OGJ Newsletter

Aug. 24, 2009

General InterestQuick Takes

Venture dismisses Centrica's final offer deadline

Venture Production PLC again rejected the £1.3 billion cash takeover bid from Centrica Ltd., despite a deadline extension to Aug. 28 to buy shares in the company.

Venture said the offer undervalued the company and urged shareholders not to sign any documentation relating to Centrica's deal. It called on Centrica to offer a "fair price" for its unique portfolio in the UK North Sea.

Centrica received valid acceptances representing 40.8% of the issued share capital of Venture. It has shown an interest in the company for months and has obtained 29.9% of it.

A report compiled by Resource Investment Strategy Consultants pegged Venture's worth at 1,066-1,385 pence/share, much more than the 845 pence/share submitted by Centrica.

But Centrica dismissed the report commissioned by Venture, arguing it was highly optimistic and lacked credibility. "The offer represents a compelling opportunity for Venture shareholders to realize the value of their shares in cash at a time of continued economic uncertainty and market volatility," it added.

Venture also insisted it has the "financial strength" and technical expertise to implement its projects in the UK North Sea.

The European Commission is reviewing the merger process and is to be finished by Aug. 26. Centrica said it believes "no material antitrust issues are likely to arise in relation to the offer."

Thailand's PTTEP reduces 2009 budget

Thailand's PTT Exploration & Production PLC (PTTEP) has cut its 2009 capital expenditures by 12%, or 16 billion baht ($470.58 million), to 120 billion baht to cope with the economic slowdown.

As a result, it reduced the number of wells to be drilled worldwide this year to 35 from 44, according to PTTEP Chief Executive Anon Sirisaengtaksin.

However, the company aims to maintain its targeted 2009 petroleum sales volume at 240,000 boe/d, and even in the "worst case" scenario does not expect the rate to miss the target by more than 3%, he said. PTTEP had sales of 232,957 boe/d in the second quarter.

The majority state-owned firm expects to boost its worldwide production by 25% over the next 4 years to 300,000 boe/d with incremental output coming from new fields, both domestic and international.

About 70-75% of the production would come from domestic fields and the rest from elsewhere.

PTTEP posted a second-quarter net profit of 6.5 billion baht, or 1.96 baht/share, down from 12.9 billion baht a year earlier, but up from 5.75 billion baht in the previous quarter.

Santos sells down Bonaparte gas fields

Santos has sold 60% of its interests in the Petrel, Tern, and Frigate gas fields in the Bonaparte Gulf straddling the Western Australian and Northern Territory offshore border to GDF Suez for $200 million.

Santos previously held 100% interest in the fields. GDF Suez will gain operatorship in 2011.

The two companies also have formed a joint venture called Bonaparte LNG to develop the fields via a floating LNG facility capable of producing 2 million tonnes/year of LNG as well as market the gas. GDF Suez will lift all the LNG production and ship it to the Asia-Pacific region.

GDF Suez will carry Santos's share of pre-FEED and FEED costs and make an additional payment to Santos of $170 million once a final investment decision is reached.

The deal is conditional on Australian Foreign Investment Review Board approval.

Contingent reserves in the fields total 220 million boe, although much of this is dry gas with estimated reserves of 1.5 tcf.

The fields were discovered by ARCO about 30-40 years ago—Petrel with a spectacular blow-out and rig fire in 1969, Tern in 1971, and Frigate in 1978. Santos drilled Frigate Deep-1 to confirm that discovery in 2008.

They lie 250-300 km west of Darwin.

Numerous plans for their development over the years, usually via a pipeline to shore, have never eventuated partly because of the low liquids content and hence lack of an additional revenue stream.

This deal represents GDF Suez's first entry into Australia's petroleum exploration and production business.

Delphi to buy Alberta properties, infrastructure

Delphi Energy Corp., Calgary, announced earlier this month it will buy some natural gas properties in the Gold Creek and Wapiti areas of northwest Alberta for $11.8 million (Can.). These properties are between Delphi's Hythe and Bigstone properties.

