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SECURITIES AND EXCHANGE COMMISSION
(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, 2007 | |
[ ] | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) | ||
OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from | to | |||||
Delaware | 01-0562944 | |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) |
Houston, TX 77079
(Address of principal executive offices)
Name of each exchange | ||||
Title of each class | on which registered | |||
Common Stock, $.01 Par Value | New York Stock Exchange | |||
Preferred Share Purchase Rights Expiring June 30, 2012 | New York Stock Exchange | |||
6.375% Notes due 2009 | New York Stock Exchange | |||
6.65% Debentures due July 15, 2018 | New York Stock Exchange | |||
7% Debentures due 2029 | New York Stock Exchange | |||
7.125% Debentures due March 15, 2028 | New York Stock Exchange | |||
9 3/8% Notes due 2011 | New York Stock Exchange |
[x] Large accelerated filer | [ ] Accelerated filer | [ ] Non-accelerated filer | [ ] Smaller reporting company |
Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held on May 14, 2008 (Part III)
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Form of Stock Option Award Agreement | ||||||||
Form of Restricted Stock Unit Award Agreement | ||||||||
Omnibus Amendments | ||||||||
Computation of Ratio of Earnings to Fixed Charges | ||||||||
List of Subsidiaries | ||||||||
Consent of Independent Registered Public Accounting Firm | ||||||||
Certification of Chief Executive Officer Pursuant to Rule 13a-14(a) | ||||||||
Certification of Chief Financial Officer Pursuant to Rule 13a-14(a) | ||||||||
Certifications Pursuant to 18 U.S.C. Section 1350 |
Table of Contents
• | Exploration and Production (E&P)—This segment primarily explores for, produces, transports and markets crude oil, natural gas and natural gas liquids on a worldwide basis. | ||
• | Midstream—This segment gathers, processes and markets natural gas produced by ConocoPhillips and others, and fractionates and markets natural gas liquids, primarily in the United States and Trinidad. The Midstream segment primarily consists of our 50 percent equity investment in DCP Midstream, LLC. | ||
• | Refining and Marketing (R&M)—This segment purchases, refines, markets and transports crude oil and petroleum products, mainly in the United States, Europe and Asia. | ||
• | LUKOIL Investment—This segment consists of our equity investment in the ordinary shares of OAO LUKOIL (LUKOIL), an international, integrated oil and gas company headquartered in Russia. At December 31, 2007, our ownership interest was 20 percent based on issued shares, and 20.6 percent based on estimated shares outstanding. | ||
• | Chemicals—This segment manufactures and markets petrochemicals and plastics on a worldwide basis. The Chemicals segment consists of our 50 percent equity investment in Chevron Phillips Chemical Company LLC (CPChem). | ||
• | Emerging Businesses—This segment represents our investment in new technologies or businesses outside our normal scope of operations. |
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• | Proved worldwide crude oil, natural gas and natural gas liquids reserves. | ||
• | Net production of crude oil, natural gas and natural gas liquids. | ||
• | Average sales prices of crude oil, natural gas and natural gas liquids. | ||
• | Average production costs per barrel-of-oil-equivalent. | ||
• | Net wells completed, wells in progress, and productive wells. | ||
• | Developed and undeveloped acreage. |
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Greater Prudhoe Area
The Greater Prudhoe Area is comprised of the Prudhoe Bay field and satellites, as well as the Greater Point McIntyre Area fields. We have a 36.1 percent non-operator interest in all fields within the Greater Prudhoe Area.
We operate the Greater Kuparuk Area, which is comprised of the Kuparuk field and four satellite fields: Tarn, Tabasco, Meltwater, and West Sak. Field installations include three central production facilities that separate oil, natural gas and water. The natural gas is either used for fuel or compressed for re-injection.
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The Alpine field, located west of the Kuparuk field, produced at a net rate of 59,200 barrels of oil per day in 2007, compared with 74,100 barrels per day in 2006. We are the operator and hold a 78 percent interest in Alpine and two satellite fields.
Our assets in Alaska also include the North Cook Inlet field, the Beluga River field, and the Kenai liquefied natural gas (LNG) facility, all of which we operate.
In 2007, we drilled six exploration wells. Two wells were classified as dry holes and four wells encountered commercial quantities of oil. One of the successful wells is located in the West Sak field, and three are in the Tarn field. We also acquired more than 2,360 square kilometers of 3D seismic and were the successful bidder in two lease sales, acquiring two lease blocks covering 8,253 acres.
We transport the petroleum liquids produced on the North Slope to market through the Trans-Alaska Pipeline System (TAPS). TAPS is comprised of an 800-mile pipeline, marine terminal, spill response and escort vessel system that ties the North Slope of Alaska to the port of Valdez in south-central Alaska.
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Gulf of Mexico
At year-end 2007, our portfolio of producing properties in the Gulf of Mexico included one operated field and five fields operated by our co-venturers.
Our 2007 onshore production primarily consisted of natural gas, with the majority of production located in the San Juan Basin, the Permian Basin, the Lobo Trend, the Bossier Trend, and the Panhandles of Texas and Oklahoma. We also have operations in the Wind River, Anadarko, and Fort Worth Basins, as well as east Texas and north and south Louisiana. We have other onshore properties in the Williston Basin, the Piceance Basin, and the Cedar Creek Anticline.
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In June 2006, we acquired a 24 percent interest in West2East Pipeline LLC, a company holding a 100 percent interest in Rockies Express Pipeline LLC (Rockies Express). Rockies Express plans to construct a 1,679-mile natural gas pipeline from Colorado to Ohio. The pipeline is expected to be completed in 2009.
In the Lower 48 states, we own undeveloped mineral interests in 7.6 million net acres and hold leases on 2.2 million undeveloped net acres. In 2007, we successfully completed 81 gross exploration wells. Areas of focus in 2007 included the east Texas Bossier Trend, deepwater Gulf of Mexico, Bakken play in the Williston Basin, and the Barnett Trend in the Fort Worth Basin. Other areas with active exploration drilling programs included the Anadarko and Piceance Basins, and south Texas.
The Greater Ekofisk Area, located approximately 200 miles offshore Norway in the center of the North Sea, is composed of four producing fields: Ekofisk, Eldfisk, Embla, and Tor. The Ekofisk complex serves as a hub for petroleum operations in the area, with surrounding developments utilizing the Ekofisk infrastructure. Net production in 2007 from the Greater Ekofisk Area was 102,700 barrels of liquids per day and 103 million cubic feet of natural gas per day, compared with 121,700 barrels of liquids per day and 123 million cubic feet of natural gas per day in 2006. We are the operator and hold a 35.1 percent interest in Ekofisk.
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We have interests in the transportation and processing infrastructure in the Norwegian North Sea, including a 35.1 percent interest in the Norpipe Oil Pipeline System and a 2.2 percent interest in Gassled, which owns most of the Norwegian gas transportation system.
In 2007, we participated in one appraisal well and four exploration wells within the Oseberg licenses of the northern North Sea, license PL018 of the Greater Ekofisk Area, and PL281 in the Moere Basin of the Norwegian Sea. Drilling operations extended into 2008 on two of these wells, one of which concluded operations and was expensed as a dry hole in the first quarter of 2008. Drilling operations continue on the other well. Hydrocarbons were encountered in all three wells whose drilling operations were completed by the end of the year. One of these wells was successful and the remaining two wells are being evaluated.
We have a 58.7 percent interest in the Britannia natural gas and condensate field, and own 50 percent of Britannia Operator Limited, the operator of the field. Our net production from Britannia averaged 252 million cubic feet of natural gas per day and 10,300 barrels of liquids per day in 2007, compared with 246 million cubic feet of natural gas per day and 10,100 barrels of liquids per day in 2006.
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The Interconnector pipeline, which connects the United Kingdom and Belgium, facilitates marketing natural gas produced in the United Kingdom throughout Europe. Our 10 percent equity share of the Interconnector pipeline allows us to ship approximately 200 million net cubic feet of natural gas per day to markets in continental Europe, and our reverse-flow rights provide an 85 million net cubic feet per day of natural gas import capability to the United Kingdom.
In 2007, we participated in five appraisal wells and four exploration wells and were awarded an interest in one North Sea exploration license in the North Sea—P1423.
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We sold our ownership interests in the Danish sector of the North Sea in 2007.
We have varying non-operated production interests in the Dutch sector of the North Sea, as well as interests in offshore pipelines and an onshore gas plant and terminal at Den Helder. Net production in 2007 averaged 52 million cubic feet of natural gas per day, compared with 34 million cubic feet of natural gas per day in 2006.
In 2007, we participated in one exploration well and one appraisal well in the southern North Sea, both of which encountered hydrocarbons. The exploration well, located within the JDA K15 license, was successfully completed and began production in 2007. The appraisal well, located within the E18a license, appraised additional potential to a 2006 discovery. The well was successful and a field development plan is being progressed.
Western Canada
Operations in western Canada encompass properties in Alberta, northeastern British Columbia and southern Saskatchewan. The properties in northern Alberta and northeastern British Columbia contain a mix of oil and natural gas, and are primarily accessible only in the winter. The properties in the central and foothills areas of Alberta mainly produce natural gas. The properties in southern Alberta and southern Saskatchewan produce natural gas and medium-to-heavy oil. Net production from these oil and gas operations in western Canada averaged 46,000 barrels per day of liquids and 1,106 million cubic feet per day of natural gas in 2007, compared with 50,000 barrels per day of liquids and 983 million cubic feet per day of natural gas in 2006.
We have a 50 percent operating interest in the Surmont lease, located approximately 35 miles south of Fort McMurray, Alberta. The Surmont project uses an enhanced thermal oil recovery method called steam-assisted gravity drainage (SAGD). Steam injection began in the second quarter of 2007, and first production was achieved in the fourth quarter of 2007. Peak production is expected in 2014. We anticipate processing our share of the heavy oil produced as a feedstock in our owned and affiliated U.S. refineries.
In October 2006, we announced a business venture with EnCana Corporation (EnCana), to create an integrated North American heavy-oil business. The transaction closed on January 3, 2007. The venture
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We are working with three other energy companies, as members of the Mackenzie Delta Producers’ Group, on the development of the Mackenzie Valley pipeline and gathering system, which is 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 gas field, one of the primary fields in the Mackenzie Delta that would anchor the pipeline development. This pipeline project faces significant regulatory and construction cost issues; therefore, no definitive startup date can be estimated at this time.
We hold exploration acreage in four areas of Canada: the Western Canada Sedimentary Basin, offshore eastern Canada, the Mackenzie Delta/Beaufort Sea, and the Arctic Islands. Within the Western Canada Sedimentary Basin, we hold exploration acreage throughout the basin, including the foothills of western Alberta and eastern British Columbia. In the foothills, we drilled three exploratory wells in 2007—two will be completed as producing wells and one will be tested and evaluated. During 2007, we also drilled three exploratory wells on acreage in the central Alberta Nisku project that resulted in one producer, while the remaining wells were expensed as dry holes. One successful exploration well was drilled in late 2007 on a recently defined Montney gas prospect in northeast British Columbia. Throughout the rest of western Canada, we participated in drilling approximately 48 lower risk exploratory wells near our producing assets. In the Mackenzie Delta, we were successful in acquiring additional offshore acreage following the 2004 Umiak discovery.
Syncrude Canada Ltd.
We own a 9 percent interest in the Syncrude Canada Ltd. (SCL) joint venture, created for the purpose of mining shallow deposits of oil sands, extracting the bitumen, and upgrading it into a light sweet crude oil called Syncrude. The primary plant and facilities are located at Mildred Lake, about 25 miles north of Fort McMurray, Alberta, with an auxiliary mining and extraction facility approximately 20 miles from the Mildred Lake plant. SCL, as operator of the joint venture, holds eight oil sands leases and the associated surface rights, of which our share is approximately 22,400 net acres. Our net share of production averaged 23,400 barrels per day in 2007, compared with 21,100 barrels per day in 2006.
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Petrozuata, Hamaca and Corocoro
On June 26, 2007, we announced we had been unable to reach agreement with respect to our migration to anempresa mixtastructure mandated by the Nationalization Decree. In response, Petróleos de Venezuela S.A. (PDVSA) or its affiliates directly assumed the activities associated with and control over ConocoPhillips’ interests in the Petrozuata and Hamaca heavy-oil ventures and the offshore Corocoro development project.
We have a 40 percent interest in Plataforma Deltana Block 2. The block is operated by our co-venturer and holds a gas discovery made by PDVSA in 1983. PDVSA has the option to enter the project with a 35 percent interest, which would proportionately reduce our interest in the project to 26 percent. In December 2007, the co-venturers presented the notification of commerciality and submitted a conditional development plan for governmental approval in compliance with license requirements. Several critical components required to progress an investment decision have not yet been defined by the government. Assuming timely resolution of these components, we expect a preliminary engineering study could be completed by late 2008, and a more significant developmental engineering study could be completed by late 2009.
In Ecuador, we hold a 42.5 percent interest in Block 7 and a 46.25 percent interest in Block 21. Net production in 2007 averaged 10,300 barrels of crude oil per day, compared with 6,800 barrels per day in 2006.
We have a 25.7 percent interest in the producing Sierra Chata concession in Argentina. Net production in 2007 averaged 19 million cubic feet of natural gas per day, compared with 17 million cubic feet per day in 2006.
We have varying ownership interests in six exploration blocks in Peru. In the first quarter of 2007, we acquired a 100 percent interest in Block 129. In Block 57, we drilled one exploration well that encountered hydrocarbons.
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We operate seven production sharing contracts (PSCs) in Indonesia. Production from Indonesia in 2007 averaged a net 330 million cubic feet per day of natural gas and 11,800 barrels per day of oil, compared with 319 million cubic feet per day of natural gas and 12,400 barrels per day of oil in 2006. Natural gas is sold under long-term contracts benchmarked to crude oil prices to markets in Indonesia and Singapore. Natural gas is also sold to the Indonesian domestic markets under U.S.-dollar-denominated, fixed-price contracts. Our assets are concentrated in two core areas: the West Natuna Sea and onshore South Sumatra.
We operate four offshore PSCs: South Natuna Sea Block B, Ketapang, Amborip VI, and Kuma. We sold our 25 percent non-operator interest in the Pangkah PSC, offshore East Java, in the third quarter of 2007.
We operate three onshore PSCs. Two are in South Sumatra: Corridor PSC and South Jambi B.We also operate Warim in Papua. In January 2007, we sold our 50 percent working interest in the Block A PSC in North Sumatra, and we sold our 60 percent interest in Corridor TAC in September 2007. In November 2007, the Sakakemang Joint Operating Body expired. We also transferred our non-operator interest in the Banyumas PSC in Java to our partners effective January 2008.
We are a 35 percent owner of TransAsia Pipeline Company Pvt. Ltd., a consortium company, which has a 40 percent ownership in PT Transportasi Gas Indonesia, an Indonesian limited liability company, which owns and operates the Grissik to Duri, and Grissik to Singapore, natural gas pipelines.
In January 2007, we signed a new PSC agreement for a 60 percent interest in the Kuma block, which is located in Makassar Straits, between the islands of Kalimantan and Sulawesi. The acreage contains multiple exploration targets. A 3D survey will commence on the Kuma PSC in 2008. In addition, exploration work will continue on the Amborip VI PSC. Exploration wells are being planned for drilling in 2009 on both of these PSCs.
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The Xijiang development consists of two fields located approximately 80 miles south of Hong Kong in the South China Sea. The facilities include two manned platforms and an FPSO vessel. Our combined net production of crude oil from the Xijiang fields averaged 7,900 barrels per day in 2007, compared with 10,100 barrels per day in 2006.
Our ownership interest in Vietnam is centered around the Cuu Long Basin in the South China Sea, and consists of two primarily oil producing blocks, four exploration blocks, and one gas pipeline transportation system.
We own a 16.3 percent interest in the Nam Con Son natural gas pipeline. This 244-mile transportation system links gas supplies from the Nam Con Son Basin to gas markets in southern Vietnam.
A successful appraisal well was drilled during 2007 in the Su Tu Nau field in the northeast area of Block 15-1. Further appraisal plans and potential development options for this field are currently being evaluated.
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Bayu-Undan
We operate and hold an ownership interest in the Bayu-Undan field located in the Timor Sea. In accordance with various governance agreements, a redetermination of the ownership interest in the Bayu-Undan Joint Venture, Darwin LNG Pty Ltd and the Bayu-Undan Pipeline Joint Venture was completed in 2007. The redetermination increased our controlling interest from 56.7 percent to 57.15 percent. The Bayu-Undan field was developed in two phases. Phase I was a gas-recycle project, where condensate and natural gas liquids were separated and removed and the dry gas was re-injected into the reservoir. This phase began production in February 2004, and averaged a net rate of 34,100 barrels of liquids per day in 2007, compared with 53,400 barrels per day in 2006.
We have a 30 percent interest in the Greater Sunrise gas and condensate field located in the Timor Sea. In January 2006, agreement was reached between the governments of Australia and Timor-Leste concerning sharing of revenues from the anticipated development of the Greater Sunrise field. In February 2007, the government of Timor-Leste ratified the International Unitisation Agreement (IUA) and the governments of Timor-Leste and Australia both ratified the treaty on Certain Maritime Arrangements in the Timor Sea. The Australian government ratified the IUA in 2004.
A cooperative field development agreement for the Athena/Perseus (WA-17-L) gas field, located offshore Western Australia, was executed in 2001. In 2007, our net share of production was 34 million cubic feet of natural gas per day, compared with 35 million cubic feet of natural gas per day in 2006. Early in the third quarter of 2007, abandonment of the Elang/Kakatua/Kakatua North fields commenced and production ceased.
We are the operator of the NT/P 69 and the NT/P 61 licenses, located offshore Northern Territory, Australia, which include the Caldita and Barossa discoveries. A Caldita appraisal well drilled in early 2007 encountered hydrocarbons, but it was expensed as a dry hole. Acquisition of seismic data concluded in 2007, and interpretation of this data will begin in 2008 to further evaluate these discoveries.
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Exploration
We have interests in deepwater Blocks G and J, located off the east Malaysian state of Sabah. In late 2007, we and our co-venturers sanctioned the Gumusut-Kakap field development that incorporates the 2003 Gumusut discovery in Block J. Also in 2007, we participated in two exploration wells. We had a discovery in the Petai field in Block G. Petai and previous Block G discoveries are being evaluated as part of a broader area development plan. One Block J well was expensed as a dry hole.
Qatargas 3 is an integrated project, jointly owned by Qatar Petroleum (68.5 percent), ConocoPhillips (30 percent) and Mitsui & Co., Ltd. (1.5 percent). The project comprises 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 the 25-year life of the project. The project also includes a 7.8-million-gross-ton-per-year LNG facility. The LNG will be shipped from Qatar in a fleet of LNG vessels, and is destined for sale primarily in the United States. The first LNG cargos are expected to be loaded from Qatargas 3 in 2009.
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Our oil concession offshore Dubai ended effective April 2007.
We have interests in three fields in Block 405a: a 65 percent operating interest in the Menzel Lejmat North (MLN) field; a 3.73 percent interest in the Ourhoud field; and a 16.9 percent interest in the EMK (El Merk) oil field unit. Net production from these fields averaged 10,800 barrels of crude oil per day in 2007, compared with 9,800 barrels per day in 2006.
ConocoPhillips holds a 16.33 percent interest in the Waha concessions in Libya. The concessions encompass nearly 13 million acres located in the Sirte Basin. Net crude oil production averaged 46,900 barrels per day in 2007, compared with 50,400 barrels per day in 2006, including 3,800 barrels per day associated with the complete recovery of our 1986 underlift position.
During the first quarter of 2007, we sold our 50 percent non-operated interest in a concession in Egypt that included the development of the Tao gas field and its associated facilities.
At year-end 2007, we were producing from four onshore Oil Mining Leases (OMLs), in which we have a 20 percent non-operator interest. Our net production from these leases was 19,300 barrels of liquids per day and 117 million cubic feet of natural gas per day in 2007, compared with 24,500 barrels per day and 138 million cubic feet per day in 2006. In 2007, we continued development of projects in the onshore OMLs to supply feedstock natural gas under a gas sales contract with Nigeria LNG Limited, which owns an LNG facility on Bonny Island.
During 2007, we made an onshore exploration discovery in OML 61, and the well is now producing. During the fourth quarter of 2007, we initiated drilling of an appraisal well in deepwater Oil Prospecting License (OPL) 214. The well encountered hydrocarbons, and drilling operations concluded in the first quarter of 2008. In the first quarter of 2007, we recorded a leasehold impairment related to OPL 248. In the second quarter of 2007, we relinquished our interest in OPL 318.
Polar Lights
We have a 50 percent equity ownership interest in Polar Lights Company, a Russian limited liability company established in January 1992 to develop fields in the Timan-Pechora Basin in northern Russia.
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In June 2005, ConocoPhillips and LUKOIL created the OOO Naryanmarneftegaz (NMNG) joint venture to develop resources in the northern part of Russia’s Timan-Pechora province. We have a 30 percent ownership interest with a 50 percent governance interest in NMNG. We use the equity method of accounting for this joint venture. NMNG is working to develop the Yuzhno Khylchuyu (YK) field.
In the Caspian Sea, we have a 9.26 percent interest in the Republic of Kazakhstan’s North Caspian Sea Production Sharing Agreement (NCSPSA), which includes the Kashagan field. Detailed design, procurement and construction activities continued on the Kashagan oil field development following approval by the Republic of Kazakhstan for the development plan and budget in 2004. The first phase of field development currently being executed includes the construction of artificial drilling islands with processing facilities and living quarters, and pipelines to carry production onshore. The initial production phase of the contract is for 20 years, with options to extend the agreement an additional 20 years. During 2007, the Republic of Kazakhstan triggered dispute proceedings under the NCSPSA following submission of a revised development plan and budget reflecting Kashagan cost increases and schedule delays. The international co-venturers signed a Memorandum of Understanding in January 2008, agreeing to the proportional dilution of their equity interest to allow the state-owned energy company, JSC NC KazMunaiGaz, to increase its ownership interest from 8.33 percent to 16.81 percent, effective January 1, 2008, subject to the completion of definitive agreements on dilution and other matters. As a result, our interest in the NCSPSA would be reduced from 9.26 percent to 8.40 percent, effective January 2008. In addition, a joint operating company, with significant involvement from the larger owners, will operate future phases of Kashagan. First production is expected at the end of 2011.
We have a 2.5 percent interest in the Baku-Tbilisi-Ceyhan (BTC) pipeline. This 1,760-kilometer pipeline transports crude oil from the Caspian region through Azerbaijan, Georgia and Turkey, for tanker loadings at the Mediterranean port of Ceyhan. The BTC pipeline became operational in mid-2006.
In 2007, appraisal and development concept studies continued for Kalamkas More, Kairan and Aktote. Testing operations on a Kairan appraisal well drilled in 2006 were successfully completed. Concept studies for development are under way for all three fields.
In late 2003, we signed an agreement with Freeport LNG Development, L.P. (Freeport LNG) to participate in its proposed LNG receiving terminal in Quintana, Texas. This agreement gave us 1 billion cubic feet per day of regasification capacity in the terminal and a 50 percent interest in the general partnership managing the venture. The terminal is designed to have capacity of 1.5 billion cubic feet per day. Freeport LNG received final approval in 2005 from the Federal Energy Regulatory Commission (FERC) to construct and operate the facility. Construction began in 2005, and commercial startup is expected in
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The Commercial organization optimizes the commodity flows of our E&P segment. This group markets our crude oil and natural gas production, with commodity buyers, traders and marketers in offices in the United States, the United Kingdom, Singapore, Canada and Dubai.
Compared with the more global nature of crude oil commodity pricing, natural gas prices have historically varied more in different regions of the world. We produce natural gas from regions around the world that have significantly different supply, demand and regulatory circumstances, typically resulting in significantly lower average sales prices than in the Lower 48 region of the United States. Moreover, excess supply conditions that exist in certain parts of the world cannot easily serve to mitigate the relatively high-price conditions in the Lower 48 states and other markets because of a lack of infrastructure and because of the difficulties in transporting natural gas. We, along with other companies in the oil and gas industry, are planning long-term projects in regions of excess supply to install the infrastructure required to produce and liquefy natural gas for transportation by tanker and subsequent regasification in regions where market demand is strong, such as the Lower 48 states or certain parts of Asia, but where supplies are not as plentiful. Due to the significance of the overall investment in these long-term projects, the natural gas sales prices (to a third-party LNG facility) or transfer prices (to a company-owned LNG facility) in the areas of excess supply are expected to remain well below sales prices for natural gas that is produced closer to areas of high demand and which can be transferred to existing natural gas pipeline networks, such as in the Lower 48 states.
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• | A 50 percent interest in a natural gas liquids extraction plant in San Juan County, New Mexico. Our net share of plant inlet capacity is 275 million cubic feet per day. Effective January 1, 2008, our interest in this plant was moved to the E&P segment for reporting purposes. | ||
• | A 25,000-barrel-per-day capacity natural gas liquids fractionation plant in Gallup, New Mexico. | ||
• | A 22.5 percent equity interest in Gulf Coast Fractionators, which owns a natural gas liquids fractionation plant in Mont Belvieu, Texas (with our net share of capacity at 25,000 barrels per day). | ||
• | A 40 percent interest in a fractionation plant in Conway, Kansas (with our net share of capacity at 42,000 barrels per day). | ||
• | A 12.5 percent equity interest in a fractionation plant in Mont Belvieu, Texas (with our net share of capacity at 26,000 barrels per day). |
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Net Crude Throughput | ||||||||||||||
Capacity (MB/D) | ||||||||||||||
At | Effective | |||||||||||||
December 31 | January 1 | |||||||||||||
Refinery | Location | Region | 2007 | 2008 | ||||||||||
Bayway | Linden | New Jersey | East Coast | 238 | 238 | |||||||||
Trainer | Trainer | Pennsylvania | East Coast | 185 | 185 | |||||||||
423 | 423 | |||||||||||||
Alliance | Belle Chasse | Louisiana | Gulf Coast | 247 | 247 | |||||||||
Lake Charles | Westlake | Louisiana | Gulf Coast | 239 | 239 | |||||||||
Sweeny | Old Ocean | Texas | Gulf Coast | 247 | 247 | |||||||||
733 | 733 | |||||||||||||
Wood River | Roxana | Illinois | Central | 153 | 153 | |||||||||
Borger | Borger | Texas | Central | 124 | 95 | * | ||||||||
Ponca City | Ponca City | Oklahoma | Central | 187 | 187 | |||||||||
464 | 435 | |||||||||||||
Billings | Billings | Montana | West Coast | 58 | 58 | |||||||||
Ferndale | Ferndale | Washington | West Coast | 100 | 100 | |||||||||
Los Angeles | Carson/Wilmington | California | West Coast | 139 | 139 | |||||||||
San Francisco | Arroyo Grande/ | California | West Coast | 120 | 120 | |||||||||
San Francisco | ||||||||||||||
417 | 417 | |||||||||||||
2,037 | 2,008 | |||||||||||||
* | Amount reflects our 65 percent share of the Borger refinery effective January 1, 2008. We had an 85 percent share of the Borger refinery in 2007. |
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Bayway Refinery
The Bayway refinery is located on the New York Harbor in Linden, New Jersey. The refinery has a crude oil processing capacity of 238,000 barrels per day, and processes mainly light, low-sulfur crude oil. Crude oil is supplied to the refinery by tanker, primarily from the North Sea, Canada and West Africa. The refinery produces a high percentage of transportation fuels, such as gasoline, ultra-low-sulfur diesel and jet fuel. Other products include petrochemical feedstocks, home heating oil and residual fuel oil. The facility distributes its refined products to East Coast customers by pipeline, barge, railcar and truck. The complex also includes a 775-million-pound-per-year polypropylene plant.
The Trainer refinery is located on the Delaware River in Trainer, Pennsylvania. The refinery has a crude oil processing capacity of 185,000 barrels per day, and processes mainly light, low-sulfur crude oil. The Bayway and Trainer refineries are operated in coordination with each other by sharing crude oil cargoes and often moving feedstocks between the facilities. Trainer receives a majority of its crude oil by tanker from West Africa, Canada and the North Sea. The refinery produces a high percentage of transportation fuels, such as gasoline, diesel and jet fuel. Other products include home heating oil, residual fuel oil and liquefied petroleum gas. Refined products are primarily distributed to customers in Pennsylvania, New York and New Jersey by pipeline, barge, railcar and truck.
Alliance Refinery
The Alliance refinery is located on the Mississippi River in Belle Chasse, Louisiana. The refinery has a crude oil processing capacity of 247,000 barrels per day, and processes mainly light, low-sulfur crude oil. Alliance receives domestic crude oil from the Gulf of Mexico via pipeline, and foreign crude oil from the North Sea and West Africa via pipeline connected to the Louisiana Offshore Oil Port. The refinery produces a high percentage of transportation fuels, such as gasoline, diesel and jet fuel. Other products include home heating oil, petrochemical feedstocks and anode petroleum coke. The majority of the refined products are distributed to customers in the southeastern and eastern United States through major common-carrier pipeline systems and by barge.
The Lake Charles refinery is located in Westlake, Louisiana. The refinery has a crude oil processing capacity of 239,000 barrels per day, and processes mainly heavy, high-sulfur crude oil, but also processes low-sulfur and acidic crude oil. The refinery receives domestic and foreign crude oil, with a majority of its foreign crude oil being heavy Venezuelan and Mexican crude oil, both delivered via tanker. The refinery produces a high percentage of transportation fuels, such as gasoline, off-road diesel and jet fuel, along with home heating oil. The majority of its refined products are distributed to customers by truck, railcar, barge or major common-carrier pipelines to customers in the southeastern and eastern United States. In addition, refined products can be sold into export markets through the refinery’s marine terminal.
The Sweeny refinery is located in Old Ocean, Texas. The refinery has a crude oil processing capacity of 247,000 barrels per day. The refinery processes both heavy, high-sulfur crude oil, the majority of which is sourced from Venezuela, and light, low-sulfur crude oil. The refinery primarily receives crude oil via tankers through its 100-percent-owned and jointly owned terminals on the Gulf Coast, including a deepwater terminal at Freeport, Texas. The refinery produces a high percentage of transportation fuels, such as gasoline, diesel and jet fuel. Other products include home heating oil, petrochemical feedstocks
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EnCana Joint Venture
In October 2006, we announced a business venture with EnCana Corporation (EnCana), to create an integrated North American heavy-oil business. The transaction closed on January 3, 2007. The venture consists of two 50/50 business ventures, a Canadian upstream general partnership, FCCL Oil Sands Partnership, and a U.S. downstream limited liability company, WRB Refining LLC (WRB). We use the equity method of accounting for our investments in both entities.
The Wood River refinery is located on the east side of the Mississippi River in Roxana, Illinois. It has a crude oil processing capacity of 306,000 barrels per day, and our net share of this capacity at December 31, 2007, was 153,000 barrels per day. The refinery processes a mix of both light, low-sulfur and heavy, high-sulfur crude oil. The refinery receives domestic and foreign crude oil by various pipelines. The refinery produces a high percentage of transportation fuels, such as gasoline, diesel and jet fuel. Other products include petrochemical feedstocks and asphalt. Through an off-take agreement, a significant portion of its gasoline and diesel is sold to a third party for delivery via pipelines into the upper Midwest, including the Chicago, Illinois, and Milwaukee, Wisconsin, metropolitan areas. The remaining refined products are distributed to customers in the Midwest by pipeline, truck, barge and railcar.
The Borger refinery is located in Borger, Texas, and the complex includes a natural gas liquids fractionation facility. The crude oil processing capacity of the refinery is 146,000 barrels per day, and the natural gas liquids fractionation capacity is 45,000 barrels per day. Our net share of the crude oil capacity at December 31, 2007, was 124,000 barrels per day. The refinery processes mainly light, high-sulfur and medium, high-sulfur crude oil. It receives crude oil and natural gas liquids feedstocks through pipelines from West Texas, the Texas Panhandle and Wyoming. The Borger refinery also receives foreign crude oil via pipeline. The refinery produces a high percentage of transportation fuels, such as gasoline, diesel and jet fuel, along with a variety of natural gas liquids and solvents. Refined products are transported via pipelines from the refinery to West Texas, New Mexico, Colorado, and the Midcontinent region.
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The Ponca City refinery is located in Ponca City, Oklahoma. The refinery has a crude oil processing capacity of 187,000 barrels per day. The refinery processes a mixture of light, medium and heavy crude oil. Most of the crude processed is received by pipeline from the Gulf of Mexico, Oklahoma, Kansas, Texas and Canada. The refinery produces high ratios of low-sulfur gasoline and ultra-low-sulfur diesel fuel from crude oil. Finished petroleum products are primarily shipped by company-owned and common carrier pipelines to markets throughout the Midcontinent region.
Billings Refinery
The Billings refinery is located in Billings, Montana. The refinery has a crude oil processing capacity of 58,000 barrels per day, and processes a mixture of Canadian heavy, high-sulfur crude oil, plus domestic high-sulfur and low-sulfur crude oil, all delivered by pipeline. A delayed coker converts heavy, high-sulfur residue into higher value light oils. The refinery produces a high percentage of transportation fuels, such as gasoline, diesel and aviation fuels, as well as fuel-grade petroleum coke. Finished petroleum products from the refinery are delivered by pipeline, railcar and truck. Pipelines transport most of the refined products to markets in Montana, Wyoming, Utah and Washington.
The Ferndale refinery is located on Puget Sound in Ferndale, Washington. During 2007, the refinery completed a project to expand the crude unit capacity by replacing piping and modifying various equipment. This project increased capacity by 4,000 barrels per day to 100,000 barrels per day, effective July 1, 2007. The refinery primarily receives light, low-sulfur crude oil from the Alaskan North Slope, as well as crude oil from Canada. The refinery produces transportation fuels such as gasoline and diesel. Other products include residual fuel oil supplying the northwest marine transportation market. Most refined products are distributed by pipeline and barge to major markets in the northwest United States.
The Los Angeles refinery is composed of two linked facilities located about five miles apart in Carson and Wilmington, California. Carson serves as the front-end of the refinery by processing crude oil, and Wilmington serves as the back-end by upgrading products. The refinery has a crude oil processing capacity of 139,000 barrels per day, and processes mainly heavy, high-sulfur crude oil. The refinery receives domestic crude oil via pipeline from California, and both foreign and domestic crude oil by tanker through a third-party terminal in the Port of Long Beach. The refinery produces a high percentage of transportation fuels, such as gasoline, diesel and jet fuel. Other products include fuel-grade petroleum coke. The refinery produces California Air Resources Board (CARB) gasoline by blending ethanol to meet government-mandated oxygenate requirements. Refined products are distributed to customers in Southern California, Nevada and Arizona by pipeline and truck.
The San Francisco refinery is composed of two linked facilities located about 200 miles apart. The Santa Maria facility is located in Arroyo Grande, California, about 200 miles south of San Francisco, while the Rodeo facility is in the San Francisco Bay area. The refinery has a crude oil processing capacity of 120,000 barrels per day. The refinery processes mainly heavy, high-sulfur crude oil, which is received by pipeline in California and by tanker from foreign and domestic sources. Semi-refined liquid products from the Santa Maria facility are sent by pipeline to the Rodeo facility for upgrading into finished petroleum
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In our wholesale operations, we utilize a network of marketers and dealers operating approximately 7,750 outlets that provide refined product off-take from our operated refineries. A strong emphasis is placed on the wholesale channel of trade because of its lower capital requirements. We also buy and sell petroleum products in the spot market. Our refined products are marketed on both a branded and unbranded basis.
In our retail operations, we own and operate 330 sites under the Phillips 66, Conoco and 76 brands. Company-operated retail operations are focused in 10 states, mainly in the Midcontinent, Rocky Mountain and West Coast regions. Most of these outlets market merchandise through the Kicks, Breakplace or Circle K brand convenience stores.
At December 31, 2007, we had approximately 28,000 miles of common-carrier crude oil, raw natural gas liquids, and petroleum products pipeline systems in the United States, including those partially owned and/or operated by affiliates. We also owned and/or operated 51 finished product terminals, seven liquefied petroleum gas terminals, five crude oil terminals and one coke exporting facility.
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At December 31, 2007, we had under charter 18 double-hulled crude oil tankers, with capacities ranging in size from 650,000 to 1,100,000 barrels. These tankers are utilized to transport feedstocks to certain of our U.S. refineries. The information above excludes the operations of the company’s subsidiary, Polar Tankers, Inc., which is discussed in the E&P segment overview, as well as an owned tanker on lease to a third party for use in the North Sea.
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Net Crude Throughput | ||||||||||||||
Capacity (MB/D) | ||||||||||||||
At | Effective | |||||||||||||
Ownership | December 31 | January 1 | ||||||||||||
Refinery | Location | Interest | 2007 | 2008 | ||||||||||
Humber | N. Lincolnshire | United Kingdom | 100.00 | % | 221 | 221 | ||||||||
Whitegate | Cork | Ireland | 100.00 | 71 | 71 | |||||||||
Wilhelmshaven | Wilhelmshaven | Germany | 100.00 | 260 | 260 | |||||||||
MiRO | Karlsruhe | Germany | 18.75 | 57 | 58 | |||||||||
Melaka | Melaka | Malaysia | 47.00 | 60 | 60 | |||||||||
669 | 670 | |||||||||||||
The Humber refinery is located in North Lincolnshire, United Kingdom. The refinery’s crude oil processing capacity is 221,000 barrels per day. Crude oil processed at the refinery is supplied primarily from the North Sea and includes light, low-sulfur and acidic crude oil. The refinery also processes intermediate feedstocks, mostly vacuum gas oils and residual fuel oil.
The Whitegate refinery in Cork, Ireland, has a crude oil processing capacity of 71,000 barrels per day. Crude oil processed by the refinery is light, low-sulfur crude oil sourced mostly from the North Sea. The refinery primarily produces transportation fuels, such as gasoline, diesel and fuel oil, which are distributed to the inland market, as well as being exported to Europe and the United States. We also operate a crude oil and products storage complex consisting of 7.5 million barrels of storage capacity and an offshore mooring buoy, located in Bantry Bay, about 80 miles southwest of the Whitegate refinery in southern Cork County.
The Wilhelmshaven refinery is located in the northern state of Lower Saxony in Germany, and has a crude oil processing capacity of 260,000 barrels per day. Crude oil processed by the refinery is low-sulfur sourced mostly from the North Sea. The Wilhelmshaven refinery mainly produces transportation fuels, fuel oil, and intermediate feedstocks, which are primarily exported to Europe and the United States, but are also distributed to the inland market via truck and rail. Additionally, we operate a marine terminal, rail and truck loading facilities and a tank farm. We have evaluated alternatives to economically improve the operation of the refinery and have incorporated a deep conversion plan into our capital budget.
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The Mineraloel Raffinerie Oberrhein GmbH (MiRO) refinery in Karlsruhe, Germany, is a joint-venture refinery with a crude oil processing capacity of 307,000 barrels per day. Effective January 1, 2008, the refinery’s capacity was increased by 5,000 barrels per day due to incremental debottlenecking, with our share being an increase of 1,000 barrels per day. We have an 18.75 percent interest in MiRO, giving us a net capacity share of 58,000 barrels per day. The refinery’s crude oil feedstock includes medium-sulfur crude oil. The MiRO complex is a fully integrated refinery producing gasoline, middle distillates and specialty products, along with a small amount of residual fuel oil. The refinery has a high capacity to convert lower-cost feedstocks into higher-value products, primarily with a fluid catalytic cracker and a delayed coker. The refinery also produces fuel-grade and specialty calcined cokes. The refinery processes crude and other feedstocks supplied by each of the co-venturers in proportion to their respective ownership interests. The majority of refined products are distributed by truck and railcar to Germany and neighboring markets.
The refinery in Melaka, Malaysia, is a joint-venture refinery in which we own a 47 percent interest. The refinery has a rated crude oil processing capacity of 128,000 barrels per day, of which our share is 60,000 barrels per day. The medium, high-sulfur crude oil processed by the refinery is sourced mostly from the Middle East. The refinery produces a full range of refined petroleum products. The refinery capitalizes on our proprietary coking technology to upgrade low-cost feedstocks to higher-margin products. Our share of refined products is transported by tanker and marketed in Malaysia and other Asian markets.
In May 2006, we signed a Memorandum of Understanding with Saudi Aramco to conduct a detailed evaluation of the proposed development of a 400,000-barrel-per-day, full-conversion refinery in Yanbu, Saudi Arabia. The refinery would be designed to process Arabian heavy crude oil and produce high-quality, ultra-low-sulfur refined products. A joint ConocoPhillips and Saudi Aramco project team has initiated work on the front-end engineering design study. This study, as well as an evaluation of project financing and negotiations of key commercial agreements, is scheduled to be completed later in 2008.
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The focus of our power business is on developing integrated projects to support the company’s E&P and R&M strategies and business objectives. The projects that are primarily in place to enable these strategies are included within their respective E&P and R&M segments. The power projects and assets that have a significant merchant component are included in the Emerging Businesses segment.
We are expanding our efforts to develop carbon-to-liquids technology focused on coal and petroleum coke.
Alternative Energy and Technology Programs focuses on developing new business opportunities designed to provide growth options for ConocoPhillips well into the future. Example areas of interest include advanced hydrocarbon processes, energy conversion technologies, new petroleum-based products, and renewable fuels. ConocoPhillips is interested in the production of biofuels. We have recently commercialized the production of renewable diesel, a new type of renewable fuel that utilizes existing infrastructure. In 2007, we formed a research relationship with Iowa State University to develop new methods for producing second-generation biofuels. We also formed alliances with Tyson Foods and Archer Daniels Midland to produce and market the next generation of renewable transportation fuels.
We offer a gasification technology (E-GasTM) that uses petroleum coke, coal, and other low-value hydrocarbons as feedstock, resulting in high-value synthetic gas used for a slate of products, including power, hydrogen and chemicals.
