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ConocoPhillips 10-K 2009 Documents found in this filing:Table of Contents
2008
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549
Form 10-K
(Mark One)
For the fiscal year ended December 31, 2008
OR
For the transition period from to
Commission file number 001-32395
ConocoPhillips
(Exact name of registrant as specified in its charter)
600 North Dairy Ashford
Houston, TX 77079 (Address of principal executive offices) Registrant’s telephone number, including area code: 281-293-1000
Securities registered pursuant to Section 12(b) of the Act:
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of
the Securities Act. þ Yes o No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or
Section 15(d) of the Act. o Yes þ No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by
Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for
such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. þ Yes o No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is
not contained herein, and will not be contained, to the best of the registrant’s knowledge, in
definitive proxy or information statements incorporated by reference in Part III of this Form 10-K
or any amendment to this Form 10-K. þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a
non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated
filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
(Check one):
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Act). o Yes þ No
The aggregate market value of common stock held by non-affiliates of the registrant on June 30,
2008, the last business day of the registrant’s most recently completed second fiscal quarter,
based on the closing price on that date of $94.39, was $143.4 billion. The registrant, solely for
the purpose of this required presentation, had deemed its Board of Directors and grantor trusts to
be affiliates, and deducted their stockholdings of 741,761 and 42,397,731 shares, respectively, in
determining the aggregate market value.
The registrant had 1,480,240,553 shares of common stock outstanding at January 31, 2009.
Documents incorporated by reference:
Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held on May 13, 2009 (Part III)
TABLE OF CONTENTS
Table of Contents
PART I
Unless otherwise indicated, “the company,” “we,” “our,” “us” and “ConocoPhillips” are used in this
report to refer to the businesses of ConocoPhillips and its consolidated subsidiaries. Items 1 and
2, Business and Properties, contain forward-looking statements including, without limitation,
statements relating to our plans, strategies, objectives, expectations and intentions that are made
pursuant to the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995.
The words “forecast,” “intend,” “believe,” “expect,” “plan,” “schedule,” “target,” “should,”
“goal,” “may,” “anticipate,” “estimate” and similar expressions identify forward-looking
statements. The company does not undertake to update, revise or correct any forward-looking
information. Readers are cautioned that such forward-looking statements should be read in
conjunction with the company’s disclosures under the heading “CAUTIONARY STATEMENT FOR THE PURPOSES
OF THE ‘SAFE HARBOR’ PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995,” beginning
on page 72.
Items 1 and 2. BUSINESS AND PROPERTIES
CORPORATE STRUCTURE
ConocoPhillips is an international, integrated energy company. ConocoPhillips was incorporated in
the state of Delaware on November 16, 2001, in connection with, and in anticipation of, the merger
between Conoco Inc. and Phillips Petroleum Company. The merger between Conoco and Phillips was
consummated on August 30, 2002.
Our business is organized into six operating segments:
At December 31, 2008, ConocoPhillips employed approximately 33,800 people.
SEGMENT AND GEOGRAPHIC INFORMATION
For operating segment and geographic information, see Note 26—Segment Disclosures and Related
Information, in the Notes to Consolidated Financial Statements, which is incorporated herein by
reference.
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EXPLORATION AND PRODUCTION (E&P)
At December 31, 2008, our E&P segment represented 67 percent of ConocoPhillips’ total assets. This
segment explores for, produces, transports and markets crude oil, natural gas, and natural gas
liquids on a worldwide basis. It also mines deposits of oil sands in Canada to extract bitumen and
upgrade it into a synthetic crude oil. Operations to liquefy natural gas and transport the resulting liquefied natural gas (LNG) are also
included in the E&P segment. At December 31, 2008, our E&P operations were producing in the United
States, Norway, the United Kingdom, Canada, Ecuador, Australia, offshore Timor-Leste in the Timor
Sea, Indonesia, China, Vietnam, Libya, Nigeria, Algeria and Russia.
In October 2008, we closed on a transaction with Origin Energy to further enhance our long-term
Australasian natural gas business. The 50/50 joint venture, named Australia Pacific LNG, will
focus on coalbed methane production from the Bowen and Surat basins in Queensland, Australia, and
LNG processing and export sales.
The E&P segment does not include the financial results or statistics from our equity investment in
the ordinary shares of LUKOIL, which are reported in our LUKOIL Investment segment. As a result,
references to results, production, prices and other statistics throughout the E&P segment
discussion exclude amounts related to our investment in LUKOIL. However, our share of LUKOIL is
included in the supplemental oil and gas operations disclosures on pages 147 through 166, as well
as in the net proved reserves table shown below.
The information listed below appears in the supplemental oil and gas operations disclosures and is
incorporated herein by reference:
The following table is a summary of the proved reserves information included in the supplemental
oil and gas operations disclosures. Natural gas reserves are converted to BOE based on a 6:1
ratio: six thousand cubic feet of natural gas converts to one BOE.
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In 2008, E&P’s worldwide production, including its share of equity affiliates’ production other
than LUKOIL, averaged 1,767,000 barrels of oil equivalent per day (BOED), compared with the
1,857,000 averaged in 2007. During 2008, 775,000 BOED were produced in the United States, a
decrease from 843,000 in 2007. Production from our international E&P operations averaged 992,000
BOED in 2008, a decrease compared with 1,014,000 in 2007. In addition, our Canadian Syncrude mining operations had net production of 22,000 barrels
per day in 2008, compared with 23,000 in 2007. The change in worldwide production was primarily
due to field decline and the expropriation of our Venezuelan oil interests, partially offset by
production from new developments primarily in the United Kingdom, Indonesia, Russia, Norway and
Canada.
E&P’s worldwide annual average crude oil sales price increased 39 percent, from $67.11 per barrel
in 2007 to $93.12 in 2008. E&P’s average annual worldwide natural gas sales price increased 32
percent, from $6.26 per thousand cubic feet in 2007 to $8.27 in 2008.
E&P—UNITED STATES
In 2008, U.S. E&P operations contributed 44 percent of E&P’s worldwide liquids production and 43
percent of natural gas production, compared with 46 percent and 45 percent in 2007, respectively.
Alaska
Greater Prudhoe Area
The Greater Prudhoe Area is composed of the Prudhoe Bay field and five satellite fields, as well as
the Greater Point McIntyre Area fields. Prudhoe Bay, the largest oil field on Alaska’s North
Slope, is the site of a large waterflood and enhanced oil recovery operation, as well as a gas
processing plant that processes and re-injects natural gas into the reservoir. Prudhoe Bay’s
satellites include Aurora, Borealis, Polaris, Midnight Sun and Orion, while the Point McIntyre,
Niakuk, Raven and Lisburne fields are part of the Greater Point McIntyre Area. We have a 36.1
percent nonoperator interest in all fields within the Greater Prudhoe Area. Net oil production
from the Greater Prudhoe Area averaged 106,000 barrels per day in 2008, compared with 107,000 in
2007, while natural gas liquids production averaged 17,000 barrels per day in 2008, compared with
19,000 in 2007.
Greater Kuparuk Area
We operate the Greater Kuparuk Area, composed of the Kuparuk field and four satellite fields: Tarn,
Tabasco, Meltwater and West Sak. Kuparuk is located about 40 miles west of Prudhoe Bay. Our
ownership interest in the area is approximately 55 percent. 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. Net oil production from the area averaged 67,000
barrels per day in 2008, compared with 74,000 in 2007.
Western North Slope
The Alpine field and its satellite fields, located west of the Kuparuk field, produced at a net
rate of 70,000 barrels of oil per day in 2008, compared with 80,000 in 2007. We operate and hold a
78 percent interest in Alpine and its three satellites, the Nanuq, Fiord and Qannik fields. The
Qannik field began production in July 2008.
Cook Inlet Area
Our assets include the North Cook Inlet field, the Beluga River field, and the Kenai LNG facility,
all of which we operate. We have a 100 percent interest in the North Cook Inlet field, while we
own 33.3 percent of the Beluga River field. Net production in 2008 from the Cook Inlet Area
averaged 88 million cubic feet per day of natural gas, compared with 101 million in 2007.
Production from the North Cook Inlet field is used primarily to supply our share of gas to the
Kenai LNG plant and also as a backup supply to local utilities, while gas from the Beluga River
field is primarily sold to local utilities and is used as backup supply to the Kenai LNG plant.
We have a 70 percent interest in the Kenai LNG plant, which supplies LNG to two utility companies
in Japan. We sold 27 net billion cubic feet in 2008, compared with 31 billion in 2007. In June
2008, the U.S.
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Department of Energy announced its approval of a two-year extension of the plant’s
export license, extending it through March 2011.
Exploration
We were the successful bidder on 98 blocks totaling $506 million in the February 2008 Chukchi Sea
lease sale. During 2008, our primary area of exploratory drilling activity was in the National
Petroleum Reserve-Alaska on the Western North Slope. Three wells were drilled in the area, and all
three encountered hydrocarbons. One of the wells was expensed as a dry hole, and we are evaluating
the potential for future development of the other two discoveries.
Transportation
We transport the petroleum liquids produced on the North Slope to south-central Alaska through an
800-mile pipeline that is part of the Trans-Alaska Pipeline System (TAPS). We have a 28.3 percent
ownership interest in TAPS, and we also have ownership interests in the Alpine, Kuparuk and Oliktok
pipelines on the North Slope.
Our wholly owned subsidiary Polar Tankers, Inc. manages the marine transportation of our North
Slope production, using five company-owned double-hulled tankers in addition to chartering
third-party vessels as necessary.
During the second quarter of 2008, ConocoPhillips and BP plc formed a limited liability company to
progress the pipeline project named Denali—The Alaska Gas Pipeline. The project, which would move
approximately 4 billion cubic feet per day of Alaska natural gas to North American markets, would
consist of a gas treatment plant on Alaska’s North Slope and a large-diameter pipeline through
Alaska to Alberta, Canada. Should a new pipeline be required to transport gas from Alberta, the
project also could include a large-diameter pipeline from Alberta to the U.S. Lower 48.
Denali announced plans to reach the first major project milestone before year-end 2010. This
milestone is an open season, a process during which the pipeline company seeks customers to make
long-term firm transportation commitments to the project. We expect Denali would seek
certification from the Federal Energy Regulatory Commission (FERC) and the Canadian National Energy
Board if the open season is successful, and thereafter move forward with project construction.
Summer fieldwork related to the project began in late May 2008, primarily in eastern Alaska, and
involved route reconnaissance and environmental studies. In late June 2008, the Denali project was
approved to use FERC’s prefiling process. There is a pipeline project competing with Denali that
is structured under the Alaska Gasline Inducement Act.
U.S. Lower 48
Gulf of Mexico
At year-end 2008, our portfolio of producing properties in the Gulf of Mexico mainly consisted of
one operated field and three fields operated by co-venturers, including:
Net production from our Gulf of Mexico properties averaged 18,000 barrels per day of liquids and 24
million cubic feet per day of natural gas in 2008, compared with 25,000 barrels per day and 36
million cubic feet per day in 2007.
Onshore
Our 2008 onshore production principally consisted of natural gas, with the majority of production
located in the San Juan Basin, Permian Basin, Lobo Trend, Bossier Trend, and panhandles of Texas
and Oklahoma. We also have operations in the Wind River, Anadarko and Fort Worth basins, as well
as in East Texas and northern
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and southern Louisiana. Other onshore ownership includes properties
in the Williston Basin, the Piceance Basin and the Cedar Creek Anticline.
The San Juan Basin, located in northwestern New Mexico and southwestern Colorado, includes the
majority of our coalbed methane (CBM) production. Additionally, we continue to pursue development
opportunities in three conventional formations in the San Juan Basin. Net production from San Juan
averaged 48,000 barrels per day of liquids and 863 million cubic feet per day of natural gas in
2008, compared with 50,000 barrels per day and 971 million cubic feet per day in 2007.
In addition to our CBM production from the San Juan Basin, we also hold CBM acreage positions in
the Uinta Basin in Utah, the Black Warrior Basin in Alabama, and the Piceance Basin in Colorado.
Onshore activities in 2008 were mostly centered on continued optimization and development of
existing assets. Combined production from all Lower 48 onshore fields in 2008 averaged a net 1,970
million cubic feet per day of natural gas and 147,000 barrels per day of liquids, compared with
2,146 million cubic feet per day and 157,000 barrels per day in 2007.
Transportation
In 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 is completing construction of a
1,679-mile natural gas pipeline from Colorado to Ohio that is expected to have an approximate
capacity of 1.8 billion cubic feet per day. A section of the pipeline extending from Colorado to
Missouri was placed in service in May 2008, and construction continues on the remaining portion of
the pipeline project. Full pipeline service extending to Lebanon, Ohio, is expected by June 2009,
while service to the final destination of Clarington, Ohio, is scheduled to begin by year-end 2009.
Exploration
During 2008, we completed 122 gross onshore exploration wells. Most of the wells were located in
the Bakken play in the Williston Basin, the Bossier Trend, and the Fort Worth Basin Barnett play,
all of which are company focus areas. Other areas with active exploration drilling programs
included the Anadarko Basin, Wyoming, Colorado and South Texas.
Gulf of Mexico deepwater leasehold acreage was expanded by successful bidding at federal offshore
lease sales in March and August 2008, with high bids totaling $334 million, adding 22 new blocks.
At year end we had interests in 267 lease blocks totaling 1.1 million net acres. During 2008, we
completed two successful appraisal wells and participated in four deepwater exploration wells.
Three of the exploration wells were expensed as dry holes, and operations on one well continued
into 2009.
E&P—EUROPE
In 2008, E&P operations in Europe contributed 24 percent of E&P’s worldwide liquids production,
compared with 22 percent in 2007. European operations contributed 20 percent of natural gas
production in 2008, compared with 19 percent in 2007. Our European assets are principally located
in the Norwegian and U.K. sectors of the North Sea.
Norway
We operate and hold a 35.1 percent interest in the Greater Ekofisk Area, located approximately 200
miles offshore Norway in the center of the North Sea. The Greater Ekofisk Area is composed of four
producing fields: Ekofisk, Eldfisk, Embla and Tor. Net production in 2008 from the Greater Ekofisk
Area was 99,000 barrels of liquids per day and 100 million cubic feet of natural gas per day,
compared with 103,000 barrels per day and 103 million cubic feet per day in 2007.
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We also have varying ownership interests in other producing fields in the Norwegian sector of the
North Sea and in the Norwegian Sea, including:
Net production from these and other fields in the Norwegian sector of the North Sea and the
Norwegian Sea averaged 68,000 barrels of liquids per day and 139 million cubic feet of natural gas
per day in 2008, compared with 67,000 barrels per day and 133 million cubic feet per day in 2007.
The Alvheim North Sea development achieved first production in June 2008 through a floating
production, storage and offloading (FPSO) vessel and subsea installations. At year-end 2008,
Alvheim was producing at a net rate of 16,000 barrels per day of liquids and 7 million cubic feet
per day of natural gas. Net peak production of 18,000 barrels per day of liquids and 9 million
cubic feet per day of natural gas is expected in the second quarter of 2009.
Transportation
We have interests in the transportation and processing infrastructure in the Norwegian sector of
the North Sea, including interests in the Norpipe Oil Pipeline System and in Gassled, which owns
most of the Norwegian gas transportation system.
Exploration
We participated in seven exploration wells during 2008, with five of the wells encountering
hydrocarbons. Two gas discoveries were made in the PL218 license, and two others were made in the
Oseberg area. A discovery was also made on the East Flank of the Visund field, and operations in
this well continued into 2009. In late 2008, we were awarded two Norway exploration licenses, both
in the central North Sea.
United Kingdom
In addition to our 58.7 percent interest in the Britannia natural gas and condensate field, we own
50 percent of Britannia Operator Limited, the operator of the field. Net production from Britannia
and its satellite fields averaged 277 million cubic feet of natural gas per day and 24,000 barrels
of liquids per day in 2008, compared with 252 million cubic feet per day and 10,000 barrels per day
in 2007. We achieved first production from two Britannia satellites, Callanish and Brodgar, in
June and July 2008, respectively. We have a respective 83.5 percent interest and a 75 percent
interest in these satellite fields.
We operate and hold a 36.5 percent interest in the Judy/Joanne fields, which together make up
J-Block. Additionally, our operated Jade field, in which we hold a 32.5 percent interest, produces
from a wellhead platform and pipeline tied to J-Block facilities. Together, these fields produced
a net 13,000 barrels of liquids per day and 88 million cubic feet of natural gas per day in 2008,
compared with 14,000 barrels per day and 94 million cubic feet per day in 2007.
Our various ownership interests in 18 producing gas fields in the Rotliegendes and Carboniferous
areas of the southern North Sea yielded average net production in 2008 of 241 million cubic feet
per day of natural gas, compared with 276 million in 2007.
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We also have ownership interests in several other producing fields in the U.K. sector of the North
Sea, including:
Production from these and other remaining fields in the U.K. sector of the North Sea averaged a net
17,000 barrels of liquids per day and 14 million cubic feet of natural gas per day in 2008,
compared with 20,000 barrels per day and 15 million cubic feet per day in 2007.
In the Atlantic Margin, we have a 24 percent interest in the Clair field. Net production in 2008
averaged 11,000 barrels of liquids per day, compared with 7,000 in 2007.
The Millom, Dalton and Calder fields in the East Irish Sea, in which we have a 100 percent
ownership interest, are operated on our behalf by a third party. Net production in 2008 averaged
43 million cubic feet of natural gas per day, compared with 36 million in 2007.
Transportation
The Interconnector pipeline, linking the United Kingdom and Belgium, facilitates marketing natural
gas produced in the United Kingdom throughout Europe. Our 10 percent equity share allows us to
ship approximately 200 million cubic feet of natural gas per day to markets in continental Europe,
and our reverse-flow rights provide an 85 million cubic feet per day import capability into the
United Kingdom.
We operate the Teesside oil and Theddlethorpe gas terminals, in which we have 29.3 percent and 50
percent ownerships, respectively. We also have a 100 percent ownership interest in the Rivers Gas
Terminal, operated by a third party, in the United Kingdom.
Exploration
During 2008 we were awarded interests in three exploration licenses: two in the central North Sea
and one in the West of Shetland region. We also participated in three appraisal wells and three
exploration wells in the Southern Gas Basin, central North Sea and the West of Shetland region,
with four of the wells encountering hydrocarbons. Three of these six wells were drilled in the
proximity of the Jasmine discovery and confirmed the viability of that project.
Netherlands
Our varying nonoperator 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, were sold in
December 2008. Net production in 2008 averaged 50 million cubic feet of natural gas per day,
compared with 52 million in 2007.
E&P—CANADA
In 2008, E&P operations in Canada contributed 8 percent of E&P’s worldwide liquids production
(excluding Syncrude production), compared with 7 percent in 2007. Canadian operations contributed
22 percent of E&P’s worldwide natural gas production in 2008 and 2007.
Oil and Gas Operations
Western Canada
Operations in western Canada encompass properties throughout Alberta, northeastern British
Columbia, and southern Saskatchewan. Net production from these oil and gas operations in western
Canada averaged 44,000 barrels per day of liquids and 1,054 million cubic feet per day of natural
gas in 2008, compared with 46,000 barrels per day and 1,106 million cubic feet per day in 2007.
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Surmont
We operate and have a 50 percent interest in the Surmont oil sands 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. Average net production
of bitumen from Surmont during 2008 was 6,000 barrels per day, and the 2008 average sales price was
$46.85 per barrel. Net peak production of 13,000 barrels per day is expected in 2013.
FCCL
On January 3, 2007, we closed on a business venture with EnCana Corporation to create an integrated
North American heavy oil business. The venture consists of two 50/50 business ventures: a Canadian
upstream general partnership, the FCCL Oil Sands Partnership, and a U.S. downstream limited
liability company, WRB Refining LLC. FCCL’s operating assets consist of the Foster Creek and
Christina Lake SAGD bitumen projects, both located in the eastern flank of the Athabasca oil sands
in northeastern Alberta. EnCana is the operator and managing partner of FCCL. With Christina Lake
phase 1B becoming operational in mid-2008 and the continuing ramp-up of Foster Creek phase C, our
share of FCCL’s production increased to 30,000 barrels per day in 2008, compared with 27,000 in
2007. Foster Creek phases D and E are expected to add additional production of more than 20,000
net barrels per day combined and are expected to become operational in early 2009. The average
sales price realized on FCCL’s 2008 production was $58.54 per barrel. See the Refining and
Marketing (R&M) section for information on WRB.
Parsons Lake/Mackenzie Gas Project
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. The Joint Review
Panel (JRP), an independent body appointed by the Minister of Environment to evaluate the potential
impacts of the project on the environment and lives of the people in the project area, completed
public hearings in November 2007. The JRP issued a press release in December 2008, indicating a
report assessing the environmental and socio-economic impact of the proposed project would be
released in December 2009. The pipeline project awaits the JRP report and will continue to
progress toward regulatory authorizations, but it has deferred detailed engineering work pending
resolution with the federal government on the fiscal and commercial framework.
