Form 10-K
Table of Contents

2012

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

 

(Mark One)          
[x]    ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)   
   OF THE SECURITIES EXCHANGE ACT OF 1934   
   For the fiscal year ended                 December 31, 2012                                           
   OR   
[  ]    TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)   
   OF THE SECURITIES EXCHANGE ACT OF 1934   
   For the transition period from                                          to                                            

Commission file number: 001-32395

ConocoPhillips

(Exact name of registrant as specified in its charter)

 

Delaware   01-0562944
(State or other jurisdiction of   (I.R.S. Employer
incorporation or organization)   Identification No.)

600 North Dairy Ashford

Houston, TX 77079

(Address of principal executive offices) (Zip Code)

Registrant’s telephone number, including area code: 281-293-1000

Securities registered pursuant to Section 12(b) of the Act:

 

Title of each class

 

Name of each exchange

            on which registered            

Common Stock, $.01 Par Value

  New York Stock Exchange

6.65% Debentures due July 15, 2018

  New York Stock Exchange

7% Debentures due 2029

  New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

[x] Yes  [  ] No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

[  ] Yes  [x] No

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. [x] Yes  [  ] No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

[x] Yes  [ ] No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [  ]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer [x]    Accelerated filer [  ]    Non-accelerated filer [  ]    Smaller reporting company [  ]

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).[  ] Yes  [x] No

The aggregate market value of common stock held by non-affiliates of the registrant on June 30, 2012, the last business day of the registrant’s most recently completed second fiscal quarter, based on the closing price on that date of $55.88, was $67.9 billion. The registrant, solely for the purpose of this required presentation, had deemed its Board of Directors to be an affiliate and deducted their stockholdings of 66,914 shares in determining the aggregate market value.

The registrant had 1,220,992,874 shares of common stock outstanding at January 31, 2013.

Documents incorporated by reference:

Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held on May 14, 2013 (Part III)

 

 

 


Table of Contents

TABLE OF CONTENTS

 

Item

        Page  
   PART I   

1 and 2.

   Business and Properties      1   
       Corporate Structure      1   
       Segment and Geographic Information      1   
           Alaska      4   
           Lower 48 and Latin America      6   
           Canada      9   
           Europe      11   
           Asia Pacific and Middle East      13   
           Other International      18   
           LUKOIL Investment      20   
       Competition      22   
       General      22   

1A.

   Risk Factors      23   

1B.

   Unresolved Staff Comments      26   

3.

   Legal Proceedings      26   

4.

   Mine Safety Disclosures      27   
   Executive Officers of the Registrant      28   
   PART II   

5.

  

Market for Registrant’s Common Equity, Related Stockholder Matters and
Issuer Purchases of Equity Securities

     30   

6.

   Selected Financial Data      31   

7.

  

Management’s Discussion and Analysis of Financial Condition and
Results of Operations

     32   

7A.

   Quantitative and Qualitative Disclosures About Market Risk      68   

8.

   Financial Statements and Supplementary Data      71   

9.

  

Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure

     172   

9A.

   Controls and Procedures      172   

9B.

   Other Information      172   
   PART III   

10.

   Directors, Executive Officers and Corporate Governance      173   

11.

   Executive Compensation      173   

12.

  

Security Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters

     173   

13.

   Certain Relationships and Related Transactions, and Director Independence      173   

14.

   Principal Accounting Fees and Services      173   
   PART IV   

15.

   Exhibits, Financial Statement Schedules      174   
   Signatures      181   


Table of Contents

PART I

Unless otherwise indicated, “the company,” “we,” “our,” “us” and “ConocoPhillips” are used in this report to refer to the businesses of ConocoPhillips and its consolidated subsidiaries. Items 1 and 2—Business and Properties, contain forward-looking statements including, without limitation, statements relating to our 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 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 67.

Items 1 and 2. BUSINESS AND PROPERTIES

CORPORATE STRUCTURE

ConocoPhillips is the world’s largest independent exploration and production (E&P) company, based on proved reserves and production of liquids and natural gas. ConocoPhillips was incorporated in the state of Delaware on November 16, 2001, in connection with, and in anticipation of, the merger between Conoco Inc. and Phillips Petroleum Company. The merger between Conoco and Phillips was consummated on August 30, 2002.

On April 30, 2012, we completed the separation of our downstream businesses into an independent, publicly traded company, Phillips 66. Our refining, marketing and transportation businesses, most of our Midstream segment, our Chemicals segment, as well as our power generation and certain technology operations included in our Emerging Businesses segment (collectively, our “Downstream business”), were transferred to Phillips 66. As a part of our strategic asset disposition program, in the fourth quarter of 2012, we agreed to sell our interest in the North Caspian Sea Production Sharing Agreement (Kashagan) and our Nigerian and Algerian businesses. Results of operations related to Phillips 66, Kashagan, Nigeria and Algeria have been classified as discontinued operations in all periods presented in this Annual Report on Form 10-K. For additional information, see Note 2—Discontinued Operations, in the Notes to Consolidated Financial Statements.

Headquartered in Houston, Texas, we have operations and activities in 30 countries. Our key focus areas include safely operating producing assets, executing major developments and exploring for new resources in promising areas. Our portfolio primarily includes legacy assets in North America, Europe, Asia and Australia; growing North American shale and oil sands businesses; several major international developments; and a global exploration program.

At December 31, 2012, ConocoPhillips employed approximately 16,900 people worldwide.

SEGMENT AND GEOGRAPHIC INFORMATION

For operating segment and geographic information, see Note 25—Segment Disclosures and Related Information, in the Notes to Consolidated Financial Statements, which is incorporated herein by reference.

We explore for, produce, transport and market crude oil, bitumen, natural gas, liquefied natural gas (LNG) and natural gas liquids on a worldwide basis. At December 31, 2012, our continuing operations were producing in

 

1


Table of Contents

the United States, Norway, the United Kingdom, Canada, Australia, offshore Timor-Leste in the Timor Sea, Indonesia, China, Malaysia, Qatar, Libya and Russia.

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

The information listed below appears in the “Oil and Gas Operations” disclosures following the Notes to Consolidated Financial Statements and is incorporated herein by reference:

 

   

Proved worldwide crude oil, natural gas liquids, natural gas and bitumen reserves.

   

Net production of crude oil, natural gas liquids, natural gas and bitumen.

   

Average sales prices of crude oil, natural gas liquids, natural gas and bitumen.

   

Average production costs per barrel of oil equivalent (BOE).

   

Net wells completed, wells in progress and productive wells.

   

Developed and undeveloped acreage.

 

2


Table of Contents

The following table is a summary of the proved reserves information included in the “Oil and Gas Operations” disclosures following the Notes to Consolidated Financial Statements. Approximately 80 percent of our proved reserves are located in politically stable countries that belong to the Organization for Economic Cooperation and Development. Natural gas reserves are converted to BOE based on a 6:1 ratio: six thousand cubic feet of natural gas converts to one BOE. See Management’s Discussion and Analysis of Financial Condition and Results of Operations for a discussion of factors that will enhance the understanding of the table below.

 

     Millions of Barrels of Oil Equivalent  
Net Proved Reserves at December 31    2012      2011      2010   

Crude oil

        

Consolidated operations

     2,684        2,617        2,496   

Equity affiliates

     95        124        177   

 

 

Total Crude Oil

     2,779        2,741        2,673   

 

 

Natural gas liquids

        

Consolidated operations

     646        670        665   

Equity affiliates

     48        51        54   

 

 

Total Natural Gas Liquids

     694        721        719   

 

 

Natural gas

        

Consolidated operations

     2,726        2,933        3,039   

Equity affiliates

     543        553        580   

 

 

Total Natural Gas

     3,269        3,486        3,619   

 

 

Bitumen

        

Consolidated operations

     506        530        455   

Equity affiliates

     1,394        909        844   

 

 

Total Bitumen

     1,900        1,439        1,299   

 

 

Total consolidated operations

     6,562        6,750        6,655   

Total equity affiliates

     2,080        1,637        1,655   

 

 

Total company

     8,642        8,387        8,310   

 

 

In 2012, worldwide production, including our share of equity affiliates, was 1,578 thousand barrels of oil equivalent per day (MBOED), a 3 percent decrease from 2011 production of 1,619 MBOED. Production from continuing operations for 2012 averaged 1,527 MBOED, compared with 1,561 MBOED in 2011. Average production from continuing operations decreased 2 percent in 2012, primarily as a result of normal field decline, the impact from asset dispositions and higher planned and unplanned downtime. These decreases were largely offset by additional production from major developments, mainly from shale plays in the Lower 48 and ramp-up of new phases at FCCL, the resumption of production in Libya following a period of civil unrest in 2011, and increased drilling programs in the Lower 48.

Our worldwide annual average crude oil sales price from continuing operations remained relatively flat in 2012, from $105.52 per barrel in 2011 to $105.72 per barrel in 2012, while worldwide average annual natural gas liquids prices from continuing operations decreased 17 percent, from $55.73 per barrel in 2011 to $46.36 per barrel in 2012. Our average annual worldwide natural gas sales price from continuing operations decreased 6 percent, from $5.80 per thousand cubic feet in 2011 to $5.48 per thousand cubic feet in 2012. Average annual bitumen prices decreased 14 percent, from $62.56 per barrel in 2011 to $53.91 per barrel in 2012.

 

3


Table of Contents

ALASKA

The Alaska segment primarily explores for, produces, transports and markets crude oil, natural gas liquids, natural gas and LNG. In 2012, Alaska operations contributed 24 percent of our worldwide liquids production and 1 percent of our natural gas production.

 

                  2012  
       

 

 

 
             Interest     Operator          Liquids
MBD
(1)
     Natural  Gas
MMCFD
(2)
     Total
MBOED
 
  

 

 

   

 

 

    

 

 

 

Average Daily Net Production

             

Greater Prudhoe Area

     36.1     BP         104        5        105   

Greater Kuparuk Area

     52.2-55.4        ConocoPhillips         54        -        54   

Western North Slope

     78        ConocoPhillips         46        1        46   

Cook Inlet Area

     33.3-100        ConocoPhillips         -        49         

 

 

Total Alaska

          204        55        213   

 

 

(1) Thousands of barrels per day.

(2) Millions of cubic feet per day.

Greater Prudhoe Area

The Greater Prudhoe Area includes the Prudhoe Bay Field and five satellite fields, as well as the Greater Point McIntyre Area fields. Prudhoe Bay, the largest oil field on Alaska’s North Slope, is the site of a large waterflood and enhanced oil recovery operation, as well as a gas processing plant which processes natural gas for reinjection into the reservoir. Prudhoe Bay’s satellites are Aurora, Borealis, Polaris, Midnight Sun and Orion, while the Point McIntyre, Niakuk, Raven and Lisburne fields are part of the Greater Point McIntyre Area.

Greater Kuparuk Area

We operate the Greater Kuparuk Area, which is made up of the Kuparuk Field and four satellite fields: Tarn, Tabasco, Meltwater and West Sak. Kuparuk is located 40 miles west of Prudhoe Bay on Alaska’s North Slope. Field installations include three central production facilities that separate oil, natural gas and water, as well as a separate seawater treatment plant. The natural gas is either used for fuel or compressed for reinjection.

Western North Slope

On the Western North Slope, we operate the Colville River Unit, which includes the Alpine Field and three satellite fields: Nanuq, Fiord and Qannik. Alpine is located 34 miles west of Kuparuk. In October 2012, Alpine West CD5, a satellite field located west of Alpine in the National Petroleum Reserve—Alaska (NPRA), was sanctioned. Initial production is anticipated in late 2015, with net peak production estimated at 10 MBOED in 2016.

Cook Inlet Area

We operate the North Cook Inlet Unit, the Beluga River Unit, and the Kenai LNG Plant in the Cook Inlet Area. We have a 100 percent interest in the North Cook Inlet Unit and the Kenai LNG Plant, while we own 33.3 percent of the Beluga River Unit. Our share of production is sold to local utilities and is also used to supply feedstock and fuel to the Kenai LNG Plant.

The Kenai LNG Plant had historically supplied LNG to utility companies in Japan. Although we idled the plant in October 2012, we maintain the capability to operate it and are evaluating options for future use. The LNG export license will expire in March 2013.

 

4


Table of Contents

Point Thomson

We own a 5 percent interest in the Point Thomson Field, which is located approximately 60 miles east of Prudhoe Bay. An initial production system is anticipated to be online by 2016, which is estimated to send 400 net BOED of condensate through the Trans-Alaska Pipeline System (TAPS).

North Slope Natural Gas

In March 2012, we, along with Exxon Mobil Corporation, BP p.l.c. and TransCanada Corporation, announced we are working together on a plan aimed at commercializing North Slope natural gas resources through large-scale LNG exports from south-central Alaska. Planning and assessment is ongoing.

Exploration

In the February 2008 Outer Continental Shelf (OCS) Lease Sale 193, we successfully bid and were awarded 10-year-primary-term leases on 98 blocks in the Chukchi Sea. We plan to drill an exploration well on our Devil’s Paw prospect in 2014, subject to the outcome of pending litigation challenging Lease Sale 193 and the receipt of required regulatory permits.

Shark Tooth #1, an appraisal step-out well from the southwestern area of the Kuparuk Field, was spud in January 2012, and is being evaluated for further development potential. During 2013, we plan to drill one exploration well, Cassin, on the North Slope.

Transportation

We transport the petroleum liquids produced on the North Slope to south-central Alaska through an 800-mile pipeline that is part of TAPS. We have a 28.3 percent ownership interest in TAPS, and we also have ownership interests in the Alpine, Kuparuk and Oliktok Pipelines on the North Slope.

Our wholly owned subsidiary, Polar Tankers, Inc., manages the marine transportation of our North Slope production, using five company-owned double-hulled tankers in addition to chartering third-party vessels as necessary.

 

5


Table of Contents

LOWER 48 AND LATIN AMERICA

Lower 48

The Lower 48 and Latin America segment primarily consists of operations located in the U.S. Lower 48 states. We hold 15.5 million net onshore and offshore acres in the Lower 48. In 2012, Lower 48 and Latin America contributed 25 percent of our worldwide liquids production and 37 percent of our natural gas production.

 

                  2012  
       

 

 

 
             Interest        Operator        
 
    Liquids
MBD
  
  
    
 
 
Natural
Gas
MMCFD
  
  
  
    
 
Total
MBOED
  
  
  

 

 

   

 

 

    

 

 

 

Average Daily Net Production

             

Eagle Ford

     Various   %      Various         56        85        70   

Bakken

     Various        Various         22        17        25   

Barnett

     Various        Various         6        49        14   

Permian

     Various        Various         33        111        51   

San Juan

     Various        Various         49        750        174   

Lobo

     Various        ConocoPhillips         5        112        24   

Anadarko Basin

     Various        Various         6        124        27   

Wind River

     Various        Various         -        78        13   

Bossier

     Various        Various         -        43         

Other onshore

     Various        Various         18        111        37   

Gulf of Mexico

     Various        Various         13        13        15   

 

 

Total U.S. Lower 48

          208        1,493        457   

 

 

Onshore

We hold 13.8 million net acres of onshore conventional and unconventional acreage in the Lower 48. Our unconventional holdings total 2.5 million net acres and include approximately 626,000 net acres in the Bakken; 227,000 net acres in the Eagle Ford; 194,000 net acres in Permian; 130,000 net acres in Niobrara; 900,000 net acres in the San Juan Basin; and nearly 430,000 net acres in other unconventional exploration plays. The majority of this acreage is either held by production or owned by the Company.

The majority of our 2012 onshore production originated from the San Juan Basin, Permian Basin, Eagle Ford, Bakken, Barnett, the Lobo Trend, Anadarko Basin and Bossier Trend. We also have operations in the Wind River Basin, East Texas, Rockies and northern and southern Louisiana. Onshore activities in 2012 were centered mostly on continued optimization and development of existing and emerging assets, with particular focus on areas with higher liquids production.

 

   

Shale Plays

Exploration and development continued in our shale positions in the Eagle Ford, Bakken and Barnett. In the Eagle Ford, we drilled 211 exploration and development wells and connected 170 wells in 2012, achieving net peak production of over 100 MBOED in December 2012. In 2013, we plan to drill approximately 140 wells and connect approximately 200 wells. With continued investments, we expect long-term average production from the Eagle Ford will be approximately 140 MBOED by 2016.

 

   

San Juan

The San Juan Basin, located in northwestern New Mexico and southwestern Colorado, includes significant conventional gas production, which yields approximately 35 percent natural gas liquids, as well as the majority of our U.S. coalbed methane (CBM) production. We hold approximately 1.3 million acres of oil and gas leases by production in San Juan, where we continue to pursue

 

6


Table of Contents

conventional development opportunities. This includes approximately 900,000 net acres of lease rights, where we are advancing the assessment of the Mancos shale play.

In January 2013, we entered into an agreement to sell the majority of our properties in the Cedar Creek Anticline, comprising approximately 86,000 net acres in southwestern North Dakota and eastern Montana. The transaction is expected to close in the first quarter of 2013.

Gulf of Mexico

At year-end 2012, our portfolio of producing properties in the Gulf of Mexico primarily consisted of one operated field and three fields operated by co-venturers, including:

 

   

75 percent operator interest in the Magnolia Field in Garden Banks Blocks 783 and 784.

   

16 percent nonoperator interest in the unitized Ursa Field located in the Mississippi Canyon Area.

   

16 percent nonoperator interest in the Princess Field, a northern, subsalt extension of the Ursa Field.

   

12.4 percent nonoperator interest in the unitized K2 Field, comprised of seven blocks in the Green Canyon Area.

Exploration

 

   

Conventional Exploration

In the deepwater Gulf of Mexico, we held 1.7 million acres at December 31, 2012. In November 2012, we were the successful high bidder on 62 blocks in OCS Western Lease Sale 229, the majority of which have been awarded to date. We anticipate the remaining blocks will be awarded in the first quarter of 2013, which would increase our Gulf of Mexico position to 2.0 million net acres. In 2013, drilling continued on the partner-operated Coronado wildcat well and the Shenandoah appraisal well, both of which were spud in 2012. During the first half of 2013, drilling is expected to commence on the partner-operated Ardennes wildcat well, the Tiber appraisal well and a ConocoPhillips-operated wildcat well in the Miocene/Pliocene Thorn prospect. We also plan to participate in two-to-three additional non-operated wildcat wells in 2013.

In support of our intentions to grow our Gulf of Mexico exploration program, we secured access to an ultra deepwater drillship in 2012, which will provide rig availability for our operated drilling program beginning in 2014.

 

   

Unconventional Exploration

In 2012, we actively pursued the appraisal of our existing unconventional resource plays, including the Eagle Ford in South Texas, the Bakken in the Williston Basin, the Barnett in the Fort Worth Basin, the Niobrara play in the Denver-Julesburg Basin, the Avalon and Wolfcamp in the Permian Basin, and the Mancos in the San Juan Basin. During 2012, we acquired approximately 340,000 net additional acres in various resource plays across the Lower 48, which included the Avalon, Wolfcamp, Niobrara, and various exploration plays, further expanding our significant acreage position in Lower 48 shale plays to approximately 2.5 million net acres.

During 2012, we drilled a total of 20 unconventional test wells in the Avalon, Wolfcamp, Niobrara, Bakken Little Missouri, Lewis and Mancos plays. Drilling is expected to continue in 2013.

Transportation

Our 25 percent interest in the Rockies Express Pipeline (REX) was transferred to Phillips 66 as part of the separation. We retained the capacity rights and obligations to REX.

