EXHIBIT 99
SELECTED FINANCIAL DATA CONOCOPHILLIPS
(FORMERLY PHILLIPS PETROLEUM COMPANY)
<Table>
<Caption>
Millions of Dollars Except Per Share Amounts
-----------------------------------------------------------------
2001 2000 1999 1998 1997
---------- ---------- ---------- ---------- ----------
Sales and other
operating revenues $ 26,341 22,265* 15,090* 12,940* 16,187*
Income from continuing
operations 1,632 1,847 602 230 950
Per common share
Basic 5.57 7.26 2.38 .89 3.61
Diluted 5.53 7.20 2.36 .88 3.58
Net income 1,661 1,862 609 237 959
Per common share
Basic 5.67 7.32 2.41 .92 3.64
Diluted 5.63 7.26 2.39 .91 3.61
Pro forma income from
continuing operations
assuming the new
turnaround accounting
method is applied
retroactively 1,632 1,836 602 235 962
Per common share
Basic 5.57 7.21 2.38 .91 3.65
Diluted 5.53 7.16 2.36 .90 3.62
Pro forma net income
assuming the new
turnaround accounting
method is applied
retroactively 1,633 1,851 609 242 971
Per common share
Basic 5.57 7.27 2.41 .94 3.69
Diluted 5.54 7.22 2.39 .93 3.66
Total assets 35,217 20,509 15,201 14,216 13,860
Long-term debt 8,645 6,622 4,271 4,106 2,775
Company-obligated
mandatorily
redeemable preferred
securities of
Phillips 66 Capital
Trusts I and II 650 650 650 650 650
Cash dividends declared
per common share 1.40 1.36 1.36 1.36 1.34
---------- ---------- ---------- ---------- ----------
</Table>
*Restated to include excise taxes on petroleum products sales.
See Management's Discussion and Analysis of Financial Condition and Results of
Operations for a discussion of factors that will enhance an understanding of
this data. All years have been restated to reflect discontinued operations (see
Note 25 in the Notes to Financial Statements).
1
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
March 15, 2002
Management's Discussion and Analysis is ConocoPhillips' analysis of its
financial performance and of significant trends that may affect future
performance. It should be read in conjunction with the financial statements and
notes, and supplemental oil and gas disclosures. It contains forward-looking
statements including, without limitation, statements relating to the company's
plans, strategies, objectives, expectations, intentions, and resources that are
made pursuant to the "safe harbor" provisions of the Private Securities
Litigation Reform Act of 1995. The words "intends," "believes," "expects,"
"plans," "scheduled," "anticipates," "estimates," and similar expressions
identify forward-looking statements. The company does not undertake to update,
revise or correct any of the forward-looking information. Readers are cautioned
that such forward-looking statements should be read in conjunction with the
company's disclosures under the heading: "CAUTIONARY STATEMENT FOR THE PURPOSES
OF THE 'SAFE HARBOR' PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT
OF 1995," beginning on page 54.
RESULTS OF OPERATIONS
The following is a discussion of the results of operations of ConocoPhillips
(ConocoPhillips or the company), as successor to Phillips Petroleum Company
(Phillips), for the three years ended December 31, 2001, 2000 and 1999, and
reflects the following changes to the information included in the Phillips
Petroleum Company Annual Report on Form 10-K for the year ended December 31,
2001:
o The restatement as discontinued operations of the Woods Cross refinery
and associated wholesale marketing activities; and
o The realignment of operating segments, including
o transferring the natural gas liquids fractionation and marketing
businesses from the Refining and Marketing segment to the
Midstream segment;
o transferring the fuels technology business from the Refining and
Marketing segment to the newly created Emerging Businesses
segment; and
2
o transferring all discontinued operations to Corporate and Other.
On August 30, 2002 (the Merger Date), Phillips and Conoco Inc. (Conoco) combined
their businesses by merging with separate acquisition subsidiaries of
ConocoPhillips. For accounting purposes, Phillips was treated as the acquirer of
Conoco, and ConocoPhillips was treated as the successor of Phillips.
Accordingly, references to ConocoPhillips in the following discussion for
periods prior to the Merger Date are to the results of operations and financial
condition of Phillips only, and do not include any information relating to
Conoco for the periods presented.
CONSOLIDATED RESULTS
A summary of ConocoPhillips' net income by business segment follows:
<Table>
<Caption>
Millions of Dollars
--------------------------------
Years Ended December 31 2001 2000 1999
-------- -------- --------
Exploration and Production (E&P) $ 1,699 1,945 570
Midstream (Formerly Gas Gathering,
Processing and Marketing) 120 162 135
Refining and Marketing (R&M)(Formerly
Refining, Marketing and Transportation) 418 237 46
Chemicals (128) (46) 164
Emerging Businesses (12) -- --
Corporate and Other (436) (436) (306)
-------- -------- --------
Net income $ 1,661 1,862 609
======== ======== ========
</Table>
Net income is affected by transactions, defined by Management and termed
"special items," which are not representative of the company's ongoing
operations. These special items can obscure the underlying operating results for
a period and affect comparability of operating results between periods. The
following table summarizes the gains/(losses), on an after-tax basis, from
special items included in the company's net income:
3
<Table>
<Caption>
Millions of Dollars
--------------------------------
Years Ended December 31 2001 2000 1999
-------- -------- --------
Property impairments* $ (25) (95) (34)
Net gains on asset sales 16 164 73
Pending claims and settlements 25 (16) 35
Equity companies' special items** (67) (98) --
Extraordinary item (10) -- --
Cumulative effect of accounting change 28 -- --
Discontinued operations*** 11 15 7
Other items (15) (9) (13)
-------- -------- --------
Total special items $ (37) (39) 68
======== ======== ========
</Table>
*See Note 9 to the financial statements for additional information.
**Primarily property impairments recorded by the company's chemicals joint
venture.
***See Note 25 to the financial statements for additional information.
Excluding the special items listed above, the company's net operating income by
business segment was:
<Table>
<Caption>
Millions of Dollars
--------------------------------
Years Ended December 31 2001 2000 1999
-------- -------- --------
E&P $ 1,693 1,865 526
Midstream 120 161 136
R&M 431 243 53
Chemicals (106) 53 146
Emerging Businesses (12) -- --
Corporate and Other (428) (421) (320)
-------- -------- --------
Net operating income $ 1,698 1,901 541
======== ======== ========
</Table>
2001 vs. 2000
ConocoPhillips' net income was $1,661 million in 2001, an 11 percent decline
from record net income of $1,862 million in 2000. Special items reduced net
income $37 million in 2001 and $39 million in 2000. After excluding special
items, net operating income was $1,698 million in 2001, compared with $1,901
million in 2000.
The 11 percent decrease in net operating income in 2001 was primarily
attributable to lower results from the E&P, Midstream and Chemicals segments.
The E&P segment's results were negatively affected by a 17 percent decrease in
its average crude oil price in 2001, while Midstream results decreased due to
lower natural gas liquids prices. The Chemicals segment continued to experience
a difficult market environment in 2001, marked by low product margins and
industry overcapacity resulting in reduced output. R&M's net operating income
increased 77 percent in 2001,
4
reflecting improved petroleum products margins, as well as the acquisition of
Tosco Corporation in September 2001. See Note 3--Acquisition of Tosco
Corporation in the Notes to Financial Statements for additional information on
the acquisition.
2000 vs. 1999
ConocoPhillips' net income was $1,862 million in 2000, compared with $609
million in 1999. Special items reduced net income $39 million in 2000, while
benefiting 1999 net income by $68 million. After excluding special items, net
operating income was $1,901 million in 2000, compared with $541 million in 1999.
The 251 percent increase in 2000 net operating income, compared with 1999, was
the result of higher earnings in ConocoPhillips' E&P, Midstream and R&M
segments. The E&P segment benefited from an 89 percent increase in crude oil
production, mainly the result of the company's acquisition of Atlantic Richfield
Company's (ARCO) Alaskan businesses in late-April 2000. The E&P segment also
benefited from significantly higher crude oil and natural gas prices--up 62
percent and 46 percent, respectively, over 1999 levels. The Midstream segment's
net operating income increased 18 percent in 2000, primarily reflecting higher
natural gas liquids prices.
R&M's net operating income increased 358 percent in 2000, compared with 1999,
mainly due to higher refining margins for gasoline and distillates and a
reduction in last-in, first-out inventories, partly offset by increased fuel and
utility costs at the refineries. Chemicals net operating income decreased 64
percent in 2000, reflecting weak margins in most major product lines, along with
higher fuel and utility costs. Corporate costs increased 32 percent in 2000,
primarily due to higher interest expense and higher foreign currency transaction
losses, compared with 1999.
INCOME STATEMENT ANALYSIS
2001 vs. 2000
On September 14, 2001, ConocoPhillips closed on the acquisition of Tosco
Corporation (Tosco). Accordingly, ConocoPhillips' consolidated income statement
for the year ended December 31, 2001, includes activity related to Tosco after
September 14. This transaction significantly increased operating revenues,
purchase costs, and other income statement line items. See Note 3--Acquisition
of Tosco Corporation in the Notes to Financial Statements for additional
information.
5
On March 31, 2000, ConocoPhillips and Duke Energy Corporation (Duke Energy)
contributed their midstream gas gathering, processing and marketing businesses
to Duke Energy Field Services, LLC (DEFS). Effective July 1, 2000,
ConocoPhillips and Chevron Corporation, which, following its merger with Texaco
Inc. was renamed ChevronTexaco Corporation (ChevronTexaco), contributed their
chemicals businesses, excluding ChevronTexaco's Oronite business, to Chevron
Phillips Chemical Company LLC (CPChem). Both of these joint ventures are being
accounted for using the equity method of accounting, which significantly affects
how the Midstream and Chemicals segments' operations are reflected in
ConocoPhillips' consolidated income statement. Under the equity method of
accounting, ConocoPhillips' share of a joint venture's net income is recorded in
a single line item on the income statement: "Equity in earnings of affiliated
companies." Correspondingly, the other income statement line items (for example,
operating revenues, operating costs, etc.) include activity related to the
Midstream and Chemicals operations only up to the effective dates of the joint
ventures.
Sales and other operating revenues increased 18 percent in 2001, primarily due
to the Tosco acquisition and increased crude oil production. These items were
partially offset by the use of equity-method accounting for the DEFS and CPChem
joint ventures, as well as a reduction in revenues attributable to certain
non-core assets sold at year-end 2000. The company now includes excise taxes on
the sale of petroleum products in operating revenues, with the corresponding
expense included in taxes other than income taxes. All prior periods presented
have been restated to reflect this change in presentation.
Equity in earnings of affiliated companies decreased 64 percent in 2001. In the
2001 period, ConocoPhillips incurred a before-tax equity loss from its
investment in CPChem of $240 million. CPChem continued to face a difficult
market environment in 2001. See the discussion of the Chemicals segment's
results of operations for additional information. ConocoPhillips' equity
earnings related to DEFS were higher in 2001, as a result of a full year's
activity in 2001, compared with only nine months in 2000. Equity earnings in
2001 benefited from a full year's operations at Merey Sweeny, L.P., a
50-percent-owned equity company that owns and operates the coker unit at the
Sweeny, Texas, refinery.
Other income decreased 65 percent in 2001, primarily attributable to lower net
gains on asset sales in 2001 compared with 2000.
6
Purchased crude oil and products increased 21 percent in 2001, mainly the result
of the Tosco acquisition. The Tosco impact was partially offset by the use of
equity-method accounting for the DEFS and CPChem joint ventures, along with
lower crude oil acquisition costs at the company's heritage refineries.
Management defines controllable costs as production and operating expenses;
selling, general and administrative expenses; and the general administrative,
geological, geophysical and lease rentals component (G&G) of exploration
expenses. Controllable costs, adjusted to exclude G&G, increased 30 percent in
2001. The increase was primarily due to the impact of the Tosco acquisition,
along with higher costs in the company's Alaska E&P operations, which were owned
and operated for a full year in 2001. These items were partially offset by the
use of equity-method accounting for the DEFS and CPChem joint ventures.
Exploration expenses were 3 percent higher in 2001, reflecting higher G&G and
leasehold impairments, partially offset by lower foreign dry hole costs.
Depreciation, depletion and amortization (DD&A) increased 18 percent in 2001,
reflecting the impact of the Tosco acquisition and a full year's DD&A associated
with the Alaska operations acquired in April and August of 2000. These items
were partly offset by the use of equity-method accounting for the DEFS and
CPChem joint ventures, and a reduction in DD&A resulting from asset dispositions
in late 2000. ConocoPhillips recorded property impairments of $26 million in
2001, compared with $100 million in 2000. See Note 9--Property Impairments in
the Notes to Financial Statements for additional information on property
impairments.
Taxes other than income taxes increased 42 percent in 2001, reflecting higher
excise taxes on petroleum products sales, mainly due to the Tosco acquisition.
Production and property taxes were also higher in 2001, primarily the result of
a full year's ownership and production in Alaska.
The company added a new line to its income statement in 2001 to disclose the
accretion of discounted liabilities. The amount of $14 million in 2001 relates
to environmental obligations acquired in the Alaska and Tosco acquisitions.
Interest and debt expense decreased 8 percent in 2001, as ConocoPhillips
benefited from lower short-term interest rates and higher interest amounts being
capitalized--mainly related to projects in Alaska, the Timor Sea and Venezuela,
partially offset by the interest associated with debt acquired in the Tosco
acquisition.
7
Foreign currency losses of $11 million were incurred in 2001,
compared with losses of $58 million in 2000. Preferred dividend requirements of
capital trusts and minority interests decreased slightly in 2001 from 2000.
2000 vs. 1999
Sales and other operating revenues increased 48 percent in 2000, compared with
1999. The increased revenues reflect higher sales prices in 2000 for petroleum
products, crude oil and natural gas, as well as the impact of significantly
higher crude oil production and sales volumes resulting from the Alaskan
acquisition. These benefits were partially offset by the reduction in operating
revenues as a result of using the equity method of accounting for the new DEFS
and CPChem joint ventures.
Equity in earnings of affiliated companies increased 13 percent in 2000,
compared with 1999, primarily due to the formation of the DEFS and CPChem joint
ventures in 2000. Other income increased 54 percent in 2000, reflecting a
higher net gain on asset sales in 2000. Major asset sales in 2000 included the
company's coal operations and the Zama operations in Canada.
Total costs and expenses increased 33 percent in 2000, compared with 1999,
primarily due to higher purchase prices for crude oil and petroleum products and
the impact of the Alaskan acquisition, partially offset by the use of the equity
method of accounting for the DEFS and CPChem joint ventures.
8
SEGMENT RESULTS
E&P
<Table>
<Caption>
2001 2000 1999
---------- ---------- ----------
Millions of Dollars
OPERATING INCOME
Net income $ 1,699 1,945 570
Less special items 6 80 44
---------- ---------- ----------
Net operating income $ 1,693 1,865 526
========== ========== ==========
Dollars Per Unit
AVERAGE SALES PRICES
Crude oil (per barrel)
United States $ 23.57 28.83 15.64
Foreign 24.16 28.42 18.26
Total consolidated 23.77 28.65 17.69
Equity affiliate in Venezuela 12.36 -- --
Worldwide 23.74 28.65 17.69
Natural gas--lease
(per thousand cubic feet)
United States 3.56 3.47 2.03
Foreign 2.60 2.56 2.37
Worldwide 3.23 3.13 2.15
---------- ---------- ----------
AVERAGE PRODUCTION COSTS PER
BARREL OF OIL EQUIVALENT
United States $ 5.52 5.27 4.16
Foreign 2.70 2.85 3.27
Total consolidated 4.60 4.29 3.66
Equity affiliate in Venezuela 2.74 -- --
Worldwide 4.60 4.29 3.66
---------- ---------- ----------
FINDING AND DEVELOPMENT COSTS PER
BARREL OF OIL EQUIVALENT
United States $ 5.15 2.78 5.08
Foreign* 6.80 1.17 4.72
Worldwide* 5.97 2.41 4.81
---------- ---------- ----------
*Includes ConocoPhillips' share of equity affiliate.
Millions of Dollars
WORLDWIDE EXPLORATION EXPENSES
General administrative; geological
and geophysical; and lease rentals $ 207 168 133
Leasehold impairment 51 39 24
Dry holes 48 91 68
---------- ---------- ----------
$ 306 298 225
========== ========== ==========
</Table>
9
<Table>
<Caption>
2001 2000 1999
-------- -------- --------
Thousands of Barrels Daily
OPERATING STATISTICS
Crude oil produced
United States 373 241 50
Norway 117 114 99
United Kingdom 19 25 34
Nigeria 30 24 20
China 11 12 10
Canada 1 6 7
Timor Sea 6 7 5
Denmark 3 4 4
Venezuela 1 4 2
-------- -------- --------
Total consolidated 561 437 231
Equity affiliate in Venezuela 2 -- --
-------- -------- --------
563 437 231
======== ======== ========
Natural gas liquids produced
United States* 26 20 2
Norway 5 5 4
Other areas 4 4 5
-------- -------- --------
35 29 11
======== ======== ========
*For 2001 and 2000, includes 15,000 and 12,000 barrels per day in Alaska,
respectively, that were sold from the Prudhoe Bay lease to the Kuparuk lease
for reinjection to enhance crude oil production.
Millions of Cubic Feet Daily
Natural gas produced*
United States 917 928 950
Norway 130 136 126
United Kingdom 178 214 220
Canada 18 83 91
Nigeria 41 33 6
Australia 51 -- --
-------- -------- --------
1,335 1,394 1,393
======== ======== ========
*Represents quantities available for sale. Excludes gas equivalent of natural
gas liquids shown above.
Liquefied natural gas sales 126 125 123
-------- -------- --------
</Table>
10
2001 vs. 2000
Net operating income from ConocoPhillips' E&P segment decreased 9 percent in
2001, as the positive impact of increased crude oil production was more than
offset by lower crude oil prices, and, to a lesser extent, lower natural gas
production due mainly to asset dispositions in Canada.
ConocoPhillips' average worldwide crude oil sales price was $23.74 per barrel in
2001, a 17 percent decrease from $28.65 in 2000. Crude oil prices have generally
trended lower since peaking in the fourth quarter of 2000. Slowing demand growth
due to the global economic slowdown and concern over worldwide production and
storage levels contributed to the slide in crude prices in 2001. Natural gas
prices began 2001 at historically high levels, but also trended lower during the
remainder of the year, with the company's December 2001 average price at $2.34
per thousand cubic feet. The company expects that its average natural gas sales
price in the first quarter of 2002 will be significantly lower than the $4.90
per thousand cubic feet reported in the first quarter of 2001.
ConocoPhillips' proved reserves at year-end 2001 were 5.13 billion barrels of
oil equivalent, a 2 percent increase over 5.02 billion barrels at year-end 2000.
ConocoPhillips replaced 135 percent of its worldwide hydrocarbon production in
2001, and has replaced an average of 359 percent over the last five years.
2000 vs. 1999
Net operating income from ConocoPhillips' E&P segment increased 255 percent in
2000, compared with 1999. The increase reflects higher sales prices for crude
oil and natural gas, higher crude oil production as a result of the Alaskan
acquisition, and higher production from the Norwegian North Sea.
ConocoPhillips' average worldwide crude oil price was $28.65 per barrel in 2000,
compared with $17.69 in 1999. Crude oil prices trended upward through most of
2000 on demand growth, limited worldwide supply, and, in the fall of 2000, on
concern over heating fuel stock levels heading into the winter months. Crude oil
price levels eased somewhat late in 2000, as major crude oil exporting countries
increased output and global demand growth began to slow.
E&P's proved reserves at year-end 2000 were 5.02 billion barrels of oil
equivalent, more than double the year-end 1999 level of 2.23 billion barrels.
The sharp increase was primarily the result of the Alaskan acquisition, as well
as the recording of net proved reserves associated with the equity-affiliate
Hamaca
11
heavy-oil project in Venezuela and Phase I of the Peng Lai 19-3 development
offshore China. ConocoPhillips replaced 1,128 percent of its worldwide
hydrocarbon production in 2000, compared with 114 percent in 1999.
U.S. E&P
- --------
<Table>
<Caption>
Millions of Dollars
------------------------------
2001 2000 1999
-------- -------- --------
OPERATING INCOME
Net income $ 1,342 1,388 379
Less special items 3 40 63
-------- -------- --------
Net operating income $ 1,339 1,348 316
======== ======== ========
Alaska $ 868 829 71
Lower 48 471 519 245
-------- -------- --------
$ 1,339 1,348 316
======== ======== ========
</Table>
2001 vs. 2000
Net operating income from the company's U.S. E&P operations decreased slightly
in 2001. The 2001 results reflect a 55 percent increase in crude oil production,
due to a full year's production from the Alaskan operations acquired in April
2000, as well as increased production due to the startup of the Alpine field in
Alaska in December 2000. The benefit of increased crude oil production was
offset by lower U.S. crude oil prices, which declined 18 percent in 2001. U.S.
natural gas production declined slightly in 2001, reflecting field declines and
asset dispositions.
Special items in 2001 included a net favorable result from claims and
settlements, partially offset by losses incurred on the disposition of assets.
Special items in 2000 primarily consisted of a net gain on asset sales of $44
million (most of which was related to the disposition of the company's coal and
lignite operations) and favorable contingency settlements, partially offset by
$9 million in property impairments.
2000 vs. 1999
Net operating income increased 327 percent in 2000, compared with 1999. The
increase was attributable to the Alaskan acquisition, as well as to higher crude
oil, natural gas, and natural gas liquids prices.
12
On April 26, 2000, ConocoPhillips purchased all of ARCO's Alaskan businesses,
other than three double-hulled tankers under construction and certain pipeline
assets, which were acquired August 1, 2000. Results of operations for the
acquired businesses are included in U.S. E&P's results from April 26, and August
1, 2000, respectively.
U.S. crude oil production increased 382 percent in 2000, compared with 1999, due
to the Alaskan acquisition. Lower 48 production continued to trend downward in
2000, reflecting property dispositions and field declines. U.S. natural gas
production decreased 2 percent in 2000, compared with 1999, as property
dispositions and field declines were mostly offset by property acquisitions.
Special items in 1999 primarily consisted of net gains of $57 million on asset
sales and a favorable pricing adjustment of $8 million, partially offset by
property impairments.
Foreign E&P
- -----------
<Table>
<Caption>
Millions of Dollars
------------------------------
2001 2000 1999
-------- -------- --------
OPERATING INCOME
Net income $ 357 557 191
Less special items 3 40 (19)
-------- -------- --------
Net operating income $ 354 517 210
======== ======== ========
</Table>
2001 vs. 2000
Net operating income from ConocoPhillips' foreign E&P operations decreased 32
percent in 2001. The decrease was primarily the result of lower crude oil and
natural gas production volumes, as well as lower crude oil prices. After-tax
foreign currency gains of $2 million were included in foreign E&P's net
operating income in 2001, compared with losses of $10 million in 2000.
Foreign crude oil production declined 3 percent in 2001, mainly due to lower
production in the U.K. North Sea, Venezuela and Canada, partly offset by
increased production from Norway and Nigeria. Canadian and Venezuelan crude oil
production declined relative to a year ago due to asset dispositions. Production
in the U.K. North Sea decreased on normal field declines. Production from Norway
improved in 2001 due to improved processing reliability and well workovers,
while Nigerian production increased on development activities and higher quotas.
13
Foreign natural gas production declined 10 percent in 2001, primarily the result
of the Canadian asset dispositions and lower U.K. North Sea output noted above,
partially offset by higher production in Nigeria and new natural gas production
from offshore western Australia.
Special items in 2001 consisted of a net gain on asset dispositions and
favorable settlements, mostly offset by a $23 million impairment of the Siri
field, offshore Denmark. See Note 9--Property Impairments in the Notes to
Financial Statements for additional information on the Siri impairment.
ConocoPhillips sold its interests in the Ann, Alison and Audrey fields located
in the U.K. North Sea in 2001, and also traded its interests in the Kate and
Tornado prospects for an additional interest in the Britannia field and an
interest in another property. Special items in 2000 included a favorable
deferred-tax adjustment resulting from a tax law change in Australia and a net
gain on property dispositions of $118 million, related to the disposition of the
Zama area fields in Canada. Special items in 2000 also included an $86 million
impairment of the Ambrosio field in Venezuela. See Note 9--Property Impairments
in the Notes to Financial Statements for additional information on this
impairment.
2000 vs. 1999
The company's foreign E&P operations generated net operating income of $517
million in 2000, a 146 percent increase over 1999's net operating income of $210
million. The increase was primarily due to higher crude oil prices, and, to a
lesser extent, higher natural gas prices and increased crude oil production in
the Norwegian North Sea and Nigeria. After-tax foreign currency transaction
losses of $10 million were included in foreign E&P's net operating income in
2000, compared with gains of $3 million in 1999.
Foreign crude oil production increased 8 percent in 2000, compared with 1999, as
higher production in most foreign areas was partially offset by lower production
in the U.K. sector of the North Sea. Production in the Norwegian sector of the
North Sea benefited from an improved operating performance in 2000. In the U.K.
North Sea, operating interruptions at the Janice field, as well as lower
production from R-Block and J-Block, contributed to the reduced crude oil
production. Nigeria production increased on higher quota levels and development
drilling.
14
Foreign natural gas production increased 5 percent in 2000, compared with 1999,
primarily due to increased production in Nigeria. In mid-1999, ConocoPhillips'
Nigerian operations began commercial delivery of natural gas to a third-party
liquefied natural gas plant on Bonny Island.
Special items in 1999 primarily consisted of property impairments of $27
million, partially offset by a net gain on asset sales of $15 million.
MIDSTREAM
<Table>
<Caption>
2001 2000 1999
-------- -------- --------
Millions of Dollars
OPERATING INCOME
Net income $ 120 162 135
Less special items -- 1 (1)
-------- -------- --------
Net operating income $ 120 161 136
======== ======== ========
Dollars Per Barrel
AVERAGE SALES PRICES
U.S. natural gas liquids* $ 18.77 21.83 12.56
-------- -------- --------
Millions of Cubic Feet Daily
OPERATING STATISTICS**
Raw gas throughput 2,363 2,089 1,758
-------- -------- --------
Thousands of Barrels Daily
Natural gas liquids production 120 131 156
-------- -------- --------
</Table>
*The price for 1999 represents ConocoPhillips' realized price prior to the
formation of DEFS. The price for 2000 is an estimate based on a weighted
average of ConocoPhillips' realized price in the first quarter of 2000 and
DEFS' index prices for the remainder of 2000. DEFS' prices are based on index
prices from the Mont Belvieu and Conway market hubs that are weighted by DEFS'
natural-gas-liquids-component and location mix.
**Production and throughput volumes for 1999 represent ConocoPhillips'
production and throughput prior to the formation of DEFS. The volumes in 2000
are estimates based on a weighted average of ConocoPhillips' production and
throughput in the first quarter of 2000 and ConocoPhillips' 30.3 percent share
of DEFS' production and throughput for the remainder of 2000. The 2001 volumes
are ConocoPhillips' 30.3 percent share of DEFS' production and throughput.
2001 vs. 2000
On March 31, 2000, ConocoPhillips combined its gas gathering, processing and
marketing business with Duke Energy's gas gathering, processing, marketing and
natural gas liquids business into Duke Energy Field Services, LLC (DEFS).
ConocoPhillips is using equity-method accounting for its 30.3 percent interest
in DEFS. Since March 31, 2000, ConocoPhillips' Midstream segment has included
its equity investment in DEFS.
15
Net operating income from the Midstream segment decreased 25 percent in 2001,
primarily the result of a 14 percent decline in natural gas liquids prices. In
addition, the Midstream segment's results were affected by the lack of interest
charges in the first quarter of 2000 prior to the formation of DEFS. DEFS incurs
interest expense in connection with financing incurred upon formation to fund
cash distributions to the parent entities. Prior to the formation of DEFS, the
Midstream segment did not have interest expense. Included in the Midstream
segment's earnings in 2001 was a benefit of $36 million, representing the
amortization of the basis difference between the book value of ConocoPhillips'
contribution to DEFS and its 30.3 percent equity interest in DEFS. The
corresponding amount for 2000 was $27 million. See Note 6--Investments and
Long-Term Receivables in the Notes to Financial Statements for additional
information on the basis difference.
There were no special items in the Midstream segment in 2001. Special items in
2000 consisted of special current and deferred state tax items related to the
closing of the DEFS transaction and a gain on DEFS' disposition of assets,
mostly offset by work force reduction charges.
2000 vs. 1999
Net operating income from the Midstream segment increased 18 percent in 2000,
compared with 1999. The improved results were primarily due to a 74 percent
increase in natural gas liquids prices in 2000, partially offset by interest
expense incurred by DEFS, but not present in the Midstream segment in 1999. In
addition, results were lower for the natural gas liquids fractionation business,
as a portion of this business was contributed to CPChem on July 1, 2000.
Special items in 1999 consisted of work force reduction charges.
16
R&M
<Table>
<Caption>
2001 2000 1999
-------- -------- --------
Millions of Dollars
OPERATING INCOME
Net income $ 418 237 46
Less special items (13) (6) (7)
-------- -------- --------
Net operating income $ 431 243 53
======== ======== ========
Dollars Per Gallon
U.S. AVERAGE SALES PRICES*
Automotive gasoline
Wholesale $ .84 .92 .60
Retail .96 1.07 .75
Distillates .78 .88 .53
-------- -------- --------
*Excludes excise taxes.
Thousands of Barrels Daily
OPERATING STATISTICS
Refining operations
United States
Rated crude oil capacity 732* 335 330
Crude oil runs 686 303 326
Capacity utilization (percent) 94% 90 99
Refinery production 795 365 385
Foreign
Rated crude oil capacity 22* -- --
Crude oil runs 20 -- --
Capacity utilization (percent) 91% -- --
Refinery production 19 -- --
-------- -------- --------
Petroleum products outside sales
United States
Automotive gasoline 537 298 285
Aviation fuels 78 41 36
Distillates 225 130 126
Other products 220 50 34
-------- -------- --------
1,060 519 481
Foreign 10 43 37
-------- -------- --------
1,070 562 518
======== ======== ========
</Table>
*The weighted-average crude oil capacity for the period included the refineries
acquired in the Tosco acquisition on September 14, 2001. Actual capacity at
December 31, 2001, was 1,656 thousand barrels per day in the United States, and
75 thousand barrels per day from foreign operations (Ireland).
17
2001 vs. 2000
Net operating income from the R&M segment increased 77 percent in 2001. On
September 14, 2001, ConocoPhillips closed on the acquisition of Tosco. This
transaction significantly increased the size of ConocoPhillips' R&M segment,
with R&M's assets increasing from $3.3 billion at year-end 2000 to $17 billion
at year-end 2001. R&M results included the acquired Tosco operations after
September 14, contributing $87 million to 2001 results.
In addition to the Tosco acquisition, R&M's earnings benefited from higher
gasoline and distillates margins, particularly during the second quarter of
2001. Negatively affecting R&M results for the year were higher utility costs at
the company's heritage refineries, resulting from higher natural gas prices
experienced in the first half of 2001. The Sweeny refinery's 2001 earnings
benefited from the coker unit that was started up in late 2000. The coker unit
allows for the processing of heavier, lower-cost crude oil, which reduced crude
oil purchase costs and contributed to the improved gasoline and distillates
margins experienced during 2001. R&M's earnings benefited $60 million from an
inventory liquidation in 2000.
ConocoPhillips' refineries (including those acquired in the Tosco transaction
since the acquisition date) processed an average of 706,000 barrels per day of
crude oil in 2001, yielding a 94 percent capacity utilization rate. This
compares with 303,000 barrels per day and a utilization rate of 90 percent in
2000. The Tosco acquisition accounted for 378,000 barrels per day in 2001.
Average barrels of crude oil processed per day will increase significantly in
2002 with a full year's ownership and operation of the Tosco refineries.
Special items in 2001 included a cumulative effect of a change in accounting
method that increased R&M net income by $26 million. Effective January 1, 2001,
ConocoPhillips changed its method of accounting for the costs of major
maintenance turnarounds from the accrue-in-advance method to the
expense-as-incurred method. See Note 2--Extraordinary Item and Accounting Change
in the Notes to Financial Statements for additional information on the
accounting change, including the pro forma impact of the change on 2000 and
1999. Other special items in 2001 included a $27 million write-down of
inventories to market value and work force reduction charges. Special items in
2000 mainly consisted of contingency related items.
18
2000 vs. 1999
Net operating income from ConocoPhillips' R&M segment increased 358 percent in
2000, compared with 1999. The increase was primarily attributable to improved
financial results from the company's refineries and branded marketing
operations, which experienced higher gasoline and distillates margins. In
addition, R&M's 2000 earnings benefited $60 million from an inventory
liquidation, compared with $9 million in 1999. The improved margins and
inventory-liquidation gain were partly offset by significant increases in fuel
and utility costs in 2000, resulting from increased prices for natural gas, as
well as the scheduled maintenance shutdowns discussed below.
ConocoPhillips' refineries ran at 90 percent of capacity in 2000, compared with
99 percent in 1999. Capacity utilization in 2000 was impacted by major projects
at the Sweeny and Borger, Texas, refineries. The Sweeny refinery was shut down
in late July 2000 to tie-in a new coker, a vacuum distillation unit, and a
continuous catalytic reformer. The refinery resumed operations in late September
2000, and the new coker was operational early in the fourth quarter. The Borger
refinery underwent a scheduled major maintenance turnaround on one of its two
cat crackers in the third quarter of 2000.
Special items in 1999 consisted primarily of work force reduction charges and
contingency accruals.
CHEMICALS
<Table>
<Caption>
2001 2000 1999
-------- -------- --------
Millions of Dollars
OPERATING RESULTS
Net income (loss) $ (128) (46) 164
Less special items (22) (99) 18
-------- -------- --------
Net operating income (loss) $ (106) 53 146
======== ======== ========
Millions of Pounds
OPERATING STATISTICS
Production*
Ethylene 3,291 3,574 3,262
Polyethylene 1,956 2,230 2,590
Styrene** 456 404 --
Normal alpha olefins 563 293 --
-------- -------- --------
</Table>
*Production volumes for periods after July 1, 2000, include ConocoPhillips' 50
percent share of Chevron Phillips Chemical Company LLC.
**Production was limited in 2001 due to a fire at the St. James, Louisiana,
facility in February 2001. Capacity was restored in October 2001.
19
2001 vs. 2000
On July 1, 2000, ConocoPhillips and ChevronTexaco combined the two companies'
worldwide chemicals businesses, excluding ChevronTexaco's Oronite business, into
a new company, Chevron Phillips Chemical Company LLC (CPChem). ConocoPhillips is
using the equity method of accounting for its 50 percent interest in CPChem.
