Revenues, production quantities and average wellhead prices from sales of natural gas and crude oil, condensate and natural gas liquids are shown in the following table (excluding results of the North Sea business that was sold in 2005):

		Three Months Ended						Six Months Ended
		June 30,						June 30,
(Millions of dollars)		2006			2005			2006			2005
Revenues -
Natural gas sales		$	569		$	632		$	1,238		$	1,180
Crude oil, condensate and natural gas liquids sales			658			476			1,168			934
Loss on oil and gas derivatives - hedge			(150	)		(59	)		(424	)		(85	)
Mark-to-market nonhedge derivative gain (loss)			20			12			150			(39	)
Gain (loss) due to hedge ineffectiveness			-			(35	)		30			(44	)
Gas marketing revenues			147			138			360			270
Process, gathering and other revenues			23			19			45			38
Total		$	1,267		$	1,183		$	2,567		$	2,254
Natural Gas Production and Average Sales Prices -
Production (MMcf/d) -
Gulf of Mexico -
Deepwater			253			285			246			270
Shelf			120			167			105			162
U.S. Onshore -
Rocky Mountain			388			330			376			331
Southern			223			241			232			253
Total			984			1,023			959			1,016
Average Sales Prices (per Mcf) -
Gulf of Mexico -
Deepwater		$	6.80		$	7.19		$	7.58		$	6.91
Shelf			6.76			6.97			7.47			6.73
U.S. Onshore -
Rocky Mountain			5.84			6.42			6.66			6.07
Southern			6.56			6.72			7.28			6.16
Average		$	6.36		$	6.79		$	7.14		$	6.42
Oil, Condensate and NGL Production and Average Sales Prices-
Production (Mbbls/d) -
Gulf of Mexico -
Deepwater			59			47			53			47
Shelf			9			13			9			14
U.S. Onshore -
Rocky Mountain			21			22			21			22
Southern			13			14			13			14
Total U.S.			102			96			96			97
China			17			17			17			19
Total			119			113			113			116
Average Wellhead Sales Prices (per bbl) -
Gulf of Mexico -
Deepwater		$	61.66		$	47.26		$	59.29		$	46.03
Shelf			58.39			47.25			56.69			46.46
U.S. Onshore -
Rocky Mountain			57.49			43.44			54.81			41.82
Southern			57.62			45.58			52.95			44.03
Average U.S.			59.99			46.13			57.20			44.84
China			63.58			42.85			59.08			40.46
Average		$	60.52		$	45.60		$	57.47		$	44.09
Energy Equivalent Production -
Thousands of barrels of oil equivalent (Mboe) per day			283			284			272			286
Millions of cubic feet of gas equivalent (MMcfe) per day			1,699			1,702			1,634			1,715

 

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Natural Gas Revenues and Production - Natural gas sales revenues of $569 million in the second quarter of 2006 decreased 10% from 2005 as a result of a $.43 per thousand cubic feet (Mcf) decrease in average natural gas sales prices and a 4% decrease in production. Lower sales prices in the 2006 second quarter decreased revenues $39 million. Production for the second quarter of 2006 was 984 million cubic feet per day (MMcf/d), 39 MMcf/d lower than 2005, reducing gas sales revenues by $24 million. The decrease in production resulted from the divestiture of certain onshore properties in the U.S. which occurred in late 2005 (25 MMcf/d), along with continued hurricane-related losses in the Gulf of Mexico shelf and natural field declines (47 MMcf/d). In the Gulf of Mexico deepwater, third-party pipelines and infrastructures that sustained damage from the 2005 hurricanes were returned to full service in late April 2006. Production from the Redhawk field was impacted by the curtailment and reported lower production for the 2006 second quarter as compared to 2005 (27 MMcf/d). These production decreases were partially offset by the 2006 start-up of Gulf of Mexico deepwater fields, Constitution and Ticonderoga (19 MMcf/d), and higher production from the Rocky Mountain region (58 MMcf/d) primarily due to our accelerated development drilling program in the Greater Natural Buttes area.

Natural gas sales revenues increased $58 million for the six months of 2006 compared to 2005 as a result of a $.72 per Mcf increase in the average natural gas sales price. The higher sales price (an average of $7.14 per Mcf) provided a $124 million increase in gas sales revenues. Production in the first six months of 2006 averaged 959 MMcf/d, 57 MMcf/d lower than 2005, decreasing gas sales revenues $66 million. The decrease in production was primarily due to hurricane-related losses in the Gulf of Mexico, the divestiture of certain U.S. onshore properties late in 2005 and natural field declines in the Gulf of Mexico. The divestiture of onshore properties reduced production in the first six months of 2006 by 26 MMcf/d compared with 2005. The production decreases were partially offset by the 2006 start-up of the Constitution and Ticonderoga fields (11 MMcf/d), our development activities in the Gulf of Mexico and higher production from the Rocky Mountain region (45 MMcf/d) due to our accelerated development drilling program in the Greater Natural Buttes area.

Crude Oil Revenues and Production - Crude oil, condensate and natural gas liquids sales revenues increased $182 million or 38% in the second quarter of 2006 compared to 2005. The increase is due to higher crude oil sales prices and slightly higher production. The average realized oil price for the second quarter of 2006 was $60.52 per barrel, an increase of $14.92 per barrel over 2005. Higher sales prices contributed an additional $162 million to second quarter 2006 oil sales revenues. Second-quarter 2006 oil production of 119 thousand barrels per day (Mbbls/d) was 6 Mbbls/d higher than 2005, increasing oil sales revenues by $20 million. The second quarter 2006 production increase was primarily due to the 2006 start-up of Gulf of Mexico’s Constitution and Ticonderoga fields (18 Mbbls/d) and increased production from China’s CFD 11-3 and CFD 11-5 fields (2 Mbbls/d) that began producing in July 2005. These production increases were partially offset by natural field declines in the Gulf of Mexico and China’s CFD 11-1 and CFD 11-2 fields.

