Exhibit 99.2

Item 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

December 3, 2012

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 32.

Due to the separation of our downstream businesses on April 30, 2012, and the subsequent reporting of such businesses as discontinued operations, income (loss) from continuing operations is more representative of ConocoPhillips as an independent exploration and production company. The terms “earnings” and “loss” as used in Management’s Discussion and Analysis refer to income (loss) from continuing operations.

BUSINESS ENVIRONMENT AND EXECUTIVE OVERVIEW

At December 31, 2011, ConocoPhillips had approximately 29,800 employees worldwide and total assets of $153 billion. After the separation of Phillips 66, we became the world’s largest independent exploration and production (E&P) company, based on proved reserves and production of liquids and natural gas. Headquartered in Houston, Texas, we have operations and activities in 30 countries. Our stock is listed on the New York Stock Exchange under the symbol “COP.”

The Separation

On April 30, 2012, we completed the separation of Phillips 66 into an independent, publicly traded company. Our refining, marketing and transportation businesses, most of our Midstream segment, our Chemicals segment, as well as our power generation and certain technology operations included in our Emerging Businesses segment (collectively, our “Downstream business”), were transferred to Phillips 66. Results of operations related to Phillips 66 have been reclassified as discontinued operations where indicated in this Form 8-K. For additional information, see Note 26—Separation of Downstream Business, in the Notes to Consolidated Financial Statements.

Business Environment

Crude oil and natural gas prices are the most significant factors affecting our profitability. In recent years, the business environment for the energy industry has experienced extreme volatility. As a result, in late 2009, we announced several strategic initiatives designed to improve our financial position and increase returns on capital. We have made significant progress on our three-year strategic plan through portfolio optimization, debt reduction and increased shareholder distributions. Through our 2012–2013 disposition program, we plan to raise $8–$10 billion of proceeds from asset dispositions by the end of 2013. As part of this program, we have generated $2.1 billion in proceeds from assets sales through September 30, 2012.

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We also completed the sale of our interest in LUKOIL in the first quarter of 2011, which generated total proceeds of $9.5 billion in 2010 and 2011. These proceeds were largely used to fund share repurchases. In December 2011, our Board authorized the additional purchase of up to $10 billion of our common stock over the next two years. This increased the share repurchase program from $15 billion to $25 billion. Since the inception of the share repurchase programs, we have repurchased 15 percent of our shares outstanding for a total of $15 billion through December 31, 2011. After the separation, share repurchases will be made opportunistically, contingent upon commodity prices and proceeds from asset sales. During 2011, we also increased the amount of our quarterly dividend rate by 20 percent, paid dividends on our common stock of $3.6 billion for the full year and reduced our debt by 4 percent.

Our total capital program in 2012 is expected to be $15.5 billion to $16.0 billion compared to $12.9 billion in 2011. We also expect 2012 production to be approximately 1.57 million to 1.58 million barrels of oil equivalent per day.

Other important factors that we must continue to manage well in order to sustain our long-term competitive position include:

| • |  | Operating our producing properties 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. Minimizing downtime in producing fields enables us to capture the value available in the market in terms of prices and margins.

There has been heightened public focus on the safety of the oil and gas industry as a result of the 2010 Deepwater Horizon incident in the Gulf of Mexico. Safety and environmental stewardship, including the operating integrity of our assets, remain our highest priorities. 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 and improve industry spill response in the U.S. Gulf of Mexico. To complement this work internationally, in 2011, we and several leading oil and gas companies established the Subsea Well Response Project in Norway, and we participated in the Oil Spill Prevention and Response Advisory Group in the United Kingdom.

| • |  | Adding to our proved reserve base. We primarily add to our proved reserve base in three ways:

| • |  | Successful exploration, exploitation and development of new and existing fields.

| • |  | Application of new technologies and processes to improve recovery from existing fields.

| • |  | Acquisition of existing fields.

Through a combination of the methods listed above, we have been successful in the past in maintaining or adding to our production and proved reserve base, and we anticipate being able to do so in the future. In the five years ended December 31, 2011, our reserve replacement was 102 percent, excluding LUKOIL and the impact of acquisitions, dispositions and expropriations.

Access to additional resources has become increasingly difficult as direct investment is prohibited in some nations, while fiscal and other terms in other countries can make projects uneconomic or unattractive. In addition, political instability, competition from national oil companies, and lack of access to high-potential areas due to environmental or other regulation may negatively impact our ability to increase our reserve base. As such, the timing and level at which we add to our reserve base may, or may not, allow us to replace our production over subsequent years.

| • |  | Controlling costs and expenses. Since we cannot control the prices of the commodity products we sell, controlling operating and overhead costs, within the context of our commitment to safety and environmental stewardship, is a high priority. We monitor these costs using various methodologies that are reported to senior management monthly, on both an absolute-dollar basis and a per-unit basis. Because managing operating and overhead costs is critical to maintaining competitive positions in our industries, cost control is a component of our variable compensation programs. Operating and overhead costs increased 4 percent in 2011, compared with 2010, primarily as a result of higher operating expenses in Alaska and the settlement of environmental claims and other costs related to Bohai Bay, China.

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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 or construct pipelines and LNG facilities. 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.

The capital expenditures and investments portion of our capital program totaled $12.2 billion in 2011, and we anticipate capital expenditures and investments to be $14.8 billion to $15.3 billion in 2012. The increase reflects our strategic emphasis on delivering value through organic growth. We expect competitive returns from increased investments in unconventional resource projects, such as our liquids-rich shale plays in the U.S. Lower 48, our oil sands business in Canada, major projects in Malaysia and the North Sea, and the Australia Pacific LNG (APLNG) joint venture. As our production profile adjusts over time to reflect our increased levels of investment in liquids plays and lower levels in North American conventional natural gas, we expect higher returns, absent changes in market factors.

| • |  | Managing our asset portfolio. We continually evaluate our assets to determine whether they fit our strategic plans or should be sold or otherwise disposed. As part of our $15–$20 billion asset divestiture program for 2010–2012, we sold our 9.03 percent interest in the Syncrude oil sands mining operation and several E&P properties located in the Lower 48 and western Canada in 2010. In 2011, we continued to divest low-return, noncore assets in the Lower 48 and western Canada, and we completed the divestiture of our entire interest in LUKOIL. Additionally, as part of this asset disposition program, we sold several assets associated with our former downstream operations, which is reflected as discontinued operations.

As part of our 2012–2013 disposition program, during the first nine months of 2012, we sold our Vietnam business, the Statfjord and Alba fields in the North Sea, our investment in Naryanmarneftegaz (NMNG) in Russia, and further diluted our interest in APLNG from 42.5 percent to 37.5 percent. In addition, in November 2012, we announced our intention to sell our 8.4 percent interest in the North Caspian Sea Production Sharing Agreement (Kashagan). The transaction is expected to close in the first half of 2013, subject to governmental approvals and various preemption rights.

| • |  | 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.

Other significant factors that can affect our profitability include:

| • |  | Commodity prices. In 2011, the global economic rate of growth slowed, leading to lower oil demand growth. Oil prices, however, increased in 2011, as supply concerns, including concerns over the loss of Libyan production, outweighed the economic uncertainty in the United States and Europe. Global oil prices continued to strengthen slightly in the first nine months of 2012, as global economic concerns eased and geopolitical risks remained high.

U.S. natural gas prices remained under pressure during 2011, as increased production from shale plays outpaced demand growth. As a result, storage inventory levels reached record highs by the end of 2011. This continued into the first nine months of 2012, and as a result, U.S. natural gas prices have continued to decline. We expect these factors will continue to moderate natural gas prices, resulting in limited U.S. LNG imports in the near- to mid-term.

The expansion in shale production has also helped boost supplies of natural gas liquids, resulting in downward pressure on U.S. natural gas liquids prices. Consequently, our domestic realized natural gas liquids price declined 26 percent in the first nine months of 2012, compared with the same periods of 2011.

