Posts from ‘April, 2006’

New oil shock ahead as $100 spike looms

Oliver Morgan and Heather Stewart
Sunday April 30, 2006
The Observer

Experts: Natural Gas Economy Losing Steam

Drivers, of course, can respond immediately to high prices by traveling less. It's harder for people to turn down their natural-gas heat. ''As soon as companies that control the resource figure out how to keep prices high, they'll do it, and I believe that's what were seeing in gas,'' says Ezra Hausman, analyst for Synapse Energy Economics in Cambridge, Mass.

Some Midwestern cities are accusing producers of doing it by collusion. In an antitrust lawsuit, they suggest that producers have reached either a secret agreement or tacit understanding to bottle up production.

''I think the increase in prices is a designed thing,'' says Charles Wheatley, a lawyer for the 18 communities from Texas to Indiana suing five leading gas producers in federal court.

They haven't found a smoking gun proving that. Yet, in Associated Press interviews, some industry executives acknowledge that, during their 1999 sessions, members of the Petroleum Council talked privately of a supply and price crunch in the near future — purportedly as a result of external factors.

Why, then, didn't they warn people? Former council leaders indicated that they wanted to keep pressure on demand. ''We needed to give comfort to our customers that gas was going to be available,'' says Joe Foster, a retired gas executive who was council chairman in 1999.

Shackouls, his successor, puts it this way: ''We were doing it to grease our own wheels.''

In the end, the council issued its reassuring report, and demand stayed strong.

On the other hand, industry leaders insist that collusion to sit on supplies cannot happen. After all, the five leading producers supply less than a fifth of domestic natural gas. So if they were to charge unjustifiable prices, smaller ones could undersell them, right?

Maybe not, if producers are more unified than they seem. Many small producers own rights, not rigs. They take a back seat to bigger companies that actually do the drilling under joint ventures, shared leases and royalty agreements.

Former federal energy regulator John Wilson estimates that the five producers named in the antitrust lawsuit can influence most domestic output through such arrangements, without changing their official production figures.

''Prices have stayed up because people in control of supply decided they could keep them up,'' says Wilson, who has supported the lawsuit with his analysis.

''That's not how we operate,'' answers Bob Davis, a spokesman for lead defendant Exxon Mobil Corp. ''This concept … is simply ridiculous.''

And ridiculous it would have been a generation ago, when government regulators set prices across the whole marketplace.

Since the 1990s, the marketplace itself has increasingly set producer and pipeline prices under pressure from new hordes of traders, many betting on the future prices of natural gas. In theory, traders would enable better deals through the magic wand of competition. And the theory seemed sound in the first years of market pricing, when supplies were robust.

During the production-pricing bind, though, something else appears to have happened. Conditioned by an irrepressible string of price increases, futures traders — who contract for future gas deliveries at fixed prices — tend to settle at even higher fixed prices, many analysts believe. Since the market uses these fixed prices as a reference point for its day-to-day prices, overestimates by traders can turn into self-fullfilling prophesies.

''One thing that's out there that I think is a bit of a negative is: Traders love volatility,'' says Reliant Energy's Langdon, who once worked for a predecessor to disgraced energy trader Enron.

Middleman traders — also children of deregulation — now sell much of the gas, taking their cut without producing or transporting it. They were supposed to bring better deals to buyers, but not everyone's so sure they do — even setting aside outright market manipulations blamed on traders like Enron in recent years.

''I sometimes wonder if these are the prices that would really be arrived at, if the user of the gas was dealing with the producer of the gas,'' muses Foster, the former Petroleum Council chairman.

Others harbor deeper doubts. Is real competition possible, they wonder, for a product that buyers absolutely need? They're not like shoppers, after all, who can simply shift to a cheaper product on the store shelf — maybe apples instead of peaches.

''I think it is very difficult, if not impossible, to foster truly competitive markets when you're dealing with energy,'' says Tyson Slocum, a consumer advocate at Public Citizen.

At six-years-and-counting, you might think supply has to expand to meet demand before long. Yet there's little sign of it yet. The industry's supply group warns of more upward pull on prices.

Even the administration of President Bush, a former oilman, hasn't come close to opening enough federal land to drilling and stripping away enough bureaucracy from permits, the industry complains. ''Our natural gas supply problems are man-made by legislation and red tape,'' groused chairman Larry Nichols of producer Devon Energy in March.

Optimists point to projections of multiplying imports of frozen liquid gas, which is warmed back to its original state in this country. However, those predictions may also veer off target.

Terminals to liquefy and regasify don't come cheaply, and investors shy away without assurance of safe supplies well into the future. Terminals typically run into a tsunami of domestic opposition, with the huge tankers and storage tanks feared as targets for attack.

''We're much more in the public eye because of the ships, because of the concern about terrorism,'' says Frank Katulak, president of the Distrigas liquid gas operation outside Boston, which wants to build a new terminal offshore.

Even with more terminals, a global supply means a world market. The United States already competes for such gas with fuel-starved Europe and will increasingly confront demand from the hulking economy of China.

More buyers means more demand, which means higher prices. By then, these could seem like the good old days.

EDITOR'S NOTE — Jeff Donn often covers energy as the AP's Northeast regional writer, based in Boston.

Shell: Mars repairs ahead of schedule

The Gulf of Mexico’s largest producing oil platform knocked off-line by Hurricane Katrina could be running again in May, just before the start of this year’s hurricane season.

Shell Exploration & Production Co., a unit of Britain’s Royal Dutch Shell PLC, said April 20 repairs to its Mars platform will be finished in April, with partial production restored in late May. Hurricane season starts June 1.

The platform represents about 5 percent of the Gulf’s daily oil and gas production, which before the hurricane stood at 140,000 barrels of oil and 150 million cubic feet of gas a day.

Originally, Shell did not expect the platform to be producing until late 2006.

Marvin Odum, the company’s head of exploration and production for North and South America, said two factors put Shell ahead of schedule: immediate and accurate damage assessment and purchasing the right pipeline repair equipment before the hurricane hit in late August.

The quick assessment enabled Shell to lease one of just two barges available worldwide capable of moving a toppled rig structure to shore.

Below the surface, Shell was already working to remotely repair pipelines at depths reaching 2,700 feet with equipment it purchased when production began 10 years ago.

“Getting that barge and having everything else in stock, then being able to put them to use right away saved us many months of time,” Odum said.

Crew of 500 lived on ship

Additionally, Odum said assembling a work force that lived for weeks at a time on an adjacent ship was crucial. The crew of 500 included engineers, geologists and technicians.

With oil prices above $70 a barrel, companies like Shell have every incentive to resume production as soon as possible.

“We expended every resource to get it done,” Odum said. “I generally don’t think people understand to what lengths we went to return all this production as quickly as possible.”

The company said its Katrina-related damages in the Gulf range between $250 million and $300 million.

