Item 3. Legal Proceedings
A. In 2001, the company's chemical affiliate (Chemical) received a Notice of Violation (NOV) from EPA, Region 9. The NOV claims that Chemical has been in continuous violation of the Clean Air Act new source review requirements applicable to the construction in 1994 and continued operation of an open-hearth furnace at its Henderson, Nevada, facility. Chemical operated the open-hearth furnace in compliance with state-issued permits and believes that the NOV is without substantial merit. Chemical is vigorously defending against the claims made in the NOV and believes that any fines and penalties related to the NOV will not have a material adverse effect on the company.
B. In 2002, Tiwest Pty Ltd, an Australian joint venture that produces titanium dioxide and in which Chemical indirectly has a 50% interest, received a complaint and notice of violation from the Department of Environmental Waters and Catchment Protection in Western Australia alleging violations of the Environmental Protection Act (1986). This matter concerns an alleged chlorine release at the facility. Tiwest defended the proceeding in the Court of Petty Sessions, Perth, Western Australia, and expects a decision in the matter around the end of the first quarter. As currently filed, the maximum fine is $625,000 (Australian dollars), but the liability of the joint venture and the amount of any monetary fine are uncertain.
C. On December 15, 2003, the District Court of Rotterdam, Netherlands, determined that Kerr-McGee Pigments (Holland) B.V., an affiliate of the company, had violated regulations imposed by the Netherlands Environmental Management Act. The violations primarily relate to the failure to notify authorities of the release of process gases from the affiliate's facility in Botlek, Netherlands, as required by the facility's environmental permit. The Court imposed a fine of (euro)80,000, which concludes the case.
D. On January 7, 2004, the United States filed a civil lawsuit in the U.S. District Court for the District of Oregon against Kerr-McGee Chemical Worldwide LLC and two other private parties in connection with the remediation of contaminated materials at the White King/Lucky Lass uranium mines in Lakeview, Oregon. The mines were owned and operated by a predecessor of Kerr-McGee Chemical Worldwide LLC and are currently designated as a Superfund site. The lawsuit seeks reimbursement of Forest Service response costs, an injunction requiring compliance with an Administrative Order issued to the private parties regarding cleanup of the site, and civil penalties for alleged noncompliance with the Administrative Order. The company expects all legal proceedings to be stayed pending discussions to resolve outstanding issues. The company believes that the litigation will not have a material adverse effect on the company.
E. On September 8, 2003, the Environmental Protection Division of the Georgia Department of Natural Resources (EPD) issued a unilateral Administrative Order to Kerr-McGee Pigments (Savannah) Inc., claiming that the Savannah plant exceeded emission allowances provided for in the facility's Title V air permit. The EPD is seeking monetary penalties of approximately $178,000. The company appealed the order on October 8, 2003, which stayed the effectiveness of the order. Meanwhile, the company is vigorously defending against the claims made in the order and believes that any penalties related to them will not have a material adverse effect on the company.
F. For a discussion of other legal proceedings and contingencies, reference is made to (1) the Environmental Matters section of Management's Discussion and Analysis of Financial Condition and Results of Operations included in Item 7. and (2) Note 16 to the Consolidated Financial Statements included in Item 8. of this Form 10-K, both of which are incorporated herein by reference.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders
None submitted during the fourth quarter of 2003.
Executive Officers of the Registrant
The following is a list of executive officers, their ages, and their positions and offices as of March 1, 2004:
Name Age Office - ----------------------- --- --------------------------------------------
Luke R. Corbett 57 Chief Executive Officer since 1997. Chairman of the Board since May 1999 and from 1997 to February 1999. President and Chief Operating Officer from 1995 until 1997.
Kenneth W. Crouch 60 Executive Vice President since March 2003. Senior Vice President from 1996 to 2003. Senior Vice President, Exploration and Production Operations, from 1998 to 2003. Senior Vice President, Exploration, from 1996 to 1998.
David A. Hager 47 Senior Vice President, Exploration and Production Operations, since March 2003. Vice President of Exploration and Production, 2002 to 2003. Vice President of Gulf of Mexico and Worldwide Deepwater Exploration and Production, 2001 to 2002; Vice President of Worldwide Deepwater Exploration and Production, 2000 to 2001; Vice President of International Operations, 2000; previously Vice President of Gulf of Mexico operations. Joined Sun Oil Co., predecessor of Oryx Energy Company, in 1981.
Gregory F. Pilcher 43 Senior Vice President, General Counsel and Corporate Secretary since July 2000. Vice President, General Counsel and Corporate Secretary from 1999 to 2000. Deputy General Counsel for Business Transactions from 1998 to 1999. Associate/Assistant General Counsel for Litigation and Civil Proceedings from 1996 to 1998.
Carol A. Schumacher 47 Senior Vice President of Corporate Affairs since February 2002. Prior to joining the company in 2002, served as Vice President of Public Relations for The Home Depot, 1998 to 2001; Executive Vice President and General Manager, Atlanta office of Edelman Worldwide, 1997 to 1998; and Executive Vice President of Cohn & Wolfe, a division of Young & Rubicam, Inc.
Robert M. Wohleber 53 Senior Vice President and Chief Financial Officer since December 1999. Prior to joining the company in 1999, served as Executive Vice President and Chief Financial Officer of Freeport-McMoRan Exploration Company, President and Chief Executive Officer of Freeport-McMoRan Sulfur and Senior Vice President of Freeport-McMoRan Gold and Copper Corporation.
W. Peter Woodward 55 Senior Vice President since 1997. Senior Vice President of Marketing for Kerr-McGee Chemical from 1996 to 1997.
George D. Christiansen 59 Vice President, Safety and Environmental Affairs, since 1998. Vice President, Environmental Assessment and Remediation, from 1996 to 1998.
Fran G. Heartwell 57 Vice President of Human Resources since March 2003; Director of Human Resources, Kerr-McGee Oil & Gas, from September 2002 to January 2003; Vice President of Human Resources and Administration, Oryx Energy Company, from 1995 until the 1999 merger of Oryx and Kerr-McGee.
J. Michael Rauh 54 Vice President since 1987. Controller since January 2002 and 1987 to 1996. Treasurer from 1996 to 2002.
John F. Reichenberger 51 Vice President, Deputy General Counsel and Assistant Secretary since July 2000. Assistant Secretary and Deputy General Counsel from 1999 to 2000. Deputy General Counsel from 1998 to 1999. Associate General Counsel from 1996 to 1999.
Elizabeth T. Wilkinson 46 Vice President and Treasurer since November 2002. Previously Assistant Treasurer - Corporate Finance, GlobalSantaFe Corporation (Global Marine Inc. until 2001 merger); Manager of Planning and Analysis from 1998 to 1999 and Manager of Budgets and Planning from 1994 to 1998, Global Marine Inc.
There is no family relationship between any of the executive officers.
CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS
Statements in this Form 10-K 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. These forward-looking statements include those statements preceded by, followed by or that otherwise include the words "believes," "expects," "anticipates," "intends," "estimates," "projects," "target," "budget," "goal," "plans," "objective," "outlook," "should," or similar words. In addition, any statements regarding possible commerciality, development plans, capacity expansions, drilling of new wells, ultimate recoverability of reserves, future production rates, future cash flows and changes in any of the foregoing are forward-looking statements. 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 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, demand for consumer products for which Kerr-McGee's businesses supply raw materials, 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 in areas where Kerr-McGee operates, trade and regulatory matters, general economic conditions, and other factors and risks discussed herein and in the company's other SEC filings. Actual results and developments may differ materially from those expressed or implied in this Form 10-K.
PART II
Item 5.
Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters
Information relative to the market in which the company's common stock is traded, the high and low sales prices of the common stock by quarters for the past two years, and the approximate number of holders of common stock is furnished in Note 34 to the Consolidated Financial Statements, which note is included in Item 8. of this Form 10-K.
Quarterly dividends declared totaled $1.80 per share for each of the years 2003, 2002 and 2001. Cash dividends have been paid continuously since 1941 and totaled $181 million in 2003, $181 million in 2002 and $173 million in 2001.
For information required under Item 201(d) of Regulation S-K related to the company's securities authorized for issuance under equity compensation plans, reference is made to Item 12. of this Form 10-K.
Item 6.
Item 6. Selected Financial Data
Information regarding selected financial data required in this item is presented in the schedule captioned "Ten-Year Financial Summary" included in Item 8. of this Form 10-K.
Item 7.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Management's Discussion and Analysis - --------------------------------------------------------------------------------
Overview
Kerr-McGee Corporation is one of the largest U.S.-based independent oil and gas exploration and production companies and the world's third-largest producer and marketer of titanium dioxide pigment. The company has three reportable business segments, oil and gas exploration and production, production and marketing of titanium dioxide pigment (chemical - pigment), and production and marketing of other chemicals (chemical - other). The company's assets total approximately $10 billion. Proved oil and gas reserves are approximately 1 billion barrels of oil equivalent and the company's equity production capacity for titanium dioxide pigment is 618,000 tonnes per year. For 2003, revenues from continuing operations totaled $4.2 billion, of which $2.9 billion (69%) was generated by the company's oil and gas exploration and production operations and $1.3 billion (31%) was generated by the company's chemical operations. Revenues for the exploration and production operations are generated primarily from the sale of crude oil and natural gas, as well as marketing revenues associated with the company's sale of nonequity gas. Revenues for the company's chemical operations are generated from the sale of titanium dioxide pigment and other chemical products. An overview of each operating unit and certain other economic considerations are included below to provide background for the various discussions that will follow in Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A). A detailed discussion of each operating unit's business and properties is included in Items 1. and 2. of this Form 10-K.
Exploration and Production - The company's exploration and production business is primarily focused on finding and developing new oil and gas reserves. The success of the company depends heavily on a successful exploration program. As a benchmark, the company works to replace at least 100% of its production each year through a combination of its drilling and development programs and tactical acquisitions. During 2003, Kerr-McGee replaced 135% of its 2003 worldwide production from continuing operations, of which 105% resulted from replacement through the company's exploration program. Kerr-McGee has established a competitive average finding, development and acquisition cost of $7.19 per barrel of oil equivalent (BOE) and annual average production replacement of 192% over the past five years, and remains focused on adding value to its reserve base. The company faces many challenges in executing a successful exploration program, including obtaining accurate and reliable geological and geophysical data, understanding reservoir complexity, and inherent risks associated with deepwater exploration, among others. Consequently, a portion of the company's total exploration costs is dry hole cost for unsuccessful drilling activity. The company works to mitigate these risks by attracting and retaining talented exploration and engineering personnel with wide ranging experience in its core exploration areas. The company utilizes advanced technology to maximize the impact of its exploration efforts including both extensive geological and geophysical data acquisition and analysis as well as state-of-the-art visualization interpretation techniques. In addition, Kerr-McGee maintains an extensive world-wide acreage position which the company believes provides it with a significant competitive advantage in its effort to maintain and develop a high-quality prospect inventory. The company believes its prospect inventory is a key component in mitigating the inherent risk of its exploration program.
In addition, profitability and cash flows for exploration and production operations are heavily dependent on market prices for crude oil and natural gas, as well as production costs, taxation levels and other operating costs. To mitigate uncertainties related to commodity price fluctuations, the company hedged the sales price of a substantial portion of its 2003 oil and gas sales. The company has entered into additional hedge contracts for 2004 to maximize the predictability of its cash flows. In addition to hedging, the company monitors its cost performance in an effort to maximize overall profitability and ensure its ability to compete within the industry. In 2003, the company completed a major divestiture program which was partially directed at reducing the overall production cost of its asset portfolio. Completion of this program contributed to a 12% reduction in the company's per unit production costs. Changes in operating costs from year to year are discussed in the Segment Operations section below.
While the company's drilling program and subsequent development of successful projects generally yield attractive economic returns, they do require a substantial capital commitment. An overview of historical capital spending, as well as a discussion of the 2004 capital spending budget, major projects and exploratory drilling program are included in the Capital Spending section of MD&A below. On an ongoing basis, the carrying values of the company's oil and gas properties are evaluated for recoverability relative to their future cash flows. Likewise, reservoir performance and reserve quantities are periodically reviewed. Negative revisions to reserve quantities or negative changes in the market prices of crude oil and natural gas can adversely affect the company's estimates of future cash flows and may result in asset impairments. Because of the large capital investment required to develop oil and gas fields and the uncertain mineral resources associated with each field, asset impairment evaluations are common in the oil and gas industry and are indicative of projects for which previous capital investments are no longer recoverable under current economic conditions. Such impairments may occur in the future; however, the company cannot predict the timing or magnitude of future asset impairment charges.
Chemical - The chemical operating unit has focused its strategy on its titanium dioxide pigment operations. As part of this strategic decision, the company continues to investigate divestiture options for the electrolytic business and plans to exit the forest products business by the end of 2004 when the lease on its only facility still in operation expires.
The profitability of the company's pigment operations is tied to consumption of, and demand for, titanium dioxide pigment, which generally follow global economic trends (discussed in the Operating Environment and Outlook section below). The profitability of the company's pigment operations also depends on the company's ability to manage operating costs. As part of its efforts to manage operating costs, the company closed its synthetic rutile plant in Mobile, Alabama, in June 2003. The Mobile plant supplied a portion of the feedstock for the company's pigment plants in the United States; however, through ongoing supply-chain initiatives, feedstock can now be purchased more economically than it could be manufactured at the Mobile plant. In connection with the shutdown, the company recorded after-tax charges of $30 million for severance, accelerated depreciation and other decommissioning expenses during 2003.
Chemical is working on technological advancements that will allow it to add plant capacity with low-cost expansions to take advantage of future market growth. As a result of these efforts, production began through a new high-productivity oxidation line at the Savannah, Georgia, chloride process pigment plant in January 2004. This new technology is expected to result in low-cost, incremental capacity increases through modification of existing chloride oxidation lines and should allow for improved operating efficiencies through simplification of hardware configurations and reduced maintenance requirements.
Based on the future outcome of these technological advancements, the company may need to review its existing configuration at the Savannah plant to optimize the plant's resources in relation to capacity requirements. The company will evaluate the performance of the new high-productivity line, analyze the implications on the capacity of existing assets and have a plan for reconfiguration, if any, by the latter part of 2004. If the new high-productivity line performs as expected, the outcome of this review may result in the redeployment of certain assets to alternate uses and/or the need to idle certain other assets. If this occurs, the future useful life of such assets may be adjusted, resulting in the acceleration of depreciation expense.
The AVESTOR joint venture was created by Kerr-McGee and Hydro-Quebec, one of North America's largest utilities, to commercialize and produce a lithium-metal-polymer battery. The company's investment in the joint venture aligns core competencies with new business expansion opportunities. Commercial battery production and sales commenced in late 2003 to the telecommunications industry. It is expected that production will continue to increase during 2004. AVESTOR's unique technical and product offering capability is expected to create additional high-market-value opportunities in the utility and industrial power generation markets. With market demand growing, the company anticipates sales to match plant capacity.
Other Economic Considerations - Other challenges facing Kerr-McGee include balancing its opportunities for growth with the company's desire to maintain a lower debt structure, reducing the company's overall cost structure to improve longer-term profitability, managing ongoing and legacy environmental obligations, and maintaining the over-funded status of its U.S. qualified pension plan.
Strategically, Kerr-McGee has committed its focus to growing its exploration and production operations and improving the profitability of its titanium dioxide pigment business. This has been achieved through selective acquisitions, the success of the company's exploration program and technological advancements. At the same time, the company must balance the capital commitment required to grow its core operations with its goal of reducing the company's total debt burden to remain competitive and to increase financial flexibility. Discussions of the company's cash flow, liquidity and debt-reduction plans in 2004 are included in the Financial Condition section below.
In the global marketplace, economic pressures continue and the economy is recovering more slowly than anticipated. In order to remain competitive, the company has taken a disciplined approach in reviewing its cost structure and initiated a work-force reduction plan during the third quarter of 2003. As a result of the program, the company's eligible U.S. nonbargaining work force was reduced by approximately 9%, or 271 employees. The reduction consisted of both voluntary retirements and involuntary terminations. Qualifying employees terminated under this program are eligible for enhanced benefits under the company's pension and postretirement plans, along with severance payments. The program was substantially completed by the end of 2003, with certain retiring employees staying into the first half of 2004 for transition purposes. In connection with the work-force reduction, the company took a pretax charge of $56 million during 2003, of which $34 million was for curtailment and special termination benefits associated with the company's retirement plans and $22 million was for severance-related costs.
Because of the nature of Kerr-McGee's current and historical operations, the company has significant environmental remediation responsibilities and continues to provide reserves for these remediation projects. During 2003, the company expensed an additional $62 million (net of reimbursements) for environmental costs and funded $104 million of expenditures associated with its environmental projects. A discussion of the status and circumstances surrounding these projects is included in the Environmental Matters discussion below.
With the substantial stock market losses experienced between 2000 and 2002, many corporations are facing a significant financial challenge with respect to the funded status of their pension plans. The company's U.S. qualified pension plan remains over funded and estimated returns on plan assets continue to exceed the company's other periodic pension costs, generating a net periodic pension benefit of $38 million in 2003. No contributions to the company's U.S. qualified pension plan will be necessary in 2004. The critical assumptions used in measuring the company's pension and postretirement obligations and the sensitivity of the various estimates associated with the company's benefit plans are discussed in the Critical Accounting Policies section below.
- -------------------------------------------------------------------------------- Operating Environment and Outlook
Oil and Gas Exploration and Production
During 2003, global geopolitical uncertainties affected investment decisions in the oil and gas industry. However, these risks were mitigated by consistently strong oil and gas prices. The near-month futures price of West Texas Intermediate (WTI) crude oil closed at or above $30 per barrel for most of the year, and natural gas maintained an average price above $5 per million British thermal units (MMBtu) during 2003.
Crude Oil - During 2003, disruptions to crude oil production in Venezuela and Nigeria due to political unrest and ethnic violence, combined with uncertainties linked to the war in Iraq, created global uncertainty about the reliability of crude oil supply. U.S. crude oil inventories began 2003 below the normal operating range resulting from a reduction in U.S. imports due to a strike in Venezuela and strong demand for distillates during the 2003 U.S. heating season. In January 2003, OPEC announced plans to increase production by 1.5 million barrels per day to compensate for the Venezuelan shortfalls. However, this increase was not enough to overcome a perceived shortfall in supply due to low U.S. inventories and expectation of a war in Iraq. Crude oil WTI prices were near $38 per barrel by the end of the 2003 first quarter. Following the onset of the Iraqi war, prices fell sharply to approximately $25 per barrel due to the war's short duration, coupled with increases in crude oil imports from Saudi Arabia and Venezuela.
Decreasing U.S. domestic oil production, delays in Iraqi oil production increases and the effect of OPEC's April 2003 production cut of 2 million barrels per day resulted in WTI crude futures prices recovering to above $30 per barrel early in the 2003 third quarter. Prices generally remained at this level for the remainder of the year.
Numerous factors are expected to influence the U.S. crude oil market in 2004. Oil production in Nigeria, Venezuela and Iraq continued to recover, although not to full capacity. OPEC's recent remarks concerning the intention to shift its strategy to revenue enhancement from market share protection could also impact crude oil markets. Finally, a continued rebound in global economies could absorb some oversupply.
Natural Gas - Higher-trending natural gas prices in 2003 are the result of fundamental shifts in the natural gas supply and demand balance. Gas prices began the year at about $5.25 per MMBtu and reached a high of more than $9 per MMBtu during February due to storage levels falling to record lows. This event heightened concerns regarding the decline of U.S. gas supplies, and deliverability issues continued to underpin market activity throughout the year.
By fall 2003, U.S. gas storage volumes had recovered to comfortable levels, but fears of the previous winter's supply shortfall, as well as reports of declining domestic production, kept prices strong. Throughout summer and fall, natural gas prices remained above $4.50 per MMBtu, maintaining a range of $4.50 to $6.50 per MMBtu until December, when seasonally cold winter weather began to push prices up towards $7 per MMBtu.
The 2004 environment for U.S. natural gas prices remains volatile and will be influenced by several factors, including the balance between supply and demand, weather patterns, the rate and development of liquefied natural gas imports, crude oil and distillate prices, and government policy.
To mitigate the above uncertainties related to price fluctuations, the company has entered into hedges covering approximately 80% of expected 2004 worldwide crude oil and condensate production, and 75% of the U.S. natural gas production. By ensuring greater predictability of cash flows to fund major exploration and capital programs, hedging enhances the company's ability to meet financial requirements. Details of the company's commodity hedging program are included in the Market Risks section below.
Chemicals
In the global titanium dioxide pigment industry, the company is the third-largest producer and marketer and one of five companies that own chloride technology. The chloride process produces a pigment with optical properties preferred by the paint, coatings and plastics industries. In early 2004, chloride technology accounted for 76% of the company's gross pigment production capacity. The remaining capacity is sulfate-process production, which produces pigment used primarily in paper and specialty products.
Titanium dioxide is a quality-of-life product, and its consumption follows general economic trends. Throughout 2003, challenging business conditions existed for the company's chemical operations due to near-recessionary conditions in Europe, high energy prices, the effect of the SARS epidemic on economic conditions in Asia and continued weakness in the U.S. manufacturing sector. These economic forces placed pressure on product prices, overall product demand and profitability. While overall global economic growth was stagnant to recessionary during the first half of 2003, the last quarter of 2003 did begin to show improvement as observed in the leading U.S. economic indicators and Euro-zone GDP. General economic conditions are expected to improve in 2004 for North America and Europe, with continued growth in the Asian markets.
The strategy for Kerr-McGee's chemical unit focuses on continued improvement in asset productivity, process and product capability, cost reductions, and providing superior products for market-segment growth. Multiple initiatives are in place to capture new market growth through segmentation strategies that align products with customer needs, low-cost plant expansions to increase volume capacity, continuous improvement programs to increase efficiency and lower operating costs, and technology-based programs to improve product quality and lower costs.
- -------------------------------------------------------------------------------- Results of Consolidated Operations
Net income (loss) and per-share amounts for each of the years in the three-year period ended December 31, 2003, were as follows:
(Millions of dollars, except per-share amounts) 2003 2002 2001 - --------------------------------------------------------------------------------
Net income (loss) $219 $(485) $486 Net income (loss) per share - Basic 2.18 (4.84) 5.01 Diluted 2.17 (4.84) 4.74
The major variances in net income on an operating unit basis (after income taxes) are outlined in the table below. The variances in individual line items in the Consolidated Statement of Operations are explained in the section that follows.
Favorable (Unfavorable) Variance ------------------------- 2003 2002 Versus Versus (Millions of dollars) 2002 2001 - -------------------------------------------------------------------------------- Net operating profit - Exploration and production $ 898 $(850) Chemical - pigment (17) 25 Chemical - other (7) (4) Net interest expense 15 (56) Other income/expense (24) (202) Discontinued operations (126) 96 Cumulative effect of accounting change (35) 20 ----- ----- Net income $ 704 $(971) ===== =====
The 2003 increase in exploration and production net operating profit is primarily due to a decrease in asset impairments of $385 million in 2003 and net gains associated with assets held for sale of $29 million in 2003 versus losses of $167 million in 2002. The remaining $317 million increase is due to the 2002 deferred tax effect of $132 million resulting from a 33% increase in the U.K. corporate tax rate for oil and gas companies, combined with lower production costs and depreciation and depletion expense and higher average realized sales prices for both crude oil and natural gas in 2003, partially offset by lower oil and gas sales volumes and higher exploration expense.
The decline in chemical - pigment net operating profit in 2003 is principally the result of plant closure and workforce reduction provisions totaling $42 million and higher average per-unit production costs, partially offset by higher pigment sales prices.
Lower interest expense in 2003 is due to lower average debt outstanding and a slightly lower weighted average interest rate. The negative variance for other income/expense is mainly due to higher general and administrative costs, workforce reduction costs and lower net gains on the revaluation of nonoperating derivatives and trading securities, partially offset by lower 2003 litigation provisions and a gain on sale of Devon Energy Corporation (Devon) shares.
Discontinued operations for all three years resulted from the company's decision in early 2002 to dispose of its exploration and production interests in Indonesia and Kazakhstan and its interest in the Bayu-Undan project in the East Timor Sea offshore Australia. These divestiture decisions were made as part of the company's strategic plan to rationalize noncore oil and gas properties. The negative variance from discontinued operations in 2003 and the positive variance in 2002 are both due primarily to the $107 million gain on sale in 2002 related to the disposals in Indonesia and Australia.
The 2003 cumulative effect of change in accounting principle is the result of the company's adoption of the Financial Accounting Standards Board's Statement No. 143, "Accounting for Asset Retirement Obligations" (FAS 143). See the New/Revised Accounting Standards section below for a discussion of the adoption.
The 2002 decline in exploration and production net operating profit resulted from asset impairments of $394 million, losses associated with assets held for sale of $167 million and the deferred tax effect of $132 million for the U.K. corporate tax law change, as well as higher lease operating expense, shipping and handling expense, depreciation and depletion, and exploration expenses. The improvement in chemical's pigment net operating profit in 2002 was principally the result of higher pigment sales volumes and lower average per-unit production costs. Higher interest expense in 2002 was due to significantly higher average debt outstanding and lower capitalized interest, partially offset by a lower overall average interest rate.
The 2002 negative variance for other income/expense was mainly due to the 2001 adoption of FAS 133, "Accounting for Derivative Instruments and Hedging Activities," which resulted in the company recognizing a $118 million net unrealized gain on shares of Devon reclassified to "trading" from the "available for sale" category of investments. Additionally, a 2002 net-of-tax litigation provision of $47 million and after-tax foreign currency losses of $33 million contributed to the other income/expense variance for 2002 versus 2001.
The 2002 positive variance from the change in accounting principle also resulted from the company's adoption of FAS 133 in 2001. This standard required the recording of all derivative instruments as assets or liabilities, measured at fair value. Kerr-McGee recorded the fair value of all its outstanding foreign currency forward contracts and the fair value of the options associated with the company's debt exchangeable for common stock (DECS) of Devon owned by the company. The net effect of recording these fair values resulted in a $20 million decrease in income as a cumulative effect of a change in accounting principle and a $3 million reduction in equity (other comprehensive income) for the foreign currency contracts designated as hedges.
- -------------------------------------------------------------------------------- Statement of Operations Comparisons
(Billions of dollars) 2003 2002 2001 - --------------------- ---- ---- ---- Revenues $4.2 $3.6 $3.6
The increase in 2003 revenues was primarily due to higher average realized sales prices for crude oil, natural gas and titanium dioxide pigment, combined with higher gas marketing sales revenue. These increases were partially offset by lower production quantities due primarily to oil and gas properties divested during 2002 and 2003. Revenues in 2002 increased slightly over 2001 due to a full year of revenues from the Rocky Mountain region compared with only five months in 2001 following the acquisition of HS Resources, combined with the favorable impact of higher pigment sales volumes, partially offset by the recognition of lower revenues from properties divested during 2002. These variances are discussed in more detail in the segment discussions that follow. See Note 1 to the Consolidated Financial Statements for a discussion of reclassifications made to revenues for 2002 and 2001.
(Millions of dollars) 2003 2002 2001 - ---------------------------- ------ ------ ------ Costs and Operating Expenses $1,668 $1,456 $1,264
Costs and operating expenses for 2003 increased $212 million over the prior year, primarily due to higher gas marketing product costs of $233 million (which offsets higher third-party gas marketing revenues), higher pigment production costs of $51 million and 2003 shutdown provisions of $42 million associated with the closure of Chemical's Mobile facility and forest products operations. These increases were partially offset by lower lease operating expense of $114 million mainly due to oil and gas property divestitures. Costs and operating expenses increased $192 million in 2002 from the 2001 level, resulting principally from higher gas marketing, gathering and pipeline costs of $74 million (full year of Rocky Mountain operations in 2002 versus five months in 2001), higher lease operating expenses of $80 million (full year of Rocky Mountain operations and new natural gas production brought online in the Gulf of Mexico region), and higher pigment production cost of $91 million (increased pigment production volumes).
(Millions of dollars) 2003 2002 2001 - ------------------------------------------- ---- ---- ---- Selling, General and Administrative Expenses $371 $313 $228
For 2003, selling, general and administrative expenses increased $58 million over the prior year, resulting primarily from provisions totaling $58 million associated with the 2003 work-force reduction plan and other transition and severance-related costs, together with additional compensation expense of $17 million resulting from loan prepayments required to release shares from the company's employee stock ownership plan. Also contributing to the increase were higher corporate and exploration and production general and administrative costs of $24 million and $14 million, respectively, partially offset by lower litigation provisions of $63 million (prior-year forest products litigation). The 2003 increase in corporate general and administration was principally due to higher compensation-related costs of $16 million related mostly to 2003 performance bonus and amortization of restricted stock compensation, along with higher general and auto liability costs of $5 million. The increase in general and administrative costs for the exploration and production operations of $14 million is due primarily to lower 2003 billings of costs on operated properties to partners, which were partially offset by lower cost for contract services and direct labor. Selling, general and administrative expenses for 2002 increased $85 million primarily as a result of the $72 million reserve for litigation established mainly in connection with certain forest products litigation in Mississippi, Louisiana and Pennsylvania. This litigation is discussed in Note 16 to the financial statements.
Shipping and handling expenses for 2003, 2002 and 2001 were $140 million, $125 million and $111 million, respectively. The increase in 2003 is primarily due to higher costs for transportation from new deepwater fields in the Gulf of Mexico, including Nansen, Boomvang and Navajo, and increased costs in the U.K. North Sea, as well as higher pigment shipping costs. The increase in pigment shipping costs is primarily related to higher ocean freight prices due to supply constraints on the availability of vessels. The 2002 increase was also due to higher transportation for new deepwater fields in the Gulf of Mexico, combined with higher costs in the Rocky Mountain region due to a full year of costs related to the former HS Resources operations.
Abandonment expense of $40 million and $34 million associated with the company's exploration and production operations has been reclassified from costs and operating expenses to depreciation and depletion for 2002 and 2001 to be consistent with the 2003 presentation after adoption of FAS 143.
