e10vk
2010
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
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(Mark One) |
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[x]
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934 |
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For the fiscal year ended
December 31, 2010
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OR |
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934 |
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For the transition period from
to
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Commission file number: 001-32395
ConocoPhillips
(Exact name of registrant as specified in its charter)
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Delaware
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01-0562944 |
(State or other jurisdiction of
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(I.R.S. Employer |
incorporation or organization) |
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Identification No.) |
600 North Dairy Ashford
Houston, TX 77079
(Address of principal executive offices) (Zip Code)
Registrants telephone number, including area code: 281-293-1000
Securities registered pursuant to Section 12(b) of the Act:
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Name of each exchange |
Title of each class |
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on which registered |
Common Stock, $.01 Par Value |
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New York Stock Exchange |
Preferred Share Purchase Rights Expiring June 30, 2012 |
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New York Stock Exchange |
6.65% Debentures due July 15, 2018 |
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New York Stock Exchange |
7% Debentures due 2029 |
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New York Stock Exchange |
9.375% Notes due 2011 |
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New York Stock Exchange |
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.
[x] Yes [ ] 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.
[ ] Yes [x] 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.
[x] Yes [ ] No
Indicate by check mark whether the registrant has submitted electronically and posted on its
corporate Web site, if any, every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period
that the registrant was required to submit and post such files).
[x] Yes [ ] 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 registrants 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. [x]
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.
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Large accelerated filer [x]
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Accelerated filer [ ]
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Non-accelerated filer [ ]
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Smaller reporting company [ ] |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Act).
[ ] Yes [x] No
The aggregate market value of common stock held by non-affiliates of the registrant on June 30,
2010, the last business day of the registrants most recently completed second fiscal quarter,
based on the closing price on that date of $49.09, was $72.8 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 827,349 and 37,798,903 shares, respectively, in
determining the aggregate market value.
The registrant had 1,429,647,979 shares of common stock outstanding at January 31, 2011.
Documents incorporated by reference:
Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held on May 11, 2011
(Part III)
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
2Business 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 anticipate, estimate, believe, budget, continue, could, intend, may,
plan, potential, predict, seek, should, will, would, expect, objective,
projection, forecast, goal, guidance, outlook, effort, target and similar expressions
identify forward-looking statements. The company does not undertake to update, revise or correct
any 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
companys 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 65.
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:
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Exploration and Production (E&P)This segment primarily explores for, produces,
transports and markets crude oil, bitumen, natural gas, liquefied natural gas (LNG) and
natural gas liquids on a worldwide basis. |
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MidstreamThis segment gathers, processes and markets natural gas produced by
ConocoPhillips and others, and fractionates and markets natural gas liquids, predominantly
in the United States and Trinidad. The Midstream segment primarily consists of our 50
percent equity investment in DCP Midstream, LLC. |
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Refining and Marketing (R&M)This segment purchases, refines, markets and transports
crude oil and petroleum products, mainly in the United States, Europe and Asia. |
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LUKOIL InvestmentThis segment consists of our investment in the ordinary shares of OAO
LUKOIL, an international, integrated oil and gas company headquartered in Russia. At
December 31, 2010, our ownership interest was 2.25 percent based on issued shares. See
Note 6Investments, Loans and Long-Term Receivables, in the Notes to Consolidated
Financial Statements, for information on sales of LUKOIL shares. |
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ChemicalsThis segment manufactures and markets petrochemicals and plastics on a
worldwide basis. The Chemicals segment consists of our 50 percent equity investment in
Chevron Phillips Chemical Company LLC (CPChem). |
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Emerging BusinessesThis segment represents our investment in new technologies or
businesses outside our normal scope of operations. |
At December 31, 2010, ConocoPhillips employed approximately 29,700 people.
1
SEGMENT AND GEOGRAPHIC INFORMATION
For operating segment and geographic information, see Note 25Segment Disclosures and Related
Information, in the Notes to Consolidated Financial Statements, which is incorporated herein by
reference.
EXPLORATION AND PRODUCTION (E&P)
At December 31, 2010, our E&P segment represented 63 percent of ConocoPhillips total assets. This
segment primarily explores for, produces, transports and markets crude oil, bitumen, natural gas
and natural gas liquids on a worldwide basis. Operations to liquefy natural gas and transport the
resulting LNG are also included in the E&P segment. At December 31, 2010, our E&P operations were
producing in the United States, Norway, the United Kingdom, Canada, Australia, offshore Timor-Leste
in the Timor Sea, Indonesia, China, Vietnam, Libya, Nigeria, Algeria, Qatar and Russia.
The E&P segment does not include the financial results or statistics from our 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 Oil and Gas Operations disclosures, as well as in the following net proved
reserves table, for periods before we ceased using equity-method accounting for this investment,
which occurred at the end of the third quarter of 2010.
The information listed below appears in the Oil and Gas Operations disclosures following the
Notes to Consolidated Financial Statements and is incorporated herein by reference:
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Proved worldwide crude oil and natural gas liquids, natural gas, bitumen and synthetic
oil reserves. |
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Net production of crude oil and natural gas liquids, natural gas, bitumen and synthetic
oil. |
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Average sales prices of crude oil and natural gas liquids, natural gas, bitumen and
synthetic oil. |
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Average production costs per barrel of oil equivalent (BOE). |
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Net wells completed, wells in progress and productive wells. |
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Developed and undeveloped acreage. |
2
The following table is a summary of the proved reserves information included in the Oil and Gas
Operations disclosures following the Notes to Consolidated Financial Statements. Approximately 75
percent of our proved reserves are located in politically stable countries that belong to the
Organization for Economic Cooperation and Development. Natural gas reserves are converted to BOE
based on a 6:1 ratio: six thousand cubic feet of natural gas converts to one BOE. See Managements
Discussion and Analysis of Financial Condition and Results of Operations for a discussion of
factors that will enhance the understanding of the table below.
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Millions of Barrels of Oil Equivalent |
Net Proved Reserves at December 31 |
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2010 |
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2009 |
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2008 |
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Crude oil and natural gas liquids |
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Consolidated operations |
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3,161 |
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3,194 |
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3,340 |
Equity affiliates |
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231 |
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1,710 |
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1,677 |
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Total Crude Oil and Natural Gas Liquids |
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3,392 |
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4,904 |
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5,017 |
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Natural gas |
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Consolidated operations |
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3,039 |
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3,161 |
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3,360 |
Equity affiliates |
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580 |
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880 |
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798 |
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Total Natural Gas |
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3,619 |
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4,041 |
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4,158 |
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Bitumen |
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Consolidated operations |
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455 |
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417 |
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100 |
Equity affiliates |
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844 |
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716 |
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700 |
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Total Bitumen |
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1,299 |
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1,133 |
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800 |
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Synthetic oil |
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Consolidated operations |
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- |
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248 |
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- |
Equity affiliates |
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- |
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- |
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- |
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Total Synthetic Oil |
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- |
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248 |
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- |
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Total consolidated operations |
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6,655 |
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7,020 |
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6,800 |
Total equity affiliates |
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1,655 |
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3,306 |
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3,175 |
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Total company |
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8,310 |
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10,326 |
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9,975 |
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Includes amounts related to LUKOIL investment: |
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- |
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1,967 |
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1,893 |
Excludes Syncrude mining-related reserves (synthetic oil): |
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n/a |
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n/a |
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249 |
In 2010, E&Ps worldwide production, including its share of equity affiliates, averaged
1,752,000 barrels of oil equivalent per day (BOED), compared with 1,854,000 BOED in 2009. During
2010, 686,000 BOED were produced in the United States, a 9 percent decrease from 755,000 BOED in
2009. Production from our international E&P operations averaged 1,066,000 BOED in 2010, a 3
percent decrease from 1,099,000 BOED in 2009. Worldwide production decreased primarily due to
field decline, the impact of higher prices on production sharing arrangements and the sale of our
Syncrude oil sands mining operation. These decreases were partially offset by production from
major projects in China, Canada, Qatar, the Lower 48 and Australia.
E&Ps worldwide annual average crude oil and natural gas liquids sales price increased 31 percent,
from $55.63 per barrel in 2009 to $72.77 per barrel in 2010. Worldwide bitumen prices increased 18
percent, from $44.84 per barrel in 2009 to $53.06 per barrel in 2010. E&Ps average annual
worldwide natural gas sales price increased 14 percent, from $4.37 per thousand cubic feet in 2009
to $4.98 per thousand cubic feet in 2010.
E&PUNITED STATES
In 2010, U.S. E&P operations contributed 40 percent of E&Ps worldwide liquids production and 39
percent of natural gas production, compared with 40 and 41 percent in 2009, respectively.
3
Alaska
Greater Prudhoe Area
The Greater Prudhoe Area includes the Prudhoe Bay Field and five satellite fields, as well as the
Greater Point McIntyre Area fields. Prudhoe Bay, the largest oil field on Alaskas 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 Bays satellites are
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 and natural gas liquids production
from the Greater Prudhoe Area averaged 113,000 barrels per day in 2010, compared with 119,000
barrels per day in 2009.
Greater Kuparuk Area
We operate the Greater Kuparuk Area, which is made up of the Kuparuk Field and four satellite
fields: Tarn, Tabasco, Meltwater and West Sak. Kuparuk is located 40 miles west of Prudhoe Bay on
Alaskas North Slope. 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 60,000 barrels per day in 2010, compared with 65,000 barrels per day in 2009.
Western North Slope
On the Western North Slope we operate the Colville River Unit, which includes the Alpine Field and
three satellite fields: Nanuq, Fiord and Qannik. Alpine is located 34 miles west of Kuparuk. Our
ownership interest in the area is 78 percent. Net production in 2010 was 59,000 barrels of oil per
day, compared with 68,000 barrels per day in 2009. Further development of potential satellite
fields west of Alpine and into the National Petroleum ReserveAlaska (NPRA) is contingent upon the
receipt of permit approvals and additional exploration appraisal work. Planned development of one
of these satellites, the Alpine West CD5 Project, was postponed due to the denial of a key permit
from the U.S. Army Corps of Engineers in February 2010. We appealed their decision, and in
December 2010, a ruling on our appeal remanded the matter back to the agencys district office in
Alaska for further review.
Cook Inlet Area
We operate the North Cook Inlet Unit, the Beluga River Unit, and the Kenai LNG Plant in the Cook
Inlet Area. We have a 100 percent interest in the North Cook Inlet Unit, while we own 33.3 percent
of the Beluga River Unit. Net production in 2010 from the Cook Inlet Area averaged 73 million
cubic feet per day of natural gas, compared with 85 million cubic feet per day in 2009. Production
from the North Cook Inlet Unit is used primarily to supply our share of natural gas to the Kenai
LNG Plant and also as a backup supply to local utilities, while gas from the Beluga River Unit 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 17 net billion cubic feet of LNG in 2010, compared with 21 billion cubic feet in
2009. On February 9, 2011, we announced that due to market conditions we will cease LNG exports
from the Kenai LNG Plant, effective in the second quarter of 2011, and will begin mothballing the
facility for potential future use.
Exploration
In a February 2008 lease sale conducted by the U. S. Department of Interior (DOI) under the Outer
Continental Shelf (OCS) Lands Act, we successfully bid and were awarded 10-year-primary-term leases
on 98 blocks in the Chukchi Sea, for total bid payments of $506 million. Various special interest
groups have brought two separate lawsuits challenging (1) the DOIs entire OCS leasing program, and
(2) the Chukchi Sea lease sale conducted by the DOI under that program. Due to continued pending
litigation and associated injunctions, our plans for drilling an exploration well on our Chukchi
Sea leases remain under review.
In January 2010, we exchanged a 25 percent working interest in 50 of our leases in the Chukchi Sea
for cash consideration and additional working interests in the deepwater Gulf of Mexico (GOM). In
late 2010, we entered into an agreement to farm-down an additional 10 percent of our working
interest in the same Chukchi
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Sea leases, and that agreement is subject to regulatory approval. In
addition, we participated in two appraisal wells in the Point Thomson Unit, where development
options are currently being evaluated.
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.
In 2008, ConocoPhillips and BP plc formed a limited liability company to progress the pipeline
project named DenaliThe Alaska Gas Pipeline. The project would move natural gas from Alaskas
North Slope to North American markets. Denali conducted an open season during 2010, a process in
which the pipeline company solicits customers to make long-term firm transportation commitments to
the project. There is a pipeline project competing with Denali that is structured under the Alaska
Gasline Inducement Act. Both projects are currently evaluating bids received from potential
customers during their respective open seasons and are engaged in confidential negotiations with
those bidders.
U.S. Lower 48
Gulf of Mexico
At year-end 2010, our portfolio of producing properties in the GOM mainly consisted of one operated
field and three fields operated by co-venturers, including:
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75 percent operator interest in the Magnolia Field in Garden Banks Blocks 783 and 784. |
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16 percent nonoperator interest in the unitized Ursa Field located in the Mississippi
Canyon Area. |
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16 percent nonoperator interest in the Princess Field, a northern, sub-salt extension of
the Ursa Field. |
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12.4 percent nonoperator interest in the unitized K2 Field, comprised of seven blocks in
the Green Canyon Area. |
Net production from our GOM properties averaged 18,000 barrels per day of liquids and 20 million
cubic feet per day of natural gas in 2010, compared with 21,000 barrels per day and 28 million
cubic feet per day in 2009.
Onshore
Our 2010 onshore production principally consisted of natural gas and associated liquids production,
with the majority of production located in the San Juan Basin, Permian Basin, Lobo Trend, Bossier
Trend, Fort Worth Basin, panhandles of Texas and Oklahoma and Williston Basin. We also have
operations in the Wind River and Anadarko Basins, as well as in East Texas and northern and
southern Louisiana.
Onshore activities in 2010 were centered mostly on continued optimization and development of
existing assets, with particular focus on areas with higher liquids production. Total net
production from all Lower 48 onshore fields in 2010 averaged 1,675 million cubic feet per day of
natural gas and 142,000 barrels per day of liquids, compared with 1,899 million cubic feet per day
and 145,000 barrels per day in 2009.
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Shale Plays
Exploration and development continues in our shale positions in Eagle Ford, Bakken and
Barnett, which produced approximately 36,000 barrels of oil equivalent per day in 2010. We
plan to drill approximately 150 exploration and development wells in the Eagle Ford in 2011
and, with subsequent investments, expect to achieve peak production in 2013 and long-term
average production of 65,000 to 70,000 barrels per day. We acquired approximately 90,000
additional acres in various resource plays across the Lower 48 during 2010, further
expanding our significant acreage position in Lower 48 shale plays. |
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San Juan
The San Juan Basin, located in northwestern New Mexico and southwestern Colorado, includes
the majority of our U.S. 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 799 million cubic feet per day of natural gas and 50,000 barrels per
day of liquids in 2010, compared with 903 million cubic feet per day and 49,000 barrels per
day in 2009. |
Exploration
In January 2010, we exchanged a 25 percent working interest in 50 of our leases in the Chukchi Sea
for cash consideration and additional working interests in the deepwater GOM. We were also the
successful bidder on 10 blocks in the March 2010 federal offshore lease sale. At year end, we had
interests in 274 lease blocks totaling 1.1 million net acres offshore GOM.
In May 2010, in response to the Deepwater Horizon incident in the GOM, the DOI issued a six-month
drilling moratorium on new deepwater wells in the OCS, which was scheduled to expire on November
30, 2010. On October 12, 2010, the DOI lifted the ban, citing new regulatory requirements which
would reduce the risks associated with deepwater drilling. The new rules are aimed at improving
safety and environmental standards and include strengthened requirements on safety equipment, well
control systems, blowout prevention practices and emergency response on offshore oil and gas
operations.
The new regulations have created delays in the permitting process and deepwater exploratory
drilling in the GOM. As a result, we have been unable to drill any GOM prospects or appraise the
Tiber and Shenandoah discoveries, which occurred in 2009. Although there are no material impacts
to our near-term production, the future effects of this incident, including any new or additional
regulations that may be adopted in response, are not clearly known at this time. We will continue
to evaluate the impact on our exploration prospects in the GOM.
Onshore, we actively pursued the appraisal of our existing shale plays in Eagle Ford in South
Texas, the Bakken in the Williston Basin and the Barnett in the Fort Worth Basin. We have seen
encouraging results in these liquids-rich plays and plan to continue appraisal and development in
2011.
Transportation
We own a 25 percent interest in the Rockies Express Pipeline (REX). REX is a 1,679-mile natural
gas pipeline stretching from northwestern Colorado to eastern Ohio, which became fully operational
in November 2009. REX has the capacity to deliver 1.8 billion cubic feet of natural gas per day to
eastern markets.
E&PEUROPE
In 2010, E&P operations in Europe contributed 21 percent of E&Ps worldwide liquids production,
compared with 23 percent in 2009. European operations contributed 18 percent of natural gas
production in 2010 and 2009. 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 North Sea. The Greater Ekofisk Area is composed of four producing
fields: Ekofisk, Eldfisk, Embla and Tor. Net production in 2010 from the Greater Ekofisk Area was
80,000 barrels of liquids per day and 79 million cubic feet of natural gas per day, compared with
92,000 barrels per day and 89 million cubic feet per day in 2009.
We also have varying ownership interests in eight other producing fields in the Norwegian sector of
the North Sea and in the Norwegian Sea. Net production from these fields averaged 57,000 barrels
of liquids per day and 130 million cubic feet of natural gas per day in 2010, compared with 68,000
barrels per day and 128 million cubic feet per day in 2009.
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Exploration
We participated in two exploration wells during 2010. Both the Megalodon and Dalsnuten wells
failed to find commercial hydrocarbons and were expensed as dry holes.
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.
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. We also have an 83.5 percent
interest and a 75 percent interest in the Callanish and Brodgar Britannia satellite fields,
respectively. Net production from Britannia and its satellite fields averaged 302 million cubic
feet of natural gas per day and 39,000 barrels of liquids per day in 2010, compared with 304
million cubic feet per day and 40,000 barrels per day in 2009.
We operate and hold a 36.5 percent interest in the Judy/Joanne/Jasmine Fields, which together make
up J-Block, located in the U.K. central North Sea. Additionally, our operated Jade Field, in which
we hold a 32.5 percent interest, produces from a wellhead platform and pipeline tied to the J-Block
facilities. The Judy/Joanne/Jade Fields produced a net 11,000 barrels of liquids per day and 82
million cubic feet of natural gas per day in 2010, compared with 12,000 barrels per day and 96
million cubic feet per day in 2009. In 2010, we received government approval for the development
of the Jasmine Field, which is expected to startup in 2012, and achieve average net peak production
of 35,000 barrels of oil equivalent per day by 2013.
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 2010 of 150 million cubic feet
per day of natural gas, compared with 185 million cubic feet per day in 2009.
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 2010 averaged
61 million cubic feet of natural gas per day, compared with 60 million cubic feet per day in 2009.
In the Atlantic Margin, we have a 24 percent interest in the Clair Field. Net production in 2010
averaged 9,000 barrels of liquids per day, compared with 12,000 barrels per day in 2009.
We also have ownership interests in several other producing fields in the U.K. sector of the North
Sea. Net production from these fields averaged 15,000 barrels of liquids per day and 11 million
cubic feet of natural gas per day in 2010, compared with 16,000 barrels per day and 12 million
cubic feet per day in 2009.
Exploration
We were awarded six blocks in the U.K. 26th Licensing Round. Three are in close
proximity to our producing J-Block infrastructure in the central North Sea, while one is adjacent
to our Britannia Field. The remaining blocks represent growth opportunities in the Dutch Bank
Basin of the North Sea.
Transportation
We have a 10 percent interest in the Interconnector Pipeline, which links the United Kingdom and
Belgium and facilitates marketing natural gas produced in the United Kingdom throughout Europe. We
have export capability to ship up to 220 million cubic feet of natural gas per day to markets in
continental Europe via the Interconnector, and our reverse-flow rights provide 85 million cubic
feet per day of 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 ownership interests, respectively. We also have a 100 percent ownership interest in the
Rivers Gas Terminal, operated by a third party, in the United Kingdom.
7
Poland
Exploration
We are participating in a shale gas venture in Poland that provides us with the opportunity to
evaluate and earn a 70 percent interest in six exploration licenses in the Baltic Basin. We
drilled two wells in 2010 and plan to continue appraisal of the play in 2011.
E&PCANADA
E&P operations in Canada contributed 11 percent of E&Ps worldwide liquids production in 2010 and
2009. Canadian operations contributed 21 percent of E&Ps worldwide natural gas production in
2010, compared with 22 percent in 2009.
Western Canada
Operations in western Canada encompass oil and gas properties throughout Alberta, northeastern
British Columbia, and southern Saskatchewan. Net production from western Canada averaged 984
million cubic feet per day of natural gas and 38,000 barrels per day of liquids in 2010, compared
with 1,062 million cubic feet per day and 40,000 barrels per day in 2009. Our 2010 drilling
program focused on the development and exploitation of several liquids-rich resource opportunities,
which included the Cardium Formation that lies primarily on our existing land base within the Deep
Basin and central Alberta. We initiated temporary production curtailments of approximately 150
million cubic feet equivalent per day from September through early December 2010, in response to
continued low natural gas prices in western Canada.
Surmont
We operate and have a 50 percent interest in the Surmont oil sands lease, located approximately 35
miles south of Fort McMurray, Alberta. An enhanced thermal oil recovery method called
steam-assisted gravity drainage (SAGD) is used at Surmont. The average net production of bitumen
during 2010 was 10,000 barrels per day, compared with 7,000 barrels per day in 2009. Surmont Phase
II construction began in 2010, with a targeted production startup in 2015. Surmonts net
production is expected to increase to 50,000 barrels per day by 2017.
FCCL
We have two 50/50 North American heavy oil business ventures with Cenovus Energy Inc.: FCCL
Partnership, a Canadian upstream general partnership, and WRB Refining LP, a U.S. downstream
limited partnership. FCCLs assets, operated by Cenovus, include the Foster Creek and Christina
Lake SAGD bitumen projects, both located in the eastern flank of the Athabasca oil sands in
northeastern Alberta. Our share of FCCLs production increased to 49,000 barrels per day in 2010,
compared with 43,000 barrels per day in 2009. In the third quarter of 2010, FCCL received
regulatory approval for Phases F, G and H at Foster Creek. Construction of Christina Lake Phase C
continued in 2010, with first production expected in the second half of 2011. Construction of
Christina Lake Phase D also continued through 2010. See the Refining and Marketing (R&M) section
for information on WRB.
Syncrude Canada Ltd.
We sold our 9.03 percent interest in the Syncrude Canada Ltd. joint venture in June 2010 for $4.6
billion. Syncrude had synthetic oil proved reserves of 248 million barrels at December 31, 2009.
Production averaged 12,000 barrels per day in 2010, compared with 23,000 barrels per day in 2009.
Parsons Lake/Mackenzie Gas Project
We are involved 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, which would anchor the pipeline development. The project is
in the final stage of regulatory approval, anticipated in early 2011; however, detailed engineering
work continues to be deferred pending resolution with the Canadian government on the fiscal and
commercial framework.
8
Exploration
We hold exploration acreage in four areas of Canada: offshore eastern Canada, onshore western
Canada, the Mackenzie Delta/Beaufort Sea Region, and the Arctic Islands. During 2010, we completed
drilling an exploration well in the Laurentian Basin, located offshore eastern Canada, which did
not find commercial quantities of hydrocarbons and was expensed as a dry hole. In western Canada,
we participated in 28 wells resulting in 20 discoveries.
E&PSOUTH AMERICA
Venezuela
In 2007, we announced we had been unable to reach agreement with respect to our migration to an
empresa mixta structure mandated by the Venezuelan governments Nationalization Decree. As a
result, Venezuelas national oil company, Petróleos de Venezuela S.A. (PDVSA), or its affiliates,
directly assumed control over ConocoPhillips interests in the Petrozuata and Hamaca heavy oil
ventures and the offshore Corocoro development project. In response to this expropriation, we
filed a request for international arbitration on November 2, 2007, with the World Banks
International Centre for Settlement of Investment Disputes (ICSID). An arbitration hearing was
held during 2010 before ICSID. We are awaiting their decision.
Ecuador
In 2008, Burlington Resources, Inc., a wholly owned subsidiary of ConocoPhillips, initiated
arbitration before ICSID against The Republic of Ecuador and PetroEcuador, as a result of the
newly enacted Windfall Profits Tax Law and government-mandated renegotiation of our production
sharing contracts. Despite a restraining order issued by ICSID, Ecuador confiscated the crude oil
production of Burlington and its co-venturer and sold the illegally seized crude oil. In 2009,
Ecuador took over operations in Blocks 7 and 21, fully expropriating our assets. In June 2010, the
ICSID tribunal concluded it has jurisdiction to hear the expropriation claim. A hearing on case
merits is scheduled for March 2011. For additional information, see Note 10Impairments, in the
Notes to Consolidated Financial Statements.
Exploration
In November 2010, Burlington Resources, Inc., and PetroEcuador signed termination agreements for
exploration Blocks 23 and 24, ending our participation in both blocks.
Peru
Exploration
During 2010, we executed two farm-downs that reduced our interests in Blocks 123, 124 and 129,
which are awaiting final government approval. We are currently completing the initial 2D seismic
program for Blocks 123 and 129 and plan to analyze the results in 2011. We also own a 35 percent
working interest in Block 39.
E&PASIA PACIFIC/MIDDLE EAST
In 2010, E&P operations in the Asia Pacific/Middle East Region contributed 15 percent of E&Ps
worldwide liquids production and 19 percent of natural gas production, compared with 13 percent and
16 percent in 2009, respectively.
Australia and Timor Sea
Australia Pacific LNG
Australia Pacific LNG (APLNG), our 50/50 joint venture with Origin Energy, is focused on producing
CBM from the Bowen and Surat Basins in Queensland, Australia. Gas is currently sold to domestic
customers, while progress continues on the development of an LNG processing and export sales
business. Once established, this will enhance our LNG position and serve as an additional LNG hub
targeting Asia Pacific markets. Two initial 4.2-million-tons-per-year LNG trains are anticipated,
with over 10,000 gross wells ultimately envisioned to supply both the domestic gas market and the
LNG development. The additional wells will be supported by expanded gas gathering systems,
centralized gas processing and compression stations, and water treatment facilities, in addition to
a new export pipeline from the gas fields to the LNG facilities.
9
Our share of the joint ventures production in 2010 was 115 million cubic feet per day of natural
gas, compared with 84 million cubic feet per day in 2009. CBM field development work is ongoing in
parallel with front-end engineering associated with the planned LNG processing facilities.
Engagement with potential LNG buyers continues to progress, and a final investment decision on the
initial phase of the project is planned for mid-2011.
In November 2010, the APLNG LNG development project received environmental approval from
Australias Queensland state. In late February 2011, the project
received environmental approval from the Australian federal
government.
Bayu-Undan
We operate and hold a 57.2 percent ownership interest in the Bayu-Undan Field located in the Timor
Sea. Net production from the field averaged 31,000 barrels of liquids per day in 2010, compared
with 35,000 barrels per day in 2009. Our share of natural gas production was 198 million cubic
feet per day in 2010, compared with 216 million cubic feet per day in 2009. Produced natural gas
is used to supply the Darwin LNG Plant, in which we own a 57.2 percent interest. In 2010, we sold
147 billion gross cubic feet of LNG to utility customers in Japan, compared with 156 billion cubic
feet in 2009.
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
must be resolved before significant funding commitments can be made. These include gaining both
governments approval of the development concept selected by the co-venturers and establishing
fiscal stability arrangements.
Western Australia
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 in both 2010 and 2009.
Exploration
We operate and own a 60 percent interest in three permits located in the Browse Basin, offshore
northwest Australia. During 2010, we continued the exploration and appraisal programs and drilled
two wells, Poseidon-2 and Kronos-1, both of which encountered hydrocarbons. We intend to carry out
a second phase of drilling in the Browse Basin during 2011 and 2012. Analysis of the
recently acquired seismic survey over the discovered resource area is ongoing.
Qatar
Qatargas 3 (QG3) is an integrated project jointly owned by Qatar Petroleum (68.5 percent),
ConocoPhillips (30 percent) and Mitsui & Co., Ltd. (1.5 percent). The project comprises upstream
natural gas production facilities to produce approximately 1.4 billion gross cubic feet per day of
natural gas from Qatars North Field over a 25 year life. The project also includes a 7.8-million-gross-ton-per-year LNG facility, from which LNG is shipped in leased LNG carriers destined
for sale in the United States and other markets. First production was achieved in October 2010,
with eight LNG cargoes loaded and shipped in 2010.
We have a 12.4 percent ownership interest in the Golden Pass LNG Terminal and affiliated Golden
Pass Pipeline. The terminal is currently under construction adjacent to the Sabine-Neches
Industrial Ship Channel northwest of Sabine Pass, Texas. Definitive terminal and pipeline use
agreements have been reached, which will provide us with terminal and pipeline capacity for the
receipt, storage and regasification of the LNG purchased from QG3 and the transportation of
regasified LNG to interconnect with major interstate natural gas pipelines.
Indonesia
We operate seven production sharing contracts (PSCs) in Indonesia. Three of these PSCs are in
various stages of development from which net production averaged 463 million cubic feet per day of
natural gas and 17,000 barrels per day of liquids in 2010, compared with 447 million
cubic feet per day and 19,000 barrels per day in 2009. Our producing assets are primarily
concentrated in two core areas: South Natuna Sea and onshore South Sumatra.
10
South Natuna Sea Block B
The offshore South Natuna Sea Block B PSC, in which we have a 40 percent interest, has two
producing oil fields and 16 natural gas fields in various stages of development. Natural gas
production is sold under international sales agreements to Malaysia and Singapore.
South Sumatra
These onshore blocks consist of the Corridor and South Jambi B PSCs. The Corridor PSC, in which we
have a 54 percent interest, has six oil fields and six natural gas fields in various stages of
development. Natural gas is supplied from the Grissik and Suban gas processing plants to the Duri
steamflood in central Sumatra and to markets in Singapore, Batam and West Java. Unitization of the
Suban natural gas field commenced in 2010, reflecting that approximately 8 percent of the fields
proved reserves are now attributable to an adjacent PSC. The unitization is expected to be
finalized during 2011. We have a 45 percent interest in the South Jambi B PSC, which supplies
natural gas to Singapore.
Exploration
We operate three offshore exploration PSCs: Amborip VI, Kuma and Arafura Sea, with interests
ranging from 60 to 100 percent. We began exploration drilling in the fourth quarter of 2010. The
first well drilled on these offshore PSCs was the Aru-1. We did not find recoverable resources
with the well, and it was expensed as a dry hole in the fourth quarter of 2010. We also operate
and own an 80 percent interest in the Warim onshore exploration PSC in Papua.
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.
China
We are the operator and have a 49 percent share of the Peng Lai 19-3 Field in Bohai Bay Block
11-05, as well as the nearby Peng Lai 19-9 and Peng Lai 25-6 Fields. As part of our Bohai Bay
Phase II Project, a floating production, storage and offloading (FPSO) vessel is used to
accommodate production from these fields. Net production averaged 56,000 barrels of oil per day in
2010, compared with 33,000 barrels per day in 2009. Production from the Peng Lai area is expected
to increase due to continued development of Peng Lai 19-3, with annual average net production of
60,000 barrels of oil per day anticipated in 2011.
The Xijiang development consisted of two fields located approximately 80 miles south of Hong Kong
in the South China Sea. Combined net production of oil from the Xijiang Fields averaged 1,000
barrels per day in 2010, compared with 5,000 barrels per day in 2009. Under the terms of the
contract, our ownership rights in the 24-3/1 Field ended in January 2010, and our rights in the
30-2 Field ended in November 2010. Our ownership in these fields was 24.5 percent and 12.3
percent, respectively.
We have a 24.5 percent interest in the offshore Panyu development, also located in the South China
Sea, which produced 11,000 net barrels of oil per day in both 2010 and 2009. We plan to expand the
scope and capacity of the existing two fields and anticipate government approval of the expansion
in the first half of 2011.
Exploration
In 2009, we entered a pilot evaluation program in a CBM play in the onshore Qinshui Basin. The
pilot program was expected to last between 12-18 months and involved drilling and monitoring the
production performance of a series of horizontal wells. In the fourth quarter of 2010, we
terminated our involvement in this program.
