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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
SCHEDULE 14A
Proxy Statement Pursuant to Section 14(a) of the Securities
Exchange Act of 1934 (Amendment No. )
Filed by the Registrant x
Filed by a Party other than the Registrant ¨
Check the appropriate box:
¨ Preliminary Proxy Statement
¨ Confidential, for Use of the Commission Only (as permitted by Rule 14a-6(e)(2))
x Definitive Proxy Statement
¨ Definitive Additional Materials
¨ Soliciting Material Pursuant to §240.14a-12
ConocoPhillips
(Name of Registrant as Specified In Its Charter)
(Name of Person(s) Filing Proxy Statement, if other than the Registrant)
Payment of Filing Fee (Check the appropriate box):
x No fee required.
¨ Fee computed on table below per Exchange Act Rules 14a-6(i)(4) and 0-11.
| 1) | Title of each class of securities to which transaction applies: |
| 2) | Aggregate number of securities to which transaction applies: |
| 3) | Per unit price or other underlying value of transaction computed pursuant to Exchange Act Rule 0-11 (set forth the amount on which the filing fee is calculated and state how it was determined): |
| 4) | Proposed maximum aggregate value of transaction: |
| 5) | Total fee paid: |
| ¨ | Fee paid previously with preliminary materials. |
| ¨ | Check box if any part of the fee is offset as provided by Exchange Act Rule 0-11(a)(2) and identify the filing for which the offsetting fee was paid previously. Identify the previous filing by registration statement number, or the Form or Schedule and the date of its filing. |
| 1) | Amount Previously Paid: |
| 2) | Form, Schedule or Registration Statement No.: |
| 3) | Filing Party: |
| 4) | Date Filed: |
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NOTICE OF 2010 ANNUAL STOCKHOLDERS MEETING
AND PROXY STATEMENT
March 31, 2010
Dear ConocoPhillips Stockholder:
On behalf of your board of directors and management, you are cordially invited to attend the Annual Meeting of Stockholders to be held at the Omni Houston Hotel at Westside, 13210 Katy Freeway, Houston, Texas, on Wednesday, May 12, 2010, at 9:00 a.m.
Your vote is important. Whether or not you plan to attend the Annual Meeting, please vote as soon as possible. You may vote on the Internet, by telephone, or, if this proxy statement was mailed to you, by completing and mailing the enclosed traditional proxy card. Please review the instructions on the proxy card or the electronic proxy material delivery notice regarding each of these voting options. Please note that submitting a proxy using any one of these methods will not prevent you from attending the meeting and voting in person. You will find information regarding the matters to be voted on at the meeting in the proxy statement.
In addition to the formal items of business to be brought before the meeting, there will be a report on ConocoPhillips’ operations during 2009 followed by a question and answer period. Your interest in ConocoPhillips is appreciated. We look forward to seeing you on May 12th.
Sincerely,
J. J. Mulva
Chairman of the Board and
Chief Executive Officer
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| Corporate Governance Matters and Communications with the Board |
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| Proposals To Be Voted On |
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| Proposal to Ratify the Appointment of Ernst & Young LLP (Item 2) |
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| Executive Compensation |
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| Stock Ownership |
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NOTICE OF 2010 ANNUAL MEETING OF STOCKHOLDERS
| Time |
9:00 a.m. (CDT) on Wednesday, May 12, 2010 |
| Place |
Omni Houston Hotel at Westside |
13210 Katy Freeway
Houston, Texas 77079
| Items of Business |
To elect Directors (page 11); |
To ratify the appointment of Ernst & Young LLP as independent registered public accounting firm for the Company for 2010 (page 18);
To consider and vote on eight stockholder proposals (pages 20 through 40); and
To transact other business properly coming before the meeting.
| Who Can Vote |
You can vote if you were a stockholder of record as of March 15, 2010. |
| Voting by Proxy |
Please submit a proxy as soon as possible so that your shares can be voted at the meeting in accordance with your instructions. You may submit your proxy: |
- Over the Internet
- By telephone, or
- By mail.
| Date of Mailing |
This notice and the proxy statement are first being mailed to stockholders on or about March 31, 2010. |
By Order of the Board of Directors
Janet Langford Kelly
Corporate Secretary
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Who is soliciting my vote?
The Board of Directors of ConocoPhillips is soliciting your vote at the 2010 Annual Meeting of ConocoPhillips’ stockholders.
How does the Board recommend that I vote my shares?
The Board’s recommendation can be found with the description of each item in this proxy statement. In summary, the Board recommends a vote:
| • | FOR the Board’s proposal to elect nominated Directors; |
| • | FOR the Board’s proposal to ratify the appointment of Ernst & Young LLP as ConocoPhillips’ independent registered public accounting firm for 2010; and |
| • | AGAINST each of the stockholder proposals. |
Unless you give other instructions on your proxy card, the persons named as proxy holders on the proxy card will vote in accordance with the recommendations of the Board of Directors.
Who is entitled to vote?
You may vote if you were the record owner of ConocoPhillips common stock as of the close of business on March 15, 2010. Each share of common stock is entitled to one vote. As of March 15, 2010, we had 1,526,898,771 shares of common stock outstanding and entitled to vote. There is no cumulative voting.
How many votes must be present to hold the meeting?
Your shares are counted as present at the Annual Meeting if you attend the meeting and vote in person or if you properly return a proxy by Internet, telephone or mail. In order for us to hold our meeting, holders of a majority of our outstanding shares of common stock as of March 15, 2010, must be present in person or by proxy at the meeting. This is referred to as a quorum. Abstentions and broker non-votes will be counted for purposes of establishing a quorum at the meeting.
What is a broker non-vote?
If a broker does not have discretion to vote shares held in street name on a particular proposal and does not receive instructions from the beneficial owner on how to vote those shares, the broker may return the proxy card without voting on that proposal. This is known as a broker non-vote. Broker non-votes will have no effect on the vote for any matter properly introduced at the meeting.
How many votes are needed to approve each of the proposals?
All proposals submitted and each of the director nominees require the affirmative “FOR” vote of a majority of those shares present in person or represented by proxy at the meeting and entitled to vote on the proposal.
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How do I vote?
You can vote either in person at the meeting or by proxy without attending the meeting.
This proxy statement, the accompanying proxy card and the Company’s 2009 Summary Annual Report to Stockholders are being made available on the Internet at www.proxyvote.com through the notice and access process to the Company’s stockholders. The year 2009 consolidated financial statements and auditors’ report, management’s discussion and analysis of financial condition and results of operations, information concerning the quarterly financial data for the past two fiscal years, and other information, are provided in Appendix A to the proxy statement.
To vote by proxy, you must do one of the following:
| • | Vote over the Internet (instructions are on the proxy card); |
| • | Vote by telephone (instructions are on the proxy card); or |
| • | If you elected to receive a hard copy of your proxy materials, fill out the enclosed proxy card, date and sign it, and return it in the enclosed postage-paid envelope. |
If you hold your ConocoPhillips stock in a brokerage account (that is, in “street name”), your ability to vote by telephone or over the Internet depends on your broker’s voting process. Please follow the directions on your proxy card or voter instruction form carefully.
Even if you plan to attend the meeting, we encourage you to vote your shares by proxy. If you plan to vote in person at the Annual Meeting and you hold your ConocoPhillips stock in street name, you must obtain a proxy from your broker and bring that proxy to the meeting.
How do I vote if I hold my stock through ConocoPhillips’ employee benefit plans?
If you hold your stock through ConocoPhillips’ employee benefit plans, you must either:
| • | Vote over the Internet (instructions are in the email sent to you or on the notice and access form); |
| • | Vote by telephone (instructions are on the notice and access form); or |
| • | If you received a hard copy of your proxy materials, fill out the enclosed voting instruction form, date and sign it, and return it in the enclosed postage-paid envelope. |
You will receive a separate voting instruction form for each employee benefit plan in which you have an interest. Please pay close attention to the deadline for returning your voting instruction form to the plan trustee. The voting deadline for each plan is set forth on the voting instruction form. Please note that different plans may have different deadlines.
Can I change my vote?
Yes. You can change or revoke your vote at any time before the polls close at the Annual Meeting. You can do this by:
| • | Voting again by telephone or over the Internet prior to 11:59 p.m. Eastern Daylight Time on May 11, 2010; |
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| • | Signing another proxy card with a later date and returning it to us prior to the meeting; |
| • | Sending our Corporate Secretary a written document revoking your earlier proxy; or |
| • | Voting again at the meeting. |
Who counts the votes?
We have hired Broadridge Financial Solutions, Inc., to count the votes represented by proxies cast by ballot, telephone, and the Internet. Employees of Broadridge will act as Inspectors of Election.
Will my shares be voted if I don’t provide my proxy and don’t attend the Annual Meeting?
If you do not provide a proxy or vote your shares held in your name, your shares will not be voted.
If you hold your shares in street name, your broker may be able to vote your shares for certain “routine” matters even if you do not provide the broker with voting instructions. Only the ratification of Ernst & Young LLP as our independent registered public accounting firm for 2010 is considered to be a routine matter.
If you do not give your broker instructions on how to vote your shares the broker will return the proxy card without voting on proposals not considered “routine.” This is a broker non-vote. Votes in connection with the approval of the election of directors and the eight stockholder proposals are not considered routine matters. The broker may not vote on these matters without instructions from you.
As more fully described on your proxy card, if you hold your shares through certain of ConocoPhillips’ employee benefit plans and do not vote your shares, your shares (along with all other shares in the plan for which votes are not cast) may be voted pro rata by the trustee in accordance with the votes directed by other participants in the plan who elect to act as a fiduciary entitled to direct the trustee of the applicable plan on how to vote the shares.
How are votes counted?
For all proposals, you may vote “FOR,” “AGAINST,” or “ABSTAIN.” If you “ABSTAIN,” it has the same effect as a vote “AGAINST.”
What if I return my proxy but don’t vote for some of the matters listed on my proxy card?
If you return a signed proxy card without indicating your vote, your shares will be voted “FOR” the director nominees listed on the card, “FOR” the ratification of Ernst & Young LLP as ConocoPhillips’ independent registered public accounting firm, and “AGAINST” each of the stockholder proposals.
Could other matters be decided at the Annual Meeting?
We are not aware of any other matters that will be considered at the Annual Meeting. If any other matters are properly brought before the Annual Meeting, the persons named in your proxies will vote in accordance with their best judgment. Discretionary authority to vote on other matters is included in the proxy.
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Who can attend the meeting?
The Annual Meeting is open to all holders of ConocoPhillips common stock. Each stockholder is permitted to bring one guest. No cameras, recording equipment, large bags, briefcases or packages will be permitted in the Annual Meeting, and security measures will be in effect to ensure the safety of attendees.
Do I need a ticket to attend the Annual Meeting?
Yes, you will need an admission ticket or proof of ownership of ConocoPhillips stock to enter the meeting. If your shares are registered in your name, you will find an admission ticket attached to the proxy card sent to you. If your shares are in the name of your broker or bank or you received your materials electronically, you will need to bring evidence of your stock ownership, such as your most recent brokerage statement. All stockholders will be required to present valid picture identification. IF YOU DO NOT HAVE VALID PICTURE IDENTIFICATION AND EITHER AN ADMISSION TICKET OR PROOF THAT YOU OWN CONOCOPHILLIPS STOCK, YOU MAY NOT BE ADMITTED INTO THE MEETING.
How can I access ConocoPhillips’ proxy materials and annual report electronically?
This proxy statement, the accompanying proxy card and the Company’s 2009 Summary Annual Report are being made available to the Company’s stockholders on the internet at www.proxyvote.com through the notice and access process. Most stockholders can elect to view future proxy statements and annual reports over the Internet instead of receiving paper copies in the mail.
If you own ConocoPhillips stock in your name, you can choose this option and save us the cost of producing and mailing these documents by checking the box for electronic delivery on your proxy card, or by following the instructions provided when you vote by telephone or over the Internet. If you hold your ConocoPhillips stock through a bank, broker or other holder of record, please refer to the information provided by that entity for instructions on how to elect to view future proxy statements and annual reports over the Internet.
If you choose to view future proxy statements and annual reports over the Internet, you will receive a Notice of Internet Availability next year containing the Internet address to use to access our proxy statement and annual report. Your choice will remain in effect unless you change your election following the receipt of a Notice of Internet Availability. You do not have to elect Internet access each year. If you later change your mind and would like to receive paper copies of our proxy statements and annual reports, you can request both by phone at (800) 579-1639, by email at sendmaterial@proxyvote.com and through the internet at www.proxyvote.com. You will need your 12 digit control number located on your Notice of Internet Availability to request a package. You will also be provided with the opportunity to receive a copy of the proxy statement and annual report in future mailings.
Will my vote be kept confidential?
The Company’s Board of Directors has a policy that all stockholder proxies, ballots, and tabulations that identify stockholders are to be maintained in confidence. No such document will
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be available for examination, and the identity and vote of any stockholder will not be disclosed, except as necessary to meet legal requirements and allow the inspectors of election to certify the results of the stockholder vote. The policy also provides that inspectors of election for stockholder votes must be independent and cannot be employees of the Company. Occasionally, stockholders provide written comments on their proxy card that may be forwarded to management.
What is the cost of this proxy solicitation?
Our Board of Directors has sent you this proxy statement. Our directors, officers and employees may solicit proxies by mail, by telephone or in person. Those persons will receive no additional compensation for any solicitation activities. We will request banking institutions, brokerage firms, custodians, trustees, nominees and fiduciaries to forward solicitation materials to the beneficial owners of common stock held of record by those entities, and we will, upon the request of those record holders, reimburse reasonable forwarding expenses. We will pay the costs of preparing, printing, assembling and mailing the proxy materials used in the solicitation of proxies. In addition, we have hired Mackenzie Partners, Inc., to assist us in soliciting proxies, which it may solicit by telephone or in person. We anticipate paying Mackenzie Partners, Inc. a fee of $15,500, plus expenses.
Why did my household receive a single set of proxy materials?
Securities and Exchange Commission (SEC) rules permit us to deliver a single copy of an annual report and proxy statement to any household not participating in electronic proxy material delivery at which two or more stockholders reside, if we believe the stockholders are members of the same family. This benefits both you and the Company, as it eliminates duplicate mailings that stockholders living at the same address receive and it reduces our printing and mailing costs. This rule applies to any annual reports, proxy statements, proxy statements combined with a prospectus or information statements. Each stockholder will continue to receive a separate proxy card or voting instruction card. Your household may have received a single set of proxy materials this year. If you prefer to receive your own copy now or in future years, please request a duplicate set by phone at (800) 579-1639, through the internet at www.proxyvote.com, by email at sendmaterial@proxyvote.com, or by writing to ConocoPhillips, c/o Broadridge, 51 Mercedes Way, Edgewood, NY 11717. If a broker or other nominee holds your shares, you may continue to receive some duplicate mailings. Certain brokers will eliminate duplicate account mailings by allowing stockholders to consent to such elimination, or through implied consent if a stockholder does not request continuation of duplicate mailings. Since not all brokers and nominees may offer stockholders the opportunity this year to eliminate duplicate mailings, you may need to contact your broker or nominee directly to discontinue duplicate mailings to your household.
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Corporate Governance Matters and Communications with the Board
The Committee on Directors’ Affairs and our Board annually review the Company’s governance structure to take into account changes in SEC and New York Stock Exchange (NYSE) rules, as well as current best practices. Our Corporate Governance Guidelines, posted on the Company’s Internet site under the “Governance” caption and available in print upon request (see “Available Information” on page 94), address the following matters, among others: director qualifications, director responsibilities, Board committees, director access to officers, employees and independent advisors, director compensation, Board performance evaluations, director orientation and continuing education, and CEO evaluation and succession planning.
The Corporate Governance Guidelines also contain director independence standards, which are consistent with the standards set forth in the NYSE listing standards, to assist the Board in determining the independence of the Company’s directors. The Board has determined that each director, except Mr. Mulva, meets the standards regarding independence set forth in the Corporate Governance Guidelines and is free of any material relationship with the Company (either directly or as a partner, stockholder or officer of an organization that has a relationship with the Company). In making such determination, the Board specifically considered the fact that many of our directors are directors, retired officers and stockholders of companies with which we conduct business. In addition, some of our directors serve as employees of, or consultants to, companies which do business with ConocoPhillips and its affiliates (as further described in “Related Party Transactions” on page 9). Finally, some of our directors may purchase retail products (such as gasoline, fuel additives or lubricants) from the Company. In all cases, it was determined that the nature of the business conducted and the interest of the director by virtue of such position were immaterial both to the Company and to such director.
The Board of Directors maintains a process for stockholders and interested parties to communicate with the Board. Stockholders and interested parties may write or call our Board of Directors by contacting our Corporate Secretary, Janet Langford Kelly, as provided below:
| • | Mailing Address: Corporate Secretary ConocoPhillips P.O. Box 4783 Houston, TX 77210-4783 |
| • | Phone Number: (281) 293-3075 |
Relevant communications are distributed to the Board or to any individual director or directors, as appropriate, depending on the facts and circumstances outlined in the communication. In that regard, the Board has requested that certain items that are unrelated to its duties and responsibilities be excluded, such as: business solicitations or advertisements; junk mail and mass mailings; new product suggestions; product complaints; product inquiries; resumes and other forms of job inquiries; spam; and surveys. In addition, material that is unduly hostile, threatening, illegal or similarly unsuitable will be excluded. Any communication that is filtered out is made available to any outside director upon request.
Recognizing that director attendance at the Company’s Annual Meeting can provide the Company’s stockholders with an opportunity to communicate with Board members about issues affecting the Company, the Company actively encourages its directors to attend the Annual Meeting of Stockholders. In 2009, all of the Company’s directors attended the Annual Meeting with the exception of Mr. Duberstein.
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The Company currently combines the offices of Chairman and Chief Executive Officer. The Board believes it is in the best interests of the Company’s shareholders to combine these offices because it places the Company’s senior most executive officer in a position to guide the Board in setting priorities for the Company and addressing the risks and challenges the Company faces. The Board believes that, while its independent directors bring a diversity of skills and perspectives to the Board, the Company’s CEO, by virtue of his day-to-day involvement in managing the Company, is in the best position to lead the Board.
The Board believes there is no single organizational model that is the best and most effective in all circumstances. As a consequence, the Board periodically considers whether the offices of Chairman and CEO should be combined and who should serve in such capacities. The Board retains the authority to separate the positions of Chairman and CEO if it deems appropriate in the future.
Our Corporate Governance Guidelines provide that non-employee directors will meet in executive session at each Board meeting. The Chairman of the Committee on Directors’ Affairs, Mr. Auchinleck, presides at these sessions and is responsible for setting the agenda for such meetings.
While the Company’s management is responsible for the day-to-day management of risks to the Company, the Board has broad oversight responsibility for the Company’s risk management programs. In this oversight role, the Board is responsible for satisfying itself that the risk management processes designed and implemented by the Company’s management are functioning as directed, and that necessary steps are taken to foster a culture of risk-adjusted decision-making throughout the organization. In carrying out its oversight responsibility, the Board has delegated to individual Board Committees certain elements of its oversight function. In this context, the Board recently delegated authority to the Audit and Finance Committee to facilitate coordination among the Board’s Committees with respect to oversight of the Company’s risk management programs. As part of this authority, the Audit and Finance Committee will regularly discuss the Company’s risk assessment and risk management policies to ensure that our risk management programs are functioning properly. Additionally, the Chairman of the Audit and Finance Committee will meet with the Chairs of each Board Committee each year to discuss the Board’s oversight of the Company’s risk management programs. The Board receives regular updates from its Committees on individual areas of risk, such as updates on financial risks from the Audit and Finance Committee, health, safety and environmental risks from the Public Policy Committee and compensation program risks from the Human Resources and Compensation Committee. The Board exercises its oversight function with respect to all material risks to the Company, which are identified and discussed in the Company’s public filings with the Securities and Exchange Commission.
Code of Business Ethics and Conduct
ConocoPhillips has adopted a worldwide Code of Business Ethics and Conduct for Directors and Employees designed to help directors and employees resolve ethical issues in an increasingly complex global business environment. Our Code of Business Ethics and Conduct applies to all directors and employees, including the Chief Executive Officer and the Chief Financial Officer. Our Code of Business Ethics and Conduct covers topics including, but not limited to, conflicts of interest, insider trading,
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competition and fair dealing, discrimination and harassment, confidentiality, payments to government personnel, anti-boycott laws, U.S. embargos and sanctions, compliance procedures and employee complaint procedures. Our Code of Business Ethics and Conduct is posted on our Internet site under the “Governance” caption. Stockholders may also request printed copies of our Code of Business Ethics and Conduct by following the instructions located under the caption “Available Information” on page 94.
Our Code of Business Ethics and Conduct requires that all directors and executive officers promptly bring to the attention of the General Counsel and, in the case of directors, the Chairman of the Committee on Directors’ Affairs or, in the case of executive officers, the Chairman of the Audit and Finance Committee, any transaction or relationship that arises and of which she or he becomes aware that reasonably could be expected to constitute a related party transaction. Any such transaction or relationship is reviewed by the Company’s management and the appropriate Board Committee to ensure that it does not constitute a conflict of interest and is reported appropriately. Additionally, the Committee on Directors’ Affairs conducts an annual review of related party transactions between each of our directors and the Company (and its subsidiaries) and makes recommendations to the Board regarding the continued independence of each board member. In 2009, there were no related party transactions in which the Company (or a subsidiary) was a participant and in which any director or executive officer (or their immediate family members) had a direct or indirect material interest. The Committee on Directors’ Affairs also considered relationships which, while not constituting related party transactions where a director had a direct or indirect material interest, nonetheless involved transactions between the Company and a company with which a director is affiliated, whether through employment status or by virtue of serving as director. Included in its review were ordinary course of business transactions with companies employing a director, including ordinary course of business transactions with The McGraw-Hill Companies, of which Mr. McGraw serves as Chairman, President and Chief Executive Officer and Lowe’s Companies, Inc., of which Mr. Niblock serves as Chairman of the Board and Chief Executive Officer. The Committee determined that there were no transactions impairing the independence of any director.
Nominating Processes of the Committee on Directors’ Affairs
The Committee on Directors’ Affairs (the “Committee”) comprises four non-employee directors, all of whom are independent under NYSE listing standards and our Corporate Governance Guidelines. The Committee identifies, investigates and recommends director candidates to the Board with the goal of creating balance of knowledge, experience and diversity. Generally, the Committee identifies candidates through business and organizational contacts of the directors and management. Our By-Laws permit stockholders to nominate candidates for director election at a stockholders meeting whether or not such nominee is submitted to and evaluated by the Committee on Directors’ Affairs. Shareholders who wish to submit nominees for election at an annual or special meeting of shareholders should follow the procedures described on page 93. The Committee will consider director candidates recommended by stockholders. If a stockholder wishes to recommend a candidate for nomination by the Committee, he or she should follow the same procedures set forth above for nominations to be made directly by the stockholder. In addition, the stockholder should provide such other information as it may deem relevant to the Committee’s evaluation. Candidates recommended by the Company’s stockholders are evaluated on the same basis as candidates recommended by the Company’s directors, CEO, other executive officers, third-party search firms or other sources.
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Audit and Finance Committee Report
The Audit and Finance Committee (the “Audit Committee”) assists the Board in fulfilling its responsibility to provide independent, objective oversight for ConocoPhillips’ financial reporting functions and internal control systems. The Audit Committee currently comprises four non-employee directors. The Board has determined that the members of the Audit Committee satisfy the requirements of the NYSE as to independence, financial literacy and expertise. The Board has determined that at least one member, James E. Copeland, Jr., is an audit committee financial expert as defined by the SEC. The responsibilities of the Audit Committee are set forth in the written charter adopted by ConocoPhillips’ Board of Directors and last amended on December 2, 2009, and which is available on our website www.conocophillips.com under the caption “Governance.” One of the Audit Committee’s primary responsibilities is to assist the Board in its oversight of the integrity of the Company’s financial statements. The following report summarizes certain of the Committee’s activities in this regard for 2009.
Review with Management. The Audit Committee has reviewed and discussed with management the audited consolidated financial statements included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2009, and management’s assessment of the effectiveness of the Company’s internal control over financial reporting, as of December 31, 2009, included therein.
Discussions with Independent Registered Public Accounting Firm. The Audit Committee has discussed with Ernst & Young LLP, independent registered public accounting firm for ConocoPhillips, the matters required to be discussed by Statement on Auditing Standards No. 61, Communication with Audit Committees, as amended. The Audit Committee has received the written disclosures and the letter from Ernst & Young LLP required by applicable requirements of the Public Company Accounting Oversight Board, and has discussed with that firm its independence from ConocoPhillips.
Recommendation to the ConocoPhillips Board of Directors. Based on its review and discussions noted above, the Audit Committee recommended to the Board of Directors that the audited financial statements be included in ConocoPhillips’ Annual Report on Form 10-K for the year ended December 31, 2009.
THE CONOCOPHILLIPS AUDIT AND FINANCE COMMITTEE
James E. Copeland, Jr., Chairman
Robert A. Niblock
Harald J. Norvik
Victoria J. Tschinkel
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PROPOSALS TO BE VOTED ON
Election of Directors and Director Biographies
(Item 1 on the Proxy Card)
What am I voting on?
You are voting on a proposal to re-elect each of the 14 directors to a one year term as a director of the Company.
What is the makeup of the Board of Directors and how often are the members elected?
Our Board of Directors currently has 14 members. Directors are elected at the Annual Meeting of Stockholders every year. Any director vacancies created between annual stockholder meetings (such as by a current director’s death, resignation or removal for cause or an increase in the number of directors) may be filled by a majority vote of the remaining directors then in office. Any director appointed in this manner would hold office until the next election. If a vacancy resulted from an action of our stockholders, only our stockholders are entitled to elect a successor. Each director is required to retire at the next annual stockholders’ meeting of the Company following his or her 72nd birthday.
What if a nominee is unable or unwilling to serve?
That is not expected to occur. If it does and the Board does not elect to reduce the size of the Board, shares represented by proxies will be voted for a substitute nominated by the Board of Directors.
How are directors compensated?
Please see our discussion of director compensation beginning on page 83.
How often did the Board meet in 2009?
The Board of Directors met nine times in 2009. Each director attended at least 75 percent of the aggregate of:
| • | the total number of meetings of the Board (held during the period for which she or he has been a director); and |
| • | the total number of full-committee meetings held by all committees of the board on which she or he served (during the periods that she or he served). |
Do the Board committees have written charters?
Yes. The charters for our Audit and Finance Committee, Executive Committee, Human Resources and Compensation Committee, Committee on Directors’ Affairs and Public Policy Committee can be found on ConocoPhillips’ website at www.conocophillips.com under the “Governance” caption (accessed through the “Investor Relations” link). Stockholders may also request printed copies of our Board committee charters by following the instructions located under the caption “Available Information” on page 94.
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What are the Committees of the Board?
| Committee | Members | Principal Functions | Number of Meetings in 2009 | |||||
| Audit and Finance | James E. Copeland, Jr.* Robert A. Niblock Harald J. Norvik Victoria J. Tschinkel |
• | Discusses with management, the independent auditors, and the internal auditors the integrity of the Company’s accounting policies, internal controls, financial statements, financial reporting practices, and select financial matters, covering the Company’s capital structure, complex financial transactions, financial risk management, retirement plans and tax planning. | 15 | ||||
| • |
Reviews significant corporate risk exposures and steps management has taken to monitor, control and report such exposures. |
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| • |
Monitors the qualifications, independence and performance of our independent auditors and internal auditors. |
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| • | Monitors our overall direction and compliance with legal and regulatory requirements and corporate governance, including our Code of Business Ethics and Conduct. | |||||||
| • | Maintains open and direct lines of communication with the Board and our management, internal auditors and independent auditors. | |||||||
| Executive | James J. Mulva* Richard H. Auchinleck James E. Copeland, Jr. Ruth R. Harkin William E. Wade, Jr. |
• | Exercises the authority of the full Board between Board meetings on all matters other than (1) those matters expressly delegated to another committee of the Board, (2) the adoption, amendment or repeal of any of our By-Laws and (3) matters which cannot be delegated to a committee under statute or our Certificate of Incorporation or By-Laws. | 1 | ||||
| Human Resources and Compensation | William E. Wade, Jr.* Harold W. McGraw III Kathryn C. Turner | • | Oversees our executive compensation policies, plans, programs and practices. | 7 | ||||
| • | Assists the Board in discharging its responsibilities relating to the fair and competitive compensation of our executives and other key employees. | |||||||
| • | Annually reviews the performance (together with the Directors’ Affairs Committee) and sets the compensation of the CEO. | |||||||
| Directors’ Affairs | Richard H. Auchinleck* Richard L. Armitage Harold W. McGraw III Kathryn C. Turner | • | Selects and recommends director candidates to the Board to be submitted for election at the Annual Meeting and to fill any vacancies on the Board. | 7 | ||||
| • | Recommends committee assignments to the Board. | |||||||
| • | Reviews and recommends to the Board compensation and benefits policies for our non-management directors. | |||||||
| • | Reviews and recommends to the Board appropriate corporate governance policies and procedures for our Company. | |||||||
| • | Conducts an annual assessment of the qualifications and performance of the Board. | |||||||
| • | Reviews and reports to the Board annually on the performance of, and succession planning for, the CEO. | |||||||
| • | Together with the Human Resources and Compensation Committee, annually reviews the performance of the CEO. | |||||||
| Public Policy | Ruth R. Harkin* Kenneth M. Duberstein William K. Reilly Bobby S. Shackouls |
• | Advises the Board on current and emerging domestic and international public policy issues. | 6 | ||||
| • | Assists the Board in the development and review of policies and budgets for charitable and political contributions. |
| * | Committee Chairperson |
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What criteria were considered by the Committee on Directors’ Affairs in selecting the nominees?
In selecting the 2010 nominees for director, the Committee on Directors’ Affairs sought candidates who possess the highest personal and professional ethics, integrity and values, and are committed to representing the long-term interests of the Company’s stockholders. In addition to reviewing a candidate’s background and accomplishments, the Committee reviewed candidates for director in the context of the current composition of the Board and the evolving needs of the Company’s businesses. The Committee also considered the number of boards on which the candidate already serves. It is the Board’s policy that at all times at least a substantial majority of its members meets the standards of independence promulgated by the NYSE and the SEC, and as set forth in the Company’s Corporate Governance Guidelines. The Committee also seeks to ensure that the Board reflects a range of talents, ages, skills, diversity, and expertise, particularly in the areas of accounting and finance, management, domestic and international markets, leadership, and oil and gas related industries, sufficient to provide sound and prudent guidance with respect to the Company’s operations and interests. The Board seeks to maintain a diverse membership, but does not have a separate policy on diversity. The Board also requires that its members be able to dedicate the time and resources necessary to ensure the diligent performance of their duties on the Company’s behalf, including attending Board and applicable committee meetings.
The following are some of the key qualifications and skills the Committee on Directors’ Affairs considered in evaluating the director nominees. The individual biographies below provide additional information about each nominee’s specific experiences, qualifications and skills.
| ¡ | CEO experience. We believe that directors with experience as CEO of public corporations provide the Company with valuable insights. These individuals have a demonstrated record of leadership qualities and a practical understanding of organizations, processes, strategy, risk management and the methods to drive change and growth. Through their service as top leaders at other organizations, they also have access to important sources of market intelligence, analysis and relationships that benefit the Company. |
| ¡ | Financial reporting experience. We believe that an understanding of finance and financial reporting processes is important for our directors. The Company measures its operating and strategic performance by reference to financial targets. In addition, accurate financial reporting and robust auditing are critical to the Company’s success. We seek to have a number of directors who qualify as audit committee financial experts, and we expect all of our directors to be financially knowledgeable. |
| ¡ | Industry experience. We seek to have directors with experience as executives, directors or other leadership positions in the energy industry. These directors have valuable perspective on energy industry business cycles and other issues specific to the Company’s business. |
| ¡ | Government experience. We seek directors with governmental experience because the energy industry is heavily regulated and is directly affected by governmental actions and decisions. The Company recognizes the importance of working constructively with governments around the world and directors with government experience offer valuable insight in this regard. |
| ¡ | Global experience. As a global, integrated energy company, the Company’s future success depends, in part, on its success in growing its businesses outside the United States. Our directors with global business experience provide valued perspective on operations globally. |
| ¡ | Environmental experience. The perspective of directors who have experience within the environmental regulatory field is valued as we implement policies and conduct operations in order to ensure that our actions today will not only provide the energy needed to drive economic growth and social well-being, but also secure a stable and healthy environment for tomorrow. |
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Who are this year’s nominees?
All directors are standing for annual election this year to hold office until the 2011 Annual Meeting of Stockholders. Included below is a listing of their name, age, tenure and qualifications.
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Richard L. Armitage, 64, Director since March 2006
Mr. Armitage has served as President of Armitage International since March 2005. He is a former U.S. Deputy Secretary of State and held a wide variety of high ranking U.S. diplomatic positions from 1989 to 1993 including: Special Mediator for Water in the Middle East; Special Emissary to King Hussein of Jordan during the 1991 Gulf War; and Ambassador, directing U.S. assistance to the newly independent states of the former Soviet Union. He served as Assistant U.S. Secretary of Defense for International Security Affairs from 1983 to 1989. He serves on the boards of ManTech International Corporation and Transcu, Ltd. The Board believes his extensive experience in government roles and in foreign relations makes him well qualified to serve as a member of the Board.
Skills and Qualifications: Government Experience, Global Experience | |
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Richard H. Auchinleck, 58, Director since August 2002
Mr. Auchinleck began his service as a director of Conoco Inc. in 2001 prior to its merger with Phillips Petroleum Company in 2002. He served as President and Chief Executive Officer of Gulf Canada Resources Limited from 1998 until its acquisition by Conoco in 2001. Prior to his service as CEO, he was Chief Operating Officer of Gulf Canada from 1997 to 1998 and Chief Executive Officer for Gulf Indonesia Resources Limited from 1997 to 1998. Mr. Auchinleck currently serves on the boards of Enbridge Commercial Trust and Telus Corporation and previously served on the board of Red Mile Entertainment Inc. from 2005 to 2008. The Board believes his experience within the energy industry and as a CEO makes him well qualified to serve as a member of the Board.
Skills and Qualifications: CEO Experience, Industry Experience, Global Experience | |
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James E. Copeland, Jr., 65, Director since February 2004
Mr. Copeland served as Chief Executive Officer of Deloitte & Touche and Deloitte Touche Tohmatsu from 1999 to 2003. Mr. Copeland formerly served as Senior Fellow for Corporate Governance with the U.S. Chamber of Commerce and as a Global Scholar with the Robinson School of Business at Georgia State University. Mr. Copeland is currently a member of the boards of Equifax Inc. and Time Warner Cable Inc. and previously served on the board of Coca Cola Enterprises from 2003 to 2008. The Board believes his experience within the financial accounting industry and as a CEO makes him well qualified to serve as a member of the Board.
Skills and Qualifications: CEO Experience, Financial Reporting Experience, Global Experience | |
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Kenneth M. Duberstein, 65, Director since August 2002
Mr. Duberstein began his service as a director of Conoco Inc. in 2000 prior to its merger with Phillips Petroleum Company in 2002. He has served since 1989 as Chairman and Chief Executive Officer of the Duberstein Group, a strategic planning and consulting company. Prior to this, Mr. Duberstein was the White House Chief of Staff from 1988 to 1989 and Deputy Chief of Staff in 1987 to President Ronald Reagan. Mr. Duberstein currently serves on the boards of The Boeing Company, Mack-Cali Realty Corporation, and The Travelers Companies, Inc. The Board believes his government and global and domestic strategic advisory experience makes him well qualified to serve as a member of the Board.
Skills and Qualifications: Government Experience, Global Experience | |
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Ruth R. Harkin, 65, Director since August 2002
Ms. Harkin began her service as a director of Conoco Inc. in 1998 prior to its merger with Phillips Petroleum Company in 2002. Ms. Harkin served as Senior Vice President, International Affairs and Government Relations of United Technologies Corporation (UTC) and was Chair of United Technologies International, UTC’s international representation arm, from June 1997 to February 2005. She also is a former President and Chief Executive Officer of the Overseas Private Investment Corporation. Ms. Harkin currently serves on the board of AbitibiBowater Inc. She previously served on the Board of Bowater Incorporated from 2005 to 2007. She is a member of the Board of Regents of the State of Iowa. The Board believes Ms. Harkin’s experience in government affairs and foreign investments makes her well qualified to serve as a member of the Board.
Skills and Qualifications: Government Experience, Global Experience | |
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Harold W. McGraw III, 61, Director since September 2005
Mr. McGraw currently serves as Chairman, President and Chief Executive Officer of The McGraw-Hill Companies. Prior to his service as Chairman, he served as President and Chief Executive Officer of The McGraw-Hill Companies from 1998 to 2000 and President and Chief Operating Officer of The McGraw-Hill Companies from 1993 to 1998. Mr. McGraw currently serves on the boards of The McGraw-Hill Companies and United Technologies Corporation. The Board believes his experience as a CEO and within the financial reporting industry makes him well qualified to serve as a member of the Board.
Skills and Qualifications: CEO Experience, Financial Reporting Experience, Global Experience | |
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James J. Mulva, 63, Director since August 2002
Mr. Mulva is the Chairman and Chief Executive Officer of ConocoPhillips, serving in such capacities since 2004 and 2002, respectively. Mr. Mulva served as President from 2002 through 2008. Mr. Mulva began his career over 35 years ago with Phillips Petroleum Company. Beginning in 1999 and continuing through its merger with Conoco Inc. in 2002, Mr. Mulva served as Chairman of the Board and Chief Executive Officer of Phillips Petroleum Company. He also served as a member of the Board of Phillips Petroleum Company beginning in 1994 and as the President and Chief Operating Officer of Phillips Petroleum Company from 1994 to June 1999. He currently serves on the board of General Electric Company. The Board believes his service as CEO at ConocoPhillips and Phillips Petroleum Company and experience within the energy industry make him well qualified to serve as Chairman and a member of the Board.
Skills and Qualifications: CEO Experience, Industry Experience, Financial Reporting Experience, Global Experience | |
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Robert A. Niblock, 47, Director since February 2010
Mr. Niblock is Chairman and Chief Executive Officer of Lowe’s Companies, Inc., a position he has held since January 2005. He also served as Lowe’s President from 2003 to 2006, and joined its board of directors when he was named Chairman and CEO-elect in 2004. Mr. Niblock joined Lowe’s in 1993 and, during his career with the company, has served as Vice President and Treasurer, Senior Vice President, and Executive Vice President and CFO. Before joining Lowe’s, Mr. Niblock had a nine-year career with accounting firm Ernst & Young. The Board believes his experiences as a CEO and CFO and his experience within the financial accounting industry make him well qualified to serve as a member of the Board.
Skills and Qualifications: CEO Experience, Financial Reporting Experience | |
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Harald J. Norvik, 63, Director since July 2005
Mr. Norvik currently serves as a Strategic Advisor to Econ-Poyry. He was Chairman and a partner at Econ Management AS from 2002 to 2008. He served as Chairman, President & CEO of Statoil from 1988 to 1999. He currently serves on the boards of Telenor ASA (as Chairman) and Petroleum Geo-Services ASA. The Board believes his experience within the energy industry and as a CEO makes him well qualified to serve as a member of the Board.
Skills and Qualifications: CEO Experience, Industry Experience, Global Experience | |
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William K. Reilly, 70, Director since August 2002
Mr. Reilly began his service as a director of Conoco Inc. in 1998 prior to its merger with Phillips Petroleum Company in 2002. Since June 1999 he has served as President and Chief Executive Officer of Aqua International Partners, an investment group which finances water improvements in developing countries. He is also a Senior Advisor to TPG Capital. He was Administrator of the U.S. Environmental Protection Agency from 1989 to 1993. Mr. Reilly currently serves on the boards of E. I. du Pont de Nemours and Company and Royal Caribbean Cruises Ltd. The Board believes his environmental regulatory background and his government experience make him well qualified to serve as a member of the Board.
Skills and Qualifications: Government Experience, Environmental Experience | |
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Bobby S. Shackouls, 59, Director since March 2006
Mr. Shackouls was Chairman, President and Chief Executive Officer of Burlington Resources Inc. at the time of its acquisition by ConocoPhillips in 2006. Mr. Shackouls served as Chairman of Burlington Resources Inc. beginning in 1997 and President and Chief Executive Officer beginning in 1995. Mr. Shackouls currently serves on the board of The Kroger Co. The Board believes his experience within the energy industry and his tenure as a CEO make him well qualified to serve as a member of the Board.
Skills and Qualifications: CEO Experience, Industry Experience | |
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Victoria J. Tschinkel, 62, Director since August 2002
Ms. Tschinkel began her service as a director of Phillips Petroleum Company in 1993 prior to its merger with Conoco Inc. in 2002. Ms. Tschinkel served as Director of the Florida Nature Conservancy from 2003 to 2006 and was a Senior Environmental Consultant to Landers & Parsons, a Tallahassee, Florida law firm, from 1987 to 2002. Ms. Tschinkel was the Secretary of the Florida Department of Environmental Regulation from 1981 to 1987. She currently serves as Chairwoman of 1000 Friends of Florida. The Board believes her experience within the government and environmental fields makes her well qualified to serve as a member of the Board.
Skills and Qualifications: Government Experience, Environmental Experience | |
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Kathryn C. Turner, 62, Director since August 2002
Ms. Turner began her service as a director of Phillips Petroleum Company in 1995 prior to its merger with Conoco Inc. in 2002. Ms. Turner is currently the Chairperson and Chief Executive Officer of Standard Technology, Inc., a management technology solutions firm she founded in 1985. She currently serves on the board of Carpenter Technology Corporation and served on the board of Schering-Plough Corporation from 2001 to 2009. The Board believes her experience within the management and information technology fields and as a CEO makes her well qualified to serve as a member of the Board.
Skills and Qualifications: CEO Experience | |
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William E. Wade, Jr., 67, Director since March 2006
Mr. Wade served as a director of Burlington Resources Inc. from 2001 through the time of its acquisition by ConocoPhillips in 2006. Mr. Wade served as President of Atlantic Richfield Company from 1998 to 1999 and Executive Vice President of Atlantic Richfield Company from 1993 to 1998. Prior to this, he served in a series of management positions with Atlantic Richfield Company beginning in 1968. The Board believes his experience within the energy industry and as President of Atlantic Richfield makes him well qualified to serve as a member of the Board.
Skills and Qualifications: Industry Experience |
What vote is required to approve this proposal?
Each nominee requires the affirmative vote of a majority of the shares present in person or represented by proxy at the meeting and entitled to vote on the proposal.
What if a director nominee does not receive a majority of votes cast?
Our By-Laws require directors to be elected by the majority of the votes cast with respect to such director (i.e., the number of votes cast “for” a director must exceed the number of votes cast “against” that director). If a nominee who is serving as a director is not elected at the annual meeting and no one else is elected in place of that director, then, under Delaware law, the director would continue to serve on the Board as a “holdover director.” However, under our By-Laws, the holdover director is required to tender his or her resignation to the Board. The Committee on Directors’ Affairs then considers the resignation and recommends to the Board whether to accept or reject the tendered resignation, or whether some other action should be taken. The Board of Directors would then make a decision whether to accept the resignation taking into account the recommendation of the Committee on Directors’ Affairs. The director who tenders his or her resignation will not participate in the Board’s decision. The Board is required to publicly disclose (by a press release, a filing with the SEC or other broadly disseminated means of communication) its decision regarding the tendered resignation and the rationale behind the decision within 90 days from the date of the certification of the election results. In a contested election (a situation in which the number of nominees exceeds the number of directors to be elected), the standard for election of directors will be a plurality of the shares represented in person or by proxy at any such meeting and entitled to vote on the election of directors.
What does the Board recommend?
THE BOARD RECOMMENDS THAT YOU VOTE “FOR” THE ELECTION OF EACH NOMINEE FOR DIRECTOR.
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Proposal to Ratify the Appointment of Ernst & Young LLP
(Item 2 on the Proxy Card)
What am I voting on?
You are voting on a proposal to ratify the appointment of Ernst & Young LLP as our independent registered public accounting firm for fiscal year 2010. The Audit and Finance Committee has appointed Ernst & Young to serve as independent registered public accounting firm.
What services does the independent registered public accounting firm provide?
Audit services of Ernst & Young for fiscal year 2009 included an audit of our consolidated financial statements, an audit of the effectiveness of the Company’s internal control over financial reporting, and services related to periodic filings made with the SEC. Additionally, Ernst & Young provided certain other services as described in the response to the next question. In connection with the audit of the 2009 financial statements, we entered into an engagement agreement with Ernst & Young that sets forth the terms by which Ernst & Young will perform audit services for us. That agreement is subject to alternative dispute resolution procedures.
How much was the independent registered public accounting firm paid for 2009 and 2008?
Ernst & Young’s fees for professional services totaled $19.1 million for 2009 and $20.1 million for 2008. Ernst & Young’s fees for professional services included the following:
| • | Audit Services — fees for audit services, which relate to the fiscal year consolidated audit, the audit of the effectiveness of internal controls, quarterly reviews, registration statements, comfort letters, statutory and regulatory audits and accounting consultations, were $16.7 million for 2009 and $16.5 million for 2008. |
| • | Audit-Related Services — fees for audit-related services, which consisted of audits in connection with proposed or consummated dispositions, benefit plan audits, other subsidiary audits, special reports, and accounting consultations, were $1.7 million for 2009 and $2.9 million for 2008. |
| • | Tax Services — fees for tax services, consisting of tax compliance services and tax planning and advisory services, were $0.7 million for 2009 and $0.6 million for 2008. |
| • | Other Services — fees for other services were negligible in 2009 and 2008. |
The Audit and Finance Committee has considered whether the non-audit services provided to ConocoPhillips by Ernst & Young impaired the independence of Ernst & Young and concluded they did not.
The Audit and Finance Committee has adopted a pre-approval policy that provides guidelines for the audit, audit-related, tax and other non-audit services that may be provided by Ernst & Young to the Company. The policy (a) identifies the guiding principles that must be considered by the Audit and Finance Committee in approving services to ensure that Ernst & Young’s independence is not impaired; (b) describes the audit, audit-related, tax and other services that may be provided and the non-audit services that are prohibited; and (c) sets forth pre-approval requirements for all permitted services. Under the policy, all services to be provided by Ernst & Young must be pre-approved by the Audit and Finance Committee. The Audit and Finance Committee has delegated authority to approve permitted services to the Committee’s Chair. Such approval must be reported to the entire Committee at the next scheduled Audit and Finance Committee meeting.
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Will a representative of Ernst & Young be present at the meeting?
Yes, one or more representatives of Ernst & Young will be present at the meeting. The representatives will have an opportunity to make a statement if they desire and will be available to respond to appropriate questions from the stockholders.
What vote is required to approve this proposal?
Approval of this proposal requires the affirmative vote of a majority of the shares present in person or represented by proxy at the meeting and entitled to vote on the proposal. If the appointment of Ernst & Young is not ratified, the Audit and Finance Committee will reconsider the appointment.
What does the Board recommend?
THE AUDIT AND FINANCE COMMITTEE RECOMMENDS THAT YOU VOTE “FOR” THE RATIFICATION OF THE APPOINTMENT OF ERNST &
YOUNG AS THE COMPANY’S INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM FOR THE YEAR 2010.
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Report on Board Risk Management Oversight
(Item 3 on the Proxy Card)
What am I voting on?
You are voting on a proposal submitted by the Sisters of the Holy Name of Jesus and Mary. We will provide the proponent’s address, and the number of the corporation’s voting securities that the proponent holds, to stockholders promptly upon receiving a request for the information. The text of the resolution and the supporting statement are printed below verbatim from the proponent’s submission.
What is the Proposal?
Report on Board Risk Management Oversight
Whereas, the April 15, 2009 SEC Form 10-K for ConocoPhillips indicated some of the risk factors to which our company is exposed, including, among other things:
| • | The rate of production from crude oil and natural gas properties generally declines as reserves are depleted… to the extent we are unsuccessful in replacing the crude oil and natural gas we produce with good prospects for future production, our business will suffer reduced cash flows and results of operations. |
| • | If the capital and credit markets continue to experience volatility and the availability of funds remains limited, we, and third parties with whom we do business, may incur increased costs associated with issuing commercial paper and/or other debt instruments and this, in turn, could adversely affect our ability to advance our strategic plans as currently contemplated. |
| • | Our operations are inherently dangerous and require significant and continuous oversight. The scope and nature of our operations present a variety of operational hazards and risks that must be managed through continual oversight and control….Failure to manage these risks could result in injury or loss of life, environmental damage, loss of revenues and damage to our reputation. |
Oversight of risk management currently is delegated among board committees to the Audit and Finance Committee. The Committee’s charter delineates how it addresses risk management issues:
Risk Management
31. Meet periodically with management to discuss the Company’s major risk exposures and the steps taken to insure appropriate processes are in place to identify, manage, and control business risks associated with the Company’s business objectives.
32. Discuss with management, significant risk management failures, if any, including management’s response.
In the proponents’ opinion, this is a superficial treatment of risk management when compared with the more numerous details in the Audit and Finance Committee charter relating, for instance, to oversight of the auditing process. A growing number of commentators, and at least one major congressional proposal, have suggested that the important task of risk management may in many companies merit delegation to a separate board of directors committee to ensure adequate attention.
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Therefore, be it resolved:
Shareholders request that the Board of Directors issue a report by October 15, 2010 regarding risk management oversight, at reasonable expense and excluding proprietary information, providing additional details, beyond what has been provided in the annual report, proxy statement and committee charters, regarding how the board of directors oversees risk management, and whether risk management oversight should be delegated to a separate board committee.
Supporting Statement
Proponents urge that such report review how the board is overseeing the management of risks to the company’s finances and operations, including market and reputation risks and environmental hazards. This should include, for example, discussion of oversight of pollution and climate risk, and risks associated with changing markets and supplies for energy resources. It should describe how the board is ensuring that management is taking sufficient action to reduce unnecessary risks and to mitigate risks such as through insurance coverage.
What vote is required to approve this proposal?
Approval of this proposal requires the affirmative vote of a majority of the shares present in person or represented by proxy at the meeting and entitled to vote on the proposal.
What does the Board recommend?
THE BOARD RECOMMENDS THAT YOU VOTE “AGAINST” THIS PROPOSAL FOR THE FOLLOWING REASONS:
The Board has considered this proposal and believes that adoption of this resolution is unnecessary and would not be in the best interests of ConocoPhillips or its stockholders. The Board is satisfied that it has all necessary procedures in place to fulfill its role in the oversight of the risk management programs of the Company. The Company’s management is responsible for the day-to-day management of risks to the Company, with the Board having broad oversight responsibility for the Company’s risk management programs. In this oversight role, the Board is responsible for satisfying itself that the risk management processes designed and implemented by the Company’s management are functioning as directed, and that necessary steps are taken to foster a culture of risk-adjusted decision-making throughout the organization. In carrying out its oversight responsibility, the Board has delegated to individual Board Committees certain elements of its oversight function. The Audit and Finance Committee facilitates coordination among the Board’s Committees with respect to oversight of the Company’s risk management programs. The Audit and Finance Committee regularly discusses the Company’s risk assessment and risk management policies to ensure that our risk management programs are functioning properly. Additionally, the Chairman of the Audit and Finance Committee meets with the Chairs of each Board Committee each year to discuss the Board’s oversight of the Company’s risk management programs. The Board exercises its oversight function with respect to all material risks to the Company, which are identified and discussed in the Company’s public filings with the Securities and Exchange Commission. The Board sees no need for an additional report on its oversight of risk management, believes the expenditures of Company resources would be disproportionate to any benefit from such report, and, therefore, recommends that you vote AGAINST this proposal.
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Stockholder Proposal:
Greenhouse Gas Reduction
(Item 4 on the Proxy Card)
What am I voting on?
You are voting on a proposal submitted by The Board of Pensions of the Presbyterian Church (USA). We will provide the proponent’s address, and the number of the corporation’s voting securities that the proponent holds, to stockholders promptly upon receiving a request for the information. The text of the resolution and the supporting statement are printed below verbatim from the proponent’s submission.
What is the Proposal?
2010 Resolution to ConocoPhillips on Greenhouse Gas Reduction Goals
Whereas: The American Geophysical Union, the world’s largest organization of earth, ocean and climate scientists, states that it is now “virtually certain” that global warming is caused by emissions of greenhouse gases (GHG) and that the warming will continue.
The International Energy Agency warned in its 2007 World Energy Outlook that “urgent action is needed if greenhouse gas concentrations are to be stabilized at a level that would prevent dangerous interference with the climate system.
The Kyoto Protocol obliges Annex I signatories (industrialized countries) to reduce national GHG emissions below 1990 levels by 2012. However, the Kyoto reduction targets may be inadequate to avert the most serious impacts of global warming. United Kingdom Prime Minister Gordon Brown says the EU should aim to reduce its carbon dioxide emissions by 30% below 1990 levels by 2020, and by at least 60% by 2050.
Since Kyoto was adopted, the urgent need for action to prevent the most damaging effects of climate change has become increasingly clear. Current negotiations on a successor agreement to Kyoto are focused on deeper reductions of emissions.
The 2006 Stern Review on the Economics of Climate Change, led by the former chief economist at the World Bank, “…estimates that if we don’t act, the overall (worldwide) costs and risks of climate change will be equivalent to losing at least 5% of global GDP each year, now and forever.” In contrast, the costs of action would be about 1% of global GDP each year. While some may criticize this scenario, Nobel Prize economists have applauded this work, urging immediate responses.
ConocoPhillips spent $80 million in 2006 to develop technology for alternative and unconventional energy sources, and planned to increase such spending to $150 million in 2007. However, the company emitted 64.3 million metric tons of CO2 equivalent GHG emissions in 2008, up from 2007 by 1.4%.
Failure to reduce operational emissions, or to offer lower-carbon products may necessitate the purchase of expensive carbon credits even as competitors are generating new revenue through the sale of excess credits.
Resolved: shareholders request that the Board of Directors adopt quantitative goals, based on current technologies, for reducing total greenhouse gas emissions from the Company’s products
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and operations; and that the Company report (omitting proprietary information and prepared at reasonable cost) to shareholders by September 30, 2010, on its plan to achieve these goals.
Supporting Statement
For several years, ConocoPhillips has acknowledged the importance of addressing global climate change, and the need to develop GHG targets for its operations, a process the company says is underway. However, no targets for reductions have been established after all this time. We believe setting targets is an important step in the development of a comprehensive long term strategy to significantly reduce GHG emissions from operations and products.
Last year, this resolution was supported by 27.43 percent of the shares for or against. We urge you to vote in favor to help move our company forward.
What vote is required to approve this proposal?
Approval of this proposal requires the affirmative vote of a majority of the shares present in person or represented by proxy at the meeting and entitled to vote on the proposal.
What does the Board recommend?
THE BOARD RECOMMENDS THAT YOU VOTE “AGAINST” THIS PROPOSAL FOR THE FOLLOWING REASONS:
ConocoPhillips has demonstrated significant commitment to addressing the challenges and issues of climate change through active participation in, and funding of, internal and external programs to understand and reduce greenhouse gas emissions, and to develop sound government policy for their regulation. In support of our commitment, the Company is implementing an action plan that includes measures to reduce emissions from Company assets. As part of this corporate-wide plan, ConocoPhillips is developing internal emission reduction-related actions and milestones for our operations as well as technology options and commercial plans. In addition, the Company is integrating an understanding of emissions impacts into long-range business planning and capital project evaluations. The Company also evaluates when it is in the Company’s best interest to purchase emissions credits, when it makes economic sense to implement mitigation projects, and when a mixture of both is most appropriate. Further, the Company will continue to report progress on its plans and will regularly report emissions data for our operations.
The Company is working to understand and address the environmental, technological and economic impact of greenhouse gases and other emissions in its operations. ConocoPhillips is improving the energy efficiency of its refineries and investigating the potential use of carbon capture and storage technology as a means to reduce emissions. In December 2007, ConocoPhillips joined the World Bank’s Global Gas Flaring Reduction partnership (GGFR). By joining GGFR, ConocoPhillips has committed to reduce natural gas flaring and to make efforts to minimize flaring practices by finding alternative uses for the natural gas associated with oil production. And in 2006, ConocoPhillips reinforced its commitment to reduce methane emissions through participation in the U.S. Environmental Protection Agency’s Natural Gas STAR program.
In addition to taking actions to reduce our emissions, we also intend to play a constructive role in public policy dialogue to devise practical, equitable and cost-effective approaches to stabilize the concentration of GHG in the atmosphere. It is our view that mandatory national legislative frameworks which link to international ones are most likely to achieve meaningful global GHG reductions.
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Because these on-going efforts are moving the Company forward to address climate change, the Board does not believe it is in the best interests of the Company, and it would not be an efficient use of Company resources, to establish at this time quantitative goals for reducing total greenhouse gas emissions from the Company’s products and operations and issue a report by September 30, 2010, regarding its plans to achieve these goals. The proposed report would not add value to the Company’s efforts in this area; therefore the Board recommends you vote AGAINST this proposal.
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Stockholder Proposal:
Oil Sands Drilling
(Item 5 on the Proxy Card)
What am I voting on?
You are voting on a proposal submitted by the California State Teachers’ Retirement System Investments (CalSTRS). We will provide the proponent’s address, and the number of the corporation’s voting securities that the proponent holds, to stockholders promptly upon receiving a request for the information. The text of the resolution and the supporting statement are printed below verbatim from the proponent’s submission.
What is the Proposal?
WHEREAS
ConocoPhillips has extensive interests in oil sands operations in the Canadian boreal forest region. Our company is the operating partner of the Surmont oil sands venture and is a partner in the FCCL Oil Sands Partnership, in addition to having interests in other properties.
Oil sands extraction presents a unique set of challenges due to its resource intensive and environmentally damaging nature. Oil sands mining requires heavy water use, land disturbance, toxic waste storage, and emission of air pollutants. These environmental impacts, along with their implications for local populations and wildlife, can introduce legal, regulatory and reputational problems to oil sands companies. In addition, volatile oil prices and changing oil demand during the lifetime of these projects can impact both their costs and associated income.
Industrial logging and oil sands have reduced the boreal to less than 40% of its original size; the remaining forest is fragmented, with harmful impacts on many species. According to the Canadian Parks and Wildness Association, it will take over 300 years before reclaimed areas become functioning forest again.
Oil sands companies have not proven that full reclamation of toxic tailing ponds is possible. The long-term persistence of these ponds, which have been shown to leak toxic pollutants into local water sources, presents additional challenges to companies.
Extracting one barrel of bitumen requires 2-5 barrels of fresh water.
An average barrel’s extraction requires enough natural gas to heat a Canadian home for 1.5-5.5 days, and the removal of four tons of earth. While processed sand must be replaced and the site reclaimed, in 40+ years of oil sands operations, not a single acre has received a reclamation certificate from the Canadian government.
Oil sands have made Alberta the largest emitter of industrial pollutants in Canada.
Litigation from First Nations presents possible problems to both oil sands and pipeline companies, which may face increased costs and restrictions on development. Even after a project has been approved, it can be subject to lawsuits challenging its development.
Oil sands extraction projects are long-term, capital-intensive developments with multi-decade payback horizons. Compliance with local, regional and national regulations may not be enough to protect our company from adverse consequences.
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RESOLVED
Shareholders request that an independent committee of the Board prepare a report (at reasonable cost and omitting proprietary information) on the environmental damage that would result from the company’s expanding oil sands operations in the Canadian boreal forest. The report should consider the implications of a policy of discontinuing these expansions and should be available to investors by November 2010.
SUPPORTING STATEMENT
The requested report should discuss the intense environmental and social impacts of oils sands operations that occur despite best efforts at mitigation, including the environmental impact on water resources and biodiversity, and the social impact on Albertans, including indigenous populations.
What vote is required to approve this proposal?
Approval of this proposal requires the affirmative vote of a majority of the shares present in person or represented by proxy at the meeting and entitled to vote on the proposal.
What does the Board recommend?
THE BOARD RECOMMENDS THAT YOU VOTE “AGAINST” THIS PROPOSAL FOR THE FOLLOWING REASONS:
ConocoPhillips has publicly committed to set a high standard in environmental protection, and it regularly reports on its performance in such publications as the ConocoPhillips Sustainable Development Report. The Company believes that development of the oil sands and the conversion of the crude oil produced from oil sands to fuel can be conducted in an environmentally sustainable manner. The perceived choice between economic development and safeguarding the environment is a false one. The Board believes that the report requested by CalSTRS is unnecessary and not an efficient use of Company resources because it will not provide more, or better, information than the Company will be providing or obtaining through the regulatory process and its own internal protection protocols.
