ConocoPhillips 10-K 2008
Documents found in this filing:
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Commission file number 001-32395
(Exact name of registrant as specified in its charter)
600 North Dairy Ashford
Houston, TX 77079
(Address of principal executive offices)
Registrants telephone number, including area code: 281-293-1000
Securities registered pursuant to Section 12(b) of the Act:
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
[x] Yes [ ] No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
[ ] Yes [x] No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. [x] Yes [ ] No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrants knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [x]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of large accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the Exchange Act. (Check one):
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). [ ] Yes [x] No
The aggregate market value of common stock held by non-affiliates of the registrant on June 29, 2007, the last business day of the registrants most recently completed second fiscal quarter, based on the closing price on that date of $78.50, was $127.7 billion. The registrant, solely for the purpose of this required presentation, had deemed its Board of Directors and grantor trusts to be affiliates, and deducted their stockholdings of 882,588 and 43,363,722 shares, respectively, in determining the aggregate market value.
The registrant had 1,561,506,369 shares of common stock outstanding at January 31, 2008.
Documents incorporated by reference:
Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held on May 14, 2008 (Part III)
TABLE OF CONTENTS
Unless otherwise indicated, the company, we, our, us, and ConocoPhillips are used in this report to refer to the businesses of ConocoPhillips and its consolidated subsidiaries. Items 1 and 2, Business and Properties, contain forward-looking statements including, without limitation, statements relating to the companys plans, strategies, objectives, expectations, and intentions, that are made pursuant to the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. The words forecasts, intends, believes, expects, plans, scheduled, targeted, should, goal, may, anticipates, estimates, and similar expressions identify forward-looking statements. The company does 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 companys disclosures under the heading: CAUTIONARY STATEMENT FOR THE PURPOSES OF THE SAFE HARBOR PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995, beginning on page 92.
Items 1 and 2. BUSINESS AND PROPERTIES
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:
At December 31, 2007, ConocoPhillips employed approximately 32,600 people.
SEGMENT AND GEOGRAPHIC INFORMATION
For operating segment and geographic information, see Note 29Segment 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 13Impairments, 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 venturesa 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:
In 2007, E&Ps 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 companys 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&Ps 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&Ps 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&Ps 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 Alaskas 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 ReserveAlaska (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 plants 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 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 governors 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&Ps 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 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.
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 NorwayPL404, 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 SeaTethys 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 SeaP1423.
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&Ps worldwide liquids production (excluding Syncrude production), compared with 5 percent in 2006. Canadian operations contributed 22 percent of E&Ps worldwide natural gas production in 2007, compared with 20 percent in 2006.
Oil and Gas Operations
Operations in western Canada encompass properties in Alberta, northeastern British Columbia and southern Saskatchewan. The properties in northern Alberta and northeastern British Columbia contain a mix of oil and natural gas, and are primarily accessible only in the winter. The properties in the central and foothills areas of Alberta mainly produce natural gas. The properties in southern Alberta and southern Saskatchewan produce natural gas and medium-to-heavy oil. Net production from these oil and gas operations in western Canada averaged 46,000 barrels per day of liquids and 1,106 million cubic feet per day of natural gas in 2007, compared with 50,000 barrels per day of liquids and 983 million cubic feet per day of natural gas in 2006.
In January 2007, we completed the sale of oil and natural gas producing properties and undeveloped acreage in western Canada, including oil properties in northern, central and southern Alberta and natural gas properties in southwestern Alberta and southeastern Saskatchewan. Combined, net production from these properties contributed approximately 18,000 BOE per day to our 2006 average production.
We have a 50 percent operating interest in the Surmont lease, located approximately 35 miles south of Fort McMurray, Alberta. The Surmont project uses an enhanced thermal oil recovery method called steam-assisted gravity drainage (SAGD). Steam injection began in the second quarter of 2007, and first production was achieved in the fourth quarter of 2007. Peak production is expected in 2014. We anticipate processing our share of the heavy oil produced as a feedstock in our owned and affiliated U.S. refineries.
EnCana Joint Venture
In October 2006, we announced a business venture with EnCana Corporation (EnCana), to create an integrated North American heavy-oil business. The transaction closed on January 3, 2007. The venture
consists of two 50/50 business ventures, a Canadian upstream general partnership, FCCL Oil Sands Partnership (FCCL), and a U.S. downstream limited liability company, WRB Refining LLC. We use the equity method of accounting for our investments in both entities.
FCCLs operating assets consist of the Foster Creek and Christina Lake SAGD bitumen projects, both located in the eastern flank of the Athabasca oil sands in northeast Alberta. EnCana is the operator and managing partner of FCCL. Our share of production was 26,800 barrels per day in 2007.
See the Refining and Marketing (R&M) section for information on WRB Refining LLC.
Consistent with our practice and in accordance with U.S. Securities and Exchange Commission guidelines, we use year-end prices for hydrocarbon reserve estimation for both our Surmont and FCCL properties. Bitumen prices can be seasonal, often reaching low levels at year end. Conversely, natural gas prices, a significant cost component of the development, can be seasonally high at year end. As a result, the ability to reflect proved reserves for SAGD bitumen projects can fluctuate because of the economics associated with this seasonality. For example, at year-end 2005, we could not reflect any proved reserves for Surmont. At year-end 2007, we were able to reflect proved reserves for Surmont and FCCL. However, it is reasonably possible that future year-end bitumen and natural gas price levels may result in the de-booking of some or all of our Surmont and FCCL proved reserves.
Parsons Lake/Mackenzie Gas Project
We are working with three other energy companies, as members of the Mackenzie Delta Producers Group, on the development of the Mackenzie Valley pipeline and gathering system, which is proposed to transport onshore gas production from the Mackenzie Delta in northern Canada to established markets in North America. We have a 75 percent interest in the Parsons Lake gas field, one of the primary fields in the Mackenzie Delta that would anchor the pipeline development. This pipeline project faces significant regulatory and construction cost issues; therefore, no definitive startup date can be estimated at this time.
We hold exploration acreage in four areas of Canada: the Western Canada Sedimentary Basin, offshore eastern Canada, the Mackenzie Delta/Beaufort Sea, and the Arctic Islands. Within the Western Canada Sedimentary Basin, we hold exploration acreage throughout the basin, including the foothills of western Alberta and eastern British Columbia. In the foothills, we drilled three exploratory wells in 2007two will be completed as producing wells and one will be tested and evaluated. During 2007, we also drilled three exploratory wells on acreage in the central Alberta Nisku project that resulted in one producer, while the remaining wells were expensed as dry holes. One successful exploration well was drilled in late 2007 on a recently defined Montney gas prospect in northeast British Columbia. Throughout the rest of western Canada, we participated in drilling approximately 48 lower risk exploratory wells near our producing assets. In the Mackenzie Delta, we were successful in acquiring additional offshore acreage following the 2004 Umiak discovery.
Other Canadian Operations
Syncrude Canada Ltd.
We own a 9 percent interest in the Syncrude Canada Ltd. (SCL) joint venture, created for the purpose of mining shallow deposits of oil sands, extracting the bitumen, and upgrading it into a light sweet crude oil called Syncrude. The primary plant and facilities are located at Mildred Lake, about 25 miles north of Fort McMurray, Alberta, with an auxiliary mining and extraction facility approximately 20 miles from the Mildred Lake plant. SCL, as operator of the joint venture, holds eight oil sands leases and the associated surface rights, of which our share is approximately 22,400 net acres. Our net share of production averaged 23,400 barrels per day in 2007, compared with 21,100 barrels per day in 2006.
The U.S. Securities and Exchange Commissions regulations define this project as mining-related and not part of conventional oil and gas operations. As such, Syncrude operations are not included in our proved oil and gas reserves or production as reported in our supplemental oil and gas information.
In 2007, E&P operations in South America contributed 5 percent of E&Ps worldwide liquids production, compared with 10 percent in 2006. This decrease primarily relates to the expropriation of our oil interests in Venezuela in the second quarter of 2007, as noted below. We also have interests in Ecuador, Argentina and Peru.
Petrozuata, Hamaca and Corocoro
On June 26, 2007, we announced we had been unable to reach agreement with respect to our migration to an empresa mixta structure mandated by the Nationalization Decree. In response, Petróleos de Venezuela S.A. (PDVSA) or its affiliates directly assumed the activities associated with and control over ConocoPhillips interests in the Petrozuata and Hamaca heavy-oil ventures and the offshore Corocoro development project.
In the second quarter of 2007, we recorded 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 13Impairments, in the Notes to Consolidated Financial Statements, which is incorporated herein by reference.
Plataforma Deltana Block 2
We have a 40 percent interest in Plataforma Deltana Block 2. The block is operated by our co-venturer and holds a gas discovery made by PDVSA in 1983. PDVSA has the option to enter the project with a 35 percent interest, which would proportionately reduce our interest in the project to 26 percent. In December 2007, the co-venturers presented the notification of commerciality and submitted a conditional development plan for governmental approval in compliance with license requirements. Several critical components required to progress an investment decision have not yet been defined by the government. Assuming timely resolution of these components, we expect a preliminary engineering study could be completed by late 2008, and a more significant developmental engineering study could be completed by late 2009.
In Ecuador, we hold a 42.5 percent interest in Block 7 and a 46.25 percent interest in Block 21. Net production in 2007 averaged 10,300 barrels of crude oil per day, compared with 6,800 barrels per day in 2006.
We have a 25.7 percent interest in the producing Sierra Chata concession in Argentina. Net production in 2007 averaged 19 million cubic feet of natural gas per day, compared with 17 million cubic feet per day in 2006.
We have varying ownership interests in six exploration blocks in Peru. In the first quarter of 2007, we acquired a 100 percent interest in Block 129. In Block 57, we drilled one exploration well that encountered hydrocarbons.
In 2007, E&P operations in the Asia Pacific area contributed 10 percent of E&Ps worldwide liquids production and 11 percent of natural gas production, compared with 11 percent and 12 percent in 2006, respectively.
We operate seven production sharing contracts (PSCs) in Indonesia. Production from Indonesia in 2007 averaged a net 330 million cubic feet per day of natural gas and 11,800 barrels per day of oil, compared with 319 million cubic feet per day of natural gas and 12,400 barrels per day of oil in 2006. Natural gas is sold under long-term contracts benchmarked to crude oil prices to markets in Indonesia and Singapore. Natural gas is also sold to the Indonesian domestic markets under U.S.-dollar-denominated, fixed-price contracts. Our assets are concentrated in two core areas: the West Natuna Sea and onshore South Sumatra.
We operate four offshore PSCs: South Natuna Sea Block B, Ketapang, Amborip VI, and Kuma. We sold our 25 percent non-operator interest in the Pangkah PSC, offshore East Java, in the third quarter of 2007.
The South Natuna Sea Block B PSC, in which we have a 40 percent interest, has two producing oil fields and 16 gas fields in various stages of development. In late 2006, gas production began from the Hiu gas field. In December 2007, crude oil and natural gas production began from the Kerisi field and development continued on the North Belut field.
We operate three onshore PSCs. Two are in South Sumatra: Corridor PSC and South Jambi B. We also operate Warim in Papua. In January 2007, we sold our 50 percent working interest in the Block A PSC in North Sumatra, and we sold our 60 percent interest in Corridor TAC in September 2007. In November 2007, the Sakakemang Joint Operating Body expired. We also transferred our non-operator interest in the Banyumas PSC in Java to our partners effective January 2008.
The Corridor PSC is located onshore South Sumatra and we have a 54 percent interest. We operate six oil fields and six natural gas fields, and supply natural gas from the Grissik and Suban gas processing plants to the Duri steamflood in central Sumatra and to markets in Singapore and Batam. The Suban Phase II project, an expansion of the existing Suban gas plant in the Corridor PSC, began producing in October 2007.
We have a 45 percent interest in the South Jambi B PSC, which is also located in South Sumatra. This shallow gas project supplies natural gas to Singapore.
We are a 35 percent owner of TransAsia Pipeline Company Pvt. Ltd., a consortium company, which has a 40 percent ownership in PT Transportasi Gas Indonesia, an Indonesian limited liability company, which owns and operates the Grissik to Duri, and Grissik to Singapore, natural gas pipelines.
In January 2007, we signed a new PSC agreement for a 60 percent interest in the Kuma block, which is located in Makassar Straits, between the islands of Kalimantan and Sulawesi. The acreage contains multiple exploration targets. A 3D survey will commence on the Kuma PSC in 2008. In addition, exploration work will continue on the Amborip VI PSC. Exploration wells are being planned for drilling in 2009 on both of these PSCs.
The Xijiang development consists of two fields located approximately 80 miles south of Hong Kong in the South China Sea. The facilities include two manned platforms and an FPSO vessel. Our combined net production of crude oil from the Xijiang fields averaged 7,900 barrels per day in 2007, compared with 10,100 barrels per day in 2006.
Production from the Peng Lai 19-3 field in Bohai Bay Block 11-05 averaged 10,500 net barrels of oil per day in 2007, compared with 13,800 net barrels per day in 2006. We have a 49 percent interest, with the remainder held by the China National Offshore Oil Corporation.
In 2005, we received government approval to develop Phase II of the Peng Lai 19-3 field, as well as concurrent development through the same facilities of the nearby Peng Lai 25-6 field. The first wellhead platform of Phase II was placed into operation in 2007. The FPSO vessel is scheduled to be installed in late 2008 with production beginning in early 2009.
We have a 24.5 percent interest in the Panyu field and a 100 percent interest in the Ba Jiao Chang (BJC) field. The Panyu development is an offshore project located approximately 36 miles southwest of the Xijiang development. The field produced 12,700 net barrels of oil per day in 2007, and 9,100 net barrels of oil per day in 2006. The BJC gas field is located onshore in Sichuan province. In 2007, net gas production averaged 11 million cubic feet per day, compared with 7 million cubic feet per day in 2006.
Our ownership interest in Vietnam is centered around the Cuu Long Basin in the South China Sea, and consists of two primarily oil producing blocks, four exploration blocks, and one gas pipeline transportation system.
We have a 23.3 percent interest in Block 15-1 in the Cuu Long Basin. Net production in 2007 was 13,700 barrels of oil per day, compared with 11,800 barrels per day in 2006. The oil is being processed through a one-million-barrel FPSO vessel. Development of the Su Tu Vang field continued in 2007. First oil production is targeted for late 2008. During 2007, preliminary engineering was completed on the Su Tu Den Northeast development. Appraisal of the Su Tu Trang and Su Tu Nau discoveries continued in 2007.
We have a 36 percent interest in the Rang Dong field in Block 15-2 in the Cuu Long Basin. All wellhead platforms produce into an FPSO vessel. Net production in 2007 was 8,500 barrels of liquids per day and 15 million cubic feet per day of natural gas, compared with 13,000 barrels per day and 21 million cubic feet per day in 2006.
We own a 16.3 percent interest in the Nam Con Son natural gas pipeline. This 244-mile transportation system links gas supplies from the Nam Con Son Basin to gas markets in southern Vietnam.
A successful appraisal well was drilled during 2007 in the Su Tu Nau field in the northeast area of Block 15-1. Further appraisal plans and potential development options for this field are currently being evaluated.
In 2007, we executed an agreement with a co-venturer to partially exchange interests in offshore Blocks 5-2 and 5-3. Within these two blocks, joint appraisal and development plans are currently under way for the Moc Tinh and Hai Thach discoveries.
We also continued to evaluate the potential of our interests in deepwater Blocks 133 and 134 in the Nam Con Son Basin.
Timor Sea and Australia
We operate and hold an ownership interest in the Bayu-Undan field located in the Timor Sea. In accordance with various governance agreements, a redetermination of the ownership interest in the Bayu-Undan Joint Venture, Darwin LNG Pty Ltd and the Bayu-Undan Pipeline Joint Venture was completed in 2007. The redetermination increased our controlling interest from 56.7 percent to 57.15 percent. The Bayu-Undan field was developed in two phases. Phase I was a gas-recycle project, where condensate and natural gas liquids were separated and removed and the dry gas was re-injected into the reservoir. This phase began production in February 2004, and averaged a net rate of 34,100 barrels of liquids per day in 2007, compared with 53,400 barrels per day in 2006.
Phase II involved the installation of a natural gas pipeline from the field to Darwin, Australia, and construction of an LNG facility located at Wickham Point, Darwin, to meet gross contracted sales of up to 3 million tons of LNG per year for a period of 17 years to customers in Japan. The LNG facility was completed and began full operation in 2006, with the first LNG cargo loaded in February 2006. Our net share of natural gas production from the Bayu-Undan field was 189 million cubic feet per day in 2007, compared with 200 million cubic feet per day in 2006. The natural gas production from the Bayu-Undan field is used by the Darwin LNG plant.
In 2007, Bayu-Undan and the Darwin LNG facility were shutdown for a 35-day period due to planned maintenance and facility improvements.
We have a 30 percent interest in the Greater Sunrise gas and condensate field located in the Timor Sea. In January 2006, agreement was reached between the governments of Australia and Timor-Leste concerning sharing of revenues from the anticipated development of the Greater Sunrise field. In February 2007, the government of Timor-Leste ratified the International Unitisation Agreement (IUA) and the governments of Timor-Leste and Australia both ratified the treaty on Certain Maritime Arrangements in the Timor Sea. The Australian government ratified the IUA in 2004.
Ratification of these two treaties created the legal and regulatory framework required by us and our co-venturers to reconsider development options for the Greater Sunrise fields. Key challenges to be resolved before significant funding commitments can be made include: ensuring the reservoir is adequately appraised, partner and government alignment on the development concept, and establishing fiscal stability arrangements. Immediate activity is focused on reprocessing seismic data to define the remaining appraisal program and commencing the development concept screening phase.
A cooperative field development agreement for the Athena/Perseus (WA-17-L) gas field, located offshore Western Australia, was executed in 2001. In 2007, our net share of production was 34 million cubic feet of natural gas per day, compared with 35 million cubic feet of natural gas per day in 2006. Early in the third quarter of 2007, abandonment of the Elang/Kakatua/Kakatua North fields commenced and production ceased.
We are the operator of the NT/P 69 and the NT/P 61 licenses, located offshore Northern Territory, Australia, which include the Caldita and Barossa discoveries. A Caldita appraisal well drilled in early 2007 encountered hydrocarbons, but it was expensed as a dry hole. Acquisition of seismic data concluded in 2007, and interpretation of this data will begin in 2008 to further evaluate these discoveries.
In 2007, we were awarded operatorship and a 60 percent interest in the Western Australia offshore exploration license WA-398-P, which is adjacent to existing ConocoPhillips acreage. The work program obligation includes 3D seismic and four exploration wells.
In the fourth quarter of 2007, we sold our interests in Western Australia offshore blocks WA-341-P, WA-343-P and WA-344-P.
We have interests in deepwater Blocks G and J, located off the east Malaysian state of Sabah. In late 2007, we and our co-venturers sanctioned the Gumusut-Kakap field development that incorporates the 2003 Gumusut discovery in Block J. Also in 2007, we participated in two exploration wells. We had a discovery in the Petai field in Block G. Petai and previous Block G discoveries are being evaluated as part of a broader area development plan. One Block J well was expensed as a dry hole.
In 2007, we signed a new PSC that includes both oil and gas rights for the Kebabangan field and three additional discoveries. Kebabangan is moving toward field development. The remaining discoveries are awaiting appraisal.
E&PMIDDLE EAST AND AFRICA
In 2007, E&P operations in the Middle East and Africa contributed 8 percent of E&Ps worldwide liquids production and 2 percent of natural gas production, compared with 10 percent and 3 percent in 2006, respectively.
Qatargas 3 is an integrated project, jointly owned by Qatar Petroleum (68.5 percent), ConocoPhillips (30 percent) and Mitsui & Co., Ltd. (1.5 percent). The project comprises upstream natural gas production facilities to produce approximately 1.4 billion gross cubic feet per day of natural gas from Qatars North field over the 25-year life of the project. The project also includes a 7.8-million-gross-ton-per-year LNG facility. The LNG will be shipped from Qatar in a fleet of LNG vessels, and is destined for sale primarily in the United States. The first LNG cargos are expected to be loaded from Qatargas 3 in 2009.
In the fourth quarter of 2007, we signed agreements with affiliates of ExxonMobil and Qatar Petroleum that provide for a 12.4 percent ownership interest in the Golden Pass LNG regasification facility and associated pipeline (Golden Pass). The facilities are currently being constructed on the Sabine-Neches Industrial Ship Channel northwest of Sabine Pass, Texas. Subject to the negotiation of definitive agreements, ConocoPhillips will also secure capacity rights in the Golden Pass LNG terminal and pipeline to manage a substantial portion of the LNG we will purchase from Qatargas 3. In addition to the United States, other market alternatives for Qatargas 3 LNG production are being evaluated.
In order to capture cost savings, Qatargas 3 is executing the development of the onshore and offshore assets as a single integrated project with Qatargas 4, a joint venture between Qatar Petroleum and Royal Dutch Shell plc. This includes the joint development of offshore facilities situated in a common offshore block in the North field, as well as the construction of two identical LNG process trains, and associated gas treating facilities for both the Qatargas 3 and Qatargas 4 joint ventures. Upon completion of the Qatargas 3 and Qatargas 4 projects, production from the LNG plant and associated facilities will be combined and shared.
In July 2007, we committed to sponsor a water sustainability center in the Qatar Science & Technology Park. The center will conduct applied research and testing in the industrial, municipal, and agricultural water sectors. The primary focus will be on removing contaminants from petroleum industry water.
In December 2007, ConocoPhillips and Qatar Petroleum International, a wholly owned subsidiary of Qatar Petroleum, announced the two companies signed a Memorandum of Understanding to pursue and develop international energy projects outside of Qatar.
Our oil concession offshore Dubai ended effective April 2007.