Odum said Shell’s estimates placed the Mars platform in the hurricane’s eye for about four hours, absorbing 80-foot waves and wind gusts reaching 200 mph. The platform’s oil derrick blew away, and pipelines and the rig that repairs wells were damaged. But Odum said it could have been worse.

“The structure itself — the platform, the tendons, connections to Gulf — sustained no damage, so the platform did what it was designed to do,” he said. “There were no problems with the wells, not a drop of oil spilled and no gas was released, so that was encouraging to us.”

On April 19, the U.S. Minerals Management Service reported 87 production platforms still out of commission following hurricanes Katrina and Rita.

The Mars platform is located about 130 miles southeast of New Orleans. Shell operates the platform and has a 71.5 percent working interest. BP has the remaining working interest.

—Associated Press

Agrium to decide on coal project in July

Company is close to finishing first phase of feasibility study that’s likely to decide the fate of huge Nikiski fertilizer plant

Allen Baker

For Petroleum News

This coming summer will provide a crucial “litmus test” on whether Agrium Inc. and other potential investors pony up well north of a billion dollars to convert coal into feedstock for the Canadian company’s giant Alaska fertilizer plant.

That’s what Bill Boycott, general manager of Agrium Kenai nitrogen operations, told Alaska legislators April 19.

“If the opportunity is strong enough, it will be fundable,” Boycott told a Juneau hearing of the Senate Finance Committee. “And we will have the participants and the partners to move forward. Or it won’t, and we’ll continue our search for natural gas and likely watch our business prepare to wind down on the (Kenai) peninsula.”

If the Blue Sky Project gets the financial support of Agrium and potential partners, the Nikiski facility could be doubled in size. A gas feedstock derived mostly from Beluga coal shipped across Cook Inlet will completely replace natural gas that currently feeds the fertilizer plant, perhaps as early as 2011. The complex would export around 2 million tons of fertilizer to customers around the Pacific Rim.

Otherwise, the second-largest nitrogen fertilizer plant in the U.S., with a replacement cost estimated at $1.5 billion or more, will almost certainly close down.

Twin projects

Both Agrium and Usibelli Coal Mine Inc. have been working on their parts of the puzzle, which would tap the huge Beluga coal deposit across Cook Inlet from Nikiski for something like 4 million tons of coal a year. The coal would be shipped across the inlet in 12,000-ton barges, with a backup supply from Healy shipped south to Anchorage by rail, then loaded into barges there.

Once it reached Nikiski, the coal would be pulverized and then burned in a specialized gasification plant to produce a gas rich in hydrogen and carbon dioxide, explained Boycott and Agrium spokeswoman Lisa Parker.

The hydrogen from that process would be combined with nitrogen from an air separation facility to produce anhydrous ammonia. Adding some of the carbon dioxide to the ammonia would turn it into urea, another fertilizer product.

The purity of the feed gas would immediately boost capacity by roughly 20 percent compared with natural gas, he said.

Enhanced oil recovery

But not all of the carbon dioxide from the process would be used in the fertilizer operation, so Boycott has been talking up the potential for using the gas as an injectant for Cook Inlet’s aging undersea fields.

“We would have significant incremental CO2 available to support an enhanced oil recovery operation in the Cook Inlet,” he said. What he means by significant is an estimated 7,000 tons a day, even without recovering the carbon dioxide from the power plant needed to supply electricity for the complex.

The upshot could be extracting as much as 300 million additional barrels of crude oil from Cook Inlet fields, he said.

Dwindling gas

The natural gas from the Cook Inlet region that has been turned into fertilizers in Nikiski since 1968 is running out.

Almost since Agrium purchased the plant from Unocal in 2000, it’s been touch and go to find sufficient supplies of natural gas to keep the complex in operation. The plant has been running at only half of its capacity since November due to supply issues, and Boycott says that executives “don’t see a chance of restarting (full operations) with natural gas.”

The company only has enough committed gas to keep up at current rates until October. Agrium has asked for proposals for gas supplies after that, “trying to get an extension of the commercial life” of the facility, he said. But even if suppliers turn up for this next round, the crystal ball looks cloudy at best later in the decade.

So if the plant has a future, that future is almost certainly tied up with coal.

Huge power plant

Alaska’s power grid is just about as dependent on natural gas from the Cook Inlet region as Agrium itself, and that fact provides another piece of the economic puzzle the company is putting together.

The power plant needed to supply 90 megawatts needed for the industrial processes could also export significant amounts of electricity for other consumers in the region, according to Boycott, replacing some of the system’s aging gas-fired generators.

The power plant alone will cost $600 million to $700 million. “With Alaska’s 900 megawatt grid, that’s a difficult expenditure to support,” Boycott notes. It would be a big stretch for Alaska’s electric cooperatives and the municipal utility in Anchorage.

“We believe with this project we have a foundation to establish the coal infrastructure (at Beluga), and also an immediate demand for 90 megawatts,” he said.

“We provide the foundation necessary and the economics to support a power plant that we really need in this state.”

With the limitations of the current power line to the major load in Anchorage, the Nikiski complex could export around 60 megawatts, according to Boycott, with a potential to reach 130 to 180 megawatts if an upgraded line were added to take more power to the north.

$28 million next step

Boycott said he was headed for Kansas City after the Juneau hearing to talk with engineers from Black & Veatch Corp. and Uhde GmbH about design issues. Those companies formed an alliance in 2004 to work on coal gasification using Shell’s coal gasification technology. Heat material balances will be done by Shell.

It’s all part of the $4 million being spent on the initial phase of the feasibility studies. Most of that work should be finished in the next couple of weeks.

“We will know at the completion of that work whether we should move forward,” Boycott told the lawmakers. The second phase will be a lot more expensive, at $28 million, and “what we’re saying is that we would fund phase 2 by July or we would …” He hesitated before adding; “That’s really a litmus test for us.”

“Assume the answer is yes,” he continued. “What we would like to do is create a bankable commercial deal.

“And when I say bankable, what I’m talking about is firm contracts for the supply of coal, for the offtake of the fertilizer, for the offtake of the power. And then a lump sum turnkey engineering contract with a process performance guarantee, so that we’ve really done our best to manage the risk.” The design of the engineering contract would take up an estimated $13 million of the phase two cost.

All that would create a blueprint “that we can then take to Wall Street and finance. And that’s really how we’re looking to finance it.”

Even Agrium, a power in the fertilizer industry with $4 billion in sales and $283 million in profits last year, doesn’t have the heft to do the deal alone. If the project goes ahead, the cost will be second only to the trans-Alaska oil pipeline among Alaska’s commercial projects.

Government partnering

For the phase two work, Agrium is looking for partners, and also for a bit of a lift from Uncle Sam and Uncle Sourdough.

The company has been talking with U.S. Sens. Ted Stevens and Lisa Murkowski about a federal contribution, Boycott said, and Agrium wants the state to put in a chunk as well.

“We are looking to both the federal government and state government for some level of support at that level,” he said. “We’re looking at $5 million in phase 2 funding (from the two governments.”