The oil sands are an area of potentially significant future growth for ConocoPhillips and the success of our oil sands investments is important to our shareholders. The Company’s goal is to be a successful, long-term contributor to the Canadian economy and the communities in which we operate. We believe we can find a balance that accomplishes our goals of delivering the energy our society needs while concurrently minimizing the environmental impact associated with such development.
ConocoPhillips’ oil sands development portfolio is primarily focused on steam assisted gravity drainage (SAGD). This in-situ extraction method occurs within the reservoir deep underground and requires only a limited surface footprint for the plant site and well pads. It does not require the accumulation of tailings, diversion of rivers, or withdrawals from or discharges to rivers or lakes.
Surmont’s SAGD operation currently recycles 90% of the water used in the process, and has a projected water intensity of less than half a barrel of water per barrel of bitumen production. The water used for the Surmont project comes from deep non-potable, or saline, aquifers. Detailed groundwater aquifer mapping and monitoring will continue during the life of operations to ensure sustainability.
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Syncrude Canada employs significant efforts to ensure the efficient use of resources, responsible extraction of bitumen and careful reclamation of the land affected by its operations. Syncrude Canada leads the industry with about 22% of its land, over 4,600 hectares, now reclaimed. Likewise, Syncrude Canada manages air emissions in order to minimize any operational impact on the environment, operating in strict compliance with regulatory requirements. We and our partners continue to work in concert with communities, Aboriginal neighbors and other key stakeholders in our reclamation plans and activities.
ConocoPhillips was an early adopter of low-impact seismic practices that substantially reduce the amount of forest clearing required, and thus accelerate reforestation. Exploration wells drilled are abandoned and reclaimed promptly, with reclamation certificates generally received within 3 to 5 years. Other examples of reducing footprint include environmental constraint mapping to place facilities away from sensitive eco-sites such as wetlands, and integrated landscape planning with other companies to use common roads and thereby reduce forest clearing, access, and ecosystem fragmentation. Ongoing research supported by ConocoPhillips to improve construction and reclamation practices will further reduce the size of the environmental footprint required, and facilitate later recovery of the land. In total, oil sands development by the industry is currently expected to impact less than 0.1% of the boreal forest located in Canada.
ConocoPhillips was a founding member of the Cumulative Environmental Management Association (CEMA), a multi-stakeholder organization established in Fort McMurray in 2000 with members representing various levels of government, industry regulatory bodies, non-government environmental groups, Aboriginal groups, and the local health authority. CEMA’s mandate is to make recommendations on how to best manage cumulative impacts from industrial activity on the land, water and air in the region. This includes the development and application of environmental management tools, regional environmental guidelines, objectives and thresholds. ConocoPhillips remains committed to exceeding the minimum requirements of reclamation of lands affected by its operations through initiatives like the “Faster Forest” program, which goes beyond the current reclamation standards by proactively planting trees in affected areas.
ConocoPhillips believes that our investments in people and technology will help us increase the production of oil sands while reducing the impacts on a per barrel basis. To enable ongoing improvement, ConocoPhillips and its partners are funding research and studies on heavy oil technology, including technology to reduce greenhouse gas emissions, water use and land disturbance. It is anticipated that this funding will continue over the next 5 years and total approximately $300 million when completed.
ConocoPhillips operates in sensitive areas only where the respective governmental entities have legally authorized such operations and where the Company is confident it can comply with all regulatory requirements. The Company is confident that it can simultaneously protect the environment and develop oil and gas reserves in areas like the Canadian oil sands region, just as it has in other environmentally sensitive locations.
The Board believes developing a special report by an independent committee of the Board on the environmental damage that would result from the Company’s oil sands operations in the Canadian boreal forest is unnecessary, duplicative and would add no value; therefore, the Board recommends that you vote AGAINST this Proposal.
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Stockholder Proposal:
Louisiana Wetlands
(Item 6 on the Proxy Card)
What am I voting on?
You are voting on a proposal submitted by The Domestic and Foreign Missionary Society of the Episcopal Church. We will provide the proponent’s address, and the number of the corporation’s voting securities that the proponent holds, to stockholders promptly upon receiving a request for the information. The text of the resolution and the supporting statement are printed below verbatim from the proponent’s submission.
What is the Proposal?
WHEREAS, it is irrefutable that oil and gas-related activities have had a major impact on Louisiana’s fragile coastal environment and are directly linked to wetland loss in coastal Louisiana. Studies have empirically demonstrated that the direct and indirect effects of oil and gas exploration, recovery and processing are together responsible for 40 to 60 percent of documented wetland loss;1
Oil and gas-related activities, as well as the 10,000 miles of canals dredged throughout the coastal zone of Louisiana, have resulted in the disruption of the natural hydrologic regime of the Mississippi delta, in enhanced subsidence, in deterioration of vegetation habitats, in increases in turbidity and in decreases in the nursery grounds for estuarine consumers (i.e. fish and shrimp). 2
In Louisiana alone, 1.3 million acres of coastal wetlands has been lost since the 1930s; it is estimated that every 38 minutes a wetlands area the size of a football field is lost.3 If nothing is done to prevent the rapid loss of wetlands and restore Louisiana’s coast, another 500-700 acres will be lost over the next 50 years;4
The loss of wetlands combined with the resulting hydrologic isolation of the remaining local marshes has robbed the two million residents of coastal Louisiana of the vital storm protection provided by wetlands. As a result, Louisiana cities, like New Orleans, are now almost completely exposed to the Gulf of Mexico. Consequently, minor storms that had relatively little effect 20 to 30 years ago now cause serious flooding and storm-related damage due to the continuous encroachment of the Gulf of Mexico and the loss of the storm protection afforded by wetlands.5
The cost of a wetlands restoration plan for Louisiana is estimated to be at least $50 billion and will take over three decades to complete.6
1 Ko, Jae-Young, Impacts of Oil and Gas Activities on Coastal Wetlands Loss in the Mississippi Delta, Harter Research Institute available at www.harteresearchinstitute.org/ebook/ch33-oil-gas-impacts-on-coastal-wetland-loss.pdf (last visited Sept. 16, 2009). See also Penland, Shea, et al., Process Classification of Coastal Land Loss Between 1932 and 1990 in the Mississippi River Delta Plain, Southeastern Louisiana (1990). U.S. Dept. of the Interior, U.S. Geological Survey, Open File Report 00-418.
2 Id.
3 Shell Oil, Protecting Louisiana’s Coastal Wetlands, available at www.shell.us/home/content/usa/responsible_energy/respecting_the_environment/sustainable_development/americaswetlands_13082007.html (last visited Oct. 1, 2009).
4 Id. See also USGS, 100+Years of Land Change for Southeast Coastal Louisiana available at http://www.coast2050.gov/images/landloss8XII.pdf (last visited Oct. 10, 2009). See also
5 Turner, R. E. 1997. Wetland Loss in the Northern Gulf of Mexico: Multiple Working Hypotheses. Estuaries, Vol. 20, No. 1:1-13. See also Gulf Restoration Network, Wetland Loss available at http://healthygulf.org/wetlandimportance/wetland-loss.html (last visited Oct. 1, 2009).
6 U.S. Gov’t Accountability Office, Report to Congressional Addressees, Lessons Learned from Past Efforts in Louisiana Could Help Guide Future Restoration and Protection, Dec. 2007 available at http://www.gao.gov/new.items/d08130.pdf (last visited Sept. 16, 2009).
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From 1981 to present, ConocoPhillips has obtained 197 coastal use permits for oil and gas exploration in coastal Louisiana and has dredged 3,309,128.6 cubic yards.7 Of the land dredged, reports from the Louisiana Department of Natural Resources have documented that 813.94 acres of wetlands have been destroyed as a result of oil and gas related activities.8
We believe that ConocoPhillips, which represents itself as a socially and environmentally responsible company concerned about Louisiana’s coastal wetlands crisis, has an obligation to adopt policies that will prevent future damage to wetland and that will assist in the amelioration of past harm.
RESOLVED, that the shareholders request that the board of directors of ConocoPhillips adopt environmental policies to address the environmental hazards of its oil and gas-related activities in coastal Louisiana by devising and implementing business practices that will prevent future harms to coastal Louisiana and by aiding in the restoration of wetlands lost through past actions of ConocoPhillips.
7 Louisiana Department of Natural Resources, Coastal Use Permit Tracking System, available at http://sonris.com/direct.asp?server=sonris-www&path=sonris/cmdPermit.jsp?sid=PROD (last visited Oct. 1, 2009).
8 Id.
What vote is required to approve this proposal?
Approval of this proposal requires the affirmative vote of a majority of the shares present in person or represented by proxy at the meeting and entitled to vote on the proposal.
What does the Board recommend?
THE BOARD RECOMMENDS THAT YOU VOTE “AGAINST” THIS PROPOSAL FOR THE FOLLOWING REASONS:
ConocoPhillips conducts exploration and production activities along the southeast Louisiana coast and currently operates eight fields in this area, a small percentage of industry activity in the region. Some of these lands and associated minerals are owned by ConocoPhillips while others are owned by the State of Louisiana and other third parties. In total ConocoPhillips owns approximately 600,000 acres in coastal Louisiana, most of which came into ConocoPhillips ownership as part of the Burlington Resources acquisition in 2006.
ConocoPhillips adheres to all regulations governing these properties and has appropriate internal policies and practices in place to address the environmental impacts of its activities. In addition the Company supports other programs designed to minimize damage to wetlands and to encourage restoration.
Specifically, ConocoPhillips’ operations are subject to a number of local, state and federal programs and regulatory bodies such as the Louisiana Coastal Resources Program, Louisiana Department of Wildlife and Fisheries and the U.S. Army Corps of Engineers. These regulatory bodies work closely together to protect, develop and, where feasible, restore the state’s coastal zone. Any activity that will disturb the seabed or marshland, including installation and maintenance of equipment, requires permitting. These permits require assessments that include, among other things, consideration for existing commercial uses of the lands as well as other stakeholder impacts.
In addition to compliance with regulations and agency involvement, ConocoPhillips has positions, policies and procedures that outline internal expectations for sustainable development
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across all operations including those in coastal Louisiana. ConocoPhillips has committed to making progress on nine different elements of sustainable development, which include minimizing environmental impact and positively impacting the communities where it operates. In addition, the Company’s operations adhere to Company position statements on biodiversity and water sustainability. ConocoPhillips reports on sustainable development progress biannually.
In coastal Louisiana, ConocoPhillips regularly provides access to its lands at no cost and works closely with the government agency or group operating projects beyond the Company’s activities. As of year-end 2009, there were over 60 completed or ongoing third-party projects on our lands to preserve and restore natural resources.
ConocoPhillips also supports restoration and education about wetlands through corporate contribution programs. ConocoPhillips launched the SPIRIT of Conservation program in 2005 to protect threatened migratory birds and their habitats worldwide, especially in regions where the Company operates. Conservation initiatives within this program include replanting migratory bird habitat in Louisiana and along the hurricane-damaged Gulf Coast. The program builds on ConocoPhillips’ 15-year partnership with the National Fish and Wildlife Foundation, which has funded more than 50 projects with a total value in excess of $6 million.
In 2009, ConocoPhillips was awarded two Gulf Guardian Awards from the EPA Gulf of Mexico Program for education about Louisiana wetlands. The Company hosted teacher workshops and tours across the Gulf Coast region to promote awareness of biodiversity and the importance of wetlands to the region. Additionally, through the Company’s partnership with the Barataria-Terrebonne National Estuary Program, birders across the country are educated about the Louisiana’s wetlands and their importance to migratory birds.
Based on the fact that ConocoPhillips has environmental policies to address the environmental impact of its activities in coastal Louisiana and is involved in a number of conservation and restoration programs in the region, the Company believes it has already satisfied the intent of this stockholder proposal. The Board therefore recommends voting AGAINST adoption of the proposal.
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Stockholder Proposal:
Financial Risks of Climate Change
(Item 7 on the Proxy Card)
What am I voting on?
You are voting on a proposal submitted by the Needmor Fund. We will provide the proponent’s address, and the number of the corporation’s voting securities that the proponent holds, to stockholders promptly upon receiving a request for the information. The text of the resolution and the supporting statement are printed below verbatim from the proponent’s submission.
What is the Proposal?
CONOCOPHILLIPS: REPORT TO SHAREOWNERS ON
FINANCIAL RISKS RESULTING FROM CLIMATE CHANGE
AND ITS IMPACT ON SHAREOWNER VALUE
Whereas:
There is a general consensus among climate scientists that, without significant intervention, climate change will result in dramatic weather events, rising sea levels, drought in some areas and significant impacts on human and ecosystem health. The Pentagon also believes that climate change will have significant national security implications.
Climate change will therefore have profound negative effects on global economies, confronting business leaders with major challenges.
Scientific, business, and political leaders globally have identified the risks of climate change for the natural environment and the global economy and are calling for urgent action.
In response, numerous companies are proactively reducing their carbon footprints. ConocoPhillips is advertising on its website and in public ads the many creative steps the company is taking to reduce greenhouse gases contributing to climate change. Proponents commend our company for this leadership.
Others, including ConocoPhillips, are lobbying actively for specific, legislative changes to shape future laws and regulations.
Many investors, including members of the Investor Network on Climate Risk, representing approximately $7 trillion of assets under management, are urging companies to provide full disclosure of climate risk and urging the Securities and Exchange Commission to mandate such disclosure.
Many companies are conducting internal assessments of the business risks and opportunities posed by climate change and some, such as AES, Dow Chemical, DuPont, Exelon, Ford, Intel, PG&E, and Xcel are adding sections in their 10K Reports on present and future risks.
We are concerned about ways in which climate change and related government policies can adversely affect our investment in ConocoPhillips.
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Hence, we believe it is important for ConocoPhillips to carefully study the impacts, risks and opportunities posed by climate change for our company and its future operations to enable management to respond effectively to protect shareowner value. The results of the study would be reported to shareowners.
Resolved: Investors request ConocoPhillips Board of Directors to prepare a report to shareowners on the financial risks resulting from climate change and its impacts on shareowner value over time, as well as actions the Board deems necessary to provide long-term protection of our business interests and shareowner value. The Board shall decide the parameters of the study and summary report.
A summary report will be made available to investors by September 15, 2010. Cost of preparation will be kept within reasonable limits and proprietary information omitted.
Supporting Statement:
We suggest management consider the following issues in their risk analysis.
Emissions management;
Physical risks of climate change on our business and operations, e.g. the impact of rising sea levels on drilling operations and refineries, including the supply chain;
U.S. and global regulatory risks of legislative proposals for carbon taxes and cap and trade;
“Material risk” with respect to climate change;
Positive business opportunities;
Reputation, brand and legal risk.
What vote is required to approve this proposal?
Approval of this proposal requires the affirmative vote of a majority of the shares present in person or represented by proxy at the meeting and entitled to vote on the proposal.
What does the Board recommend?
THE BOARD RECOMMENDS THAT YOU VOTE “AGAINST” THIS PROPOSAL FOR THE FOLLOWING REASONS:
In accordance with the rules and regulations of the Securities and Exchange Commission, the Company discloses in its periodic reports filed with the Securities and Exchange Commission all material risks management believes are facing the Company as well as all known trends that are reasonably likely to affect our Company’s earnings. The Board, the Audit and Finance Committee and the Company’s management each review such filings and believe that such disclosures describe all material risks to the Company associated with climate change at this time. These filings are updated on a regular basis to ensure they reflect our current assessment of the risks associated with climate change and related legislative and regulatory actions.
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In addition, the Company’s views, actions, and progress on climate change are widely available, for example, in speeches by Company executives, in the Sustainable Development Report, as most recently updated and available on the Company’s website, and through our participation in disclosure initiatives, such as the Carbon Disclosure Project. As outlined in the Sustainable Development Report, the Company is implementing the first phase of a Climate Change Action Plan. Key elements of this plan include: equipping for a low-emission world, reducing emissions, pursuing new business opportunities, leveraging carbon trading and technology innovation, and engaging external stakeholders. The Company is also integrating an understanding of emissions impacts into long-range business planning and capital project evaluations. At this time, the Company believes this Plan is the best way to address the issues related to climate change in a well thought-out, orderly and timely manner, consistent with its sustainable development commitments.
The Company is committed to fully disclosing, and addressing the concerns of its stockholders relating to, the potential impact of climate change, and related regulations, on the Company’s business operations and financial results. Based on the foregoing factors, the Board does not believe that engaging in the requested study will provide any meaningful benefits to its stockholders and recommends a vote AGAINST this proposal.
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Stockholder Proposal:
Toxic Pollution Report
(Item 8 on the Proxy Card)
What am I voting on?
You are voting on a proposal submitted by the Northwest Women Religious Investment Trust. We will provide the proponent’s address, and the number of the corporation’s voting securities that the proponent holds, to stockholders promptly upon receiving a request for the information. The text of the resolution and the supporting statement are printed below verbatim from the proponent’s submission.
What is the Proposal?
ConocoPhillips – 2010
Reduce Toxic Pollution
Whereas:
ConocoPhillips, the nation’s second largest oil refiner, owns 12 refineries operating in 9 states. Despite its commitment to protecting the environment in order to “secure a stable and healthy environment for tomorrow,” our company is responsible for emitting over 6.56 million pounds of toxic chemicals into the air. It ranks 13th on the 2008 Toxic 100 list of worst U.S. corporate air polluters.
(http://www.peri.umass.edu/Toxic-100-Table.265.0.html)
The 2008 Toxic 100 list is based on 2005 data on chemical releases reported by companies to the U.S. Environmental Protection Agency’s Toxic Release Inventory (TRI), and weighted for toxicity and other factors according to EPA’s Risk Screening Environmental Indicators. Valero, the largest U.S. oil refiner, ranks 16th among the Toxic 100, BP ranks 29th, and Chevron is not among the Toxic 100. Of all its U.S. refinery competitors, only ExxonMobil has a worse toxic score than ConocoPhillips, ranking 9th on the list.
Five ConocoPhillips refineries accounted for over 60% of our company’s toxic air score: Roxana, IL (34.5%); West Lake, LA (14%); Trainer, PA (9.85%); Belle Chasse, LA (9.19%) and Linden, NJ (7.25%).
(http://data.rtknet.orgtox100/index.php?search=yes&database=t1&detail=1&datype=T&reptype=a& company2=57 54&company1=&parent=&chemfac=fac&advbasic=bas)
Our company, however, has announced no goals or programs to reduce the toxic air emissions from these five facilities, or the short- and long-term risks they pose to community residents, workers and shareowners.
In January 2005, ConocoPhillips settled proceedings brought by EPA for violations of the Federal Clean Air Act (CAA) at its refineries. The 2005 settlement, the largest from the 13 refiners pursued by EPA, followed a 2001 settlement of CAA enforcement proceedings against our company. ConocoPhillips is now implementing two separate consent decrees, obligating it to spend over $600 million on pollution control technologies.
Although, on its website, ConocoPhillips discloses company-wide emissions data for CAA pollutants, it does not publish data on releases of many other toxic chemicals that are not currently
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covered by the CAA but that are reportable to the TRI. Unfortunately, complete TRI data sets are made public two years after they are reported by companies, reducing their utility for investor risk analysis.
Since 2005, concerns persist about pollution control at ConocoPhillips’ refineries. In 2008, five states sought over $1.5 million in fines and penalties for air pollution violations at ConocoPhillips’ refineries. Our company’s plan to “increase its processing capabilities for handling lower quality crudes” from Canadian tar sands was dealt a blow last June when EPA refused permission to expand the Roxana, IL, refinery because air pollution from the refinery’s flares was not sufficiently controlled. (http://www.ensnewswire.com/ens/jun2008/2008-06-10-091.asp)
Resolved:
The shareholders request the board to adopt stringent goals to reduce significantly the emission of TRI chemicals from our Company’s refineries and to report annually by September 15th (i) its progress in implementing these goals as well as (ii) a comprehensive description of the quantities of toxic chemicals reportable under the TRI that were emitted at those facilities during the prior calendar year.
What vote is required to approve this proposal?
Approval of this proposal requires the affirmative vote of a majority of the shares present in person or represented by proxy at the meeting and entitled to vote on the proposal.
What does the Board recommend?
THE BOARD RECOMMENDS THAT YOU VOTE “AGAINST” THIS PROPOSAL FOR THE FOLLOWING REASONS:
ConocoPhillips is committed to reporting on our environmental and social performance. In our sustainability reporting, we annually provide the key environmental metrics recommended by industry reporting guidance, both on a company-wide basis and by sector and region. We also comply with all regulatory reporting requirements, including reporting to the Toxic Release Inventory. We take seriously our responsibility to provide accurate and timely reporting of environmental data and invest resources accordingly. We therefore minimize the channels for our reporting in order to maximize reporting efficiency and quality of the data.
Numerous community engagement activities, including the use of Community Advisory Councils and Citizen Advisory Panels, help ensure accountability and are an additional forum for local stakeholders to discuss environmental performance directly with the refineries. All of the Company’s twelve U.S. refineries, and the Humber refinery in the United Kingdom, have established community panels. In our U.S. refineries, we continue to significantly reduce air emissions. By the end of 2010, we will have installed nine wet gas scrubbers on our fluidized catalytic cracking units, resulting in a substantial reduction in sulfur dioxide emissions and particulates. By year-end 2014, we will have completed 85 NOx reduction projects on a variety of refinery equipment. Our refineries have undertaken a benzene emission reduction effort through installation of control technologies and asset integrity projects.
We continue working diligently to meet and exceed the requirements of an agreement signed with the U.S. Environmental Protection Agency (EPA) in January 2005 to reduce air emissions at nine of our 12 U.S. refineries. The other three refineries reached a similar settlement in 2001.
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ConocoPhillips agreed to invest $525 million to install control technologies to reduce emissions from these refineries. However, our clean air initiatives will go beyond the agreement with the EPA, and by 2011 we expect to have invested more than $1 billion in projects to reduce air emissions.
Based on the fact that ConocoPhillips has publicly issued a comprehensive report on its sustainable development objectives and its performance metrics, and that it will continue to make its sustainability reports publicly available as part of its commitment to be transparent and accountable, the Company believes it has already satisfied the intent of this stockholder proposal. The Board therefore recommends AGAINST adoption of the proposal because it would result in unnecessary expense and duplicative reporting.
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Stockholder Proposal:
Gender Expression Non-Discrimination
(Item 9 on the Proxy Card)
What am I voting on?
You are voting on a proposal submitted by the Unitarian Universalist Association of Congregations. We will provide the proponent’s address, and the number of the corporation’s voting securities that the proponent holds, to stockholders promptly upon receiving a request for the information. The text of the resolution and the supporting statement are printed below verbatim from the proponent’s submission.
What is the Proposal?
GENDER IDENTITY NON-DISCRIMINATION POLICY
Whereas: ConocoPhillips Company does not explicitly prohibit discrimination based on gender identity or expression in its written employment policy, yet ConocoPhillips’ policy already does explicitly prohibit discrimination based on sexual orientation;
Over 30% of the Fortune 500 companies have adopted written nondiscrimination policies prohibiting harassment and discrimination on the basis of gender identity as well as 400 leading private sector companies and eighty-five U.S. colleges and universities, according to the Human Rights Campaign;
Ninety three City and County Governments and twelve States have passed clear gender identity and expression legislative protections including California, Colorado, the District of Columbia, Hawaii, Illinois, Maine, Minnesota, New Mexico, Pennsylvania, Rhode Island, Vermont and Washington;
Over 350 U.S. based human rights organizations and every U.S. State civil rights advocacy group has endorsed national legislation explicitly prohibiting discrimination based on sexual orientation as well as gender identity.
Our company has operations in, and makes sales to institutions in States and Cities that currently prohibit discrimination on the basis of sexual orientation and gender identity;
We believe that corporations that prohibit discrimination both on the basis of sexual orientation and gender identity have a competitive advantage in recruiting and retaining employees from the widest talent pool.
Resolved: The Shareholders request that ConocoPhillips Company, amend its written equal employment opportunity policy to explicitly prohibit discrimination based on sexual orientation and gender identity or expression and to substantially implement the policy.
Supporting Statement: Employment discrimination on the basis of sexual orientation and gender identity diminishes employee morale and productivity. Because state and local laws are inconsistent with respect to such employment discrimination, our company would benefit from a consistent, corporate-wide policy to enhance efforts to prevent discrimination, resolve complaints internally, and ensure a respectful and supportive atmosphere for all employees. Wal-Mart will enhance its competitive edge by joining the growing ranks of companies guaranteeing equal opportunity for all employees.
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What vote is required to approve this proposal?
Approval of this proposal requires the affirmative vote of a majority of the shares present in person or represented by proxy at the meeting and entitled to vote on the proposal.
What does the Board recommend?
THE BOARD RECOMMENDS THAT YOU VOTE “AGAINST” THIS PROPOSAL FOR THE FOLLOWING REASONS:
The Company is an equal opportunity employer and fully committed to complying with all applicable equal employment opportunity laws. The Board believes that the Company’s current policies and practices fully achieve the objectives of this proposal. It is not practical or even possible to list all categories on which to prohibit discrimination. The Board believes that such an effort would only divert attention from the overall goal of a truly non-discriminatory workplace. The Company’s equal employment policy prohibits discrimination on the basis of race, sex, marital status, ancestry, physical or mental disability, veteran status, sexual orientation or any other basis prohibited by applicable law. This policy applies to all areas of employment, including, but not limited to, hiring and recruitment, training, promotion, transfer, demotion, counseling and discipline, employee benefits and compensation and termination of employment. The Company recognizes the value of a truly diverse workforce and is dedicated to ensuring that diversity brings its employees, customers, vendors and communities to their full potential. The Board of Directors recommends a vote AGAINST this proposal.
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Stockholder Proposal:
Political Contributions
(Item 10 on the Proxy Card)
What am I voting on?
You are voting on a proposal submitted by The Nathan Cummings Foundation. We will provide the proponent’s address, and the number of the corporation’s voting securities that the proponent holds, to stockholders promptly upon receiving a request for the information. The text of the resolution and the supporting statement are printed below verbatim from the proponent’s submission.
What is the Proposal?
Resolved, that the shareholders of ConocoPhillips (“Company”) hereby request that the Company provide a report, updated semi-annually, disclosing:
Monetary and non-monetary political contributions and expenditures not deductible under section 162 (e)(1)(B) of the Internal Revenue Code, including but not limited to any portion of any dues or similar payments made to any tax exempt organization that is used for an expenditure or contribution that if made directly by the Corporation would not be deductible under section 162 (e)(1)(B) of the Internal Revenue Code.
The report shall include an accounting through an itemized report that includes the identity of the recipient as well as the amount paid to each recipient of the Company’s funds that are used for political contributions or expenditures as described above.
The report shall be posted on the Company’s website to reduce costs to shareholders.
Stockholder Supporting Statement
As long-term shareholders of ConocoPhillips, we support transparency and accountability in corporate spending on political activities. These activities include direct and indirect political contributions to candidates, political parties or political organizations; independent expenditures; or electioneering communications on behalf of a federal, state or local candidate.
Disclosure is consistent with public policy, in the best interest of the Company and its shareholders and critical for compliance with recent federal ethics legislation. Absent a system of accountability, Company assets can be used for policy objectives that may be inimical to the long-term interests of the Company and its shareholders.
ConocoPhillips contributed at least $6.8 million in corporate funds since the 2002 election cycle. (CQ’s PoliticalMoneyLine: http://moneyline.cq.com/pml/home.do and National Institute on Money in State Politics: http://www.followthemoney.org/index.phtml.) While the Company discloses some of its corporate political spending at the state and local level, it does not disclose its political spending through trade associations and other tax-exempt groups.
The Company’s payments to trade associations used for political activities are undisclosed and unknown. In many cases, even management does not know how trade associations use their company’s money politically. The proposal asks the Company to disclose all of its political
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contributions, including payments to trade associations and other tax exempt organizations. This would bring our Company in line with a growing number of leading companies, including Hewlett-Packard, Aetna and American Electric Power that support political disclosure and accountability and present this information on their websites.
The Company’s Board and its shareholders need complete disclosure to be able to fully evaluate the political use of corporate assets. Thus, we urge your support for this critical governance reform.
What vote is required to approve this proposal?
Approval of this proposal requires the affirmative vote of a majority of the shares present in person or represented by proxy at the meeting and entitled to vote on the proposal.
What does the Board recommend?
THE BOARD RECOMMENDS THAT YOU VOTE “AGAINST” THIS PROPOSAL FOR THE FOLLOWING REASONS:
We continuously make efforts to provide our shareholders useful information about our political activities, and the Company’s Political Policies, Procedures and Giving can be found on our Web site at www.conocophillips.com. We also provide information on our Web site regarding the Company’s political contributions to candidates every six months. In addition, ConocoPhillips complies with all disclosure requirements pertaining to political contributions under federal, state and local laws and regulations. These disclosures provide ample public information about the Company’s political contributions, as demonstrated by the Proponent’s reference to figures on political contributions previously made by ConocoPhillips.
In addition, our candidate contributions are reported regularly to, and overseen by, Company senior management and the Public Policy Committee of the Board. Independent audits of the Company’s and Spirit PAC’s political giving are performed each year.
The Board believes it has a responsibility to shareholders and employees to be engaged in the political process to both protect and promote their shared interests. The Board believes it is in the best interest of shareholders to support the legislative process by making prudent corporate political contributions to political organizations when such contributions are consistent with business objectives and are permitted by federal, state and local laws. The Board also believes in making the Company’s political contributions transparent to interested parties.
As to the issue of contributions to trade associations, ConocoPhillips’ primary purpose in joining such groups, like the National Association of Manufacturers and the American Petroleum Institute, is not for political purposes, nor does the Company agree with all positions taken by trade associations on issues. In fact, the Company publicly acknowledges that it does take contrary positions from time to time. The greater benefit ConocoPhillips receives from trade association membership are the general business, technical and industry standard-setting expertise these organizations provide.
ConocoPhillips has adopted and published its Political Policies, Procedures and Giving, made available information on its Web site regarding political contributions to candidates, and complies with laws regarding disclosure of political giving; therefore, the adoption of this resolution is unnecessary and the Board recommends that you vote AGAINST this proposal.
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EXECUTIVE COMPENSATION
Role of the Human Resources and Compensation Committee
Authority and Responsibilities
The Human Resources and Compensation Committee (HRCC) of the Board of Directors of ConocoPhillips is responsible for providing independent, objective oversight for ConocoPhillips’ executive compensation programs and determining the compensation of anyone who meets our definition of a “Senior Officer.” Currently, our internal guidelines define a Senior Officer as an employee who is a senior vice president or higher, an executive who reports directly to the CEO, or any other employee considered an officer under Section 16(b) of the Securities Exchange Act of 1934. All of the Named Executive Officers in the compensation tables that follow are Senior Officers. In addition, the HRCC acts as plan administrator of the compensation programs and benefit plans for Senior Officers and as an avenue of appeal for current and former Senior Officers regarding disputes over compensation and benefits.
One of the HRCC’s responsibilities is to assist the Board in its oversight of the integrity of the Company’s “Compensation Discussion and Analysis” found starting on page 43 of this Proxy Statement. That report summarizes certain of the HRCC’s activities during 2009 and 2010 concerning compensation earned during 2009.
A complete listing of the authority and responsibilities of the HRCC is set forth in the written charter adopted by ConocoPhillips’ Board of Directors and last amended on December 2, 2009, which is available on our website www.conocophillips.com under the caption “Governance.”
Members
The HRCC currently consists of three members. The members of the HRCC and the member to be designated as Chair, like the members and Chairs of all of the Board’s committees, are reviewed and recommended annually by the Committee on Directors’ Affairs to the full Board. The Board of Directors has final approval of the committee structure of the Board. The only pre-existing requirements for service on the HRCC are that members of the HRCC must meet the independence requirements for “non-employee” directors under the Securities Exchange Act of 1934, for “independent” directors under the NYSE listing standards, and for “outside” directors under the Internal Revenue Code.
Meetings
The HRCC has regularly scheduled meetings in association with each regular Board meeting and meets by teleconference between such meetings as necessary to discharge its duties. The HRCC reserves time at each regularly scheduled meeting to review matters in executive session with no members of management or management representatives present except as specifically requested by the HRCC. Additionally, the Committee meets jointly with the Committee on Directors’ Affairs at least annually to evaluate the performance of the CEO. In 2009, the HRCC had seven regularly scheduled meetings. More information regarding the HRCC’s activities at such meetings can be found in the “Compensation Discussion and Analysis” beginning on page 43.
Continuous Improvement
The HRCC is committed to a process of continuous improvement in exercising its responsibilities. To that end, the HRCC also:
| • | Receives ongoing training regarding best practices for executive compensation; |
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| • | Regularly reviews its responsibilities and governance practices in light of ongoing changes in the legal and regulatory arena and trends in corporate governance, which review is aided by the Company’s management, compensation consultants, and, when deemed appropriate, independent legal counsel; |
| • | Annually reviews its charter and proposes any desired changes to the Board of Directors; |
| • | Annually conducts a self-assessment of its performance that evaluates the effectiveness of the Committee’s actions and seeks ideas to improve its processes and oversight; and |
| • | Regularly reviews and assesses whether the Company’s executive compensation programs are having the desired effects and do not encourage an inappropriate level of risk. |
Human Resources and Compensation Committee Report
Review with Management. The Human Resources and Compensation Committee (HRCC) has reviewed and discussed with management the “Compensation Discussion and Analysis” presented in this proxy statement starting on page 43. Members of management with whom the HRCC discussed the “Compensation Discussion and Analysis” included the Company’s Chief Executive Officer, Chief Administrative Officer, and Vice President, Human Resources.
Discussion with Independent Executive Compensation Consultant. The HRCC has discussed with Towers Perrin (which has subsequently merged with Watson Wyatt and been renamed Towers Watson), an independent executive compensation consulting firm, the executive compensation programs of the Company, as well as specific compensation decisions made by the HRCC. Towers Perrin was retained directly by the HRCC, independent of the management of the Company. The HRCC has received written disclosures from Towers Perrin concerning other work performed for the Company by Towers Perrin, has discussed with Towers Perrin its independence from ConocoPhillips, and believes Towers Perrin to have been independent of management.
Recommendation to the ConocoPhillips Board of Directors. Based on its review and discussions noted above, the HRCC recommended to the Board of Directors that the “Compensation Discussion and Analysis” be included in ConocoPhillips’ proxy statement on Schedule 14A (and, by reference, included in ConocoPhillips’ Annual Report on Form 10-K for the year ended December 31, 2009).
THE CONOCOPHILLIPS HUMAN RESOURCES
AND COMPENSATION COMMITTEE
William E. Wade, Jr., Chairman
Harold W. McGraw III
Kathryn C. Turner
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Compensation Discussion and Analysis
This Compensation Discussion and Analysis, or CD&A, explains how we compensate our Named Executive Officers, or NEOs. The CD&A is divided into four sections:
| • | The Objectives and Process of Compensating Our Executives (beginning on page 43) |
| • | The Types of Compensation We Provide to Our Executives (beginning on page 47) |
| • | Measuring Our Performance under Our Compensation Programs (beginning on page 51) |
| • | An Analysis of Compensation Paid to Our Executives (beginning on page 54) |
The Objectives and Process of Compensating Our Executives
Our Goals: Our goals are to attract, retain and motivate high-quality employees and to maintain high standards of principled leadership so that we can responsibly deliver energy to the world and provide sustainable value for our stakeholders, now and in the future.
Our Philosophy: We believe that our ability to responsibly deliver energy and to provide sustainable value is driven by superior individual performance. We believe that a company must offer competitive compensation to attract and retain experienced, talented and motivated employees. Moreover, we believe employees in leadership roles within the organization are motivated to perform at their highest levels by making performance-based pay a significant portion of their compensation.
Our Principles: To achieve our goals, we implement our philosophy through the following guiding principles:
| • | Establish target compensation levels that are competitive with those of other companies with whom we compete for executive talent; |
| • | Create a strong link between executive pay and Company performance; |
| • | Induce prudent risk taking by our executives; |
| • | Motivate performance by considering specific individual accomplishments in determining compensation; |
| • | Encourage talented individuals to stay with the Company until retirement; and |
| • | Integrate all elements of compensation into a comprehensive package that aligns goals, efforts, and results throughout the organization. |
The Human Resources and Compensation Committee
The Human Resources and Compensation Committee (the HRCC or Committee) is responsible for all compensation actions related to our Senior Officers, including all of our Named Executive Officers. Although the Committee’s charter permits it to delegate authority to subcommittees or other Board Committees, the Committee made no such delegations in 2009.
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Compensation Program Design
Our executive compensation programs take into account marketplace compensation for executive talent, internal equity with our employees, past practices of the Company, corporate, business unit and individual results and the talents, skills and experience that each individual executive brings to ConocoPhillips. Our Named Executive Officers each serve without an employment agreement. All compensation for these officers is set by the Committee as described below.
The HRCC begins by establishing target levels of total compensation for our Senior Officers for a given year. Once an overall target compensation level is established, the Committee considers the weighting of each of our primary compensatory programs (Base Salary, Variable Cash Incentive Program, Stock Option Program and Performance Share Program) within the intended total target compensation.
Salary Grade Structure
Management, with the assistance of outside compensation consultants, thoroughly examines the scope and complexity of jobs throughout ConocoPhillips and studies the competitive compensation practices for such jobs. As a result of this work, management develops a compensation scale under which all positions are designated with specific “grades.” For our executives, the base salary midpoint increases at each increasing grade, but at a lesser rate than increases in target incentive compensation percentages. The result is an increased percentage of “at risk” compensation as the executive’s grade is increased. Any changes in compensation for our Senior Officers resulting from a change in salary grade are approved by the HRCC.
Benchmarking
With the assistance of our outside compensation consultants, we set target compensation by referring to multiple relevant compensation surveys that include but are not limited to large energy companies. We then compare that information to our salary grade targets (both for base salary and for incentive compensation) and make any changes needed to bring the cumulative target for each salary grade to broadly the 50th percentile for similar positions as indicated by the survey data.
For our Named Executive Officers, we conduct benchmarking, using available data, for each individual position. For example, although we determine targets for our CEO by benchmarking against other large, publicly-held energy companies, we often use broader measures (such as other publicly held energy companies) in setting targets for our operating executives. For staff executives’ targets, we may use benchmarking data from other large publicly-held companies, including those outside the energy industry. Towers Perrin then reviews and independently advises on the conclusions reached as a result of this benchmarking, and the Committee uses the results of these surveys as a factor in setting compensation structure and targets relating to our Named Executive Officers.
The HRCC’s use of primary peer groups in the context of our compensation programs generally falls into two broad categories: setting compensation targets and measuring Company performance.
| - | Setting Compensation Targets |
In setting total compensation targets and targets within each individual program the Committee uses the following primary peer group for benchmarking purposes – Exxon Mobil Corporation, Royal Dutch Shell plc, BP p.l.c., and Chevron Corporation.
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The Committee also utilizes a secondary group of peer companies for benchmarking the compensation of our Named Executive Officers – Valero Energy Corporation, Marathon Oil Corporation, Occidental Petroleum Corporation, and, for staff executives, other large publicly-held companies, including those outside the energy industry.
We utilize the primary peer group in setting compensation targets because these companies are broadly reflective of the industry in which we compete for business opportunities and for executive talent, and because they provide a good indicator of the current range of executive compensation.
| - | Measuring Performance |
We believe our performance is best measured against the largest publicly-held, international, integrated oil and gas companies against which we compete in our business operations. Therefore, for our performance-based programs, the Committee assesses our actual performance for a given period by using ExxonMobil, Royal Dutch Shell, BP, Total S.A., and Chevron as our primary benchmarking peer group.
Developing Performance Measures
We have attempted to develop performance metrics that assess the performance of the Company relative to its primary peer group rather than assessing absolute performance. This is based on the belief that absolute performance can be affected positively or negatively by industry-wide factors over which our executives have no control, such as prices for crude oil and natural gas. We have selected multiple metrics, as described below, because we believe no one metric is sufficient to capture the performance we are seeking to drive, and any metric in isolation is unlikely to promote the well-rounded executive performance necessary to enable us to achieve long-term success. The Committee reassesses performance metrics periodically.
Internal Pay Equity
We believe our compensation structure provides a framework for an equitable compensation ratio between executives, with higher targets for jobs at salary grades having greater duties and responsibilities. Taken as a whole, our compensation program is designed so that the individual target level rises as salary grade level increases, with the portion of performance-based compensation rising as a percentage of total targeted compensation. One result of this structure is that an executive’s actual total compensation as a multiple of the total compensation of his or her subordinates is designed to increase in periods of above-target performance and decrease in times of below-target performance.
Alignment of Interests
We place a premium on aligning the interests of executives with those of our stockholders. Our Stock Ownership Guidelines require executives to own stock and/or have an interest in restricted stock units valued at a multiple of base salary, ranging from 1.8 times salary for lower-level executives, to 6 times salary for the CEO. Employees have five years from the date they become subject to these Guidelines to comply. The multiple of equity held by each of our Named Executive Officers exceeds our established guidelines for his or her position.
In addition, we have historically required our executives to hold restricted stock units received under the Performance Share Program, and in predecessor programs, until death, disability, retirement, layoff, or severance after a change in control. The units were generally forfeited if an executive voluntarily left the Company’s employ when not retirement eligible. We were informed by our compensation consultants that this was a highly unusual feature. In light of this fact, the Committee
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considered our programs and determined, for performance periods beginning in 2009, restrictions on restricted stock unit awards will lapse five years from the anniversary of the issuance of the units although Senior Officers may elect to defer the lapsing of such restrictions. The Committee believes this change ensures our executives maintain their focus on long-term performance, while also allowing the Company’s programs to be more competitive with those of our peers.
Statutory and Regulatory Considerations
In designing our compensatory programs, we consider and take into account the various tax, accounting and disclosure rules associated with various forms of compensation. The HRCC also reviews and considers the deductibility of executive compensation under section 162(m) of the Internal Revenue Code, which provides that the Company may not deduct compensation of more than $1 million that is paid to certain individuals. The Company generally will be entitled to take tax deductions relating to compensation that is performance-based or that will not be paid until the executive leaves the Company. This compensation may include cash incentives, stock options, restricted stock, restricted stock units and other performance-based awards. The Committee seeks to preserve tax deductions for executive compensation. However, the Committee has awarded compensation that might not be fully tax deductible when it believes such grants are nonetheless in the best interests of our stockholders.
The Company designs its compensation programs with the intent that they comply with section 409A of the Internal Revenue Code. A discussion of the Company’s principal nonqualified deferred compensation arrangements is provided on page 74 under the heading “Nonqualified Deferred Compensation.”
Option Pricing
When the Committee grants options to its Named Executive Officers, the Company uses an average of the stock’s high and low prices on the date of grant (or the preceding business day, if the markets are closed on the date of grant) to determine the exercise price of the options. Options grants are generally made at the HRCC’s February meeting (the date of which is determined at least a year in advance) or, in the case of new hires, on the date of commencement of employment or the date of Committee approval, whichever is later.
Independent Consultants
Since 2004, the Committee has retained Towers Perrin (which has subsequently merged with Watson Wyatt and been renamed Towers Watson) as its independent executive compensation consultant. The Committee has adopted specific guidelines for outside compensation consultants, which (1) require that work done by such consultants for the Company at management’s request be approved in advance by the Committee; (2) require a review of the advisability of independent consultant rotation after a period of five years; and (3) prohibit the Company from employing any individual who worked on the Company’s account for a period of one year after leaving the employ of the independent consultant. Towers Perrin has provided an annual attestation of its compliance with these guidelines.
The Committee strongly discourages Company proposals to retain Towers Perrin for any work other than advising the Committee and does not approve any work proposed by the Company that it believes would compromise the consultant’s independence. The Committee previously approved a Company request to continue purchasing multi-company non-executive compensation surveys from Towers Perrin in the ordinary course of business at a nominal cost. The Committee does not believe that this activity compromises the independence of Towers Perrin as a consultant to the Committee,
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and it concurred with management’s assessment that Towers Perrin was better suited to provide the requested services than alternative providers. No other work proposals for Towers Perrin were submitted by management in 2009. The fees for all services provided by Towers Perrin, other than their services as an independent consultant to the Committee, did not exceed $120,000 in 2009.
In 2009, as a result of the then pending merger of Watson Wyatt and Towers Perrin and the expected retirement of its principal engagement representative to the Committee, the Committee considered whether to rotate its independent consultants. The Committee determined to retain its consultant through the early part of 2010 to provide continuity while making decisions during the February compensation decision process. After that, the Committee will retain a new independent consultant.
The Types of Compensation We Provide Our Executives
Our executive compensation program has four primary components. These four primary components are:
| • | Base Salary; |
| • | Variable Cash Incentive Program; |
| • | Stock Option Program; and |
| • | Performance Share Program. |
In addition to these primary components, the Company also provides its executives with retirement, severance, health and other personal benefits as described below.
Base Salary
Base salary is a major component of the compensation for all of our salaried employees, although it becomes a smaller component as an employee rises through the ConocoPhillips salary grade structure. Base salary is important to give an individual financial stability for personal planning purposes. There are also motivational and reward aspects to base salary, as base salary can be increased or decreased to account for considerations such as individual performance and time in position.
Performance-Based Pay Programs
Annual Incentive—The Variable Cash Incentive Program (VCIP) is an annual incentive program that is broadly available to our employees throughout the world, and it is our primary vehicle for recognizing Company, business unit, and individual performance for the past year. We believe that having an annual “at risk” compensation element for all employees, including executives, gives them a financial stake in the achievement of our business objectives and therefore motivates them to use their best efforts to ensure the achievement of those objectives. We believe that measuring and rewarding performance on an annual basis in a compensation program is appropriate because, like our primary peers and other public companies, we measure and report our business accomplishments annually. Additionally, our valuation is derived, in part, from comparisons of these annual results with those of our primary peers and relative to prior annual periods. We also believe that one year is a time period over which all employees who participate in the program can
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have the opportunity to establish and achieve their specified goals. The base award is weighted equally for corporate and business unit performance for the Named Executive Officers other than the CEO, and solely on corporate performance for the CEO. The HRCC has discretion to adjust the base award based on individual performance and makes its decision on individual performance adjustments based on the input of the CEO for all Named Executive Officers (other than for himself).
Long-Term Incentives—Our primary long-term incentive compensation programs for executives are the Stock Option and Stock Appreciation Rights Program (Stock Option Program) and the Performance Share Program (PSP). These programs, along with VCIP, are incentive programs under our stockholder approved 2009 Omnibus Stock and Performance Incentive Plan (2009 Omnibus Plan). These programs evaluate and reward performance over longer periods than our annual incentive program.
Our program targets generally provide approximately 50 percent of the long-term incentive award in the form of stock options and 50 percent in the form of restricted stock units awarded under the PSP.
| o | Stock Option Program—The Stock Option Program is designed to maximize medium- and long-term stockholder value. The practice under this program is to set option exercise prices at not less than 100 percent of the Company stock’s fair market value at the time of the grant. Although the Committee retains discretion to adjust stock option awards up or down by up to 30 percent from the specified target, the Committee did not elect to exercise such discretion with respect to the Stock Option Awards granted in February 2009. Because the option’s value is derived solely from an increase in the Company’s stock price, the value of a stockholder’s investment in the Company must appreciate before an option holder receives any financial benefit from the option. We understand that stock options have been criticized for giving executives incentives to increase the price of the stock in the short term to the detriment of the long term. We believe our program counters these incentives through the one-third annual vesting schedule for stock options combined with the impact of the PSP’s extended restricted stock unit holding period (discussed below). We also believe our Stock Option Program provides a valuable “completely at-risk” complement to the PSP. |
| o | Performance Share Program (PSP)—The PSP rewards executives based on their individual performances and the performance of the Company over a three-year period. Each year the Committee establishes a three-year performance period over which it compares the performance of the Company with that of its performance-measurement peer group using pre-established criteria. Thus, in any given year, there are three overlapping performance periods. Use of a multi-year performance period helps to focus management on longer-term results, but it can also provide compensation that may seem anomalous if compared only to performance in the current year (which may be better or worse relative to the multi-year period). |
Each executive’s individual award under PSP is subject to a performance adjustment at the end of the performance period. Although the HRCC maintains final discretion to adjust compensation in accordance with any extraordinary circumstances that may arise, and has done so in the past, program guidelines generally result in an award range between 0 to 200 percent of target. Final awards are based on the Committee’s subjective evaluation of the Company’s performance relative to the established metrics (discussed below under the heading “Measuring Our Performance under Our Compensation Programs”) and of each executive’s individual performance. The Committee considers input from the CEO with respect to Senior Officers.
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Targets for participants whose salary grades are changed during a performance period are prorated for the period of time such participant remained in each relevant salary grade.
The combination of the Stock Option Program, the PSP, and the PSP’s extended restricted stock unit holding periods provide a comprehensive package of medium and long-term compensation incentives for our executives that align their interests with those of our long-term stockholders. Such extended holding periods also enable the Company to more readily withdraw awards should circumstances arise that merit such action. To date, no Named Executive Officers have been subject to reductions or withdrawals of prior grants or payouts of restricted stock, restricted stock units or stock option awards.
| o | Other Possible Awards—ConocoPhillips may make awards outside the Stock Option Program or the PSP (off-cycle awards). Off-cycle awards (also commonly referred to as “ad hoc” or “special purpose” awards) are awards granted outside the context of our regular compensation programs. Currently, off-cycle awards are granted to certain incoming executive personnel, typically on the first day of employment, (1) to induce an executive to join the Company (occasionally replacing compensation the executive will lose because of termination from the prior employer); (2) to induce an executive of an acquired company to remain with the Company for a certain period of time following the acquisition; and/or (3) to provide a pro-rata equity award to an executive who joins the Company during an ongoing performance period for which he or she is ineligible under the standard PSP or Stock Option Program provisions. In these cases, the HRCC has sometimes approved a shorter period for restrictions on transfers of restricted stock units than those issued under the PSP or Stock Option Program. Pursuant to the Committee’s charter, any off-cycle awards to Senior Officers must be approved by the HRCC. No off-cycle awards were made to any of our Named Executive Officers in 2009. |
Broadly-Available Plans
Our Named Executive Officers participate in the same basic benefits package as our other U.S. salaried employees. This includes retirement, medical, dental, vision, life insurance, expatriate benefits and accident insurance plans, as well as flexible spending arrangements for health care and dependent care expenses.
Other Compensation and Personal Benefits
In addition to our four primary compensation programs, we provide our Named Executive Officers a limited number of additional benefits. In order to provide a competitive package of compensation and benefits, we provide our Named Executive Officers with executive life insurance coverage and defined benefit plans. We also provide other benefits that are designed primarily to minimize the amount of time the Named Executive Officers devote to administrative matters other than Company business, to promote a healthy work/life balance, to provide opportunities for developing business relationships, and to put a human face on our social responsibility programs. All such programs are approved by the HRCC.
| - | Comprehensive Security Program—Because our executives face personal safety risks in their roles as representatives of a global, integrated energy company, our Board of Directors has adopted a comprehensive security program for our executives. Under this program, our Manager of Global Security monitors changing developments in risk and threat analysis and security systems and services and recommends to management appropriate security measures. Other than in the case of a serious and immediate risk of harm, changes to the program are approved by our Board of Directors. In the “All Other Compensation” column of the Summary Compensation |
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| Table, we have reflected certain costs associated with this program, such as personal use of Company aircraft, the use of Company automobiles, and home security expenses. Although the Company does not believe that these services are compensatory in nature, we believe we are required to classify them as personal benefits in this proxy statement. |
| - | Personal Entertainment—We purchase tickets to various cultural, charitable, civic, entertainment and sporting events for business development and relationship-building purposes, as well as to maintain our involvement in communities in which the Company operates. Occasionally, our employees, including our executives, make personal use of tickets that would not otherwise be used for business purposes. We believe these tickets offer an opportunity to increase morale at a very low or no incremental cost to the Company. |
| - | Tax Gross-Ups—Certain of the personal benefits received by our executives are deemed to be taxable income to the individual by the Internal Revenue Service. When we believe that such income is incurred for purposes more properly characterized as Company business than personal benefit, we provide further payments to the executive to reimburse the cost of the inclusion of such item in the executive’s taxable income. Most often, these tax gross-up payments are provided for travel by a family member or other personal guest to attend a meeting or function in furtherance of Company business, such as Board meetings, Company-sponsored events, and industry and association meetings where spouses or other guests are invited or expected to attend. |
| - | Annual Physical—Our executives are reimbursed for the costs of an annual physical. This program recognizes the importance of the overall health of our executives. |
| - | Executive Life Insurance—We maintain life insurance policies and/or death benefits for all of our U.S. based salaried employees (at no cost to the employee) with a face value approximately equal to their annual salaries. For our executives, we maintain an additional life insurance policy and/or death benefits (at no cost to the executive) with a value equal to their annual salary. These two programs combine to provide an executive with life insurance equal to two times annual salary at no cost (other than imputed income for tax purposes, which we do not gross up). In addition to these two plans, we also provide our executives the option of purchasing group variable universal life insurance in an amount up to eight times their annual salary. We believe this is a benefit valued by our executives that can be provided at no cost to the Company. |
| - | Defined Contribution Plans—We maintain the following nonqualified defined contribution plans for our executives. These plans allow deferred amounts to grow tax-free until distributed, and also allow the Company to utilize the money for the duration of the deferral period for general corporate purposes. |
| o | Voluntary Deferred Compensation Plans—The purpose of our voluntary nonqualified deferred compensation plans is to allow executives to defer a portion of their salary and annual incentive compensation. By making such deferrals, the executive defers paying taxes on such amounts until the year in which distributions are made from the plans. The executives are allowed to direct the investment of deferred amounts held on their behalf. |
| o | Make-Up Plans—The purpose of our nonqualified defined contribution make-up plans is to provide benefits that an executive would otherwise lose due to limitations imposed by the Internal Revenue Code on qualified plans. |
| - | Defined Benefit Plans—We also maintain nonqualified defined benefit plans for our executives. The primary purpose of these plans is to provide benefits that an executive would otherwise lose due to limitations imposed by the Internal Revenue Code on qualified plans. |
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Severance Plans and Changes in Control
We maintain plans to address severance of our executives in certain circumstances as described under the heading “Executive Severance and Changes in Control” beginning on page 77. The structure and use of these plans are competitive within the industry and are intended to aid the Company in attracting and retaining executives.
The Executive Severance Plan was approved by the HRCC and provides benefits to executives in salary grades corresponding to vice president (or equivalent) and higher in the event that the Company discharges the executive without cause. This plan provides the Company with flexibility to make personnel changes when executives impacted by such changes would not be entitled to the layoff benefits provided in the broad-based severance plan for employees. We believe this plan aids us in recruiting executives externally because it provides them with a measure of protection, and it enables us to avoid negotiating individual severance arrangements with newly hired or departing executives. We also believe this plan reduces the likelihood and extent of litigation from executive severance.
The HRCC also approved a Change in Control Severance Plan to provide similar benefits in the event covered executives are discharged after a change in control of the Company. The Change in Control Severance Plan provides benefits to executives in salary grades corresponding to vice president (or equivalent) and higher in the event that the Company discharges the executive without cause following a change in control. In our view, the severance level provided under the plan is appropriate as it is the current standard for senior executives in many U.S. industries. The Change in Control Severance Plan also incorporates a provision to address the impact of the federal excise tax on excess parachute payments. The so-called “golden parachute” tax rules subject “excess parachute payments” to a dual penalty: the imposition of a 20 percent excise tax upon the recipient and non-deductibility of such payments by the paying corporation. While the excise tax is seemingly evenhanded, it can discriminate against long-serving employees in favor of new hires, against individuals who do not exercise stock options in favor of those who do and against those who elect to defer compensation in favor of those who do not. For these reasons, we believe that the provision of the excise tax gross-up in the Change in Control Severance Plan is appropriate.
Measuring Our Performance under Our Compensation Programs
We use corporate and business unit performance criteria in determining individual payouts. In addition, our programs contemplate that the Committee will exercise discretion in assessing and rewarding individual performance.
Corporate Performance Criteria
We utilize multiple measures of performance under our programs to ensure that no single aspect of performance is driven in isolation. We have employed the following measures of overall Company performance under our performance-based programs:
| o | Relative Total Stockholder Return—Total stockholder return represents the percentage change in a company’s common stock price from the beginning of a period of time to the end of the stated period, and assumes common stock dividends paid during the stated period are reinvested into that common stock. We use a total stockholder return measure because it is the most tangible measure of the value we have provided to our stockholders during the relevant program period. We recognize that total stockholder return is not a perfect measure. It can be affected by factors beyond management’s control and by market conditions not related to the intrinsic performance of the Company. Stockholder return over the short-term |
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| can also fail to fully reflect the value of longer-term projects. We seek to mitigate the influence of industry-wide or market-wide conditions on stock price by using total stockholder return relative to our primary peer group. |
| o | Relative Adjusted Return on Capital Employed—Our businesses are capital intensive, requiring large investments, in most cases over a number of years, before tangible financial returns are achieved. Therefore, we believe that a good indicator of long-term Company and management performance, both absolute and relative to our primary peer group, is the measure known as return on capital employed (ROCE). Relative ROCE is a measure of the profitability of our capital employed in our business compared with that of our peers. We calculate ROCE as a ratio, the numerator of which is net income plus after-tax interest expense, and the denominator of which is average total equity plus total debt. The use of ROCE as a comparative measure is complicated by the fact that two different accounting methods were used for business combinations prior to June 2001. Accounting for a combination on the “purchase” method generally resulted in a much higher amount of capital employed after the combination than did the “pooling-of-interests” method. While we were required to utilize the “purchase” method for all of our significant business combinations, several members of our performance- measurement peer group utilized the “pooling-of-interests” method for their significant combinations. For comparability, in performance periods beginning prior to 2009, we adjust “capital employed” to take into account the difference in these accounting methods. We also adjust the net income of the Company and our peers for certain non-core earnings impacts. For performance periods before 2005 and after 2007, our programs considered our improvement on Adjusted ROCE relative to our performance-measurement peer group. For the 2005-2007 performance periods, our programs considered our absolute Adjusted ROCE relative to our performance-measurement peer group. |
| o | Relative Adjusted Income per Barrel of Oil Equivalent (BOE)—An important measure of operating efficiency and management performance is a comparison of the income earned by the Company per barrel of oil produced by our Exploration & Production (E&P) business segment, and per barrel of petroleum products sold by our Refining & Marketing (R&M) business segment, versus those of our peers. This measure allows us to compare our operating efficiency in producing and refining/marketing products against that of our performance-measurement peer group. The measure is calculated by dividing adjusted income attributable to our E&P and R&M segments by the number of barrels produced or petroleum products sold, respectively. A weighted average of these two segment-level metrics is then calculated and compared against that of our peers. As with our calculation of Adjusted ROCE, we adjust both our own income and that of our peers to reflect certain non-core earnings impacts. We added this metric for performance periods beginning in 2007 and 2008. |
| o | Relative Adjusted Cash Contribution per BOE—Like ROCE, another important measure of operating efficiency and management performance is the Company’s cash contributions per barrel of oil produced by our E&P segment, and per barrel of petroleum products sold by our R&M segment. This measure is another way to compare our operating efficiency in producing and refining/marketing products against that of our performance-measurement peer group. The measure is calculated by dividing the adjusted income from operations plus the depreciation, depletion and amortization (or DD&A) attributable to our E&P and R&M segments by the number of barrels produced or petroleum products sold, respectively. A weighted average of these two segment-level metrics is then calculated, and compared against that of our peers. As with our calculation of Adjusted ROCE, we adjust both our own income and that of our peers to reflect certain non-core earnings impacts. We added this metric for performance periods beginning in 2008. |
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| o | Health, Safety and Environmental Performance—We seek to be a good employer, a good community member and a good steward of the environmental resources we manage. Therefore, we incorporate metrics of health, safety and environmental performance in our annual incentive compensation program. |
| o | Implementation of Strategic Plan—This measure is a subjective analysis of the Company’s progress in implementing its strategic plan over a given performance period. We added this metric for performance periods beginning in 2007 and 2008. |
| o | Succession Planning/Leadership Development—This measure is a subjective analysis of the Company’s progress in developing and implementing a comprehensive succession plan for senior management, and the development and implementation of a Company-wide program for identifying and developing future leaders within the Company. We added this metric for performance periods beginning in 2007. |
| o | Financial Management—This measure is a subjective analysis of the Company’s progress in managing the Company’s capital profile and liquidity needs. We added this metric for performance periods beginning in 2009. |
| o | Support of Strategic Corporate Initiatives—This measure is a subjective analysis of our progress in implementing key elements of the company’s strategic initiatives, including but not limited to relationships, climate change, reputation, people/diversity, culture, opportunity capture and execution of company strategies. We added this metric for performance periods beginning in 2009. |
Business Unit Performance Criteria
There are approximately 100 discrete award units within the Company designed to measure performance and to reward employees according to business outcomes relevant to the award group. Although most employees participate in a single award unit designated for the operational or functional group to which such employee is assigned, a Senior Officer can participate in a blend of the results of more than one of these award units depending on the scope and breadth of his or her responsibilities over the performance period. Moreover, because our CEO is responsible for overall Company performance, his award is based solely on individual and overall Company performance.
