The Daily Magic Formula Stock for 12/24/2008 is ConocoPhillips. According to the Magic Formula Investing Web Site, the ebit yield is 27% and the EBIT ROIC is 25-50%.
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ConocoPhillips is an international, integrated energy company. ConocoPhillips was incorporated in the state of Delaware on November 16, 2001, in connection with, and in anticipation of, the merger between Conoco Inc. (Conoco) and Phillips Petroleum Company (Phillips). The merger between Conoco and Phillips (the merger) was consummated on August 30, 2002, at which time Conoco and Phillips combined their businesses by merging with separate acquisition subsidiaries of ConocoPhillips.
Our business is organized into six operating segments:
â˘ Exploration and Production (E&P)â This segment primarily explores for, produces, transports and markets crude oil, natural gas and natural gas liquids on a worldwide basis.
â˘ Midstreamâ 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.
â˘ Refining and Marketing (R&M)â This segment purchases, refines, markets and transports crude oil and petroleum products, mainly in the United States, Europe and Asia.
â˘ LUKOIL Investmentâ 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.
â˘ Chemicalsâ 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).
â˘ Emerging Businessesâ This segment represents our investment in new technologies or businesses outside our normal scope of operations.
At December 31, 2007, ConocoPhillips employed approximately 32,600 people.
SEGMENT AND GEOGRAPHIC INFORMATION
For operating segment and geographic information, see Note 29âSegment Disclosures and Related Information, in the Notes to Consolidated Financial Statements, which is incorporated herein by reference.
EXPLORATION AND PRODUCTION (E&P)
At December 31, 2007, our E&P segment represented 68 percent of ConocoPhillipsâ total assets, while contributing 39 percent of net income. The E&P segment contributed 63 percent of net income in 2006. This decrease primarily reflects the impact of a $4,512 million (after-tax) non-cash impairment related to the expropriation of our oil interests in Venezuela. For additional information, see the âExpropriated Assetsâ section of Note 13âImpairments, in the Notes to Consolidated Financial Statements.
This segment explores for, produces, transports and markets crude oil, natural gas, and natural gas liquids on a worldwide basis. It also mines deposits of oil sands in Canada to extract the bitumen and upgrade it into a synthetic crude oil. Operations to liquefy and transport natural gas are also included in the E&P segment. 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.
On January 3, 2007, we closed on a business venture with EnCana Corporation to create an integrated North American heavy-oil business. The venture consists of two 50/50 business venturesâa Canadian upstream general partnership, FCCL Oil Sands Partnership, and a U.S. downstream limited liability company, WRB Refining LLC.
On March 31, 2006, we completed the acquisition of Burlington Resources Inc., an independent exploration and production company that held a substantial position in North American natural gas proved reserves, production and exploratory acreage.
The E&P segment does not include the financial results or statistics from our equity investment in the ordinary shares of LUKOIL, which are reported in a separate segment (LUKOIL Investment). As a result, references to results, production, prices and other statistics throughout the E&P segment exclude those related to our equity investment in LUKOIL. However, our share of LUKOIL is included in the supplemental oil and gas operations disclosures on pages 174 through 193.
The information listed below appears in the supplemental oil and gas operations disclosures and is incorporated herein by reference:
â˘ Proved worldwide crude oil, natural gas and natural gas liquids reserves.
â˘ Net production of crude oil, natural gas and natural gas liquids.
â˘ Average sales prices of crude oil, natural gas and natural gas liquids.
â˘ Average production costs per barrel-of-oil-equivalent.
â˘ Net wells completed, wells in progress, and productive wells.
â˘ Developed and undeveloped acreage.
In 2007, E&Pâs worldwide production, including its share of equity affiliatesâ production other than LUKOIL, averaged 1,857,000 barrels-of-oil-equivalent (BOE) per day, a decrease compared with the 1,936,000 BOE per day averaged in 2006. During 2007, 843,000 BOE per day were produced in the United States, an increase from 808,000 BOE per day in 2006. Production from our international E&P operations averaged 1,014,000 BOE per day in 2007, a decrease compared with 1,128,000 BOE per day in 2006. In addition, our Canadian Syncrude mining operations had net production of 23,000 barrels per day in 2007, compared with 21,000 barrels per day in 2006. The decrease in worldwide production was primarily due to expropriation of the companyâs Venezuelan oil interests, our exit from Dubai, and the effect of asset dispositions. We convert our natural gas production to BOE based on a 6:1 ratio: six thousand cubic feet of natural gas equals one barrel-of-oil-equivalent.
E&Pâs worldwide annual average crude oil sales price increased 11 percent, from $60.37 per barrel in 2006 to $67.11 per barrel in 2007. E&Pâs annual average worldwide natural gas sales price increased 1 percent, from $6.19 per thousand cubic feet in 2006 to $6.26 per thousand cubic feet in 2007.
In 2007, U.S. E&P operations contributed 46 percent of E&Pâs worldwide liquids production and 45 percent of natural gas production, compared with 40 percent and 44 percent in 2006, respectively.
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.
The Prudhoe Bay field is the largest oil field on Alaskaâs North Slope. It is the site of a large waterflood and enhanced oil recovery operation, as well as a gas processing plant that processes and re-injects natural gas into the reservoir. Our net crude oil production from the Prudhoe Bay field averaged 82,200 barrels per day in 2007, compared with 78,800 barrels per day in 2006, while natural gas liquids production averaged 17,900 barrels per day in 2007, compared with 16,700 barrels per day in 2006. The operator has undertaken a program to replace 16 miles of oil transit lines in the Prudhoe Bay field, with an expected completion date in the fourth quarter of 2008.
