Dailystocks.com - Ticker-based level links to all the information for the Stocks you own. Portal for Daytrading and Finance and Investing Web Sites
DailyStocks.com
What's New
Site Map
Help
FAQ
Log In
Home Quotes/Data/Chart Warren Buffett Fund Letters Ticker-based Links Education/Tips Insider Buying Index Quotes Forums Finance Site Directory
OTCBB Investors Daily Glossary News/Edtrl Company Overviews PowerRatings China Stocks Buy/Sell Indicators Company Profiles About Us
Nanotech List Videos Magic Formula Value Investing Daytrading/TA Analysis Activist Stocks Wi-fi List FOREX Quote ETF Quotes Commodities
Make DailyStocks Your Home Page AAII Ranked this System #1 Since 1998 Bookmark and Share


Welcome!
Welcome to the investing community at DailyStocks where we believe we have some of the most intelligent investors around. While we have had an online presence since 1997 as a portal, we are just beginning the forums section now. Our moderators are serious investors with MBA and CFAs with practical experience wwell-versed in fundamental, value, or technical investing. We look forward to your contribution to this community.

Recent Topics
Article by DailyStocks_admin    (04-03-08 05:17 AM)

The Daily Warren Buffett Stock is COP. Berkshire Hathaway owns 17,508,700 shares. As of Dec 31,2007, this represents 2.25% percent of portfolio.

BUSINESS OVERVIEW

CORPORATE STRUCTURE
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:
• 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.
At December 31, 2007, ConocoPhillips employed approximately 32,600 people.

SEGMENT AND GEOGRAPHIC INFORMATION
For operating segment and geographic information, see Note 29—Segment 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 ConocoPhillips’ 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 “Expropriated Assets” section of Note 13—Impairments, 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 ventures—a 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:
• 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.
In 2007, E&P’s worldwide production, including its share of equity affiliates’ 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 company’s 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&P’s 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&P’s 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.
E&P—U.S. OPERATIONS
In 2007, U.S. E&P operations contributed 46 percent of E&P’s worldwide liquids production and 45 percent of natural gas production, compared with 40 percent and 44 percent in 2006, respectively.
Alaska
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 Alaska’s 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 Reserve—Alaska (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 plant’s 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.
Exploration
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.
Transportation
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 TAPS’ 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 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.
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.
Onshore
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.
Transportation
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.
Exploration
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.
E&P—EUROPE
In 2007, E&P operations in Europe contributed 22 percent of E&P’s 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.
Norway
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 “Statfjord Late-Life Project,” 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.
Transportation
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.
Exploration
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 Norway—PL404, PL399 and PL424.
United Kingdom
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 Sea—Tethys 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.
Transportation
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.
Exploration
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.
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.
Denmark
We sold our ownership interests in the Danish sector of the North Sea in 2007.
Netherlands
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.
Exploration
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.
E&P—CANADA
In 2007, E&P operations in Canada contributed 7 percent of E&P’s worldwide liquids production (excluding Syncrude production), compared with 5 percent in 2006. Canadian operations contributed 22 percent of E&P’s worldwide natural gas production in 2007, compared with 20 percent in 2006.

MANAGEMENT DISCUSSION FROM LATEST 10K

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 “COP.”
Our business is organized into six operating segments:
• Exploration and Production (E&P) —This segment primarily explores for, produces, transports and markets crude oil, natural gas, 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.

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:
• 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 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.

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:
• 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.

Segment Analysis
The E&P segment’s results are most closely linked to crude oil and natural gas prices. These are commodity products, the prices of which are subject to factors external to our company and over which we have no control. Industry crude oil prices for West Texas Intermediate were 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 segment’s 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 Midstream’s sale of its general partnership interest in TEPPCO Partners, LP (TEPPCO). DCP Midstream’s natural gas liquids prices increased 19 percent in 2007.
Refining margins, refinery utilization, cost control, and marketing margins primarily drive the R&M segment’s results. Refining margins are subject to movements in the cost of crude oil and other feedstocks, and the sales prices for refined products, 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 LUKOIL’s 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 Russia’s 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.

