UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
[X]
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended
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March 31, 2004 | |
OR
[ ]
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from
|
to |
Commission file number
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000-49987
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ConocoPhillips
Delaware | 01-0562944 | |
(State or other jurisdiction of | (I.R.S. Employer | |
incorporation or organization) | Identification No.) |
600 North Dairy Ashford, Houston, TX 77079
(Address of principal executive offices)
281-293-1000
(Registrants 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 685,834,267 shares of common stock, $.01 par value, outstanding at March 31, 2004.
CONOCOPHILLIPS
TABLE OF CONTENTS
PART I. FINANCIAL INFORMATION
Item 1. FINANCIAL STATEMENTS
Consolidated Income Statement | ConocoPhillips |
Millions of Dollars |
||||||||
Three Months Ended | ||||||||
March 31 |
||||||||
2004 | 2003 | ** | ||||||
Revenues |
||||||||
Sales and other operating revenues* |
$ | 29,800 | 26,940 | |||||
Equity in earnings of affiliates |
269 | 49 | ||||||
Other income |
148 | 79 | ||||||
Total Revenues |
30,217 | 27,068 | ||||||
Costs and Expenses |
||||||||
Purchased crude oil and products |
19,685 | 17,672 | ||||||
Production and operating expenses |
1,719 | 1,670 | ||||||
Selling, general and administrative expenses |
464 | 447 | ||||||
Exploration expenses |
143 | 116 | ||||||
Depreciation, depletion and amortization |
918 | 859 | ||||||
Property impairments |
31 | 28 | ||||||
Taxes other than income taxes* |
4,114 | 3,422 | ||||||
Accretion on discounted liabilities |
36 | 33 | ||||||
Interest and debt expense |
145 | 239 | ||||||
Foreign currency transaction losses (gains) |
(16 | ) | 6 | |||||
Minority interests |
14 | 7 | ||||||
Total Costs and Expenses |
27,253 | 24,499 | ||||||
Income from continuing operations before income taxes |
2,964 | 2,569 | ||||||
Provision for income taxes |
1,361 | 1,306 | ||||||
Income From Continuing Operations |
1,603 | 1,263 | ||||||
Income from discontinued operations |
13 | 53 | ||||||
Income before cumulative effect of changes in accounting principles |
1,616 | 1,316 | ||||||
Cumulative effect of changes in accounting principles |
| (95 | ) | |||||
Net Income |
$ | 1,616 | 1,221 | |||||
Income Per Share of Common Stock |
||||||||
Basic |
||||||||
Continuing operations |
$ | 2.34 | 1.86 | |||||
Discontinued operations |
.02 | .08 | ||||||
Before cumulative effect of changes in accounting principles |
2.36 | 1.94 | ||||||
Cumulative effect of changes in accounting principles |
| (.14 | ) | |||||
Net Income |
$ | 2.36 | 1.80 | |||||
Diluted |
||||||||
Continuing operations |
$ | 2.31 | 1.85 | |||||
Discontinued operations |
.02 | .08 | ||||||
Before cumulative effect of changes in accounting principles |
2.33 | 1.93 | ||||||
Cumulative effect of changes in accounting principles |
| (.14 | ) | |||||
Net Income |
$ | 2.33 | 1.79 | |||||
Dividends Paid Per Share of Common Stock |
$ | .43 | .40 | |||||
Average Common Shares Outstanding (in thousands) |
||||||||
Basic |
685,541 | 679,538 | ||||||
Diluted |
694,498 | 682,744 | ||||||
*Includes excise, value added and other similar taxes on petroleum
products sales: |
$ | 3,822 | 3,148 |
**Restated for adoption of FIN 46. |
See Notes to Consolidated Financial Statements. |
1
Consolidated Balance Sheet | ConocoPhillips |
Millions of Dollars |
||||||||
March 31 | December 31 | |||||||
2004 | 2003 | |||||||
Assets |
||||||||
Cash and cash equivalents |
$ | 659 | 490 | |||||
Accounts and notes receivable (net of allowance of $48 million in 2004
and
$43 million in 2003) |
3,712 | 3,606 | ||||||
Accounts and
notes receivablerelated parties |
2,680 | 1,399 | ||||||
Inventories |
4,360 | 3,957 | ||||||
Prepaid expenses and other current assets |
733 | 876 | ||||||
Assets of discontinued operations held for sale |
776 | 864 | ||||||
Total Current Assets |
12,920 | 11,192 | ||||||
Investments and long-term receivables |
7,170 | 7,258 | ||||||
Net properties, plants and equipment |
47,704 | 47,428 | ||||||
Goodwill |
15,092 | 15,084 | ||||||
Intangibles |
1,105 | 1,085 | ||||||
Other assets |
438 | 408 | ||||||
Total Assets |
$ | 84,429 | 82,455 | |||||
Liabilities |
||||||||
Accounts payable |
$ | 6,997 | 6,598 | |||||
Accounts
payablerelated parties |
539 | 301 | ||||||
Notes payable and long-term debt due within one year |
1,441 | 1,440 | ||||||
Accrued income and other taxes |
3,240 | 2,676 | ||||||
Other accruals |
2,303 | 2,817 | ||||||
Liabilities of discontinued operations held for sale |
182 | 179 | ||||||
Total Current Liabilities |
14,702 | 14,011 | ||||||
Long-term debt |
15,668 | 16,340 | ||||||
Asset retirement obligations and accrued environmental costs |
3,607 | 3,603 | ||||||
Deferred income taxes |
8,911 | 8,565 | ||||||
Employee benefit obligations |
2,497 | 2,445 | ||||||
Other liabilities and deferred credits |
2,278 | 2,283 | ||||||
Total Liabilities |
47,663 | 47,247 | ||||||
Minority Interests |
946 | 842 | ||||||
Common Stockholders Equity |
||||||||
Common stock (2,500,000,000 shares authorized at $.01 par value) Issued (2004711,135,581 shares; 2003708,085,097 shares) |
||||||||
Par value |
7 | 7 | ||||||
Capital in excess of par |
25,587 | 25,361 | ||||||
Compensation
and Benefits Trust (CBT) (at cost: 2004 and 200325,301,314) |
(857 | ) | (857 | ) | ||||
Accumulated other comprehensive income |
797 | 821 | ||||||
Unearned employee compensation |
(270 | ) | (200 | ) | ||||
Retained earnings |
10,556 | 9,234 | ||||||
Total Common Stockholders Equity |
35,820 | 34,366 | ||||||
Total |
$ | 84,429 | 82,455 | |||||
2
Consolidated Statement of Cash Flows | ConocoPhillips |
Millions of Dollars |
||||||||
Three Months Ended | ||||||||
March 31 |
||||||||
2004 | 2003 | ** | ||||||
Cash Flows From Operating Activities |
||||||||
Income from continuing operations |
$ | 1,603 | 1,263 | |||||
Adjustments to reconcile income from continuing operations to net
cash provided by continuing operations |
||||||||
Non-working capital adjustments
|
||||||||
Depreciation, depletion and amortization |
918 | 859 | ||||||
Property impairments |
31 | 28 | ||||||
Dry hole costs and leasehold impairments |
87 | 40 | ||||||
Accretion on discounted liabilities |
36 | 33 | ||||||
Deferred taxes |
360 | 243 | ||||||
Undistributed equity earnings |
(181 | ) | 18 | |||||
Gain on asset dispositions |
(82 | ) | (56 | ) | ||||
Other |
70 | 56 | ||||||
Working capital adjustments* |
||||||||
Decrease in aggregate balance of accounts receivable sold |
(750 | ) | (2 | ) | ||||
Increase in other accounts and notes receivable |
(639 | ) | (1,551 | ) | ||||
Increase in inventories |
(401 | ) | (140 | ) | ||||
Decrease in prepaid expenses and other current assets |
135 | 27 | ||||||
Increase in accounts payable |
694 | 971 | ||||||
Increase in taxes and other accruals |
184 | 1,331 | ||||||
Net cash provided by continuing operations |
2,065 | 3,120 | ||||||
Net cash provided by discontinued operations |
8 | | ||||||
Net Cash Provided by Operating Activities |
2,073 | 3,120 | ||||||
Cash Flows From Investing Activities |
||||||||
Cash consolidated from adoption of FIN 46 |
| 225 | ||||||
Capital expenditures and investments, including dry hole costs |
(1,481 | ) | (1,308 | ) | ||||
Proceeds from asset dispositions |
449 | 125 | ||||||
Long-term advances to affiliates and other investments |
(44 | ) | (28 | ) | ||||
Net cash used in continuing operations |
(1,076 | ) | (986 | ) | ||||
Net cash used in discontinued operations |
(1 | ) | (26 | ) | ||||
Net Cash Used in Investing Activities |
(1,077 | ) | (1,012 | ) | ||||
Cash Flows From Financing Activities |
||||||||
Issuance of debt |
| 269 | ||||||
Repayment of debt |
(722 | ) | (1,838 | ) | ||||
Issuance of company common stock |
112 | 19 | ||||||
Dividends paid on common stock |
(294 | ) | (271 | ) | ||||
Other |
89 | (8 | ) | |||||
Net cash used in continuing operations |
(815 | ) | (1,829 | ) | ||||
Net Cash Used in Financing Activities |
(815 | ) | (1,829 | ) | ||||
Effect of Exchange Rate Changes on Cash and Cash Equivalents |
(12 | ) | 57 | |||||
Net Change in Cash and Cash Equivalents |
169 | 336 | ||||||
Cash and cash equivalents at beginning of period |
490 | 307 | ||||||
Cash and Cash Equivalents at End of Period |
$ | 659 | 643 | |||||
3
Notes to Consolidated Financial Statements | ConocoPhillips |
Note 1Interim 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 Managements Discussion and Analysis and the consolidated financial statements and notes included in ConocoPhillips 2003 Annual Report on Form 10-K. Certain amounts in the 2003 financial statements included in this report on Form 10-Q have been reclassified to conform to ConocoPhillips 2004 presentation and restated for the adoption of Financial Accounting Standards Board (FASB) Interpretation No. 46, Consolidation of Variable Interest Entities, (FIN 46).
Note 2Revenue Recognition Policy
Revenues associated with the sale of crude oil, natural gas, natural gas liquids, petroleum and chemical products, and other items are recognized when title passes to the customer, which is when the risk of ownership passes to the purchaser and physical delivery of goods occurs immediately or within a fixed delivery schedule that is reasonable and customary in the industry. Revenues include the sales portion of contracts involving purchases and sales necessary to reposition supply to address location, quality or grade requirements (e.g., when we reposition crude by entering into a contract with a counterparty to sell crude in one location and purchase it in a different location) and sales related to purchase for resale activity. Revenues from the production of natural gas properties, in which we have an interest with other producers, are recognized based on the actual volumes we sold during the period. Any differences between volumes sold and entitlement volumes, based on our net working interest, which are deemed non-recoverable through remaining production, are recognized as accounts receivable or accounts payable, as appropriate. Cumulative differences between volumes sold and entitlement volumes are generally not significant. Revenues associated with royalty fees from licensed technology are recorded based either upon volumes produced by the licensee or upon the successful completion of all substantive performance requirements related to the installation of licensed technology.
Note 3Changes in Accounting Principles
Accounting for Asset Retirement Obligations
Effective January 1, 2003, we adopted Statement of Financial Accounting
Standards (SFAS) No. 143, Accounting for Asset Retirement Obligations, which
applied to legal obligations associated with the retirement and removal of
long-lived assets. The cumulative effect of the change increased 2003 net
income by $145 million (after reduction of income taxes of $21 million).
Consolidation of Variable Interest Entities
In January 2003, the FASB issued FIN 46 to expand existing accounting guidance
about when a company should include in its consolidated financial statements
the assets, liabilities and activities of another entity. In December 2003, the
FASB issued a revision to FIN 46 to clarify some of the provisions and to
exempt certain entities from its guidance. The consolidation requirements of
FIN 46, as revised, apply to all
4
special purpose entities for periods ending after December 15, 2003. For all other types of variable interest entities the consolidation requirement applies for periods ending after March 15, 2004.
In the third quarter of 2003, with retroactive application to January 1, 2003, we adopted FIN 46 for variable interest entities (VIEs) involving synthetic leases and certain other financing structures, and accordingly, our financial statements for the first quarter of 2003 have been restated from amounts previously reported in the financial statements included in our Form 10-Q for the quarter ended March 31, 2003. The cumulative effect of this adoption of FIN 46 decreased 2003 net income $240 million (after an income tax benefit of $145 million). We consolidated all VIEs created prior to February 1, 2003 (except as noted below), in which we concluded we were the primary beneficiary. In addition, we deconsolidated an entity where we determined we were not the primary beneficiary. The provisions of FIN 46, which became effective for periods ending after March 15, 2004, did not change our analysis on any of the entities we consolidated or deconsolidated in 2003.
In February 2003, we entered into two agreements establishing separate guarantee facilities of $50 million each for two liquefied natural gas ships that were then under construction. Subject to the terms of each facility, we will be required to make payments should the charter revenue generated by the respective ship fall below certain specified minimum thresholds, and we will receive payments to the extent that such revenues exceed those thresholds. The net maximum future payments over the 20-year terms of the two agreements could be up to an aggregate of $100 million. Actual gross payments over the 20 years could exceed that amount to the extent revenues are received by us. In September 2003, the first ship was delivered to its owner and the second ship is scheduled for delivery to its owner in 2005. At December 31, 2003, we reported these two entities could potentially be VIEs, but that we had been unable to obtain sufficient information to confirm that the entities are VIEs or to determine if we were the primary beneficiary. In the first quarter of 2004, we received the required information related to the entity associated with the first ship and determined that it is a VIE; however, we are not the primary beneficiary and therefore will not consolidate the entity. With regard to the second ship, we will have a variable interest in the associated entity once the ship is delivered to its owner in 2005. At that time, we will determine if the entity is a VIE, and if we are the primary beneficiary. We will continue to account for these agreements as guarantees and contingent liabilities. See Note 10Guarantees for additional information.
Note 4Discontinued Operations
During 2003 and the first quarter of 2004, we disposed of or held for sale certain midstream, refining and marketing assets, which are classified as discontinued operations. In January 2004, we signed agreements to sell our Mobil-branded marketing assets on the East Coast in two separate transactions. The closing for one of these transactions took place in April 2004. Closing of the other transaction is subject to customary government and regulatory reviews and other closing conditions and is expected to close in the second quarter of 2004. Discussions are under way with potential buyers for the remaining marketing assets held for sale, and we expect to complete the sale of these assets in 2004.
