April 1st, 2006:

Contracted drilling rig backlog grows to $34.5 billion in tight world market
Ray Tyson
For Petroleum News
Five of the leading offshore drilling companies in the world have accumulated a hefty $34.5 billion in contracted rig backlog, according to information compiled by the largest offshore driller of them all, Transocean.
“This is unprecedented in the offshore drilling business,” Transocean spokesman Guy Cantwell told Petroleum News.
Transocean alone has $16.8 billion in total contracted backlog, a sum the company said is two and half times greater than its nearest competitor. Transocean also said that from March 2, 2006, through March 2, 2008, the average day rate for its high specification fleet will increase to $320,500 from $179,600, a nearly 80 percent jump.
And for one of the company’s premium fifth-generation drillships, Discoverer Enterprise, Transocean said it will receive $520,000 per day from BP for three years of deepwater work in the Gulf of Mexico beginning in December 2007. BP is leasing the same rig, currently on a three-year Gulf contract that began in December 2004, for $182,500 a day.
Demand fueled by prices
Industry attributes the huge spike in day rates and contracted backlog to increased worldwide rig demand fueled by the unprecedented strength in oil and gas prices.
“Long-duration contracts are increasingly common,” Transocean said, noting that the market for fifth-generation rigs capable of drilling in 10,000 feet of water and more is expected to remain tight into 2010.
Transocean, which didn’t identify its competitors, said that in addition to the company’s $16.8 billon in contracted backlog, four other drilling companies have backlogs totaling $17.7 billion, ranging from $6.7 billion to $2.4 billion. Some of Transocean’s competitors include GlobalSantaFe, Diamond Offshore, Ensco International and Nabors Industries.
Transocean’s $16.8 billion rig backlog breaks down to $3 billion in 2006, $4.1 billion in 2007, $4 billion in 2008, $3 billion in 2009, $1.8 billion in 2010, $500 million in 2011 and $400 million from 2012 through 2014. Of the $16.8 billion in total backlog, $13.5 billion are for Transocean’s high-specification rigs.
“They’re not letters of intent. They’re not letters of agreement. They’re contracts that are binding — firm contracts,” Transocean’s Cantwell said. “And it has grown significantly in the last year or so.”
$3 billion backlog for 2006
The $3 billion in Transocean backlog for 2006 is slightly greater than the $2.9 billion the company earned in revenues for all of 2005. Transocean said 26 percent of its contracted backlog in 2005 was held by national oil companies, 26 percent by E&P independents and 48 percent by the majors.
More specifically, Chevron accounted for 16 percent of Transocean’s contracted backlog in 2005, BP 15 percent, Shell 11 percent, ONGC 8 percent, Reliance 8 percent, Petrobras 7 percent and Anadarko Petroleum 7 percent. The remaining 28 percent is held by “other” companies. Of total 2005 revenues, 43 percent came from rigs deployed in Europe/Africa, 34 percent in North and South America and 23 percent in Asia/Pacific.
Over a two-year period ending in early March 2008, day rates for Transocean’s fifth-generation rigs will increase on average to $385,600 from $208,100, an 85 percent increase.
During the same period, the company’s “other deepwater” rigs will increase to $273,200 per day from $159,600, a 71 percent increase, while Transocean’s “other high-specification” rigs will increase to an average $286,700 per day from $161,700 per day, a 77 percent increase.
“We believe the current (drilling) cycle will last longer than any previous cycle,” Transocean COO Jean Cahuzac told the A.G. Edwards Energy Conference in mid-March. He added that Transocean’s fleet is “largely committed” through 2006.
Ray Tyson is editor and publisher of www.upstreamreview.com read more

Group threatens continued attacks on oil installations; nine foreign workers taken hostage Feb. 18 from Willbros Group barge
Osmond Chidi
Associated Press Writer
Militants demanding control of revenues from Nigeria’s oil-rich southern delta released their last remaining foreign hostages on March 27 — two Americans and a Briton — but threatened to continue attacks on oil installations.
Abel Oshevire, spokesman for the southern Delta state government, said Americans Cody Oswalt and Russell Spell and Briton John Hudspith were released just before dawn after more than five weeks in captivity.
“They are here with us now and are all in good health,” Oshevire told reporters.
The militants, responsible for a wave of recent attacks in southern Nigeria, took nine foreign oil workers hostage Feb. 18 from a barge owned by Willbros Group Inc., a Houston-based oil services company that was laying pipeline in the delta for Royal Dutch Shell. The group released six of the captives after 12 days.
The last three hostages could be seen from a distance as they greeted officials, but the freed men did not immediately address reporters.
The militants have targeted the oil industry in the world’s eighth-largest producer of crude and the fifth largest supplier to the United States, blowing up oil installations and cutting production by 20 percent.
Crude-oil prices slipped under US$64 a barrel March 27 after the release of the hostages eased concerns about supplies. But Nigeria remained volatile, and nagging worries about Iran persisted.
Since the attacks began, Royal Dutch Shell has closed half its oil fields and one of its two main loading terminals. Despite the danger, however, oil companies remain drawn to the country because its benchmark Bonnie Light is so easily — and inexpensively — extracted, and is of high quality.
The militants warned that the release of the hostages did not mean an end to attacks: “The keeping of hostages is a distraction to us,” the group wrote in an e-mail to The Associated Press.
In a general news release, the group said it had better uses for what it claimed were 800 fighters needed to take care of the hostages — namely more attacks on oil facilities.
