OGJ Newsletter

Jan. 5, 2009
General Interest — Quick Takes

NPRA, others ask for more ethanol blend tests

Fourteen organizations, including the National Petrochemical & Refiners Association, on Dec. 18 called for “unbiased and comprehensive testing” before the US Environmental Protection Agency permits the use of midlevel ethanol blends in engines.

Other groups included the Sierra Club, Natural Resources Defense Council, American Lung Association, Engine Manufacturers Association, and Motorcycle Industry Council.

Calling themselves an informal coalition, the groups said they are concerned about air quality, engine compatibility, and safety.

“There has not been sufficient testing of motor vehicle and nonroad equipment engines to justify a determination that any midlevel ethanol blend would meet the requirements,” they said in a letter to EPA Administrator Stephen L. Johnson.

The test results that exist suggest midlevel ethanol blends might be incompatible with current motor vehicle and nonroad equipment engines, might cause emission control devices or systems to fail, might defeat engines’ safety features, and might lead to significantly higher emissions over the engines’ useful life, they continued.

“Collectively, our organizations strongly believe that this issue should not be part of the rulemaking proposal for the revised Renewable Fuel Standard under the [2007 Energy Independence and Security Act]. The midlevel ethanol blend issue should be discussed at length, but the vehicle should be a separate advance notice of proposed rulemaking,” said the groups.

Australian CSM players continue to consolidate

Two recent takeover announcements will further reduce the number of Australia’s coal seam methane (CSM) players in 2009.

Brisbane-based Arrow Energy Ltd. made a cash and share takeover offer for fellow Brisbane company Pure Energy Resources Ltd., which values Pure at $673 million (Aus.).

This was followed by Sydney company AGL Energy Ltd.’s $171 million all-cash takeover bid for Sydney Gas Ltd.

Arrow’s offer is made up of $2.70/share in cash plus 1.21 Arrow shares for each Pure share.

Arrow began the move already holding 19.9% interest in Pure, setting the net acquisition cost at $551 million. Arrow says it will fund the cash component of its offer through a combination of existing cash reserves and proceeds from an earlier deal to sell 30% of its upstream coal seam methane interests to Shell.

Pure’s independent directors have unanimously recommended the offer to the company’s shareholders, if no superior bid is forthcoming.

The acquisition will provide Arrow with control of additional acreage and reserves in the prospective Walloon Coal Measures in the Surat basin of southeast Queensland, adjacent to its proposed Surat-Gladstone pipeline, as well as further acreage in the Bowen basin further north adjacent to its proposed Moranbah-Gladstone pipeline.

If successful, the acquisition will bring Arrow’s total uncontracted 2P CSM reserves to 2 tcf, which is sufficient to underpin two 1.5-million-tonne/year LNG trains planned for Gladstone.

Arrow’s offer will open Feb. 11 and close Mar. 11.

AGL Energy’s move on Sydney Gas also appears to be friendly in that Sydney Gas directors have unanimously agreed to recommend the offer and will accept shares in the absence of a superior offer.

AGL’s offer values Sydney gas at 42.5¿ (Aus.)/share. AGL will fund the acquisition with cash reserves.

The offer follows AGL’s purchase earlier this month of the prospective permit PEL 285, in the Gloucester basin of northern New South Wales, from fellow CSM players Molopo Australia and AJ Lucas for $370 million.

The Sydney Gas deal will bring AGL full control of the producing and prospective CSM acreage in the Camden and Hunter Valley regions of the Sydney basin in New South Wales.

With AGL’s capacity to meet funding requirements, it believes it is best placed to develop the Sydney basin resources.

AGL’s offer will open Jan. 12 and close Feb. 13.

This recent takeover activity comes hard of the heels of the British BG Group’s successful takeover of Queensland Gas Co., which also gathered in Sunshine Gas Co. and Roma Petroleum¿all CSM players in Queensland.

Industry Scoreboard
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Exploration & Development — Quick Takes

Total finds oil near Ofon field off Nigeria

France’s Total SA discovered oil in shallow water near its producing Ofon oil field in southeastern OML 102 off southeastern Nigeria.

