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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) | ||
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OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) | ||
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OF THE SECURITIES EXCHANGE ACT OF 1934 |
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Delaware | 01-0562944 | |
(State or other jurisdiction of
incorporation or organization) |
(I.R.S. Employer
Identification No.) |
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Title of each class | on which registered | |||
Common Stock, $.01 Par Value
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New York Stock Exchange | |||
Preferred Share Purchase Rights Expiring
June 30, 2012 |
New York Stock Exchange | |||
6.375% Notes due 2009
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New York Stock Exchange | |||
6.65% Debentures due July 15, 2018
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New York Stock Exchange | |||
7% Debentures due 2029
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New York Stock Exchange | |||
7.125% Debentures due March 15, 2028
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New York Stock Exchange | |||
9 3/8% Notes due 2011
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New York Stock Exchange |
[x] Large accelerated filer
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[ ] Accelerated filer |
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[ ] Smaller reporting company |
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Certifications Pursuant to 18 U.S.C. Section 1350 |
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Exploration and Production (E&P)
This segment primarily explores for, produces,
transports and markets crude oil, natural gas and natural gas liquids on a worldwide basis.
Midstream
This segment gathers, processes and markets natural gas produced by
ConocoPhillips and others, and fractionates and markets natural gas liquids, primarily in
the United States and Trinidad. The Midstream segment primarily consists of our 50 percent
equity investment in DCP Midstream, LLC.
Refining and Marketing (R&M)
This segment purchases, refines, markets and transports
crude oil and petroleum products, mainly in the United States, Europe and Asia.
LUKOIL Investment
This segment consists of our equity investment in the ordinary shares
of OAO LUKOIL (LUKOIL), an international, integrated oil and gas company headquartered in
Russia. At December 31, 2007, our ownership interest was 20 percent based on issued
shares, and 20.6 percent based on estimated shares outstanding.
Chemicals
This segment manufactures and markets petrochemicals and plastics on a
worldwide basis. The Chemicals segment consists of our 50 percent equity investment in
Chevron Phillips Chemical Company LLC (CPChem).
Emerging Businesses
This segment represents our investment in new technologies or
businesses outside our normal scope of operations.
Table of Contents
Proved worldwide crude oil, natural gas and natural gas liquids reserves.
Net production of crude oil, natural gas and natural gas liquids.
Average sales prices of crude oil, natural gas and natural gas liquids.
Average production costs per barrel-of-oil-equivalent.
Net wells completed, wells in progress, and productive wells.
Developed and undeveloped acreage.
Table of Contents
Greater Prudhoe Area
The Greater Prudhoe Area is comprised of the Prudhoe Bay field and satellites, as well as the
Greater Point McIntyre Area fields. We have a 36.1 percent non-operator interest in all fields
within the Greater Prudhoe Area.
We operate the Greater Kuparuk Area, which is comprised of the Kuparuk field and four satellite
fields: Tarn, Tabasco, Meltwater, and West Sak. Field installations include three central
production facilities that separate oil, natural gas and water. The natural gas is either used for
fuel or compressed for re-injection.
Table of Contents
The Alpine field, located west of the Kuparuk field, produced at a net rate of 59,200 barrels of
oil per day in 2007, compared with 74,100 barrels per day in 2006. We are the operator and hold a
78 percent interest in Alpine and two satellite fields.
Our assets in Alaska also include the North Cook Inlet field, the Beluga River field, and the Kenai
liquefied natural gas (LNG) facility, all of which we operate.
In 2007, we drilled six exploration wells. Two wells were classified as dry holes and four wells
encountered commercial quantities of oil. One of the successful wells is located in the West Sak
field, and three are in the Tarn field. We also acquired more than 2,360 square kilometers of 3D
seismic and were the successful bidder in two lease sales, acquiring two lease blocks covering
8,253 acres.
We transport the petroleum liquids produced on the North Slope to market through the Trans-Alaska
Pipeline System (TAPS). TAPS is comprised of an 800-mile pipeline, marine terminal, spill response
and escort vessel system that ties the North Slope of Alaska to the port of Valdez in south-central
Alaska.
Table of Contents
Gulf of Mexico
At year-end 2007, our portfolio of producing properties in the Gulf of Mexico included one operated
field and five fields operated by our co-venturers.
Our 2007 onshore production primarily consisted of natural gas, with the majority of production
located in the San Juan Basin, the Permian Basin, the Lobo Trend, the Bossier Trend, and the
Panhandles of Texas and Oklahoma. We also have operations in the Wind River, Anadarko, and Fort
Worth Basins, as well as east Texas and north and south Louisiana. We have other onshore
properties in the Williston Basin, the Piceance Basin, and the Cedar Creek Anticline.
Table of Contents
In June 2006, we acquired a 24 percent interest in West2East Pipeline LLC, a company holding a 100
percent interest in Rockies Express Pipeline LLC (Rockies Express). Rockies Express plans to
construct a 1,679-mile natural gas pipeline from Colorado to Ohio. The pipeline is expected to be
completed in 2009.
In the Lower 48 states, we own undeveloped mineral interests in 7.6 million net acres and hold
leases on 2.2 million undeveloped net acres. In 2007, we successfully completed 81 gross
exploration wells. Areas of focus in 2007 included the east Texas Bossier Trend, deepwater Gulf of
Mexico, Bakken play in the Williston Basin, and the Barnett Trend in the Fort Worth Basin. Other
areas with active exploration drilling programs included the Anadarko and Piceance Basins, and
south Texas.
The Greater Ekofisk Area, located approximately 200 miles offshore Norway in the center of the
North Sea, is composed of four producing fields: Ekofisk, Eldfisk, Embla, and Tor. The Ekofisk
complex serves as a hub for petroleum operations in the area, with surrounding developments
utilizing the Ekofisk infrastructure. Net production in 2007 from the Greater Ekofisk Area was
102,700 barrels of liquids per day and 103 million cubic feet of natural gas per day, compared with
121,700 barrels of liquids per day and 123 million cubic feet of natural gas per day in 2006. We
are the operator and hold a 35.1 percent interest in Ekofisk.
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We have interests in the transportation and processing infrastructure in the Norwegian North Sea,
including a 35.1 percent interest in the Norpipe Oil Pipeline System and a 2.2 percent interest in
Gassled, which owns most of the Norwegian gas transportation system.
In 2007, we participated in one appraisal well and four exploration wells within the Oseberg
licenses of the northern North Sea, license PL018 of the Greater Ekofisk Area, and PL281 in the
Moere Basin of the Norwegian Sea. Drilling operations extended into 2008 on two of these
wells, one of which concluded operations and was expensed as a dry hole in the first quarter of
2008. Drilling operations continue on the other well. Hydrocarbons were encountered in all
three wells whose drilling operations were completed by the end of the year. One of these wells
was successful and the remaining two wells are being evaluated.
We have a 58.7 percent interest in the Britannia natural gas and condensate field, and own 50
percent
of Britannia Operator Limited, the operator of the field. Our net production from Britannia
averaged
252 million cubic feet of natural gas per day and 10,300 barrels of liquids per day in 2007,
compared
with 246 million cubic feet of natural gas per day and 10,100 barrels of liquids per day in 2006.
Table of Contents
The Interconnector pipeline, which connects the United Kingdom and Belgium, facilitates marketing
natural gas produced in the United Kingdom throughout Europe. Our 10 percent equity share of the
Interconnector pipeline allows us to ship approximately 200 million net cubic feet of natural gas
per day to markets in continental Europe, and our reverse-flow rights provide an 85 million net
cubic feet per day of natural gas import capability to the United Kingdom.
In 2007, we participated in five appraisal wells and four exploration wells and were awarded an
interest in one North Sea exploration license in the North SeaP1423.
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We sold our ownership interests in the Danish sector of the North Sea in 2007.
We have varying non-operated production interests in the Dutch sector of the North Sea, as well as
interests in offshore pipelines and an onshore gas plant and terminal at Den Helder. Net
production in 2007 averaged 52 million cubic feet of natural gas per day, compared with 34 million
cubic feet of natural gas per day in 2006.
In 2007, we participated in one exploration well and one appraisal well in the southern North Sea,
both of which encountered hydrocarbons. The exploration well, located within the JDA K15 license,
was successfully completed and began production in 2007. The appraisal well, located within the
E18a license, appraised additional potential to a 2006 discovery. The well was successful and a
field development plan is being progressed.
Western Canada
Operations in western Canada encompass properties in Alberta, northeastern British Columbia and
southern Saskatchewan. The properties in northern Alberta and northeastern British Columbia
contain a mix of oil and natural gas, and are primarily accessible only in the winter. The
properties in the central and foothills areas of Alberta mainly produce natural gas. The
properties in southern Alberta and southern Saskatchewan produce natural gas and medium-to-heavy
oil. Net production from these oil and gas operations in western Canada averaged 46,000 barrels
per day of liquids and 1,106 million cubic feet per day of natural gas in 2007, compared with
50,000 barrels per day of liquids and 983 million cubic feet per day of natural gas in 2006.
We have a 50 percent operating interest in the Surmont lease, located approximately 35 miles south
of Fort McMurray, Alberta. The Surmont project uses an enhanced thermal oil recovery method called
steam-assisted gravity drainage (SAGD). Steam injection began in the second quarter of 2007, and
first production was achieved in the fourth quarter of 2007. Peak production is expected in 2014.
We anticipate processing our share of the heavy oil produced as a feedstock in our owned and
affiliated U.S. refineries.
In October 2006, we announced a business venture with EnCana Corporation (EnCana), to create an
integrated North American heavy-oil business. The transaction closed on January 3, 2007. The
venture
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We are working with three other energy companies, as members of the Mackenzie Delta Producers
Group, on the development of the Mackenzie Valley pipeline and gathering system, which is proposed
to transport onshore gas production from the Mackenzie Delta in northern Canada to established
markets in North America. We have a 75 percent interest in the Parsons Lake gas field, one of the
primary fields in the Mackenzie Delta that would anchor the pipeline development. This pipeline
project faces significant regulatory and construction cost issues; therefore, no definitive startup
date can be estimated at this time.
We hold exploration acreage in four areas of Canada: the Western Canada Sedimentary Basin, offshore
eastern Canada, the Mackenzie Delta/Beaufort Sea, and the Arctic Islands. Within the Western
Canada Sedimentary Basin, we hold exploration acreage throughout the basin, including the
foothills of western Alberta and eastern British Columbia. In the foothills, we drilled three
exploratory wells in 2007two will be completed as producing wells and one will be tested and
evaluated. During 2007, we also drilled three exploratory wells on acreage in the central Alberta
Nisku project that resulted in one producer, while the remaining wells were expensed as dry holes.
One successful exploration well was drilled in late 2007 on a recently defined Montney gas prospect
in northeast British Columbia. Throughout the rest of western Canada, we participated in drilling
approximately 48 lower risk exploratory wells near our producing assets. In the Mackenzie Delta,
we were successful in acquiring additional offshore acreage following the 2004 Umiak discovery.
Syncrude Canada Ltd.
We own a 9 percent interest in the Syncrude Canada Ltd. (SCL) joint venture, created for the
purpose of mining shallow deposits of oil sands, extracting the bitumen, and upgrading it into a
light sweet crude oil called Syncrude. The primary plant and facilities are located at Mildred
Lake, about 25 miles north of Fort McMurray, Alberta, with an auxiliary mining and extraction
facility approximately 20 miles from the Mildred Lake plant. SCL, as operator of the joint
venture, holds eight oil sands leases and the associated surface rights, of which our share is
approximately 22,400 net acres. Our net share of production averaged 23,400 barrels per day in
2007, compared with 21,100 barrels per day in 2006.
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Petrozuata, Hamaca and Corocoro
On June 26, 2007, we announced we had been unable to reach agreement with respect to our migration
to an
empresa mixta
structure mandated by the Nationalization Decree. In response, Petróleos de
Venezuela S.A. (PDVSA) or its affiliates directly assumed the activities associated with and
control over ConocoPhillips interests in the Petrozuata and Hamaca heavy-oil ventures and the
offshore Corocoro development project.
We have a 40 percent interest in Plataforma Deltana Block 2. The block is operated by our
co-venturer and holds a gas discovery made by PDVSA in 1983. PDVSA has the option to enter the
project with a 35 percent interest, which would proportionately reduce our interest in the project
to 26 percent. In December 2007, the co-venturers presented the notification of commerciality and
submitted a conditional development plan for governmental approval in compliance with license
requirements. Several critical components required to progress an investment decision have not yet
been defined by the government. Assuming timely resolution of these components, we expect a
preliminary engineering study could be completed by late 2008, and a more significant developmental
engineering study could be completed by late 2009.
In Ecuador, we hold a 42.5 percent interest in Block 7 and a 46.25 percent interest in Block 21.
Net production in 2007 averaged 10,300 barrels of crude oil per day, compared with 6,800 barrels
per day in 2006.
We have a 25.7 percent interest in the producing Sierra Chata concession in Argentina. Net
production in 2007 averaged 19 million cubic feet of natural gas per day, compared with 17 million
cubic feet per day in 2006.
We have varying ownership interests in six exploration blocks in Peru. In the first quarter of
2007, we acquired a 100 percent interest in Block 129. In Block 57, we drilled one exploration
well that encountered hydrocarbons.
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We operate seven production sharing contracts (PSCs) in Indonesia. Production from Indonesia in
2007 averaged a net 330 million cubic feet per day of natural gas and 11,800 barrels per day of
oil, compared with 319 million cubic feet per day of natural gas and 12,400 barrels per day of oil
in 2006. Natural gas is sold under long-term contracts benchmarked to crude oil prices to markets
in Indonesia and Singapore. Natural gas is also sold to the Indonesian domestic markets under
U.S.-dollar-denominated, fixed-price contracts. Our assets are concentrated in two core areas: the
West Natuna Sea and onshore South Sumatra.
We operate four offshore PSCs: South Natuna Sea Block B, Ketapang, Amborip VI, and Kuma. We sold
our 25 percent non-operator interest in the Pangkah PSC, offshore East Java, in the third quarter
of 2007.
We operate three onshore PSCs. Two are in South Sumatra: Corridor PSC and South Jambi B
.
We also
operate Warim in Papua. In January 2007, we sold our 50 percent working interest in the Block A
PSC in North Sumatra, and we sold our 60 percent interest in Corridor TAC in September 2007. In
November 2007, the Sakakemang Joint Operating Body expired. We also transferred our non-operator
interest in the Banyumas PSC in Java to our partners effective January 2008.
We are a 35 percent owner of TransAsia Pipeline Company Pvt. Ltd., a consortium company, which has
a 40 percent ownership in PT Transportasi Gas Indonesia, an Indonesian limited liability company,
which owns and operates the Grissik to Duri, and Grissik to Singapore, natural gas pipelines.
In January 2007, we signed a new PSC agreement for a 60 percent interest in the Kuma block, which
is located in Makassar Straits, between the islands of Kalimantan and Sulawesi. The acreage
contains multiple exploration targets. A 3D survey will commence on the Kuma PSC in 2008. In
addition, exploration work will continue on the Amborip VI PSC. Exploration wells are being
planned for drilling in 2009 on both of these PSCs.
Table of Contents
The Xijiang development consists of two fields located approximately 80 miles south of Hong Kong in
the South China Sea. The facilities include two manned platforms and an FPSO vessel. Our combined
net production of crude oil from the Xijiang fields averaged 7,900 barrels per day in 2007,
compared with 10,100 barrels per day in 2006.
Our ownership interest in Vietnam is centered around the Cuu Long Basin in the South China Sea, and
consists of two primarily oil producing blocks, four exploration blocks, and one gas pipeline
transportation system.
We own a 16.3 percent interest in the Nam Con Son natural gas pipeline. This 244-mile
transportation system links gas supplies from the Nam Con Son Basin to gas markets in southern
Vietnam.
A successful appraisal well was drilled during 2007 in the Su Tu Nau field in the northeast area of
Block 15-1. Further appraisal plans and potential development options for this field are currently
being evaluated.
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Bayu-Undan
We operate and hold an ownership interest in the Bayu-Undan field located in the Timor Sea. In
accordance with various governance agreements, a redetermination of the ownership interest in the
Bayu-Undan Joint Venture, Darwin LNG Pty Ltd and the Bayu-Undan Pipeline Joint Venture was
completed in 2007. The redetermination increased our controlling interest from 56.7 percent to
57.15 percent. The Bayu-Undan field was developed in two phases. Phase I was a gas-recycle project, where condensate
and natural gas liquids were separated and removed and the dry gas was re-injected into the
reservoir. This phase began production in February 2004, and averaged a net rate of 34,100 barrels
of liquids per day in 2007, compared with 53,400 barrels per day in 2006.
We have a 30 percent interest in the Greater Sunrise gas and condensate field located in the Timor
Sea. In January 2006, agreement was reached between the
governments of Australia and Timor-Leste
concerning sharing of revenues from the anticipated development of the Greater Sunrise field. In
February 2007, the government of Timor-Leste ratified the International Unitisation Agreement (IUA)
and the governments of Timor-Leste and Australia both ratified the treaty on Certain Maritime
Arrangements in the Timor Sea. The Australian government ratified the IUA in 2004.
A cooperative field development agreement for the Athena/Perseus (WA-17-L) gas field, located
offshore Western Australia, was executed in 2001. In 2007, our net share of production was 34
million cubic feet of natural gas per day, compared with 35 million cubic feet of natural gas per
day in 2006. Early in the third quarter of 2007, abandonment of the Elang/Kakatua/Kakatua North
fields commenced and production ceased.
We are the operator of the NT/P 69 and the NT/P 61 licenses, located offshore Northern Territory,
Australia, which include the Caldita and Barossa discoveries. A Caldita appraisal well drilled in
early 2007 encountered hydrocarbons, but it was expensed as a dry hole. Acquisition of seismic
data concluded in 2007, and interpretation of this data will begin in 2008 to further evaluate
these discoveries.
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Exploration
We have interests in deepwater Blocks G and J, located off the east Malaysian state of Sabah. In
late 2007, we and our co-venturers sanctioned the Gumusut-Kakap field development that incorporates
the 2003 Gumusut discovery in Block J. Also in 2007, we participated in two exploration wells. We
had a discovery in the Petai field in Block G. Petai and previous Block G discoveries are being
evaluated as part of a broader area development plan. One Block J well was expensed as a dry hole.
Qatargas 3 is an integrated project, jointly owned by Qatar Petroleum (68.5 percent),
ConocoPhillips (30 percent) and Mitsui & Co., Ltd. (1.5 percent). The project comprises upstream
natural gas production facilities to produce approximately 1.4 billion gross cubic feet per day of
natural gas from Qatars North field over the 25-year life of the project. The project also
includes a 7.8-million-gross-ton-per-year LNG facility. The LNG will be shipped from Qatar in a
fleet of LNG vessels, and is destined for sale primarily in the United States. The first LNG
cargos are expected to be loaded from Qatargas 3 in 2009.
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Our oil concession offshore Dubai ended effective April 2007.
We have interests in three fields in Block 405a: a 65 percent operating interest in the Menzel
Lejmat North (MLN) field; a 3.73 percent interest in the Ourhoud field; and a 16.9 percent interest
in the EMK (El Merk) oil field unit. Net production from these fields averaged 10,800 barrels of
crude oil per day in 2007, compared with 9,800 barrels per day in 2006.
ConocoPhillips holds a 16.33 percent interest in the Waha concessions in Libya. The concessions
encompass nearly 13 million acres located in the Sirte Basin. Net crude oil production averaged
46,900 barrels per day in 2007, compared with 50,400 barrels per day in 2006, including 3,800
barrels per day associated with the complete recovery of our 1986 underlift position.
During the first quarter of 2007, we sold our 50 percent non-operated interest in a concession in
Egypt that included the development of the Tao gas field and its associated facilities.
At year-end 2007, we were producing from four onshore Oil Mining Leases (OMLs), in which we have a
20 percent non-operator interest. Our net production from these leases was 19,300 barrels of
liquids per day and 117 million cubic feet of natural gas per day in 2007, compared with 24,500
barrels per day and 138 million cubic feet per day in 2006. In 2007, we continued development of
projects in the onshore OMLs to supply feedstock natural gas under a gas sales contract with
Nigeria LNG Limited, which owns an LNG facility on Bonny Island.
During 2007, we made an onshore exploration discovery in OML 61, and the well is now producing.
During the fourth quarter of 2007, we initiated drilling of an appraisal well in deepwater Oil
Prospecting License (OPL) 214. The well encountered hydrocarbons, and drilling operations
concluded in the first quarter of 2008. In the first quarter of 2007, we recorded a leasehold
impairment related to OPL 248. In the second quarter of 2007, we relinquished our interest in OPL
318.
Polar Lights
We have a 50 percent equity ownership interest in Polar Lights Company, a Russian limited liability
company established in January 1992 to develop fields in the Timan-Pechora Basin in northern
Russia.
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In June 2005, ConocoPhillips and LUKOIL created the OOO Naryanmarneftegaz (NMNG) joint venture to
develop resources in the northern part of Russias Timan-Pechora province. We have a 30 percent
ownership interest with a 50 percent governance interest in NMNG. We use the equity method of
accounting for this joint venture. NMNG is working to develop the Yuzhno Khylchuyu (YK) field.
In the Caspian Sea, we have a 9.26 percent interest in the Republic of Kazakhstans North Caspian
Sea Production Sharing Agreement (NCSPSA), which includes the Kashagan field. Detailed design,
procurement and construction activities continued on the Kashagan oil field development following
approval by the Republic of Kazakhstan for the development plan and budget in 2004. The first
phase of field development currently being executed includes the construction of artificial
drilling islands with processing facilities and living quarters, and pipelines to carry production
onshore. The initial production phase of the contract is for 20 years, with options to extend the
agreement an additional 20 years. During 2007, the Republic of Kazakhstan triggered dispute
proceedings under the NCSPSA following submission of a revised development plan and budget
reflecting Kashagan cost increases and schedule delays. The international co-venturers signed a
Memorandum of Understanding in January 2008, agreeing to the proportional dilution of their equity
interest to allow the state-owned energy company, JSC NC KazMunaiGaz, to increase its ownership
interest from 8.33 percent to 16.81 percent, effective January 1, 2008, subject to the completion
of definitive agreements on dilution and other matters. As a result, our interest in the NCSPSA
would be reduced from 9.26 percent to 8.40 percent, effective January 2008. In addition, a joint
operating company, with significant involvement from the larger owners, will operate future phases
of Kashagan. First production is expected at the end of 2011.
We have a 2.5 percent interest in the Baku-Tbilisi-Ceyhan (BTC) pipeline. This 1,760-kilometer
pipeline transports crude oil from the Caspian region through Azerbaijan, Georgia and Turkey, for
tanker loadings at the Mediterranean port of Ceyhan. The BTC pipeline became operational in
mid-2006.
In 2007, appraisal and development concept studies continued for Kalamkas More, Kairan and Aktote.
Testing operations on a Kairan appraisal well drilled in 2006 were successfully completed. Concept
studies for development are under way for all three fields.
In late 2003, we signed an agreement with Freeport LNG Development, L.P. (Freeport LNG) to
participate in its proposed LNG receiving terminal in Quintana, Texas. This agreement gave us 1
billion cubic feet per day of regasification capacity in the terminal and a 50 percent interest in
the general partnership managing the venture. The terminal is designed to have capacity of 1.5
billion cubic feet per day. Freeport LNG received final approval in 2005 from the Federal Energy
Regulatory Commission (FERC) to construct and operate the facility. Construction began in 2005,
and commercial startup is expected in
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The Commercial organization optimizes the commodity flows of our E&P segment. This group markets
our crude oil and natural gas production, with commodity buyers, traders and marketers in offices
in the United States, the United Kingdom, Singapore, Canada and Dubai.
Compared with the more global nature of crude oil commodity pricing, natural gas prices have
historically varied more in different regions of the world. We produce natural gas from regions
around the world that have significantly different supply, demand and regulatory circumstances,
typically resulting in significantly lower average sales prices than in the Lower 48 region of the
United States. Moreover, excess supply conditions that exist in certain parts of the world cannot
easily serve to mitigate the relatively high-price conditions in the Lower 48 states and other
markets because of a lack of infrastructure and because of the difficulties in transporting natural
gas. We, along with other companies in the oil and gas industry, are planning long-term projects
in regions of excess supply to install the infrastructure required to produce and liquefy natural
gas for transportation by tanker and subsequent regasification in regions where market demand is
strong, such as the Lower 48 states or certain parts of Asia, but where supplies are not as
plentiful. Due to the significance of the overall investment in these long-term projects, the
natural gas sales prices (to a third-party LNG facility) or transfer prices (to a company-owned LNG
facility) in the areas of excess supply are expected to remain well below sales prices for natural
gas that is produced closer to areas of high demand and which can be transferred to existing
natural gas pipeline networks, such as in the Lower 48 states.
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A 50 percent interest in a natural gas liquids extraction plant in San Juan County, New
Mexico. Our net share of plant inlet capacity is 275 million cubic feet per day.
Effective January 1, 2008, our interest in this plant was moved to the E&P segment for
reporting purposes.
A 25,000-barrel-per-day capacity natural gas liquids fractionation plant in Gallup, New
Mexico.
A 22.5 percent equity interest in Gulf Coast Fractionators, which owns a natural gas
liquids fractionation plant in Mont Belvieu, Texas (with our net share of capacity at 25,000 barrels
per day).
A 40 percent interest in a fractionation plant in Conway, Kansas (with our net share of
capacity at 42,000 barrels per day).
A 12.5 percent equity interest in a fractionation plant in Mont Belvieu, Texas (with our
net share of capacity at 26,000 barrels per day).
Table of Contents
Net Crude Throughput
Capacity (MB/D)
At
Effective
December 31
January 1
Refinery
Location
Region
2007
2008
Linden
New Jersey
East Coast
238
238
Trainer
Pennsylvania
East Coast
185
185
423
423
Belle Chasse
Louisiana
Gulf Coast
247
247
Westlake
Louisiana
Gulf Coast
239
239
Old Ocean
Texas
Gulf Coast
247
247
733
733
Roxana
Illinois
Central
153
153
Borger
Texas
Central
124
95
*
Ponca City
Oklahoma
Central
187
187
464
435
Billings
Montana
West Coast
58
58
Ferndale
Washington
West Coast
100
100
Carson/Wilmington
California
West Coast
139
139
Arroyo Grande/
California
West Coast
120
120
San Francisco
417
417
2,037
2,008
*
Amount reflects our 65 percent share of the Borger refinery effective January 1, 2008. We had an 85 percent share of the Borger refinery
in 2007.
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Bayway Refinery
The Bayway refinery is located on the New York Harbor in Linden, New Jersey. The refinery has a
crude oil processing capacity of 238,000 barrels per day, and processes mainly light, low-sulfur
crude oil. Crude oil is supplied to the refinery by tanker, primarily from the North Sea, Canada
and West Africa. The refinery produces a high percentage of transportation fuels, such as
gasoline, ultra-low-sulfur diesel and jet fuel. Other products include petrochemical feedstocks,
home heating oil and residual fuel oil. The facility distributes its refined products to East
Coast customers by pipeline, barge, railcar and truck. The complex also includes a
775-million-pound-per-year polypropylene plant.
The Trainer refinery is located on the Delaware River in Trainer, Pennsylvania. The refinery has a
crude oil processing capacity of 185,000 barrels per day, and processes mainly light, low-sulfur
crude oil. The Bayway and Trainer refineries are operated in coordination with each other by
sharing crude oil cargoes and often moving feedstocks between the facilities. Trainer receives a
majority of its crude oil by tanker from West Africa, Canada and the North Sea. The refinery
produces a high percentage of transportation fuels, such as gasoline, diesel and jet fuel. Other
products include home heating oil, residual fuel oil and liquefied petroleum gas. Refined products
are primarily distributed to customers in Pennsylvania, New York and New Jersey by pipeline, barge,
railcar and truck.
Alliance Refinery
The Alliance refinery is located on the Mississippi River in Belle Chasse, Louisiana. The refinery
has a crude oil processing capacity of 247,000 barrels per day, and processes mainly light,
low-sulfur crude oil. Alliance receives domestic crude oil from the Gulf of Mexico via pipeline,
and foreign crude oil from the North Sea and West Africa via pipeline connected to the Louisiana
Offshore Oil Port. The refinery produces a high percentage of transportation fuels, such as
gasoline, diesel and jet fuel. Other products include home heating oil, petrochemical feedstocks
and anode petroleum coke. The majority of the refined products are distributed to customers in the
southeastern and eastern United States through major common-carrier pipeline systems and by barge.
The Lake Charles refinery is located in Westlake, Louisiana. The refinery has a crude oil
processing capacity of 239,000 barrels per day, and processes mainly heavy, high-sulfur crude oil,
but also processes low-sulfur and acidic crude oil. The refinery receives domestic and foreign
crude oil, with a majority of its foreign crude oil being heavy Venezuelan and Mexican crude oil,
both delivered via tanker. The refinery produces a high percentage of transportation fuels, such
as gasoline, off-road diesel and jet fuel, along with home heating oil. The majority of its
refined products are distributed to customers by truck, railcar, barge or major common-carrier
pipelines to customers in the southeastern and eastern United States. In addition, refined
products can be sold into export markets through the refinerys marine terminal.
The Sweeny refinery is located in Old Ocean, Texas. The refinery has a crude oil processing
capacity of 247,000 barrels per day. The refinery processes both heavy, high-sulfur crude oil, the
majority of which is sourced from Venezuela, and light, low-sulfur crude oil. The refinery
primarily receives crude oil via tankers through its 100-percent-owned and jointly owned terminals
on the Gulf Coast, including a deepwater terminal at Freeport, Texas. The refinery produces a high
percentage of transportation fuels, such as gasoline, diesel and jet fuel. Other products include
home heating oil, petrochemical feedstocks
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EnCana Joint Venture
In October 2006, we announced a business venture with EnCana Corporation (EnCana), to create an
integrated North American heavy-oil business. The transaction closed on January 3, 2007. The
venture consists of two 50/50 business ventures, a Canadian upstream general partnership, FCCL Oil
Sands Partnership, and a U.S. downstream limited liability company, WRB Refining LLC (WRB). We use
the equity method of accounting for our investments in both entities.
The Wood River refinery is located on the east side of the Mississippi River in Roxana, Illinois.
It has a crude oil processing capacity of 306,000 barrels per day, and our net share of this
capacity at December 31, 2007, was 153,000 barrels per day. The refinery processes a mix of both
light, low-sulfur and heavy, high-sulfur crude oil. The refinery receives domestic and foreign
crude oil by various pipelines. The refinery produces a high percentage of transportation fuels,
such as gasoline, diesel and jet fuel. Other products include petrochemical feedstocks and
asphalt. Through an off-take agreement, a significant portion of its gasoline and diesel is sold
to a third party for delivery via pipelines into the upper Midwest, including the Chicago,
Illinois, and Milwaukee, Wisconsin, metropolitan areas. The remaining refined products are
distributed to customers in the Midwest by pipeline, truck, barge and railcar.