5
Sales and other operating revenues and income from discontinued operations were as follows:
Millions of Dollars |
||||||||
Three Months Ended | ||||||||
March 31 |
||||||||
2004 | 2003 | |||||||
Sales and other operating revenues from discontinued
operations |
$ | 578 | 2,182 | |||||
Income from discontinued operations before-tax |
$ | 21 | 88 | |||||
Income tax expense |
8 | 35 | ||||||
Income from discontinued operations |
$ | 13 | 53 | |||||
The major classes of assets and liabilities of discontinued operations held for sale were as follows:
Millions of Dollars |
||||||||
March 31 | December 31 | |||||||
2004 | 2003 | |||||||
Assets |
||||||||
Net properties, plants and equipment |
$ | 771 | 857 | |||||
Other assets |
5 | 7 | ||||||
Assets of discontinued operations |
$ | 776 | 864 | |||||
Liabilities |
||||||||
Deferred income taxes, other liabilities and deferred
credits |
$ | 182 | 179 | |||||
Liabilities of discontinued operations |
$ | 182 | 179 | |||||
Note 5Inventories
Inventories consisted of the following:
Millions of Dollars |
||||||||
March 31 | December 31 | |||||||
2004 | 2003 | |||||||
Crude oil and petroleum
products |
$ | 3,878 | 3,467 | |||||
Materials, supplies and other |
482 | 490 | ||||||
$ | 4,360 | 3,957 | ||||||
Inventories valued on a last-in, first-out (LIFO) basis totaled $3,699 million and $3,224 million at March 31, 2004, and December 31, 2003, respectively. The remainder of our inventories are valued under various methods, including first-in, first-out and weighted average. The excess of current replacement cost over LIFO cost of inventories was $1,665 million and $1,421 million at March 31, 2004, and December 31, 2003, respectively.
6
Note 6Properties, Plants and Equipment
Properties, plants and equipment included the following:
Millions of Dollars |
||||||||
March 31 | December 31 | |||||||
2004 | 2003 | |||||||
Properties, plants and equipment (at cost) |
$ | 62,880 | 61,839 | |||||
Less: accumulated depreciation, depletion and
amortization |
15,176 | 14,411 | ||||||
$ | 47,704 | 47,428 | ||||||
In June 2001, the FASB issued SFAS No. 141, Business Combinations, and SFAS No. 142, Goodwill and Other Intangible Assets, which became effective on July 1, 2001, and January 1, 2002, respectively. The Securities and Exchange Commission (SEC) requested the Emerging Issues Task Force (EITF) to consider the issue of whether SFAS Nos. 141 and 142 require interests held under oil, gas and mineral leases to be separately classified as intangible assets on the balance sheets of companies in the extractive industries. Historically, in accordance with SFAS No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies, we have capitalized the cost of oil and gas leasehold interests and, consistent with industry practice, reported these assets as part of tangible Exploration and Production (E&P) properties, plants and equipment.
At its March 2004 meeting, the EITF reached a consensus that all mineral rights should be considered tangible assets for accounting purposes. The EITF acknowledged that this consensus would require an amendment to SFAS Nos. 141 and 142 to remove mineral rights as an example of an intangible asset. In April 2004, the FASB issued FASB Staff Position Nos. FAS 141-1 and FAS 142-1, which amended SFAS Nos. 141 and 142 to remove mineral rights as an example of an intangible asset consistent with the EITFs consensus.
E&P properties, plants and equipment at March 31, 2004, and December 31, 2003, included approximately $10.0 billion and $10.5 billion, respectively, of mineral rights to extract oil and gas, net of accumulated depletion.
Property ImpairmentsIn the first quarter of 2004, we recorded property impairments of $31 million related to planned dispositions in our Midstream, E&P and Refining and Marketing (R&M) segments. In the first quarter of 2003, property impairments of $28 million were recorded in our E&P segment, also mainly related to planned dispositions.
Note 7Restructuring
As a result of the 2002 merger of Conoco Inc. and Phillips Petroleum Company that formed ConocoPhillips, 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 connection with this program, we recorded accruals in 2002 of $770 million and in 2003, as individual components of the restructuring program were finalized, we recorded an additional $350 million, of which $46 million was accrued in the first quarter. Included in the total 2002 and 2003 accruals of $1,120 million was a $290 million expense related to pension and other postretirement 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. Of the $46 million
7
accrued in the first quarter of 2003, $44 million was reflected as a purchase price adjustment in the consolidated financial statements and $2 million was reflected in selling, general and administrative expense and production and operating expense. Included in the total accruals of $46 million was a $7 million expense related to pension and other postretirement benefits. In the first three months of 2004, we recorded additional accruals totaling $18 million, which were reflected in the consolidated financial statements as selling, general and administrative expense and production and operating expense. Included in the total accruals of $18 million was a $4 million expense related to pension and postretirement benefits. A roll-forward of activity during the first quarter of 2004 is provided below for the nonpension portion of the accruals, which primarily consists of severance-related benefits to be provided based on agreed upon payment schedules to approximately 3,900 employees worldwide, most of whom are in the United States, as well as other merger-related expenses.
Millions of Dollars |
||||||||||||||||
Reserve at | First Quarter 2004 |
Reserve at | ||||||||||||||
December 31, 2003 |
Accrual |
Payments |
March 31, 2004 |
|||||||||||||
Conoco |
$ | 83 | (7 | ) | (42 | ) | 34 | |||||||||
Phillips |
164 | 21 | (98 | ) | 87 | |||||||||||
Total |
$ | 247 | 14 | (140 | ) | 121 | ||||||||||
The ending accrual balance at March 31, 2004, is expected to be extinguished within one year, except for $49 million, which is classified as long-term. Approximately 900 employees were terminated during the first quarter of 2004 and approximately 3,900 employees have been terminated since the restructuring program was implemented.
Note 8Debt
At March 31, 2004, we had four 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 $1.5 billion, 364-day revolving credit facility expiring on October 13, 2004, a $500 million five-year facility expiring in October 2008, and two revolving credit facilities totaling $2 billion expiring in October 2006. At March 31, 2004, we had no debt outstanding under these credit facilities, and no commercial paper outstanding, compared with $709 million at December 31, 2003. The commercial paper is supported 100 percent by the credit facilities and the amount approximates fair value. In addition, one of our Norwegian subsidiaries has two $300 million revolving credit facilities that expire in June 2004, under which no borrowings were outstanding at March 31, 2004.
In April 2004, we paid off the $1,350 million aggregate principal amount of our 5.90% Notes due 2004 at maturity by using the proceeds from issuing commercial paper.
Note 9Contingencies
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 Conocos separation agreement with DuPont, we also have assumed responsibility for current and future
8
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.
EnvironmentalWe 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 managements best estimates, 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 also consider unasserted claims in our determination of environmental liabilities and we accrue them in the period that they become 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 we were solely responsible, the costs, in some cases, could be material to our, or one of our segments, results of operations, capital resources or liquidity. However, settlements and costs incurred in matters 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, we may have no liability or may 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 indemnifications made by others for our benefit and some of the indemnifications are subject to dollar 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.
9
We are currently participating in environmental assessments and cleanups at numerous 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 those assumed in a purchase business combination, which we record 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. At March 31, 2004, ConocoPhillips balance sheet included a total environmental accrual of $1,117 million, compared with $1,119 million at December 31, 2003. 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.
Other Legal ProceedingsWe 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 ContingenciesWe 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 performance obligations that are secured by unused letters of credit and various purchase commitments for materials, supplies, services and items of permanent investment incident to the ordinary conduct of business.
Note 10Guarantees
At March 31, 2004, 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.
Construction Completion Guarantees
| We have a construction completion guarantee related to debt and bond financing arrangements secured by the Merey Sweeny, L.P. (MSLP) joint-venture project at the Sweeny refinery in Old Ocean, Texas. The maximum potential amount of future payments under the guarantee, including joint-and-several debt at its gross amount, is estimated to be $400 million, assuming that completion certification is not achieved. Of this amount, $200 million is attributable to Petroleos de Venezuela S.A., which has an indirect 50 percent interest in MSLP, and which is jointly-and-severally liable for the debt. If completion certification is not achieved by June 18, 2004, the full debt balance could be called. However, MSLP has received the required permit for the new waste water pipeline and has resolved issues in placing its insurance program, and therefore, expects to achieve completion certification in the second quarter. If completion certification is achieved the debt becomes nonrecourse. | |||
| We also issued a construction completion guarantee related to debt financing arrangements for the Hamaca Holding LLC joint-venture project in Venezuela. The maximum potential amount of future payments under the guarantee is estimated to be $440 million, which could be payable if the full debt financing capacity is utilized and startup and completion of the Hamaca project is not achieved by October 1, 2005. The project financing debt will be nonrecourse upon startup and completion certification. |
10
Guarantees of Joint-Venture Debt
| At March 31, 2004, we had guarantees of about $330 million outstanding for our portion of joint-venture debt obligations, which have terms of up to 22 years. Included in these outstanding guarantees was $140 million associated with the Polar Lights Company joint venture in Russia. Payment will be required if the joint venture defaults on its debt obligations. |
Other Guarantees
| In addition to the construction completion guarantee explained above, the MSLP agreement also requires the partners in the venture to pay cash calls as required to meet the minimum operating requirements of the venture, in the event revenues do not cover expenses over the next 20 years. Our maximum potential future payments under the agreement are estimated to be $300 million, assuming MSLP does not earn any revenue over the entire period and fixed costs cannot be reduced. To the extent revenue is generated by the venture or fixed costs are reduced, future required payments would be reduced accordingly. | |||
| In February 2003, we entered into two agreements establishing separate guarantee facilities for $50 million each for two liquefied natural gas vessels. Subject to the terms of each such facility, we will be required to make payments should the charter revenue generated by the respective ship fall below certain specified minimum thresholds, and we will receive payments to the extent that such revenues exceed those thresholds. The net maximum future payments that we may have to make over the 20-year terms of the two agreements could be up to an aggregate of $100 million. Actual gross payments over the 20 years could exceed that amount to the extent cash is received by us. In the event either ship is sold or a total loss occurs, we also may have recourse to the sales or insurance proceeds to recoup payments made under the guarantee facilities. In April 2003, based on the then current market view of both long-term and short-term shipping capacity, rates, and utilization probability, we estimated the fair value of the liability under these guarantee facilities to be immaterial. In September 2003, the first ship was delivered to its owner and the second ship is scheduled for delivery to its owner in 2005. With respect to the first ship, the amount drawn under the guarantee facility at March 31, 2004, was less than $1 million. | |||
| We have other guarantees totaling $190 million, which consist primarily of dealer and jobber loan guarantees to support our marketing business, a guarantee supporting a lease assignment on a corporate aircraft, a guarantee associated with a pending lawsuit and guarantees of lease payment obligations for a joint venture. The carrying amount recorded for these other guarantees as of March 31, 2004, was $13 million. These guarantees generally extend up to 15 years and payment would only be required if the dealer, jobber or lessee goes into default, or if an adverse decision occurs in the lawsuit. |
Indemnifications
| Over the years, we have entered into various agreements to sell ownership interests in certain corporations and joint ventures. In addition, we entered into a Tax Sharing Agreement in 1998 related to Conocos separation from DuPont. These agreements typically include indemnifications for additional taxes determined to be due under the relevant tax law, in connection with operations for years prior to the sale or separation. Generally, the obligation extends until the related tax years are closed. The maximum potential amount of future payments under the indemnifications is the amount of additional tax determined to be due under relevant tax law and the various agreements. Amounts estimated to be due under the agreements have been accrued and we believe it is remote that settlement of the ultimate obligations would exceed the current accruals by an amount that would have a material adverse impact on our financial statements. |
11
| During 2003 and in the first quarter of 2004, we sold several assets, including FTC-mandated sales of downstream and midstream assets, certain exploration and production assets, and downstream retail and wholesale sites, giving rise to qualifying indemnifications. Agreements associated with these sales include indemnifications for taxes, environmental liabilities, underground storage tank repairs or replacements, permits and licenses, employee claims, real estate indemnity against tenant defaults, and litigation. The terms of these indemnifications vary greatly. The majority of these indemnifications are related to environmental issues, the term is generally indefinite and the maximum amount of future payments is generally unlimited. The carrying amount recorded for these indemnifications as of March 31, 2004, was $214 million. We amortize the indemnification liability over the relevant time period, if one exists, based on the facts and circumstances surrounding each type of indemnity. In cases where the indemnification term is indefinite, we will reverse the liability when we have information that the liability is essentially relieved or amortize over an appropriate time period as the fair value of our indemnification exposure declines over time. Although it is reasonably possible that future payments may exceed amounts recorded, due to the nature of the indemnifications, it is not possible to make a reasonable estimate of the maximum potential amount of future payments. Included in the carrying amount recorded was $86 million of environmental accruals for known contamination that is included in asset retirement obligations and accrued environmental costs at March 31, 2004. For additional information about environmental liabilities, see Note 9Contingencies. | |||
| As part of our normal ongoing business operations and consistent with industry practice, we enter into numerous agreements with other parties, which apportion future risks among the parties to the transaction or relationship governed by the agreements. One method of apportioning risk is the inclusion of provisions requiring one party to indemnify the other against losses that might otherwise be incurred by the other party in the future. Many of our agreements contain an indemnity or indemnities that require us to perform certain acts, such as remediation, as a result of the occurrence of a triggering event or condition. In some instances we indemnify third parties against losses resulting from certain events or conditions that arise out of the operations of our equity affiliates. | |||
The nature of these numerous indemnity obligations are diverse and each has different terms, business purposes, and triggering events or conditions. Consistent with customary business practice, any particular indemnity obligation incurred is the result of a negotiated transaction or contractual relationship for which we have accepted a certain level of risk in return for a financial or other type of benefit. In addition, the indemnities in each agreement vary widely in their definitions of both triggering events and the resulting obligations contingent on those triggering events. | ||||
With regard to indemnifications, our risk management philosophy is to limit risk in any transaction or relationship to the maximum extent reasonable in relation to commercial and other considerations. Before accepting any indemnity obligation, we make an informed risk management decision considering, among other things, the remoteness of the possibility that the triggering event will occur, the potential costs to perform under any resulting indemnity obligation, possible actions to reduce the likelihood of a triggering event or to reduce the costs of performing under the indemnity obligation, whether we are indemnified by an unrelated third party, insurance coverage that may be available to offset the cost of the indemnity obligation, and the benefits from the transaction or relationship. |
12
Because many of our indemnity obligations are not limited in duration or potential monetary exposure, we cannot calculate a reasonable estimate of the maximum potential amount of future payments that could be paid under our indemnity obligations stemming from all our existing agreements. The carrying amount recorded for these indemnifications as of March 31, 2004, was $224 million, which is for known contamination and is included in asset retirement obligations and accrued environmental costs. For additional information about environmental liabilities and contingencies, see Note 9Contingencies. |
Note 11Other Comprehensive Income
ConocoPhillips other comprehensive income was as follows:
|
||||||||
Millions of Dollars |
||||||||
Three Months Ended | ||||||||
March 31 |
||||||||
2004 | 2003 | |||||||
Net income |
$ | 1,616 | 1,221 | |||||
After-tax changes in: |
||||||||
Minimum pension liability adjustment |
(1 | ) | 6 | |||||
Foreign currency translation adjustments |
| 137 | ||||||
Unrealized gain (loss) on securities |
1 | (1 | ) | |||||
Hedging activities |
| 3 | ||||||
Equity affiliates: |
||||||||
Foreign currency translation |
(24 | ) | 32 | |||||
Derivatives related |
| 2 | ||||||
$ | 1,592 | 1,400 | ||||||
Accumulated other comprehensive income in the equity section of the balance sheet included:
Millions of Dollars |
||||||||
March 31 | December 31 | |||||||
2004 | 2003 | |||||||
Minimum pension liability adjustment |
$ | (69 | ) | (68 | ) | |||
Foreign currency translation
adjustments |
735 | 735 | ||||||
Unrealized gain on securities |
6 | 5 | ||||||
Deferred net hedging gain |
2 | 2 | ||||||
Equity affiliates: |
||||||||
Foreign currency translation |
126 | 150 | ||||||
Derivatives related |
(3 | ) | (3 | ) | ||||
$ | 797 | 821 | ||||||
13
Note 12Supplemental Cash Flow Information
Millions of Dollars |
||||||||
Three Months Ended | ||||||||
March 31 |
||||||||
2004 | 2003 | |||||||
Non-Cash Investing and Financing Activities |
||||||||
Increase in properties, plants and equipment in
exchange for related increase in asset
retirement obligations associated with the
initial implementation of SFAS No. 143 |
$ | | 1,229 | |||||
Increase in properties, plants and equipment
related to the implementation of FIN 46 |
| 940 | ||||||
Increase in long-term debt through the
implementation and continuing application of
FIN 46 |
| 2,774 | ||||||
Increase in assets of discontinued operations
held for sale related to implementation of FIN
46 |
| 726 | ||||||
Cash Payments |
||||||||
Interest |
$ | 13 | 79 | |||||
Income taxes |
373 | 199 | ||||||
Note 13Sales of Receivables
At March 31, 2004, certain credit card and trade receivables had been sold to a Qualifying Special Purpose Entity (QSPE) in a revolving-period securitization arrangement. This arrangement provides for us to sell, and the QSPE to purchase, certain receivables, and for the QSPE to then issue beneficial interests of up to $1.2 billion to five bank-sponsored entities. All five bank-sponsored entities are multi-seller conduits with access to the commercial paper market and purchase interests in similar receivables from numerous other companies unrelated to us. We have no ownership interests, nor any variable interests, in any of the bank-sponsored entities. As a result, we do not consolidate any of these entities. Furthermore, we do not consolidate the QSPE because it meets the requirements of SFAS No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, to be excluded from the consolidated financial statements of ConocoPhillips.
