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Notes
to Consolidated Financial Statements
| Note
1 — Accounting Policies |
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Consolidation
Principles and Investments — Consolidation
decisions are based on the risk, rewards and voting rights associated
with our interest in an entity. Entities that are determined
to be Variable Interest Entities (VIEs), as defined by Financial
Accounting Standards Board (FASB) Interpretation No. 46, as
revised, (FIN 46) will be consolidated if we are the primary
beneficiary of that entity. For entities that are not VIEs under
FIN 46, we consolidate majority-owned, controlled subsidiaries.
The equity method is used to account for investments in affiliates
in which we exert significant influence, generally having a
20 to 50 percent ownership interest. We also use the equity
method for our 50.1 percent and 57.1 percent non-controlling
interests in Petrozuata C.A. and Hamaca Holding LLC, respectively,
located in Venezuela because the minority shareholders have
substantive participating rights, under which all substantive
operating decisions (e.g., annual budgets, major financings,
selection of senior operating management, etc.) require joint
approvals. The cost method is used when we do not have significant
influence. Undivided interests in oil and gas joint ventures,
pipelines, natural gas plants, certain transportation assets
and Canadian Syncrude mining operations are consolidated on
a proportionate basis. Other securities and investments, excluding
marketable securities, are generally carried at cost.
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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 include the sales
portion of contracts involving purchases and sales necessary
to reposition supply to address location or quality or grade
requirements (e.g., when we reposition crude by entering into
a contract with a counterparty to sell crude in one location
and purchase it in a different location) and sales related
to purchase for resale activity. Revenues from the production
of natural gas properties, in which we have an interest with
other producers, are recognized based on the actual volumes
we sold during the period. Any differences between volumes
sold and entitlement volumes, based on our net working interest,
which are deemed non-recoverable through remaining production,
are recognized as accounts receivable or accounts payable,
as appropriate. Cumulative differences between volumes sold
and entitlement volumes are 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.
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Reclassification
— Certain amounts in the 2002 and
2001 financial statements have been reclassified to conform
with the 2003 presentation.
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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.
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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. They are carried at
cost plus accrued interest, which approximates fair value.
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Inventories
— We have several valuation methods
for our various types of inventories and consistently use the
following methods for each type of inventory. Crude oil, petroleum
products, and Canadian Syncrude 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.
Costs include both direct and indirect expenditures incurred
in bringing an item or product to its existing condition and
location, but not unusual/non-recurring costs or research and
development costs. Materials, supplies and other miscellaneous
inventories are valued using the weighted-average-cost method,
consistent with general industry practice. Merchandise inventories
at our retail marketing outlets are valued using the first-in,
first-out (FIFO) retail method, consistent with general industry
practice.
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Derivative
Instruments — All derivative
instruments are recorded on the balance sheet at fair value
in either accounts and notes receivable, other assets, accounts
payable, or other liabilities and deferred credits. Recognition
of the gain or loss that results from recording and adjusting
a derivative to fair 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. For derivative instruments that are designated and
qualify as a fair value hedge, the gains or losses from adjusting
the derivative to its fair 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 derivative instruments
that are designated and qualify as a cash flow hedge 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 income statement, gains and losses from derivatives
that are held for trading and not directly related to our
physical business are recorded in other income. Gains and
losses from derivatives used for other purposes are recorded
in either sales and other operating revenues, other income,
purchased crude oil and products, interest and debt expense,
foreign currency transaction gains/losses, depending on the
purpose for issuing or holding the derivative.
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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 and included in the balance sheet caption
properties, plants and equipment. 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.
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Syncrude
Mining Operations — Capitalized
costs, including support facilities, include the cost of the
acquisition and other capital costs incurred. Capital costs
are depreciated using the unit-of-production method based on
the applicable portion of proven reserves associated with each
mine location and its facilities.
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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. Each reporting period, we evaluate
the remaining useful lives of intangible assets not being amortized
to determine whether events and circumstances continue to support
indefinite useful lives. Intangible assets are considered impaired
if the fair value of the intangible asset is lower than cost.