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 and one gas pipeline transportation system.
We have a 23.3 percent interest in Block 15-1, and our activities are focused around three
producing fields: Su Tu Den, Su Tu Den Northeast and Su Tu Vang; and two fields in development: Su
Tu Trang and Su Tu Nau. First production on the Su Tu Den Northeast Field occurred in May 2010,
averaging a net 4,000 barrels of oil
11
per day and 4 million cubic feet per day of natural gas. Net production from the three producing
fields averaged 18,000 barrels of oil per day in 2010, compared with 22,000 barrels per day in
2009.
We have a 36 percent interest in the Rang Dong Field in Block 15-2. Net production in 2010 was
6,000 barrels per day of liquids and 12 million cubic feet per day of natural gas, compared with
7,000 barrels per day and 15 million cubic feet per day in 2009.
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.
Malaysia
We own interests in three deepwater PSCs located off the eastern Malaysian state of Sabah: Block G,
Block J, and the Kebabangan Cluster. We have a 35 percent interest in Block G, 40 percent in Block
J, and 30 percent in the Kebabangan Cluster. Development of the Gumusut deepwater oil discovery in
Block J continues and includes the installation of a semi-submersible oil production platform.
First production for Gumusut is anticipated in 2013, with estimated net peak production of 29,000
barrels of liquids per day occurring in 2014.
Exploration
During 2010, we participated in the Ubah-4 appraisal well in Block G. The well was suspended in
order to evaluate development options for the area.
Bangladesh
Exploration
We were formally awarded two deepwater blocks offshore Bangladesh in 2009. PSC negotiations are
currently underway with government authorities.
Abu Dhabi
In April 2010, we decided to end participation in development of the Shah Gas Field in Abu Dhabi,
United Arab Emirates.
E&PAFRICA
During 2010, E&P operations in Africa contributed 8 percent of E&Ps worldwide liquids production
and 3 percent of natural gas production, compared with 7 percent and 2 percent, respectively, in
2009.
Nigeria
We have a 20 percent nonoperating interest in four onshore Oil Mining Leases (OMLs). In 2010, net
production from these leases was 20,000 barrels of liquids per day and 141 million cubic feet of
natural gas per day, compared with 19,000 barrels per day and 111 million cubic feet per day in
2009.
Natural gas is sourced from our proved reserves in the OMLs and provides fuel for a 480-megawatt
gas-fired power plant in Kwale, Nigeria. We have a 20 percent interest in this power plant, which
supplies electricity to Nigerias national electricity supplier. In 2010, the plant consumed 5
million net cubic feet per day of natural gas.
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 one exploration well during 2010, the Tuomo C. The well found commercial hydrocarbons
and is being incorporated into the ongoing Tuomo/Tuomo West Field development.
Libya
We hold a 16.3 percent interest in the Waha concessions in Libya, which encompass nearly 13 million
gross acres. Net oil production averaged 46,000 barrels per day in 2010, versus 45,000 barrels per
day in 2009.
12
Algeria
Our activities in Algeria are centered around three fields in Block 405a: the Menzel Lejmat North
Field (MLN), the Ourhoud Field, and the EMK Field. We operate and have a 65 percent interest in
MLN, and we have a 3.7 percent interest in Ourhoud and a 16.9 percent interest in EMK. The El Merk
Project was sanctioned in 2009 to develop the EMK Field, and engineering, procurement and
construction is ongoing. Net production from MLN and Ourhoud averaged 13,000 barrels of oil per
day in 2010, compared with 14,000 barrels per day in 2009.
E&PRUSSIA
NMNG
We have a 30 percent ownership interest with a 50 percent governance interest in OOO
Naryanmarneftegaz (NMNG), a joint venture with LUKOIL. NMNG achieved initial production of the
Yuzhno Khylchuyu (YK) Field in June 2008, and development was completed in 2010. Net production
averaged 45,000 barrels per day in 2010, compared with 46,000 barrels per day in 2009. Production from the NMNG
joint venture fields is transported via pipeline to LUKOILs terminal at Varandey Bay on the
Barents Sea and then shipped via tanker to international markets.
Polar Lights
We have a 50 percent equity interest in Polar Lights Company, an entity that owns producing fields
in the Timan-Pechora Basin in northern Russia. Net production averaged 7,000 barrels of oil per
day in 2010, compared with 9,000 barrels per day in 2009.
E&PCASPIAN
In the Caspian Sea, we have an 8.4 percent interest in the Republic of Kazakhstans North Caspian
Sea Production Sharing Agreement, 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. The initial
production phase of the contract lasts until 2041, with options to extend the agreement an
additional 20 years. A joint operating company, North Caspian Operating Company, oversees the
Kashagan development, and expects first production in late 2012.
Transportation
The Baku-Tbilisi-Ceyhan (BTC) Pipeline transports crude oil from the Caspian Region through
Azerbaijan, Georgia and Turkey for tanker loadings at the port of Ceyhan. We have a 2.5 percent
interest in BTC.
Exploration
We have a 24.5 percent interest in the N Block, located offshore Kazakhstan. In the fourth quarter
of 2010, drilling operations were completed on the Rak More well. The well encountered oil and gas
but requires further evaluation to determine commerciality. Further exploration drilling is
planned in 2011 to determine development potential of a second area of interest within the block.
In addition, appraisal drilling and development studies continue for the next phase of Kashagan and
the satellite fields of Kalamkas, Kairan and Aktote.
E&POTHER
Greenland
Exploration
We were formally awarded a license in 2010 for oil and gas exploration in Baffin Bay, offshore
Greenland. We will serve as operator, with a 61.3 percent interest in the Qamut Block. Planned
activities in 2011 include field work, environmental assessments, and seismic data acquisition and
evaluation.
Marine Well Containment Company
During 2010, we formed a non-profit organization with Exxon Mobil Corporation, Chevron
Corporation and Royal Dutch Shell plc to develop a new oil spill containment system and improve
industry spill response in the GOM. The
13
Marine Well Containment Company plans to build and deploy
a rapid response system that will be available to capture and contain oil in the event of a
potential future underwater well blowout in the deepwater GOM.
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 Freeports 1.5-billion-cubic-feet-per-day LNG receiving terminal
in Quintana, Texas. Market conditions currently favor the flow of LNG to European and Asian
markets; therefore, 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.
E&PRESERVES
We have not filed any information with any other federal authority or agency with respect to our
estimated total proved reserves at December 31, 2010. No difference exists between our estimated
total proved reserves for year-end 2009 and year-end 2008, which are shown in this filing, and
estimates of these reserves shown in a filing with another federal agency in 2010.
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, including approximately 700 billion cubic feet related to the
noncontrolling interests of consolidated subsidiaries, and 120 million barrels of crude oil in the
future. These contracts have various expiration dates through the year 2029. 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 the Oil and Gas Operations
section following the Notes to Consolidated Financial Statements, for information on the
development of proved undeveloped reserves.
MIDSTREAM
At December 31, 2010, our Midstream segment represented 2 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 fractionatedseparated
into individual components such as ethane, butane and propaneand marketed as chemical feedstock,
fuel or blendstock. Total natural gas liquids extracted in 2010, including our share of DCP
Midstream, were 193,000 barrels per day, compared with 187,000 barrels per day in 2009.
DCP Midstream markets a portion of its natural gas liquids to us and CPChem under a supply
agreement whose volume commitments remain steady until December 31, 2014.
This purchase commitment is on an if-produced, will-purchase basis and is expected to have a
relatively stable purchase pattern over the remaining term of the contract. 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, 2010, DCP Midstream owned or
operated 55 natural gas liquids extraction and 10 natural gas liquids fractionation plants, and its
gathering and
14
transmission systems included approximately 61,000 miles of pipeline. In 2010, DCP
Midstreams raw natural gas throughput averaged 6.1 billion cubic feet per day, and natural gas
liquids extraction averaged
369,000
barrels per day, compared with 6.1 billion cubic feet per day and 358,000 barrels per day in 2009.
DCP Midstreams 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 includes the following:
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A 25,000-barrel-per-day capacity natural gas liquids fractionation plant in Gallup, New
Mexico. |
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A 22.5 percent equity interest in Gulf Coast Fractionators, which owns a natural gas
liquids fractionation plant in Mont Belvieu, Texas. Our net share of capacity is 24,300
barrels per day. In October 2010, Gulf Coast Fractionators announced plans to expand the
capacity of its fractionation facility to 145,000 barrels per day. The expansion is
expected to be operational in the second quarter of 2012. |
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A 40 percent interest in a fractionation plant in Conway, Kansas. Our net share of
capacity is 43,200 barrels per day. |
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A 12.5 percent equity interest in a fractionation plant in Mont Belvieu, Texas. Our net
share of capacity is 26,000 barrels per day. |
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Marketing operations that optimize the flow of natural gas liquids and markets propane
on a wholesale basis. |
We also own a 39 percent equity interest in Phoenix Park Gas Processors Limited, which processes
natural gas in Trinidad and markets natural gas liquids throughout the Atlantic Basin. Its
facilities include a 2-billion-cubic-feet-per-day gas processing plant and a 70,000-barrel-per-day
natural gas liquids fractionator. Our share of natural gas liquids extracted averaged 9,000
barrels per day in 2010, compared with 8,000 barrels per day in 2009. Our share of fractionated
liquids averaged 18,000 barrels per day in 2010, compared with 17,000 barrels per day in 2009.
15
REFINING AND MARKETING (R&M)
At December 31, 2010, our R&M segment represented 24 percent of ConocoPhillips total assets. Our
R&M segment primarily refines crude oil and other feedstocks into petroleum products (such as
gasolines, distillates and aviation fuels); buys, sells and transports crude oil; and buys,
transports, distributes and markets petroleum products. R&M has operations in the United States,
Europe and Asia. 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.
R&MUNITED STATES
Refining
At December 31, 2010, we owned or had an interest in 12 operated refineries in the United States.
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|
Net Crude Throughput |
Refinery |
|
Location |
|
Ownership |
|
|
Capacity (MBD) |
|
|
|
|
|
East Coast Region |
|
|
|
|
|
|
|
|
|
|
|
|
Bayway |
|
Linden, New Jersey |
|
|
100.00 |
% |
|
|
238 |
Trainer |
|
Trainer, Pennsylvania |
|
|
100.00 |
|
|
|
185 |
|
|
|
|
|
|
|
|
|
|
|
|
423 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf Coast Region |
|
|
|
|
|
|
|
|
|
|
|
|
Alliance |
|
Belle Chasse, Louisiana |
|
|
100.00 |
|
|
|
247 |
Lake Charles |
|
Westlake, Louisiana |
|
|
100.00 |
|
|
|
239 |
Sweeny |
|
Old Ocean, Texas |
|
|
100.00 |
|
|
|
247 |
|
|
|
|
|
|
|
|
|
|
|
|
733 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Central Region |
|
|
|
|
|
|
|
|
|
|
|
|
Wood River |
|
Roxana, Illinois |
|
|
50.00 |
|
|
|
153 |
Borger |
|
Borger, Texas |
|
|
50.00 |
|
|
|
73 |
Ponca City |
|
Ponca City, Oklahoma |
|
|
100.00 |
|
|
|
187 |
|
|
|
|
|
|
|
|
|
|
|
|
413 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
West Coast Region |
|
|
|
|
|
|
|
|
|
|
|
|
Billings |
|
Billings, Montana |
|
|
100.00 |
|
|
|
58 |
Ferndale |
|
Ferndale, Washington |
|
|
100.00 |
|
|
|
100 |
Los Angeles |
|
Carson/Wilmington, California |
|
|
100.00 |
|
|
|
139 |
San Francisco |
|
Arroyo Grande/San Francisco, California |
|
|
100.00 |
|
|
|
120 |
|
|
|
|
|
|
|
|
|
|
|
|
417 |
|
|
|
|
|
|
|
|
|
|
|
|
1,986 |
|
16
Primary crude oil characteristics and sources of crude oil for our U.S. refineries are as follows:
|
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|
Characteristics |
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Sources |
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|
|
Medium |
|
|
Heavy |
|
|
High |
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|
|
|
United |
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|
|
|
|
South |
|
|
Europe |
|
Middle East |
|
|
|
|
Sweet |
|
|
Sour |
|
|
Sour |
|
|
TAN* |
|
|
|
|
States |
|
|
Canada |
|
|
America |
|
|
& FSU** |
|
& Africa |
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|
|
|
|
|
|
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|
|
|
|
|
|
|
|
|
|
Bayway |
|
|
· |
|
|
|
|
|
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|
|
|
|
|
|
|
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|
|
· |
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|
|
· |
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· |
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|
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|
|
|
|
|
|
Trainer |
|
|
· |
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|
|
|
|
|
|
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|
|
· |
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· |
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|
|
|
|
|
|
|
|
|
|
|
|
|
Alliance |
|
|
· |
|
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|
|
|
|
|
|
|
|
|
|
|
· |
|
|
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· |
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|
|
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
Lake Charles |
|
|
· |
|
|
· |
|
|
· |
|
|
· |
|
|
|
|
· |
|
|
|
|
|
· |
|
|
|
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|
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|
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|
|
|
|
|
|
Sweeny |
|
|
· |
|
|
|
|
|
· |
|
|
· |
|
|
|
|
|
|
|
|
|
|
· |
|
|
|
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|
· |
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wood River |
|
|
· |
|
|
· |
|
|
· |
|
|
· |
|
|
|
|
· |
|
|
· |
|
|
|
|
|
|
|
|
|
· |
|
|
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|
|
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|
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|
Borger |
|
|
|
|
|
· |
|
|
· |
|
|
|
|
|
|
|
· |
|
|
· |
|
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|
Ponca City |
|
|
· |
|
|
· |
|
|
· |
|
|
|
|
|
|
|
· |
|
|
· |
|
|
· |
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|
|
|
|
|
|
Billings |
|
|
|
|
|
· |
|
|
· |
|
|
|
|
|
|
|
· |
|
|
· |
|
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|
|
|
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|
|
Ferndale |
|
|
· |
|
|
· |
|
|
|
|
|
|
|
|
|
|
· |
|
|
· |
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|
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|
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|
|
|
|
|
|
|
|
|
Los Angeles |
|
|
|
|
|
· |
|
|
· |
|
|
· |
|
|
|
|
· |
|
|
· |
|
|
· |
|
|
|
|
|
|
· |
|
|
|
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|
|
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|
|
|
|
|
|
|
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|
|
|
|
|
|
|
San Francisco |
|
|
· |
|
|
|
|
|
· |
|
|
· |
|
|
|
|
· |
|
|
|
|
|
· |
|
|
|
|
|
|
|
|
|
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|
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|
|
*High TAN (Total Acid Number): acid content greater than or equal to 1.0 milligram of potassium hydroxide (KOH) per gram.
**Former Soviet Union.
Capacities for and yields of clean products, as well as other products produced, at our U.S.
refineries are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Clean Product Capacity (MBD) |
|
|
|
Other Refined Product Output |
|
|
|
|
|
|
|
|
|
Clean |
|
|
|
|
|
Fuel Oil & |
|
|
Natural |
|
|
|
|
|
Petro- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product Yield |
|
|
|
|
|
Other Heavy |
|
|
Gas |
|
|
Petroleum |
|
|
Chemical |
|
|
|
|
|
|
|
|
Gasolines |
|
|
Distillates |
|
|
Capability |
|
|
|
|
|
Intermediates |
|
|
Liquids |
|
|
Coke |
|
|
Feedstock |
|
|
Asphalt |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bayway |
|
|
145 |
|
|
110 |
|
|
90% |
|
|
|
|
|
· |
|
|
· |
|
|
|
|
|
· |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Trainer |
|
|
105 |
|
|
65 |
|
|
85 |
|
|
|
|
|
· |
|
|
· |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Alliance |
|
|
125 |
|
|
120 |
|
|
88 |
|
|
|
|
|
· |
|
|
· |
|
|
· |
|
|
· |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lake Charles |
|
|
90 |
|
|
110 |
|
|
69 |
|
|
|
|
|
· |
|
|
· |
|
|
·** |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sweeny |
|
|
130 |
|
|
120 |
|
|
86 |
|
|
|
|
|
· |
|
|
· |
|
|
· |
|
|
· |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wood River* |
|
|
83 |
|
|
45 |
|
|
80 |
|
|
|
|
|
· |
|
|
· |
|
|
· |
|
|
· |
|
|
|
· |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Borger* |
|
|
55 |
|
|
28 |
|
|
89 |
|
|
|
|
|
|
|
|
· |
|
|
· |
|
|
· |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ponca City |
|
|
105 |
|
|
75 |
|
|
90 |
|
|
|
|
|
· |
|
|
· |
|
|
· |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Billings |
|
|
35 |
|
|
25 |
|
|
89 |
|
|
|
|
|
|
|
|
· |
|
|
· |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ferndale |
|
|
55 |
|
|
30 |
|
|
75 |
|
|
|
|
|
· |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Los Angeles |
|
|
85 |
|
|
61 |
|
|
86 |
|
|
|
|
|
|
|
|
|
|
|
· |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
San Francisco |
|
|
59 |
|
|
59 |
|
|
87 |
|
|
|
|
|
· |
|
|
· |
|
|
· |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*Represents our proportionate share.
**Includes specialty coke.
MSLP
Merey Sweeny, L.P. (MSLP) is a limited partnership that owns a 70,000-barrel-per-day delayed coker
and related facilities at the Sweeny Refinery. MSLP processes our long residue, which is produced
from heavy sour crude oil, for a processing fee. Fuel-grade petroleum coke is produced as a
by-product and becomes the property of MSLP. Prior to August 28, 2009, MSLP was owned 50/50 by us
and PDVSA. Under the agreements that govern the relationships between the partners, certain
defaults by PDVSA with respect to supply of crude oil to the Sweeny Refinery gave us the right to
acquire PDVSAs 50 percent ownership interest in MSLP. On August 28, 2009, we exercised that
right. PDVSA has initiated arbitration with the International Chamber of Commerce challenging our
actions, and this arbitration is underway. We continue to use the equity method of accounting for
our investment in MSLP.
17
WRB
We have two 50/50 North American heavy oil business ventures with Cenovus Energy Inc.: FCCL
Partnership, a Canadian upstream general partnership, and WRB Refining LP, a U.S. downstream
limited partnership. 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. See
the Exploration and Production (E&P) section for additional information on FCCL.
WRBs processing capability of heavy Canadian crude is currently 145,000 barrels per day. We
continue to progress the coker and refinery expansion (CORE) project at the Wood River Refinery,
with operational startup anticipated in the fourth quarter of 2011. Upon completion of the CORE
Project, total processing capability of heavy Canadian or similar crudes within WRB will increase
to 275,000 barrels per day. The majority of the existing asphalt production at Wood River will be
replaced with production of upgraded products.
Excel Paralubes
We own a 50 percent interest in the Excel Paralubes joint venture, which 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.
Marketing
In the United States, as of December 31, 2010, we marketed gasoline, diesel and aviation fuel
through approximately 8,300 marketer-owned outlets in 49 states. The majority of these sites
utilize the Phillips 66, Conoco or 76 brands.
Wholesale
At December 31, 2010, our wholesale operations utilized a network of marketers operating
approximately 7,150 outlets that provided refined product offtake from our refineries. A strong
emphasis is placed on the wholesale channel of trade because of its lower capital requirements. In
addition, we held brand-licensing agreements with approximately 400 sites. 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, 2010, aviation gasoline and jet fuel were
sold through independent marketers at approximately 750 Phillips 66-branded locations in the United
States.
Retail
In June 2010, we sold our interest in CFJ Properties, a joint venture which owned and operated 110
Flying J-branded truck travel plazas.
In December 2006, we announced plans to divest approximately 830 of our U.S. company-owned outlets.
This program was completed during 2010.
Lubricants
We manufacture and sell automotive, commercial and industrial lubricants which are marketed under
the Phillips 66, Conoco, 76 and Kendall brands, as well as other private label brands.
Transportation
We distribute refined products to our customers via company-owned and common-carrier pipelines,
barges, railcars and trucks.
Pipelines and Terminals
At December 31, 2010, R&M managed approximately 24,000 miles of common-carrier crude oil, raw
natural gas liquids, natural gas and petroleum products pipeline systems in the United States,
including those partially owned or operated by affiliates. In addition, we owned or operated 44
finished product terminals, 7 liquefied petroleum gas terminals, 5 crude oil terminals and 1 coke
exporting facility.
18
Tankers
At December 31, 2010, we had 19 double-hulled crude oil tankers under charter, with capacities
ranging in size from 713,000 to 2,100,000 barrels. These tankers are primarily used to transport
feedstocks to certain of our U.S. refineries. In addition, we utilized four double-hulled product
tankers, with capacities ranging from 315,000 to 332,000 barrels, to transport our heavy and clean
products. The tankers discussed here exclude the operations of the companys subsidiary, Polar
Tankers, Inc., which are discussed in the Exploration and Production (E&P) section, 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, polypropylene,
pipeline flow improvers and anode material for high-power lithium-ion batteries. 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.
R&MINTERNATIONAL
Refining
At December 31, 2010, R&M owned or had an interest in five refineries outside the United States.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Crude Throughput |
|
|
|
|
|
|
|
|
|
|
|
Capacity (MBD) |
|
|
|
|
|
|
|
|
|
|
|
At |
|
|
Effective |
|
Refinery |
|
Location |
|
Ownership |
|
|
December 31, 2010 |
|
|
January 1, 2011 |
|
Humber |
|
N. Lincolnshire, United Kingdom |
|
|
100.00 |
% |
|
|
221 |
|
|
|
221 |
|
Whitegate |
|
Cork, Ireland |
|
|
100.00 |
|
|
|
71 |
|
|
|
71 |
|
Wilhelmshaven |
|
Wilhelmshaven, Germany |
|
|
100.00 |
|
|
|
260 |
|
|
|
- |
|
MiRO* |
|
Karlsruhe, Germany |
|
|
18.75 |
|
|
|
58 |
|
|
|
58 |
|
Melaka |
|
Melaka, Malaysia |
|
|
47.00 |
|
|
|
61 |
|
|
|
76 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
671 |
|
|
|
426 |
|
|
|
*Mineraloelraffinerie Oberrhein GmbH.
Primary crude oil characteristics and sources of crude oil for our international refineries
are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Characteristics |
|
|
Sources |
|
|
|
|
|
|
Medium |
|
|
Heavy |
|
|
High |
|
|
|
|
Europe |
|
Middle East |
|
|
|
|
Sweet |
|
|
Sour |
|
|
Sour |
|
|
TAN* |
|
|
|
|
& FSU** |
|
& Africa |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Humber |
|
|
· |
|
|
· |
|
|
|
|
|
· |
|
|
|
|
· |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Whitegate |
|
|
· |
|
|
|
|
|
|
|
|
|
|
|
|
|
· |
|
|
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· |
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MiRO |
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Melaka |
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*High TAN (Total Acid Number): acid content greater than or equal to 1.0 milligram of potassium hydroxide (KOH) per gram.
**Former Soviet Union.
19
Capacities for and yields of clean products, as well as other products produced, at our
international refineries are as follows:
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Clean Product Capacity (MBD) |
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Other Refined Product Output |
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Clean |
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Fuel Oil & |
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Product Yield |
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Other Heavy |
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Petroleum |
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Gasolines |
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Distillates |
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Capability |
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Intermediates |
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Liquids |
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Coke |
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Asphalt |
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Humber |
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84 |
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112 |
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84% |
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Whitegate |
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30 |
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65 |
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MiRO |
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25 |
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26 |
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85 |
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Melaka |
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14 |
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36 |
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85 |
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*Includes specialty coke.
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.
The project to expand the crude oil, conversion and treating unit capacity of the Melaka Refinery
was completed in the fourth quarter of 2010. As a result, effective January 1, 2011, our net share
of the refinerys crude throughput capacity will increase from 61,000 to 76,000 barrels per day,
and clean product capacity for gasoline and distillates will increase to 17,500 and 47,000 barrels
per day, respectively.
In the second quarter of 2010, due to ongoing unfavorable market conditions and consistent with our
strategy of maintaining capital discipline and reducing our downstream portfolio over time, we
canceled plans for a project to upgrade our refinery in Wilhelmshaven, Germany. We are currently
evaluating offers to sell the facility. If sufficient value is not achievable from a sale, we plan
to operate the facility as a terminal. As a result, effective January 1, 2011, we will no longer
include Wilhelmshavens capacity in our stated refining capacities or our capacity utilization
metrics.
Also consistent with our strategy of reducing our downstream portfolio, in the first quarter of
2010, we ended our participation in a new refinery project in Yanbu Industrial City, Saudi Arabia.
Marketing
At December 31, 2010, R&M had marketing operations in five European countries. Our European
marketing strategy is to sell primarily through owned, leased or joint venture retail sites using a
low-cost, high-volume approach. 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, 2010, we had approximately 1,450 marketing outlets in our European operations,
of which approximately 890 were company-owned and 360 were dealer-owned. We also held
brand-licensing agreements with approximately 200 sites. Through our joint venture operations in
Switzerland, we also have interests in 245 additional sites.
LUKOIL INVESTMENT
At year-end 2009, we had a 20 percent ownership interest in OAO LUKOIL. In July 2010, we announced
our intention to sell our entire interest. During 2010, we sold approximately 151 million shares
of LUKOIL, and as a result of these sales, our ownership interest was 2.25 percent at December 31,
2010, based on authorized and issued shares. By the end of the third quarter of 2010, our
ownership interest declined to a level at which we were no longer able to exercise significant
influence over the operating and financial policies of LUKOIL. Accordingly, at the end of the
third quarter of 2010, we stopped reporting equity earnings, proved reserves and production related
to our LUKOIL investment. In the first quarter of 2011, we sold our remaining interest.
20
See Note 6Investments, Loans and Long-Term Receivables, in the Notes to Consolidated Financial
Statements, for more information.
CHEMICALS
At December 31, 2010, our Chemicals segment represented 2 percent of ConocoPhillips total assets.
The Chemicals segment consists of our 50 percent equity investment in CPChem, a joint venture with
Chevron Corporation, headquartered in The Woodlands, Texas.
CPChems business is structured around two primary operating segments: Olefins & Polyolefins (O&P)
and Specialties, Aromatics & Styrenics (SAS). The O&P 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 SAS segment
manufactures and markets aromatics products, such as benzene, styrene, paraxylene and cyclohexane,
as well as polystyrene and styrene-butadiene copolymers. SAS also 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.
CPChems manufacturing facilities are located in Belgium, China, Colombia, Qatar, Saudi Arabia,
Singapore, South Korea and the United States.
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. The 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, an ethylene cracker that provides ethylene feedstock via pipeline to the Q-Chem II plants
was developed in Ras Laffan Industrial City, Qatar. The ethylene cracker and pipeline are owned by
Ras Laffan Olefins Company, a joint venture of Q-Chem II and Qatofin Company Limited.
Collectively, Q-Chem IIs interest in the ethylene cracker and pipeline and the polyethylene and
normal alpha olefins plants are referred to as the Q-Chem II Project. Operational startup of the
Q-Chem II Project was achieved in 2010.
Saudi Chevron Phillips Company (SCP) is a 50-percent-owned joint venture of CPChem that owns and
operates an aromatics complex at Jubail Industrial City, Saudi Arabia. Jubail Chevron Phillips
Company, another 50-percent-owned joint venture of CPChem, owns and operates an integrated styrene
facility adjacent to the SCP aromatics complex.
Saudi Polymers Company (SPCo), a 35-percent-owned joint venture company of CPChem, is constructing
an integrated petrochemicals complex at Jubail Industrial City, Saudi Arabia. SPCo will produce
ethylene, propylene, polyethylene, polypropylene, polystyrene and 1-hexene. Construction began in
January 2008, and commercial production is scheduled to begin in late 2011.
CPChem plans to build a 1-hexene plant capable of producing in excess of 200,000 metric tons per
year at its Cedar Bayou Chemical Complex in Baytown, Texas. Project planning has begun, with
startup anticipated in 2014.
EMERGING BUSINESSES
At December 31, 2010, our Emerging Businesses segment represented 1 percent of ConocoPhillips
total assets. The segment encompasses the development of new technologies and businesses outside
our normal operations. Activities within this segment are focused on power generation and new
technologies related to conventional and nonconventional hydrocarbon recovery, refining,
alternative energy, biofuels and the environment.
21
Power Generation
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, the following projects have a significant merchant component and are included in the
Emerging Businesses segment:
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The Immingham Combined Heat and Power Plant, a wholly owned 1,180-megawatt facility in
the United Kingdom, which provides steam and electricity to the Humber Refinery and steam
to a neighboring refinery, as well as merchant power into the U.K. market. |
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Sweeny Cogeneration LP, our 50 percent joint venture near the Sweeny Refinery complex. |
In December 2010, we sold a gas-fired cogeneration plant located in Orange, Texas.
Technology Development
Our Technology group focuses on developing new business opportunities designed to provide future
growth prospects for ConocoPhillips. Focus areas include advanced hydrocarbon processes, energy
efficiency technologies, new petroleum-based products, renewable fuels and carbon capture and
conversion technologies. We are progressing the technology development of second-generation
biofuels with Iowa State University, the Colorado Center for Biorefining and Biofuels and Archer
Daniels Midland. We have also established a relationship with the University of Texas Energy
Institute to collaborate on emerging technologies. Internally, we are continuing to evaluate wind,
solar and geothermal investment opportunities.
In early 2011, we announced we will partner with General Electric Capital and NRG Energy, Inc., to
form a new joint venture, Energy Technology Ventures (ETV), which will focus on development of next
generation energy technology. ETV will invest in, and offer commercial collaboration opportunities
to, venture- and growth-stage energy technology companies in the renewable power generation, smart
grid, energy efficiency, oil, natural gas, coal and nuclear energy, emission controls and biofuels
sectors.
In addition, we are equal co-venturers with General Electric Company in a Global Water
Sustainability Center in Qatar, which researches and develops water solutions for the petroleum,
petrochemical, municipal and agricultural sectors.
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, substitute natural gas (SNG), hydrogen and chemicals. This clean, efficient
technology facilitates carbon capture and storage, as well as minimizes criteria pollutant
emissions and reduces water consumption. E-Gas Technology has been utilized in commercial
applications since 1987 and is currently licensed to several third parties. We have also licensed
E-Gas to third parties in Asia and North America, and are pursuing several additional licensing
opportunities.
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.
Our E&P segment competes with numerous other companies in the industry, including state-owned
companies, 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 2009 reserves statistics,
we had the sixth-largest total of worldwide proved reserves of nongovernment-controlled companies.
We deliver our production into the worldwide commodity markets. Principal methods of competing
include geological, geophysical and engineering research and technology; experience and expertise;
economic analysis in connection with portfolio management; and operating efficient oil and gas
producing properties.
22
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 extractor 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.
Our R&M segment competes primarily in the United States, Europe and Asia. Based
on the statistics published in the December 6, 2010, issue of the Oil & Gas Journal, our R&M
segment had the largest U.S. refining capacity of 17 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 2010 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 efficient 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 CPChems branded
products.
GENERAL
At the end of 2010, we held a total of 1,398 active patents in 62 countries worldwide, including
597 active U.S. patents. During 2010, we received 34 patents in the United States and 69 foreign
patents. Our products and processes generated licensing revenues of $90 million in 2010. 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 $230 million,
$190 million and $209 million in 2010, 2009 and 2008, respectively.
Our Health, Safety and Environment (HSE) organization provides tools and support to our business
units and staff groups to help them ensure consistent health, safety and environmental excellence.
In support of the goal of zero incidents, we have implemented an HSE Excellence process, which
enables business units to measure their performance and compliance with our HSE Management System
requirements, identify gaps, and develop improvement plans. Assessments are conducted annually to
capture progress and set new targets. We are also committed to continuously improving process
safety and preventing releases of hazardous materials.
The environmental information contained in Managements Discussion and Analysis of Financial
Condition and Results of Operations on pages 57 through 60 under the captions Environmental and
Climate Change is incorporated herein by reference. It includes information on expensed and
capitalized environmental costs for 2010 and those expected for 2011 and 2012.
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 SECs Web site at
http://www.sec.gov.