The e-mail to AP said the hostages were released at the request of local communities who had welcomed the militants after the Nigerian military launched attacks on Delta communities accused of stealing oil. The military has withdrawn and the commander who ordered the assaults has left the area.
Government met none of demands
The group also told the AP that the government had met none of its demands for the release of the hostages, which include the release two arrested leaders of the Ijaw tribe and payment by Royal Dutch Shell of US$1.5 billion to compensate Ijaw communities for oil pollution — a demand that has also come from Nigerian lawmakers. “Our ultimate aim is the control of the resources of the Niger Delta by its people,” said the message to the AP.
President Olusegun Obasanjo’s office released a statement welcoming the release and calling on the militants to “choose the path of dialogue and due process in resolving problems instead of” resorting to violence. read more

Joins long line-up; figures outlook for crude prices and oil sands production outweigh concerns about rising project costs
Gary Park
For Petroleum News
Husky Energy has given a solid vote of confidence to the future of oil prices by starting engineering work on a plan to almost double capacity at its Western Canadian heavy oil upgrader at a possible cost of C$2.3 billion.
After about a decade of mulling over the expansion while infrastructure costs have soared, Husky plans to spend C$90 million on the engineering work over the next 15 to 18 months.
It will then decide whether to embark on full-scale construction.
If the final project is built it should be ready to come on line in 2009, raising output to 150,000 barrels per day from about 82,000 bpd.
“The upgrader will ensure that Husky captures the full value from increasing volumes of heavy oil production,” including Husky’s own Tucker project, said president and chief executive officer John Lau.
The upgrader at Loydminster, on the Alberta-Saskatchewan border, was commissioned in 1992 at a cost of C$1.6 billion and has been steadily increased from its initial capacity of 54,000 bpd, converting heavy oil into low sulfur synthetic crude for refineries in Canada and the United States.
Other Edmonton area upgrader proposals
In taking such a major step, Husky joins the ranks of several upgrader proposals for the Edmonton area, including two independent facilities by BA Energy and North West Upgrading, plus projects by Petro-Canada, Synenco Energy and Canadian Natural Resources.
In addition, Shell Canada is raising capacity at its Edmonton refinery, while France’s Total has given strong indications it may join the line-up.
The reluctance to enter the upgrading sector over recent years has reflected the economic doubts associated with such ventures.
Traditionally, refiners have been faced with the high costs of upgrading a resource that is less valuable than conventional higher crude and have ended up smeared in red ink.
Although the higher returns from fast-rising volumes of bitumen have eased the risks, the price differential between light and heavy crudes has grown to more than 50 percent from the long-term spread of 30 percent, which means heavy oil producers are now collecting only about US$30 per barrel.
Tom Ebbern, executive managing director of institutional research at Tristone Capital, said oil prices would have to fall below US$40 per barrel for Husky to back away from the upgrader.
However, he did suggest that Husky’s procrastination means it now has to swallow the higher costs of steel and labor.
Husky has been helped along by its own C$500 million Tucker oil sands project, which is scheduled to produce its first oil by late 2006 and grow to peak production by mid- to late-2008.
As well, Husky has its sights on a C$10 billion oil sands investment, targeting 200,000 bpd of bitumen, starting with a 50,000 bpd phase in 2009.
Costs also up for North West
The pressing need for upgrading capacity is bolstering plans by backers of the North West facility.
Company President Rob Pearce said costs of the three-stage 231,000 barrel per day operation have “gone up significantly” from original estimates of C$4.8 billion.
He said the initial figures were developed 18 months ago, since when costs of materials, equipment and labor have galloped ahead.
North West is hopeful it can curb that escalation by building near Edmonton rather than in the heart of the over-heated Fort McMurray oil sands region, although the same squeeze on everything from workers to steel applies.
But builders of five other upgrader complexes share North West’s view that Edmonton’s larger workforce and its proximity to infrastructure, plus the city’s role as a hub of existing and planned pipelines both from the oil sands and to U.S. and Canadian markets, provide an added edge.
BA Energy, a privately held company like North West, shares the view that Edmonton is the preferred location and is confident it has the jump on its rivals, targeting a start-up date in 2008.
Now both BA and North West are on the verge of testing the support for their plans by becoming publicly traded companies.
BA anticipates an initial public offering by late 2006 and North West said it is likely to go public in mid-2007, pinning their hopes on investor appetite for any venture related to the oil sands. read more

'Big gamble' purchase of untapped resource could open way to 38 billion barrels; others venture into Peace River, Saskatchewan
Gary Park
For Petroleum News
Royal Dutch Shell is aligning itself with the finest traditions of the oil sands — blazing a new trail in an effort to unlock hundreds of millions of barrels that have so far defied technology.
In forking over C$465 million for more than 230 square miles it has entered a region which other E&P companies have avoided until now.
Through Shell Exploration & Production in the Americas, the multi-national is tackling the late Devonian Grosmont carbonates — a massive potential heavy oil resource that poses a challenge for anyone hoping to separate the bitumen from its host limestone.
The National Energy Board estimates that of the 315 billion barrels of ultimate potential in the oil sands region, 38 billion barrels are trapped in carbonate deposits, instead of the standard sandstone or dirt, which are being widely exploited through conventional mining or steam-assisted extraction methods.
So far Shell has said only that it is hopeful it can apply either enhanced or new emerging heavy oil technologies such as thermal recovery to provide the basis for a commercial operation.
