas is produced, we sell it immediately. Consequently, we recognize oil and gas revenue under the sales method in the month of actual production based on our share of the revenues. Our actual sales have not been materially different from our entitled share of production, and we do not have any significant gas imbalances.

Transportation costs

We include transportation costs in operating costs and expenses. During the years ended December 31, 2005, 2004, and 2003, we incurred transportation costs totaling $2.0 million, $2.6 million, and $2.3 million, respectively.

Stock Options

In December 2002, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure” (“SFAS 148”). SFAS 148 amends Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation” (“SFAS 123”), to provide alternative methods of transition to SFAS No. 123’s fair value method of accounting for stock-based employee compensation.

SFAS 148 also amends the disclosure provisions of SFAS 123 and Accounting Principles Board Opinion No. 28, “Interim Financial Reporting,” to require disclosure in the summary of significant accounting policies of the effects of an entity’s accounting policy with respect to stock-based employee compensation on reported net income and earnings per share in annual and interim financial statements. While SFAS 148 does not amend SFAS 123 to require companies to account for employee stock options using the fair value method, the disclosure provisions of SFAS 148 are applicable to all companies with stock-based employee compensation, regardless of whether they account for that compensation using the fair value method of SFAS 123 or the intrinsic value method of Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB 25”).

We apply the accounting provisions of APB 25 and related interpretations to account for stock-based compensation and have adopted the disclosure requirements of SFAS 123 and SFAS 148. Accordingly, we measure compensation cost for stock options as the excess, if any, of the quoted market price of our stock at the date of the grant over the amount an employee must pay to acquire the stock. All of our options are granted with exercise prices at or above the quoted market price on the date of grant.

10

REMINGTON OIL AND GAS CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) 

The following table summarizes relevant information as to the reported results under our intrinsic value method of accounting for stock awards, with supplemental information as if the fair value recognition provision of SFAS 123 had been applied:

	For Years Ended December 31,
	2005		2004		2003
	(In thousands, except per-share amounts)
As reported:
Net income	$	70,567	$	60,996	$	42,924
Basic income per share	$	2.48	$	2.23	$	1.61
Diluted income per share	$	2.37	$	2.14	$	1.53
Stock based compensation (net of tax at statutory rate of 35%) included in net income as reported	$	3,015	$	928	$	1,017
Stock based compensation (net of tax at statutory rate of 35%) if using the fair value method as applied to all awards	$	3,015	$	6,711	$	3,146
Pro forma (if using the fair value method applied to all awards):
Net income	$	70,567	$	55,213	$	40,795
Basic income per share	$	2.48	$	2.02	$	1.53
Diluted income per share	$	2.37	$	1.94	$	1.46
Weighted average shares used in computation
Basic		28,488		27,408		26,628
Diluted		29,722		28,441		27,987

During 2004, we accelerated the vesting dates for 128,324 stock options granted during 2002, and 39,999 stock options granted during 2003, from the original vesting dates in 2005 and 2006 to vesting dates in December 2004. All stock options were in the money at the time the vesting dates were accelerated. The acceleration of the vesting increased the stock based compensation using the fair value method under SFAS 123 by $1.1 million, net of tax at the statutory rate of 35%. As a result of this acceleration all of our outstanding stock options were vested at December 31, 2004.

The fair value of each option grant for the years ended December 21, 2004 and 2003, is estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted average assumptions:

	For Years Ended December 31,
	2004			2003
Expected life (years)		7			7
Interest rate		4.07	%		3.73	%
Volatility		63.70	%		65.27	%
Dividend yield		0	%		0	%

As required, the pro forma disclosures above include options granted since January 1, 1995. All of our outstanding or previously-exercised options were granted after 1995.

Segment Reporting

We operate in only one business segment.

11

REMINGTON OIL AND GAS CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) 

General and Administrative Expenses

We report our general and administrative expenses net of reimbursed overhead costs that we allocate to working interest owners of the oil and gas properties that we operate.

Income Taxes

Income tax expense or benefit includes both current income taxes and deferred income taxes. Deferred income tax expense or benefit equals the change in the net deferred income tax asset or liability from the beginning of the year. We determine the amount of our deferred income tax asset or liability by multiplying the enacted tax rates by the temporary differences, net operating or capital loss carry-forwards plus any tax credit carry-forwards. The tax rates used are the effective rates applicable for the year in which we expect the temporary differences or carry-forwards to reverse.

In December 2004, the FASB issued Staff Position No. FAS 109-1 (“FAS 109-1”), “Application of FASB Statement No. 109, ’Accounting for Income Taxes,’ to the Tax Deduction on Qualified Production Activities by the American Jobs Creation Act of 2004.” The American Jobs Creation Act of 2004 (the “AJCA”) introduces a special 9% tax deduction on qualified production activities. FAS 109-1 clarifies that this tax deduction should be accounted for as a special tax deduction in accordance with FASB Statement No. 109. The deduction is being phased in over a period of time. For 2005, the deduction is equal to 3% of qualified production activities. We computed a deduction of approximately $250,000 for 2005.

Income per Common Share

We compute basic income per share by dividing net income by the weighted average number of common shares outstanding for the period. Diluted income per share reflects the potential dilution that could occur if options or other contracts to issue common stock were exercised or converted into common stock or resulted in the issuance of common stock that then shares in the net income of the company. The following table presents our calculation of basic and diluted income per share.

	For Years Ended December 31,
	2005		2004		2003
	(In thousands, except
	per-share amounts)
Net income available for basic income per share	$	70,567	$	60,996	$	42,924
Basic income per share	$	2.48	$	2.23	$	1.61
Diluted income per share	$	2.37	$	2.14	$	1.53
Weighted average common shares for basic income per share		28,488		27,408		26,628
Dilutive stock options outstanding (treasury stock method)		483		837		1,099
Common stock grant		751		196		260
Total common shares for diluted income per share		29,722		28,441		27,987
Non-dilutive stock options outstanding		266		749		1,235

New Accounting Pronouncements

In April 2005, the FASB issued Staff Position No. FAS 19-1, “Accounting for Suspended Well Costs,” (“FSP 19-1”). FSP 19-1 amends SFAS No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies,” (“SFAS 19”) to allow continued capitalization of exploratory well costs beyond one year from the completion of drilling under circumstances where the wells have found a sufficient quantity of reserves to justify its completion as a producing well and the company is making sufficient progress assessing the reserves and the

12

REMINGTON OIL AND GAS CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) 

economic and operating viability of the project. FSP 19-1 also amends SFAS 19 to require enhanced disclosures of suspended exploratory well costs in the notes to the financial statements for annual and interim periods when there has been a significant change from the previous disclosure. The guidance in FSP 19-1 was effective for the first reporting period beginning after April 4, 2005. Accordingly, we adopted the new requirements and have included the required disclosures in footnote 1. The adoption of FSP 19-1 did not impact our financial position or results of operations.

