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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 2012 ANNUAL STOCKHOLDERS MEETING
AND PROXY STATEMENT
March 28, 2012
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 9, 2012, at 9:00 a.m. CDT.
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 2011 followed by a question and answer period.
As you may know, we are progressing plans to effect the repositioning of the Company into two leading energy companies. We currently expect the repositioning to be completed before the Annual Meeting. If this occurs, we will continue to hold the Annual Meeting as planned and it will serve as the first Annual Meeting of the repositioned independent upstream company, ConocoPhillips. We look forward to seeing you on May 9th.
Sincerely,
J. J. Mulva
Chairman of the Board, President and
Chief Executive Officer
Ryan Lance
Designated Chairman of the Board and
Chief Executive Officer
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| Proposal to Ratify the Appointment of Ernst & Young LLP (Proposal 2) |
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| Executive Compensation |
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NOTICE OF 2012 ANNUAL MEETING OF STOCKHOLDERS
| Time |
9:00 a.m. (CDT) on Wednesday, May 9, 2012 |
| 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 2012 (page 22); |
| To provide an advisory approval of the compensation of our Named Executive Officers (page 66); |
| To consider and vote on five stockholder proposals (pages 77 through 91); 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 12, 2012. |
| 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 28, 2012. |
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 2012 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 2012; |
| • | FOR the advisory approval of the compensation of the Company’s Named Executive Officers; |
| • | 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 12, 2012. Each share of common stock is entitled to one vote. As of March 12, 2012, we had 1,273,115,130 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 12, 2012, 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.
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How many votes are needed to approve each of the proposals?
Each of the director nominees and all proposals submitted 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.
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 2011 Summary Annual Report to Stockholders are being made available to the Company’s stockholders on the Internet at www.proxyvote.com through the notice and access process. The year 2011 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 this 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.
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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 8, 2012; |
| • | 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 and cast by ballot, and Jim Gaughan of Carl T. Hagberg and Associates has been appointed to act as Inspector 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 2012 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. Without instructions from you, the broker may not vote on any proposals other than the ratification of Ernst & Young LLP as our independent registered public accounting firm for 2012.
As more fully described on your proxy card, if you hold your shares through certain 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, “FOR” the approval of the compensation of our Named Executive Officers, and “AGAINST” each of the stockholder proposals.
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Could other matters be decided at the Annual Meeting?
We are not aware of any other matters to be presented at the meeting. If any 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.
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 provide for 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 2011 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.
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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 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 email, 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 Alliance Advisors to assist us in soliciting proxies, which it may do by telephone or in person. We anticipate paying Alliance Advisors a fee of $12,000, 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 92), 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 Chief Executive Officer (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 2011, all of the Company’s directors, other than Mr. Shackouls who retired from the Board in 2011, attended the Annual Meeting.
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Chairman and CEO Roles
ConocoPhillips is focused on the Company’s corporate governance practices and values independent board oversight as an essential component of strong corporate performance to enhance stockholder value. Our commitment to independent oversight is demonstrated by the fact that all of our directors, except Mr. Mulva, are independent. In addition, all members of the Audit and Finance Committee, Committee on Directors’ Affairs, Human Resources and Compensation Committee and Public Policy Committee are independent.
While the Board retains the authority to separate the positions of Chairman and CEO if it deems appropriate in the future, the Board currently believes it is in the best interests of the Company’s stockholders to combine them. Doing so places one person in a position to guide the Board in setting priorities for the Company and in 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 best suited to perform this unified role.
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 specifically considered whether the offices of Chairman and CEO should be combined following the repositioning and concluded doing so continues to be in the best interests of the Company and its stockholders. The Board will continue to reexamine its corporate governance policies and leadership structures on an ongoing basis to ensure that they continue to meet the Company’s needs.
Independent Director Leadership
The Board believes that its current structure and processes encourage its independent directors to be actively involved in guiding the work of the Board. The Chairs of the Board’s Committees establish their agendas and review their committee materials in advance, communicating directly with other directors and members of management as each deems appropriate. Moreover, each director is free to suggest agenda items and to raise matters at Board and Committee meetings that are not on the agenda.
Our Corporate Governance Guidelines require that the independent directors meet in executive session at every meeting. As Chairman of the Committee on Directors Affairs, Mr. Auchinleck presides at executive sessions of the independent directors. Each executive session may include, among other things, (1) a discussion of the performance of the Chairman and the Chief Executive Officer, (2) matters concerning the relationship of the Board with the management directors and other members of senior management, and (3) such other matters as the non-employee directors deem appropriate. No formal action of the Board is taken at these meetings, although the non-employee directors may subsequently recommend matters for consideration by the full Board. The Board may invite guest attendees for the purpose of making presentations, responding to questions by the directors, or providing counsel on specific matters within their areas of expertise. In addition to chairing the executive sessions, Mr. Auchinleck leads the discussion with our CEO following the independent directors’ executive sessions, participates in the discussion of CEO performance with the Human Resources and Compensation Committee, and ensures that the Board’s self-assessments are done annually.
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Each year, the Board completes a self-evaluation and Mr. Auchinleck discusses the results of the self-evaluation with the full Board and, individually, with each director. This allows for direct feedback by independent directors and enables Mr. Auchinleck to speak on their behalf in conversations with management about the Board’s role and informational needs. Mr. Auchinleck is also available to meet during the year with individual directors about any other areas of interest or concern they may have.
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 intended, 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 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 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 the other Board Committees 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 SEC.
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 CEO and the Chief Financial Officer. Our Code of Business Ethics and Conduct covers topics including, but not limited to, conflicts of interest, insider trading, 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 92.
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
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regarding the continued independence of each board member. In 2011, 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. Stockholders who wish to submit nominees for election at an annual or special meeting of stockholders should follow the procedures described on page 92. 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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Election of Directors and Director Biographies
(Proposal 1 on the Proxy Card)
What am I voting on?
You are voting on a proposal to elect nominees to a one-year term as directors of the Company.
What will happen if the repositioning occurs prior to the Annual Meeting?
It is expected that the repositioning of the Company into a pure-play upstream company, ConocoPhillips, and a downstream company, Phillips 66, will occur prior to the 2012 Annual Meeting. Upon completion of the repositioning, Mr. Mulva intends to retire as Chairman, President and CEO, Messrs. Duberstein, McGraw and Mulva and Mmes. Harkin, Tschinkel and Turner will retire as directors and Mr. McGraw and Ms. Tschinkel will join the Board of Phillips 66. The nominations of these directors will only be put to a vote of stockholders if the repositioning has not occurred prior to the Annual Meeting. Mr. Lance’s nomination is contingent upon completion of the repositioning and will only be put to a vote of stockholders if the repositioning has occurred prior to the Annual Meeting. In the event the repositioning does not occur prior to the Annual Meeting, Messrs. Duberstein, McGraw and Mulva and Mmes. Harkin, Tschinkel and Turner, if elected, will continue to serve as directors and will resign at such time as the repositioning is complete.
What is the makeup of the Board of Directors and how often are the members elected?
Our Board of Directors currently has 14 members. Upon completion of the repositioning, the size of the Board is expected to be reduced to 9 members, with Messrs. Duberstein, McGraw and Mulva and Mmes. Harkin, Tschinkel and Turner retiring and Mr. Lance joining the Board. 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. Under the Company’s Corporate Governance Guidelines, each director is required to retire at the next annual stockholders’ meeting of the Company following his or her 72nd birthday. In 2012, to aid in the transition following the repositioning, the Board waived this requirement with respect to Mr. Reilly. If elected, Mr. Reilly will serve an additional one year term.
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 67.
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How often did the Board meet in 2011?
The Board of Directors met ten times in 2011. 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’ Web site 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 92.
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What are the Committees of the Board?
| Committee | Members | Principal Functions | Number of Meetings in 2011 |
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| Audit and Finance | James E. Copeland, Jr.* Mohd H. Marican 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. | 13 | ||||||
| • | Reviews significant corporate risk exposures and steps management has taken to monitor, control and report such exposures. | |||||||||
| • | Monitors the qualifications, independence and performance of our independent auditors and internal auditors. | |||||||||
| • | Monitors our 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. | — | ||||||
| Human Resources and Compensation | William E. Wade, Jr.* Harold W. McGraw III Kathryn C. Turner | • | Oversees our executive compensation policies, plans, programs and practices. | 11 | ||||||
| • | 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. | 6 | ||||||
| • | 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 |
• | 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 2012 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.
| O | 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 and risk management and the methods to drive change and growth. Through their service as top leaders at other organizations, they also bring valuable perspective on common issues affecting both their company and ConocoPhillips. |
| O | 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. |
| O | Industry experience. We seek to have directors with experience as executives or directors or in other leadership positions in the energy industry. These directors have valuable perspective on issues specific to the Company’s business. |
| O | 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 or international experience provide valued perspective on our operations. |
| O | 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?
The following directors are standing for annual election this year to hold office until the 2013 Annual Meeting of Stockholders. It is expected that the repositioning of the Company into a pure-play upstream company, ConocoPhillips, and a downstream company, Phillips 66, will occur prior to the 2012 Annual Meeting. Upon completion of the repositioning, Mr. Mulva intends to retire as Chairman, President and CEO, Messrs. Duberstein, McGraw and Mulva and Mmes. Harkin, Tschinkel and Turner will retire as directors and Mr. McGraw and Ms. Tschinkel will join the Board of Phillips 66. The nominations of these directors will only be put to a vote of stockholders if the repositioning has not occurred prior to the Annual Meeting. Mr. Lance’s nomination is contingent upon completion of the repositioning and will only be put to a vote of stockholders if the repositioning has occurred prior to the Annual Meeting. In the event the repositioning does not occur prior to the Annual Meeting, Messrs. Duberstein, McGraw and Mulva and Mmes. Harkin, Tschinkel and Turner, if elected, will continue to serve as directors and will resign at such time as the repositioning is complete. Included below is a listing of each nominee’s name, age, tenure and qualifications.
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Richard L. Armitage, 66, 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.
Skills and Qualifications: Mr. Armitage’s experience in a wide range of high ranking diplomatic positions makes him uniquely qualified to provide valuable insight and expertise in the context of the Company’s global operations with substantial governmental interface. Mr. Armitage has specific expertise in many of the Company’s key operating regions. The Board believes his experience and expertise in these matters make him well qualified to serve as a member of the Board. | |
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Richard H. Auchinleck, 60, 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.
Skills and Qualifications: Mr. Auchinleck has served as a director of ConocoPhillips and its predecessors since Gulf Canada Resources was acquired by Conoco in 2001. His extensive experience in the industry and as a CEO of an energy company provides him with valuable insights into the Company’s business. In addition, Mr. Auchinleck has extensive industry experience in Canada, the location of many key Company assets and operations. The Board believes his experience and expertise in these matters make him well qualified to serve as a member of the Board. | |
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James E. Copeland, Jr., 67, 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.
Skills and Qualifications: As the former CEO of one of the “Big Four” accounting firms, Mr. Copeland provides a wealth of financial and accounting expertise. In addition, Mr. Copeland’s experience as a CEO at a large, global corporation allows him to provide valuable insights on managing a global business. The Board believes his experience and expertise in these matters make him well qualified to serve as a member of the Board. | |
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Kenneth M. Duberstein, 67, 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 Dell Inc., The Boeing Company, Mack-Cali Realty Corporation, and The Travelers Companies, Inc. Mr. Duberstein’s nomination will be put to a vote at the Annual Meeting only if the repositioning has not occurred prior to May 9, 2012. Upon completion of the repositioning, Mr. Duberstein will resign as a director of ConocoPhillips.
Skills and Qualifications: Mr. Duberstein’s extensive experience, including serving as White House Chief of Staff, allows him to provide valuable expertise on governmental matters, particularly in the United States. Mr. Duberstein has extensive global and domestic strategic advisory experience which allows him to provide valuable insights into the Company’s global strategic plans. The Board believes his experience and expertise in these matters make him well qualified to serve as a member of the Board. | |
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Ruth R. Harkin, 67, 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. Ms. Harkin’s nomination will be put to a vote at the Annual Meeting only if the repositioning has not occurred prior to May 9, 2012. Upon completion of the repositioning, Ms. Harkin will resign as a director of ConocoPhillips.
Skills and Qualifications: Ms. Harkin’s extensive experience in advising international corporations on foreign investments and government affairs provides the Company with valuable insight applicable to its global operations. The Board believes her experience and expertise in these matters make her well qualified to serve as a member of the Board. | |
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Ryan M. Lance, 49, Senior Vice President, Exploration & Production—International
Mr. Lance will become Chairman, President and CEO of ConocoPhillips following the repositioning. He was appointed to his current position of Senior Vice President, Exploration and Production—International, in May 2009. Prior to that, he served as President, Exploration and Production—Asia, Africa, Middle East and Russia/Caspian since April 2009; President, Exploration and Production—Europe, Asia, Africa and the Middle East from 2007 to 2009; Senior Vice President, Technology in 2007; and Senior Vice President, Technology and Major Projects since 2006. Mr. Lance’s nomination will be put to a vote at the Annual Meeting only if the repositioning has occurred prior to May 9, 2012.
Skills and Qualifications: Mr. Lance’s future service as President and CEO of ConocoPhillips makes him well qualified to serve both as a director and Chairman of the Board following the repositioning. Mr. Lance’s extensive experience in the industry as an executive in our exploration and production businesses, and as the global representative of ConocoPhillips will make his service as a director invaluable to the Company. The Board believes his experience and expertise in these matters make him well qualified to serve as a member of the Board. | |
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Mohd H. Marican, 59, Director since December 2011
Tan Sri Marican was the former President and Chief Executive Officer of the Malaysian national oil company, PETRONAS, from 1995 to 2010. He served as Senior Vice President of finance for PETRONAS from 1989 to 1995 and a partner in the accounting firm of Hanafiah Raslan and Mohamed (Touche Ross & Co) from 1980 to 1989. He currently serves as a director of Sembcorp Industries, Sembcorp Marine, Lambert Energy Advisory and Singapore Power.
Skills and Qualifications: Tan Sri Marican’s extensive experience in the industry and as a CEO of an international energy company headquartered in the Asia Pacific region provides him with valuable insights into the Company’s businesses. The Board believes his experience and expertise in these matters make him well qualified to serve as a member of the Board. | |
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Harold W. McGraw III, 63, 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. Mr. McGraw’s nomination will be put to a vote at the Annual Meeting only if the repositioning has not occurred prior to May 9, 2012. Upon completion of the repositioning, Mr. McGraw will resign as a director of ConocoPhillips and will join the Phillips 66 Board.
Skills and Qualifications: As an active CEO of a large, global public company with a significant role in the financial reporting industry, Mr. McGraw’s experience allows him to provide the Company with valuable financial and operational expertise. In addition, with experience in operations worldwide, he is well-qualified to advise the Company on its global operations. The Board believes his experience and expertise in these matters make him well qualified to serve as a member of the Board. | |
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James J. Mulva, 65, 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 currently serves as President and has served in such capacity since 2011 and 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. Mr. Mulva’s nomination will be put to a vote at the Annual Meeting only if the repositioning has not occurred prior to May 9, 2012. Upon completion of the repositioning, Mr. Mulva intends to resign as Chairman, President and Chief Executive Officer of ConocoPhillips also resigning as a director.
Skills and Qualifications: Mr. Mulva’s 35+ year career, first at Phillips Petroleum and, since 2002, as CEO of ConocoPhillips, makes him uniquely and well qualified to serve both as a director and Chairman of the Board. Mr. Mulva’s extensive experience in the industry and as the global representative of ConocoPhillips makes his service as a director invaluable to the Company. The Board believes his experience and expertise in these matters make him well qualified to serve as a member of the Board. | |
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Robert A. Niblock, 49, 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.
Skills and Qualifications: After an extensive search, Mr. Niblock became a member of the Board in 2010. The Committee on Directors’ Affairs valued his experience as a CEO and in financial reporting matters. Mr. Niblock’s experience as an actively-serving CEO of a large public company allows him to provide the Board with valuable operational and financial expertise. The Board believes his experience and expertise in these matters make him well qualified to serve as a member of the Board. | |
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Harald J. Norvik, 65, Director since July 2005
Mr. Norvik currently serves as Chairman of the Board of Telenor ASA. He was Chairman and a partner at Econ Management AS from 2002 to 2008 and was a strategic advisor there from 2008 to 2010. He served as Chairman, President & Chief Executive Officer of Statoil from 1988 to 1999. He currently serves on the boards of Telenor ASA and Petroleum Geo-Services ASA.
Skills and Qualifications: As a former CEO of an international energy corporation, Mr. Norvik brings valuable experience and expertise in industry and operational matters. In addition, Mr. Norvik provides valuable international perspective as a citizen of Norway, a country in which the Company has significant operations. The Board believes his experience and expertise in these matters make him well qualified to serve as a member of the Board. | |
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William K. Reilly, 72, 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. Most recently, Mr. Reilly was appointed by President Obama as co-chair of the National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling.
Skills and Qualifications: Mr. Reilly’s extensive environmental regulatory experience with the U.S. government makes him well qualified to serve as a member of the Board. Mr. Reilly’s active role in the discussion on environmental issues allows him to provide unique and valuable perspective on matters critical to the Company’s operations. The Board believes his experience and expertise in these matters make him well qualified to serve as a member of the Board. | |
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Kathryn C. Turner, 64, 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. Ms. Turner’s nomination will be put to a vote at the Annual Meeting only if the repositioning has not occurred prior to May 9, 2012. Upon completion of the repositioning, Ms. Turner will resign as a director of ConocoPhillips.
Skills and Qualifications: Ms. Turner’s experience as a CEO in the information technology field positions her to provide valuable insights on the Company’s managerial issues. Ms. Turner’s experience in the information technology field also enables her to provide valuable insights into technology and innovation, which are vital to the Company’s future success. The Board believes her experience and expertise in these matters make her well qualified to serve as a member of the Board. | |
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Victoria J. Tschinkel, 64, 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. Ms. Tschinkel’s nomination will be put to a vote at the Annual Meeting only if the repositioning has not occurred prior to May 9, 2012. Upon completion of the repositioning, Ms. Tschinkel will resign as a director of ConocoPhillips and will join the Phillips 66 Board.
Skills and Qualifications: Ms. Tschinkel’s extensive environmental regulatory experience makes her well qualified to serve as a member of the Board. In addition, her relationships and experience working within the environmental community position her to advise the Board on the impact of our operations in sensitive areas. The Board believes her experience and expertise in these matters make her well qualified to serve as a member of the Board. | |
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William E. Wade, Jr., 69, 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.
Skills and Qualifications: Mr. Wade’s extensive experience in senior management within the industry and in areas of significant Company operations makes him uniquely and well qualified to serve as a member of the Board. Mr. Wade’s prior service as a director of Burlington Resources Inc. also provides him with valuable insights in the assets acquired as part of the acquisition of that company. The Board believes his experience and expertise in these matters make him well qualified to serve as a member of the Board. |
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 would consider the resignation and recommend 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” EACH NOMINEE STANDING FOR ELECTION FOR DIRECTOR.
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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 five 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 Web site 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 2011.
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, 2011, and management’s assessment of the effectiveness of the Company’s internal control over financial reporting, as of December 31, 2011, 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 standards of the Public Company Accounting Oversight Board. 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, 2011.
THE CONOCOPHILLIPS AUDIT AND FINANCE COMMITTEE
James E. Copeland, Jr., Chairman
Mohd H. Marican
Robert A. Niblock
Harald J. Norvik
Victoria J. Tschinkel
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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 2012. The Audit and Finance Committee has appointed Ernst & Young to serve as the Company’s independent registered public accounting firm.
What services does the independent registered public accounting firm provide?
Audit services of Ernst & Young for fiscal year 2011 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 2011 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 2011 and 2010?
Ernst & Young’s fees for professional services totaled $23.1 million for 2011 and $19.8 million for 2010. 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 $16.8 million for 2011 and $17.0 million for 2010. |
| • | 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 $5.0 million for 2011 and $2.0 million for 2010. |
| • | Tax Services—fees for tax services, consisting of tax compliance services and tax planning and advisory services, were $1.3 million for 2011 and $0.8 million for 2010. |
| • | Other Services—fees for other services were negligible in 2011 and 2010. |
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
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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.
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 2012.
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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. As of December 31, 2011, the Company had 19 Senior Officers. All of the officers shown 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 26 of this proxy statement. That report summarizes certain of the HRCC’s activities during 2011 and 2012 concerning compensation earned during 2011.
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 Web site 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 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 2011, the HRCC had six regularly scheduled meetings and five meetings via teleconference. More information regarding the HRCC’s activities at such meetings can be found in the “Compensation Discussion and Analysis” beginning on page 26.
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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; |
| • | 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 and consultants, independent 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 26. Members of management with whom the HRCC discussed the “Compensation Discussion and Analysis” included the Company’s Chief Executive Officer, Chief Financial Officer, Chief Administrative Officer, and Vice President, Human Resources.
Discussion with Independent Executive Compensation Consultant. The HRCC has discussed with Cogent Compensation Partners (“Cogent”), an independent executive compensation consulting firm, the executive compensation programs of the Company, as well as specific compensation decisions made by the HRCC. Cogent was retained directly by the HRCC, independent of the management of the Company. The HRCC has received written disclosures from Cogent confirming no other work has been performed for the Company by Cogent, has discussed with Cogent its independence from ConocoPhillips, and believes Cogent 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, 2011).
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 Chief Executive Officer and certain other officers of ConocoPhillips (the “Named Executive Officers”). The CD&A is divided into two sections:
| • | 2011 Executive Compensation—A Summary & Analysis (beginning on p. 26) |
| • | ConocoPhillips Executive Compensation Program Structure (beginning on p. 30) |
2011 Executive Compensation—A Summary & Analysis
Executive Summary
2011 Compensation Decisions
In 2011, the Company experienced solid operational results and successfully executed on its strategic plans. The Company also operated safely, maintaining its performance at record 2010 levels. The continued positive reception to the Company’s three-year strategic plan announced in 2010 was reflected in its 11% total shareholder return in 2011. In addition, the Company experienced operational success as demonstrated in its improvement in return and cash return on capital employed, the highest relative to its peers in 2011. The HRCC evaluated the Company’s one-year performance under the criteria utilized under the Variable Cash Incentive Program (VCIP) and determined corporate performance under such measures was 150% of target. For each of our Named Executive Officers, other than Mr. Mulva, whose award is based solely on corporate performance, the HRCC determined that the combined corporate and respective award unit performance merited base awards of between 132% and 153% of target. The HRCC also evaluated the Company’s three-year performance under the criteria utilized under the Performance Share Program (PSP) and determined corporate performance under such measures merited base awards of 165% of target. Finally, the HRCC approved individual adjustments under the VCIP and PSP programs ranging from 0% to 25% for the Named Executive Officers. This reflected the HRCC’s evaluation of the performance of Company’s management and the effectiveness with which the Company executed its long-term strategy.
2011 CEO Pay Mix
The following chart shows the mix of different elements of the CEO’s compensation in 2011, excluding changes in pension value. With 91% of Mr. Mulva’s pay coming in the form of incentive compensation, the HRCC believes the CEO’s pay structure is well aligned with the long-term interests of the Company’s stockholders.
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Analysis of 2011 Executive Compensation
The following is a discussion and analysis of the decisions of the HRCC in compensating our Named Executive Officers in 2011.
In determining performance-based compensation awards for our Named Executive Officers for performance periods concluding in 2011, the HRCC began by considering overall Company performance, including the following accomplishments and operating conditions:
| • | The development and implementation of a strategic plan to enhance the Company’s operating and financial position; |
| • | 120% organic reserve replacement in 2011, excluding the impact of acquisitions and dispositions; |
| • | Achievement of barrel of oil equivalent (BOE) production and capacity utilization targets; |
| • | Significant progress in high grading the Company’s asset portfolio while strengthening liquidity; |
| • | Successful exploration efforts; |
| • | Maintenance of HSE results at record 2010 levels; and |
| • | Advancement of the Company’s succession plans. |
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.
2011 VCIP Awards
In determining award payouts under VCIP for 2011, the Committee considered the following performance criteria:
| - | Company Performance for 2011—In 2011, our VCIP program used both quantitative and qualitative performance measures relating to the Company as a whole, including: |
| O | Ranking 4th in relative annual total stockholder return compared with our performance-measurement peer group (ExxonMobil, Royal Dutch Shell, BP, Total, and Chevron); |
| O | Ranking 1st in percentage change and 2nd in absolute change in improvement in relative annual adjusted return on capital employed compared with the same peer group noted above; |
| O | Ranking 1st in percentage and absolute change in relative annual adjusted cash 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; |
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| O | Our health, safety and environmental performance; and |
| O | Advancement and support of our key strategic initiatives and plans. |
Based on such review, management recommended, and the Committee concluded, that the Company’s performance under these measures in 2011 merited award of 150% of the targeted amount. This compared with VCIP corporate award performance of 180% in 2010, 111% in 2009, 70% in 2008, 140% in 2007 and 142% in 2006.
| - | Business Unit Performance in 2011—In determining award unit performance, management’s determinations of performance by the Company’s award units under their performance criteria were reviewed and approved by the Committee. Each executive’s award was tied to the operational or staff award unit over which they had responsibility weighted to reflect their time of service within such unit. The Committee determined that the combined corporate and award unit performance merited base awards of between 132% and 153% of target for each of our Named Executive Officers, other than Mr. Mulva. As noted under “Business Unit Performance Criteria” beginning on page 39, 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 2011 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 25% 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 2011 operational performance of their respective operating or staff units. |
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 2011.
PSP Awards (2009-2011 Performance Period)
In December 2008, the Committee established the seventh performance period under the PSP, for the three-year period beginning January 1, 2009, and ending December 31, 2011 (PSP VII). In February 2012, 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 3rd in relative total stockholder return compared with our performance-measurement peer group (ExxonMobil, Royal Dutch Shell, BP, Total, and Chevron), with only a 0.3% return separating the top three performers in this group; |
| • | Ranking 5th in relative annual adjusted return on capital employed compared with the same peer group noted above; |
| • | Ranking 2nd in percentage change and absolute change in improvement in relative annual adjusted return on capital employed compared with the same peer group noted above; |
| • | Ranking 2nd in relative adjusted cash contribution per BOE compared with the same peer group noted above; |
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| • | Our health, safety and environmental performance; |
| • | Implementation of the Company’s strategic plans; |
| • | Financial management; |
| • | Climate change initiatives; |
| • | Enhancement of reputation; |
| • | Culture and diversity initiatives; |
| • | Opportunity capture; and |
| • | 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 award of 165% of the targeted amount. This compared with three-year performance under the PSP of 140% for the 2008-2010 period, 60% for the 2007-2009 period, 110% for the 2006-2008 period, 175% for the 2005-2007 period and 180% for the 2004-2006 period. With respect to individual adjustments, similar to the 2011 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 15% and 25% for such Named Executive Officers.
2011 Say on Pay Vote Result and Engagement
In 2011, the advisory vote on executive compensation was approved by the Company’s stockholders. A significant number of shareholders voted against the advisory approval of the Company’s 2011 executive compensation. Since then, the Company actively engaged in dialogue with a significant number of large stockholders who voted against such approval to understand their concerns with the Company’s compensation programs. The Company continues to maintain a regular dialogue with its investors on numerous subject matters including compensation. As a result of this engagement process, the Company learned, while these stockholders are generally pleased with the Company’s compensation programs and believe such programs are well-aligned with long-term company performance, several stockholders had concerns regarding the appropriateness of certain discrete elements of our executive compensation program, primarily the provision of excise tax gross-ups under our Change in Control Severance Plan. The HRCC has considered the viewpoints of these stockholders and, in recognition of the significant transformation occurring as ConocoPhillips is repositioned as two separate companies, intends to undertake a thorough review of its executive compensation programs following the expected completion of the repositioning in the second quarter of 2012. It is expected that the equivalent committee of the Board of Phillips 66 will undertake a similar review of its executive pay programs. In deciding what changes to make to its executive compensation programs, the deliberations of the HRCC of ConocoPhillips and equivalent committee of the Board of Phillips 66 will be informed by the conversations the Company has had with its investors following the 2011 advisory vote on executive compensation, by current market practices and investor concern over certain pay practices. It is expected, at minimum, any program changes will provide for the elimination of excise tax gross-ups for future participants under the Change in Control Severance Plan and the Phillips 66 equivalent of such plan.
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2012 Target Compensation
In addition to determining the 2011 compensation payouts, the HRCC established the targets for 2012 compensation for our Named Executive Officers under our four primary compensation programs. As discussed under “Performance-Based Pay Programs” beginning on page 34, 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 these targets.
| Name | Salary |
2012 VCIP |
2012 Stock Option Award Target Value |
PSP Target |
Total 2012 Target Compensation |
|||||||||||||||||||||||||||||||||||||||||||||
| J.J. Mulva |
$ | 1,500,000 | $ | 2,025,000 | $ | 6,487,500 | $ | 6,487,500 | $ | 16,500,000 | ||||||||||||||||||||||||||||||||||||||||
| G.C. Garland |
776,000 | 690,640 | 1,280,400 | 1,280,400 | 4,027,440 | |||||||||||||||||||||||||||||||||||||||||||||
| A.J. Hirshberg |
776,000 | 690,640 | 1,280,400 | 1,280,400 | 4,027,440 | |||||||||||||||||||||||||||||||||||||||||||||
| R.M. Lance |
776,000 | 690,640 | 1,280,400 | 1,280,400 | 4,027,440 | |||||||||||||||||||||||||||||||||||||||||||||
| J.W. Sheets |
639,000 | 530,370 | 1,006,425 | 1,006,425 | 3,182,220 | |||||||||||||||||||||||||||||||||||||||||||||
| (1) | As discussed under “Effects of the Repositioning on Compensation Programs” on page 40, while the HRCC has not set target levels for long-term incentive compensation for 2012 under either the PSP or any replacement arrangements, since the PSP or replacement arrangements are expected to provide 50% of the targeted long-term incentive compensation for our executives, we have shown that value in the table above. |
ConocoPhillips Executive Compensation Program Structure
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 when performance-based pay is 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; |
| • | Encourage prudent risk taking by our executives; |
| • | Motivate performance by considering specific individual accomplishments in determining compensation; |
| • | Retain talented individuals with the Company until retirement; and |
| • | Integrate all elements of compensation into a comprehensive package that aligns goals, efforts, and results throughout the organization. |
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The Human Resources and Compensation Committee
The HRCC 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 2011.
Compensation Program Design
Our executive compensation programs take into account marketplace compensation for executive talent, internal pay 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. At the time of Mr. Hirshberg’s employment, as an incentive to his acceptance of an employment offer and in recognition of forgone compensation from his prior employer, the Company entered into a letter agreement with Mr. Hirshberg. A discussion of this agreement is set forth on page 62 under Other Arrangements. 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, VCIP, Stock Option Program and PSP) within the total targeted 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 as the salary grade increases, 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 by benchmarking against other large, publicly held energy companies, we often use broader measures, such as mid-sized publicly held energy companies and other large, publicly held companies outside the energy industry, in setting targets for our executives. The Committee’s independent consultant, Cogent Compensation Partners, 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.
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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 HRCC used the following peer group for benchmarking purposes—Exxon Mobil Corporation, Royal Dutch Shell plc, BP p.l.c., and Chevron Corporation, with emphasis on the Company’s domestic peers particularly in setting CEO target compensation.
The HRCC also utilized a second group of peer companies for benchmarking the compensation of ConocoPhillips’ Named Executive Officers—Valero Energy Corporation, Marathon Oil Corporation, Occidental Petroleum Corporation, and, for the CEO and staff executives, the other non-financial companies in the Fortune 50, including those outside the energy industry.
ConocoPhillips utilizes these peer groups in setting compensation targets because these companies are broadly reflective of the industry in which it competes for business opportunities and for executive talent, and because these peers 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, 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. We do so because we believe 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. In addition, the HRCC also reviews the compensation of Senior Officers periodically to ensure officers with similar levels of responsibilities are compensated equitably.
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Alignment of Interests—Stock Holding Requirements
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. Company policies prohibit our executives from trading in derivatives of the Company’s stock.
In addition, we have historically required our executives to hold restricted stock units received under the PSP, and under 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 considered our programs and determined, for performance periods beginning in 2009, restrictions on restricted stock unit awards under the PSP 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.
Risk Assessment
The Company has considered the risks associated with each of its executive and broad-based compensation programs and policies. As part of the analysis, the Company considered the performance measures used and described under the section entitled “Measuring our Performance under our Compensation Programs” beginning on page 37, as well as the different types of compensation, the varied performance measurement periods and the extended vesting schedules utilized under each incentive compensation program for both executives and other employees. As a result of this review, the Company has concluded the risks arising from the Company’s compensation policies and practices for its employees are not reasonably likely to have a material adverse effect on the Company. As part of the Board’s oversight of the Company’s risk management programs, the HRCC conducts an annual review of the risks associated with the Company’s executive and broad-based compensation programs. The HRCC, the HRCC’s independent consultant and the Company’s compensation consultant noted their agreement with management’s conclusion that the risks arising from the Company’s compensation policies and practices for its employees are not reasonably likely to have a material adverse effect on the Company.
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 and designs its deferred compensation programs with the intent that they comply with section 409A of the Internal Revenue Code. 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.
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
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markets are closed on the date of grant) to determine the exercise price of the options. Option 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
The Committee retained Cogent Compensation Partners (Cogent) to serve as its independent executive compensation consultant in 2011. 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 replacing the independent consultant 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. Cogent has provided an annual attestation of its compliance with these guidelines.
The Committee strongly discourages Company proposals to retain the Committee’s independent consultant 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. No work proposals for Cogent were submitted by management in 2011 and no fees were paid to Cogent by the Company other than for their services as an independent consultant to the Committee.
The Types of Compensation We Provide Our Executives
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 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 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 up or down 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).
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Long-Term Incentives—Our primary long-term incentive compensation programs for executives are the Stock Option Program and the PSP.
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. 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. Our stock options have three-year vesting provisions and ten-year terms in order to incentivize our executives to increase the Company’s share price over the long term. |
| o | Performance Share Program—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. |
Each executive’s individual award under the PSP is subject to a potential positive or negative 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, including all Named Executive Officers other than himself. 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 provides 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 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, for one or more of the following reasons: (1) to induce an executive to join the Company (occasionally replacing compensation the executive will lose by leaving the prior employer); (2) to induce an executive of an acquired company to remain |
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| with the Company for a certain period of time following the acquisition; 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 such awards were made to Named Executive Officers in 2011. |
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. |
| - | 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. |
| - | 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 the employee’s annual salary. For each of our executives, we maintain an additional life insurance policy and/or death benefits (at no cost to the executive) with a value equal to her or his annual salary. In addition to these two plans, we also provide our executives the option of |
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| purchasing group variable universal life insurance in an amount up to eight times their annual salaries. 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, while enabling 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 so that such amounts are taxable in the year in which distributions are made. |
| 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. With regard to our Named Executive Officers, the only such arrangement under which they are entitled to benefits of this type is the 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 2011, 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 ConocoPhillips Retirement Plan. Thus, in operation the combined benefits payable from the related plans for the eligible employee equal the benefit that would have been paid if there had been no limitations imposed by the Internal Revenue Code. This design is common among our competitors and we believe that lack of such a plan would put the Company at a great disadvantage in attracting and retaining talented executives. Further information on the KESRP is provided in the Pension Benefits table and notes beginning on page 53. |
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 60. The structure and use of these plans are competitive within the industry and are intended to aid the Company in attracting and retaining executives.
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.
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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 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. In calculating ROCE, we adjust the net income of the Company and our peers for certain non-core earnings impacts. For performance periods beginning in 2008, our programs considered our improvement on adjusted ROCE relative to our performance-measurement peer group. |
| 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 BOE 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 attributable to our E&P or R&M segments by the number of BOE produced or barrels of 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. |
| O | Relative Improvement in Adjusted Cash Return on Capital Employed—Similar to ROCE, adjusted cash return on capital employed (CROCE) measures the Company’s performance in efficiently allocating its capital. However, while ROCE is based on adjusted net income, CROCE is based on cash flow, measuring the ability of the Company’s capital employed to generate cash. CROCE is calculated by dividing adjusted EBIDA (earnings before interest, depreciation and amortization, adjusted for non-core earnings impacts) by average capital employed (total equity plus total debt). Our improvement in CROCE is compared against that of our peers. We added this metric for performance periods under our VCIP beginning in 2010. |
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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 and Advancement 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, 2008, 2010 and 2011. |
| 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, cash returned to stockholders, financial management relationships, climate change, reputation, people/diversity, culture, opportunity capture and execution of Company initiatives. 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. In order for a Named Executive Officer to receive any award under either VCIP or PSP certain threshold criteria must be met. This tier of performance measure and methodology is designed to meet requirements for deductibility of these items of compensation under section 162(m) of the Internal Revenue Code. Pursuant to this tier, maximum payments for the performance period under VCIP and PSP are set, but they are subject to downward adjustment through the application of the generally applicable methodology for VCIP and PSP awards previously discussed, so this effectively establishes a ceiling for VCIP and PSP payments to each Named Executive Officer. Threshold performance criteria for VCIP and PSP differed, due primarily to VCIP being a one-year program while PSP is a three-year program. For VCIP, the criteria 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 BOE; or (4) Cash from operations (normalized for the impact of asset sales and assumptions made in our budgeting process as to price for oil equivalents and excluding non-cash working capital) of at least $11.301 billion. For PSP, the criteria for the 2009-2011 program period 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 BOE; or (4) Cash from operations (normalized for the impact of asset sales and assumptions made in our budgeting process as to price for oil equivalents and excluding non-cash working capital) of at least $39.364 billion. In both cases, the specified companies for comparison were ConocoPhillips, BP, Chevron, ExxonMobil, Royal Dutch Shell, and Total. The performance criteria for this purpose are set by the HRCC and may change from year to year, although the criteria must come from a list of possible criteria set forth in the stockholder-approved 2011 Omnibus Stock and Performance Incentive Plan. The award ceilings are also set by the HRCC each year, although they may not exceed limits set in the stockholder-approved 2011 Omnibus Stock and Performance Incentive Plan. Determination of whether the criteria are met is made by the HRCC after the end of each performance period. Since the merger of companies that created ConocoPhillips in 2002, threshold criteria have always been met and the ceiling has never been reached.
Effects of Repositioning on Compensation Programs
We are in the process of repositioning ConocoPhillips into two pure-play organizations, spinning off Phillips 66 to engage in downstream operations while continuing ConocoPhillips to engage in upstream operations. We expect the spin-off to occur sometime in the second quarter of 2012. As a result, the HRCC has not approved the continuation of the PSP as part of the long-term incentive compensation for our executives, believing that such determination should come from the respective compensation committees of the pure-play organizations after the spin-off. However, the HRCC does anticipate that the respective compensation committees will institute programs similar in purpose, scope, and value to the PSP, but with performance periods and performance criteria set to reflect the new circumstances of each company. Furthermore, the HRCC expects that certain executives, including the CEO, will retire in connection with the spin-off. The HRCC has considered the long-term incentive compensation for those retiring executives and anticipates granting awards later in 2012 to provide for the value foregone by not continuing the PSP. While the HRCC has not set the target levels for long-term incentive compensation for 2012 under either the PSP or any replacement arrangements, we anticipate that the target levels will remain the same when approved. In the event that the
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repositioning does not occur, the HRCC will meet to discuss the setting of target levels of compensation in light of the circumstances. Performance periods and performance criteria would be determined at that time.
Another aspect of the PSP is its overlapping three-year performance periods. Performance criteria were set when the performance periods beginning in 2010 and 2011 were initiated. Those performance periods cross over the time that the spin-off is expected to occur which will make measuring performance difficult or less meaningful if the repositioning occurs, as the peer comparison groups will likely be different for the pure-play organizations (affecting the ability to measure performance relative to peers) and the criteria themselves would need to be reassessed in light of the changed circumstances. The HRCC believes that those activities are properly left to the respective compensation committees of the pure-play organizations. The HRCC also believes that it is best situated to determine how well the Company and the Senior Officers, including the Named Executive Officers, performed up to the spin-off; therefore, the HRCC expects that, at or near the effective time of the spin-off, it will grant awards related to the ongoing performance periods that began in 2010 and 2011, prorated to the time of the spin-off and adjusted to take into account the HRCC’s determination of the Company’s performance and the individual performance of the Senior Officers. In the event that the repositioning does not occur, the HRCC will be able to return to its customary timing with regard to this determination.
The Stock Option Program, the other portion of long-term incentive compensation, is less affected by the repositioning than the PSP, because the HRCC has traditionally delivered options having the target compensation value, with no adjustment. The HRCC, therefore, was able to grant Senior Officers, including the Named Executive Officers, options during the customary February timeframe without concern about whether the repositioning will occur as and when expected.
With VCIP, the Company’s short-term incentive program, the HRCC determined target levels and performance criteria at its February 2012 meeting, setting them without regard to the repositioning, but in the knowledge that after the repositioning, the respective compensation committees of the pure-play organizations would revisit the target levels and performance criteria. The HRCC anticipates that it is likely that performance criteria and peer comparison groups more suited to the circumstances of the pure-play organizations would be established at that time.
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This graph shows ConocoPhillips’ cumulative total stockholder return over the five-year period from December 31, 2006, to December 31, 2011. 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, 2006, in ConocoPhillips stock, in the S&P 500 Index and in ConocoPhillips’ peer group and assumes that all dividends were reinvested.
Five-Year Cumulative Total Stockholder Return
Five Years Ended December 31, 2011
| December 31 | ||||||||||||||||||||||||
| Initial | 2007 | 2008 | 2009 | 2010 | 2011 | |||||||||||||||||||
| ConocoPhillips |
$100.0 | $ | 125.4 | $ | 75.5 | $ | 77.7 | $ | 107.9 | $ | 119.7 | |||||||||||||
| Peer Group(1) |
$100.0 | $ | 122.0 | $ | 93.4 | $ | 99.9 | $ | 103.9 | $ | 117.7 | |||||||||||||
| S&P 500 |
$100.0 | $ | 105.5 | $ | 66.5 | $ | 84.1 | $ | 96.7 | $ | 98.8 | |||||||||||||
(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 provide information concerning total compensation paid to the Chief Executive Officer and certain other officers of ConocoPhillips (the “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 26. The data presented in the tables that follow include amounts paid to the Named Executive Officers by ConocoPhillips or any of its subsidiaries for 2011.
SUMMARY COMPENSATION TABLE
The Summary Compensation Table below reflects amounts earned with respect to 2011 and performance periods ending in 2011. We also provide 2012 target compensation for Named Executive Officers (other than those who have retired) on page 30. We have excluded arrangements that are generally available to our U.S.-based salaried employees, such as our medical, dental, life and accident insurance, disability, and health savings 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 2011 shown in the table below, salary accounted for approximately 7.4 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 50.8 percent. For the CEO alone in 2011, salary accounted for approximately 5.4 percent of his total compensation and incentive compensation programs accounted for approximately 62.8 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 |
2011 | $ | 1,500,000 | $ | — | $ | 7,384,724 | $ | 6,487,950 | $ | 3,543,750 | $ | 8,533,648 | $ | 263,522 | $ | 27,713,594 | |||||||||||||||||||
| 2010 | 1,500,000 | — | 6,148,572 | 5,737,680 | 4,252,500 | — | 294,143 | 17,932,895 | (9) | |||||||||||||||||||||||||||
| 2009 | 1,500,000 | — | 5,669,518 | 5,737,576 | 1,278,788 | — | 202,779 | 14,388,661 | (9) | |||||||||||||||||||||||||||
| J.A. Carrig(8) President (retired) |
2011 | 197,500 | — | — | — | 295,895 | — | 6,750,086 | 7,243,481 | |||||||||||||||||||||||||||
| 2010 | 1,165,000 | — | 3,803,787 | 3,549,780 | 2,134,979 | 3,590,672 | 113,015 | 14,357,233 | ||||||||||||||||||||||||||||
| 2009 | 1,145,000 | — | 3,507,419 | 3,549,650 | 1,474,560 | 2,487,509 | 133,033 | 12,297,171 | ||||||||||||||||||||||||||||
| G.C. Garland Senior Vice President, Exploration & Production–Americas |
2011 | 750,500 | — | 1,361,687 | 1,197,390 | 1,105,449 | 1,462,522 | 123,887 | 6,001,435 | |||||||||||||||||||||||||||
| 2010 | 173,011 | — | 2,819,115 | — | 272,699 | 2,005,824 | 26,132 | 5,296,781 | ||||||||||||||||||||||||||||
| 2009 | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||
| A.J. Hirshberg Senior Vice President, Planning and Strategy |
2011 | 750,500 | — | 1,361,687 | 1,197,390 | 1,039,990 | 5,407,899 | 176,618 | 9,934,084 | |||||||||||||||||||||||||||
| 2010 | 173,011 | 9,357,436 | 4,719,144 | — | 270,389 | 359,280 | 10,910 | 14,890,170 | ||||||||||||||||||||||||||||
| 2009 | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||
| R.M. Lance Senior Vice President, Exploration & Production–International |
2011 | 750,500 | — | 1,361,687 | 1,197,390 | 979,875 | 1,473,776 | 152,223 | 5,915,451 | |||||||||||||||||||||||||||
| 2010 | 683,758 | — | 1,381,976 | 1,038,960 | 956,219 | 634,646 | 71,529 | 4,767,088 | ||||||||||||||||||||||||||||
| 2009 | 649,508 | — | 996,020 | 1,008,436 | 637,117 | 693,413 | 53,171 | 4,037,665 | ||||||||||||||||||||||||||||
| J.W. Sheets Senior Vice President, Finance, and CFO |
2011 | 619,500 | — | 1,451,661 | 729,790 | 784,132 | 1,473,218 | 87,404 | 5,145,705 | |||||||||||||||||||||||||||
| 2010 | 496,840 | — | 880,262 | 489,060 | 696,942 | 699,405 | 58,571 | 3,321,080 | ||||||||||||||||||||||||||||
| 2009 | 461,000 | — | 468,796 | 475,150 | 437,950 | 616,475 | 41,707 | 2,501,078 | ||||||||||||||||||||||||||||
| (1) | Includes any amounts that were voluntarily deferred to the Company’s Key Employee Deferred Compensation Plan. |
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| (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. As an inducement to his employment, the HRCC approved (i) a bonus payment to Mr. Hirshberg of $3,000,000 at his employment on October 6, 2010 and (ii) the creation of a deferred compensation account under the Key Employee Deferred Compensation Plan, credited with $6,357,436, vesting as to 47% on the first anniversary of employment, as to 47% on the second anniversary of employment, and as to the remainder on the third anniversary of employment. |
| (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 “Employee Benefit Plans” section of Note 19 in the Notes to Consolidated Financial Statements in the Company’s 2011 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 2011, 2010, or 2009, except for off-cycle awards to Messrs. Garland and Hirshberg at their employment on October 6, 2010, as discussed further below. These may include awards that are expected to be finalized as late as 2014. 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.
Amounts shown are targets set for awards for 2011, 2010, and 2009, 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 and excluding any individual adjustments, 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 2009 were approved by the HRCC at its February 2012 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 2009 and ended in 2011. Those payouts were as follows (with values shown at fair market value on the date of payout): Mr. Mulva, $18,482,664; Mr. Carrig, $7,597,378; Mr. Garland, $1,541,468; Mr. Hirshberg, $1,477,216; Mr. Lance, $3,219,848; and Mr. Sheets, $1,997,483.
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 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.
Messrs. Garland and Hirshberg became employees of ConocoPhillips on October 6, 2010. As inducements to their employment, the HRCC approved the grant of certain restricted stock units to each, effective on the date of employment. Mr. Garland received 16,877 units (valued at $999,962), the restrictions on which lapse as to one-half of the units on the first anniversary of his employment, while the restrictions on the remainder lapse on the second anniversary of his employment. Mr. Hirshberg received 48,945 units (valued at $2,899,991), the restrictions on which lapse on the third anniversary of his employment. Other terms and conditions of the restricted stock unit awards for each officer reflect the standard terms and conditions of restricted stock unit awards under PSP. The amounts for 2010 reflected in the Table include these awards, as well as their target awards under PSP.
| (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 “Employee Benefit Plans” section of Note 19 in the Notes to Consolidated Financial Statements in the Company’s 2011 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 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 |
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| attained the early retirement age of 55 with five 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 five 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.
| (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. See also note (2) above. |
| (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 rate 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. |
| (7) | As discussed in Compensation Discussion and Analysis beginning on page 26 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, life and accident insurance, disability, and health savings 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. 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) |
Annual Physical(d) |
Executive Group Life Insurance Premiums(e) |
Tax Reimbursement Gross-Up(f) |
Relocation(g) | |||||||||||||||||||||||||
| J.J. Mulva |
2011 | $ | — | $ | 15,298 | $ | — | $ | — | $ | 22,860 | $ | 19,904 | $ | — | |||||||||||||||||
| 2010 | 31,274 | 32,379 | — | 2,689 | 11,880 | 65,045 | — | |||||||||||||||||||||||||
| 2009 | 3,375 | 14,967 | 874 | 1,964 | 11,880 | 17,954 | — | |||||||||||||||||||||||||
| J.A. Carrig |
2011 | — | — | — | — | 1,019 | 5,179 | — | ||||||||||||||||||||||||
| 2010 | — | — | — | — | 6,012 | — | — | |||||||||||||||||||||||||
| 2009 | — | — | — | 795 | 5,908 | 745 | — | |||||||||||||||||||||||||
| G.C. Garland |
2011 | — | — | — | — | 2,072 | 679 | 68,389 | ||||||||||||||||||||||||
| 2010 | — | — | — | — | 334 | — | 15,106 | |||||||||||||||||||||||||
| 2009 | — | — | — | — | — | — | — | |||||||||||||||||||||||||
| A.J. Hirshberg |
2011 | — | — | — | — | 2,072 | 5,338 | 113,761 | ||||||||||||||||||||||||
| 2010 | — | — | — | — | 218 | — | — | |||||||||||||||||||||||||
| 2009 | — | — | — | — | — | — | — | |||||||||||||||||||||||||
| R.M. Lance |
2011 | — | — | — | — | 1,351 | 8,199 | — | ||||||||||||||||||||||||
| 2010 | — | — | — | 1,262 | 1,231 | 3,521 | — | |||||||||||||||||||||||||
| 2009 | — | — | — | — | 1,169 | — | — | |||||||||||||||||||||||||
| J.W. Sheets |
2011 | — | — | — | — | 1,710 | 5,213 | — | ||||||||||||||||||||||||
| 2010 | — | — | — | — | 1,371 | 1,825 | — | |||||||||||||||||||||||||
| 2009 | — | — | — | — | 1,272 | 1,109 | — | |||||||||||||||||||||||||
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| Name | Expatriate(h) | Retirement Presentations(i) |
Post-Employment Payments(j) |
Matching Gift Program(k) |
Matching Contributions Under the Tax-Qualified Savings Plans(l) |
Company Contributions to Non-Qualified Defined Contribution Plans (m) |
||||||||||||||||||||||
| J.J. Mulva |
2011 | $ | — | $ | — | $ | — | $ | 15,000 | $ | 32,372 | $ | 158,088 | |||||||||||||||
| 2010 | — | — | — | 15,000 | 14,651 | 121,225 | ||||||||||||||||||||||
| 2009 | — | — | — | 18,000 | 13,947 | 119,818 | ||||||||||||||||||||||
| J.A. Carrig |
2011 | — | 9,030 | 6,626,492 | 17,500 | 26,096 | 64,770 | |||||||||||||||||||||
| 2010 | — | — | — | 5,000 | 14,651 | 87,352 | ||||||||||||||||||||||
| 2009 | — | — | — | 30,000 | 13,947 | 81,638 | ||||||||||||||||||||||
| G.C. Garland |
2011 | — | — | — | — | 32,372 | 20,375 | |||||||||||||||||||||
| 2010 | — | — | — | — | 10,692 | — | ||||||||||||||||||||||
| 2009 | — | — | — | — | — | — | ||||||||||||||||||||||
| A.J. Hirshberg |
2011 | — | — | — | 2,700 | 32,372 | 20,375 | |||||||||||||||||||||
| 2010 | — | — | — | — | 10,692 | — | ||||||||||||||||||||||
| 2009 | — | — | — | — | — | — | ||||||||||||||||||||||
| R.M. Lance |
2011 | 51,000 | — | — | 200 | 32,372 | 59,101 | |||||||||||||||||||||
| 2010 | 5,224 | — | — | 5,000 | 14,651 | 40,640 | ||||||||||||||||||||||
| 2009 | — | — | — | — | 13,947 | 38,055 | ||||||||||||||||||||||
| J.W. Sheets |
2011 | — | — | — | 13,500 | 32,255 | 34,726 | |||||||||||||||||||||
| 2010 | — | — | — | 13,500 | 15,396 | 26,479 | ||||||||||||||||||||||
| 2009 | — | — | — | 5,500 | 14,107 | 19,719 | ||||||||||||||||||||||
| (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 $0 associated with flights to the Company hangar or other locations without passengers, commonly referred to as “deadhead” flights. In 2007, the Company and Mr. Mulva entered into a 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. In 2011, the reimbursement from Mr. Mulva was greater than the aggregate incremental cost. |
| (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. No charges have been incurred under this program since 2009. |
| (d) | Historically, the Company maintained a program under which costs associated with annual physical examinations of eligible employees, including the Named Executive Officers, were paid for by the Company. This program was discontinued effective at the end of 2010. |
| (e) | 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 |
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| 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. |
| (f) | 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. |
| (g) | These amounts reflect relocation expenses approved by the HRCC in the offer letter to Mr. Garland and Mr. Hirshberg in connection with their hiring. The amounts were calculated pursuant to the standard relocation policy of the Company. |
| (h) | 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 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 $0 in 2011, $(176,325) in 2010, and $(314,163) in 2009. Amounts shown in the table above also reflect amended tax equalization and similar payments under our expatriate services policies that were made to and from or on behalf of the Named Executive Officer that were paid or received during 2011 but apply to earnings of prior years, but which were unknown or not capable of being estimated with any reasonable degree of accuracy in prior years. |
| (i) | These amounts reflect the practice of the Company to make presentations to its retiring employees, especially those of long service. The amounts shown reflect the invoiced cost to the Company. |
| (j) | Mr. Carrig retired effective March 1, 2011. The amounts presented relate to post-employment payments under the ConocoPhillips Executive Severance Plan and other payments under the Company’s standard retirement policy. Not reflected in the Summary Compensation Table, but included in the “Payments During Last Fiscal Year” column of the Pension Benefits table, are pension benefits to which he was entitled as part of the provisions of Title I of the ConocoPhillips Retirement Plan and the ConocoPhillips Key Employee Supplemental Retirement Plan. Also see footnotes 2 and 3 of the Pension Benefit Table on page 55. |
| (k) | 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 $15,000 to be paid in a single fiscal year of the Company, due to processing claims from more than one program year in that single fiscal year. The amounts shown are for the actual payments by the Company during the year. In December 2009, the Board of Directors approved changes in the Matching Gift Program provisions for employees that brought it into parity with the provisions for executives, effective in 2010. |
| (l) | Under the terms of its tax-qualified defined contribution plans, the Company makes matching contributions and allocations to the accounts of its eligible employees, including the Named Executive Officers. |
| (m) | Under the terms of its nonqualified defined contribution plans, the Company makes contributions to the accounts of its eligible employees, including the Named Executive Officers. See the narrative, table, and notes to the “Nonqualified Deferred Compensation Table” for further information. |
| (8) | Mr. Carrig retired from ConocoPhillips effective March 1, 2011. Prior to October 6, 2010, Mr. Carrig served as President and Chief Operating Officer. |
| (9) | In accordance with SEC rules prohibiting issuers from reporting a negative value in the “Change in Pension Value and Non-Qualified Deferred Compensation Earnings ($)” column, Mr. Mulva’s total compensation excludes the effect of a $246,639 decrease in the net present value of Mr. Mulva’s pension benefits in 2010 and a $7,885,466 decrease in the net present value of Mr. Mulva’s pension benefits in 2009. Including the effects of these decreases in value, Mr. Mulva’s total compensation, as reported in the Summary Compensation Table, would have been $17,686,256 in 2010 and $6,503,195 in 2009. |
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GRANTS OF PLAN-BASED AWARDS TABLE
The Grants of Plan-Based Awards Table is used to show participation by the Named Executive Officers in the incentive compensation arrangements described below.
The columns under the heading Estimated Future Payouts Under Non-Equity Incentive Plan Awards show information regarding the VCIP. The amounts shown in the Table are those applicable to the 2011 program year using a minimum of zero and a maximum of 250 percent of VCIP target for each participant and do not represent actual payouts for that program year. Actual payouts for the 2011 program year were made in February 2012 and are shown in the Summary Compensation Table under the “Non-Equity Incentive Plan Compensation” column.
The columns under the heading Estimated Future Payouts Under Equity Incentive Plan Awards show information regarding PSP. The amounts shown in the Table are those set for 2011 compensation tied to the 2011 through 2013 program period under PSP (PSP IX) and do not represent actual payouts for that program year.