Mahogony project may provide solution
Murray Gray, a professor of chemical engineering at the University of Alberta, has told reporters that Shell may already be moving towards a solution through the work it is undertaking at the Mahogony oil shale project in Colorado.
He said the company has written several patents covering the extraction of hydrocarbons from some “very tough places” such as shales.
The Mahogony project involves lowering electric heaters into 1,000-foot vertical wells to increase formation temperatures to 657-700 degrees Fahrenheit, separating the hydrocarbons from rock and further reducing the oil to heavier and lighter fractions.
Gray suggested the carbonate could be easier to develop than oil shale because it would require 80 percent less heat.
Shell has said only that it expects to drill some appraisal wells later this year to “further understand the resource, the geology and the potential for development.”
However, the company showed a glimmer of confidence, noting that it has a suite of both enhanced and emerging heavy oil technologies and, although not all are proven, the volume of the resource in place along with market conditions give it the impetus to pursue a project.
Capital spending commitments not disclosed
Otherwise, the company won’t disclose its capital spending commitments or what timelines it has set for possible commercial development beyond conceding that oil prices in the range of US$60 per barrel persuaded it to invest almost half a billion dollars.
But analysts such as Tom Ebbern of Tristone Capital are mystified that Shell would pay so much to secure rights to a prospect that has failed to even establish its worth through drilling or pilot projects.
Robert Bedin, senior analyst at Ross Smith Energy Group, offered a succinct assessment of Shell’s decision: “It’s a gamble.”
But that has been the history of the oil sands, which, until this century, were mostly scorned as nothing more than a fringe mining venture.
The change of attitude was reflected in a Wall Street Journal article on March 27 which said that “thanks to rising global oil prices and improved technology, most oil-industry experts count oil sands as recoverable reserves” vaulting Venezuela and Canada to first and third in global reserves rankings.
But the article also delved into the economic and environmental challenges of exploiting heavy oil, including the remaking of the landscape in northern Alberta and the release of greenhouse gases from the extraction and processing of bitumen.
Other pioneering ventures under way
What Shell is tackling mirrors several pioneering ventures to open up new heavy oil territories in Western Canada.
Coming into focus is the Peace River play in northwestern Alberta, the least-tapped deposit in the province.
That could be quietly heading for change, with several projects under way, including plans to start work this summer on a C$800 million first-stage bitumen processing plant to handle 25,000 barrels per day.
Privately-held PRO Upgrading hopes to complete the Bluesky Upgrader by 2010, buoyed by the fact that it raised 60 percent of the construction costs in just 30 days without going outside Alberta.
It hopes to cover the balance within six months, PRO business development manager Don Allan told Petroleum News.
PRO (short for Peace River Oil) has set an eventual goal of expanding in four stages to 100,000 bpd by 2020 to serve a fast emerging array of projects, led by companies such as BlackRock Ventures and Penn West Energy Trust.
Allan said PRO aims to have feedstock commitments in place in the next 30 days.
Penn West, in the early stages of a project, hopes to achieve 5,000 bpd by the end of 2006, more than five times current levels as it develops 1.2 million acres of leases in the Seal region.
“We believe this area has the potential to add multiple millions of barrels of reserves and very strong production additions,” said Penn West Chief Executive Officer Bill Andrew.
“Our Peace River project has the potential to redefine our business,” he said.
BlackRock, which is targeting overall production of 40,000 bpd within four years, has budgeted C$95 million for its Seal program this year, where an independent evaluation has assigned 28.8 million barrels of proved plus probable reserves, up 40 percent from 2004, as the company steps up its development efforts.
The Seal prospect offers a bitumen deposit that is 50 to 80 feet thick and offers 10 degree API heavy oil that can initially be extracted using conventional artificial lift technology, reducing operating and capital costs, although operators are turning to steam-assisted gravity drainage methods to exploit deeper deposits.
Allan described the bitumen as “heavy and ugly,” with a high sulfur content, but is confident the technology being designed for Bluesky can improve the value of the crude, reduce the density of the oil and reduce the viscosity so the oil can be moved by pipeline.
Until now, the major Peace River spotlight has been on Shell Canada, which has been active in the region for 27 years, where it plans to spend C$115 million on new wells to achieve 35,000 bpd and may eventually aim for 100,000 bpd.
The Alberta Energy and Utilities Board estimates Peace River has 130 billion barrels of bitumen in place, of which 14 billion barrels are recoverable using current technology.
Oilsands Quest working in Saskatchewan
Other operators are pinning their hopes on an eastward expansion into Saskatchewan, where privately held Oilsands Quest, owned 70 percent by CanWest Petroleum, is touting a discovery it says could open the way to a major new play.
It has almost completed 25 core wells with what it describes as very encouraging results pointing to bitumen-bearing deposits from 16 to 88 feet thick and is poised to start a second phase of 125 wells costing C$15 million.
Oilsands President Chris Hopkins rates his company as a pioneer “in a whole new industry” in Saskatchewan.
If Oilsands’ geological model proves out, he said it is possible northwestern Saskatchewan could add up to 60 billion barrels of bitumen in place, putting the province in the big leagues. read more

Invites bids on 11 parcels in three regions in attempt to stir fresh interest in a region looking for first discovery in two decades
Gary Park
For Petroleum News
Newfoundland has decided to go big in hopes of breathing new life into an offshore that has failed to notch a commercial discovery in more than two decades, has posted only seven exploratory wells (all of them dry) in the past six years and generated barely C$40 million in successful bids at its latest land sale.
