Awl Bidness

Jan. 17 (Bloomberg) -- BP Plc’s deal with Russia’s state- controlled OAO Rosneft may give the U.K. driller access to one of the largest untapped oil troves left on earth.

Seismic work indicates the three Arctic blocks BP will explore with Rosneft may have as much as 50 billion barrels of oil in place and between 12 billion and 15 billion barrels of recoverable crude, said a person with knowledge of the matter, declining to be identified because the data are confidential. By comparison, about 23 billion barrels have been pumped from the U.K. sector of the North Sea in the last four decades.

BP agreed last week to exchange $7.8 billion of its equity for a 9.5 percent holding in Russia’s largest oil producer. As part of the accord, the two companies will explore a 125,000 square-kilometer (48,000 square-mile) area of the Kara Sea, north from Russia’s largest developed fields in West Siberia.

“BP’s interest in the petroleum potential of the Kara Basin stems from a number of key geological features,” said Mike Daly, BP executive vice president for exploration, who declined to give an estimate of potential reserves. “The Kara Basin is the northerly, offshore extension of the West Siberian Basin. Regional seismic data shows the basin to have a number of very large structures.”

BP shares rose as much as 2.5 percent in London and traded at 507.6 pence as of 9:55 a.m. local time. Rosneft rose as much as 4.8 percent in Moscow to the highest since April.

More Oil Than Gas
BP is particularly attracted to the area because the three license areas in question are likely to contain more oil than gas, the person said. That would allow the company to avoid working with OAO Gazprom, which has a monopoly on gas exports. London-based BP thinks the two northernmost license areas, EPNZ- 1 and EPNZ-2, overlie oil-bearing rock, he said.

The strategic alliance between BP and Rosneft is the outgrowth of a 12-year relationship between the two companies that has included exploration drilling off Sakhalin Island in the Russian Far East and a five-year-old agreement to do scientific research in the Arctic. Several wells have been drilled off Sakhalin, where Shell and Exxon Mobil Corp. have large producing fields, but BP and Rosneft have yet to find oil and gas in commercial quantities.

The joint efforts have deepened ties between the two companies, leading to last week’s deal. The arrangement agreed to is the first major cross-shareholding between one of the world’s largest private-sector oil companies and a state-owned producer.

TNK, U.S. Congress
BP Plc’s billionaire partners in existing Russian oil venture TNK-BP said today they “welcome” the project. The deal is also good for Russia “and potentially for TNK-BP,” though TNK wants more information, said Stan Polovets, the chief executive officer of AAR, which represents the partners.

The deal has attracted criticism in U.S. Congress. Representative Edward Markey, a Massachusetts Democrat [ and genuine idiot a/k/a "Ed Malarkey" ], called for an investigation of the swap and said that BP now stands for “Bolshoi Petroleum.”

“This is an industry-changing event because BP and Rosneft have embraced a degree of reciprocity unique in the global oil and gas industry,” said Philip Lambert, chief executive officer of Lambert Energy Advisory, which advised BP on the transaction. “Both companies have invited each other into their respective ownership base and core business.”

Development of the Arctic fields is likely to be slow and expensive. Rosneft will hold two-thirds of the venture exploring the area and BP the rest. The first well is unlikely to be drilled before 2015, and first oil production may not be until 2025.

Half-Price Reserves
For BP, the swap is also equivalent to immediately replacing almost all the reserves sold off to pay for the Gulf of Mexico oil spill last year at less than half price.

Rosneft’s market value prices its oil and gas reserves at $5.33 a barrel, the fourth-lowest among the world’s biggest oil producers, data compiled by Bloomberg show. That’s 60 percent below the $13.20 average price BP got for fields sold last year holding 1.7 billion barrels, according to bank DnB NOR ASA. After the deal, BP’s 10.8 percent Rosneft holding will represent about 1.6 billion barrels of proved reserves.

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Jan. 19 (Bloomberg) -- Foreign states tried to derail Russian Prime Minister Vladimir Putin’s project to build an oil links to supply Asian markets with Siberian crude, national pipeline operator OAO Transneft said.

Representatives of foreign governments met with and funded Russian environmental and public interest groups in the Far East region that sued to stop or delay construction of the pipelines, Transneft Chief Executive Officer Nikolai Tokarev said in comments broadcast on state television today.

“Russia now has a powerful corridor to Asia-Pacific markets and, naturally, many states don’t like Russia having this capacity,” Tokarev said, without naming any countries. “Of course a company which builds these advantages for Russia needs to be stopped, through different means.”

Putin has brought the country’s energy industry under state control and sought to expand sales beyond Europe since becoming president in 2000. Russia has boosted output more than 50 percent in the period, surpassing Saudi Arabia as the world’s largest oil producer.

Transneft finished building the first phase of its East Siberian Pacific Ocean pipeline in 2009, a year behind schedule. The Moscow-based company made its first direct deliveries to China on Jan. 1 via a spur of that link.

Fraud Claims
The ESPO link will cost 770 billion rubles ($26 billion) and span 4,700 kilometers (2,900 miles), longer than the distance from London to Tehran, when completed. It will carry oil from Taishet, beyond the west Siberian basin where most of Russia’s oil is produced, to the Pacific port of Kozmino near North Korea and China when completed as early as next year.

Tokarev said allegations of a $4 billion fraud during the construction of the pipeline, published by laywer Alexey Navalny in November, were part of a campaign to discredit Transneft.

“When a company faces an information war, this always damages its image,” he said. “I’m sure it’s got nothing to do with Transneft itself.”

Navalny, who returned to Moscow in December after six months as a world fellow at Yale University, said Transneft was avoiding a response by engaging in “Cold War rhetoric.”

“They totally refuse to explain the facts of corruption, which investors deserve to know about,” Navalny, a minority shareholder in Transneft, said in a phone interview today.

The lawyer published on his website in November what he said was a report by the state budget watchdog, showing that officials at Transneft embezzled $4 billion while building the pipeline. The allegations, which the company and the Audit Chamber denied, prompted Putin to call for an investigation on Dec. 30.

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Jan. 19 (Bloomberg) -- Brazilian oil deposits below a layer of salt in the Atlantic Ocean hold at least 123 billion barrels of reserves, more than double government estimates, according to a university study by a former Petroleo Brasileiro SA geologist.

The research, which set out to show government figures were too optimistic, found they underestimated the area’s potential, said Hernani Chaves, a professor at the Rio de Janeiro State University who worked at Petrobras for 35 years. The forecast, which the study puts at a 90 percent probability, compares with the Brazilian oil regulator’s 50 billion-barrel estimate. Petrobras rose, reversing earlier losses.

“We started with a skeptical view and finished with bigger numbers,” Chaves said in an interview at the university, in the city of Rio. “When we got the first results I said: ‘Something is wrong, it’s too big.’”

Petrobras, which currently has 16 billion barrels of proven reserves, is investing more than $200 billion in five years as it taps the so-called pre-salt fields lying two miles below the ocean surface and another two to four miles beneath the seabed. The deposits include the Americas’ two largest oil discoveries since Mexico’s Cantarell in 1976. Royal Dutch Shell Plc, Repsol YPF SA and Exxon Mobil Corp. also operate blocks in the area. BG Group Plc and Galp Energia SGPS SA hold minority stakes.

Share Rise
Petrobras climbed 0.7 percent to 27.90 reais in Sao Paulo trading at 9:21 a.m. New York time. It touched 27.95 reais, after falling as much as 0.6 percent earlier.

Chaves and Cleveland Jones, a professor at the same university and co-author of the study, found there’s a 10 percent chance the region holds 206 billion barrels of oil and natural gas, which would surpass the estimate of 172 billion barrels for Venezuela at the end of 2009 in BP Plc.’s Statistical Review of World Energy. Venezuela currently has Latin America’s biggest proven reserves.

The two geologists used software from Oslo-based GeoKnowledge, an oil consulting firm, and the Monte Carlo statistical model the U.S. Geologic Survey uses to calculate undiscovered oil and natural gas resources around the world. Monte Carlo predicts potential discoveries based on the history of exploration successes and failures in an area.

Petrobras Estimate
Petrobras estimates reserves of up to 16.8 billion barrels at four pre-salt fields where it has drilled and tested wells including Lula, its biggest prospect, the company said in an e- mailed response to questions. The company didn’t provide an estimate for the entire area and declined to comment on the study.

The study assumes fields in the pre-salt region, an area bigger than Florida, will have a recovery rate of 25 percent to 30 percent, Hernani said. The rate measures the percentage of oil that can be extracted from a reservoir and that counts as reserves.

Brazilian President Dilma Rousseff said the pre-salt may hold 100 billion barrels in 2009, when she was cabinet chief for her predecessor, Luiz Inacio Lula da Silva.

Magda Chambriard, a director at the oil regulator known as ANP, said last year the pre-salt may hold more than the 50 billion-barrel estimate the agency uses in presentations.

The costs and technical challenges involved in pumping oil from ultra-deep fields will likely slow development of the reserves, Chaves said. It will cost trillions of dollars to develop the entire area, he said.

Petrobras expects to boost recoverable reserves to up to 35 billion barrels by 2014. The company’s proven reserves, or oil that can be extracted with existing infrastructure, rose 7.5 percent in 2010 to 16 billion barrels, the company said Friday.

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Noble's subsidiary has signed a contract with Hyundai Heavy Industries ("HHI") for the construction of two ultra-deepwater drillships, increasing the Company's number of floating drilling units to 26, 14 of which are dynamically positioned. The new ultra-deepwater drillships, to be named at a later date, will be constructed on a fixed price basis at HHI's shipyard in Ulsan, Korea, with expected deliveries from the shipyard in the second and fourth quarters of 2013, respectively. Operations are expected to commence 90-120 days after delivery following mobilization and acceptance testing.

