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 Earth’s 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.
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.
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 Attorney’s Office in Sacramento, California, filed a complaint in
Superior Court for alleged methyl tertiary-butyl ether (MTBE) contamination in groundwater. On
April 4, 2008, the District Attorney’s Office filed an amended complaint that included alleged
violations of state regulations relating to operation or maintenance of underground storage tanks.
There are numerous defendants named in the suit in addition to ConocoPhillips. We continue to
contest this lawsuit.
EXECUTIVE OFFICERS OF THE REGISTRANT
John A. Carrig
Willie C. W. Chiang
Greg C. Garland
Alan J. Hirshberg
Janet L. Kelly
Ryan M. Lance
James J. Mulva
Glenda M. Schwarz
Jeff W. Sheets
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 Production—Americas 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 Production—International, in
May 2009. Prior to that, he served as President, Exploration and Production—Asia, 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.
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.
PART II
| Item 5. |
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MARKET FOR REGISTRANT’S 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.”
2010
First
Second
Third
Fourth
2009
Closing Stock Price at December 31, 2010
Closing Stock Price at January 31, 2011
Number of Stockholders of Record at January 31, 2011*
*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
October 1-31, 2010
November 1-30, 2010
December 1-31, 2010
Total
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Includes the repurchase of common shares from company employees in connection with the
company’s 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 management’s 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. |
Item 6. SELECTED FINANCIAL DATA
Sales and other operating revenues
Net income (loss)
Net income (loss) attributable to ConocoPhillips
Per common share
Basic
Diluted
Total assets
Long-term debt
Joint venture acquisition obligation—long-term
Cash dividends declared per common share
*Recast to reflect a change in accounting principle. See Note 2—Changes in Accounting Principles, for more information.
Many factors can impact the comparability of this information, such as:
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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. |
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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. |
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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 Management’s 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.
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| Item 7. |
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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS |
February 23, 2011
Management’s Discussion and Analysis is the company’s analysis of its financial performance and of
significant trends that may affect future performance. It should be read in conjunction with the
financial statements and notes, and supplemental oil and gas disclosures. It contains
forward-looking statements including, without limitation, statements relating to the company’s
plans, strategies, objectives, expectations and intentions that are made pursuant to the “safe
harbor” provisions of the Private Securities Litigation Reform Act of 1995. The words
“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 company’s
disclosures under the heading: “CAUTIONARY STATEMENT FOR THE PURPOSES OF THE ‘SAFE HARBOR’
PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995,” beginning on page 65.
The terms “earnings” and “loss” as used in Management’s 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:
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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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Midstream—This 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 Investment—This 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 6—Investments, Loans and Long-Term Receivables, in the Notes to Consolidated
Financial Statements, for information on sales of LUKOIL shares. |
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Chemicals—This segment manufactures and markets petrochemicals and plastics on a
worldwide basis. The Chemicals segment consists of our 50 percent equity investment in
Chevron Phillips Chemical Company LLC (CPChem). |
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Emerging Businesses—This segment represents our investment in new technologies or
businesses outside our normal scope of operations. |
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:
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Operating our producing properties and refining and marketing operations safely,
consistently and in an environmentally sound manner. Safety is our first priority, and
we are committed to protecting the health and safety of everyone who has a role in our
operations and the communities in which we operate. 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. |
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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. |
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Adding to our proved reserve base. We primarily add to our proved reserve base in
three ways: |
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Successful exploration and development of new fields. |
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Acquisition of existing fields. |
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Application of new technologies and processes to improve recovery from existing fields. |
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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. |
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Access to additional resources has become increasingly difficult as direct investment is
prohibited in some nations, while fiscal and other terms in other countries can make
projects uneconomic or unattractive. In addition, political instability, competition from
national oil companies, and lack of access to high-potential areas due to environmental or
other regulation may negatively impact our ability to increase our reserve base. As such,
the timing and level at which we add to our reserve base may, or may not, allow us to
replace our production over subsequent years. |
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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. |
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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. |
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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. |
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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. |
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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:
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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. |
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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. |
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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.
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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. |
Segment Analysis
The E&P segment’s results are most closely linked to crude oil and natural gas prices. These are
commodity products, the prices of which are subject to factors external to our company and over
which we have no control. Industry crude oil prices for West Texas Intermediate (WTI) were higher
in 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 segment’s 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 Midstream’s natural gas liquids prices increased 39
percent in 2010.
Refining margins, refinery capacity utilization and cost control primarily drive the R&M segment’s
results. Refining margins are subject to movements in the cost of crude oil and other feedstocks,
and the sales prices for refined products, both of which are subject to market factors over which
we have no control. 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.
RESULTS OF OPERATIONS
Consolidated Results
A summary of the company’s net income (loss) attributable to ConocoPhillips by business segment
follows:
Exploration and Production (E&P)
Midstream
Refining and Marketing (R&M)
LUKOIL Investment*
Chemicals
Emerging Businesses
Corporate and Other
*2009 and 2008 recast to reflect a change in accounting principle. See Note 2—Changes in Accounting Principles, for more information.
2010 vs. 2009
The improved results in 2010 were primarily the result of:
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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. |
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Gains of $4,583 million after-tax from asset dispositions and LUKOIL share sales. |
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Improved results from our domestic R&M operations, reflecting higher refining margins. |
These items were partially offset by:
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Impairments totaling $1,928 million after-tax. |
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Lower production volumes from our E&P segment. |
2009 vs. 2008
The improved results in 2009 were primarily the result of:
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The absence of a $25,443 million before- and after-tax impairment of all E&P segment
goodwill in 2008. |
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The absence of a $7,496 million before- and after-tax impairment of our LUKOIL
investment in 2008. |
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Lower production taxes. |
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Reduced operating and overhead expenses. |
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Lower crude oil, natural gas and natural gas liquids prices, which impacted our E&P,
Midstream and LUKOIL Investment segments. |
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Lower refining margins in our R&M segment. |
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:
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Improved earnings from CPChem primarily due to higher margins in the olefins and
polyolefins business line. |
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Improved earnings from FCCL Partnership due to higher commodity prices and volumes. |
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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 5—Assets Held
for Sale and Note 6—Investment, 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 10—Impairments, 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 20—Income Taxes, in the Notes to Consolidated Financial Statements, for information
regarding our income tax expense and effective tax rate.
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.
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 6—Investments, Loans and Long-Term Receivables
and Note 9—Goodwill 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.
Segment Results
E&P
Net Income (Loss) Attributable to ConocoPhillips
Alaska
Lower 48
United States
International
Goodwill impairment
Average Sales Prices
Crude oil and natural gas liquids (per barrel)
United States
International
Total consolidated operations
Equity affiliates
Total E&P
Synthetic oil (per barrel)
Bitumen (per barrel)
Natural gas (per thousand cubic feet)*
Average Production Costs Per Barrel of Oil Equivalent
Total consolidated operations
Equity affiliates
Total E&P
Worldwide Exploration Expenses
General and administrative; geological and geophysical; and
lease rentals
Leasehold impairment
Dry holes
Operating Statistics
Crude oil and natural gas liquids produced
Alaska
Lower 48
Canada
Europe
Asia Pacific/Middle East
Africa
Other areas
Russia
Asia Pacific/Middle East
Synthetic oil produced
Consolidated operations—Canada
Bitumen produced
Equity affiliates—Canada
Natural gas produced*
*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.
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.
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.
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
Net Income Attributable to ConocoPhillips*
*Includes DCP Midstream-related earnings:
U.S. natural gas liquids*
Consolidated
*Based on index prices from the Mont Belvieu and Conway market hubs that are weighted by
natural gas liquids component and location mix.
Natural gas liquids extracted*
Natural gas liquids fractionated**
*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 fractionated—separated into individual components like ethane, butane and propane—and
marketed as chemical feedstock, fuel or blendstock. The Midstream segment consists of our 50
percent equity investment in DCP Midstream, as well as our other natural gas gathering and
processing operations, and natural gas liquids fractionation, trading and marketing businesses,
primarily in the United States and Trinidad.
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.
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
U.S. Average Wholesale Prices*
Gasoline
Distillates
*Excludes excise taxes.
Refining operations*
Crude oil capacity**
Crude oil processed
Capacity utilization (percent)
Refinery production
Worldwide
Petroleum products sales volumes
Gasoline
Distillates
Other products
**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.
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.
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.
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
Crude oil production (thousands of barrels daily)
Natural gas production (millions of cubic feet daily)
Refinery crude oil processed (thousands of barrels daily)
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 2—Changes in Accounting Principles, in the Notes to Consolidated Financial Statements, for
more information.
In addition to our equity share of LUKOIL’s 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 6—Investments, 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.
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.
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
Net Income Attributable to ConocoPhillips
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.
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.
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
Power
Other
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.
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.
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
Net Loss Attributable to ConocoPhillips
Net interest
Corporate general and administrative expenses
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.
CAPITAL RESOURCES AND LIQUIDITY
Financial Indicators
Net cash provided by operating activities
Short-term debt
Total debt
Total equity*
Percent of total debt to capital**
Percent of floating-rate debt to total debt***
*2009 and 2008 recast to reflect a change in accounting principle. See Note 2—Changes 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,
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 segment’s 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.
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 Moody’s Investor Service and “A” by both Standard and
Poor’s 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:
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Qatargas 3: We own a 30 percent interest in QG3, an integrated project to
produce and liquefy natural gas from Qatar’s 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 |
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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. |
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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 14—Guarantees, 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 payable—related 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.
Contractual Obligations
The following table summarizes our aggregate contractual fixed and variable obligations as of
December 31, 2010:
Debt obligations (a)
Capital lease obligations
Interest on debt and other obligations
Operating lease obligations
Purchase obligations (b)
Joint venture acquisition obligation (c)
Other long-term liabilities (d)
Asset retirement obligations
Accrued environmental costs
Unrecognized tax benefits (e)
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Includes $457 million of net unamortized premiums and discounts. See Note 12—Debt, in the
Notes to Consolidated Financial Statements, for additional information. |
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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. |
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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. |
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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. |
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Represents the remaining amount of contributions, excluding interest, due over a seven-year
period to the FCCL upstream joint venture with Cenovus. |
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Does not include: Pensions—for 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. |
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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
E&P
United States—Alaska
United States—Lower 48
R&M
LUKOIL Investment
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:
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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). |
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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. |
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Oil sands projects and ongoing natural gas projects in Canada. |
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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. |
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Significant U.S. lease acquisitions in the federal waters of the Chukchi Sea offshore
Alaska, as well as in the deepwater GOM. |
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Development drilling and facilities projects in the Greater Ekofisk Area, Alvheim, Heidrun
and Statfjord, located in the Norwegian sector of the North Sea. |
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The Peng Lai 19-3 development in China’s Bohai Bay. |
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The Kashagan Field and satellite prospects in the Caspian Sea offshore Kazakhstan. |
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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. |
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Investment in Rockies Express Pipeline LLC. |
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The North Belut Field, as well as other projects in offshore Block B and onshore South
Sumatra in Indonesia. |
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The QG3 Project, an integrated project to produce and liquefy natural gas from Qatar’s
North Field. |
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The Gumusut-Kakap development offshore Sabah, Malaysia. |
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Exploration activities in Australia’s Browse Basin, deepwater GOM, onshore North
American shale play and oil sands projects, offshore eastern Canada, North Sea and
Kazakhstan’s Block N. |
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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&P’s 2011 capital expenditures and investments budget is $11.3 billion, 33 percent higher than
actual expenditures in 2010. Thirty-seven percent of E&P’s 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:
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Canadian oil sands projects and ongoing natural gas projects in the western Canada gas
basins. |
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Further development of CBM projects associated with the APLNG joint venture in
Australia. |
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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. |
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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. |
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The Kashagan Field in the Caspian Sea. |
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Onshore developments in Nigeria, Algeria and Libya. |
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Exploration and appraisal activities in North American shale plays and oil sands
projects, Australia’s Browse Basin, Kazakhstan’s 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.
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:
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Installation of a 20,000-barrel-per-day hydrocracker at the Rodeo facility of our San
Francisco Refinery. |
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Installation of a 225-ton per day sulfur plant at the Sweeny Refinery. |
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Installation of facilities to reduce sulfur dioxide emissions from the Fluid Catalytic
Cracker at the Alliance Refinery. |
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Completion of a gasoline benzene reduction project at the Borger Refinery. |
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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:
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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. |
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Installations, revamps and expansions of equipment at several U.S. refineries to enable
production of low benzene gasoline. |
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U.S. programs aimed at air emission reductions. |
R&M’s 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
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 20—Income 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 agency’s processing of the application. Many of the delays associated with the permitting
process are beyond the control of the applicant.
Many states and foreign countries where we operate also have, or are developing, similar
environmental laws and regulations governing these same types of activities. While similar, in
some cases these regulations may
impose additional, or more stringent, requirements that can add to the cost and difficulty of
marketing or transporting products across state and international borders.
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
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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California’s Global Warming Solutions Act, which requires the California Air Resources
Board to develop regulations and market mechanisms that will ultimately reduce California’s
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 EPA’s 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.
CRITICAL ACCOUNTING ESTIMATES
The preparation of financial statements in conformity with generally accepted accounting principles
requires management to select appropriate accounting policies and to make estimates and assumptions
that affect the reported amounts of assets, liabilities, revenues and expenses. See Note
1—Accounting Policies, in the Notes to Consolidated Financial Statements, for descriptions of our
major accounting policies. Certain of these accounting policies involve judgments and
uncertainties to such an extent that there is a reasonable likelihood that materially different
amounts would have been reported under different conditions, or if different assumptions had been
used. These critical accounting estimates are discussed with the Audit and Finance Committee of
the Board of Directors at least annually. We believe the following discussions of critical
accounting estimates, along with the discussions of contingencies and of deferred tax asset
valuation allowances in this report, address all important accounting areas where the nature of
accounting estimates or assumptions is material due to the levels of subjectivity and judgment
necessary to account for highly uncertain matters or the susceptibility of such matters to change.
Oil and Gas Accounting
Accounting for oil and gas exploratory activity is subject to special accounting rules unique to
the oil and gas industry. The acquisition of geological and geophysical seismic information, prior
to the discovery of proved reserves, is expensed as incurred, similar to accounting for research
and development costs. However, leasehold acquisition costs and exploratory well costs are
capitalized on the balance sheet pending determination of whether proved oil and gas reserves have
been discovered on the prospect.
Property Acquisition Costs
For individually significant leaseholds, management periodically assesses for impairment based on
exploration and drilling efforts to date. For leasehold acquisition costs that individually are
relatively small, management 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
the accounting rules do prohibit continued capitalization of suspended well costs on the mere
chance that future market conditions will improve or new technologies will be found that would make
the project’s development economically profitable. Often, the ability to move the project into the
development phase and record proved reserves is dependent on obtaining permits and government or
co-venturer approvals, the timing of which is ultimately beyond our control. Exploratory well
costs remain suspended as long as 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 8—Suspended 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 company’s E&P operations. There are
several authoritative guidelines regarding the engineering criteria that must be met before
estimated reserves can be designated as “proved.” Our reservoir engineering organization has
policies and procedures in place 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,
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 assets—generally 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 10—Impairments, in the Notes to Consolidated Financial Statements, for
additional information.
Investments in nonconsolidated entities accounted for under the equity method are reviewed for
impairment when there is evidence of a loss in value 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 investment’s carrying amount. When it is determined
such a loss in value is other than temporary, an impairment charge is recognized for the difference
between the investment’s carrying value and its estimated fair value. When determining whether a
decline in value is other than temporary, management considers factors such as the length of time
and extent of the decline, the investee’s financial condition and near-term prospects, and 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 6—Investments, Loans and
Long-Term Receivables, in the Notes to Consolidated Financial Statements.
Asset Retirement Obligations and Environmental Costs
Under various contracts, permits and regulations, we have material legal obligations to remove
tangible equipment and restore the land or seabed at the end of operations at operational sites.
Our largest asset removal obligations involve removal and disposal of offshore oil and gas
platforms around the world, oil and gas production facilities and pipelines in Alaska, and asbestos
abatement at refineries. The fair values of obligations for dismantling and removing these
facilities are accrued at the installation of the asset based on estimated discounted costs.
Estimating the future asset removal costs necessary for this accounting calculation is difficult.
Most of these removal obligations are many years, or decades, in the future and the contracts and
regulations often have vague descriptions of what removal practices and criteria must be met when
the removal event actually occurs. Asset removal technologies and costs, regulatory and other
compliance considerations,
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
management’s 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
9—Goodwill 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.
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. |
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Potential disruption or interruption of our operations due to accidents, extraordinary
weather events, civil unrest, political events or terrorism. |
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International monetary conditions and exchange controls. |
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Substantial investment or reduced demand for products as a result of existing or future
environmental rules and regulations. |
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Liability for remedial actions, including removal and reclamation obligations, under
environmental regulations. |
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Liability resulting from litigation. |
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General domestic and international economic and political 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. |
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Changes in tax and other laws, regulations (including alternative energy mandates), or
royalty rules applicable to our business. |
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Limited access to capital or significantly higher cost of capital related to illiquidity
or uncertainty in the domestic or international financial markets. |
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Delays in, or our inability to implement, our asset disposition plan. |
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Inability to obtain economical financing for projects, construction or modification of
facilities and general corporate purposes. |
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The operation and financing of our midstream and chemicals joint ventures. |
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The factors generally described in Item 1A—Risk 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:
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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. |
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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. |
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Manage the risk to our cash flows from price exposures on specific crude oil, natural
gas, refined product and electric power transactions. |
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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.