23
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, bitumen, natural gas, natural gas liquids, LNG and refined products.
The factors influencing these prices are beyond our control. Lower crude oil, bitumen, natural
gas, natural gas liquids, LNG 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, bitumen and
natural gas production will decline, resulting in an adverse impact to our business.
The rate of production from upstream fields 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 experience reduced cash flows and results of operations.
Any material change in the factors and assumptions underlying our estimates of crude oil, bitumen
and natural gas reserves could impair the quantity and value of those reserves.
Our proved reserve information included in this annual report has been derived from engineering
estimates prepared or reviewed by our personnel. Any significant future price changes could 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 process that involves estimating volumes to be recovered from underground accumulations of
crude oil, bitumen 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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The discharge of pollutants into the environment. |
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Emissions into the atmosphere (such as nitrogen oxides, sulfur dioxide and mercury
emissions, and greenhouse gas emissions as they are, or may become, regulated). |
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The handling, use, storage, transportation, disposal and clean up of hazardous materials
and hazardous and nonhazardous wastes. |
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The dismantlement, abandonment and restoration of our properties and facilities at the
end of their useful lives. |
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Exploration and production activities in environmentally sensitive areas, such as
offshore environments, arctic fields, oil sands reservoirs and shale gas plays. |
24
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.
Although our business operations are designed and operated to accommodate expected climatic
conditions, to the extent there are significant changes in the Earths climate, such as more severe
or frequent weather conditions in the markets we serve or the areas where our assets reside, we
could incur increased expenses, our operations could be materially impacted, and demand for our
products could fall.
In addition, in response to the Deepwater Horizon incident, the United States, as well as other
countries where we do business, may make changes to their laws or regulations governing offshore
operations that could have a material adverse effect on our business.
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 may continue to do so in the future.
Local political and economic factors in international markets could have a material adverse effect
on us. Approximately 67 percent of our hydrocarbon production was derived from production outside
the United States in both 2009 and 2010, and 56 percent of our proved reserves, as of December 31,
2010, 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,
bitumen, natural gas, natural gas liquids or refined product pricing and taxation, other political,
economic or diplomatic developments, changing political conditions and international monetary
fluctuations.
Changes in governmental regulations may impose price controls and limitations on production of
crude oil, bitumen 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, bitumen 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.
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 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 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.
25
We do not insure against all potential losses; and therefore, we could be harmed by unexpected
liabilities and increased costs.
We maintain insurance against many, but not all, potential losses or liabilities arising from
operating risks. As such, our insurance coverage may not be sufficient to fully cover us against
potential losses arising from such risks. Uninsured losses and liabilities arising from operating
risks could reduce the funds available to us for capital, exploration and investment spending and
could have a material adverse effect on our business, financial condition, results of operations
and cash flows.
Our operations present hazards and risks that 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 exploration, production, 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 2010, as well as matters previously reported in our 2009
Form 10-K and our first-, second- and third-quarter 2010 Form 10-Qs that were not resolved prior to
the fourth quarter of 2010. 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 SEC 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 decrees
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 decrees or other reports required by permits or regulations, we occasionally report
matters that could be subject to a request for stipulated penalties. If a specific request for
stipulated penalties meeting the reporting threshold set forth in SEC 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
There are no new matters to report.
Matters Previously Reported
In October 2007, we received a Complaint from the 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.
In 2009, ConocoPhillips notified the EPA and the U.S. Department of Justice (DOJ) that it had
self-identified certain compliance issues related to Benzene Waste Operations National Emission
Standard for Hazardous Air Pollutants requirements at its Trainer, Pennsylvania, and Borger, Texas,
facilities. On January 6, 2010, the DOJ provided its initial penalty demand for this matter as
part of our confidential settlement negotiations.
26
ConocoPhillips has reached an agreement with the EPA and DOJ regarding an appropriate penalty
amount, which will be reflected in the third amendment to the consent decree in Civil Action No.
H-05-258 (the agreed-upon penalty amount remains confidential until that time).
On May 19, 2010, the Lake Charles Louisiana Refinery received a Consolidated Compliance Order and
Notice of Potential Penalty from the Louisiana Department of Environmental Quality (LDEQ) alleging
various violations of applicable air emission regulations, as well as certain provisions of the
consent decree in Civil Action No. H-01-4430. ConocoPhillips will work with the LDEQ to resolve
this matter.
On September 23, 2010, the Los Angeles County Fire Department Health and Hazardous Materials
Division (HHMD) issued a proposed penalty of $127,000 to ConocoPhillips. The penalty pertains to
alleged violations of hazardous waste regulations at the Los Angeles Refinery noted by HHMD during
its refinery compliance inspections in November and December 2009. ConocoPhillips resolved this
matter with a settlement payment of $102,880 to HHMD.
On January 22, 2010, the Bay Area Air Quality Management District (BAAQMD) issued a penalty demand
to resolve 16 Notices of Violation issued in 2008 and 2009 that allege violations of air pollution
control regulations and/or facility permit conditions at the Rodeo facility in San Francisco,
California. ConocoPhillips resolved this matter with a settlement payment of $125,050 to BAAQMD.
In October 2003, the District Attorneys 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 Attorneys 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 continue to
contest this lawsuit.
27
EXECUTIVE OFFICERS OF THE REGISTRANT
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Name |
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Position Held |
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Age* |
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John A. Carrig |
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President |
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59 |
Willie C. W. Chiang |
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Senior Vice President, Refining,
Marketing, Transportation and Commercial |
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50 |
Greg C. Garland |
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Senior Vice President, Exploration and ProductionAmericas |
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53 |
Alan J. Hirshberg |
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Senior Vice President, Planning and Strategy |
|
49 |
Janet L. Kelly |
|
Senior Vice President, Legal, General Counsel and Corporate Secretary |
|
53 |
Ryan M. Lance |
|
Senior Vice President, Exploration and ProductionInternational |
|
48 |
James J. Mulva |
|
Chairman of the Board of Directors and Chief Executive Officer |
|
64 |
Glenda M. Schwarz |
|
Vice President and Controller |
|
45 |
Jeff W. Sheets |
|
Senior Vice President, Finance and Chief Financial Officer |
|
53 |
There are no family relationships among any of 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 the 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 11, 2011.
Set forth below is information about the executive officers.
John A. Carrig has served as President since October 2010, having previously served as President
and Chief Operating Officer from 2008 to October 2010. Prior to that, he served as Executive Vice
President, Finance and Chief Financial Officer since the merger of Conoco and Phillips in 2002 (the
merger).
Willie
C. W. Chiang was appointed Senior Vice President, Refining, Marketing, Transportation and
Commercial in October 2010. He previously served as Senior Vice President, Refining, Marketing and
Transportation from 2008 to October 2010; Senior Vice President, Commercial from 2007 to 2008; and
President, Americas Supply & Trading, Commercial, from 2005 through 2007.
Greg C. Garland was appointed Senior Vice President, Exploration and ProductionAmericas in
October 2010, having previously served as President and Chief Executive Officer of CPChem since
2008. Prior to that, he served as Senior Vice President, Planning and Specialty Products at CPChem
from 2000 to 2008.
Alan J. Hirshberg was appointed Senior Vice President, Planning and Strategy in October 2010.
Prior to that, he was employed by Exxon Mobil Corporation and served as Vice President, Worldwide
Deepwater and Africa Projects since 2009; Vice President, Worldwide Deepwater Projects from 2008 to
2009; Vice President, Established Areas Projects from 2006 to 2008; and Vice President, Operated by
Others Projects in 2006.
Janet L. Kelly was appointed Senior Vice President, Legal, General Counsel and Corporate Secretary
in 2007, having previously served as Deputy General Counsel since 2006.
Ryan M. Lance was appointed Senior Vice President, Exploration and ProductionInternational, in
May 2009. Prior to that, he served as President, Exploration and ProductionAsia, Africa, Middle
East and Russia/Caspian since April 2009; President, Exploration and Production Europe, Asia,
Africa and the Middle East from 2007 to 2009; Senior Vice President, Technology in 2007; and Senior
Vice President, Technology and Major Projects since 2006.
28
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 2004. Prior to that, he served as President and Chief Executive Officer
since the merger.
Glenda M. Schwarz was appointed Vice President and Controller in 2009. She previously served as
General Auditor and Chief Ethics Officer from 2008 to 2009, having previously served as General
Manager, Downstream Finance and Performance Analysis since 2005.
Jeff W. Sheets was appointed Senior Vice President, Finance and Chief Financial Officer in October
2010. Prior to that, he served as Senior Vice President, Planning and Strategy since 2008, having
previously served as Vice President and Treasurer since the merger.
29
PART II
Item 5. |
|
MARKET FOR REGISTRANTS COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF
EQUITY SECURITIES |
Quarterly Common Stock Prices and Cash Dividends Per Share
ConocoPhillips common stock is traded on the New York Stock Exchange, under the symbol COP.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock Price |
|
|
|
|
|
|
High |
|
|
Low |
|
|
Dividends |
|
|
|
|
|
|
|
|
2010 |
|
|
|
|
|
|
|
|
|
|
|
|
First |
|
$ |
53.80 |
|
|
|
46.63 |
|
|
|
.50 |
|
Second |
|
|
60.53 |
|
|
|
48.51 |
|
|
|
.55 |
|
Third |
|
|
58.03 |
|
|
|
48.06 |
|
|
|
.55 |
|
Fourth |
|
|
68.58 |
|
|
|
56.80 |
|
|
|
.55 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
|
|
|
|
|
|
|
|
|
|
First |
|
$ |
57.44 |
|
|
|
34.12 |
|
|
|
.47 |
|
Second |
|
|
48.71 |
|
|
|
37.52 |
|
|
|
.47 |
|
Third |
|
|
47.30 |
|
|
|
38.62 |
|
|
|
.47 |
|
Fourth |
|
|
54.13 |
|
|
|
44.88 |
|
|
|
.50 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Closing Stock Price at December 31, 2010 |
|
|
|
|
|
|
|
|
|
$ |
68.10 |
|
Closing Stock Price at January 31, 2011 |
|
|
|
|
|
|
|
|
|
$ |
71.46 |
|
Number of Stockholders of Record at January 31, 2011* |
|
|
|
|
|
|
|
|
|
|
58,644 |
|
|
|
*In determining the number of stockholders, we consider clearing agencies and security position
listings as one stockholder for each agency or listing.
Issuer Purchases of Equity Securities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars |
|
|
|
|
|
|
|
|
|
|
|
Total Number of |
|
|
Approximate Dollar |
|
|
|
|
|
|
|
|
|
|
|
Shares Purchased |
|
|
Value of Shares |
|
|
|
|
|
|
Average |
|
|
as Part of Publicly |
|
|
that May Yet Be |
|
|
|
Total Number of |
|
|
Price Paid |
|
|
Announced Plans |
|
|
Purchased Under the |
|
Period |
|
Shares Purchased |
* |
|
Per Share |
|
|
or Programs |
** |
|
Plans or Programs |
|
|
|
|
|
October 1-31, 2010 |
|
|
17,776,116 |
|
|
|
$ 59.62 |
|
|
|
17,540,398 |
|
|
|
$ 2,696 |
|
November 1-30, 2010 |
|
|
11,464,464 |
|
|
|
60.93 |
|
|
|
11,458,408 |
|
|
|
1,998 |
|
December 1-31, 2010 |
|
|
13,266,256 |
|
|
|
65.25 |
|
|
|
13,249,000 |
|
|
|
1,134 |
|
|
|
Total |
|
|
42,506,836 |
|
|
|
$ 61.73 |
|
|
|
42,247,806 |
|
|
|
|
|
|
|
|
|
* |
Includes the repurchase of common shares from company employees in connection with the
companys broad-based employee incentive plans. |
** |
On March 24, 2010, we announced plans to repurchase up to $5 billion of our common stock through
2011. On February 11, 2011, we announced plans to repurchase up to $10 billion of our common
stock over the subsequent two years. Acquisitions for the share repurchase program are made
at managements discretion, at prevailing prices, subject to market conditions and other
factors. Repurchases may be increased, decreased or discontinued at any time without prior
notice. Shares of stock repurchased under the plan are held as treasury shares. |
30
Item 6. SELECTED FINANCIAL DATA
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars Except Per Share Amounts |
|
|
|
2010 |
|
|
2009 |
* |
|
2008 |
* |
|
2007 |
* |
|
2006 |
* |
|
|
|
|
Sales and other operating revenues |
|
$ |
189,441 |
|
|
|
149,341 |
|
|
|
240,842 |
|
|
|
187,437 |
|
|
|
183,650 |
|
Net income (loss) |
|
|
11,417 |
|
|
|
4,492 |
|
|
|
(16,279 |
) |
|
|
11,545 |
|
|
|
15,410 |
|
Net income (loss) attributable to ConocoPhillips |
|
|
11,358 |
|
|
|
4,414 |
|
|
|
(16,349 |
) |
|
|
11,458 |
|
|
|
15,334 |
|
Per common share |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
7.68 |
|
|
|
2.96 |
|
|
|
(10.73 |
) |
|
|
7.06 |
|
|
|
9.67 |
|
Diluted |
|
|
7.62 |
|
|
|
2.94 |
|
|
|
(10.73 |
) |
|
|
6.96 |
|
|
|
9.53 |
|
Total assets |
|
|
156,314 |
|
|
|
152,138 |
|
|
|
142,865 |
|
|
|
177,094 |
|
|
|
164,557 |
|
Long-term debt |
|
|
22,656 |
|
|
|
26,925 |
|
|
|
27,085 |
|
|
|
20,289 |
|
|
|
23,091 |
|
Joint venture acquisition obligationlong-term |
|
|
4,314 |
|
|
|
5,009 |
|
|
|
5,669 |
|
|
|
6,294 |
|
|
|
- |
|
Cash dividends declared per common share |
|
|
2.15 |
|
|
|
1.91 |
|
|
|
1.88 |
|
|
|
1.64 |
|
|
|
1.44 |
|
|
|
*Recast to reflect a change in accounting principle. See Note 2Changes in Accounting Principles, for more information.
Many factors can impact the comparability of this information, such as:
|
|
|
The financial data for 2010 includes the impact of $5,803 million before-tax ($4,583 million
after-tax) related to gains on asset dispositions and LUKOIL share sales. |
|
|
|
|
The financial data for 2008 includes the impact of impairments related to goodwill and
to our LUKOIL investment that together amount to $32,939 million before- and after-tax. |
|
|
|
|
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. |
See Managements Discussion and Analysis of Financial Condition and Results of Operations and the
Notes to Consolidated Financial Statements for a discussion of factors that will enhance an
understanding of this data.
31
|
|
|
Item 7. |
|
MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS |
February 23, 2011
Managements Discussion and Analysis is the companys 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 companys
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
anticipate, estimate, believe, budget, continue, could, intend, may, plan,
potential, predict, seek, should, will, would, expect, objective, projection,
forecast, goal, guidance, outlook, effort, target 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 companys
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 65.
The terms earnings and loss as used in Managements Discussion and Analysis refer to net income
(loss) attributable to ConocoPhillips.
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 29,700
employees worldwide, and at year-end 2010 had assets of $156 billion. Our stock is listed on the
New York Stock Exchange under the symbol COP.
Our business is organized into six operating segments:
|
|
|
Exploration and Production (E&P)This segment primarily explores for, produces,
transports and markets crude oil, bitumen, natural gas, liquefied natural gas (LNG) and
natural gas liquids on a worldwide basis. |
|
|
|
|
MidstreamThis segment gathers, processes and markets natural gas produced by
ConocoPhillips and others, and fractionates and markets natural gas liquids, predominantly
in the United States and Trinidad. The Midstream segment primarily consists of our 50
percent equity investment in DCP Midstream, LLC. |
|
|
|
|
Refining and Marketing (R&M)This segment purchases, refines, markets and transports
crude oil and petroleum products, mainly in the United States, Europe and Asia. |
|
|
|
|
LUKOIL InvestmentThis segment consists of our investment in the ordinary shares of OAO
LUKOIL, an international, integrated oil and gas company headquartered in Russia. At
December 31, 2010, our ownership interest was 2.25 percent based on issued shares. See
Note 6Investments, Loans and Long-Term Receivables, in the Notes to Consolidated
Financial Statements, for information on sales of LUKOIL shares. |
|
|
|
|
ChemicalsThis segment manufactures and markets petrochemicals and plastics on a
worldwide basis. The Chemicals segment consists of our 50 percent equity investment in
Chevron Phillips Chemical Company LLC (CPChem). |
|
|
|
|
Emerging BusinessesThis segment represents our investment in new technologies or
businesses outside our normal scope of operations. |
32
In 2010, as the global economy continued to recover from the recession, the business environment
for certain parts of the energy industry also recovered. Oil prices continued to increase in 2010,
reflecting strong oil demand growth, especially in China, and an improved economic outlook for the
United States. U.S. natural gas prices, however, remained under pressure during 2010, despite a
colder-than-normal winter and hotter-than-normal summer. U.S. natural gas production continues to
increase at a faster rate than the demand recovery from the economic crisis, primarily as a result
of increased production from shale plays. Storage levels are below 2009 levels, but remain
historically high. We expect these factors will continue to moderate natural gas prices, resulting
in limited U.S. LNG imports in the near- to mid-term, and potentially impacting the timing of
commercialization of our Alaska North Slope and Canadian Arctic gas resources.
In late 2009, we announced several strategic initiatives designed to improve our financial position
and increase returns on capital. We announced plans to raise $10 billion from asset dispositions
through the end of 2011, reduce our debt and increase shareholder distributions. As of year-end
2010, we have generated approximately $7 billion from asset dispositions, the proceeds of which
were primarily targeted toward debt reduction. This accelerated the return to our target
debt-to-capital ratio of 20 to 25 percent. In addition, we
increased the amount of our quarterly dividend rate by 10 percent, and we paid dividends on our common stock of
$3.2 billion for the full year. We also announced plans to sell our entire interest in LUKOIL, and
our Board of Directors authorized the purchase of up to $5 billion of our common stock through
2011. As of year-end 2010, we had sold approximately 90 percent of our interest in LUKOIL, which
generated cash proceeds of approximately $8 billion, while we repurchased approximately $4 billion
of our common stock. In February 2011, our Board authorized the additional purchase of up to $10
billion of our common stock over the next two years.
Our total capital program in 2011 is expected to be $13.5 billion, a $2.8 billion increase from
$10.7 billion in 2010. We also expect 2011 production to be approximately 1.7 million barrels of
oil equivalent per day, excluding the impact of any additional asset sales.
Crude oil, bitumen, natural gas and LNG 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. These prices and margins can be subject to extreme volatility. However, from a
competitive perspective, there are other important factors we must manage well to be successful,
including:
|
|
|
Operating our producing properties and refining and marketing operations safely,
consistently and in an environmentally sound manner. Safety is our first priority, and
we are committed to protecting the health and safety of everyone who has a role in our
operations and the communities in which we operate. Optimizing utilization rates at our
refineries and minimizing downtime in producing fields enable us to capture the value
available in the market in terms of prices and margins. During 2010, our worldwide
refining capacity utilization rate was 81 percent, compared with 84 percent in 2009. The
lower rate primarily reflects run reductions at Wilhelmshaven in response to market
conditions, partially offset by lower turnaround activity. Excluding Wilhelmshaven, the
worldwide refining capacity utilization rate was 90 percent in 2010, compared with 88
percent in 2009. |
|
|
|
|
There has been heightened public focus on the safety of the oil and gas industry, as a
result of the Deepwater Horizon incident in the Gulf of Mexico (GOM), which occurred in
April 2010. Safety and environmental stewardship, including the operating integrity of our
assets, remain our highest priorities. Therefore, in order to improve industry spill
response, in 2010 we formed a non-profit organization, the Marine Well Containment Company
LLC (MWCC), with Exxon Mobil Corporation, Chevron Corporation and Royal Dutch Shell plc to
develop a new oil spill containment system. MWCC plans to build and deploy a rapid response
system that will be available to capture and contain oil in the event of a potential future
underwater well blowout in the deepwater GOM. |
33
|
|
|
Adding to our proved reserve base. We primarily add to our proved reserve base in
three ways: |
|
o |
|
Successful exploration and development of new fields. |
|
|
o |
|
Acquisition of existing fields. |
|
|
o |
|
Application of new technologies and processes to improve recovery from existing fields. |
|
|
|
Through a combination of the methods listed above, we have been successful in the past in
maintaining or adding to our production and proved reserve base, and we anticipate being
able to do so in the future. In the five years ended December 31, 2010, our reserve
replacement was 111 percent, excluding LUKOIL. Over this period we added reserves through
acquisitions and project developments, partially offset by the impact of asset
expropriations in Venezuela and Ecuador. |
|
|
|
|
Access to additional resources has become increasingly difficult as direct investment is
prohibited in some nations, while fiscal and other terms in other countries can make
projects uneconomic or unattractive. In addition, political instability, competition from
national oil companies, and lack of access to high-potential areas due to environmental or
other regulation may negatively impact our ability to increase our reserve base. As such,
the timing and level at which we add to our reserve base may, or may not, allow us to
replace our production over subsequent years. |
|
|
|
|
Controlling costs and expenses. Since we cannot control the prices of the
commodity products we sell, controlling operating and overhead costs, within the context of
our commitment to safety and environmental stewardship, is a high priority. We monitor
these costs using various methodologies that are reported to senior management monthly, on
both an absolute-dollar basis and a per-unit basis. Because managing operating and
overhead costs is critical to maintaining competitive positions in our industries, cost
control is a component of our variable compensation programs. Operating and overhead costs
increased by 4 percent in 2010, compared with 2009, primarily as a result of market
conditions and higher transportation costs. |
|
|
|
|
Selecting the appropriate projects in which to invest our capital dollars. We
participate in capital-intensive industries. As a result, we must often invest significant
capital dollars to explore for new oil and gas fields, develop newly discovered fields,
maintain existing fields, construct pipelines and LNG facilities, or continue to maintain
and improve our refinery complexes. We invest in projects that are expected to provide an
adequate financial return on invested dollars. However, there are often long lead times
from the time we make an investment to the time the investment is operational and begins
generating financial returns. |
|
|
|
|
Our total capital program in 2010 was $10.7 billion, which included $9.8 billion of capital
expenditures and investments. Our 2011 capital program is expected to be approximately
$13.5 billion, which includes $12.8 billion of capital expenditures and investments. The
2011 budget is consistent with our plan to improve returns through increased capital
discipline, while still funding existing projects and enabling us to preserve flexibility to
develop major projects in the future. |
|
|
|
|
Managing our asset portfolio. We continually evaluate our assets to determine
whether they fit our strategic plans or should be sold or otherwise disposed. In 2009, we
sold a majority of our U.S. retail marketing assets and announced our intention to raise
$10 billion from asset dispositions through the end of 2011. In 2010, we completed the
U.S. retail marketing disposition program. We also sold our 9.03 percent interest in the
Syncrude oil sands mining operation; our 50 percent interest in CFJ Properties, a joint
venture which owned and operated Flying J-branded truck and travel plazas; and several E&P
properties located in the Lower 48 and western Canada. As part of a separate program, in
2010, we announced our intention to sell our entire interest in LUKOIL. As of year-end
2010, we sold approximately 90 percent of our interest in LUKOIL. We disposed of our
remaining shares in the first quarter of 2011. |
34
|
|
|
Developing and retaining a talented work force. We strive to attract, train,
develop and retain individuals with the knowledge and skills to implement our business
strategy and who support our values and ethics. Throughout the company, we focus on the
continued learning, development and technical training of our employees. Professional new
hires participate in structured development programs designed to accelerate their technical
and functional skills. |
Our key performance indicators are shown in the statistical tables provided at the beginning of the
operating segment sections that follow. These include commodity prices, production and refining
capacity utilization.
Other significant factors that can affect our profitability include:
|
|
|
Impairments. As mentioned above, we participate in capital-intensive
industries. At times, our investments become impaired when, for example, our reserve
estimates are revised downward, commodity prices or refining margins decline significantly
for long periods of time, or a decision to dispose of an asset leads to a write-down to its
fair market value. We may also invest large amounts of money in exploration which, if
exploratory drilling proves unsuccessful, could lead to a material impairment of leasehold
values. Before-tax impairments in 2010 totaled $2.4 billion and primarily related to the
$1.5 billion property impairment of our refinery in Wilhelmshaven, Germany (WRG), and a
$0.6 billion impairment of our equity investment in Naraynmarneftegaz (NMNG). Before-tax
impairments in 2009 totaled $0.8 billion and primarily related to certain natural gas
properties in western Canada and our equity investment in NMNG. |
|
|
|
|
Goodwill. We had $3.6 billion of goodwill on our balance sheet at year-end 2010
and 2009. In 2008, we recorded a $25.4 billion complete impairment of our E&P segment
goodwill, primarily as a function of decreased year-end commodity prices and the decline in
our market capitalization. Deterioration of market conditions in the future could lead to
other goodwill impairments that may have a substantial negative, though noncash, effect on
our profitability. |
|
|
|
|
Effective tax rate. Our operations are located in countries with different tax
rates and fiscal structures. Accordingly, even in a stable commodity price and
fiscal/regulatory environment, our overall effective tax rate can vary significantly
between periods based on the mix of pretax earnings within our global operations.
|
|
|
|
|
Fiscal and regulatory environment. Our operations, primarily in E&P, can be
affected by changing economic, regulatory and political environments in the various
countries in which we operate, including the United States. These changes have generally
negatively impacted our results of operations, and further changes to government fiscal
take could have a negative impact on future operations. Our assets in Venezuela and
Ecuador were expropriated in 2007 and 2009, respectively. In Canada, the Alberta
provincial government changed the royalty structure in 2009 to tie a component of the new
rate to prevailing prices. Our management carefully considers these events when evaluating
projects or determining the level of activity in such countries. |
35
Segment Analysis
The E&P segments results are most closely linked to crude oil and natural gas prices. These are
commodity products, the prices of which are subject to factors external to our company and over
which we have no control. Industry crude oil prices for West Texas Intermediate (WTI) were higher
in 2010, compared with 2009, averaging $79.39 per barrel in 2010, an increase of 29 percent.
Uncertainty about economic growth in developed countries, especially in the United States, and
concerns about the debt crisis in Europe were more than offset by increased demand from China and
other developing countries. Industry natural gas prices at Henry Hub increased 10 percent during
2010 to an average price of $4.39 per million British thermal units, primarily as a result of
weather-related events. An increase in demand was offset by higher natural gas production levels,
and as a result, natural gas storage levels remain high and have adversely impacted Henry Hub
prices.
The Midstream segments results are most closely linked to natural gas liquids prices. The most
important factor affecting the profitability of this segment is the results from our 50 percent
equity investment in DCP Midstream. DCP Midstreams natural gas liquids prices increased 39
percent in 2010.
Refining margins, refinery capacity utilization and cost control primarily drive the R&M segments
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. Global refining margins improved during 2010, compared with 2009. The U.S.
benchmark 3:2:1 crack spread increased 9 percent in 2010, while the N.W. Europe benchmark increased
16 percent. Demand for refined products improved globally in 2010, driven by the improved economic
environment, particularly in the developing nations. In addition, a wider differential in prices
for high-quality crude oil relative to lower-quality crude oil improved margins for refineries
configured to capitalize on the ability to process lower-quality crudes.
The LUKOIL Investment segment consists of our investment in the ordinary shares of LUKOIL. At
year-end 2009, we had a 20 percent ownership interest in LUKOIL based on authorized and issued
shares. At the end of the third quarter of 2010, as a result of our plan to divest of our entire
interest in LUKOIL, our ownership interest declined to a level at which we were no longer able to
exercise significant influence over the operating and financial policies of LUKOIL. Accordingly,
at the end of the third quarter of 2010, we stopped recording equity earnings from LUKOIL.
Starting in the fourth quarter of 2010, earnings from the LUKOIL Investment segment primarily
reflect the realized gain on share sales. We disposed of our remaining interest in LUKOIL in the
first quarter of 2011.
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, refining, alternative energy, biofuels and the environment.
Some of these technologies have the potential to become important drivers of profitability in
future years.
36
RESULTS OF OPERATIONS
Consolidated Results
A summary of the companys net income (loss) attributable to ConocoPhillips by business segment
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars |
|
Years Ended December 31 |
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration and Production (E&P) |
|
$ |
9,198 |
|
|
|
3,604 |
|
|
|
(13,479 |
) |
Midstream |
|
|
306 |
|
|
|
313 |
|
|
|
541 |
|
Refining and Marketing (R&M) |
|
|
192 |
|
|
|
37 |
|
|
|
2,322 |
|
LUKOIL Investment* |
|
|
2,503 |
|
|
|
1,219 |
|
|
|
(4,839 |
) |
Chemicals |
|
|
498 |
|
|
|
248 |
|
|
|
110 |
|
Emerging Businesses |
|
|
(59 |
) |
|
|
3 |
|
|
|
30 |
|
Corporate and Other |
|
|
(1,280 |
) |
|
|
(1,010 |
) |
|
|
(1,034 |
) |
|
|
Net income (loss) attributable to ConocoPhillips |
|
$ |
11,358 |
|
|
|
4,414 |
|
|
|
(16,349 |
) |
|
|
*2009 and 2008 recast to reflect a change in accounting principle. See Note 2Changes in Accounting Principles, for more information.
2010 vs. 2009
The improved results in 2010 were primarily the result of:
|
|
|
Higher prices for crude oil, natural gas, natural gas liquids and liquefied natural gas
(LNG) in our E&P segment. Commodity price benefits were somewhat offset by increased
production taxes. |
|
|
|
|
Gains of $4,583 million after-tax from asset dispositions and LUKOIL share sales. |
|
|
|
|
Improved results from our domestic R&M operations, reflecting higher refining margins. |
These items were partially offset by:
|
|
|
Impairments totaling $1,928 million after-tax. |
|
|
|
|
Lower production volumes from our E&P segment. |
2009 vs. 2008
The improved results in 2009 were primarily the result of:
|
|
|
The absence of a $25,443 million before- and after-tax impairment of all E&P segment
goodwill in 2008. |
|
|
|
|
The absence of a $7,496 million before- and after-tax impairment of our LUKOIL
investment in 2008. |
|
|
|
|
Lower production taxes. |
|
|
|
|
Reduced operating and overhead expenses. |
These items were partially offset by:
|
|
|
Lower crude oil, natural gas and natural gas liquids prices, which impacted our E&P,
Midstream and LUKOIL Investment segments. |
|
|
|
|
Lower refining margins in our R&M segment. |
37
Statement of Operations Analysis
2010 vs. 2009
Sales and other operating revenues increased 27 percent in 2010, while purchased crude
oil, natural gas and products increased 33 percent. These increases were primarily due to
higher prices for petroleum products, crude oil, natural gas, natural gas liquids and LNG.
Equity in earnings of affiliates increased 24 percent in 2010. The increase primarily
resulted from:
|
|
|
Improved earnings from CPChem primarily due to higher margins in the olefins and
polyolefins business line. |
|
|
|
|
Improved earnings from FCCL Partnership due to higher commodity prices and volumes. |
|
|
|
|
Improved earnings from Merey Sweeny, L.P. (MSLP) as a result of improved margins and
volumes. |
These increases were partially offset by a $645 million impairment of our equity investment in
NMNG.
Gain on dispositions increased $5,643 million in 2010. The increase primarily reflects the
$2,878 million gain realized from the June 2010 sale of our 9.03 percent interest in the Syncrude
oil sands mining operation; the $1,749 million gain on the divestiture of our LUKOIL shares; gains
on the disposition of certain E&P assets located in the Lower 48 and Canada; and the gain on sale
of our 50 percent interest in CFJ Properties. For additional information, see Note 5Assets Held
for Sale and Note 6Investment, Loans and Long-Term Receivables, in the Notes to Consolidated
Financial Statements.
Impairments increased $1,245 million in 2010, primarily as a result of the second quarter
impairment of WRG. For additional information, see Note 10Impairments, in the Notes to
Consolidated Financial Statements.
Taxes other than income taxes increased 8 percent during 2010, primarily due to higher
production taxes as a result of higher crude oil prices and higher excise taxes on petroleum
product sales.
Interest and debt expense decreased 8 percent during 2010, primarily due to lower debt
levels.
