BHP Billiton reportedly to make cash offer of $44.6 billion for Anadarko
Increased speculation has Australian mining giant BHP Billiton preparing a cash offer of $90 a share, or $44.6 billion, for Houston-based Anadarko Petroleum, one of the world's largest independent oil and gas producers. However, some analysts believe BHP Billiton will have to increase its offer to $110 a share or more in order for the deal to work.
As of Dec. 31, Anadarko shares were trading at nearly $77 a share, up nearly $27 a share since speculation of the BHP Billiton buyout first surfaced in early September. Anadarko stock is currently trading at a 52-week high and has been as low as $34.54 this year.
Spokesmen for Anadarko and BHP Billiton declined to comment on the acquisition reports, although it appears likely that BHP Billiton is the source of the rumors. Anadarko is famously close-mouthed about its deals. Prior to its 2006 acquisition of Kerr-McGee and Western Gas Resources, executives for the three companies reportedly met in airplane hangars to negotiate in order to avoid being seen together.
After BHP Billiton failed in its efforts to acquire Canadian fertilizer giant Potash Corp. and mining giant Rio Tinto this year, company executives have hinted that they would like to add a large petroleum company to their portfolio. Anadarko, as the largest independent producer in the Gulf of Mexico and a major holder of shale assets in the US, would seem to be a good fit for the Australian company. Anadarko also has several major development projects underway in Ghana, Brazil, and Algeria.
Anadarko stock fell earlier this year after the fatal explosion aboard the BP-operated Macondo well in the deepwater Gulf of Mexico and the subsequent massive oil spill. Anadarko has a 25% stake in the well, which has raised questions about potential liability for the company.
In November, Credit Suisse analysts said that Anadarko, along with Australia's Woodside Petroleum, were likely acquisition targets for BHP Billiton. Anadarko reportedly has $19 billion in undeveloped oil and gas projects, which could be developed more quickly with a cash injection from BHP Billiton, which is financially very healthy.
A recent Credit Suisse report says that Anadarko "holds the deepest and most scalable asset portfolio [among independent petroleum companies]" and is a very attractive acquisition target.
If the $90-or-better offer is completed, it would easily surpass the $41 billion merger between XTO Energy and Exxon Mobil Corp., which was completed in 2010 and was the largest deal in the petroleum industry in years.
Chevron sanctions GoM Big Foot projectCompany to spend $5.4B on upstream projects in 2011Chevron Corp. has sanctioned development of its $4 billion Big Foot project in the deepwater US Gulf of Mexico and plans to shift more investment spend to the upstream sector in 2011.
Big Foot
"Sanctioning Big Foot underscores our commitment to the Gulf of Mexico and will contribute to future US energy supply," said George Kirkland, vice chairman, Chevron Corp.
Big Foot will be Chevron's sixth operated facility in the deepwater Gulf of Mexico and located approximately 225 miles south of New Orleans, Louisiana, in water depths of 5,200 feet. The development will utilize a dry tree Extended Tension Leg Platform with an on-board drilling rig and have production capacity of 75,000 barrels of oil and 25 million cubic feet of natural gas per day. First oil is anticipated in 2014.
Discovered in 2006, the Big Foot field lies in the Walker Ridge Area and is estimated to contain total recoverable resources in excess of 200 million oil-equivalent barrels.
Primary pay sands are Middle to Upper Miocene ranging from 19,000 to 24,000 feet and lie below a salt canopy ranging from 8,000 to 15,000 feet thick. Three exploration and appraisal wells with multiple sidetracks have been drilled in the field to define the Big Foot structure.
Chevron, through its subsidiary Chevron USA Inc., has a 60% working interest in the Big Foot project. Partners are Statoil (27.5%) and Marubeni (12.5%).
2011 budget
On December 9, Chevron announced its $26 billion capital and exploratory budget for 2011 in which it detailed a shift to a greater proportion of investment spend to the upstream sector.
In 2008, upstream spend represented 75% of the overall program. In 2009, the figure was 80%. In 2011 it will be 85%. According to a company spokesperson, the company is "more heavily weighted in upstream because the returns in the sector are stronger over time."