Prudhoe Bay satellite fields, including Aurora, Borealis, Polaris, Midnight Sun, and Orion, produced 11,900 net barrels per day of crude oil in 2007, compared with 12,900 net barrels per day in 2006. All Prudhoe Bay satellite fields produce through the Prudhoe Bay production facilities.
The Greater Point McIntyre Area (GPMA) primarily includes the Point McIntyre, Niakuk, and Lisburne fields. The fields within the GPMA generally produce through the Lisburne Production Center. Net crude oil production for GPMA averaged 12,700 barrels per day in 2007, compared with 11,400 barrels per day in 2006, while natural gas liquids production averaged 760 barrels per day in 2007, compared with 800 barrels per day in 2006. The bulk of GPMA production came from the Point McIntyre field, which is approximately seven miles north of the Prudhoe Bay field and extends into the Beaufort Sea.
Greater Kuparuk 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.
Our net crude oil production from the Kuparuk field averaged 54,100 barrels per day in 2007, compared with 59,900 barrels per day in 2006. The Kuparuk field is located about 40 miles west of Prudhoe Bay, and our ownership interest in the field is 55.3 percent.
Other fields within the Greater Kuparuk Area produced 11,500 net barrels per day of crude oil in 2007, compared with 13,400 net barrels per day in 2006, primarily from the Tarn, Tabasco, and Meltwater satellites. We have a 55.4 percent interest in Tarn and Tabasco and a 55.5 percent interest in Meltwater. The Greater Kuparuk Area also includes the West Sak heavy-oil field. Our net crude oil production from West Sak averaged 8,000 barrels per day in 2007, compared with 8,400 barrels per day in 2006. We have a 52.2 percent interest in this field.
Western North Slope
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.
The Alpine satellite fields, Nanuq and Fiord, began production in 2006. The fields produced at a net rate of 20,900 barrels of oil per day in 2007, compared with 4,300 barrels of oil per day in 2006. Peak production is expected in 2008. The oil is processed through the existing Alpine facilities.
We and our co-venturer are pursuing state, local and federal permits for additional Alpine satellite developments in the National Petroleum ReserveâAlaska (NPR-A), including the Qannik satellite field discovery announced in 2006. Plans include developing the field from an existing Alpine drill site. Production from Qannik is expected to commence by late 2008.
Cook Inlet Area
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.
We have a 100 percent interest in the North Cook Inlet field. Net production in 2007 averaged 66 million cubic feet per day of natural gas, compared with 88 million cubic feet per day in 2006. Production from the North Cook Inlet field is used to supply our share of gas to the Kenai LNG plant (discussed below).
Our interest in the Beluga River field is 33 percent. Net production averaged 35 million cubic feet per day of natural gas in 2007, compared with 49 million cubic feet per day in 2006. Gas from the Beluga River field is sold to local utilities and industrial consumers, and is used as back-up supply to the Kenai LNG plant.
We have a 70 percent interest in the Kenai LNG plant, which supplies LNG to two utility companies in Japan, utilizing two LNG tankers for transport. We sold 31.2 net billion cubic feet in 2007, compared with 41.3 net billion cubic feet in 2006. In January 2007, we and our co-venturer filed for a two-year extension of the Kenai LNG plantâs export license with the U.S. Department of Energy, which would extend the export license through March 31, 2011. In January 2008, the state of Alaska announced its unconditional support for the requested license extension as the result of an agreement between the state, us and our co-venturer. The agreement addresses future drilling in the Cook Inlet, sale of seismic and well data to third parties, terms of access to the LNG plant and a framework to negotiate state support of potential future export license extensions.
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.
A project to upgrade TAPSâ pump stations began in 2004. The phased project startup that began in the first quarter of 2007 is progressing, and two of the four pump stations ultimately targeted for upgrade are currently online. We have a 28.3 percent ownership interest in TAPS. We also have ownership interests in the Alpine, Kuparuk and Oliktok pipelines on the North Slope.
Our wholly owned subsidiary, Polar Tankers, Inc., manages the marine transportation of our Alaska North Slope production. Polar Tankers operates five ships in the Alaskan crude trade, chartering additional third-party-operated vessels as necessary. Beginning with the Polar Endeavour in 2001, Polar Tankers has brought into service five double-hulled tankers. The fifth and final tanker, the Polar Enterprise, began Alaska North Slope service in February 2007.
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 governorâs 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.
Lower 48 States
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.
We operate and hold a 75 percent interest in the Magnolia field in Garden Banks Blocks 783 and 784. Magnolia utilizes a tension-leg platform in 4,700 feet of water. Net production from Magnolia averaged 7,300 barrels per day of liquids and 13 million cubic feet per day of natural gas in 2007, compared with 17,800 barrels per day of liquids and 44 million cubic feet per day of natural gas in 2006.
We hold a 16 percent interest in the unitized Ursa field located in the Mississippi Canyon area. Ursa utilizes a tension-leg platform in approximately 3,900 feet of water. We also own a 16 percent interest in the Princess field, a northern, subsalt extension of the Ursa field. Our total net production from the unitized area in 2007 averaged 13,400 barrels per day of liquids and 16 million cubic feet per day of natural gas, compared with 14,400 barrels per day of liquids and 18 million cubic feet per day of natural gas in 2006.
The unitized K2 field is comprised of seven blocks in the Green Canyon area. In December 2006, the unit was expanded from two to seven blocks, and our working interest was reduced from 16.8 to 12.4 percent. Net production from K2 averaged 3,500 barrels per day of liquids and 2 million cubic feet per day of natural gas in 2007, compared with 2,150 barrels per day of liquids and 1 million cubic feet per day of natural gas in 2006.