Delphi also said it will dispose of 40% of the acquired working interest in the properties to an unnamed third party following close of the acquisition at the end of this month.

The purchase brings with it the following:

  • Incremental production of 400 boe/d, consisting of 77% natural gas and 23% oil and NGLs, and proven-plus-probable reserves effective May 31 of more than 1.4 million boe.
  • Ownership in three natural gas processing plants with combined throughput capacity of 720 MMcfd, 10 compressor stations, and 393 km of gathering and transportation pipelines. The gas plants are the Devon Wapiti Deep Cut gas plant, Devon Wapiti Shallow Cut gas plant, and BP's South Wapiti gas plant.
  • Reserves and production-acquisition costs, excluding about $1 million allocated to undeveloped land.

Industry Scoreboard

Exploration & Development Quick Takes

BLM seeks comments on Colorado project

The US Bureau of Land Management is seeking public comments on an oil and natural gas development proposal on federal leases near Silt, Colo., BLM's field office in Glenwood Springs announced.

It said on Aug. 18 that Bill Barrett Corp. submitted a master development plan for the Gibson Gulch area with plans to drill as many as 136 new wells from 10 proposed well pads over 5 years, starting this fall.

The proposed development area covers 2,700 acres, 1,867 of which are federal surface and minerals, 40 of which are private surface and federal minerals, and 793 acres are private surface and minerals, according to the BLM field office. County Roads 311 and 335 would provide primary access, it indicated.

The Denver independent's proposal calls for construction of 4.2 miles of access roads and 4.3 miles of pipelines, the BLM field office said. Most of the wells would use directional drilling technology, it added.

BLM plans to prepare an environmental assessment of the plan and would like to hear any specific issues, concerns, and comments the public would like to see addressed in it by Sept. 18, the field office said.

MMS changes term of some geophysical data

The US Minerals Management Service published a final rule that enables producers to request extensions to the length of time the agency treats their data as proprietary.

Currently the US Department of the Interior agency treats seismic and other data collected through permitted geophysical operations as proprietary for 25 years. The new rule, which was published in the Aug. 13 Federal Register and goes into effect Sept. 14, will allow companies to request a 5-year extension under certain conditions. "This new rule will encourage companies to reprocess old data using new technology and modeling systems to gain a better understanding of the resources available on the Outer Continental Shelf," said Chris Oynes, MMS associate director for offshore energy and minerals management. The new rule was designed to allow producers sufficient time to market geophysical information that might not have been reprocessed otherwise, he explained.

"The opportunity to apply for an extension to the proprietary term provides greater potential for a company to realize the commercial benefits of the data they've analyzed," Oynes said. "Because the companies are required to share the data with the MMS, it also will give us a better understanding of available resources and will enable us to make more informed decisions regarding offshore energy development."

Maramzai-1 in Pakistan shows gas, condensate

Hungary's MOL Pakistan Oil & Gas Co. reported a discovery with the Maramzai-1 exploratory well on Tal Block in North West Frontier Province of Pakistan, saying it tested 12 MMcfd of natural gas and 430 b/d of condensate.

MOL serves as operator for the consortium holding interest in the block. Its partners are Oil & Gas Development Co. Ltd., Pakistan Petroleum Ltd., Pakistan Oilfields Ltd., and Government Holdings (Pvt.) Ltd.

The well, which was drilled to the Lockhart limestone formation, flowed from the uppermost reservoir section. Drilling continues to penetrate and test the potentially prospective lower zones.

The full extent of the discovery will be known once the well reaches the planned total depth during the next few months.

Beach makes oil find in Eromanga basin

Beach Petroleum NL, Adelaide, and its joint venture partner, Drillsearch Energy Ltd., Sydney, have made an oil discovery in permit PEL91 in the South Australian part of the Eromanga basin.

The Chiton-1 wildcat well found a 5.5-m oil interval in the primary Mesozoic-age Namur sandstone target.

It is the first oil discovery in the permit and, although at a P50 estimate of 120,000 bbl of reserves, it is relatively close to existing infrastructure and will be completed for future production.

