ConocoPhillips is an international energy company and is considered the third largest US oil company.
UNITED STATESSECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549
FORM 10-Q
OR
ConocoPhillips
600 North Dairy Ashford, Houston, TX 77079(Address of principal executive offices)
281-293-1000(Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes X No
The registrant had 679,926,255 shares of common stock, $.01 par value, outstanding at July 31, 2003.
CONOCOPHILLIPS
TABLE OF CONTENTS
PART I. FINANCIAL INFORMATION
Item 1. FINANCIAL STATEMENTS
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Note 1—Interim Financial Information
The financial information for the interim periods presented in the financial statements included in this report is unaudited and includes all known accruals and adjustments that, in the opinion of management, are necessary for a fair presentation of the consolidated financial position of ConocoPhillips and its results of operations and cash flows for such periods. All such adjustments are of a normal and recurring nature. These interim financial statements should be read in conjunction with the consolidated financial statements and notes included in ConocoPhillips’ 2002 Annual Report on Form 10-K. Certain amounts in the 2002 financial statements have been reclassified to reflect discontinued operations and to conform to ConocoPhillips’ presentation.
The financial statements reflect the August 30, 2002, merger of Conoco Inc. (Conoco) and Phillips Petroleum Company (Phillips). The transaction was accounted for using the purchase method of accounting as required by Statement of Financial Accounting Standards (SFAS) No. 141, “Business Combinations.” Phillips was designated as the acquirer. Results of operations for the second quarter and first six months of 2002 reflect only Phillips’ activity.
Note 2—Changes in Accounting Principles
Effective January 1, 2003, we adopted SFAS No. 143, “Accounting for Asset Retirement Obligations,” which applies to legal obligations associated with the retirement and removal of long-lived assets. SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period when it is incurred (typically when the asset is installed at the production location). When the liability is initially recorded, the entity capitalizes the cost by increasing the carrying amount of the related property, plant and equipment. Over time, the liability is accreted upward for the change in its present value each period, and the initial capitalized cost is depreciated over the useful life of the related asset.
Application of this new accounting standard resulted in an initial increase in net properties, plants and equipment of $1.2 billion and an asset retirement obligation liability increase of $1.1 billion. The cumulative effect of this change in accounting principle increased net income in the first quarter of 2003 by $145 million. The second quarter 2003 effect of adopting this accounting principle increased net income $8 million, $.01 per basic and diluted share. The effect on net income for the first six months of 2003 was an increase of $16 million, or $.02 per basic and diluted share.
We have numerous asset removal obligations that we are required to perform under law or contract once an asset is permanently taken out of service. Most of these obligations are not expected to be paid until several years, or decades, in the future and will be funded from general company resources at the time of removal. Our largest individual obligations are related to fixed-base offshore production platforms around the world and to production facilities and pipelines in Alaska.
SFAS No. 143 calls for measurements of asset retirement obligations to include, as a component of expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties and unforeseeable circumstances inherent in the obligations, sometimes referred to as a market-risk premium. To date, the oil and gas industry has no examples of credit-worthy third
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parties who are willing to assume this type of risk, for a determinable price, on major oil and gas production facilities and pipelines. Therefore, because determining such a market-risk premium would be an arbitrary process, we have excluded it from our SFAS No. 143 estimates.
During the first six months of 2003, ConocoPhillips’ overall asset retirement obligation changed as follows:
The pro forma effects of the retroactive application of this change in accounting principle follows:
Also, effective January 1, 2003, we adopted SFAS No. 145, “Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections.” The adoption of SFAS No. 145 requires that gains and losses on extinguishments of debt no longer be presented as extraordinary items in the income statement. Accordingly, a loss from the extinguishment of debt of $15 million (after reduction for income taxes of $6 million), previously reported as an extraordinary item in the second quarter and six months of 2002, has been reclassified as a charge to other income with the appropriate tax benefit to provision for income taxes.
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Note 3—Merger of Conoco and Phillips
On August 30, 2002, Conoco and Phillips combined their businesses by merging with separate acquisition subsidiaries of ConocoPhillips (the merger). As a result, each company became a wholly owned subsidiary of ConocoPhillips. For accounting purposes, Phillips was treated as the acquirer of Conoco, and ConocoPhillips was treated as the successor of Phillips. Conoco’s operating results have been included in ConocoPhillips’ consolidated financial statements since the merger date.
The $16 billion purchase price attributed to Conoco for accounting purposes was based on an exchange of Conoco common shares for ConocoPhillips common shares. The preliminary allocation of the purchase price to specific assets and liabilities was based, in part, upon a preliminary outside appraisal of the fair value of Conoco’s assets. ConocoPhillips expects to receive the final outside appraisal of the long-lived assets during the third quarter of 2003 and conclude the fair value determination of all other Conoco assets and liabilities. Subsequent to completion of the final allocation of the purchase price and determination of the ultimate asset and liability tax bases, the deferred tax liabilities will also be finalized in the third quarter. The following table summarizes, based on a June 30, 2003, preliminary purchase price allocation, the fair values of the assets acquired and liabilities assumed as of August 30, 2002:
The allocation of the purchase price, as reflected above, has not been adjusted for the U.S. Federal Trade Commission (FTC)-mandated dispositions described in Note 4—Discontinued Operations. Goodwill, land and certain identifiable intangible assets recorded in the acquisition are not subject to amortization, but the goodwill and intangible assets will be tested periodically for impairment as required by SFAS No. 142, “Goodwill and Other Intangible Assets.”
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ConocoPhillips has not yet determined the assignment of Conoco goodwill to specific reporting units. Currently, Conoco goodwill is being reported as part of the Corporate and Other reporting segment. Included in the $12,841 million of goodwill is $4,026 million attributable to recording a net liability required under purchase accounting for deferred taxes. This and the remaining goodwill of $8,815 million will ultimately be assigned to reporting units based on the benefits received by the units from the synergies and strategic advantages of the merger. None of the goodwill is deductible for tax purposes. During the first six months of 2003, the balance of goodwill was adjusted upward by $762 million, primarily due to revisions to properties, plants and equipment, and assumed contingent liabilities.
Note 4—Discontinued Operations
During 2002 and the first six months of 2003, we disposed of, or had committed to a plan to dispose of, certain U.S. retail and wholesale marketing assets, certain U.S. refining and related assets, and exploration and production assets in the Netherlands. Certain of these planned dispositions were mandated by the FTC as a condition of the merger. For reporting purposes, these operations are classified as discontinued operations, and in Note 17—Segment Disclosures and Related Information, these operations are included in Corporate and Other.
FTC-Mandated DivestituresIn the fourth quarter of 2002, we sold our propane terminal assets at Jefferson City, Missouri, and East St. Louis, Illinois. In the second quarter of 2003 we sold:
In August 2003, we sold our Commerce City, Colorado, refinery, and related crude oil pipelines, and our Colorado Phillips-branded motor fuel marketing operations (both retail and wholesale). This completed our FTC-mandated asset dispositions.
Other DispositionsIn the fourth quarter of 2002, we committed to a plan to dispose of 3,200 marketing sites that do not fit into our long-range plans. Discussions are under way with potential buyers, and we expect to complete the sales of these assets by the end of 2003. The second quarter of 2003 included a $24 million after-tax charge for lease loss provisions expected from lease guaranteed residual value deficiencies that are being recognized as the company operates the sites until sold. The corresponding amount for the first six months of 2003 was $49 million.
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Sales and other operating revenues and income from discontinued operations were as follows:
The major classes of assets and liabilities of discontinued operations held for sale were as follows:
Note 5—Subsidiary Equity Transactions
ConocoPhillips, through various affiliates, and its unaffiliated co-venturers received final approvals from the relevant authorities in June 2003 to proceed with the natural gas development phase of the Bayu-Undan project in the Timor Sea. The natural gas development phase of the project will include a pipeline from the offshore Bayu-Undan field to Darwin, Australia, and a liquefied natural gas facility, also located in Darwin. The pipeline portion of the project is owned and operated by an unincorporated joint venture, while the liquefied natural gas facility is owned and operated by Darwin LNG Pty Ltd (DLNG). Both of these entities are consolidated subsidiaries of ConocoPhillips.
In June 2003, as part of a broad Bayu-Undan ownership interest re-alignment with co-venturers, these entities issued equity and sold interests to the co-venturers (as described below), which resulted in a gain of $28 million before-tax, $25 million after-tax, recorded in the second quarter of 2003. This non-operating gain is shown in the consolidated statement of income in the line item entitled “Gain on subsidiary equity transactions.”
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DLNG—DLNG issued 118.9 million shares of stock, valued at 1 Australian dollar per share, to co-venturers for 118.9 million Australian dollars ($76.2 million U.S. dollars), reducing our ownership interest in DLNG from 100 percent to 56.72 percent. The transaction resulted in a before-tax gain of $21 million in the consolidated financial statements. Deferred income taxes were not recognized as this was an issuance of common stock and therefore not taxable.
Unincorporated Pipeline Joint Venture—The co-venturers purchased pro-rata interests in the pipeline assets held by ConocoPhillips Pipeline Australia Pty Ltd for $26.6 million U.S. dollars and contributed the purchased assets to the unincorporated joint venture, reducing our ownership interest from 100 percent to 56.72 percent. The transaction resulted in a before-tax gain of $7 million in the consolidated financial statements. A deferred tax liability of $1.3 million was recorded in connection with the transaction.
Note 6—Stock-Based Compensation
Effective January 1, 2003, ConocoPhillips adopted the fair-value accounting method of SFAS No. 123, “Accounting for Stock-Based Compensation.” Using the prospective transition method, we recognize compensation expense using the fair-value accounting method for all stock options granted or modified after December 31, 2002, whereas we continue to account for options granted prior to 2003 in accordance with Accounting Principles Board (APB) No. 25, “Accounting for Stock Issued to Employees,” and related Interpretations. The following table illustrates the effect on net income and earnings per share as if the fair-value-based method had been applied to all outstanding and unvested awards in each period.
The pro forma total stock-based employee compensation expense determined using the fair-value-based method was higher during the first six months of 2002, compared with the same period in 2003, due to the accelerated vesting of options triggered by the March 2002 shareholder approval of the merger.