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.
The San Juan Basin, located in northwest New Mexico and southwest Colorado, includes the majority of our coalbed methane (CBM) production. In addition, we continue to pursue development opportunities in three conventional formations in the San Juan Basin. Net production from the San Juan Basin averaged 49,800 barrels per day of liquids and 971 million cubic feet per day of natural gas in 2007, compared with 41,900 barrels per day of liquids and 851 million cubic feet per day of natural gas in 2006.
In addition to our CBM production from the San Juan Basin, we also hold CBM acreage positions in the Uinta Basin in Utah, the Black Warrior Basin in Alabama, and the Piceance Basin in Colorado.
Activities in 2007 primarily were centered on continued optimization and development of these assets. Combined production from all Lower 48 onshore fields in 2007 averaged a net 2,100 million cubic feet per day of natural gas and 157,000 barrels per day of liquids, compared with 1,900 million cubic feet per day of natural gas and 128,000 barrels per day of liquids in 2006.
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.
In 2007, E&P operations in Europe contributed 22 percent of E&Pâs worldwide liquids production, compared with 23 percent in 2006. Europe operations contributed 19 percent of natural gas production in 2007, compared with 21 percent in 2006. Our European assets are principally located in the Norwegian and U.K. sectors of the North Sea. We also have operations in the East Irish Sea and the Netherlands.
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.
During 2007, we continued to evaluate the optimal approach to redevelop the Eldfisk facilities. Our objective is to maintain and upgrade the facilities in order to continue production until the end of the license period in 2028.
We also have ownership interests in other producing fields in the Norwegian sector of the North Sea and Norwegian Sea, including a 24.3 percent interest in the Heidrun field, a 10.3 percent interest in the Statfjord field, a 23.3 percent interest in the Huldra field, a 1.6 percent interest in the Troll field, a 9.1 percent interest in the Visund field, a 6.4 percent interest in the Grane field, and a 2.4 percent interest in the Oseberg area. Our net production from these and other fields in the Norwegian sector of the North Sea and the Norwegian Sea averaged 67,300 barrels of liquids per day and 133 million cubic feet of natural gas per day in 2007, compared with 75,800 barrels of liquids per day and 147 million cubic feet of natural gas per day in 2006.
We and our co-venturers received approval from Norwegian authorities in 2004 for the Alvheim North Sea development. The development plans include a floating production storage and offloading (FPSO) vessel and subsea installations. Production from the field is targeted to commence in mid-2008. We have a 20 percent interest in the project.
In 2005, Norwegian and U.K. authorities approved the âStatfjord Late-Life Project,â a Statfjord-area gas recovery project which began production in October of 2007. We have a combined Norway/U.K. 15.2 percent interest in this project.
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.
In 2007, we were awarded three new North Sea exploration licenses in NorwayâPL404, PL399 and PL424.
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.
We have a 75 percent interest in the Brodgar field and an 83.5 percent interest in the Callanish field. First production from these two Britannia satellite fields is targeted for mid-2008.
We operate and hold a 36.5 percent interest in the Judy/Joanne fields, which together comprise J-Block. Additionally, the Jade field produces from a wellhead platform and pipeline tied to the J-Block facilities. We operate and hold a 32.5 percent interest in Jade. Together, these fields produced a net 14,300 barrels of liquids per day and 94 million cubic feet of natural gas per day in 2007, compared with 15,900 barrels of liquids per day and 133 million cubic feet of natural gas per day in 2006.
We have various ownership interests in 18 producing gas fields in the Rotliegendes and Carboniferous areas of the southern North Sea. Net production in 2007 averaged 276 million cubic feet per day of natural gas and 1,200 barrels of liquids per day, compared with 309 million cubic feet per day of natural gas and 1,200 barrels per day of liquids in 2006.
In 2006, the U.K. government approved a plan for the development of two new Saturn satellite fields in the Rotliegendes area of the southern North SeaâTethys and Mimas. We have a 25 percent interest in the Tethys field, and first production began in February 2007. We have a 35 percent interest in the Mimas field, and first production began in June 2007. These fields were producing a combined net 12 million cubic feet of natural gas per day at year-end 2007.
In 2007, the U.K. government approved a plan for the development of the Kelvin field in the Carboniferous area of the southern North Sea, in which we have a 50 percent operator interest. First production began in November 2007, and the field was producing at a net rate of approximately 54 million cubic feet of natural gas per day at year-end 2007.
We also have ownership interests in several other producing fields in the U.K. North Sea, including a 23.4 percent interest in the Alba field, a 40 percent interest in the MacCulloch field, and a 4.84 percent interest in the Statfjord field. Production from these and the other remaining fields in the U.K. sector of the North Sea averaged a net 20,500 barrels of liquids per day and 15 million cubic feet of natural gas per day in 2007, compared with 26,700 barrels of liquids per day and 34 million cubic feet of natural gas per day in 2006. We sold our interests in the Everest and Armada fields during the first quarter of 2007.
We have a 24 percent interest in the Clair field development in the Atlantic Margin. First production from Clair began in early 2005 from a conventional platform, with peak production expected in 2008. Net production in 2007 averaged 7,000 barrels of liquids per day and 1 million cubic feet of natural gas per day, compared with 6,000 barrels of liquids per day and 1 million cubic feet of natural gas per day in 2006.