Performance criteria are goals consistent with the Company’s operating plan and include quantitative and qualitative metrics specific to each business unit, such as income from continuing operations (adjusted to neutralize the impact of changes in commodity prices), control of costs, health, safety and environmental performance, support of corporate initiatives, and various milestones set by management. At the conclusion of a performance period, management makes a recommendation based on the unit’s performance for the year against its performance criteria. The HRCC then reviews management’s recommendation regarding each award unit’s performance and has discretion to adjust any such recommendation in approving the final awards.
Individual Performance Criteria
Individual adjustments for our Named Executive Officers are approved by the HRCC, based on the recommendation of the CEO (other than for himself). The CEO’s individual adjustment is determined by the Committee taking into account the prior review of the CEO’s performance, which is conducted jointly by the HRCC and the Committee on Directors’ Affairs.
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Tax-Based Program Criteria
Our incentive programs are also designed to conform to the requirements of section 162(m) of the Internal Revenue Code, which allows for deductible compensation in excess of $1 million if certain criteria, including the attainment of pre-established performance criteria, are met. Each year, prior to making awards under the incentive programs, the HRCC determines if the relevant criteria were met for the completed performance periods.
An Analysis of Compensation Paid to Our Executives
In determining performance-based compensation awards for our Named Executive Officers for performance periods concluding in 2009, the HRCC began by considering overall Company performance, including the following accomplishments and operating conditions:
| • | The Company’s response to the global economic crisis; |
| • | Progress on key strategic projects; |
| • | Exploration success; |
| • | Participation in the debate on key legislative proposals; and |
| • | Efforts in managing the Company’s workforce and reputation. |
The Committee then considered any adjustments to the awards under our three performance-based compensation programs (VCIP, Stock Option Program and PSP) in accordance with their terms and pre-established criteria, while retaining the discretion to adjust awards based solely on the Committee’s determination of appropriate payouts.
As a result, the Committee made the following award decisions under the Company’s performance-based compensation programs.
2009 VCIP Awards
In determining award payouts under VCIP for 2009, the Committee considered the following performance criteria:
| - | Company Performance for 2009—In 2009, our VCIP program used both quantitative and qualitative performance measures relating to the Company as a whole, including: |
| o | Ranking 5th in relative annual total stockholder return compared with our performance-measurement peer group (ExxonMobil, Royal Dutch Shell, BP, Total, and Chevron); |
| o | Ranking 2nd in absolute change and 4th in percentage change in relative annual adjusted return on capital employed compared with the same peer group noted above; |
| o | Ranking 2nd in relative adjusted cash contribution per BOE compared with the same peer group noted above; |
| o | Our health, safety and environmental performance; and |
| o | Advancement of our key strategic initiatives. |
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Based on such review, management recommended, and the Committee concluded, that the Company’s performance under these measures in 2009 merited payment of 111% of the targeted amount.
| - | Business Unit Performance in 2009—In determining award unit performance, the Committee reviewed and approved management’s determinations of performance by the Company’s award units under their performance criteria. Messrs. Carrig and Cornelius participated in the operational and staff award units, respectively, over which they had responsibility. Messrs. Meyers and Lance participated in those award units within the E&P segment over which they have, or had, responsibility, weighted to reflect their time of service within such units. Mr. Gallogly participated in all award units within the E&P segment. The Committee determined that the combined corporate and award unit performance merited base awards of between 101% and 115% of target for each of our Named Executive Officers, other than Mr. Mulva. As noted under “Business Unit Performance Criteria” beginning on page 53, Mr. Mulva’s award, as CEO, is based on individual and overall Company performance. |
| - | Individual Performance Adjustments—Finally, the Committee considered individual adjustments for each Named Executive Officer’s 2009 VCIP award based upon a subjective review of the individual’s impact on the Company’s financial and operational success during the year. The Committee considered the totality of the executive’s performance in deciding the individual adjustments. Based on the foregoing, the Committee approved individual performance adjustments of between 0% and 15% for each of our Named Executive Officers. The individual adjustments for these officers reflect the Committee’s recognition of these individuals’ contributions to the strong 2009 operational performance of their respective operating units. |
| - | CEO Award—Although the Company delivered a strong performance in 2009 in a difficult economic climate, Mr. Mulva advised that he would not accept half the amount of any VCIP award to which the HRCC ultimately determined he otherwise would be entitled. This proposal was a reflection of Mr. Mulva’s belief that, although the Company delivered a strong operational performance in 2009, this performance was not reflected in the Company’s stock price. The HRCC accepted Mr. Mulva’s proposal and ultimately approved an award of 63% of target for Mr. Mulva, which represents 50% of the VCIP award the Committee believed the Company’s and Mr. Mulva’s performance otherwise would have merited. |
Stock Option Awards
Although the Committee retains discretion to adjust stock option awards by up to 30 percent from the specified target, the Committee did not elect to exercise such discretion with respect to the Stock Option Awards granted in February 2009.
PSP Awards (2007-2009 Performance Period)
In December 2006, the Committee established the fifth performance period under the PSP, for the three-year period beginning January 1, 2007, and ending December 31, 2009 (PSP V). In February 2010, in determining awards under the PSP for this period, the Committee considered quantitative and qualitative performance measures relating to the Company as a whole, including:
| • | Ranking 6th in relative total stockholder return compared with our performance-measurement peer group (ExxonMobil, Chevron, Royal Dutch Shell, BP, and Total); |
| • | Ranking 5th in relative adjusted return on capital employed compared with the same peer group noted above; |
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| • | Ranking 6th in relative adjusted income per BOE compared with the same peer group noted above; |
| • | Advancement and implementation of the Company’s strategic plan; |
| • | Leadership development and succession planning. |
Based on this review, the Committee determined that the Company’s performance under the stated criteria during the three-year performance period merited payment of 60% of the targeted amount. With respect to individual adjustments, similar to the 2009 VCIP program, the Committee considered PSP individual adjustments for each Named Executive Officer in recognition of the individual’s personal leadership and contribution to the Company’s financial and operational success over the three-year performance period. Based on the foregoing, the Committee approved individual performance adjustments of between 10% and 15% for each of our Named Executive Officers.
2010 TARGET COMPENSATION
In addition to determining the 2009 compensation payouts, the HRCC established the targets for 2010 compensation for our Named Executive Officers (other than Mr. Gallogly, who retired from the Company on May 22, 2009) under our four primary compensation programs. As discussed under “Performance-Based Pay Programs” beginning on page 47, with the exception of salary, the targeted amounts shown below are performance-based and, therefore, actual amounts received under such programs, if any, may differ from the targets shown below.
| Name | Salary | 2010 VCIP Target Value |
2010 Stock Option Award Target Value |
PSP VIII (2010- 2012) Target Value |
Total 2010 Target Compensation |
||||||||||
| J.J. Mulva |
$1,500,000 | $2,025,000 | $5,737,500 | $5,737,500 | $15,000,000 | ||||||||||
| J.A. Carrig |
1,145,000 | 1,259,500 | 3,549,500 | 3,549,500 | 9,503,500 | ||||||||||
| S.L. Cornelius |
698,016 | 579,353 | 1,099,375 | 1,099,375 | 3,476,119 | ||||||||||
| R.M. Lance |
659,016 | 546,983 | 1,037,950 | 1,037,950 | 3,281,899 | ||||||||||
| K.O. Meyers |
644,016 | 534,533 | 1,014,325 | 1,014,325 | 3,207,199 |
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This graph shows ConocoPhillips’ cumulative total stockholder return over the five-year period from December 31, 2004, to December 31, 2009. The graph also shows the cumulative total returns for the same five-year period of the S&P 500 Index and our performance peer group of companies consisting of BP, Chevron, ExxonMobil, Royal Dutch Shell, and Total, weighted according to the respective peer’s stock market capitalization at the beginning of each annual period. The comparison assumes $100 was invested on December 31, 2004, in ConocoPhillips stock, in the S&P 500 Index and in ConocoPhillips’ peer group and assumes that all of the dividends were reinvested.
Five-Year Cumulative Total Stockholder Return
Five Years Ended December 31, 2009
| December 31 | |||||||||||||||||||
| Initial | 2005 | 2006 | 2007 | 2008 | 2009 | ||||||||||||||
| ConocoPhillips |
$100 | $ | 137 | $ | 173 | $ | 217 | $ | 131 | $ | 134 | ||||||||
| Peer Group (1) |
$100 | $ | 113 | $ | 141 | $ | 172 | $ | 131 | $ | 141 | ||||||||
| S&P 500 |
$100 | $ | 105 | $ | 121 | $ | 128 | $ | 81 | $ | 102 | ||||||||
(1) Performance Peer Group consists of BP, Chevron, ExxonMobil, Royal Dutch Shell and Total.
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The following tables and accompanying narrative disclosures and footnotes provide information concerning total compensation paid to certain of our Senior Officers, referred to as Named Executive Officers. Please also see our discussion of the relationship between the “Compensation Discussion and Analysis” to these tables under “An Analysis of Compensation Paid to Our Executives” beginning on page 54. The data presented in the tables that follow include amounts paid to the Named Executive Officers by ConocoPhillips or any of its subsidiaries for 2009.
SUMMARY COMPENSATION TABLE
The Summary Compensation Table below reflects amounts earned with respect to 2009 and performance-periods ending in 2009. We have excluded arrangements that are generally available to our U.S.-based salaried employees, such as our medical, dental, disability, and flexible spending account arrangements, since all of our Named Executive Officers are U.S.-based salaried employees. Based on the salary and total compensation amounts for Named Executive Officers for 2009 shown in the table below, salary accounted for approximately 11.5 percent of the total compensation of the Named Executive Officers and incentive compensation programs (stock awards, option awards, and non-equity incentive plan compensation) accounted for approximately 75.2 percent. For the CEO alone in 2009, salary accounted for approximately 10.4 percent of his total compensation and incentive compensation programs accounted for approximately 88.2 percent of his total compensation. These numbers reflect the emphasis placed by the Company on performance-based pay.
| Name and Principal Position |
Year | Salary ($)(1) |
Bonus ($)(2) |
Stock Awards ($)(3) |
Option Awards ($)(4) |
Non-Equity Incentive Plan Compensation ($)(5) |
Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)(6) |
All Other Compensation ($)(7) |
Total ($) | ||||||||||||||||||
| J.J. Mulva Chairman & CEO |
2009 | $1,500,000 | $ — | $5,669,518 | $5,737,576 | $1,278,788 | $ — | $ 202,779 | $14,388,661 | (8) | |||||||||||||||||
| 2008 | 1,500,000 | — | 5,454,676 | 5,738,304 | 1,417,500 | 9,776,065 | 519,007 | 24,405,552 | |||||||||||||||||||
| 2007 | 1,500,000 | — | 4,826,891 | 4,938,290 | 3,442,500 | 1,727,552 | 387,647 | 16,822,880 | |||||||||||||||||||
| J.A. Carrig President & COO |
2009 | 1,145,000 | — | 3,507,419 | 3,549,650 | 1,474,560 | 2,487,509 | 133,033 | 12,297,171 | ||||||||||||||||||
| 2008 | 967,333 | — | 3,938,728 | 1,748,208 | 1,054,944 | 3,644,373 | 143,670 | 11,497,256 | |||||||||||||||||||
| 2007 | 817,500 | — | 1,409,832 | 1,443,088 | 1,186,291 | 1,424,708 | 131,904 | 6,413,323 | |||||||||||||||||||
| S.L. Cornelius Senior Vice President, Finance, and CFO |
2009 | 688,008 | — | 1,055,177 | 1,068,808 | 575,615 | 926,945 | 73,968 | 4,388,521 | ||||||||||||||||||
| 2008 | 599,667 | — | 814,518 | 857,648 | 514,522 | 774,791 | 106,244 | 3,667,390 | |||||||||||||||||||
| 2007 | 515,000 | — | 1,071,958 | 639,388 | 596,607 | 1,088,376 | 84,684 | 3,996,013 | |||||||||||||||||||
| R.M. Lance Senior Vice President, Exploration & Production– International |
2009 | 649,508 | — | 996,020 | 1,008,436 | 637,117 | 693,413 | 53,171 | 4,037,665 | ||||||||||||||||||
| 2008 | 590,167 | — | 814,518 | 857,648 | 512,371 | 460,200 | 85,007 | 3,319,911 | |||||||||||||||||||
| 2007 | 499,000 | — | 911,777 | 623,314 | 545,032 | 210,937 | 79,096 | 2,869,156 | |||||||||||||||||||
| K.O. Meyers Senior Vice President, Exploration & Production– Americas |
2009 | 615,318 | — | 1,042,261 | 802,724 | 654,572 | 658,563 | 644,392 | 4,417,830 | ||||||||||||||||||
| 2008 | 567,167 | — | 716,008 | 755,040 | 511,812 | 580,384 | 1,561,067 | 4,691,478 | |||||||||||||||||||
| 2007 | 535,335 | — | 714,407 | 732,260 | 662,102 | 310,344 | 1,076,504 | 4,030,952 | |||||||||||||||||||
| J.L. Gallogly (9) Executive Vice President, Exploration and Production |
2009 | 531,900 | — | 2,086,300 | 2,111,902 | 438,731 | — | 83,006 | 5,251,839 | ||||||||||||||||||
| 2008 | 938,458 | — | 1,710,321 | 1,800,480 | 991,322 | 2,842,903 | 177,640 | 8,461,124 | |||||||||||||||||||
| 2007 | 858,666 | — | 1,657,259 | 1,696,700 | 1,237,698 | 1,046,381 | 135,267 | 6,631,971 |
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| (1) | Includes any amounts that were voluntarily deferred to the Company’s Key Employee Deferred Compensation Plan. |
| (2) | Because our primary short-term incentive compensation arrangement for salaried employees (the Variable Cash Incentive Program or VCIP) has mandatory performance measures that must be achieved before there is any payout to Named Executive Officers, amounts paid under VCIP are shown in the Non-Equity Incentive Plan Compensation ($) column of the table, rather than the Bonus ($) column. |
| (3) | Amounts shown represent the aggregate grant date fair value of awards made under the Performance Share Program (PSP) during each of the years indicated, as determined in accordance with FASB ASC Topic 718. See the “Share-Based Compensation Plans” section of Note 19 in the Notes to Consolidated Financial Statements in the Company’s 2009 Annual Report on Form 10-K for a discussion of the relevant assumptions used in this determination. |
The amounts shown for stock awards are from our PSP or for off-cycle awards, although no off-cycle awards were granted to any of the Named Executive Officers during 2009, 2008, or 2007. These may include awards that are expected to be finalized as late as 2012. The amounts shown for awards from PSP relate to the three-year performance period that began in the years presented. Performance periods under PSP generally cover a three-year period and, as a new performance period has begun each year since the program commenced, there are three overlapping performance periods ongoing at any time.
In December 2006, the HRCC approved the commencement of a performance period covering 2007 through 2009. In February 2007, the HRCC determined performance and approved final payout with regard to the performance period that began in 2004 and ended in 2006. In December 2007, the HRCC approved the commencement of a performance period covering 2008 through 2010. In February 2008, the HRCC determined performance and approved final payout with regard to the performance period that began in 2005 and ended in 2007. In February 2009, the HRCC approved the commencement of a performance period covering 2009 through 2011 and determined performance and approved final payout with regard to the performance period that began in 2006 and ended in 2008. In December 2009, the HRCC approved the commencement of a performance period covering 2010 through 2012. In February 2010, the HRCC determined performance and approved final payout with regard to the performance period that began in 2007 and ended in 2009.
In addition to the performance criteria contained within PSP, in order for a Named Executive Officer to receive any award under PSP beginning with the performance period that began in 2009, a second set of threshold criteria must be met. This tier of performance measure and methodology is designed to meet requirements for deductibility of this item of compensation under section 162(m) of the Internal Revenue Code. Pursuant to this tier, a maximum payment for the performance period under PSP is set, but it is subject to downward adjustment through the application of the generally applicable methodology for PSP awards discussed in the CD&A, so it effectively establishes a ceiling for PSP payouts to each Named Executive Officer. Performance criteria for the 2009 program year required that the Company meet one of the following measures as a threshold to an award being made to any Named Executive Officer: (1) Top two-thirds of specified companies in improvement in return on capital employed (adjusted net income); (2) Top two-thirds of specified companies in total stockholder return; (3) Top two-thirds of specified companies in cash per barrel-of-oil-equivalent; or (4) Cash from operations (normalized to assumptions made in our budgeting process as to price for oil equivalents and excluding non-cash working capital) of at least $30 billion. In addition to ConocoPhillips, the specified companies for this purpose were BP, Chevron, ExxonMobil, Royal Dutch Shell, and Total. The HRCC is scheduled to determine if this threshold has been achieved at its February 2012 meeting.
Amounts shown are targets set for awards for 2009, 2008, and 2007, since it is most probable at the setting of the target for the applicable performance periods that targets will be achieved. If payout was made at maximum levels for company performance, the amounts shown would double from the targets shown, although the value of the actual payout would be dependent upon the stock price at the time of the payout. If payout was made at minimum levels, the amounts would be reduced to zero. No adjustment is made to the target shown for prior years based upon any change in probability subsequent to the time the target is set. Changes to targets resulting from promotion or demotion of a Named Executive Officer are shown as awards in the year of the promotion or demotion, even though the awards may relate to a program period that began in an earlier year. Actual payouts with regard to the targets set for 2007 were approved by the HRCC at its February 2010 meeting, at which the Committee determined the payouts to be made to Senior Officers (including the Named Executive Officers) for the performance period that began in 2007 and ended in 2009. Those payouts were as follows (with values shown at fair market value on the date of payout): Mr. Mulva, 48,000 performance share units, $2,322,480; Mr. Carrig, 23,581 performance share units, $1,140,967; Mr. Cornelius, 7,856 performance share units, $380,113; Mr. Lance, 7,327 performance share units, $354,517; Mr. Meyers, 7,928 performance share units, $383,596; and Mr. Gallogly, 12,818 performance share units, $620,199.
Awards under PSP are made in restricted stock or restricted stock units that will generally be forfeited if the employee is terminated prior to the end of the escrow period set in the award (other than for death or following disability or after a change in control). For target awards for program periods beginning in 2008 and earlier, the escrow period lasts until separation from service, except in the cases of termination due to death, layoff, or retirement, or after disability or a change in control, when the escrow period ends at the exceptional termination event. For target awards for program periods beginning in 2009 and later, the escrow period lasts five years from the grant of the award (which would be more than eight years after the beginning of the program period, when measured including the performance period) unless the employee makes an election
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prior to the beginning of the program period to have the escrow period last until separation from service instead; except that in the cases of termination due to death, layoff, or retirement, or after disability or a change in control, the escrow period ends at the exceptional termination event. In the event of termination due to layoff or retirement after age 55 with five years of service, a value for the forfeited restricted stock or restricted stock units will generally be credited to a deferred compensation account for the employee for awards made prior to 2005; for later awards, restrictions lapse in the event of termination due to layoff or early retirement after age 55 with five years of service, unless the employee has elected to defer receipt of the stock until a later time.
| (4) | Amounts represent the dollar amount recognized as the aggregate grant date fair value, as determined in accordance with FASB ASC Topic 718. See the “Share-Based Compensation Plans” section of Note 19 in the Notes to Consolidated Financial Statements in the Company’s 2009 Annual Report on Form 10-K for a discussion of the relevant assumptions used in this determination. All such options were awarded under the Company’s Stock Option (and Stock Appreciation Rights) Program. Options awarded to Named Executive Officers under that program generally vest in three equal annual installments beginning with the first anniversary from the date of grant and expire ten years after the date of grant. However, in the event that a Named Executive Officer has attained the early retirement age of 55 with 5 years of service, the value of the options granted is taken in the year of grant or over the number of months until the executive attains age 55 with 5 years of service. |
Option awards are made in February of each year at a regularly-scheduled meeting of the HRCC. Occasionally, option awards may be made at other times, such as upon the commencement of employment of an individual. In determining the number of shares to be subject to these option grants, the HRCC used a Black-Scholes-Merton-based methodology to value the options. In February 2009, the HRCC determined option awards for that year, which become exercisable on the anniversary date of the grant in years 2010, 2011, and 2012. In February 2008, the HRCC determined option awards for that year, which become exercisable on the anniversary date of the grant in years 2009, 2010, and 2011. In February 2007, the HRCC determined option awards for that year, which became exercisable on the anniversary date of the grant in years 2008, 2009, and 2010. In February 2010, the HRCC determined option awards for that year, which become exercisable on the anniversary date of the grant in years 2011, 2012, and 2013, although the value for those awards will not appear in the tables until next year.
| (5) | Includes amounts paid under VCIP, our primary non-equity short-term incentive arrangement, and includes amounts that were voluntarily deferred to the Company’s Key Employee Deferred Compensation Plan. For the 2009 program year, payments were made in February 2010, for the 2008 program year, payments were made in February 2009, and for the 2007 program year, payments were made in February 2008. See also note (2) above. |
With regard to Named Executive Officers, the HRCC sets two tiers of performance criteria. First, performance criteria under VCIP apply to all eligible employees, including the Named Executive Officers. The HRCC assessed individual performance of Senior Officers, including all of the Named Executive Officers, at its February 2010 meeting for the 2009 program year, at its February 2009 meeting for the 2008 program year, and at its February 2008 meeting for the 2007 program year. Under VCIP, the amounts of individual awards are discretionary, but are expected, except in extraordinary cases, to range from zero to 200 percent of the target amount for the award year, based on the HRCC’s assessment of total Company and business unit performance, with an award for individual performance available of up to an additional 50 percent. At its February 2010 meeting, the HRCC approved the individual awards for Senior Officers, including the Named Executive Officers, for the 2009 program year. At its February 2009 meeting, the HRCC approved the individual awards for Senior Officers, including the Named Executive Officers, for the 2008 program year. At its February 2008 meeting, the HRCC approved the individual awards for Senior Officers, including the Named Executive Officers, for the 2007 program year. Individual awards for other employees were approved by the CEO effective at the same time.
In addition, in order for a Named Executive Officer to receive any award under VCIP a second set of threshold criteria must be met. This tier of performance measure and methodology is designed to meet requirements for deductibility of this item of compensation under section 162(m) of the Internal Revenue Code. Pursuant to this tier, a maximum payment for the performance period under VCIP is set, but it is subject to downward adjustment through the application of the generally applicable methodology for VCIP awards discussed in the prior paragraph, so it effectively establishes a ceiling for VCIP payments to each Named Executive Officer. Performance criteria for the 2009 program year required that the Company meet one of the following measures as a threshold to an award being made to any Named Executive Officer: (1) Top two-thirds of specified companies in improvement in return on capital employed (adjusted net income); (2) Top two-thirds of specified companies in total stockholder return; (3) Top two-thirds of specified companies in cash per barrel-of-oil-equivalent; or (4) Cash from operations (normalized to assumptions made in our budgeting process as to price for oil equivalents and excluding non-cash working capital) of at least $8 billion. In addition to ConocoPhillips, the specified companies for this purpose were BP, Chevron, ExxonMobil, Royal Dutch Shell, and Total. At its February 2010 meeting, the HRCC determined that this threshold had been achieved. Performance criteria for the 2008 program year required that the Company meet one of the following measures as a threshold to an award being made to any Named Executive Officer: (1) Top two-thirds of specified companies in improvement in return on capital employed (adjusted to purchase accounting); (2) Top two-thirds of specified companies in total stockholder return; (3) Top two-thirds of specified companies in income per barrel-of-oil-equivalent; or (4) Cash from operations (normalized to assumptions made in our budgeting process as to price for oil equivalents and excluding non-cash working capital) of at least $14.875 billion. In addition to ConocoPhillips, the
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specified companies for this purpose were BP, Chevron, ExxonMobil, Royal Dutch Shell, and Total. At its February 2009 meeting, the HRCC determined that this threshold had been achieved. Performance criteria for the 2007 program year required that the Company meet one of the following measures as a threshold to an award being made to any Named Executive Officer: (1) Top two-thirds of specified companies in return on capital employed (adjusted to purchase accounting); (2) Top two-thirds of specified companies in total stockholder return; (3) Top two-thirds of specified companies in income per barrel-of-oil-equivalent; or (4) Cash from operations (normalized to assumptions made in our budgeting process as to price for oil equivalents and excluding non-cash working capital) of at least $14.5 billion. In addition to ConocoPhillips, the specified companies for this purpose were BP, Chevron, ExxonMobil, Royal Dutch Shell, and Total. At its February 2008 meeting, the HRCC determined that this threshold had been achieved.
| (6) | Amounts represent the actuarial increase in the present value of the Named Executive Officer’s benefits under all pension plans maintained by the Company determined using interest rate and mortality rate assumptions consistent with those used in the Company’s financial statements. Interest rates assumption changes have a significant impact on the pension values with periods of lower interest rates having the effect of increasing the actuarial values reported and vice versa. Primarily as a result of such actuarial factors, the present value of the benefit to Mr. Mulva decreased from 2008 to 2009 by $7,885,466, although in accordance with SEC rules that do not permit the inclusion of values less than $0 for this column, an amount of zero is shown above. |
| (7) | As discussed in the Compensation Discussion and Analysis section of this proxy statement, ConocoPhillips provides its executives with a number of compensation and benefit arrangements. The tables below reflect amounts earned under those arrangements. We have excluded arrangements that are generally available to our U.S.-based salaried employees, such as our medical, dental, disability, and flexible spending account arrangements, since all of our Named Executive Officers are U.S.-based salaried employees. Certain of the amounts reflected below were paid in local currencies, which we value in this table in U.S. dollars using a monthly currency valuation for the month in which costs were incurred. For Mr. Lance, Singapore dollars were converted to U.S. dollars, and for Mr. Meyers, Canadian dollars were converted to U.S. dollars. All Other Compensation includes the following amounts, which were determined using actual cost paid by the Company unless otherwise noted: |
| Name | Personal Use of Company Aircraft(a) |
Automobile Provided by Company(b) |
Home Security(c) |
Financial Planning(d) |
Club Dues(e) |
Annual Physical(f) |
Executive Group Life Insurance Premiums(g) |
||||||||||||||||||
| J.J. Mulva |
2009 | $ 3,375 | $14,967 | $ 874 | $ — | $ — | $1,964 | $11,880 | |||||||||||||||||
| 2008 | 54,802 | 25,409 | 230 | 20,000 | — | 3,032 | 11,880 | ||||||||||||||||||
| 2007 | 35,309 | 22,740 | 10,498 | 20,000 | — | — | 11,880 | ||||||||||||||||||
| J.A. Carrig |
2009 | — | — | — | — | — | 795 | 5,908 | |||||||||||||||||
| 2008 | — | — | — | — | — | 867 | 4,898 | ||||||||||||||||||
| 2007 | — | — | — | — | — | 665 | 4,219 | ||||||||||||||||||
| S.L Cornelius |
2009 | — | — | — | — | — | 638 | 3,550 | |||||||||||||||||
| 2008 | — | — | — | 10,000 | — | 1,276 | 1,633 | ||||||||||||||||||
| 2007 | — | — | — | 10,000 | 1,306 | — | 1,405 | ||||||||||||||||||
| R.M. Lance |
2009 | — | — | — | — | — | — | 1,169 | |||||||||||||||||
| 2008 | — | — | — | 9,500 | — | — | 1,054 | ||||||||||||||||||
| 2007 | — | — | — | 9,500 | — | — | 884 | ||||||||||||||||||
| K.O. Meyers |
2009 | — | — | — | — | 3,111 | — | 3,162 | |||||||||||||||||
| 2008 | — | — | — | 10,000 | 4,200 | — | 2,927 | ||||||||||||||||||
| 2007 | — | — | 207 | 10,000 | 35,373 | — | 1,478 | ||||||||||||||||||
| J.L. Gallogly |
2009 | — | — | 945 | — | — | 6,097 | 2,188 | |||||||||||||||||
| 2008 | — | — | 599 | 1,454 | — | 2,994 | 4,803 | ||||||||||||||||||
| 2007 | — | — | 6,652 | 2,600 | — | 265 | 4,431 |
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| Name | Tax Reimbursement Gross-Up(h) |
Relocation(i) | Expatriate(j) | Director Charitable Gift Program(k) |
Matching Gift Program(l) |
Matching Contributions Under the Tax-Qualified Savings Plans(m) |
Company Contributions to Nonqualified Defined Contribution Plans(n) |
||||||||||||||||||
| J.J. Mulva |
2009 | $17,954 | $ — | $ — | $ — | $18,000 | $13,947 | $119,818 | |||||||||||||||||
| 2008 | 27,163 | — | — | 113,537 | 18,500 | 22,576 | 221,878 | ||||||||||||||||||
| 2007 | 8,427 | — | — | 43,628 | 18,000 | 22,668 | 194,497 | ||||||||||||||||||
| J.A. Carrig |
2009 | 745 | — | — | — | 30,000 | 13,947 | 81,638 | |||||||||||||||||
| 2008 | — | — | — | — | 2,500 | 22,576 | 112,829 | ||||||||||||||||||
| 2007 | — | — | — | — | 24,500 | 22,668 | 79,852 | ||||||||||||||||||
| S.L. Cornelius |
2009 | 823 | — | — | — | 14,250 | 13,947 | 40,760 | |||||||||||||||||
| 2008 | 1,252 | — | — | — | 13,300 | 22,576 | 56,207 | ||||||||||||||||||
| 2007 | — | — | — | — | 10,864 | 22,668 | 38,441 | ||||||||||||||||||
| R.M. Lance |
2009 | — | — | — | — | — | 13,947 | 38,055 | |||||||||||||||||
| 2008 | 367 | — | — | — | 1,000 | 22,576 | 50,510 | ||||||||||||||||||
| 2007 | 733 | — | 3,680 | — | 7,500 | 22,967 | 33,832 | ||||||||||||||||||
| K.O. Meyers |
2009 | 849 | 18,587 | 572,297 | — | 800 | 14,299 | 31,287 | |||||||||||||||||
| 2008 | — | — | 1,466,980 | — | 1,484 | 20,063 | 55,413 | ||||||||||||||||||
| 2007 | — | 24,826 | 935,161 | — | — | 23,199 | 46,260 | ||||||||||||||||||
| J.L. Gallogly |
2009 | 823 | — | — | — | — | 13,947 | 59,006 | |||||||||||||||||
| 2008 | 9,168 | — | — | — | 21,000 | 22,576 | 115,046 | ||||||||||||||||||
| 2007 | 2,943 | — | — | — | 5,000 | 22,668 | 90,708 |
| (a) | The Comprehensive Security Program of the Company requires that Mr. Mulva fly on Company aircraft, unless a determination is made by the Manager of Global Security that other arrangements are an acceptable risk. Numbers above represent the approximate incremental cost to ConocoPhillips for personal use of the aircraft, including travel for any family member or guest. Approximate incremental cost has been determined by calculating the variable costs for each aircraft during the year, dividing that amount by the total number of miles flown by that aircraft, and multiplying the result by the miles flown for personal use during the year. Included in incremental costs reported are $28 in 2009, $24,202 in 2008, and $20,551 in 2007 associated with flights to the Company hangar or other locations without passengers, commonly referred to as “deadhead” flights. Effective June 22, 2007, the Company and Mr. Mulva entered into an agreement, the Time Share Agreement, with regard to certain of the Company’s aircraft, pursuant to which Mr. Mulva agreed to reimburse the Company for his personal use of the aircraft, subject to certain limitations required by the Federal Aviation Administration. The amounts shown for incremental costs related to the personal use of an aircraft by Mr. Mulva reflect the net incremental costs to the Company after giving effect to any reimbursements received under the Time Share Agreement. |
| (b) | The value shown in the table represents the approximate incremental cost to the Company of providing and maintaining an automobile, excluding Company security personnel. Approximate incremental cost was calculated using actual expenses incurred during the year. Other executives and employees of the Company may also be required to use Company-provided transportation and security personnel, especially when traveling or living outside of the United States, in accordance with risk assessments made by the Company’s Manager of Global Security. |
| (c) | The use of a home security system is required as part of ConocoPhillips’ Comprehensive Security Program for certain executives and employees, including the Named Executive Officers noted above, based on risk assessments made by the Company’s Manager of Global Security. Amounts shown represent the approximate incremental cost to ConocoPhillips for the installation and maintenance of the home security system with features required by the Company in excess of the cost of a “standard” system typical for homes in the neighborhoods where the Named Executive Officers’ homes are located. The Named Executive Officer pays the cost of the “standard” system himself. |
| (d) | Historically, the Company had an Executive Financial Planning Program under which financial and tax planning expenses incurred by eligible executives were reimbursed by the Company up to $20,000 for the CEO and up to $10,000 for other Named Executive Officers. This personal benefit was discontinued effective at the end of 2008. |
| (e) | Historically, the Company had provided a nominal amount for membership in a social club to certain executives for use in conducting Company business. The amount shown here is for annual dues since it is possible for the executive to use the club for personal use. No other amounts for personal use were reimbursed or paid by the Company, although the Company did pay or reimburse any amounts for business use of the club, such as entertaining customers. This personal benefit was discontinued for executives located in the United States effective at the end of 2007. The amounts shown for Mr. Meyers relate to club memberships held while serving in Canada. |
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| (f) | The Company maintains a program under which costs associated with annual physical examinations of eligible employees, including the Named Executive Officers, are paid for by the Company. |
| (g) | The amounts shown are for premiums paid by the Company for executive group life insurance provided by the Company, with a value equal to the employee’s annual salary. In addition, certain employees of the Company, including the Named Executive Officers, are eligible to purchase group variable universal life insurance policies for which the employee pays all costs, so that there is no incremental cost to the Company. |
| (h) | The amounts shown are for payments by the Company relating to certain taxes incurred by the employee. These primarily occur when the Company requests family members or other guests to accompany the employee to Company functions and, as a result, the employee is deemed to make a personal use of Company assets (for example, when a spouse accompanies an employee on a Company aircraft). The Company believes that such travel is appropriately characterized as a business expense and, if the employee is imputed income in accordance with the applicable tax laws, the Company will generally reimburse the employee for any increased tax costs. |
| (i) | Mr. Meyers relocated from Canada to our Houston offices in connection with his appointment as Senior Vice President, Exploration and Production – Americas in 2009. The Company, in accordance with its standard relocation policies, reimbursed Mr. Meyers for certain of his relocation costs, including payments for increased tax costs related to such relocation costs. |
| (j) | Messrs. Lance and Meyers were previously on assignment in Singapore and Canada, respectively. These amounts reflect net expatriate benefits under our standard policies for such service outside the United States, and these amounts include payments for increased tax costs related to such expatriate assignments and benefits. Not included in the footnote table are values less than $0 that primarily relate to tax amounts returned to the company in the normal course of the expatriate tax protection process that may relate to a prior period. These amounts are returned to the Company when they are known or received through the tax reporting and filing process. The amounts noted for Mr. Lance were $(314,163) in 2009, $(43,857) in 2008 and $0 in 2007. The amounts noted for Mr. Meyers were $(164,564) in 2009, $(33,002) in 2008 and $0 in 2007. |
| (k) | Mr. Mulva is a member of the Board of Directors and as such was entitled to participate in the Director Charitable Gift Program. This program allowed eligible directors to designate charities and tax-exempt educational institutions to receive a donation from the Company of up to $1 million upon his or her death. Directors were vested in the program after one year of service on the Board, and Mr. Mulva was thus eligible. In 2008, as part of its regular review of the compensation of directors, the Committee on Directors’ Affairs decided to discontinue the Director Charitable Gift Program for current directors and future director appointees. With respect to current directors, the Company made payments equal to the net present value of the outstanding awards to charities designated by such directors in 2008. Amounts above reflect the cost to the Company of the 2008 payments, less any costs reported in previous periods with respect to the Director Charitable Gift Program. |
| (l) | The Company maintains a Matching Gift Program under which certain gifts by employees to qualified educational or charitable institutions are matched. For executives, the program matches up to $15,000 with regard to each program year. Administration of the program can cause more than $15,000 to be paid in a single fiscal year of the Company, due to processing claims from more than one program year in that single fiscal year. The amounts shown are for the actual payments by the Company during the year. In December 2009, the Board of Directors approved changes in the Matching Gift Program provisions for employees that brought it into parity with the provisions for executives, effective in 2010. |
| (m) | Under the terms of its tax-qualified defined contribution plans, the Company makes matching contributions and allocations to the accounts of its eligible employees, including the Named Executive Officers. |
| (n) | Under the terms of its nonqualified defined contribution plans, the Company makes contributions to the accounts of its eligible employees, including the Named Executive Officers. See the narrative, table, and notes to the “Nonqualified Deferred Compensation Table” for further information. |
| (8) | In accordance with SEC rules prohibiting issuers from reporting a negative value in the “Change in Pension Value and Non-Qualified Deferred Compensation Earnings ($)” column, Mr. Mulva’s total compensation for 2009 excludes the effect of a $7,885,466 decrease in the net present value of Mr. Mulva’s pension benefits in 2009. Including the effects of this decrease in value, Mr. Mulva’s total compensation in 2009, as reported in the Summary Compensation Table, would have been $6,503,195. |
| (9) | Mr. Gallogly became an employee of ConocoPhillips on April 1, 2006. Prior to joining ConocoPhillips, Mr. Gallogly was President and Chief Executive Officer for Chevron Phillips Chemical Company LLC. ConocoPhillips owns a 50 percent interest in Chevron Phillips Chemical Company LLC. None of the compensation or benefits earned by Mr. Gallogly as an employee of Chevron Phillips Chemical Company LLC is included in the Table. Mr. Gallogly retired from ConocoPhillips effective May 22, 2009. |
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With regard to the retirement of Mr. Gallogly, awards under VCIP and PSP (respectively reflected in the Non-Equity Incentive Plan Compensation ($) and Stock Awards ($) columns above) are usually reduced to reflect service for less than the full time of the relevant performance period, subject to the discretion of the HRCC to set actual payout. For PSP, except in cases of death, disability, or demotion, if the employee has participated for less than a year in a program period, awards related to that program period are forfeited. The amounts shown for VCIP in the Non-Equity Incentive Plan Compensation ($) column above reflect actual amounts paid for the applicable time. The amounts shown for PSP in the Stock Awards column ($) above reflect the gross targets set for awards for 2009, 2008, and 2007. For 2007, relating to the performance period beginning in 2007, amounts shown were paid out in accordance with the decision of the HRCC at its February 2010 meeting, and reflect reductions for service of less than the full time of the performance period. For 2008, relating to the performance period beginning in 2008, the amounts shown reflect the gross target amount prior to any such reductions, although it is expected that the HRCC will reduce the payout to be determined at its February 2011 meeting to account for service for only 16 full months during the three-year performance period. Due to his retirement less than one year after the beginning of the PSP performance period that began in 2009, Mr. Gallogly will no longer participate in such performance period.
For options (2009 option grant of which is reflected in the Option Awards ($) column), except in cases of death or disability, the Stock Option Program provides that if an employee retires prior to a date six months from the grant date, the option award will be forfeited. The 2009 option amounts shown in the Option Awards ($) column for Mr. Gallogly reflect the full amount of the stock options awarded to Mr. Gallogly under the Stock Option Program in 2009, although, due to his retirement less than six months after the grant date and in accordance with the terms of the award, these options were forfeited at the time of his retirement.
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GRANTS OF PLAN-BASED AWARDS TABLE
The Grants of Plan-Based Awards Table is used to show participation by the Named Executive Officers in the incentive compensation arrangements described below.
The columns under the heading Estimated Future Payouts Under Non-Equity Incentive Plan Awards show information regarding the ConocoPhillips Variable Cash Incentive Program (VCIP). The amounts shown in the Table are those applicable to the 2009 program year using a minimum of zero and a maximum of 250 percent of VCIP target for each participant and do not represent actual payouts for that program year. Actual payouts for the 2009 program year were made in February 2010 and are shown in the Summary Compensation Table under the Non-Equity Incentive Plan Compensation column.
The columns under the heading Estimated Future Payouts Under Equity Incentive Plan Awards show information regarding the ConocoPhillips Performance Share Program (PSP). The amounts shown in the Table are those set for 2009 compensation tied to the 2009 through 2011 program period under PSP (PSP VII) and do not represent actual payouts for that program year. Actual payouts of restricted stock or restricted stock units, if any, for PSP VII are not expected to be made until February 2012, after the close of the three-year performance period.
The All Other Option Awards column reflects option awards granted under our Stock Option (and Stock Appreciation Rights) Program (SOP). The option awards shown were granted on the same day that the target was approved. For the 2009 program year under SOP, targets were set and awards granted at the regularly scheduled February 2009 meeting of the HRCC.
| Name | Grant Date(1) |
Estimated Future Payouts Under Non-Equity Incentive Plan Awards(2) |
Estimated Future Payouts Under Equity Incentive Plan Awards(3) |
All Other Stock Awards: Number of Shares of Stock or Units (#) |
All Other Option Awards: Number of Securities Underlying Options (#)(4) |
Exercise or Base Price of Options Awards Average Price ($Sh)(5) |
Exercise or Base Price of Options Awards Closing Price ($Sh)(6) |
Grant Date Fair Value of Stock and Options Awards(7) |
||||||||||||||||||||||||||
| Threshold ($) |
Target ($) |
Maximum ($) |
Threshold (#) |
Target (#) |
Maximum (#) |
|||||||||||||||||||||||||||||
| J.J. Mulva |
$ — | $2,025,000 | $5,062,500 | — | — | — | — | — | $ — | $ — | $ — | |||||||||||||||||||||||
| 2/12/2009 | — | — | — | — | 124,687 | 249,374 | — | — | — | — | 5,669,518 | |||||||||||||||||||||||
| 2/12/2009 | — | — | — | — | — | — | — | 513,200 | 45.47 | 46.20 | 5,737,576 | |||||||||||||||||||||||
| J.A. Carrig |
— | 1,259,500 | 3,148,750 | — | — | — | — | — | — | — | — | |||||||||||||||||||||||
| 2/12/2009 | — | — | — | — | 77,137 | 154,274 | — | — | — | — | 3,507,419 | |||||||||||||||||||||||
| 2/12/2009 | — | — | — | — | — | — | — | 317,500 | 45.47 | 46.20 | 3,549,650 | |||||||||||||||||||||||
| S.L. Cornelius |
— | 571,047 | 1,427,618 | — | — | — | — | — | — | — | — | |||||||||||||||||||||||
| 2/12/2009 | — | — | — | — | 23,206 | 46,412 | — | — | — | — | 1,055,177 | |||||||||||||||||||||||
| 2/12/2009 | — | — | — | — | — | — | — | 95,600 | 45.47 | 46.20 | 1,068,808 | |||||||||||||||||||||||
| R.M. Lance |
— | 539,092 | 1,347,730 | — | — | — | — | — | — | — | — | |||||||||||||||||||||||
| 2/12/2009 | — | — | — | — | 21,905 | 43,810 | — | — | — | — | 996,020 | |||||||||||||||||||||||
| 2/12/2009 | — | — | — | — | — | — | — | 90,200 | 45.47 | 46.20 | 1,008,436 | |||||||||||||||||||||||
| K.O. Meyers |
— | 503,023 | 1,257,558 | — | — | — | — | — | — | — | — | |||||||||||||||||||||||
| 2/12/2009 | — | — | — | — | 17,433 | 34,866 | — | — | — | — | 792,679 | |||||||||||||||||||||||
| 2/12/2009 | — | — | — | — | — | — | — | 71,800 | 45.47 | 46.20 | 802,724 | |||||||||||||||||||||||
| 5/14/2009 | — | — | — | — | 726 | 1,452 | — | — | — | — | 32,380 | |||||||||||||||||||||||
| 5/14/2009 | — | — | — | — | 1,461 | 2,922 | — | — | — | — | 65,161 | |||||||||||||||||||||||
| 5/14/2009 | — | — | — | — | 3,409 | 6,818 | — | — | — | — | 152,041 | |||||||||||||||||||||||
| J.L. Gallogly(8) |
— | 390,678 | 976,695 | — | — | — | — | — | — | — | — | |||||||||||||||||||||||
| 2/12/2009 | — | — | — | — | 45,883 | 91,766 | — | — | — | — | 2,086,300 | |||||||||||||||||||||||
| 2/12/2009 | — | — | — | — | — | — | — | 188,900 | 45.47 | 46.20 | 2,111,902 | |||||||||||||||||||||||
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| (1) | The grant date shown is the date on which the HRCC approved the target, except with regard to the May 14, 2009 awards shown for Mr. Meyers. Under the terms of the Performance Share Program, an adjustment in the target and maximum awards under three ongoing performance periods automatically occurred on the effective date of his promotion, which promotion was effective May 14, 2009, and was approved by the HRCC. |
| (2) | Threshold and maximum are based on the program provisions under VCIP. Actual awards earned can range from zero to 200 percent of the target awards for corporate and business unit performance, with a further possible adjustment of up to 50 percent of the target awards for individual performance. Amounts reflect estimated possible cash payouts under the Company’s VCIP after the close of the performance period. The estimated amounts are calculated based on the applicable annual target and base salary for each Named Executive Officer in effect for the 2009 performance period. If threshold levels of performance are not met, then the payout can be zero. The HRCC also retains the authority to make awards under the program at its discretion, including the discretion to make awards greater than the maximum payout. Actual payouts under the VCIP for 2009 are based on actual base salaries earned in 2009 and are reflected in the Non-Equity Incentive Plan Compensation ($) column of the Summary Compensation Table. |
| (3) | Threshold and maximum are based on the program provisions under PSP. Actual awards earned can range from zero to 200 percent of the target awards. The HRCC retains the authority to make awards under the program at its discretion, including the discretion to make awards greater than the maximum payout. Mr. Meyers was promoted effective May 14, 2009, resulting, under the terms of the Performance Share Program, in an adjustment in the target and maximum awards under three ongoing performance periods. This adjustment is shown as separate awards on that date. |
| (4) | These amounts represent stock options granted during 2009. |
| (5) | The exercise price is the average of the high and low prices of ConocoPhillips common stock, as reported on the NYSE, on the date of the grant (or on the last preceding date for which there was a reported sale, in the absence of any reported sales on the grant date); therefore, on the grant date, the option has no immediately realizable value and any potential payout reflects an increase in share price after the grant date. The Company’s stockholder-approved 2009 Omnibus Stock and Performance Incentive Plan provides for the use of such an average price in setting the exercise price on options, unless the HRCC directs otherwise. The immediate predecessor plan, the stockholder-approved 2004 Omnibus Stock and Performance Incentive Plan, had the same provision. Grants made before May 13, 2009, were made under the 2004 Plan. |
| (6) | The closing price is the closing price of ConocoPhillips common stock, as reported on the NYSE, on the date of the grant. |
| (7) | For equity incentive plan awards, these amounts represent the grant date fair value at target level under PSP as determined pursuant to FASB ASC Topic 718. For option awards, these amounts represent the grant date fair value of the option awards using a Black-Scholes-Merton-based methodology to value the options. Actual value realized upon option exercise depends on market prices at the time of exercise. For other stock awards, these amounts represent the grant date fair value of the restricted stock or restricted stock unit awards determined pursuant to FASB ACR Topic 718. See the “Share-Based Compensation Plans” section of Note 19 in the Notes to Consolidated Financial Statements in the Company’s 2009 Annual Report on Form 10-K, for a discussion of the relevant assumptions used in this determination. Under the terms of the Performance Share Program, Mr. Meyers received incremental targeted awards on the three ongoing performance periods due to a change in salary grade. |
| (8) | With regard to the retirement of Mr. Gallogly, awards under VCIP and PSP (the target award levels of which are reflected in the Estimated Future Payouts Under Non-Equity Incentive Plan Awards and Estimated Future Payouts Under Equity Incentive Plan Awards columns) are usually reduced to reflect service for less than the full time of the relevant performance period, subject to the discretion of the HRCC to set actual payout. For VCIP, the amount reflects estimated possible cash payouts under the Company’s VCIP after the close of the performance period. The estimated amounts are calculated based on the applicable annual target and base salary for each Named Executive Officer in effect for the 2009 performance period. For PSP, except in cases of death, disability, or demotion, if the employee has participated for less than a year in a program period, awards related to that program period are forfeited. The PSP amounts shown above reflect the gross amount prior to any such reductions. The actual payout for VCIP for Mr. Gallogly for the 2009 program year is shown in the Summary Compensation Table. Due to his retirement less than one year after the beginning of the performance period, Mr. Gallogly forfeited the target awards for PSP for the 2009 through 2011 performance period shown in the Table above, and his target for that award was reduced to zero, as discussed in the applicable footnote to the Summary Compensation Table. Not related to the PSP targets for the 2009 through 2011 performance period shown in the Table above, Mr. Gallogly’s targets for PSP relating to the performance periods beginning in 2007 and 2008 were reduced to reflect service of less than the full time of the respective performance periods. |
For options (2009 option grant of which is reflected in the All Other Option Awards: Number of Securities Underlying Options (#) column), except in cases of death or disability, if the employee retires prior to a date six months from the grant date, the option award will be forfeited. The option amounts shown above reflect the gross amount prior to any such reductions. Due to his retirement less than six months after the grant date, Mr. Gallogly forfeited his 2009 stock option award, and his payout for that award was reduced to zero, as discussed in the applicable footnote to the Summary Compensation Table.
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OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END
| Option Awards(1) | Stock Awards(6) | ||||||||||||||||||||||||||
| Name | Number of Securities Underlying Unexercised Options (#) Exercisable (2) |
Number of Securities Underlying Unexercised Options (#) Unexercisable |
Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options (#) |
Option Exercise Price ($) |
Option Expiration Date |
Number of Shares or Units of Stock that have Not Vested (#) |
Market Value of Shares or Units of Stock that have Not Vested ($) |
Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights that have Not Vested (#) |
Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights that have Not Vested ($) |
||||||||||||||||||
| J.J. Mulva |
335,600 | — | — | $31.140 | 10/9/2010 | — | $ — | — | $ — | ||||||||||||||||||
| 478,000 | — | — | 27.385 | 10/8/2011 | — | — | — | — | |||||||||||||||||||
| 1,500,000 | — | — | 25.655 | 11/17/2011 | — | — | — | — | |||||||||||||||||||
| 1,500,000 | — | — | 32.065 | 11/17/2011 | — | — | — | — | |||||||||||||||||||
| 12,738 | — | — | 23.550 | 10/22/2012 | — | — | — | — | |||||||||||||||||||
| 413,062 | — | — | 23.550 | 10/22/2012 | — | — | — | — | |||||||||||||||||||
| 606,000 | — | — | 24.370 | 2/10/2013 | — | — | — | — | |||||||||||||||||||
| 745,200 | — | — | 32.810 | 2/8/2014 | — | — | — | — | |||||||||||||||||||
| 392,800 | — | — | 47.830 | 2/4/2015 | — | — | — | — | |||||||||||||||||||
| 268,800 | — | — | 59.075 | 2/10/2016 | — | — | — | — | |||||||||||||||||||
| 184,333 | 92,167 | (3) | — | 66.370 | 2/8/2017 | — | — | — | — | ||||||||||||||||||
| 98,800 | 197,600 | (4) | — | 79.380 | 2/14/2018 | — | — | — | — | ||||||||||||||||||
| — | 513,200 | (5) | — | 45.470 | 2/12/2019 | — | — | — | — | ||||||||||||||||||
| 2,835,558 | 144,811,947 | 193,403 | 9,877,091 | ||||||||||||||||||||||||
| J.A. Carrig |
10,200 | — | — | 27.385 | 10/8/2011 | — | — | — | — | ||||||||||||||||||
| 49,662 | — | — | 23.550 | 10/22/2012 | — | — | — | — | |||||||||||||||||||
| 122,200 | — | — | 24.370 | 2/10/2013 | — | — | — | — | |||||||||||||||||||
| 126,200 | — | — | 32.810 | 2/8/2014 | — | — | — | — | |||||||||||||||||||
| 104,600 | — | — | 47.830 | 2/4/2015 | — | — | — | — | |||||||||||||||||||
| 78,500 | — | — | 59.075 | 2/10/2016 | — | — | — | — | |||||||||||||||||||
| 53,866 | 26,934 | (3) | — | 66.370 | 2/8/2017 | — | — | — | — | ||||||||||||||||||
| 30,100 | 60,200 | (4) | — | 79.380 | 2/14/2018 | — | — | — | — | ||||||||||||||||||
| — | 317,500 | (5) | — | 45.470 | 2/12/2019 | — | — | — | — | ||||||||||||||||||
| 445,725 | 22,763,176 | 114,251 | 5,834,799 | ||||||||||||||||||||||||
| S.L. Cornelius |
45,000 | — | — | 32.810 | 2/8/2014 | — | — | — | — | ||||||||||||||||||
| 47,600 | — | — | 47.830 | 2/4/2015 | — | — | — | — | |||||||||||||||||||
| 32,500 | — | — | 59.075 | 2/10/2016 | — | — | — | — | |||||||||||||||||||
| 23,866 | 11,934 | (3) | — | 66.370 | 2/8/2017 | — | — | — | — | ||||||||||||||||||
| 14,766 | 29,534 | (4) | — | 79.380 | 2/14/2018 | — | — | — | — | ||||||||||||||||||
| — | 95,600 | (5) | — | 45.470 | 2/12/2019 | — | — | — | — | ||||||||||||||||||
| 120,989 | 6,178,908 | 33,467 | 1,709,160 | ||||||||||||||||||||||||
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OUTSTANDING EQUITY AWARDS AT FISCAL YEAR END
(Continued)
| Option Awards(1) | Stock Awards(6) | ||||||||||||||||||||||||||
| Name | Number of Securities Underlying Unexercised Options (#) Exercisable (2) |
Number of Securities Underlying Unexercised Options (#) Unexercisable |
Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options (#) |
Option Exercise Price ($) |
Option Expiration Date |
Number of Shares or Units of Stock that have Not Vested (#) |
Market have Not |
Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights that have Not Vested (#) |
Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights that have Not Vested ($) |
||||||||||||||||||
| R.M. Lance |
1,600 | — | — | $ 32.160 | 9/11/2010 | — | $ — | — | $ — | ||||||||||||||||||
| 3,560 | — | — | 31.140 | 10/9/2010 | — | — | — | — | |||||||||||||||||||
| 623 | — | — | 27.770 | 12/1/2011 | — | — | — | — | |||||||||||||||||||
| 10,786 | — | — | 23.550 | 10/22/2012 | — | — | — | — | |||||||||||||||||||
| 24,400 | — | — | 32.810 | 2/8/2014 | — | — | — | — | |||||||||||||||||||
| 33,400 | — | — | 47.830 | 2/4/2015 | — | — | — | — | |||||||||||||||||||
| 22,700 | — | — | 59.075 | 2/10/2016 | — | — | — | — | |||||||||||||||||||
| 23,266 | 11,634 | (3) | — | 66.370 | 2/8/2017 | — | — | — | — | ||||||||||||||||||
| 14,766 | 29,534 | (4) | — | 79.380 | 2/14/2018 | — | — | — | — | ||||||||||||||||||
| — | 90,200 | (5) | — | 45.470 | 2/12/2019 | — | — | — | — | ||||||||||||||||||
| 102,597 | 5,239,629 | 32,166 | 1,642,718 | ||||||||||||||||||||||||
| K.O. Meyers |
38,574 | — | — | 31.140 | 10/9/2010 | — | — | — | — | ||||||||||||||||||
| 20 | — | — | 31.140 | 10/9/2010 | — | — | — | — | |||||||||||||||||||
| 1,606 | — | — | 31.140 | 10/9/2010 | — | — | — | — | |||||||||||||||||||
| 5,400 | — | — | 28.170 | 2/12/2011 | — | — | — | — | |||||||||||||||||||
| 79,800 | — | — | 32.810 | 2/8/2014 | — | — | — | — | |||||||||||||||||||
| 58,600 | — | — | 47.830 | 2/4/2015 | — | — | — | — | |||||||||||||||||||
| 38,600 | — | — | 59.075 | 2/10/2016 | — | — | — | — | |||||||||||||||||||
| 27,333 | 13,667 | (3) | — | 66.370 | 2/8/2017 | — | — | — | — | ||||||||||||||||||
| 13,000 | 26,000 | (4) | — | 79.380 | 2/14/2018 | — | — | — | — | ||||||||||||||||||
| — | 71,800 | (5) | — | 45.470 | 2/12/2019 | — | — | — | — | ||||||||||||||||||
| 151,781 | 7,751,456 | 31,323 | 1,599,666 | ||||||||||||||||||||||||
| J.L. Gallogly(7) |
1,800 | — | — | 31.470 | 9/26/2010 | — | — | — | — | ||||||||||||||||||
| 63,200 | — | — | 64.770 | 4/4/2016 | — | — | — | — | |||||||||||||||||||
| 63,333 | 31,667 | (3) | — | 66.370 | 2/8/2017 | — | — | — | — | ||||||||||||||||||
| 31,000 | 62,000 | (4) | — | 79.380 | 2/14/2018 | — | — | — | — | ||||||||||||||||||
| 12,818 | 654,615 | 9,576 | 489,046 | ||||||||||||||||||||||||
| (1) | All options shown in the table have a maximum term for exercise of ten years from the grant date. Under certain circumstances, the terms for exercise may be shorter, and in certain circumstances, the options may be forfeited and cancelled. All awards shown in the table have associated restrictions upon transferability. |
| (2) | The options shown in this column vested and became exercisable in 2009 or prior years (although under certain termination circumstances, the options may still be forfeited). Following the merger of Conoco and Phillips, options become exercisable in one-third increments on the first, second and third anniversaries of the grant date. |
| (3) | Represents the final one-third vesting of the February 8, 2007 grant, which became exercisable on February 8, 2010. |
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| (4) | Represents the final two-thirds vesting of the February 14, 2008 grant, half of which became exercisable on February 14, 2010, and the other half will become exercisable on February 14, 2011. |
| (5) | Represents the February 12, 2009 grant, one-third of which became exercisable on February 12, 2010, one-third of which will become exercisable on February 12, 2011, and the final third will become exercisable on February 12, 2012. |
| (6) | No stock awards were made to the Named Executive Officers in 2009 except as a long-term incentive award under the Company’s Performance Share Program (shown in the columns labeled “Stock Awards”) or pursuant to elections made by a Named Executive Officer to receive cash compensation in the form of restricted stock units. Amounts above include PSP awards for the three-year performance period ending December 31, 2009 (PSP V), as follows: Mr. Mulva, 48,000 shares; Mr. Carrig, 23,581 shares; Mr. Cornelius, 7,856 shares; Mr. Lance, 7,327 shares; Mr. Meyers, 7,928 shares; and Mr. Gallogly 12,818 shares. Stock awards shown in the columns entitled Number of Shares or Units of Stock that have Not Vested (#) and Market Value of Shares or Units of Stock that have Not Vested ($) continue to have restrictions upon transferability. Under PSP, stock awards are made in the form of restricted stock units or restricted stock, the former having been used in the most recent awards. The terms and conditions of both are substantially the same, requiring restriction on transferability until separation from service from the Company, although for performance periods beginning in 2009, restrictions will lapse five years from the anniversary of the grant date unless the employee has elected prior to the beginning of the performance period to defer the lapsing of such restrictions until separation from service from the Company. Except in cases where the five-year provision applies, forfeiture is expected to occur if the separation is not the result of death, disability, layoff, retirement after the executive has reached the age of 55 with 5 years of service, or after a change of control, although the HRCC has the authority to waive forfeiture. Restricted stock awards have voting rights and pay dividends. Restricted stock unit awards have no voting rights and pay dividend equivalents. Dividend equivalents, if any, on restricted stock units held are paid in cash or credited to each officer’s account in the form of additional stock units. Neither pays dividends or dividend equivalents at preferential rates. Restricted stock held by the Named Executive Officers prior to November 17, 2001, was converted to restricted stock units prior to the completion of the merger, with the original restrictions still in place. In addition to stock awards actually granted, the Table reflects potential stock awards to Named Executive Officers under ongoing performance periods for PSP, for the performance periods from 2008 through 2010 and 2009 through 2011. These are shown at target levels in the columns entitled Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights that have Not Vested (#) and Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights that have Not Vested ($). There is no assurance that these awards will be granted at, below, or above target after the end of the relevant performance periods, as the determination of whether to make an actual grant and the amount of any actual grant for Named Executive Officers is within the discretion of the HRCC. Until an actual grant is made, these target awards have no voting rights and pay no dividends or dividend equivalents. Stock awards shown reflect closing price at the end of 2009 ($51.07 as of December 31, 2009). |
| Amounts presented in Number of Shares or Units of Stock that have Not Vested (#) and Market Value of Shares or Units of Stock that have Not Vested ($) represent restricted stock and restricted stock unit awards granted with respect to prior periods. The plans and programs under which such grants were made provide that awards made in the form of restricted stock and restricted stock units be held in such form until the recipient retires. If such awards immediately vested upon completion of the relevant performance period, as we are informed by our compensation consultant is more typical for restricted stock programs, the amounts reflected in this column would be zero. |
| (7) | Mr. Gallogly retired effective May 22, 2009. With regard to the option awards for Mr. Gallogly reflected in the Option Awards columns, the terms and conditions generally allow them to be exercised for up to ten years from the date of the initial grant. Grants made in 2007 and 2008 became, or will become, exercisable in one-third increments on the anniversary dates of the grants, and Mr. Gallogly’s retirement did not accelerate or terminate that exercisability. With regard to stock awards, target awards under PSP (the target award levels of which are reflected in the columns entitled Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights that have Not Vested (#) and Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights that have Not Vested ($)) are usually reduced to reflect service for less than the full time of the relevant performance period, subject to the discretion of the HRCC to set actual payout. The amounts shown reflect the prorated target amounts. The payout for PSP performance in the 2008 through 2010 performance period shown in the Table above is not expected to be determined by the HRCC until its 2011 meeting at which it makes compensation decisions, which is expected to occur in February of that year. Restrictions on all outstanding stock awards from earlier performance periods (including the 12,818 shares awarded in February 2010 with regard to PSP for the performance period from 2007 through 2009) lapsed due to the retirement of Mr. Gallogly, and payout in unrestricted stock was made 6 months after the date of his retirement. For the Stock Option Program and PSP, except in cases of death, disability, or demotion, if the employee has participated for less than a year in a program period, awards related to that program period are forfeited. The amounts shown above for option awards and target awards under PSP made for the 2009 through 2011 performance period reflect the net amount after such reductions. Due to his retirement, Mr. Gallogly forfeited the option awards for the 2009 program period and the target awards for PSP for the 2009 through 2011 performance period shown in the Table above, and his payout for those awards was reduced to zero, as shown in the applicable footnote to the Summary Compensation Table. |
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OPTION EXERCISES AND STOCK VESTED
| Option Awards | Stock Awards | |||||||||||
| Name | Number of Shares Acquired on Exercise (#) |
Value Realized Upon Exercise ($) |
Number of Shares Acquired on Vesting (#) |
Value Realized Upon Vesting ($) |
||||||||
| J.J. Mulva |
373,600 | $8,280,584 | — | $ — | ||||||||
| J.A. Carrig |
— | — | — | — | ||||||||
| S.L. Cornelius |
— | — | — | — | ||||||||
| R.M. Lance |
— | — | — | — | ||||||||
| K.O. Meyers(1) |
— | — | 3,680 | 178,112 | ||||||||
| J.L. Gallogly(2) |
6,272 | 120,767 | 85,183 | 4,507,033 | ||||||||
| (1) | Mr. Meyers participated in a predecessor program to the Company’s PSP, the Phillips Petroleum Company Long Term Incentive Plan. Under the historical administration of that plan, the HRCC may, after an employee reaches age 55, lapse the restrictions on some or all of the outstanding restricted stock or restricted stock units that an employee has been granted under that plan. Mr. Meyers indicated to the HRCC that he preferred to have restrictions lapse on certain restricted stock units issued for the LTIP VII and VIII performance periods, which such units Mr. Meyers had been vested in under the terms and conditions of the awards due to the merger of Conoco and Phillips in 2002. The amounts shown in the Table represent the value of the stock related to the units for which the restrictions were lapsed by action of the HRCC in 2009. |
| (2) | Mr. Gallogly retired effective May 22, 2009. Under the terms and conditions of the stock awards that were in the form of restricted stock and restricted stock units, restrictions upon transferability lapsed and amounts were delivered 6 months after retirement in unrestricted shares or shares were forfeited and the value credited to the Key Employee Deferred Compensation Plan. Amounts for target awards for performance periods under PSP beginning in 2007 and later are shown in the Outstanding Equity Awards at Fiscal Year-End Table rather than in the Table above, since, as discussed in the applicable footnote to Outstanding Equity Awards at Fiscal Year-End Table, determination of the amount of the payout and delivery, if any, is delayed until after 2009. |
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PENSION BENEFITS
ConocoPhillips maintains several defined benefit plans for its eligible employees. With regard to U.S.-based salaried employees, the defined benefit plan that is qualified under the Internal Revenue Code is the ConocoPhillips Retirement Plan (CPRP).