Beyond that, Boycott said, the company might be able to take advantage of some federal tax credits to encourage new energy technology. Some grant funds were included in the recent energy package approved by Congress and President George Bush, but those grant funds are very limited and Agrium won’t be trying to tap that source, he said.

BP sells Gulf of Mexico shelf properties

Apache buys BP’s last producing GOM continental shelf properties; $1.3B purchase second it has made from British giant

Ray Tyson

For Petroleum News

BP says it decided to sell the last of its producing properties on the Gulf of Mexico’s continental shelf because they no longer muster up to BP’s investment standards, not because of an increasing threat of hurricanes, which is said to be causing some producers to rethink their future on the shelf following last year’s devastating storms.

“Over time, they (shelf properties) have become less and less competitive for continued investment in BP’s global portfolio,” BP spokesman Ronnie Chappell told Petroleum News April 24.

E&P independent Apache, a master at squeezing new production from old fields, announced April 19 that it agreed to purchase BP’s remaining shelf properties for $1.3 billion. In 2003, Apache acquired mature BP properties in the Gulf and North Sea for the same $1.3 billion price, as well as $200 million worth of aging self assets from Shell.

The recent deal with BP includes 18 producing fields (11 of which are operated) covering 92 blocks with estimated proved reserves of 27 million barrels of liquid hydrocarbons and 185 billion cubic feet of natural gas. Apache said it identified 50 drilling locations on the properties and an additional 4 million barrels of liquids and 26 bcf of natural gas in probable and possible reserves.

Some of the fields are subject to exercise of preferential rights to purchase by other interest owners, which could take up to two months to resolve, Apache stressed.

Nonetheless, “nearly half of the reserves in the transaction are in properties in which we already own an interest, including the Grand Isle 40s/West Delta complex — one of the largest fields ever discovered in the Gulf,” said Steve Farris, Apache’s president and chief executive officer.

Apache said that from April through year-end 2006, the acquired BP assets are expected to provide average daily production of 7,100 barrels of oil, 1,500 barrels of natural gas liquids and 108 million cubic feet of natural gas, and generate $320 million in operating cash flow. Apache is currently the second largest producer on the shelf.

Despite selling all if its producing assets on the shelf, BP remains a major player in deepwater Gulf of Mexico, as well as an active participant in the relatively shallow waters of the shelf, where BP is pursuing high-risk, high reward “deep-gas” and “ultra-deep” exploration opportunities.

Apache addresses hurricane threat

Apache, whose shelf infrastructure was severely thrashed last year by hurricanes Katrina and Rita, went to great lengths in justifying its second acquisition of BP properties in the Gulf of Mexico. In addition to the standard press release, Apache issued a separate “White Paper” on the subject, and held a conference call to brief investors on the pending deal with BP.

“The exposure of oil and gas companies to the risks of operating in shallow waters of the outer continental shelf of the Gulf of Mexico has come under increasing scrutiny in the wake of … Katrina and Rita,” Apache acknowledged in its White Paper.

Apache added that because of rapid natural production declines on the shelf and hurricane-related disruptions, “conventional wisdom has suggested that the shallow Gulf is dead as a viable oil and gas province and that it’s time for current and … prudent operators to consider reducing their exposure and reallocating their assets. Some, analyzing the risk and reward of the shelf in their portfolios, already have begun to do so.”

Apache was down around 23,000 barrels of oil per day at year-end 2005 because of hurricane damage, representing a little over 30 percent of the company’s pre-storm production of 75,000 barrels per day. Apache also expected to be down around 20,000 barrels per day for the remainder of 2006.

Moreover, roughly 11,000 barrels per day of BP’s shelf production remained shut-in at the time of Apache’s latest announcement, according to BP transaction statistics compiled by Apache. In fact, more than 20 percent of all Gulf production affected by last year’s storms was expected to be shut-in going into this year’s hurricane season.

Investors like deal

Still, investors liked the latest BP-Apache deal. On April 19, the day of the announcement, Apache’s stock rose as high as $73.90 per share before closing that day at $73.73, a gain of 5.1 percent over the prior day’s close of $70.13. A week later Apache’s stock was trading at more than $73 per share.

BP’s Chappell said that the increasing threat of hurricanes in the Gulf played no role in the company’s decision to sell its shelf assets, reiterating that “we recognized it would be very difficult for these properties to successfully compete for investment dollars within BP.”

Apache publicly thanked BP for cleaning up its hurricane mess before deciding to sell the last of its producing shelf properties. “BP has won Apache’s admiration in the very responsible way they have handled their exit … and at a substantial cost, because it was the right thing to do,” Apache’s Farris said in a written statement.

Apache, in language obviously designed to usurp the hurricane threat and justify its latest shelf acquisition, said the recent deal is not only an excellent fit for BP, but for Apache as well, and that prior shelf acquisitions have resulted in big profits for the company.

Farris said that by year-end 2005, Apache had recovered its original shelf investment, paid for additional capital incurred and generated in excess of $1 billion of free cash, with proved remaining reserves from the properties of 270 million barrels of oil equivalent.

Apache: not all eggs in one basket

Over the years, Apache has drilled more than 350 wells on its $2.7 billion in acquired shelf properties and reinvested in the Gulf more than $2.3 billion of the $6.2 billion of cash flow generated from company operations, Farris said.

“The shelf provides some the best margins, highest returns and most free cash flow of any region in Apache’s worldwide portfolio,” he added. “By extending the lives of these fields, Apache is doing its small part to help meet rising global demand for oil and gas.”

However, Apache was quick to note that aside from its profitable shelf investment, the company does not put all its eggs in one basket. Apache said that after its latest deal with BP closes, the shelf would represent just 21 percent of Apache’s worldwide production, up from 18 percent pre-deal, and 15 percent of the company’s worldwide reserves, up from 14 percent pre-deal.

Apache also said that once the transaction closes, overall company debt is expected to be below 23 percent of total Apache capitalization, indeed an enviable debt-to-cap ratio for any E&P company.

Apache said it would purchase BP’s remaining producing shelf properties through the issuance of commercial paper, adding that the deal should close by the end of this year’s second quarter.

Alberta aboriginals and Shell team up

Gary Park

For Petroleum News

From a whirlwind of events in the Alberta oil sands there was a ground-breaking deal between Shell Canada and a northern Alberta aboriginal community to jointly develop leases.

The pact significantly advances plans by the Fort McKay First Nation to enter the commercial oil sands world in a way that could spell untold riches for its 500 residents.

A complex exchange of options and a possible land swap culminates a decade of talks involving 8,200 acres and a possible 500 million barrels of recoverable bitumen worth US$35 billion at today’s prices.

The Fort McKay Group of Companies, which is already a major supplier of services in the oil sands region valued at about C$100 million a year, is now planning to add a private company to the stable.

Fort McKay Chief Jim Boucher said that depending on how much of the project his community is prepared to shoulder, the company could be delivering production to Shell Canada’s nearby Athabasca project by 2012 or possibly earlier.