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.
Year-End 2010
2011
2012
2013
2014
2015
Remaining years
Fair value
Year-End 2009
2010
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.
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.
2011–2015
2015–fixed to variable
Fair Value
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:
Sell U.S. dollar, buy euro
Sell U.S. dollar, buy British pound
Sell U.S. dollar, buy Canadian dollar
Sell U.S. dollar, buy Norwegian kroner
Sell U.S. dollar, buy Australian dollar
Sell euro, buy British pound
*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 16—Financial
Instruments and Derivative Contracts, in the Notes to Consolidated Financial Statements.
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
CONOCOPHILLIPS
INDEX TO FINANCIAL STATEMENTS
Supplementary Information
Report of Management
Management prepared, and is responsible for, the consolidated financial statements and the other
information appearing in this annual report. The consolidated financial statements present fairly
the company’s financial position, results of operations and cash flows in conformity with
accounting principles generally accepted in the United States. In preparing its consolidated
financial statements, the company includes amounts that are based on estimates and judgments
management believes are reasonable under the circumstances. The company’s financial statements
have been audited by Ernst & Young LLP, an independent registered public accounting firm appointed
by the Audit and Finance Committee of the Board of Directors and ratified by stockholders.
Management has made available to Ernst & Young LLP all of the company’s financial records and
related data, as well as the minutes of stockholders’ and directors’ meetings.
Assessment of Internal Control Over Financial Reporting
Management is also responsible for establishing and maintaining adequate internal control over
financial reporting. ConocoPhillips’ internal control system was designed to provide reasonable
assurance to the company’s management and directors regarding the preparation and fair presentation
of published financial statements.
All internal control systems, no matter how well designed, have inherent limitations. Therefore,
even those systems determined to be effective can provide only reasonable assurance with respect to
financial statement preparation and presentation.
Management assessed the effectiveness of the company’s internal control over financial reporting as
of December 31, 2010. In making this assessment, it used the criteria set forth by the Committee
of Sponsoring Organizations of the Treadway Commission in Internal Control—Integrated Framework.
Based on our assessment, we believe the company’s internal control over financial reporting was
effective as of December 31, 2010.
Ernst & Young LLP has issued an audit report on the company’s internal control over financial
reporting as of December 31, 2010, and their report is included herein.
/s/ James J. Mulva
James J. Mulva
Chairman and
Chief Executive Officer
February 23, 2011
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 Company’s
management. Our responsibility is to express an opinion on these financial statements, condensed
consolidating financial information, and schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the
financial statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material
respects, the consolidated financial position of ConocoPhillips at December 31, 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 LUKOIL’s 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 Control—Integrated 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
Report of Independent Registered Public Accounting Firm on
Internal Control Over Financial Reporting
We have audited ConocoPhillips’ internal control over financial reporting as of December 31, 2010,
based on criteria established in Internal Control—Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission (the COSO criteria). ConocoPhillips’
management is responsible for maintaining effective internal control over financial reporting, and
for its assessment of the effectiveness of internal control over financial reporting included under
the heading “Assessment of Internal Control Over Financial Reporting” in the accompanying “Report
of Management.” Our responsibility is to express an opinion on the Company’s internal control over
financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether effective internal control over financial reporting was
maintained in all material respects. Our audit included obtaining an understanding of internal
control over financial reporting, assessing the risk that a material weakness exists, testing and
evaluating the design and operating effectiveness of internal control based on the assessed risk,
and performing such other procedures as we considered necessary in the circumstances. We believe
that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable
assurance regarding the reliability of financial reporting and the preparation of financial
statements for external purposes in accordance with generally accepted accounting principles. A
company’s internal control over financial reporting includes those policies and procedures that (1)
pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the
transactions and dispositions of the assets of the company; (2) provide reasonable assurance that
transactions are recorded as necessary to permit preparation of financial statements in accordance
with generally accepted accounting principles, and that receipts and expenditures of the company
are being made only in accordance with authorizations of management and directors of the company;
and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized
acquisition, use, or disposition of the company’s assets that could have a material effect on the
financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or
detect misstatements. Also, projections of any evaluation of effectiveness to future periods are
subject to the risk that controls may become inadequate because of changes in conditions, or that
the degree of compliance with the policies or procedures may deteriorate.
In our opinion, ConocoPhillips maintained, in all material respects, effective internal control
over financial reporting as of December 31, 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.
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| Consolidated Statement of Operations
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ConocoPhillips |
Revenues and Other Income
Sales and other operating revenues*
Equity in earnings of affiliates
Gain on dispositions
Other income
Total Revenues and Other Income
Costs and Expenses
Purchased crude oil, natural gas and products
Production and operating expenses
Selling, general and administrative expenses
Exploration expenses
Depreciation, depletion and amortization
Impairments
Goodwill
LUKOIL investment
Other
Taxes other than income taxes*
Accretion on discounted liabilities
Interest and debt expense
Foreign currency transaction (gains) losses
Total Costs and Expenses
Income (loss) before income taxes
Provision for income taxes
Less: net income attributable to noncontrolling interests
Net Income (Loss) Attributable to ConocoPhillips Per Share
of
Common Stock (dollars)
Basic
Diluted
Average Common Shares Outstanding (in thousands)
*Includes excise taxes on petroleum products sales:
**Recast to reflect a change in accounting principle. See Note 2—Changes in
Accounting Principles, for more information. Also, certain amounts have been
reclassified to conform to current-year presentation.
See Notes to Consolidated Financial Statements.
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| Consolidated Balance Sheet
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ConocoPhillips |
Assets
Cash and cash equivalents
Short-term investments*
Accounts and notes receivable (net of allowance of $32 million in 2010
and $76 million in 2009)
Accounts and notes receivable—related parties
Investment in LUKOIL
Inventories
Prepaid expenses and other current assets
Total Current Assets
Investments and long-term receivables
Loans and advances—related parties
Net properties, plants and equipment
Goodwill
Intangibles
Other assets
Total Assets
Liabilities
Accounts payable
Accounts payable—related parties
Accrued income and other taxes
Employee benefit obligations
Other accruals
Total Current Liabilities
Asset retirement obligations and accrued environmental costs
Joint venture acquisition obligation—related party
Deferred income taxes
Other liabilities and deferred credits
Total Liabilities
Equity
Common stock (2,500,000,000 shares authorized at $.01 par value)
Issued (2010—1,740,529,279 shares; 2009—1,733,345,558 shares)
Par value
Capital in excess of par
Grantor trusts (at cost: 2010—36,890,375 shares; 2009—38,742,261 shares)
Treasury stock (at cost: 2010—272,873,537 shares;
2009—208,346,815 shares)
Accumulated other comprehensive income
Unearned employee compensation
Retained earnings
Total Common Stockholders’ Equity
Noncontrolling interests
Total Equity
Total Liabilities and Equity
*Includes marketable securities of:
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| Consolidated Statement of Cash Flows
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ConocoPhillips |
Cash Flows From Operating Activities
Adjustments to reconcile net income (loss) to net cash provided by
operating activities
Depreciation, depletion and amortization
Impairments
Dry hole costs and leasehold impairments
Accretion on discounted liabilities
Deferred taxes
Undistributed equity earnings
Gain on dispositions
Other
Working capital adjustments
Decrease (increase) in accounts and notes receivable
Decrease (increase) in inventories
Decrease (increase) in prepaid expenses and other current assets
Increase (decrease) in accounts payable
Increase (decrease) in taxes and other accruals
Net Cash Provided by Operating Activities
Cash Flows From Investing Activities
Capital expenditures and investments
Proceeds from asset dispositions
Purchases of short-term investments
Long-term advances/loans—related parties
Collection of advances/loans—related parties
Net Cash Provided by (Used in) Investing Activities
Cash Flows From Financing Activities
Issuance of debt
Repayment of debt
Issuance of company common stock
Repurchase of company common stock
Dividends paid on company common stock
Net Cash Used in Financing Activities
Effect of Exchange Rate Changes on Cash and Cash Equivalents
Net Change in Cash and Cash Equivalents
Cash and cash equivalents at beginning of year
Cash and Cash Equivalents at End of Year
*Recast to reflect a change in accounting principle. See Note 2—Changes in Accounting Principles, for more information.
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| Consolidated Statement of Changes in Equity
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ConocoPhillips |
December 31, 2007*
Other comprehensive income (loss)
Defined benefit pension plans
Net prior service cost
Net actuarial loss
Nonsponsored plans
Foreign currency translation adjustments
Hedging activities
Comprehensive income (loss)
Cash dividends paid on company common stock
Distributions to noncontrolling interests and other
Distributed under benefit plans
Recognition of unearned compensation
December 31, 2008*
Net income
Comprehensive income
December 31, 2009*
Net actuarial gain
Net unrealized gain on securities
December 31, 2010
*Recast to reflect a change in accounting principle. See Note 2—Changes in Accounting Principles, for more information.
See Notes to Consolidated Financial Statements.
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| Notes to Consolidated Financial Statements
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ConocoPhillips |
Note 1—Accounting Policies
| n |
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Consolidation Principles and
Investments—Our consolidated financial
statements include the accounts of
majority-owned, controlled subsidiaries
and variable interest entities where we
are the primary beneficiary. The equity
method is used to account for investments
in affiliates in which we have the
ability to exert significant influence
over the affiliates’ operating and
financial policies. 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 |
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Foreign Currency Translation—Adjustments
resulting from the process of translating
foreign functional currency financial
statements into U.S. dollars are included
in accumulated other comprehensive income
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 |
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Use of Estimates—The preparation of
financial statements in conformity with
accounting principles generally accepted
in the United States requires management
to make estimates and assumptions that
affect the reported amounts of assets,
liabilities, revenues and expenses, and
the disclosures of contingent assets and
liabilities. Actual results could differ
from these estimates. |
| n |
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Revenue Recognition—Revenues 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. |
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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. |
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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 |
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Shipping and Handling Costs—Our Exploration and Production (E&P)
segment includes shipping and handling costs in production and
operating expenses for production activities. Transportation
costs related to E&P marketing activities are recorded in
purchased crude oil, natural gas and products. The Refining and
Marketing (R&M) segment records shipping and handling costs in
purchased crude oil, natural gas and products. Freight costs
billed to customers are recorded as a component of revenue. |
| n |
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Cash Equivalents—Cash equivalents are highly liquid, short-term
investments that are readily convertible to known amounts of cash
and have original maturities of 90 days or less from their date of
purchase. They are carried at cost plus accrued interest, which
approximates fair value. |
| n |
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Short-Term Investments—Investments 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 |
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are classified as short-term investments. See Note 16—Financial Instruments and Derivative
Contracts, for additional information on these held-to-maturity financial instruments. |
| n |
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Inventories—We have several valuation methods for our various
types of inventories and consistently use the following methods
for each type of inventory. Crude oil 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 |
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Fair Value Measurements—We 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. |
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Derivative Instruments—Derivative 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. |
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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. |
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Oil and Gas Exploration and Development—Oil and gas exploration and development costs are
accounted for using the successful efforts method of accounting. |
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Property Acquisition Costs—Oil and gas leasehold acquisition costs are capitalized and
included in the balance sheet caption properties, plants and equipment. Leasehold
impairment is recognized based on exploratory experience and management’s judgment. Upon
achievement of all conditions necessary for reserves to be classified as proved, the
associated leasehold costs are reclassified to proved properties. |
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Exploratory Costs—Geological 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 |
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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. |
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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 8—Suspended Wells, for additional information on suspended wells. |
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Development Costs—Costs incurred to drill and equip development wells, including
unsuccessful development wells, are capitalized. |
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Depletion and Amortization—Leasehold costs of producing properties are depleted using the
unit-of-production method based on estimated proved oil and gas reserves. Amortization of
intangible development costs is based on the unit-of-production method using estimated
proved developed oil and gas reserves. |
| n |
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Capitalized Interest—Interest from external borrowings is
capitalized on major projects with an expected construction period
of one year or longer. Capitalized interest is added to the cost
of the underlying asset and is amortized over the useful lives of
the assets in the same manner as the underlying assets. |
| n |
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Intangible Assets Other Than Goodwill—Intangible assets that have
finite useful lives are amortized by the straight-line method over
their useful lives. Intangible assets that have indefinite useful
lives are not amortized but are tested at least annually for
impairment. Each reporting period, we evaluate the remaining
useful lives of intangible assets not being amortized to determine
whether events and circumstances continue to support indefinite
useful lives. 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 |
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Goodwill—Goodwill 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 unit’s assets (including goodwill), less
liabilities, then a hypothetical purchase price allocation is
performed on the reporting unit’s assets and liabilities using the
fair value of the reporting unit as the purchase price in the
calculation. If the amount of goodwill resulting from this
hypothetical purchase price allocation is less than the recorded
amount of goodwill, the recorded goodwill is written down to the
new amount. For purposes of goodwill impairment calculations, two
reporting units have been determined: Worldwide Exploration and
Production and Worldwide Refining and Marketing. |
| n |
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Depreciation and Amortization—Depreciation 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 |
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Impairment of Properties, Plants and Equipment—Properties, plants
and equipment used in operations are assessed for impairment
whenever changes in facts and circumstances indicate a possible
significant deterioration in the future cash flows expected to be
generated by an asset group 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 |
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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
assets—generally 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. |
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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 |
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Impairment of Investments in Nonconsolidated Entities—Investments
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. |
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Maintenance and Repairs—Costs of maintenance and repairs, which
are not significant improvements, are expensed when incurred. |
| n |
|
Advertising Costs—Production costs of media advertising are
deferred until the first public showing of the advertisement.
Advances to secure advertising slots at specific sporting or other
events are deferred until the event occurs. All other advertising
costs are expensed as incurred, unless the cost has benefits that
clearly extend beyond the interim period in which the expenditure
is made, in which case the advertising cost is deferred and
amortized ratably over the interim periods that clearly benefit
from the expenditure. |
| n |
|
Property Dispositions—When complete units of depreciable property
are sold, the asset cost and related accumulated depreciation are
eliminated, with any gain or loss reflected in 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 |
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Asset Retirement Obligations and Environmental Costs—Fair 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
11—Asset Retirement Obligations and Accrued Environmental Costs,
for additional information. |
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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 |
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Guarantees—Fair value of a guarantee is determined and recorded
as a liability at the time the guarantee is given. The initial
liability is subsequently reduced as we are released from exposure
under the guarantee. We amortize the guarantee liability over the
relevant time period, if one exists, based on the facts and
circumstances surrounding each type of guarantee. In cases where
the guarantee term is indefinite, we reverse the liability when we
have information that the liability is essentially relieved or
amortize it over an appropriate time period as the fair value of
our guarantee exposure declines over time. We amortize the
guarantee liability to the related 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. |
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Stock-Based Compensation—We 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. |
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Income Taxes—Deferred income taxes are computed using the
liability method and are provided on all temporary differences
between the financial reporting basis and the tax basis of our
assets and liabilities, except for deferred taxes on income
considered to be permanently reinvested in certain foreign
subsidiaries and foreign corporate joint ventures. Allowable tax
credits are applied currently as reductions of the provision for
income taxes. Interest related to unrecognized tax benefits is
reflected in interest expense, and penalties in production and
operating expenses. |
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Taxes Collected from Customers and Remitted to Governmental
Authorities—Excise taxes are reported gross within sales and
other operating revenues and taxes other than income taxes, while
other sales and value-added taxes are recorded net in taxes other
than income taxes. |
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Net Income (Loss) Per Share of Common Stock—Basic 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
share—that 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. |
Note 2—Changes in Accounting Principles
LUKOIL Accounting
Effective January 1, 2010, we changed the method used to determine our equity-method share of OAO
LUKOIL’s 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, LUKOIL’s 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, “Investments—Equity 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
LUKOIL’s 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:
Net income attributable to ConocoPhillips
Net income attributable to
ConocoPhillips per share of
common stock
(dollars)
Basic
Diluted
The following table summarizes the line items affected on the consolidated balance sheet at
December 31, 2010:
The following table summarizes the line items affected on the 2010 consolidated statement of cash
flows for year ended December 31, 2010:
Deferred taxes
Undistributed equity earnings
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:
Impairment LUKOIL investment
Net income (loss) attributable to
ConocoPhillips
Net income (loss) attributable to
ConocoPhillips per share of
common stock (dollars)
The following table summarizes the line items affected on the consolidated balance sheet at
December 31, 2009:
The cumulative impact to retained earnings as of January 1, 2008, was a decrease of $649 million as
a result of the accounting change.