In December 2004, the FASB issued Statement of Financial Accounting Standards No. 123 (revised 2004), “Share-Based Payment” (“SFAS 123R”), which is a revision of Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation” (“SFAS 123”). SFAS 123R supersedes Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB 25”) and amends Statement of Financial Accounting Standards No. 95, “Statement of Cash Flows”. Generally, the approach in SFAS 123R is similar to the approach described in SFAS 123. However, SFAS 123R will require all share-based payments to employees, including grants of employee stock options, to be recognized in our Consolidated Statements of Operations based on their fair values. Pro forma disclosure is no longer an alternative. SFAS 123R must be adopted no later than January 1, 2006, and permits us to adopt its requirements using one of two methods:

A “modified prospective” method in which compensation cost is recognized beginning with the effective date based on the requirements of SFAS 123R for all share-based payments granted after the effective date and based on the requirements of SFAS 123 for all awards granted to employees prior to the adoption date of SFAS 123R that remain unvested on the adoption date.

A “modified retrospective” method which includes the requirements of the modified prospective method described above, but also permits entities to restate either all prior periods presented or prior interim periods of the year of adoption based on the amounts previously recognized under SFAS 123 for purposes of pro forma disclosures.

We have elected to adopt the provisions of SFAS 123R on January 1, 2006, using the modified prospective method. As permitted by SFAS 123, we currently account for share-based payments to employees using the intrinsic value method prescribed by APB 25 and related interpretations. Therefore, we do not recognize compensation expenses associated with employee stock options. Currently, since all of our outstanding stock options have vested prior to the adoption of SFAS 123R, we will not recognize any expenses associated with these prior stock option grants. However, the adoption of SFAS 123R fair value method could have a significant impact on our future results of operations for future stock or stock option grants but no impact on the our overall financial position. Had we adopted SFAS 123R in prior periods, the impact would have approximated the impact of SFAS 123 as described in the pro forma net income and income per share disclosures. The adoption of SFAS 123R will have no effect on our outstanding stock grant awards.

SFAS 123R also requires the tax benefits of tax deductions in excess of recognized compensation expenses to be reported as a financing cash flow, rather than as an operating cash flow as required under current literature. This requirement may reduce our future cash provided by operating activities and increase future cash provided by financing activities, to the extent of associated tax benefits that may be realized in the future. While we cannot estimate what those amounts will be in the future (because they depend on, among other things, when employees exercise stock options), the amount of operating cash flows from such excess tax deductions were $5.4 million during the year ended December 31, 2005.

In March 2005, the FASB issued FASB Interpretation (“FIN”) No. 47, “Accounting for Conditional Asset Retirement Obligations.” The interpretation clarifies the requirement to record abandonment liabilities stemming from legal obligations when the retirement depends on a conditional future event. FIN No. 47 requires that the uncertainty about the timing or method of settlement of a conditional retirement obligation be factored into the measurement of the liability when sufficient information exists. We adopted FIN No. 47 as of December 31, 2005. There was no material impact on our results of operations, financial condition, or cash flows.

13

REMINGTON OIL AND GAS CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) 

In May 2005, the FASB issued Statement of Financial Accounting Standards No. 154, “Accounting Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB Statements No. 3” (“SFAS 154”). SFAS 154 requires retrospective application to prior period financial statements for changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. SFAS 154 also requires that retrospective application of a change in accounting principle be limited to the direct effects of the change. Indirect effects of a change in accounting principle should be recognized in the period of the accounting change. SFAS 154 will become effective on January 1, 2006. The impact of SFAS 154 will depend on the nature and extent of any voluntary accounting changes and correction of errors after the effective date, but we do not currently expect SFAS 154 to have a material impact on our results of operations, financial condition, or cash flows.

Note 2 — Oil and Gas Properties

The following table summarizes the capitalized costs on our oil and gas properties, all of which are located in the United States.

	At December 31,
	2005								2004
	Proved			Unproved		Total			Proved			Unproved		Total
	(In thousands)
Oil and gas properties	$	874,579		$	33,858	$	908,437		$	717,316		$	26,899	$	744,215
Accumulated depreciation, depletion and amortization		(465,968	)		—		(465,968	)		(407,134	)		—		(407,134	)
Net oil and gas properties	$	408,611		$	33,858	$	442,469		$	310,182		$	26,899	$	337,081

The following table presents a summary of our oil and gas expenditures during the last three years.

	For Years Ended December 31,
	2005		2004		2003
	(In thousands)
Unproved acquisition costs	$	8,985	$	10,878	$	2,370
Proved acquisition costs		3,024		1,554		1,466
Exploration costs		111,427		80,970		54,138
Development costs		94,525		65,080		58,475
Discounted estimate of future asset retirement costs		2,770		4,267		9,963
Total	$	220,731	$	162,749	$	126,412

We recognized impairment expenses shown in the table below:

	For Years Ended December 31,
	2005		2004		2003
	(In thousands)
Unproved properties	$	1,238	$	1,130	$	1,136
Proved properties		—		9,746		3,311
Other		245		—		—
Total impairment expense	$	1,483	$	10,876	$	4,447

We estimate the amount of individually insignificant unproved properties which will prove unproductive by amortizing the balance of our individually immaterial unproved property costs (adjusted by an anticipated rate of

14

REMINGTON OIL AND GAS CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) 

future successful development) over an average lease term. Individually significant properties will continue to be evaluated periodically on a separate basis for impairment. We will transfer the original cost of an unproved property to proved properties when we find commercial oil and gas reserves sufficient to justify full development of the property. The impairment of unproved properties for the prior two years primarily resulted from the actual (due to unsuccessful exploration results) or impending forfeiture of leaseholds.

We analyze proved properties for impairment indicators based on the proved reserves as determined by our internal reserve engineers. No proved properties were impaired during 2005. The properties impaired in 2004 primarily consisted of two properties in the Gulf of Mexico which totaled $4.2 million and two onshore Gulf Coast properties which totaled $5.5 million, and in 2003 included two properties in the Gulf of Mexico which totaled $2.4 million and one property in the onshore Gulf Coast. The impairments resulted primarily from wells depleting sooner than originally estimated or capital costs in excess of those anticipated.