The Canada-Newfoundland and Labrador Offshore Petroleum Board has outlined the conditions of three separate Calls for Bids this year, representing the third-largest auction of offshore drilling rights in its history.
Included in the plans are 11 parcels covering 4.23 million acres of oil and natural gas exploration properties.
Three are in the well-established Jeanne d’Arc basin, home of Newfoundland’s three producing oil fields — Hibernia, Terra Nova and White Rose.
Of the rest, three parcels are in the Sydney basin and five are in the Western Newfoundland and Labrador offshore — two emerging prospects that hold the key to the province’s future as a hydrocarbon region.
Special interest will be paid to the Sydney basin, which accounts for 45 percent of the total acreage up for bids.
It is making its debut following the 2002 resolution of a 38-year offshore boundary dispute between Newfoundland and Nova Scotia, which saw arbitrators award 78.5 percent of the 15,000 square mile Laurentian sub-basin to Newfoundland.
What the Newfoundland government and industry need is a strong response to the Calls for Bids by the Nov. 15 deadline to reverse a drift that has badly dented the once unlimited optimism in the offshore, where C$18.65 billion has been invested in exploration over the past 30 years.
Five wells expected in Orphan
Recent years have been like a cold shower for Newfoundland other than a late 2003 Call for Bids that generated a startling C$673 million for eight parcels spread over 5.3 million acres — all of them in the Orphan basin, where only six wells have been drilled.
Those parcels were taken by the same ownership — Chevron Canada Resources, ExxonMobil Canada and Imperial Oil, although Shell Canada has since entered the partnership with a 20 percent stake, leaving Chevron with 50 percent and ExxonMobil and Imperial with 15 percent each.
Most of the plays in the basin are 6,500 feet to 9,800 feet, 25 to 35 times deeper than Jeanne d’Arc plays.
The consortium conducted two 3-D seismic programs over the past two summers and has signed a two-year contract with Ocean Rig to start exploratory drilling this year.
At C$100 million per well, it is widely expected that five wells will be completed over the contract term — a high-stakes gamble to test the belief that the Orphan basin has at least four oil pools each larger than Hibernia’s 884 million barrels.
Now the Sydney basin could bring another element to Newfoundland’s hydrocarbon potential.
To date the industry has barely scratched the surface of the prospect, logging two offshore wells and gathering about 1,000 miles of 2-D seismic from 1981 and 1983.
What the province needs is a strong response to achieve a turnaround in its most recent land sale when just under C$40 million was bid for five parcels representing 1.05 million acres.
The most notable acquisition was made by Husky Energy, which bid C$35 million for a 5,325 acre parcel close to the Terra Nova field.
The outcome, along with moves by several majors to cut exploration spending and either sell or trade exploration licenses, was a setback in an 18-year history of land sales that have posted C$1.7 billion in bids for 26.6 million acres.
But many industry experts shrug off the discouraging record, arguing that the knowledge of the region’s geology is still limited.
To date, they point out, only 350 wells have been drilled offshore Newfoundland and Nova Scotia compared with more than 15,000 in the Gulf of Mexico, partly reflecting the cost discrepancies between the two basins.
Pierre Alvarez, president of the Canadian Association of Petroleum Producers, has said the key to a breakthrough is to raise the number of wells to 10 to 15 per year.
Steven Paget, an analyst with FirstEnergy Capital, is confident that advances in offshore geology and the closeness of Canada’s East Coast to key U.S. markets, will ensure that exploration continues.
But the outlook for the next two or three years is tied in part to the number of companies willing to submit minimum bids of C$1 million for parcels in the Jeanne d’Arc and Sydney basins and C$250,000 for Western Newfoundland and Labrador.
Subject to government approval, successful bidders receive an exploration license for a term of nine years, but must drill a well within four years to validate the full term of the license. read more

Independents displace ‘Big Oil’ as dominant player in 2005, 2006 Gulf of Mexico federal outer continental shelf lease sales
Ray Tyson
For Petroleum News
Once upon a time in the Gulf of Mexico, the exploration and production independent was largely relegated to the shallow and relatively inexpensive waters of the continental shelf when it came to bidding in federal oil and gas lease sales. No more.
In fact, the last two Central Gulf of Mexico lease sales not only clearly demonstrated that E&P independents are capable of playing hardball with the big oil and gas companies, they have displaced them as the dominant bidder in offshore lease sales.
For one, the independent explorer-producer has mastered the fine art of partnering up with other companies on large bids to secure desired oil and gas prospects. Moreover, time has proven that E&P independents are as good, or arguably better, than the majors at finding commercial hydrocarbons on their leases.
Independents walked away from last year’s Central Gulf Lease Sale 194 with the lion’s share of exploration blocks and accounted for the 10 highest bids in the entire sale, including a sale-high $21.2 million submitted by partners Dominion E&P and Stone Energy.
In this year’s Central Gulf Lease Sale 198, the best showing in eight years with a hefty $588 million in total high bids, E&P independents again came to do battle, capturing tracts with some of the highest bids in recent memory.
E&P independents accounted for six of the highest 10 single bids in this lease sale, including a nearly $34 million bid submitted by partners Newfield and Anadarko for Green Canyon block 551, a highly competitive deepwater tract that received six bids, all but two from other independents.