For the first six months of 2006, crude oil, condensate and natural gas liquids sales revenues increased $234 million compared to 2005 as a result of higher sales prices partially offset by slightly lower production. The average sales price increased $13.38 per barrel compared with 2005, contributing $270 million to oil sales revenues. Oil production for 2006 decreased by 3 Mbbls/d or 3% from 2005, reducing oil sales revenues $36 million. The decrease is attributable to the sale of certain U.S. onshore properties and lower production from China’s CFD 11-1 and CFD 11-2 fields (6 Mbbls/d). These production decreases were partially offset by new production from the Constitution and Ticonderoga fields (11 Mbbls/d) and increased production from China’s CFD 11-3 and CFD 11-5 fields (3 Mbbls/d).

Gains (Losses) Associated with Commodity Derivatives - Gains and losses on derivatives designated as hedges of forecasted oil and gas sales are deferred in accumulated other comprehensive income (stockholders’ equity) and reclassified into earnings when the hedged sales transactions affect earnings. Gains and losses associated with hedge ineffectiveness and nonhedge derivatives are recognized in current earnings as a component of revenues. Nonhedge derivative losses represent net realized and unrealized gains and losses related to crude oil and natural gas derivative instruments that have not been designated as hedges or that do not qualify for hedge accounting treatment.

Effective March 1, 2006, the company elected to discontinue hedge accounting for its crude oil and natural gas derivatives since a large portion of our natural gas derivatives no longer qualified for hedge accounting and to increase clarity in our financial statements. Consequently, the company now recognizes mark-to-market gains and losses on all its oil and gas derivatives in earnings rather than deferring such amounts in accumulated other comprehensive income. As of June 30, 2006, a pretax loss of $939 million ($611 million after tax) deferred in accumulated other comprehensive income will be reported in future earnings through 2007 as the original hedged oil and gas sales occur. This change in reporting had no impact on the company’s reported cash flows, although future results of operations are affected by mark-to-market gains and losses that fluctuate with volatile oil and gas prices.

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In the second quarter of 2006, we recognized a $150 million hedge loss associated with amounts previously deferred in other comprehensive income compared to a loss of $59 million in 2005 when we applied hedge accounting. For the six months ended June 30, 2006, hedge losses were $424 million compared to $85 million in 2005. The higher losses in 2006 as compared to 2005 were caused by substantially higher crude oil prices and a moderate increase in natural gas prices during the 2006 periods.

During the second quarter and first six months of 2006, we recognized mark-to-market gains of $20 million and $150 million, respectively, associated with nonhedge derivatives primarily due to declining natural gas prices since year-end 2005 partially offset by mark-to-market losses on crude oil derivatives. In addition, before discontinuing hedge accounting, the company recognized a gain due to hedge ineffectiveness of $30 million through February 2006 (reflecting a reduction in hedge ineffectiveness losses measured at December 31, 2005) primarily as a result of narrowing natural gas basis differentials between NYMEX forward prices and expected future physical sales prices.

Gas Marketing Activities - Kerr-McGee purchases third-party natural gas for aggregation and sale with the company’s own production in the Rocky Mountain area. In addition, we have transportation capacity to markets in the Midwest to facilitate sale of natural gas outside the immediate vicinity of our Rocky Mountain production.

Marketing revenue was $147 million in the second quarter of 2006, an increase of $9 million over 2005. Marketing revenue for the first six months of 2006 totaled $360 million, $90 million higher than in 2005. The increase in both periods was primarily the result of higher purchase and resale of third-party natural gas in the Rocky Mountain area. An increase in natural gas sales prices also contributed to the increase in year-to-date revenues. Gas purchase costs (including transportation) increased $6 million in the second quarter of 2006 and $90 million in the first six months of 2006 compared with 2005. Third-party marketing volumes (MMbtu/day) were 289,800 and 241,000 in the second quarter of 2006 and 2005, respectively. For the first six months of 2006 and 2005, daily marketing volumes averaged 306,700 and 249,000, respectively.

Processing, Gathering and Other Revenues - Other revenues include gas processing plant and gathering system revenues primarily onshore in the U.S. Processing, gathering and other revenues totaled $23 million in the second quarter 2006, an increase of $4 million from the 2005 period. For the first six months of 2006, processing, gathering and other revenues was $45 million, compared with $38 million in 2005. The increase in both periods was mainly the result of higher gas processing revenues from the company’s nonoperated ownership in a Wattenberg field gas plant.

Operating Expenses 

Lease Operating Costs - Second quarter 2006 lease operating cost of $128 million was $13 million higher than 2005. Lease operating costs for the first six months of 2006 totaled $259 million, an increase of $36 million compared with 2005. Lease operating costs increased to $5.26 per boe for the first six months of 2006 from $4.30 per boe in 2005. The increase in both periods was due in part to higher stock-based compensation expense, a $6 million increase in the second quarter and a $16 million increase for the six-month period. In addition, the company incurred higher property insurance and hurricane-related repair costs resulting in a $5 million and $14 million increase for the 2006 second quarter and year-to-date period, respectively. Higher lease operating expenses were also incurred in the Rocky Mountain region associated with increasing production, higher water disposal costs in the Natural Buttes field and higher workover expenditures in the Wattenberg field. These increases were partially offset by lower expenses in the deepwater Gulf of Mexico due to additional production handling fees recovered with the start-up of the Gulf of Mexico’s Ticonderoga field.

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Production and Ad Valorem Taxes - Production and ad valorem taxes are comprised primarily of production-based severance and ad valorem taxes associated with properties located onshore and in state waters in the U.S. Second quarter 2006 taxes totaled $43 million compared to $34 million in 2005. Taxes for the first six months of 2006 totaled $74 million, an increase of $10 million compared with 2005. The increase for both periods is primarily due to a new “special profits tax” applicable to petroleum revenues in China when oil prices exceed $40 per barrel. This new levy was announced by China’s Ministry of Finance in March 2006 effective with April revenues and contributed $11 million to the company’s second quarter 2006 expense. Domestically, taxes decreased due to lower ad valorem tax rates for our Colorado properties and severance tax credits realized in 2006, partially offset by the effect of higher commodity prices during the six-month period.

General and Administrative Expense - Second quarter 2006 general and administrative expense was $60 million, $2 million lower than 2005. General and administrative expense of $134 million for the first six months of 2006 was $19 million higher than 2005. Both 2005 periods included $8 million for professional services in connection with the company’s consideration of strategic alternatives. This decrease in professional services costs in 2006 was offset by higher stock-based compensation cost of $8 million and $23 million for the three and six months ended June 30, 2006, respectively.