At March 31, 2004, and December 31, 2003, the QSPE had issued beneficial interests to the bank-sponsored entities of $450 million and $1.2 billion, respectively. The receivables transferred to the QSPE meet the isolation requirements and other requirements of SFAS No. 140 to be accounted for as sales and were accounted for accordingly.
We retain beneficial interests in the QSPE that are subordinate to the beneficial interests issued to the bank-sponsored entities. These retained interests, which are reported on the balance sheet in accounts and notes receivablerelated parties, were $2.3 billion at March 31, 2004, and $1.3 billion at December 31, 2003. We also retain servicing responsibility related to the sold receivables, which gives us certain rights and abilities, the fair value of which approximates the fair value of the liability incurred for continuing to service the receivables. The carrying value of our subordinated beneficial interests in the QSPE approximates fair market value due to the very short term of the underlying assets, which makes fair value stress testing for disclosure purposes unnecessary.
14
Total cash flows received from and paid under the securitization arrangements were as follows:
Millions of Dollars |
||||||||
2004 | 2003 | |||||||
Receivables sold at beginning of year |
$ | 1,200 | 1,323 | |||||
New receivables sold |
3,150 | 6,304 | ||||||
Cash collections remitted |
(3,900 | ) | (6,306 | ) | ||||
Receivables sold at March 31 |
$ | 450 | 1,321 | |||||
Discounts and other fees paid on revolving
balances |
$ | 2 | 5 | |||||
The decrease in cash flow activity in 2004 was primarily due to reductions in the average level of beneficial interests issued to the bank-sponsored entities.
At December 31, 2003, we had sold $226 million of receivables under factoring arrangements. We retain servicing responsibility related to these sold receivables, which gives us certain benefits, the fair value of which approximates the fair value of the liability incurred for continuing to service the receivables. At March 31, 2004, we had no receivables outstanding under similar arrangements.
Note 14Employee Benefit Plans
Pension and Postretirement Plans
Millions of Dollars |
||||||||||||||||||||||||
Pension Benefits |
Other Benefits |
|||||||||||||||||||||||
Three Months Ended | March 31 |
March 31 |
||||||||||||||||||||||
2004 |
2003 |
2004 |
2003 |
|||||||||||||||||||||
U.S. |
Int'l. |
U.S. |
Int'l. |
|||||||||||||||||||||
Components of Net Periodic
Benefit Cost |
||||||||||||||||||||||||
Service cost |
$ | 37 | 16 | 33 | 12 | 5 | 4 | |||||||||||||||||
Interest cost |
44 | 28 | 49 | 16 | 15 | 15 | ||||||||||||||||||
Expected return on plan assets |
(26 | ) | (23 | ) | (22 | ) | (14 | ) | | | ||||||||||||||
Amortization of prior service
cost |
1 | 2 | 1 | 1 | 5 | 5 | ||||||||||||||||||
Recognized net actuarial loss |
13 | 10 | 17 | 3 | 2 | 1 | ||||||||||||||||||
Net periodic benefit costs |
$ | 69 | 33 | 78 | 18 | 27 | 25 | |||||||||||||||||
We recognized pension settlement losses of $4 million and $9 million in the first quarters of 2004 and 2003, respectively, due to high levels of lump sum elections by new retirees in certain plans.
We have elected to defer financial recognition of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 until the FASB issues final accounting guidance. When issued, that final guidance could require us to change previously reported information. This deferral is permitted under FASB Staff Position No. FAS 106-1, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.
15
Stock-Based Compensation
Effective January 1, 2003, we voluntarily adopted the fair-value accounting method provided under SFAS No. 123, Accounting for Stock-Based Compensation. Using the SFAS No. 123 prospective transition method, we apply the fair-value accounting method and recognize compensation expense equal to the fair-market value on the grant date for all stock options granted or modified after December 31, 2002.
Employee stock options granted prior to 2003 continue to be accounted for under Accounting Principles Board (APB) No. 25, Accounting for Stock Issued to Employees, and related Interpretations. Because the exercise price of our employee stock options equals the market price of the underlying stock on the date of grant, no compensation expense is generally recognized under APB No. 25. The following table displays pro forma information as if provisions of SFAS No. 123 had been applied to all employee stock options granted:
Millions of Dollars |
||||||||
Three Months Ended | ||||||||
March 31 |
||||||||
2004 | 2003 | |||||||
Net income, as reported |
$ | 1,616 | 1,221 | |||||
Add: Stock-based employee compensation expense
included in reported net income, net of related
tax effects |
13 | 9 | ||||||
Deduct: Total stock-based employee compensation
expense determined under fair-value-based
method for all awards, net of related tax
effects |
16 | 17 | ||||||
Pro forma net income |
$ | 1,613 | 1,213 | |||||
Earnings per share: |
||||||||
Basicas reported |
$ | 2.36 | 1.80 | |||||
Basicpro forma |
2.35 | 1.79 | ||||||
Dilutedas reported |
2.33 | 1.79 | ||||||
Dilutedpro forma |
2.32 | 1.78 | ||||||
Note 15Related Party Transactions
Significant transactions with related parties were:
Millions of Dollars |
||||||||
Three Months Ended | ||||||||
March 31 |
||||||||
2004 | 2003 | |||||||
Operating revenues (a) |
$ | 1,085 | 1,087 | |||||
Purchases (b) |
899 | 885 | ||||||
Operating expenses and selling, general and administrative expenses
(c) |
186 | 138 | ||||||
Net interest (income) expense (d) |
(7 | ) | (13 | ) | ||||
(a) | Our Exploration and Production (E&P) segment sells natural gas to Duke Energy Field Services, LLC (DEFS) and crude oil to the Malaysian Refining Company Sdn. Bhd (Melaka), among others, for processing and marketing. Natural gas liquids, solvents and petrochemical feedstocks |
16
are sold to Chevron Phillips Chemical Company LLC (CPChem) and refined products are sold primarily to CFJ Properties. Also, we charge several of our affiliates including CPChem, MSLP, and Hamaca Holding LLC for the use of common facilities, such as steam generators, waste and water treaters, and warehouse facilities. | ||||
(b) | We purchase natural gas and natural gas liquids from DEFS and CPChem for use in our refinery processes and other feedstocks from various affiliates. We purchase upgraded crude oil from Petrozuata C.A. and refined products from Melaka. We also pay fees to various pipeline equity companies for transporting finished refined products. | |||
(c) | We pay processing fees to various affiliates, the most significant being MSLP. Additionally, we pay crude oil transportation fees to pipeline equity companies, and commissions to the receivable monetization QSPE. | |||
(d) | We pay and/or receive interest to/from various affiliates including the receivable monetization QSPE. |
Elimination of our equity percentage share of profit or loss on the above transactions was not material.
Note 16Segment Disclosures and Related Information
We have organized our reporting structure based on the grouping of similar products and services, resulting in five operating segments:
(1) | Exploration and Production (E&P)This segment primarily explores for and produces crude oil, natural gas and natural gas liquids on a worldwide basis. At March 31, 2004, E&P was producing in the United States, Norway, the United Kingdom, Canada, Nigeria, Venezuela, offshore Timor Leste in the Timor Sea, Australia, China, Indonesia, the United Arab Emirates, Vietnam, and Russia. The E&P segments U.S. and international operations are disclosed separately for reporting purposes. | |||
(2) | MidstreamThrough both consolidated and equity interests, this segment gathers and processes natural gas produced by ConocoPhillips and others, and fractionates and markets natural gas liquids, primarily in the United States, Canada and Trinidad. The Midstream segment includes our 30.3 percent equity investment in DEFS. | |||
(3) | Refining and Marketing (R&M)This segment purchases, refines, markets and transports crude oil and petroleum products, mainly in the United States, Europe and Asia. At March 31, 2004, we owned 12 refineries in the United States; one in the United Kingdom; one in Ireland; and had equity interests in one refinery in Germany, two in the Czech Republic, and one in Malaysia. The R&M segments U.S. and international operations are disclosed separately for reporting purposes. | |||
(4) | ChemicalsThis segment manufactures and markets petrochemicals and plastics on a worldwide basis. The Chemicals segment consists of our 50 percent equity investment in CPChem. | |||
(5) | Emerging BusinessesThis segment encompasses the development of new businesses beyond our traditional operations. Emerging Businesses includes new technologies related to natural gas conversion into clean fuels and related products (gas-to-liquids), technology solutions, power generation and emerging technologies. |
17
Corporate and Other includes general corporate overhead, all interest income and expense, discontinued operations, restructuring charges 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 net income. Intersegment sales are recorded at prices that approximate market value.
Analysis of Results by Operating Segment
Millions of Dollars |
||||||||
Three Months Ended | ||||||||
March 31 |
||||||||
2004 | 2003 | |||||||
Sales and Other Operating Revenues |
||||||||
E&P |
||||||||
United States |
$ | 5,567 | 4,738 | |||||
International |
4,039 | 3,305 | ||||||
Intersegment
eliminationsU.S. |
(662 | ) | (682 | ) | ||||
Intersegment
eliminationsInternational |
(938 | ) | (797 | ) | ||||
E&P |
8,006 | 6,564 | ||||||
Midstream |
||||||||
Total sales |
1,239 | 1,620 | ||||||
Intersegment eliminations |
(353 | ) | (376 | ) | ||||
Midstream |
886 | 1,244 | ||||||
R&M |
||||||||
United States |
15,427 | 14,852 | ||||||
International |
5,526 | 4,799 | ||||||
Intersegment
eliminationsU.S. |
(95 | ) | (570 | ) | ||||
Intersegment
eliminationsInternational |
(1 | ) | (11 | ) | ||||
R&M |
20,857 | 19,070 | ||||||
Chemicals |
4 | 3 | ||||||
Emerging Businesses |
46 | 56 | ||||||
Corporate and Other |
1 | 3 | ||||||
Consolidated Sales and Other Operating
Revenues |
$ | 29,800 | 26,940 | |||||
Net Income (Loss) |
||||||||
E&P |
||||||||
United States |
$ | 635 | 820 | |||||
International |
622 | 447 | ||||||
Total E&P |
1,257 | 1,267 | ||||||
Midstream |
55 | 31 | ||||||
R&M |
||||||||
United States |
403 | 150 | ||||||
International |
61 | 114 | ||||||
Total R&M |
464 | 264 | ||||||
Chemicals |
39 | (23 | ) | |||||
Emerging Businesses |
(22 | ) | (34 | ) | ||||
Corporate and Other |
(177 | ) | (284 | ) | ||||
Consolidated Net Income |
$ | 1,616 | 1,221 | |||||
18
Millions of Dollars |
||||||||
March 31 | December 31 | |||||||
2004 | 2003 | |||||||
Total Assets |
||||||||
E&P |
||||||||
United States |
$ | 15,409 | 15,262 | |||||
International |
22,867 | 22,458 | ||||||
Goodwill |
11,192 | 11,184 | ||||||
Total E&P |
49,468 | 48,904 | ||||||
Midstream |
1,712 | 1,736 | ||||||
R&M |
||||||||
United States |
18,413 | 17,172 | ||||||
International |
5,089 | 5,020 | ||||||
Goodwill |
3,900 | 3,900 | ||||||
Total R&M |
27,402 | 26,092 | ||||||
Chemicals |
2,139 | 2,094 | ||||||
Emerging Businesses |
891 | 843 | ||||||
Corporate and Other |
2,817 | 2,786 | ||||||
Consolidated Total
Assets |
$ | 84,429 | 82,455 | |||||
Note 17Income Taxes
Our effective tax rate for the first quarter of 2004 was 46 percent, compared with 51 percent for the same period a year ago. Contributing to the lower tax rate in the first quarter of 2004, compared with the corresponding period in 2003, was the impact of a lower portion of income being earned in higher tax-rate jurisdictions. The effective tax rate in excess of the domestic federal statutory rate of 35 percent was primarily due to foreign taxes in excess of the domestic federal statutory rate.