The “All Other Option Awards” column reflects option awards granted under the Stock Option Program. The option awards shown were granted on the same day that the target was approved. For the 2011 program year under the Stock Option Program, targets were set and awards granted at the regularly scheduled February 2011 meeting of the HRCC.
| Name | Grant Date(1) |
Estimated Future Payouts Under Non-Equity Incentive Plan Awards(2) |
Estimated Future Payouts Under Equity Incentive Plan Awards(3) |
All Other Stock Awards: Number of Shares of Stock or Units (#) |
All Other Option Awards: Number of Securities Underlying Options (#)(4) |
Exercise or Base Price Of Options Awards Average Price ($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 | — | — | — | — | — | $ | — | $ | — | $ | — | |||||||||||||||||||||||||||||||
| 2/10/2011 | — | — | — | — | 105,308 | 210,616 | — | — | — | — | 7,384,724 | |||||||||||||||||||||||||||||||||||||
| 2/10/2011 | — | — | — | — | — | — | — | 388,500 | 70.125 | 70.08 | 6,487,950 | |||||||||||||||||||||||||||||||||||||
| J.A. Carrig |
— | 217,250 | 543,125 | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||
| G.C. Garland |
— | 667,945 | 1,669,863 | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||
| 2/10/2011 | — | — | — | — | 19,418 | 38,836 | — | — | — | — | 1,361,687 | |||||||||||||||||||||||||||||||||||||
| 2/10/2011 | — | — | — | — | — | — | — | 71,700 | 70.125 | 70.08 | 1,197,390 | |||||||||||||||||||||||||||||||||||||
| A.J. Hirshberg |
— | 667,945 | 1,669,863 | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||
| 2/10/2011 | — | — | — | — | 19,418 | 38,836 | — | — | — | — | 1,361,687 | |||||||||||||||||||||||||||||||||||||
| 2/10/2011 | — | — | — | — | — | — | — | 71,700 | 70.125 | 70.08 | 1,197,390 | |||||||||||||||||||||||||||||||||||||
| R.M. Lance |
— | 667,945 | 1,669,863 | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||
| 2/10/2011 | — | — | — | — | 19,418 | 38,836 | — | — | — | — | 1,361,687 | |||||||||||||||||||||||||||||||||||||
| 2/10/2011 | — | — | — | — | — | — | — | 71,700 | 70.125 | 70.08 | 1,197,390 | |||||||||||||||||||||||||||||||||||||
| J.W. Sheets |
— | 514,185 | 1,285,463 | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||
| 1/1/2011 | — | — | — | — | 1,814 | 3,628 | — | — | — | — | 123,724 | |||||||||||||||||||||||||||||||||||||
| 1/1/2011 | — | — | — | — | 3,699 | 7,398 | — | — | — | — | 252,290 | |||||||||||||||||||||||||||||||||||||
| 2/10/2011 | — | — | — | — | 15,339 | 30,678 | — | — | — | — | 1,075,647 | |||||||||||||||||||||||||||||||||||||
| 2/10/2011 | — | — | — | — | — | — | — | 43,700 | 70.125 | 70.08 | 729,790 | |||||||||||||||||||||||||||||||||||||
| (1) | The grant date shown is the date on which the HRCC approved the target awards, except with regard to the January 1, 2011 awards shown for Mr. Sheets. With regard to Mr. Sheets, under the terms of the PSP, an adjustment in the target and maximum awards under three on-going performance periods automatically occurred on the effective date of his promotion, which was effective January 1, 2011 and was approved by the HRCC. |
| (2) | Threshold and maximum awards are based on the program provisions under the 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 VCIP after the |
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| 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 2011 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 2011 are based on actual base salaries earned in 2011 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 the 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. |
| (4) | These amounts represent stock options granted during 2011. |
| (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 2011 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 plans, the stockholder-approved 2004 and 2009 Omnibus Stock and Performance Incentive Plans, had the same provision. Grants made before May 13, 2009, were made under the 2004 Plan and grants made before May 11, 2011 but after May 12, 2009, were made under the 2009 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 ASC Topic 718. See the “Employee Benefit Plans” section of Note 19 in the Notes to Consolidated Financial Statements in the Company’s 2011 Annual Report on Form 10-K, for a discussion of the relevant assumptions used in this determination. |
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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 |
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 | — | — | — | — | ||||||||||||||||||||||||||||
| 276,500 | — | — | 66.370 | 2/8/2017 | — | — | — | — | ||||||||||||||||||||||||||||
| 296,400 | — | — | 79.380 | 2/14/2018 | — | — | — | — | ||||||||||||||||||||||||||||
| 342,133 | 171,067 | (3) | — | 45.470 | 2/12/2019 | — | — | — | — | |||||||||||||||||||||||||||
| 163,466 | 326,934 | (4) | — | 48.385 | 2/12/2020 | — | — | — | — | |||||||||||||||||||||||||||
| — | 388,500 | (5) | — | 70.125 | 2/10/2021 | — | — | — | — | |||||||||||||||||||||||||||
| 3,257,121 | 237,346,407 | 232,384 | 16,933,822 | |||||||||||||||||||||||||||||||||
| J.A. Carrig(7) |
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 | — | — | — | — | ||||||||||||||||||||||||||||
| 80,800 | — | — | 66.370 | 2/8/2017 | — | — | — | — | ||||||||||||||||||||||||||||
| 90,300 | — | — | 79.380 | 2/14/2018 | — | — | — | — | ||||||||||||||||||||||||||||
| 211,666 | 105,834 | (3) | — | 45.470 | 2/12/2019 | — | — | — | — | |||||||||||||||||||||||||||
| 101,133 | 202,267 | (4) | — | 48.385 | 2/12/2020 | — | — | — | — | |||||||||||||||||||||||||||
| 419,413 | 30,562,625 | 30,572 | 2,227,782 | |||||||||||||||||||||||||||||||||
| G.C. Garland |
— | 71,700 | (5) | — | 70.125 | 2/10/2021 | — | — | — | — | ||||||||||||||||||||||||||
| 29,887 | 2,177,866 | 39,289 | 2,862,989 | |||||||||||||||||||||||||||||||||
| A.J. Hirshberg |
— | 71,700 | (5) | — | 70.125 | 2/10/2021 | — | — | — | — | ||||||||||||||||||||||||||
| 69,499 | 5,064,392 | 39,289 | 2,862,989 | |||||||||||||||||||||||||||||||||
| R.M. Lance |
22,700 | — | — | 59.075 | 2/10/2016 | — | — | — | — | |||||||||||||||||||||||||||
| 34,900 | — | — | 66.370 | 2/8/2017 | — | — | — | — | ||||||||||||||||||||||||||||
| 44,300 | — | — | 79.380 | 2/14/2018 | — | — | — | — | ||||||||||||||||||||||||||||
| 30,133 | 30,067 | (3) | — | 45.470 | 2/12/2019 | — | — | — | — | |||||||||||||||||||||||||||
| 29,600 | 59,200 | (4) | — | 48.385 | 2/12/2020 | — | — | — | — | |||||||||||||||||||||||||||
| — | 71,700 | (5) | — | 70.125 | 2/10/2021 | — | — | — | — | |||||||||||||||||||||||||||
| 164,463 | 11,984,419 | 45,036 | 3,281,773 | |||||||||||||||||||||||||||||||||
| J.W. Sheets |
5,238 | — | — | 23.550 | 10/22/2012 | — | — | — | — | |||||||||||||||||||||||||||
| 25,800 | — | — | 24.370 | 2/10/2013 | — | — | — | — | ||||||||||||||||||||||||||||
| 29,400 | — | — | 32.810 | 2/8/2014 | — | — | — | — | ||||||||||||||||||||||||||||
| 22,400 | — | — | 47.830 | 2/4/2015 | — | — | — | — | ||||||||||||||||||||||||||||
| 15,500 | — | — | 59.075 | 2/10/2016 | — | — | — | — | ||||||||||||||||||||||||||||
| 17,100 | — | — | 66.370 | 2/8/2017 | — | — | — | — | ||||||||||||||||||||||||||||
| 16,900 | — | — | 79.380 | 2/14/2018 | — | — | — | — | ||||||||||||||||||||||||||||
| 28,333 | 14,167 | (3) | — | 45.470 | 2/12/2019 | — | — | — | — | |||||||||||||||||||||||||||
| 13,933 | 27,867 | (4) | — | 48.385 | 2/12/2020 | — | — | — | — | |||||||||||||||||||||||||||
| — | 43,700 | (5) | — | 70.125 | 2/10/2021 | — | — | — | — | |||||||||||||||||||||||||||
| 108,798 | 7,928,110 | 33,787 | 2,462,059 | |||||||||||||||||||||||||||||||||
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| (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 2011 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 12, 2009 grant, which became exercisable on February 12, 2012. |
| (4) | Represents the final two-thirds vesting of the February 12, 2010 grant, half of which became exercisable on February 12, 2012, and the other half will become exercisable on February 12, 2013. |
| (5) | Represents the February 10, 2011 grant, one-third of which became exercisable on February 10, 2012, one-third of which will become exercisable on February 10, 2013 and the final third will become exercisable on February 10, 2014. |
| (6) | No stock awards were made to the Named Executive Officers in 2011 except as a long-term incentive award under the PSP (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, 2011 (PSP VII), as follows: Mr. Mulva, 257,168 shares; Mr. Carrig, 105,710 shares; Mr. Garland 21,448 shares; Mr. Hirshberg 20,554 shares; Mr. Lance, 44,801 shares; and Mr. Sheets, 27,793 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 the 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 five 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 the PSP, for the performance periods from 2010 through 2012 and 2011 through 2013. 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 the closing price of ConocoPhillips common stock, as reported on the NYSE, on December 30, 2011 ($72.87), the last trading day of 2011. |
Amounts presented in “Number of Shares or Units of Stock That Have Not Vested (#)” and “Market Value of Shares or Units of Stock That Have Not Vested ($)” 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. Carrig retired effective March 1, 2011. With regard to the option awards 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 2009 and 2010 became, or will become, exercisable in one-third increments on the anniversary dates of the grants, and the retirement did not accelerate or terminate that exercisability. With regard to stock awards, target awards under the 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 ($))” are usually reduced to reflect service for less than the full time of the relevant performance period, subject to the discretion of the HRCC to set actual payout. The amounts shown reflect the prorated target amounts. Restrictions on all outstanding stock awards from earlier performance periods (including the 105,710 shares to Mr. Carrig awarded in February 2012 with regard to PSP for the performance period from 2009 through 2011) will lapse and payout in unrestricted stock based on his election schedule. For the Stock Option Program and PSP, except in cases of death, disability, or demotion, if the employee has participated for less than a year in a program period, awards related to that program period are forfeited. |
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OPTION EXERCISES AND STOCK VESTED
| Option Awards | Stock Awards | |||||||||||||||||||||||||||||||
| Name | Number of Shares Acquired on Exercise (#) |
Value Realized Upon Exercise ($) |
Number of Shares Acquired on Vesting (#) |
Value Realized Upon Vesting ($) |
||||||||||||||||||||||||||||
| J.J. Mulva |
3,478,000 | $ | 140,853,640 | — | $ | — | ||||||||||||||||||||||||||
| J.A. Carrig(1) |
10,200 | 368,577 | 194,374 | 15,147,049 | ||||||||||||||||||||||||||||
| G.C. Garland(2) |
— | — | 8,438 | 537,290 | ||||||||||||||||||||||||||||
| A.J. Hirshberg |
— | — | — | — | ||||||||||||||||||||||||||||
| R.M. Lance |
74,809 | 2,626,684 | — | — | ||||||||||||||||||||||||||||
| J.W. Sheets |
— | — | — | — | ||||||||||||||||||||||||||||
| (1) | Mr. Carrig received restricted stock units and restricted stock awards during his employment. Per the terms and conditions of certain awards, since Mr. Carrig had not reached normal retirement age (age 65), the value of these awards was credited to his Key Employee Deferred Compensation Plan account in lieu of receiving unrestricted shares. Accordingly, upon his retirement, 144,756 restricted stock units and 49,618 shares of restricted stock were canceled and a value of $15,147,049 was credited to his deferred compensation account. Also see note 2 to the Nonqualified Deferred Compensation table on page 59. |
| (2) | As an inducement to his employment, the HRCC approved a grant of 16,877 restricted stock units to Mr. Garland, effective on the date of employment, the restrictions on which lapse as to one-half of the units on the first anniversary of his employment, while the restrictions on the remainder lapse on the second anniversary of his employment. The amounts reflected represent the lapsing of the one-half of the units on his first anniversary of employment. |
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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, Garland, Lance, and Sheets (having been employees of Phillips) are eligible for, and vested in, benefits under Title I of the CPRP, and Mr. Hirshberg is eligible for benefits under Title II. Title I provides a final average earnings type of pension benefit for eligible employees payable at normal or early retirement from the Company. Under Title I normal retirement occurs upon termination on or after age 65; 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). 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. Mr. Mulva was retirement eligible at the end of 2011. Mr. Carrig was eligible for early retirement on his retirement on March 1, 2011. Messrs. Garland, Hirshberg, Lance, and Sheets were not eligible for early retirement at the end of 2011. Under Title I employees become vested in the benefits after five years of service, and all of the Named Executive Officers are vested in their benefits under those Titles. Under Title II, employees become vested in their benefits after three years of service. Mr. Hirshberg is not vested in his benefits under Title II. Titles I and II 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.
For Title I, 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. 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. 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 50 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 |
× | Years of Credited Service |
] |
Eligible pension compensation generally includes salary and annual incentive compensation. However, under Title I, if 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.
Benefits under Title II are based on monthly pay and interest credits to a cash balance account created on the first day of the month after a participant’s hire date. Pay credits are equal to a percentage of total salary and bonus. Participants whose combined years of age and service total less than 44 receive a 6 percent pay credit, those with 44 through 65 receive a 7 percent pay credit, and those with 66 or more receive a 9 percent pay credit. Normal retirement age is 65, but participants may receive their vested benefit upon termination of employment at any age.
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Eligible pension compensation under Titles I and II is limited in accordance with the Internal Revenue Code. In 2011, that limit was $245,000. The Internal Revenue Code also limits the annual benefit (expressed as an annuity) available under Titles I and II. In 2011, 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 2011, 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 Treasury-bill rates, under most circumstances, will 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.
Mr. Hirshberg was previously an employee of Exxon Mobil Corporation. In connection with his hiring by ConocoPhillips, the Company agreed to provide Mr. Hirshberg with a benefit under KESRP equal to the benefit calculated under KESRP for a participant in Title I of CPRP, reduced by actual benefits payable from CPRP or other ConocoPhillips plans and by estimated benefits payable from the plans of ExxonMobil. Mr. Hirshberg is vested in the benefit payable under KESRP. The Table reflects that benefit, showing only the values payable from the plans of ConocoPhillips, not from the plans of ExxonMobil.
Mr. Lance was an employee of ARCO Alaska, which was acquired by Phillips in 2000. As such, a special provision applies in the calculation of his pension benefits under Title I. First, the Company calculates 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, the Company calculates a benefit under the Title I formula using only service with ConocoPhillips. The Company compares the results of the two methods and the employee receives the larger benefit. For Mr. Lance, 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.
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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 2011 Annual Report on Form 10-K.
| Name | Plan Name | Number of Years Credited Service (#) |
Present Value of Accumulated Benefit ($)(1) |
Payments During Last Fiscal Year ($) |
||||||||||||||||||||
| J.J. Mulva(2) |
Title I - ConocoPhillips Retirement Plan | 40 | $ | 1,959,838 | $ | — | ||||||||||||||||||
|
ConocoPhillips Key Employee Supplemental Retirement Plan |
68,527,688 | — | ||||||||||||||||||||||
| J.A. Carrig(2)(3) |
Title I - ConocoPhillips Retirement Plan | 35 | — | 1,825,887 | ||||||||||||||||||||
| ConocoPhillips Key Employee Supplemental Retirement Plan | — | 28,337,299 | ||||||||||||||||||||||
| G.C. Garland(4) |
Title I - ConocoPhillips Retirement Plan | 22 | 793,184 | — | ||||||||||||||||||||
|
ConocoPhillips Key Employee Supplemental Retirement Plan |
2,675,162 | — | ||||||||||||||||||||||
| A.J. Hirshberg(5) |
Title II - ConocoPhillips Retirement Plan | 1 | 26,671 | — | ||||||||||||||||||||
| ConocoPhillips Key Employee Supplemental Retirement Plan | 29 | 5,740,508 | — | |||||||||||||||||||||
| R.M. Lance |
Title I - ConocoPhillips Retirement Plan | 28 | 602,235 | — | ||||||||||||||||||||
|
ConocoPhillips Key Employee Supplemental Retirement Plan |
4,348,611 | — | ||||||||||||||||||||||
| J.W. Sheets |
Title I - ConocoPhillips Retirement Plan | 32 | 1,208,454 | — | ||||||||||||||||||||
| ConocoPhillips Key Employee Supplemental Retirement Plan | 4,256,304 | — | ||||||||||||||||||||||
| (1) | In determining the present value of the accumulated benefit for each Named Executive Officer, the eligible pension compensation, as defined on pages 53 and 54, used to calculate the amounts above as of December 31, 2011, for each Named Executive Officer is: Mr. Mulva, $23,931,078; Mr. Garland, $1,196,210; Mr. Hirshberg, $1,193,901; Mr. Lance, $4,259,721; and Mr. Sheets, $3,125,758. In determining the present value of the accumulated benefit for Mr. Mulva, 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. |
| (2) | Includes additional credited service for Messrs. Mulva and Carrig of 18.25 and 7.5 months, respectively, related to foreign assignments and for, Mr. Carrig, 15 months additional credited service related to benefits under Title I and an additional 2 months credited service for accrued vacation under normal retirement benefits under Title I. With regard to this additional credited service, the following amount was included in the accumulated benefit shown in the pension table above: Mr. Mulva, $2,684,060. |
| (3) | Mr. Carrig retired effective March 1, 2011 and received a lump-sum distribution of his qualified and non-qualified pension benefit. |
| (4) | With regard to Mr. Garland, he became an employee of ConocoPhillips on October 6, 2010. Prior to joining ConocoPhillips, Mr. Garland was President and Chief Executive Officer for Chevron Phillips Chemical Company LLC (CPChem). ConocoPhillips owns a 50 percent interest in CPChem. None of the benefits earned by Mr. Garland as an employee of CPChem are included in the Table. The service credited to Mr. Garland does not include his time of service with CPChem. |
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| However, prior to his service at CPChem, Mr. Garland had been an employee of Phillips Petroleum Company, which became part of ConocoPhillips at merger in 2002. Mr. Garland’s service shown in the Table includes that prior service with Phillips Petroleum Company, in accordance with the standard terms and conditions of the applicable plans. |
| (5) | With regard to Mr. Hirshberg, he became an employee of ConocoPhillips on October 6, 2010. Prior to joining ConocoPhillips, Mr. Hirshberg was employed by Exxon Mobil Corporation and participated in its defined benefit plans. None of the benefits earned by Mr. Hirshberg as an employee of Exxon Mobil Corporation are included in the Table. The service credited to Mr. Hirshberg does not include his time of service with Exxon Mobil Corporation with regard to calculation of his benefit under Title II, but, pursuant to the offer letter and resolutions approved by the HRCC in connection with his hire, service credited to Mr. Hirshberg with regard to calculation of his benefit under KESRP does include his time of service with Exxon Mobil Corporation. This is reflected in the Table by showing different service crediting periods for Mr. Hirshberg with regard to each of the plans. The service crediting period for Title II is also included in the service crediting period for KESRP. |
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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. The 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 the KEDCP.
Under the KEDCP, for amounts deferred and vested after December 31, 2004, the default distribution option 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 ten 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 the KEDCP or due to limitations imposed by the Internal Revenue Code. For 2010, 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 the DCMP.
Under the 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 the 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”
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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.
| 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 | $ | 4,098,007 | $ | — | $ | 158,088 | $ | 456,242 | $ | — | $ | 4,712,337 | |||||||||||||
| Key Employee Deferred Compensation Plan of ConocoPhillips | 39,831,118 | — | — | (162,752 | ) | — | 39,668,366 | |||||||||||||||||||
| J.A. Carrig(6) |
Defined Contribution Make-Up Plan of ConocoPhillips | 1,014,319 | — | 64,770 | 101,281 | (75,413 | ) | 1,104,957 | ||||||||||||||||||
| Key Employee Deferred Compensation Plan of ConocoPhillips | 9,751,367 | 15,147,049 | — | (73,252 | ) | (3,598,570 | ) | 21,226,594 | ||||||||||||||||||
| G.C. Garland |
Defined Contribution Make-Up Plan of ConocoPhillips | 35,657 | — | 20,375 | 3,717 | — | 59,749 | |||||||||||||||||||
| Key Employee Deferred Compensation Plan of ConocoPhillips | 735,027 | — | — | 58,642 | — | 793,669 | ||||||||||||||||||||
| A.J. Hirshberg(7) |
Defined Contribution Make-Up Plan of ConocoPhillips | — | — | 20,375 | (252 | ) | — | 20,123 | ||||||||||||||||||
| Key Employee Deferred Compensation Plan of ConocoPhillips | 6,742,766 | — | — | (213,151 | ) | (2,995,829 | ) | 3,533,786 | ||||||||||||||||||
| R.M. Lance |
Defined Contribution Make-Up Plan of ConocoPhillips | 324,409 | — | 59,101 | 37,394 | — | 420,904 | |||||||||||||||||||
| Key Employee Deferred Compensation Plan of ConocoPhillips | 1,615,947 | — | — | 24,235 | — | 1,640,182 | ||||||||||||||||||||
| J.W. Sheets |
Defined Contribution Make-Up Plan of ConocoPhillips | 186,533 | — | 34,726 | 21,837 | — | 243,096 | |||||||||||||||||||
| Key Employee Deferred Compensation Plan of ConocoPhillips | 1,756,008 | 837,759 | — | 195,106 | — | 2,788,873 | ||||||||||||||||||||
| (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, 2011, there were a total of 97 investment options, of which 41 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 of which 57 were other various mutual fund options approved by an administrator designated by the relevant plan. |
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| (2) | For Mr. Carrig, he received restricted stock unit and restricted stock awards during his employment. Per the terms and conditions of certain awards, since Mr. Carrig had not reached normal retirement age (age 65), the value of these awards were credited to his Key Employee Deferred Compensation Plan account in lieu of receiving unrestricted shares. Accordingly, upon his retirement, 144,756 restricted stock units and 49,618 shares of restricted stock were canceled and a value of $15,147,049 was credited to his deferred compensation account. Also see Footnote 1 to the Option Exercises and Stock Vested table on page 52. For Mr. Sheets this reflects $154,875 in salary and $682,884 in 2010 VCIP deferred in 2011 (included in the 2011 “Salary” and 2010 “Non-Equity Incentive Plan Compensation” columns respectively of the Summary Compensation Table). |
| (3) | Reflects contributions by the Company under the DCMP in 2011 (included in the “All Other Compensation” column of the Summary Compensation Table on page 43 for 2011). |
| (4) | None of these earnings is included in the Summary Compensation Table for 2011. |
| (5) | Reflects contributions by our Named Executive Officers, contributions by the Company, and earnings on balances prior to 2011; plus contributions by our Named Executive Officers, contributions by the Company, and earnings for 2011 (shown in the appropriate columns of this table, with amounts that are included in the Summary Compensation Table for 2011 shown in Footnotes (2), (3) and (4) above). |
| (6) | Pursuant to the terms and conditions of certain of the awards that were credited to Mr. Carrig’s KEDCP account as discussed in Footnote (2) above, the value was distributed six months after his retirement. As to the distributions from his Defined Contribution Make-Up Plan, the amount reflects 2005 contributions that were distributed six months after his retirement. |
| (7) | Mr. Hirshberg became an employee of the Company on October 6, 2010. Pursuant to the terms of his offer letter (approved by the HRCC), a KEDCP account was created for Mr. Hirshberg at the time of his employment and credited with $6,357,436. Forty-seven percent of the account balance as of the first anniversary of his employment vested in 2011, 47 percent will vest on the second anniversary of his employment, and the remainder will vest on the third anniversary of his employment. Distributions will occur on the dates of vesting, unless Mr. Hirshberg has made timely elections to delay distribution. He did not elect to delay the distribution regarding the vesting on the first anniversary of his employment. |
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Executive Severance and Changes in Control
Salary and other compensation for our Named Executive Officers is set by the HRCC, as described in “Compensation Discussion and Analysis” beginning on page 26 of this proxy statement. These officers may participate in the Company’s employee benefit plans and programs for which they are eligible, in accordance with their terms. The amounts earned by the Named Executive Officers for 2011 appear in the various Executive Compensation Tables beginning on page 43 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, Stock Option Program, and PSP), early retirement is generally defined to be termination at or after the age of 55 with five years of service.
As of December 31, 2011, Mr. Mulva was retirement eligible under both our benefit plans and our compensation programs. As of December 31, 2011, Messrs. Hirshberg, Garland, Lance, and Sheets had 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, 2011, a voluntary resignation of Mr. Mulva would have been treated as a retirement. Since Mr. Mulva was then eligible for retirement under these programs, he would be able to resign and retain all awards earned under the PSP and earlier programs. As a result, the awards to Mr. Mulva under such programs are not included in the incremental amounts reflected in the tables below. Please see “Outstanding Equity Awards at Fiscal Year End” beginning on page 50 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 (CPESP), available to a limited number of senior executives; and the other being the ConocoPhillips Key Employee Change in Control Severance Plan (CICSP), 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; for example, executives receiving benefits under the CICSP would not be entitled to benefits potentially payable under the CPESP relating to the event giving rise to benefits under the CICSP.
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ConocoPhillips Executive Severance Plan
The 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 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; |
| • | A lump-sum cash payment equal to the Company cost of certain welfare benefits for an additional two or three years; |
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| • | 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.
Other Arrangements
Mr. Hirshberg became an employee of ConocoPhillips on October 6, 2010. The HRCC approved an offer letter to him which described the terms and conditions of employment, including the fact that he would serve as an at-will employee. The letter also provided certain protections against termination events. He will be considered to have been terminated by the Company if the Company terminates his employment either without cause or if his employment is terminated by mutual agreement or if he initiates the termination of his employment (but only if given good reason to do so), prior to attaining age 55. Any severance benefits to which he may become entitled prior to attainment of age 55 will not be less than the severance benefits provided under the letter, the CPESP, and the CICSP as those plans were in effect on the date of the letter.
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, 2011, 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. Carrig who retired from the Company effective March 1, 2011) would be entitled if their employment were terminated due to the events described above.
| 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 | — | 8,296,932 | — | — | |||||||||||||||
| Variable Cash Incentive Program |
— | (2,025,000 | ) | — | — | — | ||||||||||||||
| 2009—2011 (performance period) |
— | (18,739,832 | ) | — | — | — | ||||||||||||||
| 2010—2012 (performance period) |
— | (6,173,328 | ) | — | — | — | ||||||||||||||
| 2011—2013 (performance period) |
— | (2,557,956 | ) | — | — | — | ||||||||||||||
| Restricted Stock/Units from prior performance |
— | (2,754,486 | ) | — | — | — | ||||||||||||||
| Stock Options/SARs: |
||||||||||||||||||||
| Unvested and Accelerated |
— | (13,758,648 | ) | — | — | — | ||||||||||||||
| Incremental Pension |
3,163,413 | — | 4,745,119 | — | — | |||||||||||||||
| Post-employment Health & Welfare |
722,316 | — | 1,110,212 | — | — | |||||||||||||||
| Life Insurance |
— | — | — | 3,000,000 | — | |||||||||||||||
| 280G Tax Gross-up |
— | — | — | — | — | |||||||||||||||
|
|
|
|||||||||||||||||||
| 10,935,729 | (46,009,250 | ) | 18,652,263 | 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 | |||||||||||||||
| G.C. Garland† |
||||||||||||||||||||
| Base Salary |
$ | 1,552,000 | $ | — | $ | 2,328,000 | $ | — | $ | — | ||||||||||
| Short-term Incentive |
1,381,280 | — | 2,071,920 | — | — | |||||||||||||||
| Variable Cash Incentive Program |
690,640 | — | 690,640 | 690,640 | 690,640 | |||||||||||||||
| 2009—2011 (performance period) |
1,562,916 | — | 1,562,916 | 1,562,916 | 1,562,916 | |||||||||||||||
| 2010—2012 (performance period) |
965,309 | — | 965,309 | 965,309 | 965,309 | |||||||||||||||
| 2011—2013 (performance period) |
471,688 | — | 471,688 | 471,688 | 471,688 | |||||||||||||||
| Restricted Stock/Units from inducement grant |
614,950 | — | 614,950 | 614,950 | 614,950 | |||||||||||||||
| Stock Options/SARs: |
||||||||||||||||||||
| Unvested and Accelerated |
180,415 | — | 196,817 | 196,817 | 196,817 | |||||||||||||||
| Incremental Pension |
2,442,169 | — | 2,913,242 | — | — | |||||||||||||||
| Post-employment Health & Welfare |
28,625 | — | 42,037 | — | — | |||||||||||||||
| Life Insurance |
— | — | — | 1,552,000 | — | |||||||||||||||
| 280G Tax Gross-up |
— | — | 3,184,639 | — | — | |||||||||||||||
|
|
|
|||||||||||||||||||
| 9,889,992 | — | 15,042,158 | 6,054,320 | 4,502,320 | ||||||||||||||||
|
|
|
|||||||||||||||||||
| Executive Benefits
and Payments Upon Termination |
Involuntary Not-for-Cause Termination (Not CIC) |
For-Cause Termination |
Involuntary or Good Reason Termination (CIC) |
Death | Disability | |||||||||||||||
| A.J. Hirshberg† |
||||||||||||||||||||
| Base Salary |
$ | 1,552,000 | $ | — | $ | 2,328,000 | $ | — | $ | — | ||||||||||
| Short-term Incentive |
1,381,280 | — | 2,071,920 | — | — | |||||||||||||||
| Variable Cash Incentive Program |
690,640 | — | 690,640 | 690,640 | 690,640 | |||||||||||||||
| Key Employee Deferred Compensation Plan |
— | (3,533,787 | ) | — | — | — | ||||||||||||||
| 2009—2011 (performance period) |
1,497,770 | — | 1,497,770 | 1,497,770 | 1,497,770 | |||||||||||||||
| 2010—2012 (performance period) |
965,309 | — | 965,309 | 965,309 | 965,309 | |||||||||||||||
| 2011—2013 (performance period) |
471,688 | — | 471,688 | 471,688 | 471,688 | |||||||||||||||
| Restricted Stock/Units from inducement grant |
— | (3,566,622 | ) | — | — | — | ||||||||||||||
| Stock Options/SARs: |
||||||||||||||||||||
| Unvested and Accelerated |
180,415 | — | 196,817 | 196,817 | 196,817 | |||||||||||||||
| Incremental Pension |
4,320,871 | — | 4,743,808 | — | — | |||||||||||||||
| Post-employment Health & Welfare |
92,376 | — | 130,835 | — | — | |||||||||||||||
| Life Insurance |
— | — | — | 1,552,000 | — | |||||||||||||||
| 280G Tax Gross-up |
— | — | 3,469,332 | — | — | |||||||||||||||
|
|
|
|||||||||||||||||||
| 11,152,349 | (7,100,409 | ) | 16,566,119 | 5,374,224 | 3,822,224 | |||||||||||||||
|
|
|
|||||||||||||||||||
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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 | |||||||||||||||
| R.M. Lance† |
||||||||||||||||||||
| Base Salary |
$ | 1,552,000 | $ | — | $ | 2,328,000 | $ | — | $ | — | ||||||||||
| Short-term Incentive |
1,381,280 | — | 2,390,004 | — | — | |||||||||||||||
| Variable Cash Incentive Program |
690,640 | — | 690,640 | 690,640 | 690,640 | |||||||||||||||
| 2009—2011 (performance period) |
3,264,649 | — | 3,264,649 | 3,264,649 | 3,264,649 | |||||||||||||||
| 2010—2012 (performance period) |
1,223,196 | — | 1,223,196 | 1,223,196 | 1,223,196 | |||||||||||||||
| 2011—2013 (performance period) |
471,688 | — | 471,688 | 471,688 | 471,688 | |||||||||||||||
| Restricted Stock/Units from prior performance |
8,294,646 | — | 8,294,646 | 8,294,646 | 8,294,646 | |||||||||||||||
| Stock Options/SARs: |
||||||||||||||||||||
| Unvested and Accelerated |
2,453,763 | — | 2,470,165 | 2,470,165 | 2,470,165 | |||||||||||||||
| Incremental Pension |
3,604,433 | — | 3,860,474 | — | — | |||||||||||||||
| Post-employment Health & Welfare |
96,035 | — | 135,490 | — | — | |||||||||||||||
| Life Insurance |
— | — | — | 1,552,000 | — | |||||||||||||||
| 280G Tax Gross-up |
— | — | 6,138,512 | — | — | |||||||||||||||
|
|
|
|||||||||||||||||||
| 23,032,330 | — | 31,267,464 | 17,966,984 | 16,414,984 | ||||||||||||||||
|
|
|
|||||||||||||||||||
| 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.W. Sheets† |
||||||||||||||||||||
| Base Salary |
$ | 1,278,000 | $ | — | $ | 1,917,000 | $ | — | $ | — | ||||||||||
| Short-term Incentive |
1,060,740 | — | 1,702,338 | — | — | |||||||||||||||
| Variable Cash Incentive Program |
530,370 | — | 530,370 | 530,370 | 530,370 | |||||||||||||||
| 2009—2011 (performance period) |
2,025,276 | — | 2,025,276 | 2,025,276 | 2,025,276 | |||||||||||||||
| 2010—2012 (performance period) |
835,892 | — | 835,892 | 835,892 | 835,892 | |||||||||||||||
| 2011—2013 (performance period) |
372,584 | — | 372,584 | 372,584 | 372,584 | |||||||||||||||
| Restricted Stock/Units from prior performance |
4,893,731 | — | 4,893,731 | 4,893,731 | 4,893,731 | |||||||||||||||
| Stock Options/SARs: |
||||||||||||||||||||
| Unvested and Accelerated |
1,180,459 | — | 1,190,456 | 1,190,456 | 1,190,456 | |||||||||||||||
| Incremental Pension |
3,373,991 | — | 4,211,836 | — | — | |||||||||||||||
| Post-employment Health & Welfare |
30,580 | — | 41,695 | — | — | |||||||||||||||
| Life Insurance |
— | — | — | 1,278,000 | — | |||||||||||||||
| 280G Tax Gross-up |
— | — | 3,546,474 | — | — | |||||||||||||||
|
|
|
|||||||||||||||||||
| 15,581,623 | — | 21,267,652 | 11,126,309 | 9,848,309 | ||||||||||||||||
|
|
|
|||||||||||||||||||
†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 2009-2011 period are shown at the payout amount that was awarded in February 2012, while amounts for other periods are prorated to reflect the portion of the performance period completed by the end of 2011. For the PSP awards, for restricted stock and restricted stock units, amounts reflect the closing price of ConocoPhillips common stock, as reported on the NYSE, on December 30, 2011 ($72.87), the last trading day of 2011. |
| • | Stock Options—For stock options with a December 30, 2011 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, 2011, but only regarding the options that the executive would have retained for the specific termination event. For options with a December 30, 2011 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. |
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| • | 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 ConocoPhillips stock, as reported on the NYSE, on December 30, 2011 ($72.87); |
| • | 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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Advisory Approval of Executive Compensation
(Item 3 on the Proxy Card)
What am I voting on?
Stockholders are being asked to vote on the following advisory resolution:
RESOLVED, that the stockholders approve the compensation of ConocoPhillips’ Named Executive Officers as described in the Compensation Discussion and Analysis section and in the tabular disclosures regarding Named Executive Officer compensation (together with the accompanying narrative disclosures) in this proxy statement.
ConocoPhillips is providing stockholders with the opportunity to vote on an advisory resolution, commonly known as “Say-on-Pay,” considering approval of the compensation of ConocoPhillips’ Named Executive Officers.
The Human Resources and Compensation Committee, which is responsible for the compensation of our executive officers, has overseen the development of a compensation program designed to attract, retain and motivate executives who enable us to achieve our strategic and financial goals. The Compensation Discussion and Analysis and the tabular disclosures regarding Named Executive Officer compensation, together with the accompanying narrative disclosures, allow you to view the trends in compensation and application of our compensation philosophies and practices for the years presented.
The Board of Directors believes that ConocoPhillips’ executive compensation program aligns the interests of our executives with those of our stockholders. Our compensation program is guided by the philosophy that the Company’s ability to responsibly deliver energy and to provide sustainable value is driven by superior individual performance. The Board believes that a company must offer competitive compensation to attract and retain experienced, talented and motivated employees. In addition, the Board believes 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. The Board believes that our philosophy and practices have resulted in executive compensation decisions that are aligned with Company and individual performance, are appropriate in value and have benefited the Company and its stockholders.
What is the effect of this resolution?
Because your vote is advisory, it will not be binding upon the Board of Directors. However, the HRCC and the Board will take the outcome of the vote into account when considering future executive compensation arrangements.
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 OF DIRECTORS RECOMMENDS YOU VOTE “FOR”
THE ADVISORY APPROVAL OF THE COMPENSATION OF
THE COMPANY’S NAMED EXECUTIVE OFFICERS
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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 directors 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
In 2011, non-employee directors received an annual grant of restricted stock units with an aggregate value of $170,000 on the date of grant. Restrictions on the units issued to a non-employee director will lapse in the event of retirement, disability, death, or 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 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 have slightly modified terms responsive to the tax laws of their home countries (Canada and Norway, respectively), the most important difference being that the restrictions lapse only in the event of retirement, death, or loss of office.
Cash Compensation
In 2011, all non-employee directors received $115,000 annual cash compensation. Non-employee directors serving in specified committee positions also received 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 |
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| ¡ | Chair of the other committees—$10,000 |
| ¡ | All other Audit and Finance Committee members—$7,500 |
| ¡ | All other Human Resources and Compensation Committee members—$5,000 |
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 ConocoPhillips common stock on such date), or 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 (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
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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 representing this reimbursement are contained in the “All Other Compensation” column.
Stock Ownership
Directors are expected to own as much Company 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 2011 (for compensation paid to our sole employee director, Mr. Mulva, please see our Executive Compensation Tables beginning on page 43).
| Name | Fees Earned or Paid in Cash ($)(1) |
Stock Awards ($)(2)(3) |
Option Awards ($) |
Non-Equity Incentive Plan Compensation ($) |
Change in Pension Value and Nonqualified Deferred Compensation Earnings ($) |
All Other Compensation ($)(4) |
Total ($) |
|||||||||||||||||||||||||||||||||||||||||||||||||
| R.L. Armitage |
$ | 115,000 | $ | 170,012 | $ | — | $ | — | $ | — | $ | — | $ | 285,012 | ||||||||||||||||||||||||||||||||||||||||||
| R.H. Auchinleck |
150,345 | 170,012 | — | — | — | 13,639 | 333,996 | |||||||||||||||||||||||||||||||||||||||||||||||||
| J.E. Copeland, Jr. |
135,000 | 170,012 | — | — | — | 25,358 | 330,370 | |||||||||||||||||||||||||||||||||||||||||||||||||
| K.M. Duberstein |
115,000 | 170,012 | — | — | — | 26,213 | 311,225 | |||||||||||||||||||||||||||||||||||||||||||||||||
| R.R. Harkin |
125,000 | 170,012 | — | — | — | 7,000 | 302,012 | |||||||||||||||||||||||||||||||||||||||||||||||||
| M.H. Marican(5) |
10,208 | — | — | — | — | — | 10,208 | |||||||||||||||||||||||||||||||||||||||||||||||||
| H.W. McGraw III |
120,375 | 170,012 | — | — | — | — | 290,387 | |||||||||||||||||||||||||||||||||||||||||||||||||
| R.A. Niblock |
122,500 | 170,012 | — | — | — | 15,000 | 307,512 | |||||||||||||||||||||||||||||||||||||||||||||||||
| H.J. Norvik |
122,924 | 170,012 | — | — | — | 16,200 | 309,136 | |||||||||||||||||||||||||||||||||||||||||||||||||
| W.K. Reilly |
115,000 | 170,012 | — | — | — | 16,859 | 301,871 | |||||||||||||||||||||||||||||||||||||||||||||||||
| B.S. Shackouls |
47,917 | 170,012 | — | — | — | 21,778 | 239,707 | |||||||||||||||||||||||||||||||||||||||||||||||||
| V.J. Tschinkel |
122,500 | 170,012 | — | — | — | 10,164 | 302,676 | |||||||||||||||||||||||||||||||||||||||||||||||||
| K.C. Turner |
120,000 | 170,012 | — | — | — | 15,000 | 305,012 | |||||||||||||||||||||||||||||||||||||||||||||||||
| W.E. Wade, Jr. |
130,441 | 170,012 | — | — | — | 5,000 | 305,453 | |||||||||||||||||||||||||||||||||||||||||||||||||
| (1) | Reflects 2011 annual cash compensation of $115,000 payable to each non-employee director. In 2011, non-employee directors serving in specified committee positions also received 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 |
| • | All other Human Resources and Compensation Committee members—$5,000 |
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) | Amounts represent the grant date fair value of stock awards. Under our Non-Employee Director compensation program, non-employee directors received a 2011 annual grant of restricted stock units with an aggregate value of $170,000 on the date of grant based on the average of the high and low price for our common stock, as reported on the NYSE, on such date. These grants are made in whole shares with fractional share amounts rounded up, resulting in shares with a value of $170,012 being granted on January 15, 2011 to all persons who were directors on that date. |
| (3) | The following table reflects, for each director, the aggregate number of stock awards outstanding as of December 31, 2011. |
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| Option Awards | Stock Awards | |||||||||||||||||||||||||||||||||||
| Name | Number of Securities Underlying Unexercised Options (#) Exercisable |
Number of Securities Underlying Unexercised Options (#) Unexercisable |
Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options (#) |
Option Exercise Price ($) |
Option Expiration Date |
Number of Shares or Units of Stock That Have Not Vested (#) |
||||||||||||||||||||||||||||||
| R.L. Armitage |
— | — | — | $ — | — | 12,244 | ||||||||||||||||||||||||||||||
| R.H. Auchinleck |
— | — | — | — | — | 59,896 | ||||||||||||||||||||||||||||||
| J.E. Copeland, Jr. |
— | — | — | — | — | 28,261 | ||||||||||||||||||||||||||||||
| K.M. Duberstein |
— | — | — | — | — | 48,486 | ||||||||||||||||||||||||||||||
| R.R. Harkin |
— | — | — | — | — | 32,544 | ||||||||||||||||||||||||||||||
| M.H. Marican |
— | — | — | — | — | — | ||||||||||||||||||||||||||||||
| H.W. McGraw III |
— | — | — | — | — | 25,810 | ||||||||||||||||||||||||||||||
| R.A. Niblock |
— | — | — | — | — | 2,619 | ||||||||||||||||||||||||||||||
| H.J. Norvik |
— | — | — | — | — | 24,008 | ||||||||||||||||||||||||||||||
| W.K. Reilly |
— | — | — | — | — | 48,681 | ||||||||||||||||||||||||||||||
| B.S. Shackouls |
— | — | — | — | — | — | ||||||||||||||||||||||||||||||
| V.J. Tschinkel |
— | — | — | — | — | 48,030 | ||||||||||||||||||||||||||||||
| K.C. Turner |
— | — | — | — | — | 51,627 | ||||||||||||||||||||||||||||||
| W.E. Wade, Jr. |
— | — | — | — | — | 17,020 | ||||||||||||||||||||||||||||||
The following table lists option exercises by directors and vesting of director stock awards in 2011.
| Option Awards | Stock Awards | |||||||||||||||||||||||
| Name | Number of Shares Acquired on Exercise (#) |
Value Realized Upon Exercise ($) |
Number of Shares Acquired on Vesting (#) |
Value Realized Upon Vesting ($) |
||||||||||||||||||||
| R.L. Armitage |
— | $ — | — | $ — | ||||||||||||||||||||
| R.H. Auchinleck |
— | — | — | — | ||||||||||||||||||||
| J.E. Copeland, Jr. |
— | — | — | — | ||||||||||||||||||||
| K.M. Duberstein |
— | — | — | — | ||||||||||||||||||||
| R.R. Harkin |
— | — | — | — | ||||||||||||||||||||
| M.H. Marican |
— | — | — | — | ||||||||||||||||||||
| H.W. McGraw III |
— | — | — | — | ||||||||||||||||||||
| R.A. Niblock |
— | — | — | — | ||||||||||||||||||||
| H.J. Norvik |
— | — | — | — | ||||||||||||||||||||
| W.K. Reilly |
— | — | — | — | ||||||||||||||||||||
| B.S. Shackouls (a) |
— | — | 12,244 | 886,095 | ||||||||||||||||||||
| V.J. Tschinkel (b) |
— | — | 4,722 | 317,825 | ||||||||||||||||||||
| K.C. Turner |
— | — | — | — | ||||||||||||||||||||
| W.E. Wade, Jr. |
— | — | — | — | ||||||||||||||||||||
| (a) | Mr. Shackouls received restricted stock unit awards for his service as Director of ConocoPhillips in 2006—2011 totaling 12,244 units. As permitted by the terms and conditions of the awards, Mr. Shackouls elected to receive unrestricted shares in a lump sum 6 months after separation from service. Mr. Shackouls retired from the Board on May 11, 2011. The total unrestricted shares acquired upon vesting of these awards were 12,244 shares, valued at $886,095. 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. |
| (b) | Ms. Tschinkel received restricted stock unit awards for her service as Director of ConocoPhillips in 2003 totaling 4,722 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 eight years after grant date. The total unrestricted shares acquired upon vesting of these awards were 4,722 shares, valued at $317,825. 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. |
| (4) | Includes the amounts attributable to the following: |
| Name | Tax Reimbursement Gross-Up(a) |
Retirement Presentations(b) |
Matching Gift Amounts(c) |
Total | ||||||||||||||||||||||||||||||||||||
| R.L. Armitage |
$ | — | $ | — | $ | — | $ | — | ||||||||||||||||||||||||||||||||
| R.H. Auchinleck |
13,639 | — | — | 13,639 | ||||||||||||||||||||||||||||||||||||
| J.E. Copeland, Jr. |
10,358 | — | 15,000 | 25,358 | ||||||||||||||||||||||||||||||||||||
| K.M. Duberstein |
11,213 | — | 15,000 | 26,213 | ||||||||||||||||||||||||||||||||||||
| R.R. Harkin |
— | — | 7,000 | 7,000 | ||||||||||||||||||||||||||||||||||||
| M.H. Marican |
— | — | — | — | ||||||||||||||||||||||||||||||||||||
| H.W. McGraw III |
— | — | — | — | ||||||||||||||||||||||||||||||||||||
| R.A. Niblock |
— | — | 15,000 | 15,000 | ||||||||||||||||||||||||||||||||||||
| H.J. Norvik |
16,200 | — | — | 16,200 | ||||||||||||||||||||||||||||||||||||
| W.K. Reilly |
1,909 | — | 14,950 | 16,859 | ||||||||||||||||||||||||||||||||||||
| B.S. Shackouls |
4,188 | 2,590 | 15,000 | 21,778 | ||||||||||||||||||||||||||||||||||||
| V.J. Tschinkel |
1,009 | — | 9,155 | 10,164 | ||||||||||||||||||||||||||||||||||||
| K.C. Turner |
— | — | 15,000 | 15,000 | ||||||||||||||||||||||||||||||||||||
| W.E. Wade, Jr. |
— | — | 5,000 | 5,000 | ||||||||||||||||||||||||||||||||||||
| (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) | These amounts reflect the practice of the Company to make presentations to its retiring directors. The amounts shown reflect the invoiced cost to the Company. |
| (c) | 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 2011. 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 43 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. |
| (5) | Tan Sri Marican was elected to the Board in December 2011. The amounts in the tables above include his prorated compensation reflecting the portion of 2011 in which he served as a Director and as a member of the Audit and Finance Committee. He received cash compensation for December 2011 only. He received no equity compensation for 2011, as he did not join the Board until after the payment date for equity compensation in January 2011. |
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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, 2011:
| 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) |
27,359,632 | (3) | $ | 58.04 | 35,757,872 | (4) | ||||||
| Equity compensation plans not approved by security holders |
— | — | — | |||||||||
|
|
|
|||||||||||
| Total |
27,359,632 | $ | 58.04 | 35,757,872 | ||||||||
|
|
|
|||||||||||
| (1) | Includes awards issued from the 2011 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, which was approved by stockholders on May 11, 2011, and from 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 2011 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, no additional awards may be granted under the 2009 Omnibus Stock and Performance Incentive Plan of ConocoPhillips. |
| (2) | Excludes (a) options to purchase 9,571,697 shares of ConocoPhillips common stock at a weighted average price of $27.11, (b) 1,505,431 restricted stock units, and (c) 21,685 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 193,867 restricted stock units issued in payment of annual awards and dividend equivalents which were reinvested with regard to existing awards received annually, and 76,788 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 140,285 restricted stock units issued in payment of dividend equivalents reinvested with respect to certain special awards 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, under the 2009 Plan during the time period from May 13, 2009 to May 10, 2011, and thereafter under the 2011 Omnibus Stock and Performance Incentive Plan. Also includes 120,180 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, 5,570,767 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; 2,372,344 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 844,318 restricted stock units issued to executives on February 10, 2006, 740,994 restricted stock units issued to executives on February 8, 2007, 759,235 restricted stock units issued to executives on February 14, 2008, 413,229 restricted stock units issued to executives on February 12, 2009, 235,500 restricted stock units issued to executives on February 12, 2010 and 524,485 restricted stock units issued to executives on February 10, 2011. These restricted stock units have no voting rights, |
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| are eligible for cash dividend equivalents, and have restrictions on transferability that last until separation of service from the company. In addition, 703,467 restricted stock units that are not eligible for cash dividend equivalents were issued as retention bonuses; the awards vest over a period of two to three years, the restrictions lapsing in two or three equal annual installments beginning on the first anniversary of the grant dates. Further included are 14,506,980 non-qualified and 157,193 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 2011 Omnibus Stock and Performance Incentive Plan, no more than 40,000,000 shares of common stock may be issued for incentive stock options (1,429,604 have been issued with 38,570,396 available for future issuance) and no more than 40,000,000 shares of common stock may be issued with respect to stock awards (25,319,393 have been issued with 14,680,607 available for future issuance). Securities remaining available for future issuance take into account outstanding equity awards made under the 2011 Omnibus Stock and Performance Incentive Plan, 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 |
||||||
| BlackRock Inc. (1) 40 East 52nd Street New York, NY 10022 |
75,386,948 | 5.68 | % | |||||
| (1) | Based on a Schedule 13G filed with the SEC on February 13, 2012, by BlackRock Inc., on behalf of itself, BlackRock Japan Co. Ltd., BlackRock Advisors (UK) Limited, BlackRock Asset Management Deutschland AG, 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 (Korea) Ltd, BlackRock (Luxembourg) S.A., BlackRock (Netherlands) B.V., BlackRock Fund Managers Limited, BlackRock Pensions Limited, BlackRock Asset Management Ireland Limited, BlackRock International Limited, BlackRock Investment Management (UK) Limited. |
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, 2011, 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 reporting one transaction was filed late on behalf of each of Messrs. Mulva, Auchinleck, McGraw, Norvick and Wade.
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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 February 15, 2012, 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 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 February 15, 2012.
| 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 | 14,657 | — | |||||||||
| Richard H. Auchinleck |
5,989 | 60,245 | — | |||||||||
| John A. Carrig |
240,358 | 321,807 | 1,182,229 | |||||||||
| James E. Copeland, Jr. |
21,842 | 30,674 | — | |||||||||
| Kenneth M. Duberstein |
14,391 | 43,157 | — | |||||||||
| Greg C. Garland |
40,791 | 31,226 | 23,900 | |||||||||
| Ruth R. Harkin(3) |
19,393 | 34,957 | — | |||||||||
| Al J. Hirshberg |
717 | 70,295 | 23,900 | |||||||||
| Ryan M. Lance |
25,710 | 162,795 | 245,200 | |||||||||
| Harold W. McGraw III |
1,000 | 28,369 | — | |||||||||
| Mohd H. Marican |
— | 2,413 | — | |||||||||
| James J. Mulva |
1,372,065 | 2,891,720 | 3,981,132 | |||||||||
| Robert A. Niblock |
— | 5,181 | — | |||||||||
| Harald J. Norvik |
— | 26,570 | — | |||||||||
| William K. Reilly |
7,228 | 43,867 | — | |||||||||
| Jeff W. Sheets |
40,642 | 106,537 | 217,271 | |||||||||
| Victoria J. Tschinkel(4) |
29,318 | 44,730 | — | |||||||||
| Kathryn C. Turner |
12,917 | 49,324 | — | |||||||||
| William E. Wade, Jr.(5) |
20,764 | 19,473 | — | |||||||||
| Directors and Executive Officers as a Group |
1,651,882 | 3,869,457 | 5,031,837 | |||||||||
| (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 February 15, 2012, through stock options awarded under compensation plans. |
| (3) | Includes 46 shares held by Ms. Harkin’s daughter. |
| (4) | 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. |
| (5) | Includes 367 shares of common stock owned by the Wade Family Trust. |
| (6) | Excludes shares owned by Mr. Carrig, who retired March 1, 2011, and is no longer an executive officer of the Company. |
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Company Environmental Policy (Louisiana Wetlands)
(Item 4 on the Proxy Card)
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
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
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. 10, 2009). See also
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. 1, 2009).
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).
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.
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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.
What does the Board recommend?
THE BOARD RECOMMENDS THAT YOU VOTE “AGAINST” THIS PROPOSAL FOR THE FOLLOWING REASONS:
Over the past several years, ConocoPhillips has been involved in numerous coastal restoration initiatives, including addressing the challenges of significant natural subsidence in the region. In fact, access permitted on 44 of our projects has improved 166,000 acres of wetlands. Another 10 projects are under construction or pending that will improve 50,000 acres.
ConocoPhillips does not presently have any onshore production operations in the Louisiana coastal wetlands because of the disposition of eight fields in our onshore operations there in 2010. The primary presence of the Company in the area now is our fee acreage holdings of more than 600,000 acres. We continue to evaluate our position regarding future operations depending on ongoing exploration results.
The following brief overview of the current status of ConocoPhillips’ presence in the Southeast Louisiana coastal wetlands offers insight into the efforts made throughout the area over the past several years, including the donation of the Barrier Islands (or Isle Derniers) to the state of Louisiana on July 24, 1997.
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 Protection and Restoration Authority, the Louisiana Department of Wildlife and Fisheries and the U.S. Army Corps of Engineers. These regulatory bodies work closely together to protect, enhance 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 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.
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ConocoPhillips reports on sustainable development progress periodically in the online Sustainable Development section of the Company’s Web site. In coastal Louisiana, ConocoPhillips regularly provides access to its lands at no cost and works closely with government agencies and other groups operating wetland projects that complement Company activities. As of year-end 2011, there were 85 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 the Company’s 15-year partnership with the National Fish and Wildlife Foundation, which has funded more than 50 projects with a total value exceeding $6.5 million. Over the past decade, ConocoPhillips has donated nearly $100,000 and many volunteer hours to support preserving and developing Woodlands Trail & Park, an ecosystem located within one of Southeastern Louisiana’s last remaining coastal forests.
Two major federally-funded projects recently came to fruition on the Company’s Louisiana wetlands. The Penchant Basin Restoration, a $7 million project, constructed 14,000 linear feet of earthen embankment, with rock shoreline protection and two major water control structures. The East Grand Terre Island Restoration, a $16 million project, provided 310 acres of beach and coastal marsh creation and restoration. The Company provided the land, access and some design ideas for these federal projects. ConocoPhillips also hosted a workshop for agencies and landowners to introduce 17 new coastal restoration concepts. This important gathering brought together various federal, state and parish agencies and officials to advance the Coastal Restoration Protection and Planning Act. The Company took the initiative to design some of the restoration concepts, and to gain support of adjacent land owners and officials from the four parishes involved.
In 2010, the State of Louisiana executed a project at the site of ConocoPhillips’ Alliance Refinery to pump 30 million cubic yards of sediment from a sand bar in the Mississippi River through the refinery property and into the marshes to the west. This restoration project created approximately 577 acres of new, dry land where land had previously subsided and degraded into open water.
This type of wetlands restoration works to compensate for the lack of natural sediment deposition and to offset natural subsidence, an important issue in south Louisiana. With the flood control levee systems put in place over the last 50 years, the natural silting has stopped and, without new silt deposits, the wetlands eventually subside, becoming shallow water bodies instead of marshlands. Approximately 2.5 miles of 36-inch diameter pipe was laid across ConocoPhillips property to transport river sediments to the subsided marshes. ConocoPhillips donated the right of way for the project. Known as the Bayou Dupont Sediment Delivery Project, the effort was so successful that the State Department of Natural Resources has entered into talks with the Alliance Refinery about a proposal to utilize the pipeline delivery system over a longer period, extending its reach farther to the west to create a “land bridge” that would provide storm surge protection for the greater New Orleans metropolitan area. ConocoPhillips is honored to be a participant in this effort and will cooperate with the state to make the long distance pipeline sediment delivery system a reality.
Based on the fact that ConocoPhillips has 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:
Accident Risk Mitigation
(Item 5 on the Proxy Card)
What is the Proposal?
Report on Accident Risk Mitigation
Resolved, that the shareholders of ConocoPhillips (the “Company”) urge the Board of Directors (the “Board”) to prepare a report, within ninety days of the 2012 annual meeting of stockholders, at reasonable cost and excluding proprietary and personal information, on the steps the Company has taken to reduce the risk of accidents. The report should describe the Board’s oversight of process safety management, staffing levels, inspection and maintenance of refineries and other equipment.