Other top-ten single bids submitted by independents included Woodside’s $26.6 million bid for Green Canyon block 452, Dominion-Hydro’s $21.4 million bid for Atwater Valley block 428, Noble-Samson’s $20.2 million bid for Mississippi Canyon block 948, Samson’s $11.1 million bid for South Marsh Island Area block 38, and Kerr-McGee-Dominion’s $8.4-million bid for Mississippi Canyon block 945.
When broken down by the sum total of high bids per individual company, E&P independents again scored six out of 10: Dominion’s $41.4 million for 16 blocks, Newfield’s $32.2 million for six blocks, Woodside’s $32.1 million for 11 blocks, Samson’s $27.1 million for 10 blocks, LLOG’s $26.6 for 11 blocks and Anadarko’s $20.3 million for 13 blocks.
Independents got more for their buck
Additionally, E&P independents got more for their buck, taking eight of the top 10 slots in terms of total blocks won compared to the amount of high bids doled out to capture them. BHP Billiton shelled out just $7.6 million for 26 blocks, Hunt Oil $10.9 million for 23 blocks, Dominion $41.4 million for 16 blocks, Hydro $20.1 million for 14 blocks, Anadarko $20.3 million for 13 blocks, Republic Exploration $3.3 million for 12 blocks, Woodside $32.1 million for 11 blocks and LLOG $26.6 million for 11 blocks.
While Amerada Hess’ $42.8 million bid for a deepwater block in Green Canyon was the highest single bid in Sale 198, E&P independent Samson’s $11.1 million bid for a block in South Marsh Island Area was the highest bid on the Gulf’s gas-prone continental shelf.
Also successful with drill bit
The growing success of E&P independents in Gulf of Mexico lease sales has translated into success with the drill bit in exploration and ultimately commercial production.
Both in exploration and production, companies like Devon Energy, Kerr-McGee and Anadarko, among the largest E&P independents in the United States, are forces to be reckoned with in the Gulf’s deep and ultra-deep waters, initially the exclusive playgrounds of deep-pocket majors like ExxonMobil, Shell, Chevron, ConocoPhillips and BP.
Devon has accumulated a huge offshore position, most notably in the emerging Lower Tertiary trend of ultra-deepwater Walker Ridge, where Devon has been party to major discoveries St. Malo, Cascade and Jack. This area is so remote and expensive that the producers have yet to figure out exactly how they plan to get production from these discoveries ashore.
Kerr-McGee is among the first E&P independents to venture into the Gulf’s deeper waters, and is a parent to the so-called “hub-and-spoke” approach to offshore development. This entails finding a large enough field to justify a central production facility and then tying in smaller satellite accumulations as they are discovered. Kerr- McGee’s Nansen-Boomvang complex in East Breaks was among the first Gulf developments to employ the hub-and-spoke concept.
Anadarko, a relative latecomer to deepwater Gulf, had early exploration success at its 100 percent owned Marco Polo field in Green Canyon, followed by nearby discoveries K2 and K2 North.
Anadarko’s Independence Hub online in ‘07
However, it is in the Eastern Gulf where Anadarko hit its first homerun, accounting for seven natural gas discoveries that will be funneled through an Anadarko-operated central production facility known as Independence Hub, which is expected to come online in 2007 ultimately producing 850 million cubic feet of gas per day from nine fields.
Devon, Kerr-McGee and Dominion also are hub participants, making Independence Hub truly an independents’ hub.
In addition to the growing influence of E&P independents in Gulf of Mexico lease sales, the sales also are taking on a more international flavor. Spain’s Repsol made its debut in Sale 198 March 15, joining other non-U.S. based energy companies, including Brazil’s Petrobras, Italy’s Eni, Australia’s BHP and Woodside and Canada’s Nexen. Repsol submitted the sixth highest bid in the sale — $20.2 million for block 304 in Green Canyon.
Small E&P independents also are making their mark on lease sales these days, with each sale bringing a few new players. Among the smaller independents joining this exclusive club for Sale 198 were Badger Oil, Frankel Offshore Energy and Plains Exploration & Production.
Ray Tyson is editor and publisher of www.upstreamreview.com read more

Colin Campbell is the generally acknowledged world expert on the impending oil crisis and, as he tells it, the instructive point is not when oil runs out, but when it peaks – world per capita production peaked in 1979 and we've been using more than we find consistently since 1981 (currently, we use six barrels for every one that we find).
Oil companies hid this, initially, by under-declaring their fields and resources, to give themselves a buffer for bad years. And then they hid the scarcity with mergers, wherein, as Campbell explains, “Exxon bought Mobil in order to buy their unreported reserves.”
The only company that didn't merge was Shell, which hit financial crisis immediately, got rid of its chairman, and now, Campbell notes: “The new chairman of Shell has said, 'Yes, if we talk about the easily accessible oil, it has peaked. But let's think about the deep water and the polar regions.' ” If we're talking about deep water and polar regions, it seems, essentially the game is up. “For the peak of all kinds of oil together, my best estimate is 2010,” says Campbell. And what really matters is the long decline that follows.
Lord Browne, head of BP, has said that we have enough oil in reserve to support current production for 41 years. This is misleading, however, since “it's absolutely absurd to give the impression that production can continue flat for 41 years and then stop dead”, Campbell says. More likely, it will trickle out over a longer period of time.
At that point, he says, “Either nuclear energy will kick in, some miracle technology will develop and we'll figure out how to use less energy or, as I personally think, this particular moment in history has come to an end… We're at the end of the first half of the age of oil. And we could decline naturally, but, looking at it historically, the Roman Empire didn't gradually rise and gradually decline. It went bust.”