The fair value of intangible assets is determined based on quoted
market prices in active markets, 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.
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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. For
purposes of goodwill impairment calculations, reporting units
have been determined to be Worldwide Exploration and Production,
Worldwide Refining and Worldwide Marketing. 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 the present values
of expected future cash flows using discount rates commensurate
with the risks involved in the operations and observed market
multiples of operating cash flows and net income.
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Depreciation
and Amortization — Depreciation
and amortization of properties, plants and equipment on producing
oil and gas properties, certain pipeline assets (those which
are expected to have a declining utilization pattern), and on
Syncrude mining operations 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).
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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 through additional amortization or
depreciation provisions in the periods in which the determination
of impairment is made. Individual assets are grouped for impairment
purposes at 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, at an entire
complex level for refining assets or at a site level for retail
stores. 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, Statement of Financial Accounting Standards
(SFAS) 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.
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Maintenance
and Repairs — The costs of maintenance
and repairs, which are not significant improvements, are expensed
when incurred.
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Shipping
and Handling Costs — Our 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. Freight costs billed to customers are
recorded as a component of revenue.
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Advertising
Costs — Production costs of media
advertising are deferred until the first public showing of the
advertisement. Advances to secure advertising slots at specific
sporting 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
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.
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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.
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Asset
Retirement Obligations and Environmental Costs — Effective
January 1, 2003, the company adopted SFAS No. 143, “Accounting
for Asset Retirement Obligations,” which applies to legal
obligations associated with the retirement and removal of
long-lived assets. SFAS 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). Through December
31, 2002, the estimated undiscounted costs, net of salvage
values, of dismantling and removing major oil and gas production
and transportation facilities, including necessary site restoration,
were accrued using either the unit-of-production or the straight-line
method, which was used for certain regional production transportation
assets that are expected to have a straight-line utilization
pattern. See Note 2 — Changes in Accounting Principles for
additional information.
Environmental expenditures are expensed or capitalized, depending
upon their future economic benefit. Expenditures that relate
to an existing condition caused by past operations, and do
not have a 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, such as state reimbursement
funds, are recorded as assets when their receipt is probable.
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Stock-Based
Compensation — Effective January
1, 2003, we voluntarily adopted the fair-value accounting
method provided for under SFAS No. 123, “Accounting for Stock-Based
Compensation.” We used the prospective transition method provided
under SFAS 123, applying the fair-value accounting method
and recognizing compensation expense equal to the fair-market
value on the grant date for all stock options granted or modified
after December 31, 2002.
Employee
stock options granted prior to 2003 continue to be accounted
for under Accounting Principles Board Opinion (APB) No. 25,
“Accounting for Stock Issued to Employees,” and related Interpretations.
Because the exercise price of our employee stock options equals
the market price of the underlying stock on the date of grant,
no compensation expense is generally recognized under APB
No. 25. The following table displays pro forma information
as if the provisions of SFAS No. 123 had been applied to all
employee stock options granted:
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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 income/loss in common stockholders’
equity. Foreign currency transaction gains and losses are included
in current earnings. Most of our foreign operations use their
local currency as the functional currency.
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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 our assets and liabilities, except for
deferred taxes on income considered to be permanently reinvested
in certain foreign subsidiaries and foreign corporate joint
ventures. Allowable tax credits are applied currently as reductions
of the provision for income taxes.
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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 unallocated shares held by the stock savings
feature of the ConocoPhillips Savings Plan. Diluted income per
share of common stock includes the above, plus “in-the-money”
stock options issued under our compensation plans. Treasury
stock and shares held by the Compensation and Benefits Trust
(CBT) are excluded from the daily weighted-average number of
common shares outstanding in both calculations.
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Capitalized
Interest — Interest from external
borrowings is capitalized on major projects with an expected
construction period of one year or longer. Capitalized interest
is added to the cost of the underlying asset and is amortized
over the useful lives of the assets in the same manner as the
underlying assets.