The following table summarizes the line items affected on the consolidated statement of cash flows
for years ended December 31:
See Note 6—Investments, 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 3—Variable 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 FASB’s ASC Topic 932, “Extractive
Activities—Oil and Gas” to align the accounting requirements of Topic 932 with the SEC’s 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:
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An expanded definition of oil and gas producing activities to include nontraditional
resources such as bitumen extracted from oil sands. |
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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. |
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Amended definitions of key terms such as “reliable technology” and “reasonable
certainty” which are used in estimating proved oil and gas reserve quantities. |
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A requirement for disclosing separate information about reserve quantities and
financial statement amounts for geographical areas representing 15 percent or more of
proved reserves. |
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Clarification that an entity’s 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 Statements—an 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 parent’s 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 Subsidiary—a 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 Activities—an 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 16—Financial Instruments and Derivative Contracts, for additional
information.
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, “Investments—Equity 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, “Compensation—Retirement 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 19—Employee Benefit
Plans.
Note 3—Variable 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.
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 4—Inventories
Inventories at December 31 were:
Crude oil and petroleum products
Materials, supplies and other
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 5—Assets 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.
Note 6—Investments, Loans and Long-Term Receivables
Components of investments, loans and long-term receivables at December 31 were:
Equity investments*
Long-term receivables
Other investments
*2009 recast to reflect a change in accounting principle. See Note 2—Changes 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 LNG—50 percent owned joint venture with Origin Energy—to develop
coalbed methane production from the Bowen and Surat Basins in Queensland, Australia, as
well as process and export LNG. |
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FCCL Partnership—50 percent owned business venture with Cenovus Energy Inc.—produces
bitumen in the Athabasca oil sands in northeastern Alberta and sells the bitumen blend. |
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WRB Refining LP—50 percent owned business venture with Cenovus—owns the Wood River and
Borger Refineries, which process crude oil into refined products. |
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OOO Naryanmarneftegaz (NMNG)—30 percent ownership interest and a 50 percent governance
interest—a joint venture with LUKOIL to explore for, develop and produce oil and gas
resources in the northern part of Russia’s Timan-Pechora Province. |
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DCP Midstream, LLC—50 percent owned joint venture with Spectra Energy—owns and
operates gas plants, gathering systems, storage facilities and fractionation plants. |
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Chevron Phillips Chemical Company LLC (CPChem)—50 percent owned joint venture with
Chevron Corporation—manufactures 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):
Revenues
Income before income taxes
Current assets
Noncurrent assets
Current liabilities
Noncurrent liabilities
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.
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. FCCL’s
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 13—Joint Venture Acquisition Obligation.
At December 31, 2010, the book value of our investment in WRB was $3,222 million. WRB’s 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
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 2—Changes 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
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 Russia’s 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 LUKOIL’s 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 agreement’s 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:
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$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 Qatar’s 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 |
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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. |
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$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 advances—related parties” line
on the consolidated balance sheet, while the short-term portion is in “Accounts and notes
receivable—related 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 PDVSA’s 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.
Note 7—Properties, 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 company’s
investment in PP&E, with accumulated depreciation, depletion and amortization (Accum. DD&A), at
December 31 was:
Note 8—Suspended Wells
The following table reflects the net changes in suspended exploratory well costs during 2010, 2009
and 2008:
Beginning balance at January 1
Additions pending the determination of proved reserves
Reclassifications to proved properties
Sales of suspended well investment
Charged to dry hole expense
Ending balance at December 31
The following table provides an aging of suspended well balances at December 31, 2010, 2009 and
2008:
Exploratory well costs capitalized for a period of one year or less
Exploratory well costs capitalized for a period greater than one year
Ending balance
Number of projects that have exploratory well costs that have been
capitalized for a period greater than one year
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:
Aktote—Kazakhstan(1)
Alpine satellite—Alaska(1)
Browse Basin—Australia(2)
Caldita/Barossa—Australia(2)
Clair—U.K.(1)
Fiord West—Alaska(1)
Harrison—U.K.(1)
Kairan—Kazakhstan(1)
Kalamkas—Kazakhstan(2)
Kashagan—Kazakhstan(2)
Malikai—Malaysia(1)
NPR-A—Alaska(1)
Petai/Pisagon—Malaysia(2)
Saleski—Canada(2)
Shenandoah—Lower 48(2)
Sunrise 3—Australia(1)
Surmont Beyond Phase II—Canada(2)
Thornbury—Canada(2)
Tiber—Lower 48(2)
Titan—Norway(1)
Ubah—Malaysia(1)
Uge—Nigeria(2)
Eighteen projects of $10 million or less each(1)(2)
Total of 40 projects
(1) Appraisal drilling complete; costs being incurred to assess development.
(2) Additional appraisal wells planned.
Note 9—Goodwill and Intangibles
Goodwill
Changes in the carrying amount of goodwill were as follows:
Balance as of January 1
Accumulated impairment losses
Goodwill allocated to assets
held for sale or sold
Tax and other adjustments
Balance as of December 31
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
company’s 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 company’s 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 entity’s
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 hypothetical acquisition of the reporting unit. The
significant hypothetical purchase price allocation adjustments made to the assets and liabilities
of Worldwide E&P in this second step calculation were in the areas of:
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Adjusting the carrying value of major equity method investments to their estimated fair
values. |
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Adjusting the carrying value of PP&E to the estimated aggregate fair value of all oil
and gas property interests. |
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Recalculating deferred income taxes under FASB ASC Topic 740, “Income Taxes,” after
considering the likely tax basis a hypothetical buyer would have in the assets and
liabilities. |
When determining the above adjustment for the estimated aggregate fair value of PP&E, it was noted
that in order for any residual purchase price to be allocated to goodwill, the purchase price
assigned to PP&E would have to be well below the value of the PP&E implied by recently-observed
metrics from other sales of major oil and gas properties.
Based on the above analysis, we concluded that a $25.4 billion before- and after-tax noncash
impairment of the entire amount of recorded goodwill for the Worldwide E&P reporting unit was
required. This impairment was recorded in the fourth quarter of 2008.
Intangible Assets
Information at December 31 on the carrying value of intangible assets follows:
Indefinite-Lived Intangible Assets
Trade names and trademarks
Refinery air and operating permits
At year-end 2010, our amortized intangible asset balance was $62 million, compared with $83 million
at year-end 2009. Amortization expense was not material for 2010 and 2009, and is not expected to
be material in future years.
Note 10—Impairments
Goodwill
See the “Goodwill Impairment” section of Note 9—Goodwill and Intangibles, for information on the
complete impairment of our E&P segment goodwill.
LUKOIL
See the “LUKOIL” section of Note 6—Investments, Loans and Long-Term Receivables, in the Notes to
Consolidated Financial Statements, for information on the impairment of our LUKOIL investment.
Other Impairments
During 2010, 2009 and 2008, we recognized the following before-tax impairment charges, excluding
the goodwill and LUKOIL investment impairments noted above:
Corporate
2010
During 2010, we recorded a $1,514 million impairment of our refinery in Wilhelmshaven, Germany, due
to canceled plans for a project to upgrade the refinery, as well as a $98 million impairment as a
result of our decision to end our participation in a new refinery project in Yanbu Industrial City,
Saudi Arabia. We also recorded various property impairments of $81 million in our E&P segment.
2009
During 2009, we recorded property impairments of $417 million in our E&P segment, primarily as a
result of lower natural gas price assumptions, reduced volume forecasts, and higher royalty,
operating costs and capital expenditure assumptions. Additionally, we recorded a noncash charge of
$51 million before- and after-tax related to the full impairment of our exploration and production
investments in Ecuador, due to their
expropriation. An arbitration hearing on case merits regarding the expropriation is scheduled for
March 2011. Property impairments of $66 million in our R&M segment, primarily associated with
planned asset dispositions, were also recorded during 2009.
2008
As a result of the economic downturn in the fourth quarter of 2008, the outlook for crude oil and
natural gas prices, refining margins, and power spreads sharply deteriorated, which resulted in
revised capital spending plans. Because of these factors, certain E&P, R&M and Emerging Businesses
properties no longer passed the undiscounted cash flow tests and had to be written down to fair
value. Consequently, we recorded property impairments of approximately $1,480 million, primarily
consisting of various producing fields in the U.S. Lower 48 and Canada, one U.S. and one European
refinery and a U.S. power generation facility. In addition, we recorded property impairments for
increased asset retirement obligations, vacant office buildings in the United States and canceled
R&M capital projects.
Fair Value Remeasurements
The following table shows the values of assets, by major category, measured at fair value on a
nonrecurring basis in periods subsequent to their initial recognition:
Year ended December 31, 2010
Net properties, plants and
equipment (held for use)
Net properties, plants and
equipment (held for sale)
Equity method investments
Year ended December 31, 2009
*Represents the fair value at the time of the impairment.
**Includes a $55 million leasehold impairment charged to exploration expenses.
2010
During 2010, net properties, plants and equipment held for use with a carrying amount of $1,911
million were written down to a fair value of $307 million, resulting in a before-tax loss of $1,604
million. The fair values were determined by the use of internal discounted cash flow models using
estimates of future production, prices, costs and a discount rate believed to be consistent with
those used by principal market participants and cash flow multiples for similar assets and
alternative use.
Also during 2010, net properties, plants and equipment held for sale with a carrying amount of $64
million were written down to their fair value of $23 million less cost to sell of $2 million for a
net $21 million, resulting in a before-tax loss of $43 million. The fair values were primarily
determined by binding negotiated selling prices with third parties, with some adjusted for the fair
value of certain liabilities retained.
In addition, an equity method investment associated with our E&P segment was determined to have a
fair value below carrying amount, and the impairment was considered to be other than temporary.
This investment with a book value of $1,380 million was written down to a fair value of $735
million, resulting in a charge of $645 million before-tax, which is included in the “Equity in
earnings of affiliates” line of our consolidated statement of operations. The fair value was
determined by the application of an internal discounted cash flow model using estimates of future
production, prices, costs and a discount rate believed to be consistent with those used by
principal market participants. In addition, the equity investment fair value considered market
analysis of certain similar undeveloped properties.
2009
In 2009, net properties, plants and equipment held for use with a carrying amount of $610 million
were written down to a fair value of $210 million, resulting in a before-tax loss of $385 million
(including impact of exchange rates). The fair values were determined by the application of an
internal discounted cash flow model using estimates of future production, prices and a discount
rate believed to be consistent with those used by principal market participants.
Also during 2009, net properties, plants and equipment held for sale with a carrying amount of $178
million were written down to a fair value of $121 million ($91 million still unsold at year-end
2009), less cost to sell of $5 million for a net $116 million, resulting in a before-tax loss of
$62 million. The fair values were largely based on binding negotiated prices with third parties,
with some adjusted for the fair value of certain liabilities retained.
At December 31, 2009, certain equity method investments associated with our E&P segment were
determined to have a fair value below carrying amount and the impairment was considered to be other
than temporary. As a result, those investments with a book value of $2,070 million were written
down to a fair value of $1,784 million resulting in a charge of $286 million before-tax, which is
included in the “Equity in earnings of affiliates” line of the consolidated statement of
operations. The fair values were determined by the application of an internal discounted cash flow
model using estimates of future production, prices and a discount rate believed to be consistent
with those used by principal market participants, as well as reference to market analysis of
certain similar undeveloped properties.
Note 11—Asset Retirement Obligations and Accrued Environmental Costs
Asset retirement obligations and accrued environmental costs at December 31 were:
Asset retirement obligations
Accrued environmental costs
Total asset retirement obligations and accrued environmental costs
Asset retirement obligations and accrued environmental costs due
within one year*
Long-term asset retirement obligations and accrued environmental costs
*Classified as a current liability on the balance sheet, under the caption “Other accruals.”
Asset Retirement Obligations
We record the fair value of a liability for an asset retirement obligation when it is incurred
(typically when the asset is installed at the production location). When the liability is
initially recorded, we capitalize the associated asset retirement cost by increasing the carrying
amount of the related properties, plants and equipment. Over time, the liability increases for the
change in its present value, while the capitalized cost depreciates over the useful life of the
related asset.
We have numerous asset removal obligations that we are required to perform under law or contract
once an asset is permanently taken out of service. Most of these obligations are not expected to
be paid until several years, or decades, in the future and will be funded from general company
resources at the time of removal. Our largest individual obligations 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.
During 2010 and 2009, our overall asset retirement obligation changed as follows:
Balance at January 1
Accretion of discount
New obligations
Changes in estimates of existing obligations
Spending on existing obligations
Property dispositions
Foreign currency translation
Balance at December 31
Accrued Environmental Costs
Total accrued environmental costs at December 31, 2010 and 2009, were $994 million and $1,017
million, respectively. The 2010 decrease in total accrued environmental costs is due to payments
and settlements during the year exceeding new accruals, accrual adjustments and accretion.
We had accrued environmental costs of $624 million and $632 million at December 31, 2010 and 2009,
respectively, primarily related to cleanup at domestic refineries and underground storage tanks at
U.S. service stations, and remediation activities required by Canada and the state of Alaska at
exploration and production sites. We had also accrued in Corporate and Other $278 million and $292
million of environmental costs associated with nonoperator sites at December 31, 2010 and 2009,
respectively. In addition, $92 million and $93 million were included at both December 31, 2010 and
2009, respectively, where the company has been named a potentially responsible party under the
Federal Comprehensive Environmental Response, Compensation and Liability Act, or similar state
laws. Accrued environmental liabilities are expected to be paid over periods extending up to 30
years.
Because a large portion of the accrued environmental costs were acquired in various business
combinations, they are discounted obligations. Expected expenditures for acquired environmental
obligations are discounted using a weighted-average 5 percent discount factor, resulting in an
accrued balance for acquired environmental liabilities of $452 million at December 31, 2010. The
expected future undiscounted payments related to the portion of the accrued environmental costs
that have been discounted are: $54 million in 2011, $38 million in 2012, $41 million in 2013, $30
million in 2014, $28 million in 2015, and $342 million for all future years after 2015.
Note 12—Debt
Long-term debt at December 31 was:
9.875% Debentures due 2010
9.375% Notes due 2011
9.125% Debentures due 2021
8.75% Notes due 2010
8.20% Debentures due 2025
8.125% Notes due 2030
7.9% Debentures due 2047
7.8% Debentures due 2027
7.68% Notes due 2012
7.65% Debentures due 2023
7.625% Debentures due 2013
7.40% Notes due 2031
7.375% Debentures due 2029
7.25% Notes due 2031
7.20% Notes due 2031
7% Debentures due 2029
6.95% Notes due 2029
6.875% Debentures due 2026
6.68% Notes due 2011
6.65% Debentures due 2018
6.50% Notes due 2011
6.50% Notes due 2039
6.40% Notes due 2011
6.35% Notes due 2011
6.00% Notes due 2020
5.951% Notes due 2037
5.95% Notes due 2036
5.90% Notes due 2032
5.90% Notes due 2038
5.75% Notes due 2019
5.625% Notes due 2016
5.50% Notes due 2013
5.30% Notes due 2012
5.20% Notes due 2018
4.75% Notes due 2012
4.75% Notes due 2014
4.60% Notes due 2015
4.40% Notes due 2013
Commercial paper at 0.14% – 0.34% at year-end 2010 and 0.06% –
0.29% at year-end 2009
Floating Rate Five-Year Term Note due 2011 at 0.575% at year-end
2010 and 0.45% at year-end 2009
Industrial Development Bonds due 2012 through 2038 at 0.33% –
5.75% at year-end 2010 and 0.24% – 5.75% at year-end 2009
Guarantee of savings plan bank loan payable due 2015 at 2.06% at
year-end 2010 and 2.01% at year-end 2009
Note payable to Merey Sweeny, L.P. due 2020 at 7% (related party)
Marine Terminal Revenue Refunding Bonds due 2031 at 0.33% –
0.48% at year-end 2010 and 0.26% – 0.40% at year-end 2009
Debt at face value
Capitalized leases
Net unamortized premiums and discounts
Maturities of long-term borrowings, inclusive of net unamortized premiums and discounts, in
2011 through 2015 are: $936 million, $2,081 million, $1,277 million, $1,530 million and $1,610
million, respectively. At December 31, 2010, we had classified $1,125 million of short-term debt
as long-term debt, based on our ability and intent to refinance the obligation on a long-term basis
under our revolving credit facilities.
During 2010, the following debt instruments were repaid prior to their maturity:
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The $400 million 6.68% Notes due 2011. |
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The $178 million 6.40% Notes due 2011. |
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The $1,750 million 6.35% Notes due 2011. |
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The $350 million 5.30% Notes due 2012. |
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The $750 million remaining balance of the Floating Rate Five-Year Term Note due 2011. |
During 2010, the following debt instruments were repaid at their maturity:
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The $150 million 9.875% Debentures due 2010. |
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The $1,264 million 8.75% Notes due 2010. |
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.
We have two commercial paper programs: the ConocoPhillips $6.35 billion program, primarily a
funding source for short-term working capital needs, and the ConocoPhillips Qatar Funding Ltd. $1.5
billion commercial paper program, which is used to fund commitments relating to the Qatargas 3
Project. Commercial paper maturities are generally limited to 90 days. At both December 31, 2010
and 2009, we had no direct outstanding borrowings under the revolving credit facilities, but $40
million in letters of credit had been issued. In addition, under the two commercial paper
programs, there was $1,182 million of commercial paper 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.
Note 13—Joint Venture Acquisition Obligation
In 2007, we closed on a business venture with Cenovus. As a part of the transaction, we are
obligated to contribute $7.5 billion, plus interest, over a 10-year period that began in 2007, to
the upstream business venture, FCCL Partnership, 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, $695 million was
short-term and was included in the “Accounts payable—related 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.