Exploration
We hold exploration acreage in four areas of Canada: western Canada, offshore eastern Canada, the
Mackenzie Delta/Beaufort Sea region, and the Arctic Islands. In 2008, the company added 62,000
acres in the Horn River play in western Canada and acquired two additional Beaufort licenses.
Within western Canada, we participated in 43 exploratory wells.
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. 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. Net production averaged 22,000 barrels per day in 2008, compared with 23,000 in
2007.
U.S. Securities and Exchange Commission regulations currently in effect define the Syncrude project
as mining-related and not part of conventional oil and gas operations. As such, Syncrude
operations are not included in our proved oil and gas reserves or production as reported in our
supplemental oil and gas information.
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E&P—SOUTH AMERICA
In 2008, E&P operations in South America contributed 1 percent of E&P’s worldwide liquids
production, compared with 5 percent in 2007.
Venezuela
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 Venezuelan government’s Nationalization Decree. In
response, Venezuela’s national oil company, 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.
Plataforma Deltana Block 2
We have a 40 percent nonoperated interest in Plataforma Deltana Block 2 which holds a gas discovery
made by PDVSA. Several critical components required to progress an investment decision have not
yet been defined by the govenment.
Peru
At year-end 2008, we held ownership interests in five exploration blocks in Peru. Two 2D seismic
programs were carried out during the year in Blocks 39 and 104, and the sale of Block 57 was
completed in the second quarter of the year. In the fourth quarter of 2008, we completed an
appraisal well in Block 39, but the well did not confirm a stand-alone commercial hydrocarbon
accumulation. The appraisal well and suspended discovery well were expensed as dry holes.
Ecuador
In Ecuador, we own a 42.5 percent interest in Block 7 and a 46.3 percent interest in Block 21. Net
production in 2008 averaged 9,000 barrels of crude oil per day, compared with 10,000 in 2007.
Argentina
We sold our assets in Argentina in September 2008.
E&P—ASIA PACIFIC
In 2008, E&P operations in the Asia Pacific region contributed 11 percent of E&P’s worldwide
liquids production and 13 percent of natural gas production, compared with 10 percent and 11
percent in 2007, respectively.
Australia and Timor Sea
Australia Pacific LNG
In October 2008, we closed on a transaction with Origin Energy, an integrated Australian energy
company, to further enhance our long-term Australasian natural gas business. The 50/50 joint
venture, named Australia Pacific LNG, will focus on coalbed methane (CBM) production from the Bowen
and Surat basins in Queensland, Australia, and LNG processing and export sales. With this
transaction, we gained access to CBM resources in Australia and will enhance our LNG position with
the expected creation of an additional LNG hub targeting Asia Pacific markets. Four LNG trains are
anticipated, each currently expected to process an estimated 3.5 million gross tons of LNG per
year. An estimated 20,500 gross wells are ultimately envisioned to supply both the domestic gas
market and the LNG development. Drilling and production operations will be supported by gas
gathering systems and centralized gas processing and compression stations, as well as by dewatering
and water treatment facilities.
Our share of the joint venture’s year-end production rate was 68 million cubic feet per day.
Current production is sold into the Australian domestic market. CBM field development work is
ongoing in parallel with front-end engineering associated with the planned LNG processing
facilities.
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Bayu-Undan
We operate and hold a 57.2 percent ownership interest in the Bayu-Undan field located in the Timor
Sea. The field averaged a net production rate of 36,000 barrels of liquids per day in 2008,
compared with 34,000 in 2007. Our share of natural gas production was 210 million cubic feet per
day in 2008, compared with 189 million in 2007. Produced natural gas is used to supply the Darwin
LNG plant, of which we own a 57.2 percent interest. In 2008, we sold 159 billion gross cubic feet
of LNG to utility customers in Japan, compared with 140 billion in 2007.
Greater Sunrise
We have a 30 percent interest in the Greater Sunrise gas and condensate field located in the Timor
Sea. Although agreement has been reached between the governments of Australia and Timor-Leste
concerning sharing of revenues from the anticipated development of Greater Sunrise, key challenges
to be resolved before significant funding commitments can be made include ensuring the reservoir is
adequately appraised, gaining co-venturer and government alignment on the development concept, and
establishing fiscal stability arrangements. Immediate activity is focused on reprocessing seismic
data and integrating the results of an appraisal well to define the remaining appraisal program, as
well as advancing the development concept screening phase.
Western Australia
In 2008, our share of production from the Athena/Perseus (WA-17-L) gas field, located offshore
Western Australia, was 35 million cubic feet of natural gas per day, compared with 34 million in
2007.
Exploration
In November 2008, we acquired 50 percent interests in two permits in the Arafura Basin, offshore
Northern Territory. In the Bonaparte Basin, we drilled one successful appraisal well at the
Sunrise field. Additionally, seismic processing from the NT/P69 and the NT/P61 permits was
completed, and interpretation of this data is currently under way to further evaluate the Caldita
and Barossa discoveries.
The company also operates the WA-314-P, WA-315-P and WA-398-P permits in the Browse Basin. During
2008, acquisition and processing of seismic data in WA-398-P was completed. An exploration
drilling campaign will be conducted in these permits during 2009.
Indonesia
We operate seven production sharing contracts (PSCs) in Indonesia. Production from Indonesia in
2008 averaged a net 343 million cubic feet per day of natural gas and 15,000 barrels per day of
oil, compared with 330 million cubic feet per day and 12,000 barrels per day in 2007. 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, Amborip VI, Kuma and Arafura Sea. The
South Natuna Sea Block B PSC, in which we have a 40 percent interest, has two producing oil fields
and 16 gas fields in various stages of development.
We operate three onshore PSCs. Corridor and South Jambi B are in South Sumatra, and Warim is in
Papua. As part of the Corridor PSC, in which we have a 54 percent interest, we operate six oil
fields and six natural gas fields, and supply natural gas from the Grissik and Suban gas processing
plants to the Duri steamflood in central Sumatra and to markets in Singapore, Batam and West Java.
We have a 45 percent interest in the South Jambi B PSC, a shallow gas project that supplies natural
gas to Singapore.
Transportation
We are a 35 percent owner of a consortium company that has a 40 percent ownership in PT
Transportasi Gas Indonesia, which owns and operates the Grissik to Duri and Grissik to Singapore
natural gas pipelines.
Exploration
In
November 2008, we acquired the Arafura Sea Block, and a 2D seismic survey was completed on the
block by year end. One appraisal well was drilled at the South Belut field, and one appraisal well
and one exploration well were drilled at the North Belut field.
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China
Production related to our 49 percent share of the Peng Lai 19-3 field in Bohai Bay Block 11-05
averaged 14,000 barrels of oil per day in 2008, compared with 10,000 in 2007. We also hold a 49
percent interest in the nearby Peng Lai 25-6 field. An FPSO vessel to accommodate production from
both fields is expected to be installed in early 2009. Concurrent development of both fields
continues.
The Xijiang development consists of two fields located approximately 80 miles south of Hong Kong in
the South China Sea. Our ownership in these fields ranges from 12.3 percent to 24.5 percent.
Facilities include two manned platforms and an FPSO vessel. Combined net production of oil from the Xijiang fields averaged
7,000 barrels per day in 2008, compared with 8,000 in 2007.
We have a 24.5 percent interest in the offshore Panyu field, also located in the South China Sea,
which produced 12,000 net barrels of oil per day in 2008 and 13,000 in 2007. In July 2008, we sold
our 100 percent interest in the onshore Ba Jiao Chang natural gas field.
Vietnam
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 have a 23.3 percent interest in Block 15-1 in the Cuu Long Basin. Net production in 2008 was
13,000 barrels of oil per day, compared with 14,000 in 2007. The oil is processed through a
1-million-barrel FPSO vessel and through the Su Tu Vang central processing platform and new
floating storage and offloading (FSO) vessel. First oil production from the Su Tu Vang satellite
field was achieved in October 2008.
Also in the Cuu Long Basin, we have a 36 percent interest in the Rang Dong field in Block 15-2.
All wellhead platforms produce into an FSO vessel. Net production in 2008 was 9,000 barrels per
day of liquids and 16 million cubic feet per day of natural gas, compared with 8,000 barrels per
day and 15 million cubic feet per day in 2007.
Transportation
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.
Exploration
In 2008, we drilled one exploration well in Block 15-1 that was expensed as a dry hole.
Malaysia
We have interests in three deepwater PSCs located off the eastern Malaysian state of Sabah: Block
G, Block J, and the Kebabangan Cluster. Development of the Gumusut discovery in Block J continues.
Exploration
In 2008, we completed two successful appraisal wells in Block G to evaluate the prior Ubah and
Petai discoveries. Kebabangan and Malikai, a Block G discovery, are moving toward field
development.
E&P—MIDDLE EAST AND AFRICA
During 2008, E&P operations in the Middle East and Africa contributed 8 percent of E&P’s worldwide
liquids production and 2 percent of natural gas production, the same as in 2007.
Qatar
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 Qatar’s North field. The project also includes a 7.8-million-gross-ton-per-year LNG facility,
from which LNG will be shipped in
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new LNG
carriers destined for sale in the United States and other markets. The first LNG cargoes are expected to be
loaded in the fourth quarter of 2010.
In order to capture cost savings, Qatargas 3 is executing the development of the onshore and
offshore assets as a single integrated project with Qatargas 4, a joint venture between Qatar
Petroleum and Royal Dutch Shell plc. This includes the joint development of offshore facilities
situated in a common offshore block in the North field, as well as the construction of two
identical LNG process trains and associated gas treating facilities for both the Qatargas 3 and
Qatargas 4 joint ventures. Upon completion of the Qatargas 3 and Qatargas 4 projects, production
from the LNG plant and associated facilities will be combined and shared.
We have a 12.4 percent ownership interest in the Golden Pass LNG regasification facility and
associated pipeline. The facilities are currently being constructed on the Sabine-Neches
Industrial Ship Channel northwest of Sabine Pass, Texas. Subject to the negotiation of definitive
agreements, ConocoPhillips will also secure capacity rights in the regasification terminal and
pipeline to manage the LNG we will purchase from Qatargas 3. In addition to the United States,
other market alternatives for Qatargas 3 LNG production are being pursued. Despite sustaining some
damage during Hurricane Ike, the Golden Pass LNG terminal is expected to be operational in time to
receive the first cargoes of Qatargas 3 production.
Libya
ConocoPhillips holds a 16.3 percent interest in the Waha concessions in Libya, which encompass
nearly 13 million gross acres. Net oil production averaged 47,000 barrels per day in 2008 and
2007.
Nigeria
During 2008, we produced from four onshore Oil Mining Leases (OMLs), in which we have a 20 percent
nonoperator interest. Net production from these leases was 21,000 barrels of liquids per day and
105 million cubic feet of natural gas per day in 2008, compared with 19,000 barrels per day and 117
million cubic feet per day in 2007.
We have a 20 percent interest in a 480-megawatt gas-fired power plant in Kwale, Nigeria, which
supplies electricity to Nigeria’s national electricity supplier. In 2008, the plant consumed 11
million net cubic feet per day of natural gas sourced from our proved reserves in the OMLs.
We have a 17 percent equity interest in Brass LNG Limited, which plans to construct an LNG facility
in the Niger Delta.
Exploration
We drilled an exploration well in block OPL214 that did not confirm commercial quantities of
hydrocarbons and was expensed as a dry hole. Development planning activities for the prior Uge
discovery in the same block continue. In the fourth quarter of 2007, we assigned our interest in
OPL248 to a co-venturer. This assignment was formally acknowledged by the Nigerian government in
the third quarter of 2008.
Abu Dhabi
In July 2008, we signed an Interim Agreement with the Abu Dhabi National Oil Company (ADNOC) to
develop the Shah gas field in Abu Dhabi. This large-scale project involves the development of
natural gas condensate reservoirs within the onshore Shah gas field, the construction of a new
1-billion-cubic-feet-per-day natural gas processing plant at Shah, new natural gas and liquid
pipelines, and sulfur-exporting facilities at Ruwais. ADNOC would have a 60 percent interest and
we would have a 40 percent interest in the project. We are currently working on final project
agreements with ADNOC.
Algeria
We have interests in three fields in Block 405a: the Menzel Lejmat North field, the Ourhoud field,
and the development stage El Merk (EMK) oil field unit. Net production from these fields averaged
13,000 barrels of oil per day in 2008, compared with 11,000 in 2007.
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E&P—RUSSIA AND CASPIAN
Russia
Polar Lights
We have a 50 percent equity interest in Polar Lights Company, an entity created to develop fields
in the Timan-Pechora Basin in northern Russia. Net production averaged 11,000 barrels of oil per
day in 2008, compared with 12,000 in 2007.
NMNG
We have a 30 percent ownership interest with a 50 percent governance interest in OOO
Naryanmarneftegaz (NMNG), a joint venture with LUKOIL. NMNG is working to develop resources in the
northern part of Russia’s Timan-Pechora province, including the Yuzhno Khylchuyu (YK) field.
Initial production from YK was achieved in June 2008, with the field producing at a net rate of
24,000 barrels of oil per day at year end. Net peak production of 45,000 barrels per day is
expected to be reached in the second quarter of 2009. Production from the NMNG joint venture
fields is transported via pipeline to LUKOIL’s terminal at Varandey Bay on the Barents Sea and then
shipped via tanker to international markets. Late in the second quarter of 2008, LUKOIL completed
an expansion of the terminal’s gross oil-throughput capacity from 30,000 barrels per day to 240,000
barrels per day to accommodate production from the YK field.
Caspian
In the Caspian Sea, we have an interest in the Republic of Kazakhstan’s North Caspian Sea
Production Sharing Agreement (NCSPSA), which includes the Kashagan field. The first phase of field
development currently being executed includes construction of artificial drilling islands with
processing facilities and living quarters, and pipelines to carry production onshore. First
production is expected in the latter part of 2012. The initial production phase of the contract is
for 20 years, with options to extend the agreement an additional 20 years.
In 2004, the Republic of Kazakhstan approved the submitted development plan and budget relating to
the Kashagan oil field development and, in 2007, triggered dispute proceedings under the NCSPSA
following submission of a revised development plan and budget reflecting Kashagan cost increases
and schedule delays. Definitive agreements were signed October 31, 2008, resolving the Kashagan
field development dispute and allowing Kazakhstan’s state-owned energy company, JSC National
Company KazMunayGas, to increase its ownership interest from 8.33 percent to 16.81 percent. As a
result, our interest in the NCSPSA was reduced from 9.26 percent to 8.40 percent, effective January
1, 2008. We will receive our share of the purchase price plus accrued interest in three annual
installments beginning from the date of first commercial production. In addition, a new joint
operating company, with significant involvement from the owners, was established and will operate
future phases of Kashagan. We will have seconded employees in the joint operating company.
Transportation
We have a 2.5 percent interest in the Baku-Tbilisi-Ceyhan (BTC) pipeline, which transports crude
oil from the Caspian region through Azerbaijan, Georgia and Turkey for tanker loadings at the port
of Ceyhan.
Exploration
In October 2008, we signed a Memorandum of Understanding to negotiate terms for the exploration and
development of the N Block, located offshore Kazakhstan,
under a new subsoil use contract. Subsequently, in December 2008, we
signed a Heads of Agreement that would give us a 24.5 percent
interest in the exploration and development of the N Block. In
addition, development studies continue for the next phase of Kashagan and the satellite fields of
Kalamkas, Kairan and Aktote.
E&P—OTHER
LNG
We have a long-term agreement with Freeport LNG Development, L.P. to use 0.9 billion cubic feet per
day of regasification capacity at Freeport’s 1.5-billion-cubic-feet-per-day LNG receiving terminal
in Quintana, Texas. The terminal became operational late in the second quarter of 2008. In order
to deliver natural gas from the Freeport terminal to market, we constructed a 32-mile, 42-inch
pipeline from the Freeport terminal to a point near Iowa Colony, Texas. Construction was completed
in the second quarter of 2008 to coincide with the
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Freeport terminal startup. Due to present
market conditions, which favor the flow of LNG to European and Asian markets, our near-to-mid-term
utilization of the Freeport terminal is expected to be limited. We are responsible for monthly
process-or-pay payments to Freeport irrespective of whether we utilize the terminal for
regasification. The financial impact of this capacity underutilization is not expected to be
material to our future earnings or cash flows.
We received planning permission in 2008 for an LNG regasification facility and combined heat and
power plant at the existing Norsea Pipeline Limited oil terminal site at Teesside, United Kingdom.
Commercial
Our Commercial organization optimizes the commodity flows of our E&P segment. This group markets
our crude oil and natural gas production, using commodity buyers, traders and marketers in offices
in the United States, the United Kingdom, Singapore, Canada and Dubai.
E&P—RESERVES
We have not filed any information with any other federal authority or agency with respect to our
estimated total proved reserves at December 31, 2008. No difference exists between our estimated
total proved reserves for year-end 2007 and year-end 2006, which are shown in this filing, and
estimates of these reserves shown in a filing with another federal agency in 2008.
DELIVERY COMMITMENTS
We sell crude oil and natural gas from our E&P producing operations under a variety of contractual
arrangements, some of which specify the delivery of a fixed and determinable quantity. Our
Commercial organization also enters into natural gas sales contracts where the source of the
natural gas used to fulfill the contract can be the spot market or a combination of our reserves
and the spot market. Worldwide, we are contractually committed to deliver approximately 6 trillion
cubic feet of natural gas and 119 million barrels of crude oil in the future, including
approximately 800 billion cubic feet related to the minority interests of consolidated
subsidiaries. These contracts have various expiration dates through the year 2025. We expect to
fulfill the majority of these delivery commitments with proved developed reserves. In addition, we
anticipate using proved undeveloped reserves and spot market purchases to fulfill these
commitments. See the disclosure on “Proved Undeveloped Reserves” in Management’s Discussion and
Analysis of Financial Condition and Results of Operations, for information on the development of
proved undeveloped reserves.
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MIDSTREAM
At December 31, 2008, our Midstream segment represented 1 percent of ConocoPhillips’ total assets.
Our Midstream business is primarily conducted through our 50 percent equity investment in DCP
Midstream, LLC, a joint venture with Spectra Energy.
The Midstream business purchases raw natural gas from producers and gathers natural gas through
extensive pipeline gathering systems. The gathered natural gas is then processed to extract
natural gas liquids. The remaining “residue” gas is marketed to electrical utilities, industrial
users and gas marketing companies. Most of the natural gas liquids are fractionated—separated
into individual components like ethane, butane and propane—and marketed as chemical feedstock,
fuel or blendstock. Total natural gas liquids extracted in 2008, including our share of DCP
Midstream, were 188,000 barrels per day, compared with 211,000 in 2007.
DCP Midstream markets a portion of its natural gas liquids to ConocoPhillips and Chevron Phillips
Chemical Company LLC under a supply agreement that continues until December 31, 2014. This
purchase commitment is on an “if-produced, will-purchase” basis and so has no fixed production
schedule, but has had, and is expected over the remaining term of the contract to have, a
relatively stable purchase pattern. Under the agreement, natural gas liquids are purchased at
various published market index prices, less transportation and fractionation fees.
DCP Midstream is headquartered in Denver, Colorado. At December 31, 2008, DCP Midstream owned or
operated 53 natural gas liquids extraction and 10 natural gas liquids fractionation plants, and its
gathering and transmission systems included approximately 60,000 miles of pipeline. In 2008, DCP
Midstream’s raw natural gas throughput averaged 6.2 billion cubic feet per day, and natural gas
liquids extraction averaged 360,000 barrels per day, compared with 5.9 billion cubic feet per day
and 363,000 barrels per day in 2007. DCP Midstream’s assets are primarily located in the following
producing regions of the United States: Rocky Mountains, Midcontinent, Permian, East Texas/North
Louisiana, South Texas, Central Texas, and Gulf Coast.
Outside of DCP Midstream, our U.S. natural gas liquids business included the following as of
year-end 2008:
We also own a 39 percent equity interest in Phoenix Park Gas Processors Limited, a joint venture
principally with the National Gas Company of Trinidad and Tobago Limited. Phoenix Park processes
natural gas in Trinidad and markets natural gas liquids in the Caribbean, Central America and the
U.S. Gulf Coast. Its facilities include a 1.35-billion-cubic-feet-per-day gas processing plant and
a 70,000-barrel-per-day natural gas liquids fractionator. A third gas processing train is
currently under construction and, when complete in 2009, will bring Phoenix Park’s total processing
capacity to 2 billion cubic feet per day. Our share of natural gas liquids extracted averaged
8,000 barrels per day in 2008 and 2007. Our share of fractionated liquids averaged 14,000 barrels
per day in 2008, compared with 13,000 in 2007.
