CONOCOPHILLIPS
Item 1A. RISK FACTORS
You should carefully consider the following risk factors in addition to the other information included in this Annual Report on Form 10-K. Each of these risk factors could adversely affect our business, operating results and financial condition, as well as adversely affect the value of an investment in our common stock.
Our operating results, our future rate of growth and the carrying value of our assets are exposed to the effects of changing commodity prices and refining margins.
Our revenues, operating results and future rate of growth are highly dependent on the prices we receive for our crude oil, natural gas, natural gas liquids and refined products. The factors influencing the prices of crude oil, natural gas, natural gas liquids and refined products are beyond our control. Lower crude oil, natural gas, natural gas liquids and refined products prices may reduce the amount of these commodities we can produce economically, which may have a material adverse effect on our revenues, operating income and cash flows.
Unless we successfully add to our existing proved reserves, our future crude oil and natural gas production will decline, resulting in an adverse impact to our business.
The rate of production from crude oil and natural gas properties generally declines as reserves are depleted. Except to the extent that we conduct successful exploration and development activities, or, through engineering studies, identify additional or secondary recovery reserves, our proved reserves will decline materially as we produce crude oil and natural gas. Accordingly, to the extent we are unsuccessful in replacing the crude oil and natural gas we produce with good prospects for future production, our business will experience reduced cash flows and results of operations.
Any material change in the factors and assumptions underlying our estimates of crude oil and natural gas reserves could impair the quantity and value of those reserves.
Our proved crude oil and natural gas reserve information included in this annual report has been derived from engineering estimates prepared or reviewed by our personnel. Any significant future price changes will have a material effect on the quantity and present value of our proved reserves. Future reserve revisions could also result from changes in, among other things, governmental regulation. Reserve estimation is a process that involves estimating volumes to be recovered from underground accumulations of crude oil and natural gas that cannot be directly measured. As a result, different petroleum engineers, each using industry-accepted geologic and engineering practices and scientific methods, may produce different estimates of reserves and future net cash flows based on the same available data. Any changes in the factors and assumptions underlying our estimates of these items could result in a material negative impact to the volume of reserves reported.
We expect to continue to incur substantial capital expenditures and operating costs as a result of our compliance with existing and future environmental laws and regulations. Likewise, future environmental laws and regulations may impact or limit our current business plans and reduce demand for our products.
Our businesses are subject to numerous laws and regulations relating to the protection of the environment. These laws and regulations continue to increase in both number and complexity and affect our operations with respect to, among other things:
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The discharge of pollutants into the environment.
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Emissions into the atmosphere (such as nitrogen oxides, sulfur dioxide and mercury emissions, and greenhouse gas emissions as they are, or may become, regulated).
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The handling, use, storage, transportation, disposal and clean up of hazardous materials and hazardous and nonhazardous wastes.
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The dismantlement, abandonment and restoration of our properties and facilities at the end of their useful lives.
We have incurred and will continue to incur substantial capital, operating and maintenance, and remediation expenditures as a result of these laws and regulations. To the extent these expenditures, as with all costs, are not ultimately reflected in the prices of our products and services, our business, financial condition, results of operations and cash flows in future periods could be materially adversely affected.
In addition, our business operations are designed and operated to accommodate expected climatic conditions. To the extent there are significant changes in the Earth’s climate, such as more severe or frequent weather conditions in the markets we serve or the areas where our assets reside, we could incur increased expenses, our operations could be materially impacted, and demand for our products could fall.
Domestic and worldwide political and economic developments could damage our operations and materially reduce our profitability and cash flows.
Actions of the U.S., state and local governments through tax and other legislation, executive order and commercial restrictions could reduce our operating profitability both in the United States and abroad. The U.S. government can prevent or restrict us from doing business in foreign countries. These restrictions and those of foreign governments have in the past limited our ability to operate in, or gain access to, opportunities in various countries. Actions by both the United States and host governments have affected operations significantly in the past, such as the expropriation of our oil assets by the Venezuelan government, and may continue to do so in the future.
Local political and economic factors in international markets could have a material adverse effect on us. Approximately 67 percent of our hydrocarbon production in 2009 was derived from production outside the United States, and 64 percent of our proved reserves, as of December 31, 2009, were located outside the United States. We are subject to risks associated with operations in international markets, including changes in foreign governmental policies relating to crude oil, natural gas, natural gas liquids or refined product pricing and taxation, other political, economic or diplomatic developments, changing political conditions and international monetary fluctuations.
Changes in governmental regulations may impose price controls and limitations on production of crude oil and natural gas.
Our operations are subject to extensive governmental regulations. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of crude oil and natural gas wells below actual production capacity in order to conserve supplies of crude oil and natural gas. Because legal requirements are frequently changed and subject to interpretation, we cannot predict the effect of these requirements.
Our investments in joint ventures decrease our ability to manage risk.
We conduct many of our operations through joint ventures in which we may share control with our joint venture participants. There is a risk that our joint venture participants may at any time have economic, business or legal interests or goals that are inconsistent with those of the joint venture or us, or that our joint venture participants may be unable to meet their economic or other obligations and we may be required to fulfill those obligations alone. Failure by us, or an entity in which we have a joint venture interest, to adequately manage the risks associated with any acquisitions or joint ventures could have a material adverse effect on the financial condition or results of operations of our joint ventures and, in turn, our business and operations.
Our operations present hazards and risks that require significant and continuous oversight.
The scope and nature of our operations present a variety of operational hazards and risks that must be managed through continual oversight and control. These risks are present throughout the process of extraction, transportation, refinement and storage of the hydrocarbons we produce. Failure to manage these risks could result in injury or loss of life, environmental damage, loss of revenues and damage to our reputation.
Item 1B. UNRESOLVED STAFF COMMENTS
None.
Item 3. LEGAL PROCEEDINGS
The following is a description of reportable legal proceedings, including those involving governmental authorities under federal, state and local laws regulating the discharge of materials into the environment for this reporting period. The following proceedings include those matters that arose during the fourth quarter of 2009, as well as matters previously reported in our 2008 Form 10-K and our first-, second- and third-quarter 2009 Form 10-Qs that were not resolved prior to the fourth quarter of 2009. Material developments to the previously reported matters have been included in the descriptions below. While it is not possible to accurately predict the final outcome of these pending proceedings, if any one or more of such proceedings was decided adversely to ConocoPhillips, we expect there would be no material effect on our consolidated financial position. Nevertheless, such proceedings are reported pursuant to the U.S. Securities and Exchange Commission’s (SEC) regulations.
Our U.S. refineries are implementing two separate consent decrees, regarding alleged violations of the Federal Clean Air Act, with the U.S. Environmental Protection Agency (EPA), six states and one local air pollution agency. Some of the requirements and limitations contained in the decrees provide for stipulated penalties for violations. Stipulated penalties under the decrees are not automatic, but must be requested by one of the agency signatories. As part of periodic reports under the decrees or other reports required by permits or regulations, we occasionally report matters that could be subject to a request for stipulated penalties. If a specific request for stipulated penalties meeting the reporting threshold set forth in SEC rules is made pursuant to these decrees based on a given reported exceedance, we will separately report that matter and the amount of the proposed penalty.
New Matters
In May 2008, the EPA issued a Compliance Order to ConocoPhillips alleging our Argenta and Sunnyside Compressor Station facilities in Colorado violated provisions of the Clean Air Act and failed to comply with several permit conditions. On February 5, 2010, we settled this matter for a payment of $175,000 and agreement to install certain emission control equipment.
In 2009, ConocoPhillips notified the EPA and the U.S. Department of Justice (DOJ) that it had self-identified certain compliance issues related to Benzene Waste Operations National Emission Standard for Hazardous Air Pollutants requirements at its Trainer, Pennsylvania, and Borger, Texas, facilities. On January 6, 2010, the DOJ provided its initial penalty demand for this matter as part of our confidential settlement negotiations. We continue to work with the DOJ to resolve this matter.
On December 17, 2009, the San Francisco Regional Water Quality Control Board’s enforcement staff (SFRWQCB) issued an Administrative Civil Liability Complaint alleging 18 exceedances of the Rodeo facility’s stormwater permit that occurred during 2008 and 2009. The Complaint seeks a penalty of $490,000. We are working with the SFRWQCB to resolve this matter.
On January 22, 2010, the Bay Area Air Quality Management District (BAAQMD) issued a settlement demand to resolve 16 Notices of Violation (NOVs) issued in 2008 and 2009 that allege violations of air pollution control regulations and/or facility permit conditions at the Rodeo facility. The amount of the settlement demand is $179,000. We are working with BAAQMD to resolve this matter.
Matters Previously Reported
ConocoPhillips Pipe Line Company (CPPL) received a Notice of Probable Violation and Proposed Civil Penalty (NOPV) from the U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (DOT) dated March 30, 2009. The NOPV alleges that CPPL violated certain operation and
safety regulations regarding the control room response to a release on January 8, 2008, near Denver City, Texas. DOT’s proposed penalty for the alleged violation is $200,000. We are working with DOT to resolve this matter.
On October 23, 2008, ConocoPhillips received a demand from the Los Angeles Regional Water Quality Control Board (LARWQCB) to settle multiple alleged exceedances of National Pollutant Discharge Elimination System permit effluent limits at its Los Angeles lubricants plant dating back to 2000. We paid a negotiated settlement of $150,000 to the LARWQCB on January 25, 2010, to resolve this matter.
In October 2003, the District Attorney’s Office in Sacramento, California, filed a complaint in Superior Court for alleged methyl tertiary-butyl ether (MTBE) contamination in groundwater. On April 4, 2008, the District Attorney’s Office filed an amended complaint that included alleged violations of state regulations relating to operation or maintenance of underground storage tanks. There are numerous defendants named in the suit in addition to ConocoPhillips. We intend to continue to contest this lawsuit.
In October 2007, we received a Complaint from the EPA alleging violations of the Clean Water Act related to a 2006 oil spill at our Bayway Refinery and proposing a penalty of $156,000. We are working with the EPA and the U.S. Coast Guard to resolve this matter.
In March 2005, CPPL received an NOPV from DOT alleging violation of DOT operation and safety regulations at certain facilities in Kansas, Missouri, Illinois, Indiana, Wyoming and Nebraska. DOT is proposing penalties in the amount of $184,500. An information hearing was held on September 24, 2007. CPPL has provided additional information in support of its position. We are currently awaiting a ruling from DOT.
In 2006, Polar Tankers, Inc. and ConocoPhillips resolved and agreed to pay, with no admission of liability, civil penalties and response costs associated with a 2004 oil spill in Puget Sound. We remain in negotiations with the natural resource trustees regarding the natural resource damage assessment to better the environment.
In April 2004, in response to several historical spills at the Albuquerque Products Terminal, we received an Administrative Compliance Order from the New Mexico Environment Department. The order does not propose a penalty assessment, but rather attempts to impose specific design, construction and operational changes. ConocoPhillips transferred its interest in the terminal, and the current owner has ceased operations. The spills have been remediated in compliance with New Mexico Environmental Department standards. ConocoPhillips has withdrawn its settlement offer and requested that this Order be dismissed.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
EXECUTIVE OFFICERS OF THE REGISTRANT
Name
Position Held
Age*
John A. Carrig
President and Chief Operating Officer
W. C. W. Chiang
Senior Vice President, Refining, Marketing and Transportation
Sigmund L. Cornelius
Senior Vice President, Finance, and Chief Financial Officer
Janet L. Kelly
Senior Vice President, Legal, General Counsel and Corporate Secretary
Ryan M. Lance
Senior Vice President, Exploration and Production - International
Kevin O. Meyers
Senior Vice President, Exploration and Production - Americas
James J. Mulva
Chairman of the Board of Directors and Chief Executive Officer
Glenda M. Schwarz
Vice President and Controller
Jeff W. Sheets
Senior Vice President, Planning and Strategy
*
On February 15, 2010.
There are no family relationships among any of the officers named above. Each officer of the company is elected by the Board of Directors at its first meeting after the Annual Meeting of Stockholders and thereafter as appropriate. Each officer of the company holds office from date of election until the first meeting of the directors held after the next Annual Meeting of Stockholders or until a successor is elected. The date of the next annual meeting is May 12, 2010. Set forth below is information about the executive officers.
John A. Carrig was appointed President and Chief Operating Officer in October 2008, having previously served as Executive Vice President, Finance, and Chief Financial Officer since the merger of Conoco and Phillips in 2002 (the merger).
W. C. W. Chiang was appointed Senior Vice President, Refining, Marketing and Transportation in October 2008. He previously served as Senior Vice President, Commercial since 2007. Prior to that, he served as President, Americas Supply & Trading, Commercial, from 2005 through 2007 and as President, Downstream Strategy, Integration and Specialty Businesses from 2003 through 2005.
Sigmund L. Cornelius was appointed Senior Vice President, Finance, and Chief Financial Officer in October 2008. Prior to that, he served as Senior Vice President, Planning, Strategy and Corporate Affairs since September 2007, having previously served as President, Exploration and Production-Lower 48 since 2006 and President, Global Gas since 2004.
Janet L. Kelly was appointed Senior Vice President, Legal, General Counsel and Corporate Secretary effective September 1, 2007, having previously served as Deputy General Counsel since 2006. Prior to joining ConocoPhillips in 2006, she was a partner at Zelle, Hoffman, Voelbel, Mason and Gette during 2005 and 2006.
Ryan M. Lance was appointed Senior Vice President, Exploration and Production - International, in May 2009. Prior to that, he served as President, Exploration and Production - Asia, Africa, Middle East and Russia/Caspian since April 2009, having previously served as President, Exploration and Production- Europe, Asia, Africa and the Middle East since September 2007. He served as Senior Vice President, Technology since February 2007, and prior to that served as Senior Vice President, Technology and Major Projects since 2006. He served as President, Downstream Strategy, Integration and Specialty Businesses since 2005.
Kevin O. Meyers was appointed Senior Vice President, Exploration and Production - Americas, in May 2009, having previously served as President, Canada, Exploration & Production, since 2006. He served as President, ConocoPhillips Russia & Caspian Region, from 2004 to 2006.
James J. Mulva has served as Chairman of the Board of Directors and Chief Executive Officer since October 2008, having previously served as Chairman of the Board of Directors, President and Chief Executive Officer since October 2004. Prior to that, he served as President and Chief Executive Officer since the merger.
Glenda M. Schwarz was appointed Vice President and Controller in April 2009. She previously served as General Auditor and Chief Ethics Officer since 2008, having previously served as General Manager, Downstream Finance and Performance Analysis since 2005, and prior to that served as Assistant Controller, External Reporting and Accounting Policy since 2004.
Jeff W. Sheets was appointed Senior Vice President, Planning and Strategy in October 2008, having previously served as Vice President and Treasurer since the merger.
PART II
Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Quarterly Common Stock Prices and Cash Dividends Per Share
ConocoPhillips’ common stock is traded on the New York Stock Exchange, under the symbol “COP.”
*
In determining the number of stockholders, we consider clearing agencies and security position listings as one stockholder for each agency or listing.
Issuer Purchases of Equity Securities
*
Represents the repurchase of common shares from company employees in connection with the company’s broad-based employee incentive plans.
Item 6. SELECTED FINANCIAL DATA
See Management’s Discussion and Analysis of Financial Condition and Results of Operations for a discussion of factors that will enhance an understanding of this data.
The financial data for 2008 includes the impact of impairments relating to goodwill and to our LUKOIL investment that together amount to $32,853 million before- and after-tax. For additional information, see the “Goodwill Impairment” section of Note 9-Goodwill and Intangibles and the “LUKOIL” section of Note 6-Investments, Loans and Long-Term Receivables, in the Notes to Consolidated Financial Statements.
The financial data for 2007 includes the impact of a $4,588 million before-tax ($4,512 million after-tax) impairment related to the expropriation of our oil interests in Venezuela. For additional information, see the “Expropriated Assets” section of Note 10-Impairments, in the Notes to Consolidated Financial Statements.
Additionally, the acquisition of Burlington Resources in 2006 affects the comparability of the amounts included in the table above.
Item 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
February 25, 2010
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 “forecast,” “intend,” “believe,” “expect,” “plan,” “schedule,” “target,” “should,” “goal,” “may,” “anticipate,” “estimate” and similar expressions identify forward-looking statements. The company does not undertake to update, revise or correct any 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 66.
The terms “earnings” and “loss” as used in Management’s Discussion and Analysis refer to net income (loss) attributable to ConocoPhillips.
BUSINESS ENVIRONMENT AND EXECUTIVE OVERVIEW
ConocoPhillips is an international, integrated energy company. We are the third-largest integrated energy company in the United States, based on market capitalization. We have approximately 30,000 employees worldwide, and at year-end 2009 had assets of $153 billion. Our stock is listed on the New York Stock Exchange under the symbol “COP.”
Our business is organized into six operating segments:
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Exploration and Production (E&P)-This segment primarily explores for, produces, transports and markets crude oil, natural gas, natural gas liquids and bitumen on a worldwide basis.
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Midstream-This segment gathers, processes and markets natural gas produced by ConocoPhillips and others, and fractionates and markets natural gas liquids, predominantly in the United States and Trinidad. The Midstream segment primarily consists of our 50 percent equity investment in DCP Midstream, LLC.
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Refining and Marketing (R&M)-This segment purchases, refines, markets and transports crude oil and petroleum products, mainly in the United States, Europe and Asia.
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LUKOIL Investment-This segment consists of our equity investment in the ordinary shares of OAO LUKOIL, an international, integrated oil and gas company headquartered in Russia. At December 31, 2009, our ownership interest was 20 percent based on issued shares and 20.09 percent based on estimated shares outstanding.
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Chemicals-This segment manufactures and markets petrochemicals and plastics on a worldwide basis. The Chemicals segment consists of our 50 percent equity investment in Chevron Phillips Chemical Company LLC (CPChem).
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Emerging Businesses-This segment represents our investment in new technologies or businesses outside our normal scope of operations.
The business environment for the energy industry in 2009 continued to experience volatility associated with the supply/demand factors that drive its commodity prices and margins. During 2008, forecasts of worldwide economic growth and increasingly scarce supply, a weakening U.S. dollar, and other factors helped drive crude oil prices to record highs by mid-year, with the benchmark West Texas Intermediate (WTI) peaking at almost $150 per barrel. This was followed by an abrupt shift into a severe global financial recession, which drove crude oil prices to the low-$30-per-barrel range by the end of 2008. As the global economy began to recover, oil prices steadily improved during 2009 and have remained fairly strong due to demand in Asia. The recovery from the recession in the United States, however, has been slower and has impacted demand for U.S. natural gas and refined products.
In response to this challenging business environment, ConocoPhillips announced several strategic initiatives in late 2009 designed to improve its financial position and increase returns on capital. This will be accomplished primarily through a combination of enhanced capital discipline and asset portfolio rationalization, consistent with our objectives of creating shareholder value and improving financial flexibility, while pursuing long-term strategic projects. Our total capital program in 2010 is expected to be $11.2 billion, down from a budgeted $12.5 billion in 2009. To improve our financial position and strengthen the balance sheet, we intend to raise approximately $10 billion from asset dispositions over the next two years. Proceeds will be targeted to debt reduction, accelerating the return to our targeted debt-to-capital ratio of 20 percent to 25 percent. After these initiatives, we intend to continue to replace reserves and increase production from a reduced, but more strategic, asset base.
Crude oil and natural gas prices, along with refining margins, are the most significant factors in our profitability, and are driven by market factors over which we have no control. As noted above, these prices and margins are subject to extreme volatility. However, from a competitive perspective, there are other important factors we must manage well to be successful, including:
•
Operating our producing properties and refining and marketing operations safely, consistently and in an environmentally sound manner. Safety is our first priority, and we are committed to protecting the health and safety of everyone who has a role in our operations and the communities in which we operate. Optimizing utilization rates at our refineries and minimizing downtime in producing fields enable us to capture the value available in the market in terms of prices and margins. During 2009, our worldwide refining capacity utilization rate was 84 percent, compared with 90 percent in 2008. The lower rate primarily reflects reduced throughput at our U.S. and German refineries due to economic conditions, as well as higher planned downtime, efficiently utilizing periods of lower margins for maintenance. Although certain North America production was shut-in during part of 2009 due to the natural gas pricing environment, we increased total production on a barrel-of-oil-equivalent basis in 2009 by 2 percent. Finally, we strive to conduct our operations in a manner consistent with our environmental stewardship principles.
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Adding to our proved reserve base. We primarily add to our proved reserve base in three ways:
o
Successful exploration and development of new fields.
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Acquisition of existing fields.
o
Application of new technologies and processes to improve recovery from existing fields.
Through a combination of the methods listed above, we have been successful in the past in maintaining or adding to our production and proved reserve base, and we anticipate being able to do so in the future. In the five years ending December 31, 2009, our reserve replacement was 145 percent. Over this period we added reserves through acquisitions and project developments, partially offset by the impact of asset expropriations in Venezuela and Ecuador.
Access to additional resources has become increasingly difficult as direct investment is prohibited in some nations, while fiscal and other terms in other countries can make projects uneconomic or unattractive. In addition, political instability, competition from national oil companies, and lack of access to high-potential areas due to environmental or other regulation may negatively impact our ability to increase our reserve base. As such, the timing and level at which we add to our reserve base may, or may not, allow us to replace our production over subsequent years.
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Controlling costs and expenses. Since we cannot control the prices of the commodity products we sell, controlling operating and overhead costs, within the context of our commitment to safety and environmental stewardship, are high priorities. We monitor these costs using various methodologies that are reported to senior management monthly, on both an absolute-dollar basis and a per-unit basis. Because managing operating and overhead costs is critical to maintaining competitive positions in our industries, cost control is a component of our variable compensation programs. Operating and overhead costs were reduced 13 percent in 2009, compared with 2008, reflecting both market conditions and our continued emphasis on cost control throughout the year.
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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 continue to maintain and improve our refinery complexes. We invest in projects that are expected to provide an adequate financial return on invested dollars. However, there are often long lead times from the time we make an investment to the time that investment is operational and begins generating financial returns.
The capital expenditures and investments portion of our capital program totaled $10.9 billion in 2009, and we anticipate capital expenditures and investments to be approximately $10.5 billion in 2010. The 2010 budget is consistent with our recently announced plan to improve returns through increased capital discipline, while still funding existing projects and enabling us to preserve flexibility to develop major projects in the future. In addition to our capital program, we paid dividends on our common stock of $2.8 billion in 2009.
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Managing our asset portfolio. We continually evaluate our assets to determine whether they no longer fit our strategic plans and should be sold or otherwise disposed. In 2008, we sold our retail marketing assets in Norway, Sweden and Denmark, in addition to our E&P properties in Argentina and the Netherlands. In 2009, we sold a majority of our U.S. retail marketing assets. Also in 2009, we announced our intention to raise approximately $10 billion from asset dispositions over the next two years.
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Developing and retaining a talented work force. We strive to attract, train, develop and retain individuals with the knowledge and skills to implement our business strategy and who support our values and ethics. Throughout the company, we focus on the continued learning, development and technical training of our employees. Professional new hires participate in structured development programs designed to accelerate their technical and functional skills.
Our key performance indicators are shown in the statistical tables provided at the beginning of the operating segment sections that follow. These include crude oil and natural gas liquids prices, natural gas prices, production, refining capacity utilization, and refinery output.
Other significant factors that can affect our profitability include:
•
Impairments. As mentioned above, we participate in capital-intensive industries. At times, our investments become impaired when our reserve estimates are revised downward, when crude oil prices, natural gas prices or refining margins decline significantly for long periods of time, or when a decision to dispose of an asset leads to a write-down to its fair market value. We may also invest large amounts of money in exploration blocks which, if exploratory drilling proves unsuccessful, could lead to a material impairment of leasehold values. Before-tax impairments in 2009 totaled $0.8 billion and primarily related to certain natural gas properties in western Canada and our equity investment in Naraynmarneftegaz (NMNG). Before-tax impairments in 2008, excluding the goodwill impairment discussed below and a $7.4 billion impairment related to our LUKOIL investment, totaled $1.7 billion.
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Goodwill. At year-end 2009 and 2008, we had $3.6 billion and $3.8 billion, respectively, of goodwill on our balance sheet, compared with $29.3 billion at year-end 2007. In 2008, we recorded a $25.4 billion complete impairment of our E&P segment goodwill, primarily as a function of decreased year-end commodity prices and the decline in our market capitalization. For additional information, see Note 9-Goodwill and Intangibles, in the Notes to Consolidated Financial Statements. Deterioration of market conditions in the future could lead to other goodwill impairments that may have a substantial negative, though noncash, effect on our profitability.
•
Effective tax rate. Our operations are located in countries with different tax rates and fiscal structures. Accordingly, even in a stable commodity price and fiscal/regulatory environment, our overall effective tax rate can vary significantly between periods based on the “mix” of pretax earnings within our global operations.
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Fiscal and regulatory environment. As commodity prices and refining margins fluctuated upward over the last several years, certain governments responded with changes to their fiscal take. These changes have generally negatively impacted our results of operations, and further changes to government fiscal take could have a negative impact on future operations. In June 2007, our Venezuelan oil projects were expropriated, and we recorded a $4.5 billion after-tax impairment. In the second quarter of 2009, our assets in Ecuador were effectively expropriated, and we recorded a $51 million before- and after-tax impairment (see the “Expropriated Assets” section of Note 10-Impairments, in the Notes to Consolidated Financial Statements). We were also negatively impacted by increased production taxes enacted by the state of Alaska in the fourth quarter of 2007. In Canada, the Alberta provincial government changed the royalty structure for Crown lands, effective January 1, 2009, so that a component of the new royalty rate is tied to prevailing prices. In October 2008, we and our co-venturers signed definitive agreements for the proportional dilution of our equity interests in the Republic of Kazakhstan’s North Caspian Sea Production Sharing Agreement, which includes the Kashagan Field, to allow the state-owned energy company to increase its ownership percentage effective January 1, 2008. Partially offsetting the above fiscal take increases were lower corporate income tax rates enacted by Canada and Germany during 2007. These tax rate reductions applied to all corporations and were not exclusive to the oil and gas industry.
Segment Analysis
The E&P segment’s results are most closely linked to crude oil and natural gas prices. These are commodity products, the prices of which are subject to factors external to our company and over which we have no control. Industry crude oil prices for West Texas Intermediate were lower in 2009, compared with 2008, averaging $61.69 per barrel in 2009, a decrease of 38 percent. Crude oil prices steadily trended upward during 2009, as global crude inventories were reduced due to lower production and economic recovery that stimulated the resumption of global oil demand growth. Industry natural gas prices for Henry Hub decreased 56 percent during 2009 to an average price of $3.99 per million British thermal units, primarily as a result of lower demand due to the U.S. recession and higher domestic production due to increased shale gas production.
The Midstream segment’s results are most closely linked to natural gas liquids prices. The most important factor affecting the profitability of this segment is the results from our 50 percent equity investment in DCP Midstream. DCP Midstream’s natural gas liquids prices decreased 43 percent in 2009.
Refining margins, refinery utilization, cost control and marketing margins primarily drive the R&M segment’s results. Refining margins are subject to movements in the cost of crude oil and other feedstocks, and the sales prices for refined products, both of which are subject to market factors over which we have no control. Global refining margins remained weak in 2009. The U.S. benchmark 3:2:1 crack spread decreased almost 20 percent in 2009, while the N.W. Europe benchmark declined 54 percent. Demand, particularly for distillates, continued to be suppressed by the global economic slowdown. In addition, the compressed differential in prices for high-quality crude oil, compared with those of lower-quality crude oil, reduced margins for those refineries configured to capitalize on the ability to process lower-quality crudes.
The LUKOIL Investment segment consists of our investment in the ordinary shares of LUKOIL. At December 31, 2009, our ownership interest in LUKOIL was 20 percent based on issued shares and 20.09 percent based on estimated shares outstanding. LUKOIL’s results are subject to factors similar to those of our E&P and R&M segments. LUKOIL’s upstream results are closely linked to Russian (Urals) crude oil prices and are heavily impacted by extraction tax rates. Refining margins are significant factors on LUKOIL’s downstream results. Export tariff rates for crude oil and refined products also have a significant impact on both upstream and downstream results.
The Chemicals segment consists of our 50 percent interest in CPChem. The chemicals and plastics industry is mainly a commodity-based industry where the margins for key products are based on market factors over which CPChem has little or no control. CPChem is investing in feedstock-advantaged areas in the Middle East with access to large, growing markets, such as Asia.
The Emerging Businesses segment represents our investment in new technologies or businesses outside our normal scope of operations. Activities within this segment are currently focused on power generation and innovation of new technologies, such as those related to conventional and nonconventional hydrocarbon recovery (including heavy oil), refining, alternative energy, biofuels and the environment. Some of these technologies have the potential to become important drivers of profitability in future years.
RESULTS OF OPERATIONS
Consolidated Results
A summary of the company’s net income (loss) attributable to ConocoPhillips by business segment follows:
2009 vs. 2008
The improved results in 2009 were primarily the result of:
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The absence of a $25,443 million before- and after-tax impairment of all E&P segment goodwill in 2008.
•
The absence of a $7,410 million before- and after-tax impairment of our LUKOIL investment in 2008.
•
Lower production taxes.
•
Reduced operating and overhead expenses.
These items were partially offset by:
•
Lower crude oil, natural gas and natural gas liquids prices, which impacted our E&P, Midstream and LUKOIL Investment segments.
•
Lower refining margins in our R&M segment.
2008 vs. 2007
The lower results in 2008 were primarily the result of:
•
The goodwill and LUKOIL impairments, noted above.
•
Lower U.S. refining margins in our R&M segment.
•
An increase in other asset impairments, predominantly in our E&P and R&M segments.
These items were partially offset by:
•
Higher crude oil, natural gas and natural gas liquids prices, which benefitted our E&P, Midstream and LUKOIL Investment segments. Commodity price benefits were somewhat counteracted by increased production taxes.
•
A 2007 complete impairment ($4,588 million before-tax, $4,512 million after-tax) of our oil interests in Venezuela, resulting from their expropriation.
Statement of Operations Analysis
2009 vs. 2008
Sales and other operating revenues decreased 38 percent in 2009, while purchased crude oil, natural gas and products decreased 39 percent. These decreases were mainly the result of significantly lower prices for petroleum products, crude oil, natural gas and natural gas liquids.
Equity in earnings of affiliates decreased 30 percent in 2009, primarily due to reduced earnings from DCP Midstream; LUKOIL; Merey Sweeny, L.P. (MSLP); Malaysian Refining Company Sdn. Bhd.; and Excel Paralubes, which were partially offset by higher earnings from Chevron Phillips Chemical Company LLC. The decreases were mainly the result of lower commodity prices and refining margins.
Other income decreased 52 percent during 2009. The decrease was primarily due to 2008 gains related to asset dispositions in our E&P and R&M segments.
Production and operating expenses decreased 13 percent in 2009, as a result of lower utilities costs, favorable foreign exchange impacts, and our cost reduction efforts.
Selling, general and administrative expense decreased 18 percent in 2009, primarily due to disposition of U.S. and international marketing assets.
Taxes other than income taxes decreased 25 percent in 2009, primarily due to lower production taxes resulting from lower crude oil prices, as well as reduced excise taxes on petroleum product sales.