RESULTS OF OPERATIONS

2007 vs. 2006
The lower results in 2007 were primarily the result of:
• 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.
These items were partially offset by:
• 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.
2006 vs. 2005
The improved results in 2006, compared with 2005, were primarily the result of:
• 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.

These items were partially offset by:
• 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.
Income Statement Analysis
2007 vs. 2006
Equity in earnings of affiliates increased 21 percent in 2007. The increase reflects earnings from WRB Refining LLC and FCCL Oil Sands Partnership, our downstream and upstream business ventures with EnCana, formed in January 2007. Also, we had improved results from LUKOIL, reflecting higher estimated commodity prices and volumes, and an increase in our average equity ownership percentage. These increases were partially offset by lower earnings from Hamaca and Petrozuata, our heavy-oil joint ventures in Venezuela, primarily due to the expropriation of our interests during the second quarter of 2007. Additionally, CPChem reported lower earnings, primarily due to lower olefins and polyolefins margins.
Other income increased 188 percent during 2007, primarily due to:
• 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.
These increases were partially offset by the recognition in 2006 of recoveries on business interruption insurance claims attributable to losses sustained from hurricanes in 2005.
Exploration expenses increased 21 percent during 2007, primarily reflecting the amortization of unproved North American leaseholds obtained in the Burlington Resources acquisition and the impairment of an international exploration license. The increase also reflects higher geological and geophysical expenses and higher dry hole costs.
Depreciation, depletion and amortization (DD&A) increased 14 percent during 2007, primarily resulting from the addition of Burlington Resources’ assets in the E&P segment’s depreciable asset base for a full year in 2007 versus only nine months in 2006.
Impairment—expropriated assets reflects a non-cash impairment of $4,588 million before-tax related to the expropriation of our oil interests in Venezuela recorded in the second quarter of 2007. For additional information, see the “Expropriated Assets” section of Note 13—Impairments, in the Notes to Consolidated Financial Statements.
Impairments, which excludes the expropriation of our oil interests in Venezuela, decreased 35 percent during 2007, primarily due to the significant impairments recorded in 2006 of certain assets held for sale in the R&M segment, comprised of properties, plants and equipment, trademark intangibles and goodwill. See Note 13—Impairments, in the Notes to Consolidated Financial Statements, for additional information.

Interest and debt expense increased 15 percent during 2007, primarily due to the interest expense component of the Quality Bank settlements, as well as higher expense associated with the funding requirements for the business venture with EnCana.
Foreign currency transaction gains during 2007 primarily reflect the strengthening of the Canadian dollar against the U.S. dollar.
Our effective tax rate in 2007 was 49 percent, compared with 45 percent in 2006. The change in the effective rate for 2007 was primarily due to the impact of the expropriation of our oil interests in Venezuela in the second quarter of 2007. This impact was partially offset by the effect of income tax law changes enacted during 2007, and by a higher proportion of income in higher tax rate jurisdictions during 2006.

MANAGEMENT DISCUSSION FOR LATEST QUARTER

RESULTS OF OPERATIONS

Net income was $3,673 million in the third quarter of 2007, compared with $3,876 million in the third quarter of 2006. For the nine-month periods ended September 30, 2007 and 2006, net income was $7,520 million and $12,353 million, respectively.
The results for the third quarter of 2007 decreased primarily due to lower refining and marketing margins in the R&M segment, as well as lower equity earnings from our investment in LUKOIL. These decreases were partially offset by the net impact of asset rationalization efforts in our E&P and R&M segments, as well as the settlement of retroactive adjustments for crude oil quality differentials on Trans-Alaska Pipeline System shipments (Quality Bank). Additionally, the lower results were partially offset by the impact of changes in tax laws and higher crude oil prices in the E&P segment.

