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Management’s
Discussion and Analysis of Financial
Condition and Results of Operations
February 25,
2004 (Continued)
Outlook
After
adjusting for asset dispositions, E&P’s worldwide production
for 2004 is expected to be about the same level as it was in 2003.
The dispositions contributed approximately 37,000 barrels of oil
equivalent per day to 2003 production. For 2004, production increases
in Asia Pacific and Latin America are expected to offset net declines
in the United States, Canada and the North Sea.
In
R&M, the optimization of spending related to clean fuels project
initiatives will be an important focus area during 2004. In addition,
we expect our average refinery crude oil utilization rate for 2004
to average about the same as in 2003.
Crude
oil and natural gas prices are subject to external factors over
which we have no control, such as global economic conditions, political
events, demand growth, inventory levels, weather, competing fuels
prices, and availability of supply. Crude oil prices rose significantly
in 2003 due to supply disruptions during the year in several producing
countries and the delays in the return of Iraqi crude production
to the market in the face of rising global oil demand. As a result
of these factors, global oil inventories remained at exceptionally
low levels throughout 2003. Low oil inventories, coupled with economic
recovery and the prospects for higher oil demand growth are expected
to keep prices elevated through the first half of 2004. U.S. natural
gas prices weakened moderately during the second half of 2003 from
the very strong levels experienced during the second quarter, but
the annual average was significantly higher in 2003 versus 2002.
Prices weakened in the second half due to a strong buildup of natural
gas inventories during the summer and early fall, as mild weather,
weak industrial demand and fuel switching reduced natural gas demand.
At the same time, high prices and the startup of a mothballed regasification
terminal increased LNG imports to the United States. However, natural
gas prices rose moderately in December, reflecting continuing concerns
about the adequacy of gas supplies in the United States. Supply
adequacy concerns are expected to keep prices above historical levels
in 2004.
Refining
margins are subject to movements in the price of crude oil and other
feedstocks, and the prices of petroleum products, which are subject
to market factors over which we have no control, such as the U.S.
and global economies; government regulations; military, political
and social conditions in oil producing countries; seasonal factors
that affect demand, such as the summer driving months; and the levels
of refining output and product inventories. U.S. and international
refining and marketing margins rose in 2003 versus 2002, due to
improved refined product demand and a series of supply disruptions.
U.S. refining margins were above the five-year historical average
in 2003 as a result of refinery outages in several regions of the
United States, a product pipeline rupture in Arizona, and labor
strikes in Venezuela, which removed both crude and refined products
from the market. Combined with strong product demand, product inventories
were drawn down to extremely low levels in the first half of the
year, which elevated refining margins. Stronger demand in the face
of tight supplies also improved marketing margins in 2003 versus
2002. The sustainability of current refining and marketing margins
depends on the continued recovery of the global economy and refined
product demand growth.
In
February 2003, the Venezuelan government implemented a currency
exchange control regime. The government has published legal instruments
supporting the controls, one of which establishes official exchange
rates for the U.S. dollar. The devaluation of the Venezuelan currency
by approximately 17 percent in February 2004 did not have a significant
impact on our Venezuelan operations; however, future changes in
the exchange rate could have a significant impact on our Venezuelan
operations. In addition, our Venezuelan operations remain subject
to civil unrest in the country. Our Venezuelan operations contributed
approximately $150 million to our 2003 net income.
In
June 2003, we and our co-venturers in the Mackenzie gas project
in Canada announced that funding and participation agreements have
been reached and a preliminary information package was submitted
to relevant regulatory authorities. The Mackenzie gas project involves
natural gas production facilities, compression and gathering pipelines
in the Mackenzie Delta area, and a pipeline system in the Mackenzie
River Valley. The filing of the information package is a key step
in the process leading to the submission of applications for the
development of the natural gas fields and pipeline facilities. Regulatory
applications are expected to be filed in 2004. First gas production
is currently targeted to commence in late 2009.
In
July 2003, we signed a Heads of Agreement with Qatar Petroleum for
the development of Qatargas 3, a large-scale LNG project located
in Qatar and servicing the U.S. natural gas market. This provides
the framework for the necessary agreements and the completion of
key feasibility studies. Qatargas 3 would be an integrated project,
jointly owned by us and Qatar Petroleum, consisting of facilities
to produce and liquefy gas from Qatar’s North field. The LNG would
be shipped from Qatar, and we would be responsible for regasification
and marketing within the United States. Average daily gas sales
volumes are projected to be approximately 1 billion cubic feet per
day with startup anticipated in the 2009 timeframe.
In
late October 2003, we signed a Heads of Agreement with the Nigerian
National Petroleum Corporation, ENI and ChevronTexaco to conduct
front-end engineering and design work for an LNG facility to be
constructed in Nigeria’s central Niger Delta. The participants have
agreed to form an incorporated joint venture, Brass LNG Limited,
to undertake the project. The engineering and design studies are
expected to be completed in 2005, and the facility is targeted to
be operational in 2009.