The Borger refinery is located in Borger, Texas, and the complex includes a natural gas liquids
fractionation facility. The crude oil processing capacity of the refinery is 146,000 barrels per
day, and the natural gas liquids fractionation capacity is 45,000 barrels per day. Our net share
of the crude oil capacity at December 31, 2007, was 124,000 barrels per day. The refinery
processes mainly light, high-sulfur and medium, high-sulfur crude oil. It receives crude oil and
natural gas liquids feedstocks through pipelines from West Texas, the Texas Panhandle and Wyoming.
The Borger refinery also receives foreign crude oil via pipeline. The refinery produces a high
percentage of transportation fuels, such as gasoline, diesel and jet fuel, along with a variety of
natural gas liquids and solvents. Refined products are transported via pipelines from the refinery
to West Texas, New Mexico, Colorado, and the Midcontinent region.
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The Ponca City refinery is located in Ponca City, Oklahoma. The refinery has a crude oil
processing capacity of 187,000 barrels per day. The refinery processes a mixture of light, medium
and heavy crude oil. Most of the crude processed is received by pipeline from the Gulf of Mexico,
Oklahoma, Kansas, Texas and Canada. The refinery produces high ratios of low-sulfur gasoline and
ultra-low-sulfur diesel fuel from crude oil. Finished petroleum products are primarily shipped by
company-owned and common carrier pipelines to markets throughout the Midcontinent region.
Billings Refinery
The Billings refinery is located in Billings, Montana. The refinery has a crude oil processing
capacity of 58,000 barrels per day, and processes a mixture of Canadian heavy, high-sulfur crude
oil, plus domestic high-sulfur and low-sulfur crude oil, all delivered by pipeline. A delayed
coker converts heavy, high-sulfur residue into higher value light oils. The refinery produces a
high percentage of transportation fuels, such as gasoline, diesel and aviation fuels, as well as
fuel-grade petroleum coke. Finished petroleum products from the refinery are delivered by
pipeline, railcar and truck. Pipelines transport most of the refined products to markets in
Montana, Wyoming, Utah and Washington.
The Ferndale refinery is located on Puget Sound in Ferndale, Washington. During 2007, the refinery
completed a project to expand the crude unit capacity by replacing piping and modifying various
equipment. This project increased capacity by 4,000 barrels per day to 100,000 barrels per day,
effective July 1, 2007. The refinery primarily receives light, low-sulfur crude oil from the
Alaskan North Slope, as well as crude oil from Canada. The refinery produces transportation fuels
such as gasoline and diesel. Other products include residual fuel oil supplying the northwest
marine transportation market. Most refined products are distributed by pipeline and barge to major
markets in the northwest United States.
The Los Angeles refinery is composed of two linked facilities located about five miles apart in
Carson and Wilmington, California. Carson serves as the front-end of the refinery by processing
crude oil, and Wilmington serves as the back-end by upgrading products. The refinery has a crude
oil processing capacity of 139,000 barrels per day, and processes mainly heavy, high-sulfur crude
oil. The refinery receives domestic crude oil via pipeline from California, and both foreign and
domestic crude oil by tanker through a third-party terminal in the Port of Long Beach. The
refinery produces a high percentage of transportation fuels, such as gasoline, diesel and jet fuel.
Other products include fuel-grade petroleum coke. The refinery produces California Air Resources
Board (CARB) gasoline by blending ethanol to meet government-mandated oxygenate requirements.
Refined products are distributed to customers in Southern California, Nevada and Arizona by
pipeline and truck.
The San Francisco refinery is composed of two linked facilities located about 200 miles apart. The
Santa Maria facility is located in Arroyo Grande, California, about 200 miles south of San
Francisco, while the Rodeo facility is in the San Francisco Bay area. The refinery has a crude oil
processing capacity of 120,000 barrels per day. The refinery processes mainly heavy, high-sulfur
crude oil, which is received by pipeline in California and by tanker from foreign and domestic
sources. Semi-refined liquid products from the Santa Maria facility are sent by pipeline to the
Rodeo facility for upgrading into finished petroleum
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In our wholesale operations, we utilize a network of marketers and dealers operating approximately
7,750 outlets that provide refined product off-take from our operated refineries. A strong
emphasis is placed on the wholesale channel of trade because of its lower capital requirements. We
also buy and sell petroleum products in the spot market. Our refined products are marketed on both
a branded and unbranded basis.
In our retail operations, we own and operate 330 sites under the Phillips 66, Conoco and 76 brands.
Company-operated retail operations are focused in 10 states, mainly in the Midcontinent, Rocky
Mountain and West Coast regions. Most of these outlets market merchandise through the Kicks,
Breakplace or Circle K brand convenience stores.
At December 31, 2007, we had approximately 28,000 miles of common-carrier crude oil, raw natural
gas liquids, and petroleum products pipeline systems in the United States, including those
partially owned and/or operated by affiliates. We also owned and/or operated 51 finished product
terminals, seven liquefied petroleum gas terminals, five crude oil terminals and one coke exporting
facility.
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At December 31, 2007, we had under charter 18 double-hulled crude oil tankers, with capacities
ranging in size from 650,000 to 1,100,000 barrels. These tankers are utilized to transport
feedstocks to certain of our U.S. refineries. The information above excludes the operations of the
companys subsidiary, Polar Tankers, Inc., which is discussed in the E&P segment overview, as well
as an owned tanker on lease to a third party for use in the North Sea.
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Net Crude Throughput
Capacity (MB/D)
At
Effective
Ownership
December 31
January 1
Refinery
Location
Interest
2007
2008
N. Lincolnshire
United Kingdom
100.00
%
221
221
Cork
Ireland
100.00
71
71
Wilhelmshaven
Germany
100.00
260
260
Karlsruhe
Germany
18.75
57
58
Melaka
Malaysia
47.00
60
60
669
670
The Humber refinery is located in North Lincolnshire, United Kingdom. The refinerys crude oil
processing capacity is 221,000 barrels per day. Crude oil processed at the refinery is supplied
primarily from the North Sea and includes light, low-sulfur and acidic crude oil. The refinery
also processes intermediate feedstocks, mostly vacuum gas oils and residual fuel oil.
The Whitegate refinery in Cork, Ireland, has a crude oil processing capacity of 71,000 barrels per
day. Crude oil processed by the refinery is light, low-sulfur crude oil sourced mostly from the
North Sea. The refinery primarily produces transportation fuels, such as gasoline, diesel and fuel
oil, which are distributed to the inland market, as well as being exported to Europe and the United
States. We also operate a crude oil and products storage complex consisting of 7.5 million barrels
of storage capacity and an offshore mooring buoy, located in Bantry Bay, about 80 miles southwest
of the Whitegate refinery in southern Cork County.
The Wilhelmshaven refinery is located in the northern state of Lower Saxony in Germany, and has a
crude oil processing capacity of 260,000 barrels per day. Crude oil processed by the refinery is
low-sulfur sourced mostly from the North Sea. The Wilhelmshaven refinery mainly produces
transportation fuels, fuel oil, and intermediate feedstocks, which are primarily exported to Europe
and the United States, but are also distributed to the inland market via truck and rail.
Additionally, we operate a marine terminal, rail and truck loading facilities and a tank farm. We
have evaluated alternatives to economically improve the operation of the refinery and have
incorporated a deep conversion plan into our capital budget.
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The Mineraloel Raffinerie Oberrhein GmbH (MiRO) refinery in Karlsruhe, Germany, is a joint-venture
refinery with a crude oil processing capacity of 307,000 barrels per day. Effective January 1,
2008, the refinerys capacity was increased by 5,000 barrels per day due to incremental
debottlenecking, with our share being an increase of 1,000 barrels per day. We have an 18.75
percent interest in MiRO, giving us a net capacity share of 58,000 barrels per day. The refinerys
crude oil feedstock includes medium-sulfur crude oil. The MiRO complex is a fully integrated
refinery producing gasoline, middle distillates and specialty products, along with a small amount
of residual fuel oil. The refinery has a high capacity to convert lower-cost feedstocks into
higher-value products, primarily with a fluid catalytic cracker and a delayed coker. The refinery
also produces fuel-grade and specialty calcined cokes. The refinery processes crude and other
feedstocks supplied by each of the co-venturers in proportion to their respective ownership
interests. The majority of refined products are distributed by truck and railcar to Germany and
neighboring markets.
The refinery in Melaka, Malaysia, is a joint-venture refinery in which we own a 47 percent
interest. The refinery has a rated crude oil processing capacity of 128,000 barrels per day, of
which our share is 60,000 barrels per day. The medium, high-sulfur crude oil processed by the
refinery is sourced mostly from the Middle East. The refinery produces a full range of refined
petroleum products. The refinery capitalizes on our proprietary coking technology to upgrade
low-cost feedstocks to higher-margin products. Our share of refined products is transported by
tanker and marketed in Malaysia and other Asian markets.
In May 2006, we signed a Memorandum of Understanding with Saudi Aramco to conduct a detailed
evaluation of the proposed development of a 400,000-barrel-per-day, full-conversion refinery in
Yanbu, Saudi Arabia. The refinery would be designed to process Arabian heavy crude oil and produce
high-quality, ultra-low-sulfur refined products. A joint ConocoPhillips and Saudi Aramco project
team has initiated work on the front-end engineering design study. This study, as well as an
evaluation of project financing and negotiations of key commercial agreements, is scheduled to be
completed later in 2008.
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The focus of our power business is on developing integrated projects to support the companys E&P
and R&M strategies and business objectives. The projects that are primarily in place to enable
these strategies are included within their respective E&P and R&M segments. The power projects and
assets that have a significant merchant component are included in the Emerging Businesses segment.
We are expanding our efforts to develop carbon-to-liquids technology focused on coal and petroleum
coke.
Alternative Energy and Technology Programs focuses on developing new business opportunities
designed to provide growth options for ConocoPhillips well into the future. Example areas of
interest include advanced hydrocarbon processes, energy conversion technologies, new
petroleum-based products, and renewable fuels. ConocoPhillips is interested in the production of
biofuels. We have recently commercialized the production of renewable diesel, a new type of
renewable fuel that utilizes existing infrastructure. In 2007, we formed a research relationship
with Iowa State University to develop new methods for producing second-generation biofuels. We
also formed alliances with Tyson Foods and Archer Daniels Midland to produce and market the next
generation of renewable transportation fuels.
We offer a gasification technology (E-Gas
TM
) that uses petroleum coke, coal, and other
low-value hydrocarbons as feedstock, resulting in high-value synthetic gas used for a slate of
products, including power, hydrogen and chemicals.
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Worldwide and domestic supplies of, and demand for, crude oil, natural gas, natural gas
liquids and refined products.
The cost of exploring for, developing, producing, refining and marketing crude oil,
natural gas, natural gas liquids and refined products.
Changes in weather patterns and climatic changes.
The ability of the members of OPEC and other producing nations to agree to and maintain
production levels.
The worldwide military and political environment, uncertainty or instability resulting
from an escalation or additional outbreak of armed hostilities or further acts of terrorism
in the United States, or elsewhere.
The price and availability of alternative and competing fuels.
Domestic and foreign governmental regulations and taxes.
Additional or increased nationalization and expropriation activities by foreign
governments.
General economic conditions worldwide.
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Historical production from the area, compared with production from other comparable
producing areas.
The assumed effects of regulations by governmental agencies.
Assumptions concerning future crude oil and natural gas prices.
Assumptions concerning future operating costs, severance and excise taxes, development
costs and workover and remedial costs.
The amount and timing of crude oil and natural gas production.
The revenues and costs associated with that production.
The amount and timing of future development expenditures.
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Obtaining rights to explore, develop and produce crude oil and natural gas in promising
areas.
Drilling success.
The ability to complete long lead-time, capital-intensive projects timely and on budget.
Efficient and profitable operation of mature properties.
The discharge of pollutants into the environment.
Emissions into the atmosphere (such as nitrogen oxides, sulfur dioxide and mercury
emissions in the United States, or potential future control of greenhouse gas emissions).
The handling, use, storage, transportation, disposal and clean up of hazardous materials
and hazardous and non-hazardous wastes.
The dismantlement, abandonment and restoration of our properties and facilities at the
end of their useful lives.
Modify operations.
Install pollution control equipment.
Perform site cleanups.
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Curtail operations.
Acquire additional non-petroleum feedstocks or compliance credits to comply with laws
mandating specified percentages of biofuels in our refined products.
We may become subject to liabilities we currently do not anticipate in connection with new, amended
or more stringent requirements, stricter interpretations of existing requirements or the future
discovery of contamination. In addition, any failure by us to comply with existing or future laws
could result in civil or criminal fines and other enforcement actions against us.
Our, and our predecessors, operations also could expose us to civil claims by third parties for
alleged liability resulting from contamination of the environment or personal injuries caused by
releases of hazardous substances.
Environmental laws are subject to frequent change and many of them have become more stringent. In
some cases, they can impose liability for the entire cost of cleanup on any responsible party,
without regard to negligence or fault, and impose liability on us for the conduct of others or
conditions others have caused, or for our acts that complied with all applicable requirements when
we performed them.
Please read Managements Discussion and Analysis of Financial Condition and Results of
OperationsContingenciesEnvironmental in Item 7 of this annual report for further information
about environmental laws and regulations impacting our business.
Worldwide political and economic developments could damage our operations and materially reduce our
profitability and cash flows.
Local political and economic factors in international markets could have a material adverse effect
on us. Approximately 63 percent of our crude oil, natural gas and natural gas liquids production
in 2007 was derived from production outside the United States, and 59 percent of our proved
reserves, as of December 31, 2007, were located outside the United States.
There are many risks associated with operations in international markets, including changes in
foreign governmental policies relating to crude oil, natural gas, natural gas liquids or refined
product pricing and taxation, other political, economic or diplomatic developments, changing
political conditions and international monetary fluctuations. These risks include, among others:
Political and economic instability, war, acts of terrorism and civil disturbances.
The possibility that a foreign government may seize our property, with or without
compensation, may attempt to renegotiate or revoke existing contractual arrangements and
concessions, or may impose additional taxes or royalties.
Fluctuating currency values, hard currency shortages and currency controls.
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The South Coast Air Quality Management District (SCAQMD) conducted an audit of the Los Angeles
refinery to assess compliance with applicable local, state, and federal regulations related to
fugitive emissions. As a result of the audit, SCAQMD issued three Notices of Violations (NOVs)
alleging multiple counts of non-compliance. SCAQMD has not yet specified a penalty for these
alleged violations. We are currently assessing these allegations and expect to work with SCAQMD
toward a resolution of these NOVs.
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Name
Position Held
Age*
Vice President and Controller
52
Executive Vice President, Finance, and Chief Financial Officer
56
Senior Vice President, Planning, Strategy and Corporate Affairs
52
Executive Vice President, Refining, Marketing and Transportation
55
Senior Vice President, Legal, General Counsel and Corporate Secretary
50
Executive Vice President, Exploration and Production
49
Chairman of the Board of Directors, President and Chief Executive Officer
61
*
On March 1, 2008.
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45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65
66
67
68
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70
71
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88
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94
95
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97
98
99
100
101
102
103
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107
108
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110
111
112
113
114
115
116
117
118
119
120
121
122
123
124
125
126
127
128
129
130
131
132
133
134
135
136
137
138
139
140
141
142
143
144
145
146
147
148
149
150
151
152
153
154
155
156
157
158
159
160
161
162
163
164
165
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172
173
174
175
176
177
178
179
180
181
182
183
184
185
186
187
188
189
190
191
192
193
194
195
196
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199
200
201
202
203
204
Item 5.
MARKET FOR REGISTRANTS COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF
EQUITY SECURITIES
Stock Price
High
Low
Dividends
$
71.50
61.59
.41
81.40
66.24
.41
90.84
73.75
.41
89.89
74.18
.41
$
66.25
58.01
.36
72.50
57.66
.36
70.75
56.55
.36
74.89
54.90
.36
$
88.30
$
80.11
64,486
*
In determining the number of stockholders, we consider clearing
agencies and security position listings as one stockholder for each
agency or listing.
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Millions of Dollars
Total Number of
Approximate Dollar
Shares Purchased
Value of Shares
Average Price Paid
as Part of Publicly
that May Yet Be
Total Number of
per Total Shares
Announced Plans
Purchased Under the
Period
Shares Purchased
*
Purchased
or Programs
**
Plans or Programs
8,524,207
$85.01
8,519,500
$11,873
11,099,198
80.92
11,098,236
10,975
10,640,304
82.57
10,629,568
10,097
30,263,709
$82.65
30,247,304
*
Includes the repurchase of common shares from company employees in connection with the
companys broad-based employee incentive plans.
**
On January 12, 2007, we announced a stock repurchase program that provided for the repurchase
of up to $1 billion of the companys common stock. On February 9, 2007, we announced plans to
repurchase $4 billion of our common stock in 2007, including the $1 billion announced on
January 12, 2007. On July 9, 2007, we announced plans to repurchase up to $15 billion of the
companys common stock through the end of 2008, which included the $2 billion remaining under
the previously announced $4 billion program. Acquisitions for the share repurchase programs
are made at managements discretion, at prevailing prices, subject to market conditions and
other factors. Repurchases may be increased, decreased or discontinued at any time without
prior notice. Shares of stock repurchased under the plans are held as treasury shares.
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Millions of Dollars Except Per Share Amounts
2007
2006
2005
2004
2003
$
187,437
183,650
179,442
135,076
104,246
11,891
15,550
13,640
8,107
4,593
7.32
9.80
9.79
5.87
3.37
7.22
9.66
9.63
5.79
3.35
11,891
15,550
13,529
8,129
4,735
7.32
9.80
9.71
5.88
3.48
7.22
9.66
9.55
5.80
3.45
177,757
164,781
106,999
92,861
82,455
20,289
23,091
10,758
14,370
16,340
6,294
-
-
-
-
-
-
-
-
141
1.64
1.44
1.18
.895
.815
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Item 7.
MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Exploration and Production (E&P)
This segment primarily explores for, produces,
transports and markets crude oil, natural gas, and natural gas liquids on a worldwide
basis.
Midstream
This segment gathers, processes and markets natural gas produced by
ConocoPhillips and others, and fractionates and markets natural gas liquids, primarily in
the United States and Trinidad. The Midstream segment primarily consists of our 50 percent
equity investment in DCP Midstream, LLC.
Refining and Marketing (R&M)
This segment purchases, refines, markets and
transports crude oil and petroleum products, mainly in the United States, Europe and Asia.
LUKOIL Investment
This segment consists of our equity investment in the
ordinary shares of OAO LUKOIL (LUKOIL), an international, integrated oil and gas company
headquartered in Russia. At December 31, 2007, our ownership interest was 20 percent based
on issued shares, and 20.6 percent based on estimated shares outstanding.
Chemicals
This segment manufactures and markets petrochemicals and plastics on
a worldwide basis. The Chemicals segment consists of our 50 percent equity investment in
Chevron Phillips Chemical Company LLC (CPChem).
Emerging Businesses
This segment represents our investment in new technologies
or businesses outside our normal scope of operations.
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Operating our producing properties and refining and marketing operations safely,
consistently and in an environmentally sound manner.
Safety is our first priority and
we are committed to protecting the health and safety of everyone who has a role in our
operations and the communities in which we operate. Maintaining high utilization rates at
our refineries and minimizing downtime in producing fields enable us to capture the value
available in the market in terms of prices and margins. During 2007, our worldwide
refinery capacity utilization rate was 94 percent, compared with 92 percent in 2006. The
improved utilization rate reflects less scheduled downtime and unplanned weather-related
downtime. Concerning the environment, we strive to conduct our operations in a manner
consistent with our environmental stewardship principles.
Adding to our proved reserve base.
We primarily add to our proved reserve base
in three ways:
o
Successful exploration and development of new fields.
o
Acquisition of existing fields.
o
Applying new technologies and processes to improve recovery from existing fields.
Through a combination of all three methods listed above, we have been successful in the past
in maintaining or adding to our production and proved reserve base. Although it cannot be
assured, we anticipate being able to do so in the future. The acquisition of Burlington
Resources in March 2006 added approximately 2 billion barrels of oil equivalent to our
proved reserves, and through our investments in LUKOIL during 2004, 2005 and 2006, we added
about 1.9 billion barrels of oil equivalent. On January 3, 2007, we closed on a business
venture with EnCana Corporation (EnCana). As part of this transaction, we added
approximately 400 million barrels of oil equivalent to our proved reserves in 2007. In the
three years ending December 31, 2007, our reserve replacement was 186 percent, including the
impact of the Burlington Resources acquisition, our additional equity investment in LUKOIL,
the EnCana business venture, and the expropriation of our Venezuelan oil assets.
Access to additional resources has become increasingly difficult as direct investment is
prohibited in some nations, while fiscal and other terms in other countries can make
projects uneconomic or unattractive. In addition, political instability, competition from
national oil companies, and lack of access to high-potential areas due to environmental or
other regulation may negatively impact our ability to increase our reserve base. As such,
the timing and level at which we add to our reserve base may, or may not, allow us to
replace our production over subsequent years.
Controlling costs and expenses.
Since we cannot control the prices of the
commodity products we sell, controlling operating and overhead costs and prudently managing
our capital program, within the context of our commitment to safety and environmental
stewardship, are high priorities. We monitor these costs using various methodologies that
are reported to senior management monthly, on both an absolute-dollar basis and a per-unit
basis. Because managing operating and overhead costs are critical to maintaining
competitive positions in our industries, cost control is a component of our variable
compensation programs.
With the rise in commodity prices over the last several years, and the subsequent increase
in industry-wide spending on capital and major maintenance programs, we and other energy
companies are experiencing inflation for the costs of certain goods and services in excess
of general worldwide inflationary trends. Such costs include rates for drilling rigs, steel
and other
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raw materials, as well as costs for skilled labor. While we work to manage the effect these
inflationary pressures have on our costs, our capital program has been impacted by these
factors. The continued weakening of the U.S. dollar has also contributed to higher costs.
Our capital program may be further impacted by these factors going forward.
Selecting the appropriate projects in which to invest our capital dollars.
We
participate in capital-intensive industries. As a result, we must often invest significant
capital dollars to explore for new oil and gas fields, develop newly discovered fields,
maintain existing fields, or continue to maintain and improve our refinery complexes. We
invest in those projects that are expected to provide an adequate financial return on
invested dollars. However, there are often long lead times from the time we make an
investment to the time that investment is operational and begins generating financial
returns.
In January 2007, we entered into two 50/50 business ventures with EnCana to create an
integrated North American heavy-oil business, consisting of a Canadian upstream general
partnership, FCCL Oil Sands Partnership (FCCL), and a U.S. downstream limited liability
company, WRB Refining LLC (WRB). We are obligated to contribute $7.5 billion, plus accrued
interest, to FCCL over a 10-year period beginning in 2007. EnCana is obligated to
contribute $7.5 billion, plus accrued interest, to WRB over a 10-year period beginning in
2007.
Our capital expenditures and investments in 2007 totaled $11.8 billion, and we anticipate
capital expenditures and investments to be approximately $14.3 billion in 2008. In addition
to our capital program, we increased shareholder distributions in 2007 through a combination
of increased dividends and share repurchases. Our cash dividends totaled $1.64 per share in
2007, an increase of 14 percent over $1.44 per share in 2006. We repurchased $7 billion of
our common stock in 2007 and have $10 billion of share repurchase authority remaining
through 2008.
Managing our asset portfolio.
We continue to evaluate opportunities to acquire
assets that will contribute to future growth at competitive prices. We also continually
assess our assets to determine if any no longer fit our strategic plans and should be sold
or otherwise disposed. This management of our asset portfolio is important to ensuring our
long-term growth and maintaining adequate financial returns. During 2006, we increased our
investment in LUKOIL, ending the year with a 20 percent ownership interest based on issued
shares. During 2006, we completed the $33.9 billion acquisition of Burlington Resources.
Also during 2006, we announced the commencement of an asset rationalization program to
evaluate our asset base to identify those assets that may no longer fit into our strategic
plans or those that could bring more value by being monetized in the near term. This
program generated proceeds of approximately $3.8 billion through December 31, 2007. In
2008, we expect to complete the disposition of our retail assets in the United States,
Norway, Sweden and Denmark. We will evaluate additional opportunities to optimize and
strengthen our asset portfolio as the year progresses.
Hiring, developing and retaining a talented work force.
We strive to attract,
train, develop and retain individuals with the knowledge and skills to implement our
business strategy and who support our values and ethics. In 2007, we hired approximately
2,900 new employees around the world, including university hires as well as experienced
hires. Throughout the company, we focus on the continued learning, development and
technical training of our employees. Professional new hires participate in structured
development programs designed to accelerate their technical and functional skills. The
ongoing hiring and training of employees is especially important given the significant
number of experienced technical personnel potentially exiting the workplace over the next
few years.
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Property and leasehold impairments.
As mentioned above, we participate in
capital-intensive industries. At times, these investments become impaired when our reserve
estimates are revised downward, when crude oil or natural gas prices, or refinery margins
decline significantly for long periods of time, or when a decision to dispose of an asset
leads to a write-down to its fair market value. Property impairments in 2007, excluding
the impairment of expropriated assets, totaled $442 million, compared with $383 million in
2006. We may also invest large amounts of money in exploration blocks which, if
exploratory drilling proves unsuccessful, could lead to a material impairment of leasehold
values.
Goodwill.
As a result of mergers and acquisitions, at year-end 2007 we had
$29.3 billion of goodwill on our balance sheet, compared with $31.5 billion of goodwill at
year-end 2006. Although our latest tests indicate that no goodwill impairment is currently
required, future deterioration in market conditions could lead to goodwill impairments that
would have a substantial negative, though non-cash, effect on our profitability.
Effective tax rate.
Our operations are located in countries with different tax
rates and fiscal structures. Accordingly, even in a stable commodity price and
fiscal/regulatory environment, our overall effective tax rate can vary significantly
between periods based on the mix of pretax earnings within our global operations.
Fiscal and regulatory environment.
As commodity prices and refining margins
improved over the last several years, certain governments have responded with changes to
their fiscal take. These changes have generally negatively impacted our results of
operations, and further changes to government fiscal take could have a negative impact on
future operations. In June 2007, our Venezuelan oil projects were expropriated, and we
recorded a $4,588 million before-tax ($4,512 million after-tax) impairment (see the
Expropriated Assets section of Note 13Impairments, in the Notes to Consolidated
Financial Statements). The company was also negatively impacted by increased production
taxes enacted by the state of Alaska in the fourth quarter of 2007. In October 2007, the
government of Ecuador increased the tax rate of the Windfall Profits Tax Law implemented in
2006, increasing the amount of government royalty entitlement on crude oil production to 99
percent of any increase in the price of crude oil above a contractual reference price.
Also in October 2007, the Alberta provincial government publicly announced its intention to
change the royalty structure for Crown lands, effective January 1, 2009 (see the Outlook
section for additional information on the proposed royalty increase). In January 2008, we
and our co-venturers agreed to the proportional dilution of our equity interests in the
Republic of Kazakhstans North Caspian Sea Production Sharing Agreement, which includes the
Kashagan field, to allow the state-owned energy company to increase its ownership
percentage effective January 1, 2008, subject to completion of definitive agreements on
dilution and other matters.
Partially offsetting the above fiscal take increases were lower corporate income tax rates
enacted by Canada and Germany during 2007. These tax rate reductions applied to all
corporations and were not exclusive to the oil and gas industry.
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The E&P segments results are most closely linked to crude oil and natural gas prices. These are
commodity products, the prices of which are subject to factors external to our company and over
which we have no control. Industry crude oil prices for West Texas Intermediate were higher in
2007 compared with 2006, averaging $72.25 per barrel in 2007, an increase of 9 percent. The
increase was primarily due to growth in global consumption associated with continuing economic
expansions and limited spare capacity from major exporting countries. Industry natural gas prices
for Henry Hub increased during 2007, primarily due to increased demand from the residential and
electric power sector. These factors were moderated by higher domestic production, increased LNG
imports, and high storage levels.
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Millions of Dollars
Years Ended December 31
2007
2006
2005
$
4,615
9,848
8,430
453
476
688
5,923
4,481
4,173
1,818
1,425
714
359
492
323
(8
)
15
(21
)
(1,269
)
(1,187
)
(778
)
$
11,891
15,550
13,529
The complete impairment ($4,512 million after-tax) of our oil interests in Venezuela
resulting from their expropriation in June 2007.
Lower crude oil production in the E&P segment.
Decreased net income from the Chemicals segment, primarily due to lower olefins and
polyolefins margins.
Higher production and operating expenses, higher production taxes, and higher
depreciation, depletion and amortization expense in the E&P segment.
The net benefit of asset rationalization efforts in the E&P and R&M segments.
Higher realized crude oil, natural gas, and natural gas liquids prices in the E&P
segment.
Higher realized worldwide refining margins, including the benefit of planned inventory
reductions in the R&M segment.
Increased equity earnings from our investment in LUKOIL due to higher estimated
commodity prices and volumes, and an increase in our average equity ownership percentage.
Higher crude oil prices in the E&P segment.
The inclusion of Burlington Resources in our results of operations for the E&P segment.
Improved refining margins and volumes and marketing margins in the R&M segments U.S.
operations.
Increased equity earnings from our investment in LUKOIL.
The recognition in 2006 of business interruption insurance recoveries attributable to
hurricanes in 2005.
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The impairment of certain assets held for sale in the R&M and E&P segments.
Lower natural gas prices in the E&P segment.
Higher interest and debt expense resulting from higher average debt levels due to the
Burlington Resources acquisition.
Decreased net income from the Midstream segment, reflecting the inclusion of our equity
share of DCP Midstreams gain on the sale of the general partner interest in TEPPCO in our
2005 results.
Higher net gains on asset dispositions associated with asset rationalization efforts.
The release of escrowed funds related to the extinguishment of Hamaca project
financing.
The settlement of retroactive adjustments for crude oil quality differentials on
Trans-Alaska Pipeline System shipments (Quality Bank) in 2007.
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LUKOIL, resulting from an increase in our ownership percentage, as well as higher
estimated crude oil and petroleum products prices and volumes, and a net benefit from the
alignment of our estimate of LUKOILs fourth quarter 2005 net income to LUKOILs reported
results.
CPChem, due to higher margins and volumes, as well as the recognition of a business
interruption insurance net benefit.