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Note 7—Inventories
Inventories consisted of the following:
Inventories valued on a last-in, first-out (LIFO) basis totaled $3,482 million and $3,349 million at June 30, 2003, and December 31, 2002, respectively. The excess of current replacement cost over LIFO cost of inventories amounted to $1,079 million and $1,083 million at June 30, 2003, and December 31, 2002, respectively.
Note 8—Properties, Plants and Equipment
Properties, plants and equipment included the following:
Property Impairments—In the second quarter of 2003, we recorded property impairments totaling $146 million before-tax, $49 million after-tax. The impairments were recorded as a result of asset status changes from held for use to held for sale, unsuccessful development drilling results, and Norway tax law changes dealing with the treatment of asset removal costs. Of the total charges in the second quarter, $141 million before-tax, $46 million after-tax, were related to properties in the Exploration and Production segment, primarily in the North Sea, Canada, and the U.S. Lower 48. The remaining amounts related to the Corporate and Other reporting segment.
Note 9—Restructuring
In 2002, as a result of the merger, we began a restructuring program to capture the benefits of combining Conoco and Phillips by eliminating redundancies, consolidating assets, and sharing common services and functions across regions. As a result, we recognized an estimated restructuring liability for anticipated employee severance payments and incremental pension and medical plan benefit costs associated with work force reductions, site closings, and Conoco employee relocations. In the first six months of 2003, we recorded additional accruals totaling $225 million for severance-related benefits, site closings, Conoco
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employee relocation costs, and pension and other post-retirement benefits. Of this total, $77 million was reflected as a purchase price adjustment in the consolidated financial statements and $148 million was reflected in selling, general and administrative expense and production and operating expense. Included in the total additional accruals of $225 million was an $83 million expense related to pension and other post-retirement benefits that will be paid in conjunction with other retirement benefits over a number of future years. This is reported as part of our employee benefit plan obligations. A roll-forward of activity during the first six months of 2003 is provided below for the non-pension portion of the accrual, which consists of severance-related benefits to be provided to approximately 3,800 employees worldwide, most of whom are in the United States, as well as other merger related expenses.
The restructuring liability at June 30 of $287 million is expected to be expended by the end of the first quarter of 2004; except for $36 million, classified as long-term. The remaining $251 million is included in other accruals in the current liabilities section of the balance sheet. Approximately 1,550 employees were terminated during the first six months of 2003 and approximately 2,325 employees have been terminated since the restructuring program was implemented.
Note 10—Debt
At June 30, 2003, we had three bank credit facilities in place, totaling $4 billion, available for use either as direct bank borrowings or as support for the issuance of up to $4 billion in commercial paper, a portion of which may be denominated in other currencies (limited to euro 3 billion equivalent). The facilities included a $2 billion, 364-day revolving credit facility expiring on October 14, 2003, and two revolving credit facilities totaling $2 billion expiring in October 2006. At June 30, 2003, we had no debt outstanding under these credit facilities, but had $801 million in commercial paper outstanding, of which $99 million was denominated in foreign currencies. The commercial paper is supported 100 percent by the credit facilities and the amount approximates fair value. One of our Norwegian subsidiaries has two $300 million revolving credit facilities that expire in June 2004, under which no borrowings were outstanding as of June 30, 2003.
During the first six months of 2003, in addition to reducing our commercial paper from $1,517 million at December 31, 2002, to $801 million at June 30, 2003, we paid the following notes as they were called or matured, and funded the payments with cash from operating activities and proceeds from asset dispositions:
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Note 11—Contingencies
We are subject to various lawsuits and claims including, but not limited to: actions challenging oil and gas royalty and severance tax payments; actions related to gas measurement and valuation methods; actions related to joint interest billings to operating agreement partners; and claims for damages resulting from leaking underground storage tanks, or other accidental releases, with related toxic tort claims. As a result of Conoco’s separation agreement with DuPont, we also have assumed responsibility for current and future claims related to certain discontinued chemicals and agricultural chemicals businesses operated by Conoco in the past. In general, the effect on future financial results is not subject to reasonable estimation because considerable uncertainty exists. The ultimate liabilities resulting from such lawsuits and claims may be material to results of operations in the period in which they are recognized.
In the case of all known contingencies, we accrue a liability when the loss is probable and the amount is reasonably estimable. We do not reduce these liabilities for potential insurance or third-party recoveries. If applicable, we accrue receivables for probable insurance or other third-party recoveries. Based on currently available information, we believe that it is remote that future costs related to known contingent liability exposures will exceed current accruals by an amount that would have a material adverse impact on our financial statements.
As we learn new facts concerning contingencies, we reassess our position both with respect to accrued liabilities and other potential exposures. Estimates that are particularly sensitive to future changes include contingent liabilities recorded for environmental remediation, tax and legal matters. Estimated future environmental remediation costs are subject to change due to such factors as the uncertain magnitude of cleanup costs, the unknown time and extent of such remedial actions that may be required, and the determination of our liability in proportion to that of other responsible parties. Estimated future costs related to tax and legal matters are subject to change as events evolve and as additional information becomes available during the administrative and litigation processes.
Environmental—We are subject to federal, state and local environmental laws and regulations. These may result in obligations to remove or mitigate the effects on the environment of the placement, storage, disposal or release of certain chemical, mineral and petroleum substances at various sites. When we prepare our financial statements, we record accruals for environmental liabilities based on management’s best estimate, using all information that is available at the time. We measure estimates and base liabilities on currently available facts, existing technology, and presently enacted laws and regulations, taking into consideration the likely effects of societal and economic factors. When measuring environmental liabilities, we also consider our prior experience in remediation of contaminated sites, other companies’ cleanup experience and data released by the U.S. Environmental Protection Agency (EPA) or other organizations. We consider unasserted claims in our determination of environmental liabilities and we accrue them in the period that they are both probable and reasonably estimable.
Although liability of those potentially responsible for environmental remediation costs is generally joint and several for federal sites and frequently so for state sites, we are usually only one of many companies cited at a particular site. Due to the joint and several liabilities, we could be responsible for all of the cleanup costs related to any site at which we have been designated as a potentially responsible party. If ConocoPhillips were solely responsible, the costs, in some cases, could be material to our, or one of our segment’s, operations, capital resources or liquidity. However, settlements and costs incurred in matters
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that previously have been resolved have not been material to our results of operations or financial condition. We have been successful to date in sharing cleanup costs with other financially sound companies. Many of the sites at which we are potentially responsible are still under investigation by the EPA or the state agencies concerned. Prior to actual cleanup, those potentially responsible normally assess the site conditions, apportion responsibility and determine the appropriate remediation. In some instances, ConocoPhillips may have no liability or attain a settlement of liability. Where it appears that other potentially responsible parties may be financially unable to bear their proportional share, we consider this inability in estimating our potential liability and we adjust our accruals accordingly.
As a result of various acquisitions in the past, we assumed certain environmental obligations. Some of these environmental obligations are mitigated by indemnification agreements and some of the indemnifications are subject to dollar limits and time limits. We have not recorded accruals for any potential contingent liabilities that we expect to be funded by the prior owners under these indemnifications.
We are currently participating in environmental assessments and cleanups at federal Superfund and comparable state sites. After an assessment of environmental exposures for cleanup and other costs, we make accruals on an undiscounted basis (except, if assumed in a purchase business combination, we record such costs on a discounted basis) for planned investigation and remediation activities for sites where it is probable that future costs will be incurred and these costs can be reasonably estimated. We expect to incur the majority of these expenditures within the next 30 years. We have not reduced these accruals for possible insurance recoveries. In the future, we may be involved in additional environmental assessments, cleanups and proceedings. At June 30, 2003, ConocoPhillips’ balance sheet included a total environmental accrual from continuing operations of $845 million, compared with $743 million at December 31, 2002. The increase in the accrual from year-end 2002, primarily resulted from the continuing assessment of Conoco environmental liabilities during the period allowed by purchase accounting rules. These accrued environmental liabilities assumed in the merger are discounted obligations. These expected expenditures are discounted using a weighted average 5 percent discount factor, resulting in an additional accrued balance of $113 million. The expected inflated expenditures for these additional accruals are: $25 million in 2003, $39 million in 2004, $18 million in 2005, $8 million in 2006, and $7 million in 2007. The remaining expenditures in all future years after 2007 for these additional accruals are expected to total $42 million. Final purchase price adjustments will be recognized in the third quarter of 2003.
Other Legal Proceedings—We are a party to a number of other legal proceedings pending in various courts or agencies for which, in some instances, no provision has been made.
Other Contingencies—We have contingent liabilities resulting from throughput agreements with pipeline and processing companies. Under these agreements, we may be required to provide any such company with additional funds through advances and penalties for fees related to throughput capacity not utilized by ConocoPhillips. In addition, we have various purchase commitments for materials, supplies, services and items of permanent investment incident to the ordinary conduct of business.
Note 12—Guarantees
At June 30, 2003, we were liable for certain contingent obligations under various contractual arrangements as described below. We are required to recognize a liability at inception for the fair value of our obligation as a guarantor for guarantees issued or modified after December 31, 2002. Unless the carrying amount of the liability is noted, we have not recognized a liability either because the guarantees were issued prior to December 31, 2002, or because the fair value of the obligation is immaterial.
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Construction Completion Guarantees
Guaranteed Residual Value on Leases
Guarantees of Joint-Venture Debt
Other Guarantees
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Indemnifications
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Note 13—Comprehensive Income
ConocoPhillips’ comprehensive income was as follows:
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Accumulated other comprehensive income (loss) in the equity section of the balance sheet included:
Note 14—Supplemental Cash Flow Information
Cash payments for the six-month periods ended June 30 included the following:
Non-cash investing and financing activities for the six-month period of 2003 included a $1.6 billion increase in properties, plants and equipment and a related increase in long-term liabilities of $1.5 billion associated with the implementation and continuing application of SFAS No. 143. For additional information related to the implementation of SFAS No. 143, see Note 2—Changes in Accounting Principles.