Facilities

Freeport LNG Terminal

We have a long-term agreement with Freeport LNG Development, L.P. to use 0.9 billion cubic feet per day of regasification capacity at Freeport’s 1.5-billion-cubic-feet-per-day LNG receiving terminal in Quintana, Texas.

 

7


Table of Contents

Market conditions currently favor the flow of LNG to European and Asian markets; therefore, our near- to mid-term utilization of the Freeport Terminal is expected to be limited to LNG storage and reload activities. We are responsible for monthly process-or-pay payments to Freeport irrespective of whether we utilize the terminal for regasification. The financial impact of these capacity underutilization payments is not expected to be material to our future earnings or cash flows.

Golden Pass LNG Terminal

We have a 12.4 percent ownership interest in the Golden Pass LNG Terminal and affiliated Golden Pass Pipeline. It is located adjacent to the Sabine-Neches Industrial Ship Channel northwest of Sabine Pass, Texas. The terminal became commercially operational in May 2011. We hold terminal and pipeline capacity for the receipt, storage and regasification of the LNG purchased from Qatargas 3 and the transportation of regasified LNG to interconnect with major interstate natural gas pipelines. Market conditions currently favor the flow of LNG to European and Asian markets; therefore, our near-to-mid-term utilization of the terminal is expected to be limited.

Phoenix Park Gas Processors Limited

We own a 39 percent interest in Phoenix Park Gas Processors Limited, which processes natural gas in Trinidad and markets natural gas liquids in the Caribbean, Central America and the U.S. Gulf Coast. Facilities include a 2-billion-cubic-feet-per-day gas processing plant and a 70,000 barrel-per-day natural gas liquids fractionator.

Other

 

   

San Juan Gas Plant – We operate and own a 50 percent interest in the San Juan Gas Plant, a 550 million cubic-feet-per-day capacity natural gas processing plant in Bloomfield, New Mexico.

   

Lost Cabin Gas Plant – We operate and own a 46 percent interest in the Lost Cabin Gas Plant, a 313 million cubic-feet-per-day capacity natural gas processing facility in Lysite, Wyoming.

   

Wingate Fractionator – We operate and own the Wingate Fractionator, a 25,000 barrel-per-day capacity natural gas liquids fractionation plant located in Gallup, New Mexico.

Venezuela

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 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 anticipate an interim decision on key legal and factual issues in 2013. In a separate commercial arbitration from the Company’s ICSID claim discussed above, an International Chamber of Commerce (ICC) tribunal issued a decision in favor of the Company in September 2012, finding PDVSA owed $67 million for pre-expropriation breaches of the Petrozuata project agreements. In November 2012, based on the ICC tribunal ruling, PDVSA paid ConocoPhillips $68 million, including post-judgment interest, which resulted in a $61 million after-tax earnings increase. The Company also recognized additional income of $173 million after-tax associated with the reversal of a related contingent liability accrual.

Ecuador

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. On April 24, 2012, Ecuador filed a supplemental counterclaim asserting environmental damages, which we believe are not material. The ICSID tribunal issued a decision on liability on December 14, 2012, in favor of Burlington,

 

8


Table of Contents

finding that Ecuador’s seizure of Blocks 7 and 21 was an unlawful expropriation in violation of the Ecuador-U.S. Bilateral Investment Treaty. An additional arbitration phase will take place to determine the damages owed to ConocoPhillips for Ecuador’s actions.

Peru

Exploration

We own a 45 percent operating interest in Blocks 123 and 129, covering nearly 1.6 million net acres. In October 2012, we announced our decision not to pursue further exploration activities in Blocks 123 and 129. This decision to withdraw is part of our strategic plan to optimize our portfolio of assets.

CANADA

Our Canadian operations mainly consist of natural gas fields in western Canada and oil sands developments in the Athabasca Region of northeastern Alberta. In 2012, Canada operations contributed 15 percent of our worldwide liquids production and 21 percent of our natural gas production.

 

                  2012  
       

 

 

 
             Interest     Operator          Liquids
MBD
     Natural
Gas
MMCFD
     Bitumen
MBD
     Total
MBOED
 
  

 

 

   

 

 

    

 

 

 

Average Daily Net Production

                

Western Canada

     Various   %      Various         37        857        -        180   

Surmont

     50.0        ConocoPhillips         -        -        12        12   

Foster Creek

     50.0        Cenovus         -        -        51        51   

Christina Lake

     50.0        Cenovus         -        -        30        30   

 

 

Total Canada

          37        857        93        273   

 

 

Western Canada

Our operations in western Canada are primarily comprised of three core development areas: Deep Basin, Kaybob and O’Chiese, which extend from central Alberta to northeastern British Columbia. We operate or have ownership interests in approximately 80 natural gas processing plants in the region, and, as of December 31, 2012, held leasehold rights in 5.9 million net acres in western Canada.

Oil Sands

We hold approximately 1.1 million net acres of land in the Athabasca Region of northeastern Alberta. Our bitumen resources in Canada are produced via an enhanced thermal oil recovery method called steam-assisted gravity drainage (SAGD), whereby steam is injected into the reservoir, effectively liquefying the heavy bitumen, which is recovered and pumped to the surface for further processing.

 

   

Surmont

The Surmont oil sands leases are located approximately 35 miles south of Fort McMurray, Alberta. Surmont is a 50/50 joint venture with Total S.A. Surmont Phase 2 construction began in 2010, with production startup targeted for 2015. Following startup, Surmont’s gross production capacity is estimated to be 150 MBOED, with net peak production of 65 MBOED anticipated by 2018.

 

   

FCCL

We have a 50/50 heavy oil business venture with Cenovus Energy Inc., FCCL Partnership, a Canadian upstream general partnership. FCCL’s assets, operated by Cenovus, include the Foster Creek, Christina Lake and Narrows Lake SAGD bitumen developments.

Construction continued in 2012 on both the Foster Creek and Christina Lake properties. At Christina Lake, Phase D was completed and production came on stream in the third quarter of 2012. Phase D

 

9


Table of Contents

added 40 MBOED of gross production capacity, bringing total gross production capacity to 98 MBOED. Phase E is expected to be completed in 2013, with first production targeted for the second half of 2013, which will add another 40 MBOED of gross production capacity. Phase F was sanctioned in the fourth quarter of 2012, with production startup anticipated in 2016, which will add an additional 50 MBOED of gross production capacity.

At Foster Creek, construction progressed on Phases F, G and H, which are estimated to be completed in 2014, 2015 and 2016, respectively. These phases will add approximately 125 MBOED of gross production capacity. FCCL anticipates submitting an application for regulatory approval for an additional expansion, Phase J, in 2013.

Narrows Lake is a new oil sands development within the FCCL Partnership. In May 2012, FCCL received approval from the Alberta government to proceed with Narrows Lake. Narrows Lake Phase A was sanctioned in the fourth quarter of 2012, and initial production is anticipated in 2017.

Parsons Lake/Mackenzie Gas Project

We were involved with three other energy companies, as members of the Mackenzie Gas Project, on the development of the Mackenzie Valley Pipeline and gathering system, which was proposed to transport onshore gas production from the Mackenzie Delta in northern Canada to established markets in North America. We have a 75 percent interest in the Parsons Lake natural gas field, one of the primary fields in the Mackenzie Delta, which would anchor the pipeline development. Due to a continued decline in market conditions and lack of acceptable commercial terms, the project was suspended indefinitely in the first quarter of 2012. As a result, we recorded a $520 million after-tax impairment in 2012 for the carrying value of capitalized development costs and associated undeveloped leasehold costs.

Amauligak

We have a 53.8 percent operating interest in Amauligak, which lies approximately 31 miles offshore in shallow water in the Beaufort Sea. A range of development options are being evaluated.

Exploration

We hold exploration acreage in four areas of Canada: offshore eastern Canada, onshore western Canada, the Mackenzie Delta/Beaufort Sea Region and the Arctic Islands.

 

   

Unconventional Exploration

During 2012, we drilled unconventional test wells in the Duvernay and Montney plays. In 2013, exploration activities will continue in Duvernay, the Canol Shale in the Northwest Territories, Muskwa in the Horn River Basin and the Montney play. We also plan to continue delineating potential development opportunities in the oil sands.

 

10


Table of Contents

EUROPE

The Europe segment consists of operations principally located in the Norwegian and U.K. sectors of the North Sea, as well as exploration activities in Poland and Greenland. In 2012, operations in Europe contributed 17 percent of our worldwide liquids production and 13 percent of natural gas production.

Norway

 

                  2012  
       

 

 

 
                      Liquids      Natural Gas      Total  
             Interest     Operator      MBD      MMCFD      MBOED  
  

 

 

   

 

 

    

 

 

 

Average Daily Net Production

             

Greater Ekofisk Area

     35.1   %      ConocoPhillips         66        52        75   

Alvheim

     20        Marathon         14        14        16   

Heidrun

     24        Statoil         11        10        13   

Other

     Various        Various         17        84        31   

 

 

Total Norway

          108        160        135   

 

 

The Greater Ekofisk Area, located approximately 200 miles offshore Stavanger, Norway in the North Sea, is comprised of four producing fields: Ekofisk, Eldfisk, Embla and Tor. Crude oil is exported to Teesside, England, and the natural gas is exported to Emden, Germany. The Ekofisk South and Eldfisk II developments continue, with production expected in the fourth quarters of 2013 and 2014, respectively.

The Alvheim development consists of a floating production, storage and offloading (FPSO) vessel and subsea installations. Produced crude oil is exported via shuttle tankers, and natural gas is transported to the United Kingdom via a pipeline to the Beryl-Sage system.

The Heidrun Field is located in the Norwegian Sea. Produced crude oil is transported to Mongstad in Norway and Tetney in the United Kingdom by double-hulled shuttle tankers. Part of the natural gas is transported and sold to buyers in Europe, while the remainder is used as feedstock in a methanol plant in Norway, in which we own an 18.3 percent interest.

We also have varying ownership interests in five other producing fields in the Norway sector of the North Sea and in the Norwegian Sea.

In the second quarter of 2012, we sold our Norway and U.K. interests in the Statfjord Field and associated satellites.

Exploration

During 2012, we completed the evaluation of available acreage for the 22nd Licensing Round and submitted an application in December.

Transportation

We own a 35.1 percent interest in the Norpipe Oil Pipeline System, a 220-mile pipeline which carries crude oil from Ekofisk to a crude oil stabilization and natural gas liquids processing facility in Teesside, England. In addition, we own a 1.9 percent interest in Norwegian Continental Shelf Gas Transportation (Gassled), which owns most of the Norwegian gas transportation infrastructure.

 

11


Table of Contents

United Kingdom

 

                  2012  
       

 

 

 
             Interest        Operator        
 
    Liquids
MBD
  
  
    
 
 
Natural
Gas
MMCFD
  
  
  
    
 
Total
MBOED
  
  
  

 

 

   

 

 

    

 

 

 

Average Daily Net Production

             

Britannia

     58.7   %      Britannia         4        117        24   
       Operator Ltd.            

Britannia Satellites

     75.0-83.5        ConocoPhillips         13        23        17   

J-Area

     32.5-36.5        ConocoPhillips         8        59        18   

Southern North Sea

     Various        Various         -        98        16   

East Irish Sea

     100        HRL         -        56         

Other

     Various        Various         9        3         

 

 

Total United Kingdom

          34        356        93   

 

 

In addition to our interest in the Britannia natural gas and condensate field, we own 50 percent of Britannia Operator Limited, the operator of the field. Condensate is delivered through the Forties Pipeline to an oil stabilization and processing plant near the Grangemouth Refinery in Scotland, while natural gas is transported through Britannia’s line to St. Fergus, Scotland. The Britannia satellite fields, Callanish and Brodgar, produce via subsea manifolds and pipelines linked to the Britannia platform.

J-Area is comprised of the Judy/Joanne, Jade and Jasmine fields, located in the U.K. Central North Sea. Development of the Jasmine Field continued during 2012, and we anticipate first production in the fourth quarter of 2013. Jasmine is estimated to achieve average net peak production of 37 MBOED in 2014.

We have various ownership interests in 18 producing gas fields in the Rotliegendes and Carboniferous areas of the Southern North Sea. Our interests in the East Irish Sea include the Millom, Dalton and Calder fields, which are operated on our behalf by a third party.

We own a 24 percent interest in the Clair Field, located in the Atlantic Margin. The development of Clair Ridge received government approval in October 2011, and initial production is estimated to occur in 2016.

We sold our interest in the Alba Field in the second quarter of 2012.

Exploration

We were awarded three licenses during 2012, one in the East Irish Sea and two in the Central Graben, North Sea. We approved the Greater Clair exploration and appraisal program in 2012 and plan to commence drilling in 2013.

Transportation

We have a 10 percent interest in the Interconnector Pipeline, which links the United Kingdom and Belgium and facilitates the marketing throughout Europe of natural gas produced in the United Kingdom. In January 2013, we entered into an agreement to sell our equity interest. The sale is expected to close in the first quarter of 2013.

We operate the Teesside oil and Theddlethorpe gas terminals in which we have 29.3 percent and 50 percent ownership interests, respectively. We also have a 100 percent ownership interest in the Rivers Gas Terminal, operated by a third party, in the United Kingdom.

 

12


Table of Contents

Poland

Exploration

We are participating in a shale gas venture in Poland. In the third quarter of 2012, we exercised our option to acquire a 70 percent interest in Lane Energy Poland and assumed operatorship for three western Baltic Basin concessions. Four wells have been drilled on these concessions, with further well tests and drilling planned for 2013. A 3-D seismic survey is also planned for the first quarter of 2013.

Greenland

Exploration

During 2012, we successfully completed a 2-D seismic survey in Block 7011/11 of the Qamut license in West Greenland and recovered stratigraphic cores which will guide the interpretation of this new data. In addition, we have completed the evaluation of available acreage in East Greenland.

ASIA PACIFIC AND MIDDLE EAST

The Asia Pacific and Middle East segment has exploration and production operations in China, Indonesia, Malaysia, Australia and the Timor Sea; producing operations in Qatar; and exploration activities in Bangladesh and Brunei. In 2012, operations in the Asia Pacific and Middle East segment contributed 13 percent of our worldwide liquids production and 28 percent of natural gas production.

Australia and Timor Sea

 

                  2012  
       

 

 

 
             Interest     Operator          Liquids
MBD
     Natural
Gas
MMCFD
     Total
MBOED
 
  

 

 

   

 

 

    

 

 

 

Average Daily Net Production

             

Australia Pacific LNG

     37.5  %      Origin Energy         -        118        20  

Bayu-Undan

     56.9        ConocoPhillips         27        195        59  

Athena/Perseus

     50        ExxonMobil         -        35        6  

 

 

Total Australia and Timor Sea

          27        348        85  

 

 

Australia Pacific LNG

Australia Pacific LNG Pty Ltd (APLNG), our joint venture with Origin Energy and China Petrochemical Corporation (Sinopec), is focused on producing CBM from the Bowen and Surat basins in Queensland, Australia. Origin operates APLNG’s production and pipeline system, and we will operate the LNG facility. Natural gas is currently sold to domestic customers, while progress continues on the development of an LNG processing and export sales business. Once established, this will enhance our LNG position and serve as an additional LNG hub supplying Asia Pacific markets. Two initial 4.5-million-tonnes-per-year LNG trains have been sanctioned, with approximately 9,000 net wells ultimately envisioned to supply both the domestic gas market and the LNG development. The additional wells will be supported by expanded gas gathering systems, centralized gas processing and compression stations, and water treatment facilities, in addition to a new export pipeline from the gas fields to the LNG facilities.

During 2011, three significant milestones were achieved. First, the development received environmental approval from the Australian federal government. Second, definitive agreements were signed with Sinopec for the supply of 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 from 50 percent to 42.5 percent. The Subscription Agreement was completed in August 2011. Third, a binding Heads of Agreement was signed with Japan-based Kansai Electric Power Co. Inc., for the sale of approximately 1 million tonnes of LNG per year for 20 years.

 

13


Table of Contents

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. This agreement, in combination with the Kansai Electric agreement, finalized the marketing of the second train. In July 2012, we sanctioned the development of the second 4.5-million-tonnes-per-year LNG production train. Start-up of the second train is expected to occur in the fourth quarter of 2015, with resulting LNG exports commencing shortly thereafter sold under the binding sales agreements to Sinopec and Kansai Electric. Upon sanctioning of the second train in July and in conjunction with the LNG sales agreement, Sinopec subscribed to additional shares in APLNG, which increased its equity interest from 15 percent to 25 percent. As a result, on July 12, 2012, both our ownership interest and Origin Energy’s ownership interest diluted from 42.5 percent to 37.5 percent.

APLNG executed project financing agreements for an $8.5 billion project finance facility during the third quarter of 2012 and began drawing on the financing in October 2012. Our reduced ownership interest, coupled with Sinopec’s $2.1 billion injection into APLNG associated with the dilution and APLNG’s successful placement of the $8.5 billion of project financing, will lower our future capital requirements to fund the project. We are evaluating opportunities to further reduce our ownership interest in APLNG. In connection with the execution of the project financing, we provided a completion guarantee for our pro-rata share of the project finance facility, which will be released upon meeting certain completion milestones.

For additional information, see Note 3—Variable Interest Entities (VIEs), Note 6—Investments, Loans and Long-Term Receivables, and Note 13—Guarantees, in the Notes to Consolidated Financial Statements.

Bayu-Undan

The Bayu-Undan gas condensate field is located in the Timor Sea Joint Petroleum Development Area between Timor-Leste and Australia. We also operate and own a 56.9 percent interest in the associated Darwin LNG Facility, located at Wickham Point, Darwin. Produced natural gas is used to supply the Darwin LNG Plant. In 2012, we sold 148 billion gross cubic feet of LNG to utility customers in Japan.

During the first half of 2013, the Bayu-Undan Phase 3 Development will focus on procuring long-lead items and securing contracts for a semi-submersible drilling rig. Final Investment Decision is expected in mid-2013 and will be followed by further detailed engineering and procurement activities. Drilling is anticipated to commence in the second quarter of 2014.

ConocoPhillips served a Notice of Arbitration on the Timor-Leste Minister of Finance in October 2012 for outstanding disputes related to a series of tax assessments. Between 2010 and 2012, ConocoPhillips has paid, under protest, tax assessments totaling approximately $227 million, which are primarily recorded in the “Investments and long-term receivables” line on our December 31, 2012, consolidated balance sheet. The arbitration will be conducted in Singapore under the United Nations Commission on International Trade Laws (UNCITRAL) arbitration rules, pursuant to the terms of the Tax Stability Agreement with the Timor-Leste Government. The arbitration process is currently underway. Future impacts on our business are not known at this time.

Athena/Perseus

The Athena production license (WA-17-L) is located offshore Western Australia and contains part of the Perseus Field which straddles the boundary with WA-1-L, an adjoining license area. Natural gas is produced from these licenses.

Greater Sunrise

We have a 30 percent interest in the Greater Sunrise gas and condensate field located in the Timor Sea. Although the Sunrise Joint Venture and the governments of Australia and Timor-Leste are aligned with the objective to develop the Greater Sunrise Field, key challenges must be resolved before significant funding commitments can be made. These include gaining agreement between both governments and the joint venture on a development concept.

 

14


Table of Contents

Exploration

 

   

Conventional Exploration

We operate three permits located in the Browse Basin, offshore northwest Australia. We own a 60 percent interest in two of the permits, WA-315-P and WA-398-P, and a 10 percent interest in WA-314-P. Phase I of the 2009/2010 drilling campaign resulted in discoveries in WA-315-P and WA-398-P. Phase II of the drilling campaign, expected to consist of a five-to-eight well program, commenced in 2012. The first well, Boreas-1, discovered hydrocarbons and was completed, plugged and abandoned in 2012. The second well, Zephyros-1, is currently being drilled and is expected to reach targeted depth in the first quarter of 2013.