Note 18Preferred Share Purchase Rights
Our Board of Directors authorized and declared a dividend of one preferred share purchase right for each common share outstanding, and authorized and directed the issuance of one right per common share for any newly issued shares. The rights have certain anti-takeover effects. The rights will cause substantial dilution to a person or group that attempts to acquire ConocoPhillips on terms not approved by the Board of Directors. However, since the rights may either be redeemed or otherwise made inapplicable by ConocoPhillips prior to an acquiror obtaining beneficial ownership of 15 percent or more of ConocoPhillips common stock, the rights should not interfere with any merger or business combination approved by the Board of Directors prior to that occurrence. The rights, which expire June 30, 2012, will be exercisable only if a person or group acquires 15 percent or more of the companys common stock or commences a tender offer that would result in ownership of 15 percent or more of the common stock. Each right would entitle stockholders to buy one one-hundredth of a share of preferred stock at an exercise price of $300. If an acquiror obtains 15 percent or more of ConocoPhillips common stock, then each right will be adjusted so that it will entitle the holder (other than the acquiror, whose rights will become void) to purchase, for the then exercise price, a number of shares of ConocoPhillips common stock equal in value to two times the exercise price of the right. In addition, the rights enable holders to purchase the stock of an acquiring company at a discount, depending on specific circumstances. We may redeem the rights in whole, but not in part, for one cent per right.
19
Note 19New Accounting Standards
In December 2003, the FASB revised and reissued SFAS No. 132 (revised 2003), Employers Disclosures about Pensions and Other Postretirement Benefitsan amendment of FASB Statements No. 87, 88 and 106. While requiring certain new disclosures, the new Standard does not change the measurement or recognition of employee benefit plans. We adopted the provisions of this Standard effective December 2003, except for certain provisions regarding disclosure of information about estimated future benefit payments which are not required until the fourth quarter of 2004.
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 was originally intended to become effective July 1, 2003, for all previously existing contracts. However, on November 7, 2003, the FASB issued an indefinite deferral of certain provisions of SFAS No. 150. We will continue to monitor and assess the FASBs modifications to SFAS No. 150, but do not anticipate that it will have a material impact on our financial statements.
In April 2004, the FASB issued FASB Staff Position Nos. FAS 141-1 and FAS 142-1, which amended SFAS No. 141, Business Combinations, and SFAS No. 142, Goodwill and Other Intangible Assets, to remove mineral rights as an example of an intangible asset. See Note 6Properties, Plants and Equipment for more information.
20
Supplementary InformationCondensed Consolidating Financial Information
We have various cross guarantees between ConocoPhillips, ConocoPhillips Holding Company, and ConocoPhillips Company. ConocoPhillips Company 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:
| ConocoPhillips, ConocoPhillips Holding Company, and ConocoPhillips Company (in each case, reflecting investments in subsidiaries utilizing the equity method of accounting); | |||
| All other non-guarantor subsidiaries of ConocoPhillips Holding Company and ConocoPhillips Company; and | |||
| The consolidating adjustments necessary to present ConocoPhillips results on a consolidated basis. |
This condensed consolidating financial information should be read in conjunction with the accompanying consolidated financial statements and notes.
21
Millions of Dollars |
||||||||||||||||||||||||
Three Months Ended March 31, 2004 |
||||||||||||||||||||||||
ConocoPhillips | ConocoPhillips | All Other | Consolidating | Total | ||||||||||||||||||||
Income Statement | ConocoPhillips |
Holding Company |
Company |
Subsidiaries |
Adjustments |
Consolidated |
||||||||||||||||||
Revenues |
||||||||||||||||||||||||
Sales and other operating revenues |
$ | | | 19,414 | 10,386 | | 29,800 | |||||||||||||||||
Equity in earnings of affiliates |
1,610 | 1,558 | 1,145 | 215 | (4,259 | ) | 269 | |||||||||||||||||
Other income |
| | (7 | ) | 155 | | 148 | |||||||||||||||||
Intercompany revenues |
8 | 130 | 384 | 1,392 | (1,914 | ) | | |||||||||||||||||
Total Revenues |
1,618 | 1,688 | 20,936 | 12,148 | (6,173 | ) | 30,217 | |||||||||||||||||
Costs and Expenses |
||||||||||||||||||||||||
Purchased crude oil and products |
| | 16,054 | 5,323 | (1,692 | ) | 19,685 | |||||||||||||||||
Production and operating expenses |
| | 941 | 790 | (12 | ) | 1,719 | |||||||||||||||||
Selling, general and
administrative expenses |
2 | | 300 | 169 | (7 | ) | 464 | |||||||||||||||||
Exploration expenses |
| | 18 | 125 | | 143 | ||||||||||||||||||
Depreciation, depletion and
amortization |
| | 240 | 678 | | 918 | ||||||||||||||||||
Property impairments |
| | 7 | 24 | | 31 | ||||||||||||||||||
Taxes other than income taxes |
| | 1,351 | 2,763 | | 4,114 | ||||||||||||||||||
Accretion on discounted
liabilities |
| | 10 | 26 | | 36 | ||||||||||||||||||
Interest and debt expense |
22 | 50 | 272 | 4 | (203 | ) | 145 | |||||||||||||||||
Foreign currency transaction
losses (gains) |
| | (6 | ) | (10 | ) | | (16 | ) | |||||||||||||||
Minority interests |
| | | 14 | | 14 | ||||||||||||||||||
Total Costs and Expenses |
24 | 50 | 19,187 | 9,906 | (1,914 | ) | 27,253 | |||||||||||||||||
Income from continuing operations
before income taxes |
1,594 | 1,638 | 1,749 | 2,242 | (4,259 | ) | 2,964 | |||||||||||||||||
Provision for income taxes |
(9 | ) | 28 | 201 | 1,141 | | 1,361 | |||||||||||||||||
Income from continuing operations |
1,603 | 1,610 | 1,548 | 1,101 | (4,259 | ) | 1,603 | |||||||||||||||||
Income from discontinued
operations |
13 | 13 | 13 | 59 | (85 | ) | 13 | |||||||||||||||||
Income before cumulative effect
of changes in accounting
principles |
1,616 | 1,623 | 1,561 | 1,160 | (4,344 | ) | 1,616 | |||||||||||||||||
Cumulative effect of changes in
accounting principles |
| | | | | | ||||||||||||||||||
Net Income |
$ | 1,616 | 1,623 | 1,561 | 1,160 | (4,344 | ) | 1,616 | ||||||||||||||||
22
Millions of Dollars |
||||||||||||||||||||||||
Three Months Ended March 31, 2003 |
||||||||||||||||||||||||
ConocoPhillips | ConocoPhillips | All Other | Consolidating | Total | ||||||||||||||||||||
Income Statement | ConocoPhillips |
Holding Company |
Company |
Subsidiaries |
Adjustments |
Consolidated |
||||||||||||||||||
Revenues |
||||||||||||||||||||||||
Sales and other operating revenues |
$ | | | 17,087 | 9,853 | | 26,940 | |||||||||||||||||
Equity in earnings of affiliates |
1,277 | 1,241 | 968 | 81 | (3,518 | ) | 49 | |||||||||||||||||
Other income |
| | 42 | 37 | | 79 | ||||||||||||||||||
Intercompany revenues |
7 | 150 | 969 | 1,500 | (2,626 | ) | | |||||||||||||||||
Total Revenues |
1,284 | 1,391 | 19,066 | 11,471 | (6,144 | ) | 27,068 | |||||||||||||||||
Costs and Expenses |
||||||||||||||||||||||||
Purchased crude oil and products |
| | 14,719 | 5,257 | (2,304 | ) | 17,672 | |||||||||||||||||
Production and operating expenses |
| | 944 | 772 | (46 | ) | 1,670 | |||||||||||||||||
Selling, general and
administrative expenses |
1 | | 318 | 130 | (2 | ) | 447 | |||||||||||||||||
Exploration expenses |
| | 31 | 85 | | 116 | ||||||||||||||||||
Depreciation, depletion and
amortization |
| | 283 | 576 | | 859 | ||||||||||||||||||
Property impairments |
| | | 28 | | 28 | ||||||||||||||||||
Taxes other than income taxes |
| | 1,082 | 2,340 | | 3,422 | ||||||||||||||||||
Accretion on discounted
liabilities |
| | 7 | 26 | | 33 | ||||||||||||||||||
Interest and debt expense |
31 | 94 | 310 | 78 | (274 | ) | 239 | |||||||||||||||||
Foreign currency transaction
losses (gains) |
| | (8 | ) | 14 | | 6 | |||||||||||||||||
Minority interests |
| | | 7 | | 7 | ||||||||||||||||||
Total Costs and Expenses |
32 | 94 | 17,686 | 9,313 | (2,626 | ) | 24,499 | |||||||||||||||||
Income from continuing operations
before income taxes |
1,252 | 1,297 | 1,380 | 2,158 | (3,518 | ) | 2,569 | |||||||||||||||||
Provision for income taxes |
(11 | ) | 20 | 153 | 1,144 | | 1,306 | |||||||||||||||||
Income from continuing operations |
1,263 | 1,277 | 1,227 | 1,014 | (3,518 | ) | 1,263 | |||||||||||||||||
Income from discontinued
operations |
53 | 53 | 53 | 19 | (125 | ) | 53 | |||||||||||||||||
Income before cumulative effect
of changes in accounting
principles |
1,316 | 1,330 | 1,280 | 1,033 | (3,643 | ) | 1,316 | |||||||||||||||||
Cumulative effect of changes in
accounting principles |
(95 | ) | (95 | ) | (95 | ) | (255 | ) | 445 | (95 | ) | |||||||||||||
Net Income |
$ | 1,221 | 1,235 | 1,185 | 778 | (3,198 | ) | 1,221 | ||||||||||||||||
23
Millions of Dollars |
||||||||||||||||||||||||
At March 31, 2004 |
||||||||||||||||||||||||
ConocoPhillips | ConocoPhillips | All Other | Consolidating | Total | ||||||||||||||||||||
Balance Sheet | ConocoPhillips |
Holding Company |
Company |
Subsidiaries |
Adjustments |
Consolidated |
||||||||||||||||||
Assets |
||||||||||||||||||||||||
Cash and cash equivalents |
$ | | | 159 | 500 | | 659 | |||||||||||||||||
Accounts and notes receivable |
| 714 | 23,087 | 12,841 | (30,250 | ) | 6,392 | |||||||||||||||||
Inventories |
| | 3,078 | 1,282 | | 4,360 | ||||||||||||||||||
Prepaid expenses and other
current assets |
29 | 23 | 373 | 308 | | 733 | ||||||||||||||||||
Assets of discontinued
operations held for sale |
| | 475 | 301 | | 776 | ||||||||||||||||||
Total Current Assets |
29 | 737 | 27,172 | 15,232 | (30,250 | ) | 12,920 | |||||||||||||||||
Investments and long-term
receivables |
41,494 | 38,911 | 34,089 | 15,449 | (122,773 | ) | 7,170 | |||||||||||||||||
Net properties, plants and
equipment |
| | 16,333 | 31,371 | | 47,704 | ||||||||||||||||||
Goodwill |
| | 15,092 | | | 15,092 | ||||||||||||||||||
Intangibles |
| | 813 | 292 | | 1,105 | ||||||||||||||||||
Other assets |
20 | 10 | 118 | 290 | | 438 | ||||||||||||||||||
Total |
$ | 41,543 | 39,658 | 93,617 | 62,634 | (153,023 | ) | 84,429 | ||||||||||||||||
Liabilities and
Stockholders Equity |
||||||||||||||||||||||||
Accounts payable |
$ | 9,939 | 6 | 17,754 | 10,087 | (30,250 | ) | 7,536 | ||||||||||||||||
Notes payable and long-term
debt due
within one year |
| 1,350 | 71 | 20 | | 1,441 | ||||||||||||||||||
Accrued income and other
taxes |
(1 | ) | 28 | 835 | 2,378 | | 3,240 | |||||||||||||||||
Other accruals |
44 | 97 | 1,098 | 1,064 | | 2,303 | ||||||||||||||||||
Liabilities of discontinued
operations held for sale |
| | 173 | 9 | | 182 | ||||||||||||||||||
Total Current Liabilities |
9,982 | 1,481 | 19,931 | 13,558 | (30,250 | ) | 14,702 | |||||||||||||||||
Long-term debt |
2,013 | 2,959 | 6,400 | 4,296 | | 15,668 | ||||||||||||||||||
Asset retirement obligations
and accrued environmental
costs |
| | 935 | 2,672 | | 3,607 | ||||||||||||||||||
Deferred income taxes |
8 | (74 | ) | 2,635 | 6,350 | (8 | ) | 8,911 | ||||||||||||||||
Employee benefit obligations |
| 1,825 | 672 | | 2,497 | |||||||||||||||||||
Other liabilities and
deferred credits |
| 5,978 | 34,657 | 21,684 | (60,041 | ) | 2,278 | |||||||||||||||||
Total Liabilities |
12,003 | 10,344 | 66,383 | 49,232 | (90,299 | ) | 47,663 | |||||||||||||||||
Minority interests |
| (12 | ) | 5 | 953 | 946 | ||||||||||||||||||
Retained earnings |
4,017 | 3,089 | 10,260 | 9,871 | (16,681 | ) | 10,556 | |||||||||||||||||
Other stockholders equity |
25,523 | 26,237 | 16,969 | 2,578 | (46,043 | ) | 25,264 | |||||||||||||||||
Total |
$ | 41,543 | 39,658 | 93,617 | 62,634 | (153,023 | ) | 84,429 | ||||||||||||||||
24
Millions of Dollars |
||||||||||||||||||||||||
At December 31, 2003 |
||||||||||||||||||||||||
ConocoPhillips | ConocoPhillips | All Other | Consolidating | Total | ||||||||||||||||||||
Balance Sheet | ConocoPhillips |
Holding Company |
Company |
Subsidiaries |
Adjustments |
Consolidated |
||||||||||||||||||
Assets |
||||||||||||||||||||||||
Cash and cash equivalents |
$ | | | 268 | 222 | | 490 | |||||||||||||||||
Accounts and notes receivable |
| 564 | 22,065 | 13,951 | (31,575 | ) | 5,005 | |||||||||||||||||
Inventories |
| | 2,579 | 1,378 | | 3,957 | ||||||||||||||||||
Prepaid expenses and other current
assets |
8 | 7 | 388 | 473 | | 876 | ||||||||||||||||||
Assets of discontinued operations
held for sale |
| | 591 | 273 | | 864 | ||||||||||||||||||
Total Current Assets |
8 | 571 | 25,891 | 16,297 | (31,575 | ) | 11,192 | |||||||||||||||||
Investments and long-term receivables |
40,882 | 37,429 | 37,656 | 17,167 | (125,876 | ) | 7,258 | |||||||||||||||||
Net properties, plants and equipment |
| | 16,495 | 30,933 | | 47,428 | ||||||||||||||||||
Goodwill |
| | 15,046 | 38 | | 15,084 | ||||||||||||||||||
Intangibles |
| | 743 | 342 | | 1,085 | ||||||||||||||||||
Other assets |
