New and pending oil-shale development rules and leases for new fields — pushed through during the final days of the Bush administration — are candidates for review and perhaps overhaul, Interior Secretary Ken Salazar said.

"Moving forward with commercial regulations for oil-shale development is premature," Salazar said. "We are going to take a look at all the midnight actions of the Bush administration and see what needs to be changed and which are OK."

Another priority, Salazar said, is restoring ethics and standards in the department. Toward that end, he plans to visit the department's troubled Minerals Management Service in Lakewood to "discuss ethics" with the staff.

"The Interior Department's standing is probably the lowest it has been in its history," Salazar said. "We've got to change that."

On oil shale, Salazar — who was a vocal critic of the Bush administration, calling its plans "a fire sale" — faces a string of shale decisions, plans, rules, revisions and leasing changes that were made between September 4 and January 16.

The last of those — the signing by oil companies of revised research-and-development leases — was done the day of Salazar's confirmation hearing in the Senate.

"They were trying to create a juggernaut that would make it impossible for the next administration to stop," said Ted Zukowski, an attorney with the nonprofit law firm Earthjustice. He represents 13 environmental groups suing to overturn the oil-shale commercial-development rules.

The pace, however, was forced by the 2005 Energy Act, which mandated development of the oil-shale rules.

The Bureau of Land Management, which oversees the shale program, estimates there is the equivalent of 800 billion barrels of oil on about 2 million acres of land in Colorado, Wyoming and Utah. But it has to be extracted from rock — a process that has not yet proved commercially viable.

"By the Energy Act's timetable, the commercial rules should have been issued much earlier," said Tracy Boyd, a spokesman for Shell Exploration & Production Co.

Shell holds three of the six research-and-development leases.

Since taking office the Obama administration has outlined the steps agencies should take to review and delay Bush rules that have been published but not yet gone into effect. A memo advises delaying implementation for 60 days, offering a 30-day public-comment period and then reviewing the rules and comments.

The Jan. 14 offer by the BLM to issue new research-and-development leases would fall under the Obama guidelines.

The commercial rules, however, went into effect Jan. 17, so the process for reviewing or rejecting those would have to be different, though the Bush administration managed to do it on some of the rules written by the Clinton White House.

The Bush administration, for example, reopened the record on a mining law inherited from the Clinton administration and reconsidered the decision.

"Reopening record is one possibility," said Chase Huntley, a Wilderness Society policy adviser.

Other options include drafting a completely new rule or using a settlement in the environmental groups' lawsuit to revise the law.

"It really is too soon to make a decision," Salazar said. "The problem with oil-shale development is that there are too many unknowns.

"We don't know how much energy it will demand . . . We don't know how much water it will need," he said. "There are too many unanswered questions."

PA may Reveal Drillers' Secrets in Gas Shale Rush

Three decades ago, environmentalists and public officials were alarmed when the price of fossil fuels shot up and drilling companies descended on western Pennsylvania's oil and gas fields in search of a payoff.

The state Legislature responded with the 1984 Oil and Gas Act, which forced the companies to comply with strict new environmental standards - but also handed them a cushion that allowed them to keep secret most information about their below-ground discoveries for five years.

Now, with a fresh wave of exploration companies flocking to Pennsylvania in pursuit of natural gas in the sprawling Marcellus Shale rock formation, state legislators are considering peeling back that cloak of secrecy.

One proposal backed by several key senators would require disclosure of well-specific production data every six months in an effort to stimulate interest in drilling and bring Pennsylvania into line with major gas states.

"The thought is why is Pennsylvania so far out of line with what the industry is used to doing in other states?" said Sen. Gene Yaw, R-Lycoming, the bill's sponsor whose rural, north-central Pennsylvania district is bustling with exploratory activity.

Opponents say the bill would take away their control over information they spent heavily to develop - data that gives them a competitive advantage in the expensive race to tap the shale that is most abundant in Pennsylvania, New York, West Virginia and Ohio.

"It's like a trade secret," said Douglas E. Kuntz, president and chief executive of Pennsylvania General Energy Corp. in Warren.

Even with the national recession depressing natural gas prices and exploration activity, analysts say the Marcellus Shale eventually could become the nation's biggest gas field.

Right now, Pennsylvania is seeing the biggest surge of interest in the rock formation.

The exploration companies are a mixture of newcomers to the Marcellus Shale and established players, which include some national companies as well as smaller in-state ones that consider Pennsylvania their bread and butter.

The looming tussle over the 25-year-old law is the latest on a growing list of regulatory dustups as Pennsylvania scrambles to catch up to a drilling rush that is rapidly changing its landscape.

The legislation written by Yaw would require that the updated information provided by drilling companies be made available on a state Web site.