Those volumes would become part of Shell’s long-range objective of raising Athabasca output from 155,000 barrels per day to 500,000 bpd.

The transaction involves Shell’s Lease 90, which the company obtained rights to from the Alberta government before title was transferred to the first nation as part of a comprehensive land claim settlement with the Canadian government.

Fort McKay has the option of acquiring Lease 90 at a pre-determined price per hectare, in return for which Shell, under a lease swap arrangement, has the right to lease other adjacent Fort McKay lands.

Preliminary engineering work planned

The partners have agreed to conduct preliminary engineering work through SNC Lavalin to determine the extent of Fort McKay participation once the scope of a commercial venture has been determined.

Boucher said his community is conscious of the impact development could have on Fort McKay’s land and its traditional way of life, but the deal also gives the residents an opportunity to “participate fully and build a long-term economic vision.”

He said an anti-fur lobby in the 1980s virtually wiped out the economic viability of aboriginal communities in the region and most are still having difficulty finding alternative sources of income.

Breaking into the oil sands sector will give Fort McKay a chance to control its economic destiny, Boucher said.

He said that if there were no integration of Fort McKay leases with Shell Canada’s operation, the first nation would still have an opportunity to develop expertise that could eventually be applied to the leases.

It could also let Shell Canada take full charge of the development and pay Fort McKay royalties.

Shell Canada Chief Executive Officer Clive Mather said that although there is more work to be done, the agreement “has the potential to return real value to both Shell and Fort McKay for many years to come.”

All for one, one for all

Mackenzie explorers want gathering and main pipelines under one regulator

Gary Park

For Petroleum News

The pace of future natural gas development in the Mackenzie Delta-Beaufort Sea region may hang on whether Canada’s National Energy Board agrees in June to assume jurisdiction of both the gathering system and main line, submissions to the board have warned.

Having already missed a deadline to contract for firm capacity on the two systems, six members of the Mackenzie Explorer Group have told the federal regulator there is an “urgent need” to resolve an impasse in negotiations with Imperial Oil, the lead partner in the Mackenzie Gas Project.

In a motion filed in April, the MEG members — Anadarko Canada, BP Canada Energy, Chevron Canada, Devon Canada, EnCana and Nytis Exploration — want the National Energy Board to issue an order to establish a “single” pipeline that would fall under the board’s jurisdiction.

The MGP proposal is currently structured so that the main line would be regulated by the board, while the gathering system (a 115-mile network to deliver gas and gas liquids to Inuvik, where they would be separated for delivery to southern markets, and a 280-mile liquids pipeline to Norman Wells) would fall under the Canadian Oil and Gas Operation Act.

MEG: concerns over tariffs, access

MEG said in its filing that uncertainty surrounding the question of whether the board will regulate tolls and tariffs on the gathering system have made it “commercially impossible” for its companies to sign the contractual commitments required by Imperial.

MEG has also expressed concern about whether the terms and conditions under which Imperial is offering access to the gathering system and the prospects of expanding the gathering system under its current design are fair and reasonable.

The group said its members and “other prospective shippers” have rejected Imperial’s ultimatum, including a Feb. 15 deadline for producers to sign contracts, regardless of the consequences.

Imperial has until May 5 to respond to the MEG filing and until then is not discussing the contents of its submission.

However, Imperial has warned that the Feb. 15 deadline “reflects the latest possible date to modify the gathering system design to provide capacity of more than 1.075 (billion cubic feet per day) without compromising the proposed” 2011 project start-up date.

Devon Canada Vice President Michel Scott told Petroleum News MEG would “never rule out having a negotiated deal,” even with the dispute heading for a regulatory hearing.

But he emphasized that failure to make progress on the commercial negotiations with time running out meant that “going to the NEB was the only action we had left.”

Scott insisted MEG remains “very supportive” of MGP and views the filing of its motion “very much as business as usual.”

He said MEG is anxious not to cause any delays in the current rounds of public hearings.

Hearing scheduled June 2

The NEB has scheduled June 2 in Yellowknife to hear arguments from those who have filed submissions.

Scott said that whatever decision the regulator makes will be assessed at that time.

What the group wants is clarity on the regulatory framework to speed up future development of gas discoveries outside the three Mackenzie Delta anchor fields owned by Imperial, Shell Canada, ConocoPhillips Canada and ExxonMobil Canada, he said.

It also believes that if the Canadian government is going to put public money into the Mackenzie project “there should be benefits for the public,” Scott said.

The previous Liberal government said it was open to sharing some of the project “downside risks” by possibly accepting gas in lieu of royalties, guaranteeing gas in excess of that available from the anchor fields, offering a “profit-sensitive” royalty scheme or making federal investments in some of the project components — options that the new Conservative government is still pondering.

The current design capacity of the gathering system dedicates 830 million cubic feet per day from the anchor fields, leaving 245 million cubic feet per day for MEG members and other third-party producers. The mainline has an initial capacity of 1.4 billion cubic feet per day.

Gathering system could be bottleneck

But MEG said in its filing that Imperial appears to view the gathering system as one to serve the anchor fields, with only “limited extra capacity for non-owners on whatever terms (Imperial) may choose without regard for their requirements as resource developers in this new basin.”

In contract, MEG looks on the gathering system and main line as a chance to open the basin and offer an open-access transmission system, which require a “single” pipeline to be regulated under the NEB Act.

The MEG position has been endorsed by the Inuvialuit Regional Corp., whose overall job is to manage 5,000 square miles of the Western Arctic covered by a land claim settlement, and explorer Mosbacher Operating.

The Inuvialuit said the public interest requires that tolls charged for the gathering system be “just and reasonable” without any unjust discrimination in charges, provision of access to the pipelines or related services.

The aboriginal corporation is anxious to see an “orderly development and production of the full resource potential of the region.”

Unless MEG members gain access to the gathering system there could be a proliferation of pipelines in a sensitive environment, it has suggested.

However, there has been a split in MEG ranks, with Apache Canada asking the NEB to reject the group’s motion.

As a potential shipper on the Mackenzie gas and gas liquids pipelines and a potential owner and operator of the gathering and processing facilities, Apache said it is directly affected by the orders requested.

Apache said it has a 50 percent working interest with Paramount Resources on about 430,000 acres in the Colville Lake area of the Northwest Territories that could require spending up to C$650 million to build facilities to interconnect with the pipeline.

Setting the stage for Arctic offshore oil, gas exploration

Alan Bailey

Petroleum News

With oil prices at record levels and companies champing at the bit to find more oil reserves, plans to shoot seismic offshore Alaska’s Arctic are picking up speed. Shell, ConocoPhillips and Houston-based GX Technology Corp. all plan to shoot seismic this summer in the Chukchi Sea, ahead of a Chukchi lease sale planned for 2007 by the U.S. Minerals Management Service. And Shell also plans to shoot seismic on leases it purchased in MMS’ 2005 Beaufort Sea lease sale.