The following table summarizes our asset retirement obligation. The beginning balance in 2003 is presented on a pro forma basis as if the provisions of SFAS 143 had been applied when the properties were placed in service:

	At December 31,
	2005		2004			2003
	(Unaudited, in thousands)
Beginning of period	$	16,030	$	12,446		$	11,807
New properties and changes in estimates		3,439		4,267			1,393
Net settlement of liabilities(1)		645		(1,712	)		(1,631	)
Loss on settlement of liabilities		75		21			—
Accretion of liability		1,186		1,008			877
End of period	$	21,375	$	16,030		$	12,446

(1) In 2005, we received $700,000 as consideration for our assumption of dismantlement and abandonment liabilities for existing facilities on a property we acquired in 2005.

Note 3 — Insurance Receivable

As a result of Hurricanes Katrina and Rita which occurred in August and September of 2005, we incurred physical damages and shut-in production on many of our offshore properties. We maintain insurance coverage for damages to our offshore properties, including producing and drilling wells, platforms, pipelines and lost production. As of December 31, 2005, we have $23.3 million accrued as an insurance receivable on the balance sheet. Of this amount, $15.0 million represents insurance receivables for hurricane related expenditures associated with physical damage and lost equipment and a control of well claim. The remaining $8.3 million represents an insurance receivable for partial claim for lost production settled through December 31, 2005, from shut-ins caused by Hurricane Rita and is included in other income on the income statement. Additional claims associated with lost production as a result of Hurricane Katrina have been made and will be recorded when finalized.

15

REMINGTON OIL AND GAS CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) 

Note 4 — Notes Payable and Other Long-Term Payables

Bank Credit Facility

On September 9, 2005, we increased our credit facility from $150 million to $200 million and the associated borrowing base from $100 million to $150 million. The following schedule reflects certain information about the line of credit for the last two years.

	At December 31,
	2005		2004
	(In thousands)
Borrowing base	$	150,000	$	100,000
Outstanding balance		—		—
Available amount	$	150,000	$	100,000

We pledged certain oil and gas properties as collateral for this line of credit. We accrue and pay interest at varying rates based on premiums ranging from 1.0 to 2.0 percentage points over the London Interbank Offered Rates. We pay commitment fees of 0.375% on the unused amount of the line of credit. Interest only is payable quarterly through September 2009, at which time the line expires and all principal becomes due, unless the line is extended or renegotiated.

The most significant financial covenants in the line of credit include, among others, maintaining a minimum current ratio (as defined in the facility agreement) of 1.0 to 1.0, a minimum tangible net worth of $175.0 million plus 50% of net income (accumulated from the closing date of the facility agreement) and 75% of the net proceeds of any corporate equity offering, and interest coverage of 2.5 to 1.0. We are currently in compliance with these financial covenants. If we do not comply with these covenants, the lenders have the right to refuse to advance additional funds under the facility and/or declare all principal and interest immediately due and payable.

The banks review the borrowing base semi-annually and may decrease or propose an increase to the borrowing base at their discretion relative to the new estimate of proved oil and gas reserves.

Note 5 — Commitments and Contingent Liabilities

We currently lease approximately 19,000 square feet of office space in Dallas, Texas and have commitments to lease an additional 6,000 square feet in 2006. The non-cancelable operating lease expires in March 2012. The following table reflects our rent expense for the past three years and the commitment for the future minimum rental payments.

Year	(In Thousands)
2003	$	441
2004	$	441
2005	$	489
2006	$	644
2007	$	672
2008	$	678
2009	$	680
2010	$	686
After 2010	$	860

We have no material pending legal proceedings.

16

REMINGTON OIL AND GAS CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) 

Effective May 12, 2004, we entered into an executory contract with a third party under which we acquired a license to use 3-D seismic data owned by the vendor covering approximately 1,200 blocks in the Gulf of Mexico. We do not acquire ownership of the data, but simply a non-exclusive license to use the data. The term of the agreement, subject to a mutual right of termination by either party, is 20 years from delivery of the data. At the end of the 20 year term, the license shall be renewed for an additional 20 year term at no charge unless the parties agree to terminate the agreement. The following table reflects the expense for 2004 and 2005 and the amount of future payments for each specified year under the contract.

Year	(In Thousands)
2004	$	4,219
2005	$	3,718
2006	$	3,000
2007	$	3,000
2008	$	1,940

The licensor delivered to us all the 3-D seismic data under the agreement within the first three months of execution, as contemplated in the agreement, and we have full access to the data. In addition to the terms of the agreement described above, under the agreement the licensor has ongoing warranty and indemnity responsibilities as to intellectual property matters and the obligation to deliver to us certain data tapes and support data upon our request. Further, we believe that under the terms of the agreement we have the unilateral right to terminate the agreement by non-payment of two scheduled quarterly payments and because there is no provision restricting termination of the agreement, and that upon such termination we have no further obligations under the agreement, except for the return of the data to the licensor.

Note 6 — Common Stock, Preferred Stock and Dividends

We have 100.0 million shares of common stock and 25.0 million shares of “blank check” preferred stock authorized. The par value of the common stock and preferred stock is $0.01 per share. The Board of Directors can approve the issue of multiple series of preferred stock and set different terms, voting rights, conversion features, and redemption rights for each distinct series of the preferred stock.

We have reserved approximately 4.0 million shares of common stock for our 1997 Stock Option Plan and for our Non-Employee Director Stock Purchase Plan. In addition, we have reserved 2.0 million shares of common stock for our 2004 Stock Incentive Plan approved by our stockholders on May 24, 2004. Both plans are discussed in more detail in Note 7 — Stock Based Compensation Expense. Dividend payments are currently prohibited by our line of credit agreement.

Note 7 — Stock Based Compensation Expense

1997 Stock Option Plan

The Compensation Committee of the Board of Directors, comprising three independent directors, administers the 1997 Stock Option Plan. This committee has the discretion to determine the participants, the number of shares granted to each person, the exercise price of the common stock covered by each option, and most other terms of the option. Options granted under the plan may be either incentive stock options or non-qualified stock options. The committee may issue options for up to 3.75 million shares of common stock, but no more than 937,500 shares to any individual. Forfeited options are available for future issuance. In accounting for stock options granted to employees and directors, we have chosen to continue to apply the accounting method promulgated by Accounting Principles Board Opinion No. 25 (“APB 25”) rather than apply an alternative method permitted by Statement of Financial Accounting Standards No. 123 (“SFAS 123”). Under APB 25, at the time of grant we do not record compensation expense on our income statement for stock options granted to employees or directors.