We have interests in three fields in Block 405a: a 65 percent operating interest in the Menzel Lejmat North (MLN) field; a 3.73 percent interest in the Ourhoud field; and a 16.9 percent interest in the EMK (El Merk) oil field unit. Net production from these fields averaged 10,800 barrels of crude oil per day in 2007, compared with 9,800 barrels per day in 2006.
ConocoPhillips holds a 16.33 percent interest in the Waha concessions in Libya. The concessions encompass nearly 13 million acres located in the Sirte Basin. Net crude oil production averaged 46,900 barrels per day in 2007, compared with 50,400 barrels per day in 2006, including 3,800 barrels per day associated with the complete recovery of our 1986 underlift position.
During the first quarter of 2007, we sold our 50 percent non-operated interest in a concession in Egypt that included the development of the Tao gas field and its associated facilities.
At year-end 2007, we were producing from four onshore Oil Mining Leases (OMLs), in which we have a 20 percent non-operator interest. Our net production from these leases was 19,300 barrels of liquids per day and 117 million cubic feet of natural gas per day in 2007, compared with 24,500 barrels per day and 138 million cubic feet per day in 2006. In 2007, we continued development of projects in the onshore OMLs to supply feedstock natural gas under a gas sales contract with Nigeria LNG Limited, which owns an LNG facility on Bonny Island.
We have a 20 percent interest in a 480-megawatt gas-fired power plant in Kwale, Nigeria. The plant came online in March 2005, and supplies electricity to Nigerias national electricity supplier. The plant consumes 68 million gross cubic feet per day of natural gas, including that sourced from our proved natural gas reserves in the OMLs.
During 2007, Brass LNG Limited (Brass LNG) continued to progress activities for a planned LNG facility to be constructed in Nigerias central Niger Delta. We have a 17 percent equity interest in Brass LNG.
During 2007, we made an onshore exploration discovery in OML 61, and the well is now producing. During the fourth quarter of 2007, we initiated drilling of an appraisal well in deepwater Oil Prospecting License (OPL) 214. The well encountered hydrocarbons, and drilling operations concluded in the first quarter of 2008. In the first quarter of 2007, we recorded a leasehold impairment related to OPL 248. In the second quarter of 2007, we relinquished our interest in OPL 318.
E&PRUSSIA AND CASPIAN
We have a 50 percent equity ownership interest in Polar Lights Company, a Russian limited liability company established in January 1992 to develop fields in the Timan-Pechora Basin in northern Russia.
Our net production from Polar Lights averaged 11,800 barrels of oil per day in 2007, compared with 12,100 barrels per day in 2006, and is included in equity affiliate production.
In June 2005, ConocoPhillips and LUKOIL created the OOO Naryanmarneftegaz (NMNG) joint venture to develop resources in the northern part of Russias Timan-Pechora province. We have a 30 percent ownership interest with a 50 percent governance interest in NMNG. We use the equity method of accounting for this joint venture. NMNG is working to develop the Yuzhno Khylchuyu (YK) field.
Production from the NMNG joint-venture fields is transported via pipeline to LUKOILs existing terminal at Varandey Bay on the Barents Sea and then shipped via tanker to international markets. LUKOIL intends to complete an expansion of the terminals oil-throughput capacity from 30,000 barrels per day to 240,000 barrels per day to accommodate production from the YK field.
In the Caspian Sea, we have a 9.26 percent interest in the Republic of Kazakhstans North Caspian Sea Production Sharing Agreement (NCSPSA), which includes the Kashagan field. Detailed design, procurement and construction activities continued on the Kashagan oil field development following approval by the Republic of Kazakhstan for the development plan and budget in 2004. The first phase of field development currently being executed includes the construction of artificial drilling islands with processing facilities and living quarters, and pipelines to carry production onshore. The initial production phase of the contract is for 20 years, with options to extend the agreement an additional 20 years. During 2007, the Republic of Kazakhstan triggered dispute proceedings under the NCSPSA following submission of a revised development plan and budget reflecting Kashagan cost increases and schedule delays. The international co-venturers signed a Memorandum of Understanding in January 2008, agreeing to the proportional dilution of their equity interest to allow the state-owned energy company, JSC NC KazMunaiGaz, to increase its ownership interest from 8.33 percent to 16.81 percent, effective January 1, 2008, subject to the completion of definitive agreements on dilution and other matters. As a result, our interest in the NCSPSA would be reduced from 9.26 percent to 8.40 percent, effective January 2008. In addition, a joint operating company, with significant involvement from the larger owners, will operate future phases of Kashagan. First production is expected at the end of 2011.
We have a 2.5 percent interest in the Baku-Tbilisi-Ceyhan (BTC) pipeline. This 1,760-kilometer pipeline transports crude oil from the Caspian region through Azerbaijan, Georgia and Turkey, for tanker loadings at the Mediterranean port of Ceyhan. The BTC pipeline became operational in mid-2006.
In 2007, appraisal and development concept studies continued for Kalamkas More, Kairan and Aktote. Testing operations on a Kairan appraisal well drilled in 2006 were successfully completed. Concept studies for development are under way for all three fields.
In late 2003, we signed an agreement with Freeport LNG Development, L.P. (Freeport LNG) to participate in its proposed LNG receiving terminal in Quintana, Texas. This agreement gave us 1 billion cubic feet per day of regasification capacity in the terminal and a 50 percent interest in the general partnership managing the venture. The terminal is designed to have capacity of 1.5 billion cubic feet per day. Freeport LNG received final approval in 2005 from the Federal Energy Regulatory Commission (FERC) to construct and operate the facility. Construction began in 2005, and commercial startup is expected in
2008. In 2005, we executed an option to secure 0.3 billion cubic feet per day of capacity in a subsequent expansion of the facility, which is subject to certain regulatory approvals and commercial decisions to proceed. In 2007, we released 0.1 billion cubic feet per day of our original 1 billion cubic feet per day regasification capacity to allow Freeport LNG more flexibility in marketing the remaining regasification capacity.
In order to deliver the natural gas from the Freeport terminal to market, we are constructing a 32-mile, 42-inch pipeline from the Freeport terminal to a point near Iowa Colony, Texas. Construction began in the first quarter of 2007 and is planned for completion in early 2008 to coincide with the Freeport terminal startup.
In 2007, we sold our 50 percent interest in Sound Energy Solutions, a company pursuing a proposed LNG regasification terminal in the Port of Long Beach, California. In the United Kingdom, we, along with the other Norsea Pipeline Limited shareholders, submitted applications in 2007 to obtain planning permission for an LNG regasification facility and combined heat and power plant at the existing Norsea Pipeline Limited oil terminal site at Teesside, United Kingdom. A decision on the applications is expected in 2008. We withdrew from a project to develop an LNG regasification terminal at the Port of Eemshaven in the Netherlands.
The Commercial organization optimizes the commodity flows of our E&P segment. This group markets our crude oil and natural gas production, with commodity buyers, traders and marketers in offices in the United States, the United Kingdom, Singapore, Canada and Dubai.
Natural Gas Pricing
Compared with the more global nature of crude oil commodity pricing, natural gas prices have historically varied more in different regions of the world. We produce natural gas from regions around the world that have significantly different supply, demand and regulatory circumstances, typically resulting in significantly lower average sales prices than in the Lower 48 region of the United States. Moreover, excess supply conditions that exist in certain parts of the world cannot easily serve to mitigate the relatively high-price conditions in the Lower 48 states and other markets because of a lack of infrastructure and because of the difficulties in transporting natural gas. We, along with other companies in the oil and gas industry, are planning long-term projects in regions of excess supply to install the infrastructure required to produce and liquefy natural gas for transportation by tanker and subsequent regasification in regions where market demand is strong, such as the Lower 48 states or certain parts of Asia, but where supplies are not as plentiful. Due to the significance of the overall investment in these long-term projects, the natural gas sales prices (to a third-party LNG facility) or transfer prices (to a company-owned LNG facility) in the areas of excess supply are expected to remain well below sales prices for natural gas that is produced closer to areas of high demand and which can be transferred to existing natural gas pipeline networks, such as in the Lower 48 states.
We have not filed any information with any other federal authority or agency with respect to our estimated total proved reserves at December 31, 2007. No difference exists between our estimated total proved reserves for year-end 2006 and year-end 2005, which are shown in this filing, and estimates of these reserves shown in a filing with another federal agency in 2007.
We sell crude oil and natural gas from our E&P producing operations under a variety of contractual arrangements, some of which specify the delivery of a fixed and determinable quantity. Our Commercial organization also enters into natural gas sales contracts where the source of the natural gas used to fulfill the contract can be the spot market, or a combination of our reserves and the spot market. Worldwide, we are contractually committed to deliver approximately 5.0 trillion cubic feet of natural gas and 115 million barrels of crude oil in the future, including approximately 1 trillion cubic feet related to the minority interests of consolidated subsidiaries. These contracts have various expiration dates through the year 2025. Although these delivery commitments could be fulfilled utilizing proved reserves in the United States, Canada, the Timor Sea, Nigeria, Indonesia, and the United Kingdom, we anticipate that some of them will be fulfilled with purchases in the spot market. A portion of our commitments relate to proved undeveloped reserves. See the disclosure on Proved Undeveloped Reserves in Managements Discussion and Analysis of Financial Condition and Results of Operations for information on the development of proved undeveloped reserves.
At December 31, 2007, our Midstream segment represented 1 percent of ConocoPhillips total assets, while contributing 4 percent of net income.
Our Midstream business is primarily conducted through our 50 percent equity investment in DCP Midstream, LLC. DCP Midstream is a joint venture with Spectra Energy.
The Midstream business purchases raw natural gas from producers and gathers natural gas through extensive pipeline gathering systems. The gathered natural gas is then processed to extract natural gas liquids. The remaining residue gas is marketed to electrical utilities, industrial users, and gas marketing companies. Most of the natural gas liquids are fractionatedseparated into individual components like ethane, butane and propaneand marketed as chemical feedstock, fuel, or blendstock. Total natural gas liquids extracted in 2007, including our share of DCP Midstream, was 211,000 barrels per day, compared with 209,000 barrels per day in 2006.
DCP Midstream markets a portion of its natural gas liquids to ConocoPhillips and Chevron Phillips Chemical Company LLC (a joint venture between ConocoPhillips and Chevron Corporation) under a supply agreement that continues until December 31, 2014. This purchase commitment is on an if-produced, will-purchase basis and so it has no fixed production schedule, but has had, and is expected over the remaining term of the contract to have, a relatively stable purchase pattern. Under this agreement, natural gas liquids are purchased at various published market index prices, less transportation and fractionation fees.
DCP Midstream is headquartered in Denver, Colorado. At December 31, 2007, DCP Midstream owned or operated 53 natural gas liquids extraction plants, 10 natural gas liquids fractionation plants, and its gathering and transmission systems included approximately 58,000 miles of pipeline. In 2007, DCP Midstreams raw natural gas throughput averaged 5.9 billion cubic feet per day, and natural gas liquids extraction averaged 363,000 barrels per day, compared with 6.0 billion cubic feet per day and 360,000 barrels per day in 2006. DCP Midstreams assets are primarily located in the following producing regions: Rocky Mountains, Midcontinent, Permian, East Texas/North Louisiana, South Texas, Central Texas, and the Gulf Coast.
Outside of DCP Midstream, our U.S. natural gas liquids business included the following assets as of December 31, 2007:
We also own a 39 percent equity interest in Phoenix Park Gas Processors Limited (Phoenix Park), a joint venture primarily with the National Gas Company of Trinidad and Tobago Limited. Phoenix Park processes gas in Trinidad and markets natural gas liquids throughout the Caribbean and into the U.S. Gulf Coast. Its facilities include a 1.35-billion-cubic-feet-per-day gas processing plant and a 70,000-barrels-per-day natural gas liquids fractionator. Our share of natural gas liquids extracted averaged 7,800 barrels per day in 2007, compared with 6,400 barrels per day in 2006. Our share of fractionated liquids averaged 12,800 barrels per day in 2007, compared with 12,700 barrels per day in 2006.
ConocoPhillips was a party to a service contract related to the gathering, processing and transporting of natural gas in the Deir Ez Zor region of eastern Syria with the Syrian Petroleum Company that expired December 31, 2005. In 2006, we ended our presence in Syria and have no continuing operations or personnel in Syria. During 2007, we worked toward the resolution of certain immaterial claims that remain outstanding associated with our former operations there. Additionally, as part of our global crude oil supply and trading operations and consistent with applicable laws and policies of the United States and other countries in which we operate, we have purchased, and may continue to purchase, immaterial amounts of Syrian crude oil and blendstocks as feedstock for our global refining operations.
REFINING AND MARKETING (R&M)
At December 31, 2007, our R&M segment represented 21 percent of ConocoPhillips total assets, while contributing 50 percent of net income. The R&M segment contributed 29 percent of net income in 2006. R&Ms percent of consolidated net income in 2007 was higher than normal due to a significant impairment recorded in the E&P segment.
R&M 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 in the United States, Europe and Asia Pacific. The R&M segment does not include the results or statistics from our equity investment in LUKOIL, which are reported in a separate segment (LUKOIL Investment).
The Commercial organization optimizes the commodity flows of our R&M segment. This organization procures feedstocks for R&Ms refineries, facilitates supplying a portion of the gas and power needs of the R&M facilities, supplies petroleum products to our marketing operations, and markets petroleum products directly to third parties. Commercial has buyers, traders and marketers in offices in the United States, the United Kingdom, Singapore, Canada and Dubai.
At December 31, 2007, we owned or had an interest in 12 crude oil refineries in the United States, having an aggregate crude oil throughput capacity of 2,037,000 barrels per day net to ConocoPhillips. We are the operator of all 12 refineries.
East Coast Region
The Bayway refinery is located on the New York Harbor in Linden, New Jersey. The refinery has a crude oil processing capacity of 238,000 barrels per day, and processes mainly light, low-sulfur crude oil. Crude oil is supplied to the refinery by tanker, primarily from the North Sea, Canada and West Africa. The refinery produces a high percentage of transportation fuels, such as gasoline, ultra-low-sulfur diesel and jet fuel. Other products include petrochemical feedstocks, home heating oil and residual fuel oil. The facility distributes its refined products to East Coast customers by pipeline, barge, railcar and truck. The complex also includes a 775-million-pound-per-year polypropylene plant.
The Trainer refinery is located on the Delaware River in Trainer, Pennsylvania. The refinery has a crude oil processing capacity of 185,000 barrels per day, and processes mainly light, low-sulfur crude oil. The Bayway and Trainer refineries are operated in coordination with each other by sharing crude oil cargoes and often moving feedstocks between the facilities. Trainer receives a majority of its crude oil by tanker from West Africa, Canada and the North Sea. The refinery produces a high percentage of transportation fuels, such as gasoline, diesel and jet fuel. Other products include home heating oil, residual fuel oil and liquefied petroleum gas. Refined products are primarily distributed to customers in Pennsylvania, New York and New Jersey by pipeline, barge, railcar and truck.
Gulf Coast Region
The Alliance refinery is located on the Mississippi River in Belle Chasse, Louisiana. The refinery has a crude oil processing capacity of 247,000 barrels per day, and processes mainly light, low-sulfur crude oil. Alliance receives domestic crude oil from the Gulf of Mexico via pipeline, and foreign crude oil from the North Sea and West Africa via pipeline connected to the Louisiana Offshore Oil Port. The refinery produces a high percentage of transportation fuels, such as gasoline, diesel and jet fuel. Other products include home heating oil, petrochemical feedstocks and anode petroleum coke. The majority of the refined products are distributed to customers in the southeastern and eastern United States through major common-carrier pipeline systems and by barge.
Lake Charles Refinery
The Lake Charles refinery is located in Westlake, Louisiana. The refinery has a crude oil processing capacity of 239,000 barrels per day, and processes mainly heavy, high-sulfur crude oil, but also processes low-sulfur and acidic crude oil. The refinery receives domestic and foreign crude oil, with a majority of its foreign crude oil being heavy Venezuelan and Mexican crude oil, both delivered via tanker. The refinery produces a high percentage of transportation fuels, such as gasoline, off-road diesel and jet fuel, along with home heating oil. The majority of its refined products are distributed to customers by truck, railcar, barge or major common-carrier pipelines to customers in the southeastern and eastern United States. In addition, refined products can be sold into export markets through the refinerys marine terminal.
The Lake Charles facilities include a specialty coker and calciner that manufacture graphite petroleum coke, which is supplied to the steel industry. The coker and calciner also provide a substantial increase in light oils production by breaking down the heaviest part of the crude barrel to allow additional production of diesel fuel and gasoline.
The Sweeny refinery is located in Old Ocean, Texas. The refinery has a crude oil processing capacity of 247,000 barrels per day. The refinery processes both heavy, high-sulfur crude oil, the majority of which is sourced from Venezuela, and light, low-sulfur crude oil. The refinery primarily receives crude oil via tankers through its 100-percent-owned and jointly owned terminals on the Gulf Coast, including a deepwater terminal at Freeport, Texas. The refinery produces a high percentage of transportation fuels, such as gasoline, diesel and jet fuel. Other products include home heating oil, petrochemical feedstocks
and petroleum (fuel) coke. Refined products are distributed throughout the midwest and southeast United States by pipeline, barge, railcar and truck.
ConocoPhillips has a 50 percent interest in Merey Sweeny, L.P., a limited partnership that owns a 70,000-barrel-per-day delayed coker and related facilities at the Sweeny refinery that produce fuel-grade petroleum coke. PDVSA, which owns the other 50 percent interest, supplies the refinery with heavy, high-sulfur crude oil. We are the operator and managing partner.
EnCana Joint Venture
In October 2006, we announced a business venture with EnCana Corporation (EnCana), to create an integrated North American heavy-oil business. The transaction closed on January 3, 2007. The venture consists of two 50/50 business ventures, a Canadian upstream general partnership, FCCL Oil Sands Partnership, and a U.S. downstream limited liability company, WRB Refining LLC (WRB). We use the equity method of accounting for our investments in both entities.
WRB consists of the Wood River and Borger refineries, located in Roxana, Illinois and Borger, Texas, respectively. We are the operator and managing partner of WRB. The joint venture has expanded the processing capability of heavy Canadian crude to 95,000 barrels per day from 60,000 barrels per day with the startup of a new coker at Borger. With the completion of the Wood River coker and refinery expansion project, anticipated in 2011, we expect the capability to grow to 225,000 barrels per day. Further expansion of both Wood River and Borger are expected to provide the ultimate capability to process 550,000 barrels per day. For the Wood River refinery, operating results are shared 50/50. For the Borger refinery, we were entitled to 85 percent of the operating results in 2007, with our share decreasing to 65 percent in 2008, and 50 percent in all years thereafter.
See the Exploration and Production (E&P) section for additional information on the upstream venture.
Wood River Refinery
The Wood River refinery is located on the east side of the Mississippi River in Roxana, Illinois. It has a crude oil processing capacity of 306,000 barrels per day, and our net share of this capacity at December 31, 2007, was 153,000 barrels per day. The refinery processes a mix of both light, low-sulfur and heavy, high-sulfur crude oil. The refinery receives domestic and foreign crude oil by various pipelines. The refinery produces a high percentage of transportation fuels, such as gasoline, diesel and jet fuel. Other products include petrochemical feedstocks and asphalt. Through an off-take agreement, a significant portion of its gasoline and diesel is sold to a third party for delivery via pipelines into the upper Midwest, including the Chicago, Illinois, and Milwaukee, Wisconsin, metropolitan areas. The remaining refined products are distributed to customers in the Midwest by pipeline, truck, barge and railcar.
In early 2007, the refinery completed the construction and startup of a facility utilizing proprietary sulfur removal technology for the production of low-sulfur gasoline.
The Borger refinery is located in Borger, Texas, and the complex includes a natural gas liquids fractionation facility. The crude oil processing capacity of the refinery is 146,000 barrels per day, and the natural gas liquids fractionation capacity is 45,000 barrels per day. Our net share of the crude oil capacity at December 31, 2007, was 124,000 barrels per day. The refinery processes mainly light, high-sulfur and medium, high-sulfur crude oil. It receives crude oil and natural gas liquids feedstocks through pipelines from West Texas, the Texas Panhandle and Wyoming. The Borger refinery also receives foreign crude oil via pipeline. The refinery produces a high percentage of transportation fuels, such as gasoline, diesel and jet fuel, along with a variety of natural gas liquids and solvents. Refined products are transported via pipelines from the refinery to West Texas, New Mexico, Colorado, and the Midcontinent region.
In the second quarter of 2007, construction was completed on a 25,000-barrel-per-day coker and a new vacuum unit along with revamps of heavy oil and distillate hydrotreaters. These projects allow the refinery to comply with clean fuel regulations for ultra-low-sulfur diesel and low-sulfur gasoline, as well as comply with required reductions of sulfur dioxide emissions. Additional project benefits include improved operating performance by adding additional upgrading capability, improved utilization, and the capability to process heavy Canadian crude oil.
Ponca City Refinery
The Ponca City refinery is located in Ponca City, Oklahoma. The refinery has a crude oil processing capacity of 187,000 barrels per day. The refinery processes a mixture of light, medium and heavy crude oil. Most of the crude processed is received by pipeline from the Gulf of Mexico, Oklahoma, Kansas, Texas and Canada. The refinery produces high ratios of low-sulfur gasoline and ultra-low-sulfur diesel fuel from crude oil. Finished petroleum products are primarily shipped by company-owned and common carrier pipelines to markets throughout the Midcontinent region.