In the Bonaparte Basin, offshore northern Australia, we operate and own interests in three permits, NT/RL5, NT/P69 and NT/P61. In 2012, we farmed-down our interest from 60 percent to 37.5 percent. A three-well appraisal program is expected to commence in 2014.

 

   

Unconventional Exploration

In September 2011, we executed a farm-in agreement to acquire a 75 percent working interest in four exploration permits: EP-443, EP-450, EP-451 and EP-456, which cover approximately 11 million gross acres in the Canning Basin of Western Australia. In 2012, our 75 percent interest in the permits was approved, and Phase I of a three-well drilling program commenced in the third quarter of 2012 with the drilling of the first well, Nicolay-1. The second well, Gibb-Maitland-1, was spud in December 2012. Upon completion of the Phase I drilling program, we will have the right to assume operatorship of the exploration permits.

Indonesia

 

                  2012  
       

 

 

 
             Interest     Operator          Liquids
MBD
     Natural
Gas
MMCFD
     Total
MBOED
 
  

 

 

   

 

 

    

 

 

 

Average Daily Net Production

             

South Natuna Sea Block B

     40.0  %      ConocoPhillips         12        115        31   

South Sumatra

     45.0-54.0        ConocoPhillips         2        322        56   

 

 

Total Indonesia

          14        437        87   

 

 

We operate four production sharing contracts (PSCs) in Indonesia: the offshore South Natuna Sea Block B and three onshore PSCs, the Corridor Block and South Jambi “B”, both located in South Sumatra, and Warim in Papua. Our producing assets are primarily concentrated in two core areas: South Natuna Sea and onshore South Sumatra.

South Natuna Sea Block B

The offshore South Natuna Sea Block B PSC has 2 producing oil fields and 16 natural gas fields in various stages of development. Natural gas production is sold under international sales agreements to Malaysia and Singapore.

South Sumatra

The Corridor PSC consists of six oil fields and six natural gas fields in various stages of development. Natural gas is supplied from the Grissik and Suban gas processing plants to the Duri steamflood in central Sumatra and to markets in Singapore, Batam and West Java. The South Jambi “B” PSC includes three gas fields in various stages of development.

 

15


Table of Contents

Exploration

We own and operate an 80 percent interest in the Warim onshore exploration PSC in Papua. During 2012, we relinquished the Kuma and Arafura Sea offshore exploration PSCs.

Transportation

We are a 35 percent owner of a consortium company that has a 40 percent ownership in PT Transportasi Gas Indonesia, which owns and operates the Grissik to Duri and Grissik to Singapore natural gas pipelines.

China

 

       2012  
             Interest     Operator          Liquids
MBD
     Natural
Gas
MMCFD
     Total
MBOED
 
  

 

 

   

 

 

    

 

 

 

Average Daily Net Production

             

Peng Lai

     49.0  %      ConocoPhillips         30        3        31   

Panyu

     24.5       CNOOC         9        -         

 

 

Total China

          39        3        40   

 

 

The Peng Lai 19-3, 19-9 and 25-6 fields are located in Bohai Bay Block 11/05. Production from the Phase I development of the PL 19-3 Field began in 2002. The Phase II development includes six drilling and production platforms and an FPSO vessel used to accommodate production from all the fields.

In January 2012, we and the China National Offshore Oil Corp. (CNOOC) announced an agreement with China’s Ministry of Agriculture to resolve fishery-related issues in connection with two separate seepage incidents which occurred near the Peng Lai 19-3 Platforms B and C in 2011. Under this agreement, approximately $160 million was paid as compensation to settle private claims of potentially affected fishermen in relevant Bohai Bay communities, and public claims for alleged fishery damage. The agreement fulfills the objectives of the compensation fund we announced in September 2011. As part of this agreement, we have also designated approximately $16 million of our previously announced environmental fund to be used to improve fishery resources and for related projects.

In April 2012, we and CNOOC announced an agreement with China’s State Oceanic Administration (SOA) related to claims for possible impacts of the Peng Lai 19-3 seepage incidents on the Bohai Bay marine environment. Under this agreement, approximately $173 million will be paid to resolve claims, and approximately $18 million will be paid to support environmental initiatives focused on improving marine environment protection in Bohai Bay. Of the total $191 million, $86 million was paid in 2012.

We hold a 49 percent ownership interest in the Peng Lai fields.

The SOA required implementation of preventative measures to avoid recurrence of the incidents, in addition to the filing of an updated environmental impact assessment (EIA) and overall development plan (ODP) for approval. A revised ODP was submitted to China’s National Development and Reform Commission in November 2011, and a revised EIA was submitted to the SOA in February 2012. The EIA was approved in October 2012, and the ODP was approved in December 2012. In February 2013, we received notification from the SOA, which granted approval for a step-by-step resumption of normal production operations at the Peng Lai 19-3 Field in Bohai Bay.

The Panyu development, located in the South China Sea, is comprised of three oil fields: Panyu 4-2, Panyu 5-1 and Panyu 11-6. During 2012, a production platform was added to each of the Panyu 4-2 and Panyu 5-1 fields. Production from the new platforms began in September 2012.

 

16


Table of Contents

Exploration

 

   

Unconventional Exploration

In 2012, we entered into an agreement with Sinopec Southern Exploration Company to execute a joint study over the Qijiang Shale Gas Block, located in the Sichuan Basin. The Qijiang Shale Gas Block covers an area of 3,917 square kilometers. The study, which will be carried out over two years and includes seismic and drilling obligations, will be an important step in evaluating the potential for shale gas exploration in the area.

Malaysia

 

       2012  
         Interest                 Operator          Liquids
MBD
     Natural
Gas
MMCFD
     Total
MBOED
 
  

 

 

   

 

 

    

 

 

 

Average Daily Net Production

             

Gumusut

     33.0      Shell         1        -         

 

 

Total Malaysia

          1        -         

 

 

We own interests in four deepwater PSCs located off the eastern Malaysian state of Sabah: Block G, Block J, the Kebabangan (KBB) Cluster and SB-311. We have a 35 percent interest in Block G; 40 percent in Block J; 30 percent in KBB; and 40 percent in SB-311. First production from Gumusut, located in Block J, occurred in the fourth quarter of 2012. Production from a permanent, semi-submersible floating production and storage vessel is expected in late 2013, with estimated net annual peak production of 32 MBOED anticipated in 2014. The development of the KBB gas field commenced in 2011, with first production anticipated in late 2014. Estimated net annual peak production from KBB of 29 MBOED is expected in 2015. Development of the Siakap North-Petai oil field began in 2012, and first production is expected in late 2013. The Malikai oil field, sanctioned in the fourth quarter of 2012, is the fourth field under development. First production is anticipated in early 2017.

Exploration

In December 2012, we were formally awarded operatorship of exploration block SB-311, offshore Sabah. A two-well drilling program is planned for this block, and we expect to complete seismic reprocessing and acquisition in 2013.

Vietnam

We sold our Vietnam business in the first quarter of 2012. Net production averaged 3 MBOED in 2012.

Bangladesh

Exploration

In 2009, we were formally awarded two deepwater blocks in the Bay of Bengal, offshore Bangladesh. We received government approval of the PSC terms in June 2011 and hold 100 percent interests in Blocks 10 and 11. In 2012, we performed 2-D seismic activities and are currently evaluating the results.

Brunei

Exploration

We have a 6.25 percent working interest in Block CA-2. Two exploration wells were expensed as dry holes in 2011. Exploration activities continued during 2012, and we plan to drill a third well in 2013.

 

17


Table of Contents

Qatar

 

       2012  
         Interest     Operator          Liquids
MBD
     Natural
Gas
MMCFD
     Total
MBOED
 
  

 

 

   

 

 

    

 

 

 

Average Daily Net Production

             

Qatargas 3

     30.0      Qatargas Operating Co.         23        367        84   

 

 

Total Qatar

          23        367        84   

 

 

Qatargas 3 (QG3) is an integrated development jointly owned by Qatar Petroleum (68.5 percent), ConocoPhillips (30 percent) and Mitsui & Co., Ltd. (1.5 percent). QG3 is comprised of upstream natural gas production facilities to produce approximately 1.4 billion gross cubic feet per day of natural gas from Qatar’s North Field over a 25 year life. It also includes a 7.8-million-gross-tonnes-per-year LNG facility, from which LNG is shipped in leased LNG carriers destined for sale globally. First gas production was achieved in October 2010, and we achieved peak production during 2011.

QG3 executed the development of the onshore and offshore assets as a single integrated development with Qatargas 4 (QG4), a joint venture between Qatar Petroleum and Royal Dutch Shell plc. This included the joint development of offshore facilities situated in a common offshore block in the North Field, as well as the construction of two identical LNG process trains and associated gas treating facilities for both the QG3 and QG4 joint ventures. Production from the LNG trains and associated facilities are combined and shared.

OTHER INTERNATIONAL

The Other International segment includes exploration and producing operations in Libya and Russia, as well as exploration activities in Angola and the Caspian Sea. In 2012, we agreed to sell our Nigerian and Algerian businesses and our interest in the Republic of Kazakhstan’s North Caspian Sea Production Sharing Agreement (Kashagan). As such, results of these operations have been reclassified to discontinued operations for all periods presented. During 2012, operations in Other International contributed 6 percent of our worldwide liquids production.

Libya

 

       2012  
         Interest     Operator          Liquids
MBD
     Natural
Gas
MMCFD
     Total
MBOED
 
  

 

 

   

 

 

    

 

 

 

Average Daily Net Production

             

Waha Concession

     16.3      Waha Oil Co.         40        18        43   

 

 

Total Libya

          40        18        43   

 

 

The Waha Concession consists of multiple concessions and encompasses nearly 13 million gross acres in the Sirte Basin. Our production operations in Libya and related oil exports were temporarily suspended in 2011 during Libya’s period of civil unrest. Production restarted in late 2011 and reached 49 MBOED in November 2012.

Exploration

We participated in an exploration appraisal program within the Waha Concession in 2012 and are currently evaluating results. We drilled three appraisal wells during 2012 and completed one exploration well in early 2013.

 

18


Table of Contents

Russia

 

       2012  
         Interest     Operator          Liquids
MBD
     Natural
Gas
MMCFD
     Total
MBOED
 
  

 

 

   

 

 

    

 

 

 

Average Daily Net Production

             

Naryanmarneftegaz (NMNG)

     30.0  %      OOO NMNG         8        -         

Polar Lights

     50.0       Polar Lights Co.         5        -         

 

 

Total Russia

          13        -        13   

 

 

NMNG

We sold our interest in NMNG in the third quarter of 2012.

Polar Lights

Polar Lights Company is an entity which has developed several fields in the Timan-Pechora Basin in northern Russia.

Angola

Exploration

Effective January 1, 2012, we entered into two PSCs with Angola’s national oil company. We have a 30 percent operating interest in Blocks 36 and 37, both of which are located in Angola’s subsalt play trend. In 2012, we acquired 3-D seismic data for both ultra-deepwater blocks and are currently evaluating the data. The first wildcat well is expected to be spud in 2014.

Kazakhstan

Transportation

The Baku-Tbilisi-Ceyhan (BTC) Pipeline transports crude oil from the Caspian Region through Azerbaijan, Georgia and Turkey for tanker loadings at the port of Ceyhan. We have a 2.5 percent interest in BTC.

Exploration

We disposed of our interest in the N Block, located offshore Kazakhstan, in January 2013.

Discontinued Operations

Nigeria

 

       2012  
         Interest                 Operator          Liquids
MBD
     Natural
Gas
MMCFD
     Total
MBOED
 
  

 

 

   

 

 

    

 

 

 

Average Daily Net Production*

             

OMLs 60, 61, 62, 63

     20.0      Eni         16        149        40   

 

 

Total Nigeria

          16        149        40   

 

 

*Reclassified to discontinued operations.

We have an interest in four onshore Oil Mining Leases (OMLs). Natural gas is sourced from our proved reserves in the OMLs and provides fuel for a 480-megawatt gas-fired power plant in Kwale, Nigeria. We have a 20 percent interest in this power plant, which supplies electricity to Nigeria’s national electricity supplier. In 2012, the plant consumed 12 million net cubic feet per day of natural gas.

We have a 17 percent equity interest in Brass LNG Limited, which plans to construct an LNG facility in the Niger Delta.

 

19


Table of Contents

In December 2012, we entered into an agreement to sell our entire Nigerian business. The transaction is expected to close by mid-2013.

Algeria

 

       2012  
         Interest     Operator          Liquids
MBD
     Natural
Gas
MMCFD
     Total
MBOED
 
  

 

 

   

 

 

    

 

 

 

Average Daily Net Production*

             

Menzel Lejmat North

     65.0  %      ConocoPhillips         8        -         
       L’Organization            

Ourhoud

     3.7       Ourhoud         3        -         

 

 

Total Algeria

          11        -        11   

 

 

*Reclassified to discontinued operations.

Our activities in Algeria are centered around the following fields in Block 405a: the Menzel Lejmat North Fields (MLN), the Ourhoud Field and the EMK Field. Crude oil production from MLN and Ourhoud is transported to northern Algerian ports where it is sold. The development of the EMK Field, in which we own a 16.9 percent interest, was sanctioned in 2009. Startup is anticipated in mid-2013.

In December 2012, we entered into an agreement to sell our entire Algerian business. The transaction is expected to close by mid-2013.

Kazakhstan

In the Caspian Sea, we have an 8.4 percent interest in Kashagan. In November 2012, we announced our intention to sell our entire interest in Kashagan. The transaction is expected to close by mid-2013, subject to customary governmental approvals.

LUKOIL INVESTMENT

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.

OTHER

Marketing Activities

Our Commercial organization manages our worldwide commodity portfolio, which mainly includes natural gas, crude oil, bitumen, natural gas liquids and LNG. Marketing activities are performed through offices in the United States, Canada, Europe and Asia. In marketing our production, we attempt to minimize flow disruptions, maximize realized prices and manage credit-risk exposure. Commodity sales are generally made at prevailing market prices at the time of sale. We also purchase third-party volumes to better position the Company to fully utilize transportation and storage capacity and satisfy customer demand.

Natural Gas

Our natural gas production, along with third-party purchased gas, is marketed in the United States, Canada, Europe and Asia. Our natural gas is sold to a diverse client portfolio which includes local distribution companies; gas and power utilities; large industrials; independent, integrated or state-owned oil and gas companies; as well as marketing companies. To reduce our market exposure and credit risk, we also transport natural gas via firm and interruptible transportation agreements to major market hubs.

 

20


Table of Contents

Crude Oil, Bitumen and Natural Gas Liquids

Our crude oil, bitumen and natural gas liquids revenues are derived from production in the United States, Canada, Australia, Asia, Africa, China and Europe. These commodities are primarily sold under contracts with prices based on market indices, adjusted for location, quality and transportation.

Spill Containment

Marine Well Containment Company

We are a founding member of the Marine Well Containment Company (MWCC), a non-profit organization formed in 2010 which provides well containment equipment and technology in the deepwater U.S. Gulf of Mexico. In 2011, MWCC launched an interim containment system designed to improve containment response capabilities in the event of an underwater well control incident. In 2012, MWCC and the U.S. Bureau of Safety and Environmental Enforcement announced the successful demonstration of the industry’s ability to respond to a deepwater well control incident in the U.S. Gulf of Mexico. MWCC is advancing this capability and is currently developing an expanded containment system with significantly increased capacity. The expanded containment system is expected to be available in 2013.

Subsea Well Response Project

In 2011, we, along with eight leading oil and gas companies, launched the Subsea Well Response Project (SWRP), an initiative designed to enhance the industry’s capability to respond to international subsea well control incidents. In 2012, SWRP, a non-profit organization based in Stavanger, Norway, partnered with Oil Spill Response Limited, a non-profit organization in the United Kingdom, in order to develop integrated intervention systems which are more widely available to the industry. This complements the work being undertaken in the United States by MWCC and also in the United Kingdom by the Oil Spill Prevention and Response Advisory Group (OSPRAG), enhancing our global well response capabilities. We are also a participant in OSPRAG.

LNG Technology

Our Optimized Cascade® LNG liquefaction technology business continues to grow with the demand for new LNG plants. The technology has been applied in 10 LNG trains around the world, with 10 more under construction.

RESERVES

We have not filed any information with any other federal authority or agency with respect to our estimated total proved reserves at December 31, 2012. No difference exists between our estimated total proved reserves for year-end 2011 and year-end 2010, which are shown in this filing, and estimates of these reserves shown in a filing with another federal agency in 2012.

DELIVERY COMMITMENTS

We sell crude oil and natural gas from our producing operations under a variety of contractual arrangements, some of which specify the delivery of a fixed and determinable quantity. Our Commercial organization also enters into natural gas sales contracts where the source of the natural gas used to fulfill the contract can be the spot market or a combination of our reserves and the spot market. Worldwide, we are contractually committed to deliver approximately 4 trillion cubic feet of natural gas, including approximately 600 billion cubic feet related to the noncontrolling interests of consolidated subsidiaries, and 80 million barrels of crude oil in the future. These contracts have various expiration dates through the year 2028. We expect to fulfill the majority of these delivery commitments with proved developed reserves. In addition, we anticipate using proved undeveloped reserves and spot market purchases to fulfill these remaining commitments. See the disclosure on “Proved Undeveloped Reserves” in the “Oil and Gas Operations” section following the Notes to Consolidated Financial Statements, for information on the development of proved undeveloped reserves.

 

21


Table of Contents

COMPETITION

We compete with private, public and state-owned companies in all facets of the E&P business. Some of our competitors are larger and have greater resources. Each of our segments is highly competitive, with no single competitor, or small group of competitors, dominating.

We compete with numerous other companies in the industry, including state-owned companies, to locate and obtain new sources of supply and to produce oil, bitumen, natural gas liquids and natural gas in an efficient, cost-effective manner. Based on publicly available year-end 2011 reserves statistics, we had the seventh-largest total of worldwide proved reserves of nongovernment-controlled companies. We deliver our production into the worldwide commodity markets. Principal methods of competing include geological, geophysical and engineering research and technology; experience and expertise; economic analysis in connection with portfolio management; and efficiently operating oil and gas producing properties.

GENERAL

At the end of 2012, we held a total of 784 active patents in 54 countries worldwide, including 319 active U.S. patents. During 2012, we received 15 patents in the United States and 47 foreign patents. Our products and processes generated licensing revenues of $124 million in 2012. The overall profitability of any business segment is not dependent on any single patent, trademark, license, franchise or concession.

Company-sponsored research and development activities charged against earnings were $221 million, $193 million and $172 million in 2012, 2011 and 2010, respectively.

Our Health, Safety and Environment (HSE) organization provides tools and support to our business units and staff groups to help them ensure consistent health, safety and environmental excellence. In support of the goal of zero incidents, we have implemented an HSE Excellence process, which enables business units to measure their performance and compliance with our HSE Management System requirements, identify gaps, and develop improvement plans. Assessments are conducted annually to capture progress and set new targets. We are also committed to continuously improving process safety and preventing releases of hazardous materials.

The environmental information contained in Management’s Discussion and Analysis of Financial Condition and Results of Operations on pages 58 through 62 under the captions “Environmental” and “Climate Change” is incorporated herein by reference. It includes information on expensed and capitalized environmental costs for 2012 and those expected for 2013 and 2014.