Supporting Statement
The 2010 BP Deepwater Horizon explosion and oil spill in the Gulf of Mexico resulted in the largest and most costly human and environmental catastrophe in the history of the petroleum industry. Eleven workers were killed when the BP Deepwater Horizon drilling platform exploded. This was not the first major accident for BP. In 2005, an explosion at BP’s refinery in Texas City, Texas, cost the lives of 15 workers, injured 170 others and resulted in the largest fines ever levied by the Occupational, Safety and Health Administration (“OSHA”)(BP Faces Record Fine for ‘05 Refinery Explosion,” New York Times, 10/30/2009).
BP’s accidents are not unique in the petroleum industry. For example, a 2010 explosion at the Tesoro refinery in Anacortes, Washington, killed seven workers and resulted in more than six months of downtime at the 120,000 barrels per day refinery (“Tesoro Sees Anacortes at Planned Rates by mid-Nov.,” Reuters, 11/5/2010). The director of the Washington State Department of Labor and Industry stated that “The bottom line is this incident, the explosion and these deaths were preventable,” and levied an initial penalty of $2.39 million (“State Fines Tesoro $2.4 Million in Deadly Refinery Blast,” Skagit Valley Herald, 10/4/2010).
We believe that OSHA’s National Emphasis Program for petroleum refineries has revealed an industry-wide pattern of non-compliance with safety regulations. In the first year of this program, inspections of 14 refineries exposed 1,517 violations, including 1,489 for process safety management, prompting OSHA’s director of enforcement to declare “The state of process safety management is frankly just horrible” (“Process Safety Violations at Refineries ‘Depressingly’ High, OSHA Official Says,” BNA Occupational Safety and Health Reporter, 8/27/2009).
Since November, 2006, OSHA has recorded 12 safety violations at our Company, including serious and repeat violations. Eight of these violations involved Process Safety Management. Two of our Company’s California refineries have had accidents. http:osha.gov/pls/imis/establishment.inspection_detail?id=314234683&id=313641961&id=313641979&id=313640005 &id=125915397)
In our opinion, the cumulative effect of petroleum industry accidents, safety violation citations from federal and state authorities, and the public’s heightened concern for safety and environmental hazards in the petroleum industry represents a significant threat to our Company’s stock price performance. We believe that a report to shareholders on the steps our Company has taken to reduce the risk of accidents will provide transparency and increase investor confidence in our Company.
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What does the Board recommend?
THE BOARD RECOMMENDS THAT YOU VOTE “AGAINST” THIS
PROPOSAL FOR THE FOLLOWING REASONS:
ConocoPhillips is committed to protecting the health and safety of everyone who plays a part in our operations, lives in the communities in which we operate or uses our products. Wherever we operate, we will conduct our business with respect and care for both the local and global environment and systematically manage risks to drive sustainable business growth. We will not be satisfied until we succeed in eliminating all injuries, occupational illnesses, unsafe practices and incidents of environmental harm from our activities. To meet our commitment, we measure, audit and publicly report our health, safety and environmental performance and maintain open dialogue with stakeholder groups and with communities where we operate.
ConocoPhillips provides the information requested by this proposal in periodic updates to its Sustainable Development report and Web site, primarily in the section entitled Safety and Occupational Health (see http://www.conocophillips.com/EN/susdev/safety/commitment/Pages/ index.aspx).The elements included in the Company’s reporting include details of our Health, Safety and Environment Policy, Implementing our Safety Commitment, Asset and Operations Integrity, Offshore Incident Prevention and Response Capabilities, Emergency Response and Crisis Management, and Safety Performance. A summary of the information available on the Company’s Web site is included below. The headings correspond to specific headings and links with more detailed information which are found on the Company’s Web site in the Sustainable Development reporting section.
| • | Health, Safety and Environment Policy—The Company’s Health, Safety and Environment Policy (the “HSE Policy”) states the Company’s commitment to “protecting the health and safety of everybody who plays a part in [its] operations, lives in the communities in which [it] operates or uses [its] products.” The HSE Policy also sets forth the elements of the plan that the Company follows to meet that commitment. The HSE Policy is the foundational document which provides corporate health, safety and environment expectations for each business unit and enforces a variety of functional and discipline-specific standards. |
| • | Implementing our Safety Commitment—This section provides a description of how the Company implements its HSE Policy. First, it describes the Company’s HSE Governance and Management System, which is the primary tool that the Company’s business units use to implement the HSE Policy. As described therein, Company business units maintain a risk matrix in which risks are categorized and classified. Risks are analyzed, areas for potential improvement are identified, and key activities are implemented to reduce risk and further enhance HSE performance. The section goes on to explain the elaborate tracking, investigation, reporting, audit and other features of the Company’s governance and risk management systems. This section further explains how the Company incorporates its health, safety and environment policies into contractor selection and oversight activities and the steps the Company took with its employees and contractors following the Deepwater Horizon incident in the Gulf of Mexico. Finally, a description is provided as to how the Company has developed programs, such as the HSE Excellence process, employee focus groups and safety questionnaires, to avoid accidents and learn from any accidents that do occur. This section also describes the Company’s participation in the Occupational Safety and Health Administration’s Voluntary Protection Program (“VPP”) and that 23 of the Company’s U.S. sites have achieved VPP Star recognition. |
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| • | Asset and Operations Integrity—This section describes the Company’s process safety and pipeline integrity programs, which address the prevention, control and mitigation of unintentional releases from its infrastructure. This section details the in-depth process safety evaluations and mechanical integrity audits the Company completed through 2011 at its U.S. and international refineries, as well as its multi-year internal pipeline inspection and hydrotesting project which was completed in 2010. Process safety performance at ConocoPhillips is tracked to monitor performance strengths and assess any opportunities for improvement across key business areas. This monitoring includes a strong emphasis on process safety auditing to validate and support metric data. ConocoPhillips has adopted additional process safety metrics across key business sectors and key business sectors began collecting and reporting those metrics in 2011. |
| • | Offshore Incident Prevention and Response Capabilities—This section describes the process the Company follows in training its personnel, selecting contractors and planning its drilling operations. It also describes the Company’s approach to well design and explains the well safety features it typically incorporates. The section also describes the Company’s Well Management Standard, which provides a consistent framework and approach to ensure that wells are properly designed, constructed, operated, maintained and abandoned. Also described is the Company’s participation in three joint industry task forces that focus on various aspects of operations in the Gulf of Mexico, and the Company’s participation as one of four founding members with other major oil companies in a plan to build and deploy a rapid response system that will be available to capture and contain oil in the event of a future underwater blowout in the U.S. Gulf of Mexico. The Company has committed to fund up to $250 million of the cost of a system and is providing technical expertise for this Gulf of Mexico response system project. The Company is also one of nine founding members of an international consortium of major oil companies which is designing equipment which could be globally available to cap a well in the event of a future underwater blowout outside the Gulf of Mexico. |
| • | Emergency Response and Crisis Management—This section describes how the Company would mitigate damages if an accident were to occur. It details how the Company conducts oil spill exercises and drills each year for its U.S. operations, and has conducted several major exercises worldwide. |
| • | Safety Performance—This section provides a description of the Company’s safety performance, including statistics for the Company’s total recordable rate and lost workday cases. |
The cumulative effect of the information that the Company provides on its Web site gives its stockholders comprehensive knowledge of its programs, policies and practices, all of which contribute to the Company’s commitment to reducing the risk of accidents.
The Proposal also requests a description of “the Board’s oversight of process safety management, staffing levels, inspection and maintenance of refineries and other equipment.” This proxy statement, in accordance with Item 407(h) of SEC Regulation S-K, describes the role of the Company’s Board of Directors in the oversight of the Company’s risk management programs. Additionally, as discussed above, the Company’s Web site provides a detailed discussion of the Company’s HSE Governance and Management System that further elaborates on the implementation of the Company’s HSE Policy (see http://www.conocophillips.com/EN/susdev/safety/commitment/Pages/GovernanceandManagement-Systems.aspx). As more fully described in these disclosures, the Board oversees health, safety and environmental issues, including those that relate to process safety management, staffing levels, inspection and maintenance of refineries
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and other equipment, through its Public Policy Committee, which provides regular updates to the Audit and Finance Committee and the Board as a whole regarding key health, safety and environmental issues, events and performance. 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 SEC.
In summary, the Company, through its publicly filed reports and Web site, already provides extensive information regarding its commitment to health, safety and the environment, including its practices to mitigate the risk of accidents. This information ranges from a statement of the Company’s commitment generally to detailed information about how risks are identified and managed in various business units. Additionally, as required, the Company already discloses the Board’s role in reducing the risks of accidents and how the Board and management interact to identify and manage risks.
The Company is committed to fully disclosing and addressing the concerns of its stockholders relating to HSE policy and performance, including reducing accident risk, incident prevention and response capability. Based on the foregoing factors, the Board believes that providing an additional report would duplicate information already available and would not provide any meaningful benefits to its stockholders and, accordingly, recommends a vote AGAINST this proposal.
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Stockholder Proposal:
Report on Grassroots Lobbying Expenditures
(Item 6 on the Proxy Card)
What is the Proposal?
Whereas, businesses, like individuals, have a recognized legal right to express opinions to legislators and regulators public policy matters.
It is important that our company’s lobbying positions, as well as processes to influence public policy, are transparent. Public opinion is skeptical of corporate influence on Congress and public policy and questionable lobbying activities may pose risks to our company’s reputation when controversial positions are embraced. Hence, we believe full disclosure of ConocoPhillips’ policies, procedures and oversight mechanisms is warranted.
Resolved, the stockholders of ConocoPhillips request the board authorize the preparation of a report, updated annually, disclosing:
| 1. | Company policies and procedures governing the lobbying of legislators and regulators, including that done on our company’s behalf by trade associations. The disclosure should include both direct and indirect lobbying and grassroots lobbying communications. |
| 2. | A listing of payments (both direct and indirect, including payments to trade associations) used for direct lobbying as well as grassroots lobbying communications, including the amount of the payment and the recipient. |
| 3. | Memberships in and payments to any tax-exempt organization that writes and endorses model legislation. |
| 4. | Description of the decision making process and oversight by the management and Board for |
| a. | direct and indirect lobbying contribution or expenditure; and |
| b. | payment for grassroots lobbying expenditure. |
For purposes of this proposal, a “grassroots lobbying communication” is a communication directed to the general public that (a) refers to specific legislation, (b) reflects a view on the legislation and (c) encourages the recipient of the communication to take action with respect to the legislation.
Both “direct and indirect lobbying” and “grassroots lobbying communications” include efforts at the local, state and federal levels.
The report shall be presented to the Audit Committee of the Board or other relevant oversight committees of the Board and posted on the company’s Web site.
Supporting Statement
As stockholders, we support transparency and accountability on the use of staff time and corporate funds to influence legislation and regulation both directly and indirectly as well as grassroots lobbying initiatives. We believe such disclosure is stockholders’ the best interests. Absent a system of accountability, company assets could be used for policy objectives contrary to a company’s long-term interests posing risks to the company and stockholders.
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ConocoPhillips spent approximately 37.5 million in 2009 and 2010 on direct federal lobbying activities, according to disclosure reports (U.S. Senate Office of Public Records). This figure may not include grassroots lobbying to directly influence legislation by mobilizing public support or opposition. Also, not all states require disclosure of lobbying expenditures to influence legislation or regulation.
Such expenditures and contributions can potentially involve the company in controversies posing reputational risks.
We encourage our Board to require comprehensive disclosure related to direct, indirect and grassroots lobbying.
What does the Board recommend?
THE BOARD RECOMMENDS THAT YOU VOTE “AGAINST” THIS
PROPOSAL FOR THE FOLLOWING REASONS:
ConocoPhillips complies with all disclosure requirements pertaining to political contributions under federal, state and local laws and regulations. We continually provide our stockholders with useful information about our political activities. For example, a description of the company’s Political Policies, Procedures and Giving, which includes our policies on grassroots related activities, is posted on our Web site at www.conocophillips.com. We update information on our Web site regarding political contributions to candidates and to other political entities every six months, itemizing such expenditures.
The Company also discloses political expenditures as well as payments to state and national trade associations that are attributable to lobbying activities in our federal lobbying reports. These reports, filed quarterly with the Office of the Clerk, can be found on the Web site of the U.S. House of Representatives at http://lobbyingdisclosure.house.gov/ and the Web site of the U.S. Senate at http://www.senate.gov-/legislative/Public_Disclosure/LDA_reports.htm.
In the interest of transparency, ConocoPhillips has chosen to report under the tax reporting method, which is the more comprehensive of the two reporting alternatives allowed by federal lobbying disclosure requirements. Our disclosures of the costs that ConocoPhillips incurs for federal, state and grassroots lobbying provide ample public information about the Company’s political contributions. These reports accurately reflect the amounts, inclusive of costs for employee time, which ConocoPhillips spends on these lobbying activities.
Our candidate contributions also are reported regularly to, and overseen by, Company senior management and the Public Policy Committee of the Board. Audits are conducted on a biennial cycle for our corporate political contributions and annually for the Spirit political action committee receipts and disbursements.
The Board believes it has a responsibility to stockholders and employees to be engaged in the political process to protect and promote their shared interests. The Board believes it is in the best interest of stockholders 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 evidenced by our posting the information regularly on the ConocoPhillips Web site. This forthright approach has not gone unnoticed. According to the socially responsible investor community’s own barometer of
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corporate political transparency, the Wharton, Zicklin Center Index of Corporate Political Accountability and Disclosure, ConocoPhillips ranks in the second tier of S&P 100 companies.
Regarding the issue of contributions to trade associations, the Company’s primary purpose in joining groups such as the National Association of Manufacturers, the U.S. Chamber of Commerce, and the American Petroleum Institute is not for political purposes, nor does the Company agree with all positions taken by trade and industry associations on issues. In fact, ConocoPhillips publicly acknowledges that we do take contrary positions from time to time. The greater benefits we receive from trade and industry association memberships are the general business, technical and industry standard-setting expertise that these organizations provide.
ConocoPhillips has adopted and published our Political Policies, Procedures and Giving information on our corporate Web site regarding political contributions to candidates and other political entities. The Company also complies with all laws regarding disclosure of political giving, including publicly available reports filed with the U.S. House of Representatives and U.S. Senate. Therefore, the adoption of this resolution is unnecessary and the Board recommends that you vote AGAINST this proposal.
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Stockholder Proposal:
Greenhouse Gas Reduction Targets
(Item 7 on the Proxy Card)
What is the Proposal?
2012 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.
While the Kyoto Protocol obliges Annex I signatories (industrialized countries) to reduce national GHG emissions below 1990 levels by 2012, its reduction targets may be inadequate to avert the most serious impacts of global warming.
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%. Post-2008 data is not available on the company Web site.
The company states that it has been tracking greenhouse gas emissions across its business units, and reports them to the Carbon Disclosure Project on a company-wide basis. However, there are no reduction goals beyond some being set by some business units in 2010. ConocoPhillips also has withdrawn from the U.S. Climate Action Partnership (USCAP).
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 and operations; and that the Company report (omitting proprietary information and prepared at reasonable cost) to shareholders by September 30, 2012, 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, and there
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appears to be no timeline for setting one. 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.
Your support by voting “Yes” will signal to our company that we should move forward.
What does the Board recommend?
THE BOARD RECOMMENDS THAT YOU VOTE “AGAINST” THIS PROPOSAL FOR THE FOLLOWING REASONS:
ConocoPhillips continues to demonstrate its commitment to addressing climate change by taking action to reduce its greenhouse gas (GHG) emissions, by investing in lower-carbon energy and through active participation in efforts to develop sound government policy for GHG regulation. In support of our commitment, the Company is implementing a corporate-wide action plan that requires business units and major assets to develop and maintain climate change management plans. Each plan includes GHG emission measurements and forecast, identification of key risks and opportunities, and the establishment of business appropriate goals and metrics. The Company will continue to report progress on its plans, emissions data and reductions for our operations, investments, and policy engagement as part of its regular updates to the Sustainable Development report, found on the ConocoPhillips Web site.
ConocoPhillips’ business is broadly divided into Exploration and Production (“Upstream”) and Refining and Marketing (“Downstream”). In 2011, both segments of our business made investments that resulted in GHG reduction.
Exploration and Production:
ConocoPhillips’ Upstream businesses worldwide completed numerous projects to improve energy efficiency, prevent methane loss, and reduce GHG emissions. Examples include:
| • | Use of closed loop gas handling systems for well completion and service |
| • | Plunger lift optimization and controller upgrades |
| • | Compressor optimization |
These Upstream projects are estimated to result in CO2 equivalent emission reduction of approximately 1,000,000 metric tons per year.
Refining and Marketing:
In the Downstream segment, ConocoPhillips’ refineries completed many projects to improve energy efficiency and reduce GHG emissions. These include:
| • | San Francisco Refinery—improved hydrogen production efficiency |
| • | Bayway, NJ Refinery—improved use of process heat |
| • | Whitegate, Ireland Refinery—process heater modifications for greater combustion efficiency |
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These projects and other smaller energy efficiency projects are estimated to reduce CO2 equivalent emissions by approximately 100,000 metric tons per year.
ConocoPhillips is among the leading U.S. producers of cleaner burning, lower-carbon natural gas. Worldwide, we produced about 4.9 billion cubic feet of natural gas per day in 2011. To put this production volume in perspective, if all the natural gas ConocoPhillips produced in 2009 had been used to replace coal for electricity generation, GHG emissions would have been reduced by over 100 million metric tons. In addition to natural gas production, the Company is pursuing several innovative business opportunities that could result in GHG reductions within the Company, within industry or for our customers. These include investments in the areas of biofuels, gasification, methane hydrates, and CO2 capture and storage.
ConocoPhillips recognizes that there are questions about GHG emissions from oil sands production. Industry has successfully reduced the GHG intensity per barrel of oil sands crude produced by 39 percent since 1990. To capture both economic and environmental benefits, the Company continues to work to reduce per-barrel GHG intensity. We are investigating technologies focused on running our facilities more efficiently, using less energy, and reducing greenhouse gas and other air emissions. We are also designing plans for improved heat integration and testing an enhanced oil production technology, both aimed at maximizing fuel efficiency while reducing air emissions associated with steam generation.
We continue to work with trade associations like the American Petroleum Institute (API), with our industry partners, and with government to advocate climate change policy solutions that balance the need to reduce GHG emissions with the need for secure supplies of affordable energy necessary for economic recovery and growth. For the United States we do not support regulatory action under the Clean Air Act or the development of a patchwork of state regulatory programs as an effective and efficient means of addressing GHG emissions. The majority of ConocoPhillips assets are in countries, regions, and states/provinces with GHG regulations in place. These include the United States, the European Union, Australia, Alberta, British Columbia, and California. As such, the Company believes a single, voluntary, global corporate GHG reduction target would not be appropriate.
Because of these on-going Company efforts and the emergence of GHG regulations in key countries of operation, 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 voluntary, quantitative goals for reducing total GHG emissions from the Company’s products and operations and issue a report by September 30, 2012, 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:
Gender Identity Non-Discrimination
(Item 8 on the Proxy Card)
What is the Proposal?
GENDER IDENTITY NON-DISCRIMINATION POLICY
Whereas: ConocoPhillips does not explicitly prohibit discrimination based on gender identity or gender expression in its written employment policy;
According to the Human Rights Campaign, nearly 70% of the Fortune 100 and 43% of the Fortune 500 now prohibit discrimination based on gender identity or expression;
We believe that corporations that prohibit discrimination on the basis of gender identity or expression have a competitive advantage in recruiting and retaining employees from the widest talent pool;
Sixteen states, the District of Columbia, and more than 114 cities and counties have laws prohibiting employment discrimination based on gender identity or expression;
Our company is headquartered in Philadelphia, Pennsylvania where at least 65 major employers include gender identity or expression in their nondiscrimination policies; and
Our company has operations in, and makes sales to institutions in States and Cities that prohibit discrimination on the basis of gender identity or expression.
Resolved: The Shareholders request that ConocoPhillips amend its written equal employment opportunity policy to explicitly prohibit discrimination based on gender identity or expression and substantially implement the policy.
Supporting Statement: Employment discrimination on the basis of gender identity or expression diminishes employee morale and productivity. Because state and local laws are inconsistent with respect to employment discrimination, our company would benefit from a consistent, corporate-wide policy to enhance efforts to prevent discrimination, resolve complaints internally, access employees from the broadest talent pool, and ensure a respectful and supportive atmosphere for all employees. ConocoPhillips will enhance its competitive edge by joining the growing ranks of companies guaranteeing equal opportunity for all employees.
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, based in Houston, Texas with operations around the world, and is 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. The Company’s equal employment policy prohibits discrimination on the basis of race, color, sex, marital status, ancestry, religion, national origin, age, physical or mental disability, veteran status, sexual orientation, genetic information or any other basis
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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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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 2013 Annual Meeting of Stockholders, our Corporate Secretary must receive the proposal at our principal executive offices by November 28, 2012. 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 2012 Annual Meeting is held on schedule, we must receive notice pertaining to the 2013 Annual Meeting no earlier than January 9, 2013 and no later than February 8, 2013. |
| • | 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 above, or via the Internet at www.conocophillips.com under our “Governance” caption.
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, 2011, 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 21, 2012
Management’s Discussion and Analysis is the company’s analysis of its financial performance and of significant trends that may affect future performance. It should be read in conjunction with the financial statements and notes, and supplemental oil and gas disclosures. It contains forward-looking statements including, without limitation, statements relating to the company’s plans, strategies, objectives, expectations and intentions that are made pursuant to the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. The words “anticipate,” “estimate,” “believe,” “budget,” “continue,” “could,” “intend,” “may,” “plan,” “potential,” “predict,” “seek,” “should,” “will,” “would,” “expect,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,” “effort,” “target” and similar expressions identify forward-looking statements. The company does not undertake to update, revise or correct any of the forward-looking information unless required to do so under the federal securities laws. Readers are cautioned that such forward-looking statements should be read in conjunction with the company’s disclosures under the heading: “CAUTIONARY STATEMENT FOR THE PURPOSES OF THE ‘SAFE HARBOR’ PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995,” beginning on page A-35.
The terms “earnings” and “loss” as used in Management’s Discussion and Analysis refer to net income (loss) attributable to ConocoPhillips.
BUSINESS ENVIRONMENT AND EXECUTIVE OVERVIEW
ConocoPhillips is an international, integrated energy company. We are the third-largest integrated energy company in the United States, based on market capitalization. We have approximately 29,800 employees worldwide, and at year-end 2011 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, bitumen, natural gas, liquefied natural gas (LNG) and natural gas liquids 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 past investment in the ordinary shares of OAO LUKOIL, an international, integrated oil and gas company headquartered in Russia. We completed the divestiture of our entire interest in LUKOIL in the first quarter of 2011. |
| • | 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. |
Our earnings depend largely on the profitability of our E&P and R&M segments. Crude oil and natural gas prices, along with refining margins, are the most significant factors affecting our profitability. In recent
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years, the business environment for the energy industry has experienced extreme volatility. As a result, in late 2009, we announced several strategic initiatives designed to improve our financial position and increase returns on capital. We have made significant progress on our three-year strategic plan through portfolio optimization, debt reduction and increased shareholder distributions. During 2011, we announced plans to sell an additional $5–$10 billion of noncore assets over the next two years, bringing the total asset divestiture program target to $15–$20 billion for the years 2010 through 2012. As of year-end 2011, we have generated approximately $10.7 billion from asset dispositions, the proceeds of which were primarily targeted toward share repurchases and debt reduction.
We also completed the sale of our entire interest in LUKOIL in the first quarter of 2011, which generated total proceeds of $9.5 billion in 2010 and 2011. These proceeds were largely used to fund share repurchases. In December 2011, our Board authorized the additional purchase of up to $10 billion of our common stock over the next two years. This increased the share repurchase program from $15 billion to $25 billion. Since the inception of the share repurchase programs, we have repurchased 15 percent of our shares outstanding for a total of $15 billion. During 2011, we also increased the amount of our quarterly dividend rate by 20 percent, paid dividends on our common stock of $3.6 billion for the full year and reduced our debt by 4 percent.
Our total capital program in 2012 is expected to be $15.5 billion, a $1.5 billion increase from $14.0 billion in 2011. We also expect 2012 production to be approximately 1.6 million barrels of oil equivalent per day (BOED), excluding the impact of any additional asset sales.
Consistent with our strategy to focus on value creation for our shareholders, in July 2011, our Board approved pursuing the separation of our refining, marketing and transportation businesses into a stand-alone, publicly traded corporation via a tax-free distribution. The new downstream company, named Phillips 66, will also include most of our Midstream segment, our Chemicals segment, as well as our power generation and certain technology operations included in our Emerging Businesses segment. We believe the separation will enable each company to pursue a more focused strategy, which will enable the management of each company to concentrate their resources on its particular market segments, customers and core businesses. The separation is subject to market conditions, customary regulatory approvals, the receipt of an affirmative Internal Revenue Service private letter ruling and final Board approval, and is expected to be completed in the second quarter of 2012.
Upon completion of the separation, ConocoPhillips will be a large and geographically diverse pure-play exploration and production company. Our strategy of enhancing returns on capital through developing new resources, growing reserves and production per share, continuing the asset sale program and increasing shareholder distributions will not change.
Phillips 66 will be an integrated downstream company, with operations encompassing natural gas gathering and processing, crude oil refining, petroleum products marketing, transportation, power generation and petrochemicals manufacturing and marketing.
We believe the execution of our strategic plan will position the two companies to be successful and competitive in the long term. Other important factors that we must continue to manage well in order to sustain our long-term competitive position include:
| • | 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. |
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During 2011, our worldwide refining capacity utilization rate was 92 percent, compared with 81 percent in 2010. The increase in 2011 primarily resulted from the removal of the Wilhelmshaven Refinery (WRG) from our refining capacities effective January 1, 2011, and lower turnaround activity, partially offset by higher planned maintenance.
There has been heightened public focus on the safety of the oil and gas industry as a result of the 2010 Deepwater Horizon incident in the Gulf of Mexico. Safety and environmental stewardship, including the operating integrity of our assets, remain our highest priorities. In 2010, we formed a non-profit organization, the Marine Well Containment Company LLC (MWCC), with Exxon Mobil Corporation, Chevron Corporation and Royal Dutch Shell plc, to develop a new oil spill containment system and improve industry spill response in the U.S. Gulf of Mexico. To complement this work internationally, in 2011, we and several leading oil and gas companies established the Subsea Well Response Project in Norway, and we participated in the Oil Spill Prevention and Response Advisory Group in the United Kingdom.
| • | Adding to our proved reserve base. We primarily add to our proved reserve base in three ways: |
| ¡ | Successful exploration 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 ended December 31, 2011, our reserve replacement was 102 percent, excluding LUKOIL and the impact of acquisitions, dispositions and expropriations.
Access to additional resources has become increasingly difficult as direct investment is prohibited in some nations, while fiscal and other terms in other countries can make projects uneconomic or unattractive. In addition, political instability, competition from national oil companies, and lack of access to high-potential areas due to environmental or other regulation may negatively impact our ability to increase our reserve base. As such, the timing and level at which we add to our reserve base may, or may not, allow us to replace our production over subsequent years.
| • | Controlling costs and expenses. Since we cannot control the prices of the commodity products we sell, controlling operating and overhead costs, within the context of our commitment to safety and environmental stewardship, is a high priority. We monitor these costs using various methodologies that are reported to senior management monthly, on both an absolute-dollar basis and a per-unit basis. Because managing operating and overhead costs is critical to maintaining competitive positions in our industries, cost control is a component of our variable compensation programs. Operating and overhead costs increased 1 percent in 2011, compared with 2010. |
| • | Selecting the appropriate projects in which to invest our capital dollars. We participate in capital-intensive industries. As a result, we must often invest significant capital dollars to explore for new oil and gas fields, develop newly discovered fields, maintain existing fields, construct pipelines and LNG facilities, or continue to maintain and improve our refinery complexes. We invest in projects that are expected to provide an adequate financial return on invested dollars. However, there are often long lead times from the time we make an investment to the time the investment is operational and begins generating financial returns. |
The capital expenditures and investments portion of our capital program totaled $13.3 billion in 2011, and we anticipate capital expenditures and investments to be approximately $14.8 billion in 2012. The increase reflects our strategic emphasis on delivering value by investing in the most
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profitable opportunities. We expect competitive returns from increased investments in unconventional resource projects, such as our oil sands business in Canada, liquids-rich shale plays in the U.S. Lower 48 and the Australia Pacific LNG (APLNG) joint venture. As our production profile adjusts over time to reflect our increased levels of investment in liquids plays and lower levels in North American conventional natural gas, we expect higher returns in E&P, absent changes in market factors.
| • | Managing our asset portfolio. We continually evaluate our assets to determine whether they fit our strategic plans or should be sold or otherwise disposed. As part of our $15–$20 billion asset divestiture program for 2010–2012, during 2010, we sold our 9.03 percent interest in the Syncrude oil sands mining operation; our 50 percent interest in CFJ Properties, a joint venture which owned and operated Flying J-branded truck and travel plazas; and several E&P properties located in the Lower 48 and western Canada. In 2011, we continued to divest low-return, noncore assets in the Lower 48 and western Canada. We also sold WRG, Seaway Products Pipeline Company, and our equity interests in Colonial Pipeline Company and Seaway Crude Pipeline Company. Additionally, we completed the divestiture of our entire interest in LUKOIL in the first quarter of 2011. |
East Coast refining has been under severe market pressure for several years. As a result, in September 2011, we announced our intention to sell the Trainer Refinery located in Trainer, Pennsylvania. The refinery has been idled and will permanently close by the end of the first quarter of 2012 if a sales transaction is unsuccessful. In addition, in E&P we recently entered into agreements to sell our Vietnam business, as well as certain North Sea assets. These sales are expected to close in the first half of 2012.
| • | Developing and retaining a talented work force. We strive to attract, train, develop and retain individuals with the knowledge and skills to implement our business strategy and who support our values and ethics. Throughout the company, we focus on the continued learning, development and technical training of our employees. Professional new hires participate in structured development programs designed to accelerate their technical and functional skills. |
Other significant factors that can affect our profitability include:
| • | Commodity prices. In 2011, the global economic rate of growth slowed, leading to lower oil demand growth. Oil prices, however, increased in 2011, as supply concerns, including concerns over the loss of Libyan production, outweighed the economic uncertainty in the United States and Europe. U.S. natural gas prices remained under pressure during 2011, as increased production from shale plays outpaced demand growth. As a result, storage inventory levels reached record highs by the end of 2011. We expect these factors will continue to moderate natural gas prices, resulting in limited U.S. LNG imports in the near- to mid-term. |
In recent years, the use of hydraulic fracturing in shale natural gas formations has led to increased industry actual and forecasted natural gas production in the United States. Although providing short- and long-term significant growth opportunities for our company, the increased abundance of natural gas due to development of shale plays could also have adverse financial implications to us, including: an extended period of low natural gas prices; production curtailments on properties that produce primarily natural gas; cancelation or delay of plans to develop Alaska North Slope and Canadian Arctic natural gas fields; and underutilization of LNG regasification facilities and certain natural gas pipelines. Should one or more of these events occur, our revenues would be reduced and additional impairments might be possible.
| • | Impairments. As mentioned above, we participate in capital-intensive industries. At times, our investments become impaired when, for example, our reserve estimates are revised downward, commodity prices or refining margins decline significantly for long periods of time, or a decision to |
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| dispose of an asset leads to a write-down to its fair market value. We may also invest large amounts of money in exploration which, if exploratory drilling proves unsuccessful, could lead to a material impairment of leasehold values. Before-tax impairments in 2011 totaled $1.3 billion and primarily resulted from the impairments of the Trainer Refinery, our equity investment in Naraynmarneftegaz (NMNG) and certain Canadian natural gas properties. Before-tax impairments in 2010 totaled $2.4 billion and primarily related to the $1.5 billion property impairment of WRG and the $0.6 billion impairment of our equity investment in NMNG. |
| • | Effective tax rate. Our operations are located in countries with different tax rates and fiscal structures. Accordingly, even in a stable commodity price and fiscal/regulatory environment, our overall effective tax rate can vary significantly between periods based on the “mix” of pretax earnings within our global operations. |
| • | Fiscal and regulatory environment. Our operations, primarily in E&P, can be affected by changing economic, regulatory and political environments in the various countries in which we operate, including the United States. Civil unrest or strained relationships with governments may impact our operations or investments. These changing environments have generally negatively impacted our results of operations, and further changes to government fiscal take could have a negative impact on future operations. Our production operations in Libya and related oil exports were temporarily suspended in 2011 during Libya’s period of civil unrest. Our assets in Venezuela and Ecuador were expropriated in 2007 and 2009, respectively. In Canada, the Alberta provincial government changed the royalty structure in 2009 to tie a component of the new rate to prevailing prices. Our management carefully considers these events when evaluating projects or determining the level of activity in such countries. |
Segment Analysis
Earnings for the E&P segment are generally closely aligned with industry price levels for crude oil and natural gas. These are commodity products, the prices of which are subject to factors external to our company and over which we have no control. Industry crude oil prices for West Texas Intermediate (WTI) were higher in 2011, compared with 2010, averaging $95.05 per barrel in 2011, an increase of 20 percent. Industry natural gas prices at Henry Hub decreased 8 percent during 2011 to an average price of $4.04 per million British thermal units.
The Midstream segment’s results are most closely linked to natural gas liquids prices. The most important factor affecting the profitability of this segment is the results from our 50 percent equity investment in DCP Midstream. DCP Midstream’s natural gas liquids prices increased 23 percent in 2011.
Refining margins, refinery capacity utilization and cost control primarily drive the R&M segment’s results. Refining margins are subject to movements in the cost of crude oil and other feedstocks and the sales prices for refined products, both of which are subject to market factors over which we have no control. Global refining margins significantly improved during 2011, compared with 2010. The U.S. 3:2:1 crack spread, which is primarily WTI-based, increased 126 percent in 2011, while the N.W. Europe benchmark increased 20 percent. The improvement in domestic refining margins primarily resulted from increased production from shale plays and high inventory levels in the Midcontinent area, causing WTI to trade at a deeper discount relative to waterborne crudes for most of 2011. This discount, however, began to narrow toward the end of 2011. During the periods of large WTI-Brent spreads, refineries capable of processing WTI and crude oils that are WTI-based benefitted from the lower regional feedstock prices. In contrast, East Coast refining, which relies primarily on Brent-based crudes, has been under severe market pressure. Product imports, weakness in motor fuel demand, and costly regulatory requirements are key challenges in this difficult environment.
The LUKOIL Investment segment consisted of our prior investment in the ordinary shares of LUKOIL. We disposed of our remaining interest in LUKOIL in the first quarter of 2011.
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The Chemicals segment consists of our 50 percent interest in CPChem. The chemicals and plastics industry is mainly a commodity-based industry where the margins for key products are based on market factors over which CPChem has little or no control. CPChem is investing in feedstock-advantaged areas in the Middle East with access to large, growing markets, such as Asia.
The Emerging Businesses segment represents our investment in new technologies or businesses outside our normal scope of operations. Activities within this segment are currently focused on power generation and innovation of new technologies, such as those related to conventional and nonconventional hydrocarbon recovery, refining, alternative energy, biofuels and the environment. Some of these technologies have the potential to become important drivers of profitability in future years.
Our key performance indicators are shown in the statistical tables provided at the beginning of the operating segment sections that follow. These include commodity prices, production and refining capacity utilization.
RESULTS OF OPERATIONS
Consolidated Results
A summary of the company’s net income attributable to ConocoPhillips by business segment follows:
| Millions of Dollars | ||||||||||||
| Years Ended December 31 | 2011 | 2010 | 2009 | |||||||||
| E&P |
$ | 8,242 | 9,198 | 3,604 | ||||||||
| Midstream |
458 | 306 | 313 | |||||||||
| R&M |
3,751 | 192 | 37 | |||||||||
| LUKOIL Investment |
239 | 2,503 | 1,219 | |||||||||
| Chemicals |
745 | 498 | 248 | |||||||||
| Emerging Businesses |
(26 | ) | (59 | ) | 3 | |||||||
| Corporate and Other |
(973 | ) | (1,280 | ) | (1,010 | ) | ||||||
| Net income attributable to ConocoPhillips |
$ | 12,436 | 11,358 | 4,414 | ||||||||
2011 vs. 2010
Earnings for ConocoPhillips increased 9 percent in 2011. The improvement was mainly due to:
| • | Higher commodity prices in our E&P segment. Commodity price benefits were somewhat offset by increased production taxes. |
| • | Improved results from our R&M operations, reflecting significantly higher U.S. refining margins. |
| • | Lower impairments. In 2011, impairments totaled $1,004 million after-tax, compared with 2010 impairments of $1,928 million after-tax. |
These items were partially offset by:
| • | Lower gains from asset sales. In 2011, gains from asset dispositions and LUKOIL share sales were $1,637 million after-tax, compared with 2010 gains of $4,583 million after-tax. |
| • | The absence of equity earnings from LUKOIL due to the divestiture of our interest. |
| • | Lower production volumes from our E&P segment. |
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2010 vs. 2009
The improved results in 2010 were primarily the result of:
| • | Higher prices for crude oil, natural gas, natural gas liquids (NGL) and LNG in our E&P segment. Commodity price benefits were somewhat offset by increased production taxes. |
| • | Gains of $4,583 million after-tax from asset dispositions and LUKOIL share sales. |
| • | Improved results from our domestic R&M operations, reflecting higher refining margins. |
These items were partially offset by:
| • | Impairments totaling $1,928 million after-tax. |
| • | Lower production volumes from our E&P segment. |
Income Statement Analysis
2011 vs. 2010
Sales and other operating revenues increased 29 percent in 2011, while purchased crude oil, natural gas and products increased 37 percent. The increases were mainly due to significantly higher prices for petroleum products, crude oil and NGLs.
Equity in earnings of affiliates increased 30 percent in 2011. The increase primarily resulted from:
| • | Earnings from Qatar Liquefied Gas Company Limited (3) (QG3), primarily due to sales of LNG following production startup, which occurred in October 2010. |
| • | Improved earnings from WRB Refining LP, primarily due to higher refining margins. |
| • | Improved earnings from CPChem, mainly due to higher margins in the olefins and polyolefins business line. |
| • | Lower impairments from NMNG. In 2011, equity earnings included a $395 million impairment of our equity investment, and 2010 equity earnings included a $645 million impairment. |
| • | Improved earnings from FCCL Partnership, mostly due to higher commodity prices and volumes. |
| • | Improved earnings from DCP Midstream, LLC, mainly as a result of higher NGL prices. |
These increases were partially offset by the absence of equity earnings from LUKOIL due to the divestiture of our interest.
Gain on dispositions decreased 65 percent in 2011. Gains in 2011 primarily resulted from the disposition of Seaway Products Pipeline Company, our interests in Seaway Crude Pipeline Company and Colonial Pipeline Company, certain E&P assets located in the Lower 48 and Canada, and the remaining divestiture of our LUKOIL shares. These gains were partially offset by the loss on dilution of our equity interest in APLNG from 50 percent to 42.5 percent and the loss on disposition of WRG. Gains in 2010 primarily reflected the $2,878 million gain realized from the sale of our interest in Syncrude, the $1,749 million gain on the divestiture of our LUKOIL shares, gains on the disposition of certain E&P assets located in the Lower 48 and Canada, and the gain on sale of our 50 percent interest in CFJ Properties. For additional information, see Note 5—Assets Held for Sale or Sold and Note 6—Investments, Loans and Long-Term Receivables, in the Notes to Consolidated Financial Statements.
Depreciation, depletion and amortization (DD&A) decreased 12 percent in 2011. The decrease was mostly associated with our E&P segment, reflecting lower production volumes and lower unit-of-production rates related to reserve bookings in 2011.
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Impairments decreased 56 percent in 2011, primarily due to the $1,514 million impairment of WRG in 2010. This decrease was partially offset by the impairment of the Trainer Refinery and various North American E&P natural gas properties in 2011. For additional information, see Note 10—Impairments, in the Notes to Consolidated Financial Statements.
Taxes other than income taxes increased 9 percent in 2011, primarily due to higher production taxes as a result of higher crude oil prices and higher excise taxes on petroleum product sales.
Interest and debt expense decreased 18 percent in 2011, primarily due to lower debt levels.
See Note 20—Income Taxes, in the Notes to Consolidated Financial Statements, for information regarding our provision for income taxes and effective tax rate.
2010 vs. 2009
Sales and other operating revenues increased 27 percent in 2010, while purchased crude oil, natural gas and products increased 33 percent. These increases were primarily due to higher prices for petroleum products, crude oil, natural gas, natural gas liquids and LNG.
Equity in earnings of affiliates increased 24 percent in 2010. The increase primarily resulted from:
| • | Improved earnings from CPChem primarily due to higher margins in the olefins and polyolefins business line. |
| • | Improved earnings from FCCL Partnership due to higher commodity prices and volumes. |
| • | Improved earnings from Merey Sweeny, L.P. (MSLP) as a result of improved margins and volumes. |
These increases were partially offset by a $645 million impairment of our equity investment in NMNG.
Gain on dispositions increased $5,643 million in 2010. The increase was primarily due to the $2,878 million gain realized from the Syncrude sale, the $1,749 million gain on the divestiture of our LUKOIL shares, gains on the disposition of certain E&P assets located in the Lower 48 and Canada, and the gain on sale of our 50 percent interest in CFJ Properties.
Impairments increased $1,245 million in 2010, primarily as a result of the 2010 WRG impairment.
Taxes other than income taxes increased 8 percent during 2010, primarily due to higher production taxes as a result of higher crude oil prices and higher excise taxes on petroleum product sales.
Interest and debt expense decreased 8 percent during 2010, primarily due to lower debt levels.
See Note 20—Income Taxes, in the Notes to Consolidated Financial Statements, for information regarding our provision for income taxes and effective tax rate.
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Segment Results
E&P
| 2011 | 2010 | 2009 | ||||||||||
| Millions of Dollars | ||||||||||||
| Net Income (Loss) Attributable to ConocoPhillips |
||||||||||||
| Alaska |
$ | 1,983 | 1,735 | 1,540 | ||||||||
| Lower 48 |
1,271 | 1,033 | (37 | ) | ||||||||
| United States |
3,254 | 2,768 | 1,503 | |||||||||
| International |
4,988 | 6,430 | 2,101 | |||||||||
| $ | 8,242 | 9,198 | 3,604 | |||||||||
| Dollars Per Unit | ||||||||||||
| Average Sales Prices |
||||||||||||
| Crude oil and natural gas liquids (per barrel) |
||||||||||||
| United States |
$ | 91.77 | 69.73 | 53.21 | ||||||||
| International |
102.68 | 74.95 | 57.40 | |||||||||
| Total consolidated operations |
97.12 | 72.63 | 55.47 | |||||||||
| Equity affiliates |
98.60 | 74.81 | 58.23 | |||||||||
| Total E&P |
97.22 | 72.77 | 55.63 | |||||||||
| Bitumen (per barrel) |
||||||||||||
| International |
55.16 | 51.10 | 39.67 | |||||||||
| Equity affiliates |
63.93 | 53.43 | 45.69 | |||||||||
| Total E&P |
62.56 | 53.06 | 44.84 | |||||||||
| Natural gas (per thousand cubic feet) |
||||||||||||
| United States |
4.01 | 4.27 | 3.50 | |||||||||
| International |
6.73 | 5.60 | 5.06 | |||||||||
| Total consolidated operations |
5.64 | 5.07 | 4.40 | |||||||||
| Equity affiliates |
2.89 | 2.79 | 2.35 | |||||||||
| Total E&P |
5.34 | 4.98 | 4.37 | |||||||||
| Average Production Costs Per Barrel of Oil Equivalent |
||||||||||||
| United States |
$ | 9.70 | 8.30 | 7.73 | ||||||||
| International |
9.70 | 7.96 | 7.72 | |||||||||
| Total consolidated operations |
9.70 | 8.10 | 7.73 | |||||||||
| Equity affiliates |
7.85 | 8.11 | 7.68 | |||||||||
| Total E&P |
9.48 | 8.10 | 7.72 | |||||||||
| Millions of Dollars | ||||||||||||
| Worldwide Exploration Expenses |
||||||||||||
| General and administrative; geological and geophysical; and lease rentals |
$ | 596 | 678 | 576 | ||||||||
| Leasehold impairment |
161 | 241 | 247 | |||||||||
| Dry holes |
309 | 236 | 359 | |||||||||
| $ | 1,066 | 1,155 | 1,182 | |||||||||
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| 2011 | 2010 | 2009 | ||||||||||
| Thousands of Barrels Daily | ||||||||||||
| Operating Statistics |
||||||||||||
| Crude oil and natural gas liquids produced |
||||||||||||
| Alaska |
215 | 230 | 252 | |||||||||
| Lower 48 |
168 | 160 | 166 | |||||||||
| United States |
383 | 390 | 418 | |||||||||
| Canada |
38 | 38 | 40 | |||||||||
| Europe |
175 | 211 | 241 | |||||||||
| Asia Pacific/Middle East |
111 | 140 | 132 | |||||||||
| Africa |
40 | 79 | 78 | |||||||||
| Other areas |
— | — | 4 | |||||||||
| Total consolidated operations |
747 | 858 | 913 | |||||||||
| Equity affiliates |
||||||||||||
| Russia |
29 | 52 | 55 | |||||||||
| Asia Pacific/Middle East |
23 | 3 | — | |||||||||
| 799 | 913 | 968 | ||||||||||
| Synthetic oil produced |
||||||||||||
| Consolidated operations—Canada |
— | 12 | 23 | |||||||||
| Bitumen produced |
||||||||||||
| Consolidated operations—Canada |
10 | 10 | 7 | |||||||||
| Equity affiliates—Canada |
57 | 49 | 43 | |||||||||
| 67 | 59 | 50 | ||||||||||
| Millions of Cubic Feet Daily | ||||||||||||
| Natural gas produced* |
||||||||||||
| Alaska |
61 | 82 | 94 | |||||||||
| Lower 48 |
1,556 | 1,695 | 1,927 | |||||||||
| United States |
1,617 | 1,777 | 2,021 | |||||||||
| Canada |
928 | 984 | 1,062 | |||||||||
| Europe |
626 | 815 | 876 | |||||||||
| Asia Pacific/Middle East |
695 | 712 | 713 | |||||||||
| Africa |
158 | 149 | 121 | |||||||||
| Total consolidated operations |
4,024 | 4,437 | 4,793 | |||||||||
| Equity affiliates |
||||||||||||
| Asia Pacific/Middle East |
492 | 169 | 84 | |||||||||
| 4,516 | 4,606 | 4,877 | ||||||||||
| * | Represents quantities available for sale. Excludes gas equivalent of natural gas liquids included above. |
The E&P segment primarily explores for, produces, transports and markets crude oil, bitumen, natural gas, LNG and natural gas liquids on a worldwide basis. At December 31, 2011, our E&P operations were producing in the United States, Norway, the United Kingdom, Canada, Australia, offshore Timor-Leste in the Timor Sea, Indonesia, China, Vietnam, Libya, Nigeria, Algeria, Qatar and Russia. Total E&P production averaged 1,619,000 BOED in 2011, compared with 1,752,000 BOED in 2010.
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2011 vs. 2010
Earnings from our E&P segment were $8,242 million in 2011, a 10 percent decrease compared with earnings of $9,198 million in 2010. See the “Business Environment and Executive Overview” section for additional information on industry crude oil and natural gas prices.
U.S. E&P
U.S. E&P earnings were $3,254 million in 2011, an 18 percent increase compared with earnings of $2,768 million in 2010. The increase primarily resulted from higher crude oil and NGL prices, and, to a lesser extent, lower DD&A. These increases were partially offset by higher production taxes, mainly in Alaska, lower sales volumes, higher operating expenses and lower gains from asset sales in the Lower 48.
U.S. E&P production averaged 653,000 BOED in 2011, a decrease of 5 percent from 686,000 BOED in 2010. The decrease was primarily due to field decline and asset dispositions, which was partially offset by new production, mostly from the Lower 48.
International E&P
International E&P earnings were $4,988 million in 2011, a 22 percent decrease compared with earnings of $6,430 million in 2010. Earnings in 2011 included $316 million in additional income tax expense, as a result of legislation enacted in the United Kingdom in July 2011. This additional tax expense consisted of $106 million for the revaluation of deferred tax liabilities and $210 million to reflect the higher tax rates from the effective date of the legislation, March 24, 2011, through December 31, 2011. In 2011, earnings also included impairments of our investment in NMNG and various natural gas properties located in Canada, in addition to a $279 million loss on the dilution of our equity interest in APLNG from 50 percent to 42.5 percent. Earnings in 2010 included gains from the sale of Syncrude and certain Canadian properties and an impairment of NMNG. Excluding the impact from these items, earnings increased in 2011, primarily due to higher prices, a full year of LNG sales from QG3 and lower DD&A. These increases to earnings were partially offset by lower volumes and higher taxes.
International E&P production averaged 966,000 BOED in 2011, a decrease of 9 percent from 1,066,000 BOED in 2010. The decrease primarily resulted from suspended operations in Libya and in Bohai Bay, China, asset dispositions and unplanned downtime. Normal field decline was largely offset by new production.
2010 vs. 2009
Earnings from our E&P segment were $9,198 million in 2010, compared with earnings of $3,604 million in 2009.
U.S. E&P
U.S. E&P earnings increased 84 percent in 2010, from $1,503 million in 2009 to $2,768 million in 2010. The increase was primarily the result of higher prices for crude oil, natural gas and NGLs. Earnings also benefitted from higher gains from asset sales in our Lower 48 portfolio and lower DD&A. These increases were partially offset by lower crude oil and natural gas volumes, higher production taxes, primarily in Alaska, and an unfavorable tax ruling.
U.S. E&P production averaged 686,000 BOED in 2010, a decrease of 9 percent from 755,000 BOED in 2009. The decrease was primarily due to field decline and unplanned downtime, which was somewhat offset by new production.
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International E&P
International E&P earnings were $6,430 million in 2010, compared with $2,101 million in 2009. The increase in 2010 was mostly due to gains from the sale of Syncrude and other assets and higher crude oil, natural gas and LNG prices. These increases were partially offset by the NMNG impairment, lower synthetic oil and natural gas volumes, higher petroleum taxes as a result of higher prices and an $81 million after-tax charge to exploration expenses for project costs resulting from our decision to end participation in the Shah Gas Field Project in Abu Dhabi.
International E&P production averaged 1,066,000 BOED in 2010, a decrease of 3 percent from 1,099,000 BOED in 2009. The decrease was largely due to field decline, the impact of higher prices on production sharing arrangements and the sale of Syncrude. These decreases were partially offset by production from major projects, primarily in China, Canada, Qatar and Australia.
Midstream
| 2011 | 2010 | 2009 | ||||||||||
| Millions of Dollars | ||||||||||||
| Net Income Attributable to ConocoPhillips* |
$ | 458 | 306 | 313 | ||||||||
| *Includes DCP Midstream-related earnings: | $ | 274 | 191 | 183 | ||||||||
| Dollars Per Barrel | ||||||||||||
| Average Sales Prices |
||||||||||||
| U.S. natural gas liquids* |
||||||||||||
| Consolidated |
$ | 57.79 | 45.42 | 33.63 | ||||||||
| Equity affiliates |
50.64 | 41.28 | 29.80 | |||||||||
| * 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* |
200 | 193 | 187 | |||||||||
| Natural gas liquids fractionated** |
144 | 152 | 166 | |||||||||
| * | Includes our share of equity affiliates. |
| ** | Excludes DCP Midstream. |
The Midstream segment purchases raw natural gas from producers and gathers natural gas through an extensive network of pipeline gathering systems. The natural gas is then processed to extract NGLs from the raw gas stream. The remaining “residue” gas is marketed to electrical utilities, industrial users, and gas marketing companies. Most of the NGLs are fractionated—separated into individual components like ethane, butane and propane—and marketed as chemical feedstock, fuel or refinery 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 NGL fractionation, trading and marketing businesses, primarily in the United States and Trinidad.
2011 vs. 2010
Earnings from the Midstream segment increased 50 percent in 2011, reflecting higher equity earnings from DCP Midstream and improved results from our other Midstream operations. Both DCP Midstream and our equity affiliate in Trinidad benefited from significantly higher NGL prices, which generally tracked the improved crude oil price environment in 2011. Also benefiting 2011 earnings were higher fees received for NGL fractionation services, reflecting favorably renegotiated contracts. These items were partially offset by higher costs at DCP Midstream, primarily due to higher maintenance and repair costs and increased DD&A.
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2010 vs. 2009
Midstream earnings decreased 2 percent in 2010. Higher NGL prices and, to a lesser extent, improved volumes from our equity affiliate in Trinidad, were more than offset by the absence of the 2009 recognition of an $88 million after-tax benefit, which resulted from a DCP Midstream subsidiary converting subordinated units to common units. In addition, higher operating expenses contributed to the decrease in earnings.
R&M
| 2011 | 2010 | 2009 | ||||||||||
| Millions of Dollars | ||||||||||||
| Net Income (Loss) Attributable to ConocoPhillips |
||||||||||||
| United States |
$ | 3,595 | 1,022 | (192 | ) | |||||||
| International |
156 | (830 | ) | 229 | ||||||||
| $ | 3,751 | 192 | 37 | |||||||||
| Dollars Per Gallon | ||||||||||||
| U.S. Average Wholesale Prices* |
||||||||||||
| Gasoline |
$ | 2.94 | 2.24 | 1.84 | ||||||||
| Distillates |
3.12 | 2.30 | 1.76 | |||||||||
| * Excludes excise taxes. |
||||||||||||
| Thousands of Barrels Daily | ||||||||||||
| Operating Statistics |
||||||||||||
| Refining operations* |
||||||||||||
| United States |
||||||||||||
| Crude oil capacity** |
1,939 | 1,986 | 1,986 | |||||||||
| Crude oil processed |
1,757 | 1,782 | 1,731 | |||||||||
| Capacity utilization (percent) |
91 | % | 90 | 87 | ||||||||
| Refinery production |
1,932 | 1,958 | 1,891 | |||||||||
| International |
||||||||||||
| Crude oil capacity** |
426 | 671 | 671 | |||||||||
| Crude oil processed |
409 | 374 | 495 | |||||||||
| Capacity utilization (percent) |
96 | % | 56 | 74 | ||||||||
| Refinery production |
419 | 383 | 504 | |||||||||
| Worldwide |
||||||||||||
| Crude oil capacity** |
2,365 | 2,657 | 2,657 | |||||||||
| Crude oil processed |
2,166 | 2,156 | 2,226 | |||||||||
| Capacity utilization (percent) |
92 | % | 81 | 84 | ||||||||
| Refinery production |
2,351 | 2,341 | 2,395 | |||||||||
| Petroleum products sales volumes |
||||||||||||
| United States |
||||||||||||
| Gasoline |
1,129 | 1,120 | 1,130 | |||||||||
| Distillates |
884 | 873 | 858 | |||||||||
| Other products |
401 | 400 | 367 | |||||||||
| 2,414 | 2,393 | 2,355 | ||||||||||
| International |
714 | 647 | 619 | |||||||||
| 3,128 | 3,040 | 2,974 | ||||||||||
| * | Includes our share of equity affiliates. |
| ** | Weighted-average crude oil capacity for the periods. |
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Our R&M segment refines crude oil and other feedstocks into petroleum products (such as gasoline, distillates and aviation fuels); buys, sells and transports crude oil; and buys, transports, distributes and markets petroleum products. R&M has operations mainly in the United States, Europe and Asia.
2011 vs. 2010
R&M reported earnings of $3,751 million in 2011, compared with earnings of $192 million in 2010. See the “Business Environment and Executive Overview” section for additional information on industry refining margins.
U.S. R&M
Earnings from U.S. R&M were $3,595 million in 2011, compared with earnings of $1,022 million in 2010. The increase in earnings primarily resulted from significantly higher refining margins and gains from asset sales. In 2011, gains from asset sales of $1,577 million after-tax mainly resulted from the sales of Seaway Products Pipeline Company and our equity investments in Seaway Crude Pipeline Company and Colonial Pipeline Company, while 2010 included the $113 million after-tax gain on sale of our 50 percent interest in CFJ Properties. These increases were partially offset by the $303 million after-tax impairment and warehouse inventory write-down associated with our Trainer Refinery in 2011.
Our U.S. refining crude oil capacity utilization rate was 91 percent in 2011, compared with 90 percent in 2010. The increase mainly resulted from lower turnaround activity, partially offset by higher planned and unplanned downtime.
International R&M
International R&M reported earnings of $156 million in 2011, compared with a loss of $830 million in 2010. The increase in earnings was mostly due to the absence of the 2010 WRG impairment, in addition to higher refining volumes and foreign currency gains in 2011. These increases were partially offset by lower refining margins and the $86 million after-tax loss on sale of WRG and related warehouse inventory write-downs in 2011.
Our international refining crude oil capacity utilization rate was 96 percent in 2011, compared with 56 percent in 2010. The increase primarily resulted from the removal of WRG from our refining capacities effective January 1, 2011, and lower turnaround activity.
2010 vs. 2009
R&M reported earnings of $192 million in 2010, compared with earnings of $37 million in 2009.
U.S. R&M
Earnings from U.S. R&M were $1,022 million in 2010, compared with a loss of $192 million in 2009. The increase in 2010 primarily resulted from significantly higher refining margins and the gain on sale of CFJ. Higher refining and marketing volumes also contributed to the improvement in earnings.