17

REMINGTON OIL AND GAS CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) 

A summary of our stock option plan as of December 31, 2005, 2004, and 2003, and changes during the years ending on those dates is presented below:

	At December 31,
	2005					2004					2003
				Weighted					Weighted					Weighted
				Average					Average					Average
				Exercise					Exercise					Exercise
	Shares			Price		Shares			Price		Shares			Price
Outstanding at beginning of year		1,528,439		$	13.00		2,334,333		$	10.93		2,552,219		$	8.68
Granted		—			—		30,000			23.24		360,000			18.66
Exercised		(825,786	)		12.54		(835,894	)		7.58		(559,553	)		5.44
Forfeited		—			—		—			—		(18,333	)		16.82
Outstanding at end of year		702,653		$	13.54		1,528,439		$	13.00		2,334,333		$	10.93
Options exercisable at year-end		702,653		$	13.54		1,528,439		$	13.00		1,592,667		$	7.81
Weighted-average fair value of options granted during the year				$	—				$	15.23				$	12.33

The options outstanding at December 31, 2005, have a weighted-average remaining contractual life of 5.51 years and an exercise price ranging from $3.75 to $23.89 per share. A breakdown of the options outstanding at December 31, 2005 by price range is presented below:

					Weighted				Weighted
			Weighted		Average				Average Price
			Average		Remaining		Number		of Options
Option Price Range	Number		Exercise Price		Life (Years)		Exercisable		Exercisable
$3.75 - $4.25		98,866	$	3.87		4.17		98,866	$	3.87
$5.75 - $6.94		67,201	$	6.63		1.55		67,201	$	6.63
$9.00 - $15.32		211,206	$	12.53		4.28		211,206	$	12.53
$17.15 - $23.89		325,380	$	18.57		7.52		325,380	$	18.57

The effect on our net income if we recorded the estimated compensation costs for the stock options using the estimated fair value as determined by applying the Black-Scholes option pricing model is included in Note 1 — Summary of Significant Accounting Policies — Stock Options.

During 2004, we accelerated the vesting dates for 128,324 stock options granted during 2002, and 39,999 stock options granted during 2003, from the original vesting dates in 2005 and 2006 to vesting dates in December 2004. All stock options were in the money at the time the vesting dates were accelerated. The acceleration of the vesting increased the stock based compensation using the fair value method under SFAS 123 by $1.1 million, net of tax at statutory rate of 35%. As a result of this acceleration all of our outstanding stock options are vested at December 31, 2004.

Non-Employee Director Stock Purchase Plan

The Non-Employee Director Stock Purchase Plan allows the non-employee members of the Board to receive their directors’ fees in shares of restricted common stock instead of cash. The number of shares received will be equal to 150% of the cash fees divided by the closing market price of the common stock on the day that the cash fees would otherwise be paid. The director cannot transfer the common stock until the earlier of one year after issuance or the termination of a director resulting from death, disability, removal, or failure to be nominated for an additional term. The director can vote the shares of restricted stock and receive any dividend paid.

18

REMINGTON OIL AND GAS CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) 

Employee and Director Stock Grants and Our 2004 Stock Incentive Plan

In June 1999, the Board of Directors approved a contingent stock grant to our employees and directors totaling 686,472 shares. The shares under this grant vest over 3 to 5 years. In order for the grant to become effective, the price of our stock had to increase from $4.19 per share to a trigger price of $10.42 per share and close at or above $10.42 per share for 20 consecutive trading days within 5 years of the grant date. On January 24, 2001, the stock price closed above the trigger price for the twentieth consecutive trading day. On that date, we measured the total compensation cost at $8.1 million which was the total number of shares granted multiplied by the market price on that date. We recorded $8.1 million as restricted common stock and unearned compensation.

In May 2004, the stockholders approved the Remington Oil and Gas Corporation 2004 Stock Incentive Plan. This plan is administered by the Compensation Committee of the Board of Directors. Under this plan the Committee may issue stock options, purchased stock, bonus stock, stock appreciation rights, phantom stock, restricted stock awards, performance awards and other stock or performance based awards. All employees and non-employee directors are eligible to participate. In October 2004, the Board approved a stock grant of an aggregate 200,000 shares to employees and non-employee directors and an additional grant of 6,000 shares in April 2005. The shares under this grant vest one-fifth each October for the years 2005 through 2009. There is no trigger price or conditions under this stock grant other than a written stock grant agreement between us and the grantee, and the passage of time and continued employment or service of a director for vesting purposes. We recorded $0.2 million and $5.2 million as restricted common stock and as unearned compensation in 2005 and 2004, respectively.

In April 2005, the Board of Directors pursuant to the 2004 Stock Incentive Plan approved a restricted stock grant for all employees and the non-employee directors totaling 665,000 shares and approved a grant for an additional 20,000 shares in October 2005. The shares under this grant vest 25%, 25%, and 50% each April of 2008, 2009 and 2010, respectively. In addition, vesting of the grant may be accelerated under certain circumstances including our stock price closing at or above $55.80 per share, or a change in control of the company. Prior to vesting, the grantee shall have the right to vote the shares and receive any dividends. Such rights, however, will cease in the event the grantee’s service with us is terminated under conditions which do not cause an accelerated vesting of the grant shares. We recorded $19.3 million as restricted common stock and unearned compensation.

Unearned compensation is reported as a separate reduction in stockholders’ equity on the balance sheet and is amortized to stock compensation expense on a straight line basis over the life of the grant. During each of the years ended December 31, 2005, 2004 and 2003, we amortized $4.6 million, $1.3 million and $1.3 million, respectively, to stock based compensation expense. The total compensation expense may decrease if a grant fails to vest in accordance with its terms.

A summary of all stock grants as of December 31, 2005, 2004 and 2003, and changes during the years ending on those dates is presented below:

	At December 31,
	2005					2004					2003
				Weighted					Weighted					Weighted
				Average					Average					Average
	Shares			Price		Shares			Price		Shares			Price
Outstanding at beginning of period		329,382		$	20.49		259,636		$	12.16		447,192		$	12.16
Grants		691,000			28.12		200,000			25.88					—
Vested		(110,984	)		17.27		(130,254	)		12.16		(173,228	)		12.16
Forfeited		(600	)		25.88		—			—		(14,328	)		12.16
Outstanding at end of year		908,798		$	26.68		329,382		$	20.49		259,636		$	12.16

19

REMINGTON OIL AND GAS CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) 

Note 8 — Employee Benefit Plans

Pension Plans

Remington and CKB Petroleum, Inc. each have a noncontributory defined benefit pension plan. The retirement benefits available are generally based on years of service and average earnings. We fund the plans with contributions at least equal to the minimum funding provisions of employee benefit and tax laws, but usually no more than the maximum tax deductible contribution allowed. Plan assets consist primarily of equity and fixed income securities. The following tables set forth significant information about the plans, the reconciliation of the benefit obligation, plan assets, and funded status for the pension plans. We use a December 31 measurement date for the plan.