The Etisong-1 well went to TD 2,207 m in 70 m of water and tested more than 6,000 b/d of 40° gravity oil from turbiditic reservoirs.

The well is the first step in an exploration and appraisal program designed to demonstrate the feasibility of a new development pole on OML 102 that would combine production from the Etisong main discovery and as-yet-undrilled surrounding structures.

Total E&P Nigeria operates OML 102 with a 40% interest, and Nigerian National Petroleum Corp. has 60%.

Total E&P Nigeria, already a large oil producer in Nigeria, plans to start production from Akpo deepwater oil field on OML 130 in early 2009. The company is undertaking development studies for Egina oil field on the same block.

ExxonMobil to drill for gas in Poland

Poland’s environment ministry has given ExxonMobil Poland permission to explore for natural gas deposits in eastern and southeastern Poland.

ExxonMobil Poland, which obtained two 5-year licenses for conducting the related operations, plans to conduct seismic surveys and drilling in the Mazowieckie and Lubelskie provinces.

The first concession covers a 1,200 sq km area near Wolomin, northeast of Warsaw, while the second covers a 1,000-sq km area near Zamosc, in southeastern Poland.

ExxonMobil Poland paid $290,000 for the concessions, the ministry said. ExxonMobil Poland’s exploration activities are expected to last 3 years.

Shell cancels 2009 Beaufort Sea drilling program

Shell Oil Co. canceled its exploratory drilling program for 2009 in Alaska’s Beaufort Sea, a region in which the company invested $44 million as recently as 2005.

Instead, Shell said it will focuses on court challenges to its offshore plan. The decision results in a loss of 700 jobs directly related to drilling, more than 100 local support service jobs on the North Slope, and millions of dollars for the region.

Shell also canceled its seismic program in Beaufort for 2009. A company spokesperson said this decision was unrelated to the 9th Circuit Court of Appeals ruling last month that federal regulators improperly granted Shell permission to drill in the Beaufort Sea.

Alaska Gov. Sarah Palin said that state officials intend to support Shell’s petition to the appeals court for a rehearing before the full court.

The US Minerals Management Service environmental assessment determined the proposed exploration “would not significantly affect the quality of the human environment.”

However, the court ordered MMS to reconsider how exploratory drilling would affect wildlife and Inupiat Eskimo subsistence hunting and fishing.

StatoilHydro drops rigs procurement for NCS

StatoilHydro cancelled its rig procurement for operations on the Norwegian Continental Shelf because of high costs and the global economic uncertainty that has dampened oil prices.

The company said it is focused on reducing costs and determining priorities.

On Aug. 25, StatoilHydro received tenders from 15 contractors for 28 rigs, including semisubmersibles and jack ups. Contracts were to start at the end of 2012.

But back when the tenders were made, rates were higher because of greater demand for rigs in those days of higher oil prices. Since then, oil prices have dropped 60%, reducing the number of drilling prospects. As a result, StatoilHydro asked for updated tenders, including reduced rig rates, by Dec. 1.

“Despite the reduction in the prices offered, there is still a considerable gap between the tenders and the expectations we have concerning the rates,” said Anders Opedal, head of procurements in StatoilHydro. “We have therefore decided to terminate the procurement process.”

BP’s Thunder Horse field reaches full production

BP PLC’s Thunder Horse field in the ultradeepwater Gulf of Mexico has begun full production, with output of more than 200,000 boe/d.

Full operation was reached as BP brought the third and fourth wells on stream in the high-pressure, high-temperature field. Thunder Horse platform is in 6,050 ft of water in Mississippi Canyon about 150 miles southeast of New Orleans.

Thunder Horse platform has the capacity for 250,000 b/d of oil and 200 MMcfd of natural gas. The field began producing in June. In 2005, Hurricane Dennis left the platform listing, which slowed the scheduled start of production.

Production is from reservoirs 14,000-19,000 ft below the seabed with reservoir pressures of 13,000-18,000 psi, said BP, which operates Thunder Horse with 75% interest. ExxonMobil Corp. holds the remaining interest.

Additional production from nearby Thunder Horse North field is scheduled for the first half of 2009.