In
December 2003, we signed a Statement of Intent with Qatar Petroleum
regarding the construction of a gas-to-liquids plant in Ras Laffan,
Qatar. The Statement of Intent initiates detailed technical and
commercial pre-front-end engineering and design studies and establishes
principles for negotiating a Heads of Agreement for an integrated
reservoir-to-market plant. More definite agreements are expected
in 2004.
Also
in December 2003, we announced the signing of an agreement with
Freeport LNG Development, L.P. to participate in its proposed LNG
receiving terminal in Quintana, Texas. We would acquire 1 billion
cubic feet per day of regasification capacity in the terminal for
our use and obtain a 50 percent interest in the general partnership
managing the venture. The terminal will be designed with a storage
capacity of 6.9 billion cubic feet and a send-out capacity of 1.5
billion cubic feet per day. Pending government approvals, construction
is scheduled to begin in the second half of 2004, with commercial
startup in mid-2007.
In
addition, we and our co-venturer are pursuing a proposed LNG receiving
terminal in Harpswell, Maine. The proposal calls for construction
of the terminal at a site previously used as a U.S. Navy fuel depot.
LNG would be converted back to natural gas at the terminal for delivery
through a new pipeline that would connect the terminal to the existing
pipeline grid. Depending on receipt of the necessary regulatory
approvals, construction could begin in 2006, with the facility operational
by 2009.
CAUTIONARY
STATEMENT FOR THE PURPOSES OF THE
“SAFE HARBOR” PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM
ACT OF 1995
This annual report includes forward-looking
statements within the meaning of Section 27A of the Securities Act
of 1933 and Section 21E of the Securities Exchange Act of 1934.
Forward-looking statements can be identified by the words “expects,”
“anticipates,” “intends,” “plans,” “projects,” “believes,” “estimates”
and similar expressions.
We
have based the forward-looking statements relating to our operations
on our current expectations, estimates and projections about ourselves
and the industries in which we operate in general. We caution you
that these statements are not guarantees of future performance and
involve risks, uncertainties and assumptions that we cannot predict.
In addition, we have based many of these forward-looking statements
on assumptions about future events that may prove to be inaccurate.
Accordingly, our actual outcome and results may differ materially
from what we have expressed or forecast in the forward-looking statements.
Any differences could result from a variety of factors, including
the following:
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Fluctuations in crude oil, natural gas and natural gas
liquids prices, refining and marketing margins and margins for
our chemicals business;
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Changes in our business, operations, results and prospects;
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The operation and financing of our midstream and chemicals
joint ventures;
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Potential failure to realize fully or within the expected
time frame the expected cost savings and synergies from the
combination of Conoco and Phillips;
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Costs or difficulties related to the integration of the
businesses of Conoco and Phillips, as well as the continued
integration of businesses recently acquired by each of them;
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Potential failure or delays in achieving expected reserve
or production levels from existing and future oil and gas development
projects due to operating hazards, drilling risks and the inherent
uncertainties in predicting oil and gas reserves and oil and
gas reservoir performance;
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Unsuccessful exploratory drilling activities;
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Failure of new products and services to achieve market
acceptance;
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Unexpected cost increases or technical difficulties in
constructing or modifying facilities for exploration and production
projects, manufacturing or refining;
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Unexpected difficulties in manufacturing or refining
our refined products, including synthetic crude oil, and chemicals
products;
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Lack of, or disruptions in, adequate and reliable transportation
for our crude oil, natural gas, LNG and refined products;
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Inability to timely obtain or maintain permits, including
those necessary for construction of LNG terminals or regasification
facilities, comply with government regulations or make capital
expenditures required to maintain compliance;
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Potential disruption or interruption of our facilities
due to accidents, political events or terrorism;
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International monetary conditions and exchange controls;
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Liability for remedial actions, including removal and
reclamation obligations, under environmental regulations;
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Liability resulting from litigation;
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General domestic and international economic and political
conditions, including armed hostilities, homeland security,
and governmental disputes over territorial boundaries;
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Changes in tax and other laws or regulations applicable
to our business; and
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Inability to obtain economical financing for exploration
and development projects, construction or modification of facilities
and general corporate purposes. |
Quantitative
and Qualitative Disclosures About Market Risk
Financial
Instrument Market Risk
We
and certain of our 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. We may use financial and commodity-based derivative contracts
to manage the risks produced by changes in the prices of electric
power, natural gas, crude oil and related products, fluctuations
in interest rates and foreign currency exchange rates, or to exploit
market opportunities.
Our
use of derivative instruments is governed by an “Authority Limitations”
document approved by our Board that prohibits the use of highly
leveraged derivatives or derivative instruments without sufficient
liquidity for comparable valuations without approval from the Chief
Executive Officer. The Authority Limitations document also authorizes
the Chief Executive Officer to establish the maximum Value at Risk
(VaR) limits for the company and compliance with these limits is
monitored daily. The Chief Financial Officer monitors risks resulting
from foreign currency exchange rates and interest rates, while the
Executive Vice President of Commercial monitors commodity price
risk. Both report to the Chief Executive Officer. The Commercial
group manages our commercial marketing, optimizes our commodity
flows and positions, monitors related risks of our upstream and
downstream businesses, and selectively takes price risk to add value.