Website Access to SEC Reports

Our Internet website address is www.conocophillips.com. Information contained on our Internet website is not part of this report on Form 10-K.

Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are available on our website, free of charge, as soon as reasonably practicable after such reports are filed with, or furnished to, the U.S. Securities and Exchange Commission (SEC). Alternatively, you may access these reports at the SEC’s website at www.sec.gov.

 

22


Table of Contents

Item 1A. RISK FACTORS

You should carefully consider the following risk factors in addition to the other information included in this Annual Report on Form 10-K. Each of these risk factors could adversely affect our business, operating results and financial condition, as well as adversely affect the value of an investment in our common stock.

Our operating results, our future rate of growth and the carrying value of our assets are exposed to the effects of changing commodity prices.

Our revenues, operating results and future rate of growth are highly dependent on the prices we receive for our crude oil, bitumen, natural gas, natural gas liquids and LNG. The factors influencing these prices are beyond our control. Lower crude oil, bitumen, natural gas, natural gas liquids and LNG prices may have a material adverse effect on our revenues, operating income and cash flows and may reduce the amount of these commodities we can produce economically.

Unless we successfully add to our existing proved reserves, our future crude oil, bitumen, natural gas and natural gas liquids production will decline, resulting in an adverse impact to our business.

The rate of production from upstream fields generally declines as reserves are depleted. Except to the extent that we conduct successful exploration and development activities, or, through engineering studies, identify additional or secondary recovery reserves, our proved reserves will decline materially as we produce crude oil, bitumen, natural gas and natural gas liquids. Accordingly, to the extent we are unsuccessful in replacing the crude oil, bitumen, natural gas and natural gas liquids we produce with good prospects for future production, our business will experience reduced cash flows and results of operations.

Any material change in the factors and assumptions underlying our estimates of crude oil, bitumen, natural gas and natural gas liquids reserves could impair the quantity and value of those reserves.

Our proved reserve information included in this annual report has been derived from engineering estimates prepared or reviewed by our personnel. Any significant future price changes could have a material effect on the quantity and present value of our proved reserves. Future reserve revisions could also result from changes in, among other things, governmental regulation. Reserve estimation is a process that involves estimating volumes to be recovered from underground accumulations of crude oil, bitumen, natural gas and natural gas liquids that cannot be directly measured. As a result, different petroleum engineers, each using industry-accepted geologic and engineering practices and scientific methods, may produce different estimates of reserves and future net cash flows based on the same available data. Any material changes in the factors and assumptions underlying our estimates of these items could result in a material negative impact to the volume of reserves reported.

We expect to continue to incur substantial capital expenditures and operating costs as a result of our compliance with existing and future environmental laws and regulations. Likewise, future environmental laws and regulations may impact or limit our current business plans and reduce demand for our products.

Our businesses are subject to numerous laws and regulations relating to the protection of the environment. These laws and regulations continue to increase in both number and complexity and affect our operations with respect to, among other things:

 

   

The discharge of pollutants into the environment.

   

Emissions into the atmosphere (such as nitrogen oxides, sulfur dioxide and mercury emissions, and greenhouse gas emissions as they are, or may become, regulated).

   

The handling, use, storage, transportation, disposal and cleanup of hazardous materials and hazardous and nonhazardous wastes.

 

23


Table of Contents
   

The dismantlement, abandonment and restoration of our properties and facilities at the end of their useful lives.

   

Exploration and production activities in certain areas, such as offshore environments, arctic fields, oil sands reservoirs and shale gas plays.

We have incurred and will continue to incur substantial capital, operating and maintenance, and remediation expenditures as a result of these laws and regulations. To the extent these expenditures, as with all costs, are not ultimately reflected in the prices of our products and services, our business, financial condition, results of operations and cash flows in future periods could be materially adversely affected.

Although our business operations are designed and operated to accommodate expected climatic conditions, to the extent there are significant changes in the Earth’s climate, such as more severe or frequent weather conditions in the markets we serve or the areas where our assets reside, we could incur increased expenses, our operations could be materially impacted, and demand for our products could fall.

In addition, in response to the Deepwater Horizon incident, the United States, as well as other countries where we do business, may make changes to their laws or regulations governing offshore operations that could have a material adverse effect on our business.

Domestic and worldwide political and economic developments could damage our operations and materially reduce our profitability and cash flows.

Actions of the U.S., state, local and foreign governments, through tax and other legislation, executive order and commercial restrictions, could reduce our operating profitability both in the United States and abroad. In certain locations, governments have imposed or proposed restrictions on our operations; special taxes or tax assessments; and payment transparency regulations that could require us to disclose competitively sensitive information or might cause us to violate non-disclosure laws of other countries. The U.S. government can also prevent or restrict us from doing business in foreign countries. These restrictions and those of foreign governments have in the past limited our ability to operate in, or gain access to, opportunities in various countries. Actions by host governments have affected operations significantly in the past, such as the expropriation of our oil assets by the Venezuelan government, and may continue to do so in the future.

Local political and economic factors in international markets could have a material adverse effect on us. Approximately 56 percent of our hydrocarbon production from continuing operations was derived from production outside the United States in 2012, and 57 percent of our proved reserves, as of December 31, 2012, was located outside the United States. We are subject to risks associated with operations in international markets, including changes in foreign governmental policies relating to crude oil, natural gas liquids, bitumen, natural gas or LNG pricing and taxation, other political, economic or diplomatic developments, changing political conditions and international monetary fluctuations.

Changes in governmental regulations may impose price controls and limitations on production of crude oil, natural gas, bitumen, and natural gas liquids.

Our operations are subject to extensive governmental regulations. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of crude oil, natural gas, bitumen and natural gas liquids wells below actual production capacity. Because legal requirements are frequently changed and subject to interpretation, we cannot predict the effect of these requirements.

 

24


Table of Contents

Our investments in joint ventures decrease our ability to manage risk.

We conduct many of our operations through joint ventures in which we may share control with our joint venture participants. There is a risk our joint venture participants may at any time have economic, business or legal interests or goals that are inconsistent with those of the joint venture or us, or our joint venture participants may be unable to meet their economic or other obligations and we may be required to fulfill those obligations alone. Failure by us, or an entity in which we have a joint venture interest, to adequately manage the risks associated with any acquisitions or joint ventures could have a material adverse effect on the financial condition or results of operations of our joint ventures and, in turn, our business and operations.

We do not insure against all potential losses; therefore, we could be harmed by unexpected liabilities and increased costs.

We maintain insurance against many, but not all, potential losses or liabilities arising from operating risks. As such, our insurance coverage may not be sufficient to fully cover us against potential losses arising from such risks. Uninsured losses and liabilities arising from operating risks could reduce the funds available to us for capital, exploration and investment spending and could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Our operations present hazards and risks that require significant and continuous oversight.

The scope and nature of our operations present a variety of significant hazards and risks, including operational hazards and risks such as explosions, fires, pipeline interruptions, pipeline ruptures, crude oil spills, severe weather, geological events, labor disputes, or cyber attacks. Our operations are also subject to the additional hazards of pollution, releases of toxic gas and other environmental hazards and risks. All such hazards could result in loss of human life, significant property and equipment damage, environmental pollution, impairment of operations, substantial losses to us and damage to our reputation.

Our technologies, systems and networks may be subject to cybersecurity breaches. Although we have experienced occasional, actual or attempted breaches of our cybersecurity, none of these breaches has had a material effect on our business, operations or reputation. If our systems for protecting against cybersecurity risks prove to be insufficient, we could be adversely affected by having our business systems compromised, our proprietary information altered, lost or stolen, or our business operations disrupted.

 

25


Table of Contents

Item 1B. UNRESOLVED STAFF COMMENTS

None.

Item 3.    LEGAL PROCEEDINGS

The following is a description of reportable legal proceedings, including those involving governmental authorities under federal, state and local laws regulating the discharge of materials into the environment for this reporting period. The following proceedings include those matters that arose during the fourth quarter of 2012, as well as matters previously reported in our 2011 Form 10-K and our first-, second- and third-quarter 2012 Form 10-Qs that were not resolved prior to the fourth quarter of 2012. Material developments to the previously reported matters have been included in the descriptions below. While it is not possible to accurately predict the final outcome of these pending proceedings, if any one or more of such proceedings was decided adversely to ConocoPhillips, we expect there would be no material effect on our consolidated financial position. Nevertheless, such proceedings are reported pursuant to SEC regulations.

New Matters

The New Mexico Environment Department has issued four Notices of Violation (NOVs) to ConocoPhillips alleging a total of twenty individual violations for failure to comply with air emission recordkeeping, reporting and testing requirements at various natural gas compression operations in northwestern New Mexico. These violations are alleged to have occurred between 2006 and 2012. The agency is seeking a penalty of over $100,000. We have submitted responses to all four of the NOVs and will work with the agency to resolve these matters.

Matters Previously Reported – ConocoPhillips

The North Dakota Department of Health has requested all the operators in the Bakken Pool area, including ConocoPhillips, enter into an Administrative Consent Agreement to resolve alleged historic violations of the state’s air emission regulations. The state is proposing a penalty of $2,000 per well drilled in the Bakken Pool which would result in total penalty to the company of over $100,000. ConocoPhillips is working with the state to resolve this matter.

Matters Previously Reported – Phillips 66

On April 30, 2012, the separation of our Downstream business was completed, creating two independent energy companies: ConocoPhillips and Phillips 66. In connection with the separation, we entered into an Indemnification and Release Agreement, which provides for cross-indemnities between Phillips 66 and us and established procedures for handling claims subject to indemnification and related matters, such as legal proceedings. We have included matters where we remain a party to a proceeding relating to Phillips 66, in accordance with SEC regulations. We do not expect any of those matters to result in a net claim against us.

On September 19, 2012, the Bay Area Air Quality Management District (District) issued a $213,500 demand to settle fourteen NOVs issued in 2009 and 2010 with respect to alleged violations of regulatory and/or permit requirements at the Phillips 66 Rodeo Refinery. Phillips 66 is working with the District to resolve this matter.

On October 15, 2012, the District issued a $313,000 demand to settle thirteen NOVs issued in 2010 and 2011 with respect to alleged violations of regulatory and/or permit requirements at the Phillips 66 Rodeo Refinery. Phillips 66 is working with the District to resolve this matter.

On March 7, 2012, the District issued a $302,500 demand to settle five NOVs issued between 2008 and 2010 to the Phillips 66 Rodeo Refinery. The NOVs allege non-compliance with the District rules and/or facility permit conditions. Phillips 66 is working with the District to resolve this matter.

In May 2012, the Illinois Attorney General’s office filed and served a Complaint against ConocoPhillips with respect to operations at the Phillips 66 Wood River Refinery alleging violations of the Illinois groundwater standards and a third-party’s hazardous waste permit. The Complaint seeks as relief remediation of area

 

26


Table of Contents

groundwater, compliance with the hazardous waste permit, enhanced pipeline and tank integrity measures, additional spill reporting, and yet-to-be specified amounts for fines and penalties. Phillips 66 is working with the Illinois Environmental Protection Agency and Attorney General’s office to resolve these allegations.

In December 2011, ConocoPhillips was notified by the U.S. Environmental Protection Agency (EPA) of alleged violations related to the use of Renewable Identification Numbers (RINs). Phillips 66 was one of several companies who entered Administrative Settlement Agreements (ASAs) with the EPA to settle allegations it had used invalid RINs for its 2010 and 2011 fuel program compliance. Under this Agreement, Phillips 66 will pay a maximum of $350,000 in penalties for the use of invalid RINs. Payments are made upon demand from the EPA. To date, $250,000 has been paid and it is anticipated the EPA will demand the final $100,000 in 2013.

On November 28, 2011, the Phillips 66 Borger Refinery received a Notice of Enforcement from the Texas Commission on Environmental Quality (TCEQ) for alleged emissions events that occurred during inclement weather in January and February 2011. The TCEQ is seeking a penalty of $120,000. Phillips 66 is working with TCEQ to resolve this matter.

In October 2011, ConocoPhillips was notified by the Attorney General of the State of California it was conducting an investigation into possible violations of the regulations relating to the operation of underground storage tanks at gas stations in California. On January 3, 2013, we were served with a lawsuit filed by the California Attorney General that alleges such violations. Philips 66 is contesting these allegations.

In October 2007, we received a Complaint from the EPA alleging violations of the Clean Water Act related to a 2006 oil spill at the Phillips 66 Bayway Refinery and proposing a penalty of $156,000. Phillips 66 is working with the EPA and the U.S. Coast Guard to resolve this matter.

On May 19, 2010, the Phillips 66 Lake Charles Louisiana Refinery received a Consolidated Compliance Order and Notice of Potential Penalty from the Louisiana Department of Environmental Quality (LDEQ) alleging various violations of applicable air emission regulations, as well as certain provisions of the consent decree in Civil Action No. H-01-4430. Phillips 66 is working with the LDEQ to resolve this matter.

Item 4.    MINE SAFETY DISCLOSURES

Not applicable.

 

27


Table of Contents

EXECUTIVE OFFICERS OF THE REGISTRANT

 

Name

  

Position Held

  

Age*

Ellen R. DeSanctis    Vice President, Investor Relations and Communications    56
Sheila Feldman    Vice President, Human Resources    58
Matt J. Fox    Executive Vice President, Exploration and Production    52
Alan J. Hirshberg    Executive Vice President, Technology and Projects    51
Janet L. Kelly    Senior Vice President, Legal, General Counsel and Corporate Secretary    55
Ryan M. Lance    Chairman of the Board of Directors and Chief Executive Officer    50
Glenda M. Schwarz    Vice President and Controller    47
Jeff W. Sheets    Executive Vice President, Finance and Chief Financial Officer    55
Don E. Wallette, Jr.    Executive Vice President, Commercial, Business Development and Corporate Planning    54

 

*On February 15, 2013.

There are no family relationships among any of the officers named above. Each officer of the Company is elected by the Board of Directors at its first meeting after the Annual Meeting of Stockholders and thereafter as appropriate. Each officer of the Company holds office from the date of election until the first meeting of the directors held after the next Annual Meeting of Stockholders or until a successor is elected. The date of the next annual meeting is May 14, 2013. Set forth below is information about the executive officers.

Ellen R. DeSanctis was appointed Vice President, Investor Relations and Communications in May 2012. She was previously employed by Petrohawk Energy Corp. and served as Senior Vice President, Corporate Communications since 2010. Prior to that she was employed by Rosetta Resources Inc. and served as Executive Vice President of Strategy and Development from 2008 to 2010.

Sheila Feldman was appointed Vice President, Human Resources in May 2012. She was previously employed by Arch Coal, Inc. and served as Vice President, Human Resources since 2003.

Matt J. Fox was appointed Executive Vice President, Exploration and Production in May 2012. Prior to that, he was employed by Nexen, Inc. and served as Executive Vice President, International since 2010. He was previously employed by ConocoPhillips and served as President, ConocoPhillips Canada from 2009 to 2010 and Senior Vice President, Oil Sands and Canadian Arctic from 2007 to 2009.

Alan J. Hirshberg was appointed Executive Vice President, Technology and Projects in May 2012. Prior to that, he served as Senior Vice President, Planning and Strategy since 2010. He was previously employed by Exxon Mobil Corporation and served as Vice President, Worldwide Deepwater and Africa Projects since 2009; Vice President, Worldwide Deepwater Projects from 2008 to 2009; and Vice President, Established Areas Projects from 2006 to 2008.

Janet L. Kelly was appointed Senior Vice President, Legal, General Counsel and Corporate Secretary in 2007.

Ryan M. Lance was appointed Chairman of the Board of Directors and Chief Executive Officer in May 2012, having previously served as Senior Vice President, Exploration and Production—International since May 2009. Prior to that, he served as President, Exploration and Production—Asia, Africa, Middle East and Russia/Caspian since April 2009; and President, Exploration and Production— Europe, Asia, Africa and the Middle East from 2007 to 2009.

Glenda M. Schwarz was appointed Vice President and Controller in 2009. She previously served as General Auditor and Chief Ethics Officer from 2008 to 2009.

 

28


Table of Contents

Jeff W. Sheets was appointed Executive Vice President, Finance and Chief Financial Officer in May 2012. Prior to that, he served as Senior Vice President, Finance and Chief Financial Officer since 2010 and Senior Vice President, Planning and Strategy since 2008.

Don E. Wallette, Jr. was appointed Executive Vice President, Commercial, Business Development and Corporate Planning in May 2012. Prior to that, he served as President, Asia Pacific since 2010 and President, Russia/Caspian from 2006 to 2010.

 

29


Table of Contents

PART II

 

Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Quarterly Common Stock Prices and Cash Dividends Per Share

ConocoPhillips’ common stock is traded on the New York Stock Exchange, under the symbol “COP.”

 

     Stock Price         
     High        Low      Dividends  
  

 

 

    

 

 

 

2012

          

First

   $             78.29          68.00        0.66   

Second

     77.31          50.62        0.66   

Third

     58.90          52.84        0.66   

Fourth

     59.65          53.95        0.66   

 

 

2011

          

First

   $ 81.80          66.50        0.66   

Second

     81.75                      70.08        0.66   

Third

     80.13          60.40        0.66   

Fourth

     73.90          58.65        0.66   

 

 

Closing Stock Price at December 31, 2012

           $             57.99   

Closing Stock Price at January 31, 2013

           $ 58.00   

Number of Stockholders of Record at January 31, 2013*

             56,511   

 

 

*In determining the number of stockholders, we consider clearing agencies and security position listings as one stockholder for each agency listing.

Issuer Purchases of Equity Securities

 

                          Millions of Dollars  
Period    Total Number of
Shares Purchased*
     Average
Price Paid
Per Share
     Shares Purchased
as Part of Publicly
Announced Plans
or Programs**
    

Approximate Dollar
Value of Shares

that May Yet Be
Purchased Under the
Plans or Programs

 

 

 

October 1-31, 2012

     5,165       $         57.39        -       $ 4,901   

November 1-30, 2012

     -         -        -         4,901   

December 1-31, 2012

     7,359         57.67        -         4,901   

 

 

Total

     12,524       $ 57.56        -      

 

 
  * Includes the repurchase of common stock from company employees in connection with the Company’s broad-based employee incentive plans.
** On December 2, 2011, we announced a share repurchase program to repurchase up to $10 billion of common stock over the next two years. Acquisitions for the share repurchase program are made at management’s discretion, at prevailing prices, subject to market conditions and other factors. Repurchases may be increased, decreased or discontinued at any time without prior notice. Shares of stock repurchased under the plan are held as treasury shares.

 

30


Table of Contents

Item 6.    SELECTED FINANCIAL DATA

 

     Millions of Dollars Except Per Share Amounts  
     2012      2011      2010      2009      2008  
  

 

 

 

Sales and other operating revenues

   $     57,967        64,196        56,215        47,879        87,468   

Income (loss) from continuing operations

     7,481        7,188        10,305        3,737        (19,483)   

Per common share

              

Basic

     5.95        5.18        6.93        2.46        (12.83)   

Diluted

     5.91        5.14        6.88        2.44        (12.83)   

Net income (loss)

     8,498        12,502        11,417        4,492        (16,279)   

Net income (loss) attributable to ConocoPhillips

     8,428        12,436        11,358        4,414        (16,349)   

Per common share

              

Basic

     6.77        9.04        7.68        2.96        (10.73)   

Diluted

     6.72        8.97        7.62        2.94        (10.73)   

Total assets

     117,144        153,230        156,314        152,138        142,865   

Long-term debt

     20,770        21,610        22,656        26,925        27,085   

Joint venture acquisition obligation—long-term

     2,810        3,582        4,314        5,009        5,669   

Cash dividends declared per common share

     2.64        2.64        2.15        1.91        1.88   

 

 

Many factors can impact the comparability of this information, such as:

 

   

Net income (loss) and Net income (loss) attributable to ConocoPhillips for all periods presented includes income from discontinued operations as a result of the separation of the Downstream business and our intention to sell our interest in Kashagan and our Nigerian and Algerian businesses. Income from discontinued operations for these operations was $1,017 million in 2012, $5,314 million in 2011, $1,112 million in 2010, $755 million in 2009 and $3,204 million in 2008. For additional information, see Note 2—Discontinued Operations, in the Notes to Consolidated Financial Statements.