West Coast Region
The Billings refinery is located in Billings, Montana. The refinery has a crude oil processing capacity of 58,000 barrels per day, and processes a mixture of Canadian heavy, high-sulfur crude oil, plus domestic high-sulfur and low-sulfur crude oil, all delivered by pipeline. A delayed coker converts heavy, high-sulfur residue into higher value light oils. The refinery produces a high percentage of transportation fuels, such as gasoline, diesel and aviation fuels, as well as fuel-grade petroleum coke. Finished petroleum products from the refinery are delivered by pipeline, railcar and truck. Pipelines transport most of the refined products to markets in Montana, Wyoming, Utah and Washington.
The Ferndale refinery is located on Puget Sound in Ferndale, Washington. During 2007, the refinery completed a project to expand the crude unit capacity by replacing piping and modifying various equipment. This project increased capacity by 4,000 barrels per day to 100,000 barrels per day, effective July 1, 2007. The refinery primarily receives light, low-sulfur crude oil from the Alaskan North Slope, as well as crude oil from Canada. The refinery produces transportation fuels such as gasoline and diesel. Other products include residual fuel oil supplying the northwest marine transportation market. Most refined products are distributed by pipeline and barge to major markets in the northwest United States.
Los Angeles Refinery
The Los Angeles refinery is composed of two linked facilities located about five miles apart in Carson and Wilmington, California. Carson serves as the front-end of the refinery by processing crude oil, and Wilmington serves as the back-end by upgrading products. The refinery has a crude oil processing capacity of 139,000 barrels per day, and processes mainly heavy, high-sulfur crude oil. The refinery receives domestic crude oil via pipeline from California, and both foreign and domestic crude oil by tanker through a third-party terminal in the Port of Long Beach. The refinery produces a high percentage of transportation fuels, such as gasoline, diesel and jet fuel. Other products include fuel-grade petroleum coke. The refinery produces California Air Resources Board (CARB) gasoline by blending ethanol to meet government-mandated oxygenate requirements. Refined products are distributed to customers in Southern California, Nevada and Arizona by pipeline and truck.
San Francisco Refinery
The San Francisco refinery is composed of two linked facilities located about 200 miles apart. The Santa Maria facility is located in Arroyo Grande, California, about 200 miles south of San Francisco, while the Rodeo facility is in the San Francisco Bay area. The refinery has a crude oil processing capacity of 120,000 barrels per day. The refinery processes mainly heavy, high-sulfur crude oil, which is received by pipeline in California and by tanker from foreign and domestic sources. Semi-refined liquid products from the Santa Maria facility are sent by pipeline to the Rodeo facility for upgrading into finished petroleum
products. The Rodeo facility has a calciner which upgrades a portion of the coke that is produced. The refinery produces a high percentage of transportation fuels, such as gasoline, diesel and jet fuel. It also produces CARB gasoline by blending ethanol to meet government-mandated oxygenate requirements. The majority of the refined products are distributed by pipeline, railcar, truck and barge to customers in California.
In the United States, R&M markets gasoline, diesel fuel, and aviation fuel through approximately 8,750 outlets in 49 states. The majority of these sites utilize the Conoco, Phillips 66 or 76 brands.
In our wholesale operations, we utilize a network of marketers and dealers operating approximately 7,750 outlets that provide refined product off-take from our operated refineries. A strong emphasis is placed on the wholesale channel of trade because of its lower capital requirements. We also buy and sell petroleum products in the spot market. Our refined products are marketed on both a branded and unbranded basis.
In addition to automotive gasoline and diesel fuel, we produce and market aviation gasoline, which is used by smaller, piston-engine aircraft. Aviation gasoline and jet fuel are sold through independent marketers at approximately 590 Phillips 66 branded locations in the United States.
In our retail operations, we own and operate 330 sites under the Phillips 66, Conoco and 76 brands. Company-operated retail operations are focused in 10 states, mainly in the Midcontinent, Rocky Mountain and West Coast regions. Most of these outlets market merchandise through the Kicks, Breakplace or Circle K brand convenience stores.
At December 31, 2007, CFJ Properties, our 50/50 joint venture with Flying J, owned and operated approximately 110 truck travel plazas that carry the Conoco and/or Flying J brands.
In December 2006, we announced our U.S. company-owned and company-operated retail outlets, and our U.S. company-owned and dealer-operated retail outlets, were expected to be divested to new or existing wholesale marketers. We sold 54 sites during 2007, and 766 company- and dealer-operated sites were classified as held for sale at December 31, 2007. We expect to complete the disposition of our U.S. retail assets in 2008.
Pipelines and Terminals
At December 31, 2007, we had approximately 28,000 miles of common-carrier crude oil, raw natural gas liquids, and petroleum products pipeline systems in the United States, including those partially owned and/or operated by affiliates. We also owned and/or operated 51 finished product terminals, seven liquefied petroleum gas terminals, five crude oil terminals and one coke exporting facility.
In December 2007, we acquired a 50 percent equity interest in the Keystone Oil Pipeline (Keystone) to form a 50/50 joint venture with TransCanada Corporation. This joint venture plans to construct a 2,148-mile crude oil pipeline originating in Hardisty, Alberta, with delivery points at Wood River and Patoka, Illinois, and Cushing, Oklahoma. Keystone is designed to have a daily capacity of 590,000 barrels and has received binding, firm commitments from credit-worthy shippers for 495,000 barrels per day of the planned pipeline capacity, of which we have a portion. Subject to receipt of regulatory approvals, initial deliveries for Keystones first segment are projected for late 2009, and the second segment is expected to be fully operational in the first half of 2011. We expect to utilize the Keystone pipeline to transport our Canadian crude oil production to market, including as a source of supply to WRB.
At December 31, 2007, we had under charter 18 double-hulled crude oil tankers, with capacities ranging in size from 650,000 to 1,100,000 barrels. These tankers are utilized to transport feedstocks to certain of our U.S. refineries. The information above excludes the operations of the companys subsidiary, Polar Tankers, Inc., which is discussed in the E&P segment overview, as well as an owned tanker on lease to a third party for use in the North Sea.
Several transportation assets were sold during 2007, including the domestic marine inland barge and vessel operations, the Grand Junction terminal, the Bettendorf terminal, and the Kapalama pipeline. Negotiations to sell the international marine operations leasehold interest in six international tankers were under way in 2007, and this sale was completed in January 2008.
We manufacture and sell a variety of specialty products including petroleum cokes, lubes (such as automotive and industrial lubricants), solvents, and pipeline flow improvers to commercial, industrial and wholesale accounts worldwide.
Lubricants are marketed under the Conoco, Phillips 66, 76 Lubricants and Kendall Motor Oil brands. The distribution network includes mass merchandise stores, fast lubes, tire stores, automotive dealers and convenience stores. Lubricants are also sold to industrial customers in many markets.
The companys 50 percent-owned Excel Paralubes joint venture owns a hydrocracked lubricant base oil manufacturing plant located adjacent to the Lake Charles refinery. The facility produces approximately 20,000 barrels per day of high-quality, clear hydrocracked base oils. Hydrocracked base oils are second in quality only to synthetic base oils, but are produced at a much lower cost. The Lake Charles refinery supplies Excel Paralubes with a portion of its gas-oil feedstocks. We purchase 50 percent of the joint ventures output, and blend the base oil into finished lubricants or market it to third parties.
We also manufacture high-quality graphite and anode-grade cokes in the United States and Europe for use in the global steel and aluminum industries.
During 2007, our Specialty Businesses operations sold its Conostan calibration fluid technology.
Additionally, as of December 31, 2007, we had a 50 percent interest in Penreco, which manufactures and markets highly refined specialty petroleum products, including solvents, waxes, petrolatums and white oils, for global markets. In January 2008, we sold our interest in Penreco.
At December 31, 2007, R&M owned or had an interest in five refineries outside the United States with an aggregate crude oil capacity of 669,000 barrels per day net to ConocoPhillips.
The Humber refinery is located in North Lincolnshire, United Kingdom. The refinerys crude oil processing capacity is 221,000 barrels per day. Crude oil processed at the refinery is supplied primarily from the North Sea and includes light, low-sulfur and acidic crude oil. The refinery also processes intermediate feedstocks, mostly vacuum gas oils and residual fuel oil.
The Humber refinery is a fully integrated refinery that produces a high percentage of transportation fuels, such as gasoline and diesel. Other products include home heating oil and specialty chemicals. The refinery also has two coking units with associated calcining plants, which upgrade the heaviest part of the crude barrel and imported feedstocks into light-oil products and graphite and anode petroleum cokes. Products produced in the refinery are marketed in the United Kingdom, along with the rest of Europe and the United States.
The Whitegate refinery in Cork, Ireland, has a crude oil processing capacity of 71,000 barrels per day. Crude oil processed by the refinery is light, low-sulfur crude oil sourced mostly from the North Sea. The refinery primarily produces transportation fuels, such as gasoline, diesel and fuel oil, which are distributed to the inland market, as well as being exported to Europe and the United States. We also operate a crude oil and products storage complex consisting of 7.5 million barrels of storage capacity and an offshore mooring buoy, located in Bantry Bay, about 80 miles southwest of the Whitegate refinery in southern Cork County.
The Wilhelmshaven refinery is located in the northern state of Lower Saxony in Germany, and has a crude oil processing capacity of 260,000 barrels per day. Crude oil processed by the refinery is low-sulfur sourced mostly from the North Sea. The Wilhelmshaven refinery mainly produces transportation fuels, fuel oil, and intermediate feedstocks, which are primarily exported to Europe and the United States, but are also distributed to the inland market via truck and rail. Additionally, we operate a marine terminal, rail and truck loading facilities and a tank farm. We have evaluated alternatives to economically improve the operation of the refinery and have incorporated a deep conversion plan into our capital budget.
The Mineraloel Raffinerie Oberrhein GmbH (MiRO) refinery in Karlsruhe, Germany, is a joint-venture refinery with a crude oil processing capacity of 307,000 barrels per day. Effective January 1, 2008, the refinerys capacity was increased by 5,000 barrels per day due to incremental debottlenecking, with our share being an increase of 1,000 barrels per day. We have an 18.75 percent interest in MiRO, giving us a net capacity share of 58,000 barrels per day. The refinerys crude oil feedstock includes medium-sulfur crude oil. The MiRO complex is a fully integrated refinery producing gasoline, middle distillates and specialty products, along with a small amount of residual fuel oil. The refinery has a high capacity to convert lower-cost feedstocks into higher-value products, primarily with a fluid catalytic cracker and a delayed coker. The refinery also produces fuel-grade and specialty calcined cokes. The refinery processes crude and other feedstocks supplied by each of the co-venturers in proportion to their respective ownership interests. The majority of refined products are distributed by truck and railcar to Germany and neighboring markets.
The refinery in Melaka, Malaysia, is a joint-venture refinery in which we own a 47 percent interest. The refinery has a rated crude oil processing capacity of 128,000 barrels per day, of which our share is 60,000 barrels per day. The medium, high-sulfur crude oil processed by the refinery is sourced mostly from the Middle East. The refinery produces a full range of refined petroleum products. The refinery capitalizes on our proprietary coking technology to upgrade low-cost feedstocks to higher-margin products. Our share of refined products is transported by tanker and marketed in Malaysia and other Asian markets.
In late 2007, we and our co-venturers sanctioned a project for the planned expansion of the refinery due for completion in early 2010. This project is intended to increase crude oil, conversion and treating unit capacities.
In May 2006, we signed a Memorandum of Understanding with Saudi Aramco to conduct a detailed evaluation of the proposed development of a 400,000-barrel-per-day, full-conversion refinery in Yanbu, Saudi Arabia. The refinery would be designed to process Arabian heavy crude oil and produce high-quality, ultra-low-sulfur refined products. A joint ConocoPhillips and Saudi Aramco project team has initiated work on the front-end engineering design study. This study, as well as an evaluation of project financing and negotiations of key commercial agreements, is scheduled to be completed later in 2008.
In July 2006, we announced the signing of a Memorandum of Understanding with International Petroleum Investment Company (IPIC) of Abu Dhabi to identify new upstream and downstream opportunities for joint investment. A feasibility study for construction of a 500,000-barrel-per-day refinery in Fujairah, United Arab Emirates, was completed in 2007. ConocoPhillips decided not to proceed with this joint-investment opportunity.
Our 16.33 percent ownership interest in Česká Rafinérská, a.s. (CRC), consisting of two refineries located in the Czech Republic, was sold during 2007.
At December 31, 2007, R&M had marketing operations in eight European countries. R&Ms European marketing strategy is to sell primarily through owned, leased or joint-venture retail sites using a low-cost, high-volume strategy. We also market aviation fuels, liquid petroleum gases, heating oils, transportation fuels and marine bunkers to commercial customers and into the bulk or spot market.
We use the JET brand name to market retail and wholesale products in Austria, Denmark, Germany, Norway, Sweden and the United Kingdom. In addition, a joint venture in which we have an equity
interest markets products in Switzerland under the Coop brand name. We also sell a portion of our Ireland refinery output to inland Irish markets.
As of December 31, 2007, R&M had approximately 1,600 marketing outlets in its European operations, of which approximately 1,150 were company-owned, and 450 were dealer-owned. Through our joint-venture operations in Switzerland, we also have interests in 196 additional sites. The companys largest branded site networks are in Germany and the United Kingdom, which account for approximately 75 percent of our total European branded units.
During 2007, we sold 377 of our fueling stations in six European countries to LUKOIL and completely divested our marketing operations in Thailand and Malaysia. As of December 31, 2007, agreements were signed for the sale of Norway, Sweden and Denmark marketing assets. We expect to complete the disposition of these assets in 2008.
At December 31, 2007, our LUKOIL Investment segment represented 6 percent of ConocoPhillips total assets, while contributing 15 percent of net income.
In September 2004, we made a joint announcement with LUKOIL, an international integrated oil and gas company headquartered in Russia, of an agreement to form a broad-based strategic alliance, whereby we would become a strategic equity investor in LUKOIL. By year-end 2005, we had an ownership interest in LUKOIL of 16.1 percent. At December 31, 2006 and 2007, we had a 20 percent ownership interest, based on issued shares, and a 20.6 percent ownership interest, based on estimated shares outstanding. See Note 10Investments, Loans and Long-Term Receivables, in the Notes to Consolidated Financial Statements, for additional information.
Under the Shareholder Agreement between the two companies, we have representation on the LUKOIL Board of Directors (Board), and LUKOILs corporate charter requires unanimous Board consent for certain key decisions. In addition, the Shareholder Agreement limits our ownership interest in LUKOIL to 20 percent, based on authorized and issued shares, and limits our ability to sell our LUKOIL shares for a period of four years from September 29, 2004, except in certain circumstances. We use the equity method of accounting for our investment in LUKOIL.
As reported in LUKOILs 2006 annual report, the majority of its 2006 upstream oil production was sourced within Russia, with 63 percent from the western Siberia region, 14 percent from the Timan-Pechora province and 12 percent from the Urals region. Outside of Russia, LUKOIL had oil production in 2006 in Kazakhstan, Egypt, and Azerbaijan, and gas production in Uzbekistan. Ninety-one percent of LUKOILs natural gas production was sourced within Russia. In addition, LUKOIL has an active exploration program focused in Russia, but also encompassing several other international countries. Downstream, LUKOIL has seven refineries with a net crude oil throughput capacity of approximately 1.2 million barrels per day. In addition, LUKOIL has a marketing network which extends to 19 countries, with the majority of wholesale and retail sales in Russia, the United States and Europe.
At December 31, 2007, our Chemicals segment represented 1 percent of ConocoPhillips total assets, while contributing 3 percent of net income.
The Chemicals segment consists of our 50 percent equity investment in Chevron Phillips Chemical Company LLC (CPChem), a joint venture with Chevron Corporation. CPChem is headquartered in The Woodlands, Texas.
CPChems business is structured around three primary operating segments: Olefins & Polyolefins, Aromatics & Styrenics, and Specialty Products. The Olefins & Polyolefins segment produces and markets ethylene, propylene, and other olefin products, which are primarily consumed within CPChem for the production of polyethylene, normal alpha olefins, polypropylene, and polyethylene pipe. The Aromatics & Styrenics segment manufactures and markets aromatics products, such as benzene, styrene, paraxylene and cyclohexane. This segment also manufactures and markets polystyrene, as well as styrene-butadiene copolymers. The Specialty Products segment manufactures and markets a variety of specialty chemical products, including organosulfur chemicals, solvents, catalysts, drilling chemicals, mining chemicals and high-performance engineering plastics and compounds.
CPChems domestic production facilities are located at Baytown, Borger, Conroe, La Porte, Orange, Pasadena, Port Arthur and Old Ocean, Texas; St. James, Louisiana; Pascagoula, Mississippi; Marietta, Ohio; and Guayama, Puerto Rico. CPChem also has one pipe fittings production plant and eight plastic pipe production plants in eight states. Major international production facilities are located in Belgium, China, Saudi Arabia, Singapore, South Korea and Qatar. CPChem has research and technical facilities in Oklahoma, Ohio and Texas, as well as in Singapore and Belgium.
CPChem owns a 49 percent interest in a joint-venture company, Qatar Chemical Company Ltd. (Q-Chem), that owns a major olefins and polyolefins complex in Mesaieed, Qatar. CPChem also owns a 49 percent interest in Qatar Chemical Company II Ltd. (Q-Chem II), a joint venture that began construction of a second complex in Mesaieed in 2005. This Q-Chem II facility is designed to produce polyethylene and normal alpha olefins on a site adjacent to the Q-Chem complex. In connection with this project, CPChem and Qatar Petroleum entered into a separate agreement with Total Petrochemicals and Qatar Petrochemical Company Ltd., establishing a joint venture to develop an ethylene cracker in Ras Laffan Industrial City, Qatar. The cracker will provide ethylene feedstock via pipeline to the Q-Chem II plants. Operational startup of the Q-Chem II projects is anticipated in the second quarter of 2009.
In 2003, CPChem formed a 50-percent-owned joint venture company to develop an integrated styrene facility in Al Jubail, Saudi Arabia. The facility, being built on a site adjacent to the existing aromatics complex owned by Saudi Chevron Phillips Company (SCP), another 50-percent-owned CPChem joint venture, will include feed fractionation, an olefins cracker, and ethylbenzene and styrene monomer processing units. Construction of the facility, which began in the fourth quarter of 2004, is in conjunction with an expansion of SCPs existing benzene plant, together called the JCP Project. Operational startup is anticipated in mid-2008.
In 2007, CPChem formed a 50-percent-owned joint venture company, Saudi Polymers Company, to construct and operate an integrated petrochemicals complex at Al Jubail, Saudi Arabia. The facility will produce ethylene, propylene, polyethylene, polypropylene, polystyrene, and 1-hexene. Construction began in January 2008, and commercial production is scheduled to begin in late 2011. Prior to project completion, CPChems ownership interest in the joint venture is expected to decline to 35 percent.
In 2007, CPChem and the Dow Chemical Company signed a non-binding Memorandum of Understanding relating to the formation of a joint venture involving assets from their polystyrene and styrene monomer businesses in the Americas. Upon formation of the joint venture, CPChem intends to contribute its styrene monomer plant in St. James, Louisiana, and its polystyrene plant in Marietta, Ohio, and Dow intends to contribute six polystyrene plants. The new venture is subject to customary regulatory review, due diligence, completion of definitive agreements, and corporate and other approvals. Joint-venture operations are expected to commence in the first half of 2008.
At December 31, 2007, our Emerging Businesses segment represented 1 percent of ConocoPhillips total assets. Emerging Businesses encompass the development of new technologies and businesses outside our normal scope of operations.
The focus of our power business is on developing integrated projects to support the companys E&P and R&M strategies and business objectives. The projects that are primarily in place to enable these strategies are included within their respective E&P and R&M segments. The power projects and assets that have a significant merchant component are included in the Emerging Businesses segment.
The Immingham combined heat and power (CHP) plant, a wholly owned 730-megawatt, gas-fired facility in North Lincolnshire, United Kingdom, provides steam and electricity to the Humber refinery and steam to a neighboring refinery, as well as merchant power into the U.K. market.
In October 2006, we announced we would invest approximately $400 million to expand the capacity at our Immingham CHP plant by 450 megawatts to 1,180 megawatts. Development work on Immingham Phase 2 began with the award of a contract for front-end engineering and securing of additional connection availability to the U.K. grid. Commercial operation of the expansion is expected to start in mid-2009.
We also own a gas-fired cogeneration plant in Orange, Texas.
In October 2007, we purchased a 50 percent operating interest in Sweeny Cogeneration LP (SCLP). SCLP provides steam and electric power to the Sweeny refinery complex with any excess power sold into the market. We account for this joint venture using the equity method of accounting.
We are expanding our efforts to develop carbon-to-liquids technology focused on coal and petroleum coke.
Alternative Energy and Technology Programs
Alternative Energy and Technology Programs focuses on developing new business opportunities designed to provide growth options for ConocoPhillips well into the future. Example areas of interest include advanced hydrocarbon processes, energy conversion technologies, new petroleum-based products, and renewable fuels. ConocoPhillips is interested in the production of biofuels. We have recently commercialized the production of renewable diesel, a new type of renewable fuel that utilizes existing infrastructure. In 2007, we formed a research relationship with Iowa State University to develop new methods for producing second-generation biofuels. We also formed alliances with Tyson Foods and Archer Daniels Midland to produce and market the next generation of renewable transportation fuels.
We offer a gasification technology (E-GasTM) that uses petroleum coke, coal, and other low-value hydrocarbons as feedstock, resulting in high-value synthetic gas used for a slate of products, including power, hydrogen and chemicals.
In 2007, we entered into an agreement with Peabody Energy to perform a feasibility study for the development of a coal-to-gas facility using proprietary ConocoPhillips E-GasTM technology. If constructed, the facility would be developed at a location where Peabody has access to coal reserves and existing infrastructure. The feasibility study and preliminary design are expected to continue into 2008.
We compete with private, public and state-owned companies in all facets of the petroleum and chemicals businesses. Some of our competitors are larger and have greater resources. Each of the segments in which we operate is highly competitive. No single competitor, or small group of competitors, dominates any of our business lines.