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• | Worldwide and domestic supplies of, and demand for, crude oil, natural gas, natural gas liquids and refined products. | ||
• | The cost of exploring for, developing, producing, refining and marketing crude oil, natural gas, natural gas liquids and refined products. | ||
• | Changes in weather patterns and climatic changes. | ||
• | The ability of the members of OPEC and other producing nations to agree to and maintain production levels. | ||
• | The worldwide military and political environment, uncertainty or instability resulting from an escalation or additional outbreak of armed hostilities or further acts of terrorism in the United States, or elsewhere. | ||
• | The price and availability of alternative and competing fuels. | ||
• | Domestic and foreign governmental regulations and taxes. | ||
• | Additional or increased nationalization and expropriation activities by foreign governments. | ||
• | General economic conditions worldwide. |
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• | Historical production from the area, compared with production from other comparable producing areas. | ||
• | The assumed effects of regulations by governmental agencies. | ||
• | Assumptions concerning future crude oil and natural gas prices. | ||
• | Assumptions concerning future operating costs, severance and excise taxes, development costs and workover and remedial costs. |
• | The amount and timing of crude oil and natural gas production. | ||
• | The revenues and costs associated with that production. | ||
• | The amount and timing of future development expenditures. |
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• | Obtaining rights to explore, develop and produce crude oil and natural gas in promising areas. | ||
• | Drilling success. | ||
• | The ability to complete long lead-time, capital-intensive projects timely and on budget. | ||
• | Efficient and profitable operation of mature properties. |
• | The discharge of pollutants into the environment. | ||
• | Emissions into the atmosphere (such as nitrogen oxides, sulfur dioxide and mercury emissions in the United States, or potential future control of greenhouse gas emissions). | ||
• | The handling, use, storage, transportation, disposal and clean up of hazardous materials and hazardous and non-hazardous wastes. | ||
• | The dismantlement, abandonment and restoration of our properties and facilities at the end of their useful lives. |
• | Modify operations. | ||
• | Install pollution control equipment. | ||
• | Perform site cleanups. |
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• | Curtail operations. | ||
• | Acquire additional non-petroleum feedstocks or compliance credits to comply with laws mandating specified percentages of biofuels in our refined products. |
We may become subject to liabilities we currently do not anticipate in connection with new, amended or more stringent requirements, stricter interpretations of existing requirements or the future discovery of contamination. In addition, any failure by us to comply with existing or future laws could result in civil or criminal fines and other enforcement actions against us. |
Our, and our predecessors’, operations also could expose us to civil claims by third parties for alleged liability resulting from contamination of the environment or personal injuries caused by releases of hazardous substances. |
Environmental laws are subject to frequent change and many of them have become more stringent. In some cases, they can impose liability for the entire cost of cleanup on any responsible party, without regard to negligence or fault, and impose liability on us for the conduct of others or conditions others have caused, or for our acts that complied with all applicable requirements when we performed them. |
Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Contingencies—Environmental” in Item 7 of this annual report for further information about environmental laws and regulations impacting our business. |
Worldwide political and economic developments could damage our operations and materially reduce our profitability and cash flows. |
Local political and economic factors in international markets could have a material adverse effect on us. Approximately 63 percent of our crude oil, natural gas and natural gas liquids production in 2007 was derived from production outside the United States, and 59 percent of our proved reserves, as of December 31, 2007, were located outside the United States. |
There are many risks associated with operations in international markets, including changes in foreign governmental policies relating to crude oil, natural gas, natural gas liquids or refined product pricing and taxation, other political, economic or diplomatic developments, changing political conditions and international monetary fluctuations. These risks include, among others: |
• | Political and economic instability, war, acts of terrorism and civil disturbances. | ||
• | The possibility that a foreign government may seize our property, with or without compensation, may attempt to renegotiate or revoke existing contractual arrangements and concessions, or may impose additional taxes or royalties. | ||
• | Fluctuating currency values, hard currency shortages and currency controls. |
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The South Coast Air Quality Management District (SCAQMD) conducted an audit of the Los Angeles refinery to assess compliance with applicable local, state, and federal regulations related to fugitive emissions. As a result of the audit, SCAQMD issued three Notices of Violations (NOVs) alleging multiple counts of non-compliance. SCAQMD has not yet specified a penalty for these alleged violations. We are currently assessing these allegations and expect to work with SCAQMD toward a resolution of these NOVs.
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Name | Position Held | Age* | ||
Rand C. Berney | Vice President and Controller | 52 | ||
John A. Carrig | Executive Vice President, Finance, and Chief Financial Officer | 56 | ||
Sigmund L. Cornelius | Senior Vice President, Planning, Strategy and Corporate Affairs | 52 | ||
James L. Gallogly | Executive Vice President, Refining, Marketing and Transportation | 55 | ||
Janet L. Kelly | Senior Vice President, Legal, General Counsel and Corporate Secretary | 50 | ||
John E. Lowe | Executive Vice President, Exploration and Production | 49 | ||
James J. Mulva | Chairman of the Board of Directors, President and Chief Executive Officer | 61 |
* | On March 1, 2008. |
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Item 5. | MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES |
Stock Price | ||||||||||||
High | Low | Dividends | ||||||||||
2007 | ||||||||||||
First | $ | 71.50 | 61.59 | .41 | ||||||||
Second | 81.40 | 66.24 | .41 | |||||||||
Third | 90.84 | 73.75 | .41 | |||||||||
Fourth | 89.89 | 74.18 | .41 | |||||||||
2006 | ||||||||||||
First | $ | 66.25 | 58.01 | .36 | ||||||||
Second | 72.50 | 57.66 | .36 | |||||||||
Third | 70.75 | 56.55 | .36 | |||||||||
Fourth | 74.89 | 54.90 | .36 | |||||||||
Closing Stock Price at December 31, 2007 | $ | 88.30 | ||||||||||
Closing Stock Price at January 31, 2008 | $ | 80.11 | ||||||||||
Number of Stockholders of Record at January 31, 2008* | 64,486 | |||||||||||
* | In determining the number of stockholders, we consider clearing agencies and security position listings as one stockholder for each agency or listing. |
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Millions of Dollars | ||||||||||||||||
Total Number of | Approximate Dollar | |||||||||||||||
Shares Purchased | Value of Shares | |||||||||||||||
Average Price Paid | as Part of Publicly | that May Yet Be | ||||||||||||||
Total Number of | per Total Shares | Announced Plans | Purchased Under the | |||||||||||||
Period | Shares Purchased | * | Purchased | or Programs | ** | Plans or Programs | ||||||||||
October 1-31, 2007 | 8,524,207 | $85.01 | 8,519,500 | $11,873 | ||||||||||||
November 1-30, 2007 | 11,099,198 | 80.92 | 11,098,236 | 10,975 | ||||||||||||
December 1-31, 2007 | 10,640,304 | 82.57 | 10,629,568 | 10,097 | ||||||||||||
Total | 30,263,709 | $82.65 | 30,247,304 | |||||||||||||
* | Includes the repurchase of common shares from company employees in connection with the company’s broad-based employee incentive plans. |
** | On January 12, 2007, we announced a stock repurchase program that provided for the repurchase of up to $1 billion of the company’s common stock. On February 9, 2007, we announced plans to repurchase $4 billion of our common stock in 2007, including the $1 billion announced on January 12, 2007. On July 9, 2007, we announced plans to repurchase up to $15 billion of the company’s common stock through the end of 2008, which included the $2 billion remaining under the previously announced $4 billion program. Acquisitions for the share repurchase programs 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 plans are held as treasury shares. |
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Millions of Dollars Except Per Share Amounts | ||||||||||||||||||||
2007 | 2006 | 2005 | 2004 | 2003 | ||||||||||||||||
Sales and other operating revenues | $ | 187,437 | 183,650 | 179,442 | 135,076 | 104,246 | ||||||||||||||
Income from continuing operations | 11,891 | 15,550 | 13,640 | 8,107 | 4,593 | |||||||||||||||
Per common share | ||||||||||||||||||||
Basic | 7.32 | 9.80 | 9.79 | 5.87 | 3.37 | |||||||||||||||
Diluted | 7.22 | 9.66 | 9.63 | 5.79 | 3.35 | |||||||||||||||
Net income | 11,891 | 15,550 | 13,529 | 8,129 | 4,735 | |||||||||||||||
Per common share | ||||||||||||||||||||
Basic | 7.32 | 9.80 | 9.71 | 5.88 | 3.48 | |||||||||||||||
Diluted | 7.22 | 9.66 | 9.55 | 5.80 | 3.45 | |||||||||||||||
Total assets | 177,757 | 164,781 | 106,999 | 92,861 | 82,455 | |||||||||||||||
Long-term debt | 20,289 | 23,091 | 10,758 | 14,370 | 16,340 | |||||||||||||||
Joint venture acquisition obligation—related party | 6,294 | - | - | - | - | |||||||||||||||
Mandatorily redeemable minority interests | - | - | - | - | 141 | |||||||||||||||
Cash dividends declared per common share | 1.64 | 1.44 | 1.18 | .895 | .815 | |||||||||||||||
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Item 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
• | Exploration and Production (E&P)—This segment primarily explores for, produces, transports and markets crude oil, natural gas, and natural gas liquids on a worldwide basis. | ||
• | Midstream—This segment gathers, processes and markets natural gas produced by ConocoPhillips and others, and fractionates and markets natural gas liquids, primarily in the United States and Trinidad. The Midstream segment primarily consists of our 50 percent equity investment in DCP Midstream, LLC. | ||
• | Refining and Marketing (R&M)—This segment purchases, refines, markets and transports crude oil and petroleum products, mainly in the United States, Europe and Asia. | ||
• | LUKOIL Investment—This segment consists of our equity investment in the ordinary shares of OAO LUKOIL (LUKOIL), an international, integrated oil and gas company headquartered in Russia. At December 31, 2007, our ownership interest was 20 percent based on issued shares, and 20.6 percent based on estimated shares outstanding. | ||
• | Chemicals—This segment manufactures and markets petrochemicals and plastics on a worldwide basis. The Chemicals segment consists of our 50 percent equity investment in Chevron Phillips Chemical Company LLC (CPChem). | ||
• | Emerging Businesses—This segment represents our investment in new technologies or businesses outside our normal scope of operations. |
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• | Operating our producing properties and refining and marketing operations safely, consistently and in an environmentally sound manner. Safety is our first priority and we are committed to protecting the health and safety of everyone who has a role in our operations and the communities in which we operate. Maintaining high utilization rates at our refineries and minimizing downtime in producing fields enable us to capture the value available in the market in terms of prices and margins. During 2007, our worldwide refinery capacity utilization rate was 94 percent, compared with 92 percent in 2006. The improved utilization rate reflects less scheduled downtime and unplanned weather-related downtime. Concerning the environment, we strive to conduct our operations in a manner consistent with our environmental stewardship principles. | ||
• | Adding to our proved reserve base. We primarily add to our proved reserve base in three ways: |
o | Successful exploration and development of new fields. | ||
o | Acquisition of existing fields. | ||
o | Applying new technologies and processes to improve recovery from existing fields. |
Through a combination of all three methods listed above, we have been successful in the past in maintaining or adding to our production and proved reserve base. Although it cannot be assured, we anticipate being able to do so in the future. The acquisition of Burlington Resources in March 2006 added approximately 2 billion barrels of oil equivalent to our proved reserves, and through our investments in LUKOIL during 2004, 2005 and 2006, we added about 1.9 billion barrels of oil equivalent. On January 3, 2007, we closed on a business venture with EnCana Corporation (EnCana). As part of this transaction, we added approximately 400 million barrels of oil equivalent to our proved reserves in 2007. In the three years ending December 31, 2007, our reserve replacement was 186 percent, including the impact of the Burlington Resources acquisition, our additional equity investment in LUKOIL, the EnCana business venture, and the expropriation of our Venezuelan oil assets. | |||
Access to additional resources has become increasingly difficult as direct investment is prohibited in some nations, while fiscal and other terms in other countries can make projects uneconomic or unattractive. In addition, political instability, competition from national oil companies, and lack of access to high-potential areas due to environmental or other regulation may negatively impact our ability to increase our reserve base. As such, the timing and level at which we add to our reserve base may, or may not, allow us to replace our production over subsequent years. | |||
• | Controlling costs and expenses. Since we cannot control the prices of the commodity products we sell, controlling operating and overhead costs and prudently managing our capital program, within the context of our commitment to safety and environmental stewardship, are high priorities. We monitor these costs using various methodologies that are reported to senior management monthly, on both an absolute-dollar basis and a per-unit basis. Because managing operating and overhead costs are critical to maintaining competitive positions in our industries, cost control is a component of our variable compensation programs. | ||
With the rise in commodity prices over the last several years, and the subsequent increase in industry-wide spending on capital and major maintenance programs, we and other energy companies are experiencing inflation for the costs of certain goods and services in excess of general worldwide inflationary trends. Such costs include rates for drilling rigs, steel and other |
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raw materials, as well as costs for skilled labor. While we work to manage the effect these inflationary pressures have on our costs, our capital program has been impacted by these factors. The continued weakening of the U.S. dollar has also contributed to higher costs. Our capital program may be further impacted by these factors going forward. | |||
• | Selecting the appropriate projects in which to invest our capital dollars. We participate in capital-intensive industries. As a result, we must often invest significant capital dollars to explore for new oil and gas fields, develop newly discovered fields, maintain existing fields, or continue to maintain and improve our refinery complexes. We invest in those projects that are expected to provide an adequate financial return on invested dollars. However, there are often long lead times from the time we make an investment to the time that investment is operational and begins generating financial returns. | ||
In January 2007, we entered into two 50/50 business ventures with EnCana to create an integrated North American heavy-oil business, consisting of a Canadian upstream general partnership, FCCL Oil Sands Partnership (FCCL), and a U.S. downstream limited liability company, WRB Refining LLC (WRB). We are obligated to contribute $7.5 billion, plus accrued interest, to FCCL over a 10-year period beginning in 2007. EnCana is obligated to contribute $7.5 billion, plus accrued interest, to WRB over a 10-year period beginning in 2007. | |||
Our capital expenditures and investments in 2007 totaled $11.8 billion, and we anticipate capital expenditures and investments to be approximately $14.3 billion in 2008. In addition to our capital program, we increased shareholder distributions in 2007 through a combination of increased dividends and share repurchases. Our cash dividends totaled $1.64 per share in 2007, an increase of 14 percent over $1.44 per share in 2006. We repurchased $7 billion of our common stock in 2007 and have $10 billion of share repurchase authority remaining through 2008. | |||
• | Managing our asset portfolio. We continue to evaluate opportunities to acquire assets that will contribute to future growth at competitive prices. We also continually assess our assets to determine if any no longer fit our strategic plans and should be sold or otherwise disposed. This management of our asset portfolio is important to ensuring our long-term growth and maintaining adequate financial returns. During 2006, we increased our investment in LUKOIL, ending the year with a 20 percent ownership interest based on issued shares. During 2006, we completed the $33.9 billion acquisition of Burlington Resources. Also during 2006, we announced the commencement of an asset rationalization program to evaluate our asset base to identify those assets that may no longer fit into our strategic plans or those that could bring more value by being monetized in the near term. This program generated proceeds of approximately $3.8 billion through December 31, 2007. In 2008, we expect to complete the disposition of our retail assets in the United States, Norway, Sweden and Denmark. We will evaluate additional opportunities to optimize and strengthen our asset portfolio as the year progresses. | ||
• | Hiring, 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. In 2007, we hired approximately 2,900 new employees around the world, including university hires as well as experienced hires. 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. The ongoing hiring and training of employees is especially important given the significant number of experienced technical personnel potentially exiting the workplace over the next few years. |
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• | Property and leasehold impairments. As mentioned above, we participate in capital-intensive industries. At times, these investments become impaired when our reserve estimates are revised downward, when crude oil or natural gas prices, or refinery margins decline significantly for long periods of time, or when a decision to dispose of an asset leads to a write-down to its fair market value. Property impairments in 2007, excluding the impairment of expropriated assets, totaled $442 million, compared with $383 million in 2006. We may also invest large amounts of money in exploration blocks which, if exploratory drilling proves unsuccessful, could lead to a material impairment of leasehold values. | ||
• | Goodwill. As a result of mergers and acquisitions, at year-end 2007 we had $29.3 billion of goodwill on our balance sheet, compared with $31.5 billion of goodwill at year-end 2006. Although our latest tests indicate that no goodwill impairment is currently required, future deterioration in market conditions could lead to goodwill impairments that would have a substantial negative, though non-cash, effect on our profitability. | ||
• | Effective tax rate. Our operations are located in countries with different tax rates and fiscal structures. Accordingly, even in a stable commodity price and fiscal/regulatory environment, our overall effective tax rate can vary significantly between periods based on the “mix” of pretax earnings within our global operations. | ||
• | Fiscal and regulatory environment. As commodity prices and refining margins improved over the last several years, certain governments have responded with changes to their fiscal take. These changes have generally negatively impacted our results of operations, and further changes to government fiscal take could have a negative impact on future operations. In June 2007, our Venezuelan oil projects were expropriated, and we recorded a $4,588 million before-tax ($4,512 million after-tax) impairment (see the “Expropriated Assets” section of Note 13—Impairments, in the Notes to Consolidated Financial Statements). The company was also negatively impacted by increased production taxes enacted by the state of Alaska in the fourth quarter of 2007. In October 2007, the government of Ecuador increased the tax rate of the Windfall Profits Tax Law implemented in 2006, increasing the amount of government royalty entitlement on crude oil production to 99 percent of any increase in the price of crude oil above a contractual reference price. Also in October 2007, the Alberta provincial government publicly announced its intention to change the royalty structure for Crown lands, effective January 1, 2009 (see the “Outlook” section for additional information on the proposed royalty increase). In January 2008, we and our co-venturers agreed to the proportional dilution of our equity interests in the Republic of Kazakhstan’s North Caspian Sea Production Sharing Agreement, which includes the Kashagan field, to allow the state-owned energy company to increase its ownership percentage effective January 1, 2008, subject to completion of definitive agreements on dilution and other matters. Partially offsetting the above fiscal take increases were lower corporate income tax rates enacted by Canada and Germany during 2007. These tax rate reductions applied to all corporations and were not exclusive to the oil and gas industry. |
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The E&P segment’s results are most closely linked to crude oil and natural gas prices. These are commodity products, the prices of which are subject to factors external to our company and over which we have no control. Industry crude oil prices for West Texas Intermediate were higher in 2007 compared with 2006, averaging $72.25 per barrel in 2007, an increase of 9 percent. The increase was primarily due to growth in global consumption associated with continuing economic expansions and limited spare capacity from major exporting countries. Industry natural gas prices for Henry Hub increased during 2007, primarily due to increased demand from the residential and electric power sector. These factors were moderated by higher domestic production, increased LNG imports, and high storage levels.
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Millions of Dollars | ||||||||||||
Years Ended December 31 | 2007 | 2006 | 2005 | |||||||||
Exploration and Production (E&P) | $ | 4,615 | 9,848 | 8,430 | ||||||||
Midstream | 453 | 476 | 688 | |||||||||
Refining and Marketing (R&M) | 5,923 | 4,481 | 4,173 | |||||||||
LUKOIL Investment | 1,818 | 1,425 | 714 | |||||||||
Chemicals | 359 | 492 | 323 | |||||||||
Emerging Businesses | (8 | ) | 15 | (21 | ) | |||||||
Corporate and Other | (1,269 | ) | (1,187 | ) | (778 | ) | ||||||
Net income | $ | 11,891 | 15,550 | 13,529 | ||||||||
• | The complete impairment ($4,512 million after-tax) of our oil interests in Venezuela resulting from their expropriation in June 2007. | ||
• | Lower crude oil production in the E&P segment. | ||
• | Decreased net income from the Chemicals segment, primarily due to lower olefins and polyolefins margins. | ||
• | Higher production and operating expenses, higher production taxes, and higher depreciation, depletion and amortization expense in the E&P segment. |
• | The net benefit of asset rationalization efforts in the E&P and R&M segments. | ||
• | Higher realized crude oil, natural gas, and natural gas liquids prices in the E&P segment. | ||
• | Higher realized worldwide refining margins, including the benefit of planned inventory reductions in the R&M segment. | ||
• | Increased equity earnings from our investment in LUKOIL due to higher estimated commodity prices and volumes, and an increase in our average equity ownership percentage. |
• | Higher crude oil prices in the E&P segment. | ||
• | The inclusion of Burlington Resources in our results of operations for the E&P segment. | ||
• | Improved refining margins and volumes and marketing margins in the R&M segment’s U.S. operations. | ||
• | Increased equity earnings from our investment in LUKOIL. | ||
• | The recognition in 2006 of business interruption insurance recoveries attributable to hurricanes in 2005. |
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• | The impairment of certain assets held for sale in the R&M and E&P segments. | ||
• | Lower natural gas prices in the E&P segment. | ||
• | Higher interest and debt expense resulting from higher average debt levels due to the Burlington Resources acquisition. | ||
• | Decreased net income from the Midstream segment, reflecting the inclusion of our equity share of DCP Midstream’s gain on the sale of the general partner interest in TEPPCO in our 2005 results. |
• | Higher net gains on asset dispositions associated with asset rationalization efforts. | ||
• | The release of escrowed funds related to the extinguishment of Hamaca project financing. | ||
• | The settlement of retroactive adjustments for crude oil quality differentials on Trans-Alaska Pipeline System shipments (Quality Bank) in 2007. |
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• | LUKOIL, resulting from an increase in our ownership percentage, as well as higher estimated crude oil and petroleum products prices and volumes, and a net benefit from the alignment of our estimate of LUKOIL’s fourth quarter 2005 net income to LUKOIL’s reported results. | ||
• | CPChem, due to higher margins and volumes, as well as the recognition of a business interruption insurance net benefit. |
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2007 | 2006 | 2005 | ||||||||||
Millions of Dollars | ||||||||||||
Net Income | ||||||||||||
Alaska | $ | 2,255 | 2,347 | 2,552 | ||||||||
Lower 48 | 1,993 | 2,001 | 1,736 | |||||||||
United States | 4,248 | 4,348 | 4,288 | |||||||||
International | 367 | 5,500 | 4,142 | |||||||||
$ | 4,615 | 9,848 | 8,430 | |||||||||
Dollars Per Unit | ||||||||||||
Average Sales Prices | ||||||||||||
Crude oil (per barrel) | ||||||||||||
United States | $ | 68.00 | 61.09 | 51.09 | ||||||||
International | 70.79 | 63.38 | 52.27 | |||||||||
Total consolidated | 69.47 | 62.39 | 51.74 | |||||||||
Equity affiliates* | 45.31 | 46.01 | 37.79 | |||||||||
Worldwide E&P | 67.11 | 60.37 | 49.87 | |||||||||
Natural gas (per thousand cubic feet) | ||||||||||||
United States | 5.98 | 6.11 | 7.12 | |||||||||
International | 6.51 | 6.27 | 5.78 | |||||||||
Total consolidated | 6.26 | 6.20 | 6.32 | |||||||||
Equity affiliates* | .30 | .30 | .26 | |||||||||
Worldwide E&P | 6.26 | 6.19 | 6.30 | |||||||||
Natural gas liquids (per barrel) | ||||||||||||
United States | 46.00 | 40.35 | 40.40 | |||||||||
International | 48.80 | 42.89 | 36.25 | |||||||||
Total consolidated | 47.13 | 41.50 | 38.32 | |||||||||
Equity affiliates* | - | - | - | |||||||||
Worldwide E&P | 47.13 | 41.50 | 38.32 | |||||||||
Average Production Costs Per Barrel of Oil Equivalent | ||||||||||||
United States | $ | 6.52 | 5.43 | 4.24 | ||||||||
International | 7.68 | 5.65 | 4.58 | |||||||||
Total consolidated | 7.13 | 5.55 | 4.43 | |||||||||
Equity affiliates* | 8.92 | 5.83 | 4.93 | |||||||||
Worldwide E&P | 7.21 | 5.57 | 4.47 | |||||||||
*Excludes our equity share of LUKOIL, which is reported in the LUKOIL Investment segment. |
Millions of Dollars | ||||||||||||
Worldwide Exploration Expenses | ||||||||||||
General administrative, geological and geophysical, and lease rentals | $ | 544 | 483 | 312 | ||||||||
Leasehold impairment | 254 | 157 | 116 | |||||||||
Dry holes | 209 | 194 | 233 | |||||||||
$ | 1,007 | 834 | 661 | |||||||||
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2007 | 2006 | 2005 | ||||||||||
Thousands of Barrels Daily | ||||||||||||
Operating Statistics | ||||||||||||
Crude oil produced | ||||||||||||
Alaska | 261 | 263 | 294 | |||||||||
Lower 48 | 102 | 104 | 59 | |||||||||
United States | 363 | 367 | 353 | |||||||||
Europe | 210 | 245 | 257 | |||||||||
Asia Pacific | 87 | 106 | 100 | |||||||||
Canada | 19 | 25 | 23 | |||||||||
Middle East and Africa | 81 | 106 | 53 | |||||||||
Other areas | 10 | 7 | - | |||||||||
Total consolidated | 770 | 856 | 786 | |||||||||
Equity affiliates* | ||||||||||||
Canada | 27 | - | - | |||||||||
Russia and Caspian | 15 | 15 | 15 | |||||||||
Venezuela | 42 | 101 | 106 | |||||||||
854 | 972 | 907 | ||||||||||
Natural gas liquids produced | ||||||||||||
Alaska | 19 | 17 | 20 | |||||||||
Lower 48 | 79 | 62 | 30 | |||||||||
United States | 98 | 79 | 50 | |||||||||
Europe | 14 | 13 | 13 | |||||||||
Asia Pacific | 14 | 18 | 16 | |||||||||
Canada | 27 | 25 | 10 | |||||||||
Middle East and Africa | 2 | 1 | 2 | |||||||||
155 | 136 | 91 | ||||||||||
Millions of Cubic Feet Daily | ||||||||||||
Natural gas produced** | ||||||||||||
Alaska | 110 | 145 | 169 | |||||||||
Lower 48 | 2,182 | 2,028 | 1,212 | |||||||||
United States | 2,292 | 2,173 | 1,381 | |||||||||
Europe | 961 | 1,065 | 1,023 | |||||||||
Asia Pacific | 579 | 582 | 350 | |||||||||
Canada | 1,106 | 983 | 425 | |||||||||
Middle East and Africa | 125 | 142 | 84 | |||||||||
Other areas | 19 | 16 | - | |||||||||
Total consolidated | 5,082 | 4,961 | 3,263 | |||||||||
Equity affiliates* | ||||||||||||
Venezuela | 5 | 9 | 7 | |||||||||
5,087 | 4,970 | 3,270 | ||||||||||
Thousands of Barrels Daily | ||||||||||||
Mining operations | ||||||||||||
Syncrude produced | 23 | 21 | 19 | |||||||||
*Excludes our equity share of LUKOIL, which is reported in the LUKOIL Investment segment. **Represents quantities available for sale. Excludes gas equivalent of natural gas liquids shown above. |
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• | Higher realized crude oil, natural gas liquids and natural gas prices. | ||
• | A net benefit from asset rationalization efforts. | ||
• | A benefit related to the release of escrowed funds in connection with the extinguishment of the Hamaca project financing. | ||
• | The Quality Bank settlements. |
• | Higher crude oil and natural gas liquids prices, and higher natural gas and natural gas liquids production. | ||
• | The Quality Bank settlements. | ||
• | Gains on the sale of assets in Alaska and the Gulf of Mexico. |
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2007 | 2006 | 2005 | ||||||||||
Millions of Dollars | ||||||||||||
Net Income* | $ | 453 | 476 | 688 | ||||||||
*Includes DCP Midstream-related net income: | $ | 336 | 385 | 591 |
Dollars Per Barrel | ||||||||||||
Average Sales Prices | ||||||||||||
U.S. natural gas liquids* | ||||||||||||
Consolidated | $ | 47.93 | 40.22 | 36.68 | ||||||||
Equity | 46.80 | 39.45 | 35.52 | |||||||||
*Based on index prices from the Mont Belvieu and Conway market hubs that are weighted by natural gas liquids component and location mix. |
Thousands of Barrels Daily | ||||||||||||
Operating Statistics | ||||||||||||
Natural gas liquids extracted* | 211 | 209 | 195 | |||||||||
Natural gas liquids fractionated** | 173 | 144 | 168 | |||||||||
*Includes our share of equity affiliates, except LUKOIL, which is included in the LUKOIL Investment segment. **Excludes DCP Midstream. |
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2007 | 2006 | 2005 | ||||||||||
Millions of Dollars | ||||||||||||
Net Income | ||||||||||||
United States | $ | 4,615 | 3,915 | 3,329 | ||||||||
International | 1,308 | 566 | 844 | |||||||||
$ | 5,923 | 4,481 | 4,173 | |||||||||
Dollars Per Gallon | ||||||||||||
U.S. Average Sales Prices* | ||||||||||||
Gasoline | ||||||||||||
Wholesale | $ | 2.27 | 2.04 | 1.73 | ||||||||
Retail | 2.42 | 2.18 | 1.88 | |||||||||
Distillates—wholesale | 2.29 | 2.11 | 1.80 | |||||||||
*Excludes excise taxes. |
Thousands of Barrels Daily | ||||||||||||
Operating Statistics | ||||||||||||
Refining operations* | ||||||||||||
United States Crude oil capacity** | 2,035 | 2,208 | 2,180 | |||||||||
Crude oil runs | 1,944 | 2,025 | 1,996 | |||||||||
Capacity utilization (percent) | 96 | % | 92 | 92 | ||||||||
Refinery production | 2,146 | 2,213 | 2,186 | |||||||||
International Crude oil capacity** | 687 | 651 | 428 | |||||||||
Crude oil runs | 616 | 591 | 424 | |||||||||
Capacity utilization (percent) | 90 | % | 91 | 99 | ||||||||
Refinery production | 633 | 618 | 439 | |||||||||
Worldwide Crude oil capacity** | 2,722 | 2,859 | 2,608 | |||||||||
Crude oil runs | 2,560 | 2,616 | 2,420 | |||||||||
Capacity utilization (percent) | 94 | % | 92 | 93 | ||||||||
Refinery production | 2,779 | 2,831 | 2,625 | |||||||||
Petroleum products sales volumes | ||||||||||||
United States | ||||||||||||
Gasoline | 1,244 | 1,336 | 1,374 | |||||||||
Distillates | 872 | 850 | 876 | |||||||||
Other products | 432 | 531 | 519 | |||||||||
2,548 | 2,717 | 2,769 | ||||||||||
International | 697 | 759 | 482 | |||||||||
3,245 | 3,476 | 3,251 | ||||||||||
* | Includes our share of equity affiliates, except for our share of LUKOIL, which is reported in the LUKOIL Investment segment. |
** | Weighted-average crude oil capacity for the periods. Actual capacity at year-end 2007, 2006 and 2005, was 2,037,000, 2,208,000, and 2,182,000 barrels per day, respectively, for our domestic refineries, and 669,000, 693,000, and 482,000 barrels per day, respectively, for our international refineries. |
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• | The net benefit of asset rationalization efforts. | ||
• | Higher realized worldwide refining margins, reflecting in part the impact of planned inventory reductions, including a benefit of $260 million from the liquidation of prior year layers under the last-in, first-out (LIFO) method. | ||
• | Higher U.S. Gulf and East Coast refining volumes due to lower planned maintenance and less weather-related downtime. | ||
• | A $141 million deferred tax benefit related to tax legislation in Germany during the third quarter of 2007. |
• | Higher refining volumes at our Gulf and East Coast refineries. | ||
• | Higher realized refining and marketing margins, due in part to the benefit of planned inventory reductions. |
• | The net benefit of asset rationalization efforts. | ||
• | The deferred tax benefit related to the tax legislation in Germany. | ||
• | Higher realized refining margins. |
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• | Higher U.S. refining and marketing margins and higher U.S. refining volumes. | ||
• | The recognition of a net benefit related to business interruption insurance. | ||
• | The inclusion of an $83 million charge for the cumulative effect of adopting Financial Accounting Standards Board (FASB) Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations—an interpretation of FASB Statement No. 143” (FIN 47) in the results for 2005. |
• | Higher refining and marketing margins, and higher refining volumes. | ||
• | The recognition of a net $111 million business interruption insurance benefit. | ||
• | A $78 million charge for the cumulative effect of adopting FIN 47 in 2005. |
• | The recognition of a $214 million after-tax impairment charge on certain assets held for sale. | ||
• | Lower refining margins. | ||
• | Preliminary engineering costs for certain refinery-related projects. |
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Millions of Dollars | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
Net Income | $ | 1,818 | 1,425 | 714 | ||||||||
Operating Statistics* | ||||||||||||
Net crude oil production (thousands of barrels daily) | 401 | 360 | 235 | |||||||||
Net natural gas production (millions of cubic feet daily) | 256 | 244 | 67 | |||||||||
Net refinery crude oil processed (thousands of barrels daily) | 214 | 179 | 122 | |||||||||
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Millions of Dollars | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
Net Income | $ | 359 | 492 | 323 | ||||||||
Millions of Dollars | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
Net Income (Loss) | ||||||||||||
Power | $ | 53 | 82 | 43 | ||||||||
Other | (61 | ) | (67 | ) | (64 | ) | ||||||
$ | (8 | ) | 15 | (21 | ) | |||||||
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Millions of Dollars | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
Net Loss | ||||||||||||
Net interest | $ | (820 | ) | (870 | ) | (467 | ) | |||||
Corporate general and administrative expenses | (176 | ) | (133 | ) | (183 | ) | ||||||
Discontinued operations | - | - | (23 | ) | ||||||||
Acquisition-related costs | (44 | ) | (98 | ) | - | |||||||
Other | (229 | ) | (86 | ) | (105 | ) | ||||||
$ | (1,269 | ) | (1,187 | ) | (778 | ) | ||||||
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Millions of Dollars | ||||||||||||
Except as Indicated | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
Net cash provided by operating activities | $ | 24,550 | 21,516 | 17,628 | ||||||||
Notes payable and long-term debt due within one year | 1,398 | 4,043 | 1,758 | |||||||||
Total debt | 21,687 | 27,134 | 12,516 | |||||||||
Minority interests | 1,173 | 1,202 | 1,209 | |||||||||
Common stockholders’ equity | 88,983 | 82,646 | 52,731 | |||||||||
Percent of total debt to capital* | 19 | % | 24 | 19 | ||||||||
Percent of floating-rate debt to total debt | 25 | 41 | 9 | |||||||||
*Capital includes total debt, minority interests and common stockholders’ equity. |
During 2007, cash of $24,550 million was provided by operating activities, a 14 percent increase over cash from operations of $21,516 million in 2006. Contributing to the increase was a planned inventory reduction in the 2007 period, partially related to the formation of the WRB downstream business venture; the impact of the Burlington Resources acquisition late in the first quarter of 2006; and higher worldwide crude oil prices in 2007. These positive factors were partially offset by the absence of dividends from our Venezuelan operations in 2007.
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Proceeds from asset sales in 2007 were $3,572 million, compared with $545 million in 2006. The increase is mainly due to ongoing asset rationalization efforts related to the program we announced in April 2006 to dispose of assets that no longer fit into our strategic plans or those that could bring more value by being monetized in the near term. Through December 31, 2007, this program had generated proceeds of approximately $3.8 billion since inception. In 2008, we expect to complete the disposition of our retail assets in the United States, Norway, Sweden and Denmark.
In September 2007, we replaced our $5 billion and $2.5 billion revolving credit facilities, with one $7.5 billion revolving credit facility, expiring in September 2012. This facility may be used as direct bank borrowings, as support for the ConocoPhillips $7.5 billion commercial paper program, as support for the ConocoPhillips Qatar Funding Ltd. $1.5 billion commercial paper program, or as support for issuances of letters of credit totaling up to $750 million. The 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 credit 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.
We have a universal shelf registration statement on file with the U.S. Securities and Exchange Commission (SEC) under which we, as a well-known seasoned issuer, have the ability to issue and sell an indeterminate amount of various types of debt and equity securities.
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At December 31, 2007, we had outstanding $1,173 million of equity in less than wholly owned consolidated subsidiaries held by minority interest owners, including a minority interest of $508 million in Ashford Energy Capital S.A. The remaining minority interest amounts are primarily related to operating joint ventures we control. The largest of these, $648 million, was related to the Darwin LNG project located in northern Australia.
• | Qatargas 3:Qatargas 3 is an integrated project to produce and liquefy natural gas from Qatar’s North field. We own a 30 percent interest in the project. The other participants in the project are affiliates of Qatar Petroleum (68.5 percent) and Mitsui & Co., Ltd. (1.5 percent). Our interest is held through a jointly owned company, Qatar Liquefied Gas Company Limited (3), for which we use the equity method of accounting. Qatargas 3 secured project financing of $4 billion in December 2005, consisting of $1.3 billion of loans from export credit agencies (ECA), $1.5 billion from commercial banks, and $1.2 billion from ConocoPhillips. The ConocoPhillips loan facilities have substantially the same terms as the ECA and commercial bank facilities. Prior to project completion certification, all loans, including the ConocoPhillips loan facilities, are guaranteed by the participants, based on their respective ownership interests. Accordingly, our maximum exposure to this financing structure is $1.2 billion, excluding accrued interest. Upon completion certification, which is expected in 2010, all project loan facilities, including the ConocoPhillips loan facilities, will become non-recourse to the project participants. At December 31, 2007, Qatargas 3 had $2.4 billion outstanding under all the loan facilities, of which ConocoPhillips provided $690 million, and an additional $43 million of accrued interest. |
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• | Rockies Express Pipeline LLC:In June 2006, we issued a guarantee for 24 percent of the $2.0 billion in credit facilities of Rockies Express Pipeline LLC (Rockies Express), which will be used to construct a natural gas pipeline across a portion of the United States. The maximum potential amount of future payments to third-party lenders under the guarantee is estimated to be $480 million, which could become payable if the credit facility is fully utilized and Rockies Express fails to meet its obligations under the credit agreement. At December 31, 2007, Rockies Express had $1,625 million outstanding under the credit facilities, with our 24 percent guarantee equaling $390 million. In addition, we have a 24 percent guarantee on $600 million of Floating Rate Notes due 2009 issued by Rockies Express in September 2007. It is anticipated that construction completion will be achieved in 2009, and refinancing will take place at that time, making the debt non-recourse. For additional information, see Note 7—Variable Interest Entities (VIEs), in the Notes to Consolidated Financial Statements. | ||
• | Keystone Oil Pipeline:In December 2007, we acquired a 50 percent equity interest in the Keystone Oil Pipeline (Keystone), a joint venture with TransCanada Corporation. Keystone plans to construct a crude oil pipeline originating in Alberta, with delivery points in Illinois and Oklahoma. In connection with certain planning and construction activities, agreements were put in place with third parties to guarantee the payments due under those agreements. Our maximum potential amount of future payments under those agreements are estimated to be $400 million, which could become payable if Keystone fails to meet its obligations under the agreements noted above and the obligation cannot otherwise be mitigated. Payments under the guarantees are contingent upon the partners not making necessary equity contributions into Keystone; therefore, it is considered unlikely that payments would be required. All but $15 million of the guarantees will terminate after construction is completed, currently estimated to be in 2010. |
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Millions of Dollars | ||||||||||||||||||||
Payments Due by Period | ||||||||||||||||||||
Up to | Year | Year | After | |||||||||||||||||
Total | 1 Year | 2-3 | 4-5 | 5 Years | ||||||||||||||||
Debt obligations (a) | $ | 21,633 | 1,368 | 2,796 | 7,243 | 10,226 | ||||||||||||||
Capital lease obligations | 54 | 30 | 7 | - | 17 | |||||||||||||||
Total debt | 21,687 | 1,398 | 2,803 | 7,243 | 10,243 | |||||||||||||||
Interest on debt and other obligations | 15,439 | 1,429 | 2,608 | 1,949 | 9,453 | |||||||||||||||
Operating lease obligations | 3,308 | 732 | 1,032 | 737 | 807 | |||||||||||||||
Purchase obligations (b) | 125,507 | 49,929 | 11,864 | 8,665 | 55,049 | |||||||||||||||
Joint venture acquisition obligation (c) | 6,887 | 593 | 1,285 | 1,427 | 3,582 | |||||||||||||||
Other long-term liabilities (d) | ||||||||||||||||||||
Asset retirement obligations | 6,613 | 253 | 555 | 481 | 5,324 | |||||||||||||||
Accrued environmental costs | 1,089 | 187 | 319 | 114 | 469 | |||||||||||||||
Unrecognized tax benefits (e) | 144 | 144 | (e | ) | (e | ) | (e | ) | ||||||||||||
Total | $ | 180,674 | 54,665 | 20,466 | 20,616 | 84,927 | ||||||||||||||
(a) | Includes $688 million of net unamortized premiums and discounts. See Note 15—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. The majority of the purchase obligations are market-based contracts. Includes: (1) our commercial activities of $74,446 million, of which $31,834 million are primarily related to the supply of crude oil to our refineries and the optimization of the supply chain, $10,530 million primarily related to the supply of unfractionated natural gas liquids (NGL) to fractionators, optimization of NGL assets, and for resale to customers, $9,575 million on futures, $8,933 million primarily related to natural gas for resale customers, $7,354 million related to transportation, $4,984 million related to product purchases, $943 million related to power trades, and $293 million related to the purchase side of exchange agreements; (2) $45,744 million of purchase commitments for products, mostly natural gas and NGL, from CPChem over the remaining term of 92 years; and (3) purchase commitments for jointly owned fields and facilities where we are the operator, of which some of the obligations will be reimbursed by our co-venturers in these properties. | |
Does not include: (1) purchase commitments for jointly owned fields and facilities where we are not the operator; and (2) an agreement to purchase up to 165,000 barrels per day of Venezuelan Merey, or equivalent, crude oil for a market price over a remaining 12-year term if a variety of conditions are met. | ||
(c) | Represents the remaining amount of contributions, excluding interest, due over a nine-year period to the upstream joint venture formed with EnCana. | |
(d) | Does not include: Pensions—for the 2008 through 2012 time period, we expect to contribute an average of $335 million per year to our qualified and non-qualified pension and postretirement medical plans in the United States and an average of $200 million per year to our non-U.S. plans, |
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which are expected to be in excess of required minimums in many cases. The U.S. five-year average consists of $460 million for 2008 and then approximately $300 million per year for the remaining four years. Our required minimum funding in 2008 is expected to be $110 million in the United States and $120 million outside the United States. | ||
(e) | Does not include unrecognized tax benefits of $999 million because the ultimate disposition and timing of any payments to be made with regard to such amount is 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. |
Millions of Dollars | ||||||||||||||||
2008 | ||||||||||||||||
Budget | 2007 | 2006 | 2005 | |||||||||||||
E&P | ||||||||||||||||
United States—Alaska | $ | 1,007 | 666 | 820 | 746 | |||||||||||
United States—Lower 48 | 3,259 | 3,122 | 2,008 | 891 | ||||||||||||
International | 6,787 | 6,147 | 6,685 | 5,047 | ||||||||||||
11,053 | 9,935 | 9,513 | 6,684 | |||||||||||||
Midstream | 6 | 5 | 4 | 839 | ||||||||||||
R&M | ||||||||||||||||
United States | 2,060 | 1,146 | 1,597 | 1,537 | ||||||||||||
International | 741 | 240 | 1,419 | 201 | ||||||||||||
2,801 | 1,386 | 3,016 | 1,738 | |||||||||||||
LUKOIL Investment | - | - | 2,715 | 2,160 | ||||||||||||
Chemicals | - | - | - | - | ||||||||||||
Emerging Businesses | 226 | 257 | 83 | 5 | ||||||||||||
Corporate and Other | 238 | 208 | 265 | 194 | ||||||||||||
$ | 14,324 | 11,791 | 15,596 | 11,620 | ||||||||||||
United States | $ | 6,435 | 5,225 | 4,735 | 4,207 | |||||||||||
International | 7,889 | 6,566 | 10,861 | 7,413 | ||||||||||||
$ | 14,324 | 11,791 | 15,596 | 11,620 | ||||||||||||
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Capital spending for E&P during the three-year period ending December 31, 2007, totaled $26.1 billion. The expenditures over this period supported key exploration and development projects including:
• | Development drilling in the Greater Kuparuk Area, including West Sak; the Greater Prudhoe Bay Area; the Alpine field, including satellite field prospects; exploratory drilling; and the acquisition of acreage in Alaska. | ||
• | Oil and natural gas developments in the Lower 48 states, including New Mexico, Texas, Louisiana, Oklahoma, Montana, North Dakota and Colorado. | ||
• | The Magnolia development, Ursa and K-2 fields in the deepwater Gulf of Mexico. | ||
• | The acquisition of limited-term, fixed-volume overriding royalty interests in Utah and the San Juan Basin related to our natural gas production. | ||
• | Investment in the West2East Pipeline LLC (West2East), a company holding a 100 percent interest in Rockies Express Pipeline LLC (Rockies Express). | ||
• | Expansion of the Syncrude oil sands project, the development of the Surmont heavy-oil project, capital expenditures related to the EnCana upstream business venture, and development of conventional oil and gas reserves, all in Canada. | ||
• | Development of the Corocoro field offshore Venezuela (see Note 13—Impairments, in the Notes to Consolidated Financial Statements, for additional information). | ||
• | The Ekofisk Area growth project and Alvheim project in the Norwegian North Sea. | ||
• | The Statfjord Late-Life project straddling the offshore boundary between Norway and the United Kingdom. | ||
• | The Britannia satellite and Clair developments in the U.K. North Sea and Atlantic Margin, respectively. | ||
• | An integrated project to produce and liquefy natural gas from Qatar’s North field. | ||
• | Investments in three fields in Algeria. | ||
• | Expenditures related to the terms under which we returned to our former oil and natural gas production operations in the Waha concessions in Libya and continued development of these concessions. | ||
• | Ongoing development of onshore oil and natural gas fields in Nigeria and ongoing exploration activities both onshore and on deepwater leases. | ||
• | The Kashagan field and satellite prospects in the Caspian Sea, offshore Kazakhstan. | ||
• | The acquisition of an interest in OOO Naryanmarneftegaz (NMNG), a joint venture with LUKOIL, and development of the Yuzhno Khylchuyu (YK) field. | ||
• | The Bayu-Undan gas recycle and liquefied natural gas development projects in the Timor Sea and northern Australia, respectively. | ||
• | The Belanak, Suban, Kerisi, Hiu and Belut projects in Indonesia. | ||
• | The Peng Lai 19-3 development in China’s Bohai Bay and additional Bohai Bay appraisal and adjacent field prospects. | ||
• | Expenditures to develop the Su Tu Vang field and continued in-field development of the Rang Dong field in Vietnam. |
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• | The Ekofisk field in the North Sea. | ||
• | The Peng Lai 19-3 field in China. | ||
• | Fields in the United States and Canada. | ||
• | EnCana business venture projects—Christina Lake and Foster Creek. | ||
• | The Surmont heavy-oil project in Canada. |
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Capital spending for Midstream during the three-year period ending December 31, 2007, was primarily related to increasing our ownership interest in DCP Midstream in 2005 from 30.3 percent to 50 percent.