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2007
2006
2005
Millions of Dollars
$
2,255
2,347
2,552
1,993
2,001
1,736
4,248
4,348
4,288
367
5,500
4,142
$
4,615
9,848
8,430
Dollars Per Unit
$
68.00
61.09
51.09
70.79
63.38
52.27
69.47
62.39
51.74
45.31
46.01
37.79
67.11
60.37
49.87
5.98
6.11
7.12
6.51
6.27
5.78
6.26
6.20
6.32
.30
.30
.26
6.26
6.19
6.30
46.00
40.35
40.40
48.80
42.89
36.25
47.13
41.50
38.32
-
-
-
47.13
41.50
38.32
$
6.52
5.43
4.24
7.68
5.65
4.58
7.13
5.55
4.43
8.92
5.83
4.93
7.21
5.57
4.47
*Excludes our equity share of LUKOIL, which is reported in the LUKOIL Investment segment.
Millions of Dollars
$
544
483
312
254
157
116
209
194
233
$
1,007
834
661
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2007
2006
2005
Thousands of Barrels Daily
261
263
294
102
104
59
363
367
353
210
245
257
87
106
100
19
25
23
81
106
53
10
7
-
770
856
786
27
-
-
15
15
15
42
101
106
854
972
907
19
17
20
79
62
30
98
79
50
14
13
13
14
18
16
27
25
10
2
1
2
155
136
91
Millions of Cubic Feet Daily
110
145
169
2,182
2,028
1,212
2,292
2,173
1,381
961
1,065
1,023
579
582
350
1,106
983
425
125
142
84
19
16
-
5,082
4,961
3,263
5
9
7
5,087
4,970
3,270
Thousands of Barrels Daily
23
21
19
*Excludes our equity share of LUKOIL, which is reported in the LUKOIL Investment segment.
**Represents quantities available for sale. Excludes gas equivalent of natural gas liquids shown above.
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Higher realized crude oil, natural gas liquids and natural gas prices.
A net benefit from asset rationalization efforts.
A benefit related to the release of escrowed funds in connection with the extinguishment
of the Hamaca project financing.
The Quality Bank settlements.
Higher crude oil and natural gas liquids prices, and higher natural gas and natural gas
liquids production.
The Quality Bank settlements.
Gains on the sale of assets in Alaska and the Gulf of Mexico.
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2007
2006
2005
Millions of Dollars
$
453
476
688
$
336
385
591
Dollars Per Barrel
$
47.93
40.22
36.68
46.80
39.45
35.52
*Based on index prices from the Mont Belvieu and Conway market hubs that are weighted by natural gas liquids component and location mix.
Thousands of Barrels Daily
211
209
195
173
144
168
*Includes our share of equity affiliates, except LUKOIL,
which is included in the LUKOIL Investment segment.
**Excludes DCP Midstream.
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2007
2006
2005
Millions of Dollars
$
4,615
3,915
3,329
1,308
566
844
$
5,923
4,481
4,173
Dollars Per Gallon
$
2.27
2.04
1.73
2.42
2.18
1.88
2.29
2.11
1.80
Thousands of Barrels Daily
Crude oil capacity**
2,035
2,208
2,180
1,944
2,025
1,996
96
%
92
92
2,146
2,213
2,186
Crude oil capacity**
687
651
428
616
591
424
90
%
91
99
633
618
439
Crude oil capacity**
2,722
2,859
2,608
2,560
2,616
2,420
94
%
92
93
2,779
2,831
2,625
1,244
1,336
1,374
872
850
876
432
531
519
2,548
2,717
2,769
697
759
482
3,245
3,476
3,251
*
Includes our share of equity affiliates, except for our share of LUKOIL, which is reported in the LUKOIL Investment segment.
**
Weighted-average crude oil capacity for the periods. Actual capacity at year-end 2007, 2006 and 2005, was 2,037,000, 2,208,000, and 2,182,000 barrels per day,
respectively, for our domestic refineries, and 669,000, 693,000, and 482,000 barrels per day, respectively, for our international refineries.
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The net benefit of asset rationalization efforts.
Higher realized worldwide refining margins, reflecting in part the impact of planned
inventory reductions, including a benefit of $260 million from the liquidation of prior
year layers under the last-in, first-out (LIFO) method.
Higher U.S. Gulf and East Coast refining volumes due to lower planned maintenance and
less weather-related downtime.
A $141 million deferred tax benefit related to tax legislation in Germany during the
third quarter of 2007.
Higher refining volumes at our Gulf and East Coast refineries.
Higher realized refining and marketing margins, due in part to the benefit of planned
inventory reductions.
The net benefit of asset rationalization efforts.
The deferred tax benefit related to the tax legislation in Germany.
Higher realized refining margins.
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Higher U.S. refining and marketing margins and higher U.S. refining volumes.
The recognition of a net benefit related to business interruption insurance.
The inclusion of an $83 million charge for the cumulative effect of adopting Financial
Accounting Standards Board (FASB) Interpretation No. 47, Accounting for Conditional Asset
Retirement Obligationsan interpretation of FASB Statement No. 143 (FIN 47) in the
results for 2005.
Higher refining and marketing margins, and higher refining volumes.
The recognition of a net $111 million business interruption insurance benefit.
A $78 million charge for the cumulative effect of adopting FIN 47 in 2005.
The recognition of a $214 million after-tax impairment charge on certain assets held
for sale.
Lower refining margins.
Preliminary engineering costs for certain refinery-related projects.
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Millions of Dollars
2007
2006
2005
$
1,818
1,425
714
401
360
235
256
244
67
214
179
122
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Millions of Dollars
2007
2006
2005
$
359
492
323
Millions of Dollars
2007
2006
2005
$
53
82
43
(61
)
(67
)
(64
)
$
(8
)
15
(21
)
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Millions of Dollars
2007
2006
2005
$
(820
)
(870
)
(467
)
(176
)
(133
)
(183
)
-
-
(23
)
(44
)
(98
)
-
(229
)
(86
)
(105
)
$
(1,269
)
(1,187
)
(778
)
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Millions of Dollars
Except as Indicated
2007
2006
2005
$
24,550
21,516
17,628
1,398
4,043
1,758
21,687
27,134
12,516
1,173
1,202
1,209
88,983
82,646
52,731
19
%
24
19
25
41
9
*Capital includes total debt, minority interests and common stockholders equity.
During 2007, cash of $24,550 million was provided by operating activities, a 14 percent increase
over cash from operations of $21,516 million in 2006. Contributing to the increase was a planned
inventory reduction in the 2007 period, partially related to the formation of the WRB downstream
business venture; the impact of the Burlington Resources acquisition late in the first quarter of
2006; and higher worldwide crude oil prices in 2007. These positive factors were partially offset
by the absence of dividends from our Venezuelan operations in 2007.
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Proceeds from asset sales in 2007 were $3,572 million, compared with $545 million in 2006. The
increase is mainly due to ongoing asset rationalization efforts related to the program we announced
in April 2006 to dispose of assets that no longer fit into our strategic plans or those that could
bring more value by being monetized in the near term. Through December 31, 2007, this program had
generated proceeds of approximately $3.8 billion since inception. In 2008, we expect to complete
the disposition of our retail assets in the United States, Norway, Sweden and Denmark.
In September 2007, we replaced our $5 billion and $2.5 billion revolving credit facilities, with
one $7.5 billion revolving credit facility, expiring in September 2012. This facility may be used as
direct bank borrowings, as support for the ConocoPhillips $7.5 billion commercial paper program, as
support for the ConocoPhillips Qatar Funding Ltd. $1.5 billion commercial paper program, or as
support for issuances of letters of credit totaling up to $750 million. The facility is broadly
syndicated among financial institutions and does not contain any material adverse change provisions
or any covenants requiring maintenance of specified financial ratios or ratings. The credit
agreement contains a cross-default provision relating to the failure to pay principal or interest
on other debt obligations of $200 million or more by ConocoPhillips, or by any of its consolidated
subsidiaries.
We have a universal shelf registration statement on file with the U.S. Securities and Exchange
Commission (SEC) under which we, as a well-known seasoned issuer, have the ability to issue and
sell an indeterminate amount of various types of debt and equity securities.
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At December 31, 2007, we had outstanding $1,173 million of equity in less than wholly owned
consolidated subsidiaries held by minority interest owners, including a minority interest of $508
million in Ashford Energy Capital S.A. The remaining minority interest amounts are primarily
related to operating joint ventures we control. The largest of these, $648 million, was related to
the Darwin LNG project located in northern Australia.
Qatargas 3
:
Qatargas 3 is an integrated project to produce and liquefy natural
gas from Qatars North field. We own a 30 percent interest in the project. The other
participants in the project are affiliates of Qatar Petroleum (68.5 percent) and Mitsui &
Co., Ltd. (1.5 percent). Our interest is held through a jointly owned company,
Qatar Liquefied Gas Company Limited (3), for which we use the equity method of accounting.
Qatargas 3 secured project financing of $4 billion in December 2005, consisting of $1.3
billion of loans from export credit agencies (ECA), $1.5 billion from commercial banks, and
$1.2 billion from ConocoPhillips. The ConocoPhillips loan facilities have substantially
the same terms as the ECA and commercial bank facilities. Prior to project completion
certification, all loans, including the ConocoPhillips loan facilities, are guaranteed by
the participants, based on their respective ownership interests. Accordingly, our maximum
exposure to this financing structure is $1.2 billion, excluding accrued interest. Upon
completion certification, which is expected in 2010, all project loan facilities, including
the ConocoPhillips loan facilities, will become non-recourse to the project participants.
At December 31, 2007, Qatargas 3 had $2.4 billion outstanding under all the loan facilities, of
which ConocoPhillips provided $690 million, and an additional $43 million of accrued
interest.
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Rockies Express Pipeline LLC
:
In June 2006, we issued a guarantee for 24
percent of the $2.0 billion in credit facilities of Rockies Express Pipeline LLC (Rockies Express), which
will be used to construct a natural gas pipeline across a portion of the United States. The
maximum potential amount of future payments to third-party lenders under the guarantee is
estimated to be $480 million, which could become payable if the credit facility is fully utilized and Rockies Express fails
to meet its obligations under the credit agreement. At December 31, 2007, Rockies Express
had $1,625 million outstanding under the credit facilities, with our 24 percent guarantee
equaling $390 million. In addition, we have a 24 percent guarantee on $600 million of Floating Rate
Notes due 2009 issued by Rockies Express in September 2007. It is anticipated that
construction completion will be achieved in 2009, and refinancing will take place at that
time, making the debt non-recourse. For additional information, see Note 7Variable
Interest Entities (VIEs), in the Notes to Consolidated Financial Statements.
Keystone Oil Pipeline
:
In December 2007, we acquired a 50 percent equity
interest in the Keystone Oil Pipeline (Keystone), a joint venture with TransCanada
Corporation. Keystone plans to construct a crude oil pipeline originating in Alberta, with
delivery points in Illinois and Oklahoma. In connection with certain planning and
construction activities, agreements were put in place with third parties to guarantee the
payments due under those agreements. Our maximum potential amount of future payments under
those agreements are estimated to be $400 million, which could become payable if Keystone
fails to meet its obligations under the agreements noted above and the obligation cannot
otherwise be mitigated. Payments under the guarantees are contingent upon the partners not
making necessary equity contributions into Keystone; therefore, it is considered unlikely
that payments would be required. All but $15 million of the guarantees will terminate
after construction is completed, currently estimated to be in 2010.
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Millions of Dollars
Payments Due by Period
Up to
Year
Year
After
Total
1 Year
2-3
4-5
5 Years
$
21,633
1,368
2,796
7,243
10,226
54
30
7
-
17
21,687
1,398
2,803
7,243
10,243
15,439
1,429
2,608
1,949
9,453
3,308
732
1,032
737
807
125,507
49,929
11,864
8,665
55,049
6,887
593
1,285
1,427
3,582
6,613
253
555
481
5,324
1,089
187
319
114
469
144
144
(e
)
(e
)
(e
)
$
180,674
54,665
20,466
20,616
84,927
(a)
Includes $688 million of net unamortized premiums and discounts. See Note 15Debt, in the
Notes to Consolidated Financial Statements, for additional information.
(b)
Represents any agreement to purchase goods or services that is enforceable and legally
binding and that specifies all significant terms. The majority of the purchase obligations
are market-based contracts. Includes: (1) our commercial activities of $74,446 million, of
which $31,834 million are primarily related to the supply of crude oil to our refineries and
the optimization of the supply chain, $10,530 million primarily related to the supply of
unfractionated natural gas liquids (NGL) to fractionators, optimization of NGL assets, and for
resale to customers, $9,575 million on futures, $8,933 million primarily related to natural
gas for resale customers, $7,354 million related to transportation, $4,984 million related to
product purchases, $943 million related to power trades, and $293 million related to the
purchase side of exchange agreements; (2) $45,744 million of purchase commitments for
products, mostly natural gas and NGL, from CPChem over the remaining term of 92 years; and (3)
purchase commitments for jointly owned fields and facilities where we are the operator, of
which some of the obligations will be reimbursed by our co-venturers in these properties.
Does not include: (1) purchase commitments for jointly owned fields and facilities where we
are not the operator; and (2) an agreement to purchase up to 165,000 barrels per day of
Venezuelan Merey, or equivalent, crude oil for a market price over a remaining 12-year term if
a variety of conditions are met.
(c)
Represents the remaining amount of contributions, excluding interest, due over a nine-year
period to the upstream joint venture formed with EnCana.
(d)
Does not include: Pensionsfor the 2008 through 2012 time period, we expect to contribute an
average of $335 million per year to our qualified and non-qualified pension and postretirement
medical plans in the United States and an average of $200 million per year to our non-U.S.
plans,
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which are expected to be in excess of required minimums in many cases. The U.S.
five-year average consists of $460 million for 2008 and then approximately $300 million per
year for the remaining four years. Our required minimum funding in 2008 is expected to be
$110 million in the United States and $120 million outside the United States.
(e)
Does not include unrecognized tax benefits of $999 million because the ultimate disposition
and timing of any payments to be made with regard to such amount is not reasonably estimable.
Although unrecognized tax benefits are not a contractual obligation, they are presented in
this table because they represent potential demands on our liquidity.
Millions of Dollars
2008
Budget
2007
2006
2005
$
1,007
666
820
746
3,259
3,122
2,008
891
6,787
6,147
6,685
5,047
11,053
9,935
9,513
6,684
6
5
4
839
2,060
1,146
1,597
1,537
741
240
1,419
201
2,801
1,386
3,016
1,738
-
-
2,715
2,160
-
-
-
-
226
257
83
5
238
208
265
194
$
14,324
11,791
15,596
11,620
$
6,435
5,225
4,735
4,207
7,889
6,566
10,861
7,413
$
14,324
11,791
15,596
11,620
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Capital spending for E&P during the three-year period ending December 31, 2007, totaled $26.1
billion. The expenditures over this period supported key exploration and development projects
including:
Development drilling in the Greater Kuparuk Area, including West Sak; the Greater
Prudhoe Bay Area; the Alpine field, including satellite field prospects; exploratory
drilling; and the acquisition of acreage in Alaska.
Oil and natural gas developments in the Lower 48 states, including New Mexico, Texas,
Louisiana, Oklahoma, Montana, North Dakota and Colorado.
The Magnolia development, Ursa and K-2 fields in the deepwater Gulf of Mexico.
The acquisition of limited-term, fixed-volume overriding royalty interests in Utah and
the San Juan Basin related to our natural gas production.
Investment in the West2East Pipeline LLC (West2East), a company holding a 100 percent
interest in Rockies Express Pipeline LLC (Rockies Express).
Expansion of the Syncrude oil sands project, the development of the Surmont heavy-oil
project, capital expenditures related to the EnCana upstream business venture, and
development of conventional oil and gas reserves, all in Canada.
Development of the Corocoro field offshore Venezuela (see Note 13Impairments, in the
Notes to Consolidated Financial Statements, for additional information).
The Ekofisk Area growth project and Alvheim project in the Norwegian North Sea.
The Statfjord Late-Life project straddling the offshore boundary between Norway and the
United Kingdom.
The Britannia satellite and Clair developments in the U.K. North Sea and Atlantic
Margin, respectively.
An integrated project to produce and liquefy natural gas from Qatars North field.
Investments in three fields in Algeria.
Expenditures related to the terms under which we returned to our former oil and natural
gas production operations in the Waha concessions in Libya and continued development of
these concessions.
Ongoing development of onshore oil and natural gas fields in Nigeria and ongoing
exploration activities both onshore and on deepwater leases.
The Kashagan field and satellite prospects in the Caspian Sea, offshore Kazakhstan.
The acquisition of an interest in OOO Naryanmarneftegaz (NMNG), a joint venture with
LUKOIL, and development of the Yuzhno Khylchuyu (YK) field.
The Bayu-Undan gas recycle and liquefied natural gas development projects in the Timor
Sea and northern Australia, respectively.
The Belanak, Suban, Kerisi, Hiu and Belut projects in Indonesia.
The Peng Lai 19-3 development in Chinas Bohai Bay and additional Bohai Bay appraisal
and adjacent field prospects.
Expenditures to develop the Su Tu Vang field and continued in-field development of the
Rang Dong field in Vietnam.
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The Ekofisk field in the North Sea.
The Peng Lai 19-3 field in China.
Fields in the United States and Canada.
EnCana business venture projectsChristina Lake and Foster Creek.
The Surmont heavy-oil project in Canada.
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Capital spending for Midstream during the three-year period ending December 31, 2007, was primarily
related to increasing our ownership interest in DCP Midstream in 2005 from 30.3 percent to 50
percent.
Capital spending for R&M during the three-year period ending December 31, 2007, was primarily for
acquiring additional crude oil refining capacity, clean fuels projects to meet new environmental
standards, refinery-upgrade projects to improve product yields, the operating integrity of key
processing units, as well as for safety projects. In addition, in December 2007, we invested funds
to acquire a 50 percent equity interest in the Keystone Oil Pipeline (Keystone), a joint venture to
construct a crude oil pipeline from Hardisty, Alberta to U.S. Midwest markets in Illinois and
Oklahoma. During this three-year period, R&M capital spending was $6.1 billion, representing 16
percent of our total capital expenditures and investments.
Acquisition of the Wilhelmshaven refinery in Germany.
Debottlenecking of a crude and fluid catalytic cracking unit, and completion of a new
sulfur plant at the Ferndale refinery.
A new ultra-low-sulfur diesel hydrotreater at the Sweeny refinery.
Revamp of an existing hydrotreater for ultra-low-sulfur diesel and a new hydrogen plant
at the Wood River refinery.
Expansion of existing hydrotreaters for both low-sulfur gasoline and ultra-low-sulfur
diesel, with the addition of a new hydrogen plant at the Bayway refinery.
A new hydrotreater for ultra-low-sulfur diesel and a hydrogen plant at the Ponca City
refinery.
Revamps of existing hydrotreaters for ultra-low-sulfur diesel at the Los Angeles,
Trainer and Ferndale refineries.
A new ultra-low-sulfur diesel hydrotreater and hydrogen plant at the Billings refinery.
A fluid catalytic cracking gasoline hydrotreater at the Alliance refinery for production
of low-sulfur gasoline.
A sulfur removal technology unit at the Lake Charles refinery for the production of
low-sulfur gasoline.
A new ultra-low-sulfur diesel hydrotreater at the Rodeo facility of our San Francisco
refinery.
Expansion of a hydrocracker at the Rodeo facility of our San Francisco refinery.
Construction of a low-sulfur gasoline project at the Billings refinery.
U.S. programs aimed at air emission reductions.
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Capital spending in our LUKOIL Investment segment during the three-year period ending December 31,
2007, was for continued purchases of ordinary shares of LUKOIL to increase our ownership interest.
However, no additional purchases were made in 2007, and none are expected in 2008.
Capital spending for Emerging Businesses during the three-year period ending December 31, 2007, was
primarily for an expansion of the Immingham combined heat and power cogeneration plant near the
companys Humber refinery in the United Kingdom. In addition, in October 2007, we purchased a 50
percent interest in Sweeny Cogeneration LP (SCLP). SCLP provides steam and electric power to the
Sweeny refinery complex with any excess power sold into the market. We account for this joint
venture using the equity method of accounting.
We accrue for non-income-tax-related contingencies when a loss is probable and the amounts can be
reasonably estimated. If a range of amounts can be reasonably estimated and no amount within the
range is a better estimate than any other amount, then the minimum of the range is accrued. In the
case of income-tax-related contingencies, we adopted FASB
Interpretation No. 48, Accounting for Uncertainty in Income Taxesan interpretation of FASB
Statement No. 109 (FIN 48), effective January 1, 2007. FIN 48 requires a cumulative
probability-weighted loss accrual in cases where sustaining a tax position is less than certain.
Based on currently available information, we believe it is remote that future costs related to
known contingent liability exposures will exceed current accruals by an amount that would have a
material adverse impact on our consolidated financial statements.
We are subject to the same numerous international, federal, state, and local environmental laws and
regulations, as are other companies in the petroleum exploration and production, refining, and
crude oil and refined product marketing and transportation businesses. The most significant of
these environmental laws and regulations include, among others, the:
Federal Clean Air Act, which governs air emissions.
Federal Clean Water Act, which governs discharges to water bodies.
Federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA),
which imposes liability on generators, transporters, and arrangers of hazardous substances
at sites where hazardous substance releases have occurred or are threatened to occur.
Federal Resource Conservation and Recovery Act (RCRA), which governs the treatment,
storage, and disposal of solid waste.
Federal Oil Pollution Act of 1990 (OPA90), under which owners and operators of onshore
facilities and pipelines, lessees or permittees of an area in which an offshore facility is
located, and owners and operators of vessels are liable for removal costs and damages that
result from a discharge of oil into navigable waters of the United States.
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Federal Emergency Planning and Community Right-to-Know Act (EPCRA), which requires
facilities to report toxic chemical inventories with local emergency planning committees and
responses departments.
Federal Safe Drinking Water Act, which governs the disposal of wastewater in underground
injection wells.
U.S. Department of the Interior regulations, which relate to offshore oil and gas
operations in U.S. waters and impose liability for the cost of pollution cleanup resulting
from operations, as well as potential liability for pollution damages.
European Emissions Trading Scheme, the program through which many of the European Union
member states are implementing the Kyoto Protocol.
Californias Assembly Bill 32, which requires the California Air Resources Board (CARB)
to develop regulations and market mechanisms that will ultimately reduce Californias
greenhouse gas emissions by 25 percent by 2020.
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Two regulations issued by the Alberta government in 2007 under the Climate Change and
Emissions Act. These regulations require any existing facility with emissions equal to or
greater than 100,000 metric tons of carbon dioxide or equivalent per year to reduce the net
emissions intensity of that facility by 2 percent per year beginning July 1, 2007, with an
ultimate reduction target of 12 percent of baseline emissions.
The U.S. Supreme Court decision in
Massachusetts v. EPA
, 549 U.S. ___, 127 S.Ct.
1438 ( 2007) confirming that the U.S. Environmental Protection Agency (EPA) has the
authority to regulate carbon dioxide as an air pollutant under the federal Clean Air Act.
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For individually significant leaseholds, management periodically assesses for impairment based on
exploration and drilling efforts to date. For leasehold acquisition costs that individually are
relatively small, management exercises judgment and determines a percentage probability that the
prospect ultimately will fail to find proved oil and gas reserves and pools that leasehold
information with others in the geographic area. 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.
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For exploratory wells, drilling costs are temporarily capitalized, or suspended, on the balance
sheet, pending a determination of whether potentially economic oil and gas reserves have been
discovered by the drilling effort to justify completion of the find as a producing well.
Engineering estimates of the quantities of recoverable oil and gas reserves in oil and gas fields
and in-place crude bitumen volumes in oil sand mining operations are inherently imprecise and
represent only approximate amounts because of the subjective judgments involved in developing such
information. Reserve estimates are based on subjective judgments involving geological and
engineering assessments of in-place hydrocarbon volumes, the production or mining plan, historical
extraction recovery and processing yield factors, installed plant operating capacity and operating
approval limits. The reliability of these estimates at any point in time depends on both the
quality and quantity of the technical and economic data and the efficiency of extracting and
processing the hydrocarbons.
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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. We use all available information to make these fair
value determinations. We have, if necessary, up to one year after the acquisition closing date to
finish these fair value determinations and finalize the purchase price allocation.
At December 31, 2007, we had $731 million of intangible assets determined to have indefinite useful
lives, thus they 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 that require
managements judgment of the estimated fair value of these intangible assets. See Note
12Goodwill and Intangibles, in the Notes to Consolidated Financial Statements, for additional
information.
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In late 2007, we submitted a proposal to the governor of Alaska to advance the development of the
Alaska Natural Gas Pipeline Project. The proposed pipeline would transport approximately 4 billion
cubic feet per day of natural gas from the Alaska North Slope to markets in Canada and the United
States. We have a 36.1 percent non-operator interest in the Greater Prudhoe Area fields that are
expected to be a primary source of natural gas to be shipped in the proposed pipeline. Our
proposal was submitted as an alternative to the process the Alaska Legislature established in its
Alaska Gasline Inducement Act (AGIA). In our proposal, we stated our willingness to make
significant investments, without state matching funds, to advance this project. In January 2008,
we received a letter from the governor of Alaska stating our alternative does not give the state a
reason to deviate from the AGIA process. We formally responded to the governors letter on January
24, 2008. As a result of the lack of engagement by the state of
Alaska on our proposal, we are reassessing how best to advance the
Alaska natural gas pipeline project. During this reassessment, as an
initial step we will continue planning and contracting efforts in
preparation for route reconnaissance and environmental studies
starting in June 2008. We expect to continue to testify before the
Alaska Legislature and engage the Alaska public with our view of the
best path forward to advance the gas pipeline project.
Negotiations continue between ConocoPhillips and Venezuelan authorities concerning appropriate
compensation for the expropriation of the companys oil interests. We continue to preserve all our
rights with respect to this situation, including our rights under the contracts we signed and under
international and Venezuelan law. We continue to evaluate our options in realizing adequate
compensation for the value of our oil investments and operations in Venezuela and filed a request
for international arbitration on November 2, 2007, with the International Centre for Settlement of
Investment Disputes (ICSID), an arm of the World Bank. The request was registered by ICSID on
December 13, 2007.
On October 25, 2007, the Alberta provincial government publicly announced its intention to make a
change to the royalty structure for Crown lands, effective January 1, 2009. Although the
governments proposed change will require legislative and regulatory amendments to become effective
and may be further modified before final adoption, there is a high likelihood there will be some
form of change to the royalty structure in Alberta. While the precise impact of the proposed
change is not determinable at this time, the adoption of the proposed royalty structure could
result in a range of outcomes, including a negative adjustment to our Canadian reserve base. This
change will impact both our conventional western Canada natural gas business and our oil sands
operations.
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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.
Potential failure or delays in achieving expected reserve or production levels from
existing and future oil and gas development projects due to operating hazards, drilling
risks and the inherent uncertainties in predicting oil and gas reserves and oil and gas
reservoir performance.
Unsuccessful exploratory drilling activities or the inability to obtain access to
exploratory acreage.
Failure of new products and services to achieve market acceptance.
Unexpected changes in costs or technical requirements for constructing, modifying or
operating facilities for exploration and production projects, manufacturing or refining.
Unexpected technological or commercial difficulties in manufacturing, refining, or
transporting our products, including synthetic crude oil and chemicals products.
Lack of, or disruptions in, adequate and reliable transportation for our crude oil,
natural gas, natural gas liquids, LNG and refined products.
Inability to timely obtain or maintain permits, including those necessary for
construction of LNG terminals or regasification facilities, comply with government
regulations, or make capital expenditures required to maintain compliance.
Failure to complete definitive agreements and feasibility studies for, and to timely
complete construction of, announced and future LNG and refinery projects and related
facilities.
Potential disruption or interruption of our operations due to accidents, extraordinary
weather events, civil unrest, political events or terrorism.
International monetary conditions and exchange controls.
Substantial investment or reduced demand for products as a result of existing or future
environmental rules and regulations.
Liability for remedial actions, including removal and reclamation obligations, under
environmental regulations.
Liability resulting from litigation.
General domestic and international economic and political developments, including:
armed hostilities; expropriation of assets; changes in governmental policies relating to
crude oil, natural gas, natural gas liquids or refined product pricing, regulation, or
taxation; other political, economic or diplomatic developments; and international monetary
fluctuations.
Changes in tax and other laws, regulations (including alternative energy mandates), or
royalty rules applicable to our business.
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Inability to obtain economical financing for projects, construction or modification of
facilities and general corporate purposes.
The operation and financing of our midstream and chemicals joint ventures.
The factors generally described in the Risk Factors section included in Items 1 and
2Business and Properties in this report.
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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 the 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.
Balance physical systems. In addition to cash settlement prior to contract expiration,
exchange traded futures contracts also may be settled by physical delivery of the
commodity, providing another source of supply to meet our refinery requirements or
marketing demand.
Meet customer needs. Consistent with our policy to generally remain exposed to market
prices, we use swap contracts to convert fixed-price sales contracts, which are often
requested by natural gas and refined product consumers, to a floating market price.
Manage the risk to our cash flows from price exposures on specific crude oil, natural
gas, refined product and electric power transactions.
Enable us to use the market knowledge gained from these activities to do a limited
amount of trading not directly related to our physical business. For the years ended
December 31, 2007 and 2006, the gains or losses from this activity were not material to our
cash flows or net income.
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The following tables provide information about our financial instruments that are sensitive to
changes in short-term U.S. interest rates. The debt table presents 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 our floating-rate debt approximates its fair value. The
fair value of the fixed-rate financial instruments is estimated based on quoted market prices.
Millions of Dollars Except as Indicated
Debt
Fixed Rate
Average
Floating Rate
Average
Expected Maturity Date
Maturity
Interest Rate
Maturity
Interest Rate
$
324
7.12
%
$
1,000
5.58
%
313
6.44
950
5.47
1,433
8.85
-
-
3,175
6.74
2,000
5.58
1,267
4.94
743
5.43
9,082
6.68
658
4.36
$
15,594
$
5,351
$
17,750
$
5,351
$
557
7.43
%
$
1,000
5.37
%
32
6.96
-
-
307
6.43
1,250
5.47
1,433
8.85
-
-
3,175
6.74
7,944
5.53
9,983
6.57
691
4.29
$
15,487
$
10,885
$
16,856
$
10,885
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Millions of Dollars Except as Indicated
Joint Venture Acquisition Obligation
Fixed Rate
Average
Expected Maturity Date
Maturity
Interest Rate
$
593
5.30
%
626
5.30
659
5.30
695
5.30
732
5.30
3,582
5.30
$
6,887
$
7,031
We have foreign currency exchange rate risk resulting from international operations. 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.