The CPRP is a non-contributory plan that is funded through a trust. The CPRP consists of eight titles, each one corresponding to a different pension formula and having numerous other differences in terms and conditions. Employees are eligible for current participation in only one title (although an employee may also have a frozen benefit under one or more other titles), and eligibility is based on heritage company and time of hire. Of the Named Executive Officers, Messrs. Mulva, Carrig, Lance, Meyers, and Gallogly (having been employees of Phillips) are eligible for, and vested in, benefits under Title I of the CPRP and Mr. Cornelius (having been an employee of Conoco) is eligible for, and vested in, benefits under Title IV. Titles I and IV each provide a final average earnings type of pension benefit for eligible employees payable at normal or early retirement from the Company. Under each of Titles I and IV, normal retirement occurs upon termination on or after age 65. Under Title I, early retirement can occur at age 55 with five years of service (or if laid off during or after the year in which the participant reaches age 50), while under Title IV, early retirement can occur at age 50 with ten years of service. Under Title I, early retirement benefits are reduced by five percent per year for each year before age 60 that benefits are paid, but for benefits that commence at age 60 through age 65, the benefit is unreduced. Under Title IV, early retirement benefits are reduced by five percent per year for each year before age 57 that benefits are paid and four percent per year that benefits are paid between ages 57 and 60. Messrs. Mulva, Carrig, Meyers, Cornelius, and Gallogly were eligible for early retirement at the end of 2009. Mr. Lance was not eligible for early retirement at the end of 2009. Under Titles I and IV, employees become vested in the benefits after five years of service, and all of the Named Executive Officers are vested in their benefits. Titles I and IV allow the employee to elect the form of benefit payment from among several annuity types or a single sum payment option, but all of the options are actuarially equivalent. The election for form of benefit is made at retirement.
For Title I and Title IV, the benefit formula applicable to our eligible Named Executive Officers is the same. Retirement benefits are calculated as the product of 1.6 percent times years of credited service multiplied by the final annual eligible average compensation. For Title I, final annual eligible average compensation is calculated using the three highest consecutive years in the last ten calendar years before retirement plus the year of retirement. For Title IV, final annual eligible average compensation is calculated using the higher of the highest three years of compensation or the highest consecutive 36 months of compensation. In each case, such benefits are reduced by the product of 1.5 percent of the annual primary Social Security benefit multiplied by years of credited service, although a maximum reduction limit of fifty percent may apply in certain cases. The formula below provides an illustration as to how the retirement benefits are calculated. For purposes of the formula, “pension compensation” denotes the final annual eligible average compensation described above.
| [ | 1.6% | × | Pension Compensation |
× | Years of Credited Service |
] | –
|
[ | 1.5% | × | Annual Primary SS Benefit |
× | Years of Credited Service |
] |
Eligible pension compensation generally includes salary and annual incentive compensation. However, under Title I, in the event that an eligible employee receives layoff benefits from the Company, eligible pension compensation includes the annualized salary for the year of layoff, rather than actual salary, and years of credited service are increased by any period for which layoff benefits are calculated. Furthermore, certain foreign service as an employee of Phillips is counted as time and a quarter when determining the service element in the benefit formula under Title I.
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Eligible pension compensation under Titles I and IV is limited in accordance with the Internal Revenue Code. In 2009, that limit was $245,000. The Internal Revenue Code also limits the annual benefit (expressed as an annuity) available under Titles I and IV. In 2009, that limit was $195,000 (reduced actuarially for ages below 62).
In addition, the Company maintains several nonqualified pension plans. These are funded through the general assets of the Company, although the Company also maintains trusts of the type generally known as “rabbi trusts” that may be used to pay benefits under the nonqualified pension plans. The plan available to the Named Executive Officers is the ConocoPhillips Key Employee Supplemental Retirement Plan (KESRP). This plan is designed to replace benefits that would otherwise not be received due to limitations contained in the Internal Revenue Code that apply to qualified plans. The two such limitations that most frequently impact the benefits to employees are the limit on compensation that can be taken into account in determining benefit accruals and the maximum annual pension benefit. In 2009, the former limit was set at $245,000, while the latter was set at $195,000. The KESRP determines a benefit without regard to such limits, and then reduces that benefit by the amount of benefit payable from the related qualified plan, the CPRP. Thus, in operation the combined benefits payable from the related plans for the eligible employee equals the benefit that would have been paid if there had been no limitations imposed by the Internal Revenue Code. Benefits under KESRP are generally paid in a single sum the later of age 55 or six months after retirement. When payments do not begin until after retirement, interest at then current six-month T-bill rates will, under most circumstances, be credited on the delayed benefits. Distribution may also be made upon a determination of death or disability.
Certain foreign service as an employee of Phillips is counted as time and a quarter when determining the service element in the benefit formula under KESRP. Also under KESRP, certain incentive payments approved by the Phillips Board of Directors in 2000 are considered as pension compensation. Otherwise, the benefit formulas under KESRP take into account only actual service with the employer and compensation arising from salary and annual incentive compensation (including annual incentive compensation that is performance-based and is included in the Summary Compensation Table as Non-Equity Incentive Plan Compensation for that reason). The footnotes below provide further detail on extra credited service and compensation.
Messrs. Lance and Meyers were employees of ARCO Alaska, which was acquired by Phillips in 2000. As such, a special provision applies in the calculation of their pension benefits under Title I. First, we calculate a benefit under the Title I formula using service with both ARCO and ConocoPhillips, subtracting from the result the value of the benefit under the ARCO plan through the time of the acquisition (for which the BP Retirement Accumulation Plan remains liable, after the acquisition of ARCO by BP and certain plan mergers). Next, we calculate a benefit under the Title I formula using only service with ConocoPhillips. We compare the results of the two methods and the employee receives the larger benefit. For Messrs. Lance and Meyers, that calculation currently provides a larger benefit under the first method. The Table reflects that benefit, showing only the value payable from the plan of ConocoPhillips, not from the BP Retirement Accumulation Plan.
Except where otherwise noted, assumptions used in calculating the present value of accumulated benefits in the Table are found in Note 19 in the Notes to Consolidated Financial Statements in the Company’s 2009 Annual Report on Form 10-K.
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| Name | Plan Name | Number of Years Credited Service (#)(1) |
Present Value of Accumulated Benefit ($)(2) |
Payments During Last Fiscal Year ( $) |
|||||||
| J.J. Mulva |
Title I - ConocoPhillips Retirement Plan
|
38 | $ 1,692,474 | $ — | |||||||
| ConocoPhillips Key Employee Supplemental Retirement Plan | 60,508,043 | — | |||||||||
| J.A. Carrig |
Title I - ConocoPhillips Retirement Plan |
33 | 1,333,742 | — | |||||||
| ConocoPhillips Key Employee Supplemental Retirement Plan | 18,617,136 | — | |||||||||
| S.L. Cornelius |
Title IV - ConocoPhillips Retirement Plan
|
29 | 996,933 | — | |||||||
| ConocoPhillips Key Employee Supplemental Retirement Plan | 4,543,261 | — | |||||||||
| R.M. Lance |
Title I - ConocoPhillips Retirement Plan |
26 | 396,862 | — | |||||||
| ConocoPhillips Key Employee Supplemental Retirement Plan | 2,445,562 | — | |||||||||
| K.O. Meyers |
Title I - ConocoPhillips Retirement Plan
|
30 | 573,758 | — | |||||||
| ConocoPhillips Key Employee Supplemental Retirement Plan | 3,056,581 | — | |||||||||
| J.L. Gallogly(3) |
Title I - ConocoPhillips Retirement Plan |
25 | — | 1,239,255 | |||||||
| ConocoPhillips Key Employee Supplemental Retirement Plan | — | 7,658,274 | |||||||||
| (1) | Includes additional credited service for Messrs. Mulva, Carrig, and Gallogly of 18.25, 7.5, and 8.75 months, respectively, related to foreign assignments. Please see note (2) for credited amounts related to such service. |
| (2) | In determining the present value of the accumulated benefit for each Named Executive Officer, the eligible pension compensation used to calculate the amounts above as of December 31, 2009, for each Named Executive Officer is: Mr. Mulva, $23,308,579; Mr. Carrig, $9,556,020; Mr. Cornelius, $3,521,433; Mr. Lance, $3,401,709; and Mr. Meyers, $3,701,310. In determining the present value of the accumulated benefit for Messrs. Mulva and Carrig, this takes into account as an element of pension compensation the value of an off-cycle award of restricted stock and of an off-cycle performance incentive award both approved by the Phillips Compensation Committee in 2000, but with regard to which the performance conditions were met in 2005. The value of the two off-cycle awards included as part of pension compensation for 2005 was $6,278,301 for Mr. Mulva and $3,139,151 for Mr. Carrig. With regard to the additional credited service for foreign service as noted above, the following amounts were included in the accumulated benefit shown in the pension table above: Mr. Mulva, $2,468,969 and Mr. Carrig, $384,274. |
| (3) | Mr. Gallogly retired effective May 22, 2009. Mr. Gallogly had previously left the Company and later rejoined ConocoPhillips in April 2006 after serving as Chief Executive Officer of Chevron Phillips Chemical Company LLC, a 50% owned joint venture of ConocoPhillips. As a result, under terms of the Key Employee Supplemental Retirement Plan, that prior termination was treated as a separation from service under Section 409A of the Internal Revenue Code. Accordingly, Mr. Gallogly received a lump-sum distribution of his nonqualified pension benefit under KESRP with regard to the earlier period of service upon his attainment of age 55 with five years of service. That amount is not reflected in the Table above. The Table above reflects, as to KESRP, only the benefit earned between rejoining ConocoPhillips in 2006 and his 2009 retirement. As to Title I, the Table above reflects the benefit earned for all periods of service with ConocoPhillips. |
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NONQUALIFIED DEFERRED COMPENSATION
ConocoPhillips maintains several nonqualified deferred compensation plans for its eligible employees. Those available to the Named Executive Officers are briefly described below.
The Key Employee Deferred Compensation Plan of ConocoPhillips (KEDCP) is a nonqualified deferral plan that permits certain key employees to voluntarily reduce salary and request deferral of VCIP, or other similar annual incentive compensation program payments that would otherwise be received in the subsequent year. KEDCP permits eligible employees to defer compensation of up to 100 percent of VCIP and up to 50 percent of salary. All of the Named Executive Officers are eligible to participate in KEDCP.
Under KEDCP, for amounts deferred and vested after December 31, 2004, the default distribution option in KEDCP is to receive a lump sum to be paid at least six months after separation from service. Participants may elect to defer payments from one to five years after separation, and to receive annual, semiannual or quarterly payments for a period of up to 15 years. For elections that set a date certain for payment, the distribution will begin in the calendar quarter following the date requested and will be paid out on the distribution schedule elected by the participant.
For amounts deferred prior to January 1, 2005, a one-time revision of the 10 annual installment payments schedule is allowed from 365 days to no later than 90 days prior to retirement at age 55 or above or within 30 days after being notified of layoff in the calendar year in which the employee is age 50 or above. Participants may receive distributions in one to 15 annual installments, two to 30 semi-annual installments or four to 60 quarterly installments.
The Defined Contribution Make-Up Plan of ConocoPhillips (DCMP) is a nonqualified restoration plan under which the Company makes employer contributions and stock allocations that cannot be made in the qualified ConocoPhillips Savings Plan (CPSP) — a defined contribution plan of the type often referred to as a 401(k) plan — due to certain voluntary reductions of salary under KEDCP or due to limitations imposed by the Internal Revenue Code. For 2009, the Internal Revenue Code limited the amount of compensation that could be taken into account in determining a benefit under the CPSP to $245,000. Employees make no contributions to DCMP.
Under DCMP, amounts vested after December 31, 2004, will be distributed as a lump sum six months after separation from service, or, at a participant’s election, in one to 15 annual payments, no earlier than one year after separation from service. For amounts vested prior to January 1, 2005, participants may, from 365 days to no later than 90 days prior to termination or within 30 days of being notified of layoff, indicate a preference to defer the value into their account under the KEDCP.
Each participant directs investments of the individual accounts set up for that participant under both KEDCP and DCMP. Participants may make changes in the investments as often as daily. All ConocoPhillips defined contribution nonqualified deferred compensation plans allow investment of deferred amounts in a broad range of mutual funds or other market-based investments, including ConocoPhillips stock. As market-based investments none of these provide above-market return. Since each executive participating in each plan chooses the investment vehicle or vehicles and may change his or her allocations from time to time (as often as daily), the return on the investment will depend on how well the underlying investment fund performed during the time the executive chose it as an investment vehicle. The aggregate performance of such investment is reflected in the Nonqualified Deferred Compensation Table under the column “Aggregate Earnings in Last Fiscal Year.”
Benefits due under each of the plans discussed above are paid from the general assets of the Company, although the Company also maintains trusts of the type generally known as “rabbi trusts” that may be used to pay benefits under the plans. The trusts and the funds held in them are assets of ConocoPhillips. In the event of bankruptcy, participants would be unsecured general creditors.
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| Name | Applicable Plan(1) | Beginning Balance |
Executive Contributions in Last FY ($)(2) |
Registrant Contributions in Last FY ($)(3) |
Aggregate Earnings in Last FY ($)(4) |
Aggregate Withdrawals/ Distributions ($) |
Aggregate Balance at Last FYE ($)(5) |
|||||||||||||
| J.J. Mulva |
Defined Contribution Make-Up Plan of ConocoPhillips |
$ 2,630,462 | $ — | $119,818 | $ 87,827 | $ — | $ 2,838,107 | |||||||||||||
| Key Employee Deferred Compensation Plan of ConocoPhillips |
25,685,108 | — | — | 7,977,781 | — | 33,662,889 | ||||||||||||||
| J.A. Carrig |
Defined Contribution Make-Up Plan of ConocoPhillips |
542,157 | — | 81,638 | 28,330 | — | 652,125 | |||||||||||||
| Key Employee Deferred Compensation Plan of ConocoPhillips |
6,491,639 | 325,489 | — | 1,590,750 | — | 8,407,878 | ||||||||||||||
| S.L. Cornelius |
Defined Contribution Make-Up Plan of ConocoPhillips |
149,328 | — | 40,760 | 45,960 | — | 236,048 | |||||||||||||
| Key Employee Deferred Compensation Plan of ConocoPhillips |
34,407 | — | — | 9,157 | — | 43,564 | ||||||||||||||
| R.M. Lance |
Defined Contribution Make-Up Plan of ConocoPhillips |
153,919 | — | 38,055 | 6,696 | — | 198,670 | |||||||||||||
| Key Employee Deferred Compensation Plan of ConocoPhillips |
1,223,737 | 116,911 | — | 153,254 | — | 1,493,902 | ||||||||||||||
| K.O. Meyers |
Defined Contribution Make-Up Plan of ConocoPhillips |
332,777 | — | 31,287 | 16,439 | — | 380,503 | |||||||||||||
| Key Employee Deferred Compensation Plan of ConocoPhillips |
4,669,632 | 338,139 | — | 1,032,294 | — | 6,040,065 | ||||||||||||||
| J.L. Gallogly |
Defined Contribution Make-Up Plan of ConocoPhillips |
392,375 | — | 59,006 | (17,058 | ) | (221,672 | ) | 212,651 | |||||||||||
| Key Employee Deferred Compensation Plan of ConocoPhillips |
2,195,974 | — | — | 11,678 | — | 2,207,652 | ||||||||||||||
| (1) | Our primary defined contribution deferred compensation programs for executives (KEDCP and DCMP) make a variety of investments available to participants. As of December 31, 2009, there were a total of 96 investment options, of which 39 were the same as those available in the Company’s primary tax-qualified defined contribution plan for employees (its 401(k) plan, the ConocoPhillips Savings Plan) and 57 of which were other various mutual fund options approved by an administrator designated by the relevant plan. |
| (2) | For Mr. Carrig, this reflects $114,500 in salary deferred in 2009 (included in the “Salary” column of the Summary Compensation Table for 2009), and $210,989 in VCIP deferral in 2009 (included in the “Non-Equity Incentive Plan Compensation” column of the Summary Compensation Table for 2008). For Mr. Lance, this reflects $116,911 in salary deferred in 2009 (included in the “Salary” column of the Summary Compensation Table for 2009). For Mr. Meyers, this reflects $184,595 in salary deferred in 2009 (included in the “Salary” column of the Summary Compensation Table for 2009) and $153,544 in VCIP deferral in 2009 (included in the “Non-Equity Incentive Plan Compensation” column of the Summary Compensation Table for 2008). |
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| (3) | Reflects contributions by the Company under the DCMP in 2009 (included in the “All Other Compensation” column of the Summary Compensation Table for 2009). |
| (4) | None of these earnings is included in the Summary Compensation Table for 2009. |
| (5) | Reflects contributions by our Named Executive Officers, contributions by the Company, and earnings on balances prior to 2009; plus contributions by our Named Executive Officers, contributions by the Company, and earnings for 2009 (shown in the appropriate columns of this table, with amounts that are included in the Summary Compensation Table for 2009 shown in Footnotes (2), (3) and (4) above). |
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Executive Severance and Changes in Control
Each of our Named Executive Officers serves without an employment agreement. Salary and other compensation for these officers is set by the HRCC, as described in the “Compensation Discussion and Analysis” beginning on page 43 of this proxy statement. These officers may participate in the employee benefit plans and programs of the Company for which they are eligible, in accordance with their terms. The amounts earned by the Named Executive Officers for 2009 appear in the various Executive Compensation Tables beginning on page 58 of this proxy statement.
Each of our Named Executive Officers is expected to receive amounts earned during his term of employment unless he voluntarily resigns prior to becoming retirement-eligible or is terminated for cause. Such amounts include:
| • | VCIP earned during the fiscal year; |
| • | grants pursuant to the PSP for the most-recently completed performance period and ongoing performance periods in which the executive participated for at least one year; |
| • | previously granted restricted stock and restricted stock units; |
| • | vested stock option grants under the Stock Option Program; |
| • | amounts contributed and vested under our defined contribution plans; and |
| • | amounts accrued and vested under our pension plans. |
While normal retirement age under our benefit plans is 65, early retirement provisions allow benefits at earlier ages if vesting requirements are met, as discussed in the sections of this proxy statement entitled “Pension Benefits” and “Nonqualified Deferred Compensation.” For our compensation programs (VCIP, SOP, and PSP), early retirement is generally defined to be termination at or after the age of 55 with five years of service.
Messrs. Mulva, Carrig, Cornelius, and Meyers have each met the early retirement criteria under both our benefit plans and our compensation programs. Mr. Lance has not met the early retirement criteria under either the applicable title of the pension plan or of our compensation programs. Therefore, as of December 31, 2009, any voluntary resignations of Messrs. Mulva, Carrig, Cornelius, and Meyers would have been treated as retirements. Since Messrs. Mulva, Carrig, Cornelius, and Meyers are eligible for early retirement under these programs, they would be able to resign and retain all awards earned under the PSP and earlier programs. As a result, the awards to Messrs. Mulva, Carrig, Cornelius, and Meyers under such programs are not included in the incremental amounts reflected in the tables below. Mr. Lance has not yet met either the criteria under our benefit plans or our compensation programs as of December 31, 2009. Mr. Gallogly actually retired on May 22, 2009, and therefore we show payments made or expected to be made to him under “Quantification of Severance Payments” below. Please see “Outstanding Equity Awards at Fiscal Year-End” beginning on page 67 for more information.
In addition, specific severance arrangements for executive officers, including the Named Executive Officers, are provided under two severance plans of ConocoPhillips: one being the ConocoPhillips Executive Severance Plan, available to a limited number of senior executives; and the other being the ConocoPhillips Key Employee Change in Control Severance Plan, also available to a limited number of senior executives, but only upon a change in control. These arrangements are described below. Executives are not entitled to participate in both plans as a result of a single event, that is, executives
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receiving benefits under the ConocoPhillips Key Employee Change in Control Severance Plan would not be entitled to benefits potentially payable under the ConocoPhillips Executive Severance Plan relating to the event giving rise to benefits under the ConocoPhillips Key Employee Change in Control Severance Plan. Mr. Gallogly’s voluntary retirement on May 22, 2009, did not entitle him to any payment pursuant to these plans.
ConocoPhillips Executive Severance Plan
The ConocoPhillips Executive Severance Plan (CPESP) covers executives in salary grades generally corresponding to vice president and higher. The CPESP provides that if the Company terminates the employment of a participant in the plan other than for cause, as defined in the plan, upon executing a general release of liability and, if requested by the Company, an agreement not to compete with the Company, the participant will be entitled to:
| • | A lump-sum cash payment equal to one-and-a-half or two times the sum of the employee’s base salary and current target VCIP; |
| • | A lump-sum cash payment equal to the present value of the increase in retirement benefits that would result from the crediting of an additional one-and-a-half or two years to the employee’s number of years of age and service under the applicable retirement plan; |
| • | A lump-sum cash payment equal to the Company cost of certain welfare benefits for an additional one-and-a-half or two years; |
| • | Continuation in eligibility for a pro rata portion of the annual VCIP for which the employee is eligible in the year of termination; and |
| • | Treatment as a layoff under the various compensation and equity programs of the Company – generally, layoff treatment will allow executives to retain awards previously made and continue their eligibility under ongoing Company programs, thus, actual program grants as restricted stock or restricted stock units would vest and the executive would remain eligible for awards attributable to ongoing performance periods under the PSP in which they had participated for at least one year. |
The CPESP may be amended or terminated by the Company at any time. Amounts payable under the plan will be offset by any payments or benefits that are payable to the severed employee under any other plan, policy, or program of ConocoPhillips relating to severance, and amounts may also be reduced in the event of willful and bad faith conduct demonstrably injurious to the Company, monetarily or otherwise.
ConocoPhillips Key Employee Change in Control Severance Plan
The ConocoPhillips Key Employee Change in Control Severance Plan (CICSP) covers executives in salary grades generally corresponding to vice president and higher. The CICSP provides that if the employment of a participant in the plan is terminated by the Company within two years of a “change in control” of ConocoPhillips, other than for cause, or by the participant for good reason, as such terms are defined in the plan, upon executing a general release of liability, the participant will be entitled to:
| • | A lump-sum cash payment equal to two or three times the sum of the employee’s base salary and the higher of current target VCIP or previous two years’ average VCIP; |
| • | A lump-sum cash payment equal to the present value of the increase in retirement benefits that would result from the crediting of an additional two or three years to the employee’s number of years of age and service under the applicable retirement plan; |
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| • | A lump-sum cash payment equal to the Company cost of certain welfare benefits for an additional two or three years; |
| • | Continuation in eligibility for a pro rata portion of the annual VCIP for which the employee is eligible in the year of termination; and |
| • | If necessary, a gross-up payment sufficient to compensate the participant for the amount of any excise tax imposed on payments made under the plan or otherwise pursuant to section 4999 of the Internal Revenue Code and for any taxes imposed on this additional payment, although if the applicable payments are not more than 110 percent of the “safe harbor” amount under section 280G of the Internal Revenue Code, the payments are “cut back” to the safe harbor amount rather than a gross-up payment being made. |
Upon a change in control, the participant becomes eligible for vesting in all equity awards and lapsing of any restrictions, with continued ability to exercise stock options for their remaining terms. After a change in control, the CICSP may not be amended or terminated if such amendment would be adverse to the interests of any eligible employee, without the employee’s written consent. Amounts payable under the plan will be offset by any payments or benefits that are payable to the severed employee under any other plan, policy, or program of ConocoPhillips relating to severance, and amounts may also be reduced in the event of willful and bad faith conduct demonstrably injurious to the Company, monetarily or otherwise.
Quantification of Severance Payments
The tables below reflect the amount of incremental compensation payable in excess of the items listed above to each of our Named Executive Officers in the event of termination of such executive’s employment other than as a result of voluntary resignation. The amount of compensation payable to each Named Executive Officer upon involuntary not-for-cause termination, for-cause termination, termination following a change-in-control (CIC) (either involuntarily without cause or for good reason) and in the event of the death or disability of the executive is shown below. The amounts shown assume that such termination was effective as of December 31, 2009, and thus include amounts earned through such time and are estimates of the amounts which would be paid out to the executives upon their termination. The actual amounts to be paid out can only be determined at the time of such executive’s separation from the Company.
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The following tables reflect additional incremental amounts to which each of our Named Executive Officers, other than Mr. Gallogly, would be entitled if their employment were terminated due to the events described above. Mr. Gallogly retired from the Company on May 22, 2009. Mr. Gallogly met the criteria for early retirement under both our benefit plans and our compensation programs, but was not eligible for severance payments under our Executive Severance Plan.
| Executive Benefits and Payments Upon Termination |
Involuntary Not-for-Cause Termination (Not CIC) |
For-Cause Termination |
Involuntary or Good Reason Termination (CIC) |
Death | Disability | ||||||
| J.J. Mulva† |
|||||||||||
| Base Salary |
$3,000,000 | $ — | $4,500,000 | $ — | $ — | ||||||
| Short-term Incentive |
4,050,000 | — | 7,290,000 | — | — | ||||||
| Variable Cash Incentive Program |
— | (2,025,000 | ) | — | — | — | |||||
| 2007—2009 (performance period) |
— | — | — | — | — | ||||||
| 2008—2010 (performance period) |
— | (2,339,551 | ) | — | — | — | |||||
| 2009—2011 (performance period) |
— | (2,122,588 | ) | — | — | — | |||||
| Restricted Stock/Units from prior performance |
— | (1,930,446 | ) | — | — | — | |||||
| Stock Options/SARs: |
|||||||||||
| Unvested and Accelerated |
— | (2,873,920 | ) | — | — | — | |||||
| Incremental Pension |
3,106,003 | — | 4,659,005 | — | — | ||||||
| Post-employment Health & Welfare |
43,271 | — | 67,741 | — | — | ||||||
| Life Insurance |
— | — | — | 3,000,000 | — | ||||||
| 280G Tax Gross-up |
— | — | — | — | — | ||||||
| 10,199,274 | (11,291,505 | ) | 16,516,746 | 3,000,000 | — | ||||||
| Executive Benefits and Payments Upon Termination |
Involuntary Not-for-Cause Termination (Not CIC) |
For-Cause Termination |
Involuntary or Good Reason Termination (CIC) |
Death | Disability | ||||||
| J.A. Carrig† |
|||||||||||
| Base Salary |
$2,290,000 | $ — | $3,435,000 | $ — | $ — | ||||||
| Short-term Incentive |
2,519,000 | — | 3,778,500 | — | — | ||||||
| Variable Cash Incentive Program |
— | (1,259,500 | ) | — | — | — | |||||
| 2007—2009 (performance period) |
— | — | — | — | — | ||||||
| 2008—2010 (performance period) |
— | (1,263,608 | ) | — | — | — | |||||
| 2009—2011 (performance period) |
— | (1,313,129 | ) | — | — | — | |||||
| Restricted Stock/Units from prior performance |
— | (2,064,790 | ) | — | — | — | |||||
| Stock Options/SARs: |
|||||||||||
| Unvested and Accelerated |
— | (1,778,000 | ) | — | — | — | |||||
| Incremental Pension |
3,877,952 | — | 4,588,224 | — | — | ||||||
| Post-employment Health & Welfare |
22,307 | — | 35,969 | — | — | ||||||
| Life Insurance |
— | — | — | 2,290,000 | — | ||||||
| 280G Tax Gross-up |
— | — | 3,940,066 | — | — | ||||||
| 8,709,259 | (7,679,027 | ) | 15,777,759 | 2,290,000 | — | ||||||
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| Executive Benefits and Payments Upon Termination |
Involuntary Not-for-Cause Termination (Not CIC) |
For-Cause Termination |
Involuntary or Good Reason Termination (CIC) |
Death | Disability | ||||||
| S.L. Cornelius† |
|||||||||||
| Base Salary |
$1,396,032 | $ — | $2,094,048 | $ — | $ — | ||||||
| Short-term Incentive |
1,158,706 | — | 1,738,059 | — | — | ||||||
| Variable Cash Incentive Program |
— | (579,353 | ) | — | — | — | |||||
| 2007—2009 (performance period) |
— | — | — | — | — | ||||||
| 2008—2010 (performance period) |
— | (349,353 | ) | — | — | — | |||||
| 2009—2011 (performance period) |
— | (395,043 | ) | — | — | — | |||||
| Restricted Stock/Units from prior performance |
— | — | — | — | — | ||||||
| Stock Options/SARs: |
|||||||||||
| Unvested and Accelerated |
— | (535,360 | ) | — | — | — | |||||
| Incremental Pension |
1,318,961 | — | 1,935,547 | — | — | ||||||
| Post-employment Health & Welfare |
16,458 | — | 26,792 | — | — | ||||||
| Life Insurance |
— | — | — | 1,396,032 | — | ||||||
| 280G Tax Gross-up |
— | — | — | — | — | ||||||
| 3,890,157 | (1,859,109 | ) | 5,794,446 | 1,396,032 | — | ||||||
| Executive Benefits and Payments Upon Termination |
Involuntary Not-for-Cause Termination (Not CIC) |
For-Cause Termination |
Involuntary or Good Reason Termination (CIC) |
Death | Disability | |||||
| R.M. Lance† |
||||||||||
| Base Salary |
$1,318,032 | $ — | $1,977,048 | $ — | $ — | |||||
| Short-term Incentive |
1,093,966 | — | 1,640,949 | — | — | |||||
| Variable Cash Incentive Program |
546,983 | — | 546,983 | 546,983 | 546,983 | |||||
| 2007—2009 (performance period) |
374,190 | — | 374,190 | 374,190 | 374,190 | |||||
| 2008—2010 (performance period) |
349,353 | — | 349,353 | 349,353 | 349,353 | |||||
| 2009—2011 (performance period) |
372,896 | — | 372,896 | 372,896 | 372,896 | |||||
| Restricted Stock/Units from prior performance |
4,567,497 | — | 4,567,497 | 4,567,497 | 4,567,497 | |||||
| Stock Options/SARs: |
||||||||||
| Unvested and Accelerated |
463,027 | — | 505,120 | 505,120 | 505,120 | |||||
| Incremental Pension |
210,673 | — | 316,010 | — | — | |||||
| Post-employment Health & Welfare |
15,296 | — | 29,138 | — | — | |||||
| Life Insurance |
— | — | — | 1,318,032 | — | |||||
| 280G Tax Gross-up |
— | — | 3,307,140 | — | — | |||||
| 9,311,913 | — | 13,986,324 | 8,034,071 | 6,716,039 | ||||||
| Executive Benefits and Payments Upon Termination |
Involuntary Not-for-Cause Termination (Not CIC) |
For-Cause Termination |
Involuntary or Good Reason Termination (CIC) |
Death | Disability | ||||||
| K.O. Meyers† |
|||||||||||
| Base Salary |
$1,288,032 | $ — | $1,932,048 | $ — | $ — | ||||||
| Short-term Incentive |
1,069,066 | — | 1,760,871 | — | — | ||||||
| Variable Cash Incentive Program |
— | (534,533 | ) | — | — | — | |||||
| 2007—2009 (performance period) |
— | — | — | — | — | ||||||
| 2008—2010 (performance period) |
— | (356,843 | ) | — | — | — | |||||
| 2009—2011 (performance period) |
— | (354,800 | ) | — | — | — | |||||
| Restricted Stock/Units from prior performance |
— | — | — | — | — | ||||||
| Stock Options/SARs: |
|||||||||||
| Unvested and Accelerated |
— | (402,080 | ) | — | — | — | |||||
| Incremental Pension |
1,031,616 | — | 1,589,602 | — | — | ||||||
| Post-employment Health & Welfare |
14,193 | — | 23,566 | — | — | ||||||
| Life Insurance |
— | — | — | 1,288,032 | — | ||||||
| 280G Tax Gross-up |
— | — | — | — | — | ||||||
| 3,402,907 | (1,648,256 | ) | 5,306,087 | 1,288,032 | — | ||||||
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†Notes Applicable to All Termination Tables—In preparing each of the tables above, certain assumptions have been made. Benefits that would be available generally to all or substantially all salaried employees on the U.S. payroll are not included in the amounts shown. The following additional assumptions were also made:
| • | Short-Term Incentives—For the short-term incentive amounts, in the event of an involuntary not-for-cause termination not related to a change in control (“regular involuntary termination”), the amount reflects two times current VCIP target, while in the event of an involuntary or good reason termination related to a change in control (“CIC termination”), the amount reflects three times current VCIP target or three times the average of the prior two VCIP payouts. |
| • | Variable Cash Incentive Program—For the VCIP amounts, in the event of an involuntary not-for-cause termination not related to a change in control (“regular involuntary termination”) or an involuntary or good reason termination related to a change in control (“CIC termination”), the amount reflects the employee’s pro rata current VCIP target. Targets for VCIP are for a full year, and are pro-rata for the Named Executive Officers based on time spent in their respective positions. |
| • | Long-Term Incentives—For the performance periods related to PSP, amounts for the 2007-2009 period are shown at the payout amount that was awarded in February 2010, while amounts for other periods are prorated to reflect the portion of the performance period completed by the end of 2009. For the PSP awards, for restricted stock and restricted stock units, amounts reflect the closing price of ConocoPhillips common stock at the end of 2009 ($51.07 on December 31, 2009). |
| • | Stock Options—For stock options with a December 31, 2009 ConocoPhillips common stock price higher than the option exercise price, the amounts reflect the intrinsic value as if the options had been exercised on December 31, 2009, but only regarding the options that the executive would have retained for the specific termination event. For options with a December 31, 2009 ConocoPhillips common stock price lower than the option exercise price, the amounts reflect a zero intrinsic value regarding the options that the executive would have retained for the specific termination event. |
| • | Incremental Pension Values—For the incremental pension value, the amounts reflect the single sum value of the increment due to an additional two years of age and service with associated pension compensation in the event of regular involuntary termination (three years in the event of a CIC termination) regardless of whether the value is provided directly through a defined benefit plan or through the relevant severance plan. |
| • | 280G Tax Gross-up—Each Named Executive Officer is entitled, under the relevant change in control plan, to an associated “excise tax gross-up” to the extent any change in control payment triggers the golden parachute excise tax provisions under Section 4999 of the Internal Revenue Code (within certain limitations). The following material assumptions were used to estimate executive excise taxes and associated tax gross-ups: |
| • | Equity and PSP awards were valued at the closing price of the Company’s stock on December 31, 2009 of $51.07; |
| • | Options are assumed exchanged and valued using a Black-Scholes-Merton-based option methodology; |
| • | Parachute payments for time vesting stock options, restricted stock and restricted stock units were valued using Treas. Reg. Section 1.280G-1 Q&A 24(b) or (c) as applicable; and |
| • | Calculations assume certain performance-based pay such as PSP awards and pro-rata VCIP payments are reasonable compensation for services rendered prior to the CIC. |
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Non-Employee Director Compensation
The primary elements of our non-employee director compensation program consist of an equity compensation program and a cash compensation program.
Objectives and Principles
Compensation for directors is reviewed annually by the Committee on Directors’ Affairs with the assistance of such third-party consultants as the Committee deems advisable, and set by action of the Board of Directors. The Board’s goal in designing director’s compensation is to provide a competitive package that will enable it to attract and retain highly skilled individuals with relevant experience and that reflects the time and talent required to serve on the board of a complex, multinational corporation. The Board seeks to provide sufficient flexibility in the form of delivery to meet the needs of different individuals while ensuring that a substantial portion of directors’ compensation is linked to the long-term success of ConocoPhillips. In furtherance of ConocoPhillips’ commitment to be a socially responsible member of the communities in which it participates, the Board believes that it is appropriate to extend ConocoPhillips’ matching gift program to charitable contributions made by individual directors as more fully described below.
Equity Compensation
Non-employee directors receive an annual grant of restricted stock units with an aggregate value of $120,000 on the date of grant. Restrictions on the units issued to non-employee directors will lapse in the event of retirement, disability, death, or upon a change of control, unless the director has elected to receive the shares after a stated period of time. Directors forfeit the units if, prior to the lapse of restrictions, the Board finds sufficient cause for forfeiture (although no such finding can be made after a change of control). Before the restrictions lapse, directors cannot sell or otherwise transfer the units, but the units are credited with dividend equivalents in the form of additional restricted stock units. When restrictions lapse, directors will receive unrestricted shares of Company stock as settlement of the restricted stock units.
ConocoPhillips grants issued prior to 2005 had restrictions that lapsed after three years from the date of grant or in the earlier event of retirement, disability, death, or upon a change of control. Settlement for grants before 2005 could be delayed at the election of the director and settled in either cash or stock, also at the election of the director. For grants that remained unvested at the beginning of 2005, directors were allowed to make an election prior to March 15, 2005, to set the time of settlement and whether settlement was to be in a lump sum or over a period of years. Restricted stock units granted to directors who are not from the United States may have modified terms to comply with laws and tax rules that apply to them. Thus, the restricted stock units granted to Messrs. Auchinleck and Norvik lapse only in the event of retirement, death, or loss of office.
Cash Compensation
All non-employee directors receive $100,000 annual cash compensation. Non-employee directors serving in specified committee positions also receive the following additional cash compensation:
| ¡ | Director presiding over meetings of the non-employee directors—$25,000 |
| ¡ | Chair of the Audit and Finance Committee—$20,000 |
| ¡ | Chair of the Human Resources and Compensation Committee—$15,000 |
| ¡ | Chair of the other committees—$10,000 |
| ¡ | All other Audit and Finance Committee members—$7,500 |
The total annual compensation is payable in monthly cash installments. Directors may elect, on an annual basis, to receive all or part of their cash compensation in unrestricted stock or in restricted stock units (such unrestricted stock or restricted stock units are issued on the last business day of the month valued using the average of the high and the low market prices of our common stock on such date), or
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to have the amount credited to the director’s deferred compensation account. The restricted stock units issued in lieu of cash compensation are subject to the same restrictions as the annual restricted stock units granted since 2005 and described above under “Equity Compensation.” Due to differences in the tax laws of other countries, the Board, at its July 1, 2003 meeting approved modification of the compensation for directors who are taxed under the laws of other countries. Effective in 2004, Canadian directors (then and currently, Mr. Auchinleck) were able to elect to receive cash compensation either in cash or in restricted stock units, redeemable only upon retirement, death, or loss of office. Effective in 2007, Norwegian directors (currently Mr. Norvik) receive compensation that would otherwise have been received as cash only as restricted stock units.
Deferral of Compensation
Directors can elect to defer their cash compensation into the Deferred Compensation Program for Non-Employee Directors of ConocoPhillips (Director Deferral Plan). Deferred amounts are deemed to be invested in various mutual funds and similar investment choices (including ConocoPhillips common stock) selected by the director from a list of investment choices available under the Director Deferral Plan. Mr. Auchinleck (from Canada) and Mr. Norvik (from Norway) do not have the opportunity to defer cash compensation in this manner.
Compensation deferred prior to January 1, 2003, by former directors of Conoco and Phillips continues to be deferred and is deemed to be invested in various mutual funds as selected by the director. The deferred amounts may be paid as a lump sum or as installment payments following retirement from the Board.
The future payment of any compensation deferred by non-employee directors of ConocoPhillips after January 1, 2003, and by former directors of Phillips prior to January 1, 2003, may be funded in a grantor trust designed for this purpose. The future payment of any cash compensation deferred by former directors of Conoco prior to January 1, 2003, is not funded.
Directors’ Matching Gift Program
All active and retired directors are eligible to participate in the Directors’ Annual Matching Gift Program. This provides a dollar-for-dollar match of a gift of cash or securities, up to a maximum of $15,000 per donor for active directors and $7,500 per donor for retired directors during any one calendar year, to charities and educational institutions, excluding religious, political, fraternal, or athletic organizations, that are tax-exempt under Section 501(c)(3) of the Internal Revenue Code of the United States or meet similar requirements under the applicable law of other countries. In December 2009, the Public Policy Committee of the Board of Directors approved changes in the Matching Gift Program provisions for employees that brought those provisions into parity with the provisions for executives and directors, effective in 2010.
Other Compensation
The Board believes that it is important for spouses/significant others of directors and executive officers to attend certain meetings to enhance the collegiality of the Board. The cost of such attendance is treated by the Internal Revenue Service as income, and as such is taxable to the recipient. The Board believes that such costs are expenses of creating a collegial environment that enhances the effectiveness of the Board and so it reimburses directors for the cost of resulting income taxes. Amounts are contained in the “All Other Compensation” column representing this reimbursement.
Stock Ownership
Directors are expected to own as much stock as the amounts of the annual equity grants during their first five years on the Board. Directors are expected to reach this level of target ownership within five years of joining the Board. Actual shares of stock, restricted stock, or restricted stock units, including deferred stock units, may be counted in satisfying the stock ownership guidelines. The holdings of each of our directors meet or exceed the guidelines.
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NON-EMPLOYEE DIRECTOR COMPENSATION TABLE
The following table and accompanying narrative disclosures provide information concerning total compensation paid to the non-employee directors of ConocoPhillips in 2009 (for compensation paid to our sole employee director, Mr. Mulva, please see our Executive Compensation Tables beginning on page 58).
| Name | Fees Earned or Paid in Cash ($)(1) |
Stock Awards ($)(2)(3) |
Option Awards ($) |
Non-Equity Incentive Plan Compensation ($) |
Change in Pension ($) |
All Other Compensation ($)(4) |
Total ($) |
||||||||||||||
| R.L. Armitage |
$100,000 | $120,015 | $ — | $ — | $ — | $ — | $220,015 | ||||||||||||||
| R.H. Auchinleck |
135,222 | 120,015 | — | — | — | — | 255,237 | ||||||||||||||
| J.E. Copeland, Jr. |
120,000 | 120,015 | — | — | — | 10,993 | 251,008 | ||||||||||||||
| K.M. Duberstein |
100,000 | 120,015 | — | — | — | 30,000 | 250,015 | ||||||||||||||
| R.R. Harkin |
110,000 | 120,015 | — | — | — | 12,000 | 242,015 | ||||||||||||||
| H.W. McGraw III |
100,193 | 120,015 | — | — | — | 436 | 220,644 | ||||||||||||||
| H.J. Norvik |
107,805 | 120,015 | — | — | — | — | 227,820 | ||||||||||||||
| W.K. Reilly |
100,000 | 120,015 | — | — | — | 26,500 | 246,515 | ||||||||||||||
| B.S. Shackouls |
100,000 | 120,015 | — | — | — | 16,580 | 236,595 | ||||||||||||||
| V.J. Tschinkel |
107,500 | 120,015 | — | — | — | 12,561 | 240,076 | ||||||||||||||
| K.C. Turner |
100,000 | 120,015 | — | — | — | 10,000 | 230,015 | ||||||||||||||
| W.E. Wade, Jr. |
115,261 | 120,015 | — | — | — | 23,500 | 258,776 |
| (1) | Reflects annual cash compensation of $100,000 payable to each non-employee director. Non-employee directors serving in specified committee positions also receive the following additional cash compensation: |
| • | Director presiding over meetings of non-employee directors—$25,000 |
| • | Chair of the Audit and Finance Committee—$20,000 |
| • | Chair of the Human Resources and Compensation Committee—$15,000 |
| • | Chair of the other committees—$10,000 |
| • | All other Audit and Finance Committee members—$7,500 |
Compensation amounts reflect adjustments related to various changes in Committee assignments by Board members throughout the year. Amounts shown include prorated amounts attributable to Committee reassignments which may occur during the year. Amounts shown in the Fees Earned or Paid in Cash column include any amounts that were voluntarily deferred to the Director Deferral Plan, received in ConocoPhillips common stock, or received in restricted stock units.
| (2) | Grant date fair value of stock awards. Under our Non-Employee Director compensation program, non-employee directors receive an annual grant of restricted stock units with an aggregate value of $120,000 on the date of grant based on the average of the high and low price for our common stock on such date. These grants are made in whole shares with fractional share amounts rounded up, resulting in shares with a value of $120,015 being granted on January 15, 2009 to all persons who were directors on that date. |
| (3) | The following table reflects, for each director, the aggregate number of stock awards outstanding as of December 31, 2009. Although ConocoPhillips compensation programs for non-employee directors have not historically included stock options, certain directors below acquired options as directors of predecessor companies which converted to options to purchase ConocoPhillips stock. |
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| Option Awards | Stock Awards | |||||||||||||||||
| Name | Number of Securities Underlying Unexercised Options (#) Exercisable |
Number of Securities Underlying Unexercised Options (#) Unexercisable |
Equity Incentive Unearned Options (#) |
Option Exercise Price ($) |
Option Expiration Date |
Number of Shares or Units of Stock that have Not Vested (#) |
||||||||||||
| R.L. Armitage |
— | — | — | $ — | — | 6,644 | ||||||||||||
| R.H. Auchinleck |
— | — | — | — | — | 46,421 | ||||||||||||
| J.E. Copeland, Jr. |
— | — | — | — | — | 21,486 | ||||||||||||
| K.M. Duberstein |
4,014 | — | — | 29.9337 | 6/1/2010 | — | ||||||||||||
| — | — | — | — | — | 40,228 | |||||||||||||
| R.R. Harkin |
4,014 | — | — | 29.9337 | 6/1/2010 | — | ||||||||||||
| — | — | — | — | — | 25,455 | |||||||||||||
| H.W. McGraw III |
— | — | — | — | — | 15,852 | ||||||||||||
| H.J. Norvik |
— | — | — | — | — | 14,015 | ||||||||||||
| W.K. Reilly |
— | — | — | — | — | 40,409 | ||||||||||||
| B.S. Shackouls |
— | — | — | — | — | 6,644 | ||||||||||||
| V.J. Tschinkel |
— | — | — | — | — | 48,603 | ||||||||||||
| K.C. Turner |
— | — | — | — | — | 43,139 | ||||||||||||
| W.E. Wade, Jr. |
— | — | — | — | — | 10,120 | ||||||||||||
The following table lists option exercises by directors and vesting of director stock awards in 2009.
| Option Awards | Stock Awards | |||||||||||
| Name | Number of Shares (#) |
Value Realized Upon Exercise ($) |
Number of Shares Acquired on Vesting (#) |
Value Realized Upon Vesting ($) |
||||||||
| R.L. Armitage |
— | $ — | — | $ — | ||||||||
| R.H. Auchinleck |
— | — | — | — | ||||||||
| J.E. Copeland, Jr. |
— | — | — | — | ||||||||
| K.M. Duberstein |
— | — | — | — | ||||||||
| R.R. Harkin (a) |
4,116 | 69,464 | — | — | ||||||||
| H.W. McGraw III |
— | — | — | — | ||||||||
| H.J. Norvik |
— | — | — | — | ||||||||
| W.K. Reilly |
— | — | — | — | ||||||||
| B.S. Shackouls |
— | — | — | — | ||||||||
| V.J. Tschinkel (b) |
— | — | 4,304 | 202,809 | ||||||||
| K.C. Turner |
— | — | — | — | ||||||||
| W.E. Wade, Jr. (c) |
37,505 | 684,637 | — | — | ||||||||
| (a) | During her service as Director of Conoco Inc. from 1998 – 2002, Ms. Harkin received a non-qualified stock option grant of 4,116 options on June 1, 1999 at grant price $29.0785, and the options were set to expire on June 1, 2009. Ms. Harkin exercised the full award on May 8, 2009 using a stock swap method, which allows the option holder to use shares that the holder already owns to buy new shares at the exercise price. Although taxes are not collected by the Company on behalf of the non-employee director at the time of exercise, the value of the options exercised are reported on a Form 1099 for the year in which the taxable event occurs. The number of shares shown in the table reflects the gross number of options exercised by Ms. Harkin. 2,604 shares were swapped to cover the option cost and fees, and Ms. Harkin actually received 1,512 shares of company stock as a result of this transaction. |
| (b) | Ms. Tschinkel received restricted stock unit awards for her service as Director of ConocoPhillips in 2005 totaling 2,170 units. As permitted by the terms and conditions of the awards, Ms. Tschinkel elected to receive unrestricted shares in a |
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| lump sum four years after grant date. The total unrestricted shares acquired on vesting of these awards were 2,170 shares, valued at $100,085. Ms. Tschinkel received restricted stock unit awards for her service as Director of ConocoPhillips in 2006 totaling 2,134 units. As permitted by the terms and conditions of the awards, Ms. Tschinkel elected to receive unrestricted shares in a lump sum three years after grant date. The total unrestricted shares acquired on vesting of these awards were 2,133 shares, valued at $102,724. Although taxes are not collected by the Company on behalf of the non-employee director, the value of lapsed shares are reported on a Form 1099 for the year in which the taxable event occurs. |
| (c) | During his service as Director of Burlington Resources Inc. from 2001 – 2006, Mr. Wade received five non-qualified stock option grants: (1) 14,425 options on July 12, 2001 at grant price $13.237, and the options were set to expire on March 31, 2009; (2) 5,770 options on April 17, 2002 at grant price $14.4415, and the options were set to expire on March 31, 2009; (3) 5,770 options on April 23, 2003 at grant price $16.6528, and the options were set to expire on March 31, 2009; (4) 5,770 options on April 21, 2004 at grant price $22.864, and the options were set to expire on March 31, 2009; (5) 5,770 options on April 27, 2005 at grant price $34.3454, and the options were set to expire on March 31, 2009. Mr. Wade exercised all five awards on March 18, 2009 using a cashless hold method, which allows the option holder to receive the net number of shares after withholding for payment of the option cost and fees. Although taxes are not collected by the Company on behalf of the non-employee director at the time of exercise, the value of the options exercised are reported on a Form 1099 for the year in which the taxable event occurs. The number of shares shown in the table reflects the gross number of options exercised by Mr. Wade. In total, 18,983 shares were sold on the market to cover the option cost and fees, and Mr. Wade actually received 18,522 shares of company stock as a result of this transaction. |
| (4) | Includes the amounts attributable to the following: |
| Name | Tax Reimbursement Gross-Up(a) |
Matching Gift Amounts(b) |
Total(c) | ||||||
| R.L. Armitage |
$ — | $ — | $ — | ||||||
| R.H. Auchinleck |
— | — | — | ||||||
| J.E. Copeland, Jr. |
993 | 10,000 | 10,993 | ||||||
| K.M. Duberstein |
— | 30,000 | 30,000 | ||||||
| R.R. Harkin |
— | 12,000 | 12,000 | ||||||
| H.W. McGraw III |
436 | — | 436 | ||||||
| H.J. Norvik |
— | — | — | ||||||
| W.K. Reilly |
— | 26,500 | 26,500 | ||||||
| B. S. Shackouls |
1,580 | 15,000 | 16,580 | ||||||
| V.J. Tschinkel |
— | 12,561 | 12,561 | ||||||
| K.C. Turner |
— | 10,000 | 10,000 | ||||||
| W.E. Wade, Jr. |
— | 23,500 | 23,500 |
| (a) | The amounts shown are for payments by the Company relating to certain taxes incurred by the director. These primarily occur when the Company requests spouses or other guests to accompany the director to Company functions, including Board and Committee meetings, and as a result, the director is deemed to make a personal use of Company assets (for example, when a spouse accompanies a director on a Company aircraft). In such circumstances, if the director is imputed income in accordance with the applicable tax laws, the Company will generally reimburse the director for the increased tax costs. |
| (b) | The Company maintains a Matching Gift Program under which we match certain gifts by directors to charities and educational institutions, excluding religious, political, fraternal, or athletic organizations, that are tax-exempt under Section 501(c)(3) of the Internal Revenue Code of the United States or meet similar requirements under the applicable law of other countries. For directors, the program matches up to $15,000 with regard to each program year. Administration of the program can cause more than $15,000 to be paid in a single fiscal year of the Company, due to processing claims from more than one program year in that single fiscal year. The amounts shown are for the actual payments by the Company in 2009. Mr. Mulva is eligible for the Program as an executive of the Company, rather than as a director. Information on the value of matching gifts for Mr. Mulva is shown on the Summary Compensation Table on page 58 and the notes to that table. In December 2009, the Public Policy Committee of the Board of Directors approved changes in the Matching Gift Program provisions for employees that brought those provisions into parity with the provisions for executives and directors, effective in 2010. |
| (c) | In 2008 the Company discontinued its Director Charitable Gift Program. This program allowed an eligible director to designate charities and tax-exempt educational institutions to receive a donation from the Company of up to $1 million upon his or her death. With respect to then current directors, the Company made payments equal to the net present |
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| value of the outstanding awards to charities designated by such directors in 2008, with the exception of Mr. Shackouls, who, as a result of his participation in the Burlington Resources charitable gift program, rather than the ConocoPhillips program, will continue to have the donation paid upon his death. The Company does not expect to have any further costs associated with the program for Mr. Shackouls until payment of a benefit at his death. Mr. Mulva was also eligible for the Director Charitable Gift Program. Information for Mr. Mulva is shown on the Summary Compensation Table on page 58 and the notes to that table. Eligible directors who retired prior to 2008 were given the opportunity to request that the Company pay the net present value to their designated charities in 2008 or continue with the prior terms of the program. ConocoPhillips also maintains similar programs with regard to directors of companies that it has acquired. Although eligibility, time of payment, and other provisions may differ under these programs, each has the same general purpose of allowing directors to designate charities and tax-exempt educational institutions to receive a donation from the Company of up to $1 million upon the director’s death. During 2008 and 2009, living directors who had retired prior to 2008 were asked whether they preferred their charities to receive the actuarial present value as calculated by the Company or to wait until after the death of the director, per the terms of the applicable program. In response, 22 retired directors have requested the current payment, and the Company has made such payments in the total amount of $7,153,237, while 22 will still continue to wait, and the estimated incremental cost to the Company of continuing the applicable programs during 2009 for these directors is $891,731. During 2009, a donation of $1 million was made for a retired director who died in 2009. |
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Equity Compensation Plan Information
The following table sets forth information about ConocoPhillips’ common stock that may be issued under all existing equity compensation plans as of December 31, 2009:
| Plan category | Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights(2) |
Weighted Average Exercise Price of Outstanding Options, Warrants and Rights |
Number of Securities Remaining Available for Future Issuance | |||
| Equity compensation plans approved by security holders(1) |
21,387,640(3) | $58.20 | 14,293,898(4) | |||
| Equity compensation plans not approved by security holders |
— | — | — | |||
| Total |
21,387,640 | $58.20 | 14,293,898 | |||
| (1) | Includes awards issued from the 2009 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, which was approved by stockholders on May 13, 2009, and from the 2004 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, which was approved by stockholders on May 5, 2004. After approval of the 2009 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, no additional awards may be granted under the 2004 Omnibus Stock and Performance Incentive Plan of ConocoPhillips. |
| (2) | Excludes (a) options to purchase 25,405,493 shares of ConocoPhillips common stock at a weighted average price of $28.10, (b) 1,775,778 restricted stock units, and (c) 20,994 shares underlying stock units, payable in common stock on a one-for-one basis, credited to stock unit accounts under our deferred compensation arrangements. These awards, which were excluded from the above table, were issued from the 1998 Stock and Performance Incentive Plan of ConocoPhillips, the 1998 Key Employee Stock Performance Plan of ConocoPhillips, the 2002 Omnibus Securities Plan of Phillips Petroleum Company, the Omnibus Securities Plan of Phillips Petroleum Company, the Phillips Petroleum Company Stock Plan for Non-Employee Directors, the Incentive Compensation Plan of Phillips Petroleum Company, the 2001 Global Performance Sharing Plans of Conoco Inc., the 1993 Burlington Resources Inc. Stock Incentive Plan, the Burlington Resources Inc. 1997 Employee Stock Incentive Plan, the Burlington Resources Inc. 2002 Stock Incentive Plan, and the Burlington Resources Inc. 2000 Stock Option Plan for Non-Employee Directors. Upon consummation of the merger of Conoco and Phillips, all outstanding options to purchase and restricted stock units payable in common stock of Conoco and Phillips were converted into options to purchase or rights to receive shares of ConocoPhillips common stock. Likewise, upon the acquisition of Burlington Resources, Inc., all outstanding options to purchase and restricted stock units payable in common stock of Burlington Resources, Inc. were converted into options or rights to receive shares of ConocoPhillips common stock. No additional awards may be granted under the aforementioned plans. |
| (3) | Includes an aggregate of 136,835 restricted stock units issued in payment of annual awards and dividend equivalents which were reinvested with regard to existing awards received annually, and 53,609 restricted stock units issued in payment of dividend equivalents with regard to fees that were deferred in the form of stock units under our deferred compensation arrangements for non-employee members of the Board of Directors of ConocoPhillips, or assumed in connection with the merger for services performed as a non-employee member of the Board of Directors for either Conoco Inc. or Phillips Petroleum Company. Also includes 85,910 restricted stock units issued in payment of dividend equivalents reinvested with respect to certain special award made to Mr. Mulva. Dividend equivalents were credited under the 2004 Omnibus Stock and Performance Incentive Plan during the time period from May 5, 2004 to May 12, 2009, and thereafter under the 2009 Omnibus Stock and Performance Incentive Plan. Also includes 55,933 restricted stock units issued in payment of a long-term incentive award for Mr. Mulva and off cycle awards for recently hired executives. In addition, 4,641,542 restricted stock units that are eligible for cash dividend equivalents were issued to U.S. and U.K. payrolled employees residing in the United States or the United Kingdom at the time of the grant; 1,814,756 restricted stock units that are not eligible for cash dividend equivalents due to legal restrictions were issued to non-U.S. or non-U.K. payrolled employees and U.S. or U.K. payrolled employees residing in countries other than the United States or United Kingdom at the time of the grant. Both awards vest over a period of five years, the restrictions lapsing in three equal annual installments beginning on the third anniversary of the grant date. Includes 1,038,131 restricted stock units issued to executives on February 10, 2006, 920,771 restricted stock units issued to executives on February 8, 2007, 939,997 restricted stock units issued to executives on February 14, 2008, and 505,979 restricted stock units issued to executives on February 12, 2009. These restricted stock units have no voting rights, are eligible for cash dividend equivalents, and have restrictions on transferability that last until separation of service from the company. In addition, 245,121 restricted stock units that are not eligible for cash dividend equivalents were issued as retention bonuses; the awards vest over a period of three years, the restrictions lapsing in three equal annual installments |
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| beginning on the first anniversary of the grant dates. Further included are 10,762,643 non-qualified and 186,413 incentive stock options with a term of 10 years and become exercisable in three equal annual installments beginning on the first anniversary of the grant date. |
| (4) | The securities remaining available for issuance may be issued in the form of stock options, stock appreciation rights, stock awards, stock units, and performance shares. Under the 2009 Omnibus Stock and Performance Incentive Plan, no more than 40,000,000 shares of common stock may be issued for incentive stock options (3,372,602 have been issued with 36,627,398 available for future issuance) and no more than 40,000,000 shares of common stock may be issued with respect to stock awards (18,952,341 have been issued with 21,047,659 available for future issuance). Securities remaining available for future issuance take into account outstanding equity awards made under the 2009 Omnibus Stock and Performance Incentive Plan, the 2004 Omnibus Stock and Performance Incentive Plan, and prior plans of predecessor companies as set forth in footnote (2). |
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Stock Ownership
Holdings of Major Stockholders
The following table sets forth information regarding persons whom we know to be the beneficial owners of more than five percent of our issued and outstanding common stock (as of the date of such stockholder’s Schedule 13G filing with the SEC):
| Common Stock | |||||
| Name and Address |
Number of Shares |
Percent of Class |
|||
| Vanguard Fiduciary Trust Company(1) 500 Admiral Nelson Blvd. Malvern, Pennsylvania 19355 |
103,648,238 | 6.99 | % | ||
| BlackRock Inc.(2) 40 East 52nd Street New York, NY 10022 |
97,615,841 | 6.58 | % | ||
| (1) | Based on a Schedule 13G filed with the SEC on February 8, 2010, by Vanguard Fiduciary Trust Company, in its capacity as trustee for ConocoPhillips’ Savings Plan, the Retirement Savings Plan of Phillips Petroleum Company, the Tosco Corporation Capital Accumulation Plan, and the ConocoPhillips Store Savings Plan (collectively, the “Plans”) and ConocoPhillips’ Compensation and Benefits Trust (the “CBT”) with shared voting power. Vanguard and the Plans have disclaimed beneficial ownership of the shares held by Vanguard as trustee of the Plans and the CBT. Vanguard votes shares held by the Plans, which represent the allocated interests of participants, in the manner directed by individual participants. Participants in the Plans are appointed by ConocoPhillips as fiduciaries entitled to direct the trustee as to how to vote allocated shares which are not directed in these Plans and unallocated shares held by the ConocoPhillips Savings Plan. Such shares are allocated pro rata among participants accepting their fiduciary appointment and are voted by the trustee as directed by the participant fiduciaries. The trustee will vote other shares held by the Plans at its discretion only if required to do so by ERISA. Vanguard votes shares held by the CBT only in accordance with the pro rata directions of eligible domestic employees and the trustees of certain international stock plans of ConocoPhillips. |
| (2) | Based on a Schedule 13G filed with the SEC on January 29, 2010, by BlackRock Inc., on behalf of itself, BlackRock Asset Management Japan Limited, BlackRock Advisors (UK) Limited, BlackRock Institutional Trust Company, N.A., BlackRock Fund Advisors, BlackRock Asset Management Canada Limited, BlackRock Asset Management Australia Limited, BlackRock Advisors, LLC, BlackRock Capital Management, Inc., BlackRock Financial Management, Inc., BlackRock Investment Management, LLC, BlackRock Investment Management (Australia) Limited, BlackRock Investment Management (Dublin) Ltd, BlackRock (Luxembourg) S.A., BlackRock (Netherlands) B.V., BlackRock Fund Managers Ltd, BlackRock International Ltd, BlackRock Investment Management UK Ltd, and State Street Research & Management Co. |
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Securities Ownership of Officers and Directors
The following table sets forth the number of shares of our common stock beneficially owned as of March 1, 2010, by each ConocoPhillips director, by each Named Executive Officer and by all of our directors and executive officers as a group. Together these individuals beneficially own less than one percent (1%) of our common stock. The table also includes information about stock options, restricted stock, and restricted and deferred stock units credited to the accounts of our directors and executive officers under various compensation and benefit plans. For purposes of this table, shares are considered to be “beneficially” owned if the person, directly or indirectly, has sole or shared voting or investment power with respect to such shares. In addition, a person is deemed to beneficially own shares if that person has the right to acquire such shares within 60 days of March 1, 2010.
| Number of Shares or Units | ||||||
| Name of Beneficial Owner |
Total Common Stock Beneficially Owned |
Restricted/Deferred Stock Units(1) |
Options Exercisable Within 60 Days(2) | |||
| Richard L. Armitage |
505 | 9,010 | — | |||
| Richard H. Auchinleck |
5,845 | 47,562 | — | |||
| John A. Carrig |
313,194 | 396,107 | 738,195 | |||
| James E. Copeland, Jr. |
21,842 | 24,006 | — | |||
| Sigmund L. Cornelius |
28,752 | 117,394 | 222,299 | |||
| Kenneth M. Duberstein |
13,643 | 35,692 | 4,014 | |||
| James L. Gallogly (3) |
35,568 | 85,183 | 222,000 | |||
| Ruth R. Harkin (4) |
19,139 | 28,015 | 4,014 | |||
| Ryan M. Lance |
16,375 | 94,973 | 191,568 | |||
| Harold W. McGraw III |
1,000 | 13,705 | — | |||
| Kevin O. Meyers |
55,235 | 129,929 | 313,533 | |||
| James J. Mulva (5) |
741,685 | 2,410,910 | 6,897,306 | |||
| Robert A. Niblock |
— | — | — | |||
| Harald J. Norvik |
— | 16,831 | — | |||
| William K. Reilly |
6,767 | 36,356 | — | |||
| Bobby S. Shackouls |
39,298 | 9,010 | — | |||
| Victoria J. Tschinkel (6) |
21,552 | 47,097 | — | |||
| Kathryn C. Turner |
12,616 | 20,994 | — | |||
| William E. Wade, Jr. (7) |
20,764 | 12,623 | — | |||
| Directors and Executive Officers as a Group |
1,395,091 | 3,603,861 | 8,777,800 | |||
| (1) | Includes restricted or deferred stock units that may be voted or sold only upon passage of time. |
| (2) | Includes beneficial ownership of shares of common stock which may be acquired within 60 days of March 1, 2010, through stock options awarded under compensation plans. |
| (3) | Reflects ownership information as of Mr. Gallogly’s retirement date, May 22, 2009. |
| (4) | Includes 46 shares held by Ms. Harkin’s daughter. |
| (5) | Includes 6,564 shares pledged as collateral. |
| (6) | Includes 171 shares of common stock owned by the Erica Tschinkel Trust and 13,067 shares of common stock owned jointly with Ms. Tschinkel’s spouse. |
| (7) | Includes 367 shares of common stock owned by the Wade Family Trust. |
| (8) | Excludes shares owned by Mr. Gallogly, who retired May 2009 and is no longer an executive officer of the Company. |
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Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934 requires ConocoPhillips’ directors and executive officers, and persons who own more than 10% of a registered class of ConocoPhillips’ equity securities, to file reports of ownership and changes in ownership of ConocoPhillips common stock with the SEC and the NYSE, and to furnish ConocoPhillips with copies of the forms they file. To ConocoPhillips’ knowledge, based solely upon a review of the copies of such reports furnished to it and written representations of its officers and directors, during the year ended December 31, 2009, all Section 16(a) reports applicable to its officers and directors were filed on a timely basis except as follows: due to an administrative error, one Form 4 filed on behalf of Ms. Tschinkel omitted reporting one transaction and was subsequently amended to include such transaction.