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Accounting
for Sales of Stock by Subsidiary or Equity Investees
— We recognize a gain or loss upon the direct sale of equity
by our subsidiaries or equity investees if the sales price differs
from our carrying amount, and provided that the sale of such
equity is not part of a broader corporate reorganization. |
Note
2 — Changes in Accounting Principles
Accounting
for Asset Retirement Obligations
Effective
January 1, 2003, we adopted SFAS No. 143, “Accounting for Asset
Retirement Obligations,” which applies to legal obligations associated
with the retirement and removal of long-lived assets. SFAS No. 143
requires entities to record the fair value of a liability for an
asset retirement obligation in the period when it is incurred (typically
when the asset is installed at the production location). When the
liability is initially recorded, the entity capitalizes the cost
by increasing the carrying amount of the related properties, plants
and equipment. Over time, the liability is increased for the change
in its present value each period, and the initial capitalized cost
is depreciated over the useful life of the related asset.
Application of this new accounting principle resulted in an initial
increase in net properties, plants and equipment of $1.2 billion
and an asset retirement obligation liability increase of $1.1 billion.
The cumulative effect of the change increased 2003 net income by
$145 million (after reduction of income taxes of $21 million). The
2003 effect of the adoption increased income from continuing operations
and net income for 2003 by $32 million, or $.05 per basic and diluted
share.
We have numerous asset removal obligations that we are required
to perform under law or contract once an asset is permanently taken
out of service. Most of these obligations are not expected to be
paid until several years, or decades, in the future and will be
funded from general company resources at the time of removal. Our
largest individual obligations are related to fixed-base offshore
production platforms around the world and to production facilities
and pipelines in Alaska.
SFAS No. 143 calls for measurements of asset retirement obligations
to include, as a component of expected costs, an estimate of the
price that a third party would demand, and could expect to receive,
for bearing the uncertainties and unforeseeable circumstances inherent
in the obligations, sometimes referred to as a market-risk premium.
To date, the oil and gas industry has no examples of credit-worthy
third parties who are willing to assume this type of risk, for a
determinable price, on major oil and gas production facilities and
pipelines. Therefore, because determining such a market-risk premium
would be an arbitrary process, we have excluded it from our SFAS
No. 143 estimates.
During
2003, our overall asset retirement obligation changed as follows:
The
following table presents the pro forma effects of the retroactive
application of this change in accounting principle as if the principle
had been adopted on January 1, 2001.
Consolidation
of Variable Interest Entities
In January 2003, the FASB issued Interpretation No. 46, “Consolidation
of Variable Interest Entities,” (FIN 46) to expand existing accounting
guidance about when a company should include in its consolidated
financial statements the assets, liabilities and activities of another
entity. In general, a variable interest entity (VIE) is a corporation,
partnership, trust, or any other legal structure used for business
purposes that either (a) does not have equity investors with voting
rights or (b) has equity investors that do not provide sufficient
financial resources for the entity to support its activities. FIN
46 requires a VIE to be consolidated by a company if that company
is subject to a majority of the risk of loss from the VIE’s activities,
is entitled to receive a majority of the VIE’s residual returns,
or both (the company required to consolidate is called the primary
beneficiary). It also requires deconsolidation of a VIE if a company
is not the primary beneficiary of the VIE. The interpretation also
requires disclosures about VIEs that a company does not have to
consolidate, but in which it has a significant variable interest,
and about any potential VIE when a company is unable to obtain the
information necessary to confirm if an entity is a VIE or determine
if a company is the primary beneficiary.
In December 2003, the FASB issued a revision to FIN 46 to clarify
some of the provisions and to exempt certain entities from its guidance.
Under the new guidance, special effective date provisions apply
to enterprises that have fully or partially applied FIN 46 prior
to the revision. The consolidation requirements of FIN 46, as revised,
apply to all special purpose entities for periods ending after December
15, 2003. For all other types of variable interest entities the
consolidation requirement applies for periods ending after March
15, 2004.