Note 15—Sales of Receivables
At June 30, 2003, ConocoPhillips had sold certain credit card and trade receivables to two Qualifying Special Purpose Entities (QSPEs) in revolving-period securitization arrangements. These arrangements provide for us to sell, and the QSPEs to purchase, certain receivables and for the QSPEs to then issue beneficial interests of up to $1.5 billion to five bank-sponsored entities. We retain beneficial interests in the pools of receivables held by the QSPEs that are subordinate to the beneficial interests issued to the bank-sponsored entities. Our retained interests, reported on the balance sheet in accounts and notes receivable—related parties, were $1.3 billion at June 30, 2003, and December 31, 2002. We also retain servicing responsibility related to the sold receivables, the fair value of which approximates adequate compensation for the servicing costs incurred.
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In the first six months of 2003 and 2002, total cash flows received from and paid under the securitization arrangements were as follows:
At June 30, 2003, and December 31, 2002, we had sold $171 million and $264 million, respectively, of receivables under a factoring arrangement that included a recourse obligation to repurchase uncollected receivables.
Note 16—Related Party Transactions
Significant transactions with related parties were:
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Elimination of our equity percentage share of profit or loss on the above transactions was not material.
Note 17—Segment Disclosures and Related Information
We have organized our reporting structure based on the grouping of similar products and services, resulting in five operating segments:
Corporate and Other includes general corporate overhead, all interest income and expense, preferred dividend requirements of capital trusts, discontinued operations, restructuring charges and goodwill resulting from the merger, certain eliminations, and various other corporate activities. Corporate assets include all cash and cash equivalents.
We evaluate performance and allocate resources based on, among other items, net income. Intersegment sales are recorded at prices that approximate market value.
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Analysis of Results by Operating Segment
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Note 18—Income Taxes
ConocoPhillips’ effective tax rates for the second quarter and first six months of 2003 were 38 percent and 46 percent, respectively, compared with 53 percent and 70 percent for the same periods a year ago. Contributing to the decline in both the second quarter and six months of 2003, compared with the corresponding periods in 2002, was the one-time impact of tax law changes in certain international jurisdictions. The effective tax rate in excess of the domestic federal statutory rate of 35 percent was generally due to foreign taxes in excess of the domestic federal statutory rate. In addition, the 2002 period was impacted by a higher proportion of income in higher tax-rate jurisdictions and losses in lower tax-rate jurisdictions, including the partial impairment in the six-month period of an exploration prospect that had no corresponding tax benefit.
Note 19—New Accounting Standards
In January 2003, the Financial Accounting Standards Board (FASB) issued Interpretation No. 46, “Consolidation of Variable Interest Entities,” (FIN 46) in an effort to expand upon and strengthen existing accounting guidance that addresses when a company should include in its consolidated financial statements the assets, liabilities and activities of another entity. In general, a variable interest entity (VIE) is a corporation, partnership, trust, or any other legal structure used for business purposes that either (a) does not have equity investors with voting rights or (b) has equity investors that do not provide sufficient financial resources for the entity to support its activities. FIN 46 requires a VIE to be consolidated by a company if that company is subject to a majority of the risk of loss from the VIE’s activities, is entitled to receive a majority of the VIE’s residual returns, or both (the company required to consolidate is called the primary beneficiary). It also requires deconsolidation of a VIE if a company is not the primary beneficiary of the VIE. The interpretation also requires disclosures about VIEs that we are not required to consolidate, but in which we have a significant variable interest. The consolidation requirements of FIN 46 applied immediately to VIEs created after January 31, 2003, and will apply to older VIEs effective July 1, 2003. For our VIEs created before January 31, 2003, we plan to adopt this pronouncement in the third quarter of 2003, with retroactive application as of January 1, 2003.
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In April 2003, the FASB released SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities,” most of which must be adopted prospectively as of July 1, 2003. We have reviewed this new release and do not expect adoption of this standard to have a material impact on our results of operations or financial position.
In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Liabilities and Equity,” to address the balance sheet classification of certain financial instruments that have characteristics of both liabilities and equity. The statement is already effective for all contracts created or modified after May 31, 2003, and became effective July 1, 2003, for all previously existing contracts. Applying the new rule, we expect to reclassify $141 million of currently reported minority interest securities to debt.
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Supplementary Information—Condensed Consolidating Financial Information
In connection with the merger of ConocoPhillips Holding Company (formerly named Conoco Inc.) and ConocoPhillips Company (formerly named Phillips Petroleum Company) with wholly owned subsidiaries of ConocoPhillips, and to simplify our credit structure, we have established various cross guarantees between ConocoPhillips, ConocoPhillips Holding Company, and ConocoPhillips Company. With the new organizational structure, ConocoPhillips Company is the direct or indirect parent of former Conoco and Phillips subsidiaries and is wholly owned by ConocoPhillips Holding Company, which is wholly owned by ConocoPhillips. ConocoPhillips and ConocoPhillips Holding Company have fully and unconditionally guaranteed the payment obligations of ConocoPhillips Company with respect to its publicly held debt securities. Similarly, ConocoPhillips and ConocoPhillips Company have fully and unconditionally guaranteed the payment obligations of ConocoPhillips Holding Company with respect to the publicly held debt securities of ConocoPhillips Holding Company. In addition, ConocoPhillips Company and ConocoPhillips Holding Company have fully and unconditionally guaranteed the payment obligations of ConocoPhillips with respect to its publicly held debt securities. All guarantees are joint and several. The following condensed consolidating financial information presents the results of operations, financial position and cash flows for:
Effective June 30, 2003, Bayway Refining Company and Marcus Hook Refining Company were merged into ConocoPhillips Company. Previously reported prior period information has been restated to reflect this reorganization of companies under common control.
This condensed consolidating financial information should be read in conjunction with our accompanying consolidated financial statements and notes.
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Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITIONS AND RESULTS OF OPERATIONS
Management’s Discussion and Analysis contains forward-looking statements including, without limitation, statements relating to our plans, strategies, objectives, expectations, and intentions, that are made pursuant to the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. The words “intends,” “believes,” “expects,” “plans,” “scheduled,” “anticipates,” “estimates,” and similar expressions identify forward-looking statements. The company does not undertake to update, revise or correct any of the forward-looking information. Readers are cautioned that such forward-looking statements should be read in conjunction with the company’s disclosures under the heading: “CAUTIONARY STATEMENT FOR THE PURPOSES OF THE ‘SAFE HARBOR’ PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995” beginning on page 58.
RESULTS OF OPERATIONS
Unless otherwise indicated, discussion of results for the three- and six-month periods ending June 30, 2003, is based on a comparison with the corresponding periods of 2002. The merger of Conoco Inc. (Conoco) and Phillips Petroleum Company (Phillips) on August 30, 2002, impacts the comparability of the 2003 periods with the corresponding 2002 periods.
Conoco and Phillips Merger
On August 30, 2002, Conoco and Phillips combined their businesses by merging with wholly owned subsidiaries of a new company named ConocoPhillips (the merger). The merger was accounted for using the purchase method of accounting, with Phillips designated as the acquirer for accounting purposes. Because Phillips was designated as the acquirer, it is treated as the predecessor to ConocoPhillips and its operations and results are presented in this quarterly report for all periods prior to the close of the merger. From the merger date forward, the operations and results of ConocoPhillips reflect the combined operations of the two companies. For additional information on the merger, see Note 3—Merger of Conoco and Phillips, in the Notes to Consolidated Financial Statements.
Consolidated Results
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A summary of net income (loss) by business segment follows:
Net income was $1,138 million in the second quarter of 2003, compared with net income of $351 million in the second quarter of 2002. Net income was $2,575 million in the six-month period ending June 30, 2003, compared with $249 million in the corresponding period of 2002. The improved results in both periods primarily were due to increased upstream and downstream production volumes as a result of the merger, higher crude oil and natural gas sales prices in our E&P segment, and improved refining margins and wholesale gasoline margins in our R&M segment. See the “Segment Results” section for additional information on our E&P and R&M results, as well as our other reporting segments.
Income Statement Analysis
Sales and other operating revenues increased 143 percent in the second quarter of 2003, and 177 percent in the six-month period. The increases were attributable to both higher sales volumes and sales prices of key products such as crude oil, natural gas, automotive gasoline and distillates. Most of our sales volume increases were the result of the merger, while market factors led to increased sales prices of key products.
Equity in earnings of affiliates increased 438 percent in the second quarter of 2003, and 318 percent in the six-month period. Our share of earnings from affiliates acquired in the merger accounted for the majority of the increased equity earnings. Of these, our E&P joint ventures in Canada (Petrovera) and Venezuela (Petrozuata) provided the largest equity earnings. Of those equity affiliates included in the results of both years, our equity earnings from Duke Energy Field Service, LLC improved on higher natural gas liquids prices and gains on asset sales, and our earnings from Hamaca, an E&P joint venture in Venezuela, increased due to increased crude oil production volumes.
Other income increased 318 percent in the second quarter of 2003, and 249 percent in the six-month period. The increase in the second quarter of 2003 mainly was attributable to higher net gains on asset dispositions, additional operations following the merger, and a business interruption insurance settlement. In addition, the increase in the six-month period of 2003 was also attributable to insurance demutualization benefits. See the Corporate and Other section of “Segment Results” for additional information on the insurance benefits.
Purchased crude oil and products increased 129 percent in the second quarter of 2003, and 166 percent in the six-month period. The increase in both periods was attributable to both higher purchase volumes and purchase prices of petroleum products such as automotive gasoline and distillates, as well as higher
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purchase volumes and purchase prices for crude oil, which is used as a feedstock in our refineries. Most of our purchase volume increases were the result of the merger, while market factors led to increased purchase prices of key products.
Production and operating expenses increased 115 percent in the second quarter of 2003 and 97 percent in the six-month period, while selling, general and administrative expenses increased 201 percent and 141 percent, respectively. These increases primarily reflect:
Exploration expenses increased 112 percent in the second quarter of 2003, and 12 percent in the six-month period. The increase in the second quarter of 2003 reflects the increased size of our exploration program following the merger, as well as higher dry hole costs. In the first quarter of 2002, we recognized a $77 million partial impairment of our leasehold investment in deepwater Block 34, offshore Angola. The absence of such a significant item in the first six months of 2003 contributed to the lower percentage increase in the six-month period.
