First Quarter 2002
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2002
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
COMMISSION FILE NUMBER 1-14521
CONOCO INC.
(Exact name of registrant as specified in its charter)
<Table>
DELAWARE 51-0370352
(State or other jurisdiction of incorporation (I.R.S. Employer Identification No.)
or organization)
</Table>
600 NORTH DAIRY ASHFORD ROAD
HOUSTON, TEXAS 77079
(Address of principal executive offices and zip code)
(281) 293-1000
(Registrant's telephone number, including area code)
---------------------
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
626,682,434 shares of common stock, $.01 par value, were outstanding as
of May 3, 2002.
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CONOCO INC.
TABLE OF CONTENTS
<Table>
<Caption>
PAGE(S)
-------
Part I - Financial Information
Item 1. Financial Statements
Consolidated Statement of Income..................................................................... 1
Consolidated Balance Sheet........................................................................... 2
Consolidated Statement of Cash Flows................................................................. 3
Notes to Consolidated Financial Statements........................................................... 4
Item 2. Management's Discussion and Analysis of Financial Condition and Results of
Operations
(a) Financial Condition............................................................................ 12
(b) Results of Operations.......................................................................... 15
Item 3. Quantitative and Qualitative Disclosures About Market Risk..................................... 20
Part II - Other Information
Item 1. Legal Proceedings.............................................................................. 24
Item 4. Submission of Matters to a Vote of Security Holders............................................ 24
Item 5. Other Information
Disclosure Regarding Forward-Looking Information............................................... 24
Item 6. Exhibits and Reports on Form 8-K............................................................... 25
Signature................................................................................................. 26
Exhibit Index............................................................................................. 27
</Table>
i
PART I
FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
CONOCO INC.
CONSOLIDATED STATEMENT OF INCOME (NOTE 1)
(UNAUDITED)
<Table>
<Caption>
THREE MONTHS ENDED
MARCH 31
----------------------------
2002 2001
---------- ----------
(IN MILLIONS,
EXCEPT PER SHARE)
Revenues
Sales and other operating revenues (1) (2) ........................................ $ 7,998 $ 10,625
Equity in earnings of affiliates (note 5) ......................................... 36 21
Other income (note 3) ............................................................. (15) 31
---------- ----------
Total revenues .............................................................. 8,019 10,677
---------- ----------
Cost and expenses
Cost of goods sold (2) (3) ........................................................ 4,468 6,619
Operating expenses ................................................................ 692 614
Selling, general and administrative expenses ...................................... 212 196
Exploration expenses .............................................................. 70 37
Depreciation, depletion and amortization .......................................... 466 353
Taxes other than on income (1) .................................................... 1,778 1,638
Interest and debt expense ......................................................... 116 75
---------- ----------
Total costs and expenses .................................................... 7,802 9,532
---------- ----------
Income before income taxes ............................................................ 217 1,145
Income tax expense .................................................................... 135 529
---------- ----------
Income before extraordinary item and accounting changes ............................... 82 616
Extraordinary item, charge for the early extinguishment of debt, net of income taxes .. (1) --
Cumulative effect of accounting changes, net of income taxes of $11 for 2002 and
$22 for 2001 (notes 2 and 3) ...................................................... 23 37
---------- ----------
Net income (note 11) .................................................................. $ 104 $ 653
========== ==========
Earnings per share (note 6)
Basic
Before extraordinary item and accounting changes .................................. $ .13 $ .99
Extraordinary item ................................................................ -- --
Cumulative effect of accounting changes ........................................... .04 .05
---------- ----------
$ .17 $ 1.04
========== ==========
Diluted
Before extraordinary item and accounting changes .................................. $ .13 $ .97
Extraordinary item ................................................................ -- --
Cumulative effect of accounting changes ........................................... .03 .06
---------- ----------
$ .16 $ 1.03
========== ==========
Weighted-average shares outstanding (note 6)
Basic ............................................................................. 627 625
Diluted ........................................................................... 636 635
Dividends per share of common stock (note 7) .......................................... $ .19 $ .19
- ----------
(1) Includes petroleum excise taxes................................................... $ 1,729 $ 1,564
(2) First quarter 2001 includes a reclassification of revenues previously
reported as a reduction in cost of goods sold of $90.
(3) Excludes refining depreciation.................................................... 33 33
</Table>
See accompanying notes to consolidated financial statements.
1
CONOCO INC.
CONSOLIDATED BALANCE SHEET (NOTE 1)
(UNAUDITED)
<Table>
<Caption>
MARCH 31, DECEMBER 31,
2002 2001
---------- ------------
(IN MILLIONS)
ASSETS
Current assets
Cash and cash equivalents ................................................. $ 221 $ 388
Accounts and notes receivable ............................................. 2,045 1,894
Inventories (note 8) ...................................................... 1,087 995
Other current assets ...................................................... 951 1,066
---------- ------------
Total current assets ................................................ 4,304 4,343
Property, plant and equipment ................................................ 30,620 30,224
Less: accumulated depreciation, depletion and amortization ................... (12,643) (12,306)
---------- ------------
Net property, plant and equipment ............................................ 17,977 17,918
Investment in affiliates ..................................................... 1,916 1,894
Goodwill ..................................................................... 2,933 2,933
Other assets ................................................................. 804 816
---------- ------------
Total assets ................................................................. $ 27,934 $ 27,904
========== ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable .......................................................... $ 1,877 $ 1,950
Short-term borrowings and capital lease obligations ....................... 1,275 1,125
Income taxes .............................................................. 605 530
Other accrued liabilities ................................................. 2,075 1,897
---------- ------------
Total current liabilities ........................................... 5,832 5,502
Long-term borrowings and capital lease obligations ........................... 8,179 8,267
Deferred income taxes ........................................................ 3,870 3,975
Other liabilities and deferred credits ....................................... 2,315 2,346
---------- ------------
Total liabilities ................................................... 20,196 20,090
---------- ------------
Commitments and contingent liabilities (note 9)
Minority interests ........................................................... 1,213 1,204
Stockholders' equity
Preferred stock, $.01 par value
250,000,000 shares authorized; none issued .............................. -- --
Common stock, $.01 par value
4,600,000,000 shares authorized; 628,938,046 shares issued with
626,534,322 shares outstanding at March 31, 2002 and 625,658,528 shares
outstanding at December 31, 2001 ....................................... 6 6
Additional paid-in capital ................................................ 5,045 5,044
Retained earnings ......................................................... 2,519 2,537
Accumulated other comprehensive loss (note 10) ............................ (984) (894)
Treasury stock, at cost
2,403,724 and 3,279,518 shares at March 31, 2002, and
December 31, 2001, respectively ........................................ (61) (83)
---------- ------------
Total stockholders' equity .......................................... 6,525 6,610
---------- ------------
Total liabilities and stockholders' equity ................................... $ 27,934 $ 27,904
========== ============
</Table>
See accompanying notes to consolidated financial statements.
2
CONOCO INC.
CONSOLIDATED STATEMENT OF CASH FLOWS (NOTE 1)
(UNAUDITED)
<Table>
<Caption>
THREE MONTHS ENDED
MARCH 31
--------------------------
2002 2001
---------- ----------
(IN MILLIONS)
Cash provided by operations
Net income ........................................................................ $ 104 $ 653
Adjustments to reconcile net income to cash provided by operations
Extraordinary item, charge for the early extinguishment of debt ................. 1 --
Cumulative effect of accounting changes ......................................... (34) (59)
Depreciation, depletion and amortization ........................................ 466 353
Dry hole costs and impairment of unproved properties ............................ 30 7
Deferred income taxes ........................................................... (80) 128
Income applicable to minority interests ......................................... 14 7
Gain on asset dispositions ...................................................... (29) (13)
Dividends received greater than (less than) equity in earnings of affiliates .... (19) 9
Other non-cash charges and credits - net ........................................ (1) (27)
Decrease (increase) in operating assets
Accounts and notes receivable ................................................. (139) 4
Inventories ................................................................... (97) (193)
Other operating assets ........................................................ (39) (101)
Increase (decrease) in operating liabilities
Accounts and other operating payables ......................................... (67) 35
Income and other taxes payable ................................................ 309 125
---------- ----------
Cash provided by operations ................................................ 419 928
---------- ----------
Investing activities
Purchases of property, plant and equipment ........................................ (589) (336)
Investments in affiliates - net ................................................... (4) (65)
Proceeds from sales of assets and subsidiaries .................................... 55 51
Net increase in short-term instruments ........................................... (1) --
---------- ----------
Cash used in investing activities .......................................... (539) (350)
---------- ----------
Financing activities
Short-term borrowings - net ....................................................... 88 (183)
Long-term borrowings - net ........................................................ (13) --
Treasury stock purchases - net .................................................... 5 (12)
Cash dividends .................................................................... (119) (118)
Net payments to minority interests ................................................ (6) (20)
---------- ----------
Cash used in financing activities .......................................... (45) (333)
---------- ----------
Effect of exchange rate changes on cash ............................................... (2) (26)
---------- ----------
Increase (decrease) in cash and cash equivalents ...................................... (167) 219
Cash and cash equivalents at beginning of year ........................................ 388 342
---------- ----------
Cash and cash equivalents at March 31 ................................................. $ 221 $ 561
========== ==========
</Table>
See accompanying notes to consolidated financial statements.