Merger-related Costs - During the second quarter of 2006, we incurred $8 million of advisory, legal and regulatory compliance costs in connection with the proposed merger with Anadarko. Additionally, the company is party to certain agreements that require us to pay $35 million of additional financial advisory fees upon completion of the merger.

Exploration Expense - The following table presents components of exploration expense for the three and six months ended June 30, 2006 and 2005:

		Three Months Ended						Six Months Ended
		June 30,						June 30,
(Millions of dollars)		2006			2005			2006			2005
Exploration costs (1)		$	17		$	16		$	31		$	27
Geological and geophysical costs			20			14			32			29
Dry hole expense			58			71			73			86
Amortization of undeveloped leases			11			15			22			30
Sales of unproved properties			-			-			-			(1	)
Total exploration expense		$	106		$	116		$	158		$	171

(1)	Exploration costs include delay rentals, cost of retaining and carrying unproved properties and exploration department overhead.

In the second quarter of 2006, total exploration expense was $106 million, a decrease of $10 million compared to 2005. Contributing to the decrease was $4 million lower amortization of undeveloped leases, due in part to the pending sale of Gulf of Mexico shelf properties and lower amortization expense associated with deepwater Gulf of Mexico leases. Dry hole expense for the second quarter 2006 was $13 million lower than 2005 as a result of lower dry hole costs in China, Alaska, Gulf of Mexico shelf and the Southern region, partially offset by higher expense in Brazil. These exploration expense declines were partially offset by a $6 million increase in geological and geophysical costs primarily in the Southern region and an increase in exploration overhead in 2006 related to stock-based compensation ($2 million).

For the first six months of 2006, total exploration expense was $158 million. The decrease of $13 million from 2005 was primarily due to lower amortization of undeveloped leases and dry hole expense. Dry hole expense for the period was $13 million lower than 2005 as a result of lower dry hole costs in Alaska, Gulf of Mexico and the Southern region, partially offset by higher expense in Brazil. Amortization of undeveloped leases totaled $22 million for the first six months period of 2006, an $8 million decrease from 2005 due to the pending sale of Gulf of Mexico shelf properties and reduced amortization expense associated with deepwater Gulf of Mexico leases. These exploration expense declines were partially offset by a $3 million increase in geological and geophysical costs and an increase in 2006 exploration overhead related to stock-based compensation costs ($5 million).

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Capitalized exploratory well costs associated with ongoing exploration and/or appraisal activities may be charged to earnings in a future period if management determines that commercial quantities of hydrocarbons have not been discovered or that future appraisal drilling or development activities are not likely to occur. At June 30, 2006, the company had capitalized costs of approximately $234 million associated with ongoing exploration activities, primarily in the deepwater Gulf of Mexico, Alaska and Brazil ($41 million of which is associated with Gulf of Mexico shelf properties to be sold to W&T).

Gas Gathering, Processing and Other Expenses - Gas gathering, gas processing and other expenses increased by $1 million in the second quarter of 2006 compared to 2005. For the first six months of 2006, gas gathering, gas processing and other expenses totaled $61 million, a $7 million increase over 2005. The increase in both periods was primarily due to higher gas processing costs associated with the company’s nonoperated ownership interest in a Wattenberg field gas plant.

Depreciation, Depletion and Amortization (DD&A) - DD&A expense associated with continuing operations for the three and six months ended June 30, 2006 and 2005 is summarized below:

		Three Months Ended						Six Months Ended
		June 30,						June 30,
(Millions of dollars)		2006			2005			2006			2005
Oil and gas properties		$	183		$	209		$	362		$	422
Other property, plant and equipment (1)			11			11			21			21
Total		$	194		$	220		$	383		$	443
DD&A rate per boe - oil and gas properties		$	7.11		$	8.05		$	7.36		$	8.14

(1)	Represents depreciation of the company’s gas gathering and pipeline assets, primarily in Colorado and Utah, as well as general corporate equipment and facilities.

Units-of-production DD&A expense associated with oil and gas properties of $183 million for the second quarter of 2006 decreased $26 million from 2005, primarily due to ceasing expense recognition on properties held for sale in the Gulf of Mexico shelf in January 2006 ($45 million). Also contributing to the decrease was the divestiture of certain Southern region properties late in 2005 ($6 million). These decreases were partially offset by higher DD&A expense in the Rocky Mountains primarily driven by higher production in the Natural Buttes field ($11 million) and new production from the Constitution and Ticonderoga fields in the Gulf of Mexico ($14 million). Excluding production associated with held-for-sale properties, second-quarter 2006 DD&A rates would have been approximately $7.92 per boe.

Units-of-production DD&A expense for the first six months of 2006 was $362 million, a $60 million decrease from 2005. Contributing to the decrease was discontinued expense recognition on properties held for sale in the Gulf of Mexico shelf ($82 million), lower expense in the Southern region due to 2005 property divestments ($9 million), and lower China expense ($3 million). These decreases were partially offset by higher DD&A expense in the Rocky Mountain area, driven by higher production in the Natural Buttes field ($19 million) and new production from the Constitution and Ticonderoga fields ($17 million). Excluding production associated with held-for-sale properties, DD&A rates for the six months ended June 30, 2006 would have been approximately $8.15 per boe.

Accretion Expense - Accretion expense associated with our abandonment obligations totaled $4 million and $7 million in the second quarter and first six months of 2006, respectively, compared to $5 million and $11 million in the same 2005 periods. The decrease in both periods is primarily attributable to Gulf of Mexico shelf properties held for sale since January 2006 with no further accretion expense being recognized.

Asset Impairments and Gain (Loss) on Sales of Assets - Kerr-McGee records impairment losses when performance analysis and other factors indicate that expected future net cash flows from an oil and gas property will not be sufficient to recover its carrying amount. In general terms, such write-downs most often occur on mature properties that are nearing the end of their productive lives or cease production sooner than anticipated. The company did not incur any impairment losses in the first six months of 2006. Asset impairment losses recorded in the first six months of 2005 totaled $4 million. These impairment losses related primarily to two U.S. Gulf of Mexico shelf properties that ceased production in the first quarter of 2005.