Depreciation, depletion and amortization increased 114 percent in the second quarter and six-month period of 2003. The increases mainly were the result of our increased depreciable base of properties, plants and equipment (PP&E) after the merger. The amount of our net PP&E at June 30, 2003, was $45.3 billion, compared with $22.9 billion at June 30, 2002.
Property impairments increased significantly in the second quarter and first six months of 2003. The 2003 impairments were recorded as a result of asset status changes from held for use to held for sale, unsuccessful development drilling results, and tax law changes in Norway dealing with asset removal costs. See Note 8—Properties, Plants and Equipment, in the Notes to Consolidated Financial Statements, for additional information.
Taxes other than income taxes increased 271 percent in the second quarter of 2003, and 273 percent in the six-month period. The increase in both periods reflects higher excise taxes due to increased petroleum products sales volumes, higher production taxes due to increased crude oil production and prices, and increased property and payroll taxes, all following the merger.
Accretion on discounted liabilities increased 483 percent in the second quarter of 2003, and 518 percent in the six-month period. Both increases reflect the impact of environmental liabilities assumed in the merger. Effective January 1, 2003, this item also includes the accretion related to discounted obligations associated with the retirement and removal of long-lived assets. See Note 2—Changes in Accounting Principles, in the Notes to Consolidated Financial Statements, for additional information.
Interest expense increased 74 percent in the second quarter of 2003, and 85 percent in the six-month period. Both increases mainly were due to our higher debt levels following the merger. Our total debt at June 30, 2003, was $17.6 billion, compared with $9.6 billion at June 30, 2002.
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Our effective tax rate for the second quarter of 2003 was 38 percent, compared with 53 percent for the same period in the prior year. Our effective tax rate for the first six months of 2003 was 46 percent, compared with 70 percent for the corresponding period in 2002. The lower effective tax rates in the 2003 periods primarily were the result of the one-time impact of tax law changes in certain international jurisdictions and a higher proportion of income in lower-tax-rate jurisdictions. Contributing to the higher effective tax rate in the six-month 2002 period was the partial impairment of an exploration prospect that had no corresponding tax benefit.
Income from discontinued operations was $59 million in the second quarter of 2003, compared with $39 million in the second quarter of 2002. For the six-month periods, income from discontinued operations was $81 million in 2003, compared with $35 million in 2002. The improvement in the 2003 periods reflects the addition of assets classified as discontinued following the merger, as well as higher marketing margins and reduced depreciation expense. The improvement was partially offset by $24 million in the second quarter of 2003 and $49 million in the six-month period of losses expected from plans to terminate operating leases that provide for guaranteed residual values for retail sites that we plan to sell. For additional information about discontinued operations, see Note 4—Discontinued Operations, in the Notes to Consolidated Financial Statements.
We recognized higher foreign currency transaction gains in both the second quarter and six-month period of 2003, while preferred dividend requirements and minority interests increased slightly.
In the second quarter of 2003, we recognized a $28 million gain on subsidiary equity transactions related to our E&P Bayu-Undan development in the Timor Sea. See Note 5—Subsidiary Equity Transactions, in the Notes to Consolidated Financial Statements, for additional information.
We adopted Financial Accounting Standards Board Statement No. 143, “Accounting for Asset Retirement Obligations,” (SFAS No. 143) effective January 1, 2003. As a result, we recognized a benefit of $145 million for the cumulative effect of this accounting change in the first quarter of 2003. For additional information on this accounting change, see Note 2—Changes in Accounting Principles, in the Notes to Consolidated Financial Statements.
Restructuring Accruals
As a result of the merger, we began a restructuring program in September 2002 to capture the benefits of combining Conoco and Phillips by eliminating redundancies, consolidating assets, and sharing common services and functions across regions. We expect the restructuring program to be completed by the end of the first quarter of 2004. From September 2002 through June 30, 2003, approximately 3,800 positions worldwide had been identified for elimination. Of this total, 2,325 employees had been terminated by June 30, 2003.
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A roll-forward of activity during the first six months of 2003 is provided in the table below for the non-pension portion of the accrual.
The restructuring accrual balance of $287 million at June 30, 2003, is expected to be expended by the end of the first quarter of 2004, except for $36 million, which is classified as long-term. The pension and other post-retirement benefits will be paid in conjunction with other retirement benefits over a number of future years and are reported as part of our employee benefit plan obligations. For additional information on restructuring charges, see Note 9—Restructuring, in the Notes to Consolidated Financial Statements.
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Segment Results
E&P
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Net income from our E&P segment increased 216 percent in the second quarter of 2003, and 389 percent in the six-month period. The increases reflect:
These items were partially offset by increased production and operating expenses; depreciation, depletion and amortization; and taxes other than income taxes following the merger, reflecting the larger size and scope of our operations.
Our average worldwide crude oil sales price was $25.19 per barrel in the second quarter of 2003, compared with $24.44 in the second quarter of 2002. Our average crude oil price was higher for the six-month period as well, averaging $27.82 per barrel in 2003, compared with $21.90 per barrel in 2002. We also benefited from higher natural gas prices, with our average worldwide price increasing from $2.40 per thousand cubic feet in the second quarter of 2002 to $3.93 in the second quarter of 2003. See the “Outlook” section for additional discussion of crude oil and natural gas prices.
U.S. E&P
Net income from our U.S. E&P operations increased 84 percent in the second quarter of 2003, and 211 percent in the six-month period. The majority of the increase in both periods resulted from higher crude oil and natural gas prices. Increased production volumes following the merger accounted for the remaining increase, after considering the corresponding increases that go along with higher production, such as higher production taxes; production and operating expenses; and depreciation, depletion and amortization. Our U.S. E&P operations recognized a benefit of $161 million for the cumulative effect of adopting SFAS No. 143 in the first quarter of 2003.
U.S. E&P production on a barrel-of-oil-equivalent basis averaged 678,000 barrels per day in the second quarter of 2003, compared with 696,000 barrels per day in the first quarter of 2003. The 3 percent decrease primarily was due to seasonal and field declines, and maintenance work at the Greater Prudhoe Bay Area in Alaska, partially offset by improved production from Palm in the Greater Kuparuk Area and from Alpine, both in Alaska.
International E&P
Net income from our international E&P operations increased significantly in the second quarter and first six months of 2003. Increased production volumes following the merger accounted for the majority of the increase in both periods, after considering the corresponding increases that go along with higher production, such as higher production taxes; production and operating expenses; and depreciation, depletion and amortization. Higher crude oil and natural gas prices contributed to the remaining increase. Our international E&P operations recognized a charge of $15 million for the cumulative effect of adopting SFAS No. 143 in the first quarter of 2003. Included in international E&P’s net income in the second quarter of 2003 were foreign currency transaction losses of $24 million, compared with losses of
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$7 million in the second quarter of 2002. The six-month period of 2003 included foreign currency transaction losses of $14 million, while the corresponding period of 2002 had losses of $5 million.
International E&P’s net income in the second quarter of 2003 was also favorably impacted by two items:
International E&P production on a barrel-of-oil-equivalent basis averaged 939,000 barrels per day in the second quarter of 2003, compared with 909,000 barrels per day in the first quarter. The 3 percent increase primarily was due to increased production from our equity affiliates in Venezuela, where political unrest shut down our heavy oil production in December 2002. Full production was restored during March of 2003.
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Midstream
Our Midstream segment consists of a 30.3 percent interest in Duke Energy Field Services, LLC (DEFS), as well as our other natural gas gathering and processing operations, and natural gas liquids fractionation and marketing businesses.
Net income from our Midstream segment increased 108 percent in the second quarter of 2003, and 133 percent in the six-month period. The increases primarily were attributable to improved results from DEFS and the addition of midstream operations following the merger. DEFS’ results mainly increased because of higher natural gas liquids prices and gains on asset sales.
Included in the Midstream segment’s net income was a benefit of $9 million in the second quarter of 2003, the same as the second quarter of 2002, representing the amortization of the excess amount of our 30.3 percent equity interest in the net assets of DEFS over the book value of our investment in DEFS. The six-month periods for both years included $18 million for the basis difference.
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R&M
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Net income from our R&M segment increased $233 million in the second quarter of 2003, and $690 million in the six-month period. The improved results in both periods were attributable to the addition of refining and marketing assets in the merger and higher refining margins and wholesale gasoline margins. However, we accrued losses totaling $25 million after-tax in the second quarter of 2003 and $50 million after-tax in the six-month period of 2003 for plans to terminate operating leases that provide for guaranteed residual values related to various retail sites that we plan to keep, but are planning to convert from leased sites to company-owned sites.
Our worldwide crude oil refining capacity utilization rate was 96 percent in the second quarter of 2003, compared with 95 percent in the corresponding period of 2002. Our refineries produced 2,764,000 barrels per day of petroleum products in the second quarter of 2003, compared with 1,795,000 barrels per day in the second quarter of 2002. The increase reflects the addition of production from refineries acquired in the merger.
U.S. R&M
Net income from our U.S. R&M operations increased 211 percent in the second quarter of 2003. In the first six months of 2003, U.S. R&M net income was $483 million, compared with a net loss of $19 million in the first six months of 2002. The improvement in both periods was primarily due to higher refining margins, higher marketing margins and the addition of refining and marketing assets in the merger. The average cost of a barrel of crude oil feedstock for our U.S. refineries was $27.36 in the second quarter of 2003, compared with $25.00 in the second quarter of 2002.
Also impacting our U.S. R&M operations were higher fuel and utility costs due to increased natural gas prices, as well as the lease-loss provisions discussed above totaling $25 million and $50 million after-tax that we recognized in the second quarter and first six months of 2003, respectively.
Our U.S. crude oil capacity utilization rate was 98 percent in the second quarter of 2003, compared with 93 percent in the first quarter of 2003. Our first quarter 2003 utilization rate was negatively affected by scheduled maintenance turnarounds at our Sweeny, Wood River and Ferndale refineries. The Ferndale turnaround included the startup of a new fluid catalytic cracking unit designed to increase the yield of transportation fuel.