Since July 1, 2000, ConocoPhillips' Chemicals segment has consisted of its
equity investment in CPChem.
The Chemicals segment posted a net operating loss of $106 million in 2001,
compared with net operating income of $53 million in 2000. Global conditions for
the chemicals and plastics industry remained extremely difficult in 2001.
Worldwide economic slowdowns, including a recessionary economy in the United
States, led to decreased product demand and low product margins across many key
product lines. CPChem's results were negatively affected by low ethylene,
polyethylene and aromatics margins, as well as lower ethylene and polyethylene
production. In addition to low margins and production volumes, 2001 contained
interest charges incurred by CPChem that were not present in the first six
months of 2000 prior to the formation of CPChem.
The difficult marketing environment led to several asset retirements and
impairments being recorded by CPChem in 2001. A developmental reactor at the
Houston Chemical Complex in Pasadena, Texas, was retired; property impairments
were recorded on two polyethylene reactors at the Orange chemical plant in
Orange, Texas; an ethylene unit was retired at the Sweeny complex in Old Ocean,
Texas; an equity affiliate of CPChem recorded a property impairment related to a
polypropylene facility; property impairments were taken on the manufacturing
facility in Puerto Rico; and the benzene and cyclohexane units at the Puerto
Rico facility were retired. In addition, the valuation allowance on the Puerto
Rico facility's deferred tax assets was increased in 2001 so that the deferred
tax assets were fully offset by valuation allowances. ConocoPhillips' share of
the financial impact of these items are included as special items in the
financial results table above. Partially offsetting these impairments was a
business interruption insurance settlement recorded by CPChem and a favorable
deferred tax adjustment recorded by ConocoPhillips that resulted from the Puerto
Rico facility impairment.
Special items in 2000 primarily consisted of ConocoPhillips' share of a property
impairment that CPChem recorded in the fourth quarter related to its Puerto Rico
facility. The impairment was required due to the deteriorating outlook for
future paraxylene market conditions and a shift in strategic direction at the
facility. In addition, a valuation allowance was recorded against a related
deferred tax asset. Combined, these two items
20
resulted in a non-cash $180 million after-tax charge to CPChem's earnings.
ConocoPhillips' share was $90 million. Special items in 2000 also included
ConocoPhillips' share of other, less significant property impairments recorded
by CPChem, as well as contingency related items.
2000 vs. 1999
Net operating income from the Chemicals segment decreased 64 percent in 2000,
compared with 1999.
As a result of the CPChem transaction, earnings from ConocoPhillips' Chemicals
segment were not directly comparable between 2000 and 1999. Some factors
affecting the results for 2000 and 1999 were:
o Net operating income for the first six months of 2000, compared with the
first six months of 1999 (both periods reflecting results prior to the
formation of CPChem), increased 34 percent. The increase was primarily
attributable to higher ethylene, propylene, other chemicals, and plastic
pipe margins and volumes.
o In the third quarter of 2000, margins weakened due to higher feedstock
prices in key product lines. Margins continued to weaken in the fourth
quarter of 2000, with the Chemicals segment posting a net operating loss of
$41 million for the quarter. Of particular importance to CPChem were lower
polyethylene and ethylene margins, as well as higher fuel and utility costs.
o CPChem's earnings in the last half of 2000 included $65 million of interest
charges on financing incurred upon formation to fund operations and cash
distributions to the parent companies. Prior to the formation of CPChem, the
Chemicals segment did not have interest expense.
Special items in 1999 consisted of a favorable deferred tax adjustment and
contingency settlements.
21
EMERGING BUSINESSES
<Table>
<Caption>
Millions of Dollars
-------------------------------
2001 2000 1999
-------- -------- --------
OPERATING RESULTS
Net loss $ (12) -- --
Less special items -- -- --
-------- -------- --------
Net operating loss $ (12) -- --
======== ======== ========
</Table>
The Emerging Businesses segment includes the company's development of new fuels
technologies. Prior to the segment realignment, these activities were included
in the R&M segment.
CORPORATE AND OTHER
<Table>
<Caption>
Millions of Dollars
--------------------------------
2001 2000 1999
-------- -------- --------
OPERATING RESULTS
Corporate and Other $ (436) (436) (306)
Less special items (8) (15) 14
-------- -------- --------
Adjusted Corporate and Other $ (428) (421) (320)
======== ======== ========
Adjusted Corporate and Other includes:
Net interest $ (262) (278) (195)
Corporate general and
administrative expenses (114) (87) (94)
Preferred dividend requirements (38) (40) (42)
Other (14) (16) 11
-------- -------- --------
Adjusted Corporate and Other $ (428) (421) (320)
======== ======== ========
</Table>
2001 vs. 2000
Net interest represents interest income and expense, net of capitalized
interest. Net interest decreased 6 percent in 2001, as ConocoPhillips benefited
from lower short-term interest rates and higher interest amounts being
capitalized--mainly related to projects in Alaska, the Timor Sea and
Venezuela--partially offset by the interest associated with debt acquired in the
Tosco acquisition.
Corporate general and administrative expenses increased 31 percent in 2001,
reflecting increased amounts of staff costs and higher contributions, corporate
advertising and corporate transportation costs.
22
Preferred dividend requirements represent dividends on the preferred securities
of the Phillips 66 Capital I and Capital II trusts. See Note 14--Preferred Stock
in the Notes to Financial Statements for additional information on these trusts.
The category "Other" consists primarily of a captive insurance subsidiary,
certain foreign currency transaction gains and losses, and certain income tax
and other items that are not directly associated with the operating segments on
a stand-alone basis. Results from Other were improved in 2001, as lower foreign
currency transaction losses were partially offset by higher income tax expenses.
Special items in 2001 included an extraordinary loss of $10 million on the early
retirement of debt, as well as contingency accruals and a loss on the
disposition of an asset. Special items in 2000 primarily included costs related
to a late-March 2000 K-Resin styrene-butadiene copolymer facility incident that
was partially insured by the company's captive insurance subsidiary, as well as
environmental accruals. In addition, special items included net income from
discontinued operations.
2000 vs. 1999
Adjusted Corporate and Other net costs increased 32 percent in 2000, compared
with 1999, mainly due to higher net interest expense. Net interest expense
increased 43 percent in 2000, compared with 1999, reflecting higher debt levels
in 2000 as a result of funding the Alaskan acquisition in April 2000.
Special items in 1999 primarily consisted of a $24 million favorable resolution
of prior years' U.S. income tax issues, partially offset by an unfavorable
deferred-tax adjustment and by insurance claims against the company's captive
insurance subsidiary. In addition, special items included net income from
discontinued operations.
23
CAPITAL RESOURCES AND LIQUIDITY
FINANCIAL INDICATORS
<Table>
<Caption>
Millions of Dollars
Except as Indicated
-------------------------------
2001 2000 1999
-------- -------- --------
Current ratio 1.0 .8 1.1
Total debt repayment obligations
due within one year $ 44 262 31
Total debt $ 8,689 6,884 4,302
Company-obligated mandatorily
redeemable preferred securities $ 650 650 650
Common stockholders' equity $ 14,340 6,093 4,549
Percent of total debt to capital* 37% 51 45
Percent of floating-rate debt to
total debt 20% 17 27
-------- -------- --------
</Table>
*Capital includes total debt, company-obligated mandatorily redeemable preferred
securities and common stockholders' equity.
Cash from operations in 2001 was $3,562 million, a decrease of $452 million from
2000. Income from continuing operations in 2001 was $215 million less than in
2000, driven primarily by lower prices. Commodity price changes during 2001 also
affected non-cash working capital items, including receivables, payables, and
inventories, contributing to the decrease in cash from operating activities.
Reduced levels of revolving sales of accounts receivable under the company's
receivables sales programs decreased cash from operations $174 million, compared
with increasing cash from operations $317 million in 2000.
During 2001, cash and cash equivalents decreased $7 million. In addition to the
cash provided by operating activities, $256 million was received from the sale
of various assets. Funds were used to support the company's ongoing capital
expenditures program, reduce debt, and pay dividends.
Following completion of the Tosco acquisition (see Note 3--Acquisition of Tosco
Corporation in the Notes to Financial Statements for more information), Moody's
Investors Service and Standard and Poors upgraded ConocoPhillips' senior
long-term debt ratings from Baa2 to A3, and from BBB to BBB+, respectively,
reflecting the company's larger size, asset diversity, and the financial
flexibility provided by the acquisition. ConocoPhillips' debt-to-capital ratio
was 37 percent at December 31, 2001, improved from 51 percent at year-end 2000,
primarily as a result of the company's issuing 124.1 million shares of common
stock in the acquisition of Tosco.
24
In July 2001, ConocoPhillips' Board of Directors approved a dividend increase,
raising the quarterly per share dividend to $.36, a 6 percent increase,
effective with the September 4, 2001, payment.
To meet its short-term liquidity requirements, including funding its capital
program, paying dividends and repayment of debt, the company looks to a variety
of funding sources, the primary of which is cash generated from operating
activities. While the stability of the company's cash flows from operating
activities does benefit from geographic diversity and the offsetting effects of
upstream and downstream integration, the company's 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 finance tax payments and
crude oil, natural gas and product purchases. The company's primary swing
funding source for short-term working capital needs is a $3 billion commercial
paper program. Commercial paper maturities are generally kept within 90 days of
individual draw dates. The average outstanding balances of issued commercial
paper were $333 million and $1,378 million during 2001 and 2000, respectively.
In October 2001, ConocoPhillips entered into two new revolving bank credit
facilities: a five-year credit agreement providing for commitments not to exceed
$1.5 billion; and a 364-day credit agreement for commitments not to exceed $1.5
billion. The $3 billion of new credit facilities replaced the company's previous
bank credit facilities, including a $1 billion facility assumed as part of the
Tosco transaction, all of which were canceled subsequent to the effectiveness of
the new facilities. The new credit facilities are available either as direct
bank borrowings or as support for the issuance of commercial paper. At December
31, 2001, ConocoPhillips had $1,081 million of commercial paper outstanding
supported by the long-term revolving credit facility.
At December 31, 2001, ConocoPhillips had $3.5 billion of various types of debt
and equity securities, and securities convertible into either, available to
issue and sell, under a universal shelf registration that was filed with the
U.S. Securities and Exchange Commission.
In addition to the bank credit facilities, ConocoPhillips sells certain credit
card and trade receivables under revolving sales agreements with four unrelated
bank-sponsored entities. These agreements provide for ConocoPhillips to sell up
to $1.2 billion of senior, undivided interests in pools of the credit card or
trade receivables to the bank-sponsored entities. At
25
December 31, 2001 and 2000, the company had sold undivided interests of $940
million and $500 million, respectively. ConocoPhillips also retained interests
in the pools of receivables, which are subordinate to the interests sold to the
bank-sponsored entities. The subordinate interests are measured and recorded at
fair value based on the present value of expected future cash flows, which are
estimated using Management's best estimates of the receivables' performance,
including credit losses and dilution, discounted at a rate commensurate with the
risks involved, to arrive at present value. These assumptions are updated
periodically, based on actual credit loss experience and market interest rates.
ConocoPhillips also retains servicing responsibility for the sold receivables.
At December 31, 2001 and 2000, ConocoPhillips' retained interests were $450
million and $224 million, respectively, reported on the balance sheet in
accounts and notes receivable.
The company leases ocean transport vessels, tank railcars, corporate aircraft,
service stations, computers, office buildings and other facilities and
equipment. ConocoPhillips has $200 million of master leasing arrangements, under
which it leases and supervises the construction of retail marketing outlets. At
December 31, 2001, approximately $158 million had been utilized under these
arrangements. In addition, at the time ConocoPhillips acquired Tosco, Tosco had
in place previously arranged leasing arrangements for various retail stations
and two office buildings in Tempe, Arizona. At December 31, 2001, approximately
$1.4 billion had been utilized under those arrangements, which was the total
capacity available. During 2001, the company sold its first Endeavour, formerly
known as Millennium, Class tanker, the Polar Endeavour, for $205 million, then
leased it back under a 10-year long-term operating lease.
Several of the above leasing arrangements are with special purpose entities
(SPEs) that are third-party trusts established by a trustee and funded by
financial institutions. Other than the leasing arrangement, ConocoPhillips has
no other direct or indirect relationship with the trusts or their investors.
Each SPE from which ConocoPhillips leases assets is funded by at least 3 percent
substantive, third-party, residual equity capital investment, which is at-risk
during the entire term of the lease. Except in an event of default under the
terms of the lease agreements, there are not any circumstances at this time
under which ConocoPhillips would be required to record the assets and/or
liabilities of the SPEs in its financial statements in the future, based on the
terms and provisions within the various arrangements. ConocoPhillips considers
an event of default under the terms of the lease agreements to be remote.
Changes in market interest rates do have an impact on the periodic amount of
lease payments. ConocoPhillips has various purchase options to
26
acquire the leased assets from the SPEs at the end of the lease term, but those
purchase options are not required to be exercised by ConocoPhillips, under any
circumstances. If ConocoPhillips does not exercise its purchase option on a
leased asset, the company does have guaranteed residual values, which are due at
the end of the lease terms, but those guaranteed amounts would be reduced by the
fair market value of the leased assets returned. These various leasing
arrangements meet all requirements under generally accepted accounting
principles to be treated as operating leases.
During the second quarter of 2001, the company's $250 million 9% Notes due June
1, 2001, matured and were repaid. In September 2001, the company redeemed its
$300 million 9.18% Notes due September 15, 2021, at 104.59 percent. Both were
funded by the issuance of commercial paper.
During 1996 and 1997, ConocoPhillips formed two statutory business trusts,
Phillips 66 Capital I and Phillips 66 Capital II, in which the company owns all
of the common stock of the trusts and the trusts are consolidated by the
company. The trusts exist for the sole purpose of issuing preferred securities
to outside investors, and investing the proceeds thereof in an equivalent amount
of subordinated debt securities of ConocoPhillips. ConocoPhillips established
the two trusts to raise funds for general corporate purposes. The subordinated
debt securities between ConocoPhillips and the trusts are eliminated in
consolidation. The preferred trust securities held by outside investors are
mandatorily redeemable in 2036 and 2037, respectively, when the subordinated
debt securities between ConocoPhillips and the trusts are required to be repaid.
The $300 million of Phillips 66 Capital I preferred securities became callable,
at par, $25 per share, during May 2001. The total $650 million of mandatorily
redeemable preferred trust securities are presented on the balance sheet as
mezzanine-equity minority interests of a consolidated subsidiary. See Note
14--Preferred Stock in the Notes to Financial Statements.
During 2000, ConocoPhillips contributed its midstream gas gathering, processing
and marketing business and its worldwide chemicals business to joint ventures
with Duke Energy Corporation and ChevronTexaco Corporation, as successor to
Chevron Corporation (ChevronTexaco), respectively, forming Duke Energy Field
Services, LLC (DEFS) and Chevron Phillips Chemical Company LLC (CPChem),
respectively. ConocoPhillips owns 30.3 percent of DEFS and 50 percent of CPChem,
accounting for its interests in both companies using the equity method of
accounting. The capital and financing programs of both of these joint-venture
companies are intended to be self-funding.
27
DEFS supplies a substantial portion of its natural gas liquids to ConocoPhillips
and CPChem under a supply agreement that continues until December 31, 2014. This
purchase commitment is on an "if-produced, will-purchase" basis so has no fixed
production schedule, but has been, and is expected to be, a relatively stable
purchase pattern over the term of the contract. Natural gas liquids are
purchased under this agreement at various published market index prices, less
transportation and fractionation fees. DEFS also purchases raw natural gas from
ConocoPhillips' E&P operations.
ConocoPhillips and CPChem have multiple supply and purchase agreements in place,
ranging in initial terms from four years to 15 years, with extension options.
These agreements cover sales and purchases of refined products, solvents, and
petrochemical and natural gas liquids feedstocks, as well as fuel oils and
gases. Delivery quantities vary by product, ranging from zero to 100 percent of
production capacity at a particular refinery, most at the buyer's option. All
products are purchased and sold under specified pricing formulas based on
various published pricing indexes, consistent with terms extended to third-party
customers.
In the second quarter of 2001, ConocoPhillips and its co-venturers in the Hamaca
project secured approximately $1.1 billion in a joint debt financing for their
heavy-crude-oil project in Venezuela. The Export-Import Bank of the United
States provided a guarantee supporting a 17-year-term $628 million bank
facility. The joint venture also arranged an unguaranteed $470 million
14-year-term commercial bank facility for the project. Total debt of $633
million was outstanding under these credit facilities at December 31, 2001.
ConocoPhillips, through the joint venture, holds a 40 percent interest in the
Hamaca project, which is operated on behalf of the co-venturers by Petrolera
Ameriven. The proceeds of these joint financings are being used to partially
fund the development of the heavy-oil field and the construction of pipelines
and a heavy-oil upgrader. The remaining necessary funding will be provided by
capital contributions from the co-venturers on a pro rata basis to the extent
necessary to successfully complete construction. Once completion certification
is achieved, the joint project financings will become non-recourse with respect
to the co-venturers and the lenders under those facilities can then look only to
the Hamaca project's cash flows for payment.
28
During 1999, Merey Sweeny, L.P. (MSLP), a limited partnership owned 50 percent
by ConocoPhillips and 50 percent by Petroleos de Venezuela, S.A. (PdVSA), issued
$350 million of 8.85% Bonds due 2019. The proceeds of the bond issue were used
to fund the construction of a coker and related facilities to process heavy,
sour crude oil at ConocoPhillips' Sweeny refinery, including improvements to
certain existing ConocoPhillips facilities at the refinery. These improvements
to the existing ConocoPhillips facilities were sold to ConocoPhillips at a price
equal to MSLP's cost of construction, $133 million. ConocoPhillips agreed to pay
MSLP the purchase price for the improvements to the existing ConocoPhillips
facilities, plus 7 percent interest, monthly over the 240 months following
startup, which occurred during September 2000.
MSLP continues to own and operate the coker, processing Venezuelan Merey crude
oil delivered under a supply agreement with PdVSA. MSLP charges ConocoPhillips a
fee to process the heavy crude oil through the coker. This is the partnership's
primary source of revenue. MSLP pays a monthly access fee to ConocoPhillips for
the use of the improvements to the refinery, equal to the monthly principal and
interest paid by ConocoPhillips to purchase the improvements from MSLP. To the
extent that the access fee is not paid by MSLP, ConocoPhillips is not obligated
to make payments for the improvements. The coker and related facilities began
processing heavy crude oil during the third quarter of 2000, but startup
certification has not yet been achieved. Once startup certification is achieved,
expected during 2002, the MSLP bonds become non-recourse to the two partners and
the owners of the bonds can then only look to MSLP's cash flows for payment.
The following table summarizes the maturities of the drawn balances of the
company's various debt instruments, as well as other non-cancelable, fixed or
minimum, contractual commitments:
29
<Table>
<Caption>
Millions of Dollars
--------------------------------------------------------
Payments Due by Period
Debt and other non- --------------------------------------------------------
cancelable cash 2003- 2005- After
commitments Total 2002 2004 2006 2006
- ------------------- -------- -------- -------- -------- --------
Total debt $ 8,689 44 271 2,503 5,871
Above-market capital lease
obligations 67 -- 2 3 62
Mandatorily redeemable
preferred stock 650 -- -- -- 650
Operating leases
Minimum rental payments* 2,761 431 717 497 1,116
Sublease offsets (583) (141) (210) (105) (127)
Guaranteed residual
values 1,811 -- 459 918 434
Unconditional throughput
and processing fee
commitments** 679 58 114 114 393
-------- -------- -------- -------- --------
</Table>
*Excludes $383 million in lease commitments that begin upon delivery of five
crude oil tankers currently under construction. Delivery is expected in the
third and fourth quarters of 2003.
**Represents obligations to transfer funds in the future for fixed or minimum
amounts at fixed or minimum prices under various throughput or tolling
agreements with pipeline and processing companies in which the company holds
stock interests.
In addition to the above contractual commitments, the company has various
guarantees that have the potential for requiring cash outflows resulting from a
contingent event that could require company performance pursuant to a funding
commitment to a third or related party. The following table summarizes the
potential amounts and remaining time frames of these direct and indirect
guarantees:
<Table>
<Caption>
Millions of Dollars
----------------------------------------------------
Amount of Expected Guarantee
Expiration Per Period
----------------------------------------------------
Direct and indirect 2003- 2005- After
guarantees Total 2002 2004 2006 2006
- ------------------- -------- -------- -------- -------- --------
Construction completion
guarantees* $ 474 15 206 253 --
Other guarantees** 150 5 11 13 121
-------- -------- -------- -------- --------
</Table>
*Amounts represent ConocoPhillips' ownership share of the utilized portion of
debt and bond financing arrangements secured by the Hamaca and Merey Sweeny
joint-venture projects in Venezuela and Texas, respectively. The debt is
non-recourse to ConocoPhillips upon completion/startup certification of the
projects. Figures in the table represent ConocoPhillips' portion due in the
event completion/startup certification is not achieved. The Merey Sweeny debt
is joint-and-several. See Note 6--Investments and Long-Term Receivables in the
Notes to Financial Statements.
**Represents amount of obligations directly guaranteed by the company in the
event a third party or related party does not perform.
30
FINANCIAL INSTRUMENT MARKET RISK
ConocoPhillips and certain of its subsidiaries hold and issue derivative
contracts and financial instruments that expose cash flows or earnings to
changes in commodity prices, foreign exchange rates, or interest rates. The
company may use financial and commodity-based derivative contracts to manage the
risks produced by changes in the prices of crude oil, natural gas and related
products, and fluctuations in foreign currency exchange rates, or to exploit
favorable market conditions. In the past, the company has, on occasion, hedged
interest rates and may do so in the future should certain circumstances or
transactions warrant.
ConocoPhillips' Board of Directors has revised its policy governing the use of
derivative instruments. The new policy prohibits the holding or issuing of
highly complex or leveraged derivatives, as did the old policy. Except as
approved by the Chief Executive Officer, the derivative instruments used by the
company must not contain embedded financing features and must be sufficiently
liquid that comparable valuations are readily available. The policy also
requires the Chief Executive Officer to establish the maximum derivative
position limits for ConocoPhillips and requires the company's Risk Management
Steering Committee, comprised of senior management, to monitor the use and
effectiveness of the derivatives. The Audit Committee of the company's Board of
Directors periodically reviews derivatives policy and compliance.
Commodity Price Risk
In 2001, prior to the Tosco acquisition, ConocoPhillips used commodity-based
derivative contracts only to minimize exposures to price fluctuations occurring
between the purchasing of feedstock and the selling of refined products, while
Tosco used derivatives more extensively as a tool to manage or exploit exposures
to price fluctuations. Since acquiring Tosco on September 14, 2001,
ConocoPhillips has expanded both the volumes and uses of derivative instruments;
however, the aggregate fair market values of futures, swaps, and options
outstanding at December 31, 2001, were a gain of less than $6 million and a loss
of less than $8 million.
In past years, ConocoPhillips used sensitivity analysis to disclose the risk of
loss resulting from derivative positions held at year-end. The company now uses
a value-at-risk model to estimate the loss that could potentially result on a
single day from the effect of adverse changes in market conditions on the
derivative financial instruments and derivative commodity
31
instruments held or issued, including commodity purchase and sales contracts
recorded on the balance sheet as derivative instruments in accordance with
Financial Accounting Standards Board (FASB) Statement No. 133, "Accounting for
Derivative Instruments and Hedging Activities," as amended. Using a 95 percent
confidence level, the value-at-risk analysis indicated the hypothetical loss in
fair values for those instruments issued or held for trading purposes and those
instruments that were issued or held for purposes other than trading at December
31, 2001, would be immaterial to ConocoPhillips' net income and cash flows. The
value-at-risk for those instruments issued or held for purposes other than
trading at December 31, 2000, was also immaterial to ConocoPhillips' net income
and cash flows; the company neither held nor issued any derivatives for trading
purposes during 2000.
For additional information about the company's use of derivative instruments,
see Note 13--Financial Instruments and Derivative Contracts in the Notes to
Financial Statements.
Interest Rate Risk
The following tables provide information about the company's financial
instruments that are sensitive to changes in interest rates. These tables
present principal cash flows and related weighted-average interest rates by
expected maturity dates. Weighted-average variable rates are based on implied
forward rates in the yield curve at the reporting date. The carrying amount of
the company's floating-rate debt approximates its fair value. The fair value of
the fixed-rate financial instruments is estimated based on quoted market prices.
32
<Table>
<Caption>
Millions of Dollars Except as Indicated
----------------------------------------------------------------------------
Mandatorily
Redeemable
Preferred
Debt Securities
-------------------------------------------------- -----------------------
Expected Fixed Average Floating Average Fixed Average
Maturity Rate Interest Rate Interest Rate Interest
Date Maturity Rate Maturity Rate Maturity Rate
- -------- ---------- ---------- ---------- ---------- ---------- ----------
YEAR-END 2001
2002 $ 43 9.31% $ -- --% $ -- --%
2003 263 7.62 -- -- -- --
2004 6 7.02 -- -- -- --
2005 1,153 8.49 -- -- -- --
2006 267 7.61 1,081 7.06 -- --
Remaining
years 5,221 7.99 625 6.86 650 8.11
---------- ---------- ---------- ---------- ---------- ----------
Total $ 6,953 $ 1,706 $ 650
========== ========== ========== ========== ========== ==========
Fair value $ 7,474 $ 1,706 $ 662
========== ========== ========== ========== ========== ==========
Year-End 2000
2001 $ 262 8.90% $ -- --% $ -- --%
2002 4 6.80 15 5.98 -- --
2003 104 6.66 -- -- -- --
2004 4 6.82 -- -- -- --
2005 1,151 8.49 500 5.98 -- --
Remaining
years 4,204 8.11 640 5.10 650 8.11
---------- ---------- ---------- ---------- ---------- ----------
Total $ 5,729 $ 1,155 $ 650
========== ========== ========== ========== ========== ==========
Fair value $ 5,999 $ 1,155 $ 567
========== ========== ========== ========== ========== ==========
</Table>
Foreign Currency Risk
At December 31, 2000, ConocoPhillips held a collar (i.e., a purchased call and a
written put) on 133 million Australian dollars to provide protection against the
exchange rate risk of an anticipated Australian business acquisition, which was
completed in 2001. At year-end 2000, the fair market value of the collar was
minimal, and a hypothetical 10 percent change in the year-end 2000 exchange
rates would have resulted in a potential gain of $8.2 million or a potential
loss of $6.2 million. The collar was closed out in 2001 with an actual realized
gain of $0.6 million.
At December 31, 2001 and 2000, U.S. subsidiaries held long-term
sterling-denominated intercompany receivables totaling $191 million and $246
million, respectively, due from a U.K.
33
subsidiary. The U.K. subsidiary also held a dollar-denominated long-term
receivable due from a U.S. subsidiary with balances of $75 million and $81
million, respectively, at December 31, 2001 and 2000. A Norwegian subsidiary
held $79 million and $111 million of intercompany U.S. dollar-denominated
receivables due from its U.S. parent at December 31, 2001 and 2000,
respectively. Also at year-end 2001, a foreign subsidiary with the U.S. dollar
as its functional currency owed a $9 million Norwegian kroner-denominated
payable to a Norwegian subsidiary. The potential foreign currency remeasurement
gains or losses in non-cash pretax earnings from a hypothetical 10 percent
change in the year-end 2001 and 2000 exchange rates from these intercompany
balances are $21 million and $5 million, respectively.
CAPITAL SPENDING
CAPITAL EXPENDITURES AND INVESTMENTS
<Table>
<Caption>
Millions of Dollars
-----------------------------------
2002
Budget 2001 2000* 1999
------ ------ ------ ------
E&P
Alaska $ 807 965 538 25
Lower 48 314 389 413 295
Foreign 1,483 1,162 726 759
------ ------ ------ ------
2,604 2,516 1,677 1,079
Midstream -- -- 17 137
R&M 833 489 217 326
Chemicals -- 6 67 98
Emerging Businesses -- -- -- --
Corporate and Other 64 66 39 46
------ ------ ------ ------
$3,501 3,077 2,017 1,686
====== ====== ====== ======
United States $1,988 1,910 1,264 919
Foreign 1,513 1,167 753 767
------ ------ ------ ------
$3,501 3,077 2,017 1,686
====== ====== ====== ======
</Table>
*Excludes the Alaskan acquisition.
ConocoPhillips' capital spending for the three-year period ending December 31,
2001, totaled $6.8 billion, excluding the purchase of ARCO's Alaska businesses
in 2000. The company's spending was primarily focused on the growth of its E&P
business, with more than 75 percent of total spending in this segment. Certain
Midstream and Chemicals businesses were contributed to joint ventures during
2000--Midstream on March 31, 2000, and Chemicals on July 1, 2000. The capital
programs of these joint-venture companies are intended to be self-funding.
34
ConocoPhillips' Board of Directors (Board) has approved $3.5 billion for capital
projects and investments in 2002, a 14 percent increase over 2001 capital
spending of $3.1 billion. The company plans to direct approximately 75 percent
of its 2002 capital budget to E&P and approximately 25 percent to R&M.
Fifty-seven percent of the budget is targeted for projects in the United States.
In December 2000, ConocoPhillips' Board approved a $2.5 billion capital budget
for the year 2001. In October 2001, the Board authorized increasing capital
spending to $3.3 billion to cover the fourth-quarter capital requirements
related to the Tosco acquisition, investments in Angola and Brazil deepwater
leases, and the anticipated purchase of additional Kashagan ownership in
Kazakhstan. Actual 2001 expenditures were $3.1 billion, with 82 percent directed
to E&P and 16 percent to R&M. The larger capital program for 2002 and the
percentage shift in funds for R&M reflect the increased size of this segment
since the September 2001 acquisition of Tosco.
E&P
Capital spending for E&P during the three-year period ending December 31, 2001,
totaled $5.3 billion. The expenditures over the three-year period supported
several key exploration and development projects including the Bayu-Undan
project in the Timor Sea; the Hamaca heavy-oil project in Venezuela's Orinoco
Oil Belt; the company's Peng Lai 19-3 discovery in China's Bohai Bay; the Jade
development and Eldfisk waterflood development in the U.K. and Norwegian sectors
of the North Sea, respectively; and acquisition and development of
coalbed-methane and conventional gas prospects and producing properties in the
U.S. Lower 48. Also included in the three-year E&P capital outlays were
expenditures for development of Alaska North Slope fields and significant
worldwide exploration activities including the Kashagan prospect in the north
Caspian Sea, offshore Kazakhstan; additional Bohai Bay appraisal and satellite
field prospects; National Petroleum Reserve--Alaska (NPR-A) and satellite field
prospects on Alaska's North Slope; North Sea prospects in the U.K. and Norwegian
sectors, plus other Atlantic Margin wells in the United Kingdom, Greenland and
the Faroe Islands; and acquisition of deepwater exploratory interests in Angola,
Brazil, and the U.S. Gulf of Mexico. Capital expenditures for construction of
the Endeavour Class tankers and an additional interest in the Trans-Alaska
Pipeline System were also included in the E&P segment.
ConocoPhillips has contracted to build, for approximately $200 million each,
five double-hulled Endeavour Class tankers for
35
use in transporting Alaskan crude oil to the U.S. West Coast. During 2001, the
Polar Endeavour, the first Endeavour Class tanker, entered service. The second
tanker, the Polar Resolution, is expected to enter service in 2002.
ConocoPhillips expects to add a new Endeavour Class tanker to its fleet each
year through 2005, allowing the company to retire its older ships and cancel
non-operated charters.
During the fourth quarter of 2001, heavy-crude-oil production began from the
Hamaca project in Venezuela's Orinoco Oil Belt. Construction of an upgrader to
convert heavy crude into a 26-degree API synthetic crude continues. Completion
of the ugrader is expected in 2004. ConocoPhillips owns a 40 percent equity
interest in the Hamaca project.
In 2001, development activities continued on the company's Peng Lai 19-3
discovery in block 11/05 in China's Bohai Bay in line with the overall approved
development plan. First production is scheduled for the third quarter of 2002.
During 2001, ConocoPhillips and its co-venturers announced the successful
completion and testing of the second exploration well drilled by the
co-venturers in the Kashagan structure on the Kazakhstan shelf in the north
Caspian Sea. Drilling of the first of five planned appraisal wells was
successfully completed in early 2002.
Two of the co-venturers in the north Caspian Sea venture have entered into
agreements to sell their interests. ConocoPhillips, along with the other
remaining co-venturers, exercised preemptive rights to purchase the interests
being sold which will increase the company's ownership from 7.14 percent to 8.33
percent when completed. Closing is expected during the second quarter of 2002.
At year-end, commissioning work and drilling was in progress on ConocoPhillips'
Jade development in the U.K. sector of the North Sea. Production began in the
first quarter of 2002. ConocoPhillips is the operator and holds a 32.5 percent
interest in Jade.
ConocoPhillips' Bayu-Undan gas-recycle project activities continued in the Timor
Sea during 2001. The schedule of this first phase of field development was not
impacted by the delay in resolving certain critical legal, fiscal, and taxation
issues, and the company has proceeded with its $1.9 billion gross gas-recycle
project. Full commercial production of liquids is expected to begin in 2004.
ConocoPhillips now controls a 58.6 percent interest in the Bayu-Undan project
and is the operator of the gas-recycle development.
36
During 2001, ConocoPhillips announced its plans to invest $85 million for a 20
percent share of a new independent power project to be built near Kwale,
Nigeria. The plant is expected to start up in 2004. ConocoPhillips also agreed
with its co-venturers to evaluate the development of a liquefied natural gas
facility to be located offshore Nigeria. If approved, the facility, which would
be 20 percent owned by ConocoPhillips, would come onstream by 2007, utilizing
natural gas feedstocks supplied by ConocoPhillips and its co-venturers.
In the third quarter of 2001, ConocoPhillips increased its presence in deepwater
areas by securing interests in three blocks--a 20 percent interest in a block
offshore Angola and a 100 percent interest in two deepwater exploration blocks
in Brazil, where ConocoPhillips will be the operator.
E&P's 2002 capital budget is $2.6 billion, 3 percent higher than actual
expenditures in 2001. Forty-three percent of E&P's 2002 capital budget is
planned for the United States. Of that, 72 percent is slated for Alaska.
ConocoPhillips has budgeted $238 million for worldwide exploration activities in
2002, with 31 percent of that amount allocated for the United States. More than
half of the U.S. total will be directed toward the exploration program in
Alaska, where wells are planned in the NPR-A and other locations on the North
Slope. Outside the United States, significant exploration expenditures are
planned in Kazakhstan, Angola and Norway.