Capital spending for R&M during the three-year period ending December 31, 2007, was primarily for acquiring additional crude oil refining capacity, clean fuels projects to meet new environmental standards, refinery-upgrade projects to improve product yields, the operating integrity of key processing units, as well as for safety projects. In addition, in December 2007, we invested funds to acquire a 50 percent equity interest in the Keystone Oil Pipeline (Keystone), a joint venture to construct a crude oil pipeline from Hardisty, Alberta to U.S. Midwest markets in Illinois and Oklahoma. During this three-year period, R&M capital spending was $6.1 billion, representing 16 percent of our total capital expenditures and investments.
• | Acquisition of the Wilhelmshaven refinery in Germany. | ||
• | Debottlenecking of a crude and fluid catalytic cracking unit, and completion of a new sulfur plant at the Ferndale refinery. | ||
• | A new ultra-low-sulfur diesel hydrotreater at the Sweeny refinery. | ||
• | Revamp of an existing hydrotreater for ultra-low-sulfur diesel and a new hydrogen plant at the Wood River refinery. | ||
• | Expansion of existing hydrotreaters for both low-sulfur gasoline and ultra-low-sulfur diesel, with the addition of a new hydrogen plant at the Bayway refinery. | ||
• | A new hydrotreater for ultra-low-sulfur diesel and a hydrogen plant at the Ponca City refinery. | ||
• | Revamps of existing hydrotreaters for ultra-low-sulfur diesel at the Los Angeles, Trainer and Ferndale refineries. | ||
• | A new ultra-low-sulfur diesel hydrotreater and hydrogen plant at the Billings refinery. | ||
• | A fluid catalytic cracking gasoline hydrotreater at the Alliance refinery for production of low-sulfur gasoline. | ||
• | A sulfur removal technology unit at the Lake Charles refinery for the production of low-sulfur gasoline. | ||
• | A new ultra-low-sulfur diesel hydrotreater at the Rodeo facility of our San Francisco refinery. |
• | Expansion of a hydrocracker at the Rodeo facility of our San Francisco refinery. | ||
• | Construction of a low-sulfur gasoline project at the Billings refinery. | ||
• | U.S. programs aimed at air emission reductions. |
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Capital spending in our LUKOIL Investment segment during the three-year period ending December 31, 2007, was for continued purchases of ordinary shares of LUKOIL to increase our ownership interest. However, no additional purchases were made in 2007, and none are expected in 2008.
Capital spending for Emerging Businesses during the three-year period ending December 31, 2007, was primarily for an expansion of the Immingham combined heat and power cogeneration plant near the company’s Humber refinery in the United Kingdom. In addition, in October 2007, we purchased a 50 percent interest in Sweeny Cogeneration LP (SCLP). SCLP provides steam and electric power to the Sweeny refinery complex with any excess power sold into the market. We account for this joint venture using the equity method of accounting.
We accrue for non-income-tax-related contingencies when a loss is probable and the amounts can be reasonably estimated. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. In the case of income-tax-related contingencies, we adopted FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109” (FIN 48), effective January 1, 2007. FIN 48 requires a cumulative probability-weighted loss accrual in cases where sustaining a tax position is less than certain. Based on currently available information, we believe it is remote that future costs related to known contingent liability exposures will exceed current accruals by an amount that would have a material adverse impact on our consolidated financial statements.
We are subject to the same numerous international, federal, state, and local environmental laws and regulations, as are other companies in the petroleum exploration and production, refining, and crude oil and refined product marketing and transportation businesses. The most significant of these environmental laws and regulations include, among others, the:
• | Federal Clean Air Act, which governs air emissions. | ||
• | Federal Clean Water Act, which governs discharges to water bodies. | ||
• | 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 threatened to occur. | ||
• | Federal Resource Conservation and Recovery Act (RCRA), which governs the treatment, storage, and disposal of solid waste. | ||
• | Federal Oil Pollution Act of 1990 (OPA90), under which owners and operators of onshore facilities and pipelines, lessees or permittees of an area in which an offshore facility is located, and owners and operators of vessels are liable for removal costs and damages that result from a discharge of oil into navigable waters of the United States. |
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• | Federal Emergency Planning and Community Right-to-Know Act (EPCRA), which requires facilities to report toxic chemical inventories with local emergency planning committees and responses departments. | ||
• | 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 Emissions Trading Scheme, the program through which many of the European Union member states are implementing the Kyoto Protocol. | ||
• | California’s Assembly Bill 32, which requires the California Air Resources Board (CARB) to develop regulations and market mechanisms that will ultimately reduce California’s greenhouse gas emissions by 25 percent by 2020. |
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• | Two regulations issued by the Alberta government in 2007 under the Climate Change and Emissions Act. These regulations require any existing facility with emissions equal to or greater than 100,000 metric tons of carbon dioxide or equivalent per year to reduce the net emissions intensity of that facility by 2 percent per year beginning July 1, 2007, with an ultimate reduction target of 12 percent of baseline emissions. | ||
• | The U.S. Supreme Court decision inMassachusetts v. EPA, 549 U.S. ___, 127 S.Ct. 1438 ( 2007) confirming that the U.S. Environmental Protection Agency (EPA) has the authority to regulate carbon dioxide as an “air pollutant” under the federal Clean Air Act. |
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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.
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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.
Engineering estimates of the quantities of recoverable oil and gas reserves in oil and gas fields and in-place crude bitumen volumes in oil sand mining operations are inherently imprecise and represent only approximate amounts because of the subjective judgments involved in developing such information. Reserve estimates are based on subjective judgments involving geological and engineering assessments of in-place hydrocarbon volumes, the production or mining plan, historical extraction recovery and processing yield factors, installed plant operating capacity and operating approval limits. The reliability of these estimates at any point in time depends on both the quality and quantity of the technical and economic data and the efficiency of extracting and processing the hydrocarbons.
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Accounting for the acquisition of a business requires the allocation of the purchase price to the various assets and liabilities of the acquired business. For most assets and liabilities, purchase price allocation is accomplished by recording the asset or liability at its estimated fair value. The most difficult estimations of individual fair values are those involving properties, plants and equipment and identifiable intangible assets. We use all available information to make these fair value determinations. We have, if necessary, up to one year after the acquisition closing date to finish these fair value determinations and finalize the purchase price allocation.
At December 31, 2007, we had $731 million of intangible assets determined to have indefinite useful lives, thus they are not amortized. This judgmental assessment of an indefinite useful life has to be continuously evaluated in the future. If, due to changes in facts and circumstances, management determines that these intangible assets then have definite useful lives, amortization will have to commence at that time on a prospective basis. As long as these intangible assets are judged to have indefinite lives, they will be subject to periodic lower-of-cost-or-market tests that require management’s judgment of the estimated fair value of these intangible assets. See Note 12—Goodwill and Intangibles, in the Notes to Consolidated Financial Statements, for additional information.
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In late 2007, we submitted a proposal to the governor of Alaska to advance the development of the Alaska Natural Gas Pipeline Project. The proposed pipeline would transport approximately 4 billion cubic feet per day of natural gas from the Alaska North Slope to markets in Canada and the United States. We have a 36.1 percent non-operator interest in the Greater Prudhoe Area fields that are expected to be a primary source of natural gas to be shipped in the proposed pipeline. Our proposal was submitted as an alternative to the process the Alaska Legislature established in its Alaska Gasline Inducement Act (AGIA). In our proposal, we stated our willingness to make significant investments, without state matching funds, to advance this project. In January 2008, we received a letter from the governor of Alaska stating our alternative does not give the state a reason to deviate from the AGIA process. We formally responded to the governor’s letter on January 24, 2008. As a result of the lack of engagement by the state of Alaska on our proposal, we are reassessing how best to advance the Alaska natural gas pipeline project. During this reassessment, as an initial step we will continue planning and contracting efforts in preparation for route reconnaissance and environmental studies starting in June 2008. We expect to continue to testify before the Alaska Legislature and engage the Alaska public with our view of the best path forward to advance the gas pipeline project.
Negotiations continue between ConocoPhillips and Venezuelan authorities concerning appropriate compensation for the expropriation of the company’s oil interests. We continue to preserve all our rights with respect to this situation, including our rights under the contracts we signed and under international and Venezuelan law. We continue to evaluate our options in realizing adequate compensation for the value of our oil investments and operations in Venezuela and filed a request for international arbitration on November 2, 2007, with the International Centre for Settlement of Investment Disputes (ICSID), an arm of the World Bank. The request was registered by ICSID on December 13, 2007.
On October 25, 2007, the Alberta provincial government publicly announced its intention to make a change to the royalty structure for Crown lands, effective January 1, 2009. Although the government’s proposed change will require legislative and regulatory amendments to become effective and may be further modified before final adoption, there is a high likelihood there will be some form of change to the royalty structure in Alberta. While the precise impact of the proposed change is not determinable at this time, the adoption of the proposed royalty structure could result in a range of outcomes, including a negative adjustment to our Canadian reserve base. This change will impact both our conventional western Canada natural gas business and our oil sands operations.
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• | Fluctuations in crude oil, natural gas and natural gas liquids prices, refining and marketing margins and margins for our chemicals business. | ||
• | Potential failure or delays in achieving expected reserve or production levels from existing and future oil and gas development projects due to operating hazards, drilling risks and the inherent uncertainties in predicting oil and gas reserves and oil and gas reservoir performance. | ||
• | Unsuccessful exploratory drilling activities or the inability to obtain access to exploratory acreage. | ||
• | Failure of new products and services to achieve market acceptance. | ||
• | Unexpected changes in costs or technical requirements for constructing, modifying or operating facilities for exploration and production projects, manufacturing or refining. | ||
• | Unexpected technological or commercial difficulties in manufacturing, refining, or transporting our products, including synthetic crude oil and chemicals products. | ||
• | Lack of, or disruptions in, adequate and reliable transportation for our crude oil, natural gas, natural gas liquids, LNG and refined products. | ||
• | Inability to timely obtain or maintain permits, including those necessary for construction of LNG terminals or regasification facilities, 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 LNG and refinery projects and related facilities. | ||
• | Potential disruption or interruption of our operations due to accidents, extraordinary weather events, civil unrest, political events or terrorism. | ||
• | International monetary conditions and exchange controls. | ||
• | Substantial investment or reduced demand for products as a result of existing or future environmental rules and regulations. | ||
• | Liability for remedial actions, including removal and reclamation obligations, under environmental regulations. | ||
• | Liability resulting from litigation. | ||
• | General domestic and international economic and political developments, including: armed hostilities; expropriation of assets; changes in governmental policies relating to crude oil, natural gas, natural gas liquids or refined product pricing, regulation, or taxation; other political, economic or diplomatic developments; and international monetary fluctuations. | ||
• | Changes in tax and other laws, regulations (including alternative energy mandates), or royalty rules applicable to our business. |
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• | Inability to obtain economical financing for projects, construction or modification of facilities and general corporate purposes. | ||
• | The operation and financing of our midstream and chemicals joint ventures. | ||
• | The factors generally described in the “Risk Factors” section included in “Items 1 and 2—Business and Properties” in this report. |
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We operate in the worldwide crude oil, refined products, natural gas, natural gas liquids, and electric power markets and are exposed to fluctuations in the prices for these commodities. These fluctuations can affect our revenues, as well as the cost of operating, investing, and financing activities. Generally, our policy is to remain exposed to the market prices of commodities; however, executive management may elect to use derivative instruments to hedge the price risk of our crude oil and natural gas production, as well as refinery margins.
• | Balance physical systems. In addition to cash settlement prior to contract expiration, exchange traded futures contracts also may be settled by physical delivery of the commodity, providing another source of supply to meet our refinery requirements or marketing demand. | ||
• | Meet customer needs. Consistent with our policy to generally remain exposed to market prices, we use swap contracts to convert fixed-price sales contracts, which are often requested by natural gas and refined product consumers, to a floating market price. | ||
• | Manage the risk to our cash flows from price exposures on specific crude oil, natural gas, refined product and electric power transactions. | ||
• | Enable us to use the market knowledge gained from these activities to do a limited amount of trading not directly related to our physical business. For the years ended December 31, 2007 and 2006, the gains or losses from this activity were not material to our cash flows or net income. |
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The following tables provide information about our financial instruments that are sensitive to changes in short-term U.S. interest rates. The debt table presents principal cash flows and related weighted-average interest rates by expected maturity dates. Weighted-average variable rates are based on implied forward rates in the yield curve at the reporting date. The carrying amount of our floating-rate debt approximates its fair value. The fair value of the fixed-rate financial instruments is estimated based on quoted market prices.
Millions of Dollars Except as Indicated | ||||||||||||||||
Debt | ||||||||||||||||
Fixed Rate | Average | Floating Rate | Average | |||||||||||||
Expected Maturity Date | Maturity | Interest Rate | Maturity | Interest Rate | ||||||||||||
Year-End 2007 | ||||||||||||||||
2008 | $ | 324 | 7.12 | % | $ | 1,000 | 5.58 | % | ||||||||
2009 | 313 | 6.44 | 950 | 5.47 | ||||||||||||
2010 | 1,433 | 8.85 | - | - | ||||||||||||
2011 | 3,175 | 6.74 | 2,000 | 5.58 | ||||||||||||
2012 | 1,267 | 4.94 | 743 | 5.43 | ||||||||||||
Remaining years | 9,082 | 6.68 | 658 | 4.36 | ||||||||||||
Total | $ | 15,594 | $ | 5,351 | ||||||||||||
Fair value | $ | 17,750 | $ | 5,351 | ||||||||||||
Year-End 2006 | ||||||||||||||||
2007 | $ | 557 | 7.43 | % | $ | 1,000 | 5.37 | % | ||||||||
2008 | 32 | 6.96 | - | - | ||||||||||||
2009 | 307 | 6.43 | 1,250 | 5.47 | ||||||||||||
2010 | 1,433 | 8.85 | - | - | ||||||||||||
2011 | 3,175 | 6.74 | 7,944 | 5.53 | ||||||||||||
Remaining years | 9,983 | 6.57 | 691 | 4.29 | ||||||||||||
Total | $ | 15,487 | $ | 10,885 | ||||||||||||
Fair value | $ | 16,856 | $ | 10,885 | ||||||||||||
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Millions of Dollars Except as Indicated | ||||||||
Joint Venture Acquisition Obligation | ||||||||
Fixed Rate | Average | |||||||
Expected Maturity Date | Maturity | Interest Rate | ||||||
Year-End 2007 | ||||||||
2008 | $ | 593 | 5.30 | % | ||||
2009 | 626 | 5.30 | ||||||
2010 | 659 | 5.30 | ||||||
2011 | 695 | 5.30 | ||||||
2012 | 732 | 5.30 | ||||||
Remaining years | 3,582 | 5.30 | ||||||
Total | $ | 6,887 | ||||||
Fair value | $ | 7,031 | ||||||
We have foreign currency exchange rate risk resulting from international operations. We do not comprehensively hedge the exposure to currency rate changes, although we may choose to selectively hedge exposures to foreign currency rate risk. Examples include firm commitments for capital projects, certain local currency tax payments and dividends, and cash returns from net investments in foreign affiliates to be remitted within the coming year.
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In Millions | ||||||||||||||||
Foreign Currency Swaps | Notional* | Fair Market Value** | ||||||||||||||
2007 | 2006 | 2007 | 2006 | |||||||||||||
Sell U.S. dollar, buy euro | USD | 744 | 242 | $ | 3 | 5 | ||||||||||
Sell U.S. dollar, buy British pound | USD | 1,049 | 647 | (16 | ) | 20 | ||||||||||
Sell U.S. dollar, buy Canadian dollar | USD | 1,195 | 1,367 | 13 | (19 | ) | ||||||||||
Sell U.S. dollar, buy Czech koruna | USD | - | 7 | - | - | |||||||||||
Sell U.S. dollar, buy Danish krone | USD | 20 | 17 | - | - | |||||||||||
Sell U.S. dollar, buy Norwegian kroner | USD | 779 | 1,145 | 15 | 15 | |||||||||||
Sell U.S. dollar, buy Swedish krona | USD | 11 | 108 | - | - | |||||||||||
Sell U.S. dollar, buy Slovakia koruna | USD | - | 2 | - | - | |||||||||||
Sell U.S. dollar, buy Hungary forint | USD | - | 4 | - | - | |||||||||||
Sell euro, buy Norwegian kroner | EUR | - | 10 | - | - | |||||||||||
Sell euro, buy Canadian dollar | EUR | 58 | - | - | - | |||||||||||
Buy euro, sell British pound | EUR | 1 | 125 | 3 | - | |||||||||||
**Denominated in U.S. dollars.
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Page | ||||
Report of Management | 99 | |||
Report of Independent Registered Public Accounting Firm on Consolidated Financial Statements | 100 | |||
Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting | 101 | |||
Consolidated Income Statement for the years ended December 31, 2007, 2006 and 2005 | 103 | |||
Consolidated Balance Sheet at December 31, 2007 and 2006 | 104 | |||
Consolidated Statement of Cash Flows for the years ended December 31, 2007, 2006 and 2005 | 105 | |||
Consolidated Statement of Changes in Common Stockholders’ Equity for the years ended December 31, 2007, 2006 and 2005 | 106 | |||
Notes to Consolidated Financial Statements | 107 | |||
Supplementary Information | ||||
Oil and Gas Operations | 174 | |||
Selected Quarterly Financial Data | 194 | |||
Condensed Consolidating Financial Information | 195 | |||
INDEX TO FINANCIAL STATEMENT SCHEDULES | ||||
Schedule II—Valuation and Qualifying Accounts | 207 |
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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.
/s/ James J. Mulva | /s/ John A. Carrig | |
James J. Mulva | John A. Carrig | |
Chairman, President and | Executive Vice President, Finance, | |
Chief Executive Officer | and Chief Financial Officer |
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ConocoPhillips
February 21, 2008
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Internal Control Over Financial Reporting
ConocoPhillips
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February 21, 2008
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Consolidated Income Statement | ConocoPhillips |
Years Ended December 31 | Millions of Dollars | |||||||||||
2007 | 2006 | 2005 | ||||||||||
Revenues and Other Income | ||||||||||||
Sales and other operating revenues* | $ | 187,437 | 183,650 | 179,442 | ||||||||
Equity in earnings of affiliates | 5,087 | 4,188 | 3,457 | |||||||||
Other income | 1,971 | 685 | 465 | |||||||||
Total Revenues and Other Income | 194,495 | 188,523 | 183,364 | |||||||||
Costs and Expenses | ||||||||||||
Purchased crude oil, natural gas and products | 123,429 | 118,899 | 124,925 | |||||||||
Production and operating expenses | 10,683 | 10,413 | 8,562 | |||||||||
Selling, general and administrative expenses | 2,306 | 2,476 | 2,247 | |||||||||
Exploration expenses | 1,007 | 834 | 661 | |||||||||
Depreciation, depletion and amortization | 8,298 | 7,284 | 4,253 | |||||||||
Impairment—expropriated assets | 4,588 | - | - | |||||||||
Impairments | 442 | 683 | 42 | |||||||||
Taxes other than income taxes* | 18,990 | 18,187 | 18,356 | |||||||||
Accretion on discounted liabilities | 341 | 281 | 193 | |||||||||
Interest and debt expense | 1,253 | 1,087 | 497 | |||||||||
Foreign currency transaction (gains) losses | (201 | ) | (30 | ) | 48 | |||||||
Minority interests | 87 | 76 | 33 | |||||||||
Total Costs and Expenses | 171,223 | 160,190 | 159,817 | |||||||||
Income from continuing operations before income taxes | 23,272 | 28,333 | 23,547 | |||||||||
Provision for income taxes | 11,381 | 12,783 | 9,907 | |||||||||
Income From Continuing Operations | 11,891 | 15,550 | 13,640 | |||||||||
Discontinued operations | - | - | (23 | ) | ||||||||
Income before cumulative effect of changes in accounting principles | 11,891 | 15,550 | 13,617 | |||||||||
Cumulative effect of changes in accounting principles | - | - | (88 | ) | ||||||||
Net Income | $ | 11,891 | 15,550 | 13,529 | ||||||||
Income (Loss) Per Share of Common Stock(dollars) | ||||||||||||
Basic | ||||||||||||
Continuing operations | $ | 7.32 | 9.80 | 9.79 | ||||||||
Discontinued operations | - | - | (.02 | ) | ||||||||
Before cumulative effect of changes in accounting principles | 7.32 | 9.80 | 9.77 | |||||||||
Cumulative effect of changes in accounting principles | - | - | (.06 | ) | ||||||||
Net Income | $ | 7.32 | 9.80 | 9.71 | ||||||||
Diluted | ||||||||||||
Continuing operations | $ | 7.22 | 9.66 | 9.63 | ||||||||
Discontinued operations | - | - | (.02 | ) | ||||||||
Before cumulative effect of changes in accounting principles | 7.22 | 9.66 | 9.61 | |||||||||
Cumulative effect of changes in accounting principles | - | - | (.06 | ) | ||||||||
Net Income | $ | 7.22 | 9.66 | 9.55 | ||||||||
Average Common Shares Outstanding(in thousands) | ||||||||||||
Basic | 1,623,994 | 1,585,982 | 1,393,371 | |||||||||
Diluted | 1,645,919 | 1,609,530 | 1,417,028 | |||||||||
* Includes excise taxes on petroleum products sales: | $ | 15,937 | 16,072 | 17,037 | ||||||||
See Notes to Consolidated Financial Statements. |
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Consolidated Balance Sheet | ConocoPhillips |
At December 31 | Millions of Dollars | |||||||
2007 | 2006 | |||||||
Assets | ||||||||
Cash and cash equivalents | $ | 1,456 | 817 | |||||
Accounts and notes receivable (net of allowance of $58 million in 2007 and $45 million in 2006) | 14,687 | 13,456 | ||||||
Accounts and notes receivable—related parties | 1,667 | 650 | ||||||
Inventories | 4,223 | 5,153 | ||||||
Prepaid expenses and other current assets | 2,702 | 4,990 | ||||||
Total Current Assets | 24,735 | 25,066 | ||||||
Investments and long-term receivables | 31,457 | 19,595 | ||||||
Loans and advances—related parties | 1,871 | 1,118 | ||||||
Net properties, plants and equipment | 89,003 | 86,201 | ||||||
Goodwill | 29,336 | 31,488 | ||||||
Intangibles | 896 | 951 | ||||||
Other assets | 459 | 362 | ||||||
Total Assets | $ | 177,757 | 164,781 | |||||
Liabilities | ||||||||
Accounts payable | $ | 16,591 | 14,163 | |||||
Accounts payable—related parties | 1,270 | 471 | ||||||
Notes payable and long-term debt due within one year | 1,398 | 4,043 | ||||||
Accrued income and other taxes | 4,814 | 4,407 | ||||||
Employee benefit obligations | 920 | 895 | ||||||
Other accruals | 1,889 | 2,452 | ||||||
Total Current Liabilities | 26,882 | 26,431 | ||||||
Long-term debt | 20,289 | 23,091 | ||||||
Asset retirement obligations and accrued environmental costs | 7,261 | 5,619 | ||||||
Joint venture acquisition obligation—related party | 6,294 | - | ||||||
Deferred income taxes | 21,018 | 20,074 | ||||||
Employee benefit obligations | 3,191 | 3,667 | ||||||
Other liabilities and deferred credits | 2,666 | 2,051 | ||||||
Total Liabilities | 87,601 | 80,933 | ||||||
Minority Interests | 1,173 | 1,202 | ||||||
Common Stockholders’ Equity | ||||||||
Common stock (2,500,000,000 shares authorized at $.01 par value) | ||||||||
Issued (2007—1,718,448,829 shares; 2006—1,705,502,609 shares) | ||||||||
Par value | 17 | 17 | ||||||
Capital in excess of par | 42,724 | 41,926 | ||||||
Grantor trusts (at cost: 2007—42,411,331 shares; 2006—44,358,585 shares) | (731 | ) | (766 | ) | ||||
Treasury stock (at cost: 2007—104,607,149 shares; 2006—15,061,613 shares) | (7,969 | ) | (964 | ) | ||||
Accumulated other comprehensive income | 4,560 | 1,289 | ||||||
Unearned employee compensation | (128 | ) | (148 | ) | ||||
Retained earnings | 50,510 | 41,292 | ||||||
Total Common Stockholders’ Equity | 88,983 | 82,646 | ||||||
Total | $ | 177,757 | 164,781 | |||||
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Consolidated Statement of Cash Flows | ConocoPhillips |
Years Ended December 31 | Millions of Dollars | ||||||||||||
2007 | 2006 | 2005 | |||||||||||
Cash Flows From Operating Activities | |||||||||||||
Net income | $ | 11,891 | 15,550 | 13,529 | |||||||||
Adjustments to reconcile net income to net cash provided by continuing operations | |||||||||||||
Non-working capital adjustments | |||||||||||||
Depreciation, depletion and amortization | 8,298 | 7,284 | 4,253 | ||||||||||
Impairment—expropriated assets | 4,588 | - | - | ||||||||||
Impairments | 442 | 683 | 42 | ||||||||||
Dry hole costs and leasehold impairments | 463 | 351 | 349 | ||||||||||
Accretion on discounted liabilities | 341 | 281 | 193 | ||||||||||
Deferred taxes | (157 | ) | 263 | 1,101 | |||||||||
Undistributed equity earnings | (1,823 | ) | (945 | ) | (1,774 | ) | |||||||
Gain on asset dispositions | (1,348 | ) | (116 | ) | (278 | ) | |||||||
Discontinued operations | - | - | 23 | ||||||||||
Cumulative effect of changes in accounting principles | - | - | 88 | ||||||||||
Other | 105 | (201 | ) | (139 | ) | ||||||||
Working capital adjustments* | |||||||||||||
Decrease in aggregate balance of accounts receivable sold | - | - | (480 | ) | |||||||||
Increase in other accounts and notes receivable | (2,492 | ) | (906 | ) | (2,665 | ) | |||||||
Decrease (increase) in inventories | 767 | (829 | ) | (182 | ) | ||||||||
Decrease (increase) in prepaid expenses and other current assets | 487 | (372 | ) | (407 | ) | ||||||||
Increase in accounts payable | 2,772 | 657 | 3,156 | ||||||||||
Increase (decrease) in taxes and other accruals | 216 | (184 | ) | 824 | |||||||||
Net cash provided by continuing operations | 24,550 | 21,516 | 17,633 | ||||||||||
Net cash used in discontinued operations | - | - | (5 | ) | |||||||||
Net Cash Provided by Operating Activities | 24,550 | 21,516 | 17,628 | ||||||||||
Cash Flows From Investing Activities | |||||||||||||
Acquisition of Burlington Resources Inc.** | - | (14,285 | ) | - | |||||||||
Capital expenditures and investments, including dry hole costs** | (11,791 | ) | (15,596 | ) | (11,620 | ) | |||||||
Proceeds from asset dispositions | 3,572 | 545 | 768 | ||||||||||
Long-term advances/loans—related parties | (682 | ) | (780 | ) | (275 | ) | |||||||
Collection of advances/loans—related parties | 89 | 123 | 111 | ||||||||||
Other | 250 | - | - | ||||||||||
Net cash used in continuing operations | (8,562 | ) | (29,993 | ) | (11,016 | ) | |||||||
Net Cash Used in Investing Activities | (8,562 | ) | (29,993 | ) | (11,016 | ) | |||||||
Cash Flows From Financing Activities | |||||||||||||
Issuance of debt | 935 | 17,314 | 452 | ||||||||||
Repayment of debt | (6,454 | ) | (7,082 | ) | (3,002 | ) | |||||||
Issuance of company common stock | 285 | 220 | 402 | ||||||||||
Repurchase of company common stock | (7,001 | ) | (925 | ) | (1,924 | ) | |||||||
Dividends paid on company common stock | (2,661 | ) | (2,277 | ) | (1,639 | ) | |||||||
Other | (444 | ) | (185 | ) | 27 | ||||||||
Net cash provided by (used in) continuing operations | (15,340 | ) | 7,065 | (5,684 | ) | ||||||||
Net Cash Provided by (Used in) Financing Activities | (15,340 | ) | 7,065 | (5,684 | ) | ||||||||
Effect of Exchange Rate Changes on Cash and Cash Equivalents | (9 | ) | 15 | (101 | ) | ||||||||
Net Change in Cash and Cash Equivalents | 639 | (1,397 | ) | 827 | |||||||||
Cash and cash equivalents at beginning of year | 817 | 2,214 | 1,387 | ||||||||||
Cash and Cash Equivalents at End of Year | $ | 1,456 | 817 | 2,214 | |||||||||
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Consolidated Statement of Changes in Common Stockholders’ Equity | ConocoPhillips |
Millions of Dollars | ||||||||||||||||||||||||||||||||||||||||||||
Shares of Common Stock | Accumulated | |||||||||||||||||||||||||||||||||||||||||||
Held in | Common Stock | Other | Unearned | |||||||||||||||||||||||||||||||||||||||||
Held in | Grantor | Par | Capital in | Treasury | Grantor | Comprehensive | Employee | Retained | ||||||||||||||||||||||||||||||||||||
Issued | Treasury | Trusts | Value | Excess of Par | Stock | Trusts | Income | Compensation | Earnings | Total | ||||||||||||||||||||||||||||||||||
December 31, 2004 | 1,437,729,662 | - | 48,182,820 | $ | 14 | 26,047 | - | (816 | ) | 1,592 | (242 | ) | 16,128 | 42,723 | ||||||||||||||||||||||||||||||
Net income | 13,529 | 13,529 | ||||||||||||||||||||||||||||||||||||||||||
Other comprehensive income (loss) | ||||||||||||||||||||||||||||||||||||||||||||
Minimum pension liability adjustment | (56 | ) | (56 | ) | ||||||||||||||||||||||||||||||||||||||||
Foreign currency translation adjustments | (717 | ) | (717 | ) | ||||||||||||||||||||||||||||||||||||||||
Unrealized loss on securities | (6 | ) | (6 | ) | ||||||||||||||||||||||||||||||||||||||||
Hedging activities | 1 | 1 | ||||||||||||||||||||||||||||||||||||||||||
Comprehensive income | 12,751 | |||||||||||||||||||||||||||||||||||||||||||
Cash dividends paid on company common stock | (1,639 | ) | (1,639 | ) | ||||||||||||||||||||||||||||||||||||||||
Repurchase of company common stock | 32,080,000 | (1,924 | ) | (1,924 | ) | |||||||||||||||||||||||||||||||||||||||
Distributed under incentive compensation and other benefit plans | 18,131,678 | (2,250,727 | ) | 707 | 38 | 745 | ||||||||||||||||||||||||||||||||||||||
Recognition of unearned compensation | 75 | 75 | ||||||||||||||||||||||||||||||||||||||||||
December 31, 2005 | 1,455,861,340 | 32,080,000 | 45,932,093 | 14 | 26,754 | (1,924 | ) | (778 | ) | 814 | (167 | ) | 28,018 | 52,731 | ||||||||||||||||||||||||||||||
Net income | 15,550 | 15,550 | ||||||||||||||||||||||||||||||||||||||||||
Other comprehensive income Minimum pension liability adjustment | 33 | 33 | ||||||||||||||||||||||||||||||||||||||||||
Foreign currency translation adjustments | 1,013 | 1,013 | ||||||||||||||||||||||||||||||||||||||||||
Hedging activities | 4 | 4 | ||||||||||||||||||||||||||||||||||||||||||
Comprehensive income | 16,600 | |||||||||||||||||||||||||||||||||||||||||||
Initial application of SFAS No. 158 | (575 | ) | (575 | ) | ||||||||||||||||||||||||||||||||||||||||
Cash dividends paid on company common stock | (2,277 | ) | (2,277 | ) | ||||||||||||||||||||||||||||||||||||||||
Burlington Resources acquisition | 239,733,571 | (32,080,000 | ) | 890,180 | 3 | 14,475 | 1,924 | (53 | ) | 16,349 | ||||||||||||||||||||||||||||||||||
Repurchase of company common stock | 15,061,613 | (542,000 | ) | (964 | ) | 32 | (932 | ) | ||||||||||||||||||||||||||||||||||||
Distributed under incentive compensation and other benefit plans | 9,907,698 | (1,921,688 | ) | 697 | 33 | 730 | ||||||||||||||||||||||||||||||||||||||
Recognition of unearned compensation | 19 | 19 | ||||||||||||||||||||||||||||||||||||||||||
Other | 1 | 1 | ||||||||||||||||||||||||||||||||||||||||||
December 31, 2006 | 1,705,502,609 | 15,061,613 | 44,358,585 | 17 | 41,926 | (964 | ) | (766 | ) | 1,289 | (148 | ) | 41,292 | 82,646 | ||||||||||||||||||||||||||||||
Net income | 11,891 | 11,891 | ||||||||||||||||||||||||||||||||||||||||||
Other comprehensive income (loss) | ||||||||||||||||||||||||||||||||||||||||||||
Defined benefit pension plans: | ||||||||||||||||||||||||||||||||||||||||||||
Net prior service cost | 63 | 63 | ||||||||||||||||||||||||||||||||||||||||||
Net gain | 213 | 213 | ||||||||||||||||||||||||||||||||||||||||||
Non-sponsored plans | (2 | ) | (2 | ) | ||||||||||||||||||||||||||||||||||||||||
Foreign currency translation adjustments | 3,075 | 3,075 | ||||||||||||||||||||||||||||||||||||||||||
Hedging activities | (4 | ) | (4 | ) | ||||||||||||||||||||||||||||||||||||||||
Comprehensive income | 15,236 | |||||||||||||||||||||||||||||||||||||||||||
Initial application of SFAS No. 158—equity affiliate | (74 | ) | (74 | ) | ||||||||||||||||||||||||||||||||||||||||
Cash dividends paid on company common stock | (2,661 | ) | (2,661 | ) | ||||||||||||||||||||||||||||||||||||||||
Repurchase of company common stock | 89,545,536 | (177,110 | ) | (7,005 | ) | 11 | (6,994 | ) | ||||||||||||||||||||||||||||||||||||
Distributed under incentive compensation and other benefit plans | 12,946,220 | (1,856,224 | ) | 798 | 31 | 829 | ||||||||||||||||||||||||||||||||||||||
Recognition of unearned compensation | 20 | 20 | ||||||||||||||||||||||||||||||||||||||||||
Other | 86,080 | (7 | ) | (12 | ) | (19 | ) | |||||||||||||||||||||||||||||||||||||
December 31, 2007 | 1,718,448,829 | 104,607,149 | 42,411,331 | $17 | 42,724 | (7,969 | ) | (731 | ) | 4,560 | (128 | ) | 50,510 | 88,983 | ||||||||||||||||||||||||||||||
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Notes to Consolidated Financial Statements | ConocoPhillips |
n | Consolidation Principles and Investments—Our consolidated financial statements include the accounts of majority-owned, controlled subsidiaries and variable interest entities where we are the primary beneficiary. The equity method is used to account for investments in affiliates in which we have the ability to exert significant influence over the affiliates’ operating and financial policies. The cost method is used when we do not have the ability to exert significant influence. Undivided interests in oil and gas joint ventures, pipelines, natural gas plants, certain transportation assets and Canadian Syncrude mining operations are consolidated on a proportionate basis. Other securities and investments, excluding marketable securities, are generally carried at cost. | |
n | Foreign Currency Translation—Adjustments resulting from the process of translating foreign functional currency financial statements into U.S. dollars are included in accumulated other comprehensive income in common stockholders’ equity. Foreign currency transaction gains and losses are included in current earnings. Most of our foreign operations use their local currency as the functional currency. | |
n | Use of Estimates—The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosures of contingent assets and liabilities. Actual results could differ from these estimates. | |
n | Revenue Recognition—Revenues associated with sales of crude oil, natural gas, natural gas liquids, petroleum and chemical products, and other items are recognized when title passes to the customer, which is when the risk of ownership passes to the purchaser and physical delivery of goods occurs, either immediately or within a fixed delivery schedule that is reasonable and customary in the industry. | |
Prior to April 1, 2006, revenues included the sales portion of transactions commonly called buy/sell contracts. Effective April 1, 2006, we implemented Emerging Issues Task Force (EITF) Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” Issue No. 04-13 requires purchases and sales of inventory with the same counterparty and entered into “in contemplation” of one another to be combined and reported net (i.e., on the same income statement line). See Note 2—Changes in Accounting Principles, for additional information about our adoption of this Issue. | ||
Revenues from the production of natural gas and crude oil properties, in which we have an interest with other producers, are recognized based on the actual volumes we sold during the period. Any differences between volumes sold and entitlement volumes, based on our net working interest, which are deemed to be non-recoverable through remaining production, are recognized as accounts receivable or accounts payable, as appropriate. Cumulative differences between volumes sold and entitlement volumes are generally not significant. | ||
Revenues associated with royalty fees from licensed technology are recorded based either upon volumes produced by the licensee or upon the successful completion of all substantive performance requirements related to the installation of licensed technology. |
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n | Shipping and Handling Costs—Our Exploration and Production (E&P) segment includes shipping and handling costs in production and operating expenses for production activities. Transportation costs related to E&P marketing activities are recorded in purchased crude oil, natural gas and products. The Refining and Marketing (R&M) segment records shipping and handling costs in purchased crude oil, natural gas and products. Freight costs billed to customers are recorded as a component of revenue. | |
n | Cash Equivalents—Cash equivalents are highly liquid, short-term investments that are readily convertible to known amounts of cash and have original maturities of three months or less from their date of purchase. They are carried at cost plus accrued interest, which approximates fair value. | |
n | Inventories—We have several valuation methods for our various types of inventories and consistently use the following methods for each type of inventory. Crude oil, petroleum products, and Canadian Syncrude inventories are valued at the lower of cost or market in the aggregate, primarily on the last-in, first-out (LIFO) basis. Any necessary lower-of-cost-or-market write-downs are recorded as permanent adjustments to the LIFO cost basis. LIFO is used to better match current inventory costs with current revenues and to meet tax-conformity requirements. Costs include both direct and indirect expenditures incurred in bringing an item or product to its existing condition and location, but not unusual/non-recurring costs or research and development costs. Materials, supplies and other miscellaneous inventories, such as tubular goods and well equipment, are valued under various methods, including the weighted-average-cost method, and the first-in, first-out (FIFO) method, consistent with industry practice. | |
n | Derivative Instruments—All derivative instruments are recorded on the balance sheet at fair value in either prepaid expenses and other current assets, other assets, other accruals, or other liabilities and deferred credits. Recognition and classification of the gain or loss that results from recording and adjusting a derivative to fair value depends on the purpose for issuing or holding the derivative. Gains and losses from derivatives that are not accounted for as hedges under Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” are recognized immediately in earnings. For derivative instruments that are designated and qualify as a fair value hedge, the gains or losses from adjusting the derivative to its fair value will be immediately recognized in earnings and, to the extent the hedge is effective, offset the concurrent recognition of changes in the fair value of the hedged item. Gains or losses from derivative instruments that are designated and qualify as a cash flow hedge will be recorded on the balance sheet in accumulated other comprehensive income until the hedged transaction is recognized in earnings; however, to the extent the change in the value of the derivative exceeds the change in the anticipated cash flows of the hedged transaction, the excess gains or losses will be recognized immediately in earnings. | |
In the consolidated income statement, gains and losses from derivatives that are held for trading and not directly related to our physical business are recorded in other income. Gains and losses from derivatives used for other purposes are recorded in either, sales and other operating revenues; other income; purchased crude oil, natural gas and products; interest and debt expense; or foreign currency transaction (gains) losses, depending on the purpose for issuing or holding the derivatives. |
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n | Oil and Gas Exploration and Development—Oil and gas exploration and development costs are accounted for using the successful efforts method of accounting. |
n | Syncrude Mining Operations—Capitalized costs, including support facilities, include property acquisition costs and other capital costs incurred. Capital costs are depreciated using the unit-of-production method based on the applicable portion of proven reserves associated with each mine location and its facilities. | |
n | Capitalized Interest—Interest from external borrowings is capitalized on major projects with an expected construction period of one year or longer. Capitalized interest is added to the cost of the underlying asset and is amortized over the useful lives of the assets in the same manner as the underlying assets. | |
n | Intangible Assets Other Than Goodwill—Intangible assets that have finite useful lives are amortized by the straight-line method over their useful lives. Intangible assets that have indefinite useful lives are not amortized but are tested at least annually for impairment. Each reporting period, we evaluate the remaining useful lives of intangible assets not being amortized to determine whether |
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events and circumstances continue to support indefinite useful lives. Intangible assets are considered impaired if the fair value of the intangible asset is lower than net book value. The fair value of intangible assets is determined based on quoted market prices in active markets, if available. If quoted market prices are not available, fair value of intangible assets is determined based upon the present values of expected future cash flows using discount rates commensurate with the risks involved in the asset, or upon estimated replacement cost, if expected future cash flows from the intangible asset are not determinable. | ||
n | Goodwill—Goodwill is not amortized but is tested at least annually for impairment. If the fair value of a reporting unit is less than the recorded book value of the reporting unit’s assets (including goodwill), less liabilities, then a hypothetical purchase price allocation is performed on the reporting unit’s assets and liabilities using the fair value of the reporting unit as the purchase price in the calculation. If the amount of goodwill resulting from this hypothetical purchase price allocation is less than the recorded amount of goodwill, the recorded goodwill is written down to the new amount. For purposes of goodwill impairment calculations, three reporting units had been determined prior to 2007: Worldwide Exploration and Production, Worldwide Refining and Worldwide Marketing. In 2007, the Refining unit and Marketing unit were combined into one unit, Worldwide Refining and Marketing. Because quoted market prices are not available for the company’s reporting units, the fair value of the reporting units is determined based upon consideration of several factors, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the operations and observed market multiples of operating cash flows and net income. | |
n | Depreciation and Amortization—Depreciation and amortization of properties, plants and equipment on producing oil and gas properties, certain pipeline assets (those which are expected to have a declining utilization pattern), and on Syncrude mining operations are determined by the unit-of-production method. Depreciation and amortization of all other properties, plants and equipment are determined by either the individual-unit-straight-line method or the group-straight-line method (for those individual units that are highly integrated with other units). | |