Chiton-1 is the first of two wells planned in PEL91 along the oil fairway on the western flank of the Patchawarra Trough, which has seen recent discoveries in adjoining permits PELs 92 and 104.

The Chiton discovery significantly reduces the risk of oil charge for other prospects in the block and provides extra confidence for the programs to come.

The second well in PEL91 will be Marino-1 about 8 km north of Chiton, also with a Namur sandstone target.

Bowleven plans appraisal wells in Cameroon

Bowleven PLC plans to drill the IF-2 and IF-3 appraisal wells on IF field within the Etinde permit in Cameroon by second quarter 2010.

The field lies on Block 7 and is estimated to hold 53 million bbl of contingent resources, according to a report by TRACS International Consultancy Ltd. Bowleven also will reprocess 3D seismic and acquire 100 sq km of 3D seismic over the IE and IF discoveries.

Bowleven would use a spread-moored floating, production, storage, and offloading vessel to bring the field on stream if the appraisal is successful. First oil could be produced in 2012 through four production wells, (two of which will be completed appraisal wells) and 3 injector wells. Each production well could deliver 10,000 b/d and injectors 15,000 b/d.

The first phase of the field's development would cost an estimated $106 million. The second phase involves a fuel gas line to Limbe with onshore processing facilities, which will have a capacity of 60,000 b/d of liquids, a water injection capacity of 60,000 b/d, and a gas capacity of 36 MMscfd. The cost of the second phase would hit $209 million.

The work will be done in partnership with its new farm-in partner, Vitol E&P Ltd., Geneva, which will contribute $100 million towards the work program that is expected to finish in 2011. Under a farm-in agreement signed Aug. 13, Vitol will acquire a 25% interest from Bowleven, reducing its share to 75%. This is subject to approval from the Cameroon government and Bowleven's shareholders. If the go-ahead is given, it will become effective from July 1.

According to the farm-in agreement, Vitol also has the option to gain another 25% interest by Sept. 30, 2010, in return for funding an additional $100 million gross work program and paying $25 million in cash to the group to progress Etinde activities. If Vitol exercises the option, it will assume operatorship of the permit and Bowleven will become its technical partner with a 50% interest.

The Etinde permit covers three shallow water blocks off Cameroon, spanning parts of the Rio Del Rey and Douala basins, both of which have proven petroleum systems and discovered hydrocarbon resources.

Drilling & ProductionQuick Takes

Chevron advances Minas chemical flood

Chevron Pacific Indonesia is moving ahead with its pilot chemical injection project in giant Minas oil field in Sumatra, Indonesia (OGJ, Apr. 21, 2008, p. 41).

The company let contract to Technip for detail engineering, project management, procurement assistance, and construction management for water treatment and cooling facilities and a polymer and surfactant mixing plant, including chemical injection packages and production facilities.

Chevron began chemical injection last year. It hopes the project will boost recovery at Minas and surrounding fields. The Minas resource has been estimated at 4 billion bbl of oil initially in place.

Production increase planned for Bongkot field

The consortium led by Thailand's PTT Exploration & Production PLC (PTTEP) is set to ramp up production from its greater Bongkot field off Thailand by 58% to 870 MMcfd of gas in the next 2-3 years. The incremental delivery of 320 MMcfd will come from the major sister field in the Gulf of Thailand, Bongkot South, which is slated to come on stream between mid-2012 and mid-2013, behind the previous schedule of 2011.

The Bongkot partnership recently finalized an agreement to sell Bongkot South gas to PTT PLC, Thailand's biggest energy firm. PTTEP operates Bongkot with a 44.4445% share with France's Total E&P and BG Group holding 33.3333% and 22.2222%, respectively.

The main Bongkot field 600 km south of Bangkok has been in production since July 1993 and at its peak in 2007 produced an average of 629 MMcfd of gas and 17,870 b/d of condensate, more than the 550 MMcfd contractual rate agreed with PTT.