We have a 100 percent ownership interest in the Millom, Dalton and Calder fields in the East Irish Sea, which are operated on our behalf by a third party. The natural gas produced from these fields is transported onshore, processed and sold into the U.K. spot market. Net production in 2007 averaged 36 million cubic feet of natural gas per day, compared with 38 million cubic feet of natural gas per day in 2006.
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.
We operate two terminals in the United Kingdom: the Teesside oil terminal, in which we have a 29.3 percent interest, and the Theddlethorpe gas terminal, in which we have a 50 percent interest. We also have a 100 percent ownership interest in the Rivers Gas Terminal in 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 SeaâP1423.
In the Atlantic Margin West of Shetland region, and adjacent to the Clair field, operations concluded on two appraisal wells, both of which encountered hydrocarbons. The appraisal program confirmed the viability of the Clair Ridge discovery, and development planning is under way.
In the southern North Sea, one appraisal well and two exploration wells were drilled. The appraisal well was successfully completed and began first production in 2007. Operations concluded on the two exploration wells, both of which encountered hydrocarbons. One of these exploration wells was successfully tested.
In the central North Sea, we concluded operations on one exploration well and one appraisal well. The exploration well was unsuccessful and expensed as a dry hole. The appraisal well encountered hydrocarbons. Operations continue on another exploration well, located adjacent to and east of the 2006
Jasmine gas and condensate discovery. Operations also continue on an appraisal well, which is located to the north of the 2006 Jackdaw discovery.
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.
In 2007, E&P operations in Canada contributed 7 percent of E&Pâs worldwide liquids production (excluding Syncrude production), compared with 5 percent in 2006. Canadian operations contributed 22 percent of E&Pâs worldwide natural gas production in 2007, compared with 20 percent in 2006.
MANAGEMENT DISCUSSION FROM LATEST 10K
Managementâs Discussion and Analysis is the companyâs analysis of its financial performance and of significant trends that may affect future performance. It should be read in conjunction with the financial statements and notes, and supplemental oil and gas disclosures. It contains forward-looking statements including, without limitation, statements relating to the companyâs plans, strategies, objectives, expectations, and intentions, that are made pursuant to the âsafe harborâ provisions of the Private Securities Litigation Reform Act of 1995. The words âintends,â âbelieves,â âexpects,â âplans,â âscheduled,â âshould,â âanticipates,â âestimates,â and similar expressions identify forward-looking statements. The company does not undertake to update, revise or correct any of the forward-looking information unless required to do so under the federal securities laws. Readers are cautioned that such forward-looking statements should be read in conjunction with the companyâs disclosures under the heading: âCAUTIONARY STATEMENT FOR THE PURPOSES OF THE âSAFE HARBORâ PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995,â beginning on page 92.
BUSINESS ENVIRONMENT AND EXECUTIVE OVERVIEW
ConocoPhillips is an international, integrated energy company. We are the third-largest integrated energy company in the United States, based on market capitalization. We have approximately 32,600 employees worldwide, and at year-end 2007 had assets of $178 billion. Our stock is listed on the New York Stock Exchange under the symbol âCOP.â
Our business is organized into six operating segments:
â˘ Exploration and Production (E&P) âThis segment primarily explores for, produces, transports and markets crude oil, natural gas, and natural gas liquids on a worldwide basis.
â˘ Midstream âThis 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.
â˘ Refining and Marketing (R&M) âThis segment purchases, refines, markets and transports crude oil and petroleum products, mainly in the United States, Europe and Asia.
â˘ LUKOIL Investment âThis 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.
â˘ Chemicals âThis 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).
â˘ Emerging Businesses âThis segment represents our investment in new technologies or businesses outside our normal scope of operations.
Crude oil and natural gas prices, along with refining margins, are the most significant factors in our profitability. Accordingly, our overall earnings depend primarily upon the profitability of our E&P and R&M segments. Crude oil and natural gas prices, along with refining margins, are driven by market factors over which we have no control. However, from a competitive perspective, there are other important factors we must manage well to be successful, including:
â˘ 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.
â˘ 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.
â˘ 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 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.
â˘ 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.
â˘ 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.
â˘ 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.
Our key performance indicators are shown in the statistical tables provided at the beginning of the operating segment sections that follow. These include crude oil, natural gas and natural gas liquids prices and production, refining capacity utilization, and refinery output.
Other significant factors that can affect our profitability include:
â˘ 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.
â˘ 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.
â˘ 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 âmixâ of pretax earnings within our global operations.
â˘ 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 âExpropriated Assetsâ section of Note 13âImpairments, 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 âOutlookâ 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 Kazakhstanâs 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.
The E&P segmentâs 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.
The Midstream segmentâs results are most closely linked to natural gas liquids prices. The most important factor on the profitability of this segment is the results from our 50 percent equity investment in DCP Midstream. During 2005, we increased our ownership interest in DCP Midstream from 30.3 percent to 50 percent, and we recorded a gain of $306 million, after-tax, for our equity share of DCP Midstreamâs sale of its general partnership interest in TEPPCO Partners, LP (TEPPCO). DCP Midstreamâs natural gas liquids prices increased 19 percent in 2007.
Refining margins, refinery utilization, cost control, and marketing margins primarily drive the R&M segmentâs results. Refining margins are subject to movements in the cost of crude oil and other feedstocks, and the sales prices for refined products, which are subject to market factors over which we have no control. Industry refining margins in the United States were stronger overall in comparison to 2006. Key factors contributing to the stronger refining margins in 2007 were lower industry refining utilization in the United States and higher distillate and gasoline demand. Wholesale marketing margins in the United States were lower in 2007, compared with those in 2006, as the market did not generally keep pace with the rising cost of crude oil.