Risk factor: Quite likely.
http://www.guardian.co.uk/weekend/story/0,,1742893,00.html read more

JORGE RUEDA
Apr 01, 2006
President Hugo Chavez said 17 Venezuelan and foreign companies agreed on Friday to turn privately run oil fields into joint ventures controlled by the country's state oil company.
Under the new joint ventures, state-run Petroleos de Venezuela SA, or PDVSA, will hold a minimum 60 percent stake in the new partnerships, splitting oil revenues with the private companies.
The new pacts that convert 32 privately run oil fields into 30 joint ventures are replacing old agreements that gave private companies a bigger share.
“Now we are associates and this commits us much more, it's a more solid framework, it's no longer a contract for doing a service, it's a strategic alliance,” Chavez told representatives of the companies at the signing ceremony at the presidential palace.
“We all come out winning here, nobody is going to lose here,” said Chavez, adding that Venezuela would be “steering” the strategies of the new joint ventures.
Exxon Mobil Corp., the world's second-largest integrated oil company, and Italian oil and gas company Eni SpA did not sign the agreements.
Exxon avoided the new terms by selling its stake in the 15,000-barrel-a-day Quiamare-La Ceiba field in December to its partner, Repsol, while Eni was not permitted to participate in the joints ventures due to pending tax debts in Venezuela.
Spanish-Argentine Repsol YPF, Royal Dutch Shell PLC and China National Petroleum were among the 17 Venezuelan and foreign oil companies that agreed to the new legal framework.
Congress approved new oil-field guidelines on Thursday.
All of the companies involved in the joint ventures must sign individual contracts with PDVSA, which then must be approved by lawmakers.
The terms faced by the companies will include:
_PDVSA controlling the boards of the new joint ventures.
_A jump in income tax rates to 50 percent from 34 percent.
_A hike in royalties to 33.3 percent from 16.6 percent.
Participants also will see their potential drilling acreage slashed by almost two-thirds.
Nemesio Fernandez-Cuesta, Repsol's vice president of exploration and production, said before the signing ceremony that accepting the overhaul meant acknowledging Venezuela's right to control the joint ventures.
“We, the businesses here, are showing with our presence and our signature, adherence to national sovereignty,” Fernandez-Cuesta said.
Venezuela is putting the squeeze on major oil companies at a time when rising oil prices, political instability in the Mideast and Nigeria and new buyers in Asia have put the world's fifth-largest oil exporter in a strong negotiating position.
“Today is a historic day because the 'oil opening,' which was the way toward privatizing Petroleos de Venezuela, will become part of history,” Chavez said earlier Friday. “Petroleos de Venezuela will never be privatized.”
The 32 affected oil fields currently pump about 460,000 barrels of oil a day. Venezuela estimates its total production at more than 3 million barrels a day, although industry analysts estimate the figure is lower.
The state oil company announced the contract overhaul last year, saying past governments granted giveaway contracts to private companies.
After signing the agreements Friday, private oil companies are expected to negotiate the details of individual contracts before the contracts are sent to the National Assembly for approval.
The U.S. remains the top buyer of Venezuelan oil. But Chavez, a fierce critic of Washington, is seeking new markets for oil in places from the Caribbean to China.
“We want to share it with the world, but don't tread on us,” Chavez said. “We are going to share. There is oil there for 100 years and more.”
Copyright 2006 Associated Press read more

By CELIA W. DUGGER
Published: April 1, 2006
“Ajay, please come up here!” said Bill Clinton, summoning a Citigroup executive, Ajay Banga, to the stage. There, before a full house of corporate chieftains, millionaire investors, nonprofit leaders and assorted more ordinary people, the former president slipped comfortably yesterday into his new role as an impresario of philanthropy.
It was Mr. Banga's turn to bask in the glow of Mr. Clinton's approval. Under the auspices of Mr. Clinton's “global initiative,” Citigroup has committed $5.5 million to support financial education for poor people and awards that recognize individuals who create innovative programs to finance very small businesses.
“Mr. President, keep going!” Mr. Banga told Mr. Clinton, and assured him of Citigroup's support. “Three hundred thousand employees are behind you.”
The gathering at Jazz at Lincoln Center on Columbus Circle in Manhattan represented six months since Mr. Clinton invented one of the most high-profile ventures of his post-presidency, the Clinton Global Initiative. It brings together people with money, influence and ideas to talk about global poverty, climate change and religious and ethnic conflict.
What sets it apart from other such high-minded conferences is Mr. Clinton's insistence that participants not just discuss these daunting problems but also do something concrete about them — or not be invited back. A staff of four works full-time on “commitments management.”
Since the program began with a conference in September, almost 300 corporations, individuals and nonprofit groups have committed more than $2.5 billion to an array of good works, his staff says. Some projects would have happened anyway, but Mr. Clinton estimates that more than half are genuinely new.
“More and more people were saying to me all the time: 'What can I do? What can I do? Tell me something to do,' ” Mr. Clinton said in an interview. “I just heard it all the time. So here we are in New York. The United Nations meets here. We can bring together all kinds of people from all over the world. So I just decided to organize a 'What can I do?' conference. And then try to do it every year for a decade.”
A parade of people gave testimonials from microphones in the audience about what they had done since they made their commitments in September.