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REFINING AND MARKETING (R&M)
At December 31, 2008, our R&M segment represented 24 percent of ConocoPhillips’ total assets. R&M
operations encompass refining crude oil and other feedstocks into petroleum products (such as
gasolines, distillates and aviation fuels); buying, selling and transporting crude oil; and buying,
transporting, distributing and marketing petroleum products. R&M has operations in the United
States, Europe and the Asia Pacific region. The R&M segment does not include the results or
statistics from our equity investment in LUKOIL, which are reported in our LUKOIL Investment
segment.
Our Commercial organization optimizes the commodity flows of our R&M segment. This organization
procures feedstocks for R&M’s refineries, facilitates supplying a portion of the gas and power
needs of the R&M facilities, supplies petroleum products to our marketing operations, and markets
petroleum products directly to third parties. Commercial has buyers, traders and marketers in
offices in the United States, the United Kingdom, Singapore, Canada and Dubai.
R&M—UNITED STATES
Refining
At December 31, 2008, we owned or had an interest in 12 operated refineries in the United States.
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Primary crude oil characteristics and sources of crude oil for our U.S. refineries are as follows:
Capacities for and yields of clean products, as well as other products produced, relating to our
U.S. refineries are as follows:
MSLP
ConocoPhillips has a 50 percent interest in Merey Sweeny, L.P. (MSLP), a limited partnership that
owns a 70,000-barrel-per-day delayed coker and related facilities at the Sweeny refinery that
produce fuel-grade petroleum coke. Petróleos de Venezuela S.A. (PDVSA), which owns the other 50
percent interest, supplies the refinery with heavy, high-sulfur crude oil. We are the operator and
managing partner. Late in 2008, PDVSA notified us that January 2009 nominated crude oil supplies
for MSLP would not be delivered due to Venezuelan government-ordered production reductions.
Similar notifications have been received for nominated supplies for February and March. We
processed alternative crude oils at MSLP during January. Late in January, MSLP entered into a
planned turnaround, which will continue into March 2009.
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WRB
On January 3, 2007, we closed on a business venture with EnCana Corporation to create an integrated
North American heavy oil business. The venture consists of two 50/50 business ventures: a Canadian
upstream general partnership, the FCCL Oil Sands Partnership, and a U.S. downstream limited
liability company, WRB Refining LLC. WRB consists of the Wood River and Borger refineries, located
in Roxana, Illinois, and Borger, Texas, respectively. We are the operator and managing partner of
WRB. For the Wood River refinery, operating results are shared 50/50. For the Borger refinery, we
were entitled to 65 percent of the operating results in 2008, with our share decreasing to 50
percent in all years thereafter. See the Exploration and Production (E&P) section for additional
information on FCCL.
Since formation, the joint venture has expanded the processing capability of heavy Canadian crude
to 95,000 barrels per day from 60,000 barrels per day with the startup of a coker at Borger in
2007. In addition, during 2008, the final permit was received and plans were progressed to expand
the Wood River refinery, including the installation of a coker. With the completion of this
project, anticipated in 2011, total processing capability of heavy Canadian or similar crudes at
Wood River will increase to 225,000 barrels per day, and existing asphalt production at the
refinery will be replaced with production of upgraded products.
Capital Projects
In 2008, capital was directed toward projects to meet environmental and air emission standards and
to further improve the operating reliability, safety and energy efficiency of processing units. In
addition, capital was spent for small projects that are expected to yield an incremental return
through providing improvements in overall transportation fuel yields and product mix.
Significant projects during 2008 included progressing an expansion of a hydrocracker at the Rodeo
facility of our San Francisco refinery. When complete in 2009, this project is expected to
increase clean product yield at the refinery. We also installed wet gas scrubbers at our Los
Angeles and Ponca City refineries in order to improve air emissions from those plants. Another
project completed during the year was a coker upgrade at our Los Angeles refinery, which improved
the yield of transportation fuels.
Marketing
In the United States as of December 31, 2008, R&M marketed gasoline, diesel and aviation fuel
through approximately 8,340 outlets in 49 states. The majority of these sites utilize the Phillips
66, Conoco or 76 brands.
Wholesale
At December 31, 2008, our wholesale operations utilized a network of marketers operating
approximately 7,270 outlets that provided refined product offtake from our refineries, including
Borger and Wood River. 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 addition to automotive gasoline and diesel, we produce and market aviation gasoline, which is
used by smaller, piston engine aircraft. At December 31, 2008, aviation gasoline and jet fuel were
sold through independent marketers at approximately 630 Phillips 66-branded locations in the United
States.
Retail
At December 31, 2008, our retail operations consisted of approximately 330 owned and operated sites
under the Conoco, Phillips 66 and 76 brands. Company-operated retail operations were focused in 10
states, mainly in the Midcontinent, Rocky Mountain and West Coast regions. Most of these outlets
marketed merchandise through the Kicks or Circle K brand convenience stores.
At December 31, 2008, CFJ Properties, our 50/50 joint venture with Flying J, owned and operated
approximately 110 truck travel plazas that carry the Conoco, Flying J or both brands. Flying J
filed for Chapter 11 bankruptcy protection in December 2008. Flying J continues to operate the CFJ
properties jointly owned with ConocoPhillips.
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In December 2006, we announced our U.S. company-owned and company-operated retail outlets and our
U.S. company-owned and dealer-operated retail outlets would be divested to new or existing
wholesale marketers. Approximately 830 sites were included in the held for sale plans. About 620 sites have been sold,
including approximately 390 outlets sold in January 2009. The remaining sites included in the
original disposition plan are also expected to be sold in 2009.
Transportation
We distribute refined products to our customers via company-owned and common-carrier pipeline,
barge, railcar and truck.
Pipelines and Terminals
At December 31, 2008, R&M 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 or operated by affiliates. We also owned or operated 48 finished product
terminals, seven liquefied petroleum gas terminals, five crude oil terminals and one coke exporting
facility.
In December 2007, we acquired a 50 percent equity interest in four Keystone pipeline entities
(Keystone), to create a joint venture with TransCanada Corporation. In October 2008, we elected to
exercise an option to reduce our equity interest from 50 percent to 20.01 percent. The change in
equity will occur through a dilution mechanism, which is expected to gradually lower our ownership
interest until it reaches 20.01 percent by the third quarter of 2009. At December 31, 2008, our
ownership interest was 38.7 percent. Keystone’s first phase, a 2,148-mile, 590,000-barrel-per-day
crude oil pipeline from Alberta to delivery points in Illinois and Oklahoma, is expected to be
mechanically complete in late 2009. A second phase is expected to carry up to 700,000 barrels per
day to refineries on the Gulf Coast. We anticipate utilizing the Keystone pipeline to transport
our Canadian crude oil production to market, including as a source of supply to our U.S.
refineries.
Tankers
During 2008, we disposed of our international marine operations consisting of leasehold interests
in six double-hulled crude oil tankers and replaced the disposed operations with long-term charter
agreements. At December 31, 2008, we had 17 double-hulled crude oil tankers, with capacities
ranging in size from 700,000 to 2,100,000 barrels, which are under charter primarily to transport
feedstocks to certain of our U.S. refineries. In addition, we had under charter five double-hulled
product tankers utilized to transport our heavy and clean products. The tankers discussed here
exclude the operations of the company’s subsidiary, Polar Tankers, Inc., which are discussed in the
E&P segment, as well as an owned tanker on lease to a third party for use in the North Sea.
Specialty Businesses
We manufacture and sell a variety of specialty products including petroleum cokes, lubes (such as
automotive and industrial lubricants), solvents and pipeline flow improvers. Our lubes are
marketed under the Phillips 66, Conoco, 76 and Kendall brands. We also manufacture and market
high-quality graphite and anode-grade petroleum cokes in the United States and Europe for use in
the global steel and aluminum industries.
The company’s 50-percent-owned Excel Paralubes joint venture owns a hydrocracked lubricant base oil
manufacturing plant located adjacent to the Lake Charles refinery. The facility produces
approximately 20,000 barrels per day of high-quality, clear hydrocracked base oils.
In January 2008, we sold our 50 percent interest in Penreco, which manufactured and marketed highly
refined specialty petroleum products.
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R&M—INTERNATIONAL
Refining
At December 31, 2008, R&M owned or had an interest in five refineries outside the United States.
Primary crude oil characteristics and sources of crude oil for our international refineries are as
follows:
Capacities for and yields of clean products, as well as other products produced, relating to our
international refineries are as follows:
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We operate a crude oil and products storage complex consisting of 7.5 million barrels of storage
capacity and an offshore mooring buoy, located about 80 miles southwest of the Whitegate refinery
in Bantry Bay, Ireland.
During 2008, we continued to progress our plans to upgrade the Wilhelmshaven refinery in Germany.
Our future capital budget incorporates funds to economically improve the operation of the refinery,
enabling it to process heavier, higher-sulfur crude oil and produce predominantly low-sulfur
diesel.
In late 2007, we and our co-venturers sanctioned a project for the expansion of the Melaka refinery
to be completed during 2010. This project is intended to increase crude oil, conversion and
treating unit capacities.
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. In November 2008, we agreed to delay the bidding
process associated with the refinery’s construction due to uncertainties in the contracting and
financial markets. The originally scheduled bidding process requested bids be submitted in
December 2008. Instead, project bidding is now scheduled to begin in 2009.
Marketing
At December 31, 2008, R&M had marketing operations in five European countries. R&M’s European
marketing strategy is to sell primarily through owned, leased or joint venture retail sites using a
low-cost, high-volume strategy. We use the JET brand name to market retail and wholesale products
in Austria, Germany and the United Kingdom. In addition, a joint venture in which we have an
equity interest markets products in Switzerland under the Coop brand name. We also market aviation
fuels, liquid petroleum gases, heating oils, transportation fuels and marine bunkers to commercial
customers and into the bulk or spot market in the aforementioned countries and Ireland.
As of December 31, 2008, R&M had approximately 1,260 marketing outlets in its European operations,
of which approximately 860 were company-owned and 400 were dealer-owned. Through our joint venture
operations in Switzerland, we also have interests in 200 additional sites. In October 2008, we
sold our 274 fueling stations in Norway, Sweden and Denmark to Statoil.
LUKOIL INVESTMENT
At December 31, 2008, our LUKOIL Investment segment represented 4 percent of ConocoPhillips’ total
assets. In 2004, we became a strategic equity investor in OAO LUKOIL, an international, integrated
oil and gas company headquartered in Russia. Under the Shareholder Agreement between the two
companies, we have representation on the LUKOIL Board of Directors, and LUKOIL’s corporate charter
requires unanimous Board consent for certain key decisions. At year-end 2008, we had a 20 percent
ownership interest in LUKOIL based on authorized and issued shares. Based on estimated shares
outstanding at year end, our ownership was 20.06 percent. We use the equity method of accounting
for our investment in LUKOIL. See Note 7—Investments, Loans and Long-Term Receivables, in the
Notes to Consolidated Financial Statements, for additional information.
As reported in LUKOIL’s
publicly available 2007 annual report, the majority of its 2007 upstream oil production was
sourced within Russia, with 62 percent from the western Siberia region, 15 percent from the
Timan-Pechora province and 12 percent from the Urals region. Outside of Russia, LUKOIL had 2007
oil production in Kazakhstan, Egypt and Azerbaijan, and gas production in Uzbekistan. Eighty-eight
percent of LUKOIL’s natural gas production was sourced within Russia. In addition, LUKOIL has an
active exploration program focused in Russia but also encompassing several international countries.
Downstream, LUKOIL has seven refineries with a net crude oil throughput capacity of approximately
1.2 million barrels per day. LUKOIL also has a marketing network extending to 24 countries, with
the majority of wholesale and retail sales in Russia, the United States and Europe.
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CHEMICALS
At December 31, 2008, our Chemicals segment represented 2 percent of ConocoPhillips’ total assets.
The Chemicals segment consists of our 50 percent equity investment in Chevron Phillips Chemical
Company LLC (CPChem), a joint venture with Chevron Corporation, headquartered in The Woodlands,
Texas.
CPChem’s business is structured around two primary operating segments: Olefins & Polyolefins and
Specialties, Aromatics & Styrenics. The Olefins & Polyolefins segment produces and markets
ethylene, propylene, and other olefin products, which are primarily consumed within CPChem for the
production of polyethylene, normal alpha olefins, polypropylene, and polyethylene pipe. The
Specialties, Aromatics & Styrenics segment manufactures and markets aromatics products, such as
benzene, styrene, paraxylene and cyclohexane. This segment also manufactures and markets
polystyrene, as well as styrene-butadiene copolymers. Furthermore, this segment manufactures and
markets a variety of specialty chemical products including organosulfur chemicals, solvents,
catalysts, drilling chemicals, mining chemicals and high-performance engineering plastics and
compounds.
CPChem’s domestic facilities are located in California, Connecticut, Illinois, Louisiana,
Mississippi, Ohio and Texas. International facilities are located in Belgium, Brazil, China,
Columbia, Qatar, Saudi Arabia, Singapore and South Korea.
CPChem owns a 49 percent interest in Qatar Chemical Company Ltd. (Q-Chem), a joint venture that
owns a major olefins and polyolefins complex in Mesaieed, Qatar. CPChem also owns a 49 percent
interest in Qatar Chemical Company II Ltd. (Q-Chem II), a joint venture that began construction of
a second complex in Mesaieed in 2005. This Q-Chem II facility is designed to produce polyethylene
and normal alpha olefins on a site adjacent to the Q-Chem complex. In connection with this
project, CPChem entered into a separate agreement establishing a joint venture to develop an
ethylene cracker in Ras Laffan Industrial City, Qatar. Operational startup of the Q-Chem II
project is anticipated in late 2009.
In 2003, CPChem formed a 50-percent-owned joint venture company to develop an integrated styrene
facility in Al Jubail, Saudi Arabia. The facility is being built adjacent to the existing
aromatics complex owned by Saudi Chevron Phillips Company (SCP), another 50-percent-owned CPChem
joint venture. Construction of the facility, which began in the fourth quarter of 2004, is in
conjunction with an expansion of SCP’s existing benzene plant, together called the “JCP Project.”
Operational startup occurred in the third quarter of 2008, while project completion is anticipated
during the first quarter of 2009.
In 2007, CPChem formed a 50-percent-owned joint venture, Saudi Polymers Company (SPC), to construct
and operate an integrated petrochemicals complex at Al Jubail, Saudi Arabia. Construction began in
January 2008, and commercial production is scheduled to begin in late 2011. Prior to project
completion, based on a planned initial public offering of shares in CPChem’s joint venture
partner’s company and a corresponding increase in the partner’s ownership interest in SPC, CPChem’s
ownership is expected to decline to 35 percent.
In 2007, CPChem and the Dow Chemical Company signed a nonbinding Memorandum of Understanding
relating to the formation of a joint venture involving assets from their polystyrene and styrene
monomer businesses. Joint venture operations commenced in May 2008, with CPChem contributing two
domestic plants and Dow contributing four domestic and two international plants.
EMERGING BUSINESSES
At December 31, 2008, our Emerging Businesses segment represented 1 percent of ConocoPhillips’
total assets. The segment encompasses the development of new technologies and businesses outside
our normal scope of operations. Activities within this segment are currently focused on power
generation and innovation of new technologies, such as those related to conventional and
nonconventional hydrocarbon recovery (including heavy oil), refining, alternative energy, biofuels
and the environment.
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The focus of our power business is on developing projects to support our E&P and R&M strategies.
While projects primarily in place to enable these strategies are included within their respective
segments, projects with a significant merchant component are included in the Emerging Businesses
segment.
The Immingham combined heat and power plant (CHP), a wholly owned 730-megawatt facility in the
United Kingdom, provides steam and electricity to the Humber refinery and steam to a neighboring
refinery, as well as merchant power into the U.K. market. In October 2006, we announced we would
expand capacity at Immingham to 1,180 megawatts. Development work on Immingham phase 2 began with
the award of a contract for front-end engineering and securing of additional connection
availability to the U.K. grid. Commercial operation of the expansion is expected to start in
mid-2009.
We also own a gas-fired cogeneration plant in Orange, Texas, as well as a 50 percent operating
interest in Sweeny Cogeneration LP, a joint venture near the Sweeny refinery complex.
Our Technology group focuses on developing new business opportunities designed to provide future
growth prospects for ConocoPhillips. Areas of interest include advanced hydrocarbon processes,
energy conversion technologies, new petroleum-based products, renewable fuels and carbon capture
technology. We have commercialized 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. In addition, we have
formed alliances with Tyson Foods and Archer Daniels Midland to produce and market the next
generation of renewable transportation fuels. We have also formed an internal group that is
evaluating wind, solar and geothermal investment opportunities.
We are working with General Electric Company to develop a technology center in Qatar to research
water sustainability solutions for petroleum, petrochemical, municipal and agricultural
applications. The Qatar center will examine ways of treating and using by-product water from oil
production and refining operations, as well as other projects relating to industrial and municipal
water sustainability. In conjunction with the Interim Agreement to develop the Shah field with the
Abu Dhabi National Oil Company, we are planning to develop a technology center in Abu Dhabi that
will conduct research and provide technical service in areas including reservoir management and
development of sour gas fields; safe and efficient processing of gas with high hydrogen sulfide and
carbon dioxide concentrations; and sour gas sequestration. Both centers are expected to open in
2009.
We offer a gasification technology (E-Gas) that uses petroleum coke, coal, and other low-value
hydrocarbons as feedstock, resulting in high-value synthesis gas used for a slate of products,
including power, hydrogen and chemicals. In 2008, we completed a feasibility study and submitted
applications for all required environmental permits related to a proposed coal-to-substitute
natural gas (SNG) facility, which would have a capacity of 60 billion to 70 billion cubic feet per
year and be located in Muhlenberg County, Kentucky. We also became a founding member of the
Western Kentucky Carbon Storage Foundation, which is funding evaluation of carbon storage in deep
underground formations through a test well project directed by the Kentucky Geologic Survey.
A conceptual engineering study was completed in 2008 for a project at our Sweeny refinery in Texas
that would utilize E-Gas technology to convert petroleum coke to low-carbon power or SNG and
hydrogen. To minimize carbon dioxide (CO2) emissions from the facility, the proposed design allows
CO2 to be captured, transported and safely stored in nearby geological formations. This project
would increase clean energy supply while establishing critical carbon capture and storage
infrastructure in the Texas Gulf Coast region. A more detailed feasibility study is expected in
2009.
COMPETITION
We compete with private, public and state-owned companies in all facets of the petroleum and
chemicals businesses. Some of our competitors are larger and have greater resources. Each of our
segments is highly competitive. No single competitor, or small group of competitors, dominates any
of our business lines.
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Upstream, our E&P segment competes with numerous other companies in the industry to locate and
obtain new sources of supply and to produce oil and natural gas in an efficient, cost-effective
manner. Based on publicly available year-end 2007 reserves statistics, we had the sixth-largest total of worldwide proved
reserves of nongovernment-controlled companies. We deliver our oil and natural gas production into
the worldwide oil and natural gas commodity markets. Principal methods of competing include
geological, geophysical and engineering research and technology; experience and expertise; economic
analysis in connection with property acquisitions; and operating efficient oil and gas producing
properties.
The Midstream segment, through our equity investment in DCP Midstream and our consolidated
operations, competes with numerous other integrated petroleum companies, as well as natural gas
transmission and distribution companies, to deliver components of natural gas to end users in the
commodity natural gas markets. DCP Midstream is a large producer of natural gas liquids in the
United States. Principal methods of competing include economically securing the right to purchase
raw natural gas into gathering systems, managing the pressure of those systems, operating efficient
natural gas liquids processing plants, and securing markets for the products produced.
Downstream, our R&M segment competes primarily in the United States, Europe and the Asia Pacific
region. Based on the statistics published in the December 22, 2008, issue of the Oil & Gas
Journal, our R&M segment had the second-largest U.S. refining capacity of 18 large refiners of
petroleum products. Worldwide, our refining capacity ranked fourth among nongovernment-controlled
companies. In the Chemicals segment, CPChem generally ranked within the top 10 producers of many
of its major product lines, based on average 2008 production capacity, as published by industry
sources. Petroleum products, petrochemicals and plastics are delivered into the worldwide
commodity markets. Elements of competition for both our R&M and Chemicals segments include product
improvement, new product development, low-cost structures, and improved manufacturing and
distribution systems. In the marketing portion of the business, competitive factors include
product properties and processibility, reliability of supply, customer service, price and credit
terms, advertising and sales promotion, and development of customer loyalty to ConocoPhillips’ or
CPChem’s branded products.
GENERAL
At the end of 2008, we held a total of 1,464 active patents in 81 countries worldwide, including
556 active U.S. patents. During 2008, we received 39 patents in the United States and 58 foreign
patents. Our products and processes generated licensing revenues of $38 million in 2008. The
overall profitability of any business segment is not dependent on any single patent, trademark,
license, franchise or concession.