Submission of Future Stockholder Proposals
Under SEC rules, if a stockholder wants us to include a proposal in our proxy statement and form of proxy for the 2011 Annual Meeting of Stockholders, our Corporate Secretary must receive the proposal at our principal executive offices by December 1, 2010. Any such proposal should comply with the requirements of Rule 14a-8 promulgated under the Exchange Act.
Under our By-Laws, and as SEC rules permit, stockholders must follow certain procedures to nominate a person for election as a director at an annual or special meeting, or to introduce an item of business at an annual meeting. Under these procedures, stockholders must submit the proposed nominee or item of business by delivering a notice to the Corporate Secretary at the following address: Corporate Secretary, ConocoPhillips, 600 North Dairy Ashford, Houston, Texas 77079. We must receive notice as follows:
| • | We must receive notice of a stockholder’s intention to introduce a nomination or proposed item of business for an annual meeting not less than 90 days nor more than 120 days before the first anniversary of the prior year’s meeting. Assuming that our 2010 Annual Meeting is held on schedule, we must receive notice pertaining to the 2011 Annual Meeting no earlier than January 12, 2011 and no later than February 11, 2011. |
| • | However, if we hold the annual meeting on a date that is not within 30 days before or after such anniversary date, and if our first public announcement of the date of such annual meeting is less than 100 days prior to the date of such meeting, we must receive the notice no later than 10 days after the public announcement of such meeting. |
| • | If we hold a special meeting to elect directors, we must receive a stockholder’s notice of intention to introduce a nomination no later than 10 days after the earlier of the date we first provide notice of the meeting to stockholders or announce it publicly. |
As required by Article II of our By-Laws, a notice of a proposed nomination must include information about the stockholder and the nominee, as well as a written consent of the proposed nominee to serve if elected. A notice of a proposed item of business must include a description of and the reasons for bringing the proposed business to the meeting, any material interest of the stockholder in the business and certain other information about the stockholder. You can obtain a copy of ConocoPhillips’ By-Laws by writing the Corporate Secretary at the address below, or via the Internet at www.conocophillips.com under our “Governance” caption.
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SEC rules require us to provide an annual report to stockholders who receive this proxy statement. Additional printed copies of the annual report, as well as our Corporate Governance Guidelines, Code of Business Ethics and Conduct, charters for each of our Board Committees and our Annual Report on Form 10-K for the fiscal year ended December 31, 2009, including the financial statements and the financial statement schedules, are available without charge to stockholders upon written request to ConocoPhillips Shareholder Relations Department, P.O. Box 2197, Houston, Texas 77079-2197 or via the Internet at www.conocophillips.com. We will furnish the exhibits to our Annual Report on Form 10-K upon payment of our copying and mailing expenses.
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CONOCOPHILLIPS
INDEX
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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 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2009.
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:
| • | 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. |
| • | 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. |
| • | Refining and Marketing (R&M)—This segment purchases, refines, markets and transports crude oil and petroleum products, mainly in the United States, Europe and Asia. |
| • | LUKOIL 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. |
| • | 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). |
| • | 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
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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. |
| • | Adding to our proved reserve base. We primarily add to our proved reserve base in three ways: |
| ¡ | Successful exploration and development of new fields. |
| ¡ | Acquisition of existing fields. |
| ¡ | 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
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access to high-potential areas due to environmental or other regulation may negatively impact our ability to increase our reserve base. As such, the timing and level at which we add to our reserve base may, or may not, allow us to replace our production over subsequent years.
| • | Controlling costs and expenses. Since we cannot control the prices of the commodity products we sell, controlling operating and overhead costs, within the context of our commitment to safety and environmental stewardship, 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. |
| • | 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.
| • | 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. |
| • | 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, |
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| 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. |
| • | 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. |
| • | 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.
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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.
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RESULTS OF OPERATIONS
Consolidated Results
A summary of the company’s net income (loss) attributable to ConocoPhillips by business segment follows:
| Millions of Dollars | ||||||||||
| Years Ended December 31 | 2009 | 2008 | 2007 | |||||||
| Exploration and Production (E&P) |
$ | 3,604 | (13,479 | ) | 4,615 | |||||
| Midstream |
313 | 541 | 453 | |||||||
| Refining and Marketing (R&M) |
37 | 2,322 | 5,923 | |||||||
| LUKOIL Investment |
1,663 | (5,488 | ) | 1,818 | ||||||
| Chemicals |
248 | 110 | 359 | |||||||
| Emerging Businesses |
3 | 30 | (8 | ) | ||||||
| Corporate and Other |
(1,010 | ) | (1,034 | ) | (1,269 | ) | ||||
| Net income (loss) attributable to ConocoPhillips |
$ | 4,858 | (16,998 | ) | 11,891 | |||||
2009 vs. 2008
The improved results in 2009 were primarily the result of:
| • | The absence of a $25,443 million before- and after-tax impairment of all E&P segment goodwill in 2008. |
| • | The absence of a $7,410 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. |
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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. |
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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.
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Segment Results
E&P
| 2009 | 2008 | 2007 | |||||||
| Millions of Dollars | |||||||||
| Net Income (Loss) Attributable to ConocoPhillips |
|||||||||
| Alaska |
$ | 1,540 | 2,315 | 2,255 | |||||
| Lower 48 |
(37 | ) | 2,673 | 1,993 | |||||
| United States |
1,503 | 4,988 | 4,248 | ||||||
| International |
2,101 | 6,976 | 367 | ||||||
| Goodwill impairment |
— | (25,443 | ) | — | |||||
| $ | 3,604 | (13,479 | ) | 4,615 | |||||
| Dollars Per Unit | |||||||||
| Average Sales Prices |
|||||||||
| Crude oil and natural gas liquids (per barrel) |
|||||||||
| United States |
$ | 53.21 | 89.38 | 63.87 | |||||
| International |
57.40 | 89.32 | 68.09 | ||||||
| Total consolidated operations |
55.47 | 89.35 | 66.01 | ||||||
| Equity affiliates |
58.23 | 71.15 | 48.72 | ||||||
| Total E&P |
55.63 | 88.91 | 64.99 | ||||||
| Synthetic oil (per barrel) |
|||||||||
| International |
62.01 | 103.31 | 74.32 | ||||||
| Bitumen (per barrel) |
|||||||||
| International |
39.67 | 46.85 | — | ||||||
| Equity affiliates |
45.69 | 58.54 | 37.94 | ||||||
| Total E&P |
44.84 | 56.72 | 37.94 | ||||||
| Natural gas (per thousand cubic feet) |
|||||||||
| United States |
3.45 | 7.67 | 5.98 | ||||||
| International |
4.94 | 8.76 | 6.51 | ||||||
| Total consolidated operations |
4.30 | 8.28 | 6.26 | ||||||
| Equity affiliates |
2.35 | 2.04 | .30 | ||||||
| Total E&P |
4.26 | 8.27 | 6.26 | ||||||
| Average Production Costs Per Barrel of Oil Equivalent |
|||||||||
| United States |
$ | 7.73 | 8.34 | 6.52 | |||||
| International* |
7.72 | 8.03 | 7.64 | ||||||
| Total consolidated operations* |
7.73 | 8.17 | 7.11 | ||||||
| Equity affiliates |
7.68 | 13.36 | 8.92 | ||||||
| Total E&P* |
7.72 | 8.33 | 7.19 | ||||||
| * Amounts in 2008 and 2007 were adjusted for certain production cost reclassifications. | |||||||||
| Millions of Dollars | |||||||||
| Worldwide Exploration Expenses |
|||||||||
| General and administrative; geological and geophysical; and lease rentals |
$ | 576 | 639 | 544 | |||||
| Leasehold impairment |
247 | 273 | 254 | ||||||
| Dry holes |
359 | 425 | 209 | ||||||
| $ | 1,182 | 1,337 | 1,007 | ||||||
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| 2009 | 2008 | 2007 | ||||
| Thousands of Barrels Daily | ||||||
| Operating Statistics |
||||||
| Crude oil and natural gas liquids produced |
||||||
| Alaska |
252 | 261 | 280 | |||
| Lower 48 |
166 | 165 | 181 | |||
| United States |
418 | 426 | 461 | |||
| Canada |
40 | 44 | 46 | |||
| Europe |
241 | 233 | 224 | |||
| Asia Pacific/Middle East |
132 | 107 | 106 | |||
| Africa |
78 | 80 | 78 | |||
| Other areas |
4 | 9 | 10 | |||
| Total consolidated operations |
913 | 899 | 925 | |||
| Equity affiliates |
||||||
| Russia |
55 | 24 | 15 | |||
| Other areas |
— | — | 42 | |||
| 968 | 923 | 982 | ||||
| Synthetic oil produced |
||||||
| Consolidated operations—Canada |
23 | 22 | 23 | |||
| Bitumen produced |
||||||
| Consolidated operations—Canada |
7 | 6 | — | |||
| Equity affiliates—Canada |
43 | 30 | 27 | |||
| 50 | 36 | 27 | ||||
| Millions of Cubic Feet Daily | ||||||
| Natural gas produced* |
||||||
| Alaska |
94 | 97 | 110 | |||
| Lower 48 |
1,927 | 1,994 | 2,182 | |||
| United States |
2,021 | 2,091 | 2,292 | |||
| Canada |
1,062 | 1,054 | 1,106 | |||
| Europe |
876 | 954 | 961 | |||
| Asia Pacific/Middle East |
713 | 609 | 579 | |||
| Africa |
121 | 114 | 125 | |||
| Other areas |
— | 14 | 19 | |||
| Total consolidated operations |
4,793 | 4,836 | 5,082 | |||
| Equity affiliates |
||||||
| Asia Pacific/Middle East |
84 | 11 | — | |||
| Other areas |
— | — | 5 | |||
| 4,877 | 4,847 | 5,087 | ||||
| * | 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.
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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.
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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
| 2009 | 2008 | 2007 | |||||
| Millions of Dollars | |||||||
| Net Income Attributable to ConocoPhillips* |
$ | 313 | 541 | 453 | |||
| * Includes DCP Midstream-related earnings: | $ | 183 | 458 | 336 | |||
| Dollars Per Barrel | |||||||
| Average Sales Prices |
|||||||
| U.S. natural gas liquids* |
|||||||
| Consolidated |
$ | 33.63 | 56.29 | 47.93 | |||
| Equity affiliates |
29.80 | 52.08 | 46.80 | ||||
| * Based on index prices from the Mont Belvieu and Conway market hubs that are weighted by natural gas liquids component and location mix. | |||||||
| Thousands of Barrels Daily | |||||||
| Operating Statistics |
|||||||
| Natural gas liquids extracted* |
187 | 188 | 211 | ||||
| Natural gas liquids fractionated** |
166 | 165 | 173 | ||||
| * Includes our share of equity affiliates, except LUKOIL, which is included in the LUKOIL Investment segment. | |||||||
| ** Excludes DCP Midstream. | |||||||
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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.
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R&M
| 2009 | 2008 | 2007 | ||||||
| Millions of Dollars | ||||||||
| Net Income (Loss) Attributable to ConocoPhillips |
||||||||
| United States |
$ | (192 | ) | 1,540 | 4,615 | |||
| International |
229 | 782 | 1,308 | |||||
| $ | 37 | 2,322 | 5,923 | |||||
| Dollars Per Gallon | ||||||||
| U.S. Average Wholesale Prices* |
||||||||
| Gasoline |
$ | 1.84 | 2.65 | 2.27 | ||||
| Distillates |
1.76 | 3.06 | 2.29 | |||||
| * Excludes excise taxes. |
||||||||
| Thousands of Barrels Daily | ||||||||
| Operating Statistics |
||||||||
| Refining operations* |
||||||||
| United States |
||||||||
| Crude oil capacity** |
1,986 | 2,008 | 2,035 | |||||
| Crude oil processed |
1,731 | 1,849 | 1,944 | |||||
| Capacity utilization (percent) |
87 | % | 92 | 96 | ||||
| Refinery production |
1,891 | 2,035 | 2,146 | |||||
| International |
||||||||
| Crude oil capacity** |
671 | 670 | 687 | |||||
| Crude oil processed |
495 | 567 | 616 | |||||
| Capacity utilization (percent) |
74 | % | 85 | 90 | ||||
| Refinery production |
504 | 575 | 633 | |||||
| Worldwide |
||||||||
| Crude oil capacity** |
2,657 | 2,678 | 2,722 | |||||
| Crude oil processed |
2,226 | 2,416 | 2,560 | |||||
| Capacity utilization (percent) |
84 | % | 90 | 94 | ||||
| Refinery production |
2,395 | 2,610 | 2,779 | |||||
| Petroleum products sales volumes |
||||||||
| United States |
||||||||
| Gasoline |
1,130 | 1,128 | 1,244 | |||||
| Distillates |
858 | 893 | 872 | |||||
| Other products |
367 | 374 | 432 | |||||
| 2,355 | 2,395 | 2,548 | ||||||
| International |
619 | 645 | 697 | |||||
| 2,974 | 3,040 | 3,245 | ||||||
| * | 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.
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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.
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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
| Millions of Dollars | ||||||||
| 2009 | 2008 | 2007 | ||||||
| Net Income (Loss) Attributable to ConocoPhillips |
$ | 1,663 | (5,488 | ) | 1,818 | |||
| Operating Statistics* |
||||||||
| Crude oil production (thousands of barrels daily) |
387 | 386 | 401 | |||||
| Natural gas production (millions of cubic feet daily) |
280 | 356 | 256 | |||||
| Refinery crude oil processed (thousands of barrels daily) |
245 | 229 | 214 | |||||
| * | 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.
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Chemicals
| Millions of Dollars | |||||||
| 2009 | 2008 | 2007 | |||||
| Net Income Attributable to ConocoPhillips |
$ | 248 | 110 | 359 | |||
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
| Millions of Dollars | ||||||||||
| 2009 | 2008 | 2007 | ||||||||
| Net Income (Loss) Attributable to ConocoPhillips |
||||||||||
| Power |
$ | 105 | 106 | 53 | ||||||
| Other |
(102 | ) | (76 | ) | (61 | ) | ||||
| $ | 3 | 30 | (8 | ) | ||||||
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.
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Corporate and Other
| Millions of Dollars | ||||||||||
| 2009 | 2008 | 2007 | ||||||||
| Net Loss Attributable to ConocoPhillips |
||||||||||
| Net interest |
$ | (851 | ) | (558 | ) | (820 | ) | |||
| Corporate general and administrative expenses |
(108 | ) | (202 | ) | (176 | ) | ||||
| Acquisition/merger-related costs |
— | — | (44 | ) | ||||||
| Other |
(51 | ) | (274 | ) | (229 | ) | ||||
| $ | (1,010 | ) | (1,034 | ) | (1,269 | ) | ||||
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.
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CAPITAL RESOURCES AND LIQUIDITY
Financial Indicators
| Millions of Dollars Except as Indicated | ||||||||
| 2009 | 2008 | 2007 | ||||||
| Net cash provided by operating activities |
$ | 12,479 | 22,658 | 24,550 | ||||
| Short-term debt |
1,728 | 370 | 1,398 | |||||
| Total debt* |
28,653 | 27,455 | 21,687 | |||||
| Total equity |
63,057 | 56,265 | 90,156 | |||||
| Percent of total debt to capital** |
31 | % | 33 | 19 | ||||
| Percent of floating-rate debt to total debt |
9 | 37 | 25 | |||||
| *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
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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.
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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.
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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.
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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:
| Millions of Dollars | ||||||||||||||
| Payments Due by Period | ||||||||||||||
| Total | Up to 1 Year |
Year 2-3 |
Year 4-5 |
After 5 Years |
||||||||||
| Debt obligations (a) |
$ | 28,622 | 1,719 | 6,311 | 2,806 | 17,786 | ||||||||
| Capital lease obligations |
31 | 9 | 6 | 3 | 13 | |||||||||
| Total debt |
28,653 | 1,728 | 6,317 | 2,809 | 17,799 | |||||||||
| Interest on debt and other obligations |
20,680 | 1,678 | 2,866 | 2,363 | 13,773 | |||||||||
| Operating lease obligations |
3,377 | 872 | 1,166 | 618 | 721 | |||||||||
| Purchase obligations (b) |
112,131 | 45,291 | 13,615 | 9,088 | 44,137 | |||||||||
| Joint venture acquisition obligation (c) |
5,669 | 660 | 1,427 | 1,586 | 1,996 | |||||||||
| Other long-term liabilities (d) |
||||||||||||||
| Asset retirement obligations |
8,295 | 407 | 519 | 532 | 6,837 | |||||||||
| Accrued environmental costs |
1,017 | 192 | 222 | 113 | 490 | |||||||||
| Unrecognized tax benefits (e) |
60 | 60 | (e | ) | (e | ) | (e | ) | ||||||
| Total |
$ | 179,882 | 50,888 | 26,132 | 17,109 | 85,753 | ||||||||
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| (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. |
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Capital Spending
Capital Expenditures and Investments
| Millions of Dollars | |||||||||
| 2010 Budget |
2009 | 2008 | 2007 | ||||||
| E&P |
|||||||||
| United States—Alaska |
$ | 854 | 810 | 1,414 | 666 | ||||
| United States—Lower 48 |
1,621 | 2,664 | 3,836 | 3,122 | |||||
| International |
6,470 | 5,425 | 11,206 | 6,147 | |||||
| 8,945 | 8,899 | 16,456 | 9,935 | ||||||
| Midstream |
14 | 5 | 4 | 5 | |||||
| R&M |
|||||||||
| United States |
934 | 1,299 | 1,643 | 1,146 | |||||
| International |
385 | 427 | 626 | 240 | |||||
| 1,319 | 1,726 | 2,269 | 1,386 | ||||||
| LUKOIL Investment |
— | — | — | — | |||||
| Chemicals |
— | — | — | — | |||||
| Emerging Businesses |
30 | 97 | 156 | 257 | |||||
| Corporate and Other |
157 | 134 | 214 | 208 | |||||
| $ | 10,465 | 10,861 | 19,099 | 11,791 | |||||
| United States |
$ | 3,590 | 4,921 | 7,111 | 5,225 | ||||
| International |
6,875 | 5,940 | 11,988 | 6,566 | |||||
| $ | 10,465 | 10,861 | 19,099 | 11,791 | |||||
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:
| • | 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. |
| • | 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. |
| • | Oil sands projects and ongoing natural gas projects in Canada. |
| • | 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. |
| • | 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. |
| • | The Kashagan Field and satellite prospects in the Caspian Sea offshore Kazakhstan. |
| • | In the U.K. sector of the North Sea, the Britannia satellite developments and various southern and central North Sea assets. |
| • | Development of the YK Field in the northern part of Russia’s Timan-Pechora province through the NMNG joint venture with LUKOIL. |
| • | Investment in Rockies Express Pipeline LLC. |
| • | Significant U.S. lease acquisitions in the federal waters of the Chukchi Sea offshore Alaska, as well as in the deepwater Gulf of Mexico. |
| • | The North Belut Field, as well as other projects in offshore Block B and onshore South Sumatra in Indonesia. |
| • | The Qatargas 3 Project, an integrated project to produce and liquefy natural gas from Qatar’s North Field. |
| • | 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:
| • | Canadian oil sands projects and ongoing natural gas projects in the western Canada gas basins. |
| • | Further development of coalbed methane projects associated with the APLNG joint venture in Australia. |
| • | Completion of the Qatargas 3 Project in Qatar. |
| • | Elsewhere in the Asia Pacific/Middle East Region, continued development of Bohai Bay in China, new fields offshore Malaysia, offshore Block B and onshore South Sumatra in Indonesia, and offshore Vietnam. |
| • | In the North Sea, the Ekofisk Area, Greater Britannia Fields, various southern North Sea assets, and development of the Jasmine discovery in the J Block and the Clair Ridge Project. |
| • | The Kashagan Field in the Caspian Sea. |
| • | Onshore developments in Nigeria, Algeria and Libya. |
| • | 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.
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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:
| • | Installation of a 20,000 barrel-per-day hydrocracker at the Rodeo facility of our San Francisco Refinery. |
| • | Installation of a 25,000 barrel-per-day coker and new vacuum unit at the Borger Refinery. |
| • | Installations, revamps and expansions of equipment at all U.S. refineries to enable production of low-sulfur and ultra-low-sulfur fuels. |
| • | Upgrading the distillate desulfurization capability at the Humber Refinery. |
| • | Debottlenecking of a crude and fluid catalytic cracking unit, and completion of a new sulfur plant at the Ferndale Refinery. |
| • | Investment to obtain an equity interest in four Keystone Pipeline entities, and associated investment to construct a crude oil pipeline from Hardisty, Alberta, to delivery points in the United States. We disposed of our interest in the Keystone Pipeline in 2009. |
Major construction activities in progress include:
| • | Installation of a 65,000 barrel-per-day coker and a major reconfiguration of the Wood River Refinery to handle advantaged crude and increase capacity, partially funded through long-term advances from ConocoPhillips. |
| • | 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
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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:
| • | U.S. Federal Clean Air Act, which governs air emissions. |
| • | U.S. Federal Clean Water Act, which governs discharges to water bodies. |
| • | European Union Regulation for Registration, Evaluation, Authorization and Restriction of Chemicals (REACH). |
| • | U.S. Federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), which imposes liability on generators, transporters and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatening to occur. |
| • | U.S. Federal Resource Conservation and Recovery Act (RCRA), which governs the treatment, storage and disposal of solid waste. |
| • | U.S. Federal Oil Pollution Act of 1990 (OPA90), under which owners and operators of onshore facilities and pipelines, lessees or permittees of an area in which an offshore facility is located, and owners and operators of vessels are liable for removal costs and damages that result from a discharge of oil into navigable waters of the United States. |
| • | U.S. Federal Emergency Planning and Community Right-to-Know Act (EPCRA), which requires facilities to report toxic chemical inventories with local emergency planning committees and response departments. |
| • | U.S. Federal Safe Drinking Water Act, which governs the disposal of wastewater in underground injection wells. |
| • | U.S. Department of the Interior regulations, which relate to offshore oil and gas operations in U.S. waters and impose liability for the cost of pollution cleanup resulting from operations, as well as potential liability for pollution damages. |
| • | European Union Trading Directive resulting in European Emissions Trading Scheme. |
These laws and their implementing regulations set limits on emissions and, in the case of discharges to water, establish water quality limits. They also, in most cases, require permits in association with new or modified operations. These permits can require an applicant to collect substantial information in connection with the application process, which can be expensive and time-consuming. In addition, there can be delays associated with notice and comment periods and the agency’s processing of the application. Many of the delays associated with the permitting process are beyond the control of the applicant.
Many states and foreign countries where we operate also have, or are developing, similar environmental laws and regulations governing these same types of activities. While similar, in some cases these regulations may impose additional, or more stringent, requirements that can add to the cost and difficulty of marketing or transporting products across state and international borders.
The ultimate financial impact arising from environmental laws and regulations is neither clearly known nor easily determinable as new standards, such as air emission standards, water quality standards and stricter fuel regulations continue to evolve. However, environmental laws and regulations, including those that may arise to address concerns about global climate change, are expected to continue to have an increasing impact on our operations in the United States and in other countries in which we operate. Notable areas of potential impacts include air emission compliance and remediation obligations in the United States.
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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.
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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:
| • | European Emissions Trading Scheme (ETS), the program through which many of the European Union (EU) member states are implementing the Kyoto Protocol. |
| • | California’s Global Warming Solutions Act, which requires the California Air Resources Board (CARB) to develop regulations and market mechanisms that will ultimately reduce California’s GHG emissions by 25 percent by 2020. |
| • | Two regulations issued by the Alberta government in 2007 under the Climate Change and Emissions Act. These regulations require any existing facility with emissions equal to or greater than 100,000 metric tons of carbon dioxide or equivalent per year to reduce the net emissions intensity of that facility by 2 percent per year beginning July 1, 2007, with an ultimate reduction target of 12 percent of baseline emissions. |
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| • | The U.S. Supreme Court decision in Massachusetts v. EPA, 549 U.S. 497, 127 S.Ct. 1438 (2007) confirming that the EPA has the authority to regulate carbon dioxide as an “air pollutant” under the Federal Clean Air Act. |
| • | The EPA’s announcement on 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:
| • | Whether and to what extent legislation is enacted. |
| • | The nature of the legislation (such as a cap and trade system or a tax on emissions). |
| • | The GHG reductions required. |
| • | The price and availability of offsets. |
| • | The amount and allocation of allowances. |
| • | Technological and scientific developments leading to new products or services. |
| • | Any potential significant physical effects of climate change (such as increased severe weather events, changes in sea levels and changes in temperature). |
| • | Whether, and the extent to which, increased compliance costs are ultimately reflected in the prices of our products and services. |
Other
We have deferred tax assets related to certain accrued liabilities, loss carryforwards and credit carryforwards. Valuation allowances have been established to reduce these deferred tax assets to an amount that will, more likely than not, be realized. Based on our historical taxable income, our expectations for the future, and available tax-planning strategies, management expects that the net deferred tax assets will be realized as offsets to reversing deferred tax liabilities and as reductions in future taxable income.
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
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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,
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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
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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
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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.
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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
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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 the Company’s Annual Report on Form 10-K for the year ended December 31, 2009. |
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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.
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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.
| Millions of Dollars Except as Indicated | ||||||||||||||||||||||||
| Debt | Joint Venture Acquisition Obligation |
|||||||||||||||||||||||
| Expected Maturity Date |
Fixed Rate Maturity |
Average Interest Rate |
Floating Rate Maturity |
Average Interest Rate |
Fixed Rate Maturity |
Average Interest Rate |
||||||||||||||||||
| Year-End 2009 |
||||||||||||||||||||||||
| 2010 |
$ | 1,439 | 8.82 | % | $ | — | — | % | $ | 660 | 5.30 | % | ||||||||||||
| 2011 |
3,183 | 6.72 | 750 | 0.45 | 695 | 5.30 | ||||||||||||||||||
| 2012 |
1,264 | 4.94 | 1,303 | 0.25 | 732 | 5.30 | ||||||||||||||||||
| 2013 |
1,262 | 5.33 | — | — | 772 | 5.30 | ||||||||||||||||||
| 2014 |
1,513 | 4.77 | 3 | 2.01 | 814 | 5.30 | ||||||||||||||||||
| Remaining years |
16,805 | 6.28 | 598 | 0.61 | 1,996 | 5.30 | ||||||||||||||||||
| Total |
$ | 25,466 | $ | 2,654 | $ | 5,669 | ||||||||||||||||||
| Fair value |
$ | 27,911 | $ | 2,654 | $ | 6,276 | ||||||||||||||||||
| Year-End 2008 |
||||||||||||||||||||||||
| 2009 |
$ | 303 | 6.43 | % | $ | 950 | 4.42 | % | $ | 625 | 5.30 | % | ||||||||||||
| 2010 |
1,441 | 8.83 | — | — | 659 | 5.30 | ||||||||||||||||||
| 2011 |
3,174 | 6.74 | 1,500 | 1.64 | 695 | 5.30 | ||||||||||||||||||
| 2012 |
1,266 | 4.94 | 6,936 | 1.23 | 733 | 5.30 | ||||||||||||||||||
| 2013 |
1,262 | 5.33 | 10 | 2.46 | 772 | 5.30 | ||||||||||||||||||
| Remaining years |
9,318 | 6.64 | 628 | 2.58 | 2,810 | 5.30 | ||||||||||||||||||
| Total |
$ | 16,764 | $ | 10,024 | $ | 6,294 | ||||||||||||||||||
| Fair value |
$ | 16,882 | $ | 10,024 | $ | 6,294 | ||||||||||||||||||
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.
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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:
| In Millions | |||||||||||||||
| Foreign Currency Swaps | Notional* | Fair Market Value** | |||||||||||||
| 2009 | 2008 | 2009 | 2008 | ||||||||||||
| Sell U.S. dollar, buy euro |
USD | 246 | 526 | $ | (2 | ) | 53 | ||||||||
| Sell U.S. dollar, buy British pound |
USD | 1,664 | 1,657 | (16 | ) | (46 | ) | ||||||||
| Sell U.S. dollar, buy Canadian dollar |
USD | 554 | 1,474 | 34 | 13 | ||||||||||
| Sell U.S. dollar, buy Czech koruna |
USD | — | 40 | — | (2 | ) | |||||||||
| Sell U.S. dollar, buy Danish krone |
USD | — | 5 | — | — | ||||||||||
| Sell U.S. dollar, buy Norwegian kroner |
USD | 744 | 1,103 | (4 | ) | (10 | ) | ||||||||
| Sell U.S. dollar, buy Swedish krona |
USD | — | 51 | — | 1 | ||||||||||
| Sell U.S. dollar, buy Australian dollar |
USD | 3 | 246 | — | 3 | ||||||||||
| Sell euro, buy Canadian dollar |
EUR | — | 102 | — | — | ||||||||||
| Sell euro, buy British pound |
EUR | 267 | — | (14 | ) | — | |||||||||
| Buy euro, sell British pound |
EUR | — | 147 | — | (8 | ) | |||||||||
*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.
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QUARTERLY COMMON STOCK PRICES AND CASH DIVIDENDS PER SHARE
ConocoPhillips’ common stock is traded on the New York Stock Exchange, under the symbol “COP.”
| Stock Price | ||||||||||
| High | Low | Dividends | ||||||||
| 2009 |
||||||||||
| First |
$ | 57.44 | 34.12 | .47 | ||||||
| Second |
48.71 | 37.52 | .47 | |||||||
| Third |
47.30 | 38.62 | .47 | |||||||
| Fourth |
54.13 | 44.88 | .50 | |||||||
| 2008 |
||||||||||
| First |
$ | 89.71 | 67.85 | .47 | ||||||
| Second |
95.96 | 75.52 | .47 | |||||||
| Third |
94.65 | 67.31 | .47 | |||||||
| Fourth |
72.25 | 41.27 | .47 | |||||||
| Closing Stock Price at December 31, 2009 |
$ | 51.07 | ||||||||
| Closing Stock Price at January 31, 2010 |
$ | 48.00 | ||||||||
| Number of Stockholders of Record at January 31, 2010* |
61,039 | |||||||||
| * | In determining the number of stockholders, we consider clearing agencies and security position listings as one stockholder for each agency or listing. |
SELECTED QUARTERLY FINANCIAL DATA (Unaudited)
| Millions of Dollars | Per Share of Common Stock | ||||||||||||||||||
| Sales and Other Operating Revenues* |
Income (Loss) Before Income Taxes |
Net Income (Loss) Attributable to ConocoPhillips |
Net Income (Loss) Attributable to ConocoPhillips |
||||||||||||||||
| Basic | Diluted | ||||||||||||||||||
| 2009 |
|||||||||||||||||||
| First |
$ | 30,741 | 2,034 | 840 | .57 | .56 | |||||||||||||
| Second |
35,448 | 2,382 | 1,298 | .87 | .87 | ||||||||||||||
| Third |
40,173 | 2,947 | 1,503 | 1.00 | 1.00 | ||||||||||||||
| Fourth |
42,979 | 2,669 | 1,217 | .82 | .81 | ||||||||||||||
| 2008 |
|||||||||||||||||||
| First |
$ | 54,883 | 7,568 | 4,139 | 2.65 | 2.62 | |||||||||||||
| Second |
71,411 | 9,812 | 5,439 | 3.54 | 3.50 | ||||||||||||||
| Third |
70,044 | 9,482 | 5,188 | 3.43 | 3.39 | ||||||||||||||
| Fourth** |
44,504 | (30,385 | ) | (31,764 | ) | (21.37 | ) | (21.37 | ) | ||||||||||
| * | 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. |
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| Millions of Dollars Except Per Share Amounts | ||||||||||||
| 2009 | 2008 | 2007 | 2006 | 2005 | ||||||||
| Sales and other operating revenues |
$ | 149,341 | 240,842 | 187,437 | 183,650 | 179,442 | ||||||
| Income (loss) from continuing operations |
4,936 | (16,928 | ) | 11,978 | 15,626 | 13,673 | ||||||
| Income (loss) from continuing operations attributable to ConocoPhillips |
4,858 | (16,998 | ) | 11,891 | 15,550 | 13,640 | ||||||
| Per common share |
||||||||||||
| Basic |
3.26 | (11.16 | ) | 7.32 | 9.80 | 9.79 | ||||||
| Diluted |
3.24 | (11.16 | ) | 7.22 | 9.66 | 9.63 | ||||||
| Net income (loss) |
4,936 | (16,928 | ) | 11,978 | 15,626 | 13,562 | ||||||
| Net income (loss) attributable to ConocoPhillips |
4,858 | (16,998 | ) | 11,891 | 15,550 | 13,529 | ||||||
| Per common share |
||||||||||||
| Basic |
3.26 | (11.16 | ) | 7.32 | 9.80 | 9.71 | ||||||
| Diluted |
3.24 | (11.16 | ) | 7.22 | 9.66 | 9.55 | ||||||
| Total assets |
152,588 | 142,865 | 177,757 | 164,781 | 106,999 | |||||||
| Long-term debt |
26,925 | 27,085 | 20,289 | 23,091 | 10,758 | |||||||
| Joint venture acquisition obligation— long-term |
5,009 | 5,669 | 6,294 | — | — | |||||||
| Cash dividends declared per common share |
1.91 | 1.88 | 1.64 | 1.44 | 1.18 | |||||||
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.
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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
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Report of Independent Registered Public Accounting Firm on Consolidated Financial Statements
The Board of Directors and Stockholders
ConocoPhillips
We have audited the accompanying consolidated balance sheets of ConocoPhillips as of December 31, 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. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements 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.
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
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Report of Independent Registered Public Accounting Firm on
Internal Control Over Financial Reporting
The Board of Directors and Stockholders
ConocoPhillips
We have audited ConocoPhillips’ internal control over financial reporting as of December 31, 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
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| ConocoPhillips |
| Years Ended December 31 | Millions of Dollars | |||||||||
| 2009 | 2008 | 2007 | ||||||||
| Revenues and Other Income |
||||||||||
| Sales and other operating revenues* |
$ | 149,341 | 240,842 | 187,437 | ||||||
| Equity in earnings of affiliates |
2,981 | 4,250 | 5,087 | |||||||
| Other income |
518 | 1,090 | 1,971 | |||||||
| Total Revenues and Other Income |
152,840 | 246,182 | 194,495 | |||||||
| Costs and Expenses |
||||||||||
| Purchased crude oil, natural gas and products |
102,433 | 168,663 | 123,429 | |||||||
| Production and operating expenses |
10,339 | 11,818 | 10,683 | |||||||
| Selling, general and administrative expenses |
1,830 | 2,229 | 2,306 | |||||||
| Exploration expenses |
1,182 | 1,337 | 1,007 | |||||||
| Depreciation, depletion and amortization |
9,295 | 9,012 | 8,298 | |||||||
| Impairments |
||||||||||
| Goodwill |
— | 25,443 | — | |||||||
| LUKOIL investment |
— | 7,410 | — | |||||||
| Expropriated assets** |
51 | — | 4,588 | |||||||
| Other |
484 | 1,686 | 442 | |||||||
| Taxes other than income taxes* |
15,529 | 20,637 | 18,990 | |||||||
| Accretion on discounted liabilities |
422 | 418 | 341 | |||||||
| Interest and debt expense |
1,289 | 935 | 1,253 | |||||||
| Foreign currency transaction (gains) losses |
(46 | ) | 117 | (201 | ) | |||||
| Total Costs and Expenses |
142,808 | 249,705 | 171,136 | |||||||
| Income (loss) before income taxes |
10,032 | (3,523 | ) | 23,359 | ||||||
| Provision for income taxes |
5,096 | 13,405 | 11,381 | |||||||
| Net income (loss) |
4,936 | (16,928 | ) | 11,978 | ||||||
| Less: net income attributable to noncontrolling interests |
(78 | ) | (70 | ) | (87 | ) | ||||
| Net Income (Loss) Attributable to ConocoPhillips |
$ | 4,858 | (16,998 | ) | 11,891 | |||||
| Net Income (Loss) Attributable to ConocoPhillips Per Share of Common Stock (dollars)*** |
||||||||||
| Basic |
$ | 3.26 | (11.16 | ) | 7.32 | |||||
| Diluted |
3.24 | (11.16 | ) | 7.22 | ||||||
| Average Common Shares Outstanding (in thousands) |
||||||||||
| Basic |
1,487,650 | 1,523,432 | 1,623,994 | |||||||
| Diluted |
1,497,608 | 1,523,432 | 1,645,919 | |||||||
| * Includes excise taxes on petroleum products sales: |
$ | 13,325 | 15,418 | 15,937 | ||||||
| ** 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.
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| ConocoPhillips |
| At December 31 | Millions of Dollars | ||||||
| 2009 | 2008 | ||||||
| Assets |
|||||||
| Cash and cash equivalents |
$ | 542 | 755 | ||||
| Accounts and notes receivable (net of allowance of $76 million in 2009 |
11,861 | 10,892 | |||||
| Accounts and notes receivable—related parties |
1,354 | 1,103 | |||||
| Inventories |
4,940 | 5,095 | |||||
| Prepaid expenses and other current assets |
2,470 | 2,998 | |||||
| Total Current Assets |
21,167 | 20,843 | |||||
| Investments and long-term receivables |
36,192 | 30,926 | |||||
| Loans and advances—related parties |
2,352 | 1,973 | |||||
| Net properties, plants and equipment |
87,708 | 83,947 | |||||
| Goodwill |
3,638 | 3,778 | |||||
| Intangibles |
823 | 846 | |||||
| Other assets |
708 | 552 | |||||
| Total Assets |
$ | 152,588 | 142,865 | ||||
| Liabilities |
|||||||
| Accounts payable |
$ | 14,168 | 12,852 | ||||
| Accounts payable—related parties |
1,317 | 1,138 | |||||
| Short-term debt |
1,728 | 370 | |||||
| Accrued income and other taxes |
3,402 | 4,273 | |||||
| Employee benefit obligations |
846 | 939 | |||||
| Other accruals |
2,234 | 2,208 | |||||
| Total Current Liabilities |
23,695 | 21,780 | |||||
| Long-term debt |
26,925 | 27,085 | |||||
| Asset retirement obligations and accrued environmental costs |
8,713 | 7,163 | |||||
| Joint venture acquisition obligation—related party |
5,009 | 5,669 | |||||
| Deferred income taxes |
17,962 | 18,167 | |||||
| Employee benefit obligations |
4,130 | 4,127 | |||||
| Other liabilities and deferred credits |
3,097 | 2,609 | |||||
| Total Liabilities |
89,531 | 86,600 | |||||
| Equity |
|||||||
| Common stock (2,500,000,000 shares authorized at $.01 par value) |
|||||||
| Par value |
17 | 17 | |||||
| Capital in excess of par |
43,681 | 43,396 | |||||
| Grantor trusts (at cost: 2009—38,742,261 shares; 2008—40,739,129 shares) |
(667 | ) | (702 | ) | |||
| Treasury stock (at cost: 2009 and 2008—208,346,815 shares) |
(16,211 | ) | (16,211 | ) | |||
| Accumulated other comprehensive income (loss) |
3,065 | (1,875 | ) | ||||
| Unearned employee compensation |
(76 | ) | (102 | ) | |||
| Retained earnings |
32,658 | 30,642 | |||||
| Total Common Stockholders’ Equity |
62,467 | 55,165 | |||||
| Noncontrolling interests |
590 | 1,100 | |||||
| Total Equity |
63,057 | 56,265 | |||||
| Total Liabilities and Equity |
$ | 152,588 | 142,865 | ||||
See Notes to Consolidated Financial Statements.
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See Notes to Consolidated Financial Statements.
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| Consolidated Statement of Changes in Equity | ConocoPhillips |
| Millions of Dollars | |||||||||||||||||||||||||||||
| Attributable to ConocoPhillips | Noncontrolling Interests |
Total | |||||||||||||||||||||||||||
| Common Stock | Accum. Other Comprehensive Income (Loss) |
Unearned Employee Compensation |
Retained Earnings |
Comprehensive Income (Loss) |
|||||||||||||||||||||||||
| Par Value |
Capital in Excess of Par |
Treasury Stock |
Grantor Trusts |
||||||||||||||||||||||||||
| December 31, 2006 |
$ | 17 | 41,926 | (964 | ) | (766 | ) | 1,289 | (148 | ) | 41,292 | 1,202 | 83,848 | ||||||||||||||||
| Net income |
11,891 | 11,891 | 87 | 11,978 | |||||||||||||||||||||||||
| Other comprehensive income (loss) |
|||||||||||||||||||||||||||||
| Defined benefit pension plans |
|||||||||||||||||||||||||||||
| Net prior service cost |
63 | 63 | 63 | ||||||||||||||||||||||||||
| Net actuarial gain |
213 | 213 | 213 | ||||||||||||||||||||||||||
| Nonsponsored plans |
(2 | ) | (2 | ) | (2 | ) | |||||||||||||||||||||||
| Foreign currency translation adjustments |
3,075 | 3,075 | 3,075 | ||||||||||||||||||||||||||
| Hedging activities |
(4 | ) | (4 | ) | (4 | ) | |||||||||||||||||||||||
| Comprehensive income |
15,236 | 87 | 15,323 | ||||||||||||||||||||||||||
| Initial application of SFAS No. 158—equity affiliate |
(74 | ) | (74 | ) | |||||||||||||||||||||||||
| Cash dividends paid on company common stock |
(2,661 | ) | (2,661 | ) | |||||||||||||||||||||||||
| Repurchase of company common stock |
(7,005 | ) | 11 | (6,994 | ) | ||||||||||||||||||||||||
| Distributions to noncontrolling interests and other |
(116 | ) | (116 | ) | |||||||||||||||||||||||||
| Distributed under benefit plans |
798 | 31 | 829 | ||||||||||||||||||||||||||
| Recognition of unearned compensation |
20 | 20 | |||||||||||||||||||||||||||
| Other |
(7 | ) | (12 | ) | (19 | ) | |||||||||||||||||||||||
| December 31, 2007 |
17 | 42,724 | (7,969 | ) | (731 | ) | 4,560 | (128 | ) | 50,510 | 1,173 | 90,156 | |||||||||||||||||
| Net income (loss) |
(16,998 | ) | (16,998 | ) | 70 | (16,928 | ) | ||||||||||||||||||||||
| Other comprehensive income (loss) |
|||||||||||||||||||||||||||||
| Defined benefit pension plans |
|||||||||||||||||||||||||||||
| Net prior service cost |
22 | 22 | 22 | ||||||||||||||||||||||||||
| Net actuarial loss |
(950 | ) | (950 | ) | (950 | ) | |||||||||||||||||||||||
| Nonsponsored plans |
(41 | ) | (41 | ) | (41 | ) | |||||||||||||||||||||||
| Foreign currency translation adjustments |
(5,464 | ) | (5,464 | ) | (5,464 | ) | |||||||||||||||||||||||
| Hedging activities |
(2 | ) | (2 | ) | (2 | ) | |||||||||||||||||||||||
| Comprehensive income (loss) |
(23,433 | ) | 70 | (23,363 | ) | ||||||||||||||||||||||||
| Cash dividends paid on company common stock |
(2,854 | ) | (2,854 | ) | |||||||||||||||||||||||||
| Repurchase of company common stock |
(8,242 | ) | 1 | (8,241 | ) | ||||||||||||||||||||||||
| Distributions to noncontrolling interests and other |
(143 | ) | (143 | ) | |||||||||||||||||||||||||
| Distributed under benefit plans |
672 | 28 | 700 | ||||||||||||||||||||||||||
| Recognition of unearned compensation |
26 | 26 | |||||||||||||||||||||||||||
| Other |
(16 | ) | (16 | ) | |||||||||||||||||||||||||
| December 31, 2008 |
17 | 43,396 | (16,211 | ) | (702 | ) | (1,875 | ) | (102 | ) | 30,642 | 1,100 | 56,265 | ||||||||||||||||
| Net income |
4,858 | 4,858 | 78 | 4,936 | |||||||||||||||||||||||||
| Other comprehensive income (loss) |
|||||||||||||||||||||||||||||
| Defined benefit pension plans |
|||||||||||||||||||||||||||||
| Net prior service cost |
7 | 7 | 7 | ||||||||||||||||||||||||||
| Net actuarial loss |
(99 | ) | (99 | ) | (99 | ) | |||||||||||||||||||||||
| Nonsponsored plans |
22 | 22 | 22 | ||||||||||||||||||||||||||
| Foreign currency translation adjustments |
5,007 | 5,007 | 5,007 | ||||||||||||||||||||||||||
| Hedging activities |
3 | 3 | 3 | ||||||||||||||||||||||||||
| Comprehensive income |
9,798 | 78 | 9,876 | ||||||||||||||||||||||||||
| Cash dividends paid on company common stock |
(2,832 | ) | (2,832 | ) | |||||||||||||||||||||||||
| Distributions to noncontrolling interests and other |
(588 | ) | (588 | ) | |||||||||||||||||||||||||
| Distributed under benefit plans |
285 | 35 | 320 | ||||||||||||||||||||||||||
| Recognition of unearned compensation |
26 | 26 | |||||||||||||||||||||||||||
| Other |
(10 | ) | (10 | ) | |||||||||||||||||||||||||
| December 31, 2009 |
$ | 17 | 43,681 | (16,211 | ) | (667 | ) | 3,065 | (76 | ) | 32,658 | 590 | 63,057 | ||||||||||||||||
See Notes to Consolidated Financial Statements.
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| 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 |
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| 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
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“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.
| n | Capitalized Interest—Interest from external borrowings is capitalized on major projects with an expected construction period of one year or longer. Capitalized interest is added to the cost of the underlying asset and is amortized over the useful lives of the assets in the same manner as the underlying assets. |
| n | Intangible Assets Other Than Goodwill—Intangible assets that have finite useful lives are amortized by the straight-line method over their useful lives. Intangible assets that have indefinite useful lives are not amortized but are tested at least annually for impairment. Each reporting period, we evaluate the remaining useful lives of intangible assets not being amortized to determine whether events and circumstances continue to support indefinite useful lives. These indefinite lived intangibles are considered impaired if the fair value of the intangible asset is lower than net book value. The fair value of intangible assets is determined based on quoted market prices in active markets, if available. If quoted market prices are not available, fair value of intangible assets is determined based upon the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants, or upon estimated replacement cost, if expected future cash flows from the intangible asset are not determinable. |
| n | Goodwill—Goodwill resulting from a business combination is not amortized but is tested at least annually for impairment. If the fair value of a reporting unit is less than the recorded book value of the reporting unit’s assets (including goodwill), less liabilities, then a hypothetical purchase price allocation is performed on the reporting unit’s assets and liabilities using the fair value of the reporting unit as the purchase price in the calculation. If the amount of goodwill resulting from this hypothetical purchase price allocation is less than the recorded amount of goodwill, the recorded goodwill is written down to the new amount. For purposes of goodwill impairment calculations, two reporting units have been determined: Worldwide Exploration and Production and Worldwide Refining and Marketing. |
| n | 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 |
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| declining utilization pattern), are determined by the unit-of-production method. Depreciation and amortization of all other properties, plants and equipment are determined by either the individual-unit-straight-line method or the group-straight-line method (for those individual units that are highly integrated with other units). |
| n | Impairment of Properties, Plants and 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.
| n | 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. |
| n | Maintenance and Repairs—Costs of maintenance and repairs, which are not significant improvements, are expensed when incurred. |
| n | Advertising Costs—Production costs of media advertising are deferred until the first public showing of the advertisement. Advances to secure advertising slots at specific sporting or other events are deferred until the event occurs. All other advertising costs are expensed as incurred, unless the cost has benefits that clearly extend beyond the interim period in which the expenditure is made, in which case the advertising cost is deferred and amortized ratably over the interim periods that clearly benefit from the expenditure. |
| n | Property Dispositions—When complete units of depreciable property are sold, the asset cost and related accumulated depreciation are eliminated, with any gain or loss reflected in other income. When |
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| less than complete units of depreciable property are disposed of or retired, the difference between asset cost and salvage value is charged or credited to accumulated depreciation. |
| n | Asset Retirement Obligations and Environmental 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.
| n | 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. |
| n | 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. |
| n | 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. |
| n | 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. |
| n | 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 |
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| 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:
| • | An expanded definition of oil and gas producing activities to include nontraditional resources such as bitumen extracted from oil sands. |
| • | The use of an average of the first-day-of-the-month price for the 12-month period, rather than a year-end price for determining whether reserves can be produced economically. |
| • | Amended definitions of key terms such as “reliable technology” and “reasonable certainty” which are used in estimating proved oil and gas reserve quantities. |
| • | A requirement for disclosing separate information about reserve quantities and financial statement amounts for geographical areas representing 15 percent or more of proved reserves. |
| • | Clarification that an 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,
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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
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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:
| • | Recognize the funded status of the benefit in its statement of financial position. |
| • | 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. |
| • | Measure defined benefit plan assets and obligations as of the date of the employer’s fiscal year-end statement of financial position. |
| • | 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.
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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.
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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:
| Millions of Dollars | |||||
| 2009 | 2008 | ||||
| Crude oil and petroleum products |
$ | 3,955 | 4,232 | ||
| Materials, supplies and other |
985 | 863 | |||
| $ | 4,940 | 5,095 | |||
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
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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:
| Millions of Dollars | |||||
| 2009 | 2008 | ||||
| Equity investments |
$ | 34,730 | 29,914 | ||
| Loans and advances—related parties |
2,352 | 1,973 | |||
| Long-term receivables |
1,009 | 597 | |||
| Other investments |
453 | 415 | |||
| $ | 38,544 | 32,899 | |||
Equity Investments
Affiliated companies in which we have a significant equity investment include:
| • | 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. |
| • | 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. |
| • | WRB Refining LLC—50 percent owned business venture with Cenovus—owns the Wood River and Borger Refineries, which process crude oil into refined products. |
| • | 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. |
| • | 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. |
| • | DCP Midstream, LLC—50 percent owned joint venture with Spectra Energy—owns and operates gas plants, gathering systems, storage facilities and fractionation plants. |
| • | 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):
| Millions of Dollars | |||||||
| 2009 | 2008 | 2007 | |||||
| Revenues |
$ | 128,881 | 180,070 | 143,686 | |||
| Income before income taxes |
12,121 | 22,356 | 19,807 | ||||
| Net income |
9,145 | 17,976 | 15,229 | ||||
| Current assets |
36,139 | 34,838 | 29,451 | ||||
| Noncurrent assets |
126,163 | 114,294 | 90,939 | ||||
| Current liabilities |
22,483 | 21,150 | 16,882 | ||||
| Noncurrent liabilities |
30,960 | 29,845 | 26,656 | ||||
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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.
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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.
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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:
| • | $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. |
| • | $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. |
| • | $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.