We adopted FIN 46 in the third quarter of 2003, with retroactive
application to January 1, 2003, for VIEs involving synthetic leases
and certain other financing structures as discussed below. We adopted
FIN 46 for such VIEs because our work on these VIEs was complete
and we believed the FASB’s potential modifications of FIN 46 interpretive
guidance was unlikely to change the primary beneficiary determination
for these VIEs. We consolidated all VIEs created prior to February
1, 2003 (except as noted below), in which we concluded we were the
primary beneficiary. In addition, we deconsolidated an entity where
we determined we were not the primary beneficiary. The revision
of FIN 46 did not change our accounting for any of the entities
we consolidated or deconsolidated under FIN 46 in the third quarter.
We continue to review FIN 46 and related guidance. If subsequent
guidance or interpretation is different from our current understanding,
it is possible that our determination of VIEs and primary beneficiaries
could change.
There are two entities which could potentially be VIEs for which
we were unable to obtain sufficient information to confirm that
the entities were VIEs or to determine if we are the primary beneficiary.
In February 2003, we entered into two agreements establishing separate
guarantee facilities of $50 million each for two liquefied natural
gas ships that were then under construction. Subject to the terms
of each such facility, we will be required to make payments should
the charter revenue generated by the respective ship fall below
certain specified minimum thresholds, and we will receive payments
to the extent that such revenues exceed those thresholds. The net
maximum future payments that we may have to make over the 20-year
terms of the two agreements could be up to an aggregate of $100
million. Actual gross payments over the 20 years could exceed that
amount to the extent cash is received by us. In September 2003,
the first ship was delivered to its owner and the second ship is
scheduled for delivery to its owner in 2005. We have determined
that the agreements give us a variable interest in the two entities
involved, but we do not have enough information regarding these
entities and their activities to confirm that the entities are VIEs
or to determine if we are the primary beneficiary. With respect
to the first ship, the amount drawn under the guarantee facility
at December 31, 2003, was less than $1 million. We continue to make
efforts to obtain the information required to complete the FIN 46
analysis. We currently account for the guarantees under these agreements
as guarantees and contingent liabilities. See Note 16 — Guarantees
for additional information.
The adoption of FIN 46 for VIEs involving synthetic leases and certain
other financing structures resulted in the following:
| Consolidated
VIEs |
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We
consolidated certain VIEs from which we lease certain ocean
vessels, airplanes, refining assets, marketing sites and office
buildings. The consolidation increased net properties, plants
and equipment by $940 million and increased assets of discontinued
operations held for sale by $726 million (both are collateral
for the debt obligations); increased cash by $225 million; increased
debt by $2.4 billion; increased minority interest by $90 million;
reduced other accruals by $263 million, and resulted in a cumulative
after-tax effect-of-adoption loss that decreased net income
and common stockholders’ equity by $240 million. However, during
2003 we exercised our option to purchase most of these assets
and as a result, the leasing arrangements and our involvement
with all but one of the associated VIEs was terminated. See
Note 14 — Debt for more information about the resulting debt
redemptions. At December 31, 2003, we continue to lease refining
assets totaling $126 million, which are collateral for the debt
obligations of $126 million from a VIE. Other than the obligation
to make lease payments and residual value guarantees, the creditors
of the VIE have no recourse to our general credit. In addition,
we discontinued hedge accounting for an interest rate swap since
it had been designated as a cash flow hedge of the variable
interest rate component of a lease with a VIE that is now consolidated.
At December 31, 2003, the fair market value of the swap was
a liability of $13 million.