Commodity
Price Risk
We operate in the worldwide crude
oil, refined products, natural gas, natural gas liquids, and electric
power markets and are exposed to fluctuations in the prices for
these commodities. These fluctuations can affect our revenues, as
well as the cost of operating, investing, and financing activities.
Generally, our policy is to remain exposed to market prices of commodities;
however, executive management may elect to use derivative instruments
to hedge the price risk of our crude oil and natural gas production,
as well as refinery margins.
Our
Commercial group uses futures, forwards, swaps, and options in various
markets to optimize the value of our supply chain, which may move
our risk profile away from market average prices to accomplish the
following objectives:
We
use a VaR model to estimate the loss in fair value 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 instruments held or issued, including commodity purchase
and sales contracts recorded on the balance sheet at December 31,
2003, as derivative instruments in accordance with SFAS No. 133,
“Accounting for Derivative Instruments and Hedging Activities,”
as amended. Using Monte Carlo simulation, a 95 percent confidence
level and a one-day holding period, the VaR for those instruments
issued or held for trading purposes at December 31, 2003 and 2002,
was immaterial to our net income and cash flows. The VaR for instruments
held for purposes other than trading at December 31, 2003 and 2002,
was also immaterial to our net income and cash flows.
Interest
Rate Risk
The
following tables provide information about our financial instruments
that are sensitive to changes in interest rates. The debt tables
present principal cash flows and related weighted-average interest
rates by expected maturity dates; the derivative table shows the
notional quantities on which the cash flows will be calculated by
swap termination date. Weighted-average variable rates are based
on implied forward rates in the yield curve at the reporting date.
The carrying amount of our floating-rate debt approximates its fair
value. The fair value of the fixed-rate financial instruments is
estimated based on quoted market prices.
In
October and early November 2003, we executed certain interest rate
swaps that had the effect of converting $1.5 billion of debt from
fixed to floating rate. Under SFAS 133, “Accounting for Derivative
Instruments and Hedging Activities,” these swaps were designated
as hedging the exposure to changes in the fair value of $400 million
of 3.625% Notes due 2007, $750 million of 6.35% Notes due 2009,
and $350 million of 4.75% Notes due 2012. These swaps qualify for
the shortcut method of hedge accounting, so over the term of the
swaps we will not recognize gain or loss due to ineffectiveness
in the hedge.
Foreign
Currency Risk
We
have foreign currency exchange rate risk resulting from operations
in over 40 countries around the world. We do not comprehensively
hedge the exposure to currency rate changes, although we may choose
to selectively hedge exposures to foreign currency rate risk. Examples
include firm commitments for capital projects, certain local currency
tax payments and dividends, and cash returns from net investments
in foreign affiliates to be remitted within the coming year.
At
December 31, 2003, we held foreign currency swaps hedging short-term
intercompany loans between European subsidiaries and a U.S. subsidiary.
Although these swaps hedge exposures to fluctuations in exchange
rates, we elected not to utilize hedge accounting as allowed by
SFAS No. 133. As a result, the change in the fair value of these
foreign currency swaps is recorded directly in earnings. Since the
gain or loss on the swaps is offset by the gain or loss from remeasuring
the intercompany loans into the functional currency of the lender
or borrower, there would be no impact to income from an adverse
hypothetical 10 percent change in the December 31, 2003, exchange
rates.
The
notional and fair market values of these positions at December 31,
2003, were as follows:
At
December 31, 2002, ConocoPhillips had the following significant
foreign currency derivative contracts:
Although
these swaps hedge exposures to fluctuations in exchange rates, the
company elected not to utilize hedge accounting as allowed by SFAS
No. 133. As a result, the change in the fair value of these foreign
currency swaps is recorded directly in earnings. Assuming an adverse
hypothetical 10 percent change in the December 31, 2002, exchange
rates, the potential foreign currency remeasurement loss in non-cash
pretax earnings from these swaps, intercompany loans, and commercial
paper would be approximately $3 million.
In
addition to the intercompany loans discussed above, at December
31, 2002, U.S. subsidiaries held long-term sterling-denominated
intercompany receivables totaling $152 million due from a U.K. subsidiary.
A Norwegian subsidiary held $198 million of intercompany U.S. dollar-denominated
receivables due from its U.S. parent at December 31, 2002. The potential
foreign currency remeasurement gains or losses in non-cash pretax
earnings from a hypothetical 10 percent change in the year-end 2002
exchange rates from these intercompany balances was $35 million.
For
additional information about our use of derivative instruments,
see Note 18 — Derivative Instruments in the Notes to Consolidated
Financial Statements.
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