The LUKOIL Investment segment consists of our investment in the ordinary shares of LUKOIL. In October 2004, we closed on a transaction to acquire 7.6 percent of LUKOILâs shares from the Russian government for approximately $2 billion. During the remainder of 2004, all of 2005 and 2006, we invested an additional $5.5 billion, bringing our equity ownership interest in LUKOIL to 20 percent by year-end 2006, based on issued shares. At December 31, 2007, our ownership interest was 20 percent based on issued shares and 20.6 percent based on estimated shares outstanding. We initiated this strategic investment to gain further exposure to Russiaâs resource potential, where LUKOIL has significant positions in proved reserves and production. We benefited from an increase in proved oil and gas reserves at an attractive cost, and our E&P segment should benefit from direct participation with LUKOIL in large oil projects in the northern Timan-Pechora province of Russia, and potential opportunities for participation in other developments.
The Chemicals segment consists of our 50 percent interest in CPChem. The chemicals and plastics industry is mainly a commodity-based industry where the margins for key products are based on market factors over which CPChem has little or no control. CPChem is investing in feedstock-advantaged areas in the Middle East with access to large, growing markets, such as Asia.
The Emerging Businesses segment represents our investment in new technologies or businesses outside our normal scope of operations. Activities within this segment are currently focused on power generation and 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. Some of these technologies may have the potential to become important drivers of profitability in future years.
MANAGEMENT DISCUSSION FOR LATEST QUARTER
Managementâs Discussion and Analysis contains forward-looking statements including, without limitation, statements relating to our plans, strategies, objectives, expectations, and intentions, that are made pursuant to the âsafe harborâ provisions of the Private Securities Litigation Reform Act of 1995. The words âintends,â âbelieves,â âexpects,â âplans,â âscheduled,â âshould,â âanticipates,â âestimates,â and similar expressions identify forward-looking statements. We do not undertake to update, revise or correct any of the forward-looking information. Readers are cautioned that such forward-looking statements should be read in conjunction with the disclosures under the heading: âCAUTIONARY STATEMENT FOR THE PURPOSES OF THE âSAFE HARBORâ PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995â beginning on page 54.
BUSINESS ENVIRONMENT AND EXECUTIVE OVERVIEW
Our Exploration and Production (E&P) segment had net income of $3,928 million in the third quarter of 2008, which accounted for 76 percent of our total net income in the quarter. This compares with E&P net income of $3,999 million in the second quarter of 2008, and $2,082 million in the third quarter of 2007.
E&P net income in the third quarter of 2008 was impacted by a decrease in commodity prices. Industry crude oil prices for West Texas Intermediate averaged $117.83 per barrel in the third quarter of 2008, or $6.15 per barrel lower than the second quarter of 2008, but $42.35 higher than in the same period a year earlier. Crude oil prices were influenced, among other factors, by growing concerns about financial markets and the slowing worldwide economyâs expected adverse impact on oil demand growth.
Industry natural gas prices for Henry Hub decreased during the third quarter of 2008 to $10.25 per million British thermal units (MMBTU), down $0.69 per MMBTU from the second quarter of 2008 but $4.09 higher than in the same period a year earlier. Natural gas prices trended lower during the third quarter due to rising domestic unconventional gas production in the face of slowing natural gas demand growth due to the weakening U.S. economy. Although production fell in September due to hurricane outages, natural gas storage still moved above the five year average, further influencing the downward move in the natural gas price.
Our Refining and Marketing (R&M) segment had net income of $849 million in the third quarter of 2008, compared with $664 million in the second quarter of 2008, and $1,307 million in the third quarter of 2007. The increase in net income from the previous quarter was primarily due to improved global realized marketing margins and lower turnaround costs, which were partially offset by lower refining volumes. The decrease in net income from the third quarter of 2007 reflects a lower net benefit from the companyâs asset rationalization efforts, the absence of a third-quarter 2007 German tax legislation benefit and lower refining volumes. These items were partially offset by improved global realized marketing margins.
RESULTS OF OPERATIONS
Unless otherwise indicated, discussion of results for the three- and nine-month periods ending September 30, 2008, is based on a comparison with the corresponding periods of 2007.
Income Statement Analysis
Sales and other operating revenues increased 52 percent in the third quarter of 2008 and 46 percent in the nine-month period, while purchased crude oil, natural gas and products increased 61 percent and 57 percent, respectively. These increases were mainly the result of higher petroleum product prices, and higher prices for crude oil, natural gas and natural gas liquids.
Equity in earnings of affiliates decreased 8 percent in the third quarter of 2008, mainly due to lower earnings from WRB Refining LLC and Chevron Phillips Chemical Company LLC (CPChem), partially offset by increased earnings from FCCL Oil Sands Partnership, DCP Midstream, LLC and LUKOIL. Equity in earnings of affiliates increased 17 percent in the nine-month period, reflecting improved results from LUKOIL, FCCL and DCP Midstream, partially offset by lower results from WRB and CPChem, as well as the absence of earnings from Hamaca and Petrozuata, our heavy-oil joint ventures expropriated by Venezuela in the second quarter of 2007.
Other income decreased 79 percent and 67 percent during the third quarter and first nine months of 2008, respectively. The decrease was primarily due to higher 2007 net gains on asset dispositions associated with asset rationalization efforts. In addition, the 2007 periods included a net benefit from the Alaska Quality Bank settlements.
Production and operating costs increased 17 percent and 16 percent during the third quarter and first nine months of 2008, respectively. Contributing to the increase were higher maintenance and well workover costs, as well as unfavorable foreign currency exchange impacts in E&P and higher turnaround and utility costs in R&M.