Our U.S. refining crude oil capacity utilization rate was 90 percent in 2010, compared with 87 percent in 2009. The increase in 2010 was largely due to lower turnaround activity, lower run reductions due to market conditions, and less unplanned downtime.
International R&M
International R&M reported a loss of $830 million in 2010, compared with earnings of $229 million in 2009. The loss in 2010 mainly resulted from the WRG impairment and a $29 million after-tax impairment resulting from our decision to end participation in the Yanbu Refinery Project. Excluding these impairments, earnings were improved due to higher refining margins, partially offset by foreign currency losses.
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Our international refining crude oil capacity utilization rate was 56 percent in 2010, compared with 74 percent in 2009. The 2010 rate primarily reflected run reductions at WRG in response to market conditions.
LUKOIL Investment
| Millions of Dollars | ||||||||||||
| 2011 | 2010 | 2009 | ||||||||||
| Net Income Attributable to ConocoPhillips |
$ | 239 | 2,503 | 1,219 | ||||||||
| Operating Statistics |
||||||||||||
| Crude oil production (thousands of barrels daily) |
— | 284 | 388 | |||||||||
| Natural gas production (millions of cubic feet daily) |
— | 254 | 295 | |||||||||
| Refinery crude oil processed (thousands of barrels daily) |
— | 189 | 240 | |||||||||
This segment represents our former investment in the ordinary shares of OAO LUKOIL, an international, integrated oil and gas company headquartered in Russia. We sold our remaining interest in LUKOIL in the first quarter of 2011.
2011 vs. 2010
Earnings in 2011 primarily represented the realized gain on remaining share sales. Earnings in 2010 primarily reflected earnings from the equity investment in LUKOIL we held at the time, in addition to gains on the partial sale of our LUKOIL investment.
2010 vs. 2009
LUKOIL segment earnings increased $1,284 million in 2010, which primarily resulted from the $1,251 million after-tax gain on our LUKOIL shares sold during 2010.
Chemicals
| Millions of Dollars | ||||||||||||
| 2011 | 2010 | 2009 | ||||||||||
| Net Income Attributable to ConocoPhillips |
$ | 745 | 498 | 248 | ||||||||
The Chemicals segment consists of our 50 percent interest in CPChem, which we account for under the equity method. CPChem uses natural gas liquids and other feedstocks to produce petrochemicals. These products are then marketed and sold, or used as feedstocks, to produce plastics and commodity chemicals.
2011 vs. 2010
Earnings from the Chemicals segment increased 50 percent in 2011, primarily due to higher margins, volumes and equity earnings in the olefins and polyolefins business line. The specialties, aromatics and styrenics business line also contributed to the increase in earnings due to higher margins.
2010 vs. 2009
Earnings from the Chemicals segment increased $250 million in 2010, primarily due to substantially higher margins in the olefins and polyolefins business line and, to a lesser extent, improved margins from the specialties, aromatics and styrenics business line. Higher operating costs partially offset these increases.
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Emerging Businesses
| Millions of Dollars | ||||||||||||
| 2011 | 2010 | 2009 | ||||||||||
| Net Income (Loss) Attributable to ConocoPhillips |
||||||||||||
| Power |
$ | 115 | 49 | 105 | ||||||||
| Other |
(141 | ) | (108 | ) | (102 | ) | ||||||
| $ | (26 | ) | (59 | ) | 3 | |||||||
The Emerging Businesses segment represents our investment in new technologies or businesses outside our normal scope of operations. Activities within this segment are currently focused on power generation and innovation of new technologies, such as those related to conventional and nonconventional hydrocarbon recovery, refining, alternative energy, biofuels, and the environment.
2011 vs. 2010
The Emerging Businesses segment reported a loss of $26 million in 2011, compared with a loss of $59 million in 2010. The increase in “Power” earnings was primarily due to the absence of 2010 impairment charges related to a U.S. cogeneration plant, which was sold in December 2010, combined with higher international power generation results. Higher technology development expenses contributed to the increase in “Other” losses in 2011.
2010 vs. 2009
The Emerging Businesses segment reported a loss of $59 million in 2010, compared with earnings of $3 million in 2009. The decrease in “Power” earnings was mainly due to higher operating costs and lower margins in international power generation, in addition to the impairment charges and loss on sale of the U.S. cogeneration plant. Higher technology development expenses contributed to the increase in “Other” losses in 2010.
Corporate and Other
| Millions of Dollars | ||||||||||||
| 2011 | 2010 | 2009 | ||||||||||
| Net Loss Attributable to ConocoPhillips |
||||||||||||
| Net interest |
$ | (667 | ) | (965 | ) | (851 | ) | |||||
| Corporate general and administrative expenses |
(199 | ) | (209 | ) | (108 | ) | ||||||
| Separation costs |
(25 | ) | — | — | ||||||||
| Other |
(82 | ) | (106 | ) | (51 | ) | ||||||
| $ | (973 | ) | (1,280 | ) | (1,010 | ) | ||||||
2011 vs. 2010
Net interest consists of interest and financing expense, net of interest income and capitalized interest, as well as premiums incurred on the early retirement of debt. Net interest decreased 31 percent in 2011, mostly due to lower interest expense, which resulted from lower debt levels; the absence of a $114 million after-tax premium on early debt retirement, which occurred in 2010; and slightly higher interest income.
Separation costs consist of expenses incurred for the planned separation of our downstream businesses into a stand-alone, publicly traded company, Phillips 66. Expenses incurred in 2011 primarily included legal, accounting and information systems costs.
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The category “Other” includes certain foreign currency transaction gains and losses, environmental costs associated with sites no longer in operation, and other costs not directly associated with an operating segment. Changes in the “Other” category primarily resulted from foreign currency transaction gains and lower environmental costs, partially offset by a $20 million after-tax property impairment.
2010 vs. 2009
Net interest increased 13 percent in 2010, mostly due to the $114 million after-tax premium on early debt retirement and a lower effective tax rate. These increases were partially offset by lower interest expense due to lower debt levels.
Corporate general and administrative expenses increased $101 million in 2010, primarily as a result of costs related to compensation and benefit plans.
Changes in the “Other” category primarily reflected foreign currency transaction losses.
CAPITAL RESOURCES AND LIQUIDITY
Financial Indicators
| Millions of Dollars Except as Indicated |
||||||||||||
| 2011 | 2010 | 2009 | ||||||||||
| Net cash provided by operating activities |
$ | 19,646 | 17,045 | 12,479 | ||||||||
| Short-term debt |
1,013 | 936 | 1,728 | |||||||||
| Total debt |
22,623 | 23,592 | 28,653 | |||||||||
| Total equity |
65,734 | 69,109 | 62,613 | |||||||||
| Percent of total debt to capital* |
26 | % | 25 | 31 | ||||||||
| Percent of floating-rate debt to total debt** |
10 | % | 10 | 9 | ||||||||
| * | Capital includes total debt and total equity. |
| ** | Includes effect of interest rate swaps. |
To meet our short- and long-term liquidity requirements, we look to a variety of funding sources. Cash generated from operating activities is the primary source of funding. In addition, during 2011, we received $4,820 million in proceeds from asset sales. During 2011, the primary uses of our available cash were $13,266 million to support our ongoing capital expenditures and investments program; $11,123 million to repurchase common stock; $3,632 million to pay dividends on our common stock; and $961 million to repay debt. During 2011, cash and cash equivalents decreased by $3,674 million to $5,780 million.
In addition to cash flows from operating activities and proceeds from asset sales, we rely on our commercial paper and credit facility programs and our shelf registration statement to support our short- and long-term liquidity requirements. We believe current cash and short-term investment balances and cash generated by operations, together with access to external sources of funds as described below in the “Significant Sources of Capital” section, will be sufficient to meet our funding requirements in the near and long term, including our capital spending program, dividend payments, required debt payments and the funding requirements to FCCL.
Significant Sources of Capital
Operating Activities
During 2011, cash of $19,646 million was provided by operating activities, a 15 percent increase from cash from operations of $17,045 million in 2010. The increase was primarily due to higher commodity prices in our E&P segment and higher U.S. refining margins in our R&M segment.
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During 2010, cash flow from operations increased $4,566 million, compared with 2009. The increase was primarily due to significantly higher crude oil prices in our E&P segment and higher refining margins in our R&M segment.
While the stability of our cash flows from operating activities benefits from geographic diversity, our short- and long-term operating cash flows are highly dependent upon prices for crude oil, bitumen, natural gas, LNG and natural gas liquids, as well as refining and marketing margins. Crude oil prices increased in 2009, 2010 and 2011, although natural gas prices remained weak. Global refining margins were under pressure during 2009 and 2010. Domestic refining margins significantly improved during the first three quarters of 2011, followed by a sharp decline in the fourth quarter of 2011. Prices and margins in our industry are typically volatile, and are driven by market conditions over which we have no control. Absent other mitigating factors, as these prices and margins fluctuate, we would expect a corresponding change in our operating cash flows.
The level of our production volumes of crude oil, bitumen, natural gas and natural gas liquids also impacts our cash flows. These production levels are impacted by such factors as acquisitions and dispositions of fields, field production decline rates, new technologies, operating efficiency, weather conditions, the addition of proved reserves through exploratory success and their timely and cost-effective development. While we actively manage these factors, production levels can cause variability in cash flows, although historically this variability has not been as significant as that caused by commodity prices.
Our E&P production for 2011 averaged 1.62 million BOED. Future production is subject to numerous uncertainties, including, among others, the volatile crude oil and natural gas price environment, which may impact project investment decisions; the effects of price changes on production sharing and variable-royalty contracts; timing of project startups and major turnarounds; and weather-related disruptions. Our production in 2012, excluding the impact of any additional dispositions, is expected to be approximately 1.6 million BOED. We continue to evaluate various properties as potential candidates for our disposition program. The makeup and timing of our disposition program will also impact 2012 and future years’ production levels.
To maintain or grow our production volumes, we must continue to add to our proved reserve base. Our total reserve replacement in 2011 was 112 percent, including 117 percent from consolidated operations. Excluding the impact of acquisitions and dispositions, the reserve replacement was 120 percent of 2011 production. Over the five-year period ended December 31, 2011, our reserve replacement was 30 percent (including 64 percent from consolidated operations) reflecting the disposition of our interest in LUKOIL, the expropriation of our assets in Venezuela and the impact of our asset disposition program. Excluding these items and acquisitions, our five-year reserve replacement was 102 percent. The total reserve replacement amount above is based on the sum of our net additions (revisions, improved recovery, purchases, extensions and discoveries, and sales) divided by our production, as shown in our reserve table disclosures. For additional information about our proved reserves, including both developed and undeveloped reserves, see the “Oil and Gas Operations” section of this report.
We are developing and pursuing projects we anticipate will allow us to add to our reserve base. However, access to additional resources has become increasingly difficult as direct investment is prohibited in some nations, while fiscal and other terms in other countries can make projects uneconomic or unattractive. In addition, political instability, competition from national oil companies, and lack of access to high-potential areas due to environmental or other regulation may negatively impact our ability to increase our reserve base. As such, the timing and level at which we add to our reserve base may, or may not, allow us to replace our production over subsequent years.
As discussed in the “Critical Accounting Estimates” section, engineering estimates of proved reserves are imprecise; therefore, each year reserves may be revised upward or downward due to the impact of changes
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in commodity prices or as more technical data becomes available on reservoirs. In 2011, 2010 and 2009, revisions increased reserves. It is not possible to reliably predict how revisions will impact reserve quantities in the future.
In our R&M segment, the level and quality of output from our refineries impacts our cash flows. The output at our refineries is impacted by such factors as operating efficiency, maintenance turnarounds, market conditions, feedstock availability and weather conditions. We actively manage the operations of our refineries, and typically, any variability in their operations has not been as significant to cash flows as that caused by refining margins.
Asset Sales
Proceeds from asset sales in 2011 were $4.8 billion, compared with $15.4 billion in 2010. The 2011 proceeds from asset sales included $2.0 billion from the sale of our ownership interests in Colonial Pipeline Company and Seaway Crude Pipeline Company and $1.2 billion from the sale of our remaining interest in LUKOIL. Other asset sales primarily included mature North American natural gas assets and a products pipeline. We plan to raise an additional $5 billion to $10 billion from asset sales in 2012.
Commercial Paper and Credit Facilities
In August 2011, we increased our revolving credit facilities from $7.85 billion to $8.0 billion by replacing our $7.35 billion revolving credit facility with a $7.5 billion facility expiring in August 2016. The terms of the new revolving credit facility are similar to the terms of the replaced facility. We also have 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 QG3 Project. At December 31, 2011 and 2010, we had no direct borrowings under the revolving credit facilities, but $40 million in letters of credit had been issued at both periods. In addition, under the two ConocoPhillips commercial paper programs, $1,128 million of commercial paper was outstanding at December 31, 2011, compared with $1,182 million at December 31, 2010. Since we had $1,128 million of commercial paper outstanding and had issued $40 million of letters of credit, we had access to $6.8 billion in borrowing capacity under our revolving credit facilities at December 31, 2011.
Our senior long-term debt is rated “A1” by Moody’s Investors Service and “A” by both Standard and Poor’s Rating Service and by Fitch. We do not have any ratings triggers on any of our corporate debt that would cause an automatic default, and thereby impact our access to liquidity, in the event of a downgrade of our credit rating. If our credit rating were to deteriorate to a level prohibiting us from accessing the commercial paper market, we would still be able to access funds under our $7.5 billion and $500 million revolving credit facilities.
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Shelf Registration
We have a universal shelf registration statement on file with the SEC under which we, as a well-known seasoned issuer, have the ability to issue and sell an indeterminate amount of various types of debt and equity securities.
Off-Balance Sheet Arrangements
As part of our normal ongoing business operations and consistent with normal industry practice, we enter into numerous agreements with other parties to pursue business opportunities, which share costs and apportion risks among the parties as governed by the agreements.
We own a 30 percent interest in QG3, an integrated project to produce and liquefy natural gas from Qatar’s North Field. The other participants in the project are affiliates of Qatar Petroleum (68.5 percent) and Mitsui & Co., Ltd. (1.5 percent). Our interest is held through a jointly owned company, Qatar Liquefied Gas Company Limited (3), for which we use the equity method of accounting. QG3 secured project financing of $4 billion in 2005, consisting of $1.3 billion of loans from export credit agencies (ECA), $1.5 billion from commercial banks, and $1.2 billion from ConocoPhillips. The ConocoPhillips loan facilities have substantially the same terms as the ECA and commercial bank facilities. On December 15, 2011, QG3 achieved financial completion and all project loan facilities became nonrecourse to the project participants. At December 31, 2011, QG3 had approximately $3.9 billion outstanding under all the loan facilities, including $1.2 billion owed to ConocoPhillips.
For additional information about guarantees, see Note 14—Guarantees, in the Notes to Consolidated Financial Statements, which is incorporated herein by reference.
Capital Requirements
Our debt balance at December 31, 2011, was $22.6 billion, a decrease of $1.0 billion during 2011, and our debt-to-capital ratio was 26 percent at year-end 2011, versus 25 percent at the end of 2010. The slight increase in the debt-to-capital ratio was due to a decrease in total equity resulting from the share repurchase programs in 2011, partially offset by the debt reduction. Our debt-to-capital ratio target range is 20 to 25 percent.
In 2007, we closed on a business venture with Cenovus Energy Inc. As part of this transaction, we are obligated to contribute $7.5 billion, plus accrued interest, over a 10-year period that began in 2007, to the upstream business venture, FCCL, formed as a result of the transaction. Quarterly principal and interest payments of $237 million began in the second quarter of 2007, and will continue until the balance is paid. Of the principal obligation amount, approximately $732 million was short-term and was included in the “Accounts payable—related parties” line on our December 31, 2011, consolidated balance sheet. The principal portion of these payments, which totaled $695 million in 2011, is included in the “Other” line in the financing activities section of our consolidated statement of cash flows. Interest accrues at a fixed annual rate of 5.3 percent on the unpaid principal balance. Fifty percent of the quarterly interest payment is reflected as a capital contribution and is included in the “Capital expenditures and investments” line on our consolidated statement of cash flows.
During 2011, WRB Refining LP repaid $550 million of loan financing to ConocoPhillips that had been provided to assist WRB in meeting its operating and capital spending requirements. No outstanding balance remained at December 31, 2011.
In February 2012, we announced a dividend of 66 cents per share. The dividend is payable March 1, 2012, to stockholders of record at the close of business February 21, 2012.
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On March 24, 2010, our Board of Directors authorized the purchase of up to $5 billion of our common stock through 2011. Repurchase of shares under this authorization was completed in the first quarter of 2011. On February 11, 2011, the Board authorized the additional purchase of up to $10 billion of our common stock over the subsequent two years. Repurchase of shares under this authorization was completed in the fourth quarter of 2011. Under both programs, repurchases totaled 220 million shares at a cost of $15 billion through December 31, 2011. On December 2, 2011, our Board of Directors authorized the purchase of up to an additional $10 billion of our common stock over the subsequent two years.
Contractual Obligations
The following table summarizes our aggregate contractual fixed and variable obligations as of December 31, 2011:
| Millions of Dollars | ||||||||||||||||||||
| Payments Due by Period | ||||||||||||||||||||
| Total | Up to 1 Year |
Years 2-3 |
Years 4-5 |
After 5 Years |
||||||||||||||||
| Debt obligations (a) |
$ | 22,592 | 1,005 | 2,799 | 3,933 | 14,855 | ||||||||||||||
| Capital lease obligations |
31 | 8 | 3 | 2 | 18 | |||||||||||||||
| Total debt |
22,623 | 1,013 | 2,802 | 3,935 | 14,873 | |||||||||||||||
| Interest on debt and other obligations |
19,798 | 1,319 | 2,567 | 2,227 | 13,685 | |||||||||||||||
| Operating lease obligations |
2,761 | 767 | 901 | 502 | 591 | |||||||||||||||
| Purchase obligations (b) |
145,114 | 60,105 | 13,142 | 8,101 | 63,766 | |||||||||||||||
| Joint venture acquisition obligation (c) |
4,314 | 732 | 1,586 | 1,762 | 234 | |||||||||||||||
| Other long-term liabilities (d) |
||||||||||||||||||||
| Asset retirement obligations |
8,920 | 387 | 668 | 505 | 7,360 | |||||||||||||||
| Accrued environmental costs |
922 | 126 | 147 | 97 | 552 | |||||||||||||||
| Unrecognized tax benefits (e) |
153 | 153 | (e | ) | (e | ) | (e | ) | ||||||||||||
| Total |
$ | 204,605 | 64,602 | 21,813 | 17,129 | 101,061 | ||||||||||||||
| (a) | Includes $449 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, 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 $71,737 million. In addition, $50,741 million are product purchases from CPChem, mostly for natural gas and natural gas liquids over the remaining term of 88 years, and Excel Paralubes, for base oil over the remaining initial term of 14 years.
Purchase obligations of $17,044 million are related to agreements to access and utilize the capacity of third-party equipment and facilities, including pipelines and LNG and product terminals, to transport, process, treat and store products. The remainder is primarily our net share of purchase commitments for materials and services for jointly owned fields and facilities where we are the operator.
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| (c) | Represents the remaining amount of contributions, excluding interest, due over a six-year period to the FCCL upstream joint venture with Cenovus. |
| (d) | Does not include: Pensions—for the 2012 through 2016 time period, we expect to contribute an average of $490 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 $690 million for 2012 and then approximately $445 million per year for the remaining four years. Our required minimum funding in 2012 is expected to be $530 million in the United States and $220 million outside the United States. |
| (e) | Excludes unrecognized tax benefits of $918 million because the ultimate disposition and timing of any payments to be made with regard to such amounts are not reasonably estimable. Although unrecognized tax benefits are not a contractual obligation, they are presented in this table because they represent potential demands on our liquidity. |
Capital Spending
| Millions of Dollars | ||||||||||||||||
| 2012 Budget |
2011 | 2010 | 2009 | |||||||||||||
| Capital Expenditures and Investments |
||||||||||||||||
| E&P |
||||||||||||||||
| United States—Alaska |
$ | 900 | 775 | 730 | 810 | |||||||||||
| United States—Lower 48 |
4,800 | 3,880 | 1,855 | 2,664 | ||||||||||||
| International |
7,600 | 7,350 | 5,908 | 5,425 | ||||||||||||
| 13,300 | 12,005 | 8,493 | 8,899 | |||||||||||||
| Midstream |
— | 17 | 3 | 5 | ||||||||||||
| R&M |
||||||||||||||||
| United States |
1,000 | 768 | 790 | 1,299 | ||||||||||||
| International |
200 | 226 | 266 | 427 | ||||||||||||
| 1,200 | 994 | 1,056 | 1,726 | |||||||||||||
| LUKOIL Investment |
— | — | — | — | ||||||||||||
| Chemicals |
— | — | — | — | ||||||||||||
| Emerging Businesses |
100 | 30 | 27 | 97 | ||||||||||||
| Corporate and Other |
200 | 220 | 182 | 134 | ||||||||||||
| $ | 14,800 | 13,266 | 9,761 | 10,861 | ||||||||||||
| United States |
$ | 7,000 | 5,679 | 3,576 | 4,921 | |||||||||||
| International |
7,800 | 7,587 | 6,185 | 5,940 | ||||||||||||
| $ | 14,800 | 13,266 | 9,761 | 10,861 | ||||||||||||
Our capital expenditures and investments for the three-year period ending December 31, 2011, totaled $33.9 billion, with 87 percent allocated to our E&P segment.
Our capital expenditures and investments budget for 2012 is $14.8 billion. Included in this amount is approximately $0.4 billion in capitalized interest. We plan to direct 90 percent of the capital expenditures and investments budget to E&P and 8 percent to R&M. With the addition of principal contributions related to funding our portion of the FCCL business venture, our total capital program for 2012 is approximately $15.5 billion.
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E&P
Capital expenditures and investments for E&P during the three-year period ended December 31, 2011, totaled $29.4 billion. The expenditures over this period supported key exploration and development projects including:
| • | Oil, natural gas liquids and natural gas developments in the Lower 48, including Texas, New Mexico, North Dakota, Oklahoma, Montana, Colorado, Wyoming and offshore in the Gulf of Mexico. |
| • | Advancement of coalbed methane (CBM) projects associated with the APLNG joint venture in Australia. |
| • | Oil sands projects and ongoing natural gas projects in Canada. |
| • | Alaska activities related to development drilling in the Greater Kuparuk Area, the Greater Prudhoe Area, the Western North Slope and the Cook Inlet Area. |
| • | Development drilling and facilities projects in the Norwegian sector of the North Sea, including the Greater Ekofisk Area, Alvheim and Statfjord, and Heidrun in the Norwegian Sea. |
| • | The Peng Lai 19-3 development in China’s Bohai Bay. |
| • | The Kashagan Field and satellite prospects in the Caspian Sea offshore Kazakhstan. |
| • | In the U.K. sector of the North Sea, the development of the Jasmine discovery in the J-Block Area, the development of Clair Ridge, development drilling on Clair and in the southern and central North Sea. |
| • | The North Belut Field, as well as other projects in offshore Block B and onshore South Sumatra in Indonesia. |
| • | The QG3 Project, an integrated project to produce and liquefy natural gas from Qatar’s North Field. |
| • | The Gumusut-Kakap development offshore Sabah, Malaysia. |
| • | Exploration activities in Australia’s Browse Basin, North American shale plays, Canadian oil sands projects, deepwater Gulf of Mexico, Alaska, U.K. and Norwegian sectors of the North Sea, Kazakhstan and Indonesia. |
| • | The El Merk Project, comprised of wells, gathering lines and a shared central processing facility to develop the EMK Field Unit in Algeria. |
2012 CAPITAL EXPENDITURES AND INVESTMENTS BUDGET
E&P’s 2012 capital expenditures and investments budget is $13.3 billion, 11 percent higher than actual expenditures in 2011. Forty-three percent of E&P’s 2012 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 focus capital expenditures and investments on development of liquids-rich areas, such as the Eagle Ford Trend, and the Williston and Permian basins. We also expect to direct capital spending towards exploration and appraisal activities in the Eagle Ford shale formation, as well as recently acquired acreage in the Avalon, Wolfcamp, and Niobrara areas. In addition, we plan to appraise our recent deepwater Gulf of Mexico discoveries.
E&P is directing $7.6 billion of its 2012 capital expenditures and investments budget to international projects. Funds in 2012 are expected to be directed to developing major long-term projects including:
| • | Liquids opportunities in the western Canada basins and Canadian oil sands projects. |
| • | Further development of CBM projects associated with the APLNG joint venture in Australia. |
| • | Elsewhere in the Asia Pacific/Middle East Region, continued development of Bohai Bay in China, new fields offshore Malaysia, and offshore Block B and onshore South Sumatra in Indonesia. |
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| • | In the North Sea, the Greater Ekofisk Area, development of the Jasmine discovery in the J-Block Area, development of Clair Ridge and the Britannia Long Term Compression Project. |
| • | The Kashagan Field in the Caspian Sea. |
| • | Onshore developments in Nigeria, Algeria and Libya. |
| • | Exploration and appraisal activities in Canadian shale plays and oil sands projects, Australia’s offshore Browse Basin and onshore Canning Basin, deepwater Angola, Kazakhstan’s Block N, offshore Indonesia, Nigeria and the North Sea. |
For information on proved undeveloped reserves and the associated costs to develop these reserves, see the “Oil and Gas Operations” section.
R&M
Capital spending for R&M during the three-year period ended December 31, 2011, was primarily for air emission reduction and clean fuels projects to meet new environmental standards, refinery upgrade projects to improve product yields and increase heavy crude oil processing capability, improving the operating integrity of key processing units, as well as for safety projects. During this three-year period, R&M capital spending was $3.8 billion, which represented 11 percent of our total capital expenditures and investments.
Key projects during the three-year period included:
| • | Installation of a 20,000-barrel-per-day hydrocracker at the Rodeo facility of our San Francisco Refinery. |
| • | Installation of a 225-ton-per-day sulfur plant at the Sweeny Refinery. |
| • | Installation of facilities to reduce emissions from the Fluid Catalytic Crackers at the Alliance and Sweeny refineries. |
| • | Installation of facilities to reduce nitrous oxide emissions from the crude furnace and installation of a new vacuum furnace at the Bayway Refinery. |
| • | Completion of gasoline benzene reduction projects at the Alliance and Ponca City refineries. |
Major construction activities in progress include:
| • | Installation, revamp and expansion of equipment at the Bayway Refinery to enable production of low benzene gasoline. |
| • | U.S. programs aimed at air emission reductions. |
2012 CAPITAL EXPENDITURES AND INVESTMENTS BUDGET
R&M’s 2012 capital expenditures and investments budget is $1.2 billion, a 21 percent increase from actual spending in 2011, with about $1.0 billion targeted in the United States and $0.2 billion internationally. These funds will be used primarily for projects related to sustaining and improving the existing business with a focus on safety, regulatory compliance, efficiency and reliability.
Emerging Businesses
Capital spending for Emerging Businesses during the three-year period ended December 31, 2011, was primarily for an expansion and other capital improvements at the Immingham combined heat and power cogeneration plant near our Humber Refinery in the United Kingdom.
Contingencies
A number of lawsuits involving a variety of claims have been made against ConocoPhillips that arise in the ordinary course of business. We also may be required to remove or mitigate the effects on the environment of the placement, storage, disposal or release of certain chemical, mineral and petroleum substances at various active and inactive sites. We regularly assess the need for accounting recognition or disclosure of
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these contingencies. In the case of all known contingencies (other than those related to income taxes), we accrue a liability when the loss is probable and the amount is reasonably estimable. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. We do not reduce these liabilities for potential insurance or third-party recoveries. If applicable, we accrue receivables for probable insurance or other third-party recoveries. In the case of income-tax-related contingencies, we use a cumulative probability-weighted loss accrual in cases where sustaining a tax position is less than certain.
Based on currently available information, we believe it is remote that future costs related to known contingent liability exposures will exceed current accruals by an amount that would have a material adverse impact on our consolidated financial statements. As we learn new facts concerning contingencies, we reassess our position both with respect to accrued liabilities and other potential exposures. Estimates particularly sensitive to future changes include contingent liabilities recorded for environmental remediation, tax and legal matters. Estimated future environmental remediation costs are subject to change due to such factors as the uncertain magnitude of cleanup costs, the unknown time and extent of such remedial actions that may be required, and the determination of our liability in proportion to that of other responsible parties. Estimated future costs related to tax and legal matters are subject to change as events evolve and as additional information becomes available during the administrative and litigation processes.
Legal and Tax Matters
Our legal organization applies its knowledge, experience and professional judgment to the specific characteristics of our cases, employing a litigation management process to manage and monitor the legal proceedings against us. Our process facilitates the early evaluation and quantification of potential exposures in individual cases. This process also enables us to track those cases that have been scheduled for trial and/or mediation. Based on professional judgment and experience in using these litigation management tools and available information about current developments in all our cases, our legal organization regularly assesses the adequacy of current accruals and determines if adjustment of existing accruals, or establishment of new accruals, are required. See Note 20—Income Taxes, in the Notes to Consolidated Financial Statements, for additional information about income-tax-related contingencies.
Environmental
We are subject to the same numerous international, federal, state and local environmental laws and regulations as other companies in our industry. The most significant of these environmental laws and regulations include, among others, the:
| • | 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. |
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| • | U.S. Department of the Interior regulations, which relate to offshore oil and gas operations in U.S. waters and impose liability for the cost of pollution cleanup resulting from operations, as well as potential liability for pollution damages. |
| • | European Union Trading Directive resulting in European Emissions Trading Scheme. |
These laws and their implementing regulations set limits on emissions and, in the case of discharges to water, establish water quality limits. They also, in most cases, require permits in association with new or modified operations. These permits can require an applicant to collect substantial information in connection with the application process, which can be expensive and time consuming. In addition, there can be delays associated with notice and comment periods and the agency’s processing of the application. Many of the delays associated with the permitting process are beyond the control of the applicant.
Many states and foreign countries where we operate also have, or are developing, similar environmental laws and regulations governing these same types of activities. While similar, in some cases these regulations may impose additional, or more stringent, requirements that can add to the cost and difficulty of marketing or transporting products across state and international borders.
The ultimate financial impact arising from environmental laws and regulations is neither clearly known nor easily determinable as new standards, such as air emission standards, water quality standards and stricter fuel regulations, continue to evolve. However, environmental laws and regulations, including those that may arise to address concerns about global climate change, are expected to continue to have an increasing impact on our operations in the United States and in other countries in which we operate. Notable areas of potential impacts include air emission compliance and remediation obligations in the United States.
An example in the fuels area is the Energy Policy Act of 2005, which imposed obligations to provide increasing volumes of renewable fuels in transportation motor fuels through 2012. These obligations were changed with the enactment of the Energy Independence and Security Act of 2007. The 2007 law requires fuel producers and importers to provide additional renewable fuels for transportation motor fuels that include a mix of various types to be included through 2022. We have met the increased requirements to date while establishing implementation, operating and capital strategies, along with advanced technology development, to address projected future requirements.
Another example is the use of hydraulic fracturing, an essential completion technique that facilitates production of oil and natural gas that is otherwise trapped in lower permeability rock formations. A range of local, state, federal or national laws and regulations currently govern hydraulic fracturing operations. Although hydraulic fracturing has been conducted for many decades, a number of new laws, regulations and permitting requirements are under consideration by the U.S. Environmental Protection Agency (EPA), the U.S. Department of the Interior, and others which could result in increased costs, operating restrictions, operational delays and/or limit the ability to develop oil and natural gas resources. Governmental restrictions on hydraulic fracturing could impact the overall profitability or viability of certain of our oil and natural gas investments. We have adopted operating principles that incorporate established industry standards designed to meet or exceed government requirements. Our practices continually evolve as technology improves and regulations change.
We also are subject to certain laws and regulations relating to environmental remediation obligations associated with current and past operations. Such laws and regulations include CERCLA and RCRA and their state equivalents. Remediation obligations include cleanup responsibility arising from petroleum releases from underground storage tanks located at numerous past and present ConocoPhillips-owned and/or operated petroleum-marketing outlets throughout the United States. Federal and state laws require contamination caused by such underground storage tank releases be assessed and remediated to meet applicable standards. In addition to other cleanup standards, many states adopted cleanup criteria for methyl tertiary-butyl ether (MTBE) for both soil and groundwater.
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At RCRA-permitted facilities, we are required to assess environmental conditions. If conditions warrant, we may be required to remediate contamination caused by prior operations. In contrast to CERCLA, which is often referred to as “Superfund,” the cost of corrective action activities under RCRA corrective action programs typically is borne solely by us. We anticipate increased expenditures for RCRA remediation activities may be required, but such annual expenditures for the near term are not expected to vary significantly from the range of such expenditures we have experienced over the past few years. Longer-term expenditures are subject to considerable uncertainty and may fluctuate significantly.
We occasionally receive requests for information or notices of potential liability from the EPA and state environmental agencies alleging that we are a potentially responsible party under CERCLA or an equivalent state statute. On occasion, we also have been made a party to cost recovery litigation by those agencies or by private parties. These requests, notices and lawsuits assert potential liability for remediation costs at various sites that typically are not owned by us, but allegedly contain wastes attributable to our past operations. As of December 31, 2010, we reported we had been notified of potential liability under CERCLA and comparable state laws at 73 sites around the United States. At December 31, 2011, we had been notified of 8 new sites, settled 5 sites and closed 2 sites, bringing the number to 74 unresolved sites with potential liability.
For most Superfund sites, our potential liability will be significantly less than the total site remediation costs because the percentage of waste attributable to us, versus that attributable to all other potentially responsible parties, is relatively low. Although liability of those potentially responsible is generally joint and several for federal sites and frequently so for state sites, other potentially responsible parties at sites where we are a party typically have had the financial strength to meet their obligations, and where they have not, or where potentially responsible parties could not be located, our share of liability has not increased materially. Many of the sites at which we are potentially responsible are still under investigation by the EPA or the state agencies concerned. Prior to actual cleanup, those potentially responsible normally assess site conditions, apportion responsibility and determine the appropriate remediation. In some instances, we may have no liability or attain a settlement of liability. Actual cleanup costs generally occur after the parties obtain EPA or equivalent state agency approval. There are relatively few sites where we are a major participant, and given the timing and amounts of anticipated expenditures, neither the cost of remediation at those sites nor such costs at all CERCLA sites, in the aggregate, is expected to have a material adverse effect on our competitive or financial condition.
Expensed environmental costs were $1,039 million in 2011 and are expected to be about $1,100 million per year in 2012 and 2013. Capitalized environmental costs were $573 million in 2011 and are expected to be about $875 million per year in 2012 and 2013.
Accrued liabilities for remediation activities are not reduced for potential recoveries from insurers or other third parties and are not discounted (except those assumed in a purchase business combination, which we do record on a discounted basis).
Many of these liabilities result from CERCLA, RCRA and similar state laws that require us to undertake certain investigative and remedial activities at sites where we conduct, or once conducted, operations or at sites where ConocoPhillips-generated waste was disposed. The accrual also includes a number of sites we identified that may require environmental remediation, but which are not currently the subject of CERCLA, RCRA or state enforcement activities. If applicable, we accrue receivables for probable insurance or other third-party recoveries. In the future, we may incur significant costs under both CERCLA and RCRA.
Remediation activities vary substantially in duration and cost from site to site, depending on the mix of unique site characteristics, evolving remediation technologies, diverse regulatory agencies and enforcement policies, and the presence or absence of potentially liable third parties. Therefore, it is difficult to develop reasonable estimates of future site remediation costs.
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At December 31, 2011, our balance sheet included total accrued environmental costs of $922 million, compared with $994 million at December 31, 2010. We expect to incur a substantial amount of these expenditures within the next 30 years.
Notwithstanding any of the foregoing, and as with other companies engaged in similar businesses, environmental costs and liabilities are inherent concerns in our operations and products, and there can be no assurance that material costs and liabilities will not be incurred. However, we currently do not expect any material adverse effect upon our results of operations or financial position as a result of compliance with current environmental laws and regulations.
Climate Change
There has been a broad range of proposed or promulgated state, national and international laws focusing on greenhouse gas (GHG) reduction. These proposed or promulgated laws apply or could apply in countries where we have interests or may have interests in the future. Laws in this field continue to evolve, and while it is not possible to accurately estimate either a timetable for implementation or our future compliance costs relating to implementation, such laws, if enacted, could have a material impact on our results of operations and financial condition. Examples of legislation or precursors for possible regulation that do or could affect our operations include:
| • | European Emissions Trading Scheme (ETS), the program through which many of the European Union (EU) member states are implementing the Kyoto Protocol. |
| • | California’s Global Warming Solutions Act, which requires the California Air Resources Board to develop regulations and market mechanisms that will target reduction of California’s GHG emissions by 25 percent by 2020. |
| • | Two regulations issued by the Alberta government in 2007 under the Climate Change and Emissions Act. These regulations require any existing facility with emissions equal to or greater than 100,000 metric tons of carbon dioxide or equivalent per year to reduce the net emissions intensity of that facility by 2 percent per year beginning July 1, 2007, with an ultimate reduction target of 12 percent of baseline emissions. |
| • | The U.S. Supreme Court decision in Massachusetts v. EPA, 549 U.S. 497, 127 S.Ct. 1438 (2007), confirming that the EPA has the authority to regulate carbon dioxide as an “air pollutant” under the Federal Clean Air Act. |
| • | The EPA’s announcement on March 29, 2010 (published as “Interpretation of Regulations that Determine Pollutants Covered by Clean Air Act Permitting Programs,” 75 Fed. Reg. 17004 (April 2, 2010)), and the EPA’s and U.S. Department of Transportation’s joint promulgation of a Final Rule on April 1, 2010, that triggers regulation of GHGs under the Clean Air Act, may trigger more climate-based claims for damages, and may result in longer agency review time for development projects. |
| • | Carbon taxes in certain jurisdictions. |
| • | Cap and trade programs in certain jurisdictions, including the Australian Clean Energy Legislation which is scheduled to take effect July 2012. |
In the EU, we have assets that are subject to the ETS. The first phase of the EU ETS was completed at the end of 2007, with EU ETS Phase II running from 2008 through 2012. The European Commission has approved most of the Phase II national allocation plans. We are actively engaged to minimize any financial impact from the trading scheme.
In the United States, some additional form of regulation may be forthcoming in the future at the federal and state levels with respect to GHG emissions. Such regulation could take any of several forms that may result in the creation of additional costs in the form of taxes, the restriction of output, investments of capital to maintain compliance with laws and regulations, or required acquisition or trading of emission allowances.
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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.
CRITICAL ACCOUNTING ESTIMATES
The preparation of financial statements in conformity with generally accepted accounting principles requires management to select appropriate accounting policies and to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. See Note 1—Accounting Policies, in the Notes to Consolidated Financial Statements, for descriptions of our major accounting policies. Certain of these accounting policies involve judgments and uncertainties to such an extent there is a reasonable likelihood materially different amounts would have been reported under different conditions, or if different assumptions had been used. These critical accounting estimates are discussed with the Audit and Finance Committee of the Board of Directors at least annually. We believe the following discussions of critical accounting estimates, along with the discussions of contingencies and of deferred tax asset valuation allowances in this report, address all important accounting areas where the nature of accounting estimates or assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change.
Oil and Gas Accounting
Accounting for oil and gas exploratory activity is subject to special accounting rules unique to the oil and gas industry. The acquisition of geological and geophysical seismic information, prior to the discovery of proved reserves, is expensed as incurred, similar to accounting for research and development costs. However, leasehold acquisition costs and exploratory well costs are capitalized on the balance sheet pending determination of whether proved oil and gas reserves have been discovered on the prospect.
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Property Acquisition Costs
For individually significant leaseholds, management periodically assesses for impairment based on exploration and drilling efforts to date. For leasehold acquisition costs that individually are relatively small, management exercises judgment and determines a percentage probability that the prospect ultimately will fail to find proved oil and gas reserves and pools that leasehold information with others in the geographic area. For prospects in areas that have had limited, or no, previous exploratory drilling, the percentage probability of ultimate failure is normally judged to be quite high. This judgmental percentage is multiplied by the leasehold acquisition cost, and that product is divided by the contractual period of the leasehold to determine a periodic leasehold impairment charge that is reported in exploration expense.
This judgmental probability percentage is reassessed and adjusted throughout the contractual period of the leasehold based on favorable or unfavorable exploratory activity on the leasehold or on adjacent leaseholds, and leasehold impairment amortization expense is adjusted prospectively. At year-end 2011, the book value of the pools of property acquisition costs that individually are relatively small and thus subject to the above-described periodic leasehold impairment calculation was $1,880 million and the accumulated impairment reserve was $487 million. The weighted-average judgmental percentage probability of ultimate failure was approximately 47 percent, and the weighted-average amortization period was approximately four years. If that judgmental percentage were to be raised by 5 percent across all calculations, pretax leasehold impairment expense in 2012 would increase by approximately $22 million. The remaining $5,966 million of gross capitalized unproved property costs at year-end 2011 consisted of individually significant leaseholds, mineral rights held in perpetuity by title ownership, exploratory wells currently drilling, suspended exploratory wells, and capitalized interest. Management periodically assesses individually significant leaseholds for impairment based on the results of exploration and drilling efforts and the outlook for project commercialization. Of this amount, approximately $3.0 billion is concentrated in 10 major development areas. One of these major assets totaling $97 million is expected to move to proved properties in 2012.
Exploratory Costs
For exploratory wells, drilling costs are temporarily capitalized, or “suspended,” on the balance sheet, pending a determination of whether potentially economic oil and gas reserves have been discovered by the drilling effort to justify completion of the find as a producing well.
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
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development costs, ability to apply existing technology to produce the reserves, fiscal terms, regulations or contract negotiations, and our required return on investment.
At year-end 2011, total suspended well costs were $1,037 million, compared with $1,013 million at year-end 2010. For additional information on suspended wells, including an aging analysis, see Note 8—Suspended Wells, in the Notes to Consolidated Financial Statements.
Proved Reserves
Engineering estimates of the quantities of proved reserves are inherently imprecise and represent only approximate amounts because of the judgments involved in developing such information. Reserve estimates are based on geological and engineering assessments of in-place hydrocarbon volumes, the production plan, historical extraction recovery and processing yield factors, installed plant operating capacity and approved operating limits. The reliability of these estimates at any point in time depends on both the quality and quantity of the technical and economic data and the efficiency of extracting and processing the hydrocarbons.
Despite the inherent imprecision in these engineering estimates, accounting rules require disclosure of “proved” reserve estimates due to the importance of these estimates to better understand the perceived value and future cash flows of a company’s E&P operations. There are several authoritative guidelines regarding the engineering criteria that must be met before estimated reserves can be designated as “proved.” Our reservoir engineering organization has policies and procedures in place consistent with these authoritative guidelines. We have trained and experienced internal engineering personnel who estimate our proved reserves held by consolidated companies, as well as our share of equity affiliates.
Proved reserve estimates are adjusted annually in the fourth quarter and during the year if significant changes occur, and take into account recent production and subsurface information about each field. Also, as required by current authoritative guidelines, the estimated future date when a field will be permanently shut down for economic reasons is based on 12-month average prices and year-end costs. This estimated date when production will end affects the amount of estimated reserves. Therefore, as prices and cost levels change from year to year, the estimate of proved reserves also changes.
Our proved reserves include estimated quantities related to production sharing contracts, which are reported under the “economic interest” method and are subject to fluctuations in commodity prices; recoverable operating expenses; and capital costs. If costs remain stable, reserve quantities attributable to recovery of costs will change inversely to changes in commodity prices. For example, if prices increase, then our applicable reserve quantities would decline. The estimation of proved developed reserves also is important to the income statement because the proved developed reserve estimate for a field serves as the denominator in the unit-of-production calculation of depreciation, depletion and amortization (DD&A) of the capitalized costs for that asset. At year-end 2011, the net book value of productive E&P properties, plants and equipment (PP&E) subject to a unit-of-production calculation was approximately $57 billion and the DD&A recorded on these assets in 2011 was approximately $6.6 billion. The estimated proved developed reserves for our consolidated operations were 5.2 billion BOE at the end of 2010 and 5.1 billion BOE at the end of 2011. If the estimates of proved reserves used in the unit-of-production calculations had been lower by 5 percent across all calculations, pretax DD&A in 2011 would have increased by an estimated $347 million.
Impairments
Long-lived assets used in operations are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in future cash flows expected to be generated by an asset group and annually in the fourth quarter following updates to corporate planning assumptions. If, upon review, the sum of the undiscounted pretax cash flows is less than the carrying value of the asset
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group, the carrying value is written down to estimated fair value. Individual assets are grouped for impairment purposes based on a judgmental assessment of the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets—generally on a field-by-field basis for exploration and production assets, or at an entire complex level for downstream assets. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants, or based on a multiple of operating cash flow validated with historical market transactions of similar assets where possible. The expected future cash flows used for impairment reviews and related fair value calculations are based on judgmental assessments of future production volumes, commodity prices, operating costs, refining margins and capital project decisions, considering all available information at the date of review. See Note 10—Impairments, in the Notes to Consolidated Financial Statements, for additional information.
Investments in nonconsolidated entities accounted for under the equity method are reviewed for impairment when there is evidence of a loss in value and annually following updates to corporate planning assumptions. Such evidence of a loss in value might include our inability to recover the carrying amount, the lack of sustained earnings capacity which would justify the current investment amount, or a current fair value less than the investment’s carrying amount. When it is determined such a loss in value is other than temporary, an impairment charge is recognized for the difference between the investment’s carrying value and its estimated fair value. When determining whether a decline in value is other than temporary, management considers factors such as the length of time and extent of the decline, the investee’s financial condition and near-term prospects, and our ability and intention to retain our investment for a period that will be sufficient to allow for any anticipated recovery in the market value of the investment. When quoted market prices are not available, the fair value is usually based on the present value of expected future cash flows using discount rates believed to be consistent with those used by principal market participants, plus market analysis of comparable assets owned by the investee, if appropriate. Differing assumptions could affect the timing and the amount of an impairment of an investment in any period.
Asset Retirement Obligations and Environmental Costs
Under various contracts, permits and regulations, we have material legal obligations to remove tangible equipment and restore the land or seabed at the end of operations at operational sites. Our largest asset removal obligations involve plugging and abandonment of wells, removal and disposal of offshore oil and gas platforms around the world, 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 into PP&E at the installation of the asset based on estimated discounted costs. Estimating the future asset removal costs necessary for this accounting calculation is difficult. Most of these removal obligations are many years, or decades, in the future and the contracts and regulations often have vague descriptions of what removal practices and criteria must be met when the removal event actually occurs. Asset removal technologies and costs, regulatory and other compliance considerations, expenditure timing, and other inputs into valuation of the obligation, including discount and inflation rates, are also subject to change.
Normally, changes in asset removal obligations are reflected in the income statement as increases or decreases to DD&A over the remaining life of the assets. However, for assets at or nearing the end of their operations, as well as previously sold assets for which we retained the asset removal obligation, an increase in the asset removal obligation can result in an immediate charge to earnings, because any increase in PP&E due to the increased obligation would immediately be subject to impairment, due to the low fair value of these properties.
In addition to asset removal obligations, under the above or similar contracts, permits and regulations, we have certain obligations to complete environmental-related projects. These projects are primarily related to cleanup at domestic refineries and remediation activities required by Canada and the state of Alaska at
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exploration and production sites. Future environmental remediation costs are difficult to estimate because they are subject to change due to such factors as the uncertain magnitude of cleanup costs, the unknown time and extent of such remedial actions that may be required, and the determination of our liability in proportion to that of other responsible parties.
Business Acquisitions
Assets Acquired and Liabilities Assumed
Accounting for the acquisition of a business requires the recognition of the consideration paid, as well as the various assets and liabilities of the acquired business. For most assets and liabilities, the asset or liability is recorded at its estimated fair value. The most difficult estimates of individual fair values are those involving PP&E and identifiable intangible assets. We use all available information to make these fair value determinations. We have, if necessary, up to one year after the acquisition closing date to finalize these fair value determinations.
Intangible Assets and Goodwill
At December 31, 2011, we had $701 million of intangible assets determined to have indefinite useful lives, thus they are not amortized. This judgmental assessment of an indefinite useful life must be continuously evaluated in the future. If, due to changes in facts and circumstances, management determines these intangible assets have definite useful lives, amortization will have to commence at that time on a prospective basis. As long as these intangible assets are judged to have indefinite lives, they will be subject to periodic lower-of-cost-or-market tests that require management’s judgment of the estimated fair value of these intangible assets.
At December 31, 2011, we had $3,332 million of goodwill on our balance sheet, all of which was attributable to the 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.
Projected Benefit Obligations
Determination of the projected benefit obligations for our defined benefit pension and postretirement plans are important to the recorded amounts for such obligations on the balance sheet and to the amount of benefit expense in the income statement. The actuarial determination of projected benefit obligations and company contribution requirements involves judgment about uncertain future events, including estimated retirement dates, salary levels at retirement, mortality rates, lump-sum election rates, rates of return on plan assets, future health care cost-trend rates, and rates of utilization of health care services by retirees. Due to the specialized nature of these calculations, we engage outside actuarial firms to assist in the determination of these projected benefit obligations and company contribution requirements. For Employee Retirement Income Security Act-qualified pension plans, the actuary exercises fiduciary care on behalf of plan participants in the determination of the judgmental assumptions used in determining required company contributions into the plan. Due to differing objectives and requirements between financial accounting rules and the pension plan funding regulations promulgated by governmental agencies, the actuarial methods and assumptions for the two purposes differ in certain important respects. Ultimately, we will be required to fund all promised benefits under pension and postretirement benefit plans not funded by plan assets or investment returns, but the judgmental assumptions used in the actuarial calculations significantly affect periodic financial statements and funding patterns over time. Benefit expense is particularly sensitive to the discount rate and return on plan assets assumptions. A 1 percent decrease in the discount rate assumption would increase annual benefit expense by $130 million, while a 1 percent decrease in the return on plan assets assumption would increase annual benefit expense by $70 million. In determining the discount rate, we use yields on high-quality fixed income investments matched to the estimated benefit cash flows of our plans.
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CAUTIONARY STATEMENT FOR THE PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
This report includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. You can identify our forward-looking statements by the words “anticipate,” “estimate,” “believe,” “budget,” “continue,” “could,” “intend,” “may,” “plan,” “potential,” “predict,” “seek,” “should,” “will,” “would,” “expect,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,” “effort,” “target” and similar expressions.
We based the forward-looking statements on our current expectations, estimates and projections about ourselves and the industries in which we operate in general. We caution you these statements are not guarantees of future performance as they involve assumptions that, while made in good faith, may prove to be incorrect, and involve risks and uncertainties we cannot predict. In addition, we based many of these forward-looking statements on assumptions about future events that may prove to be inaccurate. Accordingly, our actual outcomes and results may differ materially from what we have expressed or forecast in the forward-looking statements. Any differences could result from a variety of factors, including the following:
| • | Fluctuations in crude oil, bitumen, natural gas, LNG and natural gas liquids prices, refining and marketing margins and margins for our chemicals business. |
| • | Potential failures or delays in achieving expected reserve or production levels from existing and future oil and gas development projects due to operating hazards, drilling risks and the inherent uncertainties in predicting reserves and reservoir performance. |
| • | Unsuccessful exploratory drilling activities or the inability to obtain access to exploratory acreage. |
| • | Failure of new products and services to achieve market acceptance. |
| • | Unexpected changes in costs or technical requirements for constructing, modifying or operating facilities for exploration and production, manufacturing, refining or transportation projects. |
| • | Unexpected technological or commercial difficulties in manufacturing, refining or transporting our products, including chemicals products. |
| • | Lack of, or disruptions in, adequate and reliable transportation for our crude oil, natural gas, natural gas liquids, bitumen, LNG and refined products. |
| • | Inability to timely obtain or maintain permits, including those necessary for drilling and/or development projects, construction of LNG terminals or regasification facilities, or refinery projects; comply with government regulations; or make capital expenditures required to maintain compliance. |
| • | Failure to complete definitive agreements and feasibility studies for, and to timely complete construction of, announced and future exploration and production, LNG, refinery and transportation projects. |
| • | Potential disruption or interruption of our operations due to accidents, extraordinary weather events, civil unrest, political events, terrorism or cyber attacks. |
| • | International monetary conditions and exchange controls. |
| • | Substantial investment or reduced demand for products as a result of existing or future environmental rules and regulations. |
| • | Liability for remedial actions, including removal and reclamation obligations, under environmental regulations. |
| • | Liability resulting from litigation. |
| • | General domestic and international economic and political developments, including armed hostilities; expropriation of assets; changes in governmental policies relating to crude oil, bitumen, natural gas, LNG, natural gas liquids or refined product pricing, regulation or taxation; other political, economic or diplomatic developments; and international monetary fluctuations. |
| • | Changes in tax and other laws, regulations (including alternative energy mandates), or royalty rules applicable to our business. |
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| • | Limited access to capital or significantly higher cost of capital related to illiquidity or uncertainty in the domestic or international financial markets. |
| • | Delays in, or our inability to implement, our asset disposition plan. |
| • | Inability to obtain economical financing for projects, construction or modification of facilities and general corporate purposes. |
| • | The operation and financing of our joint ventures. |
| • | The effect of restructuring or reorganization of business components. |
| • | The effect of the separation of our downstream businesses. |
| • | The factors generally described in Item 1A—Risk Factors in this report. |
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Financial Instrument Market Risk
We and certain of our subsidiaries hold and issue derivative contracts and financial instruments that expose our cash flows or earnings to changes in commodity prices, foreign currency exchange rates or interest rates. We may use financial and commodity-based derivative contracts to manage the risks produced by changes in the prices of electric power, natural gas, crude oil and related products; fluctuations in interest rates and foreign currency exchange rates; or to capture market opportunities.
Our use of derivative instruments is governed by an “Authority Limitations” document approved by our Board of Directors that prohibits the use of highly leveraged derivatives or derivative instruments without sufficient liquidity for comparable valuations. The Authority Limitations document also establishes the Value at Risk (VaR) limits for the company, and compliance with these limits is monitored daily. The chief financial officer monitors risks resulting from foreign currency exchange rates and interest rates and reports to the Chief Executive Officer. The senior vice president of Commercial monitors commodity price risk and also reports to the Chief Executive Officer. The Commercial organization manages our commercial marketing, optimizes our commodity flows and positions, and monitors risks related to our upstream and downstream businesses.
Commodity Price Risk
We operate in the worldwide crude oil, bitumen, refined products, natural gas, natural gas liquids, LNG and electric power markets and are exposed to fluctuations in the prices for these commodities. These fluctuations can affect our revenues, as well as the cost of operating, investing and financing activities. Generally, our policy is to remain exposed to the market prices of commodities.
Our Commercial organization uses futures, forwards, swaps and options in various markets to optimize the value of our supply chain, which may move our risk profile away from market average prices to accomplish the following objectives:
| • | Balance physical systems. In addition to cash settlement prior to contract expiration, exchange-traded futures contracts also may be settled by physical delivery of the commodity, providing another source of supply to meet our refinery requirements or marketing demands. |
| • | 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 floating market prices. |
| • | Manage the risk to our cash flows from price exposures on specific crude oil, natural gas, refined product and electric power transactions. |
| • | Enable us to use the market knowledge gained from these activities to capture market opportunities such as moving physical commodities to more profitable locations, storing commodities to capture seasonal or time premiums, and blending commodities to capture quality upgrades. We may use derivatives to optimize these activities. |
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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 we hold or issue, including commodity purchases and sales contracts recorded on the balance sheet at December 31, 2011, 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, 2011 and 2010, was immaterial to our consolidated cash flows and net income attributable to ConocoPhillips. The VaR for instruments held for purposes other than trading at December 31, 2011 and 2010, was also immaterial to our cash flows and net income attributable to ConocoPhillips.
Interest Rate Risk
The following table provides information about our financial instruments that are sensitive to changes in U.S. interest rates. The debt portion of the table presents principal cash flows and related weighted-average interest rates by expected maturity dates. Weighted-average variable rates are based on effective rates at the reporting date. The carrying amount of our floating-rate debt approximates its fair value. The fair value of the fixed-rate financial instruments is estimated based on quoted market prices. The joint venture acquisition obligation portion of the table presents principal cash flows of the fixed-rate 5.3 percent joint venture acquisition obligation owed to FCCL Partnership. The fair value of the obligation is estimated based on the net present value of the future cash flows, discounted at year-end 2011 and 2010 effective yield rates of 1.24 percent and 1.87 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 2011 |
||||||||||||||||||||||||||||||
| 2012 |
$ | 918 | 4.80 | % | $ | 3 | 0.38 | % | $ | 732 | 5.30 | % | ||||||||||||||||||
| 2013 |
1,262 | 5.33 | — | — | 772 | 5.30 | ||||||||||||||||||||||||
| 2014 |
1,511 | 4.77 | — | — | 814 | 5.30 | ||||||||||||||||||||||||
| 2015 |
1,513 | 4.62 | 15 | 2.01 | 858 | 5.30 | ||||||||||||||||||||||||
| 2016 |
1,287 | 5.54 | 1,128 | 0.51 | 904 | 5.30 | ||||||||||||||||||||||||
| Remaining years |
14,008 | 6.52 | 498 | 0.38 | 234 | 5.30 | ||||||||||||||||||||||||
| Total |
$ | 20,499 | $ | 1,644 | $ | 4,314 | ||||||||||||||||||||||||
| Fair value |
$ | 25,421 | $ | 1,644 | $ | 4,820 | ||||||||||||||||||||||||
| Year-End 2010 |
||||||||||||||||||||||||||||||
| 2011 |
$ | 853 | 7.62 | % | $ | — | — | % | $ | 695 | 5.30 | % | ||||||||||||||||||
| 2012 |
916 | 4.80 | 1,185 | 0.51 | 732 | 5.30 | ||||||||||||||||||||||||
| 2013 |
1,262 | 5.33 | — | — | 772 | 5.30 | ||||||||||||||||||||||||
| 2014 |
1,513 | 4.77 | — | — | 814 | 5.30 | ||||||||||||||||||||||||
| 2015 |
1,514 | 4.62 | 64 | 2.05 | 858 | 5.30 | ||||||||||||||||||||||||
| Remaining years |
15,291 | 6.44 | 498 | 0.38 | 1,138 | 5.30 | ||||||||||||||||||||||||
| Total |
$ | 21,349 | $ | 1,747 | $ | 5,009 | ||||||||||||||||||||||||
| Fair value |
$ | 24,397 | $ | 1,747 | $ | 5,600 | ||||||||||||||||||||||||
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During the second quarter of 2010, we executed interest rate swaps to synthetically convert $500 million of our 4.60% fixed-rate notes due in 2015 to a floating rate based on the London Interbank Offered Rate (LIBOR). These swaps qualify for and are designated as fair-value hedges using the short-cut method of hedge accounting. The short-cut method permits the assumption that changes in the value of the derivative perfectly offset changes in the value of the debt; therefore, no gain or loss has been recognized due to hedge ineffectiveness. These adjustments to the fair values of the interest rate swaps and hedged debt have not been material.