Upstream, our E&P segment competes with numerous other companies in the industry to locate and obtain new sources of supply, and to produce oil and natural gas in an efficient, cost-effective manner. Based on publicly available year-end 2006 reserves statistics, we had, on a BOE basis, the sixth-largest total of worldwide proved reserves of non-government-controlled companies. We deliver our oil and natural gas production into the worldwide oil and natural gas commodity markets. The principal methods of competing include geological, geophysical and engineering research and technology; experience and expertise; economic analysis in connection with property acquisitions; and operating efficient oil and gas producing properties.
The Midstream segment, through our equity investment in DCP Midstream and our consolidated operations, competes with numerous other integrated petroleum companies, as well as natural gas transmission and distribution companies, to deliver the components of natural gas to end users in the commodity natural gas markets. DCP Midstream is a large producer of natural gas liquids in the United States. DCP Midstreams principal methods of competing include economically securing the right to purchase raw natural gas into its gathering systems, managing the pressure of those systems, operating efficient natural gas liquids processing plants, and securing markets for the products produced.
Downstream, our R&M segment competes primarily in the United States, Europe and the Asia Pacific region. Based on the statistics published in the December 24, 2007, issue of the Oil & Gas Journal, our R&M segment had the second-largest U.S. refining capacity of 16 large refiners of petroleum products. Worldwide, it ranked fifth among non-government-controlled companies. In the Chemicals segment, CPChem generally ranks within the top 10 producers of many of its major product lines, based on average 2007 production capacity, as published by industry sources. Petroleum products, petrochemicals and plastics are delivered into the worldwide commodity markets. Elements of downstream competition include product improvement, new product development, low-cost structures, and improved manufacturing and distribution systems. In the marketing portion of the business, competitive factors include product properties and processibility, reliability of supply, customer service, price and credit terms, advertising and sales promotion, and development of customer loyalty to ConocoPhillips or CPChems branded products.
At the end of 2007, we held a total of 1,818 active patents in 72 countries worldwide, including 686 active U.S. patents. During 2007, we received 40 patents in the United States and 124 foreign patents. Our products and processes generated licensing revenues of $55 million in 2007. The overall profitability of any business segment is not dependent on any single patent, trademark, license, franchise or concession.
Company-sponsored research and development activities charged against earnings were $160 million, $117 million, and $125 million in 2007, 2006, and 2005, respectively.
The environmental information contained in Managements Discussion and Analysis of Financial Condition and Results of Operations on pages 81 through 84 under the caption, Environmental, is incorporated herein by reference. It includes information on expensed and capitalized environmental costs for 2007 and those expected for 2008 and 2009.
Web Site Access to SEC Reports
Our Internet Web site address is http://www.conocophillips.com. Information contained on our Internet Web site is not part of this report on Form 10-K.
Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are available on our Web site, free of charge, as soon as reasonably practicable after such reports are filed with, or furnished to, the SEC. Alternatively, you may access these reports at the SECs Web site at http://www.sec.gov.
Item 1A. RISK FACTORS
You should carefully consider the following risk factors in addition to the other information included in this Annual Report on Form 10-K. Each of these risk factors could adversely affect our business, operating results and financial condition, as well as adversely affect the value of an investment in our common stock.
A substantial or extended decline in crude oil, natural gas and natural gas liquids prices, as well as refining margins, would reduce our operating results and cash flows, and could impact our future rate of growth and the carrying value of our assets.
Prices for crude oil, natural gas and natural gas liquids fluctuate widely. Our revenues, operating results and future rate of growth are highly dependent on the prices we receive for our crude oil, natural gas, natural gas liquids and refined products. Historically, the markets for crude oil, natural gas, natural gas liquids and refined products have been volatile and may continue to be volatile in the future. The factors influencing the prices of crude oil, natural gas, natural gas liquids and refined products are beyond our control. These factors include, among others:
The long-term effects of these and other conditions on the prices of crude oil, natural gas, natural gas liquids and refined products are uncertain. Generally, our policy is to remain exposed to market prices of commodities; however, management may elect to hedge the price risk of our crude oil, natural gas, natural gas liquids and refined products.
Lower crude oil, natural gas, natural gas liquids and refined products prices may reduce the amount of these commodities that we can produce economically, which may reduce our revenues, operating income and cash flows. Significant reductions in commodity prices could require us to reduce capital spending, share repurchases, debt reduction, or to impair the carrying value of assets.
Estimates of crude oil and natural gas reserves depend on many factors and assumptions, including various assumptions that are based on conditions in existence as of the dates of the estimates. Any material changes in those conditions or other factors affecting those assumptions could impair the quantity and value of our crude oil and natural gas reserves.
The proved crude oil and natural gas reserve information relating to us included in this annual report has been derived from engineering estimates prepared or reviewed by our personnel. The estimates were calculated using crude oil and natural gas prices in effect as of December 31, 2007, as well as other conditions in existence as of that date. Any significant future price changes will have a material effect on the quantity and present value of our proved reserves. Future reserve revisions could also result from changes in, among other things, governmental regulation.
Reserve estimation is a subjective process that involves estimating volumes to be recovered from underground accumulations of crude oil and natural gas that cannot be directly measured. Estimates of economically recoverable crude oil and natural gas reserves and of future net cash flows depend upon a number of variable factors and assumptions, including:
As a result, different petroleum engineers, each using industry-accepted geologic and engineering practices and scientific methods, may produce different estimates of reserves and future net cash flows based on the same available data. Because of the subjective nature of crude oil and natural gas reserve estimates, each of the following items may differ materially from the amounts or other factors estimated:
The discounted future net revenues from our proved reserves should not be construed to represent fair market value. As required by rules adopted by the SEC, the estimated discounted future net cash flows from our proved reserves, as described in the supplemental oil and gas operations disclosures on pages 174 through 193, are based generally on prices and costs as of the date of the estimate, while actual future prices and costs may be materially higher or lower.
In addition, the 10 percent discount factor, which SEC rules require to be used to calculate discounted future net revenues for reporting purposes, is not necessarily the most appropriate discount factor based on our cost of capital and the risks associated with our business and the crude oil and natural gas industry in general.
If we are unsuccessful in acquiring or finding additional reserves, our future crude oil and natural gas production would decline, thereby reducing our cash flows and results of operations, negatively impacting our financial condition.
The rate of production from crude oil and natural gas properties generally declines as reserves are depleted. Except to the extent that we acquire additional properties containing proved reserves, conduct successful exploration and development activities, or, through engineering studies, identify additional or secondary recovery reserves, our proved reserves will decline materially as we produce crude oil and natural gas. Accordingly, to the extent we are unsuccessful in replacing the crude oil and natural gas we produce with
good prospects for future production, our business will decline. Creating and maintaining an inventory of projects depends on many factors, including:
We may not be able to find or acquire additional reserves at acceptable costs.
Crude oil price increases and environmental regulations may reduce our refined product margins.
The profitability of our R&M segment depends largely on the margin between the cost of crude oil and other feedstocks we refine and the selling prices we obtain for refined products. Our overall profitability could be adversely affected by the availability of supply and rising crude oil and other feedstock prices that we do not recover in the marketplace. Refined product margins historically have been volatile and vary with the level of economic activity in the various marketing areas, the regulatory climate, logistical capabilities and the available supply of refined products.
In addition, environmental regulations, particularly the 1990 amendments to the Clean Air Act, have imposed, and are expected to continue to impose, increasingly stringent and costly requirements on our refining and marketing operations, which may reduce refined product margins.
We expect to continue to incur substantial capital expenditures and operating costs as a result of our compliance with existing and future environmental laws and regulations. Likewise, future environmental laws and regulations may impact or limit our current business plans and/or reduce demand for our products. As a result, our business, financial condition, results of operations and cash flows in future periods could be materially adversely affected.
Our businesses are subject to numerous laws and regulations relating to the protection of the environment. These laws and regulations continue to increase in both number and complexity and affect our operations with respect to, among other things:
We have incurred and will continue to incur substantial capital, operating and maintenance, and remediation expenditures as a result of these laws and regulations. To the extent these expenditures, as with all costs, are not ultimately reflected in the prices of our products and services, our operating results will be adversely affected. The specific impact of these laws and regulations on us and our competitors may vary depending on a number of factors, including the age and location of operating facilities, marketing areas and production processes. We may also be required to make material expenditures to:
Continued hostilities and turmoil in the world and the occurrence or threat of future terrorist attacks could affect the economies of the United States and other developed countries. A lower level of economic activity could result in a decline in energy consumption, which could cause our revenues and margins to decline and limit our future growth prospects. More specifically, our energy-related assets may be at greater risk of future terrorist attacks than other possible targets. A direct attack on our assets, or assets used by us, could have a material adverse effect on our operations, financial condition, results of operations and prospects. These risks could lead to increased volatility in prices for crude oil, natural gas, natural gas liquids and refined products and could increase instability in the financial and insurance markets, making it more difficult for us to access capital and to obtain the insurance coverage that we consider adequate.
Actions of the U.S., state and local governments through tax and other legislation, executive order and commercial restrictions could reduce our operating profitability both in the United States and abroad. The U.S. government can prevent or restrict us from doing business in foreign countries. These restrictions and those of foreign governments have in the past limited our ability to operate in, or gain access to, opportunities in various countries. Actions by both the United States and host governments have affected operations significantly in the past and will continue to do so in the future.
We also are exposed to fluctuations in foreign currency exchange rates. We do not comprehensively hedge our exposure to currency rate changes, although we may choose to selectively hedge certain working capital balances, firm commitments, cash returns from affiliates and/or tax payments. These efforts may not be successful.
Changes in governmental regulations may impose price controls and limitations on production of crude oil and natural gas.
Our operations are subject to extensive governmental regulations. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of crude oil and natural gas wells below actual production capacity in order to conserve supplies of crude oil and natural gas. Because legal requirements are frequently changed and subject to interpretation, we cannot predict the effect of these requirements.
Our operations are subject to business interruptions and casualty losses, and we do not insure against all potential losses, so we could be seriously harmed by unexpected liabilities.
Our exploration and production operations are subject to unplanned occurrences, including blowouts, explosions, fires, loss of well control, formations with abnormal pressures, spills and adverse weather. In addition, our refining, marketing and transportation operations are subject to business interruptions due to scheduled refinery turnarounds and unplanned events such as explosions, fires, pipeline interruptions, pipeline ruptures, crude oil or refined product spills, inclement weather or labor disputes. Our operations are also subject to the additional hazards of pollution, releases of toxic gas and other environmental hazards and risks, as well as hazards of marine operations, such as capsizing, collision and damage or loss from severe weather conditions. All such hazards could result in loss of human life, significant property and equipment damage, environmental pollution, impairment of operations and substantial losses to us. These hazards have adversely affected us in the past, and litigation arising from a catastrophic occurrence in the future at one of our locations may result in our being named as a defendant in lawsuits asserting potentially large claims or being assessed potentially substantial fines by governmental authorities. In addition, we are exposed to risks inherent in any business, such as terrorist attacks, equipment failures, accidents, theft, strikes, protests and sabotage, that could disrupt or interrupt operations.
We maintain insurance against many, but not all, potential losses or liabilities arising from these operating hazards in amounts that we believe to be prudent. Uninsured losses and liabilities arising from operating hazards could reduce the funds available to us for exploration, drilling, production and other capital expenditures and could materially reduce our profitability.
Our investments in joint ventures decrease our ability to manage risk.
We conduct many of our operations through joint ventures in which we may share control with our joint-venture partners. Although we often enter into joint-venture arrangements in order to share risks with our joint-venture partners, these arrangements may decrease our ability to manage risk. As with any joint-venture arrangement, differences in views among the joint-venture participants may result in delayed decisions or in failures to agree on major issues. There is the risk that our joint-venture partners may at any time have economic, business or legal interests or goals that are inconsistent with those of the joint venture or us. There is also risk our joint-venture partners may be unable to meet their economic or other
obligations and we may be required to fulfill those obligations alone. Failure by us, or an entity in which we have a joint-venture interest, to adequately manage the risks associated with any acquisitions or joint ventures could have a material adverse effect on the financial condition or results of operations of our joint ventures and, in turn, our business and operations.
We anticipate entering into additional joint ventures with other entities. We cannot assure that we will undertake such joint ventures or, if undertaken, that such joint ventures will be successful.
Item 1B. UNRESOLVED STAFF COMMENTS
Item 3. LEGAL PROCEEDINGS
The following is a description of reportable legal proceedings, including those involving governmental authorities under federal, state and local laws regulating the discharge of materials into the environment for this reporting period. The following proceedings include those matters previously reported in ConocoPhillips 2006 Form 10-K and our first-, second- and third-quarter 2007 Form 10-Qs that were not resolved prior to the fourth quarter of 2007. No new reportable matters arose during the fourth quarter of 2007. While it is not possible to accurately predict the final outcome of these pending proceedings, if any one or more of such proceedings was decided adversely to ConocoPhillips, there would be no material effect on our consolidated financial position. Nevertheless, such proceedings are reported pursuant to the U.S. Securities and Exchange Commissions regulations.
Our U.S. refineries are implementing two separate consent decrees, regarding alleged violations of the Federal Clean Air Act, with the U.S. Environmental Protection Agency (EPA), six states and one local air pollution agency. Some of the requirements and limitations contained in the decree provide for stipulated penalties for violations. Stipulated penalties under the decrees are not automatic, but must be requested by one of the agency signatories. As part of periodic reports under the decree and/or other reports required by permits or regulations, we occasionally report matters which could be subject to a request for stipulated penalties. If a specific request for stipulated penalties meeting the reporting threshold set forth in U.S. Securities and Exchange Commission rules is made pursuant to these decrees based on a given reported exceedance, we will separately report that matter and the amount of the proposed penalty.
Matters Previously Reported
The South Coast Air Quality Management District (SCAQMD) conducted an audit of the Los Angeles refinery to assess compliance with applicable local, state, and federal regulations related to fugitive emissions. As a result of the audit, SCAQMD issued three Notices of Violations (NOVs) alleging multiple counts of non-compliance. SCAQMD has not yet specified a penalty for these alleged violations. We are currently assessing these allegations and expect to work with SCAQMD toward a resolution of these NOVs.
In October 2007, we received a Complaint from the U.S. EPA alleging violations of the Clean Water Act related to a 2006 oil spill at our Bayway refinery and proposing a penalty of $156,000. We have begun discussions with the EPA to settle this matter and will work with the agency to resolve this matter.
On September 25, 2007, the Sweeny refinery received a draft order to resolve a July 6, 2007, Notice of Enforcement (NOE) relating to alleged violations of the Texas Clean Air Act. The allegations relate to compliance with limitations contained in the refinerys Title V operating permit and one emission event.
In November 2007, we paid $114,450 as a penalty and agreed to fund a Supplemental Environmental Project (SEP) in the same amount. We anticipate approval of the settlement by the Texas Commission on Environmental Quality (TCEQ).
In June 2007, the Ferndale refinery was informed by the U.S. EPA that it will seek penalties for Ferndales alleged failure to comply with certain portions of the Benzene Waste Operations rule. The government alleges the facility has not complied with certain equipment maintenance and inspection rules since 1993. We are working with the EPA and the Department of Justice to resolve this matter.
The Pennsylvania Department of Environmental Protection (PADEP) has informed the Trainer refinery it intends to seek penalties for acid gas flaring which occurred during April and/or May 2007. We are currently assessing this matter and expect to work with the PADEP to resolve it. Since this matter is subject to an EPA Consent Decree, we do not anticipate reporting further on this matter until we receive a specific request and if such request meets the reporting threshold.
On April 30, 2007, the Borger refinery received an offer to settle a range of violations alleged in a March 16, 2007, NOE issued by the TCEQ. The alleged violations relate to air quality permit limits, emission events, testing requirements, and reporting or recordkeeping requirements. In November 2007, we submitted payment of a penalty of $84,900 and agreed to fund an SEP valued at $84,900. We anticipate TCEQ will approve this settlement.
In March 2007, the Sweeny refinery received a series of NOEs from the TCEQ. These NOEs generally relate to emission events such as flaring and other unplanned releases. The TCEQ proposed a penalty of $325,120 in a revised draft order received in November 2007. We paid a penalty of $162,560 and agreed to fund an SEP in the same amount upon final approval of the settlement by the TCEQ.
On February 7, 2007, Gulf Coast Fractionators, a gas processing facility operated by ConocoPhillips in which we have a 22.5 percent interest, received a draft order from the TCEQ proposing to settle alleged violations of air emission permit limits at the plant. The order proposed a penalty of $135,538. In October 2007, this matter was resolved by payment of a penalty of $67,769 and agreement to fund an SEP of $67,769. We anticipate this proposed settlement will be approved by the TCEQ.
In the fall of 2006, the Wood River refinery experienced two incidents where coker oil mist was released from the Distilling West coker. In a February 9, 2007, letter the state of Illinois demanded $50,000 for each release. We are working with the state toward a final resolution of this matter.
On March 28, 2006, the TCEQ issued a revised draft agreed order relating to alleged air quality violations at the Borger refinery. The order addresses several categories of air quality violations including emission events, violation of permit conditions, and failure to pay emission fees, and a single solid waste violation for improper classification and disposal of waste. The order proposed a penalty of $160,406. The TCEQ recalculated the penalty of $151,726. We agreed to pay a penalty of $75,863 and to fund an SEP in the same amount. The TCEQ approved this settlement and the required payments have been made.
On December 16, 2005, our Bayway refinery experienced a hydrocarbon spill to the Rahway River and Arthur Kill. As a result of this spill, we signed an Order on Consent (Order) with the state of New York, and are also negotiating similar settlements with the state of New Jersey and the federal government. Under the final New York Order, we paid a penalty of $50,000 and conducted a beach cleanup.
In December 2005, the TCEQ proposed an administrative penalty of $120,132 for alleged violations of the Texas Clean Air Act at the Borger refinery. The allegations relate to unexcused emission events, reporting and recordkeeping requirements, leak detection and repair, flare outages, and Title V permit reporting. We have paid an administrative penalty of $57,716, and agreed to perform SEPs totaling $57,716. This settlement was approved and adopted by the TCEQ at its meeting November 7, 2007, and the final SEP payment has been made.
In December 2005, routine tests at our refinery in Lake Charles, Louisiana, revealed that certain particulate matter emissions did not meet established limits. The refinery has resolved this issue and achieved full compliance with all applicable particulate matter emission limits in the first quarter of 2007. The EPA and Louisiana Department of Environmental Quality were kept informed of the refinerys remedial actions. The refinery will work with the agencies to resolve any enforcement actions that may be brought. Since this matter is subject to an EPA Consent Decree, we do not anticipate reporting further on this matter until we receive a specific request and if such request meets the reporting threshold.
In March 2005, ConocoPhillips Pipe Line Company (CPPL) received a Notice of Probable Violation and Proposed Civil Penalty from the Department of Transportations Pipeline and Hazardous Materials Safety Administration (DOT) alleging violation of DOT operation and safety regulations at certain facilities in
Kansas, Missouri, Illinois, Indiana, Wyoming and Nebraska. DOT is proposing penalties in the amount of $184,500. An information hearing was held on September 24, 2007. CPPL has provided additional information in support of its position. A DOT ruling is not anticipated until the first quarter of 2008.
The U.S. Coast Guard and Washington State Department of Ecology investigated the possible sources of an oil spill in Puget Sound. In November 2004, the U.S. Attorney and the U.S. Coast Guard offices in Seattle, Washington, issued subpoenas to Polar Tankers, Inc., a subsidiary of ConocoPhillips Company, for records related to the vessel Polar Texas. On December 23, 2004, the governor of the state of Washington and the U.S. Coast Guard publicly announced they believed the Polar Texas was the source of the spill. The company fully cooperated with the investigations. The U.S. Attorneys Office in Seattle declined prosecution of the company. Polar Tankers, ConocoPhillips and the state of Washington settled the matter, with payment of civil penalties in the amount of $540,000. Additionally, the company has agreed to pay the federal government $2.2 million to cover the cost of the spill cleanup, and $80,000 in civil penalties. The settlement did not include any admission of liability. The company and the authorities remain in settlement negotiations around other remaining items.
In April 2004, in response to several historic spills at the Albuquerque Products Terminal, we received an Administrative Compliance Order from the New Mexico Environment Department. The order does not propose a penalty assessment, but rather attempts to impose specific design, construction and operational changes. We have been in negotiations with the agency and have proposed a settlement offer of $100,000. We will continue to work with the agency to resolve this matter.
In August of 2003, EPA Region 6 issued a Show Cause Order alleging violations of the federal Clean Water Act at the Borger refinery. The alleged violations relate primarily to discharges of selenium and reported exceedances of permit limits for whole effluent toxicity. On April 17, 2007, the U.S. Department of Justice (DOJ) sent a draft Consent Decree (CD) proposing to settle the outstanding wastewater allegations. The draft CD proposes a penalty of $2.64 million and includes injunctive actions, some of which have already been completed by ConocoPhillips. We are working with the DOJ and EPA to resolve this matter.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
EXECUTIVE OFFICERS OF THE REGISTRANT
There is no family relationship among the officers named above. Each officer of the company is elected by the Board of Directors at its first meeting after the Annual Meeting of Stockholders and thereafter as appropriate. Each officer of the company holds office from date of election until the first meeting of the directors held after the next Annual Meeting of Stockholders or until a successor is elected. The date of the next annual meeting is May 14, 2008. Set forth below is information about the executive officers.
Rand C. Berney was appointed Vice President and Controller of ConocoPhillips upon completion of the merger in 2002.
John A. Carrig was appointed Executive Vice President, Finance, and Chief Financial Officer of ConocoPhillips upon completion of the merger in 2002.
