Hess - 10-Q quarterly report FY

     The financial statements included in this report reflect all normal and recurring adjustments which, in the opinion of management, are necessary for a fair presentation of Hess Corporation’s (the Corporation) consolidated financial position at September 30, 2009 and December 31, 2008 and the consolidated results of operations for the three and nine month periods ended September 30, 2009 and 2008 and the consolidated cash flows for the nine month periods ended September 30, 2009 and 2008. The unaudited results of operations for the interim periods reported are not necessarily indicative of results to be expected for the full year.

     The financial statements were prepared in accordance with the requirements of the Securities and Exchange Commission (SEC) for interim reporting. As permitted under those rules, certain notes or other financial information that are normally required by U.S. generally accepted accounting principles (GAAP) have been condensed or omitted from these interim financial statements. These statements, therefore, should be read in conjunction with the consolidated financial statements and related notes included in the Corporation’s Form 10-K for the year ended December 31, 2008.

     The Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) became effective on July 1, 2009. The ASC combined multiple sources of authoritative accounting literature into a single source of authoritative GAAP organized by accounting topic. Since the ASC was not intended to change existing GAAP, the only impact on the Corporation’s financial statements was that specific references to accounting principles have been changed to refer to the ASC.

     Effective January 1, 2009, the Corporation adopted the FASB accounting standard for the accounting for and reporting of noncontrolling interests in a consolidated subsidiary (ASC 810 – Consolidation). As required, the Corporation retrospectively applied the presentation and disclosure requirements of this standard. At September 30, 2009 and December 31, 2008 noncontrolling interests of $133 million and $84 million, respectively, have been classified as a component of equity. Previously the noncontrolling interests had been classified in Other liabilities. Net income (loss) attributable to the noncontrolling interests is also now separately reported in the Statement of Consolidated Income. Certain other amounts in the consolidated financial statements and footnotes have been reclassified to conform with the presentation requirements of this standard.

     Effective January 1, 2009, the Corporation adopted the FASB accounting standard that expanded the qualitative, quantitative and credit risk disclosure requirements related to an entity’s use of derivative instruments (ASC 815 – Derivatives and Hedging). See Note 8, Derivative Instruments, Hedging, and Trading Activities, for these disclosures.

     Effective January 1, 2009, the Corporation also adopted the FASB staff position that requires the application of the fair value measurement and disclosure provisions to nonfinancial assets and liabilities that are measured at fair value on a nonrecurring basis (ASC 820 – Fair Value Measurements). Such fair value measurements are determined based on the same fair value hierarchy of inputs currently required to measure the fair value of financial assets and liabilities. The impact of this accounting standard was not material to the Corporation’s consolidated financial statements.

     Effective June 30, 2009, the Corporation adopted the FASB accounting standard which provides guidance on the accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued (ASC 855 – Subsequent Events). The adoption of this standard did not impact the Corporation’s existing practice of evaluating subsequent events through the date the financial statements are filed with the SEC. The Corporation evaluated subsequent events through November 6, 2009.

     In June 2009, the FASB amended existing accounting standards to eliminate the concept of a qualifying special-purpose entity (ASC 810 – Consolidation) and limit the circumstances in which transferred financial assets should be derecognized (ASC 860 – Transfers and Servicing). The amended standards also require additional analysis of variable interest entities, which are generally defined as entities in which equity investors do not have the characteristics of a controlling interest or do not have sufficient equity at risk to finance its activities without additional subordinated financial support. These standards also change the criteria for determining the primary beneficiary of a variable interest entity, which is the entity responsible for consolidation. As required, the Corporation will adopt the provisions of these standards effective January 1, 2010. The adoption of these standards is not expected to have a material impact on the Corporation’s financial statements.

     Inventories consist of the following (in millions):

     The Corporation accounts for its investment in HOVENSA L.L.C. (HOVENSA) using the equity method. Summarized financial information for HOVENSA follows (in millions):

     The following table discloses the net changes in capitalized exploratory well costs pending determination of proved reserves for the nine months ended September 30, 2009 (in millions):

     The preceding table excludes costs related to exploratory dry holes of $158 million which were incurred and subsequently expensed in 2009. Capitalized exploratory well costs greater than one year old after completion of drilling were $919 million as of September 30, 2009 and $381 million as of December 31, 2008. This increase is primarily related to the Pony and Tubular Bells projects in the deepwater Gulf of Mexico and offshore projects in Western Australia (WA-Block 390-P) and Libya (Area 54). Development options for Pony and Tubular Bells are being evaluated. Further drilling is scheduled on WA-Block 390 and in Area 54.