The delivered cost of the new drillships is expected to be $605 million each, and includes the turnkey construction contract, Company furnished equipment, project management and spares, but excludes capitalized interest. The construction contract contains favorable payment terms that incentivize on-time delivery. The contract further includes a fixed price option for up to two additional drillships, which must be declared by early May 2011 for delivery in 2014.

"We believe the fundamentals of the global ultra-deepwater market will continue to be strong in the decade ahead," said David W. Williams, Chairman, President and Chief Executive Officer, Noble Corporation. "These units, capable of meeting the industry's most stringent operating requirements, further support our continued commitment to increasing the technological and operational capabilities of our fleet. Furthermore, the previously announced Letter of Intent from Shell for one unit reduces the speculative risk and enhances future shareholder value."

The rigs are based on a Hyundai Gusto P10000 hull design and are designed for operations in waters of up to 12,000 feet, although either may be outfitted for less depending on specific contract requirements. The units will have DP-3 station keeping abilities, the ability to handle two complete BOP systems, a heave compensated construction crane to facilitate deployment of subsea production equipment and accommodations for up to 200 personnel, in addition to a number of other operational enhancements beyond the shipyard's base specifications.

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Jan. 21 (Bloomberg) -- China Petroleum & Chemical Corp., the country’s biggest refiner, joined a group investing more than $100 million in Enbridge Inc.’s proposed $5.5 billion pipeline to Canada’s west coast, Enbridge said.

A group of Canadian producers and Southeast Asian refiners are matching Enbridge’s costs to get through the regulatory process to approve the Northern Gateway pipeline, according to a transcript of a presentation by Enbridge Chief Executive Officer Patrick Daniel.

Sinopec, as China Petroleum is known, has indicated it is one of the funding partners, Daniel said in the transcript. He said he’s unable to divulge the identify of the other companies. They have the right to take an equity stake and a share of the capacity of the pipeline, he said.

Enbridge has proposed piping as much as 525,000 barrels a day from Canada’s oil sands to the nation’s west coast, from where it would be shipped to Asia and the U.S.

Calls during office hours to the work and mobile numbers of Huang Wensheng, a Beijing-based spokesman for China Petroleum, weren’t answered.

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$89.16	Nymex Crude Future ($/bbl.)					
$2.12	Nymex Crude Future ($/gal.)        = $3.35 @ Retail ($/gal.)	
$2.64	Nymex Heating Oil ($/gal.)					
$111.08	Nymex Heating Oil ($/bbl.)					
$2.46	Nymex RBOB Gasoline Future ($/gal.) = $3.09 @ Retail ($/gal.)	
$103.12	Nymex RBOB Gasoline Future ($/bbl.)					
						
    [B][COLOR="Blue"][SIZE="3"] Thus, 3-2-1 Crack Spread:						
	$16.61[/SIZE][/COLOR][/B]

Crack spreads are calculated as follows, Example: based on a 321 CL:HU:HO crack spread: (((XBA*2*.42)+(HOA*1*.42))-(CLA*3)))/3

Please note that all contracts follow the crude contract, so if the front month for CLA is October, the other components of the calulation should be based on October contracts as well. The HU contacts are being replaced with XB contracts starting from Feb 07. All calculations from Feb 07 on contain XB contract not HU. On CRKS page 2, the 12-month 3:2:1 crack strips are an arithmetic average of twelve cracks divided by 12. And, the other crack strips are averages of their respective 12-month strip ratios.

Note: these are Bloomberg calculated spreads which are to be used for price indication purposes only.

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• Rapid economic growth and expanding prosperity in developing countries that are not part of the OECD will drive an increase in their energy demand of more than 70 percent in 2030 compared to 2005. By contrast, improvements in energy efficiency will help keep energy demand in OECD countries essentially flat over the period to 2030, even though the total economic output of these nations is expected to rise by approximately 60 percent.
  
• Efficiency gains are expected to accelerate between 2005 and 2030 versus historical trends. Gains in the wise and efficient use of energy across all sectors of economies worldwide will curb energy demand growth through 2030 by about 65 percent.
  
• There will be an expansion of natural gas supply, particularly in the United States where unconventional gas supplies are expected to meet more than 50 percent of gas demand by 2030.
  
• Power generation is the largest and fastest growing major energy-demand sector and is likely to represent 55 percent of the total growth in demand through 2030. At that time, power generation will account for about 40 percent of total primary energy demand.
  
• Oil, natural gas and coal will continue to meet most of the world’s needs during this period because no other energy sources can match their availability, versatility, affordability and scale. The fastest-growing of these fuels will be natural gas, reflecting its abundance, versatility and economic advantages as an efficient, clean-burning fuel for power generation.
  
• Wind, solar, and biofuels will grow sharply through 2030, at nearly 10 percent per year on average. However, because they are starting from a small base, their contribution by 2030 is likely to remain relatively small at about 2.5 percent of total energy.
  
  

Jan 27 (Reuters) - Some of the 30-plus deepwater rigs that were in the Gulf of Mexico have moved to other markets, first because of a U.S. halt called last May after BP Plc's well blowout, and then because of the lack of permits once the moratorium was lifted.

Below are rigs contracted to work in the Gulf of Mexico that have been or will be moved to other regions.

* Diamond Offshore Drilling Inc said on July 9 that the Ocean Endeavor, contracted to earn about $290,000 per day from Devon Energy Corp in the Gulf of Mexico, would move to Egypt under a new deal with Burullus Gas Co.

* Diamond said on July 12 it would move the Ocean Confidence, under contract to Murphy Oil Corp, from the Gulf to the Republic of Congo. The rig is now drilling wells for Cobalt International Energy Inc off Angola, but is due to return to U.S. waters in October.

* Transocean, the world's largest offshore drilling contractor, said on Sept. 1 that it had moved its Marianas rig, under contract to Italy's Eni, from the Gulf to work in Nigeria.

* Transocean said on Sept. 14 that its Discoverer Americas vessel, under contract to Norway's Statoil, was leaving for Egypt and was due back in the Gulf in March.

* Ensco Plc said on Dec. 1 that its newly built 8503 rig, under contracted with Cobalt, would work for Tullow Oil Plc off French Guiana for three months.

* Pride International Inc's newly built Deep Ocean Ascension, under contract with BP, is moving to the Mediterranean Sea from the Gulf of Mexico in the first quarter, according to the latest Pride fleet update.

* Noble Corp said on Jan. 27 that the Clyde Boudreaux would move to Brazil for a year at a knock-down rate of $290,000 per day to work for Royal Dutch Shell Plc, starting mid-April, and that it expected more to follow.

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SMOKESTACKS dot the horizon; a whiff of oil hangs in the air; gargantuan vehicles clog the highway. There is a din of heavy machinery, punctuated by blasts from cannons scaring birds away from toxic lakes. But golf courses and suburban housing make the place liveable, and some locals have grown attached to Alberta’s tar sands and Fort McMurray, the town at the centre of them. “I’d like my son and grandson to work here,” says a worker at one of Shell’s mines.

He may get his wish. After a brief hiatus during the economic downturn, world oil consumption is rising again, pushing the price of a barrel towards $100. By 2035, believes the International Energy Agency (IEA), demand may reach 110m barrels per day (b/d), about 20% more than in 2009. For those who exploit the tar sands, which contain the world’s second-largest trove of oil, this is a welcome forecast.

Despite rapid development in the past decade, the sands produce only 1.5m b/d, less than 2% of global supply. However, the Canadian Association of Petroleum Producers (CAPP), an industry group, expects output to be nearly 3.5m b/d by 2025 (see chart). Thirst for fuel is not the only thing in the oilmen’s favour. The cost of production has fallen: a few years ago most firms thought the break-even price was $75 per barrel, but now companies such as Shell say new developments are economical at $50. The provincial and federal governments are unsurprisingly supportive.

There are obstacles too, mainly because of the sheer dirtiness of the business. In America, the main market, objections to the import of more of Alberta’s bituminous oil are loud. And domestic opposition to exploiting the tar sands and building pipelines, which has long been fierce, is gathering momentum.

First, the economics. The IEA believes that global production of conventional oil, the stuff that can be recovered easily using drills and wells, is near or already at its peak, and that only a leap in output from unconventional sources will prevent new leaps in price. Even if countries around the world agree on measures to control carbon-dioxide emissions, says the agency, bituminous crudes like Canada’s must fill a coming supply gap. That the sands lie in Canada is a rare geological fluke in the West’s favour. With 70%-plus of the world’s remaining oil in the hands of OPEC, half of its “free oil” is in the tar sands, notes Peter Tertzakian, chief economist of Arc Financial, an investment firm.

No self-respecting oil major has let a position in the tar sands pass by. A flock of national oil companies has joined them, led since 2005 by China’s state-controlled firms. In December Total, a French oil firm, and Suncor Energy, one of the original tar-sands developers, announced plans to spend about C$20 billion (about $20 billion) on new projects in the next decade. This year alone developers will spend C$15 billion, predicts CAPP.

All this is making Alberta the flag-bearer of a new oil age, and the province is already becoming wealthy. At 173 billion recoverable barrels, the tar sands are worth $15.7 trillion at today’s price. As the resource owner, Alberta captures much of this wealth, but a good deal filters through to the rest of Canada in contracts for goods and services as well as in federal equalisation payments that send some of the rich west’s billions to poorer eastern provinces.

Alberta has become something of a petro-state: the oil-and-gas sector accounts for 31% of its GDP. The provincial government, run by the Progressive Conservatives for more than four decades, is naturally keen on such a generator of money and jobs. The only serious opposition, the Wildrose Alliance, is further to the right and also supports the tar sands.