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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:
| Millions of Dollars | |||||||||||||||
| 2009 | 2008 | ||||||||||||||
| Gross PP&E |
Accum. DD&A |
Net PP&E |
Gross PP&E |
Accum. DD&A |
Net PP&E | ||||||||||
| E&P |
$ | 115,224 | 45,577 | 69,647 | 102,591 | 35,375 | 67,216 | ||||||||
| Midstream |
123 | 74 | 49 | 120 | 70 | 50 | |||||||||
| R&M |
23,047 | 6,714 | 16,333 | 21,116 | 5,962 | 15,154 | |||||||||
| LUKOIL Investment |
— | — | — | — | — | — | |||||||||
| Chemicals |
— | — | — | — | — | — | |||||||||
| Emerging Businesses |
1,198 | 300 | 898 | 1,056 | 293 | 763 | |||||||||
| Corporate and Other |
1,650 | 869 | 781 | 1,561 | 797 | 764 | |||||||||
| $ | 141,242 | 53,534 | 87,708 | 126,444 | 42,497 | 83,947 | |||||||||
Note 8—Suspended Wells
The following table reflects the net changes in suspended exploratory well costs during 2009, 2008 and 2007:
| Millions of Dollars | ||||||||||
| 2009 | 2008 | 2007 | ||||||||
| Beginning balance at January 1 |
$ | 660 | 589 | 537 | ||||||
| Additions pending the determination of proved reserves |
342 | 160 | 157 | |||||||
| Reclassifications to proved properties |
(39 | ) | (37 | ) | (58 | ) | ||||
| Sales of suspended well investment |
(21 | ) | (10 | ) | (22 | ) | ||||
| Charged to dry hole expense |
(34 | ) | (42 | ) | (25 | ) | ||||
| Ending balance at December 31 |
$ | 908 | 660 | 589 | * | |||||
| * | 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:
| Millions of Dollars | |||||||
| 2009 | 2008 | 2007 | |||||
| Exploratory well costs capitalized for a period of one year or less |
$ | 319 | 182 | 153 | |||
| Exploratory well costs capitalized for a period greater than one year |
589 | 478 | 436 | ||||
| Ending balance |
$ | 908 | 660 | 589 | |||
| Number of projects that have exploratory well costs that have been capitalized for a period greater than one year |
34 | 31 | 35 | ||||
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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:
| Millions of Dollars | |||||||||
| Suspended Since | |||||||||
| Project | Total | 2007-2008 | 2004-2006 | 2001-2003 | |||||
| Aktote—Kazakhstan (2) |
$ | 17 | — | 7 | 10 | ||||
| Alpine satellite—Alaska (2) |
23 | — | — | 23 | |||||
| Caldita/Barossa—Australia (1) |
77 | — | 77 | — | |||||
| Clair—U.K. (2) |
48 | 31 | 17 | — | |||||
| Fiord West—Alaska (1) |
16 | 16 | — | — | |||||
| Harrison—U.K. (2) |
16 | 16 | — | — | |||||
| Jasmine—U.K. (2) |
72 | 47 | 25 | — | |||||
| Kairan—Kazakhstan (2) |
26 | 13 | 13 | — | |||||
| Kashagan—Kazakhstan (1) |
34 | 25 | — | 9 | |||||
| Malikai—Malaysia (2) |
48 | — | 48 | — | |||||
| Petai/Pisagon—Malaysia (1) |
19 | 10 | 9 | — | |||||
| Saleski—Canada (1) |
13 | 13 | — | — | |||||
| Sunrise 3—Australia (2) |
13 | 13 | — | — | |||||
| Surmont—Canada (1) |
23 | 15 | 8 | — | |||||
| Thornbury—Canada (1) |
19 | 19 | — | — | |||||
| Ubah—Malaysia (1) |
22 | 22 | — | — | |||||
| Uge—Nigeria (2) |
30 | 16 | 14 | — | |||||
| Seventeen projects of less than $10 million each (1)(2) |
73 | 37 | 30 | 6 | |||||
| Total of 34 projects |
$ | 589 | 293 | 248 | 48 | ||||
| (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:
| Millions of Dollars | ||||||||||||||||||||
| 2009 | 2008 | |||||||||||||||||||
| E&P | R&M | Total | E&P | R&M | Total | |||||||||||||||
| Balance as of January 1 |
||||||||||||||||||||
| Goodwill |
$ | 25,443 | 3,778 | 29,221 | 25,569 | 3,767 | 29,336 | |||||||||||||
| Accumulated impairment losses |
(25,443 | ) | — | (25,443 | ) | — | — | — | ||||||||||||
| — | 3,778 | 3,778 | 25,569 | 3,767 | 29,336 | |||||||||||||||
| Goodwill allocated to assets held for sale or sold |
— | (135 | ) | (135 | ) | (148 | ) | — | (148 | ) | ||||||||||
| Goodwill impairment |
— | — | — | (25,443 | ) | — | (25,443 | ) | ||||||||||||
| Tax and other adjustments |
— | (5 | ) | (5 | ) | 22 | 11 | 33 | ||||||||||||
| Balance as of December 31 |
||||||||||||||||||||
| Goodwill |
25,443 | 3,638 | 29,081 | 25,443 | 3,778 | 29,221 | ||||||||||||||
| Accumulated impairment losses |
(25,443 | ) | — | (25,443 | ) | (25,443 | ) | — | (25,443 | ) | ||||||||||
| $ | — | 3,638 | 3,638 | — | 3,778 | 3,778 | ||||||||||||||
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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:
| • | Adjusting the carrying value of major equity method investments to their estimated fair values. |
| • | Adjusting the carrying value of properties, plants and equipment (PP&E) to the estimated aggregate fair value of all oil and gas property interests. |
| • | Recalculating deferred income taxes under FASB ACS 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.
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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:
| Millions of Dollars | ||||||||
| Gross Carrying Amount |
Accumulated Amortization |
Net Carrying Amount | ||||||
| Amortized Intangible Assets |
||||||||
| Balance at December 31, 2009 |
||||||||
| Technology related |
$ | 126 | (74 | ) | 52 | |||
| Refinery air permits |
14 | (13 | ) | 1 | ||||
| Contract based |
87 | (65 | ) | 22 | ||||
| Other |
37 | (29 | ) | 8 | ||||
| $ | 264 | (181 | ) | 83 | ||||
| Balance at December 31, 2008 |
||||||||
| Technology related |
$ | 120 | (60 | ) | 60 | |||
| Refinery air permits |
14 | (10 | ) | 4 | ||||
| Contract based |
116 | (81 | ) | 35 | ||||
| Other |
36 | (27 | ) | 9 | ||||
| $ | 286 | (178 | ) | 108 | ||||
| Indefinite-Lived Intangible Assets |
||||||||
| Balance at December 31, 2009 |
||||||||
| Trade names and trademarks |
$ | 494 | ||||||
| Refinery air and operating permits |
246 | |||||||
| $ | 740 | |||||||
| Balance at December 31, 2008 |
||||||||
| Trade names and trademarks |
$ | 494 | ||||||
| Refinery air and operating permits |
244 | |||||||
| $ | 738 | |||||||
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.
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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.
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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:
| Millions of Dollars | ||||||||
| 2009 | 2008 | 2007 | ||||||
| E&P |
||||||||
| United States |
$ | 5 | 620 | 73 | ||||
| International |
412 | 173 | 398 | |||||
| R&M |
||||||||
| United States |
63 | 534 | 66 | |||||
| International |
3 | 181 | 25 | |||||
| Increase in fair value of previously impaired assets |
— | — | (128 | ) | ||||
| Emerging Businesses |
— | 130 | — | |||||
| Corporate |
1 | 48 | 8 | |||||
| $ | 484 | 1,686 | 442 | |||||
2009
During 2009, we recorded property impairments of $417 million in our E&P segment, primarily as a result of lower natural gas price assumptions, reduced volume forecasts, and higher royalty, operating 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.
| Millions of Dollars | |||||||||||||
| Fair Value | Fair Value Measurements Using |
2009 Before-Tax Loss | |||||||||||
| Level 1 Inputs |
Level 3 Inputs |
||||||||||||
| Net properties, plants and equipment (held for use) |
$ | 210 | — | 210 | 385 | ||||||||
| Net properties, plants and equipment (held for sale) |
91 | 35 | 56 | 62 | |||||||||
| Equity method investments |
1,784 | — | 1,784 | 286 | |||||||||
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
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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.
2008
As a result of the economic downturn in the fourth quarter of 2008, the outlook for crude oil and natural gas prices, refining margins, and power spreads sharply deteriorated. 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.
2007
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:
| Millions of Dollars | |||||||
| 2009 | 2008 | ||||||
| Asset retirement obligations |
$ | 8,295 | 6,615 | ||||
| Accrued environmental costs |
1,017 | 979 | |||||
| Total asset retirement obligations and accrued environmental costs |
9,312 | 7,594 | |||||
| Asset retirement obligations and accrued environmental costs due within one year* |
(599 | ) | (431 | ) | |||
| Long-term asset retirement obligations and accrued environmental costs |
$ | 8,713 | 7,163 | ||||
| *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.
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During 2009 and 2008, our overall asset retirement obligation changed as follows:
| Millions of Dollars | |||||||
| 2009 | 2008 | ||||||
| Balance at January 1 |
$ | 6,615 | 6,613 | ||||
| Accretion of discount |
394 | 389 | |||||
| New obligations |
113 | 123 | |||||
| Changes in estimates of existing obligations |
905 | 994 | |||||
| Spending on existing obligations |
(322 | ) | (217 | ) | |||
| Property dispositions |
(82 | ) | (115 | ) | |||
| Foreign currency translation |
672 | (1,172 | ) | ||||
| Balance at December 31 |
$ | 8,295 | 6,615 | ||||
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.
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Note 12—Debt
Long-term debt at December 31 was:
| Millions of Dollars | |||||||
| 2009 | 2008 | ||||||
| 9.875% Debentures due 2010 |
$ | 150 | 150 | ||||
| 9.375% Notes due 2011 |
328 | 328 | |||||
| 9.125% Debentures due 2021 |
150 | 150 | |||||
| 8.75% Notes due 2010 |
1,264 | 1,264 | |||||
| 8.20% Debentures due 2025 |
150 | 150 | |||||
| 8.125% Notes due 2030 |
600 | 600 | |||||
| 7.9% Debentures due 2047 |
100 | 100 | |||||
| 7.8% Debentures due 2027 |
300 | 300 | |||||
| 7.68% Notes due 2012 |
23 | 30 | |||||
| 7.65% Debentures due 2023 |
88 | 88 | |||||
| 7.625% Debentures due 2013 |
100 | 100 | |||||
| 7.40% Notes due 2031 |
500 | 500 | |||||
| 7.375% Debentures due 2029 |
92 | 92 | |||||
| 7.25% Notes due 2031 |
500 | 500 | |||||
| 7.20% Notes due 2031 |
575 | 575 | |||||
| 7% Debentures due 2029 |
200 | 200 | |||||
| 6.95% Notes due 2029 |
1,549 | 1,549 | |||||
| 6.875% Debentures due 2026 |
67 | 67 | |||||
| 6.68% Notes due 2011 |
400 | 400 | |||||
| 6.65% Debentures due 2018 |
297 | 297 | |||||
| 6.50% Notes due 2011 |
500 | 500 | |||||
| 6.50% Notes due 2039 |
2,250 | — | |||||
| 6.50% Notes due 2039 |
500 | — | |||||
| 6.40% Notes due 2011 |
178 | 178 | |||||
| 6.375% Notes due 2009 |
— | 284 | |||||
| 6.35% Notes due 2011 |
1,750 | 1,750 | |||||
| 6.00 % Notes due 2020 |
1,000 | — | |||||
| 5.951% Notes due 2037 |
645 | 645 | |||||
| 5.95% Notes due 2036 |
500 | 500 | |||||
| 5.90% Notes due 2032 |
505 | 505 | |||||
| 5.90% Notes due 2038 |
600 | 600 | |||||
| 5.75% Notes due 2019 |
2,250 | — | |||||
| 5.625% Notes due 2016 |
1,250 | 1,250 | |||||
| 5.50% Notes due 2013 |
750 | 750 | |||||
| 5.30% Notes due 2012 |
350 | 350 | |||||
| 5.20% Notes due 2018 |
500 | 500 | |||||
| 4.75% Notes due 2012 |
897 | 897 | |||||
| 4.75% Notes due 2014 |
1,500 | — | |||||
| 4.60% Notes due 2015 |
1,500 | — | |||||
| 4.40% Notes due 2013 |
400 | 400 | |||||
| Commercial paper at 0.06% – 0.29% at year-end 2009 and 1.05% – 1.76% at year-end 2008 |
1,300 | 6,933 | |||||
| Floating Rate Five-Year Term Note due 2011 at 0.45% at year-end 2009 and 1.638% at year-end 2008 |
750 | 1,500 | |||||
| Floating Rate Notes due 2009 at 4.42% at year-end 2008 |
— | 950 | |||||
| Industrial Development Bonds due 2012 through 2038 at 0.24% – 5.75% at year-end 2009 and 0.93% – 5.75% at year-end 2008 |
252 | 252 | |||||
| Guarantee of savings plan bank loan payable due 2015 at 2.01% at year-end 2009 and 2.46% at year-end 2008 |
103 | 140 | |||||
| Note payable to Merey Sweeny, L.P. due 2020 at 7% (related party) |
154 | 163 | |||||
| Marine Terminal Revenue Refunding Bonds due 2031 at 0.26% – 0.40% at year-end 2009 and 0.40% – 1.00% at year-end 2008 |
265 | 265 | |||||
| Other |
38 | 36 | |||||
| Debt at face value |
28,120 | 26,788 | |||||
| Capitalized leases |
31 | 28 | |||||
| Net unamortized premiums and discounts |
502 | 639 | |||||
| Total debt |
28,653 | 27,455 | |||||
| Short-term debt |
(1,728 | ) | (370 | ) | |||
| Long-term debt |
$ | 26,925 | 27,085 | ||||
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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
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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
| • | 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
| • | 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. |
| • | 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
| • | 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 |
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| ($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
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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
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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
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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:
| Millions of Dollars | |||||||||||||||||||||||||||
| December 31, 2009 | December 31, 2008 | ||||||||||||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||
| Assets |
|||||||||||||||||||||||||||
| Commodity derivatives |
$ | 1,710 | 1,659 | 61 | 3,430 | 4,994 | 2,874 | 112 | 7,980 | ||||||||||||||||||
| Foreign exchange derivatives |
— | 45 | — | 45 | — | 97 | — | 97 | |||||||||||||||||||
| Total assets |
1,710 | 1,704 | 61 | 3,475 | 4,994 | 2,971 | 112 | 8,077 | |||||||||||||||||||
| Liabilities |
|||||||||||||||||||||||||||
| Commodity derivatives |
(1,797 | ) | (1,496 | ) | (24 | ) | (3,317 | ) | (5,221 | ) | (2,497 | ) | (72 | ) | (7,790 | ) | |||||||||||
| Foreign exchange derivatives |
— | (47 | ) | — | (47 | ) | — | (93 | ) | — | (93 | ) | |||||||||||||||
| Total liabilities |
(1,797 | ) | (1,543 | ) | (24 | ) | (3,364 | ) | (5,221 | ) | (2,590 | ) | (72 | ) | (7,883 | ) | |||||||||||
| Net assets (liabilities) |
$ | (87 | ) | 161 | 37 | 111 | (227 | ) | 381 | 40 | 194 | ||||||||||||||||
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.
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The fair value of net commodity derivatives classified as Level 3 in the fair value hierarchy changed as follows during 2009 and 2008:
| Millions of Dollars | |||||||
| 2009 | 2008 | ||||||
| Fair Value Measurements Using Significant Unobservable Inputs (Level 3) |
|||||||
| Beginning balance |
$ | 40 | (34 | ) | |||
| Total gains (losses), realized and unrealized |
|||||||
| Included in earnings |
17 | 6 | |||||
| Included in other comprehensive income |
— | — | |||||
| Purchases, issuances and settlements |
(60 | ) | 37 | ||||
| Transfers in and/or out of Level 3 |
40 | 31 | |||||
| Ending balance |
$ | 37 | 40 | ||||
The amounts of Level 3 gains (losses) included in earnings were:
| Millions of Dollars | ||||||||||||||||||||
| 2009 | 2008 | |||||||||||||||||||
| Other Operating Revenues |
Purchased Crude Oil, Natural Gas and Products |
Total | Other Operating Revenues |
Purchased Crude Oil, Natural Gas and Products |
Total | |||||||||||||||
| Total gains (losses) included in earnings |
$ | 17 | — | 17 | 11 | (5 | ) | 6 | ||||||||||||
| Change in unrealized gains (losses) relating to assets held at December 31 |
$ | 13 | — | 13 | 20 | 63 | 83 | |||||||||||||
| Change in unrealized gains (losses) relating to liabilities held at December 31 |
$ | (14 | ) | — | (14 | ) | (8 | ) | (64 | ) | (72 | ) | ||||||||
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.
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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:
| Millions of Dollars | |||
| Assets |
|||
| Prepaid expenses and other current assets |
$ | 3,084 | |
| Other assets |
359 | ||
| Liabilities |
|||
| Other accruals |
3,006 | ||
| Other liabilities and deferred credits |
324 | ||
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:
| Millions of Dollars |
||||
| Sales and other operating revenues |
$ | 1,964 | ||
| Other income |
19 | |||
| Purchased crude oil, natural gas and products |
(2,624 | ) | ||
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.
| Open Position Long / (Short) |
|||
| Commodity |
|||
| Crude oil, refined products and natural gas liquids (millions of barrels) |
(16 | ) | |
| Natural gas and power (billions of cubic feet) |
|||
| Fixed price |
(60 | ) | |
| Basis |
154 |
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.
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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:
| Millions of Dollars | |||
| Assets |
|||
| Prepaid expenses and other current assets |
$ | 38 | |
| Other assets |
7 | ||
| Liabilities |
|||
| Other accruals |
40 | ||
| Other liabilities and deferred credits |
7 | ||
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.
| In Millions Notional* | ||||
| Foreign Currency Swaps |
||||
| Sell U.S. dollar, buy other currencies** |
USD | 3,211 | ||
| Buy British pound, sell euro |
EUR | 267 | ||
| *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.
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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:
| Millions of Dollars | |||||||||||
| Carrying Amount | Fair Value | ||||||||||
| 2009 | 2008 | 2009 | 2008 | ||||||||
| Financial assets |
|||||||||||
| Foreign currency derivatives |
$ | 45 | 160 | 45 | 160 | ||||||
| Commodity derivatives |
823 | 1,279 | 823 | 1,279 | |||||||
| Financial liabilities |
|||||||||||
| Total debt, excluding capital leases |
28,622 | 27,427 | 30,565 | 26,906 | |||||||
| Joint venture acquisition obligation |
5,669 | 6,294 | 6,276 | 6,294 | |||||||
| Foreign currency derivatives |
47 | 155 | 47 | 155 | |||||||
| Commodity derivatives |
632 | 881 | 632 | 881 | |||||||
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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:
| Shares | |||||||||
| 2009 | 2008 | 2007 | |||||||
| Issued |
|||||||||
| Beginning of year |
1,729,264,859 | 1,718,448,829 | 1,705,502,609 | ||||||
| Distributed under benefit plans |
4,080,699 | 10,816,030 | 12,946,220 | ||||||
| End of year |
1,733,345,558 | 1,729,264,859 | 1,718,448,829 | ||||||
| Held in Treasury |
|||||||||
| Beginning of year |
208,346,815 | 104,607,149 | 15,061,613 | ||||||
| Repurchase of common stock |
— | 103,739,666 | 89,545,536 | ||||||
| End of year |
208,346,815 | 208,346,815 | 104,607,149 | ||||||
| Held in Grantor Trusts |
|||||||||
| Beginning of year |
40,739,129 | 42,411,331 | 44,358,585 | ||||||
| Distributed under benefit plans |
(2,018,692 | ) | (1,668,456 | ) | (1,856,224 | ) | |||
| Repurchase of common stock |
— | (13,600 | ) | (177,110 | ) | ||||
| Other |
21,824 | 9,854 | 86,080 | ||||||
| End of year |
38,742,261 | 40,739,129 | 42,411,331 | ||||||
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.
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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:
| Millions of Dollars |
||||
| 2010 |
$ | 872 | ||
| 2011 |
637 | |||
| 2012 |
529 | |||
| 2013 |
346 | |||
| 2014 |
272 | |||
| Remaining years |
721 | |||
| Total |
3,377 | |||
| Less income from subleases |
(142 | )* | ||
| Net minimum operating lease payments |
$ | 3,235 | ||
| *Includes | $53 million related to railcars subleased to Chevron Phillips Chemical Company LLC, a related party. |
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Operating lease rental expense for the years ended December 31 was:
| Millions of Dollars | ||||||||||
| 2009 | 2008 | 2007 | ||||||||
| Total rentals* |
$ | 1,024 | 1,033 | 855 | ||||||
| Less sublease rentals |
(34 | ) | (125 | ) | (82 | ) | ||||
| $ | 990 | 908 | 773 | |||||||
| * | 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:
| Millions of Dollars | |||||||||||||||||||||||
| Pension Benefits | Other Benefits | ||||||||||||||||||||||
| 2009 | 2008 | 2009 | 2008 | ||||||||||||||||||||
| U.S. | Int’l. | U.S. | Int’l. | ||||||||||||||||||||
| Change in Benefit Obligation |
|||||||||||||||||||||||
| Benefit obligation at January 1 |
$ | 4,620 | 2,307 | 4,281 | 3,085 | 768 | 792 | ||||||||||||||||
| Service cost |
194 | 79 | 186 | 100 | 9 | 11 | |||||||||||||||||
| Interest cost |
277 | 144 | 247 | 198 | 47 | 47 | |||||||||||||||||
| Plan participant contributions |
— | 8 | — | 10 | 22 | 32 | |||||||||||||||||
| Medicare Part D subsidy |
— | — | — | — | 1 | 8 | |||||||||||||||||
| Plan amendments |
— | — | 8 | — | — | (47 | ) | ||||||||||||||||
| Actuarial (gain) loss |
456 | 366 | 230 | (180 | ) | 63 | 18 | ||||||||||||||||
| Acquisitions |
— | — | — | — | — | — | |||||||||||||||||
| Divestitures |
— | — | — | — | — | — | |||||||||||||||||
| Benefits paid |
(505 | ) | (103 | ) | (332 | ) | (117 | ) | (75 | ) | (85 | ) | |||||||||||
| Curtailment |
— | — | — | — | — | — | |||||||||||||||||
| Recognition of termination benefits |
— | 5 | — | 2 | — | — | |||||||||||||||||
| Foreign currency exchange rate change |
— | 295 | — | (791 | ) | 4 | (8 | ) | |||||||||||||||
| Benefit obligation at December 31* |
$ | 5,042 | 3,101 | 4,620 | 2,307 | 839 | 768 | ||||||||||||||||
| *Accumulatedbenefit obligation portion of above at December 31: |
$ | 3,874 | 2,595 | 4,022 | 1,946 | ||||||||||||||||||
| Change in Fair Value of Plan Assets |
|||||||||||||||||||||||
| Fair value of plan assets at January 1 |
$ | 2,373 | 1,728 | 3,138 | 2,601 | 2 | 3 | ||||||||||||||||
| Acquisitions |
— | — | — | — | — | — | |||||||||||||||||
| Divestitures |
— | — | — | — | — | — | |||||||||||||||||
| Actual return on plan assets |
574 | 245 | (840 | ) | (342 | ) | — | (1 | ) | ||||||||||||||
| Company contributions |
702 | 159 | 407 | 170 | 50 | 45 | |||||||||||||||||
| Plan participant contributions |
— | 8 | — | 10 | 22 | 32 | |||||||||||||||||
| Medicare Part D subsidy |
— | — | — | — | 1 | 8 | |||||||||||||||||
| Benefits paid |
(505 | ) | (103 | ) | (332 | ) | (117 | ) | (75 | ) | (85 | ) | |||||||||||
| Foreign currency exchange rate change |
— | 244 | — | (594 | ) | — | — | ||||||||||||||||
| Fair value of plan assets at December 31: |
$ | 3,144 | 2,281 | 2,373 | 1,728 | — | 2 | ||||||||||||||||
| Funded Status |
$ | (1,898 | ) | (820 | ) | (2,247 | ) | (579 | ) | (839 | ) | (766 | ) | ||||||||||
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| Millions of Dollars | |||||||||||||||||||||||
| Pension Benefits | Other Benefits | ||||||||||||||||||||||
| 2009 | 2008 | 2009 | 2008 | ||||||||||||||||||||
| U.S. | Int’l. | U.S. | Int’l. | ||||||||||||||||||||
| Amounts Recognized in the Consolidated Balance Sheet at December 31 |
|||||||||||||||||||||||
| Noncurrent assets |
$ | — | 96 | — | 33 | — | — | ||||||||||||||||
| Current liabilities |
(6 | ) | (12 | ) | (6 | ) | (9 | ) | (60 | ) | (49 | ) | |||||||||||
| Noncurrent liabilities |
(1,892 | ) | (904 | ) | (2,241 | ) | (603 | ) | (779 | ) | (717 | ) | |||||||||||
| Total recognized |
$ | (1,898 | ) | (820 | ) | (2,247 | ) | (579 | ) | (839 | ) | (766 | ) | ||||||||||
| Weighted-Average Assumptions Used to Determine Benefit Obligations at December 31 |
|||||||||||||||||||||||
| Discount rate |
5.35 | % | 5.80 | 6.25 | 6.00 | 5.60 | 6.30 | ||||||||||||||||
| Rate of compensation increase |
4.00 | 4.50 | 4.00 | 4.20 | — | — | |||||||||||||||||
| Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31 |
|||||||||||||||||||||||
| Discount rate |
6.25 | % | 6.00 | 6.00 | 5.90 | 6.30 | 6.20 | ||||||||||||||||
| Expected return on plan assets |
7.00 | 6.60 | 7.00 | 6.80 | 7.00 | 7.00 | |||||||||||||||||
| Rate of compensation increase |
4.00 | 4.20 | 4.00 | 4.80 | — | — | |||||||||||||||||
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.
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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:
| Millions of Dollars | |||||||||||||||||||||||
| Pension Benefits | Other Benefits | ||||||||||||||||||||||
| 2009 | 2008 | 2009 | 2008 | ||||||||||||||||||||
| U.S. | Int’l. | U.S. | Int’l. | ||||||||||||||||||||
| Unrecognized net actuarial loss (gain) |
$ | 1,664 | 574 | 1,798 | 335 | (72 | ) | (149 | ) | ||||||||||||||
| Unrecognized prior service cost |
58 | (24 | ) | 69 | (22 | ) | (51 | ) | (43 | ) | |||||||||||||
| Millions of Dollars | |||||||||||||||||||||||
| Pension Benefits | Other Benefits | ||||||||||||||||||||||
| 2009 | 2008 | 2009 | 2008 | ||||||||||||||||||||
| U.S. | Int’l. | U.S. | Int’l. | ||||||||||||||||||||
| Sources of Change in Other Comprehensive Income |
|||||||||||||||||||||||
| Net gain (loss) arising during the period |
$ | (52 | ) | (274 | ) | (1,275 | ) | (229 | ) | (62 | ) | (19 | ) | ||||||||||
| Amortization of (gain) loss included in income |
186 | 35 | 64 | 17 | (15 | ) | (17 | ) | |||||||||||||||
| Net gain (loss) during the period |
$ | 134 | (239 | ) | (1,211 | ) | (212 | ) | (77 | ) | (36 | ) | |||||||||||
| Prior service cost arising during the period |
$ | — | 1 | (8 | ) | (9 | ) | (1 | ) | 47 | |||||||||||||
| Amortization of prior service cost included in income |
11 | 1 | 10 | 1 | 9 | 11 | |||||||||||||||||
| Net prior service cost during the period |
$ | 11 | 2 | 2 | (8 | ) | 8 | 58 | |||||||||||||||
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 | Other Benefits | |||||||||
| U.S. | Int’l. | |||||||||
| Unrecognized net actuarial loss (gain) |
$ | 167 | 57 | (7 | ) | |||||
| Unrecognized prior service cost |
10 | 1 | 3 | |||||||
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.
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The components of net periodic benefit cost of all defined benefit plans are presented in the following table:
| Millions of Dollars | ||||||||||||||||||||||||||||||||||
| Pension Benefits | Other Benefits | |||||||||||||||||||||||||||||||||
| 2009 | 2008 | 2007 | 2009 | 2008 | 2007 | |||||||||||||||||||||||||||||
| U.S. | Int’l. | U.S. | Int’l. | U.S. | Int’l. | |||||||||||||||||||||||||||||
| Components of Net Periodic Benefit Cost |
||||||||||||||||||||||||||||||||||
| Service cost |
$ | 194 | 79 | 186 | 85 | 175 | 98 | 9 | 11 | 14 | ||||||||||||||||||||||||
| Interest cost |
277 | 144 | 247 | 170 | 229 | 161 | 47 | 47 | 45 | |||||||||||||||||||||||||
| Expected return on plan assets |
(184 | ) | (125 | ) | (223 | ) | (170 | ) | (204 | ) | (147 | ) | — | — | — | |||||||||||||||||||
| Amortization of prior service cost |
11 | 1 | 10 | 1 | 10 | 7 | 9 | 11 | 13 | |||||||||||||||||||||||||
| Recognized net actuarial loss (gain) |
186 | 35 | 64 | 17 | 62 | 48 | (15 | ) | (17 | ) | (20 | ) | ||||||||||||||||||||||
| Net periodic benefit cost |
$ | 484 | 134 | 284 | 103 | 272 | 167 | 50 | 52 | 52 | ||||||||||||||||||||||||
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 | (1 | ) | ||||
| Effect on the postretirement benefit obligation |
6 | (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.
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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.
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The fair values of our pension plan assets at December 31, 2009, by asset class are as follows:
| Level 1 | Level 2 | Level 3 | Total | ||||||
| Cash and cash equivalents |
$ | 23 | 11 | — | 34 | ||||
| Diversified equity securities |
|||||||||
| United States |
1,077 | — | — | 1,077 | |||||
| International |
808 | — | — | 808 | |||||
| Government debt securities |
|||||||||
| United States |
120 | — | — | 120 | |||||
| International |
222 | 48 | — | 270 | |||||
| Diversified corporate debt securities |
|||||||||
| United States |
— | 329 | 6 | 335 | |||||
| International |
— | 339 | — | 339 | |||||
| Mortgage-backed securities |
— | 107 | — | 107 | |||||
| Common/collective trusts |
— | 1,713 | — | 1,713 | |||||
| Mutual funds |
432 | — | — | 432 | |||||
| Derivatives |
— | 12 | — | 12 | |||||
| Private equity funds |
— | — | 12 | 12 | |||||
| Insurance contracts |
— | — | 16 | 16 | |||||
| Preferred stock |
3 | — | — | 3 | |||||
| Real estate |
— | — | 67 | 67 | |||||
| Total* |
$ | 2,685 | 2,559 | 101 | 5,345 | ||||
| * | 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:
| Corporate Debt Securities |
Private Equity Funds |
Insurance Contracts |
Real Estate |
Total | |||||||||||
| Balance, beginning of year |
$ | 8 | 14 | 15 | 79 | 116 | |||||||||
| Return on plan assets |
(1 | ) | (3 | ) | 1 | (9 | ) | (12 | ) | ||||||
| Purchases, sales and settlements |
(1 | ) | 1 | — | (3 | ) | (3 | ) | |||||||
| Balance, end of year |
$ | 6 | 12 | 16 | 67 | 101 | |||||||||
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.
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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:
| Millions of Dollars | |||||||||||
| Pension Benefits | Other Benefits | ||||||||||
| U.S. | Int’l. | ||||||||||
| 2010 |
$ | 378 | 95 | 51 | |||||||
| 2011 |
397 | 99 | 54 | ||||||||
| 2012 |
488 | 104 | 57 | ||||||||
| 2013 |
466 | 111 | 60 | ||||||||
| 2014 |
510 | 116 | 63 | ||||||||
| 2015-2019 |
2,872 | 693 | 350 | ||||||||
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:
| Millions of Dollars | ||||||
| 2009 | 2008 | |||||
| Beginning balance |
$ | 162 | — | |||
| Accruals |
5 | 162 | ||||
| Benefit payments |
(75 | ) | — | |||
| Accrual reversals |
(80 | ) | — | |||
| Ending balance |
$ | 12 | 162 | |||
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
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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:
| 2009 | 2008 | |||
| Unallocated shares |
5,364,887 | 7,208,150 | ||
| Allocated shares |
19,008,169 | 18,000,395 | ||
| Total shares |
24,373,056 | 25,208,545 | ||
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.
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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 | |||||||
| 2009 | 2008 | 2007 | |||||
| Compensation cost |
$ | 121 | 193 | 242 | |||
| Tax benefit |
42 | 67 | 85 | ||||
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.
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The following summarizes our stock option activity for the three years ended December 31, 2009:
| Options | Weighted- Average Exercise Price |
Weighted-Average Grant-Date Fair Value |
Millions of Dollars | |||||||||||||||
| Aggregate Intrinsic Value | ||||||||||||||||||
| Outstanding at December 31, 2006 |
54,048,779 | $ | 29.31 | |||||||||||||||
| Granted |
2,530,648 | 66.37 | $ | 17.86 | ||||||||||||||
| Exercised |
(12,176,988 | ) | 26.29 | $ | 926 | |||||||||||||
| Forfeited |
(268,177 | ) | 65.02 | |||||||||||||||
| Expired or canceled |
(29,407 | ) | 17.00 | |||||||||||||||
| Outstanding at December 31, 2007 |
44,104,855 | $ | 32.06 | |||||||||||||||
| Granted |
2,211,202 | 79.35 | $ | 18.66 | ||||||||||||||
| Exercised |
(9,493,818 | ) | 28.39 | $ | 535 | |||||||||||||
| Forfeited |
(184,148 | ) | 73.91 | |||||||||||||||
| Expired or canceled |
(22,338 | ) | 42.65 | |||||||||||||||
| Outstanding at December 31, 2008 |
36,615,753 | $ | 35.65 | |||||||||||||||
| Granted |
3,311,200 | 45.47 | $ | 11.18 | ||||||||||||||
| Exercised |
(2,919,118 | ) | 24.10 | $ | 67 | |||||||||||||
| Forfeited |
(332,941 | ) | 52.04 | |||||||||||||||
| Expired or canceled |
(241,421 | ) | 63.49 | |||||||||||||||
| Outstanding at December 31, 2009 |
36,433,473 | $ | 37.13 | |||||||||||||||
| Vested at December 31, 2009 |
33,763,309 | $ | 35.52 | $ | 607 | |||||||||||||
| Exercisable at December 31, 2009 |
31,522,673 | $ | 34.08 | $ | 599 | |||||||||||||
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:
| 2009 | 2008 | 2007 | |||||
| Assumptions used |
|||||||
| Risk-free interest rate |
2.90 | % | 3.21 | 4.77 | |||
| Dividend yield |
3.50 | % | 2.50 | 2.50 | |||
| Volatility factor |
32.90 | % | 27.78 | 26.10 | |||
| Expected life (years) |
6.53 | 5.82 | 6.70 |
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The ranges in the assumptions used were as follows:
| 2009 | 2008 | 2007 | |||||||||||||||
| High | Low | High | Low | High | Low | ||||||||||||
| Ranges used |
|||||||||||||||||
| Risk-free interest rate |
2.90 | % | 2.90 | 3.45 | 2.27 | 4.90 | 4.77 | ||||||||||
| Dividend yield |
3.50 | 3.50 | 2.50 | 2.50 | 2.50 | 2.50 | |||||||||||
| Volatility factor |
32.90 | 32.90 | 32.10 | 26.70 | 26.10 | 26.10 | |||||||||||
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:
| Stock Units | Weighted-Average Grant-Date Fair Value |
Millions of Dollars | |||||||||||
| Total Fair Value | |||||||||||||
| Outstanding at December 31, 2006 |
5,087,138 | $ | 43.75 | ||||||||||
| Granted |
1,721,521 | 65.27 | |||||||||||
| Forfeited |
(162,992 | ) | 52.57 | ||||||||||
| Issued |
(975,756 | ) | $ | 67 | |||||||||
| Outstanding at December 31, 2007 |
5,669,911 | $ | 51.28 | ||||||||||
| Granted |
1,797,803 | 77.42 | |||||||||||
| Forfeited |
(128,888 | ) | 62.82 | ||||||||||
| Issued |
(1,411,128 | ) | $ | 109 | |||||||||
| Outstanding at December 31, 2008 |
5,927,698 | $ | 61.14 | ||||||||||
| Granted |
2,910,095 | 43.41 | |||||||||||
| Forfeited |
(207,932 | ) | 51.84 | ||||||||||
| Issued |
(1,910,309 | ) | $ | 88 | |||||||||
| Outstanding at December 31, 2009 |
6,719,552 | $ | 57.08 | ||||||||||
| Not Vested at December 31, 2009 |
5,532,043 | $ | 57.21 | ||||||||||
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
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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:
| Performance Share Stock Units |
Weighted-Average Grant-Date Fair Value |
Millions of Dollars | |||||||||||
| Total Fair Value | |||||||||||||
| Outstanding at December 31, 2006 |
1,456,241 | $ | 59.08 | ||||||||||
| Granted |
1,349,475 | 66.37 | |||||||||||
| Forfeited |
(22,062 | ) | 62.45 | ||||||||||
| Issued |
(178,357 | ) | $ | 12 | |||||||||
| Outstanding at December 31, 2007 |
2,605,297 | $ | 62.49 | ||||||||||
| Granted |
1,291,453 | 79.38 | |||||||||||
| Forfeited |
(30,862 | ) | 69.24 | ||||||||||
| Issued |
(689,710 | ) | $ | 58 | |||||||||
| Outstanding at December 31, 2008 |
3,176,178 | $ | 68.13 | ||||||||||
| Granted |
659,812 | 45.47 | |||||||||||
| Forfeited |
(23,670 | ) | 65.00 | ||||||||||
| Issued |
(407,442 | ) | $ | 19 | |||||||||
| Outstanding at December 31, 2009 |
3,404,878 | $ | 64.63 | ||||||||||
| Not Vested at December 31, 2009 |
1,298,896 | $ | 32.95 | ||||||||||
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.
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The following summarizes the aggregate activity of these restricted shares and units for the three years ended December 31, 2009:
| Stock Units | Weighted-Average Grant-Date Fair Value |
Millions of Dollars | |||||||||||
| Total Fair Value | |||||||||||||
| Outstanding at December 31, 2006 |
3,602,375 | $ | 33.68 | ||||||||||
| Granted |
293,024 | 67.30 | |||||||||||
| Issued |
(227,766 | ) | $ | 17 | |||||||||
| Canceled |
(180,489 | ) | 50.39 | ||||||||||
| Outstanding at December 31, 2007 |
3,487,144 | $ | 34.41 | ||||||||||
| Granted |
237,642 | 78.59 | |||||||||||
| Issued |
(128,803 | ) | $ | 9 | |||||||||
| Canceled |
(231,963 | ) | 40.08 | ||||||||||
| Outstanding at December 31, 2008 |
3,364,020 | $ | 36.75 | ||||||||||
| Granted |
78,299 | 45.72 | |||||||||||
| Issued |
(204,160 | ) | $ | 10 | |||||||||
| Canceled |
(101,642 | ) | 52.91 | ||||||||||
| Outstanding at December 31, 2009 |
3,136,517 | $ | 35.11 | ||||||||||
| Not Vested at December 31, 2009 |
257,548 | $ | 73.01 | ||||||||||
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.
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Note 20—Income Taxes
Income taxes charged to income (loss) were:
| Millions of Dollars | ||||||||||
| 2009 | 2008 | 2007 | ||||||||
| Income Taxes |
||||||||||
| Federal |
||||||||||
| Current |
$ | 575 | 3,245 | 3,944 | ||||||
| Deferred |
52 | (227 | ) | 312 | ||||||
| Foreign |
||||||||||
| Current |
5,584 | 10,268 | 7,035 | |||||||
| Deferred |
(1,239 | ) | (312 | ) | (474 | ) | ||||
| State and local |
||||||||||
| Current |
82 | 543 | 602 | |||||||
| Deferred |
42 | (112 | ) | (38 | ) | |||||
| $ | 5,096 | 13,405 | 11,381 | |||||||
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:
| Millions of Dollars | |||||||
| 2009 | 2008 | ||||||
| Deferred Tax Liabilities |
|||||||
| Properties, plants and equipment, and intangibles |
$ | 21,281 | 20,563 | ||||
| Investment in joint ventures |
2,039 | 1,778 | |||||
| Inventory |
13 | 283 | |||||
| Partnership income deferral |
660 | 1,172 | |||||
| Other |
813 | 564 | |||||
| Total deferred tax liabilities |
24,806 | 24,360 | |||||
| Deferred Tax Assets |
|||||||
| Benefit plan accruals |
1,802 | 1,819 | |||||
| Asset retirement obligations and accrued environmental costs |
3,874 | 3,232 | |||||
| Deferred state income tax |
251 | 289 | |||||
| Other financial accruals and deferrals |
465 | 712 | |||||
| Loss and credit carryforwards |
2,105 | 1,657 | |||||
| Other |
484 | 338 | |||||
| Total deferred tax assets |
8,981 | 8,047 | |||||
| Less valuation allowance |
(1,540 | ) | (1,340 | ) | |||
| Net deferred tax assets |
7,441 | 6,707 | |||||
| Net deferred tax liabilities |
$ | 17,365 | 17,653 | ||||
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.
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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.
| Millions of Dollars | ||||||||||
| 2009 | 2008 | 2007 | ||||||||
| Balance at January 1 |
$ | 1,068 | 1,143 | 912 | ||||||
| Additions based on tax positions related to the current year |
18 | 7 | 273 | |||||||
| Additions for tax positions of prior years |
177 | 186 | 145 | |||||||
| Reductions for tax positions of prior years |
(33 | ) | (249 | ) | (168 | ) | ||||
| Settlements |
(19 | ) | (16 | ) | (15 | ) | ||||
| Lapse of statute |
(3 | ) | (3 | ) | (4 | ) | ||||
| Balance at December 31 |
$ | 1,208 | 1,068 | 1,143 | ||||||
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.
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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:
| Millions of Dollars | Percent of Pretax Income |
||||||||||||||||||||
| 2009 | 2008 | 2007 | 2009 | 2008 | 2007 | ||||||||||||||||
| Income (loss) before income taxes |
|||||||||||||||||||||
| United States |
$ | 2,456 | 10,055 | 13,945 | 24.5 | % | (285.4 | ) | 59.7 | ||||||||||||
| Foreign |
7,576 | 11,865 | 9,414 | 75.5 | (336.8 | ) | 40.3 | ||||||||||||||
| Goodwill impairment |
— | (25,443 | ) | — | — | 722.2 | — | ||||||||||||||
| $ | 10,032 | (3,523 | ) | 23,359 | 100.0 | % | 100.0 | 100.0 | |||||||||||||
| Federal statutory income tax |
$ | 3,511 | (1,233 | ) | 8,176 | 35.0 | % | 35.0 | 35.0 | ||||||||||||
| Goodwill impairment |
— | 8,905 | — | — | (252.8 | ) | — | ||||||||||||||
| Foreign taxes in excess of federal statutory rate |
1,565 | 5,670 | 3,225 | 15.6 | (160.9 | ) | 13.8 | ||||||||||||||
| Federal manufacturing deduction |
(19 | ) | (182 | ) | (250 | ) | (0.2 | ) | 5.2 | (1.1 | ) | ||||||||||
| State income tax |
81 | 280 | 367 | 0.8 | (8.0 | ) | 1.6 | ||||||||||||||
| Other |
(42 | ) | (35 | ) | (137 | ) | (0.4 | ) | 1.0 | (0.6 | ) | ||||||||||
| $ | 5,096 | 13,405 | 11,381 | 50.8 | % | (380.5 | ) | 48.7 | |||||||||||||
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.
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Note 21—Other Comprehensive Income (Loss)
The components and allocated tax effects of other comprehensive income (loss) follow:
| Millions of Dollars | ||||||||||
| Before-Tax | Tax Expense (Benefit) |
After-Tax | ||||||||
| 2009 |
||||||||||
| Defined benefit pension plans: |
||||||||||
| Prior service cost arising during the year |
$ | — | — | — | ||||||
| Reclassification adjustment for amortization of prior service cost included in net income |
21 | 14 | 7 | |||||||
| Net prior service cost |
21 | 14 | 7 | |||||||
| Net loss arising during the year |
(388 | ) | (160 | ) | (228 | ) | ||||
| Reclassification adjustment for amortization of prior net losses included in net income |
206 | 77 | 129 | |||||||
| Net actuarial loss |
(182 | ) | (83 | ) | (99 | ) | ||||
| Nonsponsored plans* |
39 | 17 | 22 | |||||||
| Foreign currency translation adjustments |
5,092 | 85 | 5,007 | |||||||
| Hedging activities |
(2 | ) | (5 | ) | 3 | |||||
| Other comprehensive income |
$ | 4,968 | 28 | 4,940 | ||||||
| 2008 |
||||||||||
| Defined benefit pension plans: |
||||||||||
| Prior service cost arising during the year |
$ | 30 | 22 | 8 | ||||||
| Reclassification adjustment for amortization of prior service cost included in net loss |
22 | 8 | 14 | |||||||
| Net prior service cost |
52 | 30 | 22 | |||||||
| Net loss arising during the year |
(1,523 | ) | (535 | ) | (988 | ) | ||||
| Reclassification adjustment for amortization of prior net losses included in net loss |
64 | 26 | 38 | |||||||
| Net actuarial loss |
(1,459 | ) | (509 | ) | (950 | ) | ||||
| Nonsponsored plans* |
(41 | ) | — | (41 | ) | |||||
| Foreign currency translation adjustments |
(5,552 | ) | (88 | ) | (5,464 | ) | ||||
| Hedging activities |
(4 | ) | (2 | ) | (2 | ) | ||||
| Other comprehensive loss |
$ | (7,004 | ) | (569 | ) | (6,435 | ) | |||
| 2007 |
||||||||||
| Defined benefit pension plans: |
||||||||||
| Prior service cost arising during the year |
$ | 65 | 20 | 45 | ||||||
| Reclassification adjustment for amortization of prior service cost included in net income |
30 | 12 | 18 | |||||||
| Net prior service cost |
95 | 32 | 63 | |||||||
| Net gain arising during the year |
222 | 67 | 155 | |||||||
| Reclassification adjustment for amortization of prior net losses included in net income |
90 | 32 | 58 | |||||||
| Net actuarial gain |
312 | 99 | 213 | |||||||
| Nonsponsored plans* |
(2 | ) | — | (2 | ) | |||||
| Foreign currency translation adjustments |
3,214 | 139 | 3,075 | |||||||
| Hedging activities |
(3 | ) | 1 | (4 | ) | |||||
| Other comprehensive income |
$ | 3,616 | 271 | 3,345 | ||||||
| *Plans | for which ConocoPhillips is not the primary obligor—primarily those administered by equity affiliates. |
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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:
| Millions of Dollars | |||||||
| 2009 | 2008 | ||||||
| Defined benefit pension liability adjustments |
$ | (1,504 | ) | (1,434 | ) | ||
| Foreign currency translation adjustments |
4,576 | (431 | ) | ||||
| Deferred net hedging loss |
(7 | ) | (10 | ) | |||
| Accumulated other comprehensive income (loss) |
$ | 3,065 | (1,875 | ) | |||
Note 22—Cash Flow Information
| Millions of Dollars | |||||||
| 2009 | 2008 | 2007 | |||||
| Noncash Investing and Financing Activities |
|||||||
| Investment in an upstream business venture through issuance of an acquisition obligation |
$ | — | — | 7,313 | |||
| Investment in a downstream business venture through contribution of noncash assets and liabilities |
— | — | 2,428 | ||||
| Increase in PP&E related to an increase in asset retirement obligations |
974 | 1,117 | 919 | ||||
| Cash Payments |
|||||||
| Interest |
$ | 998 | 858 | 1,040 | |||
| Income taxes |
6,641 | 13,122 | 11,330 | ||||
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Note 23—Other Financial Information
| Millions of Dollars Except Per Share Amounts |
||||||||||
| 2009 | 2008 | 2007 | ||||||||
| Interest and Debt Expense |
||||||||||
| Incurred |
||||||||||
| Debt |
$ | 1,485 | 1,189 | 1,369 | ||||||
| Other |
291 | 314 | 449 | |||||||
| 1,776 | 1,503 | 1,818 | ||||||||
| Capitalized |
(487 | ) | (568 | ) | (565 | ) | ||||
| Expensed |
$ | 1,289 | 935 | 1,253 | ||||||
| Other Income |
||||||||||
| Interest income |
$ | 227 | 245 | 342 | ||||||
| Gain on asset dispositions |
160 | 891 | 1,348 | |||||||
| Business interruption insurance recoveries* |
— | 2 | 52 | |||||||
| Other, net |
131 | (48 | ) | 229 | ||||||
| $ | 518 | 1,090 | 1,971 | |||||||
| *Primarilyrelated to 2005 hurricanes in the Gulf of Mexico and southern United States. |
||||||||||
| Research and Development Expenditures—expensed |
$ | 190 | 209 | 160 | ||||||
| Advertising Expenses |
$ | 60 | 96 | 84 | ||||||
| Shipping and Handling Costs* |
$ | 1,185 | 1,443 | 1,493 | ||||||
| *Amountsincluded in production and operating expenses. |
||||||||||
| Cash Dividends paid per common share |
$ | 1.91 | 1.88 | 1.64 | ||||||
| Foreign Currency Transaction Gains (Losses)—after-tax |
||||||||||
| E&P |
$ | (111 | ) | 216 | 216 | |||||
| Midstream |
— | 1 | (2 | ) | ||||||
| R&M |
36 | (173 | ) | (13 | ) | |||||
| LUKOIL Investment |
20 | (27 | ) | 5 | ||||||
| Chemicals |
— | — | — | |||||||
| Emerging Businesses |
2 | (7 | ) | 1 | ||||||
| Corporate and Other |
97 | (72 | ) | (120 | ) | |||||
| $ | 44 | (62 | ) | 87 | ||||||
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Note 24—Related Party Transactions
Significant transactions with related parties were:
| Millions of Dollars | |||||||
| 2009 | 2008 | 2007 | |||||
| Operating revenues and other income (a) |
$ | 7,200 | 13,097 | 10,949 | |||
| Purchases (b) |
12,779 | 19,409 | 15,722 | ||||
| Operating expenses and selling, general and administrative expenses (c) |
322 | 515 | 416 | ||||
| Net interest expense (d) |
74 | 66 | 99 | ||||
| (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. |
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| 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.
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Analysis of Results by Operating Segment
| Millions of Dollars | ||||||||||
| 2009 | 2008 | 2007 | ||||||||
| Sales and Other Operating Revenues |
||||||||||
| E&P |
||||||||||
| United States |
$ | 24,287 | 51,378 | 36,974 | ||||||
| International |
24,222 | 36,972 | 24,617 | |||||||
| Intersegment eliminations—U.S. |
(4,649 | ) | (8,034 | ) | (6,096 | ) | ||||
| Intersegment eliminations—international |
(6,763 | ) | (10,498 | ) | (7,341 | ) | ||||
| E&P |
37,097 | 69,818 | 48,154 | |||||||
| Midstream |
||||||||||
| Total sales |
5,199 | 6,791 | 5,106 | |||||||
| Intersegment eliminations |
(307 | ) | (227 | ) | (245 | ) | ||||
| Midstream |
4,892 | 6,564 | 4,861 | |||||||
| R&M |
||||||||||
| United States |
73,871 | 117,727 | 96,154 | |||||||
| International |
34,025 | 47,520 | 38,598 | |||||||
| Intersegment eliminations—U.S. |
(613 | ) | (965 | ) | (540 | ) | ||||
| Intersegment eliminations—international |
(50 | ) | (52 | ) | (11 | ) | ||||
| R&M |
107,233 | 164,230 | 134,201 | |||||||
| LUKOIL Investment |
— | — | — | |||||||
| Chemicals |
11 | 11 | 10 | |||||||
| Emerging Businesses |
||||||||||
| Total sales |
593 | 1,060 | 656 | |||||||
| Intersegment eliminations |
(507 | ) | (861 | ) | (458 | ) | ||||
| Emerging Businesses |
86 | 199 | 198 | |||||||
| Corporate and Other |
22 | 20 | 13 | |||||||
| Consolidated sales and other operating revenues |
$ | 149,341 | 240,842 | 187,437 | ||||||
| Depreciation, Depletion, Amortization and Impairments |
||||||||||
| E&P |
||||||||||
| United States |
$ | 3,346 | 3,725 | 3,328 | ||||||
| International |
5,459 | 5,096 | 9,121 | |||||||
| Goodwill impairment |
— | 25,443 | — | |||||||
| Total E&P |
8,805 | 34,264 | 12,449 | |||||||
| Midstream |
6 | 6 | 14 | |||||||
| R&M |
||||||||||
| United States |
707 | 1,129 | 609 | |||||||
| International |
215 | 425 | 139 | |||||||
| Total R&M |
922 | 1,554 | 748 | |||||||
| LUKOIL Investment |
— | 7,410 | — | |||||||
| Chemicals |
— | — | — | |||||||
| Emerging Businesses |
21 | 193 | 39 | |||||||
| Corporate and Other |
76 | 124 | 78 | |||||||
| Consolidated depreciation, depletion, amortization and impairments |
$ | 9,830 | 43,551 | 13,328 | ||||||
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| Millions of Dollars | ||||||||||
| 2009 | 2008 | 2007 | ||||||||
| Equity in Earnings of Affiliates |
||||||||||
| E&P |
||||||||||
| United States |
$ | (2 | ) | 57 | 11 | |||||
| International |
233 | 235 | 302 | |||||||
| Total E&P |
231 | 292 | 313 | |||||||
| Midstream |
342 | 810 | 599 | |||||||
| R&M |
||||||||||
| United States |
428 | 836 | 1,710 | |||||||
| International |
13 | 178 | 240 | |||||||
| Total R&M |
441 | 1,014 | 1,950 | |||||||
| LUKOIL Investment |
1,669 | 2,011 | * | 1,875 | ||||||
| Chemicals |
298 | 128 | 350 | |||||||
| Emerging Businesses |
— | (5 | ) | — | ||||||
| Corporate and Other |
— | — | — | |||||||
| Consolidated equity in earnings of affiliates |
$ | 2,981 | 4,250 | 5,087 | ||||||
| *Doesnot include a $7,410 million impairment of our LUKOIL investment presented as a separate line item in the consolidated statement of operations. |
| |||||||||
| Income Taxes |
||||||||||
| E&P |
||||||||||
| United States |
$ | 786 | 2,617 | 2,231 | ||||||
| International |
4,325 | 9,621 | 6,372 | |||||||
| Total E&P |
5,111 | 12,238 | 8,603 | |||||||
| Midstream |
171 | 261 | 237 | |||||||
| R&M |
||||||||||
| United States |
32 | 934 | 2,571 | |||||||
| International |
9 | 214 | 113 | |||||||
| Total R&M |
41 | 1,148 | 2,684 | |||||||
| LUKOIL Investment |
18 | 49 | 45 | |||||||
| Chemicals |
47 | 15 | (13 | ) | ||||||
| Emerging Businesses |
(16 | ) | (6 | ) | (33 | ) | ||||
| Corporate and Other |
(276 | ) | (300 | ) | (142 | ) | ||||
| Consolidated income taxes |
$ | 5,096 | 13,405 | 11,381 | ||||||
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| Millions of Dollars | ||||||||||
| 2009 | 2008 | 2007 | ||||||||
| Net Income (Loss) Attributable to ConocoPhillips |
||||||||||
| E&P |
||||||||||
| United States |
$ | 1,503 | 4,988 | 4,248 | ||||||
| International |
2,101 | 6,976 | 367 | |||||||
| Goodwill impairment |
— | (25,443 | ) | — | ||||||
| Total E&P |
3,604 | (13,479 | ) | 4,615 | ||||||
| Midstream |
313 | 541 | 453 | |||||||
| R&M |
||||||||||
| United States |
(192 | ) | 1,540 | 4,615 | ||||||
| International |
229 | 782 | 1,308 | |||||||
| Total R&M |
37 | 2,322 | 5,923 | |||||||
| LUKOIL Investment |
1,663 | (5,488 | ) | 1,818 | ||||||
| Chemicals |
248 | 110 | 359 | |||||||
| Emerging Businesses |
3 | 30 | (8 | ) | ||||||
| Corporate and Other |
(1,010 | ) | (1,034 | ) | (1,269 | ) | ||||
| Consolidated net income (loss) attributable to ConocoPhillips |
$ | 4,858 | (16,998 | ) | 11,891 | |||||
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| Millions of Dollars | |||||||
| 2009 | 2008 | 2007 | |||||
| Investments In and Advances To Affiliates |
|||||||
| E&P |
|||||||
| United States |
$ | 1,978 | 1,368 | 1,059 | |||
| International |
19,646 | 16,772 | 12,055 | ||||
| Total E&P |
21,624 | 18,140 | 13,114 | ||||
| Midstream |
1,199 | 1,033 | 1,178 | ||||
| R&M |
|||||||
| United States |
3,982 | 3,677 | 3,500 | ||||
| International |
1,142 | 1,326 | 1,091 | ||||
| Total R&M |
5,124 | 5,003 | 4,591 | ||||
| LUKOIL Investment |
6,861 | 5,452 | 11,162 | ||||
| Chemicals |
2,446 | 2,186 | 2,203 | ||||
| Emerging Businesses |
77 | 75 | 79 | ||||
| Corporate and Other |
— | — | — | ||||
| Consolidated investments in and advances to affiliates* |
$ | 37,331 | 31,889 | 32,327 | |||
| * Includes amounts classified as held for sale: |
$ | 249 | 2 | 48 | |||
| Total Assets |
|||||||
| E&P |
|||||||
| United States |
$ | 36,122 | 36,962 | 35,160 | |||
| International |
64,831 | 58,912 | 59,412 | ||||
| Goodwill |
— | — | 25,569 | ||||
| Total E&P |
100,953 | 95,874 | 120,141 | ||||
| Midstream |
2,054 | 1,455 | 2,016 | ||||
| R&M |
|||||||
| United States |
24,963 | 22,554 | 24,336 | ||||
| International |
8,446 | 7,942 | 9,766 | ||||
| Goodwill |
3,638 | 3,778 | 3,767 | ||||
| Total R&M |
37,047 | 34,274 | 37,869 | ||||
| LUKOIL Investment |
6,866 | 5,455 | 11,164 | ||||
| Chemicals |
2,451 | 2,217 | 2,225 | ||||
| Emerging Businesses |
1,069 | 924 | 1,230 | ||||
| Corporate and Other |
2,148 | 2,666 | 3,112 | ||||
| Consolidated total assets |
$ | 152,588 | 142,865 | 177,757 | |||
| Capital Expenditures and Investments |
|||||||
| E&P |
|||||||
| United States |
$ | 3,474 | 5,250 | 3,788 | |||
| International |
5,425 | 11,206 | 6,147 | ||||
| Total E&P |
8,899 | 16,456 | 9,935 | ||||
| Midstream |
5 | 4 | 5 | ||||
| R&M |
|||||||
| United States |
1,299 | 1,643 | 1,146 | ||||
| International |
427 | 626 | 240 | ||||
| Total R&M |
1,726 | 2,269 | 1,386 | ||||
| LUKOIL Investment |
— | — | — | ||||
| Chemicals |
— | — | — | ||||
| Emerging Businesses |
97 | 156 | 257 | ||||
| Corporate and Other |
134 | 214 | 208 | ||||
| Consolidated capital expenditures and investments |
$ | 10,861 | 19,099 | 11,791 | |||
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| Millions of Dollars | |||||||
| 2009 | 2008 | 2007 | |||||
| Interest Income and Expense |
|||||||
| Interest income |
|||||||
| Corporate |
$ | 89 | 128 | 246 | |||
| E&P |
91 | 115 | 96 | ||||
| R&M |
47 | 2 | — | ||||
| Interest and debt expense |
|||||||
| Corporate |
1,133 | 762 | 1,066 | ||||
| E&P |
156 | 173 | 187 | ||||
Geographic Information
| Millions of Dollars | |||||||||||||||
| Sales and Other Operating Revenues* |
Long-Lived Assets** | ||||||||||||||
| 2009 | 2008 | 2007 | 2009 | 2008 | 2007 | ||||||||||
| United States |
$ | 97,674 | 166,496 | 131,433 | 53,761 | 52,972 | 50,714 | ||||||||
| Australia*** |
2,229 | 2,735 | 1,633 | 10,729 | 8,656 | 3,420 | |||||||||
| Canada |
3,617 | 5,226 | 4,727 | 22,451 | 20,429 | 24,758 | |||||||||
| Norway |
1,749 | 3,036 | 2,479 | 5,797 | 5,002 | 6,180 | |||||||||
| Russia |
— | — | — | 8,833 | 7,604 | 13,359 | |||||||||
| United Kingdom |
20,671 | 29,699 | 20,680 | 5,778 | 5,844 | 7,995 | |||||||||
| Other foreign countries |
23,401 | 33,650 | 26,485 | 17,441 | 15,919 | 14,904 | |||||||||
| Worldwide consolidated |
$ | 149,341 | 240,842 | 187,437 | 124,790 | 116,426 | 121,330 | ||||||||
| *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.
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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.
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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.