n | Impairment of Properties, Plants and Equipment—Properties, plants and equipment used in operations are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in the future cash flows expected to be generated by an asset group. If, upon review, the sum of the undiscounted pretax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value through additional amortization or depreciation provisions and reported as impairments in the periods in which the determination of the impairment is made. Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets—generally on a field-by-field basis for exploration and production assets, at an entire complex level for refining assets or at a site level for retail stores. The fair value of impaired assets is determined based on quoted market prices in active markets, if available, or upon the present values of expected future cash flows using discount rates commensurate with the risks involved in the asset group. Long-lived assets committed by management for disposal within one year are accounted for at the lower of amortized cost or fair value, less cost to sell. | |
The expected future cash flows used for impairment reviews and related fair value calculations are based on estimated future production volumes, prices and costs, considering all available evidence at the date of review. If the future production price risk has been hedged, the hedged price is used in the calculations for the period and quantities hedged. The impairment review includes cash flows from proved developed and undeveloped reserves, including any development expenditures necessary to achieve that production. Additionally, when probable reserves exist, an appropriate risk-adjusted amount of these reserves may be included in the impairment calculation. The price and cost outlook |
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assumptions used in impairment reviews differ from the assumptions used in the Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserve Quantities. In that disclosure, SFAS No. 69, “Disclosures about Oil and Gas Producing Activities,” requires inclusion of only proved reserves and the use of prices and costs at the balance sheet date, with no projection for future changes in assumptions. |
n | Impairment of Investments in Non-Consolidated Companies—Investments in non-consolidated companies are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred, which is other than a temporary decline in value. The fair value of the impaired investment is based on quoted market prices, if available, or upon the present value of expected future cash flows using discount rates commensurate with the risks of the investment. | |
n | Maintenance and Repairs—The costs of maintenance and repairs, which are not significant improvements, are expensed when incurred. | |
n | Advertising Costs—Production costs of media advertising are deferred until the first public showing of the advertisement. Advances to secure advertising slots at specific sporting or other events are deferred until the event occurs. All other advertising costs are expensed as incurred, unless the cost has benefits that clearly extend beyond the interim period in which the expenditure is made, in which case the advertising cost is deferred and amortized ratably over the interim periods which clearly benefit from the expenditure. | |
n | Property Dispositions—When complete units of depreciable property are sold, the asset cost and related accumulated depreciation are eliminated, with any gain or loss reflected in other income. When less than complete units of depreciable property are disposed of or retired, the difference between asset cost and salvage value is charged or credited to accumulated depreciation. | |
n | Asset Retirement Obligations and Environmental Costs—We record the fair value of legal obligations to retire and remove long-lived assets in the period in which the obligation is incurred (typically when the asset is installed at the production location). When the liability is initially recorded, we capitalize this cost by increasing the carrying amount of the related properties, plants and equipment. Over time the liability is increased for the change in its present value, and the capitalized cost in properties, plants and equipment is depreciated over the useful life of the related asset. See Note 14—Asset Retirement Obligations and Accrued Environmental Costs, for additional information. | |
Environmental expenditures are expensed or capitalized, depending upon their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and do not have a future economic benefit, are expensed. Liabilities for environmental expenditures are recorded on an undiscounted basis (unless acquired in a purchase business combination) when environmental assessments or cleanups are probable and the costs can be reasonably estimated. Recoveries of environmental remediation costs from other parties, such as state reimbursement funds, are recorded as assets when their receipt is probable and estimable. |
n | Guarantees—The fair value of a guarantee is determined and recorded as a liability at the time the guarantee is given. The initial liability is subsequently reduced as we are released from exposure under the guarantee. We amortize the guarantee liability over the relevant time period, if one exists, based on the facts and circumstances surrounding each type of guarantee. In cases where the guarantee term is indefinite, we reverse the liability when we have information that the liability is essentially relieved or amortize it over an appropriate time period as the fair value of our guarantee exposure declines over time. We amortize the guarantee liability to the related income statement line |
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item based on the nature of the guarantee. When it becomes probable that we will have to perform on a guarantee, we accrue a separate liability if it is reasonably estimable, based on the facts and circumstances at that time. We reverse the fair value liability only when there is no further exposure under the guarantee. |
n | Stock-Based Compensation—Effective January 1, 2003, we voluntarily adopted the fair value accounting method prescribed by SFAS No. 123, “Accounting for Stock-Based Compensation.” We used the prospective transition method, applying the fair value accounting method and recognizing compensation expense equal to the fair-market value on the grant date for all stock options granted or modified after December 31, 2002. | |
Employee stock options granted prior to 2003 were accounted for under Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related Interpretations; however, by the end of 2005, all of these awards had vested. Because the exercise price of our employee stock options equaled the market price of the underlying stock on the date of grant, generally no compensation expense was recognized under APB Opinion No. 25. The following table displays 2005 pro forma information as if the provisions of SFAS No. 123 had been applied to all employee stock options granted: |
Millions | |||||
of Dollars | |||||
Net income, as reported | $ | 13,529 | |||
Add: Stock-based employee compensation expense included in reported net income, net of related tax effects | 142 | ||||
Deduct: Total stock-based employee compensation expense determined under fair-value based method for all awards, net of related tax effects | (144 | ) | |||
Pro forma net income | $ | 13,527 | |||
Earnings per share: | |||||
Basic—as reported | $ | 9.71 | |||
Basic—pro forma | 9.71 | ||||
Diluted—as reported | 9.55 | ||||
Diluted—pro forma | 9.55 | ||||
Generally, our stock-based compensation programs provided accelerated vesting (i.e., a waiver of the remaining period of service required to earn an award) for awards held by employees at the time of their retirement. We recognized expense for these awards over the period of time during which the employee earned the award, accelerating the recognition of expense only when an employee actually retired (both the actual expense and the pro forma expense shown in the preceding table were calculated in this manner). | ||
Effective January 1, 2006, we adopted SFAS No. 123 (revised 2004), “Share-Based Payment” (SFAS No. 123(R)), which requires us to recognize stock-based compensation expense for new awards over the shorter of: 1) the service period (i.e., the stated period of time required to earn the award); or 2) the period beginning at the start of the service period and ending when an employee first becomes eligible for retirement. This shortens the period over which we recognize expense for most |
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of our stock-based awards granted to our employees who are already age 55 or older, but it has not had a material effect on our consolidated financial statements. For share-based awards granted after our adoption of SFAS No. 123(R), we have elected to recognize expense on a straight-line basis over the service period for the entire award, whether the award was granted with ratable or cliff vesting. | ||
n | Income Taxes—Deferred income taxes are computed using the liability method and are provided on all temporary differences between the financial-reporting basis and the tax basis of our assets and liabilities, except for deferred taxes on income considered to be permanently reinvested in certain foreign subsidiaries and foreign corporate joint ventures. Allowable tax credits are applied currently as reductions of the provision for income taxes. Interest related to unrecognized tax benefits is reflected in interest expense, and penalties in production and operating expenses. | |
n | Taxes Collected from Customers and Remitted to Governmental Authorities—Excise taxes are reported gross within sales and other operating revenues and taxes other than income taxes, while other sales and value-added taxes are recorded net in taxes other than income taxes. | |
n | Net Income Per Share of Common Stock—Basic income per share of common stock is calculated based upon the daily weighted-average number of common shares outstanding during the year, including unallocated shares held by the stock savings feature of the ConocoPhillips Savings Plan. Also, this calculation includes fully vested stock and unit awards that have not been issued. Diluted income per share of common stock includes the above, plus unvested stock, unit or option awards granted under our compensation plans and vested but unexercised stock options, but only to the extent these instruments dilute net income per share. Treasury stock and shares held by the grantor trusts are excluded from the daily weighted-average number of common shares outstanding in both calculations. | |
n | Accounting for Sales of Stock by Subsidiary or Equity Investees—We recognize a gain or loss upon the direct sale of non-preference equity by our subsidiaries or equity investees if the sales price differs from our carrying amount, and provided that the sale of such equity is not part of a broader corporate reorganization. |
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Millions of Dollars | ||||||||||||
Actual | Pro Forma | |||||||||||
2007 | 2006 | 2005 | ||||||||||
Sales and other operating revenues | $ | 187,437 | 176,993 | 154,692 | ||||||||
Purchased crude oil, natural gas and products | 123,429 | 112,242 | 100,175 | |||||||||
• | Recognize the funded status of the benefit in its statement of financial position. | ||
• | Recognize as a component of other comprehensive income, net of tax, the gains or losses and prior service costs or credits that arise during the period, but are not recognized as components of net periodic benefit cost. | ||
• | Measure defined benefit plan assets and obligations as of the date of the employer’s fiscal year-end statement of financial position. | ||
• | Disclose in the notes to financial statements additional information about certain effects on net periodic benefit cost for the next fiscal year that arise from delayed recognition of the gains or losses, prior service costs or credits, and the transition asset or obligation. |
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Millions | ||||
of Dollars | ||||
Sales and other operating revenues from discontinued operations | $ | 356 | ||
Discontinued operations before-tax | $ | (26 | ) | |
Income tax benefit | (3 | ) | ||
Discontinued operations | $ | (23 | ) | |
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Millions | ||||
of Dollars | ||||
Cash and cash equivalents | $ | 3,238 | ||
Accounts and notes receivable | 1,432 | |||
Inventories | 229 | |||
Prepaid expenses and other current assets | 108 | |||
Investments and long-term receivables | 268 | |||
Properties, plants and equipment | 28,176 | |||
Goodwill | 16,787 | |||
Intangibles | 107 | |||
Other assets | 46 | |||
Total Assets | $ | 50,391 | ||
Accounts payable | $ | 1,487 | ||
Notes payable and long-term debt due within one year | 1,009 | |||
Accrued income and other taxes | 697 | |||
Employee benefit obligations—current | 248 | |||
Other accruals | 254 | |||
Long-term debt | 3,330 | |||
Asset retirement obligations | 730 | |||
Accrued environmental costs | 174 | |||
Deferred income taxes | 7,849 | |||
Employee benefit obligations | 347 | |||
Other liabilities and deferred credits | 397 | |||
Common stockholders’ equity | 33,869 | |||
Total Liabilities and Equity | $ | 50,391 | ||
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Millions of Dollars | ||||||||
2006 | 2005 | |||||||
Pro Forma | ||||||||
Sales and other operating revenues* | $ | 185,555 | 186,227 | |||||
Income from continuing operations | 15,945 | 14,780 | ||||||
Net income | 15,945 | 14,669 | ||||||
Income from continuing operations per share of common stock | ||||||||
Basic | 9.65 | 8.88 | ||||||
Diluted | 9.51 | 8.75 | ||||||
Net income per share of common stock | ||||||||
Basic | 9.65 | 8.82 | ||||||
Diluted | 9.51 | 8.68 | ||||||
Millions | ||||
of Dollars | ||||
Balance at January 1, 2006 | $ | - | ||
Accruals | 218 | |||
Benefit payments | (98 | ) | ||
Balance at December 31, 2006 | 120 | |||
Accruals | 13 | |||
Benefit payments | (68 | ) | ||
Balance at December 31, 2007 | $ | 65 | * | |
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Millions of Dollars | ||||||||
2007 | 2006 | |||||||
Crude oil and petroleum products | $ | 3,373 | 4,351 | |||||
Materials, supplies and other | 850 | 802 | ||||||
$ | 4,223 | 5,153 | ||||||
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Millions of Dollars | ||||||||
2007 | 2006 | |||||||
Assets | ||||||||
Investments and long-term receivables | $ | 48 | 170 | |||||
Net properties, plants and equipment | 946 | 2,422 | ||||||
Goodwill | 89 | 340 | ||||||
Intangibles | 2 | 13 | ||||||
Other assets | 7 | 106 | ||||||
Total assets reclassified | $ | 1,092 | 3,051 | |||||
Exploration and Production | $ | 189 | 1,465 | |||||
Refining and Marketing | 903 | 1,586 | ||||||
$ | 1,092 | 3,051 | ||||||
Liabilities | ||||||||
Asset retirement obligations and accrued environmental costs | $ | 23 | 386 | |||||
Deferred income taxes | 133 | 201 | ||||||
Other liabilities and deferred credits | 3 | 17 | ||||||
Total liabilities reclassified | $ | 159 | 604 | |||||
Exploration and Production | $ | 35 | 392 | |||||
Refining and Marketing | 124 | 212 | ||||||
$ | 159 | 604 | ||||||
Millions of Dollars | ||||||||
2007 | 2006 | |||||||
Equity investments | $ | 30,408 | 18,544 | |||||
Loans and advances—related parties | 1,871 | 1,118 | ||||||
Long-term receivables | 495 | 442 | ||||||
Other investments | 554 | 609 | ||||||
$ | 33,328 | 20,713 | ||||||
Affiliated companies in which we have a significant equity investment include:
• | FCCL Oil Sands Partnership (FCCL)—50 percent owned business venture with EnCana Corporation—produces heavy-oil in the Athabasca oil sands in northeast Alberta, as well as transports and sells the bitumen blend. | ||
• | WRB Refining LLC (WRB)—50 percent owned business venture with EnCana Corporation—processes crude oil at the Wood River and Borger refineries, as well as purchases and transports all feedstocks for the refineries and sells the refined products. |
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• | OAO LUKOIL (LUKOIL)—20 percent ownership interest. LUKOIL explores for and produces crude oil, natural gas and natural gas liquids; refines, markets and transports crude oil and petroleum products; and is headquartered in Russia. | ||
• | OOO Naryanmarneftegaz (NMNG)—30 percent ownership interest and a 50 percent governance interest—a joint venture with LUKOIL to explore for and develop oil and gas resources in the northern part of Russia’s Timan-Pechora province. | ||
• | DCP Midstream, LLC (DCP Midstream)—50 percent owned joint venture with Spectra Energy—owns and operates gas plants, gathering systems, storage facilities and fractionation plants. Effective January 2, 2007, Duke Energy Field Services, LLC (DEFS) formally changed its name to DCP Midstream. | ||
• | Chevron Phillips Chemical Co. LLC (CPChem)—50 percent owned joint venture with Chevron Corporation—manufactures and markets petrochemicals and plastics. |
Millions of Dollars | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
Revenues | $ | 143,686 | 113,607 | 96,367 | ||||||||
Income before income taxes | 19,807 | 16,257 | 15,059 | |||||||||
Net income | 15,229 | 12,447 | 11,743 | |||||||||
Current assets | 29,451 | 24,820 | 23,652 | |||||||||
Noncurrent assets | 90,939 | 59,803 | 48,181 | |||||||||
Current liabilities | 16,882 | 15,884 | 14,727 | |||||||||
Noncurrent liabilities | 26,656 | 20,603 | 15,833 | |||||||||
In October 2006, we announced a business venture with EnCana Corporation (EnCana) to create an integrated North American heavy-oil business. The transaction closed on January 3, 2007, and consists of two 50/50 business ventures, a Canadian upstream general partnership, FCCL Oil Sands Partnership (FCCL), and a U.S. downstream limited liability company, WRB Refining LLC (WRB). We use the equity method of accounting for both entities, with the operating results of our investment in FCCL reflecting its use of the full-cost method of accounting for oil and gas exploration and development activities.
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LUKOIL is an integrated energy company headquartered in Russia, with operations worldwide. In 2004, we made a joint announcement with LUKOIL of an agreement to form a broad-based strategic alliance, whereby we would become a strategic equity investor in LUKOIL.
OOO Naryanmarneftegaz (NMNG) is a joint venture with LUKOIL, created in June 2005, to develop resources in the northern part of Russia’s Timan-Pechora province. We have a 30 percent ownership interest with a 50 percent governance interest. NMNG is working to develop the Yuzhno Khylchuyu (YK) field. Production from the NMNG joint venture fields is transported via pipeline to LUKOIL’s existing terminal at Varandey Bay on the Barents Sea and then shipped via tanker to international markets.
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DCP Midstream owns and operates gas plants, gathering systems, storage facilities and fractionation plants. In July 2005, ConocoPhillips and Duke Energy Corporation (Duke) restructured their respective ownership levels in DCP Midstream, which resulted in DCP Midstream becoming a jointly controlled venture, owned 50 percent by each company. This restructuring increased our ownership in DCP Midstream to 50 percent from 30.3 percent through a series of direct and indirect transfers of certain Canadian Midstream assets from DCP Midstream to Duke, a disproportionate cash distribution from DCP Midstream to Duke from the sale of DCP Midstream’s interest in TEPPCO Partners, L.P., and a combined payment by ConocoPhillips to Duke and DCP Midstream of approximately $840 million. Our interest in the Empress plant in Canada was not included in the initial transaction as originally anticipated due to weather-related damage to the facility. Subsequently, the Empress plant was sold to Duke on August 1, 2005, for approximately $230 million. In the first quarter of 2005, as a part of equity earnings, we recorded our $306 million (after-tax) equity share of the gain from DCP Midstream’s sale of its interest in TEPPCO.
CPChem manufactures and markets petrochemicals and plastics. At December 31, 2007, the book value of our investment in CPChem was $2,203 million. Our 50 percent share of the total net assets of CPChem was $2,080 million. This basis difference of $123 million is being amortized through 2020, consistent with the remaining estimated useful lives of CPChem properties, plants and equipment.
See the “Expropriated Assets” section of Note 13—Impairments, for information on the complete impairment of our investments in the Hamaca and Petrozuata projects.
As part of our normal ongoing business operations and consistent with industry practice, we invest and enter into numerous agreements with other parties to pursue business opportunities, which share costs and apportion risks among the parties as governed by the agreements. Included in such activity are loans made to certain affiliated companies. Loans are recorded within “Loans and advances—related parties” when
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• | We entered into a credit agreement with Freeport LNG, whereby we will provide loan financing of approximately $631 million, excluding accrued interest, for the construction of an LNG facility. Through December 31, 2007, we have provided $594 million in loan financing, and an additional $87 million of accrued interest. See Note 7—Variable Interest Entities (VIEs), for additional information. | ||
• | We have an obligation to provide loan financing to Varandey Terminal Company for 30 percent of the costs of the terminal expansion. We estimate our total loan obligation for the terminal expansion to be approximately $416 million at current exchange rates, excluding interest to be accrued during construction. This amount will be adjusted as the project’s cost estimate and schedule are updated and the ruble exchange rate fluctuates. Through December 31, 2007, we had provided $331 million in loan financing, and an additional $32 million of accrued interest. See Note 7—Variable Interest Entities (VIEs), for additional information. | ||
• | Qatargas 3 is an integrated project to produce and liquefy natural gas from Qatar’s North field. We own a 30 percent interest in the project. The other participants in the project are affiliates of Qatar Petroleum (68.5 percent) and Mitsui & Co., Ltd. (1.5 percent). Our interest is held through a jointly owned company, Qatar Liquefied Gas Company Limited (3), for which we use the equity method of accounting. Qatargas 3 secured project financing of $4 billion in December 2005, consisting of $1.3 billion of loans from export credit agencies (ECA), $1.5 billion from commercial banks, and $1.2 billion from ConocoPhillips. The ConocoPhillips loan facilities have substantially the same terms as the ECA and commercial bank facilities. Prior to project completion certification, all loans, including the ConocoPhillips loan facilities, are guaranteed by the participants based on their respective ownership interests. Accordingly, our maximum exposure to this financing structure is $1.2 billion, excluding accrued interest. Upon completion certification, which is expected in 2010, all project loan facilities, including the ConocoPhillips loan facilities, will become non-recourse to the project participants. At December 31, 2007, Qatargas 3 had $2.4 billion outstanding under all the loan facilities, of which ConocoPhillips provided $690 million, and an additional $43 million of accrued interest. |
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Millions of Dollars | ||||||||||||||||||||||||
2007 | 2006 | |||||||||||||||||||||||
Gross | Accum. | Net | Gross | Accum. | Net | |||||||||||||||||||
PP&E | DD&A | PP&E | PP&E | DD&A | PP&E | |||||||||||||||||||
E&P | $ | 102,550 | 30,701 | 71,849 | 88,592 | 21,102 | 67,490 | |||||||||||||||||
Midstream | 267 | 103 | 164 | 330 | 157 | 173 | ||||||||||||||||||
R&M | 19,926 | 4,733 | 15,193 | 22,115 | 5,199 | 16,916 | ||||||||||||||||||
LUKOIL Investment | - | - | - | - | - | - | ||||||||||||||||||
Chemicals | - | - | - | - | - | - | ||||||||||||||||||
Emerging Businesses | 1,204 | 138 | 1,066 | 1,006 | 98 | 908 | ||||||||||||||||||
Corporate and Other | 1,414 | 683 | 731 | 1,229 | 515 | 714 | ||||||||||||||||||
$ | 125,361 | 36,358 | 89,003 | 113,272 | 27,071 | 86,201 | ||||||||||||||||||
In April 2005, the FASB issued FSP FAS 19-1, “Accounting for Suspended Well Costs” (FSP FAS 19-1). This FSP was issued to address whether there were circumstances that would permit the continued capitalization of exploratory well costs beyond one year, other than when further exploratory drilling is planned and major capital expenditures would be required to develop the project. We adopted FSP FAS 19-1 effective January 1, 2005. There was no impact on our consolidated financial statements from the adoption.
Millions of Dollars | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
Beginning balance at January 1 | $ | 537 | 339 | 347 | ||||||||
Additions pending the determination of proved reserves | 157 | 225 | 183 | |||||||||
Reclassifications to proved properties | (58 | ) | (8 | ) | (81 | ) | ||||||
Sales of suspended well investment | (22 | ) | - | - | ||||||||
Charged to dry hole expense | (25 | ) | (19 | ) | (110 | ) | ||||||
Ending balance at December 31 | $ | 589 | * | 537 | * | 339 | ||||||
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Millions of Dollars | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
Exploratory well costs capitalized for a period of one year or less | $ | 153 | 225 | 183 | ||||||||
Exploratory well costs capitalized for a period greater than one year | 436 | 312 | 156 | |||||||||
Ending balance | $ | 589 | 537 | 339 | ||||||||
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year | 35 | 22 | 15 | |||||||||
Millions of Dollars | ||||||||||||||||||||||||||||
Suspended Since | ||||||||||||||||||||||||||||
Project | Total | 2006 | 2005 | 2004 | 2003 | 2002 | 2001 | |||||||||||||||||||||
Aktote—Kazakhstan(2) | $ | 19 | - | - | 7 | 12 | - | - | ||||||||||||||||||||
Alpine satellite—Alaska(2) | 23 | - | - | - | - | 23 | - | |||||||||||||||||||||
Caldita—Australia(1) | 78 | 45 | 33 | - | - | - | - | |||||||||||||||||||||
Clair—U.K.(1) | 17 | 17 | - | - | - | - | - | |||||||||||||||||||||
Enochdhu/Finlaggen—U.K.(1) | 11 | 11 | - | - | - | - | - | |||||||||||||||||||||
Humphrey—U.K.(2) | 12 | 12 | - | - | - | - | - | |||||||||||||||||||||
Jasmine—U.K.(1) | 28 | 28 | - | - | - | - | - | |||||||||||||||||||||
K4—U.K.(2) | 12 | 12 | - | - | - | - | - | |||||||||||||||||||||
Kairan—Kazakhstan(2) | 13 | - | - | 13 | - | - | - | |||||||||||||||||||||
Kashagan—Kazakhstan(1) | 18 | - | - | - | 9 | - | 9 | |||||||||||||||||||||
Malikai—Malaysia(2) | 50 | 17 | 22 | 11 | - | - | - | |||||||||||||||||||||
Plataforma Deltana—Venezuela(2) | 21 | - | 6 | 15 | - | - | - | |||||||||||||||||||||
Su Tu Trang—Vietnam(2) | 32 | 16 | 8 | - | 8 | - | - | |||||||||||||||||||||
Uge—Nigeria(1) | 14 | - | 14 | - | - | - | - | |||||||||||||||||||||
West Sak—Alaska(2) | 10 | 6 | 3 | 1 | - | - | - | |||||||||||||||||||||
Twenty projects of less than $10 million each(1)(2) | 78 | 48 | 20 | 3 | 3 | 4 | - | |||||||||||||||||||||
Total of 35 projects | $ | 436 | 212 | 106 | 50 | 32 | 27 | 9 | ||||||||||||||||||||
(1) | Additional appraisal wells planned. | |
(2) | Appraisal drilling complete; costs being incurred to assess development. |
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Millions of Dollars | ||||||||||||
E&P | R&M | Total | ||||||||||
Balance at December 31, 2005 | $ | 11,423 | 3,900 | 15,323 | ||||||||
Acquired (Burlington Resources) | 16,615 | - | 16,615 | |||||||||
Acquired (Wilhelmshaven) | - | 229 | 229 | |||||||||
Goodwill allocated to assets held for sale or sold | (216 | ) | (354 | ) | (570 | ) | ||||||
Tax and other adjustments | (110 | ) | 1 | (109 | ) | |||||||
Balance at December 31, 2006 | 27,712 | 3,776 | 31,488 | |||||||||
Goodwill allocated to expropriated assets | (1,925 | ) | - | (1,925 | ) | |||||||
Acquired (Burlington Resources) | 172 | - | 172 | |||||||||
Goodwill allocated to assets held for sale or sold | (191 | ) | (3 | ) | (194 | ) | ||||||
Tax and other adjustments | (199 | ) | (6 | ) | (205 | ) | ||||||
Balance at December 31, 2007 | $ | 25,569 | 3,767 | 29,336 | ||||||||
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Millions of Dollars | ||||||||||||
Gross Carrying | Accumulated | Net Carrying | ||||||||||
Amount | Amortization | Amount | ||||||||||
Amortized Intangible Assets | ||||||||||||
Balance at December 31, 2007 | ||||||||||||
Technology related | $ | 145 | (60 | ) | 85 | |||||||
Refinery air permits | 14 | (8 | ) | 6 | ||||||||
Contract based | 124 | (62 | ) | 62 | ||||||||
Other | 37 | (25 | ) | 12 | ||||||||
$ | 320 | (155 | ) | 165 | ||||||||
Balance at December 31, 2006 | ||||||||||||
Technology related | $ | 144 | (51 | ) | 93 | |||||||
Refinery air permits | 32 | (12 | ) | 20 | ||||||||
Contract based | 139 | (44 | ) | 95 | ||||||||
Other | 31 | (24 | ) | 7 | ||||||||
$ | 346 | (131 | ) | 215 | ||||||||
Indefinite-Lived Intangible Assets | ||||||||||||
Balance at December 31, 2007 | ||||||||||||
Trade names and trademarks | $ | 494 | ||||||||||
Refinery air and operating permits | 237 | |||||||||||
$ | 731 | |||||||||||
Balance at December 31, 2006 | ||||||||||||
Trade names and trademarks | $ | 494 | ||||||||||
Refinery air and operating permits | 242 | |||||||||||
$ | 736 | |||||||||||
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On January 31, 2007, Venezuela’s National Assembly passed a law allowing the president of Venezuela to pass laws on certain matters by decree. On February 26, 2007, the president of Venezuela issued a decree (the Nationalization Decree) mandating the termination of the then-existing structures related to our heavy-oil ventures and oil production risk contracts and the transfer of all rights relating to our heavy-oil ventures and oil production risk contracts to joint ventures (“empresas mixtas”) that will be controlled by the Venezuelan national oil company or its subsidiaries.
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During 2007, 2006 and 2005, we recognized the following before-tax impairment charges, excluding the impairment of expropriated assets:
Millions of Dollars | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
E&P | ||||||||||||
United States | $ | 73 | 55 | 2 | ||||||||
International | 398 | 160 | 2 | |||||||||
Midstream | - | - | 30 | |||||||||
R&M | ||||||||||||
Goodwill and intangible assets | - | 300 | - | |||||||||
Other | 91 | 168 | 8 | |||||||||
Increase in fair value of previously impaired assets | (128 | ) | - | - | ||||||||
Corporate | 8 | - | - | |||||||||
$ | 442 | 683 | 42 | |||||||||
• | Increased asset retirement obligations for properties at the end of their economic life for certain fields primarily located in the North Sea, totaling $175 million. | ||
• | Downward reserve revisions and higher projected operating costs for fields in the United States, Canada and the United Kingdom, totaling $80 million. | ||
• | An abandoned project in Alaska resulting from increased taxes, totaling $28 million. |
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Millions of Dollars | ||||||||
2007 | 2006 | |||||||
Asset retirement obligations | $ | 6,613 | 5,402 | |||||
Accrued environmental costs | 1,089 | 1,062 | ||||||
Total asset retirement obligations and accrued environmental costs | 7,702 | 6,464 | ||||||
Asset retirement obligations and accrued environmental costs due within one year* | (441 | ) | (845 | ) | ||||
Long-term asset retirement obligations and accrued environmental costs | $ | 7,261 | 5,619 | |||||
SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation when it is incurred (typically when the asset is installed at the production location). When the liability is initially recorded, the entity capitalizes the cost by increasing the carrying amount of the related properties, plants and equipment. Over time, the liability increases for the change in its present value, while the capitalized cost depreciates over the useful life of the related asset.
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Millions of Dollars | ||||||||
2007 | 2006 | |||||||
Balance at January 1 | $ | 5,402 | 3,901 | |||||
Accretion of discount | 310 | 248 | ||||||
New obligations | 76 | 154 | ||||||
Burlington Resources acquisition | - | 732 | ||||||
Changes in estimates of existing obligations | 843 | 299 | ||||||
Spending on existing obligations | (146 | ) | (130 | ) | ||||
Property dispositions | (259 | )* | (20 | ) | ||||
Foreign currency translation | 395 | 218 | ||||||
Expropriation of Venezuela assets | (8 | ) | - | |||||
Balance at December 31 | $ | 6,613 | 5,402 | |||||
Millions of Dollars | ||||
Except per Share | ||||
Amounts | ||||
Pro forma net income* | $ | 13,600 | ||
Pro forma earnings per share | ||||
Basic | 9.76 | |||
Diluted | 9.60 | |||
Total environmental accruals at December 31, 2007 and 2006, were $1,089 million and $1,062 million, respectively. The 2007 increase in total accrued environmental costs is due to new accruals and accretion, partially offset by payments on accrued environmental costs.
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Millions of Dollars | ||||||||
2007 | 2006 | |||||||
9.875% Debentures due 2010 | $ | 150 | 150 | |||||
9.375% Notes due 2011 | 328 | 328 | ||||||
9.125% Debentures due 2021 | 150 | 150 | ||||||
8.75% Notes due 2010 | 1,264 | 1,264 | ||||||
8.20% Debentures due 2025 | 150 | 150 | ||||||
8.125% Notes due 2030 | 600 | 600 | ||||||
8% Junior Subordinated Deferrable Interest Debentures due 2037 | - | 361 | ||||||
7.9% Debentures due 2047 | 100 | 100 | ||||||
7.8% Debentures due 2027 | 300 | 300 | ||||||
7.68% Notes due 2012 | 37 | 43 | ||||||
7.65% Debentures due 2023 | 88 | 88 | ||||||
7.625% Debentures due 2013 | 100 | 100 | ||||||
7.40% Notes due 2031 | 500 | 500 | ||||||
7.375% Debentures due 2029 | 92 | 92 | ||||||
7.25% Notes due 2007 | - | 153 | ||||||
7.25% Notes due 2031 | 500 | 500 | ||||||
7.20% Notes due 2031 | 575 | 575 | ||||||
7.125% Debentures due 2028 | 300 | 300 | ||||||
7% Debentures due 2029 | 200 | 200 | ||||||
6.95% Notes due 2029 | 1,549 | 1,549 | ||||||
6.875% Debentures due 2026 | 67 | 67 | ||||||
6.68% Notes due 2011 | 400 | 400 | ||||||
6.65% Debentures due 2018 | 297 | 297 | ||||||
6.50% Notes due 2011 | 500 | 500 | ||||||
6.40% Notes due 2011 | 178 | 178 | ||||||
6.375% Notes due 2009 | 284 | 284 | ||||||
6.35% Notes due 2011 | 1,750 | 1,750 | ||||||
5.951% Notes due 2037 | 645 | - | ||||||
5.95% Notes due 2036 | 500 | 500 | ||||||
5.90% Notes due 2032 | 505 | 505 | ||||||
5.625% Notes due 2016 | 1,250 | 1,250 | ||||||
5.50% Notes due 2013 | 750 | 750 | ||||||
5.30% Notes due 2012 | 350 | 350 | ||||||
4.75% Notes due 2012 | 897 | 897 | ||||||
Commercial paper at 4.05% - 5.36% at year-end 2007 and 5.27% - 5.47% at year-end 2006 | 725 | 2,931 | ||||||
Floating Rate Five-Year Term Note due 2011 at 5.0625% at year-end 2007 and 5.575% at year-end 2006 | 3,000 | 5,000 | ||||||
Floating Rate Notes due 2009 at 5.34% at year-end 2007 and 5.47% at year-end 2006 | 950 | 1,250 | ||||||
Floating Rate Notes due 2007 at 5.37% at year-end 2006 | - | 1,000 | ||||||
Industrial Development Bonds due 2012 through 2038 at 3.50% - 5.75% at year-end 2007 and 3.60% - 5.75% at year-end 2006 | 252 | 252 | ||||||
Guarantee of savings plan bank loan payable due 2015 at 5.40% at year-end 2007 and 5.65% at year-end 2006 | 175 | 203 | ||||||
Note payable to Merey Sweeny, L.P. due 2020 at 7%* | 172 | 180 | ||||||
Marine Terminal Revenue Refunding Bonds due 2031 at 3.40% - 3.51% at year-end 2007 and 3.68% at year-end 2006 | 265 | 265 | ||||||
Other | 50 | 60 | ||||||
Debt at face value | 20,945 | 26,372 | ||||||
Capitalized leases | 54 | 44 | ||||||
Net unamortized premiums and discounts | 688 | 718 | ||||||
Total debt | 21,687 | 27,134 | ||||||
Notes payable and long-term debt due within one year | (1,398 | ) | (4,043 | ) | ||||
Long-term debt | $ | 20,289 | 23,091 | |||||
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• | In June 2006, we issued a guarantee for 24 percent of the $2 billion in credit facilities of Rockies Express Pipeline LLC (Rockies Express), which will be used to construct a natural gas pipeline across a portion of the United States. At December 31, 2007, Rockies Express had $1,625 million outstanding under the credit facilities, with our 24 percent guarantee equaling $390 million. The maximum potential amount of future payments to third-party lenders under the guarantee is estimated to be $480 million, which could become payable if the credit facility is fully utilized and Rockies Express fails to meet its obligations under the credit agreement. In addition, we also have a guarantee for 24 percent of $600 million of Floating Rate Notes due 2009 issued by Rockies Express in September 2007. It is anticipated final construction completion will be achieved in 2009, and refinancing will take place at that time, making the debt non-recourse to ConocoPhillips. At December 31, 2007, the total carrying value of these guarantees to third-party lenders was $12 million. See Note 7—Variable Interest Entities (VIEs), for additional information. | ||
• | In December 2005, we issued a construction completion guarantee for 30 percent of the $4.0 billion in loan facilities of Qatargas 3, which will be used to construct an LNG train in Qatar. Of the $4.0 billion in loan facilities, ConocoPhillips has committed to provide $1.2 billion. The maximum potential amount of future payments to third-party lenders under the guarantee is estimated to be $850 million, which could become payable if the full debt financing is utilized and completion of the Qatargas 3 project is not achieved. The project financing will be non-recourse to ConocoPhillips upon certified completion, which is expected in 2010. At December 31, 2007, the carrying value of the guarantee to the third-party lenders was $11 million. For additional information, see Note 10—Investments, Loans and Long-Term Receivables. |
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• | At December 31, 2007, we had guarantees outstanding for our portion of joint-venture debt obligations, which have terms of up to 17 years. The maximum potential amount of future payments under the guarantees is approximately $90 million. Payment would be required if a joint venture defaults on its debt obligations. |
• | The Merey Sweeny, L.P. (MSLP) joint-venture project agreement requires the partners in the venture to pay cash calls to cover operating expenses in the event the venture does not have enough cash to cover operating expenses after setting aside the amount required for debt service over the next 17 years. Although there is no maximum limit stated in the agreement, the intent is to cover short-term cash deficiencies should they occur. Our maximum potential future payments under the agreement are currently estimated to be $100 million, assuming such a shortfall exists at some point in the future due to an extended operational disruption. | ||
• | In February 2003, we entered into two agreements establishing separate guarantee facilities of $50 million each for two LNG ships. Subject to the terms of each such facility, we will be required to make payments should the charter revenue generated by the respective ship fall below certain specified minimum thresholds, and we will receive payments to the extent that such revenues exceed those thresholds. The net maximum future payments that we may have to make over the 20-year terms of the two agreements could be up to $100 million in total. To the extent we receive any such payments, our actual gross payments over the 20 years could exceed that amount. In the event either ship is sold or a total loss occurs, we also may have recourse to the sales or insurance proceeds to recoup payments made under the guarantee facilities. For additional information, see Note 7—Variable Interest Entities (VIEs). | ||
• | We have guarantees of the residual value of leased corporate aircraft. The maximum potential payment under these guarantees at December 31, 2007, was $150 million. | ||
• | In December 2007, we acquired a 50 percent equity interest in the Keystone Oil Pipeline (Keystone) to form a 50/50 joint venture with TransCanada Corporation. Keystone plans to construct a crude oil pipeline originating in Hardisty, Alberta, with delivery points at Wood River and Patoka, Illinois, and Cushing, Oklahoma. In connection with certain planning and construction activities, agreements were put in place with third parties to guarantee the payments due. Our maximum potential amount of future payments under those agreements are estimated to be $400 million, which could become payable if Keystone fails to meet its obligations under the agreements noted above and the obligation cannot otherwise be mitigated. Payments under the guarantees are contingent upon the partners not making necessary equity contributions into Keystone; therefore, it is considered unlikely that payments would be required. All but $15 million of the guarantees will terminate after construction is completed, currently estimated to be in 2010. | ||
• | We have other guarantees with maximum future potential payment amounts totaling $200 million, which consist primarily of dealer and jobber loan guarantees to support our marketing business, guarantees to fund the short-term cash liquidity deficits of certain joint ventures, one small construction completion guarantee, guarantees relating to the startup of a refining joint venture, and guarantees of the lease payment obligations of a joint venture. These guarantees generally extend up to 10 years or life of the venture and payment would be required only if the dealer, jobber or lessee goes into default, if the joint ventures have cash liquidity issues, if a construction project is not completed, if a guaranteed party defaults on lease payments, or if an adverse decision occurs in the pending lawsuit. |
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Over the years, we have entered into various agreements to sell ownership interests in certain corporations and joint ventures and have sold several assets, including downstream and midstream assets, certain exploration and production assets, and downstream retail and wholesale sites that gave rise to qualifying indemnifications. Agreements associated with these sales include indemnifications for taxes, environmental liabilities, permits and licenses, employee claims, real estate indemnity against tenant defaults, and litigation. The terms of these indemnifications vary greatly. The majority of these indemnifications are related to environmental issues, the term is generally indefinite and the maximum amount of future payments is generally unlimited. The carrying amount recorded for these indemnifications at December 31, 2007, was $471 million. We amortize the indemnification liability over the relevant time period, if one exists, based on the facts and circumstances surrounding each type of indemnity. In cases where the indemnification term is indefinite, we will reverse the liability when we have information the liability is essentially relieved or amortize the liability over an appropriate time period as the fair value of our indemnification exposure declines. Although it is reasonably possible future payments may exceed amounts recorded, due to the nature of the indemnifications, it is not possible to make a reasonable estimate of the maximum potential amount of future payments. Included in the carrying amount recorded were $294 million of environmental accruals for known contamination that is included in asset retirement obligations and accrued environmental costs at December 31, 2007. For additional information about environmental liabilities, see Note 18—Contingencies and Commitments.
We are subject to federal, state and local environmental laws and regulations. These may result in obligations to remove or mitigate the effects on the environment of the placement, storage, disposal or release of certain chemical, mineral and petroleum substances at various sites. When we prepare our consolidated financial statements, we record accruals for environmental liabilities based on management’s best estimates, using all information that is available at the time. We measure estimates and base liabilities on currently available facts, existing technology, and presently enacted laws and regulations, taking into
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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 which have been scheduled for trial, as well as the pace of settlement discussions in individual matters. Based on professional judgment and experience in using these litigation management tools and available information about current developments in all our cases, our legal organization believes that there is only a remote likelihood 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.
We have contingent liabilities resulting from throughput agreements with pipeline and processing companies not associated with financing arrangements. Under these agreements, we may be required to provide any such company with additional funds through advances and penalties for fees related to
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We have certain throughput agreements and take-or-pay agreements that are in support of financing arrangements. The agreements typically provide for natural gas or crude oil transportation to be used in the ordinary course of the company’s business. The aggregate amounts of estimated payments under these various agreements are: 2008—$97 million; 2009—$97 million; 2010—$97 million; 2011—$98 million; 2012—$97 million; and 2013 and after—$542 million. Total payments under the agreements were $67 million in 2007, $66 million in 2006 and $52 million in 2005.