	At December 31,
	2005			2004
	(In thousands)
Reconciliation of the change in projected benefit obligation
Beginning projected benefit obligation	$	7,083		$	6,032
Service cost		588			591
Interest cost		400			373
Actuarial (gain) loss		(302	)		298
Benefits paid		(1,054	)		(211	)
Ending projected benefit obligation	$	6,715		$	7,083
Reconciliation of the change in plan assets
Beginning market value	$	6,526		$	5,989
Actual return on plan assets		290			574
Employer contributions		600			174
Benefit payments		(1,054	)		(211	)
Ending market value	$	6,362		$	6,526
Funded status and amounts recognized in the balance sheet
Excess of assets over projected benefit obligation	$	(353	)	$	(557	)
Unrecognized net actuarial loss		2,307			2,498
Unrecognized prior service costs		33			36
Adjusted net prepaid benefit cost recognized	$	1,987		$	1,977
Accumulated benefit obligation	$	6,016		$	5,907
Assumptions used to determine benefit obligations
Discount rate		6.00	%		6.00	%
Rate of compensation increase		3.00	%		3.00	%

20

REMINGTON OIL AND GAS CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) 

Cash flows

Contributions

We do not expect to make a contribution in 2006.

Estimated future benefit payments

We expect to pay the following benefit payments, which reflect expected future service, as appropriate, and assume that future retirees will elect a lump-sum form of benefit.

	(In Thousands)
2006	$	1,001
2007		196
2008		190
2009		852
2010		180
2011 through 2015		2,490

The net periodic pension cost recognized in our income statements includes the following components:

	For Years Ended December 31,
	2005			2004			2003
				(In thousands)
Components of net periodic pension cost
Service cost	$	588		$	591		$	415
Interest cost on projected benefit obligation		400			373			322
Expected return on plan assets		(514	)		(471	)		(352	)
Recognized net actuarial loss		113			155			154
Amortization of prior service costs		3			3			3
Net periodic pension cost	$	590		$	651		$	542
Assumptions used to determine net periodic pension costs
Discount rate		6.00	%		6.00	%		6.50	%
Expected return on plan assets		8.00	%		8.00	%		8.00	%
Rate of compensation increase		3.00	%		3.00	%		3.00	%

To estimate the expected long-term rate of return on pension plan assets, we consider the current and expected asset allocations, as well as historical returns on equities and debt securities.

The accumulated benefit obligation represents the present value of the benefits earned to the measurement date, with benefits computed based on current compensation levels. The projected benefit obligation is the accumulated benefit obligation increased to reflect expected future compensation.

Remington’s aggregate projected benefit obligation at December 31, 2005, was $6.0 million and the aggregate fair value of plan assets was $5.5 million. On December 31, 2005, Remington had a prepaid benefit cost of $1.6 million. CKB Petroleum’s aggregate projected benefit obligation at December 31, 2005, was $687,000 and the aggregate fair value of plan assets was $843,000. On December 31, 2005, CKB Petroleum had a prepaid benefit cost of $433,000.

21

REMINGTON OIL AND GAS CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) 

Plans asset allocation (Plans’ assets are held in trust.)

	At December 31,
	2005			2004
Asset category
Equity securities		64.9	%		71.2	%
Debt securities		21.4	%		19.7	%
Money funds		13.7	%		9.1	%
Total		100.0	%		100.0	%

Money fund balances were disproportionately high at each year end because we made large contributions to the pension trusts during the last few days of each year. These funds were allocated to equity and debt securities and utilized for regular distributions to retirees during the early part of the next year. See the discussion of our investment policy below.

Plan fiduciaries set investment policies, strategies, and guidelines for the pension trusts. These include

•  Achieve a long-term average annual rate of return of at least 8%.

•  Asset allocations ranging from 75% equities and 25% debt securities to 25% equities and 75% debt securities.

Recommended long-term average allocation is 60% equities and 40% debt securities.

•  Permissible investments include publicly-traded common and preferred stocks, convertible bonds, fixed income securities, guaranteed investment contracts, and money market funds. Transactions are not permitted in futures contracts or options.

•  Broad diversification of plan assets.

Plan fiduciaries have appointed an investment advisor and asset managers. A Plan Administration Committee, comprising three company executive officers, meets with the investment advisor at least quarterly to review overall investment performance, asset manager performance, current asset category allocations, recommended asset category allocations for the coming quarter, and sources of liquidity for distributions to retirees for the coming quarter. During the latter part of 2002 the committee, with the assistance of the investment advisor, set the target allocation at 75% equities and 25% debt securities and has maintained that target allocation continuously since then.

Employee Severance Plan, Post Retirement Benefits and Post Employment Benefits

Our employee severance plan provides severance benefits ranging from 2 months to 18 months of the employee’s base salary if the employee is terminated involuntarily. The plan incorporates the provisions and terms of any individual contract or agreement that an employee may have with the company. Certain of the executive officers have individual employment contracts with the company.

We have never paid postretirement benefits other than pensions, and we are not obligated to pay such benefits in the future. Future obligations for postemployment benefits are immaterial. Therefore, we have not recognized any liability for them.

22

REMINGTON OIL AND GAS CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) 

Note 9 — Income Taxes

The following table provides a summary of our income tax expense:

	For Years Ended December 31,
	2005		2004		2003
			(In thousands)
Current Federal	$	8,745	$	7,755	$	175
State		62		147		—
		8,807		7,902		175
Deferred Federal		29,760		24,688		23,113
State		425		346		330
		30,185		25,034		23,443
Total income tax expense	$	38,992	$	32,936	$	23,618

Total income tax expense differs from the amount computed by applying the federal income tax rate to net income before income taxes as follows:

	For Years Ended December 31,
	2005		2004			2003
			(In thousands)
Federal income tax expense at statutory rate	$	38,346	$	32,876		$	23,290
State income tax expense		487		493			—
Other		159		(433	)		328
Total income tax expense	$	38,992	$	32,936		$	23,618

The following table reflects the significant components of our net deferred tax liability.

	At December 31,
	2005			2004
	(In thousands)
Deferred tax liabilities Oil and gas properties	$	(87,237	)	$	(56,335	)
Prepaid insurance		(1,094	)		—
Pension		(591	)		(598	)
Total deferred tax liabilities		(88,922	)		(56,933	)
Deferred tax assets Asset retirement obligation		3,335			2,520
Other assets		1,617			628
Total deferred tax assets		4,952			3,148
Net deferred tax (liability)	$	(83,970	)	$	(53,785	)

Note 10 — Subsequent Event

On January 22, 2006 we entered into a merger agreement with Helix Energy Solutions Group, Inc. (formerly Cal Dive International, Inc.). Consideration for the offer from Helix will be $27.00 in cash and 0.436 shares of Helix

23

REMINGTON OIL AND GAS CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) 

stock for each of our shares. Completion of the merger is expected in the second quarter of 2006, however, it is subject to customary conditions to closing, including without limitation, approval by our stockholders. We and Helix will file a proxy statement/prospectus and other relevant documents concerning the proposed merger and the special meeting of our stockholders which will be called seeking approval of the transaction.