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In Millions
Foreign Currency Swaps
Notional*
Fair Market Value**
2007
2006
2007
2006
USD
744
242
$
3
5
USD
1,049
647
(16
)
20
USD
1,195
1,367
13
(19
)
USD
-
7
-
-
USD
20
17
-
-
USD
779
1,145
15
15
USD
11
108
-
-
USD
-
2
-
-
USD
-
4
-
-
EUR
-
10
-
-
EUR
58
-
-
-
EUR
1
125
3
-
**Denominated in U.S. dollars.
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Page
99
100
101
103
104
105
106
107
174
194
195
INDEX TO FINANCIAL STATEMENT SCHEDULES
207
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Management is also responsible for establishing and maintaining adequate internal control over
financial reporting. ConocoPhillips internal control system was designed to provide reasonable
assurance to the companys management and directors regarding the preparation and fair presentation
of published financial statements.
/s/ John A. Carrig
John A. Carrig
Executive Vice President, Finance,
and Chief Financial Officer
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ConocoPhillips
February 21, 2008
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Internal Control Over Financial Reporting
ConocoPhillips
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February 21, 2008
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Consolidated Income Statement
ConocoPhillips
Years Ended December 31
Millions of Dollars
2007
2006
2005
$
187,437
183,650
179,442
5,087
4,188
3,457
1,971
685
465
194,495
188,523
183,364
123,429
118,899
124,925
10,683
10,413
8,562
2,306
2,476
2,247
1,007
834
661
8,298
7,284
4,253
4,588
-
-
442
683
42
18,990
18,187
18,356
341
281
193
1,253
1,087
497
(201
)
(30
)
48
87
76
33
171,223
160,190
159,817
23,272
28,333
23,547
11,381
12,783
9,907
11,891
15,550
13,640
-
-
(23
)
11,891
15,550
13,617
-
-
(88
)
$
11,891
15,550
13,529
$
7.32
9.80
9.79
-
-
(.02
)
7.32
9.80
9.77
-
-
(.06
)
$
7.32
9.80
9.71
$
7.22
9.66
9.63
-
-
(.02
)
7.22
9.66
9.61
-
-
(.06
)
$
7.22
9.66
9.55
1,623,994
1,585,982
1,393,371
1,645,919
1,609,530
1,417,028
$
15,937
16,072
17,037
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Consolidated Balance Sheet
ConocoPhillips
At December 31
Millions of Dollars
2007
2006
$
1,456
817
14,687
13,456
1,667
650
4,223
5,153
2,702
4,990
24,735
25,066
31,457
19,595
1,871
1,118
89,003
86,201
29,336
31,488
896
951
459
362
$
177,757
164,781
$
16,591
14,163
1,270
471
1,398
4,043
4,814
4,407
920
895
1,889
2,452
26,882
26,431
20,289
23,091
7,261
5,619
6,294
-
21,018
20,074
3,191
3,667
2,666
2,051
87,601
80,933
1,173
1,202
17
17
42,724
41,926
(731
)
(766
)
(7,969
)
(964
)
4,560
1,289
(128
)
(148
)
50,510
41,292
88,983
82,646
$
177,757
164,781
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Consolidated Statement of Cash Flows
ConocoPhillips
Years Ended December 31
Millions of Dollars
2007
2006
2005
$
11,891
15,550
13,529
8,298
7,284
4,253
4,588
-
-
442
683
42
463
351
349
341
281
193
(157
)
263
1,101
(1,823
)
(945
)
(1,774
)
(1,348
)
(116
)
(278
)
-
-
23
-
-
88
105
(201
)
(139
)
-
-
(480
)
(2,492
)
(906
)
(2,665
)
767
(829
)
(182
)
487
(372
)
(407
)
2,772
657
3,156
216
(184
)
824
24,550
21,516
17,633
-
-
(5
)
24,550
21,516
17,628
-
(14,285
)
-
(11,791
)
(15,596
)
(11,620
)
3,572
545
768
(682
)
(780
)
(275
)
89
123
111
250
-
-
(8,562
)
(29,993
)
(11,016
)
(8,562
)
(29,993
)
(11,016
)
935
17,314
452
(6,454
)
(7,082
)
(3,002
)
285
220
402
(7,001
)
(925
)
(1,924
)
(2,661
)
(2,277
)
(1,639
)
(444
)
(185
)
27
(15,340
)
7,065
(5,684
)
(15,340
)
7,065
(5,684
)
(9
)
15
(101
)
639
(1,397
)
827
817
2,214
1,387
$
1,456
817
2,214
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ConocoPhillips
Millions of Dollars
Shares of Common Stock
Accumulated
Held in
Common Stock
Other
Unearned
Held in
Grantor
Par
Capital in
Treasury
Grantor
Comprehensive
Employee
Retained
Issued
Treasury
Trusts
Value
Excess of Par
Stock
Trusts
Income
Compensation
Earnings
Total
1,437,729,662
-
48,182,820
$
14
26,047
-
(816
)
1,592
(242
)
16,128
42,723
13,529
13,529
(56
)
(56
)
(717
)
(717
)
(6
)
(6
)
1
1
12,751
(1,639
)
(1,639
)
32,080,000
(1,924
)
(1,924
)
18,131,678
(2,250,727
)
707
38
745
75
75
1,455,861,340
32,080,000
45,932,093
14
26,754
(1,924
)
(778
)
814
(167
)
28,018
52,731
15,550
15,550
Minimum pension liability adjustment
33
33
1,013
1,013
4
4
16,600
(575
)
(575
)
(2,277
)
(2,277
)
239,733,571
(32,080,000
)
890,180
3
14,475
1,924
(53
)
16,349
15,061,613
(542,000
)
(964
)
32
(932
)
9,907,698
(1,921,688
)
697
33
730
19
19
1
1
1,705,502,609
15,061,613
44,358,585
17
41,926
(964
)
(766
)
1,289
(148
)
41,292
82,646
11,891
11,891
63
63
213
213
(2
)
(2
)
3,075
3,075
(4
)
(4
)
15,236
(74
)
(74
)
(2,661
)
(2,661
)
89,545,536
(177,110
)
(7,005
)
11
(6,994
)
12,946,220
(1,856,224
)
798
31
829
20
20
86,080
(7
)
(12
)
(19
)
1,718,448,829
104,607,149
42,411,331
$17
42,724
(7,969
)
(731
)
4,560
(128
)
50,510
88,983
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Notes to Consolidated Financial Statements
ConocoPhillips
n
Consolidation Principles and Investments
Our
consolidated financial statements include the
accounts of majority-owned, controlled
subsidiaries and variable interest entities
where we are the primary beneficiary. The
equity method is used to account for
investments in affiliates in which we have
the ability to exert significant influence
over the affiliates operating and financial
policies. The cost method is used when we do
not have the ability to exert 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.
n
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 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.
n
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 these estimates.
n
Revenue Recognition
Revenues associated with
sales of crude oil, natural gas, natural gas
liquids, petroleum and chemical products, and
other items are recognized when title passes
to the customer, which is when the risk of
ownership passes to the purchaser and
physical delivery of goods occurs, either
immediately or within a fixed delivery
schedule that is reasonable and customary in
the industry.
Prior to April 1, 2006, revenues included the sales portion of transactions commonly called
buy/sell contracts. Effective April 1, 2006, we implemented Emerging Issues Task Force (EITF)
Issue No. 04-13, Accounting for Purchases and Sales of Inventory with the Same Counterparty.
Issue No. 04-13 requires purchases and sales of inventory with the same counterparty and
entered into in contemplation of one another to be combined and reported net (i.e., on the
same income statement line). See Note 2Changes in Accounting Principles, for additional
information about our adoption of this Issue.
Revenues from the production of natural gas and crude oil 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 to be non-recoverable through remaining production, are recognized
as accounts receivable or accounts payable, as appropriate. Cumulative differences between
volumes sold and entitlement volumes are generally not significant.
Revenues associated with royalty fees from licensed technology are recorded based either upon
volumes produced by the licensee or upon the successful completion of all substantive
performance requirements related to the installation of licensed technology.
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n
Shipping and Handling Costs
Our Exploration and Production (E&P)
segment includes shipping and handling costs in production and
operating expenses for production activities. Transportation
costs related to E&P marketing activities are recorded in
purchased crude oil, natural gas and products. The Refining and
Marketing (R&M) segment records shipping and handling costs in
purchased crude oil, natural gas and products. Freight costs
billed to customers are recorded as a component of revenue.
n
Cash Equivalents
Cash equivalents are highly liquid, short-term
investments that are readily convertible to known amounts of cash
and have original maturities of three months or less from their
date of purchase. They are carried at cost plus accrued interest,
which approximates fair value.
n
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, such as
tubular goods and well equipment, are valued under various
methods, including the weighted-average-cost method, and the
first-in, first-out (FIFO) method, consistent with industry
practice.
n
Derivative Instruments
All derivative instruments are recorded on
the balance sheet at fair value in either prepaid expenses and
other current assets, other assets, other accruals, or other
liabilities and deferred credits. Recognition and classification
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 accounted for as hedges under Statement of Financial
Accounting Standards (SFAS) No. 133, Accounting for Derivative
Instruments and Hedging Activities, 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 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, natural gas and products; interest and
debt expense; or foreign currency transaction (gains) losses, depending on the purpose for
issuing or holding the derivatives.
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n
Oil and Gas Exploration and Development
Oil and gas exploration and development costs are
accounted for using the successful efforts method of accounting.
n
Syncrude Mining Operations
Capitalized costs, including support
facilities, include property acquisition costs 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.
n
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.
n
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
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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 net book value.
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.
n
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 units assets
(including goodwill), less liabilities, then a hypothetical
purchase price allocation is performed on the reporting units
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, three reporting units had
been determined prior to 2007: Worldwide Exploration and
Production, Worldwide Refining and Worldwide Marketing. In 2007,
the Refining unit and Marketing unit were combined into one unit,
Worldwide Refining and Marketing. Because quoted market prices
are not available for the companys 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.
n
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).
n
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 and reported as impairments in the periods in which the
determination of the 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 assetsgenerally 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. Additionally, when probable
reserves exist, an appropriate risk-adjusted amount of these reserves may be included in the
impairment calculation. The price and cost outlook
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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, SFAS No. 69, Disclosures about Oil and Gas Producing Activities, requires
inclusion of only proved reserves and the use of prices and costs at the balance sheet date,
with no projection for future changes in assumptions.
n
Impairment of Investments in Non-Consolidated
Companies
Investments in non-consolidated companies are assessed
for impairment whenever changes in the facts and circumstances
indicate a loss in value has occurred, which is other than a
temporary decline in value. The fair value of the impaired
investment is based on quoted market prices, if available, or upon
the present value of expected future cash flows using discount
rates commensurate with the risks of the investment.
n
Maintenance and Repairs
The costs of maintenance and repairs,
which are not significant improvements, are expensed when
incurred.
n
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 that
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.
n
Property Dispositions
When complete units of depreciable property
are sold, the asset cost and related accumulated depreciation are
eliminated, with any gain or loss reflected in other 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.
n
Asset Retirement Obligations and Environmental Costs
We record
the fair value of legal obligations to retire and remove
long-lived assets in the period in which the obligation is
incurred (typically when the asset is installed at the production
location). When the liability is initially recorded, we
capitalize this 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, and the
capitalized cost in properties, plants and equipment is
depreciated over the useful life of the related asset. See Note
14Asset Retirement Obligations and Accrued Environmental Costs,
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 environmental expenditures
are recorded on an undiscounted basis (unless acquired in a purchase business combination) 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 and estimable.
n
Guarantees
The fair value of a guarantee is determined and recorded as a liability at the
time the guarantee is given. The initial liability is subsequently reduced as we are released
from exposure under the guarantee. We amortize the guarantee liability over the relevant time
period, if one exists, based on the facts and circumstances surrounding each type of
guarantee. In cases where the guarantee term is indefinite, we reverse the liability when we
have information that the liability is essentially relieved or amortize it over an appropriate
time period as the fair value of our guarantee exposure declines over time. We amortize the
guarantee liability to the related income statement line
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item based on the nature of the guarantee. When it becomes probable that we will have to
perform on a guarantee, we accrue a separate liability if it is reasonably estimable, based on
the facts and circumstances at that time. We reverse the fair value liability only when there
is no further exposure under the guarantee.
n
Stock-Based Compensation
Effective January 1, 2003, we voluntarily adopted the fair value
accounting method prescribed by SFAS No. 123, Accounting for Stock-Based Compensation. We
used the prospective transition method, 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 were accounted for under Accounting Principles
Board (APB) Opinion No. 25, Accounting for Stock Issued to Employees, and related
Interpretations; however, by the end of 2005, all of these awards had vested. Because the
exercise price of our employee stock options equaled the market price of the underlying stock
on the date of grant, generally no compensation expense was recognized under APB Opinion No.
25. The following table displays 2005 pro forma information as if the provisions of SFAS No.
123 had been applied to all employee stock options granted:
Millions
of Dollars
$
13,529
142
(144
)
$
13,527
$
9.71
9.71
9.55
9.55
Generally, our stock-based compensation programs provided accelerated vesting (i.e., a waiver
of the remaining period of service required to earn an award) for awards held by employees at
the time of their retirement. We recognized expense for these awards over the period of time
during which the employee earned the award, accelerating the recognition of expense only when
an employee actually retired (both the actual expense and the pro forma expense shown in the
preceding table were calculated in this manner).
Effective January 1, 2006, we adopted SFAS No. 123 (revised 2004), Share-Based Payment (SFAS
No. 123(R)), which requires us to recognize stock-based compensation expense for new awards
over the shorter of: 1) the service period (i.e., the stated period of time required to earn
the award); or 2) the period beginning at the start of the service period and ending when an
employee first becomes eligible for retirement. This shortens the period over which we
recognize expense for most
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of our stock-based awards granted to our employees who are already age 55 or older, but it has not had
a material effect on our consolidated financial statements. For share-based awards granted
after our adoption of SFAS No. 123(R), we have elected to recognize expense on a straight-line
basis over the service period for the entire award, whether the award was granted with ratable
or cliff vesting.
n
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. Interest related to unrecognized tax benefits is
reflected in interest expense, and penalties in production and
operating expenses.
n
Taxes Collected from Customers and Remitted to Governmental
Authorities
Excise taxes are reported gross within sales and
other operating revenues and taxes other than income taxes, while
other sales and value-added taxes are recorded net in taxes other
than income taxes.
n
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. Also, this calculation includes
fully vested stock and unit awards that have not been issued.
Diluted income per share of common stock includes the above, plus
unvested stock, unit or option awards granted under our
compensation plans and vested but unexercised stock options, but
only to the extent these instruments dilute net income per share.
Treasury stock and shares held by the grantor trusts are excluded
from the daily weighted-average number of common shares
outstanding in both calculations.
n
Accounting for Sales of Stock by Subsidiary or Equity
Investees
We recognize a gain or loss upon the direct sale of
non-preference 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.
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Millions of Dollars
Actual
Pro Forma
2007
2006
2005
$
187,437
176,993
154,692
123,429
112,242
100,175
Recognize the funded status of the benefit in its statement of financial position.
Recognize as a component of other comprehensive income, net of tax, the gains or losses
and prior service costs or credits that arise during the period, but are not recognized as
components of net periodic benefit cost.
Measure defined benefit plan assets and obligations as of the date of the employers
fiscal year-end statement of financial position.
Disclose in the notes to financial statements additional information about certain
effects on net periodic benefit cost for the next fiscal year that arise from delayed
recognition of the gains or losses, prior service costs or credits, and the transition
asset or obligation.
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Millions
of Dollars
$
356
$
(26
)
(3
)
$
(23
)
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Millions
of Dollars
$
3,238
1,432
229
108
268
28,176
16,787
107
46
$
50,391
$
1,487
1,009
697
248
254
3,330
730
174
7,849
347
397
33,869
$
50,391
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Millions of Dollars
2006
2005
$
185,555
186,227
15,945
14,780
15,945
14,669
9.65
8.88
9.51
8.75
9.65
8.82
9.51
8.68
Millions
of Dollars
$
-
218
(98
)
120
13
(68
)
$
65
*
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Millions of Dollars
2007
2006
$
3,373
4,351
850
802
$
4,223
5,153
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Millions of Dollars
2007
2006
$
48
170
946
2,422
89
340
2
13
7
106
$
1,092
3,051
$
189
1,465
903
1,586
$
1,092
3,051
$
23
386
133
201
3
17
$
159
604
$
35
392
124
212
$
159
604
Millions of Dollars
2007
2006
$
30,408
18,544
1,871
1,118
495
442
554
609
$
33,328
20,713
Affiliated companies in which we have a significant equity investment include:
FCCL Oil Sands Partnership (FCCL)50 percent owned business venture with EnCana
Corporationproduces heavy-oil in the Athabasca oil sands in northeast Alberta, as well as
transports and sells the bitumen blend.
WRB Refining LLC (WRB)50 percent owned business venture with EnCana
Corporationprocesses crude oil at the Wood River and Borger refineries, as well as
purchases and transports all feedstocks for the refineries and sells the refined products.
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OAO LUKOIL (LUKOIL)20 percent ownership interest. LUKOIL explores for and produces
crude oil, natural gas and natural gas liquids; refines, markets and transports crude oil
and petroleum products; and is headquartered in Russia.
OOO Naryanmarneftegaz (NMNG)30 percent ownership interest and a 50 percent governance
interesta joint venture with LUKOIL to explore for and develop oil and gas resources in
the northern part of Russias Timan-Pechora province.
DCP Midstream, LLC (DCP Midstream)50 percent owned joint venture with Spectra
Energyowns and operates gas plants, gathering systems, storage facilities and
fractionation plants. Effective January 2, 2007, Duke Energy Field Services, LLC (DEFS)
formally changed its name to DCP Midstream.
Chevron Phillips Chemical Co. LLC (CPChem)50 percent owned joint venture with Chevron
Corporationmanufactures and markets petrochemicals and plastics.
Millions of Dollars
2007
2006
2005
$
143,686
113,607
96,367
19,807
16,257
15,059
15,229
12,447
11,743
29,451
24,820
23,652
90,939
59,803
48,181
16,882
15,884
14,727
26,656
20,603
15,833
In October 2006, we announced a business venture with EnCana Corporation (EnCana) to create an
integrated North American heavy-oil business. The transaction closed on January 3, 2007, and
consists of two 50/50 business ventures, a Canadian upstream general partnership, FCCL Oil Sands
Partnership (FCCL), and a U.S. downstream limited liability company, WRB Refining LLC (WRB). We
use the equity method of accounting for both entities, with the operating results of our investment
in FCCL reflecting its use of the full-cost method of accounting for oil and gas exploration and
development activities.
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LUKOIL is an integrated energy company headquartered in Russia, with operations worldwide. In
2004, we made a joint announcement with LUKOIL of an agreement to form a broad-based strategic
alliance, whereby we would become a strategic equity investor in LUKOIL.
OOO Naryanmarneftegaz (NMNG) is a joint venture with LUKOIL, created in June 2005, to develop
resources in the northern part of Russias Timan-Pechora province. We have a 30 percent ownership
interest with a 50 percent governance interest. NMNG is working to develop the Yuzhno Khylchuyu
(YK) field. Production from the NMNG joint venture fields is transported via pipeline to LUKOILs
existing terminal at Varandey Bay on the Barents Sea and then shipped via tanker to international
markets.
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DCP Midstream owns and operates gas plants, gathering systems, storage facilities and fractionation
plants. In July 2005, ConocoPhillips and Duke Energy Corporation (Duke) restructured their
respective ownership levels in DCP Midstream, which resulted in DCP Midstream becoming a jointly
controlled venture, owned 50 percent by each company. This restructuring increased our ownership
in DCP Midstream to 50 percent from 30.3 percent through a series of direct and indirect transfers
of certain Canadian Midstream assets from DCP Midstream to Duke, a disproportionate cash
distribution from DCP Midstream to Duke from the sale of DCP Midstreams interest in TEPPCO
Partners, L.P., and a combined payment by ConocoPhillips to Duke and DCP Midstream of approximately
$840 million. Our interest in the Empress plant in Canada was not included in the initial
transaction as originally anticipated due to weather-related damage to the facility. Subsequently,
the Empress plant was sold to Duke on
August 1, 2005, for approximately $230 million. In the first quarter of 2005, as a part of equity
earnings, we recorded our $306 million (after-tax) equity share of the gain from DCP Midstreams
sale of its interest in TEPPCO.
CPChem manufactures and markets petrochemicals and plastics. At December 31, 2007, the book value
of our investment in CPChem was $2,203 million. Our 50 percent share of the total net assets of
CPChem was $2,080 million. This basis difference of $123 million is being amortized through 2020,
consistent with the remaining estimated useful lives of CPChem properties, plants and equipment.
See the Expropriated Assets section of Note 13Impairments, for information on the complete
impairment of our investments in the Hamaca and Petrozuata projects.
As part of our normal ongoing business operations and consistent with industry practice, we invest
and enter into numerous agreements with other parties to pursue business opportunities, which share
costs and apportion risks among the parties as governed by the agreements. Included in such
activity are loans made to certain affiliated companies. Loans are recorded within Loans and
advancesrelated parties when
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We entered into a credit agreement with Freeport LNG, whereby we will provide loan
financing of approximately $631 million, excluding accrued interest, for the construction
of an LNG facility. Through December 31, 2007, we have provided $594 million in loan
financing, and an additional $87 million of accrued interest. See Note 7Variable
Interest Entities (VIEs), for additional information.
We have an obligation to provide loan financing to Varandey Terminal Company for 30
percent of the costs of the terminal expansion. We estimate our total loan obligation for
the terminal expansion to be approximately $416 million at current exchange rates,
excluding interest to be accrued during construction. This amount will be adjusted as the
projects cost estimate and schedule are updated and the ruble exchange rate fluctuates.
Through December 31, 2007, we had provided $331 million in loan financing, and an
additional $32 million of accrued interest. See Note 7Variable Interest Entities (VIEs),
for additional information.
Qatargas 3 is an integrated project to produce and liquefy natural gas from Qatars
North field. We own a 30 percent interest in the project. The other participants in the
project are affiliates of Qatar Petroleum (68.5 percent) and Mitsui & Co., Ltd.
(1.5 percent). Our interest is held through a jointly owned company, Qatar Liquefied Gas
Company Limited (3), for which we use the equity method of accounting. Qatargas 3 secured
project financing of $4 billion in December 2005, consisting of $1.3 billion of loans from
export credit agencies (ECA), $1.5 billion from commercial banks, and $1.2 billion from
ConocoPhillips. The ConocoPhillips loan facilities have substantially the same terms as
the ECA and commercial bank facilities. Prior to project completion certification, all
loans, including the ConocoPhillips loan facilities, are guaranteed by the participants
based on their respective ownership interests. Accordingly, our maximum exposure to this
financing structure is $1.2 billion, excluding accrued interest. Upon completion
certification, which is expected in 2010, all project loan facilities, including the
ConocoPhillips loan facilities, will become non-recourse to the project participants. At
December 31, 2007, Qatargas 3 had $2.4 billion outstanding under all the loan facilities,
of which ConocoPhillips provided $690 million, and an additional $43 million of accrued
interest.
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Millions of Dollars
2007
2006
Gross
Accum.
Net
Gross
Accum.
Net
PP&E
DD&A
PP&E
PP&E
DD&A
PP&E
$
102,550
30,701
71,849
88,592
21,102
67,490
267
103
164
330
157
173
19,926
4,733
15,193
22,115
5,199
16,916
-
-
-
-
-
-
-
-
-
-
-
-
1,204
138
1,066
1,006
98
908
1,414
683
731
1,229
515
714
$
125,361
36,358
89,003
113,272
27,071
86,201
In April 2005, the FASB issued FSP FAS 19-1, Accounting for Suspended Well Costs (FSP FAS 19-1).
This FSP was issued to address whether there were circumstances that would permit the continued
capitalization of exploratory well costs beyond one year, other than when further exploratory
drilling is planned and major capital expenditures would be required to develop the project. We
adopted FSP FAS 19-1 effective January 1, 2005. There was no impact on our consolidated financial
statements from the adoption.
Millions of Dollars
2007
2006
2005
$
537
339
347
157
225
183
(58
)
(8
)
(81
)
(22
)
-
-
(25
)
(19
)
(110
)
$
589
*
537
*
339
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Millions of Dollars
2007
2006
2005
$
153
225
183
436
312
156
$
589
537
339
35
22
15
Millions of Dollars
Suspended Since
Project
Total
2006
2005
2004
2003
2002
2001
$
19
-
-
7
12
-
-
23
-
-
-
-
23
-
78
45
33
-
-
-
-
17
17
-
-
-
-
-
11
11
-
-
-
-
-
12
12
-
-
-
-
-
28
28
-
-
-
-
-
12
12
-
-
-
-
-
13
-
-
13
-
-
-
18
-
-
-
9
-
9
50
17
22
11
-
-
-
21
-
6
15
-
-
-
32
16
8
-
8
-
-
14
-
14
-
-
-
-
10
6
3
1
-
-
-
78
48
20
3
3
4
-
$
436
212
106
50
32
27
9
(1)
Additional appraisal wells planned.
(2)
Appraisal drilling complete; costs being incurred to assess development.
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Millions of Dollars
E&P
R&M
Total
$
11,423
3,900
15,323
16,615
-
16,615
-
229
229
(216
)
(354
)
(570
)
(110
)
1
(109
)
27,712
3,776
31,488
(1,925
)
-
(1,925
)
172
-
172
(191
)
(3
)
(194
)
(199
)
(6
)
(205
)
$
25,569
3,767
29,336
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Millions of Dollars
Gross Carrying
Accumulated
Net Carrying
Amount
Amortization
Amount
$
145
(60
)
85
14
(8
)
6
124
(62
)
62
37
(25
)
12
$
320
(155
)
165
$
144
(51
)
93
32
(12
)
20
139
(44
)
95
31
(24
)
7
$
346
(131
)
215
$
494
237
$
731
$
494
242
$
736
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On January 31, 2007, Venezuelas National Assembly passed a law allowing the president of Venezuela
to pass laws on certain matters by decree. On February 26, 2007, the president of Venezuela issued
a decree (the Nationalization Decree) mandating the termination of the then-existing structures
related to our heavy-oil ventures and oil production risk contracts and the transfer of all rights
relating to our heavy-oil ventures and oil production risk contracts to joint ventures (
empresas
mixtas
) that will be controlled by the Venezuelan national oil company or its subsidiaries.
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During 2007, 2006 and 2005, we recognized the following before-tax impairment charges, excluding
the impairment of expropriated assets:
Millions of Dollars
2007
2006
2005
$
73
55
2
398
160
2
-
-
30
-
300
-
91
168
8
(128
)
-
-
8
-
-
$
442
683
42
Increased asset retirement obligations for properties at the end of their economic life
for certain fields primarily located in the North Sea, totaling $175 million.
Downward reserve revisions and higher projected operating costs for fields in the United
States, Canada and the United Kingdom, totaling $80 million.
An abandoned project in Alaska resulting from increased taxes, totaling $28 million.
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Millions of Dollars
2007
2006
$
6,613
5,402
1,089
1,062
7,702
6,464
(441
)
(845
)
$
7,261
5,619
SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement
obligation 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
increases for the change in its present value, while the capitalized cost depreciates over the
useful life of the related asset.
Table of Contents
Millions of Dollars
2007
2006
$
5,402
3,901
310
248
76
154
-
732
843
299
(146
)
(130
)
(259
)*
(20
)
395
218
(8
)
-
$
6,613
5,402
Millions of Dollars
Except per Share
Amounts
$
13,600
9.76
9.60
Total environmental accruals at December 31, 2007 and 2006, were $1,089 million and $1,062 million,
respectively. The 2007 increase in total accrued environmental costs is due to new accruals and
accretion, partially offset by payments on accrued environmental costs.
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Table of Contents
Millions of Dollars
2007
2006
$
150
150
328
328
150
150
1,264
1,264
150
150
600
600
-
361
100
100
300
300
37
43
88
88
100
100
500
500
92
92
-
153
500
500
575
575
300
300
200
200
1,549
1,549
67
67
400
400
297
297
500
500
178
178
284
284
1,750
1,750
645
-
500
500
505
505
1,250
1,250
750
750
350
350
897
897
725
2,931
3,000
5,000
950
1,250
-
1,000
and 3.60% - 5.75% at year-end 2006
252
252
at year-end 2006
175
203
172
180
and 3.68% at year-end 2006
265
265
50
60
20,945
26,372
54
44
688
718
21,687
27,134
(1,398
)
(4,043
)
$
20,289
23,091
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Table of Contents
In June 2006, we issued a guarantee for 24 percent of the $2 billion in credit facilities
of Rockies Express Pipeline LLC (Rockies Express), which will be used to construct a natural
gas pipeline across a portion of the United States. At December 31, 2007, Rockies Express
had $1,625 million outstanding under the credit facilities, with our 24 percent guarantee
equaling $390 million. The maximum potential amount of future payments to third-party
lenders under the guarantee is estimated to be $480 million, which could become payable if
the credit facility is fully utilized and Rockies Express fails to meet its obligations under
the credit agreement. In addition, we also have a guarantee for 24 percent of $600 million
of Floating Rate Notes due 2009 issued by Rockies Express in September 2007. It is
anticipated final construction completion will be achieved in 2009, and refinancing will take
place at that time, making the debt non-recourse to ConocoPhillips. At December 31, 2007,
the total carrying value of these guarantees to third-party lenders was $12 million. See
Note 7Variable Interest Entities (VIEs), for additional information.
In December 2005, we issued a construction completion guarantee for 30 percent of the $4.0
billion in loan facilities of Qatargas 3, which will be used to construct an LNG train in
Qatar. Of the $4.0 billion in loan facilities, ConocoPhillips has committed to provide $1.2
billion. The maximum potential amount of future payments to third-party lenders under the
guarantee is estimated to be $850 million, which could become payable if the full debt
financing is utilized and completion of the Qatargas 3 project is not achieved. The project
financing will be non-recourse to ConocoPhillips upon certified completion, which is expected
in 2010. At December 31, 2007, the carrying value of the guarantee to the third-party
lenders was $11 million. For additional information, see Note 10Investments, Loans and
Long-Term Receivables.
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At December 31, 2007, we had guarantees outstanding for our portion of joint-venture debt
obligations, which have terms of up to 17 years. The maximum potential amount of future
payments
under the guarantees is approximately $90 million. Payment would be required if a joint
venture defaults on its debt obligations.
The Merey Sweeny, L.P. (MSLP) joint-venture project agreement requires the partners in the
venture to pay cash calls to cover operating expenses in the event the venture does not have
enough cash to cover operating expenses after setting aside the amount required for debt
service over the next 17 years. Although there is no maximum limit stated in the agreement,
the intent is to cover short-term cash deficiencies should they occur. Our maximum potential
future payments under the agreement are currently estimated to be $100 million, assuming such
a shortfall exists at some point in the future due to an extended operational disruption.