3
CONOCO INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
(DOLLARS IN MILLIONS, EXCEPT PER SHARE)
1. BASIS OF PRESENTATION AND ACCOUNTING POLICY
These consolidated interim financial statements are unaudited, but reflect
all adjustments that, in the opinion of management, are necessary to provide a
fair presentation of the financial position, results of operations and cash
flows for the dates and periods covered. All such adjustments are of a normal
recurring nature. Interim period results are not necessarily indicative of
results of operations or cash flows for a full-year period. These interim
financial statements should be read in conjunction with the consolidated
financial statements and notes thereto included in Conoco's 2001 Annual Report
on Form 10-K.
2. CUMULATIVE EFFECT OF ACCOUNTING CHANGES
Effective January 1, 2002, we changed our method of accounting for the cost
of planned major maintenance expenditures from the accrue-in-advance method to
the expense-as-incurred method, a preferable method of accounting. The new
method results in the recognition of refinery and plant turnaround or tanker,
barge and boat dry dock maintenance costs in the period that the obligation
occurs. The cumulative effect of this change in accounting principle is an
increase in net income in the first quarter of 2002 of $42 (net of income taxes
of $20), or $.07 per basic share and $.06 per diluted share. The effect of
adopting this accounting principle on income before extraordinary item and
accounting changes and on net income in the first quarter of 2002 is an increase
of $9 (net of income taxes of $5), or $.01 per basic and diluted share.
The pro forma effects of the retroactive application of the change in
accounting principle related to planned major maintenance are as follows:
<Table>
<Caption>
THREE MONTHS ENDED
MARCH 31
--------------------
2002 2001
-------- --------
Income before extraordinary item and accounting changes......................... $ 82 $ 621
Earnings per share
Basic...................................................................... .13 .99
Diluted.................................................................... .13 .98
Net income...................................................................... $ 62 $ 658
Earnings per share
Basic...................................................................... .10 1.05
Diluted.................................................................... .10 1.04
</Table>
Additionally, effective January 1, 2002, we adopted Financial Accounting
Standards Board (FASB) Derivative Implementation Group (DIG) Interpretations A18
and A19 of Statement of Financial Accounting Standards (SFAS) No. 133,
"Accounting for Derivative Instruments and Hedging Activities," as amended by
SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging
Activities," (SFAS 133) as they relate to the fair value at January 1, 2002 of
certain long-term international gas contracts. The cumulative effect of this
change in accounting principle is a transition loss of $19 (net of income taxes
of $9), or $.03 per basic and diluted share. Prior to the issuance of the
interpretations, these contracts were excluded from mark-to-market accounting
under SFAS 133. Other income in the first quarter of 2002 also included a $40
pretax gain ($25 after-tax) from changes in the fair value of these same
contracts from the January 1 adoption date of Interpretations A18 and A19
through March 31, 2002.
3. DERIVATIVE INSTRUMENTS
For the first quarter of 2002, other income included a $162 unrealized
pretax loss ($102 after-tax) and sales and other operating revenues included a
$31 realized pretax gain ($20 after-tax) related to changes in the fair value of
crude oil and natural gas collars and swaps initiated with the 2001 Gulf Canada
acquisition (see footnote 4) from January 1, 2002 through March 31, 2002. Hedge
accounting was not applied to the derivatives where the change in fair value was
reported in other income. In addition, other income in the first quarter of 2002
included a $40 pretax
4
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(UNAUDITED)
(DOLLARS IN MILLIONS, EXCEPT PER SHARE)
gain ($25 after-tax) from changes in the fair value of the long-term
international gas contracts mentioned in footnote 2 above, for which hedge
accounting was not applied. For derivative instruments where hedge accounting
was applied, the ineffective portions of these hedges were immaterial.
In accordance with the transition provisions of SFAS 133, we recorded the
following after-tax cumulative adjustments into earnings on January 1, 2001. The
total amount is shown on the consolidated statement of income as cumulative
effect of accounting change for 2001.
<Table>
Previously designated fair value hedging relationships: (1)
Fair value of hedging instruments............................................... $ 27
Offsetting changes in fair value of hedged items................................ (25)
Hedging instruments not designated for hedge accounting under SFAS 133 (2)......... 36
Contracts previously not designated as derivative instruments prior to SFAS 133.... (1)
------
Total cumulative effect of adoption on earnings, after-tax......................... $ 37
======
</Table>
- ----------
(1) These fair value hedging relationships reflect conversions of certain
commodity contracts from fixed prices to market prices, in accordance with
Conoco's Risk Management Policy. During the first quarter of 2001, the
ineffective portions of these hedges were immaterial.
(2) Primarily reflects a pretax gain of $64 ($40 after-tax) related to changes
in the fair value of certain crude oil put options from their purchase date
to the January 1, 2001 adoption date of SFAS 133. Included in income before
extraordinary item and accounting changes on the consolidated statement of
income is a $69 pretax expense ($43 after-tax) related to changes in the
fair value of these same crude oil put options from January 1, 2001 to
March 31, 2001.
4. GULF CANADA ACQUISITION
On July 16, 2001, Conoco, through a wholly owned subsidiary, completed the
acquisition of all the ordinary shares of Gulf Canada Resources Limited (Gulf
Canada), now known as Conoco Canada Resources Limited (Conoco Canada), for
approximately $4,571 in cash plus assumed liabilities and minority interests. In
this document, for ease of reference, we will refer to Conoco Canada as Gulf
Canada. Prior to the acquisition, Gulf Canada was a Canadian-based independent
exploration and production company, with primary operations in western Canada,
Indonesia, the Netherlands and Ecuador. Subsequent to the acquisition,
operational responsibilities for Gulf Canada's interests in Indonesia, the
Netherlands and Ecuador were realigned within Conoco's regional organizations
and Conoco's existing Canadian operations were merged with those of Gulf Canada.
The following table presents the unaudited pro forma results of Conoco
giving effect to the Gulf Canada acquisition as if the acquisition had occurred
on January 1, 2001. For these unaudited pro forma results, the historical
information of Gulf Canada has been converted to U.S. GAAP and converted to U.S.
dollars using the average exchange rates for the periods involved. The unaudited
results do not purport to represent what the results of operations would
actually have been if the acquisition had in fact occurred on such dates or to
project the results of operations of Conoco for any future date or period.
<Table>
<Caption>
THREE MONTHS ENDED
MARCH 31
-------------------------
2002 2001
---------- ----------
Revenues ................................................................. $ 8,019 $ 11,264
Income before extraordinary item and accounting changes .................. 82 639
Net income ............................................................... 104 676
Earnings per share before extraordinary item and accounting changes
Basic ............................................................... .13 1.02
Diluted ............................................................. .13 1.01
Earnings per share
Basic ............................................................... .17 1.08
Diluted ............................................................. .16 1.06
</Table>
5
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(UNAUDITED)
(DOLLARS IN MILLIONS, EXCEPT PER SHARE)
5. SUMMARIZED FINANCIAL INFORMATION FOR PETROZUATA
Summarized below is the consolidated financial information for Petrozuata
C.A. on a 100 percent basis. We use the equity method to account for our
noncontrolling 50.1 percent equity interest in Petrozuata.
<Table>
<Caption>
THREE MONTHS ENDED
MARCH 31
---------------------------
2002 2001
----------- ----------
RESULTS OF OPERATIONS
Sales..................................................... $ 146 $ 108
Earnings (loss) before income taxes....................... 29 (32)
Net income (loss)......................................... 27 (17)
</Table>
Conoco's equity in Petrozuata's earnings for the three months ended March
31, 2002 was $14, which included a $15 impairment from the devaluation of the
bolivar. Conoco's share of Petrozuata's loss was $9 for the three months ended
March 31, 2001.
6. EARNINGS PER SHARE
Basic earnings per share (EPS) is computed by dividing net income (the
numerator) by the weighted-average number of common shares outstanding plus the
effects of certain vested Conoco employee and director awards and fee deferrals
that are invested in Conoco stock units (the denominator). Diluted EPS is
similarly computed using the treasury stock method, except the denominator is
increased to include the dilutive effect of outstanding stock options and
unvested shares of restricted stock awarded under Conoco's compensation plans.
Fixed options and restricted stock grants that are contingent upon continued
service to the company are included in the diluted earnings per share
calculation and are excluded in the basic earnings per share calculation.
Issuance of these shares is contingent only upon a continued specified service
period of the grantees, and there are no other contingency provisions in these
fixed options and restricted stock grants.
For the three months ended March 31, 2002 and March 31, 2001, basic EPS
reflected the weighted-average number of shares of common stock and deferred
award units outstanding. Diluted EPS included the dilutive effect of an
additional 9,262,479 shares for the first quarter of 2002 and an additional
10,306,345 shares for the first quarter of 2001.
The denominator is based on the following weighted-average number of common
shares outstanding:
<Table>
<Caption>
THREE MONTHS ENDED
MARCH 31
---------------------------------
2002 2001
------------ ------------
Basic............................. 626,974,757 624,701,151
Diluted........................... 636,237,236 635,007,496
</Table>
Variable stock options for 1,331,300 shares of common stock became vested
and exercisable on March 12, 2002 as a result of stockholder approval of
Conoco's previously announced merger with Phillips Petroleum Company (Phillips)
at the stockholders meeting held on that date. These options have been
reclassified as fixed and are now included in the computation of diluted EPS.