GeoPetro extends Bengara-II appraisal

The Indonesian government granted GeoPetro Resources Co. a 1-year extension to 2010 to submit its work program and 2009 budget to appraise and evaluate commerciality of an oil discovery on Bengara-II Block, Tarakan basin, onshore East Kalimantan.

The oil discovery was made last year on the Seberaba prospects, and the approval could be extended for subsequent years subject to approvals based on an annual review of progress and results of appraisal work, said GeoPetro Resources.

GeoPetro’s 12% owned subsidiary Continental-GeoPetro (Bengara-II) Ltd. (CGB2) will carry out the work. GeoPetro is based in San Francisco.

If CGB2 decided to move to development, it can draw up a commercial development plan. If the government approves the development plan, Bengara-II Block will be held for a 30-year term through December 2027.

“The majority 70% shareholder and manager of CGB2, CNPC (Hong Kong) Ltd., has called a shareholders meeting for mid-January 2009 to discuss appraisal plans which are expected to include a 3D seismic program,” GeoPetro said.

Drilling & Production — Quick Takes

Pertamina to invest $1 billion on production

Indonesia’s state-owned PT Pertamina plans to spend 11 trillion rupiah ($1 billion) to upgrade assets and boost production in Limau oil fields in South Sumatra and Tambun gas fields in Bekasi, West Java.

Of the total upstream investment, 6 trillion rupiah will go to PT Pertamina EP, said Karen Agustiawan, Pertamina’s upstream director.

The company expects to increase oil production 7% in 2009 to 171,250 b/d from an estimated 159,000 b/d in 2008.

Pertamina’s production comes from two subsidiaries. They are Pertamina EP, which produces 80% of the parent firm’s total output, and PT Pertamina Hulu Energi, which manages and develops oil and gas upstream assets through partnerships.

Of the 2008 targeted 159,000 b/d, some 125,000 b/d will be from Pertamina EP while Pertamina Hulu provides the rest. Of 2009’s targeted 171,250 b/d, Pertamina EP is expected to contribute 132,250 b/d.

“The two fields are the backbone of Pertamina EP, and they will become pilot projects (for facility upgrading),” said Agustiawan, who did not specify the upgrades. Pertamina EP expects 6,750 b/d of production to come on stream next year from an oil block in Cepu.

Pertamina plans to acquire bigger shares in several blocks, including the West Madura block in East Java, Total’s Mahakam block in East Kalimantan, and Chevron’s deepwater fields off East Kalimantan.

Pertamina requested a bigger stake in Inpex’s Masela offshore block in the Timor Sea.

“We hope we can get 30% (of the block),” said Pertamina Pres. Director Ari Soemarno.

Pertamina also is negotiating with Verenex Energy Inc. to buy the Canadian firm’s stakes in Libya’s Ghadames basin.

Heritage Oil starts drilling in Kurdistan

Heritage Oil Ltd. has commenced drilling the Miran West-1 well in the Kurdistan Region of Iraq, the first exploration well to be drilled on the Miran license.

Heritage received its license 15 months ago, said Tony Buckingham, Heritage chief executive officer. The drilling contractor is Great Wall Drilling Co. Ltd.

“The Miran block is highly prospective, containing two anticlines that have the potential to contain billions of barrels of oil from multiple potential reservoir targets,” Buckingham said.

The rig will drill the Miran West structure to an anticipated depth of 2,500-3,000 m, targeting what Heritage calls the three principal proved reservoir formations. They are the Shiranish, Kometan, and Qamchuqua reservoirs.

The Miran license contains two large structures, Miran West and Miran East that have been mapped from some 332 km of seismic data acquired by Heritage.

Heritage has a strategic agreement with the Kurdish Regional Government to establish a 50:50 joint venture company aimed at building, owning, and operating a 20,000 b/d oil refinery in the vicinity of the license. The refinery is scheduled to be operational within 2 years.

Heritage is operator and holds a 100% interest in the Miran license, an area of 1,015 sq km west of the city of Suleimaniah.

Indonesian firm forecasts reduced 2009 output

Indonesia’s publicly listed oil and gas company PT Medco Energi Internasional predicts that its oil and gas production could drop in 2009 by as much as 10% due to asset sales and aging fields.