The company plans to spend $807 million in 2002 for its Alaska operations. Large
capital projects include the ongoing construction of four Endeavour Class
tankers; development of the Meltwater, Palm and West Sak fields in the Greater
Kuparuk area; development of the Borealis field in the Greater Prudhoe Bay area;
capacity expansion at the Alpine field; as well as the exploratory activity
discussed above.
In the Lower 48, capital expenditures will be focused on exploration and
development of coalbed methane assets in the Rocky Mountain region and continued
exploitation of the company's acreage positions in the San Juan Basin, Permian
Basin, Texas Panhandle, northern Louisiana, and the upper Texas Gulf Coast.
E&P is directing $1.5 billion of its 2002 capital budget to international
projects. The majority of these funds will go toward developing major long-term
projects, including the Bayu-Undan liquids development and gas-recycling project
in the Timor Sea, the Hamaca heavy-oil development in Venezuela, and the Bohai
Bay oil development in China. North Sea projects include
37
development of the Jade field in the U.K. sector and further development of the
Ekofisk and Eldfisk fields in the Norwegian sector.
Costs incurred for the years ended December 31, 2001, 2000, and 1999, relating
to the development of proved undeveloped oil and gas reserves were $1,627
million, $857 million, and $301 million, respectively. Of the $1,627 million
incurred in 2001, $204 million was funded by the Hamaca Holding LLC joint
venture, an equity affiliate, and was not part of ConocoPhillips' reported
capital expenditures for the year. As of December 31, 2001, estimated future
development costs relating to the development of proved undeveloped oil and gas
reserves for the years 2002 through 2004 were projected to be $1,528 million,
$991 million, and $314 million, respectively. Of the $1,528 million estimated
future development costs for 2002, $117 million was estimated to be funded by
Hamaca Holding LLC, not by ConocoPhillips' capital expenditures.
R&M
Capital spending for R&M during the three-year period ending December 31, 2001,
was primarily for refinery-upgrade projects--to improve product yields, to meet
new environmental standards, to improve the operating integrity of key
processing units, and to install advanced process control technology--as well as
for safety projects. Key significant projects during the three-year period
included completion of a coker and continuous catalytic reformer at the
company's Sweeny, Texas, refinery; capacity expansion and debottlenecking
projects at the Borger, Texas, refinery; successful completion of a commercial S
Zorb Sulfur Removal Technology (S Zorb) unit at the Borger refinery; an
expansion of capacity in the Seaway crude-oil pipeline; and installation of
advanced central control buildings and technologies at the Sweeny and Borger
facilities. In the fourth quarter of 2001, the R&M segment's capital
expenditures included $238 million related to projects which were in progress
upon the acquisition of Tosco, including construction of a polypropylene plant
at the Bayway refinery in New Jersey and the Retail Enterprise Program
initiative, a new electronic scanning and business system being implemented in
the company's retail convenience stores. Total capital spending for R&M for the
three-year period was $1.0 billion, representing approximately 15 percent of
ConocoPhillips' total capital spending.
During 2001, ConocoPhillips successfully completed and started up a new
6,000-barrel-per-day unit at its Borger refinery using the company's proprietary
S Zorb technology to significantly reduce sulfur content in gasoline in
preparation for meeting new
38
government regulations. During 2001, the company announced its third licensing
agreement for the use of S Zorb for gasoline and announced that S Zorb for
diesel was available for licensing. A large continuous pilot plant demonstrating
S Zorb for diesel is under construction and a commercial-scale unit within
ConocoPhillips' refining system is in the planning stages.
A project to increase capacity at the Borger refinery through debottlenecking
and expansion continued to progress in 2001. The project is expected to increase
the facility's capacity to process crude oil by 20,000 barrels per day and move
the facility toward production of lower-sulfur products. Operations have been
largely unaffected by the debottlenecking project, with most work occurring
during normal scheduled maintenance periods. Startup is expected in early 2002.
R&M's 2002 capital budget is $833 million, a 70 percent increase over spending
of $489 million in 2001. The 2001 spending does not include capital spending by
Tosco prior to its acquisition by ConocoPhillips on September 14. Domestic
spending is expected to consume 96 percent of the R&M budget, with the remainder
allocated to the Whitegate refinery in Ireland.
The company plans to direct 73 percent of the R&M capital budget to refining, 19
percent to marketing, and the remainder to transportation and other projects.
Approximately two-thirds of R&M's budget is slated for ongoing operating
requirements, including safety and environmental projects. The largest refining
projects include construction of a fluid catalytic cracking unit at the Ferndale
refinery, a diesel hydrotreater at the San Francisco refinery, and a low-sulfur
gasoline project at the Wood River refinery. There are no individually
significant marketing projects.
CONTINGENCIES
LEGAL AND TAX MATTERS
ConocoPhillips accrues for contingencies when a loss is probable and the amounts
can be reasonably estimated. Based on currently available information, the
company believes 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 the company's financial statements.
On June 23, 1999, a flash fire occurred in a reactor vessel at the K-Resin
styrene-butadiene copolymer (SBC) plant at the Houston Chemical Complex. Two
individuals employed by a subcontractor, Zachry Construction Corporation
(Zachry), were
39
killed and other workers were injured. Ten lawsuits were filed in Texas in
connection with the incident, including two actions for wrongful death. Both
wrongful death lawsuits and many of the personal injury claims have been
resolved. Two lawsuits remain pending on behalf of 12 workers. The first trial
is scheduled for the spring of 2002.
Under the indemnification provisions of the subcontracting agreement between
ConocoPhillips and Zachry, ConocoPhillips has sought indemnification from Zachry
with respect to the claims of the Zachry workers. ConocoPhillips has, in
addition, filed an action against various Zachry insurers to obtain a
declaration that coverage is available in regard to the incident under policies
issued by them. There are also provisions in the Contribution Agreement, under
which CPChem was formed, providing for indemnification of ConocoPhillips by
CPChem for damages stemming from this incident.
On March 27, 2000, an explosion and fire occurred at ConocoPhillips' K-Resin SBC
plant at the Houston Chemical Complex due to the overpressurization of an
out-of-service butadiene storage tank. One employee was killed and several
individuals, including employees of both ConocoPhillips and its contractors,
were injured. Additionally, several individuals who were allegedly in the area
of the Houston Chemical Complex at the time of the incident have claimed they
suffered various personal injuries due to exposure to the event. The wrongful
death claim and the claims of the most seriously injured workers have been
resolved. Currently, there are fourteen lawsuits pending on behalf of 67 primary
plaintiffs. The first trial is scheduled for April 2002. Under the
indemnification provisions of subcontracting agreements with Zachry and Brock
Maintenance, Inc., ConocoPhillips has sought indemnification from these
subcontractors with respect to claims made by their employees. The Contribution
Agreement, pursuant to which CPChem was formed, does not require CPChem to
indemnify ConocoPhillips for liability arising out of this litigation.
ENVIRONMENTAL
ConocoPhillips is subject to the same numerous federal, state, local and foreign
environmental laws and regulations as are other companies in the oil and gas
exploration and production; and refining, marketing and transportation of crude
oil and refined products businesses. The most significant of those laws, and the
regulations issued thereunder, affecting ConocoPhillips' operations are:
o The Clean Air Act, as amended.
40
o The Federal Water Pollution Control Act.
o Safe Drinking Water Act.
o Regulations of the United States Department of the Interior governing
offshore oil and gas operations.
These acts 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 obtain substantial information in
connection with the application process. The obtaining of this information can
be expensive and time-consuming. In addition, there can be delays associated
with notice and comment periods and the agency's processing of the application.
Many of the delays associated with the permitting process are beyond the control
of the applicant.
Many states also have similar statutes and regulations governing air and water.
While similar, in some cases these regulations impose additional, or more
stringent, requirements that can add to the cost and difficulty of marketing or
transporting products across state lines.
ConocoPhillips is also subject to certain acts and regulations primarily
governing remediation of wastes or oil spills. Most of the expenditures to
fulfill these obligations relate to facilities and sites where past operations
followed practices and procedures that were considered appropriate under
regulations, if any, existing at the time, but that may now require
investigatory or remedial work to adequately protect the environment or to
address new regulatory requirements. The applicable acts are:
o The Comprehensive Environmental Response, Compensation and Liability Act of
1980, as amended (CERCLA), commonly referred to as Superfund, and
comparable state statutes. CERCLA primarily addresses historic
contamination and imposes joint and several liability for cleanup of
contaminated sites on owners and operators of the contaminated sites, or on
those who have contributed wastes to a site. Many states have their own
statutes and regulatory requirements that are similar to CERCLA.
ConocoPhillips is involved in a number of Superfund sites--see the
discussion below. CERCLA also requires reporting of releases to the
environment of substances defined as hazardous. These requirements add cost
and complexity to ConocoPhillips' operations.
o The Resource Conservation and Recovery Act of 1976, as amended, and
comparable state statutes, govern the management and disposal of wastes,
with the most stringent regulations
41
applicable to treatment, storage or disposal of hazardous wastes at the
owner's property.
o The Oil Pollution Act of 1990, as amended, under which owners and operators
of tankers, owners and operators of onshore facilities and pipelines, and
lessees or permittees of an area in which an offshore facility is located
are liable for removal and cleanup costs of oil discharges into navigable
waters of the United States.
Pursuant to the authority of the Clean Air Act (CAA), the Environmental
Protection Agency (EPA) has issued several standards applicable to the
formulation of motor fuels, which are designed to reduce emissions of certain
air pollutants when the fuel enters commerce or is used. Pursuant to state laws
corresponding to the CAA, several states have passed similar or more stringent
regulations governing the formulation of motor fuels. Where these regulations
are currently applicable, ConocoPhillips has already incurred the operational or
capital costs of control or manufacturing limitations, but will continue to
incur the costs of compliance such as ongoing operational requirements and
recordkeeping.
The EPA has also promulgated specific rules governing the sulfur content of
gasoline, known generically as the "Tier II Sulfur Rules," which become
applicable to ConocoPhillips' gasoline as early as 2004. The company is
implementing a compliance strategy for meeting the requirements, including the
use of ConocoPhillips' proprietary technology known as S Zorb. ConocoPhillips
expects to use a combination of technologies to achieve compliance with the
rules. ConocoPhillips has made preliminary estimates of its cost of compliance
with this rule and will include these costs in future budgeting for refinery
compliance. The EPA has also promulgated sulfur content rules for highway diesel
fuel that become applicable in 2006. ConocoPhillips is currently developing and
testing an S Zorb system for removing sulfur from diesel fuel. It is anticipated
that S Zorb will be used as part of ConocoPhillips' strategy for complying with
these rules. Because the company is still evaluating and developing capital
strategies for compliance with the rule, ConocoPhillips cannot provide precise
estimates for compliance at this time, but will do so and report these
compliance costs as required by law.
In 1997, an international conference on global warming concluded an agreement
known as the Kyoto Protocol, which called for the reduction of certain emissions
that may contribute to increases in atmospheric greenhouse gas concentrations.
The United States has not ratified the treaty codifying the Kyoto Protocol and
it is not clear whether it will do so in the future. If the
42
protocol is ratified by the United States, the cost of complying with
regulations implementing the protocol could be substantial. It is not, however,
possible to accurately estimate the costs that could be incurred by
ConocoPhillips to comply with such regulations.
Because of the nature of ConocoPhillips' businesses, it is likely that
environmental laws and regulations will continue to have an effect on its
operations in the future. ConocoPhillips does not, however, currently expect any
material adverse effect on its operations or financial position as a result of
compliance with such laws and regulations.
At year-end 2000, ConocoPhillips reported 30 sites where it had information
indicating that it might have been identified as a Potentially Responsible Party
(PRP) under the federal Superfund law. Since then, six of these PRP sites have
been resolved and five sites were added. Of the 29 sites remaining at December
31, 2001, the company believes it has a legal defense or its records indicated
no involvement for six sites. At six other sites, present information indicates
that it is probable that the company's exposure is less than $100,000 per site.
Of the remaining sites, the company has provided for any probable costs that can
be reasonably estimated. At a number of sites, ConocoPhillips has had no
communication or activity with government agencies or other PRPs in more than
two years. Experience has shown, however, that the mere passage of time is no
guarantee that the site will never become active or that the company's
connection to the site will not be established.
ConocoPhillips does not consider the number of sites at which it has been
designated potentially responsible by state or federal agencies as a relevant
measure of liability. Some companies may be involved in few sites but have much
larger liabilities than companies involved in many more sites. Although
liability of those potentially responsible is generally joint and several for
federal sites and frequently so for state sites, the company is usually but one
of many companies cited at a particular site. ConocoPhillips has, to date, been
successful in sharing cleanup costs with other financially sound companies. Many
of the sites at which the company is potentially responsible are still under
investigation by the EPA or the state agencies concerned. Prior to actual
cleanup, those potentially responsible normally assess site conditions,
apportion responsibility and determine the appropriate remediation. In some
instances, ConocoPhillips 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.
43
At December 31, 2001, contingent liability accruals of $11 million had been made
for the company's PRP sites, and $3 million for other environmental contingent
liabilities. In addition, the company had accrued $525 million for other planned
remediation activities, including resolved state, PRP, and other federal sites,
as well as sites where no claims have been asserted, for total environmental
accruals of $539 million, compared with $127 million at December 31, 2000. The
2001 increase in accrued environmental costs is primarily the result of
ConocoPhillips' recent acquisition of Tosco on September 14, 2001. Accruals
totaling $303 million were added as a result of that transaction. Earlier in
2001, the accrual was increased for remediation activities required by the state
of Alaska at exploration and production sites formerly owned by ARCO. Because
these accruals relate to environmental conditions that existed when
ConocoPhillips acquired Tosco and the Alaska businesses, the charges impacted
the allocation of the purchase price of each acquisition, not the company's net
income. No one site exceeds 10 percent of the total.
Expensed environmental costs were $345 million in 2001 and are expected to be
approximately $235 million in 2002 and 2003. Capitalized environmental costs
were $632 million in 2001, and are expected to be approximately $275 million and
$375 million in 2002 and 2003, respectively.
After an assessment of environmental exposures for cleanup and other costs,
except those acquired in purchase business combinations, the company makes
accruals on an undiscounted 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. These accruals have not been reduced
for possible insurance recoveries.
OTHER
ConocoPhillips has deferred tax assets related to certain accrued liabilities,
alternative minimum tax credits, and loss carryforwards. Valuation allowances
have been established for certain foreign and state net operating loss
carryforwards that reduce deferred tax assets to an amount that will, more
likely than not, be realized. Uncertainties that may affect the realization of
these assets include tax law changes and the future level of product prices and
costs. Based on the company's historical taxable income, its expectations for
the future, and available tax-planning strategies, Management expects that the
net deferred tax assets will be realized as offsets to reversing deferred tax
liabilities and as reductions in future taxable operating income. The
alternative minimum tax credit can be
44
carried forward indefinitely to reduce the company's regular tax liability.
NEW ACCOUNTING STANDARDS
In June 2001, the FASB issued FASB Statement No. 143, "Accounting for Asset
Retirement Obligations." In August 2001, the FASB issued FASB Statement No. 144,
"Accounting for the Impairment or Disposal of Long-Lived Assets." For additional
information, see Note 24--New Accounting Standards in the Notes to Financial
Statements, which is incorporated herein by reference.
CRITICAL ACCOUNTING POLICIES
The preparation of financial statements in conformity with generally accepted
accounting principles requires Management to select appropriate accounting
policies and to make estimates and assumptions that affect the reported amounts
of assets, liabilities, revenues and expenses. See Note 1--Accounting Policies
in the Notes to Financial Statements for descriptions of the company's major
accounting policies. Certain of these accounting policies involve judgments and
uncertainties to such an extent that there is a reasonable likelihood that
materially different amounts would have been reported under different
conditions, or if different assumptions had been used.
Oil and Gas Accounting
- ----------------------
Accounting for oil and gas exploratory activity is subject to special accounting
rules that are unique to the oil and gas industry. The acquisition of geological
and geophysical seismic information, prior to the discovery of proved reserves,
is expensed as incurred, similar to accounting for research and development
costs. However, leasehold acquisition costs and exploratory well costs are
capitalized on the balance sheet, pending determination of whether proved oil
and gas reserves have been discovered on the prospect.
Property Acquisition Costs
For leasehold acquisition costs, Management exercises judgment and determines a
percentage probability that the prospect ultimately will fail to find proved oil
and gas reserves. For prospects in areas that have had limited, or no, previous
exploratory drilling, the percentage probability of ultimate failure is normally
judged to be quite high. This judgmental percentage is multiplied by the
leasehold acquisition cost, and that product is divided by the contractual
period of the leasehold to determine a periodic leasehold impairment charge that
is reported in exploration expense. This judgmental
45
probability percentage is reassessed and adjusted throughout the contractual
period of the leasehold based on favorable or unfavorable exploratory activity
on the leasehold or on adjacent leaseholds, and leasehold impairment
amortization expense is adjusted prospectively. By the end of the contractual
period of the leasehold, the impairment probability percentage will have been
adjusted to 100 percent if the leasehold is expected to be abandoned, or will
have been adjusted to zero percent if there is an oil or gas discovery that is
under development. See the supplemental Oil and Gas Operations disclosures about
Costs Incurred and Capitalized Costs for more information about the amounts and
geographic locations of costs incurred in acquisition activity, and the amounts
on the balance sheet related to unproved properties.
Exploratory Costs
For exploratory wells, drilling costs are temporarily capitalized, or
"suspended," on the balance sheet, pending a judgmental determination of whether
potentially economic oil and gas reserves have been discovered by the drilling
effort. This judgment usually is made within two months of the completion of the
drilling effort, but can take longer, depending on the complexity of the
geologic structure. Accounting rules require that this judgment be made at least
within one year of well completion. If a judgment is made that the well did not
encounter potentially economic oil and gas quantities, the well costs are
expensed as a dry hole and are reported in exploration expense. Exploratory
wells that are judged to have discovered potentially economic quantities of oil
and gas and that are in areas where a major capital expenditure (e.g., a
pipeline or offshore platform) would be required before production could begin,
and where the economic viability of that major capital expenditure depends upon
the successful completion of further exploratory work in the area, remain
capitalized on the balance sheet as long as additional exploratory appraisal
work is under way or firmly planned. For complicated offshore exploratory
discoveries, it is not unusual to have exploratory wells remain suspended on the
balance sheet for several years while the company performs additional appraisal
drilling and seismic work on the potential oil and gas field. Unlike leasehold
acquisition costs, there is no periodic impairment amortization of suspended
exploratory well costs. Management continuously monitors the results of the
additional appraisal drilling and seismic work and expenses the suspended well
costs as dry holes when it judges that the potential field does not warrant
further exploratory efforts in the near term. See the supplemental Oil and Gas
Operations disclosures about Costs Incurred and Capitalized Costs for more
information about the amounts and geographic locations of costs incurred in
exploration activity and the amounts on the balance sheet related to unproved
properties, as well as the
46
Wells In Progress disclosure for the number and geographic location of wells not
yet declared productive or dry.
Proved Oil and Gas Reserves
Engineering estimates of the quantities of recoverable oil and gas reserves in
oil and gas fields are inherently imprecise and represent only approximate
amounts because of the subjective judgments involved in developing such
information. Despite the inherent imprecision in these engineering estimates,
accounting rules require supplemental disclosure of "proved" oil and gas reserve
estimates due to the importance of these estimates to better understanding the
perceived value and future cash flows of a company's oil and gas operations. The
judgmental estimation of proved oil and gas reserves is also important to the
income statement because the proved oil and gas reserve estimate for a field
serves as the denominator in the unit-of-production calculation of depreciation,
depletion and amortization of the capitalized costs for that field. There are
several authoritative guidelines regarding the engineering criteria that have to
be met before estimated oil and gas reserves can be designated as "proved." The
company's reservoir engineering department has policies and procedures in place
that are consistent with these authoritative guidelines. The company has
qualified and experienced internal engineering personnel who make these
estimates. Proved reserve estimates are updated annually and take into account
recent production and seismic information about each field. Also, as required by
authoritative guidelines, the estimated future date when a field will be
permanently shut-in for economic reasons is based on an extrapolation of oil and
gas prices and operating costs prevalent at the balance sheet date. This
estimated date when production will end affects the amount of estimated
recoverable reserves. Therefore, as prices and cost levels change from year to
year, the estimate of proved reserves also change.
Impairment of Assets
- --------------------
Long-lived assets used in operations are assessed for impairment whenever
changes in facts and circumstances indicate a possible significant deterioration
in the future cash flows expected to be generated by an asset group. If, upon
review, the sum of the undiscounted pretax cash flows is less than the carrying
value of the asset group, the carrying value is written down to estimated fair
value. Individual assets are grouped for impairment purposes based on a
judgmental assessment of the lowest level for which there are identifiable cash
flows that are largely independent of the cash flows of other groups of
assets--generally on a field-by-field basis for exploration and production
assets or at an entire complex level for downstream assets. Because there
usually is a lack of quoted market prices for long-lived assets, the fair value
usually is based on the
47
present values of expected future cash flows using discount rates commensurate
with the risks involved in the asset group. The expected future cash flows used
for impairment reviews and related fair value calculations are based on
judgmental assessments of future production volumes, prices and costs,
considering all available information at the date of review. See Note
9--Property Impairments in the Notes to Financial Statements.
Dismantlement, Removal and Environmental Costs
- ----------------------------------------------
Under various contracts, permits and regulations, the company has material legal
obligations to remove tangible equipment and restore the land or seabed at the
end of operations at production sites. The largest asset removal obligations
facing ConocoPhillips involve removal and disposal of offshore oil and gas
platforms around the world, and oil and gas production facilities and pipelines
in Alaska. The estimated undiscounted costs, net of salvage values, of
dismantling and removing these facilities are accrued, using primarily the
unit-of-production method, over the productive life of the asset. Estimating the
future asset removal costs necessary for this accounting calculation is
difficult. Most of these removal obligations are many years in the future and
the contracts and regulations often have vague descriptions of what removal
practices and criteria will have to be met when the removal event actually
occurs. Asset removal technologies and costs are constantly changing, as well as
political, environmental, safety and public relations considerations. See Note
10--Accrued Dismantlement, Removal and Environmental Costs in the Notes to
Financial Statements.
Business Acquisitions
- ---------------------
Purchase Price Allocation
Accounting for the acquisition of a business requires the allocation of the
purchase price to the various assets and liabilities of the acquired business.
For most assets and liabilities, purchase price allocation is accomplished by
recording the asset or liability at its estimated fair value. The most difficult
estimations of individual fair values are those involving properties, plants and
equipment and identifiable intangible assets. The company uses all available
information to make these fair value determinations and, for major business
acquisitions, typically engages an outside appraisal firm to assist in the fair
value determination of the acquired long-lived assets. The company has, if
necessary, up to one year after the acquisition closing date to finish these
fair value determinations and finalize the purchase price allocation.
48
Intangible Assets and Goodwill
In connection with the acquisition of Tosco Corporation on September 14, 2001,
the company recorded material intangible assets for Tosco tradenames, air
emission permit credits, and permits to operate refineries. These intangible
assets were determined to have indefinite useful lives and so are not amortized.
This judgmental assessment of an indefinite useful life has to be continuously
evaluated in the future. If, due to changes in facts and circumstances,
Management determines that these intangible assets then have definite useful
lives, amortization will have to commence at that time on a prospective basis.
As long as these intangible assets are judged to have indefinite lives, they
will be subject to periodic lower-of-cost-or-market tests, which requires
Management's judgment of the estimated fair value of these intangible assets.
See Note 3--Acquisition of Tosco Corporation in the Notes to Financial
Statements.
Also in connection with the acquisition of Tosco, the company recorded a
material amount of goodwill. Under the accounting rules for goodwill, this
intangible asset is not amortized. Instead, goodwill is subject to annual
reviews for impairment based on a two-step accounting test. The first step is to
compare the estimated fair value of any reporting units within the company that
have recorded goodwill with the recorded net book value (including the goodwill)
of the reporting unit. If the estimated fair value of the reporting unit is
higher than the recorded net book value, no impairment is deemed to exist and no
further testing is required that year. If, however, the estimated fair value of
the reporting unit is below the recorded net book value, then a second step must
be performed to determine the amount of the goodwill impairment to record, if
any. In this second step, the estimated fair value from the first step is used
as the purchase price in a hypothetical new acquisition of the reporting unit.
The various purchase business combination rules are followed to determine a
hypothetical purchase price allocation for the reporting unit's assets and
liabilities. The residual amount of goodwill that results from this hypothetical
purchase price allocation is compared with the recorded amount of goodwill for
the reporting unit, and the recorded amount is written-down to the hypothetical
amount if the hypothetical amount is the lower of the two. Because quoted market
prices for the company's reporting units are not available, Management has to
apply judgment in determining the estimated fair value of its reporting units
for purposes of performing the first step of this periodic goodwill impairment
test. Management uses all available information to make these fair value
determinations and may engage an outside appraisal firm for assistance. In
addition, if the first test step is not met, further judgment has to be applied
in determining the fair values of individual assets and
49
liabilities for purposes of the hypothetical purchase price allocation. Again,
Management has to use all available information to make these fair value
determinations and may engage an outside appraisal firm for assistance.
Inventory Valuation
- -------------------
Prior to the acquisition of Tosco in September 2001, the company's inventories
on the last-in, first-out (LIFO) cost basis were predominantly reflected on the
balance sheet at historical cost layers established many years ago, when price
levels were much lower. So, prior to 2001, the company's LIFO inventories were
relatively insensitive to current price level changes. However, the acquisition
of Tosco added a very large LIFO cost layer that was recorded at replacement
cost levels prevalent in late September 2001. As a result, the company's LIFO
cost inventories will now be much more sensitive to lower-of-cost-or-market
impairment write-downs in the future, whenever price levels fall. ConocoPhillips
recorded a LIFO inventory lower-of-cost-or-market impairment in the fourth
quarter of 2001 due to such a deterioration. The determination of replacement
cost values for the lower-of-cost-or-market test uses objective evidence, but
does involve judgment in determining the most appropriate objective evidence to
use in the calculations.
Projected Benefit Obligations
- -----------------------------
Determination of the projected benefit obligations for the company's defined
benefit pension and postretirement plans are important to the recorded amounts
for such obligations on the balance sheet and to the amount of benefit expense
in the income statement. This also impacts the required company contributions
into the plans. The actuarial determination of projected benefit obligations and
company contribution requirements involves judgment about uncertain future
events, including estimated retirement dates, salary levels at retirement,
mortality rates, lump-sum election rates, rates of return on plan assets, future
health care cost-trend rates, and rates of utilization of health care services
by retirees. Due to the specialized nature of these calculations, the company
engages outside actuarial firms to assist in the determination of these
projected benefit obligations. For ERISA-qualified pension plans, the actuary
exercises fiduciary care on behalf of plan participants in the determination of
the judgmental assumptions used in determining required company contributions
into plan assets. Due to differing objectives and requirements between financial
accounting rules and the pension plan funding regulations promulgated by
governmental agencies, the actuarial methods and assumptions for the two
purposes differ in certain important respects. Ultimately, the company will be
required to fund all promised benefits under pension and postretirement benefit
plans, but the judgmental assumptions used in the actuarial calculations
50
significantly affect periodic financial statements and funding patterns over
time.
OUTLOOK
On November 18, 2001, Phillips and Conoco announced that their Boards of
Directors had unanimously approved a merger of equals, and that the companies
had signed a definitive merger agreement to form a new company to be named
ConocoPhillips. At special shareholder meetings held on March 12, 2002, the
stockholders of both companies approved the merger.
On August 30, 2002, after receiving clearance from the U.S. Federal Trade
Commission, Conoco and Phillips combined their businesses by merging with
separate acquisition subsidiaries of ConocoPhillips. As a result, each company
became a wholly owned subsidiary of ConocoPhillips. For accounting purposes,
Phillips was treated as the acquirer and ConocoPhillips was treated as the
successor of Phillips. Under the terms of the agreement, Phillips shareholders
received one share of the new ConocoPhillips common stock for each share of
Phillips common stock that they owned and Conoco shareholders received 0.4677
shares of the new ConocoPhillips common stock for each share of Conoco that they
own. When the merger was consummated, former Phillips stockholders held
approximately 58 percent of the outstanding shares of ConocoPhillips common
stock, while former Conoco shareholders held approximately 42 percent.
Effective January 1, 2002, the Norwegian authorities implemented a production
curtailment on the Norwegian Continental shelf to support the efforts of major
oil exporting countries to stabilize crude prices. ConocoPhillips expects to
incur minimal impacts to its Norway production volumes during 2002 as a result
of these curtailments--less than 1 percent, compared with budgeted volumes for
the first and second quarters of the year. In Venezuela, Petroleos de Venezuela
S.A. (PdVSA), the state-owned oil company, has indicated production capacity for
the Hamaca heavy-oil project will be restricted during 2002, taking into
consideration pipeline constraints and major oil exporting country curtailment
recommendations. The future impact of curtailment on Hamaca's 2002 production is
uncertain, but has not been significant to date.
In December 2001, the Norwegian government endorsed the company's recommendation
for the removal and disposal of the steel structures onshore and in-place
disposal of cuttings related to Ekofisk I. Removal of 11 platforms and the
topside of the Ekofisk tank is scheduled to be completed by 2013. In addition,
the OSPAR (Oslo and Paris Convention for the Protection of the Marine
Environment of the Northeast Atlantic countries) has
51
endorsed in-place disposal of the concrete structure in a cleaned condition.
This issue is expected to be finalized by the Norwegian government in a separate
parliamentary bill during the spring session of 2002.
In December 2001, ConocoPhillips and its co-venturers in the Bayu-Undan field
received from the East Timor Council of Ministers an endorsement of the
Understanding on a tax and fiscal package that will allow the Bayu-Undan gas
development in the Timor Sea to proceed. The company is currently awaiting
ratification by Australia so that finalization of gas sales arrangements can
proceed. Finalization of a new treaty between Australia and East Timor would
allow plans to develop the potential gas resources to move forward.
On March 12, 2002, ConocoPhillips announced that it and its co-venturers had
signed a Heads of Agreement with The Tokyo Electric Power Company, Incorporated
(TEPCO) and Tokyo Gas Co., Ltd. (Tokyo Gas) that would enable ConocoPhillips and
its co-venturers to move forward with the gas development phase of the project
when the Australian authorities ratify the tax and fiscal package. Under the
terms of the agreement, the co-venturers would supply TEPCO and Tokyo Gas with
three million tons per year of liquefied natural gas for a period of 17 years,
utilizing natural gas from the Bayu-Undan field. First shipments would be
scheduled for January 2006. The agreement would allow ConocoPhillips to go
forward with plans to develop a liquefied natural gas facility near Darwin,
Australia, utilizing the company's Optimized Cascade liquefied natural gas
process. Final board approvals from co-venturers and formal project commitments
are expected to be completed by the end of the third quarter of 2002. On March
12, ConocoPhillips also announced that, under a separate agreement, the company
plans to sell a 10.08 percent interest in the unitized Bayu-Undan field to TEPCO
and Tokyo Gas.
During 2001, ConocoPhillips announced that it had signed a letter of intent with
El Paso Corporation contemplating EL Paso's purchasing liquefied natural gas
from the Greater Sunrise fields with possible transportation to markets in
Southern California and northern Baja California in Mexico. A definitive
purchase agreement was not reached between El Paso and the Greater Sunrise
owners. However, ConocoPhillips and El Paso are continuing with plans to develop
a project to build a liquefied natural gas import terminal in northern Baja
California to provide access to gas markets in that region. Front-end
engineering design is under way and the companies are working with federal,
state, and local officials in Mexico to secure permits for the project. A
decision to proceed with the terminal project is expected in the third quarter
of 2002. ConocoPhillips and El Paso would each control 50 percent of the
terminal capacity and each are pursuing
52
liquefied natural gas supplies and downstream gas markets to utilize their
respective shares of the capacity.
During 2001, ConocoPhillips was selected to participate in Core Venture 1
(CV-1), the largest of three proposed developments offered by the Kingdom of
Saudi Arabia's Natural Gas Initiative. CV-1 would include natural gas
exploration, midstream, petrochemical, and power and water investments in Saudi
Arabia. Negotiations are in progress between the Kingdom and co-venturers in the
CV-1 project with anticipated finalization of issues within the Preparatory
Agreement in the second quarter of 2002. ConocoPhillips has a 15 percent
interest in the project.
ConocoPhillips, along with BP and ExxonMobil, is evaluating the potential for a
natural gas pipeline from the North Slope to the Lower 48. While, in the current
economic environment, the company does not believe the project provides the
desired return on investment, given the significant size and risk associated
with the project, ConocoPhillips continues to search for a solution that will
allow this resource to be produced. The company's net book value of these North
Slope natural gas resources was $369 million at December 31, 2001.
In 2002, ConocoPhillips expects worldwide production of approximately 830,000
barrels-of-oil-equivalent per day from currently proved reserves, a slight
increase over the 821,000 daily average rate for 2001.
Crude oil and natural gas prices are subject to external factors over which the
company has no control, such as global economic conditions, demand growth,
inventory levels, weather, competing fuel prices and the availability of supply.
A worldwide economic slowdown, along with adequate inventories and an unusually
warm early winter, put downward pressure on energy prices in 2001 and early
2002. Major oil exporting countries pledged production restraints in late 2001,
somewhat stabilizing crude oil prices in early 2002. The warm winter and
adequate natural gas storage levels have kept U.S. natural gas prices around $2
per thousand cubic feet into early 2002.
Refining margins are subject to the price of crude oil and other feedstocks, and
the price of petroleum products, which are subject to market factors over which
the company has no control, such as the U.S. economy; seasonal factors that
affect demand, such as the summer driving months; and the levels of refining
output, including refining capacity relative to demand. A weak U.S. economy and
adequate supply have resulted in low refining margins in early 2002. The outlook
for the remainder of 2002, for both upstream and downstream prices, is dependent
on an economic recovery in the United States and worldwide, as well as
53
the level of output from major crude oil producing nations and their compliance
with pledged production restraints. Conflicts in the Middle East could also lead
to price volatility in 2002.
CAUTIONARY STATEMENT FOR THE PURPOSES OF THE "SAFE HARBOR" PROVISIONS OF THE
PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
ConocoPhillips is including the following cautionary statement to take advantage
of the "safe harbor" provisions of the PRIVATE SECURITIES LITIGATION REFORM ACT
OF 1995 for any forward-looking statement made by, or on behalf of, the company.
The factors identified in this cautionary statement are important factors (but
not necessarily all important factors) that could cause actual results to differ
materially from those expressed. Where any such forward-looking statement
includes a statement of the assumptions or bases underlying such forward-looking
statement, the company believes such assumptions or bases to be reasonable and
makes them in good faith. Assumed facts or bases almost always vary from actual
results, and the differences between assumed facts or bases and actual results
can be material, depending on the circumstances. Where, in any forward-looking
statement, the company, or its Management, expresses an expectation or belief as
to future results, there can be no assurance that the statement of expectation
or belief will result, or be achieved or accomplished.