But this mushrooming activity has North Slope Native communities worrying about potential impacts on subsistence hunting and traditional Native life. The communities depend on hunting bowhead whales and other marine mammals, both as a source of food and as part of a cultural tradition. Noise from industrial activities could disturb the wildlife and disrupt hunting, Native leaders say.

The various issues surrounding offshore oil and gas development came to the forefront at the National Marine Fisheries Service’s annual Arctic Open Water Peer Review Meeting, held from April 18 to 21 in Anchorage, Alaska. Companies wanting to shoot seismic in U.S. waters have to obtain what is known as an incidental harassment authorization (or IHA) from NMFS — the open water meeting provided the public with an opportunity to comment on the IHA applications before the applications are finalized.

And comments came aplenty.

Conflict avoidance agreement signed

People need to consider the cultural and human impacts of offshore development, Edward Itta, mayor of the North Slope Borough, told the meeting attendees. Itta said that the North Slope Borough is adamantly opposed to offshore oil and gas developments in the Arctic. He expressed particular concern about the potential impact of an offshore oil spill and said that no one has demonstrated technologies for cleaning up an oil spill in Arctic waters.

“We need you to understand that you cannot separate the ocean from us. … we are tied in intricately,” Itta said.

Itta is also concerned about rushing into offshore development without adequate information about the potential impacts, especially in the Chukchi Sea.

“Too much, too soon, too fast,” Itta said.

But Itta also recognized the realities of what is happening.

“We are also realistic enough to know that we can’t ever go back and we want to work with you, and we want some definitive project that is going to answer the concerns,” he said.

A core issue that emerged during the discussions in the Anchorage meeting was the need for a conflict avoidance agreement for the summer industrial program, signed off both by industry and the North Slope whaling captains’ associations. Negotiations prior to the meeting had already resulted in a draft agreement, but some issues remained to be resolved.

Ken Hollingshead, the meeting facilitator from NMFS, pointed out that the lack of a conflict avoidance agreement would require NMFS to start a further investigation before it could issue any IHAs for the seismic work.

“We strongly urge a conflict avoidance agreement to be signed,” Hollingshead said.

On April 24 Hollingshead got his wish. The whaling captains’ associations of the North Slope communities of Kaktovik, Nuiqsut, Barrow, Wainwright and Point Hope signed a conflict avoidance agreement for the 2006 open water program.

Mark Kosiara, Shell’s health, safety and environment lead for Alaska, stressed his company’s commitment to conducting safe and environmentally responsible operations.

“We have a strong safety culture in Shell and we are committed to executing our operations in a way that is as safe to humans as feasibly possible,” Kosiara told the meeting attendees. “… We have a … strong culture on protecting the environment. We want to make sure our operations are cognizant of that here, in this very sensitive region.”

Kosiara commented on the company’s engagement with stakeholders on the North Slope.

“We want to make sure that we do everything we can to minimize our impacts on the subsistence whale hunts,” he said.

Kosiara said that Shell plans to mobilize on July 1 from Dutch Harbor in the Aleutian Islands, to carry out 3-D seismic surveys in the Chukchi Sea. The company has contracted WesternGeco to do the surveys using the M.V. Gilavar, with the M.V. Kilabuk as chase vessel. (According to Shell’s MMS permit application both the Gilavar and the Kilabuk are owned by an Azerbaijan company.)

Shell plans to move the vessels into the Beaufort Sea when sea ice conditions permit and in accordance with a timetable specified in a conflict avoidance agreement with subsistence whale hunters.

The company expects to eventually spend two to three seasons acquiring 3-D seismic data from all of its Beaufort Sea leases; exactly which areas it surveys in any particular season will depend on ice conditions.

“Sometime in mid-August through early October we would hope to collect 3-D seismic data in the Beaufort Sea,” Kosiara said. “… As … the ice starts to move in we’ll be moving back out to the Chukchi, where we hope to acquire some additional 3-D seismic data until the end of the season.”

Shell expects the seismic data acquisition in the Chukchi to continue until the end of October, Kosiara said.

Site clearing, well cellars

In parallel with the seismic operations, Shell is mobilizing another vessel, the Henry Christofferson, from the Canadian Beaufort to perform site clearing operations, identifying shallow water hazards in the Alaska Beaufort Sea, as part of Shell’s program to explore the company’s offshore leases. That operation should start in late July and might last until early October, depending on ice conditions, Kosiara said.

Also in parallel with the other operations, Shell is commissioning two Russian icebreakers to cross to Canada’s Beaufort to tow the Kulluk floating drilling barge to the Alaska Beaufort (see “Shell on fast forward” in the March 5 edition of Petroleum News). After all whaling activities have ceased, the Kulluk will prepare some mud-line “cellars” in preparation for the placement of wellhead equipment in 2007 at future well sites in Shell’s Beaufort leases, Kosiara said.

At the end of the open water season the Russian icebreakers will tow the Kulluk back to Canada. Shell has been unable to locate a safe mooring for the Kulluk in Alaska, Kosiara said.

ConocoPhillips shooting Chukchi only

In 2006 ConocoPhillips will only shoot offshore seismic in the Chukchi Sea but will not shoot in the Beaufort Sea, Bruce St. Pierre Jr., senior environmental coordinator for ConocoPhillips Alaska Inc., told the meeting attendees. St. Pierre also said that ConocoPhillips has been working with the Alaska Eskimo Whaling Commission and visiting North Slope villages, describing the company’s plans and seeking input.

“That’s an important component of how we work,” St. Pierre said.

ConocoPhillips has contracted with WesternGeco to use the M.V. Western Patriot for its Chukchi seismic. The seismic crew will mobilize from Dutch Harbor in early July. Surveying should start around July 15 and may continue into November, depending on the sea ice conditions.

“Our operations will be pretty much focused on the areas around the prospects drilled in the previous (Chukchi) wells,” St. Pierre said, adding that the company would also survey some other areas.

GX Technology shooting its own 2-D

GX Technology, a subsidiary of seismic company I/O and a newcomer to Alaska, also plans to shoot seismic in the Chukchi, Todd Jones, the company’s integrated seismic services program development manager, told the meeting attendees. GX Technology started out as a seismic data processing company but began doing seismic data acquisition about five years ago, Jones said.

Working on a scale of hundreds of miles across complete oil and gas margins the company gathers 2-D data from depths of 20,000 feet or more and then processes and licenses the data.

“We’re looking for basins. We’re looking for how the container was developed where all these sediments came in and were deposited onto,” Jones said.

And that’s the type of regional program that GX Technology proposes for the Chukchi Sea. According to the company’s MMS permit application the company also plans to collect magnetic data across the region.

“We’ve laid out a program from a geologically driven standpoint but then we impart what’s doable from an operational standpoint … we will not operate where there is ice,” Jones said. “… Our focused area is still in the central portion of those lease block areas — they are a primary target that we’re trying to collect data on for this year.”

The company will be using a large 2-D survey vessel, towing four single-gun arrays and a 4,500-meter streamer, Jones said. According to GX Technology’s MMS permit application the vessel is named the M.V. Discover and is owned by Shanghai Offshore Petroleum Geophysical.