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In the first half of 2005, we recognized a net gain on sales of assets of $47 million, related primarily to two transactions. In the first quarter of 2005, we acquired a 37.5% interest in the Blind Faith discovery in the deepwater Gulf of Mexico from BP Exploration & Production in exchange for our interests in various proved oil and gas properties in the Arkoma basin of southeast Oklahoma. In connection with this transaction, we received $24 million in cash and recognized a $19 million gain on sale based on the percentage of the Arkoma properties' fair value that was received in cash. In the second quarter of 2005, the company sold its interests in oil and gas properties in the Table Mountain and Culp Draw fields of Wyoming to Anadarko in exchange for its overriding royalty interests in the Greater Natural Buttes field and $27 million in cash. The company recognized a gain of $25 million in connection with this transaction.

Interest Expense and Loss on Early Repayment and Modification of Debt - The following table presents information regarding pretax interest expense for the three- and six-month periods ended June 30, 2006 and 2005:

		Three Months Ended						Six Months Ended
		June 30						June 30
(Millions of dollars)		2006			2005			2006			2005
Interest expense reported in:
Income from continuing operations		$	49		$	58		$	90		$	118
Income from discontinued operations (1)			-			24			-			24
Total		$	49		$	82		$	90		$	142

⁽¹⁾ Under the company’s $5.25 billion secured credit agreement which was in effect from May 2005 through January 9, 2006, the company was required to use 100% of the net after-tax cash proceeds from disposition of certain assets to repay debt. Because the North Sea oil and gas and Tronox assets were subject to this requirement, interest expense on debt that was required to be repaid upon the sale of the North Sea business and the Tronox IPO ($19 million and $5 million, respectively) is classified as a component of income from discontinued operations for the three and six months ended June 30, 2005 ($15 million on an after-tax basis).

Total interest expense for the three and six months ended June 30, 2006 was lower compared to the corresponding 2005 periods largely as a result of lower average outstanding debt. During the second half of 2005, we repaid $4.25 billion borrowed in connection with the May 2005 tender offer. Additionally, since June 30, 2005, we redeemed or repaid at maturity other debt with the face value of $359 million (including the 7% debentures discussed below).

In February 2006, the company redeemed its 7% debentures due 2011 with a face value of $250 million using cash on hand. In connection with the early redemption, a pretax loss of $69 million was recognized, representing a write-off of unamortized discount on the debentures. In addition, in connection with the termination of our $1.25 billion five-year secured revolving credit facility in January 2006, $12 million of unamortized debt issuance costs were written off.

Provision for Income Taxes - Higher income tax expense for the three and six months ended June 30, 2006 compared to the corresponding 2005 periods is primarily the result of higher pretax income from continuing operations. Effective income tax rates associated with income from continuing operations for each of the periods presented were in the range of 35% to 37%.

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Tronox Separation

As discussed under Overview and Recent Developments, on March 30, 2006, Kerr-McGee completed the Distribution of its remaining 57% equity interest in Tronox, which resulted in holders of Kerr-McGee common stock as of March 20, 2006 receiving a dividend of .20164 of a share of Tronox Class B common stock for each share of Kerr-McGee common stock they owned (on a pre-split basis). Stockholders entitled to fractional shares of Tronox Class B common stock received cash in lieu of fractional shares.

Under the terms of the Master Separation Agreement entered into between Kerr-McGee and Tronox in connection with the initial public offering, Kerr-McGee agreed to reimburse Tronox for 50% of certain qualifying environmental remediation costs incurred and paid by Tronox and its subsidiaries before November 28, 2012, subject to certain limitations and conditions. The seven-year reimbursement obligation is limited to a maximum aggregate reimbursement of $100 million. In connection with the Distribution, Kerr-McGee recognized a fair-value-based liability of $56 million associated with this reimbursement obligation, with the associated charge reflected as a component of loss from discontinued operations. Management does not expect this guarantee to result in material cash expenditures in the near term.

Financial Condition and Liquidity

The following table provides certain information useful in the analysis of the company's financial condition:

		June 30,			December 31,
(Millions of dollars)		2006			2005
Current ratio (1)			0.6 to 1			0.8 to 1
Cash and cash equivalents		$	156		$	1,053
Debt repayment obligations due within one year (2)			306			306
Unused capacity under revolving lines of credit (3)			1,193			1,184
Total debt, including $550 million of Tronox debt at December 31, 2005			2,406			3,133
Stockholders’ equity and minority interest (4)		$	4,616		$	4,327
Debt to total capitalization (4)			34	%		42	%

(1)	Represents a ratio of current assets to current liabilities.

 

(2)	Represents principal amount of Kerr-McGee debt maturing within one year from the respective balance sheet date.

 

(3)	Reflects partial utilization to support outstanding letters of credit. No revolving borrowings were outstanding at December 31, 2005 or June 30, 2006. The $1.25 billion unsecured revolving credit facility currently in effect terminates in January 2011.

 

(4)	Capitalization is determined as total debt plus total stockholders’ equity and, as of December 31, 2005, minority stockholders’ interest in net assets of Tronox of $212 million.

 

Sources of Liquidity - Our liquidity is derived from both internal and external sources. During the first six months of 2006, we satisfied our liquidity needs primarily with cash on hand, net cash provided by operating activities and borrowings under our $1.25 billion revolving credit facility (none of which were outstanding at quarter-end). In the short- and long-term, we expect the same sources of liquidity to be available to us. Additionally, the company has a total of $1 billion of debt securities, common or preferred stock, or warrants available to issue or sell under our shelf registration with the U.S. Securities and Exchange Commission (SEC), which was last updated in February 2002.

Based on the company's forecast of cash flows and liquidity, the company believes that it has and will continue to have the financial resources and liquidity to meet future cash requirements. Included in that forecast are expected proceeds from the sale of our Gulf of Mexico shelf oil and gas properties that is expected to close in the third quarter of 2006, yielding net pretax proceeds of approximately $1 billion based on estimates as of July 2006.