20 | | 92 | 296 | | 408 | ||||||||||||||||||
Total Assets |
$ | 40,910 | 38,000 | 95,923 | 65,073 | (157,451 | ) | 82,455 | ||||||||||||||||
Liabilities and Stockholders Equity |
||||||||||||||||||||||||
Accounts payable |
$ | 10,096 | 2 | 19,262 | 9,114 | (31,575 | ) | 6,899 | ||||||||||||||||
Notes payable and long-term debt due
within one year |
| 1,350 | 70 | 20 | | 1,440 | ||||||||||||||||||
Accrued income and other taxes |
| 96 | 663 | 1,917 | | 2,676 | ||||||||||||||||||
Other accruals |
20 | 45 | 1,231 | 1,521 | | 2,817 | ||||||||||||||||||
Liabilities of discontinued
operations held for sale |
| | 179 | | | 179 | ||||||||||||||||||
Total Current Liabilities |
10,116 | 1,493 | 21,405 | 12,572 | (31,575 | ) | 14,011 | |||||||||||||||||
Long-term debt |
2,704 | 2,938 | 6,394 | 4,304 | | 16,340 | ||||||||||||||||||
Asset retirement obligations and
accrued environmental costs |
| | 930 | 2,673 | | 3,603 | ||||||||||||||||||
Deferred income taxes |
| (33 | ) | 2,575 | 6,031 | (8 | ) | 8,565 | ||||||||||||||||
Employee benefit obligations |
| | 1,828 | 617 | | 2,445 | ||||||||||||||||||
Other liabilities and deferred
credits |
| 5,961 | 36,462 | 21,460 | (61,600 | ) | 2,283 | |||||||||||||||||
Total Liabilities |
12,820 | 10,359 | 69,594 | 47,657 | (93,183 | ) | 47,247 | |||||||||||||||||
Minority interests |
| (12 | ) | 5 | 849 | | 842 | |||||||||||||||||
Retained earnings |
2,695 | 1,470 | 9,485 | 10,548 | (14,964 | ) | 9,234 | |||||||||||||||||
Other stockholders equity |
25,395 | 26,183 | 16,839 | 6,019 | (49,304 | ) | 25,132 | |||||||||||||||||
Total |
$ | 40,910 | 38,000 | 95,923 | 65,073 | (157,451 | ) | 82,455 | ||||||||||||||||
25
Millions of Dollars |
||||||||||||||||||||||||
Three Months Ended March 31, 2004 |
||||||||||||||||||||||||
ConocoPhillips | ConocoPhillips | All Other | Consolidating | Total | ||||||||||||||||||||
Statement of Cash Flows | ConocoPhillips |
Holding Company |
Company |
Subsidiaries |
Adjustments |
Consolidated |
||||||||||||||||||
Cash Flows From Operating Activities |
||||||||||||||||||||||||
Net cash provided by (used in)
continuing operations |
$ | (119 | ) | (105 | ) | 1,089 | 1,781 | (581 | ) | 2,065 | ||||||||||||||
Net cash provided by (used in)
discontinued operations |
| | (35 | ) | 43 | | 8 | |||||||||||||||||
Net Cash Provided by (Used in)
Operating Activities |
(119 | ) | (105 | ) | 1,054 | 1,824 | (581 | ) | 2,073 | |||||||||||||||
Cash Flows From Investing Activities |
||||||||||||||||||||||||
Cash consolidated from adoption of
FIN 46 |
| | | | | | ||||||||||||||||||
Capital expenditures and
investments, including dry holes |
| | (284 | ) | (1,240 | ) | 43 | (1,481 | ) | |||||||||||||||
Proceeds from asset dispositions |
| | 158 | 311 | (20 | ) | 449 | |||||||||||||||||
Long-term advances to affiliates
and other investments |
1,010 | 87 | 719 | 650 | (2,510 | ) | (44 | ) | ||||||||||||||||
Net cash used in continuing
operations |
1,010 | 87 | 593 | (279 | ) | (2,487 | ) | (1,076 | ) | |||||||||||||||
Net cash provided by (used in)
discontinued operations |
| | (1 | ) | | | (1 | ) | ||||||||||||||||
Net Cash Used in Investing
Activities |
1,010 | 87 | 592 | (279 | ) | (2,487 | ) | (1,077 | ) | |||||||||||||||
Cash Flows From Financing Activities |
||||||||||||||||||||||||
Issuance of debt |
| 18 | | | (18 | ) | | |||||||||||||||||
Repayment of debt |
(709 | ) | | (1,755 | ) | (786 | ) | 2,528 | (722 | ) | ||||||||||||||
Issuance of company common stock |
112 | | | | | 112 | ||||||||||||||||||
Dividends paid on common stock |
(294 | ) | | | (601 | ) | 601 | (294 | ) | |||||||||||||||
Other |
| | | 132 | (43 | ) | 89 | |||||||||||||||||
Net Cash Provided by (Used in)
Financing Activities |
(891 | ) | 18 | (1,755 | ) | (1,255 | ) | 3,068 | (815 | ) | ||||||||||||||
Effect of Exchange Rate Changes on
Cash and Cash Equivalents |
| | | (12 | ) | | (12 | ) | ||||||||||||||||
Net Change in Cash and Cash
Equivalents |
| | (109 | ) | 278 | | 169 | |||||||||||||||||
Cash and cash equivalents at
beginning
of year |
| | 268 | 222 | | 490 | ||||||||||||||||||
Cash and Cash Equivalents at End of
Period |
$ | | | 159 | 500 | | 659 | |||||||||||||||||
26
Millions of Dollars |
||||||||||||||||||||||||
Three Months Ended March 31, 2003 |
||||||||||||||||||||||||
ConocoPhillips | ConocoPhillips | All Other | Consolidating | Total | ||||||||||||||||||||
Statement of Cash Flows | ConocoPhillips |
Holding Company |
Company |
Subsidiaries |
Adjustments |
Consolidated |
||||||||||||||||||
Cash Flows From Operating
Activities |
||||||||||||||||||||||||
Net cash provided by (used in)
continuing operations |
$ | 812 | 776 | 1,469 | 3,241 | (3,178 | ) | 3,120 | ||||||||||||||||
Net cash provided by (used in)
discontinued operations |
| | (21 | ) | 21 | | | |||||||||||||||||
Cash Provided by (Used in)
Operating Activities |
812 | 776 | 1,448 | 3,262 | (3,178 | ) | 3,120 | |||||||||||||||||
Cash Flows From Investing
Activities |
||||||||||||||||||||||||
Acquisitions, net of cash acquired |
| | | 225 | | 225 | ||||||||||||||||||
Capital expenditures and
investments, including dry holes |
| (8 | ) | (840 | ) | (969 | ) | 538 | (1,279 | ) | ||||||||||||||
Proceeds from asset dispositions |
| | (158 | ) | 204 | | 46 | |||||||||||||||||
Long-term advances to affiliates
and other investments |
450 | | (5,158 | ) | (1,530 | ) | 6,261 | 23 | ||||||||||||||||
Net cash provided by (used in)
continuing operations |
450 | (8 | ) | (6,156 | ) | (2,070 | ) | 6,799 | (985 | ) | ||||||||||||||
Net cash used in discontinued
operations |
| | (23 | ) | (4 | ) | | (27 | ) | |||||||||||||||
Net Cash Provided by (Used in)
Investing Activities |
450 | (8 | ) | (6,179 | ) | (2,074 | ) | 6,799 | (1,012 | ) | ||||||||||||||
Cash Flows From Financing
Activities |
||||||||||||||||||||||||
Issuance of debt |
| 21 | 6,097 | 413 | (6,261 | ) | 270 | |||||||||||||||||
Repayment of debt |
(1,009 | ) | | (369 | ) | (460 | ) | | (1,838 | ) | ||||||||||||||
Issuance of company common stock |
18 | | | | | 18 | ||||||||||||||||||
Dividends paid on common stock |
(271 | ) | (789 | ) | (789 | ) | (1,591 | ) | 3,169 | (271 | ) | |||||||||||||
Other |
| | (130 | ) | 651 | (529 | ) | (8 | ) | |||||||||||||||
Net Cash Provided by (Used in)
Financing Activities |
(1,262 | ) | (768 | ) | 4,809 | (987 | ) | (3,621 | ) | (1,829 | ) | |||||||||||||
Effect of Exchange Rate Changes
on Cash and Cash Equivalents |
| | 28 | 29 | | 57 | ||||||||||||||||||
Net Change in Cash and Cash
Equivalents |
| | 106 | 230 | | 336 | ||||||||||||||||||
Cash and cash equivalents at
beginning
Of year |
| | 116 | 191 | | 307 | ||||||||||||||||||
Cash and Cash Equivalents at End
of
Period |
$ | | | 222 | 421 | | 643 | |||||||||||||||||
27
Item 2. MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
Managements 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. We do 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 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 48.
RESULTS OF OPERATIONS
Unless otherwise indicated, discussion of results for the three-month period ending March 31, 2004, is based on a comparison with the corresponding period of 2003.
Business Environment and Executive Summary
By running our operations efficiently and continuing to control costs, we were able to benefit from favorable market conditions in the first quarter of 2004, which resulted in a strong financial performance. Net income in the first quarter of 2004 was $1,616 million, while cash from operations totaled $2,073 million. This, combined with proceeds from asset dispositions of $449 million, allowed us to fund our capital expenditure program of $1,481 million, pay common stock dividends of $294 million, and reduce our debt by $671 million.
Our Exploration and Production segment had net income of $1,257 million in the first quarter of 2004, compared with $991 million in the fourth quarter of 2003 and $1,267 million in the first quarter of 2003. Crude oil prices increased moderately during the first quarter of 2004, to an average of about $35 per barrel for the West Texas Intermediate grade. The increase during the quarter, compared with the fourth quarter of 2003, was primarily due to rising global consumption associated with the economic recovery, geopolitical risk of oil supply disruptions, and OPEC discipline in constraining the buildup of crude oil inventories. U.S. natural gas prices also rose moderately during the first quarter of 2004, compared with the fourth quarter of 2003, averaging $5.69 per thousand cubic feet for Henry Hub. Despite adequate natural gas inventory levels, natural gas prices increased during the quarter primarily due to concerns over supply availability and high crude oil prices limiting consumers ability to switch fuel away from natural gas.
Our Refining and Marketing segment had net income of $464 million in the first quarter of 2004, compared with $202 million in the fourth quarter of 2003 and $264 million in the first quarter of 2003. U.S. refining margins increased significantly in the first quarter of 2004, compared with the fourth quarter of 2003, due to strong gasoline demand, relatively low gasoline inventories and concern about supply availability due to more stringent gasoline specifications, including the implementation of MTBE (methyl tertiary-butyl ether) bans in several northeastern states. U.S. marketing margins in the first quarter of 2004 were lower than the fourth quarter of 2003 as wholesale and retail prices lagged sharp product cost increases.
28
Consolidated Results
Millions of Dollars |
||||||||
Three Months Ended | ||||||||
March 31 |
||||||||
2004 | 2003 | |||||||
Income from continuing operations |
$ | 1,603 | 1,263 | |||||
Income from discontinued operations |
13 | 53 | ||||||
Cumulative effect of accounting changes |
| (95 | ) | |||||
Net income |
$ | 1,616 | 1,221 | |||||
A summary of net income (loss) by business segment follows:
Millions of Dollars |
||||||||
Three Months Ended | ||||||||
March 31 |
||||||||
2004 | 2003 | |||||||
Exploration and Production
(E&P) |
$ | 1,257 | 1,267 | |||||
Midstream |
55 | 31 | ||||||
Refining and Marketing (R&M) |
464 | 264 | ||||||
Chemicals |
39 | (23 | ) | |||||
Emerging Businesses |
(22 | ) | (34 | ) | ||||
Corporate and Other |
(177 | ) | (284 | ) | ||||
Net income |
$ | 1,616 | 1,221 | |||||
Net income was $1,616 million in the first quarter of 2004, compared with $1,221 million in the first quarter of 2003. The improved results in the 2004 quarter were primarily due to:
| Higher U.S. refining margins in our R&M segment; | |||
| A $95 million charge in the first quarter of 2003 for the cumulative effect of accounting changes; and | |||
| Improved results from the Chemicals segment. |
See the Segment Results section for additional information on our reporting segments.
Income Statement Analysis
Sales and other operating revenues, along with purchase costs, increased 11 percent in the first quarter of 2004. These increases reflected:
| Increased volumes of natural gas bought and sold by our commercial organization in their role of optimizing the commodity flows of our E&P and R&M segments; | |||
| Higher excise, value added and other similar taxes; | |||
| Higher prices for crude oil; and | |||
| Higher petroleum product prices. |
29
Equity in earnings of affiliates increased from $49 million in the first quarter of 2003, to $269 million in the first quarter of 2004. The improvement reflects that our Venezuelan heavy-oil operations were shut down during most of the first quarter of 2003 due to civil unrest, as well as improved results from the Duke Energy Field Services, LLC, and Chevron Phillips Chemical Company LLC joint ventures.
Other income increased 87 percent in the first quarter of 2004, mainly due to higher net gains on asset sales. In addition the first quarter of 2003 included losses incurred on early debt retirements. Asset dispositions in the first quarter of 2004 included our interest in the Petrovera heavy-oil joint venture in Canada.
Exploration expenses increased 23 percent in the first quarter of 2004, mainly reflecting higher dry hole charges. We primarily recorded dry hole charges related to exploratory activity in the Gulf of Mexico, Venezuela, Canada and Vietnam in the first quarter of 2004.
Taxes other than income taxes increased 20 percent in the first quarter of 2004, mainly due to higher value added taxes resulting from increased sales volumes for European petroleum products and the impact of foreign currency translation.
Interest and debt expense declined 39 percent in the first quarter of 2004, primarily due to lower average debt levels during the 2004 quarter and an increased amount of interest being capitalized.
Our effective tax rate for the first quarter of 2004 was 46 percent, compared with 51 percent for the same period a year ago. Contributing to the lower tax rate in the first quarter of 2004, compared with the corresponding period in 2003, was the impact of a lower portion of income being earned in higher-tax-rate jurisdictions.