Depreciation, depletion and amortization increased 15 percent during the third quarter and 11 percent during the first nine months of 2008. The increases were mostly associated with our E&P segment, reflecting startup of new developments, foreign currency exchange impacts and changes in asset retirement obligations.
Impairmentâexpropriated assets reflects a second-quarter 2007 noncash impairment of $4,588 million before-tax related to the expropriation of our oil interests in Venezuela. For additional information, see the âExpropriated Assetsâ section of Note 13âImpairments, in our 2007 Annual Report on Form 10-K.
Taxes other than income taxes increased 23 percent and 21 percent during the third quarter and first nine months of 2008, respectively, primarily due to increased production taxes in our E&P segment, a significant portion of which relates to Alaska.
Interest and debt expense decreased 39 percent and 35 percent during both periods of 2008, respectively, primarily due to lower average interest rates, as well as impacts related to the Alaska Quality Bank settlements, which occurred in the third quarter of 2007. In addition, the decrease in the nine-month period was also affected by a lower average debt level.
The E&P segment reported net income of $3,928 million in the third quarter of 2008, compared with $2,082 million in the third quarter of 2007. Results for the third quarter of 2008 reflected higher crude oil, natural gas and natural gas liquids prices, partially offset by higher production taxes, higher operating costs, and lower volumes.
Net income for the E&P segment for the first nine months of 2008 was $10,814 million, compared with $2,007 million for the corresponding period of 2007. The nine-month 2007 period results included a noncash impairment of $4,588 million before-tax ($4,512 million after-tax) related to the expropriation of our oil interests in Venezuela. For additional information, see the âExpropriated Assetsâ section of Note 13âImpairments, in our 2007 Annual Report on Form 10-K. The increase in net income was attributed to the impact of the Venezuela impairment on our prior-year results and higher crude oil, natural gas and natural gas liquids prices. The increase was partially offset by higher production taxes, lower volumes, higher operating costs and a reduced net benefit from asset rationalization efforts. See the âBusiness Environment and Executive Overviewâ section for additional information on industry crude oil and natural gas prices.
Net income from our U.S. E&P operations increased 31 percent and 50 percent in the third quarter and first nine months of 2008, respectively, primarily due to higher crude oil, natural gas and natural gas liquids prices. The increases were partially offset by higher production taxes (mainly in Alaska), lower crude oil and natural gas volumes, higher operating costs and the absence of a net benefit from the Alaska Quality Bank settlements recorded in the third quarter of 2007.
U.S. E&P production on a barrel-of-oil-equivalent (BOE) basis averaged 736,000 BOE per day in the third quarter of 2008, a decrease of 10 percent from 821,000 BOE per day in the third quarter of 2007. The production decrease was primarily due to normal field decline, unplanned downtime mostly related to hurricane disruptions, and planned maintenance activities in Alaska.
Net income from our international E&P operations was $2,322 million in the third quarter of 2008, compared with $857 million in the third quarter of 2007. The increase was primarily attributed to higher crude oil, natural gas and natural gas liquids prices, as well as increased volumes. This was partially offset by higher depreciation expense.
Net income from our international E&P operations was $6,007 million in the first nine months of 2008, compared with a net loss of $1,189 million in the corresponding period of 2007. The increase in net income was attributed to the impact of the Venezuela impairment on our prior-year results and higher crude oil, natural gas and natural gas liquids prices. The increase was partially offset by higher depreciation expense, increased operating costs, lower volumes primarily due to the expropriation of our oil interests in Venezuela, and a lower net benefit from asset rationalization efforts.
International E&P production averaged 988,000 BOE per day in the third quarter of 2008, an increase of 8 percent from 911,000 BOE per day in the third quarter of 2007, primarily due to production from new developments in the United Kingdom, Russia, Indonesia, Norway and Canada, as well as less planned and unplanned downtime. This increase was partially offset by normal field decline and the impact of higher commodity prices on production sharing contracts.
The Midstream segment purchases raw natural gas from producers and gathers natural gas through an extensive network of pipeline gathering systems. The natural gas is then processed to extract natural gas liquids from the raw gas stream. The remaining âresidueâ gas is marketed to electrical utilities, industrial users and gas marketing companies. Most of the natural gas liquids are fractionatedâseparated into individual components like ethane, butane and propaneâand marketed as chemical feedstock, fuel or blendstock. The Midstream segment consists of our 50 percent equity investment in DCP Midstream, LLC, as well as our other natural gas gathering and processing operations, and natural gas liquids fractionation and marketing businesses, primarily in the United States and Trinidad.
Net income from the Midstream segment increased 66 percent and 62 percent in the third quarter and first nine months of 2008. The increase in both periods was primarily due to higher realized natural gas liquids prices, partially offset by higher costs, including increased fuel costs and repairs and maintenance work. In addition, the third quarter was negatively impacted by lower volumes, primarily related to hurricane impacts.
Thanks, Jen. Welcome to everybody on the call this morning to the third-quarter conference call for ConocoPhillips.
Joining me today is Jim Mulva, our Chairman and Chief Executive Officer; John Carrig, our President and Chief Operating Officer; and Sig Cornelius, our Senior Vice President of Finance and Chief Financial Officer.
The slide presentation that Jim Mulva will take you through today is intended to help you with your understanding of our financial and operating performance in the third quarter. And you can find this presentation on our website, conocophillips.com.
If you will turn to page two with me now, you will find our typical cautionary statement. That cautionary statement basically says that we will be making forward-looking statements in our presentation today, along with responses to your questions. And those forward-looking statements include our current view of expectations. Actual results can differ materially from what those expectations are and you can find those items that might cause expectations to be different than actual results in our SEC filings.