The following are identified as important risk factors, but not all of the risk
factors, that could cause actual results to differ materially from those
expressed in any forward-looking statement made by, or on behalf of, the
company:
o Plans for the further implementation of Management's announced strategy for
certain of its business segments are subject to: the completion of the
announced merger with Conoco; receipt of any approvals or clearances that
may be required from domestic and foreign government authorities; required
disposition of assets, if any, to meet regulatory requirements; successful
integration of Conoco businesses, assets, operations and personnel with
those of the company; continued successful integration of the recently
acquired Tosco assets; the successful development and operation of the
company's current E&P projects, and the achievement of production
estimates; the achievement of cost savings and synergies that are dependent
on the integration of personnel, business systems and operations from the
Conoco merger and the Tosco acquisition; the operation and financing of the
DEFS and CPChem joint ventures; and the demand and prices for the products
produced by DEFS and CPChem.
54
o Plans to drill wells and develop offshore or onshore exploration and
production properties are subject to: the company's ability to obtain
agreements with co-venturers, partners and governments and government
agencies, including necessary permits; its ability to engage specialized
drilling, construction and other contractors and equipment and to obtain
economical and timely financing; construction of pipelines, processing and
production facilities for its Bayu-Undan, Bohai Bay, Hamaca and other E&P
projects; geological, land or sea conditions; world prices for oil, natural
gas and natural gas liquids; adequate and reliable transportation systems,
including the Trans-Alaska Pipeline System, the Valdez Marine Harbor
Terminal, and the acquired and to-be-constructed crude oil tankers; and
foreign and United States laws, including tax laws.
o Plans for the modernization, the debottlenecking or other improvement
projects at its refineries, including the installation and operation of its
proprietary sulfur removal technology implementation, and the timing of
production from such plants are subject to: approval from the company's
and/or subsidiaries' Boards of Directors; obtaining loans and/or project
financing; the issuance by foreign, federal, state, and municipal
governments, or agencies thereof; obtaining timely building, environmental
and other permits; and the availability of specialized contractors, work
force and equipment. Production and delivery of the company's products are
subject to: domestic and worldwide prices and demand for refined products;
availability of raw materials; and the availability of transportation for
products in the form of pipelines, railcars, trucks or ships.
o The ability to meet liquidity requirements, including the funding of the
company's capital program from borrowings, asset sales, and operations, is
subject to: the negotiation and execution of various bank, project and
public financings and related financing documents, the market for any such
debt, and interest rates on the debt; the identification of buyers and the
negotiation and execution of instruments of sale for any assets that may be
identified for sale; changes in the commodity prices of the company's basic
products of oil, natural gas and natural gas liquids, over which
ConocoPhillips may have little or no control; its ability to operate
refineries and exploration and production operations consistently and
safely, with no major disruption in production or transportation of
products from such operations; and the effect of foreign and domestic
legislation of federal, state and municipal governments that have
jurisdiction in regard to taxes, the environment and human resources.
55
o Estimates of proved reserves, and planned spending for maintenance and
environmental remediation were developed by company personnel using the
latest available information and data, and recognized techniques of
estimating, including those prescribed by the U.S. Securities and Exchange
Commission, generally accepted accounting principles and other applicable
requirements. Estimates of project costs, cost savings and synergies were
developed by the company from current information. The estimates for
reserves, supplies, costs, maintenance, environmental remediation, savings
and synergies can change positively or negatively as new information and
data become available.
56
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
CONOCOPHILLIPS
INDEX TO FINANCIAL STATEMENTS
<Table>
<Caption>
Page
----
Report of Independent Auditors.......................... 58
Consolidated Statement of Income for the years
ended December 31, 2001, 2000 and 1999................ 59
Consolidated Balance Sheet at December 31, 2001
and 2000.............................................. 60
Consolidated Statement of Cash Flows for the years
ended December 31, 2001, 2000 and 1999................ 61
Consolidated Statement of Changes in Common Stockholders'
Equity for the years ended December 31, 2001,
2000 and 1999......................................... 62
Notes to Financial Statements........................... 63
Supplementary Information
Oil and Gas Operations............................. 122
Selected Quarterly Financial Data.................. 141
INDEX TO FINANCIAL STATEMENT SCHEDULES
Schedule II--Valuation Accounts and Reserves............ 142
</Table>
All other schedules are omitted because they are either not required, not
significant, not applicable or the information is shown in another schedule, the
financial statements or in the notes to financial statements.
57
- --------------------------------------------------------------------------------
REPORT OF INDEPENDENT AUDITORS
The Board of Directors and Stockholders
ConocoPhillips
We have audited the accompanying consolidated balance sheets of ConocoPhillips
(formerly Phillips Petroleum Company) as of December 31, 2001 and 2000, and the
related consolidated statements of income, changes in common stockholders'
equity, and cash flows for each of the three years in the period ended December
31, 2001. Our audits also included financial statement Schedule II--Valuation
Accounts and Reserves. These financial statements and schedule are the
responsibility of the company's Management. Our responsibility is to express an
opinion on these financial statements and schedule based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by Management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the consolidated financial position of ConocoPhillips at
December 31, 2001 and 2000, and the consolidated results of its operations and
its cash flows for each of the three years in the period ended December 31,
2001, in conformity with accounting principles generally accepted in the United
States. Also, in our opinion, the related financial statement schedule, when
considered in relation to the basic financial statements taken as a whole,
presents fairly in all material respects the information set forth therein.
As discussed in Note 2 to the financial statements, in 2001 ConocoPhillips
changed its method of accounting for the costs of major maintenance turnarounds.
/s/ ERNST & YOUNG LLP
ERNST & YOUNG LLP
Tulsa, Oklahoma
March 15, 2002
except for Notes 23 and 25, as to
which the date is December 20, 2002
58
- --------------------------------------------------------------------------------
CONSOLIDATED STATEMENT OF INCOME CONOCOPHILLIPS
(FORMERLY PHILLIPS PETROLEUM COMPANY)
<Table>
<Caption>
Years Ended December 31 Millions of Dollars
-------------------------------------
2001 2000 1999
---------- ---------- ----------
REVENUES
Sales and other operating revenues* $ 26,341 22,265 15,090
Equity in earnings of affiliated companies 41 114 101
Other income 98 278 180
---------- ---------- ----------
Total Revenues 26,480 22,657 15,371
---------- ---------- ----------
COSTS AND EXPENSES
Purchased crude oil and products 14,292 11,851 8,004
Production and operating expenses 2,644 2,136 1,995
Exploration expenses 306 298 225
Selling, general and administrative expenses 941 621 660
Depreciation, depletion and amortization 1,386 1,175 898
Property impairments 26 100 69
Taxes other than income taxes* 3,184 2,248 1,979
Accretion on discounted liabilities 14 -- --
Interest and debt expense 338 369 279
Foreign currency transaction losses 11 58 33
Preferred dividend requirements of capital trusts
and minority interests 53 54 54
---------- ---------- ----------
Total Costs and Expenses 23,195 18,910 14,196
---------- ---------- ----------
Income from continuing operations before income
taxes 3,285 3,747 1,175
Provision for income taxes 1,653 1,900 573
---------- ---------- ----------
Income from continuing operations 1,632 1,847 602
Income from operations of discontinued businesses
(net of income taxes of $6, $7 and $3 for 2001,
2000 and 1999, respectively) 11 15 7
---------- ---------- ----------
INCOME BEFORE EXTRAORDINARY ITEM AND CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE 1,643 1,862 609
Extraordinary item (10) -- --
Cumulative effect of change in accounting principle 28 -- --
---------- ---------- ----------
NET INCOME $ 1,661 1,862 609
========== ========== ==========
NET INCOME PER SHARE OF COMMON STOCK
Basic
Continuing operations $ 5.57 7.26 2.38
Discontinued operations .04 .06 .03
---------- ---------- ----------
Before extraordinary item and cumulative
effect of change in accounting principle 5.61 7.32 2.41
Extraordinary item (.04) -- --
Cumulative effect of change in accounting
principle .10 -- --
---------- ---------- ----------
Net Income $ 5.67 7.32 2.41
========== ========== ==========
Diluted
Continuing operations $ 5.53 7.20 2.36
Discontinued operations .04 .06 .03
---------- ---------- ----------
Before extraordinary item and cumulative
effect of change in accounting principle 5.57 7.26 2.39
Extraordinary item (.03) -- --
Cumulative effect of change in accounting
principle .09 -- --
---------- ---------- ----------
Net Income $ 5.63 7.26 2.39
========== ========== ==========
AVERAGE COMMON SHARES OUTSTANDING
(in thousands)
Basic 292,964 254,490 252,827
Diluted 295,016 256,326 254,433
---------- ---------- ----------
*Includes excise taxes on petroleum products sales $ 2,607 1,781 1,750
</Table>
See Notes to Financial Statements.
59
- --------------------------------------------------------------------------------
CONSOLIDATED BALANCE SHEET CONOCOPHILLIPS
(FORMERLY PHILLIPS PETROLEUM COMPANY)
<Table>
<Caption>
At December 31 Millions of Dollars
--------------------
2001 2000
-------- --------
ASSETS
Cash and cash equivalents $ 142 149
Accounts and notes receivable (less allowances of
$33 million in 2001 and $18 million in 2000) 1,185 1,547
Accounts and notes receivable--related parties 105 226
Inventories 2,600 350
Deferred income taxes 47 191
Prepaid expenses and other current assets 262 130
Assets of discontinued operations 108 96
-------- --------
Total Current Assets 4,449 2,689
Investments and long-term receivables 3,316 2,998
Properties, plants and equipment (net) 23,716 14,707
Goodwill 2,281 --
Intangibles 1,313 --
Deferred income taxes 9 --
Deferred charges 133 115
-------- --------
Total $ 35,217 20,509
======== ========
LIABILITIES
Accounts payable $ 2,648 1,791
Accounts payable--related parties 91 92
Notes payable and long-term debt due within one year 44 262
Accrued income and other taxes 938 813
Other accruals 796 497
Liabilities of discontinued operations 34 47
-------- --------
Total Current Liabilities 4,551 3,502
Long-term debt 8,645 6,622
Accrued dismantlement, removal and environmental costs 1,142 702
Deferred income taxes 4,006 1,885
Employee benefit obligations 953 494
Other liabilities and deferred credits 925 560
-------- --------
Total Liabilities 20,222 13,765
-------- --------
COMPANY-OBLIGATED MANDATORILY REDEEMABLE PREFERRED
SECURITIES OF PHILLIPS 66 CAPITAL TRUSTS I AND II 650 650
-------- --------
OTHER MINORITY INTERESTS 5 1
-------- --------
COMMON STOCKHOLDERS' EQUITY
Common stock--1,000,000,000 shares authorized at
$1.25 par value
Issued (2001--430,439,743 shares;
2000--306,380,511 shares)
Par value 538 383
Capital in excess of par 9,069 2,153
Treasury stock (at cost: 2001--20,725,114 shares;
2000--23,142,005 shares) (1,038) (1,156)
Compensation and Benefits Trust (CBT)
(at cost: 2001--27,556,573 shares;
2000--27,849,430 shares) (934) (943)
Accumulated other comprehensive loss (255) (100)
Unearned employee compensation--Long-Term Stock
Savings Plan (LTSSP) (237) (263)
Retained earnings 7,197 6,019
-------- --------
Total Common Stockholders' Equity 14,340 6,093
-------- --------
Total $ 35,217 20,509
======== ========
</Table>
See Notes to Financial Statements.
60
- --------------------------------------------------------------------------------
CONSOLIDATED STATEMENT OF CASH FLOWS CONOCOPHILLIPS
(FORMERLY PETROLEUM COMPANY)
<Table>
<Caption>
Years Ended December 31 Millions of Dollars
--------------------------------
2001 2000 1999
-------- -------- --------
CASH FLOWS FROM OPERATING ACTIVITIES
Income from continuing operations $ 1,632 1,847 602
Adjustments to reconcile income from
continuing operations to net cash provided
by continuing operations
Non-working capital adjustments
Depreciation, depletion and amortization 1,386 1,175 898
Property impairments 26 100 69
Dry hole costs and leasehold impairment 99 130 92
Accretion on discounted liabilities 14 -- --
Deferred taxes 515 412 160
Other 108 (210) (80)
Working capital adjustments*
Increase (decrease) in aggregate balance
of accounts receivable sold (174) 317 1
Decrease (increase) in other accounts and
notes receivable 1,330 (710) (540)
Decrease (increase) in inventories (278) (12) 18
Decrease in prepaid expenses and other
current assets 43 84 88
Increase (decrease) in accounts payable (1,019) 417 326
Increase (decrease) in taxes and other
accruals (120) 439 308
-------- -------- --------
Net cash provided by continuing operations 3,562 3,989 1,942
Net cash provided by (used for) discontinued
operations -- 25 (1)
-------- -------- --------
Net Cash Provided by Operating Activities 3,562 4,014 1,941
-------- -------- --------
CASH FLOWS FROM INVESTING ACTIVITIES
Acquisitions, net of cash acquired 80 (6,443) --
Capital expenditures and investments, including
dry hole costs (3,077) (2,017) (1,686)
Proceeds from contributing assets to joint ventures -- 2,061 --
Proceeds from asset dispositions 256 850 225
Long-term advances to affiliates and other
investments (21) (208) (17)
-------- -------- --------
Net cash used for continuing operations (2,762) (5,757) (1,478)
Net cash used for discontinued operations (8) (5) (4)
-------- -------- --------
Net Cash Used for Investing Activities (2,770) (5,762) (1,482)
-------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of debt 566 2,552 528
Repayment of debt (945) (360) (527)
Purchase of company common stock -- -- (13)
Issuance of company common stock 51 31 24
Dividends paid on common stock (403) (346) (344)
Other (68) (118) (86)
-------- -------- --------
Net cash provided by (used for) continuing operations (799) 1,759 (418)
-------- -------- --------
Net Cash Provided by (Used for) Financing Activities (799) 1,759 (418)
-------- -------- --------
NET CHANGE IN CASH AND CASH EQUIVALENTS (7) 11 41
Cash and cash equivalents at beginning of year 149 138 97
-------- -------- --------
Cash and Cash Equivalents at End of Year $ 142 149 138
======== ======== ========
</Table>
*Net of acquisition and disposition of businesses.
See Notes to Financial Statements.
61
- --------------------------------------------------------------------------------
CONSOLIDATED STATEMENT OF CHANGES CONOCOPHILLIPS
IN COMMON STOCKHOLDERS' EQUITY (FORMERLY PHILLIPS PETROLEUM COMPANY)
<Table>
<Caption>
Millions of Dollars
----------------------------------------
Shares of Common Stock Common Stock
----------------------------------- ----------------------------------------
Held in Held in Par Capital in Treasury
Issued Treasury CBT Value Excess of Par Stock CBT
----------- ---------- ---------- ------- ------------- -------- -----
December 31, 1998 306,380,511 25,259,040 29,125,863 $ 383 2,055 (1,259) (987)
Net income
Other comprehensive income
Foreign currency translation
Unrealized gain on securities, net of
reclassification adjustments
Equity affiliates:
Foreign currency translation
Comprehensive income
Cash dividends paid on common stock
Distributed under incentive
compensation and other benefit plans (849,495) (767,605) 43 42 26
Recognition of LTSSP unearned
compensation
Tax benefit of dividends on
unallocated LTSSP shares
----------- ---------- ---------- ------- ------------- -------- -----
December 31, 1999 306,380,511 24,409,545 28,358,258 383 2,098 (1,217) (961)
Net income
Other comprehensive income
Foreign currency translation
Unrealized loss on securities
Equity affiliates:
Foreign currency translation
Comprehensive income
Cash dividends paid on common stock
Distributed under incentive
compensation and other benefit plans (1,267,540) (508,828) 55 61 18
Recognition of LTSSP unearned
compensation
Tax benefit of dividends on
unallocated LTSSP shares
----------- ---------- ---------- ------- ------------- -------- -----
December 31, 2000 306,380,511 23,142,005 27,849,430 383 2,153 (1,156) (943)
Net income
Other comprehensive income
Minimum pension liability adjustment
Foreign currency translation
Unrealized loss on securities
Hedging activities
Equity affiliates:
Foreign currency translation
Derivatives related
Comprehensive income
Cash dividends paid on common stock
Tosco acquisition 124,059,232 155 6,883
Distributed under incentive
compensation and other benefit plans (2,416,891) (292,857) 33 118 9
Recognition of LTSSP unearned
compensation
Tax benefit of dividends on
unallocated LTSSP shares
----------- ---------- ---------- ------- ------------- -------- -----
DECEMBER 31, 2001 430,439,743 20,725,114 27,556,573 $ 538 9,069 (1,038) (934)
=========== ========== ========== ======= ============= ======== =====
</Table>
<Table>
<Caption>
Millions of Dollars
------------------------------------------------
Accumulated Unearned
Other Employee
Comprehensive Compensation Retained
Loss --LTSSP Earnings Total
------------- ------------ -------- -------
December 31, 1998 (13) (303) 4,343 4,219
-------
Net income 609 609
Other comprehensive income
Foreign currency translation (14) (14)
Unrealized gain on securities, net of
reclassification adjustments (2) (2)
Equity affiliates:
Foreign currency translation (2) (2)
-------
Comprehensive income 591
-------
Cash dividends paid on common stock (344) (344)
Distributed under incentive
compensation and other benefit plans (50) 61
Recognition of LTSSP unearned
compensation 17 17
Tax benefit of dividends on
unallocated LTSSP shares 5 5
------------- ------------ -------- -------
December 31, 1999 (31) (286) 4,563 4,549
-------
Net income 1,862 1,862
Other comprehensive income
Foreign currency translation (53) (53)
Unrealized loss on securities (1) (1)
Equity affiliates:
Foreign currency translation (15) (15)
-------
Comprehensive income 1,793
-------
Cash dividends paid on common stock (346) (346)
Distributed under incentive
compensation and other benefit plans (65) 69
Recognition of LTSSP unearned
compensation 23 23
Tax benefit of dividends on
unallocated LTSSP shares 5 5
------------- ------------ -------- -------
December 31, 2000 (100) (263) 6,019 6,093
-------
Net income 1,661 1,661
Other comprehensive income
Minimum pension liability adjustment (143) (143)
Foreign currency translation (14) (14)
Unrealized loss on securities (2) (2)
Hedging activities (4) (4)
Equity affiliates:
Foreign currency translation (3) (3)
Derivatives related 11 11
-------
Comprehensive income 1,506
-------
Cash dividends paid on common stock (403) (403)
Tosco acquisition 7,038
Distributed under incentive
compensation and other benefit plans (84) 76
Recognition of LTSSP unearned
compensation 26 26
Tax benefit of dividends on
unallocated LTSSP shares 4 4
------------- ------------ -------- -------
DECEMBER 31, 2001 (255) (237) 7,197 14,340
============= ============ ======== =======
</Table>
See Notes to Financial Statements.
62
- --------------------------------------------------------------------------------
NOTES TO FINANCIAL STATEMENTS CONOCOPHILLIPS
(FORMERLY PETROLEUM COMPANY)
NOTE 1--ACCOUNTING POLICIES
o CONSOLIDATION PRINCIPLES AND INVESTMENTS--Majority-owned, controlled
subsidiaries are consolidated. Investments in affiliates in which the
company owns 20 percent to 50 percent of voting control are generally
accounted for under the equity method. Undivided interests in oil and gas
joint ventures, pipelines and natural gas plants are consolidated on a pro
rata basis. Other securities and investments are generally carried at cost.
o REVENUE RECOGNITION--Revenues associated with sales of crude oil, natural
gas, natural gas liquids, petroleum and chemical products, and all other
items are recorded when title passes to the customer. Revenues from the
production of natural gas properties in which the company has an interest
with other producers are recognized based on the actual volumes sold by the
company during the period. Any differences between volumes sold and
entitlement volumes, based on the company's 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 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.
o RECLASSIFICATION--All periods have been reclassified for discontinued
operations (see Note 25--Merger with Conoco Inc.). Certain amounts in the
2000 and 1999 financial statements have been reclassified to conform with
the 2001 presentation, including presenting excise taxes on petroleum
products sales as a component of operating revenues and taxes other than
income taxes.
o USE OF ESTIMATES--The preparation of financial statements in conformity
with accounting principles generally accepted in the United States requires
Management to make estimates and assumptions that affect the reported
amounts of assets, liabilities, revenues and expenses, and the disclosures
of contingent assets and liabilities. Actual results could differ from the
estimates and assumptions used.
63
o CASH EQUIVALENTS--Cash equivalents are highly liquid short-term investments
that are readily convertible to known amounts of cash and have original
maturities within three months from their date of purchase.
o INVENTORIES--The company has several valuation methods for its various
types of inventories and consistently uses the following methods for each
type of inventory. Crude oil and petroleum products inventories are valued
at the lower of cost or market in the aggregate, primarily on the last-in,
first-out (LIFO) basis. Any necessary lower-of-cost-or-market write-downs
are recorded as permanent adjustments to the LIFO cost basis. LIFO is used
to better match current inventory costs with current revenues and to meet
tax-conformity requirements. Materials, supplies and other miscellaneous
inventories are valued using the weighted-average-cost method, consistent
with general industry practice. Merchandise inventories at the company's
retail marketing outlets are valued using the first-in, first-out (FIFO)
retail method, consistent with general industry practice.
o DERIVATIVE INSTRUMENTS--All derivative instruments are recorded on the
balance sheet at fair market value in either accounts and notes receivable
or accounts payable. Recognition of the gain or loss that results from
recording and adjusting a derivative to fair market value depends on the
purpose for issuing or holding the derivative. Gains and losses from
derivatives that are not used as hedges are recognized immediately in
earnings. If a derivative is used to hedge the fair value of an asset,
liability, or firm commitment, the gains or losses from adjusting the
derivative to its market value will be immediately recognized in earnings
and, to the extent the hedge is effective, offset the concurrent
recognition of changes in the fair value of the hedged item. Gains or
losses from derivatives hedging cash flows will be recorded on the balance
sheet in accumulated other comprehensive income/(loss) until the hedged
transaction is recognized in earnings; however, to the extent the change in
the value of the derivative exceeds the change in the anticipated cash
flows of the hedged transaction, the excess gains or losses will be
recognized immediately in earnings.
In the consolidated statement of income, gains and losses from derivatives
used for trading are recorded in other income. Gains and losses from
derivatives used for purposes other than trading are recorded in either
sales and other operating revenues or purchased crude oil and products,
64
depending on the purpose for issuing or holding the derivative.
o OIL AND GAS EXPLORATION AND DEVELOPMENT--Oil and gas exploration and
development costs are accounted for using the successful efforts method of
accounting.
PROPERTY ACQUISITION COSTS--Oil and gas leasehold acquisition costs
are capitalized. Leasehold impairment is recognized based on
exploratory experience and Management's judgment. Upon discovery of
commercial reserves, leasehold costs are transferred to proved
properties.
EXPLORATORY COSTS--Geological and geophysical costs and the costs of
carrying and retaining undeveloped properties are expensed as
incurred. Exploratory well costs are capitalized pending further
evaluation of whether economically recoverable reserves have been
found. If economically recoverable reserves are not found, exploratory
well costs are expensed as dry holes. All exploratory wells are
evaluated for economic viability within one year of well completion.
Exploratory wells that discover potentially economic reserves that are
in areas where a major capital expenditure would be required before
production could begin, and where the economic viability of that major
capital expenditure depends upon the successful completion of further
exploratory work in the area, remain capitalized as long as the
additional exploratory work is under way or firmly planned.
DEVELOPMENT COSTS--Costs incurred to drill and equip development
wells, including unsuccessful development wells, are capitalized.
DEPLETION AND AMORTIZATION--Leasehold costs of producing properties
are depleted using the unit-of-production method based on estimated
proved oil and gas reserves. Amortization of intangible development
costs is based on the unit-of-production method using estimated proved
developed oil and gas reserves.
o INTANGIBLE ASSETS OTHER THAN GOODWILL--Intangible assets that have finite
useful lives are amortized by the straight-line method over their useful
lives. Intangible assets that have indefinite useful lives are not
amortized but are tested at least annually for impairment. Intangible
assets are considered impaired if the fair value of the intangible asset is
lower than cost. Fair value of intangible assets is determined based on
quoted market prices in active markets,
65
if available. If quoted market prices are not available, fair value of
intangible assets is determined based upon the present values of expected
future cash flows using discount rates commensurate with the risks involved
in the asset, or upon estimated replacement cost, if expected future cash
flows from the intangible asset are not determinable.
o GOODWILL--Goodwill is not amortized but is tested at least annually for
impairment. If the fair value of a reporting unit is less than the recorded
book value of the reporting unit's assets (including goodwill), less
liabilities, then a hypothetical purchase price allocation is performed on
the reporting unit's assets and liabilities using the fair value of the
reporting unit as the purchase price in the calculation. If the amount of
goodwill resulting from this hypothetical purchase price allocation is less
than the recorded amount of goodwill, the recorded goodwill is written down
to the new amount. Reporting units for purposes of goodwill impairment
calculations are one level below the company's operating segment level.
Because quoted market prices are not available for the company's reporting
units, the fair value of the reporting units is determined based upon
consideration of several factors, including observed market multiples of
operating cash flows and net income, the depreciated replacement cost of
tangible equipment, and/or the present values of expected future cash flows
using discount rates commensurate with the risks involved in the asset.
o DEPRECIATION AND AMORTIZATION--Depreciation and amortization of properties,
plants and equipment on producing oil and gas properties and on certain
pipeline assets (those which are expected to have a declining utilization
pattern) are determined by the unit-of-production method. Depreciation and
amortization of all other properties, plants and equipment are determined
by either the individual-unit-straight-line method or the
group-straight-line method (for those individual units that are highly
integrated with other units).
o IMPAIRMENT OF PROPERTIES, PLANTS AND EQUIPMENT--Properties, plants and
equipment used in operations are assessed for impairment whenever changes
in facts and circumstances indicate a possible significant deterioration in
the future cash flows expected to be generated by an asset group. If, upon
review, the sum of the undiscounted pretax cash flows is less than the
carrying value of the asset group, the carrying value is written down to
estimated fair value. Individual assets are grouped for impairment purposes
at the lowest level for which there are identifiable cash flows that are
66
largely independent of the cash flows of other groups of assets--generally
on a field-by-field basis for exploration and production assets or at an
entire complex level for downstream assets. The fair value of impaired
assets is determined based on quoted market prices in active markets, if
available, or upon the present values of expected future cash flows using
discount rates commensurate with the risks involved in the asset group.
Long-lived assets committed by Management for disposal within one year are
accounted for at the lower of amortized cost or fair value, less cost to
sell.
The expected future cash flows used for impairment reviews and related fair
value calculations are based on estimated future production volumes, prices
and costs, considering all available evidence at the date of review. If the
future production price risk has been hedged, the hedged price is used in
the calculations for the period and quantities hedged. The impairment
review includes cash flows from proved developed and undeveloped reserves,
including any development expenditures necessary to achieve that
production. The price and cost outlook assumptions used in impairment
reviews differ from the assumptions used in the Standardized Measure of
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserve
Quantities. In that disclosure, Financial Accounting Standards Board (FASB)
Statement No. 69, "Disclosures about Oil and Gas Producing Activities,"
requires the use of prices and costs at the balance sheet date, with no
projection of future changes in those assumptions.
o MAINTENANCE AND REPAIRS--The costs of maintenance and repairs, which are
not significant improvements, are expensed when incurred. Effective January
1, 2001, turnaround costs of major producing units are expensed as
incurred. Prior to 2001, the estimated turnaround costs of major producing
units were accrued in other liabilities over the estimated interval between
turnarounds.
o SHIPPING AND HANDLING COSTS--The company's Exploration and Production
segment includes shipping and handling costs in production and operating
expenses, while the Refining and Marketing segment records shipping and
handling costs in purchased crude oil and products.
o ADVERTISING COSTS--Production costs of media advertising are deferred until
the first public showing of the advertisement. Advances to secure
advertising slots at specific sports, racing or other events are deferred
until the event occurs. All other advertising costs are expensed as
incurred, unless the cost has benefits which clearly extend beyond the
interim
67
period in which the expenditure is made, in which case the advertising cost
is deferred and amortized ratably over the interim periods which clearly
benefit from the expenditure. By the end of the fiscal year, all such
interim deferred advertising costs are fully amortized to expense.
o PROPERTY DISPOSITIONS--When complete units of depreciable property are
retired or sold, the asset cost and related accumulated depreciation are
eliminated, with any gain or loss reflected in income. When less than
complete units of depreciable property are disposed of or retired, the
difference between asset cost and salvage value is charged or credited to
accumulated depreciation.
o DISMANTLEMENT, REMOVAL AND ENVIRONMENTAL COSTS--The estimated undiscounted
costs, net of salvage values, of dismantling and removing major oil and gas
production and transportation facilities, including necessary site
restoration, are accrued using either the unit-of-production or the
straight-line method, which is used for certain regional production
transportation assets that are expected to have a straight-line utilization
pattern.
Environmental expenditures are expensed or capitalized as appropriate,
depending upon their future economic benefit. Expenditures that relate to
an existing condition caused by past operations, and that do not have
future economic benefit, are expensed. Liabilities for these expenditures
are recorded on an undiscounted basis (unless acquired in a purchase
business acquisition) when environmental assessments or cleanups are
probable and the costs can be reasonably estimated. Recoveries of
environmental remediation costs from other parties are recorded as assets
when their receipt is deemed probable.
o FOREIGN CURRENCY TRANSLATION--Adjustments resulting from the process of
translating foreign functional currency financial statements into U.S.
dollars are included in accumulated other comprehensive loss in common
stockholders' equity. Foreign currency transaction gains and losses are
included in current earnings. Most of the company's foreign operations use
their local currency as the functional currency.
o INCOME TAXES--Deferred income taxes are computed using the liability method
and are provided on all temporary differences between the
financial-reporting basis and the tax basis of the company's assets and
liabilities, except for temporary differences related to investments in
certain foreign subsidiaries and foreign corporate joint ventures that are
essentially permanent in duration. Allowable tax
68
credits are applied currently as reductions of the provision for income
taxes.
o NET INCOME PER SHARE OF COMMON STOCK--Basic income per share of common
stock is calculated based upon the daily weighted-average number of common
shares outstanding during the year, including shares held by the LTSSP.
Diluted income per share of common stock includes the above, plus
"in-the-money" stock options issued under company compensation plans.
Treasury stock and shares held by the CBT are excluded from the daily
weighted-average number of common shares outstanding in both calculations.
NOTE 2--EXTRAORDINARY ITEM AND ACCOUNTING CHANGE
In the third quarter of 2001, ConocoPhillips incurred an extraordinary loss of
$10 million (after reduction for income taxes of $4 million) attributable to the
call premium on the early retirement of its $300 million 9.18% Notes due
September 15, 2021, at 104.59 percent. The redemption was funded by issuing
commercial paper.
Effective January 1, 2001, the company changed its method of accounting for the
costs of major maintenance turnarounds from the accrue-in-advance method to the
expense-as-incurred method to reflect the impact of a turnaround in the period
that it occurs. The new method is preferable because it results in the
recognition of costs at the time obligations are incurred. The cumulative effect
of this accounting change increased net income in 2001 by $28 million (after
reduction for income taxes of $15 million).
The pro forma effects of retroactive application of the change in accounting
method are presented below:
<Table>
<Caption>
Millions of Dollars
Except Per Share Amounts
------------------------------------
2001 2000 1999
---------- ---------- ----------
Income before extraordinary item $ 1,643 1,851 609
Earnings per share
Basic 5.61 7.27 2.41
Diluted 5.57 7.22 2.39
---------- ---------- ----------
Net income $ 1,633 1,851 609
Earnings per share
Basic 5.57 7.27 2.41
Diluted 5.54 7.22 2.39
---------- ---------- ----------
</Table>
69
NOTE 3--ACQUISITION OF TOSCO CORPORATION
On September 14, 2001, Tosco Corporation (Tosco) was merged with a subsidiary of
ConocoPhillips, as a result of which ConocoPhillips became the owner of 100
percent of the outstanding common stock of Tosco. Tosco's results of operations
have been included in ConocoPhillips' consolidated financial statements since
that date. Tosco's operations included seven U.S. refineries with a total crude
oil capacity of 1.31 million barrels per day; one 75,000-barrel-per-day refinery
located in Cork, Ireland; and various marketing, transportation, distribution
and corporate assets.
The primary reasons for ConocoPhillips' acquisition of Tosco, and the primary
factors that contributed to a purchase price that resulted in recognition of
goodwill, are:
o The Tosco operations would deliver earnings prospects, and potential
strategic and other benefits.
o Combining the two companies' operations would provide significant cost
savings.
o Adding Tosco to ConocoPhillips' Refining and Marketing (R&M) operations
would give the segment the size, scale and resources to compete more
effectively.
o The merger would transform ConocoPhillips into a stronger, more integrated
oil company with the benefits of increased size and scale, improving the
stability of the combined businesses' earnings in varying economic and
market climates.
o The combined company would have a stronger balance sheet, improving its
access to capital in the future.
o The increased cash flow and access to capital resulting from the Tosco
acquisition would allow ConocoPhillips to pursue other opportunities in the
future.
Based on an exchange ratio of 0.8 shares of ConocoPhillips common stock for each
Tosco share, ConocoPhillips issued approximately 124.1 million common shares and
4.7 million vested employee stock options in the exchange, which increased
common stockholders' equity by approximately $7 billion. The common stock was
valued at $55.50 per share, which was ConocoPhillips' average common stock price
over the two-day trading period before and after the February 4, 2001, public
announcement of the transaction. The employee stock options were valued using
the Black-Scholes option
70
pricing model, based on assumptions prevalent at the February announcement date.
The transaction was accounted for using the purchase method of accounting as
required by FASB Statement No. 141, "Business Combinations," which was issued in
the second quarter of 2001. Goodwill and identifiable intangible assets recorded
in the acquisition will be tested periodically for impairment as required by
FASB Statement No. 142, "Goodwill and Other Intangible Assets," also issued in
the second quarter of 2001.
The allocation of the purchase price to specific assets and liabilities is
based, in part, upon an outside appraisal of Tosco's long-lived assets. The
allocation is still preliminary at this time. The company expects to finalize
the outside appraisal of the long-lived assets and the determination of the fair
value of all other Tosco assets and liabilities in 2002. Deferred tax
liabilities will also be finalized after the final allocation of the purchase
price and the final tax basis of the assets and liabilities has been determined.