In the US, the company plans to spend $5.4 billion on upstream projects, which represents 20% of its overall capital program for 2011. Upstream spending expected in 2011 includes projects in the US Gulf of Mexico such as deepwater exploration and development, including Jack/St. Malo, Tahiti-2, Big Foot, Perdido and Buckskin appraisal.
Apache's appraisal offshore Western Australia tests 58 MMcf/dApache Corp. has reported the Spar-2 appraisal well in Permit WA-4-R offshore Western Australia tested 58 million cubic feet (MMcf) of natural gas and 950 barrels of condensate per day.
Apache's Australia subsidiary plans to bring gas from the Spar Field and nearby Halyard Field to Western Australia's domestic gas market via an existing Apache-operated pipeline 10 miles southeast of Spar-2 and through the Varanus Island processing and transportation hub.
First production from Halyard of approximately 50 MMcf per day (gross) is expected in the second half of 2011 with Spar following in late-2012 as additional capacity becomes available at Varanus Island.
Apache owns a 55% interest in both WA-4-R and adjacent Permit WA-13-L, where Halyard is located. Santos owns the remaining interests.
Spar-2 was completed over a perforated interval of 131 feet (40 meters) within 163 feet (50 m) of high-quality gas pay in a single zone at the top of the Barrow Group formation. The appraisal is located about one mile (1.6 kilometers) to the southwest of the Halyard-1 discovery and approximately 18 miles (29 km) southwest of Apache's John Brookes platform.
Thomas M. Maher, vice president and managing director of Apache's Australia Region, said, "The proximity to Apache's existing infrastructure will reduce the time and expense required to develop the project and deliver needed gas supplies to the growing Western Australia market."
The Halyard-1 discovery, drilled in 2008, test-flowed at a peak rate of 68 MMcf of gas and 936 barrels of condensate per day from 91 feet (28 m) of net pay in the Cretaceous Halyard sandstone.
Rapidly growing CNOOC makes deepwater gas find in Qiongdongnan BasinCNOOC Ltd. has made a deepwater gas discovery on Block 64/11 offshore China after the Lingshui 22-1-1 exploration well drilled by its partner, BG Group (BG) , encountered gas-bearing sands.
This recent discovery comes from an exploration well located in Qiongdongnan Basin in the South China Sea approximately 130 kilometres offshore in a water depth of 1,338 metres. BG will conduct further analysis of the well results to evaluate the hydrocarbon potential in the Block.
Zhu Weilin, executive vice president of the company commented, "This is the first deepwater well in Qiongdongnan Basin. We are excited about the well results. It has further strengthened our confidence in deepwater exploration in this area."
The company signed the production sharing contract (PSC) with BG for deepwater block 64/11 on 7th June 2006.
The Chinese oil company has been very active and is growing rapidly. The recent discovery comes on the heels of a partnership with Oklahoma City-based natural gas producer Chesapeake Energy in the Eagle Ford shale in Texas. It is reported that CNOOC is looking to sign additional joint ventures with US and Canadian companies in other North American shale plays. The company recently also signed a major deal to buy Venezuelan crude.
Anadarko makes third gas discovery offshore MozambiqueAnadarko Petroleum Corp. has made its third major natural gas discovery this year in the Offshore Area 1 of Mozambique's Rovuma Basin at the Lagosta prospect. The discovery well encountered a total of more than 550 net feet of natural gas pay in multiple high-quality Oligocene and Eocene sands.
The Lagosta discovery, located approximately 16 miles to the south of its Barquentine discovery and 14 miles to the southeast of the Windjammer discovery, significantly expands this emerging world-class natural gas province, Anadarko senior vice president, Worldwide Exploration Bob Daniels said.
While additional appraisal drilling will be required, the company believes the three discoveries to date exceed the resource size threshold necessary to support an LNG (liquefied natural gas) development. The company has assigned an integrated project team to begin advancing commercialization options, added Daniels.
The Lagosta exploration well has been drilled to a current depth of approximately 13,850 feet in water depths of approximately 5,080 feet. The partnership plans to drill to a total depth of approximately 15,900 feet to evaluate a deeper zone. Once operations are complete at Lagosta, the partnership expects to mobilize the rig 17.5 miles to the southwest to drill the Tubarão exploration well, which also is located in the 2.6-million-acre Offshore Area 1.