Company-sponsored research and development activities charged against earnings were $209 million,
$160 million, and $117 million in 2008, 2007, and 2006, respectively.
The environmental information contained in Management’s Discussion and Analysis of Financial
Condition and Results of Operations on pages 63 through 65 under the caption “Environmental” is
incorporated herein by reference. It includes information on expensed and capitalized
environmental costs for 2008 and those expected for 2009 and 2010.
Web Site Access to SEC Reports
Our Internet Web site address is http://www.conocophillips.com. Information contained on our
Internet Web site is not part of this report on Form 10-K.
Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and
any amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the
Securities Exchange Act of 1934 are available on our Web site, free of charge, as soon as
reasonably practicable after such reports are filed with, or furnished to, the U.S. Securities and
Exchange Commission (SEC). Alternatively, you may access these reports at the SEC’s Web site at
http://www.sec.gov.
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Item 1A. RISK FACTORS
You should carefully consider the following risk factors in addition to the other information
included in this Annual Report on Form 10-K. Each of these risk factors could adversely affect our
business, operating results and financial condition, as well as adversely affect the value of an
investment in our common stock.
Our operating results, our future rate of growth and the carrying value of our assets are exposed
to the effects of changing commodity prices and refining margins.
Our revenues, operating results and future rate of growth are highly dependent on the prices we
receive for our crude oil, natural gas, natural gas liquids and refined products. The factors
influencing the prices of crude oil, natural gas, natural gas liquids and refined products are
beyond our control. Lower crude oil, natural gas, natural gas liquids and refined products prices
may reduce the amount of these commodities we can produce economically, which may have a material
adverse effect on our revenues, operating income and cash flows.
Unless we successfully add to our existing proved reserves, our future crude oil and natural gas
production will decline, resulting in harm to our business.
The rate of production from crude oil and natural gas properties generally declines as reserves are
depleted. Except to the extent that we conduct successful exploration and development activities,
or, through engineering studies, identify additional or secondary recovery reserves, our proved
reserves will decline materially as we produce crude oil and natural gas. Accordingly, to the
extent we are unsuccessful in replacing the crude oil and natural gas we produce with good
prospects for future production, our business will suffer reduced cash flows and results of
operations.
Any material change in the factors and assumptions underlying our estimates of crude oil and
natural gas reserves could impair the quantity and value of those reserves.
Our proved crude oil and natural gas reserve information included in this annual report has been
derived from engineering estimates prepared or reviewed by our personnel. Any significant future
price changes will have a material effect on the quantity and present value of our proved reserves.
Future reserve revisions could also result from changes in, among other things, governmental
regulation. Reserve estimation is a subjective process that involves estimating volumes to be
recovered from underground accumulations of crude oil and natural gas that cannot be directly
measured. As a result, different petroleum engineers, each using industry-accepted geologic and
engineering practices and scientific methods, may produce different estimates of reserves and
future net cash flows based on the same available data. Any changes in the factors and assumptions
underlying our estimates of these items could result in a material negative impact to the volume of
reserves reported.
We expect to continue to incur substantial capital expenditures and operating costs as a result of
our compliance with existing and future environmental laws and regulations. Likewise, future
environmental laws and regulations may impact or limit our current business plans and reduce demand
for our products.
Our businesses are subject to numerous laws and regulations relating to the protection of the
environment. These laws and regulations continue to increase in both number and complexity and
affect our operations with respect to, among other things:
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We have incurred and will continue to incur substantial capital, operating and maintenance, and
remediation expenditures as a result of these laws and regulations. To the extent these
expenditures, as with all costs, are not ultimately reflected in the prices of our products and
services, our business, financial condition, results of operations and cash flows in future periods
could be materially adversely affected.
Domestic and worldwide political and economic developments could damage our operations and
materially reduce our profitability and cash flows.
Actions of the U.S., state and local governments through tax and other legislation, executive order
and commercial restrictions could reduce our operating profitability both in the United States and
abroad. The U.S. government can prevent or restrict us from doing business in foreign countries.
These restrictions and those of foreign governments have in the past limited our ability to operate
in, or gain access to, opportunities in various countries. Actions by both the United States and
host governments have affected operations significantly in the past, such as the expropriation of
our oil assets by the Venezuelan government, and will continue to do so in the future.
Local political and economic factors in international markets could have a material adverse effect
on us. Approximately 56 percent of our crude oil, natural gas and natural gas liquids production
in 2008 was derived from production outside the United States, and 62 percent of our proved
reserves, as of December 31, 2008, were located outside the United States. We are subject to 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.
The
current financial crisis could have a material adverse affect on our
financial strength and that of our business co-venturers.
Recent disruptions in the credit markets and concerns about global economic growth have had a
significant adverse impact on global financial markets and commodity prices, both of which have
contributed to a decline in our stock price and corresponding market capitalization. A lower level
of economic activity could result in a decline in energy consumption, which could cause our
revenues and margins to decline and limit our future growth prospects. Decreased returns on
pension fund assets may also materially increase our pension funding requirements. Likewise, the
capital and credit markets have become increasingly volatile as a result of adverse conditions. If
the capital and credit markets continue to experience volatility and the availability of funds
remains limited, we, and third parties with whom we do business, may incur increased costs
associated with issuing commercial paper and/or other debt instruments and this, in turn, could
adversely affect our ability to advance our strategic plans as currently contemplated. In this
context, changes in our debt rating could have a material adverse effect on our interest costs and
financing sources.
Changes in governmental regulations may impose price controls and limitations on production of
crude oil and natural gas.
Our operations are subject to extensive governmental regulations. From time to time, regulatory
agencies have imposed price controls and limitations on production by restricting the rate of flow
of crude oil and natural gas wells below actual production capacity in order to conserve supplies
of crude oil and natural gas. Because legal requirements are frequently changed and subject to
interpretation, we cannot predict the effect of these requirements.
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Our investments in joint ventures decrease our ability to manage risk.
We conduct many of our operations through joint ventures in which we may share control with our
joint venture participants. There is a risk that our joint venture participants may at any time
have economic, business or legal interests or goals that are inconsistent with those of the joint
venture or us, or that our joint venture participants may be unable to meet their economic or other
obligations and we may be required to fulfill those obligations alone. Failure by us, or an entity
in which we have a joint venture interest, to adequately manage the risks associated with any
acquisitions or joint ventures could have a material adverse effect on the financial condition or
results of operations of our joint ventures and, in turn, our business and operations.
Our operations are inherently dangerous and require significant and continuous oversight.
The scope and nature of our operations present a variety of operational hazards and risks that must
be managed through continual oversight and control. These risks are present throughout the process
of extraction, transportation, refinement and storage of the hydrocarbons we produce. Failure to
manage these risks could result in injury or loss of life, environmental damage, loss of revenues
and damage to our reputation.
Item 1B. UNRESOLVED STAFF COMMENTS
None.
Item 3. LEGAL PROCEEDINGS
The following is a description of reportable legal proceedings, including those involving
governmental authorities under federal, state and local laws regulating the discharge of materials
into the environment for this reporting period. The following proceedings include those matters
that arose during the fourth quarter of 2008, as well as matters previously reported in our 2007
Form 10-K and our first-, second- and third-quarter 2008 Form 10-Qs that were not resolved prior to
the fourth quarter of 2008. Material developments to the previously-reported matters have been
included in the descriptions below. While it is not possible to accurately predict the final
outcome of these pending proceedings, if any one or more of such proceedings was decided adversely
to ConocoPhillips, we expect there would be no material effect on our consolidated financial
position. Nevertheless, such proceedings are reported pursuant to the U.S. Securities and Exchange
Commission’s regulations.
Our U.S. refineries are implementing two separate consent decrees, regarding alleged violations of
the Federal Clean Air Act, with the U.S. Environmental Protection Agency (EPA), six states and one
local air pollution agency. Some of the requirements and limitations contained in the decree
provide for stipulated penalties for violations. Stipulated penalties under the decrees are not
automatic, but must be requested by one of the agency signatories. As part of periodic reports
under the decree and/or other reports required by permits or regulations, we occasionally report
matters which could be subject to a request for stipulated penalties. If a specific request for
stipulated penalties meeting the reporting threshold set forth in U.S. Securities and Exchange
Commission rules is made pursuant to these decrees based on a given reported exceedance, we will
separately report that matter and the amount of the proposed penalty.
New Matters
On October 23, 2008, ConocoPhillips received a demand from the Los Angeles Regional Water Quality
Control Board (LARWQCB) to settle multiple alleged exceedances of National Pollutant Discharge
Elimination System Permit effluent limits at its Los Angeles Lubricants plant dating back to 2000.
The amount of the demand is $174,000. We will work with the LARWQCB to resolve these allegations.
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On December 15, 2008, the Trainer refinery received Citations and a Notification of Penalty
(Citation) from the Occupational Safety and Health Administration (OSHA) for 26 alleged violations
noted during the OSHA National Emphasis Program review of the refinery. The Citation seeks
$115,500 in penalties for a variety of alleged Process Safety Management violations. We are
working with OSHA to resolve this matter.
Matters Previously Reported
The South Coast Air Quality Management District (SCAQMD) conducted an audit of the Los Angeles
refinery in 2007 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 noncompliance. We resolved two of the three NOVs for a total payment
of $42,500 in the third quarter of 2008 and reached an agreement with SCAQMD to resolve the third
NOV for $12,500 in the fourth quarter of 2008.
SCAQMD conducted an audit of the Los Angeles refinery in August 2008 to assess compliance with
applicable local, state and federal regulations related to fugitive emissions. As a result of the
audit, on August 28, 2008, SCAQMD issued five NOVs alleging noncompliance. SCAQMD has not yet
specified a penalty for these alleged violations. We are working with SCAQMD to resolve these NOVs.
On July 16, 2008, ConocoPhillips received a demand from the Bay Area Air Quality Management
District (BAAQMD) to settle 24 NOVs issued in late 2006 and 2007 for alleged violations of air
pollution-control regulations at the San Francisco refinery. The amount of the settlement demand
is $304,500. On December 29, 2008, BAAQMD added an additional seven NOVs issued in 2008 and a
corresponding additional $340,500 to its settlement demand. We are working with BAAQMD to resolve
these NOVs.
On June 2, 2008, the Billings refinery received a Violation Letter from the Montana Department of
Environmental Quality (MDEQ) for opacity and nickel emissions, which occurred during startup of the
catalytic cracker in April 2007. The letter also alleged certain monitoring quality
assurance/quality control violations. The letter requests a penalty of $604,000. We intend to
work with the MDEQ to resolve this matter.
On March 27, 2008, the Trainer refinery received a proposed Consent Assessment of Civil Penalty
from the Pennsylvania Department of Environmental Protection (PADEP) for alleged air quality
violations that occurred from 2002 to 2007. The assessment covers several categories of alleged
air quality violations including emission events, air emissions inventory reporting, and violation
of permit conditions. We paid $129,424 in the fourth quarter of 2008 to resolve this matter.
On March 27, 2008, the Sweeny refinery received a Notice of Enforcement (NOE) from the Texas
Commission on Environmental Quality (TCEQ) for an emissions event related to flaring that occurred
on January 28, 2008. A penalty of $32,000 was submitted to the TCEQ in September 2008. This
matter is subject to formal approval by the TCEQ Commissioners. We expect consideration of
approval to occur in the first quarter of 2009.
On February 11, 2008, ConocoPhillips Alaska, Inc. (CPAI) received an NOV from the North Slope
Borough (NSB) in relation to its Alpine facility on the North Slope of Alaska. The NOV alleges
that three fuel tanks at the Alpine facility lacked adequate containment and/or setbacks from water
bodies. There was no environmental impact due to these alleged violations. The NOV proposed
penalties of $207,000, which was later reduced to $128,000. CPAI paid the reduced penalty under
protest in accordance with the payment demands in the NOV. On March 11, 2008, CPAI filed an appeal
with the NSB Planning Commission challenging the alleged violations and penalties in the NOV. We
will continue to work with the NSB to resolve this matter.
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In
October 2003, the District Attorney’s Office in Sacramento, California, filed a complaint in
Superior Court for alleged methyl tertiary-butyl ether (MTBE) contamination in groundwater. On
April 4, 2008, the District Attorney’s Office filed an amended complaint that included alleged
violations of state regulations relating to operation or maintenance of underground storage tanks.
There are numerous defendants named in the suit in addition to ConocoPhillips. We intend to
continue to contest this lawsuit.
In October 2007, we received a Complaint from the U.S. EPA alleging violations of the Clean Water
Act related to a 2006 oil spill at our Bayway refinery and proposing a penalty of $156,000. We are
working with the EPA and the U.S. Coast Guard to resolve this matter.
On December 16, 2005, the Bayway refinery experienced a hydrocarbon spill to the Rahway River and
Arthur Kill. On August 26, 2006, we signed an Order on Consent with the state of New York pursuant
to which we paid a penalty of $50,000 and conducted a beach cleanup. Also in December 2008, we
paid a total of $106,578 for natural resource damages and other costs to the New Jersey Department
of Environmental Protection, the U.S. Department of the Interior and the U.S. Department of Commerce.
This matter is resolved.
In March 2005, ConocoPhillips Pipe Line Company (CPPL) received a Notice of Probable Violation and
Proposed Civil Penalty from the U.S. Department of Transportation’s Pipeline and Hazardous
Materials Safety Administration (DOT) alleging violation of DOT operation and safety regulations at
certain facilities in Kansas, Missouri, Illinois, Indiana, Wyoming and Nebraska. DOT is proposing
penalties in the amount of $184,500. An information hearing was held on September 24, 2007. CPPL
has provided additional information in support of its position. We are currently awaiting a ruling
from DOT.
The U.S. Coast Guard and Washington State Department of Ecology investigated the possible sources
of an oil spill in Puget Sound. In November 2004, the U.S. Attorney and the U.S. Coast Guard
offices in Seattle, Washington, issued subpoenas to Polar Tankers, Inc., a subsidiary of
ConocoPhillips Company, for records related to the vessel Polar Texas. On December 23, 2004, the
governor of the state of Washington and the U.S. Coast Guard publicly announced they believed the
Polar Texas was the source of the spill. The company fully cooperated with the investigations.
The U.S. Attorney’s Office in Seattle declined prosecution of the company. As previously reported,
Polar Tankers, ConocoPhillips and the state of Washington settled the matter, with payment of civil
penalties and response costs. The settlement did not include any admission of liability. The
company and the authorities remain in settlement negotiations regarding the natural resource damage
assessment.
In April 2004, in response to several historical spills at the Albuquerque Products Terminal, we
received an Administrative Compliance Order from the New Mexico Environment Department. The order
does not propose a penalty assessment, but rather attempts to impose specific design, construction
and operational changes. We have been in negotiations with the agency and in June 2007 proposed a
settlement offer of $100,000. We will continue to work with the agency to resolve this matter.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
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EXECUTIVE OFFICERS OF THE REGISTRANT
There is no family relationship among the officers named above. Each officer of the company is
elected by the Board of Directors at its first meeting after the Annual Meeting of Stockholders and
thereafter as appropriate. Each officer of the company holds office from date of election until
the first meeting of the directors held after the next Annual Meeting of Stockholders or until a
successor is elected. The date of the next annual meeting is May 13, 2009. Set forth below is
information about the executive officers.
Rand C. Berney was appointed Vice President and Controller upon completion of the merger in 2002.
John A. Carrig was appointed President and Chief Operating Officer in October 2008, having
previously served as Executive Vice President, Finance, and Chief Financial Officer since the
merger in 2002.
W. C. W. Chiang was appointed Senior Vice President, Refining, Marketing and Transportation in
October 2008. He previously served as Senior Vice President, Commercial since 2007. Prior to
that, he served as President, Americas Supply & Trading, Commercial, from 2005 through 2007 and as
President, Downstream Strategy, Integration and Specialty Businesses from 2003 through 2005.
Sigmund L. Cornelius was appointed Senior Vice President, Finance, and Chief Financial Officer in
October 2008. Prior to that, he served as Senior Vice President, Planning, Strategy and Corporate
Affairs since September 2007, having previously served as President, Exploration and
Production—Lower 48 since 2006. He served as President, Global Gas since 2004, and prior to that
served as President, Lower 48, Latin America and Midstream since 2003.
James L. Gallogly was appointed Executive Vice President, Exploration and Production in October
2008, and prior to that served as Executive Vice President, Refining, Marketing and Transportation
from April 2006. He previously served as President and Chief Executive Officer of Chevron Phillips
Chemical Company LLC since 2000.
Janet L. Kelly was appointed Senior Vice President, Legal, General Counsel and Corporate Secretary
effective September 1, 2007, having previously served as Deputy General Counsel since 2006. Prior
to joining ConocoPhillips in 2006, she was a partner at Zelle, Hoffman, Voelbel, Mason and Gette
during 2005 and 2006. She previously served as Senior Vice President, Chief Administrative Officer
and Chief Compliance Officer of Kmart Corporation during 2003 and 2004.
James J. Mulva has served as Chairman of the Board of Directors and Chief Executive Officer since
October 2008, having previously served as Chairman of the Board of Directors, President and Chief
Executive Officer since October 2004. Prior to that, he served as President and Chief Executive
Officer since completion of the merger in 2002.
Jeff W. Sheets was appointed Senior Vice President, Planning and Strategy in October 2008, having
previously served as Vice President and Treasurer since the merger in 2002.
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PART II
Quarterly Common Stock Prices and Cash Dividends Per Share
ConocoPhillips’ common stock is traded on the New York Stock Exchange, under the symbol “COP.”
Issuer Purchases of Equity Securities
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Item 6. SELECTED FINANCIAL DATA
See Management’s Discussion and Analysis of Financial Condition and Results of Operations for a
discussion of factors that will enhance an understanding of this data.
The financial data for 2008 includes the impact of impairments relating to goodwill and to our
LUKOIL investment that together amount to $32,853 million before- and after-tax. For additional
information, see the “Goodwill Impairment” section of Note 9—Goodwill and Intangibles and the
“LUKOIL” section of Note 7—Investments, Loans and Long-Term Receivables, in the Notes to Consolidated Financial
Statements.
The financial data for 2007 includes the impact of a $4,588 million before-tax ($4,512 million
after-tax) impairment related to the expropriation of our oil interests in Venezuela. For
additional information, see the “Expropriated Assets” section of Note 10—Impairments, in the Notes
to Consolidated Financial Statements.
Additionally, the acquisition of Burlington Resources in 2006 affects the comparability of the
amounts included in the table above. See Note 3—Acquisition of Burlington Resources Inc., in the
Notes to Consolidated Financial Statements, for additional information. See Note 2—Changes in
Accounting Principles, in the Notes to Consolidated Financial Statements, for information on
changes in accounting principles affecting the comparability of amounts included in the table
above.
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Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
February 25, 2009
Management’s Discussion and Analysis is the company’s analysis of its financial performance and of
significant trends that may affect future performance. It should be read in conjunction with the
financial statements and notes, and supplemental oil and gas disclosures. It contains
forward-looking statements including, without limitation, statements relating to the company’s
plans, strategies, objectives, expectations and intentions, that are made pursuant to the “safe
harbor” provisions of the Private Securities Litigation Reform Act of 1995. The words “intends,”
“believes,” “expects,” “plans,” “scheduled,” “should,” “anticipates,” “estimates” and similar
expressions identify forward-looking statements. The company does not undertake to update, revise
or correct any of the forward-looking information unless required to do so under the federal
securities laws. Readers are cautioned that such forward-looking statements should be read in
conjunction with the company’s disclosures under the heading: “CAUTIONARY STATEMENT FOR THE
PURPOSES OF THE ‘SAFE HARBOR’ PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995,”
beginning on page 72.
BUSINESS ENVIRONMENT AND EXECUTIVE OVERVIEW
ConocoPhillips is an international, integrated energy company. We are the third-largest integrated
energy company in the United States, based on market capitalization. We have approximately 33,800
employees worldwide, and at year-end 2008 had assets of $143 billion. Our stock is listed on the
New York Stock Exchange under the symbol “COP.”
Our business is organized into six operating segments:
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In 2008, the energy industry was characterized by extreme volatility. Forecasts of worldwide
economic growth and increasingly scarce supply, a weakening U.S. dollar, and other factors helped
drive crude oil prices to record highs. This was followed by an abrupt shift into a severe global
financial recession, which reduced current and forecasted demand for petroleum products. Because
of this, crude oil prices fell rapidly and refining margins also significantly weakened.
As a result of the significant drop in global equity markets during the fourth quarter of 2008, we
recorded two individually significant impairments in 2008 that were primarily linked to market
capitalizations—a $25.4 billion write-down of our E&P segment’s recorded goodwill, and a $7.4
billion reduction in the carrying value of our LUKOIL investment. These impairments contributed to
a net loss in 2008 of $17.0 billion, compared with net income in 2007 of $11.9 billion, which
includes the impact of a $4.5 billion impairment due to
expropriation of our Venezuelan assets.