Note 14—Guarantees
At December 31, 2010, we were liable for certain contingent obligations under various contractual
arrangements as described below. We recognize a liability, at inception, for the fair value of our
obligation as a guarantor for newly issued or modified guarantees. Unless the carrying amount of
the liability is noted below, we have not recognized a liability either because the guarantees were
issued prior to December 31, 2002, or because the fair value of the obligation is immaterial. In
addition, unless otherwise stated we are not currently performing with any significance under the
guarantee and expect future performance to be either immaterial or have only a remote chance of
occurrence.
Construction Completion Guarantees
In December 2005, we issued a construction completion guarantee for 30 percent of the $4 billion in
loan facilities of Qatargas 3, which are being used to finance the construction of an LNG train in
Qatar. Of the $4 billion in loan facilities, we committed to provide $1.2 billion. The maximum
potential amount of future payments to third-party lenders under the guarantee is estimated to be
$850 million, which could become payable if the full debt financing is utilized and completion of
the Qatargas 3 Project is not achieved. The project financing will be nonrecourse to
ConocoPhillips upon certified completion, expected in 2011. At December 31, 2010, the carrying
value of the guarantee to third-party lenders was $11 million.
Guarantees of Joint Venture Debt
At December 31, 2010, we had guarantees outstanding for our portion of joint venture debt
obligations, which have terms of up to 15 years. The maximum potential amount of future payments
under the guarantees is approximately $80 million. Payment would be required if a joint venture
defaults on its debt obligations.
Other Guarantees
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In conjunction with our purchase of a 50 percent ownership interest in APLNG from Origin
Energy in October 2008, we agreed to participate, if and when requested, in any parent
company guarantees that were outstanding at the time we purchased our interest in APLNG.
These parent company guarantees cover the obligation of APLNG to deliver natural gas under
several sales agreements with remaining terms of 6 to 21 years. Our maximum potential amount
of future payments, or cost of volume delivery, under these guarantees is estimated to be
$1,578 million ($3,477 million in the event of intentional or reckless breach) at December
2010 exchange rates based on our 50 percent share of the remaining contracted volumes, which
could become payable if APLNG fails to meet its obligations under these agreements and the
obligations cannot otherwise be mitigated. Future payments are considered unlikely, as the
payments, or cost of volume delivery, would only be triggered if APLNG does not have enough
natural gas to meet these sales commitments and if the co-venturers do not make necessary
equity contributions into APLNG. |
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We have other guarantees with maximum future potential payment amounts totaling $400
million, which consist primarily of guarantees to fund the short-term cash liquidity deficits
of certain joint ventures, a guarantee of minimum charter revenue for two LNG vessels, one
small construction completion guarantee, guarantees relating to the startup of a refining
joint venture, guarantees of the lease payment obligations of a joint venture, and guarantees
of the residual value of leased corporate aircraft. These guarantees generally extend up to
14 years or life of the venture. |
Indemnifications
Over the years, we have entered into various agreements to sell ownership interests in certain
corporations, joint ventures and assets that gave rise to qualifying indemnifications. Agreements
associated with these sales include indemnifications for taxes, environmental liabilities, permits
and licenses, employee claims, real estate indemnity against tenant defaults, and litigation. The
terms of these indemnifications vary greatly. The
majority of these indemnifications are related to environmental issues, the term is generally
indefinite and the maximum amount of future payments is generally unlimited. The carrying amount
recorded for these indemnifications at December 31, 2010, was $386 million. We amortize the
indemnification liability over the relevant time period, if one exists, based on the facts and
circumstances surrounding each type of indemnity. In cases where the indemnification term is
indefinite, we will reverse the liability when we have information the liability is essentially
relieved or amortize the liability over an appropriate time period as the fair value of our
indemnification exposure declines. Although it is reasonably possible future payments may exceed
amounts recorded, due to the nature of the indemnifications, it is not possible to make a
reasonable estimate of the maximum potential amount of future payments. Included in the recorded
carrying amount were $250 million of environmental accruals for known contamination that are
included in asset retirement obligations and accrued environmental costs at December 31, 2010. For
additional information about environmental liabilities, see Note 15—Contingencies and Commitments.
Note 15—Contingencies and Commitments
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.
See Note 20—Income Taxes, for additional information about income-tax-related contingencies.
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 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.
Environmental
We are subject to federal, state and local environmental laws and regulations. When we prepare our
consolidated financial statements, we record accruals for environmental liabilities based on
management’s best estimates, using all information that is available at the time. We measure
estimates and base liabilities on currently available facts, existing technology, and presently
enacted laws and regulations, taking into account stakeholder and business considerations. When
measuring environmental liabilities, we also consider our prior experience in remediation of
contaminated sites, other companies’ cleanup experience, and data released by the U.S.
Environmental Protection Agency (EPA) or other organizations. We consider unasserted claims in our
determination of environmental liabilities, and we accrue them in the period they are both probable
and reasonably estimable.
Although liability of those potentially responsible for environmental remediation costs is
generally joint and several for federal sites and frequently so for state sites, we are usually
only one of many companies cited at a particular site. Due to the joint and several liabilities,
we could be responsible for all cleanup costs related to any site at which we have been designated
as a potentially responsible party. We have been successful to date
in sharing cleanup costs with other financially sound companies. 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 the site conditions,
apportion responsibility and determine the appropriate remediation. In some instances, we may have
no liability or may attain a settlement of liability. Where it appears that other potentially
responsible parties may be financially unable to bear their proportional share, we consider this
inability in estimating our potential liability, and we adjust our accruals accordingly.
As a result of various acquisitions in the past, we assumed certain environmental obligations.
Some of these environmental obligations are mitigated by indemnifications made by others for our
benefit and some of the indemnifications are subject to dollar limits and time limits. We have not
recorded accruals for any potential contingent liabilities that we expect to be funded by the prior
owners under these indemnifications.
We are currently participating in environmental assessments and cleanups at numerous federal
Superfund and comparable state sites. After an assessment of environmental exposures for cleanup
and other costs, we make accruals on an undiscounted basis (except those acquired in a purchase
business combination, which we record on a discounted basis) for planned investigation and
remediation activities for sites where it is probable future costs will be incurred and these costs
can be reasonably estimated. We have not reduced these accruals for possible insurance recoveries.
In the future, we may be involved in additional environmental assessments, cleanups and
proceedings. See Note 11—Asset Retirement Obligations and Accrued Environmental Costs, for a
summary of our accrued environmental liabilities.
Legal Proceedings
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.
Other Contingencies
We have contingent liabilities resulting from throughput agreements with pipeline and processing
companies not associated with financing arrangements. Under these agreements, we may be required
to provide any such company with additional funds through advances and penalties for fees related
to throughput capacity not utilized. In addition, at December 31, 2010, we had performance
obligations secured by letters of credit of $1,784 million (of which $40 million was issued under
the provisions of our revolving credit facility, and the remainder was issued as direct bank
letters of credit) related to various purchase commitments for materials, supplies, services and
items of permanent investment incident to the ordinary conduct of business.
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 government’s Nationalization Decree. As a
result, Venezuela’s national oil company, 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 Bank’s International Centre for Settlement of
Investment Disputes (ICSID). An arbitration hearing was held during 2010 before ICSID. We are
awaiting their decision. See Note 10—Impairments, for additional information about expropriated
assets in Ecuador.
Long-Term Throughput Agreements and Take-or-Pay Agreements
We have certain throughput agreements and take-or-pay agreements in support of financing
arrangements. The agreements typically provide for natural gas or crude oil transportation to be
used in the ordinary course of the company’s business. The aggregate amounts of estimated payments
under these various agreements are: 2011—$369 million; 2012—$410 million; 2013—$408 million;
2014—$408 million; 2015—$400 million; and 2016 and after—$4,402 million. Total payments under
the agreements were $216 million in 2010, $114 million in 2009 and $119 million in 2008.
Note 16—Financial Instruments and Derivative Contracts
Financial Instruments
We invest excess cash in financial instruments with maturities based on our cash forecasts for the
various currency pools we manage. The maturities of these investments may from time to time extend
beyond 90 days. The types of financial instruments in which we currently invest include:
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Time Deposits: Interest bearing deposits placed with approved financial institutions. |
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Commercial Paper: Unsecured promissory notes issued by a corporation, commercial bank, or
government agency purchased at a discount to mature at par. |
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Government or government agency obligations: Negotiable debt obligations issued by a
government or government agency. |
These financial instruments appear in the “Cash and cash equivalents” line of our consolidated
balance sheet if the maturities at the time we made the investments were 90 days or less;
otherwise, these held-to-maturity investments are included in the “Short-term investments” line.
At December 31, 2010, we held the following financial instruments:
Cash
Time Deposits
Remaining maturities from 1 to 90 days
Remaining maturities from 91 to 180 days
Commercial Paper
Government Obligations
*Carrying value approximates fair value.
Derivative Instruments
We use financial and commodity-based derivative contracts to manage exposures to fluctuations in
foreign currency exchange rates, commodity prices, and interest rates, or to capture market
opportunities. Since we are not currently using cash-flow hedge accounting, all gains and losses,
realized or unrealized, from derivative contracts have been recognized in the consolidated
statement of operations. Gains and losses from derivative contracts held for trading not directly
related to our physical business, whether realized or unrealized, have been reported net in other
income.
Purchase and sales contracts with fixed minimum notional volumes for commodities that are readily
convertible to cash (e.g., crude oil, natural gas and gasoline) are recorded on the balance sheet
as derivatives unless the contracts are eligible for and we elect the normal purchases and normal
sales exception (i.e., contracts to purchase or sell quantities we expect to use or sell over a
reasonable period in the normal course of business). We record most of our contracts to buy or
sell natural gas and the majority of our contracts to sell power as derivatives, but we do apply
the normal purchases and normal sales exception to certain long-term contracts to sell our natural
gas production. We generally apply this normal purchases and normal sales exception to eligible
crude oil and refined product commodity purchase and sales contracts; however, we may elect not to
apply this exception (e.g., when another derivative instrument will be used to mitigate the risk of
the purchase or sales contract but hedge accounting will not be applied, in which case both the
purchase or sales contract and the derivative contract mitigating the resulting risk will be
recorded on the balance sheet at fair value).
We value our exchange-cleared derivatives using closing prices provided by the exchange as of the
balance sheet date, and these are classified as Level 1 in the fair value hierarchy.
Over-the-counter (OTC) financial swaps and physical commodity forward purchase and sales contracts
are generally valued using quotations provided by brokers and price index developers such as Platts
and Oil Price Information Service. These quotes are corroborated with market data and are
classified as Level 2. In certain less liquid markets or for longer-term contracts, forward prices
are not as readily available. In these circumstances, OTC swaps and physical commodity purchase
and sales contracts are valued using internally developed methodologies that consider historical
relationships among various commodities that result in management’s best estimate of fair value.
These contracts are classified as Level 3. A contract that is initially classified as Level 3 due
to absence or insufficient corroboration of broker quotes over a material portion of the contract
will transfer to Level 2 when the portion of the trade having no quotes or insufficient
corroboration becomes an insignificant portion of the contract. A contract would also transfer to
Level 2 if we began using a corroborated broker quote that has become available. Conversely, if a
corroborated broker quote ceases to be available or used by us, the contract would transfer from
Level 2 to Level 3. There were no transfers in or out of Level 1.
Financial OTC and physical commodity options are valued using industry-standard models that
consider various assumptions, including quoted forward prices for commodities, time value,
volatility factors, and contractual prices for the underlying instruments, as well as other
relevant economic measures. The degree to which these inputs are observable in the forward markets
determines whether the options are classified as Level 2 or 3.
We use a mid-market pricing convention (the mid-point between bid and ask prices). When
appropriate, valuations are adjusted to reflect credit considerations, generally based on available
market evidence.
The fair value hierarchy for our derivative assets and liabilities accounted for at fair value on a
recurring basis was:
Commodity derivatives
Interest rate derivatives
Foreign currency
exchange derivatives
Total liabilities
Net assets (liabilities)
The derivative values above are based on analysis of each contract as the fundamental unit of
account; therefore, derivative assets and liabilities with the same counterparty are not reflected
net where the legal right of offset exists. Gains or losses from contracts in one level may be
offset by gains or losses on contracts in another level or by changes in values of physical
contracts or positions that are not reflected in the table above.
As reflected in the table above, Level 3 activity is not material.
Commodity Derivative Contracts—We operate in the worldwide crude oil, bitumen, refined product,
natural gas, LNG, natural gas liquids and electric power markets and are exposed to fluctuations in
the prices for these commodities. These fluctuations can affect our revenues, as well as the cost
of operating, investing and financing activities. Generally, our policy is to remain exposed to
the market prices of commodities; however, we use futures, forwards, swaps and options in various
markets to balance physical systems, meet customer needs, manage price exposures on specific
transactions, and do a limited, immaterial amount of trading not directly related to our physical
business. We also 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 used to optimize these activities which may move our risk profile
away from market average prices.
The fair value of commodity derivative assets and liabilities and the line items where they appear
on our consolidated balance sheet were:
Hedge accounting has not been used for any items in the table. The
amounts shown are presented gross (i.e., without netting assets and
liabilities with the same counterparty where the right of offset and
intent to net exist).
The gains (losses) from commodity derivatives incurred, and the line items where they appear
on our consolidated statement of operations were:
Hedge accounting has not been used for any items in the table.
The table below summarizes our material net exposures resulting from outstanding commodity
derivative contracts. These financial and physical derivative contracts are primarily used to
manage price exposure on our underlying operations. The underlying exposures may be from
non-derivative positions such as inventory volumes or firm natural gas transport contracts.
Financial derivative contracts may also offset physical derivative contracts, such as forward sales
contracts.
Commodity
Crude oil, refined products and natural gas liquids (millions of barrels)
Natural gas and power (billions of cubic feet equivalent)
Fixed price
Basis
Interest Rate Derivative Contracts—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 London
Interbank Offered Rate (LIBOR)-based floating rate. 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.
The fair value of interest rate derivative assets and liabilities and the line items where they
appear on our consolidated balance sheet were:
Hedge accounting was used for all items in the table. The amounts shown are presented gross.
The (gains) and losses from interest rate derivatives used in a fair-value hedge, losses and
(gains) from changes in the fair value of the hedged debt, and the line item where they appear on
our consolidated statement of operations were:
Recorded in interest and debt expense
From the interest rate derivatives
From the hedged debt
The extent to which the change in value of the interest rate derivatives differs from the
change in value of the hedged debt is an adjustment to recorded interest expense on the fixed-rate
debt that effectively results in interest expense for the period being recorded at floating-rate
LIBOR plus the swap spread.
Foreign Currency Exchange Derivatives—We have foreign currency exchange rate risk resulting from
international operations. We do not comprehensively hedge the exposure to movements in currency
exchange rates, 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.
The fair value of foreign currency exchange derivative assets and liabilities, and the line items
where they appear on our consolidated balance sheet were:
Hedge accounting has not been used for any items in the table. The amounts shown are presented gross.
Gains and losses from foreign currency exchange derivatives and the line item where they
appear on our consolidated statement of operations were:
We had the following net notional position of outstanding foreign currency exchange
derivatives:
Foreign Currency Exchange Derivatives
Sell U.S. dollar, buy other currencies**
Sell Euro, buy British pound
*Denominated in U.S. dollars (USD) and euros (EUR).
**Primarily euro, Canadian dollar, Norwegian krone and British pound.
Credit Risk
Financial instruments potentially exposed to concentrations of credit risk consist primarily of
cash equivalents, OTC derivative contracts and trade receivables. Our cash equivalents and
short-term investments are placed in high-quality commercial paper, money market funds, government
debt securities and time deposits with major international banks and financial institutions.
The credit risk from our OTC derivative contracts, such as forwards and swaps, derives from the
counterparty to the transaction. Individual counterparty exposure is managed within predetermined
credit limits and includes the use of cash-call margins when appropriate, thereby reducing the risk
of significant nonperformance. We also use futures contracts, but futures have a negligible credit
risk because they are traded on the New York Mercantile Exchange or the IntercontinentalExchange
(ICE) Futures.
Our trade receivables result primarily from our petroleum operations and reflect a broad national
and international customer base, which limits our exposure to concentrations of credit risk. The
majority of these receivables have payment terms of 30 days or less, and we continually monitor
this exposure and the creditworthiness of the counterparties. We do not generally require
collateral to limit the exposure to loss; however, we will sometimes use letters of credit,
prepayments, and master netting arrangements to mitigate credit risk with counterparties that both
buy from and sell to us, as these agreements permit the amounts owed by us or owed to others to be
offset against amounts due us.
Certain of our derivative instruments contain provisions that require us to post collateral if the
derivative exposure exceeds a threshold amount. We have contracts with fixed threshold amounts and
other contracts with variable threshold amounts that are contingent on our credit rating. The
variable threshold amounts typically decline for lower credit ratings, while both the variable and
fixed threshold amounts typically revert to zero if we fall below investment grade. Cash is the
primary collateral in all contracts; however, many also permit us to post letters of credit as
collateral.