International R&M
Net income from our international R&M operations was $74 million in the second quarter of 2003, compared with a net loss of $5 million in the second quarter of 2002. In the six-month period, international R&M net income was $188 million, compared with breakeven in the corresponding period of 2002. Both improvements were due to the larger size and scope of our international refining operations following the merger. In the second quarter and six-month period of 2002, our international R&M operations consisted of our Whitegate refinery in Ireland with a crude oil capacity of 72,000 barrels per day, while in the corresponding periods of 2003 our international R&M operations consisted of five additional refineries with an additional crude capacity of 370,000 barrels per day. Following the merger, we also have an extensive marketing network throughout Europe and Asia.
Our international crude oil capacity utilization rate was 85 percent in the second quarter of 2003, compared with 90 percent in the first quarter of 2003. The decline in the second quarter was due to scheduled and unscheduled downtime at our Humber refinery in the United Kingdom.
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Chemicals
The Chemicals segment consists of our 50 percent interest in Chevron Phillips Chemical Company LLC (CPChem), which we account for using the equity method of accounting. Net income from our Chemicals segment increased 71 percent in the second quarter of 2003. Net loss for the first six months of 2003 was $11 million, compared with a net loss of $4 million in the same period of 2002.
The improvement in the second quarter of 2003 primarily was the result of improved margins, as higher sales prices more than offset increased feedstock and utility costs. Although the 2003 second quarter showed improvement, the chemicals industry continues to be challenged to effectively utilize capacity, manage costs and improve margins in an adverse economic environment. Global economic slowdown in the last several years has reduced overall chemical demand, which has led to excess production capacity in the industry and pressured margins on key product lines. The chemicals industry is also impacted by energy prices, which affect both utility and feedstock costs.
At a product line level, results from ethylene, polyethylene, benzene and polystyrene improved in the second quarter of 2003, primarily due to improved margins resulting from increased sales prices outpacing higher feedstock and utility costs. The improved ethylene and polyethylene margins were partly offset by lower sales volumes. Results from normal alpha olefins and styrene were lower in the second quarter of 2003 because of lower margins.
Lower margins across most key product lines resulted in an increased net loss in the first six months of 2003, compared with the corresponding period of 2002. Earnings were also negatively impacted by lower sales volumes of ethylene, polyethylene and normal alpha olefins.
Emerging Businesses
The Emerging Businesses segment includes the development of new businesses outside our traditional operations. Our Emerging Businesses segment incurred a net loss of $23 million in the second quarter of 2003, compared with a net loss of $3 million in the second quarter of 2002. Emerging Businesses incurred a net loss of $57 million in the first six months of 2003, compared with a net loss of $8 million in the
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corresponding period of 2002. The increased net loss in both 2003 periods was the result of the expanded size of this segment following the merger. In the first six months of 2002, this segment included only the development of new fuels technologies, while in the first six months of 2003 additional new businesses acquired in the merger related to gas-to-liquids technologies, power generation, carbon fibers, and other emerging technologies were included.
We announced in February 2003 the shutdown of our carbon fibers project, as a result of market, operating and technology uncertainties. At the time of the merger, we had identified the uncertainties facing the carbon fibers project and initiated a strategic review. In early 2003, the strategic review was completed and management approved the plan to shut down the project.
Corporate and Other
Net interest after-tax represents interest expense, net of interest income and capitalized interest, as well as premiums incurred on the early retirement of debt. Net interest increased 51 percent in the second quarter of 2003, and 80 percent in the six-month period. The increase in both 2003 periods mainly was due to our higher debt levels following the merger. Our total debt at June 30, 2003, was $17.6 billion, compared with $9.6 billion at June 30, 2002.
After-tax corporate general and administrative expenses increased 41 percent in the second quarter of 2003, while decreasing slightly in the six-month period. Expenses were higher in the second quarter comparison because of the impact of the merger, as well as the expensing of stock options in the second quarter of 2003. Beginning in 2003, on a prospective basis, we elected to use the fair-value accounting method provided for under SFAS No. 123, “Accounting for Stock-Based Compensation.” See Note 6—Stock-Based Compensation, in the Notes to Consolidated Financial Statements, for additional information. In the six-month period of 2003, we benefited from lower long-term compensation plan expenses. Both 2003 periods benefited from increased allocations of certain of our staff costs to the operating segments. The increased corporate allocations did not have a material impact on the operating segment’s results.
Income from discontinued operations was $59 million in the second quarter of 2003, compared with $39 million in the second quarter of 2002. For the six-month periods, income from discontinued operations was $81 million in 2003, compared with $35 million in 2002. The improvement in the 2003 periods reflects the addition of assets classified as discontinued following the merger, as well as higher marketing margins and reduced depreciation expense. The improvement was partially offset by losses of $24 million in the second quarter of 2003 and $49 million in the six-month period related to plans to terminate operating leases that provide for guaranteed residual values for retail sites that we plan to sell. For additional information about discontinued operations, see Note 4—Discontinued Operations, in the Notes to Consolidated Financial Statements.
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On an after-tax basis, merger-related costs in the second quarter of 2003 were $115 million, and were $142 million in the six-month period. Included in these costs were employee relocation expenses, transition labor costs, and other charges directly associated with the merger. Also included was a charge of $39 million to accelerate the recognition of certain pension costs, due to the number of employee retirements associated with the merger who elected to take lump-sum pension settlements. Merger-related costs in the second quarter and first six months of 2002 were $1 million and $3 million, respectively.
The category “Other” consists primarily of items not directly associated with the operating segments on a stand-alone basis, including certain foreign currency transaction gains and losses, dividends on the preferred securities of capital trusts, and environmental costs associated with sites no longer in operation. Results from Other were lower in the second quarter of 2003, compared with the second quarter of 2002, primarily due to increased environmental costs. Results from Other were improved in the first six months of 2003 because we recognized an after-tax gain of $34 million in the first quarter of 2003, representing beneficial interests we had in certain insurance companies as a result of the conversion of those companies from mutual companies to stock companies, a process known as demutualization. These beneficial interests arose from our prior purchase and ownership of various insurance policies and contracts issued by the mutual companies. Prior to the demutualizations, our mutual ownership interests in these insurance companies were not recognized because ownership interests in the mutual companies were neither capable of valuation nor marketable. Included in Other in the second quarter of 2003 were foreign currency transaction gains of $18 million, after-tax, compared with gains of $12 million in the second quarter of 2002. The six-month period of 2003 included foreign currency transaction gains of $19 million, while the corresponding period of 2002 had gains of $8 million.
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CAPITAL RESOURCES AND LIQUIDITY
Financial Indicators
Significant Sources of Capital
During the first six months of 2003, cash of $5,294 million was provided by operating activities, an increase of $4,185 million from the same period of 2002. The increase in cash provided by operating activities was primarily due to higher crude oil, natural gas liquids and natural gas prices, combined with increased production as a result of the addition of the Conoco assets; higher refining margins; higher marketing margins; and positive working capital changes. Positive working capital changes of $1,017 million, compared with the six months of 2002, were primarily due to an increase in taxes and other accruals, a decrease in accounts and notes receivables, and a decrease in prepaid expenses and other current assets. These items were partially offset by an increase in inventories and a decrease in accounts payable. Cash from operating activities provided by discontinued operations amounted to $76 million, compared with $50 million in the first six months of 2002.
To meet our liquidity requirements, including funding our capital program, paying dividends and repaying debt, we look to a variety of funding sources, primarily cash from operating activities. In 2003 through 2004, we also anticipate raising funds of $2 billion to $3 billion from the sale of assets, including those assets required to be sold by the Federal Trade Commission (FTC), as well as a substantial portion of our U.S. retail marketing sites. See Note 4—Discontinued Operations, in the Notes to Consolidated Financial Statements, for additional information. We also plan to raise funds from the sale of non-strategic E&P properties. Through the first six months of 2003, our proceeds from the sale of assets totaled $591 million.
While the stability of our cash flows from operating activities benefits from geographic diversity and the effects of upstream and downstream integration, our operating cash flows remain exposed to the volatility of commodity crude oil and natural gas prices and downstream margins, as well as periodic cash needs to make tax payments and purchase crude oil, natural gas and petroleum products. Our primary funding source for short-term working capital needs is a $4 billion commercial paper program, a portion of which may be denominated in other currencies (limited to euro 3 billion equivalent). Commercial paper maturities are generally kept within 90 days. At June 30, 2003, ConocoPhillips had $801 million of commercial paper outstanding, of which $99 million was denominated in foreign currencies, compared with $1,517 million of commercial paper outstanding at December 31, 2002, of which $206 million was denominated in foreign currencies.
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Supporting our $4 billion commercial paper program are a $2 billion 364-day revolving credit facility expiring on October 14, 2003, and two revolving credit facilities totaling $2 billion expiring in October 2006. There were no outstanding borrowings under any of these facilities at June 30, 2003. One of our Norwegian subsidiaries has two $300 million revolving credit facilities that expire in June 2004, under which no borrowings were outstanding as of June 30, 2003.
In addition to the bank credit facilities, ConocoPhillips sells certain credit card and trade receivables to two Qualifying Special Purpose Entities (QSPEs) in revolving-period securitization arrangements. These arrangements provide for us to sell, and the QSPEs to purchase, certain receivables and for the QSPEs to then issue beneficial interests of up to $1.5 billion to five bank-sponsored entities. At June 30, 2003, and December 31, 2002, we had outstanding to the bank-sponsored entities $1.4 billion and $1.3 billion, respectively, of beneficial interests in the pools of receivables held by the QSPEs. We retained beneficial interests in the sold receivables, which are subordinate to the beneficial interests issued to the bank-sponsored entities. Our retained interests were $1.3 billion at June 30, 2003, and December 31, 2002. Our retained interests in sold receivables are reported on the balance sheet in accounts and notes receivable—related parties. In addition, at June 30, 2003, and December 31, 2002, we had sold $171 million and $264 million, respectively, of receivables under a factoring agreement. See Note 15—Sales of Receivables, in the Notes to Consolidated Financial Statements, for additional information.