 

   

The financial data for 2010 includes the impact of $5,563 million before-tax ($4,463 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.

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.

 

31


Table of Contents
Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

February 19, 2013

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 included elsewhere in this report. 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 67.

Due to the separation of the downstream businesses and our intention to sell our interest in the North Caspian Sea Production Sharing Agreement (Kashagan) and our Nigerian and Algerian businesses in 2012, which are reported as discontinued operations, income (loss) from continuing operations is more representative of ConocoPhillips as an independent exploration and production company. The terms “earnings” and “loss” as used in Management’s Discussion and Analysis refer to income (loss) from continuing operations.

BUSINESS ENVIRONMENT AND EXECUTIVE OVERVIEW

ConocoPhillips is the world’s largest independent exploration and production (E&P) company, based on proved reserves and production of liquids and natural gas. Headquartered in Houston, Texas, we have operations and activities in 30 countries. At December 31, 2012, we had approximately 16,900 employees worldwide and total assets of $117 billion. Our stock is listed on the New York Stock Exchange under the symbol “COP.”

Discontinued Operations

On April 30, 2012, we completed the separation of our downstream businesses into an independent, publicly traded company, Phillips 66. Our refining, marketing and transportation businesses, most of our Midstream segment, our Chemicals segment, as well as our power generation and certain technology operations included in our Emerging Businesses segment (collectively, our “Downstream business”), were transferred to Phillips 66. As a part of our strategic asset disposition program, in the fourth quarter of 2012, we agreed to sell our interest in Kashagan and our Nigerian and Algerian businesses. Results of operations related to Phillips 66, Kashagan, Nigeria and Algeria have been classified as discontinued operations in all periods presented in this Annual Report on Form 10-K. For additional information, see Note 2—Discontinued Operations, in the Notes to Consolidated Financial Statements.

Overview

As an independent E&P company, we are solely focused on our core business of exploring for, developing and producing crude oil and natural gas globally. Our portfolio primarily includes legacy assets in North America, Europe, Asia and Australia; growing North American shale and oil sands businesses; several major international developments; and a global exploration program. Our value proposition to our shareholders is to deliver

 

32


Table of Contents

production and cash margin growth, competitive returns on capital, and a compelling dividend, while keeping our fundamental commitment to safety, operating excellence and environmental stewardship. We expect to achieve our value proposition through portfolio optimization, investments in high-margin developments, applying technical capability and maintaining financial flexibility.

In our first year as an independent E&P company, we achieved production of 1.58 million barrels of oil equivalent per day (BOED), including production from discontinued operations of .05 million BOED; advanced our growth and drilling programs; paid dividends on our common stock of $3.3 billion for the full year; and repurchased 80 million shares of our common stock at a total cost of $5.1 billion. In 2012, we also announced plans to raise $8–$10 billion of proceeds from asset dispositions by the end of 2013. As part of this program, we have generated $2.1 billion in proceeds from asset dispositions through December 31, 2012. We have also announced asset sales, expected to close by mid-2013, which will generate approximately $9.6 billion in additional proceeds. In the near-term, we will fund a portion of our capital program with these proceeds. Over the next five years, our investment in high-margin developments should position us to deliver 3–5 percent annual production volume and margin growth, enabling us to fund our capital program organically.

Our total capital program is expected to be $15.8 billion in 2013, compared to $15.7 billion in 2012. Excluding Kashagan, Nigeria and Algeria, which are reported as discontinued operations, our 2013 capital program is expected to be $15.5 billion, compared to $14.9 billion in 2012. Our investments will be directed predominantly toward high-quality developments already underway in the United States, Canada, the United Kingdom and Norwegian North Sea, Malaysia and Australia, as well as exploration opportunities which will build our inventory for the future.

Key Operating and Financial Highlights

Significant highlights during 2012 included the following:

 

  Completed the separation of our Downstream business on April 30, 2012, creating two independent energy companies, ConocoPhillips and Phillips 66.
  Achieved annual production of 1.58 million BOED, including production from discontinued operations of .05 million BOED, and generated earnings of $7.5 billion.
  Achieved annual organic reserve replacement of 156 percent and year-end proved reserves of 8.6 billion barrels of oil equivalent.
  Repurchased 80 million ConocoPhillips shares, representing 6 percent of our outstanding shares.
  Paid quarterly dividends of 66 cents per share, consistent with pre-separation dividends.
  Exceeded 100,000 BOED production milestone in the Eagle Ford; continued Bakken activity ramp up.
  Exceeded 100,000 BOED average production in the Canadian Oil sands in the fourth quarter of 2012.
  Progressed FCCL expansion with sanction of Christina Lake Phase F and Narrows Lake Phase A.
  Achieved first oil from the Gumusut Field in Malaysia.
  Increased deepwater Gulf of Mexico position to 1.7 million acres; continued appraisal drilling. Expect to increase acreage position to 2.0 million acres in the first quarter of 2013.
  Increased Niobrara acreage position to approximately 130,000 acres; continued drilling and testing of unconventional shale plays.
  Progressed the Australia Pacific LNG Project with sanction of the second train in early July 2012; secured $8.5 billion project finance facility.
  Advanced the disposition program with the announcement of agreements to sell Kashagan, Algeria and Nigeria, generating approximately $8.5 billion in expected proceeds.

Business Environment

In recent years, the business environment for the energy industry has experienced many challenges which have influenced our operations and profitability, largely due to factors beyond our control, such as the recent financial crisis, geopolitical events or fears thereof, environmental laws, tax regulations, governmental policies, and weather-related disruptions. These factors generally influence the supply and demand of crude oil and natural gas. The most significant factor impacting our profitability and related reinvestment of our

 

33


Table of Contents

operating cash flows into our business is commodity prices. The prices for commodity products are supply- and demand-based and can be very volatile; therefore, to navigate through the volatility, our strategy is to maintain a core portfolio of low-risk, high-return development programs associated with legacy assets, coupled with a portfolio of development opportunities which offer high-margin growth, such as unconventional plays, deepwater and arctic drilling, and liquefied natural gas (LNG).

Operating and Financial Priorities

Important factors we must continue to manage well in order to be successful include:

 

   

Operating 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. We strive to conduct our business with respect and care for both the local and global environment and systematically manage risk to drive sustainable business growth.

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:

 

  o Successful exploration, exploitation and development of new and existing fields.
  o Application of new technologies and processes to improve recovery from existing fields.
  o Acquisition of existing fields.

Through a combination of the methods listed above, we have been successful in the past in maintaining or adding to our production and proved reserve base, and we anticipate being able to do so in the future. In the five years ended December 31, 2012, our organic reserve replacement was 108 percent, excluding LUKOIL and the impact of sales and purchases.

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.

 

   

Disciplined investment approach.   We participate in a capital-intensive industry. As a result, we must often invest significant capital dollars to explore for new oil and gas fields, develop newly discovered fields, maintain existing fields, or construct pipelines and LNG facilities. We use a disciplined approach to select the appropriate projects which will provide the most attractive investment opportunities, with a continued focus on higher-margin liquids plays and limited investment in North American conventional natural gas. As investments bring more liquids production online, we expect a corresponding shift in our production mix. 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.

 

34


Table of Contents

Our $15.8 billion capital program includes contributions to FCCL of $0.8 billion. Our capital expenditures and investment budget for 2013, excluding FCCL, is $15.0 billion, compared to actual capital expenditures and investments in 2012 of $15.0 billion. Excluding discontinued operations for Kashagan, Nigeria and Algeria, we estimate 2013 capital expenditures and investments will be $14.7 billion, compared to $14.2 billion in 2012. Approximately 10 percent of the 2013 capital budget is expected to be directed toward maintenance of our legacy base portfolio; 40 percent is expected to be allocated to exploitation programs in our legacy asset base, which is intended to offset natural decline from these assets; 35 percent is expected to be spent on sanctioned major developments, such as Eldfisk II, Jasmine and APLNG; and 15 percent is planned for our worldwide exploration and appraisal program, which will target both conventional and unconventional plays.

 

   

Portfolio optimization.   We continue to optimize our asset portfolio by focusing on assets which offer the highest returns and growth potential, while selling nonstrategic holdings. In 2012, we announced plans to sell an additional $8–$10 billion of noncore assets through the end of 2013. During 2012, we sold our Vietnam business, the Statfjord and Alba fields in the North Sea, our investment in Naryanmarneftegaz (NMNG) in Russia, and we further diluted our interest in APLNG from 42.5 percent to 37.5 percent. We recently announced our intention to sell our 8.4 percent interest in Kashagan, our Algerian and Nigerian businesses, and certain properties in the Cedar Creek Anticline, located in North Dakota and Montana. Cedar Creek Anticline is expected to close in the first quarter of 2013, and the remaining transactions are expected to close by mid-2013, subject to customary governmental approvals. Additionally, in January 2013, we sold our 24.5 percent interest in the N Block, located offshore Kazakhstan.

In 2011, we sold certain noncore assets in the Lower 48 and western Canada, and we completed the divestiture of our entire interest in LUKOIL.

 

   

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 industry, cost control is a component of our variable compensation programs. Operating and overhead costs increased 8 percent in 2012 compared with 2011, primarily as a result of major turnaround expenses in Australia, higher operating expenses in the Lower 48 associated with improved production as a result of increased drilling programs, the settlement of environmental claims and other costs related to Bohai Bay, China, and costs associated with the separation of Phillips 66.

 

   

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.

 

35


Table of Contents

Other significant factors that can affect our profitability include:

 

 

Commodity prices.   Our earnings generally correlate with industry price levels for crude oil and natural gas. These are commodity products, the prices of which are subject to factors external to our company and over which we have no control. The following table depicts the average benchmark prices for West Texas Intermediate (WTI) crude oil, Dated Brent crude oil and U.S. Henry Hub natural gas:

 

     Dollars Per Unit  
     2012      2011      2010  
  

 

 

 

Market Indicators

        

WTI (per barrel)

   $         94.16        95.05        79.39  

Dated Brent (per barrel)

     111.58                111.27                79.47  

U.S. Henry Hub first of month (per million British thermal units)

     2.79        4.04        4.39  

 

 

Global oil prices remained relatively flat in 2012, compared to 2011. In 2012, global oil demand grew at approximately the same pace as in 2011, at about 0.9 percent or 800 thousand barrels per day, as the pace of economic expansion moderated due to intentional slowing in China, coupled with fiscal uncertainties in the European Union and the United States. Global oil production rose due to an increase in the Organization of Petroleum Exporting Countries (OPEC) and North American production. WTI continued to trade at a discount to Brent throughout 2011 and 2012, mainly due to high inventory levels and excess crude supply in the U.S. Midcontinent market, largely as a result of limited pipeline capacity.

Henry Hub natural gas prices decreased 31 percent in 2012, compared with 2011. U.S. natural gas prices were depressed in 2012, mainly due to high inventory levels, a warmer-than-normal winter and sustained production from shale plays. We expect these factors will continue to moderate natural gas prices in the near- to mid-term. The expansion in shale production has also helped boost supplies of natural gas liquids, resulting in downward pressure on natural gas liquids prices in the United States. As a result, our domestic realized natural gas liquids price declined 30 percent in 2012 compared with 2011. Our realized bitumen price declined 14 percent in 2012. We expect bitumen prices to remain weak in the near-term, until additional heavy refining capacity comes on-line.

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 and natural gas liquids prices; production curtailments on properties that produce primarily natural gas; continued delay of plans to develop Alaska North Slope natural gas fields; and underutilization of LNG regasification facilities. 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 properties, plants and equipment and investments become impaired when, for example, our reserve estimates are revised downward, commodity prices decline significantly for long periods of time, or a decision to dispose of an asset leads to a write-down to its fair 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 2012 totaled $1.2 billion and primarily resulted from the impairments of the Mackenzie Gas Project and associated leaseholds in Canada; Cedar Creek Anticline in the Lower 48; various properties in Europe, which have ceased production or are nearing the end of their useful lives; and the N Block in the Caspian Sea. Before-tax impairments in 2011 totaled $0.8 billion and primarily resulted from the impairments of our equity

 

36


Table of Contents
 

investment in NMNG and certain Canadian natural gas properties. For additional information, see Note 9—Impairments, in the Notes to Consolidated Financial Statements.

 

   

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

 

   

Fiscal and regulatory environment.   Our operations can be affected by changing economic, regulatory and political environments in the various countries in which we operate, including the United States. Civil unrest or strained relationships with governments may impact our operations or investments. These changing environments have generally negatively impacted our results of operations, and further changes to government fiscal take could have a negative impact on future operations. Our production operations in Libya and related oil exports were temporarily suspended in 2011 during Libya’s period of civil unrest. Our assets in Venezuela and Ecuador were expropriated in 2007 and 2009, respectively. In Canada, the Alberta provincial government changed the royalty structure in 2009 to tie a component of the new rate to prevailing prices. Our management carefully considers these events when evaluating projects or determining the level of activity in such countries.

Outlook

Total production for the first quarter of 2013 is expected to be 1.58 million to 1.6 million BOED, including production from discontinued operations of approximately 40,000 BOED. Full-year 2013 production from continuing operations is expected to be 1.475 million to 1.525 million BOED,which is consistent with 2012 production from continuing operations adjusted for dispositions.

Segment Analysis

We manage our operations through six operating segments, which are defined by geographic region: Alaska, Lower 48 and Latin America, Canada, Europe, Asia Pacific and Middle East, and Other International.

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

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

Our key performance indicators, shown in the statistical tables provided at the beginning of the operating segment sections that follow, reflect results from our continuing operations, including commodity prices and production.

 

37


Table of Contents

RESULTS OF OPERATIONS

Consolidated Results

A summary of the company’s income (loss) from continuing operations by business segment follows:

 

     Millions of Dollars  
Years Ended December 31    2012     2011     2010   
  

 

 

 

Alaska

   $         2,276       1,984       1,727   

Lower 48 and Latin America

     1,029       1,288       1,029   

Canada

     (684     91       2,902   

Europe

     1,498       1,830       1,703   

Asia Pacific and Middle East

     3,996       3,093       2,153   

Other International

     359       (377     (417)   

LUKOIL Investment

     -       239       2,513   

Corporate and Other

     (993     (960     (1,305)   

 

 

Income from continuing operations

   $ 7,481               7,188               10,305   

 

 

2012 vs. 2011

Earnings for ConocoPhillips increased 4 percent in 2012. The increase was mainly due to:

 

   

Higher gains from asset sales. In 2012, gains from asset dispositions were $1,567 million after-tax, compared with gains in 2011 from asset dispositions and LUKOIL share sales of $141 million after-tax.

   

Higher LNG and crude oil prices.

   

Lower production taxes, mainly as a result of lower volumes.

   

The benefit from the realization of a tax loss carryforward of $236 million.

   

The favorable resolution of pending claims and settlements of $235 million after-tax.

These items were partially offset by:

 

   

Lower volumes, largely due to dispositions and reduced production in China.

   

Lower natural gas, natural gas liquids and bitumen prices.

   

Higher operating and selling, general and administrative (SG&A) expenses, which included pension settlement expenses of $87 million after-tax and separation costs of $84 million after-tax.

   

Higher impairments. Non-cash impairments in 2012 totaled $900 million after-tax, compared with impairments in 2011 of $698 million after-tax.

2011 vs. 2010

Earnings for ConocoPhillips decreased 30 percent in 2011. The decrease was mainly due to:

 

   

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

   

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

   

Lower production volumes.

 

38


Table of Contents

These items were partially offset by:

 

   

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

   

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

Income Statement Analysis

2012 vs. 2011

Sales and other operating revenues decreased 10 percent in 2012, mainly due to lower natural gas and natural gas liquids prices, partly offset by higher LNG prices.

Equity in earnings of affiliates increased 54 percent in 2012. The increase primarily resulted from:

 

   

Improved earnings from Qatar Liquefied Gas Company Limited (3) (QG3), mainly due to higher LNG prices, partly offset by lower volumes.

   

Lower impairments from NMNG. In 2011, equity earnings included a $395 million impairment of our equity investment.

Gain on dispositions increased $1,287 million in 2012. Gains in 2012 primarily resulted from the disposition of our Vietnam business, our equity investment in NMNG, the Statfjord and Alba fields in the North Sea and our interest in Block 39 in Peru, partly offset by the loss on further dilution of our equity interest in APLNG from 42.5 percent to 37.5 percent. Gains in 2011 mainly consisted of the divestiture of our remaining LUKOIL shares and the disposition of certain properties located in the Lower 48 and Canada, partially offset by the loss on the initial dilution of our equity interest in APLNG from 50 percent to 42.5 percent. 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.

Other income increased 78 percent in 2012, mostly as a result of the favorable resolution of the Petróleos de Venezuela S.A. (PDVSA) International Chamber of Commerce (ICC) arbitration. For additional information, see Note 14—Contingencies and Commitments, in the Notes to Consolidated Financial Statements.

Purchased commodities decreased 15 percent in 2012, largely as a result of lower U.S. natural gas prices, partly offset by higher purchased volumes.

Production and operating expenses increased 6 percent in 2012, mostly due to major turnaround expenses at our Bayu-Undan Field and Darwin LNG facility and higher operating expenses in the Lower 48.

SG&A expenses increased 28 percent in 2012, primarily due to pension settlement expense and costs associated with the separation of Phillips 66.

Exploration expenses increased 45 percent in 2012, mostly due to the impairment of undeveloped leasehold costs associated with the Mackenzie Gas Project as a result of its indefinite suspension in the first quarter of 2012.

Impairments increased 112 percent in 2012. Impairments in 2012 included the $213 million impairment of capitalized development costs associated with the Mackenzie Gas Project in the first quarter of 2012, the $192 million property impairment related to the disposition of Cedar Creek Anticline, as well as increases in the asset retirement obligation for various properties mostly located in the United Kingdom, which have ceased production or are nearing the end of their useful lives. Impairments in 2011 consisted of various North American natural gas properties. For additional information, see Note 9—Impairments, in the Notes to Consolidated Financial Statements.

 

39


Table of Contents

Taxes other than income taxes decreased 11 percent in 2012, mostly due to lower production taxes as a result of lower crude oil production volumes.

Interest and debt expense decreased 26 percent in 2012, primarily due to higher capitalized interest on projects and lower interest expense due to lower average debt levels.

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

2011 vs. 2010

Sales and other operating revenues increased 14 percent in 2011, mainly due to significantly higher prices for crude oil and higher LNG prices and volumes. Lower crude oil and natural gas volumes partly offset this increase.

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

 

   

Earnings from QG3, primarily due to sales of LNG following production startup, which occurred in October 2010.