     In February 2009, the Corporation issued $250 million of 5 year senior unsecured notes with a coupon of 7% and $1 billion of 10 year senior unsecured notes with a coupon of 8.125%. The majority of the proceeds were used to repay revolving credit debt and outstanding borrowings on other credit facilities.

     In July 2009, the Corporation amended its asset backed credit facility to increase the capacity from $500 million to $1 billion, subject to the availability of sufficient levels of eligible receivables from certain Marketing and Refining operations pledged as collateral. In addition, the expiration date has been extended to July 2010.

     During the third quarter of 2009, the Corporation assumed approximately $65 million of private placement debt in conjunction with the acquisition of 37 previously leased retail gasoline stations.

     Foreign currency gains (losses) amounted to the following (in millions):

     The pre-tax amount of foreign currency gains (losses) is reported in Other, net within the Statement of Consolidated Income.

     Components of net periodic pension cost consisted of the following (in millions):

     In 2009, the Corporation expects to contribute approximately $135 million to its pension plans and had contributed $111 million through September 30, 2009.

     The Corporation utilizes derivative instruments for both non-trading and trading activities. In non-trading activities, the Corporation uses futures, forwards, options and swaps individually or in combination, to mitigate its exposure to fluctuations in prices of crude oil, natural gas, refined products and electricity, and changes in foreign currency exchange rates. In trading activities, the Corporation, principally through a consolidated partnership (in which the Corporation has a 50% voting interest), trades energy commodities and energy derivatives, including futures, forwards, options and swaps, based on expectations of future market conditions. The following information includes 100% of the trading partnership’s accounts.

     The Corporation maintains a control environment under the direction of its chief risk officer and through its corporate risk policy, which the Corporation’s senior management has approved. Controls include volumetric, term and value-at-risk limits. Risk limits are monitored daily and exceptions are reported to business units and to senior management. The Corporation’s risk management department also performs independent verifications of sources of fair values and validations of valuation models. These controls apply to all of the Corporation’s non-trading and trading activities, including the consolidated trading partnership.

     The table below shows the gross volume of the Corporation’s trading and non-trading derivative instruments outstanding at September 30, 2009:

     The Corporation records all derivative instruments on the balance sheet at fair value (see Note 9, Fair Value Measurements). The table below reflects the gross and net fair values of the Corporation’s derivative instruments as of September 30, 2009 (in millions):

     The Corporation generally enters into master netting arrangements to mitigate counterparty credit risk. Master netting arrangements are standardized contracts that govern all specified transactions with the same counterparty and allow the Corporation to terminate all contracts upon occurrence of certain events, such as a counterparty’s default or bankruptcy. Where these arrangements provide the right of offset and the Corporation’s intent and practice is to offset amounts in the case of contract terminations, the Corporation records fair value on a net basis.

     Cash Flow Hedges: The Corporation uses commodity contracts to hedge variability of expected future cash flows and forecasted transactions (cash flow hedges). At September 30, 2009, the Corporation used cash flow hedges principally to fix the cost of supply in its energy marketing business. The Corporation records the effective portion of changes in the fair value of cash flow hedges as a component of other comprehensive income. Amounts recorded in Accumulated other comprehensive income are reclassified into Cost of products sold in the same period that the hedged item is recognized in earnings. The ineffective portion of changes in the fair value of cash flow hedges is recognized immediately in Cost of products sold. The length of time over which the Corporation hedges exposure to variability in future cash flows is predominantly two years or less. The maximum duration was five years for the contracts outstanding at September 30, 2009.

     The Corporation may use futures and swaps to hedge crude oil and natural gas production in its Exploration and Production business. In October 2008, the Corporation closed its Brent crude oil cash flow hedges, covering 24,000 barrels per day from 2009 through 2012, by entering into offsetting contracts with the same counterparty. As a result, the Corporation no longer accounts for these contracts as cash flow hedges. Because the underlying cash flows from the originally hedged production are still probable, the deferred losses within Accumulated other comprehensive income as of the date the contracts were closed will be recorded in Sales and other operating revenues as the contracts mature. There were no open hedges of crude oil or natural gas production at September 30, 2009.