The aggregate fair value of all derivative instruments with such credit-risk-related contingent
features that were in a liability position on December 31, 2010, was $225 million, for which no
collateral was posted. If our credit rating were lowered one level from its “A” rating (per
Standard and Poor’s) on December 31, 2010, we would be required to post no additional collateral to
our counterparties. If we were downgraded below investment grade, we would be required to post
$225 million of additional collateral, either with cash or letters of credit.
Fair Values of Financial Instruments
We used the following methods and assumptions to estimate the fair value of financial instruments:
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Cash, cash equivalents, and short-term investments: The carrying amount reported on the
balance sheet approximates fair value. |
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Accounts and notes receivable: The carrying amount reported on the balance sheet
approximates fair value. |
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Investment in LUKOIL shares: See Note 6—Investments, Loans and Long-Term Receivables,
for a discussion of the carrying value and fair value of our investment in LUKOIL shares. |
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Debt: The carrying amount of our floating-rate debt approximates fair value. The fair
value of the fixed-rate debt is estimated based on quoted market prices. |
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Fixed-rate 5.3 percent joint venture acquisition obligation: Fair value is estimated
based on the net present value of the future cash flows, discounted at a December 31
effective yield rate of 1.87 percent, based on yields of U.S. Treasury securities of
similar average duration adjusted for our average credit risk spread and the amortizing
nature of the obligation principal. See Note 13—Joint Venture Acquisition Obligation, for
additional information. |
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Commodity swaps: Fair value is estimated based on forward market prices and approximates
the exit price at period end. When forward market prices are not available, they are
estimated using the forward prices of a similar commodity with adjustments for differences
in quality or location. |
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Futures: Fair values are based on quoted market prices obtained from the New York
Mercantile Exchange, the ICE Futures, or other traded exchanges. |
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Interest rate swap contracts: Fair value is estimated based on a pricing model and
market observable interest rate swap curves obtained from a third-party market data
provider. |
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Forward-exchange contracts: Fair value is estimated by comparing the contract rate to
the forward rate in effect on December 31 and approximates the exit price at that date. |
Our commodity derivative and financial instruments were:
Financial assets
Foreign currency exchange derivatives
Investment in LUKOIL*
Financial liabilities
Total debt, excluding capital leases
Joint venture acquisition obligation
*Prior to September 30, 2010, our investment in LUKOIL was accounted for using the
equity method. See Note 6—Investments, Loans and Long-Term Receivables, for more information.
The amounts shown for derivatives in the preceding table are presented net (i.e., assets and
liabilities with the same counterparty are netted where the right of offset and intent to net
exist). In addition, the 2010 commodity derivative assets and liabilities appear net of $5 million
of obligations to return cash collateral and $324 million of rights to reclaim cash collateral,
respectively. The 2009 commodity derivative assets and liabilities appear net of $70 million of
obligations to return cash collateral and $148 million of rights to reclaim cash collateral,
respectively. No collateral was deposited or held for the foreign currency exchange derivatives.
Note 17—Equity
Common Stock
The changes in our shares of common stock, as categorized in the equity section of the balance
sheet, were:
Issued
Beginning of year
End of year
Held in Treasury
Repurchase of common stock
Held in Grantor Trusts
Preferred Stock
We have 500 million shares of preferred stock authorized, par value $.01 per share, none of which
was issued or outstanding at December 31, 2010 or 2009.
Noncontrolling Interests
At December 31, 2010 and 2009, we had outstanding $547 million and $590 million, respectively, of
equity in less-than-wholly owned consolidated subsidiaries held by noncontrolling interest owners.
The noncontrolling interest amounts are primarily related to operating joint ventures we control.
The largest of these, amounting to $520 million at December 31, 2010, and $565 million at December
31, 2009, was related to Darwin LNG operations, located in Australia’s Northern Territory.
Preferred Share Purchase Rights
In 2002, our Board of Directors authorized and declared a dividend of one preferred share purchase
right for each common share outstanding, and authorized and directed the issuance of one right per
common share for any newly issued shares. The rights have certain anti-takeover effects. The
rights will cause substantial dilution to a person or group that attempts to acquire ConocoPhillips
on terms not approved by the Board of Directors. However, since the rights may either be redeemed
or otherwise made inapplicable by ConocoPhillips prior to an acquirer obtaining beneficial
ownership of 15 percent or more of ConocoPhillips’ common stock, the rights should not interfere
with any merger or business combination approved by the Board of Directors prior to that
occurrence. The rights, which expire June 30, 2012, will be exercisable only if a person or group
acquires 15 percent or more of the company’s common stock or commences a tender offer that would
result in ownership of 15 percent or more of the common stock. Each right would entitle
stockholders to buy one one-hundredth of a share of preferred stock at an exercise price of $300.
If an acquirer obtains 15 percent or more of ConocoPhillips’ common stock, then each right will be
adjusted so that it will entitle the holder (other than the acquirer, whose rights will become
void) to purchase, for the then exercise price, a number of shares of ConocoPhillips’ common stock
equal in value to two times the exercise price of the right. In addition, the rights enable
holders to purchase the stock of an acquiring company at a discount, depending on specific
circumstances. We may redeem the rights in whole, but not in part, for one cent per right.
Note 18—Non-Mineral Leases
The company leases ocean transport vessels, tugboats, barges, pipelines, railcars, corporate
aircraft, service stations, drilling equipment, computers, office buildings and other facilities
and equipment. Certain leases include escalation clauses for adjusting rental payments to reflect
changes in price indices, as well as renewal options and/or options to purchase the leased property
for the fair market value at the end of the lease term. There are no significant restrictions
imposed on us by the leasing agreements in regards to dividends, asset dispositions or borrowing
ability. Leased assets under capital leases were not significant in any period presented.
At December 31, 2010, future minimum rental payments due under noncancelable leases were:
Less income from subleases
Net minimum operating lease payments
*Includes $72 million related to railcars subleased to CPChem, a related party.
Operating lease rental expense for the years ended December 31 was:
Total rentals*
Less sublease rentals
*Includes $22 million, $21 million and $22 million of contingent
rentals in 2010, 2009 and 2008, respectively. Contingent rentals
primarily are related to production and refining equipment, and are
based on throughput or volume of product sold.
Note 19—Employee Benefit Plans
Pension and Postretirement Plans
An analysis of the projected benefit obligations for our pension plans and accumulated benefit
obligations for our postretirement health and life insurance plans follows:
Change in Benefit Obligation
Benefit obligation at January 1
Service cost
Interest cost
Plan participant contributions
Medicare Part D subsidy
Plan amendments
Actuarial loss
Benefits paid
Curtailment
Recognition of termination benefits
Foreign currency exchange rate change
Benefit obligation at December 31*
*Accumulated benefit obligation portion of above
at December 31:
Change in Fair Value of Plan Assets
Fair value of plan assets at January 1
Actual return on plan assets
Company contributions
Fair value of plan assets at December 31
Funded Status
Amounts Recognized in the
Consolidated Balance Sheet at
December 31
Total recognized
Weighted-Average Assumptions
Used to Determine Benefit
Obligations at December 31
Discount rate
Rate of compensation increase
Weighted-Average Assumptions
Used to Determine Net
Periodic Benefit Cost for
Years Ended December 31
Expected return on plan assets
For both U.S. and international pensions, the overall expected long-term rate of return is
developed from the expected future return of each asset class, weighted by the expected allocation
of pension assets to that asset class. We rely on a variety of independent market forecasts in
developing the expected rate of return for each class of assets.
Included in other comprehensive income at December 31 were the following before-tax amounts that
had not been recognized in net periodic postretirement benefit cost:
Unrecognized net actuarial loss (gain)
Unrecognized prior service cost
Sources of Change in Other Comprehensive
Income
Net gain (loss) arising during the period
Amortization of (gain) loss included in
income
Net gain (loss) during the period
Prior service cost arising during the
period
Amortization of prior service cost
included in income
Net prior service cost during the period
Amounts included in accumulated other comprehensive income at December 31, 2010, that are expected
to be amortized into net periodic postretirement cost during 2011 are provided below:
For our tax-qualified pension plans with projected benefit obligations in excess of plan assets,
the projected benefit obligation, the accumulated benefit obligation, and the fair value of plan
assets were $7,661 million, $6,718 million, and $5,706 million, respectively, at December 31, 2010,
and $7,145 million, $5,653 million, and $4,748 million, respectively, at December 31, 2009.
For our unfunded nonqualified key employee supplemental pension plans, the projected benefit
obligation and the accumulated benefit obligation were $479 million and $407 million, respectively,
at December 31, 2010, and were $419 million and $355 million, respectively, at December 31, 2009.
The components of net periodic benefit cost of all defined benefit plans are presented in the
following table:
Components of Net
Periodic Benefit Cost
Expected return on plan
assets
Amortization of prior
service cost
Recognized net actuarial
loss (gain)
Net periodic benefit cost
We recognized pension settlement losses of $15 million and $18 million and special termination
benefits of $5 million and $2 million in 2009 and 2008, respectively. None were recognized in
2010.
In determining net pension and other postretirement benefit costs, we amortize prior service costs
on a straight-line basis over the average remaining service period of employees expected to receive
benefits under the plan. For net actuarial gains and losses, we amortize 10 percent of the
unamortized balance each year.
We have multiple nonpension postretirement benefit plans for health and life insurance. The health
care plans are contributory and subject to various cost sharing features, with participant and
company contributions adjusted annually; the life insurance plans are noncontributory. The
measurement of the accumulated postretirement benefit obligation assumes a health care cost trend
rate of 8 percent in 2011 that declines to 5 percent by 2023. A one-percentage-point change in the
assumed health care cost trend rate would have the following effects on the 2010 amounts:
Effect on total of service and interest cost components
Effect on the postretirement benefit obligation
Plan Assets—We follow a policy of broadly diversifying pension plan assets across asset classes,
investment managers, and individual holdings. As a result, our plan assets have no significant
concentrations of credit risk. Asset classes that are considered appropriate include U.S.
equities, non-U.S. equities, U.S. fixed income, non-U.S. fixed income, real estate and private
equity investments. Plan fiduciaries may consider and add other asset classes to the investment
program from time to time. The target allocations for plan assets are 56 percent equity
securities, 35 percent debt securities, 6 percent real estate and 3 percent in all other types of
investments. Generally, the investments in the plans are publicly traded, therefore minimizing
liquidity risk in the portfolio.
Following is a description of the valuation methodologies used for the pension plan assets. There
have been no changes in the methodologies used at December 31, 2010 and 2009.
Fair values of equity securities and government debt securities categorized in Level 1 are
primarily based on quoted market prices.
Fair values of corporate debt securities, agency and mortgage-backed securities and government debt
securities categorized in Level 2 are estimated using recently executed transactions and market
price quotations. If there have been no market transactions in a particular fixed income security,
its fair market value is calculated by pricing models that benchmark the security against other
securities with actual market prices. When observable price quotations are not available, fair
value is based on pricing models that use something other than actual market prices (e.g.,
observable inputs such as benchmark yields, reported trades and issuer spreads for similar
securities), and these securities are categorized in Level 3 of the fair value hierarchy.
Fair values of investments in common/collective trusts are determined by the issuer of each fund
based on the fair value of the underlying assets.
Fair values of mutual funds are valued based on quoted market prices, which represent the net asset
value of shares held.
Cash is valued at cost, which approximates fair value. Fair values of cash equivalents categorized
in Level 2 are valued using observable yield curves, discounting and interest rates.
Fair values of exchange-traded derivatives classified in Level 1 are based on quoted market prices.
For other derivatives classified in Level 2, the values are generally calculated from pricing
models with market input parameters from third-party sources.
Private equity funds are valued at net asset value as determined by the issuer based on the fair
value of the underlying assets.
Fair values of insurance contracts are valued at the present value of the future benefit payments
owed by the insurance company to the Plans’ participants.
Fair values of real estate investments are valued using real estate valuation techniques and other
methods that include reference to third-party sources and sales comparables where available.
A portion of U.S. pension plan assets is held as a participating interest in an insurance annuity
contract. This participating interest is calculated as the market value of investments held under
this contract, less the accumulated benefit obligation covered by the contract. The participation
interest is classified as Level 3 in the fair value hierarchy as the fair value is determined via a
combination of comparison to quoted market prices and estimation using recently executed
transactions and market price quotations for contract assets, and an actuarial present value
computation for contract obligations. At December 31, 2010, the participating interest in the
annuity contract was valued at $92 million and consisted of $357 million in debt securities, less
$265 million for the accumulated benefit obligation covered by the contract. At December 31, 2009,
the participating interest in the annuity contract was valued at $94 million and consisted of $349
million in debt securities, less $255 million for the accumulated benefit obligation covered by the
contract. The net change from 2009 to 2010 is due to an increase in the fair market value of the
underlying investments of $8 million and an increase in the present value of the contract
obligation of $10 million. The participating interest is not available for meeting general pension
benefit obligations in the near term. No future company contributions are required and no new
benefits are being accrued under this insurance annuity contract.
The fair values of our pension plan assets at December 31, by asset class were as follows:
Equity Securities
U.S.
International
Common/collective trusts
Mutual funds
Debt Securities
Government
Corporate
Agency and
mortgage-backed
securities
Private equity funds
Derivatives
Insurance contacts
Real estate
Total*
*Excludes the participating interest in the annuity contract with a net asset value of $92 million and net
receivables related to security transactions of $15 million.
*Excludes the participating interest in the annuity contract with a net asset value of $94 million and
net payables related to security transactions of $(14) million.
As reflected in the table above, Level 3 activity is not material.
Our funding policy for U.S. plans is to contribute at least the minimum required by the Employee
Retirement Income Security Act of 1974 and the Internal Revenue Code of 1986, as amended.
Contributions to foreign plans are dependent upon local laws and tax regulations. In 2011, we
expect to contribute approximately $730 million to our domestic qualified and nonqualified pension
and postretirement benefit plans and $230 million to our international qualified and nonqualified
pension and postretirement benefit plans.
The following benefit payments, which are exclusive of amounts to be paid from the participating
annuity contract and which reflect expected future service, as appropriate, are expected to be
paid:
2016-2020
Defined Contribution Plans
Most U.S. employees are eligible to participate in the ConocoPhillips Savings Plan (CPSP).
Employees can deposit up to 75 percent of their eligible pay up to the statutory limit ($16,500 in
2010) in the thrift feature of the CPSP to a choice of approximately 39 investment funds.
ConocoPhillips matches contribution deposits, up to 1.25 percent of eligible pay. Company
contributions charged to expense for the CPSP and predecessor plans, excluding the stock savings
feature (discussed below), were $24 million in 2010, $23 million in 2009, and $28 million in 2008.
The stock savings feature of the CPSP is a leveraged employee stock ownership plan. Employees may
elect to participate in the stock savings feature by contributing 1 percent of eligible pay and
receiving an allocation of shares of common stock proportionate to the amount of contribution.
In 1990, the Long-Term Stock Savings Plan of Phillips Petroleum Company (now the stock savings
feature of the CPSP) borrowed funds that were used to purchase previously unissued shares of
company common stock. Since the company guarantees the CPSP’s borrowings, the unpaid balance is
reported as a liability of the company and unearned compensation is shown as a reduction of common
stockholders’ equity. Dividends on all shares are charged against retained earnings. The debt is
serviced by the CPSP from company contributions and dividends received on certain shares of common
stock held by the plan, including all unallocated shares. The shares held by the stock savings
feature of the CPSP are released for allocation to participant accounts based on debt service
payments on CPSP borrowings. In addition, during the period from 2011 through 2014, when no debt
principal payments are scheduled to occur, we have committed to make direct contributions of stock
to the stock savings feature of the CPSP, or make prepayments on CPSP borrowings, to ensure a
certain minimum level of stock allocation to participant accounts.
We recognize interest expense as incurred and compensation expense based on the fair market value
of the stock contributed or on the cost of the unallocated shares released, using the
shares-allocated method. We recognized total CPSP expense related to the stock savings feature of
$92 million, $83 million and $111 million in 2010, 2009 and 2008, respectively, all of which was
compensation expense. In 2010, 2009 and 2008, we contributed 1,776,873 shares, 2,018,692 shares
and 1,668,456 shares, respectively, of company common stock from the Compensation and Benefits
Trust. The shares had a fair market value of $103 million, $94 million and $120 million,
respectively. Dividends used to service debt were $41 million, $39 million and $41 million in
2010, 2009 and 2008, respectively. These dividends reduced the amount of compensation expense
recognized each period. Interest incurred on the CPSP debt in 2010, 2009 and 2008 was $2 million,
$2 million and $6 million, respectively.
The total CPSP stock savings feature shares as of December 31 were:
Unallocated shares
Allocated shares
Total shares
The fair value of unallocated shares at December 31, 2010 and 2009, was $231 million and $274
million, respectively.
We have several defined contribution plans for our international employees, each with its own terms
and eligibility depending on location. Total compensation expense recognized for these
international plans was approximately $52 million in 2010, $51 million in 2009 and $53 million in
2008.