Impairments decreased from $34,539 million in 2008 to $535 million in 2009, primarily reflecting the 2008 goodwill and LUKOIL impairments. Other impairments decreased $1,202 million during 2009. For additional information, see Note 6-Investments, Loans and Long-Term Receivables, Note 9-Goodwill and Intangibles, and Note 10-Impairments, in the Notes to Consolidated Financial Statements.
Interest and debt expense increased 38 percent in 2009, as a result of a higher average debt level, partially offset by lower interest rates. Interest expense also increased as a result of lower capitalized interest.
See Note 20-Income Taxes, in the Notes to Consolidated Financial Statements, for information regarding our income tax expense and effective tax rate.
2008 vs. 2007
Sales and other operating revenues increased 28 percent in 2008, while purchased crude oil, natural gas and products increased 37 percent. These increases were the result of higher petroleum product prices and higher prices for crude oil, natural gas and natural gas liquids.
Equity in earnings of affiliates decreased 16 percent in 2008, reflecting:
•
Lower results from WRB Refining LLC, due to lower margins and a decline in equity ownership in accordance with the designed formation of the venture.
•
Lower results from CPChem, due to higher operating costs, lower specialties, aromatics and styrenics margins, and lower olefins and polyolefins volumes.
•
The absence of earnings from our heavy oil joint ventures expropriated by Venezuela in 2007.
•
Increased losses related to our NMNG joint venture as a result of higher production taxes and increased depreciation, depletion and amortization (DD&A) costs during the startup and early production phase of the Yuzhno Khylchuyu (YK) Field.
These negative results were somewhat offset by improved results from the FCCL Partnership, DCP Midstream, LUKOIL (excluding the investment impairment), and CFJ Properties.
Other income decreased 45 percent during 2008, mainly due to a lower net benefit from asset rationalization efforts, the release in 2007 of escrowed funds associated with our Hamaca joint venture in Venezuela, and the settlement of retroactive adjustments for crude oil quality differentials on Trans-Alaska Pipeline System shipments (Quality Bank) in 2007.
Exploration expenses increased 33 percent during 2008, reflecting increased dry hole costs and higher expenses for post-discovery feasibility and development planning studies.
Impairments increased from $5,030 million in 2007 to $34,539 million in 2008. This increase primarily reflects the 2008 goodwill and LUKOIL impairments, partially offset by a 2007 impairment of $4,588 million related to the expropriation of our oil interests in Venezuela.
Interest and debt expense decreased 25 percent in 2008, primarily due to lower average interest rates, as well as the absence of 2007 interest expense related to the Alaska Quality Bank settlements.
Foreign currency transaction losses incurred during 2008 totaled $117 million, compared with foreign currency transaction gains of $201 million in 2007. This change occurred as the Canadian dollar, Russian rouble, British pound, and euro all weakened against the U.S. dollar during 2008, compared with the strengthening of these currencies against the U.S. dollar in 2007.
See Note 20-Income Taxes, in the Notes to Consolidated Financial Statements, for information regarding our income tax expense and effective tax rate.
Segment Results
E&P
*
Amounts in 2008 and 2007 were adjusted for certain production cost reclassifications.
*
Represents quantities available for sale. Excludes gas equivalent of natural gas liquids included above.
Equity affiliate statistics exclude our share of LUKOIL, which is reported in the LUKOIL Investment segment.
The E&P segment primarily explores for, produces, transports and markets crude oil, natural gas, natural gas liquids and bitumen on a worldwide basis. At December 31, 2009, our E&P operations were producing in the United States, Norway, the United Kingdom, Canada, Australia, offshore Timor-Leste in the Timor Sea, Indonesia, China, Vietnam, Libya, Nigeria, Algeria and Russia.
2009 vs. 2008
The E&P segment had earnings of $3,604 million during 2009. In 2008, the E&P segment had a loss of $13,479 million, which included a $25,443 million before- and after-tax complete impairment of E&P segment goodwill. For additional information, see the “Goodwill Impairment” section of Note 9-Goodwill and Intangibles, in the Notes to Consolidated Financial Statements, which is incorporated herein by reference.
Excluding the impact from the goodwill impairment, earnings from the E&P segment decreased 70 percent during 2009, primarily due to substantially lower crude oil, natural gas and natural gas liquids prices. Our E&P segment also recognized property impairment charges. These decreases were partially offset by lower Alaska and Lower 48 production taxes due to lower prices, as well as higher international volumes and improved operating costs. See the “Business Environment and Executive Overview” section for additional information on industry crude oil and natural gas prices.
Proved reserves at year-end 2009 were 8.36 billion barrels of oil equivalent (BOE), compared with 8.08 billion at year-end 2008. This excludes the estimated 1,967 million BOE and 1,893 million BOE included in the LUKOIL Investment segment at year-end 2009 and 2008, respectively. Also excluded for 2008 is our share of Canadian Syncrude reserves of 249 million barrels.
U.S. E&P
Earnings from our U.S. E&P operations decreased 70 percent, due to significantly lower crude oil, natural gas and natural gas liquids prices. Lower production taxes, lower property impairments in the Lower 48 and improved operating costs partially offset the decrease.
U.S. E&P production averaged 755,000 BOE per day in 2009, a decrease of 3 percent from 775,000 in 2008. Less unplanned downtime and improved well performance were more than offset by field decline.
International E&P
Earnings from our international E&P operations were $2,101 million in 2009, compared with $6,976 million in 2008. The decline was primarily a result of significantly lower crude oil, natural gas and natural gas liquids prices and higher impairments. These decreases were partially offset by higher volumes and lower operating costs.
International E&P production averaged 1,099,000 BOE per day in 2009, an increase of 8 percent from 1,014,000 in 2008. The increase was predominantly due to new production in the United Kingdom, Russia, China, Canada, Norway and Vietnam. In addition, production increased due to the impacts from the royalty framework in Alberta, Canada, as well as less unplanned downtime and the impact of lower prices on production sharing arrangements. These increases were partially offset by field decline and more planned downtime.
2008 vs. 2007
The E&P segment recorded a loss of $13,479 million during 2008. This amount included a $25,443 million before- and after-tax complete impairment of E&P segment goodwill. In 2007, the E&P segment had earnings of $4,615 million, which included the impact of a $4,588 million before-tax impairment ($4,512 million after-tax) related to the expropriation of our oil interests in Venezuela. For additional information, see the “Goodwill Impairment” section of Note 9-Goodwill and Intangibles, and the “Expropriated Assets” section of Note 10-Impairments, in the Notes to Consolidated Financial Statements, which are incorporated herein by reference.
The decrease in earnings resulted from the goodwill impairment, higher taxes other than income (mainly in Alaska), lower production volumes, higher operating and exploration costs, increased property impairments and depreciation expense, and the absence of a 2007 benefit related to release of escrowed funds associated with our Hamaca joint venture in Venezuela. The decrease was partially offset by the absence of the 2007 Venezuela impairment, as well as higher crude oil, natural gas and natural gas liquids prices. During 2008, our E&P segment recognized property impairment charges totaling $511 million after-tax, mostly due to revised capital spending plans as a result of current project economics, as well as a significantly diminished outlook for commodity prices. A large portion of these impairments relate to fields in the U.S. Lower 48 and Canada.
U.S. E&P
Earnings from our U.S. E&P operations increased 17 percent, primarily due to higher crude oil, natural gas and natural gas liquids prices. The increase was partially offset by higher production taxes (mainly in Alaska), lower volumes, an increase in impairments of properties in the Lower 48, and higher operating costs.
E&P production on a BOE basis averaged 775,000 per day in 2008, a decrease of 8 percent from 843,000 in 2007. The production decrease was primarily attributable to field decline and unplanned downtime in the Lower 48 due to hurricane disruptions.
International E&P
Earnings from our international E&P operations increased from $367 million in 2007 to $6,976 million in 2008. The increase was attributed to the impact of the Venezuelan impairment on our prior-year results and higher crude oil, natural gas and natural gas liquids prices. The increase was partially offset by higher depreciation expense due to increased rates and new assets being placed in service, increased taxes other than income, higher operating costs, and the absence of a 2007 benefit related to release of escrowed funds associated with our Hamaca joint venture in Venezuela.
International E&P production averaged 1,014,000 BOE per day in 2008, a decrease of 2 percent from 1,037,000 in 2007. Decreases in production were caused by field decline and the expropriation of our Venezuelan oil interests. These decreases were mostly offset by increased production from new developments in the United Kingdom, Indonesia, Russia, Norway and Canada.
Midstream
Millions of Dollars
Net Income Attributable to ConocoPhillips*
$
* Includes DCP Midstream-related earnings:
$
*
Based on index prices from the Mont Belvieu and Conway market hubs that are weighted by natural gas liquids component and location mix.
*
Includes our share of equity affiliates, except LUKOIL, which is included in the LUKOIL Investment segment.
**
Excludes DCP Midstream.
The Midstream segment purchases raw natural gas from producers and gathers natural gas through an extensive network of pipeline gathering systems. The natural gas is then processed to extract natural gas liquids from the raw gas stream. The remaining “residue” gas is marketed to electrical utilities, industrial users, and gas marketing companies. Most of the natural gas liquids are fractionated-separated into individual components like ethane, butane and propane-and marketed as chemical feedstock, fuel or blendstock. The Midstream segment consists of our 50 percent equity investment in DCP Midstream, as well as our other natural gas gathering and processing operations, and natural gas liquids fractionation and marketing businesses, primarily in the United States and Trinidad.
2009 vs. 2008
Earnings from the Midstream segment decreased 42 percent in 2009. The decrease was primarily due to substantially lower realized natural gas liquids prices, partially offset by the recognition of an $88 million after-tax benefit in the first quarter of 2009 resulting from a DCP Midstream subsidiary converting subordinated units to common units.
2008 vs. 2007
Earnings from the Midstream segment increased 19 percent in 2008. The increase was primarily due to higher realized natural gas liquids prices, partially offset by higher operating costs and higher depreciation expense.
R&M
*
Excludes excise taxes.
*
Includes our share of equity affiliates, except LUKOIL, which is included in the LUKOIL Investment segment.
**
Weighted-average crude oil capacity for the periods. Actual capacity at year-end 2007 was 2,037,000 barrels per day for our domestic refineries and 669,000 barrels per day for our international refineries.
The R&M segment’s operations encompass refining crude oil and other feedstocks into petroleum products (such as gasoline, distillates and aviation fuels); buying, selling and transporting crude oil; and buying, transporting, distributing and marketing petroleum products. R&M has operations mainly in the United States, Europe and the Asia Pacific Region.
2009 vs. 2008
R&M reported earnings of $37 million in 2009, compared with $2,322 million in 2008. The decrease was primarily a result of significantly lower U.S. and international refining margins, lower volumes, lower international marketing margins and a lower net benefit from asset rationalization efforts. These decreases were partially offset by lower operating expenses, lower property impairments and positive foreign currency exchange impacts. During 2008, our R&M segment had property impairments totaling $511 million after-tax, mostly due to a significantly diminished outlook for refining margins.
During 2009, our worldwide refining capacity utilization rate was 84 percent, compared with 90 percent in 2008.
U.S. R&M
Our U.S. R&M operations reported a loss of $192 million in 2009, compared with earnings of $1,540 million in 2008. The decrease was primarily due to significantly lower U.S. refining margins, lower U.S. refining and marketing volumes and a lower net benefit from asset sales. These decreases were partially offset by lower operating expenses and lower property impairments.
Our U.S. refining capacity utilization rate was 87 percent in 2009, compared with 92 percent in 2008. The current-year rate was mainly affected by run reductions due to market conditions and increased turnaround activity, while the prior-year rate was impacted by downtime associated with hurricanes.
International R&M
International R&M reported earnings of $229 million in 2009 and earnings of $782 million in 2008. The decrease in earnings was primarily due to significantly lower international refining and marketing margins, lower international marketing volumes and a lower net benefit from asset sales. These decreases were partially offset by positive foreign currency impacts, lower property impairments and lower operating expenses.
Our international refining capacity utilization rate was 74 percent in 2009, compared with 85 percent in 2008. The current-year rate reflects higher turnaround activity. In addition, the utilization rate for both periods reflects run reductions in response to market conditions.
2008 vs. 2007
R&M earnings decreased 61 percent in 2008. The results were lower due to decreases in U.S. refining margins and volumes, increased property impairments, higher operating costs, a reduced benefit from asset rationalization efforts, and lower international marketing and refining volumes due to asset sales. These R&M decreases were partially offset by higher international marketing margins.
During 2008, our worldwide refining capacity utilization rate was 90 percent, compared with 94 percent in 2007.
U.S. R&M
Earnings from our U.S. R&M operations decreased 67 percent in 2008. Results for 2008 also included an impairment related to one of our U.S. refineries.
Our U.S. refining capacity utilization rate was 92 percent in 2008, compared with 96 percent in 2007. The decline in the 2008 rate resulted mainly from refinery optimization and unplanned downtime, which included the impact of hurricanes on our U.S. Gulf Coast refineries.
International R&M
Earnings from our international R&M operations decreased 40 percent in 2008. Contributing to the decrease was the impairment of a refinery in Europe and the absence of a $141 million 2007 German tax legislation benefit.
Our international refining capacity utilization rate was 85 percent in 2008, compared with 90 percent during the previous year. The utilization rate was primarily impacted by reduced crude throughput at our Wilhelmshaven Refinery due to economic conditions and planned maintenance.
LUKOIL Investment
*
Represents our net share of our estimate of LUKOIL’s production and processing.
This segment represents our investment in the ordinary shares of LUKOIL, an international, integrated oil and gas company headquartered in Russia, which we account for under the equity method. At December 31, 2009, our ownership interest in LUKOIL was 20 percent based on authorized and issued shares. Our ownership interest based on estimated shares outstanding, used for equity method accounting, was 20.09 percent at that date.
Because LUKOIL’s accounting cycle close and preparation of U.S. generally accepted accounting principles financial statements occur subsequent to our reporting deadline, our equity earnings and statistics for our LUKOIL investment are estimated based on current market indicators, publicly available LUKOIL information, and other objective data. Once the difference between actual and estimated results is known, an adjustment is recorded. This estimate-to-actual adjustment will be a recurring component of future-period results. In addition to our estimated equity share of LUKOIL’s earnings, this segment reflects the amortization of the basis difference between our equity interest in the net assets of LUKOIL and the book value of our investment. The segment also includes the costs associated with our employees seconded to LUKOIL.
2009 vs. 2008
The LUKOIL Investment segment had earnings of $1,663 million during 2009, compared with a loss of $5,488 million in 2008. Results for 2008 included a $7,410 million noncash, before- and after-tax impairment of our LUKOIL investment taken during the fourth quarter. For additional information, see the “LUKOIL” section of Note 6-Investments, Loans and Long-Term Receivables, in the Notes to Consolidated Financial Statements, which is incorporated herein by reference.
Excluding the impact of the impairment, earnings from the LUKOIL Investment segment decreased 13 percent in 2009. The decrease was primarily due to lower estimated realized refined product and crude oil prices, which was mostly offset by lower estimated extraction taxes and export tariff rates, and a benefit from basis difference amortization.
2008 vs. 2007
The LUKOIL Investment segment had a $5,488 million loss in 2008, compared with $1,818 million of earnings in 2007. Excluding the impact of the impairment, earnings from the LUKOIL Investment segment increased 6 percent in 2008. This increase was primarily due to higher estimated realized prices of both refined product and crude oil sales. Partially offsetting these positive impacts were higher estimated extraction taxes and higher estimated crude and refined product export tariff rates, as well as higher estimated operating costs and lower estimated crude volumes.
Chemicals
Millions of Dollars
Net Income Attributable to ConocoPhillips
$
The Chemicals segment consists of our 50 percent interest in Chevron Phillips Chemical Company LLC (CPChem), which we account for under the equity method. CPChem uses natural gas liquids and other feedstocks to produce petrochemicals. These products are then marketed and sold, or used as feedstocks, to produce plastics and commodity chemicals.
2009 vs. 2008
Earnings from the Chemicals segment increased $138 million in 2009 due to lower operating costs and higher margins in the specialties, aromatics and styrenics business line. These increases were partially offset by lower margins in the olefins and polyolefins business line.
2008 vs. 2007
Earnings from the Chemicals segment decreased by $249 million in 2008 due to higher utilities and other operating costs, the absence of 2007 one-time tax benefits, lower margins in the specialties, aromatics and styrenics business line, and lower volumes from the olefins and polyolefins business line. Increases in olefins and polyolefins margins somewhat offset these negative effects.
Emerging Businesses
The Emerging Businesses segment represents our investment in new technologies or businesses outside our normal scope of operations. Activities within this segment are currently focused on power generation and innovation of new technologies, such as those related to conventional and nonconventional hydrocarbon recovery (including heavy oil), refining, alternative energy, biofuels, and the environment.
2009 vs. 2008
Emerging Businesses reported earnings of $3 million in 2009, compared with $30 million in 2008. The decrease was primarily due to lower international power results and higher technology development expenses, which were mostly offset by the absence of an $85 million after-tax impairment of a U.S. cogeneration power plant in 2008.
2008 vs. 2007
Emerging Businesses reported earnings of $30 million in 2008, compared with a loss of $8 million in 2007. The increase primarily reflects improved international power generation results, including the impact of higher spark spreads. These benefits were partially offset by an $85 million after-tax impairment of a U.S. cogeneration power plant, as well as by lower domestic power results.
Corporate and Other
2009 vs. 2008
Net interest consists of interest and financing expense, net of interest income and capitalized interest, as well as premiums incurred on the early retirement of debt. Net interest increased 53 percent in 2009 as a result of higher average debt levels, partially offset by lower average interest rates. Capitalized interest was also lower in 2009. Corporate general and administrative expenses decreased 47 percent due to decreased costs related to compensation plans and overhead. 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 are primarily due to higher foreign currency transaction gains.
2008 vs. 2007
Net interest decreased 32 percent in 2008, primarily due to lower average interest rates and a higher effective tax rate. Corporate general and administrative expenses increased 15 percent in 2008, mainly as a result of increased charitable contributions. Acquisition-related costs in 2007 included transition costs associated with the Burlington Resources acquisition. “Other” expenses increased in 2008 due to various tax-related adjustments, partially offset by lower foreign currency losses.
CAPITAL RESOURCES AND LIQUIDITY
Financial Indicators
*
Total debt includes short-term and long-term debt, as shown on our consolidated balance sheet.
**
Capital includes total debt and total equity.
To meet our short- and long-term liquidity requirements, we look to a variety of funding sources. Cash generated from operating activities is the primary source of funding. In addition, during 2009 $1,229 million of net debt was issued, and we received $1,270 million in proceeds from asset sales. During 2009, available cash was used to support our ongoing capital expenditures and investments program, pay dividends, and meet the funding requirements to FCCL Partnership. Total dividends paid on our common stock during the year were $2,832 million. During 2009, cash and cash equivalents decreased by $213 million to $542 million.
In addition to cash flows from operating activities and proceeds from asset sales, we rely on our commercial paper and credit facility programs and our shelf registration statement to support our short- and long-term liquidity requirements. The credit markets, including the commercial paper markets in the United States, have experienced adverse conditions during 2008 and 2009. Although we have not been materially impacted by these conditions, continuing volatility in the credit markets may increase costs associated with issuing commercial paper or other debt instruments due to increased spreads over relevant interest rate benchmarks. Such volatility may also affect our ability, the ability of our joint ventures and equity affiliates, and the ability of third parties with whom we seek to do business, to access those credit markets. Notwithstanding these adverse market conditions, we believe current cash and short-term investment balances and cash generated by operations, together with access to external sources of funds as described below in the “Significant Sources of Capital” section, will be sufficient to meet our funding requirements in the near and long term, including our capital spending program, dividend payments, required debt payments and the funding requirements to FCCL.
Significant Sources of Capital
Operating Activities
During 2009, cash of $12,479 million was provided by operating activities, a 45 percent decrease from cash from operations of $22,658 million in 2008. The decline was primarily due to significantly lower commodity prices in our E&P segment and lower refining margins in our R&M segment.
During 2008, cash flow from operations decreased $1,892 million, compared with 2007. Contributing to the decrease were lower U.S. refining margins and volumetric inventory builds in our R&M segment in 2008, versus reductions in 2007. These factors were partially offset by higher commodity prices in our E&P segment.
While the stability of our cash flows from operating activities benefits from geographic diversity and the effects of upstream and downstream integration, our short- and long-term operating cash flows are highly dependent upon prices for crude oil, natural gas and natural gas liquids, as well as refining and marketing margins. During 2008 and 2007, we benefited from favorable crude oil and natural gas prices, although these prices deteriorated significantly in the fourth quarter of 2008. Crude oil and natural gas prices generally trended higher during 2009. Refining margins deteriorated significantly in the fourth quarter of 2008 and
remained low throughout 2009. Prices and margins in our industry are typically volatile, and are driven by market conditions over which we have no control. Absent other mitigating factors, as these prices and margins fluctuate, we would expect a corresponding change in our operating cash flows.
The level of our production volumes of crude oil, 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 2009, including our share of production from equity affiliates, averaged 2.29 million BOE per day. Future production is subject to numerous uncertainties, including, among others, the volatile crude oil and natural gas price environment, which may impact project investment decisions; the effects of price changes on production sharing and variable-royalty contracts; timing of project startups and major turnarounds; and weather-related disruptions. Our production in 2010, including the impact of anticipated dispositions, is expected to be in the range of 2.2 million BOE per day, similar to 2008 production levels. We continue to evaluate various properties as potential candidates for our recently announced disposition program. The makeup and timing of our disposition program will also impact 2010 and future years’ production levels.
To maintain or grow our production volumes, we must continue to add to our proved reserve base. Our reserve replacement in 2009 was 141 percent, including 133 percent from consolidated operations. The
U.S. Securities and Exchange Commission (SEC) adopted new reserves reporting rules effective in 2009, which allowed us to include Syncrude oil sands mining operations in our proved reserves. Excluding the impact of the addition of Syncrude, we replaced 112 percent of total production in 2009, reflecting progress on major projects, including the sanctioning of additional phases of in-situ oil sands projects in Canada, as well as reserve additions from our LUKOIL Investment segment. Over the five-year period ending December 31, 2009, our reserve replacement was 145 percent, including 120 percent from consolidated operations. Over this period we added reserves through acquisitions and project developments, partially offset by the impact of asset expropriations in Venezuela and Ecuador. The reserve replacement amounts above were based on the sum of our net additions (revisions, improved recovery, purchases, extensions and discoveries, and sales) divided by our production, as shown in our reserve table disclosures. For additional information about our proved reserves, including both developed and undeveloped reserves, see the “Oil and Gas Operations” section of this report.
We are developing and pursuing projects we anticipate will allow us to add to our reserve base. However, access to additional resources has become increasingly difficult as direct investment is prohibited in some nations, while fiscal and other terms in other countries can make projects uneconomic or unattractive. In addition, political instability, competition from national oil companies, and lack of access to high-potential areas due to environmental or other regulation may negatively impact our ability to increase our reserve base. As such, the timing and level at which we add to our reserve base may, or may not, allow us to replace our production over subsequent years.
As discussed in the “Critical Accounting Estimates” section, engineering estimates of proved reserves are imprecise, and therefore, each year reserves may be revised upward or downward due to the impact of changes in oil and gas prices or as more technical data becomes available on reservoirs. In 2009 and 2007, revisions increased reserves, while in 2008 revisions decreased reserves. It is not possible to reliably predict how revisions will impact reserve quantities in the future.
In addition, the level and quality of output from our refineries impacts our cash flows. The output at our refineries is impacted by such factors as operating efficiency, maintenance turnarounds, market conditions, feedstock availability and weather conditions. We actively manage the operations of our refineries, and, typically, any variability in their operations has not been as significant to cash flows as that caused by refining margins.
Asset Sales
Proceeds from asset sales in 2009 were $1,270 million, compared with $1,640 million in 2008. In 2009, we closed on the sale of our ownership interest in the Keystone Pipeline and a large part of our U.S. retail marketing assets, which included seller financing in the form of a $370 million five-year note and letters of credit totaling $54 million.
We plan to raise approximately $10 billion from asset dispositions over the next two years. We will continue to identify the assets and begin marketing efforts over the near term, with disposition candidates across the company’s operations being considered. Proceeds will be targeted toward debt reduction.
Commercial Paper and Credit Facilities
At December 31, 2009, we had two revolving credit facilities totaling $7.85 billion, consisting of a $7.35 billion facility expiring in September 2012 and a $500 million facility expiring in July 2012. Our revolving credit facilities may be used as direct bank borrowings, as support for issuances of letters of credit totaling up to $750 million, or as support for our commercial paper programs. The revolving credit facilities are broadly syndicated among financial institutions and do not contain any material adverse change provisions or any covenants requiring maintenance of specified financial ratios or ratings. The facility agreements contain a cross-default provision relating to the failure to pay principal or interest on other debt obligations of $200 million or more by ConocoPhillips, or by any of its consolidated subsidiaries.
Credit facility borrowings may bear interest at a margin above rates offered by certain designated banks in the London interbank market or at a margin above the overnight federal funds rate or prime rates offered by certain designated banks in the United States. The agreements call for commitment fees on available, but unused, amounts. The agreements also contain early termination rights if our current directors or their approved successors cease to be a majority of the Board of Directors.
Our primary funding source for short-term working capital needs is the ConocoPhillips $6.35 billion commercial paper program. Commercial paper maturities are generally limited to 90 days. We also have the ConocoPhillips Qatar Funding Ltd. $1.5 billion commercial paper program, which is used to fund commitments relating to the Qatargas 3 Project. At December 31, 2009 and 2008, 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, $1,300 million of commercial paper was outstanding at December 31, 2009, compared with $6,933 million at December 31, 2008. Since we had $1,300 million of commercial paper outstanding and had issued $40 million of letters of credit, we had access to $6.5 billion in borrowing capacity under our revolving credit facilities at December 31, 2009.
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. Under SEC shelf registrations, in early February 2009, we issued $1.5 billion of 4.75% Notes due 2014, $2.25 billion of 5.75% Notes due 2019, and $2.25 billion of 6.50% Notes due 2039, and in May 2009, we issued $1.5 billion of 4.60% Notes due 2015, $1.0 billion of 6.00% Notes due 2020 and an additional $500 million of 6.50% Notes due 2039. The proceeds from these notes were primarily used to reduce outstanding commercial paper balances and for general corporate purposes.
Our senior long-term debt is rated “A1” by Moody’s Investor Service and “A” by both Standard and Poor’s Rating Service and by Fitch. We do not have any ratings triggers on any of our corporate debt that would cause an automatic default, and thereby impact our access to liquidity, in the event of a downgrade of our credit rating. If our credit rating were to deteriorate to a level prohibiting us from accessing the commercial paper market, we would still be able to access funds under our $7.35 billion revolving credit facility and our $500 million credit facility.
Noncontrolling Interests
At December 31, 2009, and December 31, 2008, we had $590 million and $1,100 million, respectively, of equity in less-than-wholly owned consolidated subsidiaries held by noncontrolling interest owners. The decline from year-end 2008 was primarily due to Ashford Energy Capital S.A. redeeming for $500 million,
plus accrued dividends, the investment in Ashford held by Cold Spring Finance S.a.r.l. in the third quarter of 2009. The remaining noncontrolling interests at December 31, 2009, primarily represent operating joint ventures we control. The largest of these, amounting to $565 million, was related to Darwin liquefied natural gas (LNG) operations, located in Australia’s Northern Territory.
Off-Balance Sheet Arrangements
As part of our normal ongoing business operations and consistent with normal industry practice, we enter into numerous agreements with other parties to pursue business opportunities, which share costs and apportion risks among the parties as governed by the agreements. At December 31, 2009, we were liable for certain contingent obligations under the following contractual arrangements:
•
Qatargas 3: We own a 30 percent interest in Qatargas 3, 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. Qatargas 3 secured project financing of $4 billion in December 2005, consisting of $1.3 billion of loans from export credit agencies (ECA), $1.5 billion from commercial banks, and $1.2 billion from ConocoPhillips. The ConocoPhillips loan facilities have substantially the same terms as the ECA and commercial bank facilities. Prior to project completion certification, all loans, including the ConocoPhillips loan facilities, are guaranteed by the participants, based on their respective ownership interests. Accordingly, our maximum exposure to this financing structure is $1.2 billion. Upon completion certification, currently expected in 2011, all project loan facilities, including the ConocoPhillips loan facilities, will become nonrecourse to the project participants. At December 31, 2009, Qatargas 3 had approximately $3.6 billion outstanding under all the loan facilities, of which ConocoPhillips provided $1 billion, and an additional $88 million of accrued interest.
•
Rockies Express Pipeline: In June 2006, we issued a guarantee for 24 percent of $2 billion in credit facilities issued to Rockies Express Pipeline LLC, operated by Kinder Morgan Energy Partners, L.P. Rockies Express completed construction of a natural gas pipeline across a portion of the United States in November 2009. Shortly after completion, ConocoPhillips increased its ownership from 24 to 25 percent. The maximum potential amount of future payments to third-party lenders under the guarantee is estimated to be $500 million, which could become payable if the credit facilities are fully utilized and Rockies Express fails to meet its obligations under the credit agreement. At December 31, 2009, Rockies Express had $1,673 million outstanding under the credit facilities, with our 25 percent guarantee equaling $418 million. The guarantee expires in April 2011. However, it is anticipated refinancing of all or a portion of the $2 billion credit facility will take place in 2010, which is expected to reduce our guarantee exposure.
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, 2009, was $28.7 billion, an increase of $1.2 billion during 2009, and our debt-to-capital ratio was 31 percent at year-end 2009, versus 33 percent at the end of 2008. The change in the debt-to-capital ratio was due to an increase in equity. Our debt-to-capital ratio target range is 20 to 25 percent.
During 2009, we used proceeds from the issuance of commercial paper to redeem $284 million of 6.375% Notes and $950 million of Floating Rate Notes upon their maturity, and prepaid $750 million of Floating Rate Five-Year Term Notes.
On January 3, 2007, we closed on a business venture with EnCana (now Cenovus). 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. An initial contribution of $188 million was made upon closing in January. Quarterly principal and interest payments of $237 million began in the second quarter of 2007, and will continue until the balance is paid. Of the principal obligation
amount, approximately $660 million was short-term and was included in the “Accounts payable-related parties” line on our December 31, 2009, consolidated balance sheet. The principal portion of these payments, which totaled $625 million in 2009, are included in the “Other” line in the financing activities section of our consolidated statement of cash flows. Interest accrues at a fixed annual rate of 5.3 percent on the unpaid principal balance. Fifty percent of the quarterly interest payment is reflected as a capital contribution and is included in the “Capital expenditures and investments” line on our consolidated statement of cash flows.
We have provided loan financing to WRB Refining LLC, to assist it in meeting its operating and capital spending requirements. At December 31, 2009, $350 million of such financing was outstanding and was classified as long term.
In February 2010, we announced a quarterly dividend of 50 cents per share. The dividend is payable March 1, 2010, to stockholders of record at the close of business February 22, 2010.
Contractual Obligations
The following table summarizes our aggregate contractual fixed and variable obligations as of December 31, 2009:
(a)
Includes $502 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, including exchanges and futures, for the purchase of products such as crude oil, unfractionated natural gas liquids (NGL), natural gas and power. The products are mostly used to supply our refineries and fractionators, optimize the supply chain, and resell to customers. Product purchase commitments with third parties totaled $58,935 million. In addition, $40,739 million are product purchases from CPChem, mostly for natural gas and NGL over the remaining term of 90 years, and Excel Paralubes, for base oil over the remaining initial term of 15 years.