Since these 2008 and 2007 impairment charges were noncash, they did not impact our cash provided by
operating activities, which was $22.7 billion in 2008, compared with $24.6 billion in 2007.
Crude oil and natural gas prices, along with refining margins, are the most significant factors in
our profitability, and are driven by market factors over which we have no control. However, from a
competitive perspective, there are other important factors we must manage well to be successful,
including:
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. In the three years ending
December 31, 2008, our reserve replacement was 124 percent, including the impacts of the
Burlington Resources acquisition, additional equity investments in LUKOIL, the FCCL Oil
Sands Partnership with EnCana, the Australia Pacific LNG joint venture with Origin Energy,
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.
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industries, cost control is a component of our variable compensation programs. In response
to the current depressed market environment, we expect to reduce our work force in 2009,
reduce the headcount of contractors, and continue to emphasize cost discipline throughout
our operations.
With the rise in commodity prices over the last several years and through the first half of
2008, and the subsequent increase in industry-wide spending on capital and major maintenance
programs, we and other energy companies experienced inflation for the costs of certain goods
and services in excess of general worldwide inflationary trends. Such costs included rates
for drilling rigs, steel and other raw materials, as well as costs for skilled labor. With
the weakening of the economy and the decline in commodity prices, our industry began to see
some relief from this upward cost pressure in late 2008 and into early 2009.
In October 2008, we formed Australia Pacific LNG, a 50/50 joint venture with Origin Energy
for the development of coalbed natural gas in Australia, and the subsequent liquefaction and
transport of the liquefied natural gas targeting Asia Pacific markets. In January 2007, we entered
into two 50/50 business ventures with EnCana to create an integrated North American heavy
oil business, consisting of the upstream FCCL Oil Sands Partnership in Canada and the
downstream WRB Refining LLC in the United States.
Our capital expenditures and investments in 2008 totaled $19.1 billion, and we anticipate
capital expenditures and investments to be approximately $11.7 billion in 2009. The reduced
capital budget in 2009 reflects the impact of the Origin transaction on the 2008 totals, and
a planned reduction in response to current market conditions. In addition to our capital
program, we paid dividends on our common stock of $2.9 billion in 2008, and repurchased $8.2
billion of our common stock.
Our key performance indicators are shown in the statistical tables provided at the beginning of the
operating segment sections that follow. These include crude oil, natural gas and natural gas
liquids prices and production, refining capacity utilization, and refinery output.
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Other significant factors that can affect our profitability include:
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Segment Analysis
The E&P segment’s 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 (WTI) were higher
in 2008, compared with 2007, averaging $99.56 per barrel in 2008, an increase of 38 percent. The
increase was driven by concerns during the first half of 2008 of adequate supplies given the strong
oil demand growth in developing Asia and the Middle East. The average annual price for WTI
moderated due to the economic crisis in the second half of 2008 that impacted demand from all
regions of the world. Industry natural gas prices for Henry Hub increased 32 percent during 2008
to an average price of $9.04 per million British thermal units (MMBTU), primarily due to increased
demand from the industrial and electric power sector during the first half of 2008 and higher oil
prices. These factors were moderated by higher domestic production and lower demand, which led to
higher storage in the second half of 2008.
The Midstream segment’s results are most closely linked to natural gas liquids prices. The most
important factor on the profitability of this segment is the results from our 50 percent equity
investment in DCP Midstream. DCP Midstream’s natural gas liquids prices increased 11 percent in
2008.
Refining margins, refinery utilization, cost control and marketing margins primarily drive the R&M
segment’s results. Refining margins are subject to movements in the cost of crude oil and other
feedstocks, and the sales prices for refined products, both of which are subject to market factors
over which we have no control. Industry refining margins in the United States were lower overall
in comparison with 2007. The primary factor contributing to the reduced refining margins in 2008
was a decrease in gasoline demand.
The LUKOIL Investment segment consists of our investment in the ordinary shares of LUKOIL. At
December 31, 2008, our ownership interest in LUKOIL was 20 percent based on issued shares and 20.06
percent based on estimated shares outstanding. LUKOIL’s results are subject to factors similar to
those of our E&P and R&M segments. LUKOIL’s upstream results are closely linked to Russian (Urals)
crude oil prices and are heavily impacted by extraction tax rates. Refining margins are
significant factors on LUKOIL’s downstream results. Export tariff rates for crude oil and refined
products also have a significant impact on both upstream and downstream results.
The Chemicals segment consists of our 50 percent interest in CPChem. The chemicals and plastics
industry is mainly a commodity-based industry where the margins for key products are based on
market factors over which CPChem has little or no control. CPChem is investing in
feedstock-advantaged areas in the Middle East with access to large, growing markets, such as Asia.
The Emerging Businesses 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 innovation of new technologies, such as those related to conventional and
nonconventional hydrocarbon recovery (including heavy oil), refining, alternative energy, biofuels
and the environment. Some of these technologies have the potential to become important drivers of
profitability in future years.
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RESULTS OF OPERATIONS
Consolidated Results
A summary of the company’s net income (loss) by business segment follows:
2008 vs. 2007
The lower results in 2008 were primarily the result of:
These items were partially offset by:
2007 vs. 2006
The lower results in 2007 were primarily the result of:
These items were partially offset by:
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Statement of Operations Analysis
2008 vs. 2007
Sales and other operating revenues increased 28 percent in 2008, while purchased crude
oil, natural gas and products increased 37 percent. These increases were mainly the result of
higher petroleum product prices and higher prices for crude oil, natural gas and natural gas
liquids.
Equity in earnings of affiliates decreased 16 percent in 2008, reflecting:
These negative results were somewhat offset by improved results from the FCCL Oil Sands
Partnership, DCP Midstream, LUKOIL (excluding the investment impairment), and CFJ Properties.
Other income decreased 45 percent during 2008, mainly due to a lower net benefit from asset
rationalization efforts, the release in 2007 of escrowed funds associated with our Hamaca joint
venture in Venezuela, and the settlement of retroactive adjustments for crude oil quality
differentials on Trans-Alaska Pipeline System shipments (Quality Bank) in 2007.
Exploration expenses increased 33 percent during 2008, reflecting increased dry hole costs
and higher expenses for post-discovery feasibility and development planning studies.
Impairments increased from $5,030 million in 2007 to $34,539 million in 2008. This
increase reflects a $25,443 million goodwill impairment recorded during 2008 in our E&P segment.
Also contributing to the increase was a $7,410 million impairment of our LUKOIL investment taken
during 2008. These 2008 impairments were partially offset by a 2007 impairment of $4,588 million
related to the expropriation of our oil interests in Venezuela.
Other impairments increased $1,244 million during 2008 primarily due to property impairments taken
in response to a significantly diminished outlook for crude oil and natural gas prices, refining
margins and power spreads, as well as in response to revised capital spending plans. For
additional information, see Note 7—Investments, Loans, and Long-Term Receivables, Note 9—Goodwill
and Intangibles, and Note 10—Impairments, in the Notes to Consolidated Financial Statements.
Interest and debt expense decreased 25 percent in 2008, primarily due to lower average
interest rates, as well as the absence of 2007 interest expense related to the Alaska Quality Bank
settlements.
Foreign currency transaction losses incurred during 2008 totaled $117 million, compared
with foreign currency transaction gains of $201 million in 2007. This change occurred as the
Canadian dollar, Russian rouble, British pound, and euro all weakened against the U.S. dollar
during 2008, compared with the strengthening of these currencies against the U.S. dollar in 2007.
See Note 21—Income Taxes, in the Notes to Consolidated Financial Statements, for information
regarding our income tax expense and effective tax rate.
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2007 vs. 2006
Equity in earnings of affiliates increased 21 percent in 2007. The increase reflects
earnings from WRB and FCCL, our downstream and upstream business ventures with EnCana, formed in
January 2007. Also, we had improved results from LUKOIL, reflecting higher estimated commodity
prices and volumes, and an increase in our average equity ownership percentage. These increases
were partially offset by lower earnings from Hamaca and Petrozuata, our heavy oil joint ventures
expropriated by Venezuela in the second quarter of 2007. Additionally, CPChem reported lower
earnings, primarily due to lower olefins and polyolefins margins.
Other income increased 188 percent during 2007, primarily due to:
These increases were partially offset by the recognition in 2006 of recoveries on business
interruption insurance claims attributable to losses sustained from hurricanes in 2005.
Exploration expenses increased 21 percent during 2007, primarily reflecting the
amortization of unproved North American leaseholds obtained in the Burlington Resources acquisition
and the impairment of an international exploration license. The increase also reflects higher
geological and geophysical expenses and higher dry hole costs.
Depreciation, depletion and amortization increased 14 percent during 2007, primarily
resulting from the addition of Burlington Resources’ assets in the E&P segment’s depreciable asset
base for a full year in 2007 versus only nine months in 2006.
Impairments reflects an impairment of $4,588 million related to the expropriation of our
oil interests in Venezuela recorded in the second quarter of 2007. Impairments unrelated to the
expropriation decreased 35 percent during 2007, primarily due to impairments recorded in 2006 of
certain assets held for sale in the R&M segment, comprised of properties, plants and equipment,
trademark intangibles and goodwill.
Interest and debt expense increased 15 percent during 2007, primarily due to the interest
expense component of the Alaska Quality Bank settlements, as well as higher expense associated with
the funding requirements for the business venture with EnCana.
Foreign currency transaction gains during 2007 primarily reflect the strengthening of the
Canadian dollar against the U.S. dollar.
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Segment Results
E&P
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The E&P segment explores for, produces, transports and markets crude oil, natural gas and natural
gas liquids on a worldwide basis. It also mines deposits of oil sands in Canada to extract the
bitumen and upgrade it into a synthetic crude oil. At December 31, 2008, our E&P operations were
producing in the United States, Norway, the United Kingdom, Canada, Ecuador, Australia, offshore
Timor-Leste in the Timor Sea, Indonesia, China, Vietnam, Libya, Nigeria, Algeria and Russia.
2008 vs. 2007
The E&P segment recorded a net loss of $13,479 million during 2008. This amount includes a $25,443
million before- and after-tax complete impairment of E&P segment goodwill. In 2007, the E&P
segment had net income of $4,615 million, which includes the impact of a $4,588 million before-tax
impairment ($4,512 million after-tax) related to the expropriation of our oil interests in
Venezuela. For additional information, see the “Goodwill Impairment” section of Note 9—Goodwill
and Intangibles, and the “Expropriated Assets” section of Note 10—Impairments, in the Notes to
Consolidated Financial Statements, which are incorporated herein by reference.
The decrease in net income was attributed to the goodwill impairment, higher taxes other than
income (mainly in Alaska), lower production volumes, higher operating and exploration costs,
increased impairments and depreciation expense, and the absence of a 2007 benefit related to
release of escrowed funds associated with our Hamaca joint venture in Venezuela. The decrease was
partially offset by the absence of the 2007 Venezuela impairment, as well as higher crude oil,
natural gas and natural gas liquids prices. During 2008, our E&P segment recognized property
impairment charges totaling $511 million after-tax, mostly due to revised capital spending plans as
a result of current project economics, as well as a significantly diminished outlook for commodity
prices. A large portion of these impairments relate to fields in the U.S. Lower 48 and Canada.
E&P’s results for 2008 reflect an average realized worldwide selling price of $93.12 per barrel of
crude oil. In contrast, our average realized worldwide crude oil price per barrel in December 2008
was $37.23. If average crude oil prices in 2009 do not increase appreciably from the low levels at
year-end 2008, we would expect E&P’s 2009 results to be negatively impacted.
Proved reserves at year-end 2008 were 8.08 billion barrels of oil equivalent (BOE), compared with
8.72 billion at year-end 2007. This excludes the estimated 1,893 million BOE and 1,838 million BOE
included in the LUKOIL Investment segment at year-end 2008 and 2007, respectively. Also excluded
is our share of Canadian Syncrude, which was 249 million barrels at year-end 2008, compared with
221 million at year-end 2007.
U.S. E&P
Net income from our U.S. E&P operations increased 17 percent, primarily due to higher crude oil,
natural gas and natural gas liquids prices. The increase was partially offset by higher production
taxes (mainly in Alaska), lower volumes, an increase in impairments of properties in the Lower 48,
and higher operating costs.
E&P production on a BOE basis averaged 775,000 per day in 2008, a decrease of 8 percent from
843,000 in 2007. The production decrease was primarily due to field decline and unplanned downtime
in the Lower 48 reflecting the impact of hurricane disruptions.
International E&P
Net income from our international E&P operations increased from $367 million in 2007 to $6,976
million in 2008. The increase was attributed to the impact of the
Venezuelan impairment on our
prior-year results and higher crude oil, natural gas and natural gas liquids prices. The increase
was partially offset by higher depreciation expense due to increased rates and new assets being
placed in service, increased taxes other than income, higher operating costs, and the absence of a
2007 benefit related to release of escrowed funds associated with our Hamaca joint venture in
Venezuela.
International E&P production averaged 992,000 BOE per day in 2008, a decrease of 2 percent from
1,014,000 in 2007. Decreases in production were caused by field decline and the expropriation of
our Venezuelan oil interests. These decreases were mostly offset by increased production from new
developments
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in the United Kingdom, Indonesia, Russia, Norway and Canada. Our Syncrude mining operations
produced 22,000 barrels per day in 2008, compared with 23,000 barrels per day in 2007.
In regards to our Venezuelan assets expropriated during 2007, we 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. The tribunal of three arbitrators is constituted, and the arbitration proceeding is under
way.
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. In April 2008, we initiated arbitration with ICSID against The Republic of Ecuador and
PetroEcuador as a result of the government’s confiscatory fiscal measures enacted in 2006 and 2007,
as well as the government-mandated renegotiation of our production sharing contracts into service
agreements with inferior fiscal and legal terms. The arbitration has been registered by ICSID, the
arbitration tribunal is fully constituted and the case is proceeding.
In Canada, the Alberta provincial government changed the royalty structure for Crown lands,
effective January 1, 2009. A component of the new royalty rate calculation for each well will be
based on prevailing prices, and therefore we expect that our reported production and reserve
volumes will move inversely with changes in commodity prices. This change will impact both our
conventional western Canada natural gas and oil business and our oil sands operations.
2007 vs. 2006
Net income from the E&P segment decreased 53 percent in 2007. In the second quarter of 2007, we
recorded a noncash impairment of $4,588 million before-tax ($4,512 million after-tax) related to
the expropriation of our oil interests in Venezuela. The decrease in net income during 2007
reflects this impairment, as well as lower crude oil production, higher production taxes and
operating costs, and higher DD&A expense. These decreases were partially offset by:
Proved reserves at year-end 2007 were 8.72 billion BOE, compared with 9.36 billion at year-end
2006. This excludes the estimated 1,838 million BOE and 1,805 million BOE included in the LUKOIL
Investment segment at year-end 2007 and 2006, respectively. Also excluded is our share of Canadian
Syncrude, which was 221 million barrels at year-end 2007, compared with 243 million at year-end
2006.
U.S. E&P
Net income from our U.S. E&P operations decreased 2 percent, primarily due to higher production
taxes in Alaska, higher operating costs and DD&A expense, and lower crude oil production. These
decreases were mostly offset by:
In December 2007, the state of Alaska enacted new production tax legislation, with retroactive
provisions, which results in a higher production tax structure for ConocoPhillips.
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U.S. E&P production averaged 843,000 BOE per day in 2007, an increase of 4 percent from 808,000 in
2006. Production was impacted by the inclusion of the Burlington Resources assets for the full
year of 2007, offset slightly by field decline.
International E&P
Net income from our international E&P operations decreased 93 percent, primarily due to the
impairment of expropriated assets in Venezuela, lower crude oil production, higher DD&A expense,
and higher operating costs. These decreases were partially offset by higher crude oil and natural
gas prices, a net benefit from asset rationalization efforts, and the benefit from the release of
the escrowed funds related to the Hamaca project.
International E&P production averaged 1,014,000 BOE per day in 2007, a decrease of 10 percent from
1,128,000 in 2006. Production was impacted by the expropriation of our Venezuelan oil projects,
planned and unplanned downtime in Australia and the North Sea, production sharing contract impacts
in Australia, our exit from Dubai, and the effect of asset dispositions. These decreases were
slightly offset by new production volumes from our FCCL upstream business venture with EnCana, as
well as inclusion of the Burlington Resources assets for the full year of 2007. Our Syncrude
mining operations produced 23,000 barrels per day in 2007, compared with 21,000 in 2006.
During 2006, significant tax legislation was enacted in the United Kingdom and in Canada. The
United Kingdom increased income tax rates on upstream income, resulting in a negative earnings
impact of $470 million to adjust 2006 taxes and restate deferred tax liabilities. In Canada, an
overall rate reduction in 2006 resulted in a favorable earnings impact of $401 million to restate
deferred tax liabilities.
Midstream
The Midstream segment purchases raw natural gas from producers and gathers natural gas through an
extensive network of pipeline gathering systems. The natural gas is then processed to extract
natural gas liquids from the raw gas stream. The remaining “residue” gas is marketed to electrical
utilities, industrial users, and gas marketing companies. Most of the natural gas liquids are
fractionated—separated into individual components like ethane, butane and propane—and marketed as
chemical feedstock, fuel or blendstock. The Midstream segment consists of our 50 percent equity
investment in DCP Midstream, as well as our other natural gas gathering and processing operations,
and natural gas liquids fractionation and marketing businesses, primarily in the United States and
Trinidad.
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2008 vs. 2007
Net income from the Midstream segment increased 19 percent in 2008. The increase was primarily due
to higher realized natural gas liquids prices, partially offset by higher operating costs and
higher depreciation expense.
2007 vs. 2006
Net income from the Midstream segment decreased 5 percent in 2007, reflecting a shift in natural
gas purchase contract terms that are more favorable to natural gas producers. In addition,
earnings from DCP Midstream were lower, primarily due to increased operating costs, mainly repairs,
maintenance and asset integrity work. The results also reflect a positive tax adjustment included
in the 2006 results. These decreases were partially offset by higher natural gas liquids prices.
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R&M
The R&M segment’s operations encompass refining crude oil and other feedstocks into petroleum
products (such as gasoline, distillates and aviation fuels); buying, selling and transporting crude
oil; and buying, transporting, distributing and marketing petroleum products. R&M has operations
mainly in the United States, Europe and the Asia Pacific region.
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2008 vs. 2007
Net income from the R&M segment decreased 61 percent in 2008. The results were lower due to
decreases in U.S. refining margins and volumes, increased property impairments, higher operating
costs, a reduced benefit from asset rationalization efforts, and lower international marketing and
refining volumes due to asset sales. During 2008, our R&M segment had property impairments
totaling $511 million after-tax, mostly due to a significantly diminished outlook for refining
margins. These R&M decreases were partially offset by higher international marketing margins.
During 2008, our worldwide refining capacity utilization rate was 90 percent, compared with 94
percent in 2007. We expect our 2009 rate to be similar to our rate in 2008.
U.S. R&M
Net income from our U.S. R&M operations decreased 67 percent in 2008. The decrease was primarily
the result of lower refining margins and, to a lesser extent, lower refining volumes and higher
turnaround and utility costs. In addition, property impairments increased in 2008, including an
impairment related to one of our U.S. refineries.
Our U.S. refining capacity utilization rate was 92 percent in 2008, compared with 96 percent in
2007. The decline in the current-year rate resulted mainly from refinery optimization and
unplanned downtime including impacts from hurricanes on our U.S. Gulf Coast refineries.
International R&M
Net income from our international R&M operations decreased 40 percent in 2008. Contributing to the
decrease were higher property impairments, including impacts from a 2008 impairment of a refinery
in Europe and the absence of a 2007 benefit related to an increase in the fair value of previously
impaired assets held for sale. Net income for 2008 was also impacted by a reduced net benefit from
asset rationalization efforts, negative foreign currency exchange impacts, the absence of a $141
million 2007 German tax legislation benefit, and lower refining and marketing volumes due to asset
sales. Higher international refining and marketing margins partially offset these decreases.
Our international refining capacity utilization rate was 85 percent in 2008, compared with 90
percent during the previous year. The utilization rate was primarily impacted by reduced crude
throughput at our Wilhelmshaven refinery due to economic conditions and planned maintenance.
2007 vs. 2006
Net income from the R&M segment increased 32 percent in 2007. The increase resulted primarily
from:
These increases were partially offset by the net impact of our contribution of assets to WRB
Refining LLC, foreign currency impacts, and lower marketing sales volumes due to asset sales.
U.S. R&M
Net income from our U.S. R&M operations increased 18 percent in 2007, primarily due to:
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These items were partially offset by the net impact of our contribution of the Wood River and
Borger refineries to WRB, and the impact of business interruption insurance recoveries on our 2006
results. Our U.S. refining capacity utilization rate was 96 percent in 2007, compared with 92
percent in 2006, primarily reflecting lower planned maintenance and less weather-related downtime.