Although natural resources are under provincial jurisdiction, the tar sands are a national issue too, not least because of the federal government’s repeated failure to produce a plan to tackle climate change. Critics of Stephen Harper, the Conservative leader of a minority administration, say this lack of progress has everything to do with the prime minister’s desire to protect the oil business and to avoid offending voters in Alberta, where his party has its core support. The environment minister, Peter Kent, upset some Canadians recently when he defended Alberta’s “ethical oil”, the proceeds of which would not be spent on palaces or civil wars, as they might have been elsewhere. Michael Ignatieff, the leader of the Liberals, the main opposition at federal level, also supports development of the tar sands, though he says it has to become more sustainable.

A bitumen bottleneck
However, if Canada’s oilmen are to fulfil their rosy output forecasts, they will need new ways of reaching customers. America is an obvious place: Canada is already America’s biggest supplier of oil and petroleum, and as the sands are exploited further its market share should only rise. By 2030, according to IHS CERA, a firm of consultants, the tar sands should supply more than one-third of America’s imported oil.

But Alberta’s bituminous crude needs specialised coking facilities, and its only significant outlets are refineries in the American Midwest. By 2014, says Jackie Forrest of IHS CERA, new production from the tar sands will have filled the available coking capacity. That will create a bottleneck and hinder upstream spending.

With this in mind, TransCanada, a Calgary firm, has proposed building a $7 billion pipeline, Keystone XL, to send 510,000 b/d of Albertan oil to refineries in Texas (see map). It already has a line of similar capacity, Keystone. The company says that the new one would pump $20 billion into the American economy and hand $5 billion in taxes to states on the route. Keystone XL would not only take more Canadian oil to America; via terminals on the Gulf of Mexico it could connect the tar sands with international markets as well. There are also plans to ship oil to Asia from Canada’s Pacific coast.

However, these plans require political approval, and this is an awkward time for North American politicians to be weighing oily matters. You might imagine that last year’s spill in the gulf would have done Alberta’s onshore reserves in the sands, 40 times the size of those in the gulf, a favour. But the spill has stained the whole industry’s reputation in America and has intensified long-running opposition to the sands in Canada.

Hillary Clinton, America’s secretary of state, who must approve Keystone XL (because it crosses the border), has said she is “inclined” to do so; and 39 Republican members of Congress have written a letter asking her to support it. But the pipeline is meeting opposition. The governor of Nebraska, one of the states along the route, and one of its senators, both Republicans, have expressed concern. In December a union of Nebraskan farmers, not known for radical greenery, voted to oppose the project. Online petitions have drawn thousands of virtual signatures in Texas and elsewhere. And last year the Environmental Protection Agency demanded that the State Department review its assessment of the pipeline’s environmental impact. This has left the decision hanging and may yet upset TransCanada’s plans.

Northern Gateway, an ambitious Pacific coast proposal, would allow exports to Asia and help Canada become the “new energy superpower” Mr Harper predicted in 2006. But last month the project, which would cost C$5.5 billion and carry 525,000 b/d of oil, ran into opposition too. Leaders of First Nations (http://www.afn.ca/index.php/en/about-afn/charter-of-the-assembly-of-first-nations) in British Columbia said they would prevent the pipeline from crossing their territories. The chiefs talked of “inevitable” spills, a threat to salmon runs and devastation of their way of life. Spills last summer from pipelines in the Midwest owned by Enbridge, the company behind Northern Gateway, were scarcely a public-relations triumph.

To many critics the broader environmental legacy of the tar sands is reason enough to halt the whole endeavour. To get at the bitumen, the companies bulldoze wetlands to create vast open-pit mines. Inside them, the world’s largest dumptrucks ferry paydirt to nearby separation plants, where the tarry soil is crushed and diluted until bitumen can be skimmed off. This needs lots of water and energy, and yields the notorious “tailings”, a residue of sand, unclaimed bitumen, water, clay particles and contaminants. Some lakes of this have been festering for decades.

Mining accounts for just over half of production. It will become less common as shallower reserves are exhausted. Extracting the deeper stuff is less ugly but also damaging. Typically it involves drilling wells to pump steam into the ground to melt the bitumen and make it easier to suck up to the surface. Heating the steam burns much natural gas, emitting CO2. Both methods, say the tar sands’ critics, threaten local rivers, poison fish, destroy the landscape, kill wildlife and pollute the air.

The movement to stop this “dirty oil” has gathered momentum. Several American states, led by California, have passed laws designed to stop Albertan oil reaching their citizens. Some American retailers have forsworn fuel from the tar sands. A coalition of green groups has launched a campaign, “Rethink Alberta”, to dissuade tourists from visiting the province until expansion of the tar sands stops.

The provincial government has begun to fight back with advertisements in newspapers and in Times Square. The industry has run ads featuring ordinary workers talking up the wonders of the oil sands. Both often offer journalists and activists tours, hoping to persuade them that things are better than they think. This candour is usually rewarded with more negative publicity. Aided by, among other things, the death of 1,600 ducks in a tailings pond and photos making northern Alberta look like a moonscape, environmentalists have succeeded in tarnishing the province’s brand. “The oil sands have become the harp seal of the environmental movement,” says Preston McEachern, a water scientist with the provincial government: the easiest, and softest, beast to club.

David Schindler, an ecologist at the University of Alberta, has long been publishing peer-reviewed studies showing that airborne emissions from smokestacks on upgraders, which convert the bitumen into synthetic crude oil, have polluted the Athabasca, the giant river that flows through the tar sands. His findings gained more publicity in September, when he offered photographers deformed turbot and other species pulled from the river. The images prompted a federal investigation. “I’m surprised it wasn’t mounted on a block of bitumen,” said an oil executive of Dr Schindler’s piscine trophy.

Such weary sentiment is widespread in the industry. Sometimes it is justified. Agriculture has severely depleted south-eastern Alberta’s rivers, for example, yet is allowed to use more than six times as much water as the tar sands in a region soaked with lakes and rivers. David Keith, a scientist at the University of Calgary, says the tar sands’ water use is so benign, in pollution and consumption, that environmentalists ought to drop the issue. In December a report by the Royal Society of Canada (RSC) dismissed other complaints. Claims that the tar sands were the “most environmentally destructive project on Earth” were “not accurate”, it said. Although reclamation of the land, a legal obligation, has not kept up with the disturbance of the tar sands, it was “achievable”. The RSC added that “no credible evidence” supported worries about elevated human cancer rates downstream of the developments.

Progress by developers in cleaning up after themselves tends to win only grudging approval. In September Suncor reclaimed Pond 1, a toxic lake of residue that had been an open wound for decades. This was a small step, to be sure. The Pembina Institute, a local environmental think-tank, claims that a lot of the mature, fine tailings were merely transferred to other, larger lakes; Suncor says not. Such toxic lakes still cover 170 square kilometres (66 square miles) and will keep growing, according to the RSC. Some of them leach their waste into the ground, says Pembina, although how much is uncertain.

Suncor is promising to spend another C$1.2 billion to deal with its tailings. Rick George, its chief executive, believes that as companies share new technology, like that used by Suncor on Pond 1, the tar sands will within a decade look like any other mining operation, with only one lake open, temporarily, per mine. Only since the turn of the century have the companies cracked the economics of the tar sands, argues Mr George. Now they can concentrate on greening them.

Whether Alberta’s government can be relied on to promote greener tar sands, however, is questionable. The province has been a model of laissez-faire. In private many oil-industry executives wish it would be more diligent as a regulator, feeling that its lax approach has become a threat to developments, not an incentive. Most of the province’s best minds don’t join the government in Edmonton, goes a frequent lament, but head for deep-pocketed oil companies in Calgary.

Both the RSC’s report and another commissioned by the federal government, also released last month, demolished Alberta’s claims to have monitored the tar sands’ impact adequately. Regulators had “not kept pace with rapid growth” and the province’s environmental assessments had “serious deficiencies” leaving them below “international best practice”, the RSC said. The federal report rubbished the province’s water-monitoring, which involved handing the job to an industry body—putting the “fox in charge of the henhouse”, says Dr Schindler. After December’s reports both the federal and provincial governments promised new measures to improve monitoring, an admission that the current arrangements are inadequate. Yet Mr Kent, the federal environment minister, has flatly rejected Dr Schindler’s research into the pollution of the Athabasca.

Clean and scrub
Some environmental problems could be solved fairly easily. One long-standing idea is to create a large wildlife refuge in areas that will eventually be tapped for bitumen. Only after a developer has restored land it has already mined could it begin tearing up an area of equivalent size within the refuge. Pembina says up to 40% of the region could be protected this way, with no impact on oil production. Various nasties Dr Schindler found in the Athabasca could be dealt with by adding “simple off-the-shelf” scrubbers to upgraders’ smokestacks, he says. Though they are not legally required, many companies have added them to capture sulphur dioxide. Enforcement of rules to make operators deal safely with half of their tailings by 2013 has been patchy. Many operators will miss the deadline, says Pembina, and another rule is needed for the other half.

Outside Canada, most complaints are about the tar sands’ CO2 emissions. Here too, confusion abounds. Some critics, calculating emissions from extraction through to refining (“well to tank”), say fuel sourced from the sands is up to three times more carbon-intensive than others consumed in America. But from “well to wheels”, counting emissions from cars’ exhaust pipes, tar sands are only 5-15% dirtier, says IHS CERA. Most CO2 comes from burning the petrol, not digging up the oil.

Whatever the measure, Alberta lacks an adequate strategy to deal with emissions. Its climate-change targets would allow emissions to grow until 2020. And those from the tar sands could triple in the next decade, as more oil is extracted by steam-based methods. Still, the sands are carbon-emitting minnows. Just 5% of Canada’s CO2, about 0.1% of the world total, comes from the developments, says CAPP. If people are serious about fighting climate change, argues Dr Keith, they should worry first about coal-fired electricity, whose emissions in America dwarf those from the tar sands. Andrew Leach, of the Alberta School of Business, calculates that the tar sands create about C$500 of value-added per tonne of CO2, against C$20-30 from coal-fired power stations.