Based on the year-end 2001 preliminary purchase price allocation, the following
table summarizes the fair values of the assets acquired and liabilities assumed
at September 14, 2001:
<Table>
<Caption>
Millions
of Dollars
----------
Cash and cash equivalents $ 103
Accounts and notes receivable 712
Inventories 1,965
Prepaid expenses and other current assets 154
Investments and long-term receivables 131
Properties, plants and equipment
(including $1,718 of land) 7,673
Identifiable intangible assets 1,251
Goodwill 2,288
Deferred charges 11
----------
Total assets $ 14,288
==========
Accounts payable $ 1,914
Accrued income and other taxes 401
Other accruals 214
Long-term debt 2,135
Accrued environmental costs 303
Deferred income taxes 1,755
Employee benefit obligations 177
Other liabilities and deferred credits 309
Common stockholders' equity 7,080
----------
Total liabilities and equity $ 14,288
==========
</Table>
71
The $1,251 million of identifiable intangible assets consist primarily of
marketing trade names ($655 million) and refinery air emission and operating
permits ($562 million). The preliminary appraisal methodology used to value
refinery air emission permits is presently under review and, depending on the
outcome of that review, could result in a reallocation of purchase price between
identifiable intangible assets and goodwill. Of the $1,251 million, $1,240
million has been preliminarily allocated to intangible assets not subject to
amortization, while $11 million has been preliminarily allocated to intangible
assets with a weighted-average amortization period of seven years.
The company has not yet determined the assignment of Tosco goodwill to specific
reporting units. Currently, all Tosco goodwill is being reported as part of the
R&M reporting segment. Of the $2,288 million of goodwill, a significant portion,
$1,755 million, was attributable to deferred tax liabilities, which are required
to be recorded on an undiscounted basis. Therefore, a significant portion of the
goodwill will be allocated to reporting units based on the sources of the
book-tax differences that give rise to the deferred tax liabilities. This
goodwill is not deductible for tax purposes. The remaining $533 million of true
goodwill will ultimately be assigned to those reporting units that benefit from
the synergies and strategic advantages of the merger.
Expected expenditures for Tosco environmental remediation activities are: $61
million in 2002, $55 million in 2003, $43 million in 2004, $34 million in 2005,
and $33 million in 2006. Remaining expenditures thereafter are expected to be
$150 million. The effect of inflation, net of a 5 percent discount factor,
reduced the accrual by $73 million, resulting in a discounted environmental
liability of $303 million at December 31, 2001.
The following unaudited pro forma summary presents information as if Tosco had
been acquired at the beginning of each period presented. The pro forma amounts
include certain adjustments, including recognition of depreciation and
amortization based on the preliminary allocated purchase price of the
properties, plants and equipment acquired; adjustment of interest for the
amortization of the fair-value adjustment to debt; cessation of the amortization
of deferred gains not recognizable in the purchase price allocation; accretion
of discount on environmental accruals recorded at net present values; and
adjustments to conform Tosco's accounting policies for major maintenance
turnarounds to ConocoPhillips' expense-as-incurred method. The pro forma amounts
do not reflect any benefits from economies
72
which might be achieved from combining the operations. The pro forma information
does not necessarily reflect the actual results that would have occurred had the
companies been combined during the periods presented, nor is it necessarily
indicative of the future results of operations of the combined companies:
<Table>
<Caption>
Millions of Dollars
Except Per Share Amounts
------------------------
2001 2000
---------- -----------
Revenues $ 47,338 50,789
Income before extraordinary item
and cumulative effect of change
in accounting principle 2,127 2,392
Net income 2,145 2,392
Income before extraordinary item
and cumulative effect of change
in accounting principle per share
of common stock
Basic 5.59 6.32
Diluted 5.54 6.26
Net income per share of common stock
Basic 5.64 6.32
Diluted 5.59 6.26
---------- ----------
</Table>
NOTE 4--ALASKAN ACQUISITION
On April 26, 2000, ConocoPhillips purchased all of Atlantic Richfield Company's
(ARCO) Alaska businesses, other than three double-hulled tankers under
construction and certain pipeline operations, which were acquired on August 1,
2000. The acquisition was accounted for using the purchase method of accounting.
Because the purchase was retroactive to January 1, 2000, the activity from that
date until the dates of closing has been reflected as adjustments to the
purchase price. Results of operations for the acquired businesses were included
in ConocoPhillips' income statement effective after April 26, and August 1,
2000, respectively.
ConocoPhillips used a combination of new corporate borrowings and available cash
to fund the $6,441 million cash purchase price of the ARCO Alaska businesses,
paid $15 million cash for acquisition-related costs, assumed $265 million of
variable-rate long-term debt, and assumed working capital and various other
liabilities and assets. ConocoPhillips did not receive any indemnification for
environmental liabilities associated with the ARCO Alaska operations. The
allocation of the purchase price to specific assets and liabilities was based,
in part, on an outside
73
appraisal of ARCO Alaska's long-lived assets. Based on the final purchase price
allocation, the following table summarizes the fair values of the assets
acquired and liabilities assumed during 2000:
<Table>
<Caption>
Millions
of Dollars
----------
Cash and cash equivalents $ 9
Accounts and notes receivable 92
Inventories 160
Prepaid expenses and other current assets 22
Investments and long-term receivables 4
Properties, plants and equipment 7,032
Other long-term assets 7
----------
Total assets acquired 7,326
----------
Accounts payable (191)
Other accruals (94)
Long-term debt (265)
Accrued environmental costs (179)
Deferred income taxes (47)
Employee benefit obligations (48)
Other liabilities (46)
----------
Total liabilities assumed (870)
----------
Net cash paid $ 6,456
==========
</Table>
No goodwill was recorded in the purchase price allocation.
The following unaudited pro forma summary presents information as if the
businesses acquired on April 26, and August 1, 2000, had been acquired at the
beginning of each period presented. The pro forma amounts include certain
adjustments, including recognition of depreciation, depletion and amortization;
interest on additional debt incurred; capitalization of interest on major
projects under development; and adjustments to conform ARCO Alaska's accounting
policy that capitalized the costs of enhanced oil recovery miscible injectants
to ConocoPhillips' policy of expensing such injectants as incurred. The pro
forma amounts do not reflect any benefits from economies which might be achieved
from combining the operations. The pro forma information does not necessarily
reflect the actual results that would have occurred had the businesses been
combined during the periods presented, nor is it necessarily indicative of
future results of operations of the combined companies:
74
<Table>
<Caption>
Millions of Dollars
Except Per Share Amounts
------------------------
2000 1999
---------- -----------
Revenues* $ 23,774 17,649
Income before extraordinary item
and cumulative effect of change
in accounting principle 2,097 875
Net income 2,097 875
Net income per share of common stock
Basic 8.24 3.46
Diluted 8.18 3.44
---------- ----------
</Table>
*Restated to include excise taxes on petroleum products sales.
During 2001, net cash activity with BP related to the acquisition was not
material. However, there was a $128 million increase in properties, plants and
equipment during the period due to the additional quantification and recognition
of certain non-cash liabilities of the acquired businesses, primarily an
additional accrual, on a discounted basis, to cover environmental remediation
activities required by the state of Alaska at exploration and production sites
formerly owned by ARCO. Expected expenditures for Alaska remediation activities
are: $27 million in 2002, $18 million in 2003, $16 million in 2004, $17 million
in 2005, and $15 million in 2006. Remaining expenditures thereafter are expected
to be $83 million. The effect of inflation, net of a 5 percent discount factor,
reduced the accrual by $13 million, resulting in a discounted environmental
liability of $163 million at December 31, 2001.
NOTE 5--INVENTORIES
Inventories at December 31 were:
<Table>
<Caption>
Millions of Dollars
-------------------
2001 2000
-------- --------
Crude oil and petroleum products $ 2,225 210
Merchandise 144 13
Materials, supplies and other 231 127
-------- --------
$ 2,600 350
======== ========
</Table>
Included were inventories valued on a LIFO basis totaling $2,178 million and
$200 million at December 31, 2001 and 2000, respectively. The remainder of the
company's inventories are valued under various other methods, including FIFO and
weighted average. The excess of current replacement cost over LIFO cost
75
of inventories amounted to $2 million and $493 million at December 31, 2001 and
2000, respectively.
In the fourth quarter of 2001, the company recorded a $42 million before-tax,
$27 million after-tax, lower-of-cost-or-market write-down of its petroleum
products inventory. During 2000, certain inventory quantity reductions caused a
liquidation of LIFO inventory values. This liquidation increased net income by
$63 million, of which $60 million was attributable to ConocoPhillips' R&M
segment.
Inventories were significantly higher at year-end 2001, compared with year-end
2000, due to the Tosco acquisition (see Note 3--Acquisition of Tosco
Corporation).
NOTE 6--INVESTMENTS AND LONG-TERM RECEIVABLES
Components of investments and long-term receivables at December 31 were:
<Table>
<Caption>
Millions of Dollars
-------------------
2001 2000
-------- --------
Investments in and advances to affiliated
companies $ 2,788 2,612
Long-term receivables 248 152
Other investments 280 234
-------- --------
$ 3,316 2,998
======== ========
</Table>
At December 31, 2001, retained earnings included $124 million related to the
undistributed earnings of affiliated companies, and distributions received from
affiliates were $163 million, $2,180 million and $111 million in 2001, 2000 and
1999, respectively.
DUKE ENERGY FIELD SERVICES, LLC
On March 31, 2000, ConocoPhillips combined its midstream gas gathering,
processing and marketing business with the gas gathering, processing, marketing
and natural gas liquids business of Duke Energy Corporation (Duke Energy)
forming a new company, Duke Energy Field Services, LLC (DEFS). Duke Energy owns
69.7 percent of the new company, which it consolidates, and ConocoPhillips owns
30.3 percent. At the close of business on March 31, 2000, ConocoPhillips began
accounting for its investment in the new company on the equity basis. DEFS
arranged debt financing and on April 3, 2000, made one-time cash distributions
to both Duke Energy and ConocoPhillips. ConocoPhillips received $1.2 billion.
Duke Energy estimated the
76
fair value of the ConocoPhillips' midstream business at $1.9 billion in its
purchase method accounting for the acquisition. The book value of the midstream
business contributed to DEFS was $1.1 billion, but no gain was recognized in
connection with the transaction because of ConocoPhillips' and Chevron Phillips
Chemical Company's long-term commitment to purchase the natural gas liquids
output from the former ConocoPhillips' natural gas processing plants until
December 31, 2014. This purchase commitment is on an "if-produced,
will-purchase" basis so has no fixed production schedule, but has been, and is
expected to be, a relatively stable purchase pattern over the term of the
contract. Natural gas liquids are purchased under this agreement at various
published market index prices, less transportation and fractionation fees.
ConocoPhillips' consolidated results of operations include 100 percent of the
activity of its gas gathering, processing and marketing business through March
31, 2000, and its 30.3 percent share of DEFS' earnings since that date. Included
in operating results in 2001 and 2000 were after-tax benefits of $36 million and
$27 million, respectively, representing the amortization of the $824 million
basis difference between the book value of ConocoPhillips' contribution to DEFS
and its 30.3 percent equity interest in DEFS. This difference is being amortized
on a straight-line basis over 15 years, consistent with the remaining estimated
useful lives of the properties, plants and equipment contributed to DEFS.
On August 4, 2000, DEFS, Duke Energy and ConocoPhillips agreed to modify the
Limited Liability Company Agreement governing DEFS to provide for the admission
of a class of preferred members in DEFS. Subsidiaries of Duke Energy and
ConocoPhillips purchased new preferred member interests for $209 million and $91
million, respectively. The preferred member interests have a 30-year term, will
pay a distribution yielding 9.5 percent annually, and contain provisions which
require their redemption with any proceeds from an initial public offering.
77
Summarized financial information for DEFS (100 percent) follows:
<Table>
<Caption>
Millions of Dollars
----------------------------
April 1, 2000
Through
2001 December 31, 2000
-------- -----------------
Revenues $ 9,598 7,654
Income before income taxes and
cumulative effect of change in
accounting principle 367 321
Net income 364 318
Current assets 1,167 1,549
Other assets 5,478 4,979
Current liabilities 1,266 2,087
Other liabilities 2,427 1,720
-------- -----------------
</Table>
The members of DEFS are generally taxable on their respective shares of income
for U.S. and state income tax purposes. ConocoPhillips' share of income taxes
incurred directly by DEFS is reported in equity in earnings, and as such is not
included in income taxes in ConocoPhillips' consolidated financial statements.
CHEVRON PHILLIPS CHEMICAL COMPANY LLC
On July 1, 2000, ConocoPhillips and ChevronTexaco Corporation, as successor to
Chevron Corporation (ChevronTexaco), combined the companies' worldwide chemicals
businesses, excluding ChevronTexaco's Oronite business, into a new company,
Chevron Phillips Chemical Company LLC (CPChem). In addition to contributing the
assets and operations included in the company's Chemicals segment,
ConocoPhillips also contributed the natural gas liquids business associated with
its Sweeny, Texas, Complex.
ConocoPhillips and ChevronTexaco each own 50 percent of the voting and economic
interests in CPChem, and on July 1, 2000, ConocoPhillips began accounting for
its investment in CPChem using the equity method. CPChem accounted for the
combination using the historical bases of the assets and liabilities contributed
by ConocoPhillips and ChevronTexaco.
At December 31, 2001, the book value of the net assets contributed to CPChem was
$3.0 billion. ConocoPhillips' 50 percent share of the total net assets of CPChem
was $2.9 billion. A basis difference of $116 million is being amortized over 20
years, consistent with the remaining estimated
78
useful lives of the properties, plants and equipment contributed to CPChem. In
connection with the combination, CPChem borrowed $1.67 billion.
The proceeds of the borrowing were used to make cash distributions of $835
million each to ConocoPhillips and ChevronTexaco. Also in connection with the
combination, ConocoPhillips made a $70 million cash contribution to CPChem
related to re-establishing the K-Resin styrene-butadiene copolymer operations
contributed by ConocoPhillips. ConocoPhillips will continue to contribute
approximately $3 million per month during 2002 until the K-Resin facilities can
demonstrate production and sales capacity of specified quantities, or December
31, 2002, whichever occurs earlier. These cash contributions will be treated as
contributed capital and reflected in the basis difference.
ConocoPhillips' consolidated results of operations include 100 percent of the
activity of its chemicals business through June 30, 2000, and its 50 percent
share of CPChem's earnings since that date. Also included in ConocoPhillips'
2001 and 2000 operating results were a $4 million and a $2 million after-tax
reduction, respectively, for the amortization of the $116 million basis
difference between the book value of ConocoPhillips' contribution to CPChem and
its 50 percent interest in the equity of CPChem.
Summarized financial information for CPChem (100 percent) follows:
<Table>
<Caption>
Millions of Dollars
-----------------------------
July 1, 2000
Through
2001 December 31, 2000
-------- -----------------
Revenues $ 6,010 3,463
Loss before income taxes (431) (213)
Net loss (480) (241)
Current assets 1,551 2,065
Other assets 4,309 4,608
Current liabilities 820 910
Other liabilities 1,606 1,920
-------- -----------------
</Table>
The members of CPChem are generally taxable on their respective shares of income
for U.S. and state income tax purposes. ConocoPhillips' share of income taxes
incurred directly by CPChem is reported in equity in earnings, and as such is
not included in income taxes in ConocoPhillips' consolidated financial
statements.
79
OTHER EQUITY INVESTMENTS
The company owns or owned investments in chemicals, a heavy-oil project, oil and
gas transportation, coal mining, and other industries. During 2000, certain of
ConocoPhillips' equity investments were contributed to the CPChem and DEFS joint
ventures. As a result, the information included in the summarized financial
information for other equity companies includes financial information for those
equity investments only for those periods prior to the effective dates of the
joint ventures.
Summarized financial information for all entities accounted for using the equity
method, except DEFS and CPChem, follows:
<Table>
<Caption>
Millions of Dollars
------------------------------
2001 2000 1999
-------- -------- --------
Revenues $ 1,555 3,241 3,000
Income before income taxes 607 611 652
Net income 414 412 442
Current assets 689 438 1,060
Other assets 3,949 2,967 3,692
Current liabilities 1,184 510 805
Other liabilities 1,960 1,749 1,855
-------- -------- --------
</Table>
MEREY SWEENY, L.P.
In August 1998, Merey Sweeny, L.P. (MSLP) was formed to build and own a
58,000-barrel-per-day coker, vacuum unit and related facilities located at
ConocoPhillips' Sweeny Complex. The coker unit was operational in the fourth
quarter of 2000. ConocoPhillips and the Venezuelan state oil company, Petroleos
de Venezuela S.A., each hold an indirect 50 percent interest in Merey Sweeny,
L.P. In 1998, 2000 and 2001, the limited partnership issued $25 million of
tax-exempt bonds due 2018, 2020 and 2021, respectively. Until the senior bank
debt of MSLP is repaid in full, interest and principal payments on the
tax-exempt bonds are made by drawing upon a letter of credit facility that has
to be immediately reimbursed by the two partners in MSLP. ConocoPhillips'
December 31, 2001 and 2000, balance sheets included $38 million and $25 million,
respectively, of long-term debt as a result of the company's primary obligor
support of its 50 percent share of these financings. During 1999, MSLP issued
$350 million of 8.85% Bonds due 2019 and entered into a 15-year, $80 million
bank facility. The bank facility's commitment was reduced to $75 million on
December 18, 2001, according to the
80
terms of the facility. At December 31, 2001, no funds had been drawn under the
bank facility. In February 2002, MSLP reduced the credit facility to $25
million. The proceeds of the bond issues were used to fund the construction of
the coker and related refinery improvements. Any additional expenditures will be
funded through the bank facility, equity contributions or cash from operations.
In connection with any financing, the partners made capital contributions to the
partnership on a pro rata joint-and-several basis to the extent necessary to
successfully complete construction. When startup certification is achieved the
bonds become non-recourse to the two MSLP owners and the bondholders can then
look only to MSLP's cash flows for payment.
HAMACA HOLDING LLC
During 2000, ConocoPhillips and ChevronTexaco, as successor to Texaco Inc.
(ChevronTexaco), formed Hamaca Holding LLC, which holds the companies' 70
percent ownership interests in the Hamaca heavy-oil project in Venezuela. The
other 30 percent ownership interest in the Hamaca project is held by Petroleos
de Venezuela S.A. Hamaca Holding LLC participates, on behalf of its two owners,
in both the development of the heavy-oil field and the operations to upgrade the
heavy oil into a marketable, medium-grade oil and in the placement of joint
project financing. ConocoPhillips owns approximately 57 percent of Hamaca
Holding LLC and accounts for it using the equity method of accounting, as
control is shared equally with ChevronTexaco.
In the second quarter of 2001, Hamaca Holding LLC and its co-venturer in the
Hamaca project secured approximately $1.1 billion in debt financing for the
project. The Export-Import Bank of the United States provided a guarantee
supporting a 17-year-term $628 million bank facility. Additionally, an
unguaranteed $470 million 14-year-term commercial bank facility was arranged for
the project. At December 31, 2001, $633 million had been drawn under these
credit facilities.
The proceeds of these joint financings are being used to partially fund the
development of the heavy-oil field and the construction of pipelines and a
heavy-oil upgrader. The remaining necessary funding will be provided by capital
contributions from the co-venturers on a pro rata basis to the extent necessary
to successfully complete construction. Once completion certification is achieved
the joint project financings become non-recourse to the co-venturers and the
lenders under those facilities can then look only to the Hamaca project's cash
flows for payment.
81
NOTE 7--PROPERTIES, PLANTS AND EQUIPMENT
The company's investment in properties, plants and equipment (PP&E), with
accumulated depreciation, depletion and amortization (DD&A), at December 31 was:
<Table>
<Caption>
Millions of Dollars
---------------------------------------------------------------------
2001 2000
--------------------------------- ---------------------------------
Gross Net Gross Net
PP&E DD&A PP&E PP&E DD&A PP&E
--------- --------- --------- --------- --------- ---------
E&P $ 20,995 7,870 13,125 19,217 7,185 12,032
Midstream 49 34 15 49 33 16
R&M 13,736 3,404 10,332 4,503 2,062 2,441
Chemicals -- -- -- -- -- --
Emerging
Businesses -- -- -- -- -- --
Corporate
and Other 493 249 244 458 240 218
--------- --------- --------- --------- --------- ---------
$ 35,273 11,557 23,716 24,227 9,520 14,707
========= ========= ========= ========= ========= =========
</Table>
Net properties, plants and equipment increased approximately $9 billion during
2001, primarily due to the acquisition of Tosco (see Note 3--Acquisition of
Tosco Corporation).
82
NOTE 8--OTHER COMPREHENSIVE INCOME
The components and allocated tax effects of other comprehensive income (loss)
follow:
<Table>
<Caption>
Millions of Dollars
--------------------------------------
Tax
Before-Tax Expense After-Tax
---------- ---------- ----------
2001
Minimum pension liability
adjustment $ (220) (77) (143)
Unrealized loss on securities (3) (1) (2)
Foreign currency translation
adjustments (14) -- (14)
Hedging activities (4) -- (4)
Equity affiliates:
Foreign currency translation (3) -- (3)
Derivatives related 17 6 11
---------- ---------- ----------
Other comprehensive income $ (227) (72) (155)
========== ========== ==========
2000
Unrealized loss on securities $ (2) (1) (1)
Foreign currency translation
adjustments (53) -- (53)
Equity affiliates:
Foreign currency translation (15) -- (15)
---------- ---------- ----------
Other comprehensive income $ (70) (1) (69)
========== ========== ==========
1999
Unrealized gain on securities
Unrealized gain arising
during the period $ 3 1 2
Less: reclassification
adjustment for gains
realized in net income 6 2 4
---------- ---------- ----------
Net change (3) (1) (2)
Foreign currency translation
adjustments (14) -- (14)
Equity affiliates:
Foreign currency translation (2) -- (2)
---------- ---------- ----------
Other comprehensive income $ (19) (1) (18)
========== ========== ==========
</Table>
At year-end 2001, a minimum pension liability adjustment was required for
certain of the company's domestic pension plans and for its plan covering
employees in the United Kingdom. For these plans, accumulated benefit
obligations exceeded the fair value of plan assets by $383 million, compared
with a net liability recognized in the balance sheet of $102 million. After
83
reductions for amounts charged to intangible assets ($61 million) and deferred
taxes ($77 million), a charge to accumulated other comprehensive loss of $143
million was recorded.
Deferred taxes have not been provided on temporary differences related to
foreign currency translation adjustments for investments in certain foreign
subsidiaries and foreign corporate joint ventures that are essentially permanent
in duration.
Unrealized gains on securities relate to available-for-sale securities held by
irrevocable grantor trusts that fund certain of the company's domestic,
non-qualified supplemental key employee pension plans.
Accumulated other comprehensive loss in the equity section of the balance sheet
included:
<Table>
<Caption>
Millions of Dollars
--------------------
2001 2000
-------- --------
Minimum pension liability adjustment $ (143) --
Foreign currency translation adjustments (84) (70)
Unrealized gain on securities 4 6
Deferred net hedging loss (4) --
Equity affiliates:
Foreign currency translation (39) (36)
Derivatives related 11 --
-------- --------
Accumulated other comprehensive loss $ (255) (100)
======== ========
</Table>
NOTE 9--PROPERTY IMPAIRMENTS
During 2001, 2000 and 1999, the company recognized the following before-tax
impairment charges in its E&P segment:
<Table>
<Caption>
Millions of Dollars
------------------------
2001 2000 1999
------ ------ ------
Denmark--Siri field $ 23 -- --
Venezuela--Ambrosio field -- 87 --
U.S. properties, primarily Gulf
of Mexico and Gulf Coast area -- 13 11
United Kingdom offshore properties -- -- 30
Other E&P 3 -- 28
------ ------ ------
$ 26 100 69
====== ====== ======
</Table>
After-tax, the above impairment charges were $25 million in 2001, $95 million in
2000, and $34 million in 1999.
84
In the second quarter of 2001, the company committed to a plan to sell its 12.5
percent interest in the Siri oil field, offshore Denmark, triggering a
write-down of the field's assets to fair market value. The sale closed in early
2002. The company also recorded a property impairment on a crude oil tanker that
was sold in the fourth quarter of 2001.
The company recorded an impairment of its Ambrosio field, located in Lake
Maracaibo, Venezuela, in 2000. The Ambrosio field exploitation program did not
achieve originally premised results. The $87 million impairment charge was based
on the difference between the net book value of the investment and the
discounted value of estimated future cash flows. The remaining property
impairments in 2000 were related to fields in the United States, and were
prompted by disappointing drilling results or negative oil and gas reserve
revisions.
The U.S. E&P impairment charges in 1999 were primarily related to the Agate
subsalt field in the Gulf of Mexico, where a downhole well failure resulted in
the shutdown of the field. The U.K. E&P impairment charges in 1999 were
primarily related to the Renee and Maureen fields. The Renee impairment was
triggered by an unsuccessful development well, while the Maureen impairment
resulted from upward revisions of platform dismantlement costs. Other E&P
impairments in 1999 were caused by upward revisions of decommissioning costs
related to outlying fields in the Ekofisk area.
NOTE 10--ACCRUED DISMANTLEMENT, REMOVAL AND ENVIRONMENTAL COSTS
At December 31, 2001 and 2000, the company had accrued $776 million and $681
million, respectively, of dismantlement and removal costs, primarily related to
worldwide offshore production facilities and to production facilities in Alaska.
Estimated total future dismantlement and removal costs at December 31, 2001,
were $2,827 million, compared with $2,570 million in 2000. These costs are
accrued primarily on the unit-of-production method.
ConocoPhillips had accrued environmental costs, primarily related to cleanup of
ponds and pits at domestic refineries and underground storage tanks at U.S.
service stations, and remediation activities required by the state of Alaska at
exploration and production sites formerly owned by ARCO, of $388 million and $78
million at December 31, 2001 and 2000, respectively. ConocoPhillips had also
accrued $136 million and $40 million of environmental costs associated with
discontinued or sold operations at December 31, 2001 and 2000, respectively.
85
Also,$12 million and $6 million were included at December 31, 2001 and 2000,
respectively, for sites where the company has been named a Potentially
Responsible Party. At December 31, 2001 and 2000, $3 million had been accrued
for other environmental litigation.
Total environmental accruals at December 31, 2001 and 2000, were $539 million
and $127 million, respectively. The 2001 increase in accrued environmental costs
of $412 million is primarily the result of ConocoPhillips' recent acquisition of
Tosco on September 14, 2001. Accruals totaling approximately $303 million were
added as a result of that transaction. Earlier in the year, the company's
accrual was increased by approximately $107 million for remediation activities
required by the state of Alaska at exploration and production sites formerly
owned by ARCO. Because these accruals relate to environmental conditions that
existed when ConocoPhillips acquired Tosco and the Alaskan businesses, the
charges impacted the allocation of the purchase price of each acquisition, not
the company's net income.
Of the total $1,315 million of accrued dismantlement, removal and environmental
costs at December 31, 2001, $173 million was classified as a current liability
on the balance sheet, under the caption "Other accruals." At year-end 2000, $106
million was classified as current.
86
NOTE 11--DEBT
Long-term debt at December 31 was:
<Table>
<Caption>
Millions of Dollars
--------------------
2001 2000
-------- --------
9 3/8% Notes due 2011 $ 350 350
9.18% Notes due September 15, 2021 -- 300
9% Notes due 2001 -- 250
8.86% Notes due May 15, 2022 250 250
8.75% Notes due 2010 1,350 1,350
8.5% Notes due 2005 1,150 1,150
8.49% Notes due January 1, 2023 250 250
8.25% Mortgage Bonds due May 15, 2003* 150 --
8.125% Notes due 2030* 600 --
7.92% Notes due April 15, 2023 250 250
7.9% Notes due 2047* 100 --
7.8% Notes due 2027* 300 --
7.625% Notes due 2006* 240 --
7.25% Notes due 2007* 200 --
7.20% Notes due November 1, 2023 250 250
7.125% Debentures due March 15, 2028 300 300
7% Debentures due 2029 200 200
6.65% Notes due March 1, 2003 100 100
6.65% Debentures due July 15, 2018 300 300
6 3/8% Notes due 2009 300 300
5 5/8% Marine Terminal Revenue Bonds,
Series 1977 due 2007 18 18
Commercial paper and revolving debt due
to banks and others through 2006 at
2.05% - 7.90% 1,081 515
Guarantee of LTSSP bank loan payable
at 2.36% - 7.10% 322 349
Note payable to Merey Sweeny, L.P. at 7% 133 111
Marine Terminal Revenue Refunding Bonds
at 1.45% - 5.05% 265 265
Capitalized leases and other 121 42
Net unamortized debt premium (discount) 109 (16)
-------- --------
Total debt 8,689 6,884
Notes payable and long-term debt due
within one year (44) (262)
-------- --------
Long-term debt $ 8,645 6,622
======== ========
</Table>
*Debt assumed in the Tosco acquisition completed on September 14, 2001.
Maturities in 2002 through 2006 are: $44 million (included in current
liabilities), $264 million, $7 million, $1,154 million and $1,349 million,
respectively.
87
During 2001, ConocoPhillips redeemed its $300 million 9.18% Notes due September
15, 2021, at 104.59 percent, retired its $250 million 9% Notes due 2001, and
assumed $2.1 billion of debt with the acquisition of Tosco. After amortization
of the fair-value-adjustment premiums, the fixed-rate debt had a
weighted-average effective interest rate of 7.3 percent.
In October 2001, ConocoPhillips entered into two new revolving bank credit
facilities: a five-year credit agreement providing for commitments not to exceed
$1.5 billion; and a 364-day credit agreement for commitments not to exceed $1.5
billion. The $3 billion of new credit facilities replaced all those that were
previously available, including a $1 billion facility assumed as part of the
Tosco transaction. All previous facilities were canceled subsequent to the
effectiveness of the new facilities. The new facilities are available for use
either as direct bank borrowings or as support for the issuance of commercial
paper.
At December 31, 2001, ConocoPhillips had $1,081 million of commercial paper
outstanding, supported by the long-term credit facility. This amount
approximates fair market value.
As of December 31, 2001, the company's wholly owned subsidiary, Phillips
Petroleum Company Norway, had no outstanding debt under its two $300 million
revolving credit facilities expiring in June 2004.
Depending on the credit facility, borrowings may bear interest at a margin above
rates offered by certain designated banks in the London interbank market or at
margins above certificate of deposit or prime rates offered by certain
designated banks in the United States. The agreements call for commitment fees
on available, but unused, amounts. The agreements also contain early termination
rights if the company's current directors or their approved successors cease to
be a majority of the Board of Directors (Board).
At December 31, 2001, $322 million was outstanding under the company's Long-Term
Stock Savings Plan (LTSSP) term loan, which will require annual installments
beginning in 2007 and continue through 2015. Under this bank loan, any
participating bank in the syndicate of lenders may cease to participate on
December 5, 2004, by giving not less than 180 days' prior notice to the LTSSP
and the company. The company does not anticipate a cessation of participation by
the lenders, and plans to commence scheduled repayments beginning in 2007.
88
Each bank participating in the LTSSP loan has the optional right, if the current
company directors or their approved successors cease to be a majority of the
Board, and upon not less than 90 days' notice, to cease to participate in the
loan. Under the above conditions, such banks' rights and obligations under the
loan agreement must be purchased by the company if not transferred to a bank of
the company's choice. See Note 17--Employee Benefit Plans for additional
discussion of the LTSSP.
NOTE 12--CONTINGENCIES
In the case of all known contingencies, the company accrues an undiscounted
liability when the loss is probable and the amount is reasonably estimable.
These liabilities are not reduced for potential insurance recoveries. If
applicable, undiscounted receivables are accrued for probable insurance or other
third-party recoveries. Based on currently available information, the company
believes 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 the company's financial statements.
As facts concerning contingencies become known to the company, the company
reassesses its position both with respect to accrued liabilities and other
potential exposures. Estimates that are particularly sensitive to future change
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 unknown magnitude of cleanup costs, the
unknown time and extent of such remedial actions that may be required, and the
determination of the company's liability in proportion to that of other
responsible parties. Estimated future costs related to tax and legal matters are
subject to change as events evolve and as additional information becomes
available during the administrative and litigation processes.
ENVIRONMENTAL--The company is 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 the
company prepares its financial statements, accruals for environmental
liabilities are recorded based on Management's best estimate using all
information that is available at the time. Loss estimates are measured and
liabilities are based on currently available facts, existing technology, and
presently enacted laws and regulations, taking into consideration the
89
likely effects of inflation and other societal and economic factors. Also
considered when measuring environmental liability are the company's prior
experience in remediation of contaminated sites, other companies' cleanup
experience and data released by the Environmental Protection Agency (EPA) or
other organizations. Unasserted claims are reflected in ConocoPhillips'
determination of environmental liabilities and are accrued in the period that
they are both probable and reasonably estimable.
Although liability of those potentially responsible is generally joint and
several for federal sites and frequently so for state sites, the company is
usually but one of many companies cited at a particular site. Due to the joint
and several liabilities, the company could be responsible for all of the cleanup
costs at any site which it has been designated as a potentially responsible
party. If ConocoPhillips was solely responsible, the costs, in some cases, could
be material to its, or one of its segments' operations, capital resources or
liquidity. However, settlements and costs incurred in matters that previously
have been resolved have not been materially significant to the company's results
of operations or financial condition. The company has, to date, been successful
in sharing cleanup costs with other financially sound companies. Many of the
sites at which the company is potentially responsible are still under
investigation by the EPA or the state agencies concerned. Prior to actual
cleanup, those potentially responsible normally assess the site conditions,
apportion responsibility and determine the appropriate remediation. In some
instances, ConocoPhillips may have no liability or attain a settlement of
liability. Where it appears that other potentially responsible parties may be
financially unable to bear their proportional share, this inability has been
considered in estimating ConocoPhillips' potential liability and accruals have
been adjusted accordingly.
Upon ConocoPhillips' acquisition of Tosco on September 14, 2001, the assumed
environmental obligations of Tosco, some of which are mitigated by
indemnification agreements, became contingencies reportable on a consolidated
basis by ConocoPhillips. Beginning with the acquisition of the Bayway refinery
in 1993, but excluding the Alliance refinery acquisition, Tosco negotiated, as
part of its acquisitions, environmental indemnification from the former owners
for remediating contamination that occurred prior to the respective acquisition
dates. Some of the environmental indemnifications are subject to caps and time
limits. No accruals have been recorded for any potential contingent liabilities
that will be funded by the prior owners under these indemnifications.