I will now turn the call over to Jim Mulva.
Welcome to our conference call. I am going now right to page three of our presentation, and as we normally do, we will go through these slides. You can see in the third quarter our income was $5.2 billion, which is $3.39 a share. We generated $7.5 billion of cash from operations, so our debt to capital ratio remained unchanged at 19%.
Now on our upstream business, we produced 2.17 million BOE a day and that includes 422,000 BOE per day from our LUKOIL investments segment. Downstream, our refinery utilization rate was 87%, that's down from last quarter and it is primarily due to the hurricane impacts.
We purchased $2.5 billion of our stock in the third quarter and that reduced our average shares outstanding to 1.528 billion shares; 116 million shares lower than the third quarter 2007 average.
We are pretty pleased with our strong operating performance when you give consideration to the negative impacts from the Gulf Coast hurricanes in the third quarter.
So I am moving now onto page four of the presentation, total company net income. Here you can see that third-quarter net income of $5.2 billion was $251 million lower than the prior quarter, which was $5.4 billion. That's shown on the gold bar on the left-hand side of the chart.
So if you move from the left to the right, you could see our contribution from asset rationalizations in the third quarter was $129 million higher than the second quarter. Then we had prices, margins, and other market impacts reduce third-quarter income by $13 million.
We had lower volumes, primarily from LUKOIL and refining and marketing segments. That reduced income of $232 million. I'll talk more about this when we go through the individual segments. There were a number of other items that in the aggregates had a negative impact of $135 million, and that's going to be covered more in subsequent slides.
I'll now go over to the fifth slide, which is total company cash flow. And if you start on the left gold bar, you could see that in the third quarter we generated $7.5 billion of cash from operations. So that along with our cash balance at the start of the quarter $787 million, we had $8.3 billion in cash, which was available for use during the third quarter.
As we move from left to right in the slide, you can see how we used this cash, which was $4 billion for our capital program, $710 million in dividends. We purchased about $2.5 billion of our shares. We ended with cash balance in the quarter of $1.1 billion.
So I'm moving to slide six, which is our total company cash flow for the first nine months of the year. And you could see the pie chart on the left, total cash available for the first three quarters was $20.8 billion, of which $19.5 billion or 94% was generated from operations, $1.3 billion or 6% mainly came from a combination of a slight amount of debt increase and proceeds from asset sales.
If you look at the pie chart on the right, you could see how we used $20.8 billion. We spent $11.2 billion on our capital program. We purchased $7.5 billion of our stock and paid $2.2 billion in dividends.
Now, I am moving on to slide seven, start talking that Exploration & Production. And as you are aware, we experienced both lower crude oil and natural gas prices in the third quarter. Our realized crude oil price at the third quarter was $112.19 a barrel or $5.82 a barrel lower than the second quarter.
Our realized natural gas price was $8.91 per Mcf, and that's $0.96 per Mcf lower than the prior quarter. And this is consistent with our previous guidance, as well as in our previous guidance, our production volumes were similar to last quarter and we are going to go through that in the next slide, which is page eight.
Third-quarter production from E&P segment was 1.75 million BOE a day, which is basically flat from the second quarter, as we progress from the left-hand side of the slide to the right. Although, our production was basically flat during the third quarter, we had the variances which are positive and some that were down.
So starting with the red bar on the left, you can see that production was 29,000 BOE a day lower in Alaska. This is primarily due to planned downtime and seasonality that we experience normally in this time of the year. Moving further to the right, our production in the Lower-48 was down 22,000 BOE a day, primarily due to the impact from the hurricanes.
In Norway, our production was 19,000 BOE a day higher, mainly from the startup of our participation in the Alvheim Field. In Russia, production was up 15,000 BOE a day and that's due to the startup of the YK Field in the Timan-Pechora area up in Siberia. In addition, the production in Canada was 13,000 BOE a day higher due to lower planned downtime.
Now it is important to note that even though production was higher in the UK, due to the startup of the Britannia satellite fields, that benefit was offset by planned and unplanned downtime and normal fuel decline. So when you add to this 1.75 million BOE a day, which is our E&P segment, and you add the equity share of LUKOIL's production, then our total company production totaled 2.17 million BOE a day in the third quarter.
Now, moving on to slide nine, talking about E&P net income. Our income in the third quarter was $3.9 billion, compared to about $4 billion in the second quarter, which is shown on the gold bar on the left. So we move from the left to the right, contribution from asset sales increased income to $126 million, and prices and other market impacts reduced income $250 million when you compare third quarter to second quarter.
Income has also improved $41 million compared to the previous quarter, as a result of just the impact of regional mix and divergence of effective tax rates on sales volumes.
Then there were other items which improved earnings $13 million. This includes positive impacts from foreign exchange and production taxes. That's offset partially by higher DD&A and operating costs, as well as, adjustments and abandonment obligations.
Now I'm going to move from the upstream to the downstream part of the company on slide 10. Our global realized marketing margins were higher in the third quarter. In the United States, the realized margin was $3.56 a barrel. Now that's up $2.33 a barrel from the second quarter and internationally $9.90 a barrel, which is up $0.85 a barrel compared to the second quarter.
In the US, the realized refining margin in the third quarter was $9.03 a barrel, that's $1.26 a barrel lower than the previous quarter. We had the benefit from higher clean product yields and improved margin for secondary products, but that was more than offset by the narrowing of the heavy crude oil differentials and inventory impacts related to the decrease in crude and refined product prices.