(Millions of dollars) 2003 2002 2001 - -------------------------- ---- ---- ---- Depreciation and Depletion $745 $814 $747
Depreciation and depletion expense totaled $745 million in 2003, $814 million in 2002 and $747 million in 2001. The decrease for 2003 is due to lower depletion expense for divested or held-for-sale properties of $49 million and lower depletion on the Leadon field of $36 million, partially offset by higher depletion expense in the Gulf of Mexico region of $24 million mainly due to higher production from the Nansen, Boomvang and Navajo fields which began producing in 2002. The 2002 increase was due to higher depletion expense for the Rocky Mountain region of $75 million (full year of ownership) and for the U.K. region of $11 million. Partially offsetting these increases was lower expense in the Gulf of Mexico region of $24 million due to normal declines in production and held-for-sale properties, which more than offset the impact of new production from the Nansen, Boomvang and Navajo fields.
Impairment losses on held-for-use assets totaled $14 million in 2003, $652 million in 2002 and $76 million in 2001. These impairments were related to assets with remaining investments that were no longer expected to be recovered through future cash flows. Impairments in 2003 were related primarily to various mature oil and gas fields in the U.S. onshore and Gulf of Mexico shelf areas. The impairments in 2002 included $541 million for the Leadon field in the North Sea, $82 million for certain nonoperated fields in the North Sea, $23 million for several older Gulf of Mexico shelf properties, and $6 million related to the company's planned shutdown of the forest products operations. The 2001 impairments were comprised of $47 million associated with the shut-down of the North Sea Hutton field and $29 million for certain chemical facilities in Belgium and the U.S.
During 2003, the company selectively marketed its 100%-owned Leadon field to third parties. Although no divestiture negotiations are currently under way, the company continues to review its options with respect to the field and, particularly, the associated floating production, storage and offloading (FPSO) facility. Management presently intends to continue operating and producing the field until such time as the operating cash flow generated by the field does not support continued production or until a higher value option is identified. Given the significant value associated with the FPSO relative to the size of the entire project, the company will continue to pursue a long-term solution that achieves maximum value for Leadon - which may include disposing of the field, monetizing the FPSO by selling it as a development option for a third-party discovery, or redeployment in other company operations. As of December 31, 2003, the carrying value of the Leadon field assets totaled $374 million. Given the uncertainty concerning possible outcomes, it is reasonably possible that the company's estimate of future cash flows from the Leadon field and associated fair value could change in the near term due to, among other things, (i) unfavorable changes in commodity prices or operating costs, (ii) a production profile that declines more rapidly than currently anticipated, and/or (iii) unsuccessful results of continued marketing activities or failure to locate a strategic buyer (or suitable redeployment opportunity). Accordingly, management anticipates that the Leadon field will be subject to periodic impairment review until such time as the field is abandoned or sold. If future cash flows or fair value decrease from that presently estimated, an additional write-down of the Leadon field could occur in the future.
In connection with the company's divestiture program initiated in 2002, certain oil and gas properties were identified for disposal and classified as held-for-sale properties. Upon classification as held-for-sale, the carrying value of the related properties is analyzed in relation to the estimated fair value less costs to sell, and losses are recognized, if necessary. Upon ultimate disposal of the properties, any gain or additional loss on sale is recognized. Losses of $23 million and gains of $68 million were recognized in 2003 upon conclusion of the divestiture program in the U.S. and North Sea, and for the sale of the company's interest in the South China Sea (Liuhua field) and other noncore U.S. properties (onshore and Gulf of Mexico shelf areas). The company recognized losses of $176 million in 2002 associated with oil and gas properties held for sale in the U.S. (onshore and Gulf of Mexico shelf areas), the U.K. North Sea and Ecuador. Proceeds realized from these disposals totaled $119 million in 2003 and $374 million in 2002. The proceeds from the sale of such properties have been used to reduce long-term debt. From time to time, other oil and gas properties may be identified for disposal when such properties are considered noncore or nearing the end of their productive lives.
(Millions of dollars) 2003 2002 2001 - --------------------- ---- ---- ---- Exploration Expense $354 $273 $210
Exploration costs were $354 million, $273 million and $210 million for 2003, 2002 and 2001, respectively. The 2003 increase was due to higher dry hole costs of $68 million, primarily exploratory drilling in the deepwater Gulf of Mexico, and higher exploration department costs of $11 million. The 2002 increase was due to higher dry hole costs of $41 million, mainly exploratory drilling in the deepwater Gulf of Mexico and in the North Sea, higher nonproducing leasehold amortization of $11 million, and higher geophysical costs of $5 million.
Interest and debt expense totaled $251 million in 2003, $275 million in 2002 and $195 million in 2001. The $24 million decrease in 2003 was due to lower average borrowings under revolving credit facilities and commercial paper of approximately $570 million and slightly lower average interest rates on the company's long-term debt. The $80 million increase in 2002 was due to an annual average debt balance that was approximately $1.4 billion higher than 2001 due to the acquisition of HS Resources in August 2001 and capitalized interest that was lower by $23 million, partially offset by overall average interest rates that were approximately 1% lower than in the prior year.
Other income (expense) includes the following for each of the years in the three-year period ended December 31, 2003:
(Millions of dollars) 2003 2002 2001 - -------------------------------------------------------------------------------- Foreign currency translation gain (loss) $(41) $(38) $ 3 Loss from equity affiliates (33) (25) (5) Gain on sale of Devon stock 17 - - Unrealized gain on Devon stock reclassified to "trading" category of investments - - 181 Exchangeable debt embedded options and Devon stock revaluations 8 27 17 Gains (losses) on non-hedge natural gas derivatives (4) 8 27 Other (6) (7) 1 ---- ---- ---- Other income (expense) $(59) $(35) $224 ==== ==== ====
The majority of the 2003 and 2002 foreign currency losses resulted from the company's U.K. operations, where the company has experienced unfavorable changes in the U.S. dollar/British pound sterling exchange rates. The loss from equity affiliates for 2003, 2002 and 2001 was primarily the result of the investment in the AVESTOR joint venture formed in 2001 to develop new lithium-metal-polymer batteries. The 2003 gain on sale of Devon stock resulted from the sale of approximately 1 million shares that were in excess of the total shares the company believes will be required to extinguish the debt exchangeable for common stock due in August 2004. The company sold its remaining Devon shares in January 2004 for a pretax gain of $9 million. All other Devon shares will be held through August 2004 in connection with the maturity of the debt exchangeable for common stock.
The effective tax rate for 2003 was 42.7%, compared with (7.0)% in 2002 and 36.7% in 2001. The 2003 effective rate is higher than the U.S. statutory rate primarily due to the impact of taxation on foreign operations. The 2002 tax benefit was reduced from the U.S. statutory rate due to the deferred tax effect of $132 million for the 33% increase in the U.K. corporate tax rate for oil and gas companies, together with the impact of taxation on foreign operations.
- -------------------------------------------------------------------------------- Segment Operations
Operating profit (loss) from each of the company's segments is summarized in the following table:
(Millions of dollars) 2003 2002 2001 - --------------------------------------------------------------------------------
Operating profit (loss) - Exploration and production $1,002 $(140) $922 ------ ----- ---- Chemicals - Pigment (13) 24 (22) Other (35) (23) (17) ------ ----- ---- Total Chemicals (48) 1 (39) ------ ----- ----
Operating profit (loss) $ 954 $(139) $883 ====== ===== ====
Exploration and Production
Revenues - Revenues, production statistics and average prices received from sales of crude oil, condensate and natural gas are shown in the following table:
(Millions of dollars, except per-unit amounts) 2003 2002 2001 - --------------------------------------------------------------------------------
Revenues - Crude oil and condensate sales $1,426 $1,531 $1,560 Natural gas sales 1,156 819 833 Gas marketing activities 298 70 22 Other 43 30 13 ------ ------ ------ Total $2,923 $2,450 $2,428 ====== ====== ======
Production - Crude oil and condensate (thousands of barrels per day) 150 191 189 Natural gas (MMcf per day) 726 760 596
Total equivalent barrels of oil (thousands of barrels per day) 271 318 288
Average Prices - Crude oil and condensate (per barrel) (1) $26.04 $22.04 $22.60 Natural gas (per Mcf) (1) $ 4.37 $ 2.95 $ 3.83
(1) Includes the results of the company's oil and gas commodity hedging program, which began in 2002. In 2003, hedges reduced the average sales price of crude oil and natural gas sold by $2.46 per barrel and $.55 per Mcf, respectively. In 2002, hedge activity reduced the average sales price of crude oil and natural gas sold by $1.13 per barrel and $.01 per Mcf, respectively.
Oil sales revenues declined $105 million in 2003 compared with 2002, primarily as a result of lower production due to the divestiture of various properties. This 21% decrease in oil production was partially offset by higher realized prices. The average realized price for oil increased $4 per barrel, adding $220 million to oil revenues, while lower oil production reduced revenues by $325 million.
The 2003 oil production decline was primarily due to the sale of various noncore properties during 2003 and 2002. The company began a divestiture program in mid-2002 to improve the overall quality of its asset portfolio, targeting high-operating-cost, noncore assets. The program was completed in 2003. Property sales were concentrated in the U.S. onshore region, Gulf of Mexico shelf and the U.K. North Sea, as well as Ecuador and the South China Sea. After adjusting for divestitures, 2003 oil production was approximately the same as 2002.
Oil sales revenues for 2002 declined $29 million compared with 2001, primarily driven by lower realized prices of $.56 per barrel. The 2002 oil production volumes remained relatively flat compared with 2001.
Natural gas sales revenues increased $337 million in 2003, primarily as a result of a $1.42 per Mcf increase in the average realized price for natural gas, partially offset by a 5% decline in production volumes. Higher realized prices increased revenue by $374 million, while lower gas production reduced revenues by $37 million. Production declines resulted primarily from property divestitures concentrated mainly in the U.S onshore and Gulf of Mexico shelf areas. After adjusting for divestitures, 2003 gas production volumes declined by 2% compared with 2002.
Natural gas sales revenue decreased $14 million in 2002 compared with 2001. Lower 2002 realized prices of $.88 per Mcf resulted in a revenue decline of $243 million that was partially offset by an increase of $229 million due to higher sales volumes. In 2002, gas sales volumes increased 28% or 164 MMcf/day over the 2001 levels, primarily due to a full year of gas production from the Wattenberg field in Colorado, which was acquired in August 2001.
The variances in revenues from gas marketing activities are discussed in the Gas Marketing Activities section below.
Operating Costs and Expenses - Operating costs and expenses relating to the sale of crude oil, condensate and natural gas are shown in the following table.
(Millions of dollars) 2003 2002 2001 - --------------------------------------------------------------------------------
Lease operating expense $ 334 $ 448 $ 368 Production taxes 52 67 74 ------ ------ ------ Total lifting costs 386 515 442
Transportation expense 94 84 71 Depreciation, depletion and amortization 609 690 619 Accretion expense (abandonment obligations) 25 - - General and administrative expense 127 87 72 Exploration expense 354 273 210 Impairments on assets held for use 14 646 47 Loss (gain) associated with assets held for sale (45) 176 - Gas gathering, pipeline and other 66 61 28 ------ ------ ------ Total operating cost and expenses $1,630 $2,532 $1,489 ====== ====== ======
Lease Operating Expense - During 2003, lease operating expense decreased 25% or $114 million compared with 2002. On a per-unit basis, lease operating expense decreased by about 13% to $3.37 per barrel of oil equivalent (BOE) sold in 2003 from $3.87 per BOE in 2002. Lower costs were primarily related to the divestiture of noncore, high-operating-cost properties. Lease operating expense increased $80 million in 2002 compared with 2001, resulting in costs of $3.87 and $3.50 per BOE, respectively. Higher lease operating expense in 2002 was the result of new production from the Nansen and Boomvang fields in the deepwater Gulf of Mexico and from a full year of production from the Leadon field in the U.K. North Sea, which commenced production in late 2001. A full year of operating expenses from the Wattenberg field (acquired in August 2001) also contributed to the increase.
Production Taxes - During 2003, production taxes decreased by $15 million, primarily due to the elimination of royalty payments in the U.K. North Sea area and lower production volumes. These factors were partially offset by higher commodity prices as production taxes are generally based on sales revenue.
Production taxes in 2002 decreased by $7 million compared with 2001 as a result of lower commodity prices (primarily natural gas prices), partially offset by higher sales volumes.
Transportation Expense - Transportation costs, representing the costs paid to third-party providers to transport oil and gas production, increased $10 million during 2003. Transportation costs in 2002 reflected a $13 million increase over 2001 levels. The increase for both periods resulted from transportation costs associated with new deepwater Gulf of Mexico producing fields such as Boomvang, Nansen and Navajo as well as increased costs in the U.K North Sea area. In addition, 2002 transportation costs include a full year of costs associated with the Wattenberg field.
Depreciation, Depletion and Amortization - Depreciation, depletion and amortization (DD&A) expense decreased $81 million in 2003, representing a 12% decline compared with 2002. The decrease in DD&A expense is primarily the result of production declines associated with the divestiture program that began in mid-2002 and asset impairments that were recorded in 2002 (primarily the Leadon field). On a per-unit basis, DD&A increased 3% to $6.16 per BOE in 2003 from $5.97 per BOE in 2002. Although total DD&A expense was lower, higher unit costs resulted from the company's divestiture activity and the overall mix of producing properties between 2003 and 2002. In accordance with accounting standards, depreciation was not recorded for various assets that were designated as held-for-sale in 2003 and 2002, although production quantities for these properties continued to be included in the calculation of total unit DD&A.
DD&A expense in 2002 was $71 million higher than in 2001. This increase was primarily due to higher production in 2002. On a per-unit basis, DD&A expense increased to $5.97 per BOE in 2002 from $5.89 per BOE in 2001. The increase in unit costs was due primarily to higher DD&A rates for various new fields that were brought on production in late 2002 and 2001, including the Nansen and Boomvang fields in the Gulf of Mexico as well as the Leadon field in the U.K. North Sea. In addition, a full year of production from the Wattenberg field (acquired in August 2001) contributed to the increase.
Accretion Expense - Accretion expense of $25 million in 2003 is related to the company's discounted abandonment liability recognized in 2003 as a result of implementing FAS 143.
General and Administrative Expenses - General and administrative (G&A) expenses were $40 million higher in 2003 compared with 2002. This resulted from $27 million of nonrecurring employee severance and related costs in 2003 associated with the company's work-force reduction plan. Additionally, the company incurred higher costs associated with employee benefits and the pension plan, as well as lower billings of costs on operated properties to partners. These costs were partially offset by lower costs for direct labor and contract services.
G&A expense in 2002 was $15 million higher than in 2001, primarily as a result of higher contract services and increased labor and benefits costs.
Exploration Expense - Exploration expense in 2003 was $81 million higher than in 2002 primarily as a result of higher dry hole costs from increased exploration activity during the year. In addition, staffing levels were increased during 2003 to support the company's worldwide exploration efforts and continued development of the company's high-potential prospect inventory.
Exploration expense in 2002 increased $63 million compared with the prior year primarily as a result of higher dry hole costs from increased exploration activity during the year. In addition, higher amortization expense for nonproducing leaseholds and increased costs for geological and geophysical projects contributed to the increase.
Impairments on held-for-use assets and the gain or loss on assets held for sale have been discussed in the Statement of Operations Comparisons section above.
Gas Marketing Activities - In the Rocky Mountain region, Kerr-McGee purchases third-party natural gas for aggregation and sale with the company's own production from the Wattenberg field in Colorado. In addition, Kerr-McGee has purchased transportation capacity to markets in the Midwest to facilitate sale of its natural gas outside the immediate vicinity of its production. This activity began with the company's acquisition of HS Resources in August 2001 and has increased since that time. Revenues (from sale of third-party gas) and associated gas purchase cost relating to gas marketing activities are shown in the following table.
(Millions of dollars) 2003 2002 2001 - --------------------------------------------------------------------------------
Gas marketing revenues $ 298 $ 70 $ 22 Gas purchase costs (including transportation) (291) (58) (17) ------ ------ ----- Net marketing margin $ 7 $ 12 $ 5 ====== ====== =====
Marketing volumes (thousand MMBtu/day) 178 77 29 ------ ------ -----
Marketing revenues increased $228 million in 2003 compared with 2002 primarily due to higher purchase and resale of natural gas in the Rocky Mountain area and higher natural gas prices. Gas purchase costs increased proportionately for the same period, an increase of $233 million.
Marketing revenues increased $48 million in 2002 compared with 2001, primarily as a result of a full year of marketing activity in the Rocky Mountain area after the HS Resources acquisition. Gas purchase costs also increased in 2002 by $41 million in proportion to the higher level of marketing activity.
Chemicals
Chemical revenues, operating profit (loss) and pigment production volumes are shown in the following table:
(Millions of dollars) 2003 2002 2001 - --------------------------------------------------------------------------------
Revenues - Pigment $1,079 $ 995 $ 931 Other 183 201 196 ------ ------ ------ Total $1,262 $1,196 $1,127 ====== ====== ======
Operating profit (loss) - Pigment $ (13) $ 24 $ (22) Other (35) (23) (17) ------ ------ ------ Total $ (48) $ 1 $ (39) ====== ====== ======
Titanium dioxide pigment production (thousands of tonnes) 532 508 483
Pigment - Revenues increased $84 million, or 8%, in 2003 to $1.079 billion from $995 million in 2002. Of the total increase, $94 million resulted from an increase in average sales prices, partially offset by a $10 million decrease due to lower sales volumes. The increase in average sales prices in 2003 was largely due to the effect of foreign currency exchange rates. Excluding the effect of foreign currency exchange rates, average selling prices in local currencies for 2003 were 3% higher than in 2002. Sales volumes for 2003 were approximately 1% lower than in the prior year.
Titanium dioxide pigment revenues for 2002 increased $64 million, or 7%, over 2001, resulting from a $149 million increase due to higher sales volume, combined with an offsetting decrease of $85 million resulting from weaker sales prices in 2002, of which $13 million was due to the effect of foreign currency exchange rates. While poor overall market conditions persisted through the first quarter of 2002, product demand increased through the remainder of the year. As demand accelerated, the company announced multiple price increases through the second half of 2002.
The chemical - pigment operating unit recorded an operating loss of $13 million in 2003, compared with operating profit of $24 million in 2002. The $94 million increase in revenues due to higher sales prices was partially offset by an increase in average product costs of $51 million and an increase in shipping and handling costs and selling, general and administrative costs of $18 million over 2002. Additionally, operating results in 2003 were impacted by $47 million in plant closure provisions related to the synthetic rutile plant in Mobile, Alabama, together with a $23 million charge for work-force reduction and other compensation costs. The $47 million shutdown provision for the Mobile operations included $6 million for curtailment costs related to pension and postretirement benefits. The 2002 operating profit included $12 million in charges for abandoned chemical engineering projects, $3 million for severance and other costs and a $5 million reversal of environmental reserves associated with the Savannah operations.
Operating profit for 2002 improved $46 million over 2001. Higher 2002 sales volume, combined with lower average per-unit production costs, increased operating profit by $57 million, offset by reductions due to lower sales prices of $85 million. Shipping and handling costs and selling, general and administrative costs decreased $5 million from 2001. In addition, the 2002 operating profit included a provision of $12 million related to abandoned chemical engineering projects, a $5 million reversal of environmental reserves, and $3 million for severance and other costs, compared with provisions in 2001 for closure of a pigment plant in Belgium, asset impairments, severance and other costs totaling $79 million.
Other - Operating loss for 2003 was $35 million on revenues of $183 million, compared with operating loss of $23 million on revenues of $201 million in 2002. Of the decrease in sales, $27 million resulted from lower forest products sales, partially offset by a $9 million increase in electrolytic operations sales volumes. The increased volumes were predominantly achieved in sodium chlorate and boron products, 17% and 37%, respectively. The $12 million increase in operating loss for 2003 was primarily due to 2003 work-force reduction and other compensation charges of $8 million and higher electrolytic product costs of $8 million, partially offset by lower environmental costs of $5 million. Environmental provisions in both 2003 and 2002 related primarily to ammonium perchlorate remediation associated with the company's Henderson, Nevada, operations (See Note 16). The 2003 operating results were also negatively affected by an operating loss of $12 million from the forest products operations, which includes shutdown provisions of $14 million, compared with a 2002 operating loss of $10 million, which included $23 million for shutdown and impairment provisions. The 2003 forest products shutdown provision of $14 million included $8 million for curtailment costs related to pension and postretirement benefits.
Operating loss for 2002 was $23 million on revenues of $201 million, compared with operating loss of $17 million on revenues of $196 million in 2001. The increase in operating loss was primarily due to 2002 provisions for the shutdown and impairment of the forest products business of $23 million and environmental provisions of $15 million, compared with 2001 provisions of $25 million for the termination of manganese metal production and $5 million for severance and asset impairment charges.
During the third quarter of 2003, Kerr-McGee Chemical LLC placed its electrolytic manganese dioxide (EMD) manufacturing operation in Henderson, Nevada, on standby to reduce inventory levels because of the harmful effect of low-priced imports on the company's EMD business. In response to the pricing activities of importing companies, Kerr-McGee Chemical LLC filed a petition for the imposition of anti-dumping duties with the U.S. Department of Commerce International Trade Administration and the U.S. International Trade Commission on July 31, 2003. In its petition, the company alleged that manufacturers in certain countries export EMD to the United States in violation of the U.S. anti-dumping laws and requested that the U.S. Department of Commerce apply anti-dumping duties to the EMD imported from such countries. The Department of Commerce found probable cause to believe that manufacturers in the specified countries engaged in dumping and initiated an anti-dumping investigation with respect to such manufacturers. Partly as a result of the anti-dumping petition, demand for U.S. EMD product increased, and the plant resumed operations in December 2003. The company withdrew its anti-dumping petition in February 2004 but will continue to monitor market conditions.
- -------------------------------------------------------------------------------- Financial Condition
(Millions of dollars) 2003 2002 2001 - --------------------------------------------------------------------------------
Current ratio 0.8 to 1 0.8 to 1 1.2 to 1 Total debt $3,655 $3,904 $4,574 Total debt less cash (net debt) 3,513 3,814 4,483 Total debt less cash and DECS 3,187 3,496 4,173 Stockholders' equity $2,636 $2,536 $3,174 Net debt to total capitalization 57% 60% 59% Total debt less cash and DECS to total capitalization 55% 58% 57% Floating-rate debt to total debt (including fixed-rate debt with interest rate swap to variable rate) 14% 16% 28%
The negative working capital at the end of 2003 and 2002 is not indicative of a lack of liquidity as the company maintains sufficient current assets to settle current liabilities when due. Current asset balances are minimized as one way to finance capital expenditures and lower borrowing costs. If needed, the company also has unused lines of credit and revolving credit facilities as discussed in the Liquidity section that follows.
Kerr-McGee operates with the philosophy that over a five-year plan period the company's capital expenditures and dividends should be paid from cash generated by operations. On a cumulative basis, the cash generated from operations for the past five years has exceeded the company's capital expenditures and dividend payments. Debt and equity transactions are utilized for acquisition opportunities and short-term needs due to timing of cash flow.
(Percentages) 2003 2002 2001 - -------------------------------- ---- ---- ---- Net Debt to Total Capitalization 57% 60% 59%
(Net debt to total capitalization is total debt less cash divided by total debt less cash plus stockholders' equity.)
A reduction in net debt of $301 million from 2002, combined with an increase in stockholders' equity of $100 million resulted in a 3% improvement in the percentage of net debt to total capitalization as compared to 2002. The company's goal is to reduce its percentage of net debt to total capitalization to 50% or below by the end of 2004. Although debt was reduced $670 million from 2001 to 2002, a decrease in equity resulting primarily from the 2002 net loss and dividends declared resulted in a slightly higher percentage of net debt to total capitalization in 2002 compared with 2001.
Cash Flow
(Millions of dollars) 2003 2002 2001 - ----------------------------------- ------ ------ ------ Cash Flow from Operating Activities $1,518 $1,448 $1,143
(Cash flow from operating activities has increased significantly over the past two years.)
Cash flow from operating activities increased $70 million, from $1.448 billion in 2002 to $1.518 billion in 2003, primarily due to an increase in income excluding noncash items, partially offset by changes in various working capital items. Year-end 2003 cash was $142 million, compared with $90 million at December 31, 2002.
The company invested $1.2 billion in its 2003 capital program, which included $181 million of unsuccessful exploratory drilling costs. The capital program for 2003 was $110 million lower than in the prior year, resulting primarily from lower capital expenditures in the North Sea, Rocky Mountain and U.S. onshore regions, partially offset by higher capital expenditures in the Gulf of Mexico and China and higher dry hole costs. During 2003, the company completed the divestiture of several oil and gas properties and other assets, generating proceeds of $304 million. These proceeds were used primarily to pay down debt. The company also invested $110 million in selected oil and gas property acquisitions related to the acquisition of an additional interest in the U.K. Gryphon and South Gryphon fields and an onshore property acquisition in South Texas. Cash outlays for investing activities include a $34 million investment by the chemical unit in AVESTOR, its lithium-metal-polymer battery joint venture in Canada. Other investing cash inflows included $47 million in proceeds related to the sale of Devon stock.
(Millions of dollars) 2003 2002 2001 - ----------------------------------- ------ ------ ------ Total Debt $3,655 $3,904 $4,574
(From year-end 2001 to 2003, the company reduced total debt by more than $900 million.)
During 2003, the company reduced its variable interest rate commercial paper by $68 million. Other debt was reduced $301 million, which included repayment of current year borrowings on revolving credit facilities of $31 million. Included in the total 2003 repayments of $301 million is $64 million related to open-market repurchases of long-term debt issuances on which the company recorded a loss of $7 million for early extinguishment in other expense in the Consolidated Statement of Operations. However, by executing the open-market repurchases, the company will avoid approximately $10 million in future interest expense. The company added $75 million in debt at December 31, 2003, due to the consolidation of the Kerr-McGee Gunnison Trust. This synthetic lease arrangement was restructured to an operating lease arrangement in January 2004, and the related debt will no longer be reflected on the company's balance sheet. The consolidation, which resulted in a noncash increase in debt and property, is discussed in more detail in the Off-Balance Sheet Arrangements section below. Cash flow was used to pay the company's dividends of $181 million in 2003.
As of December 31, 2003, the company's senior unsecured debt was rated BBB by Standard & Poor's and Fitch and Baa3 by Moody's. See Note 9 for details of the company's debt. At December 31, 2001, the company's outstanding debt had increased significantly from prior-year levels to fund the acquisition of HS Resources and major development projects in the Gulf of Mexico and the North Sea. Throughout 2002 and 2003, the company aggressively pursued its strategy of divesting noncore, high-cost assets, the proceeds from which have been used primarily to reduce the company's outstanding debt. The company expects to further reduce debt by approximately $550 million during 2004 by using excess cash flows and by using Devon common stock to repay the $330 million face amount of debt exchangeable for Devon common stock (DECS) owned by the company.
Liquidity
The company believes that it has the ability to provide for its operational needs and its long- and short-term capital programs through its operating cash flow (partially protected by the company's hedging program), borrowing capacity and ability to raise capital. The company's primary source of funds has been from operating cash flow, which could be adversely affected by declines in oil, natural gas and pigment prices, all of which can be volatile as discussed in the preceding Outlook section. Should operating cash flows decline, the company may reduce its capital expenditures program, borrow under its commercial paper program, draw upon revolving credit facilities and/or consider selective long-term borrowings or equity issuances. Kerr-McGee's commercial paper programs are backed by the revolving credit facilities currently in place. Should the company's commercial paper or debt rating be downgraded, borrowing costs will increase, and the company may experience loss of investor interest in its debt instruments as evidenced by a reduction in the number of investors and/or amounts they are willing to invest.
At December 31, 2003, the company had unused lines of credit and committed amounts under revolving credit agreements totaling $1.4 billion. The company maintains two revolving credit agreements consisting of a five-year $650 million facility signed January 12, 2001, and a 364-day $700 million facility renewed on November 14, 2003. In addition, the company had other unused credit facilities of $50 million at December 31, 2003. Of the total of $1.4 billion, $870 million and $490 million can be used to support commercial paper borrowings in the U.S. and Europe, respectively, by certain wholly owned subsidiaries and are guaranteed by the parent company. The borrowings can be made in U.S. dollars, British pound sterling, euros or local European currencies. Interest for each of the revolving credit facilities and lines of credit is payable at varying rates.
The company holds derivative financial instruments that require margin deposits if unrealized losses exceed limits established with individual counterparty institutions. From time to time, the company may be required to advance cash to its counterparties to satisfy margin deposit requirements. No margin deposits were outstanding at December 31, 2003. Between January 1, 2004, and March 5, 2004, margin calls totaled $7 million; however, these amounts have since been refunded to the company.
At December 31, 2002, the company classified $68 million of its short-term obligations as long-term debt. The company has the intent and the ability, as evidenced by committed credit agreements, to refinance this type of debt on a long-term basis. The company's practice has been to continually refinance its commercial paper or draw on its backup facilities, while maintaining borrowing levels believed to be appropriate.
The company issued 5 1/2% notes exchangeable for common stock in August 1999, which allow each holder to receive between .85 and 1.0 share of Devon common stock or, at the company's option, an equivalent amount of cash at maturity in August 2004. As of February 27, 2004, Devon common stock was trading at $56.78 per share. Embedded options in the DECS provide the company a floor price on Devon's common stock of $33.19 per share (the put option). The company also has the right to retain up to 15% of the shares if Devon's stock price is greater than $39.16 per share (the DECS holders have an embedded call option on 85% of the shares). If Devon's stock price at maturity is greater than $33.19 per share but less than $39.16 per share, the company's right to retain Devon stock will be reduced proportionately. The company is not entitled to retain any Devon stock if the price of Devon stock at maturity is less than or equal to $33.19 per share. Using the Black-Scholes valuation model, the company recognizes any gains or losses resulting from changes in the fair value of the put and call options in other income. The fluctuation in the value of the put and call derivative financial instruments will generally offset the increase or decease in the market value of the Devon stock classified as trading. The remaining Devon shares, accounted for as available-for-sale securities, were partially liquidated in December 2003, with the remaining shares sold in January 2004. The available-for-sale Devon shares were in excess of the number of shares the company believes will be required to extinguish the DECS; however, should the price of the stock fall below $39.16 per share at the maturity of the DECS, the company would be required to either purchase additional Devon shares to settle the DECS or settle a portion of the DECS with cash.