Purchase obligations of $8,226 million are related to agreements to access and utilize the capacity of third-party equipment and facilities, including pipelines and LNG and product terminals, to transport, process, treat, and store products.
The remainder is primarily our net share of purchase commitments for materials and services for jointly owned fields and facilities where we are the operator.
(c)
Represents the remaining amount of contributions, excluding interest, due over a seven-year period to the FCCL upstream joint venture with Cenovus.
(d)
Does not include: Pensions-for the 2010 through 2014 time period, we expect to contribute an average of $540 million per year to our qualified and nonqualified pension and postretirement benefit plans in the United States and an average of $250 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 $530 million for 2010 and then approximately $540 million per year for the remaining four years. Our required minimum funding in 2010 is expected to be $130 million in the United States and $170 million outside the United States.
(e)
Excludes unrecognized tax benefits of $1,148 million because the ultimate disposition and timing of any payments to be made with regard to such amount are not reasonably estimable. Although unrecognized tax benefits are not a contractual obligation, they are presented in this table because they represent potential demands on our liquidity.
Capital Spending
Capital Expenditures and Investments
Our capital expenditures and investments for the three-year period ending December 31, 2009, totaled $41.8 billion, with 85 percent allocated to our E&P segment.
Our capital expenditures and investments budget for 2010 is $10.5 billion. Included in this amount is approximately $500 million in capitalized interest. We plan to direct 85 percent of the capital expenditures and investments budget to E&P and 13 percent to R&M. With the addition of loans to certain affiliated companies and principal contributions related to funding our portion of the FCCL business venture, our total capital program for 2010 is approximately $11.2 billion.
E&P
Capital expenditures and investments for E&P during the three-year period ended December 31, 2009, totaled $35.3 billion. The expenditures over this period supported key exploration and development projects including:
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Oil and natural gas developments in the Lower 48, including New Mexico, Texas, Louisiana, Oklahoma, Montana, North Dakota, Colorado, Wyoming, and offshore in the Gulf of Mexico.
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The initial investment in 2008 related to the Australia Pacific LNG (APLNG) 50/50 joint venture and subsequent expenditures to advance the associated coalbed methane projects.
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Oil sands projects and ongoing natural gas projects in Canada.
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Alaska activities related to development drilling in the Greater Kuparuk Area, the Greater Prudhoe Bay Area, the Western North Slope and the Cook Inlet Area; and exploration.
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Development drilling and facilities projects in the Greater Ekofisk Area, Alvheim, Heidrun and Statfjord, located in the Norwegian sector of the North Sea.
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The Peng Lai 19-3 development in China’s Bohai Bay.
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The Kashagan Field and satellite prospects in the Caspian Sea offshore Kazakhstan.
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In the U.K. sector of the North Sea, the Britannia satellite developments and various southern and central North Sea assets.
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Development of the YK Field in the northern part of Russia’s Timan-Pechora province through the NMNG joint venture with LUKOIL.
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Investment in Rockies Express Pipeline LLC.
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Significant U.S. lease acquisitions in the federal waters of the Chukchi Sea offshore Alaska, as well as in the deepwater Gulf of Mexico.
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The North Belut Field, as well as other projects in offshore Block B and onshore South Sumatra in Indonesia.
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The Qatargas 3 Project, an integrated project to produce and liquefy natural gas from Qatar’s North Field.
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The Gumusut-Kakap development offshore Sabah, Malaysia.
2010 CAPITAL EXPENDITURES AND INVESTMENTS BUDGET
E&P’s 2010 capital expenditures and investments budget is $8.9 billion, which is essentially the same as actual expenditures in 2009. Twenty-eight percent of E&P’s 2010 capital expenditures and investments budget is planned for the United States.
Capital spending for our Alaskan operations is expected to be directed toward the Prudhoe Bay and Kuparuk Fields, as well as the Alpine Field and satellites on the Western North Slope.
In the Lower 48, we expect to make capital expenditures and investments for ongoing development in the San Juan and Permian Basins and the Bakken and Lobo Trends. Also, we expect to direct capital spending towards exploration activities in the deepwater Gulf of Mexico and the Eagle Ford shale position in Texas.
E&P is directing $6.5 billion of its 2010 capital expenditures and investments budget to international projects. Funds in 2010 will be directed to developing major long-term projects including:
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Canadian oil sands projects and ongoing natural gas projects in the western Canada gas basins.
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Further development of coalbed methane projects associated with the APLNG joint venture in Australia.
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Completion of the Qatargas 3 Project in Qatar.
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Elsewhere in the Asia Pacific/Middle East Region, continued development of Bohai Bay in China, new fields offshore Malaysia, offshore Block B and onshore South Sumatra in Indonesia, and offshore Vietnam.
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In the North Sea, the Ekofisk Area, Greater Britannia Fields, various southern North Sea assets, and development of the Jasmine discovery in the J Block and the Clair Ridge Project.
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The Kashagan Field in the Caspian Sea.
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Onshore developments in Nigeria, Algeria and Libya.
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Exploration activities in Australia’s Browse Basin, Kazakhstan’s Block N, offshore eastern Canada, offshore Indonesia and the North Sea, as well as a coal seam gas play in China and shale gas play in Poland.
For information on proved undeveloped reserves and the associated cost to develop these reserves, see the “Oil and Gas Operations” section.
R&M
Capital spending for R&M during the three-year period ended December 31, 2009, was primarily for clean fuels projects to meet new environmental standards, refinery upgrade projects to improve product yields and increase heavy crude oil processing capability, improving the operating integrity of key processing units, as well as for safety projects. During this three-year period, R&M capital spending was $5.4 billion, representing 13 percent of our total capital expenditures and investments.
Key projects during the three-year period included:
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Installation of a 20,000 barrel-per-day hydrocracker at the Rodeo facility of our San Francisco Refinery.
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Installation of a 25,000 barrel-per-day coker and new vacuum unit at the Borger Refinery.
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Installations, revamps and expansions of equipment at all U.S. refineries to enable production of low-sulfur and ultra-low-sulfur fuels.
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Upgrading the distillate desulfurization capability at the Humber Refinery.
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Debottlenecking of a crude and fluid catalytic cracking unit, and completion of a new sulfur plant at the Ferndale Refinery.
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Investment to obtain an equity interest in four Keystone Pipeline entities, and associated investment to construct a crude oil pipeline from Hardisty, Alberta, to delivery points in the United States. We disposed of our interest in the Keystone Pipeline in 2009.
Major construction activities in progress include:
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Installation of a 65,000 barrel-per-day coker and a major reconfiguration of the Wood River Refinery to handle advantaged crude and increase capacity, partially funded through long-term advances from ConocoPhillips.
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U.S. programs aimed at air emission reductions.
2010 CAPITAL EXPENDITURES AND INVESTMENTS BUDGET
R&M’s 2010 capital budget is $1.3 billion, a 24 percent decrease from actual spending in 2009, with about $0.9 billion for its U.S. downstream businesses and $0.4 billion for international R&M. These funds will be used for projects related to sustaining and improving the existing business with a focus on safety, regulatory compliance and reliability. As previously announced, the refinery upgrade project at Wilhelmshaven has been delayed.
Emerging Businesses
Capital spending for Emerging Businesses during the three-year period ended December 31, 2009, was primarily for an expansion of the Immingham combined heat and power cogeneration plant near our Humber Refinery in the United Kingdom. In addition, in October 2007, we purchased a 50 percent interest in Sweeny Cogeneration LP.
Contingencies
Legal and Tax Matters
We accrue a liability for known contingencies (other than those related to income taxes) when a loss is probable and the amounts can be reasonably estimated. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is
accrued. In the case of income-tax-related contingencies, we 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.
Environmental
We are subject to the same numerous international, federal, state and local environmental laws and regulations as other companies in the petroleum exploration and production, refining, and crude oil and refined product marketing and transportation businesses. The most significant of these environmental laws and regulations include, among others, the:
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U.S. Federal Clean Air Act, which governs air emissions.
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U.S. Federal Clean Water Act, which governs discharges to water bodies.
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European Union Regulation for Registration, Evaluation, Authorization and Restriction of Chemicals (REACH).
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U.S. Federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), which imposes liability on generators, transporters and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatening to occur.
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U.S. Federal Resource Conservation and Recovery Act (RCRA), which governs the treatment, storage and disposal of solid waste.
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U.S. Federal Oil Pollution Act of 1990 (OPA90), under which owners and operators of onshore facilities and pipelines, lessees or permittees of an area in which an offshore facility is located, and owners and operators of vessels are liable for removal costs and damages that result from a discharge of oil into navigable waters of the United States.
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U.S. Federal Emergency Planning and Community Right-to-Know Act (EPCRA), which requires facilities to report toxic chemical inventories with local emergency planning committees and response departments.
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U.S. Federal Safe Drinking Water Act, which governs the disposal of wastewater in underground injection wells.
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U.S. Department of the Interior regulations, which relate to offshore oil and gas operations in U.S. waters and impose liability for the cost of pollution cleanup resulting from operations, as well as potential liability for pollution damages.
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European Union Trading Directive resulting in European Emissions Trading Scheme.
These laws and their implementing regulations set limits on emissions and, in the case of discharges to water, establish water quality limits. They also, in most cases, require permits in association with new or modified operations. These permits can require an applicant to collect substantial information in connection with the application process, which can be expensive and time-consuming. In addition, there can be delays associated with notice and comment periods and the agency’s processing of the application. Many of the delays associated with the permitting process are beyond the control of the applicant.
Many states and foreign countries where we operate also have, or are developing, similar environmental laws and regulations governing these same types of activities. While similar, in some cases these regulations may impose additional, or more stringent, requirements that can add to the cost and difficulty of marketing or transporting products across state and international borders.
The ultimate financial impact arising from environmental laws and regulations is neither clearly known nor easily determinable as new standards, such as air emission standards, water quality standards and stricter fuel regulations continue to evolve. However, environmental laws and regulations, including those that may arise to address concerns about global climate change, are expected to continue to have an increasing impact on our operations in the United States and in other countries in which we operate. Notable areas of potential impacts include air emission compliance and remediation obligations in the United States.
For example, the Energy Policy Act of 2005 imposed obligations to provide increasing volumes on a percentage basis of renewable fuels in transportation motor fuels through 2012. These obligations were changed with the enactment of the Energy Independence & Security Act of 2007, which was signed in
December 2007. The 2007 law requires fuel producers and importers to provide approximately 66 percent more renewable fuels in 2008 as compared with amounts set forth in the Energy Policy Act of 2005, with further increases in amounts of renewable fuels required 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. Implementing regulations and standards for 2010 and beyond remain uncertain as the U.S. Environmental Protection Agency (EPA) has not promulgated final provisions.
We also are subject to certain laws and regulations relating to environmental remediation obligations associated with current and past operations. Such laws and regulations include CERCLA and RCRA and their state equivalents. Remediation obligations include cleanup responsibility arising from petroleum releases from underground storage tanks located at numerous past and present ConocoPhillips-owned and/or operated petroleum-marketing outlets throughout the United States. Federal and state laws require contamination caused by such underground storage tank releases be assessed and remediated to meet applicable standards. In addition to other cleanup standards, many states adopted cleanup criteria for methyl tertiary-butyl ether (MTBE) for both soil and groundwater.
At RCRA-permitted facilities, we are required to assess environmental conditions. If conditions warrant, we may be required to remediate contamination caused by prior operations. In contrast to CERCLA, which is often referred to as “Superfund,” the cost of corrective action activities under RCRA corrective action programs typically is borne solely by us. We anticipate increased expenditures for RCRA remediation activities may be required, but such annual expenditures for the near term are not expected to vary significantly from the range of such expenditures we have experienced over the past few years. Longer-term expenditures are subject to considerable uncertainty and may fluctuate significantly.
We, from time to time, receive requests for information or notices of potential liability from the EPA and state environmental agencies alleging that we are a potentially responsible party under CERCLA or an equivalent state statute. On occasion, we also have been made a party to cost recovery litigation by those agencies or by private parties. These requests, notices and lawsuits assert potential liability for remediation costs at various sites that typically are not owned by us, but allegedly contain wastes attributable to our past operations. As of December 31, 2008, we reported we had been notified of potential liability under CERCLA and comparable state laws at 65 sites around the United States. At December 31, 2009, we resolved and closed two sites, re-opened one site, and received one notice of potential liability, leaving 65 unresolved sites where we have been notified of potential liability.
For most Superfund sites, our potential liability will be significantly less than the total site remediation costs because the percentage of waste attributable to us, versus that attributable to all other potentially responsible parties, is relatively low. Although liability of those potentially responsible is generally joint and several for federal sites and frequently so for state sites, other potentially responsible parties at sites where we are a party typically have had the financial strength to meet their obligations, and where they have not, or where potentially responsible parties could not be located, our share of liability has not increased materially. Many of the sites at which we are potentially responsible are still under investigation by the EPA or the state agencies concerned. Prior to actual cleanup, those potentially responsible normally assess site conditions, apportion responsibility and determine the appropriate remediation. In some instances, we may have no liability or attain a settlement of liability. Actual cleanup costs generally occur after the parties obtain EPA or equivalent state agency approval. There are relatively few sites where we are a major participant, and given the timing and 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 $1,070 million in 2009 and are expected to be about $1.1 billion per year in 2010 and 2011. Capitalized environmental costs were $891 million in 2009 and are expected to be about $830 million per year in 2010 and 2011.
We accrue for remediation activities when it is probable that a liability has been incurred and reasonable estimates of the liability can be made. These accrued liabilities are not reduced for potential recoveries from
insurers or other third parties and are not discounted (except those assumed in a purchase business combination, which we do record on a discounted basis).
Many of these liabilities result from CERCLA, RCRA and similar state laws that require us to undertake certain investigative and remedial activities at sites where we conduct, or once conducted, operations or at sites where ConocoPhillips-generated waste was disposed. The accrual also includes a number of sites we identified that may require environmental remediation, but which are not currently the subject of CERCLA, RCRA or state enforcement activities. If applicable, we accrue receivables for probable insurance or other third-party recoveries. In the future, we may incur significant costs under both CERCLA and RCRA. Considerable uncertainty exists with respect to these costs, and under adverse changes in circumstances, potential liability may exceed amounts accrued as of December 31, 2009.
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, 2009, our balance sheet included total accrued environmental costs of $1,017 million, compared with $979 million at December 31, 2008. We expect to incur a substantial amount of these expenditures within the next 30 years.
Notwithstanding any of the foregoing, and as with other companies engaged in similar businesses, environmental costs and liabilities are inherent in our operations and products, and there can be no assurance that material costs and liabilities will not be incurred. However, we currently do not expect any material adverse effect upon our results of operations or financial position as a result of compliance with current environmental laws and regulations.
Climate Change
There has been a broad range of proposed or promulgated state, national and international laws focusing on greenhouse gas (GHG) reduction. These proposed or promulgated laws apply or could apply in countries where we have interests or may have interests in the future. Laws in this field continue to evolve, and while it is not possible to accurately estimate either a timetable for implementation or our future compliance costs relating to implementation, such laws, if enacted, could have a material impact on our results of operations and financial condition. Examples of legislation or precursors for possible regulation that do or could affect our operations include:
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European Emissions Trading Scheme (ETS), the program through which many of the European Union (EU) member states are implementing the Kyoto Protocol.
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California’s Global Warming Solutions Act, which requires the California Air Resources Board (CARB) to develop regulations and market mechanisms that will ultimately reduce California’s GHG emissions by 25 percent by 2020.
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Two regulations issued by the Alberta government in 2007 under the Climate Change and Emissions Act. These regulations require any existing facility with emissions equal to or greater than 100,000 metric tons of carbon dioxide or equivalent per year to reduce the net emissions intensity of that facility by 2 percent per year beginning July 1, 2007, with an ultimate reduction target of 12 percent of baseline emissions.
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The U.S. Supreme Court decision in Massachusetts v. EPA, 549 U.S. 497, 127 S.Ct. 1438 (2007) confirming that the EPA has the authority to regulate carbon dioxide as an “air pollutant” under the Federal Clean Air Act.
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The EPA’s announcement on December 7, 2009, “Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air Act, 74, Fed. Reg. 66,495,” finalizing its findings that GHG emissions threaten public health and the environment and that cars and light trucks cause or contribute to this threat. While these findings do not themselves impose any requirements on any industry or company at this time, these findings may lead to greater regulation of GHG emissions by the EPA, may trigger more climate-based claims for damages, and may result in longer agency review time for development projects to determine the extent of climate change.
In the EU, we have assets that are subject to the ETS. The first phase of the EU ETS was completed at the end of 2007, with EU ETS Phase II running from 2008 through 2012. The European Commission has approved most of the Phase II national allocation plans. We are actively engaged to minimize any financial impact from the trading scheme.
In the United States, there is growing consensus that some form of regulation will be forthcoming at the federal level with respect to GHG emissions. Such regulation could take any of several forms that result in the creation of additional costs in the form of taxes, the restriction of output, investments of capital to maintain compliance with laws and regulations, or required acquisition or trading of emission allowances. We are working to continuously improve operational and energy efficiency through resource and energy conservation throughout our operations.
Compliance with changes in laws and regulations that create a GHG emission trading scheme or GHG reduction policies could significantly increase our costs, reduce demand for fossil energy derived products, impact the cost and availability of capital and increase our exposure to litigation. Such laws and regulations could also increase demand for less carbon intensive energy sources, including natural gas. The ultimate impact on our financial performance, either positive or negative, will depend on a number of factors, including but not limited to:
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Whether and to what extent legislation is enacted.
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The nature of the legislation (such as a cap and trade system or a tax on emissions).
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The GHG reductions required.
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The price and availability of offsets.
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The amount and allocation of allowances.
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Technological and scientific developments leading to new products or services.
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Any potential significant physical effects of climate change (such as increased severe weather events, changes in sea levels and changes in temperature).
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Whether, and the extent to which, increased compliance costs are ultimately reflected in the prices of our products and services.
Other
We have deferred tax assets related to certain accrued liabilities, loss carryforwards and credit carryforwards. Valuation allowances have been established to reduce these deferred tax assets to an amount that will, more likely than not, be realized. Based on our historical taxable income, our expectations for the future, and available tax-planning strategies, management expects that the net deferred tax assets will be realized as offsets to reversing deferred tax liabilities and as reductions in future taxable income.
NEW ACCOUNTING STANDARDS
In June 2009, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 166, “Accounting for Transfers of Financial Assets, an amendment of FASB Statement No. 140.” This Statement was codified into FASB Accounting Standards Codification (ASC) Topic 860, “Transfers and Servicing.” This Statement removes the concept of a qualifying special purpose entity (SPE) and the exception for qualifying SPEs from the consolidation guidance. Additionally, the Statement clarifies the requirements for financial asset transfers eligible for sale accounting. This Statement is effective January 1, 2010, and is not expected to have a material impact on our consolidated financial statements.
Also in June 2009, the FASB issued SFAS No. 167, “Amendments to FASB Interpretation No. 46(R),” to address the effects of the elimination of the qualifying SPE concept in SFAS No. 166, and other concerns about the application of key provisions of consolidation guidance for variable interest entities (VIEs). This Statement was codified into FASB ASC Topic 810, “Consolidation.” More specifically, SFAS No. 167 requires a qualitative rather than a quantitative approach to determine the primary beneficiary of a VIE, it amends certain guidance pertaining to the determination of the primary beneficiary when related parties are involved, and it amends certain guidance for determining whether an entity is a VIE. Additionally, this
Statement requires continuous assessments of whether an enterprise is the primary beneficiary of a VIE. This Statement is effective January 1, 2010, and is not expected to have a material impact on our consolidated financial statements.
CRITICAL ACCOUNTING ESTIMATES
The preparation of financial statements in conformity with generally accepted accounting principles requires management to select appropriate accounting policies and to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. See Note 1-Accounting Policies, in the Notes to Consolidated Financial Statements, for descriptions of our major accounting policies. Certain of these accounting policies involve judgments and uncertainties to such an extent that there is a reasonable likelihood that materially different amounts would have been reported under different conditions, or if different assumptions had been used. These critical accounting estimates are discussed with the Audit and Finance Committee of the Board of Directors at least annually. We believe the following discussions of critical accounting estimates, along with the discussions of contingencies and of deferred tax asset valuation allowances in this report, address all important accounting areas where the nature of accounting estimates or assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change.
Oil and Gas Accounting
Accounting for oil and gas exploratory activity is subject to special accounting rules unique to the oil and gas industry. The acquisition of geological and geophysical seismic information, prior to the discovery of proved reserves, is expensed as incurred, similar to accounting for research and development costs. However, leasehold acquisition costs and exploratory well costs are capitalized on the balance sheet pending determination of whether proved oil and gas reserves have been discovered on the prospect.
Property Acquisition Costs
For individually significant leaseholds, management periodically assesses for impairment based on exploration and drilling efforts to date. For leasehold acquisition costs that individually are relatively small, management exercises judgment and determines a percentage probability that the prospect ultimately will fail to find proved oil and gas reserves and pools that leasehold information with others in the geographic area. For prospects in areas that have had limited, or no, previous exploratory drilling, the percentage probability of ultimate failure is normally judged to be quite high. This judgmental percentage is multiplied by the leasehold acquisition cost, and that product is divided by the contractual period of the leasehold to determine a periodic leasehold impairment charge that is reported in exploration expense.
This judgmental probability percentage is reassessed and adjusted throughout the contractual period of the leasehold based on favorable or unfavorable exploratory activity on the leasehold or on adjacent leaseholds, and leasehold impairment amortization expense is adjusted prospectively. At year-end 2009, 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 $1,466 million and the accumulated impairment reserve was $551 million. The weighted-average judgmental percentage probability of ultimate failure was approximately 62 percent, and the weighted-average amortization period was approximately 2.5 years. If that judgmental percentage were to be raised by 5 percent across all calculations, pretax leasehold impairment expense in 2010 would increase by approximately $32 million. The remaining $5,040 million of gross capitalized unproved property costs at year-end 2009 consisted of individually significant leaseholds, mineral rights held in perpetuity by title ownership, exploratory wells currently drilling, and suspended exploratory wells. Management periodically assesses individually significant leaseholds for impairment based on the results of exploration and drilling efforts and the outlook for project commercialization. Of this amount, approximately $2.6 billion is concentrated in 10 major development areas. One of these major assets totaling $102 million is expected to move to proved properties in 2010.
Exploratory Costs
For exploratory wells, drilling costs are temporarily capitalized, or “suspended,” on the balance sheet, pending a determination of whether potentially economic oil and gas reserves have been discovered by the drilling effort to justify completion of the find as a producing well.
If exploratory wells encounter potentially economic quantities of oil and gas, the well costs remain capitalized on the balance sheet as long as sufficient progress assessing the reserves and the economic and operating viability of the project is being made. The accounting notion of “sufficient progress” is a judgmental area, but the accounting rules do prohibit continued capitalization of suspended well costs on the mere chance that future market conditions will improve or new technologies will be found that would make the project’s development economically profitable. Often, the ability to move the project into the development phase and record proved reserves is dependent on obtaining permits and government or co-venturer approvals, the timing of which is ultimately beyond our control. Exploratory well costs remain suspended as long as we are actively pursuing such approvals and permits, and believe they will be obtained. Once all required approvals and permits have been obtained, the projects are moved into the development phase, and the oil and gas reserves are designated as proved reserves. For complex exploratory discoveries, it is not unusual to have exploratory wells remain suspended on the balance sheet for several years while we perform additional appraisal drilling and seismic work on the potential oil and gas field or while we seek government or co-venturer approval of development plans or seek environmental permitting. Once a determination is made the well did not encounter potentially economic oil and gas quantities, the well costs are expensed as a dry hole and reported in exploration expense.
Management reviews suspended well balances quarterly, continuously monitors the results of the additional appraisal drilling and seismic work, and expenses the suspended well costs as a dry hole when it determines the potential field does not warrant further investment in the near term. Criteria utilized in making this determination include evaluation of the reservoir characteristics and hydrocarbon properties, expected development costs, ability to apply existing technology to produce the reserves, fiscal terms, regulations or contract negotiations, and our required return on investment.
At year-end 2009, total suspended well costs were $908 million, compared with $660 million at year-end 2008. 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 operating approval limits. The reliability of these estimates at any point in time depends on both the quality and quantity of the technical and economic data and the efficiency of extracting and processing the hydrocarbons.
Despite the inherent imprecision in these engineering estimates, accounting rules require disclosure of “proved” reserve estimates due to the importance of these estimates to better understand the perceived value and future cash flows of a company’s E&P operations. There are several authoritative guidelines regarding the engineering criteria that must be met before estimated reserves can be designated as “proved.” Our reservoir engineering organization has policies and procedures in place 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 and during the year if significant changes occur, and take into account recent production and subsurface information about each field. Also, as required by current authoritative guidelines, the estimated future date when a field will be permanently shut down for economic reasons is based on 12-month average prices and year-end costs. This estimated date when production will end affects the amount of estimated reserves. Therefore, as prices and cost levels change from year to year, the estimate of proved reserves also changes.
Our proved reserves include estimated quantities related to production sharing contracts, which are reported under the “economic interest” method and are subject to fluctuations in prices of crude oil, natural gas and natural gas liquids; recoverable operating expenses; and capital costs. If costs remain stable, reserve quantities attributable to recovery of costs will change inversely to changes in commodity prices. For example, if prices increase, then our applicable reserve quantities would decline. The estimation of proved developed reserves
also is important to the statement of operations because the proved developed reserve estimate for a field serves as the denominator in the unit-of-production calculation of depreciation, depletion and amortization of the capitalized costs for that asset. At year-end 2009, the net book value of productive E&P properties, plants and equipment subject to a unit-of-production calculation was approximately $60 billion and the depreciation, depletion and amortization recorded on these assets in 2009 was approximately $8 billion. The estimated proved developed reserves for our consolidated operations were 5.5 billion BOE at the beginning of 2009 and were 5.6 billion BOE at the end of 2009. If the estimates of proved reserves used in the unit-of-production calculations had been lower by 5 percent across all calculations, pretax depreciation, depletion and amortization in 2009 would have increased by an estimated $424 million. Impairments of producing properties resulting from downward revisions of proved reserves due to reservoir performance were not material in the last three years.
Impairments
Long-lived assets used in operations are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in future cash flows expected to be generated by an asset group and annually following updates to corporate planning assumptions. If, upon review, the sum of the undiscounted pretax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value. Individual assets are grouped for impairment purposes based on a judgmental assessment of the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets-generally on a field-by-field basis for exploration and production assets, or at an entire complex level for downstream assets. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is determined based on the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants, or based on a multiple of operating cash flow validated with historical market transactions of similar assets where possible. The expected future cash flows used for impairment reviews and related fair value calculations are based on judgmental assessments of future production volumes, commodity prices, operating costs, refining margins and capital project decisions, considering all available information at the date of review. See Note 10-Impairments, in the Notes to Consolidated Financial Statements, for additional information.
Investments in nonconsolidated entities accounted for under the equity method are reviewed for impairment when there is evidence of a loss in value and annually following updates to corporate planning assumptions. Such evidence of a loss in value might include our inability to recover the carrying amount, the lack of sustained earnings capacity which would justify the current investment amount, or a current fair value less than the investment’s carrying amount. When it is determined such a loss in value is other than temporary, an impairment charge is recognized for the difference between the investment’s carrying value and its estimated fair value. When determining whether a decline in value is other than temporary, management considers factors such as the length of time and extent of the decline, the investee’s financial condition and near-term prospects, and our ability and intention to retain our investment for a period that will be sufficient to allow for any anticipated recovery in the market value of the investment. When quoted market prices are not available, the fair value is usually based on the present value of expected future cash flows using discount rates believed to be consistent with those used by principal market participants, plus market analysis of comparable assets owned by the investee, if appropriate. Differing assumptions could affect the timing and the amount of an impairment of an investment in any period. For additional information, see the “LUKOIL” and “NMNG” sections of Note 6-Investments, Loans and Long-Term Receivables, in the Notes to Consolidated Financial Statements.
Asset Retirement Obligations and Environmental Costs
Under various contracts, permits and regulations, we have material legal obligations to remove tangible equipment and restore the land or seabed at the end of operations at operational sites. Our largest asset removal obligations involve removal and disposal of offshore oil and gas platforms around the world, oil and gas production facilities and pipelines in Alaska, and asbestos abatement at refineries. The fair values of obligations for dismantling and removing these facilities are accrued at the installation of the asset based on estimated discounted costs. Estimating the future asset removal costs necessary for this accounting calculation is difficult. Most of these removal obligations are many years, or decades, in the future and the contracts and regulations often have vague descriptions of what removal practices and criteria must be met when the removal
event actually occurs. Asset removal technologies and costs, regulatory and other compliance considerations, expenditure timing, and other inputs into valuation of the obligation, including discount and inflation rates, are also subject to change.
In addition, under the above or similar contracts, permits and regulations, we have certain obligations to complete environmental-related projects. These projects are primarily related to cleanup at domestic refineries and underground storage tanks at U.S. service stations, and remediation activities required by Canada and the state of Alaska at exploration and production sites. Future environmental remediation costs are difficult to estimate because they are subject to change due to such factors as the uncertain magnitude of cleanup costs, the unknown time and extent of such remedial actions that may be required, and the determination of our liability in proportion to that of other responsible parties.
Business Acquisitions
Assets Acquired and Liabilities Assumed
Accounting for the acquisition of a business requires the recognition of the consideration paid, as well as the various assets and liabilities of the acquired business. For most assets and liabilities, the asset or liability is recorded at its estimated fair value. The most difficult estimates of individual fair values are those involving properties, plants and equipment and identifiable intangible assets. We use all available information to make these fair value determinations. We have, if necessary, up to one year after the acquisition closing date to finalize these fair value determinations.
Intangible Assets and Goodwill
At December 31, 2009, we had $740 million of intangible assets determined to have indefinite useful lives, thus they are not amortized. This judgmental assessment of an indefinite useful life must be continuously evaluated in the future. If, due to changes in facts and circumstances, management determines these intangible assets have definite useful lives, amortization will have to commence at that time on a prospective basis. As long as these intangible assets are judged to have indefinite lives, they will be subject to periodic lower-of-cost-or-market tests that require management’s judgment of the estimated fair value of these intangible assets.
In the fourth quarter of 2008, we fully impaired the recorded goodwill associated with our Worldwide E&P reporting unit. At December 31, 2009, we had $3,638 million of goodwill remaining on our balance sheet, all of which was attributable to the Worldwide R&M reporting unit. See Note 9-Goodwill and Intangibles, in the Notes to Consolidated Financial Statements, for additional information on intangibles and goodwill, including a detailed discussion of the facts and circumstances leading to the goodwill impairment, as well as the judgments required by management in the analysis leading to the impairment determination.