Variable stock options for 3,124,146 shares of common stock were outstanding at
March 31, 2001. These options were not included in the computation of diluted
EPS because the threshold price required for these options to be vested had not
been reached.
Fixed stock options for 7,701,314 and 7,681,467 shares of common stock were
not included in the diluted earnings per share calculation for March 31, 2002
and March 31, 2001, respectively, because the exercise price was greater than
the average market price over the quarter.
Common shares held as treasury stock are deducted in determining the number
of shares outstanding.
6
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(UNAUDITED)
(DOLLARS IN MILLIONS, EXCEPT PER SHARE)
7. DIVIDENDS
Conoco paid a $.19 dividend per share in the first quarter of 2002 and a
$.19 dividend per share in the first quarter of 2001.
On April 25, 2002, Conoco declared a second quarter cash dividend of $.19
per share on each outstanding share of common stock, payable on June 10, 2002 to
shareholders of record on May 10, 2002.
8. INVENTORIES
<Table>
<Caption>
MARCH 31, DECEMBER 31,
2002 2001
---------- ------------
Crude oil and petroleum products .............. $ 872 $ 773
Canadian Syncrude (from mining operations) .... 7 10
Other merchandise ............................. 25 26
Materials and supplies ........................ 183 186
---------- ------------
Inventories ................................... $ 1,087 $ 995
========== ============
</Table>
9. COMMITMENTS AND CONTINGENT LIABILITIES
Conoco has various purchase commitments for materials, supplies, services
and items of permanent investment incident to the ordinary conduct of business.
Such commitments are not at prices in excess of current market. Additionally, we
have obligations under international contracts to purchase natural gas over
periods up to 18 years. Due to weakening market prices since year-end, these
long-term purchase obligations are at prices in excess of March 31, 2002 quoted
market prices. No material annual gain or loss is expected from these long-term
commitments.
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; claims for damages resulting
from leaking underground storage tanks; and related toxic tort claims. As a
result of the 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
and cash flows in the period in which they are recognized.
An accrual of $112 was recorded during the fourth quarter of 2001 for a
litigation settlement related to certain discontinued chemicals businesses for
which we assumed responsibility for claims as a result of the separation
agreement with DuPont. As of the end of April 2002, we paid $98 of the accrual,
with the remainder to be paid during May 2002. Additionally, we anticipate
receiving insurance proceeds of $28 over the next three months.
Over the next seven years, we will spend an estimated $95 to $110 for
capital improvements at our U.S. refineries to install control technology and
equipment to reduce emissions from stacks, vents, valves, heaters, boilers and
flares.
We also are subject to contingencies pursuant to environmental laws and
regulations that in the future may require further action to correct the effects
on the environment of prior disposal practices or releases of petroleum
substances by us or other parties. We have accrued for certain environmental
remediation activities consistent with the policy set forth in note 2 to the
consolidated financial statements presented in our 2001 Annual Report on Form
10-K. These accrued liabilities exclude claims against our insurers or other
third parties and are not discounted. We assumed environmental remediation
liabilities from DuPont related to certain discontinued chemicals and
agricultural chemicals businesses operated by us in the past and in the third
quarter of 2001, we assumed environmental remediation liabilities with the
purchase of Gulf Canada. The liabilities are included in our environmental
accrual. At March 31, 2002, our environmental accrual was $160. In management's
opinion, this accrual was appropriate based on existing facts and circumstances.
Under adverse changes in circumstances,
7
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(UNAUDITED)
(DOLLARS IN MILLIONS, EXCEPT PER SHARE)
potential liability may exceed amounts accrued. In the event future monitoring
and remediation expenditures are in excess of amounts accrued, they may be
significant to results of operations and cash flows in the period recognized.
However, management does not anticipate they will have a material adverse effect
on the consolidated financial position of Conoco.
At March 31, 2002, Conoco or DuPont, on behalf of and indemnified by
Conoco, had directly guaranteed $372 of borrowings and other obligations of
certain affiliated companies and others. The balance at March 31, 2002, no
longer includes $719 associated with Petrozuata. In March 2002, Conoco was
notified that DuPont was released from its guarantee of the debt associated with
Petrozuata, and that debt became non-recourse to both Conoco and DuPont. In
addition, at March 31, 2002, Conoco owned 7,510 million shares of Turcas Petrol
A.S., of which 3,964 million shares were pledged to a group of Turkish banks
that issued letters of credit in support of a $70 borrowing. Conoco had no
indirect guarantees as of March 31, 2002.
10. COMPREHENSIVE INCOME
The following sets forth Conoco's comprehensive income for the periods
shown:
<Table>
<Caption>
THREE MONTHS ENDED
MARCH 31
--------------------------
2002 2001
---------- ----------
Net income .................................................................................. $ 104 $ 653
Other comprehensive loss
Foreign currency translation adjustment ................................................... (14) (117)
Unrealized gains (losses) on crude oil and natural gas derivatives - current charges ... (65) --
Unrealized gains (losses) on crude oil and natural gas derivatives - reclassified
into income .......................................................................... (20) --
Unrealized gains (losses) on interest rate derivatives - current gains (charges) ....... 9 (2)
---------- ----------
Unrealized losses on derivatives .......................................................... (76) (2)
---------- ----------
Comprehensive income ........................................................................ $ 14 $ 534
========== ==========
</Table>
During the first quarter of 2002, Conoco recorded an after-tax loss of $76
($124 pretax) into other comprehensive income from derivatives. This loss
includes an after-tax charge of $85 ($65 after-tax in current charges and a $20
after-tax charge reclassification into income) related to derivative instruments
designated as cash flow hedges of certain forecasted sales of crude oil and
natural gas and a net after-tax gain of $9 due to changes in the fair values of
derivative instruments designated as cash flow hedges of variable interest rate
obligations. During the 12-month period ended March 31, 2003, all of the $65
after-tax gain associated with the forecasted sales of crude oil and natural
gas, as well as a portion of the $9 net after-tax gain related to variable
interest rate obligations, is expected to be reclassified into income.
During the first quarter of 2001, Conoco recorded an after-tax loss of $2
($3 pretax) into other comprehensive income from derivatives. This loss included
an after-tax gain of $1, recorded at the date of adoption of SFAS 133, related
to a derivative instrument designated as a cash flow hedge of a variable
interest rate obligation, an after-tax charge of $3 due to changes in the fair
value of this derivative instrument, and an immaterial amount that was
reclassified into net income as a result of the settlement of a small portion of
the obligation.
11. OPERATING SEGMENT AND GEOGRAPHIC INFORMATION
We have three operating segments that comprise the structure used by senior
management to make key operating decisions and assess performance. These are the
upstream, downstream and emerging businesses segments. Upstream operating
segment activities include exploring for, developing, producing and selling
crude oil, natural gas and natural gas liquids; and Syncrude mining operations.
Activities of the downstream operating segment include refining crude oil and
other feedstocks into petroleum products; buying and selling crude oil and
refined products; and transporting, distributing and marketing petroleum
products. Emerging businesses operating segment activities include the
development of new businesses beyond our traditional operations. Emerging
8
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(UNAUDITED)
(DOLLARS IN MILLIONS, EXCEPT PER SHARE)
businesses currently is involved in carbon fibers (Conoco Cevolution(R));
natural gas refining, including gas-to-liquids; and international power.
Conoco has five reporting segments. Four reporting segments reflect the
geographic division between the U.S. and international operations of its
upstream and downstream businesses. One reporting segment is for emerging
businesses. Corporate includes general corporate expenses, financing costs and
other non-operating items and captive insurance operations.
We sell our products worldwide. Major products include crude oil, natural
gas, Canadian Syncrude and refined products that are sold primarily in the
energy and transportation markets. Our sales are not materially dependent on any
single customer or small group of customers. Transfers between segments are on
the basis of estimated market values.
<Table>
<Caption>
UPSTREAM DOWNSTREAM
----------------------- ---------------------
EMERGING ELIMINA- CONSOLI-
SEGMENT INFORMATION U.S. INT'L. U.S. INT'L. BUSINESSES CORPORATE TIONS DATED
--------- ----------- --------- --------- ---------- --------- -------- --------
THREE MONTHS ENDED MARCH 31, 2002
Sales and other operating revenues... $ 1,149 $ 1,469 $ 2,614 $ 2,766 $ -- $ -- $ -- $ 7,998
Transfers between segments........... 116 193 23 93 -- -- (425) --
--------- ----------- --------- --------- ---------- --------- -------- --------
Total operating revenues............. $ 1,265 $ 1,662 $ 2,637 $ 2,859 $ -- $ -- $ (425) $ 7,998
========= =========== ========= ========= ========== ========= ======== ========
Operating profit..................... $ (41) $ 392 $ (14) $ 25 $ (42) $ (30) $ -- $ 290
Equity in earnings of affiliates..... (1) 24 25 (12) -- -- -- 36
Corporate non-operating items
Interest and debt expense......... -- -- -- -- -- (116) -- (116)
Interest income (net of misc.