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Ashford
Energy Capital S.A. continues to be consolidated in our financial
statements under the provisions of FIN 46 because we are the
primary beneficiary. In December 2001, in order to raise funds
for general corporate purposes, Conoco and Cold Spring Finance
S.a.r.l. formed Ashford Energy Capital S.A. through the contribution
of a $1 billion Conoco subsidiary promissory note and $500
million cash. Through its initial $500 million investment,
Cold Spring is entitled to a cumulative annual preferred return,
based on three-month LIBOR rates, plus 1.27 percent. The preferred
return at December 31, 2003, was 2.48 percent. In 2008, and
each 10-year anniversary thereafter, Cold Spring may elect
to remarket their investment in Ashford, and if unsuccessful,
could require ConocoPhillips to provide a letter of credit
in support of Cold Spring’s investment, or in the event that
such letter of credit is not provided, then cause the redemption
of their investment in Ashford. Should ConocoPhillips’ credit
rating fall below investment grade, Ashford would require
a letter of credit to support $475 million of the term loans,
as of December 31, 2003, made by Ashford to other ConocoPhillips
subsidiaries. If the letter of credit is not obtained within
60 days, Cold Spring could cause Ashford to sell the ConocoPhillips
subsidiary notes. At December 31, 2003, Ashford held $1.6
billion of ConocoPhillips subsidiary notes and $25 million
in investments unrelated to ConocoPhillips. We report Cold
Spring’s investment as a minority interest because it is not
mandatorily redeemable and the entity does not have a specified
liquidation date. Other than the obligation to make payment
on the subsidiary notes described above, Cold Spring does
not have recourse to our general credit.
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| Unconsolidated
VIEs |
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Phillips
66 Capital II (Trust) was deconsolidated under the provisions
of FIN 46 because ConocoPhillips is not the primary beneficiary.
During 1997 in order to raise funds for general corporate purposes,
we formed the Trust (a statutory business trust), in which we
own all common beneficial interests. The Trust was created for
the sole purpose of issuing mandatorily redeemable preferred
securities to third-party investors and investing the proceeds
thereof in an approximate equivalent amount of subordinated
debt securities of ConocoPhillips. Application of FIN 46 required
deconsolidation of the Trust, which increased debt by $361 million
since the 8% Junior Subordinated Deferrable Interest Debentures
due 2037 were no longer eliminated in consolidation, and the
$350 million of mandatorily redeemable preferred securities
were deconsolidated.
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In 2003, we recorded a charge of $240 million (after an income tax
benefit of $145 million) for the cumulative effect of adopting FIN
46. The effect of adopting FIN 46 increased 2003 income from continuing
operations by $34 million, or $.05 per basic and diluted share.
Excluding the cumulative effect, the adoption of FIN 46 increased
net income by $139 million, or $.20 per basic and diluted share
in 2003.
Stock-Based Compensation
Effective
January 1, 2003, we adopted the fair-value accounting method provided
for under SFAS No. 123, “Accounting for Stock-Based Compensation.”
We used the prospective transition method provided under SFAS 123,
applying the fair-value accounting method and recognizing compensation
expense for all stock options granted or modified after December
31, 2002. See Note 1 — Accounting Policies and Note 22 — Employee
Benefit Plans for additional information.
Other
Effective
January 1, 2003, we adopted SFAS No. 145, “Rescission of FASB Statements
No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections.” The adoption of SFAS No. 145 requires that gains and
losses on extinguishments of debt no longer be presented as extraordinary
items in the income statement. Accordingly, losses from the extinguishment
of debt of $16 million (after reduction for income taxes of $8 million),
previously reported as an extraordinary item in 2002, have been
reclassified as a $24 million charge to other income with the tax
benefit reclassified to provision for income taxes. Similarly, in
2001, a loss from the early retirement of debt of $10 million (after
reduction for income taxes of $4 million), has been reclassified
as a $14 million charge to other income with the tax benefit reclassified
to provision for income taxes.
In December 2003, the FASB revised and reissued SFAS No. 132 (revised
2003), “Employer’s Disclosures about Pensions and Other Postretirement
Benefits — an amendment of FASB Statements No. 87, 88 and 106.”
While requiring certain new disclosures, the new Standard does not
change the measurement or recognition of employee benefit plans.
We adopted the provisions of this Standard effective December 2003,
except for certain provisions regarding disclosure of information
about estimated future benefit payments which are not required until
periods ending after December 15, 2004.
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).
Note
3 — Merger of Conoco and Phillips
On August 30, 2002, Conoco and Phillips
combined their businesses by merging with separate acquisition subsidiaries
of ConocoPhillips (the merger). As a result, each company became
a wholly owned subsidiary of ConocoPhillips. For accounting purposes,
Phillips was treated as the acquirer of Conoco, and ConocoPhillips
was treated as the successor of Phillips. Conoco’s operating results
have been included in ConocoPhillips’ consolidated financial statements
since the merger date.