We have entered into the following agreements for forward sales of production for the period March 2006 through June 2007:

Oil:	1,000 bbls/day @ $70.00/bbl	March 2006-February 2007
Gas:	20 mmbtu/day @ $9.83/mmbtu	March 2006-August 2006
	10 mmbtu/day @ $8.88/mmbtu	September 2006-December 2006
	20 mmbtu/day @ $9.72/mmbtu	January 2007-June 2007

Note 11 — Oil and Gas Reserves and Present Value Disclosures (Unaudited)

The estimates of oil and gas reserves were prepared by us and audited by Netherland, Sewell & Associates, Inc. an independent reserve engineering firm. The determination of these reserves is a complex and interpretative process that is subject to continued revision as additional information becomes available. In many cases, a relatively accurate determination of reserves may not be possible for several years due to the time necessary for development drilling, testing and studies of the reservoirs. We do not file reserve estimates with any other federal authority or agency.

The quantities of proved oil and gas reserves presented below include only the amounts which we reasonably expect to recover in the future from known oil and gas reservoirs under the current economic and operating conditions. Proved reserves include only quantities that we can commercially recover using current prices, costs, existing regulatory practices and technology. Therefore, any changes in future prices, costs, regulations, technology or other unforeseen factors could significantly increase or decrease proved reserve estimates. Our proved undeveloped reserves are generally brought on line within 12 months. Alternatively, they are associated with long life fields where economics dictate waiting for an existing wellbore available for sidetrack, or waiting to mobilize a platform rig for operations. Accordingly, proved undeveloped reserves in major fields may be carried for many years. The following table presents our net ownership interest in proved oil and gas reserves.

	At December 31,
	2005						2004						2003
	Oil			Gas			Oil			Gas			Oil			Gas
	Bbls			Mcf			Bbls			Mcf			Bbls			Mcf
							(In thousands)
Beginning of period		16,899			150,699			11,619			142,432			13,114			124,967
Revisions of previous estimates		1,736			(16,776	)		1,862			(12,801	)		(363	)		(5,754	)
Extensions, discoveries and other		1,234			57,405			5,093			49,125			337			42,676
Reserves purchased		—			—			—			—			306			4,692
Reserves sold		(4	)		(508	)		—			—			—			—
Production		(1,484	)		(22,161	)		(1,675	)		(28,057	)		(1,775	)		(24,149	)
End of period		18,381			168,659			16,899			150,699			11,619			142,432
Proved developed reserves		9,511			102,447			6,858			89,376			7,071			76,475

The following tables represent value-based information about our proved oil and gas reserves. The standardized measure of discounted future net cash flows results from the application of specific criteria applicable to the value-based disclosures of all oil and gas reserves in the industry. Due to the imprecise nature of estimating oil and gas reserve quantities and the uncertainty of future economic conditions, we cannot make any representation

24

REMINGTON OIL AND GAS CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) 

about interpretations that may be made or what degree of reliance that may be placed on this method of evaluating proved oil and gas reserves.

We compute future cash revenue by multiplying the year-end commodity prices, or contractual pricing if applicable, by estimated future production from proved oil and gas reserves. We use year-end West Texas Intermediate posted prices per barrel and Henry Hub spot market prices per MMBtu adjusted by property for energy content, quality, transportation fees, and regional price differentials.

	Years Ended December 31,
	2005		2004		2003
West Texas Intermediate posted price (per barrel)	$	57.75	$	40.25	$	29.25
Henry Hub spot market price (per MMbtu)	$	10.08	$	6.18	$	5.97

We estimated the costs based on the prior year costs incurred for individual properties, or similar properties if a particular property did not have production during the prior year. Future income tax expense was determined by applying the current statutory tax rate to the estimated future net cash flow from all properties. Finally, we discounted the future net cash flow, after tax, by 10% per year to arrive at the standardized measure of discounted future net cash flows presented below.

	At December 31,
	2005			2004			2003
				(In thousands)
Oil and gas revenues	$	2,713,983		$	1,581,927		$	1,206,775
Production costs		(200,297	)		(192,761	)		(165,733	)
Development, dismantlement and abandonment costs(1)		(148,514	)		(150,596	)		(140,175	)
Income tax expense		(706,403	)		(323,492	)		(223,929	)
Net cash flow		1,658,769			915,078			676,938
10% annual discount		(421,786	)		(276,229	)		(190,642	)
Standardized measure of discounted future net cash flows	$	1,236,983		$	638,849		$	486,296

(1) Based on our Netherland, Sewell & Associates’ audited reserve report as of December 31, 2005, we estimate that the amount of capital required to convert proved undeveloped reserves to proved developed reserves will be $113.0 million of the $121.1 million of future development costs, including $62.8 million in 2006, $12.1 million in 2007 and $7.6 million in 2008. Our actual expenditures may differ from these estimates. Capital expenditures incurred to develop proved undeveloped reserves were $40.2 million in 2005, $21.8 million in 2004 and $28.4 million in 2003.

25

REMINGTON OIL AND GAS CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) 

The following table summarizes the principal sources of change in the standardized measure of discounted future net cash flows from year to year.

	At December 31,
	2005			2004			2003
				(In thousands)
Standardized measure of discounted cash flows at beginning of year	$	638,849		$	486,296		$	351,042
Sales and transfers of oil and gas produced, net of production costs		(232,065	)		(208,492	)		(161,670	)
Net changes in prices and production costs		578,486			76,957			134,883
Net changes in estimated development costs		(68,504	)		(40,570	)		(13,169	)
Net changes in income tax expense		(302,104	)		(63,665	)		(47,324	)
Extensions, discoveries and improved recovery less related costs		436,613			321,813			141,970
Proved oil and gas reserves purchased		—			—			13,998
Proved oil and gas reserves sold		(2,192	)		—			—
Previously estimated development costs incurred during the year		70,061			32,932			28,477
Revisions of previous quantity estimates		(42,847	)		(6,579	)		(34,006	)
Other changes		96,801			(25,026	)		36,991
Accretion of discount		63,885			65,183			35,104
Standardized measure of discounted future net cash flows end of year	$	1,236,983		$	638,849		$	486,296

26

REMINGTON OIL AND GAS CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) 

Note 12 — Quarterly Financial Information (Unaudited)

	For Years Ending
	December 31,
	2005		2004
	(In thousands, except per share data)
First Quarter
Net revenues(1)	$	59,471	$	46,057
Net income	$	16,035	$	11,001
Basic net income per share	$	0.57	$	0.41
Diluted net income per share	$	0.56	$	0.39
Second Quarter
Net revenues(1)	$	77,261	$	58,265
Net income	$	24,924	$	14,988
Basic net income per share	$	0.87	$	0.55
Diluted net income per share	$	0.83	$	0.53
Third Quarter
Net revenues (1)	$	71,224	$	59,904
Net income	$	23,875	$	15,639
Basic net income per share	$	0.83	$	0.57
Diluted net income per share	$	0.79	$	0.55
Fourth Quarter
Net revenues (1)	$	52,295	$	69,279
Net income	$	5,735	$	19,368
Basic net income per share	$	0.20	$	0.70
Diluted net income per share	$	0.19	$	0.67

(1) Net revenues include only oil and gas sales revenue.