Share-Based Compensation Plans
The 2009 Omnibus Stock and Performance Incentive Plan of ConocoPhillips (the Plan) was approved by
shareholders in May 2009. Over its 10-year life, the Plan allows the issuance of up to 70 million
shares of our common stock for compensation to our employees, directors and consultants; however,
as of the effective date of the Plan, (i) any shares of common stock available for future awards
under the prior plans and (ii) any shares of common stock represented by awards granted under the
prior plans that are forfeited, expire or are canceled without delivery of shares of common stock
or which result in the forfeiture of shares of common stock back to the company shall be available
for awards under the Plan, and no new awards shall be granted under the prior plans. Of the 70
million shares available for issuance under the Plan, no more than 40 million shares of common
stock are available for incentive stock options, and no more than 40 million shares are available
for awards in stock.
Our share-based compensation programs generally provide accelerated vesting (i.e., a waiver of the
remaining period of service required to earn an award) for awards held by employees at the time of
their retirement. For share-based awards granted prior to our adoption of SFAS No. 123(R),
codified into FASB ASC Topic 718, “Compensation—Stock Compensation,” we recognize expense over the
period of time during which the employee earns the award, accelerating the recognition of expense
only when an employee actually retires. For share-based awards granted after our adoption of ASC
718 on January 1, 2006, we recognize share-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, but not less than six months, as this is the minimum period of time required for an
award to not be subject to forfeiture.
Some of our share-based awards vest ratably (i.e., portions of the award vest at different times)
while some of our awards cliff vest (i.e., all of the award vests at the same time). For awards
granted prior to our adoption of ASC 718 that vest ratably, we recognize expense on a straight-line
basis over the service period for each separate vesting portion of the award (i.e., as if the award
was multiple awards with different requisite service periods). For share-based awards granted
after our adoption of ASC 718, we 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.
Total share-based compensation expense recognized in income and the associated tax benefit for the
years ended December 31, were as follows:
Compensation cost
Tax benefit
Stock Options—Stock options granted under the provisions of the Plan and earlier plans permit
purchase of our common stock at exercise prices equivalent to the average market price of the stock
on the date the options were granted. The options have terms of 10 years and generally vest
ratably, with one-third of the options awarded vesting and becoming exercisable on each anniversary
date following the date of grant. Options awarded to employees already eligible for retirement
vest within six months of the grant date, but those options do not become exercisable until the end
of the normal vesting period.
The following summarizes our stock option activity for the three years ended December 31, 2010:
Outstanding at December
31, 2007
Granted
Exercised
Forfeited
Expired or canceled
Outstanding at December
31, 2008
Outstanding at December
31, 2009
Outstanding at December 31, 2010
Vested at December 31, 2010
Exercisable at December
31, 2010
The weighted-average remaining contractual term of vested options and exercisable options at
December 31, 2010, was 3.56 years and 2.98 years, respectively.
During 2010, we received $168 million in cash and realized a tax benefit of $54 million from the
exercise of options. At December 31, 2010, the remaining unrecognized compensation expense from
unvested options was $15 million, which will be recognized over a weighted-average period of 17
months, the longest period being 25 months.
The significant assumptions used to calculate the fair market values of the options granted over
the past three years, as calculated using the Black-Scholes-Merton option-pricing model, were as
follows:
Assumptions used
Risk-free interest rate
Dividend yield
Volatility factor
Expected life (years)
The ranges in the assumptions used were as follows:
Ranges used
We calculate volatility using the most recent ConocoPhillips end-of-week closing stock prices
spanning a period equal to the expected life of the options granted. We periodically calculate the
average period of time lapsed between grant dates and exercise dates of past grants to estimate the
expected life of new option grants.
Stock Unit Program—Stock units granted under the provisions of the Plan vest ratably, with
one-third of the units vesting in 36 months, one-third vesting in 48 months, and the final third
vesting 60 months from the date of grant. Upon vesting, the units are settled by issuing one share
of ConocoPhillips common stock per unit. Units awarded to employees already eligible for
retirement vest within six months of the grant date, but those units are not issued as shares until
the end of the normal vesting period. Until issued as stock, most recipients of the units receive
a quarterly cash payment of a dividend equivalent that is charged to expense. The grant date fair
value of these units is deemed equal to the average ConocoPhillips stock price on the date of
grant. The grant date fair market value of units that do not receive a dividend equivalent while
unvested is deemed equal to the average ConocoPhillips stock price on the grant date, less the net
present value of the dividends that will not be received.
The following summarizes our stock unit activity for the three years ended December 31, 2010:
Outstanding at December 31, 2007
Issued
Outstanding at December 31, 2008
Outstanding at December 31, 2009
Not Vested at December 31, 2010
At December 31, 2010, the remaining unrecognized compensation cost from the unvested units was $165
million, which will be recognized over a weighted-average period of 25 months, the longest period
being 49 months.
Performance Share Program—Under the Plan, we also annually grant to senior management restricted
stock units that do not vest until either (i) with respect to awards for periods beginning before
2010, the employee becomes eligible for retirement by reaching age 55 with five years of service or
(ii) with respect to awards for periods beginning in 2010, five years after the grant date of the
award (although recipients can elect to defer the lapsing of restrictions until retirement after
reaching age 55 with five years of service), so we recognize compensation expense for these awards
beginning on the date of grant and ending on the date the units are scheduled to vest. Since these
awards are authorized three years prior to the grant date, for employees eligible for such
retirement by or shortly after the grant date, we recognize compensation expense over the period
beginning on the date of authorization and ending on the date of grant. These units are settled by
issuing one share of ConocoPhillips common stock per unit. Until issued as stock, recipients of
the units receive a quarterly cash payment of a dividend equivalent that is charged to expense. In
its current form, the first grant of units under this program was in 2006.
The following summarizes our Performance Share Program activity for the three years ended December
31, 2010:
At December 31, 2010, the remaining unrecognized compensation cost from unvested Performance Share
awards was $38 million, which will be recognized over a weighted-average period of 42 months, the
longest period being 16 years.
Other—In addition to the above active programs, we have outstanding shares of restricted stock and
restricted stock units that were either issued to replace awards held by employees of companies we
acquired or issued as part of a compensation program that has been discontinued. Generally, the
recipients of the restricted shares or units receive a quarterly dividend or dividend equivalent.
The following summarizes the aggregate activity of these restricted shares and units for the three
years ended December 31, 2010:
Canceled
At December 31, 2010, the remaining unrecognized compensation cost from the unvested units was $0.3
million, which was recognized by February 2011.
Compensation and Benefits Trust
The Compensation and Benefits Trust (CBT) is an irrevocable grantor trust, administered by an
independent trustee and designed to acquire, hold and distribute shares of our common stock to fund
certain future compensation and benefit obligations of the company. The CBT does not increase or
alter the amount of benefits or compensation that will be paid under existing plans, but offers us
enhanced financial flexibility in providing the funding requirements of those plans. We also have
flexibility in determining the timing of distributions of shares from the CBT to fund compensation
and benefits, subject to a minimum distribution schedule. The trustee votes shares held by the CBT
in accordance with voting directions from eligible employees, as specified in a trust agreement
with the trustee.
We sold 58.4 million shares of previously unissued company common stock to the CBT in 1995 for $37
million of cash, previously contributed to the CBT by us, and a promissory note from the CBT to us
of $952 million. The CBT is consolidated by ConocoPhillips; therefore, the cash contribution and
promissory note are eliminated in consolidation. Shares held by the CBT are valued at cost and do
not affect earnings per share or total common stockholders’ equity until after they are transferred
out of the CBT. In 2010 and 2009, shares transferred out of the CBT were 1,776,873 and 2,018,692,
respectively. At December 31, 2010, the CBT had 36.7 million shares remaining. All shares are
required to be transferred out of the CBT by January 1, 2021. The CBT, together with two smaller
grantor trusts, comprise the “Grantor trusts” line in the equity section of the consolidated
balance sheet.
Note 20—Income Taxes
Income taxes charged to income (loss) were:
Income Taxes
Federal
Current
Deferred
Foreign
Deferred*
State and local
Deferred income taxes reflect the net tax effect of temporary differences between the
carrying amounts of assets and liabilities for financial reporting purposes and the amounts used
for tax purposes. Major components of deferred tax liabilities and assets at December 31 were:
Deferred Tax Liabilities
Properties, plants and equipment, and intangibles
Investment in joint ventures
Inventory
Partnership income deferral
Other*
Total deferred tax liabilities*
Deferred Tax Assets
Benefit plan accruals
Deferred state income tax
Other financial accruals and deferrals
Loss and credit carryforwards
Total deferred tax assets
Less valuation allowance
Net deferred tax assets
Net deferred tax liabilities*
Current assets, long-term assets, current liabilities and long-term liabilities included
deferred taxes of $562 million, $160 million, $21 million and $17,335 million, respectively, at
December 31, 2010, and $581 million, $21 million, $5 million and $17,956 million, respectively, at
December 31, 2009.
We have loss and credit carryovers in multiple taxing jurisdictions. These attributes generally
expire between 2011 and 2030 with some carryovers having indefinite carryforward periods.
Valuation allowances have been established to reduce deferred tax assets to an amount that will,
more likely than not, be realized. During 2010, valuation allowances decreased a total of $140
million. This reflects decreases of $554 million primarily related to utilization of U.S. foreign
tax credit and foreign loss carryforwards, partially offset by increases of $414 million, primarily
related to foreign tax loss carryforwards and unrealized foreign exchange losses. Based on our
historical taxable income, expectations for the future, and available tax-planning strategies,
management expects remaining net deferred tax assets will be realized as offsets to reversing
deferred tax liabilities and as offsets to the tax consequences of future taxable income.
At December 31, 2010 and 2009, income considered to be permanently reinvested in certain foreign
subsidiaries and foreign corporate joint ventures totaled approximately $4,134 million and $2,129
million, respectively. Deferred income taxes have not been provided on this income, as we do not
plan to initiate any action that would require the payment of income taxes. It is not practicable
to estimate the amount of additional tax that might be payable on this foreign income if
distributed.
The following table shows a reconciliation of the beginning and ending unrecognized tax benefits
for 2010, 2009 and 2008:
Additions based on tax positions related to the current year
Additions for tax positions of prior years
Reductions for tax positions of prior years
Settlements
Lapse of statute
Included in the balance of unrecognized tax benefits for 2010, 2009 and 2008 were $914 million,
$931 million and $862 million, respectively, which, if recognized, would affect our effective tax
rate.
At December 31, 2010, 2009 and 2008, accrued liabilities for interest and penalties totaled $171
million, $166 million and $147 million, respectively, net of accrued income taxes. Interest and
penalties benefitted earnings in 2010 by $2 million, and resulted in a charge to earnings in 2009
and 2008 of $18 million and $25 million, respectively.
We and our subsidiaries file tax returns in the U.S. federal jurisdiction and in many foreign and
state jurisdictions. Audits in major jurisdictions are generally complete as follows: United
Kingdom (2007), Canada (2005), United States (2006) and Norway (2008). Issues in dispute for
audited years and audits for subsequent years are ongoing and in various stages of completion in
the many jurisdictions in which we operate around the world. As a consequence, the balance in
unrecognized tax benefits can be expected to fluctuate from period to period. It is reasonably
possible such changes could be significant when compared with our total unrecognized tax benefits,
but the amount of change is not estimable.
The amounts of U.S. and foreign income (loss) before income taxes, with a reconciliation of tax at
the federal statutory rate with the provision for income taxes, were:
United States
Foreign
Goodwill impairment
Federal statutory income tax
Foreign taxes in excess of
federal statutory rate
Federal manufacturing deduction
State income tax
The change in the effective tax rate from 2009 was primarily due to the effect of asset
dispositions in 2010 and a higher proportion of income in higher tax jurisdictions in 2009, offset
in part by the effect of asset impairments occurring in 2010.
Statutory tax rate changes did not have a significant impact on our income tax expense in 2010,
2009 or 2008.
Note 21—Other Comprehensive Income (Loss)
The components and allocated tax effects of other comprehensive income (loss) follow:
Defined benefit pension plans:
Prior service cost arising during the year
Reclassification adjustment for amortization of prior
service cost
included in net income
Net prior service cost
Net loss arising during the year
Reclassification adjustment for amortization of prior
net losses included
in net income
Net actuarial gain
Nonsponsored plans*
Unrealized holding gain arising during the year
Reclassification adjustment for gain included in net income
Net unrealized gain on securities**
Foreign currency translation adjustments
Other comprehensive income
Net actuarial loss
Hedging activities
2008
Reclassification adjustment for amortization of prior
service cost
included in net loss
Reclassification adjustment for amortization of prior
net losses included
in net loss
Other comprehensive loss
Deferred taxes have not been provided on temporary differences related to foreign currency
translation adjustments for investments in certain foreign subsidiaries and foreign corporate joint
ventures that are considered permanent in duration.
Accumulated other comprehensive income in the equity section of the balance sheet included:
Defined benefit pension liability adjustments
Net unrealized gain on securities
Deferred net hedging loss
Note 22—Cash Flow Information
Noncash Investing and Financing Activities
Increase in PP&E related to an increase in asset retirement obligations
Cash Payments
Interest
Income taxes
Note 23—Other Financial Information
Interest and Debt Expense
Incurred
Debt
Capitalized
Expensed
Other Income
Interest income
Other, net
Research and Development Expenditures—expensed
Advertising Expenses
Shipping and Handling Costs*
*Amounts included in production and operating expenses.
Cash Dividends paid per common share
Foreign Currency Transaction (Gains) Losses—after-tax
Note 24—Related Party Transactions
Significant transactions with related parties were:
Operating revenues and other income (a)
Gain on dispositions (b)
Purchases (c)
Operating
expenses and selling, general and administrative expenses (d)
Net interest expense (e)
| (a) |
|
We sold natural gas to DCP Midstream and crude oil to the Malaysian Refining Company Sdn.
Bhd. (MRC), among others, for processing and marketing. Natural gas liquids, solvents and
petrochemical feedstocks were sold to CPChem, gas oil and hydrogen feedstocks were sold to
Excel Paralubes and refined products were sold primarily to CFJ Properties and LUKOIL.
Beginning in the third quarter of 2010, CFJ was no longer considered a related party due to
the sale of our interest. Natural gas, crude oil, blendstock and other intermediate products
were sold to WRB Refining LP. In addition, we charged several of our affiliates, including
CPChem and MSLP, for the use of common facilities, such as steam generators, waste and water
treaters, and warehouse facilities. |
| |
| (b) |
|
During 2010, we sold a portion of our LUKOIL shares under a stock purchase and option
agreement with a wholly owned subsidiary of LUKOIL, resulting in a before-tax gain of $1,149
million. |
| |
| (c) |
|
We purchased refined products from WRB. We purchased natural gas and natural gas liquids
from DCP Midstream and CPChem for use in our refinery processes and other feedstocks from
various affiliates. We purchased crude oil from LUKOIL and refined products from MRC. We
also paid fees to various pipeline equity companies for transporting finished refined products
and natural gas, as well as a price upgrade to MSLP for heavy crude processing. We purchased
base oils and fuel products from Excel Paralubes for use in our refinery and specialty
businesses. |
| |
| (d) |
|
We paid processing fees to various affiliates. Additionally, we paid transportation fees to
pipeline equity companies. |
| |
| (e) |
|
We paid and/or received interest to/from various affiliates, including FCCL Partnership. See
Note 6—Investments, Loans and Long-Term Receivables, for additional information on loans to
affiliated companies. |
Beginning in the fourth quarter of 2010, transactions with LUKOIL and its subsidiaries were no
longer considered related party transactions. See Note 6—Investments, Loans and Long-Term
Receivables, for additional information.
Note 25—Segment Disclosures and Related Information
We have organized our reporting structure based on the grouping of similar products and services,
resulting in six operating segments:
| |
1) |
|
E&P—This 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. The E&P segment’s U.S. and international operations
are disclosed separately for reporting purposes. |
| |
| |
2) |
|
Midstream—This 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. |
| |
| |
3) |
|
R&M—This segment purchases, refines, markets and transports crude oil and petroleum
products, mainly in the United States, Europe and Asia. At December 31, 2010, we owned or
had an interest in 12 refineries in the United States, one in the United Kingdom, one in
Ireland, two in Germany, and one in Malaysia. The R&M segment’s U.S. and international
operations are disclosed separately for reporting purposes. |
| |
| |
4) |
|
LUKOIL Investment—This segment represents 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 6—Investments, Loans and Long-Term Receivables, for information on sales of LUKOIL shares. |
| |
| |
5) |
|
Chemicals—This segment manufactures and markets petrochemicals and plastics on a
worldwide basis. The Chemicals segment consists of our 50 percent equity investment in
CPChem. |
| |
| |
6) |
|
Emerging Businesses—This 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. |
Corporate and Other includes general corporate overhead, most interest expense and various other
corporate activities. Corporate assets include all cash and cash equivalents and short-term
investments.
We evaluate performance and allocate resources based on net income attributable to ConocoPhillips.
Segment accounting policies are the same as those in Note 1—Accounting Policies. Intersegment
sales are at prices that approximate market.
Analysis of Results by Operating Segment
Sales and Other Operating Revenues
E&P*
Intersegment eliminations—U.S.