We, and certain of our subsidiaries, may use financial and commodity-based derivative contracts to manage exposures to fluctuations in foreign currency exchange rates, commodity prices, and interest rates, or to exploit 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 without approval from the Chief Executive Officer. The Authority Limitations document also authorizes the Chief Executive Officer to establish the maximum 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, while the Senior Vice President of Commercial monitors commodity price risk. Both report to the Chief Executive Officer. The Commercial organization manages our commercial marketing, optimizes our commodity flows and positions, monitors related risks of our upstream and downstream businesses and selectively takes price risk to add value.
Millions of Dollars | ||||||||
2007 | 2006 | |||||||
Derivative Assets | ||||||||
Current | $ | 453 | 924 | |||||
Long-term | 89 | 82 | ||||||
$ | 542 | 1,006 | ||||||
Derivative Liabilities | ||||||||
Current | $ | 493 | 681 | |||||
Long-term | 67 | 126 | ||||||
$ | 560 | 807 | ||||||
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• | Balance physical systems. In addition to cash settlement prior to contract expiration, exchange traded futures contracts may also be settled by physical delivery of the commodity, providing another source of supply to meet our refinery requirements or marketing demand. | ||
• | Meet customer needs. Consistent with our policy to generally remain exposed to market prices, we use swap contracts to convert fixed-price sales contracts, which are often requested by natural gas and refined product consumers, to a floating market price. | ||
• | Manage the risk to our cash flows from price exposures on specific crude oil, natural gas, refined product and electric power transactions. | ||
• | Enable us to use the market knowledge gained from these activities to do a limited amount of trading not directly related to our physical business. For the years ended December 31, 2007, 2006 and 2005, the gains or losses from this activity were not material to our cash flows or net income. |
Our financial instruments that are potentially exposed to concentrations of credit risk consist primarily of cash equivalents, over-the-counter derivative contracts, and trade receivables. Our cash equivalents are placed in high-quality commercial paper, money market funds and time deposits with major international banks and financial institutions. The credit risk from our over-the-counter derivative contracts, such as forwards and swaps, derives from the counterparty to the transaction, typically a major bank or financial institution. We closely monitor these credit exposures against predetermined credit limits, including the continual exposure adjustments that result from market movements. Individual counterparty exposure is managed within these limits, and includes the use of cash-call margins when appropriate, thereby reducing the risk of significant non-performance. We also use futures contracts, but futures have a negligible credit risk because they are traded on the New York Mercantile Exchange or the ICE Futures.
We used the following methods and assumptions to estimate the fair value of financial instruments:
• | Cash and cash equivalents: The carrying amount reported on the balance sheet approximates fair value. | ||
• | Accounts and notes receivable: The carrying amount reported on the balance sheet approximates fair value. | ||
• | Investment in LUKOIL shares: See Note 10—Investments, Loans and Long-Term Receivables, for a discussion of the carrying value and fair value of our investment in LUKOIL shares. |
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• | Debt: The carrying amount of our floating-rate debt approximates fair value. The fair value of the fixed-rate debt is estimated based on quoted market prices. | ||
• | Fixed-rate 5.3 percent joint venture acquisition obligation: Fair value is estimated based on the net present value of the future cash flows, discounted at a year-end effective yield rate of 4.9 percent, based on yields of U.S. Treasury securities of similar average duration adjusted for our average credit risk spread and the amortizing nature of the obligation principal. See Note 16—Joint Venture Acquisition Obligation, for additional information. | ||
• | Swaps: Fair value is estimated based on forward market prices and approximates the net gains and losses that would have been realized if the contracts had been closed out at year-end. When forward market prices are not available, they are estimated using the forward prices of a similar commodity with adjustments for differences in quality or location. | ||
• | Futures: Fair values are based on quoted market prices obtained from the New York Mercantile Exchange, the ICE Futures, or other traded exchanges. | ||
• | Forward-exchange contracts: Fair value is estimated by comparing the contract rate to the forward rate in effect on December 31 and approximates the net gains and losses that would have been realized if the contracts had been closed out at year-end. |
Millions of Dollars | ||||||||||||||||
Carrying Amount | Fair Value | |||||||||||||||
2007 | 2006 | 2007 | 2006 | |||||||||||||
Financial assets | ||||||||||||||||
Foreign currency derivatives | $ | 47 | 47 | 47 | 47 | |||||||||||
Commodity derivatives | 495 | 959 | 495 | 959 | ||||||||||||
Financial liabilities | ||||||||||||||||
Total debt, excluding capital leases | 21,633 | 27,090 | 23,101 | 27,741 | ||||||||||||
Joint venture acquisition obligation | 6,887 | - | 7,031 | - | ||||||||||||
Foreign currency derivatives | 29 | 26 | 29 | 26 | ||||||||||||
Interest rate derivatives | - | 10 | - | 10 | ||||||||||||
Commodity derivatives | 531 | 771 | 531 | 771 | ||||||||||||
We have 500 million shares of preferred stock authorized, par value $.01 per share, none of which was issued or outstanding at December 31, 2007 or 2006.
The minority interest owner in Ashford Energy Capital S.A. is entitled to a cumulative annual preferred return on its investment, based on three-month LIBOR rates plus 1.32 percent. The preferred return at December 31, 2007 and 2006, was 6.55 percent and 6.69 percent, respectively. At December 31, 2007 and 2006, the minority interest was $508 million, for both periods. Ashford Energy Capital S.A. continues to be consolidated in our financial statements under the provisions of FIN 46(R) because we are the primary beneficiary. See Note 7—Variable Interest Entities (VIEs), for additional information.
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Millions | ||||
of Dollars | ||||
2008 | $ | 732 | ||
2009 | 593 | |||
2010 | 439 | |||
2011 | 340 | |||
2012 | 397 | |||
Remaining years | 807 | |||
Total | 3,308 | |||
Less income from subleases | (186 | )* | ||
Net minimum operating lease payments | $ | 3,122 | ||
*Includes $90 million related to railroad cars subleased to CPChem, a related party. |
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Millions of Dollars | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
Total rentals* | $ | 855 | 698 | 564 | ||||||||
Less sublease rentals | (82 | ) | (103 | ) | (66 | ) | ||||||
$ | 773 | 595 | 498 | |||||||||
* | Includes $27 million, $29 million and $28 million of contingent rentals in 2007, 2006 and 2005, respectively. Contingent rentals primarily are related to retail sites and refining equipment, and are based on volume of product sold or throughput. |
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An analysis of the projected benefit obligations for our pension plans and accumulated benefit obligations for our postretirement health and life insurance plans follows:
Millions of Dollars | ||||||||||||||||||||||||
Pension Benefits | Other Benefits | |||||||||||||||||||||||
2007 | 2006 | 2007 | 2006 | |||||||||||||||||||||
U.S. | Int’l. | U.S. | Int’l. | |||||||||||||||||||||
Change in Benefit Obligation | ||||||||||||||||||||||||
Benefit obligation at January 1 | $ | 4,113 | 3,087 | 3,703 | 2,495 | 778 | 815 | |||||||||||||||||
Service cost | 175 | 98 | 174 | 87 | 14 | 14 | ||||||||||||||||||
Interest cost | 229 | 161 | 210 | 134 | 45 | 47 | ||||||||||||||||||
Plan participant contributions | - | 10 | - | 9 | 28 | 31 | ||||||||||||||||||
Medicare Part D subsidy | - | - | - | - | 6 | 6 | ||||||||||||||||||
Plan amendments | 2 | (68 | ) | 1 | - | - | (26 | ) | ||||||||||||||||
Actuarial (gain) loss | 109 | (294 | ) | 57 | 79 | (6 | ) | (59 | ) | |||||||||||||||
Acquisitions | - | - | 275 | 42 | - | 36 | ||||||||||||||||||
Divestitures | - | - | - | - | - | - | ||||||||||||||||||
Benefits paid | (347 | ) | (97 | ) | (307 | ) | (77 | ) | (81 | ) | (86 | ) | ||||||||||||
Curtailment | - | 1 | - | - | - | - | ||||||||||||||||||
Recognition of termination benefits | - | 1 | - | 1 | - | - | ||||||||||||||||||
Foreign currency exchange rate change | - | 186 | - | 317 | 8 | - | ||||||||||||||||||
Benefit obligation at December 31* | $ | 4,281 | 3,085 | 4,113 | 3,087 | 792 | 778 | |||||||||||||||||
*Accumulated benefit obligation portion of above at December 31: | $ | 3,666 | 2,550 | 3,493 | 2,585 | |||||||||||||||||||
Change in Fair Value of Plan Assets | ||||||||||||||||||||||||
Fair value of plan assets at January 1 | $ | 2,863 | 2,185 | 2,183 | 1,725 | 3 | 3 | |||||||||||||||||
Acquisitions | - | - | 214 | 44 | - | - | ||||||||||||||||||
Divestitures | - | - | - | - | - | - | ||||||||||||||||||
Actual return on plan assets | 237 | 169 | 356 | 142 | - | - | ||||||||||||||||||
Company contributions | 385 | 185 | 417 | 120 | 47 | 49 | ||||||||||||||||||
Plan participant contributions | - | 10 | - | 9 | 28 | 31 | ||||||||||||||||||
Medicare Part D subsidy | - | - | - | - | 6 | 6 | ||||||||||||||||||
Benefits paid | (347 | ) | (97 | ) | (307 | ) | (77 | ) | (81 | ) | (86 | ) | ||||||||||||
Foreign currency exchange rate change | - | 149 | - | 222 | - | - | ||||||||||||||||||
Fair value of plan assets at December 31: | $ | 3,138 | 2,601 | 2,863 | 2,185 | 3 | 3 | |||||||||||||||||
Funded Status | $ | (1,143 | ) | (484 | ) | (1,250 | ) | (902 | ) | (789 | ) | (775 | ) | |||||||||||
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Millions of Dollars | ||||||||||||||||||||||||
Pension Benefits | Other Benefits | |||||||||||||||||||||||
2007 | 2006 | 2007 | 2006 | |||||||||||||||||||||
U.S. | Int’l. | U.S. | Int’l. | |||||||||||||||||||||
Amounts Recognized in the Consolidated Balance Sheet at December 31 | ||||||||||||||||||||||||
Noncurrent assets | $ | – | 98 | – | 16 | – | – | |||||||||||||||||
Current liabilities | (6 | ) | (9 | ) | (3 | ) | (11 | ) | (50 | ) | (48 | ) | ||||||||||||
Noncurrent liabilities | (1,137 | ) | (573 | ) | (1,247 | ) | (907 | ) | (739 | ) | (727 | ) | ||||||||||||
Total recognized | $ | (1,143 | ) | (484 | ) | (1,250 | ) | (902 | ) | (789 | ) | (775 | ) | |||||||||||
Weighted-Average Assumptions Used to Determine Benefit Obligations at December 31 | ||||||||||||||||||||||||
Discount rate | 6.00 | % | 5.90 | 5.75 | 5.15 | 6.20 | 5.95 | |||||||||||||||||
Rate of compensation increase | 4.00 | 4.80 | 4.00 | 4.70 | – | – | ||||||||||||||||||
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31 | ||||||||||||||||||||||||
Discount rate | 5.75 | % | 5.15 | 5.50 | 5.05 | 5.95 | 5.70 | |||||||||||||||||
Expected return on plan assets | 7.00 | 6.50 | 7.00 | 6.50 | 7.00 | 7.00 | ||||||||||||||||||
Rate of compensation increase | 4.00 | 4.70 | 4.00 | 4.35 | – | – | ||||||||||||||||||
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Millions of Dollars | ||||||||||||||||||||||||
Pension Benefits | Other Benefits | |||||||||||||||||||||||
2007 | 2006 | 2007 | 2006 | |||||||||||||||||||||
U.S. | Int’l. | U.S. | Int’l. | |||||||||||||||||||||
Unrecognized net actuarial loss (gain) | $ | 587 | 123 | 577 | 460 | (185 | ) | (200 | ) | |||||||||||||||
Unrecognized prior service cost | 71 | (30 | ) | 79 | 44 | 15 | 28 | |||||||||||||||||
Millions of Dollars | ||||||||||||
2007 | ||||||||||||
Pension | Other | |||||||||||
Benefits | Benefits | |||||||||||
U.S. | Int’l. | |||||||||||
Sources of Change in Other Comprehensive Income | ||||||||||||
Net gain (loss) arising during the period | $ | (72 | ) | 289 | 5 | |||||||
Amortization of gain (loss) included in income | 62 | 48 | (20 | ) | ||||||||
Net gain (loss) during the period | $ | (10 | ) | 337 | (15 | ) | ||||||
Prior service cost arising during the period | $ | (2 | ) | 67 | - | |||||||
Amortization of prior service cost included in income | 10 | 7 | 13 | |||||||||
Net prior service cost during the period | $ | 8 | 74 | 13 | ||||||||
Millions of Dollars | ||||||||||||
Pension | Other Benefits | |||||||||||
U.S. | Int’l. | |||||||||||
Unrecognized net actuarial loss (gain) | $ | 64 | 12 | (19 | ) | |||||||
Unrecognized prior service cost | 10 | 1 | 13 | |||||||||
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Millions of Dollars | ||||||||||||||||||||||||||||||||||||
Pension Benefits | Other Benefits | |||||||||||||||||||||||||||||||||||
2007 | 2006 | 2005 | 2007 | 2006 | 2005 | |||||||||||||||||||||||||||||||
U.S. | Int’l. | U.S. | Int’l. | U.S. | Int’l. | |||||||||||||||||||||||||||||||
Components of Net Periodic Benefit Cost | ||||||||||||||||||||||||||||||||||||
Service cost | $ | 175 | 98 | 174 | 87 | 151 | 69 | 14 | 14 | 19 | ||||||||||||||||||||||||||
Interest cost | 229 | 161 | 210 | 134 | 174 | 122 | 45 | 47 | 48 | |||||||||||||||||||||||||||
Expected return on plan assets | (204 | ) | (147 | ) | (169 | ) | (121 | ) | (126 | ) | (105 | ) | – | – | – | |||||||||||||||||||||
Amortization of prior service cost | 10 | 7 | 9 | 7 | 4 | 7 | 13 | 19 | 19 | |||||||||||||||||||||||||||
Recognized net actuarial loss (gain) | 62 | 48 | 89 | 41 | 55 | 33 | (20 | ) | (16 | ) | (6 | ) | ||||||||||||||||||||||||
Net periodic benefit cost | $ | 272 | 167 | 313 | 148 | 258 | 126 | 52 | 64 | 80 | ||||||||||||||||||||||||||
Millions of Dollars | ||||||||
One-Percentage-Point | ||||||||
Increase | Decrease | |||||||
Effect on total of service and interest cost components | $ | 2 | (3 | ) | ||||
Effect on the postretirement benefit obligation | 33 | (39 | ) | |||||
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Pension | ||||||||||||||||||||||||
U.S. | International | |||||||||||||||||||||||
2007 | 2006 | Target | 2007 | 2006 | Target | |||||||||||||||||||
Asset Category | ||||||||||||||||||||||||
Equity securities | 64 | % | 66 | 60 | 48 | 50 | 51 | |||||||||||||||||
Debt securities | 36 | 33 | 30 | 46 | 44 | 43 | ||||||||||||||||||
Real estate | – | – | 5 | 5 | 5 | 5 | ||||||||||||||||||
Other | – | 1 | 5 | 1 | 1 | 1 | ||||||||||||||||||
100 | % | 100 | 100 | 100 | 100 | 100 | ||||||||||||||||||
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Pension | ||||||||||||||||
U.S. | International | |||||||||||||||
2007 | 2006 | 2007 | 2006 | |||||||||||||
Asset Category | ||||||||||||||||
Equity securities | 62 | % | 72 | 48 | 50 | |||||||||||
Debt securities | 33 | 21 | 46 | 44 | ||||||||||||
Participating interest in annuity contract | 5 | 6 | - | - | ||||||||||||
Real estate | - | - | 5 | 5 | ||||||||||||
Other | - | 1 | 1 | 1 | ||||||||||||
100 | % | 100 | 100 | 100 | ||||||||||||
Millions of Dollars | ||||||||||||||||
Pension Benefits | Other Benefits | |||||||||||||||
Subsidy | ||||||||||||||||
U.S. | Int’l. | Gross | Receipts | |||||||||||||
2008 | $ | 326 | 98 | 55 | 7 | |||||||||||
2009 | 294 | 107 | 57 | 8 | ||||||||||||
2010 | 320 | 111 | 60 | 9 | ||||||||||||
2011 | 356 | 116 | 63 | 9 | ||||||||||||
2012 | 391 | 123 | 64 | 10 | ||||||||||||
2013-2017 | 2,537 | 730 | 342 | 61 | ||||||||||||
Most U.S. employees (excluding retail service station employees) are eligible to participate in either the ConocoPhillips Savings Plan (CPSP) or the Burlington Resources Savings Plan (BR Savings Plan). Employees can deposit up to 30 percent of their pay in the thrift feature of the CPSP to a choice of approximately 32 investment funds. ConocoPhillips matches deposits, up to 1.25 percent of eligible pay. Company contributions charged to expense for the CPSP and predecessor plans, excluding the stock savings feature (discussed below), were $21 million in 2007, $19 million in 2006, and $18 million in 2005. For the BR Savings Plan, ConocoPhillips matches deposits, up to 6 percent or 8 percent of the employee’s eligible pay based upon years of service. During 2007, ConocoPhillips contributed $5 million to the BR Savings Plan, to match eligible contributions by employees.
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2007 | 2006 | |||||||
Unallocated shares | 9,040,949 | 10,499,837 | ||||||
Allocated shares | 17,648,368 | 18,501,772 | ||||||
Total shares | 26,689,317 | 29,001,609 | ||||||
The 2004 Omnibus Stock and Performance Incentive Plan (the Plan) was approved by shareholders in May 2004. Over its 10-year life, the Plan allows the issuance of up to 70 million shares of our common stock for compensation to our employees, directors and consultants. After approval of the Plan, the heritage plans were no longer used for further awards. Of the 70 million shares available for issuance under the Plan, 40 million shares of common stock are available for incentive stock options, and no more than 40 million shares may be used for awards in stock.
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Millions of Dollars | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
Compensation cost | $ | 242 | 140 | 226 | ||||||||
Tax benefit | 85 | 54 | 84 | |||||||||
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Weighted- | Weighted-Average | Millions of Dollars | ||||||||||||||
Average | Grant-Date | Aggregate | ||||||||||||||
Options | Exercise Price | Fair Value | Intrinsic Value | |||||||||||||
Outstanding at December 31, 2004 | 74,263,922 | $ 25.97 | ||||||||||||||
Granted | 2,567,000 | 47.87 | $ 10.92 | |||||||||||||
Exercised | (19,265,175 | ) | 24.85 | $ 615 | ||||||||||||
Forfeited/expired | (169,001 | ) | 34.83 | |||||||||||||
Outstanding at December 31, 2005 | 57,396,746 | $ 27.31 | ||||||||||||||
Burlington Resources acquisition at March 31, 2006 | 4,927,116 | 33.95 | ||||||||||||||
Granted | 1,809,281 | 59.33 | $ 16.16 | |||||||||||||
Exercised | (9,737,765 | ) | 24.32 | $ 416 | ||||||||||||
Forfeited | (341,759 | ) | 60.58 | |||||||||||||
Expired | (4,840 | ) | 50.16 | |||||||||||||
Outstanding at December 31, 2006 | 54,048,779 | $ 29.31 | ||||||||||||||
Granted | 2,530,648 | 66.37 | $ 17.86 | |||||||||||||
Exercised | (12,176,988 | ) | 26.29 | $ 926 | ||||||||||||
Forfeited | (268,177 | ) | 65.02 | |||||||||||||
Expired or cancelled | (29,407 | ) | 17.00 | |||||||||||||
Outstanding at December 31, 2007 | 44,104,855 | $ 32.06 | ||||||||||||||
Vested at December 31, 2007 | 41,386,111 | $ 30.26 | $ 2,407 | |||||||||||||
Exercisable at December 31, 2007 | 39,721,035 | $ 28.86 | $ 2,366 | |||||||||||||
2007 | 2006 | 2005 | ||||||||||
Assumptions used | ||||||||||||
Risk-free interest rate | 4.77 | % | 4.63 | 3.92 | ||||||||
Dividend yield | 2.50 | % | 2.50 | 2.50 | ||||||||
Volatility factor | 26.10 | % | 26.10 | 22.50 | ||||||||
Expected life (years) | 6.70 | 7.18 | 7.18 | |||||||||
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2007 | 2006 | 2005 | ||||||||||||||||||||||
High | Low | High | Low | High | Low | |||||||||||||||||||
Ranges used | ||||||||||||||||||||||||
Risk-free interest rate | 4.90 | % | 4.77 | 5.15 | 4.54 | 4.45 | 3.33 | |||||||||||||||||
Dividend yield | 2.50 | 2.50 | 2.50 | 2.50 | 2.50 | 2.50 | ||||||||||||||||||
Volatility factor | 26.10 | 26.10 | 26.50 | 25.90 | 25.70 | 22.30 | ||||||||||||||||||
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Weighted-Average | Millions of Dollars | |||||||||||
Stock Units | Grant-Date Fair Value | Total Fair Value | ||||||||||
Outstanding at December 31, 2004 | 2,316,690 | $ | 32.10 | |||||||||
Granted | 1,668,192 | 46.95 | ||||||||||
Forfeited | (57,262 | ) | 37.81 | |||||||||
Issued | (35,216 | ) | $ | 2 | ||||||||
Outstanding at December 31, 2005 | 3,892,404 | $ | 38.34 | |||||||||
Granted | 1,480,294 | 57.77 | ||||||||||
Forfeited | (118,461 | ) | 45.92 | |||||||||
Issued | (167,099 | ) | $ | 11 | ||||||||
Outstanding at December 31, 2006 | 5,087,138 | $ | 43.75 | |||||||||
Granted | 1,721,521 | 65.33 | ||||||||||
Forfeited | (162,992 | ) | 52.57 | |||||||||
Issued | (975,756 | ) | $ | 36 | ||||||||
Outstanding at December 31, 2007 | 5,669,911 | $ | 51.30 | |||||||||
Not Vested at December 31, 2007 | 5,314,557 | $ | 50.61 | |||||||||
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Performance Share | Grant-Date | Millions of Dollars | ||||||||||
Stock Units | Fair Value | Total Fair Value | ||||||||||
Outstanding at December 31, 2005 | - | - | ||||||||||
Granted | 1,641,216 | $ | 59.08 | |||||||||
Forfeited/cancelled | - | |||||||||||
Issued | (184,975 | ) | $ | 12 | ||||||||
Outstanding at December 31, 2006 | 1,456,241 | $ | 59.08 | |||||||||
Granted | 1,349,475 | 66.37 | ||||||||||
Forfeited | (22,062 | ) | ||||||||||
Issued | (178,357 | ) | $ | 12 | ||||||||
Outstanding at December 31, 2007 | 2,605,297 | $ | 62.49 | |||||||||
Not Vested at December 31, 2007 | 1,198,599 | $ | 41.97 | |||||||||
Weighted-Average | Millions of Dollars | |||||||||||
Stock Units | Grant-Date Fair Value | Total Fair Value | ||||||||||
Outstanding at December 31, 2004 | 3,461,899 | $ | 28.44 | |||||||||
Granted | 89,676 | 54.08 | ||||||||||
Stock swaps | 9,116 | 43.97 | ||||||||||
Issued | (135,168 | ) | $ | 7 | ||||||||
Cancelled | (80,582 | ) | 28.93 | |||||||||
Outstanding at December 31, 2005 | 3,344,941 | $ | 29.16 | |||||||||
Granted | 248,421 | 64.48 | ||||||||||
Burlington Resources acquisition | 523,769 | 64.95 | ||||||||||
Issued | (239,257 | ) | $ | 16 | ||||||||
Cancelled | (275,499 | ) | 47.56 | |||||||||
Outstanding at December 31, 2006 | 3,602,375 | $ | 33.68 | |||||||||
Granted | 293,024 | 67.30 | ||||||||||
Issued | (227,766 | ) | $ | 17 | ||||||||
Cancelled | (180,489 | ) | 50.39 | |||||||||
Outstanding at December 31, 2007 | 3,487,144 | $ | 34.41 | |||||||||
Not Vested at December 31, 2007 | �� | 370,303 | $ | 65.65 | ||||||||
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Millions of Dollars | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
Income Taxes | ||||||||||||
Federal | ||||||||||||
Current | $ | 3,944 | 4,313 | 3,434 | ||||||||
Deferred | 312 | (77 | ) | 375 | ||||||||
Foreign | ||||||||||||
Current | 7,035 | 7,581 | 5,093 | |||||||||
Deferred | (474 | ) | 392 | 384 | ||||||||
State and local | ||||||||||||
Current | 602 | 622 | 538 | |||||||||
Deferred | (38 | ) | (48 | ) | 83 | |||||||
$ | 11,381 | 12,783 | 9,907 | |||||||||
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Millions of Dollars | ||||||||
2007 | 2006 | |||||||
Deferred Tax Liabilities | ||||||||
Properties, plants and equipment, and intangibles | $ | 23,344 | 22,733 | |||||
Investment in joint ventures | 1,300 | 1,178 | ||||||
Inventory | 197 | 339 | ||||||
Partnership income deferral | 1,501 | 1,305 | ||||||
Other | 725 | 438 | ||||||
Total deferred tax liabilities | 27,067 | 25,993 | ||||||
Deferred Tax Assets | ||||||||
Benefit plan accruals | 1,603 | 1,730 | ||||||
Asset retirement obligations and accrued environmental costs | 3,135 | 2,330 | ||||||
Deferred state income tax | 390 | 408 | ||||||
Other financial accruals and deferrals | 539 | 820 | ||||||
Loss and credit carryforwards | 1,716 | 1,283 | ||||||
Other | 251 | 230 | ||||||
Total deferred tax assets | 7,634 | 6,801 | ||||||
Less valuation allowance | (1,269 | ) | (822 | ) | ||||
Net deferred tax assets | 6,365 | 5,979 | ||||||
Net deferred tax liabilities | $ | 20,702 | 20,014 | |||||
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Millions | ||||
of Dollars | ||||
Balance at January 1 | $ | 912 | ||
Additions based on tax positions related to the current year | 273 | |||
Additions for tax positions of prior years | 145 | |||
Reductions for tax positions of prior years | (168 | ) | ||
Settlements | (15 | ) | ||
Lapse of statute | (4 | ) | ||
Balance at December 31, 2007 | $ | 1,143 | ||
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Percent of | ||||||||||||||||||||||||
Millions of Dollars | Pretax Income | |||||||||||||||||||||||
2007 | 2006 | 2005 | 2007 | 2006 | 2005 | |||||||||||||||||||
Income from continuing operations before income taxes | ||||||||||||||||||||||||
United States | $ | 13,939 | 13,376 | 12,486 | 59.9 | % | 47.2 | 53.0 | ||||||||||||||||
Foreign | 9,333 | 14,957 | 11,061 | 40.1 | 52.8 | 47.0 | ||||||||||||||||||
$ | 23,272 | 28,333 | 23,547 | 100.0 | % | 100.0 | 100.0 | |||||||||||||||||
Federal statutory income tax | $ | 8,145 | 9,917 | 8,241 | 35.0 | % | 35.0 | 35.0 | ||||||||||||||||
Foreign taxes in excess of federal statutory rate | 3,254 | 2,697 | 1,562 | 14.0 | 9.5 | 6.6 | ||||||||||||||||||
Federal manufacturing deduction | (250 | ) | (119 | ) | (106 | ) | (1.1 | ) | (.4 | ) | (.4 | ) | ||||||||||||
State income tax | 367 | 373 | 404 | 1.6 | 1.3 | 1.7 | ||||||||||||||||||
Other | (135 | ) | (85 | ) | (194 | ) | (.6 | ) | (.3 | ) | (.8 | ) | ||||||||||||
$ | 11,381 | 12,783 | 9,907 | 48.9 | % | 45.1 | 42.1 | |||||||||||||||||
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Millions of Dollars | ||||||||||||
Tax Expense | ||||||||||||
Before-Tax | (Benefit) | After-Tax | ||||||||||
2007 | ||||||||||||
Defined benefit pension plans: | ||||||||||||
Prior service cost arising during the year | $ | 65 | 20 | 45 | ||||||||
Reclassification adjustment for amortization of prior service cost included in net income | 30 | 12 | 18 | |||||||||
Net prior service cost | 95 | 32 | 63 | |||||||||
Net gain arising during the year | 222 | 67 | 155 | |||||||||
Reclassification adjustment for amortization of prior net losses included in net income | 90 | 32 | 58 | |||||||||
Net gain | 312 | 99 | 213 | |||||||||
Non-sponsored plans* | (2 | ) | - | (2 | ) | |||||||
Foreign currency translation adjustments | 3,214 | 139 | 3,075 | |||||||||
Hedging activities | (3 | ) | 1 | (4 | ) | |||||||
Other comprehensive income | $ | 3,616 | 271 | 3,345 | ||||||||
2006 | ||||||||||||
Minimum pension liability adjustment | $ | 53 | 20 | 33 | ||||||||
Foreign currency translation adjustments | 913 | (100 | ) | 1,013 | ||||||||
Hedging activities | 4 | - | 4 | |||||||||
Other comprehensive income | $ | 970 | (80 | ) | 1,050 | |||||||
2005 | ||||||||||||
Minimum pension liability adjustment | $ | (101 | ) | (45 | ) | (56 | ) | |||||
Unrealized loss on securities | (10 | ) | (4 | ) | (6 | ) | ||||||
Foreign currency translation adjustments | (786 | ) | (69 | ) | (717 | ) | ||||||
Hedging activities | (3 | ) | (4 | ) | 1 | |||||||
Other comprehensive loss | $ | (900 | ) | (122 | ) | (778 | ) | |||||
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Millions of Dollars | ||||||||
2007 | 2006 | |||||||
Defined benefit pension liability adjustments | $ | (465 | ) | (665 | ) | |||
Foreign currency translation adjustments | 5,033 | 1,958 | ||||||
Deferred net hedging loss | (8 | ) | (4 | ) | ||||
Accumulated other comprehensive income | $ | 4,560 | 1,289 | |||||
Millions of Dollars | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
Non-Cash Investing and Financing Activities | ||||||||||||
Issuance of stock and options for the acquisition of Burlington Resources | $ | - | 16,343 | - | ||||||||
Investment in an upstream business venture through issuance of an acquisition obligation | 7,313 | - | - | |||||||||
Investment in a downstream business venture through contribution of non-cash assets and liabilities | 2,428 | - | - | |||||||||
Increase in properties, plants and equipment (PP&E) resulting from our payment obligations to acquire an ownership interest in producing properties in Libya | - | - | 732 | |||||||||
Increase in PP&E related to an increase in asset retirement obligations | 919 | 464 | 511 | |||||||||
Cash Payments | ||||||||||||
Interest | $ | 1,040 | 958 | 500 | ||||||||
Income taxes | 11,330 | 13,050 | 8,507 | |||||||||
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Millions of Dollars | ||||||||||||
Except Per Share Amounts | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
Interest and Debt Expense | ||||||||||||
Incurred | ||||||||||||
Debt | $ | 1,369 | 1,409 | 807 | ||||||||
Other | 449 | 136 | 85 | |||||||||
1,818 | 1,545 | 892 | ||||||||||
Capitalized | (565 | ) | (458 | ) | (395 | ) | ||||||
Expensed | $ | 1,253 | 1,087 | 497 | ||||||||
Other Income | ||||||||||||
Interest income | $ | 342 | 165 | 127 | ||||||||
Gain on asset dispositions | 1,348 | 116 | 278 | |||||||||
Business interruption insurance recoveries* | 52 | 239 | - | |||||||||
Other | 229 | 165 | 60 | |||||||||
$ | 1,971 | 685 | 465 | |||||||||
Research and Development Expenditures—expensed | $ | 160 | 117 | 125 | ||||||||
Advertising Expenses | $ | 84 | 87 | 84 | ||||||||
Shipping and Handling Costs* | $ | 1,493 | 1,415 | 1,265 | ||||||||
Cash Dividendspaid per common share | $ | 1.64 | 1.44 | 1.18 | ||||||||
Foreign Currency Transaction Gains (Losses)—after-tax | ||||||||||||
E&P | $ | 216 | (44 | ) | 7 | |||||||
Midstream | (2 | ) | - | 7 | ||||||||
R&M | (13 | ) | 60 | (52 | ) | |||||||
LUKOIL Investment | 5 | - | (1 | ) | ||||||||
Chemicals | - | - | - | |||||||||
Emerging Businesses | 1 | 1 | (1 | ) | ||||||||
Corporate and Other | (120 | ) | 65 | (42 | ) | |||||||
$ | 87 | 82 | (82 | ) | ||||||||
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Millions of Dollars | ||||||||||||
2007 | 2006 | * | 2005 | * | ||||||||
Operating revenues (a) | $ | 10,949 | 8,808 | 7,719 | ||||||||
Purchases (b)** | 15,722 | 7,072 | 6,089 | |||||||||
Operating expenses and selling, general and administrative expenses (c) | 416 | 386 | 380 | |||||||||
Net interest expense (d) | 99 | (13 | ) | 30 | ||||||||
(a) | We sold natural gas to DCP Midstream and crude oil to the Malaysian Refining Company Sdn. Bhd. (MRC), among others, for processing and marketing. Natural gas liquids, solvents and petrochemical feedstocks were sold to Chevron Phillips Chemical Company LLC (CPChem), gas oil and hydrogen feedstocks were sold to Excel Paralubes and refined products were sold primarily to CFJ Properties and LUKOIL. Natural gas, crude oil, blendstock and other intermediate products were sold to WRB Refining LLC. We also sold various international marketing companies to LUKOIL in the second quarter of 2007. In addition, we charged several of our affiliates including CPChem, Merey Sweeny L.P. (MSLP) and Hamaca Holding LLC (until expropriation on June 26, 2007) for the use of common facilities, such as steam generators, waste and water treaters, and warehouse facilities. |
(b) | We purchased refined products from WRB Refining. We purchased natural gas and natural gas liquids from DCP Midstream and CPChem for use in our refinery processes and other feedstocks from various affiliates. We purchased crude oil from LUKOIL, upgraded crude oil from Petrozuata C.A. (until expropriation on June 26, 2007) and refined products from MRC. We also paid fees to various pipeline equity companies for transporting finished refined products and a price upgrade to MSLP for heavy crude processing. We purchased base oils and fuel products from Excel Paralubes for use in our refinery and specialty businesses. |
(c) | We paid processing fees to various affiliates. Additionally, we paid crude oil transportation fees to pipeline equity companies. |
(d) | We paid and/or received interest to/from various affiliates, including FCCL Oil Sands Partnership. See Note 10—Investments, Loans and Long-Term Receivables, for additional information on loans to affiliated companies. |
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1) | E&P—This segment primarily explores for, produces, transports and markets crude oil, natural gas and natural gas liquids on a worldwide basis. At December 31, 2007, our E&P operations were producing in the United States, Norway, the United Kingdom, the Netherlands, Canada, Nigeria, Ecuador, Argentina, offshore Timor-Leste in the Timor Sea, Australia, China, Indonesia, Algeria, Libya, Vietnam, and Russia. The E&P segment’s U.S. and international operations are disclosed separately for reporting purposes. | ||
2) | Midstream—This segment gathers, processes and markets natural gas produced by ConocoPhillips and others, and fractionates and markets natural gas liquids, primarily in the United States and Trinidad. The Midstream segment primarily consists of our 50 percent equity investment in DCP Midstream. | ||
3) | R&M—This segment purchases, refines, markets and transports crude oil and petroleum products, mainly in the United States, Europe and Asia. At December 31, 2007, we owned or had an interest in 12 refineries in the United States, one in the United Kingdom, one in Ireland, two in Germany, and one in Malaysia. The R&M segment’s U.S. and international operations are disclosed separately for reporting purposes. | ||
4) | LUKOIL Investment—This segment represents our investment in the ordinary shares of LUKOIL, an international, integrated oil and gas company headquartered in Russia. At December 31, 2007, our ownership interest was 20 percent based on issued shares, and 20.6 percent based on estimated shares outstanding. See Note 10—Investments, Loans and Long-Term Receivables, for additional information. | ||
5) | Chemicals—This segment manufactures and markets petrochemicals and plastics on a worldwide basis. The Chemicals segment consists of our 50 percent equity investment in CPChem. | ||
6) | Emerging Businesses—This segment represents our investment in new technologies or businesses outside our normal scope of operations. Activities within this segment are currently focused on power generation and other items, such as carbon-to-liquids, technology solutions, and alternative energy and programs, such as advanced hydrocarbon processes, energy conversion technologies, new petroleum-based products, and renewable fuels. |
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Millions of Dollars | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
Sales and Other Operating Revenues | ||||||||||||
E&P | ||||||||||||
United States | $ | 36,974 | 35,335 | 35,159 | ||||||||
International | 24,617 | 28,111 | 21,692 | |||||||||
Intersegment eliminations—U.S. | (6,096 | ) | (5,438 | ) | (4,075 | ) | ||||||
Intersegment eliminations—international | (7,341 | ) | (7,842 | ) | (4,251 | ) | ||||||
E&P | 48,154 | 50,166 | 48,525 | |||||||||
Midstream | ||||||||||||
Total sales | 5,106 | 4,461 | 4,041 | |||||||||
Intersegment eliminations | (245 | ) | (1,037 | ) | (955 | ) | ||||||
Midstream | 4,861 | 3,424 | 3,086 | |||||||||
R&M | ||||||||||||
United States | 96,154 | 95,314 | 97,251 | |||||||||
International | 38,598 | 35,439 | 30,633 | |||||||||
Intersegment eliminations—U.S. | (540 | ) | (855 | ) | (593 | ) | ||||||
Intersegment eliminations—international | (11 | ) | (21 | ) | (11 | ) | ||||||
R&M | 134,201 | 129,877 | 127,280 | |||||||||
LUKOIL Investment | - | - | - | |||||||||
Chemicals | 10 | 13 | 14 | |||||||||
Emerging Businesses* | ||||||||||||
Total sales | 656 | 675 | 618 | |||||||||
Intersegment eliminations | (458 | ) | (515 | ) | (426 | ) | ||||||
Emerging Businesses | 198 | 160 | 192 | |||||||||
Corporate and Other | 13 | 10 | 13 | |||||||||
Other adjustments* | - | - | 332 | |||||||||
Consolidated sales and other operating revenues | $ | 187,437 | 183,650 | 179,442 | ||||||||
E&P | ||||||||||||
United States | $ | 3,328 | 2,901 | 1,402 | ||||||||
International | 9,121 | 3,445 | 1,914 | |||||||||
Total E&P | 12,449 | 6,346 | 3,316 | |||||||||
Midstream | 14 | 29 | 61 | |||||||||
R&M | ||||||||||||
United States | 609 | 1,014 | 633 | |||||||||
International | 139 | 458 | 193 | |||||||||
Total R&M | 748 | 1,472 | 826 | |||||||||
LUKOIL Investment | - | - | - | |||||||||
Chemicals | - | - | - | |||||||||
Emerging Businesses | 39 | 58 | 32 | |||||||||
Corporate and Other | 78 | 62 | 60 | |||||||||
Consolidated depreciation, depletion, amortization and impairments | $ | 13,328 | 7,967 | 4,295 | ||||||||
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Millions of Dollars | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
Equity in Earnings of Affiliates | ||||||||||||
E&P | ||||||||||||
United States | $ | 11 | 20 | 19 | ||||||||
International | 302 | 782 | 825 | |||||||||
Total E&P | 313 | 802 | 844 | |||||||||
Midstream | 599 | 618 | 829 | |||||||||
R&M | ||||||||||||
United States | 1,710 | 466 | 388 | |||||||||
International | 240 | 151 | 227 | |||||||||
Total R&M | 1,950 | 617 | 615 | |||||||||
LUKOIL Investment | 1,875 | 1,481 | 756 | |||||||||
Chemicals | 350 | 665 | 413 | |||||||||
Emerging Businesses | - | 5 | - | |||||||||
Corporate and Other | - | - | - | |||||||||
Consolidated equity in earnings of affiliates | $ | 5,087 | 4,188 | 3,457 | ||||||||
Income Taxes | ||||||||||||
E&P | ||||||||||||
United States | $ | 2,231 | 2,545 | 2,349 | ||||||||
International | 6,372 | 7,584 | 5,145 | |||||||||
Total E&P | 8,603 | 10,129 | 7,494 | |||||||||
Midstream | 237 | 248 | 214 | |||||||||
R&M | ||||||||||||
United States | 2,571 | 2,334 | 2,124 | |||||||||
International | 113 | 218 | 212 | |||||||||
Total R&M | 2,684 | 2,552 | 2,336 | |||||||||
LUKOIL Investment | 45 | 37 | 25 | |||||||||
Chemicals | (13 | ) | 171 | 93 | ||||||||
Emerging Businesses | (33 | ) | (2 | ) | (18 | ) | ||||||
Corporate and Other | (142 | ) | (352 | ) | (237 | ) | ||||||
Consolidated income taxes | $ | 11,381 | 12,783 | 9,907 | ||||||||
Net Income (Loss) | ||||||||||||
E&P | ||||||||||||
United States | $ | 4,248 | 4,348 | 4,288 | ||||||||
International | 367 | 5,500 | 4,142 | |||||||||
Total E&P | 4,615 | 9,848 | 8,430 | |||||||||
Midstream | 453 | 476 | 688 | |||||||||
R&M | ||||||||||||
United States | 4,615 | 3,915 | 3,329 | |||||||||
International | 1,308 | 566 | 844 | |||||||||
Total R&M | 5,923 | 4,481 | 4,173 | |||||||||
LUKOIL Investment | 1,818 | 1,425 | 714 | |||||||||
Chemicals | 359 | 492 | 323 | |||||||||
Emerging Businesses | (8 | ) | 15 | (21 | ) | |||||||
Corporate and Other | (1,269 | ) | (1,187 | ) | (778 | ) | ||||||
Consolidated net income | $ | 11,891 | 15,550 | 13,529 | ||||||||
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Millions of Dollars | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
Investments In and Advances To Affiliates | ||||||||||||
E&P | ||||||||||||
United States | $ | 1,059 | 690 | 336 | ||||||||
International | 12,055 | 4,346 | 3,789 | |||||||||
Total E&P | 13,114 | 5,036 | 4,125 | |||||||||
Midstream | 1,178 | 1,319 | 1,446 | |||||||||
R&M | ||||||||||||
United States | 3,500 | 698 | 662 | |||||||||
International | 1,091 | 948 | 819 | |||||||||
Total R&M | 4,591 | 1,646 | 1,481 | |||||||||
LUKOIL Investment | 11,162 | 9,564 | 5,549 | |||||||||
Chemicals | 2,203 | 2,255 | 2,158 | |||||||||
Emerging Businesses | 79 | - | - | |||||||||
Corporate and Other | - | - | 18 | |||||||||
Consolidated investments in and advances to affiliates* | $ | 32,327 | 19,820 | 14,777 | ||||||||
*Includes amounts classified as held for sale: | $ | 48 | 158 | - | ||||||||
Total Assets | ||||||||||||
E&P | ||||||||||||
United States | $ | 35,160 | 35,523 | 18,434 | ||||||||
International | 59,412 | 48,143 | 31,662 | |||||||||
Goodwill | 25,569 | 27,712 | 11,423 | |||||||||
Total E&P | 120,141 | 111,378 | 61,519 | |||||||||
Midstream | 2,016 | 2,045 | 2,109 | |||||||||
R&M | ||||||||||||
United States | 24,336 | 22,936 | 20,693 | |||||||||
International | 9,766 | 9,135 | 6,096 | |||||||||
Goodwill | 3,767 | 3,776 | 3,900 | |||||||||
Total R&M | 37,869 | 35,847 | 30,689 | |||||||||
LUKOIL Investment | 11,164 | 9,564 | 5,549 | |||||||||
Chemicals | 2,225 | 2,379 | 2,324 | |||||||||
Emerging Businesses | 1,230 | 977 | 858 | |||||||||
Corporate and Other | 3,112 | 2,591 | 3,951 | |||||||||
Consolidated total assets | $ | 177,757 | 164,781 | 106,999 | ||||||||
Capital Expenditures and Investments* | ||||||||||||
E&P | ||||||||||||
United States | $ | 3,788 | 2,828 | 1,637 | ||||||||
International | 6,147 | 6,685 | 5,047 | |||||||||
Total E&P | 9,935 | 9,513 | 6,684 | |||||||||
Midstream | 5 | 4 | 839 | |||||||||
R&M | ||||||||||||
United States | 1,146 | 1,597 | 1,537 | |||||||||
International | 240 | 1,419 | 201 | |||||||||
Total R&M | 1,386 | 3,016 | 1,738 | |||||||||
LUKOIL Investment | - | 2,715 | 2,160 | |||||||||
Chemicals | - | - | - | |||||||||
Emerging Businesses | 257 | 83 | 5 | |||||||||
Corporate and Other | 208 | 265 | 194 | |||||||||
Consolidated capital expenditures and investments | $ | 11,791 | 15,596 | 11,620 | ||||||||
*Net of cash acquired. |
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Millions of Dollars | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
Interest income* | $ | 246 | 106 | 113 | ||||||||
Interest and debt expense** | 1,066 | 1,087 | 497 | |||||||||
*In addition, the E&P segment had interest income of: | $ | 96 | 57 | 12 | ||||||||
**In addition, the E&P segment had interest expense of: | 187 | - | - |
Millions of Dollars | ||||||||||||||||||||||||||||
Other | ||||||||||||||||||||||||||||
United | United | Foreign | Worldwide | |||||||||||||||||||||||||
States | Norway | Kingdom | Canada | Russia | Countries | Consolidated | ||||||||||||||||||||||
2007 | ||||||||||||||||||||||||||||
Sales and Other | ||||||||||||||||||||||||||||
Operating Revenues* | $ | 131,433 | 2,479 | 20,680 | 4,727 | - | 28,118 | 187,437 | ||||||||||||||||||||
Long-Lived Assets** | $ | 50,714 | 6,180 | 7,995 | 24,758 | 13,359 | 18,324 | 121,330 | ||||||||||||||||||||
2006 | ||||||||||||||||||||||||||||
Sales and Other | ||||||||||||||||||||||||||||
Operating Revenues* | $ | 127,869 | 2,480 | 19,510 | 5,554 | - | 28,237 | 183,650 | ||||||||||||||||||||
Long-Lived Assets** | $ | 48,418 | 4,982 | 7,755 | 14,831 | 10,886 | 19,149 | 106,021 | ||||||||||||||||||||
2005 | ||||||||||||||||||||||||||||
Sales and Other | ||||||||||||||||||||||||||||
Operating Revenues* | $ | 130,874 | 3,280 | 19,043 | 5,676 | - | 20,569 | 179,442 | ||||||||||||||||||||
Long-Lived Assets** | $ | 33,161 | 4,380 | 5,564 | 5,328 | 6,342 | 14,671 | 69,446 | ||||||||||||||||||||
**Defined as net properties, plants and equipment plus investments in and advances to affiliated companies.
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The recording and reporting of proved reserves are governed by criteria established by regulations of the SEC. Those regulations define proved reserves as those estimated quantities of hydrocarbons that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved reserves are further classified as either developed or undeveloped. Proved developed reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods, while proved undeveloped reserves are the quantities expected to be recovered from new wells on undrilled acreage, or from an existing well where relatively major expenditures are required for recompletion.