The lower results in the nine-month period were primarily the result of a complete impairment ($4,512 million after-tax) of our oil interests in Venezuela, resulting from their expropriation in June of 2007. The nine-month period of 2007 benefited from the net impact of asset rationalization efforts, as well as the Alaska Quality Bank settlements.
See the “Segment Results” section for additional information on our segment results.
Income Statement Analysis
Equity in earnings of affiliates increased 10 percent in the third quarter of 2007 and 13 percent in the nine-month period, reflecting results from WRB Refining LLC, our new downstream business venture with EnCana. The improved results for both 2007 periods were partially offset by lower equity earnings from:
• Hamaca and Petrozuata, our heavy-oil joint ventures in Venezuela, primarily due to the expropriation of our oil interests during the second quarter of 2007.

• Chevron Phillips Chemical Company LLC, our chemicals joint venture, due to lower olefins and polyolefins margins.

• DCP Midstream, our midstream joint venture, primarily due to higher operating costs and a positive tax adjustment included in 2006 results.
Earnings from our investment in LUKOIL were lower during the third quarter of 2007 due to an alignment of estimated net income to reported results, as well as higher estimated operating costs.
Other income increased significantly during the third quarter and nine-month period of 2007. The increase in both 2007 periods was primarily due to higher net gains on asset dispositions associated with asset rationalization efforts. In addition, other income increased due to the Alaska Quality Bank settlements. These increases were partially offset by the inclusion of a benefit related to business interruption insurance in 2006 results.
Exploration expenses increased during the first nine months of 2007, partially reflecting the amortization of unproved North American leaseholds obtained in the Burlington Resources acquisition and the impairment of an international exploration license. The increase also reflects higher dry hole costs and geological and geophysical expenses.
Depreciation, depletion and amortization (DD&A) increased 15 percent in the nine-month period of 2007, primarily resulting from the addition of Burlington Resources’ assets in the E&P segment’s depreciable asset base.
Impairment—expropriated assets reflects a non-cash impairment of $4,588 million before-tax related to the expropriation of our oil interests in Venezuela recorded in the second quarter of 2007. For additional information, see the “Expropriated Assets” section of Note 10—Impairments, in the Notes to Consolidated Financial Statements, which is incorporated herein by reference.
Interest and debt expense increased 27 percent in the third quarter of 2007 and 30 percent in the nine-month period. The increase in both 2007 periods is primarily due to the interest expense component of the Alaska Quality Bank settlements, as well as higher expense associated with the funding requirements for the business venture with EnCana. The increase in the third quarter of 2007 is partially offset by lower average debt levels compared with the third quarter of 2006.
Our effective tax rate for the third quarter and first nine months of 2007 was 42 percent and 53 percent, respectively, compared with 51 percent and 45 percent for the corresponding periods of 2006. The change in the effective tax rate for the third quarter of 2007 was primarily due to a tax rate increase enacted in the United Kingdom in the third quarter of 2006, the effect of asset rationalization efforts, and a tax rate decrease enacted in Germany in the third quarter of 2007. The change in the effective rate for the nine-month period was primarily due to the impact of the expropriation of our oil interests in Venezuela in the second quarter of 2007 (see Note 10—Impairments, in the Notes to Consolidated Financial Statements, for additional information). This impact was partially offset by a higher proportion of income in higher-tax-rate jurisdictions for the nine months of 2006.
Foreign currency transaction gains in the first nine months of 2007 primarily reflect the strengthening of the Canadian dollar against the U.S. dollar.