Other Financing and Off-Balance Sheet Arrangements
At June 30, 2003, we had $350 million of mandatorily redeemable preferred trust securities issued by the Phillips 66 Capital Trust II, which are mandatorily redeemable in 2037, when the ConocoPhillips subordinated debt securities held by the trust must be repaid. At June 30, 2003, we also had outstanding $723 million of equity held by minority interest owners, including a net minority interest of $141 million in Conoco Corporate Holdings L.P. and a $502 million net minority interest in Ashford Energy. We present the mandatorily redeemable preferred securities and other minority interests in the mezzanine section of our balance sheet based on accounting rules as of the balance sheet date. However, in the third quarter of 2003, in accordance with new accounting rules issued by the Financial Accounting Standards Board in Interpretation No. 46, “Consolidation of Variable Interest Entities,” and in Statement of Financial Accounting Standard No. 150, “Accounting for Certain Financial Instruments with Characteristics of Liabilities and Equity,” accounting for mandatorily redeemable preferred securities and certain minority interests will change. We expect that the Phillips 66 Capital Trust II will be deconsolidated which will eliminate the reporting of the $350 million of mandatorily redeemable preferred trust securities and will require reporting as debt $361 million in 8% Junior Subordinated Deferrable Interest Debentures due 2037, which were previously eliminated in our consolidated financial statements. We expect the $141 million net minority interest in Conoco Corporate Holdings L.P. to be reclassified to debt. The $502 million Ashford minority interest has conditions for redemption that are outside our control; so it will continue to be reported in the mezzanine section of our balance sheet. See Note 19—New Accounting Standards, in the Notes to Consolidated Financial Statements, for more information.
We lease ocean transport vessels, drillships, tank railcars, corporate aircraft, service stations, computers, office buildings, certain refining equipment, and other facilities and equipment. Several of these leasing arrangements are with special purpose entities (SPEs) that are third-party trusts established by a trustee and funded by financial institutions. Other than those leasing arrangements, we have no other direct or indirect relationships with the trusts or their investors. We have various purchase options to acquire the leased assets from the SPEs throughout the lease terms, but we are not required to exercise these options under any specific circumstances. If we do not exercise our purchase options on leased assets, we do have guaranteed residual values, which are due at the end of the lease terms, but those guaranteed amounts
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would be reduced by the fair market value of the leased assets returned. These various leasing arrangements meet all requirements under generally accepted accounting principles to be treated as operating leases. However, in January 2003, the FASB issued Interpretation No. 46, “Consolidation of Variable Interest Entities,” which will require consolidation in the third quarter of 2003 certain SPEs that were created prior to January 31, 2003, and that are still in existence at July 1, 2003. For those VIEs created prior to January 31, 2003, we plan to implement Interpretation No. 46 in the third quarter of 2003 with retroactive application back to January 1, 2003. This application is expected to result in an increase in debt of approximately $2.5 billion for these leasing entities. See Note 19—New Accounting Standards, in the Notes to Consolidated Financial Statements, for more information. Of the $2.5 billion in debt that will be consolidated, approximately $1.5 billion is associated with approximately 1,000 store sites, the majority of which we plan to sell, and two office buildings that are also a part of our divestiture plan.
Capital Requirements
For information about our capital expenditures and investments, see “Capital Spending” below.
In the first six months of 2003, in addition to reducing our commercial paper, we paid the following notes as they were called or matured and funded the payments with cash from operating activities and proceeds from asset dispositions:
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Capital Expenditures and Investments
We continue with the construction of our double-hulled Endeavour Class tankers, which are used in transporting Alaskan crude oil to the U.S. West Coast. We expect the third tanker, the Polar Discovery, to enter service later in 2003. We expect to add a new Endeavour Class tanker to our fleet each year through 2005.
In the first quarter of 2003, we completed the purchase of Amerada Hess’ 1.5 percent interest in the Trans-Alaska Pipeline System (TAPS), increasing our ownership in TAPS to 28.2 percent interest.
In Alaska, we continued development drilling in the Kuparuk, Palm and West Sak fields in the Greater Kuparuk Area, the Borealis field in the Greater Prudhoe Bay Area, and the Alpine field. In addition, we plan to increase oil production capacity at the Alpine field. The Alpine Capacity Expansion Project Phase I is expected to start up in 2004. The project will increase both water and gas handling capacities, both of which are important for increasing oil production and maintaining reservoir pressure.
In the Lower 48, we continued to explore and develop our acreage positions in the deepwater Gulf of Mexico, South Texas, the San Juan Basin, the Permian Basin, and the Texas Panhandle. In the Gulf of Mexico, development drilling is ongoing in the Magnolia and Princess fields, and appraisal drilling is under way on the K-2 discovery. In January 2003, we began construction of the Magnolia tension-leg platform, and we expect completion in 12 months. In February 2003, we began drilling the Lorien exploration well in the Gulf of Mexico on Green Canyon Block 199, which was declared a discovery in July. The well has been temporarily suspended, pending further appraisal of the hydrocarbon zone. We are the operator with a 65 percent interest.
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In the U.K. and Norwegian sectors of the North Sea, we continued with several exploration and development projects, with the largest expenditures on the Clair field. We expect first production from Clair in 2004.
In Indonesia, we completed the successful test of the Suban-8 delineation well in the Suban gas field, located on the Corridor Production Sharing Contract (PSC) of South Sumatra; and drilled the North Sumpal-1 exploratory well in the Sakakemang Block also located in South Sumatra. We began testing the North Sumpal-1 well in late July. In addition, we continue to develop the offshore Belanak and other fields in the Block B PSC.
In China’s Bohai Bay, we continued with feasibility planning and design for Phase II of the Peng Lai 19-3 development. Phase II includes multiple wellhead platforms, central processing facilities, and a floating storage and offloading facility. We are developing, in conjunction with Phase II, the Peng Lai 25-6 oil field, located three miles east of Peng Lai 19-3. We also drilled exploration wells on the Peng Lai 19-9 prospect and the Peng Lai 13-1 prospect, which resulted in two discoveries. The Peng Lai 19-9-1 well is located two miles east of the Peng Lai 19-3 oil field and along with adjacent structures will be a part of the Phase II development. The Peng Lai 13-1-1 well is located 18 miles north of the Peng Lai 19-3 field. We plan to drill additional wells to appraise this discovery and the structures in the same trend.
In the Timor Sea, we continued with development activities associated with the Bayu-Undan gas recycle project. We continued to drill future production wells, to fabricate and assemble two large platform decks, and to work on the multi-product floating storage and offtake vessel. Installation of the first deck began in late June 2003, and we expect to install the second deck and take delivery of the floating storage and offtake vessel in the fourth quarter of 2003, with first gas and commissioning commencing in the fourth quarter. We have also received approval of the gas development plan for the Bayu-Undan project from the Timor Sea Designated Authority, concluded fiscal and legal provisions with the government of Timor-Lesté and executed new PSC arrangements with the Designated Authority. The gas development project includes a liquefied natural gas (LNG) plant, including a pipeline to Darwin, Australia. The first LNG cargo from the three-million-ton-per-year facility is scheduled for delivery in early 2006. In June 2003, we sold what currently equates to a 10.08 percent interest in the unitized Bayu-Undan field; purchased other interests that currently equates to a 2.65 percent interest in the field; sold a 43.3 percent interest in the Bayu-Undan pipeline under construction, and sold a 43.3 percent interest in Darwin LNG Pty Ltd (owner of the LNG plant to be constructed). The net result is that ConocoPhillips retains a 56.7 percent controlling interest in the integrated project.
In Block 15-1 in the Cuu Long Basin of Vietnam, ConocoPhillips is currently evaluating the commerciality of the northeast portion of the Su Tu Den and the Su Tu Vang fields. We continue to develop the Southwest Phase I project of the Su Tu Den field. Currently, a wellhead platform and a floating production, storage and offloading vessel are under construction. We expect the field to begin production in the fourth quarter of 2003. In Block 15-2 (Rang Dong field), while the field is in full production, field facilities are being upgraded to include a utilities-living quarters platform; a gas lift, water injection, gas export platform; and water injection pipelines to the S-1 and future C-1 platforms. These facilities are anticipated to be operational in the fourth quarter of 2003.
At our Hamaca project in Venezuela, we continued with activities required to produce, transport and upgrade 8.6-degree API extra-heavy crude into high-quality synthetic crude oil. Total current production is approximately 80,000 gross barrels of heavy crude oil per day, 26,000 net. This production level is limited by the availability of diluent. We anticipate completing the construction of the upgrader in the third quarter of 2004, with peak capacity of extra-heavy crude in the 190,000 gross barrels per day range.
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We continued with development of the Stage III expansion-mining project in the Canadian province of Alberta, which is expected to increase our Canadian Syncrude production. The Aurora Train 2 project (the new mine) is now 87 percent complete and on track to start up in the fourth quarter of 2003. The expansion project is expected to bring various units onstream during 2004, while the completion of a new coker is anticipated in the first quarter of 2005.
In the Caspian Sea, we exercised our pre-emptive rights related to British Gas’ sale of their share in the North Caspian License that includes the Kashagan field offshore Kazakhstan. The transaction is expected to close in the fourth quarter of 2003, at which time our interest in the license will increase from 8.33 percent to 10.185 percent.
The polypropylene plant at the Bayway refinery in Linden, New Jersey, began operations in March 2003, utilizing propylene feedstock from the refinery to make up to 775 million pounds of polypropylene per year.
At our Ferndale, Washington, refinery, we completed construction of a new fluid catalytic cracking unit, which commenced initial operations in March 2003. We expect the unit to improve gasoline production from each barrel of crude oil input.
In the United States, we continue to expend funds related to clean fuels, safety and environmental projects. We continue to work on refinery projects in Ponca City, Oklahoma; Ferndale, Washington; and at our Wood River refinery in Roxana, Illinois, to produce the low-sulfur gasoline required by the Environmental Protection Agency. We expect to complete these projects by year-end.
In July 2003, we completed the acquisition of certain refining assets in Hartford, Illinois. The operations of these assets will be integrated into the operations of our nearby Wood River refinery.
Internationally we continue to invest in our ongoing refining and marketing operations, including a replacement reformer at our Humber refinery in the United Kingdom and marketing growth in select countries in Europe and Asia.