Immediately after the closing of the merger, former Phillips stockholders
held approximately 56 percent of the outstanding shares of ConocoPhillips
common stock, while former Conoco stockholders held approximately
44 percent. ConocoPhillips common stock, listed on the New York
Stock Exchange under the symbol “COP,” began trading on September
3, 2002.
The primary reasons for the merger and the principal factors that
contributed to a purchase price that resulted in the recognition
of goodwill were:
The
$16 billion purchase price attributed to Conoco for accounting purposes
was based on an exchange of Conoco shares for ConocoPhillips common
shares. ConocoPhillips issued approximately 293 million shares of
common stock and approximately 23.3 million of employee stock options
in exchange for 627 million shares of Conoco common stock and 49.8
million Conoco stock options. The common stock was valued at $53.15
per share, which was Phillips’ average common stock price over the
two-day trading period immediately before and after the November
18, 2001, public announcement of the transaction. The Conoco stock
options, the fair value of which was determined using the Black-Scholes
option-pricing model, were exchanged for ConocoPhillips stock options
valued at $384 million. Transaction-related costs, included in the
purchase price, were $78 million.
The allocation of the purchase price to specific assets and liabilities
was based, in part, upon an outside appraisal of the fair value
of Conoco’s assets. The following table summarizes the final purchase
price allocation of the fair values of the assets acquired and liabilities
assumed as of August 30, 2002:
Goodwill and certain identifiable intangible assets recorded in
the acquisition are not subject to amortization. However, goodwill
and intangible assets are tested periodically for impairment as
is required by SFAS No. 142, “Goodwill and Other Intangible Assets.”
The acquired intangible assets include $441 million assigned to
marketing tradenames, which are not subject to amortization, $95
million assigned to refining technology, with a weighted-average
amortization period of 12 years, and $18 million assigned to other
intangible assets, with a weighted-average amortization period of
eight years.
We assigned the Conoco goodwill to specific reporting units in the
fourth quarter of 2003. Previously, it had all been reported as
part of Corporate and Other. Included in the $12,721 million of
goodwill is $3,841 million attributable to recording a liability
required for deferred taxes under purchase accounting. This, and
the remaining goodwill of $8,880 million, was assigned to reporting
units based on the benefits received by the units from the synergies
and strategic advantages of the merger. The $12,721 million of goodwill
has been allocated to three reporting units. See Note 11 — Goodwill
and Intangibles for additional information. None of the goodwill
is deductible for tax purposes. During 2003, the balance of goodwill
was adjusted upward by $642 million, primarily due to revisions
in the valuation of properties, plants and equipment, and assumed
contingent liabilities.
The purchase price allocation included $246 million of in-process
research and development costs related to Conoco’s natural gas-to-liquids
and other technologies. In accordance with FASB Interpretation No.
4, “Applicability of FASB Statement No. 2 to Business Combinations
Accounted for by the Purchase Method,” the value assigned to the
research and development activities was charged to selling, general
and administrative expenses in the Emerging Businesses segment at
the date of the merger, as these research and development costs
had no alternative future use.
Merger-related items that reduced our 2003 and 2002 income from
continuing operations were:
In total, these items reduced 2003 and 2002 income from continuing
operations by $223 million and $557 million, respectively ($.33
per share and $1.15 per share on a diluted basis).
The following pro forma summary presents information as if the merger
had occurred at the beginning of each period presented, and includes
for 2002 the $557 million effect of the merger-related items mentioned
above.
During 2001, both Phillips and Conoco entered into other significant
transactions that are not reflected in each of their historical
income statements for the full year 2001. The pro forma results
have been prepared as if the Phillips’ September 14, 2001, acquisition
of Tosco Corporation (Tosco) (see Note 6 — Acquisition of Tosco
Corporation) and Conoco’s July 16, 2001, $4.6 billion acquisition
of Gulf Canada Resources Limited occurred on January 1, 2001. Gulf
Canada Resources Limited was a Canadian-based independent exploration
and production company with primary operations in Western Canada,
Indonesia, the Netherlands and Ecuador.