     At September 30, 2009, the after-tax deferred losses reported in Accumulated other comprehensive income relating to cash flow hedges were $1,433 million. The Corporation estimates that approximately $606 million of this amount will be reclassified into earnings over the next twelve months.

     Other Risk Management Derivatives: The Corporation mitigates certain risks in its energy marketing business using commodity contracts that it does not designate as hedges. Changes in the fair value of the commodity contracts, which include forward purchases and sales of energy marketing products, are recognized currently in earnings. Revenues from the sales contracts are reported within Sales and other operating revenues and supply contract purchases are reported within Cost of products sold. The Corporation also uses foreign exchange contracts that it does not designate as hedges with the intent to reduce its exposure to fluctuations in foreign exchange rates. Net pre-tax gains on these derivative contracts amounted to the following (in millions):

     In trading activities, the Corporation is primarily exposed to changes in crude oil, natural gas, and refined product prices. Pre-tax gains (losses) from trading activities, reported in Sales and other operating revenues, amounted to the following (in millions):

     The Corporation is exposed to credit risks that may at times be concentrated with certain counterparties or groups of counterparties. Accounts receivable are generated from a diverse domestic and international customer base. The Corporation reduces its risk related to certain counterparties by using master netting arrangements and, in certain circumstances, requiring collateral, generally cash or letters of credit. The Corporation records the cash collateral received or posted as an offset of the fair value of derivatives executed with the same counterparty.

     At September 30, 2009, the Corporation had a total of $3,676 million of outstanding letters of credit, primarily issued to satisfy margin and collateral requirements. Certain of the Corporation’s agreements also contain contingent collateral provisions that could require the Corporation to post additional collateral if the Corporation’s credit rating declines. As of September 30, 2009, the net liability related to derivatives with contingent collateral provisions was approximately $2,642 million before cash collateral posted of approximately $323 million. At September 30, 2009, all three major credit rating agencies that rate the Corporation’s debt had assigned an investment grade rating. If two of the three agencies were to downgrade the Corporation’s rating to below investment grade as of September 30, 2009, the Corporation would be required to post additional collateral of approximately $265 million.

     The Corporation determines fair value in accordance with the FASB fair value measurements accounting standard (ASC 820 – Fair Value Measurements), which established a hierarchy that categorizes the sources of inputs, which generally range from quoted prices for identical instruments in a principal trading market (Level 1) to estimates determined using related market data (Level 3). Multiple inputs may be used to measure fair value, however, the level of fair value for each financial asset or liability presented below is based on the lowest significant input level within this fair value hierarchy. The following table provides the fair value of the Corporation’s financial assets and (liabilities) based on this hierarchy (in millions):

     The carrying amount of the Corporation’s financial instruments generally approximate their fair values at September 30, 2009 except fixed rate long term debt, which had a carrying value of $4,379 million and a fair value of $4,999 million.

     The weighted average numbers of common shares used in the basic and diluted earnings per share computations are as follows (in thousands):

     The Corporation issued 3,091,080 stock options and 1,041,530 shares of restricted stock in the first nine months of 2009. The calculation of weighted average common shares excludes the effect of 3,533,000 and 3,893,000 out-of-the money options for the quarter and nine months ended September 30, 2009, respectively.

     The table below summarizes changes in equity (in millions):

     Comprehensive income was $629 million ($614 million attributable to Hess Corporation) for the three months ended September 30, 2009 and $1,121 million ($1,129 million attributable to Hess Corporation) for the three months ended September 30, 2008.

     The Corporation’s results by operating segment were as follows (in millions):

     Operating revenues exclude excise and similar taxes of approximately $525 million and $550 million in the third quarter of 2009 and 2008, respectively, and $1,525 million and $1,650 million during the first nine months of 2009 and 2008, respectively.