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. Also effective January 1, 2003, we adopted FIN 46 for variable interest entities involving synthetic leases and certain other financing structures created prior to February 1, 2003. This resulted in a charge of $240 million for the cumulative effect of this accounting change. Together, we recognized a net $95 million charge in the first quarter of 2003 for the cumulative effect of the two accounting changes.
Restructuring Accruals
The information in Note 7Restructuring, in the Notes to Consolidated Financial Statements, is incorporated herein by reference.
30
Segment Results
E&P
Three Months Ended | ||||||||
March 31 |
||||||||
2004 | 2003 | |||||||
Millions of Dollars |
||||||||
Net Income |
||||||||
Alaska |
$ | 403 | 508 | |||||
Lower 48 |
232 | 312 | ||||||
United States |
635 | 820 | ||||||
International |
622 | 447 | ||||||
$ | 1,257 | 1,267 | ||||||
Dollars Per Unit |
||||||||
Average Sales Prices |
||||||||
Crude oil (per barrel) |
||||||||
United States |
$ | 32.78 | 31.47 | |||||
International |
31.48 | 31.10 | ||||||
Total consolidated |
32.08 | 31.27 | ||||||
Equity affiliates |
18.68 | 20.97 | ||||||
Worldwide |
30.35 | 30.73 | ||||||
Natural
gaslease (per thousand cubic feet) |
||||||||
United States |
4.79 | 5.34 | ||||||
International |
4.28 | 3.92 | ||||||
Total consolidated |
4.48 | 4.49 | ||||||
Equity affiliates |
3.91 | 4.82 | ||||||
Worldwide |
4.48 | 4.49 | ||||||
Millions of Dollars |
||||||||
Worldwide Exploration Expenses |
||||||||
General administrative; geological and geophysical; and
lease rentals |
$ | 56 | 76 | |||||
Leasehold impairment |
20 | 20 | ||||||
Dry holes |
67 | 20 | ||||||
$ | 143 | 116 | ||||||
31
Three Months Ended | ||||||||
March 31 |
||||||||
2004 | 2003 | |||||||
Thousands of Barrels Daily |
||||||||
Operating Statistics |
||||||||
Crude oil produced |
||||||||
Alaska |
320 | 337 | ||||||
Lower 48 |
53 | 60 | ||||||
United States |
373 | 397 | ||||||
European North Sea |
282 | 313 | ||||||
Asia Pacific |
83 | 63 | ||||||
Canada |
27 | 33 | ||||||
Other areas |
63 | 74 | ||||||
Total consolidated |
828 | 880 | ||||||
Equity affiliates |
113 | 55 | ||||||
941 | 935 | |||||||
Natural gas liquids produced |
||||||||
Alaska |
26 | 26 | ||||||
Lower 48 |
24 | 22 | ||||||
United States |
50 | 48 | ||||||
European North Sea |
14 | 10 | ||||||
Canada |
10 | 11 | ||||||
Other areas |
2 | 2 | ||||||
76 | 71 | |||||||
Millions of Cubic Feet Daily |
||||||||
Natural gas produced* |
||||||||
Alaska |
185 | 189 | ||||||
Lower 48 |
1,233 | 1,338 | ||||||
United States |
1,418 | 1,527 | ||||||
European North Sea |
1,198 | 1,307 | ||||||
Asia Pacific |
305 | 285 | ||||||
Canada |
428 | 436 | ||||||
Other areas |
66 | 50 | ||||||
Total consolidated |
3,415 | 3,605 | ||||||
Equity affiliates |
9 | 12 | ||||||
3,424 | 3,617 | |||||||
Thousands of Barrels Daily |
||||||||
Mining operations |
||||||||
Syncrude produced |
23 | 17 | ||||||
32
The E&P segment explores for and produces crude oil, natural gas, and natural gas liquids on a worldwide basis. It also mines deposits of oil sands in Canada to extract the bitumen and upgrade it into a synthetic crude oil. At March 31, 2004, our E&P operations were producing in the United States, Norway, the United Kingdom, Canada, Nigeria, Venezuela, offshore Timor Leste in the Timor Sea, Australia, China, Indonesia, the United Arab Emirates, Vietnam, and Russia.
Net income from the E&P segment decreased slightly in the first quarter of 2004. Positive variances in prices and net gains from asset sales in the first quarter of 2004 were more than offset by a net benefit of $142 million in the first quarter of 2003 for the cumulative effect of accounting changes.
U.S. E&P
Net income from our U.S. E&P operations declined 23 percent in the first quarter of 2004. The majority of this decline was due to the fact that the first quarter of 2003 included a net benefit of $142 million for the cumulative effect of accounting changes. The remainder of the decrease in 2004 was primarily attributable to lower natural gas prices, lower production volumes, and higher dry hole charges, partially offset by higher crude oil prices.
U.S. E&P production on a barrel-of-oil-equivalent (BOE) basis averaged 659,000 barrels per day in the first quarter of 2004, down 6 percent from 700,000 BOE per day in the first quarter of 2003. The decreased production primarily was the result of field production declines and asset dispositions.
International E&P
Net income from our international E&P operations increased 39 percent in the first quarter of 2004. The increase was primarily due to:
| Improved equity earnings. Our Venezuelan heavy-oil joint ventures operated throughout the first quarter of 2004, but were shutdown during most of the first quarter of 2003 due to civil unrest; | |||
| Higher net gains on asset sales. In the first quarter of 2004, we sold our interest in the Petrovera heavy-oil joint venture in Canada; and | |||
| Higher natural gas prices. Primarily for natural gas sales from production originating in the North Sea. |
International E&P production on a barrel-of-oil-equivalent (BOE) basis averaged 929,000 barrels per day in the first quarter of 2004, an increase of 2 percent from 909,000 BOE per day in the first quarter of 2003. The increase in production was primarily the result of the previously mentioned shut down of our Veneuzelan joint ventures during part of the first quarter of 2003, and, to a lesser extent, the startup of production from the Su Tu Den field in Vietnam in late 2003 and the ramp up of the Peng Lai 19-3 Phase I project in Chinas Bohai Bay. These items were partially offset by field production declines and asset dispositions.
33
Midstream
Three Months Ended | ||||||||
March 31 |
||||||||
2004 | 2003 | |||||||
Millions of Dollars |
||||||||
Net income* |
$ | 55 | 31 | |||||
*Includes DEFS-related net income: |
$ | 33 | 13 |
Dollars Per Barrel |
||||||||
Average Sales Prices |
||||||||
U.S. natural gas liquids* |
||||||||
Consolidated |
$ | 25.68 | 25.59 | |||||
Equity |
24.81 | 24.53 | ||||||
Thousands of Barrels Daily |
||||||||
Operating Statistics |
||||||||
Natural gas liquids extracted** |
221 | 222 | ||||||
Natural gas
liquids fractionatedUnited States |
158 | 168 | ||||||
The Midstream segment purchases raw natural gas from producers and gathers natural gas through extensive pipeline gathering systems. The natural gas is then processed to extract natural gas liquids from the raw gas stream. The remaining residue gas is marketed to electrical utilities, industrial users, and gas marketing companies. Most of the natural gas liquids are fractionatedseparated into individual components like ethane, butane and propaneand marketed as chemical feedstock, fuel, or blendstock.
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, primarily in the United States, Canada and Trinidad.
Net income from the Midstream segment increased 77 percent in the first quarter of 2004. The improvement was primarily attributable to improved results from DEFS. DEFS results increased mainly due to:
| Higher gross margins, reflecting higher natural gas liquids prices and lower natural gas prices; | |||
| Lower costs and expenses, primarily due to decreased facility maintenance and pipeline repair costs; and | |||
| A $23 million (gross) charge in the first quarter of 2003 for the cumulative effect of changes in accounting principles, mainly related to the adoption of SFAS No. 143, Accounting for Asset Retirement Obligations. |
Outside of DEFS, we recorded property impairments of $20 million before-tax, $12 million after-tax, related to planned asset dispositions in Texas and Louisiana.
Included in the Midstream segments net income was a benefit of $9 million in the first quarter of 2004, the same as the first quarter of 2003, 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.
34
R&M
Three Months Ended | ||||||||
March 31 |
||||||||
2004 | 2003 | |||||||
Millions of Dollars |
||||||||
Net Income |
||||||||
United States |
$ | 403 | 150 | |||||
International |
61 | 114 | ||||||
$ | 464 | 264 | ||||||
Dollars Per Gallon |
||||||||
U.S. Average Sales Prices* |
||||||||
Automotive gasoline |
||||||||
Wholesale |
$ | 1.16 | 1.10 | |||||
Retail |
1.32 | 1.37 | ||||||
Distillates |
1.02 | 1.05 | ||||||
Thousands of Barrels Daily |
||||||||
Operating Statistics |
||||||||
Refining operations* |
||||||||
United States |
||||||||
Rated crude oil capacity |
2,168 | 2,167 | ||||||
Crude oil runs |
2,105 | 2,008 | ||||||
Capacity utilization (percent) |
97 | % | 93 | |||||
Refinery production |
2,255 | 2,254 | ||||||
International |
||||||||
Rated crude oil capacity |
447 | 442 | ||||||
Crude oil runs |
374 | 396 | ||||||
Capacity utilization (percent) |
84 | % | 90 | |||||
Refinery production |
410 | 436 | ||||||
Worldwide |
||||||||
Rated crude oil capacity |
2,615 | 2,609 | ||||||
Crude oil runs |
2,479 | 2,404 | ||||||
Capacity utilization (percent) |
95 | % | 92 | |||||
Refinery production |
2,665 | 2,690 | ||||||
Petroleum products outside sales |
||||||||
United States |
||||||||
Automotive gasoline |
1,315 | 1,331 | ||||||
Distillates |
570 | 600 | ||||||
Aviation fuels |
178 | 164 | ||||||
Other products |
517 | 509 | ||||||
2,580 | 2,604 | |||||||
International |
501 | 428 | ||||||
3,081 | 3,032 | |||||||
35
The R&M segments operations encompass refining crude oil and other feedstocks into petroleum products (such as gasoline, distillates and aviation fuels), buying and selling crude oil and petroleum products, and transporting, distributing and marketing petroleum products. R&M has operations in the United States, Europe and Asia Pacific.
Net income from the R&M segment increased 76 percent in the first quarter of 2004. Of the $200 million improvement, $125 million was attributable to a first quarter 2003 net charge for the cumulative effect of accounting changes. The remaining $75 million improvement was primarily due to higher U.S. refining margins, partially offset by lower worldwide marketing margins and lower international refining margins.
U.S. R&M
Net income from our U.S. R&M operations increased significantly in the first quarter of 2004. About half of the improvement was due to the fact that the first quarter of 2003 included a net charge of $125 million for the cumulative effect of accounting changes. The remaining improvement was primarily due to higher refining margins, partially offset by lower wholesale and retail marketing margins.
Our U.S. crude oil capacity utilization rate was 97 percent in the first quarter of 2004, compared with 93 percent in the first quarter of 2003. The first quarter 2003 utilization rate was affected by scheduled maintenance turnarounds at our Sweeny, Wood River and Ferndale refineries. The first quarter 2004 utilization rate reflects maintenance turnaround activity at the Los Angeles, Trainer, Wood River and Alliance refineries. The turnarounds in the first quarter of 2004 generally did not involve the refineries crude processing units to the extent they did in the first quarter of 2003.
International R&M
Net income from our international R&M operations decreased 46 percent in the first quarter of 2004. The decrease is mainly attributable to lower refining and marketing margins.
Our international crude oil capacity utilization rate was 84 percent in the first quarter of 2004, compared with 90 percent in the first quarter of 2003. The decrease was due to a turnaround in March 2004 at the MiRO refinery in Karlsruhe, Germany, along with small throughput decreases in our other five international refineries.
Chemicals
Millions of Dollars |
||||||||
Three Months Ended | ||||||||
March 31 |
||||||||
2004 | 2003 | |||||||
Net income (loss) |
$ | 39 | (23 | ) | ||||
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. CPChem uses natural gas liquids and other feedstocks to produce petrochemicals such as ethylene, propylene, styrene, benzene, and paraxylene. These products are then marketed and sold, or used as feedstocks to produce plastics and commodity chemicals, such as polyethylene, polystyrene and cyclohexane.
36
The Chemicals segment had net income of $39 million in the first quarter of 2004, compared with a net loss of $23 million in the corresponding quarter of 2003. The improved results in the 2004 quarter were primarily due to higher margins in the olefins and polyolefins business line, particularly ethylene margins, and, to a lesser extent, polyethylene margins. CPChem also benefited from improved equity earnings from Q-Chem Chemical Company Ltd. (an olefins and polyolefins complex in Qatar) and Saudi Chevron Phillips Company (an aromatics complex in Saudi Arabia), and also lower utility costs resulting from a decrease in U.S. natural gas prices.
Emerging Businesses
Millions of Dollars |
||||||||
Three Months Ended | ||||||||
March 31 |
||||||||
2004 | 2003 | |||||||
Net Income (Loss) |
||||||||
Technology solutions |
$ | (4 | ) | (5 | ) | |||
Gas-to-liquids |
(9 | ) | (20 | ) | ||||
Power |
(4 | ) | 1 | |||||
Other |
(5 | ) | (10 | ) | ||||
$ | (22 | ) | (34 | ) | ||||
The Emerging Businesses segment includes the development of new businesses outside our traditional operations. Emerging Businesses incurred a net loss of $22 million in the first quarter of 2004, compared with a net loss of $34 million in the first quarter of 2003. The lower net loss in the first quarter of 2004 reflects:
| Higher research and development costs incurred in the first quarter of 2003 related to a demonstration gas-to-liquids plant under construction. Construction was substantially completed in the second quarter of 2003; and | |||
| Costs incurred in the first quarter of 2003 related to carbon fibers. We terminated our carbon fibers project in 2003. |
Corporate and Other
Millions of Dollars |
||||||||
Three Months Ended | ||||||||
March 31 |
||||||||
2004 | 2003 | |||||||
Net Income (Loss) |
||||||||
Net interest |
$ | (104 | ) | (190 | ) | |||
Corporate general and administrative
expenses |
(55 | ) | (30 | ) | ||||
Discontinued operations |
13 | 53 | ||||||
Merger-related costs |
(14 | ) | (27 | ) | ||||
Cumulative effect of accounting change |
| (112 | ) | |||||
Other |
(17 | ) | 22 | |||||
$ | (177 | ) | (284 | ) | ||||
37
After-tax net interest consists of interest and financing expense, net of interest income and capitalized interest, as well as premiums incurred on the early retirement of debt. Net interest decreased 45 percent in the first quarter of 2004, mainly due to lower average debt levels and increased amounts of interest being capitalized.