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In recent years, the use of hydraulic fracturing in shale natural gas formations has led to increased industry actual and forecasted natural gas production in the United States. Although providing short- and long-term significant growth opportunities for our company, the increased abundance of natural gas due to development of shale plays could also have adverse financial implications to us, including: an extended period of low natural gas prices; production curtailments on properties that produce primarily natural gas; cancelation or delay of plans to develop Alaska North Slope and Canadian Arctic natural gas fields; and underutilization of LNG regasification facilities and certain natural gas pipelines. Should one or more of these events occur, our revenues would be reduced and additional impairments might be possible.

| • |  | 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 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 2011 totaled $800 million and primarily resulted from the impairments of our equity investment in NMNG and certain Canadian natural gas properties. Before-tax impairments in 2010 totaled $726 million and primarily related to the $645 million impairment of our equity investment in NMNG.

| • |  | Effective tax rate. Our operations are located in countries with different tax rates and fiscal structures. Accordingly, even in a stable commodity price and fiscal/regulatory environment, our overall effective tax rate can vary significantly between periods based on the “mix” of pretax earnings within our global operations.

| • |  | Fiscal and regulatory environment. Our operations can be affected by changing economic, regulatory and political environments in the various countries in which we operate, including the United States. Civil unrest or strained relationships with governments may impact our operations or investments. These changing environments have generally negatively impacted our results of operations, and further changes to government fiscal take could have a negative impact on future operations. Our production operations in Libya and related oil exports were temporarily suspended in 2011 during Libya’s period of civil unrest. 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

Our operating segments were realigned as a result of the separation of Phillips 66. We now manage our operations through six operating segments, which are defined by geographic region: Alaska, Lower 48 and Latin America, Canada, Europe, Asia Pacific and Middle East, and Other International.

Our earnings generally correlate with industry price levels for crude oil and natural gas. 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 2011, compared with 2010, averaging $95.05 per barrel in 2011, an increase of 20 percent. Industry natural gas prices at Henry Hub decreased 8 percent during 2011 to an average price of $4.04 per million British thermal units.

Our LUKOIL Investment represents our prior investment in the ordinary shares of OAO LUKOIL, which was sold in the first quarter of 2011.

Corporate and Other represents costs not directly associated with an operating segment, such as most interest expense, corporate overhead, ongoing costs related to the separation of Phillips 66 and certain technology activities, net of licensing revenues.

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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 and production.

RESULTS OF OPERATIONS

The following discussion of the results of operations of ConocoPhillips for the three years ended December 31, 2011, reflects changes to the information included in the ConocoPhillips Annual Report on Form 10-K for the year ended December 31, 2011, as a result of the realignment of our operating segments due to the separation of Phillips 66.

Consolidated Results

A summary of income (loss) from continuing operations by business segment follows:

|  | Millions of Dollars |
Years Ended December 31 |  | 2011 |  |  | 2010 |  |  | 2009 |
Alaska |  | $ | 1,984 |  |  |  | 1,727 |  |  |  | 1,534 |
Lower 48 and Latin America |  |  | 1,288 |  |  |  | 1,029 |  |  |  | (73 | )
Canada |  |  | 91 |  |  |  | 2,902 |  |  |  | (257 | )
Europe |  |  | 1,830 |  |  |  | 1,703 |  |  |  | 1,119 |
Asia Pacific and Middle East |  |  | 3,093 |  |  |  | 2,153 |  |  |  | 1,389 |
Other International |  |  | (94 | ) |  |  | (261 | ) |  |  | 20 |
LUKOIL Investment |  |  | 239 |  |  |  | 2,513 |  |  |  | 1,219 |
Corporate and Other |  |  | (976 | ) |  |  | (1,317 | ) |  |  | (1,154 | )
Income from continuing operations |  | $ | 7,455 |  |  |  | 10,449 |  |  |  | 3,797 |

2011 vs. 2010

Earnings for ConocoPhillips decreased 29 percent in 2011. The decrease was mainly due to:

| • |  | Lower gains from asset sales. In 2011, gains from asset dispositions and LUKOIL share sales were $141 million after-tax, compared with gains in 2010 of $4,463 million after-tax.

| • |  | The absence of equity earnings from LUKOIL due to the divestiture of our interest.

| • |  | Lower production volumes.

These items were partially offset by:

| • |  | Higher commodity prices. Commodity price benefits were partly offset by increased production taxes.

| • |  | Lower depreciation, depletion and amortization (DD&A) expenses, mainly as a result of lower volumes.

2010 vs. 2009

Earnings for ConocoPhillips increased 175 percent in 2010. The improvement was mainly due to:

| • |  | Gains of $4,463 million after-tax from asset dispositions and LUKOIL share sales.

| • |  | Higher commodity prices, which were somewhat offset by increased production taxes.

These items were partially offset by lower production volumes.

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Income Statement Analysis

2011 vs. 2010

Sales and other operating revenues increased 15 percent in 2011, mainly due to significantly higher prices for crude oil and higher LNG prices and volumes. Lower crude oil and natural gas volumes partly offset this increase.

Equity in earnings of affiliates decreased 10 percent in 2011. The decrease primarily resulted from the absence of equity earnings from LUKOIL due to the divestiture of our interest. This decrease was partially offset by:

| • |  | Earnings from Qatar Liquefied Gas Company Limited (3) (QG3), primarily due to sales of LNG following production startup, which occurred in October 2010.

| • |  | Lower impairments from NMNG. In 2011, equity earnings included a $395 million impairment of our equity investment, and 2010 equity earnings included a $645 million impairment.

| • |  | Improved earnings from FCCL Partnership, mostly due to higher commodity prices and volumes.

Gain on dispositions decreased 93 percent in 2011. Gains in 2011 primarily resulted from the disposition of certain E&P assets located in the Lower 48 and Canada, as well as the divestiture of our remaining LUKOIL shares. These gains were partially offset by the loss on dilution of our equity interest in APLNG from 50 percent to 42.5 percent. Gains in 2010 primarily reflected the $2,878 million gain realized from the sale of our interest in Syncrude, the $1,749 million gain on the divestiture of a portion of our LUKOIL shares, and gains on the disposition of certain assets located in the Lower 48 and Canada. For additional information, see Note 5—Assets Held for Sale or Sold and Note 6—Investments, Loans and Long-Term Receivables, in the Notes to Consolidated Financial Statements.

Purchased commodities increased 20 percent in 2011, mainly due to higher international natural gas prices in Europe.

DD&A decreased 14 percent in 2011. The decrease was mostly associated with lower production volumes and lower unit-of-production rates related to reserve bookings in 2011.

Impairments increased $240 million in 2011, mostly due to the impairment of various North American natural gas properties in 2011. For additional information, see Note 10—Impairments, in the Notes to Consolidated Financial Statements.

Taxes other than income taxes increased 43 percent in 2011, mostly due to higher production taxes in Alaska as a result of higher crude oil prices.

Interest and debt expense decreased 18 percent in 2011, primarily due to lower average debt levels.

See Note 20—Income Taxes, in the Notes to Consolidated Financial Statements, for information regarding our provision for income taxes and effective tax rate.

2010 vs. 2009

Sales and other operating revenues increased 17 percent in 2010, mainly due to higher commodity prices, partly offset by lower sales volumes.

Gain on dispositions increased by $5,482 million in 2010. The increase was primarily due to the $2,878 million gain realized from the Syncrude sale, the $1,749 million gain on the divestiture of our LUKOIL shares, and gains on the disposition of certain assets located in the Lower 48 and Canada.

Purchased commodities increased 17 percent in 2010, mostly due to higher natural gas prices.

Selling, general and administrative expenses increased 22 percent during 2010, primarily as a result of costs related to compensation and benefit plans.

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Impairments decreased 83 percent in 2010. During 2009, we recorded various property impairments, mostly related to various North American natural gas properties, in addition to a $51 million impairment of our investments in Ecuador due to their expropriation.

Taxes other than income taxes increased 51 percent in 2010, primarily due to higher production taxes in Alaska as a result of higher crude oil prices.

Interest and debt expense decreased 8 percent during 2010, primarily due to lower average debt levels.

See Note 20—Income Taxes, in the Notes to Consolidated Financial Statements, for information regarding our provision for income taxes and effective tax rate.