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n | Proved Reserves Worldwide |
Years Ended | Crude Oil | |||||||||||||||||||||||||||||||||||||||||||
December 31 | Millions of Barrels | |||||||||||||||||||||||||||||||||||||||||||
Consolidated Operations | ||||||||||||||||||||||||||||||||||||||||||||
Lower | Total | Asia | Middle East | Russia and | Other | Equity | ||||||||||||||||||||||||||||||||||||||
Alaska | 48 | U.S. | Canada | Europe | Pacific | and Africa | Caspian | Areas | Total | Affiliates | ||||||||||||||||||||||||||||||||||
Developed and Undeveloped | ||||||||||||||||||||||||||||||||||||||||||||
End of 2004 | 1,536 | 170 | 1,706 | 47 | 851 | 255 | 127 | 181 | - | 3,167 | 1,982 | |||||||||||||||||||||||||||||||||
Revisions | 31 | 6 | 37 | 4 | 34 | 7 | (21 | ) | (11 | ) | - | 50 | 6 | |||||||||||||||||||||||||||||||
Improved recovery | 15 | 1 | 16 | - | - | - | - | - | - | 16 | - | |||||||||||||||||||||||||||||||||
Purchases | - | 3 | 3 | - | - | - | 238 | 20 | - | 261 | 515 | |||||||||||||||||||||||||||||||||
Extensions and discoveries | 31 | 13 | 44 | 1 | 17 | 49 | 4 | - | 17 | 132 | 60 | |||||||||||||||||||||||||||||||||
Production | (108 | ) | (21 | ) | (129 | ) | (8 | ) | (94 | ) | (37 | ) | (20 | ) | - | - | (288 | ) | (130 | ) | ||||||||||||||||||||||||
Sales | - | (2 | ) | (2 | ) | - | - | - | - | - | - | (2 | ) | (3 | ) | |||||||||||||||||||||||||||||
End of 2005 | 1,505 | 170 | 1,675 | 44 | 808 | 274 | 328 | 190 | 17 | 3,336 | 2,430 | |||||||||||||||||||||||||||||||||
Revisions | (118 | ) | (11 | ) | (129 | ) | 58 | (65 | ) | (12 | ) | (18 | ) | (74 | ) | 2 | (238 | ) | (35 | ) | ||||||||||||||||||||||||
Improved recovery | 13 | 1 | 14 | - | 5 | 63 | - | - | - | 82 | - | |||||||||||||||||||||||||||||||||
Purchases | - | 181 | 181 | 16 | - | 13 | 42 | - | 17 | 269 | 393 | |||||||||||||||||||||||||||||||||
Extensions and discoveries | 53 | 9 | 62 | 4 | 6 | 8 | 3 | - | - | 83 | 74 | |||||||||||||||||||||||||||||||||
Production | (97 | ) | (37 | ) | (134 | ) | (9 | ) | (90 | ) | (39 | ) | (39 | ) | - | (3 | ) | (314 | ) | (171 | ) | |||||||||||||||||||||||
Sales | - | (18 | ) | (18 | ) | - | - | - | - | - | - | (18 | ) | (1 | ) | |||||||||||||||||||||||||||||
End of 2006 | 1,356 | 295 | 1,651 | 113 | 664 | 307 | 316 | 116 | 33 | 3,200 | 2,690 | |||||||||||||||||||||||||||||||||
Revisions | 24 | 19 | 43 | 28 | 10 | (23 | ) | (13 | ) | 1 | (3 | ) | 43 | 202 | ||||||||||||||||||||||||||||||
Improved recovery | 25 | 16 | 41 | - | - | - | - | - | - | 41 | - | |||||||||||||||||||||||||||||||||
Purchases | - | - | - | - | - | - | - | - | - | - | 403 | |||||||||||||||||||||||||||||||||
Extensions and discoveries | 26 | 15 | 41 | 3 | 8 | 73 | 16 | - | - | 141 | 303 | |||||||||||||||||||||||||||||||||
Production | (96 | ) | (36 | ) | (132 | ) | (7 | ) | (76 | ) | (32 | ) | (29 | ) | - | (4 | ) | (280 | ) | (172 | ) | |||||||||||||||||||||||
Sales | - | (1 | ) | (1 | ) | (16 | ) | (1 | ) | (6 | ) | - | - | (17 | ) | (41 | ) | (1,028 | ) | |||||||||||||||||||||||||
End of 2007 | 1,335 | 308 | 1,643 | 121 | 605 | 319 | 290 | 117 | 9 | 3,104 | 2,398 | |||||||||||||||||||||||||||||||||
Equity affiliates | ||||||||||||||||||||||||||||||||||||||||||||
End of 2004 | - | - | - | - | - | - | - | 800 | 1,182 | - | 1,982 | |||||||||||||||||||||||||||||||||
End of 2005 | - | - | - | - | - | - | 46 | 1,295 | 1,089 | - | 2,430 | |||||||||||||||||||||||||||||||||
End of 2006 | - | - | - | - | - | - | 60 | 1,607 | 1,023 | - | 2,690 | |||||||||||||||||||||||||||||||||
End of 2007 | - | - | - | 623 | - | - | 70 | 1,705 | - | - | 2,398 | |||||||||||||||||||||||||||||||||
Developed | ||||||||||||||||||||||||||||||||||||||||||||
Consolidated operations | ||||||||||||||||||||||||||||||||||||||||||||
End of 2004 | 1,415 | 148 | 1,563 | 46 | 429 | 207 | 121 | - | - | 2,366 | - | |||||||||||||||||||||||||||||||||
End of 2005 | 1,359 | 158 | 1,517 | 42 | 409 | 202 | 326 | - | - | 2,496 | - | |||||||||||||||||||||||||||||||||
End of 2006 | 1,254 | 281 | 1,535 | 50 | 359 | 181 | 292 | - | 13 | 2,430 | - | |||||||||||||||||||||||||||||||||
End of 2007 | 1,238 | 281 | 1,519 | 51 | 337 | 146 | 259 | - | 9 | 2,321 | - | |||||||||||||||||||||||||||||||||
Equity affiliates | ||||||||||||||||||||||||||||||||||||||||||||
End of 2004 | - | - | - | - | - | - | - | 624 | 491 | - | 1,115 | |||||||||||||||||||||||||||||||||
End of 2005 | - | - | - | - | - | - | - | 1,013 | 472 | - | 1,485 | |||||||||||||||||||||||||||||||||
End of 2006 | - | - | - | - | - | - | - | 1,293 | 369 | - | 1,662 | |||||||||||||||||||||||||||||||||
End of 2007 | - | - | - | 45 | - | - | - | 1,336 | - | - | 1,381 | |||||||||||||||||||||||||||||||||
• | Revisions: In 2007 for our equity affiliate operations, revisions were primarily attributable to LUKOIL. In 2006, revisions in Alaska were primarily a result of reservoir performance. | ||
• | Purchases: In 2007 for our equity affiliate operations, purchases reflect the formation of FCCL. In 2006, purchases in the Lower 48 were primarily related to our acquisition of Burlington Resources in March 2006. In 2006 and 2005 for our equity affiliate operations, purchases were mainly attributable to acquiring additional interests in LUKOIL. In 2005, purchases in the Middle East and Africa were attributable to our re-entry into Libya. |
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• | Extensions and Discoveries: In 2007 for our equity affiliate operations, extensions and discoveries were primarily associated with FCCL. | ||
• | Sales: In 2007 for our equity affiliates, sales were primarily due to the expropriation of our oil interests in Venezuela. |
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Years Ended | Natural Gas | |||||||||||||||||||||||||||||||||||||||||||
December 31 | Billions of Cubic Feet | |||||||||||||||||||||||||||||||||||||||||||
Consolidated Operations | ||||||||||||||||||||||||||||||||||||||||||||
Lower | Total | Asia | Middle East | Russia and | Other | Equity | ||||||||||||||||||||||||||||||||||||||
Alaska | 48 | U.S. | Canada | Europe | Pacific | and Africa | Caspian | Areas | Total | Affiliates | ||||||||||||||||||||||||||||||||||
Developed and Undeveloped | ||||||||||||||||||||||||||||||||||||||||||||
End of 2004 | 3,344 | 4,234 | 7,578 | 975 | 3,285 | 3,773 | 1,104 | 119 | - | 16,834 | 862 | |||||||||||||||||||||||||||||||||
Revisions | 260 | (43 | ) | 217 | 72 | 83 | (20 | ) | - | (3 | ) | - | 349 | 51 | ||||||||||||||||||||||||||||||
Improved recovery | - | 1 | 1 | - | - | - | - | - | - | 1 | - | |||||||||||||||||||||||||||||||||
Purchases | 7 | 163 | 170 | - | 1 | 8 | - | 13 | - | 192 | 453 | |||||||||||||||||||||||||||||||||
Extensions and discoveries | 5 | 270 | 275 | 78 | 79 | 85 | 2 | - | 5 | 524 | 1,212 | |||||||||||||||||||||||||||||||||
Production | (144 | ) | (449 | ) | (593 | ) | (155 | ) | (386 | ) | (146 | ) | (45 | ) | - | - | (1,325 | ) | (30 | ) | ||||||||||||||||||||||||
Sales | - | (62 | ) | (62 | ) | - | - | - | - | - | - | (62 | ) | - | ||||||||||||||||||||||||||||||
End of 2005 | 3,472 | 4,114 | 7,586 | 970 | 3,062 | 3,700 | 1,061 | 129 | 5 | 16,513 | 2,548 | |||||||||||||||||||||||||||||||||
Revisions | 43 | (87 | ) | (44 | ) | (123 | ) | (293 | ) | 71 | (64 | ) | (31 | ) | (39 | ) | (523 | ) | (310 | ) | ||||||||||||||||||||||||
Improved recovery | - | 4 | 4 | - | 1 | - | - | - | - | 5 | - | |||||||||||||||||||||||||||||||||
Purchases | 6 | 5,258 | 5,264 | 2,466 | 432 | 25 | 94 | - | 129 | 8,410 | 325 | |||||||||||||||||||||||||||||||||
Extensions and discoveries | 23 | 551 | 574 | 353 | 64 | 6 | 58 | - | - | 1,055 | 925 | |||||||||||||||||||||||||||||||||
Production | (130 | ) | (770 | ) | (900 | ) | (356 | ) | (414 | ) | (233 | ) | (62 | ) | - | (6 | ) | (1,971 | ) | (99 | ) | |||||||||||||||||||||||
Sales | - | (43 | ) | (43 | ) | - | - | - | - | - | - | (43 | ) | - | ||||||||||||||||||||||||||||||
End of 2006 | 3,414 | 9,027 | 12,441 | 3,310 | 2,852 | 3,569 | 1,087 | 98 | 89 | 23,446 | 3,389 | |||||||||||||||||||||||||||||||||
Revisions | 120 | 446 | 566 | (41 | ) | 91 | (47 | ) | (26 | ) | - | (12 | ) | 531 | (327 | ) | ||||||||||||||||||||||||||||
Improved recovery | 5 | 1 | 6 | - | - | - | - | - | - | 6 | - | |||||||||||||||||||||||||||||||||
Purchases | - | 30 | 30 | - | - | - | - | - | - | 30 | - | |||||||||||||||||||||||||||||||||
Extensions and discoveries | 5 | 539 | 544 | 143 | 29 | 28 | 23 | - | - | 767 | 364 | |||||||||||||||||||||||||||||||||
Production | (113 | ) | (835 | ) | (948 | ) | (404 | ) | (369 | ) | (224 | ) | (55 | ) | - | (7 | ) | (2,007 | ) | (103 | ) | |||||||||||||||||||||||
Sales | - | (5 | ) | (5 | ) | (170 | ) | (20 | ) | (74 | ) | - | - | (5 | ) | (274 | ) | (384 | ) | |||||||||||||||||||||||||
End of 2007 | 3,431 | 9,203 | 12,634 | 2,838 | 2,583 | 3,252 | 1,029 | 98 | 65 | 22,499 | 2,939 | |||||||||||||||||||||||||||||||||
Equity affiliates | ||||||||||||||||||||||||||||||||||||||||||||
End of 2004 | - | - | - | - | - | - | - | 661 | 201 | - | 862 | |||||||||||||||||||||||||||||||||
End of 2005 | - | - | - | - | - | - | 1,063 | 1,197 | 288 | - | 2,548 | |||||||||||||||||||||||||||||||||
End of 2006 | - | - | - | - | - | - | 1,573 | 1,429 | 387 | - | 3,389 | |||||||||||||||||||||||||||||||||
End of 2007 | - | - | - | - | - | - | 1,925 | 1,014 | - | - | 2,939 | |||||||||||||||||||||||||||||||||
Developed | ||||||||||||||||||||||||||||||||||||||||||||
Consolidated operations | ||||||||||||||||||||||||||||||||||||||||||||
End of 2004 | 3,194 | 3,989 | 7,183 | 934 | 2,467 | 1,520 | 522 | - | - | 12,626 | - | |||||||||||||||||||||||||||||||||
End of 2005 | 3,316 | 3,966 | 7,282 | 918 | 2,393 | 2,600 | 1,060 | - | - | 14,253 | - | |||||||||||||||||||||||||||||||||
End of 2006 | 3,336 | 7,484 | 10,820 | 2,672 | 2,314 | 3,105 | 1,029 | - | 24 | 19,964 | - | |||||||||||||||||||||||||||||||||
End of 2007 | 3,344 | 7,417 | 10,761 | 2,328 | 2,177 | 2,857 | 963 | - | 26 | 19,112 | - | |||||||||||||||||||||||||||||||||
Equity affiliates | ||||||||||||||||||||||||||||||||||||||||||||
End of 2004 | - | - | - | - | - | - | - | 207 | 118 | - | 325 | |||||||||||||||||||||||||||||||||
End of 2005 | - | - | - | - | - | - | - | 581 | 155 | - | 736 | |||||||||||||||||||||||||||||||||
End of 2006 | - | - | - | - | - | - | - | 655 | 173 | - | 828 | |||||||||||||||||||||||||||||||||
End of 2007 | - | - | - | - | - | - | - | 698 | - | - | 698 | |||||||||||||||||||||||||||||||||
• | Purchases: In 2006 for our consolidated operations, purchases were primarily related to our acquisition of Burlington Resources. | ||
• | Extensions and Discoveries: In 2006 for our equity affiliate operations, extensions and discoveries were primarily in Qatar and LUKOIL. In 2005, extensions and discoveries for our equity affiliate operations were primarily in Qatar. |
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Years Ended | Natural Gas Liquids | |||||||||||||||||||||||||||||||||||||||||||
December 31 | Millions of Barrels | |||||||||||||||||||||||||||||||||||||||||||
Consolidated Operations | ||||||||||||||||||||||||||||||||||||||||||||
Lower | Total | Asia | Middle East | Russia and | Other | Equity | ||||||||||||||||||||||||||||||||||||||
Alaska | 48 | U.S. | Canada | Europe | Pacific | and Africa | Caspian | Areas | Total | Affiliates | ||||||||||||||||||||||||||||||||||
Developed and Undeveloped | ||||||||||||||||||||||||||||||||||||||||||||
End of 2004 | 153 | 88 | 241 | 26 | 48 | 71 | 4 | - | - | 390 | - | |||||||||||||||||||||||||||||||||
Revisions | - | 17 | 17 | 1 | 6 | 4 | - | - | - | 28 | - | |||||||||||||||||||||||||||||||||
Improved recovery | - | - | - | - | - | - | - | - | - | - | - | |||||||||||||||||||||||||||||||||
Purchases | - | 8 | 8 | - | - | - | - | - | - | 8 | - | |||||||||||||||||||||||||||||||||
Extensions and discoveries | - | 5 | 5 | - | 1 | 2 | - | - | - | 8 | 21 | |||||||||||||||||||||||||||||||||
Production | (7 | ) | (9 | ) | (16 | ) | (3 | ) | (5 | ) | (6 | ) | (1 | ) | - | - | (31 | ) | - | |||||||||||||||||||||||||
Sales | - | (1 | ) | (1 | ) | - | - | - | - | - | - | (1 | ) | - | ||||||||||||||||||||||||||||||
End of 2005 | 146 | 108 | 254 | 24 | 50 | 71 | 3 | - | - | 402 | 21 | |||||||||||||||||||||||||||||||||
Revisions | (1 | ) | 24 | 23 | 1 | (4 | ) | (1 | ) | (1 | ) | - | - | 18 | - | |||||||||||||||||||||||||||||
Improved recovery | - | - | - | - | - | - | - | - | - | - | - | |||||||||||||||||||||||||||||||||
Purchases | - | 328 | 328 | 56 | - | - | - | - | - | 384 | - | |||||||||||||||||||||||||||||||||
Extensions and discoveries | - | 14 | 14 | 7 | - | - | - | - | - | 21 | 11 | |||||||||||||||||||||||||||||||||
Production | (6 | ) | (22 | ) | (28 | ) | (9 | ) | (5 | ) | (7 | ) | - | - | - | (49 | ) | - | ||||||||||||||||||||||||||
Sales | - | (2 | ) | (2 | ) | - | - | - | - | - | - | (2 | ) | - | ||||||||||||||||||||||||||||||
End of 2006 | 139 | 450 | 589 | 79 | 41 | 63 | 2 | - | - | 774 | 32 | |||||||||||||||||||||||||||||||||
Revisions | 1 | 31 | 32 | (4 | ) | - | (2 | ) | - | - | - | 26 | 20 | |||||||||||||||||||||||||||||||
Improved recovery | - | - | - | - | - | - | - | - | - | - | - | |||||||||||||||||||||||||||||||||
Purchases | - | - | - | - | - | - | - | - | - | - | - | |||||||||||||||||||||||||||||||||
Extensions and discoveries | - | 12 | 12 | 2 | 1 | 3 | - | - | - | 18 | 7 | |||||||||||||||||||||||||||||||||
Production | (7 | ) | (27 | ) | (34 | ) | (10 | ) | (4 | ) | (5 | ) | (1 | ) | - | - | (54 | ) | - | |||||||||||||||||||||||||
Sales | - | - | - | (2 | ) | - | (3 | ) | - | - | - | (5 | ) | - | ||||||||||||||||||||||||||||||
End of 2007 | 133 | 466 | 599 | 65 | 38 | 56 | 1 | - | - | 759 | 59 | |||||||||||||||||||||||||||||||||
Equity affiliates | ||||||||||||||||||||||||||||||||||||||||||||
End of 2004 | - | - | - | - | - | - | - | - | - | - | - | |||||||||||||||||||||||||||||||||
End of 2005 | - | - | - | - | - | - | 21 | - | - | - | 21 | |||||||||||||||||||||||||||||||||
End of 2006 | - | - | - | - | - | - | 32 | - | - | - | 32 | |||||||||||||||||||||||||||||||||
End of 2007 | - | - | - | - | - | - | 39 | 20 | - | - | 59 | |||||||||||||||||||||||||||||||||
Developed | ||||||||||||||||||||||||||||||||||||||||||||
Consolidated operations | ||||||||||||||||||||||||||||||||||||||||||||
End of 2004 | 153 | 82 | 235 | 25 | 34 | 71 | 4 | - | - | 369 | - | |||||||||||||||||||||||||||||||||
End of 2005 | 146 | 106 | 252 | 23 | 31 | 64 | 2 | - | - | 372 | - | |||||||||||||||||||||||||||||||||
End of 2006 | 139 | 346 | 485 | 64 | 28 | 56 | 2 | - | - | 635 | - | |||||||||||||||||||||||||||||||||
End of 2007 | 133 | 343 | 476 | 53 | 33 | 54 | 1 | - | - | 617 | - | |||||||||||||||||||||||||||||||||
Equity affiliates | ||||||||||||||||||||||||||||||||||||||||||||
End of 2004 | - | - | - | - | - | - | - | - | - | - | - | |||||||||||||||||||||||||||||||||
End of 2005 | - | - | - | - | - | - | - | - | - | - | - | |||||||||||||||||||||||||||||||||
End of 2006 | - | - | - | - | - | - | - | - | - | - | - | |||||||||||||||||||||||||||||||||
End of 2007 | - | - | - | - | - | - | - | 18 | - | - | 18 | |||||||||||||||||||||||||||||||||
• | Purchases: In 2006 for our consolidated operations, purchases were related to our acquisition of Burlington Resources. |
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n | Results of Operations |
Year Ended | Millions of Dollars | |||||||||||||||||||||||||||||||||||||||||||
December 31 | Consolidated Operations | |||||||||||||||||||||||||||||||||||||||||||
Lower | Total | Asia | Middle East | Russia and | Other | Equity | ||||||||||||||||||||||||||||||||||||||
Alaska | 48 | U.S. | Canada | Europe | Pacific | and Africa | Caspian | Areas | Total | Affiliates | ||||||||||||||||||||||||||||||||||
2007 | ||||||||||||||||||||||||||||||||||||||||||||
Sales | $ | 4,659 | 5,422 | 10,081 | 3,406 | 5,701 | 3,383 | 1,038 | - | 240 | 23,849 | 5,212 | ||||||||||||||||||||||||||||||||
Transfers | 2,344 | 2,986 | 5,330 | - | 2,729 | 267 | 1,157 | - | - | 9,483 | 3,427 | |||||||||||||||||||||||||||||||||
Other revenues | 173 | 94 | 267 | 430 | 330 | 252 | 201 | 1 | 3 | 1,484 | 71 | |||||||||||||||||||||||||||||||||
Total revenues | 7,176 | 8,502 | 15,678 | 3,836 | 8,760 | 3,902 | 2,396 | 1 | 243 | 34,816 | 8,710 | |||||||||||||||||||||||||||||||||
Production costs excluding taxes | 775 | 1,232 | 2,007 | 874 | 1,029 | 410 | 251 | - | 41 | 4,612 | 906 | |||||||||||||||||||||||||||||||||
Taxes other than income taxes | 1,663 | 628 | 2,291 | 70 | 45 | 129 | 18 | 2 | 98 | 2,653 | 3,675 | |||||||||||||||||||||||||||||||||
Exploration expenses | 104 | 318 | 422 | 247 | 105 | 130 | 77 | 24 | 12 | 1,017 | 68 | |||||||||||||||||||||||||||||||||
Depreciation, depletion and amortization | 583 | 2,559 | 3,142 | 1,661 | 1,394 | 608 | 204 | - | - | 7,009 | 551 | |||||||||||||||||||||||||||||||||
Impairment— expropriated assets | - | - | - | - | - | - | - | - | 4,588 | 4,588 | - | |||||||||||||||||||||||||||||||||
Property impairments | 28 | 43 | 71 | 27 | 188 | 26 | - | - | 155 | 467 | - | |||||||||||||||||||||||||||||||||
Transportation costs | 412 | 553 | 965 | 137 | 335 | 101 | 24 | - | 64 | 1,626 | 770 | |||||||||||||||||||||||||||||||||
Other related expenses | (64 | ) | 72 | 8 | (96 | ) | 46 | (26 | ) | 34 | 56 | 37 | 59 | 57 | ||||||||||||||||||||||||||||||
Accretion | 37 | 48 | 85 | 47 | 132 | 9 | 3 | 1 | - | 277 | 7 | |||||||||||||||||||||||||||||||||
3,638 | 3,049 | 6,687 | 869 | 5,486 | 2,515 | 1,785 | (82 | ) | (4,752 | ) | 12,508 | 2,676 | ||||||||||||||||||||||||||||||||
Provision for income taxes | 1,248 | 1,091 | 2,339 | 237 | 3,595 | 982 | 1,545 | (28 | ) | 1 | 8,671 | 844 | ||||||||||||||||||||||||||||||||
Results of operations for producing activities | 2,390 | 1,958 | 4,348 | 632 | 1,891 | 1,533 | 240 | (54 | ) | (4,753 | ) | 3,837 | 1,832 | |||||||||||||||||||||||||||||||
Other earnings | (135 | ) | 35 | (100 | ) | 280 | 48 | 67 | 25 | 33 | 197 | 550 | 214 | |||||||||||||||||||||||||||||||
Net income (loss) | $ | 2,255 | 1,993 | 4,248 | 912 | 1,939 | 1,600 | 265 | (21 | ) | (4,556 | ) | 4,387 | 2,046 | ||||||||||||||||||||||||||||||
Results of operations for producing activities of equity affiliates | $ | - | - | - | 98 | - | - | (5 | ) | 1,554 | 185 | - | 1,832 | |||||||||||||||||||||||||||||||
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Year Ended | Millions of Dollars | |||||||||||||||||||||||||||||||||||||||||||
December 31 | Consolidated Operations | |||||||||||||||||||||||||||||||||||||||||||
Lower | Total | Asia | Middle East | Russia and | Other | Equity | ||||||||||||||||||||||||||||||||||||||
Alaska | 48 | U.S. | Canada | Europe | Pacific | and Africa | Caspian | Areas | Total | Affiliates | ||||||||||||||||||||||||||||||||||
2006 | ||||||||||||||||||||||||||||||||||||||||||||
Sales* | $ | 4,491 | 4,881 | 9,372 | 2,951 | 5,950 | 3,493 | 1,743 | - | 140 | 23,649 | 5,161 | ||||||||||||||||||||||||||||||||
Transfers* | 2,023 | 2,550 | 4,573 | - | 2,954 | 271 | 764 | - | - | 8,562 | 2,821 | |||||||||||||||||||||||||||||||||
Other revenues | 2 | 56 | 58 | 145 | 14 | (8 | ) | 127 | - | 4 | 340 | 108 | ||||||||||||||||||||||||||||||||
Total revenues | 6,516 | 7,487 | 14,003 | 3,096 | 8,918 | 3,756 | 2,634 | - | 144 | 32,551 | 8,090 | |||||||||||||||||||||||||||||||||
Production costs excluding taxes | 708 | 893 | 1,601 | 706 | 814 | 324 | 215 | - | 27 | 3,687 | 739 | |||||||||||||||||||||||||||||||||
Taxes other than income taxes | 914 | 554 | 1,468 | 52 | 37 | 91 | 10 | 1 | 30 | 1,689 | 3,444 | |||||||||||||||||||||||||||||||||
Exploration expenses | 105 | 222 | 327 | 246 | 73 | 121 | 44 | 32 | 17 | 860 | 46 | |||||||||||||||||||||||||||||||||
Depreciation, depletion and amortization | 460 | 2,272 | 2,732 | 1,155 | 1,200 | 512 | 220 | 1 | 21 | 5,841 | 461 | |||||||||||||||||||||||||||||||||
Property impairments | - | 15 | 15 | 131 | - | 10 | - | - | 19 | 175 | - | |||||||||||||||||||||||||||||||||
Transportation costs | 610 | 555 | 1,165 | 104 | 316 | 89 | 18 | - | 10 | 1,702 | 420 | |||||||||||||||||||||||||||||||||
Other related expenses | 11 | 44 | 55 | 15 | 87 | 18 | 38 | 43 | 28 | 284 | 52 | |||||||||||||||||||||||||||||||||
Accretion | 34 | 36 | 70 | 39 | 97 | 8 | 2 | - | - | 216 | 6 | |||||||||||||||||||||||||||||||||
3,674 | 2,896 | 6,570 | 648 | 6,294 | 2,583 | 2,087 | (77 | ) | (8 | ) | 18,097 | 2,922 | ||||||||||||||||||||||||||||||||
Provision for income taxes | 1,409 | 1,064 | 2,473 | (193 | ) | 4,578 | 1,061 | 1,931 | (13 | ) | (7 | ) | 9,830 | 891 | ||||||||||||||||||||||||||||||
Results of operations for producing activities | 2,265 | 1,832 | 4,097 | 841 | 1,716 | 1,522 | 156 | (64 | ) | (1 | ) | 8,267 | 2,031 | |||||||||||||||||||||||||||||||
Other earnings | 82 | ** | 169 | ** | 251 | 191 | 335 | 62 | 32 | (4 | ) | (25 | ) | 842 | 133 | |||||||||||||||||||||||||||||
Net income (loss) | $ | 2,347 | ** | 2,001 | ** | 4,348 | 1,032 | 2,051 | 1,584 | 188 | (68 | ) | (26 | ) | 9,109 | 2,164 | ||||||||||||||||||||||||||||
Results of operations for producing activities of equity affiliates | $ | - | - | - | - | - | - | (6 | ) | 1,229 | 808 | - | 2,031 | |||||||||||||||||||||||||||||||
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Year Ended | Millions of Dollars | |||||||||||||||||||||||||||||||||||||||||||
December 31 | Consolidated Operations | |||||||||||||||||||||||||||||||||||||||||||
Lower | Total | Asia | Middle East | Russia and | Other | Equity | ||||||||||||||||||||||||||||||||||||||
Alaska | 48 | U.S. | Canada | Europe | Pacific | and Africa | Caspian | Areas | Total | Affiliates | ||||||||||||||||||||||||||||||||||
2005 | ||||||||||||||||||||||||||||||||||||||||||||
Sales* | $ | 4,102 | 3,385 | 7,487 | 1,642 | 5,142 | 2,795 | 423 | - | - | 17,489 | 3,470 | ||||||||||||||||||||||||||||||||
Transfers* | 1,997 | 1,206 | 3,203 | - | 2,207 | 26 | 640 | - | - | 6,076 | 1,458 | |||||||||||||||||||||||||||||||||
Other revenues | 2 | 168 | 170 | 40 | (253 | ) | 11 | 4 | - | - | (28 | ) | 38 | |||||||||||||||||||||||||||||||
Total revenues | 6,101 | 4,759 | 10,860 | 1,682 | 7,096 | 2,832 | 1,067 | - | - | 23,537 | 4,966 | |||||||||||||||||||||||||||||||||
Production costs excluding taxes | 488 | 492 | 980 | 316 | 612 | 274 | 115 | - | - | 2,297 | 452 | |||||||||||||||||||||||||||||||||
Taxes other than income taxes | 537 | 311 | 848 | 33 | 41 | 26 | 18 | 1 | 1 | 968 | 1,635 | |||||||||||||||||||||||||||||||||
Exploration expenses | 120 | 66 | 186 | 147 | 87 | 139 | 69 | 33 | 8 | 669 | 56 | |||||||||||||||||||||||||||||||||
Depreciation, depletion and amortization | 443 | 848 | 1,291 | 399 | 1,074 | 329 | 53 | - | - | 3,146 | 288 | |||||||||||||||||||||||||||||||||
Property impairments | - | 1 | 1 | 13 | (10 | ) | - | - | - | - | 4 | - | ||||||||||||||||||||||||||||||||
Transportation costs | 665 | 350 | 1,015 | 53 | 296 | 64 | 5 | - | - | 1,433 | 255 | |||||||||||||||||||||||||||||||||
Other related expenses | 67 | 48 | 115 | (12 | ) | 28 | 38 | 32 | 35 | 17 | 253 | 26 | ||||||||||||||||||||||||||||||||
Accretion | 29 | 19 | 48 | 16 | 84 | 7 | 2 | - | - | 157 | 1 | |||||||||||||||||||||||||||||||||
3,752 | 2,624 | 6,376 | 717 | 4,884 | 1,955 | 773 | (69 | ) | (26 | ) | 14,610 | 2,253 | ||||||||||||||||||||||||||||||||
Provision for income taxes | 1,342 | 900 | 2,242 | 228 | 3,311 | 747 | 759 | (6 | ) | (13 | ) | 7,268 | 673 | |||||||||||||||||||||||||||||||
Results of operations for producing activities | 2,410 | 1,724 | 4,134 | 489 | 1,573 | 1,208 | 14 | (63 | ) | (13 | ) | 7,342 | 1,580 | |||||||||||||||||||||||||||||||
Other earnings | 141 | 15 | 156 | 93 | 64 | 7 | (28 | ) | (2 | ) | 26 | 316 | (90 | ) | ||||||||||||||||||||||||||||||
Cumulative effect of accounting change | 1 | (3 | ) | (2 | ) | - | (2 | ) | - | - | - | - | (4 | ) | - | |||||||||||||||||||||||||||||
Net income (loss) | $ | 2,552 | 1,736 | 4,288 | 582 | 1,635 | 1,215 | (14 | ) | (65 | ) | 13 | 7,654 | 1,490 | ||||||||||||||||||||||||||||||
Results of operations for producing activities of equity affiliates | $ | - | - | - | - | - | - | (11 | ) | 773 | 818 | - | 1,580 | |||||||||||||||||||||||||||||||
n | Results of operations for producing activities consist of all the activities within the E&P organization and producing activities within the LUKOIL Investment segment, except for pipeline and marine operations, liquefied natural gas operations, a Canadian Syncrude operation, and crude oil and gas marketing activities, which are included in other earnings. Also excluded are our Midstream segment, downstream petroleum and chemical activities, as well as general corporate administrative expenses and interest. | |
n | Transfers are valued at prices that approximate market. | |
n | Other revenues include gains and losses from asset sales, certain amounts resulting from the purchase and sale of hydrocarbons, and other miscellaneous income. Also included in 2005 were losses of approximately $282 million for the mark-to-market valuation of certain U.K. gas contracts. | |
n | Production costs are those incurred to operate and maintain wells and related equipment and facilities used to produce petroleum liquids and natural gas. These costs also include depreciation of support equipment and administrative expenses related to the production activity. | |
n | Taxes other than income taxes include production, property and other non-income taxes. |
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n | Exploration expenses include dry hole, leasehold impairment, geological and geophysical expenses, the cost of retaining undeveloped leaseholds, and depreciation of support equipment and administrative expenses related to the exploration activity. | |
n | Depreciation, depletion and amortization (DD&A) in Results of Operations differs from that shown for total E&P in Note 29—Segment Disclosures and Related Information, in the Notes to Consolidated Financial Statements, mainly due to depreciation of support equipment being reclassified to production or exploration expenses, as applicable, in Results of Operations. In addition, other earnings include certain E&P activities, including their related DD&A charges. | |
n | Transportation costs include costs to transport our produced oil, natural gas or natural gas liquids to their points of sale, as well as processing fees paid to process natural gas to natural gas liquids. The profit element of transportation operations in which we have an ownership interest are deemed to be outside the oil and gas producing activity. The net income of the transportation operations is included in other earnings. | |
n | Other related expenses include foreign currency gains and losses, and other miscellaneous expenses. | |
n | The provision for income taxes is computed by adjusting each country’s income before income taxes for permanent differences related to the oil and gas producing activities that are reflected in our consolidated income tax expense for the period, multiplying the result by the country’s statutory tax rate and adjusting for applicable tax credits. Included in 2007 for Canada is a benefit related to the remeasurement of deferred tax liabilities from the 2007 Canadian graduated tax rate reduction. Included in 2006 for Canada is a $353 million benefit (which excludes $48 million related to the Syncrude oil project reflected in other earnings) related to the remeasurement of deferred tax liabilities from the 2006 Canadian graduated tax rate reduction and an Alberta provincial tax rate change. Europe income tax expense for 2006 was increased $250 million due to remeasurement of deferred tax liabilities as a result of increases in the U.K. tax rate. |
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n | Statistics |
Net Production | 2007 | 2006 | 2005 | |||||||||
Thousands of Barrels Daily | ||||||||||||
Crude Oil | ||||||||||||
Consolidated operations | ||||||||||||
Alaska | 261 | 263 | 294 | |||||||||
Lower 48 | 102 | 104 | 59 | |||||||||
United States | 363 | 367 | 353 | |||||||||
Canada | 19 | 25 | 23 | |||||||||
Europe | 210 | 245 | 257 | |||||||||
Asia Pacific | 87 | 106 | 100 | |||||||||
Middle East and Africa | 81 | 106 | 53 | |||||||||
Other areas | 10 | 7 | - | |||||||||
Total consolidated | 770 | 856 | 786 | |||||||||
Equity affiliates | ||||||||||||
Canada | 27 | - | - | |||||||||
Russia and Caspian | 416 | 375 | 250 | |||||||||
Other areas | 42 | 101 | 106 | |||||||||
Total equity affiliates | 485 | 476 | 356 | |||||||||
Natural Gas Liquids* | ||||||||||||
Consolidated operations | ||||||||||||
Alaska | 19 | 17 | 20 | |||||||||
Lower 48 | 79 | 62 | 30 | |||||||||
United States | 98 | 79 | 50 | |||||||||
Canada | 27 | 25 | 10 | |||||||||
Europe | 14 | 13 | 13 | |||||||||
Asia Pacific | 14 | 18 | 16 | |||||||||
Middle East and Africa | 2 | 1 | 2 | |||||||||
Total consolidated | 155 | 136 | 91 | |||||||||
Millions of Cubic Feet Daily | ||||||||||||
Natural Gas* | ||||||||||||
Consolidated operations | ||||||||||||
Alaska | 110 | 145 | 169 | |||||||||
Lower 48 | 2,182 | 2,028 | 1,212 | |||||||||
United States | 2,292 | 2,173 | 1,381 | |||||||||
Canada | 1,106 | 983 | 425 | |||||||||
Europe | 961 | 1,065 | 1,023 | |||||||||
Asia Pacific | 579 | 582 | 350 | |||||||||
Middle East and Africa | 125 | 142 | 84 | |||||||||
Other areas | 19 | 16 | - | |||||||||
Total consolidated | 5,082 | 4,961 | 3,263 | |||||||||
Equity affiliates | ||||||||||||
Russia and Caspian | 256 | 244 | 67 | |||||||||
Other areas | 5 | 9 | 7 | |||||||||
Total equity affiliates | 261 | 253 | 74 | |||||||||
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Average Sales Price | 2007 | 2006 | 2005 | |||||||||
Crude Oil Per Barrel | ||||||||||||
Consolidated operations | ||||||||||||
Alaska | $ | 69.75 | 62.66 | 52.24 | ||||||||
Lower 48 | 63.49 | 57.04 | 45.24 | |||||||||
United States | 68.00 | 61.09 | 51.09 | |||||||||
Canada | 61.77 | 54.25 | 44.70 | |||||||||
Europe | 71.81 | 64.05 | 53.16 | |||||||||
Asia Pacific | 70.23 | 61.93 | 51.34 | |||||||||
Middle East and Africa | 72.18 | 66.59 | 52.93 | |||||||||
Other areas | 60.84 | 50.63 | - | |||||||||
Total international | 70.79 | 63.38 | 52.27 | |||||||||
Total consolidated | 69.47 | 62.39 | 51.74 | |||||||||
Equity affiliates | ||||||||||||
Canada | 37.94 | - | - | |||||||||
Russia and Caspian | 50.00 | 41.61 | 37.39 | |||||||||
Other areas | 47.46 | 46.40 | 38.08 | |||||||||
Total equity affiliates | 49.13 | 42.66 | 37.60 | |||||||||
Natural Gas Liquids Per Barrel | ||||||||||||
Consolidated operations | ||||||||||||
Alaska | $ | 71.85 | 61.06 | 51.30 | ||||||||
Lower 48 | 44.43 | 38.10 | 36.43 | |||||||||
United States | 46.00 | 40.35 | 40.40 | |||||||||
Canada | 50.85 | 45.62 | 42.20 | |||||||||
Europe | 45.72 | 38.78 | 31.25 | |||||||||
Asia Pacific | 53.19 | 43.95 | 40.11 | |||||||||
Middle East and Africa | 8.31 | 8.15 | 7.39 | |||||||||
Total international | 48.80 | 42.89 | 36.25 | |||||||||
Total consolidated | 47.13 | 41.50 | 38.32 | |||||||||
Natural Gas Per Thousand Cubic Feet | ||||||||||||
Consolidated operations | ||||||||||||
Alaska | $ | 3.68 | 3.59 | 2.75 | ||||||||
Lower 48 | 5.99 | 6.14 | 7.28 | |||||||||
United States | 5.98 | 6.11 | 7.12 | |||||||||
Canada | 6.09 | 5.67 | 7.25 | |||||||||
Europe | 7.87 | 7.78 | 5.77 | |||||||||
Asia Pacific | 6.37 | 5.91 | 5.24 | |||||||||
Middle East and Africa | .80 | .70 | .67 | |||||||||
Other areas | 1.18 | 1.31 | - | |||||||||
Total international | 6.51 | 6.27 | 5.78 | |||||||||
Total consolidated | 6.26 | 6.20 | 6.32 | |||||||||
Equity affiliates | ||||||||||||
Russia and Caspian | 1.02 | .57 | .48 | |||||||||
Other areas | .30 | .30 | .26 | |||||||||
Total equity affiliates | 1.01 | .57 | .46 | |||||||||
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2007 | 2006 | 2005 | ||||||||||
Average Production Costs Per Barrel of Oil Equivalent | ||||||||||||
Consolidated operations | ||||||||||||
Alaska | $ | 7.12 | 6.38 | 3.91 | ||||||||
Lower 48 | 6.20 | 4.85 | 4.63 | |||||||||
United States | 6.52 | 5.43 | 4.24 | |||||||||
Canada | 10.40 | 9.05 | 8.34 | |||||||||
Europe | 7.34 | 5.12 | 3.81 | |||||||||
Asia Pacific | 5.69 | 4.02 | 4.31 | |||||||||
Middle East and Africa | 6.62 | 4.51 | 4.57 | |||||||||
Other areas | 8.53 | 7.65 | - | |||||||||
Total international | 7.68 | 5.65 | 4.58 | |||||||||
Total consolidated | 7.13 | 5.55 | 4.43 | |||||||||
Equity affiliates | ||||||||||||
Canada | 13.32 | - | - | |||||||||
Russia and Caspian | 4.04 | 3.53 | 2.69 | |||||||||
Other areas | 6.24 | 5.42 | 5.01 | |||||||||
Total equity affiliates | 4.70 | 3.91 | 3.36 | |||||||||
Taxes Other Than Income Taxes Per Barrel of Oil Equivalent | ||||||||||||
Consolidated operations Alaska | $ | 15.27 | 8.23 | 4.30 | ||||||||
Lower 48 | 3.16 | 3.01 | 2.93 | |||||||||
United States | 7.45 | 4.98 | 3.67 | |||||||||
Canada | .83 | .67 | .87 | |||||||||
Europe | .32 | .23 | .26 | |||||||||
Asia Pacific | 1.79 | 1.13 | .41 | |||||||||
Middle East and Africa | .47 | .21 | .71 | |||||||||
Other areas | 20.39 | 8.50 | - | |||||||||
Total international | 1.07 | .60 | .42 | |||||||||
Total consolidated | 4.10 | 2.54 | 1.87 | |||||||||
Equity affiliates | ||||||||||||
Canada | .21 | - | - | |||||||||
Russia and Caspian | 20.89 | 21.40 | 17.12 | |||||||||
Other areas | 11.21 | 5.28 | .06 | |||||||||
Total equity affiliates | 19.05 | 18.21 | 12.16 | |||||||||
Depreciation, Depletion and Amortization | ||||||||||||
Per Barrel of Oil Equivalent | ||||||||||||
Consolidated operations | ||||||||||||
Alaska | $ | 5.35 | 4.14 | 3.55 | ||||||||
Lower 48 | 12.87 | 12.35 | 7.98 | |||||||||
United States | 10.21 | 9.26 | 5.59 | |||||||||
Canada | 19.76 | 14.80 | 10.53 | |||||||||
Europe | 9.94 | 7.55 | 6.68 | |||||||||
Asia Pacific | 8.43 | 6.35 | 5.17 | |||||||||
Middle East and Africa | 5.38 | 4.61 | 2.10 | |||||||||
Other areas | - | 5.95 | - | |||||||||
Total international | 11.40 | 8.43 | 6.45 | |||||||||
Total consolidated | 10.84 | 8.80 | 6.07 | |||||||||
Equity affiliates | ||||||||||||
Canada | 6.82 | - | - | |||||||||
Russia and Caspian | 2.53 | 2.04 | 1.55 | |||||||||
Other areas | 3.88 | 4.04 | 3.58 | |||||||||
Total equity affiliates | 2.86 | 2.43 | 2.14 | |||||||||
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Net Wells Completed(1) | Productive | Dry | ||||||||||||||||||||||
2007 | 2006 | 2005 | 2007 | 2006 | 2005 | |||||||||||||||||||
Exploratory(2) | ||||||||||||||||||||||||
Consolidated operations | ||||||||||||||||||||||||
Alaska | 3 | - | - | 1 | 1 | 5 | ||||||||||||||||||
Lower 48 | 71 | 27 | 23 | 9 | 9 | 5 | ||||||||||||||||||
United States | 74 | 27 | 23 | 10 | 10 | 10 | ||||||||||||||||||
Canada | 50 | 8 | 26 | 17 | 7 | 7 | ||||||||||||||||||
Europe | 1 | 1 | 1 | 1 | 1 | * | ||||||||||||||||||
Asia Pacific | 4 | 2 | 7 | 1 | 2 | 3 | ||||||||||||||||||
Middle East and Africa | - | 1 | - | 1 | 1 | 2 | ||||||||||||||||||
Russia and Caspian | - | - | - | * | - | * | ||||||||||||||||||
Other areas | - | 1 | 1 | - | * | - | ||||||||||||||||||
Total consolidated | 129 | 40 | 58 | 30 | 21 | 22 | ||||||||||||||||||
Equity affiliates | ||||||||||||||||||||||||
Canada | - | - | - | - | - | - | ||||||||||||||||||
Middle East and Africa | - | * | * | - | - | - | ||||||||||||||||||
Russia and Caspian | - | - | - | - | 1 | - | ||||||||||||||||||
Other areas | - | - | - | - | - | - | ||||||||||||||||||