International R&M
Net income from our international R&M operations increased 131 percent in 2007, due primarily to:
These increases were partially offset by foreign currency impacts and lower marketing volumes due
to the asset sales. Our international refining capacity utilization rate was 90 percent in 2007,
compared with 91 percent in 2006. The 2007 utilization rate was affected by a temporary idling of
the Wilhelmshaven refinery in Germany during the month of August due to economic conditions.
LUKOIL Investment
This segment represents our investment in the ordinary shares of LUKOIL, an international,
integrated oil and gas company headquartered in Russia, which we account for under the equity
method. At December 31, 2008, our ownership interest in LUKOIL was 20 percent based on authorized
and issued shares. Our ownership interest based on estimated shares outstanding, used for
equity method accounting, was 20.06 percent at that date.
Because LUKOIL’s accounting cycle close and preparation of U.S. generally accepted accounting
principles financial statements occur subsequent to our reporting deadline, our equity earnings and
statistics for our LUKOIL investment are estimated based on current market indicators, publicly
available LUKOIL information, and other objective data. Once the difference between actual and
estimated results is known, an adjustment is recorded. This estimate-to-actual adjustment will be
a recurring component of future-period results. In addition to our estimated equity share of
LUKOIL’s earnings, this segment reflects the amortization of the basis difference between our
equity interest in the net assets of LUKOIL and the book value of our investment. The segment also
includes the costs associated with our employees seconded to LUKOIL.
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2008 vs. 2007
The LUKOIL Investment segment had a $5,488 million net loss during 2008, compared with
$1,818 million of net income in 2007. The 2008 results include a $7,410 million noncash, before-
and after-tax impairment of our LUKOIL investment taken during the fourth quarter. For additional
information, see the “LUKOIL” section of Note 7—Investments, Loans and Long-Term Receivables, in
the Notes to Consolidated Financial Statements, which is incorporated herein by reference.
Excluding the impact of the impairment, income from the LUKOIL Investment segment increased 6
percent in 2008. This increase was primarily due to higher estimated realized prices of both
refined product and crude oil sales. Partially offsetting these positive impacts were higher
estimated extraction taxes and higher estimated crude and refined product export tariff rates, as
well as higher estimated operating costs and lower estimated crude volumes.
The adjustment to estimated results for the fourth quarter of 2007, recorded in 2008, decreased net
income $16 million, compared with a $19 million decrease to net income recorded in 2007 to adjust
the estimated results for the fourth quarter of 2006.
2007 vs. 2006
Net income from the LUKOIL Investment segment increased 28 percent during 2007, primarily due to
higher estimated realized prices, higher estimated volumes, and an increase in our average equity
ownership. The increase was partially offset by higher estimated taxes and operating costs, as
well as the net impact from the alignment of estimated net income to reported results. The
adjustment to estimated results for the fourth quarter of 2006, recorded in 2007, decreased net
income $19 million, compared with a $71 million increase to net income recorded in 2006 to adjust
the estimated results for the fourth quarter of 2005.
Chemicals
The Chemicals segment consists of our 50 percent interest in Chevron Phillips Chemical Company LLC
(CPChem), which we account for under the equity method. CPChem uses natural gas liquids and other
feedstocks to produce petrochemicals. These products are then marketed and sold, or used as
feedstocks to produce plastics and commodity chemicals.
2008 vs. 2007
Net income from the Chemicals segment decreased 69 percent in 2008 due to higher utilities and
other operating costs, the absence of 2007 one-time tax benefits, lower specialties, aromatics and
styrenics margins, and lower olefins and polyolefins volumes. Increases in olefins and polyolefins
margins somewhat offset these negative effects. Business conditions in the chemicals and plastics
industry are expected to remain challenging in the near term.
2007 vs. 2006
Net income from the Chemicals segment decreased 27 percent during 2007, primarily due to lower
olefins and polyolefins margins and higher turnaround and weather-related repair costs, offset
partially by a capital-loss tax benefit of $65 million recorded in the fourth quarter of 2007.
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Emerging Businesses
The Emerging Businesses 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 innovation of new technologies, such as those related to conventional and
nonconventional hydrocarbon recovery (including heavy oil), refining, alternative energy, biofuels,
and the environment.
2008 vs. 2007
Emerging Businesses reported net income of $30 million in 2008, compared with a net loss of $8
million in 2007. The increase primarily reflects improved international power generation results,
including the impact of higher spark spreads. These benefits were partially offset by an $85
million after-tax impairment of a U.S. cogeneration power plant, as well as by lower domestic power
results.
2007 vs. 2006
The Emerging Businesses segment had a net loss of $8 million in 2007, compared with net income of
$15 million in 2006. The decrease reflects lower margins from the Immingham power plant in the
United Kingdom, as well as higher spending associated with alternative energy programs. These
decreases were slightly offset by the inclusion of a write-down of a damaged gas turbine at a
domestic power plant in 2006 results.
Corporate and Other
2008 vs. 2007
Net interest consists of interest and financing expense, net of interest income and capitalized
interest, as well as premiums incurred on the early retirement of debt. In 2008, net interest
decreased 32 percent primarily due to lower average interest rates and a higher effective tax rate.
Corporate general and administrative expenses increased 15 percent in 2008, mainly as a result of
increased charitable contributions. Acquisition-related costs in 2007 included transition costs
associated with the Burlington Resources acquisition. The category “Other” includes certain
foreign currency transaction gains and losses, environmental costs associated with sites no longer
in operation, and other costs not directly associated with an operating segment. “Other” expenses
increased in 2008 due to various tax-related adjustments, partially offset by lower foreign
currency losses.
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2007 vs. 2006
Net interest decreased 6 percent in 2007, primarily due to higher amounts of interest being
capitalized, partially offset by a premium on the early retirement of debt. Corporate general and
administrative expenses increased 32 percent in 2007, primarily due to higher benefit-related
expenses. Acquisition-related costs in 2007 included transition costs associated with the
Burlington Resources acquisition. Results from “Other” were primarily impacted by foreign currency
losses in 2007.
CAPITAL RESOURCES AND LIQUIDITY
Financial Indicators
To meet our short- and long-term liquidity requirements, we look to a variety of funding sources.
Cash generated from operating activities is the primary source of funding. In addition, during
2008 we raised $1,640 million in proceeds from asset dispositions. During 2008, available cash was
used to support our ongoing capital expenditures and investments program, repurchase shares of our
common stock, provide loan financing to certain equity affiliates, pay dividends, and meet the
funding requirements to FCCL Oil Sands Partnership. Total dividends paid on our common stock during
the year were $2,854 million. During 2008, cash and cash equivalents decreased $701 million to
$755 million.
In addition to cash flows from operating activities and proceeds from asset sales, we rely on our
commercial paper and credit facility programs, and our shelf registration statements to support our
short- and long-term liquidity requirements. The credit markets, including the commercial paper
markets in the United States, have recently experienced adverse conditions. Although we have not
been materially impacted by these conditions, continuing volatility in the credit markets may
increase costs associated with issuing commercial paper or other debt instruments due to increased
spreads over relevant interest rate benchmarks. Such volatility may also affect our ability, or
the ability of third parties with whom we seek to do business, to access those credit markets.
Notwithstanding these adverse market conditions, we believe current cash and short-term investment
balances and cash generated by operations, together with access to external sources of funds as
described below in the “Significant Sources of Capital” section, will be sufficient to meet our
funding requirements in the near- and long-term, including our capital spending program, dividend
payments, required debt payments and the funding requirements to FCCL.
Significant Sources of Capital
Operating Activities
During 2008, cash of $22,658 million was provided by operating activities, an 8 percent decrease
from cash from operations of $24,550 million in 2007. Contributing to the decrease were lower U.S.
refining margins and volumetric inventory builds in our R&M segment in 2008, versus reductions in
2007. These factors were partially offset by higher commodity prices in our E&P segment.
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During 2007, cash flow from operations increased $3,034 million to $24,550 million. Contributing
to the improvement over 2006 results 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.
While the stability of our cash flows from operating activities benefits from geographic diversity
and the effects of upstream and downstream integration, our short- and long-term operating cash
flows are highly dependent upon prices for crude oil, natural gas and natural gas liquids, as well
as refining and marketing margins. During 2008 and 2007, we benefited from favorable crude oil and
natural gas prices, although these prices deteriorated significantly in the fourth quarter of 2008.
Prices and margins are driven by market conditions over which we have no control. Absent other
mitigating factors, as these prices and margins fluctuate, we would expect a corresponding change
in our operating cash flows.
The level of our production volumes of crude oil, natural gas and natural gas liquids also impacts
our cash flows. These production levels are impacted by such factors as acquisitions and
dispositions of fields, field production decline rates, new technologies, operating efficiency,
weather conditions, the addition of proved reserves through exploratory success, and the timely and
cost-effective development of those proved reserves. While we actively manage these factors,
production levels can cause variability in cash flows, although historically this variability has
not been as significant as that caused by commodity prices.
Our production for 2008, including our share of production from equity affiliates, averaged 2.21
million BOE per day. Future production is subject to numerous uncertainties, including, among
others, the volatile crude oil and natural gas price environment, which may impact project
investment decisions; the price effect of production sharing contracts; changes in fiscal terms of
projects; project delays; and weather-related disruptions. Although actual year-to-year production
levels will vary, based on our current outlook and planning assumptions, we project no material
change in annual production levels from 2008 through 2013.
To maintain or grow our production volumes, we must continue to add to our proved reserve base.
Our reserve replacement in 2008, including equity affiliates, was 31 percent. The 2008 reserve
replacement was adversely impacted by low year-end commodity prices, which resulted in significant
negative reserve revisions. Our 2008 reserve replacement from consolidated operations and from our
equity affiliates was a negative 23 percent and a positive 224 percent, respectively. Over the
three-year period ending December 31, 2008, our reserve replacement was 124 percent. This was
comprised of a reserve replacement from consolidated operations of 115 percent and from equity
affiliates of 153 percent. The purchase of reserves in place was a significant factor in replacing
our reserves over the past three-year period, partially offset by the expropriation of our
Venezuelan oil assets. Significant purchases during this three-year period included reserves added
as part of the 2008 Origin Energy joint venture, the 2007 EnCana business venture, and the 2006
acquisition of Burlington Resources, as well as proved reserves added through our investments in
LUKOIL in 2006. The reserve replacement amounts above were based on the sum of our net additions
(revisions, improved recovery, purchases, extensions and discoveries, and sales) divided by our
production, as shown in our reserve table disclosures in the “Oil and Gas Operations” section of
this report.
We are developing and pursuing projects we anticipate will allow us to add to our reserve base.
However, 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.
As discussed in the “Critical Accounting Estimates” section, engineering estimates of proved
reserves are imprecise, and therefore, each year reserves may be revised upward or downward due to
the impact of changes in oil and gas prices or as more technical data becomes available on
reservoirs. In 2008 and 2006, revisions decreased our reserves, while in 2007 revisions increased
reserves. It is not possible to reliably predict how
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revisions will impact reserve quantities in the future. See the “Capital Spending” section for an
analysis of proved undeveloped reserves.
In addition, the level and quality of output from our refineries impacts our cash flows. The
output at our refineries is impacted by such factors as operating efficiency, maintenance
turnarounds, feedstock availability and weather conditions. We actively manage the operations of
our refineries and, typically, any variability in their operations has not been as significant to
cash flows as that caused by refining margins.
In 2006, we received approximately $1.1 billion in distributions from two heavy-oil projects in
Venezuela. The majority of these distributions represented operating results from previous years.
We did not receive an operating distribution related to these projects in 2007 or 2008.
Asset Sales
Proceeds from asset sales in 2008 were $1,640 million, compared with $3,572 million in 2007. The
amounts for both periods are mainly due to 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. We do not expect any material
asset dispositions in 2009 beyond the sale of our U.S. retail marketing assets. In January 2009,
we closed on the sale of a large part of these assets, which included seller financing in the form
of a $370 million five-year note and letters of credit totaling $54 million.
Commercial Paper and Credit Facilities
At December 31, 2008, we had two revolving credit facilities totaling $9.85 billion, consisting of
a $7.35 billion facility, expiring in September 2012, and a $2.5 billion facility scheduled to
expire in September 2009 (terminated in early 2009, see the
“Shelf Registrations” section below).
The $7.35 billion facility was reduced from $7.5 billion during the third quarter of 2008 due to
the bankruptcy of Lehman Commercial Paper Inc., one of the revolver participants. The $2.5 billion
facility is a 364-day bank facility entered into during October 2008 to provide additional support
of a temporary expansion of our commercial paper program. We expanded our commercial paper program
to ensure adequate liquidity after the initial funding of our transaction with Origin Energy. For
additional information on the Origin transaction, see Note 7—Investments, Loans and Long-Term
Receivables, in the Notes to Consolidated Financial Statements.
Our revolving credit facilities may be used as direct bank borrowings, as support for issuances of
letters of credit totaling up to $750 million, as support for our commercial paper programs, or as
support of up to $250 million on commercial paper issued by TransCanada Keystone Pipeline LP, a
Keystone pipeline joint venture entity. The revolving credit facilities are broadly syndicated
among financial institutions and do not contain any material adverse change provisions or any
covenants requiring maintenance of specified financial ratios or ratings. The facility agreements
contain 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.
Our primary funding source for short-term working capital needs is the ConocoPhillips $8.1 billion
commercial paper program. Commercial paper maturities are generally limited to 90 days. We also
have the ConocoPhillips Qatar Funding Ltd. $1.5 billion commercial paper program, which is used to
fund commitments relating to the Qatargas 3 project. At December 31, 2008 and 2007, we had no
direct outstanding borrowings under the revolving credit facilities, but $40 million and $41
million, respectively, in letters of credit had been issued. In addition, under both commercial
paper programs, there was $6,933 million of commercial paper outstanding at December 31, 2008,
compared with $725 million at December 31, 2007. Since we had $6,933 million of commercial paper
outstanding, had issued $40 million of letters of credit and had up to a $250 million guarantee on
commercial paper issued by Keystone, we had access to $2.6 billion in borrowing capacity under our
revolving credit facilities at December 31, 2008.
Shelf Registrations
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. Under this shelf
registration, in May 2008 we issued notes consisting of $400 million of 4.40% Notes due 2013, $500
million of 5.20% Notes due 2018 and
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$600 million of 5.90% Notes due 2038. The proceeds from the offering were used at that time to
reduce commercial paper and for general corporate purposes.
Also under this shelf registration, in early 2009 we issued $1.5 billion of 4.75% Notes due 2014,
$2.25 billion of 5.75% Notes due 2019, and $2.25 billion of 6.50% Notes due 2039. The proceeds of
the notes were primarily used to reduce outstanding commercial paper balances. Under the terms of
the $2.5 billion, 364-day revolving credit facility noted above, the receipt of the proceeds from
this bond offering terminated this revolving credit facility.
Our senior long-term debt is rated “A1” by Moody’s Investor Service and “A” by both Standard and
Poors’ Rating Service and Fitch, unchanged from December 31, 2008. We do not have any ratings
triggers on any of our corporate debt that would cause an automatic default, and thereby impact our
access to liquidity, in the event of a downgrade of our credit rating. In the event our credit
rating deteriorates to a level prohibiting us from accessing the commercial paper market, we would
still be able to access funds under our $7.35 billion revolving credit facility.
We also have on file with the SEC a shelf registration statement under which ConocoPhillips Canada
Funding Company I and ConocoPhillips Canada Funding Company II, both wholly owned subsidiaries,
could issue an indeterminate amount of senior debt securities, fully and unconditionally guaranteed
by ConocoPhillips and ConocoPhillips Company.
Minority Interests
At December 31, 2008, we had outstanding $1,100 million of equity in less than wholly owned
consolidated subsidiaries held by minority interest owners, including a minority interest of
$507 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, amounting to $580 million,
was related to Darwin LNG, an operation located in Australia’s Northern Territory.
In December 2001, in order to raise funds for general corporate purposes, ConocoPhillips and Cold
Spring Finance S.a.r.l. formed Ashford Energy Capital S.A. through the contribution of a $1 billion
ConocoPhillips subsidiary promissory note and $500 million cash by Cold Spring. Through its
initial $500 million investment, Cold Spring is entitled to a cumulative annual preferred return
consisting of 1.32 percent plus a three-month LIBOR rate set at the beginning of each quarter. The
preferred return at December 31, 2008, was 5.37 percent. In 2008, Cold Spring declined its option
to remarket its investment in Ashford. This option remains available in 2018 and at each 10-year
anniversary thereafter. If remarketing is unsuccessful, we could be required to provide a letter
of credit in support of Cold Spring’s investment, or in the event such a letter of credit is not
provided, cause the redemption of Cold Spring’s investment in Ashford. Should our credit rating
fall below investment grade, Ashford would require a letter of credit to support $475 million of
the term loans, as of December 31, 2008, made by Ashford to other ConocoPhillips subsidiaries. If
the letter of credit is not obtained within 60 days, Cold Spring could cause Ashford to sell the
ConocoPhillips subsidiary notes. At December 31, 2008, Ashford held $2.0 billion of ConocoPhillips
subsidiary notes and $28 million in investments unrelated to ConocoPhillips. We report Cold
Spring’s investment as a minority interest because it is not mandatorily redeemable, and the entity
does not have a specified liquidation date. Other than the obligation to make payment on the
subsidiary notes described above, Cold Spring does not have recourse to our general credit.
Off-Balance Sheet Arrangements
As part of our normal ongoing business operations and consistent with normal industry practice, we
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. At December 31, 2008,
we were liable for certain contingent obligations under the following contractual arrangements:
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For additional information about guarantees, see Note 14—Guarantees, in the Notes to Consolidated
Financial Statements, which is incorporated herein by reference.
Capital Requirements
Our debt balance at December 31, 2008, was $27.5 billion, an increase of $5.8 billion during 2008,
and our debt-to-capital ratio was 33 percent at year-end 2008, versus 19 percent at the end of
2007. The increase in the debt-to-capital ratio was mainly due to noncash impairments taken in the
fourth quarter of 2008 and the increase in debt. Our debt-to-capital target range is 20 percent to
25 percent.
In January 2008, we reduced our Floating Rate Five-Year Term Note due 2011 from $3 billion to $2
billion, with a subsequent reduction in June 2008 to $1.5 billion. In March 2008, we redeemed our
$300 million 7.125% Debentures due 2028 at a premium of $8 million, plus accrued interest.
On January 3, 2007, we closed on a business venture with EnCana. As part of this transaction, we
are obligated to contribute $7.5 billion, plus accrued interest,
over a 10-year period, beginning
in 2007, to the upstream business venture, FCCL, formed as a result of the transaction. An initial
contribution of $188 million was made upon closing in January. Quarterly principal and interest
payments of $237 million began in the second quarter of 2007, and will continue until the balance
is paid. Of the principal obligation amount, approximately $625 million is short-term and was
included in the “Accounts payable—related parties” line on our December 31, 2008, consolidated
balance sheet. The principal portion of these payments, which totaled $593 million in 2008, was
included in the “Other” line in the financing activities section of our consolidated statement of
cash flows. Interest accrues at a fixed annual rate of 5.3 percent on the unpaid principal
balance. Fifty percent of the quarterly interest payments was reflected as an additional capital
contribution and was included in the “Capital expenditures and investments” line on our
consolidated statement of cash flows.
On July 9, 2007, we announced plans to repurchase up to $15 billion of our common stock through the
end of 2008. This amount included $2 billion remaining under a previously announced program. At
year-end 2007, approximately $10.1 billion remained authorized for share repurchases in 2008.
During 2008, we repurchased 103.7 million shares of our common stock at a cost of $8.2 billion.
In December 2005, we entered into a credit agreement with Qatargas 3, whereby we will provide loan
financing of approximately $1.2 billion for the construction of an LNG train in Qatar. This
financing will represent 30 percent of the project’s total debt financing. Through December 31,
2008, we had provided $835 million in loan financing, and an additional $76 million of accrued
interest.
In 2004, we finalized our transaction with Freeport LNG Development, L.P. to participate in an LNG
receiving terminal in Quintana, Texas, for which construction began in early 2005. We do not have
an ownership interest in the facility, but we do have a 50 percent interest in the general
partnership managing the venture, along with contractual rights to regasification capacity of the
terminal. We entered into a credit agreement with Freeport to provide loan financing for the
construction of the facility. The terminal became operational in June 2008, and in August 2008,
the loan was converted from a construction loan to a term loan and consisted of $650 million in
loan financing and $124 million of accrued interest. Freeport began making repayments in September
2008, and the loan balance outstanding at December 31, 2008, was $757 million.