90
As part of Tosco's acquisition of Unocal's West Coast petroleum refining,
marketing, and related supply and transportation assets in March 1997, Tosco
agreed to pay the first $7 million per year of any environmental remediation
liabilities at the acquired sites arising out of, or relating to, the period
prior to the transaction's closing, plus 40 percent of any amount in excess of
$7 million per year, with Unocal paying the remaining 60 percent per year. This
indemnification agreement with Unocal has a 25-year term and ConocoPhillips has
a maximum cap, adjusted for amounts paid through December 31, 2001, of $140
million of environmental remediation costs that ConocoPhillips has to fund
during the remainder of the agreement period.
The company is currently participating in environmental assessments and cleanup
under these laws at federal Superfund and comparable state sites. After an
assessment of environmental exposures for cleanup and other costs, the company
makes accruals on an undiscounted basis (unless acquired in a purchase business
combination) 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 December 31, 2001, contingent liability accruals of $11
million had been made for the company's PRP sites, and $3 million for other
environmental contingent liabilities. Accrued environmental liabilities will be
paid over periods extending as far as 30 years in the future. These accruals
have not been reduced for possible insurance recoveries. In the future, the
company may be involved in additional environmental assessments, cleanups and
proceedings.
OTHER LEGAL PROCEEDINGS--The company is a party to a number of other legal
proceedings pending in various courts or agencies for which, in some instances,
no provision has been made.
OTHER CONTINGENCIES--The company has contingent liabilities resulting from
throughput agreements with pipeline and processing companies in which it holds
stock interests. Under these agreements, ConocoPhillips 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.
91
NOTE 13--FINANCIAL INSTRUMENTS AND DERIVATIVE CONTRACTS
DERIVATIVE INSTRUMENTS AND OTHER CONTRACTS
The company and certain of its subsidiaries may use financial and
commodity-based derivative contracts to manage exposures to fluctuations in
foreign currency exchange rates, commodity prices, and interest rates or to
exploit favorable market conditions. During the third quarter of 2001,
ConocoPhillips' Board of Directors revised its policy governing the use of
derivative instruments. The revised policy prohibits the holding or issuing of
highly complex or leveraged derivatives, as did the previous policy, and unless
approved by the Chief Executive Officer, all derivative instruments used by the
company must not contain embedded financing features and must be sufficiently
liquid that comparable valuations are readily available. The policy also
requires the Chief Executive Officer to establish the maximum derivative
position limits for ConocoPhillips and requires the company's Risk Management
Steering Committee, comprised of senior management, to monitor the use and
effectiveness of derivatives. The Audit Committee of the company's Board of
Directors periodically reviews the derivatives policy and compliance with the
policy.
FASB Statement No. 133, "Accounting for Derivative Instruments and Hedging
Activities" (Statement No. 133), as amended, requires companies to recognize all
derivative instruments as either assets or liabilities on the balance sheet at
fair value. The accounting for changes in fair value (i.e., gains or losses) of
a derivative instrument depends on whether it meets the qualifications for, and
has been designated as, a hedge, and the type of hedge. ConocoPhillips elected
not to use hedge accounting for derivative contracts used in the company's risk
management programs during 2001, except for the two programs noted below. All
gains and losses, realized or unrealized, from derivative contracts not
designated as hedges have been recognized in the statement of income. Assets and
liabilities resulting from derivative contracts open at December 31, 2001,
appear as receivables or payables on the balance sheet. The amount related to
hedging activity in other comprehensive income is the net loss from the
cash-flow hedges of the company's hedge of the Brazilian real, discussed below.
ConocoPhillips had no cumulative effect of accounting change as a result of
adopting Statement No. 133, as of January 1, 2001.
Statement No. 133 also requires purchase and sales contracts for commodities
that are readily convertible to cash (e.g., crude oil, natural gas, and
gasoline) to be recorded on the balance sheet as derivatives unless the
contracts are for quantities
92
expected to be used or sold by the company over a reasonable period in the
normal course of business and the company has documented its intent to apply
this exception. ConocoPhillips generally applies this exception to all eligible
purchase and sales contracts; however, the company may elect not to apply this
exception if a derivative instrument will be used to hedge the contract but
hedge accounting will not be applied. When this occurs, the purchase or sale
contract will be recorded on the balance sheet as a derivative in accordance
with the preceding paragraph.
FINANCIAL DERIVATIVE CONTRACTS--During the third quarter of 2001, the company
used hedge accounting to record the results of using a forward-exchange contract
to hedge the exposure to fluctuations in the exchange rate between the U.S.
dollar and Brazilian real, resulting from a firm commitment to pay reals to
acquire an exploratory lease. The hedge was closed in August 2001, upon payment
of the lease bonus. Results from the hedge appear in Accumulated Other
Comprehensive Loss on the balance sheet and will be reclassified into earnings
concurrent with the amortization or write-down of the lease bonus, but no
portion of this amount is expected to be reclassified during 2002. No component
of the hedge results was excluded from the assessment of hedge effectiveness,
and no gain or loss was recorded in earnings from hedge ineffectiveness.
The company on occasion uses forward-exchange contracts or collars to manage
exposures to currency-exchange-rate fluctuations associated with certain assets,
liabilities and firm commitments for which hedge accounting was not used. During
2001, ConocoPhillips used derivative contracts to manage exposures to: 1)
exchange-rate fluctuations between U.S. and Australian dollars to fund an
Australian acquisition; and 2) exchange-rate fluctuations between revenues
received in U.S. dollars and various European currencies and the company's
Norwegian subsidiary's expenditures payable in kroner. Results from this
activity appear in foreign currency transaction gains and losses on the
statement of income.
COMMODITY DERIVATIVE CONTRACTS--During the last four months of 2001, the company
used hedge accounting for West Texas Intermediate crude oil (WTI) futures
designated as fair-value hedges of firm commitments to sell WTI at Cushing,
Oklahoma. The changes in the fair values of the futures and the firm commitments
have been recognized in income. No component of the futures gain or loss was
excluded from the assessment of hedge effectiveness, and the amount recognized
in earnings during the year from ineffectiveness was immaterial.
93
ConocoPhillips also used various derivative instruments to manage exposures to
commodity price fluctuations for which hedge accounting was not used. Futures,
swaps, options, and fixed-price contracts were used to lock in future sales
prices for crude oil, motor fuel, distillates, propane, butane and other light
ends, blending components, and residual fuels, and also to lock in margins
(e.g., the spread between the cost of feedstock purchased and refined products
sold). These instruments were also used to manage the exposure to changes in the
value of physical inventory. In addition, the company uses futures contracts to
exploit favorable market conditions.
CREDIT RISK
The company's financial instruments that are potentially exposed to
concentrations of credit risk consist primarily of cash equivalents,
over-the-counter derivative contracts, and trade receivables. ConocoPhillips'
cash equivalents, which are placed in high-quality money market funds and time
deposits with major international banks and financial institutions, are
generally not maintained at levels material to the company's financial position.
The credit risk from the company's over-the-counter derivative contracts, such
as forwards and swaps, derives from the counterparty to the transaction,
typically a major bank or financial institution. ConocoPhillips does not
anticipate non-performance by any of these counterparties, none of whom does
sufficient volume with the company to create a significant concentration of
credit risk. ConocoPhillips also uses futures contracts, but futures have a
negligible credit risk because they are traded on the New York Mercantile
Exchange or the International Petroleum Exchange of London Limited.
The company's trade receivables result primarily from its petroleum operations
and reflect a broad customer base, both nationally and internationally. At
December 31, 2001, the amount of trade receivables owed to ConocoPhillips or its
U.S. subsidiaries, excluding credit card receivables, by companies directly or
indirectly exposed to the U.S. market for oil, gas, and refined products was
less than $700 million. The majority of these receivables have payment terms of
30 days or less, and the company continually monitors this exposure and the
creditworthiness of the counterparties. ConocoPhillips does not generally
require collateral to limit the exposure to loss; however, ConocoPhillips uses
master netting arrangements to mitigate credit risk with counterparties that
both buy from and sell to the company, as these agreements permit the amounts
owed by ConocoPhillips to be offset against amounts due to the company.
94
FAIR VALUES OF FINANCIAL INSTRUMENTS
The company used the following methods and assumptions to estimate the fair
value of its financial instruments:
Cash and cash equivalents: The carrying amount reported on the balance sheet
approximates fair value.
Accounts and notes receivable: The carrying amount reported on the balance sheet
approximates fair value.
Debt and mandatorily redeemable preferred securities: The carrying amount of the
company's floating-rate debt approximates fair value. The fair value of the
fixed-rate debt and mandatorily redeemable preferred securities is estimated
based on quoted market prices.
Swaps: Fair value is estimated based on forward market prices and approximates
the net gains and losses that would have been realized if the contracts had been
closed out at year-end. When forward market prices are not available, they are
estimated using the forward prices of a similar commodity with adjustments for
differences in quality or location.
Forward-exchange contracts: Fair value is estimated by comparing the contract
rate to the forward rate in effect on December 31 and approximates the net gains
and losses that would have been realized if the contracts had been closed out at
year-end.
Certain company financial instruments at December 31 were:
<Table>
<Caption>
Millions of Dollars
-----------------------------------------
Carrying Amount Fair Value
------------------- -------------------
2001 2000 2001 2000
-------- -------- -------- --------
Financial assets
Futures $ -- 1 -- 1
Swaps 5 * 5 *
Options or collars -- * -- *
Financial liabilities
Total debt, excluding
capital leases 8,659 6,884 9,180 7,153
Mandatorily redeemable
preferred securities 650 650 662 567
Futures 5 -- 5 --
Swaps 2 -- 2 --
Options * -- * --
-------- -------- -------- --------
</Table>
*Indicates amount was less than $1 million.
95
NOTE 14--PREFERRED STOCK
COMPANY-OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF PHILLIPS 66
CAPITAL TRUSTS
During 1996 and 1997, the company formed two statutory business trusts, Phillips
66 Capital I (Trust I) and Phillips 66 Capital II (Trust II), in which the
company owns all common stock. The Trusts exist for the sole purpose of issuing
securities and investing the proceeds thereof in an equivalent amount of
subordinated debt securities of ConocoPhillips. ConocoPhillips established the
two trusts to raise funds for general corporate purposes.
On May 29, 1996, Trust I completed a $300 million underwritten public offering
of 12,000,000 shares of 8.24% Trust Originated Preferred Securities (Preferred
Securities). The sole asset of Trust I is $309 million of ConocoPhillips' 8.24%
Junior Subordinated Deferrable Interest Debentures due 2036 (Subordinated Debt
Securities I), purchased by Trust I on May 29, 1996. On January 17, 1997, Trust
II completed a $350 million underwritten public offering of 350,000 shares of 8%
Capital Securities (Capital Securities). The sole asset of Trust II is $361
million of the company's 8% Junior Subordinated Deferrable Interest Debentures
due 2037 (Subordinated Debt Securities II) purchased by Trust II on January 17,
1997.
The Subordinated Debt Securities I are due May 29, 2036, and are redeemable in
whole, or in part, at the option of ConocoPhillips, on or after May 29, 2001, at
a redemption price of $25 per share, plus accrued and unpaid interest. The
Subordinated Debt Securities II are due January 15, 2037, and are redeemable in
whole, or in part, at the option of ConocoPhillips, on or after January 15,
2007, at a redemption price of $1,000 per share, plus accrued and unpaid
interest.
Subordinated Debt Securities I and II are unsecured obligations of
ConocoPhillips, equal in right of payment but subordinate and junior in right of
payment to all present and future senior indebtedness of ConocoPhillips.
The subordinated debt securities and related income statement effects are
eliminated in the company's consolidated financial statements. When the company
redeems the subordinated debt securities, Trusts I and II are required to apply
all redemption proceeds to the immediate redemption of the Trusts' Securities.
ConocoPhillips fully and unconditionally guarantees the Trusts' obligations
under the Preferred and Capital Securities.
96
PREFERRED STOCK
ConocoPhillips has 300 million shares of preferred stock authorized, none of
which was issued or outstanding at December 31, 2001, or 2000.
NOTE 15--PREFERRED SHARE PURCHASE RIGHTS
ConocoPhillips' Board of Directors authorized and declared a dividend of one
preferred share purchase right for each common share outstanding on August 1,
1999, and authorized and directed the issuance of one right per common share for
any shares issued after that date. The rights, which expire July 31, 2009, will
be exercisable only if a person or group acquires 15 percent or more of the
company's common stock or announces 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 $180. In addition, the rights enable holders to either acquire
additional shares of ConocoPhillips common stock or purchase the stock of an
acquiring company at a discount, depending on specific circumstances. The rights
may be redeemed by the company in whole, but not in part, for one cent per
right. In connection with its approval of the proposed merger transaction among
Phillips Petroleum Company (Phillips) and Conoco Inc. (Conoco), the Board of
Directors approved amendments to the rights that would render them inoperative
in connection with the merger.
NOTE 16--NON-MINERAL LEASES
The company leases ocean transport vessels, tank railcars, corporate aircraft,
service stations, computers, office buildings and other facilities and
equipment. ConocoPhillips has sale-leaseback transactions involving office
buildings, corporate aircraft, retail service stations, railroad tank cars, and
ocean-going vessels. Certain leases include escalation clauses for adjusting
rentals to reflect changes in price indices, as well as renewal options and/or
options to purchase the leased property for the fair market value at the end of
the lease term. There are no significant restrictions on ConocoPhillips imposed
by the leasing agreements in regards to dividends, asset dispositions or
borrowing ability. Leased assets under capital leases in the gross and net
amounts of $31 million and $24 million, respectively, were included in the R&M
segment's "properties, plants and equipment" balance at December 31, 2001.
97
ConocoPhillips has leasing arrangements with several special purpose entities
(SPEs) that are third-party trusts established by a trustee and funded by
financial institutions. Other than the leasing arrangement, ConocoPhillips has
no other direct or indirect relationship with the trusts or their investors.
Each SPE from which ConocoPhillips leases assets is funded by at least 3 percent
substantive third-party residual equity capital investment, which is at-risk
during the entire term of the lease. Except in an event of default under the
terms of the lease agreements, there are not any circumstances at this time
under which ConocoPhillips would be required to record the assets and/or
liabilities of the SPEs in its financial statements in the future, based on the
terms and provisions within the various arrangements. ConocoPhillips considers
an event of default under the terms of the lease agreements to be remote.
ConocoPhillips does have various purchase options to acquire the leased assets
from the SPEs at the end of the lease term, but those purchase options are not
required to be exercised by ConocoPhillips under any circumstances.
At December 31, 2001, future minimum rental payments due under non-cancelable
leases were:
<Table>
<Caption>
Millions of Dollars
---------------------
Operating Capital
Leases Leases
--------- ---------
2002 $ 431 9
2003 389 9
2004 328 9
2005 277 10
2006 220 10
Remaining years 1,116 150
--------- ---------
Total 2,761 197
Less imputed interest 99
Less current portion of capital leases 1
---------
Long-term capital lease obligations* $ 97
=========
Less income from subleases 583
---------
Net minimum operating lease payments $ 2,178
=========
</Table>
*Includes $67 million of above-market capital lease obligations acquired in an
acquisition, which are presented as part of Other liabilities and deferred
credits on the balance sheet.
The above amounts exclude guaranteed residual value payments totaling $197
million in 2003, $262 million in 2004, $866 million in 2005, $52 million in
2006, and $434 million in the remaining years, due at the end of lease terms,
which would be reduced by the fair market value of the leased assets returned.
98
ConocoPhillips has agreements with a shipping company for the long-term
chartering of five crude oil tankers that are currently under construction. The
charters will be accounted for as operating leases upon delivery, which is
expected in the third and fourth quarters of 2003. If the completed tankers are
not delivered to ConocoPhillips before specified dates in 2004, the chartering
commitments are cancelable by ConocoPhillips. Upon delivery, the base term of
the charter agreements is 12 years, with certain renewal options by
ConocoPhillips. ConocoPhillips has options to cancel the charter agreements at
any time, including during construction or after delivery. After delivery, if
ConocoPhillips were to exercise its cancellation options, the company's maximum
commitment for the five tankers together would be $92 million. If ConocoPhillips
does not exercise its cancellation options, the total operating lease commitment
over the 12-year term for the five tankers would be $383 million on an estimated
bareboat basis.
Operating lease rental expense for years ended December 31 was:
<Table>
<Caption>
Millions of Dollars
------------------------------
2001 2000 1999
-------- -------- --------
Total rentals $ 271 128 143
Less sublease rentals 22 2 2
-------- -------- --------
$ 249 126 141
======== ======== ========
</Table>
Contingent rentals were not significant in any year presented.
99
NOTE 17--EMPLOYEE BENEFIT PLANS
PENSION AND POSTRETIREMENT PLANS
An analysis of the projected benefit obligations for the company's pension plans
and accumulated benefit obligations for its postretirement health and life
insurance plans follows:
<Table>
<Caption>
Millions of Dollars
--------------------------------------------
Pension Benefits Other Benefits
-------------------- --------------------
2001 2000 2001 2000
-------- -------- -------- --------
CHANGE IN BENEFIT OBLIGATION
Benefit obligation at January 1 $ 1,377 1,314 140 132
Service cost 55 48 4 2
Interest cost 106 98 11 9
Plan participant contributions 1 1 11 11
Plan amendments 6 32 21 --
Actuarial loss 169 65 14 13
Acquisitions 277 18 68 1
Divestitures -- (64) -- (6)
Benefits paid (143) (103) (31) (24)
Curtailment (2) -- -- 1
Settlement -- (4) -- --
Recognition of termination
benefits 11 6 1 1
Foreign currency exchange
rate change (8) (34) -- --
-------- -------- -------- --------
Benefit obligation at
December 31 $ 1,849 1,377 239 140
======== ======== ======== ========
Accumulated benefit
obligation portion of
above at December 31 $ 1,466 1,136
======== ========
CHANGE IN FAIR VALUE OF
PLAN ASSETS
Fair value of plan assets at
January 1 $ 1,097 1,230 20 23
Actual return on plan assets (110) (7) 2 --
Acquisitions 166 -- 4 --
Divestitures -- (40) -- --
Company contributions 110 56 15 10
Plan participant contributions 1 1 11 11
Benefits paid (143) (103) (31) (24)
Settlement -- (4) -- --
Foreign currency exchange
rate change (8) (36) -- --
-------- -------- -------- --------
Fair value of plan assets at
December 31 $ 1,113 1,097 21 20
======== ======== ======== ========
</Table>
100
<Table>
<Caption>
Millions of Dollars
---------------------------------------------
Pension Benefits Other Benefits
--------------------- --------------------
2001 2000 2001 2000
-------- -------- -------- --------
FUNDED STATUS
Excess obligation $ (736) (280) (218) (120)
Unrecognized net actuarial
loss 480 121 30 19
Unrecognized prior service cost 63 64 18 (5)
Unrecognized net transition
asset -- -- -- --
-------- -------- -------- --------
Total recognized amount in the
consolidated balance sheet $ (193) (95) (170) (106)
======== ======== ======== ========
Components of above amount:
Prepaid benefit cost $ 42 40 -- --
Accrued benefit liability (516) (135) (170) (106)
Intangible asset 61 -- -- --
Accumulated other
comprehensive loss 220* -- -- --
-------- -------- -------- --------
Total recognized $ (193) (95) (170) (106)
======== ======== ======== ========
*Before reduction for associated deferred taxes of $77 million.
WEIGHTED-AVERAGE ASSUMPTIONS
AS OF DECEMBER 31
Discount rate 7.00% 7.20 7.25 7.25
Expected return on plan assets 8.30 9.10 5.20 6.25
Rate of compensation increase 4.00 4.00 4.00 4.00
-------- -------- -------- --------
</Table>
Pension plan funds are invested in a diversified portfolio of assets.
Approximately $200 million held in a participating annuity contract is not
available for meeting benefit obligations in the near term. None of the plans
hold company stock.
The company's funding policy for U.S. plans is to contribute at least the
minimum required by the Employee Retirement Income Security Act of 1974.
Contributions to foreign plans are dependent upon local laws and tax
regulations.
The funded status of the plans was impacted the last year by changes in
assumptions used to calculate plan liabilities, acquisition of the Tosco benefit
plans, and negative asset performance.
At year-end 2001, a minimum pension liability adjustment was required for
certain of the company's domestic pension plans and for its plan covering
employees in the United Kingdom. For these plans, accumulated benefit
obligations exceeded the fair value of plan assets by $383 million, compared
with a net liability
101
recognized in the balance sheet of $102 million. After reductions for amounts
charged to intangible assets ($61 million) and deferred taxes ($77 million), a
charge to accumulated other comprehensive loss of $143 million was recorded.
<Table>
<Caption>
Millions of Dollars
--------------------------------------------------------
Pension Benefits Other Benefits
-------------------------- --------------------------
2001 2000 1999 2001 2000 1999
------ ------ ------ ------ ------ ------
COMPONENTS OF NET PERIODIC
BENEFIT COST
Service cost $ 55 48 58 4 2 3
Interest cost 106 98 96 11 9 9
Expected return on plan
assets (104) (109) (107) (1) (1) (2)
Amortization of prior
service cost 7 6 5 (1) (3) (7)
Recognized net actuarial
loss/(gain) 16 (5) 18 2 1 2
Amortization of net asset (1) (7) (7) -- -- --
------ ------ ------ ------ ------ ------
Net periodic benefit cost $ 79 31 63 15 8 5
====== ====== ====== ====== ====== ======
</Table>
The company recorded settlement losses of $10 million and $8 million in 2001 and
1999, respectively.
In determining net pension and other postretirement benefit costs,
ConocoPhillips has elected to amortize net gains and losses on a straight-line
basis over 10 years. Prior service cost is amortized on a straight-line basis
over the average remaining service period of employees expected to receive
benefits under the plan.
For the company's tax-qualified pension plans with projected benefit obligations
in excess of plan assets, the projected benefit obligation, the accumulated
benefit obligation, and the fair value of plan assets were $1,519 million,
$1,211 million, and $886 million at December 31, 2001, respectively, and $890
million, $739 million, and $683 million at December 31, 2000, respectively.
For the company's unfunded non-qualified supplemental key employee pension
plans, the projected benefit obligation and the accumulated benefit obligation
were $109 million and $76 million, respectively, at December 31, 2001, and were
$105 million and $77 million at December 31, 2000.
102
The company has multiple non-pension postretirement benefit plans for health and
life insurance. The health care plans are contributory, with participant and
company contributions adjusted annually; the life insurance plans are
non-contributory. As of December 31, 2001, the weighted-average health care cost
trend rate is assumed to decrease gradually from 11.5 percent in 2002 to 10.0
percent in 2004. For certain groups of employees, no increases in medical costs
are assumed for years beginning in 2005 because of a provision in the health
plan that freezes the company's contribution at 2004 levels. For other groups of
employees, the trend rate decreases to 5.5 percent by 2010, subject to per
capita maximums.
The assumed health care cost trend rate has a significant effect on the amounts
reported. A one-percentage-point change in the assumed health care cost trend
rate would have the following effects on the 2001 amounts:
<Table>
<Caption>
Millions of Dollars
--------------------
One-Percentage-Point
--------------------
Increase Decrease
-------- --------
Effect on total of service and interest
cost components $ 1 (1)
Effect on the postretirement benefit
obligation 5 (5)
-------- --------
</Table>
DEFINED CONTRIBUTION PLANS
Most employees are eligible to participate in either the company-sponsored
Thrift Plan of Phillips Petroleum Company or the Tosco Corporation Capital
Accumulation Plan. Employees contribute a portion of their salaries to any of
several investment funds, including a company stock fund, a percentage of which
is matched by the company. In addition, eligible participants in the Tosco
Corporation Capital Accumulation Plan may receive an additional company
contribution in lieu of pension plan benefits. Company contributions charged to
expense in total for both plans were $14 million in 2001, and $6 million each in
2000 and 1999.
The company's LTSSP is a leveraged employee stock ownership plan. Employees
eligible for the Thrift Plan may also elect to participate in the LTSSP by
contributing 1 percent of their salaries and receiving an allocation of shares
of common stock proportionate to their contributions. In 1990, the LTSSP
borrowed funds that were used to purchase previously unissued shares of company
common stock.
103
Since the company guarantees the LTSSP's borrowings, the unpaid balance is
reported as a liability of the company and unearned compensation is shown as a
reduction of common stockholders' equity. Dividends on all shares are charged
against retained earnings. The debt is serviced by the LTSSP from company
contributions and dividends received on certain shares of common stock held by
the plan, including all unallocated shares. The shares held by the LTSSP are
released for allocation to participant accounts based on debt service payments
on LTSSP borrowings. In addition, during the period from 2002 through 2006, when
no debt principal payments are scheduled to occur, the company has committed to
make direct contributions of stock to the LTSSP, or make prepayments on LTSSP
borrowings, to ensure a certain minimum level of stock allocation to participant
accounts.
The company recognizes interest expense as incurred and compensation expense
based on the fair market value of the stock contributed or on the cost of the
unallocated shares released, using the shares-allocated method. The company
recognized total LTSSP expense of $33 million, $40 million and $35 million in
2001, 2000 and 1999, respectively, all of which was compensation expense. In
2001 and 2000, respectively, the company made cash contributions to the LTSSP of
$17 million and $23 million. In 2001, 2000 and 1999, the company contributed
292,857 shares, 508,828 shares and 767,605 shares, respectively, of
ConocoPhillips common stock from the Compensation and Benefits Trust. The shares
had a fair market value of $17 million, $24 million and $36 million,
respectively. Dividends used to service debt were $28 million, $32 million and
$41 million in 2001, 2000 and 1999, respectively.
These dividends reduced the amount of expense recognized each period. Interest
incurred on the LTSSP debt in 2001, 2000 and 1999 was $17 million, $26 million
and $22 million, respectively.
The total LTSSP shares as of December 31 were:
<Table>
<Caption>
2001 2000
---------- ----------
Unallocated shares 8,379,924 9,318,949
Allocated shares 14,794,203 16,090,976
---------- ----------
Total LTSSP shares 23,174,127 25,409,925
========== ==========
</Table>
The fair value of unallocated shares at December 31, 2001, and 2000, was $505
million and $530 million, respectively.
104
STOCK-BASED COMPENSATION PLANS
Under the Omnibus Securities Plan (the Plan) approved by shareholders in 1993,
stock options and stock awards for certain employees are authorized for up to
eight-tenths of 1 percent (0.8 percent) of the total issued and outstanding
shares as of December 31 of the year preceding the awards. Any shares not issued
in the current year are available for future grant. The Plan could result in an
8 percent dilution of stockholders' interest if all available shares are awarded
over the 10-year life of the Plan. The Plan also provides for non-stock-based
awards. Stock-based compensation expense recognized in connection with the Plan
was $21 million, $23 million and $8 million in 2001, 2000 and 1999,
respectively.
Shares of stock awarded under the Plan were:
<Table>
<Caption>
2001 2000 1999
---------- ---------- ----------
Shares 237,849 319,726 97,979
Weighted-average fair value $ 56.23 46.98 41.53
---------- ---------- ----------
</Table>
Stock options granted under provisions of the Plan and earlier plans permit
purchase of the company's common stock at exercise prices equivalent to the
average market price of the stock on the date the options were granted. The
options have terms of 10 years and normally become exercisable in increments of
up to 33.33 percent on each anniversary date following the date of grant. Stock
Appreciation Rights (SARs) may, from time to time, be affixed to the options.
Options exercised in the form of SARs permit the holder to receive stock, or a
combination of cash and stock, subject to a declining cap on the exercise price.
The planned merger with Conoco (see Note 25--Merger with Conoco Inc.) would be a
change-in-control event that would result in a lapsing of restrictions on, and
payout of, stock and stock option awards under the Plan. ConocoPhillips offered
to exchange certain stock awards under the Plan with new awards in the form of
restricted stock units. These new restricted stock units would be converted, at
the time of the merger with Conoco, into awards based on the same number of
shares of ConocoPhillips common stock. The exchange offer expired January 16,
2002.
The company has elected to follow Accounting Principles Board Opinion No. 25,
"Accounting for Stock Issued to Employees" (APB No. 25), and related
Interpretations in accounting for its employee stock options, and not the
fair-value accounting provided for under FASB Statement No. 123, "Accounting for
Stock-
105
Based Compensation." Because the exercise price of ConocoPhillips' employee
stock options equals the market price of the underlying stock on the date of
grant, no compensation expense is recognized under APB No. 25. If the provisions
of FASB Statement No. 123 had been applied, net income would have been reduced
$17 million, $12 million and $10 million in 2001, 2000 and 1999, respectively.
Basic and diluted earnings per share would have been reduced $.06 in 2001, $.05
in 2000 and $.04 in 1999. The average grant-date fair values of options awarded
during 2001, 2000 and 1999 were $23.19, $16.00 and $9.92, respectively. The fair
value of each option was estimated using the Black-Scholes option-pricing model
with the following assumptions: expected dividend yields of 2.5 percent in 2001
and 2000, and 3 percent in 1999; expected life of five years in all years;
expected volatility of 27 percent in 2001, 26 percent in 2000, and 21 percent in
1999; and risk-free interest rates of 4.5 percent in 2001, 5.9 percent in 2000
and 6.0 percent in 1999.
In September 2001, ConocoPhillips issued 4.7 million vested stock options to
replace unexercised Tosco stock options. These options had a weighted-average
exercise price of $23.15 per option and a Black-Scholes option-pricing model
value of $32.51 per share.
A summary of ConocoPhillips' stock option activity follows:
<Table>
<Caption>
Weighted-Average
Options Exercise Price
----------- ----------------
Outstanding at December 31, 1998 9,009,228 $ 36.79
Granted 2,010,980 47.09
Exercised (1,086,976) 27.45
Forfeited (88,708) 46.15
----------- ----------------
Outstanding at December 31, 1999 9,844,524 $ 39.84
Granted 1,299,500 61.85
Exercised (1,223,779) 30.79
Forfeited (57,278) 47.06
----------- ----------------
Outstanding at December 31, 2000 9,862,967 $ 43.82
Granted (including Tosco exchange) 9,038,571 38.81
Exercised (2,373,062) 22.36
Forfeited (96,126) 60.41
----------- ----------------
OUTSTANDING AT DECEMBER 31, 2001 16,432,350 $ 44.06
=========== ----------------
</Table>
106
OUTSTANDING AT DECEMBER 31, 2001
<Table>
<Caption>
Weighted-Average
-----------------------------------
Exercise Prices Options Remaining Lives Exercise Price
- --------------- ---------- ---------------- --------------
$ 9.04 TO $31.44 3,056,009 2.83 YEARS $22.67
$31.52 TO $44.91 3,298,126 5.66 YEARS 38.40
$45.75 TO $64.43 10,078,215 8.34 YEARS 52.41
---------- --------------- --------------
</Table>
EXERCISABLE AT DECEMBER 31
<Table>
<Caption>
Weighted-Average
Exercise Prices Options Exercise Price
---------------- -------------- ----------------
2001 $ 9.04 TO $31.44 3,056,009 $ 22.67
$31.52 TO $44.91 3,075,354 38.06
$45.75 TO $64.43 3,525,616 48.32
---------------- -------------- ----------------
2000 $22.57 to $31.44 1,754,047 $ 29.42
$32.25 to $44.91 1,674,129 37.49
$45.75 to $62.57 2,029,352 46.46
---------------- -------------- ----------------
1999 $22.57 to $31.44 2,661,456 $ 28.69
$32.25 to $44.91 1,277,554 36.85
$45.75 to $50.72 962,881 46.18
---------------- -------------- ----------------
</Table>
COMPENSATION AND BENEFITS TRUST (CBT)
The CBT is an irrevocable grantor trust, administered by an independent trustee
and designed to acquire, hold and distribute shares of the company's common
stock to fund certain future compensation and benefit obligations of the
company. The CBT does not increase or alter the amount of benefits or
compensation that will be paid under existing plans, but offers the company
enhanced financial flexibility in providing the funding requirements of those
plans. ConocoPhillips also has flexibility in determining the timing of
distributions of shares from the CBT to fund compensation and benefits, subject
to a minimum distribution schedule. The trustee votes shares held by the CBT in
accordance with voting directions from eligible employees, as specified in a
trust agreement with the trustee.
The company sold 29.2 million shares of previously unissued ConocoPhillips
common stock, $1.25 par value, to the CBT in 1995 for $37 million of cash,
previously contributed to the CBT by ConocoPhillips, and a promissory note from
the CBT to ConocoPhillips of $952 million. The CBT is consolidated by
ConocoPhillips, therefore the cash contribution and promissory note are
eliminated in consolidation. Shares held by the CBT are valued at cost and do
not affect earnings per share or total common stockholders' equity until after
they are transferred out
107
of the CBT. In 2001 and 2000, shares transferred out of the CBT were 292,857 and
508,828, respectively. At December 31, 2001, 27.6 million shares remained in the
CBT. All shares are required to be transferred out of the CBT by January 1,
2021.
NOTE 18--TAXES
Taxes charged to income before extraordinary item and cumulative effect of
change in accounting principle were:
<Table>
<Caption>
Millions of Dollars
------------------------------
2001 2000 1999
-------- -------- --------
TAXES OTHER THAN INCOME TAXES
Excise $ 2,607 1,781 1,750
Property 159 111 82
Production 328 278 58
Payroll 57 53 58
Environmental 14 12 16
Other 19 13 15
-------- -------- --------
$ 3,184 2,248 1,979
======== ======== ========
INCOME TAXES
Federal
Current $ 133 470 40
Deferred 435 224 90
Foreign
Current 842 965 302
Deferred 126 127 127
State and local
Current 97 100 7
Deferred 20 14 7
-------- -------- --------
$ 1,653 1,900 573
======== ======== ========
</Table>
Deferred income taxes reflect the net tax effect of temporary differences
between the carrying amounts of assets and liabilities for financial reporting
purposes and the amounts used for tax purposes. Major components of deferred tax
liabilities and assets at December 31 were:
108
<Table>
<Caption>
Millions of Dollars
-------------------
2001 2000
-------- --------
DEFERRED TAX LIABILITIES
Properties, plants and equipment, and
intangible assets $ 4,739 2,027
Investment in joint ventures 524 564
Inventory 212 --
Other 74 53
-------- --------
Total deferred tax liabilities 5,549 2,644
-------- --------
DEFERRED TAX ASSETS
Contingency accruals 110 20
Benefit plan accruals 450 272
Accrued dismantlement, removal and
environmental costs 452 262
Deferred state income tax 164 17
Inventory -- 20
Other financial accruals and deferrals 72 52
Alternative minimum tax and other
credit carryforwards 228 241
Loss carryforwards 262 323
Other 107 58
-------- --------
Total deferred tax assets 1,845 1,265
Less valuation allowance 263 315
-------- --------
Net deferred tax assets 1,582 950
-------- --------
Net deferred tax liabilities $ 3,967 1,694
======== ========
</Table>
The acquisition of Tosco in September 2001 (see Note 3--Acquisition of Tosco
Corporation) significantly increased deferred tax liabilities and assets.