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Working Capital Position - As of June 30, 2006, the company had negative working capital of $978 million; however, this is not indicative of a lack of liquidity, as the company maintains sufficient current assets to settle current liabilities when due. Our working capital position is affected by current assets and liabilities associated with our financial derivatives. As of June 30, 2006, the company had recorded $774 million of net current derivative liabilities for contracts that will effectively adjust the cash flows to be realized upon the sale of our future oil and gas production. Because those sales have not yet occurred, the associated accounts receivable are not yet reflected in our Condensed Consolidated Balance Sheet, while derivative assets and liabilities are reflected at their estimated fair values. Because of the high degree of volatility in oil and natural gas commodity markets, our working capital position will be continually affected by changes in the fair value of derivative instruments.

Debt to Total Capitalization - Since December 31, 2005, the percentage of debt to total capitalization decreased from 42% to 34%. Significant 2006 transactions affecting our capital structure and the level of leverage are summarized below. The combined effect of these transactions reduced the debt to total capitalization ratio by 1%, with the remaining decrease attributable primarily to net income and a reduction of unrealized derivative losses in stockholders’ equity.

		Increase (Decrease) in
(Millions of dollars)		Total Debt			Total Equity
Early redemption of $250 million 7% debentures (1)		$	(181	)	$	(45	)
Tronox Distribution (2)			(550	)		(265	)
Repurchases of common stock (3)			-			(356	)

(1)	The decrease in equity represents the after-tax loss on early redemption of the debentures that resulted from writing off unamortized discount of $69 million.

 

(2)	The Distribution reduced retained earnings by $244 million and accumulated other comprehensive income by $21 million.

 

(3)	Represents open-market purchases of Kerr-McGee stock under the $1 billion stock repurchase program.

 

Credit Ratings - In rating the company’s debt, rating agencies consider our financial and operating risk profile by analyzing our debt levels, growth profile, cost structure, oil and gas reserve replacement ratios, capital expenditure requirements, contingencies, dividend policy and any other factors they deem relevant that could potentially impact our ability to service debt. On May 1, 2006, our credit rating was upgraded by Moody’s Investor Services to Ba2. The following table provides a summary of our senior unsecured debt ratings by selected rating agencies.

	December 31, 2005		June 30, 2006
Standard & Poor’s	BB+		BB+
Moody’s Investors Service	Ba3		Ba2

Credit Facilities and Debt Covenants - In January 2006, Kerr-McGee closed on a $1.25 billion unsecured revolving credit agreement. The facility is available to provide support for commercial paper and for general corporate purposes. Interest on amounts borrowed under the credit agreement is payable, at the company’s election, at an alternate base rate (ABR) or a Eurodollar rate, in each case as defined in the credit agreement. The margin applicable to Eurodollar borrowings may vary from 50 to 150 basis points depending on Kerr-McGee’s credit rating. As a result of the May 2006 upgrade discussed above, the margin applicable to Eurodollar borrowings under the company’s revolving credit agreement decreased from 125 basis points to 100 basis points.

The terms of the revolving credit agreement provide for customary representations and warranties, affirmative and negative covenants, and events of default. The company also is required to maintain compliance with the following financial covenants (in each case, as defined in the agreement):

·	Consolidated Leverage Ratio of no more than 3.5:1

·	Consolidated Interest Coverage Ratio over a specified period of at least 3:1

·	Asset Coverage Ratio of more than 1.75:1 so long as the company’s corporate credit rating is below investment grade

The company was in compliance with all applicable covenants to date and expects to maintain compliance in future periods.

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Property Insurance Coverage - Significant claim losses were experienced during 2005 by the insurance industry as a result of hurricane damage sustained in the Gulf of Mexico region. As a result, the amount of insurance capacity available for windstorm perils in Gulf of Mexico and surrounding areas has been significantly reduced during the 2006 windstorm season and is available only at higher premium rates.

While exploration and production industry losses during the 2004 and 2005 windstorm seasons were significant, Kerr-McGee has experienced minimal physical damage to its Gulf of Mexico assets as a result of Hurricanes Ivan, Katrina and Rita, with total net losses after expected insurance reimbursements of approximately $27 million for exploration and production asset physical damage. While Kerr-McGee did not sustain material property damage losses during the 2004 and 2005 windstorm seasons, we do have concentrated property values as well as concentrated production volumes in the Gulf of Mexico. We maintain insurance against certain losses or liabilities at amounts that management believes to be prudent. However, given current insurance market conditions, companies with Gulf of Mexico exposure, including Kerr-McGee, will retain more risk with respect to physical damage and business interruption losses during the 2006 windstorm season than in the prior year.

Cash Flows

The following summarizes selected cash flow information for the first six months of 2006 and 2005. Unless indicated otherwise, discussion of cash flows reflects the company’s continuing and discontinued operations. Cash flows associated with discontinued operations relate to Tronox and our former North Sea oil and gas business that was sold in November 2005.

		Six Months Ended
		June 30,
(Millions of dollars)		2006			2005
Net cash provided by operating activities		$	710		$	1,578
Net cash used in investing activities			(939	)		(841	)
Net cash used in financing activities			(665	)		(488	)

Operating Activities - The $868 million decrease in cash flows from operating activities in the first six months of 2006 compared to 2005 is largely attributable to the North Sea oil and gas business, which contributed approximately $500 million to operating cash flow (before working capital changes) in 2005 and none in 2006. In addition, we paid income taxes of $548 million during the first six months of 2006, an amount that reflects a substantial U.S. taxable gain from the sale of our North Sea business.

 

Investing Activities - Net cash used in investing activities during the first six months of 2006 and 2005 is summarized below:

		Six Months Ended June 30,
(Millions of dollars)		2006			2005
Capital expenditures -
Exploration and development (including dry hole costs) -
Continuing operations		$	(933	)	$	(766	)
Discontinued operations			-			(77	)
Tronox			(22	)		(31	)
Corporate and other			(10	)		(9	)
Total capital expenditures			(965	)		(883	)
Proceeds from sales of assets			11			63
Other investing activities			15			(21	)
Net cash used in investing activities		$	(939	)	$	(841	)

Exploration and development expenditures associated with continuing operations increased by 22% in 2006 to $933 million as compared to 2005. The increase from 2005 is primarily attributable to increased funding for exploitation-type development activity in the U.S. onshore areas, heavily weighted toward accelerated development of the Natural Buttes and Wattenberg fields and increased exploration activity in the deepwater Gulf of Mexico, with several high-cost exploration wells drilled during 2006. This increase was partially offset by reduced exploration spending in Alaska and Brazil in 2006.