Foreign Currency Exchange Risk
We have foreign currency exchange rate risk resulting from international operations. We do not comprehensively hedge the exposure to currency rate changes although we may choose to selectively hedge certain foreign currency exchange rate exposures, such as firm commitments for capital projects or local currency tax payments, dividends and cash returns from net investments in foreign affiliates to be remitted within the coming year.
At December 31, 2011 and 2010, we held foreign currency exchange forwards hedging cross-border commercial activity and foreign currency exchange swaps hedging short-term intercompany loans between European subsidiaries and a U.S. subsidiary. Although these forwards and swaps hedge exposures to fluctuations in exchange rates, we elected not to utilize hedge accounting. As a result, the change in the fair value of these foreign currency exchange derivatives is recorded directly in earnings. Since the gain or loss on the swaps is offset by the gain or loss from remeasuring the intercompany loans into the functional currency of the lender or borrower, and since our aggregate position in the forwards was not material, there would be no material impact to our income from an adverse hypothetical 10 percent change in the December 31, 2011, or 2010, exchange rates. The notional and fair market values of these positions at December 31, 2011 and 2010, were as follows:
| In Millions | ||||||||||||||||||||||
| Foreign Currency Exchange Derivatives | Notional* | Fair Market Value** | ||||||||||||||||||||
| 2011 | 2010 | 2011 | 2010 | |||||||||||||||||||
| Sell U.S. dollar, buy euro |
USD | 219 | — | $ | (8 | ) | — | |||||||||||||||
| Sell U.S. dollar, buy British pound |
USD | 790 | 4 | — | (3 | ) | ||||||||||||||||
| Sell U.S. dollar, buy Canadian dollar |
USD | 648 | 562 | — | 8 | |||||||||||||||||
| Sell U.S. dollar, buy Norwegian krone |
USD | 292 | 3 | (7 | ) | — | ||||||||||||||||
| Buy euro, sell the Norwegian krone |
EUR | 3 | — | — | — | |||||||||||||||||
| Sell euro, buy British pound |
EUR | 64 | 253 | 5 | 1 | |||||||||||||||||
* 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 | ||||||||||||
| 2011 |
||||||||||||||
| First |
$ | 81.80 | 66.50 | .66 | ||||||||||
| Second |
81.75 | 70.08 | .66 | |||||||||||
| Third |
80.13 | 60.40 | .66 | |||||||||||
| Fourth |
73.90 | 58.65 | .66 | |||||||||||
| 2010 |
||||||||||||||
| First |
$ | 53.80 | 46.63 | .50 | ||||||||||
| Second |
60.53 | 48.51 | .55 | |||||||||||
| Third |
58.03 | 48.06 | .55 | |||||||||||
| Fourth |
68.58 | 56.80 | .55 | |||||||||||
| Closing Stock Price at December 31, 2011 |
$ | 72.87 | ||||||||||||
| Closing Stock Price at January 31, 2012 |
$ | 68.21 | ||||||||||||
| Number of Stockholders of Record at January 31, 2012* |
57,800 | |||||||||||||
| * | 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 Before Income Taxes |
Net Income |
Net Income Attributable to ConocoPhillips |
Net Income Attributable to ConocoPhillips |
||||||||||||||||||||||||
| Basic | Diluted | |||||||||||||||||||||||||||
| 2011 |
||||||||||||||||||||||||||||
| First |
$ | 56,530 | 5,796 | 3,042 | 3,028 | 2.11 | 2.09 | |||||||||||||||||||||
| Second |
65,627 | 6,192 | 3,419 | 3,402 | 2.43 | 2.41 | ||||||||||||||||||||||
| Third |
62,784 | 5,180 | 2,631 | 2,616 | 1.93 | 1.91 | ||||||||||||||||||||||
| Fourth |
59,872 | 5,833 | 3,410 | 3,390 | 2.58 | 2.56 | ||||||||||||||||||||||
| 2010 |
||||||||||||||||||||||||||||
| First |
$ | 44,821 | 3,990 | 2,112 | 2,098 | 1.41 | 1.40 | |||||||||||||||||||||
| Second |
45,686 | 6,194 | 4,183 | 4,164 | 2.79 | 2.77 | ||||||||||||||||||||||
| Third |
47,208 | 5,274 | 3,069 | 3,055 | 2.06 | 2.05 | ||||||||||||||||||||||
| Fourth |
51,726 | 4,292 | 2,053 | 2,041 | 1.40 | 1.39 | ||||||||||||||||||||||
| *Includes | excise taxes on petroleum products sales. |
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| Millions of Dollars Except Per Share Amounts | ||||||||||||||||||||
| 2011 | 2010 | 2009 | 2008 | 2007 | ||||||||||||||||
| Sales and other operating revenues |
$ | 244,813 | 189,441 | 149,341 | 240,842 | 187,437 | ||||||||||||||
| Net income (loss) |
12,502 | 11,417 | 4,492 | (16,279 | ) | 11,545 | ||||||||||||||
| Net income (loss) attributable to ConocoPhillips |
12,436 | 11,358 | 4,414 | (16,349 | ) | 11,458 | ||||||||||||||
| Per common share |
||||||||||||||||||||
| Basic |
9.04 | 7.68 | 2.96 | (10.73 | ) | 7.06 | ||||||||||||||
| Diluted |
8.97 | 7.62 | 2.94 | (10.73 | ) | 6.96 | ||||||||||||||
| Total assets |
153,230 | 156,314 | 152,138 | 142,865 | 177,094 | |||||||||||||||
| Long-term debt |
21,610 | 22,656 | 26,925 | 27,085 | 20,289 | |||||||||||||||
| Joint venture acquisition obligation— long-term |
3,582 | 4,314 | 5,009 | 5,669 | 6,294 | |||||||||||||||
| Cash dividends declared per common share |
2.64 | 2.15 | 1.91 | 1.88 | 1.64 | |||||||||||||||
Many factors can impact the comparability of this information, such as:
| • | The financial data for 2010 includes the impact of $5,803 million before-tax ($4,583 million after-tax) related to gains from asset dispositions and LUKOIL share sales. |
| • | The financial data for 2008 includes the impact of impairments related to goodwill and to our LUKOIL investment that together amount to $32,939 million before- and after-tax. |
| • | The financial data for 2007 includes the impact of a $4,588 million before-tax ($4,512 million after-tax) impairment related to the expropriation of our oil interests in Venezuela. |
See Management’s Discussion and Analysis of Financial Condition and Results of Operations and the Notes to Consolidated Financial Statements for a discussion of factors that will enhance an understanding of this data.
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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, 2011. 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, 2011.
Ernst & Young LLP has issued an audit report on the company’s internal control over financial reporting as of December 31, 2011, and their report is included herein.
| /s/ James J. Mulva | /s/ Jeff W. Sheets | |
| James J. Mulva | Jeff W. Sheets | |
| Chairman, President and | Senior Vice President, Finance | |
| Chief Executive Officer | and Chief Financial Officer | |
February 21, 2012
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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, 2011 and 2010, and the related consolidated statements of income, comprehensive income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2011. 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, 2011 and 2010, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2011, in conformity with U.S. generally accepted accounting principles.
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, 2011, 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 21, 2012 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Houston, Texas
February 21, 2012
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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, 2011, 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, 2011, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the 2011 consolidated financial statements of ConocoPhillips and our report dated February 21, 2012 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Houston, Texas
February 21, 2012
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| Consolidated Statement of Changes in Equity | ConocoPhillips
| |||||||||||||||||
| Millions of Dollars | ||||||||||||||||||||||||||||||||||||
| Attributable to ConocoPhillips | ||||||||||||||||||||||||||||||||||||
| Common Stock | Accum. Other Comprehensive Income (Loss) |
Unearned Employee Compensation |
Retained Earnings |
Noncontrolling Interests |
Total | |||||||||||||||||||||||||||||||
| Par Value |
Capital in Excess of Par |
Treasury Stock |
Grantor Trusts |
|||||||||||||||||||||||||||||||||
| December 31, 2008 |
$ | 17 | 43,396 | (16,211 | ) | (702 | ) | (1,875 | ) | (102 | ) | 30,642 | 1,100 | 56,265 | ||||||||||||||||||||||
| Net income |
4,414 | 78 | 4,492 | |||||||||||||||||||||||||||||||||
| Other comprehensive income |
4,940 | 4,940 | ||||||||||||||||||||||||||||||||||
| Cash dividends paid on company common stock |
(2,832 | ) | (2,832 | ) | ||||||||||||||||||||||||||||||||
| Distributions to noncontrolling interests and other |
(588 | ) | (588 | ) | ||||||||||||||||||||||||||||||||
| Distributed under benefit plans |
285 | 35 | 320 | |||||||||||||||||||||||||||||||||
| Recognition of unearned compensation |
26 | 26 | ||||||||||||||||||||||||||||||||||
| Other |
(10 | ) | (10 | ) | ||||||||||||||||||||||||||||||||
| December 31, 2009 |
17 | 43,681 | (16,211 | ) | (667 | ) | 3,065 | (76 | ) | 32,214 | 590 | 62,613 | ||||||||||||||||||||||||
| Net income |
11,358 | 59 | 11,417 | |||||||||||||||||||||||||||||||||
| Other comprehensive income |
1,708 | 1,708 | ||||||||||||||||||||||||||||||||||
| Cash dividends paid on company common stock |
(3,175 | ) | (3,175 | ) | ||||||||||||||||||||||||||||||||
| Repurchase of company common stock |
(3,866 | ) | (3,866 | ) | ||||||||||||||||||||||||||||||||
| Distributions to noncontrolling interests and other |
(102 | ) | (102 | ) | ||||||||||||||||||||||||||||||||
| Distributed under benefit plans |
451 | 34 | 485 | |||||||||||||||||||||||||||||||||
| Recognition of unearned compensation |
29 | 29 | ||||||||||||||||||||||||||||||||||
| December 31, 2010 |
17 | 44,132 | (20,077 | ) | (633 | ) | 4,773 | (47 | ) | 40,397 | 547 | 69,109 | ||||||||||||||||||||||||
| Net income |
12,436 | 66 | 12,502 | |||||||||||||||||||||||||||||||||
| Other comprehensive income (loss) |
(1,687 | ) | (1,687 | ) | ||||||||||||||||||||||||||||||||
| Cash dividends paid on company common stock |
(3,632 | ) | (3,632 | ) | ||||||||||||||||||||||||||||||||
| Repurchase of company common stock |
(11,133 | ) | 10 | (11,123 | ) | |||||||||||||||||||||||||||||||
| Distributions to noncontrolling interests and other |
(103 | ) | (103 | ) | ||||||||||||||||||||||||||||||||
| Distributed under benefit plans |
593 | 33 | 13 | 639 | ||||||||||||||||||||||||||||||||
| Recognition of unearned compensation |
36 | 36 | ||||||||||||||||||||||||||||||||||
| Transfer to treasury stock |
(610 | ) | 610 | — | ||||||||||||||||||||||||||||||||
| Other |
(7 | ) | (7 | ) | ||||||||||||||||||||||||||||||||
| December 31, 2011 |
$ | 17 | 44,725 | (31,787 | ) | — | 3,086 | (11 | ) | 49,194 | 510 | 65,734 | ||||||||||||||||||||||||
| 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. When we do not have the ability to exert significant influence, the investment is either classified as available-for-sale if fair value is readily determinable, or the cost method is used if fair value is not readily determinable. Undivided interests in oil and gas joint ventures, pipelines, natural gas plants and terminals are consolidated on a proportionate basis. Other securities and investments are generally carried at cost. |
| n | Foreign Currency Translation—Adjustments resulting from the process of translating foreign functional currency financial statements into U.S. dollars are included in accumulated other comprehensive income in common stockholders’ equity. Foreign currency transaction gains and losses are included in current earnings. Most of our foreign operations use their local currency as the functional currency. |
| n | 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, bitumen, natural gas, liquefied natural gas (LNG), natural gas liquids, petroleum and chemical products, and other items are recognized when title passes to the customer, which is when the risk of ownership passes to the purchaser and physical delivery of goods occurs, either immediately or within a fixed delivery schedule that is reasonable and customary in the industry. |
Revenues associated with producing properties in which we have an interest with other producers are recognized based on the actual volumes we sold during the period. Any differences between volumes sold and entitlement volumes, based on our net working interest, which are deemed to be nonrecoverable through remaining production, are recognized as accounts receivable or accounts payable, as appropriate. Cumulative differences between volumes sold and entitlement volumes are generally not significant.
Revenues associated with transactions commonly called buy/sell contracts, in which the purchase and sale of inventory with the same counterparty are entered into “in contemplation” of one another, are combined and reported net (i.e., on the same 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 90 days or less from their date of purchase. They are carried at cost plus accrued interest, which approximates fair value. |
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| n | Short-Term Investments—Investments in bank time deposits and marketable securities (commercial paper and government obligations) with original maturities of greater than 90 days but less than one year are classified as short-term investments. See Note 16—Financial Instruments and Derivative Contracts, for additional information on these held-to-maturity financial instruments. |
| n | Inventories—We have several valuation methods for our various types of inventories and consistently use the following methods for each type of inventory. Crude oil and petroleum products inventories are valued at the lower of cost or market in the aggregate, primarily on the last-in, first-out (LIFO) basis. Any necessary lower-of-cost-or-market write-downs at year end are recorded as permanent adjustments to the LIFO cost basis. LIFO is used to better match current inventory costs with current revenues and to meet tax-conformity requirements. Costs include both direct and indirect expenditures incurred in bringing an item or product to its existing condition and location, but not unusual/nonrecurring costs or research and development costs. Materials, supplies and other miscellaneous inventories, such as tubular goods and well equipment, are valued using 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—Derivative instruments are recorded on the balance sheet at fair value. If the right of offset exists and certain other criteria are met, derivative assets and liabilities with the same counterparty are netted on the balance sheet and the collateral payable or receivable is netted against derivative assets and derivative liabilities, respectively. |
Recognition and classification of the gain or loss that results from recording and adjusting a derivative to fair value depends on the purpose for issuing or holding the derivative. Gains and losses from derivatives not accounted for as hedges are recognized immediately in earnings. For derivative instruments that are designated and qualify as a fair value hedge, the gains or losses from adjusting the derivative to its fair value will be immediately recognized in earnings and, to the extent the hedge is effective, offset the concurrent recognition of changes in the fair value of the hedged item. Gains or losses from derivative instruments that are designated and qualify as a cash flow hedge or hedge of a net investment in a foreign entity are recognized in other comprehensive income and appear on the balance sheet in accumulated other comprehensive income until the hedged transaction is recognized in earnings; however, to the extent the change in the value of the derivative exceeds the change in the anticipated cash flows of the hedged transaction, the excess gains or losses will be recognized immediately in earnings.
| n | Oil and Gas Exploration and 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 (PP&E). Leasehold impairment is recognized based on exploratory experience and management’s judgment. Upon achievement of all conditions necessary for reserves to be classified as proved, the associated leasehold costs are reclassified to proved properties.
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Exploratory Costs—Geological and geophysical costs and the costs of carrying and retaining undeveloped properties are expensed as incurred. Exploratory well costs are capitalized, or “suspended,” on the balance sheet pending further evaluation of whether economically recoverable reserves have been found. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. If exploratory wells encounter potentially economic quantities of oil and gas, the well costs remain capitalized on the balance sheet as long as sufficient progress assessing the reserves and the economic and operating viability of the project is being made. For complex exploratory discoveries, it is not unusual to have exploratory wells remain suspended on the balance sheet for several years while we perform additional appraisal drilling and seismic work on the potential oil and gas field or while we seek government or co-venturer approval of development plans or seek environmental permitting. Once all required approvals and permits have been obtained, the projects are moved into the development phase, and the oil and gas resources are designated as proved reserves.
Management reviews suspended well balances quarterly, continuously monitors the results of the additional appraisal drilling and seismic work, and expenses the suspended well costs as dry holes when it judges the potential field does not warrant further investment in the near term. See Note 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. |
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| n | Depreciation and Amortization—Depreciation and amortization of PP&E on producing hydrocarbon properties and certain pipeline assets (those which are expected to have a declining utilization pattern), are determined by the unit-of-production method. Depreciation and amortization of all other PP&E 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—PP&E used in operations are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in the future cash flows expected to be generated by an asset group and annually in the fourth quarter following updates to corporate planning assumptions. If, upon review, the sum of the undiscounted pretax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value through additional amortization or depreciation provisions and reported as impairments in the periods in which the determination of the impairment is made. Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets—generally on a field-by-field basis for exploration and production assets, or at an entire complex level for downstream assets. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants or based on a multiple of operating cash flow validated with historical market transactions of similar assets where possible. Long-lived assets committed by management for disposal within one year are accounted for at the lower of amortized cost or fair value, less cost to sell, with fair value determined using a binding negotiated price, if available, or present value of expected future cash flows as previously described. |
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. For E&P assets, 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. Major refinery turnarounds are expensed as 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. |
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| n | Property Dispositions—When complete units of depreciable property are sold, the asset cost and related accumulated depreciation are eliminated, with any gain or loss reflected in the “Gain on dispositions” line of our consolidated income statement. When less than complete units of depreciable property are disposed of or retired, the difference between asset cost and salvage value is charged or credited to accumulated depreciation. |
| n | Asset Retirement Obligations and Environmental Costs—The 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 PP&E. Over time the liability is increased for the change in its present value, and the capitalized cost in PP&E is depreciated over the useful life of the related asset. For additional information, 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 relating to an existing condition caused by past operations, and those having no 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 indicating 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 income statement 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 have elected to recognize expense on a straight-line basis over the service period for the entire award, whether the award was granted with ratable or cliff vesting. |
| n | Income 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 Per Share of Common Stock—Basic net income per share of common stock is calculated based upon the daily weighted-average number of common shares outstanding during the |
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| year, including unallocated shares held by the stock savings feature of the ConocoPhillips Savings Plan. Also, this calculation includes fully vested stock and unit awards that have not been issued. Diluted net income per share of common stock includes the above, plus unvested stock, unit or option awards granted under our compensation plans and vested but unexercised stock options, but only to the extent these instruments dilute net income per share. For the purpose of the 2009 earnings per share calculation, net income attributable to ConocoPhillips was reduced by $12 million for the excess of the amount paid for the redemption of a noncontrolling interest over its carrying value, which was charged directly to retained earnings. Treasury stock and shares held by grantor trusts are excluded from the daily weighted-average number of common shares outstanding in both calculations. |
Note 2—Changes in Accounting Principles
Comprehensive Income
Effective December 31, 2011, we early adopted Financial Accounting Standards Board (FASB) Accounting Standards Update (ASU) No. 2011-05, “Presentation of Comprehensive Income.” This ASU amends FASB Accounting Standards Codification (ASC) Topic 220, “Comprehensive Income,” by requiring a more prominent presentation of the components of other comprehensive income. We elected the two-statement approach presenting other comprehensive income in a separate statement immediately following the income statement. On December 23, 2011, the FASB issued ASU 2011-12, “Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in ASU No. 2011-05.” ASU 2011-12 defers the ASU 2011-05 requirement to present items reclassified into net income from other comprehensive income. This deferral only impacted the presentation requirement on the consolidated income statement.
Note 3—Variable Interest Entities (VIEs)
We hold variable interests in VIEs that have not been consolidated because we are not considered the primary beneficiary. Information on our significant VIE follows:
We have an agreement with Freeport LNG Development, L.P. (Freeport LNG) to participate in an 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, 2011, was $612 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.
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Note 4—Inventories
Inventories at December 31 were:
| Millions of Dollars | ||||||||
| 2011 | 2010 | |||||||
| Crude oil and petroleum products |
$ | 3,633 | 4,254 | |||||
| Materials, supplies and other |
998 | 943 | ||||||
| $ | 4,631 | 5,197 | ||||||
Inventories valued on the LIFO basis totaled $3,387 million and $4,051 million at December 31, 2011 and 2010, respectively. The estimated excess of current replacement cost over LIFO cost of inventories amounted to approximately $8,400 million and $6,800 million at December 31, 2011 and 2010, respectively. In 2011, a liquidation of LIFO inventory values increased net income attributable to ConocoPhillips $160 million, of which $155 million was attributable to the R&M segment.
Note 5—Assets Held for Sale or Sold
In December 2011, we sold our ownership interests in Colonial Pipeline Company and Seaway Crude Pipeline Company. The total carrying value of these assets, which were included in our R&M segment, was $348 million, which included $104 million of investment in equity affiliates and $244 million of allocated goodwill. The $1,661 million before-tax gain on these dispositions was included in the “Gain on dispositions” line in the consolidated income statement.
In June 2010, we sold our 9.03 percent interest in the Syncrude Canada Ltd. joint venture for $4.6 billion. The $2.9 billion before-tax gain was included in the “Gain on dispositions” line of our consolidated income statement. At the time of disposition, Syncrude had a net carrying value of $1.75 billion, which included $1.97 billion of PP&E, and was included in the E&P segment.
In February 2012, we signed definitive agreements to sell our Vietnam E&P business for $1.29 billion, excluding customary working capital adjustments. The transaction is expected to close in the first half of 2012. At December 31, 2011, this business had a net carrying value of approximately $150 million, which included PP&E of $350 million.
See Note 6—Investments, Loans and Long-Term Receivables, for information on the disposition of our investment in OAO LUKOIL during 2010 and 2011.
Note 6—Investments, Loans and Long-Term Receivables
Components of investments, loans and long-term receivables at December 31 were:
| Millions of Dollars | ||||||||
| 2011 | 2010 | |||||||
| Equity investments |
$ | 30,985 | 30,055 | |||||
| Loans and advances—related parties |
1,675 | 2,180 | ||||||
| Long-term receivables |
559 | 922 | ||||||
| Other investments |
564 | 604 | ||||||
| $ | 33,783 | 33,761 | ||||||
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Equity Investments
Affiliated companies in which we had a significant equity investment at December 31, 2011, included:
| • | Australia Pacific LNG (APLNG)—42.5 percent owned joint venture with Origin Energy (42.5 percent) and China Petrochemical Corporation (Sinopec) (15 percent)—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 LP—50 percent owned business venture with Cenovus—owns the Wood River and Borger refineries, which process crude oil into refined products. |
| • | Qatar Liquefied Gas Company Limited 3 (QG3)—30 percent owned joint venture with affiliates of Qatar Petroleum (68.5 percent) and Mitsui & Co., Ltd. (1.5 percent)—produces and liquefies natural gas from Qatar’s North Field. |
| • | 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 includes LUKOIL until loss of significant influence):
| Millions of Dollars | ||||||||||||
| 2011 | 2010 | 2009 | ||||||||||
| Revenues |
$ | 77,263 | 105,589 | 128,881 | ||||||||
| Income before income taxes |
11,958 | 11,250 | 12,121 | |||||||||
| Net income |
11,089 | 9,495 | 9,145 | |||||||||
| Current assets |
21,530 | 14,039 | 36,139 | |||||||||
| Noncurrent assets |
76,300 | 79,411 | 126,163 | |||||||||
| Current liabilities |
9,708 | 9,325 | 22,483 | |||||||||
| Noncurrent liabilities |
22,993 | 24,412 | 30,960 | |||||||||
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, 2011, retained earnings included $2,814 million related to the undistributed earnings of affiliated companies. Dividends received from affiliates were $3,670 million, $2,282 million and $1,727 million in 2011, 2010 and 2009, respectively.
APLNG
In 2008, we closed on a transaction with Origin Energy, an integrated Australian energy company, to further enhance our long-term Australasian natural gas business. 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. Origin is the operator of APLNG’s production and pipeline system, while we will operate the LNG facility.
In April 2011, APLNG and Sinopec signed definitive agreements for APLNG to supply up to 4.3 million tonnes of LNG per year for 20 years. The agreements also specified terms under which Sinopec subscribed for a 15 percent equity interest in APLNG, with both our ownership interest and Origin Energy’s ownership interest diluting to 42.5 percent. The Subscription Agreement was completed in August 2011, and we recorded a loss on disposition of $279 million before- and after-tax from the dilution. The book value of
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our investment in APLNG was reduced by $795 million, and we reduced the currency translation adjustment associated with our investment by $516 million.
In November 2011, APLNG signed a binding Heads of Agreement with Japan-based Kansai Electric for the sale of approximately 1 million tonnes of LNG per year for 20 years. Under the terms of the agreement, Kansai Electric will be supplied LNG beginning in mid-2016. The agreement is also subject to a final investment decision on the second LNG train, which is expected in the first half of 2012.
In January 2012, APLNG and Sinopec signed an amendment to their existing LNG sales agreement for the sale and purchase of an additional 3.3 million tonnes of LNG per year through 2035, subject to a final investment decision on the second LNG train. This agreement, in combination with the Kansai Electric agreement, finalizes the marketing of the second train. In conjunction with the LNG sale, the parties have also agreed for Sinopec to subscribe for additional shares in APLNG, which will raise its equity interest from 15 percent to 25 percent. As a result, both our ownership interest and Origin Energy’s ownership interest would dilute from 42.5 percent to 37.5 percent. We expect to record a loss of approximately $135 million after-tax from the dilution.
At December 31, 2011, the book value of our equity method investment in APLNG was $9,467 million, which includes $2,716 million of cumulative translation effects due to a strengthening Australian dollar relative to the U.S. dollar. Our 42.5 percent share of the historical cost basis net assets of APLNG on its books under U.S. generally accepted accounting principles was $2,380 million, resulting in a basis difference of $7,087 million on our books. The amortizable portion of the basis difference, $5,192 million associated with PP&E, 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 2011, 2010 and 2009 was after-tax expense of $17 million, $5 million and $4 million, respectively, representing the amortization of this basis difference on currently producing licenses.
FCCL and WRB
We have two 50/50 North American heavy oil business ventures with Cenovus Energy Inc.: FCCL Partnership, a Canadian upstream general partnership, and WRB Refining LP, a U.S. downstream limited partnership. We use the equity method of accounting for both entities, with the operating results of our investment in FCCL reflecting the use of the successful efforts method of accounting for oil and gas exploration and development activities.
At December 31, 2011, the book value of our investment in FCCL was $9,044 million. FCCL’s operating assets consist of the Foster Creek and Christina Lake steam-assisted gravity drainage bitumen projects, both located in the eastern flank of the Athabasca oil sands in northeastern Alberta. Cenovus is the operator and managing partner of FCCL. We are obligated to contribute $7.5 billion, plus accrued interest, to FCCL over a 10-year period that began in 2007. For additional information on this obligation, see Note 13—Joint Venture Acquisition Obligation.
At December 31, 2011, the book value of our investment in WRB was $3,722 million. WRB’s operating assets consist of the Wood River and Borger refineries, located in Roxana, Illinois, and Borger, Texas, respectively. As a result of our contribution of these two assets to WRB, a basis difference was created due to the fair value of the contributed assets recorded by WRB exceeding their historical book value. The difference is primarily amortized and recognized as a benefit evenly over a period of 26 years, which was the estimated remaining useful life of the refineries’ PP&E at the closing date. The basis difference at
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December 31, 2011, was $3,918 million. Equity earnings in 2011, 2010 and 2009 were increased by $185 million, $243 million and $209 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.
QG3
QG3 is a joint venture that owns an integrated large-scale LNG project located in Qatar. We provided project financing, with a current outstanding balance of $1,159 million as described below under “Loans and Long-term Receivables.” At December 31, 2011, the book value of our equity method investment in QG3 was $931 million. We have terminal and pipeline use agreements with Golden Pass LNG Terminal and affiliated Golden Pass Pipeline near Port Arthur, Texas, in which we have a 12.4 percent interest, intended to provide us with terminal and pipeline capacity for the receipt, storage and regasification of LNG purchased from QG3. However, currently the LNG from QG3 is being sold to markets outside of the United States.
DCP Midstream
DCP Midstream owns and operates gas plants, gathering systems, storage facilities and fractionation plants. At December 31, 2011, the book value of our equity method investment in DCP Midstream was $927 million. DCP Midstream markets a portion of its natural gas liquids to us and CPChem under a supply agreement that continues at the current volume commitment with a primary term ending December 31, 2014. This purchase commitment is on an “if-produced, will-purchase” basis and so has no fixed production schedule, but has had, and is expected over the remaining term of the contract to have, a relatively stable purchase pattern. Natural gas liquids are purchased under this agreement at various published market index prices, less transportation and fractionation fees.
CPChem
CPChem manufactures and markets petrochemicals and plastics. At December 31, 2011, the book value of our equity method investment in CPChem was $2,998 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.
In anticipation of the separation of our downstream businesses (including CPChem), we reached agreement with Chevron Corporation regarding CPChem that provides for CPChem to: (i) prior to the separation, suspend all cash distributions to its owners and accumulate its excess cash; and (ii) after the separation, use the accumulated cash and its excess cash flow to pay down $1 billion of its outstanding fixed-rate bonds on an accelerated basis. During this period of bond repayment, CPChem is not required to make any cash distributions to its owners.
LUKOIL
LUKOIL is an integrated energy company headquartered in Russia. We completed the disposition of our interest in LUKOIL during the first quarter of 2011, realizing a before-tax gain of $360 million, which was included in the “Gain on dispositions” line of our consolidated income statement, and cash proceeds of $1,243 million. Our ownership interest was 2.25 percent at December 31, 2010, and 20 percent at December 31, 2009.
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On July 28, 2010, we announced our intention to sell our entire interest in LUKOIL, then consisting of 163.4 million shares. This decision was implemented as follows:
| • | On July 28, 2010, we entered into a stock purchase and option agreement (the Agreement) with a wholly owned subsidiary of LUKOIL, pursuant to which such subsidiary purchased 64.6 million shares from us at a price of $53.25 per share, or $3,442 million in total. This transaction closed on August 16, 2010. |
| • | Also pursuant to the Agreement, the LUKOIL subsidiary had a 60-day option, expiring on September 26, 2010, to purchase any or all of our interest remaining at the time of exercise of the option, at a price of $56 per share. Upon exercise of this option, we sold 42.5 million shares on September 29, 2010, for proceeds of $2,380 million. |
| • | Finally, we sold our remaining shares in the open market subject to the terms of the Shareholder Agreement, with the final disposition of all shares occurring in the first quarter of 2011. The cost basis for shares sold was average cost. |
During the third quarter of 2010, our ownership interest declined to a level at which we were no longer able to exercise significant influence over the operating and financial policies of LUKOIL. Accordingly, at the end of the third quarter of 2010, we stopped applying the equity method of accounting for our remaining investment in LUKOIL, and we reclassified the investment from “Investments and long-term receivables” to current assets on our consolidated balance sheet as an available-for-sale equity security.
In total, during 2010, we sold 151 million shares of LUKOIL for $8,345 million, realizing a before-tax gain on disposition of $1,749 million, which was included in the “Gain on dispositions” line of our consolidated income statement. Included in these amounts were sales proceeds of $1,793 million and a realized before-tax gain of $437 million incurred subsequent to classifying the investment as available-for-sale. The cost basis for shares sold is average cost.
At December 31, 2010, our then remaining investment in LUKOIL was carried at fair value of $1,083 million, reflecting a closing price of LUKOIL American Depositary Receipts (ADRs) on the London Stock Exchange of $56.50 per share. The carrying value reflected a pre-tax unrealized gain over our cost basis of $247 million. This unrealized gain, net of related income taxes, was reported as a component of accumulated other comprehensive income. The fair value was categorized as Level 1 in the fair value hierarchy.
While applying the equity method of accounting, a negative basis difference existed which was primarily amortized on a straight-line basis over a 22-year useful life as an increase to equity earnings. Equity earnings in 2010 and 2009 were increased $155 million and $157 million, respectively, due to amortization of this basis difference.
Loans and Long-term Receivables
As part of our normal ongoing business operations and consistent with industry practice, we enter into numerous agreements with other parties to pursue business opportunities. Included in such activity are loans and long-term receivables to certain affiliated and non-affiliated companies. Loans are recorded when cash is transferred or seller financing is provided to the affiliated or non-affiliated company pursuant to a loan agreement. The loan balance will increase as interest is earned on the outstanding loan balance and will decrease as interest and principal payments are received. Interest is earned at the loan agreement’s stated interest rate. Loans and long-term receivables are assessed for impairment when events indicate the loan balance may not be fully recovered.
At December 31, 2011, significant loans to affiliated companies include the following:
| • | $612 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 |
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| 2008 and is required to continue making repayments through full repayment of the loan in 2026. Repayment by Freeport is supported by “process-or-pay” capacity service payments made by us to Freeport under our terminal use agreement. |
| • | $1,159 million in project financing to QG3. We own a 30 percent interest in QG3, for which we use the equity method of accounting. The other participants in the project are affiliates of Qatar Petroleum and Mitsui. QG3 secured project financing of $4.0 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. On December 15, 2011, QG3 achieved financial completion and all project loan facilities became nonrecourse to the project participants. Bi-annual repayments began in January 2011 and will extend through July 2022. |
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.”
WRB Refining LP fully repaid its outstanding loans from us with payments of $550 million in 2011.
In November 2011, a long-term loan to a non-affiliated company related to seller financing of U.S. retail marketing assets was refinanced, which resulted in a receipt of $365 million. As part of the refinancing, we provided loan guarantees in support of $191 million of the total refinancing.
Long-term receivables and the long-term portion of these loans are included in the “Investments and long-term receivables” line on the consolidated balance sheet, while the short-term portion related to non-affiliate loans is in “Accounts and notes receivable.”
Other
We have investments remeasured at fair value on a recurring basis to support certain nonqualified deferred compensation plans. The fair value of these assets at December 31, 2011, was $336 million, and at December 31, 2010, was $325 million. Substantially the entire value is categorized in Level 1 of the fair value hierarchy. These investments are measured at fair value using a market approach based on quotations from national securities exchanges.
Merey Sweeny, L.P. (MSLP) owns a delayed coker and related facilities at the Sweeny Refinery. MSLP processes our long residue, which is produced from heavy sour crude oil, for a processing fee. Fuel-grade petroleum coke is produced as a by-product and becomes the property of MSLP. Prior to August 28, 2009, MSLP was owned 50/50 by us and Petróleos de Venezuela S.A. (PDVSA). Under the agreements that govern the relationships between the partners, certain defaults by PDVSA with respect to supply of crude oil to the Sweeny Refinery gave us the right to acquire PDVSA’s 50 percent ownership interest in MSLP, which we exercised on August 28, 2009. PDVSA has initiated arbitration with the International Chamber of Commerce challenging the exercise of the call right and claiming it was invalid. The arbitral tribunal is scheduled to hold hearings on the merits of the dispute in December 2012. We continue to use the equity method of accounting for our investment in MSLP.
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Note 7—Properties, Plants and Equipment
PP&E is 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 | ||||||||||||||||||||||||||
| 2011 | 2010 | |||||||||||||||||||||||||
| Gross PP&E |
Accum. DD&A |
Net PP&E |
Gross PP&E |
Accum. DD&A |
Net PP&E |
|||||||||||||||||||||
| E&P |
$ | 124,111 | 55,565 | 68,546 | 116,805 | 50,501 | 66,304 | |||||||||||||||||||
| Midstream |
135 | 86 | 49 | 128 | 80 | 48 | ||||||||||||||||||||
| R&M |
22,096 | 8,128 | 13,968 | 23,579 | 8,999 | 14,580 | ||||||||||||||||||||
| LUKOIL Investment |
— | — | — | — | — | — | ||||||||||||||||||||
| Chemicals |
— | — | — | — | — | — | ||||||||||||||||||||
| Emerging Businesses |
1,023 | 220 | 803 | 981 | 161 | 820 | ||||||||||||||||||||
| Corporate and Other |
1,844 | 1,030 | 814 | 1,732 | 930 | 802 | ||||||||||||||||||||
| $ | 149,209 | 65,029 | 84,180 | 143,225 | 60,671 | 82,554 | ||||||||||||||||||||
Note 8—Suspended Wells
The following table reflects the net changes in suspended exploratory well costs during 2011, 2010 and 2009:
| Millions of Dollars | ||||||||||||
| 2011 | 2010 | 2009 | ||||||||||
| Beginning balance at January 1 |
$ | 1,013 | 908 | 660 | ||||||||
| Additions pending the determination of proved reserves |
96 | 216 | 342 | |||||||||
| Reclassifications to proved properties |
(72 | ) | (106 | ) | (39 | ) | ||||||
| Sales of suspended well investment |
— | (4 | ) | (21 | ) | |||||||
| Charged to dry hole expense |
— | (1 | ) | (34 | ) | |||||||
| Ending balance at December 31 |
$ | 1,037 | 1,013 | 908 | ||||||||
The following table provides an aging of suspended well balances at December 31, 2011, 2010 and 2009:
| Millions of Dollars | ||||||||||||
| 2011 | 2010 | 2009 | ||||||||||
| Exploratory well costs capitalized for a period of one year or less |
$ | 115 | 220 | 319 | ||||||||
| Exploratory well costs capitalized for a period greater than one year |
922 | 793 | 589 | |||||||||
| Ending balance |
$ | 1,037 | 1,013 | 908 | ||||||||
| Number of projects that have exploratory well costs that have been capitalized for a period greater than one year |
40 | 40 | 34 | |||||||||
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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, 2011:
| Millions of Dollars | ||||||||||||||||
| Total | Suspended Since | |||||||||||||||
| Project | 2008-2010 | 2005-2007 | 2001-2004 | |||||||||||||
| Aktote—Kazakhstan (2) |
$ | 19 | — | — | 19 | |||||||||||
| Alpine Satellite—Alaska (2) |
21 | — | — | 21 | ||||||||||||
| Browse Basin—Australia (1) |
216 | 216 | — | — | ||||||||||||
| Caldita/Barossa—Australia (1) |
77 | — | 77 | — | ||||||||||||
| Fiord West—Alaska (2) |
16 | 16 | — | — | ||||||||||||
| Harrison—U.K. (2) |
15 | — | 15 | — | ||||||||||||
| Kairan—Kazakhstan (2) |
27 | — | 14 | 13 | ||||||||||||
| Kalamkas—Kazakhstan (1) |
14 | 5 | 5 | 4 | ||||||||||||
| Kashagan—Kazakhstan (1) |
44 | 19 | 15 | 10 | ||||||||||||
| Malikai—Malaysia (2) |
52 | — | 40 | 12 | ||||||||||||
| NPR-A—Alaska (2) |
17 | 17 | — | — | ||||||||||||
| Petai—Malaysia (2) |
30 | 19 | 11 | — | ||||||||||||
| Point Thomson—Alaska (2) |
37 | 37 | — | — | ||||||||||||
| Rak More—Kazakhstan (1) |
22 | 22 | — | — | ||||||||||||
| Saleski—Canada (1) |
14 | 14 | — | — | ||||||||||||
| Shenandoah—Lower 48 (1) |
43 | 43 | — | — | ||||||||||||
| Sunrise 3—Australia (2) |
13 | 13 | — | — | ||||||||||||
| Surmont III and beyond—Canada (1) |
26 | 6 | 18 | 2 | ||||||||||||
| Su tu Nau—Vietnam (2) |
18 | 9 | 9 | — | ||||||||||||
| Thornbury—Canada (1) |
19 | 19 | — | — | ||||||||||||
| Tiber—Lower 48 (1) |
40 | 40 | — | — | ||||||||||||
| Titan—Norway (2) |
11 | 11 | — | — | ||||||||||||
| Ubah—Malaysia (2) |
34 | 34 | — | — | ||||||||||||
| Uge—Nigeria (1) |
29 | 15 | 14 | — | ||||||||||||
| Sixteen projects of $10 million or less each (1)(2) |
68 | 34 | 32 | 2 | ||||||||||||
| Total of 40 projects |
$ | 922 | 589 | 250 | 83 | |||||||||||
| (1) | Additional appraisal wells planned. |
| (2) | Appraisal drilling complete; costs being incurred to assess development. |
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Note 9—Goodwill and Intangibles
Goodwill
Changes in the carrying amount of goodwill were as follows:
| Millions of Dollars | ||||||||||||||||||||||||||
| 2011 | 2010 | |||||||||||||||||||||||||
| E&P | R&M | Total | E&P | R&M | Total | |||||||||||||||||||||
| Balance as of January 1 |
||||||||||||||||||||||||||
| Goodwill |
$ | 25,443 | 3,633 | 29,076 | 25,443 | 3,638 | 29,081 | |||||||||||||||||||
| Accumulated impairment losses |
(25,443 | ) | — | (25,443 | ) | (25,443 | ) | — | (25,443 | ) | ||||||||||||||||
| — | 3,633 | 3,633 | — | 3,638 | 3,638 | |||||||||||||||||||||
| Goodwill allocated to assets held for sale or sold |
— | (273 | ) | (273 | ) | — | — | — | ||||||||||||||||||
| Tax and other adjustments |
— | (28 | ) | (28 | ) | — | (5 | ) | (5 | ) | ||||||||||||||||
| Balance as of December 31 |
||||||||||||||||||||||||||
| Goodwill |
25,443 | 3,332 | 28,775 | 25,443 | 3,633 | 29,076 | ||||||||||||||||||||
| Accumulated impairment losses |
(25,443 | ) | — | (25,443 | ) | (25,443 | ) | — | (25,443 | ) | ||||||||||||||||
| $ | — | 3,332 | 3,332 | — | 3,633 | 3,633 | ||||||||||||||||||||
Intangible Assets
Information at December 31 on the carrying value of intangible assets follows:
| Millions of Dollars | ||||||||
| Gross Carrying Amount | ||||||||
| 2011 | 2010 | |||||||
| Indefinite-Lived Intangible Assets |
||||||||
| Trade names and trademarks |
$ | 494 | 494 | |||||
| Refinery air and operating permits |
207 | 245 | ||||||
| $ | 701 | 739 | ||||||
At year-end 2011, our amortized intangible asset balance was $44 million, compared with $62 million at year-end 2010. Amortization expense was not material for 2011 and 2010, and is not expected to be material in future years.
Note 10—Impairments
During 2011, 2010 and 2009, we recognized the following before-tax impairment charges:
| Millions of Dollars | ||||||||||||
| 2011 | 2010 | 2009 | ||||||||||
| E&P |
||||||||||||
| United States |
$ | 72 | 25 | 5 | ||||||||
| International |
216 | 56 | 463 | |||||||||
| R&M |
||||||||||||
| United States |
470 | 52 | 63 | |||||||||
| International |
2 | 1,616 | 3 | |||||||||
| Emerging Businesses |
— | 31 | — | |||||||||
| Corporate |
32 | — | 1 | |||||||||
| $ | 792 | 1,780 | 535 | |||||||||
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2011
In 2011, we recorded a $467 million impairment of our refinery and associated pipelines and terminals in Trainer, Pennsylvania. In September 2011, we announced plans to seek a buyer for the refinery and have idled the facility. If unable to sell the refinery, we expect to permanently close the plant by the end of the first quarter of 2012. Additionally, we recorded property impairments of $288 million in our E&P segment, primarily as a result of lower natural gas price assumptions and reduced volume forecasts.
2010
During 2010, we recorded a $1,514 million impairment of our refinery in Wilhelmshaven, Germany, due to canceled plans for a project to upgrade the refinery, as well as a $98 million impairment as a result of our decision to end our participation in a new refinery project in Yanbu Industrial City, Saudi Arabia. We also recorded various property impairments of $81 million in our E&P segment.
2009
During 2009, we recorded property impairments of $417 million in our E&P segment, primarily as a result of lower natural gas price assumptions, reduced volume forecasts, and higher royalty, operating costs and capital expenditure assumptions. Additionally, we recorded a noncash charge of $51 million before- and after-tax related to the full impairment of our exploration and production investments in Ecuador, due to their expropriation. An arbitration hearing on case merits occurred in March 2011, and the arbitration process is ongoing. Property impairments of $66 million in our R&M segment, primarily associated with planned asset dispositions, were also recorded during 2009.
Fair Value Remeasurements
The following table shows the values of assets, by major category, measured at fair value on a nonrecurring basis in periods subsequent to their initial recognition:
| Millions of Dollars | ||||||||||||||||||||
| Fair Value Measurements Using |
||||||||||||||||||||
| Fair Value * | Level 1 Inputs |
Level 3 Inputs |
Before-Tax Loss | |||||||||||||||||
| Year ended December 31, 2011 |
||||||||||||||||||||
| Net PP&E (held for use) |
$ | 162 | — | 162 | 265 | |||||||||||||||
| Equity method investments |
274 | — | 274 | 399 | ||||||||||||||||
| Cost method investments |
2 | 2 | — | 8 | ||||||||||||||||
| Year ended December 31, 2010 |
||||||||||||||||||||
| Net PP&E (held for use) |
$ | 307 | — | 307 | 1,604 | ** | ||||||||||||||
| Net PP&E (held for sale) |
23 | 5 | 18 | 43 | ||||||||||||||||
| Equity method investments |
735 | — | 735 | 645 | ||||||||||||||||
| *Represents | the fair value at the time of the impairment. |
| **Includes | a $55 million leasehold impairment charged to exploration expenses. |
2011
During 2011, net PP&E held for use with a carrying amount of $427 million was written down to a fair value of $162 million, resulting in a before-tax loss of $265 million. The fair values were determined by the use of internal discounted cash flow models using estimates of future production, prices, costs and a discount rate believed to be consistent with those used by principal market participants and cash flow multiples for similar assets and alternative use.
Also during 2011, certain equity method investments were determined to have fair values below their carrying amount, and the impairments were considered to be other than temporary. This primarily included
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an investment associated with our E&P segment with a book value of $651 million, which was written down to its fair value of $256 million, resulting in a charge of $395 million before-tax. This was included in the “Equity in earnings of affiliates” line of our consolidated income statement. The fair value was determined by the application of an internal discounted cash flow model using estimates of future production, prices, costs and a discount rate believed to be consistent with those used by principal market participants. In addition, the fair value was determined by the comparison of market data for certain similar undeveloped properties.
2010
During 2010, net PP&E held for use with a carrying amount of $1,911 million was written down to a fair value of $307 million, resulting in a before-tax loss of $1,604 million. The fair values were determined by the use of internal discounted cash flow models using estimates of future production, prices, costs and a discount rate believed to be consistent with those used by principal market participants and cash flow multiples for similar assets and alternative use.
Also during 2010, net PP&E held for sale with a carrying amount of $64 million was written down to a fair value of $23 million less cost to sell of $2 million for a net $21 million, resulting in a before-tax loss of $43 million. The fair values were primarily determined by binding negotiated selling prices with third parties, with some adjusted for the fair value of certain liabilities retained.
In addition, an equity method investment associated with our E&P segment was determined to have a fair value below carrying amount, and the impairment was considered to be other than temporary. This investment with a book value of $1,380 million was written down to its fair value of $735 million, resulting in a charge of $645 million before-tax, which was included in the “Equity in earnings of affiliates” line of our consolidated income statement. The fair value was determined by the application of an internal discounted cash flow model using estimates of future production, prices, costs and a discount rate believed to be consistent with those used by principal market participants. In addition, the equity investment fair value was determined by the comparison of market data for certain similar undeveloped properties.
Note 11—Asset Retirement Obligations and Accrued Environmental Costs
Asset retirement obligations and accrued environmental costs at December 31 were:
| Millions of Dollars | ||||||||
| 2011 | 2010 | |||||||
| Asset retirement obligations |
$ | 8,920 | 8,776 | |||||
| Accrued environmental costs |
922 | 994 | ||||||
| Total asset retirement obligations and accrued environmental costs |
9,842 | 9,770 | ||||||
| Asset retirement obligations and accrued environmental costs due within one year* |
(513 | ) | (571 | ) | ||||
| Long-term asset retirement obligations and accrued environmental costs |
$ | 9,329 | 9,199 | |||||
| *Classified | as a current liability on the balance sheet, under the caption “Other accruals.” |
Asset Retirement Obligations
We record the fair value of a liability for an asset retirement obligation when it is incurred (typically when the asset is installed at the production location). When the liability is initially recorded, we capitalize the associated asset retirement cost by increasing the carrying amount of the related PP&E. 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.
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Our largest individual obligations involve plugging and abandonment of wells, removal and disposal of offshore oil and gas platforms around the world, oil and gas production facilities and pipelines in Alaska, and asbestos abatement at refineries.
During 2011 and 2010, our overall asset retirement obligation changed as follows:
| Millions of Dollars | ||||||||
| 2011 | 2010 | |||||||
| Balance at January 1 |
$ | 8,776 | 8,295 | |||||
| Accretion of discount |
435 | 422 | ||||||
| New obligations |
153 | 64 | ||||||
| Changes in estimates of existing obligations |
29 | 744 | ||||||
| Spending on existing obligations |
(327 | ) | (314 | ) | ||||
| Property dispositions |
(60 | ) | (394 | ) | ||||
| Foreign currency translation |
(86 | ) | (41 | ) | ||||
| Balance at December 31 |
$ | 8,920 | 8,776 | |||||
Accrued Environmental Costs
Total accrued environmental costs at December 31, 2011 and 2010, were $922 million and $994 million, respectively. The 2011 decrease in total accrued environmental costs is due to payments and settlements during the year exceeding new accruals, accrual adjustments and accretion.
We had accrued environmental costs of $571 million and $624 million at December 31, 2011 and 2010, 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 $274 million and $278 million of environmental costs associated with nonoperator sites at December 31, 2011 and 2010, respectively. In addition, $77 million and $92 million were included at both December 31, 2011 and 2010, respectively, where the company has been named a potentially responsible party under the Federal Comprehensive Environmental Response, Compensation and Liability Act, or similar state laws. Accrued environmental liabilities are expected to be paid over periods extending up to 30 years.
Because a large portion of the accrued environmental costs were acquired in various business combinations, they are discounted obligations. Expected expenditures for acquired environmental obligations are discounted using a weighted-average 5 percent discount factor, resulting in an accrued balance for acquired environmental liabilities of $427 million at December 31, 2011. The expected future undiscounted payments related to the portion of the accrued environmental costs that have been discounted are: $58 million in 2012, $44 million in 2013, $22 million in 2014, $19 million in 2015, $20 million in 2016, and $373 million for all future years after 2016.
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Note 12—Debt
Long-term debt at December 31 was:
| Millions of Dollars | ||||||||
| 2011 | 2010 | |||||||
| 9.375% Notes due 2011 |
$ | — | 328 | |||||
| 9.125% Debentures due 2021 |
150 | 150 | ||||||
| 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 |
7 | 15 | ||||||
| 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 | ||||||
| 6.65% Debentures due 2018 |
297 | 297 | ||||||
| 6.50% Notes due 2011 |
— | 500 | ||||||
| 6.50% Notes due 2039 |
2,250 | 2,250 | ||||||
| 6.50% Notes due 2039 |
500 | 500 | ||||||
| 6.00% Notes due 2020 |
1,000 | 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 | 2,250 | ||||||
| 5.625% Notes due 2016 |
1,250 | 1,250 | ||||||
| 5.50% Notes due 2013 |
750 | 750 | ||||||
| 5.20% Notes due 2018 |
500 | 500 | ||||||
| 4.75% Notes due 2012 |
897 | 897 | ||||||
| 4.75% Notes due 2014 |
1,500 | 1,500 | ||||||
| 4.60% Notes due 2015 |
1,500 | 1,500 | ||||||
| 4.40% Notes due 2013 |
400 | 400 | ||||||
| Commercial paper at 0.34% – 0.341% at year-end 2011 and 0.14% – 0.34% at year-end 2010 |
1,128 | 1,182 | ||||||
| Industrial Development Bonds due 2012 through 2038 at 0.08% – 5.75% at year-end 2011 and 0.33% – 5.75% at year-end 2010 |
252 | 252 | ||||||
| Guarantee of savings plan bank loan payable due 2015 at 2.29% at year-end 2011 and 2.06% at year-end 2010 |
15 | 64 | ||||||
| Note payable to Merey Sweeny, L.P. due 2020 at 7% (related party) |
133 | 144 | ||||||
| Marine Terminal Revenue Refunding Bonds due 2031 at 0.08% – 0.15% at year-end 2011 and 0.33% – 0.48% at year-end 2010 |
265 | 265 | ||||||
| Other |
28 | 31 | ||||||
| Debt at face value |
22,143 | 23,096 | ||||||
| Capitalized leases |
31 | 39 | ||||||
| Net unamortized premiums and discounts |
449 | 457 | ||||||
| Total debt |
22,623 | 23,592 | ||||||
| Short-term debt |
(1,013 | ) | (936 | ) | ||||
| Long-term debt |
$ | 21,610 | 22,656 | |||||
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Maturities of long-term borrowings, inclusive of net unamortized premiums and discounts, in 2012 through 2016 are: $1,013 million, $1,275 million, $1,527 million, $1,571 million and $2,364 million, respectively. At December 31, 2011, we classified $1,058 million of short-term debt as long-term debt, based on our ability and intent to refinance the obligation on a long-term basis under our revolving credit facilities.
During 2011, the following debt instruments were repaid at their maturity:
| • | The $328 million 9.375% Debentures due 2011. |
| • | The $500 million 6.50% Notes due 2011. |
In August 2011, we increased our revolving credit facilities from $7.85 billion to $8.0 billion by replacing our $7.35 billion revolving credit facility with a $7.5 billion facility expiring in August 2016. We also have 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, 2011 and 2010, 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 $1,128 million of commercial paper outstanding at December 31, 2011, compared with $1,182 million at December 31, 2010. Since we had $1,128 million of commercial paper outstanding and had issued $40 million of letters of credit, we had access to $6.8 billion in borrowing capacity under our revolving credit facilities at December 31, 2011.
Note 13—Joint Venture Acquisition Obligation
In 2007, we closed on a business venture with Cenovus. As a part of the transaction, we are obligated to contribute $7.5 billion, plus interest, over a 10-year period that began in 2007, to the upstream business venture, FCCL Partnership, formed as a result of the transaction.
Quarterly principal and interest payments of $237 million began in the second quarter of 2007, and will continue until the balance is paid. Of the principal obligation amount, $732 million was short-term and was included in the “Accounts payable—related parties” line on our December 31, 2011, consolidated balance sheet. The principal portion of these payments, which totaled $695 million in 2011, is included in the “Other” line in the financing activities section of our consolidated statement of cash flows. Interest accrues at a fixed annual rate of 5.3 percent on the unpaid principal balance. Fifty percent of the quarterly interest payment is reflected as a capital contribution and is included in the “Capital expenditures and investments” line on our consolidated statement of cash flows.
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Note 14—Guarantees
At December 31, 2011, 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. Effective December 15, 2011, the project achieved financial completion, the financing became nonrecourse to ConocoPhillips and our guarantee was released.
Guarantees of Joint Venture Debt
At December 31, 2011, we had guarantees outstanding for our portion of joint venture debt obligations, which have terms of up to 24 years. The maximum potential amount of future payments under the guarantees is approximately $100 million. Payment would be required if a joint venture defaults on its debt obligations.
Other Guarantees
| • | In conjunction with our purchase of an 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 5 to 20 years. Our maximum potential amount of future payments, or cost of volume delivery, under these guarantees is estimated to be $1,261 million ($2,820 million in the event of intentional or reckless breach) at December 2011 exchange rates based on our 42.5 percent share of the remaining contracted volumes, which could become payable if APLNG fails to meet its obligations under these agreements and the obligations cannot otherwise be mitigated. Future payments are considered unlikely, as the payments, or cost of volume delivery, would only be triggered if APLNG does not have enough natural gas to meet these sales commitments and if the co-venturers do not make necessary equity contributions into APLNG. Additionally, we have guaranteed the performance of APLNG with regard to certain contracts executed in connection with APLNG’s issuance of the Train 1 Notice to Proceed. Our maximum potential amount of future payments related to these guarantees is estimated to be $171 million at December 2011 exchange rates based on our 42.5 percent ownership in APLNG. |
| • | We have other guarantees with maximum future potential payment amounts totaling $450 million, which consist primarily of guarantees to fund the short-term cash liquidity deficits of certain joint ventures, a guarantee of minimum charter revenue for two LNG vessels, one small construction completion guarantee, guarantees relating to the startup of a refining joint venture, guarantees of the lease payment obligations of a joint venture, guarantees of the residual value of leased corporate aircraft, and guarantees of the performance of a business partner or some of its customers. These guarantees generally extend up to 13 years or life of the venture. |
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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, 2011, was $362 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 $218 million of environmental accruals for known contamination that are included in asset retirement obligations and accrued environmental costs at December 31, 2011. For additional information about environmental liabilities, see Note 15—Contingencies and Commitments.