     Identifiable assets by operating segment were as follows (in millions):

     The United States Deep Water Royalty Relief Act of 1995 (the Act) implemented a royalty relief program that relieves eligible leases issued between November 28, 1995 and November 28, 2000 from paying royalties on deepwater production in Federal Outer Continental Shelf lands. The Act does not impose any price thresholds in order to qualify for the royalty relief. The U.S. Minerals Management Service (MMS) created regulations that included pricing requirements to qualify for the royalty relief provided in the Act. During the period from 2003 to 2009, the Corporation accrued the royalties imposed by the MMS regulations. The legality of the thresholds imposed by the MMS was challenged in the federal courts and, in early October 2009, the U.S. Supreme Court decided not to review the appellate court’s decision against the MMS. As a result, the Corporation recognized a pre-tax gain of $143 million ($89 million after income taxes) in the third quarter of 2009 to reverse all previously recorded royalties. The pre-tax gain is reported in Other, net within the Statement of Consolidated Income.

     Hess Corporation (the Corporation) is a global integrated energy company that operates in two segments, Exploration and Production (E&P) and Marketing and Refining (M&R). The E&P segment explores for, develops, produces, purchases, transports and sells crude oil and natural gas. The M&R segment manufactures refined petroleum products and purchases, trades and markets refined petroleum products, natural gas and electricity. The Corporation reported net income of $341 million in the third quarter of 2009, compared with $775 million in the third quarter of 2008.

     Exploration and Production: E&P reported income of $397 million for the third quarter of 2009, compared with income of $699 million in the third quarter of 2008. The decrease in earnings mainly reflects significantly lower average oil and gas selling prices. Reported E&P earnings for the third quarter of 2009 included after-tax income of $89 million related to the resolution of a U.S. royalty dispute.

     In the third quarter of 2009, the Corporation’s average worldwide crude oil selling price, including the effect of hedging, was $56.07 per barrel compared with $93.36 per barrel in the third quarter of 2008. The Corporation’s average worldwide natural gas selling price was $4.60 per thousand cubic feet (mcf) in the third quarter of 2009 compared with $7.60 per mcf in the third quarter of 2008.

     Worldwide crude oil and natural gas production was 420,000 barrels of oil equivalent per day (boepd) in the third quarter of 2009 compared with 361,000 boepd in the same period of 2008. This increase was largely due to production from the Shenzi Field together with Phase 2 production from Block A-18 of the Joint Development Area of Malaysia and Thailand (JDA). The Shenzi Field commenced production at the end of the first quarter of 2009 and net production averaged 38,000 boepd for the third quarter. For the full year of 2009, worldwide crude oil and natural gas production is expected to average between approximately 400,000 and 410,000 boepd.

     Drilling continued in the Carnarvon Basin offshore Western Australia (WA-Block 390-P, Hess 100%) during the third quarter. The Corporation has now completed 9 wells and expects to drill the remaining 7 wells of the program by mid-2010.

     Marketing and Refining: M&R results generated income of $38 million for the third quarter of 2009, compared with income of $161 million in the third quarter of 2008, primarily reflecting lower margins. M&R results included a benefit of $12 million due to an income tax adjustment relating to refining operations.

     The after-tax results by major operating activity were as follows (in millions, except per share data):

     The following table summarizes, on an after-tax basis, items of income (expense) that are included in net income and affect comparability between periods (amounts in millions):

     The items in the table above are explained on pages 17 through 19.

     In the discussion that follows, the financial effects of certain transactions are disclosed on an after-tax basis. Management reviews segment earnings on an after-tax basis and uses after-tax amounts in its review of variances in segment earnings. Management believes that after-tax amounts are preferable to pre-tax amounts for explaining variances in earnings, since they show the entire effect of a transaction. After-tax amounts are determined by applying the appropriate income tax rate in each tax jurisdiction to pre-tax amounts.

     Following is a summarized income statement of the Corporation’s E&P operations (in millions):

     After considering the items affecting comparability between periods in the table on page 17, the remaining changes in E&P earnings are primarily attributable to changes in selling prices, sales volumes, operating costs, depreciation, depletion and amortization, and exploration expenses as discussed below.

Selling prices: Lower average realized selling prices of crude oil and natural gas decreased E&P revenues by approximately $1,205 million and $4,250 million in the third quarter and first nine months of 2009, respectively, compared with the corresponding periods of 2008. The Corporation’s average selling prices were as follows:

     In October 2008, the Corporation closed its Brent crude oil cash flow hedges, covering 24,000 barrels per day from 2009 through 2012, by entering into offsetting contracts with the same counterparty. The deferred after tax loss as of the date the hedge positions were closed will be recorded in earnings as the contracts mature. The estimated annual after-tax loss from the closed positions will be approximately $335 million from 2009 through 2012. Crude oil hedges reduced E&P earnings by $84 million and $249 million in the third quarter and first nine months of 2009 ($134 million and $398 million before income taxes). Crude oil and natural gas hedges reduced Exploration and Production earnings by $138 million and $377 million in the third quarter and first nine months of 2008, respectively ($224 million and $610 million before income taxes).