Sigmund L. Cornelius was appointed Senior Vice President, Planning, Strategy and Corporate Affairs of ConocoPhillips effective September 1, 2007, having previously served as ConocoPhillips President, Exploration and ProductionLower 48 since 2006. He served as President, Global Gas of ConocoPhillips since 2004, and prior to that he served as ConocoPhillips President, Lower 48, Latin America and Midstream since 2003. He served as Vice President, Upstream Business Development of ConocoPhillips following completion of the merger in 2002.
James L. Gallogly was appointed Executive Vice President, Refining, Marketing and Transportation of ConocoPhillips effective April 1, 2006, having previously served as President and Chief Executive Officer of Chevron Phillips Chemical Company LLC since 2000.
Janet L. Kelly was appointed Senior Vice President, Legal, General Counsel and Corporate Secretary of ConocoPhillips effective September 1, 2007, having previously served as ConocoPhillips Deputy General Counsel since 2006. Prior to joining ConocoPhillips in 2006, she was a partner at Zelle, Hoffman, Voelbel, Mason and Gette, having previously served as Senior Vice President, Chief Administrative Officer and Chief Compliance Officer of Kmart Corporation since 2003. Prior to joining Kmart
Corporation, she served as Executive Vice President of Corporate Development and Administration, General Counsel and Secretary of Kellogg Company since 2001.
John E. Lowe was appointed Executive Vice President, Exploration and Production of ConocoPhillips effective September 1, 2007, having previously served as ConocoPhillips Executive Vice President, Commercial since 2006. He served as ConocoPhillips Executive Vice President, Planning, Strategy and Corporate Affairs since completion of the merger in 2002.
James J. Mulva was appointed Chairman of the Board of Directors, President and Chief Executive Officer of ConocoPhillips effective October 1, 2004, having previously served as ConocoPhillips President and Chief Executive Officer since completion of the merger in 2002.
Quarterly Common Stock Prices and Cash Dividends Per Share
ConocoPhillips common stock is traded on the New York Stock Exchange, under the symbol COP.
Issuer Purchases of Equity Securities
Item 6. SELECTED FINANCIAL DATA
See Managements Discussion and Analysis of Financial Condition and Results of Operations for a discussion of factors that will enhance an understanding of this data. The financial data for 2007 includes the impact of a $4,588 million before-tax ($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 13Impairments, in the Notes to Consolidated Financial Statements. Additionally, the acquisition of Burlington Resources in 2006 affects the comparability of the amounts included in the table above. See Note 5Acquisition of Burlington Resources Inc., in the Notes to Consolidated Financial Statements, for additional information. See Note 2Changes in Accounting Principles, in the Notes to Consolidated Financial Statements, for information on changes in accounting principles affecting the comparability of the amounts included in the table above.
February 21, 2008
Managements Discussion and Analysis is the companys 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 companys plans, strategies, objectives, expectations, and intentions, that are made pursuant to the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. The words intends, believes, expects, plans, scheduled, should, anticipates, estimates, 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 companys disclosures under the heading: CAUTIONARY STATEMENT FOR THE PURPOSES OF THE SAFE HARBOR PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995, beginning on page 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 COP.
Our business is organized into six operating segments:
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:
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:
The E&P segments 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 segments 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 Midstreams sale of its general partnership interest in TEPPCO Partners, LP (TEPPCO). DCP Midstreams natural gas liquids prices increased 19 percent in 2007.
Refining margins, refinery utilization, cost control, and marketing margins primarily drive the R&M segments 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 LUKOILs 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 Russias 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
A summary of the companys net income (loss) by business segment follows:
2007 vs. 2006
The lower results in 2007 were primarily the result of:
These items were partially offset by:
2006 vs. 2005
The improved results in 2006, compared with 2005, were primarily the result of:
These items were partially offset by:
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:
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 segments depreciable asset base for a full year in 2007 versus only nine months in 2006.
Impairmentexpropriated 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 13Impairments, 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 13Impairments, 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.
2006 vs. 2005
Sales and other operating revenues increased 2 percent in 2006, compared with 2005, while purchased crude oil, natural gas and products decreased 5 percent. The increase in sales and other operating revenues was primarily due to higher realized prices for crude oil and petroleum products, as well as higher sales volumes associated with the Burlington Resources acquisition. These increases were mostly offset by decreases associated with the implementation of Emerging Issues Task Force Issue No. 04-13, Accounting for Purchases and Sales of Inventory with the Same Counterparty. The decrease in purchased crude oil, natural gas and products was primarily the result of the implementation of Issue No. 04-13. See Note 2Changes in Accounting Principles, in the Notes to Consolidated Financial Statements, for additional information on the impact of this Issue on our income statement.
Equity in earnings of affiliates increased 21 percent in 2006, compared with 2005. The increase reflects improved results from:
These increases were offset partially by the inclusion of our equity share of DCP Midstreams gain on the sale of the general partner interest in TEPPCO in our 2005 results.
Other income increased 47 percent during 2006, compared with 2005, primarily due to the recognition in 2006 of recoveries on business interruption insurance claims. In addition, interest income was higher in 2006, compared with 2005. These increases were partially offset by higher net gains on asset dispositions recorded in 2005.
Production and operating expenses increased 22 percent in 2006, compared with 2005. The increase was primarily due to the acquired Burlington Resources assets, increased production at the Bayu-Undan field associated with the Darwin liquefied natural gas (LNG) project in Australia, the first year of production in Libya, and the acquisition of the Wilhelmshaven refinery in Germany.
Exploration expenses increased 26 percent in 2006, compared with 2005, primarily due to the Burlington Resources acquisition.
DD&A increased 71 percent during 2006, compared with 2005. The increase was primarily the result of the addition of Burlington Resources assets in E&Ps depreciable asset base. In addition, the acquisition of the Wilhelmshaven refinery increased DD&A recorded by the R&M segment.
Impairments were $683 million in 2006, compared with $42 million in 2005. The increase primarily relates to the impairment in 2006 of certain assets held for sale in the R&M and E&P segments. We also recorded an impairment charge in the E&P segment associated with assets in the Canadian Rockies Foothills area.
Interest and debt expense increased from $497 million in 2005 to $1,087 million in 2006, primarily due to higher average debt levels as a result of the financing required to partially fund the acquisition of Burlington Resources.
As a result of the acquisition of Burlington Resources, we implemented a restructuring program in March 2006 to capture the synergies of combining the two companies. Under this program, we recorded accruals totaling $230 million in 2006 for employee severance payments, site closings, incremental pension benefit costs associated with the workforce reductions, and employee relocations. Approximately 600 positions were identified for elimination, most of which were in the United States.
Of the total accrual, $224 million was reflected in the Burlington Resources purchase price allocation as an assumed liability, and $6 million ($4 million after-tax) related to ConocoPhillips was reflected in selling, general and administrative expenses in 2006. Included in the total accruals of $230 million was $12 million related to pension benefits to be paid in conjunction with other retirement benefits over a number of future years. See Note 6Restructuring, in the Notes to Consolidated Financial Statements, for additional information.
The E&P 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. 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.
2007 vs. 2006
Net income from the E&P segment decreased 53 percent in 2007. 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 13Impairments, in the Notes to Consolidated Financial Statements, which is incorporated herein by reference. The decrease in net income during 2007 reflects this impairment, as well as lower crude oil production, higher production taxes and operating costs, and higher DD&A expense. These decreases were partially offset by:
If crude oil prices in 2008 do not remain at the levels experienced in 2007, and if costs continue to increase, the E&P segments earnings would be negatively impacted. See the Business Environment and Executive Overview section for additional information on industry crude oil and natural gas prices and inflationary cost pressures.
Proved reserves at year-end 2007 were 8.72 billion barrels of oil equivalent (BOE), compared with 9.36 billion BOE at year-end 2006. This excludes the estimated 1,838 million BOE and 1,805 million BOE included in the LUKOIL Investment segment at year-end 2007 and 2006, respectively. Also excluded is our share of Canadian Syncrude mining operations, which was 221 million barrels at year-end 2007, compared with 243 million barrels at year-end 2006.
Net income from our U.S. E&P operations decreased 2 percent, primarily due to higher production taxes in Alaska, higher operating costs and DD&A expense, and lower crude oil production. These decreases were mostly offset by:
In December 2007, the state of Alaska enacted new production tax legislation, with retroactive provisions, which results in a higher production tax structure for ConocoPhillips.
U.S. E&P production averaged 843,000 BOE per day in 2007, an increase of 4 percent from 808,000 BOE per day in 2006. Production was impacted by the inclusion of the Burlington Resources assets for the full year of 2007, offset slightly by normal field decline.
Net income from our international E&P operations decreased 93 percent, primarily due to the impairment of expropriated assets in Venezuela, lower crude oil production, higher DD&A expense, and higher operating costs. These decreases were partially offset by higher crude oil and natural gas prices, a net benefit from asset rationalization efforts, and the benefit from the release of the escrowed funds related to the Hamaca project.
International E&P production averaged 1,014,000 BOE per day in 2007, a decrease of 10 percent from 1,128,000 BOE per day in 2006. Production was impacted by the expropriation of our Venezuelan oil projects, planned and unplanned downtime in Australia and the North Sea, production sharing contract impacts in Australia, our exit from Dubai, and the effect of asset dispositions. These decreases were slightly offset by new production volumes from our upstream business venture with EnCana, as well as inclusion of the Burlington Resources assets for the full year of 2007. Our Syncrude mining operations produced 23,000 barrels per day in 2007, compared with 21,000 barrels per day in 2006.
2006 vs. 2005
Net income from the E&P segment increased 17 percent in 2006, compared with 2005. The increase was primarily due to higher realized crude oil prices and, to a lesser extent, higher sales prices for natural gas liquids and Syncrude. In addition, increased sales volumes, primarily the result of the Burlington Resources acquisition, contributed positively to net income in 2006. These items were partially offset by lower realized natural gas prices, higher exploration expenses, the negative impacts of changes in tax laws, and asset impairments.
Net income from our U.S. E&P operations increased slightly in 2006, compared with 2005, primarily resulting from higher crude oil prices, as well as increased crude oil, natural gas, and natural gas liquids production in the Lower 48 states, reflecting the Burlington Resources acquisition. These increases were partially offset by lower natural gas prices, higher exploration expenses, lower production levels in Alaska, and higher production taxes in Alaska.
In August 2006, the state of Alaska enacted new production tax legislation, retroactive to April 1, 2006. The new legislation resulted in a higher production tax structure for ConocoPhillips.
U.S. E&P production on a BOE basis averaged 808,000 barrels per day in 2006, compared with 633,000 barrels per day in 2005. Production was favorably impacted in 2006 by the addition of volumes from the Burlington Resources assets, offset slightly by decreases in production levels in Alaska. Production in Alaska was negatively impacted by operational shut downs and weather-related transportation delays.
Net income from our international E&P operations increased 33 percent in 2006, compared with 2005, reflecting higher crude oil, natural gas, and natural gas liquids prices and production, as well as higher levels of LNG production from the Darwin LNG facility associated with the Bayu-Undan field in the Timor Sea. These increases were offset partially by increased exploration expenses and a $93 million after-tax impairment charge associated with assets in the Canadian Rockies Foothills area. In addition, the increases to net income were partially offset by the net negative impacts of tax law changes in the United Kingdom, Canada, China, Venezuela, and Algeria.
During 2006, significant tax legislation was enacted in the United Kingdom and in Canada. The United Kingdom increased income tax rates on upstream income, resulting in a negative earnings impact of $470 million to adjust 2006 taxes and restate deferred tax liabilities. In Canada, an overall rate reduction in 2006 resulted in a favorable earnings impact of $401 million to restate deferred tax liabilities.
International E&P production averaged 1,128,000 BOE per day in 2006, an increase of 24 percent from 910,000 BOE per day in 2005. Production was favorably impacted in 2006 by the addition of Burlington Resources assets, higher gas production at Bayu-Undan associated with the Darwin LNG ramp-up in Australia, and the 2006 re-entry into Libya. Our Syncrude mining operations produced 21,000 barrels per day in 2006, compared with 19,000 barrels per day in 2005.
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 fractionatedseparated into individual components like ethane, butane and propaneand 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.
2007 vs. 2006
Net income from the Midstream segment decreased 5 percent in 2007, reflecting a shift in natural gas purchase contract terms that are more favorable to natural gas producers. In addition, earnings from DCP Midstream were lower, primarily due to increased operating costs, mainly repairs, maintenance and asset integrity work. The results also reflect a positive tax adjustment included in the 2006 results. These decreases were partially offset by higher natural gas liquids prices.
2006 vs. 2005
Net income from the Midstream segment decreased 31 percent in 2006, compared with 2005, primarily due to the gain from the sale of DCP Midstreams interest in TEPPCO included in 2005 results. Our net share of this gain was $306 million on an after-tax basis. This decrease was partially offset by a $24 million positive tax adjustment recorded in 2006 to the gain recorded in 2005 on the sale of DCP Midstreams interest in TEPPCO, as well as higher natural gas liquids prices and an increased ownership interest in DCP Midstream.
In July 2005, ConocoPhillips increased its ownership interest in DCP Midstream to 50 percent from 30.3 percent.
The R&M segments 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.
2007 vs. 2006
Net income from the R&M segment increased 32 percent in 2007. The increase resulted primarily from:
These increases were partially offset by the net impact of our contribution of assets to WRB Refining LLC (WRB), our downstream business venture with EnCana; foreign currency impacts; and lower marketing sales volumes due to asset sales. See the Business Environment and Executive Overview section for our view of the factors supporting industry refining and marketing margins.
We expect our average worldwide refinery crude oil utilization rate for 2008 to average in the mid-nineties.
Net income from our U.S. R&M operations increased 18 percent in 2007, primarily due to:
These items were partially offset by the net impact of our contribution of the Wood River and Borger refineries to WRB, and the impact of business interruption insurance recoveries on our 2006 results.
Our U.S. refining capacity utilization rate was 96 percent in 2007, compared with 92 percent in 2006, primarily reflecting lower planned maintenance and less weather-related downtime.
Net income from our international R&M operations increased 131 percent in 2007, due primarily to:
These increases were partially offset by foreign currency impacts and lower marketing volumes due to the asset sales.
Our international refining capacity utilization rate was 90 percent in 2007, compared with 91 percent in 2006. The 2007 utilization rate was affected by a temporary idling of the Wilhelmshaven refinery in Germany during the month of August due to economic conditions.
2006 vs. 2005
Net income from the R&M segment increased 7 percent in 2006, compared with 2005. The increase resulted primarily from:
The increase in net income was partially offset by impairments on assets held for sale recognized in 2006, as well as higher depreciation expense.
Net income from our U.S. R&M operations increased 18 percent in 2006, compared with 2005, primarily due to:
These items were partially offset by after-tax impairments of $227 million associated with certain assets held for sale, as well as higher depreciation expense.
Our U.S. refining capacity utilization rate was 92 percent in 2006, the same as in 2005, reflecting unplanned weather-related downtime in both years.
Net income from our international R&M operations decreased 33 percent in 2006, compared with 2005, due primarily to:
These decreases were partially offset by favorable foreign currency exchange impacts and higher refining and marketing sales volumes.
Our international refining capacity utilization rate was 91 percent in 2006, compared with 99 percent in 2005. The decrease reflected scheduled downtime at certain refineries and unscheduled downtime at the Humber refinery in the United Kingdom.
*Represents our net share of our estimate of LUKOILs production and processing.
This segment represents our investment in the ordinary shares of LUKOIL, an international, integrated oil and gas company headquartered in Russia, which we account for under the equity method. During 2005, we expended $2,160 million to purchase LUKOILs ordinary shares, increasing our ownership interest to 16.1 percent. We expended another $2,715 million to increase our ownership interest in LUKOIL to 20 percent at December 31, 2006, based on 851 million issued shares. At December 31, 2007, our ownership interest was 20 percent based on issued shares. Our ownership interest based on estimated shares outstanding, used for equity-method accounting, was 20.6 percent at December 31, 2006 and 2007.
2007 vs. 2006
Net income from the LUKOIL Investment segment increased 28 percent during 2007, primarily due to higher estimated realized prices, higher estimated volumes, and an increase in our average equity ownership. The increase was partially offset by higher estimated taxes and operating costs, as well as the net impact from the alignment of estimated net income to reported results.
Because LUKOILs accounting cycle close and preparation of U.S. generally accepted accounting principles (GAAP) financial statements occur subsequent to our reporting deadline, our equity earnings and statistics for our LUKOIL investment are estimated, based on current market indicators, publicly available LUKOIL operating results, and other objective data. Once the difference between actual and estimated results is known, an adjustment is recorded. This estimate-to-actual adjustment will be a recurring component of future period results. The adjustment to estimated results for the fourth quarter of 2006, recorded in 2007, decreased net income $19 million, compared with a $71 million increase to net income recorded in 2006 to adjust the estimated results for the fourth quarter of 2005.
In addition to our estimate of our equity share of LUKOILs earnings, this segment reflects the amortization of the basis difference between our equity interest in the net assets of LUKOIL and the historical cost of our investment in LUKOIL, and also includes the costs associated with our employees seconded to LUKOIL.
2006 vs. 2005
Net income from the LUKOIL Investment segment increased 100 percent during 2006, compared with 2005, primarily as a result of our increased equity ownership, higher estimated prices and volumes, and a net benefit from the alignment of our estimate of LUKOILs fourth quarter 2005 net income to LUKOILs reported results.
The Chemicals segment consists of our 50 percent interest in Chevron Phillips Chemical Company LLC (CPChem), which we account for under the equity method. CPChem uses natural gas liquids and other feedstocks to produce petrochemicals. These products are then marketed and sold, or used as feedstocks to produce plastics and commodity chemicals.
2007 vs. 2006
Net income from the Chemicals segment decreased 27 percent during 2007, primarily due to lower olefins and polyolefins margins and higher turnaround and weather-related repair costs, offset partially by a capital-loss tax benefit of $65 million recorded in the fourth quarter of 2007.
2006 vs. 2005
Net income from the Chemicals segment increased 52 percent during 2006, compared with 2005. Results for 2006 reflected improved olefins and polyolefins margins and volumes. The results for 2006 also included a hurricane-related business interruption insurance benefit of $20 million after-tax, as well as lower utility costs due to decreased natural gas prices.
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.
2007 vs. 2006
The Emerging Businesses segment had a net loss of $8 million in 2007, compared with net income of $15 million in 2006. The decrease reflects lower margins from the Immingham power plant in the United Kingdom, as well as higher spending associated with alternative energy programs. These decreases were slightly offset by the inclusion of a write-down of a damaged gas turbine at a domestic power plant in 2006 results.
2006 vs. 2005
The Emerging Businesses segment had net income of $15 million in 2006, compared with a net loss of $21 million in 2005. The improved results reflect higher international power margins and volumes. The increase in net income was partially offset by the write-down of a damaged gas turbine, as well as lower domestic power margins and volumes.
Corporate and Other
2007 vs. 2006
Net interest consists of interest and financing expense, net of interest income and capitalized interest, as well as premiums incurred on the early retirement of debt. Net interest decreased 6 percent in 2007, primarily due to higher amounts of interest being capitalized and higher interest income. These decreases were partially offset by the net impact of the interest components of the Quality Bank settlements and a premium on the early retirement of debt.
Corporate general and administrative expenses increased 32 percent in 2007, primarily due to higher benefit-related expenses.
Acquisition-related costs in 2007 included transition costs associated with the Burlington Resources acquisition.
The category Other includes certain foreign currency transaction gains and losses, and environmental costs associated with sites no longer in operation. Results from Other were primarily impacted by foreign currency losses in 2007.
2006 vs. 2005
Net interest increased 86 percent in 2006, compared with 2005. The increase was primarily due to higher average debt levels as a result of the financing required to partially fund the acquisition of Burlington Resources. The increases were partially offset by higher amounts of interest being capitalized, as well as higher premiums incurred in 2005 on the early retirement of debt.
Corporate general and administrative expenses decreased 27 percent in 2006, compared with 2005, primarily due to reduced benefit-related expenses.
Acquisition-related costs in 2006 included seismic relicensing and other transition costs associated with the Burlington Resources acquisition.
Results from Other improved during 2006, compared with 2005, primarily due to foreign currency transaction gains in 2006, versus losses in 2005, partially offset by certain tax items not directly attributable to the operating segments.
CAPITAL RESOURCES AND LIQUIDITY
To meet our short- and long-term liquidity requirements, we look to a variety of funding sources. Cash generated from operating activities is the primary source of funding. In addition, during 2007 we raised $3,572 million in proceeds from asset dispositions. During 2007, available cash was used to support our ongoing capital expenditures and investments program, repurchase shares of our common stock, repay debt, provide loan financing to certain related parties, pay dividends, and meet the funding requirements related to the business venture with EnCana. During 2007, cash and cash equivalents increased $639 million to $1,456 million.
In addition to cash flows from operating activities and proceeds from asset sales, we also rely on our cash balance, commercial paper and credit facility programs, and our shelf registration statements, to support our short- and long-term liquidity requirements. We anticipate these sources of liquidity will be adequate to meet our funding requirements in the near- and long-term, including our capital spending program, our share repurchase program, dividend payments, required debt payments, and the funding requirements related to the business venture with EnCana. For additional information about the EnCana transaction, see Note 16Joint Venture Acquisition Obligation, in the Notes to Consolidated Financial Statements.
Our cash flows from operating activities increased in each of the annual periods from 2005 through 2007. Favorable market conditions played a significant role in the upward trend of our cash flows from operating activities. In addition, cash flows in 2007 benefited from the full year inclusion of the operating activity of Burlington Resources, versus only nine months in 2006. Absent any unusual event during 2008, we expect market conditions will again be the most important factor affecting our 2008 operating cash flows.