27

REMINGTON OIL AND GAS CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

		March 31,			December 31,
		2006			2005
		(Unaudited)
		(In thousands, except
		share data)
ASSETS
Current assets
	Cash and cash equivalents	$	47,887		$	38,860
	Accounts receivable		62,704			66,887
	Insurance receivable		38,932			23,308
	Income taxes receivable		—			5,767
	Prepaid expenses and other current assets		12,942			5,466
Total current assets			162,465			140,288
Properties
	Oil and gas properties (successful-efforts method)		937,791			908,437
	Other properties		3,876			3,758
	Accumulated depreciation, depletion and amortization		(485,804	)		(468,290	)
Total properties			455,863			443,905
Other assets			1,874			1,872
Total assets		$	620,202		$	586,065
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
	Accounts payable and accrued liabilities	$	72,474		$	76,561
	Income taxes payable		3,521			—
	Current deferred income taxes		1,094			1,094
Total current liabilities			77,089			77,655
Long-term liabilities
	Asset retirement obligation		23,498			21,375
	Deferred income taxes		86,612			82,876
Total long-term liabilities			110,110			104,251
	Total liabilities		187,199			181,906
Commitments and contingencies (Note 7)
Stockholders’ equity
	Preferred stock, $.01 par value, 25,000,000 shares authorized, no shares outstanding
	Common stock, $.01 par value, 100,000,000 shares authorized, 28,886,443 shares issued and 28,852,084 shares outstanding in 2006, 28,790,997 shares issued and 28,756,638 shares outstanding in 2005		289			288
	Additional paid-in capital		155,573			149,234
	Restricted common stock		—			24,264
	Unearned compensation		—			(20,385	)
	Retained earnings		277,141			250,758
Total stockholders’ equity			433,003			404,159
Total liabilities and stockholders’ equity		$	620,202		$	586,065

See accompanying Notes to Condensed Consolidated Financial Statements.

28

REMINGTON OIL AND GAS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

		Three Months Ended
		March 31,
		2006		2005
		(Unaudited)
		(In thousands, except
		per share amounts)
Revenues
	Gas sales	$	44,619	$	40,390
	Oil sales		15,377		19,081
	Interest income		458		252
	Other income		17,644		63
Total revenues			78,098		59,786
Costs and expenses
	Operating		7,228		5,912
	Exploration		7,004		10,385
	Depreciation, depletion and amortization		17,858		16,011
	Impairment expense		274		297
	General and administrative		5,186		2,121
	Interest and financing		127		198
Total costs and expenses			37,677		34,924
Income before income taxes			40,421		24,862
	Income tax expense		14,038		8,827
Net income		$	26,383	$	16,035
Basic income per share		$	0.92	$	0.57
Diluted income per share		$	0.90	$	0.56
Weighted average shares outstanding (Basic)			28,822		28,045
Weighted average shares outstanding (Diluted)			29,414		28,838

See accompanying Notes to Condensed Consolidated Financial Statements.

29

REMINGTON OIL AND GAS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

			Three Months
			Ended
			March 31,
			2006			2005
			(Unaudited)
			(In thousands)
Cash flow provided by operations
	Net income		$	26,383		$	16,035
	Adjustments to reconcile net income
		Depreciation, depletion and amortization		17,858			16,011
		Deferred income taxes		3,736			5,451
		Amortization of deferred charges		25			46
		Dry hole costs		5,227			9,049
		Impairment costs		274			297
		Cash paid for dismantlement		(10	)		(243	)
		Stock based compensation		1,241			512
		Tax benefit from exercise of stock options		(1,013	)		3,376
		Gain on sale of properties		(59	)		—
	Changes in working capital
		(Increase) decrease in accounts receivable		3,968			(5,646	)
		(Increase) in insurance receivable		(15,624	)		—
		Decrease in income taxes receivable		5,767			—
		(Increase) decrease in prepaid expenses and other assets		(7,501	)		49
		Increase in accounts payable and accrued expenses		5,539			418
		Increase in income taxes payable		4,534			—
	Net cash flow provided by operations			50,345			45,355
	Cash from investing activities
	Capital expenditures			(42,668	)		(47,600	)
	Proceeds from sale of properties			130			—
	Net cash (used in) investing activities			(42,538	)		(47,600	)
	Cash from financing activities
		Tax benefit from exercise of stock options		1,013			—
		Common stock issued		665			6,833
		Purchase of treasury stock		(458	)		(336	)
	Net cash provided by financing activities			1,220			6,497
Net increase in cash and cash equivalents				9,027			4,252
	Cash and cash equivalents at beginning of period			38,860			58,659
Cash and cash equivalents at end of period			$	47,887		$	62,911

See accompanying Notes to Condensed Consolidated Financial Statements.

30

REMINGTON OIL AND GAS CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note 1. Accounting Policies and Basis of Presentation

      Remington Oil and Gas Corporation is an independent oil and gas exploration and production company incorporated in Delaware. Our oil and gas properties are located in the Gulf of Mexico and the onshore Gulf Coast.

      We prepared these financial statements according to the instructions for Form 10-Q. Therefore, the financial statements do not include all disclosures required by generally accepted accounting principles. However, we have recorded all transactions and adjustments necessary to fairly present the financial statements included in this Form 10-Q. The adjustments made are normal and recurring. The following notes describe only the material changes in accounting policies, account details, or financial statement notes during the first three months of 2006. Therefore, please read these financial statements and notes to the financial statements together with the audited financial statements and notes to financial statements in our 2005 Form 10-K and 10-K/A. The income statement for the three months ended March 31, 2006, cannot necessarily be used to project results for the full year.

New Accounting Standard

      Effective January 1, 2006, we adopted Statement of Financial Accounting Standards No. 123 (revised 2004), “Share-Based Payment” (“SFAS 123(R)”), which requires all share-based payments to employees, including grants of employee stock options, to be recognized in our Consolidated Statements of Income, based on their fair values as of the grant date. SFAS 123(R) supersedes Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation” (“SFAS 123”) and Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB 25”) and amends Statement of Financial Accounting Standards No. 95, “Statement of Cash Flows”.