Jones said that the seismic crew will mobilize at the beginning of July at Dutch Harbor and move out to open water to begin operations as early as possible in the season. Data acquisition in the Chukchi will continue until ice in the Beaufort Sea opens sufficiently for the vessel to cross to Canada’s Beaufort, to do a survey there. Later in the season the crew will return to the Chukchi to complete as much as possible of the Chukchi data acquisition.

Academics to do surveys, too

In addition to the industry seismic surveys, a team from the University of Texas and the U.S. Geological Survey plans to acquire seismic data in the northern Chukchi Sea and Arctic Ocean, using the U.S. Coast Guard icebreaker Healy during the summer season. This seismic program forms part of a scientific study of the composition of submarine plateaus and the structure of the Earth’s crust in the Arctic Ocean.

Other open water activities in 2006 will include barging operations by FEX and Pioneer Natural Resources, in support of their exploration and development activities.

Federal permits needed

All of the organizations planning to do seismic surveys in the open water season require permits from MMS and from NMFS.

MMS permitting requirements fit within that agency’s role in administering the operation of the National Environmental Policy Act (known as NEPA) on the U.S. outer continental shelf.

NEPA requires an environmental assessment of any activity that involves federal action or approval. If the environmental assessment determines that the activity is likely to have a significant environmental impact, an environmental impact statement, or EIS, is required.

The procedure for developing an EIS can take several years to complete. MMS has a set of science-based criteria for determining a significant environmental impact.

In general, MMS grants an offshore seismic survey what is known as a categorical exclusion from an environmental assessment. However, given the level of interest and planned activity in the Arctic offshore, the agency is preparing what it terms a “programmatic environmental assessment” (or PEA) for the complete 2006 program of seismic surveying in the Beaufort and Chukchi Seas. The agency has published the PEA in draft form for public review — the review period ends on May 8. The draft PEA and contact information for comments are available at www.mms.gov/alaska/ref/pea_be.htm.

“Anticipating an increase in seismic survey permitting activities in the Arctic Ocean in 2006, the Minerals Management Service decided to prepare the subject document (the PEA),” Wayne Crayton, MMS biologist and NEPA team coordinator, told the open water meeting attendees. “… The comments that we receive from it will be used by the Minerals Management Service to environmentally evaluate possible impacts associated with ramping geological and geophysical seismic surveys.”

MMS has also published on its web site permit applications from the companies wishing to do the seismic surveys. The public can comment on those applications, although there is no mandated comment period for seismic permits, Crayton said.

Crayton explained that a determination of a significant environmental impact in the PEA would trigger the need for an EIS for the complete seismic program. However, even were the whole program to require an EIS, an individual seismic survey might not in itself require an EIS. But, in any case, each seismic survey will require an individual environmental assessment, although that assessment will be very straightforward if the survey falls within the scope of the PEA.

Incidental harassment authorization

NMFS also has responsibilities under the terms of NEPA and is a cooperating agency in the development of the MMS PEA. NMFS will use the PEA to assist in its evaluation of the environmental impacts of the seismic program, Crayton said.

But the main focus for NMFS is the protection of marine wildlife under the terms of the Endangered Species Act and the Marine Mammals Protection Act. And it is the Marine Mammals Protection Act that spells out the need for an organization doing an offshore seismic survey to apply to NMFS for an incidental harassment authorization.

In issuing an incidental harassment authorization NMFS specifies criteria that will prevent what NMFS considers to be harassment to sea mammals.

As part of its criteria NMFS prohibits the shooting of seismic if there are whales within a zone where seismic noise levels exceed 180 decibels. The equivalent noise level for pinnipeds such as seals is 190 decibels (the MMS PEA quotes research indicating that the ambient noise level in the Arctic marine environment is in the range 63 to 133 decibels).

Monitoring and mitigation

To ensure compliance with MMS and NMFS permit stipulations and to avoid harassment of marine mammals each offshore seismic crew has to establish an exclusion zone around its seismic vessel. Within that zone the sound levels from the seismic air guns exceed the marine mammal harassment levels.

As the vessel moves through the water, the exclusion zone may approach marine mammals. In that case, the crew will power down the seismic operation. If an animal comes within the exclusion zone the seismic operation will shut down.

Two marine mammal observers on each vessel (including support vessels) must continuously monitor the ocean for animals, to initiate a power down or shut down, as necessary.

The observers also have to communicate with whaling crews and an industry-whaling communications center, to minimize impacts on subsistence hunting. Observers will include people from the North Slope communities, who can bring local knowledge and experience to the observation program.

Initially, the crews will use exclusion zone dimensions derived from computer models that use parameters such as the water depth to estimate sound levels propagated from the seismic air guns.

Given the uncertainties regarding the accuracy of the models, crews will add safety factors to the estimated exclusion zone dimensions. However, as a first step in surveying in a particular region each seismic crew must verify the zone dimensions by measuring the actual sound levels at various distances around the seismic vessel.

After completion of the sound level verification the crew will use the measured size of the exclusion zone, rather than the modeled size.

The marine mammal observers have to record their observations as part of the reporting process associated with the government permits. The observations also build on the accumulated data about the wildlife of the region and help in planning future offshore work programs.

Shell plans additional wildlife monitoring

Shell described some additional wildlife monitoring that it plans. The company will monitor marine mammal movements by the use of daily aerial surveys in the Beaufort Sea and by vessel-based surveys in the Chukchi Sea, Shell biology advisor Michael Macrander explained.

Shell also plans acoustic monitoring of animal sounds in the Beaufort Sea, he said.

“In the course of developing the monitoring plan there were several goals that we should look to achieve,” Macrander said. “… The first one is to meet the reporting requirements. … We also have to develop a monitoring program allows us to be protective of the (marine mammal) resources and the resource use. … The third goal is to contribute to advancing science.”

And Kosiara explained that Shell has also committed $1 million to a research program for deploying new seafloor acoustic recorders and developing new computer software for interpreting the data from the recorders.

Impact on subsistence hunting

But will all of these monitoring and mitigation measures satisfy the needs of the subsistence hunters from the North Slope communities?

The crucial issue for hunters is the potential for the industrial disturbance to deflect the summer whale migration route and, thus, force the hunt dangerously far offshore or even render the hunt impractical.

There was some debate at the meeting as to whether a 120-decibel sound level limit would be needed to prevent whale deflection. However, the conflict avoidance agreements between industry and the whalers are designed to ensure separation between the seismic activities and the whale hunts.

One of the major concerns that emerged from the discussions at the meeting was the need for much more scientific data about the Arctic offshore. People were especially concerned about the Chukchi Sea, where relatively little is known about the ocean biology. People also voiced concerns that data should be gathered as soon as possible — a lack of solid information leads to uncertainty and worry about the impacts of industrial activities. And comprehensive data would enable a better understanding of industry impacts for future planning.