Significant Sources of Capital
During 2007, cash of $24,550 million was provided by operating activities, a 14 percent increase over cash from operations of $21,516 million in 2006. Contributing to the increase was a planned inventory reduction in the 2007 period, partially related to the formation of the WRB downstream business venture; the impact of the Burlington Resources acquisition late in the first quarter of 2006; and higher worldwide crude oil prices in 2007. These positive factors were partially offset by the absence of dividends from our Venezuelan operations in 2007.
During 2006, cash flow from operations increased $3,888 million to $21,516 million. The improvement, compared with 2005, reflects higher worldwide crude oil prices and U.S. refining margins, higher
distributions from equity affiliates, and the impact of the Burlington Resources acquisition, partially offset by higher interest payments.
While the stability of our cash flows from operating activities benefits from geographic diversity and the effects of upstream and downstream integration, our short- and long-term operating cash flows are highly dependent upon prices for crude oil, natural gas and natural gas liquids, as well as refining and marketing margins. During 2007 and 2006, we benefited from favorable crude oil and natural gas prices, as well as refining margins. The sustainability of these prices and margins is driven by market conditions over which we have no control. Absent other mitigating factors, as these prices and margins fluctuate, we would expect a corresponding change in our operating cash flows.
The level of our production volumes of crude oil, natural gas and natural gas liquids also impacts our cash flows. These production levels are impacted by such factors as acquisitions and dispositions of fields, field production decline rates, new technologies, operating efficiency, weather conditions, the addition of proved reserves through exploratory success, and the timely and cost-effective development of those proved reserves. While we actively manage these factors, production levels can cause variability in cash flows, although historically this variability has not been as significant as that experienced with commodity prices.
After adjusting our production rates for the impact of the expropriation of our Venezuelan oil operations in June 2007, our BOE production has increased in each of the past three years. These increases were driven primarily by acquisitions, including our increased ownership interest in LUKOIL during 2005 and 2006, the acquisition of Burlington Resources in 2006 and the business venture with EnCana in 2007. Our adjusted 2007 production was approximately 2.25 million BOE per day, after reductions for the expropriation, our exit from Dubai and the sale of non-core assets. We expect 2008 annual production to be similar to the adjusted 2007 amount. Through 2012, we expect our annual production growth rate to average approximately 2 percent. These projections are tied to projects currently scheduled to begin production or ramp-up in those years and exclude our Canadian Syncrude mining operations.
To maintain or grow our production volumes, we must continue to add to our proved reserve base. Our reserve replacement over the three-year period ending December 31, 2007, was 186 percent. The purchase of reserves in place was a significant factor in replacing our reserves over the past three years, partially offset by the expropriation of our Venezuelan oil assets. Significant purchases during this three-year period included reserves added in 2007 related to the EnCana business venture, the 2006 acquisition of Burlington Resources and the 2005 re-entry into Libya, as well as proved reserves added through our investments in LUKOIL.
We are developing and pursuing projects we anticipate will allow us to add to our reserve base going forward. However, access to additional resources has become increasingly difficult as direct investment is prohibited in some nations, while fiscal and other terms in other countries can make projects uneconomic or unattractive. In addition, political instability, competition from national oil companies, and lack of access to high-potential areas due to environmental or other regulation may negatively impact our ability to increase our reserve base. As such, the timing and level at which we add to our reserve base may, or may not, allow us to replace our production over subsequent years.
As discussed in Critical Accounting Estimates, engineering estimates of proved reserves are imprecise, and therefore, each year reserves may be revised upward or downward due to the impact of changes in oil and gas prices or as more technical data becomes available on the reservoirs. In 2007 and 2005, revisions increased our reserves, while in 2006, revisions decreased reserves. It is not possible to reliably predict how revisions will impact reserve quantities in the future. See the Capital Spending section for an analysis of proved undeveloped reserves.
In addition, the level and quality of output from our refineries impacts our cash flows. The output at our refineries is impacted by such factors as operating efficiency, maintenance turnarounds, feedstock availability and weather conditions. We actively manage the operations of our refineries and, typically, any variability in their operations has not been as significant to cash flows as that experienced with refining margins.
In 2006, we received approximately $1.1 billion in distributions from two heavy-oil projects in Venezuela. The majority of these distributions represented operating results from previous years. We did not receive an operating distribution related to these projects in 2007. See the Outlook section for additional discussion concerning our operations in Venezuela.
Proceeds from asset sales in 2007 were $3,572 million, compared with $545 million in 2006. The increase is mainly due to ongoing asset rationalization efforts related to the program we announced in April 2006 to dispose of assets that no longer fit into our strategic plans or those that could bring more value by being monetized in the near term. Through December 31, 2007, this program had generated proceeds of approximately $3.8 billion since inception. In 2008, we expect to complete the disposition of our retail assets in the United States, Norway, Sweden and Denmark.
Commercial Paper and Credit Facilities
In September 2007, we replaced our $5 billion and $2.5 billion revolving credit facilities, with one $7.5 billion revolving credit facility, expiring in September 2012. This facility may be used as direct bank borrowings, as support for the ConocoPhillips $7.5 billion commercial paper program, as support for the ConocoPhillips Qatar Funding Ltd. $1.5 billion commercial paper program, or as support for issuances of letters of credit totaling up to $750 million. The facility is broadly syndicated among financial institutions and does not contain any material adverse change provisions or any covenants requiring maintenance of specified financial ratios or ratings. The credit agreement contains a cross-default provision relating to the failure to pay principal or interest on other debt obligations of $200 million or more by ConocoPhillips, or by any of its consolidated subsidiaries.
Our primary funding source for short-term working capital needs is the ConocoPhillips $7.5 billion commercial paper program, a portion of which may be denominated in other currencies (limited to euro 3 billion equivalent). Commercial paper maturities are generally limited to 90 days. The ConocoPhillips Qatar Funding Ltd. $1.5 billion commercial paper program is used to fund commitments relating to the Qatargas 3 project. At December 31, 2007 and 2006, we had no outstanding borrowings under the credit facilities, but $41 million in letters of credit had been issued at both dates. Under both commercial paper programs, there was $725 million of commercial paper outstanding at December 31, 2007, compared with $2,931 million at December 31, 2006. Since we had $725 million of commercial paper outstanding and had issued $41 million of letters of credit, we had access to $6.7 billion in borrowing capacity under our revolving credit facility at December 31, 2007.
At December 31, 2007, Moodys Investor Service had a rating of A1 on our senior long-term debt; and Standard and Poors Rating Service and Fitch had ratings of A. We do not have any ratings triggers on any of our corporate debt that would cause an automatic event of default in the event of a downgrade of our credit rating and thereby impact our access to liquidity. In the event that our credit rating deteriorated to a level that would prohibit us from accessing the commercial paper market, we would still be able to access funds under our $7.5 billion revolving credit facilities.
We have a universal shelf registration statement on file with the U.S. Securities and Exchange Commission (SEC) under which we, as a well-known seasoned issuer, have the ability to issue and sell an indeterminate amount of various types of debt and equity securities.
We also have on file with the SEC a shelf registration statement under which ConocoPhillips Canada Funding Company I and ConocoPhillips Canada Funding Company II, both wholly owned subsidiaries, could issue an indeterminate amount of senior debt securities, fully and unconditionally guaranteed by ConocoPhillips and ConocoPhillips Company.
At December 31, 2007, we had outstanding $1,173 million of equity in less than wholly owned consolidated subsidiaries held by minority interest owners, including a minority interest of $508 million in Ashford Energy Capital S.A. The remaining minority interest amounts are primarily related to operating joint ventures we control. The largest of these, $648 million, was related to the Darwin LNG project located in northern Australia.
In December 2001, in order to raise funds for general corporate purposes, ConocoPhillips and Cold Spring Finance S.a.r.l. (Cold Spring) formed Ashford Energy Capital S.A. through the contribution of a $1 billion ConocoPhillips subsidiary promissory note and $500 million cash by Cold Spring. Through its initial $500 million investment, Cold Spring is entitled to a cumulative annual preferred return based on three-month LIBOR rates, plus 1.32 percent. The preferred return at December 31, 2007, was 6.55 percent. In 2008, and at each 10-year anniversary thereafter, Cold Spring may elect to remarket their investment in Ashford, and if unsuccessful, could require ConocoPhillips to provide a letter of credit in support of Cold Springs investment, or in the event that such letter of credit is not provided, then cause the redemption of their investment in Ashford. Should ConocoPhillips credit rating fall below investment grade on a redemption date, Ashford would require a letter of credit to support $475 million of the term loans, as of December 31, 2007, made by Ashford to other ConocoPhillips subsidiaries. If the letter of credit is not obtained within 60 days, Cold Spring could cause Ashford to sell the ConocoPhillips subsidiary notes. At December 31, 2007, Ashford held $2.0 billion of ConocoPhillips subsidiary notes and $29 million in investments unrelated to ConocoPhillips. We report Cold Springs investment as a minority interest because it is not mandatorily redeemable and the entity does not have a specified liquidation date. Other than the obligation to make payment on the subsidiary notes described above, Cold Spring does not have recourse to our general credit.
Off-Balance Sheet Arrangements
As part of our normal ongoing business operations and consistent with normal industry practice, we enter into numerous agreements with other parties to pursue business opportunities, which share costs and apportion risks among the parties as governed by the agreements. At December 31, 2007, we were liable for certain contingent obligations under the following contractual arrangements:
For additional information about guarantees, see Note 17Guarantees, in the Notes to Consolidated Financial Statements, which is incorporated herein by reference.
For information about our capital expenditures and investments, see the Capital Spending section.
Our debt balance at December 31, 2007, was $21.7 billion, a decrease of $5.4 billion during 2007, and our debt-to-capital ratio was 19 percent at year-end 2007. Our debt-to-capital ratio at the end of 2008 will depend on realized commodity prices and margins, the funding of our capital program, and the level of our dividends and share repurchases. Our current debt-to-capital target is 20 percent to 25 percent.
Effective January 15, 2007, we redeemed the 8% Junior Subordinated Deferrable Interest Debentures due 2037, at a premium of $14 million, plus accrued interest. This redemption resulted in the immediate redemption by Phillips 66 Capital II of $350 million of 8% Capital Securities. See Note 15Debt, in the Notes to Consolidated Financial Statements, for additional information.
Also, in January 2007, we redeemed our $153 million 7.25% Notes due 2007 upon their maturity. In February 2007, we reduced our Floating Rate Five-Year Term Note due 2011 from $5 billion to $4 billion, with a subsequent reduction in July 2007 to $3 billion. In April 2007, we redeemed our $1 billion Floating Rate Notes due 2007 upon their maturity. In October 2007, we redeemed $300 million of ConocoPhillips Australia Funding Companys Floating Rate Notes due 2009 at par plus accrued interest.
In May 2007, Polar Tankers Inc., a wholly owned subsidiary, issued $645 million of 5.951% Notes due 2037. The notes are fully and unconditionally guaranteed by ConocoPhillips and ConocoPhillips Company.
In December 2007, we terminated interest rate swaps on $350 million of our 4.75% Notes due 2012. No interest rate swaps remain on any of our debt.
In January 2008, we repaid $1 billion of our Floating Rate Five-Year Term Note due 2011, reducing the balance outstanding to $2 billion. In February 2008, we gave notice to redeem in March 2008 our $300 million 7.125% Debentures due 2028 at 102.7 percent, plus accrued interest.
On January 3, 2007, we closed on a business venture with EnCana. As part of this transaction, we are obligated to contribute $7.5 billion, plus accrued interest, over a ten-year period, beginning in 2007, to the upstream business venture, FCCL Oil Sands Partnership, formed as a result of the transaction. An initial contribution of $188 million was made upon closing in January. Quarterly principal and interest payments of $237 million began in the second quarter of 2007, and will continue until the balance is paid. Of the principal obligation amount, approximately $593 million is short-term and is included in the Accounts payablerelated parties line on our consolidated balance sheet. The principal portion of these payments, which totaled $425 million in 2007, is presented on our consolidated statement of cash flows as an other financing activity. Interest accrues at a fixed annual rate of 5.3 percent on the unpaid principal balance. Fifty percent of the quarterly interest payment is reflected as an additional capital contribution and is included in the Capital expenditures and investments line on our consolidated statement of cash flows.
On July 9, 2007, we announced plans to repurchase up to $15 billion of our common stock through the end of 2008. This amount included $2 billion remaining under a previously announced program. During 2007, we repurchased 89.5 million shares of our common stock at a cost of $7.0 billion, including 177,110 shares at a cost of $14 million from a consolidated Burlington Resources grantor trust. We anticipate first-quarter 2008 share repurchases to be $2 billion to $3 billion.
In December 2005, we entered into a credit agreement with Qatargas 3, whereby we will provide loan financing of approximately $1.2 billion for the construction of an LNG train in Qatar. This financing will represent 30 percent of the projects total debt financing. Through December 31, 2007, we had provided $690 million in loan financing, and an additional $43 million of accrued interest. See the Off-Balance Sheet Arrangements section for additional information on Qatargas 3.
In 2004, we finalized our transaction with Freeport LNG Development, L.P. (Freeport LNG) to participate in a proposed LNG receiving terminal in Quintana, Texas. Construction began in early 2005. We do not have an ownership interest in the facility, but we do have a 50 percent interest in the general partnership managing the venture, along with contractual rights to regasification capacity of the terminal. We entered into a credit agreement with Freeport LNG to provide loan financing of approximately $631 million, excluding accrued interest, for the construction of the facility. Through December 31, 2007, we had provided $594 million in loan financing, and an additional $87 million of accrued interest.
In the fall of 2004, ConocoPhillips and LUKOIL agreed to the expansion of the Varandey terminal as part of our investment in the OOO Naryanmarneftegaz (NMNG) joint venture. We have an obligation to provide loan financing to Varandey Terminal Company for 30 percent of the costs of the terminal expansion, but we will have no governance or ownership interest in the terminal. We estimate our total loan obligation for the terminal expansion to be approximately $416 million at current exchange rates, excluding interest to be accrued during construction. This amount will be adjusted as the projects cost estimate and schedule are updated and the ruble exchange rate fluctuates. Through December 31, 2007, we had provided $331 million in loan financing, and an additional $32 million of accrued interest.
Our loans to Qatargas 3, Freeport LNG and Varandey Terminal Company are included in the Loans and advancesrelated parties line on the balance sheet.
In February 2008, we announced a quarterly dividend of 47 cents per share, representing a 15 percent increase over the previous quarters dividend of 41 cents per share. The dividend is payable March 3, 2008, to stockholders of record at the close of business February 25, 2008.
The following table summarizes our aggregate contractual fixed and variable obligations as of December 31, 2007:
Capital Expenditures and Investments
Our capital spending for the three-year period ending December 31, 2007, totaled $39.0 billion. During the three-year period, 67 percent of total spending went to our E&P segment. In addition to our capital expenditures and investments spending during 2007 and 2006, we also provided loans of approximately $700 million and $800 million, respectively, to certain related parties.
Our capital expenditures and investments budget for 2008 is $14.3 billion. Included in this amount is approximately $700 million in capitalized interest. We plan to direct 77 percent of the capital expenditures and investments budget to E&P and 20 percent to R&M. With the addition of loans to certain affiliated companies and principal contributions related to funding our portion of the EnCana transaction, our total capital program for 2008 is approximately $15.3 billion. See the Capital Requirements section, as well as Note 10Investments, Loans and Long-Term Receivables and Note 16Joint Venture Acquisition Obligation, in the Notes to Consolidated Financial Statements, for additional information.
Capital spending for E&P during the three-year period ending December 31, 2007, totaled $26.1 billion. The expenditures over this period supported key exploration and development projects including:
Capital expenditures for construction of our Endeavour Class tankers, as well as for an upgrade to the Trans-Alaska Pipeline System pump stations were also included in the E&P segment.
2008 CAPITAL EXPENDITURES AND INVESTMENTS BUDGET
E&Ps 2008 capital expenditures and investments budget is $11.1 billion, 11 percent higher than actual expenditures in 2007. Thirty-nine percent of E&Ps 2008 capital expenditures and investments budget is planned for the United States.
Capital spending for our Alaskan operations is expected to fund Prudhoe Bay, Greater Kuparuk and western North Slope operations, including the Alpine satellite fields, as well as exploration activities. In addition, we anticipate further development spending in our Cook Inlet Area. As a result of increased production taxes enacted by the state of Alaska in the fourth quarter of 2007, we anticipate our 2008 capital expenditures will be less than originally planned, mainly related to reduced project funding on the North Slope of Alaska.
In the Lower 48, capital expenditures will focus primarily on developing natural gas reserves within core areas, including the San Juan Basin of New Mexico and Colorado; the Lobo Trend of south Texas; the Bossier and Cotton Valley Trends of east Texas and north Louisiana; the Barnett Shale Trend of north Texas; the Anadarko Basin of western Oklahoma; and the Piceance Basin in northwest Colorado. We also plan to pursue oil development in the Williston Basin of Montana and North Dakota, as well as oil and gas developments in southern Louisiana and the Permian Basin of West Texas. Offshore capital will be focused mainly on the Ursa development in the Gulf of Mexico. In addition, investments will be made in West2East for Rockies Express.
E&P is directing $6.8 billion of its 2008 capital expenditures and investments budget to international projects. Funds in 2008 will be directed to developing major long-term projects, including the Kashagan project in the Caspian Sea and the YK field in northern Russia, through the NMNG joint venture with LUKOIL; the J-Block fields, the Britannia satellites and the Ekofisk Area in the North Sea; the Bohai Bay project in China; heavy-oil projects in Canada and western Canada natural gas projects; offshore Block B and onshore South Sumatra in Indonesia; fields offshore Malaysia and Vietnam; the Qatargas 3 LNG project in Qatar; and the Waha concessions in Libya.
PROVED UNDEVELOPED RESERVES
The net addition of proved undeveloped reserves accounted for 77 percent, 37 percent and 44 percent of our total net additions in 2007, 2006 and 2005, respectively. During these years, we converted, on average, 16 percent per year of our proved undeveloped reserves to proved developed reserves. Of our 2,921 million total BOE proved undeveloped reserves at December 31, 2007, we estimated that the average annual conversion rate for these reserves for the three-year period ending 2010 will be approximately 18 percent.
Costs incurred for the years ended December 31, 2007, 2006 and 2005, relating to the development of proved undeveloped oil and gas reserves were $6.4 billion, $6.4 billion, and $3.4 billion, respectively. Estimated future development costs relating to the development of proved undeveloped reserves for the years 2008 through 2010 are projected to be $4.5 billion, $3.6 billion, and $2.6 billion, respectively.
Approximately 78 percent of our proved undeveloped reserves at year-end 2007 were associated with 10 major development areas and our investment in LUKOIL. Eight of the major development areas are currently producing and are expected to have proved reserves convert from undeveloped to developed over time as development activities continue and/or production facilities are expanded or upgraded, and include:
The remaining two major projects, Qatargas 3 in Qatar and the Kashagan field in Kazakhstan, will have undeveloped proved reserves convert to developed as these projects begin production.
Capital spending for Midstream during the three-year period ending December 31, 2007, was primarily related to increasing our ownership interest in DCP Midstream in 2005 from 30.3 percent to 50 percent.
Capital spending for R&M during the three-year period ending December 31, 2007, was primarily for acquiring additional crude oil refining capacity, clean fuels projects to meet new environmental standards, refinery-upgrade projects to improve product yields, the operating integrity of key processing units, as well as for safety projects. In addition, in December 2007, we invested funds to acquire a 50 percent equity interest in the Keystone Oil Pipeline (Keystone), a joint venture to construct a crude oil pipeline from Hardisty, Alberta to U.S. Midwest markets in Illinois and Oklahoma. During this three-year period, R&M capital spending was $6.1 billion, representing 16 percent of our total capital expenditures and investments.
Key projects during the three-year period included:
Major construction activities in progress include:
Internationally, we continued to invest in our ongoing refining and marketing operations to upgrade and increase the profitability of our existing assets, including upgrading the distillate desulfurization capabilities at our Humber refinery in the United Kingdom.
2008 CAPITAL EXPENDITURES AND INVESTMENTS BUDGET
R&Ms 2008 capital budget is $2.8 billion, a 102 percent increase from actual spending in 2007. Domestic spending in 2008 is expected to comprise 74 percent of the R&M budget.
We plan to direct about $1.6 billion of the R&M capital budget to domestic refining, primarily for projects related to sustaining and improving the existing business with a focus on reliability, energy efficiency, capital maintenance and regulatory compliance. Work continues at a number of refineries on projects to
increase crude oil capacity, expand conversion capability and increase clean product yield. Our North American transportation and marketing businesses are expected to spend about $800 million, including investments in the Keystone project.
Outside North America, we plan to spend about $400 million, with a focus on projects related to reliability, safety and the environment, as well as an upgrade project at the Wilhelmshaven, Germany, refinery and the advancement of a full-conversion refinery project in Yanbu, Saudi Arabia.
Capital spending in our LUKOIL Investment segment during the three-year period ending December 31, 2007, was for continued purchases of ordinary shares of LUKOIL to increase our ownership interest. However, no additional purchases were made in 2007, and none are expected in 2008.
Capital spending for Emerging Businesses during the three-year period ending December 31, 2007, was primarily for an expansion of the Immingham combined heat and power cogeneration plant near the companys Humber refinery in the United Kingdom. In addition, in October 2007, we purchased a 50 percent interest in Sweeny Cogeneration LP (SCLP). SCLP provides steam and electric power to the Sweeny refinery complex with any excess power sold into the market. We account for this joint venture using the equity method of accounting.
Legal and Tax Matters
We accrue for non-income-tax-related contingencies when a loss is probable and the amounts can be reasonably estimated. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. In the case of income-tax-related contingencies, we adopted FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxesan interpretation of FASB Statement No. 109 (FIN 48), effective January 1, 2007. FIN 48 requires a cumulative probability-weighted loss accrual in cases where sustaining a tax position is less than certain. Based on currently available information, we believe it is remote that future costs related to known contingent liability exposures will exceed current accruals by an amount that would have a material adverse impact on our consolidated financial statements.