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Summary Operating Statistics

|  | 2011 |  |  | 2010 |  |  | 2009 |
Average Net Production* |  |  |  |  |  |  |  |  |  |  |  |
Crude oil (MBD)** |  |  | 650 |  |  |  | 763 |  |  |  | 815 |
Natural gas liquids (MBD) |  |  | 149 |  |  |  | 150 |  |  |  | 153 |
Synthetic oil (MBD) |  |  | — |  |  |  | 12 |  |  |  | 23 |
Bitumen (MBD) |  |  | 67 |  |  |  | 59 |  |  |  | 50 |
Natural gas (MMCFD)*** |  |  | 4,516 |  |  |  | 4,606 |  |  |  | 4,877 |
Total Production (MBOED)**** |  |  | 1,619 |  |  |  | 1,752 |  |  |  | 1,854 |
|  | Dollars Per Unit |
Average Sales Prices* |  |  |  |  |  |  |  |  |  |  |  |
Crude oil (per barrel) |  | $ | 105.87 |  |  |  | 77.83 |  |  |  | 59.43 |
Natural gas liquids (per barrel) |  |  | 54.71 |  |  |  | 45.24 |  |  |  | 34.01 |
Synthetic oil (per barrel) |  |  | — |  |  |  | 77.56 |  |  |  | 62.01 |
Bitumen (per barrel) |  |  | 62.56 |  |  |  | 53.06 |  |  |  | 44.84 |
Natural gas (per thousand cubic feet) |  |  | 5.34 |  |  |  | 4.98 |  |  |  | 4.37 |
|  | Millions of Dollars |
Worldwide Exploration Expenses |  |  |  |  |  |  |  |  |  |  |  |
General and administrative; geological and geophysical; and lease rentals |  | $ | 596 |  |  |  | 678 |  |  |  | 576 |
Leasehold impairment |  |  | 161 |  |  |  | 241 |  |  |  | 247 |
Dry holes |  |  | 309 |  |  |  | 236 |  |  |  | 359 |
|  | $ | 1,066 |  |  |  | 1,155 |  |  |  | 1,182 |

| * | Excludes amounts related to LUKOIL Investment.

| ** | Thousands of barrels per day.

| *** | Millions of cubic feet per day. Represents quantities available for sale and excludes gas equivalent of natural gas liquids included above.

| **** | Thousands of barrels of oil equivalent per day.

We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and natural gas liquids on a worldwide basis. At December 31, 2011, our 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.

In 2011, average production decreased 8 percent compared with 2010, mostly as a result of suspended operations in Libya and Bohai Bay, China, asset dispositions and higher unplanned downtime. Normal field decline was largely offset by new production.

Average production decreased 6 percent in 2010 compared with 2009, largely due to field decline, the impact of higher prices on production sharing arrangements and the sale of Syncrude. These decreases were partly offset by new production, primarily in China, the Lower 48, Canada, Qatar and Australia.

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Alaska

|  | 2011 |  |  | 2010 |  |  | 2009 |
Income from Continuing Operations (millions of dollars) |  | $ | 1,984 |  |  |  | 1,727 |  |  |  | 1,534 |
Average Net Production |  |  |  |  |  |  |  |  |  |  |  |
Crude oil (MBD) |  |  | 200 |  |  |  | 215 |  |  |  | 235 |
Natural gas liquids (MBD) |  |  | 15 |  |  |  | 15 |  |  |  | 17 |
Natural gas (MMCFD) |  |  | 61 |  |  |  | 82 |  |  |  | 94 |
Total Production (MBOED) |  |  | 225 |  |  |  | 244 |  |  |  | 268 |
Average Sales Prices |  |  |  |  |  |  |  |  |  |  |  |
Crude oil (dollars per barrel) |  | $ | 105.95 |  |  |  | 78.65 |  |  |  | 59.19 |
Natural gas (dollars per thousand cubic feet) |  |  | 4.56 |  |  |  | 4.62 |  |  |  | 5.33 |

The Alaska segment primarily explores for, produces, transports and markets crude oil, natural gas liquids, natural gas and LNG. In 2011, Alaska contributed 25 percent of our worldwide liquids production and 1 percent of our natural gas production.

2011 vs. 2010

Our Alaska operations reported earnings of $1,984 million in 2011, a 15 percent increase compared with earnings of $1,727 million in 2010. Earnings in 2011 benefitted from significantly higher crude oil prices, partially offset by higher production taxes, lower volumes, higher operating expenses, as well as the $54 million after-tax write-off of our investment associated with the cancellation of the Denali gas pipeline project in 2011.

Production averaged 225 MBOED in 2011, a decrease of 8 percent compared with 2010. This decrease was mainly due to normal field decline, somewhat offset by increased drilling activity.

2010 vs. 2009

Alaska earnings were $1,727 million in 2010, an increase of 13 percent compared with 2009 earnings. The improvement in earnings primarily resulted from higher crude oil prices, and to a lesser extent, lower DD&A, partly offset by higher production taxes, lower crude oil volumes, higher operating expenses and an $82 million tax-related settlement.

Production averaged 244 MBOED in 2010, a decrease of 9 percent compared with 2009. This decrease was mainly due to normal field decline, somewhat offset by increased drilling activity.

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Lower 48 and Latin America

|  | 2011 |  |  | 2010 |  |  | 2009 |
Income from Continuing Operations (millions of dollars) |  | $ | 1,288 |  |  |  | 1,029 |  |  |  | (73 | )
Average Net Production |  |  |  |  |  |  |  |  |  |  |  |
Crude oil (MBD) |  |  | 94 |  |  |  | 85 |  |  |  | 95 |
Natural gas liquids (MBD) |  |  | 74 |  |  |  | 75 |  |  |  | 75 |
Natural gas (MMCFD) |  |  | 1,556 |  |  |  | 1,695 |  |  |  | 1,927 |
Total Production (MBOED) |  |  | 428 |  |  |  | 442 |  |  |  | 491 |
Average Sales Prices |  |  |  |  |  |  |  |  |  |  |  |
Crude oil (dollars per barrel) |  | $ | 92.79 |  |  |  | 73.52 |  |  |  | 55.80 |
Natural gas liquids (dollars per barrel) |  |  | 50.55 |  |  |  | 39.92 |  |  |  | 29.65 |
Natural gas (dollars per thousand cubic feet) |  |  | 3.99 |  |  |  | 4.25 |  |  |  | 3.42 |

During 2011, Lower 48 and Latin America contributed 19 percent of our worldwide liquids production and 34 percent of our natural gas production. The Lower 48 and Latin America segment primarily consists of operations located in the U.S. Lower 48 states. Also included in this segment is our 39 percent equity interest in Phoenix Park Gas Processors Limited, which processes natural gas in Trinidad and markets natural gas liquids in the Atlantic Basin, and the Wingate fractionation plant located in Gallup, New Mexico.

2011 vs. 2010

Lower 48 and Latin America operations reported earnings of $1,288 million in 2011, a 25 percent increase compared with 2010. The increase in 2011 earnings was mainly due to higher crude oil and natural gas liquids prices and lower DD&A. These increases were partly offset by lower gains from asset sales, lower natural gas prices, higher dry hole expenses and impairments.

Production averaged 428 MBOED in 2011, a 3 percent decrease compared with 2010. The decrease in 2011 was mainly due to asset dispositions. Normal field decline was offset by new production, mainly from the Eagle Ford, Bakken, Permian and Barnett areas, and improved drilling and well performance.

2010 vs. 2009

Lower 48 and Latin America earnings were $1,029 million in 2010, compared with a loss of $73 million in 2009. Earnings in 2010 primarily benefitted from higher crude oil, natural gas and natural gas liquids prices, as well as higher gains from asset sales and lower DD&A. These increases were partially offset by lower crude oil and natural gas volumes.

Production averaged 442 MBOED in 2010, a 10 percent decrease compared with 2009. The decrease in 2010 was largely due to normal field decline and higher unplanned downtime, partly offset by new production from the Eagle Ford, Bakken, Permian and Barnett areas.

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Canada

|  | 2011 |  |  | 2010 |  |  | 2009 |
Income from Continuing Operations (millions of dollars) |  | $ | 91 |  |  |  | 2,902 |  |  |  | (257 | )
Average Net Production |  |  |  |  |  |  |  |  |  |  |  |
Crude oil (MBD) |  |  | 12 |  |  |  | 15 |  |  |  | 16 |
Natural gas liquids (MBD) |  |  | 26 |  |  |  | 23 |  |  |  | 24 |
Synthetic oil (MBD) |  |  | — |  |  |  | 12 |  |  |  | 23 |
Bitumen (MBD) |  |  |  |  |  |  |  |  |  |  |  |
Consolidated operations |  |  | 10 |  |  |  | 10 |  |  |  | 7 |
Equity affiliates |  |  | 57 |  |  |  | 49 |  |  |  | 43 |
Total bitumen |  |  | 67 |  |  |  | 59 |  |  |  | 50 |
Natural gas (MMCFD) |  |  | 928 |  |  |  | 984 |  |  |  | 1,062 |
Total Production (MBOED) |  |  | 260 |  |  |  | 273 |  |  |  | 290 |
Average Sales Prices |  |  |  |  |  |  |  |  |  |  |  |
Crude oil (dollars per barrel) |  | $ | 86.04 |  |  |  | 67.99 |  |  |  | 53.22 |
Natural gas liquids (dollars per barrel) |  |  | 56.84 |  |  |  | 47.68 |  |  |  | 33.86 |
Bitumen (dollars per barrel) |  |  |  |  |  |  |  |  |  |  |  |
Consolidated operations |  |  | 55.16 |  |  |  | 51.10 |  |  |  | 39.67 |
Equity affiliates |  |  | 63.93 |  |  |  | 53.43 |  |  |  | 45.69 |
Natural gas (dollars per thousand cubic feet) |  |  | 3.46 |  |  |  | 3.74 |  |  |  | 3.33 |

Our Canadian operations are mainly comprised of natural gas fields in western Canada and oil sands projects in the Athabasca Region of northeastern Alberta. In 2011, Canada contributed 12 percent of our worldwide liquids production and 21 percent of our natural gas production.