The company also has available, to issue and sell, a total of $1.65 billion of debt securities, common or preferred stock, or warrants under its shelf registration with the Securities and Exchange Commission, which was last updated in February 2002.
Off-Balance Sheet Arrangements
During 2001 and 2000, the company identified certain financing needs that it determined would be best handled by off-balance sheet arrangements with unconsolidated, special-purpose entities. Three leasing arrangements were entered into for financing the company's working interest obligations for production platforms and related equipment at three company-operated fields in the Gulf of Mexico. Also, the company entered into an accounts receivable monetization program to sell its receivables from certain pigment customers. Each of these transactions has provided specific financing for the company's business needs and/or projects and does not expose the company to significant additional risks or commitments. The leases have provided a tax-efficient method of financing a portion of these major development projects, and the sale of the pigment receivables offers an attractive low-cost source of liquidity.
During 2001, the company entered into a leasing arrangement for its interest in the production platform and related equipment for the Gunnison field in the Garden Banks area of the Gulf of Mexico. This leasing arrangement is similar to two arrangements entered into in 2000 for the Nansen and Boomvang fields in the East Breaks area of the Gulf of Mexico. In each of these three arrangements, the company entered into lease commitments with separate business trusts that were created to construct independent spar production platforms for each field development. Under the terms of the agreements, the company's share of construction costs for the platforms was initially financed by synthetic lease credit facilities between the trust and groups of financial institutions for $149 million, $137 million and $78 million for Gunnison, Nansen and Boomvang, respectively, with the company making lease payments sufficient to pay interest at varying rates on the financings. Upon completion of the construction phase, separate business trusts with third-party equity participants acquired the assets and became the lessor/owner of the platforms and related equipment. The company and these trusts have entered into operating leases for the use of the spar platform and related equipment. During 2002, the Nansen and Boomvang synthetic leases were converted to operating lease arrangements upon completion of construction of the respective production platforms. Completion of the Gunnison platform occurred in December 2003, at which time a portion of the Gunnison synthetic lease was converted to an operating lease. The remaining portion of the Gunnison synthetic lease was converted to an operating lease on January 15, 2004. Under this type of financing structure, the company leases the platforms under operating lease agreements, and neither the platform assets nor the related debt is recognized in the company's Consolidated Balance Sheet. However, since only a portion of the Gunnison synthetic lease had been converted to an operating lease structure as of year-end, the remaining assets and liabilities of the synthetic lessor trust are consolidated in the company's Consolidated Balance Sheet at December 31, 2003, which includes $83 million in property, plant and equipment, $4 million in accrued liabilities, $75 million in long-term debt and $4 million in minority interest. The consolidation of the synthetic lessor trust occurred in connection with the adoption of a new accounting standard as discussed in the New/Revised Accounting Standards section below. Since the remaining portion of the Gunnison synthetic lease was converted to an operating lease structure in January, the related property and debt will not be reflected in the company's Consolidated Balance Sheet in 2004.
In conjunction with the operating lease agreements, the company has guaranteed that the residual values of the Nansen, Boomvang and Gunnison platforms at the end of the operating leases shall be equal to at least 10% of their fair market value at the inception of the lease. For Nansen and Boomvang, the guaranteed values are $14 million and $8 million, respectively, in 2022, and for Gunnison the guaranteed value is $15 million in 2024. Estimated future minimum annual rentals under these leases and the residual value guarantees are shown in the table of contractual obligations below.
In December 2000, the company began an accounts receivable monetization program for its pigment business through the sale of selected accounts receivable with a three-year, credit-insurance-backed asset securitization program. On July 30, 2003, the company restructured the existing accounts receivable monetization program to include the sale of receivables originated by the company's European chemical operations. The maximum available funding under the amended program is $165 million. In addition, certain other terms of the program have been modified as part of the restructuring. Under the terms of the program, selected qualifying customer accounts receivable may be sold monthly to a special-purpose entity (SPE), which in turn sells an undivided ownership interest in the receivables to a third-party multi-seller commercial paper conduit sponsored by an independent financial institution. The company sells, and retains an interest in, excess receivables to the SPE as over-collateralization for the program. The company's retained interest in the SPE's receivables is recorded in trade accounts receivable in the Consolidated Balance Sheet. The retained interest is subordinate to, and provides credit enhancement for, the conduit's ownership interest in the SPE's receivables, and is available to the conduit to pay certain fees or expenses due to the conduit, and to absorb credit losses incurred on any of the SPE's receivables in the event of termination. However, the company believes that the risk of credit loss is very low since its bad-debt experience has historically been insignificant. The company also holds preference stock in the special-purpose entity equal to 3.5% of the receivables sold. The preference stock is essentially a retained deposit to provide further credit enhancements, if needed, but is otherwise recoverable by the company at the end of the program. The company records a loss on the receivable sales equal to the difference in the cash received plus the fair value of the retained interests and the carrying value of the receivables sold. The fair value of the retained interests (servicing fees, excess receivables and preference stock of the SPE) is based on the discounted present value of future cash flows. At year-end 2003 and 2002, the outstanding balance on receivables sold under the program totaled $165 million and $111 million, respectively.
During 2003 and 2002, the company entered into sale-leaseback arrangements with General Electric Capital Corporation (GECC) covering assets associated with a gas-gathering system in the Rocky Mountain region. The lease agreements were entered into for the purpose of monetizing the related assets. The sales price for the 2003 equipment was $6 million. The sales price for the 2002 equipment was $71 million; however, an $18 million settlement obligation existed for equipment previously covered by the lease agreement, resulting in net cash proceeds of $53 million in 2002. The 2002 operating lease agreements have an initial term of five years, with two 12-month renewal options, and the company may elect to purchase the equipment at specified amounts after the end of the fourth year. The 2003 operating lease agreement has an initial term of four years, with two 12-month renewal options. In the event the company does not purchase the equipment and it is returned to GECC, the company guarantees a residual value ranging from $35 million at the end of the initial terms to $27 million at the end of the last renewal option. The company recorded no gain or loss associated with the GECC sale-leaseback agreements. Estimated future minimum annual rentals under this agreement and the residual value guarantee are shown in the table of contractual obligations below.
In conjunction with the company's 2002 sale of its Ecuadorean assets, which included the company's nonoperating interest in the Oleoducto de Crudos Pesados Ltd. (OCP) pipeline, the company has entered into a performance guarantee agreement with the buyer for the benefit of OCP. Under the terms of the agreement, the company guarantees payment of any claims from OCP against the buyer upon default by the buyer and its parent company. Claims would generally be for the buyer's proportionate share of construction costs of OCP; however, other claims may arise in the normal operations of the pipeline. Accordingly, the amount of any such future claims cannot be reasonably estimated. In connection with this guarantee, the buyer's parent company has issued a letter of credit in favor of the company up to a maximum of $50 million, upon which the company can draw in the event it is required to perform under the guarantee agreement. The company will be released from this guarantee when the buyer obtains a specified credit rating as stipulated under the guarantee agreement.
In addition, the company enters into certain indemnification agreements related to title claims, environmental matters, litigation and other claims. The company has recorded no material obligations in connection with its indemnification agreements.
Obligations and Commitments
In the normal course of business, the company enters into purchase obligations, contracts, leases and borrowing arrangements. The company has no debt guarantees for unrelated parties. As part of the company's project-oriented exploration and production business, Kerr-McGee routinely enters into contracts for certain aspects of a project, such as engineering, drilling, subsea work, etc. 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. Kerr-McGee's commitments and obligations as of December 31, 2003, are summarized in the following table:
(Millions of dollars) Payments due by period - -------------------------------------------------------------------------------- 2005 2007 After Type of Obligation Total 2004 -2006 -2008 2008 - ------------------ ------ ---- ------ ---- ------ Long-term debt (1) $3,580 $574 $ 767 $150 $2,089 Operating leases for Nansen, Boomvang and Gunnison 599 17 51 54 477 All other operating leases 342 33 80 66 163 Drilling rig commitments 9 9 - - - Purchase obligations - Ore contracts 477 168 235 74 - Gas purchase and transportation contracts 112 49 21 17 25 Other purchase obligations 405 128 158 67 52 Leased equipment residual value guarantees 72 - - 35 37 ------ ---- ------ ---- ------ Total $5,596 $978 $1,312 $463 $2,843 ====== ==== ====== ==== ======
(1) Excludes the $75 million of debt associated with the Gunnison Trust. As discussed above, the synthetic lease was restructured to an operating lease in January 2004. The related future minimum lease payments are included with operating leases for Gunnison.
- -------------------------------------------------------------------------------- Capital Spending
Capital expenditures are summarized as follows:
(Millions of dollars) Est. 2004 2003 2002 2001 - -------------------------------------------------------------------------------- Exploration and production, including dry hole costs $ 920 $1,050 $1,101 $1,629 Chemicals 95 97 86 153 Other, including discontinued operations 20 15 85 82 ------ ------ ------ ------ Total $1,035 $1,162 $1,272 $1,864 ====== ====== ====== ======
Capital spending, excluding acquisitions, totaled $4.3 billion in the three-year period ended December 31, 2003, and dividends paid totaled $535 million in the same three-year period, which compares with $4.1 billion of net cash provided by operating activities during the same period. During the three-year period, the company made one major acquisition -- the 2001 acquisition of HS Resources for $955 million cash plus common stock and assumed debt.
Kerr-McGee has budgeted approximately $1.035 billion for its capital program in 2004. Management anticipates that the 2004 capital program, dividends and debt reduction can be provided for through internally generated funds. The available capacity for borrowings may be used for selective acquisitions that support the company's growth strategy or to support the company's capital expenditure program should internally generated cash flow fall short in any one measurement period.
Oil and Gas
The company's exploration and production capital spending continues to be focused on global growth and deepwater projects. Successful exploration and appraisal drilling in the deepwater Gulf of Mexico has resulted in the development of three major projects during the last two years - Nansen (50% working interest), Boomvang (30%), and Gunnison (50%). The Red Hawk (50%) and Constitution (100%) projects currently under development are also in the deepwater Gulf of Mexico. Constitution will be developed with a truss spar, capitalizing on the success of the truss spar technology introduced at the Nansen, Boomvang and Gunnison fields, while Red Hawk is being developed using innovative cell spar technology. Red Hawk is expected to reach initial production in mid-2004, while Constitution is expected to reach first production by mid-2006. The company expects initial production at its Bohai Bay development by the end of 2004. Two Bohai Bay discoveries are being developed with a centrally located floating production, storage and offloading vessel, along with fixed platforms for dry wellheads. Kerr-McGee operates this development with a 40% working interest. Of the $920 million total budget for 2004, $330 million is allocated to the Gulf of Mexico, $180 million to the North Sea, $155 million to U.S. onshore, $125 million to other international projects, $10 million to technology enhancements and $120 million for dry hole costs. In addition, the company has budgeted approximately $130 million (excluding noncash amortization of nonproducing leasehold costs) for other exploration program expenses in 2004. The company's exploration program is expected to fund approximately 50 wells, with emphasis on balancing risks and potential rewards in both shallow and deep waters and U.S. onshore.
Chemicals
Capital expenditures for chemical operations are budgeted at $95 million for 2004. Process and technology improvements that increase productivity and enhance product quality will account for approximately 30% of the 2004 capital budget. This includes the remaining estimated expenditures related to the high-productivity oxidation line that began production in January 2004 at the Savannah, Georgia, chloride-process pigment plant. Chemical has also budgeted $38 million of additional investment in AVESTOR for 2004.
- -------------------------------------------------------------------------------- Market Risks
The company is exposed to a variety of market risks, including credit risks, the effects of movements in foreign currency exchange rates, interest rates and certain commodity prices. The company addresses its risks through a controlled program of risk management that includes the use of insurance and derivative financial instruments. See Notes 1 and 18 for additional discussions of the company's financial instruments, derivatives and hedging activities.
Foreign Currency Exchange Rate Risk
The U.S. dollar is the functional currency for the company's international operations, except for its European chemical operations, for which the euro is the functional currency. Periodically, the company enters into forward contracts to buy and sell foreign currencies. Certain of these contracts (purchases of Australian dollars and British pound sterling, and sales of euro) have been designated and have qualified as cash flow hedges of the company's anticipated future cash flow needs for a portion of its capital expenditures, raw material purchases and operating costs. These contracts generally have durations of less than three years. The resulting changes in fair value of these contracts are recorded in accumulated other comprehensive income.
Selected pigment receivables have been sold in an asset securitization program at their equivalent U.S. dollar value at the date the receivables were sold. The company is collection agent and retains the risk of foreign currency rate changes between the date of sale and collection of the receivables. Under the terms of the asset securitization agreement, the company is required to enter into forward contracts for the value of the euro-denominated receivables sold into the program to mitigate its foreign currency risk. Gains or losses on the forward contracts are recognized currently in earnings. The company has entered into other forward contracts to sell foreign currencies, which will be collected as a result of pigment sales denominated in foreign currencies, primarily in European currencies. These contracts have not been designated as hedges even though they do protect the company from changes in foreign currency rates.
Following are the notional amounts at the contract exchange rates, weighted-average contractual exchange rates and estimated contract values for open contracts at year-end 2003 and 2002 to purchase (sell) foreign currencies. Contract values are based on the estimated forward exchange rates in effect at year-end. All amounts are U.S. dollar equivalents.
Interest Rate Risk
The company's exposure to changes in interest rates relates primarily to long-term debt obligations. The table below presents principal amounts and related weighted-average interest rates by maturity date for the company's long-term debt obligations outstanding at year-end 2003. All borrowings are in U.S. dollars.
(1) Includes fixed-rate debt with interest rate swap to variable rate.
At December 31, 2002, long-term debt included fixed-rate debt of $3.286 billion (fair value - $3.706 billion) with a weighted-average interest rate of 6.67% and $618 million of variable-rate debt, which approximated fair value, with a weighted-average interest rate of 2.56%.
In connection with the issuance of $350 million 5.375% notes due April 15, 2005, the company entered into an interest rate swap arrangement in 2002. The terms of the agreement effectively change the interest the company will pay on the debt until maturity from the fixed rate to a variable rate of LIBOR plus .875%. The company considers the swap to be a hedge against the change in fair value of the debt as a result of interest rate changes. The estimated fair value of the interest rate swap was $15 million at December 31, 2003.
During February 2004, the company reviewed the composition of its outstanding debt and entered into additional interest rate swaps, converting an aggregate of $566 million in fixed-rate debt to variable-rate debt. Under the interest rate swaps, $150 million of 6.625% notes due October 15, 2007, will pay a variable rate of LIBOR plus 3.35%; $109 million of 8.125% notes due October 15, 2005, will pay a variable rate of LIBOR plus 5.86%; and $307 million of 5.875% notes due September 15, 2006, will pay a variable rate of LIBOR plus 3.1%. The interest rate swaps have been designated as hedges against changes in the fair value of the related debt resulting from interest rate changes. The estimated fair value of the interest rate swaps, including the original swap outstanding at December 31, 2003, totaled $21 million as of February 29, 2004.
Commodity Price Risk
The company is exposed to market risk from fluctuations in crude oil and natural gas prices. To increase the predictability of its cash flows and to support capital projects, the company initiated a hedging program in 2002 and periodically enters into financial derivative instruments that generally fix the commodity prices to be received for a portion of its oil and gas production in the future. At December 31, 2003, the outstanding commodity-related derivatives accounted for as hedges had a liability fair value of $168 million, which is recorded as a current liability. The fair value of these derivative instruments at December 31, 2003, was determined based on prices actively quoted, generally NYMEX and Dated Brent prices. At December 31, 2003, the company had after-tax deferred losses of $106 million in accumulated other comprehensive income associated with these contracts. The company expects to reclassify the entire amount of these losses into earnings during the next 12 months, assuming no further changes in fair market value of the contracts. During 2003, the company realized a $71 million loss on U.S. oil hedging, a $64 million loss on North Sea oil hedging and a $144 million loss on U.S. natural gas hedging. During 2002, the company realized a $28 million loss on U.S. oil hedging, a $50 million loss on North Sea oil hedging and a $2 million loss on U.S. natural gas hedging. The losses offset the higher oil and natural gas prices realized on the physical sale of crude oil and natural gas. Losses for hedge ineffectiveness are recognized as a reduction of revenue in the Consolidated Statement of Operations and were not material for 2003 or 2002.
At December 31, 2003, the following commodity-related derivative contracts were outstanding:
Daily Average Contract Type (1) Period Volume Price - --------------------------------------------------------------------------------
Natural Gas MMBtu $/MMBtu - ----------- ------- ------- Fixed-price swaps (NYMEX) Q1 - 2004 195,000 $5.33 Q2 - 2004 565,000 $4.74 Q3,4 - 2004 575,000 $4.75
Costless collars (NYMEX) Q1 - 2004 360,000 $4.79 - $6.47
Basis swaps (CIG and Northwest) Q1 - 2004 135,000 $0.57 Q2,3 - 2004 55,000 $0.47 Q4 - 2004 41,739 $0.38
Crude Oil Bbl $/Bbl - --------- ------ ------ Fixed-price swaps (WTI) Q1 - 2004 48,000 $28.57 Q2 - 2004 48,000 $27.65 Q3 - 2004 45,000 $27.29 Q4 - 2004 30,000 $26.96
Fixed-price swaps (Brent) Q1 - 2004 45,000 $26.38 Q2 - 2004 46,500 $25.86 Q3 - 2004 39,750 $25.98 Q4 - 2004 32,000 $25.65
(1) These contracts may be subject to margin calls above certain limits established with individual counterparty institutions.
After December 31, 2003, the following derivative contacts were added to the company's 2004 hedging program and, combined with the hedges outstanding at December 31, 2003, cover approximately 80% of expected 2004 worldwide crude oil and condensate production, and 75% of the U.S. natural gas production.
Daily Average Contract Type (1) Period Volume Price - --------------------------------------------------------------------------------
Crude Oil Bbl $/Bbl - --------- ------ ------ Fixed-price swaps (WTI) Q1 - 2004 4,352 $34.13 Q2 - 2004 6,300 $32.67 Q3 - 2004 5,915 $31.18 Q4 - 2004 20,015 $30.28
Fixed-price swaps (Brent) Q1 - 2004 4,286 $30.77 Q2 - 2004 5,300 $29.92 Q3 - 2004 7,100 $29.07 Q4 - 2004 20,000 $28.41
(1) These contracts may be subject to margin calls above certain limits established with individual counterparty institutions.
In addition to the company's hedging program, Kerr-McGee Rocky Mountain Corp. holds certain gas basis swaps settling between 2004 and 2008. Through December 2003, the company treated these gas basis swaps as non-hedge derivatives, and changes in fair value were recognized in earnings. On December 31, 2003, the company designated those swaps settling in 2004 as hedges since the basis swaps have been coupled with natural gas fixed-price swaps, while the remainder settling between 2005 and 2008 will continue to be treated as non-hedge derivatives. At December 31, 2003, these derivatives are recorded at their fair value of $23 million, of which $8 million is recorded as a current asset and $15 million is recorded in investments - other assets. At December 31, 2002, these derivatives were recorded at their fair value of $21 million in investments - other assets. The net gains associated with these non-hedge derivatives were $2 million, $8 million and $27 million in 2003, 2002 and 2001, respectively, and are included in other income in the Consolidated Statement of Operations.
The company's marketing subsidiary, Kerr-McGee Energy Services (KMES), markets natural gas (primarily equity gas) in the Denver area. Existing contracts for the physical delivery of gas at fixed prices have not been designated as hedges and are marked to market in accordance with FAS 133. KMES has also entered into natural gas swaps and basis swaps that offset its fixed-price risk on physical contracts. These derivative contracts lock in the margins associated with the physical sale. The company believes that risk associated with these derivatives is minimal due to the credit-worthiness of the counterparties. The net asset fair value of these derivative instruments was not material at year-end 2003 and 2002. The fair values of the outstanding derivative instruments at December 31, 2003, were based on prices actively quoted. During 2003, the net loss associated with these derivative contracts totaled $12 million, of which $7 million is included as a reduction of revenue and $5 million is included in other income. For 2002 and 2001, the net loss associated with these derivative contracts totaled $20 million and $24 million, respectively, and is included as a reduction of revenue in the Consolidated Statement of Operations. The losses on the derivative contracts are substantially offset by the fixed prices realized on the physical sale of the natural gas.
- -------------------------------------------------------------------------------- Critical Accounting Policies
Preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates, judgments and assumptions regarding matters that are inherently uncertain and that ultimately affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. However, the accounting principles used by the company generally do not impact the company's reported cash flows or liquidity. Generally, accounting rules do not involve a selection among alternatives, but involve a selection of the appropriate policies for applying the basic principles. Interpretation of the existing rules must be done and judgments made on how the specifics of a given rule apply to the company.
The more significant reporting areas impacted by management's judgments and estimates are assessment of unproved oil and gas properties for impairment, crude oil and natural gas reserve estimation, site dismantlement and asset retirement obligations, recoverability of assets, environmental remediation, derivative instruments, litigation, tax accruals, and benefit plans. Management's judgments and estimates in these areas are based on information available from both internal and external sources, including engineers, legal counsel, actuaries, environmental studies and historical experience in similar matters. Actual results could differ materially from those estimates as additional information becomes known.
Successful Efforts Method of Accounting
The company has elected to use the successful efforts method of accounting for its oil and gas exploration and development activities. Exploration expenses, including geological and geophysical costs, rentals, and exploratory dry holes, are charged against income as incurred. Costs of successful wells and related production equipment and developmental dry holes are capitalized and amortized by field using the unit-of-production method as oil and gas is produced. The successful efforts method reflects the inherent volatility in exploring for and producing oil and gas. The accounting method may yield significantly different operating results than the full-cost method.
Under the successful efforts method, the costs of drilling an exploratory well are capitalized pending determination of whether proved reserves can be attributed to the discovery. In the case of onshore wells and offshore wells in relatively shallow water, that determination usually can be made upon or shortly after cessation of drilling operations. However, such determination may take longer depending on, among other things, the amount of hydrocarbons encountered, results of future appraisal drilling and proximity to existing infrastructure - especially in the case of deepwater and international exploration. As a consequence, the company has capitalized costs associated with exploratory wells on its balance sheet at any point in time that may be charged to earnings in a future period if management determines that commercial quantities of hydrocarbons have not been discovered. At December 31, 2003, the company had capitalized costs of approximately $143 million associated with such ongoing exploration activities, primarily in the deepwater Gulf of Mexico and China.
Oil and Gas Reserves and Standardized Measure of Future Cash Flows
The estimates of oil and gas reserves and associated future net cash flows are prepared by the company's geologists and engineers. Only proved oil and gas reserves are included in any financial statement disclosure. The U.S. Securities and Exchange Commission has defined proved reserves as the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Even though the company's geologists and engineers are knowledgeable and follow authoritative guidelines for estimating reserves, they must make a number of subjective assumptions based on professional judgments in developing the reserve estimates. Reserve estimates are updated at least annually and consider recent production levels and other technical information about each field. Revisions in the estimated reserves and future cash flows may be necessary due to a number of factors, including reservoir performance, new drilling, oil and gas prices and cost changes, technological advances, new geological or geophysical data, or other economic factors. See Notes 32 and 33 to the Consolidated Financial Statements for information concerning historical changes in reserve estimates and standardized measure of future cash flows for each of the last three years. The company cannot predict the amounts or timing of future reserve revisions.
Depreciation and depletion rates are calculated using both reserve quantity estimates and the capitalized costs of producing properties. As the estimated reserves are adjusted, the depreciation and depletion expense for a property will change, assuming no change in production volumes or the costs capitalized. Estimated reserves also are used as the basis for calculating the expected future cash flows from a property, which are further used to analyze a property for potential impairment. In addition, reserves are used to estimate the company's supplemental disclosure of the standardized measure of discounted future net cash flows relating to its oil and gas producing activities. Changes in estimated reserves are considered changes in estimates for accounting purposes and are reflected on a prospective basis.
Site Dismantlement and Asset Retirement Obligations
The company has significant obligations for the dismantlement and removal of its oil and gas production and related facilities. Estimating future asset removal costs is difficult and requires management to make estimates and judgments since most of the removal activities will occur several years in the future. Asset removal technologies and costs are constantly changing, as are political, environmental, safety and public relations considerations that may ultimately impact the amount of the obligation. In June 2001, the FASB issued FAS 143, "Accounting for Asset Retirement Obligations," which the company adopted on January 1, 2003. The impact of this new standard is discussed below in the New/Revised Accounting Standards section.
Impairment of Assets
All long-lived assets are assessed for potential impairment when events or changes in circumstances indicate that the carrying value of the asset may be greater than its future net cash flows. The evaluations involve a significant amount of judgment since the results are based on estimated future events, such as future sales prices for oil, gas or chemicals; future costs to produce these products; estimates of future oil and gas reserves to be recovered; development costs and the timing thereof; the economic and regulatory climates; and other factors. The need to test a property for impairment may result from significant declines in sales prices, unfavorable adjustments to oil and gas reserves, increases in operating costs, and changes in environmental or abandonment regulations. Assets held for sale are reviewed for potential loss on sale when the company approves the plan to sell and thereafter while the asset is held for sale. Losses are measured as the difference between fair value less costs to sell, and the assets' carrying value. Estimates of anticipated sales prices are highly judgmental and subject to material revision in future periods. Goodwill is tested annually for impairment, or more frequently if impairment indicators arise. The company completed its annual test for impairment of goodwill and indefinite-lived intangible assets as of June 30, 2003, with no impairment loss indicated. The company cannot predict when or if future impairment charges for held-for-use assets, goodwill or intangibles, or losses associated with held-for-sale properties will be recorded.
Derivative Instruments
The company is exposed to risk from fluctuations in crude oil and natural gas prices, foreign currency exchange rates, and interest rates. To reduce the impact of these risks on earnings and to increase the predictability of its cash flow, from time to time the company enters into certain derivative contracts, primarily swaps and collars for a portion of its oil and gas production, forward contracts to buy and sell foreign currencies, and interest rate swaps. The company accounts for all its derivative instruments, including hedges, in accordance with FAS 133, "Accounting for Derivative Instruments and Hedging Activities." The commodity, foreign currency and interest rate contracts are measured at fair value and recorded as assets or liabilities in the Consolidated Balance Sheet. When available, quoted market prices are used in determining fair value; however, if quoted market prices are not available, the company estimates fair value using either quoted market prices of financial instruments with similar characteristics or other valuation techniques. The counterparties to these contractual arrangements generally are limited to major institutions.
Environmental Remediation, Litigation and Other Contingency Reserves
Kerr-McGee management makes judgments and estimates in accordance with applicable accounting rules when it establishes reserves for environmental remediation, litigation and other contingent matters. Provisions for such matters are charged to expense when it is probable that a liability has been incurred and reasonable estimates of the liability can be made. It is not possible for management to reliably estimate the amount and timing of all future expenditures related to environmental, legal or other contingent matters because of continually changing laws and regulations, inherent uncertainties associated with court and regulatory proceedings as well as cleanup requirements and related work, the possible existence of other potentially responsible parties, and the changing political and economic environment. For these reasons, actual environmental, litigation and other contingency costs can vary significantly from the company's estimates. For additional information about contingencies, refer to the Environmental Matters section that follows and Note 16.
Tax Accruals
The company has operations in several countries around the world and is subject to income and other similar taxes in these countries. The estimation of the amounts of income tax to be recorded by the company involves interpretation of complex tax laws and regulations, evaluation of tax audit findings, and assessment of how the foreign taxes affect domestic taxes. Although the company's management believes its tax accruals are adequate, differences may occur in the future, depending on the resolution of pending and new tax matters.
Benefit Plans
The company provides defined benefit retirement plans and certain nonqualified benefits for employees in the U.S., U.K., Germany and the Netherlands and accounts for these plans in accordance with FAS 87, "Employers' Accounting for Pensions." The various assumptions used and the attribution of the costs to periods of employee service are fundamental to the measurement of net periodic cost and pension obligations associated with the retirement plans.
One of the significant assumptions used to account for the company's pension plans is the expected long-term rate of return on plan assets. The expected long-term rate of return forecasting methodology is based on a capital asset pricing model using historical data. Based on this information, the company selected 8.5% for 2003 and 2004 for U.S. pension plans.
Another significant assumption for pension plan accounting is the discount rate. The company selects a discount rate as of December 31 each year for U.S. plans to reflect average rates available on high-quality fixed income debt instruments during December of that year. The average Moody's Long-Term AA Corporate Bond Yield for December is used as a guide in the selection of the discount rate for U.S. pension plans. For December 2002, the average Moody's Long-Term AA Corporate Bond Yield was 6.63%, and the company chose 6.75% as its discount rate at the end of 2002. For December 2003, the average Moody's Long-Term AA Corporate Bond Yield was 6.04%, and the company chose 6.25% as its discount rate at the end of 2003. This decrease in the discount rate effective December 31, 2003, is expected to increase 2004 net periodic pension cost by $5 million but not affect expected contributions to fund the pension plans.
The rate of compensation increase is another significant assumption used in the development of accounting information for pension plans. The company determines this assumption based on its long-term plans for compensation increases and current economic conditions. Based on this information, the company selected 4.5% at December 31, 2002 and 2003, for U.S. pensions plans.
The net effect the U.S. pension plans had on results of operations for 2003 was $32 million of income due to the expected return on assets exceeding other pension charges. The total expected return on assets of the U.S. pension plans for 2003 was $117 million, compared with an actual return of $189 million. During 2003, the company's contributions to the retirement plans totaled $5 million for certain U.S. nonqualified plans and foreign plans.
When calculating expected return on plan assets for U.S. pension plans, the company uses a market-related value of assets that spreads asset gains and losses (differences between actual return and expected return) over five years. As of January 1, 2004, the amount of unrecognized losses on U.S. pension assets was $188 million. As these losses are recognized during future years in the market-related value of assets, they will result in cumulative increases in net periodic pension cost of $16 million in 2005 through 2008.