Anadarko is the operator of Offshore Area 1 with a 36.5% working interest. Co-owners in the area are Mitsui E&P Mozambique Area 1 Ltd. (20%), BPRL Ventures Mozambique BV (10%), Videocon Mozambique Rovuma 1 Ltd. (10%) and Cove Energy Mozambique Rovuma Offshore Ltd. (8.5%). Empresa Nacional de Hidrocarbonetos ep's 15% interest is carried through the exploration phase.
Talisman, Sasol to partner in Canada's Montney ShaleCalgary-based Talisman Energy signed an agreement with South Africa's Sasol Ltd. on Dec. 20 to create a strategic partnership to develop the Farrell Creek assets in Talisman's Montney Shale play in northeastern British Columbia. Talisman will sell a 50% working interest in its Farrell Creek assets to Sasol for a total consideration of Can$1.05 billion (about US$1.03 billion).
The deal allows Talisman to develop the Farrell Creek area and unlock some of the value of the estimated 44 tcfe of net contingent resource held across its Montney Shale play. Farrell Creek represents about 22% (9.6 tcfe) of Talisman's resource potential in the play and about 275 (51,000 net acres) of the company's 190,000 net Tier 1 acres of land in the Montney.
Sasol will pay 25% of the consideration (about Can$260 million – US$256 million) in cash at closing and carry 75% of Talisman's future capital commitments in the Farrell Creek area to a total of about Can$790 million (US$778 million).
The play has been largely de-risked and production at Farrell Creek is expected to exit this year at between 40 and 60 MMcfe per day, said a Talisman spokesman. Talisman's processing facilities at Farrell Creek have been expanded to 120 MMcf per day, and the company has secured more than 500 MMcf per day of egress capacity from the region.
As part of the deal, the partners have agreed to conduct a feasibility study around the economic viability of a facility in western Canada to convert natural gas to liquid fuels, using Sasol's commercial gas-to-liquids (GTL) technology. This could prove a strategic alternative to traditional North American pipeline or LNG marketing. The outlook for GTL could be very positive if North American natural gas prices continue to decouple from oil prices. The GTL process produces premium, clean liquid fuels.
Sasol will acquire a 50% working interest in all Talisman lands, existing wells, and processing facilities in the Farrell Creek region. Talisman and Sasol will each own 50% of the Farrell Creek assets, with Talisman as operator of the partnership. The companies have also agreed to collaborate on certain other western Canadian natural gas opportunities. Closing is expected in the first half of 2011.
Sasol is looking at expanding its proprietary GTL technology in new markets. Sasol is listed on the Johannesburg and NYSE, and has a market capitalization of about US$30 billion. Goldman, Sachs & Co. and Jefferies & Co. acted as advisors to Talisman on this transaction.
Noble makes gas discovery offshore IsraelNoble Energy Inc. has made a significant natural gas discovery at the Leviathan exploration prospect offshore Israel. Drilled in the Rachel license, the well encountered a minimum of 220 feet of net natural gas pay in several subsalt Miocene intervals. Noble said that apparent reservoir quality is very good, and the intervals discovered are geologically similar to those intersected at Tamar.
Leviathan-1, located in approximately 5,400 feet of water, is about 80 miles offshore of Haifa and 29 miles southwest of the Tamar discovery. The results from the well confirm the pre-drill estimated resource range, with a gross mean for Leviathan of 16 trillion cubic feet. The Leviathan field is estimated to cover approximately 125 square miles and, as a result of its size, will require two or more appraisal wells to further define total gas resources.
Charles D. Davidson, Noble's chairman and CEO, said, "Leviathan is the latest major discovery for Noble Energy and is easily the largest exploration discovery in our history. In the past two years, we and our partners have made three significant natural gas discoveries in the Levantine basin. Total gross mean resources discovered are estimated to be approximately 25 trillion cubic feet, with nearly 8.5 trillion cubic feet net to Noble Energy's interest."
Drilling at Leviathan-1 will continue to a planned total depth of 23,600 feet to evaluate two additional intervals. Current well depth is 16,960 feet. The company's second contracted rig will arrive in early 2011 to spud an appraisal well located 8 miles northeast of the discovery well. Noble operates Leviathan with a 39.66% working interest. Delek Drilling and Avner Oil Exploration both hold a 22.67% interest, and Ratio Oil Exploration holds the remaining 15%.
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