2011 vs. 2010

Canada operations reported earnings of $91 million in 2011, a reduction of $2,811 million compared with 2010. This decrease was primarily due to lower gains from asset dispositions. Earnings in 2010 included the $2,679 million after-tax gain realized from the sale of our 9.03 percent interest in the Syncrude oil sands mining operation. Lower volumes, mostly as a result of asset dispositions, impairments on various natural gas properties and lower natural gas prices also contributed to the decrease in 2011 earnings. These decreases were somewhat offset by higher bitumen, natural gas liquids and crude oil prices, lower DD&A and lower dry hole expenses.

Production averaged 260 MBOED in 2011, a 5 percent decrease compared with 2010. The decrease was mainly due to asset dispositions and normal field decline, partly offset by new production from FCCL Partnership.

2010 vs. 2009

Canada reported earnings of $2,902 million in 2010, compared with a loss of $257 million in 2009. The increase was mostly due to gains from the sale of Syncrude and other assets, higher commodity prices and lower impairments, partially offset by lower volumes.

Average production decreased 6 percent in 2010, mostly due to normal field decline and asset dispositions, partly offset by new production from FCCL.

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Europe

|  | 2011 |  |  | 2010 |  |  | 2009 |
Income from Continuing Operations (millions of dollars) |  | $ | 1,830 |  |  |  | 1,703 |  |  |  | 1,119 |
Average Net Production |  |  |  |  |  |  |  |  |  |  |  |
Crude oil (MBD) |  |  | 164 |  |  |  | 196 |  |  |  | 224 |
Natural gas liquids (MBD) |  |  | 11 |  |  |  | 15 |  |  |  | 17 |
Natural gas (MMCFD) |  |  | 626 |  |  |  | 815 |  |  |  | 876 |
Total Production (MBOED) |  |  | 279 |  |  |  | 347 |  |  |  | 387 |
Average Sales Prices |  |  |  |  |  |  |  |  |  |  |  |
Crude oil (dollars per barrel) |  | $ | 111.82 |  |  |  | 79.74 |  |  |  | 60.89 |
Natural gas liquids (dollars per barrel) |  |  | 59.19 |  |  |  | 46.75 |  |  |  | 34.31 |
Natural gas (dollars per thousand cubic feet) |  |  | 9.26 |  |  |  | 6.94 |  |  |  | 6.81 |

The Europe segment consists of operations principally located in the Norwegian and U.K. sectors of the North Sea, as well as exploration activities in Poland and Greenland. In 2011, our Europe operations contributed 20 percent of our worldwide liquids production and 14 percent of our natural gas production.

In December 2011, we entered into an agreement to sell our interests in the MacCulloch, Alba and Nicol fields in the United Kingdom. The sale of the Alba Field closed in the second quarter of 2012. The sale of our interests in the MacCulloch and Nicol fields is expected to close in the fourth quarter of 2012, subject to agreement on final terms. In January 2012, we entered into an agreement to sell our interests in the Statfjord Field and associated satellites, which closed in the second quarter of 2012.

2011 vs. 2010

Earnings for our Europe operations were $1,830 million in 2011, a 7 percent increase compared with earnings of $1,703 million in 2010. Earnings benefitted from significantly higher prices and lower DD&A, partly offset by lower volumes and a $316 million increase in income tax expense, as a result of legislation enacted in the United Kingdom in July 2011. This additional tax expense consisted of $106 million for the revaluation of deferred tax liabilities and $210 million to reflect the higher tax rates from the effective date of the legislation, March 24, 2011, through December 31, 2011. Earnings in 2010 also benefitted from a $58 million insurance settlement.

Production averaged 279 MBOED in 2011, a 20 percent decrease compared with 2010. The decrease mainly resulted from normal field decline, unplanned downtime and dispositions, somewhat offset by new production from Britannia and J-Block.

2010 vs. 2009

Europe earnings improved $584 million in 2010, a 52 percent increase compared with 2009. Earnings largely benefitted from higher crude oil prices, partially offset by lower crude oil and natural gas volumes. Lower foreign currency transaction losses, the $58 million insurance settlement and lower taxes also contributed to the improvement in 2010 earnings.

Average production in Europe decreased 10 percent in 2010, largely due to normal field decline and planned maintenance, partly offset by new production and improved well performance in the United Kingdom.

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Asia Pacific and Middle East

|  | 2011 |  |  | 2010 |  |  | 2009 |
Income from Continuing Operations (millions of dollars) |  | $ | 3,093 |  |  |  | 2,153 |  |  |  | 1,389 |
Average Net Production |  |  |  |  |  |  |  |  |  |  |  |
Crude oil (MBD) |  |  |  |  |  |  |  |  |  |  |  |
Consolidated operations |  |  | 99 |  |  |  | 122 |  |  |  | 114 |
Equity affiliates |  |  | 16 |  |  |  | 2 |  |  |  | — |
Total crude oil |  |  | 115 |  |  |  | 124 |  |  |  | 114 |
Natural gas liquids (MBD) |  |  |  |  |  |  |  |  |  |  |  |
Consolidated operations |  |  | 12 |  |  |  | 18 |  |  |  | 18 |
Equity affiliates |  |  | 7 |  |  |  | 1 |  |  |  | — |
Total natural gas liquids |  |  | 19 |  |  |  | 19 |  |  |  | 18 |
Natural gas (MMCFD) |  |  |  |  |  |  |  |  |  |  |  |
Consolidated operations |  |  | 695 |  |  |  | 712 |  |  |  | 713 |
Equity affiliates |  |  | 492 |  |  |  | 169 |  |  |  | 84 |
Total natural gas |  |  | 1,187 |  |  |  | 881 |  |  |  | 797 |
Total Production (MBOED) |  |  | 332 |  |  |  | 290 |  |  |  | 265 |
Average Sales Prices |  |  |  |  |  |  |  |  |  |  |  |
Crude oil (dollars per barrel) |  |  |  |  |  |  |  |  |  |  |  |
Consolidated operations |  | $ | 109.84 |  |  |  | 77.69 |  |  |  | 59.56 |
Equity affiliates |  |  | 106.96 |  |  |  | 89.24 |  |  |  | 62.66 |
Total crude oil |  |  | 109.46 |  |  |  | 77.89 |  |  |  | 59.56 |
Natural gas liquids (dollars per barrel) |  |  |  |  |  |  |  |  |  |  |  |
Consolidated operations |  |  | 72.87 |  |  |  | 60.57 |  |  |  | 44.94 |
Equity affiliates |  |  | 70.62 |  |  |  | 65.16 |  |  |  | — |
Total natural gas liquids |  |  | 71.98 |  |  |  | 60.73 |  |  |  | 44.94 |
Natural gas (dollars per thousand cubic feet) |  |  |  |  |  |  |  |  |  |  |  |
Consolidated operations |  |  | 9.82 |  |  |  | 7.39 |  |  |  | 6.00 |
Equity affiliates |  |  | 2.89 |  |  |  | 2.79 |  |  |  | 2.35 |
Total natural gas |  |  | 6.95 |  |  |  | 6.52 |  |  |  | 5.61 |

The Asia Pacific and Middle East segment has producing operations in China, Vietnam, Indonesia, Australia, the Timor Sea and Qatar, as well as exploration activities in Malaysia, Bangladesh and Brunei. During 2011, Asia Pacific and Middle East contributed 16 percent of our worldwide liquids production and 26 percent of our natural gas production.

In February 2012, we entered into an agreement to sell our entire Vietnam business. The transaction closed in the first quarter of 2012. We also further diluted our equity investment in APLNG from 42.5 percent to 37.5 percent in the third quarter of 2012.

2011 vs. 2010

Asia Pacific and Middle East operations reported earnings of $3,093 million in 2011, a 44 percent increase compared with 2010 earnings of $2,153 million. Earnings in 2011 primarily benefitted from higher prices, higher volumes, mostly as a result of a full year of LNG sales from Qatargas 3 (QG3), and lower DD&A. These increases to earnings were partly offset by higher production taxes, higher operating expenses and the $279 million loss on dilution of our equity interest in APLNG from 50 percent to 42.5 percent.