Projected Benefit Obligations
Determination of the projected benefit obligations for our defined benefit pension and postretirement plans are important to the recorded amounts for such obligations on the balance sheet and to the amount of benefit expense in the statement of operations. The actuarial determination of projected benefit obligations and company contribution requirements involves judgment about uncertain future events, including estimated retirement dates, salary levels at retirement, mortality rates, lump-sum election rates, rates of return on plan assets, future health care cost-trend rates, and rates of utilization of health care services by retirees. Due to the specialized nature of these calculations, we engage outside actuarial firms to assist in the determination of these projected benefit obligations and company contribution requirements. For Employee Retirement Income Security Act-qualified pension plans, the actuary exercises fiduciary care on behalf of plan participants in the determination of the judgmental assumptions used in determining required company contributions into the plan. Due to differing objectives and requirements between financial accounting rules and the pension plan funding regulations promulgated by governmental agencies, the actuarial methods and assumptions for the two purposes differ in certain important respects. Ultimately, we will be required to fund all promised benefits under pension and postretirement benefit plans not funded by plan assets or investment returns, but the judgmental assumptions used in the actuarial calculations significantly affect periodic financial statements and funding patterns over time. Benefit expense is particularly sensitive to the discount rate and return on plan assets assumptions. A 1 percent decrease in the discount rate assumption would increase annual benefit expense by $140 million, while a 1 percent decrease in the return on plan assets assumption would increase
annual benefit expense by $60 million. In determining the discount rate, we use yields on high-quality fixed income investments matched to the estimated benefit cash flows of our plans.
CAUTIONARY STATEMENT FOR THE PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
This report includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. You can identify our forward-looking statements by the words “anticipate,” “estimate,” “believe,” “continue,” “could,” “intend,” “may,” “plan,” “potential,” “predict,” “should,” “will,” “expect,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,” “effort,” “target” and similar expressions.
We based the forward-looking statements 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, natural gas 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 oil and gas reserves and oil and gas reservoir performance.
•
Unsuccessful exploratory drilling activities or the inability to obtain access to exploratory acreage.
•
Failure of new products and services to achieve market acceptance.
•
Unexpected changes in costs or technical requirements for constructing, modifying or operating facilities for exploration and production, manufacturing, refining or transportation projects.
•
Unexpected technological or commercial difficulties in manufacturing, refining or transporting our products, including synthetic crude oil and chemicals products.
•
Lack of, or disruptions in, adequate and reliable transportation for our crude oil, natural gas, natural gas liquids, LNG and refined products.
•
Inability to timely obtain or maintain permits, including those necessary for construction of LNG terminals or regasification facilities, 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 or terrorism.
•
International monetary conditions and exchange controls.
•
Substantial investment or reduced demand for products as a result of existing or future environmental rules and regulations.
•
Liability for remedial actions, including removal and reclamation obligations, under environmental regulations.
•
Liability resulting from litigation.
•
General domestic and international economic and political developments, including armed hostilities; expropriation of assets; changes in governmental policies relating to crude oil, natural gas, natural gas liquids or refined product pricing, regulation or taxation; other political, economic or diplomatic developments; and international monetary fluctuations.
•
Changes in tax and other laws, regulations (including alternative energy mandates), or royalty rules applicable to our business.
•
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 recently announced asset disposition plan.
•
Inability to obtain economical financing for projects, construction or modification of facilities and general corporate purposes.
•
The operation and financing of our midstream and chemicals joint ventures.
•
The factors generally described in Item 1A - Risk Factors in this report.
Item 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Financial Instrument Market Risk
We and certain of our subsidiaries hold and issue derivative contracts and financial instruments that expose our cash flows or earnings to changes in commodity prices, foreign exchange rates or interest rates. We may use financial and commodity-based derivative contracts to manage the risks produced by changes in the prices of electric power, natural gas, crude oil and related products; fluctuations in interest rates and foreign currency exchange rates; or to capture market opportunities.
Our use of derivative instruments is governed by an “Authority Limitations” document approved by our Board of Directors that prohibits the use of highly leveraged derivatives or derivative instruments without sufficient liquidity for comparable valuations. The Authority Limitations document also establishes the Value at Risk (VaR) limits for the company, and compliance with these limits is monitored daily. The Chief Financial Officer monitors risks resulting from foreign currency exchange rates and interest rates and reports to the Chief Executive Officer. The Senior Vice President of Commercial monitors commodity price risk and reports to the Chief Operating Officer. The Commercial organization manages our commercial marketing, optimizes our commodity flows and positions, and monitors related risks of our upstream and downstream businesses.
Commodity Price Risk
We operate in the worldwide crude oil, refined products, natural gas, natural gas liquids, and electric power markets and are exposed to fluctuations in the prices for these commodities. These fluctuations can affect our revenues, as well as the cost of operating, investing and financing activities. Generally, our policy is to remain exposed to the market prices of commodities.
Our Commercial organization uses futures, forwards, swaps and options in various markets to optimize the value of our supply chain, which may move our risk profile away from market average prices to accomplish the following objectives:
•
Balance physical systems. In addition to cash settlement prior to contract expiration, exchange-traded futures contracts also may be settled by physical delivery of the commodity, providing another source of supply to meet our refinery requirements or marketing demand.
•
Meet customer needs. Consistent with our policy to generally remain exposed to market prices, we use swap contracts to convert fixed-price sales contracts, which are often requested by natural gas and refined product consumers, to a floating market price.
•
Manage the risk to our cash flows from price exposures on specific crude oil, natural gas, refined product and electric power transactions.
•
Enable us to use the market knowledge gained from these activities to do a limited amount of commodity trading around our asset base.
We use a VaR model to estimate the loss in fair value that could potentially result on a single day from the effect of adverse changes in market conditions on the derivative financial instruments and derivative
commodity instruments held or issued, including commodity purchase and sales contracts recorded on the balance sheet at December 31, 2009, as derivative instruments. Using Monte Carlo simulation, a 95 percent confidence level and a one-day holding period, the VaR for those instruments issued or held for trading purposes at December 31, 2009 and 2008, was immaterial to our cash flows and net income attributable to ConocoPhillips.
The VaR for instruments held for purposes other than trading at December 31, 2009 and 2008, was also immaterial to our cash flows and net income attributable to ConocoPhillips.
Interest Rate Risk
The following table provides information about our financial instruments that are sensitive to changes in short-term U.S. interest rates. The debt portion of the table presents principal cash flows and related weighted-average interest rates by expected maturity dates. Weighted-average variable rates are based on implied forward rates in the yield curve at the reporting date. The carrying amount of our floating-rate debt approximates its fair value. The fair value of the fixed-rate financial instruments is estimated based on quoted market prices. The joint venture acquisition obligation portion of the table presents principal cash flows of the fixed-rate 5.3 percent joint venture acquisition obligation owed to FCCL Partnership. The fair value of the obligation is estimated based on the net present value of the future cash flows, discounted at a year-end 2009 and 2008 effective yield rate of 2.63 percent and 5.4 percent, respectively, based on yields of U.S. Treasury securities of a similar average duration adjusted for ConocoPhillips’ average credit risk spread and the amortizing nature of the obligation principal.
Foreign Currency Risk
We have foreign currency exchange rate risk resulting from international operations. We do not comprehensively hedge the exposure to currency rate changes although we may choose to selectively hedge certain foreign currency exchange rate exposures, such as firm commitments for capital projects or local currency tax payments, dividends and cash returns from net investments in foreign affiliates to be remitted within the coming year.
At December 31, 2009 and 2008, we held foreign currency swaps hedging short-term intercompany loans between European subsidiaries and a U.S. subsidiary. Although these swaps hedge exposures to fluctuations in exchange rates, we elected not to utilize hedge accounting as allowed by FASB ASC Topic 815. As a result, the change in the fair value of these foreign currency swaps is recorded directly in earnings. Since the gain or loss on the swaps is offset by the gain or loss from remeasuring the intercompany loans into the functional currency of the lender or borrower, there would be no material impact to income from an adverse hypothetical 10 percent change in the December 31, 2009 or 2008, exchange rates. The notional and fair market values of these positions at December 31, 2009 and 2008, were as follows:
*
Denominated in U.S. dollars (USD) and euro (EUR).
**
Denominated in U.S. dollars.
For additional information about our use of derivative instruments, see Note 16-Financial Instruments and Derivative Contracts, in the Notes to Consolidated Financial Statements.
Item 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
CONOCOPHILLIPS
Page
Report of Management
Report of Independent Registered Public Accounting Firm on Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting
Consolidated Statement of Operations for the years ended December 31, 2009, 2008 and 2007
Consolidated Balance Sheet at December 31, 2009 and 2008
Consolidated Statement of Cash Flows for the years ended December 31, 2009, 2008 and 2007
Consolidated Statement of Changes in Equity for the years ended December 31, 2009, 2008 and 2007
Notes to Consolidated Financial Statements
Supplementary Information
Oil and Gas Operations
Selected Quarterly Financial Data
Condensed Consolidating Financial Information
Report of Management
Management prepared, and is responsible for, the consolidated financial statements and the other information appearing in this annual report. The consolidated financial statements present fairly the company’s financial position, results of operations and cash flows in conformity with accounting principles generally accepted in the United States. In preparing its consolidated financial statements, the company includes amounts that are based on estimates and judgments management believes are reasonable under the circumstances. The company’s financial statements have been audited by Ernst & Young LLP, an independent registered public accounting firm appointed by the Audit and Finance Committee of the Board of Directors and ratified by stockholders. Management has made available to Ernst & Young LLP all of the company’s financial records and related data, as well as the minutes of stockholders’ and directors’ meetings.
Assessment of Internal Control Over Financial Reporting
Management is also responsible for establishing and maintaining adequate internal control over financial reporting. ConocoPhillips’ internal control system was designed to provide reasonable assurance to the company’s management and directors regarding the preparation and fair presentation of published financial statements.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
Management assessed the effectiveness of the company’s internal control over financial reporting as of December 31, 2009. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework. Based on our assessment, we believe the company’s internal control over financial reporting was effective as of December 31, 2009.
Ernst & Young LLP has issued an audit report on the company’s internal control over financial reporting as of December 31, 2009, and their report is included herein.
/s/ James J. Mulva
/s/ Sigmund L. Cornelius
James J. Mulva
Sigmund L. Cornelius
Chairman and
Senior Vice President, Finance,
Chief Executive Officer
and Chief Financial Officer
February 25, 2010
Report of Independent Registered Public Accounting Firm on Consolidated Financial Statements
The Board of Directors and Stockholders
ConocoPhillips
We have audited the accompanying consolidated balance sheets of ConocoPhillips as of December 31, 2009 and 2008, and the related consolidated statements of operations, changes in equity, and cash flows for each of the three years in the period ended December 31, 2009. Our audits also included the related condensed consolidating financial information listed in the Index at Item 8 and financial statement schedule listed in Item 15(a). These financial statements, condensed consolidating financial information, and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements, condensed consolidating financial information, and schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of ConocoPhillips at December 31, 2009 and 2008, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related condensed consolidating financial information and financial statement schedule, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects the information set forth therein.
As discussed in Note 2 to the consolidated financial statements, in 2009 ConocoPhillips has changed its reserve estimates and related disclosures as a result of adopting new oil and gas reserve estimation and disclosure requirements.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), ConocoPhillips’ internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 25, 2010 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Houston, Texas
February 25, 2010
Report of Independent Registered Public Accounting Firm on
Internal Control Over Financial Reporting
The Board of Directors and Stockholders
ConocoPhillips
We have audited ConocoPhillips’ internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). ConocoPhillips’ management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included under the heading “Assessment of Internal Control Over Financial Reporting” in the accompanying “Report of Management.” Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, ConocoPhillips maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the 2009 consolidated financial statements of ConocoPhillips and our report dated February 25, 2010 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Houston, Texas
February 25, 2010
Consolidated Statement of Operations
ConocoPhillips
**
Includes allocated goodwill.
***
For the purpose of the earnings per share calculation only, 2009 net income attributable to ConocoPhillips has been reduced by $12 million for the excess of the amount paid for the redemption of a noncontrolling interest over its carrying value, which was charged directly to retained earnings.
See Notes to Consolidated Financial Statements.
Consolidated Balance Sheet
ConocoPhillips
See Notes to Consolidated Financial Statements.
Consolidated Statement of Cash Flows
ConocoPhillips
See Notes to Consolidated Financial Statements.
Consolidated Statement of Changes in Equity
ConocoPhillips
See Notes to Consolidated Financial Statements.
Notes to Consolidated Financial Statements
ConocoPhillips
Note 1-Accounting Policies
n
Consolidation Principles and Investments-Our consolidated financial statements include the accounts of majority-owned, controlled subsidiaries and variable interest entities where we are the primary beneficiary. The equity method is used to account for investments in affiliates in which we have the ability to exert significant influence over the affiliates’ operating and financial policies. The cost method is used when we do not have the ability to exert significant influence. Undivided interests in oil and gas joint ventures, pipelines, natural gas plants and terminals are consolidated on a proportionate basis. Other securities and investments, excluding marketable securities, are generally carried at cost.
n
Foreign Currency Translation-Adjustments resulting from the process of translating foreign functional currency financial statements into U.S. dollars are included in accumulated other comprehensive income (loss) in common stockholders’ equity. Foreign currency transaction gains and losses are included in current earnings. Most of our foreign operations use their local currency as the functional currency.
n
Use of Estimates-The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosures of contingent assets and liabilities. Actual results could differ from these estimates.
n
Revenue Recognition-Revenues associated with sales of crude oil, natural gas, natural gas liquids, petroleum and chemical products, and other items are recognized when title passes to the customer, which is when the risk of ownership passes to the purchaser and physical delivery of goods occurs, either immediately or within a fixed delivery schedule that is reasonable and customary in the industry.
Revenues associated with properties producing natural gas and crude oil, in which we have an interest with other producers, are recognized based on the actual volumes we sold during the period. Any differences between volumes sold and entitlement volumes, based on our net working interest, which are deemed to be nonrecoverable through remaining production, are recognized as accounts receivable or accounts payable, as appropriate. Cumulative differences between volumes sold and entitlement volumes are generally not significant.
Revenues associated with transactions commonly called buy/sell contracts, in which the purchase and sale of inventory with the same counterparty are entered into “in contemplation” of one another, are combined and reported net (i.e., on the same income statement line).
n
Shipping and Handling Costs-Our Exploration and Production (E&P) segment includes shipping and handling costs in production and operating expenses for production activities. Transportation costs related to E&P marketing activities are recorded in purchased crude oil, natural gas and products. The Refining and Marketing (R&M) segment records shipping and handling costs in purchased crude oil, natural gas and products. Freight costs billed to customers are recorded as a component of revenue.
n
Cash Equivalents-Cash equivalents are highly liquid, short-term investments that are readily convertible to known amounts of cash and have original maturities of three months or less from their date of purchase. They are carried at cost plus accrued interest, which approximates fair value.
n
Inventories-We have several valuation methods for our various types of inventories and consistently use the following methods for each type of inventory. Crude oil and petroleum products inventories are valued at the lower of cost or market in the aggregate, primarily on the last-in, first-out (LIFO) basis. Any necessary lower-of-cost-or-market write-downs at year end are recorded as permanent adjustments to the LIFO cost basis. LIFO is used to better match current inventory costs with current revenues and to meet tax-conformity requirements. Costs include both direct and indirect expenditures incurred in
bringing an item or product to its existing condition and location, but not unusual/nonrecurring costs or research and development costs. Materials, supplies and other miscellaneous inventories, such as tubular goods and well equipment, are valued under various methods, including the weighted-average-cost method, and the first-in, first-out (FIFO) method, consistent with industry practice.
n
Fair Value Measurements-We categorize assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are observable inputs other than quoted prices included within Level 1 for the asset or liability, either directly or indirectly through market-corroborated inputs. Level 3 inputs are unobservable inputs for the asset or liability reflecting significant modifications to observable related market data or our assumptions about pricing by market participants.
n
Derivative Instruments-All derivative instruments are recorded on the balance sheet at fair value in either prepaid expenses and other current assets, other assets, other accruals, or other liabilities and deferred credits. If the right of offset exists and certain other criteria are met, derivative assets and liabilities with the same counterparty are netted on the balance sheet and the collateral payable or receivable is netted against derivative assets and derivative liabilities, respectively.
Recognition and classification of the gain or loss that results from recording and adjusting a derivative to fair value depends on the purpose for issuing or holding the derivative. Gains and losses from derivatives not accounted for as hedges are recognized immediately in earnings. For derivative instruments that are designated and qualify as a fair value hedge, the gains or losses from adjusting the derivative to its fair value will be immediately recognized in earnings and, to the extent the hedge is effective, offset the concurrent recognition of changes in the fair value of the hedged item. Gains or losses from derivative instruments that are designated and qualify as a cash flow hedge or hedge of a net investment in a foreign entity will be recorded on the balance sheet in accumulated other comprehensive income (loss) until the hedged transaction is recognized in earnings; however, to the extent the change in the value of the derivative exceeds the change in the anticipated cash flows of the hedged transaction, the excess gains or losses will be recognized immediately in earnings.
In the consolidated statement of operations, gains and losses from derivatives that are held for trading and not directly related to our physical business are recorded in other income. Gains and losses from derivatives used for other purposes are recorded in sales and other operating revenues; other income; purchased crude oil, natural gas and products; interest and debt expense; or foreign currency transaction (gains) losses, depending on the purpose for issuing or holding the derivatives.
n
Oil and Gas Exploration and Development-Oil and gas exploration and development costs are accounted for using the successful efforts method of accounting.
Property Acquisition Costs-Oil and gas leasehold acquisition costs are capitalized and included in the balance sheet caption properties, plants and equipment. Leasehold impairment is recognized based on exploratory experience and management’s judgment. Upon achievement of all conditions necessary for reserves to be classified as proved, the associated leasehold costs are reclassified to proved properties.
Exploratory Costs-Geological and geophysical costs and the costs of carrying and retaining undeveloped properties are expensed as incurred. Exploratory well costs are capitalized, or “suspended,” on the balance sheet pending further evaluation of whether economically recoverable reserves have been found. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. If exploratory wells encounter potentially economic quantities of oil and gas, the well costs remain capitalized on the balance sheet as long as sufficient progress assessing the reserves and the economic and operating viability of the project is being made. For complex exploratory discoveries, it is not unusual to have exploratory wells remain suspended on the balance sheet for several years while we perform additional appraisal drilling and seismic work on the potential oil and gas field or while we seek government or co-venturer approval of development plans
or seek environmental permitting. Once all required approvals and permits have been obtained, the projects are moved into the development phase, and the oil and gas reserves are designated as proved reserves.
Management reviews suspended well balances quarterly, continuously monitors the results of the additional appraisal drilling and seismic work, and expenses the suspended well costs as dry holes when it judges the potential field does not warrant further investment in the near term. See Note 8-Suspended Wells for additional information on suspended wells.
Development Costs-Costs incurred to drill and equip development wells, including unsuccessful development wells, are capitalized.
Depletion and Amortization-Leasehold costs of producing properties are depleted using the unit-of-production method based on estimated proved oil and gas reserves. Amortization of intangible development costs is based on the unit-of-production method using estimated proved developed oil and gas reserves.
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Capitalized Interest-Interest from external borrowings is capitalized on major projects with an expected construction period of one year or longer. Capitalized interest is added to the cost of the underlying asset and is amortized over the useful lives of the assets in the same manner as the underlying assets.
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Intangible Assets Other Than Goodwill-Intangible assets that have finite useful lives are amortized by the straight-line method over their useful lives. Intangible assets that have indefinite useful lives are not amortized but are tested at least annually for impairment. Each reporting period, we evaluate the remaining useful lives of intangible assets not being amortized to determine whether events and circumstances continue to support indefinite useful lives. These indefinite lived intangibles are considered impaired if the fair value of the intangible asset is lower than net book value. The fair value of intangible assets is determined based on quoted market prices in active markets, if available. If quoted market prices are not available, fair value of intangible assets is determined based upon the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants, or upon estimated replacement cost, if expected future cash flows from the intangible asset are not determinable.
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Goodwill-Goodwill resulting from a business combination is not amortized but is tested at least annually for impairment. If the fair value of a reporting unit is less than the recorded book value of the reporting unit’s assets (including goodwill), less liabilities, then a hypothetical purchase price allocation is performed on the reporting unit’s assets and liabilities using the fair value of the reporting unit as the purchase price in the calculation. If the amount of goodwill resulting from this hypothetical purchase price allocation is less than the recorded amount of goodwill, the recorded goodwill is written down to the new amount. For purposes of goodwill impairment calculations, two reporting units have been determined: Worldwide Exploration and Production and Worldwide Refining and Marketing.
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Depreciation and Amortization-Depreciation and amortization of properties, plants and equipment on producing hydrocarbon properties and certain pipeline assets (those which are expected to have a declining utilization pattern), are determined by the unit-of-production method. Depreciation and amortization of all other properties, plants and equipment are determined by either the individual-unit-straight-line method or the group-straight-line method (for those individual units that are highly integrated with other units).
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Impairment of Properties, Plants and Equipment-Properties, plants and equipment used in operations are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in the future cash flows expected to be generated by an asset group and annually following updates to corporate planning assumptions. If, upon review, the sum of the undiscounted pretax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value through additional amortization or depreciation provisions and reported as
impairments in the periods in which the determination of the impairment is made. Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets-generally on a field-by-field basis for exploration and production assets, or at an entire complex level for refining assets. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants or based on a multiple of operating cash flow validated with historical market transactions of similar assets where possible. Long-lived assets committed by management for disposal within one year are accounted for at the lower of amortized cost or fair value, less cost to sell, with fair value determined using a binding negotiated price, if available, or present value of expected future cash flows as previously described.
The expected future cash flows used for impairment reviews and related fair value calculations are based on estimated future production volumes, prices and costs, considering all available evidence at the date of review. If the future production price risk has been hedged, the hedged price is used in the calculations for the period and quantities hedged. The impairment review includes cash flows from proved developed and undeveloped reserves, including any development expenditures necessary to achieve that production. Additionally, when probable reserves exist, an appropriate risk-adjusted amount of these reserves may be included in the impairment calculation.
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Impairment of Investments in Nonconsolidated Entities-Investments in nonconsolidated entities are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred and annually following updates to corporate planning assumptions. When such a condition is judgmentally determined to be other than temporary, the carrying value of the investment is written down to fair value. The fair value of the impaired investment is based on quoted market prices, if available, or upon the present value of expected future cash flows using discount rates believed to be consistent with those used by principal market participants, plus market analysis of comparable assets owned by the investee, if appropriate.
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Maintenance and Repairs-Costs of maintenance and repairs, which are not significant improvements, are expensed when incurred.
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Advertising Costs-Production costs of media advertising are deferred until the first public showing of the advertisement. Advances to secure advertising slots at specific sporting or other events are deferred until the event occurs. All other advertising costs are expensed as incurred, unless the cost has benefits that clearly extend beyond the interim period in which the expenditure is made, in which case the advertising cost is deferred and amortized ratably over the interim periods that clearly benefit from the expenditure.
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Property Dispositions-When complete units of depreciable property are sold, the asset cost and related accumulated depreciation are eliminated, with any gain or loss reflected in other income. When less than complete units of depreciable property are disposed of or retired, the difference between asset cost and salvage value is charged or credited to accumulated depreciation.
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Asset Retirement Obligations and Environmental Costs-Fair value of legal obligations to retire and remove long-lived assets are recorded in the period in which the obligation is incurred (typically when the asset is installed at the production location). When the liability is initially recorded, we capitalize this cost by increasing the carrying amount of the related properties, plants and equipment. Over time the liability is increased for the change in its present value, and the capitalized cost in properties, plants and equipment is depreciated over the useful life of the related asset. See Note 11-Asset Retirement Obligations and Accrued Environmental Costs, for additional information.
Environmental expenditures are expensed or capitalized, depending upon their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and that do not have a future economic benefit, are expensed. Liabilities for environmental expenditures are recorded on an undiscounted basis (unless acquired in a purchase business combination) when environmental assessments or cleanups are probable and the costs can be reasonably estimated. Recoveries of environmental remediation costs from other parties, such as state reimbursement funds, are recorded as assets when their receipt is probable and estimable.
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Guarantees-Fair value of a guarantee is determined and recorded as a liability at the time the guarantee is given. The initial liability is subsequently reduced as we are released from exposure under the guarantee. We amortize the guarantee liability over the relevant time period, if one exists, based on the facts and circumstances surrounding each type of guarantee. In cases where the guarantee term is indefinite, we reverse the liability when we have information that the liability is essentially relieved or amortize it over an appropriate time period as the fair value of our guarantee exposure declines over time. We amortize the guarantee liability to the related statement of operations line item based on the nature of the guarantee. When it becomes probable that we will have to perform on a guarantee, we accrue a separate liability if it is reasonably estimable, based on the facts and circumstances at that time. We reverse the fair value liability only when there is no further exposure under the guarantee.
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Stock-Based Compensation-We recognize stock-based compensation expense over the shorter of the service period (i.e., the stated period of time required to earn the award); or the period beginning at the start of the service period and ending when an employee first becomes eligible for retirement. We elected to recognize expense on a straight-line basis over the service period for the entire award, whether the award was granted with ratable or cliff vesting.
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Income Taxes-Deferred income taxes are computed using the liability method and are provided on all temporary differences between the financial reporting basis and the tax basis of our assets and liabilities, except for deferred taxes on income considered to be permanently reinvested in certain foreign subsidiaries and foreign corporate joint ventures. Allowable tax credits are applied currently as reductions of the provision for income taxes. Interest related to unrecognized tax benefits is reflected in interest expense, and penalties in production and operating expenses.
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Taxes Collected from Customers and Remitted to Governmental Authorities-Excise taxes are reported gross within sales and other operating revenues and taxes other than income taxes, while other sales and value-added taxes are recorded net in taxes other than income taxes.
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Net Income (Loss) Per Share of Common Stock-Basic net income (loss) per share of common stock is calculated based upon the daily weighted-average number of common shares outstanding during the year, including unallocated shares held by the stock savings feature of the ConocoPhillips Savings Plan. Also, this calculation includes fully vested stock and unit awards that have not been issued. Diluted net income per share of common stock includes the above, plus unvested stock, unit or option awards granted under our compensation plans and vested but unexercised stock options, but only to the extent these instruments dilute net income per share. Diluted net loss per share in 2008 is calculated the same as basic net loss per share-that is, it does not assume conversion or exercise of securities, totaling 17,354,959 shares in 2008 that would have an anti-dilutive effect. Treasury stock and shares held by the grantor trusts are excluded from the daily weighted-average number of common shares outstanding in both calculations.
Note 2-Changes in Accounting Principles
Reserve Estimation and Disclosures
In January 2010, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2010-03, “Oil and Gas Reserve Estimation and Disclosures.” This ASU amends the FASB’s Accounting Standards Codification (ASC) Topic 932, “Extractive Activities-Oil and Gas” to align the accounting requirements of Topic 932 with the Securities and Exchange Commission’s final rule, “Modernization of the Oil and Gas Reporting Requirements” issued on December 31, 2008. In summary, the revisions in ASU 2010-3 modernize the disclosure rules to better align with current industry practices and expand the disclosure requirements for equity method investments so that more useful information is provided. More specifically, the main provisions include the following:
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An expanded definition of oil and gas producing activities to include nontraditional resources such as bitumen extracted from oil sands.
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The use of an average of the first-day-of-the-month price for the 12-month period, rather than a year-end price for determining whether reserves can be produced economically.
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Amended definitions of key terms such as “reliable technology” and “reasonable certainty” which are used in estimating proved oil and gas reserve quantities.
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A requirement for disclosing separate information about reserve quantities and financial statement amounts for geographical areas representing 15 percent or more of proved reserves.
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Clarification that an entity’s equity investments must be considered in determining whether it has significant oil and gas activities and a requirement to disclose equity method investments in the same level of detail as is required for consolidated investments.
This ASU is effective for annual reporting periods ended on or after December 31, 2009, and it requires (1) the effect of the adoption to be included within each of the dollar amounts and quantities disclosed, (2) qualitative and quantitative disclosure of the estimated effect of adoption on each of the dollar amounts and quantities disclosed, if significant and practical to estimate and (3) the effect of adoption on the financial statements, if significant and practical to estimate. Adoption of these requirements did not significantly impact our reported reserves or our consolidated financial statements.
Codification
The FASB issued ASU No. 2009-01 in June 2009. This Update, also issued as FASB Statement of Financial Accounting Standards (SFAS) No. 168, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles,” is effective for financial statements issued after September 15, 2009. Update 2009-01 requires that the FASB’s ASC become the sole source of authoritative U.S. generally accepted accounting principles recognized by the FASB for nongovernmental entities. We adopted this Update effective July 1, 2009.
Subsequent Events
Effective April 1, 2009, we adopted FASB SFAS No. 165, “Subsequent Events.” This Statement was codified into FASB ASC Topic 855, “Subsequent Events.” Topic 855 establishes the accounting for, and disclosure of, material events that occur after the balance sheet date, but before the financial statements are issued. In general, these events will be recognized if the condition existed at the date of the balance sheet, and will not be recognized if the condition did not exist at the balance sheet date. Disclosure is required for nonrecognized events if required to keep the financial statements from being misleading. The guidance in this Topic is very similar to previous guidance provided in auditing literature and, therefore, did not result in significant changes in practice.
Business Combinations
In December 2007, the FASB issued SFAS No. 141 (Revised), “Business Combinations” (SFAS No. 141(R)), which was subsequently amended by FASB Staff Position (FSP) FAS 141(R)-1 in April 2009. This Statement was codified into FASB ASC Topic 805, “Business Combinations.” Topic 805 applies prospectively to all transactions in which an entity obtains control of one or more other businesses on or after January 1, 2009. In general, Topic 805 requires the acquiring entity in a business combination to recognize the fair value of all
assets acquired and liabilities assumed in the transaction; establishes the acquisition date as the fair value measurement point; and modifies disclosure requirements. It also modifies the accounting treatment for transaction costs, in-process research and development, restructuring costs, changes in deferred tax asset valuation allowances as a result of a business combination, and changes in income tax uncertainties after the acquisition date. Additionally, effective January 1, 2009, accounting for changes in valuation allowances for acquired deferred tax assets and the resolution of uncertain tax positions for prior business combinations impact tax expense instead of goodwill.
Noncontrolling Interests
Effective January 1, 2009, we implemented SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements-an amendment of ARB No. 51.” This Statement was codified into FASB ASC Topic 810, “Consolidation.” Topic 810 requires noncontrolling interests, previously called minority interests, to be presented as a separate item in the equity section of the consolidated balance sheet. It also requires the amount of consolidated net income attributable to noncontrolling interests to be clearly presented on the face of the consolidated income statement. Additionally, Topic 810 clarifies that changes in a parent’s ownership interest in a subsidiary that do not result in deconsolidation are equity transactions, and that deconsolidation of a subsidiary requires gain or loss recognition in net income based on the fair value on the deconsolidation date. Topic 810 was applied prospectively with the exception of presentation and disclosure requirements, which were applied retrospectively for all periods presented, and did not significantly change the presentation of our consolidated financial statements. FASB ASU No. 2010-02, “Accounting and Reporting for Decreases in Ownership of a Subsidiary-a Scope Clarification,” clarified the decrease in ownership provision of Topic 810 applies to a group of assets or a subsidiary that is a business, but was not applicable to sales of in-substance real estate, or conveyances of oil and gas mineral rights.