Total equity affiliates(3) | - | * | * | - | 1 | - | ||||||||||||||||||
Includes step-out wells of: | 99 | 37 | 42 | 18 | 11 | 7 |
Productive | Dry | |||||||||||||||||||||||
2007 | 2006 | 2005 | 2007 | 2006 | 2005 | |||||||||||||||||||
Development | ||||||||||||||||||||||||
Consolidated operations | ||||||||||||||||||||||||
Alaska | 46 | 30 | 31 | - | 1 | - | ||||||||||||||||||
Lower 48 | 686 | 659 | 297 | 7 | 3 | 9 | ||||||||||||||||||
United States | 732 | 689 | 328 | 7 | 4 | 9 | ||||||||||||||||||
Canada | 348 | 675 | 425 | 1 | 8 | 2 | ||||||||||||||||||
Europe | 10 | 10 | 19 | - | - | - | ||||||||||||||||||
Asia Pacific | 17 | 15 | 17 | - | - | - | ||||||||||||||||||
Middle East and Africa | 7 | 7 | 6 | * | - | - | ||||||||||||||||||
Russia and Caspian | * | * | - | - | - | - | ||||||||||||||||||
Other areas | 5 | 11 | - | - | - | - | ||||||||||||||||||
Total consolidated | 1,119 | 1,407 | 795 | 8 | 12 | 11 | ||||||||||||||||||
Equity affiliates | ||||||||||||||||||||||||
Canada | 70 | - | - | 1 | - | - | ||||||||||||||||||
Middle East and Africa | - | - | - | - | - | - | ||||||||||||||||||
Russia and Caspian | 2 | 2 | 1 | - | 1 | - | ||||||||||||||||||
Other areas | - | 15 | 28 | - | - | 1 | ||||||||||||||||||
Total equity affiliates(3) | 72 | 17 | 29 | 1 | 1 | 1 | ||||||||||||||||||
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Wells at Year-End 2007 | Productive(2) | |||||||||||||||||||||||
In Progress(1) | Oil | Gas | ||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
Consolidated operations | ||||||||||||||||||||||||
Alaska | 22 | 12 | 1,790 | 810 | 27 | 18 | ||||||||||||||||||
Lower 48 | 280 | 233 | 12,498 | 4,595 | 24,742 | 16,135 | ||||||||||||||||||
United States | 302 | 245 | 14,288 | 5,405 | 24,769 | 16,153 | ||||||||||||||||||
Canada | 147 | (3) | 87 | (3) | 1,648 | 913 | 10,773 | 6,412 | ||||||||||||||||
Europe | 59 | 11 | 556 | 99 | 344 | 118 | ||||||||||||||||||
Asia Pacific | 168 | 79 | 335 | 124 | 95 | 58 | ||||||||||||||||||
Middle East and Africa | 31 | 5 | 1,000 | 177 | - | - | ||||||||||||||||||
Russia and Caspian | 25 | 2 | - | - | - | - | ||||||||||||||||||
Other areas | 5 | 2 | 100 | 44 | 50 | 13 | ||||||||||||||||||
Total consolidated | 737 | 431 | 17,927 | 6,762 | 36,031 | 22,754 | ||||||||||||||||||
Equity affiliates | ||||||||||||||||||||||||
Canada | 8 | 4 | 93 | 47 | 6 | 3 | ||||||||||||||||||
Russia and Caspian | 28 | 9 | 69 | 25 | - | - | ||||||||||||||||||
Other areas | 31 | 5 | - | - | - | - | ||||||||||||||||||
Total equity affiliates(4) | 67 | 18 | 162 | 72 | 6 | 3 | ||||||||||||||||||
(1) | Includes wells that have been temporarily suspended. |
(2) | Includes 5,479 gross and 3,450 net multiple completion wells. |
(3) | Includes 93 gross and 47 net stratigraphic test wells related to the Surmont heavy-oil project. |
(4) | Excludes LUKOIL. |
Acreage at December 31, 2007 | Thousands of Acres | |||||||||||||||
Developed | Undeveloped | |||||||||||||||
Gross | Net | Gross | Net | |||||||||||||
Consolidated operations | ||||||||||||||||
Alaska | 646 | 327 | 2,475 | 1,572 | ||||||||||||
Lower 48 | 7,666 | 5,301 | 13,965 | 9,917 | ||||||||||||
United States | 8,312 | 5,628 | 16,440 | 11,489 | ||||||||||||
Canada | 7,002 | 4,328 | 14,074 | 9,292 | ||||||||||||
Europe | 1,373 | 342 | 4,454 | 1,429 | ||||||||||||
Asia Pacific | 4,214 | 1,818 | 28,367 | 18,588 | ||||||||||||
Middle East and Africa | 2,466 | 449 | 13,395 | 2,694 | ||||||||||||
Russia and Caspian | - | - | 1,379 | 128 | ||||||||||||
Other areas | 1,356 | 573 | 13,071 | 10,444 | ||||||||||||
Total consolidated | 24,723 | 13,138 | 91,180 | 54,064 | ||||||||||||
Equity affiliates | ||||||||||||||||
Canada | 57 | 23 | 483 | 186 | ||||||||||||
Middle East and Africa | - | - | 76 | 11 | ||||||||||||
Russia and Caspian | 385 | 119 | 2,898 | 994 | ||||||||||||
Other areas | - | - | - | - | ||||||||||||
Total equity affiliates* | 442 | 142 | 3,457 | 1,191 | ||||||||||||
* | Excludes LUKOIL. |
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n | Costs Incurred |
Millions of Dollars | ||||||||||||||||||||||||||||||||||||||||||||
Consolidated Operations | ||||||||||||||||||||||||||||||||||||||||||||
Lower | Total | Asia | Middle East | Russia and | Other | Equity | ||||||||||||||||||||||||||||||||||||||
Alaska | 48 | U.S. | Canada | Europe | Pacific | and Africa | Caspian | Areas | Total | Affiliates | ||||||||||||||||||||||||||||||||||
2007 | ||||||||||||||||||||||||||||||||||||||||||||
Unproved property acquisition | $ | 5 | 202 | 207 | 117 | - | 122 | - | - | - | 446 | 2,030 | ||||||||||||||||||||||||||||||||
Proved property acquisition | - | 42 | 42 | - | - | - | 2 | - | - | 44 | 1,729 | |||||||||||||||||||||||||||||||||
5 | 244 | 249 | 117 | - | 122 | 2 | - | - | 490 | 3,759 | ||||||||||||||||||||||||||||||||||
Exploration | 115 | 468 | 583 | 196 | 235 | 147 | 73 | 37 | 21 | 1,292 | 78 | |||||||||||||||||||||||||||||||||
Development | 567 | 2,375 | 2,942 | 1,252 | 1,871 | 1,275 | 404 | 462 | 73 | 8,279 | 2,394 | |||||||||||||||||||||||||||||||||
$ | 687 | 3,087 | 3,774 | 1,565 | 2,106 | 1,544 | 479 | 499 | 94 | 10,061 | 6,231 | |||||||||||||||||||||||||||||||||
Costs incurred of equity affiliates | - | - | - | 4,117 | - | - | 314 | 1,749 | 51 | - | 6,231 | |||||||||||||||||||||||||||||||||
2006 | ||||||||||||||||||||||||||||||||||||||||||||
Unproved property acquisition | $ | 4 | 860 | 864 | 554 | 113 | - | 30 | - | 39 | 1,600 | 143 | ||||||||||||||||||||||||||||||||
Proved property acquisition | 13 | 15,784 | 15,797 | 8,296 | 1,169 | 525 | 856 | - | 252 | 26,895 | 2,647 | |||||||||||||||||||||||||||||||||
17 | 16,644 | 16,661 | 8,850 | 1,282 | 525 | 886 | - | 291 | 28,495 | 2,790 | ||||||||||||||||||||||||||||||||||
Exploration | 131 | 332 | 463 | 182 | 172 | 231 | 57 | 47 | 27 | 1,179 | 58 | |||||||||||||||||||||||||||||||||
Development | 629 | 1,733 | 2,362 | 1,926 | 1,653 | 919 | 249 | 371 | 141 | 7,621 | 1,326 | |||||||||||||||||||||||||||||||||
$ | 777 | 18,709 | 19,486 | 10,958 | 3,107 | 1,675 | 1,192 | 418 | 459 | 37,295 | 4,174 | |||||||||||||||||||||||||||||||||
Costs incurred of equity affiliates | $ | - | - | - | - | - | - | 183 | 3,854 | 137 | - | 4,174 | ||||||||||||||||||||||||||||||||
2005 | ||||||||||||||||||||||||||||||||||||||||||||
Unproved property acquisition | $ | 1 | 14 | 15 | 68 | - | 26 | 85 | 83 | - | 277 | 796 | ||||||||||||||||||||||||||||||||
Proved property acquisition | 16 | 767 | 783 | - | - | 6 | 569 | 125 | - | 1,483 | 1,763 | |||||||||||||||||||||||||||||||||
17 | 781 | 798 | 68 | - | 32 | 654 | 208 | - | 1,760 | 2,559 | ||||||||||||||||||||||||||||||||||
Exploration | 64 | 74 | 138 | 163 | 117 | 204 | 67 | 37 | 11 | 737 | 60 | |||||||||||||||||||||||||||||||||
Development | 650 | 688 | 1,338 | 782 | 1,402 | 682 | 137 | 372 | 42 | 4,755 | 449 | |||||||||||||||||||||||||||||||||
$ | 731 | 1,543 | 2,274 | 1,013 | 1,519 | 918 | 858 | 617 | 53 | 7,252 | 3,068 | |||||||||||||||||||||||||||||||||
Costs incurred of equity affiliates | $ | - | - | - | - | - | - | 54 | 2,903 | 111 | - | 3,068 | ||||||||||||||||||||||||||||||||
n | Costs incurred include capitalized and expensed items. |
n | Acquisition costs include the costs of acquiring proved and unproved oil and gas properties. In 2007, equity affiliate acquisition costs were due to the EnCana business venture. In 2006 in our consolidated operations, acquisition costs were primarily related to the Burlington Resources acquisition. |
n | Exploration costs include geological and geophysical expenses, the cost of retaining undeveloped leaseholds, and exploratory drilling costs. |
n | Development costs include the cost of drilling and equipping development wells and building related production facilities for extracting, treating, gathering and storing petroleum liquids and natural gas. |
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n | Capitalized Costs |
At December 31 | Millions of Dollars | |||||||||||||||||||||||||||||||||||||||||||
Consolidated Operations | ||||||||||||||||||||||||||||||||||||||||||||
Lower | Total | Asia | Middle East | Russia and | Other | Equity | ||||||||||||||||||||||||||||||||||||||
Alaska | 48 | U.S. | Canada | Europe | Pacific | and Africa | Caspian | Areas | Total | Affiliates | ||||||||||||||||||||||||||||||||||
2007 | ||||||||||||||||||||||||||||||||||||||||||||
Proved properties | $ | 10,182 | 28,645 | 38,827 | 17,330 | 20,615 | 8,014 | 2,758 | 2,135 | 641 | 90,320 | 12,491 | ||||||||||||||||||||||||||||||||
Unproved properties | 848 | 1,137 | 1,985 | 1,798 | 446 | 795 | 281 | 131 | 83 | 5,519 | 3,360 | |||||||||||||||||||||||||||||||||
11,030 | 29,782 | 40,812 | 19,128 | 21,061 | 8,809 | 3,039 | 2,266 | 724 | 95,839 | 15,851 | ||||||||||||||||||||||||||||||||||
Accumulated depreciation, depletion and amortization | 4,158 | 7,920 | 12,078 | 4,875 | 9,374 | 2,155 | 822 | 4 | 504 | 29,812 | 1,008 | |||||||||||||||||||||||||||||||||
$ | 6,872 | 21,862 | 28,734 | 14,253 | 11,687 | 6,654 | 2,217 | 2,262 | 220 | 66,027 | 14,843 | |||||||||||||||||||||||||||||||||
Capitalized costs of equity affiliates | $ | - | - | - | 4,771 | - | - | 606 | 9,466 | - | - | 14,843 | ||||||||||||||||||||||||||||||||
2006 | ||||||||||||||||||||||||||||||||||||||||||||
Proved properties | $ | 9,567 | 26,227 | 35,794 | 14,455 | 17,773 | 6,870 | 2,577 | 1,669 | 633 | 79,771 | 11,550 | ||||||||||||||||||||||||||||||||
Unproved properties | 840 | 1,045 | 1,885 | 1,425 | 365 | 743 | 321 | 117 | 72 | 4,928 | 944 | |||||||||||||||||||||||||||||||||
10,407 | 27,272 | 37,679 | 15,880 | 18,138 | 7,613 | 2,898 | 1,786 | 705 | 84,699 | 12,494 | ||||||||||||||||||||||||||||||||||
Accumulated depreciation, depletion and amortization | 3,573 | 5,525 | 9,098 | 2,795 | 7,450 | 1,581 | 737 | 3 | 81 | 21,745 | 933 | |||||||||||||||||||||||||||||||||
$ | 6,834 | 21,747 | 28,581 | 13,085 | 10,688 | 6,032 | 2,161 | 1,783 | 624 | 62,954 | 11,561 | |||||||||||||||||||||||||||||||||
Capitalized costs of equity affiliates | $ | - | - | - | - | - | - | 180 | 8,310 | 3,071 | - | 11,561 | ||||||||||||||||||||||||||||||||
n | Capitalized costs include the cost of equipment and facilities for oil and gas producing activities. These costs include the activities of our E&P and LUKOIL Investment segments, excluding pipeline and marine operations, liquefied natural gas operations, a Canadian Syncrude operation, crude oil and natural gas marketing activities, and downstream operations. |
n | Proved properties include capitalized costs for oil and gas leaseholds holding proved reserves, development wells and related equipment and facilities (including uncompleted development well costs), and support equipment. |
n | Unproved properties include capitalized costs for oil and gas leaseholds under exploration (including where petroleum liquids and natural gas were found but determination of the economic viability of the required infrastructure is dependent upon further exploratory work under way or firmly planned) and for uncompleted exploratory well costs, including exploratory wells under evaluation. |
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n | Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserve Quantities |
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Millions of Dollars | ||||||||||||||||||||||||||||||||||||||||||||
Consolidated Operations | ||||||||||||||||||||||||||||||||||||||||||||
Lower | Total | Asia | Middle East | Russia and | Other | Equity | ||||||||||||||||||||||||||||||||||||||
Alaska | 48 | U.S. | Canada | Europe | Pacific | and Africa | Caspian | Areas | Total | Affiliates | ||||||||||||||||||||||||||||||||||
2007 | ||||||||||||||||||||||||||||||||||||||||||||
Future cash inflows | $ | 133,909 | 94,706 | 228,615 | 30,125 | 83,367 | 46,520 | 31,509 | 11,272 | 803 | 432,211 | 163,555 | ||||||||||||||||||||||||||||||||
Less: | ||||||||||||||||||||||||||||||||||||||||||||
Future production and transportation costs* | 75,024 | 41,945 | 116,969 | 11,206 | 15,781 | 11,996 | 3,884 | 1,876 | 706 | 162,418 | 97,375 | |||||||||||||||||||||||||||||||||
Future development costs | 8,392 | 9,690 | 18,082 | 4,605 | 10,920 | 3,958 | 400 | 2,761 | 34 | 40,760 | 10,847 | |||||||||||||||||||||||||||||||||
Future income tax provisions | 18,798 | 14,793 | 33,591 | 2,235 | 37,645 | 12,331 | 22,599 | 1,680 | 10 | 110,091 | 12,381 | |||||||||||||||||||||||||||||||||
Future net cash flows | 31,695 | 28,278 | 59,973 | 12,079 | 19,021 | 18,235 | 4,626 | 4,955 | 53 | 118,942 | 42,952 | |||||||||||||||||||||||||||||||||
10 percent annual discount | 16,510 | 12,158 | 28,668 | 3,870 | 5,776 | 7,113 | 1,847 | 4,504 | 2 | 51,780 | 22,925 | |||||||||||||||||||||||||||||||||
Discounted future net cash flows | $ | 15,185 | 16,120 | 31,305 | 8,209 | 13,245 | 11,122 | 2,779 | 451 | 51 | 67,162 | 20,027 | ||||||||||||||||||||||||||||||||
Discounted future net cash flows of equity affiliates | $ | - | - | - | 3,889 | - | - | 4,453 | 11,685 | - | - | 20,027 | ||||||||||||||||||||||||||||||||
2006 | ||||||||||||||||||||||||||||||||||||||||||||
Future cash inflows | $ | 86,843 | 75,039 | 161,882 | 25,363 | 60,118 | 32,420 | 19,369 | 6,853 | 1,777 | 307,782 | 117,860 | ||||||||||||||||||||||||||||||||
Less: | ||||||||||||||||||||||||||||||||||||||||||||
Future production and transportation costs* | 43,393 | 23,096 | 66,489 | 9,393 | 13,186 | 6,730 | 4,308 | 1,692 | 1,082 | 102,880 | 66,929 | |||||||||||||||||||||||||||||||||
Future development costs | 5,142 | 7,274 | 12,416 | 4,154 | 7,865 | 2,886 | 586 | 2,787 | 220 | 30,914 | 6,369 | |||||||||||||||||||||||||||||||||
Future income tax provisions | 14,138 | 14,357 | 28,495 | 2,313 | 25,627 | 9,204 | 12,029 | 590 | 101 | 78,359 | 16,085 | |||||||||||||||||||||||||||||||||
Future net cash flows | 24,170 | 30,312 | 54,482 | 9,503 | 13,440 | 13,600 | 2,446 | 1,784 | 374 | 95,629 | 28,477 | |||||||||||||||||||||||||||||||||
10 percent annual discount | 12,479 | 15,697 | 28,176 | 3,297 | 4,052 | 5,482 | 753 | 2,213 | 66 | 44,039 | 16,044 | |||||||||||||||||||||||||||||||||
Discounted future net cash flows | $ | 11,691 | 14,615 | 26,306 | 6,206 | 9,388 | 8,118 | 1,693 | (429 | ) | 308 | 51,590 | 12,433 | |||||||||||||||||||||||||||||||
Discounted future net cash flows of equity affiliates | $ | - | - | - | - | - | - | 1,703 | 5,441 | 5,289 | - | 12,433 | ||||||||||||||||||||||||||||||||
2005 | ||||||||||||||||||||||||||||||||||||||||||||
Future cash inflows | $ | 96,574 | 48,560 | 145,134 | 11,907 | 74,790 | 31,310 | 19,337 | 11,069 | 787 | 294,334 | 111,825 | ||||||||||||||||||||||||||||||||
Less: | ||||||||||||||||||||||||||||||||||||||||||||
Future production and transportation costs* | 34,586 | 10,425 | 45,011 | 2,892 | 12,055 | 5,343 | 3,442 | 2,410 | 488 | 71,641 | 47,634 | |||||||||||||||||||||||||||||||||
Future development costs | 4,569 | 1,686 | 6,255 | 965 | 7,517 | 2,920 | 474 | 1,917 | 149 | 20,197 | 4,760 | |||||||||||||||||||||||||||||||||
Future income tax provisions | 20,421 | 12,831 | 33,252 | 2,349 | 37,208 | 9,653 | 13,882 | 2,163 | 80 | 98,587 | 17,052 | |||||||||||||||||||||||||||||||||
Future net cash flows | 36,998 | 23,618 | 60,616 | 5,701 | 18,010 | 13,394 | 1,539 | 4,579 | 70 | 103,909 | 42,379 | |||||||||||||||||||||||||||||||||
10 percent annual discount | 19,414 | 11,934 | 31,348 | 2,184 | 6,006 | 5,639 | 560 | 4,168 | 56 | 49,961 | 25,720 | |||||||||||||||||||||||||||||||||
Discounted future net cash flows | $ | 17,584 | 11,684 | 29,268 | 3,517 | 12,004 | 7,755 | 979 | 411 | 14 | 53,948 | 16,659 | ||||||||||||||||||||||||||||||||
Discounted future net cash flows of equity affiliates | $ | - | - | - | - | - | - | 1,865 | 5,024 | 9,770 | - | 16,659 | ||||||||||||||||||||||||||||||||
Excludes discounted future net cash flows from Canadian Syncrude of $4,484 million in 2007, $2,220 million in 2006 and $2,159 million in 2005.
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Millions of Dollars | ||||||||||||||||||||||||
Consolidated Operations | Equity Affiliates | |||||||||||||||||||||||
2007 | 2006 | 2005 | 2007 | 2006 | 2005 | |||||||||||||||||||
Discounted future net cash flows at the beginning of the year | $ | 51,590 | 53,948 | 35,488 | 12,433 | 16,659 | 8,210 | |||||||||||||||||
Changes during the year | ||||||||||||||||||||||||
Revenues less production and transportation costs for the year* | (24,441 | ) | (25,133 | ) | (18,867 | ) | (3,288 | ) | (3,379 | ) | (2,586 | ) | ||||||||||||
Net change in prices, and production and transportation costs* | 49,447 | (18,928 | ) | 46,332 | 10,082 | (5,582 | ) | 6,555 | ||||||||||||||||
Extensions, discoveries and improved recovery, less estimated future costs | 6,985 | 3,867 | 3,942 | 2,188 | 401 | 2,201 | ||||||||||||||||||
Development costs for the year | 7,289 | 7,020 | 4,282 | 2,346 | 1,327 | 449 | ||||||||||||||||||
Changes in estimated future development costs | (10,813 | ) | (6,195 | ) | (3,261 | ) | (3,468 | ) | (1,291 | ) | (142 | ) | ||||||||||||
Purchases of reserves in place, less estimated future costs | 51 | 24,203 | 6,610 | 2,989 | 1,945 | 2,361 | ||||||||||||||||||
Sales of reserves in place, less estimated future costs | (1,347 | ) | (506 | ) | (306 | ) | (9,619 | ) | 2 | (34 | ) | |||||||||||||
Revisions of previous quantity estimates** | (79 | ) | (7,028 | ) | (175 | ) | 3,855 | 107 | 1,245 | |||||||||||||||
Accretion of discount | 8,561 | 9,759 | 5,728 | 1,809 | 2,215 | 1,032 | ||||||||||||||||||
Net change in income taxes | (20,081 | ) | 10,583 | (25,825 | ) | 700 | 29 | (2,632 | ) | |||||||||||||||
Other | - | - | - | - | - | - | ||||||||||||||||||
Total changes | 15,572 | (2,358 | ) | 18,460 | 7,594 | (4,226 | ) | 8,449 | ||||||||||||||||
Discounted future net cash flows at year end | $ | 67,162 | 51,590 | 53,948 | 20,027 | 12,433 | 16,659 | |||||||||||||||||
**Includes amounts resulting from changes in the timing of production.
n | The net change in prices, and production and transportation costs is the beginning-of-the-year reserve-production forecast multiplied by the net annual change in the per-unit sales price, and production and transportation cost, discounted at 10 percent. | |
n | Purchases and sales of reserves in place, along with extensions, discoveries and improved recovery, are calculated using production forecasts of the applicable reserve quantities for the year multiplied by the end-of-the-year sales prices, less future estimated costs, discounted at 10 percent. | |
n | The accretion of discount is 10 percent of the prior year’s discounted future cash inflows, less future production, transportation and development costs. | |
n | The net change in income taxes is the annual change in the discounted future income tax provisions. |
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Millions of Dollars | Per Share of Common Stock | |||||||||||||||||||||||||||||||
Income from | Income Before | |||||||||||||||||||||||||||||||
Sales and | Continuing | Income Before | Cumulative Effect | |||||||||||||||||||||||||||||
Other | Operations | Cumulative Effect | of Changes in | |||||||||||||||||||||||||||||
Operating | Before Income | of Changes in | Net | Accounting Principles | Net Income | |||||||||||||||||||||||||||
Revenues | ** | Taxes | Accounting Principles | Income | Basic | Diluted | Basic | Diluted | ||||||||||||||||||||||||
2007 | ||||||||||||||||||||||||||||||||
First | $ | 41,320 | 6,066 | 3,546 | 3,546 | 2.15 | 2.12 | 2.15 | 2.12 | |||||||||||||||||||||||
Second*** | 47,370 | 3,518 | 301 | 301 | .18 | .18 | .18 | .18 | ||||||||||||||||||||||||
Third | 46,062 | 6,364 | 3,673 | 3,673 | 2.26 | 2.23 | 2.26 | 2.23 | ||||||||||||||||||||||||
Fourth | 52,685 | 7,324 | 4,371 | 4,371 | 2.75 | 2.71 | 2.75 | 2.71 | ||||||||||||||||||||||||
2006 | ||||||||||||||||||||||||||||||||
First | $ | 46,906 | 5,797 | 3,291 | 3,291 | 2.38 | 2.34 | 2.38 | 2.34 | |||||||||||||||||||||||
Second | 47,149 | 8,682 | 5,186 | 5,186 | 3.13 | 3.09 | 3.13 | 3.09 | ||||||||||||||||||||||||
Third | 48,076 | 7,937 | 3,876 | 3,876 | 2.35 | 2.31 | 2.35 | 2.31 | ||||||||||||||||||||||||
Fourth | 41,519 | 5,917 | 3,197 | 3,197 | 1.94 | 1.91 | 1.94 | 1.91 | ||||||||||||||||||||||||
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• | ConocoPhillips, ConocoPhillips Company, ConocoPhillips Australia Funding Company, ConocoPhillips Canada Funding Company I, and ConocoPhillips Canada Funding Company II (in each case, reflecting investments in subsidiaries utilizing the equity method of accounting). | ||
• | All other non-guarantor subsidiaries of ConocoPhillips. | ||
• | The consolidating adjustments necessary to present ConocoPhillips’ results on a consolidated basis. |
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Millions of Dollars | ||||||||||||||||||||||||||||||||
Year Ended December 31, 2007 | ||||||||||||||||||||||||||||||||
ConocoPhillips | ||||||||||||||||||||||||||||||||
Australia | ConocoPhillips | ConocoPhillips | ||||||||||||||||||||||||||||||
ConocoPhillips | Funding | Canada Funding | Canada Funding | All Other | Consolidating | Total | ||||||||||||||||||||||||||
Income Statement | ConocoPhillips | Company | Company | Company I | Company II | Subsidiaries | Adjustments | Consolidated | ||||||||||||||||||||||||
Revenues and Other Income | ||||||||||||||||||||||||||||||||
Sales and other operating revenues | $ | - | 120,687 | - | - | - | 66,750 | - | 187,437 | |||||||||||||||||||||||
Equity in earnings of affiliates | 12,071 | 9,800 | - | - | - | 3,025 | (19,809 | ) | 5,087 | |||||||||||||||||||||||
Other income | 4 | (199 | ) | - | - | - | 2,166 | - | 1,971 | |||||||||||||||||||||||
Intercompany revenues | 149 | 3,014 | 117 | 83 | 51 | 18,407 | (21,821 | ) | - | |||||||||||||||||||||||
Total Revenues and Other Income | 12,224 | 133,302 | 117 | 83 | 51 | 90,348 | (41,630 | ) | 194,495 | |||||||||||||||||||||||
Costs and Expenses | ||||||||||||||||||||||||||||||||
Purchased crude oil, natural gas and products | - | 103,516 | - | - | - | 38,880 | (18,967 | ) | 123,429 | |||||||||||||||||||||||
Production and operating expenses | - | 4,522 | - | - | - | 6,247 | (86 | ) | 10,683 | |||||||||||||||||||||||
Selling, general and administrative expenses | 17 | 1,407 | - | - | - | 943 | (61 | ) | 2,306 | |||||||||||||||||||||||
Exploration expenses | - | 111 | - | - | - | 896 | - | 1,007 | ||||||||||||||||||||||||
Depreciation, depletion and amortization | - | 1,476 | - | - | - | 6,822 | - | 8,298 | ||||||||||||||||||||||||
Impairment—expropriated assets | - | 1,925 | - | - | - | 2,663 | - | 4,588 | ||||||||||||||||||||||||
Impairments | - | (73 | ) | - | - | - | 515 | - | 442 | |||||||||||||||||||||||
Taxes other than income taxes | - | 5,463 | - | - | - | 13,802 | (275 | ) | 18,990 | |||||||||||||||||||||||
Accretion on discounted liabilities | - | 55 | - | - | - | 286 | - | 341 | ||||||||||||||||||||||||
Interest and debt expense | 423 | 1,054 | 109 | 77 | 53 | 1,969 | (2,432 | ) | 1,253 | |||||||||||||||||||||||
Foreign currency transaction (gains) losses | - | 12 | - | 166 | 124 | (503 | ) | - | (201 | ) | ||||||||||||||||||||||
Minority interests | - | - | - | - | - | 87 | - | 87 | ||||||||||||||||||||||||
Total Costs and Expenses | 440 | 119,468 | 109 | 243 | 177 | 72,607 | (21,821 | ) | 171,223 | |||||||||||||||||||||||
Income from continuing operations before income taxes | 11,784 | 13,834 | 8 | (160 | ) | (126 | ) | 17,741 | (19,809 | ) | 23,272 | |||||||||||||||||||||
Provision for income taxes | (107 | ) | 2,810 | 3 | 16 | 6 | 8,653 | - | 11,381 | |||||||||||||||||||||||
Income from continuing operations | 11,891 | 11,024 | 5 | (176 | ) | (132 | ) | 9,088 | (19,809 | ) | 11,891 | |||||||||||||||||||||
Income (loss) from discontinued operations | - | - | - | - | - | - | - | - | ||||||||||||||||||||||||
Income before cumulative effect of changes in accounting principles | 11,891 | 11,024 | 5 | (176 | ) | (132 | ) | 9,088 | (19,809 | ) | 11,891 | |||||||||||||||||||||
Cumulative effect of changes in accounting principles | - | - | - | - | - | - | - | - | ||||||||||||||||||||||||
Net Income (Loss) | $ | 11,891 | 11,024 | 5 | (176 | ) | (132 | ) | 9,088 | (19,809 | ) | 11,891 | ||||||||||||||||||||
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Millions of Dollars | ||||||||||||||||||||||||||||||||
Year Ended December 31, 2006 | ||||||||||||||||||||||||||||||||
ConocoPhillips | ||||||||||||||||||||||||||||||||
Australia | ConocoPhillips | ConocoPhillips | ||||||||||||||||||||||||||||||
ConocoPhillips | Funding | Canada Funding | Canada Funding | All Other | Consolidating | Total | ||||||||||||||||||||||||||
Income Statement | ConocoPhillips | Company | Company | Company I | Company II | Subsidiaries | Adjustments | Consolidated | ||||||||||||||||||||||||
Revenues and Other Income | ||||||||||||||||||||||||||||||||
Sales and other operating revenues | $ | - | 117,063 | - | - | - | 66,587 | - | 183,650 | |||||||||||||||||||||||
Equity in earnings of affiliates | 15,798 | 11,136 | - | - | - | 3,608 | (26,354 | ) | 4,188 | |||||||||||||||||||||||
Other income | - | 337 | - | - | - | 348 | - | 685 | ||||||||||||||||||||||||
Intercompany revenues | 173 | 2,599 | 94 | 17 | 10 | 15,740 | (18,633 | ) | - | |||||||||||||||||||||||
Total Revenues and Other Income | 15,971 | 131,135 | 94 | 17 | 10 | 86,283 | (44,987 | ) | 188,523 | |||||||||||||||||||||||
Costs and Expenses | ||||||||||||||||||||||||||||||||
Purchased crude oil, natural gas and products | - | 97,986 | - | - | - | 37,735 | (16,822 | ) | 118,899 | |||||||||||||||||||||||
Production and operating expenses | - | 4,720 | - | - | - | 5,782 | (89 | ) | 10,413 | |||||||||||||||||||||||
Selling, general and administrative expenses | 19 | 1,593 | - | - | - | 914 | (50 | ) | 2,476 | |||||||||||||||||||||||
Exploration expenses | - | 120 | - | - | - | 714 | - | 834 | ||||||||||||||||||||||||
Depreciation, depletion and amortization | - | 1,702 | - | - | - | 5,582 | - | 7,284 | ||||||||||||||||||||||||
Impairments | - | 410 | - | - | - | 273 | - | 683 | ||||||||||||||||||||||||
Taxes other than income taxes | - | 5,877 | - | - | - | 12,577 | (267 | ) | 18,187 | |||||||||||||||||||||||
Accretion on discounted liabilities | - | 58 | - | - | - | 223 | - | 281 | ||||||||||||||||||||||||
Interest and debt expense | 537 | 1,070 | 80 | 17 | 11 | 777 | (1,405 | ) | 1,087 | |||||||||||||||||||||||
Foreign currency transaction (gains) losses | - | (2 | ) | - | (39 | ) | (37 | ) | 48 | - | (30 | ) | ||||||||||||||||||||
Minority interests | - | - | - | - | - | 76 | - | 76 | ||||||||||||||||||||||||
Total Costs and Expenses | 556 | 113,534 | 80 | (22 | ) | (26 | ) | 64,701 | (18,633 | ) | 160,190 | |||||||||||||||||||||
Income from continuing operations before income taxes | 15,415 | 17,601 | 14 | 39 | 36 | 21,582 | (26,354 | ) | 28,333 | |||||||||||||||||||||||
Provision for income taxes | (135 | ) | 2,839 | 5 | 10 | 10 | 10,054 | - | 12,783 | |||||||||||||||||||||||
Income from continuing operations | 15,550 | 14,762 | 9 | 29 | 26 | 11,528 | (26,354 | ) | 15,550 | |||||||||||||||||||||||
Income (loss) from discontinued operations | - | - | - | - | - | - | - | - | ||||||||||||||||||||||||
Income before cumulative effect of changes in accounting principles | 15,550 | 14,762 | 9 | 29 | 26 | 11,528 | (26,354 | ) | 15,550 | |||||||||||||||||||||||
Cumulative effect of changes in accounting principles | - | - | - | - | - | - | - | - | ||||||||||||||||||||||||
Net Income | $ | 15,550 | 14,762 | 9 | 29 | 26 | 11,528 | (26,354 | ) | 15,550 | ||||||||||||||||||||||
197
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Millions of Dollars | ||||||||||||||||||||
Year Ended December 31, 2005 | ||||||||||||||||||||
ConocoPhillips | All Other | Consolidating | Total | |||||||||||||||||
Income Statement | ConocoPhillips | Company | Subsidiaries | Adjustments | Consolidated | |||||||||||||||
Revenues and Other Income | ||||||||||||||||||||
Sales and other operating revenues | $ | - | 121,718 | 57,724 | - | 179,442 | ||||||||||||||
Equity in earnings of affiliates | 13,754 | 10,235 | 2,842 | (23,374 | ) | 3,457 | ||||||||||||||
Other income (loss) | (25 | ) | 152 | 338 | - | 465 | ||||||||||||||
Intercompany revenues | 30 | 2,250 | 9,925 | (12,205 | ) | - | ||||||||||||||
Total Revenues and Other Income | 13,759 | 134,355 | 70,829 | (35,579 | ) | 183,364 | ||||||||||||||
Costs and Expenses | ||||||||||||||||||||
Purchased crude oil, natural gas and products | - | 103,307 | 32,665 | (11,047 | ) | 124,925 | ||||||||||||||
Production and operating expenses | - | 4,711 | 3,917 | (66 | ) | 8,562 | ||||||||||||||
Selling, general and administrative expenses | 16 | 1,436 | 818 | (23 | ) | 2,247 | ||||||||||||||
Exploration expenses | - | 84 | 577 | - | 661 | |||||||||||||||
Depreciation, depletion and amortization | - | 1,473 | 2,780 | - | 4,253 | |||||||||||||||
Impairments | - | 2 | 40 | - | 42 | |||||||||||||||
Taxes other than income taxes | - | 6,065 | 12,533 | (242 | ) | 18,356 | ||||||||||||||
Accretion on discounted liabilities | - | 37 | 156 | - | 193 | |||||||||||||||
Interest and debt expense | 135 | 833 | 356 | (827 | ) | 497 | ||||||||||||||
Foreign currency transaction (gains) losses | - | (16 | ) | 64 | - | 48 | ||||||||||||||
Minority interests | - | - | 33 | - | 33 | |||||||||||||||
Total Costs and Expenses | 151 | 117,932 | 53,939 | (12,205 | ) | 159,817 | ||||||||||||||
Income from continuing operations before income taxes | 13,608 | 16,423 | 16,890 | (23,374 | ) | 23,547 | ||||||||||||||
Provision for income taxes | (32 | ) | 2,669 | 7,270 | - | 9,907 | ||||||||||||||
Income from continuing operations | 13,640 | 13,754 | 9,620 | (23,374 | ) | 13,640 | ||||||||||||||
Loss from discontinued operations | (23 | ) | (23 | ) | (6 | ) | 29 | (23 | ) | |||||||||||
Income before cumulative effect of changes in accounting principles | 13,617 | 13,731 | 9,614 | (23,345 | ) | 13,617 | ||||||||||||||
Cumulative effect of changes in accounting principles | (88 | ) | (88 | ) | (29 | ) | 117 | (88 | ) | |||||||||||
Net Income | $ | 13,529 | 13,643 | 9,585 | (23,228 | ) | 13,529 | |||||||||||||
198
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Millions of Dollars | ||||||||||||||||||||||||||||||||
At December 31, 2007 | ||||||||||||||||||||||||||||||||
ConocoPhillips | ||||||||||||||||||||||||||||||||
Australia | ConocoPhillips | ConocoPhillips | ||||||||||||||||||||||||||||||
ConocoPhillips | Funding | Canada Funding | Canada Funding | All Other | Consolidating | Total | ||||||||||||||||||||||||||
Balance Sheet | ConocoPhillips | Company | Company | Company I | Company II | Subsidiaries | Adjustments | Consolidated | ||||||||||||||||||||||||
Assets | ||||||||||||||||||||||||||||||||
Cash and cash equivalents | $ | - | 195 | - | 7 | 1 | 1,626 | (373 | ) | 1,456 | ||||||||||||||||||||||
Accounts and notes receivable | 40 | 12,421 | 15 | 12 | 4 | 19,548 | (15,686 | ) | 16,354 | |||||||||||||||||||||||
Inventories | - | 2,043 | - | - | - | 2,190 | (10 | ) | 4,223 | |||||||||||||||||||||||
Prepaid expenses and other current assets | 9 | 578 | - | 1 | - | 2,114 | - | 2,702 | ||||||||||||||||||||||||
Total Current Assets | 49 | 15,237 | 15 | 20 | 5 | 25,478 | (16,069 | ) | 24,735 | |||||||||||||||||||||||
Investments, loans and long-term receivables* | 86,942 | 57,936 | 1,700 | 1,470 | 997 | 18,972 | (134,689 | ) | 33,328 | |||||||||||||||||||||||
Net properties, plants and equipment | - | 17,677 | - | - | - | 71,317 | 9 | 89,003 | ||||||||||||||||||||||||
Goodwill | - | 12,746 | - | - | - | 16,590 | - | 29,336 | ||||||||||||||||||||||||
Intangibles | - | 808 | - | - | - | 88 | - | 896 | ||||||||||||||||||||||||
Other assets | 8 | 153 | 3 | 5 | 4 | 520 | (234 | ) | 459 | |||||||||||||||||||||||
Total Assets | $ | 86,999 | 104,557 | 1,718 | 1,495 | 1,006 | 132,965 | (150,983 | ) | 177,757 | ||||||||||||||||||||||
Liabilities and Stockholders’ Equity | ||||||||||||||||||||||||||||||||
Accounts payable | $ | 6 | 18,792 | - | 10 | 4 | 15,108 | (16,059 | ) | 17,861 | ||||||||||||||||||||||
Notes payable and long-term debt due within one year | 1,000 | 309 | - | - | - | 89 | - | 1,398 | ||||||||||||||||||||||||
Accrued income and other taxes | - | 601 | - | - | (1 | ) | 4,117 | 97 | 4,814 | |||||||||||||||||||||||
Employee benefit obligations | - | 509 | - | - | - | 411 | - | 920 | ||||||||||||||||||||||||
Other accruals | 21 | 594 | 20 | 16 | 11 | 1,230 | (3 | ) | 1,889 | |||||||||||||||||||||||
Total Current Liabilities | 1,027 | 20,805 | 20 | 26 | 14 | 20,955 | (15,965 | ) | 26,882 | |||||||||||||||||||||||
Long-term debt | 3,402 | 5,694 | 1,699 | 1,250 | 848 | 7,396 | - | 20,289 | ||||||||||||||||||||||||
Asset retirement obligations and accrued environmental costs | - | 1,167 | - | - | - | 6,094 | - | 7,261 | ||||||||||||||||||||||||
Joint venture acquisition obligation | - | - | - | - | - | 6,294 | - | 6,294 | ||||||||||||||||||||||||
Deferred income taxes | (3 | ) | 3,050 | - | 32 | 18 | 17,907 | 14 | 21,018 | |||||||||||||||||||||||
Employee benefit obligations | - | 2,292 | - | - | - | 899 | - | 3,191 | ||||||||||||||||||||||||
Other liabilities and deferred credits* | 42 | 16,447 | - | 132 | 102 | 15,489 | (29,546 | ) | 2,666 | |||||||||||||||||||||||
Total Liabilities | 4,468 | 49,455 | 1,719 | 1,440 | 982 | 75,034 | (45,497 | ) | 87,601 | |||||||||||||||||||||||
Minority interests | - | (19 | ) | - | - | - | 1,194 | (2 | ) | 1,173 | ||||||||||||||||||||||
Retained earnings | 43,988 | 23,952 | (1 | ) | (147 | ) | (107 | ) | 20,738 | (37,913 | ) | 50,510 | ||||||||||||||||||||
Other stockholders’ equity | 38,543 | 31,169 | - | 202 | 131 | 35,999 | (67,571 | ) | 38,473 | |||||||||||||||||||||||
Total | $ | 86,999 | 104,557 | 1,718 | 1,495 | 1,006 | 132,965 | (150,983 | ) | 177,757 | ||||||||||||||||||||||
199
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Millions of Dollars | ||||||||||||||||||||||||||||||||
At December 31, 2006 | ||||||||||||||||||||||||||||||||
ConocoPhillips | ||||||||||||||||||||||||||||||||
Australia | ConocoPhillips | ConocoPhillips | ||||||||||||||||||||||||||||||
ConocoPhillips | Funding | Canada Funding | Canada Funding | All Other | Consolidating | Total | ||||||||||||||||||||||||||
Balance Sheet | ConocoPhillips | Company | Company | Company I | Company II | Subsidiaries | Adjustments | Consolidated | ||||||||||||||||||||||||
Assets | ||||||||||||||||||||||||||||||||
Cash and cash equivalents | $ | - | 116 | - | - | 1 | 1,042 | (342 | ) | 817 | ||||||||||||||||||||||
Accounts and notes receivable | 65 | 13,233 | 22 | 10 | 2 | 17,224 | (16,450 | ) | 14,106 | |||||||||||||||||||||||
Inventories | - | 2,906 | - | - | - | 2,247 | - | 5,153 | ||||||||||||||||||||||||
Prepaid expenses and other current assets | 11 | 895 | - | 10 | 7 | 4,067 | - | 4,990 | ||||||||||||||||||||||||
Total Current Assets | 76 | 17,150 | 22 | 20 | 10 | 24,580 | (16,792 | ) | 25,066 | |||||||||||||||||||||||
Investments and long-term receivables* | 86,292 | 58,530 | 2,000 | 1,241 | 841 | 28,372 | (156,563 | ) | 20,713 | |||||||||||||||||||||||
Net properties, plants and equipment | - | 19,072 | - | - | - | 67,122 | 7 | 86,201 | ||||||||||||||||||||||||
Goodwill | - | 15,226 | - | - | - | 16,262 | - | 31,488 | ||||||||||||||||||||||||