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Production averaged 332 MBOED in 2011, a 14 percent increase compared with 2010. The increase was largely due to the ramp-up of production from QG3, partly offset by higher unplanned downtime, mainly in China, and normal field decline.

2010 vs. 2009

Asia Pacific and Middle East earnings increased $764 million in 2010, or 55 percent compared with 2009. Earnings in 2010 mainly benefitted from higher prices and volumes, as well as higher gains from foreign currency transactions. These increases to earnings were partly offset by higher DD&A, increased 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 in 2010.

Production averaged 290 MBOED in 2010, a 9 percent increase compared with 2009. The increase was largely due to new production, primarily in China, Qatar and Australia, partly offset by normal field decline, the impact of higher prices on production sharing arrangements and higher planned maintenance at our Bayu-Undan Field and Darwin LNG Facility.

China—Bohai Bay

At the end of the third quarter of 2012, Peng Lai’s net production was approximately 45 MBOED. We continue to seek approval for the revised overall development plan, while the environmental impact assessment was approved in October 2012. Oil offtake should remain fairly level for the remainder of 2012 under an approved interim operations resumption plan.

Other International

|  | 2011 |  |  | 2010 |  |  | 2009 |
Income from Continuing Operations (millions of dollars) |  | $ | (94 | ) |  |  | (261 | ) |  |  | 20 |
Average Net Production |  |  |  |  |  |  |  |  |  |  |  |
Crude oil (MBD) |  |  |  |  |  |  |  |  |  |  |  |
Consolidated operations |  |  | 36 |  |  |  | 76 |  |  |  | 76 |
Equity affiliates |  |  | 29 |  |  |  | 52 |  |  |  | 55 |
Total crude oil |  |  | 65 |  |  |  | 128 |  |  |  | 131 |
Natural gas liquids (MBD) |  |  | 4 |  |  |  | 3 |  |  |  | 2 |
Natural gas (MMCFD) |  |  | 158 |  |  |  | 149 |  |  |  | 121 |
Total Production (MBOED) |  |  | 95 |  |  |  | 156 |  |  |  | 153 |
Average Sales Prices |  |  |  |  |  |  |  |  |  |  |  |
Crude oil (dollars per barrel) |  |  |  |  |  |  |  |  |  |  |  |
Consolidated operations |  | $ | 111.17 |  |  |  | 79.58 |  |  |  | 62.42 |
Equity affiliates |  |  | 101.62 |  |  |  | 74.33 |  |  |  | 58.23 |
Total crude oil |  |  | 106.72 |  |  |  | 77.37 |  |  |  | 60.67 |
Natural gas liquids (dollars per barrel) |  |  | 13.63 |  |  |  | 11.26 |  |  |  | 8.73 |
Natural gas (dollars per thousand cubic feet) |  |  | 2.24 |  |  |  | 1.81 |  |  |  | 1.56 |

The Other International segment includes producing operations in Nigeria, Libya, Algeria and Russia, exploration activities in Angola and exploration and development in the Caspian Sea. During 2011, Other International contributed 8 percent of our worldwide liquids production and 4 percent of our natural gas production.

In the third quarter of 2012, we sold our equity investment in NMNG. In November 2012, we announced our intention to sell our 8.4 percent interest in Kashagan. The transaction is expected to close in the first half of 2013, subject to governmental approvals and various preemption rights.

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2011 vs. 2010

Other International operations reported a loss of $94 million in 2011, compared with a loss of $261 million in 2010. The improvement in 2011 was primarily the result of higher crude oil prices, higher equity earnings due to lower DD&A from NMNG and lower impairments. In 2011, we recorded a $395 million impairment of our equity investment in NMNG, compared with a $645 million impairment to NMNG recorded in 2010. These improvements in 2011 were partly offset by considerably lower volumes, mainly from Libya and Russia, as well as the absence of a deferred tax benefit recognized in 2010.

Production averaged 95 MBOED in 2011, a 39 percent decrease compared with 2010 production. The decrease was mostly due to suspended operations in Libya following a period of civil unrest in 2011, and field decline in Russia.

2010 vs. 2009

Other International operations reported a loss of $261 million in 2010, compared with earnings of $20 million in 2009. The loss in 2010 mainly resulted from the NMNG impairment, lower equity earnings due to higher DD&A and taxes from equity affiliates, and lower crude oil volumes, somewhat offset by higher crude oil prices and the recognition of a deferred tax benefit.

Production averaged 156 MBOED in 2010, a 2 percent increase compared with 2009 production. Field decline in Russia and higher unplanned downtime in Libya were more than offset by the absence of the Organization of Petroleum Exporting Countries (OPEC) quota restrictions in Libya in 2010 and improved natural gas production in Nigeria.

LUKOIL Investment

|  | Millions of Dollars |
|  | 2011 |  |  | 2010 |  |  | 2009 |
Income From Continuing Operations |  | $ | 239 |  |  |  | 2,513 |  |  |  | 1,219 |
Average Net Production |  |  |  |  |  |  |  |  |  |  |  |
Crude oil—Equity affiliates (MBD) |  |  | — |  |  |  | 284 |  |  |  | 388 |
Natural gas—Equity affiliates (MMCFD) |  |  | — |  |  |  | 254 |  |  |  | 295 |
Total Production (MBOED) |  |  | — |  |  |  | 326 |  |  |  | 437 |

This segment represents our former investment in the ordinary shares of OAO LUKOIL, an international, integrated oil and gas company headquartered in Russia. We sold our remaining interest in LUKOIL in the first quarter of 2011.

2011 vs. 2010

Earnings in 2011 primarily represented the realized gain on remaining share sales. Earnings in 2010 primarily reflected earnings from the equity investment in LUKOIL we held at the time, in addition to gains on the partial sale of our LUKOIL investment.

2010 vs. 2009

LUKOIL segment earnings increased $1,294 million in 2010, which primarily resulted from the $1,251 million after-tax gain on our LUKOIL shares sold during 2010.

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Corporate and Other

|  | Millions of Dollars |
|  | 2011 |  |  | 2010 |  |  | 2009 |
Income (Loss) From Continuing Operations |  |  |  |  |  |  |  |  |  |  |  |
Net interest |  | $ | (710 | ) |  |  | (995 | ) |  |  | (915 | )
Corporate general and administrative expenses |  |  | (190 | ) |  |  | (209 | ) |  |  | (108 | )
Technology |  |  | 15 |  |  |  | (23 | ) |  |  | (63 | )
Separation costs |  |  | (25 | ) |  |  | — |  |  |  | — |
Other |  |  | (66 | ) |  |  | (90 | ) |  |  | (68 | )
|  | $ | (976 | ) |  |  | (1,317 | ) |  |  | (1,154 | )

2011 vs. 2010

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 decreased 29 percent in 2011, mostly due to lower interest expense, as a result of lower average debt levels. In addition, the absence of a $114 million after-tax premium on early debt retirement and the absence of $24 million of after-tax interest expense associated with a tax settlement, both of which occurred in 2010, contributed to the decrease.

Corporate general and administrative expenses decreased 9 percent in 2011, mainly due to lower costs related to compensation and benefit plans, partly offset by higher advertising expenses.

Technology includes our investment in new technologies or businesses, as well as licensing revenues received. Activities are focused on heavy oil and oil sands, unconventional reservoirs, subsurface technology, liquefied natural gas, arctic and deepwater, as well as sustainability technology. Technology had earnings of $15 million in 2011, as a result of higher licensing revenues, partially offset by higher project expenses.

Separation costs consist of expenses related to the separation of our Downstream business into a stand-alone, publicly traded company, Phillips 66. Expenses incurred in 2011 primarily included legal, accounting and information systems costs.

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 resulted from lower environmental costs and gains from foreign currency transactions, partially offset by a $20 million after-tax property impairment.

2010 vs. 2009

Net interest increased 9 percent in 2010, mostly due to the $114 million after-tax premium on early debt retirement and the $24 million after-tax interest expense settlement. These increases were partially offset by lower interest expense due to lower debt levels.

Corporate general and administrative expenses increased 94 percent in 2010, primarily as a result of costs related to compensation and benefit plans.

Technology earnings improved $40 million as a result of higher licensing revenues.

Changes in the “Other” category primarily reflected foreign currency transaction losses, partly offset by various tax-related adjustments.