The pro forma results reflect the following:
The
pro forma adjustments use estimates and assumptions based on currently
available information. Management believes that the estimates and
assumptions are reasonable, and that the significant effects of
the transactions are properly reflected.
The pro forma information does not reflect any anticipated synergies
that might be achieved from combining the operations. The pro forma
information is not intended to reflect the actual results that would
have occurred had the companies been combined during the periods
presented. This pro forma information is not intended to be indicative
of the results of operations that may be achieved by ConocoPhillips
in the future.
Note 4 — Discontinued
Operations
During
2002 and 2003, we disposed of, or had committed to a plan to dispose
of, certain U.S. retail and wholesale marketing assets, certain
U.S. refining and related assets, certain U.S. midstream natural
gas gathering and processing assets, and exploration and production
assets in the Netherlands. Some of these planned dispositions were
mandated by the FTC as a condition of the merger. For reporting
purposes, these operations are classified as discontinued operations,
and in Note 28 — Segment Disclosures and Related Information, these
operations are included in Corporate and Other.
FTC-Mandated
Divestitures
In
the fourth quarter of 2002, we sold our propane terminal assets
at Jefferson City, Missouri, and East St. Louis, Illinois.
During 2003 we sold:
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Our
Woods Cross business unit, which includes the Woods Cross, Utah,
refinery; the Utah, Idaho, Montana, and Wyoming Phillips-branded
motor fuel marketing operations (both retail and wholesale)
and associated assets; and a refined products terminal in Spokane,
Washington;
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Certain
midstream natural gas gathering and processing assets in southeast
New Mexico, and certain midstream natural gas gathering assets
in West Texas; and
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Our
Commerce City, Colorado, refinery, and related crude oil pipelines,
and our Colorado Phillips-branded motor fuel marketing operations
(both retail and wholesale).
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As
a result, all asset dispositions mandated by the FTC as a condition
of the merger have been completed.
Other
Dispositions
In the fourth quarter of 2002, we committed to and initiated
a plan to dispose of 3,200 marketing sites that did not fit into
our long-range plans. In connection with the anticipated sale of
these retail sites, we recorded charges in 2002 totaling $1,412
million before-tax, $1,008 million after-tax, primarily related
to the impairment of properties, plants and equipment ($249 million);
goodwill ($257 million); intangible asset ($429 million); and provisions
for losses and penalties associated with various operating lease
commitments ($477 million).
The intangible asset represented the Circle K tradename. Properties,
plants and equipment included land, buildings and equipment of owned
retail sites and leasehold improvements of leased sites. Fair value
determinations were based on estimated sales prices for comparable
sites.
The provisions for losses and penalties associated with various
operating lease commitments included obligations for residual value
guarantee deficiencies, and future minimum rental payments that
existed prior to the commitment date that would continue after the
exit plan is completed with no economic benefit. It also included
penalties incurred to cancel the contractual arrangements.
In the third quarter of 2003, we concluded the sale of all of our
Exxon-branded marketing assets in New York and New England, including
contracts with independent dealers and marketers. Approximately
230 of the 3,200 sites were included in this package.
In the fourth quarter of 2003, we completed the sale of The Circle
K Corporation and its subsidiaries. The transaction included about
1,660 retail marketing outlets in 16 states and the Circle K brand,
as well as the assignment of the franchise relationship with more
than 350 franchised and licensed stores. In January 2004, we signed
agreements to sell our Mobil-branded marketing assets on the East
Coast in two separate transactions. Assets in the packages include
104 company-owned and operated sites, and 352 dealer sites. Each
of the transactions is expected to close in the second quarter of
2004. Discussions are under way with potential buyers for the remaining
sites, and we expect to complete the sales of these assets during
2004. Based on disposals completed and signed agreements as of December
31, 2003, we recognized an additional charge in 2003 of approximately
$96 million before-tax, $11 million after-tax.
Sales and other operating revenues and income (loss) from discontinued
operations were as follows:
Major
classes of assets and liabilities of discontinued operations held
for sale at December 31 were as follows:
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