See Note 20Income Taxes, in the Notes to Consolidated Financial Statements, for information
regarding our income tax expense and effective tax rate.
2009 vs. 2008
Sales and other operating revenues decreased 38 percent in 2009, while purchased crude
oil, natural gas and products decreased 39 percent. These decreases were mainly the result of
significantly lower prices for petroleum products, crude oil, natural gas and natural gas liquids.
Equity in earnings of affiliates decreased 49 percent in 2009, primarily due to reduced
earnings from LUKOIL; DCP Midstream; MSLP; Malaysian Refining Company Sdn. Bhd.; and Excel
Paralubes, which were partially offset by higher earnings from CPChem. The decreases were mainly
the result of lower commodity prices and refining margins.
Gain on dispositions decreased 82 percent during 2009. The decrease was primarily due to
2008 gains related to asset dispositions in our E&P and R&M segments.
Production
and operating expenses decreased 13 percent in 2009, as a result of lower
utilities costs, favorable foreign currency exchange impacts, and our cost reduction efforts.
Selling, general and administrative expense decreased 18 percent in 2009, primarily due to
disposition of U.S. and international marketing assets.
38
Impairments decreased from $34,625 million in 2008 to $535 million in 2009, primarily
reflecting the 2008 goodwill and LUKOIL impairments. Other impairments decreased $1,151 million
during 2009. For additional information, see Note 6Investments, Loans and Long-Term Receivables
and Note 9Goodwill and Intangibles, in the Notes to Consolidated Financial Statements.
Taxes other than income taxes decreased 25 percent in 2009, primarily due to lower
production taxes resulting from lower crude oil prices, as well as reduced excise taxes on
petroleum product sales.
Interest and debt expense increased 38 percent in 2009, as a result of a higher average
debt level, partially offset by lower interest rates. Interest expense also increased as a result
of lower capitalized interest.
See Note 20Income Taxes, in the Notes to Consolidated Financial Statements, for information
regarding our income tax expense and effective tax rate.
39
Segment Results
E&P
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
|
Millions of Dollars |
|
Net Income (Loss) Attributable to ConocoPhillips |
|
|
|
|
|
|
|
|
|
|
|
|
Alaska |
|
$ |
1,735 |
|
|
|
1,540 |
|
|
|
2,315 |
|
Lower 48 |
|
|
1,033 |
|
|
|
(37 |
) |
|
|
2,673 |
|
|
|
United States |
|
|
2,768 |
|
|
|
1,503 |
|
|
|
4,988 |
|
International |
|
|
6,430 |
|
|
|
2,101 |
|
|
|
6,976 |
|
Goodwill impairment |
|
|
- |
|
|
|
- |
|
|
|
(25,443 |
) |
|
|
|
|
$ |
9,198 |
|
|
|
3,604 |
|
|
|
(13,479 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dollars Per Unit
|
|
|
|
|
|
Average Sales Prices |
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil and natural gas liquids (per barrel) |
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
$ |
69.73 |
|
|
|
53.21 |
|
|
|
89.38 |
|
International |
|
|
74.95 |
|
|
|
57.40 |
|
|
|
89.32 |
|
Total consolidated operations |
|
|
72.63 |
|
|
|
55.47 |
|
|
|
89.35 |
|
Equity affiliates |
|
|
74.81 |
|
|
|
58.23 |
|
|
|
71.15 |
|
Total E&P |
|
|
72.77 |
|
|
|
55.63 |
|
|
|
88.91 |
|
Synthetic oil (per barrel) |
|
|
|
|
|
|
|
|
|
|
|
|
International |
|
|
77.56 |
|
|
|
62.01 |
|
|
|
103.31 |
|
Bitumen (per barrel) |
|
|
|
|
|
|
|
|
|
|
|
|
International |
|
|
51.10 |
|
|
|
39.67 |
|
|
|
46.85 |
|
Equity affiliates |
|
|
53.43 |
|
|
|
45.69 |
|
|
|
58.54 |
|
Total E&P |
|
|
53.06 |
|
|
|
44.84 |
|
|
|
56.72 |
|
Natural gas (per thousand cubic feet)* |
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
|
4.27 |
|
|
|
3.50 |
|
|
|
7.60 |
|
International |
|
|
5.60 |
|
|
|
5.06 |
|
|
|
8.65 |
|
Total consolidated operations |
|
|
5.07 |
|
|
|
4.40 |
|
|
|
8.20 |
|
Equity affiliates |
|
|
2.79 |
|
|
|
2.35 |
|
|
|
2.04 |
|
Total E&P |
|
|
4.98 |
|
|
|
4.37 |
|
|
|
8.18 |
|
|
|
*Prior periods reclassified to conform to current year
presentation which includes intrasegment transfer pricing. |
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Production Costs Per Barrel of Oil Equivalent |
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
$ |
8.30 |
|
|
|
7.73 |
|
|
|
8.34 |
|
International |
|
|
7.96 |
|
|
|
7.72 |
|
|
|
8.03 |
|
Total consolidated operations |
|
|
8.10 |
|
|
|
7.73 |
|
|
|
8.17 |
|
Equity affiliates |
|
|
8.11 |
|
|
|
7.68 |
|
|
|
13.36 |
|
Total E&P |
|
|
8.10 |
|
|
|
7.72 |
|
|
|
8.33 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
|
|
|
Worldwide Exploration Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative; geological and geophysical; and
lease rentals |
|
$ |
678 |
|
|
|
576 |
|
|
|
639 |
|
Leasehold impairment |
|
|
241 |
|
|
|
247 |
|
|
|
273 |
|
Dry holes |
|
|
236 |
|
|
|
359 |
|
|
|
425 |
|
|
|
|
|
$ |
1,155 |
|
|
|
1,182 |
|
|
|
1,337 |
|
|
|
40
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
|
Thousands of Barrels Daily |
|
Operating Statistics |
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil and natural gas liquids produced |
|
|
|
|
|
|
|
|
|
|
|
|
Alaska |
|
|
230 |
|
|
|
252 |
|
|
|
261 |
|
Lower 48 |
|
|
160 |
|
|
|
166 |
|
|
|
165 |
|
|
|
United States |
|
|
390 |
|
|
|
418 |
|
|
|
426 |
|
Canada |
|
|
38 |
|
|
|
40 |
|
|
|
44 |
|
Europe |
|
|
211 |
|
|
|
241 |
|
|
|
233 |
|
Asia Pacific/Middle East |
|
|
140 |
|
|
|
132 |
|
|
|
107 |
|
Africa |
|
|
79 |
|
|
|
78 |
|
|
|
80 |
|
Other areas |
|
|
- |
|
|
|
4 |
|
|
|
9 |
|
|
|
Total consolidated operations |
|
|
858 |
|
|
|
913 |
|
|
|
899 |
|
Equity affiliates |
|
|
|
|
|
|
|
|
|
|
|
|
Russia |
|
|
52 |
|
|
|
55 |
|
|
|
24 |
|
Asia Pacific/Middle East |
|
|
3 |
|
|
|
- |
|
|
|
- |
|
|
|
|
|
|
913 |
|
|
|
968 |
|
|
|
923 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Synthetic oil produced |
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated operationsCanada |
|
|
12 |
|
|
|
23 |
|
|
|
22 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bitumen produced |
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated operationsCanada |
|
|
10 |
|
|
|
7 |
|
|
|
6 |
|
Equity affiliatesCanada |
|
|
49 |
|
|
|
43 |
|
|
|
30 |
|
|
|
|
|
|
59 |
|
|
|
50 |
|
|
|
36 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Cubic Feet Daily
|
|
|
|
|
|
Natural gas produced* |
|
|
|
|
|
|
|
|
|
|
|
|
Alaska |
|
|
82 |
|
|
|
94 |
|
|
|
97 |
|
Lower 48 |
|
|
1,695 |
|
|
|
1,927 |
|
|
|
1,994 |
|
|
|
United States |
|
|
1,777 |
|
|
|
2,021 |
|
|
|
2,091 |
|
Canada |
|
|
984 |
|
|
|
1,062 |
|
|
|
1,054 |
|
Europe |
|
|
815 |
|
|
|
876 |
|
|
|
954 |
|
Asia Pacific/Middle East |
|
|
712 |
|
|
|
713 |
|
|
|
609 |
|
Africa |
|
|
149 |
|
|
|
121 |
|
|
|
114 |
|
Other areas |
|
|
- |
|
|
|
- |
|
|
|
14 |
|
|
|
Total consolidated operations |
|
|
4,437 |
|
|
|
4,793 |
|
|
|
4,836 |
|
Equity affiliates |
|
|
|
|
|
|
|
|
|
|
|
|
Asia Pacific/Middle East |
|
|
169 |
|
|
|
84 |
|
|
|
11 |
|
|
|
|
|
|
4,606 |
|
|
|
4,877 |
|
|
|
4,847 |
|
|
|
*Represents quantities available for sale. Excludes gas equivalent of natural gas liquids
included above.
Equity affiliate statistics exclude our share of LUKOIL, which is reported in the LUKOIL Investment
segment.
The E&P segment primarily explores for, produces, transports and markets crude oil, bitumen,
natural gas, LNG and natural gas liquids on a worldwide basis. At December 31, 2010, our E&P
operations were producing in the United States, Norway, the United Kingdom, Canada, Australia,
offshore Timor-Leste in the Timor Sea, Indonesia, China, Vietnam, Libya, Nigeria, Algeria, Qatar
and Russia. Total E&P production on a barrel-of-oil-equivalent (BOE) basis averaged 1,752,000 BOE
per day in 2010, compared with 1,854,000 BOE per day in 2009.
41
2010 vs. 2009
Earnings from our E&P segment were $9,198 million in 2010, compared with earnings of $3,604 million
in 2009. The increase in 2010 earnings primarily resulted from higher prices for crude oil,
natural gas, natural gas liquids and LNG. In addition, 2010 earnings benefitted from the $2,679
million after-tax gain on sale of Syncrude and higher gains from other asset rationalization
efforts. These increases were partially offset by lower crude oil, natural gas and synthetic oil
volumes, higher petroleum and export taxes as a result of higher prices, and the NMNG impairment.
See the Business Environment and Executive Overview section for additional information on
industry crude oil and natural gas prices.
U.S. E&P
U.S. E&P earnings increased 84 percent in 2010, from $1,503 million in 2009 to $2,768 million in
2010. The increase was primarily the result of higher prices for crude oil, natural gas and
natural gas liquids. Earnings also benefitted from higher gains from asset sales in our Lower 48
portfolio and lower depreciation, depletion and amortization. These increases were partially
offset by lower crude oil and natural gas volumes, higher production taxes, primarily in Alaska,
and an unfavorable tax ruling.
U.S. E&P production averaged 686,000 BOE per day in 2010, a decrease of 9 percent from 755,000 BOE
in 2009. The decrease was primarily due to field decline and unplanned downtime, which was
somewhat offset by new production.
International E&P
International E&P earnings were $6,430 million in 2010, compared with $2,101 million in 2009. The
increase in 2010 was mostly due to gains from the sale of Syncrude and other assets and higher
crude oil, natural gas and LNG prices. These increases were partially offset by the NMNG
impairment, lower synthetic oil and natural gas volumes, higher petroleum taxes as a result of
higher prices and an $81 million after-tax charge to exploration expenses for project costs
resulting from our decision to end participation in the Shah Gas Field Project in Abu Dhabi.
International E&P production averaged 1,066,000 BOE per day in 2010, a decrease of 3 percent from
1,099,000 BOE in 2009. The decrease was largely due to field decline, the impact of higher prices
on production sharing arrangements and the sale of Syncrude. These decreases were partially offset
by production from major projects, primarily in China, Canada, Qatar and Australia.
2009 vs. 2008
The E&P segment had earnings of $3,604 million during 2009. In 2008, the E&P segment had a loss of
$13,479 million, which included a $25,443 million before- and after-tax complete impairment of E&P
segment goodwill.
Excluding the impact from the goodwill impairment, earnings from the E&P segment decreased 70
percent during 2009, primarily due to substantially lower crude oil, natural gas and natural gas
liquids prices. Our E&P segment also recognized property impairment charges. These decreases were
partially offset by lower Alaska and Lower 48 production taxes due to lower prices, as well as
higher international volumes and improved operating costs.
U.S. E&P
Earnings from our U.S. E&P operations decreased 70 percent, due to significantly lower crude oil,
natural gas and natural gas liquids prices. Lower production taxes, lower property impairments in
the Lower 48 and improved operating costs partially offset the decrease.
U.S. E&P production averaged 755,000 BOE per day in 2009, a decrease of 3 percent from 775,000 BOE
per day in 2008. Less unplanned downtime and improved well performance were more than offset by
field decline.
42
International E&P
Earnings from our international E&P operations were $2,101 million in 2009, compared with $6,976
million in 2008. The decline was primarily a result of significantly lower crude oil, natural gas
and natural gas liquids prices and higher impairments. These decreases were partially offset by
higher volumes and lower operating costs.
International E&P production averaged 1,099,000 BOE per day in 2009, an increase of 8 percent from
1,014,000 BOE per day in 2008. The increase was predominantly due to new production in the United
Kingdom, Russia, China, Canada, Norway and Vietnam. In addition, production increased due to the
impacts from the royalty framework in Alberta, Canada, as well as less unplanned downtime and the
impact of lower prices on production sharing arrangements. These increases were partially offset
by field decline and planned downtime.
Midstream
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
|
Millions of Dollars |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income Attributable to ConocoPhillips* |
|
$ |
306 |
|
|
|
313 |
|
|
|
541 |
|
|
|
*Includes DCP Midstream-related earnings: |
|
$ |
191 |
|
|
|
183 |
|
|
|
458 |
|
|
|
Dollars Per Barrel |
|
Average Sales Prices |
|
|
|
|
|
|
|
|
|
|
|
|
U.S. natural gas liquids* |
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated |
|
$ |
45.42 |
|
|
|
33.63 |
|
|
|
56.29 |
|
Equity affiliates |
|
|
41.28 |
|
|
|
29.80 |
|
|
|
52.08 |
|
|
|
*Based on index prices from the Mont Belvieu and Conway market hubs that are weighted by
natural gas liquids component and location mix.
|
|
|
Thousands of Barrels Daily |
|
Operating Statistics |
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas liquids extracted* |
|
|
193 |
|
|
|
187 |
|
|
|
188 |
|
Natural gas liquids fractionated** |
|
|
152 |
|
|
|
166 |
|
|
|
165 |
|
|
|
*Includes our share of equity affiliates, except LUKOIL, which is included in the LUKOIL
Investment segment.
**Excludes DCP 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 fractionatedseparated into individual components like ethane, butane and propaneand
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, trading and marketing businesses,
primarily in the United States and Trinidad.
2010 vs. 2009
Midstream earnings decreased 2 percent in 2010. Higher natural gas liquids prices and, to a lesser
extent, improved volumes from our equity affiliate, Phoenix Park Gas Processors Limited, were more
than offset by the absence of the 2009 recognition of an $88 million after-tax benefit, which
resulted from a DCP Midstream subsidiary converting subordinated units to common units. In
addition, higher operating expenses resulting from higher turnaround activity contributed to the
decrease in earnings.
43
2009 vs. 2008
Earnings from the Midstream segment decreased 42 percent in 2009. The decrease was primarily due
to substantially lower realized natural gas liquids prices, partially offset by the recognition of
the $88 million after-tax benefit resulting from the conversion of subordinated units to common
units.
R&M
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
|
Millions of Dollars |
|
Net Income (Loss) Attributable to ConocoPhillips |
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
$ |
1,022 |
|
|
|
(192 |
) |
|
|
1,540 |
|
International |
|
|
(830 |
) |
|
|
229 |
|
|
|
782 |
|
|
|
|
|
$ |
192 |
|
|
|
37 |
|
|
|
2,322 |
|
|
|
|
|
Dollars Per Gallon |
|
U.S. Average Wholesale Prices* |
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline |
|
$ |
2.24 |
|
|
|
1.84 |
|
|
|
2.65 |
|
Distillates |
|
|
2.30 |
|
|
|
1.76 |
|
|
|
3.06 |
|
|
|
*Excludes excise taxes.
|
|
|
Thousands of Barrels Daily |
|
Operating Statistics |
|
|
|
|
|
|
|
|
|
|
|
|
Refining operations* |
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil capacity** |
|
|
1,986 |
|
|
|
1,986 |
|
|
|
2,008 |
|
Crude oil processed |
|
|
1,782 |
|
|
|
1,731 |
|
|
|
1,849 |
|
Capacity utilization (percent) |
|
|
90 |
% |
|
|
87 |
|
|
|
92 |
|
Refinery production |
|
|
1,958 |
|
|
|
1,891 |
|
|
|
2,035 |
|
International |
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil capacity** |
|
|
671 |
|
|
|
671 |
|
|
|
670 |
|
Crude oil processed |
|
|
374 |
|
|
|
495 |
|
|
|
567 |
|
Capacity utilization (percent) |
|
|
56 |
% |
|
|
74 |
|
|
|
85 |
|
Refinery production |
|
|
383 |
|
|
|
504 |
|
|
|
575 |
|
Worldwide |
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil capacity** |
|
|
2,657 |
|
|
|
2,657 |
|
|
|
2,678 |
|
Crude oil processed |
|
|
2,156 |
|
|
|
2,226 |
|
|
|
2,416 |
|
Capacity utilization (percent) |
|
|
81 |
% |
|
|
84 |
|
|
|
90 |
|
Refinery production |
|
|
2,341 |
|
|
|
2,395 |
|
|
|
2,610 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Petroleum products sales volumes |
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline |
|
|
1,120 |
|
|
|
1,130 |
|
|
|
1,128 |
|
Distillates |
|
|
873 |
|
|
|
858 |
|
|
|
893 |
|
Other products |
|
|
400 |
|
|
|
367 |
|
|
|
374 |
|
|
|
|
|
|
2,393 |
|
|
|
2,355 |
|
|
|
2,395 |
|
International |
|
|
647 |
|
|
|
619 |
|
|
|
645 |
|
|
|
|
|
|
3,040 |
|
|
|
2,974 |
|
|
|
3,040 |
|
|
|
*Includes our share of equity affiliates, except LUKOIL, which is included in the LUKOIL
Investment segment.
**Weighted-average crude oil capacity for the periods.
Our R&M segment refines crude oil and other feedstocks into petroleum products (such as
gasoline, distillates and aviation fuels); buys, sells and transports crude oil; and buys,
transports, distributes and markets petroleum products. R&M has operations mainly in the United
States, Europe and Asia.
44
2010 vs. 2009
R&M reported earnings of $192 million in 2010, compared with earnings of $37 million in 2009.
Earnings for 2010 included the $1,124 million after-tax property impairment of WRG. Excluding the
impact of this impairment, earnings were significantly improved during 2010 due to higher global
refining margins. Results also benefitted from a $113 million after-tax gain on the sale of CFJ
and higher refining and marketing volumes. These increases were partially offset by negative
foreign currency impacts. See the Business Environment and Executive Overview section for
additional information on industry refining margins.
U.S. R&M
Earnings from U.S. R&M were $1,022 million in 2010, compared with a loss of $192 million in 2009.
The increase in 2010 primarily resulted from significantly higher refining margins and the gain on
sale of CFJ. Higher refining and marketing volumes also contributed to the improvement in
earnings.
Our U.S. refining crude oil capacity utilization rate was 90 percent in 2010, compared with 87
percent in 2009. The increase in 2010 was primarily due to lower turnaround activity, lower run
reductions due to market conditions, and less unplanned downtime.
International R&M
International R&M reported a loss of $830 million in 2010, compared with earnings of $229 million
in 2009. The loss in 2010 primarily resulted from the WRG impairment and a $29 million after-tax
impairment resulting from our decision to end participation in the Yanbu Refinery Project.
Excluding these impairments, earnings were improved due to higher refining margins, partially
offset by foreign currency losses.
Our international refining crude oil capacity utilization rate was 56 percent in 2010, compared
with 74 percent in 2009. The 2010 rate primarily reflects run reductions at WRG in response to
market conditions.
We are currently exploring options to either pursue the sale of WRG or operate it as a terminal.
As a result, effective January 1, 2011, we no longer include its capacity in our stated refining
capacities or our capacity utilization metrics.
2009 vs. 2008
R&M reported earnings of $37 million in 2009, compared with $2,322 million in 2008. The decrease
was primarily a result of significantly lower U.S. and international refining margins, lower
volumes, lower international marketing margins and a lower net benefit from asset rationalization
efforts. These decreases were partially offset by lower operating expenses, lower property
impairments and positive foreign currency impacts. During 2008, our R&M segment had property
impairments totaling $511 million after-tax, mostly due to a significantly diminished outlook for
refining margins.
U.S. R&M
Our U.S. R&M operations reported a loss of $192 million in 2009, compared with earnings of $1,540
million in 2008. The decrease was primarily due to significantly lower U.S. refining margins,
lower U.S. refining and marketing volumes and a lower net benefit from asset sales. These
decreases were partially offset by lower operating expenses and lower property impairments.
Our U.S. refining capacity utilization rate was 87 percent in 2009, compared with 92 percent in
2008. The rate for 2009 was mainly affected by run reductions due to market conditions and
increased turnaround activity, while the 2008 rate was impacted by downtime associated with
hurricanes.
International R&M
International R&M reported earnings of $229 million in 2009 and earnings of $782 million in 2008.
The decrease in earnings was primarily due to significantly lower international refining and
marketing margins, lower international marketing volumes and a lower net benefit from asset sales.
These decreases were partially offset by positive foreign currency impacts, lower property
impairments and lower operating expenses.
45
Our international refining capacity utilization rate was 74 percent in 2009, compared with 85
percent in 2008. The rate for 2009 reflected higher turnaround activity. In addition, the
utilization rate for both periods reflected run reductions in response to market conditions.
LUKOIL Investment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars |
|
|
|
2010 |
|
|
2009 |
* |
|
2008 |
* |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) Attributable to ConocoPhillips |
|
$ |
2,503 |
|
|
|
1,219 |
|
|
|
(4,839 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Statistics |
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil production (thousands of barrels daily) |
|
|
284 |
|
|
|
388 |
|
|
|
389 |
|
Natural gas production (millions of cubic feet daily) |
|
|
254 |
|
|
|
295 |
|
|
|
330 |
|
Refinery crude oil processed (thousands of barrels daily) |
|
|
189 |
|
|
|
240 |
|
|
|
226 |
|
|
|
*Recast to reflect a change in accounting principle. See Note 2Changes in Accounting Principles, for more information.
This segment represents our investment in the ordinary shares of LUKOIL, an international,
integrated oil and gas company headquartered in Russia.
Prior to 2010, our equity earnings for LUKOIL were estimated. Effective January 1, 2010, we
changed our accounting to record our equity earnings for LUKOIL on a one-quarter-lag basis. This
change in accounting principle has been applied retrospectively, by recasting prior period
financial information. The performance metrics are also reported on a one-quarter-lag basis. See
Note 2Changes in Accounting Principles, in the Notes to Consolidated Financial Statements, for
more information.
In addition to our equity share of LUKOILs earnings, segment results include the amortization of
the basis difference between our equity interest in the net assets of LUKOIL and the book value of
our investment, as well as gains from the divestiture of our LUKOIL shares.
At year-end 2009, we had a 20 percent ownership interest in LUKOIL based on authorized and issued
shares. In July 2010, we announced our intention to sell our entire interest in LUKOIL. During
2010, we sold approximately 151 million shares of LUKOIL, and as a result of these sales, our
ownership interest in LUKOIL was 2.25 percent at December 31, 2010, based on authorized and issued
shares. In the third quarter of 2010, our ownership interest declined to a level at which we were
no longer able to exercise significant influence over the operating and financial policies of
LUKOIL. Accordingly, at the end of the third quarter of 2010, we stopped applying the equity
method of accounting for our remaining investment. In addition, we will no longer report proved
reserves or production related to our LUKOIL investment. See Note 6Investments, Loans and
Long-Term Receivables, in the Notes to Consolidated Financial Statements, for more information.
In the first quarter of 2011, we sold our remaining interest in LUKOIL. As a result, our first
quarter 2011 earnings from the LUKOIL Investment segment will primarily reflect the realized gain
on share sales. The total unrealized gain on those shares at December 31, 2010, based on a closing
price of LUKOIL shares on the London Stock Exchange of $56.50 per share, was $158 million
after-tax, and this amount was included in accumulated other comprehensive income.
2010 vs. 2009
LUKOIL segment earnings increased $1,284 million in 2010, which primarily resulted from the $1,251
million after-tax gain on our LUKOIL shares sold during 2010.
46
2009 vs. 2008
LUKOIL segment earnings were $1,219 million in 2009, compared with a loss of $4,839 million in
2008. Results for 2008 included a $7,496 million noncash, before- and after-tax impairment of our
LUKOIL investment taken during the fourth quarter. Excluding the impact of this impairment,
earnings decreased 54 percent in 2009. The decrease was primarily due to lower realized refined
product and crude oil prices, which was partly offset by lower extraction taxes and export tariff
rates, and a benefit from basis difference amortization.
Chemicals
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income Attributable to ConocoPhillips |
|
$ |
498 |
|
|
|
248 |
|
|
|
110 |
|
|
|
The Chemicals segment consists of our 50 percent interest in 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.
2010 vs. 2009
Earnings from the Chemicals segment increased $250 million in 2010, primarily due to substantially
higher margins in the olefins and polyolefins business line and, to a lesser extent, improved
margins from the specialties, aromatics and styrenics business line. Higher operating costs
partially offset these increases.
2009 vs. 2008
Earnings from the Chemicals segment increased $138 million in 2009 due to lower operating costs and
higher margins in the specialties, aromatics and styrenics business line. These increases were
partially offset by lower margins in the olefins and polyolefins business line.
Emerging Businesses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
|
|
|
Net Income (Loss) Attributable to ConocoPhillips |
|
|
|
|
|
|
|
|
|
|
|
|
Power |
|
$ |
49 |
|
|
|
105 |
|
|
|
106 |
|
Other |
|
|
(108 |
) |
|
|
(102 |
) |
|
|
(76 |
) |
|
|
|
|
$ |
(59 |
) |
|
|
3 |
|
|
|
30 |
|
|
|
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, refining, alternative energy, biofuels, and the environment.
47
2010 vs. 2009
The Emerging Businesses segment reported a loss of $59 million in 2010, compared with earnings of
$3 million in 2009. The decrease for 2010 was mainly due to lower domestic and international power
generation results, which resulted from higher operating costs and impairment charges related to a
U.S. cogeneration plant that was sold in December 2010. Lower margins in international power and
higher technology development expenses also contributed to the decrease.
2009 vs. 2008
Emerging Businesses reported earnings of $3 million in 2009, compared with $30 million in 2008.
The decrease in 2009 was primarily due to lower international power results and higher technology
development expenses, which were mostly offset by the absence of an $85 million after-tax
impairment of a U.S. cogeneration power plant in 2008.
Corporate and Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
|
|
|
Net Loss Attributable to ConocoPhillips |
|
|
|
|
|
|
|
|
|
|
|
|
Net interest |
|
$ |
(965 |
) |
|
|
(851 |
) |
|
|
(558 |
) |
Corporate general and administrative expenses |
|
|
(209 |
) |
|
|
(108 |
) |
|
|
(202 |
) |
Other |
|
|
(106 |
) |
|
|
(51 |
) |
|
|
(274 |
) |
|
|
|
|
$ |
(1,280 |
) |
|
|
(1,010 |
) |
|
|
(1,034 |
) |
|
|
2010 vs. 2009
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. Net interest increased 13
percent in 2010, mostly due to a $114 million after-tax premium on early debt retirement and a
lower effective tax rate. These increases were partially offset by lower interest expense due to
lower debt levels. Corporate general and administrative expenses increased $101 million in 2010,
primarily as a result of costs related to compensation and benefit plans. 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.
Changes in the Other category primarily reflect foreign currency transaction losses.
2009 vs. 2008
Net interest increased 53 percent in 2009 as a result of higher average debt levels, partially
offset by lower average interest rates. Capitalized interest was also lower in 2009. Corporate
general and administrative expenses decreased 47 percent due to decreased costs related to
compensation plans and overhead. Changes in the Other category are primarily due to foreign
currency transaction gains in 2009, compared with foreign currency transaction losses in 2008.
48
CAPITAL RESOURCES AND LIQUIDITY
Financial Indicators
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars |
|
|
|
Except as Indicated |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
Net cash provided by operating activities |
|
$ |
17,045 |
|
|
|
12,479 |
|
|
|
22,658 |
|
Short-term debt |
|
|
936 |
|
|
|
1,728 |
|
|
|
370 |
|
Total debt |
|
|
23,592 |
|
|
|
28,653 |
|
|
|
27,455 |
|
Total equity* |
|
|
69,109 |
|
|
|
62,613 |
|
|
|
56,265 |
|
Percent of total debt to capital** |
|
|
25 |
% |
|
|
31 |
|
|
|
33 |
|
Percent of floating-rate debt to total debt*** |
|
|
10 |
% |
|
|
9 |
|
|
|
37 |
|
|
|
*2009 and 2008 recast to reflect a change in accounting principle. See Note 2Changes in Accounting Principles, for more information.
**Capital includes total debt and total equity.
***Includes effect of interest rate swaps.
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 2010, we received $15,372 million in proceeds from asset sales. During 2010, the primary
uses of our available cash were: $9,761 million to support our ongoing capital expenditures and
investments program, $5,202 million to repay debt, $3,866 million to repurchase common stock,
$3,175 million to pay dividends on our common stock, and $982 million to purchase short-term
investments. During 2010, cash and cash equivalents increased by $8,912 million to $9,454 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 statement to support our
short- and long-term liquidity requirements. 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 2010, cash of $17,045 million was provided by operating activities, a 37 percent increase
from cash from operations of $12,479 million in 2009. The increase was primarily due to
significantly higher crude oil prices in our E&P segment and higher refining margins in our R&M
segment.
During 2009, cash flow from operations decreased $10,179 million, compared with 2008. The decline
was primarily due to significantly lower commodity prices in our E&P segment and lower refining
margins in our R&M segment.
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, bitumen, natural gas, LNG and natural gas
liquids, as well as refining and marketing margins. Crude oil and natural gas prices deteriorated
significantly in the fourth quarter of 2008. Crude oil prices trended higher in 2009 and 2010
although natural gas prices remained weak. Refining margins deteriorated significantly in the
fourth quarter of 2008, remained low throughout 2009, and showed improvement during 2010. Prices
and margins in our industry are typically volatile, and 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, bitumen, 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,
49
field production decline rates, new technologies, operating efficiency, weather conditions, the
addition of proved reserves through exploratory success and their timely and cost-effective
development. 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 E&P production for 2010 averaged 1.75 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 effects of price changes on
production sharing and variable-royalty contracts; timing of project startups and major
turnarounds; and weather-related disruptions. Our production in 2011, excluding the impact of any
additional dispositions, is expected to be approximately 1.7 million BOE per day. We continue to
evaluate various properties as potential candidates for our disposition program. The makeup and
timing of our disposition program will also impact 2011 and future years production levels.
To maintain or grow our production volumes, we must continue to add to our proved reserve base.
Our reserve replacement in 2010 was negative 160 percent, including a positive 41 percent from
consolidated operations. The 2010 reserve replacement reflects a reduction of 2.2 billion BOE due
to LUKOIL share sales and other asset dispositions. Excluding the impact of acquisitions and
dispositions, the E&P segments reserve replacement was 138 percent of 2010 production. Over the
five-year period ended December 31, 2010, our reserve replacement was 75 percent, including 105
percent from consolidated operations; however, excluding LUKOIL, our five-year reserve replacement
would have been 111 percent. Over this period we added reserves through acquisitions and project
developments, which were more than offset by the impact of asset expropriations in Venezuela and
Ecuador and the sale of our investment in LUKOIL. 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. For
additional information about our proved reserves, including both developed and undeveloped
reserves, see 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; therefore, each year reserves may be revised upward or downward due to the
impact of changes in commodity prices or as more technical data becomes available on reservoirs.
In 2010 and 2009, revisions increased reserves, while in 2008 revisions decreased reserves. It is
not possible to reliably predict how revisions will impact reserve quantities in the future.