In February 2003, we entered into two agreements establishing separate guarantee
facilities of $50 million each for two LNG ships. 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 $100
million in total. To the extent we receive any such payments, our actual gross payments over
the 20 years could exceed that amount. In the event either ship is sold or a total loss
occurs, we also may have recourse to the sales or insurance proceeds to recoup payments made
under the guarantee facilities. For additional information, see Note 7Variable Interest
Entities (VIEs).
We have guarantees of the residual value of leased corporate aircraft. The maximum
potential payment under these guarantees at December 31, 2007, was $150 million.
In December 2007, we acquired a 50 percent equity interest in the Keystone Oil Pipeline
(Keystone) to form a 50/50 joint venture with TransCanada Corporation. Keystone plans to
construct a crude oil pipeline originating in Hardisty, Alberta, with delivery points at Wood
River and Patoka, Illinois, and Cushing, Oklahoma. In connection with certain planning and
construction activities, agreements were put in place with third parties to guarantee the
payments due. Our maximum potential amount of future payments under those agreements are
estimated to be $400 million, which could become payable if Keystone fails to meet its
obligations under the agreements noted above and the obligation cannot otherwise be
mitigated. Payments under the guarantees are contingent upon the partners not making
necessary equity contributions into Keystone; therefore, it is considered unlikely that
payments would be required. All but $15 million of the guarantees will terminate after
construction is completed, currently estimated to be in 2010.
We have other guarantees with maximum future potential payment amounts totaling $200
million, which consist primarily of dealer and jobber loan guarantees to support our
marketing business, guarantees to fund the short-term cash liquidity deficits of certain
joint ventures, one small construction completion guarantee, guarantees relating to the
startup of a refining joint venture, and guarantees of the lease payment obligations of a
joint venture. These guarantees generally extend up to 10 years or life of the venture and
payment would be required only if the dealer, jobber or lessee goes into default, if the
joint ventures have cash liquidity issues, if a construction project is not completed, if a
guaranteed party defaults on lease payments, or if an adverse decision occurs in the pending
lawsuit.
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Over the years, we have entered into various agreements to sell ownership interests in certain
corporations and joint ventures and have sold several assets, including downstream and midstream
assets, certain exploration and production assets, and downstream retail and wholesale sites that
gave rise to qualifying indemnifications. Agreements associated with these sales include
indemnifications for taxes, environmental liabilities, permits and licenses, employee claims, real
estate indemnity against tenant defaults, and litigation. The terms of these indemnifications vary
greatly. The majority of these indemnifications are related to environmental issues, the term is
generally indefinite and the maximum amount of future payments is generally unlimited. The
carrying amount recorded for these indemnifications at December 31, 2007, was $471 million. We
amortize the indemnification liability over the relevant time period, if one exists, based on the
facts and circumstances surrounding each type of indemnity. In cases where the indemnification
term is indefinite, we will reverse the liability when we have information the liability is
essentially relieved or amortize the liability over an appropriate time period as the fair value of
our indemnification exposure declines. Although it is reasonably possible future payments may
exceed amounts recorded, due to the nature of the indemnifications, it is not possible to make a
reasonable estimate of the maximum potential amount of future payments. Included in the carrying
amount recorded were $294 million of environmental accruals for known contamination that is
included in asset retirement obligations and accrued environmental costs at December 31, 2007. For
additional information about environmental liabilities, see Note 18Contingencies and Commitments.
We are subject to federal, state and local environmental laws and regulations. These may result in
obligations to remove or mitigate the effects on the environment of the placement, storage,
disposal or release of certain chemical, mineral and petroleum substances at various sites. When
we prepare our consolidated financial statements, we record accruals for environmental liabilities
based on managements best estimates, using all information that is available at the time. We
measure estimates and base liabilities on currently available facts, existing technology, and
presently enacted laws and regulations, taking into
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Our legal organization applies its knowledge, experience, and professional judgment to the specific
characteristics of our cases, employing a litigation management process to manage and monitor the
legal proceedings against us. Our process facilitates the early evaluation and quantification of
potential exposures in individual cases. This process also enables us to track those cases which
have been scheduled for trial, as well as the pace of settlement discussions in individual matters.
Based on professional judgment and experience in using these litigation management tools and
available information about current developments in all our cases, our legal organization believes
that there is only a remote likelihood that future costs related to known contingent liability
exposures will exceed current accruals by an amount that would have a material adverse impact on
our consolidated financial statements.
We have contingent liabilities resulting from throughput agreements with pipeline and processing
companies not associated with financing arrangements. Under these agreements, we may be required
to provide any such company with additional funds through advances and penalties for fees related
to
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We have certain throughput agreements and take-or-pay agreements that are in support of financing
arrangements. The agreements typically provide for natural gas or crude oil transportation to be
used in the ordinary course of the companys business. The aggregate amounts of estimated payments
under these various agreements are: 2008$97 million; 2009$97 million; 2010$97 million;
2011$98 million; 2012$97 million; and 2013 and after$542 million. Total payments under the
agreements were $67 million in 2007, $66 million in 2006 and $52 million in 2005.
We, and certain of our 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 market opportunities. Our use of derivative instruments is governed by an
Authority Limitations document approved by our Board of Directors 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 Senior
Vice President of Commercial monitors commodity price risk. Both report to the Chief Executive
Officer. The Commercial organization 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.
Millions of Dollars
2007
2006
$
453
924
89
82
$
542
1,006
$
493
681
67
126
$
560
807
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Balance physical systems. In addition to cash settlement prior to contract expiration,
exchange traded futures contracts may also be settled by physical delivery of the
commodity, providing another source of supply to meet our refinery requirements or
marketing demand.
Meet customer needs. Consistent with our policy to generally remain exposed to market
prices, we use swap contracts to convert fixed-price sales contracts, which are often
requested by natural gas and refined product consumers, to a floating market price.
Manage the risk to our cash flows from price exposures on specific crude oil, natural
gas, refined product and electric power transactions.
Enable us to use the market knowledge gained from these activities to do a limited
amount of trading not directly related to our physical business. For the years ended
December 31, 2007, 2006 and 2005, the gains or losses from this activity were not material
to our cash flows or net income.
Our financial instruments that are potentially exposed to concentrations of credit risk consist
primarily of cash equivalents, over-the-counter derivative contracts, and trade receivables. Our
cash equivalents are placed in high-quality commercial paper, money market funds and time deposits
with major international banks and financial institutions. The credit risk from our
over-the-counter derivative contracts, such as forwards and swaps, derives from the counterparty to
the transaction, typically a major bank or financial institution. We closely monitor these credit
exposures against predetermined credit limits, including the continual exposure adjustments that
result from market movements. Individual counterparty exposure is managed within these limits, and
includes the use of cash-call margins when appropriate, thereby reducing the risk of significant
non-performance. We also use futures contracts, but futures have a negligible credit risk because
they are traded on the New York Mercantile Exchange or the ICE Futures.
We used the following methods and assumptions to estimate the fair value of 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.
Investment in LUKOIL shares: See Note 10Investments, Loans and Long-Term Receivables,
for a discussion of the carrying value and fair value of our investment in LUKOIL shares.
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Debt: The carrying amount of our floating-rate debt approximates fair value. The fair
value of the fixed-rate debt is estimated based on quoted market prices.
Fixed-rate 5.3 percent joint venture acquisition obligation: Fair value is estimated
based on the net present value of the future cash flows, discounted at a year-end effective
yield rate of 4.9 percent, based on yields of U.S. Treasury securities of similar average
duration adjusted for our average credit risk spread and the amortizing nature of the
obligation principal. See Note 16Joint Venture Acquisition Obligation, for additional
information.
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.
Futures: Fair values are based on quoted market prices obtained from the New York
Mercantile Exchange, the ICE Futures, or other traded exchanges.
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.
Millions of Dollars
Carrying Amount
Fair Value
2007
2006
2007
2006
$
47
47
47
47
495
959
495
959
21,633
27,090
23,101
27,741
6,887
-
7,031
-
29
26
29
26
-
10
-
10
531
771
531
771
We have 500 million shares of preferred stock authorized, par value $.01 per share, none of which
was issued or outstanding at December 31, 2007 or 2006.
The minority interest owner in Ashford Energy Capital S.A. is entitled to a cumulative annual
preferred return on its investment, based on three-month LIBOR rates plus 1.32 percent. The
preferred return at December 31, 2007 and 2006, was 6.55 percent and 6.69 percent, respectively.
At December 31, 2007 and 2006, the minority interest was $508 million, for both periods. Ashford
Energy Capital S.A. continues to be consolidated in our financial statements under the provisions
of FIN 46(R) because we are the primary beneficiary. See Note 7Variable Interest Entities
(VIEs), for additional information.
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Millions
of Dollars
$
732
593
439
340
397
807
3,308
(186
)*
$
3,122
*Includes $90 million related to railroad cars subleased to CPChem, a related party.
Table of Contents
Millions of Dollars
2007
2006
2005
$
855
698
564
(82
)
(103
)
(66
)
$
773
595
498
*
Includes $27 million, $29 million and $28 million of contingent rentals in 2007, 2006 and 2005,
respectively. Contingent rentals primarily are related to retail sites and refining
equipment, and are based on volume of product sold or throughput.
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An analysis of the projected benefit obligations for our pension plans and accumulated benefit
obligations for our postretirement health and life insurance plans follows:
Millions of Dollars
Pension Benefits
Other Benefits
2007
2006
2007
2006
U.S.
Intl.
U.S.
Intl.
$
4,113
3,087
3,703
2,495
778
815
175
98
174
87
14
14
229
161
210
134
45
47
-
10
-
9
28
31
-
-
-
-
6
6
2
(68
)
1
-
-
(26
)
109
(294
)
57
79
(6
)
(59
)
-
-
275
42
-
36
-
-
-
-
-
-
(347
)
(97
)
(307
)
(77
)
(81
)
(86
)
-
1
-
-
-
-
-
1
-
1
-
-
-
186
-
317
8
-
$
4,281
3,085
4,113
3,087
792
778
$
3,666
2,550
3,493
2,585
$
2,863
2,185
2,183
1,725
3
3
-
-
214
44
-
-
-
-
-
-
-
-
237
169
356
142
-
-
385
185
417
120
47
49
-
10
-
9
28
31
-
-
-
-
6
6
(347
)
(97
)
(307
)
(77
)
(81
)
(86
)
-
149
-
222
-
-
$
3,138
2,601
2,863
2,185
3
3
$
(1,143
)
(484
)
(1,250
)
(902
)
(789
)
(775
)
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Millions of Dollars
Pension Benefits
Other Benefits
2007
2006
2007
2006
U.S.
Intl.
U.S.
Intl.
$
98
16
(6
)
(9
)
(3
)
(11
)
(50
)
(48
)
(1,137
)
(573
)
(1,247
)
(907
)
(739
)
(727
)
$
(1,143
)
(484
)
(1,250
)
(902
)
(789
)
(775
)
6.00
%
5.90
5.75
5.15
6.20
5.95
4.00
4.80
4.00
4.70
5.75
%
5.15
5.50
5.05
5.95
5.70
7.00
6.50
7.00
6.50
7.00
7.00
4.00
4.70
4.00
4.35
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Millions of Dollars
Pension Benefits
Other Benefits
2007
2006
2007
2006
U.S.
Intl.
U.S.
Intl.
$
587
123
577
460
(185
)
(200
)
71
(30
)
79
44
15
28
Millions of Dollars
2007
Pension
Other
Benefits
Benefits
U.S.
Intl.
$
(72
)
289
5
62
48
(20
)
$
(10
)
337
(15
)
$
(2
)
67
-
10
7
13
$
8
74
13
Millions of Dollars
Pension
Other Benefits
U.S.
Intl.
$
64
12
(19
)
10
1
13
Table of Contents
Millions of Dollars
Pension Benefits
Other Benefits
2007
2006
2005
2007
2006
2005
U.S.
Intl.
U.S.
Intl.
U.S.
Intl.
$
175
98
174
87
151
69
14
14
19
229
161
210
134
174
122
45
47
48
(204
)
(147
)
(169
)
(121
)
(126
)
(105
)
10
7
9
7
4
7
13
19
19
62
48
89
41
55
33
(20
)
(16
)
(6
)
$
272
167
313
148
258
126
52
64
80
Millions of Dollars
One-Percentage-Point
Increase
Decrease
$
2
(3
)
33
(39
)
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Pension
U.S.
International
2007
2006
Target
2007
2006
Target
64
%
66
60
48
50
51
36
33
30
46
44
43
5
5
5
5
1
5
1
1
1
100
%
100
100
100
100
100
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Pension
U.S.
International
2007
2006
2007
2006
62
%
72
48
50
33
21
46
44
5
6
-
-
-
-
5
5
-
1
1
1
100
%
100
100
100
Millions of Dollars
Pension Benefits
Other Benefits
Subsidy
U.S.
Intl.
Gross
Receipts
$
326
98
55
7
294
107
57
8
320
111
60
9
356
116
63
9
391
123
64
10
2,537
730
342
61
Most U.S. employees (excluding retail service station employees) are eligible to participate in
either the ConocoPhillips Savings Plan (CPSP) or the Burlington Resources Savings Plan (BR Savings
Plan). Employees can deposit up to 30 percent of their pay in the thrift feature of the CPSP to a
choice of approximately 32 investment funds. ConocoPhillips matches deposits, up to 1.25 percent
of eligible pay. Company contributions charged to expense for the CPSP and predecessor plans,
excluding the stock savings feature (discussed below), were $21 million in 2007, $19 million in
2006, and $18 million in 2005. For the BR Savings Plan, ConocoPhillips matches deposits, up to 6
percent or 8 percent of the employees eligible pay based upon years of service. During 2007,
ConocoPhillips contributed $5 million to the BR Savings Plan, to match eligible contributions by
employees.
Table of Contents
2007
2006
9,040,949
10,499,837
17,648,368
18,501,772
26,689,317
29,001,609
The 2004 Omnibus Stock and Performance Incentive Plan (the Plan) was approved by shareholders in
May 2004. Over its 10-year life, the Plan allows the issuance of up to 70 million shares of our
common stock for compensation to our employees, directors and consultants. After approval of the
Plan, the heritage plans were no longer used for further awards. Of the 70 million shares
available for issuance under the Plan, 40 million shares of common stock are available for
incentive stock options, and no more than 40 million shares may be used for awards in stock.
Table of Contents
Millions of Dollars
2007
2006
2005
$
242
140
226
85
54
84
Table of Contents
Weighted-
Weighted-Average
Millions of Dollars
Average
Grant-Date
Aggregate
Options
Exercise Price
Fair Value
Intrinsic Value
74,263,922
$ 25.97
2,567,000
47.87
$ 10.92
(19,265,175
)
24.85
$ 615
(169,001
)
34.83
57,396,746
$ 27.31
4,927,116
33.95
1,809,281
59.33
$ 16.16
(9,737,765
)
24.32
$ 416
(341,759
)
60.58
(4,840
)
50.16
54,048,779
$ 29.31
2,530,648
66.37
$ 17.86
(12,176,988
)
26.29
$ 926
(268,177
)
65.02
(29,407
)
17.00
44,104,855
$ 32.06
41,386,111
$ 30.26
$ 2,407
39,721,035
$ 28.86
$ 2,366
2007
2006
2005
4.77
%
4.63
3.92
2.50
%
2.50
2.50
26.10
%
26.10
22.50
6.70
7.18
7.18
Table of Contents
2007
2006
2005
High
Low
High
Low
High
Low
4.90
%
4.77
5.15
4.54
4.45
3.33
2.50
2.50
2.50
2.50
2.50
2.50
26.10
26.10
26.50
25.90
25.70
22.30
Table of Contents
Weighted-Average
Millions of Dollars
Stock Units
Grant-Date Fair Value
Total Fair Value
2,316,690
$
32.10
1,668,192
46.95
(57,262
)
37.81
(35,216
)
$
2
3,892,404
$
38.34
1,480,294
57.77
(118,461
)
45.92
(167,099
)
$
11
5,087,138
$
43.75
1,721,521
65.33
(162,992
)
52.57
(975,756
)
$
36
5,669,911
$
51.30
5,314,557
$
50.61
Table of Contents
Performance Share
Grant-Date
Millions of Dollars
Stock Units
Fair Value
Total Fair Value
-
-
1,641,216
$
59.08
-
(184,975
)
$
12
1,456,241
$
59.08
1,349,475
66.37
(22,062
)
(178,357
)
$
12
2,605,297
$
62.49
1,198,599
$
41.97
Weighted-Average
Millions of Dollars
Stock Units
Grant-Date Fair Value
Total Fair Value
3,461,899
$
28.44
89,676
54.08
9,116
43.97
(135,168
)
$
7
(80,582
)
28.93
3,344,941
$
29.16
248,421
64.48
523,769
64.95
(239,257
)
$
16
(275,499
)
47.56
3,602,375
$
33.68
293,024
67.30
(227,766
)
$
17
(180,489
)
50.39
3,487,144
$
34.41
370,303
$
65.65
Table of Contents
Millions of Dollars
2007
2006
2005
$
3,944
4,313
3,434
312
(77
)
375
7,035
7,581
5,093
(474
)
392
384
602
622
538
(38
)
(48
)
83
$
11,381
12,783
9,907
Table of Contents
Millions of Dollars
2007
2006
$
23,344
22,733
1,300
1,178
197
339
1,501
1,305
725
438
27,067
25,993
1,603
1,730
3,135
2,330
390
408
539
820
1,716
1,283
251
230
7,634
6,801
(1,269
)
(822
)
6,365
5,979
$
20,702
20,014
Table of Contents
Millions
of Dollars
$
912
273
145
(168
)
(15
)
(4
)
$
1,143
Table of Contents
Percent of
Millions of Dollars
Pretax Income
2007
2006
2005
2007
2006
2005
$
13,939
13,376
12,486
59.9
%
47.2
53.0
9,333
14,957
11,061
40.1
52.8
47.0
$
23,272
28,333
23,547
100.0
%
100.0
100.0
$
8,145
9,917
8,241
35.0
%
35.0
35.0
3,254
2,697
1,562
14.0
9.5
6.6
(250
)
(119
)
(106
)
(1.1
)
(.4
)
(.4
)
367
373
404
1.6
1.3
1.7
(135
)
(85
)
(194
)
(.6
)
(.3
)
(.8
)
$
11,381
12,783
9,907
48.9
%
45.1
42.1
Table of Contents
Millions of Dollars
Tax Expense
Before-Tax
(Benefit)
After-Tax
$
65
20
45
30
12
18
95
32
63
222
67
155
90
32
58
312
99
213
(2
)
-
(2
)
3,214
139
3,075
(3
)
1
(4
)
$
3,616
271
3,345
$
53
20
33
913
(100
)
1,013
4
-
4
$
970
(80
)
1,050
$
(101
)
(45
)
(56
)
(10
)
(4
)
(6
)
(786
)
(69
)
(717
)
(3
)
(4
)
1
$
(900
)
(122
)
(778
)
Table of Contents
Millions of Dollars
2007
2006
$
(465
)
(665
)
5,033
1,958
(8
)
(4
)
$
4,560
1,289
Millions of Dollars
2007
2006
2005
$
-
16,343
-
7,313
-
-
2,428
-
-
-
-
732
919
464
511
$
1,040
958
500
11,330
13,050
8,507
Table of Contents
Millions of Dollars
Except Per Share Amounts
2007
2006
2005
$
1,369
1,409
807
449
136
85
1,818
1,545
892
(565
)
(458
)
(395
)
$
1,253
1,087
497
$
342
165
127
1,348
116
278
52
239
-
229
165
60
$
1,971
685
465
$
160
117
125
$
84
87
84
$
1,493
1,415
1,265
$
1.64
1.44
1.18
$
216
(44
)
7
(2
)
-
7
(13
)
60
(52
)
5
-
(1
)
-
-
-
1
1
(1
)
(120
)
65
(42
)
$
87
82
(82
)
Table of Contents
Millions of Dollars
2007
2006
*
2005
*
$
10,949
8,808
7,719
15,722
7,072
6,089
416
386
380
99
(13
)
30
(a)
We sold natural gas to DCP Midstream and crude oil to the Malaysian Refining Company Sdn.
Bhd. (MRC), among others, for processing and marketing. Natural gas liquids, solvents and
petrochemical feedstocks were sold to Chevron Phillips Chemical Company LLC (CPChem), gas oil
and hydrogen feedstocks were sold to Excel Paralubes and refined products were sold primarily
to CFJ Properties and LUKOIL. Natural gas, crude oil, blendstock and other intermediate
products were sold to WRB Refining LLC. We also sold various international marketing
companies to LUKOIL in the second quarter of 2007. In addition, we charged several of our
affiliates including CPChem, Merey Sweeny L.P. (MSLP) and Hamaca Holding LLC (until
expropriation on June 26, 2007) for the use of common facilities, such as steam generators,
waste and water treaters, and warehouse facilities.
(b)
We purchased refined products from WRB Refining. We purchased natural gas and natural gas
liquids from DCP Midstream and CPChem for use in our refinery processes and other feedstocks
from various affiliates. We purchased crude oil from LUKOIL, upgraded crude oil from
Petrozuata C.A. (until expropriation on June 26, 2007) and refined products from MRC. We also
paid fees to various pipeline equity companies for transporting finished refined products and
a price upgrade to MSLP for heavy crude processing. We purchased base oils and fuel products
from Excel Paralubes for use in our refinery and specialty businesses.
(c)
We paid processing fees to various affiliates. Additionally, we paid crude oil
transportation fees to pipeline equity companies.
(d)
We paid and/or received interest to/from various affiliates, including FCCL Oil Sands
Partnership. See Note 10Investments, Loans and Long-Term Receivables, for additional
information on loans to affiliated companies.
Table of Contents
1)
E&PThis segment primarily explores for, produces, transports and markets crude oil,
natural gas and natural gas liquids on a worldwide basis. At December 31, 2007, our E&P
operations were producing in the United States, Norway, the United Kingdom, the
Netherlands, Canada, Nigeria, Ecuador, Argentina, offshore Timor-Leste in the Timor Sea,
Australia, China, Indonesia, Algeria, Libya, Vietnam, and Russia. The E&P segments U.S.
and international operations are disclosed separately for reporting purposes.
2)
MidstreamThis segment gathers, processes and markets natural gas produced by
ConocoPhillips and others, and fractionates and markets natural gas liquids, primarily in
the United States and Trinidad. The Midstream segment primarily consists of our 50 percent
equity investment in DCP Midstream.
3)
R&MThis segment purchases, refines, markets and transports crude oil and petroleum
products, mainly in the United States, Europe and Asia. At December 31, 2007, we owned or
had an interest in 12 refineries in the United States, one in the United Kingdom, one in
Ireland, two in Germany, and one in Malaysia. The R&M segments U.S. and international
operations are disclosed separately for reporting purposes.
4)
LUKOIL InvestmentThis segment represents our investment in the ordinary shares of
LUKOIL, an international, integrated oil and gas company headquartered in Russia. At
December 31, 2007, our ownership interest was 20 percent based on issued shares, and 20.6
percent based on estimated shares outstanding. See Note 10Investments, Loans and
Long-Term Receivables, for additional information.
5)
ChemicalsThis segment manufactures and markets petrochemicals and plastics on a
worldwide basis. The Chemicals segment consists of our 50 percent equity investment in
CPChem.
6)
Emerging BusinessesThis segment represents our investment in new technologies or
businesses outside our normal scope of operations. Activities within this segment are
currently focused on power generation and other items, such as carbon-to-liquids,
technology solutions, and alternative energy and programs, such as advanced hydrocarbon
processes, energy conversion technologies, new petroleum-based products, and renewable
fuels.
Table of Contents
Millions of Dollars
2007
2006
2005
$
36,974
35,335
35,159
24,617
28,111
21,692
(6,096
)
(5,438
)
(4,075
)
(7,341
)
(7,842
)
(4,251
)
48,154
50,166
48,525
5,106
4,461
4,041
(245
)
(1,037
)
(955
)
4,861
3,424
3,086
96,154
95,314
97,251
38,598
35,439
30,633
(540
)
(855
)
(593
)
(11
)
(21
)
(11
)
134,201
129,877
127,280
-
-
-
10
13
14
656
675
618
(458
)
(515
)
(426
)
198
160
192
13
10
13
-
-
332
$
187,437
183,650
179,442
Table of Contents
Millions of Dollars
2007
2006
2005
$
11
20
19
302
782
825
313
802
844
599
618
829
1,710
466
388
240
151
227
1,950
617
615
1,875
1,481
756
350
665
413
-
5
-
-
-
-
$
5,087
4,188
3,457
$
2,231
2,545
2,349
6,372
7,584
5,145
8,603
10,129
7,494
237
248
214
2,571
2,334
2,124
113
218
212
2,684
2,552
2,336
45
37
25
(13
)
171
93
(33
)
(2
)
(18
)
(142
)
(352
)
(237
)
$
11,381
12,783
9,907
$
4,248
4,348
4,288
367
5,500
4,142
4,615
9,848
8,430
453
476
688
4,615
3,915
3,329
1,308
566
844
5,923
4,481
4,173
1,818
1,425
714
359
492
323
(8
)
15
(21
)
(1,269
)
(1,187
)
(778
)
$
11,891
15,550
13,529
Table of Contents
Millions of Dollars
2007
2006
2005
$
1,059
690
336
12,055
4,346
3,789
13,114
5,036
4,125
1,178
1,319
1,446
3,500
698
662
1,091
948
819
4,591
1,646
1,481
11,162
9,564
5,549
2,203
2,255
2,158
79
-
-
-
-
18
$
32,327
19,820
14,777
$
48
158
-
$
35,160
35,523
18,434
59,412
48,143
31,662
25,569
27,712
11,423
120,141
111,378
61,519
2,016
2,045
2,109
24,336
22,936
20,693
9,766
9,135
6,096
3,767
3,776
3,900
37,869
35,847
30,689
11,164
9,564
5,549
2,225
2,379
2,324
1,230
977
858
3,112
2,591
3,951
$
177,757
164,781
106,999
Table of Contents
Millions of Dollars
2007
2006
2005
$
246
106
113
1,066
1,087
497
$
96
57
12
187
-
-
Millions of Dollars
Other
United
United
Foreign
Worldwide
States
Norway
Kingdom
Canada
Russia
Countries
Consolidated
$
131,433
2,479
20,680
4,727
-
28,118
187,437
$
50,714
6,180
7,995
24,758
13,359
18,324
121,330
$
127,869
2,480
19,510
5,554
-
28,237
183,650
$
48,418
4,982
7,755
14,831
10,886
19,149
106,021
$
130,874
3,280
19,043
5,676
-
20,569
179,442
$
33,161
4,380
5,564
5,328
6,342
14,671
69,446
**Defined as net properties, plants and equipment plus investments in and advances to affiliated companies.
Table of Contents
Table of Contents
Table of Contents
The recording and reporting of proved reserves are governed by criteria established by regulations
of the SEC. Those regulations define proved reserves as those estimated quantities of hydrocarbons
that geological and engineering data demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and operating conditions. Proved
reserves are further classified as either developed or undeveloped. Proved developed reserves are
the quantities expected to be recovered through existing wells with existing equipment and
operating methods, while proved undeveloped reserves are the quantities expected to be recovered
from new wells on undrilled acreage, or from an existing well where relatively major expenditures
are required for recompletion.
Table of Contents
n
Proved Reserves Worldwide
Years Ended
Crude Oil
December 31
Millions of Barrels
Consolidated Operations
Lower
Total
Asia
Middle East
Russia and
Other
Equity
Alaska
48
U.S.
Canada
Europe
Pacific
and Africa
Caspian
Areas
Total
Affiliates
1,536
170
1,706
47
851
255
127
181
-
3,167
1,982
31
6
37
4
34
7
(21
)
(11
)
-
50
6
15
1
16
-
-
-
-
-
-
16
-
-
3
3
-
-
-
238
20
-
261
515
31
13
44
1
17
49
4
-
17
132
60
(108
)
(21
)
(129
)
(8
)
(94
)
(37
)
(20
)
-
-
(288
)
(130
)
-
(2
)
(2
)
-
-
-
-
-
-
(2
)
(3
)
1,505
170
1,675
44
808
274
328
190
17
3,336
2,430
(118
)
(11
)
(129
)
58
(65
)
(12
)
(18
)
(74
)
2
(238
)
(35
)
13
1
14
-
5
63
-
-
-
82
-
-
181
181
16
-
13
42
-
17
269
393
53
9
62
4
6
8
3
-
-
83
74
(97
)
(37
)
(134
)
(9
)
(90
)
(39
)
(39
)
-
(3
)
(314
)
(171
)
-
(18
)
(18
)
-
-
-
-
-
-
(18
)
(1
)
1,356
295
1,651
113
664
307
316
116
33
3,200
2,690
24
19
43
28
10
(23
)
(13
)
1
(3
)
43
202
25
16
41
-
-
-
-
-
-
41
-
-
-
-
-
-
-
-
-
-
-
403
26
15
41
3
8
73
16
-
-
141
303
(96
)
(36
)
(132
)
(7
)
(76
)
(32
)
(29
)
-
(4
)
(280
)
(172
)
-
(1
)
(1
)
(16
)
(1
)
(6
)
-
-
(17
)
(41
)
(1,028
)
1,335
308
1,643
121
605
319
290
117
9
3,104
2,398
-
-
-
-
-
-
-
800
1,182
-
1,982
-
-
-
-
-
-
46
1,295
1,089
-
2,430
-
-
-
-
-
-
60
1,607
1,023
-
2,690
-
-
-
623
-
-
70
1,705
-
-
2,398
1,415
148
1,563
46
429
207
121
-
-
2,366
-
1,359
158
1,517
42
409
202
326
-
-
2,496
-
1,254
281
1,535
50
359
181
292
-
13
2,430
-
1,238
281
1,519
51
337
146
259
-
9
2,321
-
-
-
-
-
-
-
-
624
491
-
1,115
-
-
-
-
-
-
-
1,013
472
-
1,485
-
-
-
-
-
-
-
1,293
369
-
1,662
-
-
-
45
-
-
-
1,336
-
-
1,381
Revisions
: In 2007 for our equity affiliate operations, revisions were primarily
attributable to LUKOIL. In 2006, revisions in Alaska were primarily a result of reservoir
performance.
Purchases
: In 2007 for our equity affiliate operations, purchases reflect the
formation of FCCL. In 2006, purchases in the Lower 48 were primarily related to our
acquisition of Burlington Resources in March 2006. In 2006 and 2005 for our equity affiliate
operations, purchases were mainly attributable to acquiring additional interests in LUKOIL.
In 2005, purchases in the Middle East and Africa were attributable to our re-entry into Libya.