interest expense)................ -- -- -- -- -- 5 -- 5
Other............................. -- -- -- -- -- 2 -- 2
--------- ----------- --------- --------- ---------- --------- -------- --------
Income before income taxes........... (42) 416 11 13 (42) (139) -- 217
Income tax expense................... 25 (226) (3) (3) 15 57 -- (135)
--------- ----------- --------- --------- ---------- --------- -------- --------
Income before accounting changes..... (17) 190 8 10 (27) (82) -- 82
Extraordinary item, charge for the
early extinguishment of debt, net
of income taxes..................... -- -- -- -- -- (1) -- (1)
Cumulative effect of accounting
changes, net of income taxes........ -- (17) 22 18 -- -- -- 23
--------- ----------- --------- --------- ---------- --------- -------- --------
Net income (loss) (1)................ $ (17) $ 173 $ 30 $ 28 $ (27) $ (83) $ -- $ 104
========= =========== ========= ========= ========== ========= ======== ========
THREE MONTHS ENDED MARCH 31, 2001
Sales and other operating revenues... $ 2,686 $ 1,330 $ 3,803 $ 2,801 $ 5 $ -- $ -- $ 10,625
Transfers between segments........... 253 230 53 130 24 -- (690) --
--------- ----------- --------- --------- ---------- --------- -------- --------
Total operating revenues............. $ 2,939 $ 1,560 $ 3,856 $ 2,931 $ 29 $ -- $ (690) $ 10,625
========= =========== ========= ========= ========== ========= ======== ========
Operating profit..................... $ 484 $ 568 $ 105 $ 86 $ (22) $ (37) $ -- $ 1,184
Equity in earnings of affiliates..... 16 10 5 (6) (4) -- -- 21
Corporate non-operating items
Interest and debt expense......... -- -- -- -- -- (75) -- (75)
Interest income (net of misc.
interest expense)................ -- -- -- -- -- 10 -- 10
Other............................. -- -- -- -- -- 5 -- 5
--------- ----------- --------- --------- ---------- --------- -------- --------
Income before income taxes........... 500 578 110 80 (26) (97) -- 1,145
Income tax expense................... (176) (322) (39) (27) 9 26 -- (529)
--------- ----------- --------- --------- ---------- --------- -------- --------
Income before accounting change...... 324 256 71 53 (17) (71) -- 616
Cumulative effect of accounting
change, net of income taxes......... 8 32 (3) -- -- -- -- 37
--------- ----------- --------- --------- ---------- --------- -------- --------
Net income (loss) (1)................ $ 332 $ 288 $ 68 $ 53 $ (17) $ (71) $ -- $ 653
========= =========== ========= ========= ========== ========= ======== ========
</Table>
9
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(UNAUDITED)
(DOLLARS IN MILLIONS, EXCEPT PER SHARE)
<Table>
<Caption>
UPSTREAM DOWNSTREAM
----------------------- ---------------------
EMERGING ELIMINA- CONSOLI-
SEGMENT INFORMATION U.S. INT'L. U.S. INT'L. BUSINESSES CORPORATE TIONS DATED
--------- ----------- --------- --------- ---------- --------- -------- --------
TOTAL ASSETS (2)
At March 31, 2002................. $ 4,205 $ 17,038 $ 3,582 $ 2,926 $ 310 $ 406 $ (533) $ 27,934
At December 31, 2001.............. $ 4,378 $ 16,607 $ 3,411 $ 2,786 $ 234 $ 1,070 $ (582) $ 27,904
</Table>
- ----------
(1) Includes after-tax benefits (charges) from special items:
<Table>
THREE MONTHS ENDED MARCH 31, 2002
Asset sales.......................... $ 19 $ -- $ -- $ -- $ -- $ -- $ -- $ 19
Cumulative effect of accounting
changes............................ -- (17) 22 18 -- -- -- 23
Premium on debt retirement........... -- -- -- -- -- (1) -- (1)
Discontinued businesses.............. -- -- -- -- -- 18 -- 18
Merger costs......................... (1) -- (1) -- -- (8) -- (10)
--------- ----------- --------- --------- ---------- --------- -------- --------
Total special items.................. $ 18 $ (17) $ 21 $ 18 $ -- $ 9 $ -- $ 49
========= =========== ========= ========= ========== ========= ======== ========
THREE MONTHS ENDED MARCH 31, 2001
Cumulative effect of accounting
change............................. $ 8 $ 32 $ (3) $ -- $ -- $ -- $ -- $ 37
--------- ----------- --------- --------- ---------- --------- -------- --------
Total special items.................. $ 8 $ 32 $ (3) $ -- $ -- $ -- $ -- $ 37
========= =========== ========= ========= ========== ========= ======== ========
</Table>
Special items totaling $49 for the first three months of 2002 included
gains of $60 consisting of $19 from the sale of U.S. Permian Basin producing
properties, $23 to a cumulative effect of accounting changes and insurance
recovery proceeds of $18 associated with a discontinued business.
The $23 cumulative effect of accounting changes was attributable to the two
changes in accounting method discussed in footnote 2. The first, a $42
cumulative effect of accounting change, recorded on January 1, 2002, resulted
from a change in our method of accounting for the cost of planned major
maintenance expenditures from the accrue-in-advance method to the
expense-as-incurred method. It included $40 related to downstream for the
reversal of planned major maintenance expenses of $22 for U.S. refineries and
marine operations and $18 for our international refineries, and $2 attributable
to upstream international operations. The second was a $19 transition loss
resulting from a cumulative effect of accounting change recorded with our
adoption of FASB DIG Interpretations of SFAS 133 as they relate to the January
1, 2002 fair value of certain long-term international gas contracts.
Included in net income for international upstream was a $25 gain related to
changes in the fair value of the long-term international gas contracts mentioned
in the paragraph above.
Partially offsetting these gains were a $10 charge for expenses related to
our planned merger with Phillips and a $1 extraordinary item charge related to
premiums incurred on the early repayment of high-cost Gulf Canada debt.
Special items for the first three months of 2001 included a cumulative
transition gain of $37 recorded on January 1, 2001 upon initial adoption of SFAS
133. This cumulative transition gain included a $40 gain in upstream related to
changes in the fair value of certain crude oil put options from their purchase
date to the January 1, 2001 adoption of SFAS 133 and a $3 charge in U.S.
downstream associated with various derivatives.
The $40 upstream gain consisted of $8 that was U.S. related and $32 that
was related to international operations. Also included in net income for
upstream was a $43 expense related to changes in the fair value of these same
crude oil put options from January 1, 2001 to March 31, 2001, which essentially
offsets the $40 transition gain. This expense consisted of $9 for U.S.
operations and $34 for international operations.
(2) Upstream includes $2,927 of goodwill arising from the third quarter 2001
acquisition of Gulf Canada. In accordance with the requirements of SFAS No.
142, "Goodwill and Other Intangible Assets," which was adopted on January
1, 2002, a test for impairment of this goodwill must be completed annually.
As part of this test, $1,952 of the goodwill has been allocated to the
international upstream reporting unit, and $975 has been allocated to the
U.S. upstream reporting unit. The first step of this impairment test, which
is a comparison of the fair values and net book values of these reporting
units, will be completed by June 30, 2002. Based on our preliminary
assessment, we do not anticipate a goodwill write-down from the 2002
impairment test. We can make no assurance, however, that we will not be
required to write down goodwill based on that test.
12. VOTE ON CONOCOPHILLIPS MERGER
On March 12, 2002, Conoco held a special meeting of stockholders for the
purpose of adopting the Agreement and Plan of Merger, dated as of November 18,
2001, by and among Conoco, Phillips Petroleum Company, a Delaware corporation,
ConocoPhillips, a Delaware corporation which we refer to as "New Parent," C
Merger Corp.,
10
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(UNAUDITED)
(DOLLARS IN MILLIONS, EXCEPT PER SHARE)
a Delaware corporation and a wholly owned subsidiary of New Parent, and P Merger
Corp., a Delaware corporation and a wholly owned subsidiary of New Parent.
Stockholders approved the proposal.
13. SUBSEQUENT EVENTS
In April 2002, Conoco began selling certain U.S. credit card and trade
receivables under a revolving sales agreement to Conoco Enterprise Funding
L.L.C., a consolidated wholly owned special purpose entity, which in turn sells
undivided interests in the receivables on a limited recourse basis to an
unaffiliated bank-sponsored entity. This revolving sales agreement provides for
the sale of up to $400 of senior, undivided interests in pools of the credit
card or trade receivables. Conoco Enterprise Funding L.L.C. retains an undivided
interest in the conveyed pool of receivables, which is subordinated to the
interests sold to the unaffiliated bank-sponsored entity, and Conoco retains the
servicing responsibility for the sold receivables. We expect that the cost of
funds for this program will be comparable to our commercial paper, currently
around 2 percent.
Also in April, Gulf Canada completed the redemption of its Series 1 and
Series 2 preferred stock totaling $364. The weighted-average dividend paid on
the preferred stock for the first quarter of 2002 was 2.86 percent. In addition,
Gulf Canada redeemed $67 of 6.45 percent medium-term notes due 2007.
11
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
(a) FINANCIAL CONDITION
LIQUIDITY AND CAPITAL RESOURCES
CASH PROVIDED BY OPERATIONS
Cash provided by operations in the first three months of 2002 decreased
$509 million to $419 million from $928 million in the first three months of
2001. Cash provided by operations before changes in operating assets and
liabilities decreased $606 million compared to the first three months of 2001,
primarily due to lower natural gas and crude oil prices, as well as weaker
downstream margins. Positive changes to net operating assets and liabilities of
$97 million were primarily due to higher taxes payable and decreased inventories
partially offset by an increase in accounts receivable.