We continued to spend funds in the first half of 2003 on construction of our Immingham combined heat and power cogeneration plant near our Humber refinery in the United Kingdom. We expect the plant to become operational in 2004.
Contingencies
Legal and Tax Matters
ConocoPhillips accrues for contingencies when a loss is probable and the amounts can be reasonably estimated. Based on currently available information, we believe that the chance is remote that future costs related to known contingent liability exposures will exceed current accruals by an amount that would have a material adverse impact on our financial statements.
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Environmental
ConocoPhillips and each of our various businesses are subject to the same numerous international, federal, state, and local environmental laws and regulations, as are other companies in the petroleum exploration and production; and refining, marketing and transportation of crude oil and refined products businesses. The most significant of these environmental laws and regulations include, among others, the:
These laws and their implementing regulations set limits on emissions and, in the case of discharges to water, establish water quality limits. They also, in most cases, require permits in association with new or modified operations. These permits can require an applicant to collect substantial information in connection with the application process, which can be expensive and time-consuming. In addition, there can be delays associated with notice and comment periods and the agency’s processing of the application. Many of the delays associated with the permitting process are beyond the control of the applicant.
Many states and foreign countries where we operate also have, or are developing, similar environmental laws and regulations governing these same types of activities. While similar, in some cases these regulations may impose additional, or more stringent, requirements that can add to the cost and difficulty of marketing or transporting products across state and international borders.
The ultimate financial impact arising from environmental laws and regulations is neither clearly known nor easily determinable as new standards, such as air emission standards, water quality standards and stricter fuel regulations, continue to evolve. However, environmental laws and regulations are expected to continue to have an increasing impact on our operations in the United States and in most of the countries in which we operate. Notable areas of potential impacts include air emission compliance and remediation obligations in the United States. Under the Clean Air Act, the U.S. Environmental Protection Agency (EPA) has promulgated a number of stringent limits on air emissions and established a federally mandated
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operating permit program. Violations of the Clean Air Act and most other environmental laws and regulations are enforceable with civil and criminal sanctions.
The EPA has also promulgated specific rules governing the sulfur content of gasoline, known generically as the “Tier II Sulfur Rules,” which become applicable to our gasoline as early as 2004. To meet the requirements, we are implementing a compliance strategy that relies on the use of a combination of technologies, including our proprietary S Zorb technology. The estimated costs for implementing our strategy will be included in future budgeting for refinery compliance.
The EPA has also promulgated rules regarding the sulfur content in highway diesel fuel, which become applicable in 2006. In April 2003, the EPA proposed a rule regarding emissions from non-road diesel engines and limiting non-road diesel fuel sulfur content. If promulgated, this rule would significantly reduce non-road diesel fuel sulfur content limits as early as 2007. We are currently developing and testing an S Zorb system for removing sulfur from diesel fuel. This advanced technology is one of many under consideration for complying with these rules. Because the non-road rule is not final, we are still evaluating and developing capital strategies for future compliance and we cannot provide precise cost estimates at this time.
Additional areas of potential air-related impact are the proposed revisions to the National Ambient Air Quality Standards (NAAQS) and the Kyoto Protocol. In July 1997, the EPA promulgated more stringent revisions to the NAAQS for ozone and particulate matter. Since that time, final adoption of these revisions has been the subject of litigation (American Trucking Association, Inc. et al. v. United States Environmental Protection Agency) that eventually reached the U.S. Supreme Court during the fall of 2000. In February 2001, the U.S. Supreme Court remanded this matter, in part, to the EPA to address the implementation provisions relating to the revised ozone NAAQS. If adopted, the revised NAAQS could result in substantial future environmental expenditures for ConocoPhillips.
In 1997, an international conference on global warming concluded an agreement, known as the Kyoto Protocol, which called for reductions of certain emissions that contribute to increases in atmospheric greenhouse gas concentrations. The United States has not ratified the treaty codifying the Kyoto Protocol but may in the future. In addition, other countries where we have interests, or may have interests in the future, have made commitments to the Kyoto Protocol and are in various stages of formulating applicable regulations. Currently, it is not possible to accurately estimate the costs that we could incur to comply with such regulations, but such expenditures could be substantial.
We also are subject to certain laws and regulations relating to environmental remediation obligations associated with current and past operations. Such laws and regulations include CERCLA and RCRA and their state equivalents. Remediation obligations include cleanup responsibility arising from petroleum releases from underground storage tanks located at numerous past and present ConocoPhillips-owned and/or operated petroleum-marketing outlets throughout the United States. Federal and state laws require that contamination caused by such underground storage tank releases be assessed and remediated to meet applicable standards. In addition to other cleanup standards, many states have adopted cleanup criteria for methyl tertiary-butyl ether (MTBE) for both soil and groundwater. MTBE standards continue to evolve, and future environmental expenditures associated with the remediation of MTBE-contaminated underground storage tank sites could be substantial.
At RCRA permitted facilities, we are required to assess environmental conditions. If conditions warrant, we may be required to remediate contamination caused by prior operations. In contrast to CERCLA, which is often referred to as “Superfund,” the cost of corrective action activities under RCRA corrective action programs typically is borne solely by ConocoPhillips. Over the next decade, we anticipate that significant ongoing expenditures for RCRA remediation activities may be required, but such annual
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expenditures for the near term are not expected to vary significantly from the range of such expenditures we have experienced over the past few years. Longer term, expenditures are subject to considerable uncertainty and may fluctuate significantly.
We from time to time receive requests for information or notices of potential liability from the EPA and state environmental agencies alleging that we are a potentially responsible party under CERCLA or an equivalent state statute. On occasion, we also have been made a party to cost recovery litigation by those agencies or by private parties. These requests, notices and lawsuits assert potential liability for remediation costs at various sites that typically are not owned by us, but allegedly contain wastes attributable to our past operations. As of December 31, 2002, we reported we had been notified of potential liability under CERCLA and comparable state laws at 58 sites around the United States. At June 30, 2003, we had resolved four of these sites but had received five new notices of potential liability, leaving approximately 59 sites where we have been notified of potential liability.
For most Superfund sites, our potential liability will be significantly less than the total site remediation costs because the percentage of waste attributable to us, versus that attributable to all other potentially responsible parties is relatively low. Although liability of those potentially responsible is generally joint and several for federal sites and frequently so for state sites, other potentially responsible parties at sites where we are a party typically have had the financial strength to meet their obligations, and where they have not, or where potentially responsible parties could not be located, our share of liability has not increased materially. Many of the sites at which we are potentially responsible are still under investigation by the EPA or the state agencies concerned. Prior to actual cleanup, those potentially responsible normally assess site conditions, apportion responsibility and determine the appropriate remediation. In some instances, we may have no liability or attain a settlement of liability. Actual cleanup costs generally occur after the parties obtain EPA or equivalent state agency approval. There are relatively few sites where we are a major participant, and given the timing and amounts of anticipated expenditures, neither the cost of remediation at those sites nor such costs at all CERCLA sites, in the aggregate, is expected to have a material adverse effect on our competitive or financial condition.
Remediation Accruals
We accrue for remediation activities when it is probable that a liability has been incurred and reasonable estimates of the liability can be made. These accrued liabilities are not reduced for potential recoveries from insurers or other third parties and are not discounted (except, if assumed in a purchase business combination, we record such costs on a discounted basis). Many of these liabilities result from CERCLA, RCRA and similar state laws that require us to undertake certain investigative and remedial activities at sites where we conduct, or once conducted, operations or at sites where ConocoPhillips-generated waste was disposed. The accrual also includes a number of sites we have identified that may require environmental remediation, but which are not currently the subject of CERCLA, RCRA or state enforcement activities. If applicable, we accrue receivables for probable insurance or other third-party recoveries. In the future, we may incur significant costs under both CERCLA and RCRA. Considerable uncertainty exists with respect to these costs, and under adverse changes in circumstances, potential liability may exceed amounts accrued as of June 30, 2003.
Remediation activities vary substantially in duration and cost from site to site, depending on the mix of unique site characteristics, evolving remediation technologies, diverse regulatory agencies and enforcement policies, and the presence or absence of potentially liable third parties. Therefore, it is difficult to develop reasonable estimates of future site remediation costs.
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At June 30, 2003, our balance sheet included a total environmental accrual related to continuing operations of $845 million, compared with $743 million at December 31, 2002. The increase in accruals from year-end 2002, primarily resulted from the continuing assessment of Conoco environmental liabilities during the period allowed by purchase accounting rules. Final purchase price adjustments will be recognized in the third quarter of 2003. We expect to incur the majority of these expenditures within the next 30 years.
Notwithstanding any of the foregoing, and as with other companies engaged in similar businesses, environmental costs and liabilities are inherent in our operations and products, and there can be no assurance that material costs and liabilities will not be incurred. However, we currently do not expect any material adverse affect upon our results of operations or financial position as a result of compliance with environmental laws and regulations.
OUTLOOK
In December 2002, we committed to and initiated a plan to sell a substantial portion of our U.S. retail marketing sites. With the help of an investment banking firm, we are actively marketing these assets in packages. We are in discussions with potential buyers and expect to complete the sale of the majority of these sites in 2003. During the second quarter, we reached an agreement to sell certain retail and dealer marketing sites in the Northeast. This sale is expected to be completed in the third quarter of 2003.
In February 2003, the Venezuelan government implemented a currency exchange control regime. The government has published legal instruments supporting the controls, one of which establishes official exchange rates for the U.S. dollar. Changes in the exchange rate could have a significant impact on our Venezuelan operations.
During the second quarter, draft legislation was introduced in the Canadian Parliament regarding federal tax rate reductions for oil and gas producers. If this legislation is enacted, we expect to recognize a significant earnings benefit upon revaluation of our deferred tax liability. However, due to the complexity of the calculation, we do not anticipate providing an estimate of the benefit until a thorough evaluation and review has been completed.