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CAPITAL RESOURCES AND LIQUIDITY

Financial Indicators

|  | Millions of Dollars Except as Indicated |
|  | 2011 |  |  | 2010 |  |  | 2009 |
Net cash provided by continuing operating activities |  | $ | 14,477 |  |  |  | 14,453 |  |  |  | 11,383 |
Short-term debt |  |  | 1,013 |  |  |  | 936 |  |  |  | 1,728 |
Total debt |  |  | 22,623 |  |  |  | 23,592 |  |  |  | 28,653 |
Total equity* |  |  | 65,749 |  |  |  | 69,124 |  |  |  | 62,628 |
Percent of total debt to capital** |  |  | 26 | % |  |  | 25 |  |  |  | 31 |
Percent of floating-rate debt to total debt*** |  |  | 10 | % |  |  | 10 |  |  |  | 9 |

| * | Certain amounts have been restated to reflect a prior period adjustment. See Note 21—Accumulated Other Comprehensive Income, in the Notes to Consolidated Financial Statements.

| ** | 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 continuing operating activities is the primary source of funding. In addition, during 2011, we received $2,192 million in proceeds from asset sales. During 2011, the primary uses of our available cash were $12,244 million to support our ongoing capital expenditures and investments program; $11,123 million to repurchase common stock; $3,632 million to pay dividends on our common stock; and $934 million to repay debt. During 2011, cash and cash equivalents decreased by $3,674 million to $5,780 million.

In addition to cash flows from continuing 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.

Separation of Phillips 66

On April 30, 2012, the separation of our Downstream business was completed, creating two independent energy companies: ConocoPhillips and Phillips 66. Our refining, marketing and transportation businesses, most of our Midstream segment, our Chemicals segment, as well as our power generation and certain technology operations included in our Emerging Businesses segment, were transferred to Phillips 66.

After the close of the New York Stock Exchange on April 30, 2012, the shareholders of record as of 5:00 p.m. Eastern time on April 16, 2012 (the Record Date), received one share of Phillips 66 common stock for every two ConocoPhillips common shares held as of the Record Date.

In connection with the separation, Phillips 66 distributed approximately $7.8 billion to us in a special cash distribution. These funds will be used solely to pay dividends, repurchase common stock, repay debt, or a combination of the foregoing, within twelve months following the distribution.

Significant Sources of Capital

Operating Activities

During 2011, cash of $14,477 million was provided by continuing operating activities, compared to $14,453 million in 2010.

During 2010, cash flow from continuing operations increased $3,070 million, compared with 2009. The increase was primarily due to significantly higher crude oil prices.

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While the stability of our cash flows from operating activities benefits from geographic diversity, our short- and long-term operating cash flows are highly dependent upon prices for crude oil, bitumen, natural gas, LNG and natural gas liquids. Crude oil prices increased in 2009, 2010 and 2011, although natural gas prices remained weak. Prices 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 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 production for 2011 averaged 1.62 million barrels of oil equivalent 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 2012, excluding the impact of any additional dispositions, is expected to be approximately 1.57 million to 1.58 million barrels of oil equivalent 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 2012 and future years’ production levels.

To maintain or grow our production volumes, we must continue to add to our proved reserve base. Our total reserve replacement in 2011 was 112 percent, including 117 percent from consolidated operations. Excluding the impact of acquisitions and dispositions, the reserve replacement was 120 percent of 2011 production. Over the five-year period ended December 31, 2011, our reserve replacement was 30 percent (including 64 percent from consolidated operations) reflecting the disposition of our interest in LUKOIL, the expropriation of our assets in Venezuela and the impact of our asset disposition program. Excluding these items and acquisitions, our five-year reserve replacement was 102 percent. The total reserve replacement amount above is 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 2011, 2010 and 2009, revisions increased reserves. It is not possible to reliably predict how revisions will impact reserve quantities in the future.

Asset Sales

Proceeds from asset sales in 2011 were $2.2 billion, compared with $14.7 billion in 2010. The 2011 proceeds from asset sales included $1.2 billion from the sale of our remaining interest in LUKOIL. Other asset sales primarily included mature North American natural gas assets. We plan to raise an additional $8–$10 billion from asset sales by the end of 2013.

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Commercial Paper and Credit Facilities

In August 2011, we increased our revolving credit facilities from $7.85 billion to $8.0 billion by replacing our $7.35 billion revolving credit facility with a $7.5 billion facility expiring in August 2016. The terms of the new revolving credit facility are similar to the terms of the replaced facility. We also had a $500 million facility, which was terminated in May 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 QG3 Project. At December 31, 2011 and 2010, 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, $1,128 million of commercial paper was outstanding at December 31, 2011, compared with $1,182 million at December 31, 2010. Since we had $1,128 million of commercial paper outstanding and had issued $40 million of letters of credit, we had access to $6.8 billion in borrowing capacity under our revolving credit facilities at December 31, 2011.

Our senior long-term debt is rated “A1” by Moody’s Investors 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 $7.5 billion and $500 million revolving credit facilities.

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.

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.

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 $4.0 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. On December 15, 2011, QG3 achieved financial completion and all project loan facilities became nonrecourse to the project participants. At December 31, 2011, QG3 had approximately $3.9 billion outstanding under all the loan facilities, including $1.2 billion owed to ConocoPhillips.

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For additional information about guarantees, see Note 14—Guarantees, in the Notes to Consolidated Financial Statements, which is incorporated herein by reference.

Capital Requirements

Our debt balance at December 31, 2011, was $22.6 billion, a decrease of $1.0 billion during 2011, and our debt-to-capital ratio was 26 percent at year-end 2011, versus 25 percent at the end of 2010. The slight increase in the debt-to-capital ratio was due to a decrease in total equity resulting from the share repurchase programs in 2011, partially offset by the debt reduction. Our debt-to-capital ratio target range is 25 to 30 percent.

During 2012, the following debt instruments were repaid:

| • |  | The $400 million 4.4% Notes due 2013.

| • |  | $1,100 million of the $1,500 million 4.75% Notes due 2014.

| • |  | The $897 million 4.75% Notes due 2012.

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 $732 million was short-term and was included in the “Accounts payable—related parties” line on our December 31, 2011, consolidated balance sheet. The principal portion of these payments, which totaled $695 million in 2011, 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.

In October 2012, we announced a dividend of 66 cents per share. The dividend will be paid December 3, 2012, to stockholders of record at the close of business October 15, 2012.

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 was completed in the first quarter of 2011. On February 11, 2011, the Board authorized the additional purchase of up to $10 billion of our common stock over the subsequent two years. Repurchase of shares under this authorization was completed in the fourth quarter of 2011. On December 2, 2011, our Board of Directors authorized the purchase of up to an additional $10 billion of our common stock over the subsequent two years. Since our share repurchase programs began in 2010, share repurchases totaled 300 million shares at a cost of $20.1 billion through December 3, 2012. Future share purchases will be made opportunistically, contingent upon commodity prices and proceeds from asset dispositions.

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Contractual Obligations

The following table summarizes the aggregate contractual fixed and variable obligations of our continuing operations as of December 31, 2011:

|  | Millions of Dollars |
|  | Payments Due by Period |
|  | Total |  |  | Up to 1 Year |  |  | Years 2-3 |  |  | Years 4-5 |  |  | After 5 Years |
Debt obligations (a) |  | $ | 22,217 |  |  |  | 983 |  |  |  | 2,775 |  |  |  | 3,904 |  |  |  | 14,555 |
Capital lease obligations |  |  | 16 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 16 |
Total debt |  |  | 22,233 |  |  |  | 983 |  |  |  | 2,775 |  |  |  | 3,904 |  |  |  | 14,571 |
Interest on debt and other obligations |  |  | 18,937 |  |  |  | 1,311 |  |  |  | 2,319 |  |  |  | 2,020 |  |  |  | 13,287 |
Operating lease obligations |  |  | 1,014 |  |  |  | 341 |  |  |  | 342 |  |  |  | 175 |  |  |  | 156 |
Purchase obligations (b) |  |  | 24,630 |  |  |  | 10,452 |  |  |  | 3,907 |  |  |  | 2,111 |  |  |  | 8,160 |
Joint venture acquisition obligation (c) |  |  | 4,314 |  |  |  | 732 |  |  |  | 1,586 |  |  |  | 1,762 |  |  |  | 234 |
Other long-term liabilities (d) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Asset retirement obligations |  |  | 8,539 |  |  |  | 328 |  |  |  | 654 |  |  |  | 490 |  |  |  | 7,067 |
Accrued environmental costs |  |  | 380 |  |  |  | 50 |  |  |  | 54 |  |  |  | 46 |  |  |  | 230 |
Unrecognized tax benefits (e) |  |  | 153 |  |  |  | 153 |  |  |  | (e | ) |  |  | (e | ) |  |  | (e | )
Total (f) |  | $ | 80,200 |  |  |  | 14,350 |  |  |  | 11,637 |  |  |  | 10,508 |  |  |  | 43,705 |

(a) | Includes $448 million of net unamortized premiums and discounts. See Note 12—Debt, in the Notes to Consolidated Financial Statements, for additional information.