Table of Contents
Extensions and Discoveries
: In 2007 for our equity affiliate operations,
extensions and discoveries were primarily associated with FCCL.
Sales
: In 2007 for our equity affiliates, sales were primarily due to the
expropriation of our oil interests in Venezuela.
Table of Contents
Years Ended
Natural Gas
December 31
Billions of Cubic Feet
Consolidated Operations
Lower
Total
Asia
Middle East
Russia and
Other
Equity
Alaska
48
U.S.
Canada
Europe
Pacific
and Africa
Caspian
Areas
Total
Affiliates
3,344
4,234
7,578
975
3,285
3,773
1,104
119
-
16,834
862
260
(43
)
217
72
83
(20
)
-
(3
)
-
349
51
-
1
1
-
-
-
-
-
-
1
-
7
163
170
-
1
8
-
13
-
192
453
5
270
275
78
79
85
2
-
5
524
1,212
(144
)
(449
)
(593
)
(155
)
(386
)
(146
)
(45
)
-
-
(1,325
)
(30
)
-
(62
)
(62
)
-
-
-
-
-
-
(62
)
-
3,472
4,114
7,586
970
3,062
3,700
1,061
129
5
16,513
2,548
43
(87
)
(44
)
(123
)
(293
)
71
(64
)
(31
)
(39
)
(523
)
(310
)
-
4
4
-
1
-
-
-
-
5
-
6
5,258
5,264
2,466
432
25
94
-
129
8,410
325
23
551
574
353
64
6
58
-
-
1,055
925
(130
)
(770
)
(900
)
(356
)
(414
)
(233
)
(62
)
-
(6
)
(1,971
)
(99
)
-
(43
)
(43
)
-
-
-
-
-
-
(43
)
-
3,414
9,027
12,441
3,310
2,852
3,569
1,087
98
89
23,446
3,389
120
446
566
(41
)
91
(47
)
(26
)
-
(12
)
531
(327
)
5
1
6
-
-
-
-
-
-
6
-
-
30
30
-
-
-
-
-
-
30
-
5
539
544
143
29
28
23
-
-
767
364
(113
)
(835
)
(948
)
(404
)
(369
)
(224
)
(55
)
-
(7
)
(2,007
)
(103
)
-
(5
)
(5
)
(170
)
(20
)
(74
)
-
-
(5
)
(274
)
(384
)
3,431
9,203
12,634
2,838
2,583
3,252
1,029
98
65
22,499
2,939
-
-
-
-
-
-
-
661
201
-
862
-
-
-
-
-
-
1,063
1,197
288
-
2,548
-
-
-
-
-
-
1,573
1,429
387
-
3,389
-
-
-
-
-
-
1,925
1,014
-
-
2,939
3,194
3,989
7,183
934
2,467
1,520
522
-
-
12,626
-
3,316
3,966
7,282
918
2,393
2,600
1,060
-
-
14,253
-
3,336
7,484
10,820
2,672
2,314
3,105
1,029
-
24
19,964
-
3,344
7,417
10,761
2,328
2,177
2,857
963
-
26
19,112
-
-
-
-
-
-
-
-
207
118
-
325
-
-
-
-
-
-
-
581
155
-
736
-
-
-
-
-
-
-
655
173
-
828
-
-
-
-
-
-
-
698
-
-
698
Purchases
: In 2006 for our consolidated operations, purchases were primarily
related to our acquisition of Burlington Resources.
Extensions and Discoveries
: In 2006 for our equity affiliate operations,
extensions and discoveries were primarily in Qatar and LUKOIL. In 2005, extensions and
discoveries for our equity affiliate operations were primarily in Qatar.
Table of Contents
Years Ended
Natural Gas Liquids
December 31
Millions of Barrels
Consolidated Operations
Lower
Total
Asia
Middle East
Russia and
Other
Equity
Alaska
48
U.S.
Canada
Europe
Pacific
and Africa
Caspian
Areas
Total
Affiliates
153
88
241
26
48
71
4
-
-
390
-
-
17
17
1
6
4
-
-
-
28
-
-
-
-
-
-
-
-
-
-
-
-
-
8
8
-
-
-
-
-
-
8
-
-
5
5
-
1
2
-
-
-
8
21
(7
)
(9
)
(16
)
(3
)
(5
)
(6
)
(1
)
-
-
(31
)
-
-
(1
)
(1
)
-
-
-
-
-
-
(1
)
-
146
108
254
24
50
71
3
-
-
402
21
(1
)
24
23
1
(4
)
(1
)
(1
)
-
-
18
-
-
-
-
-
-
-
-
-
-
-
-
-
328
328
56
-
-
-
-
-
384
-
-
14
14
7
-
-
-
-
-
21
11
(6
)
(22
)
(28
)
(9
)
(5
)
(7
)
-
-
-
(49
)
-
-
(2
)
(2
)
-
-
-
-
-
-
(2
)
-
139
450
589
79
41
63
2
-
-
774
32
1
31
32
(4
)
-
(2
)
-
-
-
26
20
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
12
12
2
1
3
-
-
-
18
7
(7
)
(27
)
(34
)
(10
)
(4
)
(5
)
(1
)
-
-
(54
)
-
-
-
-
(2
)
-
(3
)
-
-
-
(5
)
-
133
466
599
65
38
56
1
-
-
759
59
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
21
-
-
-
21
-
-
-
-
-
-
32
-
-
-
32
-
-
-
-
-
-
39
20
-
-
59
153
82
235
25
34
71
4
-
-
369
-
146
106
252
23
31
64
2
-
-
372
-
139
346
485
64
28
56
2
-
-
635
-
133
343
476
53
33
54
1
-
-
617
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
18
-
-
18
Purchases
: In 2006 for our consolidated operations, purchases were related to
our acquisition of Burlington Resources.
Table of Contents
n
Results of Operations
Year Ended
Millions of Dollars
December 31
Consolidated Operations
Lower
Total
Asia
Middle East
Russia and
Other
Equity
Alaska
48
U.S.
Canada
Europe
Pacific
and Africa
Caspian
Areas
Total
Affiliates
$
4,659
5,422
10,081
3,406
5,701
3,383
1,038
-
240
23,849
5,212
2,344
2,986
5,330
-
2,729
267
1,157
-
-
9,483
3,427
173
94
267
430
330
252
201
1
3
1,484
71
7,176
8,502
15,678
3,836
8,760
3,902
2,396
1
243
34,816
8,710
775
1,232
2,007
874
1,029
410
251
-
41
4,612
906
1,663
628
2,291
70
45
129
18
2
98
2,653
3,675
104
318
422
247
105
130
77
24
12
1,017
68
583
2,559
3,142
1,661
1,394
608
204
-
-
7,009
551
-
-
-
-
-
-
-
-
4,588
4,588
-
28
43
71
27
188
26
-
-
155
467
-
412
553
965
137
335
101
24
-
64
1,626
770
(64
)
72
8
(96
)
46
(26
)
34
56
37
59
57
37
48
85
47
132
9
3
1
-
277
7
3,638
3,049
6,687
869
5,486
2,515
1,785
(82
)
(4,752
)
12,508
2,676
1,248
1,091
2,339
237
3,595
982
1,545
(28
)
1
8,671
844
2,390
1,958
4,348
632
1,891
1,533
240
(54
)
(4,753
)
3,837
1,832
(135
)
35
(100
)
280
48
67
25
33
197
550
214
$
2,255
1,993
4,248
912
1,939
1,600
265
(21
)
(4,556
)
4,387
2,046
$
-
-
-
98
-
-
(5
)
1,554
185
-
1,832
Table of Contents
Year Ended
Millions of Dollars
December 31
Consolidated Operations
Lower
Total
Asia
Middle East
Russia and
Other
Equity
Alaska
48
U.S.
Canada
Europe
Pacific
and Africa
Caspian
Areas
Total
Affiliates
$
4,491
4,881
9,372
2,951
5,950
3,493
1,743
-
140
23,649
5,161
2,023
2,550
4,573
-
2,954
271
764
-
-
8,562
2,821
2
56
58
145
14
(8
)
127
-
4
340
108
6,516
7,487
14,003
3,096
8,918
3,756
2,634
-
144
32,551
8,090
708
893
1,601
706
814
324
215
-
27
3,687
739
914
554
1,468
52
37
91
10
1
30
1,689
3,444
105
222
327
246
73
121
44
32
17
860
46
460
2,272
2,732
1,155
1,200
512
220
1
21
5,841
461
-
15
15
131
-
10
-
-
19
175
-
610
555
1,165
104
316
89
18
-
10
1,702
420
11
44
55
15
87
18
38
43
28
284
52
34
36
70
39
97
8
2
-
-
216
6
3,674
2,896
6,570
648
6,294
2,583
2,087
(77
)
(8
)
18,097
2,922
1,409
1,064
2,473
(193
)
4,578
1,061
1,931
(13
)
(7
)
9,830
891
2,265
1,832
4,097
841
1,716
1,522
156
(64
)
(1
)
8,267
2,031
82
**
169
**
251
191
335
62
32
(4
)
(25
)
842
133
$
2,347
**
2,001
**
4,348
1,032
2,051
1,584
188
(68
)
(26
)
9,109
2,164
$
-
-
-
-
-
-
(6
)
1,229
808
-
2,031
Table of Contents
Year Ended
Millions of Dollars
December 31
Consolidated Operations
Lower
Total
Asia
Middle East
Russia and
Other
Equity
Alaska
48
U.S.
Canada
Europe
Pacific
and Africa
Caspian
Areas
Total
Affiliates
$
4,102
3,385
7,487
1,642
5,142
2,795
423
-
-
17,489
3,470
1,997
1,206
3,203
-
2,207
26
640
-
-
6,076
1,458
2
168
170
40
(253
)
11
4
-
-
(28
)
38
6,101
4,759
10,860
1,682
7,096
2,832
1,067
-
-
23,537
4,966
488
492
980
316
612
274
115
-
-
2,297
452
537
311
848
33
41
26
18
1
1
968
1,635
120
66
186
147
87
139
69
33
8
669
56
443
848
1,291
399
1,074
329
53
-
-
3,146
288
-
1
1
13
(10
)
-
-
-
-
4
-
665
350
1,015
53
296
64
5
-
-
1,433
255
67
48
115
(12
)
28
38
32
35
17
253
26
29
19
48
16
84
7
2
-
-
157
1
3,752
2,624
6,376
717
4,884
1,955
773
(69
)
(26
)
14,610
2,253
1,342
900
2,242
228
3,311
747
759
(6
)
(13
)
7,268
673
2,410
1,724
4,134
489
1,573
1,208
14
(63
)
(13
)
7,342
1,580
141
15
156
93
64
7
(28
)
(2
)
26
316
(90
)
1
(3
)
(2
)
-
(2
)
-
-
-
-
(4
)
-
$
2,552
1,736
4,288
582
1,635
1,215
(14
)
(65
)
13
7,654
1,490
$
-
-
-
-
-
-
(11
)
773
818
-
1,580
n
Results of operations for producing activities consist of all the activities within the E&P
organization and producing activities within the LUKOIL Investment segment, except for
pipeline and marine operations, liquefied natural gas operations, a Canadian Syncrude
operation, and crude oil and gas marketing activities, which are included in other earnings.
Also excluded are our Midstream segment, downstream petroleum and chemical activities, as well
as general corporate administrative expenses and interest.
n
Transfers are valued at prices that approximate market.
n
Other revenues include gains and losses from asset sales, certain amounts resulting from
the purchase and sale of hydrocarbons, and other miscellaneous income. Also included in 2005
were losses of approximately $282 million for the mark-to-market valuation of certain U.K. gas
contracts.
n
Production costs are those incurred to operate and maintain wells and related equipment and
facilities used to produce petroleum liquids and natural gas. These costs also include
depreciation of support equipment and administrative expenses related to the production
activity.
n
Taxes other than income taxes include production, property and other non-income taxes.
Table of Contents
n
Exploration expenses include dry hole, leasehold impairment, geological and geophysical
expenses, the cost of retaining undeveloped leaseholds, and depreciation of support equipment
and administrative expenses related to the exploration activity.
n
Depreciation, depletion and amortization (DD&A) in Results of Operations differs from that
shown for total E&P in Note 29Segment Disclosures and Related Information, in the Notes to
Consolidated 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.
n
Transportation costs include costs to transport our produced oil, natural gas or natural
gas liquids to their points of sale, as well as processing fees paid to process natural gas to
natural gas liquids. The profit element of transportation operations in which we have an
ownership interest are deemed to be outside the oil and gas producing activity. The net
income of the transportation operations is included in other earnings.
n
Other related expenses include foreign currency gains and losses, and other miscellaneous
expenses.
n
The provision for income taxes is computed by adjusting each countrys income before income
taxes for permanent differences related to the oil and gas producing activities that are
reflected in our consolidated income tax expense for the period, multiplying the result by the
countrys statutory tax rate and adjusting for applicable tax credits. Included in 2007 for
Canada is a benefit related to the remeasurement of deferred tax liabilities from the 2007
Canadian graduated tax rate reduction. Included in 2006 for Canada is
a $353 million benefit (which excludes $48 million related to the
Syncrude oil project reflected in other earnings) related to the
remeasurement of deferred tax liabilities from the 2006 Canadian
graduated tax rate reduction and an Alberta provincial tax rate
change. Europe income tax expense for 2006 was increased $250 million
due to remeasurement of deferred tax liabilities as a result of
increases in the U.K. tax rate.
Table of Contents
n
Statistics
Net Production
2007
2006
2005
Thousands of Barrels Daily
261
263
294
102
104
59
363
367
353
19
25
23
210
245
257
87
106
100
81
106
53
10
7
-
770
856
786
27
-
-
416
375
250
42
101
106
485
476
356
19
17
20
79
62
30
98
79
50
27
25
10
14
13
13
14
18
16
2
1
2
155
136
91
Millions of Cubic Feet Daily
110
145
169
2,182
2,028
1,212
2,292
2,173
1,381
1,106
983
425
961
1,065
1,023
579
582
350
125
142
84
19
16
-
5,082
4,961
3,263
256
244
67
5
9
7
261
253
74
Table of Contents
Average Sales Price
2007
2006
2005
$
69.75
62.66
52.24
63.49
57.04
45.24
68.00
61.09
51.09
61.77
54.25
44.70
71.81
64.05
53.16
70.23
61.93
51.34
72.18
66.59
52.93
60.84
50.63
-
70.79
63.38
52.27
69.47
62.39
51.74
37.94
-
-
50.00
41.61
37.39
47.46
46.40
38.08
49.13
42.66
37.60
$
71.85
61.06
51.30
44.43
38.10
36.43
46.00
40.35
40.40
50.85
45.62
42.20
45.72
38.78
31.25
53.19
43.95
40.11
8.31
8.15
7.39
48.80
42.89
36.25
47.13
41.50
38.32
$
3.68
3.59
2.75
5.99
6.14
7.28
5.98
6.11
7.12
6.09
5.67
7.25
7.87
7.78
5.77
6.37
5.91
5.24
.80
.70
.67
1.18
1.31
-
6.51
6.27
5.78
6.26
6.20
6.32
1.02
.57
.48
.30
.30
.26
1.01
.57
.46
Table of Contents
2007
2006
2005
$
7.12
6.38
3.91
6.20
4.85
4.63
6.52
5.43
4.24
10.40
9.05
8.34
7.34
5.12
3.81
5.69
4.02
4.31
6.62
4.51
4.57
8.53
7.65
-
7.68
5.65
4.58
7.13
5.55
4.43
13.32
-
-
4.04
3.53
2.69
6.24
5.42
5.01
4.70
3.91
3.36
Alaska
$
15.27
8.23
4.30
3.16
3.01
2.93
7.45
4.98
3.67
.83
.67
.87
.32
.23
.26
1.79
1.13
.41
.47
.21
.71
20.39
8.50
-
1.07
.60
.42
4.10
2.54
1.87
.21
-
-
20.89
21.40
17.12
11.21
5.28
.06
19.05
18.21
12.16
Table of Contents
Net Wells Completed
(1)
Productive
Dry
2007
2006
2005
2007
2006
2005
3
-
-
1
1
5
71
27
23
9
9
5
74
27
23
10
10
10
50
8
26
17
7
7
1
1
1
1
1
*
4
2
7
1
2
3
-
1
-
1
1
2
-
-
-
*
-
*
-
1
1
-
*
-
129
40
58
30
21
22
-
-
-
-
-
-
-
*
*
-
-
-
-
-
-
-
1
-
-
-
-
-
-
-
-
*
*
-
1
-
99
37
42
18
11
7
Productive
Dry
2007
2006
2005
2007
2006
2005
46
30
31
-
1
-
686
659
297
7
3
9
732
689
328
7
4
9
348
675
425
1
8
2
10
10
19
-
-
-
17
15
17
-
-
-
7
7
6
*
-
-
*
*
-
-
-
-
5
11
-
-
-
-
1,119
1,407
795
8
12
11
70
-
-
1
-
-
-
-
-
-
-
-
2
2
1
-
1
-
-
15
28
-
-
1
72
17
29
1
1
1
Table of Contents
Wells at Year-End 2007
Productive
(2)
In Progress
(1)
Oil
Gas
Gross
Net
Gross
Net
Gross
Net
22
12
1,790
810
27
18
280
233
12,498
4,595
24,742
16,135
302
245
14,288
5,405
24,769
16,153
147
(3)
87
(3)
1,648
913
10,773
6,412
59
11
556
99
344
118
168
79
335
124
95
58
31
5
1,000
177
-
-
25
2
-
-
-
-
5
2
100
44
50
13
737
431
17,927
6,762
36,031
22,754
8
4
93
47
6
3
28
9
69
25
-
-
31
5
-
-
-
-
67
18
162
72
6
3
(1)
Includes wells that have been temporarily suspended.
(2)
Includes 5,479 gross and 3,450 net multiple completion wells.
(3)
Includes 93 gross and 47 net stratigraphic test wells related to the Surmont heavy-oil project.
(4)
Excludes LUKOIL.
Acreage at December 31, 2007
Thousands of Acres
Developed
Undeveloped
Gross
Net
Gross
Net
646
327
2,475
1,572
7,666
5,301
13,965
9,917
8,312
5,628
16,440
11,489
7,002
4,328
14,074
9,292
1,373
342
4,454
1,429
4,214
1,818
28,367
18,588
2,466
449
13,395
2,694
-
-
1,379
128
1,356
573
13,071
10,444
24,723
13,138
91,180
54,064
57
23
483
186
-
-
76
11
385
119
2,898
994
-
-
-
-
442
142
3,457
1,191
*
Excludes LUKOIL.
Table of Contents
n
Costs Incurred
Millions of Dollars
Consolidated Operations
Lower
Total
Asia
Middle East
Russia and
Other
Equity
Alaska
48
U.S.
Canada
Europe
Pacific
and Africa
Caspian
Areas
Total
Affiliates
$
5
202
207
117
-
122
-
-
-
446
2,030
-
42
42
-
-
-
2
-
-
44
1,729
5
244
249
117
-
122
2
-
-
490
3,759
115
468
583
196
235
147
73
37
21
1,292
78
567
2,375
2,942
1,252
1,871
1,275
404
462
73
8,279
2,394
$
687
3,087
3,774
1,565
2,106
1,544
479
499
94
10,061
6,231
-
-
-
4,117
-
-
314
1,749
51
-
6,231
$
4
860
864
554
113
-
30
-
39
1,600
143
13
15,784
15,797
8,296
1,169
525
856
-
252
26,895
2,647
17
16,644
16,661
8,850
1,282
525
886
-
291
28,495
2,790
131
332
463
182
172
231
57
47
27
1,179
58
629
1,733
2,362
1,926
1,653
919
249
371
141
7,621
1,326
$
777
18,709
19,486
10,958
3,107
1,675
1,192
418
459
37,295
4,174
$
-
-
-
-
-
-
183
3,854
137
-
4,174
$
1
14
15
68
-
26
85
83
-
277
796
16
767
783
-
-
6
569
125
-
1,483
1,763
17
781
798
68
-
32
654
208
-
1,760
2,559
64
74
138
163
117
204
67
37
11
737
60
650
688
1,338
782
1,402
682
137
372
42
4,755
449
$
731
1,543
2,274
1,013
1,519
918
858
617
53
7,252
3,068
$
-
-
-
-
-
-
54
2,903
111
-
3,068
n
Costs incurred include capitalized and expensed items.
n
Acquisition costs include the costs of acquiring proved and unproved oil and gas
properties. In 2007, equity affiliate acquisition costs were due to
the EnCana business venture. In 2006 in our consolidated operations,
acquisition costs were primarily related to the Burlington Resources
acquisition.
n
Exploration costs include geological and geophysical expenses, the cost of retaining
undeveloped leaseholds, and exploratory drilling costs.
n
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.
Table of Contents
n
Capitalized Costs
At December 31
Millions of Dollars
Consolidated Operations
Lower
Total
Asia
Middle East
Russia and
Other
Equity
Alaska
48
U.S.
Canada
Europe
Pacific
and Africa
Caspian
Areas
Total
Affiliates
$
10,182
28,645
38,827
17,330
20,615
8,014
2,758
2,135
641
90,320
12,491
848
1,137
1,985
1,798
446
795
281
131
83
5,519
3,360
11,030
29,782
40,812
19,128
21,061
8,809
3,039
2,266
724
95,839
15,851
4,158
7,920
12,078
4,875
9,374
2,155
822
4
504
29,812
1,008
$
6,872
21,862
28,734
14,253
11,687
6,654
2,217
2,262
220
66,027
14,843
$
-
-
-
4,771
-
-
606
9,466
-
-
14,843
$
9,567
26,227
35,794
14,455
17,773
6,870
2,577
1,669
633
79,771
11,550
840
1,045
1,885
1,425
365
743
321
117
72
4,928
944
10,407
27,272
37,679
15,880
18,138
7,613
2,898
1,786
705
84,699
12,494
3,573
5,525
9,098
2,795
7,450
1,581
737
3
81
21,745
933
$
6,834
21,747
28,581
13,085
10,688
6,032
2,161
1,783
624
62,954
11,561
$
-
-
-
-
-
-
180
8,310
3,071
-
11,561
n
Capitalized costs include the cost of equipment and facilities for oil and gas producing
activities. These costs include the activities of our E&P and LUKOIL Investment segments,
excluding pipeline and marine operations, liquefied natural gas operations, a Canadian
Syncrude operation, crude oil and natural gas marketing activities, and downstream operations.
n
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.
n
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.
Table of Contents
n
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas
Reserve Quantities
Table of Contents
Millions of Dollars
Consolidated Operations
Lower
Total
Asia
Middle East
Russia and
Other
Equity
Alaska
48
U.S.
Canada
Europe
Pacific
and Africa
Caspian
Areas
Total
Affiliates
$
133,909
94,706
228,615
30,125
83,367
46,520
31,509
11,272
803
432,211
163,555
75,024
41,945
116,969
11,206
15,781
11,996
3,884
1,876
706
162,418
97,375
8,392
9,690
18,082
4,605
10,920
3,958
400
2,761
34
40,760
10,847
18,798
14,793
33,591
2,235
37,645
12,331
22,599
1,680
10
110,091
12,381
31,695
28,278
59,973
12,079
19,021
18,235
4,626
4,955
53
118,942
42,952
16,510
12,158
28,668
3,870
5,776
7,113
1,847
4,504
2
51,780
22,925
$
15,185
16,120
31,305
8,209
13,245
11,122
2,779
451
51
67,162
20,027
$
-
-
-
3,889
-
-
4,453
11,685
-
-
20,027
$
86,843
75,039
161,882
25,363
60,118
32,420
19,369
6,853
1,777
307,782
117,860
43,393
23,096
66,489
9,393
13,186
6,730
4,308
1,692
1,082
102,880
66,929
5,142
7,274
12,416
4,154
7,865
2,886
586
2,787
220
30,914
6,369
14,138
14,357
28,495
2,313
25,627
9,204
12,029
590
101
78,359
16,085
24,170
30,312
54,482
9,503
13,440
13,600
2,446
1,784
374
95,629
28,477
12,479
15,697
28,176
3,297
4,052
5,482
753
2,213
66
44,039
16,044
$
11,691
14,615
26,306
6,206
9,388
8,118
1,693
(429
)
308
51,590
12,433
$
-
-
-
-
-
-
1,703
5,441
5,289
-
12,433
$
96,574
48,560
145,134
11,907
74,790
31,310
19,337
11,069
787
294,334
111,825
34,586
10,425
45,011
2,892
12,055
5,343
3,442
2,410
488
71,641
47,634
4,569
1,686
6,255
965
7,517
2,920
474
1,917
149
20,197
4,760
20,421
12,831
33,252
2,349
37,208
9,653
13,882
2,163
80
98,587
17,052
36,998
23,618
60,616
5,701
18,010
13,394
1,539
4,579
70
103,909
42,379
19,414
11,934
31,348
2,184
6,006
5,639
560
4,168
56
49,961
25,720
$
17,584
11,684
29,268
3,517
12,004
7,755
979
411
14
53,948
16,659
$
-
-
-
-
-
-
1,865
5,024
9,770
-
16,659
Excludes discounted future net cash flows from Canadian Syncrude of $4,484 million in 2007, $2,220
million in 2006 and $2,159 million in 2005.
Table of Contents
Millions of Dollars
Consolidated Operations
Equity Affiliates
2007
2006
2005
2007
2006
2005
$
51,590
53,948
35,488
12,433
16,659
8,210
(24,441
)
(25,133
)
(18,867
)
(3,288
)
(3,379
)
(2,586
)
49,447
(18,928
)
46,332
10,082
(5,582
)
6,555
6,985
3,867
3,942
2,188
401
2,201
7,289
7,020
4,282
2,346
1,327
449
(10,813
)
(6,195
)
(3,261
)
(3,468
)
(1,291
)
(142
)
51
24,203
6,610
2,989
1,945
2,361
(1,347
)
(506
)
(306
)
(9,619
)
2
(34
)
(79
)
(7,028
)
(175
)
3,855
107
1,245
8,561
9,759
5,728
1,809
2,215
1,032
(20,081
)
10,583
(25,825
)
700
29
(2,632
)
-
-
-
-
-
-
15,572
(2,358
)
18,460
7,594
(4,226
)
8,449
$
67,162
51,590
53,948
20,027
12,433
16,659
**Includes amounts resulting from changes in the timing of production.
n
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.
n
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.
n
The accretion of discount is 10 percent of the prior years discounted future cash inflows,
less future production, transportation and development costs.
n
The net change in income taxes is the annual change in the discounted future income tax
provisions.
Table of Contents
Millions of Dollars
Per Share of Common Stock
Income from
Income Before
Sales and
Continuing
Income Before
Cumulative Effect
Other
Operations
Cumulative Effect
of Changes in
Operating
Before Income
of Changes in
Net
Accounting Principles
Net Income
Revenues
**
Taxes
Accounting Principles
Income
Basic
Diluted
Basic
Diluted
$
41,320
6,066
3,546
3,546
2.15
2.12
2.15
2.12
47,370
3,518
301
301
.18
.18
.18
.18
46,062
6,364
3,673
3,673
2.26
2.23
2.26
2.23
52,685
7,324
4,371
4,371
2.75
2.71
2.75
2.71
$
46,906
5,797
3,291
3,291
2.38
2.34
2.38
2.34
47,149
8,682
5,186
5,186
3.13
3.09
3.13
3.09
48,076
7,937
3,876
3,876
2.35
2.31
2.35
2.31
41,519
5,917
3,197
3,197
1.94
1.91
1.94
1.91
Table of Contents
ConocoPhillips, ConocoPhillips Company, ConocoPhillips Australia Funding Company,
ConocoPhillips Canada Funding Company I, and ConocoPhillips Canada Funding Company II (in
each case, reflecting investments in subsidiaries utilizing the equity method of
accounting).
All other non-guarantor subsidiaries of ConocoPhillips.
The consolidating adjustments necessary to present ConocoPhillips results on a
consolidated basis.