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In May 2006, management and the Board approved a $170 million expansion of our 2006 capital program to accelerate drilling activities in the U.S. onshore area and fund infrastructure expansions in the Uinta Basin of eastern Utah.  Approximately $85 million has been allocated for development drilling of our resource plays in the Natural Buttes and Wattenberg fields, with another $50 million dedicated to upgrading our processing and gathering capabilities in the Uinta Basin, in the vicinity of the Natural Buttes field.  The remainder relates to additional drilling activities in South Texas. Our U.S. onshore program expansion is expected to increase near- and long-term production at competitive finding, development and acquisition costs. In addition, $80 million was approved for ongoing exploration and development projects in the deepwater Gulf of Mexico, including appraisal work on the recent discoveries at our Caesar and Claymore prospects.

Other investing cash flows in 2006 includes a $25 million deposit received from W&T in connection with our pending sale of certain Gulf of Mexico shelf properties.

Financing Activities - For the six months ended June 30, 2006 net cash used in financing activities was $665 million, compared to $488 million in 2005. In 2006, we used $250 million to redeem our 7% deep-discount debentures and $356 million for treasury stock repurchases under the $1 billion share repurchase program, sourced with cash on hand and operating cash flows. In 2005, we spent $392 million to repay debt and $4.2 billion on share repurchases; however, the majority of this spending was funded with net proceeds from borrowings of $4.2 billion. The change in our dividend policy effective with the July 2005 dividend payment resulted in $131 million lower cash outflow during the first six months of 2006 compared to 2005. Favorable effects of this change on 2006 financing cash flows were largely offset by $116 million lower proceeds from stock option exercises.

Obligations and Commitments

In the normal course of business, the company enters into purchase obligations, contracts, leases and borrowing arrangements. As part of our project-oriented exploration and production business, we routinely enter into contracts for certain aspects of a project, such as engineering, drilling and subsea work. These contracts are generally not unconditional obligations; thus, the company accrues for the value of work done at any point in time, a portion of which is billed to partners.

In 2006, we entered into additional commitments to assure transportation capacity and drilling rig availability for executing our drilling program. Additionally, in late June 2006, we initiated an employee retention program that provides for cash payments to participating employees if they meet continuing employment and other conditions. The following table summarizes the company’s obligations under these additional commitments:

(Millions of dollars)		Payments due by period
								2007			2009			After
Type of Obligation		Total			2006			-2008			-2010			2010
Transportation capacity		$	360		$	-		$	23		$	47		$	290
Drilling rig commitments			117			6			75			36			-
Employee retention benefits			53			17			36			-			-
		$	530		$	23		$	134		$	83		$	290

Other Obligations and Commitments - The company has commitments to its officers and certain key employees under agreements that provide for continuation of salary, bonuses and specified benefits for varying terms in the event of a qualifying termination of employment (including termination without cause or upon change in control). As of June 30, 2006, the company’s commitment for such benefits approximated $55 million, plus income and excise tax gross-up payments.

Under the merger agreement between Kerr-McGee and Anadarko, the company may be required to pay Anadarko $493 million if the merger agreement is terminated under certain conditions and the company enters into an alternative transaction. Under separate agreements, the company is committed to pay $35 million of financial advisory fees upon completion of the merger.

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New/Revised Accounting Standards

Effective January 1, 2006, we adopted the fair-value recognition provisions of Statement of Financial Accounting Standards No. 123 (Revised 2004), "Share-Based Payment" (FAS No. 123(R)). In the six months ended June 30, 2006, we recognized stock-based compensation expense associated with continuing operations of $62 million, $16 million higher than we would have recognized had the standard not been adopted. We expect that reported stock-based compensation cost in future periods will continue to be higher than in comparable historical periods. Additional information regarding our adoption of FAS No. 123(R) and stock-based compensation expense recognized in 2006 is provided in Notes 1 and 9 to the Condensed Consolidated Financial Statements included in Part I of this Quarterly Report on Form 10-Q.

New Accounting Pronouncements - In July 2006, the Financial Accounting Standards Board (FASB) issued FASB Interpretation (FIN) No. 48, Accounting for Uncertainty in Income Taxes - An Interpretation of FASB Statement No. 109 (FIN 48). FIN 48 prescribes how a company should recognize, measure, present and disclose in its financial statements uncertain tax positions the company has taken or expects to take on a tax return. The provisions of FIN 48 are effective beginning in 2007 and will apply to all tax positions upon initial adoption. The company is currently evaluating the possible financial statement effects of adopting this new standard.

Item 3.

Quantitative and Qualitative Disclosures about Market Risk.

The company is exposed to a variety of market risks, including credit risk, changes in oil and gas commodity prices, foreign currency exchange rates and interest rates. We address these risks through a controlled program of risk management that includes the use of insurance and derivative financial instruments. In addition to information included in this section, see Note 5 to the condensed consolidated financial statements included in Item 1, Part I of this Quarterly Report on Form 10-Q for a discussion of the company’s derivatives and hedging activities.

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Commodity Price Risk

The company is exposed to market risk due to changes in crude oil and natural gas prices. To increase the predictability of cash flows and support capital expenditure plans, Kerr-McGee periodically enters into financial derivative instruments that generally fix the commodity prices to be received for a portion of the company’s oil and gas production in the future. At June 30, 2006, the following commodity-related derivatives were outstanding:

		July - December 2006						2007
		Average Contract Price ($/Barrel)			Average Daily Volume (Barrels)			Average Contract Price ($/Barrel)			Average Daily Volume (Barrels)
Crude Oil (WTI) -
Fixed price swaps		$	53.13			20,345		$	51.44			27,250
Costless collars		$	27.00 - $30.58			19,000	(a)		-			-
		$	45.00 - $65.81			22,000		$	45.00 - $61.42			18,000
Three-way collars		$	25.00 - $28.65			2,000	(b)		-			-
Three-way average floor		$	20.88
						63,345						45,250

		($/MMBtu)			(MMBtu)			($/MMBtu)			(MMBtu)
Natural Gas (NYMEX) -
Fixed price swaps		$	7.54			196,000		$	7.03			265,000
Costless collars		$	4.75 - $ 5.50			340,000	(a)		-			-
		$	6.00 - $10.80			197,000		$	6.00 - $9.03			265,000
Three-way collars		$	4.00 - $ 6.00			20,000	(b)		-			-
Three-way average floor		$	3.04
						753,000						530,000
Basis Swaps vs. NYMEX -
CIG (1)		$	1.51			178,451		$	1.33			67,808
NWPL (2)		$	1.46			145,109		$	1.30			53,247
						323,560						121,055

(a)	Placed by Kerr-McGee in connection with the Westport Resources merger in June 2004.