A 25 basis point increase/decrease in the company's expected long-term rate of return assumption as of the beginning of 2004 would decrease/increase net periodic pension cost for U.S. pension plans for 2004 by $3 million. The change would not affect expected contributions to fund the company's U.S. pension plans.
The company also provides certain postretirement health care and life insurance benefits and accounts for the related plans in accordance with FAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions." The postretirement benefit cost and obligation are also dependent on the company's assumptions used in the actuarially determined amounts. These assumptions include discount rates (discussed above), health care cost trend rates, inflation rates, retirement rates, mortality rates and other factors. The health care cost trend assumptions are developed based on historical cost data, the near-term outlook and an assessment of likely long-term trends. Assumed inflation rates are based on an evaluation of external market indicators. Retirement and mortality rates are based primarily on actual plan experience. See Note 24 for a discussion of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 as it relates to the company's postretirement health care plan.
The above description of the company's critical accounting policies is not intended to be an all-inclusive discussion of the uncertainties considered and estimates made by management in applying accounting principles and policies. Results may vary significantly if different policies were used or required and if new or different information becomes known to management.
- -------------------------------------------------------------------------------- Environmental Matters
The company's affiliates are subject to various environmental laws and regulations in the United States and in foreign countries in which they operate. Under these laws, the company's affiliates are or may be required to obtain or maintain permits and/or licenses in connection with their operations. In addition, under these laws, the company's affiliates are or may be required to remove or mitigate the effects on the environment due to the disposal or release of certain chemical, petroleum, low-level radioactive and other substances at various sites. Environmental laws and regulations are becoming increasingly stringent, and compliance costs are significant and will continue to be significant in the foreseeable future. There can be no assurance that such laws and regulations or any environmental law or regulation enacted in the future will not have a material effect on the company's operations or financial condition.
Sites at which the company's affiliates have environmental responsibilities include sites that have been designated as Superfund sites by the U.S. Environmental Protection Agency (EPA) pursuant to the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA), as amended, and that are included on the National Priority List (NPL). As of December 31, 2003, the company's affiliates had received notices that they had been named potentially responsible parties (PRP) with respect to 13 existing EPA Superfund sites on the NPL that require remediation. The company does not consider the number of sites for which its affiliates have been named a PRP to be the determining factor when considering the company's overall environmental liability. Decommissioning and remediation obligations, and the attendant costs, vary substantially from site to site and depend on unique site characteristics, available technology and the regulatory requirements applicable to each site. Additionally, the company's affiliates may share liability at some sites with numerous other PRPs, and the law currently imposes joint and several liability on all PRPs under CERCLA. The company's affiliates are also obligated to perform or have performed remediation or remedial investigations and feasibility studies at sites that have not been designated as Superfund sites by EPA. Such work is frequently undertaken pursuant to consent orders or other agreements.
Current Businesses
The company's oil and gas affiliates are subject to numerous international, federal, state and local laws and regulations relating to environmental protection. In the United States, these include the Federal Water Pollution Control Act, commonly known as the Clean Water Act, the Clean Air Act and the Resource Conservation and Recovery Act (RCRA). These laws and regulations govern, among other things, the amounts and types of substances and materials that may be released into the environment; the issuance of permits in connection with exploration, drilling and production activities; the release of emissions into the atmosphere; and the discharge and disposition of waste materials. Environmental laws and regulations also govern offshore oil and gas operations, the implementation of spill prevention plans, the reclamation and abandonment of wells and facility sites, and the remediation and monitoring of contaminated sites. The company's chemical affiliates are subject to a broad array of international, federal, state and local laws and regulations relating to environmental protection, including the Clean Water Act, the Clean Air Act, CERCLA and RCRA. These laws require the company's affiliates to undertake various activities to reduce air emissions, eliminate the generation of hazardous waste, decrease the volume of wastewater discharges and increase the efficiency of energy use.
Discontinued Businesses
The company's affiliates historically have held interests in various businesses in which they are no longer engaged or which they intend to exit. Such businesses include the refining and marketing of oil and gas and associated petroleum products, the mining and processing of uranium and thorium, the production of ammonium perchlorate, and other activities. Additionally, the company expects to complete its exit from the forest products business by the end of 2004. Although the company's affiliates are no longer engaged in certain businesses or have announced their intention to exit certain businesses, residual obligations may still exist, including obligations related to compliance with environmental laws and regulations, including the Clean Water Act, the Clean Air Act, CERCLA and RCRA. These laws and regulations require company affiliates to undertake remedial measures at sites of current or former operations or at sites where waste was disposed. For example, company affiliates are required to conduct decommissioning and environmental remediation at certain refineries, distribution facilities and service stations they owned and/or operated before exiting the refining and marketing business in 1995. Company affiliates also are required to conduct decommissioning and remediation activities at sites where they were involved in the exploration, production, processing and/or sale of uranium or thorium. Additionally, the company's chemical affiliate may be required to decommission and remediate its wood-treatment facilities as part of its plan to exit the forest products business.
Environmental Costs
Expenditures for environmental protection and cleanup for each of the last three years and for the three-year period ended December 31, 2003, are as follows:
(Millions of dollars) 2003 2002 2001 Total - -------------------------------------------------------------------------------- Charges to environmental reserves $104 $128 $142 $374 Recurring expenses 19 37 57 113 Capital expenditures 18 22 21 61 ---- ---- ---- ---- Total $141 $187 $220 $548 ==== ==== ==== ====
In addition to past expenditures, reserves have been established for the remediation and restoration of active and inactive sites where it is probable that future costs will be incurred and the liability is reasonably estimable. For environmental sites, the company considers a variety of matters when setting reserves, including the stage of investigation; whether EPA or another relevant agency has ordered action or quantified cost; whether the company has received an order to conduct work; whether the company participates as a PRP in the Remedial Investigation/Feasibility Study (RI/FS) process and, if so, how far the RI/FS has progressed; the status of the record of decision by the relevant agency; the status of site characterization; the stage of the remedial design; evaluation of existing remediation technologies; the number and financial condition of other potential PRPs; and whether the company reasonably can evaluate costs based upon a remedial design and/or engineering plan.
After the remediation work has begun, additional accruals or adjustments to costs may be made based on any number of developments, including revisions to the remedial design; unanticipated construction problems; identification of additional areas or volumes of contamination; inability to implement a planned engineering design or to use planned technologies and excavation methods; changes in costs of labor, equipment and/or technology; any additional or updated engineering and other studies; and weather conditions.
As of December 31, 2003, the company's financial reserves for all active and inactive sites totaled $259 million. This includes $105 million added in 2003 for active and inactive sites. In the Consolidated Balance Sheet, $161 million of the total reserve is classified as a deferred credit, and the remaining $98 million is included in current liabilities. Management believes that currently the company has reserved adequately for the reasonably estimable costs of known environmental contingencies. However, additional reserves may be required in the future due to the previously noted uncertainties. Additionally, there may be other sites where the company has potential liability for environmental-related matters but for which the company does not have sufficient information to determine that the liability is probable and/or reasonably estimable. The company has not established reserves for such sites.
The following table reflects the company's portion of the known estimated costs of investigation and/or remediation that are probable and estimable. The table summarizes EPA Superfund NPL sites where the company and/or its affiliates have been notified it is a PRP under CERCLA and other sites for which the company had some ongoing financial involvement in investigation and/or remediation at year-end 2003. In the table, aggregated information is presented for certain sites that are individually not significant (having a remaining reserve balance of less than $10 million) or for which the company has not recorded a reserve because the liability is not probable and/or reasonably estimable. Amounts reported in the table for the West Chicago sites are not reduced for actual or expected reimbursement from the U.S. government under Title X of the Energy Policy Act of 1992 (Title X), described in Note 16 to the Consolidated Financial Statements, which financial statements are included in Item 8. of this Form 10-K.
The company has not recorded in the financial statements potential reimbursements from governmental agencies or other third parties, except for amounts due from the U.S. government under Title X for costs incurred by the company on its behalf and recoveries under certain insurance policies. If recoveries from third parties, other than recovery from the U.S. government under Title X and recoveries under certain insurance policies, become probable, they will be disclosed but will not generally be recorded in the financial statements until received.
Sites specifically identified in the table above are discussed in Note 16 to the Consolidated Financial Statements, which financial statements are included in Item 8. of this Form 10-K. Any discussion in Note 16 of the West Chicago, Illinois; Henderson, Nevada; Milwaukee, Wisconsin; Cushing, Oklahoma; and Mobile, Alabama, sites is incorporated herein by reference and made fully a part hereof.
- -------------------------------------------------------------------------------- New/Revised Accounting Standards
In June 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (FAS) No. 143, "Accounting for Asset Retirement Obligations." FAS 143 requires that an asset retirement obligation (ARO) associated with the retirement of a tangible long-lived asset be recognized as a liability in the period in which it is incurred or becomes determinable (as defined by the standard), with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the initially recognized asset retirement cost, is depreciated over the useful life of the asset. The ARO is recorded at fair value, and accretion expense will be recognized over time as the discounted liability is accreted to its expected settlement value. The fair value of the ARO is measured using expected future cash outflows discounted at the company's credit-adjusted risk-free interest rate.
The company adopted FAS 143 on January 1, 2003, which resulted in an increase in net property of $108 million, an increase in abandonment liabilities of $161 million and a decrease in deferred income tax liabilities of $18 million. The net impact of these changes resulted in an after-tax charge to earnings of $35 million to recognize the cumulative effect of retroactively applying the new accounting principle. In accordance with the provisions of FAS 143, Kerr-McGee accrues an abandonment liability associated with its oil and gas wells and platforms when those assets are placed in service, rather than its past practice of accruing the expected abandonment costs on a unit-of-production basis over the productive life of the associated oil and gas field. No market risk premium has been included in the company's calculation of the ARO for oil and gas wells and platforms since no reliable estimate can be made by the company. In connection with the change in accounting principle, abandonment expense of $40 million in 2002 and $34 million in 2001 has been reclassified from costs and operating expenses to depreciation and depletion in the Consolidated Statement of Operations to be consistent with the 2003 presentation. In January 2003, the company announced its plan to close the synthetic rutile plant in Mobile, Alabama, and closed the plant in June 2003. Since the plant had a determinate closure date, the company accrued an abandonment liability of $18 million associated with its plans to decommission the Mobile facility in connection with the adoption of FAS 143.
In November 2002, the FASB issued FASB Interpretation (FIN) No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others - an Interpretation of FASB Statements No. 5, 57, and 107 and Rescission of FASB Interpretation No. 34." For certain guarantees, FIN 45 requires recognition at the inception of a guarantee of a liability for the fair value of the obligation assumed in issuing the guarantee. FIN 45 also requires expanded disclosures for outstanding guarantees, even if the likelihood of the guarantor having to make any payments under the guarantee is considered remote. The recognition provisions of FIN 45 were effective for guarantees issued or modified after December 31, 2002. The company has not issued or modified any material guarantees within the scope of FIN 45 during 2003; therefore, implementation of this new standard has not impacted its consolidated financial condition or results of operations.
In January 2003, the FASB issued FIN No. 46, "Consolidation of Variable Interest Entities - an Interpretation of ARB No. 51." This interpretation clarifies the application of ARB 51, "Consolidated Financial Statements," to certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. Because application of the majority voting interest requirement in ARB 51 may not identify the party with a controlling financial interest in situations where controlling financial interest is achieved through arrangements not involving voting interests, this interpretation introduces the concept of variable interests and requires consolidation by an enterprise having variable interests in a previously unconsolidated entity if the enterprise is considered the primary beneficiary, meaning the enterprise will absorb a majority of the variable interest entity's expected losses or residual returns. For variable interest entities in existence as of February 1, 2003, FIN 46, as originally issued, required consolidation by the primary beneficiary in the third quarter of 2003. In October 2003, the FASB deferred the effective date of FIN 46 to the fourth quarter.
In accordance with the provisions of FIN 46, the company has consolidated the business trust created to construct and finance the Gunnison production platform. Accordingly, the assets and liabilities of the trust are reflected in the company's Consolidated Balance Sheet at December 31, 2003, which includes $83 million in property, plant and equipment, $4 million in accrued liabilities, $75 million in long-term debt and $4 million in minority interest (See Notes 1 and 9). The company has reviewed the effects of FIN 46 relative to its other relationships with possible variable interest entities, such as the lessor trusts that are party to the Nansen and Boomvang operating leases and certain joint-venture arrangements, and has determined that consolidation of these entities is not required.
The company applies the provisions of FAS No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies," for the accounting of oil and gas mineral rights held by lease or contract and accordingly classifies these assets as property, plant and equipment. This classification is the long standing and current industry standard and is consistent with most mineral rights case law (that is, mineral rights generally are treated as interests in real property and real property laws are used to interpret the leases). However, the SEC has asked that the Emerging Issues Task Force (EITF) consider whether mineral rights are intangible assets under the guidance provided by FAS No. 141, "Business Combinations," and FAS No. 142, "Goodwill and Other Intangible Assets." If such interests are deemed to be intangible assets by the EITF, mineral rights to extract oil and gas for both undeveloped and developed leaseholds may be reclassified separately as intangible assets.
Even though management believes the company's current balance sheet classification is required under generally accepted accounting principles, reclassification may be necessary in the future when further guidance is provided by the EITF. However, it is not currently clear which mineral rights might have to be reclassified as intangible assets - all producing and nonproducing leaseholds, only nonproducing leaseholds or only leaseholds acquired in business combinations since the effective date of FAS No. 141. Any such reclassification would not affect the company's total assets, net worth, cash flows or results of operations. A reclassification could negatively impact one of the company's debt covenants and certain contractual obligations that require the company to maintain a certain level of tangible net worth, absent waiver or amendment of such provisions. These mineral rights would continue to be amortized in accordance with FAS No. 19. At December 31, 2003 and 2002, the company had total producing leasehold costs for mineral interests of approximately $1.6 billion, net of accumulated depletion and amortization, and nonproducing leasehold costs of approximately $.5 billion, net of accumulated depletion and amortization. Of these amounts, leasehold costs, net of accumulated depletion and amortization, acquired in business combinations since the effective date of FAS No. 141 were approximately $1.3 billion and $1.4 billion of producing leasehold costs at December 31, 2003 and 2002, respectively, and $.1 billion of nonproducing leasehold costs at both December 31, 2003 and 2002.
Item 7a.
Item 7a. Quantitative and Qualitative Disclosure about Market Risk
For information required under this section, reference is made to the "Market Risks" section of Management's Discussion and Analysis, which discussion is included in Item 7. of this Form 10-K.
Item 8.
Item 8. Financial Statements and Supplementary Data
Index to the Consolidated Financial Statements PAGE - ---------------------------------------------- ----
Responsibility for Financial Reporting 57 Report of Independent Auditors 58 Consolidated Statement of Operations for the years ended December 31, 2003, 2002 and 2001 59 Consolidated Statement of Comprehensive Income and Stockholders' Equity for the years ended December 31, 2003, 2002 and 2001 60 Consolidated Balance Sheet at December 31, 2003 and 2002 61 Consolidated Statement of Cash Flows for the years ended December 31, 2003, 2002 and 2001 62 Notes to Financial Statements 63
Index to Supplementary Data - ---------------------------
Ten-Year Financial Summary 117 Ten-Year Operating Summary 118
Index to the Financial Statement Schedules - ------------------------------------------
Schedule II - Valuation Accounts and Reserves 126
All other schedules are omitted because they are either not required, not significant, not applicable or the information is presented in the financial statements or the notes to the financial statements.
- -------------------------------------------------------------------------------- Responsibility for Financial Reporting
The company's management is responsible for the integrity and objectivity of the financial data contained in the financial statements. These financial statements have been prepared in conformity with generally accepted accounting principles appropriate under the circumstances and, where necessary, reflect informed judgments and estimates of the effects of certain events and transactions based on currently available information at the date the financial statements were prepared.
The company's management depends on the company's system of internal accounting controls to assure itself of the reliability of the financial statements. The internal control system is designed to provide reasonable assurance, at appropriate cost, that assets are safeguarded and transactions are executed in accordance with management's authorizations and are recorded properly to permit the preparation of financial statements in accordance with generally accepted accounting principles. Periodic reviews are made of internal controls by the company's staff of internal auditors, and corrective action is taken if needed.
The Board of Directors reviews and monitors financial statements through its audit committee, which is composed solely of directors who are not officers or employees of the company and who satisfy the independence requirements of the Securities and Exchange Commission and the New York Stock Exchange. The audit committee meets regularly with the independent auditors, internal auditors and management to review internal accounting controls, auditing and financial reporting matters.
The independent auditors are engaged to provide an objective and independent review of the company's financial statements and to express an opinion thereon. Their audits are conducted in accordance with generally accepted auditing standards, and their report is included below.
- -------------------------------------------------------------------------------- Report of Independent Auditors
The Board of Directors and Stockholders Kerr-McGee Corporation
We have audited the accompanying consolidated balance sheets of Kerr-McGee Corporation as of December 31, 2003 and 2002, and the related consolidated statements of operations, comprehensive income and stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2003. Our audits also included the financial statement schedule listed in the Index in Item 8. These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Kerr-McGee Corporation at December 31, 2003 and 2002, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
As discussed in Notes 1 and 13 to the consolidated financial statements, effective January 1, 2003, the Company adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations. As discussed in Notes 1, 9 and 17 to the consolidated financial statements, effective December 31, 2003, the Company adopted FASB Interpretation No. 46, Consolidation of Variable Interest Entities. As discussed in Notes 1 and 18 to the consolidated financial statements, effective January 1, 2001, the Company adopted Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities.
/s/ ERNST & YOUNG LLP
Oklahoma City, Oklahoma March 3, 2004
(1) The balance of the items in Accumulated Other Comprehensive Income (Loss) at December 31, 2003 and 2002, includes - unrealized gains on securities, $5 million and $6 million; fair value of cash flow hedges, $(88) million and $(57) million; foreign currency translation adjustments, $62 million and $6 million; and minimum pension liability, $(24) million and $(17) million, respectively.
The accompanying notes are an integral part of this statement.
The "successful efforts" method of accounting for oil and gas exploration and production activities has been followed in preparing this balance sheet.
The accompanying notes are an integral part of this balance sheet.
The accompanying notes are an integral part of this statement.
Notes to Financial Statements - --------------------------------------------------------------------------------
1. The Company and Significant Accounting Policies
Kerr-McGee is an energy and chemical company with worldwide operations. It explores for, develops, produces and markets crude oil and natural gas, and its chemical operations primarily produce and market titanium dioxide pigment. The exploration and production unit produces and explores for oil and gas in the United States, the United Kingdom sector of the North Sea and China. Exploration efforts also extend to Australia, Benin, Bahamas, Brazil, Gabon, Morocco, Western Sahara, Canada, Yemen and the Danish and Norwegian sectors of the North Sea. The chemical unit has production facilities in the United States, Australia, Germany and the Netherlands.
On August 1, 2001, the company completed the acquisition of all the outstanding shares of common stock of HS Resources, Inc., an independent oil and gas exploration and production company. To accomplish the acquisition, the company reorganized and formed a new holding company, Kerr-McGee Holdco, which later changed its name to Kerr-McGee Corporation. All the outstanding shares of the former Kerr-McGee Corporation were canceled and the same number of shares was issued by the new holding company. The former Kerr-McGee Corporation was renamed and is now a wholly owned subsidiary.
Basis of Presentation
The consolidated financial statements include the accounts of all subsidiary companies that are more than 50% owned, the proportionate share of joint ventures in which the company has an undivided interest and variable interest entities for which the company is considered the primary beneficiary. Investments in affiliated companies that are 20% to 50% owned are carried as investments - equity affiliates in the Consolidated Balance Sheet at cost adjusted for equity in undistributed earnings. Except for dividends and changes in ownership interest, changes in equity in undistributed earnings are included in the Consolidated Statement of Operations. All material intercompany transactions have been eliminated.
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates as additional information becomes known.
Discontinued operations in the consolidated financial statements represent the company's former oil and gas operations in Kazakhstan, Indonesia and Australia (see Note 21).
Variable Interest Entities
In January 2003, the Financial Accounting Standards Board (FASB) issued FASB Interpretation (FIN) No. 46, "Consolidation of Variable Interest Entities - an Interpretation of ARB No. 51." This interpretation clarifies the application of Accounting Research Bulletin (ARB) 51, "Consolidated Financial Statements," to certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. Because application of the majority voting interest requirement in ARB 51 may not identify the party with a controlling financial interest in situations where controlling financial interest is achieved through arrangements not involving voting interests, this interpretation introduces the concept of variable interests. Consolidation is required by an enterprise having variable interests in a previously unconsolidated entity if the enterprise is considered the primary beneficiary, meaning the enterprise will absorb a majority of the variable interest entity's expected losses or residual returns. For variable interest entities in existence as of February 1, 2003, FIN 46, as originally issued, required consolidation by the primary beneficiary in the third quarter of 2003. In October 2003, the FASB deferred the effective date of FIN 46 to December 31, 2003.
In accordance with the provisions of FIN 46, the company has consolidated the business trust created to construct and finance the Gunnison production platform. Accordingly, the assets and liabilities of the trust are reflected in the company's Consolidated Balance Sheet at December 31, 2003, which includes $83 million in property, plant and equipment, $4 million in accrued liabilities, $75 million in long-term debt and $4 million in minority interest (See Notes 9 and 17). The company has reviewed the effects of FIN 46 relative to its other relationships with possible variable interest entities, such as the lessor trusts that are party to the Nansen and Boomvang operating leases and certain joint-venture arrangements, and has determined that consolidation of these entities is not required.
Reclassifications
Certain prior year amounts have been reclassified to conform with the current year presentation.
In 2003, the company began reporting the net marketing fee received from sales of nonequity North Sea crude oil marketed on behalf of other partners in revenues. Prior to 2003, the company reported purchases and sales of nonequity crude oil on a gross basis. The company believes this change in reporting, which has no impact on net income, better reflects the economic substance of its North Sea marketing arrangements. For 2002 and 2001, the company has reclassified $54 million and $11 million, respectively, from costs and operating expenses to reduce revenues in the Consolidated Statement of Operations to conform with the 2003 presentation.
In connection with the adoption of the Statement of Financial Accounting Standards (FAS) No. 143, "Accounting for Asset Retirement Obligations," abandonment expense of $40 million for 2002 and $34 million for 2001 has been reclassified from costs and operating expenses to depreciation and depletion in the Consolidated Statement of Operations. This new standard is discussed in more detail below.
Foreign Currencies
The U.S. dollar is considered the functional currency for each of the company's international operations, except for its European chemical operations. Foreign currency transaction gains or losses are recognized in the period incurred and are included in other income (expense) in the Consolidated Statement of Operations. The company recorded net foreign currency transaction gains (losses) of $(41) million, $(38) million and $3 million in 2003, 2002 and 2001, respectively.
The euro is the functional currency for the European chemical operations. Translation adjustments resulting from translating the functional currency financial statements into U.S. dollar equivalents are reported separately in accumulated other comprehensive income in the Consolidated Statement of Comprehensive Income and Stockholders' Equity.
Cash Equivalents
The company considers all investments with a maturity of three months or less to be cash equivalents. Cash equivalents totaling $72 million in 2003 and $23 million in 2002 were comprised of time deposits, certificates of deposit and U.S. government securities.
Accounts Receivable and Receivable Sales
Accounts receivable are reflected at their net realizable value, reduced by an allowance for doubtful accounts to allow for expected credit losses. The allowance is estimated by management based on factors such as age of the related receivables and historical experience, giving consideration to customer profiles. The company does not generally charge interest on accounts receivable; however, certain operating agreements have provisions for interest and penalties that may be invoked if deemed necessary. Accounts receivable are aged in accordance with contract terms and are written off when deemed uncollectible. Any subsequent recoveries of amounts written off are credited to the allowance for doubtful accounts.
Under an asset securitization program, Kerr-McGee sells selected pigment customers' accounts receivable to a variable interest entity (VIE). The company does not own any of the common stock of the VIE. When the receivables are sold, Kerr-McGee retains an interest in excess receivables that serve as over-collateralization for the program and retains interests for servicing and in preference stock of the VIE. The interest in the preference stock is essentially a deposit to provide further credit enhancement to the securitization program, if needed, but is otherwise recoverable by the company at the end of the program. The servicing fee received is estimated by management to be adequate compensation and is equal to what would otherwise be charged by an outside servicing agent. The company records the loss associated with the receivable sales by comparing cash received and fair value of the retained interests to the carrying amount of the receivables sold. The estimate of fair value of the retained interests is based on the present value of future cash flows discounted at rates estimated by management to be commensurate with the risks.
Inventories
Inventories are stated at the lower of cost or market. The costs of the company's product inventories are determined by the first-in, first-out (FIFO) method. Inventory carrying values include material costs, labor and associated indirect manufacturing expenses. Costs for materials and supplies, excluding ore, are determined by average cost to acquire. Ore inventories are carried at actual cost.
Property, Plant and Equipment
Exploration and Production - Exploration expenses, including geological and geophysical costs, rentals and exploratory dry holes, are charged against income as incurred. Costs of drilling exploratory wells are capitalized pending determination of whether proved reserves can be attributed to the discovery. Capitalized costs associated with exploratory wells may be charged to earnings in a future period if management determines that commercial quantities of hydrocarbons have not been discovered. At December 31, 2003, the company had capitalized costs of approximately $143 million associated with such ongoing exploration activities, primarily in the deepwater Gulf of Mexico and China. Costs of successful wells and related production equipment and developmental dry holes are capitalized and amortized by field using the unit-of-production method as the oil and gas are produced.
Undeveloped acreage costs are capitalized and amortized at rates that provide full amortization on abandonment of unproductive leases. Costs of abandoned leases are charged to the accumulated amortization accounts, and costs of productive leases are transferred to the developed property accounts.
Other - Property, plant and equipment is stated at cost less reserves for depreciation, depletion and amortization. Maintenance and repairs are expensed as incurred, except that costs of replacements or renewals that improve or extend the lives of existing properties are capitalized.
Depreciation and Depletion - Property, plant and equipment is depreciated or depleted over its estimated life by the unit-of-production or the straight-line method. Capitalized exploratory drilling and development costs are amortized using the unit-of-production method based on total estimated proved developed oil and gas reserves. Amortization of producing leasehold, platform costs, asset retirement costs and acquisition costs of proved properties is based on the unit-of-production method using total estimated proved reserves. In arriving at rates under the unit-of-production method, the quantities of recoverable oil, gas and other minerals are established based on estimates made by the company's geologists and engineers. Non-oil and gas assets are depreciated using the straight-line method over the estimated useful lives.
Retirements and Sales - The cost and related depreciation, depletion and amortization reserves are removed from the respective accounts upon retirement or sale of property, plant and equipment. The resulting gain or loss is included in other income (expense) in the Consolidated Statement of Operations.
Interest Capitalized - The company capitalizes interest costs on major projects that require an extended length of time to complete. Interest capitalized in 2003, 2002 and 2001 was $10 million, $8 million and $31 million, respectively.
Impairments on Assets Held for Use
Proved oil and gas properties are reviewed for impairment on a field-by-field basis when facts and circumstances indicate that their carrying amounts may not be recoverable. In performing this review, future cash flows are estimated by applying future oil and gas prices to future production quantities, less future expenditures necessary to develop and produce the reserves. If the sum of these estimated future cash flows (undiscounted and without interest charges) is less than the carrying amount of the property, an impairment loss is recognized for the excess of the carrying amount over the estimated fair value of the property based on estimated discounted future cash flows.
Other assets are reviewed for impairment by asset group for which the lowest level of independent cash flows can be identified and impaired in a similar manner as proved oil and gas properties.
Gain or Loss on Assets Held for Sale
Assets are classified as held for sale when management approves a plan of sale that is expected to be completed within one year. Upon transfer to the held-for-sale category, long-lived assets are no longer depreciated. Losses are measured at the time of transfer, and subsequently thereafter, as the difference between fair value less costs to sell and the assets' carrying value. Losses may be reversed up to the original carrying value as estimates are revised; however, any gain above the assets' carrying value at the date of transfer is only recognized upon disposition.
Revenue Recognition
Revenue is recognized when title passes to the customer. Natural gas sales revenues involving gas-balancing arrangements with partners are recognized when the gas is sold using the entitlements method of accounting and are based on the company's net working interests. At December 31, 2003 and 2002, both the quantity and dollar amount of gas-balancing arrangements were immaterial.
Income Taxes
Deferred income taxes are provided to reflect the future tax consequences of differences between the tax basis of assets and liabilities and their reported amounts in the financial statements.
Remediation, Restoration and Site Dismantlement Costs
As sites of environmental concern are identified, the company assesses the existing conditions, claims and assertions, generally related to former operations, and records an estimated undiscounted liability when environmental assessments and/or remedial efforts are probable and the associated costs can be reasonably estimated.
In June 2001, the FASB issued FAS No. 143, "Accounting for Asset Retirement Obligations." FAS 143 requires that an asset retirement obligation (ARO) associated with the retirement of a tangible long-lived asset be recognized as a liability in the period in which it is incurred or becomes determinable (as defined by the standard), with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the initially recognized asset retirement cost, is depreciated over the useful life of the asset. The ARO is recorded at fair value, and accretion expense will be recognized over time as the discounted liability is accreted to its expected settlement value. The fair value of the ARO is measured using expected future cash outflows discounted at the company's credit-adjusted risk-free interest rate.
The company adopted FAS 143 on January 1, 2003, which resulted in an increase in net property of $108 million, an increase in abandonment liabilities of $161 million and a decrease in deferred income tax liabilities of $18 million. The net impact of these changes resulted in an after-tax charge to earnings of $35 million to recognize the cumulative effect of adopting the new accounting standard. In addition, accretion expense of $25 million was recorded during 2003. In accordance with the provisions of FAS 143, Kerr-McGee accrues an abandonment liability associated with its oil and gas wells and platforms when those assets are placed in service, rather than its past practice of accruing the expected abandonment costs on a unit-of-production basis over the productive life of the associated oil and gas field. No market risk premium has been included in the company's calculation of the ARO for oil and gas wells and platforms since no reliable estimate can be made by the company. Additionally, in January 2003, the company announced its plan to close the synthetic rutile plant in Mobile, Alabama, and closed the plant in June 2003. Since the plant had a determinate closure date, the company accrued an abandonment liability of $18 million as of January 1, 2003, associated with its plans to decommission the Mobile facility. Otherwise, the company has not recognized an asset retirement obligation associated with its operating chemical facilities, since there is either no legal obligation or the life of such facilities is indeterminate.