Medco finance director Cyril Noerhadi said the firm had sold participating shares in the Tuban block to state-owned PT Pertamina and in the Simenggaris block to Salamander Energy Ltd.

“Aside from that, our fields on average are already at the aging stage and can no longer produce optimally,” Cyril said.

During the first 9 months of 2008, Medco oil and gas production totaled 65,460 b/d of oil equivalent, down 6.4% from the 69,970 b/d produced during the same period in 2007.

Last year, Medco’s oil production alone reached 50,411 b/d, down from 56,367 b/d in 2006.

The director said Medco’s oil and gas output likely would start increasing again in 2011 after seven key projects are completed.

Although Medco recorded a 51.6% increase in revenue between the first 9 months of 2008, climbing to $972.2 million over last year’s $641.4 million, Cyril declined to state how much the firm planned by way of capital expenditure next year.

“The current economic conditions will narrow down alternatives for capital access,” Cyril said, adding that Medco normally spends $250-300 million annually.

Meanwhile, Medco Pres.-Director Darmoyo Doyoatmojo said new gas facilities being installed on South Sumatra’s Lematang Block would be completed in June 2009.

Darmoyo said the remaining projects, which will be completed in 2011-12, include Block A gas field in Aceh, the enhanced oil recovery project on Block Rimau in South Sumatra, Area 47 in Libya, the Senoro gas field in Central Sulawesi, and a power project in Sarulla, North Sumatra.

Darmoyo also said the company would intensify its search for overseas oil and gas fields as the success rate for confirming feasible reserves in Indonesia remains very low at between 10-15%.

Processing — Quick Takes

Irving Oil lets NB refinery contract

Irving Oil Ltd. has selected Fluor Canada, a subsidiary of Fluor Corp., to perform front-end engineering design for a proposed $7 billion, 300,000-b/d refinery to be constructed in St. John, New Brunswick, 65 miles from the US border.

Irving conducted initial feasibility work and informal public consultation in 2006, and has been engaged since January 2007 in permitting, public consultation, and engineering design for the proposed refinery. It would be situated near Irving’s existing 300,000- b/d refinery and the existing Irving Canaport deepwater crude oil terminal, which receives cargoes via very large crude carriers.

Construction would begin in 2011, and operations start-up is scheduled for 2015.

Transportation — Quick Takes

USGS: Planned LNG line lies in quake zone

Pipelines from a proposed deepwater LNG terminal off Southern California face a 16-48% probability of a damaging earthquake within 30 miles of their route, the US Geological Survey reported Dec. 23.

While the US Department of the Interior agency does not make recommendations for or against proposed projects, researchers found that the probability of an earthquake measuring 6.5 or above on the Richter scale along the OceanWay Secure Energy project’s planned pipeline route in Santa Monica Bay ranged from 16% at its origin 23 miles offshore to 48% at its planned terminus near Los Angeles International Airport.

“Earthquakes of this size can cause damage over a large region,” said USGS in the report, citing impacts of the 1994 Northridge quake, which measured 6.7 points at its epicenter.

USGS said the proposed deepwater LNG project would be situated in 3,000 ft of water and would be connected to onshore systems by twin 24-in. pipelines to onshore systems 35 miles away. Facilities would include a deepwater port, including submersible buoys, manifolds, and risers.

The deepwater terminal would be 27 miles from the Los Angeles coast and more than 5 miles from shipping lanes, according to project sponsor Woodside Natural Gas of Santa Monica, Calif. USGS said the regasified LNG would be delivered onshore into an existing Southern California Gas Co. system. Woodside Natural Gas is a subsidiary of Woodside Petroleum Ltd.

USGS reported that the proposed project’s pipelines would face hazards from potential sea floor offsets because they cross at least two faults, as well as tsunamis, erosion or scouring, shallow gas deposit venting, and pipeline settling.

It added that 27 USGS and California Geological Survey scientists reviewed regional geologic hazards identified in a 2007 report prepared by Fugro West Inc. as part of OceanWay’s 2007 deepwater port application.

US Rep. Jane Harmon (D-Calif.), in a Mar. 25 letter to USGS, also requested information on geologic hazards that should be considered in connection with the proposed project.