Peter Silverstone, of the University of Alberta, argues in a recent book that the province should levy its tar-sands royalties on a scale that reflects each project’s emissions. Some companies may welcome this. Shell already adds a nominal carbon levy of $40 per tonne to its projects when deciding whether to invest in the region, calling this a “licence to operate”, even though Alberta’s own carbon tax is just C$15 per tonne. With hefty provincial funding, Shell is also among those hoping to capture CO2 emitted by one of its tar-sands upgraders. Alberta is investing C$2 billion in carbon capture and sequestration, its favoured way of cleaning up emissions.

Environmentalists may regard such schemes with mixed feelings. Carbon-neutral extraction would do nothing to cut the bulk of oil-related emissions that come from combustion. Eco-friendlier tar sands could also encourage unconventional development elsewhere: Jordan, Madagascar, Congo and Venezuela, where the government claims a reserve of bitumen even greater than Alberta’s, may be less open to environmental scrutiny. Kill Alberta’s tar sands, say some, and rising crude prices would choke oil consumption and force an era of clean energy into being.

This would be a hard argument to make, especially in the United States. Even if America’s consumption keeps shrinking, it will remain the world’s biggest oil buyer for decades: foreign supplies will grow more, not less, important in its market. Ezra Levant, author of a recent polemical defence of the tar sands, argues that Americans would rather buy from Canada than from Venezuela and the Middle East.

Meanwhile in Calgary, oilmen expect a pipeline to the Pacific, and in effect to Asia, to come sooner than later, especially if Keystone XL is blocked. A settlement with First Nations opposed to Northern Gateway, involving both money and environmental safeguards, could hasten that. Chinese oil companies would happily take delivery, might be less fickle customers than the southern neighbours and might help Canada fulfil Mr Harper’s dream of energy superpowerdom. Many Americans, however, might ask why the State Department had allowed a rising economic rival into such a vast oil reserve.

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• [#1] The Strait of Hormuz is by far the world’s most important chokepoint with an oil flow of 15.5 million barrels per day in 2009.
  
• [#2] The Strait of Malacca, linking the Indian and Pacific Oceans is the shortest sea route between the Middle East and growing Asian markets.
  
• [#3] Closure of the Suez Canal and SUMED Pipeline would add 6,000 miles of transit around the continent of Africa.
  
• [#4] Closure of the Bab el-Mandab could keep tankers from the Persian Gulf from reaching the Suez Canal/Sumed pipeline complex, diverting them around the southern tip of Africa.
  
• [#5] Increased oil exports from the Caspian Sea region make the Bosporus Straits one of the busiest and most dangerous chokepoints in the world supplying Western and Southern Europe.
  
• [#6] The United States is the primary country of origin and destination for all commodities transiting through the Panama Canal, however, it is not a significant route for U.S. petroleum trade.
  
• [#7] The Danish Straits are becoming an increasingly important route for Russian oil exports to Europe.
  

Jan. 31 (Bloomberg) -- Cnooc Ltd., China’s largest offshore energy producer, agreed to pay $570 million in cash for a one- third stake in Chesapeake Energy Corp.’s Niobrara shale project, adding to its U.S. holdings in crude oil production.

The Chinese explorer also agreed to pay 66.7 percent of Chesapeake’s costs up to $697 million to drill and complete wells in the area, the companies said in a statement yesterday.

The deal follows Chinese President Hu Jintao’s first state visit to the U.S. this month to expand economic ties, and would give Cnooc its second U.S. energy asset, five years after political opposition derailed its $18.5 billion bid for Unocal Corp. The Hong Kong-listed explorer will pay about $2,140 an acre for the one-third stake in Chesapeake’s 800,000 Niobrara acres and has the right to a 33.3 percent stake in future acquisitions in the formation in Colorado and Wyoming.

“If you look at President Hu’s recent trip to Washington, there seems to be a greater willingness in the U.S. to encourage Chinese investment,” said Wang Aochao, head of China energy research at UOB-Kay Hian Ltd. in Shanghai. “We don’t have all the details at hand, but it appears to be a fair price for these assets. The Chinese oil majors still think valuations generally for oil and gas assets are reasonable.”

Niobrara covers 8,400 square miles (21,756 square kilometers) and may contain 103.6 million barrels of oil, the U.S. Geological Survey estimated in 2006 before Chesapeake, EOG Resources Inc. and other producers began drilling the formation.

“The project will not only strengthen our solid resource and production base overseas but create value to the shareholders in the long term,” Cnooc’s Chief Executive Officer Yang Hua said in the e-mailed statement.

Cnooc’s Production Target
Cnooc has risen 52 percent in Hong Kong trading in the past 12 months, outpacing the 15 percent gain in the benchmark Hang Seng Index. The shares fell 1.6 percent to HK$17.04 at 10:19 a.m. local time.

The Chinese energy explorer forecast a 12 percent increase in oil and gas production in 2011 after spending about $8.4 billion in the past year acquiring assets in the U.S., Africa and Argentina. By contrast, output rose 44 percent in 2010.

Cnooc, based in Beijing, completed its $1.08 billion purchase for a one-third interest in Chesapeake’s 600,000 acres in the Eagle Ford project in South Texas in November. The Niobrara deal may be completed in the first quarter of this year, according to yesterday’s statement.

“The win-win deal valuation is fair based on our estimates and Cnooc’s strategy to further expand into the oil-rich shale deposits in the U.S.,” said Gordon Kwan, head of regional energy search at Mirae Asset Securities in Hong Kong. “The total investment of $1.27 billion in the deal through 2014 is manageable and equates to about 14 percent of Cnooc’s budgeted $9 billion for 2011.”

Funding Drilling

The Niobrara deal will lead to a reduction in U.S. oil imports over time and the creation of thousands of jobs, Chesapeake’s Chief Executive Officer Aubrey McClendon said in the statement.

“This transaction will provide the capital necessary to accelerate drilling of this large domestic oil and natural gas resource,” McClendon added.

Chesapeake expects to double its drilling rigs to 10 by the year-end from the five currently operating in Wyoming’s Powder River and Colorado’s Denver-Julesburg basins. It plans to have 20 rigs working by end-2012.

Oklahoma City-based Chesapeake, the most active U.S. gas and oil driller, has 16 wells producing in those basins with initial output as high as 1,000 barrels of oil and 3 million cubic feet of natural gas a day, according to the company.

The companies plan to eventually produce the equivalent of as much as 5 billion barrels of oil from the basins.

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Feb. 3 (Bloomberg) -- Royal Dutch Shell Plc, Europe’s largest oil company, will delay its drilling campaign in Alaska after the worst U.S. oil spill in the Gulf of Mexico last year.

Shell hasn’t received full clearance to start drilling off the coast of Alaska, according to Chief Executive Officer Peter Voser. The company decided to postpone its plans to spend as much as $150 million in the region until 2012.

“Despite our investment in acreage and technology and our work with the stakeholders, we haven’t been able to drill a single exploration well,” Voser told reporters today on a conference call. “Critical permits continue to be delayed and the timeline for getting these permits is still uncertain.”

The Hague-based company last year asked the U.S. Interior Department for a permit to conduct exploratory drilling this year in the Beaufort Sea. Shell in 2008 offered $2.1 billion for drilling rights in the Chukchi Sea off the coast of Alaska.

Alaska may hold the second-biggest U.S. oil and gas reserves after the Gulf, according to government estimates.

Shell in November said it had planned to limit the effect on wildlife from exploration in the Beaufort and Chukchi seas, meeting the concerns of environmental campaigners.

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Feb. 3 (Bloomberg) -- The Obama Administration acted in contempt by continuing its deepwater-drilling moratorium after the policy was struck down, a New Orleans judge ruled.

Interior Department regulators acted with “determined disregard” by lifting and reinstituting a series of policy changes that restricted offshore drilling, following the worst offshore oil spill in U.S. history, U.S. District Judge, Martin Feldman of New Orleans ruled yesterday.

“Each step the government took following the court’s imposition of a preliminary injunction showcases its defiance,” Feldman said in the ruling.

“Such dismissive conduct, viewed in tandem with the re-imposition of a second blanket and substantively identical moratorium, and in light of the national importance of this case, provide this court with clear and convincing evidence of the government’s contempt,” Feldman said.

President Barack Obama’s administration first halted offshore exploration in waters deeper than 500 feet in May, after the explosion and sinking of the Deepwater Horizon drilling rig off the Louisiana coast led to a subsea blowout of a BP Plc well that spewed more than 4.1 million barrels of oil into the Gulf of Mexico...


more...
http://noir.bloomberg.com/apps/news?pid=newsarchive&sid=asLSHNSlJkKE

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Feb. 4 (Bloomberg) -- OPEC is under pressure from consumers to boost supply as most of the world’s benchmark crudes surpass $100 a barrel amid political unrest in North Africa and the Middle East.

Oil prices are high enough to “derail” the global economic recovery, Fatih Birol of the International Energy Agency said this week. Saudi Arabian Oil Minister Ali al-Naimi said last week prices nearer $75 would be “appropriate.” Goldman Sachs Group Inc. says the Organization of Petroleum Exporting Countries has already raised output.

“OPEC needs to put in more barrels this year, given how strong demand has been,” said Amrita Sen, a commodity analyst at Barclays Capital in London. “Above $100 there would be a bit more urgency to increase their volumes, because at the end of the day what they want is more stability.”

Riots in Egypt that have led to concern of disruption to shipments through the Suez Canal sent North Sea Brent above $100 a barrel for the first time since October 2008 this week. Six of the world’s 10 most-used oil price markers, including Nigeria’s Bonny Light, Malaysia’s Tapis, Indonesia’s Minas and Louisiana’s Heavy Sweet and Light Sweet grades, have breached three digits, stoking speculation governments will struggle to contain inflation as economies recover from the recession.