In our R&M segment, 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, market conditions, 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.
Asset Sales
Proceeds from asset sales in 2010 were $15.4 billion, compared with $1.3 billion in 2009. The 2010
proceeds from asset sales included $8.3 billion from our interest in LUKOIL. The remaining sales
consisted primarily of our interest in Syncrude Canada Ltd., CFJ Properties and North America E&P
assets. We plan to raise an additional $3 billion through the end of 2011, as part of our
previously announced $10 billion asset disposition program. The sale of our LUKOIL interest is not
included in this program.
50
Commercial Paper and Credit Facilities
At December 31, 2010, we had two revolving credit facilities totaling $7.85 billion, consisting of
a $7.35 billion facility expiring in September 2012 and a $500 million facility expiring in July
2012. Our revolving credit facilities may be used as direct bank borrowings, as support for
issuances of letters of credit totaling up to $750 million, or as support for our commercial paper
programs. 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.
Credit facility borrowings may bear interest at a margin above rates offered by certain designated
banks in the London interbank market or at a margin above the overnight federal funds rate or prime
rates offered by certain designated banks in the United States. The agreements call for commitment
fees on available, but unused, amounts. The agreements also contain early termination rights if
our current directors or their approved successors cease to be a majority of the Board of
Directors.
Our primary funding source for short-term working capital needs is the ConocoPhillips $6.35 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 (QG3) Project. At December 31, 2010 and 2009, we had
no direct borrowings under the revolving credit facilities, but $40 million in letters of credit
had been issued at both periods. In addition, under the two ConocoPhillips commercial paper
programs, $1,182 million of commercial paper was outstanding at December 31, 2010, compared with
$1,300 million at December 31, 2009. Since we had $1,182 million of commercial paper outstanding
and had issued $40 million of letters of credit, we had access to $6.6 billion in borrowing
capacity under our revolving credit facilities at December 31, 2010.
Shelf Registration
We have a universal shelf registration statement on file with the 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.
Our senior long-term debt is rated A1 by Moodys Investor Service and A by both Standard and
Poors Rating Service and by Fitch. 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. If our credit rating were to deteriorate to a level
prohibiting us from accessing the commercial paper market, we would still be able to access funds
under our $7.35 billion and $500 million revolving credit facilities.
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, 2010,
we were liable for certain contingent obligations under the following contractual arrangements:
|
|
|
Qatargas 3: We own a 30 percent interest in QG3, an integrated project to
produce and liquefy natural gas from Qatars North Field. The other participants in the
project are affiliates of Qatar Petroleum (68.5 percent) and Mitsui & Co., Ltd. (1.5
percent). Our interest is held through a jointly owned company, Qatar Liquefied Gas
Company Limited (3), for which we use the equity method of accounting. QG3 secured project
financing of $4 billion in 2005, consisting of $1.3 billion of loans from export credit
agencies (ECA), $1.5 billion from commercial banks, and $1.2 billion from ConocoPhillips.
The ConocoPhillips loan facilities have substantially the same terms as the ECA and
commercial bank facilities. Prior to project completion certification, all loans,
including the ConocoPhillips loan facilities, are guaranteed by the participants, based on
their respective ownership interests. Accordingly, our maximum exposure to this financing
structure is $1.2 billion. Upon completion certification, currently expected in 2011, all
project loan facilities, including the |
51
|
|
|
ConocoPhillips loan facilities, will become nonrecourse to the project participants. At
December 31, 2010, QG3 had approximately $4 billion outstanding under all the loan
facilities, including the $1.2 billion from ConocoPhillips. |
|
|
|
|
Rockies Express Pipeline: In June 2006, we issued a guarantee for 24 percent of
$2 billion in credit facilities issued to Rockies Express Pipeline LLC, operated by Kinder
Morgan Energy Partners, L.P. In the second quarter of 2010, the credit facilities were
reduced, and our guarantee was released. |
For additional information about guarantees, see Note 14Guarantees, in the Notes to Consolidated
Financial Statements, which is incorporated herein by reference.
Capital Requirements
Our debt balance at December 31, 2010, was $23.6 billion, a decrease of $5.1 billion during 2010,
and our debt-to-capital ratio was 25 percent at year-end 2010, versus 31 percent at the end of
2009. The change in the debt-to-capital ratio was due to a combination of a decrease in debt and
an increase in equity. Our debt-to-capital ratio target range is 20 to 25 percent. On February
15, 2011, a $328 million 9.375% Note was repaid at maturity.
In 2007, we closed on a business venture with Cenovus Energy Inc. As part of this transaction, we
are obligated to contribute $7.5 billion, plus accrued interest, over a 10-year period that began
in 2007, to the upstream business venture, FCCL, formed as a result of the transaction. 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 $695 million
was short-term and was included in the Accounts payablerelated parties line on our December 31,
2010, consolidated balance sheet. The principal portion of these payments, which totaled $659
million in 2010, is 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 payment is reflected as a
capital contribution and is included in the Capital expenditures and investments line on our
consolidated statement of cash flows.
We have provided loan financing to WRB Refining LP, to assist it in meeting its operating and
capital spending requirements. At December 31, 2010, $550 million of such financing was
outstanding and $400 million was classified as long term.
In
February 2011, we announced a 20 percent increase in the
quarterly dividend rate to 66 cents per share. The dividend is payable
March 1, 2011, to stockholders of record at the close of business February 22, 2011.
On March 24, 2010, our Board of Directors authorized the purchase of up to $5 billion of our common
stock through 2011. Repurchase of shares under this authorization totaled 64.5 million shares at a
cost of $3.9 billion, through December 31, 2010. On February 11, 2011, the Board authorized the
additional purchase of up to $10 billion of our common stock over the subsequent two years. At
year end we had a cash and short-term investment balance of $10.4 billion, a significant portion of
which is expected to be directed toward the repurchase of common stock.
52
Contractual Obligations
The following table summarizes our aggregate contractual fixed and variable obligations as of
December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars |
|
|
|
Payments Due by Period |
|
|
|
|
|
|
|
Up to |
|
|
Years |
|
|
Years |
|
|
After |
|
|
|
Total |
|
|
1 Year |
|
|
2-3 |
|
|
4-5 |
|
|
5 Years |
|
|
|
|
Debt obligations (a) |
|
$ |
23,553 |
|
|
|
924 |
|
|
|
3,354 |
|
|
|
3,137 |
|
|
|
16,138 |
|
Capital lease obligations |
|
|
39 |
|
|
|
12 |
|
|
|
4 |
|
|
|
3 |
|
|
|
20 |
|
|
|
Total debt |
|
|
23,592 |
|
|
|
936 |
|
|
|
3,358 |
|
|
|
3,140 |
|
|
|
16,158 |
|
|
|
Interest on debt and other obligations |
|
|
20,060 |
|
|
|
1,404 |
|
|
|
2,649 |
|
|
|
2,274 |
|
|
|
13,733 |
|
Operating lease obligations |
|
|
2,896 |
|
|
|
752 |
|
|
|
1,033 |
|
|
|
554 |
|
|
|
557 |
|
Purchase obligations (b) |
|
|
139,575 |
|
|
|
61,136 |
|
|
|
14,326 |
|
|
|
9,044 |
|
|
|
55,069 |
|
Joint venture acquisition obligation (c) |
|
|
5,009 |
|
|
|
695 |
|
|
|
1,504 |
|
|
|
1,672 |
|
|
|
1,138 |
|
Other long-term liabilities (d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations |
|
|
8,776 |
|
|
|
454 |
|
|
|
722 |
|
|
|
627 |
|
|
|
6,973 |
|
Accrued environmental costs |
|
|
994 |
|
|
|
117 |
|
|
|
176 |
|
|
|
119 |
|
|
|
582 |
|
Unrecognized tax benefits (e) |
|
|
160 |
|
|
|
160 |
|
|
|
(e |
) |
|
|
(e |
) |
|
|
(e |
) |
|
|
Total |
|
$ |
201,062 |
|
|
|
65,654 |
|
|
|
23,768 |
|
|
|
17,430 |
|
|
|
94,210 |
|
|
|
(a) |
|
Includes $457 million of net unamortized premiums and discounts. See Note 12Debt, in the
Notes to Consolidated Financial Statements, for additional information. |
|
(b) |
|
Represents any agreement to purchase goods or services that is enforceable and legally
binding and that specifies all significant terms. Does not include purchase commitments for
jointly owned fields and facilities where we are not the operator. |
|
|
|
The majority of the purchase obligations are market-based contracts, including exchanges and
futures, for the purchase of products such as crude oil, unfractionated natural gas liquids,
natural gas and power. The products are mostly used to supply our refineries and
fractionators, optimize the supply chain, and resell to customers. Product purchase
commitments with third parties totaled $73,138 million. In addition, $50,179 million are
product purchases from CPChem, mostly for natural gas and natural gas liquids over the
remaining term of 89 years, and Excel Paralubes, for base oil over the remaining initial term
of 15 years. |
|
|
|
Purchase obligations of $12,806 million are related to agreements to access and utilize the
capacity of third-party equipment and facilities, including pipelines and LNG and product
terminals, to transport, process, treat, and store products. The remainder is primarily our
net share of purchase commitments for materials and services for jointly owned fields and
facilities where we are the operator. |
|
(c) |
|
Represents the remaining amount of contributions, excluding interest, due over a seven-year
period to the FCCL upstream joint venture with Cenovus. |
|
(d) |
|
Does not include: Pensionsfor the 2011 through 2015 time period, we expect to contribute an
average of $530 million per year to our qualified and nonqualified pension and postretirement
benefit plans in the United States and an average of $240 million per year to our non-U.S.
plans, which are expected to be in excess of required minimums in many cases. The U.S.
five-year average consists of $730 million for 2011 and then approximately $480 million per
year for the remaining four years. Our required minimum funding in 2011 is expected to be
$360 million in the United States and $160 million outside the United States. |
53
(e) |
|
Excludes unrecognized tax benefits of $965 million because the ultimate disposition and
timing of any payments to be made with regard to such amounts are not reasonably estimable.
Although unrecognized tax benefits are not a contractual obligation, they are presented in
this table because they represent potential demands on our liquidity. |
Capital Spending
Capital Expenditures and Investments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars |
|
|
|
2011 |
|
|
|
|
|
|
|
|
|
|
|
|
Budget |
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
|
|
E&P |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United StatesAlaska |
|
$ |
900 |
|
|
|
730 |
|
|
|
810 |
|
|
|
1,414 |
|
United StatesLower 48 |
|
|
3,300 |
|
|
|
1,855 |
|
|
|
2,664 |
|
|
|
3,836 |
|
International |
|
|
7,100 |
|
|
|
5,908 |
|
|
|
5,425 |
|
|
|
11,206 |
|
|
|
|
|
|
11,300 |
|
|
|
8,493 |
|
|
|
8,899 |
|
|
|
16,456 |
|
|
|
Midstream |
|
|
- |
|
|
|
3 |
|
|
|
5 |
|
|
|
4 |
|
|
|
R&M |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
|
1,000 |
|
|
|
790 |
|
|
|
1,299 |
|
|
|
1,643 |
|
International |
|
|
200 |
|
|
|
266 |
|
|
|
427 |
|
|
|
626 |
|
|
|
|
|
|
1,200 |
|
|
|
1,056 |
|
|
|
1,726 |
|
|
|
2,269 |
|
|
|
LUKOIL Investment |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Chemicals |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Emerging Businesses |
|
|
100 |
|
|
|
27 |
|
|
|
97 |
|
|
|
156 |
|
Corporate and Other |
|
|
200 |
|
|
|
182 |
|
|
|
134 |
|
|
|
214 |
|
|
|
|
|
$ |
12,800 |
|
|
|
9,761 |
|
|
|
10,861 |
|
|
|
19,099 |
|
|
|
United States |
|
$ |
5,400 |
|
|
|
3,576 |
|
|
|
4,921 |
|
|
|
7,111 |
|
International |
|
|
7,400 |
|
|
|
6,185 |
|
|
|
5,940 |
|
|
|
11,988 |
|
|
|
|
|
$ |
12,800 |
|
|
|
9,761 |
|
|
|
10,861 |
|
|
|
19,099 |
|
|
|
Our capital expenditures and investments for the three-year period ending December 31, 2010,
totaled $39.7 billion, with 85 percent allocated to our E&P segment.
Our capital expenditures and investments budget for 2011 is $12.8 billion. Included in this amount
is approximately $0.4 billion in capitalized interest. We plan to direct 88 percent of the capital
expenditures and investments budget to E&P and 9 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 2011 is approximately $13.5 billion.
E&P
Capital expenditures and investments for E&P during the three-year period ended December 31, 2010,
totaled $33.8 billion. The expenditures over this period supported key exploration and development
projects including:
|
|
|
Oil, natural gas liquids and natural gas developments in the Lower 48, including Texas,
New Mexico, North Dakota, Oklahoma, Montana, Colorado, Wyoming, and offshore in the Gulf of
Mexico (GOM). |
|
|
|
|
The initial investment in 2008 related to the Australia Pacific LNG (APLNG) 50/50 joint
venture and subsequent expenditures to advance the associated coalbed methane (CBM)
projects. |
|
|
|
|
Oil sands projects and ongoing natural gas projects in Canada. |
|
|
|
|
Alaska activities related to development drilling in the Greater Kuparuk Area, the
Greater Prudhoe Area, the Western North Slope and the Cook Inlet Area; and exploration. |
|
|
|
|
Significant U.S. lease acquisitions in the federal waters of the Chukchi Sea offshore
Alaska, as well as in the deepwater GOM. |
54
|
|
|
Development drilling and facilities projects in the Greater Ekofisk Area, Alvheim, Heidrun
and Statfjord, located in the Norwegian sector of the North Sea. |
|
|
|
|
The Peng Lai 19-3 development in Chinas Bohai Bay. |
|
|
|
|
The Kashagan Field and satellite prospects in the Caspian Sea offshore Kazakhstan. |
|
|
|
|
In the U.K. sector of the North Sea, the development of the Britannia satellite fields,
the development of the Jasmine discovery in the J-Block Area and development drilling on
Clair and in the southern and central North Sea. |
|
|
|
|
Investment in Rockies Express Pipeline LLC. |
|
|
|
|
The North Belut Field, as well as other projects in offshore Block B and onshore South
Sumatra in Indonesia. |
|
|
|
|
The QG3 Project, an integrated project to produce and liquefy natural gas from Qatars
North Field. |
|
|
|
|
The Gumusut-Kakap development offshore Sabah, Malaysia. |
|
|
|
|
Exploration activities in Australias Browse Basin, deepwater GOM, onshore North
American shale play and oil sands projects, offshore eastern Canada, North Sea and
Kazakhstans Block N. |
|
|
|
|
The El Merk Project, comprised of wells, gathering lines and a shared Central Processing
Facility to develop the EMK Field Unit in Algeria. |
2011 CAPITAL EXPENDITURES AND INVESTMENTS BUDGET
E&Ps 2011 capital expenditures and investments budget is $11.3 billion, 33 percent higher than
actual expenditures in 2010. Thirty-seven percent of E&Ps 2011 capital expenditures and
investments budget is planned for the United States.
Capital spending for our Alaskan operations is expected to be directed toward the Prudhoe Bay and
Kuparuk Fields, as well as the Alpine Field and satellites on the Western North Slope.
In the Lower 48, we expect to make capital expenditures and investments for ongoing development in
the Williston, Permian and San Juan Basins, as well as the Eagle Ford, Barnett and Lobo Trends.
Also, we expect to direct capital spending towards exploration and appraisal activities in the
Eagle Ford shale position in Texas, the Bakken shale formation in North Dakota and the deepwater
GOM.
E&P is directing $7.1 billion of its 2011 capital expenditures and investments budget to
international projects. Funds in 2011 will be directed to developing major long-term projects
including:
|
|
|
Canadian oil sands projects and ongoing natural gas projects in the western Canada gas
basins. |
|
|
|
|
Further development of CBM projects associated with the APLNG joint venture in
Australia. |
|
|
|
|
Elsewhere in the Asia Pacific/Middle East Region, continued development of Bohai Bay
in China, new fields offshore Malaysia, offshore Block B and onshore South Sumatra in
Indonesia, and offshore Vietnam. |
|
|
|
|
In the North Sea, the Ekofisk Area, Greater Britannia Fields, Southern North Sea
assets, development of the Jasmine discovery in the J-Block Area and the Clair Ridge
Project. |
|
|
|
|
The Kashagan Field in the Caspian Sea. |
|
|
|
|
Onshore developments in Nigeria, Algeria and Libya. |
|
|
|
|
Exploration and appraisal activities in North American shale plays and oil sands
projects, Australias Browse Basin, Kazakhstans Block N, deepwater GOM, offshore
Indonesia and the North Sea. |
For information on proved undeveloped reserves and the associated cost to develop these reserves,
see the Oil and Gas Operations section.
55
R&M
Capital spending for R&M during the three-year period ended December 31, 2010, was primarily for
air emission reduction and clean fuels projects to meet new environmental standards, refinery
upgrade projects to improve product yields and increase heavy crude oil processing capability,
improving the operating integrity of key processing units, as well as for safety projects. During
this three-year period, R&M capital spending was $5.1 billion, which represented 13 percent of our
total capital expenditures and investments.
Key projects during the three-year period included:
|
|
|
Installation of a 20,000-barrel-per-day hydrocracker at the Rodeo facility of our San
Francisco Refinery. |
|
|
|
|
Installation of a 225-ton per day sulfur plant at the Sweeny Refinery. |
|
|
|
|
Installation of facilities to reduce sulfur dioxide emissions from the Fluid Catalytic
Cracker at the Alliance Refinery. |
|
|
|
|
Completion of a gasoline benzene reduction project at the Borger Refinery. |
|
|
|
|
Investment to obtain an equity interest in four Keystone Pipeline entities, and
associated investment to construct a crude oil pipeline from Hardisty, Alberta, to delivery
points in the United States. We disposed of our interest in the Keystone Pipeline in 2009. |
Major construction activities in progress include:
|
|
|
Installation of a 65,000-barrel-per-day coker and a major reconfiguration of the Wood
River Refinery to handle advantaged crude and increase capacity, partially funded through
long-term advances from ConocoPhillips. |
|
|
|
|
Installations, revamps and expansions of equipment at several U.S. refineries to enable
production of low benzene gasoline. |
|
|
|
|
U.S. programs aimed at air emission reductions. |
2011 CAPITAL EXPENDITURES AND INVESTMENTS BUDGET
R&Ms 2011 capital expenditures and investments budget is $1.2 billion, a 14 percent increase from
actual spending in 2010, with about $1 billion targeted in the United States and $0.2 billion
internationally. These funds will be used primarily for projects related to sustaining and
improving the existing business with a focus on safety, regulatory compliance and reliability.
Emerging Businesses
Capital spending for Emerging Businesses during the three-year period ended December 31, 2010, was
primarily for an expansion of the Immingham combined heat and power cogeneration plant near our
Humber Refinery in the United Kingdom.
Contingencies
A number of lawsuits involving a variety of claims have been made against ConocoPhillips that arise
in the ordinary course of business. We also may be required to remove or mitigate the effects on
the environment of the placement, storage, disposal or release of certain chemical, mineral and
petroleum substances at various active and inactive sites. We regularly assess the need for
accounting recognition or disclosure of these contingencies. In the case of all known
contingencies (other than those related to income taxes), we accrue a liability when the loss is
probable and the amount is reasonably estimable. 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. We do not reduce these liabilities for potential insurance or third-party
recoveries. If applicable, we accrue receivables for probable insurance or other third-party
recoveries. In the case of income-tax-related contingencies, we use 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. As we learn new facts concerning
contingencies, we reassess our position
56
both with respect to accrued liabilities and other potential exposures. Estimates particularly
sensitive to future changes include contingent liabilities recorded for environmental remediation,
tax and legal matters. Estimated future environmental remediation costs are subject to change due
to such factors as the 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. Estimated future costs related to tax and legal matters are subject
to change as events evolve and as additional information becomes available during the
administrative and litigation processes.
Legal and Tax Matters
Our legal organization applies its knowledge, experience and professional judgment to the specific
characteristics of our cases, employing a litigation management process to manage and monitor the
legal proceedings against us. Our process facilitates the early evaluation and quantification of
potential exposures in individual cases. This process also enables us to track those cases that
have been scheduled for trial and/or mediation. Based on professional judgment and experience in
using these litigation management tools and available information about current developments in all
our cases, our legal organization regularly assesses the adequacy of current accruals and
determines if adjustment of existing accruals, or establishment of new accruals, are required. See
Note 20Income Taxes, in the Notes to Consolidated Financial Statements, for additional
information about income-tax-related contingencies.
Environmental
We are subject to the same numerous international, federal, state and local environmental laws and
regulations as other companies in our industry. The most significant of these environmental laws
and regulations include, among others, the:
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U.S. Federal Clean Air Act, which governs air emissions. |
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U.S. Federal Clean Water Act, which governs discharges to water bodies. |
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European Union Regulation for Registration, Evaluation, Authorization and Restriction of
Chemicals (REACH). |
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U.S. Federal Comprehensive Environmental Response, Compensation and Liability Act
(CERCLA), which imposes liability on generators, transporters and arrangers of hazardous
substances at sites where hazardous substance releases have occurred or are threatening to
occur. |
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U.S. Federal Resource Conservation and Recovery Act (RCRA), which governs the treatment,
storage and disposal of solid waste. |
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U.S. Federal Oil Pollution Act of 1990 (OPA90), under which owners and operators of
onshore facilities and pipelines, lessees or permittees of an area in which an offshore
facility is located, and owners and operators of vessels are liable for removal costs and
damages that result from a discharge of oil into navigable waters of the United States. |
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U.S. Federal Emergency Planning and Community Right-to-Know Act (EPCRA), which requires
facilities to report toxic chemical inventories with local emergency planning committees
and response departments. |
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U.S. Federal Safe Drinking Water Act, which governs the disposal of wastewater in
underground injection wells. |
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U.S. Department of the Interior regulations, which relate to offshore oil and gas
operations in U.S. waters and impose liability for the cost of pollution cleanup resulting
from operations, as well as potential liability for pollution damages. |
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European Union Trading Directive resulting in European Emissions Trading Scheme. |
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 agencys 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
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impose additional, or more stringent, requirements that can add to the cost and difficulty of
marketing or transporting products across state and international borders.
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.
An example in the fuels area is the Energy Policy Act of 2005, which imposed obligations to provide
increasing volumes of renewable fuels in transportation motor fuels through 2012. These
obligations were changed with the enactment of the Energy Independence and Security Act of 2007.
The 2007 law requires fuel producers and importers to provide additional renewable fuels for
transportation motor fuels that include a mix of various types to be included through 2022. We
have met the increased requirements to date while establishing implementation, operating and
capital strategies, along with advanced technology development, to address projected future
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. We anticipate increased
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, 2009, we
reported we had been notified of potential liability under CERCLA and comparable state laws at 65
sites around the United States. At December 31, 2010, we had been notified of seven new sites,
re-opened three sites and settled two sites, bringing the number to 73 unresolved sites with
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 $928 million in 2010 and are expected to be about $1,100 million
per year in 2011 and 2012. Capitalized environmental costs were $574 million in 2010 and are
expected to be about $650 million per year in 2011 and 2012.
Accrued liabilities for remediation activities 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.
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, 2010, our balance sheet included total accrued environmental costs of $994 million,
compared with $1,017 million at December 31, 2009. 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 concerns 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 it is not possible to accurately estimate either a timetable for
implementation or our future compliance costs relating to implementation, such laws, if enacted,
could have a material impact on our results of operations and financial condition. Examples of
legislation or precursors for possible regulation that do or could affect our operations include:
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European Emissions Trading Scheme (ETS), the program through which many of the European
Union (EU) member states are implementing the Kyoto Protocol. |
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Californias Global Warming Solutions Act, which requires the California Air Resources
Board to develop regulations and market mechanisms that will ultimately reduce Californias
GHG emissions by 25 percent by 2020. |
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Two regulations issued by the Alberta government in 2007 under the Climate Change and
Emissions Act. These regulations require any existing facility with emissions equal to or
greater than 100,000 metric tons of carbon dioxide or equivalent per year to reduce the net
emissions intensity of that facility by 2 percent per year beginning July 1, 2007, with an
ultimate reduction target of 12 percent of baseline emissions. |
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The U.S. Supreme Court decision in Massachusetts v. EPA, 549 U.S. 497, 127 S.Ct.
1438 (2007), confirming that the EPA has the authority to regulate carbon dioxide as an
air pollutant under the Federal Clean Air Act. |
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The EPAs announcement on December 7, 2009, Endangerment and Cause or Contribute
Findings for Greenhouse Gases Under Section 202(a) of the Clean Air Act, 74, Fed. Reg.
66,495, finalizing its findings that GHG emissions threaten public health and the
environment and that cars and light trucks cause or contribute to this threat. While these
findings do not themselves impose any requirements on any industry or company at this time,
these findings may lead to greater regulation of GHG emissions by the EPA, may trigger more
climate-based claims for damages, and may result in longer agency review time for
development projects to determine the extent of climate change. |
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. Such regulation could take any of several
forms that may result in the creation of additional costs in the form of taxes, the restriction of
output, investments of capital to maintain compliance with laws and regulations, or required
acquisition or trading of emission allowances. We are working to continuously improve operational
and energy efficiency through resource and energy conservation throughout our operations.
Compliance with changes in laws and regulations that create a GHG emission trading scheme or GHG
reduction policies could significantly increase our costs, reduce demand for fossil energy derived
products, impact the cost and availability of capital and increase our exposure to litigation.
Such laws and regulations could also increase demand for less carbon intensive energy sources,
including natural gas. The ultimate impact on our financial performance, either positive or
negative, will depend on a number of factors, including but not limited to:
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Whether and to what extent legislation is enacted. |
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The nature of the legislation (such as a cap and trade system or a tax on emissions). |
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The GHG reductions required. |
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The price and availability of offsets. |
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The amount and allocation of allowances. |
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Technological and scientific developments leading to new products or services. |
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Any potential significant physical effects of climate change (such as increased severe
weather events, changes in sea levels and changes in temperature). |
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Whether, and the extent to which, increased compliance costs are ultimately reflected in
the prices of our products and services. |
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.
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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
1Accounting 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 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 2010, 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 $1,581 million and the accumulated impairment reserve was $497 million. The weighted-average
judgmental percentage probability of ultimate failure was approximately 58 percent, and the
weighted-average amortization period was approximately three years. If that judgmental percentage
were to be raised by 5 percent across all calculations, pretax leasehold impairment expense in 2011
would increase by approximately $23 million. The remaining $5,374 million of gross capitalized
unproved property costs at year-end 2010 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 $2.8 billion is concentrated in 10 major
development areas. One of these major assets totaling $118 million is expected to move to proved
properties in 2011.
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.
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
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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 projects 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 we are actively pursuing such approvals and permits, and believe
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. 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.
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 2010, total suspended well costs were $1,013 million, compared with $908 million at
year-end 2009. For additional information on suspended wells, including an aging analysis, see
Note 8Suspended Wells, in the Notes to Consolidated Financial Statements.
Proved Reserves
Engineering estimates of the quantities of proved reserves are inherently imprecise and represent
only approximate amounts because of the judgments involved in developing such information. Reserve
estimates are based on geological and engineering assessments of in-place hydrocarbon volumes, the
production plan, historical extraction recovery and processing yield factors, installed plant
operating capacity and approved operating 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 companys 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 consistent with these authoritative guidelines. We have trained
and experienced internal engineering personnel who estimate our proved reserves held by
consolidated companies, as well as our share of equity affiliates.
Proved reserve estimates are adjusted annually in the fourth quarter and during the year if
significant changes occur, and take into account recent production and subsurface information about
each field. Also, as required by current authoritative guidelines, the estimated future date when
a field will be permanently shut down for economic reasons is based on 12-month average prices and
year-end costs. 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 developed reserves
also is important to the statement of operations because the proved developed reserve estimate for
a field serves as the denominator in the unit-of-production calculation of depreciation, depletion
and amortization of the capitalized costs for that asset. At year-end 2010, the net book value of
productive E&P properties, plants and equipment subject to a unit-of-production calculation was
approximately $56 billion and the depreciation,
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depletion and amortization recorded on these assets in 2010 was approximately $7.8 billion. The
estimated proved developed reserves for our consolidated operations were 5.6 billion BOE at the
beginning of 2010 and were 5.2 billion BOE at the end of 2010. 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 2010 would have increased by an estimated $410
million. Impairments of producing properties resulting from downward revisions of proved reserves
due to reservoir performance were not material in the last three years.
Impairments
Long-lived assets used in operations are assessed for impairment whenever changes in facts and
circumstances indicate a possible significant deterioration in future cash flows expected to be
generated by an asset group and annually in the fourth quarter following updates to corporate
planning assumptions. If, upon review, the sum of the undiscounted pretax cash flows is less than
the carrying value of the asset group, the carrying value is written down to estimated fair value.
Individual assets are grouped for impairment purposes based on a judgmental assessment of the
lowest level for which there are identifiable cash flows that are largely independent of the cash
flows of other groups of assetsgenerally on a field-by-field basis for exploration and production
assets, or at an entire complex level for downstream assets. Because there usually is a lack of
quoted market prices for long-lived assets, the fair value of impaired assets is typically
determined based on the present values of expected future cash flows using discount rates believed
to be consistent with those used by principal market participants, 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, commodity prices, operating costs,
refining margins and capital project decisions, considering all available information at the date
of review. See Note 10Impairments, 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 and annually following updates to corporate
planning assumptions. 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 investments 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 investments 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 investees financial condition and near-term prospects, and our
ability and intention to retain our 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 believed to be consistent with those used by principal market participants, plus
market analysis of comparable assets owned by the investee, if appropriate. Differing assumptions
could affect the timing and the amount of an impairment of an investment in any period. For
additional information, see the LUKOIL and NMNG sections of Note 6Investments, 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, regulatory and other
compliance considerations,
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expenditure timing, and other inputs into valuation of the obligation, including discount and
inflation rates, are also subject to change.
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 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.
Business Acquisitions
Assets Acquired and Liabilities Assumed
Accounting for the acquisition of a business requires the recognition of the consideration paid, as
well as the various assets and liabilities of the acquired business. For most assets and
liabilities, the asset or liability is recorded at its estimated fair value. The most difficult
estimates 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
finalize these fair value determinations.
Intangible Assets and Goodwill
At December 31, 2010, we had $739 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
managements judgment of the estimated fair value of these intangible assets.
In the fourth quarter of 2008, we fully impaired the recorded goodwill associated with our
Worldwide E&P reporting unit. At December 31, 2010, we had $3,633 million of goodwill remaining on
our balance sheet, all of which was attributable to the Worldwide R&M reporting unit. See Note
9Goodwill and Intangibles, in the Notes to Consolidated Financial Statements, for additional
information on intangibles and goodwill, including a detailed discussion of the facts and
circumstances leading to the goodwill impairment, as well as the judgments required by management
in the analysis leading to the impairment determination.
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 the plan. 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 assumption would increase annual benefit expense by $130 million, while a 1 percent
decrease in the return on plan assets assumption would increase annual benefit expense by $70
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, budget, continue,
could, intend, may, plan, potential, predict, seek, should, will, would,
expect, objective, projection, forecast, goal, guidance, outlook, effort, target
and similar expressions.