INVESTING ACTIVITIES
CAPITAL EXPENDITURES AND INVESTMENTS
<Table>
<Caption>
THREE MONTHS ENDED
MARCH 31
---------------------
2002 2001
-------- --------
(IN MILLIONS)
Upstream
United States .............................. $ 116 $ 122
International .............................. 351 177
-------- --------
Total upstream ......................... 467 299
Downstream
United States .............................. 23 26
International .............................. 29 41
-------- --------
Total downstream ....................... 52 67
Emerging businesses ............................ 75 34
Corporate ...................................... 2 6
-------- --------
Total capital expenditures and investments ..... $ 596 $ 406
======== ========
United States .................................. $ 154 $ 187
International .................................. 442 219
-------- --------
Total capital expenditures and investments ..... $ 596 $ 406
======== ========
</Table>
Total capital expenditures and investments were $596 million for the first
three months of 2002, an increase of $190 million, or 47 percent, versus capital
expenditures and investments of $406 million for the first three months of 2001.
The increase was primarily due to higher spending on international upstream
acquisitions. Capital expenditures and investments include capitalized
exploratory wells but do not include expensed exploration costs. A more detailed
description and analysis of capital expenditures and investments by operating
segment within the U.S. and international follows below.
Upstream
Upstream capital expenditures and investments totaled $467 million for the
first three months of 2002 compared to $299 million for the first three months
of 2001. The increase of $168 million, or approximately 56 percent, was
primarily the result of higher spending associated with new properties obtained
through our Gulf Canada Resources Limited (Gulf Canada), now known as Conoco
Canada Resources Limited (Conoco Canada) acquisition. In this document, for ease
of reference, we will refer to Conoco Canada as Gulf Canada.
United States
During the first three months of 2002, Conoco spent $116 million on U.S.
capital projects, a decrease of $6 million, or 5 percent, from $122 million in
the first three months of 2001. The decrease in expenditures in 2002 versus 2001
was primarily due to decreased drilling activity.
12
International
International upstream capital expenditures and investments totaled $351
million in the first three months of 2002, an increase of $174 million, or 98
percent, from $177 million in the first three months of 2001. The increase was
primarily the result of higher spending associated with new properties obtained
through our Gulf Canada acquisition.
Downstream
Downstream capital expenditures and investments totaled $52 million in the
first three months of 2002, a decrease of $15 million, or 22 percent, versus $67
million in the first three months of 2001, reflecting reduced expenditures in
refining and marketing operations worldwide.
United States
During the first three months of 2002, Conoco spent $23 million on
downstream U.S. capital projects, down $3 million, or 12 percent, from $26
million in the first three months of 2001. Capital expenditures and investments
in the first three months of 2002 were primarily related to several small
investments in our refining operations. Capital expenditures and investments in
the first three months of 2001 were principally related to several small
investments in our pipeline and refining operations.
International
Conoco spent $29 million on downstream international capital projects
during the first three months of 2002, down $12 million, or 29 percent, from $41
million in the first three months of 2001. In the first three months of 2002 and
2001, a major portion of capital expenditures and investments went to ongoing
refining and marketing operations.
Emerging Businesses
First quarter emerging businesses capital expenditures and investments
totaled $75 million in 2002, an increase of $41 million, or 121 percent,
compared to $34 million in the first three months of 2001. The increased
expenditures during the first three months of 2002 were primarily related to
construction costs for the Immingham Combined Heat and Power Cogeneration plant
located in the U.K. near our Humber refinery. Capital expenditures do not
include construction costs associated with our natural gas refining pilot plant
in Ponca City, Oklahoma as these costs were expensed as research and development
costs.
Corporate
Corporate capital expenditures and investments totaled $2 million in the
first three months of 2002, a decrease of $4 million, or 67 percent, compared to
$6 million in the first three months of 2001. The decreased expenditures during
the first three months of 2002 were largely the result of reduced spending on
computer infrastructure.
PROCEEDS FROM SALES OF ASSETS AND SUBSIDIARIES
Proceeds from asset sales amounted to $55 million for the first three
months of 2002, an increase of $4 million, or 8 percent, from $51 million in the
first three months of 2001. Proceeds in the first quarter of 2002 were primarily
the result of the sale of Permian Basin producing properties in west Texas,
while proceeds in the first quarter of 2001 were primarily the result of the
sale of our interest in Arkhangelskgeoldobycha, a Russian exploration and mining
company.
FINANCING ACTIVITIES
Conoco's ability to maintain and grow its operating income and cash flow is
dependent upon continued capital spending to replace depleting assets. Conoco
believes its future cash flow from operations and its borrowing capacity should
be sufficient to fund its payments of dividends, if any, capital expenditures
and working capital requirements and to service debt.
13
At March 31, 2002, Conoco had an unsecured $3,000 million revolving credit
facility with a syndicate of U.S. and international banks. The terms consist of
a 364-day committed facility in the amount of $2,350 million and a five-year
committed facility in the amount of $650 million. The five-year committed
facility had over two years remaining at March 31, 2002. Conoco had no
outstanding borrowings under the credit facility at March 31, 2002. Subsequently
on May 2, 2002, Conoco reduced availability under the 364-day facility to $1,850
million and renewed it for another 364 days.
Conoco maintains a $2,500 million U.S. commercial paper program and a euro
1,000 million European commercial paper program that are fully supported by the
credit facility. Conoco has the ability to issue commercial paper at any time
with maturities not to exceed 270 days. At March 31, 2002, we had $645 million
of commercial paper outstanding, with a weighted-average interest rate of 2.11
percent. None of the outstanding commercial paper was denominated in foreign
currencies.
Total Conoco debt was $9,454 million at March 31, 2002, up $62 million
versus $9,392 million at December 31, 2001. The total debt-to-capitalization
ratio was 55.0 percent at March 31, 2002 and 54.6 percent at December 31, 2001.
During the first quarter, Gulf Canada redeemed the remaining $5 million of
its 7.125 percent notes due 2011. In addition, Gulf Canada repurchased a total
of $7 million of its 8.25 percent notes due 2017. The early repayment of this
debt resulted in an extraordinary loss of $1 million for the quarter.
In April 2002, Conoco began selling certain U.S. credit card and trade
receivables under a revolving sales agreement to Conoco Enterprise Funding
L.L.C., a consolidated wholly owned special purpose entity, which in turn sells
undivided interests in the receivables on a limited recourse basis to an
unaffiliated bank-sponsored entity. This revolving sales agreement provides for
the sale of up to $400 million of senior, undivided interests in pools of the
credit card or trade receivables. Conoco Enterprise Funding L.L.C. retains an
undivided interest in the conveyed pool of receivables, which is subordinated to
the interests sold to the unaffiliated bank-sponsored entity, and Conoco retains
the servicing responsibility for the sold receivables. We expect that the cost
of funds for this program will be comparable to our commercial paper, currently
around 2 percent.
Also in April, Gulf Canada completed the redemption of its Series 1 and
Series 2 preferred stock totaling $364 million. The weighted-average dividend
paid on the preferred stock for the first quarter of 2002 was 2.86 percent. In
addition, Gulf Canada redeemed $67 million of 6.45 percent medium-term notes due
2007.
14
(b) RESULTS OF OPERATIONS
CONSOLIDATED RESULTS
<Table>
<Caption>
THREE MONTHS ENDED
MARCH 31
--------------------------
2002 2001
---------- ----------
(IN MILLIONS)
SALES AND OTHER OPERATING REVENUES
Upstream
United States ..................................... $ 1,149 $ 2,686
International ..................................... 1,469 1,330
---------- ----------
Total upstream .............................. 2,618 4,016
Downstream
United States ..................................... 2,614 3,803
International ..................................... 2,766 2,801
---------- ----------
Total downstream ............................ 5,380 6,604
Emerging businesses ................................. -- 5
Corporate ........................................... -- --
---------- ----------
Sales and other operating revenues ..................... $ 7,998 $ 10,625
========== ==========
AFTER-TAX OPERATING INCOME
Upstream
United States ..................................... $ (17) $ 332
International ..................................... 173 288
---------- ----------
Total upstream .............................. 156 620
Downstream
United States ..................................... 30 68
International ..................................... 28 53
---------- ----------
Total downstream ............................ 58 121
Emerging businesses ................................. (27) (17)
Corporate ........................................... (25) (24)
---------- ----------
Total after-tax operating income ............ 162 700
Interest and other non-operating expenses net of tax ... (58) (47)
---------- ----------
Net income ............................................. $ 104 $ 653
========== ==========
</Table>
SPECIAL ITEMS
Net income includes the following non-recurring items (special items) on an
after-tax basis:
<Table>
<Caption>
THREE MONTHS ENDED
MARCH 31
--------------------------
2002 2001
---------- ----------
(IN MILLIONS)
UPSTREAM
Asset sales ............................................ $ 19 $ --
Cumulative effect of accounting changes ................ (17) 40
Merger costs ........................................... (1) --
---------- ----------
Total upstream special items ...................... 1 40
DOWNSTREAM
Cumulative effect of accounting changes ................ 40 (3)
Merger costs ........................................... (1) --
---------- ----------
Total downstream special items .................... 39 (3)
CORPORATE
Discontinued businesses ................................ 18 --
Merger costs ........................................... (8) --
---------- ----------
Total corporate special items ..................... 10 --
INTEREST AND OTHER NON-OPERATING EXPENSES
Premium on debt retirement ............................. (1) --
---------- ----------
Total special items ........................................ $ 49 $ 37
========== ==========
</Table>
15
Special items totaling $49 million for the first three months of 2002
included gains of $60 million consisting of $19 million from the sale of U.S.