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Proved Reserves
| Years Ended |
Crude Oil and Natural Gas Liquids | |||||||||||||||||||||||||||||
| December 31 | Millions of Barrels | |||||||||||||||||||||||||||||
| Alaska | Lower 48 |
Total U.S. |
Canada | Europe | Russia | Asia Pacific/ Middle East |
Africa | Other Areas |
Total | |||||||||||||||||||||
| Developed and Undeveloped |
||||||||||||||||||||||||||||||
| Consolidated operations |
||||||||||||||||||||||||||||||
| End of 2006 |
1,495 | 745 | 2,240 | 134 | 705 | — | 372 | 316 | 149 | 3,916 | ||||||||||||||||||||
| Revisions |
25 | 50 | 75 | (3 | ) | 10 | — | (25 | ) | (13 | ) | (2 | ) | 42 | ||||||||||||||||
| Improved recovery |
25 | 16 | 41 | — | — | — | — | — | — | 41 | ||||||||||||||||||||
| Purchases |
— | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||
| Extensions and discoveries |
26 | 27 | 53 | 5 | 9 | — | 76 | 16 | — | 159 | ||||||||||||||||||||
| Production |
(103 | ) | (63 | ) | (166 | ) | (17 | ) | (80 | ) | — | (39 | ) | (28 | ) | (4 | ) | (334 | ) | |||||||||||
| Sales |
— | (1 | ) | (1 | ) | (18 | ) | (1 | ) | — | (9 | ) | — | (17 | ) | (46 | ) | |||||||||||||
| End of 2007 |
1,468 | 774 | 2,242 | 101 | 643 | — | 375 | 291 | 126 | 3,778 | ||||||||||||||||||||
| Revisions |
(206 | ) | (17 | ) | (223 | ) | 4 | (16 | ) | — | 15 | 15 | 9 | (196 | ) | |||||||||||||||
| Improved recovery |
23 | 5 | 28 | — | — | — | — | — | — | 28 | ||||||||||||||||||||
| Purchases |
— | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||
| Extensions and discoveries |
13 | 25 | 38 | 4 | 9 | — | 13 | 5 | — | 69 | ||||||||||||||||||||
| Production |
(96 | ) | (61 | ) | (157 | ) | (16 | ) | (84 | ) | — | (39 | ) | (29 | ) | (3 | ) | (328 | ) | |||||||||||
| Sales |
— | — | — | — | — | — | — | — | (11 | ) | (11 | ) | ||||||||||||||||||
| End of 2008 |
1,202 | 726 | 1,928 | 93 | 552 | — | 364 | 282 | 121 | 3,340 | ||||||||||||||||||||
| Revisions |
84 | 1 | 85 | — | 29 | — | (12 | ) | 10 | (8 | ) | 104 | ||||||||||||||||||
| Improved recovery |
13 | 2 | 15 | — | — | — | 2 | — | — | 17 | ||||||||||||||||||||
| Purchases |
— | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||
| Extensions and discoveries |
14 | 17 | 31 | 3 | 7 | — | 26 | 3 | — | 70 | ||||||||||||||||||||
| Production |
(93 | ) | (60 | ) | (153 | ) | (15 | ) | (87 | ) | — | (48 | ) | (28 | ) | — | (331 | ) | ||||||||||||
| Sales |
— | (1 | ) | (1 | ) | — | — | — | — | — | (5 | ) | (6 | ) | ||||||||||||||||
| End of 2009 |
1,220 | 685 | 1,905 | 81 | 501 | — | 332 | 267 | 108 | 3,194 | ||||||||||||||||||||
| Equity affiliates |
||||||||||||||||||||||||||||||
| End of 2006 |
— | — | — | — | — | 1,607 | 92 | — | 1,023 | 2,722 | ||||||||||||||||||||
| Revisions |
— | — | — | — | — | 217 | — | — | — | 217 | ||||||||||||||||||||
| Improved recovery |
— | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||
| Purchases |
— | — | — | — | — | 5 | — | — | — | 5 | ||||||||||||||||||||
| Extensions and discoveries |
— | — | — | — | — | 63 | 17 | — | — | 80 | ||||||||||||||||||||
| Production |
— | — | — | — | — | (147 | ) | — | — | (15 | ) | (162 | ) | |||||||||||||||||
| Sales |
— | — | — | — | — | (20 | ) | — | — | (1,008 | ) | (1,028 | ) | |||||||||||||||||
| End of 2007 |
— | — | — | — | — | 1,725 | 109 | — | — | 1,834 | ||||||||||||||||||||
| Revisions |
— | — | — | — | — | (36 | ) | — | — | — | (36 | ) | ||||||||||||||||||
| Improved recovery |
— | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||
| Purchases |
— | — | — | — | — | 2 | — | — | — | 2 | ||||||||||||||||||||
| Extensions and discoveries |
— | — | — | — | — | 71 | — | — | — | 71 | ||||||||||||||||||||
| Production |
— | — | — | — | — | (153 | ) | — | — | — | (153 | ) | ||||||||||||||||||
| Sales |
— | — | — | — | — | (41 | ) | — | — | — | (41 | ) | ||||||||||||||||||
| End of 2008 |
— | — | — | — | — | 1,568 | 109 | — | — | 1,677 | ||||||||||||||||||||
| Revisions |
— | — | — | — | — | 33 | (3 | ) | — | — | 30 | |||||||||||||||||||
| Improved recovery |
— | — | — | — | — | 54 | — | — | — | 54 | ||||||||||||||||||||
| Purchases |
— | — | — | — | — | 21 | — | — | — | 21 | ||||||||||||||||||||
| Extensions and discoveries |
— | — | — | — | — | 94 | — | — | — | 94 | ||||||||||||||||||||
| Production |
— | — | — | — | — | (166 | ) | — | — | — | (166 | ) | ||||||||||||||||||
| Sales |
— | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||
| End of 2009 |
— | — | — | — | — | 1,604 | 106 | — | — | 1,710 | ||||||||||||||||||||
| Total company |
||||||||||||||||||||||||||||||
| End of 2006 |
1,495 | 745 | 2,240 | 134 | 705 | 1,607 | 464 | 316 | 1,172 | 6,638 | ||||||||||||||||||||
| End of 2007 |
1,468 | 774 | 2,242 | 101 | 643 | 1,725 | 484 | 291 | 126 | 5,612 | ||||||||||||||||||||
| End of 2008 |
1,202 | 726 | 1,928 | 93 | 552 | 1,568 | 473 | 282 | 121 | 5,017 | ||||||||||||||||||||
| End of 2009 |
1,220 | 685 | 1,905 | 81 | 501 | 1,604 | 438 | 267 | 108 | 4,904 | ||||||||||||||||||||
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| Years Ended |
Crude Oil and Natural Gas Liquids | |||||||||||||||||||
| December 31 | Millions of Barrels | |||||||||||||||||||
| Alaska | Lower 48 |
Total U.S. |
Canada | Europe | Russia | Asia Pacific/ Middle East |
Africa | Other Areas |
Total | |||||||||||
| Developed |
||||||||||||||||||||
| Consolidated operations |
||||||||||||||||||||
| End of 2006 |
1,393 | 627 | 2,020 | 114 | 387 | — | 239 | 292 | 13 | 3,065 | ||||||||||
| End of 2007 |
1,371 | 624 | 1,995 | 87 | 370 | — | 200 | 260 | 9 | 2,921 | ||||||||||
| End of 2008 |
1,104 | 572 | 1,676 | 85 | 342 | — | 217 | 264 | 6 | 2,590 | ||||||||||
| End of 2009 |
1,130 | 558 | 1,688 | 77 | 312 | — | 221 | 246 | — | 2,544 | ||||||||||
| Equity affiliates |
||||||||||||||||||||
| End of 2006 |
— | — | — | — | — | 1,293 | — | — | 369 | 1,662 | ||||||||||
| End of 2007 |
— | — | — | — | — | 1,354 | — | — | — | 1,354 | ||||||||||
| End of 2008 |
— | — | — | — | — | 1,228 | — | — | — | 1,228 | ||||||||||
| End of 2009 |
— | — | — | — | — | 1,213 | — | — | — | 1,213 | ||||||||||
| Undeveloped |
||||||||||||||||||||
| Consolidated operations |
||||||||||||||||||||
| End of 2006 |
102 | 118 | 220 | 20 | 318 | — | 133 | 24 | 136 | 851 | ||||||||||
| End of 2007 |
97 | 150 | 247 | 14 | 273 | — | 175 | 31 | 117 | 857 | ||||||||||
| End of 2008 |
98 | 154 | 252 | 8 | 210 | — | 147 | 18 | 115 | 750 | ||||||||||
| End of 2009 |
90 | 127 | 217 | 4 | 189 | — | 111 | 21 | 108 | 650 | ||||||||||
| Equity affiliates |
||||||||||||||||||||
| End of 2006 |
— | — | — | — | — | 314 | 92 | — | 654 | 1,060 | ||||||||||
| End of 2007 |
— | — | — | — | — | 371 | 109 | — | — | 480 | ||||||||||
| End of 2008 |
— | — | — | — | — | 340 | 109 | — | — | 449 | ||||||||||
| End of 2009 |
— | — | — | — | — | 391 | 106 | — | — | 497 | ||||||||||
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. |
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| Years Ended |
Natural Gas | |||||||||||||||||||||||||||||
| December 31 | Billions of Cubic Feet | |||||||||||||||||||||||||||||
| Alaska | Lower 48 |
Total U.S. |
Canada | Europe | Russia | Asia Pacific/ Middle East |
Africa | Other Areas |
Total | |||||||||||||||||||||
| Developed and Undeveloped |
||||||||||||||||||||||||||||||
| Consolidated operations |
||||||||||||||||||||||||||||||
| End of 2006 |
3,414 | 9,027 | 12,441 | 3,310 | 2,852 | — | 3,570 | 1,086 | 187 | 23,446 | ||||||||||||||||||||
| Revisions |
120 | 446 | 566 | (41 | ) | 91 | — | (47 | ) | (26 | ) | (12 | ) | 531 | ||||||||||||||||
| Improved recovery |
5 | 1 | 6 | — | — | — | — | — | — | 6 | ||||||||||||||||||||
| Purchases |
— | 30 | 30 | — | — | — | — | — | — | 30 | ||||||||||||||||||||
| Extensions and discoveries |
5 | 539 | 544 | 143 | 29 | — | 28 | 23 | — | 767 | ||||||||||||||||||||
| Production |
(113 | ) | (835 | ) | (948 | ) | (404 | ) | (369 | ) | — | (226 | ) | (53 | ) | (7 | ) | (2,007 | ) | |||||||||||
| Sales |
— | (5 | ) | (5 | ) | (170 | ) | (20 | ) | — | (74 | ) | — | (5 | ) | (274 | ) | |||||||||||||
| End of 2007 |
3,431 | 9,203 | 12,634 | 2,838 | 2,583 | — | 3,251 | 1,030 | 163 | 22,499 | ||||||||||||||||||||
| Revisions |
(852 | ) | (270 | ) | (1,122 | ) | 45 | 119 | — | 249 | 19 | (1 | ) | (691 | ) | |||||||||||||||
| Improved recovery |
15 | 2 | 17 | — | — | — | — | — | — | 17 | ||||||||||||||||||||
| Purchases |
— | 13 | 13 | — | — | — | — | — | — | 13 | ||||||||||||||||||||
| Extensions and discoveries |
2 | 273 | 275 | 118 | 45 | — | 3 | — | — | 441 | ||||||||||||||||||||
| Production |
(108 | ) | (788 | ) | (896 | ) | (385 | ) | (391 | ) | — | (249 | ) | (51 | ) | (5 | ) | (1,977 | ) | |||||||||||
| Sales |
— | (1 | ) | (1 | ) | (2 | ) | (53 | ) | — | (17 | ) | — | (69 | ) | (142 | ) | |||||||||||||
| End of 2008 |
2,488 | 8,432 | 10,920 | 2,614 | 2,303 | — | 3,237 | 998 | 88 | 20,160 | ||||||||||||||||||||
| Revisions |
400 | 126 | 526 | (23 | ) | 19 | — | (94 | ) | (2 | ) | (32 | ) | 394 | ||||||||||||||||
| Improved recovery |
3 | — | 3 | — | — | — | — | — | — | 3 | ||||||||||||||||||||
| Purchases |
— | — | — | 2 | — | — | — | — | — | 2 | ||||||||||||||||||||
| Extensions and discoveries |
— | 146 | 146 | 95 | 24 | — | 54 | — | — | 319 | ||||||||||||||||||||
| Production |
(111 | ) | (739 | ) | (850 | ) | (388 | ) | (337 | ) | — | (285 | ) | (46 | ) | — | (1,906 | ) | ||||||||||||
| Sales |
— | (3 | ) | (3 | ) | (4 | ) | — | — | — | — | — | (7 | ) | ||||||||||||||||
| End of 2009 |
2,780 | 7,962 | 10,742 | 2,296 | 2,009 | — | 2,912 | 950 | 56 | 18,965 | ||||||||||||||||||||
| Equity affiliates |
||||||||||||||||||||||||||||||
| End of 2006 |
— | — | — | — | — | 1,429 | 1,573 | — | 387 | 3,389 | ||||||||||||||||||||
| Revisions |
— | — | — | — | — | (328 | ) | 1 | — | — | (327 | ) | ||||||||||||||||||
| Improved recovery |
— | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||
| Purchases |
— | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||
| Extensions and discoveries |
— | — | — | — | — | 13 | 351 | — | — | 364 | ||||||||||||||||||||
| Production |
— | — | — | — | — | (100 | ) | — | — | (3 | ) | (103 | ) | |||||||||||||||||
| Sales |
— | — | — | — | — | — | — | — | (384 | ) | (384 | ) | ||||||||||||||||||
| End of 2007 |
— | — | — | — | — | 1,014 | 1,925 | — | — | 2,939 | ||||||||||||||||||||
| Revisions |
— | — | — | — | — | 1,394 | — | — | — | 1,394 | ||||||||||||||||||||
| Improved recovery |
— | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||
| Purchases |
— | — | — | — | — | — | 598 | — | — | 598 | ||||||||||||||||||||
| Extensions and discoveries |
— | — | — | — | — | 37 | — | — | — | 37 | ||||||||||||||||||||
| Production |
— | — | — | — | — | (114 | ) | (4 | ) | — | — | (118 | ) | |||||||||||||||||
| Sales |
— | — | — | — | — | (62 | ) | — | — | — | (62 | ) | ||||||||||||||||||
| End of 2008 |
— | — | — | — | — | 2,269 | 2,519 | — | — | 4,788 | ||||||||||||||||||||
| Revisions |
— | — | — | — | — | 436 | (203 | ) | — | — | 233 | |||||||||||||||||||
| Improved recovery |
— | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||
| Purchases |
— | — | — | — | — | 25 | — | — | — | 25 | ||||||||||||||||||||
| Extensions and discoveries |
— | — | — | — | — | 89 | 294 | — | — | 383 | ||||||||||||||||||||
| Production |
— | — | — | — | — | (114 | ) | (33 | ) | — | — | (147 | ) | |||||||||||||||||
| Sales |
— | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||
| End of 2009 |
— | — | — | — | — | 2,705 | 2,577 | — | — | 5,282 | ||||||||||||||||||||
| Total company |
||||||||||||||||||||||||||||||
| End of 2006 |
3,414 | 9,027 | 12,441 | 3,310 | 2,852 | 1,429 | 5,143 | 1,086 | 574 | 26,835 | ||||||||||||||||||||
| End of 2007 |
3,431 | 9,203 | 12,634 | 2,838 | 2,583 | 1,014 | 5,176 | 1,030 | 163 | 25,438 | ||||||||||||||||||||
| End of 2008 |
2,488 | 8,432 | 10,920 | 2,614 | 2,303 | 2,269 | 5,756 | 998 | 88 | 24,948 | ||||||||||||||||||||
| End of 2009 |
2,780 | 7,962 | 10,742 | 2,296 | 2,009 | 2,705 | 5,489 | 950 | 56 | 24,247 | ||||||||||||||||||||
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| Years Ended |
Natural Gas | |||||||||||||||||||
| December 31 | Billions of Cubic Feet | |||||||||||||||||||
| Alaska | Lower 48 |
Total U.S. |
Canada | Europe | Russia | Asia Pacific/ Middle East |
Africa | Other Areas |
Total | |||||||||||
| Developed |
||||||||||||||||||||
| Consolidated operations |
||||||||||||||||||||
| End of 2006 |
3,336 | 7,484 | 10,820 | 2,672 | 2,314 | — | 3,106 | 1,028 | 24 | 19,964 | ||||||||||
| End of 2007 |
3,344 | 7,417 | 10,761 | 2,328 | 2,177 | — | 2,857 | 963 | 26 | 19,112 | ||||||||||
| End of 2008 |
2,413 | 6,875 | 9,288 | 2,272 | 2,036 | — | 2,877 | 936 | — | 17,409 | ||||||||||
| End of 2009 |
2,744 | 6,633 | 9,377 | 2,173 | 1,772 | — | 2,537 | 889 | — | 16,748 | ||||||||||
| Equity affiliates |
||||||||||||||||||||
| End of 2006 |
— | — | — | — | — | 655 | — | — | 173 | 828 | ||||||||||
| End of 2007 |
— | — | — | — | — | 698 | — | — | — | 698 | ||||||||||
| End of 2008 |
— | — | — | — | — | 1,458 | 361 | — | — | 1,819 | ||||||||||
| End of 2009 |
— | — | — | — | — | 1,506 | 307 | — | — | 1,813 | ||||||||||
| Undeveloped |
||||||||||||||||||||
| Consolidated operations |
||||||||||||||||||||
| End of 2006 |
78 | 1,543 | 1,621 | 638 | 538 | — | 464 | 58 | 163 | 3,482 | ||||||||||
| End of 2007 |
87 | 1,786 | 1,873 | 510 | 406 | — | 394 | 67 | 137 | 3,387 | ||||||||||
| End of 2008 |
75 | 1,557 | 1,632 | 342 | 267 | — | 360 | 62 | 88 | 2,751 | ||||||||||
| End of 2009 |
36 | 1,329 | 1,365 | 123 | 237 | — | 375 | 61 | 56 | 2,217 | ||||||||||
| Equity affiliates |
||||||||||||||||||||
| End of 2006 |
— | — | — | — | — | 774 | 1,573 | — | 214 | 2,561 | ||||||||||
| End of 2007 |
— | — | — | — | — | 316 | 1,925 | — | — | 2,241 | ||||||||||
| End of 2008 |
— | — | — | — | — | 811 | 2,158 | — | — | 2,969 | ||||||||||
| End of 2009 |
— | — | — | — | — | 1,199 | 2,270 | — | — | 3,469 | ||||||||||
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. |
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| Years Ended December 31 |
Other Products | |||||||
| Millions of Barrels | ||||||||
| Synthetic Oil | Bitumen | |||||||
| Canada | Canada | |||||||
| Developed and Undeveloped |
||||||||
| Consolidated operations |
||||||||
| End of 2006 |
— | 58 | ||||||
| Revisions |
— | 27 | ||||||
| Improved recovery |
— | — | ||||||
| Purchases |
— | — | ||||||
| Extensions and discoveries |
— | — | ||||||
| Production |
— | — | ||||||
| Sales |
— | — | ||||||
| End of 2007 |
— | 85 | ||||||
| Revisions |
— | 17 | ||||||
| Improved recovery |
— | — | ||||||
| Purchases |
— | — | ||||||
| Extensions and discoveries |
— | — | ||||||
| Production |
— | (2 | ) | |||||
| Sales |
— | — | ||||||
| End of 2008 |
— | 100 | ||||||
| Revisions |
256 | 152 | ||||||
| Improved recovery |
— | — | ||||||
| Purchases |
— | — | ||||||
| Extensions and discoveries |
— | 167 | ||||||
| Production |
(8 | ) | (2 | ) | ||||
| Sales |
— | — | ||||||
| End of 2009 |
248 | 417 | ||||||
| Equity affiliates |
||||||||
| End of 2006 |
— | — | ||||||
| Revisions |
— | 5 | ||||||
| Improved recovery |
— | — | ||||||
| Purchases |
— | 398 | ||||||
| Extensions and discoveries |
— | 230 | ||||||
| Production |
— | (10 | ) | |||||
| Sales |
— | — | ||||||
| End of 2007 |
— | 623 | ||||||
| Revisions |
— | 70 | ||||||
| Improved recovery |
— | — | ||||||
| Purchases |
— | — | ||||||
| Extensions and discoveries |
— | 18 | ||||||
| Production |
— | (11 | ) | |||||
| Sales |
— | — | ||||||
| End of 2008 |
— | 700 | ||||||
| Revisions |
— | (87 | ) | |||||
| Improved recovery |
— | — | ||||||
| Purchases |
— | — | ||||||
| Extensions and discoveries |
— | 118 | ||||||
| Production |
— | (15 | ) | |||||
| Sales |
— | — | ||||||
| End of 2009 |
— | 716 | ||||||
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| Years Ended December 31 |
Other Products | |||||
| Millions of Barrels | ||||||
| Synthetic Oil | Bitumen | |||||
| Canada | Canada | |||||
| Total company |
||||||
| End of 2006 |
— | 58 | ||||
| End of 2007 |
— | 708 | ||||
| End of 2008 |
— | 800 | ||||
| End of 2009 |
248 | 1,133 | ||||
| Developed |
||||||
| Consolidated operations |
||||||
| End of 2006 |
— | — | ||||
| End of 2007 |
— | 17 | ||||
| End of 2008 |
— | 24 | ||||
| End of 2009 |
248 | 24 | ||||
| Equity affiliates |
||||||
| End of 2006 |
— | — | ||||
| End of 2007 |
— | 45 | ||||
| End of 2008 |
— | 105 | ||||
| End of 2009 |
— | 116 | ||||
| Undeveloped |
||||||
| Consolidated operations |
||||||
| End of 2006 |
— | 58 | ||||
| End of 2007 |
— | 68 | ||||
| End of 2008 |
— | 76 | ||||
| End of 2009 |
— | 393 | ||||
| Equity affiliates |
||||||
| End of 2006 |
— | — | ||||
| End of 2007 |
— | 578 | ||||
| End of 2008 |
— | 595 | ||||
| End of 2009 |
— | 600 | ||||
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. |
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| Years Ended December 31 |
Total Proved Reserves | |||||||||||||||||||||||||||||
| Millions of Barrels of Oil Equivalent | ||||||||||||||||||||||||||||||
| Alaska | Lower 48 |
Total U.S. |
Canada | Europe | Russia | Asia Pacific/ Middle East |
Africa | Other Areas |
Total | |||||||||||||||||||||
| Developed and Undeveloped |
||||||||||||||||||||||||||||||
| Consolidated operations |
||||||||||||||||||||||||||||||
| End of 2006 |
2,064 | 2,250 | 4,314 | 744 | 1,180 | — | 967 | 497 | 180 | 7,882 | ||||||||||||||||||||
| Revisions |
45 | 124 | 169 | 17 | 25 | — | (33 | ) | (17 | ) | (4 | ) | 157 | |||||||||||||||||
| Improved recovery |
26 | 16 | 42 | — | — | — | — | — | — | 42 | ||||||||||||||||||||
| Purchases |
— | 5 | 5 | — | — | — | — | — | — | 5 | ||||||||||||||||||||
| Extensions and discoveries |
27 | 117 | 144 | 29 | 14 | — | 80 | 20 | — | 287 | ||||||||||||||||||||
| Production |
(122 | ) | (202 | ) | (324 | ) | (84 | ) | (142 | ) | — | (76 | ) | (37 | ) | (5 | ) | (668 | ) | |||||||||||
| Sales |
— | (2 | ) | (2 | ) | (47 | ) | (4 | ) | — | (21 | ) | — | (18 | ) | (92 | ) | |||||||||||||
| End of 2007 |
2,040 | 2,308 | 4,348 | 659 | 1,073 | — | 917 | 463 | 153 | 7,613 | ||||||||||||||||||||
| Revisions |
(348 | ) | (62 | ) | (410 | ) | 28 | 4 | — | 57 | 18 | 9 | (294 | ) | ||||||||||||||||
| Improved recovery |
26 | 5 | 31 | — | — | — | — | — | — | 31 | ||||||||||||||||||||
| Purchases |
— | 2 | 2 | — | — | — | — | — | — | 2 | ||||||||||||||||||||
| Extensions and discoveries |
13 | 70 | 83 | 24 | 17 | — | 14 | 5 | — | 143 | ||||||||||||||||||||
| Production |
(114 | ) | (192 | ) | (306 | ) | (82 | ) | (149 | ) | — | (81 | ) | (38 | ) | (4 | ) | (660 | ) | |||||||||||
| Sales |
— | — | — | — | (9 | ) | — | (3 | ) | — | (23 | ) | (35 | ) | ||||||||||||||||
| End of 2008 |
1,617 | 2,131 | 3,748 | 629 | 936 | — | 904 | 448 | 135 | 6,800 | ||||||||||||||||||||
| Revisions |
151 | 22 | 173 | 404 | 32 | — | (28 | ) | 10 | (13 | ) | 578 | ||||||||||||||||||
| Improved recovery |
14 | 2 | 16 | — | — | — | 2 | — | — | 18 | ||||||||||||||||||||
| Purchases |
— | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||
| Extensions and discoveries |
14 | 41 | 55 | 186 | 11 | — | 35 | 3 | — | 290 | ||||||||||||||||||||
| Production |
(112 | ) | (183 | ) | (295 | ) | (89 | ) | (143 | ) | — | (96 | ) | (36 | ) | — | (659 | ) | ||||||||||||
| Sales |
— | (1 | ) | (1 | ) | (1 | ) | — | — | — | — | (5 | ) | (7 | ) | |||||||||||||||
| End of 2009 |
1,684 | 2,012 | 3,696 | 1,129 | 836 | — | 817 | 425 | 117 | 7,020 | ||||||||||||||||||||
| Equity affiliates |
||||||||||||||||||||||||||||||
| End of 2006 |
— | — | — | — | — | 1,845 | 354 | — | 1,088 | 3,287 | ||||||||||||||||||||
| Revisions |
— | — | — | 5 | — | 162 | — | — | — | 167 | ||||||||||||||||||||
| Improved recovery |
— | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||
| Purchases |
— | — | — | 398 | — | 5 | — | — | — | 403 | ||||||||||||||||||||
| Extensions and discoveries |
— | — | — | 230 | — | 65 | 76 | — | — | 371 | ||||||||||||||||||||
| Production |
— | — | — | (10 | ) | — | (163 | ) | — | — | (16 | ) | (189 | ) | ||||||||||||||||
| Sales |
— | — | — | — | — | (20 | ) | — | — | (1,072 | ) | (1,092 | ) | |||||||||||||||||
| End of 2007 |
— | — | — | 623 | — | 1,894 | 430 | — | — | 2,947 | ||||||||||||||||||||
| Revisions |
— | — | — | 70 | — | 196 | — | — | — | 266 | ||||||||||||||||||||
| Improved recovery |
— | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||
| Purchases |
— | — | — | — | — | 2 | 100 | — | — | 102 | ||||||||||||||||||||
| Extensions and discoveries |
— | — | — | 18 | — | 77 | — | — | — | 95 | ||||||||||||||||||||
| Production |
— | — | — | (11 | ) | — | (172 | ) | (1 | ) | — | — | (184 | ) | ||||||||||||||||
| Sales |
— | — | — | — | — | (51 | ) | — | — | — | (51 | ) | ||||||||||||||||||
| End of 2008 |
— | — | — | 700 | — | 1,946 | 529 | — | — | 3,175 | ||||||||||||||||||||
| Revisions |
— | — | — | (87 | ) | — | 106 | (37 | ) | — | — | (18 | ) | |||||||||||||||||
| Improved recovery |
— | — | — | — | — | 54 | — | — | — | 54 | ||||||||||||||||||||
| Purchases |
— | — | — | — | — | 25 | — | — | — | 25 | ||||||||||||||||||||
| Extensions and discoveries |
— | — | — | 118 | — | 109 | 49 | — | — | 276 | ||||||||||||||||||||
| Production |
— | — | — | (15 | ) | — | (185 | ) | (6 | ) | — | — | (206 | ) | ||||||||||||||||
| Sales |
— | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||
| End of 2009 |
— | — | — | 716 | — | 2,055 | 535 | — | — | 3,306 | ||||||||||||||||||||
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| Years Ended December 31 |
Total Proved Reserves | |||||||||||||||||||
| Millions of Barrels of Oil Equivalent | ||||||||||||||||||||
| Alaska | Lower 48 |
Total U.S. |
Canada | Europe | Russia | Asia Pacific/ Middle East |
Africa | Other Areas |
Total | |||||||||||
| Total company |
||||||||||||||||||||
| End of 2006 |
2,064 | 2,250 | 4,314 | 744 | 1,180 | 1,845 | 1,321 | 497 | 1,268 | 11,169 | ||||||||||
| End of 2007 |
2,040 | 2,308 | 4,348 | 1,282 | 1,073 | 1,894 | 1,347 | 463 | 153 | 10,560 | ||||||||||
| End of 2008 |
1,617 | 2,131 | 3,748 | 1,329 | 936 | 1,946 | 1,433 | 448 | 135 | 9,975 | ||||||||||
| End of 2009 |
1,684 | 2,012 | 3,696 | 1,845 | 836 | 2,055 | 1,352 | 425 | 117 | 10,326 | ||||||||||
| Developed |
||||||||||||||||||||
| Consolidated operations |
||||||||||||||||||||
| End of 2006 |
1,949 | 1,874 | 3,823 | 559 | 773 | — | 757 | 464 | 17 | 6,393 | ||||||||||
| End of 2007 |
1,928 | 1,860 | 3,788 | 492 | 733 | — | 676 | 421 | 13 | 6,123 | ||||||||||
| End of 2008 |
1,506 | 1,718 | 3,224 | 488 | 681 | — | 697 | 420 | 6 | 5,516 | ||||||||||
| End of 2009 |
1,588 | 1,663 | 3,251 | 711 | 608 | — | 644 | 394 | — | 5,608 | ||||||||||
| Equity affiliates |
||||||||||||||||||||
| End of 2006 |
— | — | — | — | — | 1,402 | — | — | 398 | 1,800 | ||||||||||
| End of 2007 |
— | — | — | 45 | — | 1,470 | — | — | — | 1,515 | ||||||||||
| End of 2008 |
— | — | — | 105 | — | 1,471 | 60 | — | — | 1,636 | ||||||||||
| End of 2009 |
— | — | — | 116 | — | 1,464 | 51 | — | — | 1,631 | ||||||||||
| Undeveloped |
||||||||||||||||||||
| Consolidated operations |
||||||||||||||||||||
| End of 2006 |
115 | 376 | 491 | 185 | 407 | — | 210 | 33 | 163 | 1,489 | ||||||||||
| End of 2007 |
112 | 448 | 560 | 167 | 340 | — | 241 | 42 | 140 | 1,490 | ||||||||||
| End of 2008 |
111 | 413 | 524 | 141 | 255 | — | 207 | 28 | 129 | 1,284 | ||||||||||
| End of 2009 |
96 | 349 | 445 | 418 | 228 | — | 173 | 31 | 117 | 1,412 | ||||||||||
| Equity affiliates |
||||||||||||||||||||
| End of 2006 |
— | — | — | — | — | 443 | 354 | — | 690 | 1,487 | ||||||||||
| End of 2007 |
— | — | — | 578 | — | 424 | 430 | — | — | 1,432 | ||||||||||
| End of 2008 |
— | — | — | 595 | — | 475 | 469 | — | — | 1,539 | ||||||||||
| End of 2009 |
— | — | — | 600 | — | 591 | 484 | — | — | 1,675 | ||||||||||
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
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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.
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Results of Operations
| Year Ended |
Millions of Dollars | |||||||||||||||||||||||||||||
| December 31, 2009 | Alaska | Lower 48 |
Total U.S. |
Canada | Europe | Russia | Asia Pacific/ Middle East |
Africa | Other Areas |
Total | ||||||||||||||||||||
| Consolidated operations |
||||||||||||||||||||||||||||||
| Sales |
$ | 3,935 | 3,144 | 7,079 | 2,179 | 4,995 | — | 3,830 | 1,562 | 11 | 19,656 | |||||||||||||||||||
| Transfers |
1,679 | 1,937 | 3,616 | 345 | 2,305 | — | 500 | 257 | — | 7,023 | ||||||||||||||||||||
| Other revenues |
(83 | ) | 54 | (29 | ) | 168 | (66 | ) | — | 10 | 136 | 54 | 273 | |||||||||||||||||
| Total revenues |
5,531 | 5,135 | 10,666 | 2,692 | 7,234 | — | 4,340 | 1,955 | 65 | 26,952 | ||||||||||||||||||||
| Production costs excluding taxes |
864 | 1,266 | 2,130 | 1,011 | 1,048 | — | 445 | 270 | 8 | 4,912 | ||||||||||||||||||||
| Taxes other than income taxes |
1,135 | 422 | 1,557 | 75 | 3 | 1 | 165 | 17 | 7 | 1,825 | ||||||||||||||||||||
| Exploration expenses |
74 | 426 | 500 | 201 | 156 | 4 | 212 | 32 | 75 | 1,180 | ||||||||||||||||||||
| Depreciation, depletion and amortization |
611 | 2,615 | 3,226 | 1,689 | 2,016 | 2 | 910 | 201 | 11 | 8,055 | ||||||||||||||||||||
| Impairments |
— | 5 | 5 | 296 | 104 | — | 12 | — | 51 | 468 | ||||||||||||||||||||
| Transportation costs |
548 | 392 | 940 | 135 | 267 | — | 111 | 24 | 5 | 1,482 | ||||||||||||||||||||
| Other related expenses |
138 | 60 | 198 | (3 | ) | 62 | 3 | 121 | 23 | 14 | 418 | |||||||||||||||||||
| Accretion |
49 | 55 | 104 | 41 | 191 | — | 19 | 3 | 3 | 361 | ||||||||||||||||||||
| 2,112 | (106 | ) | 2,006 | (753 | ) | 3,387 | (10 | ) | 2,345 | 1,385 | (109 | ) | 8,251 | |||||||||||||||||
| Provision for income taxes |
716 | (79 | ) | 637 | (309 | ) | 2,280 | (3 | ) | 1,093 | 1,186 | (21 | ) | 4,863 | ||||||||||||||||
| Results of operations for producing activities |
1,396 | (27 | ) | 1,369 | (444 | ) | 1,107 | (7 | ) | 1,252 | 199 | (88 | ) | 3,388 | ||||||||||||||||
| Other earnings |
144 | (10 | ) | 134 | (91 | ) | (59 | ) | (5 | ) | 132 | 4 | (1 | ) | 114 | |||||||||||||||
| Net income (loss) attributable to ConocoPhillips |
$ | 1,540 | (37 | ) | 1,503 | (535 | ) | 1,048 | (12 | ) | 1,384 | 203 | (89 | ) | 3,502 | |||||||||||||||
| Equity affiliates |
||||||||||||||||||||||||||||||
| Sales |
$ | — | — | — | 713 | — | 5,514 | 74 | — | — | 6,301 | |||||||||||||||||||
| Transfers |
— | — | — | — | — | 2,195 | — | — | — | 2,195 | ||||||||||||||||||||
| Other revenues |
— | — | — | (2 | ) | — | — | 1 | — | — | (1 | ) | ||||||||||||||||||
| Total revenues |
— | — | — | 711 | — | 7,709 | 75 | — | — | 8,495 | ||||||||||||||||||||
| Production costs excluding taxes |
— | — | — | 213 | — | 635 | 26 | — | — | 874 | ||||||||||||||||||||
| Taxes other than income taxes |
— | — | — | 3 | — | 3,024 | 4 | — | — | 3,031 | ||||||||||||||||||||
| Exploration expenses |
— | — | — | — | — | 55 | 2 | — | — | 57 | ||||||||||||||||||||
| Depreciation, depletion and amortization |
— | — | — | 133 | — | 523 | 21 | — | — | 677 | ||||||||||||||||||||
| Impairments |
— | — | — | — | — | 277 | — | — | — | 277 | ||||||||||||||||||||
| Transportation costs |
— | — | — | — | — | 902 | 3 | — | — | 905 | ||||||||||||||||||||
| Other related expenses |
— | — | — | 17 | — | 3 | 1 | — | — | 21 | ||||||||||||||||||||
| Accretion |
— | — | — | 1 | — | 5 | 1 | — | — | 7 | ||||||||||||||||||||
| — | — | — | 344 | — | 2,285 | 17 | — | — | 2,646 | |||||||||||||||||||||
| Provision for income taxes |
— | — | — | 89 | — | 523 | 9 | — | — | 621 | ||||||||||||||||||||
| Results of operations for producing activities |
— | — | — | 255 | — | 1,762 | 8 | — | — | 2,025 | ||||||||||||||||||||
| Other earnings |
— | — | — | — | — | (174 | ) | (86 | ) | — | — | (260 | ) | |||||||||||||||||
| Net income (loss) attributable to ConocoPhillips |
$ | — | — | — | 255 | — | 1,588 | (78 | ) | — | — | 1,765 | ||||||||||||||||||
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| Year Ended |
Millions of Dollars | |||||||||||||||||||||||||||
| December 31, 2008 | Alaska | Lower 48 |
Total U.S. |
Canada | Europe | Russia | Asia Pacific/ Middle East |
Africa | Other Areas |
Total | ||||||||||||||||||
| Consolidated operations |
||||||||||||||||||||||||||||
| Sales |
$ | 5,771 | 6,726 | 12,497 | 4,386 | 8,061 | — | 4,787 | 2,075 | 290 | 32,096 | |||||||||||||||||
| Transfers |
3,444 | 3,401 | 6,845 | — | 3,415 | — | 579 | 669 | — | 11,508 | ||||||||||||||||||
| Other revenues |
(25 | ) | 98 | 73 | 317 | 477 | — | 40 | 230 | (16 | ) | 1,121 | ||||||||||||||||
| Total revenues |
9,190 | 10,225 | 19,415 | 4,703 | 11,953 | — | 5,406 | 2,974 | 274 | 44,725 | ||||||||||||||||||
| Production costs excluding taxes |
960 | 1,405 | 2,365 | 887 | 1,157 | — | 428 | 245 | 34 | 5,116 | ||||||||||||||||||
| Taxes other than income taxes |
3,432 | 764 | 4,196 | 61 | 29 | 2 | 295 | 27 | 205 | 4,815 | ||||||||||||||||||
| Exploration expenses |
99 | 469 | 568 | 240 | 235 | 4 | 148 | 41 | 103 | 1,339 | ||||||||||||||||||
| Depreciation, depletion and amortization |
559 | 2,426 | 2,985 | 1,802 | 1,917 | 2 | 733 | 215 | 24 | 7,678 | ||||||||||||||||||
| Impairments* |
— | 620 | 620 | 92 | 72 | — | 9 | — | — | 793 | ||||||||||||||||||
| Transportation costs |
409 | 519 | 928 | 140 | 302 | — | 115 | 29 | 10 | 1,524 | ||||||||||||||||||
| Other related expenses |
(38 | ) | 108 | 70 | 56 | (306 | ) | 18 | 113 | 6 | 53 | 10 | ||||||||||||||||
| Accretion |
40 | 59 | 99 | 33 | 196 | — | 14 | 4 | 3 | 349 | ||||||||||||||||||
| 3,729 | 3,855 | 7,584 | 1,392 | 8,351 | (26 | ) | 3,551 | 2,407 | (158 | ) | 23,101 | |||||||||||||||||
| Provision for income taxes |
1,317 | 1,310 | 2,627 | 371 | 5,241 | 7 | 1,640 | 2,094 | (46 | ) | 11,934 | |||||||||||||||||
| Results of operations for producing activities |
2,412 | 2,545 | 4,957 | 1,021 | 3,110 | (33 | ) | 1,911 | 313 | (112 | ) | 11,167 | ||||||||||||||||
| Other earnings |
(97 | ) | 128 | 31 | 243 | 314 | 66 | 46 | (35 | ) | (11 | ) | 654 | |||||||||||||||
| Net income (loss) attributable to ConocoPhillips |
$ | 2,315 | 2,673 | 4,988 | 1,264 | 3,424 | 33 | 1,957 | 278 | (123 | ) | 11,821 | ||||||||||||||||
| Equity affiliates |
||||||||||||||||||||||||||||
| Sales |
$ | — | — | — | 644 | — | 5,451 | 9 | — | — | 6,104 | |||||||||||||||||
| Transfers |
— | — | — | — | — | 3,952 | — | — | — | 3,952 | ||||||||||||||||||
| Other revenues |
— | — | — | 45 | — | — | — | — | — | 45 | ||||||||||||||||||
| Total revenues |
— | — | — | 689 | — | 9,403 | 9 | — | — | 10,101 | ||||||||||||||||||
| Production costs excluding taxes |
— | — | — | 182 | — | 766 | 4 | — | — | 952 | ||||||||||||||||||
| Taxes other than income taxes |
— | — | — | 3 | — | 5,215 | — | — | — | 5,218 | ||||||||||||||||||
| Exploration expenses |
— | — | — | — | — | 89 | — | — | — | 89 | ||||||||||||||||||
| Depreciation, depletion and amortization |
— | — | — | 84 | — | 537 | 9 | — | — | 630 | ||||||||||||||||||
| Impairments |
— | — | — | — | — | 6,666 | — | — | — | 6,666 | ||||||||||||||||||
| Transportation costs |
— | — | — | — | — | 966 | 1 | — | — | 967 | ||||||||||||||||||
| Other related expenses |
— | — | — | 1 | — | 7 | 5 | — | — | 13 | ||||||||||||||||||
| Accretion |
— | — | — | 1 | — | 3 | — | — | — | 4 | ||||||||||||||||||
| — | — | — | 418 | — | (4,846 | ) | (10 | ) | — | — | (4,438 | ) | ||||||||||||||||
| Provision for income taxes |
— | — | — | 132 | — | 511 | (11 | ) | — | 1 | 633 | |||||||||||||||||
| Results of operations for producing activities |
— | — | — | 286 | — | (5,357 | ) | 1 | — | (1 | ) | (5,071 | ) | |||||||||||||||
| Other earnings |
— | — | — | 3 | — | (274 | ) | (3 | ) | — | — | (274 | ) | |||||||||||||||
| Net income (loss) attributable to ConocoPhillips |
$ | — | — | — | 289 | — | (5,631 | ) | (2 | ) | — | (1 | ) | (5,345 | ) | |||||||||||||
| *Excludes | goodwill impairment of $25,443 million. |
A-125
Table of Contents
| Year End |
Millions of Dollars | ||||||||||||||||||||||||||||
| December 31, 2007 | Alaska | Lower 48 |
Total U.S. |
Canada | Europe | Russia | Asia Pacific/ Middle East |
Africa | Other Areas |
Total | |||||||||||||||||||
| Consolidated operations |
|||||||||||||||||||||||||||||
| Sales |
$ | 4,659 | 5,422 | 10,081 | 3,406 | 5,701 | — | 3,484 | 1,515 | 240 | 24,427 | ||||||||||||||||||
| Transfers |
2,344 | 2,986 | 5,330 | — | 2,729 | — | 284 | 562 | — | 8,905 | |||||||||||||||||||
| Other revenues |
173 | 94 | 267 | 430 | 330 | 1 | 263 | 190 | 3 | 1,484 | |||||||||||||||||||
| Total revenues |
7,176 | 8,502 | 15,678 | 3,836 | 8,760 | 1 | 4,031 | 2,267 | 243 | 34,816 | |||||||||||||||||||
| Production costs excluding taxes |
775 | 1,232 | 2,007 | 874 | 1,029 | — | 423 | 224 | 41 | 4,598 | |||||||||||||||||||
| Taxes other than income taxes |
1,663 | 628 | 2,291 | 70 | 45 | 2 | 130 | 17 | 98 | 2,653 | |||||||||||||||||||
| Exploration expenses |
104 | 318 | 422 | 247 | 105 | 5 | 135 | 72 | 31 | 1,017 | |||||||||||||||||||
| Depreciation, depletion and amortization |
583 | 2,559 | 3,142 | 1,661 | 1,394 | — | 641 | 171 | — | 7,009 | |||||||||||||||||||
| Impairments |
28 | 43 | 71 | 27 | 188 | — | 26 | — | 918 | 1,230 | |||||||||||||||||||
| Transportation costs |
412 | 553 | 965 | 137 | 335 | — | 101 | 24 | 64 | 1,626 | |||||||||||||||||||
| Other related expenses |
(64 | ) | 72 | 8 | (96 | ) | 46 | 16 | 14 | 8 | 77 | 73 | |||||||||||||||||
| Accretion |
37 | 48 | 85 | 47 | 132 | — | 9 | 3 | 1 | 277 | |||||||||||||||||||
| 3,638 | 3,049 | 6,687 | 869 | 5,486 | (22 | ) | 2,552 | 1,748 | (987 | ) | 16,333 | ||||||||||||||||||
| Provision for income taxes |
1,248 | 1,091 | 2,339 | 237 | 3,595 | (6 | ) | 1,045 | 1,482 | (21 | ) | 8,671 | |||||||||||||||||
| Results of operations for producing activities |
2,390 | 1,958 | 4,348 | 632 | 1,891 | (16 | ) | 1,507 | 266 | (966 | ) | 7,662 | |||||||||||||||||
| Other earnings |
(135 | ) | 35 | (100 | ) | 280 | 48 | 36 | 94 | (2 | ) | 194 | 550 | ||||||||||||||||
| Net income (loss) attributable to ConocoPhillips |
$ | 2,255 | 1,993 | 4,248 | 912 | 1,939 | 20 | 1,601 | 264 | (772 | ) | 8,212 | |||||||||||||||||
| Equity affiliates |
|||||||||||||||||||||||||||||
| Sales |
$ | — | — | — | 365 | — | 4,400 | — | — | 447 | 5,212 | ||||||||||||||||||
| Transfers |
— | — | — | — | — | 3,162 | — | — | 265 | 3,427 | |||||||||||||||||||
| Other revenues |
— | — | — | 1 | — | — | — | — | 37 | 38 | |||||||||||||||||||
| Total revenues |
— | — | — | 366 | — | 7,562 | — | — | 749 | 8,677 | |||||||||||||||||||
| Production costs excluding taxes |
— | — | — | 131 | — | 677 | — | — | 98 | 906 | |||||||||||||||||||
| Taxes other than income taxes |
— | — | — | 2 | — | 3,498 | — | — | 175 | 3,675 | |||||||||||||||||||
| Exploration expenses |
— | — | — | — | — | 68 | — | — | — | 68 | |||||||||||||||||||
| Depreciation, depletion and amortization |
— | — | — | 67 | — | 423 | — | — | 61 | 551 | |||||||||||||||||||
| Impairments |
— | — | — | — | — | — | — | — | 3,825 | 3,825 | |||||||||||||||||||
| Transportation costs |
— | — | — | — | — | 737 | — | — | — | 737 | |||||||||||||||||||
| Other related expenses |
— | — | — | 27 | — | 14 | 5 | — | 11 | 57 | |||||||||||||||||||
| Accretion |
— | — | — | — | — | 7 | — | — | — | 7 | |||||||||||||||||||
| — | — | — | 139 | — | 2,138 | (5 | ) | — | (3,421 | ) | (1,149 | ) | |||||||||||||||||
| Provision for income taxes |
— | — | — | 41 | — | 584 | — | — | 219 | 844 | |||||||||||||||||||
| Results of operations for producing activities |
— | — | — | 98 | — | 1,554 | (5 | ) | — | (3,640 | ) | (1,993 | ) | ||||||||||||||||
| Other earnings |
— | — | — | 2 | — | 258 | (5 | ) | — | (41 | ) | 214 | |||||||||||||||||
| Net income (loss) attributable to ConocoPhillips |
$ | — | — | — | 100 | — | 1,812 | (10 | ) | — | (3,681 | ) | (1,779 | ) | |||||||||||||||
A-126
Table of Contents
| • | 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. |
A-127
Table of Contents
Statistics
| Net Production | 2009 | 2008 | 2007 | |||
| Thousands of Barrels Daily | ||||||
| Crude Oil and Natural Gas Liquids |
||||||
| Consolidated operations |
||||||
| Alaska |
252 | 261 | 280 | |||
| Lower 48 |
166 | 165 | 181 | |||
| United States |
418 | 426 | 461 | |||
| Canada |
40 | 44 | 46 | |||
| Europe |
241 | 233 | 224 | |||
| Asia Pacific/Middle East |
132 | 107 | 106 | |||
| Africa |
78 | 80 | 78 | |||
| Other areas |
4 | 9 | 10 | |||
| Total consolidated operations |
913 | 899 | 925 | |||
| Equity affiliates |
||||||
| Russia |
442 | 410 | 416 | |||
| Other areas |
— | — | 42 | |||
| Total equity affiliates |
442 | 410 | 458 | |||
| Total company |
1,355 | 1,309 | 1,383 | |||
| Synthetic Oil |
||||||
| Consolidated operations—Canada |
23 | 22 | 23 | |||
| Bitumen |
||||||
| Consolidated operations—Canada |
7 | 6 | — | |||
| Equity affiliates—Canada |
43 | 30 | 27 | |||
| Total company |
50 | 36 | 27 | |||
| Millions of Cubic Feet Daily | ||||||
| Natural Gas* |
||||||
| Consolidated operations |
||||||
| Alaska |
94 | 97 | 110 | |||
| Lower 48 |
1,927 | 1,994 | 2,182 | |||
| United States |
2,021 | 2,091 | 2,292 | |||
| Canada |
1,062 | 1,054 | 1,106 | |||
| Europe |
876 | 954 | 961 | |||
| Asia Pacific/Middle East |
713 | 609 | 579 | |||
| Africa |
121 | 114 | 125 | |||
| Other areas |
— | 14 | 19 | |||
| Total consolidated operations |
4,793 | 4,836 | 5,082 | |||
| Equity affiliates |
||||||
| Russia |
280 | 356 | 256 | |||
| Asia Pacific/Middle East |
84 | 11 | — | |||
| Other areas |
— | — | 5 | |||
| Total equity affiliates |
364 | 367 | 261 | |||
| Total company |
5,157 | 5,203 | 5,343 | |||
| * | Represents quantities available for sale. Excludes gas equivalent of natural gas liquids included above. |
A-128
Table of Contents
| Average Sales Prices | 2009 | 2008 | 2007 | ||||
| Crude Oil and Natural Gas Liquids Per Barrel |
|||||||
| Consolidated operations |
|||||||
| Alaska |
$ | 59.23 | 99.10 | 69.79 | |||
| Lower 48 |
44.12 | 74.70 | 55.15 | ||||
| United States |
53.21 | 89.38 | 63.87 | ||||
| Canada |
41.76 | 76.53 | 55.52 | ||||
| Europe |
58.92 | 92.10 | 70.19 | ||||
| Asia Pacific/Middle East |
57.59 | 87.32 | 67.20 | ||||
| Africa |
60.83 | 91.54 | 71.84 | ||||
| Other areas |
32.01 | 84.74 | 60.84 | ||||
| Total international |
57.40 | 89.32 | 68.09 | ||||
| Total consolidated operations |
55.47 | 89.35 | 66.01 | ||||
| Equity affiliates |
|||||||
| Russia |
47.02 | 61.48 | 50.00 | ||||
| Other areas |
— | — | 47.46 | ||||
| Total equity affiliates |
47.02 | 61.48 | 49.77 | ||||
| Synthetic Oil Per Barrel |
|||||||
| Consolidated operations—Canada |
$ | 62.01 | 103.31 | 74.32 | |||
| Bitumen Per Barrel |
|||||||
| Consolidated operations—Canada |
$ | 39.67 | 46.85 | — | |||
| Equity affiliates—Canada |
45.69 | 58.54 | 37.94 | ||||
| Natural Gas Per Thousand Cubic Feet |
|||||||
| Consolidated operations |
|||||||
| Alaska |
$ | 6.25 | 4.38 | 3.68 | |||
| Lower 48 |
3.42 | 7.71 | 5.99 | ||||
| United States |
3.45 | 7.67 | 5.98 | ||||
| Canada |
3.33 | 7.92 | 6.09 | ||||
| Europe |
6.81 | 10.55 | 7.87 | ||||
| Asia Pacific/Middle East |
5.84 | 9.10 | 6.37 | ||||
| Africa |
1.56 | 1.09 | .80 | ||||
| Other areas |
— | 1.41 | 1.18 | ||||
| Total international |
4.94 | 8.76 | 6.51 | ||||
| Total consolidated operations |
4.30 | 8.28 | 6.26 | ||||
| Equity affiliates |
|||||||
| Russia |
1.18 | 1.06 | 1.02 | ||||
| Asia Pacific/Middle East |
2.35 | 2.04 | — | ||||
| Other areas |
— | — | .30 | ||||
| Total equity affiliates |
1.45 | 1.10 | 1.01 | ||||
A-129
Table of Contents
| 2009 | 2008 | 2007 | |||||
| Average Production Costs Per Barrel of Oil Equivalent* |
|||||||
| Consolidated operations |
|||||||
| Alaska |
$ | 8.84 | 9.46 | 7.12 | |||
| Lower 48 |
7.12 | 7.72 | 6.20 | ||||
| United States |
7.73 | 8.34 | 6.52 | ||||
| Canada |
11.21 | 10.74 | 10.40 | ||||
| Europe |
7.42 | 8.06 | 7.34 | ||||
| Asia Pacific/Middle East |
4.86 | 5.61 | 5.72 | ||||
| Africa |
7.54 | 6.76 | 6.21 | ||||
| Other areas |
5.48 | 8.20 | 8.53 | ||||
| Total international |
7.72 | 8.03 | 7.64 | ||||
| Total consolidated operations |
7.73 | 8.17 | 7.11 | ||||
| Equity affiliates |
|||||||
| Canada |
13.57 | 16.58 | 13.32 | ||||
| Russia |
3.56 | 4.46 | 4.04 | ||||
| Asia Pacific/Middle East |
5.09 | 5.96 | — | ||||
| Other areas |
— | — | 6.24 | ||||
| Total equity affiliates |
4.39 | 5.19 | 4.70 | ||||
| Average Production Costs Per Barrel—Bitumen |
|||||||
| Consolidated operations—Canada |
$ | 30.92 | 39.62 | — | |||
| Equity affiliates—Canada |
13.57 | 16.58 | 13.32 | ||||
| Taxes Other Than Income Taxes Per Barrel of Oil Equivalent* |
|||||||
| Consolidated operations |
|||||||
| Alaska |
$ | 11.62 | 33.83 | 15.27 | |||
| Lower 48 |
2.37 | 4.20 | 3.16 | ||||
| United States |
5.65 | 14.80 | 7.45 | ||||
| Canada |
.83 | .74 | .83 | ||||
| Europe |
.02 | .20 | .32 | ||||
| Asia Pacific/Middle East |
1.80 | 3.87 | 1.76 | ||||
| Africa |
.47 | .75 | .47 | ||||
| Other areas |
4.79 | 49.42 | 20.39 | ||||
| Total international |
.74 | 1.81 | 1.07 | ||||
| Total consolidated operations |
2.87 | 7.69 | 4.10 | ||||
| Equity affiliates |
|||||||
| Canada |
.19 | .27 | .21 | ||||
| Russia |
16.95 | 30.36 | 20.89 | ||||
| Asia Pacific/Middle East |
.78 | — | — | ||||
| Other areas |
— | — | 11.21 | ||||
| Total equity affiliates |
15.22 | 28.45 | 19.05 | ||||
| Depreciation, Depletion and Amortization Per Barrel of Oil Equivalent* |
|||||||
| Consolidated operations |
|||||||
| Alaska |
$ | 6.25 | 5.51 | 5.35 | |||
| Lower 48 |
14.71 | 13.33 | 12.87 | ||||
| United States |
11.71 | 10.53 | 10.21 | ||||
| Canada |
18.73 | 21.82 | 19.76 | ||||
| Europe |
14.27 | 13.36 | 9.94 | ||||
| Asia Pacific/Middle East |
9.94 | 9.61 | 8.67 | ||||
| Africa |
5.61 | 5.93 | 4.74 | ||||
| Other areas |
7.53 | 5.79 | — | ||||
| Total international |
13.40 | 13.69 | 11.40 | ||||
| Total consolidated operations |
12.67 | 12.26 | 10.84 | ||||
| Equity affiliates |
|||||||
| Canada |
8.47 | 7.65 | 6.82 | ||||
| Russia |
2.93 | 3.13 | 2.53 | ||||
| Asia Pacific/Middle East |
4.11 | 13.41 | — | ||||
| Other areas |
— | — | 3.88 | ||||
| Total equity affiliates |
3.40 | 3.43 | 2.86 | ||||
| * | Includes bitumen. For 2008 and 2007, excludes our Canadian synthetic oil operations. |
A-130
Table of Contents
| Net Wells Completed (1) | Productive | Dry | ||||||||||||
| 2009 | 2008 | 2007 | 2009 | 2008 | 2007 | |||||||||
| Exploratory (2) |
||||||||||||||
| Consolidated operations |
||||||||||||||
| Alaska |
— | — | 3 | 2 | 1 | 1 | ||||||||
| Lower 48 |
33 | 81 | 71 | 14 | 22 | 9 | ||||||||
| United States |
33 | 81 | 74 | 16 | 23 | 10 | ||||||||
| Canada |
17 | 49 | 50 | 19 | 36 | 17 | ||||||||
| Europe |
1 | * | 1 | 2 | 1 | 1 | ||||||||
| Asia Pacific/Middle East |
3 | 1 | 4 | 3 | * | 1 | ||||||||
| Africa |
* | * | — | * | 1 | 1 | ||||||||
| Other areas |
— | — | — | — | 1 | * | ||||||||
| Total consolidated operations |
54 | 131 | 129 | 40 | 62 | 30 | ||||||||
| Equity affiliates |
||||||||||||||
| Russia |
1 | 1 | — | — | 1 | — | ||||||||
| Asia Pacific/Middle East |
— | — | — | — | * | — | ||||||||
| Total equity affiliates (3) |
1 | 1 | — | — | 1 | — | ||||||||
| Includes step-out wells of: | 40 | 127 | 99 | 29 | 27 | 18 | ||||||||
| Productive | Dry | |||||||||||||
| 2009 | 2008 | 2007 | 2009 | 2008 | 2007 | |||||||||
| Development |
||||||||||||||
| Consolidated operations |
||||||||||||||
| Alaska |
47 | 47 | 46 | — | — | — | ||||||||
| Lower 48 |
592 | 690 | 686 | 4 | 8 | 7 | ||||||||
| United States |
639 | 737 | 732 | 4 | 8 | 7 | ||||||||
| Canada |
227 | 465 | 326 | 20 | 32 | 23 | ||||||||
| Europe |
9 | 10 | 10 | — | — | — | ||||||||
| Asia Pacific/Middle East |
47 | 26 | 18 | — | — | — | ||||||||
| Africa |
3 | 4 | 6 | — | — | * | ||||||||
| Other areas |
— | — | 5 | — | — | — | ||||||||
| Total consolidated operations |
925 | 1,242 | 1,097 | 24 | 40 | 30 | ||||||||
| Equity affiliates |
||||||||||||||
| Canada |
61 | 148 | 70 | — | — | 1 | ||||||||
| Russia |
6 | 7 | 2 | * | — | — | ||||||||
| Asia Pacific/Middle East |
28 | * | — | — | — | — | ||||||||
| Total equity affiliates (3) |
95 | 155 | 72 | * | — | 1 | ||||||||
| (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. |
A-131
Table of Contents
| Wells at Year-End 2009 | Productive (2) | |||||||||||||||||
| In Progress (1) | Oil | Gas | ||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | |||||||||||||
| Consolidated operations |
||||||||||||||||||
| Alaska |
22 | 11 | 1,935 | 868 | 29 | 19 | ||||||||||||
| Lower 48 |
96 | 73 | 12,958 | 4,758 | 26,053 | 16,631 | ||||||||||||
| United States |
118 | 84 | 14,893 | 5,626 | 26,082 | 16,650 | ||||||||||||
| Canada |
176 | (3) | 134 | (3) | 2,126 | 1,207 | 12,736 | 7,650 | ||||||||||
| Europe |
37 | 6 | 596 | 108 | 273 | 110 | ||||||||||||
| Asia Pacific/Middle East |
140 | 62 | 439 | 174 | 93 | 44 | ||||||||||||
| Africa |
35 | 7 | 1,117 | 192 | — | — | ||||||||||||
| Other areas |
31 | 3 | — | — | — | — | ||||||||||||
| Total consolidated operations |
537 | 296 | 19,171 | 7,307 | 39,184 | 24,454 | ||||||||||||
| Equity affiliates |
||||||||||||||||||
| Canada |
8 | 4 | 191 | 96 | — | — | ||||||||||||
| Russia |
6 | 2 | 102 | 35 | 2 | 1 | ||||||||||||
| Asia Pacific/Middle East |
574 | 143 | — | — | 498 | 153 | ||||||||||||
| Total equity affiliates (4) |
588 | 149 | 293 | 131 | 500 | 154 | ||||||||||||
| (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. |
| Acreage at December 31, 2009 | Thousands of Acres | |||||||||
| Developed | Undeveloped | |||||||||
| Gross | Net | Gross | Net | |||||||
| Consolidated operations |
||||||||||
| Alaska |
647 | 328 | 1,764 | 1,498 | ||||||
| Lower 48 |
6,979 | 5,613 | 12,901 | 9,628 | ||||||
| United States |
7,626 | 5,941 | 14,665 | 11,126 | ||||||
| Canada |
7,258 | 4,528 | 10,650 | 6,726 | ||||||
| Europe |
848 | 228 | 3,535 | 1,444 | ||||||
| Asia Pacific/Middle East |
4,157 | 1,784 | 29,906 | 18,388 | ||||||
| Africa |
528 | 132 | 14,729 | 2,575 | ||||||
| Other areas |
— | — | 13,313 | 9,062 | ||||||
| Total consolidated operations |
20,417 | 12,613 | 86,798 | 49,321 | ||||||
| Equity affiliates |
||||||||||
| Canada |
32 | 14 | 505 | 203 | ||||||
| Russia |
291 | 90 | 1,173 | 476 | ||||||
| Asia Pacific/Middle East |
964 | 245 | 9,250 | 3,740 | ||||||
| Total equity affiliates* |
1,287 | 349 | 10,928 | 4,419 | ||||||
| * | Excludes LUKOIL. |
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Costs Incurred
| Years Ended |
Millions of Dollars | ||||||||||||||||||||
| December 31 | Alaska | Lower 48 |
Total U.S. |
Canada | Europe | Russia | Asia Pacific/ Middle East |
Africa | Other Areas |
Total | |||||||||||
| 2009 |
|||||||||||||||||||||
| Consolidated operations |
|||||||||||||||||||||
| Unproved property acquisition |
$ | — | 78 | 78 | 62 | 5 | — | 30 | — | 55 | 230 | ||||||||||
| Proved property acquisition |
1 | 6 | 7 | 7 | — | — | — | — | — | 14 | |||||||||||
| 1 | 84 | 85 | 69 | 5 | — | 30 | — | 55 | 244 | ||||||||||||
| Exploration |
137 | 476 | 613 | 251 | 184 | 4 | 342 | 33 | 90 | 1,517 | |||||||||||
| Development |
790 | 1,726 | 2,516 | 1,114 | 1,108 | — | 1,244 | 240 | 685 | 6,907 | |||||||||||
| $ | 928 | 2,286 | 3,214 | 1,434 | 1,297 | 4 | 1,616 | 273 | 830 | 8,668 | |||||||||||
| Equity affiliates |
|||||||||||||||||||||
| Unproved property acquisition |
$ | — | — | — | — | — | 5 | — | — | — | 5 | ||||||||||
| Proved property acquisition |
— | — | — | — | — | 56 | 219 | — | — | 275 | |||||||||||
| — | — | — | — | — | 61 | 219 | — | — | 280 | ||||||||||||
| Exploration |
— | — | — | — | — | 106 | 53 | — | — | 159 | |||||||||||
| Development |
— | — | — | 446 | — | 1,007 | 376 | — | — | 1,829 | |||||||||||
| $ | — | — | — | 446 | — | 1,174 | 648 | — | — | 2,268 | |||||||||||
| 2008 |
|||||||||||||||||||||
| Consolidated operations |
|||||||||||||||||||||
| Unproved property acquisition |
$ | 514 | 505 | 1,019 | 195 | — | — | 5 | — | — | 1,219 | ||||||||||
| Proved property acquisition |
— | 37 | 37 | — | — | — | — | — | — | 37 | |||||||||||
| 514 | 542 | 1,056 | 195 | — | — | 5 | — | — | 1,256 | ||||||||||||
| Exploration |
124 | 733 | 857 | 306 | 279 | 3 | 224 | 42 | 94 | 1,805 | |||||||||||
| Development |
823 | 2,458 | 3,281 | 1,300 | 2,056 | — | 1,314 | 175 | 619 | 8,745 | |||||||||||
| $ | 1,461 | 3,733 | 5,194 | 1,801 | 2,335 | 3 | 1,543 | 217 | 713 | 11,806 | |||||||||||
| Equity affiliates |
|||||||||||||||||||||
| Unproved property acquisition |
$ | — | — | — | — | — | 39 | 4,505 | — | — | 4,544 | ||||||||||
| Proved property acquisition |
— | — | — | 7 | — | 30 | 245 | — | — | 282 | |||||||||||
| — | — | — | 7 | — | 69 | 4,750 | — | — | 4,826 | ||||||||||||
| Exploration |
— | — | — | — | — | 155 | 5 | — | — | 160 | |||||||||||
| Development |
— | — | — | 569 | — | 1,842 | 214 | — | — | 2,625 | |||||||||||
| $ | — | — | — | 576 | — | 2,066 | 4,969 | — | — | 7,611 | |||||||||||
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| Years Ended December 31 |
Millions of Dollars | ||||||||||||||||||||
| Alaska | Lower 48 |
Total U.S. |
Canada | Europe | Russia | Asia Pacific/ Middle East |
Africa | Other Areas |
Total | ||||||||||||
| 2007 |
|||||||||||||||||||||
| Consolidated operations |
|||||||||||||||||||||
| Unproved property acquisition |
$ | 5 | 202 | 207 | 117 | — | — | 122 | — | — | 446 | ||||||||||
| Proved property acquisition |
— | 42 | 42 | — | — | — | — | — | — | 42 | |||||||||||
| 5 | 244 | 249 | 117 | — | — | 122 | — | — | 488 | ||||||||||||
| Exploration |
115 | 468 | 583 | 278 | 235 | 5 | 153 | 67 | 53 | 1,374 | |||||||||||
| Development |
567 | 2,375 | 2,942 | 1,170 | 1,871 | — | 1,275 | 355 | 535 | 8,148 | |||||||||||
| $ | 687 | 3,087 | 3,774 | 1,565 | 2,106 | 5 | 1,550 | 422 | 588 | 10,010 | |||||||||||
| Equity affiliates |
|||||||||||||||||||||
| Unproved property acquisition |
$ | — | — | — | 2,030 | — | 105 | — | — | — | 2,135 | ||||||||||
| Proved property acquisition |
— | — | — | 1,729 | — | 81 | — | — | — | 1,810 | |||||||||||
| — | — | — | 3,759 | — | 186 | — | — | — | 3,945 | ||||||||||||
| Exploration |
— | — | — | — | — | 144 | — | — | — | 144 | |||||||||||
| Development |