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In 2004, ConocoPhillips and LUKOIL agreed to the expansion of the Varandey terminal as part of our
investment in the OOO Naryanmarneftegaz (NMNG) joint venture. We have an obligation to provide
loan financing to Varandey Terminal Company for 30 percent of the costs of the terminal expansion,
but we will have no governance or ownership interest in the terminal. Terminal construction was
completed in June 2008, and the final loan amount was $275 million at December 2008 exchange rates,
excluding accrued interest. Although repayments are not required to start until May 2010, Varandey
used available cash to repay $12 million of interest in the second half of 2008. The outstanding
accrued interest at December 31, 2008, was $38 million at December exchange rates.
Our loans to Qatargas 3, Freeport and Varandey Terminal Company are included in the “Loans and
advances—related parties” line on our consolidated balance sheet, while the short-term portion is
in “Accounts and notes receivable—related parties.”
In February 2009, we announced a quarterly dividend of 47 cents per share. The dividend is payable
March 2, 2009, to stockholders of record at the close of business February 23, 2009.
Contractual Obligations
The following table summarizes our aggregate contractual fixed and variable obligations as of
December 31, 2008:
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Capital Spending
Capital Expenditures and Investments
Our capital expenditures and investments for the three-year period ending December 31, 2008,
totaled $46.5 billion, with 77 percent going to our E&P segment. Included in these amounts was
approximately $4.7 billion related to the October 2008 closing of a transaction with Origin Energy
to further enhance our long-term Australasian natural gas business through a 50/50 joint venture
named Australia Pacific LNG. The joint venture will focus on coalbed methane production from the
Bowen and Surat basins in Queensland, Australia, and LNG processing and export sales. For
additional information about the Origin transaction,
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see Note 7—Investments,
Loans and Long-Term Receivables, in the Notes to
Consolidated Financial Statements.
Our capital expenditures and investments budget for 2009 is $11.7 billion. Included in this amount
is approximately $600 million in capitalized interest. The decline from 2008 spending is primarily
due to the closing of the transaction with Origin Energy in 2008 and the deferring or slowing of
some projects or programs in 2009, as a result of the current business environment. We plan to
direct 81 percent of the capital expenditures and investments budget to E&P and 17 percent to R&M.
With the addition of loans to certain affiliated companies and principal contributions related to
funding our portion of the FCCL business venture, our total capital program for 2009 is
approximately $12.5 billion.
E&P
Capital expenditures and investments for E&P during the three-year period ending December 31, 2008,
totaled $35.9 billion. The expenditures over this period supported key exploration and development
projects including:
2009 CAPITAL EXPENDITURES AND INVESTMENTS BUDGET
E&P’s 2009 capital expenditures and investments budget is $9.5 billion, 43 percent lower than
actual expenditures in 2008. The decline is primarily due to the 2008 Origin transaction and the
deferring or slowing of some projects or programs. Thirty-seven percent of E&P’s 2009 capital
expenditures and investments budget is planned for the United States.
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Capital spending for our Alaskan operations is expected to fund Prudhoe Bay, Kuparuk and Western
North Slope operations, including the Alpine satellite fields, as well as initiatives to progress
Denali—The Alaska Gas Pipeline, and exploration activities.
In the Lower 48, we expect to make capital expenditures and investments for ongoing development
programs in the Permian, San Juan, Williston and Fort Worth basins and the Lobo Trend in South
Texas, as well as for development of projects such as the Rockies Express natural gas pipeline.
E&P is directing $6.0 billion of its 2009 capital expenditures and investments budget to
international projects. Funds in 2009 will be directed to developing major long-term projects
including:
PROVED UNDEVELOPED RESERVES
The net addition of proved undeveloped reserves accounted for 156 percent, 77 percent and
37 percent of our total net additions in 2008, 2007 and 2006, respectively. During these years, we
converted, on average, 15 percent per year of our proved undeveloped reserves to proved developed
reserves. Of our 2,823 million total BOE proved undeveloped reserves at December 31, 2008, we
estimated that the average annual conversion rate for these reserves for the three-year period
ending 2011 will be approximately 15 percent.
Costs incurred for the years ended December 31, 2008, 2007 and 2006, relating to the development of
proved undeveloped reserves were $4.8 billion, $4.3 billion, and $3.9 billion, respectively.
Estimated future development costs relating to the development of proved undeveloped reserves for
the years 2009 through 2011 are projected to be $3.9 billion, $3.1 billion, and $2.0 billion,
respectively.
Approximately 80 percent of our proved undeveloped reserves at year-end 2008 were associated with
10 major development areas in our E&P segment, and our investment in LUKOIL. Eight of the major
development areas within E&P are currently producing and are expected to have proved reserves
convert from undeveloped to developed over time as development activities continue and/or
production facilities are expanded or upgraded, and include:
The remaining two major projects, Qatargas 3 in Qatar and the Kashagan field in Kazakhstan, will
have undeveloped proved reserves convert to developed as these projects begin production.
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R&M
Capital spending for R&M during the three-year period ending December 31, 2008, 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. During this three-year period, R&M capital
spending was $6.7 billion, representing 14 percent of our total capital expenditures and
investments.
Key projects during the three-year period included:
Major construction activities in progress include:
2009 CAPITAL EXPENDITURES AND INVESTMENTS BUDGET
R&M’s 2009 capital budget is $2.0 billion, a 12 percent decrease from actual spending in 2008.
Domestic spending in 2009 is expected to comprise 71 percent of the R&M budget.
We plan to direct about $1.1 billion of the R&M capital budget to domestic refining, primarily for
projects related to sustaining and improving existing business with a focus on safety, regulatory
compliance, reliability and capital maintenance. Work continues on projects to expand conversion
capability and increase clean product yield, including funding for the San Francisco hydrocracker
project. Our U.S. transportation, marketing and specialty businesses are expected to spend about
$300 million, including investments in the Keystone project.
Internationally, we plan to spend about $600 million, with a focus on projects related to
reliability, safety and the environment, as well as an upgrade project at the Wilhelmshaven,
Germany, refinery. The construction bidding process for the refinery project in Yanbu, Saudi
Arabia, is currently scheduled to take place in 2009.
LUKOIL Investment
Capital spending in our LUKOIL Investment segment during the three-year period ending December 31,
2008, was for purchases of ordinary shares of LUKOIL in 2006 to increase our ownership interest.
No additional purchases were made in 2007 or 2008, and none are expected in 2009.
Emerging Businesses
Capital spending for Emerging Businesses during the three-year period ending December 31, 2008, was
primarily for an expansion of the Immingham combined heat and power cogeneration plant near the
company’s Humber refinery in the United Kingdom. In addition, in October 2007, we purchased a 50
percent interest in Sweeny Cogeneration LP.
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Contingencies
Legal and Tax Matters
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 Financial
Accounting Standards Board (FASB) Interpretation No. 48, “Accounting for
Uncertainty in Income Taxes—an 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.
Environmental
We are subject to the same numerous international, federal, state and local environmental laws and
regulations as 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:
These laws and their implementing regulations set limits on emissions and, in the case of
discharges to water, establish water quality limits. They also, in most cases, require permits in
association with new or modified operations. These permits can require an applicant to collect
substantial information in connection with the application process, which can be expensive and
time-consuming. In addition, there can be delays associated with notice and comment periods and
the agency’s processing of the application. Many of the delays associated with the permitting
process are beyond the control of the applicant.
Many states and foreign countries where we operate also have, or are developing, similar
environmental laws and regulations governing these same types of activities. While similar, in
some cases these regulations may impose additional, or more stringent, requirements that can add to
the cost and difficulty of marketing or transporting products across state and international
borders.
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The ultimate financial impact arising from environmental laws and regulations is neither clearly
known nor easily determinable as new standards, such as air emission standards, water quality
standards and stricter fuel regulations continue to evolve. However, environmental laws and
regulations, including those that may arise to address concerns about global climate change, are
expected to continue to have an increasing impact on our operations in the United States and in
other countries in which we operate. Notable areas of potential impacts include air emission
compliance and remediation obligations in the United States.
For example, the Energy Policy Act of 2005 imposed obligations to provide increasing volumes on a
percentage basis of renewable fuels in transportation motor fuels through 2012. These obligations
were changed with the enactment of the Energy Independence & Security Act of 2007, which was signed
in late December. The new law requires fuel producers and importers to provide approximately 66
percent more renewable fuels in 2008 as compared with amounts set forth in the Energy Policy Act of
2005, with increases in amounts of renewable fuels required through 2022. We are in the process of
establishing implementation, operating and capital strategies, along with advanced technology
development, to meet these requirements.
We also are subject to certain laws and regulations relating to environmental remediation
obligations associated with current and past operations. Such laws and regulations include CERCLA
and RCRA and their state equivalents. Remediation obligations include cleanup responsibility
arising from petroleum releases from underground storage tanks located at numerous past and present
ConocoPhillips-owned and/or operated petroleum-marketing outlets throughout the United States.
Federal and state laws require contamination caused by such underground storage tank releases be
assessed and remediated to meet applicable standards. In addition to other cleanup standards, many
states adopted cleanup criteria for methyl tertiary-butyl ether (MTBE) for both soil and
groundwater.
At RCRA permitted facilities, we are required to assess environmental conditions. If conditions
warrant, we may be required to remediate contamination caused by prior operations. In contrast to
CERCLA, which is often referred to as “Superfund,” the cost of corrective action activities under
RCRA corrective action programs typically is borne solely by us. Over the next decade, we
anticipate increasing expenditures for RCRA remediation activities may be required, but such annual
expenditures for the near term are not expected to vary significantly from the range of such
expenditures we have experienced over the past few years. Longer-term expenditures are subject to
considerable uncertainty and may fluctuate significantly.
We, from time to time, receive requests for information or notices of potential liability from the
EPA and state environmental agencies alleging that we are a potentially responsible party under
CERCLA or an equivalent state statute. On occasion, we also have been made a party to cost
recovery litigation by those agencies or by private parties. These requests, notices and lawsuits
assert potential liability for remediation costs at various sites that typically are not owned by
us, but allegedly contain wastes attributable to our past operations. As of December 31, 2007, we
reported we had been notified of potential liability under CERCLA and comparable state laws at 68
sites around the United States. At December 31, 2008, we re-opened three sites and closed one of
those sites, resolved and closed seven sites, and received two new notices of potential liability,
leaving 65 unresolved sites where we have been notified of potential liability.
For most Superfund sites, our potential liability will be significantly less than the total site
remediation costs because the percentage of waste attributable to us, versus that attributable to
all other potentially responsible parties, is relatively low. Although liability of those
potentially responsible is generally joint and several for federal sites and frequently so for
state sites, other potentially responsible parties at sites where we are a party typically have had
the financial strength to meet their obligations, and where they have not, or where potentially
responsible parties could not be located, our share of liability has not increased materially.
Many of the sites at which we are potentially responsible are still under investigation by the EPA
or the state agencies concerned. Prior to actual cleanup, those potentially responsible normally
assess site conditions, apportion responsibility and determine the appropriate remediation. In
some instances, we may have no liability or attain a settlement of liability. Actual cleanup costs
generally occur after the parties obtain EPA or equivalent state agency approval. There are
relatively few sites where we are a major participant, and given the timing and
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amounts of anticipated expenditures, neither the cost of remediation at those sites nor such costs
at all CERCLA sites, in the aggregate, is expected to have a material adverse effect on our
competitive or financial condition.
Expensed environmental costs were $957 million in 2008 and are expected to be about $1.0 billion
per year in 2009 and 2010. Capitalized environmental costs were $1,025 million in 2008 and are
expected to be about $900 million per year in 2009 and 2010.
We accrue for remediation activities when it is probable that a liability has been incurred and
reasonable estimates of the liability can be made. These accrued liabilities are not reduced for
potential recoveries from insurers or other third parties and are not discounted (except those
assumed in a purchase business combination, which we do record on a discounted basis).
Many of these liabilities result from CERCLA, RCRA and similar state laws that require us to
undertake certain investigative and remedial activities at sites where we conduct, or once
conducted, operations or at sites where ConocoPhillips-generated waste was disposed. The accrual
also includes a number of sites we identified that may require environmental remediation, but which
are not currently the subject of CERCLA, RCRA or state enforcement activities. If applicable, we
accrue receivables for probable insurance or other third-party recoveries. In the future, we may
incur significant costs under both CERCLA and RCRA. Considerable uncertainty exists with respect
to these costs, and under adverse changes in circumstances, potential liability may exceed amounts
accrued as of December 31, 2008.
Remediation activities vary substantially in duration and cost from site to site, depending on the
mix of unique site characteristics, evolving remediation technologies, diverse regulatory agencies
and enforcement policies, and the presence or absence of potentially liable third parties.
Therefore, it is difficult to develop reasonable estimates of future site remediation costs.
At December 31, 2008, our balance sheet included total accrued environmental costs of $979 million,
compared with $1,089 million at December 31, 2007. We expect to incur a substantial amount of
these expenditures within the next 30 years.
Notwithstanding any of the foregoing, and as with other companies engaged in similar businesses,
environmental costs and liabilities are inherent in our operations and products, and there can be
no assurance that material costs and liabilities will not be incurred. However, we currently do
not expect any material adverse effect upon our results of operations or financial position as a
result of compliance with current environmental laws and regulations.
Climate Change
There has been a broad range of proposed or promulgated state, national and international laws
focusing on greenhouse gas (GHG) reduction. These proposed or promulgated laws apply or could
apply in countries where we have interests or may have interests in the future. Laws in this field
continue to evolve, and while they are likely to be increasingly widespread and stringent, at this
stage it is not possible to accurately estimate either a timetable for implementation or our future
compliance costs relating to implementation. Compliance with changes in laws, regulations and
obligations that create a GHG emissions trading scheme or GHG reduction policies generally could
significantly increase costs or reduce demand for fossil energy derived products. Examples of
legislation or precursors for possible regulation that does or could affect our operations include:
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In the EU, we have assets that are subject to the ETS. The first phase of the EU ETS was completed
at the end of 2007, with EU ETS phase II running from 2008 through 2012. The European Commission
has approved most of the phase II national allocation plans. We are actively engaged to minimize
any financial impact from the trading scheme.
In the United States, there is growing consensus that some form of regulation will be forthcoming
at the federal level with respect to GHG emissions and such regulation could result in the creation
of additional costs in the form of taxes or required acquisition or trading of emission allowances.
In light of this consensus, we have taken a position to encourage the adoption of a pragmatic and
sustainable regulatory framework addressing GHG. To that end, we joined the U.S. Climate Action
Partnership (USCAP) in support of the development of a national regulatory framework to reduce the
level of GHG emissions. We support a framework that is economically sustainable, environmentally
effective, transparent and fair, and internationally linked. We are working to continuously
improve operational and energy efficiency through resource and energy conservation throughout our
operations.
Other
We have deferred tax assets related to certain accrued liabilities, loss carryforwards and credit
carryforwards. Valuation allowances have been established to reduce these deferred tax assets to
an amount that will, more likely than not, be realized. Based on our historical taxable income,
our expectations for the future, and available tax-planning strategies, management expects that the
net deferred tax assets will be realized as offsets to reversing deferred tax liabilities and as
reductions in future taxable income.
NEW ACCOUNTING STANDARDS
In December 2007, the FASB issued Statement of Financial Accounting Standards (SFAS) No. 141
(Revised), “Business Combinations” (SFAS No. 141(R)). This Statement will apply to all
transactions in which an entity obtains control of one or more other businesses. In general, SFAS
No. 141(R) requires the acquiring entity in a business combination to recognize the fair value of
all the assets acquired and liabilities assumed in the transaction; establishes the acquisition
date as the fair value measurement point; and modifies the disclosure requirements. Additionally,
it changes the accounting treatment for transaction costs, acquired contingent arrangements,
in-process research and development, restructuring costs, changes in deferred tax asset valuation
allowances as a result of business combination, and changes in income tax uncertainties after the
acquisition date. This Statement applies prospectively to business combinations for which the
acquisition date is on or after January 1, 2009. However, starting January 1, 2009, accounting for
changes in valuation allowances for acquired deferred tax assets and the resolution of uncertain
tax positions for prior business combinations will impact tax expense instead of impacting
goodwill.
Also in December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated
Financial Statements—an amendment of ARB No. 51,” which requires noncontrolling interests, also
called minority interests, to be presented as a separate item in the equity section of the
consolidated balance sheet. It also requires the amount of consolidated net income attributable to
the noncontrolling interest to be clearly presented on the face of the consolidated income
statement. Additionally, this Statement clarifies that changes in a parent’s ownership interest in
a subsidiary that do not result in deconsolidation are equity transactions, and when a subsidiary
is deconsolidated, it requires gain or loss recognition in net income based on the fair value on
the deconsolidation date. This Statement is effective January 1,
2009, and will be applied prospectively
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with the exception of the presentation and disclosure requirements, which must be applied
retrospectively for all periods presented.
In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging
Activities—an amendment of FASB No. 133.” This Statement expands disclosure requirements of SFAS
No. 133, “Accounting for Derivative Instruments and Hedging Activities,” for derivative instruments
within the scope of that Statement to provide greater transparency. This includes disclosure of
the additional information regarding how and why derivative instruments are used, how derivatives
are accounted for, and how they affect an entity’s financial performance. This Statement is
effective for interim and annual financial statements beginning with the first quarter of 2009, but
it will not have any impact on our consolidated financial statements, other than the additional
disclosures.
In November 2008, the FASB reached a consensus on Emerging Issues Task Force Issue No. 08-6,
“Equity Method Investment Accounting Considerations” (EITF 08-6), which was issued to clarify how
the application of equity method accounting will be affected by SFAS No. 141(R) and SFAS No. 160.
EITF 08-6 clarifies that an entity shall continue to use the cost accumulation model for its equity
method investments. It also confirms past accounting practices related to the treatment of
contingent consideration and the use of the impairment model under
Accounting Principles Board (APB) Opinion No. 18, “The
Equity Method of Accounting for Investments in Common Stock.” Additionally, it
requires an equity method investor to account for a share issuance by an investee as if the
investor had sold a proportionate share of the investment. This issue is effective January 1,
2009, and will be applied prospectively.
In December 2008, the FASB issued FASB Staff Position (FSP) No. 132(R)-1, “Employers’ Disclosures
about Postretirement Benefit Plan Assets,” to improve the transparency associated with the
disclosures about the plan assets of a defined benefit pension or other postretirement plan. This
FSP requires the disclosure of each major asset category at fair value using the fair value
hierarchy in SFAS No. 157, “Fair Value Measurements.” Also, this FSP requires entities to disclose
the net periodic benefit cost recognized for each annual period for which a statement of income is
presented. This FSP is effective for annual statements beginning with 2009.
CRITICAL ACCOUNTING ESTIMATES
The preparation of financial statements in conformity with generally accepted accounting principles
requires management to select appropriate accounting policies and to make estimates and assumptions
that affect the reported amounts of assets, liabilities, revenues and expenses. See Note
1—Accounting Policies, in the Notes to Consolidated Financial Statements, for descriptions of our
major accounting policies. Certain of these accounting policies involve judgments and
uncertainties to such an extent that there is a reasonable likelihood that materially different
amounts would have been reported under different conditions, or if different assumptions had been
used. These critical accounting estimates are discussed with the Audit and Finance Committee of
the Board of Directors at least annually. We believe the following discussions of critical
accounting estimates, along with the discussions of contingencies and of deferred tax asset
valuation allowances in this report, address all important accounting areas where the nature of
accounting estimates or assumptions is material due to the levels of subjectivity and judgment
necessary to account for highly uncertain matters or the susceptibility of such matters to change.
Oil and Gas Accounting
Accounting for oil and gas exploratory activity is subject to special accounting rules unique to
the oil and gas industry. The acquisition of geological and geophysical seismic information, prior
to the discovery of proved reserves, is expensed as incurred, similar to accounting for research
and development costs. However, leasehold acquisition costs and exploratory well costs are
capitalized on the balance sheet pending determination of whether proved oil and gas reserves have
been discovered on the prospect.
Property Acquisition Costs
For 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
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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.
This judgmental probability percentage is reassessed and adjusted throughout the contractual period
of the leasehold based on favorable or unfavorable exploratory activity on the leasehold or on
adjacent leaseholds, and leasehold impairment amortization expense is adjusted prospectively. At
year-end 2008, the book value of the pools of property acquisition costs, that individually are
relatively small and thus subject to the above-described periodic leasehold impairment calculation,
was $1,447 million and the accumulated impairment reserve was
$494 million. The weighted-average
judgmental percentage probability of ultimate failure was
approximately 65 percent, and the weighted-average amortization period was approximately 2.4 years. If that judgmental percentage were to be
raised by 5 percent across all calculations, pretax leasehold impairment expense in 2009 would
increase by approximately $30 million. The remaining $4,745 million of capitalized unproved
property costs at year-end 2008 consisted of individually significant leaseholds, mineral rights
held in perpetuity by title ownership, exploratory wells currently drilling, and suspended
exploratory wells. Management periodically assesses individually significant leaseholds for
impairment based on the results of exploration and drilling efforts and the outlook for project
commercialization. Of this amount, approximately $2.4 billion is concentrated in 10 major
development areas. None of these major assets are expected to move to proved properties in 2009.