Derivatives
Effective January 1, 2009, we implemented SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities-an amendment of FASB No. 133.” This Statement was codified into FASB ASC Topic 815, “Derivatives and Hedging.” The amendments to Topic 815 expanded disclosure requirements to provide greater transparency for derivative instruments. In addition, we now must include an indication of the volume of derivative activity by category (e.g., interest rate, commodity and foreign currency); derivative gains and losses, by category, for the periods presented in the financial statements; and expanded disclosures about credit-risk-related contingent features. See Note 16-Financial Instruments and Derivative Contracts, for additional information.
Fair Value Measurement
Effective January 1, 2008, we implemented SFAS No. 157, “Fair Value Measurements.” This Statement was codified primarily into FASB ASC Topic 820, “Fair Value Measurements and Disclosures.” This Topic defines fair value, establishes a framework for its measurement and expands disclosures about fair value measurements. We elected to implement this guidance with the one-year deferral permitted for nonfinancial assets and nonfinancial liabilities measured at fair value, except those that are recognized or disclosed on a recurring basis (at least annually). Following the allowed one-year deferral, effective January 1, 2009, we implemented Topic 820 for nonfinancial assets and nonfinancial liabilities measured at fair value on a nonrecurring basis. The implementation covers assets and liabilities measured at fair value in a business combination; impaired properties, plants and equipment, intangible assets and goodwill; initial recognition of asset retirement obligations; and restructuring costs for which we use fair value. There was no impact to our consolidated financial statements from the implementation of this Topic for nonfinancial assets and liabilities, other than additional disclosures.
Financial Instruments
In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities-Including an amendment of FASB Statement No. 115.” This Statement was codified into FASB ASC Topic 825, “Financial Instruments.” Topic 825 permits the election to carry financial instruments and certain other items similar to financial instruments at fair value on the balance sheet, with all changes in fair value reported in earnings. By electing the fair value option in conjunction with a derivative, an entity can achieve an accounting result similar to a fair value hedge without having to comply with complex hedge accounting rules. We adopted this Statement effective January 1, 2008, but did not make a fair value election at that time or during the remaining period of 2008 through the year 2009 for any financial instruments not
already carried at fair value in accordance with other accounting standards. Accordingly, the adoption of SFAS No. 159 did not impact our consolidated financial statements.
Compensation-Retirement Benefits
In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans-an amendment of FASB Statements No. 87, 88, 106, and 132(R).” This Statement was codified into FASB ASC Topic 715, “Compensation-Retirement Benefits.” Topic 715 requires an employer that sponsors one or more single-employer defined benefit plans to:
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Recognize the funded status of the benefit in its statement of financial position.
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Recognize as a component of other comprehensive income, net of tax, the gains or losses and prior service costs or credits that arise during the period, but are not recognized as components of net periodic benefit cost.
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Measure defined benefit plan assets and obligations as of the date of the employer’s fiscal year-end statement of financial position.
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Disclose in the notes to financial statements additional information about certain effects on net periodic benefit cost for the next fiscal year that arise from delayed recognition of the gains or losses, prior service costs or credits, and the transition asset or obligation.
We adopted the provisions of this Statement effective December 31, 2006, except for the requirement to measure plan assets and benefit obligations as of the date of the employer’s fiscal year end, which we adopted effective December 31, 2008. For information on the impact of the adoption of this Statement, see Note 19-Employee Benefit Plans.
Equity Method Accounting
In November 2008, the FASB reached a consensus on Emerging Issues Task Force (EITF) Issue No. 08-6, “Equity Method Investment Accounting Considerations” (EITF 08-6). EITF 08-6 was codified into FASB ASC Topic 323, “Investments-Equity Method and Joint Ventures.” EITF 08-6 was issued to clarify how the application of equity method accounting is affected by SFAS No. 141(R) and SFAS No. 160. Topic 323 clarifies that an entity shall continue to use the cost accumulation model for its equity method investments. It also confirms past accounting practices related to the treatment of contingent consideration and the use of the impairment model under Accounting Principles Board Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock.” Additionally, it requires an equity method investor to account for a share issuance by an investee as if the investor had sold a proportionate share of the investment. This Topic was effective January 1, 2009, and applies prospectively. The adoption did not impact our consolidated financial statements.
Financial Assets and Variable Interest Entities
In December 2008, the FASB issued FSP FAS 140-4 and FIN 46(R)-8, “Disclosures about Transfers of Financial Assets and Interest in Variable Interest Entities.” This FSP was codified into FASB ASC Topic 810, “Consolidation.” Topic 810 requires additional disclosures about an entity’s involvement with a variable interest entity (VIE) and certain transfers of financial assets to special-purpose entities and VIEs. This FSP was effective December 31, 2008, and the additional disclosures related to VIEs have been incorporated into Note 3-Variable Interest Entities (VIEs), including the methodology for determining whether we are the primary beneficiary of a VIE, whether we have provided financial or other support we were not contractually required to provide, and other qualitative and quantitative information. We did not have any transfers of financial assets within the scope of Topic 810.
Postretirement Benefit Plan Assets
In December 2008, the FASB issued FSP FAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets,” to improve the transparency associated with disclosures about the plan assets of a defined benefit pension or other postretirement plan. This Statement was codified into FASB ASC Topic 715, “Compensation-Retirement Benefits.” Topic 715 requires the disclosure of each major asset class at fair value using the fair value hierarchy in SFAS No. 157, “Fair Value Measurements.” This Topic is effective
for annual financial statements beginning with the 2009 fiscal year, but did not impact our consolidated financial statements, other than requiring additional disclosures. For more information on this disclosure, see Note 19-Employee Benefit Plans.
Note 3-Variable Interest Entities (VIEs)
We hold significant variable interests in VIEs that have not been consolidated because we are not considered the primary beneficiary. Information on these VIEs follows. See Note 26-New Accounting Standards, for information affecting the accounting for VIEs effective January 1, 2010.
We have a 30 percent ownership interest with a 50 percent governance interest in the OOO Naryanmarneftegaz (NMNG) joint venture to develop resources in the Timan-Pechora province of Russia. The NMNG joint venture is a VIE because we and a related party, OAO LUKOIL, have disproportionate interests. When related parties are involved in a VIE, reasonable judgment should take into account the relevant facts and circumstances for the determination of the primary beneficiary. The activities of NMNG are more closely aligned with LUKOIL because they share Russia as a home country, and LUKOIL conducts extensive exploration activities in the same province. Additionally, there are no financial guarantees given by LUKOIL or us, and LUKOIL owns 70 percent, versus our 30 percent direct interest. As a result, we have determined we are not the primary beneficiary of NMNG, and we use the equity method of accounting for this investment. The funding of NMNG has been provided with equity contributions, primarily for the development of the Yuzhno Khylchuyu (YK) Field. Initial production from YK was achieved in June 2008. At December 31, 2009, the book value of our investment in the venture was $1,647 million.
Production from the NMNG joint venture fields is transported via pipeline to LUKOIL’s terminal at Varandey Bay on the Barents Sea and then shipped via tanker to international markets. LUKOIL completed an expansion of the terminal’s gross oil-throughput capacity from 30,000 barrels per day to 240,000 barrels per day, and we participated in the design and financing of the expansion. The terminal entity, Varandey Terminal Company, is a VIE because we and LUKOIL have disproportionate interests. We had an obligation to fund, through loans, 30 percent of the terminal’s expansion costs, but have no governance or direct ownership interest in the terminal. Similar to NMNG, we determined we are not the primary beneficiary for Varandey because of LUKOIL’s ownership, the activities are in LUKOIL’s home country, and LUKOIL is the operator of Varandey. We account for our loan to Varandey as a financial asset. Terminal expansion was completed in June 2008. Principal repayments began in April 2009. The loan balance outstanding as of December 31, 2009, at current exchange rates, was $278 million.
We have an agreement with Freeport LNG Development, L.P. (Freeport LNG) to participate in a liquefied natural gas (LNG) receiving terminal in Quintana, Texas. We have no ownership in Freeport LNG; however, we own a 50 percent interest in Freeport LNG GP, Inc. (Freeport GP), which serves as the general partner managing the venture. We entered into a credit agreement with Freeport LNG, whereby we agreed to provide loan financing for the construction of the terminal. We also entered into a long-term agreement with Freeport LNG to use 0.9 billion cubic feet per day of regasification capacity. The terminal became operational in June 2008, and we began making payments under the terminal use agreement. Freeport LNG began making loan repayments in September 2008, and the loan balance outstanding as of December 31, 2009, was $707 million. Freeport LNG is a VIE because Freeport GP holds no equity in Freeport LNG, and the limited partners of Freeport LNG do not have any substantive decision making ability. We performed an analysis of the expected losses and determined we are not the primary beneficiary. This expected loss analysis took into account that the credit support arrangement requires Freeport LNG to maintain sufficient commercial insurance to mitigate any loan losses. The loan to Freeport LNG is accounted for as a financial asset, and our investment in Freeport GP is accounted for as an equity investment.
In the third quarter of 2009, Ashford Energy Capital S.A. redeemed for $500 million, plus accrued dividends, the investment in Ashford held by Cold Spring Finance S.a.r.l. Accordingly, we wholly own Ashford, and it is no longer a VIE.
Our ownership in Rockies Express Pipeline LLC, was previously reported as a VIE because a third party with no ownership interest had a 49 percent voting interest through the end of the construction phase of the pipeline. With completion of construction in November 2009, our ownership increased from 24 to 25 percent and is now aligned with our voting interest. Rockies Express Pipeline is no longer considered a VIE.
Note 4-Inventories
Inventories at December 31 were:
Inventories valued on the LIFO basis totaled $3,747 million and $3,939 million at December 31, 2009 and 2008, respectively. The excess of current replacement cost over LIFO cost of inventories amounted to $5,627 million and $1,959 million at December 31, 2009 and 2008, respectively. In 2007, a liquidation of LIFO inventory values increased net income attributable to ConocoPhillips $280 million, of which $260 million was attributable to our R&M segment.
Note 5-Assets Held for Sale
At December 31, 2008, we classified $594 million of noncurrent assets, primarily properties, plants and equipment, and $92 million of noncurrent liabilities, primarily deferred taxes, as held for sale on the consolidated balance sheet. During 2009, we closed on the sale of a large part of our U.S. retail marketing assets, which included seller financing in the form of a $370 million five-year note and letters of credit totaling $54 million. In addition, we had other dispositions during the year and some assets were classified back into held for use. Also during 2009, we classified additional marketing assets as held for sale. Accordingly, at December 31, 2009, we classified $323 million of noncurrent assets, primarily investments in equity affiliates, as held for sale and most of this amount is included in “Prepaid expenses and other current assets.” We also classified $75 million of noncurrent deferred tax liabilities as current, based on their held for sale status.
Note 6-Investments, Loans and Long-Term Receivables
Components of investments, loans and long-term receivables at December 31 were:
Equity Investments
Affiliated companies in which we have a significant equity investment include:
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Australia Pacific LNG-50 percent owned joint venture with Origin Energy-to develop coalbed methane production from the Bowen and Surat Basins in Queensland, Australia, as well as process and export LNG.
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FCCL Partnership-50 percent owned business venture with Cenovus Energy Inc.-produces bitumen in the Athabasca oil sands in northeastern Alberta and sells the bitumen blend.
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WRB Refining LLC-50 percent owned business venture with Cenovus-owns the Wood River and Borger Refineries, which process crude oil into refined products.
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OAO LUKOIL-20 percent ownership interest-explores for and produces crude oil, natural gas and natural gas liquids; refines, markets and transports crude oil and petroleum products; and is headquartered in Russia.
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OOO Naryanmarneftegaz (NMNG)-30 percent ownership interest and a 50 percent governance interest-a joint venture with LUKOIL to explore for, develop and produce oil and gas resources in the northern part of Russia’s Timan-Pechora province.
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DCP Midstream, LLC-50 percent owned joint venture with Spectra Energy-owns and operates gas plants, gathering systems, storage facilities and fractionation plants.
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Chevron Phillips Chemical Company LLC (CPChem)-50 percent owned joint venture with Chevron Corporation-manufactures and markets petrochemicals and plastics.
Summarized 100 percent financial information for equity method investments in affiliated companies, combined, was as follows (information included for LUKOIL is based on estimates):
Our share of income taxes incurred directly by the equity companies is reported in equity in earnings of affiliates, and as such is not included in income taxes in our consolidated financial statements.
At December 31, 2009, retained earnings included $1,504 million related to the undistributed earnings of affiliated companies. Distributions received from affiliates were $2,882 million, $3,259 million and $3,326 million in 2009, 2008 and 2007, respectively.
Australia Pacific LNG
In October 2008, we closed on a transaction with Origin Energy, an integrated Australian energy company, to further enhance our long-term Australasian natural gas business. The 50/50 joint venture, Australia Pacific LNG (APLNG) is focused on coalbed methane production from the Bowen and Surat Basins in Queensland, Australia, and LNG processing and export sales. This transaction gives us access to coalbed methane resources in Australia and enhances our LNG position with the expected creation of an additional LNG hub targeting the Asia Pacific markets.
Under the terms of the transaction, we paid $5 billion at closing, which after the effect of hedging gains, resulted in an initial cash acquisition cost of $4.7 billion. In addition, we are responsible for AU$1.15 billion related to Origin’s initial share of joint venture funding requirements, as incurred. We have committed to
make up to four additional payments of $500 million each, expected within the next decade, conditional on up to four LNG trains being approved by the joint venture for development.
At December 31, 2009, the book value of our equity method investment in APLNG was $7,344 million, which includes $2,196 million of cumulative translation effects due to a strengthening Australian dollar. Our 50 percent share of the historical cost basis net assets of APLNG on its books under U.S. generally accepted accounting principles (GAAP) was $659 million, resulting in a basis difference of $6,698 million on our books. The amortizable portion of the basis difference, $4,692 million associated with properties, plants and equipment, has been allocated on a relative fair value basis to individual exploration and production license areas owned by APLNG, most of which are not currently in production. Any future additional payments are expected to be allocated in a similar manner. Each exploration license area will periodically be reviewed for any indicators of potential impairment, which, if required, would result in acceleration of basis difference amortization. As the joint venture begins producing natural gas from each license, we amortize the basis difference allocated to that license using the unit-of-production method. Included in net income attributable to ConocoPhillips for 2009 and 2008 was after-tax expense of $4 million and $7 million, respectively, representing the amortization of this basis difference on currently producing licenses.
FCCL and WRB
In January 2007, we closed on a business venture with EnCana Corporation (now Cenovus) to create an integrated North American heavy oil business. The transaction consists of two 50/50 business ventures, a Canadian upstream general partnership, FCCL Partnership, and a U.S. downstream limited liability company, WRB Refining LLC. We use the equity method of accounting for both entities, with the operating results of our investment in FCCL reflecting its use of the full-cost method of accounting for oil and gas exploration and development activities.
At December 31, 2009, the book value of our investment in FCCL was $8,318 million. FCCL’s operating assets consist of the Foster Creek and Christina Lake steam-assisted gravity drainage bitumen projects, both located in the eastern flank of the Athabasca oil sands in northeastern Alberta. Cenovus is the operator and managing partner of FCCL. We are obligated to contribute $7.5 billion, plus accrued interest, to FCCL over a 10-year period that began in 2007. For additional information on this obligation, see Note 13-Joint Venture Acquisition Obligation.
At December 31, 2009, the book value of our investment in WRB was $2,975 million. WRB’s operating assets consist of the Wood River and Borger Refineries, located in Roxana, Illinois, and Borger, Texas, respectively. As a result of our contribution of these two assets to WRB, a basis difference was created due to the fair value of the contributed assets recorded by WRB exceeding their historical book value. The difference is primarily amortized and recognized as a benefit evenly over a period of 25 years, which is the estimated remaining useful life of the refineries at the closing date. The basis difference at December 31, 2009, was $4,344 million. Equity earnings in 2009, 2008 and 2007 were increased by $209 million, $246 million and $202 million, respectively, due to amortization of the basis difference. We are the operator and managing partner of WRB. Cenovus is obligated to contribute $7.5 billion, plus accrued interest, to WRB over a 10-year period that began in 2007. For the Wood River Refinery, operating results are shared 50/50 starting upon formation. For the Borger Refinery, we were entitled to 85 percent of the operating results in 2007, with our share decreasing to 65 percent in 2008, and 50 percent in all years thereafter.
LUKOIL
LUKOIL is an integrated energy company headquartered in Russia, with operations worldwide. Our ownership interest was 20 percent at December 31, 2009, 2008 and 2007, based on 851 million shares authorized and issued. For financial reporting under U.S. GAAP, treasury shares held by LUKOIL are not considered outstanding for determining our equity method ownership interest in LUKOIL. Our ownership interest, based on estimated shares outstanding at December 31, 2009, 2008 and 2007, was 20.09 percent, 20.06 percent and 20.6 percent, respectively.
Because LUKOIL’s accounting cycle close and preparation of U.S. GAAP financial statements occur subsequent to our reporting deadline, our equity earnings for our LUKOIL investment are estimated, based on current market indicators, publicly available LUKOIL information, and other objective data. Once the
difference between actual and estimated results is known, an adjustment is recorded. This estimate-to-actual adjustment will be a recurring component of future period results.
Since the inception of our investment and through June 30, 2008, the market value of our investment in LUKOIL exceeded book value, based on the price of LUKOIL American Depositary Receipts (ADRs) on the London Stock Exchange. However, the price of LUKOIL ADRs experienced significant decline during the second half of 2008, and traded for most of the fourth quarter and into early 2009 in the general range of $25 to $40 per share. The ADR price ended the year at $32.05 per share, or 67 percent lower than the June 30, 2008, price. This resulted in a December 31, 2008, market value of our investment of $5,452 million, or 58 percent lower than our book value. Based on a review of the facts and circumstances surrounding this decline in the market value of our investment during the second half of 2008, we concluded that an impairment of our investment was necessary. In reaching this conclusion, we considered the length of time market value has been below book value and the severity of the decline in market value to be important factors. In combination, these two items caused us to conclude that the decline was other than temporary.
Accordingly, we recorded a noncash $7,410 million, before- and after-tax impairment, in our fourth-quarter 2008 results. This impairment had the effect of reducing our book value to $5,452 million, based on the market value of LUKOIL ADRs on December 31, 2008.
At December 31, 2009, the book value of our investment in LUKOIL was $6,861 million. Our 20 percent share of the net assets of LUKOIL was estimated to be $11,314 million. This negative basis difference of $4,453 million is primarily being amortized on a straight-line basis over a 22-year useful life as an increase to equity earnings. Equity earnings in 2009 were increased $209 million, while equity earnings in 2008 and 2007 were reduced $88 million and $77 million, respectively, due to amortization of the positive basis difference that existed prior to the 2008 year-end investment impairment. On December 31, 2009, the closing price of LUKOIL shares on the London Stock Exchange was $57.30 per share, making the aggregate total market value of our LUKOIL investment $9,747 million.
NMNG
NMNG is a joint venture with LUKOIL, created in June 2005, to develop resources in the northern part of Russia’s Timan-Pechora province. We have a 30 percent direct ownership interest with a 50 percent governance interest. At December 31, 2009, the book value of our equity method investment in NMNG was $1,647 million. NMNG is nearing completion of the development of the YK Field, which achieved initial production in June 2008. Production from the NMNG joint venture fields is transported via pipeline to LUKOIL’s existing terminal at Varandey Bay on the Barents Sea and then shipped via tanker to international markets. During 2009, we reduced the carrying value of our NMNG investment, reflecting an other-than-temporary decline in fair value primarily attributable to lower probable resources in the YK area.
DCP Midstream
DCP Midstream owns and operates gas plants, gathering systems, storage facilities and fractionation plants. At December 31, 2009, the book value of our equity method investment in DCP Midstream was $1,003 million. DCP Midstream markets a portion of its natural gas liquids to us and CPChem under a supply agreement that continues until December 31, 2014. Beginning in 2015, the volume commitment is reduced by 20 percent each year until the volume commitment is zero. This purchase commitment is on an “if-produced, will-purchase” basis and so has no fixed production schedule, but has had, and is expected over the remaining term of the contract to have, a relatively stable purchase pattern. Natural gas liquids are purchased under this agreement at various published market index prices, less transportation and fractionation fees.
CPChem
CPChem manufactures and markets petrochemicals and plastics. At December 31, 2009, the book value of our equity method investment in CPChem was $2,445 million. We have multiple supply and purchase agreements in place with CPChem, ranging in initial terms from one to 99 years, with extension options. These agreements cover sales and purchases of refined products, solvents, and petrochemical and natural gas liquids feedstocks, as well as fuel oils and gases. Delivery quantities vary by product, and are generally on an “if-produced, will-purchase” basis. All products are purchased and sold under specified pricing formulas based on various published pricing indices, consistent with terms extended to third-party customers.
Loans to Related Parties
As part of our normal ongoing business operations and consistent with industry practice, we invest and enter into numerous agreements with other parties to pursue business opportunities, which share costs and apportion risks among the parties as governed by the agreements. Included in such activity are loans made to certain affiliated companies. Loans are recorded when cash is transferred to the affiliated company pursuant to a loan agreement. The loan balance will increase as interest is earned on the outstanding loan balance and will decrease as interest and principal payments are received. Interest is earned at the loan agreement’s stated interest rate. Loans are assessed for impairment when events indicate the loan balance may not be fully recovered.
Significant loans to affiliated companies include the following:
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$707 million in loan financing to Freeport LNG Development, L.P. for the construction of an LNG receiving terminal that became operational in June 2008. Freeport began making repayments in September 2008.
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$278 million in loan financing at December 2009 exchange rates to Varandey Terminal Company associated with the costs of the terminal expansion. The terminal expansion was completed in June 2008, and principal repayments began in April 2009.
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$1,000 million of project financing and an additional $88 million of accrued interest to Qatargas 3, which is an integrated project to produce and liquefy natural gas from Qatar’s North Field. We own a 30 percent interest in the project. The other participants in the project are affiliates of Qatar Petroleum (68.5 percent) and Mitsui & Co., Ltd. (1.5 percent). Our interest is held through a jointly owned company, Qatar Liquefied Gas Company Limited (3), for which we use the equity method of accounting. Qatargas 3 secured project financing of $4 billion in December 2005, consisting of $1.3 billion of loans from export credit agencies (ECA), $1.5 billion from commercial banks, and $1.2 billion from ConocoPhillips. The ConocoPhillips loan facilities have substantially the same terms as the ECA and commercial bank facilities. Prior to project completion certification, all loans, including the ConocoPhillips loan facilities, are guaranteed by the participants based on their respective ownership interests. Accordingly, our maximum exposure to this financing structure is $1.2 billion. Upon completion certification, which is expected in 2011, all project loan facilities, including the ConocoPhillips loan facilities, will become nonrecourse to the project participants. At December 31, 2009, Qatargas 3 had approximately $3.6 billion outstanding under all the loan facilities.
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$350 million of loan financing to WRB Refining LLC to assist it in meeting its operating and capital spending requirements.
The long-term portion of these loans are included in the “Loans and advances-related parties” line on the consolidated balance sheet, while the short-term portion is in “Accounts and notes receivable-related parties.”
Other Investments
We have investments remeasured at fair value on a recurring basis to support certain nonqualified deferred compensation plans. The fair value of these assets at December 31, 2009, was $338 million, and substantially the entire value is categorized in Level 1 of the fair value hierarchy. These investments are measured at fair value using a market approach based on quotations from national securities exchanges.
Merey Sweeny, L.P. (MSLP) is a limited partnership that owns a 70,000 barrel-per-day delayed coker and related facilities at the Sweeny Refinery used to produce fuel-grade petroleum coke. Prior to August 28, 2009, MSLP was owned 50/50 by us and Petróleos de Venezuela S.A. (PDVSA). Under the agreements that govern the relationships between the partners, certain defaults by PDVSA with respect to supply of crude oil to the Sweeny Refinery gave us the right to acquire PDVSA’s 50 percent ownership interest in MSLP. On August 28, 2009, we exercised that right. In public statements, PDVSA has challenged our actions. We continue to use the equity method of accounting for our investment in MSLP.
Note 7-Properties, Plants and Equipment
Properties, plants and equipment (PP&E) are recorded at cost. Within the E&P segment, depreciation is mainly on a unit-of-production basis, so depreciable life will vary by field. In the R&M segment, investments in refining manufacturing facilities are generally depreciated on a straight-line basis over a 25-year life, and pipeline assets over a 45-year life. The company’s investment in PP&E, with accumulated depreciation, depletion and amortization (Accum. DD&A), at December 31 was:
Note 8-Suspended Wells
The following table reflects the net changes in suspended exploratory well costs during 2009, 2008 and 2007:
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Includes $7 million related to assets held for sale in 2007.
The following table provides an aging of suspended well balances at December 31, 2009, 2008 and 2007:
The following table provides a further aging of those exploratory well costs that have been capitalized for more than one year since the completion of drilling as of December 31, 2009:
(1)
Additional appraisal wells planned.
(2)
Appraisal drilling complete; costs being incurred to assess development.
Note 9-Goodwill and Intangibles
Goodwill
Changes in the carrying amount of goodwill are as follows:
Goodwill Impairment
We perform our annual goodwill impairment review in the fourth quarter of each year. During the fourth quarter of 2008, there were severe disruptions in the credit markets and reductions in global economic activity which had significant adverse impacts on stock markets and oil-and-gas-related commodity prices, both of which contributed to a significant decline in our company’s stock price and corresponding market
capitalization. For most of the fourth quarter, our market capitalization value was significantly below the recorded net book value of our balance sheet, including goodwill.
Because quoted market prices for our reporting units are not available, management must apply judgment in determining the estimated fair value of these reporting units for purposes of performing the annual goodwill impairment test. Management uses all available information to make these fair value determinations, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets. A key component of these fair value determinations is a reconciliation of the sum of these net present value calculations to our market capitalization. We use an average of our market capitalization over the 30 calendar days preceding the impairment testing date as being more reflective of our stock price trend than a single day, point-in-time market price. Because, in our judgment, Worldwide E&P is considered to have a higher valuation volatility than Worldwide R&M, the long-term free cash flow growth rate implied from this reconciliation to our recent average market capitalization is applied to the Worldwide E&P net present value calculation.
The accounting principles regarding goodwill acknowledge that the observed market prices of individual trades of a company’s stock (and thus its computed market capitalization) may not be representative of the fair value of the company as a whole. Substantial value may arise from the ability to take advantage of synergies and other benefits that flow from control over another entity. Consequently, measuring the fair value of a collection of assets and liabilities that operate together in a controlled entity is different from measuring the fair value of that entity’s individual common stock. In most industries, including ours, an acquiring entity typically is willing to pay more for equity securities that give it a controlling interest than an investor would pay for a number of equity securities representing less than a controlling interest. Therefore, once the above net present value calculations have been determined, we also add a control premium to the calculations. This control premium is judgmental and is based on observed acquisitions in our industry. The resultant fair values calculated for the reporting units are then compared to observable metrics on large mergers and acquisitions in our industry to determine whether those valuations, in our judgment, appear reasonable.
After determining the fair values of our various reporting units as of December 31, 2008, it was determined that our Worldwide R&M reporting unit passed the first step of the goodwill impairment test, while our Worldwide E&P reporting unit did not pass the first step. As described above, the second step of the goodwill impairment test uses the estimated fair value of Worldwide E&P from the first step as the purchase price in a hypothetical acquisition of the reporting unit. The significant hypothetical purchase price allocation adjustments made to the assets and liabilities of Worldwide E&P in this second step calculation were in the areas of:
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Adjusting the carrying value of major equity method investments to their estimated fair values.
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Adjusting the carrying value of properties, plants and equipment (PP&E) to the estimated aggregate fair value of all oil and gas property interests.
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Recalculating deferred income taxes under FASB ASC Topic 740, “Income Taxes,” after considering the likely tax basis a hypothetical buyer would have in the assets and liabilities.
When determining the above adjustment for the estimated aggregate fair value of PP&E, it was noted that in order for any residual purchase price to be allocated to goodwill, the purchase price assigned to PP&E would have to be well below the value of the PP&E implied by recently-observed metrics from other sales of major oil and gas properties.
Based on the above analysis, we concluded that a $25.4 billion before- and after-tax noncash impairment of the entire amount of recorded goodwill for the Worldwide E&P reporting unit was required. This impairment was recorded in the fourth quarter of 2008.
Intangible Assets
Information on the carrying value of intangible assets follows:
Amortization expense related to the intangible assets above for the years ended December 31, 2009 and 2008, was $30 million and $35 million, respectively. Estimated 2010 amortization expense is $25 million. Amortization expense is expected to be approximately $20 million and $10 million per year during 2011 and 2012, respectively, and approximately $5 million per year during 2013 and 2014.
Note 10-Impairments
Goodwill
See the “Goodwill Impairment” section of Note 9-Goodwill and Intangibles, for information on the complete impairment of our E&P segment goodwill.
LUKOIL
See the “LUKOIL” section of Note 6-Investments, Loans and Long-Term Receivables, for information on the impairment of our LUKOIL investment.
Expropriated Assets
Ecuador
In April 2008, Burlington Resources, Inc., a wholly owned subsidiary of ConocoPhillips, initiated arbitration before the World Bank’s International Centre for Settlement of Investment Disputes (ICSID) against The Republic of Ecuador and PetroEcuador as a result of the newly-enacted Windfall Profits Tax Law and government-mandated renegotiation of our production sharing contracts. Despite a restraining order issued by the ICSID, Ecuador confiscated the crude oil production of Burlington and its co-venturer and sold the illegally
seized crude oil. As a result, our assets in Ecuador were effectively expropriated. Accordingly, in the second quarter of 2009, we recorded a noncash charge of $51 million before- and after-tax related to the full impairment of our exploration and production investments in Ecuador. In the third quarter of 2009, Ecuador took over operations in Block 7 and 21, formalizing the complete expropriation of our assets. A jurisdictional hearing before the ICSID was held in January 2010, with the outcome still pending.
Venezuela
On January 31, 2007, Venezuela’s National Assembly passed a law allowing the president of Venezuela to pass laws on certain matters by decree. On February 26, 2007, the president of Venezuela issued a decree (the Nationalization Decree) mandating the termination of the then-existing structures related to our heavy oil ventures and oil production risk contracts and the transfer of all rights relating to our heavy oil ventures and oil production risk contracts to joint ventures (“empresas mixtas”) that will be controlled by the Venezuelan national oil company or its subsidiaries.
On June 26, 2007, we announced we had been unable to reach agreement with respect to our migration to an empresa mixta structure mandated by the Nationalization Decree. In response, Petróleos de Venezuela S.A. (PDVSA) or its affiliates directly assumed the activities associated with ConocoPhillips’ interests in the Petrozuata and Hamaca heavy oil ventures and the offshore Corocoro oil development project. Based on Venezuelan statements that the expropriation of our oil interests in Venezuela occurred on June 26, 2007, management determined such expropriation required a complete impairment, under U.S. generally accepted accounting principles, of our investments in the Petrozuata and Hamaca heavy oil ventures and the offshore Corocoro oil development project. Accordingly, we recorded a noncash impairment, including allocable goodwill, of $4,588 million before-tax ($4,512 million after-tax) in the second quarter of 2007.
The impairment included equity method investments and properties, plants and equipment. Also, this expropriation of our oil interests is viewed as a partial disposition of our Worldwide E&P reporting unit and required an allocation of goodwill to the expropriation event. The amount of goodwill impaired as a result of this allocation was $1,925 million.