(b)	Acquired in the Westport merger.

 

(1)	Colorado Interstate Gas pipeline index.

(2)	Northwest Pipeline Rocky Mountain index.

The fair value of the company’s oil and gas commodity derivative instruments is determined based on prices actively quoted, generally NYMEX prices.

Effective March 1, 2006, we elected to discontinue hedge accounting for our crude oil and natural gas derivatives. Refer to discussion under Results of Operations - Revenues - Gains (Losses) Associated with Commodity Derivatives for additional information about this change in the company's accounting policy.

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Item 4.

Controls and Procedures.

As of the end of the period covered by this report, an evaluation was carried out under the supervision and with the participation of the company's management, including its Chief Executive Officer and Chief Financial Officer, of the effectiveness of the company's disclosure controls and procedures pursuant to Exchange Act Rule 13a-15. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the company's disclosure controls and procedures are effective in alerting them in a timely manner to material information relating to the company (including its consolidated subsidiaries) required to be included in the company's periodic SEC filings. There was no change in the company's internal control over financial reporting that occurred during the second quarter of 2006 that has materially affected or is reasonably likely to materially affect the company's internal control over financial reporting.

Forward-Looking Information

Statements in this quarterly report regarding the company's or management's intentions, beliefs or expectations, or that otherwise speak to future events, are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Future results and developments discussed in these statements may be affected by numerous factors and risks, such as the accuracy of the assumptions that underlie the statements, the divestiture of certain oil and gas properties, the success of the oil and gas exploration and production program, drilling risks, the market value of Kerr-McGee's products, uncertainties in interpreting engineering data, the financial resources of competitors, changes in laws and regulations, the ability to respond to challenges in international markets, including changes in currency exchange rates, political or economic conditions, trade and regulatory matters, general economic conditions, progress made with respect to, and developments related to, the company’s proposed merger with Anadarko, and other factors and risks identified in the Risk Factors section of the company's latest Annual Report on Form 10-K, Part II, Item 1A of this Quarterly Report on Form 10-Q and other SEC filings. Actual results and developments may differ materially from those expressed in this quarterly report.

PART II - OTHER INFORMATION

Item 1. Legal Proceedings

A.

Kerr-McGee Oil and Gas Onshore LP (KM Onshore), an affiliate of the company, received notices of violation (NOVs) from the Colorado Department of Public Health and Environment (CDPHE) on June 21, 2005, and November 4, 2005.  The NOVs allege that, with respect to certain production operations in Colorado, the affiliate exceeded allowable air emissions under the Clean Air Act.  KM Onshore recently was informed that the CDPHE intends to address these matters collectively, including any related penalties, which could result in penalties in excess of $100,000.  However, no formal demand has been made of KM Onshore.  The affiliate intends to vigorously defend against the NOVs.  The affiliate and the state and federal agencies are currently discussing the allegations and possible resolutions.

 

B.

On November 14, 2005, the company received a letter from the United States Department of Justice (DOJ) alleging that the company violated certain air quality and permitting regulations at the Cottonwood and Ouray compressor stations in Uintah County, Utah, which were operated by Westport Oil and Gas Company, L.P. prior to Westport’s merger with Kerr-McGee. No formal demand has been made by the DOJ. Later DOJ alleged that certain air quality regulations were also violated at the Bridge compressor station. The affiliate and the state and federal agencies currently are discussing the allegations and possible resolutions.

 

C.

On June 26, 2006, a petition was filed in the District Court of Oklahoma County, Oklahoma styled John Rinderknecht, On Behalf of Himself and All Others Similarly Situated v. Kerr-McGee Corp., Luke R. Corbett, Sylvia A. Earle, Martin C. Jischke, Leroy C. Richie, William E. Bradford, David C. Genever-Watling, Farah M. Walters, Robert O. Lorenz, Michael Portillo, William F. Wallace and Ian L. White-Thomson. On July 25, 2006, another petition was filed in the District Court of Oklahoma County, Oklahoma styled Marilyn Clark, On Behalf of Herself and All Others Similarly Situated v. Kerr-McGee Corp., Luke R. Corbett, Sylvia A. Earle, Martin C. Jischke, Leroy C. Richie, William E. Bradford, David C. Genever-Watling, Farah M. Walters, Robert O. Lorenz, Michael Portillo, William F. Wallace and Ian L. White-Thomson. The plaintiffs in both actions allege that they are shareholders of the company, and they each purport to sue on behalf of a class of other company shareholders. Both petitions allege that the company and its directors engaged in self-dealing and breached fiduciary duties owed to the company’s shareholders in connection with the merger agreement with Anadarko Petroleum Corporation. Among other things, the petitions seek to enjoin and prevent the parties from completing the merger until the company adopts and implements a procedure to obtain the highest possible price for the company shareholders. On July 28, 2006, the company entered into an agreement in principle to settle the lawsuits by agreeing to make certain additional disclosures in a Form 8-K filing, to seek the certification of a class, and, subject to court approval, to paying class counsel fees and expenses of $825,000.

 

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D.	For a discussion of other legal proceedings and contingencies, reference is made to Note 13 to the Condensed Consolidated Financial Statements included in Part 1, Item 1 of this Quarterly Report on Form 10-Q, which is incorporated herein by reference.