‘Calm the Market’
“Naimi has announced they’re thinking of production increases; there will be some production increases,” Christof Ruehl, chief economist at BP Plc, Europe’s second-biggest company, said in an interview with Bloomberg Television on Feb. 2. “If markets are getting very worried about the political situation in the Middle East that could even foster production increases by OPEC to calm the market down.”

The world’s energy bill as a share of the economy will return to the 9 percent level of the 1980s, when oil costs tipped consuming nations into a recession, should crude advance to $115 a barrel this year, Bank of America Merrill Lynch said in a Jan. 25 research report.

Twelve European nations, recuperating from last year’s sovereign debt crisis, already face record gasoline prices, including taxes, European Commission data on Bloomberg shows.

Brent crude gained 18 cents to $101.94 a barrel on the ICE Futures Europe exchange in London as of 10:15 a.m. local time. It reached $103.37 during yesterday’s trade, the highest level in 28 months. West Texas Intermediate gained as much as 1 percent to $91.40 on the New York Mercantile Exchange, up 25 percent in the past year.

Derail Economy
“Just before the turmoil in Egypt we already had very high prices as a result of strong demand growth expectations for the next year,” Birol, the chief economist of the Paris-based IEA, which has advised energy-consuming nations since 1974, said in a Feb. 2 interview with Bloomberg Television. “The turmoil in Egypt has been a trigger. Brent over $100 is a risk to derail the economic recovery.”

The Suez Canal and the adjacent Suez-Mediterranean Pipeline have remained open throughout the Egyptian unrest, carrying about 2 million barrels a day, or 2.5 percent of world oil production, according to Goldman Sachs. Even before the unrest the links weren’t operating at full capacity which is about double this amount.

A halt of 1 million barrels a day or more would trigger a response from OPEC, according to the group’s Secretary-General Abdalla El-Badri. “If we see a real shortage we will have to act,” he told reporters in London on Jan. 31. “But I don’t think this will happen.”

The 11 OPEC members subject to production quotas pumped 26.85 million barrels a day last month, the most since it announced supply cuts in late 2008. The group accounts for 40 percent of global supply.

Curbing Rally
Saudi Arabia, the largest member, may already be seeking to curb the oil rally. State-run Saudi Aramco on Feb. 2 cut prices for its March crude sales to Asia, its biggest market, contrary to the expectations of five refiners surveyed the previous day by Bloomberg News.

OPEC is due to meet on June 2 to review its daily quota of 24.845 million barrels, which it’s currently exceeding by about 2 million barrels, according to data compiled by Bloomberg. Most OPEC ministers will also gather in Riyadh, Saudi Arabia, on Feb. 22 for a meeting of the International Energy Forum.

While OPEC has left its quota unchanged at seven consecutive meetings, global inventory levels suggest the group is raising output, Goldman Sachs said in a report on Jan. 24. The group’s effective spare capacity, which excludes Iraq, Nigeria and Venezuela, dropped below 5 million barrels a day in December, the first time in two years, according to a Jan. 18 IEA report. Stockpiles held by companies in the most developed economies were at 2.742 billion barrels in November, close to the top of their five-year range, it said.

‘No Shortage’
Plentiful supplies make any production increase unnecessary, according to Shokri Ghanem, chairman of Libya’s National Oil Corp. “We don’t feel there is a shortage in the market,” he said in a Feb. 3 Bloomberg Television interview.

The political turmoil in the region started in Tunisia with the Jan. 14 ouster of President Zine El Abidine Ben Ali has spread to Yemen, where thousands of demonstrators gathered yesterday in the capital and police used tear gas in the port city of Aden. More violence may occur in Egypt today after Friday prayers.

Any escalation of the crisis in Egypt would require Middle East producers to divert Suez shipments on a longer route that avoids the canal, rather than increase supply, according to Edward Morse, Credit Suisse AG’s head of commodities research. Additional barrels aren’t needed because demand will slacken as winter ends in the Northern Hemisphere.

‘Dangerous Time’
“This is a particularly dangerous time to open the taps,” Morse said in an interview in London on Feb. 1. “This is not a supply disruption. It just means that flows that would have occurred now occur in a more expensive way and take longer to get where they’re going.”

Rising demand means an extra 300,000 barrels a day is needed from OPEC to stem oil’s advance, Bank of America Merrill Lynch said on Jan. 25. JPMorgan Chase & Co. said that any premium caused by events in Egypt has already dissipated, and that $100 oil reflects levels of supply versus demand.

Rather than damping oil’s rally, additional OPEC exports may signal that demand is recovering faster than anticipated and that spare supply will shrink, according to Goldman Sachs.

Higher production “ultimately accelerates the draw on OPEC spare capacity,” analysts led by Jeff Currie in London wrote on Jan. 24. This may indicate “the market may already have moved into the second stage of its cyclical recovery to a structural bull market,” they said.

The four benchmark crudes that haven’t risen above $100 a barrel are WTI and Mars blend in the U.S., Oman and Murban grades in the Middle East.

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Feb. 8 (Bloomberg) -- There’s more to Ensco Plc’s deal for Pride International Inc., the costliest oil drilling takeover in a decade, than just the math.

Ensco’s agreement yesterday to pay $7.3 billion in stock and cash to create the second-largest offshore driller valued Houston-based Pride at 21 times earnings before interest, taxes, depreciation and amortization in the past year, according to data compiled by Bloomberg that includes net debt. That’s more expensive than any purchase of an oil driller in the past 10 years and almost twice the industry average of 10.7 times.

The takeover is the first by London-based Ensco since Chief Executive Officer Dan Rabun lost a bidding contest for Scorpion Offshore Ltd. to Norwegian billionaire John Fredriksen’s Seadrill Ltd. in May. Ensco may borrow as much as $2.75 billion to finance the acquisition, which may help fend off potential suitors for a company with assets in Brazil and West Africa, two of the world’s richest exploration regions, and earnings that analysts predict will rebound to a record next year.

“It’s a rich valuation,” said David Abella, a money manager at Rochdale Investment Management LLC in New York, which oversees $3 billion and owns shares of Ensco and Pride. “They might be paying on the high side to discourage other bidders, including Seadrill. They didn’t want to lose the battle again.”

Still, “if the future looks like oil could go higher, it can make some sense even at this price,” he said.

Relative Value
Ensco will pay 0.4778 of its own stock and $15.60 in cash for each Pride share, according to the terms of the agreement. That valued Pride at $41.60 a share, or about a 24 percent premium, data compiled by Bloomberg show.

The total value of the acquisition, including the assumption of Pride’s net debt, is now about $8.4 billion, or 21 times the company’s previous 12 months of reported Ebitda. Based on analysts’ Ebitda estimates of $480.2 million for 2010, Pride is valued at 17.4 times.

No oil drilling takeover of at least $500 million has been costlier in the past 10 years based on either measure, data compiled by Bloomberg show. The most expensive deal on record was Vernier, Switzerland-based Transocean Ltd.’s purchase of R&B Falcon Corp. for $6.8 billion including net debt.

Transocean announced in August 2000 that it agreed to pay 36 times R&B Falcon’s reported Ebitda. After completing the transaction on Feb. 1, 2001, the combined company’s shares fell 31 percent in the next 12 months, almost double the 18 percent drop in the Standard & Poor’s 500 Index in the same period.

‘Salty Premium’
Future earnings may decrease Ensco’s acquisition cost. Pride’s Ebitda will surge 73 percent to $829.3 million this year and climb 23 percent to a record $1.02 billion in 2012, according to analysts’ estimates compiled by Bloomberg.

That would still value the transaction at 8.2 times next year’s earnings, or 14 percent higher than the 7.2 times average multiple for Pride’s competitors Seadrill, Baar, Switzerland- based Noble Corp. and Diamond Offshore Drilling Inc. in Houston, data compiled by Bloomberg show.

“It was a salty premium,” said Collin Gerry, an analyst for St. Petersburg, Florida-based Raymond James Financial Inc. “It was an expensive deal but they’ve got some high quality assets. The forward numbers for Pride are substantially higher than the trailing numbers because they are adding a lot of assets.”

Rabun’s last attempt to acquire a rival failed last year when a bid to buy a 19 percent stake in Hamilton, Bermuda-based Scorpion collapsed in May. He indicated at the time that the offer was a step toward an eventual takeover of Scorpion.

Failed Bid
The bid, supported by Scorpion, was unsuccessful even after Ensco raised the price on May 28 to 40 kroner ($6.94) a share from 39.5 kroner a share. Hamilton, Bermuda-based Seadrill offered to buy 10.1 percent of Scorpion for 40.50 kroner a share to raise its holding to more than 50 percent.

“Ensco didn’t want anyone to be able to counteroffer” their Pride bid, said Judson Bailey, an analyst at Jefferies & Co. in Houston. “The last thing they want is to relive the Scorpion experience...”

Brazil, West Africa
Ensco is acquiring Pride to gain a foothold in Brazil and West Africa, Rabun, 56, said on a conference call yesterday. The company signed its first contract to lease a rig in Brazil last week and had no presence in West Africa. With the purchase, Ensco’s Brazilian rig count will climb to 10, with five more in West Africa.

The company’s deepwater drilling operations may benefit from Pride’s customer relationships in Brazil with state- controlled Petroleo Brasileiro SA, known as Petrobras, and OGX Petroleo e Gas Participacoes SA of Rio de Janeiro.

Petrobras is investing more than $200 billion through 2014 as it taps Brazilian oil deposits below a layer of salt in the Atlantic Ocean that may hold at least 123 billion barrels of reserves. Brazilian lawmakers last year made Petrobras the operator of all new exploration licenses in the so-called pre- salt and other strategic areas.

Lula Field
Petrobras’s Lula field, discovered in 2006 and previously known as Tupi, was at the time the biggest find in the Americas since Mexico’s Cantarell in 1976. The Lula field holds an estimated 6.5 billion barrels of recoverable oil.