If the provisions of FAS 143 had been applied retroactively, pro forma net loss for 2002 would have been $492 million, with basic and diluted loss per share of $4.91. Pro forma net income for 2001 would have been $484 million, with basic and diluted earnings per share of $4.98 and $4.72, respectively.
Employee Stock Option Plan
FAS 123, "Accounting for Stock-Based Compensation," prescribes a fair-value method of accounting for employee stock options under which compensation expense is measured based on the estimated fair value of stock options at the grant date and recognized over the period that the options vest. The company, however, chooses to account for its stock option plans under the optional intrinsic-value method of Accounting Principles Board Opinion (APB) No. 25, "Accounting for Stock Issued to Employees," whereby no compensation expense is generally recognized for fixed-price stock options.
If compensation expense for stock option grants had been determined in accordance with FAS 123, the resulting expense would have affected stock-based compensation expense, net income and per-share amounts as shown in the following table. These amounts may not be representative of future compensation expense using the fair-value method of accounting for employee stock options as the number of options granted in a particular year may not be indicative of the number of options granted in future years, and the fair-value method of accounting has not been applied to options granted prior to January 1, 1995.
(Millions of dollars, except per-share amounts) 2003 2002 2001 - --------------------------------------------------------------------------------
Net income (loss) as reported $ 219 $ (485) $ 486 Less stock-based compensation expense determined using a fair-value method, net of taxes (16) (15) (8) ----- ------ ----- Pro forma net income (loss) $ 203 $ (500) $ 478 ===== ====== =====
Net income (loss) per share - Basic - As reported $2.18 $(4.84) $5.01 Pro forma 2.03 (4.99) 4.92
Diluted - As reported 2.17 (4.84) 4.74 Pro forma 2.03 (4.99) 4.66
The fair value of each option granted in 2003, 2002 and 2001 was estimated as of the date of the grant using the Black-Scholes option pricing model with the following weighted-average assumptions:
Financial Instruments
Investments in marketable securities are classified as either "trading" or "available for sale," depending on management's intent. Unrecognized gains or losses on trading securities are recognized in earnings, while unrecognized gains or losses on available-for-sale securities are recorded as a component of other comprehensive income (loss) within stockholders' equity.
The company accounts for all its derivative financial instruments in accordance with FAS 133, "Accounting for Derivative Instruments and Hedging Activities." Derivative financial instruments are recorded as assets or liabilities in the Consolidated Balance Sheet, measured at fair value. When available, quoted market prices are used in determining fair value; however, if quoted market prices are not available, the company estimates fair value using either quoted market prices of financial instruments with similar characteristics or other valuation techniques.
The company uses futures, forwards, options, collars and swaps to reduce the effects of fluctuations in crude oil, natural gas, foreign currency exchange rates and interest rates. Gains or losses due to changes in the fair value of instruments that are designated as cash flow hedges and that qualify for hedge accounting under the provisions of FAS 133 are recorded in accumulated other comprehensive income (loss). These hedging gains or losses will be recognized in earnings in the periods during which the hedged forecasted transactions affect earnings. The ineffective portion of the change in fair value of such hedges, if any, is included in current earnings. Instruments that are not designated as hedges or that do not meet the criteria for hedge accounting and those designated as fair-value hedges under FAS 133 are recorded at fair value with gains or losses reported currently in earnings (together with offsetting gains or losses on the hedged item for fair value hedges).
On January 1, 2001, the company adopted FAS 133 by recording the fair value of the options associated with the company's debt exchangeable for stock (DECS) of Devon Energy Corporation (Devon). In adopting the standard, the company recognized an expense of $20 million as a cumulative effect of the accounting change and a $3 million reduction in equity (other comprehensive income) for the foreign currency contracts designated as hedges. Also, in accordance with FAS 133, the company chose to reclassify 85% of the Devon shares owned to "trading" from the "available for sale" category of investments as of January 1, 2001, and recognized after-tax income of $118 million for the unrealized appreciation on these shares.
Shipping and Handling Fees and Costs
All amounts billed to a customer in a sales transaction related to shipping and handling represent revenues earned and are reported as revenue. Costs incurred by the company for shipping and handling, including transportation costs paid to third-party shippers to transport oil and gas production, are reported as an expense.
Goodwill and Intangible Assets
In accordance with FAS 142, "Goodwill and Other Intangible Assets," which the company adopted on January 1, 2002, goodwill and certain indefinite-lived intangibles are not amortized but are reviewed annually for impairment, or more frequently if impairment indicators arise. The annual test for impairment was completed in the second quarter of 2003, with no impairment indicated for the $357 million of goodwill ($346 million, exploration and production; $11 million, chemical - pigment) or the $55 million of indefinite-lived intangible assets (chemical - pigment) associated with patented technology and other intellectual property. The company's net income for 2001 would not have been materially different had the indefinite-lived intangibles and goodwill not been amortized prior to adoption of FAS 142. Additionally, the company had immaterial amounts of intangibles subject to amortization ($19 million gross carrying value at December 31, 2003 and 2002; $9 million and $14 million net of accumulated amortization at December 31, 2003 and 2002, respectively).
2. Cash Flow Information
Net cash provided by operating activities reflects cash payments for income taxes and interest as follows:
(Millions of dollars) 2003 2002 2001 - --------------------------------------------------------------------------------
Income tax payments $115 $ 89 $434 Less refunds received (49) (268) (19) ---- ----- ---- Net income tax payments (refunds) $ 66 $(179) $415 ==== ===== ====
Interest payments $237 $ 258 $189 ==== ===== ====
Noncash items affecting net income included in the reconciliation of net income to net cash provided by operating activities include the following:
(Millions of dollars) 2003 2002 2001 - -------------------------------------------------------------------------------- Increase (decrease) in fair value of embedded options in the DECS (1) $ 88 $ 34 $(205) (Increase) decrease in fair value of trading securities (1) (96) (61) 7 Performance incentive provisions 33 16 27 Compensation expense for ESOP shares allocated to participants 32 14 14 Net periodic postretirement expense 30 21 18 Net losses on equity method investments 33 25 5 Litigation reserve provisions 7 72 - Net periodic pension credit for qualified plan (2) - (48) (53) All other (3) 17 27 (2) ---- ---- ----- Total $144 $100 $(189) ==== ==== =====
Details of other changes in current assets and liabilities and other within the operating section of the Consolidated Statement of Cash Flows are as follows:
(Millions of dollars) 2003 2002 2001 - -------------------------------------------------------------------------------- Environmental expenditures $(104) $(107) $(94) Cash abandonment expenditures - exploration and production (17) (48) (29) Employer contributions to postretirement plan (24) (18) (20) All other (3) (18) (24) (30) ----- ----- ----- Total $(163) $(197) $(173) ===== ===== =====
Information about noncash investing and financing activities not reflected in the Consolidated Statement of Cash Flows follows:
(1) See Notes 1 and 18 for discussion of FAS 133 adoption. (2) Net periodic pension credit for 2003 of $(38) million is reflected net of curtailment losses of $38 million. (3) No other individual item is material to total cash flows from operations. (4) See Note 1 for a discussion of the adoption of FIN 46.
3. Inventories
Major categories of inventories at year-end 2003 and 2002 are:
(Millions of dollars) 2003 2002 - --------------------------------------------------------------------------------
Chemicals and other products $307 $306 Materials and supplies 80 89 Crude oil and natural gas liquids 7 7 ---- ----
Total $394 $402 ==== ====
4. Investments - Other Assets
Investments in other assets consist of the following at December 31, 2003 and 2002:
(Millions of dollars) 2003 2002 - --------------------------------------------------------------------------------
Long-term receivables, net of allowance for doubtful notes of $9 in both 2003 and 2002 $101 $ 94 Derivatives (fixed-price and basis swap commodity contracts) 17 22 Other 7 11 ---- ----
Total $125 $127 ==== ====
5. Property, Plant and Equipment
Property, plant and equipment and related reserves at December 31, 2003 and 2002, are as follows:
The company applies the provisions of FAS No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies," for the accounting of oil and gas mineral rights held by lease or contract and accordingly classifies these assets as property, plant and equipment. This classification is the long standing and current industry standard and is consistent with most mineral rights case law (that is, mineral rights generally are treated as interests in real property and real property laws are used to interpret the leases). However, the U.S. Securities and Exchange Commission has asked that the Emerging Issues Task Force (EITF) consider whether mineral rights are intangible assets under the guidance provided by FAS No. 141, "Business Combinations," and FAS No. 142, "Goodwill and Other Intangible Assets." If such interests are deemed to be intangible assets by the EITF, mineral rights to extract oil and gas for both undeveloped and developed leaseholds may be reclassified separately as intangible assets.
Even though management believes the company's current balance sheet classification is required under generally accepted accounting principles, reclassification may be necessary in the future when further guidance is provided by the EITF. However, it is not currently clear which mineral rights might have to be reclassified as intangible assets - all producing and nonproducing leaseholds, only nonproducing leaseholds or only leaseholds acquired in business combinations since the effective date of FAS No. 141. Any such reclassification would not affect the company's total assets, net worth, cash flows or results of operations. A reclassification could negatively impact one of the company's debt covenants and certain contractual obligations that require the company to maintain a certain level of tangible net worth, absent waiver or amendment of such provisions. These mineral rights would continue to be amortized in accordance with FAS No. 19. At December 31, 2003 and 2002, the company had total producing leasehold costs for mineral interests of approximately $1.6 billion, net of accumulated depletion and amortization, and nonproducing leasehold costs of approximately $.5 billion, net of accumulated depletion and amortization. Of these amounts, leasehold costs, net of accumulated depletion and amortization, acquired in business combinations since the effective date of FAS No. 141 were approximately $1.3 billion and $1.4 billion of producing leasehold costs at December 31, 2003 and 2002, respectively, and $.1 billion of nonproducing leasehold costs at both December 31, 2003 and 2002.
6. Deferred Charges
Deferred charges are as follows at year-end 2003 and 2002:
(Millions of dollars) 2003 2002 - --------------------------------------------------------------------------------
Pension plan prepayments $243 $240 Nonqualified benefit plans deposits 35 35 Unamortized debt issue costs 22 27 Amounts pending recovery from third parties 8 13 Other 9 13 ---- ----
Total $317 $328 ==== ====
7. Accrued Liabilities
Accrued liabilities at year-end 2003 and 2002 are as follows:
(Millions of dollars) 2003 2002 - --------------------------------------------------------------------------------
Derivatives (1) $354 $135 Employee-related costs and benefits 141 103 Interest payable 109 105 Current environmental reserves 98 100 Asset retirement obligations (current portion) 20 - Litigation reserves 5 43 North Sea royalties - 13 Other 32 21 ---- ---- Total $759 $520 ==== ====
(1) Balance at December 31, 2003, includes the call option associated with the DECS of $155 million (See Note 18).
8. Work Force Reduction, Restructuring Provisions and Exit Activities
In September 2003, the company announced a program to reduce its U.S. nonbargaining work force through both voluntary retirements and involuntary terminations. As a result of the program, the company's eligible U.S. nonbargaining work force was reduced by approximately 9%, or 271 employees. Qualifying employees terminated under this program are eligible for enhanced benefits under the company's pension and postretirement plans, along with severance payments. The program was substantially completed by the end of 2003, with certain retiring employees staying into the first half of 2004 for transition purposes. In connection with the work force reduction, the company took a pretax charge of $56 million during 2003, of which $34 million was for curtailment and special termination benefits associated with the company's retirement plans and $22 million was for severance-related costs. The provision for severance-related costs is included in the restructuring reserve balance below. Of the severance-related provision of $22 million, $5 million has been paid through December 31, 2003, with $17 million remaining in the accrual to be paid in 2004.
The company closed its synthetic rutile plant in Mobile, Alabama, during June 2003. During the year, the company's chemical - pigment operating unit provided $24 million for costs associated with the closure of this facility. Included in this amount were $14 million recorded as a cumulative effect of change in accounting principle related to the recognition of an asset retirement obligation and $10 million for the accrual of severance benefits. The provision for severance benefits is included in the restructuring reserve balance below. See Note 1 for a discussion of the asset retirement obligation. Of the total severance provision of $10 million, $8 million was paid through the end of the year and $2 million remained in the accrual at December 31, 2003. Approximately 135 employees will ultimately be terminated in connection with this plant closure, of which 117 had been terminated as of December 31, 2003. Additionally, during 2003, the company recognized $15 million in accelerated depreciation on the plant assets, $6 million for curtailment costs and special termination benefits related to pension and postretirement plans, $8 million for cleanup and decommissioning costs associated with the plant, and $8 million for other shutdown costs.
During 2002, the company's chemical - other operating unit provided $17 million for costs associated with exiting its forest products business. During 2003, the company provided an additional $5 million associated with exiting the forest products business. Included in the total provision of $22 million were $16 million for dismantlement and closure costs, and $6 million for severance costs. These costs are reflected in costs and operating expenses in the Consolidated Statement of Operations. Of the total provision, $8 million was paid through December 31, 2003, and $14 million remained in the accrual as of year-end 2003. Of its five remaining forest products-treating plants, one has been closed, and three have ceased operations and are in the process of being dismantled. The company will continue to operate its fifth plant, a leased facility located in The Dalles, Oregon, through the term of the lease, which runs through November 30, 2004. In connection with the plant closures, 252 employees will be terminated, of which 163 were terminated as of year-end 2003. Additionally, during 2003, the company recognized $9 million for other shutdown related costs, including accelerated depreciation on plant assets, curtailment costs and special termination benefits related to pension and postretirement plans.
In 2001, the company's chemical - pigment operating unit provided $32 million related to the closure of a plant in Antwerp, Belgium. The provision consisted of $12 million for severance costs, $12 million for dismantlement costs, $7 million for contract settlement costs and $1 million for other plant closure costs. Of this total accrual, $5 million and $9 million remained in the restructuring accrual at the end of 2003 and 2002, respectively. As a result of this plant closure, 121 employees were identified for termination and all have been terminated as of December 31, 2003.
Also in 2001, the company's chemical - other operating unit provided $12 million for the discontinuation of manganese metal production at its Hamilton, Mississippi, facility. The provision consisted of $7 million for pond-closure costs, $2 million for severance costs and $3 million for other plant-closure costs. Of this total accrual, $1 million and $2 million remained in the restructuring accrual at the end of 2003 and 2002, respectively. As a result of this plant closure, 42 employees were terminated and all related severance costs were paid in 2001. Completion of the remaining action of pond closure may take from three to 10 years, depending on environmental constraints.
The provisions, payments, adjustments and reserve balances for 2003 and 2002 are included in the table below.
(1) Includes amounts in total provision that were charged directly to expense. (2) Includes foreign-currency translation adjustments related to Antwerp, Belgium, accrual.
9. Debt
Lines of Credit
At year-end 2003, the company had available unused bank lines of credit and revolving credit facilities of $1.4 billion. Of this amount, $870 million can be used to support commercial paper borrowing arrangements of Kerr-McGee Credit LLC, and $490 million can be used to support European commercial paper borrowings of Kerr-McGee (G.B.) PLC, Kerr-McGee Chemical GmbH, Kerr-McGee Pigments (Holland) B.V. and Kerr-McGee International ApS.
The company has arrangements to maintain compensating balances with certain banks that provide credit. At year-end 2003, the aggregate amount of such compensating balances was immaterial, and the company was not legally restricted from withdrawing all or a portion of such balances at any time during the year.
Long-Term Debt
The company's policy is to classify certain borrowings under revolving credit facilities and commercial paper as long-term debt since the company has the ability under certain revolving credit agreements and the intent to maintain these obligations for longer than one year. At year-end 2003 and 2002, debt totaling nil and $68 million, respectively, was classified as long-term consistent with this policy.
Long-term debt consisted of the following at year-end 2003 and 2002:
Future maturities of long-term debt as of December 31, 2003, are as follows:
(1) Of this amount, $326 million may be a noncash settlement of the DECS with distribution of the Devon stock.
The company's long-term debt agreements do not contain subjective acceleration clauses (commonly referred to as material adverse change clauses); however, certain of the company's long-term debt agreements contain restrictive covenants, including a minimum tangible net worth requirement and a maximum total debt to total capitalization ratio, as defined in the agreements. At December 31, 2003, the company was in compliance with its debt covenants. Except for the Gunnison Trust floating rate notes payable discussed below, all outstanding notes and debentures are unsecured.
During 2001, the company entered into a leasing arrangement with Kerr-McGee Gunnison Trust (Gunnison Trust) for the construction of the company's share of a platform to be used in the development of the Gunnison field, in which the company has a 50% working interest. Under the terms of the agreement, the company's share of construction costs for the platform has been financed under a five-year synthetic lease credit facility between the trust and groups of financial institutions for up to $157 million, with the company making lease payments sufficient to pay interest at varying rates on the notes. Construction of the platform was completed in December 2003, with the company's share of construction costs totaling $149 million. On December 31, 2003, $66 million of the synthetic lease facility was converted to a leveraged lease structure, whereby the company leases an interest in the platform under an operating lease agreement from a separate business trust.
Both the Gunnison Trust and the new operating lease trust are considered variable interest entities under the provisions of FIN 46. As such, the company is required to analyze its relationship with each trust to determine whether the company is the primary beneficiary, and thus required to consolidate the trusts. Based on the analyses performed, the company is not the primary beneficiary of the operating lease trust; however, the company is considered the primary beneficiary of the Gunnison Trust. Accordingly, the remaining assets and liabilities of the Gunnison Trust are reflected in the company's Consolidated Balance Sheet at December 31, 2003, which includes $83 million in property, plant and equipment, $4 million in accrued liabilities, $75 million in long-term debt, and $4 million in minority interest. The Gunnison Trust floating rate notes payable are secured by the platform assets of $83 million included in property and an assignment of the company's lease agreement with the Gunnison Trust. The $66 million of platform assets and related debt that was converted to the leveraged lease structure in December 2003 is not recognized in the company's Consolidated Balance Sheet at December 31, 2003. On January 15, 2004, the remaining $83 million of the synthetic lease facility was converted to the leveraged lease structure, and the related lessor trust will not be subject to consolidation. As a result, the related property and debt will not be reflected in the company's Consolidated Balance Sheet in 2004. The operating lease commitment is included in the Note 17 disclosure.
10. Asset Securitization
In December 2000, the company began an accounts receivable monetization program for its pigment business through the sale of selected accounts receivable with a three-year, credit-insurance-backed asset securitization program. On July 30, 2003, the company restructured the existing accounts receivable monetization program to include the sale of receivables originated by the company's European chemical operations. The maximum available funding under the amended program is $165 million. In addition, certain other terms of the program have been modified as part of the restructuring. Under the terms of the program, selected qualifying customer accounts receivable may be sold monthly to a special-purpose entity (SPE), which in turn sells an undivided ownership interest in the receivables to a third-party multi-seller commercial paper conduit sponsored by an independent financial institution. The company sells, and retains an interest in, excess receivables to the SPE as over-collateralization for the program. The company's retained interest in the SPE's receivables is classified in trade accounts receivable in the accompanying Consolidated Balance Sheet. The retained interest is subordinate to, and provides credit enhancement for, the conduit's ownership interest in the SPE's receivables, and is available to the conduit to pay certain fees or expenses due to the conduit, and to absorb credit losses incurred on any of the SPE's receivables in the event of termination. However, the company believes that the risk of credit loss is very low since its bad-debt experience has historically been insignificant. The company retains servicing responsibilities and receives a servicing fee of 1.07% of the receivables sold for the period of time outstanding, generally 60 to 120 days. Servicing fees collected were $2 million in 2003 and $1 million in both 2002 and 2001. No recourse obligations were recorded since the company has no obligations for any recourse actions on the sold receivables. The company also holds preference stock in the special-purpose entity equal to 3.5% of the receivables sold. The preference stock is essentially a retained deposit to provide further credit enhancements, if needed, but otherwise recoverable by the company at the end of the program.
During 2003, 2002 and 2001, the company sold $836 million, $609 million and $597 million, respectively, of its pigment receivables, resulting in pretax losses of $5 million, $5 million and $8 million, respectively. The losses are equal to the difference in the book value of the receivables sold and the total of cash and the fair value of the deposit retained by the special-purpose entity. At year-end 2003 and 2002, the outstanding balance on receivables sold, net of the company's retained interest in receivables serving as over-collateralization, totaled $165 million and $111 million, respectively. The outstanding balance for receivables serving as over-collateralization totaled $36 million at December 31, 2003. There were no delinquencies as of year-end 2003.
11. Income Taxes
The 2003, 2002 and 2001 income tax provisions (benefits) from continuing operations are summarized below:
(Millions of dollars) 2003 2002 2001 - --------------------------------------------------------------------------------
U.S. Federal - Current $ 9 $ 12 $(70) Deferred 19 (104) 219 ---- ----- ---- 28 (92) 149 ---- ----- ---- International - Current 58 36 130 Deferred 100 10 (8) ---- ----- ---- 158 46 122 ---- ----- ---- State 3 - 5 ---- ----- ----
Total $189 $ (46) $276 ==== ===== ====
In the following table, the U.S. Federal income tax rate is reconciled to the company's effective tax rates for income or loss from continuing operations as reflected in the Consolidated Statement of Operations.
2003 2002 2001 - --------------------------------------------------------------------------------
U.S. statutory rate - provision (benefit) 35.0% (35.0)% 35.0% Increases (decreases) resulting from - Adjustment of deferred tax balances due to tax rate changes - 19.9 (.1) Taxation of foreign operations 8.6 12.1 1.7 Federal income tax credits - (1.8) - State income taxes .5 - .6 Other - net (1.4) (2.2) (.5) ---- ---- ----
Total 42.7% (7.0)% 36.7% ==== ==== ====
Net deferred tax liabilities at December 31, 2003 and 2002, are composed of the following:
(Millions of dollars) 2003 2002 - --------------------------------------------------------------------------------
Net deferred tax liabilities - Accelerated depreciation $1,100 $1,088 Exploration and development 406 192 Undistributed earnings of foreign subsidiaries 28 28 Postretirement benefits (76) (89) Dismantlement, remediation, restoration and other reserves (109) (34) U.S. and foreign operating loss carryforward (126) (92) AMT credit carryforward (47) (47) Other 83 99 ------ ------
Total $1,259 $1,145 ====== ======
The taxation of a company that has operations in several countries involves many complex variables, such as tax structures that differ from country to country and the effect on U.S. taxation of international earnings. These complexities do not permit meaningful comparisons between the U.S. and international components of income before income taxes and the provision for income taxes, and disclosures of these components do not necessarily provide reliable indicators of relationships in future periods. Income (loss) from continuing operations before income taxes is comprised of the following:
(Millions of dollars) 2003 2002 2001 - --------------------------------------------------------------------------------
United States $145 $(116) $524 International 298 (541) 228 ---- ----- ---- Total $443 $(657) $752 ==== ===== ====
On July 24, 2002, the United Kingdom government made certain changes to its existing tax laws. Under one of these changes, companies are required to pay a supplementary corporate tax charge of 10% on profits from their U.K. oil and gas production, in addition to the required 30% corporate tax on these profits. The U.K. government also accelerated tax depreciation for capital investments in U.K. upstream activities and abolished North Sea royalty. The deferred income tax liability was adjusted to reflect these changes, causing a net increase in the 2002 international deferred provision for income taxes of $132 million.
At December 31, 2003, the company had foreign operating loss carryforwards totaling $272 million. Of this amount, $3 million expires in 2004, $13 million in 2006, $1 million in 2007 and $255 million has no expiration date. Realization of these operating loss carryforwards depends on generating sufficient taxable income in future periods. A valuation allowance of $9 million has been recorded to reduce deferred tax assets associated with loss carryforwards that the company does not expect to fully realize prior to expiration.
Undistributed earnings of certain consolidated foreign subsidiaries totaled $710 million at December 31, 2003. No provision for deferred U.S. income taxes has been made for these earnings because they are considered to be indefinitely invested outside the U.S. The distribution of these earnings in the form of dividends or otherwise, may subject the company to U.S. income taxes. However, because of the complexities of U.S. taxation of foreign earnings, it is not practicable to estimate the amount of additional tax that might be payable on the eventual remittance of these earnings.
The Internal Revenue Service has completed its examination of the Kerr-McGee Corporation and subsidiaries' Federal income tax returns for all years through 1998 and is conducting an examination of the years 1999 through 2002. The years through 1994 have been closed. The Oryx income tax returns have been examined through 1997, and the years through 1978 have been closed, as have the years 1988 through 1997. The company believes that it has made adequate provision for income taxes that may be payable with respect to open years.
12. Taxes, Other than Income Taxes
Taxes, other than income taxes, as shown in the Consolidated Statement of Operations for the years ended December 31, 2003, 2002 and 2001, are comprised of the following:
(Millions of dollars) 2003 2002 2001 - --------------------------------------------------------------------------------
Production/severance $46 $ 58 $ 67 Payroll 30 21 27 Property 19 20 15 Other 3 5 5 --- ---- ----
Total $98 $104 $114 === ==== ====
13. Asset Retirement Obligations
As discussed in Note 1, the company adopted FAS 143 on January 1, 2003. At December 31, 2002, the comparable balance of $222 million reflected in the company's Consolidated Balance Sheet represents the non-current portion of the company's site dismantlement reserve prior to the adoption of FAS 143. A summary of the changes in asset retirement obligations since the date of adoption is included in the table below.
(Millions of dollars) - --------------------------------------------------------------------------------
January 1, 2003, balance upon adoption of FAS 143 $395 Obligations incurred 11 Accretion expense 25 Abandonment expenditures (17) Abandonment obligations settled through property divestitures (15) Changes in estimates, including timing 22 ---- December 31, 2003 421 Less current asset retirement obligation (20) ---- Non-current asset retirement obligation $401 ====
14. Deferred Credits and Reserves - Other
Other deferred credits and reserves consist of the following at year-end 2003 and 2002:
(Millions of dollars) 2003 2002 - --------------------------------------------------------------------------------
Postretirement benefit obligations $215 $210 Reserves for remediation and restoration 152 165 Pension plan liabilities 73 54 Derivatives (1) 2 67 Litigation reserves 32 30 Accrued rent expense - spar operating leases 32 9 Ad valorem taxes 31 21 Other 28 26 ---- ----
Total $565 $582 ==== ====
(1) Options associated with exchangeable debt of $67 million at December 31, 2002, were reclassified from other deferred credits and reserves to accrued liabilities during 2003 in connection with the maturity of the DECS in August 2004 (see Note 18).
The company provided for environmental remediation and restoration, net of authorized reimbursements, during each of the years 2003, 2002 and 2001, as follows:
(Millions of dollars) 2003 2002 2001 - --------------------------------------------------------------------------------
Provision, net of authorized reimbursements $62 $ 80 $90 Reimbursements received 15 9 11 Authorized reimbursements accrued 32 113 -
The reimbursements pertain to the former facility in West Chicago, Illinois, and the Henderson, Nevada, facility. The West Chicago reimbursements are authorized pursuant to Title X of the Energy Policy Act of 1992 and the Henderson reimbursements represent amounts recoverable under an environmental cost cap insurance policy (see Note 16).
15. Other Income (Expense)
Other income (expense) included the following during each of the years in the three-year period ended December 31, 2003:
(Millions of dollars) 2003 2002 2001 - --------------------------------------------------------------------------------
Gain (loss) on foreign currency exchange $(41) $(38) $ 3 Loss from unconsolidated affiliates (33) (25) (5) Gain on sale of Devon stock 17 - - Derivatives and Devon stock revaluation (1) 4 35 225 Interest income 5 5 10 Other (11) (12) (9) ---- ---- ----
Total $(59) $(35) $224 ==== ==== ====
(1) See Note 18.
16. Contingencies
West Chicago, Illinois
In 1973, the company's chemical affiliate (Chemical) closed a facility in West Chicago, Illinois, that processed thorium ores for the federal government and for certain commercial purposes. Historical operations had resulted in low-level radioactive contamination at the facility and in surrounding areas. The original processing facility is regulated by the State of Illinois (the State), and four vicinity areas are designated as Superfund sites on the National Priorities List (NPL).
Closed Facility - Pursuant to agreements reached in 1994 and 1997 among Chemical, the City of West Chicago (the City) and the State regarding the decommissioning of the closed West Chicago facility, Chemical has substantially completed the excavation of contaminated soils and has shipped the bulk of those soils to a licensed disposal facility. Removal of the remaining materials is expected to be substantially completed by the end of 2004, leaving principally surface restoration and groundwater monitoring and/or remediation for subsequent years. Surface restoration is expected to be completed in 2004, except for areas designated for use in connection with the Kress Creek and Sewage Treatment Plant remediation discussed below. The long-term scope, duration and cost of groundwater monitoring and/or remediation are uncertain because it is not possible to reliably predict how groundwater conditions have been affected by the excavation and removal work.
Vicinity Areas - The Environmental Protection Agency (EPA) has listed four areas in the vicinity of the closed West Chicago facility on the NPL and has designated Chemical as a Potentially Responsible Party (PRP) in these four areas. Chemical has substantially completed remedial work for two of the areas (known as the Residential Areas and Reed-Keppler Park). The other two NPL sites, known as Kress Creek and the Sewage Treatment Plant, are contiguous and involve low levels of insoluble thorium residues, principally in streambanks and streambed sediments, virtually all within a floodway. Chemical has reached an agreement in principle with the appropriate federal and state agencies and local communities regarding the characterization and cleanup of the sites, past and future government response costs, and the waiver of natural resource damage claims. The agreement in principle is expected to be incorporated in a consent decree, which must be agreed to by the appropriate federal and state agencies and local communities and then entered by a federal court. Court approval is expected in 2004. Chemical has already conducted an extensive characterization of Kress Creek and the Sewage Treatment Plant and, at the request of EPA, Chemical is conducting limited additional characterization that is expected to be completed in 2004. The cleanup work, which is expected to take about four years to complete following entry of the consent decree, will require excavation of contaminated soils and stream sediments, shipment of excavated materials to a licensed disposal facility and restoration of affected areas.