Sales and production volumes: The Corporation’s crude oil and natural gas production was 420,000 boepd in the third quarter of 2009 compared with 361,000 boepd in the same period of 2008. Production in the first nine months of 2009 was 406,000 boepd compared with 382,000 boepd in the first nine months of 2008. The Corporation anticipates that its production for the full year of 2009 will average between approximately 400,000 and 410,000 boepd.

     The Corporation’s net daily worldwide production by region was as follows (in thousands):

     United States: Crude oil production in the United States was higher in the third quarter and first nine months of 2009 compared to the corresponding periods in 2008, primarily due to the Shenzi Field which commenced production at the end of the first quarter of 2009. Crude oil and natural gas production in the Gulf of Mexico totaling approximately 10,000 boepd was shut-in during the third quarter of 2008 due to the impact of hurricanes.

     Europe: Crude oil production in Europe in the third quarter and first nine months of 2009 was comparable to the same periods in 2008, as higher production in Russia was offset by lower production in the U.K. North Sea. Natural gas production was lower in the third quarter and first nine months of 2009 compared to the same periods in 2008, primarily due to decline at the Atlantic and Cromarty fields, which are nearing the end of their productive lives.

     Asia and other: The increase in natural gas production in the third quarter and first nine months of 2009 compared to the corresponding periods in 2008 was principally due to Phase 2 gas sales from the JDA, which commenced production in November 2008.

     Sales volumes: Higher crude oil sales volumes increased revenue by approximately $335 million in the third quarter and $530 million in the first nine months of 2009, compared with the corresponding periods of 2008. During the third quarter of 2009, the Corporation’s sales volumes were under lifted compared to production while year-to-date sales volumes approximated total production volumes.

Operating costs and depreciation, depletion and amortization: Cash operating costs, consisting of production expenses and general and administrative expenses, decreased by $62 million and $165 million in the third quarter and first nine months of 2009 compared with the corresponding periods of 2008, excluding the impact of items affecting comparability discussed below. These decreases were principally due to lower price related production taxes.

     Depreciation, depletion and amortization expenses increased by $123 million and $179 million in the third quarter and first nine months of 2009 compared with the corresponding periods of 2008, excluding the impact of items affecting comparability discussed below. These increases were primarily due to the commencement of production in the Shenzi Field at the end of the first quarter 2009 and the ramp up of production at the JDA with Phase 2 gas. Rates per barrel also increased due to the mix of production from assets with varying per barrel rates, including the Shenzi Field.

     Excluding the impact of items affecting comparability discussed below, E&P total production unit costs (cash operating costs plus depreciation, depletion, and amortization) are anticipated to be in the range of $27 to $29 per barrel of oil equivalent (boe).

Exploration expenses: Exploration expenses were higher in the third quarter and the first nine months of 2009 compared with the same periods in 2008 principally reflecting higher dry hole expense and lease impairment partially offset by lower seismic costs.

Income taxes: The effective income tax rate for E&P operations in the first nine months of 2009 was 49% compared with 48% in the first nine months of 2008. The effective income tax rate for E&P operations for the full year of 2009 is expected to be in the range of 47% to 49%.

Foreign exchange: The after-tax foreign currency gains related to E&P activities were $4 million in the third quarter of 2009 compared with losses of $8 million in the third quarter of 2008. The after-tax foreign currency loss in the nine months ended September 30, 2009 was $1 million compared with a gain of $3 million for the nine months ended September 30, 2008.

     Reported E&P earnings include the following items affecting comparability of earnings between periods, after-tax (in millions):

     In early October 2009, the U.S. Supreme Court decided it would not review the decision of the 5th Circuit Court of Appeals against the U.S. Minerals Management Service relating to royalty relief under the Deep Water Royalty Relief Act of 1995. As a result, the Corporation recognized an after-tax gain of $89 million in the third quarter of 2009 to reverse all previously recorded royalties covering the periods from 2003 to 2009. The pre-tax gain of $143 million is reported in Other, net within the Statement of Consolidated Income. Approximately $7 million of the after-tax gain related to 2009.