The E&P segment explores for, produces 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. At September 30, 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.
Net income for the E&P segment increased 9 percent in the third quarter of 2007, primarily due to the negative impact of changes in tax laws on the results for the third quarter of 2006. The increase also resulted from higher crude oil prices and a net benefit associated with asset rationalization efforts. In addition, the third quarter of 2007 was impacted by the Quality Bank settlements. These increases were partially offset by lower crude oil and natural gas production, as well as lower natural gas prices and higher operating costs.
Net income for the E&P segment was $2,007 million in the nine-month period of 2007, compared with net income of $7,761 million in the corresponding period of 2006. In the second quarter of 2007, we recorded a non-cash 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 “Expropriated Assets” section of Note 10—Impairments, in the Notes to Consolidated Financial Statements, which is incorporated herein by reference. The results for the nine-month period reflect this impairment of expropriated assets in Venezuela, as well as higher DD&A expense, operating costs and taxes, and lower realized crude oil and natural gas prices. These decreases were partially offset by a net benefit from asset rationalization efforts and net foreign exchange gains.
See the “Business Environment and Executive Overview” section for additional information on industry crude oil and natural gas prices.
U.S. E&P
Net income from our U.S. E&P operations increased 23 percent in the third quarter of 2007, primarily due to higher crude oil prices and sales volumes, as well as the Alaska Quality Bank settlements recorded in the third quarter of 2007. These increases were partially offset by lower natural gas prices and production, higher operating costs, and higher production taxes in Alaska.
Net income for the first nine months of 2007 decreased 8 percent, primarily due to higher operating costs, lower crude oil and natural gas prices, and higher production taxes in Alaska. These decreases were partially offset by higher gas production, as well as the Alaska Quality Bank settlements recorded in 2007. In addition, results included gains on the sale of assets in Alaska and the Gulf of Mexico.
U.S. E&P production on a barrel-of-oil-equivalent (BOE) basis averaged 821,000 BOE per day in the third quarter of 2007, a decrease of 3 percent from 846,000 BOE per day in the third quarter of 2006. Production was impacted in 2007 by normal field decline, offset slightly by less downtime in Alaska and new production from satellite fields in Alaska.

International E&P
Net income from our international E&P operations decreased 6 percent in the third quarter of 2007. The decrease in net income was primarily due to lower crude oil production and, to a lesser extent, lower natural gas production. In addition, the results reflect higher operating costs and a decrease in natural gas prices. These decreases were partially offset by a U.K. tax increase enacted in the third quarter of 2006, as well as higher crude oil prices and a net benefit from asset rationalization efforts.
Our international E&P operations reported a net loss of $1,189 million in the nine-month period of 2007, compared with net income of $4,285 million in the corresponding period of 2006. The results were impacted by the impairment of expropriated assets, lower crude oil production, and higher operating costs. These decreases were partially offset by a net benefit from asset rationalization efforts and higher natural gas production.
International E&P production averaged 911,000 BOE per day in the third quarter of 2007, a decrease of 22 percent from 1,167,000 BOE per day in the third quarter of 2006. Production was impacted by the expropriation of our Venezuelan oil projects, our exit from Dubai, planned and unplanned downtime in Australia and the North Sea, production sharing contract impacts, and the effect of asset dispositions. These decreases were slightly offset by production volumes from our upstream business venture with EnCana.
Estimated production for the first six months of 2007 at Petrozuata and Hamaca was 83,000 net barrels per day of crude oil after application of disproportionate OPEC restrictions imposed by the Venezuelan government for January through mid-May, 2007. The estimated net loss attributable to our Venezuelan operations for the first six months of 2007 was $4,393 million, including the $4,512 million (after-tax) impairment of our expropriated Venezuelan oil assets.
ConocoPhillips’ 40 percent interest in Block 2 of Plataforma Deltana, a natural gas region on Venezuela’s continental shelf, was not included in the Nationalization Decree. We continue to evaluate our opportunities for commercial development of Block 2.
In October of 2007, the president of Ecuador issued a decree 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. This decree was published into law effective October 18, 2007. We are currently evaluating the impact of this law on our operations.
Our Canadian Syncrude mining operations produced 27,000 barrels per day in the third quarter of 2007, compared with 23,000 barrels per day in the third quarter of 2006.