   

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

   

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

Gain on dispositions decreased 93 percent in 2011. Gains in 2011 primarily resulted from the disposition of certain assets located in the Lower 48 and Canada, as well as the divestiture of our remaining LUKOIL shares. These gains were partially offset by the loss on dilution of our equity interest in APLNG from 50 percent to 42.5 percent. Gains in 2010 primarily reflected the $2,878 million gain realized from the sale of our interest in Syncrude, the $1,749 million gain on the divestiture of a portion of our LUKOIL shares, and gains on the disposition of certain assets located in the Lower 48 and Canada.

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

DD&A decreased 15 percent in 2011. The decrease was mostly associated with lower production volumes and lower unit-of-production rates related to reserve bookings in 2011.

Impairments increased $240 million in 2011, mostly due to the impairment of various North American natural gas properties in 2011.

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

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

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

 

40


Table of Contents

Summary Operating Statistics

 

     2012      2011      2010  
  

 

 

 
                      

Average Net Production(1)

        

Crude oil (MBD)(2)

     595        622        733  

Natural gas liquids (MBD)

     156        145        147  

Synthetic oil (MBD)

     -        -        12  

Bitumen (MBD)

     93        67        59  

Natural gas (MMCFD)(3)

     4,096        4,359        4,465  

 

 

Total Production (MBOED)(4)

     1,527        1,561        1,695  

 

 
     Dollars Per Unit  

Average Sales Prices

        

Crude oil (per barrel)

   $       105.72        105.52        77.74  

Natural gas liquids (per barrel)

     46.36        55.73        46.00  

Synthetic oil (per barrel)

     -        -        77.56  

Bitumen (per barrel)

     53.91        62.56        53.06  

Natural gas (per thousand cubic feet)

     5.48        5.80        5.05  

 

 
     Millions of Dollars  

Worldwide Exploration Expenses

        

General and administrative; geological and geophysical; and lease rentals

   $ 626        569        649  

Leasehold impairment

     719        159        241  

Dry holes

     155        310        235  

 

 
   $ 1,500                1,038                1,125  

 

 

Excludes discontinued operations.

(1)Excludes amounts related to LUKOIL.

(2)Thousands of barrels per day.

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

(4)Thousands of barrels of oil equivalent per day.

We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and natural gas liquids on a worldwide basis. At December 31, 2012, our continuing operations were producing in the United States, Norway, the United Kingdom, Canada, Australia, offshore Timor-Leste in the Timor Sea, Indonesia, China, Malaysia, Qatar, Libya and Russia.

In 2012, average production from continuing operations decreased 2 percent compared with 2011, primarily as a result of normal field decline, the impact from asset dispositions and higher planned and unplanned downtime. These decreases were largely offset by additional production from major developments, mainly from shale plays in the Lower 48 and ramp-up of new phases at FCCL, the resumption of production in Libya following a period of civil unrest in 2011, and increased drilling programs in the Lower 48.

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

 

41


Table of Contents

Alaska

 

     2012      2011      2010  
  

 

 

 

Income from Continuing Operations (millions of dollars)

   $ 2,276        1,984        1,727  

 

 

Average Net Production

        

Crude oil (MBD)

     188        200        215  

Natural gas liquids (MBD)

     16        15        15  

Natural gas (MMCFD)

     55        61        82  

 

 

Total Production (MBOED)

     213        225        244  

 

 

Average Sales Prices

        

Crude oil (per barrel)

   $       109.62                105.95                78.65  

Natural gas (per thousand cubic feet)

     4.22        4.56        4.62  

 

 

The Alaska segment primarily explores for, produces, transports and markets crude oil, natural gas liquids, natural gas and LNG. In 2012, Alaska contributed 24 percent of our worldwide liquids production and 1 percent of our natural gas production.

2012 vs. 2011

Our Alaska operations reported earnings of $2,276 million in 2012, a 15 percent increase compared with earnings of $1,984 million in 2011. The increase in earnings was primarily due to higher crude oil prices, lower production taxes as a result of lower crude oil production volumes, the absence of the $54 million after-tax write-off of our investment associated with the cancellation of the Denali gas pipeline project in 2011, and lower DD&A. These increases were partly offset by lower crude oil sales volumes and higher operating expenses.

Production averaged 213 MBOED in 2012, a decrease of 5 percent compared with 2011. This decrease was mainly due to normal field decline, partially offset by lower unplanned downtime.

2011 vs. 2010

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

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

 

42


Table of Contents

Lower 48 and Latin America

 

     2012      2011      2010  
  

 

 

 

Income from Continuing Operations (millions of dollars)

   $ 1,029        1,288        1,029  

 

 

Average Net Production

        

Crude oil (MBD)

     123        94        85  

Natural gas liquids (MBD)

     85        74        75  

Natural gas (MMCFD)

     1,493                1,556                1,695  

 

 

Total Production (MBOED)

     457        428        442  

 

 

Average Sales Prices

        

Crude oil (per barrel)

   $         91.67        92.79        73.52  

Natural gas liquids (per barrel)

     35.45        50.55        39.92  

Natural gas (per thousand cubic feet)

     2.67        3.99        4.25  

 

 

During 2012, Lower 48 and Latin America contributed 25 percent of our worldwide liquids production and 37 percent of our natural gas production. The Lower 48 and Latin America segment primarily consists of operations located in the U.S. Lower 48 states.

2012 vs. 2011

Lower 48 and Latin America operations reported earnings of $1,029 million in 2012, a 20 percent decrease compared with 2011. The decrease in earnings was primarily the result of substantially lower natural gas and natural gas liquids prices; higher DD&A, mostly due to higher crude oil and natural gas liquids production; lower gains from asset dispositions; higher operating expenses and higher impairments. These decreases were partially offset by higher crude oil and natural gas liquids volumes. Earnings in 2012 also benefitted from the realization of a tax loss carryforward of $236 million, and the favorable resolution of the PDVSA ICC arbitration.

In November 2012, based on an ICC arbitration tribunal ruling, PDVSA paid ConocoPhillips $68 million for pre-expropriation breaches of the Petrozuata project agreements, which resulted in a $61 million after-tax earnings increase. The Company also recognized additional income of $173 million after-tax associated with the reversal of a related contingent liability accrual. These amounts included interest of $33 million after-tax, which has been reflected in the Corporate and Other segment. For additional information, see Note 14—Contingencies and Commitments, in the Notes to Consolidated Financial Statements.

Average production in the Lower 48 increased 7 percent in 2012, while average liquids production increased 24 percent over the same period. New production, primarily from the Eagle Ford, Bakken and Permian areas, and improved drilling and well performance more than offset normal field decline. In addition, higher unplanned downtime during 2012 partly offset the increase in production.

2011 vs. 2010

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

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

 

43


Table of Contents

Canada

 

     2012     2011      2010  
  

 

 

 

Income (Loss) from Continuing Operations (millions of dollars)

   $ (684     91        2,902  

 

 

Average Net Production

       

Crude oil (MBD)

     13       12        15  

Natural gas liquids (MBD)

     24       26        23  

Synthetic oil (MBD)

     -       -        12  

Bitumen (MBD)

       

Consolidated operations

     12       10        10  

Equity affiliates

     81       57        49  

 

 

Total bitumen

     93       67        59  

Natural gas (MMCFD)

     857               928        984  

 

 

Total Production (MBOED)

     273       260        273  

 

 

Average Sales Prices

       

Crude oil (per barrel)

   $         78.26       86.04                67.99  

Natural gas liquids (per barrel)

     48.64       56.84        47.68  

Synthetic oil (per barrel)

     -       -        77.56  

Bitumen (dollars per barrel)

       

Consolidated operations

     57.58       55.16        51.10  

Equity affiliates

     53.39       63.93        53.43  

Total bitumen

     53.91       62.56        53.06  

Natural gas (per thousand cubic feet)

     2.13       3.46        3.74  

 

 

Our Canadian operations are mainly comprised of natural gas fields in western Canada and oil sands developments in the Athabasca Region of northeastern Alberta. In 2012, Canada contributed 15 percent of our worldwide liquids production and 21 percent of our natural gas production.

2012 vs. 2011

Canada operations reported a loss of $684 million in 2012, a reduction of $775 million compared with earnings of $91 million in 2011. The decrease in earnings was largely due to significantly lower natural gas prices, lower bitumen prices and higher impairments, mainly as a result of the $520 million after-tax impairment of the Mackenzie Gas Project and associated leaseholds in 2012. These decreases were partially offset by significantly higher bitumen volumes from FCCL and lower DD&A from our western Canadian gas assets, primarily due to asset dispositions and curtailments. Equity earnings from FCCL were also impacted by higher operating and DD&A expenses, mostly as a result of higher production volumes.

Average production in Canada increased 5 percent in 2012, while average liquids production increased 24 percent over the same period. Normal field decline and the impact from asset dispositions were more than offset by new production from Christina Lake Phases C and D and improved well performance from Foster Creek, both in FCCL.

2011 vs. 2010

Canada earnings were $91 million in 2011, a reduction of $2,811 million compared with 2010. This decrease was primarily due to lower gains from asset dispositions. Earnings in 2010 included the $2,679 million after-tax gain realized from the sale of our 9.03 percent interest in the Syncrude oil sands mining operation. Lower volumes, mostly as a result of asset dispositions, impairments on various natural gas properties and lower

 

44


Table of Contents

natural gas prices also contributed to the decrease in 2011 earnings. These decreases were somewhat offset by higher bitumen, natural gas liquids and crude oil prices, lower DD&A and lower dry hole expenses.

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

Europe

 

     2012      2011      2010  
  

 

 

 

Income from Continuing Operations (millions of dollars)

   $ 1,498        1,830        1,703  

 

 

Average Net Production

        

Crude oil (MBD)

     135        164        196  

Natural gas liquids (MBD)

     7        11        15  

Natural gas (MMCFD)

     516        626        815  

 

 

Total Production (MBOED)

     228        279        347  

 

 

Average Sales Prices

        

Crude oil (dollars per barrel)

   $         113.08                111.82                79.74  

Natural gas liquids (per barrel)

     61.53        59.19        46.75  

Natural gas (per thousand cubic feet)

     9.76        9.26        6.94  

 

 

The Europe segment consists of operations principally located in the Norwegian and U.K. sectors of the North Sea, as well as exploration activities in Poland and Greenland. In 2012, our Europe operations contributed 17 percent of our worldwide liquids production and 13 percent of our natural gas production.

2012 vs. 2011

Europe operations reported earnings of $1,498 million in 2012, an 18 percent decrease compared with 2011. The reduction in earnings was mainly due to lower volumes and higher impairments. Earnings for 2012 were also impacted by additional income tax expense due to legislation enacted in the United Kingdom in 2012, which restricted corporate tax relief on decommissioning costs. The additional tax expense resulted from the revaluation of deferred tax balances. These decreases to earnings were partly offset by a $287 million after-tax gain on sale of our interests in the Statfjord and Alba fields and lower DD&A. Additionally, earnings in 2011 included a $316 million increase in U.K. corporate income tax expense due to legislation enacted in 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.

Production averaged 228 MBOED in 2012, an 18 percent decrease compared with 2011. The decrease was mostly due to normal field decline, dispositions and higher unplanned downtime in the United Kingdom.

2011 vs. 2010

Earnings for our Europe operations were $1,830 million in 2011, a 7 percent increase compared with earnings of $1,703 million in 2010. Earnings benefitted from significantly higher prices and lower DD&A, partly offset by lower volumes and the $316 million increase in U.K. corporate income tax expense. Earnings in 2010 also benefitted from a $58 million insurance settlement.

 

45


Table of Contents

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

Asia Pacific and Middle East

 

     2012      2011      2010    
  

 

 

 

Income from Continuing Operations (millions of dollars)

   $ 3,996        3,093        2,153    

 

 

Average Net Production

        

Crude oil (MBD)

        

Consolidated operations

     68        99        122    

Equity affiliates

     15        16        2    

 

 

Total crude oil

     83        115        124    

 

 

Natural gas liquids (MBD)

        

Consolidated operations

     16        12        18    

Equity affiliates

     8        7        1    

 

 

Total natural gas liquids

     24        19        19    

 

 

Natural gas (MMCFD)

        

Consolidated operations

     672        695        712    

Equity affiliates

     485        492        169    

 

 

Total natural gas

     1,157        1,187        881    

 

 

Total Production (MBOED)

     300        332        290    

 

 

Average Sales Prices

        

Crude oil (dollars per barrel)

        

Consolidated operations

   $ 108.20                109.84                77.69    

Equity affiliates

     108.07        106.96        89.24    

Total crude oil

     108.18        109.46        77.89    

Natural gas liquids (dollars per barrel)

        

Consolidated operations

     79.26        72.87        60.57    

Equity affiliates

     77.30        70.62        65.16    

Total natural gas liquids

     78.64        71.98        60.73    

Natural gas (dollars per thousand cubic feet)

        

Consolidated operations

     10.63        9.82        7.39    

Equity affiliates

     8.54        5.93        1.91    

Total natural gas

     9.75        8.21        6.35    

 

 

The Asia Pacific and Middle East segment has producing operations in China, Indonesia, Malaysia, Australia, the Timor Sea and Qatar, as well as exploration activities in Bangladesh and Brunei. During 2012, Asia Pacific and Middle East contributed 13 percent of our worldwide liquids production and 28 percent of our natural gas production.

2012 vs. 2011

Asia Pacific and Middle East operations reported earnings of $3,996 million in 2012, a 29 percent increase compared with 2011 earnings of $3,093 million. Earnings in 2012 primarily benefitted from higher gains from asset dispositions, significantly higher LNG prices, higher equity earnings due to lower DD&A and operating expenses from QG3, and lower Bohai Bay expenses incurred in 2012. Amounts realized from dispositions in

 

46


Table of Contents

2012 consisted of a $931 million after-tax gain on sale of our Vietnam business and a $133 million after-tax loss recognized on the further dilution of our equity interest in APLNG from 42.5 percent to 37.5 percent. In 2011, we recognized a $279 million after-tax loss on the initial dilution of our interest in APLNG from 50 percent to 42.5 percent. The increase in 2012 earnings was partly offset by lower crude oil volumes, mainly as a result of the Bohai Bay seepage incidents and the Vietnam disposition, lower LNG volumes and higher production taxes.

Average production decreased 10 percent in 2012. The decrease was largely due to the disposition of our Vietnam business, normal field decline, planned maintenance at our Bayu-Undan Field and Darwin LNG Facility in 2012, as well as lower production in China.

2011 vs. 2010

Asia Pacific and Middle East earnings increased 44 percent in 2011, compared with 2010 earnings. The increase was mainly due to higher prices, higher volumes, mostly as a result of a full year of LNG sales from QG3, and lower DD&A. These increases to earnings were partly offset by higher production taxes, higher operating expenses and the $279 million loss on dilution of our equity interest in APLNG from 50 percent to 42.5 percent.

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

Timor-Leste Arbitration

ConocoPhillips served a Notice of Arbitration on the Timor-Leste Minister of Finance in October 2012 for outstanding disputes related to a series of tax assessments. Between 2010 and 2012, ConocoPhillips has paid, under protest, tax assessments totaling approximately $227 million, which are primarily recorded in the “Investments and long-term receivables” line on our December 31, 2012, consolidated balance sheet. The arbitration will be conducted in Singapore under the United Nations Commission on International Trade Laws (UNCITRAL) arbitration rules, pursuant to the terms of the Tax Stability Agreement with the Timor-Leste Government. The arbitration process is currently underway. Future impacts on our business are not known at this time.

 

47


Table of Contents

Other International

 

     2012      2011     2010    
  

 

 

 

Income (Loss) from Continuing Operations (millions of dollars)*

   $ 359        (377     (417)    

 

 

Average Net Production*

       

Crude oil (MBD)

       

Consolidated operations

     40        8       46    

Equity affiliates

     13        29       52    

 

 

Total crude oil

     53        37       98    

 

 

Natural gas (MMCFD)

     18        1       8    

 

 

Total Production (MBOED)

     56        37       99    

 

 

Average Sales Prices*

       

Crude oil (dollars per barrel)

       

Consolidated operations

   $ 110.75        98.30       79.22    

Equity affiliates

     96.50                101.62               74.33    

Total crude oil

     107.56        101.14       76.57    

Natural gas (dollars per thousand cubic feet)

     5.55        0.09       0.09    

 

 
* Prior periods have been restated to exclude discontinued operations.

The Other International segment includes producing operations in Libya and Russia, as well as exploration activities in Angola and the Caspian Sea. During 2012, Other International contributed 6 percent of our worldwide liquids production.

2012 vs. 2011

Other International operations reported earnings of $359 million in 2012, a $736 million increase compared with 2011. Earnings in 2012 primarily benefitted from the $443 million after-tax gain on disposition of our interest in NMNG, the absence of a $395 million after-tax impairment of our investment in NMNG in 2011, and higher earnings from Libya, as a result of the resumption of production following a period of civil unrest in 2011. These increases were partially offset by a $108 million after-tax impairment associated with the N Block in the Caspian Sea.

Production averaged 56 MBOED in 2012, a 51 percent increase compared with 2011 production. The increase was mainly due to the resumption of production in Libya, partly offset by field decline in Russia and the disposition of our interest in NMNG.

2011 vs. 2010

Other International reported a loss of $377 million in 2011, compared with a loss of $417 million in 2010. The improvement in 2011 was primarily the result of higher crude oil prices, higher equity earnings due to lower DD&A from NMNG and lower impairments. In 2011, we recorded a $395 million impairment of our equity investment in NMNG, compared with a $645 million impairment to NMNG recorded in 2010. These improvements in 2011 were partly offset by considerably lower volumes, mainly from Libya and Russia, as well as the absence of a deferred tax benefit recognized in 2010.

Production averaged 37 MBOED in 2011, a 63 percent decrease compared with 2010 production. The decrease was mostly due to suspended operations in Libya following a period of civil unrest in 2011, and field decline in Russia.

 

48


Table of Contents

Asset Dispositions

We recently announced our intention to sell our 8.4 percent interest in Kashagan and our Algerian and Nigerian businesses. The transactions are expected to close by mid-2013, subject to customary governmental approvals. In January 2013, we sold our 24.5 percent interest in the N Block, located offshore Kazakhstan.

LUKOIL Investment

 

                                                                             
     Millions of Dollars  
  

 

 

 
     2012      2011      2010   
  

 

 

 

Income from Continuing Operations

   $         -         239        2,513   

 

 

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.

Corporate and Other

 

                                                                    
     Millions of Dollars  
  

 

 

 
     2012     2011     2010   
  

 

 

 

Income (Loss) from Continuing Operations

      

Net interest

   $ (648     (710     (995)   

Corporate general and administrative expenses

     (313     (190     (209)   

Technology

     (4     15       (23)   

Separation costs

     (84     (25      

Other

     56       (50     (78)   

 

 
   $ (993     (960     (1,305)   

 

 

2012 vs. 2011

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 9 percent in 2012, mostly due to higher capitalized interest, lower interest expense due to lower average debt levels, higher interest income and the $33 million after-tax interest benefit from the favorable resolution of the PDVSA arbitration. These improvements were partly offset by a $68 million after-tax premium on early debt retirement.

Corporate general and administrative expenses increased 65 percent in 2012, mainly due to $87 million of after-tax pension settlement expense and higher costs related to compensation and benefit plans.

Technology includes our investment in new technologies or businesses, as well as licensing revenues received. Activities are focused on heavy oil and oil sands; unconventional reservoirs; subsurface technology; liquefied natural gas; and arctic, deepwater and sustainability technology. Technology reported a loss of $4 million in 2012, compared to earnings of $15 million in 2011, primarily as a result of lower licensing revenues.

 

49


Table of Contents

Separation costs consist of expenses related to the separation of our Downstream business into a stand-alone, publicly traded company, Phillips 66. Separation costs increased $59 million in 2012 and mainly included costs related to compensation and benefit plans.