In March 2003, our board of directors approved a plan to further develop the Ekofisk Area in the Norwegian North Sea. We intend to increase the recovery of oil and gas from the Ekofisk Area by increasing the area’s processing capacity and reliability. Our co-venturers have also approved the plan for the further development of PL018. The Ekofisk growth project consists of two interrelated components: the construction and installation of a new platform, named Ekofisk 2/4 M and an increase in capacity from existing facilities. The Ekofisk 2/4 M platform will be a steel wellhead and process platform that will be located southeast of the existing Ekofisk 2/4 J platform and will have 30 well slots, a high-pressure separator, equipment for produced water treatment, and risers for tie-in of future projects. We expect to complete and install the steel jacket in 2004 and the topsides in the early summer of 2005, with production anticipated to begin in the fall of 2005. We also expect to modify the existing Ekofisk Complex and four additional platforms to increase our processing capacity.
In April 2003, the Control Committee, comprised of representatives of the Venezuelan Ministry of Energy and Mines, Petroleos de Venezuela S. A. (PDVSA), and the partners, approved Phase I of the development plan for the Corocoro field in Venezuela’s Gulf of Paria West area. We are the operator in the Gulf of Paria West Block and currently hold a 50 percent working interest. Under terms of the Gulf of Paria West Block profit sharing agreement with the Venezuelan government, Corporación Venezolana de Petróleo (a subsidiary of PDVSA) has elected to acquire a 35 percent participating interest in the Corocoro discovery, which will reduce our working interest to 32.5 percent. We have started development and first production is expected in early 2006.
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In May 2003, we received regulatory approval from the Alberta Energy and Utilities Board for our Surmont oil sands project in Northern Alberta, Canada. We are finalizing the evaluation of the commercial potential of the project, and a decision regarding development is expected later this year. We are the operator of the Surmont lease with a 43.5 percent interest. If a decision is made to proceed with the project, construction of the first phase could begin this year, with first oil production in 2006.
Also, in June 2003, we and our co-venturers in the Mackenzie Gas Project in Canada announced that funding and participation agreements have been reached and a Preliminary Information Package (PIP) was submitted to relevant regulatory authorities. The Mackenzie Gas Project involves natural gas production facilities, compression and gathering pipelines in the Mackenzie Delta area, and a pipeline system in the Mackenzie River Valley. The filing of the PIP is a key step in the process leading to the submission of applications for the development of the natural gas fields and pipeline facilities. Regulatory applications could be filed in 2004.
In July 2003, we announced that we had signed a Heads of Agreement with Qatar Petroleum for the development of Qatargas 3, a large-scale LNG project located in Qatar and servicing the U.S. natural gas market. The agreement provides the framework for the necessary agreements and the completion of key feasibility studies. Qatargas 3 would be an integrated project, jointly owned by Qatar Petroleum and ConocoPhillips, consisting of facilities to produce and liquefy gas from Qatar’s North field. The LNG would be shipped from Qatar and we would be responsible for regasification and marketing it within the United States. Average daily gas sales volumes are projected to be approximately 1 billion cubic feet per day with startup anticipated to be in the 2008-2009 timeframe.
On July 21, 2003, we experienced a fire at our 194,000-barrel-per-day refinery in Ponca City, Oklahoma. The fire involved a gas processing unit, an 85,000-barrel-per-day crude distillation unit and a desulfurization unit. The units are currently shutdown, and we are assessing the causes of the fire and the necessary repairs to the unit. Based on preliminary estimates, we expect to lose about 65,000 barrels per day of crude oil throughput in the third quarter of 2003, but we expect to be able to meet the supply needs of our branded customers.
In E&P, we expect our worldwide production for the third quarter of 2003 to be below our second quarter level, primarily because of seasonal declines in the United Kingdom and Norway, as well as asset dispositions and field declines in the U.S. Lower 48.
In R&M, we expect our average refinery utilization rate for the third quarter of 2003 to be below that of the second quarter primarily due to the temporary reduction of available capacity at the Ponca City refinery.
Crude oil and natural gas prices are subject to external factors over which we have no control, such as global economic conditions, political events, demand growth, inventory levels, weather, competing fuels prices and availability of supply. Crude oil prices declined in the second quarter from the exceptionally high levels experienced in the first quarter due to the war ending quickly in Iraq and production increases in Venezuela and Nigeria, both of which had major supply disruptions in the first quarter. However, crude prices remained strong in the second quarter due to low global oil inventories and a delay in the return of Iraqi crude production following the war. Uncertainty about the timing of the full restoration of Iraqi production is likely to keep prices volatile for the remainder of the year. U.S. natural gas prices also declined in the second quarter from extremely high first quarter levels. However, prices remained strong in the second quarter due to exceptionally low natural gas inventories caused by high heating demand in the Northeast during the first quarter, and continuing supply adequacy concerns.
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Refining margins are subject to movements in the price of crude oil and other feedstocks, and the prices of petroleum products, which are subject to market factors over which we have no control, such as the U.S. and global economies; government regulations; military, political and social conditions in oil producing countries; seasonal factors that affect demand, such as the summer driving months; and the levels of refining output and product inventories. Global refining margins retreated in the second quarter from very strong first quarter levels but remained at healthy levels. They retreated in the United States because weak gasoline demand combined with high gasoline imports caused gasoline inventories to rise during the second quarter. However, margins remain at fairly healthy levels because gasoline and distillate inventories are still lower than normal. Marketing margins increased in the second quarter from reasonably strong first quarter levels as refined product prices fell faster than retail and wholesale prices. The sustainability of current refining and marketing margins depends on the continued recovery of the global economy and oil demand growth.
CAUTIONARY STATEMENT FOR THE PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
This report includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. You can identify our forward-looking statements by the words “expects,” “anticipates,” “intends,” “plans,” “projects,” “believes,” “estimates” and similar expressions.
We have based the forward-looking statements relating to ConocoPhillips’ operations on its current expectations, estimates and projections about ConocoPhillips and the industries in which it operates in general. We caution you that these statements are not guarantees of future performance and involve risks, uncertainties and assumptions that we cannot predict. In addition, we have based many of these forward-looking statements on assumptions about future events that may prove to be inaccurate. Accordingly, ConocoPhillips’ actual outcomes and results may differ materially from what we have expressed or forecast in the forward-looking statements. Any differences could result from a variety of factors, including the following:
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Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Information about market risks for the three and six months ended June 30, 2003, does not differ materially from that discussed under Item 7A of ConocoPhillips’ Annual Report on Form 10-K for the year ended December 31, 2002.
Item 4. CONTROLS AND PROCEDURES
As of June 30, 2003, with the participation of our management, our President and Chief Executive Officer and our Executive Vice President, Finance, and Chief Financial Officer carried out an evaluation of the effectiveness of the design and operation of ConocoPhillips’ disclosure controls and procedures pursuant to Rule 13a-15(b) of the Securities Exchange Act of 1934, as amended. Based upon that evaluation, our President and Chief Executive Officer and our Executive Vice President, Finance, and Chief Financial Officer concluded that our disclosure controls and procedures were operating effectively as of June 30, 2003.
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There have been no changes in our internal control over financial reporting, as defined in Rule 13a-15(f) of the Securities Exchange Act, that occurred during the period covered by this report that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
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PART II. OTHER INFORMATION
Item 1. LEGAL PROCEEDINGS
With the exception of the single matter described below, there have been no material developments with respect to the legal proceedings previously reported in our 2002 Annual Report on Form 10-K.
On September 27, 2002, the Montana Department of Environmental Quality issued a Notice of Violation to ConocoPhillips alleging that on December 13, 2000, the company discharged 52,374 gallons of gasoline from Tank 32 at its Helena, Montana, product storage terminal. The matter was settled on July 15, 2003.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
We held our annual stockholders’ meeting on May 6, 2003. A brief description of each proposal and the voting results follow:
A company proposal to elect five directors.
Those directors whose term of office continued were as follows: Norman R. Augustine, David L. Boren, Kenneth M. Duberstein, Archie W. Dunham, Ruth R. Harkin, Larry D. Horner, Charles C. Krulak, Frank A. McPherson, J. J. Mulva, William R. Rhodes and J. Stapleton Roy.
A company proposal to ratify the appointment of Ernst & Young LLP as independent auditors for 2003.
All five nominated directors were elected and the appointment of the independent auditors was ratified.
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Item 5. OTHER INFORMATION
The following information is being provided under Item 11 of Form 8-K pursuant to Release Nos. 33-8216; 34-47583 of the Securities and Exchange Commission:
On July 21, 2003, ConocoPhillips received notice from the plan administrator of the Conoco Thrift Plan for Employees and the Conoco Thrift Plan for Retail Employees (collectively, the “Plans”) regarding a blackout period, as defined in Rule 100 of the Securities and Exchange Commission’s Regulation BTR. The blackout period is expected to commence October 3, 2003, and end during the week of October 5, 2003. The blackout period is being instituted to effectuate the merger of the Plans into other existing plans of ConocoPhillips. During the blackout period, participants in the Plans will be unable to make exchanges or asset allocation changes involving ConocoPhillips’ common stock, submit loan requests or make loan payments by check or money order, or request a withdrawal or final distribution. The ability of ConocoPhillips’ directors and executive officers to purchase, sell or otherwise transfer any equity security of ConocoPhillips (or derivative securities of those equity securities) acquired in connection with service to or employment with ConocoPhillips will also be suspended during the blackout period.
The person designated by ConocoPhillips to respond to inquiries about the blackout period is Elizabeth Cook, ConocoPhillips, 600 North Dairy Ashford, Houston, Texas 77079, 281-293-4966. During the blackout period, directors, executive officers and participants in the Plans can receive further information regarding the commencement or ending of the blackout period by calling 1-800-523-1888 Monday through Friday from 7:30 a.m. to 8:00 p.m. Central time or by logging on to http://cop.vanguard-education.com.
As required by Section 306 of the Sarbanes-Oxley Act of 2002 and Rule 104 of Regulation BTR, ConocoPhillips transmitted a notice of blackout period to its directors and executive officers.
Item 6. EXHIBITS AND REPORTS ON FORM 8-K
Exhibits
Reports on Form 8-K
During the three months ended June 30, 2003, ConocoPhillips furnished the following Current Reports on Form 8-K:
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SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
August 12, 2003
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EXHIBIT INDEX