Financial Reserves - As of December 31, 2003, the company had remaining reserves of $96 million for costs related to West Chicago. This includes $19 million added to the reserve in 2003 because of an increase in soil volumes experienced at the Closed Facility and related post-cleanup demolition, city infrastructure replacement, and additional support and oversight costs. Although actual costs may exceed current estimates, the amount of any increases cannot be reasonably estimated at this time. The amount of the reserve is not reduced by reimbursements expected from the federal government under Title X of the Energy Policy Act of 1992 (Title X) (discussed below).
Government Reimbursement - Pursuant to Title X, the U.S. Department of Energy (DOE) is obligated to reimburse Chemical for certain decommissioning and cleanup costs incurred in connection with the West Chicago sites in recognition of the fact that about 55% of the facility's production was dedicated to U.S. government contracts. The amount authorized for reimbursement under Title X is $365 million plus inflation adjustments. That amount is expected to cover the government's full share of West Chicago cleanup costs. Through December 31, 2003, Chemical had been reimbursed approximately $171 million under Title X. In March 2004, Chemical received an additional reimbursement of $44 million, bringing the total reimbursement received to date to about $215 million.
Reimbursements under Title X are provided by congressional appropriations. Historically, congressional appropriations have lagged Chemical's cleanup expenditures. As of December 31, 2003, the government's share of costs incurred by Chemical but not yet reimbursed by the DOE totaled approximately $109 million, which was reduced to $65 million in March 2004 following receipt of the additional reimbursement of $44 million. The company believes receipt of the remaining arrearage in due course following additional congressional appropriations is probable and has reflected the arrearage as a receivable in the financial statements. The company expects to receive reimbursement for the remainder of this receivable by the end of 2006, and will recognize recovery of the government's share of future remediation costs for the West Chicago sites as Chemical incurs the costs.
Henderson, Nevada
In 1998, Chemical decided to exit the ammonium perchlorate business. At that time, Chemical curtailed operations and began preparation for the shutdown of the associated production facilities in Henderson, Nevada, that produced ammonium perchlorate and other related products. Manufacture of perchlorate compounds began at Henderson in 1945 in facilities owned by the U.S. government. The U.S. Navy expanded production significantly in 1953 when it completed construction of a plant for the manufacture of ammonium perchlorate. The Navy continued to own the ammonium perchlorate plant as well as other associated production equipment at Henderson until 1962, when the plant was purchased by a predecessor of Chemical. The ammonium perchlorate produced at the Henderson facility was used primarily in federal government defense and space programs. Perchlorate has been detected in nearby Lake Mead and the Colorado River.
Chemical began decommissioning the facility and remediating associated perchlorate contamination, including surface impoundments and groundwater when it decided to exit the business in 1998. In 1999 and 2001, Chemical entered into consent orders with the Nevada Division of Environmental Protection that require Chemical to implement both interim and long-term remedial measures to capture and remove perchlorate from groundwater.
In 1999, Chemical initiated the interim measures required by the consent orders. In June 2003, construction began on a long-term remediation system. It is anticipated that this system will be operational in early 2004. The scope and duration of groundwater remediation will be driven in the long term by drinking water standards, which to date have not been formally established by state or federal regulatory authorities. EPA and other federal and state agencies currently are evaluating the health and environmental risks associated with perchlorate as part of the process for ultimately setting a drinking water standard. The resolution of these issues could materially affect the scope, duration and cost of the long-term groundwater remediation that Chemical is required to perform.
Financial Reserves - In 2003, the company added $32 million to its reserves for groundwater remediation at Henderson for the construction and operation of the long-term remediation system and the continued operation of the interim system during the construction and startup period for the long-term system. Remaining reserves for Henderson totaled $23 million as of December 31, 2003. As noted above, the long-term scope, duration and cost of groundwater remediation are uncertain and, therefore, additional costs may be incurred in the future. However, the amount of any additional costs cannot be reasonably estimated at this time.
Government Litigation - In 2000, Chemical initiated litigation against the United States seeking contribution for response costs. The suit is based on the fact that the government owned the plant in the early years of its operation, exercised significant control over production at the plant and the sale of products produced at the plant, and was the largest consumer of products produced at the plant. The litigation is in the discovery stage. Although the outcome of the litigation is uncertain, Chemical believes it is likely to recover a portion of its costs from the government. The amount and timing of any recovery cannot be estimated at this time and, accordingly, the company has not recorded a receivable or otherwise reflected in the financial statements any potential recovery from the government.
Insurance - In 2001, Chemical purchased a 10-year, $100 million environmental cost cap insurance policy for groundwater and other remediation at Henderson. The insurance policy provides coverage only after Chemical exhausts a self-insured retention of approximately $61 million and covers only those costs incurred to achieve a cleanup level specified in the policy. As noted above, federal and state agencies have not established a drinking water standard and, therefore, it is possible that Chemical may be required to achieve a cleanup level more stringent than that covered by the policy. If so, the amount recoverable under the policy could be affected. Through December 31, 2003, Chemical has incurred expenditures of about $59 million that it believes can be applied to the self-insured retention. The company believes that the remaining reserve of $23 million at December 31, 2003, also will qualify under the insurance policy, which would exhaust the self-insured retention and leave about $21 million for recovery under the policy. The company believes that reimbursement of the $21 million under the insurance policy is probable and, accordingly, the company has recorded a $21 million receivable in the financial statements. The company expects to be reimbursed for this receivable by the end of 2007.
Milwaukee, Wisconsin
In 1976, Chemical closed a wood-treatment facility it had operated in Milwaukee, Wisconsin. Operations at the facility prior to its closure had resulted in the contamination of soil and groundwater at and around the site with creosote and other substances used in the wood-treatment process. In 1984, EPA designated the Milwaukee wood-treatment facility as a Superfund site under CERCLA, listed the site on the NPL and named Chemical a PRP. Chemical executed a consent decree in 1991 that required it to perform soil and groundwater remediation at and below the former wood-treatment area and to address a tributary creek of the Menominee River that had become contaminated as a result of the wood-treatment operations. Actual remedial activities were deferred until after the decree was finally entered in 1996 by a federal court in Milwaukee.
Groundwater treatment was initiated in 1996 to remediate groundwater contamination below and in the vicinity of the former wood-treatment area. It is not possible to reliably predict how groundwater conditions will be affected by the ongoing soil remediation and groundwater treatment; therefore, it is not known how long groundwater treatment will continue. Soil cleanup of the former wood-treatment area began in 2000 and was completed in 2002. Also in 2002, terms for addressing the tributary creek were agreed upon with EPA, after which Chemical began the implementation of a remedy to reroute the creek and to remediate associated sediment and stream bank soils, which is expected to take about four more years.
As of December 31, 2003, the company had remaining reserves of $11 million for the costs of the remediation work described above. Although actual costs may exceed current estimates, the amount of any increases cannot be reasonably estimated at this time.
Cushing, Oklahoma
In 1972, an affiliate of the company closed a petroleum refinery it had operated near Cushing, Oklahoma. Prior to closing the refinery, the affiliate also had produced uranium and thorium fuel and metal at the site pursuant to licenses issued by the Atomic Energy Commission (AEC). The uranium and thorium operations commenced in 1962 and were shut down in 1966, at which time the affiliate decommissioned and cleaned up the portion of the facility related to uranium and thorium operations to applicable standards. The refinery also was cleaned up to applicable standards at the time of closing.
Subsequent regulatory changes required more extensive remediation at the site. In 1990, the affiliate entered into a consent agreement with the State of Oklahoma to investigate the site and take appropriate remedial actions related to petroleum refining and uranium and thorium residuals. Investigation and remediation of hydrocarbon contamination is being performed with oversight of the Oklahoma Department of Environmental Quality. Soil remediation to address hydrocarbon contamination is expected to continue for about four more years. The long-term scope, duration and cost of groundwater remediation are uncertain and, therefore, additional costs may be incurred in the future. Additionally, in 1993, the affiliate received a decommissioning license from the Nuclear Regulatory Commission (NRC), the successor to AEC's licensing authority, to perform certain cleanup of uranium and thorium residuals. This work is expected to be substantially completed in 2004.
As of December 31, 2003, the company had remaining reserves of $22 million for the costs of the ongoing remediation and decommissioning work described above. This includes $17 million added to the reserve in 2003 as a result of the increase in uranium and thorium residuals experienced at the site, which required excavation, transportation and disposal, as well as additional characterization of petroleum hydrocarbons, and extended support costs. Although actual costs may exceed current estimates, the amount of any increases cannot be reasonably estimated at this time.
Mobile, Alabama
In June 2003, Chemical ceased operations at its facility in Mobile, Alabama, which Chemical had used to produce feedstock for its titanium dioxide plants. Operations prior to closure had resulted in minor contamination of the groundwater adjacent to surface impoundments. A groundwater recovery system was installed prior to closure and continues in operation as required under Chemical's National Pollutant Discharge Elimination System (NPDES) permit. Future remediation work, including groundwater recovery, closure of the impoundments and other minor work, is expected to be substantially completed in about five years. Reserves of $11 million were provided for the remediation in 2003 and remain outstanding as of December 31, 2003. Although actual costs may exceed current estimates, the amount of any increases cannot be reasonably estimated at this time.
New Jersey Wood-Treatment Site
In 1999, EPA notified Chemical and its parent company that they were potentially responsible parties at a former wood-treatment site in New Jersey that has been listed by EPA as a Superfund site. At that time, the company knew little about the site as neither Chemical nor its parent had ever owned or operated the site. A predecessor of Chemical had been the sole stockholder of a company that owned and operated the site. The company that owned the site already had been dissolved and the site had been sold to a third party before Chemical became affiliated with the former stockholder in 1964. EPA has preliminarily estimated that cleanup costs may reach $120 million or more.
There are substantial uncertainties about Chemical's responsibility for the site, and Chemical is evaluating possible defenses to any claim by EPA for response costs. EPA has not articulated the factual and legal basis on which EPA notified Chemical and its parent that they are potentially responsible parties. The EPA notification may be based on a successor liability theory premised on the 1964 transaction pursuant to which Chemical became affiliated with the former stockholder of the company that had owned and operated the site. Based on available historical records, it is uncertain whether and, if so, under what terms, the former stockholder assumed liabilities of the dissolved company. Moreover, as noted above, the site had been sold to a third party and the company that owned and operated the site had been dissolved before Chemical became affiliated with that company's stockholder. In addition, there appear to be other potentially responsible parties, though it is not known whether the other parties have received notification from EPA. EPA has not ordered Chemical or its parent to perform work at the site and is instead performing the work itself. The company has not recorded a reserve for the site as it is not possible to reliably estimate whatever liability Chemical or its parent may have for the cleanup because of the aforementioned uncertainties and the existence of other potentially responsible parties.
Forest Products Litigation
Between 1999 and 2001, Kerr-McGee Chemical LLC (Chemical) and its parent company were named in 22 lawsuits in three states (Mississippi, Louisiana and Pennsylvania) in connection with present and former forest products operations located in those states (in Columbus, Mississippi; Bossier City, Louisiana; and Avoca, Pennsylvania). The lawsuits sought recovery under a variety of common law and statutory legal theories for personal injuries and property damages allegedly caused by exposure to and/or release of creosote and other substances used in the wood-treatment process.
Having earlier set a reserve of $70 million for liabilities associated with these matters, Chemical executed settlement agreements, which are expected to resolve substantially all of the Louisiana, Pennsylvania and Columbus, Mississippi, lawsuits described above. About 90% of approximately 10,400 identified claimants and about 2,500 class members pursuant to a class action settlement have released Chemical and its parent from liability related to the former forest products operations in exchange for settlement payments totaling approximately $66 million (leaving approximately $4 million in the reserve). Accordingly most of the suits have been, or are expected to be, dismissed. The settlements do not resolve two of the Columbus, Mississippi, lawsuits, which together involve 27 plaintiffs. The settlements also do not resolve the claims of plaintiffs who did not sign releases, class members who opted out of the class settlement, or class members whose claims may arise in the future for currently unmanifested personal injuries.
Chemical and its affiliates believe that lawsuits and claims not resolved pursuant to the settlements described above are without substantial merit, and Chemical and its affiliates are vigorously defending against them. However, there is no assurance that the company will not be required to adjust the reserve in the future in light of the uncertainties of litigation. The company believes that the resolution of the claims that remain outstanding with respect to forest products operations in Columbus, Mississippi; Bossier City, Louisiana; and Avoca, Pennsylvania, will not have a material adverse effect on the company.
Following the adoption by the Mississippi legislature of tort reform, plaintiffs' lawyers filed many new lawsuits across the state of Mississippi in advance of the reform's effective date. On December 31, 2002, approximately 245 lawsuits were filed against Chemical and its affiliates on behalf of approximately 4,600 claimants in connection with Chemical's Columbus, Mississippi, operations, seeking recovery on legal theories substantially similar to those advanced in the litigation described above. Substantially all of these lawsuits have been removed to the U.S. District Court for the Northern District of Mississippi, and the company is seeking to consolidate these lawsuits for pretrial and discovery purposes. Chemical and its affiliates believe the lawsuits are without substantial merit and are vigorously defending against them. The company has not provided a reserve for the lawsuits because it cannot reasonably determine the probability of a loss, and the amount of loss, if any, cannot be reasonably estimated.
On December 31, 2002, and June 13, 2003, two lawsuits were filed against Chemical in connection with a former wood-treatment plant located in Hattiesburg, Mississippi, and the plaintiffs' lawyers also have asserted similar claims on behalf of other persons not named in the lawsuits. The lawsuits and other claims seek recovery on legal theories substantially similar to those advanced in the litigation described above. Chemical resolved the majority of these claims pursuant to a settlement reached in April 2003, which has resulted in aggregate payments by Chemical of approximately $600,000. Chemical and its affiliates believe that claims not resolved pursuant to the Hattiesburg settlements are without substantial merit and are vigorously defending against such claims.
The company believes that the resolution of the claims that remain outstanding with respect to the follow-on litigation will not have a material adverse effect on the company's financial condition or results of operations.
Other Matters
The company and/or its affiliates are parties to a number of legal and administrative proceedings involving environmental and/or other matters pending in various courts or agencies. These include proceedings associated with facilities currently or previously owned, operated or used by the company's affiliates and/or their predecessors, some of which include claims for personal injuries and property damages. Current and former operations of the company's affiliates also involve management of regulated materials and are subject to various environmental laws and regulations. These laws and regulations will obligate the company's affiliates to clean up various sites at which petroleum and other hydrocarbons, chemicals, low-level radioactive substances and/or other materials have been contained, disposed of or released. Some of these sites have been designated Superfund sites by EPA pursuant to CERCLA. Similar environmental regulations exist in foreign countries in which the company's affiliates operate.
The company provides for costs related to contingencies when a loss is probable and the amount is reasonably estimable. It is not possible for the company to reliably estimate the amount and timing of all future expenditures related to environmental and legal matters and other contingencies because, among other reasons:
o some sites are in the early stages of investigation, and other sites may be identified in the future;
o remediation activities vary significantly in duration, scope and cost from site to site depending on the mix of unique site characteristics, applicable technologies and regulatory agencies involved;
o cleanup requirements are difficult to predict at sites where remedial investigations have not been completed or final decisions have not been made regarding cleanup requirements, technologies or other factors that bear on cleanup costs;
o environmental laws frequently impose joint and several liability on all potentially responsible parties, and it can be difficult to determine the number and financial condition of other potentially responsible parties and their respective shares of responsibility for cleanup costs;
o environmental laws and regulations, as well as enforcement policies, are continually changing, and the outcome of court proceedings and discussions with regulatory agencies are inherently uncertain;
o some legal matters are in the early stages of investigation or proceeding or their outcomes otherwise may be difficult to predict, and other legal matters may be identified in the future;
o unanticipated construction problems and weather conditions can hinder the completion of environmental remediation;
o the inability to implement a planned engineering design or use planned technologies and excavation methods may require revisions to the design of remediation measures, which delay remediation and increase costs; and
o the identification of additional areas or volumes of contamination and changes in costs of labor, equipment and technology generate corresponding changes in environmental remediation costs.
As of December 31, 2003, the company had reserves totaling $259 million for cleaning up and remediating environmental sites, reflecting the reasonably estimable costs for addressing these sites. This includes $96 million for the West Chicago sites, $23 million for the Henderson, Nevada, site and $35 million for forest products sites. Additionally, as of December 31, 2003, the company had litigation reserves totaling approximately $37 million for the reasonably estimable losses associated with litigation. Management believes, after consultation with general counsel, that currently the company has reserved adequately for the reasonably estimable costs of environmental matters and other contingencies. However, additions to the reserves may be required as additional information is obtained that enables the company to better estimate its liabilities, including liabilities at sites now under review, though the company cannot now reliably estimate the amount of future additions to the reserves.
17. Commitments
Lease Obligations and Guarantees
Total lease rental expense was $65 million in 2003, $61 million in 2002 and $38 million in 2001.
The company has various commitments under noncancelable operating lease agreements, principally for office space, production and gathering facilities, and drilling and other equipment. The company has also entered into operating lease agreements for the use of the Nansen, Boomvang and Gunnison platforms located in the Gulf of Mexico. Aggregate minimum annual rentals under all operating leases (including the platform leases in effect at December 31, 2003, and the Gunnison operating lease which closed January 15, 2004), total $941 million, of which $50 million is due in 2004, $66 million in 2005, $65 million in 2006, $59 million in 2007, $61 million in 2008 and $640 million thereafter.
During 2001, the company entered into a synthetic lease arrangement with Kerr-McGee Gunnison Trust for the construction of the company's share of a platform to be used in the development of the Gulf of Mexico Gunnison field, in which the company has a 50% working interest. The construction of the company's portion of the platform was financed with a $149 million synthetic lease between the trust and a group of financial institutions. Completion of the Gunnison platform occurred in December 2003, at which time a portion of the platform assets was acquired by a separate business trust and the company entered into an operating lease for the use of the assets. The remaining portion of the Gunnison synthetic lease was converted to an operating lease on January 15, 2004. In accordance with the provisions of FIN 46, the company has consolidated the remaining synthetic lessor trust as of December 31, 2003, as discussed in Note 1.
The company has guaranteed that the Nansen, Boomvang and Gunnison platforms will have residual values at the end of the operating leases equal to at least 10% of the fair-market value of the platform at the inception of the lease. For Nansen and Boomvang, the guaranteed values are $14 million and $8 million, respectively, in 2022, and for Gunnison the guarantee is $15 million in 2024.
During 2003 and 2002, the company entered into sale-leaseback arrangements with General Electric Capital Corporation (GECC) covering assets associated with a gas-gathering system in the Rocky Mountain region. The lease agreements were entered into for the purpose of monetizing the related assets. The sales price for the 2003 equipment was $6 million. The sales price for the 2002 equipment was $71 million; however, an $18 million settlement obligation existed for equipment previously covered by the lease agreement, resulting in net cash proceeds of $53 million in 2002. The 2002 operating lease agreements have an initial term of five years, with two 12-month renewal options, and the company may elect to purchase the equipment at specified amounts after the end of the fourth year. The 2003 operating lease agreement has an initial term of four years, with two 12-month renewal options. In the event the company does not purchase the equipment and it is returned to GECC, the company guarantees a residual value ranging from $35 million at the end of the initial terms to $27 million at the end of the last renewal option. The company recorded no gain or loss associated with the GECC sale-leaseback agreements. The future minimum annual rentals due under noncancelable operating leases shown above include payments related to these agreements.
In conjunction with the company's sale of its Ecuadorean assets, which included the company's nonoperating interest in the Oleoducto de Crudos Pesados Ltd. (OCP) pipeline, the company has entered into a performance guarantee agreement with the buyer for the benefit of OCP. Under the terms of the agreement, the company guarantees payment of any claims from OCP against the buyer upon default by the buyer and its parent company. Claims would generally be for the buyer's proportionate share of construction costs of OCP; however, other claims may arise in the normal operations of the pipeline. Accordingly, the amount of any such future claims cannot be reasonably estimated. In connection with this guarantee, the buyer's parent company has issued a letter of credit in favor of the company up to a maximum of $50 million, upon which the company can draw in the event it is required to perform under the guarantee agreement. The company will be released from this guarantee when the buyer obtains a specified credit rating as stipulated under the guarantee agreement.
In connection with certain contracts and agreements, the company enters into indemnifications related to title claims, environmental matters, litigation and other claims. The company has recorded no material obligations in connection with its indemnification agreements.
Purchase Obligations
In the normal course of business, the company enters into contractual agreements to purchase raw materials, pipeline capacity, utilities and other services. Aggregate future payments under these contracts total $994 million, of which $345 million is expected to be paid in 2004, $414 million between 2005 and 2006, $158 million between 2007 and 2008, and $77 million thereafter.
Drilling Rig Commitments
During 1999, the company entered into lease agreements to participate in the use of various drilling rigs. The total commitment with respect to these arrangements ranges from nil to $9 million, depending on partner utilization. These agreements extend through 2004.
18. Financial Instruments and Derivative Activities
Investments in Certain Debt and Equity Securities
The company has certain investments that are considered to be available for sale. These financial instruments are carried in the Consolidated Balance Sheet at fair value, which is based on quoted market prices. The company had no securities classified as held to maturity at December 31, 2003 or 2002. At December 31, 2003 and 2002, available-for-sale securities for which fair value can be determined are as follows:
(1) This amount includes $9 million and $28 million at December 31, 2003 and 2002, respectively, of gross unrealized hedging losses on 15% of the exchangeable debt at the time of adoption of FAS 133.
The equity securities represent the company's investment in Devon Energy Corporation common stock. The company also holds debt exchangeable for stock (DECS) that may be repaid with the Devon stock currently owned by Kerr-McGee. Prior to the beginning of 2001, the stock and the debt were marked to market each month, with the offset recognized in accumulated other comprehensive income. On January 1, 2001, the company adopted the provisions of FAS 133 and in accordance with that standard chose to reclassify 85% of the Devon shares owned at that time to "trading" from the "available for sale" category of investments. As a result of the reclassification, the company recognized after-tax income totaling $118 million ($181 million before taxes) for the unrealized appreciation on 85% of the Devon shares. Additionally, with adoption of FAS 133, the DECS and its embedded option features were separated. The debt is now recorded in the Consolidated Balance Sheet at face value less unamortized discount, and the options associated with the exchangeable feature of the debt have been recorded at fair value on the balance sheet in accrued liabilities. (See further discussion on derivatives below.)
During December 2003, the company sold a portion of its Devon shares classified as available for sale resulting in a pretax gain of $17 million. The remaining shares were sold in January 2004 for a pretax gain of $9 million. Proceeds from the December sales totaled $59 million ($47 million received in 2003 and $12 million received in 2004) and proceeds from the January sales totaled $27 million. The cost of the shares sold and the amount of the gain reclassified from accumulated other comprehensive income were determined using the average cost of the shares held. The Devon securities are carried in the Consolidated Balance Sheet as current assets. U.S. government obligations are carried as current assets or as investments - other assets, depending on their maturities.
The change in unrealized holding gains (losses), net of income taxes, as shown in accumulated other comprehensive income for the years ended December 31, 2003, 2002 and 2001, is as follows:
(Millions of dollars) 2003 2002 2001 - --------------------------------------------------------------------------------
Beginning balance $ 6 $(1) $ 139 Net unrealized holding gains (losses) 6 7 (22) Reclassification of gains included in net income (7) - (118) --- --- ----- Ending balance $ 5 $ 6 $ (1) === === =====
Trading Securities
As discussed above, the company has recorded 85% of its Devon shares as trading securities and marks this investment to market through income. At December 31, 2003, the market value of 8.4 million shares of Devon was $483 million, and $96 million in unrealized pretax gains was recognized during 2003 in other income (expense) in the Consolidated Statement of Operations. However, this gain was substantially offset by an $88 million unrealized loss on the embedded options associated with the DECS. See the discussion of these derivatives below. At year-end 2002, the market value of 8.4 million shares of Devon was $387 million, and $61 million in unrealized pretax gains were recognized during 2002. This gain was partially offset by a $34 million unrealized loss on the embedded options associated with the DECS.
Financial Instruments for Other than Trading Purposes
In addition to the financial instruments previously discussed, the company holds or issues financial instruments for other than trading purposes. At December 31, 2003 and 2002, the carrying amount and estimated fair value of these instruments for which fair value can be determined are as follows:
The carrying amount of cash and cash equivalents approximates fair value of those instruments due to their short maturity. The fair value of long-term receivables is based on discounted cash flows. The fair value of foreign currency forward contracts represents the aggregate replacement cost based on financial institutions' quotes. The fair value of the company's long-term debt is based on the quoted market prices for the same or similar debt issues or on the current rates offered to the company for debt with the same remaining maturity.
Derivatives
The company is exposed to market risk from fluctuations in crude oil and natural gas prices. To increase the predictability of its cash flows and to support capital projects, the company initiated a hedging program in 2002 and periodically enters into financial derivative instruments that generally fix the commodity prices to be received for a portion of its oil and gas production in the future. At December 31, 2003, the outstanding commodity-related derivatives accounted for as hedges had a liability fair value of $168 million, which is recorded as a current liability. At December 31, 2002, the outstanding commodity-related derivatives accounted for as hedges had a net liability fair value of $83 million, of which $27 million was recorded as a current asset and $110 million was recorded as a current liability. The fair value of these derivative instruments was determined based on prices actively quoted, generally NYMEX and Dated Brent prices. At December 31, 2003, the company had after-tax deferred losses of $106 million in accumulated other comprehensive income associated with these contracts. The company expects to reclassify the entire amount of these losses into earnings during the next 12 months, assuming no further changes in fair market value of the contracts. During 2003, the company realized a $71 million loss on U.S. oil hedging, a $64 million loss on North Sea oil hedging and a $144 million loss on U.S. natural gas hedging. During 2002, the company realized a $28 million loss on U.S. oil hedging, a $50 million loss on North Sea oil hedging and a $2 million loss on U.S. natural gas hedging. The losses offset the higher oil and natural gas prices realized on the physical sale of crude oil and natural gas. Losses for hedge ineffectiveness are recognized as a reduction of revenue in the Consolidated Statement of Operations and were not material for 2003 or 2002.
In addition to the company's hedging program, Kerr-McGee Rocky Mountain Corp. holds certain gas basis swaps settling between 2004 and 2008. Through December 2003, the company treated these gas basis swaps as nonhedge derivatives, and changes in fair value were recognized in earnings. On December 31, 2003, the company designated those swaps settling in 2004 as hedges since the basis swaps have been coupled with natural gas fixed-price swaps, while the remainder settling between 2005 and 2008 will continue to be treated as non-hedge derivatives. At December 31, 2003, these derivatives are recorded at their fair value of $23 million, of which $8 million is recorded as a current asset and $15 million is recorded in investments - other assets. At December 31, 2002, these derivatives were recorded at their fair value of $21 million in investments - other assets. The net gains associated with these non-hedge derivatives were $2 million, $8 million and $27 million in 2003, 2002 and 2001, respectively, and are included in other income in the Consolidated Statement of Operations.
The company's marketing subsidiary, Kerr-McGee Energy Services Corporation (KMES) markets natural gas (primarily equity gas) in the Denver area. Existing contracts for the physical delivery of gas at fixed prices have not been designated as hedges and are marked to market in accordance with FAS 133. KMES also has entered into natural gas swaps and basis swaps that offset its fixed-price risk on physical contracts. These derivative contracts lock in the margins associated with the physical sale. The company believes that risk associated with these derivatives is minimal due to the creditworthiness of the counterparties. The net asset fair value of these derivative instruments was not material at year-end 2003 or 2002. The fair values of the outstanding derivative instruments at December 31, 2003, were based on prices actively quoted. During 2003, the net loss associated with these derivative contracts totaled $12 million, of which $7 million is included as a reduction of revenue and $5 million is included in other income. For 2002 and 2001, the net loss associated with these derivative contracts totaled $20 million and $24 million, respectively, and is included as a reduction of revenue in the Consolidated Statement of Operations. The losses on the derivative contracts are substantially offset by the fixed prices realized on the physical sale of the natural gas.
From time to time, the company enters into forward contracts to buy and sell foreign currencies. Certain of these contracts (purchases of Australian dollars and British pound sterling, and sales of euro) have been designated and have qualified as cash flow hedges of the company's anticipated future cash flow needs for a portion of its capital expenditures, raw material purchases and operating costs. These forward contracts generally have durations of less than three years. At December 31, 2003, the outstanding foreign exchange derivative contracts accounted for as hedges had a net asset fair value of $21 million, of which $28 million was recorded in current assets and $7 million was recorded in current liabilities. Changes in the fair value of these contracts are recorded in accumulated other comprehensive income and will be recognized in earnings in the periods during which the hedged forecasted transactions affect earnings (i.e., when hedged assets are depreciated in the case of a hedge of capital expenditures, when finished inventory is sold in the case of a hedged raw material purchase and when the forward contracts close in the case of a hedge of operating costs). At December 31, 2003 and 2002, the company had after-tax deferred gains of $17 million and deferred losses of $7 million, respectively, in accumulated other comprehensive income. In 2003, the company reclassified $11 million of gains on forward contracts from accumulated other comprehensive income to operating expenses in the Consolidated Statement of Operations. In 2002 and 2001, the company reclassified $5 million and $9 million, respectively, of losses on forward contracts from accumulated other comprehensive income to operating expenses in the Consolidated Statement of Operations. Of the existing unrealized net gains at December 31, 2003, approximately $9 million in gains will be reclassified into earnings during the next 12 months, assuming no further changes in fair value of the contracts. No hedges were discontinued during 2003, and no ineffectiveness was recognized.
Selected pigment receivables have been sold in an asset securitization program at their equivalent U.S. dollar value at the date the receivables were sold. The company is collection agent and retains the risk of foreign currency rate changes between the date of sale and collection of the receivables. Under the terms of the asset securitization agreement restructured in 2003, the company is required to enter into forward contracts for the value of the euro-denominated receivables sold into the program to mitigate its foreign currency risk. Gains or losses on the forward contracts are recognized currently in earnings. During 2003, the company recognized losses of $7 million associated with these contracts.