We filed a request for international arbitration on November 2, 2007, with the ICSID, an arm of the World Bank. The request was registered by the ICSID on December 13, 2007. The tribunal of three arbitrators is constituted, and the arbitration proceeding is under way.
We believe the value of our expropriated Venezuelan oil operations substantially exceeds the historical cost-based carrying value plus goodwill allocable to those operations. However, U.S. generally accepted accounting principles require a claim that is the subject of litigation be presumed to not be probable of realization. In addition, the timing of any negotiated or arbitrated settlement is not known at this time, but we anticipate it could take years. Accordingly, any compensation for our expropriated assets was not considered when making the impairment determination, since to do so could result in the recognition of compensation for the expropriation prior to its realization.
Other Impairments
During 2009, 2008 and 2007, we recognized the following before-tax impairment charges, excluding the goodwill, LUKOIL investment and expropriated assets impairments noted above:
During 2009, we recorded property impairments of $417 million in our E&P segment, primarily as a result of lower natural gas price assumptions, reduced volume forecasts, and higher royalty, operating cost and capital expenditure assumptions. We also recorded property impairments of $66 million in our R&M segment, primarily associated with planned asset dispositions.
The following table shows the values of assets at December 31, 2009, by major category, measured at fair value on a nonrecurring basis in periods subsequent to their initial recognition.
Net properties, plants and equipment held for use with a carrying amount of $610 million were written down to a fair value of $210 million, resulting in a before-tax loss of $385 million (including impact of exchange rates). The fair values were determined by the application of an internal discounted cash flow model using estimates of future production, prices and a discount rate believed to be consistent with those used by principal market participants.
During the year, net properties, plants and equipment held for sale with a carrying amount of $178 million were written down to a fair value of $121 million ($91 million still unsold at year end), less cost to sell of $5 million for a net $116 million, resulting in a before-tax loss of $62 million. The fair values were largely based on binding negotiated prices with third parties, with some adjusted for the fair value of certain liabilities retained.
At December 31, 2009 certain equity method investments associated with our E&P segment were determined to have a fair value below carrying amount and the impairment was considered to be other than temporary. As a result, those investments with a book value of $2,070 million were written down to a fair value of $1,784 million resulting in a charge of $286 million before-tax, which is included in the “Equity in earnings of affiliates” line of the consolidated statement of operations. The fair values were determined by the application
of an internal discounted cash flow model using estimates of future production, prices and a discount rate believed to be consistent with those used by principal market participants, as well as reference to market analysis of certain similar undeveloped properties owned by one of the investees.
As a result of the economic downturn in the fourth quarter of 2008, the outlook for crude oil and natural gas prices, refining margins, and power spreads sharply deteriorated. In addition, current project economics in our E&P segment resulted in revised capital spending plans. Because of these factors, certain E&P, R&M and Emerging Businesses properties no longer passed the undiscounted cash flow tests and had to be written down to fair value. Consequently, we recorded property impairments of approximately $1,480 million, primarily consisting of various producing fields in the U.S. Lower 48 and Canada, one U.S. and one European refinery and a U.S. power generation facility. In addition, we recorded property impairments for increased asset retirement obligations, vacant office buildings in the United States and canceled R&M capital projects.
During 2007, we recorded property impairments of $257 million associated with planned asset dispositions in our E&P and R&M segments. E&P also recorded additional property impairments in 2007 resulting from increased asset retirement obligations, downward reserve revisions and higher projected operating costs for certain fields in North America and the United Kingdom and an abandoned project in Alaska. R&M recorded additional property impairments associated with various terminals and pipelines, primarily in the United States. Also, we reported a $128 million benefit in 2007 for the subsequent increase in the fair value of certain assets impaired in the prior year, primarily to reflect finalized sales agreements. This gain was included in the “Impairments-Other” line of the consolidated statement of operations.
Note 11-Asset Retirement Obligations and Accrued Environmental Costs
Asset retirement obligations and accrued environmental costs at December 31 were:
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Classified as a current liability on the balance sheet, under the caption “Other accruals.” Includes $14 million related to assets held for sale in 2008.
Asset Retirement Obligations
We are required to record the fair value of a liability for an asset retirement obligation when it is incurred (typically when the asset is installed at the production location). When the liability is initially recorded, the entity capitalizes the cost by increasing the carrying amount of the related properties, plants and equipment. Over time, the liability increases for the change in its present value, while the capitalized cost depreciates over the useful life of the related asset.
We have numerous asset removal obligations that we are required to perform under law or contract once an asset is permanently taken out of service. Most of these obligations are not expected to be paid until several years, or decades, in the future and will be funded from general company resources at the time of removal. Our largest individual obligations involve removal and disposal of offshore oil and gas platforms around the world, oil and gas production facilities and pipelines in Alaska, and asbestos abatement at refineries.
During 2009 and 2008, our overall asset retirement obligation changed as follows:
Accrued Environmental Costs
Total environmental accruals at December 31, 2009 and 2008, were $1,017 million and $979 million, respectively. The 2009 increase in total accrued environmental costs is due to new accruals, accrual adjustments and accretion exceeding payments during the year on accrued environmental costs.
We had accrued environmental costs of $632 million and $652 million at December 31, 2009 and 2008, respectively, primarily related to cleanup at domestic refineries and underground storage tanks at U.S. service stations, and remediation activities required by Canada and the state of Alaska at exploration and production sites. We had also accrued in Corporate and Other $292 million and $234 million of environmental costs associated with nonoperator sites at December 31, 2009 and 2008, respectively. In addition, $93 million was included at both December 31, 2009 and 2008, where the company has been named a potentially responsible party under the Federal Comprehensive Environmental Response, Compensation and Liability Act, or similar state laws. Accrued environmental liabilities will be paid over periods extending up to 30 years.
Because a large portion of the accrued environmental costs were acquired in various business combinations, they are discounted obligations. Expected expenditures for acquired environmental obligations are discounted using a weighted-average 5 percent discount factor, resulting in an accrued balance for acquired environmental liabilities of $627 million at December 31, 2009. The expected future undiscounted payments related to the portion of the accrued environmental costs that have been discounted are: $90 million in 2010, $87 million in 2011, $67 million in 2012, $48 million in 2013, $39 million in 2014, and $358 million for all future years after 2014.
Note 12-Debt
Long-term debt at December 31 was:
Maturities of long-term borrowings, inclusive of net unamortized premiums and discounts, in 2010 through 2014 are: $1,728 million, $3,972 million, $2,345 million, $1,277 million and $1,532 million, respectively. At December 31, 2009, we had classified $1,060 million of short-term debt as long-term debt, based on our ability and intent to refinance the obligation on a long-term basis under our revolving credit facilities.
In February 2009, we issued $1.5 billion of 4.75% Notes due 2014, $2.25 billion of 5.75% Notes due 2019, and $2.25 billion of 6.50% Notes due 2039, and in May 2009, we issued $1.5 billion of 4.60% Notes due 2015, $1.0 billion of 6.00% Notes due 2020 and an additional $500 million of 6.50% Notes due 2039. The proceeds from the notes were primarily used to reduce outstanding commercial paper balances and for general corporate purposes.
During 2009, we used proceeds from the issuance of commercial paper to redeem $284 million of 6.375% Notes and $950 million of Floating Rate Notes upon their maturity, and prepaid $750 million of Floating Rate Five-Year Term Notes.
At December 31, 2009, we had two revolving credit facilities totaling $7.85 billion, consisting of a $7.35 billion facility expiring in September 2012 and a $500 million facility expiring in July 2012. Our revolving credit facilities may be used as direct bank borrowings, as support for issuances of letters of credit totaling up to $750 million, or as support for our commercial paper programs. The revolving credit facilities are broadly syndicated among financial institutions and do not contain any material adverse change provisions or any covenants requiring maintenance of specified financial ratios or ratings. The facility agreements contain a cross-default provision relating to the failure to pay principal or interest on other debt obligations of $200 million or more by ConocoPhillips, or by any of its consolidated subsidiaries.
Credit facility borrowings may bear interest at a margin above rates offered by certain designated banks in the London interbank market or at a margin above the overnight federal funds rate or prime rates offered by certain designated banks in the United States. The agreements call for commitment fees on available, but unused, amounts. The agreements also contain early termination rights if our current directors or their approved successors cease to be a majority of the Board of Directors.
We have two commercial paper programs: the ConocoPhillips $6.35 billion program, primarily a funding source for short-term working capital needs, and the ConocoPhillips Qatar Funding Ltd. $1.5 billion commercial paper program, which is used to fund commitments relating to the Qatargas 3 Project. Commercial paper maturities are generally limited to 90 days. At both December 31, 2009 and 2008, we had no direct outstanding borrowings under the revolving credit facilities, but $40 million in letters of credit had been issued. In addition, under the two commercial paper programs, there was $1,300 million of commercial paper outstanding at December 31, 2009, compared with $6,933 million at December 31, 2008. Since we had $1,300 million of commercial paper outstanding and had issued $40 million of letters of credit, we had access to $6.5 billion in borrowing capacity under our revolving credit facilities at December 31, 2009.
Note 13-Joint Venture Acquisition Obligation
On January 3, 2007, we closed on a business venture with EnCana Corporation (now Cenovus). As a part of the transaction, we are obligated to contribute $7.5 billion, plus interest, over a 10-year period that began in 2007, to the upstream business venture, FCCL Partnership, formed as a result of the transaction. An initial cash contribution of $188 million was made upon closing in January of 2007, and was included in the “Capital expenditures and investments” line on our consolidated statement of cash flows.
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 $660 million was short-term and was included in the “Accounts payable-related parties” line on our December 31, 2009, consolidated balance sheet. The principal portion of these payments, which totaled $625 million in 2009, is included in the “Other” line in the financing activities section of our consolidated statement of cash flows. Interest accrues at a fixed annual rate of 5.3 percent on the unpaid principal balance. Fifty percent of the quarterly interest payment is reflected as a capital contribution and is included in the “Capital expenditures and investments” line on our consolidated statement of cash flows.
Note 14-Guarantees
At December 31, 2009, we were liable for certain contingent obligations under various contractual arrangements as described below. We recognize a liability, at inception, for the fair value of our obligation as a guarantor for newly issued or modified guarantees. Unless the carrying amount of the liability is noted below, we have not recognized a liability either because the guarantees were issued prior to December 31, 2002, or because the fair value of the obligation is immaterial. In addition, unless otherwise stated we are not currently performing with any significance under the guarantee and expect future performance to be either immaterial or have only a remote chance of occurrence.
Construction Completion Guarantees
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In December 2005, we issued a construction completion guarantee for 30 percent of the $4 billion in loan facilities of Qatargas 3, which are being used to finance the construction of an LNG train in Qatar. Of the $4 billion in loan facilities, we committed to provide $1.2 billion. The maximum potential amount of future payments to third-party lenders under the guarantee is estimated to be $850 million, which could become payable if the full debt financing is utilized and completion of the Qatargas 3 Project is not achieved. The project financing will be nonrecourse to ConocoPhillips upon certified completion, expected in 2011. At December 31, 2009, the carrying value of the guarantee to third-party lenders was $11 million.
Guarantees of Joint Venture Debt
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In June 2006, we issued a guarantee for our ownership percentage of $2 billion in credit facilities of Rockies Express Pipeline LLC, operated by Kinder Morgan Energy Partners, L.P. At December 31, 2009, Rockies Express had $1,673 million outstanding under the credit facilities, with our 25 percent guarantee equaling $418 million. The maximum potential amount of future payments to third-party lenders under the guarantee is estimated to be $500 million, which could become payable if the credit facilities are fully utilized and Rockies Express fails to meet its obligations under the credit agreement. The guarantee expires in April 2011. At December 31, 2009, the total carrying value of this guarantee to third-party lenders was $11 million.
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At December 31, 2009, we had guarantees outstanding for our portion of joint venture debt obligations, which have terms of up to 16 years. The maximum potential amount of future payments under the guarantees is approximately $80 million. Payment would be required if a joint venture defaults on its debt obligations.
Other Guarantees
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In conjunction with our purchase of a 50 percent ownership interest in APLNG from Origin Energy in October 2008, we agreed to participate, if and when requested, in any parent company guarantees that were outstanding at the time we purchased our interest in APLNG. These parent company guarantees cover the obligation of APLNG to deliver natural gas under several sales agreements with remaining terms of 7 to 22 years. Our maximum potential amount of future payments, or cost of volume delivery, under these guarantees is estimated to be $1,450 million ($3,140 million in the event of intentional or reckless breach) at December 2009 exchange rates based on our 50 percent share of the remaining contracted volumes, which could become payable if APLNG fails to meet its obligations under these agreements and the obligations cannot otherwise be mitigated. Future payments are considered unlikely, as the payments, or cost of volume delivery, would only be triggered if APLNG does not have enough natural gas to meet these sales commitments and if the partners do not make necessary equity contributions into APLNG.
•
We have other guarantees with maximum future potential payment amounts totaling $506 million, which consist primarily of dealer and jobber loan guarantees to support our marketing business, guarantees to fund the short-term cash liquidity deficits of certain joint ventures, a guarantee of minimum charter revenue for two LNG vessels, one small construction completion guarantee, guarantees relating to the startup of a refining joint venture, guarantees of the lease payment obligations of a joint venture, and guarantees of the residual value of leased corporate aircraft. At December 31,
2009, the carrying value of these guarantees to third-party lenders was $1 million. These guarantees generally extend up to 15 years or life of the venture.
In the third quarter of 2009, we sold our remaining ownership interest in four Keystone Pipeline entities to TransCanada Corporation. As a result, we no longer have any financial guarantees related to Keystone.
Indemnifications
Over the years, we have entered into various agreements to sell ownership interests in certain corporations, joint ventures and assets that gave rise to qualifying indemnifications. Agreements associated with these sales include indemnifications for taxes, environmental liabilities, permits and licenses, employee claims, real estate indemnity against tenant defaults, and litigation. The terms of these indemnifications vary greatly. The majority of these indemnifications are related to environmental issues, the term is generally indefinite and the maximum amount of future payments is generally unlimited. The carrying amount recorded for these indemnifications at December 31, 2009, was $412 million. We amortize the indemnification liability over the relevant time period, if one exists, based on the facts and circumstances surrounding each type of indemnity. In cases where the indemnification term is indefinite, we will reverse the liability when we have information the liability is essentially relieved or amortize the liability over an appropriate time period as the fair value of our indemnification exposure declines. Although it is reasonably possible future payments may exceed amounts recorded, due to the nature of the indemnifications, it is not possible to make a reasonable estimate of the maximum potential amount of future payments. Included in the recorded carrying amount were $258 million of environmental accruals for known contamination that are included in asset retirement obligations and accrued environmental costs at December 31, 2009. For additional information about environmental liabilities, see Note 15-Contingencies and Commitments.
Note 15-Contingencies and Commitments
In the case of all known contingencies (other than those related to income taxes), we accrue a liability when the loss is probable and the amount is reasonably estimable. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. We do not reduce these liabilities for potential insurance or third-party recoveries. If applicable, we accrue receivables for probable insurance or other third-party recoveries. In the case of income-tax-related contingencies, we use a cumulative probability-weighted loss accrual in cases where sustaining a tax position is less than certain. See Note 20-Income Taxes, for additional information about income-tax-related contingencies.
Based on currently available information, we believe it is remote that future costs related to known contingent liability exposures will exceed current accruals by an amount that would have a material adverse impact on our consolidated financial statements. As we learn new facts concerning contingencies, we reassess our position both with respect to accrued liabilities and other potential exposures. Estimates particularly sensitive to future changes include contingent liabilities recorded for environmental remediation, tax and legal matters. Estimated future environmental remediation costs are subject to change due to such factors as the uncertain magnitude of cleanup costs, the unknown time and extent of such remedial actions that may be required, and the determination of our liability in proportion to that of other responsible parties. Estimated future costs related to tax and legal matters are subject to change as events evolve and as additional information becomes available during the administrative and litigation processes.
Environmental
We are subject to federal, state and local environmental laws and regulations. These may result in obligations to remove or mitigate the effects on the environment of the placement, storage, disposal or release of certain chemical, mineral and petroleum substances at various sites. When we prepare our consolidated financial statements, we record accruals for environmental liabilities based on management’s best estimates, using all information that is available at the time. We measure estimates and base liabilities on currently available facts, existing technology, and presently enacted laws and regulations, taking into account stakeholder and business considerations. When measuring environmental liabilities, we also consider our prior experience in
remediation of contaminated sites, other companies’ cleanup experience, and data released by the U.S. Environmental Protection Agency (EPA) or other organizations. We consider unasserted claims in our determination of environmental liabilities, and we accrue them in the period they are both probable and reasonably estimable.
Although liability of those potentially responsible for environmental remediation costs is generally joint and several for federal sites and frequently so for state sites, we are usually only one of many companies cited at a particular site. Due to the joint and several liabilities, we could be responsible for all cleanup costs related to any site at which we have been designated as a potentially responsible party. If we were solely responsible, the costs, in some cases, could be material to our results of operations, capital resources or liquidity, or to those of one of our segments. However, settlements and costs incurred in matters that previously have been resolved have not been material to our results of operations or financial condition. We have been successful to date in sharing cleanup costs with other financially sound companies. Many of the sites at which we are potentially responsible are still under investigation by the EPA or the state agencies concerned. Prior to actual cleanup, those potentially responsible normally assess the site conditions, apportion responsibility and determine the appropriate remediation. In some instances, we may have no liability or may attain a settlement of liability. Where it appears that other potentially responsible parties may be financially unable to bear their proportional share, we consider this inability in estimating our potential liability, and we adjust our accruals accordingly.
As a result of various acquisitions in the past, we assumed certain environmental obligations. Some of these environmental obligations are mitigated by indemnifications made by others for our benefit and some of the indemnifications are subject to dollar limits and time limits. We have not recorded accruals for any potential contingent liabilities that we expect to be funded by the prior owners under these indemnifications.
We are currently participating in environmental assessments and cleanups at numerous federal Superfund and comparable state sites. After an assessment of environmental exposures for cleanup and other costs, we make accruals on an undiscounted basis (except those acquired in a purchase business combination, which we record on a discounted basis) for planned investigation and remediation activities for sites where it is probable future costs will be incurred and these costs can be reasonably estimated. We have not reduced these accruals for possible insurance recoveries. In the future, we may be involved in additional environmental assessments, cleanups and proceedings. See Note 11-Asset Retirement Obligations and Accrued Environmental Costs, for a summary of our accrued environmental liabilities.
Legal Proceedings
Our legal organization applies its knowledge, experience and professional judgment to the specific characteristics of our cases, employing a litigation management process to manage and monitor the legal proceedings against us. Our process facilitates the early evaluation and quantification of potential exposures in individual cases. This process also enables us to track those cases that have been scheduled for trial, as well as the pace of settlement discussions in individual matters. Based on professional judgment and experience in using these litigation management tools and available information about current developments in all our cases, our legal organization believes there is a remote likelihood 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.
Other Contingencies
We have contingent liabilities resulting from throughput agreements with pipeline and processing companies not associated with financing arrangements. Under these agreements, we may be required to provide any such company with additional funds through advances and penalties for fees related to throughput capacity not utilized. In addition, at December 31, 2009, we had performance obligations secured by letters of credit of $1,624 million (of which $40 million was issued under the provisions of our revolving credit facility, and the remainder was issued as direct bank letters of credit) related to various purchase commitments for materials, supplies, services and items of permanent investment incident to the ordinary conduct of business. See Note 10-Impairments, for additional information about expropriated assets in Ecuador and Venezuela and the contingencies related to receiving adequate compensation for our oil interests related to these assets.
Long-Term Throughput Agreements and Take-or-Pay Agreements
We have certain throughput agreements and take-or-pay agreements in support of financing arrangements. The agreements typically provide for natural gas or crude oil transportation to be used in the ordinary course of the company’s business. The aggregate amounts of estimated payments under these various agreements are: 2010-$88 million; 2011-$88 million; 2012-$84 million; 2013-$83 million; 2014-$84 million; and 2015 and after-$273 million. Total payments under the agreements were $77 million in 2009, $75 million in 2008 and $67 million in 2007.
Note 16-Financial Instruments and Derivative Contracts
Derivative Instruments
We use financial and commodity-based derivative contracts to manage exposures to fluctuations in foreign currency exchange rates, commodity prices, and interest rates, or to capture market opportunities. Since we are not currently using hedge accounting, all gains and losses, realized or unrealized, from derivative contracts have been recognized in the consolidated statement of operations. Gains and losses from derivative contracts held for trading not directly related to our physical business, whether realized or unrealized, have been reported net in other income.
Purchase and sales contracts for commodities that are readily convertible to cash (e.g., crude oil, natural gas and gasoline) are recorded on the balance sheet as derivatives unless the contracts are for quantities we expect to use or sell over a reasonable period in the normal course of business (i.e., contracts eligible for the normal purchases and normal sales exception). We record most of our contracts to buy or sell natural gas and the majority of our contracts to sell power as derivatives, but we do apply the normal purchases and normal sales exception to certain long-term contracts to sell our natural gas production. We generally apply this normal purchases and normal sales exception to eligible crude oil and refined product commodity purchase and sales contracts; however, we may elect not to apply this exception (e.g., when another derivative instrument will be used to mitigate the risk of the purchase or sale contract but hedge accounting will not be applied, in which case both the purchase or sales contract and the derivative contract mitigating the resulting risk will be recorded on the balance sheet at fair value).
We value our exchange-cleared derivatives using closing prices provided by the exchange as of the balance sheet date, and these are classified as Level 1 in the fair value hierarchy. Over-the-counter (OTC) financial swaps and physical commodity forward purchase and sale contracts are generally valued using quotations provided by brokers and price index developers such as Platts and Oil Price Information Service. These quotes are corroborated with market data and are classified as Level 2. In certain less liquid markets or for longer-term contracts, forward prices are not as readily available. In these circumstances, OTC swaps and physical commodity purchase and sale contracts are valued using internally developed methodologies that consider historical relationships among various commodities that result in management’s best estimate of fair value. These contracts are classified as Level 3.
Exchange-cleared financial options are valued using exchange closing prices and are classified as Level 1. Financial OTC and physical commodity options are valued using industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and contractual prices for the underlying instruments, as well as other relevant economic measures. The degree to which these inputs are observable in the forward markets determines whether the options are classified as Level 2 or 3.
We use a mid-market pricing convention (the mid-point between bid and ask prices). When appropriate, valuations are adjusted to reflect credit considerations, generally based on available market evidence.
The fair value hierarchy for our derivative assets and liabilities accounted for at fair value on a recurring basis was:
The derivative values above are based on analysis of each contract as the fundamental unit of account; therefore, derivative assets and liabilities with the same counterparty are not reflected net where the legal right of offset exists. Gains or losses from contracts in one level may be offset by gains or losses on contracts in another level or by changes in values of physical contracts or positions that are not reflected in the table above.
The fair value of net commodity derivatives classified as Level 3 in the fair value hierarchy changed as follows during 2009 and 2008:
The amounts of Level 3 gains (losses) included in earnings were:
Commodity Derivative Contracts-We operate in the worldwide crude oil, refined product, natural gas, natural gas liquids and electric power markets and are exposed to fluctuations in the prices for these commodities. These fluctuations can affect our revenues, as well as the cost of operating, investing and financing activities. Generally, our policy is to remain exposed to the market prices of commodities. However, we use futures, forwards, swaps and options in various markets to balance physical systems, meet customer needs, manage price exposures on specific transactions, and do a limited, immaterial amount of trading not directly related to our physical business. These activities may move our risk profile away from market average prices.
The fair value of commodity derivative assets and liabilities at December 31, 2009, and the line items where they appear on our consolidated balance sheet were:
Hedge accounting has not been used for any items in the table unless specified otherwise. The amounts shown are presented gross (i.e., without netting assets and liabilities with the same counterparty where the right of offset and intent to net exist).
The gains (losses) from commodity derivatives incurred during 2009, and the line items where they appear on our consolidated statement of operations were:
Hedge accounting has not been used for any items in the table unless specified otherwise.
The table below summarizes our material net exposures as of December 31, 2009, resulting from outstanding commodity derivative contracts. These financial and physical derivative contracts are primarily used to manage price exposure on our underlying operations. The underlying exposures may be from non-derivative positions such as inventory volumes or firm natural gas transport contracts. Financial derivative contracts may also offset physical derivative contracts, such as forward sales contracts.
Currency Exchange Rate Derivative Contracts-We have foreign currency exchange rate risk resulting from international operations. We do not comprehensively hedge the exposure to movements in currency exchange rates, although we may choose to selectively hedge certain foreign currency exchange rate exposures, such as firm commitments for capital projects or local currency tax payments, dividends, and cash returns from net investments in foreign affiliates to be remitted within the coming year.
The fair value of foreign currency derivative assets and liabilities open at December 31, 2009, and the line items where they appear on our consolidated balance sheet were:
Hedge accounting has not been used for any items in the table unless specified otherwise. The amounts shown are presented gross.
Gains and losses from foreign currency derivatives at December 31, 2009, and the line item where they appear on our consolidated statement of operations were:
Millions
of Dollars
Foreign currency transaction (gains) losses
$ (121 )
Hedge accounting has not been used for any items in the table unless specified otherwise.
As of December 31, 2009, we had the following net position of outstanding foreign currency swap contracts, entered into primarily to hedge price exposure in our international operations.
*
Denominated in U.S. dollars (USD) and euros (EUR).
**
Primarily euro, Canadian dollar, Norwegian krone and British pound.
Credit Risk
Financial instruments potentially exposed to concentrations of credit risk consist primarily of cash equivalents, over-the-counter derivative contracts and trade receivables. Our cash equivalents are placed in high-quality commercial paper, money market funds and time deposits with major international banks and financial institutions.
The credit risk from our over-the-counter derivative contracts, such as forwards and swaps, derives from the counterparty to the transaction, typically a major bank or financial institution. Individual counterparty exposure is managed within predetermined credit limits and includes the use of cash-call margins when appropriate, thereby reducing the risk of significant nonperformance. We also use futures contracts, but futures have a negligible credit risk because they are traded on the New York Mercantile Exchange or the ICE Futures.
Our trade receivables result primarily from our petroleum operations and reflect a broad national and international customer base, which limits our exposure to concentrations of credit risk. The majority of these receivables have payment terms of 30 days or less, and we continually monitor this exposure and the creditworthiness of the counterparties. We do not generally require collateral to limit the exposure to loss; however, we will sometimes use letters of credit, prepayments, and master netting arrangements to mitigate credit risk with counterparties that both buy from and sell to us, as these agreements permit the amounts owed by us or owed to others to be offset against amounts due us.
Certain of our derivative instruments contain provisions that require us to post collateral if the derivative exposure exceeds a threshold amount. We have contracts with fixed threshold amounts and other contracts with variable threshold amounts that are contingent on our credit rating. The variable threshold amounts typically decline for lower credit ratings, while both the variable and fixed threshold amounts typically revert to zero if we fall below investment grade. Cash is the primary collateral in all contracts; however, many also permit us to post letters of credit as collateral.
The aggregate fair value of all derivative instruments with such credit-risk-related contingent features that were in a liability position on December 31, 2009, was $381 million, for which no collateral was posted. If our credit rating were lowered one level from its “A” rating (per Standard and Poor’s) on December 31, 2009, we would be required to post no additional collateral to our counterparties. If we were downgraded below investment grade, we would be required to post $381 million of additional collateral, either with cash or letters of credit.
Fair Values of Financial Instruments
We used the following methods and assumptions to estimate the fair value of financial instruments:
•
Cash and cash equivalents: The carrying amount reported on the balance sheet approximates fair value.
•
Accounts and notes receivable: The carrying amount reported on the balance sheet approximates fair value.
•
Investment in LUKOIL shares: See Note 6-Investments, Loans and Long-Term Receivables, for a discussion of the carrying value and fair value of our investment in LUKOIL shares.
•
Debt: The carrying amount of our floating-rate debt approximates fair value. The fair value of the fixed-rate debt is estimated based on quoted market prices.
•
Fixed-rate 5.3 percent joint venture acquisition obligation: Fair value is estimated based on the net present value of the future cash flows, discounted at a December 31 effective yield rate of 2.63 percent, based on yields of U.S. Treasury securities of similar average duration adjusted for our average credit risk spread and the amortizing nature of the obligation principal. See Note 13-Joint Venture Acquisition Obligation, for additional information.
•
Swaps: Fair value is estimated based on forward market prices and approximates the exit price at period end. When forward market prices are not available, they are estimated using the forward prices of a similar commodity with adjustments for differences in quality or location.
•
Futures: Fair values are based on quoted market prices obtained from the New York Mercantile Exchange, the ICE Futures, or other traded exchanges.
•
Forward-exchange contracts: Fair value is estimated by comparing the contract rate to the forward rate in effect on December 31 and approximates the exit price at that date.
Certain of our commodity derivative and financial instruments at December 31 were:
The amounts shown for derivatives in the preceding table are presented net (i.e., assets and liabilities with the same counterparty are netted where the right of offset and intent to net exist). In addition, the 2009 commodity derivative assets and liabilities appear net of $70 million of obligations to return cash collateral and $148 million of rights to reclaim cash collateral, respectively. The 2008 commodity derivative assets and liabilities appear net of $123 million of obligations to return cash collateral and $332 million of rights to reclaim cash collateral, respectively. No collateral was deposited or held for the foreign currency derivatives.
Note 17-Equity
Common Stock
The changes in our shares of common stock, as categorized in the equity section of the balance sheet, were:
Preferred Stock
We have 500 million shares of preferred stock authorized, par value $.01 per share, none of which was issued or outstanding at December 31, 2009 or 2008.
Noncontrolling Interests
At December 31, 2009 and 2008, we had outstanding $590 million and $1,100 million, respectively, of equity in less-than-wholly owned consolidated subsidiaries held by noncontrolling interest owners. The decrease from 2008 was primarily due to Ashford Energy Capital S.A., a wholly owned consolidated subsidiary, redeeming for $500 million, plus accrued dividends, the investment in Ashford held by Cold Spring Finance S.a.r.l. in the third quarter of 2009. The difference between the redemption amount and the carrying value of the investment was $12 million. The redemption amount was included as a cash outflow in the “Other” line in the financing activities section of our consolidated statement of cash flows.
The remaining noncontrolling interest amounts are primarily related to operating joint ventures we control. The largest of these, amounting to $565 million at December 31, 2009, and $580 million at December 31, 2008, was related to Darwin LNG operations, located in Australia’s Northern Territory.
Preferred Share Purchase Rights
In 2002, our Board of Directors authorized and declared a dividend of one preferred share purchase right for each common share outstanding, and authorized and directed the issuance of one right per common share for any newly issued shares. The rights have certain anti-takeover effects. The rights will cause substantial dilution to a person or group that attempts to acquire ConocoPhillips on terms not approved by the Board of Directors. However, since the rights may either be redeemed or otherwise made inapplicable by ConocoPhillips prior to an acquirer obtaining beneficial ownership of 15 percent or more of ConocoPhillips’ common stock, the rights should not interfere with any merger or business combination approved by the Board of Directors prior to that occurrence. The rights, which expire June 30, 2012, will be exercisable only if a person or group acquires 15 percent or more of the company’s common stock or commences a tender offer that would result in ownership of 15 percent or more of the common stock. Each right would entitle stockholders to buy one one-hundredth of a share of preferred stock at an exercise price of $300. If an acquirer obtains 15 percent or more of ConocoPhillips’ common stock, then each right will be adjusted so that it will entitle the holder (other than the acquirer, whose rights will become void) to purchase, for the then exercise price, a number of shares of ConocoPhillips’ common stock equal in value to two times the exercise price of the right. In addition, the rights enable holders to purchase the stock of an acquiring company at a discount, depending on specific circumstances. We may redeem the rights in whole, but not in part, for one cent per right.