Dr. Bruce Charish, a Manhattan cardiologist, founded a new nonprofit group, Doc to Dock, to send medical tools and supplies to hospitals and clinics in Africa. “Just the prestige of being a C.G.I. commitment has opened many corporate doors,” he said.
Maria Otero, who heads Acción, described how her nonprofit group and another, Unitus, have taken steps to fulfill their promise to provide small loans and other financial service to millions of poor people in India by 2015. “I want to thank you for galvanizing us to do this work,” she told Mr. Clinton.
Nancy Kete, the director of Embarq, founded with a grant from the Shell Foundation, is working with Porto Alegre, Brazil, to develop mass transit powered by low-polluting buses. “If you care about climate change, you have to care about transportation,” she said.
A row of black Mercedeses and Lincolns lined up on West 60th Street as guests arrived yesterday for a breakfast with Mr. Clinton at Dizzy's Club that felt more like a cocktail party, albeit one where only orange juice and coffee were served. A duo played jazz on saxophone and piano, and Mr. Clinton embraced his daughter, Chelsea.
With sweeping views of Central Park, 100 or so people milled about. They were a reflection of Mr. Clinton's vast network. There was Mike Rienzi, an Italian food importer from Astoria, who said Mr. Clinton came to a recent fund-raiser he held for research into deafness, and stayed all evening. Yesterday was his first time at a Clinton Global Initiative event, and he said he had not made any commitment yet. But he added, “Whatever the Clintons do, I support them.”
Across the room Bernard Schwartz, chairman of Loral Space and Communications, and Lewis Cullman, 87, a philanthropist, chatted. Both had come to the September meeting and neither had yet picked a project to finance. “I'm ready to do so,” Mr. Schwartz said. “I'm sure having said so, I'll get a lot of knocks on my door, and they'll be welcome.”
Soon the breakfast guests merged with the 500 people who had come for the main event, an updating on the program's progress. Ami Nahshon, who heads the Abraham Fund Initiatives, a nonprofit group that promotes coexistence between Israel's Jewish and Arab citizens, hopes to find patrons to encourage business development in Arab communities. He seemed very pleased to be at the event. “It feels a bit like philanthropic speed dating,” he said.
Mr. Clinton himself chose a retailing metaphor.
“Maybe the model is eBay,” he said. “It brings buyers and sellers together. Maybe we can create a massive, floating and flexible partnership where people who want to give some money and people who want to provide services or programs and people who need economic and social support will be together in an ongoing dialogue.”
“That would be my dream,” he said, “that we could turn the concern of people who are well educated and have good incomes or represent foundations or businesses into action.” read more

PRIGORODNOYE, Russia–Despite delays and mushrooming costs, investors are confident that the Sakhalin II energy project in the Russian Far East will succeed because of a global shift to liquefied natural gas from crude oil.
Apr 01, 2006
The costs are now estimated at $20 billion (about 2.3 trillion yen), almost double the initial projection, due mainly to surging prices of construction materials and environment protection measures
In February, some 6,000 people from about 20 countries were working on construction of a natural gas liquefaction plant, one of the largest in the world, on a 520-hectare site in Prigorodnoye on the southern coast of Sakhalin island
Natural gas taken from two fields off the northeastern shore of the island will be transported through an 800-kilometer pipeline to Prigorodnoye, where it will be liquefied and shipped to Japan, South Korea and the United States
Shipment will start sometime between November 2007 and summer of 2008. Crude oil production began in 1999
The port of Prigorodnoye is not completely frozen during winter, enabling use of tankers with reinforced hulls. However, the temperature sometimes drops to minus 30 degrees, and ice floes halt work on offshore piers and other facilities
An official of project operator Sakhalin Energy Investment Co. said that because of Sakhalin's harsh environment the project will take 51 months to complete, compared with 36 months for a similar-size plant under normal conditions
More than 60 percent of the project has been completed, according to Sakhalin Energy. Completion rates for the LNG plant and the pipeline are 66 percent and 53 percent, respectively
In an environmental protection effort, a major cause of delays, Sakhalin Energy decided to reroute the pipeline to bypass the habitat of endangered western gray whales. Environmentalists are also watching the project for possible impact on Steller's sea eagles and other creatures
Winter's cold isn't the only weather obstacle. The pipeline sometimes runs under riverbeds, but installation has to be suspended between May and November to protect salmon and trout, which go upstream for spawning
A source close to the project said the operator had been too optimistic about the problems with Sakhalin's natural environment
Three shareholders in Sakhalin Energy–Royal Dutch/Shell Group, Mitsui & Co. and Mitsubishi Corp.–will be hit with huge cost overruns
Shell, which holds the largest 55-percent stake, plans to transfer some of the shares to Russian natural gas supplier Gazprom by swapping them for part of the latter's share in a gas field in western Siberia
The two Japanese trading houses expect participation by the Russian state-owned company to accelerate the project, although they will also have to relinquish part of their stakes
There have been suggestions in Russia of an alliance with the Sakhalin I gas and oil project led by Exxon Mobil Corp. of the United States, Itochu Corp., Marubeni Corp., Japan Petroleum Exploration Co. and others.