We based the forward-looking statements 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 as they involve assumptions that, while made in good
faith, may prove to be incorrect, and involve risks and uncertainties 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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Fluctuations in crude oil, bitumen, natural gas, LNG and natural gas liquids prices,
refining and marketing margins and margins for our chemicals business. |
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Potential failures or delays in achieving expected reserve or production levels from
existing and future oil and gas development projects due to operating hazards, drilling
risks and the inherent uncertainties in predicting reserves and reservoir performance. |
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Unsuccessful exploratory drilling activities or the inability to obtain access to
exploratory acreage. |
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Failure of new products and services to achieve market acceptance. |
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Unexpected changes in costs or technical requirements for constructing, modifying or
operating facilities for exploration and production, manufacturing, refining or
transportation projects. |
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Unexpected technological or commercial difficulties in manufacturing, refining or
transporting our products, including chemicals products. |
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Lack of, or disruptions in, adequate and reliable transportation for our crude oil,
natural gas, natural gas liquids, bitumen, LNG and refined products. |
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Inability to timely obtain or maintain permits, including those necessary for
construction of LNG terminals or regasification facilities, or refinery projects; comply
with government regulations; or make capital expenditures required to maintain compliance. |
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Failure to complete definitive agreements and feasibility studies for, and to timely
complete construction of, announced and future exploration and production, LNG, refinery
and transportation projects. |
|
|
|
|
Potential disruption or interruption of our operations due to accidents, extraordinary
weather events, civil unrest, political events or terrorism. |
|
|
|
|
International monetary conditions and exchange controls. |
|
|
|
|
Substantial investment or reduced demand for products as a result of existing or future
environmental rules and regulations. |
|
|
|
|
Liability for remedial actions, including removal and reclamation obligations, under
environmental regulations. |
|
|
|
|
Liability resulting from litigation. |
|
|
|
|
General domestic and international economic and political developments, including armed
hostilities; expropriation of assets; changes in governmental policies relating to crude
oil, bitumen, natural gas, LNG, natural gas liquids or refined product pricing, regulation
or taxation; other political, economic or diplomatic developments; and international
monetary fluctuations. |
|
|
|
|
Changes in tax and other laws, regulations (including alternative energy mandates), or
royalty rules applicable to our business. |
|
|
|
|
Limited access to capital or significantly higher cost of capital related to illiquidity
or uncertainty in the domestic or international financial markets. |
|
|
|
|
Delays in, or our inability to implement, our asset disposition plan. |
|
|
|
|
Inability to obtain economical financing for projects, construction or modification of
facilities and general corporate purposes. |
65
|
|
|
The operation and financing of our midstream and chemicals joint ventures. |
|
|
|
|
The factors generally described in Item 1ARisk Factors in this report. |
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 currency 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 capture 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 establishes the 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 Refining, Marketing and Transportation and Commercial monitors commodity price
risk and also reports to the Chief Executive Officer. The Commercial organization manages our
commercial marketing, optimizes our commodity flows and positions, and monitors related risks of
our upstream and downstream businesses.
Commodity Price Risk
We operate in the worldwide crude oil, bitumen, refined products, natural gas, natural gas liquids,
LNG 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.
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:
|
|
|
Balance physical systems. In addition to cash settlement prior to contract expiration,
exchange-traded futures contracts also may be settled by physical delivery of the
commodity, providing another source of supply to meet our refinery requirements or
marketing demand. |
|
|
|
|
Meet customer needs. Consistent with our policy to generally remain exposed to market
prices, we use swap contracts to convert fixed-price sales contracts, which are often
requested by natural gas and refined product consumers, to a floating market price. |
|
|
|
|
Manage the risk to our cash flows from price exposures on specific crude oil, natural
gas, refined product and electric power transactions. |
|
|
|
|
Enable us to use the market knowledge gained from these activities to capture market
opportunities such as moving physical commodities to more profitable locations, storing
commodities to capture seasonal or time premiums, and blending commodities to capture
quality upgrades. Derivatives may be utilized to optimize these activities. |
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, 2010, as derivative instruments. 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, 2010 and 2009, was immaterial to
our cash flows and net income attributable to ConocoPhillips.
66
The VaR for instruments held for purposes other than trading at December 31, 2010 and 2009, was
also immaterial to our cash flows and net income attributable to ConocoPhillips.
Interest Rate Risk
The following table provides information about our financial instruments that are sensitive to
changes in U.S. interest rates. The debt portion of the table presents principal cash flows and
related weighted-average interest rates by expected maturity dates. Weighted-average variable
rates are based on effective rates 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. The joint venture acquisition obligation portion of the
table presents principal cash flows of the fixed-rate 5.3 percent joint venture acquisition
obligation owed to FCCL 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 2010 and 2009 effective yield
rate of 2.33 percent and 2.63 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars Except as Indicated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Joint Venture |
|
|
|
Debt |
|
|
Acquisition Obligation |
|
|
|
Fixed |
|
|
Average |
|
|
Floating |
|
|
Average |
|
|
Fixed |
|
|
Average |
|
Expected |
|
Rate |
|
|
Interest |
|
|
Rate |
|
|
Interest |
|
|
Rate |
|
|
Interest |
|
Maturity Date |
|
Maturity |
|
|
Rate |
|
|
Maturity |
|
|
Rate |
|
|
Maturity |
|
|
Rate |
|
Year-End 2010 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2011 |
|
$ |
853 |
|
|
|
7.62 |
% |
|
$ |
- |
|
|
|
- |
% |
|
$ |
695 |
|
|
|
5.30 |
% |
2012 |
|
|
916 |
|
|
|
4.80 |
|
|
|
1,185 |
|
|
|
0.51 |
|
|
|
732 |
|
|
|
5.30 |
|
2013 |
|
|
1,262 |
|
|
|
5.33 |
|
|
|
- |
|
|
|
- |
|
|
|
772 |
|
|
|
5.30 |
|
2014 |
|
|
1,513 |
|
|
|
4.77 |
|
|
|
- |
|
|
|
- |
|
|
|
814 |
|
|
|
5.30 |
|
2015 |
|
|
1,514 |
|
|
|
4.62 |
|
|
|
64 |
|
|
|
2.05 |
|
|
|
858 |
|
|
|
5.30 |
|
Remaining years |
|
|
15,291 |
|
|
|
6.44 |
|
|
|
498 |
|
|
|
0.38 |
|
|
|
1,138 |
|
|
|
5.30 |
|
|
Total |
|
$ |
21,349 |
|
|
|
|
|
|
$ |
1,747 |
|
|
|
|
|
|
$ |
5,009 |
|
|
|
|
|
|
Fair value |
|
$ |
24,397 |
|
|
|
|
|
|
$ |
1,747 |
|
|
|
|
|
|
$ |
5,600 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year-End 2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
$ |
1,439 |
|
|
|
8.82 |
% |
|
$ |
- |
|
|
|
- |
% |
|
$ |
660 |
|
|
|
5.30 |
% |
2011 |
|
|
3,183 |
|
|
|
6.72 |
|
|
|
750 |
|
|
|
0.45 |
|
|
|
695 |
|
|
|
5.30 |
|
2012 |
|
|
1,264 |
|
|
|
4.94 |
|
|
|
1,303 |
|
|
|
0.25 |
|
|
|
732 |
|
|
|
5.30 |
|
2013 |
|
|
1,262 |
|
|
|
5.33 |
|
|
|
- |
|
|
|
- |
|
|
|
772 |
|
|
|
5.30 |
|
2014 |
|
|
1,513 |
|
|
|
4.77 |
|
|
|
3 |
|
|
|
2.01 |
|
|
|
814 |
|
|
|
5.30 |
|
Remaining years |
|
|
16,805 |
|
|
|
6.28 |
|
|
|
598 |
|
|
|
0.61 |
|
|
|
1,996 |
|
|
|
5.30 |
|
|
Total |
|
$ |
25,466 |
|
|
|
|
|
|
$ |
2,654 |
|
|
|
|
|
|
$ |
5,669 |
|
|
|
|
|
|
Fair value |
|
$ |
27,911 |
|
|
|
|
|
|
$ |
2,654 |
|
|
|
|
|
|
$ |
6,276 |
|
|
|
|
|
|
During the second quarter of 2010, we executed interest rate swaps to synthetically convert $500
million of our 4.60% fixed-rate notes due in 2015 to a floating rate based on the London Interbank
Offered Rate (LIBOR). These swaps qualify for and are designated as fair-value hedges using the
short-cut method of hedge accounting. The short-cut method permits the assumption that changes in
the value of the derivative perfectly offset changes in the value of the debt; therefore, no gain
or loss has been recognized due to hedge ineffectiveness.
67
The average pay rate is comprised of the LIBOR index rate and the swap spread. The swap spread
consists primarily of the difference between the 4.60% fixed receive rate and the fixed rates for
similar instruments at the time of execution.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars Except as Indicated |
|
|
|
Interest Rate Derivatives |
|
|
|
|
|
|
|
Average |
|
|
Average |
|
Expected Maturity Date |
|
Notional |
|
|
Pay Rate |
|
|
Receive Rate |
|
Year-End 2010 |
|
|
|
|
|
|
|
|
|
|
|
|
20112015 |
|
$ |
- |
|
|
|
- |
% |
|
|
- |
% |
2015fixed to variable |
|
|
500 |
|
|
|
2.33 |
|
|
|
4.60 |
|
Remaining years |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Total |
|
$ |
500 |
|
|
|
|
|
|
|
|
|
|
Fair Value |
|
$ |
20 |
|
|
|
|
|
|
|
|
|
|
Foreign Currency Exchange 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 certain foreign currency exchange rate exposures, such as firm commitments for capital
projects or local currency tax payments, dividends and cash returns from net investments in foreign
affiliates to be remitted within the coming year.
At December 31, 2010 and 2009, we held foreign currency exchange forwards hedging cross-border
commercial activity and foreign currency exchange swaps hedging short-term intercompany loans
between European subsidiaries and a U.S. subsidiary. Although these forwards and swaps hedge
exposures to fluctuations in exchange rates, we elected not to utilize hedge accounting. As a result, the change in the fair value of these foreign currency
exchange derivatives 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, and since our aggregate position in the forwards was not material, there
would be no material impact to our income from an adverse hypothetical 10 percent change in the
December 31, 2010 or 2009, exchange rates. The notional and fair market values of these positions
at December 31, 2010 and 2009, were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In Millions |
|
Foreign Currency Exchange Derivatives |
|
Notional* |
|
|
Fair Market Value** |
|
|
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
|
|
|
|
Sell U.S. dollar, buy euro |
|
USD |
|
|
- |
|
|
|
246 |
|
|
$ |
- |
|
|
|
(2 |
) |
Sell U.S. dollar, buy British pound |
|
USD |
|
|
4 |
|
|
|
1,664 |
|
|
|
(3 |
) |
|
|
(16 |
) |
Sell U.S. dollar, buy Canadian dollar |
|
USD |
|
|
562 |
|
|
|
554 |
|
|
|
8 |
|
|
|
34 |
|
Sell U.S. dollar, buy Norwegian kroner |
|
USD |
|
|
3 |
|
|
|
744 |
|
|
|
- |
|
|
|
(4 |
) |
Sell U.S. dollar, buy Australian dollar |
|
USD |
|
|
- |
|
|
|
3 |
|
|
|
- |
|
|
|
- |
|
Sell euro, buy British pound |
|
EUR |
|
|
253 |
|
|
|
267 |
|
|
|
1 |
|
|
|
(14 |
) |
|
*Denominated in U.S. dollars (USD) and euro (EUR).
**Denominated in U.S. dollars.
For additional information about our use of derivative instruments, see Note 16Financial
Instruments and Derivative Contracts, in the Notes to Consolidated Financial Statements.
68
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
CONOCOPHILLIPS
INDEX TO FINANCIAL STATEMENTS
|
|
|
|
|
Page |
|
|
70 |
|
|
|
|
|
71 |
|
|
|
|
|
72 |
|
|
|
|
|
73 |
|
|
|
|
|
74 |
|
|
|
|
|
75 |
|
|
|
|
|
76 |
|
|
|
|
|
77 |
|
|
|
Supplementary Information |
|
|
|
|
|
|
|
137 |
|
|
|
|
|
165 |
|
|
|
|
|
166 |
69
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 companys 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
management believes are reasonable under the circumstances. The companys 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 companys 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 companys 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 companys internal control over financial reporting as
of December 31, 2010. In making this assessment, it used the criteria set forth by the Committee
of Sponsoring Organizations of the Treadway Commission in Internal ControlIntegrated Framework.
Based on our assessment, we believe the companys internal control over financial reporting was
effective as of December 31, 2010.
Ernst & Young LLP has issued an audit report on the companys internal control over financial
reporting as of December 31, 2010, and their report is included herein.
|
|
|
|
|
|
|
|
|
/s/ James J. Mulva
|
|
/s/ Jeff W. Sheets |
|
|
|
James J. Mulva
|
|
Jeff W. Sheets |
Chairman and
|
|
Senior Vice President, Finance |
Chief Executive Officer
|
|
and Chief Financial Officer |
February 23, 2011
70
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,
2010 and 2009, and the related consolidated statements of operations, changes in equity, and cash
flows for each of the three years in the period ended December 31, 2010. 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 Companys
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, 2010 and 2009, and
the consolidated results of its operations and its cash flows for each of the three years in the
period ended December 31, 2010, 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 2010 ConocoPhillips changed the
method used to determine its equity method share of LUKOILs earnings. In addition, as discussed
in Note 2, in 2009 ConocoPhillips changed its reserve estimates and related disclosures as a result
of adopting new oil and gas reserve estimation and disclosure requirements.
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,
2010, based on criteria established in Internal ControlIntegrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 23,
2011 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Houston, Texas
February 23, 2011
71
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, 2010,
based on criteria established in Internal ControlIntegrated 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 Companys 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 companys 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
companys 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 companys 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, 2010, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight
Board (United States), the 2010 consolidated financial statements of ConocoPhillips and our report
dated February 23, 2011 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Houston, Texas
February 23, 2011
72
|
|
|
Consolidated Statement of Operations
|
|
ConocoPhillips |
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31 |
|
Millions of Dollars |
|
|
|
2010 |
|
|
2009 |
** |
|
2008 |
** |
Revenues and Other Income |
|
|
|
|
|
|
|
|
|
|
|
|
Sales and other operating revenues* |
|
$ |
189,441 |
|
|
|
149,341 |
|
|
|
240,842 |
|
Equity in earnings of affiliates |
|
|
3,133 |
|
|
|
2,531 |
|
|
|
4,999 |
|
Gain on dispositions |
|
|
5,803 |
|
|
|
160 |
|
|
|
891 |
|
Other income |
|
|
278 |
|
|
|
358 |
|
|
|
199 |
|
|
Total Revenues and Other Income |
|
|
198,655 |
|
|
|
152,390 |
|
|
|
246,931 |
|
|
Costs and Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
Purchased crude oil, natural gas and products |
|
|
135,751 |
|
|
|
102,433 |
|
|
|
168,663 |
|
Production and operating expenses |
|
|
10,635 |
|
|
|
10,339 |
|
|
|
11,818 |
|
Selling, general and administrative expenses |
|
|
2,005 |
|
|
|
1,830 |
|
|
|
2,229 |
|
Exploration expenses |
|
|
1,155 |
|
|
|
1,182 |
|
|
|
1,337 |
|
Depreciation, depletion and amortization |
|
|
9,060 |
|
|
|
9,295 |
|
|
|
9,012 |
|
Impairments |
|
|
|
|
|
|
|
|
|
|
|
|
Goodwill |
|
|
- |
|
|
|
- |
|
|
|
25,443 |
|
LUKOIL investment |
|
|
- |
|
|
|
- |
|
|
|
7,496 |
|
Other |
|
|
1,780 |
|
|
|
535 |
|
|
|
1,686 |
|
Taxes other than income taxes* |
|
|
16,793 |
|
|
|
15,529 |
|
|
|
20,637 |
|
Accretion on discounted liabilities |
|
|
447 |
|
|
|
422 |
|
|
|
418 |
|
Interest and debt expense |
|
|
1,187 |
|
|
|
1,289 |
|
|
|
935 |
|
Foreign currency transaction (gains) losses |
|
|
92 |
|
|
|
(46 |
) |
|
|
117 |
|
|
Total Costs and Expenses |
|
|
178,905 |
|
|
|
142,808 |
|
|
|
249,791 |
|
|
Income (loss) before income taxes |
|
|
19,750 |
|
|
|
9,582 |
|
|
|
(2,860 |
) |
Provision for income taxes |
|
|
8,333 |
|
|
|
5,090 |
|
|
|
13,419 |
|
|
Net income (loss) |
|
|
11,417 |
|
|
|
4,492 |
|
|
|
(16,279 |
) |
Less: net income attributable to noncontrolling interests |
|
|
(59 |
) |
|
|
(78 |
) |
|
|
(70 |
) |
|
Net Income (Loss) Attributable to ConocoPhillips |
|
$ |
11,358 |
|
|
|
4,414 |
|
|
|
(16,349 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) Attributable to ConocoPhillips Per Share
of
Common Stock (dollars) |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
7.68 |
|
|
|
2.96 |
|
|
|
(10.73 |
) |
Diluted |
|
|
7.62 |
|
|
|
2.94 |
|
|
|
(10.73 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Common Shares Outstanding (in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
1,479,330 |
|
|
|
1,487,650 |
|
|
|
1,523,432 |
|
Diluted |
|
|
1,491,067 |
|
|
|
1,497,608 |
|
|
|
1,523,432 |
|
|
*Includes excise taxes on petroleum products sales: |
|
$ |
13,689 |
|
|
|
13,325 |
|
|
|
15,418 |
|
**Recast to reflect a change in accounting principle. See Note 2Changes in
Accounting Principles, for more information. Also, certain amounts have been
reclassified to conform to current-year presentation. |
See Notes to Consolidated Financial Statements.
73
|
|
|
Consolidated Balance Sheet
|
|
ConocoPhillips |
|
|
|
|
|
|
|
|
|
At December 31 |
|
Millions of Dollars |
|
|
|
2010 |
|
|
2009 |
** |
Assets |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
9,454 |
|
|
|
542 |
|
Short-term investments* |
|
|
973 |
|
|
|
- |
|
Accounts and notes receivable (net of allowance of $32 million in 2010
and $76 million in 2009) |
|
|
13,787 |
|
|
|
11,861 |
|
Accounts and notes receivablerelated parties |
|
|
2,025 |
|
|
|
1,354 |
|
Investment in LUKOIL |
|
|
1,083 |
|
|
|
- |
|
Inventories |
|
|
5,197 |
|
|
|
4,940 |
|
Prepaid expenses and other current assets |
|
|
2,141 |
|
|
|
2,470 |
|
|
Total Current Assets |
|
|
34,660 |
|
|
|
21,167 |
|
Investments and long-term receivables |
|
|
31,581 |
|
|
|
35,742 |
|
Loans and advancesrelated parties |
|
|
2,180 |
|
|
|
2,352 |
|
Net properties, plants and equipment |
|
|
82,554 |
|
|
|
87,708 |
|
Goodwill |
|
|
3,633 |
|
|
|
3,638 |
|
Intangibles |
|
|
801 |
|
|
|
823 |
|
Other assets |
|
|
905 |
|
|
|
708 |
|
|
Total Assets |
|
$ |
156,314 |
|
|
|
152,138 |
|
|
|
|
|
|
|
|
|
|
|
Liabilities |
|
|
|
|
|
|
|
|
Accounts payable |
|
$ |
16,613 |
|
|
|
14,168 |
|
Accounts payablerelated parties |
|
|
1,786 |
|
|
|
1,317 |
|
Short-term debt |
|
|
936 |
|
|
|
1,728 |
|
Accrued income and other taxes |
|
|
4,874 |
|
|
|
3,402 |
|
Employee benefit obligations |
|
|
1,081 |
|
|
|
846 |
|
Other accruals |
|
|
2,129 |
|
|
|
2,234 |
|
|
Total Current Liabilities |
|
|
27,419 |
|
|
|
23,695 |
|
Long-term debt |
|
|
22,656 |
|
|
|
26,925 |
|
Asset retirement obligations and accrued environmental costs |
|
|
9,199 |
|
|
|
8,713 |
|
Joint venture acquisition obligationrelated party |
|
|
4,314 |
|
|
|
5,009 |
|
Deferred income taxes |
|
|
17,335 |
|
|
|
17,956 |
|
Employee benefit obligations |
|
|
3,683 |
|
|
|
4,130 |
|
Other liabilities and deferred credits |
|
|
2,599 |
|
|
|
3,097 |
|
|
Total Liabilities |
|
|
87,205 |
|
|
|
89,525 |
|
|
|
|
|
|
|
|
|
|
|
Equity |
|
|
|
|
|
|
|
|
Common stock (2,500,000,000 shares authorized at $.01 par value) |
|
|
|
|
|
|
|
|
Issued (20101,740,529,279 shares; 20091,733,345,558 shares) |
|
|
|
|
|
|
|
|
Par value |
|
|
17 |
|
|
|
17 |
|
Capital in excess of par |
|
|
44,132 |
|
|
|
43,681 |
|
Grantor trusts (at cost: 201036,890,375 shares; 200938,742,261 shares) |
|
|
(633 |
) |
|
|
(667 |
) |
Treasury stock (at cost: 2010272,873,537 shares;
2009208,346,815 shares) |
|
|
(20,077 |
) |
|
|
(16,211 |
) |
Accumulated other comprehensive income |
|
|
4,773 |
|
|
|
3,065 |
|
Unearned employee compensation |
|
|
(47 |
) |
|
|
(76 |
) |
Retained earnings |
|
|
40,397 |
|
|
|
32,214 |
|
|
Total Common Stockholders Equity |
|
|
68,562 |
|
|
|
62,023 |
|
Noncontrolling interests |
|
|
547 |
|
|
|
590 |
|
|
Total Equity |
|
|
69,109 |
|
|
|
62,613 |
|
|
Total Liabilities and Equity |
|
$ |
156,314 |
|
|
|
152,138 |
|
|
*Includes marketable securities of: |
|
$ |
602 |
|
|
|
- |
|
**Recast to reflect a change in accounting principle. See Note 2Changes in Accounting Principles, for more information. |
See Notes to Consolidated Financial Statements.
74
|
|
|
Consolidated Statement of Cash Flows
|
|
ConocoPhillips |
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31 |
|
Millions of Dollars |
|
|
|
2010 |
|
|
2009 |
* |
|
2008 |
* |
Cash Flows From Operating Activities |
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
11,417 |
|
|
|
4,492 |
|
|
|
(16,279 |
) |
Adjustments to reconcile net income (loss) to net cash provided by
operating activities |
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
|
|
9,060 |
|
|
|
9,295 |
|
|
|
9,012 |
|
Impairments |
|
|
1,780 |
|
|
|
535 |
|
|
|
34,625 |
|
Dry hole costs and leasehold impairments |
|
|
477 |
|
|
|
606 |
|
|
|
698 |
|
Accretion on discounted liabilities |
|
|
447 |
|
|
|
422 |
|
|
|
418 |
|
Deferred taxes |
|
|
(878 |
) |
|
|
(1,115 |
) |
|
|
(414 |
) |
Undistributed equity earnings |
|
|
(1,073 |
) |
|
|
(1,254 |
) |
|
|
(2,357 |
) |
Gain on dispositions |
|
|
(5,803 |
) |
|
|
(160 |
) |
|
|
(891 |
) |
Other |
|
|
(249 |
) |
|
|
196 |
|
|
|
(1,135 |
) |
Working capital adjustments |
|
|
|
|
|
|
|
|
|
|
|
|
Decrease (increase) in accounts and notes receivable |
|
|
(2,427 |
) |
|
|
(1,106 |
) |
|
|
4,225 |
|
Decrease (increase) in inventories |
|
|
(363 |
) |
|
|
320 |
|
|
|
(1,321 |
) |
Decrease (increase) in prepaid expenses and other current assets |
|
|
43 |
|
|
|
282 |
|
|
|
(724 |
) |
Increase (decrease) in accounts payable |
|
|
2,887 |
|
|
|
1,612 |
|
|
|
(3,874 |
) |
Increase (decrease) in taxes and other accruals |
|
|
1,727 |
|
|
|
(1,646 |
) |
|
|
675 |
|
|
Net Cash Provided by Operating Activities |
|
|
17,045 |
|
|
|
12,479 |
|
|
|
22,658 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows From Investing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures and investments |
|
|
(9,761 |
) |
|
|
(10,861 |
) |
|
|
(19,099 |
) |
Proceeds from asset dispositions |
|
|
15,372 |
|
|
|
1,270 |
|
|
|
1,640 |
|
Purchases of short-term investments |
|
|
(982 |
) |
|
|
- |
|
|
|
- |
|
Long-term advances/loansrelated parties |
|
|
(313 |
) |
|
|
(525 |
) |
|
|
(163 |
) |
Collection of advances/loansrelated parties |
|
|
115 |
|
|
|
93 |
|
|
|
34 |
|
Other |
|
|
234 |
|
|
|
88 |
|
|
|
(28 |
) |
|
Net Cash Provided by (Used in) Investing Activities |
|
|
4,665 |
|
|
|
(9,935 |
) |
|
|
(17,616 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows From Financing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of debt |
|
|
118 |
|
|
|
9,087 |
|
|
|
7,657 |
|
Repayment of debt |
|
|
(5,320 |
) |
|
|
(7,858 |
) |
|
|
(1,897 |
) |
Issuance of company common stock |
|
|
133 |
|
|
|
13 |
|
|
|
198 |
|
Repurchase of company common stock |
|
|
(3,866 |
) |
|
|
- |
|
|
|
(8,249 |
) |
Dividends paid on company common stock |
|
|
(3,175 |
) |
|
|
(2,832 |
) |
|
|
(2,854 |
) |
Other |
|
|
(709 |
) |
|
|
(1,265 |
) |
|
|
(619 |
) |
|
Net Cash Used in Financing Activities |
|
|
(12,819 |
) |
|
|
(2,855 |
) |
|
|
(5,764 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of Exchange Rate Changes on Cash and Cash Equivalents |
|
|
21 |
|
|
|
98 |
|
|
|
21 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Change in Cash and Cash Equivalents |
|
|
8,912 |
|
|
|
(213 |
) |
|
|
(701 |
) |
Cash and cash equivalents at beginning of year |
|
|
542 |
|
|
|
755 |
|
|
|
1,456 |
|
|
Cash and Cash Equivalents at End of Year |
|
$ |
9,454 |
|
|
|
542 |
|
|
|
755 |
|
|
*Recast to reflect a change in accounting principle. See Note 2Changes in Accounting Principles, for more information.
See Notes to Consolidated Financial Statements.
75
|
|
|
Consolidated Statement of Changes in Equity
|
|
ConocoPhillips |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars |
|
|
|
Attributable to ConocoPhillips |
|
|
|
|
|
|
|
|
|
Common Stock |
|
|
Accum. Other |
|
|
Unearned |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Par |
|
|
Capital in |
|
|
Treasury |
|
|
Grantor |
|
|
Comprehensive |
|
|
Employee |
|
|
Retained |
|
|
Comprehensive |
|
|
Noncontrolling |
|
|
|
|
|
|
Value |
|
|
Excess of Par |
|
|
Stock |
|
|
Trusts |
|
|
Income (Loss) |
|
|
Compensation |
|
|
Earnings |
|
|
Income (Loss) |
|
|
Interests |
|
|
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2007* |
|
$ |
17 |
|
|
|
42,724 |
|
|
|
(7,969 |
) |
|
|
(731 |
) |
|
|
4,560 |
|
|
|
(128 |
) |
|
|
49,861 |
|
|
|
|
|
|
|
1,173 |
|
|
|
89,507 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(16,349 |
) |
|
|
(16,349 |
) |
|
|
70 |
|
|
|
(16,279 |
) |
Other comprehensive income (loss) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Defined benefit pension plans |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net prior service cost |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
22 |
|
|
|
|
|
|
|
|
|
|
|
22 |
|
|
|
|
|
|
|
22 |
|
Net actuarial loss |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(950 |
) |
|
|
|
|
|
|
|
|
|
|
(950 |
) |
|
|
|
|
|
|
(950 |
) |
Nonsponsored plans |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(41 |
) |
|
|
|
|
|
|
|
|
|
|
(41 |
) |
|
|
|
|
|
|
(41 |
) |
Foreign currency translation adjustments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(5,464 |
) |
|
|
|
|
|
|
|
|
|
|
(5,464 |
) |
|
|
|
|
|
|
(5,464 |
) |
Hedging activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2 |
) |
|
|
|
|
|
|
|
|
|
|
(2 |
) |
|
|
|
|
|
|
(2 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income (loss) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(22,784 |
) |
|
|
70 |
|
|
|
(22,714 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash dividends paid on company common stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,854 |
) |
|
|
|
|
|
|
|
|
|
|
(2,854 |
) |
Repurchase of company common stock |
|
|
|
|
|
|
|
|
|
|
(8,242 |
) |
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(8,241 |
) |
Distributions to noncontrolling interests and other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(143 |
) |
|
|
(143 |
) |
Distributed under benefit plans |
|
|
|
|
|
|
672 |
|
|
|
|
|
|
|
28 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
700 |
|
Recognition of unearned compensation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
26 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
26 |
|
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(16 |
) |
|
|
|
|
|
|
|
|
|
|
(16 |
) |
|
December 31, 2008* |
|
|
17 |
|
|
|
43,396 |
|
|
|
(16,211 |
) |
|
|
(702 |
) |
|
|
(1,875 |
) |
|
|
(102 |
) |
|
|
30,642 |
|
|
|
|
|
|
|
1,100 |
|
|
|
56,265 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,414 |
|
|
|
4,414 |
|
|
|
78 |
|
|
|
4,492 |
|
Other comprehensive income (loss) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Defined benefit pension plans |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net prior service cost |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7 |
|
|
|
|
|
|
|
|
|
|
|
7 |
|
|
|
|
|
|
|
7 |
|
Net actuarial loss |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(99 |
) |
|
|
|
|
|
|
|
|
|
|
(99 |
) |
|
|
|
|
|
|
(99 |
) |
Nonsponsored plans |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
22 |
|
|
|
|
|
|
|
|
|
|
|
22 |
|
|
|
|
|
|
|
22 |
|
Foreign currency translation adjustments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,007 |
|
|
|
|
|
|
|
|
|
|
|
5,007 |
|
|
|
|
|
|
|
5,007 |
|
Hedging activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
3 |
|
|
|
|
|
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,354 |
|
|
|
78 |
|
|
|
9,432 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash dividends paid on company common stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,832 |
) |
|
|
|
|
|
|
|
|
|
|
(2,832 |
) |
Distributions to noncontrolling interests and other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(588 |
) |
|
|
(588 |
) |
Distributed under benefit plans |
|
|
|
|
|
|
285 |
|
|
|
|
|
|
|
35 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
320 |
|
Recognition of unearned compensation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
26 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
26 |
|
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(10 |
) |
|
|
|
|
|
|
|
|
|
|
(10 |
) |
|
December 31, 2009* |
|
|
17 |
|
|
|
43,681 |
|
|
|
(16,211 |
) |
|
|
(667 |
) |
|
|
3,065 |
|
|
|
(76 |
) |
|
|
32,214 |
|
|
|
|
|
|
|
590 |
|
|
|
62,613 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11,358 |
|
|
|
11,358 |
|
|
|
59 |
|
|
|
11,417 |
|
Other comprehensive income (loss) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Defined benefit pension plans |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net prior service cost |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
- |
|
|
|
|
|
|
|
- |
|
Net actuarial gain |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
133 |
|
|
|
|
|
|
|
|
|
|
|
133 |
|
|
|
|
|
|
|
133 |
|
Nonsponsored plans |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13 |
|
|
|
|
|
|
|
|
|
|
|
13 |
|
|
|
|
|
|
|
13 |
|
Net unrealized gain on securities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
158 |
|
|
|
|
|
|
|
|
|
|
|
158 |
|
|
|
|
|
|
|
158 |
|
Foreign currency translation adjustments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,404 |
|
|
|
|
|
|
|
|
|
|
|
1,404 |
|
|
|
|
|
|
|
1,404 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13,066 |
|
|
|
59 |
|
|
|
13,125 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash dividends paid on company common stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3,175 |
) |
|
|
|
|
|
|
|
|
|
|
(3,175 |
) |
Repurchase of company common stock |
|
|
|
|
|
|
|
|
|
|
(3,866 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3,866 |
) |
Distributions to noncontrolling interests and other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(102 |
) |
|
|
(102 |
) |
Distributed under benefit plans |
|
|
|
|
|
|
451 |
|
|
|
|
|
|
|
34 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
485 |
|
Recognition of unearned compensation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
29 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
29 |
|
|
December 31, 2010 |
|
$ |
17 |
|
|
|
44,132 |
|
|
|
(20,077 |
) |
|
|
(633 |
) |
|
|
4,773 |
|
|
|
(47 |
) |
|
|
40,397 |
|
|
|
|
|
|
|
547 |
|
|
|
69,109 |
|
|
*Recast to reflect a change in accounting principle. See Note 2Changes in Accounting Principles, for more information.