The category “Other” includes certain foreign currency transaction gains and losses, environmental costs associated with sites no longer in operation, and other costs not directly associated with an operating segment. The improvement in “Other” in 2012 was largely due to various tax-related adjustments, including a $39 million after-tax settlement. These improvements were partially offset by higher environmental expenses and foreign currency transaction losses.

2011 vs. 2010

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

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

Technology had earnings of $15 million in 2011, as a result of higher licensing revenues, partially offset by higher project expenses.

Separation costs in 2011 primarily included legal, accounting and information systems costs.

Changes in the “Other” category primarily resulted from lower environmental costs and gains from foreign currency transactions, partially offset by a $20 million after-tax property impairment.

 

50


Table of Contents

CAPITAL RESOURCES AND LIQUIDITY

Financial Indicators

 

    

Millions of Dollars

Except as Indicated

 
  

 

 

 
     2012     2011      2010  
  

 

 

 

Net cash provided by continuing operating activities

   $         13,458       13,953        14,013  

Net cash provided by discontinued operations

     464       5,693        3,032  

Short-term debt

     955       1,013        936  

Total debt

     21,725       22,623        23,592  

Total equity

     48,427               65,749                69,124  

Percent of total debt to capital*

     31  %      26        25  

Percent of floating-rate debt to total debt**

     9  %      10        10  

 

 

  * Capital includes total debt and total equity.

** Includes effect of interest rate swaps.

To meet our short- and long-term liquidity requirements, we look to a variety of funding sources. Cash generated from continuing operating activities is the primary source of funding. In addition, during 2012, we received $2,132 million in proceeds from asset sales and $1,996 million for the issuance of debt. During 2012, the primary uses of our available cash were $14,172 million to support our ongoing capital expenditures and investments; $5,098 million to repurchase common stock; $3,278 million to pay dividends on our common stock; and $2,565 million to repay debt. During 2012, cash and cash equivalents decreased by $2,162 million to $3,618 million.

In addition to cash flows from continuing operating activities and proceeds from asset sales, we rely on our commercial paper and credit facility programs and our shelf registration statement to support our short- and long-term liquidity requirements. We believe our current cash balance 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 program, dividend payments, required debt payments and the funding requirements to FCCL.

Separation of Phillips 66

On April 30, 2012, the separation of our Downstream business was completed, creating two independent energy companies: ConocoPhillips and Phillips 66. Our refining, marketing and transportation businesses, most of our Midstream segment, our Chemicals segment, as well as our power generation and certain technology operations included in our Emerging Businesses segment, were transferred to Phillips 66. After the close of the New York Stock Exchange on April 30, 2012, the shareholders of record as of 5:00 p.m. Eastern time on April 16, 2012 (the Record Date), received one share of Phillips 66 common stock for every two ConocoPhillips common shares held as of the Record Date.

In connection with the separation, Phillips 66 distributed approximately $7.8 billion to us in a special cash distribution. These funds will be used solely to pay dividends, repurchase common stock, repay debt, or a combination of the foregoing, within twelve months following the distribution. At December 31, 2012, the unused amount of the special cash distribution was $748 million and is designated as “Restricted cash” on our consolidated balance sheet.

Significant Sources of Capital

Operating Activities

During 2012, cash provided by continuing operating activities was $13,458 million, a 4 percent decrease from 2011. During 2011, cash provided by continuing operations was $13,953 million compared with $14,013 million in 2010.

 

51


Table of Contents

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. 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 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 generally this variability has not been as significant as that caused by commodity prices.

Our 2012 production from continuing operations averaged 1.527 million BOED. Future production is subject to numerous uncertainties, including, among others, the volatile crude oil and natural gas price environment, which may impact investment decisions; the effects of price changes on production sharing and variable-royalty contracts; timing of startups and major turnarounds; and weather-related disruptions. Our production from continuing operations in 2013 is expected to be 1.475 million to 1.525 million BOED.

To maintain or grow our production volumes, we must continue to add to our proved reserve base. Our total reserve replacement in 2012 was 142 percent. Excluding the impact of sales and purchases, the organic reserve replacement was 156 percent of 2012 production. Over the five-year period ended December 31, 2012, our reserve replacement was 48 percent (including 65 percent from consolidated operations) reflecting the disposition of our interest in LUKOIL and the impact of our asset disposition program. Excluding these items and purchases, our five-year organic reserve replacement was 108 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 pursuing developments 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 development uneconomic or unattractive. In addition, political instability, competition from national oil companies, and lack of access to high-potential areas due to environmental or other regulation may negatively impact our ability to increase our reserve base. As such, the timing and level at which we add to our reserve base may, or may not, allow us to replace our production over subsequent years.

As discussed in the “Critical Accounting Estimates” section, engineering estimates of proved reserves are imprecise; therefore, each year reserves may be revised upward or downward due to the impact of changes in commodity prices or as more technical data becomes available on reservoirs. In 2012, 2011 and 2010, revisions increased reserves. It is not possible to reliably predict how revisions will impact reserve quantities in the future.

Asset Sales

Proceeds from asset sales in 2012 were $2,132 million, primarily from the sale of our Vietnam business, the sale of our equity interest in NMNG and the sale of our interest in the Statfjord and Alba fields in the North Sea. This compares with proceeds of $2,192 million in 2011, which mainly included the sale of our remaining interest in LUKOIL and certain properties located in the Lower 48. We have announced additional asset sales of $9.6 billion which are expected to close by mid-2013. We continue to evaluate opportunities to further optimize the portfolio.

Commercial Paper and Credit Facilities

In May 2012, we decreased our total revolving credit facilities from $8.0 billion to $7.5 billion by terminating all commitments under the $500 million credit facility, which was due to expire in July 2012. At

 

52


Table of Contents

December 31, 2012, we had a revolving credit facility totaling $7.5 billion expiring in August 2016. Our revolving credit facility 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 facility is broadly syndicated among financial institutions and does not contain any material adverse change provisions or any covenants requiring maintenance of specified financial ratios or ratings. The facility agreement contains 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 agreement calls for commitment fees on available, but unused, amounts. The agreement also contains 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. $1.15 billion commercial paper program, which is used to fund commitments relating to QG3. At December 31, 2012 and 2011, we had no direct borrowings under the revolving credit facilities, with no letters of credit issued at December 31, 2012, and $40 million at December 31, 2011. In addition, under the ConocoPhillips Qatar Funding Ltd. commercial paper program, $1,055 million of commercial paper was outstanding at December 31, 2012, compared with $1,128 million at December 31, 2011. Since we had $1,055 million of commercial paper outstanding and had issued no letters of credit, we had access to $6.4 billion in borrowing capacity under our revolving credit facilities at December 31, 2012.

Our senior long-term debt is rated “A1” by Moody’s Investors Service and “A” by both Standard and Poor’s Rating Service and 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 revolving credit facility.

Certain of our project-related contracts and derivative instruments contain provisions that require us to post collateral. Cash is the primary source for providing collateral; however, many permit us to post letters of credit. At December 31, 2012, we had performance obligations secured by letters of credit of $852 million (issued as direct bank letters of credit) related to various purchase commitments for materials, supplies, commercial activities and services incident to the ordinary conduct of business.

Shelf Registration

We have a universal shelf registration statement on file with the U.S. Securities and Exchange Commission 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.

 

53


Table of Contents

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.

For information about guarantees, see Note 13—Guarantees, in the Notes to Consolidated Financial Statements, which is incorporated herein by reference.

Capital Requirements

For information about our capital expenditures and investments, see the “Capital Spending” section.

Our debt balance at December 31, 2012, was $21.7 billion, a decrease of $0.9 billion during 2012. During 2012, we repaid notes totaling $2.4 billion. We incurred a before-tax loss on redemption of $79 million, consisting of make-whole premiums and unamortized issuance costs. In December 2012, we issued $2.0 billion of new low-interest notes.

We are obligated to contribute $7.5 billion, plus interest, over a 10-year period that began in 2007, to FCCL. 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 $772 million was short-term and was included in the “Accounts payable—related parties” line on our December 31, 2012, consolidated balance sheet. The principal portion of these payments, which totaled $733 million in 2012, is included in the “Other” line in the financing activities section of our consolidated statement of cash flows. Interest accrues at a fixed annual rate of 5.3 percent on the unpaid principal balance. Fifty percent of the quarterly interest payment is reflected as a capital contribution and is included in the “Capital expenditures and investments” line on our consolidated statement of cash flows.

In February, 2013, we announced a dividend of 66 cents per share. The dividend will be paid March 1, 2013, to stockholders of record at the close of business on February 19, 2013.

Since our share repurchase programs began in 2010, share repurchases totaled 300 million shares at a cost of $20.1 billion through December 31, 2012. Although we have no current plans for further share repurchases, we may do so opportunistically, contingent upon commodity prices and proceeds from asset dispositions.

 

54


Table of Contents

Contractual Obligations

The following table summarizes our aggregate contractual fixed and variable obligations of our continuing operations as of December 31, 2012:

 

     Millions of Dollars  
  

 

 

 
     Payments Due by Period   
  

 

 

 
     Total      Up to 1
Year
     Years 2-3     Years 4-5     After
5 Years
 
  

 

 

 

Debt obligations (a)

   $ 21,709        955        1,952       3,274       15,528   

Capital lease obligations

     16        -        -       -       16   

 

 

Total debt

     21,725        955        1,952       3,274       15,544   

 

 

Interest on debt and other obligations

     16,355        1,247        2,216       1,964       10,928   

Operating lease obligations

     2,151        477        960       424       290   

Purchase obligations (b)

     26,465        12,149        4,370       2,242       7,704   

Joint venture acquisition obligation (c)

     3,582        772        1,672       1,138        

Other long-term liabilities

            

Pension and postretirement benefit contributions (d)

     2,579        484        1,045       1,050        

Asset retirement obligations*

     9,033        387        521       413       7,712   

Accrued environmental costs

     364        38        65       48       213   

Unrecognized tax benefits (e)

     116        116        (e     (e     (e)   

 

 

Total

   $         82,370            16,625            12,801           10,553           42,391   

 

 

*Excludes amounts related to discontinued operations:

   $ 131        -        -       -       131   

 

(a) Includes $429 million of net unamortized premiums and discounts. See Note 11—Debt, in the Notes to Consolidated Financial Statements, for additional information.

 

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

The majority of the purchase obligations are market-based contracts related to our commodity business. Product purchase commitments with third parties totaled $12,602 million.

Purchase obligations of $9,629 million are related to agreements to access and utilize the capacity of third-party equipment and facilities, including pipelines and LNG and product terminals, to transport, process, treat and store commodities. The remainder is primarily our net share of purchase commitments for materials and services for jointly owned fields and facilities where we are the operator.

 

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

 

(d) Represents contributions to qualified and nonqualified pension and postretirement benefit plans for the years 2013 through 2017. For additional information related to expected benefit payments subsequent to 2017, see Note 19—Employee Benefit Plans, in the Notes to Consolidated Financial Statements.

 

(e) Excludes unrecognized tax benefits of $756 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.

 

55


Table of Contents

Capital Spending

 

Capital Program    Millions of Dollars  
  

 

 

 
     2012      2011      2010  
  

 

 

 

Alaska

   $ 828        774        729  

Lower 48 and Latin America

     5,251        3,882        1,790  

Canada

     2,184        1,761        1,356  

Europe

     2,860        2,222        1,190  

Asia Pacific and Middle East

     2,430        2,325        2,157  

Other International

     415        8        127  

LUKOIL Investment

     -        -        -  

Corporate and Other

     204        242        186  

 

 

Capital expenditures and investments from continuing operations

     14,172        11,214        7,535  

 

 

Discontinued operations in Kashagan, Nigeria and Algeria

     817        1,038        1,071  

Joint venture acquisition obligation (principal)—Canada

     733        695        659  

 

 

Capital Program

   $         15,722                12,947                9,265  

 

 

Our capital expenditures and investments from continuing operations for the three-year period ended December 31, 2012, totaled $32.9 billion. The expenditures over this period supported key exploration and developments, primarily:

 

   

Oil, natural gas liquids and natural gas developments in the Lower 48, including Texas, New Mexico, North Dakota, Oklahoma, Montana, Colorado, Wyoming and offshore in the Gulf of Mexico.

   

Further development of coalbed methane (CBM) associated with the APLNG joint venture in Australia.

   

Oil sands and ongoing natural gas developments in Canada.

   

Alaska activities related to development in the Greater Kuparuk Area, the Greater Prudhoe Area, the Western North Slope and the Cook Inlet Area and initial development of the Point Thomson Unit.

   

Development drilling and new facilities in the Norway sector of the North Sea, including the Greater Ekofisk Area, Alvheim, Visund and Statfjord, and Heidrun in the Norwegian Sea.

   

The Bohai Bay development in China.

   

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

   

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

   

QG3, an integrated development which produces and liquefies 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 developments, deepwater Gulf of Mexico, Alaska, the U.K. and Norway sectors of the North Sea, Kazakhstan and Indonesia.

   

Leasehold acquisitions in Angola.

 

56


Table of Contents

2013 CAPITAL PROGRAM

Our 2013 capital program of $15.8 billion is comprised of $15.0 billion for the capital expenditures and investments budget and $0.8 billion for principal contributions to fund our portion of the FCCL business venture. Of the $15.0 billion for the capital expenditures and investments budget, $0.3 billion relates to our discontinued operations in Kashagan, Nigeria and Algeria and $14.7 billion relates to continuing operations. Included in the 2013 capital expenditures and investments budget is $0.6 billion in capitalized interest.

Our 2013 capital expenditures and investments budget for continuing operations of $14.7 billion is 4 percent higher than actual expenditures in 2012.

We are directing approximately 60 percent of our 2013 capital expenditures and investments budget for continuing operations to North America. These funds are expected to be directed toward:

 

   

In Alaska, further development of opportunities in Prudhoe Bay, Kuparuk and Alpine fields, and initial development of Point Thomson Field.

   

In Lower 48, development of liquids-rich areas, such as the Eagle Ford trend, and the Williston and Permian basins.

   

Exploration and appraisal activities in the Eagle Ford shale formation, and Avalon, Wolfcamp and Niobrara areas in Lower 48.

   

Appraisal of deepwater Gulf of Mexico discoveries, wildcat wells and acreage additions.

   

Liquids opportunities in the western Canada basins and Canadian oil sands.

   

Exploration and appraisal activities in Canadian shale plays and oil sands.

We are directing approximately 40 percent of our 2013 capital expenditures and investments budget for continuing operations to Europe, Asia Pacific and other international businesses. These funds are expected to be directed toward:

 

   

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

   

Elsewhere in the Asia Pacific and Middle East segment, continued development of Bohai Bay in China, new fields offshore Malaysia, and offshore Block B and onshore South Sumatra in Indonesia.

   

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.

   

Onshore developments in Libya.

   

Exploration and appraisal activities in Australia’s offshore Browse Basin and onshore Canning Basin, deepwater Angola, offshore Indonesia and Malaysia, 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.

Contingencies

A number of lawsuits involving a variety of claims have been made against ConocoPhillips that arise in the ordinary course of business. We also may be required to remove or mitigate the effects on the environment of the placement, storage, disposal or release of certain chemical, mineral and petroleum substances at various active and inactive sites. We regularly assess the need for accounting recognition or disclosure of these contingencies. In the case of all known contingencies (other than those related to income taxes), we accrue a liability when the loss is probable and the amount is reasonably estimable. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. We do not reduce these liabilities for potential insurance or third-party recoveries. If applicable, we accrue receivables for probable insurance or other third-party recoveries. In the case of income-tax-related contingencies, we use a cumulative probability-weighted loss accrual in cases where sustaining a tax position is less than certain.

 

57


Table of Contents

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. For information on other contingencies, see Note 14—Contingencies and Commitments, in the Notes to Consolidated Financial Statements.

Legal and Tax Matters

Our legal organization applies its knowledge, experience and professional judgment to the specific characteristics of our cases, employing a litigation management process to manage and monitor the legal proceedings against us. Our process facilitates the early evaluation and quantification of potential exposures in individual cases. This process also enables us to track those cases that have been scheduled for trial and/or mediation. Based on professional judgment and experience in using these litigation management tools and available information about current developments in all our cases, our legal organization regularly assesses the adequacy of current accruals and determines if adjustment of existing accruals, or establishment of new accruals, are required. See Note 20—Income Taxes, in the Notes to Consolidated Financial Statements, for additional information about income-tax-related contingencies.

Environmental

We are subject to the same numerous international, federal, state and local environmental laws and regulations as other companies in our industry. The most significant of these environmental laws and regulations include, among others, the:

 

   

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

   

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

   

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

   

U.S. Federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), which imposes liability on generators, transporters and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatening to occur.

   

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

   

U.S. Federal Oil Pollution Act of 1990 (OPA90), under which owners and operators of onshore facilities and pipelines, lessees or permittees of an area in which an offshore facility is located, and owners and operators of vessels are liable for removal costs and damages that result from a discharge of oil into navigable waters of the United States.

   

U.S. Federal Emergency Planning and Community Right-to-Know Act (EPCRA), which requires facilities to report toxic chemical inventories with local emergency planning committees and response departments.

   

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

   

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

   

European Union Trading Directive resulting in European Emissions Trading Scheme.

 

58


Table of Contents

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 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. 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, 2011, we reported we had been notified of potential liability under CERCLA and comparable state laws at 74 sites around the United States. At December 31, 2012, we had closed 2 sites and transferred 61 sites to Phillips 66, bringing the number to 11 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

 

59


Table of Contents

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 $575 million in 2012 and are expected to be about $478 million per year in 2013 and 2014. Capitalized environmental costs were $297 million in 2012 and are expected to be about $459 million per year in 2013 and 2014.

Accrued liabilities for remediation activities are not reduced for potential recoveries from insurers or other third parties and are not discounted (except those assumed in a purchase business combination, which we do record on a discounted basis).

Many of these liabilities result from CERCLA, RCRA and similar state laws that require us to undertake certain investigative and remedial activities at sites where we conduct, or once conducted, operations or at sites where ConocoPhillips-generated waste was disposed. The accrual also includes a number of sites we identified that may require environmental remediation, but which are not currently the subject of CERCLA, RCRA or state enforcement activities. If applicable, we accrue receivables for probable insurance or other third-party recoveries. In the future, we may incur significant costs under both CERCLA and RCRA.

Remediation activities vary substantially in duration and cost from site to site, depending on the mix of unique site characteristics, evolving remediation technologies, diverse regulatory agencies and enforcement policies, and the presence or absence of potentially liable third parties. Therefore, it is difficult to develop reasonable estimates of future site remediation costs.

At December 31, 2012, our balance sheet included total accrued environmental costs of $364 million, and we expect to incur a substantial amount of these expenditures within the next 30 years. At December 31, 2011, accrued environmental costs were $922 million, of which $542 million related to the Downstream business.

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. Our cost of compliance with the EU ETS in 2012 was approximately $10 million (pre-tax equity share).

   

A regulation issued by the Alberta government in 2007 under the Climate Change and Emissions Act. The regulation requires 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 beginning July 1, 2007 by 12 percent. New facilities must reduce 2 percent per year until they reach the maximum target of 12 percent. We also incur a carbon tax for emissions from fossil fuel combustion in our British Columbia operations. The total cost of compliance with these Canadian regulations in 2012 was approximately $7 million.