After-tax corporate general and administrative expenses increased $25 million in the first quarter of 2004, reflecting increased compensation costs, as well as increases in various other staff costs. The increase in compensation costs included higher stock-based compensation, which reflected both an increase in the number of units issued and our higher stock price in the first quarter of 2004, compared with the first quarter of 2003.
Income from discontinued operations decreased 75 percent in the first quarter of 2004, primarily reflecting the disposition of The Circle K Corporation and its subsidiaries in the fourth quarter of 2003; the Commerce City, Colorado, refinery in the third quarter of 2003; and the Woods Cross, Utah, refinery and related marketing assets in the second quarter of 2003.
After-tax merger-related costs were $14 million in the first quarter of 2004, compared with $27 million in the corresponding period of 2003. The charges in 2004 represented adjustments to severance accruals. Merger-related costs will no longer be separately identified and reported beginning with the second quarter of 2004.
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, and environmental costs associated with sites no longer in operation. Results from Other were lower in the first quarter of 2004, primarily because the first quarter of 2003 included an after-tax gain of $34 million related to insurance demutualization benefits.
38
CAPITAL RESOURCES AND LIQUIDITY
Financial Indicators
Millions of Dollars |
||||||||
At March 31 | At December 31 | |||||||
2004 | 2003 | |||||||
Current ratio |
.9 | .8 | ||||||
Total debt repayment obligations due within one
year |
$ | 1,441 | 1,440 | |||||
Total debt |
$ | 17,109 | 17,780 | |||||
Minority interests |
$ | 946 | 842 | |||||
Common stockholders equity |
$ | 35,820 | 34,366 | |||||
Percent of total debt to capital* |
32 | % | 34 | |||||
Percent of floating-rate debt to total debt |
14 | % | 17 | |||||
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. As we have previously disclosed, we also anticipate raising approximately $1 billion in funds during 2004 from the sale of assets. During the first quarter of 2004, available cash was used to support our ongoing capital expenditure program, reduce debt and pay dividends. Total dividends paid on common stock during the first quarter of 2004 were $294 million. During the first three months of 2004, cash and cash equivalents increased $169 million to $659 million.
Our cash flows from operating activities are highly dependent upon prices for crude oil, natural gas and natural gas liquids, as well as refining and marketing margins. These prices and margins are driven by market conditions over which we have no control. In addition, the level of our production volumes of crude oil, natural gas and natural gas liquids also impacts our cash flows. These production levels are impacted by such factors as acquisitions and dispositions of fields, field production decline rates, new technologies, operating efficiency, the addition of proved reserves through exploratory success, and the timely and cost-effective development of those proved reserves. We will need to continue to add to our proved reserve base through exploration and development of new fields, or by acquisition, and to apply new technologies and processes to boost recovery from existing fields in order to maintain or increase production and proved reserves. We have been successful in the past in maintaining or adding to our production and proved reserve base and anticipate being able to do so in the future. Our barrel-of-oil-equivalent (BOE) production has increased in each of the past three years and we have replaced more than 100 percent of our BOE production in each of the past three years. After adjusting for asset dispositions, our production level for 2004 is expected to be about the same level as it was in 2003, and we expect our 2004 replacement of reserves to exceed our 2004 production. However, these anticipated results for 2004 are subject to risks, including reservoir performance, operational downtime, finding and development execution, obtaining approval of development projects in a timely manner, regulatory changes, geographical location, market prices and environmental issues, and therefore cannot be assured.
39
Significant Sources of Capital
Operating Activities
During the first quarter of 2004, cash of $2,073 million was provided by
operating activities, a decrease of $1,047 million from the same period in
2003. The difference in the changes in working capital between the two periods
was the primary reason for the reduction in cash provided by operating
activities, partly offset by higher income from continuing operations. Working
capital changes decreased cash flow $777 million in the first quarter of 2004,
and increased cash flows $636 million in the same period a year ago. This
difference in working capital changes was primarily due to a smaller increase
in taxes and other accruals relating to a shift in the timing of payments.
Contributing to the improvement in income from continuing operations was higher
refining margins as a result of a favorable market environment; a decline in
interest expense due to lower average debt levels and an increase in
capitalized interest; and a lower portion of income being earned in higher
tax-rate jurisdictions.
Asset Sales
Following the merger of Conoco and Phillips in August of 2002, we initiated an
asset disposition program. The initial target, to sell approximately $3 billion
to $4 billion of assets by the end of 2004, was raised at the end of 2003 to
approximately $4.5 billion by the end of 2004. During the first quarter of
2004, proceeds from asset sales were $449 million, bringing total proceeds to
$3.8 billion since the program began.
Commercial Paper and Credit Facilities
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 March 31, 2004, we had no
commercial paper outstanding, compared with $709 million of commercial paper
outstanding at December 31, 2003.
At March 31, 2004, we had a $1.5 billion 364-day revolving credit facility expiring on October 13, 2004, a $500 million facility expiring in October 2008, and two revolving credit facilities totaling $2 billion expiring in October 2006 that supported our $4 billion commercial paper program. There were no outstanding borrowings under any of these facilities at March 31, 2004. In addition, 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 March 31, 2004.
Minority Interests
At March 31, 2004, we had outstanding $946 million of equity held by minority
interest owners, including a net minority interest of $503 million in Ashford
Energy Capital S.A. and a $141 million net minority interest in Conoco
Corporate Holdings L.P. The remaining minority interest amounts relate to
controlled operating joint ventures with minority interest owners. The largest
amount, $290 million, relates to the Bayu-Undan liquefied natural gas project
in the Timor Sea.
Receivables Factoring
At December 31, 2003, we had sold $226 million of receivables under a factoring
arrangement. We retained servicing responsibility for these sold receivables,
which gives us certain benefits, the fair value of which approximates the fair
value of the liability incurred for continuing to service the receivables. At
March 31, 2004, we had no receivables outstanding under similar arrangements.
40
Off-Balance Sheet Arrangements
Receivables Monetization
At March 31, 2004, certain credit card and trade receivables had been sold to a
Qualifying Special Purpose Entity (QSPE) in a revolving-period securitization
arrangement. This arrangement provides for us to sell, and the QSPE to
purchase, certain receivables, and for the QSPE to then issue beneficial
interests of up to $1.2 billion to five bank-sponsored entities. All five
bank-sponsored entities are multi-seller conduits with access to the commercial
paper market and purchase interests in similar receivables from numerous other
companies unrelated to us. We have no ownership interests, nor any variable
interests, in any of the bank-sponsored entities. As a result, we do not
consolidate any of these entities. Furthermore, we do not consolidate the QSPE
because it meets the requirements of SFAS No. 140, Accounting for Transfers
and Servicing of Financial Assets and Extinguishments of Liabilities, to be
excluded from the consolidated financial statements of ConocoPhillips.
At March 31, 2004, and December 31, 2003, the QSPE had issued beneficial interests to the bank-sponsored entities of $450 million and $1.2 billion, respectively. The receivables transferred to the QSPE meet the isolation requirements and other requirements of SFAS No. 140 to be accounted for as sales and were accounted for accordingly.
We retain beneficial interests in the QSPE that are subordinate to the beneficial interests issued to the bank-sponsored entities. These retained interests, which are reported on the balance sheet in accounts and notes receivablerelated parties, were $2.3 billion at March 31, 2004, and $1.3 billion at December 31, 2003. We also retain servicing responsibility related to the sold receivables, which gives us certain rights and abilities, the fair value of which approximates the fair value of the liability incurred for continuing to service the receivables. The carrying value of our subordinated beneficial interests in the QSPE approximates fair market value due to the very short term of the underlying assets. See Note 13Sales of Receivables, in the Notes to Consolidated Financial Statements, for additional information.
Capital Requirements
For information about our capital expenditures and investments, see Capital Spending below.
Our balance sheet debt at March 31, 2004, was $17.1 billion. This reflects debt reductions of $671 million during the first quarter, primarily resulting from a reduction in our commercial paper.
In April 2004, we paid off the $1,350 million aggregate principal amount of our 5.90% Notes due 2004 at maturity by using the proceeds from issuing commercial paper.
41
Capital Spending
Capital Expenditures and Investments
Millions of Dollars |
||||||||
Three Months Ended | ||||||||
March 31 |
||||||||
2004 | 2003 | |||||||
E&P |
||||||||
United
StatesAlaska |
$ | 159 | 140 | |||||
United
StatesLower 48 |
147 | 186 | ||||||
International |
904 | 686 | ||||||
1,210 | 1,012 | |||||||
Midstream |
3 | 2 | ||||||
R&M |
||||||||
United States |
161 | 150 | ||||||
International |
54 | 53 | ||||||
215 | 203 | |||||||
Chemicals |
| | ||||||
Emerging Businesses |
28 | 66 | ||||||
Corporate and Other* |
25 | 25 | ||||||
$ | 1,481 | 1,308 | ||||||
United States |
$ | 494 | 512 | |||||
International |
987 | 796 | ||||||
$ | 1,481 | 1,308 | ||||||
Discontinued operations |
$ | 1 | 21 | |||||
E&P
In Alaska, we continued development drilling in the Greater Kuparuk Area, the Greater Prudhoe Area, the Alpine field and to develop heavy oil accumulations in the West Sak field. In addition, we are on track to increase oil production capacity at the Alpine field with Phase 1 expected to start up in the second half of 2004 and have recently announced plans for Phase 2, which is expected to be completed by mid-2005. The capacity expansion projects will increase water, oil and gas handling capacities, all of which are important for oil production and maintaining reservoir pressure.
We continued 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 to add a new Endeavour Class tanker to our fleet in both 2004 and 2005.
In the Lower 48, we continued with the development of the deepwater Magnolia field, where production is anticipated to start up in late 2004. We are the operator of the Magnolia project with a 75 percent interest. We continue to evaluate the results from the 2003 drilling program, as well as other factors affecting the profitability of this investment. Our estimate of total oil and gas to be produced is in excess of our booked reserves. In the first quarter, on behalf of the Garden Banks 783/784 unit, we filed an application for royalty relief with the Minerals Management Service (MMS). Royalty relief may be granted if the value of the project using the MMS economic model and criteria is insufficient to recover the project investment without the relief. There is no assurance that such relief will be granted. At March 31, 2004, our investment in Magnolia was approximately $700 million.
42
Company sanction of the K2 offshore development project in the Gulf of Mexico occurred in the first quarter of 2004. The K2 project involves tieback of subsea wells to an existing platform in a nearby block, with startup, targeted for late 2005.
We continued development of the Syncrude Stage III expansion-mining project in the Canadian province of Alberta, where an upgrader expansion project is expected to start up by mid-2006.
Also in Canada, development expenditures have started for the Surmont heavy-oil project. The initial development project is designed to use the Steam Assisted Gravity Drainage process, with first oil production expected in 2006.
At our Hamaca project in Venezuela, we continued activities required to produce, transport and upgrade 8.6-degree API extra-heavy crude into medium-grade crude oil. We anticipate completing the construction of the upgrader in the fourth quarter of 2004, at which time our net production from the Hamaca field is expected to increase to approximately 71,000 barrels per day.
In the U.K. and Norwegian sectors of the North Sea, we continued with several exploration and development projects, including the Ekofisk Area growth project, which consists of construction and installation of a new steel wellhead and processing platform and an increase in capacity from existing facilities; development of the U.K. Clair field, where production is expected in late 2004; and development of the U.K. CMS3 area, where drilling operations on the final reservoir, Boulton H, were completed in March.
In the North Caspian region, detailed design, procurement and construction activities continued on the Kashagan oil field development following approval by the Republic of Kazakhstan of the development plan and budget in February 2004. During 2003, we exercised our pre-emptive rights related to B.G. Internationals sale of their share in the North Caspian License that includes the Kashagan field. Upon approval of the pre-emptions, our ownership interest increases from 8.33 percent to 10.19 percent. In the South Caspian, operations continued on the Zafar-Mashal #1 exploration well in Azerbaijan waters. The well is expected to be completed in the third quarter of 2004. Construction of the Baku-Tbilisi-Ceyhan pipeline progressed during the first quarter, with completion expected by the end of 2004.
In Chinas Bohai Bay, we continued to evaluate development plans for Phase II of the Peng Lai 19-3 oil field. Phase II is expected to include multiple wellhead platforms, central processing facilities and a floating production, storage and offloading facility (FPSO). In conjunction with Phase II, we plan to develop the Peng Lai 25-6 oil field, located three miles east of Peng Lai 19-3. The Peng Lai 19-9 oil field, located two miles east of the Peng Lai 19-3, is expected to be a part of the Phase II development.
In the Timor Sea, commissioning of the Bayu-Undan gas recycle project is under way. First liquids production began in February 2004. Full capacity, 62,000 net barrels per day of condensate and gas liquids, is anticipated to be reached in the third quarter of 2004. An average rate of 23,000 net barrels per day of combined condensate and natural gas liquids is expected for 2004.
Also during the first quarter, we continued with the gas development project for Bayu-Undan, which includes a liquefied natural gas (LNG) plant near Darwin, Australia, as well as a gas pipeline from Bayu-Undan to the LNG facility. The first LNG cargo from the 3.52 million-ton-per-year facility is scheduled for delivery in early 2006. We own a 56.72 percent controlling interest in the integrated gas development project.
43
In Indonesia, we continued with the construction of the South Jambi gas project in the South Jambi B Block located in South Sumatra and the development of offshore Belanak and other fields in the Block B production sharing contract. First production from the South Jambi gas project is expected in the second quarter of 2004. At our Belanak project, the topside modules have been loaded onto the FPSO vessel, and commissioning of the topsides is currently under way. Commercial production from this project is targeted to commence in the first half of 2005.
R&M
In the United States, we continued to expend funds related to clean fuels, safety and environmental projects. We also are investing in a new diesel hydrotreater at the Rodeo facility of our San Francisco-area refinery that will produce reformulated California highway diesel an estimated one year ahead of the June 2006 deadline.
The integration of certain refining assets purchased adjacent to our Wood River refinery in Illinois continued during the quarter. The overall production at the refinery will only increase slightly, but integration of the assets will enable the refinery to process heavier, lower cost crude oil. Integration is expected to be completed in the second quarter of 2004.
Internationally, we continued to invest in our ongoing refining and marketing operations, including the replacement of a catalytic reformer at our Humber refinery in the United Kingdom and a diesel clean fuels project at our refinery in Ireland.
Emerging Businesses
We continued to spend funds in the first quarter to complete our Immingham combined steam and power cogeneration plant near our Humber refinery in the United Kingdom. We expect the plant to become operational in the third quarter of 2004.