Note 15—Contingencies and Commitments
A number of lawsuits involving a variety of claims have been made against ConocoPhillips that arise in the ordinary course of business. We also may be required to remove or mitigate the effects on the environment of the placement, storage, disposal or release of certain chemical, mineral and petroleum substances at various active and inactive sites. We regularly assess the need for accounting recognition or disclosure of these contingencies. In the case of all known contingencies (other than those related to income taxes), we accrue a liability when the loss is probable and the amount is reasonably estimable. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. We do not reduce these liabilities for potential insurance or third-party recoveries. If applicable, we accrue receivables for probable insurance or other third-party recoveries. In the case of income-tax-related contingencies, we use a cumulative probability-weighted loss accrual in cases where sustaining a tax position is less than certain. See Note 20—Income Taxes, for additional information about income-tax-related contingencies.
Based on currently available information, we believe it is remote that future costs related to known contingent liability exposures will exceed current accruals by an amount that would have a material adverse impact on our consolidated financial statements. As we learn new facts concerning contingencies, we reassess our position both with respect to accrued liabilities and other potential exposures. Estimates particularly sensitive to future changes include contingent liabilities recorded for environmental remediation, tax and legal matters. Estimated future environmental remediation costs are subject to change due to such factors as the uncertain magnitude of cleanup costs, the unknown time and extent of such remedial actions that may be required, and the determination of our liability in proportion to that of other responsible parties. Estimated future costs related to tax and legal matters are subject to change as events evolve and as additional information becomes available during the administrative and litigation processes.
Environmental
We are subject to international, federal, state and local environmental laws and regulations. When we prepare our consolidated financial statements, we record accruals for environmental liabilities based on management’s best estimates, using all information that is available at the time. We measure estimates and base liabilities on currently available facts, existing technology, and presently enacted laws and regulations, taking into account stakeholder and business considerations. When measuring environmental liabilities, we
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also consider our prior experience in remediation of contaminated sites, other companies’ cleanup experience, and data released by the U.S. Environmental Protection Agency (EPA) or other organizations. We consider unasserted claims in our determination of environmental liabilities, and we accrue them in the period they are both probable and reasonably estimable.
Although liability of those potentially responsible for environmental remediation costs is generally joint and several for federal sites and frequently so for state sites, we are usually only one of many companies cited at a particular site. Due to the joint and several liabilities, we could be responsible for all cleanup costs related to any site at which we have been designated as a potentially responsible party. We have been successful to date in sharing cleanup costs with other financially sound companies. Many of the sites at which we are potentially responsible are still under investigation by the EPA or the state agencies concerned. Prior to actual cleanup, those potentially responsible normally assess the site conditions, apportion responsibility and determine the appropriate remediation. In some instances, we may have no liability or may attain a settlement of liability. Where it appears that other potentially responsible parties may be financially unable to bear their proportional share, we consider this inability in estimating our potential liability, and we adjust our accruals accordingly. As a result of various acquisitions in the past, we assumed certain environmental obligations. Some of these environmental obligations are mitigated by indemnifications made by others for our benefit and some of the indemnifications are subject to dollar limits and time limits.
We are currently participating in environmental assessments and cleanups at numerous federal Superfund and comparable state sites. After an assessment of environmental exposures for cleanup and other costs, we make accruals on an undiscounted basis (except those acquired in a purchase business combination, which we record on a discounted basis) for planned investigation and remediation activities for sites where it is probable future costs will be incurred and these costs can be reasonably estimated. We have not reduced these accruals for possible insurance recoveries. In the future, we may be involved in additional environmental assessments, cleanups and proceedings. See Note 11—Asset Retirement Obligations and Accrued Environmental Costs, for a summary of our accrued environmental liabilities.
Legal Proceedings
Our legal organization applies its knowledge, experience and professional judgment to the specific characteristics of our cases, employing a litigation management process to manage and monitor the legal proceedings against us. Our process facilitates the early evaluation and quantification of potential exposures in individual cases. This process also enables us to track those cases that have been scheduled for trial and/or mediation. Based on professional judgment and experience in using these litigation management tools and available information about current developments in all our cases, our legal organization regularly assesses the adequacy of current accruals and determines if adjustment of existing accruals, or establishment of new accruals, is required.
Other Contingencies
We have contingent liabilities resulting from throughput agreements with pipeline and processing companies not associated with financing arrangements. Under these agreements, we may be required to provide any such company with additional funds through advances and penalties for fees related to throughput capacity not utilized. In addition, at December 31, 2011, we had performance obligations secured by letters of credit of $1,954 million (of which $40 million was issued under the provisions of our revolving credit facility, and the remainder was issued as direct bank letters of credit) related to various purchase commitments for materials, supplies, services and items of permanent investment incident to the ordinary conduct of business.
In 2007, we announced we had been unable to reach agreement with respect to our migration to an empresa mixta structure mandated by the Venezuelan government’s Nationalization Decree. As a result, Venezuela’s national oil company, Petróleos de Venezuela S.A. (PDVSA), or its affiliates, directly assumed control over ConocoPhillips’ interests in the Petrozuata and Hamaca heavy oil ventures and the offshore Corocoro development project. In response to this expropriation, we filed a request for international arbitration on
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November 2, 2007, with the World Bank’s International Centre for Settlement of Investment Disputes (ICSID). An arbitration hearing was held before an ICSID tribunal during the summer of 2010, and we are currently awaiting an interim decision on key legal and factual issues. A separate arbitration hearing was held in January 2012 before the International Chamber of Commerce on ConocoPhillips’ separate claims against PDVSA for certain breaches of their Association Agreements prior to the expropriation.
In 2008, Burlington Resources, Inc., a wholly owned subsidiary of ConocoPhillips, initiated arbitration before ICSID against The Republic of Ecuador, as a result of the newly enacted Windfall Profits Tax Law and government-mandated renegotiation of our production sharing contracts. Despite a restraining order issued by ICSID, Ecuador confiscated the crude oil production of Burlington and its co-venturer and sold the illegally seized crude oil. In 2009, Ecuador took over operations in Blocks 7 and 21, fully expropriating our assets. In June 2010, the ICSID tribunal concluded it has jurisdiction to hear the expropriation claim. An arbitration hearing on case merits occurred in March 2011. On September 30, 2011, Ecuador filed a supplemental counterclaim asserting environmental damages, which we believe will not be material. The arbitration process is ongoing. For additional information, see Note 10—Impairments.
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: 2012—$468 million; 2013—$467 million; 2014—$467 million; 2015—$458 million; 2016—$364 million; and 2017 and after—$4,890 million. Total payments under the agreements were $429 million in 2011, $216 million in 2010 and $114 million in 2009.
Note 16—Financial Instruments and Derivative Contracts
Financial Instruments
We invest excess cash in financial instruments with maturities based on our cash forecasts for the various currency pools we manage. The maturities of these investments may from time to time extend beyond 90 days. The types of financial instruments in which we currently invest include:
| • | Time deposits: Interest bearing deposits placed with approved financial institutions. |
| • | Commercial paper: Unsecured promissory notes issued by a corporation, commercial bank, or government agency purchased at a discount, maturing at par. |
| • | Government or government agency obligations: Negotiable debt obligations issued by a government or government agency. |
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These financial instruments appear in the “Cash and cash equivalents” line of our consolidated balance sheet if the maturities at the time we made the investments were 90 days or less; otherwise, these held-to-maturity investments are included in the “Short-term investments” line. At December 31, we held the following financial instruments:
| Millions of Dollars | ||||||||||||||||||
| Carrying Amount | ||||||||||||||||||
| Cash and Cash Equivalents |
Short-Term Investments* |
|||||||||||||||||
| 2011 | 2010 | 2011 | 2010 | |||||||||||||||
| Cash |
$ | 1,169 | 1,284 | — | — | |||||||||||||
| Time Deposits |
||||||||||||||||||
| Remaining maturities from 1 to 90 days |
4,318 | 6,154 | 349 | 302 | ||||||||||||||
| Remaining maturities from 91 to 180 days |
— | — | — | 69 | ||||||||||||||
| Commercial Paper |
||||||||||||||||||
| Remaining maturities from 1 to 90 days |
293 | 1,566 | 232 | 525 | ||||||||||||||
| Remaining maturities from 91 to 180 days |
— | — | — | — | ||||||||||||||
| Government Obligations |
||||||||||||||||||
| Remaining maturities from 1 to 90 days |
— | 450 | — | 77 | ||||||||||||||
| Remaining maturities from 91 to 180 days |
— | — | — | — | ||||||||||||||
| $ | 5,780 | 9,454 | 581 | 973 | ||||||||||||||
| *Carrying | value approximates fair value. |
Derivative Instruments
We use financial and commodity-based derivative contracts to manage exposures to fluctuations in foreign currency exchange rates, commodity prices, and interest rates, or to capture market opportunities. Since we are not currently using cash-flow hedge accounting, all gains and losses, realized or unrealized, from derivative contracts have been recognized in the consolidated income statement. Gains and losses from derivative contracts held for trading not directly related to our physical business, whether realized or unrealized, have been reported net in other income.
Purchase and sales contracts with fixed minimum notional volumes for commodities that are readily convertible to cash (e.g., crude oil, natural gas and gasoline) are recorded on the balance sheet as derivatives unless the contracts are eligible for and we elect the normal purchases and normal sales exception (i.e., contracts to purchase or sell quantities we expect to use or sell over a reasonable period in the normal course of business). We record most of our contracts to buy or sell natural gas and the majority of our contracts to sell power as derivatives, but we do apply the normal purchases and normal sales exception to certain long-term contracts to sell our natural gas production. We generally apply this normal purchases and normal sales exception to eligible crude oil and refined product commodity purchase and sales contracts; however, we may elect not to apply this exception (e.g., when another derivative instrument will be used to mitigate the risk of the purchase or sales contract but hedge accounting will not be applied, in which case both the purchase or sales contract and the derivative contract mitigating the resulting risk will be recorded on the balance sheet at fair value).
We value our exchange-traded 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. Where exchange-provided prices are adjusted, non-exchange quotes are used, or when the instrument lacks sufficient liquidity, we generally classify those exchange-cleared contracts as Level 2. Over-the-counter (OTC) financial swaps and physical commodity forward purchase and sales contracts are generally valued using quotations provided by brokers and price index developers, such as Platts and Oil Price Information Service. These quotes are corroborated with market data and are classified as Level 2. In certain less liquid markets or for longer-term contracts, forward prices are not as readily available. In these circumstances, OTC swaps and physical commodity
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purchase and sales contracts are valued using internally developed methodologies that consider historical relationships among various commodities that result in management’s best estimate of fair value. These contracts are classified as Level 3. A contract that is initially classified as Level 3 due to absence or insufficient corroboration of broker quotes over a material portion of the contract will transfer to Level 2 when the portion of the trade having no quotes or insufficient corroboration becomes an insignificant portion of the contract. A contract would also transfer to Level 2 if we began using a corroborated broker quote that has become available. Conversely, if a corroborated broker quote ceases to be available or used by us, the contract would transfer from Level 2 to Level 3. There were no material transfers in or out of Level 1.
Financial OTC and physical commodity options are valued using industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and contractual prices for the underlying instruments, as well as other relevant economic measures. The degree to which these inputs are observable in the forward markets determines whether the options are classified as Level 2 or 3.
We use a mid-market pricing convention (the mid-point between bid and ask prices). When appropriate, valuations are adjusted to reflect credit considerations, generally based on available market evidence.
The fair value hierarchy for our derivative assets and liabilities accounted for at fair value on a recurring basis was:
| Millions of Dollars | ||||||||||||||||||||||||||||||||||
| December 31, 2011 | December 31, 2010 | |||||||||||||||||||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||||||||
| Assets |
||||||||||||||||||||||||||||||||||
| Commodity derivatives* |
$ | 2,807 | 1,947 | 72 | 4,826 | 1,456 | 1,744 | 63 | 3,263 | |||||||||||||||||||||||||
| Interest rate derivatives |
— | 31 | — | 31 | — | 20 | — | 20 | ||||||||||||||||||||||||||
| Foreign currency exchange derivatives |
— | 13 | — | 13 | — | 15 | — | 15 | ||||||||||||||||||||||||||
| Total assets |
2,807 | 1,991 | 72 | 4,870 | 1,456 | 1,779 | 63 | 3,298 | ||||||||||||||||||||||||||
| Liabilities |
||||||||||||||||||||||||||||||||||
| Commodity derivatives* |
2,970 | 1,722 | 10 | 4,702 | 1,611 | 1,737 | 36 | 3,384 | ||||||||||||||||||||||||||
| Foreign currency exchange derivatives |
— | 23 | — | 23 | — | 9 | — | 9 | ||||||||||||||||||||||||||
| Total liabilities |
2,970 | 1,745 | 10 | 4,725 | 1,611 | 1,746 | 36 | 3,393 | ||||||||||||||||||||||||||
| Net assets (liabilities) |
$ | (163 | ) | 246 | 62 | 145 | (155 | ) | 33 | 27 | (95 | ) | ||||||||||||||||||||||
| *2010 | has been reclassified to conform to current-year presentation. |
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 right of setoff exists. Gains or losses from contracts in one level may be offset by gains or losses on contracts in another level or by changes in values of physical contracts or positions that are not reflected in the table above.
As reflected in the table above, Level 3 activity was not material.
Commodity Derivative Contracts—We operate in the worldwide crude oil, bitumen, refined product, natural gas, LNG, natural gas liquids and electric power markets and are exposed to fluctuations in the prices for these commodities. These fluctuations can affect our revenues, as well as the cost of operating, investing and financing activities. Generally, our policy is to remain exposed to the market prices of commodities; however, we use futures, forwards, swaps and options in various markets to balance physical systems, meet customer needs, manage price exposures on specific transactions, and do a limited,
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immaterial amount of trading not directly related to our physical business. We also use the market knowledge gained from these activities to capture market opportunities such as moving physical commodities to more profitable locations, storing commodities to capture seasonal or time premiums, and blending commodities to capture quality upgrades. Derivatives may be used to optimize these activities which may move our risk profile away from market average prices.
The fair value of commodity derivative assets and liabilities and the line items where they appear on our consolidated balance sheet were:
| Millions of Dollars | ||||||||
| 2011 | 2010 | |||||||
| Assets |
||||||||
| Prepaid expenses and other current assets |
$ | 4,433 | 3,073 | |||||
| Other assets |
415 | 211 | ||||||
| Liabilities |
||||||||
| Other accruals |
4,350 | 3,212 | ||||||
| Other liabilities and deferred credits |
374 | 193 | ||||||
Hedge accounting has not been used for any item in the table. The amounts shown are presented gross (i.e., without netting assets and liabilities with the same counterparty where the right of setoff exists).
The gains (losses) from commodity derivatives incurred, and the line items where they appear on our consolidated income statement were:
| Millions of Dollars | ||||||||||||
| 2011 | 2010 | 2009 | ||||||||||
| Sales and other operating revenues* |
$ | 302 | (1,243 | ) | 1,167 | |||||||
| Other income |
3 | (38 | ) | 19 | ||||||||
| Purchased crude oil, natural gas and products* |
(596 | ) | 1,127 | (1,823 | ) | |||||||
*2010 and 2009 have been restated to eliminate certain non-derivative transactions and realign certain derivative transactions between sales and purchases.
Hedge accounting has not been used for any item in the table.
The table below summarizes our material net exposures resulting from outstanding commodity derivative contracts. These financial and physical derivative contracts are primarily used to manage price exposures 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) |
||||||||
| 2011 | 2010 | |||||||
| Commodity |
||||||||
| Crude oil, refined products and natural gas liquids (millions of barrels) |
(13 | ) | (16 | ) | ||||
| Natural gas and power (billions of cubic feet equivalent) |
||||||||
| Fixed price |
(57 | ) | (69 | ) | ||||
| Basis |
(25 | ) | (43 | ) | ||||
Interest Rate Derivative Contracts—During the second quarter of 2010, we executed interest rate swaps to synthetically convert $500 million of our 4.60% fixed-rate notes due in 2015 to a floating rate based on the London Interbank Offered Rate (LIBOR). These swaps qualify for and are designated as fair-value hedges using the short-cut method of hedge accounting. The short-cut method permits the assumption that changes in the value of the derivative perfectly offset changes in the value of the debt; therefore, no gain or loss has been recognized due to hedge ineffectiveness.
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The adjustments to the fair values of the interest rate swaps and hedged debt have not been material.
Foreign Currency Exchange Derivatives—We have foreign currency exchange rate risk resulting from international operations. We do not comprehensively hedge the exposure to movements in currency exchange rates, although we may choose to selectively hedge certain foreign currency exchange rate exposures, such as firm commitments for capital projects or local currency tax payments, dividends, and cash returns from net investments in foreign affiliates to be remitted within the coming year.
The fair value of foreign currency exchange derivative assets and liabilities, and the line items where they appear on our consolidated balance sheet were:
| Millions of Dollars | ||||||||
| 2011 | 2010 | |||||||
| Assets |
||||||||
| Prepaid expenses and other current assets |
$ | 12 | 14 | |||||
| Other assets |
1 | 1 | ||||||
| Liabilities |
||||||||
| Other accruals |
23 | 7 | ||||||
| Other liabilities and deferred credits |
— | 2 | ||||||
Hedge accounting has not been used for any item in the table. The amounts shown are presented gross.
Gains and losses from foreign currency exchange derivatives and the line item where they appear on our consolidated income statement were:
| Millions of Dollars | ||||||||||||
| 2011 | 2010 | 2009 | ||||||||||
| Foreign currency transaction (gains) losses |
$ | (14 | ) | 118 | (121 | ) | ||||||
Hedge accounting has not been used for any item in the table.
We had the following net notional position of outstanding foreign currency exchange derivatives:
| In Millions | ||||||||
| Notional Currency* | ||||||||
| 2011 | 2010 | |||||||
| Foreign Currency Exchange Derivatives |
||||||||
| Sell U.S. dollar, buy other currencies** |
USD | 1,949 | 569 | |||||
| Sell euro, buy other currencies*** |
EUR | 61 | 253 | |||||
| * | Denominated in U.S. dollars (USD) and euros (EUR). |
| ** | Primarily euro, Canadian dollar, Norwegian krone and British pound. |
| *** | Primarily Norwegian krone and British pound. |
Credit Risk
Financial instruments potentially exposed to concentrations of credit risk consist primarily of cash equivalents, OTC derivative contracts and trade receivables. Our cash equivalents and short-term investments are placed in high-quality commercial paper, money market funds, government debt securities and time deposits with major international banks and financial institutions.
The credit risk from our OTC derivative contracts, such as forwards and swaps, derives from the counterparty to the transaction. Individual counterparty exposure is managed within predetermined credit limits and includes the use of cash-call margins when appropriate, thereby reducing the risk of significant nonperformance. We also use futures, swaps and option contracts that have a negligible credit risk because
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these trades are cleared with an exchange clearinghouse and subject to mandatory margin requirements until settled; however, we are exposed to the credit risk of those exchange brokers for receivables arising from daily margin cash calls, as well as for cash deposited to meet initial margin requirements.
Our trade receivables result primarily from our petroleum operations and reflect a broad national and international customer base, which limits our exposure to concentrations of credit risk. The majority of these receivables have payment terms of 30 days or less, and we continually monitor this exposure and the creditworthiness of the counterparties. We do not generally require collateral to limit the exposure to loss; however, we will sometimes use letters of credit, prepayments, and master netting arrangements to mitigate credit risk with counterparties that both buy from and sell to us, as these agreements permit the amounts owed by us or owed to others to be offset against amounts due us.
Certain of our derivative instruments contain provisions that require us to post collateral if the derivative exposure exceeds a threshold amount. We have contracts with fixed threshold amounts and other contracts with variable threshold amounts that are contingent on our credit rating. The variable threshold amounts typically decline for lower credit ratings, while both the variable and fixed threshold amounts typically revert to zero if we fall below investment grade. Cash is the primary collateral in all contracts; however, many also permit us to post letters of credit as collateral.
The aggregate fair value of all derivative instruments with such credit-risk-related contingent features that were in a liability position on December 31, 2011, was $237 million, for which $3 million of collateral was posted. If our credit rating were lowered one level from its “A” rating (per Standard and Poor’s) on December 31, 2011, 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 $234 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, cash equivalents and short-term investments: 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: We completed the disposition of our interest in LUKOIL during the first quarter of 2011. At December 31, 2010, our investment in LUKOIL was carried at fair value of $1,083 million, reflecting a closing price of LUKOIL ADRs on the London Stock Exchange of $56.50 per share. |
| • | 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 December 31, 2011, and December 31, 2010, using effective yield rates of 1.24 percent and 1.87 percent, respectively, 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. |
| • | Commodity swaps: Fair value is estimated based on forward market prices and approximates the exit price at period end. When forward market prices are not available, fair value is 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 IntercontinentalExchange (ICE) Futures, or other traded exchanges. |
| • | Interest rate swap contracts: Fair value is estimated based on a pricing model and market-observable interest rate swap curves obtained from a third-party market data provider. |
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| • | Forward-exchange contracts: Fair values are estimated by comparing the contract rate to the forward rates in effect at the end of the respective reporting periods, and approximate the exit prices at those dates. |
Our commodity derivative and financial instruments were:
| Millions of Dollars | ||||||||||||||||||
| Carrying Amount | Fair Value | |||||||||||||||||
| 2011 | 2010 | 2011 | 2010 | |||||||||||||||
| Financial Assets |
||||||||||||||||||
| Foreign currency exchange derivatives |
$ | 13 | 15 | 13 | 15 | |||||||||||||
| Interest rate derivatives |
31 | 20 | 31 | 20 | ||||||||||||||
| Commodity derivatives |
814 | 624 | 814 | 624 | ||||||||||||||
| Investment in LUKOIL |
— | 1,083 | — | 1,083 | ||||||||||||||
| Financial Liabilities |
||||||||||||||||||
| Total debt, excluding capital leases |
22,592 | 23,553 | 27,065 | 26,144 | ||||||||||||||
| Joint venture acquisition obligation |
4,314 | 5,009 | 4,820 | 5,600 | ||||||||||||||
| Foreign currency exchange derivatives |
23 | 9 | 23 | 9 | ||||||||||||||
| Commodity derivatives |
446 | 426 | 446 | 426 | ||||||||||||||
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 setoff exists). In addition, the December 31, 2011, commodity derivative assets and liabilities appear net of no obligations to return cash collateral and $244 million of rights to reclaim cash collateral. The December 31, 2010, commodity derivative assets and liabilities appear net of $5 million of obligations to return cash collateral and $324 million of rights to reclaim cash collateral, respectively. No collateral was deposited or held for the foreign currency derivatives or interest rate 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 | ||||||||||||
| 2011 | 2010 | 2009 | ||||||||||
| Issued |
||||||||||||
| Beginning of year |
1,740,529,279 | 1,733,345,558 | 1,729,264,859 | |||||||||
| Distributed under benefit plans |
9,021,308 | 7,183,721 | 4,080,699 | |||||||||
| End of year |
1,749,550,587 | 1,740,529,279 | 1,733,345,558 | |||||||||
| Held in Treasury |
||||||||||||
| Beginning of year |
272,873,537 | 208,346,815 | 208,346,815 | |||||||||
| Repurchase of common stock |
155,453,382 | 64,526,722 | — | |||||||||
| Distributed under benefit plans |
(475,696 | ) | — | — | ||||||||
| Transfer from grantor trust |
36,029,405 | — | — | |||||||||
| End of year |
463,880,628 | 272,873,537 | 208,346,815 | |||||||||
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| Shares | ||||||||||||
| 2011 | 2010 | 2009 | ||||||||||
| Held in Grantor Trusts |
||||||||||||
| Beginning of year |
36,890,375 | 38,742,261 | 40,739,129 | |||||||||
| Repurchase of common stock |
(157,470 | ) | — | — | ||||||||
| Distributed under benefit plans |
(703,500 | ) | (1,776,873 | ) | (2,018,692 | ) | ||||||
| Transfer to treasury stock |
(36,029,405 | ) | — | — | ||||||||
| Other |
— | (75,013 | ) | 21,824 | ||||||||
| End of year |
— | 36,890,375 | 38,742,261 | |||||||||
Preferred Stock
We have authorized 500 million shares of preferred stock, par value $.01 per share, none of which was issued or outstanding at December 31, 2011 or 2010.
Noncontrolling Interests
At December 31, 2011 and 2010, we had outstanding $510 million and $547 million, respectively, of equity in less-than-wholly owned consolidated subsidiaries held by noncontrolling interest owners. The noncontrolling interest amounts are primarily related to operating joint ventures we control. The largest of these, amounting to $482 million and $520 million at December 31, 2011, and 2010, respectively, was related to Darwin LNG operations, located in Australia’s Northern Territory.
Preferred Share Purchase Rights
In 2002, our Board of Directors authorized and declared a dividend of one preferred share purchase right for each common share outstanding, and authorized and directed the issuance of one right per common share for any newly issued shares. The rights have certain anti-takeover effects. The rights will cause substantial dilution to a person or group that attempts to acquire ConocoPhillips on terms not approved by the Board of Directors. However, since the rights may either be redeemed or otherwise made inapplicable by ConocoPhillips prior to an acquirer obtaining beneficial ownership of 15 percent or more of ConocoPhillips’ common stock, the rights should not interfere with any merger or business combination approved by the Board of Directors prior to that occurrence. The rights, which expire June 30, 2012, will be exercisable only if a person or group acquires 15 percent or more of the company’s common stock or commences a tender offer that would result in ownership of 15 percent or more of the common stock. Each right would entitle stockholders to buy one one-hundredth of a share of preferred stock at an exercise price of $300. If an acquirer obtains 15 percent or more of ConocoPhillips’ common stock, then each right will be adjusted so that it will entitle the holder (other than the acquirer, whose rights will become void) to purchase, for the then exercise price, a number of shares of ConocoPhillips’ common stock equal in value to two times the exercise price of the right. In addition, the rights enable holders to purchase the stock of an acquiring company at a discount, depending on specific circumstances. We may redeem the rights in whole, but not in part, for one cent per right.
Note 18—Non-Mineral Leases
The company leases ocean transport vessels, tugboats, barges, pipelines, railcars, corporate aircraft, service stations, drilling equipment, computers, office buildings and other facilities and equipment. Certain leases include escalation clauses for adjusting rental payments to reflect changes in price indices, as well as renewal options and/or options to purchase the leased property for the fair market value at the end of the lease term. There are no significant restrictions imposed on us by the leasing agreements with regard to dividends, asset dispositions or borrowing ability. Leased assets under capital leases were not significant in any period presented.
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At December 31, 2011, future minimum rental payments due under noncancelable leases were:
| Millions of Dollars |
||||
| 2012 |
$ | 767 | ||
| 2013 |
519 | |||
| 2014 |
382 | |||
| 2015 |
300 | |||
| 2016 |
202 | |||
| Remaining years |
591 | |||
| Total |
2,761 | |||
| Less income from subleases |
132 | * | ||
| Net minimum operating lease payments |
$ | 2,629 | ||
| * | Includes $64 million related to subleases to related parties. |
Operating lease rental expense for the years ended December 31 was:
| Millions of Dollars | ||||||||||||
| 2011 | 2010 | 2009 | ||||||||||
| Total rentals* |
$ | 901 | 925 | 1,024 | ||||||||
| Less sublease rentals |
(32 | ) | (34 | ) | (34 | ) | ||||||
| $ | 869 | 891 | 990 | |||||||||
| * | Includes $35 million, $22 million and $21 million of contingent rentals in 2011, 2010 and 2009, respectively. Contingent rentals primarily are related to drilling equipment and retail sites, and are based on usage or volume of product sold. |
Note 19—Employee Benefit Plans
Pension and Postretirement Plans
An analysis of the projected benefit obligations for our pension plans and accumulated benefit obligations for our postretirement health and life insurance plans follows:
| Millions of Dollars | ||||||||||||||||||||||||||||
| Pension Benefits | Other Benefits | |||||||||||||||||||||||||||
| 2011 | 2010 | 2011 | 2010 | |||||||||||||||||||||||||
| U.S. | Int’l. | U.S. | Int’l. | |||||||||||||||||||||||||
| Change in Benefit Obligation |
||||||||||||||||||||||||||||
| Benefit obligation at January 1 |
$ | 5,539 | 3,206 | 5,042 | 3,101 | 862 | 839 | |||||||||||||||||||||
| Service cost |
225 | 98 | 229 | 90 | 10 | 11 | ||||||||||||||||||||||
| Interest cost |
247 | 178 | 260 | 169 | 42 | 46 | ||||||||||||||||||||||
| Plan participant contributions |
— | 5 | — | 4 | 23 | 20 | ||||||||||||||||||||||
| Government subsidy |
— | — | — | — | 4 | — | ||||||||||||||||||||||
| Plan amendments |
— | (53 | ) | 12 | — | 35 | — | |||||||||||||||||||||
| Actuarial loss |
642 | 195 | 305 | 59 | 20 | 14 | ||||||||||||||||||||||
| Benefits paid |
(478 | ) | (116 | ) | (309 | ) | (115 | ) | (68 | ) | (70 | ) | ||||||||||||||||
| Curtailment |
— | — | — | (1 | ) | — | — | |||||||||||||||||||||
| Foreign currency exchange rate change |
— | (29 | ) | — | (101 | ) | (2 | ) | 2 | |||||||||||||||||||
| Benefit obligation at December 31* |
$ | 6,175 | 3,484 | 5,539 | 3,206 | 926 | 862 | |||||||||||||||||||||
| * Accumulated benefit obligation portion of above at December 31: |
$ | 5,363 | 2,939 | 4,905 | 2,711 | |||||||||||||||||||||||
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| Millions of Dollars | ||||||||||||||||||||||||||||
| Pension Benefits | Other Benefits | |||||||||||||||||||||||||||
| 2011 | 2010 | 2011 | 2010 | |||||||||||||||||||||||||
| U.S. | Int’l. | U.S. | Int’l. | |||||||||||||||||||||||||
| Change in Fair Value of Plan Assets |
||||||||||||||||||||||||||||
| Fair value of plan assets at January 1 |
$ | 3,890 | 2,581 | 3,144 | 2,281 | — | — | |||||||||||||||||||||
| Actual return on plan assets |
64 | 53 | 458 | 259 | — | — | ||||||||||||||||||||||
| Company contributions |
673 | 226 | 597 | 216 | 41 | 50 | ||||||||||||||||||||||
| Plan participant contributions |
— | 5 | — | 4 | 23 | 20 | ||||||||||||||||||||||
| Government subsidy |
— | — | — | — | 4 | — | ||||||||||||||||||||||
| Benefits paid |
(478 | ) | (116 | ) | (309 | ) | (115 | ) | (68 | ) | (70 | ) | ||||||||||||||||
| Curtailment |
— | — | — | (1 | ) | — | — | |||||||||||||||||||||
| Foreign currency exchange rate change |
— | (27 | ) | — | (63 | ) | — | — | ||||||||||||||||||||
| Fair value of plan assets at December 31 |
$ | 4,149 | 2,722 | 3,890 | 2,581 | — | — | |||||||||||||||||||||
| Funded Status |
$ | (2,026 | ) | (762 | ) | (1,649 | ) | (625 | ) | (926 | ) | (862 | ) | |||||||||||||||
| Millions of Dollars | ||||||||||||||||||||||||||||
| Pension Benefits | Other Benefits | |||||||||||||||||||||||||||
| 2011 | 2010 | 2011 | 2010 | |||||||||||||||||||||||||
| U.S. | Int’l. | U.S. | Int’l. | |||||||||||||||||||||||||
| Amounts Recognized in the Consolidated Balance Sheet at December 31 |
||||||||||||||||||||||||||||
| Noncurrent assets |
$ | — | 94 | — | 156 | — | — | |||||||||||||||||||||
| Current liabilities |
(118 | ) | (5 | ) | (74 | ) | (4 | ) | (62 | ) | (51 | ) | ||||||||||||||||
| Noncurrent liabilities |
(1,908 | ) | (851 | ) | (1,575 | ) | (777 | ) | (864 | ) | (811 | ) | ||||||||||||||||
| Total recognized |
$ | (2,026 | ) | (762 | ) | (1,649 | ) | (625 | ) | (926 | ) | (862 | ) | |||||||||||||||
| Weighted-Average Assumptions Used to Determine Benefit Obligations at December 31 |
||||||||||||||||||||||||||||
| Discount rate |
4.30 | % | 4.90 | 4.65 | 5.40 | 4.40 | 5.00 | |||||||||||||||||||||
| Rate of compensation increase |
4.25 | 4.30 | 4.00 | 4.10 | — | — | ||||||||||||||||||||||
| Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31 |
||||||||||||||||||||||||||||
| Discount rate |
4.65 | % | 5.40 | 5.35 | 5.80 | 5.00 | 5.60 | |||||||||||||||||||||
| Expected return on plan assets |
7.00 | 6.40 | 7.00 | 6.50 | — | — | ||||||||||||||||||||||
| Rate of compensation increase |
4.00 | 4.10 | 4.00 | 4.50 | — | — | ||||||||||||||||||||||
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.
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Included in accumulated other comprehensive income at December 31 were the following before-tax amounts that had not been recognized in net periodic benefit cost:
| Millions of Dollars | ||||||||||||||||||||||||||||
| Pension Benefits | Other Benefits | |||||||||||||||||||||||||||
| 2011 | 2010 | 2011 | 2010 | |||||||||||||||||||||||||
| U.S. | Int’l. |
|
U.S. | Int’l. | ||||||||||||||||||||||||
| Unrecognized net actuarial loss (gain) |
$ | 2,240 | 705 | 1,567 | 444 | (26 | ) | (51 | ) | |||||||||||||||||||
| Unrecognized prior service cost (credit) |
52 | (78 | ) | 61 | (25 | ) | (13 | ) | (54 | ) | ||||||||||||||||||
| Millions of Dollars | ||||||||||||||||||||||||||||
| Pension Benefits | Other Benefits | |||||||||||||||||||||||||||
| 2011 | 2010 | 2011 | 2010 | |||||||||||||||||||||||||
| U.S. | Int’l. | U.S. | Int’l. | |||||||||||||||||||||||||
| Sources of Change in Other Comprehensive Income |
||||||||||||||||||||||||||||
| Net gain (loss) arising during the period |
$ | (858 | ) | (307 | ) | (70 | ) | 75 | (20 | ) | (14 | ) | ||||||||||||||||
| Amortization of (gain) loss included in income |
185 | 46 | 167 | 55 | (5 | ) | (7 | ) | ||||||||||||||||||||
| Net change during the period |
$ | (673 | ) | (261 | ) | 97 | 130 | (25 | ) | (21 | ) | |||||||||||||||||
| Prior service (cost) credit arising during the period |
$ | — | 53 | (12 | ) | (1 | ) | (34 | ) | — | ||||||||||||||||||
| Amortization of prior service cost (credit) included in income |
9 | — | 10 | 2 | (7 | ) | 3 | |||||||||||||||||||||
| Net change during the period |
$ | 9 | 53 | (2 | ) | 1 | (41 | ) | 3 | |||||||||||||||||||
Amounts included in accumulated other comprehensive income at December 31, 2011, that are expected to be amortized into net periodic postretirement cost during 2012 are provided below:
| Millions of Dollars | ||||||||||||||
| Pension Benefits | Other Benefits | |||||||||||||
| U.S. | Int’l. | |||||||||||||
| Unrecognized net actuarial loss (gain) |
$ | 235 | 71 | (3 | ) | |||||||||
| Unrecognized prior service cost |
9 | (9 | ) | (4 | ) | |||||||||
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 $8,481 million, $7,377 million, and $6,098 million, respectively, at December 31, 2011, and $7,661 million, $6,718 million, and $5,706 million, respectively, at December 31, 2010.
For our unfunded nonqualified key employee supplemental pension plans, the projected benefit obligation and the accumulated benefit obligation were $499 million and $374 million, respectively, at December 31, 2011, and were $479 million and $407 million, respectively, at December 31, 2010.
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 | |||||||||||||||||||||||||||||||||||||||||
| 2011 | 2010 | 2009 | 2011 | 2010 | 2009 | |||||||||||||||||||||||||||||||||||||
| U.S. | Int’l. | U.S. | Int’l. | U.S. | Int’l. | |||||||||||||||||||||||||||||||||||||
| Components of Net Periodic Benefit Cost |
||||||||||||||||||||||||||||||||||||||||||
| Service cost |
$ | 225 | 98 | 229 | 90 | 194 | 79 | 10 | 11 | 9 | ||||||||||||||||||||||||||||||||
| Interest cost |
247 | 178 | 260 | 169 | 277 | 144 | 42 | 46 | 47 | |||||||||||||||||||||||||||||||||
| Expected return on plan assets |
(280 | ) | (175 | ) | (224 | ) | (147 | ) | (184 | ) | (125 | ) | — | — | — | |||||||||||||||||||||||||||
| Amortization of prior service cost (credit) |
9 | — | 10 | 2 | 11 | 1 | (7 | ) | 3 | 9 | ||||||||||||||||||||||||||||||||
| Recognized net actuarial loss (gain) |
165 | 46 | 167 | 55 | 186 | 35 | (5 | ) | (7 | ) | (15 | ) | ||||||||||||||||||||||||||||||
| Net periodic benefit cost |
$ | 366 | 147 | 442 | 169 | 484 | 134 | 40 | 53 | 50 | ||||||||||||||||||||||||||||||||
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We recognized pension settlement losses of $21 million in 2011 and $15 million in 2009. None were recognized in 2010.
We recognized special termination benefits of $5 million in 2009. None were recognized in 2011 and 2010.
In determining net pension and other postretirement benefit costs, we amortize prior service costs on a straight-line basis over the average remaining service period of employees expected to receive benefits under the plan. For net actuarial gains and losses, we amortize 10 percent of the unamortized balance each year.
We have multiple nonpension postretirement benefit plans for health and life insurance. The health care plans are contributory and subject to various cost sharing features, with participant and company contributions adjusted annually; the life insurance plans are noncontributory. The measurement of the accumulated postretirement benefit obligation assumes a health care cost trend rate of 7.75 percent in 2012 that declines to 5 percent by 2023. A one-percentage-point change in the assumed health care cost trend rate would be immaterial to ConocoPhillips.
Plan Assets—We follow a policy of broadly diversifying pension plan assets across asset classes, investment managers, and individual holdings. As a result, our plan assets have no significant concentrations of credit risk. Asset classes that are considered appropriate include U.S. equities, non-U.S. equities, U.S. fixed income, non-U.S. fixed income, real estate and private equity investments. Plan fiduciaries may consider and add other asset classes to the investment program from time to time. The target allocations for plan assets are 56 percent equity securities, 35 percent debt securities, 6 percent real estate and 3 percent in all other types of investments. Generally, the investments in the plans are publicly traded, therefore minimizing liquidity risk in the portfolio.
Following is a description of the valuation methodologies used for the pension plan assets. There have been no changes in the methodologies used at December 31, 2011 and 2010.
| • | Fair values of equity securities and government debt securities categorized in Level 1 are primarily based on quoted market prices. |
| • | Fair values of corporate debt securities, agency and mortgage-backed securities and government debt securities categorized in Level 2 are estimated using recently executed transactions and market price quotations. If there have been no market transactions in a particular fixed income security, its fair market value is calculated by pricing models that benchmark the security against other securities with actual market prices. When observable price quotations are not available, fair value is based on pricing models that use something other than actual market prices (e.g., observable inputs such as benchmark yields, reported trades and issuer spreads for similar securities), and these securities are categorized in Level 3 of the fair value hierarchy. |
| • | Fair values of investments in common/collective trusts are determined by the issuer of each fund based on the fair value of the underlying assets. |
| • | Fair values of mutual funds are valued based on quoted market prices, which represent the net asset value of shares held. |
| • | Cash is valued at cost, which approximates fair value. Fair values of cash equivalents categorized in Level 2 are valued using observable yield curves, discounting and interest rates. |
| • | Fair values of exchange-traded derivatives classified in Level 1 are based on quoted market prices. For other derivatives classified in Level 2, the values are generally calculated from pricing models with market input parameters from third-party sources. |
| • | Private equity funds are valued at net asset value as determined by the issuer based on the fair value of the underlying assets. |
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| • | 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, 2011, the participating interest in the annuity contract was valued at $144 million and consisted of $391 million in debt securities, less $247 million for the accumulated benefit obligation covered by the contract. At December 31, 2010, the participating interest in the annuity contract was valued at $92 million and consisted of $357 million in debt securities, less $265 million for the accumulated benefit obligation covered by the contract. The net change from 2010 to 2011 is due to an increase in the fair market value of the underlying investments of $34 million and a decrease in the present value of the contract obligation of $18 million. The participating interest is not available for meeting general pension benefit obligations in the near term. No future company contributions are required and no new benefits are being accrued under this insurance annuity contract. |
The fair values of our pension plan assets at December 31, by asset class were as follows:
| Millions of Dollars | ||||||||||||||||||||||||||||||||||
| U.S. | International | |||||||||||||||||||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||||||||
| 2011 |
||||||||||||||||||||||||||||||||||
| Equity Securities |
||||||||||||||||||||||||||||||||||
| U.S. |
$ | 1,251 | — | — | 1,251 | 413 | — | — | 413 | |||||||||||||||||||||||||
| International |
803 | — | — | 803 | 413 | — | — | 413 | ||||||||||||||||||||||||||
| Common/collective trusts |
— | 634 | — | 634 | — | 234 | — | 234 | ||||||||||||||||||||||||||
| Mutual funds |
— | — | — | — | 246 | — | — | 246 | ||||||||||||||||||||||||||
| Debt Securities |
||||||||||||||||||||||||||||||||||
| Government |
311 | 81 | — | 392 | 532 | — | — | 532 | ||||||||||||||||||||||||||
| Corporate |
— | 551 | 3 | 554 | — | 122 | 1 | 123 | ||||||||||||||||||||||||||
| Agency and mortgage-backed securities |
— | 105 | — | 105 | — | 43 | — | 43 | ||||||||||||||||||||||||||
| Common/collective trusts |
— | 249 | — | 249 | — | 346 | — | 346 | ||||||||||||||||||||||||||
| Mutual funds |
— | — | — | — | 130 | — | — | 130 | ||||||||||||||||||||||||||
| Cash and cash equivalents |
— | — | — | — | 32 | 26 | — | 58 | ||||||||||||||||||||||||||
| Private equity funds |
— | — | 4 | 4 | — | — | 13 | 13 | ||||||||||||||||||||||||||
| Derivatives |
— | — | — | — | — | 11 | — | 11 | ||||||||||||||||||||||||||
| Insurance contracts |
— | — | — | — | — | — | 15 | 15 | ||||||||||||||||||||||||||
| Real estate |
— | — | — | — | — | — | 139 | 139 | ||||||||||||||||||||||||||
| Total* |
$ | 2,365 | 1,620 | 7 | 3,992 | 1,766 | 782 | 168 | 2,716 | |||||||||||||||||||||||||
| * | Excludes the participating interest in the annuity contract with a net asset value of $144 million and net receivables related to security transactions of $19 million. |
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| Millions of Dollars | ||||||||||||||||||||||||||||||||||
| U.S. | International | |||||||||||||||||||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||||||||
| 2010 |
||||||||||||||||||||||||||||||||||
| Equity Securities |
||||||||||||||||||||||||||||||||||
| U.S. |
$ | 1,250 | — | — | 1,250 | 378 | — | — | 378 | |||||||||||||||||||||||||
| International |
818 | — | — | 818 | 498 | — | — | 498 | ||||||||||||||||||||||||||
| Common/collective trusts |
— | 635 | — | 635 | — | 246 | — | 246 | ||||||||||||||||||||||||||
| Mutual funds |
— | — | — | — | 282 | — | — | 282 | ||||||||||||||||||||||||||
| Debt Securities |
||||||||||||||||||||||||||||||||||
| Government |
251 | 56 | — | 307 | 390 | — | — | 390 | ||||||||||||||||||||||||||
| Corporate |
— | 420 | 3 | 423 | — | 171 | 2 | 173 | ||||||||||||||||||||||||||
| Agency and mortgage-backed securities |
— | 81 | — | 81 | — | — | — | — | ||||||||||||||||||||||||||
| Common/collective trusts |
— | 270 | — | 270 | — | 329 | — | 329 | ||||||||||||||||||||||||||
| Mutual funds |
— | — | — | — | 122 | — | — | 122 | ||||||||||||||||||||||||||
| Cash and cash equivalents |
— | — | — | — | 9 | 10 | — | 19 | ||||||||||||||||||||||||||
| Private equity funds |
— | — | 6 | 6 | — | — | 8 | 8 | ||||||||||||||||||||||||||
| Derivatives |
— | — | — | — | — | 12 | — | 12 | ||||||||||||||||||||||||||
| Insurance contracts |
— | — | — | — | — | — | 16 | 16 | ||||||||||||||||||||||||||
| Real estate |
— | — | — | — | — | — | 101 | 101 | ||||||||||||||||||||||||||
| Total* |
$ | 2,319 | 1,462 | 9 | 3,790 | 1,679 | 768 | 127 | 2,574 | |||||||||||||||||||||||||
| * | Excludes the participating interest in the annuity contract with a net asset value of $92 million and net receivables related to security transactions of $15 million. |
As reflected in the table above, Level 3 activity was not material.
Our funding policy for U.S. plans is to contribute at least the minimum required by the Employee Retirement Income Security Act of 1974 and the Internal Revenue Code of 1986, as amended. Contributions to foreign plans are dependent upon local laws and tax regulations. In 2012, we expect to contribute approximately $690 million to our domestic qualified and nonqualified pension and postretirement benefit plans and $235 million to our international qualified and nonqualified pension and postretirement benefit plans.
The following benefit payments, which are exclusive of amounts to be paid from the participating annuity contract and which reflect expected future service, as appropriate, are expected to be paid:
| Millions of Dollars | ||||||||||||||||
| Pension Benefits | Other Benefits | |||||||||||||||
| U.S. | Int’l. | |||||||||||||||
| 2012 |
$ | 577 | 110 | 63 | ||||||||||||
| 2013 |
501 | 113 | 64 | |||||||||||||
| 2014 |
524 | 121 | 67 | |||||||||||||
| 2015 |
553 | 129 | 70 | |||||||||||||
| 2016 |
598 | 134 | 72 | |||||||||||||
| 2017-2021 |
3,206 | 794 | 385 | |||||||||||||
Defined Contribution Plans
Most U.S. employees are eligible to participate in the ConocoPhillips Savings Plan (CPSP). Employees can deposit up to 75 percent of their eligible pay up to the statutory limit ($16,500 in 2011) in the thrift feature
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of the CPSP to a choice of approximately 39 investment funds. ConocoPhillips matches contribution deposits, up to 1.25 percent of eligible pay. Company contributions charged to expense for the CPSP and predecessor plans, excluding the stock savings feature (discussed below), were $25 million in 2011, $24 million in 2010, and $23 million in 2009.
The stock savings feature of the CPSP is a leveraged employee stock ownership plan. Employees may elect to participate in the stock savings feature by contributing 1 percent of eligible pay and receiving an allocation of shares of common stock proportionate to the amount of contribution.
In 1990, the Long-Term Stock Savings Plan of Phillips Petroleum Company (now the stock savings feature of the CPSP) borrowed funds that were used to purchase previously unissued shares of company common stock. Since the company guarantees the CPSP’s borrowings, the unpaid balance is reported as a liability of the company and unearned compensation is shown as a reduction of common stockholders’ equity. Dividends on all shares are charged against retained earnings. The debt is serviced by the CPSP from company contributions and dividends received on certain shares of common stock held by the plan, including all unallocated shares. The shares held by the stock savings feature of the CPSP are released for allocation to participant accounts based on debt service payments on CPSP borrowings. In addition, during the period from 2012 through 2014, when no debt principal payments are scheduled to occur, we have committed to make direct contributions of stock to the stock savings feature of the CPSP, or make prepayments on CPSP borrowings, to ensure a certain minimum level of stock allocation to participant accounts.
We recognize interest expense as incurred and compensation expense based on the fair market value of the stock contributed or on the cost of the unallocated shares released, using the shares-allocated method. We recognized total CPSP expense related to the stock savings feature of $77 million, $92 million and $83 million in 2011, 2010 and 2009, respectively, all of which was compensation expense. In 2011, we made cash contributions to the CPSP of $4 million. No cash contributions were made in 2010 and 2009. In 2011, 2010 and 2009, we contributed 660,755 shares, 1,776,873 shares and 2,018,692 shares, respectively, of company common stock from the Compensation and Benefits Trust. The shares had a fair market value of $84 million, $103 million and $94 million, respectively. Also in 2011, we contributed 475,696 shares of company common stock from Treasury stock. Dividends used to service debt were $45 million, $41 million and $39 million in 2011, 2010 and 2009, respectively. These dividends reduced the amount of compensation expense recognized each period. Interest incurred on the CPSP debt in 2011, 2010 and 2009 was $1 million, $2 million and $2 million, respectively.
The total CPSP stock savings feature shares as of December 31 were:
| 2011 | 2010 | |||||||
| Unallocated shares |
811,963 | 3,385,778 | ||||||
| Allocated shares |
19,315,372 | 19,198,502 | ||||||
| Total shares |
20,127,335 | 22,584,280 | ||||||
The fair value of unallocated shares at December 31, 2011 and 2010, was $59 million and $231 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 $56 million in 2011, $52 million in 2010 and $51 million in 2009.
Share-Based Compensation Plans
The 2011 Omnibus Stock and Performance Incentive Plan of ConocoPhillips (the Plan) was approved by shareholders in May 2011. Over its 10-year life, the Plan allows the issuance of up to 100 million shares of
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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 100 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 Statement of Financial Accounting Standards No. 123(R), codified into FASB ASC Topic 718, “Compensation—Stock Compensation,” we recognize expense over the period of time during which the employee earns the award, accelerating the recognition of expense only when an employee actually retires. For share-based awards granted after our adoption of ASC 718 on January 1, 2006, we recognize share-based compensation expense over the shorter of the service period (i.e., the stated period of time required to earn the award); or the period beginning at the start of the service period and ending when an employee first becomes eligible for retirement, but not less than six months, as this is the minimum period of time required for an award to not be subject to forfeiture.
Some of our share-based awards vest ratably (i.e., portions of the award vest at different times) while some of our awards cliff vest (i.e., all of the award vests at the same time). For awards granted prior to our adoption of ASC 718 that vest ratably, we recognize expense on a straight-line basis over the service period for each separate vesting portion of the award (i.e., as if the award was multiple awards with different requisite service periods). For share-based awards granted after our adoption of ASC 718, we recognize expense on a straight-line basis over the service period for the entire award, whether the award was granted with ratable or cliff vesting.
Total share-based compensation expense recognized in income and the associated tax benefit for the years ended December 31, were as follows:
| Millions of Dollars | ||||||||||||
| 2011 | 2010 | 2009 | ||||||||||
| Compensation cost |
$ | 246 | 211 | 121 | ||||||||
| Tax benefit |
86 | 78 | 42 | |||||||||
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, 2011:
| Options | Weighted- Average Exercise Price |
Weighted-Average Grant-Date Fair Value |
Millions of Dollars | |||||||||||||||||||
| |
Aggregate Intrinsic Value |
| ||||||||||||||||||||
| Outstanding at |
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 | |||||||||||||||||||
| Granted |
3,040,500 | 48.39 | $ | 11.70 | ||||||||||||||||||
| Exercised |
(6,401,483 | ) | 29.08 | $ | 183 | |||||||||||||||||
| Forfeited |
(255,889 | ) | 48.42 | |||||||||||||||||||
| Expired or canceled |
(204,727 | ) | 58.94 | |||||||||||||||||||
| Outstanding at December 31, 2010 |
32,611,874 | $ | 39.54 | |||||||||||||||||||
| Granted |
1,907,000 | 70.13 | $ | 16.70 | ||||||||||||||||||
| Exercised |
(10,022,685 | ) | 30.08 | $ | 416 | |||||||||||||||||
| Forfeited |
(82,434 | ) | 62.26 | |||||||||||||||||||
| Expired or canceled |
(41,704 | ) | 51.60 | |||||||||||||||||||
| Outstanding at |
24,372,051 | $ | 45.73 | |||||||||||||||||||
| Vested at December 31, 2011 |
22,214,254 | $ | 44.49 | $ | 611 | |||||||||||||||||
| Exercisable at |
19,666,959 | $ | 43.19 | $ | 564 | |||||||||||||||||
The weighted-average remaining contractual term of vested options and exercisable options at December 31, 2011, was 3.95 years and 3.4 years, respectively.
During 2011, we received $197 million in cash and realized a tax benefit of $119 million from the exercise of options. At December 31, 2011, the remaining unrecognized compensation expense from unvested options was $16 million, which will be recognized over a weighted-average period of 19 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:
| 2011 | 2010 | 2009 | ||||||||||
| Assumptions used |
||||||||||||
| Risk-free interest rate |
3.10 | % | 3.23 | 2.90 | ||||||||
| Dividend yield |
4.00 | % | 4.00 | 3.50 | ||||||||
| Volatility factor |
33.40 | % | 33.80 | 32.90 | ||||||||
| Expected life (years) |
6.87 | 6.65 | 6.53 | |||||||||
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The ranges in the assumptions used were as follows:
| 2011 | 2010 | 2009 | ||||||||||||||||||||||||||
| High | Low | High | Low | High | Low | |||||||||||||||||||||||
| Ranges used |
||||||||||||||||||||||||||||
| Risk-free interest rate |
3.10 | % | 3.10 | 3.23 | 3.23 | 2.90 | 2.90 | |||||||||||||||||||||
| Dividend yield |
4.00 | 4.00 | 4.00 | 4.00 | 3.50 | 3.50 | ||||||||||||||||||||||
| Volatility factor |
33.40 | 33.40 | 33.80 | 33.80 | 32.90 | 32.90 | ||||||||||||||||||||||
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—Generally, restricted stock units are granted annually under the provisions of the Plan and 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. In addition to these regularly scheduled annual awards, restricted stock units are also granted ad hoc to attract or retain key personnel, and the terms and conditions under which these restricted stock units vest vary by award. 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, 2011:
| Weighted-Average Grant-Date Fair Value |
Millions of Dollars | |||||||||||||||
| Stock Units | Total Fair Value | |||||||||||||||
| 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 | |||||||||||||
| Granted |
2,890,010 | 46.38 | ||||||||||||||
| Forfeited |
(233,212 | ) | 53.11 | |||||||||||||
| Issued |
(1,573,487 | ) | $ | 79 | ||||||||||||
| Outstanding at December 31, 2010 |
7,802,863 | $ | 53.04 | |||||||||||||
| Granted |
2,746,045 | 67.54 | ||||||||||||||
| Forfeited |
(299,531 | ) | 56.43 | |||||||||||||
| Issued |
(1,520,419 | ) | $ | 109 | ||||||||||||
| Outstanding at December 31, 2011 |
8,728,958 | $ | 55.41 | |||||||||||||
| Not Vested at December 31, 2011 |
6,175,477 | $ | 55.93 | |||||||||||||
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At December 31, 2011, the remaining unrecognized compensation cost from the unvested units was $188 million, which will be recognized over a weighted-average period of 30 months, the longest period being 100 months.
Performance Share Program—Under the Plan, we also annually grant to senior management restricted performance share units (PSUs) that do not vest until either (i) with respect to awards for performance periods beginning before 2009, the employee becomes eligible for retirement by reaching age 55 with five years of service or (ii) with respect to awards for performance 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 PSUs 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 PSUs are settled by issuing one share of ConocoPhillips common stock per unit. Until issued as stock, recipients of the PSUs receive a quarterly cash payment of a dividend equivalent that is charged to expense. In its current form, the first grant of PSUs under this program was in 2006.
The following summarizes our Performance Share Program activity for the three years ended December 31, 2011:
| Performance Share Units |
Weighted-Average Grant-Date Fair Value |
Millions of Dollars | ||||||||||||||
| Total Fair Value | ||||||||||||||||
| 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 | |||||||||||||
| Granted |
317,072 | 48.39 | ||||||||||||||
| Forfeited |
(53,243 | ) | 62.66 | |||||||||||||
| Issued |
(234,121 | ) | $ | 12 | ||||||||||||
| Outstanding at December 31, 2010 |
3,434,586 | $ | 63.43 | |||||||||||||
| Granted |
615,780 | 70.57 | ||||||||||||||
| Forfeited |
(23,240 | ) | 63.18 | |||||||||||||
| Issued |
(509,365 | ) | $ | 37 | ||||||||||||
| Outstanding at December 31, 2011 |
3,517,761 | $ | 64.35 | |||||||||||||
| Not Vested at December 31, 2011 |
1,063,982 | $ | 64.16 | |||||||||||||
At December 31, 2011, the remaining unrecognized compensation cost from unvested Performance Share awards was $27 million, which will be recognized over a weighted-average period of 46 months, the longest period being 15 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, 2011:
| Stock Units | Weighted-Average Grant-Date Fair Value |
Millions of Dollars | ||||||||||||||
| Total Fair Value | ||||||||||||||||
| 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 | |||||||||||||
| Granted |
73,395 | 53.33 | ||||||||||||||
| Issued |
(181,035 | ) | $ | 9 | ||||||||||||
| Canceled |
(58,441 | ) | 44.23 | |||||||||||||
| Outstanding at December 31, 2010 |
2,970,436 | $ | 34.06 | |||||||||||||
| Granted |
76,642 | 70.25 | ||||||||||||||
| Issued |
(139,523 | ) | $ | 10 | ||||||||||||
| Canceled |
(319,640 | ) | 30.90 | |||||||||||||
| Outstanding at December 31, 2011 |
2,587,915 | $ | 33.49 | |||||||||||||
| Not Vested at December 31, 2011 |
— | |||||||||||||||
At December 31, 2011, there was no remaining unrecognized compensation cost from the unvested units.