— | — | — | 358 | — | 1,763 | 334 | — | 51 | 2,506 | |||||||||||
| $ | — | — | — | 4,117 | — | 2,093 | 334 | — | 51 | 6,595 | |||||||||||
| • | 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. |
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Capitalized Costs
| At December 31 | Millions of Dollars | ||||||||||||||||||||
| Alaska | Lower 48 |
Total U.S. |
Canada | Europe | Russia | Asia Pacific/ Middle East |
Africa | Other Areas |
Total | ||||||||||||
| 2009 |
|||||||||||||||||||||
| Consolidated operations |
|||||||||||||||||||||
| Proved properties |
$ | 11,678 | 33,408 | 45,086 | 21,070 | 20,759 | 9 | 10,398 | 3,170 | 3,235 | 103,727 | ||||||||||
| Unproved properties |
1,421 | 1,407 | 2,828 | 1,899 | 396 | — | 970 | 195 | 218 | 6,506 | |||||||||||
| 13,099 | 34,815 | 47,914 | 22,969 | 21,155 | 9 | 11,368 | 3,365 | 3,453 | 110,233 | ||||||||||||
| Accumulated depreciation, depletion and amortization |
5,218 | 13,464 | 18,682 | 8,919 | 11,995 | 5 | 3,578 | 1,167 | 43 | 44,389 | |||||||||||
| $ | 7,881 | 21,351 | 29,232 | 14,050 | 9,160 | 4 | 7,790 | 2,198 | 3,410 | 65,844 | |||||||||||
| Equity affiliates |
|||||||||||||||||||||
| Proved properties |
$ | — | — | — | 3,912 | — | 12,562 | 1,511 | — | — | 17,985 | ||||||||||
| Unproved properties |
— | — | — | 1,681 | — | 1,271 | 6,840 | — | — | 9,792 | |||||||||||
| — | — | — | 5,593 | — | 13,833 | 8,351 | — | — | 27,777 | ||||||||||||
| Accumulated depreciation, depletion and amortization |
— | — | — | 299 | — | 8,901 | 36 | — | — | 9,236 | |||||||||||
| $ | — | — | — | 5,294 | — | 4,932 | 8,315 | — | — | 18,541 | |||||||||||
| 2008 |
|||||||||||||||||||||
| Consolidated operations |
|||||||||||||||||||||
| Proved properties |
$ | 10,880 | 31,592 | 42,472 | 15,237 | 17,025 | 9 | 9,274 | 2,917 | 3,065 | 89,999 | ||||||||||
| Unproved properties |
1,388 | 1,541 | 2,929 | 1,672 | 316 | — | 833 | 261 | 181 | 6,192 | |||||||||||
| 12,268 | 33,133 | 45,401 | 16,909 | 17,341 | 9 | 10,107 | 3,178 | 3,246 | 96,191 | ||||||||||||
| Accumulated depreciation, depletion and amortization |
4,642 | 10,974 | 15,616 | 5,672 | 8,622 | 4 | 2,820 | 1,015 | 529 | 34,278 | |||||||||||
| $ | 7,626 | 22,159 | 29,785 | 11,237 | 8,719 | 5 | 7,287 | 2,163 | 2,717 | 61,913 | |||||||||||
| Equity affiliates |
|||||||||||||||||||||
| Proved properties |
$ | — | — | — | 2,787 | — | 11,498 | 1,076 | — | — | 15,361 | ||||||||||
| Unproved properties |
— | — | — | 1,604 | — | 1,216 | 5,116 | — | — | 7,936 | |||||||||||
| — | — | — | 4,391 | — | 12,714 | 6,192 | — | — | 23,297 | ||||||||||||
| Accumulated depreciation, depletion and amortization |
— | — | — | 133 | — | 8,129 | 9 | — | — | 8,271 | |||||||||||
| $ | — | — | — | 4,258 | — | 4,585 | 6,183 | — | — | 15,026 | |||||||||||
| • | 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. |
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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
| Millions of Dollars | ||||||||||||||||||||||
| Alaska | Lower 48 |
Total U.S. |
Canada | Europe | Russia | Asia Pacific/ Middle East |
Africa | Other Areas |
Total | |||||||||||||
| 2009 |
||||||||||||||||||||||
| Consolidated operations |
||||||||||||||||||||||
| Future cash inflows |
$ | 74,359 | 51,007 | 125,366 | 45,965 | 41,832 | — | 31,276 | 18,580 | 6,416 | 269,435 | |||||||||||
| Less: |
||||||||||||||||||||||
| Future production and transportation costs* |
44,789 | 32,491 | 77,280 | 23,625 | 13,559 | — | 9,058 | 4,142 | 2,071 | 129,735 | ||||||||||||
| Future development costs |
7,829 | 8,350 | 16,179 | 12,769 | 10,369 | — | 2,284 | 845 | 3,879 | 46,325 | ||||||||||||
| Future income tax provisions |
7,519 | 2,992 | 10,511 | 2,183 | 10,676 | — | 7,288 | 10,223 | 71 | 40,952 | ||||||||||||
| Future net cash flows |
14,222 | 7,174 | 21,396 | 7,388 | 7,228 | — | 12,646 | 3,370 | 395 | 52,423 | ||||||||||||
| 10 percent annual discount |
6,474 | 2,300 | 8,774 | 3,703 | 1,878 | — | 4,108 | 1,424 | 1,566 | 21,453 | ||||||||||||
| Discounted future net cash flows |
$ | 7,748 | 4,874 | 12,622 | 3,685 | 5,350 | — | 8,538 | 1,946 | (1,171 | ) | 30,970 | ||||||||||
| Equity affiliates |
||||||||||||||||||||||
| Future cash inflows |
$ | — | — | — | 36,540 | — | 69,277 | 19,420 | — | — | 125,237 | |||||||||||
| Less: |
||||||||||||||||||||||
| Future production and transportation costs* |
— | — | — | 13,689 | — | 49,874 | 13,891 | — | — | 77,454 | ||||||||||||
| Future development costs |
— | — | — | 4,481 | — | 7,795 | 350 | — | — | 12,626 | ||||||||||||
| Future income tax provisions |
— | — | — | 4,785 | — | 2,265 | 694 | — | — | 7,744 | ||||||||||||
| Future net cash flows |
— | — | — | 13,585 | — | 9,343 | 4,485 | — | — | 27,413 | ||||||||||||
| 10 percent annual discount |
— | — | — | 9,512 | — | 4,002 | 2,018 | — | — | 15,532 | ||||||||||||
| Discounted future net cash flows |
$ | — | — | — | 4,073 | — | 5,341 | 2,467 | — | — | 11,881 | |||||||||||
| Total company |
||||||||||||||||||||||
| Discounted future net cash flows |
$ | 7,748 | 4,874 | 12,622 | 7,758 | 5,350 | 5,341 | 11,005 | 1,946 | (1,171 | ) | 42,851 | ||||||||||
| * | Includes taxes other than income taxes. |
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| Millions of Dollars | ||||||||||||||||||||||
| Alaska | Lower 48 |
Total U.S. |
Canada | Europe | Russia | Asia Pacific/ Middle East |
Africa | Other Areas |
Total | |||||||||||||
| 2008 |
||||||||||||||||||||||
| Consolidated operations |
||||||||||||||||||||||
| Future cash inflows |
$ | 54,662 | 51,354 | 106,016 | 19,632 | 42,230 | — | 22,626 | 11,388 | 4,357 | 206,249 | |||||||||||
| Less: |
||||||||||||||||||||||
| Future production and transportation costs* |
35,150 | 30,5308 | 65,658 | 9,357 | 12,217 | — | 6,960 | 3,567 | 2,000 | 99,759 | ||||||||||||
| Future development costs |
9,681 | 10,443 | 20,124 | 4,188 | 8,835 | — | 2,859 | 440 | 2,084 | 38,530 | ||||||||||||
| Future income tax provisions |
3,227 | 3,439 | 6,666 | 401 | 11,679 | — | 4,880 | 6,082 | 248 | 29,956 | ||||||||||||
| Future net cash flows |
6,604 | 6,964 | 13,568 | 5,686 | 9,499 | — | 7,927 | 1,299 | 25 | 38,004 | ||||||||||||
| 10 percent annual discount |
2,159 | 2,886 | 5,045 | 1,222 | 3,178 | — | 2,998 | 398 | 703 | 13,544 | ||||||||||||
| Discounted future net cash flows |
$ | 4,445 | 4,078 | 8,523 | 4,464 | 6,321 | — | 4,929 | 901 | (678 | ) | 24,460 | ||||||||||
| Equity affiliates |
||||||||||||||||||||||
| Future cash inflows |
$ | — | — | — | 17,055 | — | 36,679 | 15,798 | — | — | 69,532 | |||||||||||
| Less: |
||||||||||||||||||||||
| Future production and transportation costs* |
— | — | — | 12,820 | — | 30,137 | 10,536 | — | — | 53,493 | ||||||||||||
| Future development costs |
— | — | — | 3,010 | — | 5,200 | 611 | — | — | 8,821 | ||||||||||||
| Future income tax provisions |
— | — | — | 252 | — | 260 | 379 | — | — | 891 | ||||||||||||
| Future net cash flows |
— | — | — | 973 | — | 1,082 | 4,272 | — | — | 6,327 | ||||||||||||
| 10 percent annual discount |
— | — | — | 894 | — | 119 | 2,281 | — | — | 3,294 | ||||||||||||
| Discounted future net cash flows |
$ | — | — | — | 79 | — | 963 | 1,991 | — | — | 3,033 | |||||||||||
| Total company |
||||||||||||||||||||||
| Discounted future net cash flows |
$ | 4,445 | 4,078 | 8,523 | 4,543 | 6,321 | 963 | 6,920 | 901 | (678 | ) | 27,493 | ||||||||||
| * | Includes taxes other than income taxes. |
| Excludes | discounted future net cash flows from Canadian Syncrude of $435 million. |
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| Millions of Dollars | |||||||||||||||||||||
| Alaska | Lower 48 |
Total U.S. |
Canada | Europe | Russia | Asia Pacific/ Middle East |
Africa | Other Areas |
Total | ||||||||||||
| 2007 |
|||||||||||||||||||||
| Consolidated operations |
|||||||||||||||||||||
| Future cash inflows |
$ | 133,909 | 94,706 | 228,615 | 30,125 | 83,367 | — | 46,520 | 31,509 | 12,075 | 432,211 | ||||||||||
| Less: |
|||||||||||||||||||||
| Future production and transportation costs* |
75,024 | 41,945 | 116,969 | 11,206 | 15,781 | — | 11,996 | 3,884 | 2,582 | 162,418 | |||||||||||
| Future development costs |
8,392 | 9,690 | 18,082 | 4,605 | 10,920 | — | 3,958 | 400 | 2,795 | 40,760 | |||||||||||
| Future income tax provisions |
18,798 | 14,793 | 33,591 | 2,235 | 37,645 | — | 12,331 | 22,599 | 1,690 | 110,091 | |||||||||||
| Future net cash flows |
31,695 | 28,278 | 59,973 | 12,079 | 19,021 | — | 18,235 | 4,626 | 5,008 | 118,942 | |||||||||||
| 10 percent annual discount |
16,510 | 12,158 | 28,668 | 3,870 | 5,776 | — | 7,113 | 1,847 | 4,506 | 51,780 | |||||||||||
| Discounted future net |
$ | 15,185 | 16,120 | 31,305 | 8,209 | 13,245 | — | 11,122 | 2,779 | 502 | 67,162 | ||||||||||
| Equity affiliates |
|||||||||||||||||||||
| Future cash inflows |
$ | — | — | — | 30,626 | — | 116,893 | 22,156 | — | — | 169,675 | ||||||||||
| Less: |
|||||||||||||||||||||
| Future production and transportation costs* |
— | — | — | 11,495 | — | 80,571 | 11,429 | — | — | 103,495 | |||||||||||
| Future development costs |
— | — | — | 3,065 | — | 7,518 | 264 | — | — | 10,847 | |||||||||||
| Future income tax provisions |
— | — | — | 3,656 | — | 7,826 | 899 | — | — | 12,381 | |||||||||||
| Future net cash flows |
— | — | — | 12,410 | — | 20,978 | 9,564 | — | — | 42,952 | |||||||||||
| 10 percent annual discount |
— | — | — | 8,521 | — | 9,293 | 5,111 | — | — | 22,925 | |||||||||||
| Discounted future net |
$ | — | — | — | 3,889 | — | 11,685 | 4,453 | — | — | 20,027 | ||||||||||
| Total company |
|||||||||||||||||||||
| Discounted future net |
$ | 15,185 | 16,120 | 31,305 | 12,098 | 13,245 | 11,685 | 15,575 | 2,779 | 502 | 87,189 | ||||||||||
| * | Includes taxes other than income taxes. |
| Excludes | discounted future net cash flows from Canadian Syncrude of $4,484 million. |
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Table of Contents
Sources of Change in Discounted Future Net Cash Flows
| Millions of Dollars | ||||||||||||||||||||||||||||||||
| Consolidated Operations | Equity Affiliates | Total Company | ||||||||||||||||||||||||||||||
| 2009 | 2008 | 2007 | 2009 | 2008 | 2007 | 2009 | 2008 | 2007 | ||||||||||||||||||||||||
| Discounted future net cash flows at the beginning of the year |
$ | 24,460 | 67,162 | 51,590 | 3,033 | 20,027 | 12,433 | 27,493 | 87,189 | 64,023 | ||||||||||||||||||||||
| Changes during the year |
||||||||||||||||||||||||||||||||
| Revenues less production and transportation costs for the year* |
(18,460 | ) | (32,149 | ) | (24,455 | ) | (3,686 | ) | (2,919 | ) | (3,321 | ) | (22,146 | ) | (35,068 | ) | (27,776 | ) | ||||||||||||||
| Net change in prices, and production and transportation costs* |
19,318 | (73,477 | ) | 49,461 | 15,279 | (22,495 | ) | 10,115 | 34,597 | (95,972 | ) | 59,576 | ||||||||||||||||||||
| Extensions, discoveries and improved recovery, less |
2,303 | 1,743 | 6,985 | 1,342 | 181 | 2,188 | 3,645 | 1,924 | 9,173 | |||||||||||||||||||||||
| Development costs for the year |
6,148 | 7,715 | 7,289 | 1,623 | 2,622 | 2,346 | 7,771 | 10,337 | 9,635 | |||||||||||||||||||||||
| Changes in estimated future development costs |
(7,085 | ) | (3,129 | ) | (10,813 | ) | (2,197 | ) | (813 | ) | (3,468 | ) | (9,282 | ) | (3,942 | ) | (14,281 | ) | ||||||||||||||
| Purchases of reserves in place, |
3 | 10 | 51 | 96 | 321 | 2,989 | 99 | 331 | 3,040 | |||||||||||||||||||||||
| Sales of reserves in place, less estimated future costs |
(75 | ) | (52 | ) | (1,347 | ) | — | (33 | ) | (9,619 | ) | (75 | ) | (85 | ) | (10,966 | ) | |||||||||||||||
| Revisions of previous quantity estimates** |
5,140 | 1,893 | (79 | ) | (1,597 | ) | (1,689 | ) | 3,855 | 3,543 | 204 | 3,776 | ||||||||||||||||||||
| Accretion of discount |
3,924 | 11,765 | 8,561 | 365 | 2,456 | 1,809 | 4,289 | 14,221 | 10,370 | |||||||||||||||||||||||
| Net change in income taxes |
(4,706 | ) | 42,979 | (20,081 | ) | (2,377 | ) | 5,375 | 700 | (7,083 | ) | 48,354 | (19,381 | ) | ||||||||||||||||||
| Total changes |
6,510 | (42,702 | ) | 15,572 | 8,848 | (16,994 | ) | 7,594 | 15,358 | (59,696 | ) | 23,166 | ||||||||||||||||||||
| Discounted future net cash flows at year end |
$ | 30,970 | 24,460 | 67,162 | 11,881 | 3,033 | 20,027 | 42,851 | 27,493 | 87,189 | ||||||||||||||||||||||
| * | 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. |
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DIRECTIONS TO THE ANNUAL MEETING OF STOCKHOLDERS
FROM DOWNTOWN HOUSTON
Omni Houston Hotel at Westside
13210 Katy Freeway
Houston, Texas 77079
(281) 558-8338
| • | Take I-10 West 3 miles past Sam Houston Tollway. |
| • | Exit Eldridge Parkway, Exit 753A. |
| • | Turn right (north) on Eldridge Parkway. |
| • | The hotel will be immediately on your left. |
Table of Contents
*** Exercise Your Right to Vote ***
IMPORTANT NOTICE Regarding the Availability of Proxy Materials
CONOCO PHILLIPS
Meeting Information
Meeting Type: Annual
For holders as of: March 15, 2010
Date: May 12, 2010 Time: 9:00 a.m. Central Time
Location: Omni Houston Hotel at Westside
13210 Katy Freeway
Houston, Texas 77079
ConocoPhillips
600 N. DAIRY ASHFORD MCLEAN BUILDING #3025 HOUSTON, TX 77079
You are receiving this communication because you hold shares in the above named company.
This is not a ballot. You cannot use this notice to vote these shares. This communication presents only an overview of the more complete proxy materials that are available to you on the Internet. You may view the proxy materials online at www.proxyvote.com or easily request a paper copy (see reverse side).
We encourage you to access and review all of the important information contained in the proxy materials before voting.
See the reverse side of this notice to obtain proxy materials and voting instructions.
M21378-P92996
Table of Contents
Before You Vote
How to Access the Proxy Materials
Proxy Materials Available to VIEW or RECEIVE:
NOTICE AND PROXY STATEMENT ANNUAL REPORT
How to View Online:
Have the 12-Digit Control Number available (located on the following page) and visit: www.proxyvote.com.
How to Request and Receive a PAPER or E-MAIL Copy:
If you want to receive a paper or e-mail copy of these documents, you must request one. There is NO charge for requesting a copy. Please choose one of the following methods to make your request:
1) BY INTERNET: www.proxyvote.com
2) BY TELEPHONE: 1-800-579-1639
3) BY E-MAIL*: sendmaterial@proxyvote.com
* If requesting materials by e-mail, please send a blank e-mail with the 12-Digit Control Number (located on the following page) in the subject line.
Requests, instructions and other inquiries sent to this e-mail address will NOT be forwarded to your investment advisor. Please make the request as instructed above on or before April 28, 2010 to facilitate timely delivery.
How To Vote
Please Choose One of the Following Voting Methods
Vote In Person: Many shareholder meetings have attendance requirements including, but not limited to, the possession of an attendance ticket issued by the entity holding the meeting. Please check the meeting materials for any special requirements for meeting attendance. At the Meeting you will need to request a ballot to vote these shares.
Vote By Internet: To vote now by Internet, go to www.proxyvote.com. Have the 12 Digit Control Number available and follow the instructions.
Vote By Mail: You can vote by mail by requesting a paper copy of the materials, which will include a proxy card.
M21379-P92996
Table of Contents
Voting Items
THE BOARD OF DIRECTORS RECOMMENDS A VOTE “FOR” ITEMS 1 AND 2.
1. ELECTION OF DIRECTORS
Nominees:
1a. Richard L. Armitage
1b. Richard H. Auchinleck
1c. James E. Copeland, Jr.
1d. Kenneth M. Duberstein
1e. Ruth R. Harkin
1f. Harold W. McGraw III
1g. James J. Mulva
1h. Robert A. Niblock
1i. Harald J. Norvik
1j. William K. Reilly
1k. Bobby S. Shackouls
1l. Victoria J. Tschinkel
1m. Kathryn C. Turner
1n. William E. Wade, Jr.
2. Proposal to ratify appointment of Ernst & Young LLP as ConocoPhillips’ independent registered public accounting firm for 2010.
THE BOARD OF DIRECTORS RECOMMENDS A VOTE “AGAINST” ITEMS 3-10.
3. Board Risk Management Oversight
4. Greenhouse Gas Reduction
5. Oil Sands Drilling
6. Louisiana Wetlands
7. Financial Risks of Climate Change
8. Toxic Pollution Report
9. Gender Expression Non-Discrimination
10. Political Contributions
11. In its discretion, upon such other matters that may properly come before the meeting or any adjournment or adjournments thereof.
M21380-P92996
Table of Contents
M21381-P92996
Table of Contents
ConocoPhillips
600 N. DAIRY ASHFORD
MCLEAN BUILDING #3025
HOUSTON, TX 77079
VOTE BY INTERNET - www.proxyvote.com
Use the Internet to transmit your voting instructions and for electronic delivery of information up until the cut-off date. Have your Voting Direction card in hand when you access the web site and follow the instructions to obtain your records and to create an electronic voting instruction form.
ELECTRONIC DELIVERY OF FUTURE STOCKHOLDER COMMUNICATIONS
If you would like to reduce the costs incurred by ConocoPhillips in mailing proxy materials, you can consent to receiving all future proxy statements, Voting Direction cards and annual reports electronically via e-mail or the Internet. To sign up for electronic delivery, please follow the instructions above to vote using the Internet and, when prompted, indicate that you agree to receive or access stockholder communications electronically in future years.
VOTE BY PHONE - 1-800-690-6903
Use any touch-tone telephone to transmit your voting instructions up until 11:59 p.m. Eastern Time the day before the cut-off date or meeting date. Have your Voting Direction card in hand when you call and then follow the instructions.
VOTE BY MAIL
Mark, sign and date your Voting Direction card and return it in the postage-paid envelope we have provided or return it to ConocoPhillips, c/o Broadridge, 51 Mercedes Way, Edgewood, NY 11717.
TO VOTE, MARK BLOCKS BELOW IN BLUE OR BLACK INK AS FOLLOWS:
M21262-Z52130 KEEP THIS PORTION FOR YOUR RECORDS
THIS VOTING DIRECTION CARD IS VALID ONLY WHEN SIGNED AND DATED. DETACH AND RETURN THIS PORTION ONLY
CONOCOPHILLIPS
THE BOARD OF DIRECTORS RECOMMENDS A VOTE “FOR” ITEMS 1 AND 2.
1. ELECTION OF DIRECTORS For Against Abstain
Nominees:
1a. Richard L. Armitage
1b. Richard H. Auchinleck
1c. James E. Copeland, Jr.
1d. Kenneth M. Duberstein
1e. Ruth R. Harkin
1f. Harold W. McGraw III
1g. James J. Mulva
1h. Robert A. Niblock
1i. Harald J. Norvik
1j. William K. Reilly
1k. Bobby S. Shackouls
1l. Victoria J. Tschinkel
1m. Kathryn C. Turner
1n. William E. Wade, Jr.
2. Proposal to ratify appointment of Ernst & Young LLP as ConocoPhillips’ independent registered public accounting firm for 2010.
THE BOARD OF DIRECTORS RECOMMENDS A VOTE “AGAINST” ITEMS 3-10.
For Against Abstain
3. Board Risk Management Oversight
4. Greenhouse Gas Reduction
5. Oil Sands Drilling
6. Louisiana Wetlands
7. Financial Risks of Climate Change
8. Toxic Pollution Report
9. Gender Expression Non-Discrimination
10. Political Contributions
11. In its discretion, upon such other matters that may properly come before the meeting or any adjournment or adjournments thereof.
Signature [PLEASE SIGN WITHIN BOX] Date Signature (Joint Owners) Date
Table of Contents
Important Notice Regarding the Availability of Proxy Materials for the Annual Meeting:
The Notice and Proxy Statement and Annual Report are available at www.proxyvote.com.
M21263-Z52130
CONOCOPHILLIPS
CONOCOPHILLIPS UK, Australia, Norway Plans
CONFIDENTIAL VOTING DIRECTION
ConocoPhillips Annual Meeting of Stockholders May 12, 2010
The undersigned hereby directs that EES Trustees Limited, Trustee of the ConocoPhillips Share Incentive Plan, ConocoPhillips Overseas Stock Savings Plan (Australia or Norway), Conoco Stock Ownership Plan, Employee Share Allocation Scheme of Phillips Petroleum Company United Kingdom Limited, and/or Conoco Employee Share Ownership Plan (the “Plan”), vote all shares of ConocoPhillips Common Stock (described on the back of this Voting Direction card) at the ConocoPhillips Annual Meeting of Stockholders to be held at the Omni Houston Hotel at Westside, 13210 Katy Freeway, Houston, Texas, on May 12, 2010, at 9:00 a.m., Central Time, and at any adjournment thereof, in the manner indicated on the back of this card as to the matters shown and at its discretion as to any other matters that come before the meeting, all as described in the Notice and Proxy Statement.
In order for your vote to be counted, Broadridge, the Tabulator for the Trustee, EES Trustees Limited, must receive this Voting Direction card no later than 11:59 p.m. EDT on May 5, 2010. If Broadridge, the Tabulator for the Trustee, Vanguard Fiduciary Trust Company, does not receive this Voting Direction card by 11:59 p.m. EDT on May 5, 2010, if you do not fill in any boxes on the back of this card, if you return this card unsigned, and if you do not vote by the Internet or telephone on or before May 5, 2010, any shares held in the ConocoPhillips Overseas Savings Plan (Australia or Norway) or the Employee Share Allocation Scheme of Phillips Petroleum Company United Kingdom Limited that you otherwise could have directed will be voted in the same proportion as the shares for which the Trustee has received instructions. Any such shares held in the ConocoPhillips Share Incentive Plan, the Conoco Stock Ownership Plan or the Conoco Employee Share Ownership Plan will not be voted by the Trustee.
ConocoPhillips has acknowledged and agreed to honor the confidentiality of your voting instructions to the Trustee. The Trustee will keep your voting instructions confidential.
This package contains your confidential Voting Direction card to instruct the Trustee of the Plan how to vote the shares of ConocoPhillips Common Stock described on the back of the card representing your interest in the Plan.
Also enclosed is the Company’s 2009 Summary Annual Report along with the Notice and Proxy Statement for the 2010 Annual Meeting. Please use these documents to help you decide how to direct the way the Trustee (EES Trustees Limited) should vote.
Address Changes/Comments:
(If you noted any Address Changes/Comments above, please mark corresponding box on the reverse side.)
CONTINUED AND TO BE SIGNED ON REVERSE SIDE
Table of Contents
ConocoPhillips
600 N. DAIRY ASHFORD
MCLEAN BUILDING #3025
HOUSTON, TX 77079
VOTE BY INTERNET - www.proxyvote.com
Use the Internet to transmit your voting instructions and for electronic delivery of information up until the cut-off date. Have your Voting Direction card in hand when you access the web site and follow the instructions to obtain your records and to create an electronic voting instruction form.
ELECTRONIC DELIVERY OF FUTURE STOCKHOLDER COMMUNICATIONS
If you would like to reduce the costs incurred by ConocoPhillips in mailing proxy materials, you can consent to receiving all future proxy statements, Voting Direction cards and annual reports electronically via e-mail or the Internet. To sign up for electronic delivery, please follow the instructions above to vote using the Internet and, when prompted, indicate that you agree to receive or access stockholder communications electronically in future years.
VOTE BY PHONE - 1-800-690-6903
Use any touch-tone telephone to transmit your voting instructions up until 11:59 p.m. Eastern Time the day before the cut-off date or meeting date. Have your Voting Direction card in hand when you call and then follow the instructions.
VOTE BY MAIL
Mark, sign and date your Voting Direction card and return it in the postage-paid envelope we have provided or return it to CONOCOPHILLIPS, c/o Broadridge, 51 Mercedes Way, Edgewood, NY 11717.
TO VOTE, MARK BLOCKS BELOW IN BLUE OR BLACK INK AS FOLLOWS:
M21264-Z52124, Z52127, Z52128 KEEP THIS PORTION FOR YOUR RECORDS
THIS VOTING DIRECTION CARD IS VALID ONLY WHEN SIGNED AND DATED. DETACH AND RETURN THIS PORTION ONLY
CONOCOPHILLIPS
THE BOARD OF DIRECTORS RECOMMENDS A VOTE “FOR” ITEMS 1 AND 2.
1. ELECTION OF DIRECTORS For Against Abstain
Nominees:
1a. Richard L. Armitage
1b. Richard H. Auchinleck
1c. James E. Copeland, Jr.
1d. Kenneth M. Duberstein
1e. Ruth R. Harkin
1f. Harold W. McGraw III
1g. James J. Mulva
1h. Robert A. Niblock
1i. Harald J. Norvik
1j. William K. Reilly
1k. Bobby S. Shackouls
1l. Victoria J. Tschinkel
1m. Kathryn C. Turner
1n. William E. Wade, Jr.
2. Proposal to ratify appointment of Ernst & Young LLP as ConocoPhillips’ independent registered public accounting firm for 2010.
THE BOARD OF DIRECTORS RECOMMENDS A VOTE
For Against Abstain
“AGAINST” ITEMS 3-10.
3. Board Risk Management Oversight
4. Greenhouse Gas Reduction
5. Oil Sands Drilling
6. Louisiana Wetlands
7. Financial Risks of Climate Change
8. Toxic Pollution Report
9. Gender Expression Non-Discrimination
10. Political Contributions
11. In its discretion, upon such other matters that may properly come before the meeting or any adjournment or adjournments thereof.
Signature [PLEASE SIGN WITHIN BOX] Date Signature (Joint Owners) Date
Table of Contents
Important Notice Regarding the Availability of Proxy Materials for the Annual Meeting:
The Notice and Proxy Statement and Annual Report are available at www.proxyvote.com.
M21265-Z52124, Z52127, Z52128
ConocoPhillips
ConocoPhillips Savings Plan
CONFIDENTIAL FIDUCIARY VOTING DIRECTION
ConocoPhillips Annual Meeting of Stockholders May 12, 2010
The undersigned hereby directs that Vanguard Fiduciary Trust Company, Trustee of the ConocoPhillips Savings Plan (“CPSP”), vote: (1) all unallocated shares of stock in the Company Stock Fund and (2) all shares of stock representing the interest of CPSP and/or CPSSP participants who fail to give voting direction at the ConocoPhillips Annual Meeting of Stockholders to be held at the Omni Houston Hotel at Westside, 13210 Katy Freeway, Houston, Texas, on May 12, 2010, at 9:00 a.m., Central Time, and at any adjournment thereof, in the manner indicated on the back of this card as to the matters shown and at its discretion as to any other matters that come before the meeting, all as described in the Notice and Proxy Statement. If Broadridge, the Tabulator for the Trustee, Vanguard Fiduciary Trust Company, does not receive this Voting Direction card by May 7, 2010 at 11:59 p.m. EDT, if you do not fill in any boxes on the back of this card, if you return this card unsigned, and if you do not vote by the Internet or telephone on or before May 7, 2010, any shares in the CPSP that you otherwise could have directed will be directed by other eligible employees who elect to direct such shares.
Important Information - I understand that by electing to direct the Trustee’s vote of shares which do not represent my own part of the CPSP that I become a fiduciary of the CPSP for voting such shares; that I must act in the best interests of all participants of the CPSP when giving directions for voting shares not representing my part of the CPSP; that I have read and understand my duties as a fiduciary as they are described on pages 32 and 33 of the CPSP Employee Handbook dated January 1, 2008; and that I may decline to accept the responsibility of a fiduciary as to such shares by NOT completing or returning this Voting Direction card or NOT voting by Internet or telephone.
ConocoPhillips has acknowledged and agreed to honor the confidentiality of your voting instructions to the Trustee. The Trustee will keep your voting instructions confidential.
This package contains your confidential Voting Direction card to instruct the Trustee of the Plan how to vote the shares of ConocoPhillips Common Stock described on the back of the card representing your interest in the CPSP Plan. Also enclosed is the Company’s 2009 Summary Annual Report along with the Notice and Proxy Statement for the 2010 Annual Meeting. Please use these documents to help you decide how to direct the way the Trustee (Vanguard Fiduciary Trust Company) should vote.
Address Changes/Comments:
(If you noted any Address Changes/Comments above, please mark corresponding box on the reverse side.)
CONTINUED AND TO BE SIGNED ON REVERSE SIDE
Table of Contents
ConocoPhillips
600 N. DAIRY ASHFORD
MCLEAN BUILDING #3025
HOUSTON, TX 77079
VOTE BY INTERNET - www.proxyvote.com
Use the Internet to transmit your voting instructions and for electronic delivery of information up until the cut-off date. Have your Voting Direction card in hand when you access the web site and follow the instructions to obtain your records and to create an electronic voting instruction form.
ELECTRONIC DELIVERY OF FUTURE STOCKHOLDER COMMUNICATIONS
If you would like to reduce the costs incurred by ConocoPhillips in mailing proxy materials, you can consent to receiving all future proxy statements, Voting Direction cards and annual reports electronically via e-mail or the Internet. To sign up for electronic delivery, please follow the instructions above to vote using the Internet and, when prompted, indicate that you agree to receive or access stockholder communications electronically in future years.
VOTE BY PHONE - 1-800-690-6903
Use any touch-tone telephone to transmit your voting instructions up until 11:59 p.m. Eastern Time the day before the cut-off date or meeting date. Have your Voting Direction card in hand when you call and then follow the instructions.
VOTE BY MAIL
Mark, sign and date your Voting Direction card and return it in the postage-paid envelope we have provided or return it to ConocoPhillips, c/o Broadridge, 51 Mercedes Way, Edgewood, NY 11717.
TO VOTE, MARK BLOCKS BELOW IN BLUE OR BLACK INK AS FOLLOWS:
M21266-Z52129 KEEP THIS PORTION FOR YOUR RECORDS
THIS VOTING DIRECTION CARD IS VALID ONLY WHEN SIGNED AND DATED. DETACH AND RETURN THIS PORTION ONLY
CONOCOPHILLIPS
THE BOARD OF DIRECTORS RECOMMENDS A VOTE “FOR” ITEMS 1 AND 2.
1. ELECTION OF DIRECTORS For Against Abstain
Nominees:
1a. Richard L. Armitage
1b. Richard H. Auchinleck
1c. James E. Copeland, Jr.
1d. Kenneth M. Duberstein
1e. Ruth R. Harkin
1f. Harold W. McGraw III
1g. James J. Mulva
1h. Robert A. Niblock
1i. Harald J. Norvik
1j. William K. Reilly
1k. Bobby S. Shackouls
1l. Victoria J. Tschinkel
1m. Kathryn C. Turner
1n. William E. Wade, Jr.
2. Proposal to ratify appointment of Ernst & Young LLP as ConocoPhillips’ independent registered public accounting firm for 2010.
THE BOARD OF DIRECTORS RECOMMENDS A VOTE “AGAINST” ITEMS 3-10.
For Against Abstain
3. Board Risk Management Oversight
4. Greenhouse Gas Reduction
5. Oil Sands Drilling
6. Louisiana Wetlands
7. Financial Risks of Climate Change
8. Toxic Pollution Report
9. Gender Expression Non-Discrimination
10. Political Contributions
11. In its discretion, upon such other matters that may properly come before the meeting or any adjournment or adjournments thereof.
Signature [PLEASE SIGN WITHIN BOX] Date Signature (Joint Owners) Date
Table of Contents
Important Notice Regarding the Availability of Proxy Materials for the Annual Meeting:
The Notice and Proxy Statement and Annual Report are available at www.proxyvote.com.
M21267-Z52129
CONOCOPHILLIPS
Compensation and Benefits Arrangements Stock Trust CONFIDENTIAL FIDUCIARY VOTING DIRECTION
CONOCOPHILLIPS ANNUAL MEETING OF STOCKHOLDERS MAY 12, 2010
The undersigned hereby directs that Vanguard Fiduciary Trust Company, Trustee of the ConocoPhillips Compensation and Benefits Arrangements Stock Trust (“CBT”), vote all shares of ConocoPhillips Common Stock (described on the back of this Voting Direction card) at the ConocoPhillips Annual Meeting of Stockholders to be held at the Omni Houston Hotel at Westside, 13210 Katy Freeway, Houston, Texas, on May 12, 2010, at 9:00 a.m., Central Time, and at any adjournment thereof, in the manner indicated on the back of this card as to the matters shown and at its discretion as to any other matters that come before the meeting, all as described in the Notice and Proxy Statement.
I understand that by electing to direct the Trustee’s vote of domestic shares held in the CBT, that I become a directing fiduciary of the CBT for voting such shares; and that I may decline to accept the responsibility of a directing fiduciary as to such shares by NOT completing and returning this Voting Direction card or NOT voting by the Internet or telephone.
If Broadridge, the Tabulator for the Trustee, Vanguard Fiduciary Trust Company, does not receive this card by 5:00 p.m. EDT on May 7, 2010, if you do not fill in any boxes or if you return this card unsigned, and if you do not vote by the Internet or telephone on or before May 7, 2010, the Trustee will conclusively presume that you have rejected your appointment as a directing fiduciary and any shares in the CBT that you otherwise could have directed will be directed by other eligible employees who elect to direct such shares.
ConocoPhillips has acknowledged and agreed to honor the confidentiality of your voting instructions to the Trustee. The Trustee will keep your voting instructions confidential.
This package contains your confidential Voting Direction card to instruct the Trustee of the Plan how to vote the shares of ConocoPhillips Common Stock described on the back of the card.
Also enclosed is the Company’s 2009 Summary Annual Report along with the Notice and Proxy Statement for the 2010 Annual Meeting. Please use these documents to help you decide how to direct the way the Trustee (Vanguard Fiduciary Trust Company) should vote.
Employees who direct the CBT Trustee how to vote shares held by this trust have an important voice in matters which affect ConocoPhillips.
Address Changes/Comments:
(If you noted any Address Changes/Comments above, please mark corresponding box on the reverse side.)
CONTINUED AND TO BE SIGNED ON REVERSE SIDE
Table of Contents
ConocoPhillips
600 N. DAIRY ASHFORD
MCLEAN BUILDING #3025
HOUSTON, TX 77079
VOTE BY INTERNET - www.proxyvote.com
Use the Internet to transmit your voting instructions and for electronic delivery of information up until the cut-off date. Have your Voting Direction card in hand when you access the web site and follow the instructions to obtain your records and to create an electronic voting instruction form.
ELECTRONIC DELIVERY OF FUTURE STOCKHOLDER COMMUNICATIONS
If you would like to reduce the costs incurred by ConocoPhillips in mailing proxy materials, you can consent to receiving all future proxy statements, Voting Direction cards and annual reports electronically via e-mail or the Internet. To sign up for electronic delivery, please follow the instructions above to vote using the Internet and, when prompted, indicate that you agree to receive or access stockholder communications electronically in future years.
VOTE BY PHONE - 1-800-690-6903
Use any touch-tone telephone to transmit your voting instructions up until 11:59 p.m. Eastern Time the day before the cut-off date or meeting date. Have your Voting Direction card in hand when you call and then follow the instructions.
VOTE BY MAIL
Mark, sign and date your Voting Direction card and return it in the postage-paid envelope we have provided or return it to ConocoPhillips, c/o Broadridge, 51 Mercedes Way, Edgewood, NY 11717.
TO VOTE, MARK BLOCKS BELOW IN BLUE OR BLACK INK AS FOLLOWS:
M21268-P92996 KEEP THIS PORTION FOR YOUR RECORDS
THIS VOTING DIRECTION CARD IS VALID ONLY WHEN SIGNED AND DATED. DETACH AND RETURN THIS PORTION ONLY
CONOCOPHILLIPS
THE BOARD OF DIRECTORS RECOMMENDS A VOTE “FOR” ITEMS 1 AND 2.
1. ELECTION OF DIRECTORS For Against Abstain
Nominees:
1a. Richard L. Armitage
1b. Richard H. Auchinleck
1c. James E. Copeland, Jr.
1d. Kenneth M. Duberstein
1e. Ruth R. Harkin
1f. Harold W. McGraw III
1g. James J. Mulva
1h. Robert A. Niblock
1i. Harald J. Norvik
1j. William K. Reilly
1k. Bobby S. Shackouls
1l. Victoria J. Tschinkel
1m. Kathryn C. Turner
1n. William E. Wade, Jr.
2. Proposal to ratify appointment of Ernst & Young LLP as ConocoPhillips’ independent registered public accounting firm for 2010.
THE BOARD OF DIRECTORS RECOMMENDS A VOTE
“AGAINST” ITEMS 3-10.
For Against Abstain
3. Board Risk Management Oversight
4. Greenhouse Gas Reduction
5. Oil Sands Drilling
6. Louisiana Wetlands
7. Financial Risks of Climate Change
8. Toxic Pollution Report
9. Gender Expression Non-Discrimination
10. Political Contributions
11. In its discretion, upon such other matters that may properly come before the meeting or any adjournment or adjournments thereof.
Signature [PLEASE SIGN WITHIN BOX] Date Signature (Joint Owners) Date
Table of Contents
Important Notice Regarding the Availability of Proxy Materials for the Annual Meeting:
The Notice and Proxy Statement and Annual Report are available at www.proxyvote.com.
M21269-P92996
CONOCOPHILLIPS
THIS PROXY IS SOLICITED ON BEHALF OF THE BOARD OF DIRECTORS
ANNUAL MEETING OF STOCKHOLDERS MAY 12, 2010
The stockholder(s) hereby appoint(s) James J. Mulva and Janet Langford Kelly, or either of them, as proxies, each with the power to appoint his or her substitute, and hereby authorize(s) them to represent and to vote, as designated on the reverse side of this ballot, all of the shares of Common Stock of ConocoPhillips that the stockholder(s) is/are entitled to vote at the Annual Meeting of Stockholders to be held at 9:00 a.m., Central Time, on May 12, 2010, at the Omni Houston Hotel at Westside, 13210 Katy Freeway, Houston, Texas, and any adjournment or postponement thereof.
THIS PROXY, WHEN PROPERLY EXECUTED, WILL BE VOTED AS DIRECTED BY THE STOCKHOLDER(S). IF NO SUCH DIRECTIONS ARE MADE, THIS PROXY WILL BE VOTED FOR THE ELECTION OF THE NOMINEES LISTED ON THE REVERSE SIDE FOR THE BOARD OF DIRECTORS, FOR THE RATIFICATION OF THE APPOINTMENT OF ERNST & YOUNG LLP AS CONOCOPHILLIPS’ INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM, AND AGAINST EACH OF THE STOCKHOLDER PROPOSALS.
PLEASE MARK, SIGN, DATE AND RETURN THIS PROXY CARD PROMPTLY USING THE ENCLOSED REPLY ENVELOPE
Address Changes/Comments:
(If you noted any Address Changes/Comments above, please mark corresponding box on the reverse side.)
CONTINUED AND TO BE SIGNED ON REVERSE SIDE
Table of Contents
ConocoPhillips
600 N. DAIRY ASHFORD
MCLEAN BUILDING #3025
HOUSTON, TX 77079
VOTE BY INTERNET - www.proxyvote.com
Use the Internet to transmit your voting instructions and for electronic delivery of information up until the cut-off date. Have your Voting Direction card in hand when you access the web site and follow the instructions to obtain your records and to create an electronic voting instruction form.
ELECTRONIC DELIVERY OF FUTURE STOCKHOLDER COMMUNICATIONS
If you would like to reduce the costs incurred by ConocoPhillips in mailing proxy materials, you can consent to receiving all future proxy statements, Voting Direction cards and annual reports electronically via e-mail or the Internet. To sign up for electronic delivery, please follow the instructions above to vote using the Internet and, when prompted, indicate that you agree to receive or access stockholder communications electronically in future years.
VOTE BY PHONE - 1-800-690-6903
Use any touch-tone telephone to transmit your voting instructions up until 11:59 p.m. Eastern Time the day before the cut-off date or meeting date. Have your Voting Direction card in hand when you call and then follow the instructions.
VOTE BY MAIL
Mark, sign and date your Voting Direction card and return it in the postage-paid envelope we have provided or return it to ConocoPhillips, c/o Broadridge, 51 Mercedes Way, Edgewood, NY 11717.
TO VOTE, MARK BLOCKS BELOW IN BLUE OR BLACK INK AS FOLLOWS:
M21270-Z52127 KEEP THIS PORTION FOR YOUR RECORDS
THIS VOTING DIRECTION CARD IS VALID ONLY WHEN SIGNED AND DATED. DETACH AND RETURN THIS PORTION ONLY
CONOCOPHILLIPS
THE BOARD OF DIRECTORS RECOMMENDS A VOTE “FOR” ITEMS 1 AND 2.
1. ELECTION OF DIRECTORS For Against Abstain
Nominees:
1a. Richard L. Armitage
1b. Richard H. Auchinleck
1c. James E. Copeland, Jr.
1d. Kenneth M. Duberstein
1e. Ruth R. Harkin
1f. Harold W. McGraw III
1g. James J. Mulva
1h. Robert A. Niblock
1i. Harald J. Norvik
1j. William K. Reilly
1k. Bobby S. Shackouls
1l. Victoria J. Tschinkel
1m. Kathryn C. Turner
1n. William E. Wade, Jr.
2. Proposal to ratify appointment of Ernst & Young LLP as ConocoPhillips’ independent registered public accounting firm for 2010.
THE BOARD OF DIRECTORS RECOMMENDS A VOTE
“AGAINST” ITEMS 3-10.
For Against Abstain
3. Board Risk Management Oversight
4. Greenhouse Gas Reduction
5. Oil Sands Drilling
6. Louisiana Wetlands
7. Financial Risks of Climate Change
8. Toxic Pollution Report
9. Gender Expression Non-Discrimination
10. Political Contributions
11. In its discretion, upon such other matters that may properly come before the meeting or any adjournment or adjournments thereof.
Signature [PLEASE SIGN WITHIN BOX] Date Signature (Joint Owners) Date
Table of Contents
Important Notice Regarding the Availability of Proxy Materials for the Annual Meeting:
The Notice and Proxy Statement and Annual Report are available at www.proxyvote.com.
M21271-Z52127
ConocoPhillips
ConocoPhillips Savings Plan CONFIDENTIAL VOTING DIRECTION
ConocoPhillips Annual Meeting of Stockholders May 12, 2010
The undersigned hereby directs that Vanguard Fiduciary Trust Company, Trustee of the ConocoPhillips Savings Plan (“CPSP”), vote all shares of ConocoPhillips Common Stock (described on the back of this Voting Direction card) at the ConocoPhillips Annual Meeting of Stockholders to be held at the Omni Houston Hotel at Westside, 13210 Katy Freeway, Houston, Texas, on May 12, 2010, at 9:00 a.m., Central Time, and at any adjournment thereof, in the manner indicated on the back of this card as to the matters shown and at its discretion as to any other matters that come before the meeting, all as described in the Notice and Proxy Statement.
If Broadridge, the Tabulator for the Trustee, The Vanguard Fiduciary Trust Company, does not receive this Voting Direction card by 11:59 p.m. EDT on May 7, 2010, if you do not fill in any boxes on the back of this card, if you return this card unsigned, and if you do not vote by the Internet or telephone on or before May 7, 2010, any shares in the CPSP that you otherwise could have directed will be directed by other eligible employees who elect to direct such shares.
ConocoPhillips has acknowledged and agreed to honor the confidentiality of your voting instructions to the Trustee. The Trustee will keep your voting instructions confidential.
This package contains your confidential Voting Direction card to instruct the Trustee of the Plan how to vote the shares of ConocoPhillips Common Stock described on the back of the card representing your interest in the Plan.
Also enclosed is the Company’s 2009 Summary Annual Report along with the Notice and Proxy Statement for the 2010 Annual Meeting. Please use these documents to help you decide how to direct the way the Trustee (Vanguard Fiduciary Trust Company) should vote.
Address Changes/Comments:
(If you noted any Address Changes/Comments above, please mark corresponding box on the reverse side.)
CONTINUED AND TO BE SIGNED ON REVERSE SIDE
Table of Contents
ConocoPhillips
600 N. DAIRY ASHFORD
MCLEAN BUILDING #3025
HOUSTON, TX 77079
VOTE BY INTERNET - www.proxyvote.com
Use the Internet to transmit your voting instructions and for electronic delivery of information up until the cut-off date. Have your Voting Direction card in hand when you access the web site and follow the instructions to obtain your records and to create an electronic voting instruction form.
ELECTRONIC DELIVERY OF FUTURE STOCKHOLDER COMMUNICATIONS
If you would like to reduce the costs incurred by ConocoPhillips in mailing proxy materials, you can consent to receiving all future proxy statements, Voting Direction cards and annual reports electronically via e-mail or the Internet. To sign up for electronic delivery, please follow the instructions above to vote using the Internet and, when prompted, indicate that you agree to receive or access stockholder communications electronically in future years.
VOTE BY PHONE - 1-800-690-6903
Use any touch-tone telephone to transmit your voting instructions up until 11:59 p.m. Eastern Time the day before the cut-off date or meeting date. Have your Voting Direction card in hand when you call and then follow the instructions.
VOTE BY MAIL
Mark, sign and date your Voting Direction card and return it in the postage-paid envelope we have provided or return it to ConocoPhillips, c/o Broadridge, 51 Mercedes Way, Edgewood, NY 11717.
TO VOTE, MARK BLOCKS BELOW IN BLUE OR BLACK INK AS FOLLOWS:
M21272-Z52123 KEEP THIS PORTION FOR YOUR RECORDS
THIS VOTING DIRECTION CARD IS VALID ONLY WHEN SIGNED AND DATED. DETACH AND RETURN THIS PORTION ONLY
CONOCOPHILLIPS
THE BOARD OF DIRECTORS RECOMMENDS A VOTE “FOR” ITEMS 1 AND 2.
1. ELECTION OF DIRECTORS For Against Abstain
Nominees:
1a. Richard L. Armitage
1b. Richard H. Auchinleck
1c. James E. Copeland, Jr.
1d. Kenneth M. Duberstein
1e. Ruth R. Harkin
1f. Harold W. McGraw III
1g. James J. Mulva
1h. Robert A. Niblock
1i. Harald J. Norvik
1j. William K. Reilly
1k. Bobby S. Shackouls
1l. Victoria J. Tschinkel
1m. Kathryn C. Turner
1n. William E. Wade, Jr.
2. Proposal to ratify appointment of Ernst & Young LLP as ConocoPhillips’ independent registered public accounting firm for 2010.
THE BOARD OF DIRECTORS RECOMMENDS A VOTE “AGAINST” ITEMS 3-10.
For Against Abstain
3. Board Risk Management Oversight
4. Greenhouse Gas Reduction
5. Oil Sands Drilling
6. Louisiana Wetlands
7. Financial Risks of Climate Change
8. Toxic Pollution Report
9. Gender Expression Non-Discrimination
10. Political Contributions
11. In its discretion, upon such other matters that may properly come before the meeting or any adjournment or adjournments thereof.
Signature [PLEASE SIGN WITHIN BOX] Date Signature (Joint Owners) Date
Table of Contents
Important Notice Regarding the Availability of Proxy Materials for the Annual Meeting:
The Notice and Proxy Statement and Annual Report are available at www.proxyvote.com.
M21273-Z52123
ConocoPhillips
ConocoPhillips Canada Employee Stock Ownership Plan Voting Direction
ANNUAL MEETING OF STOCKHOLDERS MAY 12, 2010
The undersigned hereby directs that Computershare Trust Company of Canada, Trustee of the ConocoPhillips Canada Employee Stock Ownership Plan (the “Canadian Plan”), vote all shares of ConocoPhillips Common Stock (as set out on the back of this Voting Direction card) at the ConocoPhillips Annual Meeting of Stockholders to be held at the Omni Houston Hotel at Westside, 13210 Katy Freeway, Houston, Texas, on May 12, 2010, at 9:00 a.m., Central Time, and any adjournment thereof, in the manner indicated on the back of this card as to the matters shown and at its discretion as to any other matters that come before the meeting, all described in the Proxy Statement and the Company’s Notice of the Annual Meeting on May 12, 2010.
If Broadridge, the Tabulator for the Trustees, Computershare Trust Company of Canada, does not receive this Voting Direction card by 11:59 p.m. EDT on May 7, 2010, if you do not fill in any boxes on the back of this card, if you return this card unsigned, and if you do not vote by the Internet or telephone on or before May 7, 2010, any shares representing your part of the Canadian Plan will not be voted by the Trustee.
This package contains your Voting Direction card to instruct the Trustee of the Canadian Plan how to vote shares of ConocoPhillips Common Stock described on the back of the card representing your interest in the Canadian Plan.
Also enclosed is the Company’s Notice and Proxy Statement for the 2010 Annual Meeting and the Company’s 2009 Summary Annual Report. Please use these documents to help you to decide how to direct the way the Trustee (Computershare Trust Company of Canada) should vote.
Address Changes/Comments:
(If you noted any Address Changes/Comments above, please mark corresponding box on the reverse side.)
CONTINUED AND TO BE SIGNED ON REVERSE SIDE
Table of Contents
CONOCO PHILLIPS
ANNUAL MEETING FOR HOLDERS AS OF 3/15/10
TO BE HELD ON 5/12/10
Your vote is important. Thank you for voting.
To vote by Internet
1) Read the Proxy Statement and have the voting instruction form below at hand.
2) Go to website www.proxyvote.com.
3) Follow the instructions provided on the website.
To vote by Telephone
1) Read the Proxy Statement and have the voting instruction form below at hand.
2) Call 1-800-454-8683.
3) Follow the instructions.
To vote by Mail
1) Read the Proxy Statement.
2) Check the appropriate boxes on the voting instruction form below.
3) Sign and date the voting instruction form.
4) Return the voting instruction form in the envelope provided.
TO VOTE, MARK BLOCKS BELOW IN BLUE OR BLACK INK AS FOLLOWS: M21311-P89178
Important Notice Regarding the Availability of Proxy Materials for the Shareholder Meeting. The following material is available at www.proxyvote.com. Notice and Proxy Statement and Annual Report
THE BOARD OF DIRECTORS RECOMMENDS A VOTE “FOR” ITEMS 1 AND 2.
Vote On Directors
1. ELECTION OF DIRECTORS For Against Abstain
Nominees:
1a. Richard L. Armitage
1b. Richard H. Auchinleck
1c. James E. Copeland, Jr.
1d. Kenneth M. Duberstein
1e. Ruth R. Harkin
1f. Harold W. McGraw III
1g. James J. Mulva
1h. Robert A. Niblock
1i. Harald J. Norvik
1j. William K. Reilly
1k. Bobby S. Shackouls
1l. Victoria J. Tschinkel
NOTE: SUCH OTHER BUSINESS AS MAY PROPERLY COME BEFORE THE MEETING OR ANY ADJOURNMENT THEREOF.
PLEASE “X” HERE ONLY IF YOU PLAN TO ATTEND THE MEETING AND VOTE THESE SHARES IN PERSON
For Against Abstain
1m. Kathryn C. Turner
1n. William E. Wade, Jr.
Vote On Proposals
2. Proposal to ratify appointment of Ernst & Young LLP as ConocoPhillips’ independent registered public accounting firm for 2010.
THE BOARD OF DIRECTORS RECOMMENDS A VOTE “AGAINST” ITEMS 3-10.
3. Board Risk Management Oversight
4. Greenhouse Gas Reduction
5. Oil Sands Drilling
6. Louisiana Wetlands
7. Financial Risks of Climate Change
8. Toxic Pollution Report
9. Gender Expression Non-Discrimination
10. Political Contributions
Signature [PLEASE SIGN WITHIN BOX] Date