Ensco’s offer may deter competing bids, with Seadrill expected to sell its stake, Kevin Simpson, an analyst at Miller Tabak & Co. in New York, wrote in a report yesterday.

By agreeing to sell at Ensco’s offer price, Fredriksen’s Seadrill would make a $124 million profit on its 9.4 percent stake in Pride, data compiled by Bloomberg show. That’s a return of about 23 percent, based on the price of Seadrill’s forward contracts for Pride shares, according to regulatory filings.

Seadrill hasn’t decided if it will sell its stake and pursue other targets, Esa Ikaeheimonen, the company’s chief financial officer, said in an interview yesterday. Seadrill’s shares fell 1.9 percent to 202 kroner at 12:33 p.m. in Oslo.

“We’ve got a lot of work to do to finalize the merger so I can’t really address any one shareholder’s particular situation,” Kate Perez, a spokeswoman for Pride, said in response to questions about the stake of Fredriksen, 66, and the premium Ensco agreed to pay...

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Feb. 9 (Bloomberg) -- Royal Dutch Shell Plc and BP Plc, Europe’s largest oil companies, plan to close and sell refineries in the U.S. and Germany on declining demand for fuels such as gasoline in developed nations.

BP plans to sell its 475,000 barrel-a-day Texas City refinery in Texas and its 266,000 barrel-a-day Carson plant in California, the London-based company said on Feb. 1.

Shell plans to stop oil-processing at its 110,000 barrel-a- day Hamburg facility in 2012 after failing to find a buyer, the company based in The Hague said on Jan. 12.

Following are two tables. The first lists refineries around the world that have shut, are slated for permanent closure or conversion, units idled for economic reasons, and those that are up for sale. The second shows refinery sales that have been agreed or completed since early 2010. Capacity is shown in thousands of barrels of oil a day.

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 FOR SALE, CLOSURE OR CONVERSION

Company      Refinery         Status                 Capacity

EUROPE

Petroplus    Reichstett       May stop oil           85
             France           processing in the
                              second quarter,
                              company said on
                              Feb. 3. Conversion
                              to terminal
                              announced Oct. 21.

Unipetrol    Pardubice        Nine-week shutdown     20
Paramo       Czech Republic   from Jan. 20 on
                              low profits.

Shell        Hamburg          Plans to convert       110
             Germany          site into terminal
                              in 2012, after
                              failing to find
                              buyer, company
                              said on Jan. 12.

OMV          Arpechim         Shut in June on        70
             Romania          weak demand. First
                              contacts with
                              possible buyers,
                              CEO said Nov. 19.

Tamoil       Cremona          Plans to convert to    95
             Italy            a storage facility
                              at the end of 2011,
                              company said Nov. 12.

Conoco       Wilhelmshaven    Production won’t be    260
             Germany          resumed, CEO said Oct.
                              27. Plans remain for
                              sale or conversion.

Conoco       Humber           Will consider selling  221
             U.K.             at “right price,”
                              CEO said Oct. 27.

Lyondell-    Berre            May sell unless        105
Basell       France           profits improve, CEO
                              said Sept. 16.

PKN Orlen    Lietuva          Under review because   200
             Lithuania        of low profitability,
                              company said Aug. 15.

Murphy Oil   Milford Haven    Up for sale, company   130
             Wales            said July 22.
                              Transaction expected
                              in first quarter 2011.

Total        Lindsey          Petroplus CEO said     221
             U.K.             April 22 company
                              makes non-binding
                              offer.

Total        Dunkirk          Conversion to          137
             France           terminal. Announced
                              in March 2010.

Chevron      Pembroke         Up for sale.           210
             U.K.             Announced in March
                              2010.

Petroplus    Teesside         Conversion to          117
             U.K.             terminal end-2009.

Total        Gonfreville      Crude unit shut in     173
             France           August 2009.

Shell        Stanlow          Up for sale.           233
             U.K.             Announced in August
                              2009.

NORTH/CENTRAL AMERICA

BP           Texas City       Up for sale, company   475
             Texas            said Feb. 1.

BP           Carson           Up for sale, company   266
             California       said Feb. 1.

Valero       Aruba            At full rates since    275
                              Jan. 31. Plant was
                              shut in July 2009 on
                              poor economics.
                              Company pursues sale
                              or joint venture.

Marathon     6 refineries     To be spun off into    1,140
                              Marathon Petroleum,
                              company said Jan. 13.

Western      Yorktown         In process of          71
             Virginia         converting to
                              storage terminal,
                              company said Dec. 8.
                              Is also negotiating a
                              sale and deal may
                              occur in first or
                              second quarter.

Exxon        Chalmette        Some units will be     196
             Louisiana        stopped, company
                              said in August.

Murphy Oil   Meraux           Up for sale.           125
             Louisiana        Announced July 22.

Murphy Oil   Superior         Up for sale.           35
             Wisconsin        Announced July 22.

Chevron      Kapolei          Operations may be      54
             Hawaii           reduced, company
                              announced in March
                              2010.

Sunoco       Eagle Point      Shut on poor           150
             New Jersey       economics in
                              November 2009.
                              Possible conversion
                              to biofuels announced
                              in February 2010.

Alon         Bakersfield      Shut in January 2009   68
             California       after Big West went
                              bankrupt. Alon bought
                              the plant in February
                              2010 and said Jan. 28
                              it expects to start
                              production in June.

Western      Bloomfield       Shut in late 2009 on   17
             New Mexico       poor economics.
                              Operates as a
                              terminal.

Valero       Corpus Christi   FCC shut on economics  20
             East, Texas      in March 2009.

Shell        Montreal         Conversion to          130
             Canada           terminal after
                              operations ceased in
                              Oct. 2010.

ASIA PACIFIC

Showa Shell  Keihin           Permanent closure      120
             Japan            of Ogimachi crude
                              unit in September
                              2011.

JX Holdings* Negishi          Permanent closure      70
             Japan            of a crude unit in
                              October 2010.

JX Holdings* Mizushima        Permanent closure      110
             Japan            of crude unit 2 in
                              June 2010.

JX Holdings* Oita             Permanent closure      24
             Japan            of crude unit 1 in
                              May 2010.

Fuji Oil     Sodegaura        Permanent closure      52
             Japan            of crude unit 1 in
                              November 2010.

Nihonkai Oil Toyama           Conversion to          60
             Japan            terminal in March
                              2009.

CPC Corp.    Kaohsiung        FCC shut on            25
             Taiwan           economics in
                              February 2009.

*JX Holdings Inc. is the parent company of JX Nippon Oil &
Energy Corp., Japan’s largest refiner, and was formed in April
2010 after the merger of Nippon Oil Corp. and Nippon Mining
Holdings Inc.


                    COMPLETED OR AGREED SALES

Company      Refinery         Status                 Capacity

Ineos        Grangemouth      PetroChina buys        210
             Scotland         50 percent stake.
                              Announced Jan. 31.

Ineos        Lavera           PetroChina buys        210
             France           50 percent stake.
                              Announced Jan. 31.

Sunoco       Toledo           PBF Energy agrees      170
             Ohio             to buy on Dec. 2.

Shell        Gothenburg       Agreed sale to St1     78
             Sweden           Oy of Finland on Oct.
                              27.

Marathon     St. Paul Park    TPG Capital agrees     74
             Minnesota        to buy plant on
                              Oct. 6.

Valero       Paulsboro        PBF Energy agrees to   166
             New Jersey       buy on Sept. 27 for
                              $360 million.

Shell        Heide            Agreed sale to         91
             Germany          U.K.’s Klesch & Co.
                              on Aug. 20.

Valero       Delaware City    Sold to PBF Energy     190
             Delaware         in April 2010.

Shell        Marsden Pt       Shell sells 17%        109
             New Zealand      share to Infratil
                              and government
                              pension fund in
                              March 2010.

Ruhr Oel*    Gelsenkirchen    Russia’s Rosneft       266
             Germany          agrees to buy PDVSA’s
                              50 percent stake in
                              Ruhr Oel Oct. 15.

Ruhr Oel*    Miro             Russia’s Rosneft       311
             Karlsruhe        agrees to buy PDVSA’s
             Germany          50 percent stake in
                              Ruhr Oel Oct. 15.

Ruhr Oel*    Bayernoil        Russia’s Rosneft       240
             Neustadt         agrees to buy PDVSA’s
             Vohburg          50 percent stake in
             Germany          Ruhr Oel Oct. 15.

Ruhr Oel*    PCK              Russia’s Rosneft       226
             Schwedt          agrees to buys PDVSA’s
             Germany          50 percent stake in
                              Ruhr Oel Oct. 15.

* Ruhr Oel, part owned by BP, has a 100 percent stake in the
Gelsenkirchen refinery and a 24 percent share in Miro’s
Karlsruhe plant. It also holds a 25 percent share in Bayernoil
and a 37.5 percent stake in the Schwedt facility. The sale was
announced on Oct. 15.

Feb. 10 (Bloomberg) -- PetroChina Co., the nation’s biggest energy producer, agreed to buy a 50 percent stake in Encana Corp.’s Cutbank Ridge assets for C$5.4 billion ($5.4 billion), giving the Chinese company its first gas asset in North America.

The acquisition would give PetroChina daily production of 255 million cubic feet of natural gas from 635,000 acres in the Canadian provinces of Alberta and British Columbia, Encana said in a statement yesterday. The companies will also form an equal venture to increase output, the Beijing-based producer said in a statement today.

The deal would bring the total value of energy acquisitions by Chinese companies since last year to about $46 billion to supply the world’s fastest-growing major economy. The Canadian transaction follows PetroChina’s decision last month to form a venture with U.K. refiner Ineos Group Holdings Plc to process crude oil at plants in Scotland and southern France.