Table of Contents
Millions of Dollars
Year Ended December 31, 2007
ConocoPhillips
Australia
ConocoPhillips
ConocoPhillips
ConocoPhillips
Funding
Canada Funding
Canada Funding
All Other
Consolidating
Total
Income Statement
ConocoPhillips
Company
Company
Company I
Company II
Subsidiaries
Adjustments
Consolidated
$
-
120,687
-
-
-
66,750
-
187,437
12,071
9,800
-
-
-
3,025
(19,809
)
5,087
4
(199
)
-
-
-
2,166
-
1,971
149
3,014
117
83
51
18,407
(21,821
)
-
12,224
133,302
117
83
51
90,348
(41,630
)
194,495
-
103,516
-
-
-
38,880
(18,967
)
123,429
-
4,522
-
-
-
6,247
(86
)
10,683
17
1,407
-
-
-
943
(61
)
2,306
-
111
-
-
-
896
-
1,007
-
1,476
-
-
-
6,822
-
8,298
-
1,925
-
-
-
2,663
-
4,588
-
(73
)
-
-
-
515
-
442
-
5,463
-
-
-
13,802
(275
)
18,990
-
55
-
-
-
286
-
341
423
1,054
109
77
53
1,969
(2,432
)
1,253
-
12
-
166
124
(503
)
-
(201
)
-
-
-
-
-
87
-
87
440
119,468
109
243
177
72,607
(21,821
)
171,223
11,784
13,834
8
(160
)
(126
)
17,741
(19,809
)
23,272
(107
)
2,810
3
16
6
8,653
-
11,381
11,891
11,024
5
(176
)
(132
)
9,088
(19,809
)
11,891
-
-
-
-
-
-
-
-
11,891
11,024
5
(176
)
(132
)
9,088
(19,809
)
11,891
-
-
-
-
-
-
-
-
$
11,891
11,024
5
(176
)
(132
)
9,088
(19,809
)
11,891
Table of Contents
Millions of Dollars
Year Ended December 31, 2006
ConocoPhillips
Australia
ConocoPhillips
ConocoPhillips
ConocoPhillips
Funding
Canada Funding
Canada Funding
All Other
Consolidating
Total
Income Statement
ConocoPhillips
Company
Company
Company I
Company II
Subsidiaries
Adjustments
Consolidated
$
-
117,063
-
-
-
66,587
-
183,650
15,798
11,136
-
-
-
3,608
(26,354
)
4,188
-
337
-
-
-
348
-
685
173
2,599
94
17
10
15,740
(18,633
)
-
15,971
131,135
94
17
10
86,283
(44,987
)
188,523
-
97,986
-
-
-
37,735
(16,822
)
118,899
-
4,720
-
-
-
5,782
(89
)
10,413
19
1,593
-
-
-
914
(50
)
2,476
-
120
-
-
-
714
-
834
-
1,702
-
-
-
5,582
-
7,284
-
410
-
-
-
273
-
683
-
5,877
-
-
-
12,577
(267
)
18,187
-
58
-
-
-
223
-
281
537
1,070
80
17
11
777
(1,405
)
1,087
-
(2
)
-
(39
)
(37
)
48
-
(30
)
-
-
-
-
-
76
-
76
556
113,534
80
(22
)
(26
)
64,701
(18,633
)
160,190
15,415
17,601
14
39
36
21,582
(26,354
)
28,333
(135
)
2,839
5
10
10
10,054
-
12,783
15,550
14,762
9
29
26
11,528
(26,354
)
15,550
-
-
-
-
-
-
-
-
15,550
14,762
9
29
26
11,528
(26,354
)
15,550
-
-
-
-
-
-
-
-
$
15,550
14,762
9
29
26
11,528
(26,354
)
15,550
Table of Contents
Millions of Dollars
Year Ended December 31, 2005
ConocoPhillips
All Other
Consolidating
Total
Income Statement
ConocoPhillips
Company
Subsidiaries
Adjustments
Consolidated
$
-
121,718
57,724
-
179,442
13,754
10,235
2,842
(23,374
)
3,457
(25
)
152
338
-
465
30
2,250
9,925
(12,205
)
-
13,759
134,355
70,829
(35,579
)
183,364
-
103,307
32,665
(11,047
)
124,925
-
4,711
3,917
(66
)
8,562
16
1,436
818
(23
)
2,247
-
84
577
-
661
-
1,473
2,780
-
4,253
-
2
40
-
42
-
6,065
12,533
(242
)
18,356
-
37
156
-
193
135
833
356
(827
)
497
-
(16
)
64
-
48
-
-
33
-
33
151
117,932
53,939
(12,205
)
159,817
13,608
16,423
16,890
(23,374
)
23,547
(32
)
2,669
7,270
-
9,907
13,640
13,754
9,620
(23,374
)
13,640
(23
)
(23
)
(6
)
29
(23
)
13,617
13,731
9,614
(23,345
)
13,617
(88
)
(88
)
(29
)
117
(88
)
$
13,529
13,643
9,585
(23,228
)
13,529
Table of Contents
Millions of Dollars
At December 31, 2007
ConocoPhillips
Australia
ConocoPhillips
ConocoPhillips
ConocoPhillips
Funding
Canada Funding
Canada Funding
All Other
Consolidating
Total
Balance Sheet
ConocoPhillips
Company
Company
Company I
Company II
Subsidiaries
Adjustments
Consolidated
$
-
195
-
7
1
1,626
(373
)
1,456
40
12,421
15
12
4
19,548
(15,686
)
16,354
-
2,043
-
-
-
2,190
(10
)
4,223
9
578
-
1
-
2,114
-
2,702
49
15,237
15
20
5
25,478
(16,069
)
24,735
86,942
57,936
1,700
1,470
997
18,972
(134,689
)
33,328
-
17,677
-
-
-
71,317
9
89,003
-
12,746
-
-
-
16,590
-
29,336
-
808
-
-
-
88
-
896
8
153
3
5
4
520
(234
)
459
$
86,999
104,557
1,718
1,495
1,006
132,965
(150,983
)
177,757
$
6
18,792
-
10
4
15,108
(16,059
)
17,861
1,000
309
-
-
-
89
-
1,398
-
601
-
-
(1
)
4,117
97
4,814
-
509
-
-
-
411
-
920
21
594
20
16
11
1,230
(3
)
1,889
1,027
20,805
20
26
14
20,955
(15,965
)
26,882
3,402
5,694
1,699
1,250
848
7,396
-
20,289
-
1,167
-
-
-
6,094
-
7,261
-
-
-
-
-
6,294
-
6,294
(3
)
3,050
-
32
18
17,907
14
21,018
-
2,292
-
-
-
899
-
3,191
42
16,447
-
132
102
15,489
(29,546
)
2,666
4,468
49,455
1,719
1,440
982
75,034
(45,497
)
87,601
-
(19
)
-
-
-
1,194
(2
)
1,173
43,988
23,952
(1
)
(147
)
(107
)
20,738
(37,913
)
50,510
38,543
31,169
-
202
131
35,999
(67,571
)
38,473
$
86,999
104,557
1,718
1,495
1,006
132,965
(150,983
)
177,757
Table of Contents
Millions of Dollars
At December 31, 2006
ConocoPhillips
Australia
ConocoPhillips
ConocoPhillips
ConocoPhillips
Funding
Canada Funding
Canada Funding
All Other
Consolidating
Total
Balance Sheet
ConocoPhillips
Company
Company
Company I
Company II
Subsidiaries
Adjustments
Consolidated
$
-
116
-
-
1
1,042
(342
)
817
65
13,233
22
10
2
17,224
(16,450
)
14,106
-
2,906
-
-
-
2,247
-
5,153
11
895
-
10
7
4,067
-
4,990
76
17,150
22
20
10
24,580
(16,792
)
25,066
86,292
58,530
2,000
1,241
841
28,372
(156,563
)
20,713
-
19,072
-
-
-
67,122
7
86,201
-
15,226
-
-
-
16,262
-
31,488
-
852
-
-
-
99
-
951
10
141
5
35
24
195
(48
)
362
$
86,378
110,971
2,027
1,296
875
136,630
(173,396
)
164,781
$
68
16,641
-
5
3
14,367
(16,450
)
14,634
3,431
525
-
-
-
87
-
4,043
-
732
-
-
-
3,577
98
4,407
-
464
-
-
-
431
-
895
50
804
24
16
10
1,565
(17
)
2,452
3,549
19,166
24
21
13
20,027
(16,369
)
26,431
6,521
6,036
1,999
1,250
848
6,437
-
23,091
-
1,095
-
-
-
4,524
-
5,619
(8
)
2,969
-
16
10
17,086
1
20,074
-
2,379
-
-
-
1,288
-
3,667
29
28,306
-
-
-
22,300
(48,584
)
2,051
10,091
59,951
2,023
1,287
871
71,662
(64,952
)
80,933
-
(19
)
-
-
-
1,221
-
1,202
34,756
22,939
4
29
26
28,029
(44,491
)
41,292
41,531
28,100
-
(20
)
(22
)
35,718
(63,953
)
41,354
$
86,378
110,971
2,027
1,296
875
136,630
(173,396
)
164,781
* Includes intercompany loans.
Table of Contents
Millions of Dollars
Year Ended December 31, 2007
ConocoPhillips
Australia
ConocoPhillips
ConocoPhillips
Statement of Cash Flows
ConocoPhillips
Funding
Canada Funding
Canada Funding
All Other
Consolidating
Total
ConocoPhillips
Company
Company
Company I
Company II
Subsidiaries
Adjustments
Consolidated
$
14,984
9,944
10
7
-
26,021
(26,416
)
24,550
-
-
-
-
-
-
-
-
14,984
9,944
10
7
-
26,021
(26,416
)
24,550
-
-
-
-
-
-
-
-
-
(2,967
)
-
-
-
(9,121
)
297
(11,791
)
-
1,391
-
-
-
3,029
(848
)
3,572
-
(491
)
-
-
-
(2,649
)
2,458
(682
)
-
1,238
300
-
-
837
(2,286
)
89
1
83
-
-
-
166
-
250
1
(746
)
300
-
-
(7,738
)
(379
)
(8,562
)
-
-
-
-
-
-
-
-
1
(746
)
300
-
-
(7,738
)
(379
)
(8,562
)
(39
)
2,179
-
-
-
1,253
(2,458
)
935
(5,564
)
(1,385
)
(300
)
-
-
(1,491
)
2,286
(6,454
)
(7,001
)
-
-
-
-
-
-
(7,001
)
285
-
-
-
-
-
-
285
(2,661
)
(10,000
)
(10
)
-
-
(16,376
)
26,386
(2,661
)
(5
)
87
-
-
-
(1,076
)
550
(444
)
(14,985
)
(9,119
)
(310
)
-
-
(17,690
)
26,764
(15,340
)
-
-
-
-
-
(9
)
-
(9
)
-
79
-
7
-
584
(31
)
639
-
116
-
-
1
1,042
(342
)
817
$
-
195
-
7
1
1,626
(373
)
1,456
Table of Contents
Millions of Dollars
Year Ended December 31, 2006
ConocoPhillips
Australia
ConocoPhillips
ConocoPhillips
Statement of Cash Flows
ConocoPhillips
Funding
Canada Funding
Canada Funding
All Other
Consolidating
Total
ConocoPhillips
Company
Company
Company I
Company II
Subsidiaries
Adjustments
Consolidated
$
29,520
6,723
4
6
8
7,659
(22,404
)
21,516
-
-
-
-
-
-
-
-
29,520
6,723
4
6
8
7,659
(22,404
)
21,516
-
-
-
-
-
(14,285
)
-
(14,285
)
(17,494
)
(3,538
)
-
-
-
(12,696
)
18,132
(15,596
)
-
73
-
-
-
472
-
545
(14,989
)
(290
)
(1,992
)
(1,250
)
(1,711
)
(3,896
)
23,348
(780
)
-
2,708
-
-
861
4,384
(7,830
)
123
(32,483
)
(1,047
)
(1,992
)
(1,250
)
(850
)
(26,021
)
33,650
(29,993
)
-
-
-
-
-
-
-
-
(32,483
)
(1,047
)
(1,992
)
(1,250
)
(850
)
(26,021
)
33,650
(29,993
)
12,892
18,394
2,000
1,250
848
5,278
(23,348
)
17,314
(6,936
)
(4,536
)
-
-
-
(3,440
)
7,830
(7,082
)
(925
)
-
-
-
-
-
-
(925
)
220
-
-
-
-
-
-
220
(2,277
)
(20,000
)
(5
)
-
-
(2,056
)
22,061
(2,277
)
(11
)
(31
)
(7
)
(6
)
(5
)
18,006
(18,131
)
(185
)
2,963
(6,173
)
1,988
1,244
843
17,788
(11,588
)
7,065
-
-
-
-
-
15
-
15
-
(497
)
-
-
1
(559
)
(342
)
(1,397
)
-
613
-
-
-
1,601
-
2,214
$
-
116
-
-
1
1,042
(342
)
817
Table of Contents
Millions of Dollars
Year Ended December 31, 2005
ConocoPhillips
All Other
Consolidating
Total
Statement of Cash Flows
ConocoPhillips
Company
Subsidiaries
Adjustments
Consolidated
$
183
15,956
11,192
(9,698
)
17,633
-
(7
)
2
-
(5
)
183
15,949
11,194
(9,698
)
17,628
-
(5,118
)
(9,119
)
2,617
(11,620
)
-
279
491
(2
)
768
-
(20,056
)
(1,208
)
20,989
(275
)
1,240
12,339
2,161
(15,629
)
111
1,240
(12,556
)
(7,675
)
7,975
(11,016
)
-
-
-
-
-
1,240
(12,556
)
(7,675
)
7,975
(11,016
)
2,901
1,504
17,036
(20,989
)
452
(1,160
)
(5,115
)
(12,356
)
15,629
(3,002
)
(1,924
)
-
-
-
(1,924
)
402
-
-
-
402
(1,639
)
-
(9,700
)
9,700
(1,639
)
(3
)
(50
)
2,697
(2,617
)
27
(1,423
)
(3,661
)
(2,323
)
1,723
(5,684
)
-
2
(103
)
-
(101
)
-
(266
)
1,093
-
827
-
879
508
-
1,387
$
-
613
1,601
-
2,214
Table of Contents
Item 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
Item 9A.
CONTROLS AND PROCEDURES
Item 9B.
OTHER INFORMATION
Table of Contents
205
Item 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Item 11.
EXECUTIVE COMPENSATION
Item 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Item 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Item 14.
PRINCIPAL ACCOUNTING FEES AND SERVICES
*
Table of Contents
206
207
208
209
210
211
212
213
214
Item 15.
EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(a)
1.
Financial Statements and Financial Statement Schedules
2.
Exhibits
Table of Contents
Millions of Dollars
Additions
Balance At
Charged to
Balance At
Description
January 1
Expense
Other(a)
Deductions
December 31
$
45
23
(2
)
(8
)(b)
58
822
67
417
(37
)
1,269
164
31
5
(83
)(c)
117
$
72
11
9
(47
)(b)
45
850
103
42
(173
)
822
53
10
216
(115
)(c)
164
$
55
21
4
(8
)(b)
72
968
90
(26
)
(182
)
850
89
(2
)
(3
)
(31
)(c)
53
(a)
Represents acquisitions/dispositions/revisions and the effect of translating foreign
financial statements.
(b)
Amounts charged off less recoveries of amounts previously charged off.
(c)
Benefit payments.
Table of Contents
Exhibit
Number
Description
Agreement and Plan of Merger, dated as of November 18, 2001, by and among ConocoPhillips
Company (formerly named Phillips Petroleum Company), ConocoPhillips (formerly named
CorvettePorsche Corp.), P Merger Corp. (formerly named Porsche Merger Corp.), C Merger Corp.
(formerly named Corvette Merger Corp.) and ConocoPhillips Holding Company (formerly named
Conoco Inc.) (Holding) (incorporated by reference to Annex A to the Joint Proxy
Statement/Prospectus included in ConocoPhillips Registration Statement on Form S-4;
Registration No. 333-74798 (the Form S-4)).
Agreement and Plan of Merger, dated as of December 12, 2005, by and among ConocoPhillips,
Cello Acquisition Corp. and Burlington Resources Inc. (incorporated by reference to Exhibit
2.1 to the Current Report of ConocoPhillips on Form 8-K filed on December 14, 2005; File No.
001-32395).
Restated Certificate of Incorporation of ConocoPhillips (incorporated by reference to Exhibit
3.1 to the Current Report of ConocoPhillips on Form 8-K filed on August 30, 2002; File No.
000-49987 (the Form 8-K)).
Certificate of Designations of Series A Junior Participating Preferred Stock of
ConocoPhillips (incorporated by reference to Exhibit 3.2 to the Form 8-K).
By-Laws of ConocoPhillips, as
amended on February 15, 2008 (incorporated by reference to
Exhibit 99.1 to the Current Report of ConocoPhillips on
Form 8-K filed on February 19, 2008;
File No. 001-32395).
Rights agreement, dated as of June 30, 2002, between ConocoPhillips and Mellon Investor
Services LLC, as rights agent, which includes as Exhibit A the form of Certificate of
Designations of Series A Junior Participating Preferred Stock, as Exhibit B the form of Rights
Certificate and as Exhibit C the Summary of Rights to Purchase Preferred Stock (incorporated
by reference to Exhibit 4.1 to the Form 8-K).
ConocoPhillips and its subsidiaries are parties to several debt instruments under which
the total amount of securities authorized does not exceed 10 percent of the total assets
of ConocoPhillips and its subsidiaries on a consolidated basis. Pursuant to paragraph
4(iii)(A) of Item 601(b) of Regulation S-K, ConocoPhillips agrees to furnish a copy of
such instruments to the SEC upon request.
Shareholder Agreement, dated September 29, 2004, by and between LUKOIL and ConocoPhillips
(incorporated by reference to Exhibit 99.2 of the Current Report of ConocoPhillips on Form 8-K
filed on September 30, 2004; File No. 333-74798).
1986 Stock Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10.11 to
the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002; File
No. 000-49987).
Table of Contents
Exhibit
Number
Description
1990 Stock Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10.12 to
the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002; File
No. 000-49987).
Annual Incentive Compensation Plan of Phillips Petroleum Company (incorporated by reference
to Exhibit 10.13 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2002; File No. 000-49987).
Incentive Compensation Plan of Phillips Petroleum Company (incorporated by reference to
Exhibit 10(g) to the Annual Report of ConocoPhillips Company on Form 10-K for the year ended
December 31, 1999; File No. 1-720).
Principal Corporate Officers Supplemental Retirement Plan of Phillips Petroleum Company
(incorporated by reference to Exhibit 10(h) to the Annual Report of ConocoPhillips Company on
Form 10-K for the year ended December 31, 1995; File No. 1-720).
ConocoPhillips Supplemental Executive Retirement Plan (incorporated by reference to Exhibit
10.7 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2005;
File No. 001-32395).
Non-Employee Director Retirement Plan of Phillips Petroleum Company (incorporated by
reference to Exhibit 10.18 to the Annual Report of ConocoPhillips on Form 10-K for the year
ended December 31, 2002; File No. 000-49987).
Omnibus Securities Plan of Phillips Petroleum Company (incorporated by reference to Exhibit
10.19 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31,
2002; File No. 000-49987).
Key Employee Missed Credited Service Retirement Plan of ConocoPhillips (incorporated by
reference to Exhibit 10.10 to the Annual Report of ConocoPhillips on Form 10-K for the year
ended December 31, 2005; File No. 001-32395).
Phillips Petroleum Company Stock Plan for Non-Employee Directors (incorporated by reference
to Exhibit 10.22 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2002; File No. 000-49987).
ConocoPhillips Key Employee Supplemental Retirement Plan (incorporated by reference to
Exhibit 10.12 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December
31, 2005; File No. 001-32395).
Defined Contribution Make-Up Plan of ConocoPhillipsTitle I (incorporated by reference to
Exhibit 10.13.1 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2005; File No. 001-32395).
Defined Contribution Make-Up Plan of ConocoPhillipsTitle II (incorporated by reference to
Exhibit 10.13.2 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2005; File No. 001-32395).
Table of Contents
Exhibit
Number
Description
2002 Omnibus Securities Plan of Phillips Petroleum Company (incorporated by reference to
Exhibit 10.26 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December
31, 2002; File No. 000-49987).
1998 Stock and Performance Incentive Plan of ConocoPhillips (incorporated by reference to
Exhibit 10.27 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December
31, 2002; File No. 000-49987).
1998 Key Employee Stock Performance Plan of ConocoPhillips (incorporated by reference to
Exhibit 10.28 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December
31, 2002; File No. 000-49987).
Deferred Compensation Plan for Non-Employee Directors of ConocoPhillips (incorporated by
reference to Exhibit 10.17 to the Annual Report of ConocoPhillips on Form 10-K for the year
ended December 31, 2005; File No. 001-32395).
ConocoPhillips Form Indemnity Agreement with Directors (incorporated by reference to Exhibit
10.34 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31,
2002; File No. 000-49987).
Letter Agreement, dated as of April 12, 2002, between Holding and Jim W. Nokes (incorporated
by reference to Exhibit 10.2 to the Quarterly Report of ConocoPhillips on Form 10-Q for the
quarterly period ended September 30, 2002; File No. 000-49987).
Rabbi Trust Agreement dated December 17, 1999 (incorporated by reference to Exhibit 10.11 of
Holdings Form 10-K for the year ended December 31, 1999, File No. 001-14521).
Amendment to Rabbi Trust Agreement dated February 25, 2002 (incorporated by reference to
Exhibit 10.39.1 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2002; File No. 000-49987).
ConocoPhillips Directors Charitable Gift Program (incorporated by reference to Exhibit
10.40 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31,
2003; File No. 000-49987).
ConocoPhillips Matching Gift Plan for Directors and Executives (incorporated by reference to
Exhibit 10.41 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December
31, 2003; File No. 000-49987).
Key Employee Deferred Compensation Plan of ConocoPhillipsTitle I (incorporated by
reference to Exhibit 10.23.1 to the Annual Report of ConocoPhillips on Form 10-K for the year
ended December 31, 2005; File No. 001-32395).
Key Employee Deferred Compensation Plan of ConocoPhillipsTitle II (incorporated by
reference to Exhibit 10.23.2 to the Annual Report of ConocoPhillips on Form 10-K for the year
ended December 31, 2005; File No. 001-32395).
Table of Contents
Exhibit
Number
Description
ConocoPhillips Key Employee Change in Control Severance Plan (incorporated by reference to
Exhibit 10.1 of the Quarterly Report of ConocoPhillips on Form 10-Q for the quarterly period
ended September 30, 2004; File No. 000-49987).
ConocoPhillips Executive Severance Plan (incorporated by reference to Exhibit 10.25 to the
Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2005; File No.
001-32395).
First and Second Amendments to the ConocoPhillips Executive Severance Plan (incorporated by
reference to Exhibit 10 of the Quarterly Report of ConocoPhillips on Form 10-Q for the
quarterly period ended March 31, 2007; File No. 001-32395).
2004 Omnibus Stock and Performance Incentive Plan of ConocoPhillips (incorporated by
reference to Appendix C of ConocoPhillips Proxy Statement on Schedule 14A relating to the
2004 Annual Meeting of Shareholders; File No. 000-49987).
Aircraft Time Sharing Agreement by and between James J. Mulva and ConocoPhillips
(incorporated by reference to Exhibit 10 of the Quarterly Report of ConocoPhillips on
Form 10-Q for the quarterly period ended June 30, 2007; File No. 001-32395).
Form of Stock Option Award Agreement under the ConocoPhillips Stock Option and Stock
Appreciation Rights Program.
Form of Restricted Stock Unit Award Agreement under the ConocoPhillips Performance Share
Program.
Omnibus Amendments to certain ConocoPhillips employee benefit plans, adopted
December 7, 2007.
Computation of Ratio of Earnings to Fixed Charges.
List of Subsidiaries of ConocoPhillips.
Consent of Independent Registered Public Accounting Firm.
Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities
Exchange Act of 1934.
Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities
Exchange Act of 1934.
Certifications pursuant to 18 U.S.C. Section 1350.
Table of Contents
CONOCOPHILLIPS
February 21, 2008
/s/ James J. Mulva
James J. Mulva
Chairman of the Board of Directors,
President and Chief Executive Officer
Title
/s/ James J. Mulva
Chairman of the Board of Directors,
President and Chief Executive Officer
(Principal executive officer)
/s/ John A. Carrig
Executive Vice President, Finance,
and Chief Financial Officer
(Principal financial officer)
/s/ Rand C. Berney
Vice President and Controller
(Principal accounting officer)
Table of Contents
/s/ Richard L. Armitage
Director
/s/ Richard H. Auchinleck
Director
/s/ Norman R. Augustine
Director
/s/ James E. Copeland, Jr.
Director
/s/ Kenneth M. Duberstein
Director
/s/ Ruth R. Harkin
Director
/s/ Charles C. Krulak
Director
/s/ Harold W. McGraw, III
Director
/s/ Harald J. Norvik
Director
/s/ William K. Reilly
Director
/s/ William R. Rhodes
Director
/s/ J. Stapleton Roy
Director
/s/ Bobby S. Shackouls
Director
Table of Contents
/s/ Victoria J. Tschinkel
Director
/s/ Kathryn C. Turner
Director
/s/ William E. Wade, Jr.
Director
Table of Contents
Exhibit
Number
Description
Agreement and Plan of Merger, dated as of November 18, 2001, by and among ConocoPhillips
Company (formerly named Phillips Petroleum Company), ConocoPhillips (formerly named
CorvettePorsche Corp.), P Merger Corp. (formerly named Porsche Merger Corp.), C Merger Corp.
(formerly named Corvette Merger Corp.) and ConocoPhillips Holding Company (formerly named
Conoco Inc.) (Holding) (incorporated by reference to Annex A to the Joint Proxy
Statement/Prospectus included in ConocoPhillips Registration Statement on Form S-4;
Registration No. 333-74798 (the Form S-4)).
Agreement and Plan of Merger, dated as of December 12, 2005, by and among ConocoPhillips,
Cello Acquisition Corp. and Burlington Resources Inc. (incorporated by reference to Exhibit
2.1 to the Current Report of ConocoPhillips on Form 8-K filed on December 14, 2005; File No.
001-32395).
Restated Certificate of Incorporation of ConocoPhillips (incorporated by reference to Exhibit
3.1 to the Current Report of ConocoPhillips on Form 8-K filed on August 30, 2002; File No.
000-49987 (the Form 8-K)).
Certificate of Designations of Series A Junior Participating Preferred Stock of
ConocoPhillips (incorporated by reference to Exhibit 3.2 to the Form 8-K).
By-Laws of ConocoPhillips, as
amended on February 15, 2008 (incorporated by reference to
Exhibit 99.1 to the Current Report of ConocoPhillips on
Form 8-K filed on February 19, 2008;
File No. 001-32395).
Rights agreement, dated as of June 30, 2002, between ConocoPhillips and Mellon Investor
Services LLC, as rights agent, which includes as Exhibit A the form of Certificate of
Designations of Series A Junior Participating Preferred Stock, as Exhibit B the form of Rights
Certificate and as Exhibit C the Summary of Rights to Purchase Preferred Stock (incorporated
by reference to Exhibit 4.1 to the Form 8-K).
ConocoPhillips and its subsidiaries are parties to several debt instruments under which
the total amount of securities authorized does not exceed 10 percent of the total assets
of ConocoPhillips and its subsidiaries on a consolidated basis. Pursuant to paragraph
4(iii)(A) of Item 601(b) of Regulation S-K, ConocoPhillips agrees to furnish a copy of
such instruments to the SEC upon request.
Shareholder Agreement, dated September 29, 2004, by and between LUKOIL and ConocoPhillips
(incorporated by reference to Exhibit 99.2 of the Current Report of ConocoPhillips on Form 8-K
filed on September 30, 2004; File No. 333-74798).
1986 Stock Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10.11 to
the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002; File
No. 000-49987).
Table of Contents
Exhibit
Number
Description
1990 Stock Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10.12 to
the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002; File
No. 000-49987).
Annual Incentive Compensation Plan of Phillips Petroleum Company (incorporated by reference
to Exhibit 10.13 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2002; File No. 000-49987).
Incentive Compensation Plan of Phillips Petroleum Company (incorporated by reference to
Exhibit 10(g) to the Annual Report of ConocoPhillips Company on Form 10-K for the year ended
December 31, 1999; File No. 1-720).
Principal Corporate Officers Supplemental Retirement Plan of Phillips Petroleum Company
(incorporated by reference to Exhibit 10(h) to the Annual Report of ConocoPhillips Company on
Form 10-K for the year ended December 31, 1995; File No. 1-720).
ConocoPhillips Supplemental Executive Retirement Plan (incorporated by reference to Exhibit
10.7 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2005;
File No. 001-32395).
Non-Employee Director Retirement Plan of Phillips Petroleum Company (incorporated by
reference to Exhibit 10.18 to the Annual Report of ConocoPhillips on Form 10-K for the year
ended December 31, 2002; File No. 000-49987).
Omnibus Securities Plan of Phillips Petroleum Company (incorporated by reference to Exhibit
10.19 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31,
2002; File No. 000-49987).
Key Employee Missed Credited Service Retirement Plan of ConocoPhillips (incorporated by
reference to Exhibit 10.10 to the Annual Report of ConocoPhillips on Form 10-K for the year
ended December 31, 2005; File No. 001-32395).
Phillips Petroleum Company Stock Plan for Non-Employee Directors (incorporated by reference
to Exhibit 10.22 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2002; File No. 000-49987).
ConocoPhillips Key Employee Supplemental Retirement Plan (incorporated by reference to
Exhibit 10.12 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December
31, 2005; File No. 001-32395).
Defined Contribution Make-Up Plan of ConocoPhillipsTitle I (incorporated by reference to
Exhibit 10.13.1 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2005; File No. 001-32395).
Defined Contribution Make-Up Plan of ConocoPhillipsTitle II (incorporated by reference to
Exhibit 10.13.2 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2005; File No. 001-32395).
Table of Contents
Exhibit
Number
Description
2002 Omnibus Securities Plan of Phillips Petroleum Company (incorporated by reference to
Exhibit 10.26 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December
31, 2002; File No. 000-49987).
1998 Stock and Performance Incentive Plan of ConocoPhillips (incorporated by reference to
Exhibit 10.27 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December
31, 2002; File No. 000-49987).
1998 Key Employee Stock Performance Plan of ConocoPhillips (incorporated by reference to
Exhibit 10.28 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December
31, 2002; File No. 000-49987).
Deferred Compensation Plan for Non-Employee Directors of ConocoPhillips (incorporated by
reference to Exhibit 10.17 to the Annual Report of ConocoPhillips on Form 10-K for the year
ended December 31, 2005; File No. 001-32395).
ConocoPhillips Form Indemnity Agreement with Directors (incorporated by reference to Exhibit
10.34 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31,
2002; File No. 000-49987).
Letter Agreement, dated as of April 12, 2002, between Holding and Jim W. Nokes (incorporated
by reference to Exhibit 10.2 to the Quarterly Report of ConocoPhillips on Form 10-Q for the
quarterly period ended September 30, 2002; File No. 000-49987).
Rabbi Trust Agreement dated December 17, 1999 (incorporated by reference to Exhibit 10.11 of
Holdings Form 10-K for the year ended December 31, 1999, File No. 001-14521).
Amendment to Rabbi Trust Agreement dated February 25, 2002 (incorporated by reference to
Exhibit 10.39.1 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2002; File No. 000-49987).
ConocoPhillips Directors Charitable Gift Program (incorporated by reference to Exhibit
10.40 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31,
2003; File No. 000-49987).
ConocoPhillips Matching Gift Plan for Directors and Executives (incorporated by reference to
Exhibit 10.41 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December
31, 2003; File No. 000-49987).
Key Employee Deferred Compensation Plan of ConocoPhillipsTitle I (incorporated by
reference to Exhibit 10.23.1 to the Annual Report of ConocoPhillips on Form 10-K for the year
ended December 31, 2005; File No. 001-32395).
Key Employee Deferred Compensation Plan of ConocoPhillipsTitle II (incorporated by
reference to Exhibit 10.23.2 to the Annual Report of ConocoPhillips on Form 10-K for the year
ended December 31, 2005; File No. 001-32395).
Table of Contents
Exhibit
Number
Description
ConocoPhillips Key Employee Change in Control Severance Plan (incorporated by reference to
Exhibit 10.1 of the Quarterly Report of ConocoPhillips on Form 10-Q for the quarterly period
ended September 30, 2004; File No. 000-49987).
ConocoPhillips Executive Severance Plan (incorporated by reference to Exhibit 10.25 to the
Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2005; File No.
001-32395).
First and Second Amendments to the ConocoPhillips Executive Severance Plan (incorporated by
reference to Exhibit 10 of the Quarterly Report of ConocoPhillips on Form 10-Q for the
quarterly period ended March 31, 2007; File No. 001-32395).
2004 Omnibus Stock and Performance Incentive Plan of ConocoPhillips (incorporated by
reference to Appendix C of ConocoPhillips Proxy Statement on Schedule 14A relating to the
2004 Annual Meeting of Shareholders; File No. 000-49987).
Aircraft Time Sharing Agreement by and between James J. Mulva and ConocoPhillips
(incorporated by reference to Exhibit 10 of the Quarterly Report of ConocoPhillips on
Form 10-Q for the quarterly period ended June 30, 2007; File No. 001-32395).
Form of Stock Option Award Agreement under the ConocoPhillips Stock Option and Stock
Appreciation Rights Program.
Form of Restricted Stock Unit Award Agreement under the ConocoPhillips Performance Share
Program.