Permian Basin producing properties, $23 million to a cumulative effect of
accounting changes and insurance recovery proceeds of $18 million associated
with a discontinued business.
The $23 million cumulative effect of accounting changes was attributable to
two changes in accounting method. The first, a $42 million cumulative effect of
accounting change, recorded on January 1, 2002, resulted from a change in our
method of accounting for the cost of planned major maintenance expenditures from
the accrue-in-advance method to the expense-as-incurred method. It included $40
million related to downstream for the reversal of planned major maintenance
expenses of $22 million for U.S. refineries and marine operations and $18
million for our international refineries, and $2 million attributable to
upstream international operations. The second was a $19 million transition loss
resulting from a cumulative effect of accounting change recorded with our
adoption of Financial Accounting Standards Board (FASB) Derivative
Implementation Group (DIG) Interpretations of Statement of Financial Accounting
Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging
Activities," as amended by SFAS No. 138, "Accounting for Certain Derivative
Instruments and Certain Hedging Activities," (SFAS 133) as they relate to the
January 1, 2002 fair value of certain long-term international gas contracts.
Included in net income for international upstream was a $25 million gain
related to changes in the fair value of the long-term international gas
contracts mentioned in the paragraph above.
Partially offsetting these gains were a $10 million charge for expenses
related to our planned merger with Phillips Petroleum Company (Phillips) and a
$1 million extraordinary item charge related to premiums incurred on the early
repayment of high-cost Gulf Canada debt.
Special items for the first three months of 2001 included a cumulative
transition gain of $37 million recorded on January 1, 2001 upon initial adoption
of SFAS 133. This cumulative transition gain included a $40 million gain in
upstream related to changes in the fair value of certain crude oil put options
from their purchase date to the January 1, 2001 adoption of SFAS 133 and a $3
million charge in U.S. downstream associated with various derivatives.
The $40 million upstream gain consisted of $8 million that was U.S. related
and $32 million that was related to international operations. Also included in
net income for upstream was a $43 million expense related to changes in the fair
value of these same crude oil put options from January 1, 2001 to March 31,
2001, which essentially offsets the $40 million transition gain. This expense
consisted of $9 million for U.S. operations and $34 million for international
operations.
FIRST QUARTER 2002 VERSUS FIRST QUARTER 2001
Net income was $104 million in the first quarter of 2002, down 84 percent
from $653 million in the first quarter of 2001. Net income before special items
was $55 million in the first quarter of 2002, down 91 percent from $616 million
in the first quarter of 2001. These decreases predominantly reflected lower
natural gas and crude oil prices, weaker downstream margins and a non-cash
charge for the mark-to-market portion of crude oil and natural gas hedges
associated with the Gulf Canada acquisition. Partly offsetting these decreases
were increased crude oil sales and natural gas volumes resulting from our 2001
Gulf Canada acquisition.
Sales and other operating revenues for the first quarter of 2002 were
$7,998 million, down 25 percent from $10,625 million in the first quarter of
2001, primarily due to lower crude oil, natural gas and refined product prices.
Crude oil and refined product buy/sell and natural gas resale activities in the
first quarter of 2002 totaled $1,567 million, down 45 percent compared to $2,832
million in the first quarter of 2001, primarily due to lower crude oil, natural
gas and refined product prices.
Income from equity affiliates for the first quarter of 2002 was $36
million, up $15 million, or 71 percent, compared to $21 million in the first
quarter of 2001. Additional crude oil volumes, higher syncrude oil prices and
lower costs in the first quarter of 2002 from our Petrozuata joint venture drove
this improvement.
Other income for the first quarter of 2002 was a loss of $15 million, down
$46 million from other income of $31 million in the first quarter of 2001. Other
income for the first quarter of 2002 included losses of $162 million from the
hedges initiated with the Gulf Canada acquisition associated with a quarter-end
mark-to-market adjustment for higher prices and gains of $40 million related to
changes in the fair value of long-term gas contracts from adopting FASB DIG
Interpretations of SFAS 133. Other income for the first quarter of 2001 included
losses of $69
16
million related to the change during the quarter in the market value of crude
oil put options as a result of the implementation of SFAS 133.
Cost of goods sold for the first quarter of 2002 totaled $4,468 million, a
decrease of $2,151 million, or 32 percent, compared to $6,619 million in the
first quarter of 2001, primarily due to the decrease in natural gas prices and
lower refinery feedstock costs.
Operating expenses for the first quarter of 2002 were $692 million, up 13
percent, or $78 million, compared to $614 million for the first quarter of 2001.
This increase was primarily due to our Gulf Canada acquisition.
Selling, general and administrative expenses for the first quarter of 2002
were $212 million, an increase of $16 million, or 8 percent, compared to $196
million for the first quarter of 2001. The increase was mostly due to higher
technology, aviation and legal costs.
Exploration expenses for the first quarter of 2002 totaled $70 million, an
increase of $33 million, or 89 percent, compared to $37 million from the first
quarter of 2001, reflecting higher exploration expenses due to our Gulf Canada
acquisition and higher dry hole costs.
Depreciation, depletion and amortization (DD&A) for the first quarter of
2002 totaled $466 million, an increase of $113 million, or 32 percent, compared
to $353 million in the first quarter of 2001. The increase was principally due
to changes in rates and field mix and the volumes associated with the Gulf
Canada acquisition.
Income tax expense for the first quarter of 2002 totaled $135 million, down
74 percent, compared to $529 million for the first quarter of 2001, as a result
of lower pretax income. The effective tax rate, approximately 62 percent in the
first quarter of 2002 compared to 46 percent in the first quarter of 2001, was
higher primarily due to a significantly higher portion of pretax income being
generated in countries with higher effective tax rates.
UPSTREAM SEGMENT RESULTS
<Table>
<Caption>
THREE MONTHS ENDED
MARCH 31
--------------------------
2002 2001
---------- ----------
(IN MILLIONS)
After-tax operating income
United States ...................................... $ (17) $ 332
International ...................................... 173 288
---------- ----------
After-tax operating income ....................... 156 620
Special items
United States ...................................... (18) (8)
International ...................................... 17 (32)
---------- ----------
Special items .................................... (1) (40)
Earnings before special items
United States ...................................... (35) 324
International ...................................... 190 256
---------- ----------
Earnings before special items ......................... $ 155 $ 580
========== ==========
</Table>
The following table sets forth for Conoco, including equity affiliates,
average sales prices per barrel of crude oil and condensate sold and average
sales prices per thousand cubic feet (mcf) of natural gas sold.
<Table>
<Caption>
UNITED CONSOLIDATED EQUITY TOTAL
STATES INT'L. COMPANIES COMPANIES WORLDWIDE
---------- ---------- ------------ ---------- ----------
(UNITED STATES DOLLARS)
FOR THE QUARTER ENDED MARCH 31, 2002
Average sales prices of produced petroleum
including hedges
Per barrel of crude oil and condensate sold .. $ 23.21 $ 19.75 $ 20.15 $ 13.23 $ 18.73
Per mcf of natural gas sold .................. 2.64 2.86 2.79 2.17 2.79
Average sales prices of produced petroleum
excluding hedges
Per barrel of crude oil and condensate sold .. $ 17.90 $ 19.75 $ 19.53 $ 13.23 $ 18.24
Per mcf of natural gas sold .................. 2.54 2.81 2.73 2.17 2.73
</Table>
17
<Table>
<Caption>
UNITED CONSOLIDATED EQUITY TOTAL
STATES INT'L. COMPANIES COMPANIES WORLDWIDE
---------- ---------- ------------ ---------- ----------
(UNITED STATES DOLLARS)
FOR THE QUARTER ENDED MARCH 31, 2001 (1)
Average sales prices of produced petroleum
Per barrel of crude oil and condensate sold .. $ 25.29 $ 24.63 $ 24.75 $ 12.25 $ 23.19
Per mcf of natural gas sold .................. 6.76 4.09 5.28 7.57 5.31
</Table>
- ----------
(1) There were no hedging effects in the first quarter of 2001.
The following table sets forth for Conoco the average sales price per
barrel of Canadian Syncrude sold from the Canadian Syncrude project in Canada.
<Table>
<Caption>
AMOUNT
--------------
(UNITED STATES
DOLLARS)
CANADIAN SYNCRUDE
FOR THE QUARTER ENDED MARCH 31, 2002
Average sales price of Canadian Syncrude sold.................................................... $ 21.77
</Table>
FIRST QUARTER 2002 VERSUS FIRST QUARTER 2001
Upstream earnings before special items were $155 million in the first
quarter of 2002, down 73 percent from $580 million in the first quarter of 2001,
driven by significantly weaker worldwide natural gas and crude oil prices,
mark-to-market losses from open crude oil and natural gas hedges and higher
costs, mainly reflecting the addition of Gulf Canada operations. Increased
international production partly offset the fall in prices and higher costs. U.S.
upstream earnings before special items was a loss of $35 million in the first
quarter of 2002, down $359 million from $324 million in the comparable period of
2001, reflecting lower crude oil and natural gas prices, the non-cash charge for
the mark-to-market portion of open crude oil and natural gas hedges associated
with the Gulf Canada acquisition, as well as lower crude oil and natural gas
volumes. International upstream earnings before special items were $190 million,
a decrease of 26 percent from $256 million in the comparable period in 2001. The
decline was primarily attributable to lower crude oil and natural gas prices,
higher overhead and operating expenses, DD&A and exploration expenses, partly
offset by increased crude oil and natural gas volumes.