The company has entered into other forward contracts to sell foreign currencies, which will be collected as a result of pigment sales denominated in foreign currencies, primarily in European currencies. These contracts have not been designated as hedges even though they do protect the company from changes in foreign currency rates. The estimated fair value of these contracts was immaterial at December 31, 2003 and 2002.
The company issued 5 1/2% notes exchangeable for common stock (DECS) in August 1999, which allow each holder to receive between .85 and 1.0 share of Devon common stock or, at the company's option, an equivalent amount of cash at maturity in August 2004. Embedded options in the DECS provide the company a floor price on Devon's common stock of $33.19 per share (the put option). The company also has the right to retain up to 15% of the shares if Devon's stock price is greater than $39.16 per share (the DECS holders have an imbedded call option on 85% of the shares). If Devon's stock price at maturity is greater than $33.19 per share but less than $39.16 per share, the company's right to retain Devon stock will be reduced proportionately. The company is not entitled to retain any Devon stock if the price of Devon stock at maturity is less than or equal to $33.19 per share. Using the Black-Scholes valuation model, the company recognizes any gains or losses resulting from changes in the fair value of the put and call options in other income. At December 31, 2003 and 2002, the net liability fair value of the embedded put and call options was $155 million and $67 million, respectively. The company recorded losses of $88 million, $34 million and $205 million during 2003, 2002 and 2001, respectively, in other income for the changes in the fair values of the put and call options. The fluctuation in the value of the put and call derivative financial instruments will generally offset the increase or decease in the market value of the Devon stock classified as trading. The remaining Devon shares, which are classified as available-for-sale securities, were partially liquidated in December 2003, with the remaining shares sold in January 2004 as discussed above. The available-for-sale Devon shares were in excess of the number of shares the company believes will be required to extinguish the DECS; however, should the price of the stock fall below $39.16 per share at the maturity of the DECS, the company would be required to either purchase additional Devon shares to settle the DECS or settle a portion of the DECS with cash. The DECS and the derivative liability associated with the call option have been classified as current liabilities in the Consolidated Balance Sheet as of December 31, 2003.
In connection with the issuance of $350 million 5.375% notes due April 15, 2005, the company entered into an interest rate swap arrangement in April 2002. The terms of the agreement effectively change the interest the company will pay on the debt until maturity from the fixed rate to a variable rate of LIBOR plus ..875%. The company considers the swap to be a hedge against the change in fair value of the debt as a result of interest rate changes. The estimated fair value of the interest rate swap was $15 million and $21 million at December 31, 2003 and 2002, respectively. Any gain or loss on the swap is offset by a comparable gain or loss resulting from recording changes in the fair value of the related debt. The critical terms of the swap match the terms of the debt; therefore, the swap is considered highly effective and no hedge ineffectiveness has been recorded. The company recognized an $11 million reduction in interest expense in 2003 and a $6 million reduction in interest expense in 2002 from the swap arrangement.
19. Acquisition and Merger Reserves
During 2002, the company recorded an accrual of $3 million representing additional severance and other acquisition-related costs related to its 2001 acquisition of HS Resources. In 2001, the company recorded an accrual of $42 million for items associated with this acquisition, which included transaction costs, severance and other employee-related costs, contract termination costs, and other acquisition-related costs. Of the total accrual of $45 million, $11 million was paid in 2002 and $34 million was paid during 2001, leaving no remaining reserve balance at December 31, 2002.
20. Business Combination
On August 1, 2001, the company completed the acquisition of all of the outstanding shares of common stock of HS Resources, Inc., an independent oil and gas exploration and production company with active projects in the Denver-Julesburg Basin, Gulf Coast, Mid-Continent and Northern Rocky Mountain regions of the U.S. The acquisition added approximately 250 million cubic feet equivalent of daily gas production and 1.3 trillion cubic feet equivalent of proved gas reserves, primarily in the Denver, Colorado, area. The addition of these primarily natural gas reserves provided the company a more balanced portfolio, geographic diversity and production mix, while also providing low-risk exploitation drilling opportunities from identified projects based on HS Resources' seismic inventory. The acquisition price totaled $1.8 billion in cash, company stock and assumption of debt. The company reflected the assets and liabilities acquired at fair value in its balance sheet effective August 1, 2001, and the company's results of operations include HS Resources beginning August 1, 2001. The purchase price was allocated to specific assets and liabilities based on their estimated fair value at the date of acquisition. The allocations included $348 million recorded as goodwill, which is not deductible for income tax purposes. The cash portion of the acquisition totaled $955 million, including direct expenses, and was ultimately financed through issuance of long-term debt. A total of 5,057,273 shares of Kerr-McGee common stock were issued in connection with the acquisition. The shares were valued at $70.33 per share, the average price two days before and after the purchase was announced. Debt totaling $506 million was assumed.
The following unaudited pro forma condensed information has been prepared to give effect to the HS Resources acquisition as if it had occurred at the beginning of 2001, including purchase accounting adjustments.
(Millions of dollars, except per-share amounts) 2001 - -------------------------------------------------------------------------------- Revenues $3,787 Income from continuing operations 490 Net income 499 Earnings per share- Basic 4.99 Diluted 4.73
21. Discontinued Operations, Asset Impairments and Asset Disposals
During 2002, the company approved a plan to dispose of its exploration and production operations in Kazakhstan, its interest in the Bayu-Undan project in the East Timor Sea offshore Australia and its interest in the Jabung block of Sumatra, Indonesia. These divestiture decisions were made as part of the company's strategic plan to rationalize noncore oil and gas properties. The results of these operations have been reported separately as discontinued operations in the accompanying Consolidated Statement of Operations for all years presented. In conjunction with the disposals, the related assets were evaluated and losses were recorded for the Kazakhstan operations, calculated as the difference between the estimated sales price for the operation, less costs to sell, and the operations' carrying value. The losses totaled $6 million in 2003 and $35 million in 2002 and are reported as part of discontinued operations. On March 31, 2003, the company completed the sale of its Kazakhstan operations for $169 million. In 2002, the company completed the sale of its interest in the Bayu-Undan project for $132 million in cash, resulting in a pretax gain of $35 million. The company also completed the sale of its Sumatra operations in 2002 for $171 million in cash with an $11 million contingent purchase price pending government approval of an LPG project. The sale resulted in a pretax gain of $72 million (excluding the contingent purchase price). The net proceeds received by the company from these sales were used to reduce outstanding debt.
Revenues applicable to the discontinued operations totaled $6 million, $36 million and $72 million for 2003, 2002 and 2001, respectively. Pretax income for the discontinued operations totaled nil (including the loss on sale of $6 million), $104 million (including the gains on sale of $107 million and the loss on sale of $35 million) and $52 million for the years 2003, 2002 and 2001, respectively.
Impairment losses on held-for-use assets totaled $14 million in 2003, and were primarily related to oil and gas fields in the U.S. onshore and Gulf of Mexico shelf areas with remaining investments that were no longer expected to be recovered through future cash flows. Pretax impairment losses totaling $652 million were recorded in 2002, of which $646 million related to the exploration and production operating unit and $6 million related to the chemical - other operating unit. For the exploration and production operating unit, the impairment charge included $541 million for the Leadon field in the U.K. North Sea, $82 million for certain other North Sea fields and $23 million for several older Gulf of Mexico shelf properties. Negative reserve revisions stemming from additional performance analysis for these properties during 2002 resulted in revised estimates of future cash flows from the properties that were less than the carrying values of the related assets. For the chemical - other operating unit, the $6 million impairment related to the company's decision to exit the forest products business. In addition, the chemical - pigment operating unit recorded a $12 million pretax write-down of property, plant and equipment in 2002 related to abandoned chemical engineering projects, which is reflected in depreciation and depletion in the Consolidated Statement of Operations.
During 2003, the company selectively marketed its 100% owned Leadon field to third parties. Although no divestiture negotiations are currently under way, the company continues to review its options with respect to the field and, particularly, the associated floating production, storage and offloading (FPSO) facility. Management presently intends to continue operating and producing the field until such time as the operating cash flow generated by the field does not support continued production or until a higher value option is identified. Given the significant value associated with the FPSO relative to the size of the entire project, the company will continue to pursue a long-term solution that achieves maximum value for Leadon - which may include disposing of the field, monetizing the FPSO by selling it as a development option for a third-party discovery, or redeployment in other company operations. As of December 31, 2003, the carrying value of the Leadon field assets totaled $374 million. Given the uncertainty concerning possible outcomes, it is reasonably possible that the company's estimate of future cash flows from the Leadon field and associated fair value could change in the near term due to, among other things, (i) unfavorable changes in commodity prices or operating costs, (ii) a production profile that declines more rapidly than currently anticipated, and/or (iii) unsuccessful results of continued marketing activities or failure to locate a strategic buyer (or suitable redeployment opportunity). Accordingly, management anticipates that the Leadon field will be subject to periodic impairment review until such time as the field is abandoned or sold. If future cash flows or fair value decrease from that presently estimated, an additional write-down of the Leadon field could occur in the future.
Impairment losses in 2001 were comprised of a $47 million write-down associated with the shut-down of the North Sea Hutton field and $29 million for certain chemical facilities in Belgium and the U.S. In 2001, the company's exploration and production operating unit suspended production from the Hutton field in the North Sea due to concerns about the amount of corrosion present in the pipeline, which would have ultimately required replacement of the pipeline for production to resume. Due to the small amount of remaining field reserves, the company, as operator, and the other partners entered into a plan to decommission the field, which was completed during 2003.
At the end of 2001, the company's chemical - pigment operating unit ceased production at its titanium dioxide pigment plant in Antwerp, Belgium, as part of its strategy to improve efficiencies and enhance margins by rationalizing assets within the chemical unit. A $14 million impairment loss was recognized in connection with the Antwerp shutdown. Also during 2001, the company's chemical - other operating unit ceased production at its manganese metal production plant in Hamilton, Mississippi, due to low-priced imports and softening prices that made the product no longer profitable. A $13 million impairment loss was recognized in connection with the Hamilton shutdown. Additionally, the loss of its only major customer led to a $2 million impairment charge for the shutdown of a wood-preserving plant in Indianapolis, Indiana.
In connection with the company's divestiture program initiated in 2002, certain oil and gas properties were identified for disposal and classified as held-for-sale properties. Upon classification as held-for-sale, the carrying value of the related properties is analyzed in relation to the estimated fair value less costs to sell, and losses are recognized if necessary. Upon ultimate disposal of the properties, any gain or additional loss on sale is recognized. Losses of $23 million and gains of $68 million were recognized in 2003 upon conclusion of the divestiture program in the U.S. and North Sea, and for the sale of the company's interest in the South China Sea (Liuhua field) and other noncore U.S. properties (onshore and Gulf of Mexico shelf areas). The company recognized losses of $176 million in 2002 associated with oil and gas properties held for sale in the U.S. (onshore and Gulf of Mexico shelf areas), the U.K. North Sea and Ecuador. Proceeds realized from these disposals totaled $119 million in 2003 and $374 million in 2002. The proceeds from the sale of these properties have been used to reduce long-term debt.
The chemical - pigment operating unit began production through a new high-productivity oxidation line at the Savannah, Georgia, chloride process pigment plant in January 2004. This new technology results in low-cost, incremental capacity increases through modification of existing chloride oxidation lines and allows for improved operating efficiencies through simplification of hardware configurations and reduced maintenance requirements. Based on the future outcome of these technological advancements, the company may need to review its existing configuration at the Savannah plant to optimize the plant's resources in relation to capacity requirements. The company will evaluate the performance of the new high-productivity line, analyze the implications on the capacity of existing assets and have a plan for reconfiguration, if any, by the latter part of 2004. If the new high-productivity line performs as expected, the outcome of this review may result in the deployment of certain assets to alternate uses and/or the need to idle certain other assets. If this occurs, the future useful life of such assets may be adjusted, resulting in the acceleration of depreciation expense.
The assets and liabilities of discontinued operations and other assets held for sale have been reclassified as Assets/Liabilities Associated with Properties Held for Disposal in the Consolidated Balance Sheet. The company recognized a net gain on disposal of property, excluding discontinued operations and assets held for sale, of $1 million in 2003, $1 million in 2002 and $12 million in 2001, which is reflected in Other Income in the Consolidated Statement of Operations.
22. Common Stock
Changes in common stock issued and treasury stock held for 2003, 2002 and 2001 are as follows:
Common Treasury (Thousands of shares) Stock Stock - --------------------------------------------------------------------------------
Balance December 31, 2000 101,417 6,933 Exercise of stock options and stock appreciation rights 533 - Cancellation of outstanding shares of Kerr-McGee Operating Corporation (formerly Kerr-McGee Corporation) (95,118) - Issuance of stock by Kerr-McGee Corporation (new holding company) 95,118 - Shares issued to purchase HS Resources 5,057 - Cancellation of treasury stock (6,838) (6,838) Issuance of restricted stock 16 (102) Forfeiture of restricted stock - 8 Issuance of shares for achievement awards 1 - ------- ------ Balance December 31, 2001 100,186 1 Exercise of stock options 112 - Issuance of restricted stock 94 (5) Forfeiture of restricted stock (2) 11 Issuance of shares for achievement awards 1 - ------- ------ Balance December 31, 2002 100,391 7 Exercise of stock options 18 - Issuance of restricted stock 483 - Forfeiture of restricted stock - 25 ------- ------ Balance December 31, 2003 100,892 32 ======= ======
The company has 40 million shares of preferred stock without par value authorized, and none is issued.
There are 1,107,692 shares of the company's common stock registered in the name of a wholly owned subsidiary of the company. These shares are not included in the number of shares shown in the preceding table or in the Consolidated Balance Sheet. These shares are not entitled to be voted.
Under the 2002 Long-Term Incentive Plan (Plan), the company may grant incentive opportunities to key employees. The Plan includes provisions for stock, stock options and performance-related awards. A maximum of 7,000,000 shares of common stock was authorized for issuance under the Plan in connection with stock options, stock appreciation rights, restricted stock and performance awards. Of the total 7,000,000 shares, a maximum of 1,750,000 shares of common stock are authorized for issuance under the Plan in connection with awards of restricted stock and performance awards. Restricted stock is awarded in the name of the employee and, except for the right of disposal, holders have full shareholders' rights during the period of restriction, including voting rights and the right to receive dividends. Under the Plan, certain key employees in Europe and Australia have received stock opportunity grants giving them the opportunity to earn unrestricted stock in the future provided that certain conditions are met. These stock opportunity grants do not carry voting privileges or dividend rights since the related shares are not issued until vested. Restricted stock and stock opportunity grants generally vest between three and five years. Compensation expense is recognized over the vesting period and was $10 million, $6 million and $4 million in 2003, 2002 and 2001, respectively. The company granted 483,000, 99,000 and 118,000 shares of restricted common stock in 2003, 2002 and 2001, respectively, for which the weighted average fair value at the date of grant was $20 million, $4 million and $7 million, respectively. The company granted 9,000 stock opportunity shares in 2003 for which the weighted average fair value at the date of grant was $.4 million. There were no stock opportunity grants issued in 2002 or 2001.
The company has had a stockholders-rights plan since 1986. The current rights plan is dated July 26, 2001, and replaced the previous plan prior to its expiration. Rights were distributed as a dividend at the rate of one right for each share of the company's common stock and continue to trade together with each share of common stock. Generally, the rights become exercisable the earlier of 10 days after a public announcement that a person or group has acquired, or a tender offer has been made for, 15% or more of the company's then-outstanding stock. If either of these events occurs, each right would entitle the holder (other than a holder owning more than 15% of the outstanding stock) to buy the number of shares of the company's common stock having a market value two times the exercise price. The exercise price is $215. Generally, the rights may be redeemed at $.01 per right until a person or group has acquired 15% or more of the company's stock. The rights expire in July 2006.
23. Employee Stock Option Plans
The 2002 Long-Term Incentive Plan (2002 Plan) authorizes the issuance of shares of the company's common stock any time prior to May 13, 2012, in the form of stock options, restricted stock or performance awards. The options may be accompanied by stock appreciation rights. A total of 7,000,000 shares of the company's common stock is authorized to be issued under the 2002 Plan.
In January 1998, the Board of Directors approved a broad-based stock option plan (BSOP) that provides for the granting of options to purchase the company's common stock to full-time, nonbargaining-unit employees, except officers. A total of 1,500,000 shares of common stock is authorized to be issued under the BSOP.
The 1987 Long-Term Incentive Program (1987 Program), the 1998 Long-Term Incentive Plan (1998 Plan) and the 2000 Long-Term Incentive Plan (2000 Plan) authorized the issuance of shares of the company's stock in the form of stock options, restricted stock or long-term performance awards. The 1987 Program was terminated when the stockholders approved the 1998 Plan, the 1998 Plan was terminated with the approval of the 2000 Plan, and the 2000 Plan was terminated with the approval of the 2002 Plan. No options could be granted under the 1987 Program, the 1998 Plan or the 2000 Plan after each plan's respective termination date, although options and any accompanying stock appreciation rights outstanding may be exercised prior to their expiration dates.
The company's employee stock options are fixed-price options granted at the fair market value of the underlying common stock on the date of the grant. Generally, one-third of each grant vests and becomes exercisable over a three-year period immediately following the grant date and expires 10 years after the grant date.
The following table summarizes the stock option transactions under the plans described above.
The following table summarizes information about stock options issued under the plans described above that are outstanding and exercisable at December 31, 2003:
24. Employee Benefit Plans
The company has both noncontributory and contributory defined-benefit retirement plans and company-sponsored contributory postretirement plans for health care and life insurance. Most employees are covered under the company's retirement plans, and substantially all U.S. employees may become eligible for the postretirement benefits if they reach retirement age while working for the company. Kerr-McGee uses a December 31 measurement date for its plans. In 2003, the company recognized a curtailment loss with respect to pension and postretirement benefits in connection with its work-force reduction program and other plant closures and recognized special termination benefits associated with its work-force reduction program. These losses have been reflected in the disclosures below.
In December 2003, the FASB issued FAS 132 (revised 2003), "Employers' Disclosures about Pensions and Other Postretirement Benefits," (FAS 132). FAS 132 does not change the measurement or recognition of those plans; however, certain additional disclosures are required by the new standard and are included herein. Additional disclosures for the company's foreign plans will be delayed for one year as permitted by the new standard.
Following are the changes in the benefit obligations during the past two years:
The benefit amount that can be covered by the retirement plans that qualify under the Employee Retirement Income Security Act of 1974 (ERISA) is limited by both ERISA and the Internal Revenue Code. Therefore, the company has unfunded supplemental plans designed to maintain benefits for all employees at the plan formula level and to provide senior executives with benefits equal to a specified percentage of their final average compensation. The projected benefit obligation and accumulated benefit obligation for the U.S and certain foreign unfunded retirement plans, excluding the under-funded U.K. plan discussed below, were $60 million and $51 million, respectively, at December 31, 2003, and $58 million and $47 million, respectively, at December 31, 2002. Although not considered plan assets, a grantor trust was established from which payments for certain of these U.S. supplemental plans are made. The trust had a balance of $37 million at year-end 2003 and at year-end 2002. The postretirement plans are also unfunded. In addition, the company has an under-funded foreign pension plan covering employees in the United Kingdom. The projected benefit obligation and accumulated benefit obligation for that plan at year-end 2003 were $75 million and $63 million, respectively, and were $50 million and $45 million, respectively, at year-end 2002. The market value of plan assets for the U.K. plan was $44 million at December 31, 2003, resulting in an under-funded status for the plan of $31 million.
Following are the changes in the fair value of plan assets during the past two years and the reconciliation of the plans' funded status to the amounts recognized in the financial statements at December 31, 2003 and 2002:
(1) No contributions are expected in 2004 for the U.S. qualified retirement plan. Kerr-McGee Corporation expects to contribute $2 million to its U.S. nonqualified retirement plans in 2004.
(2) The fair value of plan assets for the U.S. qualified retirement plan was $1.188 billion at December 31, 2003.
Following is the classification of the amounts recognized in the Consolidated Balance Sheet at December 31, 2003 and 2002:
For 2003, 2002 and 2001, the company had after-tax losses of $7 million, $14 million and $2 million, respectively, included in other comprehensive income resulting from changes in the additional minimum pension liability.
Total costs recognized for employee retirement and postretirement benefit plans for each of the years ended December 31, 2003, 2002 and 2001, were as follows:
The following assumptions were used in estimating the net periodic expense:
The following assumptions were used in estimating the actuarial present value of the plans' benefit obligations:
The health care cost trend rates used to determine the year-end 2003 postretirement benefit obligation were 10% in 2004, gradually declining to 5% in the year 2009 and thereafter. A 1% increase in the assumed health care cost trend rate for each future year would increase the postretirement benefit obligation at December 31, 2003, by $15 million and increase the aggregate of the service and interest cost components of net periodic postretirement expense for 2003 by $1 million. A 1% decrease in the trend rate for each future year would reduce the benefit obligation at year-end 2003 by $15 million and decrease the aggregate of the service and interest cost components of the net periodic postretirement expense for 2003 by $1 million.
Asset categories for the company's U.S. funded retirement plan (the Plan) and the weighted-average asset allocations at December 31, 2003 and 2002, by asset category are as follows:
Plan Assets at December 31, ------------------------- 2003 2002 - -------------------------------------------------------------------------------- Equity securities 55% 42% Debt securities 41% 56% Cash 4% 2% ---- ---- Total 100% 100% ==== ====
The Plan is administered by a board appointed committee that maintains a well developed investment policy stating the guidelines for the performance and allocation of plan assets, performance review procedures, and updating of the policy itself. The committee adheres to traditional capital market pricing theory, recognizing that over the long term the risk of owning equity securities is generally rewarded with a greater return than available from fixed-income investments. However, the committee also recognizes that the avoidance of large risks is desirable and may forego certain higher return opportunities in order to preserve a lower-risk investment profile. At least annually, the Plan's asset allocation guidelines are reviewed in light of evolving risk and return expectations. Current guidelines permit the committee to manage the allocation of funds between equity and debt securities at its discretion; however, throughout 2002 and 2003, the committee has maintained an allocation of assets in the range of 40-60% equity securities and 40-60% debt securities. The long-term return forecasting methodology for both equity and fixed-income securities is based on a capital asset pricing model using historical data. Based on the asset allocation at the end of 2003, the expected long-term rate of return of plan assets is forecasted to be 8.5%.
Substantially all of the plan's assets are invested with eight select equity fund managers and six fixed-income fund managers. At year-end 2003 and 2002, equity securities held by the plan included $2 million of Kerr-McGee stock, or 50,737 shares. Dividends paid on these shares were less than $100,000 in 2003 and 2002. To control risk, equity fund managers are prohibited from investing in commodities, including all futures contracts, purchasing letter stock, short selling, option trading, margin and Kerr-McGee securities, but are permitted to invest in U.S. common stock, U.S. preferred stock, U.S. securities convertible into common stock, common stock of foreign companies listed on major U.S. exchanges, common stock of foreign companies listed on foreign exchanges, covered call writing, and cash and cash equivalents. Fixed-income fund managers are prohibited from investing in foreign debt securities, direct real estate mortgages or commingled real estate funds, private placements, purchase of guaranteed investment contracts, and Kerr-McGee securities, but are permitted to invest in debt securities issued by the U.S. government, its agencies or instrumentalities, corporate bonds, debentures and other forms of corporate debt obligations, commercial paper rated A1/P1, certificates of deposit or bankers acceptances in amounts of $100,000 or less of U.S. banks insured by the FDIC, and financial futures contracts on U.S. Treasury obligations and options on such contracts where these investments are for the sole purpose of hedging. Some exceptions to the plan's investment restrictions are granted to equity and fixed income mutual funds. As long as a mutual fund remains in compliance with its own prospectus with regard to investment restrictions it is deemed to be in compliance with plan policy. All securities held in fixed-income fund manager accounts must be rated no less than Baa3 or its equivalent and each fund manager's portfolio should have an average credit rating that is A or better.
On December 8, 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 ("the Act") was signed into law. The Act expanded Medicare to include, for the first time, coverage for prescription drugs. Kerr-McGee expects that this legislation will eventually reduce the cost associated with its retiree medical programs. However, at this point, Kerr-McGee's investigation into its options in response to the legislation is preliminary and guidance from various governmental and regulatory agencies concerning the requirements that must be met to obtain these cost reductions, as well as the manner in which such savings should be measured, has not yet been issued.
Because of various uncertainties surrounding Kerr-McGee's response to this legislation and the appropriate accounting methodology for this event, the company has elected to defer financial recognition of the impact of this legislation until the FASB issues final accounting guidance. When issued, the final guidance could require the company to change previously reported information. This one-time deferral election is permitted under FASB Staff Position No. 106-1, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003."
25. Employee Stock Ownership Plan
In 1989, the company's Board of Directors approved a leveraged Employee Stock Ownership Plan (ESOP) into which is paid the company's matching contribution for the employees' contributions to the Kerr-McGee Corporation Savings Investment Plan (SIP). The ESOP was amended in 2001 to provide matching contributions for the employees' contributions made to the Kerr-McGee Pigments (Savannah) Inc., Employees' Savings Plan, a savings plan for the bargaining-unit employees at the company's Savannah, Georgia, pigment plant (Savannah Plan). Most of the company's employees are eligible to participate in both the ESOP and the SIP or Savannah Plan. Although the ESOP, SIP and Savannah Plan are separate plans, matching contributions to the ESOP are contingent upon participants' contributions to the SIP or Savannah Plan. Additionally, HS Resources had a savings plan at the time of acquisition, which had only discretionary cash contributions by the employer. Kerr-McGee paid $1 million into this plan in December 2001. Beginning January 1, 2002, the remaining HS Resources employees became eligible to participate in the Kerr-McGee ESOP and SIP.
In 1989, the ESOP trust borrowed $125 million from a group of lending institutions and used the proceeds to purchase approximately three million shares of the company's treasury stock. The company used the $125 million in proceeds from the sale of the stock to acquire shares of its common stock in open-market and privately negotiated transactions. In 1996, a portion of the third-party borrowings was replaced with a note payable to the company (sponsor financing), which was fully paid in 2003. The third-party borrowings are guaranteed by the company and are reflected in the Consolidated Balance Sheet as Long-Term Debt (see Note 9).
The Oryx Capital Accumulation Plan (CAP) was a combined stock bonus and leveraged employee stock ownership plan available to substantially all U.S. employees of the former Oryx operations. In 1989, Oryx privately placed $110 million of notes pursuant to the provisions of the CAP. Oryx loaned the proceeds to the CAP, which used the funds to purchase Oryx common stock that was placed in a trust. This loan was sponsor financing and does not appear in the accompanying balance sheet. The remaining balance of the sponsor financing is $33 million at year-end 2003. During 1999, the company merged the Oryx CAP into the ESOP and SIP.
The company stock owned by the ESOP trust is held in a loan suspense account. Deferred compensation, representing the unallocated ESOP shares, is reflected as a reduction of stockholders' equity. The company's matching contribution and dividends on the shares held by the ESOP trust are used to repay the loan, and stock is released from the loan suspense account as the principal and interest are paid. The expense is recognized and stock is then allocated to participants' accounts at market value as the participants' contributions are made to the SIP. Long-term debt is reduced as payments are made on the third-party financing. Dividends paid on the common stock held in participants' accounts are also used to repay the loans, and stock with a market value equal to the amount of dividends is allocated to participants' accounts.
Shares of stock allocated to the ESOP participants' accounts and in the loan suspense account are as follows:
(Thousands of shares) 2003 2002 - --------------------------------------------------------------------------------
Participants' accounts 1,496 1,448 Loan suspense account 315 630
The shares in the loan suspense account at December 31, 2003, included approximately 5,000 released shares that were allocated to participants' accounts in January 2004. At December 31, 2002, the shares in the loan suspense account included approximately 6,000 released shares that were allocated to participants' accounts in January 2003.
All ESOP shares are considered outstanding for net income per-share calculations. Dividends on ESOP shares are charged to retained earnings.
Compensation expense related to the plan was $33 million, $19 million and $12 million in 2003, 2002 and 2001, respectively. These amounts include interest expense incurred on the third-party ESOP debt, which was not material for 2003, 2002 or 2001. The company contributed $42 million, $27 million and $22 million to the ESOP in 2003, 2002 and 2001, respectively. Included in the respective contributions were $37 million, $19 million and $12 million for principal and interest payments on the sponsor financings. The cash contributions are net of $4 million, $5 million and $4 million for the dividends paid on the company stock held by the ESOP trust in 2003, 2002 and 2001, respectively.
26. Earnings Per Share
Basic earnings per share includes no dilution and is computed by dividing income or loss from continuing operations available to common stockholders by the weighted-average number of common shares outstanding for the period. Diluted earnings per share reflects the potential dilution that could occur if security interests were exercised or converted into common stock.
The following table sets forth the computation of basic and diluted earnings per share for the years ended December 31, 2003, 2002 and 2001.
Not included in the calculation of the denominator for diluted earnings per share were 4,866,144, 4,688,853 and 2,219,858 employee stock options outstanding at year-end 2003, 2002 and 2001, respectively. The inclusion of these options would have been antidilutive since they were not "in the money" at the end of the respective years. Since the company incurred a loss from continuing operations for 2002, no dilution of the loss per share would result from an additional 330,003 stock options that were "in the money" at year-end 2002 or the assumed conversion of the convertible debentures, discussed below.
The company has reserved 9,823,778 shares of common stock for issuance to the owners of its 5-1/4% Convertible Subordinated Debentures due 2010. These debentures are convertible into the company's common stock at any time prior to maturity at $61.08 per share of common stock.