We are subject to the same numerous international, federal, state, and local environmental laws and regulations, as are other companies in the petroleum exploration and production, refining, and crude oil and refined product marketing and transportation businesses. The most significant of these environmental laws and regulations include, among others, the:
These laws and their implementing regulations set limits on emissions and, in the case of discharges to water, establish water quality limits. They also, in most cases, require permits in association with new or modified operations. These permits can require an applicant to collect substantial information in connection with the application process, which can be expensive and time-consuming. In addition, there can be delays associated with notice and comment periods and the agencys processing of the application. Many of the delays associated with the permitting process are beyond the control of the applicant.
Many states and foreign countries where we operate also have, or are developing, similar environmental laws and regulations governing these same types of activities. While similar, in some cases these regulations may impose additional, or more stringent, requirements that can add to the cost and difficulty of marketing or transporting products across state and international borders.
The ultimate financial impact arising from environmental laws and regulations is neither clearly known nor easily determinable as new standards, such as air emission standards, water quality standards and stricter fuel regulations continue to evolve. However, environmental laws and regulations, including those that may arise to address concerns about global climate change, are expected to continue to have an increasing impact on our operations in the United States and in other countries in which we operate. Notable areas of potential impacts include air emission compliance and remediation obligations in the United States.
For example, the Energy Policy Act of 2005 imposed obligations to provide increasing volumes on a percentage basis of renewable fuels in transportation motor fuels through 2012. These obligations were changed with the enactment of the Energy Independence & Security Act of 2007, which was signed in late December. The new law requires fuel producers and importers to provide approximately 66 percent more renewable fuels in 2008 as compared with amounts set forth in the Energy Policy Act of 2005, with increases in amounts of renewable fuels required through 2022. We are in the process of establishing implementation, operating and capital strategies along with advanced technology development to meet these requirements.
Since 1997 when the Kyoto Protocol called for reductions of certain emissions that contribute to increases in atmospheric greenhouse gas concentrations, there have been a range of national, sub-national and international regulations proposed or implemented focusing on greenhouse gas reduction. These actual or proposed regulations do or will apply in countries where we have interests or may have interests in the future. Regulation in this field continues to evolve and while it is likely to be increasingly widespread and stringent, at this stage it is not possible to accurately estimate either a timetable for implementation or our future compliance costs. The overall long-term fiscal impact from this type of regulation is uncertain. Examples of legislation or precursors for possible regulation include:
There is growing consensus that some form of regulation will be forthcoming at the federal level in the United States with respect to greenhouse gas emissions (including carbon dioxide) and such regulation could result in the creation of substantial additional costs in the form of taxes or required acquisition or trading of emission allowances. Additionally, with the continuing trend toward stricter standards, greater regulation and more extensive permitting requirements, our capital and operating environmental expenditures are likely to be substantial and may increase in the future. We may experience significant delays in obtaining all required environmental regulatory permits or other approvals that we need to operate or upgrade our existing facilities or construct new facilities. If there is a delay in obtaining any required environmental regulatory approvals or permits, the operation of our facilities may be interrupted or become subject to additional costs.
We also are subject to certain laws and regulations relating to environmental remediation obligations associated with current and past operations. Such laws and regulations include CERCLA and RCRA and their state equivalents. Remediation obligations include cleanup responsibility arising from petroleum releases from underground storage tanks located at numerous past and present ConocoPhillips-owned and/or operated petroleum-marketing outlets throughout the United States. Federal and state laws require contamination caused by such underground storage tank releases be assessed and remediated to meet applicable standards. In addition to other cleanup standards, many states adopted cleanup criteria for methyl tertiary-butyl ether (MTBE) for both soil and groundwater. Future environmental expenditures associated with the remediation of MTBE-contaminated underground storage tank sites could be substantial.
At RCRA permitted facilities, we are required to assess environmental conditions. If conditions warrant, we may be required to remediate contamination caused by prior operations. In contrast to CERCLA, which is often referred to as Superfund, the cost of corrective action activities under RCRA corrective action programs typically is borne solely by us. Over the next decade, we anticipate that significant ongoing expenditures for RCRA remediation activities may be required, but such annual expenditures for the near term are not expected to vary significantly from the range of such expenditures we have experienced over the past few years. Longer-term expenditures are subject to considerable uncertainty and may fluctuate significantly.
We, from time to time, receive requests for information or notices of potential liability from the EPA and state environmental agencies alleging that we are a potentially responsible party under CERCLA or an equivalent state statute. On occasion, we also have been made a party to cost recovery litigation by those agencies or by private parties. These requests, notices and lawsuits assert potential liability for remediation costs at various sites that typically are not owned by us, but allegedly contain wastes attributable to our past operations. As of December 31, 2006, we reported we had been notified of potential liability under CERCLA and comparable state laws at 64 sites around the United States. At December 31, 2007, we had resolved five of these sites and had received nine new notices of potential liability, leaving 68 unresolved sites where we have been notified of potential liability.
For most Superfund sites, our potential liability will be significantly less than the total site remediation costs because the percentage of waste attributable to us, versus that attributable to all other potentially responsible parties, is relatively low. Although liability of those potentially responsible is generally joint
and several for federal sites and frequently so for state sites, other potentially responsible parties at sites where we are a party typically have had the financial strength to meet their obligations, and where they have not, or where potentially responsible parties could not be located, our share of liability has not increased materially. Many of the sites at which we are potentially responsible are still under investigation by the EPA or the state agencies concerned. Prior to actual cleanup, those potentially responsible normally assess site conditions, apportion responsibility and determine the appropriate remediation. In some instances, we may have no liability or attain a settlement of liability. Actual cleanup costs generally occur after the parties obtain EPA or equivalent state agency approval. There are relatively few sites where we are a major participant, and given the timing and amounts of anticipated expenditures, neither the cost of remediation at those sites nor such costs at all CERCLA sites, in the aggregate, is expected to have a material adverse effect on our competitive or financial condition.
Expensed environmental costs were $1,025 million in 2007 and are expected to be about $1.1 billion in 2008 and 2009. Capitalized environmental costs were $785 million in 2007 and are expected to be about $1.2 billion and $1.1 billion in 2008 and 2009, respectively.
We accrue for remediation activities when it is probable that a liability has been incurred and reasonable estimates of the liability can be made. These accrued liabilities are not reduced for potential recoveries from insurers or other third parties and are not discounted (except those assumed in a purchase business combination, which we do record on a discounted basis).
Many of these liabilities result from CERCLA, RCRA and similar state laws that require us to undertake certain investigative and remedial activities at sites where we conduct, or once conducted, operations or at sites where ConocoPhillips-generated waste was disposed. The accrual also includes a number of sites we identified that may require environmental remediation, but which are not currently the subject of CERCLA, RCRA or state enforcement activities. If applicable, we accrue receivables for probable insurance or other third-party recoveries. In the future, we may incur significant costs under both CERCLA and RCRA. Considerable uncertainty exists with respect to these costs, and under adverse changes in circumstances, potential liability may exceed amounts accrued as of December 31, 2007.
Remediation activities vary substantially in duration and cost from site to site, depending on the mix of unique site characteristics, evolving remediation technologies, diverse regulatory agencies and enforcement policies, and the presence or absence of potentially liable third parties. Therefore, it is difficult to develop reasonable estimates of future site remediation costs.
At December 31, 2007, our balance sheet included total accrued environmental costs of $1,089 million, compared with $1,062 million at December 31, 2006. We expect to incur a substantial majority of these expenditures within the next 30 years.
Notwithstanding any of the foregoing, and as with other companies engaged in similar businesses, environmental costs and liabilities are inherent in our operations and products, and there can be no assurance that material costs and liabilities will not be incurred. However, we currently do not expect any material adverse effect upon our results of operations or financial position as a result of compliance with environmental laws and regulations.
We have deferred tax assets related to certain accrued liabilities, loss carryforwards and credit carryforwards. Valuation allowances have been established to reduce these deferred tax assets to an amount that will, more likely than not, be realized. Uncertainties that may affect the realization of these assets include tax law changes and the future level of product prices and costs. Based on our historical taxable income, our expectations for the future, and available tax-planning strategies, management expects
that the net deferred tax assets will be realized as offsets to reversing deferred tax liabilities and as reductions in future taxable income.
NEW ACCOUNTING STANDARDS
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. This Statement defines fair value, establishes a framework for its measurement and expands disclosures about fair value measurements. We use fair value measurements to measure, among other items, purchased assets and investments, derivative contracts and financial guarantees. We also use them to assess impairment of properties, plants and equipment, intangible assets and goodwill. The Statement does not apply to share-based payment transactions and inventory pricing. In February 2008, the FASB issued a FASB Staff Position (FSP) on Statement No. 157 that permits a one-year delay of the effective date for all non-financial assets and non-financial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). We will adopt this Statement effective January 1, 2008, with the exceptions allowed under the FSP described above and do not expect any significant impact to our consolidated financial statements, other than additional disclosures.
In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial LiabilitiesIncluding an amendment of FASB Statement No. 115. This Statement permits an entity to choose to measure financial instruments and certain other items similar to financial instruments at fair value, with all subsequent changes in fair value for the financial instrument reported in earnings. By electing the fair value option in conjunction with a derivative, an entity can achieve an accounting result similar to a fair value hedge without having to comply with complex hedge accounting rules. We will adopt this Statement effective January 1, 2008, and do not expect any significant impact to our consolidated financial statements.
In December 2007, the FASB issued SFAS No. 141 (Revised), Business Combinations (SFAS No. 141(R)). This Statement will apply to all transactions in which an entity obtains control of one or more other businesses. In general, SFAS No. 141(R) requires the acquiring entity in a business combination to recognize the fair value of all the assets acquired and liabilities assumed in the transaction; establishes the acquisition-date as the fair value measurement point; and modifies the disclosure requirements. This Statement applies prospectively to business combinations for which the acquisition date is on or after January 1, 2009. However, accounting for changes in valuation allowances for acquired deferred tax assets and the resolution of uncertain tax positions for prior business combinations will impact tax expense instead of impacting the prior business combination accounting starting January 1, 2009. We are currently evaluating the changes provided in this Statement.
Also in December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statementsan amendment of ARB No. 51, which changes the classification of non-controlling interests, sometimes called a minority interest, in the consolidated financial statements. Additionally, this Statement establishes a single method of accounting for changes in a parent companys ownership interest that do not result in deconsolidation and requires a parent company to recognize a gain or loss when a subsidiary is deconsolidated. This Statement is effective January 1, 2009, and will be applied prospectively with the exception of the presentation and disclosure requirements which must be applied retrospectively for all periods presented. We are currently evaluating the impact on our consolidated financial statements.
CRITICAL ACCOUNTING ESTIMATES
The preparation of financial statements in conformity with generally accepted accounting principles requires management to select appropriate accounting policies and to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. See Note 1Accounting Policies, in the Notes to Consolidated Financial Statements, for descriptions of our major accounting policies. Certain of these accounting policies involve judgments and uncertainties to such an extent that there is a reasonable likelihood that materially different amounts would have been reported under different conditions, or if different assumptions had been used. These critical accounting estimates are discussed with the Audit and Finance Committee of the Board of Directors at least annually. We believe the following discussions of critical accounting estimates, along with the discussions of contingencies and of deferred tax asset valuation allowances in this report, address all important accounting areas where the nature of accounting estimates or assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change.
Oil and Gas Accounting
Accounting for oil and gas exploratory activity is subject to special accounting rules unique to the oil and gas industry. The acquisition of geological and geophysical seismic information, prior to the discovery of proved reserves, is expensed as incurred, similar to accounting for research and development costs. However, leasehold acquisition costs and exploratory well costs are capitalized on the balance sheet pending determination of whether proved oil and gas reserves have been discovered on the prospect.
Property Acquisition Costs
For individually significant leaseholds, management periodically assesses for impairment based on exploration and drilling efforts to date. For leasehold acquisition costs that individually are relatively small, management exercises judgment and determines a percentage probability that the prospect ultimately will fail to find proved oil and gas reserves and pools that leasehold information with others in the geographic area. For prospects in areas that have had limited, or no, previous exploratory drilling, the percentage probability of ultimate failure is normally judged to be quite high. This judgmental percentage is multiplied by the leasehold acquisition cost, and that product is divided by the contractual period of the leasehold to determine a periodic leasehold impairment charge that is reported in exploration expense.
This judgmental probability percentage is reassessed and adjusted throughout the contractual period of the leasehold based on favorable or unfavorable exploratory activity on the leasehold or on adjacent leaseholds, and leasehold impairment amortization expense is adjusted prospectively. At year-end 2007, the book value of the pools of property acquisition costs, that individually are relatively small and thus subject to the above-described periodic leasehold impairment calculation, was $1,385 million and the accumulated impairment reserve was $429 million. The weighted average judgmental percentage probability of ultimate failure was approximately 65 percent and the weighted average amortization period was approximately 2.1 years. If that judgmental percentage were to be raised by 5 percent across all calculations, pretax leasehold impairment expense in 2008 would increase by approximately $29 million. The remaining $4,134 million of capitalized unproved property costs at year-end 2007 consisted of individually significant leaseholds, mineral rights held in perpetuity by title ownership, exploratory wells currently drilling, and suspended exploratory wells. Management periodically assesses individually significant leaseholds for impairment based on the results of exploration and drilling efforts and the outlook for project commercialization. Of this amount, approximately $2 billion is concentrated in 10 major assets. Management expects less than $50 million to move to proved properties in 2008. Most of the $2 billion is associated with North America and Asia Pacific natural gas projects and North America oil-sands projects, on which we continue to work with co-venturers and regulatory agencies to develop.
For exploratory wells, drilling costs are temporarily capitalized, or suspended, on the balance sheet, pending a determination of whether potentially economic oil and gas reserves have been discovered by the drilling effort to justify completion of the find as a producing well.
Once a determination is made the well did not encounter potentially economic oil and gas quantities, the well costs are expensed as a dry hole and reported in exploration expense. If exploratory wells encounter potentially economic quantities of oil and gas, the well costs remain capitalized on the balance sheet as long as sufficient progress assessing the reserves and the economic and operating viability of the project is being made. The accounting notion of sufficient progress is a judgmental area, but the accounting rules do prohibit continued capitalization of suspended well costs on the mere chance that future market conditions will improve or new technologies will be found that would make the projects development economically profitable. Often, the ability to move the project into the development phase and record proved reserves is dependent on obtaining permits and government or co-venturer approvals, the timing of which is ultimately beyond our control. Exploratory well costs remain suspended as long as the company is actively pursuing such approvals and permits and believes they will be obtained. Once all required approvals and permits have been obtained, the projects are moved into the development phase and the oil and gas reserves are designated as proved reserves. For complex exploratory discoveries, it is not unusual to have exploratory wells remain suspended on the balance sheet for several years while we perform additional appraisal drilling and seismic work on the potential oil and gas field, or we seek government or co-venturer approval of development plans or seek environmental permitting.
Management reviews suspended well balances quarterly, continuously monitors the results of the additional appraisal drilling and seismic work, and expenses the suspended well costs as a dry hole when it determines the potential field does not warrant further investment in the near term. Criteria utilized in making this determination include evaluation of the reservoir characteristics and hydrocarbon properties, expected development costs, ability to apply existing technology to produce the reserves, fiscal terms, regulations or contract negotiations, and our required return on investment.
At year-end 2007, total suspended well costs were $589 million, compared with $537 million at year-end 2006. For additional information on suspended wells, including an aging analysis, see Note 11Properties, Plants and Equipment, in the Notes to Consolidated Financial Statements.
Proved Oil and Gas Reserves and Canadian Syncrude Reserves
Engineering estimates of the quantities of recoverable oil and gas reserves in oil and gas fields and in-place crude bitumen volumes in oil sand mining operations are inherently imprecise and represent only approximate amounts because of the subjective judgments involved in developing such information. Reserve estimates are based on subjective judgments involving geological and engineering assessments of in-place hydrocarbon volumes, the production or mining plan, historical extraction recovery and processing yield factors, installed plant operating capacity and operating approval limits. The reliability of these estimates at any point in time depends on both the quality and quantity of the technical and economic data and the efficiency of extracting and processing the hydrocarbons.
Despite the inherent imprecision in these engineering estimates, accounting rules require disclosure of proved reserve estimates due to the importance of these estimates to better understand the perceived value and future cash flows of a companys E&P operations. There are several authoritative guidelines regarding the engineering criteria that must be met before estimated reserves can be designated as proved. Our reservoir engineering organization has policies and procedures in place that are consistent with these authoritative guidelines. We have qualified and experienced internal engineering personnel who make these estimates for our E&P segment.
All of our proved crude oil, natural gas and natural gas liquids reserves held by consolidated companies have been estimated by ConocoPhillips. Our policy with respect to equity affiliates is either to estimate the
proved reserve quantities ourselves (applicable to those situations where we have a substantial engineering presence), or to rely on estimates prepared by the equity affiliate, and perform a reasonableness review of those assessments. Of the proved reserves attributable to equity affiliates at year-end 2007, 38 percent was based on assessments of the available data performed by ConocoPhillips. The remaining 62 percent, reflecting our equity interest in LUKOIL, was based on estimates prepared by the equity affiliate. These equity-affiliate-prepared estimates are reviewed by ConocoPhillips and adjusted to comply with our internal reserves governance policies.
Proved reserve estimates are updated annually and take into account recent production and sub-surface information about each field or oil sand mining operation. Also, as required by authoritative guidelines, the estimated future date when a field or oil sand mining operation will be permanently shut down for economic reasons is based on an extrapolation of sales prices and operating costs prevalent at the balance sheet date. This estimated date when production will end affects the amount of estimated recoverable reserves. Therefore, as prices and cost levels change from year to year, the estimate of proved reserves also changes.
Our proved reserves include estimated quantities related to production sharing contracts, which are reported under the economic interest method and are subject to fluctuations in prices of crude oil, natural gas and natural gas liquids; recoverable operating expenses; and capital costs. If costs remain stable, reserve quantities attributable to recovery of costs will change inversely to changes in commodity prices. For example, if prices go up then our applicable reserve quantities would decline.
The judgmental estimation of proved reserves also is important to the income statement because the proved oil and gas reserve estimate for a field or the estimated in-place crude bitumen volume for an oil sand mining operation serves as the denominator in the unit-of-production calculation of depreciation, depletion and amortization of the capitalized costs for that asset. At year-end 2007, the net book value of productive E&P properties, plants and equipment subject to a unit-of-production calculation, including our Canadian Syncrude bitumen oil sand assets, was approximately $63 billion and the depreciation, depletion and amortization recorded on these assets in 2007 was approximately $6.9 billion. The estimated proved developed oil and gas reserves on these fields were 6.4 billion BOE at the beginning of 2007 and were 6.1 billion BOE at the end of 2007. The estimated proved reserves on the Canadian Syncrude assets were 243 million barrels at the beginning of 2007 and were 221 million barrels at the end of 2007. If the judgmental estimates of proved reserves used in the unit-of-production calculations had been lower by 5 percent across all calculations, pretax depreciation, depletion and amortization in 2007 would have been increased by an estimated $361 million. Impairments of producing oil and gas properties in 2007, 2006 and 2005 totaled $471 million, $215 million and $4 million, respectively. Of these write-downs, $76 million in 2007, $131 million in 2006 and $1 million in 2005 were due to downward revisions of proved reserves.
Impairment of Assets
Long-lived assets used in operations are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in the future cash flows expected to be generated by an asset group. If, upon review, the sum of the undiscounted pretax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value. Individual assets are grouped for impairment purposes based on a judgmental assessment of the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assetsgenerally on a field-by-field basis for exploration and production assets, at an entire complex level for downstream assets, or at a site level for retail stores. Because there usually is a lack of quoted market prices for long-lived assets, the fair value usually is based on the present values of expected future cash flows using discount rates commensurate with the risks involved in the asset group. The expected future cash flows
used for impairment reviews and related fair value calculations are based on judgmental assessments of future production volumes, prices and costs, considering all available information at the date of review. See Note 13Impairments, in the Notes to Consolidated Financial Statements, for additional information.
Asset Retirement Obligations and Environmental Costs
Under various contracts, permits and regulations, we have material legal obligations to remove tangible equipment and restore the land or seabed at the end of operations at operational sites. Our largest asset removal obligations involve removal and disposal of offshore oil and gas platforms around the world, oil and gas production facilities and pipelines in Alaska, and asbestos abatement at refineries. The fair values of obligations for dismantling and removing these facilities are accrued at the installation of the asset based on estimated discounted costs. Estimating the future asset removal costs necessary for this accounting calculation is difficult. Most of these removal obligations are many years, or decades, in the future and the contracts and regulations often have vague descriptions of what removal practices and criteria must be met when the removal event actually occurs. Asset removal technologies and costs are changing constantly, as well as political, environmental, safety and public relations considerations.
In addition, under the above or similar contracts, permits and regulations, we have certain obligations to complete environmental-related projects. These projects are primarily related to cleanup at domestic refineries and underground storage tanks at U.S. service stations, and remediation activities required by Canada and the state of Alaska at exploration and production sites. Future environmental remediation costs are difficult to estimate because they are subject to change due to such factors as the uncertain magnitude of cleanup costs, the unknown time and extent of such remedial actions that may be required, and the determination of our liability in proportion to that of other responsible parties.
See Note 1Accounting Policies, Note 14Asset Retirement Obligations and Accrued Environmental Costs, and Note 18Contingencies and Commitments, in the Notes to Consolidated Financial Statements, for additional information.