Mayor Itta expressed his support for efforts by industry to work with North Slope communities to gather more data.

“These kinds of efforts allay my concerns,” Itta said. “I would truly support as much to get done this season as possible.”

“We’re going to do this,” responded Rick Fox, Shell’s asset manager for Alaska, “… It’s that simple.”

What if whales can’t be hunted?

There was also general agreement in the meeting that, although scientific data are very important, the traditional knowledge of the Native peoples is also critical to any assessment of the situation.

Gordon Brower of the North Slope Borough planning department said that in the past seismic activities have deflected whales and disrupted hunting.

“The whales are nowhere in sight and lo behold there is seismic activity being conducted,” he said.

And Harry Brower, chairman of the Alaska Eskimo Whaling Commission, expressed major concern at the high level of activity planned for the 2006 open water season — the whaling captains are saying that there may not be whales this fall, he said.

“That’s a concern that I need to share with you all,” Brower said. “… This is something that we have not seen before, having this much noise being propagated into the water.”

Would it be possible to reduce noise levels by consolidating the seismic activities into a single operation, some of the North Slope representatives at the meeting asked.

Maggie Ahmaogak, executive director of the Alaska Eskimo Whaling Commission, pointed out that a poor subsistence harvest would lead to food shortages in the North Slope communities.

“What is industry prepared to do if … all the animal resources … are not available to them to harvest?” she asked.

Agreements on monitoring and mitigation

The upshot of discussions around the concerns of people from the North Slope was a commitment by all of the companies engaged in offshore seismic data acquisition to implement a comprehensive monitoring program to gather data about the marine wildlife and the impact of the seismic work. An industry team will develop a monitoring plan that potentially includes sound monitoring from vessels and an array of passive sound monitors offshore the Chukchi and Beaufort Sea coasts.

Chandler Wilhelm, Shell’s manager for Alaska exploration, said that Shell will commit to a baseline environmental monitoring program.

“If we do not do this now we will not be able to answer the fundamental questions … when we are faced with other decisions later on,” Wilhelm said.

Wilhelm also said that Shell commits to explore appropriate ways in which to mitigate any adverse impacts of the seismic work on North Slope communities.

Wilhelm said that reducing the level of seismic activity presents greater difficulties than meeting the monitoring and mitigation concerns. However, he said that Shell would commit to a “small surgical program” in the Chukchi by limiting the total area of the survey to 2 percent of the lease sale area. Shell is also working with the other companies doing seismic work to find ways to limit the amount of vessel traffic for logistical support of the offshore operations.

ConocoPhillips and GX Technology made the same commitments as Shell on monitoring and mitigation. ConocoPhillips said that it also would limit its seismic activities to about 2 percent of the Chukchi lease sale area. GX Technology said that it will consult with its stakeholders on how to reduce its program. The company will also investigate how to reduce the impact of its seismic operations by coordinating its program with other operators, Jones said.

The Alaska Eskimo Whaling Commission emphasized the need for a protocol for reducing the noise or stopping operations, if the subsistence hunters observe an impact from the seismic work on their hunt.

“There’s some work to do there but that should be no problem,” Fox said.

So what comes next?

MMS will likely complete its programmatic environmental assessment in May, prior to completing consideration of the individual seismic permits. NMFS will probably issue the incidental harassment authorizations in June.

Nonsense, nonsense, nonsense: the myths about high oil prices
By Niall Ferguson
(Filed: 30/04/2006)

The British call it petrol, Americans prefer gasoline. But whatever you call it, prices at the pump are soaring. Last week gas hit $3 a gallon in some parts of the United States. To which British motorists can only reply: Diddums.

Driving down the M40 on Friday, I passed petrol stations selling regular unleaded at 97.9 pence per litre. That works out at $6.62 a gallon. If a British outlet offered petrol at American prices – 44 pence a litre – there would be a queue from Beaconsfield to Birmingham.

It's no great mystery why the British shell out more than double what Americans pay to fill up their cars. For years the United Kingdom has levied much higher taxes on fossil fuels than the United States. So if British motorists want to blame someone for the high cost of motoring, they know where to start.

Of course, it's not Gordon Brown's fault that the underlying price of petrol has risen steeply since he came into office. Crude oil futures hit a record price of $75 a barrel last week. That's six times the price that producers were asking back in December 1998.

So who's to blame for higher oil prices? This week, we have heard nearly all the usual suspects fingered, along with some new ones. “We are dealing not just with normal supply and demand economics,” Lord Browne, the chief executive of BP explained in an interview. “Financial activity in the oil markets” was driving prices up, one of his colleagues explained, a thinly-veiled reference to hedge funds.

American politicians offered a less subtle story. Leading Democrats blamed President Bush for being too “cosy with the oil industry”. Those who previously argued that the Bush administration invaded Iraq to make oil cheap now argue that it was in fact, er, to make oil dear.

The Chancellor? The hedge funds? The oil companies? I'm surprised someone hasn't yet blamed the Deputy Prime Minister, John Prescott, who famously keeps two Jaguars – one (it now turns out) for each of the women in his life.

This blame game is a farce. The price of fuel is high precisely because of “supply and demand economics”, as Lord Browne knows only too well. Global demand for oil has risen by around 40 per cent in the past 20 years. As so often in world economic affairs these days, a crucial role is being played by China. In the last five years, the G7 countries have accounted for just 15 per cent of the growth in global demand; China has accounted for twice that.

Soaring demand is coinciding with stagnant supply. Global refining capacity has scarcely grown and took a big knock from last year's hurricanes. Meanwhile, political instability in some of the world's principal oil producing countries – Iraq, Nigeria and Venezuela – has made commodity traders and intelligent investors legitimately pessimistic about future supply. And let's not forget the possibility of US air strikes against Iran. It's hardly “speculation” to bid up the price of oil futures. Only a fool is “short oil” these days.

Could we be about to relive the 1970s, which was the last time oil prices were this high relative to other consumer prices? The good news is that, thanks to increased efficiency and reduced industry, the G7 economies are much less oil-dependent than they were back in the days of kipper ties and bell-bottoms. Nor are high oil prices likely to bring back the stagflation – low growth plus high inflation – we saw in those dreary days.

Some analysts even argue that high oil prices are good, on the principle that they send a signal to producers and consumers that it is time to seek new sources of energy. But this is another piece of nonsense.

There are two problems with high oil prices. The first is political: they enrich the wrong people. “Naturally Iran is happy,” the Iranian oil minister was quoted as saying by al-Jazeera last week. “High prices make any supplier happy.” Well, anything that makes the regime in Teheran happy is bad in my book.

But the much more serious problem is environmental. Here, I have to dissent from the fashionably contrarian view that global warming isn't happening or doesn't matter. For 400,000 years, the world's atmospheric concentration of carbon dioxide (CO2) fluctuated between 180 and 280 parts per million (ppm). Last year it reached 380 ppm. The evidence that global temperatures are rising as a result is incontrovertible. True, no one knows exactly what the effects on the world's climate may be. But, once again, only a fool thinks there will be no effects.