      We have adopted SFAS 123(R) using the modified prospective method which requires us to record compensation cost related to unvested stock awards over the remaining service periods of those awards with no change in historical reported earnings. Awards granted after December 31, 2005 are valued at fair value in accordance with the provisions of SFAS 123(R) and recognized on a straight line basis over the service period relating to each award. SFAS 123(R) also requires the tax benefits in excess of recognized compensation expenses to be reported as a financing cash flow rather than as an operating cash flow as required under previous literature.

      On November 10, 2005, the FASB issued FASB Staff Position No. FAS 123(R)-3, “Transition Election Related to Accounting for Tax Effects of Share-Based Payment Awards.” We have elected to adopt the alternative transition method provided in this FASB Staff Position for calculating the tax effects of share-based compensation pursuant to SFAS 123(R). The alternative transition method includes a simplified method to establish the beginning balance of the additional paid-in capital pool (APIC pool) related to the tax effects of employee share-based compensation, which is available to absorb tax deficiencies recognized subsequent to the adoption of SFAS 123(R).

      We recorded $1.2 million in share-based compensation expense during the three months ended March 31, 2006, related to employee stock grants. In addition, for the three months ended March 31, 2006, the adoption of SFAS 123(R) resulted in a reclassification to reduce net cash provided by operating activities with an offsetting increase in net cash provided by financing activities of $1.0 million, related to incremental tax benefits from stock options exercised during the period.

      Prior to the adoption of SFAS 123(R), we accounted for share-based payments to employees using the intrinsic value method prescribed by APB 25 and related interpretations, and therefore, did not recognize compensation expenses associated with employee stock options. However, since all of our outstanding stock options vested prior to the adoption of SFAS 123(R), we will not recognize any expenses associated with

31

REMINGTON OIL AND GAS CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

these prior stock option grants. The adoption of SFAS 123(R) had no effect on the accounting for our outstanding stock grant awards.

      The following table summarizes relevant information as to the reported results under the intrinsic value method of accounting for stock awards, with supplemental information as if the fair value recognition provisions of SFAS No. 123 had been applied for the three months ended March 31, 2005:

		Three Months
		Ended
		March 31, 2005
		(In thousands,
		except per
		share amounts)
As reported:
	Net income	$	16,035
	Basic income per share	$	0.57
	Diluted income per share	$	0.56
Stock based compensation (net of tax at statutory rate of 35%) included in net income as reported		$	329
Stock based compensation (net of tax at statutory rate of 35%) if using the fair value method as applied to all awards		$	329
Pro forma (if using the fair value method applied to all awards):
	Net income	$	16,035
	Basic income per share	$	0.57
	Diluted income per share	$	0.56
Weighted average shares used in computation
	Basic		28,045
	Diluted		28,838

Note 2. Net Income per Share

		Three Months Ended
		March 31,
		2006		2005
		(In thousands, except
		per share amounts)
Net income		$	26,383	$	16,035
Basic income per share		$	0.92	$	0.57
Diluted income per share		$	0.90	$	0.56
Weighted average common stock
	Total common shares for basic income per share		28,822		28,045
	Dilutive stock options outstanding (treasury stock method)		288		529
	Restricted common stock grant		304		264
Total common shares for diluted income per share			29,414		28,838
Non-dilutive stock options outstanding			928		417

32

REMINGTON OIL AND GAS CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

Note 3. Insurance Receivables

      As a result of Hurricanes Katrina and Rita, which occurred in August and September of 2005, we incurred physical damage and shut-in production on many of our offshore properties. We maintain insurance coverage for damages to our offshore properties, including producing and drilling wells, platforms, pipelines and lost production. As of March 31, 2006, we have $38.9 million accrued as an insurance receivable on the Balance Sheet. Of this amount, $18.3 million represents insurance receivables for hurricane related expenditures associated with physical damage, lost equipment and a control of well claim. The remaining $20.6 million represents an insurance receivable for partial claim for lost production settled through March 31, 2006, from shut-ins caused by Hurricane Rita, of which $17.3 million is related to the current period and is included in Other income on the Income Statement. Additional claims associated with lost production as a result of Hurricane Katrina have been made and will be recorded when finalized.

Note 4. Pension Benefits

Components of Net Periodic Pension Benefit Cost

	Three Months
	Ended
	March 31,
	2006			2005
	(In thousands)
Service cost	$	208		$	136
Interest cost on projected benefit obligation		118			96
Expected return on plan assets		(125	)		(128	)
Recognized net actuarial loss		52			24
Amortization of prior service costs		1			1
Net periodic pension benefit costs	$	254		$	129

Employer Contributions

      We disclosed in our financial statements for the year ended December 31, 2005, that we do not expect to make a contribution to the plans in 2006. During the three months ended March 31, 2006, we made no contributions to the plans. At this time, if the Pension Plan is continued, we do not expect to make a contribution to the Pension Plan for 2006. If the Pension Plan is altered as a result of the merger with Helix, a contribution may be required.

Note 5. Notes Payable

      As of March 31, 2006, our credit facility of $200.0 million had a borrowing base of $150.0 million. Interest only is payable quarterly through September 2009, at which time the line expires and all principal becomes due, unless the line is extended or renegotiated. As of March 31, 2006, there were no borrowings outstanding under the facility.

Note 6. Forward Sales Contracts

      We have entered into the following agreements for forward sales of production for the period March 2006 through June 2007:

Oil:	1,000 bbls/day @ $70.00/bbl	March 2006 — February 2007
Gas:	20,000 mmbtu/day @ $9.83/mmbtu	March 2006 — August 2006
	10,000 mmbtu/day @ $8.88/mmbtu	September 2006 — December 2006
	20,000 mmbtu/day @ $9.72/mmbtu	January 2007 — June 2007

33

REMINGTON OIL AND GAS CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

Note 7. Contingencies

      We have no material pending legal proceedings.

Note 8. Proposed Merger with Helix Energy Solutions Group, Inc.

      On January 22, 2006 we entered into a merger agreement with Helix Energy Solutions Group, Inc. (formerly Cal Dive International, Inc.). Consideration for the offer from Helix will be $27.00 in cash and 0.436 shares of Helix stock for each of our shares. Completion of the merger is expected in the second quarter of 2006, however, it is subject to customary conditions to closing, including without limitation, approval by our stockholders. We and Helix filed a proxy statement/ prospectus and other relevant documents concerning the proposed merger with the Securities and Exchange Commission on April 3, 2006. In addition, a special meeting of our stockholders will be called seeking approval of the transaction.

34