The Midstream segment purchases raw natural gas from producers and gathers natural gas through an extensive network of pipeline gathering systems. The natural gas is then processed to extract natural gas liquids from the raw gas stream. The remaining “residue” gas is marketed to electrical utilities, industrial users, and gas marketing companies. Most of the natural gas liquids are fractionated—separated into individual components like ethane, butane and propane—and marketed as chemical feedstock, fuel, or blendstock. The Midstream segment consists of our 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 decreased 38 percent in the third quarter of 2007 and 25 percent in the first nine months of 2007, primarily due to a positive tax adjustment included in the 2006 results. In addition, the results for both 2007 periods reflect a gradual shift in natural gas purchase contract terms that are more favorable to natural gas producers. Earnings from DCP Midstream were lower in both 2007 periods, primarily due to increased operating costs, mainly repairs, maintenance and asset integrity work. These decreases were slightly offset by higher natural gas liquids prices.

The R&M segment’s operations encompass refining crude oil and other feedstocks into petroleum products (such as gasoline, distillates and aviation fuels); buying, selling and transporting crude oil; and buying, transporting, distributing and marketing petroleum products. R&M has operations mainly in the United States, Europe and Asia Pacific.
Net income from the R&M segment decreased 11 percent in the third quarter of 2007, primarily due to lower realized refining and marketing margins and a business interruption insurance benefit recognized in the prior year. This decrease was further attributed to the net impact of our contribution of assets to WRB Refining LLC (WRB), our downstream business venture with EnCana. These decreases were largely offset by a net benefit from asset rationalization efforts and the impact of a tax law change in Germany.
Net income for the first nine months of 2007 increased 35 percent. This increase was primarily due to a net benefit from asset rationalization efforts, higher Gulf and East Coast refining volumes, higher realized refining and marketing margins, and the tax law change in Germany. The increase was partially offset by the net impact of the contribution of assets to WRB, as well as the business interruption insurance benefit recognized in the prior year.
U.S. R&M
Net income from our U.S. R&M operations decreased 40 percent in the third quarter of 2007, primarily due to lower refining and marketing margins. In addition, net income decreased due to the inclusion of a benefit related to business interruption insurance in the results for 2006, as well as the net impact of our contribution of assets to WRB. These decreases were slightly offset by a net benefit from asset rationalization efforts.
Net income for the first nine months of 2007 increased 15 percent, primarily due to higher Gulf and East Coast refining volumes, higher realized refining and marketing margins and a net benefit from asset rationalization efforts. The increase was partially offset by the net impact associated with the contribution of assets to WRB and the inclusion of a benefit related to business interruption insurance in 2006 results.
Our U.S. refining capacity utilization rate was 97 percent in the third quarter of 2007, a slight improvement from the third-quarter 2006 rate of 96 percent.
International R&M
Net income from our international R&M operations was $434 million in the third quarter of 2007 and $1,153 million in the first nine months of 2007, compared with net income of $20 million and $388 million, respectively, in the corresponding periods of 2006. The increases in both 2007 periods were primarily due to a net benefit from asset rationalization efforts, as well as a tax law change in Germany during the third quarter of 2007. The results for the first nine months of 2007 also benefited from a slight increase in refining and marketing margins. The increase in the third quarter of 2007 was slightly offset by lower refining and marketing margins.
Our international refining capacity utilization rate was 84 percent in the third quarter of 2007, compared with 89 percent in the third quarter of 2006. The Wilhelmshaven refinery in Germany was temporarily shut down during the month of August due to economic conditions.

SHARE THIS PAGE:  Add to Delicious Delicious  Share    Bookmark and Share



 
Username Comments
dailystock_admin 
Administrator
Posts: 249

Reg: 09-24-07

02-18-09 10:28 PM - Post#2092    
    In response to DailyStocks_admin

When to Buy Big Oil? 1/25/2009

Barron's takes a look at the large integrated oil companies that refine oil as well as explore for it and produce it. Dimitra DeFotis comments.

Watch Video

SHARE THIS PAGE:  Add to Delicious Delicious  Share    Bookmark and Share


Edited by dailystock on 02-18-09 10:28 PM. Reason for edit: No reason given.

 
Icon Legend Permissions Topic Options
You can comment on this topic
Print Topic

Email Topic

74679 Views