The trouble is that high oil prices are not a signal to mankind to do anything about CO2 emissions. On the contrary, they are as much a signal for oil companies to exploit hitherto non-viable deposits of hydrocarbons, such as Canada's tar sands. At the same time, high oil prices do not deter people from buying gas-guzzling cars. Indeed, the demand for Sports Utility Vehicles like the monstrous Hummer seems to be (as economists say) “price-inelastic”. Better-off Americans are still buying Hummers even with gas at $3 a gallon.

It's easy to see why. If you drive as much as Americans do – it's a big country and people commute long distances to work – you want to be comfortable on the road. The SUV is in fact a kind of hybrid – part vehicle, part living room. Unfortunately, the market is only as far-sighted as consumers. If people don't believe that global warming will affect their lives – and polls show that they don't – then the risk of climate change simply isn't priced in.

So what is to be done? Is there a better way to propel ourselves around than sucking oil out of the ground, refining it and setting it alight in internal combustion engines? The answer is yes.

I've often agreed with Homer Simpson that alcohol is the solution to (as well as the cause of) most of life's problems. In this case, alcohol really is the answer – to be precise, the form of alcohol known as ethanol, which is distilled from plants such as sugar cane.

Unnoticed in the northern hemisphere, one country is pioneering a transportation revolution by switching from petrol to ethanol. That country is Brazil. Today, ethanol accounts for 40 per cent of all automobile fuel in Brazil, while 80 per cent of new Brazilian cars are flexible-fuel cars that can run on either petrol or ethanol.

In theory, such “biomass” fuels – derived from carbohydrates not hydrocarbons – could replace nearly all of the world's oil-based transportation fuels. There would be some environmental costs to such a switch, no doubt, but it would radically curtail CO2 emissions.

What's preventing the northern hemisphere from following Brazil's lead? The answer is not so much Big Oil - though American oil companies have fought tooth and nail against the introduction of ethanol, even as a fuel additive – as Small Agriculture. To protect northern farmers, huge tariffs are currently imposed on imports of Brazilian-produced ethanol by both the United States and the European Union.

Yet not even a world of perfect free trade would convert humanity to more prudent forms of propulsion. Tax incentives are also needed to encourage people to buy flexible-fuel cars.

And if you want to know how to pay for those tax breaks, just ask Gordon Brown. British-style taxation of gasoline won't stop Americans from driving Hummers. But it could help finance a transition to the car of the future: Green Hummers that run on booze.

• Niall Ferguson is Laurence A. Tisch Professor of History at Harvard University www.niallferguson.org

© Niall Ferguson, 2006

'We've got 2 trillion barrels of the stuff left'(Filed: 30/04/2006)

Sylvia Pfeifer finds that the doomsayers who have been predicting that we'll soon be running out of oil are far too pessimistic

When Jeroen van der Veer, the chief executive of Royal Dutch Shell, unveils a strategy update this Thursday, investors will want to know one thing: is Shell finding more oil?

With oil at $73 a barrel, nobody can pump the stuff fast enough. But in order to keep pumping it, oil companies also need to find new reserves. Unfortunately, most western oil majors aren't getting any better at finding oil, let alone at building their reserves. The last discovery of more than 5bn barrels was the Kashagan field in Kazakhstan in 2000.

	Click to enlarge

According to analysts at Sanford Bernstein, western oil companies had an average reserve-replacement ratio of 129 per cent over the past five years – in other words, they found 29 per cent more oil and gas than they pumped. Last year, however, that ratio fell to 114 per cent and that includes reserves acquired through acquisitions.

The news this week from Shell on production is not expected to be any rosier. Analysts expect van der Veer to announce that Shell will come in at the lower end of its targeted production for this year of between 3.5m and 3.8m barrels of oil equivalent per day.

It is numbers like these that have re-ignited fears that the world's oil production will soon peak – or even has peaked already. Current concerns over the security of supply, aggravated by political tensions in Iran and Nigeria, coupled with ever-increasing demand just add to concerns.

Predictions of imminent disaster have been around for years. Princeton geologist Ken Deffeyes warned in 2001 of “war, famine, pestilence and death” as a result of oil production peaking. Last year he predicted that the peak of global oil production would occur last Thanksgiving.

Thanksgiving came and went, but Deffeyes is not alone. Last year Matthew Simmons claimed in his book, Twilight in the Desert: The Coming Saudi Oil Shock and the World Economy, that the Saudis are too optimistic about the size of their oil reserves.

But are we really starting to run out of oil? “I don't believe the world is running out of energy,” van der Veer said in Houston earlier this year.

But it is not just the chief executives of oil majors who believe there is still enough oil left.

“Running out of oil is a very black and white concept,” says Peter Jackson of ambridge Energy Research Associates, a consultancy. “The idea that suddenly worldwide production is going to start plummeting is not going to happen.”

Jackson says that his analysis of the outlook for supply until 2020 shows that “there is no peak or even dramatic slowing down of oil production”.

According to van der Veer, oil companies must do three things to address the challenge: make the most of fossil resources, develop alternative forms of energy and improve energy efficiency.

The biggest impact so far has come from oil companies increasing the amount of oil they recover from existing reservoirs. On average, oil companies now recover little more than a third from their reservoirs. New technology holds the key.

According to Jackson, technological advances have already boosted recovery rates in the Norwegian sector of the North Sea from between 30 per cent and 35 per cent in the 1980s to between 60 and 65 per cent. He says that the “peakists” discount the additional amount of oil from such field upgrades.

“'We estimate that there are at least 3 trillion barrels of conventional global reserves and resources, of which we have produced 1 trillion barrels. This estimate does not include unconventional oils such as oil from Canada's oil sands and oil shales in the USA and Australia,” he says.

Bjorn Lomborg, author of The Skeptical Environmentalist, says that the world is seriously underestimating “our ability to alter our parameters”. He points out that if you look at all the shale oil that's available, there is enough to last between 80 and 90 years – double previous predictions of between 40 and 45 years.

“The whole point is that we find other alternatives that are better and cheaper,” he says.

New technology will also enable oil companies to explore in more remote and difficult places. Recent figures from the International Energy Agency estimate that about half of the undiscovered conventional oil resources outside the Middle East are to be found in deep water or in the Arctic.

One perennial problem is, of course, the fact that much of the world's remaining oil reserves are not owned by private companies but by government-owned enterprises.

That means that the oil may not be produced with all the efficiency associated with private companies. Nevertheless, western oil companies are still striking lucrative deals with their government-owned counterparts.

Speaking to The Sunday Telegraph earlier this month, Lord Browne, the chief executive of BP, said that oil-rich states are still interested in doing deals with private companies. He cited BP's talks with Libya as an example.

In the very long term – if the oil peak were to come after 2020 or 2030, as for example the International Energy Agency predicts – then the increasing amount of alternative fuels such as bio-fuels, solar and wind power, should ease the transition to a life using less oil. But life after oil is some time away yet.