Exploratory Costs
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.
Once a determination is made the well did not encounter potentially economic oil and gas
quantities, the well costs are expensed as a dry hole and reported in exploration expense. If
exploratory wells encounter potentially economic quantities of oil and gas, the well costs remain
capitalized on the balance sheet as long as sufficient progress assessing the reserves and the
economic and operating viability of the project is being made. The accounting notion of “sufficient
progress” is a judgmental area, but the accounting rules do prohibit continued capitalization of
suspended well costs on the mere chance that future market conditions will improve or new
technologies will be found that would make the project’s development economically profitable.
Often, the ability to move the project into the development phase and record proved reserves is
dependent on obtaining permits and government or co-venturer approvals, the timing of which is
ultimately beyond our control. Exploratory well costs remain suspended as long as the company is
actively pursuing such approvals and permits, and believes they will be obtained. Once all
required approvals and permits have been obtained, the projects are moved into the development
phase, and the oil and gas reserves are designated as proved reserves. For complex exploratory
discoveries, it is not unusual to have exploratory wells remain suspended on the balance sheet for
several years while we perform additional appraisal drilling and seismic work on the potential oil
and gas field, or while we seek government or co-venturer approval of development plans or seek
environmental permitting.
Management reviews suspended well balances quarterly, continuously monitors the results of the
additional appraisal drilling and seismic work, and expenses the suspended well costs as a dry hole
when it determines the potential field does not warrant further investment in the near term.
Criteria utilized in making this determination include evaluation of the reservoir characteristics
and hydrocarbon properties, expected development costs, ability to apply existing technology to
produce the reserves, fiscal terms, regulations or contract negotiations, and our required return
on investment.
At year-end 2008, total suspended well costs were $660 million, compared with $589 million at
year-end 2007. For additional information on suspended wells, including an aging analysis, see Note
8—Properties, Plants and Equipment, in the Notes to Consolidated Financial Statements.
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Proved Oil and Gas Reserves and Canadian Syncrude Reserves
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.
Despite the inherent imprecision in these engineering estimates, accounting rules require
disclosure of “proved” reserve estimates due to the importance of these estimates to better
understand the perceived value and future cash flows of a company’s E&P operations. There are
several authoritative guidelines regarding the engineering criteria that must be met before
estimated reserves can be designated as “proved.” Our reservoir engineering organization has
policies and procedures in place that are consistent with these authoritative guidelines. We have
trained and experienced internal engineering personnel who estimate our proved crude oil, natural
gas and natural gas liquids reserves held by consolidated companies, as well as our share of equity
affiliates, with assistance from third-party petroleum engineering consultants with regard to our
equity interests in LUKOIL and Australia Pacific LNG.
Proved reserve estimates are updated annually and take into account recent production and
subsurface information about each field or oil sand mining operation. Also, as required by current
authoritative guidelines, the estimated future date when a field or oil sand mining operation will
be permanently shut down for economic reasons is based on an extrapolation of sales prices and
operating costs prevalent at the balance sheet date. This estimated date when production will end
affects the amount of estimated reserves. Therefore, as prices and cost levels change from year to
year, the estimate of proved reserves also changes.
Our proved reserves include estimated quantities related to production sharing contracts, which are
reported under the “economic interest” method and are subject to fluctuations in prices of crude
oil, natural gas and natural gas liquids; recoverable operating expenses; and capital costs. If
costs remain stable, reserve quantities attributable to recovery of costs will change inversely to
changes in commodity prices. For example, if prices increase, then our applicable reserve
quantities would decline.
The estimation of proved reserves also is important to the statement of operations because the
proved oil and gas reserve estimate for a field or the estimated in-place crude bitumen volume for
an oil sand mining operation serves as the denominator in the unit-of-production calculation of
depreciation, depletion and amortization of the capitalized costs for that asset. At year-end
2008, the net book value of productive E&P properties, plants and equipment subject to a
unit-of-production calculation, including our Canadian Syncrude bitumen oil sand assets, was
approximately $58 billion and the depreciation, depletion and amortization recorded on these assets
in 2008 was approximately $7.7 billion. The estimated proved developed oil and gas reserves of
these fields were 6.1 billion BOE at the beginning of 2008 and were 5.5 billion BOE at the end of
2008. The estimated proved reserves of Canadian Syncrude assets were 221 million barrels at the
beginning of 2008 and were 249 million barrels at the end of 2008. If the estimates of proved
reserves used in the unit-of-production calculations had been lower by 5 percent across all
calculations, pretax depreciation, depletion and amortization in 2008 would have increased by an
estimated $406 million. Impairments of producing oil and gas properties in 2008, 2007 and 2006
totaled $793 million, $471 million and $215 million, respectively. Of these write-downs,
$56 million in 2008, $76 million in 2007 and $131 million in 2006 were due to downward revisions of
proved reserves due to reservoir performance.
Impairments
Long-lived assets used in operations are assessed for impairment whenever changes in facts and
circumstances indicate a possible significant deterioration in the future cash flows expected to be
generated by an asset group. If, upon review, the sum of the undiscounted pretax cash flows is less
than the carrying value of the asset group, the carrying value is written down to estimated fair
value. Individual assets are grouped for impairment purposes based on a judgmental assessment of
the lowest level for which there are identifiable cash flows that
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are largely independent of the cash flows of other groups of assets—generally on a field-by-field
basis for exploration and production assets, at an entire complex level for downstream assets, or
at a site level for retail stores. Because there usually is a lack of quoted market prices for
long-lived assets, the fair value of impaired assets is determined based on the present values of
expected future cash flows using discount rates commensurate with the risks involved in the asset
group or based on a multiple of operating cash flow validated with historical market transactions
of similar assets where possible. The expected future cash flows used for impairment reviews and
related fair value calculations are based on judgmental assessments of future production volumes,
prices and costs, considering all available information at the date of review. See Note
10—Impairments, in the Notes to Consolidated Financial Statements, for additional information.
Investments in nonconsolidated entities accounted for under the equity method are reviewed for
impairment when there is evidence of a loss in value. Such evidence of a loss in value might
include our inability to recover the carrying amount, the lack of sustained earnings capacity which
would justify the current investment amount, or a current fair value less than the investment’s
carrying amount. When it is determined such a loss in value is other than temporary, an impairment
charge is recognized for the difference between the investment’s carrying value and its estimated
fair value. When determining whether a decline in value is other than
temporary, management considers factors such as the length of time and extent of the decline, the
investee’s financial condition and near-term prospects, and the company’s ability and intention to
retain its investment for a period that will be sufficient to allow for any anticipated recovery in
the market value of the investment. When quoted market prices are not available, the fair value is
usually based on the present value of expected future cash flows using discount rates commensurate
with the risks of the investment. Differing assumptions could affect the timing and the amount of
an impairment of an investment in any period. For additional information, see the “LUKOIL” section
of Note 7—Investments, Loans and Long-Term Receivables, in the Notes to Consolidated Financial
Statements.
Asset Retirement Obligations and Environmental Costs
Under various contracts, permits and regulations, we have material legal obligations to remove
tangible equipment and restore the land or seabed at the end of operations at operational sites.
Our largest asset removal obligations involve removal and disposal of offshore oil and gas
platforms around the world, oil and gas production facilities and pipelines in Alaska, and asbestos
abatement at refineries. The fair values of obligations for dismantling and removing these
facilities are accrued at the installation of the asset based on estimated discounted costs.
Estimating the future asset removal costs necessary for this accounting calculation is difficult.
Most of these removal obligations are many years, or decades, in the future and the contracts and
regulations often have vague descriptions of what removal practices and criteria must be met when
the removal event actually occurs. Asset removal technologies and costs are changing constantly,
as well as political, environmental, safety and public relations considerations.
In addition, under the above or similar contracts, permits and regulations, we have certain
obligations to complete environmental-related projects. These projects are primarily related to
cleanup at domestic refineries and underground storage tanks at U.S. service stations, and
remediation activities required by Canada and the state of Alaska at exploration and production
sites. Future environmental remediation costs are difficult to estimate because they are subject
to change due to such factors as the uncertain magnitude of cleanup costs, the unknown time and
extent of such remedial actions that may be required, and the determination of our liability in
proportion to that of other responsible parties.
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Business Acquisitions
Purchase Price Allocation
Accounting for the acquisition of a business requires the allocation of the purchase price to the
various assets and liabilities of the acquired business. For most assets and liabilities, purchase
price allocation is accomplished by recording the asset or liability at its estimated fair value.
The most difficult estimations of individual fair values are those involving properties, plants and
equipment and identifiable intangible assets. 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.
Intangible Assets and Goodwill
At December 31, 2008, we had $738 million of intangible assets determined to have indefinite useful
lives, thus they are not amortized. This judgmental assessment of an indefinite useful life must
be continuously evaluated in the future. If, due to changes in facts and circumstances, management
determines these intangible assets 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
management’s judgment of the estimated fair value of these intangible assets. See Note 9—Goodwill
and Intangibles, in the Notes to Consolidated Financial Statements, for additional information.
In the fourth quarter of 2008, we fully impaired the recorded goodwill associated with our
Worldwide E&P reporting unit. See the “Goodwill Impairment” section of Note 9—Goodwill and
Intangibles, in the Notes to Consolidated Financial Statements, which is incorporated herein by
reference, for a detailed discussion of the facts and circumstances leading to this impairment, as
well as the judgments required by management in the analysis leading to the impairment
determination. After the goodwill impairment, at December 31, 2008, we had $3,778 million of
goodwill remaining on our balance sheet, all of which was attributable to the Worldwide R&M
reporting unit.
Projected Benefit Obligations
Determination of the projected benefit obligations for our defined benefit pension and
postretirement plans are important to the recorded amounts for such obligations on the balance
sheet and to the amount of benefit expense in the statement of operations. The actuarial
determination of projected benefit obligations and company contribution requirements involves
judgment about uncertain future events, including estimated retirement dates, salary levels at
retirement, mortality rates, lump-sum election rates, rates of return on plan assets, future health
care cost-trend rates, and rates of utilization of health care services by retirees. Due to the
specialized nature of these calculations, we engage outside actuarial firms to assist in the
determination of these projected benefit obligations and company contribution requirements. For
Employee Retirement Income Security Act-qualified pension plans, the actuary exercises fiduciary
care on behalf of plan participants in the determination of the judgmental assumptions used in
determining required company contributions into plan assets. Due to differing objectives and
requirements between financial accounting rules and the pension plan funding regulations
promulgated by governmental agencies, the actuarial methods and assumptions for the two purposes
differ in certain important respects. Ultimately, we will be required to fund all promised
benefits under pension and postretirement benefit plans not funded by plan assets or investment
returns, but the judgmental assumptions used in the actuarial calculations significantly affect
periodic financial statements and funding patterns over time. Benefit expense is particularly
sensitive to the discount rate and return on plan assets assumptions. A 1 percent decrease in the
discount rate would increase annual benefit expense by $79 million, while a 1 percent decrease in
the return on plan assets assumption would increase annual benefit expense by $43 million. In
determining the discount rate, we use yields on high-quality fixed income investments matched to
the estimated benefit cash flows of our plans.
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CAUTIONARY STATEMENT FOR THE PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF THE PRIVATE SECURITIES
LITIGATION REFORM ACT OF 1995
This report includes forward-looking statements within the meaning of Section 27A of the Securities
Act of 1933 and Section 21E of the Securities Exchange Act of 1934. You can identify our
forward-looking statements by the words “anticipate,” “estimate,” “believe,” “continue,” “could,”
“intend,” “may,” “plan,” “potential,” “predict,” “should,” “will,” “expect,” “objective,”
“projection,” “forecast,” “goal,” “guidance,” “outlook,” “effort,” “target” and similar
expressions.
We based the forward-looking statements relating to our operations on our current expectations,
estimates and projections about ourselves and the industries in which we operate in general. We
caution you these statements are not guarantees of future performance and involve risks,
uncertainties and assumptions we cannot predict. In addition, we based many of these
forward-looking statements on assumptions about future events that may prove to be inaccurate.
Accordingly, our actual outcomes and results may differ materially from what we have expressed or
forecast in the forward-looking statements. Any differences could result from a variety of
factors, including the following:
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Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Financial Instrument Market Risk
We and certain of our subsidiaries hold and issue derivative contracts and financial instruments
that expose our cash flows or earnings to changes in commodity prices, foreign exchange rates or
interest rates. We may use financial and commodity-based derivative contracts to manage the risks
produced by changes in the prices of electric power, natural gas, crude oil and related products,
fluctuations in interest rates and foreign currency exchange rates, or to exploit market
opportunities.
Our use of derivative instruments is governed by an “Authority Limitations” document approved by
our Board of Directors that prohibits the use of highly leveraged derivatives or derivative
instruments without sufficient liquidity for comparable valuations. The Authority Limitations
document also authorizes the Chief Operating 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 and
reports to the Chief Executive Officer. The Senior Vice President of Commercial monitors commodity
price risk and reports to the Chief Operating 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.
Commodity Price Risk
We operate in the worldwide crude oil, refined products, natural gas, natural gas liquids, and
electric power markets and are exposed to fluctuations in the prices for these commodities. These
fluctuations can affect our revenues, as well as the cost of operating, investing, and financing
activities. Generally, our policy is to remain exposed to 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.
Our Commercial organization uses futures, forwards, swaps, and options in various markets to
optimize the value of our supply chain, which may move our risk profile away from market average
prices to accomplish the following objectives:
We use a VaR model to estimate the loss in fair value that could potentially result on a single day
from the effect of adverse changes in market conditions on the derivative financial instruments and
derivative commodity instruments held or issued, including commodity purchase and sales contracts
recorded on the balance sheet at December 31, 2008, as derivative instruments in accordance with
SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended (SFAS No.
133). Using Monte Carlo simulation, a 95 percent confidence level and a one-day holding period,
the VaR for those instruments issued or held for trading purposes at December 31, 2008 and 2007,
was immaterial to our net income and cash flows.
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The VaR for instruments held for purposes other than trading at December 31, 2008 and 2007, was
also immaterial to our net income and cash flows.
Interest Rate Risk
The following tables provide information about our financial instruments that are sensitive to
changes in 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.
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The following tables present principal cash flows of the fixed-rate 5.3 percent joint venture
acquisition obligation owed to FCCL Oil Sands Partnership. The fair value of the obligation is
estimated based on the net present value of the future cash flows, discounted at a year-end 2008
and 2007 effective yield rate of 5.4 percent and 4.9 percent, respectively, based on yields of U.S.
Treasury securities of a similar average duration adjusted for ConocoPhillips’ average credit risk
spread and the amortizing nature of the obligation principal.
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Foreign Currency Risk
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, net investments in foreign subsidiaries, certain local currency tax payments and
dividends, and cash returns from net investments in foreign affiliates to be remitted within the
coming year.
At December 31, 2008 and 2007, we held foreign currency swaps hedging short-term intercompany loans
between European subsidiaries and a U.S. subsidiary. Although these swaps hedge exposures to
fluctuations in exchange rates, we elected not to utilize hedge accounting as allowed by SFAS No.
133. As a result, the change in the fair value of these foreign currency swaps is recorded
directly in earnings. Since the gain or loss on the swaps is offset by the gain or loss from
remeasuring the intercompany loans into the functional currency of the lender or borrower, there
would be no material impact to income from an adverse hypothetical 10 percent change in the
December 31, 2008 or 2007, exchange rates. The notional and fair market values of these positions
at December 31, 2008 and 2007, were as follows:
For additional information about our use of derivative instruments, see Note 16—Financial
Instruments and Derivative Contracts, in the Notes to Consolidated Financial Statements.
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Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
CONOCOPHILLIPS
INDEX TO FINANCIAL STATEMENTS
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Report of Management
Management prepared, and is responsible for, the consolidated financial statements and the other
information appearing in this annual report. The consolidated financial statements present fairly
the company’s financial position, results of operations and cash flows in conformity with
accounting principles generally accepted in the United States. In preparing its consolidated
financial statements, the company includes amounts that are based on estimates and judgments that
management believes are reasonable under the circumstances. The company’s financial statements
have been audited by Ernst & Young LLP, an independent registered public accounting firm appointed
by the Audit and Finance Committee of the Board of Directors and ratified by stockholders.
Management has made available to Ernst & Young LLP all of the company’s financial records and
related data, as well as the minutes of stockholders’ and directors’ meetings.
Assessment of Internal Control Over Financial Reporting
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 company’s management and directors regarding the preparation and fair presentation
of published financial statements.
All internal control systems, no matter how well designed, have inherent limitations. Therefore,
even those systems determined to be effective can provide only reasonable assurance with respect to
financial statement preparation and presentation.
Management assessed the effectiveness of the company’s internal control over financial reporting as
of December 31, 2008. In making this assessment, it used the criteria set forth by the Committee
of Sponsoring Organizations of the Treadway Commission in Internal Control—Integrated Framework.
Based on our assessment, we believe the company’s internal control over financial reporting was
effective as of December 31, 2008.
Ernst & Young LLP has issued an audit report on the company’s internal control over financial
reporting as of December 31, 2008.
February 25, 2009
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Report of Independent Registered Public Accounting Firm on Consolidated Financial Statements
The Board of Directors and Stockholders
ConocoPhillips We have audited the accompanying consolidated balance sheets of ConocoPhillips as of December 31,
2008 and 2007, and the related consolidated statements of operations, changes in common
stockholders’ equity, and cash flows for each of the three years in the period ended December 31,
2008. Our audits also included the related condensed consolidating
financial information listed in the Index at Item 8 and
financial statement schedule listed in Item 15(a). These financial statements, condensed
consolidating financial information, and schedule are the responsibility of the Company’s
management. Our responsibility is to express an opinion on these financial statements, condensed
consolidating financial information, and schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the
financial statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material
respects, the consolidated financial position of ConocoPhillips at December 31, 2008 and 2007, and
the consolidated results of its operations and its cash flows for each of the three years in the
period ended December 31, 2008, in conformity with U.S. generally accepted accounting principles.
Also, in our opinion, the related condensed consolidating financial information and financial
statement schedule, when considered in relation to the basic financial statements taken as a whole,
present fairly in all material respects the information set forth therein.
As discussed in Note 2 to the consolidated financial statements, in 2006 ConocoPhillips adopted
Emerging Issues Task Force Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with
the Same Counterparty,” and the recognition and disclosure provisions of Statement of Financial
Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other
Postretirement Plans—an amendment of FASB Statements No. 87, 88, 106, and 132(R).”
We also have audited, in accordance with the standards of the Public Company Accounting Oversight
Board (United States), ConocoPhillips’ internal control over financial reporting as of December 31,
2008, based on criteria established in Internal Control—Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 25,
2009 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Houston, Texas
February 25, 2009
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Report of Independent Registered Public Accounting Firm on
Internal Control Over Financial Reporting The Board of Directors and Stockholders
ConocoPhillips We have audited ConocoPhillips’ internal control over financial reporting as of December 31, 2008,
based on criteria established in Internal Control—Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission (the COSO criteria). ConocoPhillips’
management is responsible for maintaining effective internal control over financial reporting, and
for its assessment of the effectiveness of internal control over financial reporting included under
the heading “Assessment of Internal Control Over Financial Reporting” in the accompanying “Report
of Management.” Our responsibility is to express an opinion on the Company’s internal control over
financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether effective internal control over financial reporting was
maintained in all material respects. Our audit included obtaining an understanding of internal
control over financial reporting, assessing the risk that a material weakness exists, testing and
evaluating the design and operating effectiveness of internal control based on the assessed risk,
and performing such other procedures as we considered necessary in the circumstances. We believe
that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed 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. A
company’s internal control over financial reporting includes those policies and procedures that (1)
pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the
transactions and dispositions of the assets of the company; (2) provide reasonable assurance that
transactions are recorded as necessary to permit preparation of financial statements in accordance
with generally accepted accounting principles, and that receipts and expenditures of the company
are being made only in accordance with authorizations of management and directors of the company;
and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized
acquisition, use, or disposition of the company’s assets that could have a material effect on the
financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or
detect misstatements. Also, projections of any evaluation of effectiveness to future periods are
subject to the risk that controls may become inadequate because of changes in conditions, or that
the degree of compliance with the policies or procedures may deteriorate.
In our opinion, ConocoPhillips maintained, in all material respects, effective internal control
over financial reporting as of December 31, 2008, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight
Board (United States), the 2008 consolidated financial statements of ConocoPhillips and our report
dated February 25, 2009 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Houston, Texas
February 25, 2009
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See Notes to Consolidated Financial Statements.
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See Notes to Consolidated Financial Statements.
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