TAQA, Gazprom sign MOU for Bergermeer project

Gazprom Export and TAQA Energy BV., a wholly owned subsidiary of Abu Dhabi National Energy Co., signed a memorandum of understanding to partner in Europe’s largest new gas storage project in the Netherlands, the Bergermeer gas storage.

Operator TAQA is finalizing technical design, permitting, and planning processes to start converting the existing depleted Bergermeer gas reservoir into Europe’s largest new seasonal gas storage facility. The project is essential to the Dutch government’s ambition to realize the North-West European gas hub in the Netherlands.

The Bergermeer consortium consists of Energie Beheer Nederland, Dyas BV, Petro-Canada, and TAQA Energy BV.

Construction is expected to start in second-quarter 2009, with commercial operations scheduled to begin in second-quarter 2013. Once operational, most of the facility’s capacity will be available for third party access.

Gazprom will deliver cushion gas for injection in the summer months over the next 4 years. Cushion gas will ensure that the reservoir has the optimal pressure to start commercial storage operations.

TAQA and Gazprom Export aim to finalize all technical and contractual discussions in coming months to reach a final investment decision by the end of first-quarter 2009. At the same time TAQA is continuing discussions with other potential partners and cushion gas suppliers to create a diverse consortium of global energy players to participate in the project and ensure on-time completion of Bergermeer.

Santos lets FEED contract for CSM-fed LNG plant

Santos Ltd. hired Bechtel as its front-end engineering and design contractor for a proposed 3.5 million tonnes/year coalseam methane (CSM)-fed LNG plant in Gladstone, Queensland.

The $40 million contract is expected to provide an updated estimate of project cost, Santos said. An initial estimate was $7.7 billion. Petronas is working with Santos to produce LNG using CSM.

Santos expects to make a decision during the first half of 2009 on whether to proceed with the project. Construction tentatively is scheduled to begin in 2010, with first shipments of LNG scheduled for 2014.

Conventional natural gas reserves in fields close to eastern Australian markets are declining while gas demand continues to grow substantially. CSM resources are close to large potential markets in eastern Australia.

Nippon Oil boosts stake in PNG LNG

Nippon Oil Corp. has purchased AGL Energy Ltd.’s entire 3.6% stake of the PNG LNG gas production and liquefaction project off Papua New Guinea, increasing Nippon’s share to 5.4% from 1.8%.

The PNG LNG project, led by ExxonMobil Corp., is designed to liquefy natural gas at a local facility and export 6.3 million tonnes/year of LNG, starting in third-quarter 2013 (OGJ Online, Dec. 18, 2008).

The agreement with AGL Energy also stepped up Nippon Oil’s interest in two Papua New Guinea producing oil fields, increasing its share of output to 8,000 b/d from 2,000 b/d.

The sale to Nippon Oil is a plus for the project, especially after recent reports that ExxonMobil, due to the current global financial crisis, has been searching for $10 billion in financing for the LNG venture.

“At a time when we are seeking to borrow more than $10 billion on the international money market, it would be foolish of me to stand here and tell you that this project is¿and will remain¿completely immune from the fallout of the current financial crisis,” ExxonMobil’s LNG venture manager Peter Graham told an investors conference.

“We continue to look for ways to protect this project from the global financial uncertainties, and I emphasize we’re still targeting fourth-quarter of 2009 for that all-important financial investment decision,” Graham said.

In November, the PNG LNG project received a financial boost when the government concluded a $1 billion agreement with Abu Dhabi’s state-owned International Petroleum Investment Co. (OGJ Online, Nov. 5, 2008).

“This is an exceptional deal in the current global financial climate,” PNG’s Minister for Public Enterprise Arthur Somare said of the agreement with IPIC.

According to Somare, the IPIC loan “should also assist the project developer, ExxonMobil, in its efforts to conclude LNG marketing arrangements and to raise the 70% debt finance required for this Kina 40 billion ($16 billion) venture.”

Following the AGL Energy sale, the PNG LNG project consortium includes ExxonMobil subsidiary Esso Highlands Ltd. 41.5%, Oil Search 34%, Santos 17.7%, Nippon Oil 5.4%, MRDC 1.2%, and Petromin PNG Holdings’ Eda Oil 0.2%.