“PetroChina is now buying assets in developed countries like Canada and the U.S. as well as developing nations as part of its strategy to become an international oil major,” said Shi Yan, an analyst at UOB-Kay Hian Ltd. in Shanghai. “The focus on gas is because demand for the fuel in China is growing. Gas demand is rising by about 20 percent a year and the government is encouraging its use because it’s cleaner.”

China’s government wants to triple the country’s use of gas, which pollutes less than oil and coal, by 2020 and the fuel to account for about 10 percent of energy consumption. PetroChina plans to spend at least $60 billion on global assets in the next decade to increase reserves and production. The Encana deal, announced after market close yesterday, requires approval from the Canadian and Chinese authorities.

Share Gains
PetroChina has risen 25 percent in Hong Kong trading in the past year, outpacing the 17 percent increase in the benchmark Hang Seng Index. The stock fell 3.8 percent to close at HK$10.54 yesterday. Encana dropped 1.9 percent to C$30.65 on the Toronto Stock Exchange.

“By combining resources with PetroChina in this joint venture, we would expect to recognize additional value through accelerating our pace of development,” Encana Chief Executive Officer Randy Eresman said in yesterday’s statement.

The Calgary-based company in 2009 spun off Cenovus Energy Inc. to focus on natural gas as prices for the resource began falling because of oversupplies generated by an onshore drilling boom in North America.

Encana shares have gained 5.4 percent this year as investors expect ventures with Chinese competitors would shelter the Canadian company from the slump in natural gas prices...

Gas Prices
Natural-gas futures have declined 65 percent from a July 2008 high to $4.32 per million British thermal units yesterday...

...The stake at Cutbank Ridge includes both shale gas formations as well as conventional resources, said spokeswoman Carol Howes. Executives were not available to discuss the deal further, she said. Encana reports quarterly earnings today...


more...
http://noir.bloomberg.com/apps/news?pid=20601087&sid=a0y59cmlcG6s&pos=1

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TORONTO (AP) — PetroChina, China’s biggest oil and gas producer, said Wednesday it agreed to pay $5.4 billion for a 50 percent stake in Encana’s shale natural gas project in British Columbia in what would be the largest ever Chinese investment in Canada’s energy sector.

The state-owned Chinese firm is investing in Encana’s Cutbank Ridge assets. Encana is Canada’s biggest natural gas provider.

Randy Eresman, the chief executive of Encana, said the deal was the culmination of nine months of negotiations.

PetroChina’s interest represents current daily production of 255 million cubic feet of gas a day, proven reserves of one trillion cubic feet of natural gas and nearly 257,000 hectares (635,050 acres) of land.

The transaction requires Canadian and Chinese government approval. Prime Minister Stephen Harper’s Conservative government blocked Anglo-Australian BHP Billiton’s takeover of Potash of Saskatchewan last November, but Mr. Harper has welcomed Chinese investment in recent years.

China has been acquiring Canadian energy properties to try to secure future supplies and meet its growing demand.

Last April, the Chinese made their first foray into an operating oil sands project, with Sinopec paying $4.65 billion for a 9 percent stake in Syncrude Canada. Sinopec already had a 50 percent stake in the Northern Lights project, planned by Total.

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Former Shell Oil Co. president John Hofmeister said that the Obama administration's energy policies and regulations are strangling the U.S. economy and preventing the country from decreasing its dependence on foreign oil.

Testifying before the House Energy and Power Subcommittee, the Houston businessman blamed the administration for restricting offshore drilling after the oil spill in the Gulf of Mexico last year.

"I believe that the decline" in drilling in the Gulf of Mexico "will be sharper and deeper than what anyone is currently projecting," he told lawmakers. "We have made a horrible error as a country."

Hofmeister was one of six energy experts testifying about the effect of Middle East political unrest, including the ongoing protests in Egypt, on the U.S. oil market. The panelists presented a gloomy view of the America's energy future if restrictions on domestic production remain. The Obama administration lifted a moratorium on deep-water drilling in October, but the government has not approved any projects that would have been blocked by that ban.

"We have a real strangulation by regulation taking place for domestic production at the current time in this country," Hofmeister said.

"It is "absolutely critical to reduce dependence on the Middle East," he said. He said, for example, that if oil tanker traffic were shut down in the Strait of Hormuz, the price of crude would double or even triple rapidly

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Gasoline prices have been on the rise for months now. As the economy improves, demand has gone up. But aside from that, something unusual is happening with gasoline prices in the U.S. this winter: Prices are rising faster on the East and West Coasts than they are in the middle of the country.

Since September, a gallon of regular gas in New York state has gone up 59 cents. In Colorado, it's increased only 25 cents. Some of that increase is because of different tax rates in the two states, but the bulk of it is due to bargain-priced oil coming in from Canada.

When you think "foreign oil," the Middle East probably comes to mind. But Canada actually is the No. 1 supplier of foreign oil to the United States. The amount of oil Canada delivers to this country is growing, thanks in large part to the Alberta oil sands.

A Bottleneck
Despite protests from environmentalists, Canada's oil sands business is booming. Much of that crude heads into the U.S. through a network of pipelines. But pipeline construction hasn't kept up and a bottleneck has developed in Cushing, Okla.

"Because there are no pipes going south from Cushing to Houston, the oil backs up there and as inventories build, prices go down," says Philip Verleger, an oil market analyst and professor at the University of Calgary.


That means crude in the middle of the country is selling for about $15 a barrel less than it would on the world market. Verleger says you can see that reflected at gas pumps in the middle of the country.

"Consumers in Colorado, consumers in Illinois, consumers in Minnesota should all be sending thank you notes to the province of Alberta," says Verleger, who lives in Colorado. "We're benefiting from the increased supply in Alberta because it can't make its way to the Gulf Coast."

Glenda Walden of Lakewood, Colo., recently filled up her 2001 Honda Civic for $2.99 a gallon — about 25 cents more than she paid in September.

In New York, the increase has been more than twice that. But that's cold comfort for Mark Fox of Denver, who spent $75 dollars on gas for his sport utility vehicle.

"That's what they cap you at [on] the credit card — so can't even fill up anymore, but we do what we can," he said. "It's tough, though."

Still, when he finds out why he's getting a better deal than a New Yorker, Fox shows his appreciation: "Thank you, Canada!"

Pipeline Problems
What's been a boon for some U.S. drivers is considered a problem by Canadian oil companies. They don't like selling their oil at a discount. So the firm TransCanada has proposed a new pipeline that would make it easier to relieve that bottleneck in Oklahoma and get oil down to the Gulf Coast, where it would fetch higher prices.

"We, as a company, submitted our application for this proposed pipeline back in 2008 to the U.S. Department of State," says Terry Cunha, a TransCanada spokesman. "And we're continuing to wait for a decision."

The State Department must issue what's called a "presidential permit" for the project because it crosses an international boundary. The department says it's still gathering information about things such as the environmental effects of the pipeline.

Meanwhile, an increasing supply of Canadian oil continues to flow into the U.S., says Verleger, the oil market analyst.

"If the new pipeline is not approved, Alberta has a serious problem of what to do with the crude," Verleger says.

Companies in Alberta and Oklahoma are building more oil tanks, hoping storage will relieve the surplus. But until there are more ways for Canada's oil to get to the broader market, drivers in the middle of the country will continue to benefit.

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Feb. 16 (Bloomberg) -- Record demand for liquefied natural- gas is causing the decade-long glut of vessels that carry the fuel to disappear, doubling freight rates and at least tripling profit for shipping lines Golar LNG Ltd. and Exmar NV.

Consumption of LNG, liquefied by cooling the gas to about minus 260 degrees Fahrenheit, is rising 5.1 percent at a time when nations from the U.K. to South Korea are increasing curbs on pollution. Natural gas emits about 50 percent less carbon dioxide than coal and power companies are also burning more because it’s cheaper after plunging 30 percent since the end of 2008 while coal rose 52 percent and oil almost doubled.

While owners of oil tankers and coal carriers are slowing down, anchoring ships and scrapping them because rental rates have been unprofitable, gas ships are sailing at the fastest speeds since at least 2008, data compiled by Bloomberg show. Average spot LNG tanker rates will about double to $70,000 a day this year, the highest since 2007, according to Martin Korsvold, an analyst with Pareto Securities AS in Oslo, whose ratings on Golar earned investors an 87 percent return in six months.

“High-growth economies such as China and India are using more and more natural gas and Europe is using more LNG for environmental reasons,” said Zach Allen, president of Pan Eurasian Enterprises Inc., a Raleigh, North Carolina-based company tracking gas shipments. “It will benefit the LNG tanker owners more than anyone else because there are really very few additional tankers coming on line.”

Lake Charles
Since the first LNG shipment from Lake Charles in Louisiana to the U.K. in 1959, the industry has expanded to import facilities in 23 countries, according to Clarkson Plc, the world’s biggest shipbroker. Exxon Mobil Corp. says natural gas will be the fastest-growing major fuel through 2030 and bought XTO Energy Inc. in June for $34.9 billion, giving it proprietary technology used to get gas.

Increasing profit is encouraging owners to sail vessels faster, with the average speed of the fleet increasing to 13.4 knots last week, from as low as 12.1 knots in July, according to ship-tracking data compiled by Bloomberg. It’s also spurring them to stop idling tankers. There were an average of 51 anchored last week, down from 91 in June, the data show.

The opposite is happening elsewhere in the merchant fleet. Returns for owners of supertankers dropped 35 percent last year and were last at $48,333 on the benchmark Saudi Arabia-to-Japan route while for capesize ships carrying coal and iron ore they declined 46 percent and were last at $7,189, according to data from the Baltic Exchange. The bourse in London publishes assessments for more than 50 maritime routes.

Vessel Surplus
Most of that slump is being caused by a surplus of vessels rather than a slowing global economy. New orders are equal to 24 percent of the supertanker fleet and 43 percent of existing capesizes, according to Redhill, Surrey-based IHS Fairplay, which compiles data on ships, ports and vessel movements. The orders were mostly made in 2007 and 2008 when daily income rose to $177,036 for supertankers and $233,988 for capesizes.