Item 1A. Risk Factors

In addition to those risk factors previously described in the company’s Form 10-K for the year ended December 31, 2005, and the company’s other filings with the SEC, investors should carefully consider the following risks:

Business Uncertainties and Contractual Restrictions While Merger is Pending. Uncertainty about the effect of the proposed merger with Anadarko Petroleum Corporation on employees, suppliers and partners may have an adverse effect on the company. These uncertainties may impair the company’s ability to attract, retain and motivate key personnel until the merger is consummated, and could cause persons that deal with the company to defer decisions concerning the company, or seek to change existing business relationships with the company. Employee retention may be particularly challenging while the merger is pending, as employees may experience uncertainty about their future employment. In addition, the merger agreement restricts the company from making certain acquisitions and taking other specified actions without Anadarko’s approval. These restrictions could prevent the company from pursuing attractive business opportunities that may arise prior to the completion of the merger.

Failure to Complete Merger Could Negatively Impact Stock Price, Future Business and Financial Results. Although the Board of Directors has recommended that the company’s stockholders approve and adopt the merger agreement, there is no assurance that the merger agreement and the merger will be approved, and there is no assurance that other conditions to the completion of the merger will be satisfied. If the merger is not completed, the company will be subject to several risks, including the following:

·	The company may be required to pay a termination fee of $493 million if the merger agreement is terminated under certain circumstances and the company enters into an alternative transaction;

 

·	The current market price of the company’s common stock may reflect a market assumption that the merger will occur, and a failure to complete the merger could result in a decline in the market price of the company’s common stock;

 

·	Certain costs relating to the merger (such as legal and financial advisory fees) are payable by the company whether or not the merger is completed;

 

·

There may be substantial disruption to the business of the company and a distraction of its management and employees from day-to-day operations, because matters related to the merger (including integration planning) may require substantial commitments of time and resources, which could otherwise have been devoted to other opportunities that could have been beneficial to the company;

 

·	The company’s business could be adversely affected if it is unable to retain key employees or attract qualified replacements; and

 

·	The company would continue to face the risks that it currently faces as an independent company.

 

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Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

Issuer Purchases Of Equity Securities

The following table summarizes the company’s repurchases of equity securities registered under Section 12 of the Securities Exchange Act of 1934 that occurred during the quarter ended June 30, 2006. The share and per-share information provided in the table below does not give effect to the two-for-one stock split in June 2006.

Period		Total Number of Shares Purchased (a)			Average Price Paid per Share (a)			Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (b)			Maximum Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (b)
April 1-30, 2006			5,000		$	74.09			-
May 1-31, 2006			66,780			99.64			54,000		$	644,000,000
June 1-30, 2006			4,075			64.57			-
Total			75,855		$	96.07			54,000

(a)    Includes 5,700 shares purchased in the open market for the matching contributions to the Kerr-McGee Corporation Savings Investment Plan, 16,155 shares delivered to the company by employees in satisfaction of withholding taxes and upon forfeiture of restricted shares, and 54,000 shares purchased in connection with the $1 billion stock repurchase program discussed below.

 

(b)    Represents repurchase activity under the $1 billion repurchase program approved by our Board of Directors on January 10, 2006.

Item 4. Submission of Matters to a Vote of Security Holders.

The 2006 annual meeting of stockholders was held on May 9, 2006. The following matters were voted upon at the meeting:

(1)	Stockholders ratified the appointment of Ernst & Young LLP as the company’s independent auditors for 2006. There were 99,578,208 votes for the proposal; 333,909 votes against the proposal; and 1,090,324 abstentions.

(2)	Stockholders did not approve a stockholder proposal to establish an Office of the Board of Directors. There were 4,916,212 votes for the proposal; 73,574,075 votes against the proposal; and 6,025,995 abstentions.

(3)	The following directors were elected with the following vote totals.

		Votes		Votes
		In Favor		Withheld
Silvia A. Earle		99,080,208		1,922,233
Martin C. Jischke		97,729,280		3,273,161
Leroy C. Richie		99,083,955		1,918,486

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Item 6. Exhibits.

	Exhibit No.
	2.1	Agreement and Plan of Merger among the company, Anadarko Petroleum Corporation and APC Acquisition Sub, Inc., filed as Exhibit 2.1 to Current Report on Form 8-K dated June 26, 2006, and incorporated herein by reference.
	4.1	Second Amendment to Rights Agreement, dated as of June 23, 2006, by and between the company and UMB Bank, N.A., filed as Exhibit 4.3 to Amendment No. 2 to Form 8-A dated June 26, 2006, and incorporated herein by reference.
	10.1	Amended Continuity Agreement, dated May 22, 2006, between the company and Luke R. Corbett, filed as Exhibit 10.1 to Current Report on Form 8-K dated May 22, 2006, and incorporated herein by reference.
	10.2	Amended Continuity Agreement, dated May 22, 2006, between the company and Kenneth W. Crouch, filed as Exhibit 10.2 to Current Report on Form 8-K dated May 22, 2006, and incorporated herein by reference.
	10.3	Amended Continuity Agreement, dated May 22, 2006, between the company and David A. Hager, filed as Exhibit 10.3 to Current Report on Form 8-K dated May 22, 2006, and incorporated herein by reference.
	10.4	Amended Continuity Agreement, dated May 22, 2006, between the company and Gregory F. Pilcher, filed as Exhibit 10.4 to Current Report on Form 8-K dated May 22, 2006, and incorporated herein by reference.
	10.5	Amended Continuity Agreement, dated May 22, 2006, between the company and Robert M. Wohleber, filed as Exhibit 10.5 to Current Report on Form 8-K dated May 22, 2006, and incorporated herein by reference.
	10.6	Amended and Restated Continuity Agreement, dated as of June 22, 2006, between the company and Luke R. Corbett, filed as Exhibit 10.1 to Current Report on Form 8-K dated June 26, 2006, and incorporated herein by reference.
	31.1	Certification pursuant to Securities Exchange Act Rule 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	31.2	Certification pursuant to Securities Exchange Act Rule 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	32.1	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
	32.2	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

KERR-McGEE CORPORATION

Date: August 4, 2006	By:	/s/ John M. Rauh
		John M. Rauh
		Vice President and Controller
		and Chief Accounting Officer

 

 

 

 

 

 

 

 

 

 

 

 

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