Valuation allowances have been established for certain foreign and state net
operating loss carryforwards that reduce deferred tax assets to an amount that
will, more likely than not, be realized. Uncertainties that may affect the
realization of these assets include tax law changes and the future level of
product prices and costs. Based on the company's historical taxable income, its
expectations for the future, and available tax-planning strategies, Management
expects that the net deferred tax assets will be realized as offsets to
reversing deferred tax liabilities and as offsets to the tax consequences of
future taxable operating income. The alternative minimum tax credit can be
carried forward indefinitely to reduce the company's regular tax liability.
109
Deferred taxes have not been provided on temporary differences related to
investments in certain foreign subsidiaries and foreign corporate joint ventures
that are essentially permanent in duration. At December 31, 2001 and 2000, these
temporary differences were $247 million and $270 million, respectively.
Determination of the amount of unrecognized deferred taxes on these temporary
differences is not practicable due to foreign tax credits and exclusions.
The amounts of U.S. and foreign income before income taxes, extraordinary item
and cumulative effect of change in accounting principle, with a reconciliation
of tax at the federal statutory rate with the provision for income taxes, were:
<Table>
<Caption>
Percent of
Millions of Dollars Pretax Income
-------------------------------- ---------------------------------
2001 2000 1999 2001 2000 1999
-------- -------- -------- -------- -------- --------
Income from continuing
operations before income
taxes
United States $ 2,110 2,040 388 64.2% 54.4 33.0
Foreign 1,175 1,707 787 35.8 45.6 67.0
-------- -------- -------- -------- -------- --------
$ 3,285 3,747 1,175 100.0% 100.0 100.0
======== ======== ======== ======== ======== ========
Federal statutory
income tax $ 1,150 1,312 411 35.0% 35.0 35.0
Foreign taxes in excess of
federal statutory rate 515 572 225 15.7 15.3 19.1
Domestic tax credits (84) (53) (44) (2.6) (1.4) (3.7)
Tax settlements -- -- (19) -- -- (1.6)
State income tax 76 74 9 2.3 2.0 .8
Other (4) (5) (9) (.1) (.2) (.8)
-------- -------- -------- -------- -------- --------
$ 1,653 1,900 573 50.3% 50.7 48.8
======== ======== ======== ======== ======== ========
</Table>
110
NOTE 19--CASH FLOW INFORMATION
<Table>
<Caption>
Millions of Dollars
-------------------------------
2001 2000 1999
-------- -------- --------
NON-CASH INVESTING AND FINANCING
ACTIVITIES
Acquisition of Tosco by issuance of stock $ 7,049 -- --
Short-term deferred payment to purchase
properties, plants and equipment -- -- 27
Note payable to purchase properties,
plants and equipment 25 111 --
Investment in properties, plants and
equipment through assumption of a
non-cash liability 22 28 --
Investment in properties, plants and
equipment of Alaska businesses
through the assumption of net
non-cash liabilities of these
businesses 125 472 --
Company stock issued under compensation
and benefit plans 13 23 20
Change in fair value of securities (10) 3 15
Fair market value of properties, plants
and equipment exchanged in monetary
transactions -- -- 3
Investment in equity affiliates through
exchange of non-cash assets and
liabilities* (15) 4,272 8
Net book value of properties, plants and
equipment involved in oil and gas
property non-monetary exchanges -- -- 120
Investment in equity affiliate
through direct guarantee of debt 13 13 --
-------- -------- --------
CASH PAYMENTS
Interest
Debt $ 273 294 256
Taxes and other 51 29 19
-------- -------- --------
$ 324 323 275
======== ======== ========
Income taxes $ 1,504 1,066 184
-------- -------- --------
</Table>
*On March 31, 2000, ConocoPhillips combined its midstream gas gathering,
processing and marketing business with the gas gathering, processing, marketing
and natural gas liquids business of Duke Energy into DEFS and on July 1, 2000,
ConocoPhillips and ChevronTexaco combined the two companies' worldwide
chemicals businesses, excluding ChevronTexaco's Oronite business, into CPChem.
See Note 6--Investments and Long-Term Receivables.
111
NOTE 20--SALES OF RECEIVABLES
At December 31, 2001, ConocoPhillips had sold certain credit card and trade
receivables under revolving sales agreements with four unrelated bank-sponsored
entities. These agreements provide for ConocoPhillips to sell up to $1.2 billion
of senior, undivided interests in pools of the credit card or trade receivables
to the bank-sponsored entities. The sold receivables have been legally isolated
from ConocoPhillips and qualify as sales under generally accepted accounting
principles. Three of the bank-sponsored entities are multi-seller conduits, with
access to commercial paper markets, which purchase interests in similar
receivables from numerous other companies unrelated to ConocoPhillips. A fourth
entity is a consolidated subsidiary of an unrelated bank, which engages in other
financing and banking activities with companies unrelated to ConocoPhillips.
ConocoPhillips has no ownership in any of the four bank-sponsored entities and
has no voting influence over any bank-sponsored entity's operating and financial
decisions. As a result, ConocoPhillips does not consolidate any of these
entities. ConocoPhillips also retained interests in the pools of receivables,
which are subordinate to the interests sold to the bank-sponsored entities. The
subordinate interests are measured and recorded at fair value based on the
present value of future expected cash flows, which are estimated using
Management's best estimates of the receivables' performance, including credit
losses and dilution, discounted at a rate commensurate with the risks involved,
to arrive at present value. These assumptions are updated periodically, based on
actual credit loss experience and market interest rates. ConocoPhillips also
retains servicing responsibility for the sold receivables. The fair value of the
servicing responsibility approximates adequate compensation for the servicing
costs incurred. At December 31, 2001 and 2000, ConocoPhillips' retained
interests were $450 million and $224 million, respectively, reported on the
balance sheet in accounts and notes receivable.
112
Total cash flows received from and paid to the bank-sponsored entities in 2001
and 2000 were as follows:
<Table>
<Caption>
Millions of Dollars
--------------------
2001 2000
-------- --------
Receivables sold at beginning of year
Under a revolving agreement $ 400 183
Under a non-revolving agreement 100 --
Tosco receivables sold at September 14, 2001 614 --
New receivables sold 8,907 6,066
Cash collections remitted (9,081) (5,749)
-------- --------
Receivables sold at end of year $ 940 500
======== ========
Discounts and other fees paid on
revolving balances $ 24 18
-------- --------
</Table>
NOTE 21--OTHER FINANCIAL INFORMATION
<Table>
<Caption>
Millions of Dollars
Except Per Share Amounts
--------------------------------
2001 2000 1999
-------- -------- --------
INTEREST
Incurred
Debt $ 524 511 310
Other 45 32 18
-------- -------- --------
569 543 328
Capitalized (231) (174) (49)
-------- -------- --------
Expensed $ 338 369 279
======== ======== ========
RESEARCH AND DEVELOPMENT
EXPENDITURES--expensed $ 44 43 50
-------- -------- --------
ADVERTISING EXPENSES* $ 61 43 36
-------- -------- --------
*Deferred amounts at December 31 were immaterial in all three years.
CASH DIVIDENDS paid per
common share $ 1.40 1.36 1.36
-------- -------- --------
FOREIGN CURRENCY TRANSACTION
GAINS/(LOSSES)--after-tax
E&P $ 2 (10) 3
R&M 3 (3) --
Chemicals -- (1) (1)
Corporate and Other (8) (25) (12)
-------- -------- --------
$ (3) (39) (10)
======== ======== ========
</Table>
113
NOTE 22--RELATED PARTY TRANSACTIONS
Significant transactions with related parties were:
<Table>
<Caption>
Millions of Dollars
------------------------------
2001 2000 1999
-------- -------- --------
Operating revenues(a) $ 935 1,573 882
Purchases(b) 1,006 1,292 340
Operating expenses(c) 246 97 44
Selling, general and
administrative
expenses(d) 102 66 114
Interest income(e) -- 5 9
Interest expense(f) 8 2 --
-------- -------- --------
</Table>
(a) ConocoPhillips' E&P segment sells natural gas to DEFS for processing and
marketing. The company sells natural gas liquids, solvents and
petrochemical feedstocks to CPChem and charges CPChem for the use of common
facilities, such as steam generators, waste and water treaters, and
warehouse facilities at its refining operations.
(b) ConocoPhillips purchases natural gas and natural gas liquids from DEFS and
CPChem for use in its refinery processes and other feedstocks from various
affiliates.
(c) ConocoPhillips pays processing fees to various affiliates.
(d) ConocoPhillips charges both DEFS and CPChem for corporate services provided
to the two equity companies under transition service agreements.
ConocoPhillips pays fees to its pipeline equity companies for transporting
finished products. ConocoPhillips pays processing and common facility fees
to its affiliates.
(e) Prior to July 1, 2000, ConocoPhillips earned interest on loans to certain
affiliates, primarily Sweeny Olefins Limited Partnership.
(f) ConocoPhillips paid interest to Merey Sweeny, L.P. for a loan related to
improvements at the Sweeny refinery.
Elimination of the company's equity percentage share of profit or loss on the
above transactions was not material.
114
NOTE 23--SEGMENT DISCLOSURES AND RELATED INFORMATION
With the merger of Conoco and Phillips, ConocoPhillips' operating segments were
realigned. The following changes were made:
o The natural gas liquids fractionation and marketing business was
transferred from the Refining and Marketing segment to the Midstream
segment.
o The fuels technology business was transferred from the Refining and
Marketing segment to the newly created Emerging Businesses segment.
o Businesses classified as discontinued operations are included in
Corporate and Other.
Amounts reported for 2001, 2000 and 1999 have been reclassified to reflect these
changes.
ConocoPhillips has organized its reporting structure based on the grouping of
similar products and services, resulting in five operating segments:
(1) Exploration and Production (E&P)--This segment explores for and produces
crude oil, natural gas and natural gas liquids on a worldwide basis. At
December 31, 2001, E&P was producing in the United States; the Norwegian
and U.K. sectors of the North Sea; Canada; Nigeria; Venezuela; the Timor
Sea; and offshore Australia and China.
(2) Midstream (formerly Gas Gathering, Processing and Marketing)--This segment
gathers and processes natural gas produced by ConocoPhillips and others,
and fractionates and markets natural gas liquids. Since March 31, 2000,
ConocoPhillips' Midstream segment has included its 30.3 percent equity
investment in DEFS.
(3) Refining and Marketing (R&M)--This segment refines, markets and transports
crude oil and petroleum products, primarily in the United States. The
company has nine U.S. refineries (excluding one refinery treated as
discontinued operations and reported in Corporate and Other) and one in
Ireland. ConocoPhillips markets petroleum products nationwide. On September
14, 2001, ConocoPhillips acquired Tosco Corporation. This acquisition
significantly increased the R&M segment's assets and operations.
115
(4) Chemicals--This segment manufactures and markets petrochemicals and
plastics on a worldwide basis. Since July 1, 2000, ConocoPhillips'
Chemicals segment has consisted primarily of its 50 percent equity
investment in CPChem.
(5) Emerging Businesses--This segment includes the development of new fuels
technologies.
Corporate and Other includes general corporate overhead; all interest revenue
and expense, including preferred dividend requirements of capital trusts;
certain eliminations; discontinued operations; and various other corporate
activities, such as a captive insurance subsidiary and tax items not directly
attributable to the operating segments. Corporate identifiable assets include
all cash and cash equivalents, the company's owned office buildings and research
and development facilities in Bartlesville, Oklahoma, and discontinued
operations. Reporting reclassifications represent adjustments to assets to
include debit balances in liability accounts and exclude credit balances in
asset accounts, which is done for consolidated reporting but not at the
operating segment level.
The company evaluates performance and allocates resources based on, among other
items, net income. Segment accounting policies are the same as those in Note
1--Accounting Policies. Intersegment sales are at prices that approximate
market.
116
ANALYSIS OF RESULTS BY OPERATING SEGMENT
<Table>
<Caption>
Millions of Dollars
------------------------------------------------------------------------------------------
Operating Segments
-------------------------------------------------------------
Emerging Corporate
2001 E&P Midstream R&M Chemicals Businesses and Other Consolidated
--------- --------- --------- --------- ---------- --------- ------------
SALES AND OTHER OPERATING REVENUES
External customers $ 7,611 777 17,944 -- 7 2 26,341
Intersegment (eliminations) 534 416 92 -- -- (1,042) --
--------- --------- --------- --------- --------- --------- ------------
Segment sales $ 8,145 1,193 18,036 -- 7 (1,040) 26,341
========= ========= ========= ========= ========= ========= ============
Depreciation, depletion and
amortization $ (1,115) (1) (246) -- -- (24) (1,386)
Property impairments (26) -- -- -- -- -- (26)
Equity in earnings/(losses) of
affiliates 28 165 88 (240) -- -- 41
Preferred dividend requirements
of capital trusts -- -- -- -- -- (53) (53)
Interest revenue -- -- -- -- -- 13 13
Interest expense -- -- -- -- -- (338) (338)
Income taxes (1,583) (73) (219) 89 7 126 (1,653)
Extraordinary item -- -- -- -- -- (10) (10)
Cumulative effect of accounting
change -- -- 26 -- -- 2 28
Discontinued operations -- -- -- -- -- 11 11
Net income (loss) 1,699 120 418 (128) (12) (436) 1,661
--------- --------- --------- --------- --------- --------- ------------
ASSETS
Identifiable assets $ 14,210 30 16,846 82 2 954 32,124
Investments in and advances
to affiliates 586 166 166 1,852 -- 18 2,788
Reporting reclassifications -- -- -- -- -- 305 305
--------- --------- --------- --------- --------- --------- ------------
Total assets $ 14,796 196 17,012 1,934 2 1,277 35,217
========= ========= ========= ========= ========= ========= ============
CAPITAL EXPENDITURES AND
INVESTMENTS $ 2,516 -- 489 6 -- 66 3,077
--------- --------- --------- --------- --------- --------- ------------
OTHER SIGNIFICANT NON-CASH ITEMS
Dry hole costs and leasehold
impairment $ 99 -- -- -- -- -- 99
Foreign currency losses (gains) 6 -- (2) -- -- 7 11
--------- --------- --------- --------- --------- --------- ------------
2000
SALES AND OTHER OPERATING REVENUES
External customers $ 7,611 1,154 11,851 1,647 -- 2 22,265
Intersegment (eliminations) 654 665 361 147 -- (1,827) --
--------- --------- --------- --------- --------- --------- ------------
Segment sales $ 8,265 1,819 12,212 1,794 -- (1,825) 22,265
========= ========= ========= ========= ========= ========= ============
Depreciation, depletion and
amortization $ (939) (24) (145) (54) -- (13) (1,175)
Property impairments (100) -- -- -- -- -- (100)
Equity in earnings/(losses) of
affiliates 31 137 36 (90) -- -- 114
Preferred dividend requirements
of capital trusts -- -- -- -- -- (53) (53)
Interest revenue -- -- -- -- -- 28 28
Interest expense -- -- -- -- -- (369) (369)
Income taxes (1,794) (91) (125) (21) -- 131 (1,900)
Discontinued operations -- -- -- -- -- 15 15
Net income (loss) 1,945 162 237 (46) -- (436) 1,862
--------- --------- --------- --------- --------- --------- ------------
ASSETS
Identifiable assets $ 13,487 102 3,109 124 -- 953 17,775
Investments in and advances to
affiliates 347 43 147 2,046 -- 29 2,612
Reporting reclassifications -- -- -- -- -- 122 122
--------- --------- --------- --------- --------- --------- ------------
Total assets $ 13,834 145 3,256 2,170 -- 1,104 20,509
========= ========= ========= ========= ========= ========= ============
CAPITAL EXPENDITURES AND
INVESTMENTS $ 1,677 17 217 67 -- 39 2,017
--------- --------- --------- --------- --------- --------- ------------
ACQUISITION OF ARCO'S ALASKA
BUSINESSES $ 6,443 -- -- -- -- -- 6,443
--------- --------- --------- --------- --------- --------- ------------
OTHER SIGNIFICANT NON-CASH ITEMS
Dry hole costs and leasehold
impairment $ 130 -- -- -- -- -- 130
Foreign currency losses 29 -- 3 1 -- 25 58
--------- --------- --------- --------- --------- --------- ------------
</Table>
117
<Table>
<Caption>
Millions of Dollars
------------------------------------------------------------------------------------------
Operating Segments
--------------------------------------------------------------
Emerging Corporate
1999 E&P Midstream R&M Chemicals Businesses and Other Consolidated
--------- --------- --------- --------- ---------- --------- ------------
SALES AND OTHER OPERATING REVENUES
External customers $ 2,998 1,572 8,100 2,418 -- 2 15,090
Intersegment (eliminations) 490 678 369 148 -- (1,685) --
--------- --------- --------- --------- ---------- --------- ------------
Segment sales $ 3,488 2,250 8,469 2,566 -- (1,683) 15,090
========= ========= ========= ========= ========== ========= ============
Depreciation, depletion and
amortization $ (559) (82) (126) (95) -- (36) (898)
Property impairments (69) -- -- -- -- -- (69)
Equity in earnings of affiliates 38 2 30 31 -- -- 101
Preferred dividend requirements
of capital trusts -- -- -- -- -- (53) (53)
Interest revenue -- -- -- -- -- 29 29
Interest expense -- -- -- -- -- (279) (279)
Income taxes (543) (80) (16) (65) -- 131 (573)
Discontinued operations -- -- -- -- -- 7 7
Net income (loss) 570 135 46 164 -- (306) 609
--------- --------- --------- --------- ---------- --------- ------------
ASSETS
Identifiable assets $ 6,462 1,445 2,962 2,470 -- 899 14,238
Investments in and advances to
affiliates 131 6 135 485 -- 13 770
Reporting reclassifications -- -- -- -- -- 193 193
--------- --------- --------- --------- ---------- --------- ------------
Total assets $ 6,593 1,451 3,097 2,955 -- 1,105 15,201
========= ========= ========= ========= ========== ========= ============
CAPITAL EXPENDITURES AND
INVESTMENTS $ 1,079 137 326 98 -- 46 1,686
--------- --------- --------- --------- ---------- --------- ------------
OTHER SIGNIFICANT NON-CASH ITEMS
Dry hole costs and leasehold
impairment $ 92 -- -- -- -- -- 92
Foreign currency losses 19 -- -- 1 -- 13 33
--------- --------- --------- --------- ---------- --------- ------------
</Table>
GEOGRAPHIC INFORMATION
<Table>
<Caption>
Millions of Dollars
------------------------------------------------------------------------
Other
United United Foreign Worldwide
States Norway* Kingdom* Nigeria Countries Consolidated
--------- --------- --------- --------- --------- ------------
2001
OUTSIDE OPERATING REVENUES** $ 23,915 1,322 380 350 374 26,341
--------- --------- --------- --------- --------- ------------
LONG-LIVED ASSETS*** $ 21,618 1,484 654 256 2,572 26,584
--------- --------- --------- --------- --------- ------------
2000
OUTSIDE OPERATING REVENUES** $ 18,810 231 2,183 336 705 22,265
--------- --------- --------- --------- --------- ------------
LONG-LIVED ASSETS*** $ 13,339 1,487 709 224 1,637 17,396
--------- --------- --------- --------- --------- ------------
1999
OUTSIDE OPERATING REVENUES** $ 12,713 193 1,374 164 646 15,090
--------- --------- --------- --------- --------- ------------
LONG-LIVED ASSETS*** $ 7,418 1,605 876 197 1,760 11,856
--------- --------- --------- --------- --------- ------------
</Table>
*In 2000 and 1999, Norway crude oil production was sold internally to the
United Kingdom operations, which then sold it externally to third parties.
**Revenues are attributable to countries based on the location of the
operations generating the revenues.
***Defined as net properties, plants and equipment (including discontinued
operations) plus investments in and advances to affiliates.
Export sales totaled $262 million, $367 million and $356 million in 2001, 2000
and 1999, respectively.
118
NOTE 24--NEW ACCOUNTING STANDARDS
In June 2001, the FASB issued Statement No. 143, "Accounting for Asset
Retirement Obligations." Statement No. 143 is required to be adopted by the
company no later than January 1, 2003, and will require major changes in the
accounting for asset retirement obligations, such as required decommissioning of
oil and gas production platforms, facilities and pipelines. Statement No. 143
requires entities to record the fair value of a liability for an asset
retirement obligation in the period when it is incurred (typically when the
asset is installed at the production location). When the liability is initially
recorded, the entity capitalizes a cost by increasing the carrying amount of the
related property, plant and equipment. Over time, the liability is accreted for
the change in its present value each period, and the initial capitalized cost is
depreciated over the useful life of the related asset. Upon adoption of
Statement No. 143, the company will adjust its recorded asset retirement
obligations to the new requirements using a cumulative-effect approach. All
transition amounts are to be measured using the company's current information,
assumptions, and credit-adjusted, risk-free interest rates. The company is
studying the impact of Statement No. 143 to quantify the potentially significant
impact of the new standard.
In August 2001, the FASB issued Statement No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets," which supersedes Statement No.
121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of," and the accounting and reporting provisions for the
disposal of a segment of a business from APB Opinion No. 30, "Reporting the
Results of Operations--Reporting the Effect of Disposal of a Segment of a
Business, and Extraordinary, Unusual and Infrequently Occurring Events and
Transactions." Statement No. 144 retains the basic recognition and measurement
requirements of Statement No. 121 but addresses certain issues that had surfaced
implementing Statement No. 121. In addition, Statement No. 144 revised the rules
governing non-monetary exchanges of proved oil and gas properties to require
recognition of any loss implied in the exchange. Previously, the book value of
the relinquished property was carried over to the acquired property. This change
is required on a prospective basis so no restatement of exchanges made prior to
January 1, 2002, when ConocoPhillips adopted Statement No. 144, is required.
119
NOTE 25--MERGER WITH CONOCO INC.
On November 18, 2001, Phillips and Conoco announced that their Boards of
Directors had unanimously approved a merger of equals, and that the companies
had signed a definitive merger agreement to form a new company to be named
ConocoPhillips. At special shareholder meetings held on March 12, 2002, the
stockholders of both companies approved the merger.
On August 30, 2002, after receiving clearance from the U.S. Federal Trade
Commission (FTC), Conoco and Phillips combined their businesses by merging with
separate acquisition subsidiaries of ConocoPhillips. As a result, each company
became a wholly owned subsidiary of ConocoPhillips. For accounting purposes,
Phillips was treated as the acquirer and ConocoPhillips was treated as the
successor of Phillips. Under the terms of the agreement, Phillips shareholders
received one share of the new ConocoPhillips common stock for each share of
Phillips common stock that they owned and Conoco shareholders received 0.4677
shares of the new ConocoPhillips common stock for each share of Conoco that they
own. When the merger was consummated, former Phillips stockholders held
approximately 58 percent of the outstanding shares of ConocoPhillips common
stock, while former Conoco shareholders held approximately 42 percent.
As a condition to the merger of Conoco and Phillips, the FTC required that
ConocoPhillips divest the following assets:
o Phillips' Woods Cross business unit, which includes the Woods Cross,
Utah, refinery and associated motor fuel marketing operations (both
retail and wholesale) in Utah, Idaho, Wyoming, and Montana, as well as
Phillips' 50 percent interests in two refined products terminals in
Boise and Burley, Idaho;
o Conoco's Commerce City, Colorado, refinery and related crude oil
pipelines;
o Phillips' Colorado motor fuel marketing operations (both retail and
wholesale);
o Phillips' refined products terminal in Spokane, Washington;
o Phillips' propane terminal assets at Jefferson City, Missouri, and
East St. Louis, Illinois, which include the propane portions of these
terminals and the customer relationships and contracts for the supply
of propane therefrom;
120
o Certain of Conoco's midstream natural gas gathering and processing
assets in southeast New Mexico; and
o Certain of Conoco's midstream natural gas gathering assets in West
Texas.
Further, the FTC required that certain of these assets be held separately within
ConocoPhillips, under the management of a trustee until sold.
Of the Phillips assets listed above, only the Woods Cross business unit
qualified as a "component of an entity" as defined in FASB Statement No. 144,
"Accounting for the Impairment or Disposal of Long-Lived Assets." Accordingly,
the assets and liabilities of the Woods Cross business unit, along with its
earnings and cash flows, are reflected in the financial statements as
discontinued operations.
Results from discontinued operations for the years ended December 31, 2001, 2000
and 1999, included $388 million, $425 million, and $306 million of sales and
other operating revenues, respectively. The company expects to finalize the sale
of the Woods Cross business unit during 2003.
121
- --------------------------------------------------------------------------------
OIL AND GAS OPERATIONS (Unaudited)
Exploration and Production
In accordance with FASB Statement No. 69, "Disclosures about Oil and Gas
Producing Activities," and regulations of the U.S. Securities and Exchange
Commission, the company is making certain supplemental disclosures about its oil
and gas exploration and production operations. While this information was
developed with reasonable care and disclosed in good faith, it is emphasized
that some of the data is necessarily imprecise and represents only approximate
amounts because of the subjective judgments involved in developing such
information. Accordingly, this information may not necessarily represent the
current financial condition of the company or its expected future results.
ConocoPhillips' disclosures by geographic areas include the United States
(U.S.), Norway, the United Kingdom (U.K.), Africa (mainly Nigeria) and Other
Areas. Other Areas include Canada, China, Denmark, Australia, the Timor Sea, and
other countries. When the company uses equity accounting for operations that
have proved reserves, the oil and gas operations are shown separately and
designated as Equity Affiliate. In 2001 and 2000, this consisted of a heavy-oil
project in Venezuela.
Amounts in 2000 were impacted by ConocoPhillips' purchase of all of Atlantic
Richfield Company's (ARCO) Alaskan businesses in late-April 2000.
<Table>
<Caption>
Contents--Oil and Gas Operations Page
- -------------------------------- ----
Proved Reserves Worldwide 123
Results of Operations 129
Statistics 132
Costs Incurred 136
Capitalized Costs 137
Standardized Measure of Discounted Future Net
Cash Flows Relating to Proved Oil and Gas
Reserve Quantities 138
</Table>
122
o PROVED RESERVES WORLDWIDE
<Table>
<Caption>
Years Ended CRUDE OIL
December 31 ------------------------------------------------------------------------------------------------------
Millions of Barrels
------------------------------------------------------------------------------------------------------
Consolidated Operations
-----------------------------------------------------------------------------
Lower Total Other Equity Combined
Alaska 48 U.S. Norway U.K. Africa Areas Total Affiliate Total
------ ------ ------ ------ ------ ------ ------ ------ --------- --------
DEVELOPED AND
UNDEVELOPED
End of 1998 34 148 182 508 64 90 114 958 -- 958
Revisions 1 1 2 33 (3) 11 (5) 38 -- 38
Improved
recovery -- 2 2 16 -- -- -- 18 -- 18
Purchases -- 1 1 -- -- -- 47 48 -- 48
Extensions and
discoveries -- 3 3 -- 9 8 8 28 -- 28
Production (2) (16) (18) (36) (13) (7) (10) (84) -- (84)
Sales -- (30) (30) -- -- -- (12) (42) -- (42)
------ ------ ------ ------ ------ ------ ------ ------ --------- --------
End of 1999 33 109 142 521 57 102 142 964 -- 964
Revisions 9 12 21 73 3 9 (10) 96 -- 96
Improved
recovery 31 -- 31 5 -- -- -- 36 -- 36
Purchases 1,594 1 1,595 -- -- -- -- 1,595 -- 1,595
Extensions and
discoveries 12 3 15 -- -- 5 35 55 613 668
Production (75) (12) (87) (41) (9) (9) (12) (158) -- (158)
Sales -- (1) (1) -- -- -- (12) (13) -- (13)
------ ------ ------ ------ ------ ------ ------ ------ --------- --------
End of 2000 1,604 112 1,716 558 51 107 143 2,575 613 3,188
Revisions 77 (2) 75 51 (6) (5) 9 124 48 172
Improved
recovery 67 1 68 12 -- -- -- 80 -- 80
Purchases -- -- -- -- -- -- 17 17 -- 17
Extensions and
discoveries 9 6 15 -- 2 10 2 29 -- 29
Production (126) (12) (138) (43) (6) (11) (8) (206) (1) (207)
Sales -- -- -- -- -- -- (3) (3) -- (3)
------ ------ ------ ------ ------ ------ ------ ------ --------- --------
END OF 2001 1,631 105 1,736 578 41 101 160* 2,616 660 3,276*
====== ====== ====== ====== ====== ====== ====== ====== ========= ========
DEVELOPED
End of 1998 27 122 149 380 27 84 39 679 -- 679
End of 1999 25 93 118 433 37 89 35 712 -- 712
End of 2000 1,207 98 1,305 478 25 94 24 1,926 -- 1,926
END OF 2001 1,275 91 1,366 513 21 83 15 1,998 47 2,045
------ ------ ------ ------ ------ ------ ------ ------ --------- --------
</Table>
*Includes proved reserves of 17 million barrels attributable to a consolidated
subsidiary in which there is a 13 percent minority interest.
123
o Purchases in Other Areas in 2001 were related to the acquisition of a
majority interest in Petroz N.L., which resulted in the addition of
reserves in the Bayu-Undan field in the Timor Sea.
o At the end of 2000 and 1999, Other Areas included 2 million and 14 million
barrels, respectively, of reserves in Venezuela in which the company had an
economic interest through risk-service contracts. These properties were
sold in June 2001. Net production to the company was approximately 400,000
barrels in 2001; 1,200,000 barrels in 2000; and 600,000 barrels in 1999.
124
<Table>
<Caption>
Years Ended NATURAL GAS
December 31 -----------------------------------------------------------------------------------------------------
Billions of Cubic Feet
-----------------------------------------------------------------------------------------------------
Consolidated Operations
-----------------------------------------------------------------------------
Lower Total Other Equity Combined
Alaska 48 U.S. Norway U.K. Africa Areas Total Affiliate Total
------ ------ ------ ------ ------ ------ ------ ------ --------- --------
DEVELOPED AND
UNDEVELOPED
End of 1998 835 2,702 3,537 1,152 617 329 634 6,269 -- 6,269
Revisions 10 (57) (47) 1 23 23 (46) (46) -- (46)
Improved
recovery -- -- -- 74 -- -- -- 74 -- 74
Purchases -- 128 128 -- -- -- 29 157 -- 157
Extensions and
discoveries -- 253 253 -- 125 226 27 631 -- 631
Production (47) (292) (339) (51) (84) (3) (39) (516) -- (516)
Sales -- (180) (180) -- -- -- (25) (205) -- (205)
------ ------ ------ ------ ------ ------ ------ ------ --------- --------
End of 1999 798 2,554 3,352 1,176 681 575 580 6,364 -- 6,364
Revisions 87 183 270 (162) 10 -- (199) (81) -- (81)
Improved
recovery -- -- -- 52 -- -- -- 52 -- 52
Purchases 2,448 193 2,641 -- -- -- -- 2,641 -- 2,641
Extensions and
discoveries 7 211 218 -- -- -- 26 244 131 375
Production (103) (283) (386) (54) (79) (14) (33) (566) -- (566)
Sales -- (5) (5) -- -- -- (246) (251) -- (251)
------ ------ ------ ------ ------ ------ ------ ------ --------- --------
End of 2000 3,237 2,853 6,090 1,012 612 561 128 8,403 131 8,534
Revisions 60 9 69 (65) (59) 65 (3) 7 14 21
Improved
recovery -- -- -- 13 -- -- -- 13 -- 13
Purchases -- 12 12 -- 10 -- 10 32 -- 32
Extensions and
discoveries 5 405 410 -- 23 109 265 807 -- 807
Production (141) (261) (402) (53) (68) (19) (28) (570) -- (570)
Sales -- -- -- -- (8) -- -- (8) -- (8)
------ ------ ------ ------ ------ ------ ------ ------ --------- --------
END OF 2001 3,161 3,018 6,179 907 510 716 372* 8,684 145 8,829*
====== ====== ====== ====== ====== ====== ====== ====== ========= ========
DEVELOPED
End of 1998 709 2,482 3,191 927 445 26 144 4,733 -- 4,733
End of 1999 630 2,317 2,947 856 413 349 131 4,696 -- 4,696
End of 2000 2,969 2,564 5,533 738 321 335 55 6,982 -- 6,982
END OF 2001 2,969 2,684 5,653 788 265 491 290 7,487 3 7,490
------ ------ ------ ------ ------ ------ ------ ------ --------- --------
</Table>
*Includes proved reserves of 10 billion cubic feet attributable to a
consolidated subsidiary in which there is a 13 percent minority interest.
125
o Natural gas production may differ from gas production (delivered for sale)
on page 132, primarily because the quantities above include gas consumed at
the lease, but omit the gas equivalent of liquids extracted at any
ConocoPhillips-owned, equity-affiliate, or third-party processing plant or
facility.
o Purchases in Other Areas in 2001 were related to the acquisition of a
majority interest in Petroz N.L., which resulted in the addition of
reserves in the Bayu-Undan field in the Timor Sea.
o Extensions and discoveries in Other Areas in 2001 were in Australia.
o Natural gas reserves are computed at 14.65 pounds per square inch absolute
and 60 degrees Fahrenheit.
126
<Table>
<Caption>
Years Ended NATURAL GAS LIQUIDS
December 31 -----------------------------------------------------------------------------------------------------
Millions of Barrels
-----------------------------------------------------------------------------------------------------
Consolidated Operations
-----------------------------------------------------------------------------
Lower Total Other Equity Combined
Alaska 48 U.S. Norway U.K. Africa Areas Total Affiliate Total
------ ------ ------ ------ ------ ------ ------ ------ --------- --------
DEVELOPED AND
UNDEVELOPED
End of 1998 1 99 100 42 5 18 38 203 -- 203
Revisions -- 5 5 (13) (1) -- (1) (10) -- (10)
Improved
recovery -- -- -- 2 -- -- -- 2 -- 2
Purchases -- -- -- -- -- -- 28 28 -- 28
Extensions and
discoveries -- 2 2 -- -- -- -- 2 -- 2
Production -- (9) (9) (2) -- (1) -- (12) -- (12)
Sales -- (6) (6) -- -- -- -- (6) -- (6)
------ ------ ------ ------ ------ ------ ------ ------ --------- --------
End of 1999 1 91 92 29 4 17 65 207 -- 207
Revisions 57 11 68 7 -- 1 (1) 75 -- 75
Purchases 147 -- 147 -- -- -- -- 147 -- 147
Extensions and
discoveries -- 2 2 -- -- -- -- 2 -- 2
Production (7) (8) (15) (2) (1) (1) -- (19) -- (19)
Sales -- -- -- -- -- -- (3) (3) -- (3)
------ ------ ------ ------ ------ ------ ------ ------ --------- --------
End of 2000 198 96 294 34 3 17 61 409 -- 409
Revisions (25) 2 (23) -- -- -- 4 (19) -- (19)
Improved
recovery -- -- -- 1 -- -- -- 1 -- 1
Purchases -- -- -- -- -- -- 10 10 -- 10
Extensions and
discoveries -- 2 2 -- -- -- -- 2 -- 2
Production (9) (7) (16) (2) -- (1) -- (19) -- (19)
------ ------ ------ ------ ------ ------ ------ ------ --------- --------
END OF 2001 164 93 257 33 3 16 75* 384 -- 384*
====== ====== ====== ====== ====== ====== ====== ====== ========= ========
DEVELOPED
End of 1998 -- 97 97 33 3 18 1 152 -- 152
End of 1999 1 89 90 22 3 17 1 133 -- 133
End of 2000 197 94 291 27 2 17 1 338 -- 338
END OF 2001 163 92 255 29 2 16 -- 302 -- 302
------ ------ ------ ------ ------ ------ ------ ------ --------- --------
</Table>
*Includes proved reserves of 10 million barrels attributable to a consolidated
subsidiary in which there is a 13 percent minority interest.