 

60


Table of Contents
   

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. Our cost of compliance with Norwegian carbon tax legislation in 2012 was approximately $20 million (equity share pre-tax). In October 2012 the Norwegian government announced a doubling of the carbon tax for oil and gas production in 2013. Cap and trade programs in certain jurisdictions, including the Australian Clean Energy Legislation which took effect from July 2012. Our annual cost of compliance with the Australian Clean Energy Legislation during the initial fixed price phase is approximately $10 million (equity share pre-tax).

In the United States, some additional form of regulation may be forthcoming in the future at the federal and state levels with respect to GHG emissions. Such regulation could take any of several forms that may result in the creation of additional costs in the form of taxes, the restriction of output, investments of capital to maintain compliance with laws and regulations, or required acquisition or trading of emission allowances. We are working to continuously improve operational and energy efficiency through resource and energy conservation throughout our operations.

Compliance with changes in laws and regulations that create a GHG emission trading scheme or GHG reduction policies could significantly increase our costs, reduce demand for fossil energy derived products, impact the cost and availability of capital and increase our exposure to litigation. Such laws and regulations could also increase demand for less carbon intensive energy sources, including natural gas. The ultimate impact on our financial performance, either positive or negative, will depend on a number of factors, including but not limited to:

 

   

Whether and to what extent legislation is enacted.

   

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

   

The price placed on GHG emissions (either by the market or through a tax).

   

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.

 

61


Table of Contents

The Company has responded by putting in place a corporate Climate Change Action Plan, together with individual business unit climate change management plans in order to undertake actions in four major areas:

 

   

Equipping the Company for a low emission world, for example by integrating GHG forecasting and reporting into company procedures; utilizing GHG pricing in planning economics; developing systems to handle GHG market transactions.

   

Reducing GHG emissions—In 2011 the Company reduced GHG emissions by 600,000 tonnes by carrying out a range of programs across a number of business units.

   

Evaluating business opportunities such as the creation of offsets and allowances; carbon capture and storage; the use of low carbon energy and the development of low carbon technologies.

   

Engaging externally—The Company is a sponsor of MIT’s Joint Program on the Science and Policy of Global Change; constructively engages in the development of climate change legislation and regulation; and discloses our progress and performance through the Carbon Disclosure Project and the Dow Jones Sustainability Index.

The Company uses an estimated market cost of GHG emissions in the range of $8 to $46 per tonne depending on the timing and country or region to evaluate future opportunities.

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 the net deferred tax assets will be realized as offsets to reversing deferred tax liabilities and as reductions in future taxable income.

 

62


Table of Contents

CRITICAL ACCOUNTING ESTIMATES

The preparation of financial statements in conformity with generally accepted accounting principles requires management to select appropriate accounting policies and to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. See Note 1—Accounting Policies, in the Notes to Consolidated Financial Statements, for descriptions of our major accounting policies. Certain of these accounting policies involve judgments and uncertainties to such an extent there is a reasonable likelihood materially different amounts would have been reported under different conditions, or if different assumptions had been used. These critical accounting estimates are discussed with the Audit and Finance Committee of the Board of Directors at least annually. We believe the following discussions of critical accounting estimates, along with the discussions of contingencies and of deferred tax asset valuation allowances in this report, address all important accounting areas where the nature of accounting estimates or assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change.

Oil and Gas Accounting

Accounting for oil and gas exploratory activity is subject to special accounting rules unique to the oil and gas industry. The acquisition of geological and geophysical seismic information, prior to the discovery of proved reserves, is expensed as incurred, similar to accounting for research and development costs. However, leasehold acquisition costs and exploratory well costs are capitalized on the balance sheet pending determination of whether proved oil and gas reserves have been discovered on the prospect.

Property Acquisition Costs

For individually significant leaseholds, management periodically assesses for impairment based on exploration and drilling efforts to date. For leasehold acquisition costs that individually are relatively small, management exercises judgment and determines a percentage probability that the prospect ultimately will fail to find proved oil and gas reserves and pools that leasehold information with others in the geographic area. For prospects in areas that have had limited, or no, previous exploratory drilling, the percentage probability of ultimate failure is normally judged to be quite high. This judgmental percentage is multiplied by the leasehold acquisition cost, and that product is divided by the contractual period of the leasehold to determine a periodic leasehold impairment charge that is reported in exploration expense.

This judgmental probability percentage is reassessed and adjusted throughout the contractual period of the leasehold based on favorable or unfavorable exploratory activity on the leasehold or on adjacent leaseholds, and leasehold impairment amortization expense is adjusted prospectively. At year-end 2012, 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 $1,915 million and the accumulated impairment reserve was $517 million. The weighted-average judgmental percentage probability of ultimate failure was approximately 46 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 2013 would increase by approximately $30 million. At year-end 2012, the remaining $6,576 million of gross capitalized unproved property costs consisted of individually significant leaseholds, mineral rights held in perpetuity by title ownership, exploratory wells currently being drilled, 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 commercialization. Of this amount, approximately $3 billion is concentrated in 10 major development areas. These major assets are not expected to move to proved properties in 2013.

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.

 

63


Table of Contents

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 development economically profitable. Often, the ability to move into the development phase and record proved reserves is dependent on obtaining permits and government or co-venturer approvals, the timing of which is ultimately beyond our control. Exploratory well costs remain suspended as long as we are actively pursuing such approvals and permits, and believe they will be obtained. Once all required approvals and permits have been obtained, the projects are moved into the development phase, and the oil and gas reserves are designated as proved reserves. For complex exploratory discoveries, it is not unusual to have exploratory wells remain suspended on the balance sheet for several years while we perform additional appraisal drilling and seismic work on the potential oil and gas field or while we seek government or co-venturer approval of development plans or seek environmental permitting. Once a determination is made the well did not encounter potentially economic oil and gas quantities, the well costs are expensed as a dry hole and reported in exploration expense.

Management reviews suspended well balances quarterly, continuously monitors the results of the additional appraisal drilling and seismic work, and expenses the suspended well costs as a dry hole when it determines the potential field does not warrant further investment in the near term. Criteria utilized in making this determination include evaluation of the reservoir characteristics and hydrocarbon properties, expected development costs, ability to apply existing technology to produce the reserves, fiscal terms, regulations or contract negotiations, and our required return on investment.

At year-end 2012, total suspended well costs were $1,038 million, compared with $1,037 million at year-end 2011. For additional information on suspended wells, including an aging analysis, see Note 7—Suspended Wells, in the Notes to Consolidated Financial Statements.

Proved Reserves

Engineering estimates of the quantities of proved reserves are inherently imprecise and represent only approximate amounts because of the judgments involved in developing such information. Reserve estimates are based on geological and engineering assessments of in-place hydrocarbon volumes, the production plan, historical extraction recovery and processing yield factors, installed plant operating capacity and approved operating limits. The reliability of these estimates at any point in time depends on both the quality and quantity of the technical and economic data and the efficiency of extracting and processing the hydrocarbons.

Despite the inherent imprecision in these engineering estimates, accounting rules require disclosure of “proved” reserve estimates due to the importance of these estimates to better understand the perceived value and future cash flows of a company’s operations. There are several authoritative guidelines regarding the engineering criteria that must be met before estimated reserves can be designated as “proved.” Our reservoir engineering organization has policies and procedures in place consistent with these authoritative guidelines. We have trained and experienced internal engineering personnel who estimate our proved reserves held by consolidated companies, as well as our share of equity affiliates.

Proved reserve estimates are adjusted annually in the fourth quarter and during the year if significant changes occur, and take into account recent production and subsurface information about each field. Also, as required by current authoritative guidelines, the estimated future date when a field will be permanently shut down for economic reasons is based on 12-month average prices and year-end costs. This estimated date when production will end affects the amount of estimated reserves. Therefore, as prices and cost levels change from year to year, the estimate of proved reserves also changes.

Our proved reserves include estimated quantities related to production sharing contracts, which are reported under the “economic interest” method and are subject to fluctuations in commodity prices; recoverable operating expenses; and capital costs. If costs remain stable, reserve quantities attributable to recovery of costs will change inversely to changes in commodity prices. For example, if prices increase, then our applicable reserve quantities would decline. The estimation of proved developed reserves also is important to the income

 

64


Table of Contents

statement because the proved developed reserve estimate for a field serves as the denominator in the unit-of-production calculation of the DD&A of the capitalized costs for that asset. At year-end 2012, the net book value of productive properties, plants and equipment (PP&E) subject to a unit-of-production calculation was approximately $55 billion and the DD&A recorded on these assets in 2012 was approximately $6.4 billion. The estimated proved developed reserves for our consolidated operations were 5.1 billion BOE at the end of 2011 and 4.9 billion BOE at the end of 2012. 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 2012 would have increased by an estimated $336 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 there is an indication the carrying amount of an asset may not be recovered, the asset is monitored by management through an established process where changes to significant assumptions such as prices, volumes and future development plans are reviewed. If, upon review, the sum of the undiscounted pretax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value. Individual assets are grouped for impairment purposes based on a judgmental assessment of the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets—generally on a field-by-field basis for exploration and production assets. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants, or based on a multiple of operating cash flow validated with historical market transactions of similar assets where possible. The expected future cash flows used for impairment reviews and related fair value calculations are based on judgmental assessments of future production volumes, commodity prices, operating costs and capital decisions, considering all available information at the date of review. See Note 9—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, as well as oil and gas production facilities and pipelines in Alaska. The fair values of obligations for dismantling and removing these facilities are accrued into PP&E at the time of 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

 

65


Table of Contents

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 environmental-related projects. These are primarily related to remediation activities required by Canada and various states within the United States at exploration and production sites. Future environmental remediation costs are difficult to estimate because they are subject to change due to such factors as the uncertain magnitude of cleanup costs, the unknown time and extent of such remedial actions that may be required, and the determination of our liability in proportion to that of other responsible parties.

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 $50 million. In determining the discount rate, we use yields on high-quality fixed income investments matched to the estimated benefit cash flows of our plans. We are also exposed to the possibility that lump sum retirement benefits taken from pension plans during the year could exceed the total of service and interest components of annual pension expense and trigger accelerated recognition of a portion of unrecognized net actuarial losses and gains. These benefit payments are based on decisions by plan participants and are therefore difficult to predict.

 

66


Table of Contents

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.

   

Potential failures or delays in achieving expected reserve or production levels from existing and future oil and gas developments 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.

   

Unexpected changes in costs or technical requirements for constructing, modifying or operating exploration and production facilities.

   

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

   

Inability to timely obtain or maintain permits, including those necessary for drilling and/or development, construction of LNG terminals or regasification facilities; 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 and LNG development.

   

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 or natural gas liquids pricing, regulation or taxation; other political, economic or diplomatic developments; and international monetary fluctuations.

   

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

   

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

   

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

   

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

   

The operation and financing of our joint ventures.

   

The factors generally described in Item 1A—Risk Factors in this report.

 

67


Table of Contents

Item 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Financial Instrument Market Risk

We and certain of our subsidiaries hold and issue derivative contracts and financial instruments that expose our cash flows or earnings to changes in commodity prices, foreign currency exchange rates or interest rates. We may use financial and commodity-based derivative contracts to manage the risks produced by changes in the prices of 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 Executive Vice President of Commercial, Business Development and Corporate Planning 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.

Commodity Price Risk

Our Commercial organization uses futures, forwards, swaps and options in various markets to accomplish the following objectives:

 

   

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 consumers, to floating market prices.

   

Enable us to use the market knowledge gained from these activities to capture market opportunities such as moving physical commodities to more profitable locations and storing commodities to capture seasonal or time premiums. We may use derivatives to optimize these activities.

We use a VaR model to estimate the loss in fair value that could potentially result on a single day from the effect of adverse changes in market conditions on the derivative financial instruments and derivative commodity instruments we hold or issue, including commodity purchases and sales contracts recorded on the balance sheet at December 31, 2012, 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, 2012 and 2011, 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, 2012 and 2011, 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 2012 and 2011 effective yield rates of 0.7 percent and 1.24 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.

 

68


Table of Contents
     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 2012

               

2013

   $ 850        5.75  %    $ 91        0.25  %    $ 772        5.30

2014

     400        4.75       -         -       814        5.30  

2015

     1,500        4.60       -         -       858        5.30  

2016

     1,273        5.52       964        0.25       904        5.30  

2017

     1,001        1.06       -         -       234        5.30  

Remaining years

     14,918        6.25       283        0.19       -        5.30  

 

 

Total

   $ 19,942        $ 1,338        $ 3,582     

 

 

Fair value

   $ 25,011        $ 1,338        $ 3,968     

 

 

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     

 

 

Foreign Currency Exchange Risk

We have foreign currency exchange rate risk resulting from international operations. We do not comprehensively hedge the exposure to currency exchange 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, 2012 and 2011, we held foreign currency exchange forwards hedging cross-border commercial activity and foreign currency exchange swaps for purposes of mitigating our cash related exposures. 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 related cash balances, 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, 2012, or 2011, exchange rates. The notional and fair market values of these positions at December 31, 2012 and 2011, were as follows:

 

69


Table of Contents
     In Millions  
Foreign Currency Exchange Derivatives    Notional*      Fair Market Value**  
            2012      2011      2012     2011  
  

 

 

    

 

 

 

Sell U.S. dollar, buy euro

     USD         -        219      $ -       (8)   

Sell U.S. dollar, buy British pound

     USD         2,573                    790                    31         

Sell U.S. dollar, buy Canadian dollar

     USD         -        648        -                   -    

Sell U.S. dollar, buy Norwegian krone

     USD         -        292        -       (7)   

Buy U.S. dollar, sell euro

     USD         7        -        -         

Buy U.S. dollar, sell Norwegian krone

     USD         90        -        -         

Buy U.S. dollar, sell Canadian dollar

     USD         43        -        (2       

Buy euro, sell Norwegian krone

     EUR         -        3        -         

Buy euro, sell British pound

     EUR         96        -        -         

Sell euro, buy British pound

     EUR         -        64        -         

 

 

  *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.

 

70


Table of Contents

Item 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

CONOCOPHILLIPS

INDEX TO FINANCIAL STATEMENTS

 

     Page  

Report of Management

     72   

Report of Independent Registered Public Accounting Firm on Consolidated Financial Statements

     73   

Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting

     74   

Consolidated Income Statement for the years ended December 31, 2012, 2011 and 2010

     75   

Consolidated Statement of Comprehensive Income for the years ended December 31, 2012, 2011 and 2010

     76   

Consolidated Balance Sheet at December 31, 2012 and 2011

     77   

Consolidated Statement of Cash Flows for the years ended December 31, 2012, 2011 and 2010

     78   

Consolidated Statement of Changes in Equity for the years ended December 31, 2012, 2011 and 2010

     79   

Notes to Consolidated Financial Statements

     80   

Supplementary Information

  

Oil and Gas Operations

     135   

Selected Quarterly Financial Data

     165   

Condensed Consolidating Financial Information

     166   

 

71


Table of Contents

 

Report of Management

Management prepared, and is responsible for, the consolidated financial statements and the other information appearing in this annual report. The consolidated financial statements present fairly the company’s financial position, results of operations and cash flows in conformity with accounting principles generally accepted in the United States. In preparing its consolidated financial statements, the company includes amounts that are based on estimates and judgments management believes are reasonable under the circumstances. The company’s financial statements have been audited by Ernst & Young LLP, an independent registered public accounting firm appointed by the Audit and Finance Committee of the Board of Directors and ratified by stockholders. Management has made available to Ernst & Young LLP all of the company’s financial records and related data, as well as the minutes of stockholders’ and directors’ meetings.

Assessment of Internal Control Over Financial Reporting

Management is also responsible for establishing and maintaining adequate internal control over financial reporting. ConocoPhillips’ internal control system was designed to provide reasonable assurance to the company’s management and directors regarding the preparation and fair presentation of published financial statements.

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

Management assessed the effectiveness of the company’s internal control over financial reporting as of December 31, 2012. 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, 2012.

Ernst & Young LLP has issued an audit report on the company’s internal control over financial reporting as of December 31, 2012, and their report is included herein.

 

/s/ Ryan M. Lance

     /s/ Jeff W. Sheets

Ryan M. Lance

     Jeff W. Sheets

Chairman and

     Executive Vice President, Finance

Chief Executive Officer

     and Chief Financial Officer

February 19, 2013

 

72


Table of Contents

 

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, 2012 and 2011, 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, 2012. Our audits also included the related condensed consolidating financial information listed in the Index at Item 8 and financial statement schedule listed in Item 15(a). These financial statements, condensed consolidating financial information, and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements, condensed consolidating financial information, and schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of ConocoPhillips at December 31, 2012 and 2011, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related condensed consolidating financial information and financial statement schedule, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects the information set forth therein.

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, 2012, 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 19, 2013 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Houston, Texas

February 19, 2013

 

73


Table of Contents

 

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, 2012, 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, 2012, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the 2012 consolidated financial statements of ConocoPhillips and our report dated February 19, 2013 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Houston, Texas

February 19, 2013

 

74


Table of Contents
Consolidated Income Statement      ConocoPhillips   

 

<
Years Ended December 31    Millions of Dollars  
     2012       2011       2010  
  

 

 

 

Revenues and Other Income

      

Sales and other operating revenues

   $ 57,967       64,196       56,215   

Equity in earnings of affiliates

     1,911       1,239       1,376   

Gain on dispositions

     1,657       370       5,563   

Other income

     469       264       181   

 

 

Total Revenues and Other Income

     62,004       66,069       63,335   

 

 

Costs and Expenses

      

Purchased commodities

     25,232       29,797       24,854   

Production and operating expenses

     6,793       6,426       6,227   

Selling, general and administrative expenses

     1,106       865       809   

Exploration expenses

     1,500       1,038       1,125   

Depreciation, depletion and amortization

     6,580       6,827       8,004   

Impairments

     680       321       81   

Taxes other than income taxes

     3,546       3,999       2,788   

Accretion on discounted liabilities

     394       422       409   

Interest and debt expense

     709       954       1,167   

Foreign currency transaction (gains) losses

     41       24       (4)   

 

 

Total Costs and Expenses

     46,581       50,673       45,460   

 

 

Income from continuing operations before income taxes

     15,423       15,396       17,875   

Provision for income taxes

     7,942       8,208       7,570   

 

 

Income From Continuing Operations

     7,481       7,188       10,305   

Income from discontinued operations*

     1,017       5,314       1,112   

 

 

Net income

     8,498       12,502       11,417   

Less: net income attributable to noncontrolling interests

     (70     (66     (59)   

 

 

Net Income Attributable to ConocoPhillips

   $ 8,428       12,436       11,358   

 

 

Amounts Attributable to ConocoPhillips Common Shareholders:

      

Income from continuing operations

   $ 7,413       7,127       10,251   

Income from discontinued operations

     1,015       5,309       1,107   

 

 

Net Income

   $ 8,428       12,436       11,358   

 

 

Net Income Attributable to ConocoPhillips Per Share
of Common Stock
(dollars)

      

Basic

      

Continuing operations

   $ 5.95       5.18       6.93   

Discontinued operations

     0.82       3.86       0.75   

 

 

Net Income Attributable to ConocoPhillips Per Share of Common Stock

   $ 6.77       9.04       7.68   

 

 

Diluted

      

Continuing operations

   $ 5.91       5.14       6.88   

Discontinued operations

     0.81       3.83       0.74   

 

 

Net Income Attributable to ConocoPhillips Per Share of Common Stock

   $ 6.72       8.97       7.62   

 

 

Dividends Paid Per Share of Common Stock (dollars)

   $ 2.64       2.64       2.15   

 

 

Average Common Shares Outstanding (in thousands)

      

Basic

         1,243,799       1,375,035       1,479,330   

Diluted