Omnibus Amendments to certain ConocoPhillips employee benefit plans, adopted
December 7, 2007.
Computation of Ratio of Earnings to Fixed Charges.
List of Subsidiaries of ConocoPhillips.
Consent of Independent Registered Public Accounting Firm.
Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities
Exchange Act of 1934.
Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities
Exchange Act of 1934.
Certifications pursuant to 18 U.S.C. Section 1350.
1. | Type and Size of Grant . Subject to the Plan and this Agreement, the Company grants to certain eligible Employees a Nonqualified Stock Option to purchase all or any part of an aggregate number of shares of Common Stock of the Company. In certain countries, grants will be in the form of Stock Appreciation Rights (SARs). Individual awards will be as set forth in the Annual Award Summary given to each Employee to whom an Award is granted. The Annual Award Summary for each Employee is made a part of this Agreement with regard to such Employee. |
2. | Grant Date, Price, and Plan . The grant date is February 14, 2008 and the Grant Price is $79.38 . Awards are made under the 2004 Omnibus Stock and Performance Incentive Plan. |
3. | Term of Awards, Exercise Installments, and Last Date to Exercise . Except as otherwise noted in this Agreement, the following summary table describes term of awards, exercise installments, and last date to exercise, subject to the more detailed provisions set forth below: |
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Summary of Exercise Rules | ||||
Status | Condition | Last Date to Exercise | ||
Active Employee
|
10 years from grant date | |||
|
||||
Retirement (age 55
and 5 years of
service)
|
Prior to 6 months from grant date | Canceled upon Termination | ||
6 months from grant date & after | 10 years from grant date | |||
Layoff
|
Prior to 6 months from grant date | Canceled upon Termination | ||
6 months to 1 year from grant date | 10 years from grant date (award is prorated) | |||
1 year from grant date & after | 10 years from grant date | |||
Disability
|
Any date after grant date | 10 years from grant date | ||
|
||||
Death
|
Any date after grant date | 10 years from grant date | ||
|
||||
Divestitures,
outsourcing, and
moves to joint
ventures
|
Any date after grant date | Canceled upon Termination, unless approval otherwise | ||
|
||||
All other Terminations
|
Canceled upon Termination |
(a) | Exercise Installments and Expiration . Stock Options/SARs granted under this Agreement will become exercisable to the extent that one third of the number of shares of Stock subject to the Stock Option/SAR (rounded down to nearest whole share) shall be exercisable on the first anniversary date of the Stock Option/SAR grant. On the second anniversary date of the Stock Option/SAR grant, an additional one third of the number of shares of Stock (rounded down to nearest whole share) shall become exercisable. On the third anniversary date of the Stock Option/SAR grant, the remaining shares shall become exercisable. To the extent that an installment is not exercised when it becomes first exercisable, it will remain exercisable at any time thereafter until the Award shall be canceled, expire, or be surrendered. A Stock Option or SAR expires on the tenth anniversary of the date on which it was granted. |
(b) | Last Date to Exercise (Terminations) . |
(i) | General Rule for Termination . If, prior to the exercise of Stock Options/SAR grants, the Optionees employment with a Participating Company shall be terminated for any reason except death, Disability, Retirement, or Layoff, such Award shall be canceled and all rights thereunder shall cease; provided that the Authorized Party may, in its or his sole discretion, determine that all or any portion of any other Award shall not be canceled due to Termination of Employment. |
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(ii) | Layoff Within Six Months . If, prior to a date six months from the date an Award is granted, the Optionees employment with a Participating Company shall be terminated by reason of Layoff, such Award shall be canceled and all rights thereunder shall cease. | ||
(iii) | Layoff After Six Months but Within One Year . If, on or after a date six months from the date an Award is granted but prior to a date one year from the date an Award is granted, the Optionees employment with a Participating Company shall be terminated by reason of Layoff, the Optionee shall retain a prorated number of the Award shares granted. The number of Award shares retained will be computed by multiplying the original number of Award shares granted by a fraction, the numerator of which is the number of full months of employment from the first day of the month in which the Award was granted until the date the employee is terminated and the denominator of which is 12. Such calculation shall be rounded down to the nearest whole share. | ||
(iv) | Layoff After One Year . If, on or after a date one year from the date an Award is granted, the Optionees employment with a Participating Company shall be terminated by reason of Layoff, the Optionee shall retain all rights provided by the Award at the time of such Termination of Employment. | ||
(v) | Retirement After Six Months . If, on or after a date six months from the Grant Date of an Award, the Optionees employment with a Participating Company shall be terminated by reason of Retirement, the Optionee shall retain all rights provided by the Award at the time of such Termination of Employment. | ||
(vi) | Disability . If, after the date the Award is granted, an Optionee shall terminate employment following Disability of the Optionee, the Optionee shall retain all rights provided by the Award at the time of such Termination of Employment. | ||
(vii) | Death . If, after the date an Award is granted, an Optionee shall die while in the employ of a Participating Company , or after Termination of Employment by reason of Retirement, Disability, or Layoff (and prior to the cancellation of the Award), the executor or administrator of the estate of the Optionee or the person or persons to whom the Award shall have been validly transferred by the executor or the administrator pursuant to will or the laws of descent and distribution shall have the right to exercise the Award to the same extent the Optionee could have, had the Optionee not died. No transfer of an Award by the Optionee by will or by the laws of descent and distribution shall be effective to bind the Company unless the Company shall have been furnished with written notice thereof and a copy of the will and such other evidence as the Company may deem necessary to establish the validity of the transfer and the acceptance by the transferee or transferees of the terms and conditions of such Award. | ||
(viii) | Transfers and Leaves . Transfer of employment between Participating Companies shall not constitute Termination of Employment for the purpose of any Award granted under the Program. Whether any leave of absence shall constitute Termination of Employment for the purposes of any Award granted under the Program shall be determined in each case in accordance with applicable law and by application of the policies and procedures adopted by the Company in relation to such leave of absence. | ||
(ix) | Divestiture, Outsourcing, or Move to Joint Venture . If, after the date the Award is granted, an Optionee ceases to be employed by a Participating Company as a result of (a) the outsourcing of a function, (b) the sale or transfer of all or a portion of the equity |
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interest of such Participating Company (removing it from the controlled group of companies of which the Company is a part), (c) the sale of all or substantially all of the assets of such Participating Company to another employer outside of the controlled group of corporations (whether the Optionee is offered employment or accepts employment with the other employer), (d) the Termination of the Optionee by Participating Company followed by employment within a reasonable time with a company or other entity in which the Company owns, directly or indirectly, at least a 50% interest, prior to exercise of an Award, or (e) any other sale of assets determined by the Authorized Party to be considered a divestiture under this program, the Authorized Party may, in its or his sole discretion, determine that all or a portion of any such Award shall not be canceled. |
(c) | Detrimental Activities and Suspension of Exercises . |
(i) | If the Authorized Party determines that, subsequent to the grant of any Award, the Employee has engaged or is engaging in any activity which, in the sole judgment of the Authorized Party, is or may be detrimental to the Company or a subsidiary, the Authorized Party may suspend the right of the Employee to exercise, refuse to honor the exercise of such Employees Awards already requested, or cancel all or part of the Award or Awards granted to that Employee. | ||
(ii) | If the Authorized Party, in its or his sole discretion, determines that the exercise of any Award has the possibility of violating any law, regulation, or decree pertaining to the Company, a subsidiary, or the Employee, the Authorized Party may freeze or suspend the Employees right to exercise until such time as the exercise of the Award would no longer, in the sole discretion of the Authorized Party, have the possibility of violating such law, regulation, or decree. |
4. | Exercising the Stock Option . The Company has retained outside firms to administer Stock Options (and SARs) granted under the Plans (the third party administrators). The Option (or SAR) must be exercised in accordance with methods and at times set by the third party administrator and by the Employees delivering to the third party administrators such authorization as may be required. |
5. | Payment for Shares . The Grant Price for all shares of Stock purchased upon the exercise of a Stock Option, or a portion thereof, shall be paid in full at the time of such exercise. Such payment may be made in cash or by tendering shares of Stock having a value on the date of exercise equal to the Grant Price. Such value shall be the average of the high and low trading prices of the stock on the day of exercise. If the Optionee makes payment of the Grant Price by tendering shares of Stock, such Stock must be registered in the sole name of the Optionee on the exercise date or an appropriate Stock Power acceptable to the Company to transfer such stock to the sole name of the Optionee must be provided at the time of exercise. In the case of an Optionee who makes payment of the Grant Price by tendering shares of Stock, if the Company deems it appropriate, and if allowed by the applicable laws, regulations and rulings, the Company may accept an attestation from the Optionee in lieu of actual physical delivery to the Company of the shares to be tendered. The attestation must indicate the number of shares held, and if deemed necessary by the Company, the certificate numbers if the Stock is held in certificate form, or the broker and brokerage account number if the shares are held in a brokerage account, and any other information necessary to confirm ownership of the shares. The Company may not accept an attestation in lieu of physical delivery of the shares unless the shares are held in the sole name of the Optionee either in certificate form, or in a single brokerage account, or in such other form as the Company may deem appropriate. Depending on its source, Stock tendered in the exercise of a Stock Option must have met the appropriate holding period required by current tax, accounting, legal, or other applicable rules and regulations. At the election of the Optionee (but |
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subject to any administrative limitations on exercise of Stock Options or permissible methods of option exercise imposed), the Stock Option may also be exercised by a net-share settlement method for exercising outstanding nonqualified stock options. The Committee, in its sole discretion and judgment, limit the extent to which shares of Stock may be used in exercising Stock Options or limit the use of any method or time of option exercise. |
6. | Assignment of Option and Exercises After Death . Rights under the Plans and this Agreement cannot be assigned or transferred other than by (i) will, (ii) beneficiary designation, or (iii) the laws of descent and distribution. In the event that a beneficiary designation conflicts with an assignment by will or under the laws of descent and distribution, the beneficiary designation will prevail. Upon the death of an Employee, exercise of the grant will be permitted only by the Employees designated beneficiary, executor, or personal representative of the Employees estate. |
7. | Tax Withholding . In the U.S. and many countries, the difference between the Grant Price and the value of the stock at the time of an Option exercise multiplied by the number of shares purchased is compensation subject to tax withholding. The Option exercise will not be completed until all federal, state, local and other governmental withholding tax requirements have been met. Should a withholding tax obligation arise upon the exercise of a Stock Option, the withholding tax may be satisfied by withholding shares of Stock or by payment of cash. This withholding obligation includes, but is not limited to, federal, state, and local taxes, including applicable non-U.S. taxes, such as U.K. PAYE. The plan administrator will take such steps, as it deems necessary or desirable for the withholding of any taxes that are required by laws or regulations of any governmental authority in connection with any exercise. For SARs, the SAR Gain will be paid through the local payroll and is subject to applicable withholding taxes. |
8. | Shareholder Rights . The Employee shall not have the rights of a shareholder until the Option has been exercised and ownership of shares of Common Stock has been transferred to the Employee. SARs never convey shareholder rights. |
9. | Certain Adjustments . In the event certain corporate transactions, recapitalizations, or stock splits occur while a Stock Option (or SAR) is outstanding, the Grant Price and the number of Stock Option Shares (or SARs) shall be correspondingly adjusted. |
10. | Relationship to the Plan . In addition to the terms and conditions described in this Agreement, Awards are subject to all other applicable provisions of the Plan. The decisions of the Committee with respect to questions arising as to the interpretation of the Plan or this Agreement and as to findings of fact shall be final, conclusive, and binding. |
11. | No Employment Guarantee . No provision of this Agreement shall confer any right upon the Employee to continued employment with any Participating Company. |
12. | Governing Law . This Agreement shall be governed by, construed and enforced in accordance with the laws of the State of Delaware. |
13. | Amendment . Without the consent of the Employee, this Agreement may be amended or supplemented (i) to cure any ambiguity or to correct or supplement any provision herein which may be defective or inconsistent with any other provision herein, or (ii) to add to the covenants and agreements of the Company for the benefit of an Employee or to add to the rights of an Employee or to surrender any right or power reserved to or conferred upon the Company in this Agreement, provided, in each case, that such changes or corrections shall not adversely affect the rights of the Employee with respect to the grant of an Option (or SAR) evidenced hereby without the Employees |
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consent, or (iii) to make such other changes as the Company, upon advice of counsel, determines are necessary or advisable because of the adoption or promulgation of, or change in or of the interpretation of, any law or governmental rule or regulation, including any applicable federal or state securities or tax laws. |
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1. | The Termination of the Grantees employment as a result of Layoff of the Grantee; | ||
2. | The Termination of the Grantees employment after attainment of age 55 and completion of 5 years of service with the Company or its subsidiaries; | ||
3. | The Termination of the Grantees employment due to Death; | ||
4. | The Termination of the Grantees employment following Disability of the Grantee; or | ||
5. | The Termination of the Grantees employment following a Change of Control. |
1. | one lump sum payment of unrestricted stock of the Company settled six months after Separation from Service with the Company and its subsidiaries, or | ||
2. | in a series of annual installments, using a declining balance method, over a period of three, five, ten, or fifteen years after Separation from Service with the Company and its subsidiaries. |
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1. | The election to change the time or form of payment may not take effect until at least twelve months after the date on which such election is made; | ||
2. | Payment under such election may not be made earlier than at least five years from the date the payment would have otherwise been made or commenced; | ||
3. | An election may provide for either a lump sum payment or installment payments; | ||
4. | An election to receive payments in installments shall be treated as a single payment for purposes of these rules; | ||
5. | Installment payments may be made only annually, over a period of from one to fifteen years as elected; | ||
6. | The election may not result in an impermissible acceleration of payment prohibited under section 409A of the Internal Revenue Code; | ||
7. | No more than four such elections shall be permitted with respect to the PSUs subject to this Award; and | ||
8. | No payment may be made after the date that is twenty (20) years after the date of the Grantees Separation from Service. |
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2
3
4
5
6
Millions of Dollars | ||||||||||||||||||||
Years Ended December 31 | ||||||||||||||||||||
2007 | 2006 | 2005 | 2004 | 2003 | ||||||||||||||||
Earnings Available for Fixed Charges
|
||||||||||||||||||||
Income from
continuing operations before income taxes and minority interest
|
$ | 23,310 | 28,371 | 23,547 | 14,369 | 8,337 | ||||||||||||||
Distributions less than equity in earnings of fifty-percent-or-less-owned companies
|
(1,839 | ) | (962 | ) | (1,785 | ) | (780 | ) | (52 | ) | ||||||||||
Fixed charges, excluding capitalized interest*
|
1,680 | 1,410 | 747 | 758 | 1,019 | |||||||||||||||
|
$ | 23,151 | 28,819 | 22,509 | 14,347 | 9,304 | ||||||||||||||
|
||||||||||||||||||||
Fixed Charges
|
||||||||||||||||||||
Interest and expense on indebtedness,
excluding capitalized interest
|
$ | 1,253 | 1,087 | 497 | 546 | 844 | ||||||||||||||
Capitalized interest
|
565 | 458 | 395 | 430 | 327 | |||||||||||||||
Preferred dividend requirements of subsidiary
and capital trusts
|
- | - | - | - | - | |||||||||||||||
Interest portion of rental expense
|
171 | 232 | 188 | 174 | 149 | |||||||||||||||
Interest expense relating to guaranteed debt
of fifty-percent-or-less-owned companies
|
19 | - | - | 9 | 1 | |||||||||||||||
Interest expense relating to guaranteed debt
of greater than fifty-percent-owned companies
|
- | - | - | - | - | |||||||||||||||
|
$ | 2,008 | 1,777 | 1,080 | 1,159 | 1,321 | ||||||||||||||
Ratio of Earnings to Fixed Charges
|
11.5 | 16.2 | 20.8 | 12.4 | 7.0 | |||||||||||||||
* | Includes amortization of capitalized interest totaling approximately $237 million in 2007, $92 million in 2006, $62 million in 2005, $29 million in 2004, and $25 million in 2003. |
Incorporation | |||||
Company Name | Location | ||||
Alpine Pipeline Company
|
Delaware | ||||
Ashford Energy Capital S.A.
|
Luxembourg | ||||
BR (Global) Holdings B.V.
|
Netherlands | ||||
BROG LP Inc.
|
Delaware | ||||
Burlington Resources (Irish Sea) Limited
|
England | ||||
Burlington Resources (Netherlands) B.V.
|
Netherlands | ||||
Burlington Resources (UK) Holdings Limited
|
England | ||||
Burlington Resources Algeria LLC
|
Delaware | ||||
Burlington Resources Canada (Hunter) Ltd.
|
Alberta | ||||
Burlington Resources Canada Holding ULC
|
Alberta | ||||
Burlington Resources Canada International Holdings Limited
|
Bermuda | ||||
Burlington Resources Canada Ltd.
|
Alberta | ||||
Burlington Resources Canada Marketing Ltd.
|
Alberta | ||||
Burlington Resources Canada Partnership
|
Alberta | ||||
Burlington Resources China Holdings Limited
|
Bermuda | ||||
Burlington Resources China LLC
|
Delaware | ||||
Burlington Resources Finance Company
|
Nova Scotia | ||||
Burlington Resources Financial Services Inc.
|
Delaware | ||||
Burlington Resources Inc.
|
Delaware | ||||
Burlington Resources International Holdings LLC
|
Delaware | ||||
Burlington Resources International Inc.
|
Delaware | ||||
Burlington Resources Nederland Petroleum B.V.
|
Netherlands | ||||
Burlington Resources Offshore Inc.
|
Delaware | ||||
Burlington Resources Oil & Gas Company LP
|
Delaware | ||||
Burlington Resources Oriente Limited
|
Bermuda | ||||
Burlington Resources Peru Limited
|
Bermuda | ||||
Burlington Resources Trading Inc.
|
Delaware | ||||
Canadian Hunter Resources
|
Alberta | ||||
Clearwater Ltd.
|
Bermuda | ||||
Clyde Petroleum Limited
|
Scotland | ||||
Conoco AG, Zug
|
Switzerland | ||||
Conoco Asia Ltd.
|
Bermuda | ||||
Conoco Central Europe Inc.
|
Delaware | ||||
Conoco Colombia Ltd.
|
Bermuda | ||||
Conoco Development Services Inc.
|
Delaware | ||||
Conoco Funding Company
|
Nova Scotia | ||||
Conoco Global Power Assets Sabine Inc.
|
Delaware | ||||
Conoco Investment AG
|
Switzerland | ||||
Conoco Nordic Holdings AB
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Sweden | ||||
Conoco Nordic Limited
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Bermuda | ||||
1
Incorporation | |||||
Company Name | Location | ||||
Conoco Petroleum Nigeria Limited
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Nigeria | ||||
Conoco Petroleum Operations Inc.
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Delaware | ||||
Conoco Shipping & Marine Development L.L.C.
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Marshall Islands | ||||
Conoco Shipping Company
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Liberia | ||||
Conoco Venezuela C.A.
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Venezuela | ||||
Conoco Venezuela Ltd.
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Bermuda | ||||
ConocoPhillips (03-12) Pty Ltd
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Victoria | ||||
ConocoPhillips (03-13) Pty Ltd
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Western Australia | ||||
ConocoPhillips (AIB) Ltd.
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Bermuda | ||||
ConocoPhillips (East Malaysia) Ltd.
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Bermuda | ||||
ConocoPhillips (GIB) Ltd.
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Bermuda | ||||
ConocoPhillips (Grissik) Ltd.
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Bermuda | ||||
ConocoPhillips (Sakakemang) Ltd.
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Bermuda | ||||
ConocoPhillips (Timor Sea) Pty Ltd
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Western Australia | ||||
ConocoPhillips (U.K.) Alpha Limited
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England | ||||
ConocoPhillips (U.K.) Cuu Long Limited
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England | ||||
ConocoPhillips (U.K.) Eta Limited
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England | ||||
ConocoPhillips (U.K.) Finance Limited
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England | ||||
ConocoPhillips (U.K.) Gama Limited
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England | ||||
ConocoPhillips (U.K.) Lambda Limited
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Ireland | ||||
ConocoPhillips (U.K.) Limited
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England | ||||
ConocoPhillips (U.K.) Theta Limited
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England | ||||
ConocoPhillips (U.K.) Zeta Limited
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England | ||||
ConocoPhillips Alaska Natural Gas Corporation
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Delaware | ||||
ConocoPhillips Alaska, Inc.
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Delaware | ||||
ConocoPhillips Asia Ventures Pte. Ltd.
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Singapore | ||||
ConocoPhillips Australia Exploration Pty Ltd
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Western Australia | ||||
ConocoPhillips Australia Funding Company
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Delaware | ||||
ConocoPhillips Australia Gas Holdings Pty Ltd
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Western Australia | ||||
ConocoPhillips Australia Holdings Pty Ltd
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Australia | ||||
ConocoPhillips Australia Pty Ltd
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Western Australia | ||||
ConocoPhillips Austria GmbH
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Austria | ||||
ConocoPhillips Bohai Limited
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Bahamas | ||||
ConocoPhillips Canada (North) Limited
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Canada | ||||
ConocoPhillips Canada Energy Partnership
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Alberta | ||||
ConocoPhillips Canada Funding Company I
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Nova Scotia | ||||
ConocoPhillips Canada Funding Company II
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Nova Scotia | ||||
ConocoPhillips Canada Limited
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Alberta | ||||
ConocoPhillips Canada Oilsands Limited
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Alberta | ||||
ConocoPhillips Canada Resources Corp.
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Nova Scotia | ||||
ConocoPhillips Central and Eastern Europe Holdings B.V.
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Netherlands | ||||
ConocoPhillips China Inc.
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Liberia | ||||
ConocoPhillips Company
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Delaware | ||||
ConocoPhillips Continental Holding GmbH
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Germany | ||||
2
Incorporation | |||||
Company Name | Location | ||||
ConocoPhillips CR Refining s.r.o.
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Czech Republic | ||||
ConocoPhillips Developments Limited
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England | ||||
ConocoPhillips Energy Holding GmbH
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Germany | ||||
ConocoPhillips Energy Marketing Corp.
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Delaware | ||||
ConocoPhillips European Power Limited
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England | ||||
ConocoPhillips Funding Ltd.
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Bermuda | ||||
ConocoPhillips Gas Company
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Delaware | ||||
ConocoPhillips Germany GmbH
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Germany | ||||
ConocoPhillips Global Funding S.a.r.l.
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Luxembourg | ||||
ConocoPhillips Gulf of Paria B.V.
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Netherlands | ||||
ConocoPhillips Hamaca B.V.
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Netherlands | ||||
ConocoPhillips Holdings Limited
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England | ||||
ConocoPhillips ICHP Limited
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England | ||||
ConocoPhillips Indonesia Holding Ltd.
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British Virgin Islands | ||||
ConocoPhillips Indonesia Inc. Ltd.
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Bermuda | ||||
ConocoPhillips International Holding Ltd.
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British Virgin Islands | ||||
ConocoPhillips International Inc.
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Delaware | ||||
ConocoPhillips International Ventures Ltd.
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Bahamas | ||||
ConocoPhillips Investments Norge AS
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Norway | ||||
ConocoPhillips Iraq Ltd.
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Cayman Islands | ||||
ConocoPhillips Ireland Limited
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Ireland | ||||
ConocoPhillips JET AS
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Norway | ||||
ConocoPhillips JPDA Pty Ltd
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Western Australia | ||||
ConocoPhillips Limited
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England | ||||
ConocoPhillips MENA Ltd.
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Cayman Islands | ||||
ConocoPhillips Mineraloel Grosshandels GmbH
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Germany | ||||
ConocoPhillips New Ventures Ltd.
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Cayman Islands | ||||
ConocoPhillips NGL Marketing (Canada) ULC
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Alberta | ||||
ConocoPhillips Nordic AB
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Sweden | ||||
ConocoPhillips Norge
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Delaware | ||||
ConocoPhillips North Caspian Ltd.
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Liberia | ||||
ConocoPhillips Northern Partnership
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Alberta | ||||
ConocoPhillips Oilsands Partnership II
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Alberta | ||||
ConocoPhillips Petroleum Company U.K. Limited
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England | ||||
ConocoPhillips Petroleum Limited
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England | ||||
ConocoPhillips Petrozuata B.V.
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Netherlands | ||||
ConocoPhillips Pipe Line Company
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Delaware | ||||
ConocoPhillips Pipeline Australia Pty Ltd
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Western Australia | ||||
ConocoPhillips Qatar Funding Ltd.
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Cayman Islands | ||||
ConocoPhillips Qatar Ltd.
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Cayman Islands | ||||
ConocoPhillips Russia Inc.
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Delaware | ||||
ConocoPhillips Sabah Ltd.
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Bermuda | ||||
ConocoPhillips Shipping LLC
|
Delaware | ||||
ConocoPhillips Skandinavia AS
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Norway | ||||
ConocoPhillips Specialty Products Inc.
|
Delaware | ||||
3
Incorporation | |||||
Company Name | Location | ||||
ConocoPhillips Supply and Trading Limited
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England | ||||
ConocoPhillips Surmont Partnership
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Alberta | ||||
ConocoPhillips Timan-Pechora Inc.
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Delaware | ||||
ConocoPhillips Transportation Alaska, Inc.
|
Delaware | ||||
ConocoPhillips Trinidad and Tobago Holdings Inc.
|
Delaware | ||||
ConocoPhillips Vietnam AS
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Norway | ||||
ConocoPhillips WA Exploration Pty Ltd
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Western Australia | ||||
ConocoPhillips WA-248 Pty Ltd
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Western Australia | ||||
ConocoPhillips Western Canada Partnership
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Alberta | ||||
ConocoPhillips Whitegate Refinery Limited
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Ireland | ||||
ConocoPhillips Yanbu Ltd.
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Cayman Islands | ||||
ConocoPhillips Z&M Ltd.
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Cayman Islands | ||||
Continental Oil Company (Nederland) B.V.
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Netherlands | ||||
Continental Oil Company of Libya
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Delaware | ||||
COP Holdings Limited
|
England | ||||
Darwin LNG Pty Ltd
|
Western Australia | ||||
Douglas Oil Company of California
|
California | ||||
Dubai Marketing Company Ltd.
|
Delaware | ||||
Dubai Petroleum Company
|
Delaware | ||||
Eagle Sun Company Limited
|
Liberia | ||||
Glacier Park Company
|
Delaware | ||||
Immingham CHP LLP
|
England | ||||
Immingham Energy Limited
|
England | ||||
Inexco Oil Company
|
Delaware | ||||
International Petroleum Holdings LLC
|
Delaware | ||||
Kayo Oil Company
|
Delaware | ||||
Kenai Tankers LLC
|
Delaware | ||||
Lobo Inc.
|
Delaware | ||||
Norske ConocoPhillips AS
|
Norway | ||||
Phillips (Brass) Limited
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Cayman Islands | ||||
Phillips Coal Company
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Nevada | ||||
Phillips Deepwater Exploration Nigeria Limited
|
Nigeria | ||||
Phillips Gas Company Shareholder, Inc.
|
Delaware | ||||
Phillips International Investments, Inc.
|
Delaware | ||||
Phillips Investment Company
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Nevada | ||||
Phillips Oil Company Nigeria Ltd.
|
Nigeria | ||||
Phillips Petroleum International Corporation
|
Delaware | ||||
Phillips Petroleum International Investment Company
|
Delaware | ||||
Phillips Petroleum Resources, Ltd.
|
Delaware | ||||
Phillips Texas Pipeline Company, Ltd.
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Texas | ||||
Phillips-New Mexico Partners, L.P.
|
Delaware | ||||
Phillips-San Juan Partners, L.P.
|
Delaware | ||||
Pioneer Investments Corp.
|
Delaware | ||||
Polar Tankers, Inc.
|
Delaware | ||||
4
Incorporation | |||||
Company Name | Location | ||||
Seaway Products Pipeline Company
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Texas | ||||
Sooner Insurance Company
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Vermont | ||||
Springtime Holdings Limited
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Cayman Islands | ||||
SRW Cogeneration Limited Partnership
|
Delaware | ||||
Sweeny Coker Investor Sub, Inc.
|
Delaware | ||||
The Louisiana Land and Exploration Company
|
Maryland | ||||
Wabiskaw Explorations Ltd.
|
Alberta | ||||
WesTTex 66 Pipeline Company
|
Delaware | ||||
Wilhelmshavener Raffineriegesellschaft mbH
|
Germany | ||||
World Wide Transport, Inc.
|
Liberia | ||||
66 Pipe Line Company
|
Delaware | ||||
5
ConocoPhillips Form S-3
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File No. 333-133363 | |
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ConocoPhillips Form S-3
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File No. 333-137890 | |
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ConocoPhillips Form S-4
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File No. 333-130967 | |
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ConocoPhillips Form S-8
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File No. 333-98681 | |
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ConocoPhillips Form S-8
|
File No. 333-116216 | |
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ConocoPhillips Form S-8
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File No. 333-133101 |
1. | I have reviewed this annual report on Form 10-K of ConocoPhillips; | |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; | |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; | |
4. | The registrants other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
(a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; | ||
(b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; | ||
(c) | Evaluated the effectiveness of the registrants disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and | ||
(d) | Disclosed in this report any change in the registrants internal control over financial reporting that occurred during the registrants most recent fiscal quarter (the registrants fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrants internal control over financial reporting; and |
5. | The registrants other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrants auditors and the audit committee of the registrants board of directors (or persons performing the equivalent functions): |
(a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrants ability to record, process, summarize and report financial information; and | ||
(b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrants internal control over financial reporting. |
/s/ James J. Mulva
Chairman, President and Chief Executive Officer |
1. | I have reviewed this annual report on Form 10-K of ConocoPhillips; | |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; | |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; | |
4. | The registrants other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
(a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; | ||
(b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; | ||
(c) | Evaluated the effectiveness of the registrants disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and | ||
(d) | Disclosed in this report any change in the registrants internal control over financial reporting that occurred during the registrants most recent fiscal quarter (the registrants fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrants internal control over financial reporting; and |
5. | The registrants other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrants auditors and the audit committee of the registrants board of directors (or persons performing the equivalent functions): |
(a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrants ability to record, process, summarize and report financial information; and | ||
(b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrants internal control over financial reporting. |
/s/ John A. Carrig | ||||
John A. Carrig | ||||
Executive Vice President, Finance, and | ||||
Chief Financial Officer |
(1) | The Report fully complies with the requirements of Sections 13(a) or 15(d) of the Securities Exchange Act of 1934; and | ||
(2) | The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the company. |
/s/ James J. Mulva
|
||||
James J. Mulva | ||||
Chairman, President and Chief Executive | ||||
Officer | ||||
/s/ John A. Carrig | ||||
John A. Carrig | ||||
Executive Vice President, Finance, and
Chief Financial Officer |