27. Condensed Consolidating Financial Information
In connection with the acquisition of HS Resources in 2001, a holding company structure was implemented. The company formed a new holding company, Kerr-McGee Holdco, which then changed its name to Kerr-McGee Corporation. The former Kerr-McGee Corporation's name was changed to Kerr-McGee Operating Corporation. At the end of 2002, another reorganization took place whereby among other changes, Kerr-McGee Operating Corporation distributed its investment in certain subsidiaries (primarily the oil and gas operating subsidiaries) to a newly formed intermediate holding company, Kerr-McGee Worldwide Corporation. Kerr-McGee Operating Corporation formed a new subsidiary, Kerr-McGee Chemical Worldwide LLC, and merged into it.
On October 3, 2001, Kerr-McGee Corporation issued $1.5 billion of long-term notes in a public offering. The notes are general, unsecured obligations of the company and rank in parity with all of the company's other unsecured and unsubordinated indebtedness. Kerr-McGee Chemical Worldwide LLC (formerly Kerr-McGee Operating Corporation, which was previously the original Kerr-McGee Corporation) and Kerr-McGee Rocky Mountain Corporation have guaranteed the notes. Additionally Kerr-McGee Corporation has guaranteed all indebtedness of its subsidiaries, including the indebtedness assumed in the purchase of HS Resources. As a result of these guarantee arrangements, the company is required to present condensed consolidating financial information. The top holding company is Kerr-McGee Corporation. The guarantor subsidiaries include Kerr-McGee Chemical Worldwide LLC in 2003 and 2002, its predecessor, Kerr-McGee Operating Corporation in 2001, along with Kerr-McGee Rocky Mountain Corporation in 2003, 2002 and 2001.
The following tables present condensed consolidating financial information for (a) Kerr-McGee Corporation, the parent company, (b) the guarantor subsidiaries, and (c) the non-guarantor subsidiaries on a consolidated basis.
28. Reporting by Business Segments and Geographic Locations
The company has three reportable segments: oil and gas exploration and production, production and marketing of titanium dioxide pigment, and production and marketing of other chemicals. The exploration and production unit explores for and produces oil and gas in the United States, the United Kingdom sector of the North Sea and China. Exploration efforts also extend to Australia, Benin, Bahamas, Brazil, Gabon, Morocco, Western Sahara, Canada, Yemen and the Danish and Norwegian sectors of the North Sea. The chemical unit primarily produces and markets titanium dioxide pigment and has production facilities in the United States, Australia, Germany and the Netherlands. Other chemicals include the company's electrolytic manufacturing and marketing operations and forest products treatment business. All of these operations are in the United States.
Crude oil sales to individually significant customers totaled $446 million to BP PLC and subsidiaries (BP) in 2003; $408 million to Texon L.P. and $450 million to BP in 2002; and $408 million to Texon L.P. and $401 million to BP in 2001. In addition, natural gas sales totaled $103 million to BP and $782 million to Cinergy Marketing & Trading LP (Cinergy) in 2003; $72 million to BP and $496 million to Cinergy in 2002; and $682 million to Cinergy in 2001. Sales to subsidiary companies are eliminated as described in Note 1.
(Millions of dollars) 2003 2002 2001 - -------------------------------------------------------------------------------- Revenues - Exploration and production $2,923 $2,450 $2,428 ------ ------ ------ Chemicals - Pigment 1,079 995 931 Other 183 201 196 ------ ------ ------ Total Chemicals 1,262 1,196 1,127 ------ ------ ------ Total $4,185 $3,646 $3,555 ====== ====== ======
Operating profit (loss) - Exploration and production $1,002 $ (140) $ 922 ------ ------ ------ Chemicals - Pigment (13) 24 (22) Other (35) (23) (17) ------ ------ ------ Total Chemicals (48) 1 (39) ------ ------ ------ Total 954 (139) 883 ------ ------ ------
Net interest expense (246) (270) (185) Net nonoperating income (expense) (265) (248) 54 Benefit (provision) for income taxes (189) 46 (276) Discontinued operations, net of taxes - 126 30 Cumulative effect of change in accounting principle, net of taxes (35) - (20) ------ ------ ------ Net income (loss) $ 219 $ (485) $ 486 ====== ====== ======
Depreciation, depletion and amortization - Exploration and production (1) $ 678 $ 758 $ 675 ------ ------ ------ Chemicals - Pigment 110 97 103 Other 18 20 17 ------ ------ ------ Total Chemicals 128 117 120 ------ ------ ------ Other 8 6 8 Discontinued operations - 3 10 ------ ------ ------ Total $ 814 $ 884 $ 813 ====== ====== ======
(1) Includes amortization of nonproducing leasehold costs that is reported in exploration expense in the Consolidated Statement of Operations.
(Millions of dollars) 2003 2002 2001 - -------------------------------------------------------------------------------- Capital expenditures - Exploration and production (excludes Gunnison lease of $83) $ 869 $ 988 $ 1,557 ------- ------ ------- Chemicals - Pigment 90 78 139 Other 7 8 14 ------- ------ ------- Total Chemicals 97 86 153 ------- ------ ------- Other 15 58 15 Discontinued operations - 27 67 ------- ------ ------- Total 981 1,159 1,792 ------- ------ -------
Exploration expenses - Exploration and production - Dry hole costs 181 113 72 Amortization of undeveloped leases 69 67 56 Other 104 93 82 ------- ------ ------- Total 354 273 210 ------- ------ ------- Total capital expenditures and exploration expenses $ 1,335 $1,432 $ 2,002 ======= ====== =======
Total assets - Exploration and production $ 7,324 $7,030 $ 8,076 ------- ------ ------- Chemicals - Pigment 1,521 1,413 1,391 Other 212 247 245 ------- ------ ------- Total Chemicals 1,733 1,660 1,636 ------- ------ ------- Total 9,057 8,690 9,712
Corporate and other assets 1,117 1,038 1,010 Discontinued operations - 181 354 ------- ------ ------- Total $10,174 $9,909 $11,076 ======= ====== =======
Revenues - U.S. operations $ 2,860 $2,190 $ 2,125 ------- ------ ------- International operations - North Sea - exploration and production 791 936 935 China - exploration and production 23 30 31 Other - exploration and production - 28 39 Europe - pigment 313 294 258 Australia - pigment 198 168 167 ------- ------ ------- 1,325 1,456 1,430 ------- ------ ------- Total $ 4,185 $3,646 $ 3,555 ======= ====== =======
Operating profit (loss) - U.S. operations $ 622 $ 322 $ 647 ------- ------ ------- International operations - North Sea - exploration and production 353 (412) 318 China - exploration and production 1 7 6 Other - exploration and production (66) (59) (66) Europe - pigment 14 (21) (53) Australia - pigment 30 24 31 ------- ------ ------- 332 (461) 236 ------- ------ ------- Total $ 954 $ (139) $ 883 ======= ====== =======
Net property, plant and equipment - U.S. operations $ 5,021 $4,631 $ 4,483 ------- ------ ------- International operations - North Sea - exploration and production 1,874 1,912 2,427 China - exploration and production 165 115 93 Other - exploration and production 4 13 27 Europe - pigment 301 255 226 Australia - pigment 102 110 122 ------- ------ ------- 2,446 2,405 2,895 ------- ------ ------- Total $ 7,467 $7,036 $ 7,378 ======= ====== =======
29. Costs Incurred in Crude Oil and Natural Gas Activities
Total expenditures, both capitalized and expensed, for crude oil and natural gas property acquisition, exploration and development activities for the three years ended December 31, 2003, are reflected in the following table:
(1) Includes $95 million, $69 million and $1.128 billion applicable to purchases of reserves in place in 2003, 2002 and 2001, respectively.
(2) Exploration costs include delay rentals, exploratory dry holes, dry hole and bottom hole contributions, geological and geophysical costs, costs of carrying and retaining properties, and capital expenditures, such as costs of drilling and equipping successful exploratory wells.
(3) Development costs include costs incurred to obtain access to proved reserves (surveying, clearing ground, building roads), to drill and equip development wells, and to acquire, construct and install production facilities and improved-recovery systems. Development costs also include costs of developmental dry holes.
(4) Asset retirement costs represent the noncash increase in property, plant and equipment recognized when initially recording a liability for abandonment obligations (discounted) associated with the company's oil and gas wells and platforms. Asset retirement costs are depleted on a unit-of-production basis over the useful life of the related field. See further discussion in Note 1 regarding the 2003 adoption of FAS 143.
30. Results of Operations from Crude Oil and Natural Gas Activities
The results of operations from crude oil and natural gas activities for the three years ended December 31, 2003, consist of the following:
(1) Includes transportation, general and administrative expense, and taxes other than income taxes associated with oil and gas producing activities.
(2) Includes gas marketing activities, gas processing plants, pipelines and other items that do not fit the definition of crude oil and natural gas producing activities but have been included above to reconcile to the segment presentations.
The table below presents the company's average per-unit sales price of crude oil and natural gas and lifting costs (lease operating expense and production taxes) per barrel of oil equivalent from continuing operations for each of the past three years. Natural gas production has been converted to a barrel of oil equivalent based on approximate relative heating value (6 Mcf equals 1 barrel).
2003 2002 2001 - -------------------------------------------------------------------------------- Average price of crude oil sold (per barrel) - United States $26.14 $21.56 $22.05 North Sea 25.82 22.41 23.23 China 29.66 24.84 21.94 Other international - 20.28 19.14 Average(1) 26.04 22.04 22.60
Average price of natural gas sold (per Mcf) - United States $4.56 $3.04 $3.99 North Sea 3.09 2.35 2.46 Average(1) 4.37 2.95 3.83
Lifting costs (per barrel of oil equivalent) - United States $3.57 $3.64 $3.56 North Sea 4.52 5.64 5.03 China 6.02 8.08 7.15 Other international - 5.05 4.54 Average 3.90 4.45 4.20
(1) Includes the results of the company's 2003 and 2002 hedging program, which reduced the average price of crude oil sold by $2.46 and $1.13 per barrel, respectively, and natural gas sold by $.55 and $.01 per Mcf, respectively.
31. Capitalized Costs of Crude Oil and Natural Gas Activities
Capitalized costs of crude oil and natural gas activities and the related reserves for depreciation, depletion and amortization at the end of 2003 and 2002 are set forth in the table below.
(Millions of dollars) 2003 2002 - -------------------------------------------------------------------------------- Capitalized costs - Proved properties $10,875 $10,442 Unproved properties 837 782 Other 375 361 ------- ------- Total 12,087 11,585 Assets held for disposal 467 782 Discontinued operations - 63 ------- ------- Total 12,554 12,430 ------- -------
Reserves for depreciation, depletion and amortization - Proved properties 5,403 5,384 Unproved properties 206 155 Other 110 93 ------- ------- Total 5,719 5,632 Assets held for disposal 439 746 Discontinued operations - 17 ------- ------- Total 6,158 6,395 ------- -------
Net capitalized costs $ 6,396 $ 6,035 ======= =======
32. Crude Oil, Condensate, Natural Gas Liquids and Natural Gas Net Reserves (Unaudited)
The estimates of proved reserves have been prepared by the company's geologists and engineers in accordance with the Securities and Exchange Commission definitions. Such estimates include reserves on certain properties that are partially undeveloped and reserves that may be obtained in the future by improved-recovery operations now in operation or for which successful testing has been demonstrated. The company has no proved reserves attributable to long-term supply agreements with governments or consolidated subsidiaries in which there are significant minority interests. Natural gas liquids and natural gas volumes are determined using a gas pressure base of 14.73 psia.
The following table summarizes the changes in the estimated quantities of the company's crude oil, condensate, natural gas liquids and natural gas proved reserves for the three years ended December 31, 2003.
The following presents the company's barrel of oil equivalent proved developed and undeveloped reserves based on approximate heating value (6 Mcf equals 1 barrel).
33. Standardized Measure of and Reconciliation of Changes in Discounted Future Net Cash Flows (Unaudited)
The standardized measure of future net cash flows presented in the following table was computed using year-end prices and costs and a 10% discount factor. The future income tax expense was computed by applying the appropriate year-end statutory rates, with consideration of future tax rates already legislated, to the future pretax net cash flows less the tax basis of the properties involved. However, the company cautions that actual future net cash flows may vary considerably from these estimates. Although the company's estimates of total reserves, development costs and production rates were based on the best information available, the development and production of the oil and gas reserves may not occur in the periods assumed. Actual prices realized, costs incurred and production quantities may vary significantly from those used. Therefore, such estimated future net cash flow computations should not be considered to represent the company's estimate of the expected revenues or the current value of existing proved reserves.
(1) Future cash inflows from sales of crude oil and natural gas are based on average year-end prices of $29.05, $28.61 and $17.52 per barrel of oil and $5.77, $3.63 and $2.31 per Mcf of natural gas for 2003, 2002 and 2001, respectively.
(2) Future abandonment costs, net of anticipated salvage values, for 2002 and 2001 have been classified in future development costs (rather than production costs) to conform with the current year presentation.
(3) Estimated future net cash flows before income tax expense, discounted at 10%, totaled approximately $13.2 billion, $10.3 billion and $6.5 billion, for 2003, 2002 and 2001, respectively.
The changes in the standardized measure of future net cash flows are presented below for each of the past three years:
(Millions of dollars) 2003 2002 2001 - -------------------------------------------------------------------------------- Net change in sales prices and production costs $ 3,308 $ 6,870 $(5,879) Sales revenues less production costs (2,383) (1,795) (1,904) Purchases of reserves in place 344 243 1,117 Extensions, discoveries and other additions 1,183 347 1,232 Revisions in quantity estimates 63 (1,433) 168 Sales of reserves in place (255) (1,920) (87) Current-period development costs incurred 573 743 1,237 Changes in estimated future development costs (472) (209) (639) Accretion of discount 1,033 701 1,093 Change in income taxes (978) (1,336) 1,689 Timing and other (572) (137) (265) ------- ------- ------- Net change 1,844 2,074 (2,238) Total at beginning of year 7,062 4,988 7,226 ------- ------- ------- Total at end of year $8,906 $7,062 $ 4,988 ======= ======= =======
34. Quarterly Financial Information (Unaudited)
A summary of quarterly consolidated results for 2003 and 2002 is presented below. The quarterly per-share amounts do not add to the annual amounts due to the effects of the weighted average of stock issued and the anti-dilutive effect of convertible debentures in certain quarters.
The company's common stock is listed for trading on the New York Stock Exchange and at year-end 2003 was held by approximately 24,500 Kerr-McGee stockholders of record and Oryx and HS Resources owners who have not yet exchanged their stock. The ranges of market prices and dividends declared during the last two years for Kerr-McGee Corporation are as follows:
(1) Includes discontinued operations.
Item 9.
Item 9. Change in and Disagreements with Accountants on Accounting and Financial Disclosure None.
Item 9A.
Item 9A. 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 design and operation 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 were no significant changes in the company's internal controls or in other factors that could significantly affect these controls subsequent to the date of their evaluation.
PART III
Item 10.
Item 10. Directors and Executive Officers of the Registrant
(a) Identification of directors -
For information required under this section, reference is made to the "Director Information" section of the company's proxy statement made in connection with its Annual Stockholders' Meeting to be held on May 11, 2004.
(b) Identification of executive officers -
The information required under this section is set forth in the caption "Executive Officers of the Registrant" on pages 23 and 24 of this Form 10-K pursuant to Instruction 3 to Item 401(b) of Regulation S-K and General Instruction G(3) to Form 10-K.
(c) Compliance with Section 16(a) of the 1934 Act -
For information required under this section, reference is made to the "Section 16(a) Beneficial Ownership Reporting Compliance" section of the company's proxy statement made in connection with its Annual Stockholders' Meeting to be held on May 11, 2004.
(d) Code of ethics for the Chief Executive Officer and Principal Financial Officers -
Information regarding the Code of Ethics for The Chief Executive Officer and Principal Financial Officers can be found in Item 2. of this Form 10-K under "Availability of Reports and Governance Documents."
(e) Audit committee financial expert -
For information required under this section, reference is made to the "Information About the Board" section of the company's proxy statement made in connection with its Annual Stockholders' Meeting to be held on May 11, 2004.
Item 11.
Item 11. Executive Compensation
For information required under this section, reference is made to the executive compensation sections of the company's proxy statement made in connection with its Annual Stockholders' Meeting to be held on May 11, 2004.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Information regarding Kerr-McGee common stock that may be issued under the company's equity compensation plans as of December 31, 2003, is included in the following table:
(1) Excludes shares to be issued upon exercise of outstanding options, warrants and rights.
The Kerr-McGee Corporation Performance Share Plan was approved by the Board of Directors in January 1998 but was not approved by the company's stockholders. This plan is a broad-based stock option plan that provides for the granting of options to purchase the company's common stock to full-time, nonbargaining-unit employees, except officers. A total of 1,500,000 shares of common stock were authorized to be issued under this plan. A copy of the plan document was attached as exhibit 10.19 to the company's December 31, 2002, Form 10-K and is incorporated by reference in exhibit 10.14 to the company's December 31, 2003 Form 10-K.
For information required under Item 403 of Regulation S-K, reference is made to the "Ownership of Stock of the Company" section of the company's proxy statement made in connection with its Annual Stockholders' Meeting to be held on May 11, 2004.
Item 13.
Item 13. Certain Relationships and Related Transactions
None.
Item 14.
Item 14. Principal Accountant Fees and Services
For information required under this section, reference is made to the "Fees Paid to the Independent Auditors" section of the company's proxy statement made in connection with its Annual Stockholders' Meeting to be held on May 11, 2004.
PART IV
Item 15.
Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K
(a) 1. Financial Statements - See the Index to the Consolidated Financial Statements included in Item 8. of this Form 10-K.
(a) 2. Financial Statement Schedules - See the Index to the Financial Statement Schedules included in Item 8. of this Form 10-K.
(a) 3. Exhibits - The following documents are filed under Commission file numbers 1-16619 and 1-3939 as part of this report.
Exhibit No. -----------
3.1 Amended and restated Certificate of Incorporation of Kerr-McGee Corporation, filed as Exhibit 4.1 to the company's Registration Statement on Form S-4 dated June 28, 2001, and incorporated herein by reference.
3.2 Amended and restated By Laws of Kerr-McGee Corporation.
4.1 Rights Agreement dated as of July 26, 2001, by and between the company and UMB Bank, N.A., filed as Exhibit 4.1 to the company's Registration Statement on Form 8-A filed on July 27, 2001, and incorporated herein by reference.
4.2 First Amendment to Rights Agreement, dated as of July 30, 2001, by and between the company and UMB Bank, N.A., filed as Exhibit 4.1 to the company's Registration Statement on Form 8-A/A filed on August 1, 2001, and incorporated herein by reference.
4.3 Indenture dated as of November 1, 1981, between the company and United States Trust Company of New York, as trustee, relating to the company's 7% Debentures due November 1, 2011, filed as Exhibit 4 to Form S-16, effective November 16, 1981, Registration No. 2-772987, and incorporated herein by reference.
4.4 Indenture dated as of August 1, 1982, filed as Exhibit 4 to Form S-3, effective August 27, 1982, Registration Statement No. 2-78952, and incorporated herein by reference, and the first supplement thereto dated May 7, 1996, between the company and Citibank, N.A., as trustee, relating to the company's 6.625% notes due October 15, 2007, and 7.125% debentures due October 15, 2027, filed as Exhibit 4.1 to the Current Report on Form 8-K filed July 27, 1999, and incorporated herein by reference.
4.5 The company agrees to furnish to the Securities and Exchange Commission, upon request, copies of each of the following instruments defining the rights of the holders of certain long-term debt of the company: the Note Agreement dated as of November 29, 1989, among the Kerr-McGee Corporation Employee Stock Ownership Plan Trust (the Trust) and several lenders, providing for a loan guaranteed by the company of $125 million to the Trust; the $150 million, 8.375% Note Agreement entered into by Oryx dated as of July 17, 1996, and due July 15, 2004; the $150 million, 8-1/8% Note Agreement entered into by Oryx dated as of October 20, 1995, and due October 15, 2005; the amended and restated Revolving Credit Agreement dated as of January 11, 2002, between the company or certain subsidiary borrowers and various banks providing for revolving credit up to $650 million through January 12, 2006; the $700 million Credit Agreement dated as of November 14, 2003, between the company or certain subsidiary borrowers and various banks providing for a 364-day revolving credit facility; and the $200 million variable-interest rate Note Agreement dated June 26, 2001, and due June 28, 2004. The total amount of securities authorized under each of such instruments does not exceed 10% of the total assets of the company and its subsidiaries on a consolidated basis.
4.6 Kerr-McGee Corporation Direct Purchase and Dividend Reinvestment Plan filed on September 9, 2001, pursuant to Rule 424(b)(2) of the Securities Act of 1933 as the Prospectus Supplement to the Prospectus dated August 31, 2001, and incorporated herein by reference.
4.7 Second Supplement to the August 1, 1982, Indenture dated as of August 2, 1999, between the company and Citibank, N.A., as trustee, relating to the company's 5-1/2% exchangeable notes due August 2, 2004, filed as Exhibit 4.11 to the report on Form 10-K for the year ended December 31, 1999, and incorporated herein by reference.
4.8 Fifth Supplement to the August 1, 1982, Indenture dated as of February 11, 2000, between the company and Citibank, N.A., as trustee, relating to the company's 5-1/4% Convertible Subordinated Debentures due February 15, 2010, filed as Exhibit 4.1 to Form 8-K filed February 4, 2000, and incorporated herein by reference.
4.9 Indenture dated as of August 1, 2001, between the company and Citibank, N.A., as trustee, relating to the company's $350 million, 5-3/8% notes due April 15, 2005; $325 million, 5-7/8% notes due September 15, 2006; $675 million, 6-7/8% notes due September 15, 2011; and $500 million 7-7/8% notes due September 15, 2031, filed as Exhibit 4.1 to Form S-3 Registration Statement No. 333-68136 Pre-effective Amendment No. 1, and incorporated herein by reference.
10.1* Kerr-McGee Corporation Deferred Compensation Plan for Non-Employee Directors as amended and restated effective January 1, 2003, filed as Exhibit 10.1 to the Form 10-K for the year ended December 31, 2002, and incorporated herein by reference.
10.2* Kerr-McGee Corporation Executive Deferred Compensation Plan as amended and restated effective January 1, 2003, filed as Exhibit 10.4 to the Form 10-K for the year ended December 31, 2002, and incorporated herein by reference.
10.3* Benefits Restoration Plan as amended and restated effective May 1, 1999.
10.4* First Supplement to Benefits Restoration Plan as amended and restated effective January 1, 2000.
10.5* Second Supplement to Benefits Restoration Plan as amended and restated effective January 1, 2001.
10.6* Kerr-McGee Corporation Supplemental Executive Retirement Plan as amended and restated effective February 26, 1999, filed as exhibit 10.6 to the report on Form 10-K for the year ended December 31, 2001, and incorporated herein by reference.
10.7* First Supplement to the Kerr-McGee Corporation Supplemental Executive Retirement Plan as amended and restated effective February 26, 1999, filed as exhibit 10.7 to the report on Form 10-K for the year ended December 31, 2001, and incorporated herein by reference.
10.8* Second Supplement to the Kerr-McGee Corporation Supplemental Executive Retirement Plan as amended and restated effective February 26, 1999, filed as exhibit 10.8 to the report on Form 10-K for the year ended December 31, 2001, and incorporated herein by reference.
10.9* The Long Term Incentive Program as amended and restated effective May 9, 1995, filed as Exhibit 10.5 on Form 10-Q for the quarter ended March 31, 1995, and incorporated herein by reference.
10.10* The Kerr-McGee Corporation 1998 Long Term Incentive Plan effective January 1, 1998, filed as Exhibit 10.4 on Form 10-Q for the quarter ended March 31, 1998, and incorporated herein by reference.
10.11* The Kerr-McGee Corporation 2000 Long Term Incentive Plan effective May 1, 2000, filed as Exhibit 10.4 on Form 10-Q for the quarter ended March 31, 2000, and incorporated herein by reference.
10.12* The 2002 Long Term Incentive Plan effective May 14, 2002, filed as Exhibit 10.1 on Form 10-Q for the quarter ended June 30, 2002, and incorporated herein by reference.
10.13* The 2002 Annual Incentive Compensation Plan effective May 14, 2002, filed as Exhibit 10.1 on Form 10-Q for the quarter ended June 30, 2002, and incorporated herein by reference.
10.14* Kerr-McGee Corporation Performance Share Plan effective January 1, 1998, filed as Exhibit 10.19 to the Form 10-K for the year ended December 31, 2002, and incorporated herein by reference.
10.15* Oryx Energy Company 1992 Long-Term Incentive Plan, as amended and restated May 1, 1997.
10.16* Oryx Energy Company 1997 Long-Term Incentive Plan, as amended and restated May 1, 1997.
10.17* Amended and restated Agreement, restated as of January 11, 2000, between the company and Luke R. Corbett filed as Exhibit 10.10 on Form 10-K for the year ended December 31, 2000, and incorporated herein by reference.
10.18* Amended and restated Agreement, restated as of January 11, 2000, between the company and Kenneth W. Crouch filed as Exhibit 10.11 on Form 10-K for the year ended December 31, 2000, and incorporated herein by reference.
10.19* Amended and restated Agreement, restated as of January 11, 2000, between the company and Robert M. Wohleber filed as Exhibit 10.12 on Form 10-K for the year ended December 31, 2000, and incorporated herein by reference.
10.20* Amended and restated Agreement, restated as of January 11, 2000, between the company and William P. Woodward filed as Exhibit 10.13 on Form 10-K for the year ended December 31, 2000, and incorporated herein by reference.
10.21* Amended and restated Agreement, restated as of January 11, 2000, between the company and Gregory F. Pilcher filed as Exhibit 10.14 on Form 10-K for the year ended December 31, 2000, and incorporated herein by reference.
10.22* Form of agreement, amended and restated as of January 11, 2000, between the company and certain executive officers not named in the Summary Compensation Table contained in the company's definitive Proxy Statement for the 2001 Annual Meeting of Stockholders filed as Exhibit 10.15 on Form 10-K for the year ended December 31, 2000, and incorporated herein by reference.
12 Computation of ratio of earnings to fixed charges.
14 Code of Ethics.
21 Subsidiaries of the Registrant.
23 Consent of Ernst & Young LLP.
24 Powers of Attorney.
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.
*These exhibits relate to the compensation plans and arrangements of the company.
(b) Reports on Form 8-K -
The following Current Reports on Form 8-K were filed by the company during the quarter ended December 31, 2003:
o Current Report dated October 22, 2003, announcing a conference call to discuss the company's third-quarter 2003 financial and operating activities, and expectations for the future.
o Current Report dated October 29, 2003, announcing a security analyst meeting to discuss the company's financial and operating outlook for 2003 and certain expectations for oil and natural gas production volumes for the year 2003.
o Current Report dated October 29, 2003, announcing the company had posted on its website a table containing hedge guidance for 2003 and 2004 oil and gas derivative instruments.
o Current Report dated October 29, 2003, announcing the company had posted on its website a table containing a reconciliation of GAAP to Adjusted Net Income for the year-to-date and quarterly fiscal periods ended September 30, 2003.
o Current Report dated October 29, 2003, announcing the company's third-quarter 2003 earnings.
o Current Report dated November 3, 2003, announcing that the company would present at the Merrill Lynch Global Energy Conference on November 5, 2003.
o Current Report dated November 13, 2003, announcing certain expectations for oil and natural gas production volumes for the year 2004.
o Current Report dated November 14, 2003, announcing that the company would present at the Banc of America Securities 2003 Energy & Power Conference on November 18, 2003.
o Current Report dated November 20, 2003, announcing a conference call to discuss the company's interim fourth-quarter 2003 financial and operating activities, and expectations for the future.
o Current Report dated November 25, 2003, announcing the company had posted on its website a table containing hedge guidance for 2003 and 2004 oil and gas derivative instruments.
o Current Report dated November 25, 2003, announcing certain expectations for oil and natural gas production volumes for the year 2003.
o Current Report dated December 1, 2003, announcing that the company would present at the Friedman, Billings, Ramsey 10th Annual Investor Conference on December 3, 2003.
o Current Report dated December 9, 2003, announcing certain updates to 2004 oil and gas hedge positions.
o Current Report dated December 17, 2003, announcing a conference call to discuss the company's interim fourth-quarter 2003 financial and operating activities, and expectations for the future.
o Current Report dated December 23, 2003, announcing a security analyst meeting to discuss the company's financial and operating outlook for 2003 and certain expectations for oil and natural gas production volumes for the year 2003.
o Current Report dated December 23, 2003, announcing a security analyst meeting to discuss the company's financial and operating outlook for 2003 and certain expectations for oil and natural gas production volumes for the year 2004.
SCHEDULE II
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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
By: Luke R. Corbett* ----------------------------- Luke R. Corbett, Chief Executive Officer
March 11, 2004 By: (Robert M. Wohleber) - -------------- ----------------------------- Date Robert M. Wohleber Senior Vice President and Chief Financial Officer
By: (John M. Rauh) ----------------------------- John M. Rauh Vice President and Controller and Chief Accounting Officer
* By his signature set forth below, John M. Rauh has signed this Annual Report on Form 10-K as attorney-in-fact for the officer noted above, pursuant to power of attorney filed with the Securities and Exchange Commission.
By: (John M. Rauh) ----------------------------- John M. Rauh
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons in the capacities and on the date indicated.
By: Luke R. Corbett* ---------------------------------- Luke R. Corbett, Director
By: William E. Bradford* ---------------------------------- William E. Bradford, Director
By: Sylvia A. Earle* ---------------------------------- Sylvia A. Earle, Director
By: David C. Genever-Watling* ---------------------------------- David C. Genever-Watling, Director
March 11, 2004 By: Martin C. Jischke* - -------------- ---------------------------------- Date Martin C. Jischke, Director
By: Leroy C. Richie* ---------------------------------- Leroy C. Richie, Director
By: Matthew R. Simmons* ---------------------------------- Matthew R. Simmons, Director
By: Farah M. Walters* ---------------------------------- Farah M. Walters, Director
By: Ian L. White-Thomson* ---------------------------------- Ian L. White-Thomson, Director
* By his signature set forth below, John M. Rauh has signed this Annual Report on Form 10-K as attorney-in-fact for the directors noted above, pursuant to the powers of attorney filed with the Securities and Exchange Commission.
By: (John M. Rauh) ---------------------------------- John M. Rauh