Conoco's worldwide net realized crude oil price, including equity
affiliates, was $18.73 per barrel for the first quarter of 2002, down $4.46 per
barrel, or 19 percent, from $23.19 per barrel in the first quarter of 2001.
Worldwide net realized natural gas prices, including equity affiliates, averaged
$2.79 per mcf for the first quarter of 2002, compared with $5.31 per mcf in the
same period in 2001, a decrease of 47 percent.
Worldwide petroleum liquids production, including our share of equity
affiliates, but excluding Canadian Syncrude, in the first quarter of 2002 was
441,000 barrels per day versus 381,000 barrels per day in the first quarter of
2001, a 16 percent increase. U.S. petroleum liquids production was down 21
percent as a result of asset dispositions in 2001. International petroleum
liquids production increased 24 percent to 383,000 barrels per day due to the
Gulf Canada acquisition and increases in Norway, partly offset by declines in
the U.K. Canadian Syncrude production for the first quarter of 2002 was 22,000
barrels per day.
Worldwide natural gas production, including our share of equity affiliates,
in the first quarter of 2002 was up 31 percent to 2,383 million cubic feet
(mmcf) per day from 1,822 mmcf per day in the first quarter of 2001. U.S.
natural gas production was down 11 percent while international natural gas
production was up 66 percent. The international increase was mainly due to our
Gulf Canada acquisition, while the U.S. decline was attributable to asset
dispositions in 2001 and natural field decline.
Worldwide refined product sales for upstream in the first quarter of 2002
were 248,000 barrels per day, up 26 percent from the first quarter of 2001,
primarily due to additional volumes available for sale.
18
DOWNSTREAM SEGMENT RESULTS
<Table>
<Caption>
THREE MONTHS ENDED
MARCH 31
--------------------------
2002 2001
---------- ----------
(IN MILLIONS)
After-tax operating income
United States ...................................... $ 30 $ 68
International ...................................... 28 53
---------- ----------
After-tax operating income ....................... 58 121
Special items
United States ...................................... (21) 3
International ...................................... (18) --
---------- ----------
Special items .................................... (39) 3
Earnings before special items
United States ...................................... 9 71
International ...................................... 10 53
---------- ----------
Earnings before special items ......................... $ 19 $ 124
========== ==========
</Table>
FIRST QUARTER 2002 VERSUS FIRST QUARTER 2001
Downstream earnings before special items were $19 million for the first
quarter of 2002, a decrease of $105 million, or 85 percent, from $124 million in
the comparable period in 2001 due to much lower refining margins in all regions,
partially offset by improved co-product margins caused by lower crude oil
prices. U.S. downstream earnings before special items were $9 million for the
first quarter of 2002, down $62 million, or 87 percent from the first quarter of
2001. The decrease was primarily attributable to very weak refining margins and
reduced price discounts for heavy oil. International downstream earnings before
special items were $10 million for the first quarter of 2002, down $43 million,
or 81 percent, from $53 million in the comparable period in 2001, primarily
reflecting weak European and Asian refining and marketing margins. Worldwide
refined product sales in the first quarter of 2002 were 1,175,000 barrels per
day, down 8 percent from the first quarter of 2001, primarily due to reduced
demand.
EMERGING BUSINESSES SEGMENT RESULTS
<Table>
<Caption>
THREE MONTHS ENDED
MARCH 31
--------------------------
2002 2001
---------- ----------
(IN MILLIONS)
After-tax operating loss .............................. $ (27) $ (17)
Special items ......................................... -- --
---------- ----------
Losses before special items ........................... $ (27) $ (17)
========== ==========
</Table>
FIRST QUARTER 2002 VERSUS FIRST QUARTER 2001
Emerging businesses operating losses were $27 million for the first quarter
of 2002, an increase of $10 million compared to the first quarter of 2001,
principally due to construction expenses for the natural gas refining pilot
plant in Ponca City, Oklahoma, scheduled for completion in the fourth quarter of
2002.
CORPORATE SEGMENT RESULTS
<Table>
<Caption>
THREE MONTHS ENDED
MARCH 31
--------------------------
2002 2001
---------- ----------
(IN MILLIONS)
After-tax operating loss .............................. $ (25) $ (24)
Special items ......................................... (10) --
---------- ----------
Losses before special items ........................... $ (35) $ (24)
========== ==========
</Table>
19
FIRST QUARTER 2002 VERSUS FIRST QUARTER 2001
Corporate operating losses before special items were $35 million for the
first quarter of 2002, an increase of $11 million compared to the first quarter
of 2001, mainly due to higher technology, aviation, legal and minority interest
costs.
INTEREST AND OTHER NON-OPERATING EXPENSES NET OF TAX
<Table>
<Caption>
THREE MONTHS ENDED
MARCH 31
--------------------------
2002 2001
---------- ----------
(IN MILLIONS)
Interest expense on debt .................................................... $ (86) $ (67)
Interest income ............................................................. 32 11
Exchange gains (losses) ..................................................... (4) 9
---------- ----------
Interest and other non-operating expenses net of tax ........................ (58) (47)
Special items ............................................................... 1 --
---------- ----------
Interest and other non-operating expenses net of tax before special items ... $ (57) $ (47)
========== ==========
</Table>
FIRST QUARTER 2002 VERSUS FIRST QUARTER 2001
Interest and other non-operating expenses before special items for the
first quarter of 2002 amounted to $57 million, an increase of $10 million, or 21
percent, compared to $47 million in the comparable period in 2001. This increase
is primarily attributable to an increase in interest expense resulting from
additional debt incurred to acquire Gulf Canada and foreign currency exchange
losses partially offset by higher interest income and higher capitalized
interest.
TAX MATTERS
The U.K. government has recently proposed changes to their tax laws on the
production of oil and gas. The tax law changes will likely be enacted in the
second or third quarter of 2002. The potential impact of these changes could be
material to Conoco's results of operations in the period the changes are
enacted.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
MARKET RISKS
Changes in commodity price risk, foreign currency risk and interest rate
risk for the period ended March 31, 2002, are summarized below.
COMMODITY PRICE RISK
The fair value gain or loss of outstanding derivative commodity instruments
and the change in the fair value that would be expected from a 10 percent
adverse price change are shown in the following table:
<Table>
<Caption>
CHANGE IN FAIR VALUE
FROM 10% ADVERSE
FAIR VALUE PRICE CHANGE
---------- --------------------
COMMODITY DERIVATIVES (1) (IN MILLIONS)
AT MARCH 31, 2002
Crude oil and refined products
Trading ............................................ $ 8 $ 1
Non-trading (2) .................................... 40 (80)
---------- ----------
Combined .............................................. $ 48 $ (79)
========== ==========
Natural gas and electricity
Trading ............................................ $ 3 $ --
Non-trading (3) .................................... 80 (28)
---------- ----------
Combined .............................................. $ 83 $ (28)
========== ==========
</Table>
20
<Table>
<Caption>
CHANGE IN FAIR VALUE
FROM 10% ADVERSE
FAIR VALUE PRICE CHANGE
---------- --------------------
(IN MILLIONS)
AT DECEMBER 31, 2001
Crude oil and refined products
Trading ............................................ $ -- $ (3)
Non-trading (2) .................................... 264 (105)
---------- ----------
Combined .............................................. $ 264 $ (108)
========== ==========
Natural gas and electricity
Trading ............................................ $ -- $ (1)
Non-trading (3) .................................... 74 (8)
---------- ----------
Combined .............................................. $ 74 $ (9)
========== ==========
</Table>
- ----------
(1) Includes derivative instruments that can be settled in cash or by physical
delivery of the commodity.
(2) Includes collars with a $24.04 floor price and a $26.54 cap price (West
Texas Intermediate equivalent) on 54.5 million barrels for the period
October 2001 through December 2002.
Includes swaps at $25.30 on 18.3 million barrels for the period October
2001 through December 2002.
(3) Includes collars with a $4.00 floor price and a $4.60 cap price (NYMEX
equivalent) on approximately 120,000 mmbtu per day for the period October
2001 through December 2002.
Includes swaps at $4.02 on approximately 100,000 mmbtu per day for the
period October 2001 through December 2002.
The fair values of the futures contracts are based on publicly quoted
market prices obtained from the New York Mercantile Exchange (NYMEX) or the
International Petroleum Exchange of London. The fair values of swaps and other
over-the-counter instruments are estimated based on quoted market prices of
comparable contracts and approximate the gain or loss that would have been
realized if the contracts had been closed out at the end of the period.
Price-risk sensitivities were calculated by assuming an across-the-board 10
percent adverse change in prices regardless of term or historical relationships
between the contractual price of the instrument and the underlying commodity
price. In the event of an actual 10 percent change in prompt month crude oil or
natural gas prices, the fair value of Conoco's derivative portfolio would
typically change less than that shown in the table due to lower volatility in
out-month prices.