In 2008, 13 percent of the LNG tanker fleet was idled, compared with 3 percent of the oil-tanker fleet and less than 1 percent of the dry bulk fleet, the United Nations estimates. Golar in a report in November said there had been “more or less 10 years with structural overcapacity” in the fleet.

“We are not seeing a huge expansion on the LNG fleet side,” said Jorn Bakkelund, an analyst with RS Platou, an Oslo- based shipbroker and investment bank. “That’s what separates LNG from most of the other shipping segments.”

The LNG tanker fleet has a total of 347 vessels. There are 26 new ships on order, equal to 10 percent of the existing capacity of the fleet, according to IHS Fairplay data.

Gas Carriers
Part of the reason is the expense in building the vessels. An LNG ship cost about $210 million in March, compared with $99 million for a supertanker and $57 million for a capesize, according to the UN. Gas carriers need equipment to hold about 155,000 cubic meters of liquid that expands to 95 million cubic meters in gas form, equal to about 25 percent of peak daily winter demand in the U.K., Europe’s biggest gas market.

LNG tankers are often the only option to connect producers and consumers. All pipeline projects into Europe combined wouldn’t be enough to meet anticipated demand, according to Clarkson. Qatar, the biggest LNG supplier, is about 5,000 miles away from Japan, the largest consumer.

“By 2020, we will need another 100 ships and by 2035 the fleet has to double,” said David Glendinning, president of Teekay Gas Services, a unit of Hamilton, Bermuda-based Teekay Corp. that provides LNG transport for energy companies and utilities.

Shipping Recommendations
Golar’s tanker rates will double to an average of $40,000 a day this year, according to Urs Dur, an analyst at Lazard Capital Markets Ltd. in New York, whose recommendations on the company earned investors a 79 percent return in 12 months. His estimate is a combination of long-term contracts and spot rates.

The spot market in gas tankers started in the past four years because ships were still being delivered from yards as new LNG projects were delayed by financing or construction, according to Calum Kennedy, an analyst at Clarkson in London.

Golar will report a fivefold increase in earnings per share this year to $1.15, according to the mean of 10 analyst estimates compiled by Bloomberg. Shares of the company jumped 22 percent in Oslo trading this year.

Exmar, based in Antwerp, Belgium, will earn 78 cents a share, up from 25 cents, the mean of five estimates shows. Its stock gained 7.4 percent this year in Brussels. Teekay LNG Partners LP, based in Hamilton, Bermuda, will report earnings of $2.09 a share, from $1.68, based on two estimates. The shares were little changed in New York trading this year.

LNG Demand
Global LNG demand will increase to the equivalent of 31.1 billion cubic feet a day in 2011, according to Barclays Capital. China, the world’s biggest energy consumer, bought 87 percent more LNG in 2010, customs data show. While Asia led growth in demand last year, it will be Latin America and the Middle East this year, Barclays estimates.

Natural gas will account for 25 percent of global energy supply by 2030, rising from about 20 percent, Irving, Texas- based Exxon said last month in its Outlook for Energy: A View to 2030 report, used to guide the company’s investment decisions.

“Global demand for natural gas as a clean fuel will keep increasing,” said Oyvind Hagen, an analyst at Oslo-based ABG Sundal Collier Holding ASA. “You have a much better market outlook in LNG than crude tankers because you still have oversupply in crude tankers.”

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Feb. 16 (Bloomberg) -- The biggest difference between natural gas and crude oil prices in eight months is fanning calls by Europe’s largest power producers to scrap the almost 40-year-old system for setting their fuel costs.

E.ON AG, Germany’s biggest gas importer, asked suppliers last year to sell it fuel at spot-market rates rather than at prices tied to oil products, two people with knowledge of the matter said this week. GDF Suez SA, operator of Europe’s largest natural-gas network, said in September it was negotiating a stronger link to spot prices for long-term purchases. North Sea Brent crude costs $55 a barrel more than U.K. gas, the most since May 3, according to data compiled by Bloomberg.

Gas buyers on mainland Europe buy about two-thirds of their fuel under long-term contracts, a formula that’s driven up their costs after Brent crude rallied 9 percent this year to a 28- month high. By contrast, U.K. consumers can purchase gas at cheaper spot-market prices, which have fallen 15 percent.

“If E.ON is pushing for 100 percent spot indexation it suggests they believe the entire European market is moving to a fully liberalized structure as already exists in Britain and North America,” said Patrick Heren, a London-based consultant who founded Heren Energy Ltd., the European price-information service bought by Reed Business Information Ltd. to form ICIS Heren.

Oil-Linked Contracts
The contracts are often pegged to gasoil or fuel oil prices with a three-to-six month time lag, rather than crude, in a method that dates back to the 1970s, when oil-based fuels were more commonly used in power generation. Spot gas prices have fallen 40 percent from their 2008 peak as industrial demand collapsed during the global financial crisis and U.S. and Middle Eastern supply rose.

E.ON is in talks with all its suppliers over adapting long- term contracts to the “current market situation,” Kai Krischnak, a spokesman for E.ON Ruhrgas, the company’s Essen- based gas unit, said yesterday. He declined to comment on contract details or the timing of the talks.

Moscow-based OAO Gazprom, the world’s biggest producer, agreed last year with companies such as E.ON, Wingas GmbH, GDF Suez, Eni SpA to reduce prices by including more spot fuel and delaying some contracted volumes to a later period, the Russian company said in a quarterly earnings report on Feb. 14.

Arbitration Confidence
The company reached agreements with E.ON, Eni and GDF Suez on their requests for reconsidering price formulas, Deputy Chief Executive Officer Alexander Medvedev said in November. The deals will last for three years, he said.

“A number of our key customers used their right to renegotiate prices at the beginning of last year,” Medvedev said at an investor meeting in London yesterday. “If it does come to arbitration proceedings, we are pretty confident.”

As much as 67 percent of gas on mainland Europe was sold under oil-linked contracts last year, Societe Generale SA said in a Feb. 2 report. Prices in the U.K.’s National Balancing Point market are determined by supply and demand, without any direct link to oil.

North Sea Brent crude oil settled at $101.64 a barrel on the ICE Futures Europe exchange in London yesterday. U.K. natural gas closed at 52.89 pence a therm, or $48.45 a barrel when converted into similar units.

‘Increasingly Untenable’
“A rising oil price makes things very rapidly increasingly untenable” for consumers with oil-linked contracts, Jonathan Stern, director of gas research at the Oxford Institute for Energy Studies, said in a phone interview from Oxford, England.

E.ON Ruhrgas sold 20.6 billion euros ($27.9 billion) of the fuel in 2009, or about 58 billion cubic meters, according to its website. That’s more gas than India used that year, according to BP Plc’s Statistical Review of World Energy.

While purchases based solely on U.K. gas futures would have averaged $6.40 a million British thermal units last year, the cost for buyers of Gazprom’s contract gas was $8.60 a million Btu in 2010, according to data from Sanford C. Bernstein & Co.

The world’s gas “glut” may exceed 200 billion cubic meters this year, up from 130 billion in 2010, the International Energy Agency, an adviser to developed nations, said in November. The Paris-based agency defines the glut as the capacity of inter-regional pipelines and liquefied-gas export plants minus the volume of gas traded.

Deferred Deliveries
About 5 billion cubic meters of pre-paid Russian gas is weighing on spot prices because customers have deferred delivery to a later date, said Thierry Bros, a senior analyst at Societe Generale SA. The oil link will be preserved and utilities will “suck up their losses” before the market returns to balance by the middle of the decade, he said in London yesterday.

E.ON “didn’t share the money with their customers or with Gazprom when oil-indexed contracts were out of the money” in 2005-2007. At that time, lower oil prices cut gas costs to utilities that bought supplies under multiyear contracts, Bros said.

For Heren, E.ON and other companies are faced with the dilemma of buying gas at a higher price than they can pass on to consumers amid competition from liquefied natural gas shipments and U.K. supplies priced in the free market.

E.ON “cannot support an ineffective two-tier pricing system,” he said. “With the changes in the European energy marketplace it recognizes that it cannot purchase gas on an oil- indexed basis which it will then have to sell on a gas index.”

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MOSCOW, Feb 17 (Reuters) - Rosneft on Thursday held firmly to its spot as top Russian oil producer and the world's biggest holder of oil reserves by announcing a 0.3 percent in crude reserves last year.

But its overall hydrocarbon reserves edged down 0.4 percent to 22.77 billion barrels of oil equivalent (boe) because of a 3.1-percent fall in gas reserves, according to DeGolyer & MacNaughton's audit.

The state-controlled firm could hugely increase its resource base following last month's agreement with BP to develop Arctic oil fields with estimated reserves of 5 billion tonnes of oil and 10 trillion cubic metres of gas.

Rosneft has been behind the recent surge in oil output by Russia, the world's biggest producer. Last month Russia pumped 10.18 million barrels per day.

Earlier this week it also announced the discovery of the Sanarsky and Lisovsky deposits in Eastern Siberia, with each holding around 80 million tonnes of oil.

Rosneft said that in 2010 its oil reserve replacement ratio was 106 percent. Under the Petroleum Resources Management System (PRMS), formerly known as SPE, it had net oil and gas proved reserves of 22.765 billion boe, down from 22.858 billion boe in 2009.

Oil reserves increased by 0.3 percent to 18.110 billion boe under PRMS.

Under the more stringent U.S. Securities and Exchange Commission's (SEC) methodology, which takes into account reserves extractable during the life of companies' existing licences, Rosneft's hydrocarbon reserves rose to 15.199 billion boe from 15.146 billion boe in 2009.

Rosneft said its hydrocarbon reserve life was 25 years, 21 years for oil and 67 years for gas, under the PRMS rules.

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