(b) | Represents any agreement to purchase goods or services that is enforceable and legally binding and that specifies all significant terms. Does not include purchase commitments for jointly owned fields and facilities where we are not the operator.

The majority of the purchase obligations are market-based contracts related to our commodity business. Product purchase commitments with third parties totaled $9,311 million.

Purchase obligations of $10,061 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 commodities. The remainder is primarily our net share of purchase commitments for materials and services for jointly owned fields and facilities where we are the operator.

(c) | Represents the remaining amount of contributions, excluding interest, due over a five-year period to the FCCL upstream joint venture with Cenovus.

(d) | Does not include pensions. For the 2012 through 2016 time period, we expect to contribute an average of $320 million per year to our qualified and nonqualified pension and postretirement benefit plans in the United States and an average of $210 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 $410 million for 2012, and then approximately $300 million per year for the remaining four years. Our required minimum funding in 2012 is expected to be $380 million in the United States and $200 million outside the United States.

(e) | Excludes unrecognized tax benefits of $918 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.

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(f) | In addition to the contractual obligations from our continuing operations, as shown in the above table, contractual obligations relating to discontinued operations are as follows:

| • |  | Debt obligations—$377 million.

| • |  | Capital leases—$14 million.

| • |  | Interest on debt and other obligations—$65 million.

| • |  | Operating lease obligations—$1,746 million.

| • |  | Purchase obligations—$122,508 million.

| • |  | Asset retirement obligations—$378 million.

| • |  | Accrued environmental costs—$542 million.

Capital Spending

Capital Expenditures and Investments

|  | Millions of Dollars |
|  | 2011 |  |  | 2010 |  |  | 2009 |
Alaska |  | $ | 774 |  |  |  | 729 |  |  |  | 810 |
Lower 48 and Latin America |  |  | 3,882 |  |  |  | 1,790 |  |  |  | 2,035 |
Canada |  |  | 1,761 |  |  |  | 1,356 |  |  |  | 1,176 |
Europe |  |  | 2,222 |  |  |  | 1,190 |  |  |  | 1,144 |
Asia Pacific and Middle East |  |  | 2,325 |  |  |  | 2,157 |  |  |  | 2,100 |
Other International |  |  | 1,038 |  |  |  | 1,203 |  |  |  | 1,001 |
LUKOIL Investment |  |  | — |  |  |  | — |  |  |  | — |
Corporate and Other |  |  | 242 |  |  |  | 186 |  |  |  | 134 |
|  | $ | 12,244 |  |  |  | 8,611 |  |  |  | 8,400 |
United States |  | $ | 4,898 |  |  |  | 2,705 |  |  |  | 2,974 |
International |  |  | 7,346 |  |  |  | 5,906 |  |  |  | 5,426 |
|  | $ | 12,244 |  |  |  | 8,611 |  |  |  | 8,400 |

Our capital expenditures and investments for the three-year period ending December 31, 2011, totaled $29.3 billion. The expenditures over this period supported key exploration and development programs, primarily:

| • |  | 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.

| • |  | Advancement of coalbed methane (CBM) projects associated with the APLNG joint venture in Australia.

| • |  | Oil sands projects and ongoing natural gas projects in Canada.

| • |  | Alaska activities related to development drilling in the Greater Kuparuk Area, the Greater Prudhoe Area, the Western North Slope and the Cook Inlet Area.

| • |  | Development drilling and facilities projects in the Norwegian sector of the North Sea, including the Greater Ekofisk Area, Alvheim and Statfjord, and Heidrun in the Norwegian Sea.

| • |  | The Peng Lai 19-3 development in China’s Bohai Bay.

| • |  | The Kashagan Field and satellite prospects in the Caspian Sea offshore Kazakhstan.

| • |  | In the U.K. sector of the North Sea, the development of the Jasmine discovery in the J-Block Area, the development of Clair Ridge, development drilling on Clair and in the southern and central North Sea.

| • |  | The North Belut Field, as well as other projects in offshore Block B and onshore South Sumatra in Indonesia.

| • |  | The QG3 Project, an integrated project to produce and liquefy natural gas from Qatar’s North Field.

| • |  | The Gumusut-Kakap development offshore Sabah, Malaysia.

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| • |  | Exploration activities in Australia’s Browse Basin, North American shale plays, Canadian oil sands projects, deepwater Gulf of Mexico, Alaska, U.K. and Norwegian sectors of the North Sea, Kazakhstan and Indonesia.

| • |  | The El Merk Project, comprised of wells, gathering lines and a shared central processing facility to develop the EMK Field Unit in Algeria.

2012 CAPITAL EXPENDITURES AND INVESTMENTS BUDGET

Our 2012 capital expenditures and investments projected spend is $14.8 billion to $15.3 billion, approximately 30 percent higher than actual expenditures in 2011. Over the next five years, we plan to execute a disciplined capital program in order to generate 3 to 5 percent cumulative annual production volume and margin growth, primarily from major developments underway in the United States, Canada, the United Kingdom and Norwegian North Sea, Malaysia and Australia.

During the first nine months of 2012, capital expenditures and investments supported key exploration and development programs, primarily:

| • |  | Oil and natural gas exploration and development activities in the Lower 48, including the Eagle Ford and Bakken shale plays, and the Permian Basin.

| • |  | Exploration leases and wells in deepwater Gulf of Mexico.

| • |  | Oil sands development and ongoing liquids-focused plays in Canada.

| • |  | Further development of CBM projects associated with the APLNG joint venture in Australia.

| • |  | Continued development of new fields offshore Malaysia and ongoing exploration and development activity offshore Indonesia and Australia.

| • |  | In Europe, development activities in the Ekofisk, Jasmine and Clair Ridge areas, as well as investment in a joint venture in Poland.

| • |  | The Kashagan Field in the Caspian Sea.

| • |  | Leasehold acquisitions in Angola.

For information on proved undeveloped reserves and the associated costs to develop these reserves, see the “Oil and Gas Operations” section.

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.

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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:

| • |  | U.S. Federal Clean Air Act, which governs air emissions.

| • |  | U.S. Federal Clean Water Act, which governs discharges to water bodies.

| • |  | European Union Regulation for Registration, Evaluation, Authorization and Restriction of Chemicals (REACH).

| • |  | 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.

| • |  | U.S. Federal Resource Conservation and Recovery Act (RCRA), which governs the treatment, storage and disposal of solid waste.

| • |  | 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.

| • |  | 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.

| • |  | U.S. Federal Safe Drinking Water Act, which governs the disposal of wastewater in underground injection wells.

| • |  | U.S. Department of the Interior regulations, which relate to offshore oil and gas operations in U.S. waters and impose liability for the cost of pollution cleanup resulting from operations, as well as potential liability for pollution damages.

| • |  | European 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.

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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.

Another example is the use of hydraulic fracturing, an essential completion technique that facilitates production of oil and natural gas that is otherwise trapped in lower permeability rock formations. A range of local, state, federal or national laws and regulations currently govern hydraulic fracturing operations. Although hydraulic fracturing has been conducted for many decades, a number of new laws, regulations and permitting requirements are under consideration by the U.S. Environmental Protection Agency (EPA), the U.S. Department of the Interior, and others which could result in increased costs, operating restrictions, operational delays and/or limit the ability to develop oil and natural gas resources. Governmental restrictions on hydraulic fracturing could impact the overall profitability or viability of certain of our oil and natural gas investments. We have adopted operating principles that incorporate established industry standards designed to meet or exceed government requirements. Our practices continually evolve as technology improves and regulations change.

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 occasionally 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, 2010, we reported we had been notified of potential liability under CERCLA and comparable state laws at 73 sites around the United States. At December 31, 2011, we had been notified of 8 new sites, settled 5 sites and closed 2 sites, bringing the number to 74 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

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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 $588 million in 2011 and are expected to be about $650 million per year in 2012 and 2013. Capitalized environmental costs were $288 million in 2011 and are expected to be about $380 million per year in 2012 and 2013.