See Notes to Consolidated Financial Statements.
76
|
|
|
Notes to Consolidated Financial Statements
|
|
ConocoPhillips |
Note 1Accounting Policies
n |
|
Consolidation Principles and
InvestmentsOur consolidated financial
statements include the accounts of
majority-owned, controlled subsidiaries
and variable interest entities where we
are the primary beneficiary. The equity
method is used to account for investments
in affiliates in which we have the
ability to exert significant influence
over the affiliates operating and
financial policies. When we do not have
the ability to exert significant
influence, the investment is either
classified as available-for-sale if fair
value is readily determinable, or the
cost method is used if fair value is not
readily determinable. Undivided
interests in oil and gas joint ventures,
pipelines, natural gas plants and
terminals are consolidated on a
proportionate basis. Other securities
and investments are generally carried at
cost. |
n |
|
Foreign Currency TranslationAdjustments
resulting from the process of translating
foreign functional currency financial
statements into U.S. dollars are included
in accumulated other comprehensive income
in common stockholders equity.
Foreign currency transaction gains and
losses are included in current earnings.
Most of our foreign operations use their
local currency as the functional
currency. |
n |
|
Use of EstimatesThe preparation of
financial statements in conformity with
accounting principles generally accepted
in the United States requires management
to make estimates and assumptions that
affect the reported amounts of assets,
liabilities, revenues and expenses, and
the disclosures of contingent assets and
liabilities. Actual results could differ
from these estimates. |
n |
|
Revenue RecognitionRevenues associated
with sales of crude oil, bitumen, natural
gas, liquefied natural gas (LNG), natural
gas liquids, petroleum and chemical
products, and other items are recognized
when title passes to the customer, which
is when the risk of ownership passes to
the purchaser and physical delivery of
goods occurs, either immediately or
within a fixed delivery schedule that is
reasonable and customary in the industry. |
|
|
Revenues associated with producing properties in which we have an interest with other producers
are recognized based on the actual volumes we sold during the period. Any differences between
volumes sold and entitlement volumes, based on our net working interest, which are deemed to be
nonrecoverable through remaining production, are recognized as accounts receivable or accounts
payable, as appropriate. Cumulative differences between volumes sold and entitlement volumes
are generally not significant. |
|
|
Revenues associated with transactions commonly called buy/sell contracts, in which the purchase
and sale of inventory with the same counterparty are entered into in contemplation of one
another, are combined and reported net (i.e., on the same statement of operations line). |
n |
|
Shipping and Handling CostsOur Exploration and Production (E&P)
segment includes shipping and handling costs in production and
operating expenses for production activities. Transportation
costs related to E&P marketing activities are recorded in
purchased crude oil, natural gas and products. The Refining and
Marketing (R&M) segment records shipping and handling costs in
purchased crude oil, natural gas and products. Freight costs
billed to customers are recorded as a component of revenue. |
n |
|
Cash EquivalentsCash equivalents are highly liquid, short-term
investments that are readily convertible to known amounts of cash
and have original maturities of 90 days or less from their date of
purchase. They are carried at cost plus accrued interest, which
approximates fair value. |
n |
|
Short-Term InvestmentsInvestments in bank time deposits and
marketable securities (commercial paper and government
obligations) with original maturities of greater than 90 days but
less than one year |
77
|
|
are classified as short-term investments. See Note 16Financial Instruments and Derivative
Contracts, for additional information on these held-to-maturity financial instruments. |
n |
|
InventoriesWe have several valuation methods for our various
types of inventories and consistently use the following methods
for each type of inventory. Crude oil and petroleum products
inventories are valued at the lower of cost or market in the
aggregate, primarily on the last-in, first-out (LIFO) basis. Any
necessary lower-of-cost-or-market write-downs at year end are
recorded as permanent adjustments to the LIFO cost basis. LIFO is
used to better match current inventory costs with current revenues
and to meet tax-conformity requirements. Costs include both
direct and indirect expenditures incurred in bringing an item or
product to its existing condition and location, but not
unusual/nonrecurring costs or research and development costs.
Materials, supplies and other miscellaneous inventories, such as
tubular goods and well equipment, are valued under various
methods, including the weighted-average-cost method, and the
first-in, first-out (FIFO) method, consistent with industry
practice. |
n |
|
Fair Value MeasurementsWe categorize assets and liabilities
measured at fair value into one of three different levels
depending on the observability of the inputs employed in the
measurement. Level 1 inputs are quoted prices in active markets
for identical assets or liabilities. Level 2 inputs are
observable inputs other than quoted prices included within Level 1
for the asset or liability, either directly or indirectly through
market-corroborated inputs. Level 3 inputs are unobservable
inputs for the asset or liability reflecting significant
modifications to observable related market data or our assumptions
about pricing by market participants. |
n |
|
Derivative InstrumentsDerivative instruments are recorded on the
balance sheet at fair value. If the right of offset exists and
certain other criteria are met, derivative assets and liabilities
with the same counterparty are netted on the balance sheet and the
collateral payable or receivable is netted against derivative
assets and derivative liabilities, respectively. |
|
|
Recognition and classification of the gain or loss that results from recording and adjusting a
derivative to fair value depends on the purpose for issuing or holding the derivative. Gains
and losses from derivatives not accounted for as hedges are recognized immediately in earnings.
For derivative instruments that are designated and qualify as a fair value hedge, the gains or
losses from adjusting the derivative to its fair value will be immediately recognized in
earnings and, to the extent the hedge is effective, offset the concurrent recognition of
changes in the fair value of the hedged item. Gains or losses from derivative instruments that
are designated and qualify as a cash flow hedge or hedge of a net investment in a foreign
entity are recognized in other comprehensive income and appear on the balance sheet in
accumulated other comprehensive income until the hedged transaction is recognized in
earnings; however, to the extent the change in the value of the derivative exceeds the change
in the anticipated cash flows of the hedged transaction, the excess gains or losses will be
recognized immediately in earnings. |
n |
|
Oil and Gas Exploration and DevelopmentOil and gas exploration and development costs are
accounted for using the successful efforts method of accounting. |
|
|
Property Acquisition CostsOil and gas leasehold acquisition costs are capitalized and
included in the balance sheet caption properties, plants and equipment. Leasehold
impairment is recognized based on exploratory experience and managements judgment. Upon
achievement of all conditions necessary for reserves to be classified as proved, the
associated leasehold costs are reclassified to proved properties. |
|
|
Exploratory CostsGeological and geophysical costs and the costs of carrying and retaining
undeveloped properties are expensed as incurred. Exploratory well costs are capitalized, or
suspended, on the balance sheet pending further evaluation of whether economically
recoverable reserves have been found. If economically recoverable reserves are not found,
exploratory well costs are expensed as dry holes. 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. 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 |
78
|
|
potential oil and gas field or while we seek government or co-venturer approval of
development plans
or seek environmental permitting. Once all required approvals and permits have been
obtained, the projects are moved into the development phase, and the oil and gas resources
are designated as proved reserves. |
|
|
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
dry holes when it judges the potential field does not warrant further investment in the near
term. See Note 8Suspended Wells, for additional information on suspended wells. |
|
|
Development CostsCosts incurred to drill and equip development wells, including
unsuccessful development wells, are capitalized. |
|
|
Depletion and AmortizationLeasehold costs of producing properties are depleted using the
unit-of-production method based on estimated proved oil and gas reserves. Amortization of
intangible development costs is based on the unit-of-production method using estimated
proved developed oil and gas reserves. |
n |
|
Capitalized InterestInterest from external borrowings is
capitalized on major projects with an expected construction period
of one year or longer. Capitalized interest is added to the cost
of the underlying asset and is amortized over the useful lives of
the assets in the same manner as the underlying assets. |
n |
|
Intangible Assets Other Than GoodwillIntangible assets that have
finite useful lives are amortized by the straight-line method over
their useful lives. Intangible assets that have indefinite useful
lives are not amortized but are tested at least annually for
impairment. Each reporting period, we evaluate the remaining
useful lives of intangible assets not being amortized to determine
whether events and circumstances continue to support indefinite
useful lives. These indefinite lived intangibles are considered
impaired if the fair value of the intangible asset is lower than
net book value. The fair value of intangible assets is determined
based on quoted market prices in active markets, if available. If
quoted market prices are not available, fair value of intangible
assets is determined based upon the present values of expected
future cash flows using discount rates believed to be consistent
with those used by principal market participants, or upon
estimated replacement cost, if expected future cash flows from the
intangible asset are not determinable. |
n |
|
GoodwillGoodwill resulting from a business combination is not
amortized but is tested at least annually for impairment. If the
fair value of a reporting unit is less than the recorded book
value of the reporting units assets (including goodwill), less
liabilities, then a hypothetical purchase price allocation is
performed on the reporting units assets and liabilities using the
fair value of the reporting unit as the purchase price in the
calculation. If the amount of goodwill resulting from this
hypothetical purchase price allocation is less than the recorded
amount of goodwill, the recorded goodwill is written down to the
new amount. For purposes of goodwill impairment calculations, two
reporting units have been determined: Worldwide Exploration and
Production and Worldwide Refining and Marketing. |
n |
|
Depreciation and AmortizationDepreciation and amortization of
properties, plants and equipment on producing hydrocarbon
properties and certain pipeline assets (those which are expected
to have a declining utilization pattern), are determined by the
unit-of-production method. Depreciation and amortization of all
other properties, plants and equipment are determined by either
the individual-unit-straight-line method or the
group-straight-line method (for those individual units that are
highly integrated with other units). |
n |
|
Impairment of Properties, Plants and EquipmentProperties, plants
and equipment used in operations are assessed for impairment
whenever changes in facts and circumstances indicate a possible
significant deterioration in the future cash flows expected to be
generated by an asset group and annually in the fourth quarter
following updates to corporate planning assumptions. If, upon
review, the sum of the undiscounted pretax cash flows is less than
the carrying value of the asset group, the carrying value is
written down to estimated fair value through additional
amortization or depreciation provisions and |
79
|
|
reported as impairments in the periods in which the determination of the impairment is made.
Individual assets are grouped for impairment purposes at the lowest level for which there are
identifiable cash flows that are largely independent of the cash flows of other groups of
assetsgenerally on a field-by-field basis for exploration and production assets, or at an
entire complex level for downstream assets. Because there usually is a lack of quoted market
prices for long-lived assets, the fair value of impaired assets is typically determined based
on the present values of expected future cash flows using discount rates believed to be
consistent with those used by principal market participants or based on a multiple of operating
cash flow validated with historical market transactions of similar assets where possible.
Long-lived assets committed by management for disposal within one year are accounted for at the
lower of amortized cost or fair value, less cost to sell, with fair value determined using a
binding negotiated price, if available, or present value of expected future cash flows as
previously described. |
|
|
The expected future cash flows used for impairment reviews and related fair value calculations
are based on estimated future production volumes, prices and costs, considering all available
evidence at the date of review. If the future production price risk has been hedged, the
hedged price is used in the calculations for the period and quantities hedged. The impairment
review includes cash flows from proved developed and undeveloped reserves, including any
development expenditures necessary to achieve that production. Additionally, when probable
reserves exist, an appropriate risk-adjusted amount of these reserves may be included in the
impairment calculation. |
n |
|
Impairment of Investments in Nonconsolidated EntitiesInvestments
in nonconsolidated entities are assessed for impairment whenever
changes in the facts and circumstances indicate a loss in value
has occurred and annually following updates to corporate planning
assumptions. When such a condition is judgmentally determined to
be other than temporary, the carrying value of the investment is
written down to fair value. The fair value of the impaired
investment is based on quoted market prices, if available, or upon
the present value of expected future cash flows using discount
rates believed to be consistent with those used by principal
market participants, plus market analysis of comparable assets
owned by the investee, if appropriate. |
n |
|
Maintenance and RepairsCosts of maintenance and repairs, which
are not significant improvements, are expensed when incurred. |
n |
|
Advertising CostsProduction costs of media advertising are
deferred until the first public showing of the advertisement.
Advances to secure advertising slots at specific sporting or other
events are deferred until the event occurs. All other advertising
costs are expensed as incurred, unless the cost has benefits that
clearly extend beyond the interim period in which the expenditure
is made, in which case the advertising cost is deferred and
amortized ratably over the interim periods that clearly benefit
from the expenditure. |
n |
|
Property DispositionsWhen complete units of depreciable property
are sold, the asset cost and related accumulated depreciation are
eliminated, with any gain or loss reflected in the Gain on
dispositions line of our consolidated statement of operations.
When less than complete units of depreciable property are disposed
of or retired, the difference between asset cost and salvage value
is charged or credited to accumulated depreciation. |
n |
|
Asset Retirement Obligations and Environmental CostsFair value
of legal obligations to retire and remove long-lived assets are
recorded in the period in which the obligation is incurred
(typically when the asset is installed at the production
location). When the liability is initially recorded, we
capitalize this cost by increasing the carrying amount of the
related properties, plants and equipment. Over time the liability
is increased for the change in its present value, and the
capitalized cost in properties, plants and equipment is
depreciated over the useful life of the related asset. See Note
11Asset Retirement Obligations and Accrued Environmental Costs,
for additional information. |
80
|
|
Environmental expenditures are expensed or capitalized, depending upon their future economic
benefit. Expenditures that relate to an existing condition caused by past operations, and that
do not have a future economic benefit, are expensed. Liabilities for environmental
expenditures are recorded on an undiscounted basis (unless acquired in a purchase business
combination) when environmental
assessments or cleanups are probable and the costs can be reasonably estimated. Recoveries of
environmental remediation costs from other parties, such as state reimbursement funds, are
recorded as assets when their receipt is probable and estimable. |
n |
|
GuaranteesFair value of a guarantee is determined and recorded
as a liability at the time the guarantee is given. The initial
liability is subsequently reduced as we are released from exposure
under the guarantee. We amortize the guarantee liability over the
relevant time period, if one exists, based on the facts and
circumstances surrounding each type of guarantee. In cases where
the guarantee term is indefinite, we reverse the liability when we
have information that the liability is essentially relieved or
amortize it over an appropriate time period as the fair value of
our guarantee exposure declines over time. We amortize the
guarantee liability to the related statement of operations line
item based on the nature of the guarantee. When it becomes
probable that we will have to perform on a guarantee, we accrue a
separate liability if it is reasonably estimable, based on the
facts and circumstances at that time. We reverse the fair value
liability only when there is no further exposure under the
guarantee. |
n |
|
Stock-Based CompensationWe recognize stock-based compensation
expense over the shorter of the service period (i.e., the stated
period of time required to earn the award) or the period beginning
at the start of the service period and ending when an employee
first becomes eligible for retirement. We have elected to
recognize expense on a straight-line basis over the service period
for the entire award, whether the award was granted with ratable
or cliff vesting. |
n |
|
Income TaxesDeferred income taxes are computed using the
liability method and are provided on all temporary differences
between the financial reporting basis and the tax basis of our
assets and liabilities, except for deferred taxes on income
considered to be permanently reinvested in certain foreign
subsidiaries and foreign corporate joint ventures. Allowable tax
credits are applied currently as reductions of the provision for
income taxes. Interest related to unrecognized tax benefits is
reflected in interest expense, and penalties in production and
operating expenses. |
n |
|
Taxes Collected from Customers and Remitted to Governmental
AuthoritiesExcise taxes are reported gross within sales and
other operating revenues and taxes other than income taxes, while
other sales and value-added taxes are recorded net in taxes other
than income taxes. |
n |
|
Net Income (Loss) Per Share of Common StockBasic net income
(loss) per share of common stock is calculated based upon the
daily weighted-average number of common shares outstanding during
the year, including unallocated shares held by the stock savings
feature of the ConocoPhillips Savings Plan. Also, this
calculation includes fully vested stock and unit awards that have
not been issued. Diluted net income per share of common stock
includes the above, plus unvested stock, unit or option awards
granted under our compensation plans and vested but unexercised
stock options, but only to the extent these instruments dilute net
income per share. For the purpose of the 2009 earnings per share
calculation, net income attributable to ConocoPhillips was reduced
by $12 million for the excess of the amount paid for the
redemption of a noncontrolling interest over its carrying value,
which was charged directly to retained earnings. Diluted net loss
per share in 2008 is calculated the same as basic net loss per
sharethat is, it does not assume conversion or exercise of
securities, totaling 17,354,959 shares in 2008 that would have an
anti-dilutive effect. Treasury stock and shares held by the
grantor trusts are excluded from the daily weighted-average number
of common shares outstanding in both calculations. |
81
Note 2Changes in Accounting Principles
LUKOIL Accounting
Effective January 1, 2010, we changed the method used to determine our equity-method share of OAO
LUKOILs earnings. Prior to 2010, we estimated our LUKOIL equity earnings for the current quarter
based on current market indicators, publicly available LUKOIL information and other objective data.
This earnings estimation process was necessary because, historically, LUKOILs accounting cycle
close and preparation of U.S. generally accepted accounting principles financial statements
occurred subsequent to our reporting deadline, and for certain periods this timing gap exceeded 93
days. Although Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC)
Topic 323, InvestmentsEquity Method and Joint Ventures, provides that when financial statements
of an investee are not sufficiently timely, then the investor should record its share of earnings
or loss based on the most recently available financial statements, U.S. Securities and Exchange
Commission (SEC) guidance indicates this timing gap generally should not exceed 93 days. When the
timing gap was reduced to less than 93 days for all reporting periods, we believed it was
preferable to implement a change in accounting principle to record our equity-method share of
LUKOILs earnings on a one-quarter-lag basis, because it improves reporting reliability, while
maintaining an acceptable level of relevance.
The following table summarizes the line items affected on the consolidated statement of
operations for year ended December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars |
|
|
|
Computed with |
|
|
As Reported |
|
|
Effect of |
|
|
|
Estimate |
|
|
with Lag |
|
|
Change |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of affiliates |
|
$ |
2,951 |
|
|
|
3,133 |
|
|
|
182 |
|
Gain on dispositions |
|
|
5,593 |
|
|
|
5,803 |
|
|
|
210 |
|
Provision for income taxes |
|
|
8,343 |
|
|
|
8,333 |
|
|
|
(10 |
) |
Net income |
|
|
11,015 |
|
|
|
11,417 |
|
|
|
402 |
|
Net income attributable to ConocoPhillips |
|
|
10,956 |
|
|
|
11,358 |
|
|
|
402 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to
ConocoPhillips per share of
common stock
(dollars) |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
7.41 |
|
|
|
7.68 |
|
|
|
.27 |
|
Diluted |
|
|
7.35 |
|
|
|
7.62 |
|
|
|
.27 |
|
|
The following table summarizes the line items affected on the consolidated balance sheet at
December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars |
|
|
|
Computed with |
|
|
As Reported |
|
|
Effect of |
|
|
|
Estimate |
|
|
with Lag |
|
|
Change |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accrued income and other taxes |
|
$ |
4,865 |
|
|
|
4,874 |
|
|
|
9 |
|
Accumulated other comprehensive income |
|
|
4,741 |
|
|
|
4,773 |
|
|
|
32 |
|
Retained earnings |
|
|
40,438 |
|
|
|
40,397 |
|
|
|
(41 |
) |
|
82
The following table summarizes the line items affected on the 2010 consolidated statement of cash
flows for year ended December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars |
|
|
|
Computed with |
|
|
As Reported |
|
|
Effect of |
|
|
|
Estimate |
|
|
with Lag |
|
|
Change |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
11,015 |
|
|
|
11,417 |
|
|
|
402 |
|
Deferred taxes |
|
|
(868 |
) |
|
|
(878 |
) |
|
|
(10 |
) |
Undistributed equity earnings |
|
|
(891 |
) |
|
|
(1,073 |
) |
|
|
(182 |
) |
Gain on dispositions |
|
|
(5,593 |
) |
|
|
(5,803 |
) |
|
|
(210 |
) |
|
This change in accounting principle to a one-quarter lag under ASC Topic 323 has been applied
retrospectively, by recasting prior period financial information. The following table summarizes
the line items affected on the consolidated statement of operations for years ended December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars |
|
|
|
2009 |
|
|
2008 |
|
|
|
As |
|
|
|
|
|
|
Effect |
|
|
As |
|
|
|
|
|
|
Effect |
|
|
|
Originally |
|
|
As |
|
|
of |
|
|
Originally |
|
|
As |
|
|
of |
|
|
|
Reported |
|
|
Adjusted |
|
|
Change |
|
|
Reported |
|
|
Adjusted |
|
|
Change |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of affiliates |
|
$ |
2,981 |
|
|
|
2,531 |
|
|
|
(450 |
) |
|
|
4,250 |
|
|
|
4,999 |
|
|
|
749 |
|
Impairment LUKOIL investment |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
7,410 |
|
|
|
7,496 |
|
|
|
86 |
|
Provision for income taxes |
|
|
5,096 |
|
|
|
5,090 |
|
|
|
(6 |
) |
|
|
13,405 |
|
|
|
13,419 |
|
|
|
14 |
|
Net income (loss) |
|
|
4,936 |
|
|
|
4,492 |
|
|
|
(444 |
) |
|
|
(16,928 |
) |
|
|
(16,279 |
) |
|
|
649 |
|
Net income (loss) attributable to
ConocoPhillips |
|
|
4,858 |
|
|
|
4,414 |
|
|
|
(444 |
) |
|
|
(16,998 |
) |
|
|
(16,349 |
) |
|
|
649 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to
ConocoPhillips per share of
common stock (dollars) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
3.26 |
|
|
|
2.96 |
|
|
|
(.30 |
) |
|
|
(11.16 |
) |
|
|
(10.73 |
) |
|
|
.43 |
|
Diluted |
|
|
3.24 |
|
|
|
2.94 |
|
|
|
(.30 |
) |
|
|
(11.16 |
) |
|
|
(10.73 |
) |
|
|
.43 |
|
|
The following table summarizes the line items affected on the consolidated balance sheet at
December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars |
|
|
|
As Originally |
|
|
As Reported |
|
|
Effect of |
|
|
|
Reported |
|
|
with Lag |
|
|
Change |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investments and long-term receivables |
|
$ |
36,192 |
|
|
|
35,742 |
|
|
|
(450 |
) |
Deferred income taxes |
|
|
17,962 |
|
|
|
17,956 |
|
|
|
(6 |
) |
Retained earnings |
|
|
32,658 |
|
|
|
32,214 |
|
|
|
(444 |
) |
|
The cumulative impact to retained earnings as of January 1, 2008, was a decrease of $649 million as
a result of the accounting change.
83
The following table summarizes the line items affected on the consolidated statement of cash flows
for years ended December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars |
|
|
|
2009 |
|
|
2008 |
|
|
|
As |
|
|
|
|
|
|
Effect |
|
|
As |
|
|
|
|
|
|
Effect |
|
|
|
Originally |
|
|
As |
|
|
of |
|
|
Originally |
|
|
As |
|
|
of |
|
|
|
Reported |
|
|
Adjusted |
|
|
Change |
|
|
Reported |
|
|
Adjusted |
|
|
Change |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
4,936 |
|
|
|
4,492 |
|
|
|
(444 |
) |
|
|
(16,928 |
) |
|
|
(16,279 |
) |
|
|
649 |
|
Impairments |
|
|
535 |
|
|
|
535 |
|
|
|
- |
|
|
|
34,539 |
|
|
|
34,625 |
|
|
|
86 |
|
Deferred taxes |
|
|
(1,109 |
) |
|
|
(1,115 |
) |
|
|
(6 |
) |
|
|
(428 |
) |
|
|
(414 |
) |
|
|
14 |
|
Undistributed equity earnings |
|
|
(1,704 |
) |
|
|
(1,254 |
) |
|
|
450 |
|
|
|
(1,609 |
) |
|
|
(2,357 |
) |
|
|
(748 |
) |
Other |
|
|
196 |
|
|
|
196 |
|
|
|
- |
|
|
|
(1,134 |
) |
|
|
(1,135 |
) |
|
|
(1 |
) |
|
See Note 6Investments, Loans and Long-Term Receivables, for additional information relating to
our LUKOIL investment.
Transfers of Financial Assets
In June 2009, the FASB issued Statement of Financial Accounting Standards (SFAS) No. 166,
Accounting for Transfers of Financial Assets, an amendment of FASB Statement No. 140, which was
codified into FASB ASC Topic 860, Transfers and Servicing. This Statement removed the concept of
a qualifying special purpose entity (SPE) and the exception for qualifying SPEs from the
consolidation guidance. Additionally, the Statement clarified the requirements for financial asset
transfers eligible for sale accounting. This Statement was effective January 1, 2010, and did not
impact our consolidated financial statements.
Variable Interest Entities (VIEs)
Also in June 2009, the FASB issued SFAS No. 167, Amendments to FASB Interpretation No. 46(R), to
address the effects of the elimination of the qualifying SPE concept in SFAS No. 166, and other
concerns about the application of key provisions of consolidation guidance for VIEs. This
Statement was codified into FASB ASC Topic 810, Consolidation. More specifically, Topic 810
requires a qualitative rather than a quantitative approach to determine the primary beneficiary of
a VIE, it amended certain guidance pertaining to the determination of the primary beneficiary when
related parties are involved, and it amended certain guidance for determining whether an entity is
a VIE. Additionally, this Statement requires continuous assessments of whether an enterprise is
the primary beneficiary of a VIE. This Statement was effective January 1, 2010, and its adoption
did not impact our consolidated financial statements, other than the required disclosures. For
additional information, see Note 3Variable Interest Entities (VIEs).
Reserve Estimation and Disclosures
In January 2010, the FASB issued Accounting Standards Update (ASU) No. 2010-03, Oil and Gas
Reserve Estimation and Disclosures. This ASU amended the FASBs ASC Topic 932, Extractive
ActivitiesOil and Gas to align the accounting requirements of Topic 932 with the SECs final
rule, Modernization of the Oil and Gas Reporting Requirements issued on December 31, 2008. In
summary, the revisions in ASU 2010-03 modernized the disclosure rules to better align with current
industry practices and expanded the disclosure requirements for equity method investments so that
more useful information is provided. More specifically, the main provisions include the following:
|
|
|
An expanded definition of oil and gas producing activities to include nontraditional
resources such as bitumen extracted from oil sands. |
|
|
|
|
The use of an average of the first-day-of-the-month price for the 12-month period,
rather than a year-end price for determining whether reserves can be produced
economically. |
|
|
|
|
Amended definitions of key terms such as reliable technology and reasonable
certainty which are used in estimating proved oil and gas reserve quantities. |
84
|
|
|
A requirement for disclosing separate information about reserve quantities and
financial statement amounts for geographical areas representing 15 percent or more of
proved reserves. |
|
|
|
|
Clarification that an entitys equity investments must be considered in determining
whether it has significant oil and gas activities and a requirement to disclose equity
method investments in the same level of detail as is required for consolidated
investments. |
This ASU is effective for annual reporting periods ended on or after December 31, 2009, and it
requires (1) the effect of the adoption to be included within each of the dollar amounts and
quantities disclosed, (2) qualitative and quantitative disclosure of the estimated effect of
adoption on each of the dollar amounts and quantities disclosed, if significant and practical to
estimate and (3) the effect of adoption on the financial statements, if significant and practical
to estimate. Adoption of these requirements did not significantly impact our reported reserves or
our consolidated financial statements.
Business Combinations
In December 2007, the FASB issued SFAS No. 141 (Revised), Business Combinations (SFAS No.
141(R)), which was subsequently amended by FASB Staff Position (FSP) FAS 141(R)-1 in April 2009.
This Statement was codified into FASB ASC Topic 805, Business Combinations. Topic 805 applies
prospectively to all transactions in which an entity obtains control of one or more other
businesses on or after January 1, 2009. In general, Topic 805 requires the acquiring entity in a
business combination to recognize the fair value of all
assets acquired and liabilities assumed in the transaction; establishes the acquisition date as the
fair value measurement point; and modifies disclosure requirements. It also modifies the
accounting treatment for transaction costs, in-process research and development, restructuring
costs, changes in deferred tax asset valuation allowances as a result of a business combination,
and changes in income tax uncertainties after the acquisition date. Additionally, effective
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 impact tax expense
instead of goodwill.
Noncontrolling Interests
Effective January 1, 2009, we implemented SFAS No. 160, Noncontrolling Interests in Consolidated
Financial Statementsan amendment of ARB No. 51. This Statement was codified into FASB ASC Topic
810, Consolidation. Topic 810 requires noncontrolling interests, previously 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 noncontrolling
interests to be clearly presented on the face of the consolidated statement of operations.
Additionally, Topic 810 clarified that changes in a parents ownership interest in a subsidiary
that do not result in deconsolidation are equity transactions, and that deconsolidation of a
subsidiary requires gain or loss recognition in net income based on the fair value on the
deconsolidation date. Topic 810 was applied prospectively with the exception of presentation and
disclosure requirements, which were applied retrospectively for all periods presented, and did not
significantly change the presentation of our consolidated financial statements. FASB ASU No.
2010-02, Accounting and Reporting for Decreases in Ownership of a Subsidiarya Scope
Clarification, clarified the decrease in ownership provision of Topic 810 applies to a group of
assets or a subsidiary that is a business, but was not applicable to sales of in-substance real
estate, or conveyances of oil and gas mineral rights.
Derivatives
Effective January 1, 2009, we implemented SFAS No. 161, Disclosures about Derivative Instruments
and Hedging Activitiesan amendment of FASB No. 133. This Statement was codified into FASB ASC
Topic 815, Derivatives and Hedging. The amendments to Topic 815 expanded disclosure requirements
to provide greater transparency for derivative instruments. In addition, we now must include an
indication of the volume of derivative activity by category (e.g., interest rate, commodity and
foreign currency); derivative assets, liabilities, gains and losses, by category, for the periods
presented in the financial statements; and expanded disclosures about credit-risk-related
contingent features. See Note 16Financial Instruments and Derivative Contracts, for additional
information.
85
Fair Value Measurement
Effective January 1, 2008, we implemented SFAS No. 157, Fair Value Measurements. This Statement
was codified primarily into FASB ASC Topic 820, Fair Value Measurements and Disclosures. This
Topic defined fair value, established a framework for its measurement and expanded disclosures
about fair value measurements. We elected to implement this guidance with the one-year deferral
permitted for nonfinancial assets and nonfinancial liabilities measured at fair value, except those
that are recognized or disclosed on a recurring basis (at least annually). Following the allowed
one-year deferral, effective January 1, 2009, we implemented Topic 820 for nonfinancial assets and
nonfinancial liabilities measured at fair value on a nonrecurring basis. The implementation covers
assets and liabilities measured at fair value in a business combination; impaired properties,
plants and equipment, intangible assets and goodwill; initial recognition of asset retirement
obligations; and restructuring costs for which we use fair value. There was no impact to our
consolidated financial statements from the implementation of this Topic for nonfinancial assets and
liabilities, other than additional disclosures.
Equity Method Accounting
In November 2008, the FASB reached a consensus on Emerging Issues Task Force (EITF) Issue No. 08-6,
Equity Method Investment Accounting Considerations (EITF 08-6). EITF 08-6 was codified into FASB
ASC Topic 323, InvestmentsEquity Method and Joint Ventures. EITF 08-6 was issued to clarify
how the application of equity method accounting is affected by SFAS No. 141(R) and SFAS No. 160.
Topic 323 clarified that an entity shall continue to use the cost accumulation model for its equity
method investments. It also confirmed past accounting practices related to the treatment of
contingent consideration and the use of the impairment model under Accounting Principles Board
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 Topic was effective January 1,
2009, and applies prospectively. The adoption did not impact our consolidated financial
statements.
Postretirement Benefit Plan Assets
In December 2008, the FASB issued FSP FAS 132(R)-1, Employers Disclosures about Postretirement
Benefit Plan Assets, to improve the transparency associated with disclosures about the plan assets
of a defined benefit pension or other postretirement plan. This Statement was codified into FASB
ASC Topic 715, CompensationRetirement Benefits. Topic 715 requires the disclosure of each
major asset class at fair value using the fair value hierarchy in SFAS No. 157, Fair Value
Measurements. This Topic is effective for annual financial statements beginning with the 2009
fiscal year, but did not impact our consolidated financial statements, other than requiring
additional disclosures. For more information on this disclosure, see Note 19Employee Benefit
Plans.