Compensation and Benefits Trust
The Compensation and Benefits Trust (CBT) was 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 trustee voted 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 was consolidated by ConocoPhillips; therefore, the cash contribution and promissory note were eliminated in consolidation. Shares held by the CBT were valued at cost and did not affect earnings per share or total common stockholders’ equity until after they were transferred out of the CBT. In 2010, 1,776,873 shares were transferred out of the CBT.
In August 2011, all of the approximately 36 million shares of company common stock held by the CBT were transferred to ConocoPhillips, and those shares are now held as non-voting treasury stock. Because the CBT was consolidated by us, the transfer of its shares from “Grantor trusts” to “Treasury stock” in the equity section of our balance sheet was recorded at the shares’ historical carrying value of $610 million. This transfer did not affect total equity, shares outstanding or earnings per share. The CBT no longer holds any assets. Two smaller grantor trusts also disposed of all their shares of company stock during 2011.
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Note 20—Income Taxes
Income taxes charged to income were:
| Millions of Dollars | ||||||||||||
| 2011 | 2010 | 2009 | ||||||||||
| Income Taxes |
||||||||||||
| Federal |
||||||||||||
| Current |
$ | 1,917 | 1,312 | 575 | ||||||||
| Deferred |
943 | 781 | 52 | |||||||||
| Foreign |
||||||||||||
| Current |
7,095 | 7,469 | 5,584 | |||||||||
| Deferred |
(2 | ) | (1,546 | ) | (1,245 | ) | ||||||
| State and local |
||||||||||||
| Current |
413 | 320 | 82 | |||||||||
| Deferred |
133 | (3 | ) | 42 | ||||||||
| $ | 10,499 | 8,333 | 5,090 | |||||||||
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 | ||||||||
| 2011 | 2010 | |||||||
| Deferred Tax Liabilities |
||||||||
| PP&E and intangibles |
$ | 21,159 | 20,344 | |||||
| Investment in joint ventures |
2,943 | 2,201 | ||||||
| Inventory |
— | 43 | ||||||
| Partnership income deferral |
363 | 434 | ||||||
| Other |
718 | 586 | ||||||
| Total deferred tax liabilities |
25,183 | 23,608 | ||||||
| Deferred Tax Assets |
||||||||
| Benefit plan accruals |
2,063 | 1,691 | ||||||
| Asset retirement obligations and accrued environmental costs |
4,254 | 3,971 | ||||||
| Inventory |
43 | — | ||||||
| Deferred state income tax |
299 | 257 | ||||||
| Other financial accruals and deferrals |
618 | 394 | ||||||
| Loss and credit carryforwards |
1,608 | 1,344 | ||||||
| Other |
692 | 717 | ||||||
| Total deferred tax assets |
9,577 | 8,374 | ||||||
| Less valuation allowance |
(1,487 | ) | (1,400 | ) | ||||
| Net deferred tax assets |
8,090 | 6,974 | ||||||
| Net deferred tax liabilities |
$ | 17,093 | 16,634 | |||||
Current assets, long-term assets, current liabilities and long-term liabilities included deferred taxes of $788 million, $183 million, $9 million and $18,055 million, respectively, at December 31, 2011, and $562 million, $160 million, $21 million and $17,335 million, respectively, at December 31, 2010.
We have loss and credit carryovers in multiple taxing jurisdictions. These attributes generally expire between 2012 and 2031 with some carryovers having indefinite carryforward periods.
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Valuation allowances have been established to reduce deferred tax assets to an amount that will, more likely than not, be realized. During 2011, valuation allowances increased a total of $87 million. This reflects increases of $174 million primarily related to U.S. foreign tax credit and foreign loss carryforwards, partially offset by decreases of $87 million, primarily related to utilization of U.S. foreign tax credit and state loss carryforwards, currency effects 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, 2011 and 2010, income considered to be permanently reinvested in certain foreign subsidiaries and foreign corporate joint ventures totaled approximately $4,227 million and $4,134 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 2011, 2010 and 2009:
| Millions of Dollars | ||||||||||||
| 2011 | 2010 | 2009 | ||||||||||
| Balance at January 1 |
$ | 1,125 | 1,208 | 1,068 | ||||||||
| Additions based on tax positions related to the current year |
46 | 63 | 18 | |||||||||
| Additions for tax positions of prior years |
145 | 344 | 177 | |||||||||
| Reductions for tax positions of prior years |
(35 | ) | (199 | ) | (33 | ) | ||||||
| Settlements |
(206 | ) | (215 | ) | (19 | ) | ||||||
| Lapse of statute |
(4 | ) | (76 | ) | (3 | ) | ||||||
| Balance at December 31 |
$ | 1,071 | 1,125 | 1,208 | ||||||||
Included in the balance of unrecognized tax benefits for 2011, 2010 and 2009 were $815 million, $914 million and $931 million, respectively, which, if recognized, would affect our effective tax rate.
At December 31, 2011, 2010 and 2009, accrued liabilities for interest and penalties totaled $141 million, $171 million and $166 million, respectively, net of accrued income taxes. Interest and penalties resulted in a charge to earnings in 2011 of $10 million, a benefit to earnings in 2010 of $2 million, and a charge to earnings in 2009 of $18 million.
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 (2008), Canada (2005), United States (2006) and Norway (2010). 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 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 |
|||||||||||||||||||||||||
| 2011 | 2010 | 2009 | 2011 | 2010 | 2009 | |||||||||||||||||||||
| Income before income taxes |
||||||||||||||||||||||||||
| United States |
$ | 11,217 | 6,214 | 2,456 | 48.8 | % | 31.5 | 25.6 | ||||||||||||||||||
| Foreign |
11,784 | 13,536 | 7,126 | 51.2 | 68.5 | 74.4 | ||||||||||||||||||||
| $ | 23,001 | 19,750 | 9,582 | 100.0 | % | 100.0 | 100.0 | |||||||||||||||||||
| Federal statutory income tax |
$ | 8,050 | 6,912 | 3,354 | 35.0 | % | 35.0 | 35.0 | ||||||||||||||||||
| Capital loss utilization |
(563 | ) | — | — | (2.5 | ) | — | — | ||||||||||||||||||
| Foreign taxes in excess of federal statutory rate |
2,736 | 1,308 | 1,716 | 11.9 | 6.6 | 17.9 | ||||||||||||||||||||
| Federal manufacturing deduction |
(122 | ) | (82 | ) | (19 | ) | (0.5 | ) | (0.4 | ) | (0.2 | ) | ||||||||||||||
| State income tax |
354 | 206 | 81 | 1.5 | 1.0 | 0.8 | ||||||||||||||||||||
| Other |
44 | (11 | ) | (42 | ) | 0.2 | — | (0.4 | ) | |||||||||||||||||
| $ | 10,499 | 8,333 | 5,090 | 45.6 | % | 42.2 | 53.1 | |||||||||||||||||||
During 2011, we recognized a significant tax capital loss on disposition of the legal entity which ultimately holds the Wilhelmshaven Refinery assets. A large portion of the tax benefit of this loss was realized in 2011 because of other capital gains that occurred.
The change in the effective tax rate from 2010 to 2011 was primarily due to the effect of asset dispositions occurring in 2010, partially offset by asset impairments occurring in 2010.
In the United Kingdom, legislation was enacted on July 19, 2011, which increased the supplementary corporate tax rate applicable to U.K. Upstream activity from 20 to 32 percent, retroactively effective from March 24, 2011. This resulted in the overall U.K. corporate rate increasing from 50 percent to 62 percent. The enactment resulted in increased income tax expense of $316 million in 2011. This is comprised of $106 million due to remeasurement of U.K. deferred tax liabilities, and $210 million to reflect the new rate from March 24, 2011, through the end of the year. Statutory tax rate changes did not have a significant impact on our income tax expense in 2010 or 2009.
Note 21—Accumulated Other Comprehensive Income
Accumulated other comprehensive income in the equity section of the balance sheet included:
| Millions of Dollars | ||||||||||||||||||||
| Defined Benefit Plans |
Net Unrealized Gain on Securities |
Foreign Currency Translation |
Hedging | Accumulated Other Comprehensive Income (Loss) |
||||||||||||||||
| December 31, 2008 |
$ | (1,434 | ) | — | (431 | ) | (10 | ) | (1,875 | ) | ||||||||||
| Other comprehensive income (loss) |
(70 | ) | — | 5,007 | 3 | 4,940 | ||||||||||||||
| December 31, 2009 |
(1,504 | ) | — | 4,576 | (7 | ) | 3,065 | |||||||||||||
| Other comprehensive income |
146 | 158 | 1,404 | — | 1,708 | |||||||||||||||
| December 31, 2010 |
(1,358 | ) | 158 | 5,980 | (7 | ) | 4,773 | |||||||||||||
| Other comprehensive income (loss) |
(613 | ) | (158 | ) | (917 | ) | 1 | (1,687 | ) | |||||||||||
| December 31, 2011 |
$ | (1,971 | ) | — | 5,063 | (6 | ) | 3,086 | ||||||||||||
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Note 22—Cash Flow Information
| Millions of Dollars | ||||||||||||
| 2011 | 2010 | 2009 | ||||||||||
| Noncash Investing and Financing Activities |
||||||||||||
| Increase in PP&E related to an increase in asset retirement obligations |
$ | 182 | 808 | 974 | ||||||||
| Cash Payments |
||||||||||||
| Interest |
$ | 932 | 1,210 | 998 | ||||||||
| Income taxes |
10,561 | 8,474 | 6,641 | |||||||||
| Net Sales (Purchases) of Short-Term Investments |
||||||||||||
| Short-term investments purchased |
$ | (6,744 | ) | (982 | ) | — | ||||||
| Short-term investments sold |
7,144 | — | — | |||||||||
| $ | 400 | (982 | ) | — | ||||||||
Note 23—Other Financial Information
| Millions of Dollars Except Per Share Amounts |
||||||||||||
| 2011 | 2010 | 2009 | ||||||||||
| Interest and Debt Expense |
||||||||||||
| Incurred |
||||||||||||
| Debt |
$ | 1,242 | 1,414 | 1,485 | ||||||||
| Other |
218 | 244 | 291 | |||||||||
| 1,460 | 1,658 | 1,776 | ||||||||||
| Capitalized |
(488 | ) | (471 | ) | (487 | ) | ||||||
| Expensed |
$ | 972 | 1,187 | 1,289 | ||||||||
| Other Income |
||||||||||||
| Interest income |
$ | 216 | 187 | 227 | ||||||||
| Other, net |
113 | 91 | 131 | |||||||||
| $ | 329 | 278 | 358 | |||||||||
| Research and Development Expenditures—expensed |
$ | 267 | 230 | 190 | ||||||||
| Advertising Expenses |
$ | 92 | 66 | 60 | ||||||||
| Shipping and Handling Costs* |
$ | 1,382 | 1,366 | 1,185 | ||||||||
| *Amounts included in production and operating expenses. | ||||||||||||
| Cash Dividends paid per common share |
$ | 2.64 | 2.15 | 1.91 | ||||||||
| Foreign Currency Transaction (Gains) Losses—after-tax |
||||||||||||
| E&P |
$ | (17 | ) | (60 | ) | 111 | ||||||
| Midstream |
— | — | — | |||||||||
| R&M |
(23 | ) | 60 | (36 | ) | |||||||
| LUKOIL Investment |
(2 | ) | 15 | (20 | ) | |||||||
| Chemicals |
— | — | — | |||||||||
| Emerging Businesses |
— | 1 | (2 | ) | ||||||||
| Corporate and Other |
(20 | ) | 15 | (97 | ) | |||||||
| $ | (62 | ) | 31 | (44 | ) | |||||||
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Note 24—Related Party Transactions
Significant transactions with related parties were:
| Millions of Dollars | ||||||||||||
| 2011 | 2010 | 2009 | ||||||||||
| Operating revenues and other income (a) |
$ | 8,353 | 7,333 | 7,200 | ||||||||
| Gain on dispositions (b) |
156 | 1,149 | — | |||||||||
| Purchases (c) |
20,696 | 15,819 | 12,779 | |||||||||
| Operating expenses and selling, general and administrative expenses (d) |
392 | 344 | 322 | |||||||||
| Net interest expense (e) |
71 | 73 | 74 | |||||||||
| (a) | We sold natural gas to DCP Midstream and crude oil to the Malaysian Refining Company Sdn. Bhd. (MRC), among others, for processing and marketing. Natural gas liquids, solvents and petrochemical feedstocks were sold to CPChem, gas oil and hydrogen feedstocks were sold to Excel Paralubes and refined products were sold primarily to CFJ Properties and LUKOIL. Beginning in the third quarter of 2010, CFJ was no longer considered a related party due to the sale of our interest. Natural gas, crude oil, blendstock and other intermediate products were sold to WRB. In addition, we charged several of our affiliates, including CPChem and MSLP, for the use of common facilities, such as steam generators, waste and water treaters and warehouse facilities. |
| (b) | In 2011, we sold the Seaway Products Pipeline to DCP Midstream for cash proceeds of $400 million, resulting in a before-tax gain of $156 million. During 2010, we sold a portion of our LUKOIL shares under a stock purchase and option agreement with a wholly owned subsidiary of LUKOIL, resulting in a before-tax gain of $1,149 million. |
| (c) | We purchased refined products from WRB. We purchased natural gas and natural gas liquids from DCP Midstream and CPChem for use in our refinery processes and other feedstocks from various affiliates. We purchased crude oil from LUKOIL and refined products from MRC. We also paid fees to various pipeline equity companies for transporting finished refined products and natural gas, as well as a price upgrade to MSLP for heavy crude processing. We purchased base oils and fuel products from Excel Paralubes for use in our refinery and specialty businesses. |
| (d) | We paid processing fees to various affiliates. Additionally, we paid transportation fees to pipeline equity companies. |
| (e) | We paid and/or received interest to/from various affiliates, including FCCL. See Note 6—Investments, Loans and Long-Term Receivables, for additional information on loans to affiliated companies. |
Beginning in the fourth quarter of 2010, transactions with LUKOIL and its subsidiaries were no longer considered related party transactions. See Note 6—Investments, Loans and Long-Term Receivables, for additional information.
Note 25—Segment Disclosures and Related Information
We have organized our reporting structure based on the grouping of similar products and services, resulting in six operating segments:
| 1) | E&P—This segment primarily explores for, produces, transports and markets crude oil, bitumen, natural gas, LNG and natural gas liquids on a worldwide basis. At December 31, 2011, our E&P |
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| operations were producing in the United States, Norway, the United Kingdom, Canada, Australia, offshore Timor-Leste in the Timor Sea, Indonesia, China, Vietnam, Libya, Nigeria, Algeria, Qatar and Russia. The E&P segment’s U.S. and international operations are disclosed separately for reporting purposes. |
| 2) | Midstream—This segment gathers, processes and markets natural gas produced by ConocoPhillips and others, and fractionates and markets natural gas liquids, predominantly in the United States and Trinidad. The Midstream segment primarily consists of our 50 percent equity investment in DCP Midstream. |
| 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, 2011, we owned or had an interest in 12 refineries in the United States, one in the United Kingdom, one in Ireland, one 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 prior investment in the ordinary shares of OAO LUKOIL, an international, integrated oil and gas company headquartered in Russia. We completed the divestiture of our entire interest in LUKOIL in the first quarter of 2011. |
| 5) | Chemicals—This segment manufactures and markets petrochemicals and plastics on a worldwide basis. The Chemicals segment consists of our 50 percent equity investment in CPChem. |
| 6) | Emerging Businesses—This segment represents our investment in new technologies or businesses outside our normal scope of operations. Activities within this segment are currently focused on power generation and innovation of new technologies, such as those related to conventional and nonconventional hydrocarbon recovery, refining, alternative energy, biofuels and the environment. |
Corporate and Other includes general corporate overhead, most interest expense and various other corporate activities. Corporate assets include all cash and cash equivalents and short-term investments.
We evaluate performance and allocate resources based on net income attributable to ConocoPhillips. Segment accounting policies are the same as those in Note 1—Accounting Policies. Intersegment sales are at prices that approximate market.
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Analysis of Results by Operating Segment
| Millions of Dollars | ||||||||||||
| 2011 | 2010 | 2009 | ||||||||||
| Sales and Other Operating Revenues |
||||||||||||
| E&P |
||||||||||||
| United States |
$ | 32,300 | 28,934 | 24,287 | ||||||||
| International |
32,966 | 27,992 | 24,222 | |||||||||
| Intersegment eliminations—U.S. |
(7,639 | ) | (5,653 | ) | (4,649 | ) | ||||||
| Intersegment eliminations—international |
(8,174 | ) | (7,748 | ) | (6,763 | ) | ||||||
| E&P |
49,453 | 43,525 | 37,097 | |||||||||
| Midstream |
||||||||||||
| Total sales |
9,228 | 7,714 | 5,199 | |||||||||
| Intersegment eliminations |
(499 | ) | (407 | ) | (307 | ) | ||||||
| Midstream |
8,729 | 7,307 | 4,892 | |||||||||
| R&M |
||||||||||||
| United States |
127,204 | 94,564 | 73,871 | |||||||||
| International |
60,373 | 44,721 | 34,025 | |||||||||
| Intersegment eliminations—U.S. |
(1,010 | ) | (763 | ) | (613 | ) | ||||||
| Intersegment eliminations—international |
(65 | ) | (101 | ) | (50 | ) | ||||||
| R&M |
186,502 | 138,421 | 107,233 | |||||||||
| LUKOIL Investment |
— | — | — | |||||||||
| Chemicals |
11 | 11 | 11 | |||||||||
| Emerging Businesses |
||||||||||||
| Total sales |
822 | 746 | 593 | |||||||||
| Intersegment eliminations |
(727 | ) | (595 | ) | (507 | ) | ||||||
| Emerging Businesses |
95 | 151 | 86 | |||||||||
| Corporate and Other |
23 | 26 | 22 | |||||||||
| Consolidated sales and other operating revenues |
$ | 244,813 | 189,441 | 149,341 | ||||||||
| Depreciation, Depletion, Amortization and Impairments | ||||||||||||
| E&P |
||||||||||||
| United States |
$ | 2,800 | 2,909 | 3,346 | ||||||||
| International |
4,429 | 5,268 | 5,459 | |||||||||
| Total E&P |
7,229 | 8,177 | 8,805 | |||||||||
| Midstream |
6 | 6 | 6 | |||||||||
| R&M |
||||||||||||
| United States |
1,180 | 711 | 707 | |||||||||
| International |
149 | 1,789 | 215 | |||||||||
| Total R&M |
1,329 | 2,500 | 922 | |||||||||
| LUKOIL Investment |
— | — | — | |||||||||
| Chemicals |
— | — | — | |||||||||
| Emerging Businesses |
54 | 78 | 21 | |||||||||
| Corporate and Other |
108 | 79 | 76 | |||||||||
| Consolidated depreciation, depletion, amortization and impairments |
$ | 8,726 | 10,840 | 9,830 | ||||||||
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| Millions of Dollars | ||||||||||||
| 2011 | 2010 | 2009 | ||||||||||
| Equity in Earnings of Affiliates |
||||||||||||
| E&P |
||||||||||||
| United States |
$ | (53 | ) | 39 | (2 | ) | ||||||
| International |
1,214 | (14 | ) | 233 | ||||||||
| Total E&P |
1,161 | 25 | 231 | |||||||||
| Midstream |
563 | 411 | 342 | |||||||||
| R&M |
||||||||||||
| United States |
1,283 | 607 | 428 | |||||||||
| International |
95 | 113 | 13 | |||||||||
| Total R&M |
1,378 | 720 | 441 | |||||||||
| LUKOIL Investment |
— | 1,295 | 1,219 | |||||||||
| Chemicals |
975 | 684 | 298 | |||||||||
| Emerging Businesses |
— | (2 | ) | — | ||||||||
| Corporate and Other |
— | — | — | |||||||||
| Consolidated equity in earnings of affiliates |
$ | 4,077 | 3,133 | 2,531 | ||||||||
| Income Taxes |
||||||||||||
| E&P |
||||||||||||
| United States |
$ | 1,901 | 1,570 | 786 | ||||||||
| International |
6,929 | 6,124 | 4,325 | |||||||||
| Total E&P |
8,830 | 7,694 | 5,111 | |||||||||
| Midstream |
236 | 158 | 171 | |||||||||
| R&M |
||||||||||||
| United States |
1,477 | 645 | 32 | |||||||||
| International |
(42 | ) | (414 | ) | 9 | |||||||
| Total R&M |
1,435 | 231 | 41 | |||||||||
| LUKOIL Investment |
123 | 514 | 12 | |||||||||
| Chemicals |
225 | 182 | 47 | |||||||||
| Emerging Businesses |
(49 | ) | (54 | ) | (16 | ) | ||||||
| Corporate and Other |
(301 | ) | (392 | ) | (276 | ) | ||||||
| Consolidated income taxes |
$ | 10,499 | 8,333 | 5,090 | ||||||||
| Net Income Attributable to ConocoPhillips |
||||||||||||
| E&P |
||||||||||||
| United States |
$ | 3,254 | 2,768 | 1,503 | ||||||||
| International |
4,988 | 6,430 | 2,101 | |||||||||
| Total E&P |
8,242 | 9,198 | 3,604 | |||||||||
| Midstream |
458 | 306 | 313 | |||||||||
| R&M |
||||||||||||
| United States |
3,595 | 1,022 | (192 | ) | ||||||||
| International |
156 | (830 | ) | 229 | ||||||||
| Total R&M |
3,751 | 192 | 37 | |||||||||
| LUKOIL Investment |
239 | 2,503 | 1,219 | |||||||||
| Chemicals |
745 | 498 | 248 | |||||||||
| Emerging Businesses |
(26 | ) | (59 | ) | 3 | |||||||
| Corporate and Other |
(973 | ) | (1,280 | ) | (1,010 | ) | ||||||
| Consolidated net income attributable to ConocoPhillips |
$ | 12,436 | 11,358 | 4,414 | ||||||||
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| Millions of Dollars | ||||||||||||
| 2011 | 2010 | 2009 | ||||||||||
| Investments In and Advances To Affiliates |
||||||||||||
| E&P |
||||||||||||
| United States |
$ | 1,822 | 1,989 | 1,978 | ||||||||
| International |
21,192 | 21,049 | 19,646 | |||||||||
| Total E&P |
23,014 | 23,038 | 21,624 | |||||||||
| Midstream |
1,146 | 1,240 | 1,199 | |||||||||
| R&M |
||||||||||||
| United States |
4,090 | 4,059 | 3,982 | |||||||||
| International |
1,326 | 1,304 | 1,142 | |||||||||
| Total R&M |
5,416 | 5,363 | 5,124 | |||||||||
| LUKOIL Investment |
— | — | 6,411 | |||||||||
| Chemicals |
2,998 | 2,518 | 2,446 | |||||||||
| Emerging Businesses |
86 | 76 | 77 | |||||||||
| Corporate and Other |
— | — | — | |||||||||
| Consolidated investments in and advances to affiliates(1) |
$ | 32,660 | 32,235 | 36,881 | ||||||||
| (1) Includes amounts classified as held for sale: |
$ | — | — | 249 | ||||||||
| Total Assets |
||||||||||||
| E&P |
||||||||||||
| United States |
$ | 37,150 | 35,607 | 36,122 | ||||||||
| International |
64,752 | 63,086 | 64,831 | |||||||||
| Total E&P |
101,902 | 98,693 | 100,953 | |||||||||
| Midstream |
2,338 | 2,506 | 2,054 | |||||||||
| R&M |
||||||||||||
| United States |
24,976 | 26,028 | 24,963 | |||||||||
| International |
8,061 | 8,463 | 8,446 | |||||||||
| Goodwill |
3,332 | 3,633 | 3,638 | |||||||||
| Total R&M |
36,369 | 38,124 | 37,047 | |||||||||
| LUKOIL Investment |
— | 1,129 | 6,416 | |||||||||
| Chemicals |
2,999 | 2,732 | 2,451 | |||||||||
| Emerging Businesses |
974 | 964 | 1,069 | |||||||||
| Corporate and Other |
8,648 | 12,166 | 2,148 | |||||||||
| Consolidated total assets |
$ | 153,230 | 156,314 | 152,138 | ||||||||
| Capital Expenditures and Investments |
||||||||||||
| E&P |
||||||||||||
| United States |
$ | 4,655 | 2,585 | 3,474 | ||||||||
| International |
7,350 | 5,908 | 5,425 | |||||||||
| Total E&P |
12,005 | 8,493 | 8,899 | |||||||||
| Midstream |
17 | 3 | 5 | |||||||||
| R&M |
||||||||||||
| United States |
768 | 790 | 1,299 | |||||||||
| International |
226 | 266 | 427 | |||||||||
| Total R&M |
994 | 1,056 | 1,726 | |||||||||
| LUKOIL Investment |
— | — | — | |||||||||
| Chemicals |
— | — | — | |||||||||
| Emerging Businesses |
30 | 27 | 97 | |||||||||
| Corporate and Other |
220 | 182 | 134 | |||||||||
| Consolidated capital expenditures and investments |
$ | 13,266 | 9,761 | 10,861 | ||||||||
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| Millions of Dollars | ||||||||||||
| 2011 | 2010 | 2009 | ||||||||||
| Interest Income and Expense |
||||||||||||
| Interest income |
||||||||||||
| Corporate |
$ | 108 | 64 | 89 | ||||||||
| E&P |
75 | 81 | 91 | |||||||||
| R&M |
33 | 42 | 47 | |||||||||
| Interest and debt expense |
||||||||||||
| Corporate |
$ | 851 | 1,047 | 1,133 | ||||||||
| E&P |
121 | 140 | 156 | |||||||||
Geographic Information
| Millions of Dollars | ||||||||||||||||||||||||||
| Sales and Other Operating Revenues* | Long-Lived Assets** | |||||||||||||||||||||||||
| 2011 | 2010 | 2009 | 2011 | 2010 | 2009 | |||||||||||||||||||||
| United States |
$ | 159,129 | 124,173 | 97,674 | 55,198 | 53,706 | 53,761 | |||||||||||||||||||
| Australia*** |
3,458 | 2,789 | 2,229 | 12,572 | 12,461 | 10,729 | ||||||||||||||||||||
| Canada |
7,076 | 4,784 | 3,617 | 20,083 | 20,439 | 22,451 | ||||||||||||||||||||
| Norway |
2,209 | 2,248 | 1,749 | 5,918 | 5,664 | 5,797 | ||||||||||||||||||||
| Russia |
— | — | — | 341 | 815 | 8,383 | ||||||||||||||||||||
| United Kingdom |
36,252 | 26,693 | 20,671 | 5,168 | 4,885 | 5,778 | ||||||||||||||||||||
| Other foreign countries |
36,689 | 28,754 | 23,401 | 17,560 | 16,819 | 17,441 | ||||||||||||||||||||
| Worldwide consolidated |
$ | 244,813 | 189,441 | 149,341 | 116,840 | 114,789 | 124,340 | |||||||||||||||||||
| * | Sales and other operating revenues are attributable to countries based on the location of the operations generating the revenues. |
| ** | Defined as net PP&E 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—Planned Separation of Downstream Businesses
On July 14, 2011, we announced approval by our Board of Directors to pursue the separation of our refining, marketing and transportation businesses into a stand-alone, publicly traded corporation via a tax-free distribution. The new downstream company, named Phillips 66, will be headquartered in Houston, Texas. In addition to the refining, marketing and transportation businesses, we expect Phillips 66 will also include most of our Midstream segment, our Chemicals segment, as well as our power generation and certain technology operations included in our Emerging Businesses segment, to create an integrated downstream company. The separation is to be accomplished by the pro rata distribution of one share of Phillips 66 stock for every two shares of ConocoPhillips stock held by ConocoPhillips’ shareholders on the record date for the share distribution.
In October 2011, we requested a private letter ruling from the U.S. Internal Revenue Service, which is expected to confirm the distribution will qualify as a tax-free reorganization for U.S. federal income tax purposes. In addition, we filed the initial Phillips 66 Form 10 registration statement with the U.S. Securities and Exchange Commission on November 14, 2011, and an amendment on January 3, 2012.
The separation is subject to market conditions, customary regulatory approvals, the receipt of an affirmative Internal Revenue Service private letter ruling and final Board approval, and is expected to be completed in the second quarter of 2012.
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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, for periods prior to 2011, amounts reported as equity affiliates in Oil and Gas Operations may differ from those shown in the individual segment disclosures reported elsewhere in this report.
Our proved reserves include estimated quantities related to production sharing contracts (PSCs), which are reported under the “economic interest” method and are subject to fluctuations in commodity prices; recoverable operating expenses; and capital costs. If costs remain stable, reserve quantities attributable to recovery of costs will change inversely to changes in commodity prices. For example, if prices increase, then our applicable reserve quantities would decline. At December 31, 2011, approximately 10 percent of our total proved reserves were under PSCs, primarily in our Asia Pacific/Middle East geographic reporting area.
Our disclosures by geographic area include the United States, Canada, Europe (primarily Norway and the United Kingdom), Russia, Asia Pacific/Middle East, Africa and Other Areas. Other Areas primarily consists of the Caspian Region.
In the following disclosures, the synthetic oil classification included our past Syncrude mining operations, and the bitumen classification includes our Surmont operations and the FCCL Partnership. In June 2010, we sold our interest in the Syncrude Canada Ltd. joint venture; accordingly, as of December 31, 2010, we no longer held synthetic oil reserves.
On July 28, 2010, we announced our intention to sell our entire interest in LUKOIL over a period of time through the end of 2011. As a result of this sell down of our interest, at the end of the third quarter of 2010 we ceased using equity-method accounting for our investment in LUKOIL. Accordingly, the supplemental oil and gas disclosures reflect activity for LUKOIL through June 30, 2010, which, on a lag basis, results in three quarters of activity being included in the year 2010 (the fourth quarter of 2009 and the first two quarters of 2010). Since the proved reserves tables are not on a lag basis, they reflect activity for the first three quarters of 2010, at which point LUKOIL’s reserves were removed from our reserve quantities.
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.
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We have a companywide, comprehensive, SEC-compliant internal policy that governs the determination and reporting of proved reserves. This policy is applied by the geologists and reservoir engineers in our E&P business units around the world. As part of our internal control process, each business unit’s reserves are reviewed annually by an internal team which is headed by the Company’s Manager of Reserves Compliance and Reporting. This team, composed of internal reservoir engineers, geologists and finance personnel, reviews the business units’ reserves for adherence to SEC guidelines and company policy through on-site visits and review of documentation. In addition to providing independent reviews, this internal team also ensures reserves are calculated using consistent and appropriate standards and procedures. This team is independent of business unit line management and is responsible for reporting its findings to senior management and our internal audit group. The team is responsible for communicating our reserves policy and procedures and is available for internal peer reviews and consultation on major projects or technical issues throughout the year. All of our proved reserves held by consolidated companies and our share of equity affiliates have been estimated by ConocoPhillips.
The technical person primarily responsible for overseeing the preparation of the Company’s reserve estimates is the Manager of Reserves Compliance and Reporting. This individual is a petroleum engineer with a bachelor’s degree in petroleum engineering. He is an active member of the Society of Petroleum Engineers (SPE) with over 30 years of oil and gas industry experience, including drilling and production engineering assignments in several field locations. He is currently serving a three-year term on the Oil & Gas Reserves Committee of the SPE and has held positions of increasing responsibility in reservoir engineering, reserves reporting and compliance, and business management.
During 2011, our processes and controls used to assess over 90 percent of proved reserves as of December 31, 2011, were reviewed by DeGolyer and MacNaughton (D&M), a third-party petroleum engineering consulting firm. The purpose of their review was to assess whether the adequacy and effectiveness of our internal processes and controls used to determine estimates of proved reserves are in accordance with SEC regulations. In such review, ConocoPhillips’ technical staff presented D&M with an overview of the reserves data, as well as the methods and assumptions used in estimating reserves. The data presented included pertinent seismic information, geologic maps, well logs, production tests, material balance calculations, reservoir simulation models, well performance data, operating procedures and relevant economic criteria. Management’s intent in retaining D&M to review its processes and controls was to provide objective third-party input on these processes and controls. D&M’s opinion was that the general processes and controls employed by ConocoPhillips in estimating its December 31, 2011, proved reserves for the properties reviewed are in accordance with the SEC reserves definitions. D&M’s report is included as Exhibit 99 to the Company’s 2011 Annual Report on Form 10-K.
Engineering estimates of the quantities of proved reserves are inherently imprecise. See the “Critical Accounting Estimates” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional discussion of the sensitivities surrounding these estimates.
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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 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 | ||||||||||||||||||||||||||||||
| Revisions |
81 | 8 | 89 | 15 | 28 | — | 7 | 21 | — | 160 | ||||||||||||||||||||||||||||||
| Improved recovery |
51 | 2 | 53 | — | — | — | 5 | — | — | 58 | ||||||||||||||||||||||||||||||
| Purchases |
— | 1 | 1 | — | — | — | — | — | — | 1 | ||||||||||||||||||||||||||||||
| Extensions and discoveries |
17 | 30 | 47 | 4 | 18 | — | 7 | 10 | — | 86 | ||||||||||||||||||||||||||||||
| Production |
(84 | ) | (55 | ) | (139 | ) | (14 | ) | (78 | ) | — | (51 | ) | (28 | ) | — | (310 | ) | ||||||||||||||||||||||
| Sales |
— | (22 | ) | (22 | ) | (6 | ) | — | — | — | — | — | (28 | ) | ||||||||||||||||||||||||||
| End of 2010 |
1,285 | 649 | 1,934 | 80 | 469 | — | 300 | 270 | 108 | 3,161 | ||||||||||||||||||||||||||||||
| Revisions |
70 | 45 | 115 | 10 | (3 | ) | — | (7 | ) | 5 | — | 120 | ||||||||||||||||||||||||||||
| Improved recovery |
14 | 3 | 17 | 1 | 51 | — | 13 | — | — | 82 | ||||||||||||||||||||||||||||||
| Purchases |
— | 1 | 1 | — | — | — | — | — | — | 1 | ||||||||||||||||||||||||||||||
| Extensions and discoveries |
21 | 68 | 89 | 4 | 102 | — | 8 | — | — | 203 | ||||||||||||||||||||||||||||||
| Production |
(79 | ) | (60 | ) | (139 | ) | (13 | ) | (64 | ) | — | (41 | ) | (14 | ) | — | (271 | ) | ||||||||||||||||||||||
| Sales |
— | (8 | ) | (8 | ) | (1 | ) | — | — | — | — | — | (9 | ) | ||||||||||||||||||||||||||
| End of 2011 |
1,311 | 698 | 2,009 | 81 | 555 | — | 273 | 261 | 108 | 3,287 | ||||||||||||||||||||||||||||||
| Equity affiliates |
||||||||||||||||||||||||||||||||||||||||
| 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 | ||||||||||||||||||||||||||||||
| Revisions |
— | — | — | — | — | 6 | 51 | — | — | 57 | ||||||||||||||||||||||||||||||
| Improved recovery |
— | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||
| Purchases |
— | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||
| Extensions and discoveries |
— | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||
| Production |
— | — | — | — | — | (114 | ) | (1 | ) | — | — | (115 | ) | |||||||||||||||||||||||||||
| Sales |
— | — | — | — | — | (1,421 | ) | — | — | — | (1,421 | ) | ||||||||||||||||||||||||||||
| End of 2010 |
— | — | — | — | — | 75 | 156 | — | — | 231 | ||||||||||||||||||||||||||||||
| Revisions |
— | — | — | — | — | (37 | ) | — | — | — | (37 | ) | ||||||||||||||||||||||||||||
| Improved recovery |
— | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||
| Purchases |
— | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||
| Extensions and discoveries |
— | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||
| Production |
— | — | — | — | — | (11 | ) | (8 | ) | — | — | (19 | ) | |||||||||||||||||||||||||||
| Sales |
— | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||
| End of 2011 |
— | — | — | — | — | 27 | 148 | — | — | 175 | ||||||||||||||||||||||||||||||
| Total company |
||||||||||||||||||||||||||||||||||||||||
| 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 | ||||||||||||||||||||||||||||||
| End of 2010 |
1,285 | 649 | 1,934 | 80 | 469 | 75 | 456 | 270 | 108 | 3,392 | ||||||||||||||||||||||||||||||
| End of 2011 |
1,311 | 698 | 2,009 | 81 | 555 | 27 | 421 | 261 | 108 | 3,462 | ||||||||||||||||||||||||||||||
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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 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 | ||||||||||||||||||||||||||||||
| End of 2010 |
1,155 | 534 | 1,689 | 75 | 290 | — | 218 | 251 | — | 2,523 | ||||||||||||||||||||||||||||||
| End of 2011 |
1,182 | 564 | 1,746 | 74 | 317 | — | 187 | 248 | — | 2,572 | ||||||||||||||||||||||||||||||
| Equity affiliates |
||||||||||||||||||||||||||||||||||||||||
| End of 2008 |
— | — | — | — | — | 1,228 | — | — | — | 1,228 | ||||||||||||||||||||||||||||||
| End of 2009 |
— | — | — | — | — | 1,213 | — | — | — | 1,213 | ||||||||||||||||||||||||||||||
| End of 2010 |
— | — | — | — | — | 73 | 156 | — | — | 229 | ||||||||||||||||||||||||||||||
| End of 2011 |
— | — | — | — | — | 27 | 148 | — | — | 175 | ||||||||||||||||||||||||||||||
| Undeveloped |
||||||||||||||||||||||||||||||||||||||||
| Consolidated operations |
||||||||||||||||||||||||||||||||||||||||
| End of 2008 |
98 | 154 | 252 | 8 | 210 | — | 147 | 18 | 115 | 750 | ||||||||||||||||||||||||||||||
| End of 2009 |
90 | 127 | 217 | 4 | 189 | — | 111 | 21 | 108 | 650 | ||||||||||||||||||||||||||||||
| End of 2010 |
130 | 115 | 245 | 5 | 179 | — | 82 | 19 | 108 | 638 | ||||||||||||||||||||||||||||||
| End of 2011 |
129 | 134 | 263 | 7 | 238 | — | 86 | 13 | 108 | 715 | ||||||||||||||||||||||||||||||
| Equity affiliates |
||||||||||||||||||||||||||||||||||||||||
| End of 2008 |
— | — | — | — | — | 340 | 109 | — | — | 449 | ||||||||||||||||||||||||||||||
| End of 2009 |
— | — | — | — | — | 391 | 106 | — | — | 497 | ||||||||||||||||||||||||||||||
| End of 2010 |
— | — | — | — | — | 2 | — | — | — | 2 | ||||||||||||||||||||||||||||||
| End of 2011 |
— | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||
Notable changes in proved crude oil and natural gas liquids reserves in the three years ended December 31, 2011, included:
| • | Revisions: In 2009, revisions in Alaska were primarily due to higher prices in 2009, versus 2008. |
| • | Extensions and discoveries: In 2011, extensions and discoveries in Europe were primarily due to the sanctioning of the Ekofisk South and Clair Ridge development projects in the North Sea. |
| • | Sales: In 2010, for our equity affiliates in Russia, sales were primarily due to the disposition of our interest in LUKOIL. |
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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 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 | ||||||||||||||||||||||||||||||
| Revisions |
155 | 365 | 520 | 309 | 86 | — | (39 | ) | 36 | — | 912 | |||||||||||||||||||||||||||||
| Improved recovery |
24 | 1 | 25 | — | — | — | — | — | — | 25 | ||||||||||||||||||||||||||||||
| Purchases |
— | 9 | 9 | — | — | — | — | — | — | 9 | ||||||||||||||||||||||||||||||
| Extensions and discoveries |
4 | 122 | 126 | 84 | 89 | — | 24 | — | — | 323 | ||||||||||||||||||||||||||||||
| Production |
(101 | ) | (663 | ) | (764 | ) | (358 | ) | (323 | ) | — | (289 | ) | (60 | ) | — | (1,794 | ) | ||||||||||||||||||||||
| Sales |
— | (179 | ) | (179 | ) | (26 | ) | — | — | — | — | — | (205 | ) | ||||||||||||||||||||||||||
| End of 2010 |
2,862 | 7,617 | 10,479 | 2,305 | 1,861 | — | 2,608 | 926 | 56 | 18,235 | ||||||||||||||||||||||||||||||
| Revisions |
186 | 15 | 201 | 134 | 70 | — | (8 | ) | 9 | — | 406 | |||||||||||||||||||||||||||||
| Improved recovery |
1 | 5 | 6 | — | 53 | — | — | — | — | 59 | ||||||||||||||||||||||||||||||
| Purchases |
— | 7 | 7 | 1 | — | — | — | — | — | 8 | ||||||||||||||||||||||||||||||
| Extensions and discoveries |
3 | 171 | 174 | 78 | 158 | — | 192 | — | — | 602 | ||||||||||||||||||||||||||||||
| Production |
(92 | ) | (616 | ) | (708 | ) | (338 | ) | (246 | ) | — | (277 | ) | (63 | ) | — | (1,632 | ) | ||||||||||||||||||||||
| Sales |
— | (11 | ) | (11 | ) | (67 | ) | — | — | — | — | — | (78 | ) | ||||||||||||||||||||||||||
| End of 2011 |
2,960 | 7,188 | 10,148 | 2,113 | 1,896 | — | 2,515 | 872 | 56 | 17,600 | ||||||||||||||||||||||||||||||
| Equity affiliates |
||||||||||||||||||||||||||||||||||||||||
| 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 | ||||||||||||||||||||||||||||||
| Revisions |
— | — | — | — | — | 19 | 683 | — | — | 702 | ||||||||||||||||||||||||||||||
| Improved recovery |
— | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||
| Purchases |
— | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||
| Extensions and discoveries |
— | — | — | — | — | — | 269 | — | — | 269 | ||||||||||||||||||||||||||||||
| Production |
— | — | — | — | — | (91 | ) | (65 | ) | — | — | (156 | ) | |||||||||||||||||||||||||||
| Sales |
— | — | — | — | — | (2,616 | ) | — | — | — | (2,616 | ) | ||||||||||||||||||||||||||||
| End of 2010 |
— | — | — | — | — | 17 | 3,464 | — | — | 3,481 | ||||||||||||||||||||||||||||||
| Revisions |
— | — | — | — | — | (11 | ) | (76 | ) | — | — | (87 | ) | |||||||||||||||||||||||||||
| Improved recovery |
— | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||
| Purchases |
— | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||
| Extensions and discoveries |
— | — | — | — | — | — | 259 | — | — | 259 | ||||||||||||||||||||||||||||||
| Production |
— | — | — | — | — | (2 | ) | (184 | ) | — | — | (186 | ) | |||||||||||||||||||||||||||
| Sales |
— | — | — | — | — | — | (151 | ) | — | — | (151 | ) | ||||||||||||||||||||||||||||
| End of 2011 |
— | — | — | — | — | 4 | 3,312 | — | — | 3,316 | ||||||||||||||||||||||||||||||
| Total company |
||||||||||||||||||||||||||||||||||||||||
| 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 | ||||||||||||||||||||||||||||||
| End of 2010 |
2,862 | 7,617 | 10,479 | 2,305 | 1,861 | 17 | 6,072 | 926 | 56 | 21,716 | ||||||||||||||||||||||||||||||
| End of 2011 |
2,960 | 7,188 | 10,148 | 2,113 | 1,896 | 4 | 5,827 | 872 | 56 | 20,916 | ||||||||||||||||||||||||||||||
A-106
Table of Contents
| 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 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 | ||||||||||||||||||||||||||||||
| End of 2010 |
2,785 | 6,399 | 9,184 | 2,134 | 1,529 | — | 2,136 | 865 | — | 15,848 | ||||||||||||||||||||||||||||||
| End of 2011 |
2,907 | 6,194 | 9,101 | 1,932 | 1,439 | — | 1,932 | 738 | — | 15,142 | ||||||||||||||||||||||||||||||
| Equity affiliates |
||||||||||||||||||||||||||||||||||||||||
| End of 2008 |
— | — | — | — | — | 1,458 | 361 | — | — | 1,819 | ||||||||||||||||||||||||||||||
| End of 2009 |
— | — | — | — | — | 1,506 | 307 | — | — | 1,813 | ||||||||||||||||||||||||||||||
| End of 2010 |
— | — | — | — | — | 17 | 3,114 | — | — | 3,131 | ||||||||||||||||||||||||||||||
| End of 2011 |
— | — | — | — | — | 4 | 2,943 | — | — | 2,947 | ||||||||||||||||||||||||||||||
| Undeveloped |
||||||||||||||||||||||||||||||||||||||||
| Consolidated operations |
||||||||||||||||||||||||||||||||||||||||
| 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 | ||||||||||||||||||||||||||||||
| End of 2010 |
77 | 1,218 | 1,295 | 171 | 332 | — | 472 | 61 | 56 | 2,387 | ||||||||||||||||||||||||||||||
| End of 2011 |
53 | 994 | 1,047 | 181 | 457 | — | 583 | 134 | 56 | 2,458 | ||||||||||||||||||||||||||||||
| Equity affiliates |
||||||||||||||||||||||||||||||||||||||||
| End of 2008 |
— | — | — | — | — | 811 | 2,158 | — | — | 2,969 | ||||||||||||||||||||||||||||||
| End of 2009 |
— | — | — | — | — | 1,199 | 2,270 | — | — | 3,469 | ||||||||||||||||||||||||||||||
| End of 2010 |
— | — | — | — | — | — | 350 | — | — | 350 | ||||||||||||||||||||||||||||||
| End of 2011 |
— | — | — | — | — | — | 369 | — | — | 369 | ||||||||||||||||||||||||||||||
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, 2011, included:
| • | Revisions: In 2010, revisions in Alaska, Lower 48 and Canada were primarily due to higher prices in 2010, versus 2009, as well as improved well performance. In 2009, revisions in Alaska were primarily due to higher prices in 2009, versus 2008. 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. |
| • | Extensions and discoveries: In 2011, for our equity affiliate operations in Asia Pacific/Middle East, extensions and discoveries were primarily due to ongoing development drilling onshore Australia associated with the APLNG Project. In 2010, extensions and discoveries in Lower 48 and Canada were primarily due to continued drilling success in various fields. In 2009, for our equity affiliate operations in Asia Pacific/Middle East, extensions and discoveries primarily resulted from drilling success in Australia related to a coalbed methane project. |
| • | Sales: In 2010, for our equity affiliates in Russia, sales were primarily due to the disposition of our interest in LUKOIL. |
A-107
Table of Contents
| Years Ended | Other Products | |||||||||
| December 31 | Millions of Barrels | |||||||||
| Synthetic Oil | Bitumen | |||||||||
| Canada | Canada | |||||||||
| Developed and Undeveloped |
||||||||||
| Consolidated operations |
||||||||||
| End of 2008 |
— | 100 | ||||||||
| Revisions |
256 | 152 | ||||||||
| Improved recovery |
— | — | ||||||||
| Purchases |
— | — | ||||||||
| Extensions and discoveries |
— | 167 | ||||||||
| Production |
(8 | ) | (2 | ) | ||||||
| Sales |
— | — | ||||||||
| End of 2009 |
248 | 417 | ||||||||
| Revisions |
— | 42 | ||||||||
| Improved recovery |
— | — | ||||||||
| Purchases |
— | — | ||||||||
| Extensions and discoveries |
— | — | ||||||||
| Production |
(4 | ) | (4 | ) | ||||||
| Sales |
(244 | ) | — | |||||||
| End of 2010 |
— | 455 | ||||||||
| Revisions |
— | (1 | ) | |||||||
| Improved recovery |
— | — | ||||||||
| Purchases |
— | — | ||||||||
| Extensions and discoveries |
— | 79 | ||||||||
| Production |
— | (3 | ) | |||||||
| Sales |
— | — | ||||||||
| End of 2011 |
— | 530 | ||||||||
| Equity affiliates |
||||||||||
| End of 2008 |
— | 700 | ||||||||
| Revisions |
— | (87 | ) | |||||||
| Improved recovery |
— | — | ||||||||
| Purchases |
— | — | ||||||||
| Extensions and discoveries |
— | 118 | ||||||||
| Production |
— | (15 | ) | |||||||
| Sales |
— | — | ||||||||
| End of 2009 |
— | 716 | ||||||||
| Revisions |
— | 13 | ||||||||
| Improved recovery |
— | — | ||||||||
| Purchases |
— | — | ||||||||
| Extensions and discoveries |
— | 133 | ||||||||
| Production |
— | (18 | ) | |||||||
| Sales |
— | — | ||||||||
| End of 2010 |
— | 844 | ||||||||
| Revisions |
— | (101 | ) | |||||||
| Improved recovery |
— | — | ||||||||
| Purchases |
— | — | ||||||||
| Extensions and discoveries |
— | 187 | ||||||||
| Production |
— | (21 | ) | |||||||
| Sales |
— | — | ||||||||
| End of 2011 |
— | 909 | ||||||||
A-108
Table of Contents
| Years Ended | Other Products | |||||||||
| December 31 | Millions of Barrels | |||||||||
| Synthetic Oil | Bitumen | |||||||||
| Canada | Canada | |||||||||
| Developed and Undeveloped (continued) Total company |
||||||||||
| End of 2008 |
— | 800 | ||||||||
| End of 2009 |
248 | 1,133 | ||||||||
| End of 2010 |
— | 1,299 | ||||||||
| End of 2011 |
— | 1,439 | ||||||||
| Developed |
||||||||||
| Consolidated operations |
||||||||||
| End of 2008 |
— | 24 | ||||||||
| End of 2009 |
248 | 24 | ||||||||
| End of 2010 |
— | 34 | ||||||||
| End of 2011 |
— | 29 | ||||||||
| Equity affiliates |
||||||||||
| End of 2008 |
— | 105 | ||||||||
| End of 2009 |
— | 116 | ||||||||
| End of 2010 |
— | 142 | ||||||||
| End of 2011 |
— | 131 | ||||||||
| Undeveloped |
||||||||||
| Consolidated operations |
||||||||||
| End of 2008 |
— | 76 | ||||||||
| End of 2009 |
— | 393 | ||||||||
| End of 2010 |
— | 421 | ||||||||
| End of 2011 |
— | 501 | ||||||||
| Equity affiliates |
||||||||||
| End of 2008 |
— | 595 | ||||||||
| End of 2009 |
— | 600 | ||||||||
| End of 2010 |
— | 702 | ||||||||
| End of 2011 |
— | 778 | ||||||||
Notable changes in proved synthetic oil and bitumen reserves in the three years ended December 31, 2011, included:
| • | Revisions: In 2011, for our bitumen equity operations, revisions were primarily due to new subsurface interpretations, as well as the effects of higher prices on sliding scale royalty provisions. In 2009, for synthetic oil consolidated operations, revisions reflect our Syncrude Canada Ltd. operations. 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. |
| • | Extensions and discoveries: In 2011, for our consolidated operations, extensions and discoveries were related to continued development of Surmont. For our equity affiliate operations, extensions and discoveries were related to the sanctioning of new projects in FCCL. In 2009, for our bitumen consolidated operations, extensions and discoveries were related to the sanction of the Surmont Phase II Project. In 2010 and 2009, for our equity affiliate operations, extensions and discoveries mainly reflect the continued development of FCCL. |
| • | Sales: In 2010, for synthetic oil consolidated operations, sales reflect the disposition of our interest in Syncrude. |
A-109
Table of Contents
| Years Ended | Total Proved Reserves | |||||||||||||||||||||||||||||||||||||||
| December 31 | 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 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 | ||||||||||||||||||||||||||||||
| Revisions |
107 | 68 | 175 | 109 | 42 | — | 1 | 27 | — | 354 | ||||||||||||||||||||||||||||||
| Improved recovery |
55 | 2 | 57 | — | — | — | 5 | — | — | 62 | ||||||||||||||||||||||||||||||
| Purchases |
— | 2 | 2 | — | — | — | — | — | — | 2 | ||||||||||||||||||||||||||||||
| Extensions and discoveries |
17 | 51 | 68 | 18 | 33 | — | 11 | 10 | — | 140 | ||||||||||||||||||||||||||||||
| Production |
(101 | ) | (165 | ) | (266 | ) | (82 | ) | (132 | ) | — | (99 | ) | (38 | ) | — | (617 | ) | ||||||||||||||||||||||
| Sales |
— | (52 | ) | (52 | ) | (254 | ) | — | — | — | — | — | (306 | ) | ||||||||||||||||||||||||||
| End of 2010 |
1,762 | 1,918 | 3,680 | 920 | 779 | — | 735 | 424 | 117 | 6,655 | ||||||||||||||||||||||||||||||
| Revisions |
101 | 48 | 149 | 31 | 8 | — | (9 | ) | 7 | — | 186 | |||||||||||||||||||||||||||||
| Improved recovery |
14 | 4 | 18 | 1 | 60 | — | 13 | — | — | 92 | ||||||||||||||||||||||||||||||
| Purchases |
— | 2 | 2 | — | — | — | — | — | — | 2 | ||||||||||||||||||||||||||||||
| Extensions and discoveries |
21 | 97 | 118 | 97 | 128 | — | 40 | — | — | 383 | ||||||||||||||||||||||||||||||
| Production |
(94 | ) | (163 | ) | (257 | ) | (73 | ) | (105 | ) | — | (86 | ) | (25 | ) | — | (546 | ) | ||||||||||||||||||||||
| Sales |
— | (10 | ) | (10 | ) | (12 | ) | — | — | — | — | — | (22 | ) | ||||||||||||||||||||||||||
| End of 2011 |
1,804 | 1,896 | 3,700 | 964 | 870 | — | 693 | 406 | 117 | 6,750 | ||||||||||||||||||||||||||||||
| Equity affiliates |
||||||||||||||||||||||||||||||||||||||||
| 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 | ||||||||||||||||||||||||||||||
| Revisions |
— | — | — | 13 | — | 9 | 165 | — | — | 187 | ||||||||||||||||||||||||||||||
| Improved recovery |
— | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||
| Purchases |
— | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||
| Extensions and discoveries |
— | — | — | 133 | — | — | 45 | — | — | 178 | ||||||||||||||||||||||||||||||
| Production |
— | — | — | (18 | ) | — | (129 | ) | (12 | ) | — | — | (159 | ) | ||||||||||||||||||||||||||
| Sales |
— | — | — | — | — | (1,857 | )* | — | — | — | (1,857 | ) | ||||||||||||||||||||||||||||
| End of 2010 |
— | — | — | 844 | — | 78 | 733 | — | — | 1,655 | ||||||||||||||||||||||||||||||
| Revisions |
— | — | — | (101 | ) | — | (39 | ) | (12 | ) | — | — | (152 | ) | ||||||||||||||||||||||||||
| Improved recovery |
— | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||
| Purchases |
— | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||
| Extensions and discoveries |
— | — | — | 187 | — | — | 43 | — | — | 230 | ||||||||||||||||||||||||||||||
| Production |
— | — | — | (21 | ) | — | (11 | ) | (39 | ) | — | — | (71 | ) | ||||||||||||||||||||||||||
| Sales |
— | — | — | — | — | — | (25 | ) | — | — | (25 | ) | ||||||||||||||||||||||||||||
| End of 2011 |
— | — | — | 909 | — | 28 | 700 | — | — | 1,637 | ||||||||||||||||||||||||||||||
| Total company |
||||||||||||||||||||||||||||||||||||||||
| 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 | ||||||||||||||||||||||||||||||
| End of 2010 |
1,762 | 1,918 | 3,680 | 1,764 | 779 | 78 | 1,468 | 424 | 117 | 8,310 | ||||||||||||||||||||||||||||||
| End of 2011 |
1,804 | 1,896 | 3,700 | 1,873 | 870 | 28 | 1,393 | 406 | 117 | 8,387 | ||||||||||||||||||||||||||||||
| * | Includes 594 million barrels of oil equivalent due to the cessation of equity accounting. |
A-110
Table of Contents
| Years Ended | Total Proved Reserves | |||||||||||||||||||||||||||||||||||||||
| December 31 | Millions of Barrels of Oil Equivalent | |||||||||||||||||||||||||||||||||||||||
| Alaska | Lower 48 |
Total U.S. |
Canada | Europe | Russia | Asia Pacific / Middle East |
Africa | Other Areas |
Total | |||||||||||||||||||||||||||||||
| Developed |
||||||||||||||||||||||||||||||||||||||||
| Consolidated operations |
||||||||||||||||||||||||||||||||||||||||
| 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 | ||||||||||||||||||||||||||||||
| End of 2010 |
1,619 | 1,601 | 3,220 | 465 | 545 | — | 574 | 396 | — | 5,200 | ||||||||||||||||||||||||||||||
| End of 2011 |
1,666 | 1,597 | 3,263 | 425 | 556 | — | 510 | 371 | — | 5,125 | ||||||||||||||||||||||||||||||
| Equity affiliates |
||||||||||||||||||||||||||||||||||||||||
| End of 2008 |
— | — | — | 105 | — | 1,471 | 60 | — | — | 1,636 | ||||||||||||||||||||||||||||||
| End of 2009 |
— | — | — | 116 | — | 1,464 | 51 | — | — | 1,631 | ||||||||||||||||||||||||||||||
| End of 2010 |
— | — | — | 142 | — | 76 | 675 | — | — | 893 | ||||||||||||||||||||||||||||||
| End of 2011 |
— | — | — | 131 | — | 28 | 638 | — | — | 797 | ||||||||||||||||||||||||||||||
| Undeveloped |
||||||||||||||||||||||||||||||||||||||||
| Consolidated operations |
||||||||||||||||||||||||||||||||||||||||
| 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 | ||||||||||||||||||||||||||||||
| End of 2010 |
143 | 317 | 460 | 455 | 234 | — | 161 | 28 | 117 | 1,455 | ||||||||||||||||||||||||||||||
| End of 2011 |
138 | 299 | 437 | 539 | 314 | — | 183 | 35 | 117 | 1,625 | ||||||||||||||||||||||||||||||
| Equity affiliates |
||||||||||||||||||||||||||||||||||||||||
| End of 2008 |
— | — | — | 595 | — | 475 | 469 | — | — | 1,539 | ||||||||||||||||||||||||||||||
| End of 2009 |
— | — | — | 600 | — | 591 | 484 | — | — | 1,675 | ||||||||||||||||||||||||||||||
| End of 2010 |
— | — | — | 702 | — | 2 | 58 | — | — | 762 | ||||||||||||||||||||||||||||||
| End of 2011 |
— | — | — | 778 | — | — | 62 | — | — | 840 | ||||||||||||||||||||||||||||||
Natural gas reserves are converted to barrels of oil equivalent (BOE) based on a 6:1 ratio: six thousand cubic feet of natural gas converts to one BOE.