Note 18-Non-Mineral Leases
The company leases ocean transport vessels, tugboats, barges, pipelines, railcars, corporate aircraft, service stations, drilling equipment, computers, office buildings and other facilities and equipment. Certain leases include escalation clauses for adjusting rental payments to reflect changes in price indices, as well as renewal options and/or options to purchase the leased property for the fair market value at the end of the lease term. There are no significant restrictions imposed on us by the leasing agreements in regards to dividends, asset dispositions or borrowing ability. Leased assets under capital leases were not significant in any period presented.
At December 31, 2009, future minimum rental payments due under noncancelable leases were:
*
Includes $53 million related to railcars subleased to Chevron Phillips Chemical Company LLC, a related party.
Operating lease rental expense for the years ended December 31 was:
*
Includes $21 million, $22 million and $27 million of contingent rentals in 2009, 2008 and 2007, respectively. Contingent rentals primarily are related to retail sites and refining equipment, and are based on volume of product sold or throughput.
Note 19-Employee Benefit Plans
Pension and Postretirement Plans
An analysis of the projected benefit obligations for our pension plans and accumulated benefit obligations for our postretirement health and life insurance plans follows:
For both U.S. and international pensions, the overall expected long-term rate of return is developed from the expected future return of each asset class, weighted by the expected allocation of pension assets to that asset class. We rely on a variety of independent market forecasts in developing the expected rate of return for each class of assets.
At December 31, 2007, all of our plans used a December 31 measurement date, except for a plan in the United Kingdom, which had a September 30 measurement date. To comply with the provisions of SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans-an amendment of FASB Statements No. 87, 88, 106, and 132(R),” as codified into FASB ASC Topic 715, “Compensation-Retirement Benefits,” we changed the measurement date for the U.K. plan from September 30 to December 31 for our 2008 consolidated financial statements. We elected to implement the change by remeasuring the U.K. plan assets and obligations as of December 31, 2007. To implement the change in measurement date, we recognized the $10 million (net of tax) of net periodic pension cost incurred from October 1, 2007, to December 31, 2007, as an adjustment to 2008 beginning retained earnings.
Included in other comprehensive income at December 31 were the following before-tax amounts that had not been recognized in net periodic postretirement benefit cost:
Amounts included in accumulated other comprehensive income at December 31, 2009, that are expected to be amortized into net periodic postretirement cost during 2010 are provided below:
Millions of Dollars
Pension Benefits
U.S.
Int’l.
Other Benefits
Unrecognized net actuarial loss (gain)
$
(7 )
Unrecognized prior service cost
For our tax-qualified pension plans with projected benefit obligations in excess of plan assets, the projected benefit obligation, the accumulated benefit obligation, and the fair value of plan assets were $7,145 million, $5,653 million, and $4,748 million, respectively, at December 31, 2009 and $6,092 million, $5,289 million, and $3,624 million, respectively, at December 31, 2008.
For our unfunded nonqualified key employee supplemental pension plans, the projected benefit obligation and the accumulated benefit obligation were $419 million and $355 million, respectively, at December 31, 2009, and were $391 million and $334 million, respectively, at December 31, 2008.
The components of net periodic benefit cost of all defined benefit plans are presented in the following table:
We recognized pension settlement losses of $15 million, $18 million and $2 million and special termination benefits of $5 million, $2 million and $1 million in 2009, 2008 and 2007, respectively. Curtailment losses of $1 million were recognized in 2007.
In determining net pension and other postretirement benefit costs, we amortize prior service costs on a straight-line basis over the average remaining service period of employees expected to receive benefits under the plan. For net actuarial gains and losses, we amortize 10 percent of the unamortized balance each year.
We have multiple nonpension postretirement benefit plans for health and life insurance. The health care plans are contributory and subject to various cost sharing features, with participant and company contributions adjusted annually; the life insurance plans are noncontributory. The measurement of the accumulated postretirement benefit obligation assumes a health care cost trend rate of 8.25 percent in 2010 that declines to 5.0 percent by 2023. A one-percentage-point change in the assumed health care cost trend rate would have the following effects on the 2009 amounts:
Millions of Dollars
One-Percentage-Point
Increase
Decrease
Effect on total of service and interest cost components
$
(1 )
Effect on the postretirement benefit obligation
(6 )
Plan Assets-We follow a policy of broadly diversifying pension plan assets across asset classes, investment managers, and individual holdings. As a result, our plan assets have no significant concentrations of credit risk. Asset classes that are considered appropriate include U.S. equities, non-U.S. equities, U.S. fixed income, non-U.S. fixed income, real estate, and private equity investments. Plan fiduciaries may consider and add other asset classes to the investment program from time to time. The target allocations for plan assets are 56 percent equity securities, 35 percent debt securities, 5 percent real estate, and 4 percent in all other types of investments. Generally, the investments in the plans are publicly traded, therefore minimizing liquidity risk in the portfolio.
Following is a description of the valuation methodologies used for the pension plan assets. There have been no changes in the methodologies used at December 31, 2009 and 2008.
Cash is valued at cost, which approximates fair value. Fair values of cash equivalents categorized in Level 2 are valued using observable yield curves, discounting and interest rates.
Fair values of diversified equity securities, preferred stock and government debt securities categorized in Level 1 are primarily based on quoted market prices.
Fair values of diversified corporate debt securities, mortgage-backed securities and government debt securities categorized in Level 2 are estimated using recently executed transactions and market price quotations. If there have been no market transactions in a particular fixed income security, its fair market value is calculated by pricing models that benchmark the security against other securities with actual market prices. When observable price quotations are not available, fair value is based on pricing models that use something other than actual market prices (e.g., observable inputs such as benchmark yields, reported trades, issuer spreads for similar securities), and these securities are categorized in Level 3 of the fair value hierarchy.
Fair values of investments in common/collective trusts are determined by the issuer of each fund based on the fair value of the underlying assets.
Fair values of mutual funds are valued based on quoted market prices, which represent the net asset value of shares held.
Fair values of derivatives, which include options and swaps, are generally calculated from pricing models with market input parameters from third-party sources. Also included in this category are cash and short-term investments required to be held as collateral by brokers based on the fair value of certain derivative instruments. Some derivatives are publicly traded, and fair values for these are based on quoted market prices.
Private equity funds are valued at fair value using a variety of methods including consideration of the initial cost of securities or properties acquired, recent transactions in the same or comparable securities or properties, fundamental analytical techniques, real estate valuation techniques and other methods that reference third-party sources for discount and capitalization rates.
Fair values of insurance contracts are valued at the present value of the future benefit payments owed by the insurance company to the Plans’ participants.
Fair values of real estate investments are valued using real estate valuation techniques and other methods that include reference to third-party sources and sales comparables where available.
A portion of U.S. pension plan assets is held as a participating interest in an insurance annuity contract. This participating interest is calculated as the market value of investments held under this contract, less the accumulated benefit obligation covered by the contract. The participation interest is classified as Level 3 in the fair value hierarchy as the fair value is determined via a combination of comparison to quoted market prices and estimation using recently executed transactions and market price quotations for contract assets, and an actuarial present value computation for contract obligations. At December 31, 2009, the participating interest in the annuity contract was valued at $94 million and consisted of $349 million in debt securities, less $255 million for the accumulated benefit obligation covered by the contract. At December 31, 2008, the participating interest in the annuity contract was valued at $138 million and consisted of $400 million in debt securities, less $262 million for the accumulated benefit obligation covered by the contract. The net change from 2008 to 2009 is due to a decrease in the fair market value of the underlying investments of $51 million and a decrease in the present value of the contract obligation of $7 million. The participating interest is not available for meeting general pension benefit obligations in the near term. No future company contributions are required and no new benefits are being accrued under this insurance annuity contract.
The fair values of our pension plan assets at December 31, 2009, by asset class are as follows:
*
Excludes the participating interest in the annuity contract with a net asset value of $94 million and net payables related to security transactions of $(14) million.
The table below sets forth a summary of changes in the fair value of the Level 3 plan assets for the year ended December 31, 2009:
Our funding policy for U.S. plans is to contribute at least the minimum required by the Employee Retirement Income Security Act of 1974 and the Internal Revenue Code of 1986, as amended. Contributions to foreign plans are dependent upon local laws and tax regulations. In 2010, we expect to contribute approximately $530 million to our domestic qualified and nonqualified pension and postretirement benefit plans and $230 million to our international qualified and nonqualified pension and postretirement benefit plans.
The following benefit payments, which are exclusive of amounts to be paid from the participating annuity contract and which reflect expected future service, as appropriate, are expected to be paid:
Severance Accrual
As a result of the 2008 business environment’s impact on our operating and capital plans, a reduction in our overall employee work force occurred in 2009. Various business units and staff groups recorded accruals in the fourth quarter of 2008 for severance and related employee benefits totaling $162 million. The following table summarizes our severance accrual activity at December 31:
The remaining balance at December 31, 2009, of $12 million is classified as short term.
Defined Contribution Plans
Most U.S. employees are eligible to participate in the ConocoPhillips Savings Plan (CPSP). Employees can deposit up to 30 percent of their eligible pay up to the statutory limit ($16,500 in 2009) in the thrift feature of the CPSP to a choice of approximately 38 investment funds. ConocoPhillips matches contribution deposits, up to 1.25 percent of eligible pay. Company contributions charged to expense for the CPSP and predecessor plans, excluding the stock savings feature (discussed below), were $23 million in 2009, $28 million in 2008, and $26 million in 2007.
The stock savings feature of the CPSP is a leveraged employee stock ownership plan. Employees may elect to participate in the stock savings feature by contributing 1 percent of eligible pay and receiving an allocation of shares of common stock proportionate to the amount of contribution.
In 1990, the Long-Term Stock Savings Plan of Phillips Petroleum Company (now the stock savings feature of the CPSP) borrowed funds that were used to purchase previously unissued shares of company common stock. Since the company guarantees the CPSP’s borrowings, the unpaid balance is reported as a liability of the company and unearned compensation is shown as a reduction of common stockholders’ equity. Dividends on all shares are charged against retained earnings. The debt is serviced by the CPSP from company contributions and dividends received on certain shares of common stock held by the plan, including all unallocated shares. The shares held by the stock savings feature of the CPSP are released for allocation to participant accounts based on debt service payments on CPSP borrowings. In addition, during the period from 2010 through 2013,
when no debt principal payments are scheduled to occur, we have committed to make direct contributions of stock to the stock savings feature of the CPSP, or make prepayments on CPSP borrowings, to ensure a certain minimum level of stock allocation to participant accounts.
We recognize interest expense as incurred and compensation expense based on the fair market value of the stock contributed or on the cost of the unallocated shares released, using the shares-allocated method. We recognized total CPSP expense related to the stock savings feature of $83 million, $111 million and $148 million in 2009, 2008 and 2007, respectively, all of which was compensation expense. In 2009, 2008 and 2007, we contributed 2,018,692 shares, 1,668,456 shares and 1,856,224 shares, respectively, of company common stock from the Compensation and Benefits Trust. The shares had a fair market value of $94 million, $120 million and $155 million, respectively. Dividends used to service debt were $39 million, $41 million and $39 million in 2009, 2008 and 2007, respectively. These dividends reduced the amount of compensation expense recognized each period. Interest incurred on the CPSP debt in 2009, 2008 and 2007 was $2 million, $6 million and $11 million, respectively.
The total CPSP stock savings feature shares as of December 31 were:
The fair value of unallocated shares at December 31, 2009 and 2008, was $274 million and $373 million, respectively.
We have several defined contribution plans for our international employees, each with its own terms and eligibility depending on location. Total compensation expense recognized for these international plans was approximately $51 million in 2009, $53 million in 2008 and $44 million in 2007.
Share-Based Compensation Plans
The 2009 Omnibus Stock and Performance Incentive Plan of ConocoPhillips (the Plan) was approved by shareholders in May 2009. Over its 10-year life, the Plan allows the issuance of up to 70 million shares of our common stock for compensation to our employees, directors and consultants; however, as of the effective date of the Plan, (i) any shares of common stock available for future awards under the prior plans and (ii) any shares of common stock represented by awards granted under the prior plans that are forfeited, expire or are canceled without delivery of shares of common stock or which result in the forfeiture of shares of common stock back to the company shall be available for awards under the Plan, and no new awards shall be granted under the prior plans. Of the 70 million shares available for issuance under the Plan, no more than 40 million shares of common stock are available for incentive stock options, and no more than 40 million shares are available for awards in stock.
Our share-based compensation programs generally provide accelerated vesting (i.e., a waiver of the remaining period of service required to earn an award) for awards held by employees at the time of their retirement. For share-based awards granted prior to our adoption of SFAS No. 123(R), codified into FASB ASC Topic 718, “Compensation-Stock Compensation,” we recognize expense over the period of time during which the employee earns the award, accelerating the recognition of expense only when an employee actually retires. For share-based awards granted after our adoption of SFAS No. 123(R) on January 1, 2006, we recognize share-based compensation expense over the shorter of the service period (i.e., the stated period of time required to earn the award); or the period beginning at the start of the service period and ending when an employee first becomes eligible for retirement, but not less than six months, as this is the minimum period of time required for an award to not be subject to forfeiture.
Some of our share-based awards vest ratably (i.e., portions of the award vest at different times) while some of our awards cliff vest (i.e., all of the award vests at the same time). For awards granted prior to our adoption of SFAS No. 123(R) that vest ratably, we recognize expense on a straight-line basis over the service period for
each separate vesting portion of the award (i.e., as if the award was multiple awards with different requisite service periods). For share-based awards granted after our adoption of SFAS No. 123(R), we recognize expense on a straight-line basis over the service period for the entire award, whether the award was granted with ratable or cliff vesting.
Total share-based compensation expense recognized in income and the associated tax benefit for the three years ended December 31, 2009, was as follows:
Millions of Dollars
Compensation cost
$
Tax benefit
Stock Options-Stock options granted under the provisions of the Plan and earlier plans permit purchase of our common stock at exercise prices equivalent to the average market price of the stock on the date the options were granted. The options have terms of 10 years and generally vest ratably, with one-third of the options awarded vesting and becoming exercisable on each anniversary date following the date of grant. Options awarded to employees already eligible for retirement vest within six months of the grant date, but those options do not become exercisable until the end of the normal vesting period.
The following summarizes our stock option activity for the three years ended December 31, 2009:
The weighted-average remaining contractual term of vested options and exercisable options at December 31, 2009, was 3.57 years and 3.21 years, respectively.
During 2009, we received $59 million in cash and realized a tax benefit of $20 million from the exercise of options. At December 31, 2009, the remaining unrecognized compensation expense from unvested options was $16 million, which will be recognized over a weighted-average period of 14 months, the longest period being 25 months.
The significant assumptions used to calculate the fair market values of the options granted over the past three years, as calculated using the Black-Scholes-Merton option-pricing model, were as follows:
The ranges in the assumptions used were as follows:
We calculate volatility using the most recent ConocoPhillips end-of-week closing stock prices spanning a period equal to the expected life of the options granted. We periodically calculate the average period of time lapsed between grant dates and exercise dates of past grants to estimate the expected life of new option grants.
Stock Unit Program-Stock units granted under the provisions of the Plan vest ratably, with one-third of the units vesting in 36 months, one-third vesting in 48 months, and the final third vesting 60 months from the date of grant. Upon vesting, the units are settled by issuing one share of ConocoPhillips common stock per unit. Units awarded to employees already eligible for retirement vest within six months of the grant date, but those units are not issued as shares until the end of the normal vesting period. Until issued as stock, most recipients of the units receive a quarterly cash payment of a dividend equivalent that is charged to expense. The grant date fair value of these units is deemed equal to the average ConocoPhillips stock price on the date of grant. The grant date fair market value of units that do not receive a dividend equivalent while unvested is deemed equal to the average ConocoPhillips stock price on the grant date, less the net present value of the dividends that will not be received.
The following summarizes our stock unit activity for the three years ended December 31, 2009:
At December 31, 2009, the remaining unrecognized compensation cost from the unvested units was $162 million, which will be recognized over a weighted-average period of 24 months, the longest period being 49 months.
Performance Share Program-Under the Plan, we also annually grant to senior management restricted stock units that do not vest until either (i) with respect to awards for periods beginning before 2009, the employee becomes eligible for retirement by reaching age 55 with five years of service or (ii) with respect to awards for periods beginning in 2009, five years after the grant date of the award (although recipients can elect to defer the lapsing of restrictions until retirement after reaching age 55 with five years of service), so we recognize compensation expense for these awards beginning on the date of grant and ending on the date the units are scheduled to vest. Since these awards are authorized three years prior to the grant date, for employees eligible for such retirement by or shortly after the grant date, we recognize compensation expense over the period beginning on the date of authorization and ending on the date of grant. These units are settled by issuing one share of ConocoPhillips common stock per unit. Until issued as stock, recipients of the units receive a quarterly cash payment of a dividend equivalent that is charged to expense. In its current form, the first grant of units under this program was in 2006.
The following summarizes our Performance Share Program activity for the three years ended December 31, 2009:
At December 31, 2009, the remaining unrecognized compensation cost from unvested Performance Share awards was $43 million, which will be recognized over a weighted-average period of 42 months, the longest period being 12 years.
Other-In addition to the above active programs, we have outstanding shares of restricted stock and restricted stock units that were either issued to replace awards held by employees of companies we acquired or issued as part of a compensation program that has been discontinued. Generally, the recipients of the restricted shares or units receive a quarterly dividend or dividend equivalent.
The following summarizes the aggregate activity of these restricted shares and units for the three years ended December 31, 2009:
At December 31, 2009, the remaining unrecognized compensation cost from the unvested units was $4 million, which will be recognized over a weighted-average period of 7 months, the longest period being 13 months.
Compensation and Benefits Trust
The Compensation and Benefits Trust (CBT) is an irrevocable grantor trust, administered by an independent trustee and designed to acquire, hold and distribute shares of our common stock to fund certain future compensation and benefit obligations of the company. The CBT does not increase or alter the amount of benefits or compensation that will be paid under existing plans, but offers us enhanced financial flexibility in providing the funding requirements of those plans. We also have flexibility in determining the timing of distributions of shares from the CBT to fund compensation and benefits, subject to a minimum distribution schedule. The trustee votes shares held by the CBT in accordance with voting directions from eligible employees, as specified in a trust agreement with the trustee.
We sold 58.4 million shares of previously unissued company common stock to the CBT in 1995 for $37 million of cash, previously contributed to the CBT by us, and a promissory note from the CBT to us of $952 million. The CBT is consolidated by ConocoPhillips; therefore, the cash contribution and promissory note are eliminated in consolidation. Shares held by the CBT are valued at cost and do not affect earnings per share or total common stockholders’ equity until after they are transferred out of the CBT. In 2009 and 2008, shares transferred out of the CBT were 2,018,692 and 1,668,456, respectively. At December 31, 2009, the CBT had 38.5 million shares remaining. All shares are required to be transferred out of the CBT by January 1, 2021. The CBT, together with two smaller grantor trusts, comprise the “Grantor trusts” line in the equity section of the consolidated balance sheet.
Note 20-Income Taxes
Income taxes charged to income (loss) were:
Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for tax purposes. Major components of deferred tax liabilities and assets at December 31 were:
Current assets, long-term assets, current liabilities and long-term liabilities included deferred taxes of $581 million, $21 million, $5 million and $17,962 million, respectively, at December 31, 2009, and $457 million, $58 million, $1 million and $18,167 million, respectively, at December 31, 2008.
We have loss and credit carryovers in multiple taxing jurisdictions. These attributes generally expire between 2010 and 2029 with some carryovers having indefinite carryforward periods.
Valuation allowances have been established for certain loss and credit carryforwards that reduce deferred tax assets to an amount that will, more likely than not, be realized. During 2009, valuation allowances increased a total of $200 million. This reflects increases of $224 million primarily related to U.S. foreign tax credit and foreign and state tax loss carryforwards and currency effects, partially offset by decreases of $24 million related to utilization of loss carryforwards and asset relinquishment. Based on our historical taxable income, expectations for the future, and available tax-planning strategies, management expects remaining net deferred tax assets will be realized as offsets to reversing deferred tax liabilities and as offsets to the tax consequences of future taxable income.
At December 31, 2009 and 2008, income considered to be permanently reinvested in certain foreign subsidiaries and foreign corporate joint ventures totaled approximately $2,129 million and $3,871 million, respectively. Deferred income taxes have not been provided on this income, as we do not plan to initiate any action that would require the payment of income taxes. It is not practicable to estimate the amount of additional tax that might be payable on this foreign income if distributed.
The following table shows a reconciliation of the beginning and ending unrecognized tax benefits for 2009, 2008 and 2007.
Included in the balance of unrecognized tax benefits for 2009, 2008 and 2007 were $931 million, $862 million and $698 million, respectively, which, if recognized, would affect our effective tax rate. The increase from 2007 to 2008 was primarily due to the effect of FASB ASC Topic 805, “Business Combinations.”
At December 31, 2009, 2008 and 2007, accrued liabilities for interest and penalties totaled $166 million, $147 million and $137 million, respectively, net of accrued income taxes. Interest and penalties affecting earnings in 2009, 2008 and 2007 were $14 million, $28 million and $46 million, respectively.
We and our subsidiaries file tax returns in the U.S. federal jurisdiction and in many foreign and state jurisdictions. Audits in major jurisdictions are generally complete as follows: United Kingdom (2007), Canada (2003), United States (2004) and Norway (2008). Issues in dispute for audited years and audits for subsequent years are ongoing and in various stages of completion in the many jurisdictions in which we operate around the world. As a consequence, the balance in unrecognized tax benefits can be expected to fluctuate from period to period. It is reasonably possible such changes could be significant when compared with our total unrecognized tax benefits, but the amount of change is not estimable.
The amounts of U.S. and foreign income (loss) before income taxes, with a reconciliation of tax at the federal statutory rate with the provision for income taxes, were:
Our effective tax rate in 2009 was 51 percent, compared with a negative 381 percent in 2008. The change in the effective tax rate from 2008 was primarily due to the impact of impairments relating to goodwill and to our LUKOIL investment taken in the fourth quarter of 2008. For additional information on the impairments, see Note 9-Goodwill and Intangibles and Note 6-Investments, Loans and Long-Term Receivables.
Tax rate changes in 2009 and 2008 did not have a significant impact on our income tax expense. Our 2007 tax expense was decreased $204 million and $141 million, respectively, due to remeasurement of deferred tax liabilities resulting from tax rate reductions in Canada and Germany.
Note 21-Other Comprehensive Income (Loss)
The components and allocated tax effects of other comprehensive income (loss) follow:
*
Plans for which ConocoPhillips is not the primary obligor-primarily those administered by equity affiliates.
Deferred taxes have not been provided on temporary differences related to foreign currency translation adjustments for investments in certain foreign subsidiaries and foreign corporate joint ventures that are considered permanent in duration.
Accumulated other comprehensive income (loss) in the equity section of the balance sheet included:
Note 22-Cash Flow Information
Note 23-Other Financial Information
*
Primarily related to 2005 hurricanes in the Gulf of Mexico and southern United States.
*
Amounts included in production and operating expenses.
Note 24-Related Party Transactions
Significant transactions with related parties were:
(a)
We sold natural gas to DCP Midstream, LLC and crude oil to the Malaysian Refining Company Sdn. Bhd. (MRC), among others, for processing and marketing. Natural gas liquids, solvents and petrochemical feedstocks were sold to Chevron Phillips Chemical Company LLC (CPChem), gas oil and hydrogen feedstocks were sold to Excel Paralubes and refined products were sold primarily to CFJ Properties and LUKOIL. Natural gas, crude oil, blendstock and other intermediate products were sold to WRB Refining LLC. In addition, we charged several of our affiliates, including CPChem, Merey Sweeny, L.P. (MSLP) and Hamaca Holding LLC (until expropriation on June 26, 2007), for the use of common facilities, such as steam generators, waste and water treaters, and warehouse facilities.
(b)
We purchased refined products from WRB. We purchased natural gas and natural gas liquids from DCP Midstream and CPChem for use in our refinery processes and other feedstocks from various affiliates. We purchased crude oil from LUKOIL, upgraded crude oil from Petrozuata C.A. (until expropriation on June 26, 2007) and refined products from MRC. We also paid fees to various pipeline equity companies for transporting finished refined products and natural gas, as well as a price upgrade to MSLP for heavy crude processing. We purchased base oils and fuel products from Excel Paralubes for use in our refinery and specialty businesses.
(c)
We paid processing fees to various affiliates. Additionally, we paid crude oil transportation fees to pipeline equity companies.
(d)
We paid and/or received interest to/from various affiliates, including FCCL Partnership. See Note 6-Investments, Loans and Long-Term Receivables, for additional information on loans to affiliated companies.
Note 25-Segment Disclosures and Related Information
We have organized our reporting structure based on the grouping of similar products and services, resulting in six operating segments:
1)
E&P-This segment primarily explores for, produces, transports and markets crude oil, natural gas, natural gas liquids and bitumen on a worldwide basis. At December 31, 2009, our E&P operations were producing in the United States, Norway, the United Kingdom, Canada, Australia, offshore Timor-Leste in the Timor Sea, Indonesia, China, Vietnam, Libya, Nigeria, Algeria and Russia. The E&P segment’s U.S. and international operations are disclosed separately for reporting purposes.
2)
Midstream-This segment gathers, processes and markets natural gas produced by ConocoPhillips and others, and fractionates and markets natural gas liquids, predominantly in the United States and Trinidad. The Midstream segment primarily consists of our 50 percent equity investment in DCP Midstream, LLC.
3)
R&M-This segment purchases, refines, markets and transports crude oil and petroleum products, mainly in the United States, Europe and Asia. At December 31, 2009, we owned or had an interest in 12 refineries in the United States, one in the United Kingdom, one in Ireland, two in Germany, and one in Malaysia. The R&M segment’s U.S. and international operations are disclosed separately for reporting purposes.
4)
LUKOIL Investment-This segment represents our investment in the ordinary shares of OAO LUKOIL, an international, integrated oil and gas company headquartered in Russia. At December 31, 2009, our ownership interest was 20 percent based on issued shares and 20.09 percent based on estimated shares outstanding. See Note 6-Investments, Loans and Long-Term Receivables, for additional information.
5)
Chemicals-This segment manufactures and markets petrochemicals and plastics on a worldwide basis. The Chemicals segment consists of our 50 percent equity investment in Chevron Phillips Chemical Company LLC.
6)
Emerging Businesses-This segment represents our investment in new technologies or businesses outside our normal scope of operations. Activities within this segment are currently focused on power generation and innovation of new technologies, such as those related to conventional and nonconventional hydrocarbon recovery (including heavy oil), refining, alternative energy, biofuels and the environment.
Corporate and Other includes general corporate overhead, most interest expense and various other corporate activities. Corporate assets include all cash and cash equivalents.
We evaluate performance and allocate resources based on net income attributable to ConocoPhillips. Segment accounting policies are the same as those in Note 1-Accounting Policies. Intersegment sales are at prices that approximate market.
Analysis of Results by Operating Segment
*
Does not include a $7,410 million impairment of our LUKOIL investment presented as a separate line item in the consolidated statement of operations.
Geographic Information
* Sales and other operating revenues are attributable to countries based on the location of the operations generating the revenues.
** Defined as net properties, plants and equipment plus investments in and advances to affiliated companies.
*** Includes amounts related to the joint petroleum development area with shared ownership held by Australia and Timor-Leste.
Note 26-New Accounting Standards
In June 2009, the FASB issued SFAS No. 166, “Accounting for Transfers of Financial Assets, an amendment of FASB Statement No. 140.” This Statement was codified into FASB ASC Topic 860, “Transfers and Servicing.” This Statement removes the concept of a qualifying special purpose entity (SPE) and the exception for qualifying SPEs from the consolidation guidance. Additionally, the Statement clarifies the requirements for financial asset transfers eligible for sale accounting. This Statement is effective January 1, 2010, and is not expected to have a material impact on our consolidated financial statements.
Also in June 2009, the FASB issued SFAS No. 167, “Amendments to FASB Interpretation No. 46(R),” to address the effects of the elimination of the qualifying SPE concept in SFAS No. 166, and other concerns about the application of key provisions of consolidation guidance for VIEs. This Statement was codified into FASB ASC Topic 810, “Consolidation.” More specifically, SFAS No. 167 requires a qualitative rather than a quantitative approach to determine the primary beneficiary of a VIE, it amends certain guidance pertaining to the determination of the primary beneficiary when related parties are involved, and it amends certain guidance for determining whether an entity is a VIE. Additionally, this Statement requires continuous assessments of whether an enterprise is the primary beneficiary of a VIE. This Statement is effective January 1, 2010, and is not expected to have a material impact on our consolidated financial statements.
Oil and Gas Operations (Unaudited)
In accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification Topic 932, “Extractive Activities-Oil and Gas,” and regulations of the U.S. Securities and Exchange Commission (SEC), we are making certain supplemental disclosures about our oil and gas exploration and production operations.
These disclosures include information about our consolidated oil and gas activities and our proportionate share of our equity affiliates’ oil and gas activities, covering both those in our Exploration and Production (E&P) segment, as well as in our LUKOIL Investment segment. As a result, amounts reported as Equity Affiliates in Oil and Gas Operations may differ from those shown in the individual segment disclosures reported elsewhere in this report. The data included for the LUKOIL Investment segment reflects the company’s estimated share of OAO LUKOIL’s amounts. Because LUKOIL’s accounting cycle close and preparation of U.S. generally accepted accounting principles financial statements occur subsequent to our reporting deadline, our equity share of financial information and statistics for our LUKOIL investment are estimated based on current market indicators, publicly available LUKOIL information, and other objective data. Once the difference between actual and estimated results is known, an adjustment is recorded. Our estimated year-end 2009 reserves related to our equity investment in LUKOIL are based on LUKOIL’s year-end 2009 reserve estimates and include adjustments to conform them to ConocoPhillips’ reserves policy.
Our proved reserves include estimated quantities related to production sharing contracts (PSCs), which are reported under the “economic interest” method and are subject to fluctuations in prices of crude oil, natural gas and natural gas liquids; recoverable operating expenses; and capital costs. If costs remain stable, reserve quantities attributable to recovery of costs will change inversely to changes in commodity prices. For example, if prices increase, then our applicable reserve quantities would decline. At December 31, 2009, approximately 12 percent of our total proved reserves, excluding LUKOIL, were under PSCs, primarily in our Asia Pacific/Middle East geographic reporting area.
Our disclosures by geographic area include the United States, Canada, Europe (primarily Norway and the United Kingdom), Russia, Asia Pacific/Middle East, Africa, and Other Areas. Other Areas primarily consists of the Caspian Region, as well as the Petrozuata and Hamaca heavy oil projects in Venezuela, which were expropriated in 2007, and Ecuador, which was expropriated in 2009. Certain previously reported amounts for 2008 and 2007 appearing in the following oil and gas operations schedules have been reclassified between line items to conform to the current year presentation.