Intersegment eliminations—international
E&P
Total sales
Intersegment eliminations
Midstream
R&M*
R&M
Emerging Businesses
Consolidated sales and other operating revenues
Goodwill impairment
Total E&P
Total R&M
Consolidated depreciation, depletion, amortization and impairments
| *2009 and 2008 recast to reflect a change in accounting principle. See Note 2—Changes in Accounting Principles, for more information. |
Equity in Earnings of Affiliates
Consolidated equity in earnings of affiliates
(1) Does not include a $7,496 million impairment of our LUKOIL investment which is presented as a separate line item in the consolidated statement of operations.
Consolidated income taxes
Consolidated net income (loss) attributable to ConocoPhillips
*2009 and 2008 recast to reflect a change in accounting principle. See Note 2—Changes in Accounting Principles, for more information.
Investments In and Advances To Affiliates
Consolidated investments in and advances to affiliates(1)
(1) Includes amounts classified as held for sale:
Total Assets
Consolidated total assets
Capital Expenditures and Investments
Consolidated capital expenditures and investments
| *2009 and 2008 recast to reflect a change in accounting principle. See Note 2—Changes in Accounting Principles, for more information. |
Interest Income and Expense
Corporate
E&P
R&M
Geographic Information
Australia(3)
Canada
Norway
Russia(4)
United Kingdom
Other foreign countries
Worldwide consolidated
Oil and Gas Operations (Unaudited)
In accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification
Topic 932, “Extractive Activities—Oil and Gas,” and regulations of the U.S. Securities and
Exchange Commission (SEC), we are making certain supplemental disclosures about our oil and gas
exploration and production operations.
These disclosures include information about our consolidated oil and gas activities and our
proportionate share of our equity affiliates’ oil and gas activities, covering both those in our
Exploration and Production (E&P) segment, as well as in our LUKOIL Investment segment. As a
result, amounts reported as Equity Affiliates in Oil and Gas Operations may differ from those shown
in the individual segment disclosures reported elsewhere in this report.
Our proved reserves include estimated quantities related to production sharing contracts (PSCs),
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. At December 31, 2010, approximately 12 percent of our total
proved reserves were under PSCs, primarily in our Asia Pacific/Middle East geographic reporting
area.
Our disclosures by geographic area include the United States, Canada, Europe (primarily Norway and
the United Kingdom), Russia, Asia Pacific/Middle East, Africa, and Other Areas. Other Areas
primarily consists of the Caspian Region.
On December 31, 2008, the SEC issued its final rules to modernize the supplemental oil and gas
disclosures, and in January 2010, the FASB issued Accounting Standards Update No. 2010-03, “Oil and
Gas Reserve Estimation and Disclosures.” As a result of these two new rules, our disclosures
reflect the expanded definitions for oil and gas producing activities, including nontraditional
resources such as Syncrude operations. The inclusion of Syncrude as part of our oil and gas
producing activities, effective January 1, 2009, did not have a significant impact on our
disclosures. In the following disclosures, the synthetic oil classification includes Syncrude
mining operations, and the bitumen classification includes our Surmont operations and the FCCL
Partnership. In June 2010, we sold our interest in the Syncrude Canada Ltd. joint venture;
accordingly, as of December 31, 2010, we no longer held synthetic oil reserves.
Two items occurred during 2010 that impact the disclosure of our investment in OAO LUKOIL in the
supplemental oil and gas disclosures:
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Effective January 1, 2010, we changed the method used to determine our equity-method
share of LUKOIL’s earnings. Prior to 2010, we estimated our LUKOIL equity earnings for
the current quarter. Beginning in 2010, we implemented a change in accounting principle
to record our LUKOIL equity earnings on a one-quarter-lag basis. Prior periods have been
recast to reflect this change, including those in the supplemental oil and gas
disclosures (other than the proved reserves tables, which continue to reflect LUKOIL on a
current basis). |
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On July 28, 2010, we announced our intention to sell our entire interest in LUKOIL
over a period of time through the end of 2011. As a result of this sell down of our
interest, at the end of the third quarter of 2010 we ceased using equity-method
accounting for our investment in LUKOIL. Accordingly, the supplemental oil and gas
disclosures reflect activity for LUKOIL through June 30, 2010, which, on a lag basis,
results in three quarters of activity being included in the year 2010 (the fourth quarter
of 2009 and the first two quarters of 2010). Since the proved reserves tables are not on
a lag basis, they reflect activity for the first three quarters of 2010, at which point
LUKOIL’s reserves were removed from our reserve quantities. |
See Note 2—Changes in Accounting Principles, and Note 6—Investments, Loans and Long-Term
Receivables, in the Notes to Consolidated Financial Statements, for more information about both of
these items.
Reserves Governance
The recording and reporting of proved reserves are governed by criteria established by regulations
of the SEC and FASB. Proved reserves are those quantities of oil and gas, which, by analysis of
geoscience and engineering data, can be estimated with reasonable certainty to be economically
producible—from a given date forward, from known reservoirs, and under existing economic
conditions, operating methods, and government regulations—prior to the time at which contracts
providing the right to operate expire, unless evidence indicates that renewal is reasonably
certain, regardless of whether deterministic or probabilistic methods are used for the estimation.
The project to extract the hydrocarbons must have commenced or the operator must be reasonably
certain that it will commence the project within a reasonable time. Proved reserves are further
classified as either developed or undeveloped. Proved developed reserves are proved reserves that
can be expected to be recovered through existing wells with existing equipment and operating
methods or in which the cost of the required equipment is relatively minor compared to the cost of
a new well, and through installed extraction equipment and infrastructure operational at the time
of the reserves estimate if the extraction is by means not involving a well. Proved undeveloped
reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage,
or from existing wells where a relatively major expenditure is required for recompletion.
We have a companywide, comprehensive, SEC-compliant internal policy that governs the determination
and reporting of proved reserves. This policy is applied by the geologists and reservoir engineers
in our E&P business units around the world. As part of our internal control process, each business
unit’s reserves are reviewed annually by an internal team which is headed by the company’s Manager
of Reserves Compliance and Reporting. This team, composed of internal reservoir engineers,
geologists and finance personnel, reviews the business units’ reserves for adherence to SEC
guidelines and company policy through on-site visits and review of documentation. In addition to
providing independent reviews, this internal team also ensures reserves are calculated using
consistent and appropriate standards and procedures. This team is independent of business unit
line management and is responsible for reporting its findings to senior management and our internal
audit group. The team is responsible for maintaining and communicating our reserves policy and
procedures and is available for internal peer reviews and consultation on major projects or
technical issues throughout the year. All of our proved reserves held by consolidated companies
and our share of equity affiliates have been estimated by ConocoPhillips.
The technical person primarily responsible for overseeing the preparation of the company’s reserve
estimates is the Manager of Reserves Compliance and Reporting. This individual is a petroleum
engineer with a bachelor’s degree in petroleum engineering. He is an active member of the Society
of Petroleum Engineers (SPE) with over 30 years of oil and gas industry experience, including
drilling and production engineering assignments in several field locations. He is currently
serving a three-year term on the Oil & Gas Reserves Committee of the SPE and has held positions of
increasing responsibility in reservoir engineering, reserves reporting and compliance, and business
management.
During 2010, our processes and controls used to assess over 90 percent of proved reserves as of
December 31, 2010, were reviewed by DeGolyer and MacNaughton (D&M), a third-party petroleum
engineering consulting firm. The purpose of their review was to assess whether the adequacy and
effectiveness of our internal processes and controls used to determine estimates of proved reserves
are in accordance with SEC regulations. In such review, ConocoPhillips’ technical staff presented
D&M with an overview of the reserves data, as well as the methods and assumptions used in
estimating reserves. The data presented included pertinent seismic information, geologic maps,
well logs, production tests, material balance calculations, reservoir simulation models, well
performance data, operating procedures and relevant economic criteria. Management’s intent in
retaining D&M to review its processes and controls was to provide objective third-party input on
these processes and controls. D&M’s opinion was that the general processes and controls employed
by ConocoPhillips in estimating its December 31, 2010, proved reserves for the properties reviewed
are in accordance with the SEC reserves definitions. D&M’s report is included as Exhibit 99 of
this Annual Report on Form 10-K.
Engineering estimates of the quantities of proved reserves are inherently imprecise. See the
“Critical Accounting Estimates” section of Management’s Discussion and Analysis of Financial
Condition and Results of Operations for additional discussion of the sensitivities surrounding
these estimates.
Proved Reserves
Developed and Undeveloped
Consolidated operations
End of 2007
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
End of 2008
End of 2009
End of 2010
Equity affiliates
Total company
Developed
Undeveloped
Notable changes in proved crude oil and natural gas liquids reserves in the three years ended
December 31, 2010, included:
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Revisions: In 2009 and 2008, revisions in Alaska were primarily due to higher
prices in 2009, versus 2008; and lower prices in 2008, compared with 2007, respectively. |
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Sales: In 2010 for our equity affiliates in Russia, sales were primarily due to the
disposition of our interest in LUKOIL. |
Natural gas production in the reserves table may differ from gas production (delivered for sale) in
our statistics disclosure, primarily because the quantities above include gas consumed at the
lease.
Natural gas reserves are computed at 14.65 pounds per square inch absolute and 60 degrees
Fahrenheit.
Notable changes in proved natural gas reserves in the three years ended December 31, 2010,
included:
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Revisions: In 2010, revisions in Alaska, Lower 48 and Canada were primarily due to
higher prices in 2010, versus 2009, as well as improved well performance. In 2009 and 2008,
revisions in Alaska were primarily due to higher prices in 2009, versus 2008; and lower prices
in 2008, compared with 2007, respectively. In 2009, for our equity affiliate operations in
Asia Pacific/Middle East, revisions resulted from modified coalbed methane drilling plans in
Australia. In Russia, revisions were attributable to positive performance in various LUKOIL
fields. In 2008, revisions in Russia primarily resulted from a revised assessment of the
reasonable certainty of project development and of the marketability of non-contracted gas
volumes. |
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Purchases: In 2008, for our equity affiliate operations in Asia Pacific/Middle
East, purchases relate to our Australia Pacific LNG joint venture to develop coalbed methane. |
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Extensions and Discoveries: In 2010, extensions and discoveries in Lower 48 and
Canada were primarily due to continued drilling success in various fields. In 2009, for our
equity affiliate operations in Asia Pacific/Middle East, extensions and discoveries primarily
resulted from drilling success in Australia related to a coalbed methane project. |
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Sales: In 2010, for our equity affiliates in Russia, sales were primarily due to
the disposition of our interest in LUKOIL. |
Notable changes in proved synthetic oil and bitumen reserves in the three years ended December 31,
2010, included:
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Revisions: In 2009, for synthetic oil consolidated operations, revisions reflect
our Syncrude Canada Ltd. operations, which are now considered an oil and gas activity under
the new FASB and SEC rules and regulations. For our bitumen consolidated operations,
revisions primarily were related to the sanction of the Surmont Phase II Project. For our
bitumen equity affiliate operations, revisions were mainly the result of the effect of higher
prices on sliding scale royalty provisions. |
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Extensions and Discoveries: In 2009, for our bitumen consolidated operations,
extensions and discoveries were related to the sanction of the Surmont Phase II Project. In
2010 and 2009, for our equity affiliate operations, extensions and discoveries mainly reflect
the continued development of FCCL. |
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Sales: In 2010, for synthetic oil consolidated operations, sales reflect the
disposition of our interest in Syncrude. |
*Includes 594 million barrels of oil equivalent due to the cessation of equity accounting.
Natural gas reserves are converted to barrels of oil equivalent (BOE) based on a 6:1 ratio: six
thousand cubic feet of natural gas converts to one BOE.
Proved Undeveloped Reserves
We had 2,217 million BOE of proved undeveloped reserves at year-end 2010, compared with 3,087
million BOE at year-end 2009. The disposition of our investment in LUKOIL resulted in the removal
of 589 million BOE of undeveloped reserves. We also converted 844 million BOE of undeveloped
reserves to developed during 2010 as we achieved startup of major development projects. Finally,
we added 563 million BOE of undeveloped reserves in 2010 mainly through exploratory success and
revisions. As a result, at December 31, 2010, our proved undeveloped reserves represented 27
percent of total proved reserves, compared with 30 percent at December 31, 2009. Costs incurred
for the year ended December 31, 2010, relating to the development of proved undeveloped reserves
were $3.3 billion.
Approximately 75 percent of our proved undeveloped reserves at year-end 2010 were associated with
eight major development areas. Seven of the major development areas are currently producing and
are expected to have proved undeveloped reserves convert to developed over time as development
activities continue and/or production facilities are expanded or upgraded, and include:
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FCCL oil sands—Christina Lake and Foster Creek in Canada. |
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The Surmont oil sands project in Canada. |
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The Ekofisk Field in the North Sea. |
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Certain fields in the United States. |
The remaining major project, the Kashagan Field in Kazakhstan, will have proved undeveloped
reserves convert to developed as this project begins production.
At the end of 2010, we did not have any material amounts of proved undeveloped reserves in
individual fields or countries that have remained undeveloped for five years or more. However, our
largest concentrations of proved undeveloped reserves at year-end 2010 are located in the Athabasca
oil sands in Canada, consisting of the FCCL and Surmont steam-assisted gravity drainage (SAGD)
projects. The majority of our proved undeveloped reserves in this area were first recorded in 2006
and 2007, and we expect a material portion of these reserves will remain undeveloped for more than
five years.
Our SAGD projects are large, multi-year projects with steady, long-term production at consistent
levels. The associated reserves are expected to be developed over many years as additional well
pairs are drilled across the extensive resource base to maintain throughput at the central
processing facilities.
Results of Operations
Transfers
Other revenues
Total revenues
Production costs excluding taxes
Taxes other than income taxes
Transportation costs
Other related expenses
Accretion
Results of operations for producing activities
Other earnings
Impairments**
Other earnings**
*Certain amounts were reclassified between “Sales” and “Transfers,” as well as between “Other revenues” and “Other related expenses.” Total Results of operations was unchanged.
**Goodwill considered to be a non-oil-and-gas producing activity was reclassified from “Impairments” to “Other earnings.”
Impairments*
*Excludes goodwill impairment of $25,443 million.
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Results of operations for producing activities consist of all activities within the E&P
organization and producing activities within the LUKOIL Investment segment, except for
pipeline and marine operations, liquefied natural gas operations, and crude oil and gas
marketing activities, which are included in other earnings. Also excluded are our Midstream
segment, downstream petroleum and chemical activities, as well as general corporate
administrative expenses and interest. |
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Transfers are valued at prices that approximate market. |
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Other revenues include gains and losses from asset sales, certain amounts resulting from
the purchase and sale of hydrocarbons, and other miscellaneous income. |
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Production costs are those incurred to operate and maintain wells and related equipment and
facilities used to produce proved reserves. These costs also include depreciation of support
equipment and administrative expenses related to the production activity. |
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Taxes other than income taxes include production, property and other non-income taxes. |
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Exploration expenses include dry hole costs, leasehold impairments, geological and
geophysical expenses, the costs of retaining undeveloped leaseholds, and depreciation of
support equipment and administrative expenses related to the exploration activity. |
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Depreciation, depletion and amortization (DD&A) in Results of Operations differs from that
shown for total E&P in Note 25—Segment Disclosures and Related Information, in the Notes to
Consolidated Financial Statements, mainly due to depreciation of support equipment being
reclassified to production or exploration expenses, as applicable, in Results of Operations.
In addition, other earnings include certain E&P activities, including their related DD&A
charges. |
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Transportation costs include costs to transport our produced hydrocarbons to their points
of sale, as well as processing fees paid to process natural gas to natural gas liquids. The
profit element of transportation operations in which we have an ownership interest are deemed
to be outside oil and gas producing activities. The net income of the transportation
operations is included in other earnings. |
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Other related expenses include foreign currency transaction gains and losses, and other
miscellaneous expenses. |
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The provision for income taxes is computed by adjusting each country’s income before income
taxes for permanent differences related to oil and gas producing activities that are reflected
in our consolidated income tax expense for the period, multiplying the result by the country’s
statutory tax rate, and adjusting for applicable tax credits. |
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The equity affiliate results in Russia for 2009 reflect only three quarters of activity for
our share of LUKOIL. Under the lag accounting method used for our investment in LUKOIL,
equity earnings were not recorded in the first quarter of 2009, since our LUKOIL investment
was written down in the fourth quarter of 2008 to its fair value at December 31, 2008. This
approach was consistently followed in Results of Operations (RESOP), such that LUKOIL’s
fourth-quarter 2008 results are not reflected in RESOP. For supplemental information, the
fourth-quarter 2008 amounts excluded for selected line items were: total revenues—$1,371
million; production costs—$171 million; taxes other than income taxes—$867 million; and
DD&A—$127 million. These amounts were included in the numerator of the per-unit calculations
included in the “Statistics” section. |
Statistics
Crude Oil and Natural Gas Liquids
Europe
Asia Pacific/Middle East
Africa
Other areas
Russia
Total equity affiliates
Total company
Synthetic Oil
Consolidated operations—Canada
Bitumen
Equity affiliates—Canada
Natural Gas*
*Represents quantities available for sale. Excludes gas equivalent of natural gas liquids included above.
Crude Oil and Natural Gas Liquids Per Barrel
Total international
Synthetic Oil Per Barrel
Bitumen Per Barrel
Natural Gas Per Thousand Cubic Feet*
*Prior periods reclassified to conform to current year presentation of including intrasegment transfer pricing.