Proved Undeveloped Reserves
We had 2,465 million BOE of proved undeveloped reserves at year-end 2011, compared with 2,217 million BOE at year-end 2010. We converted 210 million BOE of undeveloped reserves to developed during 2011 as we achieved startup of major development projects. In addition, we added 458 million BOE of undeveloped reserves in 2011 mainly through exploratory success and revisions. As a result, at December 31, 2011, our proved undeveloped reserves represented 29 percent of total proved reserves, compared with 27 percent at December 31, 2010. Costs incurred for the year ended December 31, 2011, relating to the development of proved undeveloped reserves were $4.5 billion.
Approximately 70 percent of our proved undeveloped reserves at year-end 2011 were associated with eight major development areas. Seven of the major development areas are currently producing and are expected to have proved undeveloped reserves convert to developed over time as development activities continue and/or production facilities are expanded or upgraded, and include:
| • | FCCL oil sands—Foster Creek and Christina Lake in Canada. |
| • | The Surmont oil sands project in Canada. |
| • | The Ekofisk Field in the North Sea. |
| • | Certain fields in the Lower 48 and Alaska. |
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The remaining major project, the Kashagan Field in Kazakhstan, will have proved undeveloped reserves convert to developed as this project begins production.
At the end of 2011, 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 2011 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
The company’s results of operations from oil and gas activities for the years 2011, 2010 and 2009 are shown in the following tables. Additional information about selected line items within the results of operations tables is shown below:
| • | Other revenues include gains and losses from asset sales, certain amounts resulting from the purchase and sale of hydrocarbons, and other miscellaneous income. |
| • | Taxes other than income taxes include production, property and other non-income taxes. |
| • | Depreciation of support equipment is reclassified as applicable. |
| • | 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. |
| • | Other earnings include non-oil and gas activities within the E&P segment, such as pipeline and marine operations, liquefied natural gas operations, and crude oil and gas marketing activities. |
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Results of Operations
| Year Ended | Millions of Dollars | |||||||||||||||||||||||||||||||||||||||
| December 31, 2011 | Alaska | Lower 48 |
Total U.S. |
Canada | Europe | Russia | Asia Pacific / Middle East |
Africa | Other Areas |
Total | ||||||||||||||||||||||||||||||
| Consolidated operations |
||||||||||||||||||||||||||||||||||||||||
| Sales |
$ | 4,319 | 3,513 | 7,832 | 2,123 | 5,233 | — | 5,901 | 1,486 | — | 22,575 | |||||||||||||||||||||||||||||
| Transfers |
3,869 | 3,283 | 7,152 | 176 | 3,854 | — | 932 | 54 | — | 12,168 | ||||||||||||||||||||||||||||||
| Other revenues |
(46 | ) | 303 | 257 | 138 | (16 | ) | — | (264 | ) | 30 | 16 | 161 | |||||||||||||||||||||||||||
| Total revenues |
8,142 | 7,099 | 15,241 | 2,437 | 9,071 | — | 6,569 | 1,570 | 16 | 34,904 | ||||||||||||||||||||||||||||||
| Production costs excluding taxes |
1,023 | 1,286 | 2,309 | 781 | 956 | — | 742 | 266 | — | 5,054 | ||||||||||||||||||||||||||||||
| Taxes other than income taxes |
2,721 | 520 | 3,241 | 65 | 4 | 1 | 543 | 23 | — | 3,877 | ||||||||||||||||||||||||||||||
| Exploration expenses |
36 | 368 | 404 | 177 | 201 | — | 192 | 51 | 54 | 1,079 | ||||||||||||||||||||||||||||||
| Depreciation, depletion and amortization |
468 | 2,113 | 2,581 | 1,504 | 1,407 | 1 | 940 | 188 | — | 6,621 | ||||||||||||||||||||||||||||||
| Impairments |
2 | 71 | 73 | 253 | (38 | ) | — | — | — | — | 288 | |||||||||||||||||||||||||||||
| Transportation costs |
609 | 432 | 1,041 | 128 | 273 | — | 120 | 27 | — | 1,589 | ||||||||||||||||||||||||||||||
| Other related expenses |
49 | 60 | 109 | 55 | 63 | 20 | 87 | (7 | ) | 56 | 383 | |||||||||||||||||||||||||||||
| Accretion |
59 | 58 | 117 | 50 | 203 | — | 23 | 2 | 1 | 396 | ||||||||||||||||||||||||||||||
| 3,175 | 2,191 | 5,366 | (576 | ) | 6,002 | (22 | ) | 3,922 | 1,020 | (95 | ) | 15,617 | ||||||||||||||||||||||||||||
| Provision for income taxes |
1,167 | 755 | 1,922 | (194 | ) | 4,355 | 3 | 1,844 | 722 | (23 | ) | 8,629 | ||||||||||||||||||||||||||||
| Results of operations for producing activities |
2,008 | 1,436 | 3,444 | (382 | ) | 1,647 | (25 | ) | 2,078 | 298 | (72 | ) | 6,988 | |||||||||||||||||||||||||||
| Other earnings |
(25 | ) | (165 | ) | (190 | ) | (32 | ) | 248 | 11 | 191 | 11 | 7 | 246 | ||||||||||||||||||||||||||
| Net income (loss) attributable to ConocoPhillips |
$ | 1,983 | 1,271 | 3,254 | (414 | ) | 1,895 | (14 | ) | 2,269 | 309 | (65 | ) | 7,234 | ||||||||||||||||||||||||||
| Equity affiliates |
||||||||||||||||||||||||||||||||||||||||
| Sales |
$ | — | — | — | 1,295 | — | 1,107 | 956 | — | — | 3,358 | |||||||||||||||||||||||||||||
| Transfers |
— | — | — | — | — | — | 365 | — | — | 365 | ||||||||||||||||||||||||||||||
| Other revenues |
— | — | — | 6 | — | — | 6 | — | — | 12 | ||||||||||||||||||||||||||||||
| Total revenues |
— | — | — | 1,301 | — | 1,107 | 1,327 | — | — | 3,735 | ||||||||||||||||||||||||||||||
| Production costs excluding taxes |
— | — | — | 367 | — | 72 | 108 | — | — | 547 | ||||||||||||||||||||||||||||||
| Taxes other than income taxes |
— | — | — | 5 | — | 750 | 187 | — | — | 942 | ||||||||||||||||||||||||||||||
| Exploration expenses |
— | — | — | 36 | — | 1 | 2 | — | — | 39 | ||||||||||||||||||||||||||||||
| Depreciation, depletion and amortization |
— | — | — | 209 | — | 52 | 128 | — | — | 389 | ||||||||||||||||||||||||||||||
| Impairments |
— | — | — | — | — | 395 | — | — | — | 395 | ||||||||||||||||||||||||||||||
| Transportation costs |
— | — | — | — | — | 139 | 133 | — | — | 272 | ||||||||||||||||||||||||||||||
| Other related expenses |
— | — | — | 3 | — | — | 41 | — | — | 44 | ||||||||||||||||||||||||||||||
| Accretion |
— | — | — | 4 | — | 1 | 3 | — | — | 8 | ||||||||||||||||||||||||||||||
| — | — | — | 677 | — | (303 | ) | 725 | — | — | 1,099 | ||||||||||||||||||||||||||||||
| Provision for income taxes |
— | — | — | 159 | — | 18 | 32 | — | — | 209 | ||||||||||||||||||||||||||||||
| Results of operations for producing activities |
— | — | — | 518 | — | (321 | ) | 693 | — | — | 890 | |||||||||||||||||||||||||||||
| Other earnings |
— | — | — | — | — | 238 | 119 | — | — | 357 | ||||||||||||||||||||||||||||||
| Net income (loss) attributable to ConocoPhillips |
$ | — | — | — | 518 | — | (83 | ) | 812 | — | — | 1,247 | ||||||||||||||||||||||||||||
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| Year Ended | Millions of Dollars | |||||||||||||||||||||||||||||||||||||||
| December 31, 2010 | Alaska | Lower 48 |
Total U.S. |
Canada | Europe | Russia | Asia Pacific / Middle East |
Africa | Other Areas |
Total | ||||||||||||||||||||||||||||||
| Consolidated operations |
||||||||||||||||||||||||||||||||||||||||
| Sales |
$ | 3,645 | 3,600 | 7,245 | 2,379 | 5,967 | — | 4,958 | 1,743 | — | 22,292 | |||||||||||||||||||||||||||||
| Transfers |
2,693 | 2,389 | 5,082 | 246 | 2,278 | — | 770 | 450 | — | 8,826 | ||||||||||||||||||||||||||||||
| Other revenues |
— | 559 | 559 | 3,216 | 142 | — | 55 | 172 | 18 | 4,162 | ||||||||||||||||||||||||||||||
| Total revenues |
6,338 | 6,548 | 12,886 | 5,841 | 8,387 | — | 5,783 | 2,365 | 18 | 35,280 | ||||||||||||||||||||||||||||||
| Production costs excluding taxes |
849 | 1,230 | 2,079 | 873 | 1,004 | — | 538 | 296 | — | 4,790 | ||||||||||||||||||||||||||||||
| Taxes other than income taxes |
1,570 | 498 | 2,068 | 74 | 6 | 1 | 355 | 18 | 1 | 2,523 | ||||||||||||||||||||||||||||||
| Exploration expenses |
37 | 292 | 329 | 295 | 146 | 2 | 260 | 29 | 101 | 1,162 | ||||||||||||||||||||||||||||||
| Depreciation, depletion and amortization |
529 | 2,231 | 2,760 | 1,666 | 1,972 | 2 | 1,206 | 202 | — | 7,808 | ||||||||||||||||||||||||||||||
| Impairments |
4 | 19 | 23 | 13 | 43 | — | — | — | — | 79 | ||||||||||||||||||||||||||||||
| Transportation costs |
528 | 424 | 952 | 134 | 281 | — | 119 | 23 | — | 1,509 | ||||||||||||||||||||||||||||||
| Other related expenses |
(38 | ) | 112 | 74 | 41 | 42 | 17 | (48 | ) | (10 | ) | 62 | 178 | |||||||||||||||||||||||||||
| Accretion |
58 | 55 | 113 | 50 | 192 | — | 24 | — | 4 | 383 | ||||||||||||||||||||||||||||||
| 2,801 | 1,687 | 4,488 | 2,695 | 4,701 | (22 | ) | 3,329 | 1,807 | (150 | ) | 16,848 | |||||||||||||||||||||||||||||
| Provision for income taxes |
1,014 | 555 | 1,569 | 108 | 3,066 | (23 | ) | 1,361 | 1,458 | (28 | ) | 7,511 | ||||||||||||||||||||||||||||
| Results of operations for producing activities |
1,787 | 1,132 | 2,919 | 2,587 | 1,635 | 1 | 1,968 | 349 | (122 | ) | 9,337 | |||||||||||||||||||||||||||||
| Other earnings |
(52 | ) | (99 | ) | (151 | ) | (72 | ) | 76 | 16 | 139 | 29 | 8 | 45 | ||||||||||||||||||||||||||
| Net income (loss) attributable to ConocoPhillips |
$ | 1,735 | 1,033 | 2,768 | 2,515 | 1,711 | 17 | 2,107 | 378 | (114 | ) | 9,382 | ||||||||||||||||||||||||||||
| Equity affiliates |
||||||||||||||||||||||||||||||||||||||||
| Sales |
$ | — | — | — | 955 | — | 5,189 | 249 | — | — | 6,393 | |||||||||||||||||||||||||||||
| Transfers |
— | — | — | — | — | 1,876 | — | — | — | 1,876 | ||||||||||||||||||||||||||||||
| Other revenues |
— | — | — | 7 | — | 1,219 | 10 | — | — | 1,236 | ||||||||||||||||||||||||||||||
| Total revenues |
— | — | — | 962 | — | 8,284 | 259 | — | — | 9,505 | ||||||||||||||||||||||||||||||
| Production costs excluding taxes |
— | — | — | 265 | — | 544 | 59 | — | — | 868 | ||||||||||||||||||||||||||||||
| Taxes other than income taxes |
— | — | — | 4 | — | 3,463 | 42 | — | — | 3,509 | ||||||||||||||||||||||||||||||
| Exploration expenses |
— | — | — | — | — | 61 | (2 | ) | — | — | 59 | |||||||||||||||||||||||||||||
| Depreciation, depletion and amortization |
— | — | — | 190 | — | 568 | 55 | — | — | 813 | ||||||||||||||||||||||||||||||
| Impairments |
— | — | — | — | — | 645 | — | — | — | 645 | ||||||||||||||||||||||||||||||
| Transportation costs |
— | — | — | — | — | 784 | 25 | — | — | 809 | ||||||||||||||||||||||||||||||
| Other related expenses |
— | — | — | (3 | ) | — | — | 44 | — | — | 41 | |||||||||||||||||||||||||||||
| Accretion |
— | — | — | 2 | — | 7 | 2 | — | — | 11 | ||||||||||||||||||||||||||||||
| — | — | — | 504 | — | 2,212 | 34 | — | — | 2,750 | |||||||||||||||||||||||||||||||
| Provision for income taxes |
— | — | — | 128 | — | 647 | (25 | ) | — | — | 750 | |||||||||||||||||||||||||||||
| Results of operations for producing activities |
— | — | — | 376 | — | 1,565 | 59 | — | — | 2,000 | ||||||||||||||||||||||||||||||
| Other earnings |
— | — | — | — | — | 405 | (86 | ) | — | — | 319 | |||||||||||||||||||||||||||||
| Net income (loss) attributable to ConocoPhillips |
$ | — | — | — | 376 | — | 1,970 | (27 | ) | — | — | 2,319 | ||||||||||||||||||||||||||||
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| 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 |
$ | 3,353 | 3,144 | 6,497 | 2,179 | 4,995 | — | 3,830 | 1,562 | 11 | 19,074 | |||||||||||||||||||||||||||||
| Transfers |
2,261 | 1,937 | 4,198 | 345 | 2,305 | — | 500 | 257 | — | 7,605 | ||||||||||||||||||||||||||||||
| Other revenues |
30 | 54 | 84 | 168 | (66 | ) | — | 10 | 136 | 54 | 386 | |||||||||||||||||||||||||||||
| Total revenues |
5,644 | 5,135 | 10,779 | 2,692 | 7,234 | — | 4,340 | 1,955 | 65 | 27,065 | ||||||||||||||||||||||||||||||
| 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 |
251 | 60 | 311 | (3 | ) | 62 | 3 | 121 | 23 | 14 | 531 | |||||||||||||||||||||||||||||
| 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 | — | 3,783 | 74 | — | — | 4,570 | |||||||||||||||||||||||||||||
| Transfers |
— | — | — | — | — | 1,946 | — | — | — | 1,946 | ||||||||||||||||||||||||||||||
| Other revenues |
— | — | — | (2 | ) | — | — | 1 | — | — | (1 | ) | ||||||||||||||||||||||||||||
| Total revenues |
— | — | — | 711 | — | 5,729 | 75 | — | — | 6,515 | ||||||||||||||||||||||||||||||
| Production costs excluding taxes |
— | — | — | 213 | — | 501 | 26 | — | — | 740 | ||||||||||||||||||||||||||||||
| Taxes other than income taxes |
— | — | — | 3 | — | 2,270 | 4 | — | — | 2,277 | ||||||||||||||||||||||||||||||
| Exploration expenses |
— | — | — | — | — | 37 | 2 | — | — | 39 | ||||||||||||||||||||||||||||||
| Depreciation, depletion and amortization |
— | — | — | 133 | — | 455 | 21 | — | — | 609 | ||||||||||||||||||||||||||||||
| Impairments |
— | — | — | — | — | 83 | — | — | — | 83 | ||||||||||||||||||||||||||||||
| Transportation costs |
— | — | — | — | — | 703 | 3 | — | — | 706 | ||||||||||||||||||||||||||||||
| Other related expenses |
— | — | — | 17 | — | 3 | 1 | — | — | 21 | ||||||||||||||||||||||||||||||
| Accretion |
— | — | — | 1 | — | 6 | 1 | — | — | 8 | ||||||||||||||||||||||||||||||
| — | — | — | 344 | — | 1,671 | 17 | — | — | 2,032 | |||||||||||||||||||||||||||||||
| Provision for income taxes |
— | — | — | 89 | — | 326 | 9 | — | — | 424 | ||||||||||||||||||||||||||||||
| Results of operations for producing activities |
— | — | — | 255 | — | 1,345 | 8 | — | — | 1,608 | ||||||||||||||||||||||||||||||
| Other earnings |
— | — | — | — | — | (201 | ) | (86 | ) | — | — | (287 | ) | |||||||||||||||||||||||||||
| Net income (loss) attributable to ConocoPhillips |
$ | — | — | — | 255 | — | 1,144 | (78 | ) | — | — | 1,321 | ||||||||||||||||||||||||||||
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Statistics
| Net Production | 2011 | 2010 | 2009 | |||||||||
| Thousands of Barrels Daily | ||||||||||||
| Crude Oil and Natural Gas Liquids |
||||||||||||
| Consolidated operations |
||||||||||||
| Alaska |
215 | 230 | 252 | |||||||||
| Lower 48 |
168 | 160 | 166 | |||||||||
| United States |
383 | 390 | 418 | |||||||||
| Canada |
38 | 38 | 40 | |||||||||
| Europe |
175 | 211 | 241 | |||||||||
| Asia Pacific/Middle East |
111 | 140 | 132 | |||||||||
| Africa |
40 | 79 | 78 | |||||||||
| Other areas |
— | — | 4 | |||||||||
| Total consolidated operations |
747 | 858 | 913 | |||||||||
| Equity affiliates |
||||||||||||
| Russia |
29 | 336 | 443 | |||||||||
| Asia Pacific/Middle East |
23 | 3 | — | |||||||||
| Total equity affiliates |
52 | 339 | 443 | |||||||||
| Total company |
799 | 1,197 | 1,356 | |||||||||
| Synthetic Oil |
||||||||||||
| Consolidated operations—Canada |
— | 12 | 23 | |||||||||
| Bitumen |
||||||||||||
| Consolidated operations—Canada |
10 | 10 | 7 | |||||||||
| Equity affiliates—Canada |
57 | 49 | 43 | |||||||||
| Total company |
67 | 59 | 50 | |||||||||
| Millions of Cubic Feet Daily | ||||||||||||
| Natural Gas* |
||||||||||||
| Consolidated operations |
||||||||||||
| Alaska |
61 | 82 | 94 | |||||||||
| Lower 48 |
1,556 | 1,695 | 1,927 | |||||||||
| United States |
1,617 | 1,777 | 2,021 | |||||||||
| Canada |
928 | 984 | 1,062 | |||||||||
| Europe |
626 | 815 | 876 | |||||||||
| Asia Pacific/Middle East |
695 | 712 | 713 | |||||||||
| Africa |
158 | 149 | 121 | |||||||||
| Total consolidated operations |
4,024 | 4,437 | 4,793 | |||||||||
| Equity affiliates |
||||||||||||
| Russia |
— | 254 | 295 | |||||||||
| Asia Pacific/Middle East |
492 | 169 | 84 | |||||||||
| Total equity affiliates |
492 | 423 | 379 | |||||||||
| Total company |
4,516 | 4,860 | 5,172 | |||||||||
| * | Represents quantities available for sale. Excludes gas equivalent of natural gas liquids included above. |
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| Average Sales Prices | 2011 | 2010 | 2009 | |||||||||
| Crude Oil and Natural Gas Liquids Per Barrel |
||||||||||||
| Consolidated operations |
||||||||||||
| Alaska |
$ | 105.95 | 78.61 | 59.23 | ||||||||
| Lower 48 |
74.09 | 57.69 | 44.12 | |||||||||
| United States |
91.77 | 69.73 | 53.21 | |||||||||
| Canada |
66.07 | 55.70 | 41.76 | |||||||||
| Europe |
108.58 | 77.35 | 58.92 | |||||||||
| Asia Pacific/Middle East |
105.94 | 75.50 | 57.59 | |||||||||
| Africa |
102.75 | 76.80 | 60.83 | |||||||||
| Other areas |
— | — | 32.01 | |||||||||
| Total international |
102.68 | 74.95 | 57.40 | |||||||||
| Total consolidated operations |
97.12 | 72.63 | 55.47 | |||||||||
| Equity affiliates |
||||||||||||
| Russia |
101.62 | 56.65 | 43.19 | |||||||||
| Asia Pacific/Middle East |
94.67 | 83.82 | — | |||||||||
| Total equity affiliates |
98.60 | 56.87 | 43.19 | |||||||||
| Synthetic Oil Per Barrel |
||||||||||||
| Consolidated operations—Canada |
$ | — | 77.56 | 62.01 | ||||||||
| Bitumen Per Barrel |
||||||||||||
| Consolidated operations—Canada |
$ | 55.16 | 51.10 | 39.67 | ||||||||
| Equity affiliates—Canada |
63.93 | 53.43 | 45.69 | |||||||||
| Natural Gas Per Thousand Cubic Feet |
||||||||||||
| Consolidated operations |
||||||||||||
| Alaska |
$ | 4.56 | 4.62 | 5.33 | ||||||||
| Lower 48 |
3.99 | 4.25 | 3.42 | |||||||||
| United States |
4.01 | 4.27 | 3.50 | |||||||||
| Canada |
3.46 | 3.74 | 3.33 | |||||||||
| Europe |
9.26 | 6.94 | 6.81 | |||||||||
| Asia Pacific/Middle East |
9.82 | 7.39 | 6.00 | |||||||||
| Africa |
2.24 | 1.81 | 1.56 | |||||||||
| Total international |
6.73 | 5.60 | 5.06 | |||||||||
| Total consolidated operations |
5.64 | 5.07 | 4.40 | |||||||||
| Equity affiliates |
||||||||||||
| Russia |
— | 1.18 | 1.16 | |||||||||
| Asia Pacific/Middle East |
2.89 | 2.79 | 2.35 | |||||||||
| Total equity affiliates |
2.89 | 1.82 | 1.43 | |||||||||
A-118
Table of Contents
| 2011 | 2010 | 2009 | ||||||||||
| Average Production Costs Per Barrel of Oil Equivalent* |
||||||||||||
| Consolidated operations |
||||||||||||
| Alaska |
$ | 12.45 | 9.55 | 8.84 | ||||||||
| Lower 48 |
8.24 | 7.62 | 7.12 | |||||||||
| United States |
9.70 | 8.30 | 7.73 | |||||||||
| Canada |
10.56 | 10.68 | 11.21 | |||||||||
| Europe |
9.38 | 7.93 | 7.42 | |||||||||
| Asia Pacific/Middle East |
8.96 | 5.70 | 4.86 | |||||||||
| Africa |
10.99 | 7.81 | 7.54 | |||||||||
| Other areas |
— | — | 5.48 | |||||||||
| Total international |
9.70 | 7.96 | 7.72 | |||||||||
| Total consolidated operations |
9.70 | 8.10 | 7.73 | |||||||||
| Equity affiliates |
||||||||||||
| Canada |
17.64 | 14.82 | 13.57 | |||||||||
| Russia |
6.80 | 3.94 | 3.74 | |||||||||
| Asia Pacific/Middle East |
2.82 | 5.19 | 5.09 | |||||||||
| Total equity affiliates |
7.85 | 5.19 | 4.54 | |||||||||
| Average Production Costs Per Barrel—Bitumen |
||||||||||||
| Consolidated operations—Canada |
$ | 27.12 | 19.45 | 30.92 | ||||||||
| Equity affiliates—Canada |
17.64 | 14.82 | 13.57 | |||||||||
| Taxes Other Than Income Taxes Per Barrel of Oil Equivalent* |
||||||||||||
| Consolidated operations |
||||||||||||
| Alaska |
$ | 33.11 | 17.65 | 11.62 | ||||||||
| Lower 48 |
3.33 | 3.08 | 2.37 | |||||||||
| United States |
13.61 | 8.26 | 5.65 | |||||||||
| Canada |
.88 | .91 | .83 | |||||||||
| Europe |
.04 | .05 | .02 | |||||||||
| Asia Pacific/Middle East |
6.56 | 3.76 | 1.80 | |||||||||
| Africa |
.95 | .47 | .47 | |||||||||
| Other areas |
— | — | 4.79 | |||||||||
| Total international |
2.25 | 1.34 | .74 | |||||||||
| Total consolidated operations |
7.44 | 4.27 | 2.87 | |||||||||
| Equity affiliates |
||||||||||||
| Canada |
.24 | .22 | .19 | |||||||||
| Russia |
70.85 | 25.08 | 17.46 | |||||||||
| Asia Pacific/Middle East |
4.88 | 3.69 | .78 | |||||||||
| Total equity affiliates |
13.51 | 20.97 | 15.69 | |||||||||
| Depreciation, Depletion and Amortization Per Barrel of Oil Equivalent* |
||||||||||||
| Consolidated operations |
||||||||||||
| Alaska |
$ | 5.69 | 5.95 | 6.25 | ||||||||
| Lower 48 |
13.55 | 13.81 | 14.71 | |||||||||
| United States |
10.84 | 11.02 | 11.71 | |||||||||
| Canada |
20.33 | 20.38 | 18.73 | |||||||||
| Europe |
13.80 | 15.58 | 14.27 | |||||||||
| Asia Pacific/Middle East |
11.35 | 12.77 | 9.94 | |||||||||
| Africa |
7.76 | 5.33 | 5.61 | |||||||||
| Other areas |
— | — | 7.53 | |||||||||
| Total international |
14.28 | 14.82 | 13.40 | |||||||||
| Total consolidated operations |
12.71 | 13.21 | 12.67 | |||||||||
| Equity affiliates |
||||||||||||
| Canada |
10.05 | 10.62 | 8.47 | |||||||||
| Russia |
4.91 | 4.11 | 3.24 | |||||||||
| Asia Pacific/Middle East |
3.34 | 4.83 | 4.11 | |||||||||
| Total equity affiliates |
5.58 | 4.86 | 3.67 | |||||||||
| * | Includes bitumen. |
A-119
Table of Contents
| Net Wells Completed(1) | Productive | Dry | ||||||||||||||||||||||||
| 2011 | 2010 | 2009 | 2011 | 2010 | 2009 | |||||||||||||||||||||
| Exploratory(2) |
||||||||||||||||||||||||||
| Consolidated operations |
||||||||||||||||||||||||||
| Alaska |
— | — | — | — | — | 2 | ||||||||||||||||||||
| Lower 48 |
98 | 23 | 33 | 5 | 1 | 14 | ||||||||||||||||||||
| United States |
98 | 23 | 33 | 5 | 1 | 16 | ||||||||||||||||||||
| Canada |
8 | 15 | 17 | 3 | 7 | 19 | ||||||||||||||||||||
| Europe |
1 | 1 | 1 | * | * | 2 | ||||||||||||||||||||
| Asia Pacific/Middle East |
1 | 3 | 3 | 1 | 1 | 3 | ||||||||||||||||||||
| Africa |
* | 1 | * | * | * | * | ||||||||||||||||||||
| Total consolidated operations |
108 | 43 | 54 | 9 | 9 | 40 | ||||||||||||||||||||
| Equity affiliates |
||||||||||||||||||||||||||
| Russia |
— | — | 1 | — | — | — | ||||||||||||||||||||
| Asia Pacific/Middle East |
5 | 2 | — | — | — | — | ||||||||||||||||||||
| Total equity affiliates(3) |
5 | 2 | 1 | — | — | — | ||||||||||||||||||||
| Includes extension wells of: | 98 | 23 | 40 | 3 | 1 | 29 | ||||||||||||||||||||
| Productive | Dry | |||||||||||||||||||||||||
| 2011 | 2010 | 2009 | 2011 | 2010 | 2009 | |||||||||||||||||||||
| Development |
||||||||||||||||||||||||||
| Consolidated operations |
||||||||||||||||||||||||||
| Alaska |
41 | 47 | 47 | — | * | — | ||||||||||||||||||||
| Lower 48 |
350 | 269 | 592 | 4 | 2 | 4 | ||||||||||||||||||||
| United States |
391 | 316 | 639 | 4 | 2 | 4 | ||||||||||||||||||||
| Canada |
146 | 186 | 227 | 1 | 12 | 20 | ||||||||||||||||||||
| Europe |
4 | 6 | 9 | — | — | — | ||||||||||||||||||||
| Asia Pacific/Middle East |
30 | 59 | 47 | — | * | — | ||||||||||||||||||||
| Africa |
5 | 9 | 3 | — | — | — | ||||||||||||||||||||
| Total consolidated operations |
576 | 576 | 925 | 5 | 14 | 24 | ||||||||||||||||||||
| Equity affiliates |
||||||||||||||||||||||||||
| Canada |
157 | 112 | 61 | — | — | — | ||||||||||||||||||||
| Russia |
3 | 2 | 6 | — | — | * | ||||||||||||||||||||
| Asia Pacific/Middle East |
9 | 25 | 28 | 1 | — | — | ||||||||||||||||||||
| Total equity affiliates(3) |
169 | 139 | 95 | 1 | — | * | ||||||||||||||||||||
| (1) | Excludes farmout arrangements. |
| (2) | Includes extension wells, as well as other types of exploratory wells. Extension exploratory wells are either wells drilled in areas near or offsetting current production, or wells drilled in areas that have not yet achieved a well density and production history to achieve statistical certainty of results. These are classified as exploratory wells because proved reserves cannot be attributed to these locations. |
| (3) | Excludes LUKOIL. |
| * | Our total proportionate interest was less than one. |
A-120
Table of Contents
| Wells at December 31, 2011 | Productive(2) | |||||||||||||||||||||||||||
| In Progress(1) | Oil | Gas | ||||||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||||||
| Consolidated operations |
||||||||||||||||||||||||||||
| Alaska |
24 | 12 | 1,902 | 860 | 35 | 22 | ||||||||||||||||||||||
| Lower 48 |
296 | 218 | 9,133 | 4,393 | 24,793 | 15,624 | ||||||||||||||||||||||
| United States |
320 | 230 | 11,035 | 5,253 | 24,828 | 15,646 | ||||||||||||||||||||||
| Canada |
306 | (3) | 211 | (3) | 1,630 | 971 | 12,895 | 7,593 | ||||||||||||||||||||
| Europe |
25 | 5 | 609 | 109 | 271 | 109 | ||||||||||||||||||||||
| Asia Pacific/Middle East |
62 | 25 | 467 | 200 | 114 | 52 | ||||||||||||||||||||||
| Africa |
103 | 17 | 1,151 | 201 | 12 | 2 | ||||||||||||||||||||||
| Other areas |
46 | 4 | — | — | — | — | ||||||||||||||||||||||
| Total consolidated operations |
862 | 492 | 14,892 | 6,734 | 38,120 | 23,402 | ||||||||||||||||||||||
| Equity affiliates |
||||||||||||||||||||||||||||
| Canada |
15 | 8 | 242 | 121 | — | — | ||||||||||||||||||||||
| Russia |
8 | 2 | 107 | 38 | 2 | 1 | ||||||||||||||||||||||
| Asia Pacific/Middle East |
1,015 | 220 | — | — | 521 | 140 | ||||||||||||||||||||||
| Total equity affiliates |
1,038 | 230 | 349 | 159 | 523 | 141 | ||||||||||||||||||||||
| (1) | Includes wells that have been temporarily suspended. |
| (2) | Includes 5,883 gross and 3,734 net multiple completion wells. |
| (3) | Includes 246 gross and 165 net stratigraphic test wells for oil sands projects. |
| Acreage at December 31, 2011 | Thousands of Acres | |||||||||||||||||
| Developed | Undeveloped | |||||||||||||||||
| Gross | Net | Gross | Net | |||||||||||||||
| Consolidated operations |
||||||||||||||||||
| Alaska |
650 | 329 | 1,440 | 1,197 | ||||||||||||||
| Lower 48 |
7,012 | 5,244 | 10,286 | 8,790 | ||||||||||||||
| United States |
7,662 | 5,573 | 11,726 | 9,987 | ||||||||||||||
| Canada |
6,543 | 4,240 | 6,412 | 4,379 | ||||||||||||||
| Europe |
862 | 242 | 3,008 | 1,177 | ||||||||||||||
| Asia Pacific/Middle East |
4,123 | 1,777 | 19,585 | 11,989 | ||||||||||||||
| Africa |
528 | 132 | 14,730 | 2,575 | ||||||||||||||
| Other areas |
— | — | 11,066 | 4,251 | ||||||||||||||
| Total consolidated operations |
19,718 | 11,964 | 66,527 | 34,358 | ||||||||||||||
| Equity affiliates |
||||||||||||||||||
| Canada |
33 | 14 | 588 | 243 | ||||||||||||||
| Russia |
291 | 90 | 1,173 | 476 | ||||||||||||||
| Asia Pacific/Middle East |
1,129 | 250 | 8,140 | 2,750 | ||||||||||||||
| Total equity affiliates |
1,453 | 354 | 9,901 | 3,469 | ||||||||||||||
A-121
Table of Contents
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 | ||||||||||||||||||||||||||||||
| 2011 |
||||||||||||||||||||||||||||||||||||||||
| Consolidated operations |
||||||||||||||||||||||||||||||||||||||||
| Unproved property acquisition |
$ | 1 | 577 | 578 | 145 | — | — | — | — | — | 723 | |||||||||||||||||||||||||||||
| Proved property acquisition |
— | 10 | 10 | — | — | — | 36 | — | — | 46 | ||||||||||||||||||||||||||||||
| 1 | 587 | 588 | 145 | — | — | 36 | — | — | 769 | |||||||||||||||||||||||||||||||
| Exploration |
84 | 1,031 | 1,115 | 269 | 201 | 1 | 226 | 63 | 88 | 1,963 | ||||||||||||||||||||||||||||||
| Development |
499 | 2,633 | 3,132 | 1,347 | 2,123 | — | 949 | 263 | 726 | 8,540 | ||||||||||||||||||||||||||||||
| $ | 584 | 4,251 | 4,835 | 1,761 | 2,324 | 1 | 1,211 | 326 | 814 | 11,272 | ||||||||||||||||||||||||||||||
| Equity affiliates |
||||||||||||||||||||||||||||||||||||||||
| Unproved property acquisition |
$ | — | — | — | — | — | — | 484 | — | — | 484 | |||||||||||||||||||||||||||||
| Proved property acquisition |
— | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||
| — | — | — | — | — | — | 484 | — | — | 484 | |||||||||||||||||||||||||||||||
| Exploration |
— | — | — | 64 | — | 1 | 100 | — | — | 165 | ||||||||||||||||||||||||||||||
| Development |
— | — | — | 911 | — | 43 | 632 | — | — | 1,586 | ||||||||||||||||||||||||||||||
| $ | — | — | — | 975 | — | 44 | 1,216 | — | — | 2,235 | ||||||||||||||||||||||||||||||
| 2010 |
||||||||||||||||||||||||||||||||||||||||
| Consolidated operations |
||||||||||||||||||||||||||||||||||||||||
| Unproved property acquisition |
$ | (26 | ) | 286 | 260 | 113 | 9 | — | — | — | — | 382 | ||||||||||||||||||||||||||||
| Proved property acquisition |
— | 100 | 100 | 1 | — | — | — | — | — | 101 | ||||||||||||||||||||||||||||||
| (26 | ) | 386 | 360 | 114 | 9 | — | — | — | — | 483 | ||||||||||||||||||||||||||||||
| Exploration |
119 | 487 | 606 | 269 | 144 | 3 | 356 | 45 | 143 | 1,566 | ||||||||||||||||||||||||||||||
| Development |
588 | 1,439 | 2,027 | 927 | 1,351 | — | 858 | 375 | 729 | 6,267 | ||||||||||||||||||||||||||||||
| $ | 681 | 2,312 | 2,993 | 1,310 | 1,504 | 3 | 1,214 | 420 | 872 | 8,316 | ||||||||||||||||||||||||||||||
| Equity affiliates |
||||||||||||||||||||||||||||||||||||||||
| Unproved property acquisition* |
$ | — | — | — | 81 | — | 15 | 379 | — | — | 475 | |||||||||||||||||||||||||||||
| Proved property acquisition* |
— | — | — | — | — | 173 | — | — | — | 173 | ||||||||||||||||||||||||||||||
| — | — | — | 81 | — | 188 | 379 | — | — | 648 | |||||||||||||||||||||||||||||||
| Exploration |
— | — | — | — | — | 92 | 123 | — | — | 215 | ||||||||||||||||||||||||||||||
| Development |
— | — | — | 621 | — | 751 | 403 | — | — | 1,775 | ||||||||||||||||||||||||||||||
| $ | — | — | — | 702 | — | 1,031 | 905 | — | — | 2,638 | ||||||||||||||||||||||||||||||
| * | Amounts in Asia Pacific/Middle East were reclassified between “Unproved property acquisition” and “Proved property acquisition.” Total acquisition costs were unchanged. |
A-122
Table of Contents
| 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* |
$ | — | — | — | — | — | 18 | 219 | — | — | 237 | |||||||||||||||||||||||||||||
| Proved property acquisition* |
— | — | — | — | — | 176 | — | — | — | 176 | ||||||||||||||||||||||||||||||
| — | — | — | — | — | 194 | 219 | — | — | 413 | |||||||||||||||||||||||||||||||
| Exploration |
— | — | — | — | — | 62 | 53 | — | — | 115 | ||||||||||||||||||||||||||||||
| Development |
— | — | — | 446 | — | 820 | 376 | — | — | 1,642 | ||||||||||||||||||||||||||||||
| $ | — | — | — | 446 | — | 1,076 | 648 | — | — | 2,170 | ||||||||||||||||||||||||||||||
| * | Amounts in Asia Pacific/Middle East were reclassified between “Unproved property acquisition” and “Proved property acquisition.” Total acquisition costs were unchanged. |
A-123
Table of Contents
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 | |||||||||||||||||||||||||||||||
| 2011 |
||||||||||||||||||||||||||||||||||||||||
| Consolidated operations |
||||||||||||||||||||||||||||||||||||||||
| Proved properties |
$ | 12,770 | 34,939 | 47,709 | 19,578 | 22,948 | 8 | 12,284 | 3,867 | 4,650 | 111,044 | |||||||||||||||||||||||||||||
| Unproved properties |
1,528 | 2,574 | 4,102 | 1,986 | 289 | 1 | 1,026 | 174 | 268 | 7,846 | ||||||||||||||||||||||||||||||
| 14,298 | 37,513 | 51,811 | 21,564 | 23,237 | 9 | 13,310 | 4,041 | 4,918 | 118,890 | |||||||||||||||||||||||||||||||
| Accumulated depreciation, depletion and amortization |
6,237 | 15,464 | 21,701 | 10,599 | 14,451 | 7 | 5,626 | 1,559 | 12 | 53,955 | ||||||||||||||||||||||||||||||
| $ | 8,061 | 22,049 | 30,110 | 10,965 | 8,786 | 2 | 7,684 | 2,482 | 4,906 | 64,935 | ||||||||||||||||||||||||||||||
| Equity affiliates |
||||||||||||||||||||||||||||||||||||||||
| Proved properties |
$ | — | — | — | 5,774 | — | 1,966 | 2,870 | — | — | 10,610 | |||||||||||||||||||||||||||||
| Unproved properties |
— | — | — | 1,657 | — | 146 | 7,182 | — | — | 8,985 | ||||||||||||||||||||||||||||||
| — | — | — | 7,431 | — | 2,112 | 10,052 | — | — | 19,595 | |||||||||||||||||||||||||||||||
| Accumulated depreciation, depletion and amortization |
— | — | — | 764 | — | 1,902 | 184 | — | — | 2,850 | ||||||||||||||||||||||||||||||
| $ | — | — | — | 6,667 | — | 210 | 9,868 | — | — | 16,745 | ||||||||||||||||||||||||||||||
| 2010 |
||||||||||||||||||||||||||||||||||||||||
| Consolidated operations |
||||||||||||||||||||||||||||||||||||||||
| Proved properties |
$ | 12,268 | 32,076 | 44,344 | 20,037 | 21,547 | 9 | 11,199 | 3,595 | 3,921 | 104,652 | |||||||||||||||||||||||||||||
| Unproved properties |
1,471 | 1,700 | 3,171 | 1,930 | 328 | 1 | 1,113 | 163 | 249 | 6,955 | ||||||||||||||||||||||||||||||
| 13,739 | 33,776 | 47,515 | 21,967 | 21,875 | 10 | 12,312 | 3,758 | 4,170 | 111,607 | |||||||||||||||||||||||||||||||
| Accumulated depreciation, depletion and amortization |
5,758 | 13,362 | 19,120 | 10,281 | 13,636 | 7 | 4,690 | 1,370 | 10 | 49,114 | ||||||||||||||||||||||||||||||
| $ | 7,981 | 20,414 | 28,395 | 11,686 | 8,239 | 3 | 7,622 | 2,388 | 4,160 | 62,493 | ||||||||||||||||||||||||||||||
| Equity affiliates |
||||||||||||||||||||||||||||||||||||||||
| Proved properties |
$ | — | — | — | 4,812 | — | 1,923 | 2,320 | — | — | 9,055 | |||||||||||||||||||||||||||||
| Unproved properties |
— | — | — | 1,794 | — | 146 | 8,144 | — | — | 10,084 | ||||||||||||||||||||||||||||||
| — | — | — | 6,606 | — | 2,069 | 10,464 | — | — | 19,139 | |||||||||||||||||||||||||||||||
| Accumulated depreciation, depletion and amortization |
— | — | — | 512 | — | 1,584 | 84 | — | — | 2,180 | ||||||||||||||||||||||||||||||
| $ | — | — | — | 6,094 | — | 485 | 10,380 | — | — | 16,959 | ||||||||||||||||||||||||||||||
A-124
Table of Contents
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserve Quantities
In accordance with SEC and FASB requirements, amounts were computed using 12-month average prices and end-of-year costs (adjusted only for existing contractual changes), appropriate statutory tax rates and a prescribed 10 percent discount factor. Twelve-month average prices are calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. 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 | |||||||||||||||||||||||||||||||
| 2011 |
||||||||||||||||||||||||||||||||||||||||
| Consolidated operations |
||||||||||||||||||||||||||||||||||||||||
| Future cash inflows |
$ | 143,652 | 73,807 | 217,459 | 40,581 | 78,250 | — | 49,936 | 33,017 | 11,891 | 431,134 | |||||||||||||||||||||||||||||
| Less: |
||||||||||||||||||||||||||||||||||||||||
| Future production and transportation costs* |
75,771 | 32,766 | 108,537 | 19,148 | 17,166 | — | 14,380 | 4,113 | 3,768 | 167,112 | ||||||||||||||||||||||||||||||
| Future development costs |
11,385 | 7,519 | 18,904 | 13,393 | 16,986 | — | 3,051 | 885 | 2,080 | 55,299 | ||||||||||||||||||||||||||||||
| Future income tax provisions |
20,512 | 11,771 | 32,283 | 2,060 | 29,853 | — | 11,967 | 23,825 | 990 | 100,978 | ||||||||||||||||||||||||||||||
| Future net cash flows |
35,984 | 21,751 | 57,735 | 5,980 | 14,245 | — | 20,538 | 4,194 | 5,053 | 107,745 | ||||||||||||||||||||||||||||||
| 10 percent annual discount |
19,233 | 9,643 | 28,876 | 4,025 | 5,372 | — | 6,649 | 1,522 | 3,712 | 50,156 | ||||||||||||||||||||||||||||||
| Discounted future net cash flows |
$ | 16,751 | 12,108 | 28,859 | 1,955 | 8,873 | — | 13,889 | 2,672 | 1,341 | 57,589 | |||||||||||||||||||||||||||||
| Equity affiliates |
||||||||||||||||||||||||||||||||||||||||
| Future cash inflows |
$ | — | — | — | 53,618 | — | 2,786 | 43,327 | — | — | 99,731 | |||||||||||||||||||||||||||||
| Less: |
||||||||||||||||||||||||||||||||||||||||
| Future production and transportation costs* |
— | — | — | 16,405 | — | 2,765 | 24,702 | — | — | 43,872 | ||||||||||||||||||||||||||||||
| Future development costs |
— | — | — | 7,163 | — | 36 | 905 | — | — | 8,104 | ||||||||||||||||||||||||||||||
| Future income tax provisions |
— | — | — | 7,574 | — | 3 | 3,705 | — | — | 11,282 | ||||||||||||||||||||||||||||||
| Future net cash flows |
— | — | — | 22,476 | — | (18 | ) | 14,015 | — | — | 36,473 | |||||||||||||||||||||||||||||
| 10 percent annual discount |
— | — | — | 14,662 | — | (39 | ) | 7,217 | — | — | 21,840 | |||||||||||||||||||||||||||||
| Discounted future net cash flows |
$ | — | — | — | 7,814 | — | 21 | 6,798 | — | — | 14,633 | |||||||||||||||||||||||||||||
| Total company |
||||||||||||||||||||||||||||||||||||||||
| Discounted future net cash flows |
$ | 16,751 | 12,108 | 28,859 | 9,769 | 8,873 | 21 | 20,687 | 2,672 | 1,341 | 72,222 | |||||||||||||||||||||||||||||
| * | 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 | |||||||||||||||||||||||||||||||
| 2010 |
||||||||||||||||||||||||||||||||||||||||
| Consolidated operations |
||||||||||||||||||||||||||||||||||||||||
| Future cash inflows |
$ | 102,743 | 68,949 | 171,692 | 38,083 | 49,270 | — | 37,673 | 24,487 | 8,466 | 329,671 | |||||||||||||||||||||||||||||
| Less: |
||||||||||||||||||||||||||||||||||||||||
| Future production and transportation costs** |
57,899 | 29,749 | 87,648 | 16,753 | 12,899 | — | 10,480 | 4,142 | 3,007 | 134,929 | ||||||||||||||||||||||||||||||
| Future development costs |
8,792 | 7,752 | 16,544 | 11,161 | 10,295 | — | 2,226 | 1,133 | 3,050 | 44,409 | ||||||||||||||||||||||||||||||
| Future income tax provisions |
13,383 | 10,953 | 24,336 | 2,416 | 16,765 | — | 9,211 | 16,217 | 384 | 69,329 | ||||||||||||||||||||||||||||||
| Future net cash flows |
22,669 | 20,495 | 43,164 | 7,753 | 9,311 | — | 15,756 | 2,995 | 2,025 | 81,004 | ||||||||||||||||||||||||||||||
| 10 percent annual discount |
10,723 | 10,046 | 20,769 | 3,890 | 2,597 | — | 4,889 | 1,025 | 2,368 | 35,538 | ||||||||||||||||||||||||||||||
| Discounted future net cash flows |
$ | 11,946 | 10,449 | 22,395 | 3,863 | 6,714 | — | 10,867 | 1,970 | (343 | ) | 45,466 | ||||||||||||||||||||||||||||
| Equity affiliates |
||||||||||||||||||||||||||||||||||||||||
| Future cash inflows |
$ | — | — | — | 47,169 | — | 5,610 | 32,845 | — | — | 85,624 | |||||||||||||||||||||||||||||
| Less: |
||||||||||||||||||||||||||||||||||||||||
| Future production and transportation costs** |
— | — | — | 16,492 | — | 4,809 | 21,036 | — | — | 42,337 | ||||||||||||||||||||||||||||||
| Future development costs |
— | — | — | 4,684 | — | 85 | 295 | — | — | 5,064 | ||||||||||||||||||||||||||||||
| Future income tax provisions |
— | — | — | 6,649 | — | (80 | ) | 2,082 | — | — | 8,651 | |||||||||||||||||||||||||||||
| Future net cash flows |
— | — | — | 19,344 | — | 796 | 9,432 | — | — | 29,572 | ||||||||||||||||||||||||||||||
| 10 percent annual discount |
— | — | — | 13,453 | — | 293 | 4,732 | — | — | 18,478 | ||||||||||||||||||||||||||||||
| Discounted future net cash flows |
$ | — | — | — | 5,891 | — | 503 | 4,700 | — | — | 11,094 | |||||||||||||||||||||||||||||
| Total company |
||||||||||||||||||||||||||||||||||||||||
| Discounted future net cash flows |
$ | 11,946 | 10,449 | 22,395 | 9,754 | 6,714 | 503 | 15,567 | 1,970 | (343 | ) | 56,560 | ||||||||||||||||||||||||||||
| * | Certain amounts have been restated to remove future development costs related to probable reserves. |
| ** | 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 | |||||||||||||||||||||||||||||||
| 2009 |
||||||||||||||||||||||||||||||||||||||||
| Consolidated operations |
||||||||||||||||||||||||||||||||||||||||
| Future cash inflows |
$ | 74,359 | 51,007 | 125,366 | 45,965 | 41,832 | — | 31,276 | 19,618 | 6,416 | 270,473 | |||||||||||||||||||||||||||||
| Less: |
||||||||||||||||||||||||||||||||||||||||
| Future production and transportation costs* |
44,789 | 32,491 | 77,280 | 23,625 | 13,559 | — | 9,058 | 3,832 | 2,071 | 129,425 | ||||||||||||||||||||||||||||||
| Future development costs |
7,829 | 8,350 | 16,179 | 12,769 | 10,369 | — | 2,284 | 1,142 | 3,879 | 46,622 | ||||||||||||||||||||||||||||||
| Future income tax provisions |
7,519 | 2,992 | 10,511 | 2,183 | 10,676 | — | 7,288 | 12,396 | 71 | 43,125 | ||||||||||||||||||||||||||||||
| Future net cash flows |
14,222 | 7,174 | 21,396 | 7,388 | 7,228 | — | 12,646 | 2,248 | 395 | 51,301 | ||||||||||||||||||||||||||||||
| 10 percent annual discount |
6,474 | 2,300 | 8,774 | 3,703 | 1,878 | — | 4,108 | 879 | 1,566 | 20,908 | ||||||||||||||||||||||||||||||
| Discounted future net cash flows |
$ | 7,748 | 4,874 | 12,622 | 3,685 | 5,350 | — | 8,538 | 1,369 | (1,171 | ) | 30,393 | ||||||||||||||||||||||||||||
| 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 | 1,369 | (1,171 | ) | 42,274 | ||||||||||||||||||||||||||||
| * | Includes taxes other than income taxes. |
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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 | ||||||||||||||||||||||||||||||||||||||
| 2011 | 2010 * | 2009 | 2011 | 2010 | 2009 | 2011 | 2010 * | 2009 | ||||||||||||||||||||||||||||||||
| Discounted future net cash flows at the beginning of the year |
$ | 45,466 | 30,393 | 24,548 | 11,094 | 11,881 | 3,033 | 56,560 | 42,274 | 27,581 | ||||||||||||||||||||||||||||||
| Changes during the year |
||||||||||||||||||||||||||||||||||||||||
| Revenues less production and transportation costs for the year** |
(24,223 | ) | (22,296 | ) | (18,460 | ) | (1,962 | ) | (3,083 | ) | (2,793 | ) | (26,185 | ) | (25,379 | ) | (21,253 | ) | ||||||||||||||||||||||
| Net change in prices, and production and transportation costs** |
38,161 | 39,532 | 19,208 | 4,685 | 3,478 | 14,386 | 42,846 | 43,010 | 33,594 | |||||||||||||||||||||||||||||||
| Extensions, discoveries and improved recovery, less estimated future costs |
8,730 | 4,517 | 2,312 | 832 | 297 | 1,342 | 9,562 | 4,814 | 3,654 | |||||||||||||||||||||||||||||||
| Development costs for the year |
8,428 | 5,617 | 6,148 | 1,488 | 1,758 | 1,623 | 9,916 | 7,375 | 7,771 | |||||||||||||||||||||||||||||||
| Changes in estimated future development costs |
(8,374 | ) | (2,917 | ) | (7,036 | ) | (1,508 | ) | (129 | ) | (2,197 | ) | (9,882 | ) | (3,046 | ) | (9,233 | ) | ||||||||||||||||||||||
| Purchases of reserves in place, less estimated future costs |
19 | 19 | 3 | — | — | 96 | 19 | 19 | 99 | |||||||||||||||||||||||||||||||
| Sales of reserves in place, less estimated future costs |
(390 | ) | (3,729 | ) | (75 | ) | (234 | ) | (5,405 | ) | — | (624 | ) | (9,134 | ) | (75 | ) | |||||||||||||||||||||||
| Revisions of previous quantity estimates*** |
(1,938 | ) | 3,062 | 5,149 | 491 | 372 | (1,597 | ) | (1,447 | ) | 3,434 | 3,552 | ||||||||||||||||||||||||||||
| Accretion of discount |
7,710 | 5,000 | 3,972 | 1,284 | 1,404 | 365 | 8,994 | 6,404 | 4,337 | |||||||||||||||||||||||||||||||
| Net change in income taxes |
(16,000 | ) | (13,732 | ) | (5,376 | ) | (1,537 | ) | 521 | (2,377 | ) | (17,537 | ) | (13,211 | ) | (7,753 | ) | |||||||||||||||||||||||
| Total changes |
12,123 | 15,073 | 5,845 | 3,539 | (787 | ) | 8,848 | 15,662 | 14,286 | 14,693 | ||||||||||||||||||||||||||||||
| Discounted future net cash flows at year end |
$ | 57,589 | 45,466 | 30,393 | 14,633 | 11,094 | 11,881 | 72,222 | 56,560 | 42,274 | ||||||||||||||||||||||||||||||
| * | Certain amounts have been restated to remove future development costs related to probable reserves. |
| ** | 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. |
| • | 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. |
| • | 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. |
A-128
Table of Contents
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
600 N. DAIRY ASHFORD
MCLEAN BUILDING #3025
HOUSTON, TX 77079
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TO VOTE, MARK BLOCKS BELOW IN BLUE OR BLACK INK AS FOLLOWS:
M43497-P23032 KEEP THIS PORTION FOR YOUR RECORDS
DETACH AND RETURN THIS PORTION ONLY
THIS VOTING DIRECTION CARD IS VALID ONLY WHEN SIGNED AND DATED.
CONOCOPHILLIPS
THE BOARD OF DIRECTORS RECOMMENDS A VOTE “FOR” ITEMS 1-3.
| .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. |
Ryan M. Lance |
| 1g. |
Mohd H. Marican |
| 1h. |
Harold W. McGraw III |
| 1i. |
James J. Mulva |
| 1j. |
Robert A. Niblock |
| 1k. |
Harald J. Norvik |
| 1l. |
William K. Reilly |
| 1m. |
Victoria J. Tschinkel |
| 1n. |
Kathryn C. Turner |
| 2. |
Proposal to ratify appointment of Ernst & Young LLP as ConocoPhillips’ independent registered public accounting firm for 2012. |
| 3. |
Advisory Approval of Executive Compensation. |
THE BOARD OF DIRECTORS RECOMMENDS A VOTE “AGAINST” ITEMS 4-8.
| 4. |
Company Environmental Policy (Louisiana Wetlands). |
| 5. |
Accident Risk Mitigation. |
| 6. |
Report on Grassroots Lobbying Expenditures. |
| 7. |
Greenhouse Gas Reduction Targets. |
| 8. |
Gender Expression Non-Discrimination. |
| 9. |
In its discretion, upon such other matters that may properly come before the meeting or any adjournment or adjournments thereof. |
For
For
Against
Against
Abstain
Abstain
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.
THIS PROXY IS SOLICITED ON BEHALF OF THE BOARD OF DIRECTORS
ANNUAL MEETING OF STOCKHOLDERS
MAY 9, 2012
The stockholder(s) hereby appoint(s) Jeff W. Sheets 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 9, 2012, 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, FOR THE ADVISORY APPROVAL OF EXECUTIVE COMPENSATION, AND AGAINST EACH OF THE STOCKHOLDER PROPOSALS.
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Continued and to be signed on reverse side
M43498-P23032