127
o Natural gas liquids reserves include estimates of natural gas liquids to be
extracted from ConocoPhillips' leasehold gas at gas processing plants or
facilities. Estimates are based at the wellhead and assume full extraction.
Production above differs from natural gas liquids production per day
delivered for sale primarily due to:
(1) Natural gas consumed at the lease.
(2) Natural gas liquids production delivered for sale includes only
natural gas liquids extracted from ConocoPhillips' leasehold gas and
sold by ConocoPhillips' Exploration and Production (E&P) segment,
whereas the production above also includes natural gas liquids
extracted from ConocoPhillips' leasehold gas at equity-affiliate or
third-party facilities.
o Purchases in Other Areas in 2001 were related to the acquisition of a
majority interest in Petroz N.L., which resulted in the addition of
reserves in the Bayu-Undan field in the Timor Sea.
128
o RESULTS OF OPERATIONS
<Table>
<Caption>
Years Ended Millions of Dollars
December 31 -------------------------------------------------------------------------------------------------
Consolidated Operations
----------------------------------------------------------------
Lower Total Other Equity Combined
Alaska 48 U.S. Norway U.K. Africa Areas Total Affiliate Total
------ ------ ------ ------ ------ ------ ------ ------ --------- --------
2001
Sales $3,020 1,178 4,198 175 371 281 228 5,253 8 5,261
Transfers 119 119 238 1,039 -- -- -- 1,277 -- 1,277
Other revenues 116 26 142 13 10 8 (7) 166 1 167
------ ------ ------ ------ ------ ------ ------ ------ --------- --------
Total revenues 3,255 1,323 4,578 1,227 381 289 221 6,696 9 6,705
Production costs 784 328 1,112 124 41 47 51 1,375 2 1,377
Exploration expenses 61 69 130 20 11 40 114 315 -- 315
Depreciation, depletion
and amortization 531 203 734 115 118 22 31 1,020 2 1,022
Property impairments -- -- -- -- -- -- 23 23 -- 23
Transportation costs 726 77 803 27 33 5 4 872 -- 872
Other related expenses 84 5 89 -- (8) 3 26 110 2 112
------ ------ ------ ------ ------ ------ ------ ------ --------- --------
1,069 641 1,710 941 186 172 (28) 2,981 3 2,984
Provision for income
taxes 392 173 565 729 50 155 (9) 1,490 -- 1,490
------ ------ ------ ------ ------ ------ ------ ------ --------- --------
Results of operations for
producing activities 677 468 1,145 212 136 17 (19) 1,491 3 1,494
Other earnings 189 8 197 17 -- -- (9) 205 -- 205
------ ------ ------ ------ ------ ------ ------ ------ --------- --------
E&P net income (loss) $ 866 476 1,342 229 136 17 (28) 1,696 3 1,699
====== ====== ====== ====== ====== ====== ====== ====== ========= ========
2000
Sales $2,252 1,102 3,354 139 481 269 456 4,699 -- 4,699
Transfers 74 275 349 1,186 -- -- -- 1,535 -- 1,535
Other revenues 34 25 59 5 (1) -- 138 201 -- 201
------ ------ ------ ------ ------ ------ ------ ------ --------- --------
Total revenues 2,360 1,402 3,762 1,330 480 269 594 6,435 -- 6,435
Production costs 494 308 802 118 42 45 90 1,097 -- 1,097
Exploration expenses 38 73 111 14 36 26 117 304 -- 304
Depreciation, depletion
and amortization 305 190 495 106 138 14 119 872 -- 872
Property impairments -- 13 13 -- -- -- 87 100 -- 100
Transportation costs 364 101 465 27 39 3 11 545 -- 545
Other related expenses 16 4 20 21 (2) -- 36 75 -- 75
------ ------ ------ ------ ------ ------ ------ ------ --------- --------
1,143 713 1,856 1,044 227 181 134 3,442 -- 3,442
Provision for income
taxes 443 207 650 817 69 155 11 1,702 -- 1,702
------ ------ ------ ------ ------ ------ ------ ------ --------- --------
Results of operations for
producing activities 700 506 1,206 227 158 26 123 1,740 -- 1,740
Other earnings 129 53 182 16 (1) -- 8 205 -- 205
------ ------ ------ ------ ------ ------ ------ ------ --------- --------
E&P net income $ 829 559 1,388 243 157 26 131 1,945 -- 1,945
====== ====== ====== ====== ====== ====== ====== ====== ========= ========
1999
Sales $ 31 403 434 103 455 133 259 1,384 -- 1,384
Transfers 57 474 531 650 -- -- -- 1,181 -- 1,181
Other revenues 2 134 136 12 30 -- 16 194 -- 194
------ ------ ------ ------ ------ ------ ------ ------ --------- --------
Total revenues 90 1,011 1,101 765 485 133 275 2,759 -- 2,759
Production costs 24 295 319 140 45 27 103 634 -- 634
Exploration expenses 5 48 53 36 28 24 89 230 -- 230
Depreciation, depletion
and amortization* 8 164 172 105 165 11 80 533 -- 533
Property impairments -- 11 11 28 30 -- -- 69 -- 69
Transportation costs -- 114 114 30 44 5 13 206 -- 206
Other related expenses -- (1) (1) 31 3 2 26 61 -- 61
------ ------ ------ ------ ------ ------ ------ ------ --------- --------
53 380 433 395 170 64 (36) 1,026 -- 1,026
Provision for income
taxes 14 90 104 300 53 60 5 522 -- 522
------ ------ ------ ------ ------ ------ ------ ------ --------- --------
Results of operations for
producing activities 39 290 329 95 117 4 (41) 504 -- 504
Other earnings 32 18 50 19 -- -- (3) 66 -- 66
------ ------ ------ ------ ------ ------ ------ ------ --------- --------
E&P net income (loss) $ 71 308 379 114 117 4 (44) 570 -- 570
====== ====== ====== ====== ====== ====== ====== ====== ========= ========
</Table>
*Includes a $5 million decommissioning accrual adjustment in Norway.
129
o Results of operations for producing activities consist of all the
activities within the E&P organization, except for pipeline and marine
operations, a liquefied natural gas operation, coal operations, and crude
oil and gas marketing activities, which are included in Other earnings.
Also excluded are non-E&P activities, including natural gas liquids
extraction facilities in ConocoPhillips' gas gathering, processing and
marketing joint venture, as well as downstream petroleum and chemical
activities. In addition, there is no deduction for general corporate
administrative expenses or interest.
o Transfers are valued at prices that approximate market.
o Other revenues include gains and losses from asset sales, certain amounts
resulting from the purchase and sale of hydrocarbons, and other
miscellaneous income.
o Production costs consist of costs incurred to operate and maintain wells
and related equipment and facilities used in the production of petroleum
liquids and natural gas. These costs also include taxes other than income
taxes, depreciation of support equipment and administrative expenses
related to the production activity. Excluded are depreciation, depletion
and amortization of capitalized acquisition, exploration and development
costs.
o Exploration expenses include dry hole, leasehold impairment, geological and
geophysical expenses and the cost of retaining undeveloped leaseholds. Also
included are taxes other than income taxes, depreciation of support
equipment and administrative expenses related to the exploration activity.
o Depreciation, depletion and amortization (DD&A) in Results of Operations
differs from that shown for total E&P in Note 23--Segment Disclosures and
Related Information in the Notes to Financial Statements, mainly due to
depreciation of support equipment being reclassified to production or
exploration expenses, as applicable, in Results of Operations. In addition,
Other earnings include certain E&P activities, including their related DD&A
charges.
130
o Transportation costs include costs to transport oil, natural gas or natural
gas liquids to their points of sale. Transportation operations in which the
company has an ownership interest are deemed to be outside the oil and gas
producing activity. Therefore, the profit element related to the cost of
transporting hydrocarbons using operations, in which the company has an
ownership interest, has not been eliminated. The net income of the
transportation operations is included in Other earnings.
o Other related expenses include transportation costs in Alaska for purchased
liquids that were transported to their point of sale, foreign currency
gains and losses, and other miscellaneous expenses.
o The provision for income taxes is computed by adjusting each country's
income before income taxes for permanent differences related to the oil and
gas producing activities that are reflected in the company's consolidated
income tax expense for the period, multiplying the result by the country's
statutory tax rate and adjusting for applicable tax credits.
o Other earnings consist of activities within the E&P segment that are not a
part of the "Results of operations for producing activities." These
non-producing activities include pipeline and marine operations, liquefied
natural gas operations, coal operations, and crude oil and gas marketing
activities.
131
o STATISTICS
<Table>
<Caption>
NET PRODUCTION 2001 2000 1999
------- ------- --------
Thousands of Barrels Daily
CRUDE OIL
Alaska 339 207 7
Lower 48 34 34 43
------ ------ ------
United States 373 241 50
Norway 117 114 99
United Kingdom 19 25 34
Nigeria 30 24 20
China 11 12 10
Canada 1 6 7
Timor Sea 6 7 5
Denmark 3 4 4
Venezuela 1 4 2
------ ------ ------
Total consolidated 561 437 231
Equity affiliate 2 -- --
------ ------ ------
563 437 231
====== ====== ======
NATURAL GAS LIQUIDS*
Alaska 25 19 --
Lower 48 1 1 2
------ ------ ------
United States 26 20 2
Norway 5 5 4
United Kingdom 2 2 2
Nigeria 2 1 2
Canada -- 1 1
------ ------ ------
35 29 11
====== ====== ======
</Table>
*Represents amounts extracted attributable to E&P operations (see natural gas
liquids reserves on page 128 for further discussion). Includes for 2001 and
2000, 15,000 and 12,000 barrels daily in Alaska, respectively, that were sold
from the Prudhoe Bay lease to the Kuparuk lease for reinjection to enhance
crude oil production.
<Table>
<Caption>
NATURAL GAS* Millions of Cubic Feet Daily
----------------------------
Alaska 177 158 122
Lower 48 740 770 828
------ ------ ------
United States 917 928 950
Norway 130 136 126
United Kingdom 178 214 220
Canada 18 83 91
Nigeria 41 33 6
Australia 51 -- --
------ ------ ------
1,335 1,394 1,393
====== ====== ======
</Table>
*Represents quantities available for sale. Excludes gas equivalent of natural
gas liquids shown above.
132
<Table>
<Caption>
2001 2000 1999
-------- -------- --------
AVERAGE SALES PRICES
CRUDE OIL PER BARREL
Alaska $ 23.60 28.87 12.18
Lower 48 23.27 28.57 16.20
United States 23.57 28.83 15.64
Norway 24.02 28.27 18.25
United Kingdom 24.52 28.19 18.40
Nigeria 24.39 28.73 17.84
China 23.89 29.42 17.49
Canada 26.96 28.21 17.45
Timor Sea 24.90 29.81 20.47
Denmark 23.40 28.28 20.64
Venezuela 25.48 26.97 17.80
Total foreign 24.16 28.42 18.26
Total consolidated 23.77 28.65 17.69
Equity affiliate 12.36 -- --
Worldwide 23.74 28.65 17.69
-------- -------- --------
NATURAL GAS LIQUIDS PER BARREL
Alaska $ 23.61 28 97 --
Lower 48 22.47 22.97 12.73
United States 23.49 27.94 12.73
Norway 16.55 14.13 7.67
United Kingdom 18.49 20.57 13.32
Nigeria 7.22 7.18 7.46
Canada 18.77 25.49 14.22
Total foreign 14.61 15.14 9.76
Worldwide 19.74 21.20 10.29
-------- -------- --------
NATURAL GAS (LEASE) PER THOUSAND
CUBIC FEET
Alaska $ 1.75 1.40 --
Lower 48 3.68 3.56 2.03
United States 3.56 3.47 2.03
Norway 3.53 2.56 2.04
United Kingdom 2.88 2.61 2.71
Canada 3.80 3.26 2.14
Nigeria .57 .50 .36
Australia .43 -- --
Total foreign 2.60 2.56 2.37
Worldwide 3.23 3.13 2.15
-------- -------- --------
AVERAGE PRODUCTION COSTS
PER BARREL OF OIL EQUIVALENT
Alaska $ 5.46 5.35 2.41
Lower 48 5.67 5.15 4.42
United States 5.52 5.27 4.16
Norway 2.36 2.28 3.09
United Kingdom 2.22 1.83 1.70
Africa 3.32 4.03 3.22
Other areas 4.17 5.14 6.39
Total foreign 2.70 2.85 3.27
Total consolidated 4.60 4.29 3.66
Equity affiliate 2.74 -- --
Worldwide 4.60 4.29 3.66
-------- -------- --------
</Table>
133
<Table>
<Caption>
2001 2000 1999
------ ------ ------
DEPRECIATION, DEPLETION AND
AMORTIZATION PER BARREL
OF OIL EQUIVALENT
Alaska $ 3.70 3.30 .80
Lower 48 3.30 3.18 2.46
United States 3.58 3.25 2.24
Norway 2.19 2.04 2.21
United Kingdom 6.38 6.02 6.22
Africa 1.55 1.25 1.31
Other areas 2.53 6.80 4.96
Total foreign 2.94 3.64 3.70
Total consolidated 3.37 3.41 3.05
Equity affiliate 2.74 -- --
Worldwide 3.37 3.41 3.05
------ ------ ------
</Table>
<Table>
<Caption>
NET WELLS COMPLETED* Productive Dry
---------------------- ----------------------
2001 2000 1999 2001 2000 1999
---- ---- ---- ---- ---- ----
EXPLORATORY
Alaska 1 -- -- 1 1 **
Lower 48 63 45 1 3 4 1
---- ---- ---- ---- ---- ----
United States 64 45 1 4 5 1
Norway ** ** -- -- -- **
United Kingdom ** 1 1 1 1 --
Africa ** ** ** -- 1 --
Other areas 2 9 9 1 6 5
---- ---- ---- ---- ---- ----
Total consolidated 66 55 11 6 13 6
Equity affiliate -- -- -- -- -- --
---- ---- ---- ---- ---- ----
66 55 11 6 13 6
==== ==== ==== ==== ==== ====
DEVELOPMENT
Alaska 47 52 ** 2 1 --
Lower 48 331 208 116 11 8 6
---- ---- ---- ---- ---- ----
United States 378 260 116 13 9 6
Norway 3 1 2 -- -- --
United Kingdom 1 1 2 -- -- 1
Africa 1 2 ** -- -- --
Other areas 6 12 19 -- 1 3
---- ---- ---- ---- ---- ----
Total consolidated 389 276 139 13 10 10
Equity affiliate 20 -- -- -- -- --
---- ---- ---- ---- ---- ----
409 276 139 13 10 10
==== ==== ==== ==== ==== ====
</Table>
* Includes conventional and coalbed methane wells. Excludes farmout
arrangements.
** ConocoPhillips' total proportionate interest was less than one.
134
WELLS AT YEAR-END 2001
<Table>
<Caption>
Productive**
---------------------------------------
In Progress* Oil Gas
----------------- ----------------- -----------------
Gross Net Gross Net Gross Net
------ ------ ------ ------ ------ ------
Alaska 13 6 1,545 676 25 16
Lower 48 72 32 6,724 1,754 7,244 3,670
------ ------ ------ ------ ------ ------
United States 85 38 8,269 2,430 7,269 3,686
Norway 3 1 165 57 14 5
United Kingdom 6 2 17 5 128 22
Africa 2 *** 209 42 12 2
Other areas 6 1 115 30 219 70
------ ------ ------ ------ ------ ------
Total consolidated 102 42 8,775 2,564 7,642 3,785
Equity affiliate 13 5 49 20 7 2
------ ------ ------ ------ ------ ------
115 47 8,824 2,584 7,649 3,787
====== ====== ====== ====== ====== ======
</Table>
* Includes wells that have been temporarily suspended.
** Includes 1,322 gross and 524 net multiple completion wells.
*** ConocoPhillips' total proportionate interest was less than one.
<Table>
<Caption>
ACREAGE AT DECEMBER 31, 2001 Thousands of Acres
------------------
Gross Net
------ ------
DEVELOPED
Alaska 767 356
Lower 48 2,896 1,891
------ ------
United States 3,663 2,247
Norway 45 16
United Kingdom 339 98
Africa 81 16
Other areas 293 101
------ ------
Total consolidated 4,421 2,478
Equity affiliate 163 65
------ ------
4,584 2,543
====== ======
UNDEVELOPED
Alaska 2,342 1,324
Lower 48 1,674 919
------ ------
United States 4,016 2,243
Norway 2,202 490
United Kingdom 1,355 473
Africa* 25,689 9,237
Other areas 22,958 10,820
------ ------
Total consolidated 56,220 23,263
Equity affiliate -- --
------ ------
56,220 23,263
====== ======
</Table>
* Includes two Somalia concessions where operations have been suspended by
declarations of force majeure totaling 21,865 gross and 8,135 net acres.
135
o COSTS INCURRED
<Table>
<Caption>
Millions of Dollars
--------------------------------------------------------------------------------------------------------------
Consolidated Operations
-----------------------------------------------------------------------------------
Lower Total Other Equity Combined
Alaska 48 U.S. Norway U.K. Africa Areas Total Affiliate Total
------ ------ ------ ------ ------ ------ ------ ------ --------- --------
2001
Acquisition $ 17 37 54 -- -- 99 129 282 -- 282
Exploration 93 57 150 26 18 39 184 417 -- 417
Development 610 312 922 94 75 50 354 1,495 420 1,915
------ ------ ------ ------ ------ ------ ------ ------ ------ ------
$ 720 406 1,126 120 93 188 667 2,194 420 2,614
====== ====== ====== ====== ====== ====== ====== ====== ====== ======
2000
Acquisition $5,787 151 5,938 36 -- -- 38 6,012 3 6,015
Exploration 32 66 98 17 36 26 193 370 -- 370
Development 422 218 640 71 50 35 199 995 135 1,130
------ ------ ------ ------ ------ ------ ------ ------ ------ ------
$6,241 435 6,676 124 86 61 430 7,377 138 7,515
====== ====== ====== ====== ====== ====== ====== ====== ====== ======
1999
Acquisition $ 12 144 156 -- -- -- 360 516 -- 516
Exploration 6 30 36 33 28 21 152 270 -- 270
Development 10 157 167 165 80 23 173 608 -- 608
------ ------ ------ ------ ------ ------ ------ ------ ------ ------
$ 28 331 359 198 108 44 685 1,394 -- 1,394
====== ====== ====== ====== ====== ====== ====== ====== ====== ======
</Table>
o Costs incurred include capitalized and expensed items.
o Acquisition costs include the costs of acquiring proved and unproved oil
and gas properties. It included proved properties of $13 million, $87
million and $89 million in the Lower 48 for 2001, 2000 and 1999,
respectively. The 2001 amount in Other Areas included $63 million for
proved properties in the Timor Sea. The 2000 amount in Alaska included
$5,125 million for proved properties. The 2000 amount in Other Areas
included $33 million for proved properties in Canada. The 1999 amount in
Other Areas included $191 million for proved properties in the Timor Sea.
o Exploration costs include geological and geophysical expenses, the cost of
retaining undeveloped leaseholds, and exploratory drilling costs.
o Development costs include the cost of drilling and equipping development
wells and building related production facilities for extracting, treating,
gathering and storing petroleum liquids and natural gas.
136
o CAPITALIZED COSTS
<Table>
<Caption>
At December 31 Millions of Dollars
-----------------------------------------------------------------------------------------------------------
Consolidated Operations
-----------------------------------------------------------------------------------
Lower Total Other Equity Combined
Alaska 48 U.S. Norway U.K. Africa Areas Total Affiliate Total
------ ------ ------ ------ ------ ------ ------ ------ --------- --------
2001
Proved
properties $6,646 4,552 11,198 2,889 1,773 558 1,298 17,716 708 18,424
Unproved
properties 772 181 953 40 41 104 667 1,805 -- 1,805
------ ------ ------ ------ ------ ------ ------ ------ ------ ------
7,418 4,733 12,151 2,929 1,814 662 1,965 19,521 708 20,229
Accumulated
depreciation,
depletion and
amortization 1,097 3,238 4,335 1,529 1,161 305 314 7,644 4 7,648
------ ------ ------ ------ ------ ------ ------ ------ ------ ------
$6,321 1,495 7,816 1,400 653 357 1,651 11,877 704 12,581
====== ====== ====== ====== ====== ====== ====== ====== ====== ======
2000
Proved
properties $5,967 4,228 10,195 2,830 1,817 505 989 16,336 304 16,640
Unproved
properties 734 180 914 40 71 1 540 1,566 -- 1,566
------ ------ ------ ------ ------ ------ ------ ------ ------ ------
6,701 4,408 11,109 2,870 1,888 506 1,529 17,902 304 18,206
Accumulated
depreciation,
depletion and
amortization 642 3,070 3,712 1,455 1,180 282 366 6,995 1 6,996
------ ------ ------ ------ ------ ------ ------ ------ ------ ------
$6,059 1,338 7,397 1,415 708 224 1,163 10,907 303 11,210
====== ====== ====== ====== ====== ====== ====== ====== ====== ======
</Table>
o Capitalized costs include the cost of equipment and facilities for oil and
gas producing activities. These costs include the activities of
ConocoPhillips' E&P organization, excluding pipeline and marine operations,
the Kenai liquefied natural gas operation, coal operations, and crude oil
and natural gas marketing activities.
o Proved properties include capitalized costs for oil and gas leaseholds
holding proved reserves; development wells and related equipment and
facilities (including uncompleted development well costs); and support
equipment.
o Unproved properties include capitalized costs for oil and gas leaseholds
under exploration (including where petroleum liquids and natural gas were
found but determination of the economic viability of the required
infrastructure is dependent upon further exploratory work under way or
firmly planned) and for uncompleted exploratory well costs, including
exploratory wells under evaluation.
137
o STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED
OIL AND GAS RESERVE QUANTITIES
Amounts are computed using year-end prices and costs (adjusted only for existing
contractual changes), appropriate statutory tax rates and a prescribed 10
percent discount factor. Continuation of year-end economic conditions also is
assumed. The calculation is based on estimates of proved reserves, which are
revised over time as new data becomes available. Probable or possible reserves,
which may become proved in the future, are not considered. The calculation also
requires assumptions as to the timing of future production of proved reserves,
and the timing and amount of future development and production costs.
While due care was taken in its preparation, the company does not represent that
this data is the fair value of the company's oil and gas properties, or a fair
estimate of the present value of cash flows to be obtained from their
development and production.
138
DISCOUNTED FUTURE NET CASH FLOWS
<Table>
<Caption>
Millions of Dollars
------------------------------------------------------------------------------------------------
Consolidated Operations
--------------------------------------------------------------------------
Lower Total Other Equity Combined
Alaska 48 U.S. Norway U.K. Africa Areas Total Affiliate Total
------- ------ ------ ------ ----- ------ ----- ------ --------- --------
2001
Future cash inflows $33,138 9,441 42,579 14,278 2,143 2,453 4,433 65,886 11,581 77,467
Less:
Future production and
transportation costs 20,541 4,241 24,782 2,117 357 583 895 28,734 3,483 32,217
Future development
costs 3,071 530 3,601 627 248 161 927 5,564 1,282 6,846
Future income tax
provisions 1,797 1,253 3,050 8,762 389 1,187 1,417 14,805 2,133 16,938
------- ------ ------ ------ ----- ----- ----- ------ ------ -------
Future net cash flows 7,729 3,417 11,146 2,772 1,149 522 1,194 16,783 4,683 21,466
10 percent annual
discount 3,297 1,821 5,118 1,247 360 259 804 7,788 3,687 11,475
------- ------ ------ ------ ----- ----- ----- ------ ------ -------
Discounted future
net cash flows $ 4,432 1,596 6,028 1,525 789 263 390* 8,995 996 9,991*
======= ====== ====== ====== ===== ===== ===== ====== ====== =======
2000
Future cash inflows $39,554 29,027 68,581 16,002 3,012 2,699 5,630 95,924 14,812 110,736
Less:
Future production and
transportation costs 20,338 3,996 24,334 2,060 426 653 831 28,304 2,519 30,823
Future development
costs 2,916 479 3,395 679 372 65 960 5,471 1,684 7,155
Future income tax
provisions 3,772 8,206 11,978 10,103 592 1,419 1,057 25,149 2,546 27,695
------- ------ ------ ------ ----- ----- ----- ------ ------ -------
Future net cash flows 12,528 16,346 28,874 3,160 1,622 562 2,782 37,000 8,063 45,063
10 percent annual
discount 5,660 8,684 14,344 1,429 571 279 1,595 18,218 6,428 24,646
------- ------ ------ ------ ----- ----- ----- ------ ------ -------
Discounted future
net cash flows $ 6,868 7,662 14,530 1,731 1,051 283 1,187 18,782 1,635 20,417
======= ====== ====== ====== ===== ===== ===== ====== ====== =======
1999
Future cash inflows $ 1,518 7,897 9,415 15,387 3,207 2,869 5,967 36,845 -- 36,845
Less:
Future production and
transportation costs 339 3,322 3,661 2,723 488 530 1,283 8,685 -- 8,685
Future development
costs 210 445 655 772 491 91 990 2,999 -- 2,999
Future income tax
provisions 334 1,084 1,418 8,949 572 1,701 1,166 13,806 -- 13,806
------- ------ ------ ------ ----- ----- ----- ------ ------ -------
Future net cash flows 635 3,046 3,681 2,943 1,656 547 2,528 11,355 -- 11,355
10 percent annual
discount 286 1,417 1,703 1,229 556 266 1,396 5,150 -- 5,150
------- ------ ------ ------ ----- ----- ----- ------ ------ -------
Discounted future
net cash flows $ 349 1,629 1,978 1,714 1,100 281 1,132 6,205 -- 6,205
======= ====== ====== ====== ===== ===== ===== ====== ====== =======
</Table>
*Includes $17 million attributable to a consolidated subsidiary in which there
is a 13 percent minority interest.
139
SOURCES OF CHANGE IN DISCOUNTED FUTURE NET CASH FLOWS
<Table>
<Caption>
Millions of Dollars
-----------------------------------------------------------------------------------------------
Consolidated Operations Equity Affiliate Total
------------------------------- ------------------------- ------------------------------
2001 2000 1999 2001 2000 1999 2001 2000 1999
-------- ------- ------ ------ ------ ----- ------- ------- ------
Discounted future net cash
flows at the beginning
of the year $ 18,782 6,205 3,094 1,635 -- -- 20,417 6,205 3,094
-------- ------- ------ ------ ------ ----- ------- ------- ------
Changes during the year
Revenues less production
and transportation
costs for the year (4,283) (4,592) (1,725) (6) -- -- (4,289) (4,592) (1,725)
Net change in prices, and
production and
transportation costs (14,668) 10,396 8,316 (1,552) -- -- (16,220) 10,396 8,316
Extensions, discoveries and
improved recovery, less
estimated future costs 757 1,817 734 -- 2,402 -- 757 4,219 734
Development costs for the
year 1,495 995 608 420 135 -- 1,915 1,130 608
Changes in estimated
future development costs (1,011) (775) (376) (17) (135) -- (1,028) (910) (376)
Purchases of reserves in
place, less estimated
future costs 130 8,168 633 -- -- -- 130 8,168 633
Sales of reserves in
place, less estimated
future costs (9) (1,037) (509) -- -- -- (9) (1,037) (509)
Revisions of previous
quantity estimates* 15 1,750 (332) 38 -- -- 53 1,750 (332)
Accretion of discount 2,877 1,217 498 260 -- -- 3,137 1,217 498
Net change in income taxes 4,909 (5,360) (4,738) 218 (767) -- 5,127 (6,127) (4,738)
Other 1 (2) 2 -- -- -- 1 (2) 2
-------- ------- ------ ------ ------ ----- ------- ------- ------
Total changes (9,787) 12,577 3,111 (639) 1,635 -- (10,426) 14,212 3,111
-------- ------- ------ ------ ------ ----- ------- ------- ------
Discounted future net cash
flows at year-end $ 8,995 18,782 6,205 996 1,635 -- 9,991 20,417 6,205
======== ======= ====== ====== ====== ===== ======= ======= ======
</Table>
* Includes amounts resulting from changes in the timing of production.
o The net change in prices, and production and transportation costs is the
beginning-of-the-year reserve-production forecast multiplied by the net
annual change in the per-unit sales price, and production and
transportation cost, discounted at 10 percent.
o Purchases and sales of reserves in place, along with extensions,
discoveries and improved recovery, are calculated using production
forecasts of the applicable reserve quantities for the year multiplied by
the end-of-the-year sales prices, less future estimated costs, discounted
at 10 percent.
o The accretion of discount is 10 percent of the prior year's discounted
future cash inflows, less future production, transportation and development
costs.
o The net change in income taxes is the annual change in the discounted
future income tax provisions.
140
SELECTED QUARTERLY FINANCIAL DATA
<Table>
<Caption>
Millions of Dollars Per Share of Common Stock
--------------------------------------------------- --------------------------------
Income Before
Extraordinary
Income Before Item and
Extraordinary Cumulative
Item and Effect of
Income from Cumulative Change in
Sales Continuing Effect of Accounting
and Other Operations Change in Principle Net Income
Operating Before Income Accounting Net -------------- --------------
Revenues* Taxes Principle Income Basic Diluted Basic Diluted
--------- ------------- ----------- ------ ----- ------- ----- -------
2001
First** $5,185 1,017 488 516 1.91 1.90 2.02 2.01
Second** 5,211 1,199 619 619 2.42 2.40 2.42 2.40
Third 6,034 713 374 364 1.35 1.34 1.31 1.30
Fourth 9,911 356 162 162 .42 .42 .42 .42
--------- ------------- ----------- ------ ----- ------- ----- -------
2000
First $5,089 542 250 250 .99 .98 .99 .98
Second 5,708 884 442 442 1.74 1.73 1.74 1.73
Third 5,464 927 426 426 1.67 1.66 1.67 1.66
Fourth 6,004 1,394 744 744 2.91 2.88 2.91 2.88
--------- ------------- ----------- ------ ----- ------- ----- -------
</Table>
* Includes excise taxes on petroleum products sales, beginning third quarter
2001. Prior periods have been restated to conform.
** Restated to reflect a change in the company's method of accounting for the
costs of major maintenance turnarounds from the accrue-in-advance method to
the expense-as-incurred method.
In the above table, amounts for net income include certain special items, as
shown in the following table:
<Table>
<Caption>
Special Items by Quarter
-------------------------------------------------------------------
Millions of Dollars
-------------------------------------------------------------------
First Second Third Fourth
------------- ------------- ------------- -------------
2001 2000 2001 2000 2001 2000 2001 2000
---- ---- ---- ---- ---- ---- ---- ----
Property impairments $ -- -- (23) -- -- (93) (2) (2)
Net gain/(loss) on asset sales (3) 7 6 (5) 13 19 -- 143
Pending claims and settlements (5) (30) 2 6 5 (2) 23 10
Equity companies' special items (5) -- 32 -- (34) (2) (60) (96)
Extraordinary item -- -- -- -- (10) -- -- --
Cumulative effect of accounting
change 28 -- -- -- -- -- -- --
Discontinued operations (1) -- 4 3 5 7 3 5
Other items (1) 2 -- 2 12 (1) (26) (12)
---- ---- ---- ---- ---- ---- ---- ----
Total special items $ 13 (21) 21 6 (9) (72) (62) 48
==== ==== ==== ==== ==== ==== ==== ====
</Table>
All periods restated for discontinued operations (see Note 25 in the financial
statements notes)
141
CONOCOPHILLIPS
(FORMERLY PHILLIPS PETROLEUM COMPANY)
(CONSOLIDATED)
SCHEDULE II--VALUATION ACCOUNTS AND RESERVES
<Table>
<Caption>
Millions of Dollars
-------------------------------------------------------------
Additions
Balance ------------------- Balance
at Charged to at
Description January 1 Expense Other Deductions December 31
- ----------- --------- ---------- ----- ---------- -----------
(a) (b) (c)
2001
Deducted from asset accounts:
Allowance for doubtful accounts
and notes receivable $ 18 13 18 16 33
Deferred tax asset valuation
allowance 315 14 (47) 17 263
Included in other liabilities
and discontinued operations:
Reserve for maintenance
turnarounds 47 -- -- 47(e) --
--------- ---------- ----- ---------- -----------
2000
Deducted from asset accounts:
Allowance for doubtful accounts
and notes receivable $ 19 8 -- 9* 18
Deferred tax asset valuation
allowance 328 (11) (2) -- 315
Included in other liabilities
and discontinued operations:
Reserve for maintenance
turnarounds 88 52 -- 93(d) 47
--------- ---------- ----- ---------- -----------
1999
Deducted from asset accounts:
Allowance for doubtful accounts
and notes receivable $ 13 12 -- 6 19
Deferred tax asset valuation
allowance 327 (4) 5 -- 328
Included in other liabilities
and discontinued operations:
Reserve for maintenance
turnarounds 87 52 -- 51 88
--------- ---------- ----- ---------- -----------
</Table>
*Includes $2 million transferred to joint-venture companies.
(a) Amounts charged to income less reversal of amounts previously charged to
income.
(b) Represents acquisitions/dispositions and the effect of translating foreign
financial statements.
(c) Amounts charged off less recoveries of amounts previously charged off.
(d) Includes $24 million transferred to an equity-affiliate company on July 1,
2000.
(e) Effective January 1, 2001, ConocoPhillips changed its method of accounting
for the costs of major maintenance turnarounds from the accrue-in-advance
method to the expense- as-incurred method.
142