Contingencies
Legal and Tax Matters
We accrue for contingencies when a loss is probable and amounts can be reasonably estimated. 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.
Environmental
We are subject to the same numerous international, federal, state, and local environmental laws and regulations, as other companies in the petroleum exploration and production industry; 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:
| Federal Clean Air Act, which governs air emissions; |
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| Federal Clean Water Act, which governs discharges to water bodies; | |||
| Federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), which imposes liability on generators, transporters, and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatened to occur; | |||
| Federal Resource Conservation and Recovery Act (RCRA), which governs the treatment, storage, and disposal of solid waste; | |||
| Federal Oil Pollution Act of 1990, under which owners and operators of onshore facilities and pipelines, lessees or permittees of an area in which an offshore facility is located, and owners and operators of vessels are liable for removal costs and damages that result from a discharge of oil into navigable waters of the United States; | |||
| Federal Emergency Planning and Community Right-to-Know Act, which requires facilities to report toxic chemical inventories with local emergency planning committees and responses departments; | |||
| Federal Safe Drinking Water Act, which governs the disposal of wastewater in underground injection wells; and | |||
| U.S. Department of the Interior regulations, which relate to offshore oil and gas operations in U.S. waters and impose liability for the cost of pollution cleanup resulting from operations, as well as potential liability for pollution damages. |
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 agencys 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, including those that may arise to address concerns about global climate change, are expected to continue to have an increasing impact on our operations in the United States and in other countries in which we operate. Notable areas of potential impacts include air emission compliance and remediation obligations in the United States.
For example, the U.S. Environmental Protection Agency (EPA) has 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. Because the non-road rule is not final, we are still evaluating and developing capital strategies for future compliance. 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
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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. Depending upon area designations and resulting State Implementation Plans, the revised NAAQS could result in substantial future environmental expenditures for us.
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 us. Over the next decade, we anticipate that significant ongoing expenditures for RCRA remediation activities may be required, but such annual 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.
From time to time, we 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, 2003, we reported we had been notified of potential liability under CERCLA and comparable state laws at 61 sites around the United States. At March 31, 2004, we had resolved two of these sites and had received no new notices of potential liability, leaving 59 unresolved 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
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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 those assumed in a purchase business combination, which we do record 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 March 31, 2004.
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.
At March 31, 2004, our balance sheet included a total environmental accrual of $1,117 million, compared with $1,119 million at December 31, 2003. We expect to incur a substantial 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.
NEW ACCOUNTING DEVELOPMENTS
In June 2001, the FASB issued SFAS No. 141, Business Combinations, and SFAS No. 142, Goodwill and Other Intangible Assets, which became effective on July 1, 2001, and January 1, 2002, respectively. The Securities and Exchange Commission (SEC) requested the Emerging Issues Task Force (EITF) to consider the issue of whether SFAS Nos. 141 and 142 require interests held under oil, gas and mineral leases to be separately classified as intangible assets on the balance sheets of companies in the extractive industries. Historically, in accordance with SFAS No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies, we have capitalized the cost of oil and gas leasehold interests and, consistent with industry practice, reported these assets as part of tangible Exploration and Production (E&P) properties, plants and equipment.
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At its March 2004 meeting, the EITF reached a consensus that all mineral rights should be considered tangible assets for accounting purposes. The EITF acknowledged that this consensus would require an amendment to SFAS Nos. 141 and 142 to remove mineral rights as an example of an intangible asset. In April 2004, the FASB issued FASB Staff Position Nos. FAS 141-1 and FAS 142-1, which amended SFAS Nos. 141 and 142 to remove mineral rights as an example of an intangible asset consistent with the EITFs consensus. See Note 6Properties, Plants and Equipment for more information.
OUTLOOK
In E&P, we expect our worldwide production for the second quarter of 2004 to be less than our first quarter level, primarily because of seasonality declines in Alaska and the United Kingdom, the impact of first quarter asset sales, planned maintenance downtime and normal field declines. These declines are expected to be partly offset by the expected ramp up of liquids production at Bayu-Undan.
In R&M, we expect our average refinery crude oil utilization rate for the second quarter of 2004 to be in the mid-90 percent range.
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. The devaluation of the Venezuelan currency by approximately 17 percent in February 2004 was not large enough to have a significant impact on our Venezuelan operations; however, future changes in the exchange rate could have a significant impact on our Venezuelan operations.
In March 2004, in conjunction with our co-venturer, we announced that we were suspending further work on a proposed liquefied natural gas (LNG) receiving terminal in Harpswell, Maine, following a vote by the residents of Harpswell not to lease a former U.S. Navy fuel site in the community for the purpose of building a LNG regasification facility. We continue to pursue regasification facility projects at other locations in the United States.
Late in the first quarter, the U.K. Department of Trade and Industry approved the development of the Brodgar and Callanish fields in the U.K. North Sea. Both fields are to be developed simultaneously as satellites of the already producing Britannia field. First production from these satellite fields is targeted for 2007.
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 our operations on our current expectations, estimates and projections about ourselves and the industries in which we operate 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
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on assumptions about future events that may prove to be inaccurate. Accordingly, our 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:
| Fluctuations in crude oil, natural gas and natural gas liquids prices, refining and marketing margins and margins for our chemicals business; | |||
| Changes in our business, operations, results and prospects; | |||
| The operation and financing of our midstream and chemicals joint ventures; | |||
| Potential failure to realize fully or within the expected time frame the expected cost savings and synergies from the combination of Conoco and Phillips; | |||
| Costs or difficulties related to the integration of the businesses of Conoco and Phillips, as well as the continued integration of businesses recently acquired by each of them; | |||
| Potential failure or delays in achieving expected reserve or production levels from existing and future oil and gas development projects due to operating hazards, drilling risks and the inherent uncertainties in predicting oil and gas reserves and oil and gas reservoir performance; | |||
| Unsuccessful exploratory drilling activities; | |||
| Failure of new products and services to achieve market acceptance; | |||
| Unexpected cost increases or technical difficulties in constructing or modifying facilities for exploration and production projects, manufacturing or refining; | |||
| Unexpected difficulties in manufacturing or refining our refined products, including synthetic crude oil and chemicals products; | |||
| Lack of, or disruptions in, adequate and reliable transportation for our crude oil, natural gas, natural gas liquids, LNG and refined products; | |||
| Inability to timely obtain or maintain permits, including those necessary for construction of LNG terminals or regasification facilities, comply with government regulations or make capital expenditures required to maintain compliance; | |||
| Failure to complete definitive agreements and feasibility studies for, and to timely complete construction of, announced and future LNG projects and related facilities; | |||
| Potential disruption or interruption of our facilities due to accidents, political events or terrorism; | |||
| International monetary conditions and exchange controls; | |||
| Liability for remedial actions, including removal and reclamation obligations, under environmental regulations; | |||
| Liability resulting from litigation; | |||
| General domestic and international economic and political conditions, including armed hostilities and governmental disputes over territorial boundaries; | |||
| Changes in tax and other laws or regulations applicable to our business; and | |||
| Inability to obtain economical financing for exploration and development projects, construction or modification of facilities and general corporate purposes. |
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Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Information about market risks for the three months ended March 31, 2004, does not differ materially from that discussed under Item 7A of ConocoPhillips Annual Report on Form 10-K for the year ended December 31, 2003.
Item 4. CONTROLS AND PROCEDURES
As of March 31, 2004, 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 March 31, 2004.
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
The following is a description of reportable legal proceedings including those involving governmental authorities under federal, state and local laws regulating the discharge of materials into the environment for this reporting period. The following proceedings include those matters that arose during the first quarter of 2004 and any material developments with respect to those matters previously reported in ConocoPhillips 2003 Form 10-K. While it is not possible to accurately predict the final outcome of these pending proceedings, if any one or more of such proceedings were decided adversely to ConocoPhillips, we expect there would be no material effect on our consolidated financial position. Nevertheless, such proceedings are reported pursuant to the United States Securities and Exchange Commissions regulations.
On March 2, 2004, the Bay Area Air Quality Management District (BAAQMD) notified us of their intent to seek civil penalties in the amount of $750,000 for 17 alleged violations of various BAAQMD regulations at our Rodeo facility and carbon plant located in the San Francisco area. We are currently assessing these allegations and expect to work with the BAAQMD towards a negotiated resolution of this matter.
On November 14, 2002, the Texas Commission on Environmental Quality issued a proposed agreed Findings Order to resolve alleged water discharge violations of the Texas Water Code and Commission Rules at the Sweeny refinery for the period beginning March 2000 through July 2002. In January 2004, we agreed to resolve this matter by paying a civil penalty to the State of Texas in the amount of $140,250.
On July 15, 2002, the United States filed a Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) cost recovery action against Conoco Inc. and seven other defendants alleging that the United States has incurred unreimbursed response costs at the Lowry Superfund Site located in Arapahoe County, Colorado. The United States seeks recovery of approximately $12.3 million in past response costs and a declaratory judgment for future CERCLA response cost liability. The defendants filed counterclaims seeking declaratory relief that certain response actions taken by the government were inconsistent with the National Contingency Plan. The defendants counterclaims, if successful, will reduce the total amount of response costs that are reimbursable to the government.
In June 1997, we experienced pipeline spills on our Seminoe pipeline at Banner, Wyoming, and Lodge Grass, Montana. In response to these spills, the United States Department of Justice advised us in August 2000 that the United States was contemplating a legal proceeding under the Clean Water Act against us. On February 9, 2004, we entered into a settlement agreement with the United States to resolve these matters. Under the terms of the settlement, we will pay the United States a civil penalty in the amount of $465,000.
Additionally, 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 Conocos 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.
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Item 6. EXHIBITS AND REPORTS ON FORM 8-K
Exhibits
12
|
Computation of Ratio of Earnings to Fixed Charges. | |
31.1
|
Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934. | |
31.2
|
Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934. | |
32
|
Certifications pursuant to 18 U.S.C. Section 1350. |
Reports on Form 8-K
During the three months ended March 31, 2004, ConocoPhillips furnished the following Current Reports on Form 8-K:
| Current Report furnished January 8, 2004, reporting Item 7 and Item 12. | |||
| Current Report furnished January 28, 2004, reporting Item 7 and Item 12. | |||
| Current Report furnished February 26, 2004, reporting Item 7 and Item 12. |
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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.
CONOCOPHILLIPS | ||
/s/ Rand C. Berney Rand C. Berney Vice President and Controller (Chief Accounting and Duly Authorized Officer) |
May 5, 2004
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EXHIBIT INDEX
EXHIBITS |
||
12
|
Computation of Ratio of Earnings to Fixed Charges. | |
31.1
|
Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934. | |
31.2
|
Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934. | |
32
|
Certifications pursuant to 18 U.S.C. Section 1350. |
Exhibit 12
CONOCOPHILLIPS AND CONSOLIDATED SUBSIDIARIES
TOTAL ENTERPRISE
Computation of Ratio of Earnings to Fixed Charges
Millions of Dollars |
||||||||
Three Months Ended | ||||||||
March 31 |
||||||||
2004 |
2003 |
|||||||
(Unaudited) | ||||||||
Earnings Available for Fixed Charges |
||||||||
Income from continuing operations before income taxes |
$ | 2,964 | 2,569 | |||||
Distributions less than equity in earnings of
fifty-percent-or-less-owned companies |
(153 | ) | (1 | ) | ||||
Fixed charges, excluding capitalized interest* |
188 | 284 | ||||||
$ | 2,999 | 2,852 | ||||||
Fixed Charges |
||||||||
Interest and expense on indebtedness, excluding capitalized interest |
$ | 145 | 239 | |||||
Capitalized interest |
115 | 74 | ||||||
Interest portion of rental expense |
37 | 42 | ||||||
$ | 297 | 355 | ||||||
Ratio of Earnings to Fixed Charges |
10.1 | 8.0 | ||||||
Earnings available for fixed charges include, if any, our equity in losses of companies owned less than fifty percent and having debt for which the company is contingently liable. Fixed charges include our proportionate share, if any, of interest relating to the contingent debt.
Earnings available for fixed charges include, if any, 100 percent of the losses of companies owned greater than fifty percent that have debt for which we are contingently liable. Fixed charges include 100 percent of interest and capitalized interest, if any, relating to the contingent debt.
Exhibit 31.1
CERTIFICATION
I, J. J. Mulva, certify that:
1. | I have reviewed this quarterly report on Form 10-Q of ConocoPhillips; | |||
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; | |||
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; | |||
4. | The registrants other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have: |
(a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; | |||
(b) | Evaluated the effectiveness of the registrants disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and | |||
(c) | Disclosed in this report any change in the registrants internal control over financial reporting that occurred during the registrants most recent fiscal quarter (the registrants fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrants internal control over financial reporting; and |
5. | The registrants other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrants auditors and the audit committee of the registrants board of directors (or persons performing the equivalent functions): |
(a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrants ability to record, process, summarize and report financial information; and | |||
(b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrants internal control over financial reporting. |
Date: May 4, 2004
/s/ J. J. Mulva | ||||
J. J. Mulva | ||||
President and Chief Executive Officer | ||||
Exhibit 31.2
CERTIFICATION
I, John A. Carrig, certify that:
1. | I have reviewed this quarterly report on Form 10-Q of ConocoPhillips; | |||
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; | |||
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; | |||
4. | The registrants other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have: |
(a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; | |||
(b) | Evaluated the effectiveness of the registrants disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and | |||
(c) | Disclosed in this report any change in the registrants internal control over financial reporting that occurred during the registrants most recent fiscal quarter (the registrants fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrants internal control over financial reporting; and |
5. | The registrants other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrants auditors and the audit committee of the registrants board of directors (or persons performing the equivalent functions): |
(a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrants ability to record, process, summarize and report financial information; and | |||
(b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrants internal control over financial reporting. |
Date: May 4, 2004
/s/ John A. Carrig | ||||
John A. Carrig | ||||
Executive Vice President, Finance, and Chief Financial Officer |
||||
Exhibit 32
CERTIFICATIONS PURSUANT TO 18 U.S.C. SECTION 1350
In connection with the Quarterly Report of ConocoPhillips (the company) on Form 10-Q for the period ending March 31, 2004, as filed with the U.S. Securities and Exchange Commission on the date hereof (the Report), each of the undersigned hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to their knowledge:
(1) | The Report fully complies with the requirements of Sections 13(a) or 15(d) of the Securities Exchange Act of 1934; and | |||
(2) | The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the company. |
Date: May 4, 2004
/s/ J. J. Mulva | ||||
J. J. Mulva | ||||
President and Chief Executive Officer |
/s/ John A. Carrig | ||||
John A. Carrig | ||||
Executive Vice President, Finance, and Chief Financial Officer |
||||