Average Production Costs Per Barrel of Oil Equivalent*
Average Production Costs Per Barrel—Bitumen
Taxes Other Than Income Taxes Per Barrel of Oil Equivalent*
Depreciation, Depletion and Amortization Per Barrel of Oil Equivalent*
*Includes bitumen. For 2008, excludes our Canadian synthetic oil operations.
Exploratory(2)
Total equity affiliates(3)
Includes step-out wells of:
Development
(1)Excludes farmout arrangements.
(2)Includes step-out wells, as well as other types of exploratory wells. Step-out exploratory wells are wells drilled in areas near or
offsetting current production, for which we cannot demonstrate with certainty that there is continuity of production from an existing
productive formation. These are classified as exploratory wells because we cannot attribute proved reserves to these locations.
(3)Excludes LUKOIL.
*Our total proportionate interest was less than one.
(1)Includes wells that have been temporarily suspended.
(2)Includes 6,000 gross and 3,802 net multiple completion wells.
(3)Includes 191 gross and 138 net stratigraphic test wells for heavy oil projects.
Costs Incurred
Unproved property acquisition
Proved property acquisition
Exploration
Development
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Costs incurred include capitalized and expensed items. |
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Acquisition costs include the costs of acquiring proved and unproved hydrocarbon
properties. In 2008, equity affiliate acquisition costs were due to the Australia Pacific LNG
joint venture with Origin Energy. |
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Exploration costs include geological and geophysical expenses, the cost of retaining
undeveloped leaseholds, exploratory drilling costs, and costs incurred to assess the
commerciality of potential discoveries. |
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Development costs include the cost of drilling and equipping development wells and building
related production facilities for extracting, treating, gathering and storing hydrocarbons. |
Capitalized Costs
Proved properties
Unproved properties
Accumulated depreciation, depletion and amortization
*2009 equity affiliates adjusted to reclassify certain costs between proved and unproved, as well as to include amounts determined to be capitalized.
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Capitalized costs include the cost of equipment and facilities for oil and gas producing
activities. These costs include the activities of our E&P and LUKOIL Investment segments,
excluding pipeline and marine operations, liquefied natural gas operations, crude oil and
natural gas marketing activities and downstream operations. |
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Proved properties include capitalized costs for leaseholds holding proved reserves,
development wells and related equipment and facilities (including uncompleted development well
costs), mining facilities associated with our synthetic oil operations and support equipment. |
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Unproved properties include capitalized costs for leaseholds under exploration (including
where hydrocarbons were found but determination of the economic viability of the required
infrastructure is dependent upon further exploratory work under way or firmly planned) and for
uncompleted exploratory well costs, including exploratory wells under evaluation. |
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas
Reserve Quantities
In accordance with SEC and FASB requirements, amounts for 2010 and 2009 were computed using
12-month average prices and
end-of-year costs (adjusted only for existing contractual changes), appropriate statutory tax rates
and a prescribed 10 percent discount factor. Twelve-month average prices are calculated as the
unweighted arithmetic average of the first-day-of-the-month price for each month within the
12-month period prior to the end of the reporting period. Amounts for 2008 were computed using
end-of-year prices and costs. For all years, continuation of year-end economic conditions was
assumed. The calculations were based on estimates of proved reserves, which are revised over time
as new data becomes available. Probable or possible reserves, which may become proved in the
future, were not considered. The calculations also require assumptions as to the timing of future
production of proved reserves, and the timing and amount of future development, including
dismantlement, and production costs.
While due care was taken in its preparation, we do not represent that this data is the fair value
of our oil and gas properties, or a fair estimate of the present value of cash flows to be obtained
from their development and production.
Discounted Future Net Cash Flows
2010
Consolidated operations
Future cash inflows
Less:
Future production and transportation costs*
Future development costs
Future income tax provisions
Future net cash flows
10 percent annual discount
Discounted future net cash flows
Equity affiliates
Total company
*Includes taxes other than income taxes.
2009
Future production and transportation costs**
*Restated to include amounts omitted and to reclassify between production costs, development costs
and taxes.
**Includes taxes other than income taxes.
Excludes discounted future net cash flows from Canadian Syncrude of $435 million.
Sources of Change in Discounted Future Net Cash Flows
Discounted future net cash flows at the beginning of the year
Changes during the year
Revenues less production and transportation costs for the
year**
Net change in prices, and production and transportation
costs***
Extensions, discoveries and improved recovery, less
estimated future costs
Development costs for the year
Changes in estimated future development costs
Purchases of reserves in place,
less estimated future costs
Sales of reserves in place, less estimated future costs
Revisions of previous quantity estimates**
Accretion of discount
Net change in income taxes
Total changes
Discounted future net cash flows at year end
*Restated to include amounts omitted in the Africa geographic area.
**Includes taxes other than income taxes.
***Includes amounts resulting from changes in the timing of production.
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The net change in prices, and production and transportation costs is the
beginning-of-year reserve-production forecast multiplied by the net annual change in the
per-unit sales price, and production and transportation cost, discounted at 10 percent. |
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For 2010 and 2009, as required, purchases and sales of reserves in place, along with
extensions, discoveries and improved recovery, are calculated using production forecasts of
the applicable reserve quantities for the year multiplied by the 12-month average sales
prices, less future estimated costs, discounted at 10 percent. For 2008, the end-of-year
sales prices were used, as required. |
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The accretion of discount is 10 percent of the prior year’s discounted future cash inflows,
less future production, transportation and development costs. |
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The net change in income taxes is the annual change in the discounted future income tax
provisions. |
First
Second
Third
Fourth
*Includes excise taxes on petroleum products sales.
Certain amounts in 2009 have been recast to reflect a change in accounting principle. See Note
2—Changes in Accounting Principles, in the Notes to Consolidated Financial Statements, for more
information.
We have various cross guarantees among ConocoPhillips, ConocoPhillips Company, ConocoPhillips
Australia Funding Company, ConocoPhillips Canada Funding Company I, and ConocoPhillips Canada
Funding Company II, with respect to publicly held debt securities. ConocoPhillips Company is
wholly owned by ConocoPhillips. ConocoPhillips Australia Funding Company is an indirect, wholly
owned subsidiary of ConocoPhillips Company. ConocoPhillips Canada Funding Company I and
ConocoPhillips Canada Funding Company II are indirect, wholly owned subsidiaries of ConocoPhillips.
ConocoPhillips and ConocoPhillips Company have fully and unconditionally guaranteed the payment
obligations of ConocoPhillips Australia Funding Company, ConocoPhillips Canada Funding Company I,
and ConocoPhillips Canada Funding Company II, with respect to their publicly held debt securities.
Similarly, ConocoPhillips has fully and unconditionally guaranteed the payment obligations of
ConocoPhillips Company with respect to its publicly held debt securities. In addition,
ConocoPhillips Company has fully and unconditionally guaranteed the payment obligations of
ConocoPhillips with respect to its publicly held debt securities. All guarantees are joint and
several. The following condensed consolidating financial information presents the results of
operations, financial position and cash flows for:
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ConocoPhillips, ConocoPhillips Company, ConocoPhillips Australia Funding Company,
ConocoPhillips Canada Funding Company I, and ConocoPhillips Canada Funding Company II (in
each case, reflecting investments in subsidiaries utilizing the equity method of
accounting). |
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All other nonguarantor subsidiaries of ConocoPhillips. |
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The consolidating adjustments necessary to present ConocoPhillips’ results on a
consolidated basis. |
In February 2009, we filed a universal shelf registration statement with the SEC under which
ConocoPhillips, as a well-known seasoned issuer, has the ability to issue and sell an indeterminate
amount of various types of debt and equity securities, with certain debt securities guaranteed by
ConocoPhillips Company. Also as part of that registration statement, ConocoPhillips Trust I and
ConocoPhillips Trust II have the ability to issue and sell preferred trust securities, guaranteed
by ConocoPhillips. ConocoPhillips Trust I and ConocoPhillips Trust II have not issued any
trust-preferred securities under this registration statement, and thus have no assets or
liabilities. Accordingly, columns for these two trusts are not included in the condensed
consolidating financial information.
To facilitate the restructuring of certain legal entities within the Canada operating unit,
ConocoPhillips Canada Funding Company I (CFC I) entered into a transaction with another wholly
owned subsidiary of ConocoPhillips (included in the “All Other Subsidiaries” column) whereby it
acquired an investment in certain preferred shares of a Canadian legal entity within the
ConocoPhillips group, in exchange for a non-interest-bearing demand note payable. The value
ascribed to the preferred shares and note payable represented the redemption price for both. This
noncash transaction was effective December 31, 2009. As a result, the balance sheet of CFC I
reflects a short-term investment of $2,973 million and a corresponding amount in short-term debt.
In January 2010, the preferred shares acquired under the above transaction were resold to the
original holder at the same value as the original purchase price, as satisfaction of the obligation
under the demand note payable. As these transactions were completed between wholly owned
subsidiaries of ConocoPhillips, there is no impact on the consolidated results in either period.
This condensed consolidating financial information should be read in conjunction with the
accompanying consolidated financial statements and notes.
Certain amounts in 2009 and 2008 have been recast to reflect a change in accounting principle. See
Note 2—Changes in Accounting Principles, in the Notes to Consolidated Financial Statements, for
more information.
Revenues and Other Income
Sales and other operating revenues
Equity in earnings of affiliates
Gain on dispostions
Other income (loss)
Intercompany revenues
Total Revenues and Other Income
Costs and Expenses
Purchased crude oil, natural gas and products
Production and operating expenses
Selling, general and administrative expenses
Exploration expenses
Depreciation, depletion and amortization
Impairments
Taxes other than income taxes
Accretion on discounted liabilities
Interest and debt expense
Foreign currency transaction (gains) losses
Total Costs and Expenses
Income (loss) before income taxes
Provision for income taxes
Net income (loss)
Less: net income attributable to
noncontrolling interests
Net Income (Loss) Attributable to ConocoPhillips
Gain on dispositions
Net Income (Loss) Attributable to
ConocoPhillips
Gain (loss) on dispositions
Less: net income attributable to
noncontrolling
interests
Assets
Cash and cash equivalents
Short-term investments
Accounts and notes receivable
Investment in LUKOIL
Inventories
Prepaid expenses and other current assets
Total Current Assets
Investments, loans and long-term receivables*
Net properties, plants and equipment
Goodwill
Intangibles
Other assets
Total Assets
Liabilities and Stockholders’ Equity
Accounts payable
Short-term debt
Accrued income and other taxes
Employee benefit obligations
Other accruals
Total Current Liabilities
Long-term debt
Asset retirement obligations and accrued
environmental costs
Joint venture acquisition obligation
Deferred income taxes
Other liabilities and deferred credits*
Total Liabilities
Retained earnings
Other common stockholders’ equity
Noncontrolling interests
Total Liabilities and Stockholders’ Equity
*Includes intercompany loans.
Cash Flows From Operating Activities
Net Cash Provided by (Used in)
Operating Activities
Cash Flows From Investing Activities
Capital expenditures and investments
Proceeds from asset dispositions
Net purchases of short-term investments
Long-term advances/loans—related parties
Collection of advances/loans—related parties
Other
Net Cash Provided by (Used in)
Investing Activities
Cash Flows From Financing Activities
Issuance of debt
Repayment of debt
Issuance of company common stock
Repurchase of company common stock
Dividends paid on common stock
Net Cash Provided by (Used in)
Financing Activities
Effect of Exchange Rate Changes
on Cash and Cash Equivalents
Net Change in Cash and Cash Equivalents
Cash and cash equivalents at beginning of year
Cash and Cash Equivalents at End of Year
Net Cash Provided by (Used in)
Operating Activities
Net Cash Provided by (Used in)
Investing Activities
Net Cash Provided by Operating Activities
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| Item 9. |
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CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
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| Item 9A. |
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CONTROLS AND PROCEDURES |
As of December 31, 2010, with the participation of our management, our Chairman and Chief Executive
Officer (principal executive officer) and our Senior Vice President, Finance and Chief Financial
Officer (principal financial officer) carried out an evaluation, pursuant to Rule 13a-15(b) of the
Securities Exchange Act of 1934, as amended (the Act), of the effectiveness of the design and
operation of ConocoPhillips’ disclosure controls and procedures (as defined in Rule 13a-15(e) of
the Act). Based upon that evaluation, our Chairman and Chief Executive Officer and our Senior Vice
President, Finance and Chief Financial Officer concluded that our disclosure controls and
procedures were operating effectively as of December 31, 2010.
There have been no changes in our internal control over financial reporting, as defined in Rule
13a-15(f) of the Act, in the quarterly period ended December 31, 2010, that have materially
affected, or are reasonably likely to materially affect, our internal control over financial
reporting.
Management’s Annual Report on Internal Control Over Financial Reporting
This report is included in Item 8 on page 70 and is incorporated herein by reference.
Report of Independent Registered Public Accounting Firm on Internal Control Over Financial
Reporting
This report is included in Item 8 on page 72 and is incorporated herein by reference.
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|
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| Item 9B. |
|
OTHER INFORMATION |
PART III
|
|
|
| Item 10. |
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DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE |
Information regarding our executive officers appears in Part I of this report on pages 28 and 29.
Code of Business Ethics and Conduct for Directors and Employees
We have a Code of Business Ethics and Conduct for Directors and Employees (Code of Ethics),
including our principal executive officer, principal financial officer, principal accounting
officer and persons performing similar functions. We have posted a copy of our Code of Ethics on
the “Corporate Governance” section of our Internet Web site at www.conocophillips.com (within the
Investor Relations>Governance section). Any waivers of the Code of Ethics must be approved, in
advance, by our full Board of Directors. Any amendments to, or waivers from, the Code of Ethics
that apply to our executive officers and directors will be posted on the “Corporate Governance”
section of our Internet Web site.
All other information required by Item 10 of Part III will be included in our Proxy Statement
relating to our 2011 Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or
before April 30, 2011, and is incorporated herein by reference.*
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| Item 11. |
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EXECUTIVE COMPENSATION |
Information required by Item 11 of Part III will be included in our Proxy Statement relating to our
2011 Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before April 30,
2011, and is incorporated herein by reference.*
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| Item 12. |
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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER
MATTERS |
Information required by Item 12 of Part III will be included in our Proxy Statement relating to our
2011 Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before April 30,
2011, and is incorporated herein by reference.*
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|
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| Item 13. |
|
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE |
Information required by Item 13 of Part III will be included in our Proxy Statement relating to our
2011 Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before April 30,
2011, and is incorporated herein by reference.*
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| Item 14. |
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PRINCIPAL ACCOUNTING FEES AND SERVICES |
Information required by Item 14 of Part III will be included in our Proxy Statement relating to our
2011 Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before April 30,
2011, and is incorporated herein by reference.*
Schedule
PART IV
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| Item 15. |
|
EXHIBITS, FINANCIAL STATEMENT SCHEDULES |
(a)
SCHEDULE II—
VALUATION AND QUALIFYING ACCOUNTS
(Consolidated)
ConocoPhillips
Deducted from asset accounts:
Allowance for doubtful accounts and
notes receivable
Deferred tax asset valuation allowance
Included in other liabilities:
Restructuring accruals
2008
(a)Represents acquisitions/dispositions/revisions and the effect of translating foreign financial statements.
(b)Amounts charged off less recoveries of amounts previously charged off.
(c)Benefit payments.
CONOCOPHILLIPS
INDEX TO EXHIBITS
3.1
3.2
3.3
4.1
10.1
10.2
10.3
10.4
10.5
10.6
10.7
10.8
10.9
10.10.1
10.10.2
10.11.1
10.11.2
10.12
10.13
10.14
10.15
10.16
10.17.1
10.17.2
10.18.1
10.18.2
10.19
10.20.1
10.20.2
10.20.3
10.20.4
10.21
10.22
10.23
10.24
10.25
10.26
10.27
10.28
10.29
12
21
23.1
23.2
31.1
31.2
32
99
101.INS
101.SCH
101.CAL
101.DEF
101.LAB
101.PRE
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto
duly authorized.
February 23, 2011
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed,
as of February 23, 2011, on behalf of the registrant by the following officers in the capacity
indicated and by a majority of directors.
/s/ James J. Mulva
James J. Mulva
/s/ Jeff W. Sheets
Jeff W. Sheets
/s/ Glenda M. Schwarz
Glenda M. Schwarz
/s/ Richard L. Armitage
Richard L. Armitage
/s/ Richard H. Auchinleck
Richard H. Auchinleck
/s/ James E. Copeland, Jr.
James E. Copeland, Jr.
/s/ Kenneth M. Duberstein
Kenneth M. Duberstein
/s/ Ruth R. Harkin
Ruth R. Harkin
/s/ Harold W. McGraw III
Harold W. McGraw III
/s/ Robert A. Niblock
Robert A. Niblock
/s/ Harald J. Norvik
Harald J. Norvik
/s/ William K. Reilly
William K. Reilly
/s/ Bobby S. Shackouls
Bobby S. Shackouls
/s/ Victoria J. Tschinkel
Victoria J. Tschinkel
/s/ Kathryn C. Turner
Kathryn C. Turner
/s/ William E. Wade, Jr.
William E. Wade, Jr.