Maersk Oil starts production from Affleck

Maersk Oil UK Ltd. has brought Affleck field on stream in the central UK North Sea, adding potentially 8,000 b/d of oil to its portfolio when it reaches full capacity.

The field was originally scheduled to start production in July 2007, but was delayed due to the Janice floating production unit (FPU) had two lengthly shutdown periods after being given prohibition orders by safety watchdog Health & Safety Executive.

A company spokesman told OGJ that it had initially started at 2,000 b/d through two subsea horizontal production wells tied back via a 28-km production flow line to the Janice FPU on Block 30/17a, also operated by Maersk Oil.

The Affleck subsea manifold, umbilical, and control systems could utilize up to four production wells for future upside potential. Hydrocarbons are being produced from a chalk formation and Maersk Oil used the Noble TVL rig to complete development drilling.

Maersk constructed a new gas export spurline to the Clyde platform, which is operated by partner Talisman North Sea Ltd. "We have also undertaken a significant modification program on Janice to process and export Affleck production fluids, said Tom Van Leenen, Maersk Oil managing director. "In addition Clyde has also undergone topside modifications," he said.

Affleck was first discovered by Royal Dutch Shell PLC in 1974. Oil is being exported through the existing Janice pipeline into Norpipe, and then to Teeside. Gas is being routed through existing ties on the Janice and Judy export pipeline to SEGAL, via the Clyde and Fulmar facilities, and onward to the St. Fergus terminal.

Processing Quick Takes

Pemex settles on new refinery site

Mexico's Petroleos Mexicanos (Pemex) said it has settled on a site at Tula in Hidalgo state to construct a $9-billion refinery, and will modernize another facility at Salamanca in nearby Guanajuato state for $3 billion.

According to Pemex Chief Executive Officer Jesus Reyes Heroles, Hidalgo was the first of the two states to acquire the 700 hectares the firm needed for the refinery, ending a contest between the two over which would host the new facility.

The contest began shortly after mid-April when Pemex announced plans to build the refinery in Tula while simultaneously carrying out a reconfiguration of the Salamanca refinery in Guanajuato state (OGJ Online, Apr. 16, 2009).

But Hidalgo failed to produce the needed 700 hectares within 100 days of the original announcement, and Pemex then said the new refinery would go to whichever state acquired the land first, while the other state would have its existing refinery reconfigured.

According to Heroles, the Hidalgo government was the first of the two states to complete "all the necessary requirements to guarantee legal certainty on land ownership that the state company requires."

The 300,000 b/d facility to be built in Tula is expected to come on stream in 2015, while the expansion of the Guanajuato facility will be ready by yearend 2014.

Reyes said it will cost $673 million less for Pemex to build the refinery in Tula than in Salamanca, largely because of lower costs for pipelines and transport.

"The crude for the new refinery, which comes from the south of the country, will (travel a shorter distance to reach) Tula, and therefore the amount to be invested in pipelines and transport will be less," he said.

Detailing figures, Reyes said that a total of $859 million will be invested in pipelines for the Tula refinery, compared with $1.28 billion if the Salamanca site had been chosen.

Reyes said Tula was chosen also because it can use 70,000 b/d of residual fuels produced at existing refineries in the area, compared with just 50,000 b/d at the Guanajuato facility.

Biodiesel plant starts up at Finland refinery

Neste Oil Corp. began operating its second plant to produce renewable diesel in late July at the company's main refinery at Porvoo, Finland. The new plant can produce 170,000 tonnes/year of NExBTL renewable diesel. It uses a proprietary technology that converts bio-based inputs into a fuel that closely resembles fossil diesel in chemical composition.

Neste Oil commissioned its first 170,000 tpy NExBTL plant, also in Porvoo, in summer 2007 and is building two worldscale plants in Singapore and Rotterdam capable of producing 800,000 tpy each. They are due to be completed in 2010 and 2011, repectively. Neste Oil has refineries in Porvoo and Naantali with combined refining capacity of about 260,000 b/d. In 2008, according to the company, it had net sales of €15 billion.