Under the project, natural gas will be delivered to Japan and China through undersea pipelines. However, the project has stalled because of compensation to the fishery industry and other problems
If the alliance is formed, natural gas from the Sakhalin I project will be liquefied at the Sakhalin II plant for delivery by tankers
However, many observers say the possibility is remote. “As two majors, pride will not allow Exxon and Shell to tie up,” a source said
Despite adversities, Sakhalin Energy is considering expansion
The plant under construction in Prigorodnoye, which consists of two production units, will have an annual capacity of 9.6 million tons of LNG. Retrofitting is expected to increase the capacity by more than 20 percent
Sakhalin Energy President Ian Craig has a more ambitious vision. He said the company is considering adding another unit in 2013, saying that the required land has been purchased
Behind his confidence is the geographical advantage of Sakhalin. It takes only two to three days by ship from Sakhalin to Japan, compared with about two weeks from the Middle East
A large number of expensive LNG tankers will be needed for delivery from distant producers. A ton of LNG from Sakhalin is expected to be $10 cheaper than that from the Middle East
The island, which has estimated natural gas reserves of about 500 billion cubic meters, might serve as a stable energy supplier to Japan as the North Sea is to Britain
Almost all annual gas output from the Sakhalin II project has found purchasers, including Japanese electric power and gas companies and a South Korean public gas company.
Copyright 2006. Asahi Shimbun read more

TEMPUS
By Peter Klinger
IT WAS a busy end of March for Britain’s independent oil and gas companies, with most of the big guns reporting full-year results. The profits showed a massive gain on 2004, not surprising given the spike in oil prices over the past two years. Even a mug with a solitary barrel of oil would have improved his worth, and companies with a prudent growth strategy fared as well as the market had expected; Tullow Oil’s profit soared 261 per cent, Burren Energy was up 196 per and Dana Petroleum gained 232 per cent.
The independents will never challenge BP or Royal Dutch Shell for FTSE 100 domination, but that is not to say that the likes of Premier Oil and Tullow cannot produce barrel-loads of oil and — most importantly — growth opportunities for canny investors.
Yet with production levels hovering below 100,000 barrels of oil and gas-equivalent a day (Shell’s output last year was 3.5 million bpd) and market values of less than £3 billion (BP’s is £136 billion), the independents attract a different breed of investors.
Whereas it is virtually impossible for Shell to double its daily production profile within the next four years, or even come close, Premier Oil wants to boost its output from 33,300 bpd last year to just over 60,000 bpd by 2010. It is an ambitious target for Simon Lockett, Premier’s chief executive, but possible. These realisable goals and resultant profit boosts make the independents, as a sector, a potentially lucrative investment proposition.
Over the past two years, the FTSE 350 oil and gas index has easily outperformed the FTSE all-share index, driven by a rampant oil price. Even more impressively the oil and gas sector’s outperformance was greater when excluding BP and Royal Dutch Shell, whose weightings dictate the sector’s overall performance. In other words, whereas BP and Royal Dutch Shell shareholders enjoyed a stellar two-year period, investors in the independents had even more reasons to cheer.
The independents offer a far greater leverage to changes in the oil price. They are also far more exposed to outcomes of drilling programmes that can determine a company’s prospects — both on the upside, if results are favourable, and the downside, if a well is dry. BP does not have to report updates on each well that it participates in. Burren, however, does, and it felt the brunt of market disappointment this week when it said that an outer well at the M’Boundi oilfield in Congo-Brazzaville, one of its key assets, was dry. It contributed towards Burren downgrading the oil-in-place estimates for M’Boundi from 1.6 billion barrels to 1.4 billion barrels.
Premier, often seen as an unlucky explorer, is trying hard to alter its image and yesterday said that its Lembu Peteng-1 well in Indonesia had flowed at a modest 610 bpd. Lembu Peteng alone will not propel Mr Lockett to his target, but every barrel helps. Premier’s key exploration wells, in Vietnam and Guinea-Bissau, are due to be drilled this year and have potential to be company-defining. No one doubts the potential, but everyone understands the risks and costs associated with drilling — dry wells will be punished by investors.
The independents have no shortage of cash to invest in exploring and developing assets. Tullow, the biggest of the independents, wants to boost its production from 58,450 bpd last year to 80,000 bpd by next year. It has set aside £280 million for capital expenditure this year and also has not ruled out further acquisitions. With oil prices forecast to remain well above $40 a barrel in the medium term, acquisitions even in this highly priced environment can make sense.
A year ago, Roy Franklin, Paladin Resources’ chief executive, said that his company would boost production from 41,000 bpd in 2004 to 100,000 bpd by 2008. The only way that he would fail, he said, was if Paladin was taken over. Whether Mr Franklin was marketing Paladin for sale or not is open to debate, but seven months later Talisman Energy swooped with a £1.2 billion bid.
Analysts at Morgan Stanley argued this week that mergers involving Europe’s biggest oil and gas groups should be on the agenda. They cite the problems that the majors have in replacing the oil and gas that they produce, as well as relatively low valuations, as the triggers. The market’s herd mentality means that once one deal is announced, others will follow, as observers of Britain’s telecoms or ports sectors will know. The independents will not be immune from corporate activity should their larger peers start the consolidation process.
Takeover activity cannot be guaranteed, and only a carefree investor — or an insider trader — would blindly back a company on that basis. There are two likely scenarios: the independents will need to acquire assets to meet or exceed production targets, thereby triggering corporate activity, or they will successfully explore and develop on their own, and thus become the target of bigger players. A third scenario is for the company, and its share price, to fall from grace because of management or operational failures. That is why Regal Petroleum and BowLeven should be avoided. For many of the other independents, the future looks bright — but handle with care. Overzealous support of high-risk exploration programmes can result in the biggest rewards, but also the largest losses. read more