And then in addition, our ability to capture the higher Gulf Coast refining margins was impacted by the downtime in certain of our refineries associated with the hurricanes.
Turning to the international market, our realized refining margin was at $11.24 a barrel, that's $4.54, a barrel higher than the previous quarter and that's due to reduction in temporary inventory builds and we had better clean product yields. International margins continue to be though negatively impacted by the poor hydroskimming margins associated with primarily our Wilhelmshaven Refinery.
The domestic refining crude oil capacity utilization in the third quarter was 90%, that's 4% down from the second quarter, primarily due to the hurricane impacts. That impact was approximately 6% and was partially offset by lower turnaround activity.
The international crude oil capacity utilization was 75%, its down from 88% the prior quarter and the weak hydroskimming margins continued to impact the utilization at the company's Wilhelmshaven Refinery. We didn't run the Wilhelmshaven Refinery at all time periods through the third quarter, because of the margins that impacts utilization.
So worldwide, our Refining & Marketing crude oil capacity utilization rate was 86% compared to 93% in the prior quarter.
Now I am going to go to the next slide, page 11, which is downstream net income. Our third quarter income was $849 million, which is $185 million higher than the second quarter, which was $664 million. That is reflected in the gold bar on the left-hand side of the chart.
So if you move from the left to the right, you could see that prices, margin, other market impacts improved the income $207 million. This improvement is primarily attributed to higher global marketing margins. As previously mentioned, reduced volumes mainly as a result of the hurricanes, negatively impacted income a $128 million when you compare quarter-to-quarter.
We did experience lower operating costs, mainly due to the reduced turnaround activity and this increased income is $77 million. There are a lot of other items in the aggregate that improved the income by $29 million.
Now I'm moving on to page 12, the other segments. For financial reporting, page 12, our estimate of third quarter earnings from LUKOIL is $438 billion. This is lower than second-quarter estimate of $774 million. This is primarily due to lower volumes, prices, margin estimates. Net true up quarter-to-quarter was a positive $19 million.
The income from our midstream business was $173 million that compares to $162 million in the second quarter, which is due primarily to higher margins, marketing activity and offset somewhat by the hurricane impacts.
In Chemicals segment, our joint-venture contributed $46 million in income higher than the prior quarter of $18 million and primarily due to higher ethylene and polyethylene margins, offset somewhat by the impact of the hurricanes.
Our emerging businesses contributed $35 million in the third quarter that compares to $8 million in the second quarter. It reflects primarily the higher spark spreads and foreign exchange impacts.
Our corporate costs of $281 million were $95 million higher than the second quarter, primarily a result of foreign exchange impacts.
So now I'm going to move on to our metrics, E&P and downstream on page 13. On page 13, it shows E&P income and cash per BOE for the years 2003 through 2007. By the way when we show our peer group, what we are really looking at is competition against the five largest publicly traded companies, and that is Shell and BP, and Total and Chevron, and Exxon.
While we don't have peer data for the third quarter, obviously 2008, because we're the first one reporting, when you look at the third quarter, we would expect to be competitive on these metrics for E&P on an income and on cash per BOE.
Now, I'm going to go to slide 14. We have the same peer group, and looking at the metrics for downstream on an income and on cash per barrel, it shows for the years 2003 through 2007 we expect to be competitive on both of these metrics as we look at the third quarter results.
Now, I'm going to go to slide 15. Again the shaded areas are the same peer group, BP, Shell, Total, Exxon and Chevron. You can see that it reflects for a return on capital employed that no adjustments are made for purchase accounting. Adjustments made to the peer group reflect purchase accounting for them is attached to table three. So, our annualized ROCE for the third quarter of 2008 was 18%. That's compared to 17% for the first half.
Then we go to the last slide, 16, which is our outlook. We recently announced a plan to create long-term Australasian natural gas business with Origin focused on coalbed methane production and liquefied natural gas processing and sales and expect to close this here in the next week or so.
And then we recently announced the signing of an MOU with KazMunayGas in Kazakhstan and Mubadala from Abu Dhabi to negotiate terms for exploration and production in the N Block, the Nursultan block, offshore of Kazakhstan. This will be under a new subsoil use contract, and this is a new major exploration presence for ConocoPhillips in Kazakhstan.
On downstream, we received our government approval in early September to keep permits associated with expansion of the Wood River refinery. It's located at Roxana, Illinois, and that's jointly owned by our company and EnCana.
Then for the fourth quarter, we anticipate the company's E&P segment production will be higher in the fourth quarter than the third quarter. We expect our full year 2008 production to be slightly below 1.8 million BOE per day due to the impacts of the higher prices and the first three quarters of the year, higher prices and their impact on production sharing volumes. We experienced production loss associated with the hurricanes in the third quarter.
We expect our exploration expenses to be in the range of $400 million in the fourth quarter. Now, on downstream fourth quarter, our crude oil capacity utilization rate is expected to be in the mid-90% range. Our turnaround costs are expected to be about $75 million before tax.
Share repurchases have continued into the fourth quarter. Through the end of October, we will have purchased about $8 billion in 2008 under our previously announced program. Stock repurchase levels for the balance of the year will depend on the market conditions that we see in our capital commitments, and we're going to update the market in the early to mid part of December on the anticipated level of share repurchase that we expect for remainder of the fourth quarter.
Along with that announcement, we will announce what we have in mind for our 2009 capital program along with anticipated share repurchase plans for 2009.
So, that completes the prepared remarks, Gary. And so, I think we are ready now to take questions and comments from those participating in our conference call.
Okay, Jen, go ahead and queue up the questions please.