Intangibles | - | 852 | - | - | - | 99 | - | 951 | ||||||||||||||||||||||||
Other assets | 10 | 141 | 5 | 35 | 24 | 195 | (48 | ) | 362 | |||||||||||||||||||||||
Total Assets | $ | 86,378 | 110,971 | 2,027 | 1,296 | 875 | 136,630 | (173,396 | ) | 164,781 | ||||||||||||||||||||||
Liabilities and Stockholders’ Equity | ||||||||||||||||||||||||||||||||
Accounts payable | $ | 68 | 16,641 | - | 5 | 3 | 14,367 | (16,450 | ) | 14,634 | ||||||||||||||||||||||
Notes payable and long-term debt due within one year | 3,431 | 525 | - | - | - | 87 | - | 4,043 | ||||||||||||||||||||||||
Accrued income and other taxes | - | 732 | - | - | - | 3,577 | 98 | 4,407 | ||||||||||||||||||||||||
Employee benefit obligations | - | 464 | - | - | - | 431 | - | 895 | ||||||||||||||||||||||||
Other accruals | 50 | 804 | 24 | 16 | 10 | 1,565 | (17 | ) | 2,452 | |||||||||||||||||||||||
Total Current Liabilities | 3,549 | 19,166 | 24 | 21 | 13 | 20,027 | (16,369 | ) | 26,431 | |||||||||||||||||||||||
Long-term debt | 6,521 | 6,036 | 1,999 | 1,250 | 848 | 6,437 | - | 23,091 | ||||||||||||||||||||||||
Asset retirement obligations and accrued environmental costs | - | 1,095 | - | - | - | 4,524 | - | 5,619 | ||||||||||||||||||||||||
Deferred income taxes | (8 | ) | 2,969 | - | 16 | 10 | 17,086 | 1 | 20,074 | |||||||||||||||||||||||
Employee benefit obligations | - | 2,379 | - | - | - | 1,288 | - | 3,667 | ||||||||||||||||||||||||
Other liabilities and deferred credits* | 29 | 28,306 | - | - | - | 22,300 | (48,584 | ) | 2,051 | |||||||||||||||||||||||
Total Liabilities | 10,091 | 59,951 | 2,023 | 1,287 | 871 | 71,662 | (64,952 | ) | 80,933 | |||||||||||||||||||||||
Minority interests | - | (19 | ) | - | - | - | 1,221 | - | 1,202 | |||||||||||||||||||||||
Retained earnings | 34,756 | 22,939 | 4 | 29 | 26 | 28,029 | (44,491 | ) | 41,292 | |||||||||||||||||||||||
Other stockholders’ equity | 41,531 | 28,100 | - | (20 | ) | (22 | ) | 35,718 | (63,953 | ) | 41,354 | |||||||||||||||||||||
Total | $ | 86,378 | 110,971 | 2,027 | 1,296 | 875 | 136,630 | (173,396 | ) | 164,781 | ||||||||||||||||||||||
* Includes intercompany loans. |
200
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Millions of Dollars | ||||||||||||||||||||||||||||||||
Year Ended December 31, 2007 | ||||||||||||||||||||||||||||||||
ConocoPhillips | ||||||||||||||||||||||||||||||||
Australia | ConocoPhillips | ConocoPhillips | ||||||||||||||||||||||||||||||
Statement of Cash Flows | ConocoPhillips | Funding | Canada Funding | Canada Funding | All Other | Consolidating | Total | |||||||||||||||||||||||||
ConocoPhillips | Company | Company | Company I | Company II | Subsidiaries | Adjustments | Consolidated | |||||||||||||||||||||||||
Cash Flows From Operating Activities | ||||||||||||||||||||||||||||||||
Net cash provided by continuing operations | $ | 14,984 | 9,944 | 10 | 7 | - | 26,021 | (26,416 | ) | 24,550 | ||||||||||||||||||||||
Net cash used in discontinued operations | - | - | - | - | - | - | - | - | ||||||||||||||||||||||||
Net Cash Provided by Operating Activities | 14,984 | 9,944 | 10 | 7 | - | 26,021 | (26,416 | ) | 24,550 | |||||||||||||||||||||||
Cash Flows From Investing Activities | ||||||||||||||||||||||||||||||||
Acquisition of Burlington Resources Inc. | - | - | - | - | - | - | - | - | ||||||||||||||||||||||||
Capital expenditures and investments, including dry hole costs | - | (2,967 | ) | - | - | - | (9,121 | ) | 297 | (11,791 | ) | |||||||||||||||||||||
Proceeds from asset dispositions | - | 1,391 | - | - | - | 3,029 | (848 | ) | 3,572 | |||||||||||||||||||||||
Long-term advances/loans to affiliates and other investments | - | (491 | ) | - | - | - | (2,649 | ) | 2,458 | (682 | ) | |||||||||||||||||||||
Collection of advances/loans to affiliates | �� | - | 1,238 | 300 | - | - | 837 | (2,286 | ) | 89 | ||||||||||||||||||||||
Other | 1 | 83 | - | - | - | 166 | - | 250 | ||||||||||||||||||||||||
Net cash provided by (used in) continuing operations | 1 | (746 | ) | 300 | - | - | (7,738 | ) | (379 | ) | (8,562 | ) | ||||||||||||||||||||
Net cash used in discontinued operations | - | - | - | - | - | - | - | - | ||||||||||||||||||||||||
Net Cash Provided by (Used in) Investing Activities | 1 | (746 | ) | 300 | - | - | (7,738 | ) | (379 | ) | (8,562 | ) | ||||||||||||||||||||
Cash Flows From Financing Activities | ||||||||||||||||||||||||||||||||
Issuance of debt | (39 | ) | 2,179 | - | - | - | 1,253 | (2,458 | ) | 935 | ||||||||||||||||||||||
Repayment of debt | (5,564 | ) | (1,385 | ) | (300 | ) | - | - | (1,491 | ) | 2,286 | (6,454 | ) | |||||||||||||||||||
Repurchase of company common stock | (7,001 | ) | - | - | - | - | - | - | (7,001 | ) | ||||||||||||||||||||||
Issuance of company common stock | 285 | - | - | - | - | - | - | 285 | ||||||||||||||||||||||||
Dividends paid on common stock | (2,661 | ) | (10,000 | ) | (10 | ) | - | - | (16,376 | ) | 26,386 | (2,661 | ) | |||||||||||||||||||
Other | (5 | ) | 87 | - | - | - | (1,076 | ) | 550 | (444 | ) | |||||||||||||||||||||
Net Cash Used in Financing Activities | (14,985 | ) | (9,119 | ) | (310 | ) | - | - | (17,690 | ) | 26,764 | (15,340 | ) | |||||||||||||||||||
Effect of Exchange Rate Changes on Cash and Cash Equivalents | - | - | - | - | - | (9 | ) | - | (9 | ) | ||||||||||||||||||||||
Net Change in Cash and Cash Equivalents | - | 79 | - | 7 | - | 584 | (31 | ) | 639 | |||||||||||||||||||||||
Cash and cash equivalents at beginning of year | - | 116 | - | - | 1 | 1,042 | (342 | ) | 817 | |||||||||||||||||||||||
Cash and Cash Equivalents at End of Year | $ | - | 195 | - | 7 | 1 | 1,626 | (373 | ) | 1,456 | ||||||||||||||||||||||
201
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Millions of Dollars | ||||||||||||||||||||||||||||||||
Year Ended December 31, 2006 | ||||||||||||||||||||||||||||||||
ConocoPhillips | ||||||||||||||||||||||||||||||||
Australia | ConocoPhillips | ConocoPhillips | ||||||||||||||||||||||||||||||
Statement of Cash Flows | ConocoPhillips | Funding | Canada Funding | Canada Funding | All Other | Consolidating | Total | |||||||||||||||||||||||||
ConocoPhillips | Company | Company | Company I | Company II | Subsidiaries | Adjustments | Consolidated | |||||||||||||||||||||||||
Cash Flows From Operating Activities | ||||||||||||||||||||||||||||||||
Net cash provided by continuing operations | $ | 29,520 | 6,723 | 4 | 6 | 8 | 7,659 | (22,404 | ) | 21,516 | ||||||||||||||||||||||
Net cash used in discontinued operations | - | - | - | - | - | - | - | - | ||||||||||||||||||||||||
Net Cash Provided by Operating Activities | 29,520 | 6,723 | 4 | 6 | 8 | 7,659 | (22,404 | ) | 21,516 | |||||||||||||||||||||||
Cash Flows From Investing Activities | ||||||||||||||||||||||||||||||||
Acquisition of Burlington Resources Inc. | - | - | - | - | - | (14,285 | ) | - | (14,285 | ) | ||||||||||||||||||||||
Capital expenditures and investments, including dry hole costs | (17,494 | ) | (3,538 | ) | - | - | - | (12,696 | ) | 18,132 | (15,596 | ) | ||||||||||||||||||||
Proceeds from asset dispositions | - | 73 | - | - | - | 472 | - | 545 | ||||||||||||||||||||||||
Long-term advances/loans to affiliates and other investments | (14,989 | ) | (290 | ) | (1,992 | ) | (1,250 | ) | (1,711 | ) | (3,896 | ) | 23,348 | (780 | ) | |||||||||||||||||
Collection of advances/loans to affiliates | - | 2,708 | - | - | 861 | 4,384 | (7,830 | ) | 123 | |||||||||||||||||||||||
Net cash used in continuing operations | (32,483 | ) | (1,047 | ) | (1,992 | ) | (1,250 | ) | (850 | ) | (26,021 | ) | 33,650 | (29,993 | ) | |||||||||||||||||
Net cash used in discontinued operations | - | - | - | - | - | - | - | - | ||||||||||||||||||||||||
Net Cash Used in Investing Activities | (32,483 | ) | (1,047 | ) | (1,992 | ) | (1,250 | ) | (850 | ) | (26,021 | ) | 33,650 | (29,993 | ) | |||||||||||||||||
Cash Flows From Financing Activities | ||||||||||||||||||||||||||||||||
Issuance of debt | 12,892 | 18,394 | 2,000 | 1,250 | 848 | 5,278 | (23,348 | ) | 17,314 | |||||||||||||||||||||||
Repayment of debt | (6,936 | ) | (4,536 | ) | - | - | - | (3,440 | ) | 7,830 | (7,082 | ) | ||||||||||||||||||||
Repurchase of company common stock | (925 | ) | - | - | - | - | - | - | (925 | ) | ||||||||||||||||||||||
Issuance of company common stock | 220 | - | - | - | - | - | - | 220 | ||||||||||||||||||||||||
Dividends paid on common stock | (2,277 | ) | (20,000 | ) | (5 | ) | - | - | (2,056 | ) | 22,061 | (2,277 | ) | |||||||||||||||||||
Other | (11 | ) | (31 | ) | (7 | ) | (6 | ) | (5 | ) | 18,006 | (18,131 | ) | (185 | ) | |||||||||||||||||
Net Cash Provided by (Used in) Financing Activities | 2,963 | (6,173 | ) | 1,988 | 1,244 | 843 | 17,788 | (11,588 | ) | 7,065 | ||||||||||||||||||||||
Effect of Exchange Rate Changes on Cash and Cash Equivalents | - | - | - | - | - | 15 | - | 15 | ||||||||||||||||||||||||
Net Change in Cash and Cash Equivalents | - | (497 | ) | - | - | 1 | (559 | ) | (342 | ) | (1,397 | ) | ||||||||||||||||||||
Cash and cash equivalents at beginning of year | - | 613 | - | - | - | 1,601 | - | 2,214 | ||||||||||||||||||||||||
Cash and Cash Equivalents at End of Year | $ | - | 116 | - | - | 1 | 1,042 | (342 | ) | 817 | ||||||||||||||||||||||
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Millions of Dollars | ||||||||||||||||||||
Year Ended December 31, 2005 | ||||||||||||||||||||
ConocoPhillips | All Other | Consolidating | Total | |||||||||||||||||
Statement of Cash Flows | ConocoPhillips | Company | Subsidiaries | Adjustments | Consolidated | |||||||||||||||
Cash Flows From Operating Activities | ||||||||||||||||||||
Net cash provided by continuing operations | $ | 183 | 15,956 | 11,192 | (9,698 | ) | 17,633 | |||||||||||||
Net cash provided by (used in) discontinued operations | - | (7 | ) | 2 | - | (5 | ) | |||||||||||||
Net Cash Provided by Operating Activities | 183 | 15,949 | 11,194 | (9,698 | ) | 17,628 | ||||||||||||||
Cash Flows From Investing Activities | ||||||||||||||||||||
Capital expenditures and investments, including dry hole costs | - | (5,118 | ) | (9,119 | ) | 2,617 | (11,620 | ) | ||||||||||||
Proceeds from asset dispositions | - | 279 | 491 | (2 | ) | 768 | ||||||||||||||
Long-term advances/loans to affiliates and other | - | (20,056 | ) | (1,208 | ) | 20,989 | (275 | ) | ||||||||||||
Collection of advances/loans to affiliates and other | 1,240 | 12,339 | 2,161 | (15,629 | ) | 111 | ||||||||||||||
Net cash provided by (used in) continuing operations | 1,240 | (12,556 | ) | (7,675 | ) | 7,975 | (11,016 | ) | ||||||||||||
Net cash used in discontinued operations | - | - | - | - | - | |||||||||||||||
Net Cash Provided by (Used in) Investing Activities | 1,240 | (12,556 | ) | (7,675 | ) | 7,975 | (11,016 | ) | ||||||||||||
Cash Flows From Financing Activities | ||||||||||||||||||||
Issuance of debt | 2,901 | 1,504 | 17,036 | (20,989 | ) | 452 | ||||||||||||||
Repayment of debt | (1,160 | ) | (5,115 | ) | (12,356 | ) | 15,629 | (3,002 | ) | |||||||||||
Repurchase of company common stock | (1,924 | ) | - | - | - | (1,924 | ) | |||||||||||||
Issuance of company common stock | 402 | - | - | - | 402 | |||||||||||||||
Dividends paid on common stock | (1,639 | ) | - | (9,700 | ) | 9,700 | (1,639 | ) | ||||||||||||
Other | (3 | ) | (50 | ) | 2,697 | (2,617 | ) | 27 | ||||||||||||
Net Cash Used in Financing Activities | (1,423 | ) | (3,661 | ) | (2,323 | ) | 1,723 | (5,684 | ) | |||||||||||
Effect of Exchange Rate Changes on Cash and Cash Equivalents | - | 2 | (103 | ) | - | (101 | ) | |||||||||||||
Net Change in Cash and Cash Equivalents | - | (266 | ) | 1,093 | - | 827 | ||||||||||||||
Cash and cash equivalents at beginning of year | - | 879 | 508 | - | 1,387 | |||||||||||||||
Cash and Cash Equivalents at End of Year | $ | - | 613 | 1,601 | - | 2,214 | ||||||||||||||
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Item 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
Item 9A. | CONTROLS AND PROCEDURES |
Item 9B. | OTHER INFORMATION |
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Item 10. | DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE |
Item 11. | EXECUTIVE COMPENSATION |
Item 12. | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS |
Item 13. | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE |
Item 14. | PRINCIPAL ACCOUNTING FEES AND SERVICES |
* | Except for information or data specifically incorporated herein by reference under Items 10 through 14, other information and data appearing in the 2008 Proxy Statement are not deemed to be a part of this Annual Report on Form 10-K or deemed to be filed with the Commission as a part of this report. |
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Item 15. | EXHIBITS, FINANCIAL STATEMENT SCHEDULES |
(a) | 1. Financial Statements and Financial Statement Schedules | |
The financial statements and schedule listed in the Index to Financial Statements and Financial Statement Schedules, which appears on page 98, are filed as part of this annual report. | ||
2. Exhibits The exhibits listed in the Index to Exhibits, which appears on pages 208 through 211, are filed as a part of this annual report. |
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Millions of Dollars | ||||||||||||||||||||
Additions | ||||||||||||||||||||
Balance At | Charged to | Balance At | ||||||||||||||||||
Description | January 1 | Expense | Other(a) | Deductions | December 31 | |||||||||||||||
2007 | ||||||||||||||||||||
Deducted from asset accounts: | ||||||||||||||||||||
Allowance for doubtful accounts and notes receivable | $ | 45 | 23 | (2 | ) | (8 | )(b) | 58 | ||||||||||||
Deferred tax asset valuation allowance | 822 | 67 | 417 | (37 | ) | 1,269 | ||||||||||||||
Included in other liabilities: | ||||||||||||||||||||
Restructuring accruals | 164 | 31 | 5 | (83 | )(c) | 117 | ||||||||||||||
2006 | ||||||||||||||||||||
Deducted from asset accounts: | ||||||||||||||||||||
Allowance for doubtful accounts and notes receivable | $ | 72 | 11 | 9 | (47 | )(b) | 45 | |||||||||||||
Deferred tax asset valuation allowance | 850 | 103 | 42 | (173 | ) | 822 | ||||||||||||||
Included in other liabilities: | ||||||||||||||||||||
Restructuring accruals | 53 | 10 | 216 | (115 | )(c) | 164 | ||||||||||||||
2005 | ||||||||||||||||||||
Deducted from asset accounts: | ||||||||||||||||||||
Allowance for doubtful accounts and notes receivable | $ | 55 | 21 | 4 | (8 | )(b) | 72 | |||||||||||||
Deferred tax asset valuation allowance | 968 | 90 | (26 | ) | (182 | ) | 850 | |||||||||||||
Included in other liabilities: | ||||||||||||||||||||
Restructuring accruals | 89 | (2 | ) | (3 | ) | (31 | )(c) | 53 | ||||||||||||
(a) | Represents acquisitions/dispositions/revisions and the effect of translating foreign financial statements. | |
(b) | Amounts charged off less recoveries of amounts previously charged off. | |
(c) | Benefit payments. |
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Exhibit | ||
Number | Description | |
2.1 | Agreement and Plan of Merger, dated as of November 18, 2001, by and among ConocoPhillips Company (formerly named Phillips Petroleum Company), ConocoPhillips (formerly named CorvettePorsche Corp.), P Merger Corp. (formerly named Porsche Merger Corp.), C Merger Corp. (formerly named Corvette Merger Corp.) and ConocoPhillips Holding Company (formerly named Conoco Inc.) (“Holding”) (incorporated by reference to Annex A to the Joint Proxy Statement/Prospectus included in ConocoPhillips’ Registration Statement on Form S-4; Registration No. 333-74798 (the “Form S-4”)). | |
2.2 | Agreement and Plan of Merger, dated as of December 12, 2005, by and among ConocoPhillips, Cello Acquisition Corp. and Burlington Resources Inc. (incorporated by reference to Exhibit 2.1 to the Current Report of ConocoPhillips on Form 8-K filed on December 14, 2005; File No. 001-32395). | |
3.1 | Restated Certificate of Incorporation of ConocoPhillips (incorporated by reference to Exhibit 3.1 to the Current Report of ConocoPhillips on Form 8-K filed on August 30, 2002; File No. 000-49987 (the “Form 8-K”)). | |
3.2 | Certificate of Designations of Series A Junior Participating Preferred Stock of ConocoPhillips (incorporated by reference to Exhibit 3.2 to the Form 8-K). | |
3.3 | By-Laws of ConocoPhillips, as amended on February 15, 2008 (incorporated by reference to Exhibit 99.1 to the Current Report of ConocoPhillips on Form 8-K filed on February 19, 2008; File No. 001-32395). | |
4.1 | Rights agreement, dated as of June 30, 2002, between ConocoPhillips and Mellon Investor Services LLC, as rights agent, which includes as Exhibit A the form of Certificate of Designations of Series A Junior Participating Preferred Stock, as Exhibit B the form of Rights Certificate and as Exhibit C the Summary of Rights to Purchase Preferred Stock (incorporated by reference to Exhibit 4.1 to the Form 8-K). | |
ConocoPhillips and its subsidiaries are parties to several debt instruments under which the total amount of securities authorized does not exceed 10 percent of the total assets of ConocoPhillips and its subsidiaries on a consolidated basis. Pursuant to paragraph 4(iii)(A) of Item 601(b) of Regulation S-K, ConocoPhillips agrees to furnish a copy of such instruments to the SEC upon request. | ||
10.1 | Shareholder Agreement, dated September 29, 2004, by and between LUKOIL and ConocoPhillips (incorporated by reference to Exhibit 99.2 of the Current Report of ConocoPhillips on Form 8-K filed on September 30, 2004; File No. 333-74798). | |
10.2 | 1986 Stock Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10.11 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002; File No. 000-49987). |
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Exhibit | ||
Number | Description | |
10.3 | 1990 Stock Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10.12 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002; File No. 000-49987). | |
10.4 | Annual Incentive Compensation Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10.13 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002; File No. 000-49987). | |
10.5 | Incentive Compensation Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10(g) to the Annual Report of ConocoPhillips Company on Form 10-K for the year ended December 31, 1999; File No. 1-720). | |
10.6 | Principal Corporate Officers Supplemental Retirement Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10(h) to the Annual Report of ConocoPhillips Company on Form 10-K for the year ended December 31, 1995; File No. 1-720). | |
10.7 | ConocoPhillips Supplemental Executive Retirement Plan (incorporated by reference to Exhibit 10.7 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2005; File No. 001-32395). | |
10.8 | Non-Employee Director Retirement Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10.18 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002; File No. 000-49987). | |
10.9 | Omnibus Securities Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10.19 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002; File No. 000-49987). | |
10.10 | Key Employee Missed Credited Service Retirement Plan of ConocoPhillips (incorporated by reference to Exhibit 10.10 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2005; File No. 001-32395). | |
10.11 | Phillips Petroleum Company Stock Plan for Non-Employee Directors (incorporated by reference to Exhibit 10.22 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002; File No. 000-49987). | |
10.12 | ConocoPhillips Key Employee Supplemental Retirement Plan (incorporated by reference to Exhibit 10.12 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2005; File No. 001-32395). | |
10.13.1 | Defined Contribution Make-Up Plan of ConocoPhillips—Title I (incorporated by reference to Exhibit 10.13.1 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2005; File No. 001-32395). | |
10.13.2 | Defined Contribution Make-Up Plan of ConocoPhillips—Title II (incorporated by reference to Exhibit 10.13.2 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2005; File No. 001-32395). |
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Exhibit | ||
Number | Description | |
10.14 | 2002 Omnibus Securities Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10.26 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002; File No. 000-49987). | |
10.15 | 1998 Stock and Performance Incentive Plan of ConocoPhillips (incorporated by reference to Exhibit 10.27 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002; File No. 000-49987). | |
10.16 | 1998 Key Employee Stock Performance Plan of ConocoPhillips (incorporated by reference to Exhibit 10.28 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002; File No. 000-49987). | |
10.17 | Deferred Compensation Plan for Non-Employee Directors of ConocoPhillips (incorporated by reference to Exhibit 10.17 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2005; File No. 001-32395). | |
10.18 | ConocoPhillips Form Indemnity Agreement with Directors (incorporated by reference to Exhibit 10.34 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002; File No. 000-49987). | |
10.19 | Letter Agreement, dated as of April 12, 2002, between Holding and Jim W. Nokes (incorporated by reference to Exhibit 10.2 to the Quarterly Report of ConocoPhillips on Form 10-Q for the quarterly period ended September 30, 2002; File No. 000-49987). | |
10.20 | Rabbi Trust Agreement dated December 17, 1999 (incorporated by reference to Exhibit 10.11 of Holding’s Form 10-K for the year ended December 31, 1999, File No. 001-14521). | |
10.20.1 | Amendment to Rabbi Trust Agreement dated February 25, 2002 (incorporated by reference to Exhibit 10.39.1 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002; File No. 000-49987). | |
10.21 | ConocoPhillips Directors’ Charitable Gift Program (incorporated by reference to Exhibit 10.40 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2003; File No. 000-49987). | |
10.22 | ConocoPhillips Matching Gift Plan for Directors and Executives (incorporated by reference to Exhibit 10.41 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2003; File No. 000-49987). | |
10.23.1 | Key Employee Deferred Compensation Plan of ConocoPhillips—Title I (incorporated by reference to Exhibit 10.23.1 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2005; File No. 001-32395). | |
10.23.2 | Key Employee Deferred Compensation Plan of ConocoPhillips—Title II (incorporated by reference to Exhibit 10.23.2 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2005; File No. 001-32395). |
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Exhibit | ||
Number | Description | |
10.24 | ConocoPhillips Key Employee Change in Control Severance Plan (incorporated by reference to Exhibit 10.1 of the Quarterly Report of ConocoPhillips on Form 10-Q for the quarterly period ended September 30, 2004; File No. 000-49987). | |
10.25 | ConocoPhillips Executive Severance Plan (incorporated by reference to Exhibit 10.25 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2005; File No. 001-32395). | |
10.25.1 | First and Second Amendments to the ConocoPhillips Executive Severance Plan (incorporated by reference to Exhibit 10 of the Quarterly Report of ConocoPhillips on Form 10-Q for the quarterly period ended March 31, 2007; File No. 001-32395). | |
10.26 | 2004 Omnibus Stock and Performance Incentive Plan of ConocoPhillips (incorporated by reference to Appendix C of ConocoPhillips’ Proxy Statement on Schedule 14A relating to the 2004 Annual Meeting of Shareholders; File No. 000-49987). | |
10.27 | Aircraft Time Sharing Agreement by and between James J. Mulva and ConocoPhillips (incorporated by reference to Exhibit 10 of the Quarterly Report of ConocoPhillips on Form 10-Q for the quarterly period ended June 30, 2007; File No. 001-32395). | |
10.28 | Form of Stock Option Award Agreement under the ConocoPhillips Stock Option and Stock Appreciation Rights Program. | |
10.29 | Form of Restricted Stock Unit Award Agreement under the ConocoPhillips Performance Share Program. | |
10.30 | Omnibus Amendments to certain ConocoPhillips employee benefit plans, adopted December 7, 2007. | |
12 | Computation of Ratio of Earnings to Fixed Charges. | |
21 | List of Subsidiaries of ConocoPhillips. | |
23 | Consent of Independent Registered Public Accounting Firm. | |
31.1 | Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934. | |
31.2 | Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934. | |
32 | Certifications pursuant to 18 U.S.C. Section 1350. |
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CONOCOPHILLIPS | ||||
February 21, 2008 | /s/ James J. Mulva | |||
James J. Mulva | ||||
Chairman of the Board of Directors, President and Chief Executive Officer | ||||
Signature | Title | |
/s/ James J. Mulva | Chairman of the Board of Directors, President and Chief Executive Officer (Principal executive officer) | |
/s/ John A. Carrig | Executive Vice President, Finance, and Chief Financial Officer (Principal financial officer) | |
/s/ Rand C. Berney | Vice President and Controller (Principal accounting officer) |
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/s/ Richard L. Armitage | Director | |
/s/ Richard H. Auchinleck | Director | |
/s/ Norman R. Augustine | Director | |
/s/ James E. Copeland, Jr. | Director | |
/s/ Kenneth M. Duberstein | Director | |
/s/ Ruth R. Harkin | Director | |
/s/ Charles C. Krulak | Director | |
/s/ Harold W. McGraw, III | Director | |
/s/ Harald J. Norvik | Director | |
/s/ William K. Reilly | Director | |
/s/ William R. Rhodes | Director | |
/s/ J. Stapleton Roy | Director | |
/s/ Bobby S. Shackouls | Director |
213
Table of Contents
/s/ Victoria J. Tschinkel | Director | |
/s/ Kathryn C. Turner | Director | |
/s/ William E. Wade, Jr. | Director |
214
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Exhibit | ||
Number | Description | |
2.1 | Agreement and Plan of Merger, dated as of November 18, 2001, by and among ConocoPhillips Company (formerly named Phillips Petroleum Company), ConocoPhillips (formerly named CorvettePorsche Corp.), P Merger Corp. (formerly named Porsche Merger Corp.), C Merger Corp. (formerly named Corvette Merger Corp.) and ConocoPhillips Holding Company (formerly named Conoco Inc.) (“Holding”) (incorporated by reference to Annex A to the Joint Proxy Statement/Prospectus included in ConocoPhillips’ Registration Statement on Form S-4; Registration No. 333-74798 (the “Form S-4”)). | |
2.2 | Agreement and Plan of Merger, dated as of December 12, 2005, by and among ConocoPhillips, Cello Acquisition Corp. and Burlington Resources Inc. (incorporated by reference to Exhibit 2.1 to the Current Report of ConocoPhillips on Form 8-K filed on December 14, 2005; File No. 001-32395). | |
3.1 | Restated Certificate of Incorporation of ConocoPhillips (incorporated by reference to Exhibit 3.1 to the Current Report of ConocoPhillips on Form 8-K filed on August 30, 2002; File No. 000-49987 (the “Form 8-K”)). | |
3.2 | Certificate of Designations of Series A Junior Participating Preferred Stock of ConocoPhillips (incorporated by reference to Exhibit 3.2 to the Form 8-K). | |
3.3 | By-Laws of ConocoPhillips, as amended on February 15, 2008 (incorporated by reference to Exhibit 99.1 to the Current Report of ConocoPhillips on Form 8-K filed on February 19, 2008; File No. 001-32395). | |
4.1 | Rights agreement, dated as of June 30, 2002, between ConocoPhillips and Mellon Investor Services LLC, as rights agent, which includes as Exhibit A the form of Certificate of Designations of Series A Junior Participating Preferred Stock, as Exhibit B the form of Rights Certificate and as Exhibit C the Summary of Rights to Purchase Preferred Stock (incorporated by reference to Exhibit 4.1 to the Form 8-K). | |
ConocoPhillips and its subsidiaries are parties to several debt instruments under which the total amount of securities authorized does not exceed 10 percent of the total assets of ConocoPhillips and its subsidiaries on a consolidated basis. Pursuant to paragraph 4(iii)(A) of Item 601(b) of Regulation S-K, ConocoPhillips agrees to furnish a copy of such instruments to the SEC upon request. | ||
10.1 | Shareholder Agreement, dated September 29, 2004, by and between LUKOIL and ConocoPhillips (incorporated by reference to Exhibit 99.2 of the Current Report of ConocoPhillips on Form 8-K filed on September 30, 2004; File No. 333-74798). | |
10.2 | 1986 Stock Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10.11 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002; File No. 000-49987). |
Table of Contents
Exhibit | ||
Number | Description | |
10.3 | 1990 Stock Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10.12 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002; File No. 000-49987). | |
10.4 | Annual Incentive Compensation Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10.13 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002; File No. 000-49987). | |
10.5 | Incentive Compensation Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10(g) to the Annual Report of ConocoPhillips Company on Form 10-K for the year ended December 31, 1999; File No. 1-720). | |
10.6 | Principal Corporate Officers Supplemental Retirement Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10(h) to the Annual Report of ConocoPhillips Company on Form 10-K for the year ended December 31, 1995; File No. 1-720). | |
10.7 | ConocoPhillips Supplemental Executive Retirement Plan (incorporated by reference to Exhibit 10.7 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2005; File No. 001-32395). | |
10.8 | Non-Employee Director Retirement Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10.18 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002; File No. 000-49987). | |
10.9 | Omnibus Securities Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10.19 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002; File No. 000-49987). | |
10.10 | Key Employee Missed Credited Service Retirement Plan of ConocoPhillips (incorporated by reference to Exhibit 10.10 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2005; File No. 001-32395). | |
10.11 | Phillips Petroleum Company Stock Plan for Non-Employee Directors (incorporated by reference to Exhibit 10.22 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002; File No. 000-49987). | |
10.12 | ConocoPhillips Key Employee Supplemental Retirement Plan (incorporated by reference to Exhibit 10.12 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2005; File No. 001-32395). | |
10.13.1 | Defined Contribution Make-Up Plan of ConocoPhillips—Title I (incorporated by reference to Exhibit 10.13.1 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2005; File No. 001-32395). | |
10.13.2 | Defined Contribution Make-Up Plan of ConocoPhillips—Title II (incorporated by reference to Exhibit 10.13.2 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2005; File No. 001-32395). |
Table of Contents
Exhibit | ||
Number | Description | |
10.14 | 2002 Omnibus Securities Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10.26 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002; File No. 000-49987). | |
10.15 | 1998 Stock and Performance Incentive Plan of ConocoPhillips (incorporated by reference to Exhibit 10.27 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002; File No. 000-49987). | |
10.16 | 1998 Key Employee Stock Performance Plan of ConocoPhillips (incorporated by reference to Exhibit 10.28 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002; File No. 000-49987). | |
10.17 | Deferred Compensation Plan for Non-Employee Directors of ConocoPhillips (incorporated by reference to Exhibit 10.17 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2005; File No. 001-32395). | |
10.18 | ConocoPhillips Form Indemnity Agreement with Directors (incorporated by reference to Exhibit 10.34 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002; File No. 000-49987). | |
10.19 | Letter Agreement, dated as of April 12, 2002, between Holding and Jim W. Nokes (incorporated by reference to Exhibit 10.2 to the Quarterly Report of ConocoPhillips on Form 10-Q for the quarterly period ended September 30, 2002; File No. 000-49987). | |
10.20 | Rabbi Trust Agreement dated December 17, 1999 (incorporated by reference to Exhibit 10.11 of Holding’s Form 10-K for the year ended December 31, 1999, File No. 001-14521). | |
10.20.1 | Amendment to Rabbi Trust Agreement dated February 25, 2002 (incorporated by reference to Exhibit 10.39.1 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002; File No. 000-49987). | |
10.21 | ConocoPhillips Directors’ Charitable Gift Program (incorporated by reference to Exhibit 10.40 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2003; File No. 000-49987). | |
10.22 | ConocoPhillips Matching Gift Plan for Directors and Executives (incorporated by reference to Exhibit 10.41 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2003; File No. 000-49987). | |
10.23.1 | Key Employee Deferred Compensation Plan of ConocoPhillips—Title I (incorporated by reference to Exhibit 10.23.1 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2005; File No. 001-32395). | |
10.23.2 | Key Employee Deferred Compensation Plan of ConocoPhillips—Title II (incorporated by reference to Exhibit 10.23.2 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2005; File No. 001-32395). |
Table of Contents
Exhibit | ||
Number | Description | |
10.24 | ConocoPhillips Key Employee Change in Control Severance Plan (incorporated by reference to Exhibit 10.1 of the Quarterly Report of ConocoPhillips on Form 10-Q for the quarterly period ended September 30, 2004; File No. 000-49987). | |
10.25 | ConocoPhillips Executive Severance Plan (incorporated by reference to Exhibit 10.25 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2005; File No. 001-32395). | |
10.25.1 | First and Second Amendments to the ConocoPhillips Executive Severance Plan (incorporated by reference to Exhibit 10 of the Quarterly Report of ConocoPhillips on Form 10-Q for the quarterly period ended March 31, 2007; File No. 001-32395). | |
10.26 | 2004 Omnibus Stock and Performance Incentive Plan of ConocoPhillips (incorporated by reference to Appendix C of ConocoPhillips’ Proxy Statement on Schedule 14A relating to the 2004 Annual Meeting of Shareholders; File No. 000-49987). | |
10.27 | Aircraft Time Sharing Agreement by and between James J. Mulva and ConocoPhillips (incorporated by reference to Exhibit 10 of the Quarterly Report of ConocoPhillips on Form 10-Q for the quarterly period ended June 30, 2007; File No. 001-32395). | |
10.28 | Form of Stock Option Award Agreement under the ConocoPhillips Stock Option and Stock Appreciation Rights Program. | |
10.29 | Form of Restricted Stock Unit Award Agreement under the ConocoPhillips Performance Share Program. | |
10.30 | Omnibus Amendments to certain ConocoPhillips employee benefit plans, adopted December 7, 2007. | |
12 | Computation of Ratio of Earnings to Fixed Charges. | |
21 | List of Subsidiaries of ConocoPhillips. | |
23 | Consent of Independent Registered Public Accounting Firm. | |
31.1 | Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934. | |
31.2 | Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934. | |
32 | Certifications pursuant to 18 U.S.C. Section 1350. |