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, 2011, our balance sheet included total accrued environmental costs of $922 million, of which $542 million related to our Downstream business. At December 31, 2010, our balance sheet included total accrued environmental costs of $994 million, of which $553 million related to our Downstream business. We expect to incur a substantial amount of these expenditures related to our continuing operations 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:

| • |  | European Emissions Trading Scheme (ETS), the program through which many of the European Union (EU) member states are implementing the Kyoto Protocol.

| • |  | California’s Global Warming Solutions Act, which requires the California Air Resources Board to develop regulations and market mechanisms that will target reduction of California’s GHG emissions by 25 percent by 2020.

| • |  | 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.

| • |  | The EPA’s announcement on March 29, 2010 (published as “Interpretation of Regulations that Determine Pollutants Covered by Clean Air Act Permitting Programs,” 75 Fed. Reg. 17004 (April 2, 2010)), and the EPA’s and U.S. Department of Transportation’s joint promulgation of a Final Rule on April 1, 2010, that triggers regulation of GHGs under the Clean Air Act, may trigger more climate-based claims for damages, and may result in longer agency review time for development projects.

| • |  | Carbon taxes in certain jurisdictions.

| • |  | Cap and trade programs in certain jurisdictions, including the Australian Clean Energy Legislation which is scheduled to take effect July 2012.

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, some additional form of regulation may be forthcoming in the future at the federal and state levels 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:

| • |  | Whether and to what extent legislation is enacted.

| • |  | The nature of the legislation (such as a cap and trade system or a tax on emissions).

| • |  | The GHG reductions required.

| • |  | The price and availability of offsets.

| • |  | The amount and allocation of allowances.

| • |  | Technological and scientific developments leading to new products or services.

| • |  | Any potential significant physical effects of climate change (such as increased severe weather events, changes in sea levels and changes in temperature).

| • |  | Whether, and the extent to which, increased compliance costs are ultimately reflected in the prices of our products and services.

Other

We have deferred tax assets related to certain accrued liabilities, loss carryforwards and credit carryforwards. Valuation allowances have been established to reduce these deferred tax assets to an amount that will, more likely than not, be realized. Based on our historical taxable income, our expectations for the future, and available tax-planning strategies, management expects that the net deferred tax assets will be realized as offsets to reversing deferred tax liabilities and as reductions in future taxable income.

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CRITICAL ACCOUNTING ESTIMATES

The preparation of financial statements in conformity with generally accepted accounting principles requires management to select appropriate accounting policies and to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. See Note 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 there is a reasonable likelihood 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 2011, 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 $1,880 million and the accumulated impairment reserve was $487 million. The weighted-average judgmental percentage probability of ultimate failure was approximately 47 percent, and the weighted-average amortization period was approximately four years. If that judgmental percentage were to be raised by 5 percent across all calculations, pretax leasehold impairment expense in 2012 would increase by approximately $22 million. The remaining $5,966 million of gross capitalized unproved property costs at year-end 2011 consisted of individually significant leaseholds, mineral rights held in perpetuity by title ownership, exploratory wells currently drilling, suspended exploratory wells, and capitalized interest. 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 $3.0 billion is concentrated in 10 major development areas. One of these major assets totaling $97 million was moved to proved properties in 2012, and another major asset unit totaling $563 million was written off in 2012.

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.

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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 2011, total suspended well costs were $1,037 million, compared with $1,013 million at year-end 2010. 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 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 commodity prices, 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 income statement because the proved developed reserve estimate for a field serves as the denominator in the unit-of-production calculation of DD&A of the capitalized costs for that asset. At year-end 2011, the net book value of productive E&P properties, plants and

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equipment (PP&E) subject to a unit-of-production calculation was approximately $57.0 billion and the DD&A recorded on these assets in 2011 was approximately $6.6 billion. The estimated proved developed reserves for our consolidated operations were 5.2 billion BOE at the end of 2010 and 5.1 billion BOE at the end of 2011. If the estimates of proved reserves used in the unit-of-production calculations had been lower by 5 percent across all calculations, pretax DD&A in 2011 would have increased by an estimated $347 million.

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. 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 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.

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 plugging and abandonment of wells, removal and disposal of offshore oil and gas platforms around the world and oil and gas production facilities and pipelines in Alaska. The fair values of obligations for dismantling and removing these facilities are accrued into PP&E 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.

Normally, changes in asset removal obligations are reflected in the income statement as increases or decreases to DD&A over the remaining life of the assets. However, for assets at or nearing the end of their operations, as well as previously sold assets for which we retained the asset removal obligation, an increase in the asset removal obligation can result in an immediate charge to earnings, because any increase in PP&E due to the increased obligation would immediately be subject to impairment, due to the low fair value of these properties.

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In addition to asset removal obligations, under the above or similar contracts, permits and regulations, we have certain obligations to complete environmental-related projects. These projects are primarily related to 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 PP&E 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, 2011, we had $701 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.

At December 31, 2011, we had $3,332 million of goodwill on our balance sheet, all of which was attributable to the discontinued Worldwide R&M reporting unit. See Note 9—Goodwill and Intangibles and Note 26—Separation of Downstream Business, in the Notes to Consolidated Financial Statements, for additional information.

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 income statement. 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 $120 million, while a 1 percent decrease in the return on plan assets assumption would increase annual benefit expense by $50 million. In determining the discount rate, we use yields on high-quality fixed income investments matched to the estimated benefit cash flows of our plans.

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CAUTIONARY STATEMENT FOR THE PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

This report includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. You can identify our forward-looking statements by the words “anticipate,” “estimate,” “believe,” “budget,” “continue,” “could,” “intend,” “may,” “plan,” “potential,” “predict,” “seek,” “should,” “will,” “would,” “expect,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,” “effort,” “target” and similar expressions.

We based the forward-looking statements on our current expectations, estimates and projections about ourselves and the industries in which we operate in general. We caution you these statements are not guarantees of future performance as they involve assumptions that, while made in good faith, may prove to be incorrect, and involve risks and uncertainties we cannot predict. In addition, we based many of these forward-looking statements on assumptions about future events that may prove to be inaccurate. Accordingly, our actual outcomes and results may differ materially from what we have expressed or forecast in the forward-looking statements. Any differences could result from a variety of factors, including the following:

| • |  | Fluctuations in crude oil, bitumen, natural gas, LNG and natural gas liquids prices, refining and marketing margins and margins for our chemicals business.

| • |  | 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.

| • |  | Unsuccessful exploratory drilling activities or the inability to obtain access to exploratory acreage.

| • |  | Failure of new products and services to achieve market acceptance.

| • |  | Unexpected changes in costs or technical requirements for constructing, modifying or operating facilities for exploration and production, manufacturing, refining or transportation projects.

| • |  | Unexpected technological or commercial difficulties in manufacturing, refining or transporting our products, including chemicals products.

| • |  | Lack of, or disruptions in, adequate and reliable transportation for our crude oil, natural gas, natural gas liquids, bitumen, LNG and refined products.

| • |  | Inability to timely obtain or maintain permits, including those necessary for drilling and/or development projects, construction of LNG terminals or regasification facilities, or refinery projects; comply with government regulations; or make capital expenditures required to maintain compliance.

| • |  | Failure to complete definitive agreements and feasibility studies for, and to timely complete construction of, announced and future exploration and production, LNG, refinery and transportation projects.

| • |  | Potential disruption or interruption of our operations due to accidents, extraordinary weather events, civil unrest, political events, terrorism or cyber attacks.

| • |  | International monetary conditions and exchange controls.

| • |  | Substantial investment or reduced demand for products as a result of existing or future environmental rules and regulations.

| • |  | Liability for remedial actions, including removal and reclamation obligations, under environmental regulations.

| • |  | Liability resulting from litigation.

| • |  | General domestic and international economic and political developments, including armed hostilities; expropriation of assets; changes in governmental policies relating to crude oil, bitumen, natural gas, LNG, natural gas liquids or refined product pricing, regulation or taxation; other political, economic or diplomatic developments; and international monetary fluctuations.

| • |  | Changes in tax and other laws, regulations (including alternative energy mandates), or royalty rules applicable to our business.

| • |  | Limited access to capital or significantly higher cost of capital related to illiquidity or uncertainty in the domestic or international financial markets.

| • |  | Delays in, or our inability to implement, our asset disposition plan.

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| • |  | Inability to obtain economical financing for projects, construction or modification of facilities and general corporate purposes.

| • |  | The operation and financing of our joint ventures.

| • |  | The effect of restructuring or reorganization of business components.

| • |  | The effect of the separation of our downstream businesses.

| • |  | The factors generally described in Item 1A—Risk Factors in our 2011 Annual Report on Form 10-K and the additional factor described in Item 1A—Risk Factors in our Quarterly Report on Form 10-Q for the period ended September 30, 2012.

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