On December 31, 2008, the SEC issued its final rules to modernize the supplemental oil and gas disclosures, and in January 2010, the FASB issued Accounting Standards Update No. 2010-03, “Oil and Gas Reserve Estimation and Disclosures.” As a result of these two new rules, our disclosures reflect the expanded definitions for oil and gas producing activities, including nontraditional resources such as our Syncrude operations. The inclusion of Syncrude as part of our oil and gas producing activities, effective January 1, 2009, did not have a significant impact on our disclosures. In the following disclosures, our synthetic oil classification includes our Syncrude mining operations, and our bitumen classification includes our Surmont operations and the FCCL Partnership. In addition, we have applied the 12-month average price rather than year-end price for determining economic producibility of reserves, revised our geographic areas, and expanded disclosures for equity investments to the same level of detail as required for consolidated investments.
We own a 9 percent interest in the Syncrude Canada Ltd. (SCL) joint venture, created for the purpose of mining shallow deposits of oil sands, extracting the bitumen, and upgrading it into a light sweet synthetic crude oil called Syncrude. The primary plant and facilities are located at Mildred Lake, about 25 miles north of Fort McMurray, Alberta. SCL, as operator of the joint venture, holds eight oil sands leases and the associated surface rights, of which our share is approximately 22,400 net acres. Net production averaged 23,000 barrels per day in 2009.
Reserves Governance
The recording and reporting of proved reserves are governed by criteria established by regulations of the SEC and FASB. Proved reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible-from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations-prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Proved reserves are further classified as either developed or undeveloped. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well, and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
We have a companywide, comprehensive, SEC-compliant internal policy that governs the determination and reporting of proved reserves. This policy is applied by the geologists and reservoir engineers in our E&P business units around the world. As part of our internal control process, each business unit’s reserves are reviewed annually by an internal team which is headed by the company’s Reserves Compliance and Reporting Manager. This team, composed of internal reservoir engineers, geologists and finance personnel, reviews the business units’ reserves for adherence to SEC guidelines and company policy through on-site visits and review of documentation. In addition to providing independent reviews, this internal team also ensures reserves are calculated using consistent and appropriate standards and procedures. This team is independent of business unit line management and is responsible for reporting its findings to senior management and our internal audit group. The team is responsible for maintaining and communicating our reserves policy and procedures and is available for internal peer reviews and consultation on major projects or technical issues throughout the year. All of our proved reserves held by consolidated companies and our share of equity affiliates have been estimated by ConocoPhillips.
The technical person primarily responsible for overseeing the preparation of the company’s reserve estimates is the Manager of Reserves Compliance and Reporting. This individual is a petroleum engineer with a bachelor’s degree in petroleum engineering. He is an active member of the Society of Petroleum Engineers (SPE) with over 30 years of oil and gas industry experience, including drilling and production engineering assignments in several field locations. He is currently serving a three-year term on the Oil & Gas Reserves Committee of the SPE and has held positions of increasing responsibility in reservoir engineering, reserves reporting and compliance, and business management.
Engineering estimates of the quantities of proved reserves are inherently imprecise. See the “Critical Accounting Estimates” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional discussion of the sensitivities surrounding these estimates.
Proved Reserves
Notable changes in proved crude oil and natural gas liquids reserves in the three years ended December 31, 2009, included:
•
Revisions: In 2009 and 2008, revisions in Alaska were primarily due to higher prices in 2009, versus 2008; and lower prices in 2008, compared with 2007, respectively. In 2007 for our equity affiliate operations, revisions were primarily attributable to LUKOIL.
•
Extensions and Discoveries: In 2009 in Russia, extensions and discoveries were attributable to drilling success in various LUKOIL fields.
•
Sales: In 2007 for our equity affiliates in Other Areas, sales were primarily due to the expropriation of our oil interests in Venezuela.
Natural gas production in the reserves table may differ from gas production (delivered for sale) in our statistics disclosure, primarily because the quantities above include gas consumed at the lease.
Natural gas reserves are computed at 14.65 pounds per square inch absolute and 60 degrees Fahrenheit.
Notable changes in proved natural gas reserves in the three years ended December 31, 2009, included:
•
Revisions: In 2009 and 2008, revisions in Alaska were primarily due to higher prices in 2009, versus 2008; and lower prices in 2008, compared with 2007, respectively. In 2009 for our equity affiliate operations in Asia Pacific/Middle East, revisions resulted from modified coalbed methane drilling plans in Australia. In Russia, revisions were attributable to positive performance in various LUKOIL fields. In 2008, revisions in Russia primarily resulted from a revised assessment of the reasonable certainty of project development and of the marketability of non-contracted gas volumes.
•
Purchases: In 2008 for our equity affiliate operations in Asia Pacific/Middle East, purchases relate to our Australia Pacific LNG joint venture to develop coalbed methane.
•
Extensions and Discoveries: In 2009 for our equity affiliate operations in Asia Pacific/Middle East, extensions and discoveries primarily resulted from drilling success in Australia related to a coalbed methane project.
Notable changes in proved synthetic oil and bitumen reserves in the three years ended December 31, 2009, included:
•
Revisions: In 2009 for synthetic oil consolidated operations, revisions reflect our Syncrude Canada Ltd. operations, which are now considered an oil and gas activity under the new FASB and SEC rules and regulations. For our bitumen consolidated operations, revisions primarily were related to the sanction of the Surmont Phase II Project. For our bitumen equity affiliate operations, revisions were mainly the result of the effect of higher prices on sliding scale royalty provisions.
•
Purchases: In 2007 for our bitumen equity affiliate operations, purchases reflect the formation of FCCL.
•
Extensions and Discoveries: In 2009 for our bitumen consolidated operations, extensions and discoveries were related to the sanction of the Surmont Phase II Project. For our equity affiliate operations, extensions and discoveries mainly reflect the approval of the FCCL Christina Lake Phase 1D Project. In 2007 for our bitumen equity affiliate operations, extensions and discoveries were primarily associated with FCCL.
Natural gas reserves are converted to barrels of oil equivalent (BOE) based on a 6:1 ratio: six thousand cubic feet of natural gas converts to one BOE.
Proved Undeveloped Reserves
Our total proved undeveloped reserves at December 31, 2009, were 3,087 million BOE.
The net addition of proved undeveloped reserves accounted for 52 percent, 156 percent and 77 percent of our total net additions in 2009, 2008 and 2007, respectively. During these years, we converted, on average, 13 percent per year of our proved undeveloped reserves to proved developed reserves. During 2009, we converted approximately 370 million BOE of proved undeveloped reserves to proved developed.
Costs incurred for the years ended December 31, 2009, 2008 and 2007, relating to the development of proved undeveloped reserves were $4.2 billion, $4.8 billion, and $4.3 billion, respectively.
Approximately 80 percent of our proved undeveloped reserves at year-end 2009 were associated with eight major development areas in our E&P segment; and our investment in LUKOIL. Six of the major development areas within E&P are currently producing and are expected to have proved reserves convert from undeveloped to developed over time as development activities continue and/or production facilities are expanded or upgraded, and include:
•
FCCL oil sands-Christina Lake and Foster Creek in Canada.
•
The Surmont oil sands project in Canada.
•
The Ekofisk Field in the North Sea.
•
Certain fields in the United States.
The remaining two major projects, Qatargas 3 in Qatar and the Kashagan Field in Kazakhstan, will have proved undeveloped reserves convert to developed as these projects begin production.
At the end of 2009, we did not have any material amounts of proved undeveloped reserves in individual fields or countries that have remained undeveloped for five years or more. However, our largest concentrations of proved undeveloped reserves at year-end 2009 are located in the Athabasca oil sands in Canada, consisting of the FCCL and Surmont steam-assisted gravity drainage (SAGD) projects. The majority of our proved undeveloped reserves in this area were first recorded in 2006 and 2007, and we expect a material portion of these reserves will remain undeveloped for more than five years.
Our SAGD projects are large, multi-year projects with steady, long-term production at consistent levels. The associated reserves are expected to be developed over many years as additional well pairs are drilled across the extensive resource base to maintain throughput at the central processing facilities.
Results of Operations
*
Excludes goodwill impairment of $25,443 million.
•
Results of operations for producing activities consist of all activities within the E&P organization and producing activities within the LUKOIL Investment segment, except for pipeline and marine operations, liquefied natural gas operations, and crude oil and gas marketing activities, which are included in other earnings. Also excluded are our Midstream segment, downstream petroleum and chemical activities, as well as general corporate administrative expenses and interest.
•
Transfers are valued at prices that approximate market.
•
Other revenues include gains and losses from asset sales, certain amounts resulting from the purchase and sale of hydrocarbons, and other miscellaneous income.
•
Production costs are those incurred to operate and maintain wells and related equipment and facilities used to produce proved reserves. These costs also include depreciation of support equipment and administrative expenses related to the production activity.
•
Taxes other than income taxes include production, property and other non-income taxes.
•
Exploration expenses include dry hole costs, leasehold impairments, geological and geophysical expenses, the costs of retaining undeveloped leaseholds, and depreciation of support equipment and administrative expenses related to the exploration activity.
•
Depreciation, depletion and amortization (DD&A) in Results of Operations differs from that shown for total E&P in Note 25-Segment Disclosures and Related Information, in the Notes to Consolidated Financial Statements, mainly due to depreciation of support equipment being reclassified to production or exploration expenses, as applicable, in Results of Operations. In addition, other earnings include certain E&P activities, including their related DD&A charges.
•
Transportation costs include costs to transport our produced hydrocarbons to their points of sale, as well as processing fees paid to process natural gas to natural gas liquids. The profit element of transportation operations in which we have an ownership interest are deemed to be outside oil and gas producing activities. The net income of the transportation operations is included in other earnings.
•
Other related expenses include foreign currency transaction gains and losses, and other miscellaneous expenses.
•
The provision for income taxes is computed by adjusting each country’s income before income taxes for permanent differences related to oil and gas producing activities that are reflected in our consolidated income tax expense for the period, multiplying the result by the country’s statutory tax rate, and adjusting for applicable tax credits. Included in 2007 for Canada is a benefit related to the remeasurement of deferred tax liabilities from the 2007 Canadian graduated tax rate reduction.
Statistics
*
Represents quantities available for sale. Excludes gas equivalent of natural gas liquids included above.
*
Includes bitumen. For 2008 and 2007, excludes our Canadian synthetic oil operations.
(1)
Excludes farmout arrangements.
(2)
Includes step-out wells, as well as other types of exploratory wells. Step-out exploratory wells are wells drilled in areas near or offsetting current production, for which we cannot demonstrate with certainty that there is continuity of production from an existing productive formation. These are classified as exploratory wells because we cannot attribute proved reserves to these locations.
(3)
Excludes LUKOIL.
*
Our total proportionate interest was less than one.
(1)
Includes wells that have been temporarily suspended.
(2)
Includes 6,098 gross and 3,845 net multiple completion wells.
(3)
Includes 132 gross and 108 net stratigraphic test wells for heavy oil projects.
(4)
Excludes LUKOIL.
*
Excludes LUKOIL.
Costs Incurred
•
Costs incurred include capitalized and expensed items.
•
Acquisition costs include the costs of acquiring proved and unproved hydrocarbon properties. In 2008, equity affiliate acquisition costs were due to the Australia Pacific LNG joint venture with Origin Energy. In 2007, equity affiliate acquisition costs reflect the formation of FCCL.
•
Exploration costs include geological and geophysical expenses, the cost of retaining undeveloped leaseholds, and exploratory drilling costs.
•
Development costs include the cost of drilling and equipping development wells and building related production facilities for extracting, treating, gathering and storing hydrocarbons.
Capitalized Costs
•
Capitalized costs include the cost of equipment and facilities for oil and gas producing activities. These costs include the activities of our E&P and LUKOIL Investment segments, excluding pipeline and marine operations, liquefied natural gas operations, crude oil and natural gas marketing activities, and downstream operations.
•
Proved properties include capitalized costs for leaseholds holding proved reserves, development wells and related equipment and facilities (including uncompleted development well costs), mining facilities associated with our synthetic oil operations, and support equipment.
•
Unproved properties include capitalized costs for leaseholds under exploration (including where hydrocarbons were found but determination of the economic viability of the required infrastructure is dependent upon further exploratory work under way or firmly planned) and for uncompleted exploratory well costs, including exploratory wells under evaluation.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserve Quantities
In accordance with new SEC and FASB requirements, amounts for 2009 were computed using 12-month average prices and end-of-year costs (adjusted only for existing contractual changes), appropriate statutory tax rates and a prescribed 10 percent discount factor. Twelve-month average prices are calculated as the unweighted arithmetic average of the first-day-of-the month price for each month. Prior year amounts were computed using end-of-year prices and costs. For all years, continuation of year-end economic conditions was assumed. The calculations were based on estimates of proved reserves, which are revised over time as new data becomes available. Probable or possible reserves, which may become proved in the future, were not considered. The calculations also require assumptions as to the timing of future production of proved reserves, and the timing and amount of future development, including dismantlement, and production costs.
While due care was taken in its preparation, we do not represent that this data is the fair value of our oil and gas properties, or a fair estimate of the present value of cash flows to be obtained from their development and production.
Discounted Future Net Cash Flows
*
Includes taxes other than income taxes.
*
Includes taxes other than income taxes.
Excludes discounted future net cash flows from Canadian Syncrude of $435 million.
* Includes taxes other than income taxes.
Excludes discounted future net cash flows from Canadian Syncrude of $4,484 million.
Sources of Change in Discounted Future Net Cash Flows
* Includes taxes other than income taxes.
** Includes amounts resulting from changes in the timing of production.
•
The net change in prices, and production and transportation costs is the beginning-of-year reserve-production forecast multiplied by the net annual change in the per-unit sales price, and production and transportation cost, discounted at 10 percent.
•
For 2009, as required, purchases and sales of reserves in place, along with extensions, discoveries and improved recovery, are calculated using production forecasts of the applicable reserve quantities for the year multiplied by the 12-month average sales prices, less future estimated costs, discounted at 10 percent. For prior years the end-of-year sales prices were used, as required.
•
The accretion of discount is 10 percent of the prior year’s discounted future cash inflows, less future production, transportation and development costs.
•
The net change in income taxes is the annual change in the discounted future income tax provisions.
Selected Quarterly Financial Data (Unaudited)
* Includes excise taxes on petroleum products sales.
** Includes noncash impairments relating to goodwill and to our LUKOIL investment that together amount to $32,853 million before- and after-tax.
Supplementary Information-Condensed Consolidating Financial Information
We have various cross guarantees among ConocoPhillips, ConocoPhillips Company, ConocoPhillips Australia Funding Company, ConocoPhillips Canada Funding Company I, and ConocoPhillips Canada Funding Company II, with respect to publicly held debt securities. ConocoPhillips Company is wholly owned by ConocoPhillips. ConocoPhillips Australia Funding Company is an indirect, wholly owned subsidiary of ConocoPhillips Company. ConocoPhillips Canada Funding Company I and ConocoPhillips Canada Funding Company II are indirect, wholly owned subsidiaries of ConocoPhillips. ConocoPhillips and ConocoPhillips Company have fully and unconditionally guaranteed the payment obligations of ConocoPhillips Australia Funding Company, ConocoPhillips Canada Funding Company I, and ConocoPhillips Canada Funding Company II, with respect to their publicly held debt securities. Similarly, ConocoPhillips has fully and unconditionally guaranteed the payment obligations of ConocoPhillips Company with respect to its publicly held debt securities. In addition, ConocoPhillips Company has fully and unconditionally guaranteed the payment obligations of ConocoPhillips with respect to its publicly held debt securities. All guarantees are joint and several. The following condensed consolidating financial information presents the results of operations, financial position and cash flows for:
•
ConocoPhillips, ConocoPhillips Company, ConocoPhillips Australia Funding Company, ConocoPhillips Canada Funding Company I, and ConocoPhillips Canada Funding Company II (in each case, reflecting investments in subsidiaries utilizing the equity method of accounting).
•
All other nonguarantor subsidiaries of ConocoPhillips.
•
The consolidating adjustments necessary to present ConocoPhillips’ results on a consolidated basis.
In February 2009, we filed a universal shelf registration statement with the SEC under which ConocoPhillips, as a well-known seasoned issuer, has the ability to issue and sell an indeterminate amount of various types of debt and equity securities, with certain debt securities guaranteed by ConocoPhillips Company. Also as part of that registration statement, ConocoPhillips Trust I and ConocoPhillips Trust II have the ability to issue and sell preferred trust securities, guaranteed by ConocoPhillips. ConocoPhillips Trust I and ConocoPhillips Trust II have not issued any trust-preferred securities under this registration statement, and thus have no assets or liabilities. Accordingly, columns for these two trusts are not included in the condensed consolidating financial information.
To facilitate the restructuring of certain legal entities within the Canada operating unit, ConocoPhillips Canada Funding Company I (CFC I) entered into a transaction with another wholly owned subsidiary of ConocoPhillips (included in the “All Other Subsidiaries” column) whereby it acquired an investment in certain preferred shares of a Canadian legal entity within the ConocoPhillips group, in exchange for a non-interest-bearing demand note payable. The value ascribed to the preferred shares and note payable represented the redemption price for both. This noncash transaction was effective December 31, 2009. As a result, the balance sheet of CFC I reflects a short-term investment of $2,973 million and a corresponding amount in short-term debt. In January 2010, the preferred shares acquired under the above transaction were resold to the original holder at the same value as the original purchase price, as satisfaction of the obligation under the demand note payable. A pro forma presentation of CFC I’s December 31, 2009, balance sheet reflecting this subsequent event would show balances of $-0- in short-term investments and short-term debt. As these transactions were completed between wholly owned subsidiaries of ConocoPhillips, there is no impact on the consolidated results in either period.
This condensed consolidating financial information should be read in conjunction with the accompanying consolidated financial statements and notes.
*
Includes intercompany loans.
*
Includes intercompany loans.
Item 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
Item 9A.
CONTROLS AND PROCEDURES
As of December 31, 2009, with the participation of our management, our Chairman and Chief Executive Officer (principal executive officer) and our Senior Vice President, Finance, and Chief Financial Officer (principal financial officer) carried out an evaluation, pursuant to Rule 13a-15(b) of the Securities Exchange Act of 1934, as amended (the Act), of the effectiveness of the design and operation of ConocoPhillips’ disclosure controls and procedures (as defined in Rule 13a-15(e) of the Act). Based upon that evaluation, our Chairman and Chief Executive Officer and our Senior Vice President, Finance, and Chief Financial Officer concluded that our disclosure controls and procedures were operating effectively as of December 31, 2009.
There have been no changes in our internal control over financial reporting, as defined in Rule 13a-15(f) of the Act, in the quarterly period ended December 31, 2009, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Management’s Annual Report on Internal Control Over Financial Reporting
This report is included in Item 8 on page 71 and is incorporated herein by reference.
Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting
This report is included in Item 8 on page 73 and is incorporated herein by reference.
Item 9B.
OTHER INFORMATION
None.
PART III
Item 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Information regarding our executive officers appears in Part I of this report on pages 28 and 29.
Code of Business Ethics and Conduct for Directors and Employees
We have a Code of Business Ethics and Conduct for Directors and Employees (Code of Ethics), including our principal executive officer, principal financial officer, principal accounting officer and persons performing similar functions. We have posted a copy of our Code of Ethics on the “Corporate Governance” section of our Internet Web site at www.conocophillips.com (within the Investor Relations>Governance section). Any waivers of the Code of Ethics must be approved, in advance, by our full Board of Directors. Any amendments to, or waivers from, the Code of Ethics that apply to our executive officers and directors will be posted on the “Corporate Governance” section of our Internet Web site.
All other information required by Item 10 of Part III will be included in our Proxy Statement relating to our 2010 Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before April 30, 2010, and is incorporated herein by reference.*
Item 11.
EXECUTIVE COMPENSATION
Information required by Item 11 of Part III will be included in our Proxy Statement relating to our 2010 Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before April 30, 2010, and is incorporated herein by reference.*
Item 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Information required by Item 12 of Part III will be included in our Proxy Statement relating to our 2010 Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before April 30, 2010, and is incorporated herein by reference.*
Item 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Information required by Item 13 of Part III will be included in our Proxy Statement relating to our 2010 Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before April 30, 2010, and is incorporated herein by reference.*
Item 14.
PRINCIPAL ACCOUNTING FEES AND SERVICES
Information required by Item 14 of Part III will be included in our Proxy Statement relating to our 2010 Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before April 30, 2010, and is incorporated herein by reference.*
*
Except for information or data specifically incorporated herein by reference under Items 10 through 14, other information and data appearing in our 2010 Proxy Statement are not deemed to be a part of this Annual Report on Form 10-K or deemed to be filed with the Commission as a part of this report.
PART IV
Item 15.
EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(a)
1. Financial Statements and Supplementary Data
The financial statements and supplementary information listed in the Index to Financial Statements, which appears on page 70, are filed as part of this annual report.
2. Financial Statement Schedules
Schedule II-Valuation and Qualifying Accounts, appears below. All other schedules are omitted because they are not required, not significant, not applicable or the information is shown in another schedule, the financial statements or the notes to consolidated financial statements.
3. Exhibits
The exhibits listed in the Index to Exhibits, which appears on pages 174 through 177 are filed as part of this annual report.
(c)
Financial statements of OAO LUKOIL will be filed by amendment to this Annual Report on Form 10-K no later than June 30, 2010, in accordance with Rule 3.09 of Regulation S-X.
Schedule Of Valuation And Qualifying Accounts Disclosure
SCHEDULE II-VALUATION AND QUALIFYING ACCOUNTS (Consolidated)
ConocoPhillips
(a) Represents acquisitions/dispositions/revisions and the effect of translating foreign financial statements.
(b) Amounts charged off less recoveries of amounts previously charged off.
(c) Benefit payments.
CONOCOPHILLIPS
INDEX TO EXHIBITS
Exhibit
Number
Description
3.1
Amended and Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Quarterly Report of ConocoPhillips on Form 10-Q for the quarterly period ended June 30, 2008; File No. 001-32395).
3.2
Certificate of Designations of Series A Junior Participating Preferred Stock of ConocoPhillips (incorporated by reference to Exhibit 3.2 to the Current Report of ConocoPhillips on Form 8-K filed on August 30, 2002; File No. 000-49987).
3.3
By-Laws of ConocoPhillips, as amended on December 12, 2008 (incorporated by reference to Exhibit 3.1 to the Current Report of ConocoPhillips on Form 8-K filed on December 12, 2008; File No. 001-32395).
4.1
Rights agreement, dated as of June 30, 2002, between ConocoPhillips and Mellon Investor Services LLC, as rights agent, which includes as Exhibit A the form of Certificate of Designations of Series A Junior Participating Preferred Stock, as Exhibit B the form of Rights Certificate and as Exhibit C the Summary of Rights to Purchase Preferred Stock (incorporated by reference to Exhibit 4.1 to the Current Report of ConocoPhillips on Form 8-K filed on August 30, 2002; File No. 000-49987).
ConocoPhillips and its subsidiaries are parties to several debt instruments under which the total amount of securities authorized does not exceed 10 percent of the total assets of ConocoPhillips and its subsidiaries on a consolidated basis. Pursuant to paragraph 4(iii)(A) of Item 601(b) of Regulation S-K, ConocoPhillips agrees to furnish a copy of such instruments to the SEC upon request.
10.1
Shareholder Agreement, dated September 29, 2004, by and between LUKOIL and ConocoPhillips (incorporated by reference to Exhibit 99.2 of the Current Report of ConocoPhillips on Form 8-K filed on September 30, 2004; File No. 333-74798).
10.2
1986 Stock Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10.11 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002; File No. 000-49987).
10.3
1990 Stock Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10.12 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002; File No. 000-49987).
10.4
Annual Incentive Compensation Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10.13 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002; File No. 000-49987).
10.5
Incentive Compensation Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10(g) to the Annual Report of ConocoPhillips Company on Form 10-K for the year ended December 31, 1999; File No. 1-720).
Exhibit
Number
Description
10.6
ConocoPhillips Supplemental Executive Retirement Plan (incorporated by reference to Exhibit 10.7 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2005; File No. 001-32395).
10.7
Non-Employee Director Retirement Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10.18 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002; File No. 000-49987).
10.8
Omnibus Securities Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10.19 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002; File No. 000-49987).
10.9
Key Employee Missed Credited Service Retirement Plan of ConocoPhillips (incorporated by reference to Exhibit 10.10 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2005; File No. 001-32395).
10.10
Phillips Petroleum Company Stock Plan for Non-Employee Directors (incorporated by reference to Exhibit 10.22 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002; File No. 000-49987).
10.11
ConocoPhillips Key Employee Supplemental Retirement Plan (incorporated by reference to Exhibit 10.11 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2008; File No. 001-32395).
10.12.1
Defined Contribution Make-Up Plan of ConocoPhillips-Title I (incorporated by reference to Exhibit 10.13.1 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2005; File No. 001-32395).
10.12.2
Defined Contribution Make-Up Plan of ConocoPhillips-Title II (incorporated by reference to Exhibit 10.12.2 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2008; File No. 001-32395).
10.13
2002 Omnibus Securities Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10.26 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002; File No. 000-49987).
10.14
1998 Stock and Performance Incentive Plan of ConocoPhillips (incorporated by reference to Exhibit 10.27 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002; File No. 000-49987).
10.15
1998 Key Employee Stock Performance Plan of ConocoPhillips (incorporated by reference to Exhibit 10.28 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002; File No. 000-49987).
10.16
Deferred Compensation Plan for Non-Employee Directors of ConocoPhillips (incorporated by reference to Exhibit 10.17 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2005; File No. 001-32395).
Exhibit
Number
Description
10.17
ConocoPhillips Form Indemnity Agreement with Directors (incorporated by reference to Exhibit 10.34 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002; File No. 000-49987).
10.18
Rabbi Trust Agreement dated December 17, 1999 (incorporated by reference to Exhibit 10.11 of the Annual Report of ConocoPhillips Holding Company on Form 10-K for the year ended December 31, 1999; File No. 001-14521).
10.18.1
Amendment to Rabbi Trust Agreement dated February 25, 2002 (incorporated by reference to Exhibit 10.39.1 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002; File No. 000-49987).
10.19
ConocoPhillips Directors’ Charitable Gift Program (incorporated by reference to Exhibit 10.40 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2003; File No. 000-49987).
10.19.1
First and Second Amendments to the ConocoPhillips Directors’ Charitable Gift Program (incorporated by reference to Exhibit 10 to the Quarterly Report of ConocoPhillips on Form 10-Q for the quarterly period ended June 30, 2008; File No. 001-32395).
10.20
ConocoPhillips Matching Gift Plan for Directors and Executives (incorporated by reference to Exhibit 10.41 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2003; File No. 000-49987).
10.21.1
Key Employee Deferred Compensation Plan of ConocoPhillips-Title I (incorporated by reference to Exhibit 10.23.1 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2005; File No. 001-32395).
10.21.2
Key Employee Deferred Compensation Plan of ConocoPhillips-Title II (incorporated by reference to Exhibit 10.21.2 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2008; File No. 001-32395).
10.22
ConocoPhillips Key Employee Change in Control Severance Plan (incorporated by reference to Exhibit 10.22 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2008; File No. 001-32395).
10.23
ConocoPhillips Executive Severance Plan (incorporated by reference to Exhibit 10.23 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2008; File No. 001-32395).
10.24
2004 Omnibus Stock and Performance Incentive Plan of ConocoPhillips (incorporated by reference to Appendix C of ConocoPhillips’ Proxy Statement on Schedule 14A relating to the 2004 Annual Meeting of Shareholders; File No. 000-49987).
10.25
Aircraft Time Sharing Agreement by and between James J. Mulva and ConocoPhillips (incorporated by reference to Exhibit 10 of the Quarterly Report of ConocoPhillips on Form 10-Q for the quarterly period ended June 30, 2007; File No. 001-32395).
10.26
Form of Stock Option Award Agreement under the ConocoPhillips Stock Option and Stock Appreciation Rights Program (incorporated by reference to Exhibit 10.26 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2008; File No. 001-32395).
Exhibit
Number
Description
10.27
Form of Restricted Stock Unit Award Agreement under the ConocoPhillips Performance Share Program (incorporated by reference to Exhibit 10.27 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2008; File No. 001-32395).
10.28
Omnibus Amendments to certain ConocoPhillips employee benefit plans, adopted December 7, 2007 (incorporated by reference to Exhibit 10.30 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2007; File No. 001-32395).
10.29
Letter Agreement between ConocoPhillips and John E. Lowe, dated October 1, 2008 (incorporated by reference to Exhibit 99.1 to the Current Report of ConocoPhillips on Form 8-K filed on October 1, 2008; File No. 001-32395).
10.30
Annex to Nonqualified Deferred Compensation Arrangements of ConocoPhillips (incorporated by reference to Exhibit 10.30 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2008; File No. 001-32395).
10.31
2009 Omnibus Stock and Performance Incentive Plan of ConocoPhillips (incorporated by reference to Appendix A of ConocoPhillips’ Proxy Statement on Schedule 14A relating to the 2009 Annual Meeting of Shareholders; File No. 001-32395).
Computation of Ratio of Earnings to Fixed Charges.
List of Subsidiaries of ConocoPhillips.
Consent of Ernst & Young LLP, Independent Registered Public Accounting Firm.
31.1
Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
31.2
Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
Certifications pursuant to 18 U.S.C. Section 1350.
101. INS
XBRL Instance Document.
101. SCH
XBRL Schema Document.
101. CAL
XBRL Calculation Linkbase Document.
101. DEF
XBRL Definition Linkbase Document.
101. LAB
XBRL Labels Linkbase Document.
101. PRE
XBRL Presentation Linkbase Document.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
CONOCOPHILLIPS
February 25, 2010 /s/ James J. Mulva
James J. Mulva
Chairman of the Board of Directors
and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed, as of February 25, 2010, on behalf of the registrant by the following officers in the capacity indicated and by a majority of directors.
Signature
Title
/s/ James J. Mulva
James J. Mulva
Chairman of the Board of Directors
and Chief Executive Officer
(Principal executive officer)
/s/ Sigmund L. Cornelius
Sigmund L. Cornelius
Senior Vice President, Finance,
and Chief Financial Officer
(Principal financial officer)
/s/ Glenda M. Schwarz
Glenda M. Schwarz
Vice President and Controller
(Principal accounting officer)
/s/ Richard L. Armitage
Richard L. Armitage
Director
/s/ Richard H. Auchinleck
Richard H. Auchinleck
Director
/s/ James E. Copeland, Jr.
James E. Copeland, Jr.
Director
/s/ Kenneth M. Duberstein
Kenneth M. Duberstein
Director
/s/ Ruth R. Harkin
Ruth R. Harkin
Director
/s/ Harold W. McGraw, III
Harold W. McGraw, III
Director
/s/ Robert A. Niblock
Robert A. Niblock
Director
/s/ Harald J. Norvik
Harald J. Norvik
Director
/s/ William K. Reilly
William K. Reilly
Director
/s/ Bobby S. Shackouls
Bobby S. Shackouls
Director
/s/ Victoria J. Tschinkel
Victoria J. Tschinkel
Director
/s/ Kathryn C. Turner
Kathryn C. Turner
Director
/s/ William E. Wade, Jr.
William E. Wade, Jr.
Director