     In the second quarter of 2009, after-tax charges of $31 million ($51 million before income taxes) were recorded to reduce the carrying values of production equipment in the U.K. North Sea and materials inventory in Equatorial Guinea and the United States. In the first quarter of 2009, the Corporation recorded an after-tax charge of $13 million ($26 million before income taxes) to reduce the carrying values of two short-lived fields in the U.K. North Sea. The pre-tax amount of the reductions in carrying value of production equipment and the short-lived fields was reported in Depreciation, depletion and amortization and the majority of the reduction in carrying values of inventory of $25 million was reported in Production expenses in the Statement of Consolidated Income.

     The Corporation’s future E&P earnings may be impacted by external factors, such as political risk, volatility in the selling prices of crude oil and natural gas, reserve and production changes, industry cost inflation, exploration expenses, the effects of weather and changes in foreign exchange and income tax rates.

     M&R activities generated income of $38 million and $110 million in the third quarter and first nine months of 2009 compared with $161 million and $125 million for the corresponding periods of 2008. The Corporation’s downstream operations include HOVENSA L.L.C. (HOVENSA), a 50% owned refining joint venture with a subsidiary of Petroleos de Venezuela S.A. (PDVSA), which is accounted for using the equity method. Additional Marketing and Refining activities include a fluid catalytic cracking facility in Port Reading, New Jersey, as well as retail gasoline stations, energy marketing and trading operations.

Refining: Refining operations generated a loss of $15 million and $59 million in the third quarter and first nine months of 2009 compared with income of $46 million in both the third quarter and first nine months of 2008, excluding the impact of the item affecting comparability discussed below. The Corporation’s share of HOVENSA’s losses, after income taxes, was $30 million in the third quarter of 2009 and $101 million in the first nine months of 2009 compared with income of $32 million and $14 million in the corresponding periods of 2008, principally reflecting lower refining margins. Port Reading’s after tax earnings were $16 million and $43 million in the third quarter and first nine months of 2009, compared with $14 million and $30 million in the corresponding periods of 2008.

The following table summarizes refinery capacity and utilization rates:

     In the third quarter of 2009, M&R results included a benefit of $12 million due to an income tax adjustment. This amount is included in the table of items affecting comparability between periods on page 14.

Marketing: Marketing operations, which consist principally of energy marketing and retail gasoline operations, generated earnings of $35 million in the third quarter of 2009 compared with $110 million in the third quarter of 2008. The decrease was primarily due to lower margins and lower refined product volumes. Marketing operations had earnings of $123 million in the first nine months of 2009 compared with earnings of $102 million in the first nine months of 2008.

     The following table summarizes marketing sales volumes:

     The Corporation has a 50% voting interest in a consolidated partnership that trades energy commodities and energy derivatives. The Corporation also takes trading positions for its own account. The Corporation’s after-tax results from trading activities, including its share of the results from the trading partnership, amounted to income of $6 million in the third quarter and $34 million in the first nine months of 2009 compared with income of $5 million in the third quarter and a loss of $23 million in the first nine months of 2008.

     Marketing expenses decreased in the third quarter and first nine months of 2009 compared with the corresponding periods of 2008, principally reflecting lower retail credit card fees.

     The Corporation’s future M&R earnings may be impacted by external factors, such as volatility in margins, competitive industry conditions, government regulatory changes, credit risk and supply and demand factors, including the effects of weather.

     The following table summarizes corporate expenses (in millions):

     After-tax corporate expenses were lower in the third quarter and first nine months of 2009 compared with the same periods of 2008, mainly due to higher income from pension related investments and lower costs as a result of cost saving initiatives, partly offset by higher bank facility fees. In the first nine months of 2009, a charge of $25 million before income taxes ($16 million after-tax) relating to retirement benefits and employee severance costs, was recorded in General and administrative expenses. In the fourth quarter of 2009, the Corporation will record a pre-tax charge of approximately $15 million ($10 million after-tax) for pension plan settlements relating to the retirements referred to above.

     After-tax corporate expenses in 2009 are estimated to be in the range of $145 to $150 million, excluding items affecting comparability between periods.

     Interest expense was as follows (in millions):