Note 3Variable Interest Entities (VIEs)
We hold significant variable interests in VIEs that have not been consolidated because we are not
considered the primary beneficiary. Information on these VIEs follows.
We have a 30 percent ownership interest with a 50 percent governance interest in the OOO
Naryanmarneftegaz (NMNG) joint venture to develop resources in the Timan-Pechora province of
Russia. The NMNG joint venture is a VIE because we and LUKOIL have disproportionate interests, and
LUKOIL was a related party at inception of the joint venture. Since LUKOIL is no longer a related
party, we do not believe NMNG would be a VIE if reconsidered today. LUKOIL owns 70 percent versus
our 30 percent direct interest; therefore, we have determined we are not the primary beneficiary of
NMNG, and we use the equity method of accounting for this investment. The funding of NMNG has been
provided with equity contributions, primarily for the development of the Yuzhno Khylchuyu (YK)
Field. At December 31, 2010, the book value of our investment in the venture was $735 million.
86
We have an agreement with Freeport LNG Development, L.P. (Freeport LNG) to participate in a
liquefied natural gas (LNG) receiving terminal in Quintana, Texas. We have no ownership in
Freeport LNG; however, we own a 50 percent interest in Freeport LNG GP, Inc. (Freeport GP), which
serves as the general partner managing the venture. We entered into a credit agreement with
Freeport LNG, whereby we agreed to provide loan financing for the construction of the terminal. We
also entered into a long-term agreement with Freeport LNG to use 0.9 billion cubic feet per day of
regasification capacity. The terminal became operational in June 2008, and we began making
payments under the terminal use agreement. Freeport LNG began making loan repayments in September
2008, and the loan balance outstanding as of December 31, 2010, was $653 million. Freeport LNG is
a VIE because Freeport GP holds no equity in Freeport LNG, and the limited partners of Freeport LNG
do not have any substantive decision making ability. We performed an analysis of the expected
losses and determined we are not the primary beneficiary. This expected loss analysis took into
account that the credit support arrangement requires Freeport LNG to maintain sufficient commercial
insurance to mitigate any loan losses. The loan to Freeport LNG is accounted for as a financial
asset, and our investment in Freeport GP is accounted for as an equity investment.
Note 4Inventories
Inventories at December 31 were:
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars |
|
|
|
2010 |
|
|
2009 |
|
|
|
|
|
|
|
|
|
|
Crude oil and petroleum products |
|
$ |
4,254 |
|
|
|
3,955 |
|
Materials, supplies and other |
|
|
943 |
|
|
|
985 |
|
|
|
|
$ |
5,197 |
|
|
|
4,940 |
|
|
Inventories valued on the LIFO basis totaled $4,051 million and $3,747 million at December 31, 2010
and 2009, respectively. The excess of current replacement cost over LIFO cost of inventories
amounted to $6,794 million and $5,627 million at December 31, 2010 and 2009, respectively.
Note 5Assets Held for Sale
In the fourth quarter of 2009, we announced plans to raise approximately $10 billion from asset
sales through the end of 2011. At December 31, 2009, we classified $323 million of Refining and
Marketing (R&M) noncurrent assets, primarily investment in equity affiliates, and $75 million of
R&M noncurrent deferred income tax liabilities as held for sale. During 2010, these assets and
others were sold. While we continue to market and evaluate other assets for sale under this
program that may be sold in 2011, we did not have significant assets meeting the criteria to be
classified as held for sale as of December 31, 2010.
On June 25, 2010, we sold our 9.03 percent interest in the Syncrude Canada Ltd. joint venture for
$4.6 billion. The $2.9 billion before-tax gain was included in the Gain on dispositions line of
our consolidated statement of operations. The cash proceeds were included in the Proceeds from
asset dispositions line within the investing cash flow section of our consolidated statement of
cash flows. At the time of disposition, Syncrude had a net carrying value of $1.75 billion, which
included $1.97 billion of properties, plants and equipment. During 2010 until its disposition,
Syncrude contributed $327 million in intercompany sales and other operating revenues, and generated
income before taxes of $127 million and net income of $93 million for the E&P segment.
87
Note 6Investments, Loans and Long-Term Receivables
Components of investments, loans and long-term receivables at December 31 were:
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|
|
|
|
|
|
|
Millions of Dollars |
|
|
|
2010 |
|
|
2009 |
|
|
|
|
|
|
|
|
|
|
Equity investments* |
|
$ |
30,055 |
|
|
|
34,280 |
|
Loans and advancesrelated parties |
|
|
2,180 |
|
|
|
2,352 |
|
Long-term receivables |
|
|
922 |
|
|
|
1,009 |
|
Other investments |
|
|
604 |
|
|
|
453 |
|
|
|
|
$ |
33,761 |
|
|
|
38,094 |
|
|
*2009 recast to reflect a change in accounting principle. See Note 2Changes in Accounting Principles, for more information.
Equity Investments
Affiliated companies in which we had a significant equity investment at December 31, 2010 include:
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|
|
Australia Pacific LNG50 percent owned joint venture with Origin Energyto develop
coalbed methane production from the Bowen and Surat Basins in Queensland, Australia, as
well as process and export LNG. |
|
|
|
|
FCCL Partnership50 percent owned business venture with Cenovus Energy Inc.produces
bitumen in the Athabasca oil sands in northeastern Alberta and sells the bitumen blend. |
|
|
|
|
WRB Refining LP50 percent owned business venture with Cenovusowns the Wood River and
Borger Refineries, which process crude oil into refined products. |
|
|
|
|
OOO Naryanmarneftegaz (NMNG)30 percent ownership interest and a 50 percent governance
interesta joint venture with LUKOIL to explore for, develop and produce oil and gas
resources in the northern part of Russias Timan-Pechora Province. |
|
|
|
|
DCP Midstream, LLC50 percent owned joint venture with Spectra Energyowns and
operates gas plants, gathering systems, storage facilities and fractionation plants. |
|
|
|
|
Chevron Phillips Chemical Company LLC (CPChem)50 percent owned joint venture with
Chevron Corporationmanufactures and markets petrochemicals and plastics. |
Summarized 100 percent financial information for equity method investments in affiliated companies,
combined, was as follows (information includes LUKOIL until loss of significant influence):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
105,589 |
|
|
|
128,881 |
|
|
|
180,070 |
|
Income before income taxes |
|
|
11,250 |
|
|
|
12,121 |
|
|
|
22,356 |
|
Net income |
|
|
9,495 |
|
|
|
9,145 |
|
|
|
17,976 |
|
Current assets |
|
|
14,039 |
|
|
|
36,139 |
|
|
|
34,838 |
|
Noncurrent assets |
|
|
79,411 |
|
|
|
126,163 |
|
|
|
114,294 |
|
Current liabilities |
|
|
9,325 |
|
|
|
22,483 |
|
|
|
21,150 |
|
Noncurrent liabilities |
|
|
24,412 |
|
|
|
30,960 |
|
|
|
29,845 |
|
|
Our share of income taxes incurred directly by the equity companies is reported in equity in
earnings of affiliates, and as such is not included in income taxes in our consolidated financial
statements.
At December 31, 2010, retained earnings included $1,991 million related to the undistributed
earnings of affiliated companies.
88
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, Australia Pacific LNG (APLNG), is focused on coalbed methane production from the Bowen and
Surat Basins in Queensland, Australia, and LNG processing and export sales. This transaction gives
us access to coalbed methane resources in Australia and enhances our LNG position with the expected
creation of an additional LNG hub targeting the Asia Pacific markets.
Under the terms of our agreements with Origin Energy, we will potentially make up to four
additional payments to Origin of $500 million each. The payments
are conditional on up to four LNG trains being
approved and developed by the joint venture and achievement of certain other financial and operating milestones.
At December 31, 2010, the book value of our equity method investment in APLNG was $9,159 million,
which includes $3,244 million of cumulative translation effects due to a strengthening Australian
dollar. Our 50 percent share of the historical cost basis net assets of APLNG on its books under
U.S. generally accepted accounting principles (GAAP) was $1,187 million, resulting in a basis
difference of $7,948 million on our books. The amortizable portion of the basis difference, $5,719
million associated with properties, plants and equipment, has been allocated on a relative fair
value basis to individual exploration and production license areas owned by APLNG, most of which
are not currently in production. Any future additional payments are expected to be allocated in a
similar manner. Each exploration license area will periodically be reviewed for any indicators of
potential impairment, which, if required, would result in acceleration of basis difference
amortization. As the joint venture begins producing natural gas from each license, we amortize the
basis difference allocated to that license using the unit-of-production method. Included in net
income attributable to ConocoPhillips for 2010, 2009 and 2008 was after-tax expense of $5 million,
$4 million and $7 million, respectively, representing the amortization of this basis difference on
currently producing licenses.
FCCL and WRB
In January 2007, we closed on a business venture with Cenovus to create an integrated North
American heavy oil business. The transaction consists of two 50/50 business ventures, a Canadian
upstream general partnership, FCCL Partnership, and a U.S. downstream limited partnership, WRB
Refining LP. We use the equity method of accounting for both entities, with the operating results
of our investment in FCCL reflecting its use of the full-cost method of accounting for oil and gas
exploration and development activities.
At December 31, 2010, the book value of our investment in FCCL was $8,674 million. FCCLs
operating assets consist of the Foster Creek and Christina Lake steam-assisted gravity drainage
bitumen projects, both located in the eastern flank of the Athabasca oil sands in northeastern
Alberta. Cenovus is the operator and managing partner of FCCL. We are obligated to contribute
$7.5 billion, plus accrued interest, to FCCL over a 10-year period that began in 2007. For
additional information on this obligation, see Note 13Joint Venture Acquisition Obligation.
At December 31, 2010, the book value of our investment in WRB was $3,222 million. WRBs operating
assets consist of the Wood River and Borger Refineries, located in Roxana, Illinois, and Borger,
Texas, respectively. As a result of our contribution of these two assets to WRB, a basis
difference was created due to the fair value of the contributed assets recorded by WRB exceeding
their historical book value. The difference is primarily amortized and recognized as a benefit
evenly over a period of 26 years, which is the estimated remaining useful life of the refineries
property, plant and equipment at the closing date. The basis difference at December 31, 2010, was
$4,101 million. Equity earnings in 2010, 2009 and 2008 were increased by $243 million, $209
million and $246 million, respectively, due to amortization of the basis difference. We are the
operator and managing partner of WRB. Cenovus is obligated to contribute $7.5 billion, plus
accrued interest, to WRB over a 10-year period that began in 2007. For the Wood River Refinery,
operating results are shared 50/50 starting upon formation. For the Borger Refinery, we were
entitled to 85 percent of the operating results in 2007, with our share decreasing to 65 percent in
2008, and 50 percent in all years thereafter.
LUKOIL
LUKOIL is an integrated energy company headquartered in Russia. Our ownership interest was 2.25
percent at December 31, 2010, and 20 percent at December 31, 2009 and 2008, based on 851 million
shares authorized and issued. For financial reporting under U.S. GAAP, treasury shares held by
LUKOIL are not considered
89
outstanding for determining equity method ownership interest. Our ownership interest, based on
estimated shares outstanding at December 31, 2009 and 2008, was 20.09 percent and 20.06 percent,
respectively.
On July 28, 2010, we announced our intention to sell our entire interest in LUKOIL, then consisting
of 163.4 million shares. This decision was implemented as follows:
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|
|
On July 28, 2010, we entered into a stock purchase and option agreement (the Agreement)
with a wholly owned subsidiary of LUKOIL, pursuant to which such subsidiary purchased 64.6
million shares from us at a price of $53.25 per share, or $3,442 million in total. This
transaction closed on August 16, 2010. |
|
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|
Also pursuant to the Agreement, the LUKOIL subsidiary had a 60-day option, expiring on
September 26, 2010, to purchase any or all of our interest remaining at the time of
exercise of the option, at a price of $56 per share. Upon exercise of this option, we sold
42.5 million shares on September 29, 2010, for proceeds of $2,380 million. |
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|
Finally, we sold our remaining shares in the open market subject to the terms of the
Shareholder Agreement, with the final disposition of all shares occurring in the first
quarter of 2011. |
During the third quarter of 2010, our ownership interest declined to a level at which we were no
longer able to exercise significant influence over the operating and financial policies of LUKOIL.
Accordingly, at the end of the third quarter of 2010, we stopped applying the equity method of
accounting for our remaining investment in LUKOIL, and we reclassified the investment from
Investments and long-term receivables to current assets on our consolidated balance sheet as an
available-for-sale equity security.
In total, during 2010, we sold 151 million shares of LUKOIL for $8,345 million, realizing a
before-tax gain on disposition of $1,749 million, which was included in the Gain on dispositions
line of our consolidated statement of operations. Included in these amounts are sales proceeds of
$1,793 million and a realized before-tax gain of $437 million incurred subsequent to classifying
the investment as available-for-sale. The cost basis for shares sold is average cost.
At December 31, 2010, our remaining investment in LUKOIL was carried at fair value of $1,083
million, reflecting a closing price of LUKOIL American Depositary Receipts (ADRs) on the London
Stock Exchange of $56.50 per share. The carrying value reflects a pretax unrealized gain over our
cost basis of $247 million. This unrealized gain, net of related income taxes, is reported as a
component of accumulated other comprehensive income. The fair value is categorized as Level 1 in
the fair value hierarchy.
Prior to 2010, our equity earnings for LUKOIL were estimated. Effective January 1, 2010, we
changed our accounting to record our equity earnings for LUKOIL on a one-quarter-lag basis. See
Note 2Changes in Accounting Principles, for additional information about this change in
accounting principle for our LUKOIL investment.
While applying the equity method of accounting, a negative basis difference existed which was
primarily amortized on a straight-line basis over a 22-year useful life as an increase to equity
earnings. Equity earnings in 2010 and 2009 were increased $155 million and $157 million,
respectively, while equity earnings in 2008 were reduced $86 million due to amortization of the
positive basis difference that existed prior to the 2008 year-end investment impairment discussed
below.
Since the inception of our investment and through June 30, 2008, the market value of our investment
in LUKOIL exceeded book value, based on the price of LUKOIL ADRs on the London Stock Exchange.
However, the price of LUKOIL ADRs experienced significant decline during the second half of 2008,
and traded for most of the fourth quarter and into early 2009 in the general range of $25 to $40
per share. The ADR price at year-end 2008 was $32.05 per share, or 67 percent lower than the June
30, 2008, price. This resulted in a December 31, 2008, market value of our investment of $5,452
million, or 58 percent lower than our book value. Based on a review of the facts and circumstances
surrounding this decline in the market value of our investment during the second half of 2008, we
concluded that an impairment of our investment was necessary. In reaching this conclusion, we
considered the length of time market value had been below book value and the severity of the
decline in market value to be important factors. In combination, these two items
90
caused us to conclude that the decline was other than temporary. Accordingly, we recorded a
noncash $7,496 million, before- and after-tax impairment, in our fourth-quarter 2008 results. This
impairment had the effect of reducing our book value to $5,452 million, based on the market value
of LUKOIL ADRs on December 31, 2008.
NMNG
NMNG is a joint venture with LUKOIL, created in June 2005, to develop resources in the northern
part of Russias Timan-Pechora province. We have a 30 percent direct ownership interest with a 50
percent governance interest. At December 31, 2010, the book value of our equity method investment
in NMNG was $735 million. NMNG achieved initial production of the YK Field in June 2008, and
development was completed in 2010. Production from the NMNG joint venture fields is transported
via pipeline to LUKOILs existing terminal at Varandey Bay on the Barents Sea and then shipped via
tanker to international markets. During 2010 and 2009, we reduced the carrying value of our NMNG
investment, reflecting other-than-temporary declines in fair value.
DCP Midstream
DCP Midstream owns and operates gas plants, gathering systems, storage facilities and fractionation
plants. At December 31, 2010, the book value of our equity method investment in DCP Midstream was
$1,038 million. DCP Midstream markets a portion of its natural gas liquids to us and CPChem under
a supply agreement that continues at the current volume commitment with a primary term ending
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. Natural gas liquids are purchased under this
agreement at various published market index prices, less transportation and fractionation fees.
CPChem
CPChem manufactures and markets petrochemicals and plastics. At December 31, 2010, the book value
of our equity method investment in CPChem was $2,518 million. We have multiple supply and purchase
agreements in place with CPChem, ranging in initial terms from one to 99 years, with extension
options. These agreements cover sales and purchases of refined products, solvents, and
petrochemical and natural gas liquids feedstocks, as well as fuel oils and gases. Delivery
quantities vary by product, and are generally on an if-produced, will-purchase basis. All
products are purchased and sold under specified pricing formulas based on various published pricing
indices, consistent with terms extended to third-party customers.
Loans and Long-term Receivables
As part of our normal ongoing business operations and consistent with industry practice, we enter
into numerous agreements with other parties to pursue business opportunities. Included in such
activity are loans and long-term receivables to certain affiliated and non-affiliated companies.
Loans are recorded when cash is transferred or seller financing is provided to the affiliated or
non-affiliated company pursuant to a loan agreement. The loan balance will increase as interest is
earned on the outstanding loan balance and will decrease as interest and principal payments are
received. Interest is earned at the loan agreements stated interest rate. Loans and long-term
receivables are assessed for impairment when events indicate the loan balance may not be fully
recovered.
At December 31, 2010, significant loans to affiliated companies include the following:
|
|
|
$653 million in loan financing to Freeport LNG Development, L.P. for the construction of
an LNG receiving terminal that became operational in June 2008. Freeport began making
repayments in 2008 and is required to continue making repayments through full repayment of
the loan in 2026. Repayment by Freeport is supported by process-or-pay capacity service
payments made by us to Freeport under our terminal use agreement. |
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|
|
$1,118 million of project financing and an additional $96 million of accrued interest to
Qatar Liquefied Gas Company Limited (3) (QG3), which is an integrated project to produce
and liquefy natural gas from Qatars North Field. We own a 30 percent interest in QG3, for
which we use the equity method of accounting. The other participants in the project are
affiliates of Qatar Petroleum (68.5 percent) and Mitsui & Co., Ltd. (1.5 percent). QG3
secured project financing of $4.0 billion in |
91
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|
|
December 2005, consisting of $1.3 billion of loans from export credit agencies (ECA), $1.5
billion from commercial banks, and $1.2 billion from ConocoPhillips. The ConocoPhillips
loan facilities have substantially the same terms as the ECA and commercial bank
facilities. Prior to project completion certification, all loans, including the
ConocoPhillips loan facilities, are guaranteed by the participants based on their
respective ownership interests. Accordingly, our maximum exposure to this financing
structure is $1.2 billion. Upon completion certification, which is expected in 2011, all
project loan facilities, including the ConocoPhillips loan facilities, will become
nonrecourse to the project participants. At December 31, 2010, QG3 had approximately $4.0
billion outstanding under all the loan facilities. Bi-annual repayments began in January
2011 and will extend through July 2022. |
|
|
|
$550 million of loan financing to WRB Refining LP to assist it in meeting its operating
and capital spending requirements. We have certain creditor rights in case of default or
insolvency. |
The long-term portion of these loans are included in the Loans and advancesrelated parties line
on the consolidated balance sheet, while the short-term portion is in Accounts and notes
receivablerelated parties.
At September 30, 2010, the Varandey Terminal Company was no longer considered a related party.
Accordingly, the long-term portion of this loan is included in the Investments and long-term
receivables line of the consolidated balance sheet, while the short-term portion is in Prepaid
expenses and other current assets.
At December 31, 2010, significant long-term receivables and loans to non-affiliated companies
included $372 million related to seller financing of U.S. retail marketing assets. In January
2009, we closed on the sale of a large part of our U.S. retail marketing assets which included a
five-year note to finance the sale of certain assets. The note is collateralized by the underlying
assets related to the sale.
Long-term receivables and the long-term portion of these loans are included in the Investments and
long-term receivables line on the consolidated balance sheet, while the short-term portion related
to non-affiliate loans is in Accounts and notes receivable.
Other
We have investments remeasured at fair value on a recurring basis to support certain nonqualified
deferred compensation plans. The fair value of these assets at December 31, 2010, was $325
million, and at December 31, 2009, was $338 million. Substantially the entire value is categorized
in Level 1 of the fair value hierarchy. These investments are measured at fair value using a
market approach based on quotations from national securities exchanges.
Merey Sweeny, L.P. (MSLP) is a limited partnership that owns a 70,000-barrel-per-day delayed coker
and related facilities at the Sweeny Refinery. MSLP processes our long residue, which is produced
from heavy sour crude oil, for a processing fee. Fuel-grade petroleum coke is produced as a
by-product and becomes the property of MSLP. Prior to August 28, 2009, MSLP was owned 50/50 by us
and Petróleos de Venezuela S.A. (PDVSA). Under the agreements that govern the relationships
between the partners, certain defaults by PDVSA with respect to supply of crude oil to the Sweeny
Refinery gave us the right to acquire PDVSAs 50 percent ownership interest in MSLP. On August 28,
2009, we exercised that right. PDVSA has initiated arbitration with the International Chamber of
Commerce challenging our actions, and this arbitration is underway. We continue to use the equity
method of accounting for our investment in MSLP.
92
Note 7Properties, Plants and Equipment
Properties, plants and equipment (PP&E) are recorded at cost. Within the E&P segment, depreciation
is mainly on a unit-of-production basis, so depreciable life will vary by field. In the R&M
segment, investments in refining manufacturing facilities are generally depreciated on a
straight-line basis over a 25-year life, and pipeline assets over a 45-year life. The companys
investment in PP&E, with accumulated depreciation, depletion and amortization (Accum. DD&A), at
December 31 was:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars |
|
|
|
2010 |
|
|
2009 |
|
|
|
Gross |
|
|
Accum. |
|
|
Net |
|
|
Gross |
|
|
Accum. |
|
|
Net |
|
|
|
PP&E |
|
|
DD&A |
|
|
PP&E |
|
|
PP&E |
|
|
DD&A |
|
|
PP&E |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
E&P |
|
$ |
116,805 |
|
|
|
50,501 |
|
|
|
66,304 |
|
|
|
115,224 |
|
|
|
45,577 |
|
|
|
69,647 |
|
Midstream |
|
|
128 |
|
|
|
80 |
|
|
|
48 |
|
|
|
123 |
|
|
|
74 |
|
|
|
49 |
|
R&M |
|
|
23,579 |
|
|
|
8,999 |
|
|
|
14,580 |
|
|
|
23,047 |
|
|
|
6,714 |
|
|
|
16,333 |
|
LUKOIL Investment |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Chemicals |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Emerging Businesses |
|
|
981 |
|
|
|
161 |
|
|
|
820 |
|
|
|
1,198 |
|
|
|
300 |
|
|
|
898 |
|
Corporate and Other |
|
|
1,732 |
|
|
|
930 |
|
|
|
802 |
|
|
|
1,650 |
|
|
|
869 |
|
|
|
781 |
|
|
|
|
$ |
143,225 |
|
|
|
60,671 |
|
|
|
82,554 |
|
|
|
141,242 |
|
|
|
53,534 |
|
|
|
87,708 |
|
|
Note 8Suspended Wells
The following table reflects the net changes in suspended exploratory well costs during 2010, 2009
and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning balance at January 1 |
|
$ |
908 |
|
|
|
660 |
|
|
|
589 |
|
Additions pending the determination of proved reserves |
|
|
216 |
|
|
|
342 |
|
|
|
160 |
|
Reclassifications to proved properties |
|
|
(106 |
) |
|
|
(39 |
) |
|
|
(37 |
) |
Sales of suspended well investment |
|
|
(4 |
) |
|
|
(21 |
) |
|
|
(10 |
) |
Charged to dry hole expense |
|
|
(1 |
) |
|
|
(34 |
) |
|
|
(42 |
) |
|
Ending balance at December 31 |
|
$ |
1,013 |
|
|
|
908 |
|
|
|
660 |
|
|
The following table provides an aging of suspended well balances at December 31, 2010, 2009 and
2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory well costs capitalized for a period of one year or less |
|
$ |
220 |
|
|
|
319 |
|
|
|
182 |
|
Exploratory well costs capitalized for a period greater than one year |
|
|
793 |
|
|
|
589 |
|
|
|
478 |
|
|
Ending balance |
|
$ |
1,013 |
|
|
|
908 |
|
|
|
660 |
|
|
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year |
|
|
40 |
|
|
|
34 |
|
|
|
31 |
|
|
93
The following table provides a further aging of those exploratory well costs that have been
capitalized for more than one year since the completion of drilling as of December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars |
|
|
|
|
|
|
|
Suspended Since |
|
Project |
|
Total |
|
|
2007-2009 |
|
|
2004-2006 |
|
|
2001-2003 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
AktoteKazakhstan(1) |
|
$ |
19 |
|
|
|
- |
|
|
|
8 |
|
|
|
11 |
|
Alpine satelliteAlaska(1) |
|
|
23 |
|
|
|
- |
|
|
|
- |
|
|
|
23 |
|
Browse BasinAustralia(2) |
|
|
93 |
|
|
|
93 |
|
|
|
- |
|
|
|
- |
|
Caldita/BarossaAustralia(2) |
|
|
77 |
|
|
|
- |
|
|
|
77 |
|
|
|
- |
|
ClairU.K.(1) |
|
|
46 |
|
|
|
29 |
|
|
|
17 |
|
|
|
- |
|
Fiord WestAlaska(1) |
|
|
16 |
|
|
|
16 |
|
|
|
- |
|
|
|
- |
|
HarrisonU.K.(1) |
|
|
15 |
|
|
|
15 |
|
|
|
- |
|
|
|
- |
|
KairanKazakhstan(1) |
|
|
27 |
|
|
|
14 |
|
|
|
13 |
|
|
|
- |
|
KalamkasKazakhstan(2) |
|
|
13 |
|
|
|
4 |
|
|
|
5 |
|
|
|
4 |
|
KashaganKazakhstan(2) |
|
|
44 |
|
|
|
34 |
|
|
|
- |
|
|
|
10 |
|
MalikaiMalaysia(1) |
|
|
53 |
|
|
|
- |
|
|
|
53 |
|
|
|
- |
|
NPR-AAlaska(1) |
|
|
17 |
|
|
|
17 |
|
|
|
- |
|
|
|
- |
|
Petai/PisagonMalaysia(2) |
|
|
43 |
|
|
|
33 |
|
|
|
10 |
|
|
|
- |
|
SaleskiCanada(2) |
|
|
14 |
|
|
|
14 |
|
|
|
- |
|
|
|
- |
|
ShenandoahLower 48(2) |
|
|
43 |
|
|
|
43 |
|
|
|
- |
|
|
|
- |
|
Sunrise 3Australia(1) |
|
|
13 |
|
|
|
13 |
|
|
|
- |
|
|
|
- |
|
Surmont Beyond Phase IICanada(2) |
|
|
28 |
|
|
|
19 |
|
|
|
9 |
|
|
|
- |
|
ThornburyCanada(2) |
|
|
20 |
|
|
|
20 |
|
|
|
- |
|
|
|
- |
|
TiberLower 48(2) |
|
|
40 |
|
|
|
40 |
|
|
|
- |
|
|
|
- |
|
TitanNorway(1) |
|
|
12 |
|
|
|
12 |
|
|
|
- |
|
|
|
- |
|
UbahMalaysia(1) |
|
|
24 |
|
|
|
24 |
|
|
|
- |
|
|
|
- |
|
UgeNigeria(2) |
|
|
30 |
|
|
|
16 |
|
|
|
14 |
|
|
|
- |
|
Eighteen projects of $10 million or less each(1)(2) |
|
|
83 |
|
|
|
59 |
|
|
|
24 |
|
|
|
- |
|
|
Total of 40 projects |
|
$ |
793 |
|
|
|
515 |
|
|
|
230 |
|
|
|
48 |
|
|
(1) Appraisal drilling complete; costs being incurred to assess development.
(2) Additional appraisal wells planned.
Note 9Goodwill and Intangibles
Goodwill
Changes in the carrying amount of goodwill were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars |
|
|
|
2010 |
|
|
2009 |
|
|
|
E&P |
|
|
R&M |
|
|
Total |
|
|
E&P |
|
|
R&M |
|
|
Total |
|
|
|
|
|
|
|
|
Balance as of January 1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Goodwill |
|
$ |
25,443 |
|
|
|
3,638 |
|
|
|
29,081 |
|
|
|
25,443 |
|
|
|
3,778 |
|
|
|
29,221 |
|
Accumulated impairment losses |
|
|
(25,443 |
) |
|
|
- |
|
|
|
(25,443 |
) |
|
|
(25,443 |
) |
|
|
- |
|
|
|
(25,443 |
) |
|
|
|
|
- |
|
|
|
3,638 |
|
|
|
3,638 |
|
|
|
- |
|
|
|
3,778 |
|
|
|
3,778 |
|
Goodwill allocated to assets
held for sale or sold |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(135 |
) |
|
|
(135 |
) |
Tax and other adjustments |
|
|
- |
|
|
|
(5 |
) |
|
|
(5 |
) |
|
|
- |
|
|
|
(5 |
) |
|
|
(5 |
) |
|
Balance as of December 31 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Goodwill |
|
|
25,443 |
|
|
|
3,633 |
|
|
|
29,076 |
|
|
|
25,443 |
|
|
|
3,638 |
|
|
|
29,081 |
|
Accumulated impairment losses |
|
|
(25,443 |
) |
|
|
- |
|
|
|
(25,443 |
) |
|
|
(25,443 |
) |
|
|
- |
|
|
|
(25,443 |
) |
|
|
|
$ |
- |
|
|
|
3,633 |
|
|
|
3,633 |
|
|
|
- |
|
|
|
3,638 |
|
|
|
3,638 |
|
|
94
Goodwill Impairment
We perform our annual goodwill impairment review in the fourth quarter of each year. During the
fourth quarter of 2008, there were severe disruptions in the credit markets and reductions in
global economic activity which had significant adverse impacts on stock markets and
oil-and-gas-related commodity prices, both of which contributed to a significant decline in our
companys stock price and corresponding market
capitalization. For most of the fourth quarter of 2008, our market capitalization value was
significantly below the recorded net book value of our balance sheet, including goodwill.
Because quoted market prices for our reporting units are not available, management must apply
judgment in determining the estimated fair value of these reporting units for purposes of
performing the annual goodwill impairment test. Management uses all available information to make
these fair value determinations, including the present values of expected future cash flows using
discount rates commensurate with the risks involved in the assets. A key component of these fair
value determinations is a reconciliation of the sum of these net present value calculations to our
market capitalization. We use an average of our market capitalization over the 30 calendar days
preceding the impairment testing date as being more reflective of our stock price trend than a
single day, point-in-time market price. Because, in our judgment, Worldwide E&P is considered to
have a higher valuation volatility than Worldwide R&M, the long-term free cash flow growth rate
implied from this reconciliation to our recent average market capitalization is applied to the
Worldwide E&P net present value calculation.
The accounting principles regarding goodwill acknowledge that the observed market prices of
individual trades of a companys stock (and thus its computed market capitalization) may not be
representative of the fair value of the company as a whole. Substantial value may arise from the
ability to take advantage of synergies and other benefits that flow from control over another
entity. Consequently, measuring the fair value of a collection of assets and liabilities that
operate together in a controlled entity is different from measuring the fair value of that entitys
individual common stock. In most industries, including ours, an acquiring entity typically is
willing to pay more for equity securities that give it a controlling interest than an investor
would pay for a number of equity securities representing less than a controlling interest.
Therefore, once the above net present value calculations have been determined, we also add a
control premium to the calculations. This control premium is judgmental and is based on observed
acquisitions in our industry. The resultant fair values calculated for the reporting units are
then compared to observable metrics on large mergers and acquisitions in our industry to determine
whether those valuations, in our judgment, appear reasonable.
After determining the fair values of our various reporting units as of December 31, 2008, it was
determined that our Worldwide R&M reporting unit passed the first step of the goodwill impairment
test, while our Worldwide E&P reporting unit did not pass the first step. As described above, the
second step of the goodwill impairment test uses the estimated fair value of Worldwide E&P from the
first step as the purchase price in a hypothetic