Transportation Quick Takes

PNSC updates oil tanker fleet

Pakistan National Shipping Corp. (PNSC) has short-listed two Japanese-built oil tankers for acquisition at a cost of $60 million.

PNSC said it could make the acquisitions after the finance ministry gave permission to convert its rupees into dollars.

The two vessels with twin-hulls are anchored off Turkey and Spain. One was built in 1997 and the other in 2003. PNSC declined to identify the vessels further. The company will proceed with the bidding process following successful completion of inspections.

The proposed acquisitions are part of PNSC's plan to update its ageing tanker fleet. Except the recently acquired M/T Quetta oil tanker, built in 2005, its other vessels have an average age of 28 years. Pakistan currently has three oil tankers, of which only the M/T Quetta has a twin-hull. The other two, M/T Swat and M/T Jauhar, will not be seaworthy after the 2011 deadline imposed by the International Maritime Organization for retiring single-hull tankers, officials said.

ExxonMobil secures Gorgon-Jansz LNG contract

ExxonMobil Corp. has secured another customer to complete its share of LNG from the Gorgon-Jansz project by signing up PetroChina for a 20-year supply deal.

ExxonMobil will supply the Chinese company with 2.25 million tonnes/year of LNG for 20 years. The deal is worth an estimated $50 billion (Aus.) and comes on the heels of last week's finalization of an agreement to supply Petronet of India with 2 million tpy from Gorgon-Jansz (OGJ Online, Aug. 12, 2009).

The project has now received environmental approval from the Western Australian government for the three-train 15 million tpy liquefaction plant to be constructed on Barrow Island and is expecting word on the federal government's environmental stance by early September. If this is positive the way will be clear for the Chevron Australia-led joint venture to make its final investment decision on the development within the next few months.

Origin, ConocoPhillips choose CSM-LNG site

The Australia Pacific LNG joint venture of Origin Energy Ltd., Sydney, and ConocoPhillips's Australian arm in Perth chose Laird Point on Curtis Island near Gladstone in Queensland as the site of its proposed LNG plant. The plant will be fed by coalseam methane from the Surat and Bowen basins. The 50-50 JV secured the 230-hectare site from the Queensland government. The LNG project is scheduled to sell its first shipment to international markets in 2014.

The companies say the project will create 10,300 jobs during the construction period with 18,600 direct and indirect jobs created nationally during the peak years from 2012-15. The JV intends to lodge its environmental impact statement for the project early next year with a final investment decision timed for the end of 2010.

Overall plans are to develop the JV's vast CSM reserves base into a 14-16 million tonne/year LNG plant at the Curtis Island site.

Petrobras gets license for LNG terminal

Brazil's Petroleo Brasileiro SA (Petrobras) has received an operating license for its 14 cu m/day LNG regasification terminal at Guanabara Bay in Rio de Janeiro state.

Rio de Janeiro's Environmental Institute Inea issued the license, which also includes approval for a pipeline connecting the terminal and the future compression station in Campos Eliseos, also in Guanabara Bay.

The license, which will be valid until July 29, 2014, enables Petrobras subsidiary Transportadora Associada de Gas SA to operate the facility—Brazil's second after Pecem Port in Ceara state.

Petrobras's Golar Spirit floating regasification plant concluded initial tests at Guanabara Bay in April, with deliveries made via pipeline to two gas-fired power plants in southeast Brazil.

Testing at Guanabara Bay started on Mar. 26, with regasified LNG delivered to the two gas-fired power plants which generated average daily output of 435 Mw and 215 Mw, respectively.

Petrobras last year completed construction and testing of the terminal at Pecem, which has installed capacity to produce 7 million cu m/day of gas. Last month, Royal Dutch Shell PLC delivered the first LNG to Petrobras, supplying 135,000 cu m to the Pecem terminal under an agreement signed in 2008.

In May, Maria das Gracas Silva Foster, Petrobras gas and energy director, said the firm plans to complete the construction of its third LNG terminal by January 2013, adding that its capacity could reach 20 million cu m/day of gas.

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