Purchase Price Allocation
Accounting for the acquisition of a business requires the allocation of the purchase price to the various assets and liabilities of the acquired business. For most assets and liabilities, purchase price allocation is accomplished by recording the asset or liability at its estimated fair value. The most difficult estimations of individual fair values are those involving properties, plants and equipment and identifiable intangible assets. We use all available information to make these fair value determinations. We have, if necessary, up to one year after the acquisition closing date to finish these fair value determinations and finalize the purchase price allocation.
Intangible Assets and Goodwill
At December 31, 2007, we had $731 million of intangible assets determined to have indefinite useful lives, thus they are not amortized. This judgmental assessment of an indefinite useful life has to be continuously evaluated in the future. If, due to changes in facts and circumstances, management determines that these intangible assets then have definite useful lives, amortization will have to commence at that time on a prospective basis. As long as these intangible assets are judged to have indefinite lives, they will be subject to periodic lower-of-cost-or-market tests that require managements judgment of the estimated fair value of these intangible assets. See Note 12Goodwill and Intangibles, in the Notes to Consolidated Financial Statements, for additional information.
At December 31, 2007, we had $29.3 billion of goodwill recorded in conjunction with past business combinations. Under the accounting rules for goodwill, this intangible asset is not amortized. Instead, goodwill is subject to annual reviews for impairment at a reporting unit level. The reporting unit or units
used to evaluate and measure goodwill for impairment are determined primarily from the manner in which the business is managed. A reporting unit is an operating segment or a component that is one level below an operating segment. Prior to 2007, within our E&P and our R&M segments, we determined we had one and two reporting units, respectively, for purposes of assigning goodwill and testing for impairment. These were Worldwide Exploration and Production, Worldwide Refining and Worldwide Marketing. In December 2006, we announced a new business strategy for Worldwide Marketing to shift most of our marketing operations to a wholesale channel of trade and significantly increase the level of vertical integration between our refining and wholesale marketing operations. Because of this new business strategy, we plan to dispose of most of the retail outlets we operate or own. During 2007, the execution of this new business strategy was well under way and is expected to be fully in place by the end of 2008. In accordance with SFAS No. 142, Goodwill and Other Intangible Assets (SFAS No. 142), we have reassessed the reporting unit definitions within the R&M segment based on this new business strategy and have concluded that the refining and marketing components within the R&M segment now are economically similar enough to be aggregated into one reporting unit, Worldwide Refining and Marketing, beginning in 2007. No goodwill impairment would have been required in 2007 had we retained Worldwide Marketing as a separate reporting unit.
If we later reorganize our businesses or management structure so that the components within our two reporting units are no longer economically similar, the reporting units would be revised and goodwill would be re-assigned using a relative fair value approach in accordance with SFAS No. 142. Goodwill impairment testing at a lower reporting unit level could result in the recognition of impairment that would not otherwise be recognized at the current higher level of aggregation. In addition, the sale or disposition of a portion of these two reporting units will be allocated a portion of the reporting units goodwill, based on relative fair values, which will adjust the amount of gain or loss on the sale or disposition. When assessing the need for impairments on those sales and disposals, we take into consideration the anticipated allocation of goodwill and provisionally provide for its expected impairment upon final sale or disposal.
Because quoted market prices for our reporting units are not available, management must apply judgment in determining the estimated fair value of these reporting units for purposes of performing the periodic goodwill impairment test. Management uses all available information to make these fair value determinations, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets and observed market multiples of operating cash flows and net income. In addition, if the estimated fair value of a reporting unit is less than the book value (including the goodwill), further judgment must be applied in determining the fair values of individual assets and liabilities for purposes of the hypothetical purchase price allocation. Again, management must use all available information to make these fair value determinations. At year-end 2007, the estimated fair values of our Worldwide Exploration and Production and Worldwide Refining and Marketing reporting units ranged from between 44 percent to 65 percent higher than recorded net book values (including goodwill) of the reporting units. However, a lower fair value estimate in the future for any of these reporting units could result in an impairment.
Projected Benefit Obligations
Determination of the projected benefit obligations for our defined benefit pension and postretirement plans are important to the recorded amounts for such obligations on the balance sheet and to the amount of benefit expense in the income statement. This also impacts the required company contributions into the plans. The actuarial determination of projected benefit obligations and company contribution requirements involves judgment about uncertain future events, including estimated retirement dates, salary levels at retirement, mortality rates, lump-sum election rates, rates of return on plan assets, future health care cost-trend rates, and rates of utilization of health care services by retirees. Due to the specialized nature of these calculations, we engage outside actuarial firms to assist in the determination of these projected benefit obligations. For Employee Retirement Income Security Act-qualified pension plans, the actuary exercises fiduciary care on behalf of plan participants in the determination of the judgmental assumptions used in
determining required company contributions into plan assets. Due to differing objectives and requirements between financial accounting rules and the pension plan funding regulations promulgated by governmental agencies, the actuarial methods and assumptions for the two purposes differ in certain important respects. Ultimately, we will be required to fund all promised benefits under pension and postretirement benefit plans not funded by plan assets or investment returns, but the judgmental assumptions used in the actuarial calculations significantly affect periodic financial statements and funding patterns over time. Benefit expense is particularly sensitive to the discount rate and return on plan assets assumptions. A 1 percent decrease in the discount rate would increase annual benefit expense by $100 million, while a 1 percent decrease in the return on plan assets assumption would increase annual benefit expense by $55 million. In determining the discount rate, we use yields on high-quality fixed income investments (including among other things, Moodys Aa corporate bond yields) with adjustments as needed to match the estimated benefit cash flows of our plans.
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 governors letter on January 24, 2008. As a result of the lack of engagement by the state of Alaska on our proposal, we are reassessing how best to advance the Alaska natural gas pipeline project. During this reassessment, as an initial step we will continue planning and contracting efforts in preparation for route reconnaissance and environmental studies starting in June 2008. We expect to continue to testify before the Alaska Legislature and engage the Alaska public with our view of the best path forward to advance the gas pipeline project.
Negotiations continue between ConocoPhillips and Venezuelan authorities concerning appropriate compensation for the expropriation of the companys oil interests. We continue to preserve all our rights with respect to this situation, including our rights under the contracts we signed and under international and Venezuelan law. We continue to evaluate our options in realizing adequate compensation for the value of our oil investments and operations in Venezuela and filed a request for international arbitration on November 2, 2007, with the International Centre for Settlement of Investment Disputes (ICSID), an arm of the World Bank. The request was registered by ICSID on December 13, 2007.
On October 25, 2007, the Alberta provincial government publicly announced its intention to make a change to the royalty structure for Crown lands, effective January 1, 2009. Although the governments proposed change will require legislative and regulatory amendments to become effective and may be further modified before final adoption, there is a high likelihood there will be some form of change to the royalty structure in Alberta. While the precise impact of the proposed change is not determinable at this time, the adoption of the proposed royalty structure could result in a range of outcomes, including a negative adjustment to our Canadian reserve base. This change will impact both our conventional western Canada natural gas business and our oil sands operations.
CAUTIONARY STATEMENT FOR THE PURPOSES OF THE SAFE HARBOR PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
This report includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. You can identify our forward-looking statements by the words anticipate, estimate, believe, continue, could, intend, may, plan, potential, predict, should, will, expect, objective, projection, forecast, goal, guidance, outlook, effort, target and similar expressions.
We based the forward-looking statements relating to our operations on our current expectations, estimates and projections about ourselves and the industries in which we operate in general. We caution you these statements are not guarantees of future performance and involve risks, uncertainties and assumptions we cannot predict. In addition, we based many of these forward-looking statements on assumptions about future events that may prove to be inaccurate. Accordingly, our actual outcomes and results may differ materially from what we have expressed or forecast in the forward-looking statements. Any differences could result from a variety of factors, including the following:
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Financial Instrument Market Risk
We and certain of our subsidiaries hold and issue derivative contracts and financial instruments that expose our cash flows or earnings to changes in commodity prices, foreign exchange rates or interest rates. We may use financial and commodity-based derivative contracts to manage the risks produced by changes in the prices of electric power, natural gas, crude oil and related products, fluctuations in interest rates and foreign currency exchange rates, or to exploit market opportunities.
Our use of derivative instruments is governed by an Authority Limitations document approved by our Board of Directors that prohibits the use of highly leveraged derivatives or derivative instruments without sufficient liquidity for comparable valuations without approval from the Chief Executive Officer. The Authority Limitations document also authorizes the Chief Executive Officer to establish the maximum Value at Risk (VaR) limits for the company and compliance with these limits is monitored daily. The Chief Financial Officer monitors risks resulting from foreign currency exchange rates and interest rates, while the Senior Vice President of Commercial monitors commodity price risk. Both report to the Chief Executive Officer. The Commercial organization manages our commercial marketing, optimizes our commodity flows and positions, monitors related risks of our upstream and downstream businesses, and selectively takes price risk to add value.
Commodity Price Risk
We operate in the worldwide crude oil, refined products, natural gas, natural gas liquids, and electric power markets and are exposed to fluctuations in the prices for these commodities. These fluctuations can affect our revenues, as well as the cost of operating, investing, and financing activities. Generally, our policy is to remain exposed to the market prices of commodities; however, executive management may elect to use derivative instruments to hedge the price risk of our crude oil and natural gas production, as well as refinery margins.
Our Commercial organization uses futures, forwards, swaps, and options in various markets to optimize the value of our supply chain, which may move our risk profile away from market average prices to accomplish the following objectives:
We use a VaR model to estimate the loss in fair value that could potentially result on a single day from the effect of adverse changes in market conditions on the derivative financial instruments and derivative commodity instruments held or issued, including commodity purchase and sales contracts recorded on the balance sheet at December 31, 2007, as derivative instruments in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended (SFAS No. 133). Using Monte Carlo simulation, a 95 percent confidence level and a one-day holding period, the VaR for those
instruments issued or held for trading purposes at December 31, 2007 and 2006, was immaterial to our net income and cash flows. The VaR for instruments held for purposes other than trading at December 31, 2007 and 2006, was also immaterial to our net income and cash flows.
Interest Rate Risk
The following tables provide information about our financial instruments that are sensitive to changes in short-term U.S. interest rates. The debt table presents principal cash flows and related weighted-average interest rates by expected maturity dates. Weighted-average variable rates are based on implied forward rates in the yield curve at the reporting date. The carrying amount of our floating-rate debt approximates its fair value. The fair value of the fixed-rate financial instruments is estimated based on quoted market prices.
At the beginning of 2007, we held interest rate swaps that converted $350 million of debt from fixed to floating rate. Under SFAS No. 133, these swaps were designated as hedging the exposure to changes in the fair value of $350 million of 4.75% Notes due 2012. This hedge was terminated in December 2007, when we sold our positions in the swaps for approximately $3 million.
The following table presents principal cash flows of the fixed-rate 5.3 percent joint venture acquisition obligation owed to FCCL Oil Sands Partnership. The fair value of the obligation is estimated based on the net present value of the future cash flows, discounted at a year-end 2007 effective yield rate of 4.9 percent, based on yields of U.S. Treasury securities of a similar average duration adjusted for ConocoPhillips average credit risk spread and the amortizing nature of the obligation principal.
Foreign Currency Risk
We have foreign currency exchange rate risk resulting from international operations. We do not comprehensively hedge the exposure to currency rate changes, although we may choose to selectively hedge exposures to foreign currency rate risk. Examples include firm commitments for capital projects, certain local currency tax payments and dividends, and cash returns from net investments in foreign affiliates to be remitted within the coming year.
At December 31, 2007 and 2006, we held foreign currency swaps hedging short-term intercompany loans between European subsidiaries and a U.S. subsidiary. Although these swaps hedge exposures to fluctuations in exchange rates, we elected not to utilize hedge accounting as allowed by SFAS No. 133. As a result, the change in the fair value of these foreign currency swaps is recorded directly in earnings. Since the gain or loss on the swaps is offset by the gain or loss from remeasuring the intercompany loans into the functional currency of the lender or borrower, there would be no material impact to income from an adverse hypothetical 10 percent change in the December 31, 2007 or 2006, exchange rates. The notional and fair market values of these positions at December 31, 2007 and 2006, were as follows:
*Denominated in U.S. dollars (USD) and euro (EUR).
**Denominated in U.S. dollars.
For additional information about our use of derivative instruments, see Note 19Financial Instruments and Derivative Contracts, in the Notes to Consolidated Financial Statements.
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS
All other schedules are omitted because they are either not required, not significant, not applicable or the information is shown in another schedule, the financial statements or in the notes to consolidated financial statements.
Report of Management
Management prepared, and is responsible for, the consolidated financial statements and the other information appearing in this annual report. The consolidated financial statements present fairly the companys financial position, results of operations and cash flows in conformity with accounting principles generally accepted in the United States. In preparing its consolidated financial statements, the company includes amounts that are based on estimates and judgments that management believes are reasonable under the circumstances. The companys financial statements have been audited by Ernst & Young LLP, an independent registered public accounting firm appointed by the Audit and Finance Committee of the Board of Directors and ratified by stockholders. Management has made available to Ernst & Young LLP all of the companys financial records and related data, as well as the minutes of stockholders and directors meetings.
Assessment of Internal Control Over Financial Reporting
Management is also responsible for establishing and maintaining adequate internal control over financial reporting. ConocoPhillips internal control system was designed to provide reasonable assurance to the companys management and directors regarding the preparation and fair presentation of published financial statements.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
Management assessed the effectiveness of the companys internal control over financial reporting as of December 31, 2007. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal ControlIntegrated Framework. Based on our assessment, we believe the companys internal control over financial reporting was effective as of December 31, 2007.
Ernst & Young LLP has issued an audit report on the companys internal control over financial reporting as of December 31, 2007.
February 21, 2008
Report of Independent Registered Public Accounting Firm on Consolidated Financial Statements
The Board of Directors and Stockholders
We have audited the accompanying consolidated balance sheets of ConocoPhillips as of December 31, 2007 and 2006, and the related consolidated statements of income, changes in common stockholders equity, and cash flows for each of the three years in the period ended December 31, 2007. Our audits also included the condensed consolidating financial information and financial statement schedule listed in the Index at Item 8. These financial statements, condensed consolidating financial information, and schedule are the responsibility of the Companys management. Our responsibility is to express an opinion on these financial statements, condensed consolidating financial information, and schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of ConocoPhillips at December 31, 2007 and 2006, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2007, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related condensed consolidating financial information and financial statement schedule, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects the information set forth therein.
As discussed in Note 2 to the consolidated financial statements, in 2006 ConocoPhillips adopted Emerging Issues Task Force Issue No. 04-13, Accounting for Purchases and Sales of Inventory with the Same Counterparty, and the recognition and disclosure provisions of Statement of Financial Accounting Standards No. 158, Employers Accounting for Defined Benefit Pension and Other Postretirement Plansan amendment of FASB Statements No. 87, 88, 106, and 132(R), and in 2005 ConocoPhillips adopted Financial Accounting Standards Board Interpretation No. 47, Accounting for Conditional Asset Retirement Obligationsan interpretation of FASB Statement No. 143.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), ConocoPhillips internal control over financial reporting as of December 31, 2007, based on criteria established in Internal ControlIntegrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 21, 2008 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
ERNST & YOUNG LLP
February 21, 2008
Report of Independent Registered Public Accounting Firm on
Internal Control Over Financial Reporting
The Board of Directors and Stockholders
We have audited ConocoPhillips internal control over financial reporting as of December 31, 2007, based on criteria established in Internal ControlIntegrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). ConocoPhillips management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included under the heading Assessment of Internal Control Over Financial Reporting in the accompanying Report of Management. Our responsibility is to express an opinion on the companys internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A companys internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A companys internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the companys assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, ConocoPhillips maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the 2007 consolidated financial statements of ConocoPhillips and our report dated February 21, 2008 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
ERNST & YOUNG LLP
February 21, 2008
See Notes to Consolidated Financial Statements.
*Net of acquisition and disposition of businesses.
**Net of cash acquired.
See Notes to Consolidated Financial Statements.
See Notes to Consolidated Financial Statements.
Note 1Accounting Policies
Property Acquisition CostsOil and gas leasehold acquisition costs are capitalized and included in the balance sheet caption properties, plants and equipment. Leasehold impairment is recognized based on exploratory experience and managements judgment. Upon achievement of all conditions necessary for the classification of reserves as proved, the associated leasehold costs are reclassified to proved properties.
Exploratory CostsGeological and geophysical costs and the costs of carrying and retaining undeveloped properties are expensed as incurred. Exploratory well costs are capitalized, or suspended, on the balance sheet pending further evaluation of whether economically recoverable reserves have been found. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. If exploratory wells encounter potentially economic quantities of oil and gas, the well costs remain capitalized on the balance sheet as long as sufficient progress assessing the reserves and the economic and operating viability of the project is being made. For complex exploratory discoveries, it is not unusual to have exploratory wells remain suspended on the balance sheet for several years while we perform additional appraisal drilling and seismic work on the potential oil and gas field, or we seek government or co-venturer approval of development plans or seek environmental permitting. Once all required approvals and permits have been obtained, the projects are moved into the development phase and the oil and gas reserves are designated as proved reserves.
Management reviews suspended well balances quarterly, continuously monitors the results of the additional appraisal drilling and seismic work, and expenses the suspended well costs as a dry hole when it judges that the potential field does not warrant further investment in the near term.
See Note 11Properties, Plants and Equipment, for additional information on suspended wells.
Development CostsCosts incurred to drill and equip development wells, including unsuccessful development wells, are capitalized.
Depletion and AmortizationLeasehold costs of producing properties are depleted using the unit-of-production method based on estimated proved oil and gas reserves. Amortization of intangible development costs is based on the unit-of-production method using estimated proved developed oil and gas reserves.
Note 2Changes in Accounting Principles
In June 2006, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxesan interpretation of FASB Statement No. 109 (FIN 48). This Interpretation provides guidance on recognition, classification and disclosure concerning uncertain tax liabilities. The evaluation of a tax position requires recognition of a tax benefit if it is more likely than not it will be sustained upon examination. We adopted FIN 48 effective January 1, 2007. The adoption did not have a material impact on our consolidated financial statements. See Note 24Income Taxes, for additional information about income taxes.
Effective April 1, 2006, we implemented EITF Issue No. 04-13, which requires purchases and sales of inventory with the same counterparty and entered into in contemplation of one another to be combined and reported net (i.e., on the same income statement line). Exceptions to this are exchanges of finished goods for raw materials or work-in-progress within the same line of business, which are only reported net if the transaction lacks economic substance. The implementation of Issue No. 04-13 did not have a material impact on net income.
The table below shows the actual 2007, sales and other operating revenues, and purchased crude oil, natural gas and products under Issue No. 04-13, and the respective pro forma amounts had this new guidance been effective for all the periods prior to April 1, 2006.
For information on our December 31, 2005, adoption of FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligationsan interpretation of FASB Statement No. 143, and related disclosures, see Note 14Asset Retirement Obligations and Accrued Environmental Costs.
In September 2006, the FASB issued SFAS No. 158, Employers Accounting for Defined Benefit Pension and Other Postretirement Plansan amendment of FASB Statements No. 87, 88, 106, and 132(R). This Statement requires an employer that sponsors one or more single-employer defined benefit plans to:
We adopted the provisions of this Statement effective December 31, 2006, except for the requirement to measure plan assets and benefit obligations as of the date of the employers fiscal year end, which we will adopt effective December 31, 2008. For information on the impact of the adoption of this new Statement, see Note 23Employee Benefit Plans.
In June 2006, the FASB ratified EITF Issue No. 06-3, How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That is, Gross versus Net Presentation). Issue No. 06-3 requires disclosure of either the gross or net method of presentation for taxes assessed by a governmental authority resulting from specific revenue-producing transactions between a customer and a seller. For any such taxes reported on a gross basis, the entity must also disclose the amount of the tax reported in revenue in the interim and annual financial statements. We adopted the Issue effective December 31, 2006. See Note 1Accounting Policies, for additional information.
In December 2004, the FASB issued SFAS No. 123 (revised 2004), Share-Based Payment, (SFAS No. 123(R)), which superseded APB Opinion No. 25, Accounting for Stock Issued to Employees, and replaced SFAS No. 123, Accounting for Stock-Based Compensation, that we adopted effective January 1, 2003. SFAS No. 123(R) prescribes the accounting for a wide range of share-based compensation arrangements, including options, restricted-share plans, performance-based awards, share appreciation rights, and employee share purchase plans, and generally requires the fair value of share-based awards to
be expensed. Our adoption of the provisions of this Statement on January 1, 2006, using the modified-prospective transition method, did not have a material impact on our financial statements. For more information on our adoption of SFAS No. 123(R) and its effect on net income, see Note 1Accounting Policies and the Share-Based Compensation Plans section in Note 23Employee Benefit Plans.
In November 2004, the FASB issued SFAS No. 151, Inventory Costs, an amendment of ARB No. 43, Chapter 4. This Statement clarifies how items, such as abnormal amounts of idle facility expense, freight, handling costs, and wasted material (spoilage) should be recognized as current-period charges. In addition, the Statement requires the allocation of fixed production overhead to the costs of conversion be based on the normal capacity of the production facilities. We adopted this Statement effective January 1, 2006. The adoption did not have a material impact on our financial statements.
Note 3Common Stock Split
On April 7, 2005, our Board of Directors declared a 2-for-1 common stock split effected in the form of a 100 percent stock dividend, payable June 1, 2005, to stockholders of record as of May 16, 2005. The total number of authorized common shares and associated par value per share were unchanged by this action. Shares and per-share information in this report are on an after-split basis for all periods presented.
Note 4Discontinued Operations
During 2005, we sold the majority of the remaining assets that had been previously classified as discontinued operations and reclassified the remaining immaterial assets back into continuing operations.
Sales and other operating revenues and income (loss) fr