EXCHANGE AND NON-EXCHANGE TRADED CONTRACTS ACCOUNTED FOR AT FAIR VALUE
<Table>
<Caption>
NON-
EXCHANGE EXCHANGE
TRADED TRADED TOTAL
---------- ---------- ----------
(IN MILLIONS)
Fair value of contracts outstanding at the beginning of the period ... $ (4) $ 342 $ 338
Implementation of DIG Interpretations A18 and A19 (1) ................ -- (28) (28)
Contracts realized or otherwise settled during the period ............ (2) 10 8
Fair value of new contracts when entered into during the period ...... -- 12 12
Changes in fair value values attributable to changes
in valuation techniques ........................................... -- -- --
Other changes in fair values ......................................... 9 (208) (199)
---------- ---------- ----------
Fair value of contracts outstanding at the end of the period ......... $ 3 $ 128 $ 131
========== ========== ==========
</Table>
- ----------
(1) Reduction in the January 1, 2002 fair value of certain long-term
international gas contracts resulting from the application of FASB DIG
Interpretations of SFAS 133.
21
<Table>
<Caption>
FAIR VALUE OF CONTRACTS AT PERIOD-END
------------------------------------------------------------------------
MATURITY IN
MATURITY UP MATURITY MATURITY EXCESS OF 5 TOTAL FAIR
TO 1 YEAR 2-3 YEARS 4-5 YEARS YEARS VALUE
----------- ---------- ---------- ----------- ----------
(IN MILLIONS)
SOURCE OF FAIR VALUE
Prices actively quoted
Exchange ............................. $ 1 $ 2 $ -- $ -- $ 3
Non-exchange ......................... 127 3 (2) -- 128
---------- ---------- ---------- ---------- ----------
Total ............................. $ 128 $ 5 $ (2) $ -- $ 131
========== ========== ========== ========== ==========
Prices provided by other external
sources ............................. -- -- -- -- --
Prices based on models and other
valuation methods ................... -- -- -- -- --
</Table>
FOREIGN CURRENCY RISK
At March 31, 2002, Conoco had no foreign currency swaps associated with our
European commercial paper program. At December 31, 2001, the U.S. dollar
equivalent of all non-U.S. dollar notes outstanding was $29 million, all of
which were swapped to the U.S. dollar.
At March 31, 2002, we had open foreign currency exchange derivative
instruments with a notional value of $238 million related to forward currency
purchases. At December 31, 2001, we had open foreign currency exchange
derivative instruments with a notional value of $9 million related to forward
currency sales.
The fair value of outstanding foreign currency hedges and the change in the
fair value that would be expected from a 10 percent adverse foreign currency
rate change are shown in the following table:
<Table>
<Caption>
CHANGE IN FAIR VALUE FROM
10% ADVERSE FOREIGN
FAIR VALUE CURRENCY RATE CHANGE
----------- -------------------------
(IN MILLIONS)
FOREIGN CURRENCY DERIVATIVES
AT MARCH 31, 2002
Non-trading ................................... $ 4 $ (15)
AT DECEMBER 31, 2001
Non-trading ................................... $ -- $ (4)
</Table>
Price-risk sensitivities were calculated by assuming an across-the-board 10
percent adverse change in foreign currency rates.
22
INTEREST RATE RISK
The fair value gain or loss of outstanding interest rate swaps and the
change in fair value that would be expected from a 10 percent adverse interest
rate change are shown in the following table:
<Table>
<Caption>
CHANGE IN FAIR VALUE
FROM 10% ADVERSE
FAIR VALUE INTEREST RATE CHANGE
----------- --------------------
(IN MILLIONS)
INTEREST RATE DERIVATIVES
AT MARCH 31, 2002
Fixed rate to floating rate
Notes due 2009 ................................. $ (41) $ (67)
Notes due 2029 ................................. (88) (169)
----------- -----------
Fixed rate to floating rate ...................... (129) (236)
Floating rate to fixed rate ...................... (6) (1)
----------- -----------
Total ............................................ $ (135) $ (237)
=========== ===========
AT DECEMBER 31, 2001
Fixed rate to floating rate
Notes due 2009 ................................. $ (35) $ (52)
Notes due 2029 ................................. (74) (134)
----------- -----------
Fixed rate to floating rate ...................... (109) (186)
Floating rate to fixed rate ...................... (8) (1)
----------- -----------
Total ............................................ $ (117) $ (187)
=========== ===========
</Table>
23
PART II
OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
There have been no material developments with respect to the legal
proceedings previously reported in the 2001 Annual Report on Form 10-K, except
as described below.
During August 2001, the United States Environmental Protection Agency
(USEPA) issued a Notice of Violation (NOV) to Conoco for certain alleged
violations of the federal fuels regulations of the Clean Air Act. The NOV arises
from a June 1998 USEPA audit of each of Conoco's Billings, Denver, Lake Charles
and Ponca City refineries and its Conoco Center complex in Houston, Texas.
Conoco settled this matter on March 11, 2002 by paying the USEPA a $119,000
penalty and agreeing to take future preventative measures.
An accrual of $112 million was recorded during the fourth quarter of 2001
for a litigation settlement related to certain discontinued chemicals businesses
for which we assumed responsibility for claims as a result of the separation
agreement with DuPont. As of the end of April 2002, we paid $98 million of the
accrual, with the remainder to be paid during May 2002. Additionally, we
anticipate receiving insurance proceeds of $28 million over the next three
months.
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; claims for damages resulting
from leaking underground storage tanks; and related toxic tort claims. As a
result of the 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
and cash flows in the period in which they are recognized.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
On March 12, 2002, Conoco held a special meeting of stockholders for the
purpose of adopting the Agreement and Plan of Merger, dated as of November 18,
2001, by and among Conoco, Phillips Petroleum Company, a Delaware corporation,
ConocoPhillips, a Delaware corporation which we refer to as "New Parent," C
Merger Corp., a Delaware corporation and a wholly owned subsidiary of New
Parent, and P Merger Corp., a Delaware corporation and a wholly owned subsidiary
of New Parent. Stockholders approved the proposal as follows:
<Table>
For............................................................................ 482,521,156
Against........................................................................ 16,015,270
Abstain........................................................................ 2,418,143
Not voted...................................................................... 124,911,081
</Table>
ITEM 5. OTHER INFORMATION
DISCLOSURE REGARDING FORWARD-LOOKING INFORMATION
This quarterly report on Form 10-Q 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," "intends," "plans," "projects," "believes,"
"estimates," "will," "should," and similar expressions.
We have based the forward-looking statements relating to our operations on
our current expectations and on estimates and projections about Conoco and the
petroleum industry in general. We caution you that these statements are not
guarantees of future performance and involve risks, uncertainties and
assumptions that we cannot predict with certainty. In addition, we have based
many of these forward-looking statements on assumptions about future events that
may prove to be inaccurate. Accordingly, our actual outcomes and results may
differ materially from
24
what we have expressed or forecasted in the forward-looking statements. Any
differences could result from a variety of factors including the following:
o fluctuations in crude oil and natural gas prices and refining and
marketing margins;
o 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;
o unsuccessful exploratory and development drilling activities;
o failure of new products and services to achieve market acceptance;
o unexpected cost increases or technical difficulties in constructing or
modifying company manufacturing and refining facilities;
o unexpected difficulties in mining, manufacturing, transporting or
refining synthetic crude oil;
o ability to meet government regulations;
o potential disruption or interruption of our production facilities due
to accidents, political events or terrorism;
o international monetary conditions and exchange controls;
o liability for remedial actions under environmental regulations;
o liability resulting from litigation;
o general domestic and international economic and political conditions,
including armed hostilities and terrorism; or
o changes in tax and other laws applicable to our business.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) EXHIBITS
The exhibit index filed with this Form 10-Q is on page 27.
(b) REPORTS ON FORM 8-K
1. In a current report on Form 8-K dated February 25, 2002, we filed
pursuant to Item 7 of Form 8-K our 2001 audited financial statements.
2. In a current report on Form 8-K dated February 26, 2002, we reported
pursuant to Item 5 of Form 8-K that Conoco and Phillips Petroleum
Company had announced five key members of the management team for
ConocoPhillips. We also filed as an exhibit pursuant to Item 7 of Form
8-K the joint press release dated February 26, 2002 that we issued
with Phillips making the announcement.
3. In a current report on Form 8-K dated March 12, 2002, we reported
pursuant to Item 5 of Form 8-K that the shareholders of Conoco voted
to approve the proposed merger with Phillips. We also filed as an
exhibit pursuant to Item 7 of Form 8-K our press release dated March
12, 2002 announcing such approval.
25
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.
CONOCO INC.
(Registrant)
By: /s/ W. DAVID WELCH
------------------------------------
Vice President, Controller and
Principal Accounting Officer
Date: May 8, 2002
26
EXHIBIT INDEX
<Table>
<Caption>
EXHIBIT NUMBER DESCRIPTION
- -------------- -----------
12* Computation of Ratio of Earnings to Fixed Charges.
18* Letter re Change in Method of Accounting for the Cost of Planned Major Maintenance
Expenditures.
</Table>
* Filed herein.
27