Yaw's proposal would make Pennsylvania's law more like those in Louisiana, Texas, Oklahoma and Wyoming, where state agencies post well-specific production information online, usually within weeks of getting it.

The just-introduced bill has not moved out of committee, and spokesmen for Gov. Ed Rendell and the House's Democratic majority declined to take positions on the issue.

Don Likwartz, who supervised the Wyoming Oil and Gas Conservation Commission before he retired last month, said the quality of the information available from his agency enables companies around the world to download it and create their own maps.

"I can't tell you how many companies told me or someone in the office that they came to Wyoming because of the accessibility of the data," he said.

That argument dovetails with how some of the bill's early supporters see it. But Stephen W. Rhoads, president of the Pennsylvania Oil and Gas Association, scoffed at the goal of attracting more exploration companies.

"How many more can you get?" Rhoads asked. "All the major players are here now."

In some cases, Wyoming allows confidentiality of well data for up to six months - but there must be a good reason, such as testing of new production technology, Likwartz said.

Pennsylvania does not currently post well-by-well production data online - even after the five-year confidentiality period expires.

All but one of the four exploration companies that responded to questions about the legislation opposed any change in the law.

"Lifting the nondisclosure rule would harm the very companies who have spent the risk capital that unlocked the potential of the Marcellus Shale," said Richard D. Weber, president and chief operating officer of Pittsburgh-based Atlas Energy Resources: LLC.

But a spokesman for Range Resources Corp. of Fort Worth, Texas, which is generally recognized as having drilled the first Marcellus Shale well in this exploration wave, said it supports anything that boosts public understanding of the industry and enhances efforts to develop the field's full potential.

Salazar may Put Oil Shale Development in Obama Energy Pan

The Obama administration will push an energy plan that includes solar, wind, geothermal, oil and gas and potentially oil shale, Interior Secretary Ken Salazar said February 22.

Salazar, who halted leases for oil and gas development on some federal lands in Utah earlier this month, said that while the administration will focus on energy efficiency and renewable sources, there is still room for conventional fuels. Oil shale, he added, still has "great potential," and he may revise rules on harvesting that energy source "in the near term."

"We intend to move forward with a comprehensive energy plan," Salazar told a bipartisan group of Western governors in Washington for a national summit. "You should take away from this conference in Washington that the Obama administration is not against developing any of those resources. … Let's put everything on the table."

Salazar, a former Colorado senator, previously pushed for limits in congressional legislation on tapping oil shale in his home state, Utah and Wyoming out of concern that the development may scar the landscape.

He said on the 22^nd that the Bush administration rules on oil shale, approved in the last days of the president's second term, were "misplaced" and he's looking at what the Interior Department's "legal options are," with regard to those decisions. He said he hopes to make his own decisions on where to take development of the energy source within the first six months of President Barack Obama's term.

Carol Browner, the White House's czar on energy and climate change, carried a similar message to the governors, saying there are "many things" the administration needs to learn from how governors are acting on energy issues.

Utah Gov. Jon Huntsman Jr., who chairs the Western Governors Association and is a proponent of oil shale development, said he was encouraged the administration is looking at all forms of energy.

"It's foolish to dismiss any options at this point," Huntsman said.

Supporters of oil shale development say the West holds more potential energy than the Middle East, while detractors say there is no technology available yet to commercially produce the energy source and there's no reason to rush to development.

Colorado Gov. Bill Ritter, who mirrors Salazar's take on oil shale, said the deposits in the West are a resource that should still be considered but "we should just be prudent in how we develop it."

"It's heartening to me that [Salazar is] going to be thoughtful and that he'll only allow oil shale to be developed when the technology is such that we can also protect our air and our water and our wildlife," Ritter said.

Bossier, Caddo Parishes Allow Public to Weigh in on Proposed Oil and Gas Laws

Elected officials of Louisiana’s Caddo and Bossier parishes are getting their first glances at proposed laws aimed at regulating oil and gas drilling.

Along with Shreveport and Bossier City and DeSoto and Webster parishes, they have worked to have similar ordinances for the benefit of the oil and gas industry and northwest Louisiana residents. The other entities have not publicly floated drafts.

Jim Smith, head of the Caddo Commission's natural resources committee, says it's too early to tell what kind of adjustments could be needed on the proposals. The commission and Bossier Parish Police Jury likely will consider approving the ordinances in the next few months.

"It's going to take a good bit of study on it from our perspective," said Smith, the commissioner for southwest Caddo. "We're going to have to hold some public meetings."

The proposals were on the agenda of a recent meeting of the Shreve Centre Coalition, a group of neighborhood associations pushing for property owner rights in Haynesville Shale natural gas production. Besides six or seven Caddo and Shreveport public officials, about 15 local residents attended. Smith was disappointed more constituents didn't attend.

Though the state generally handles oil and gas law enforcement, Scott said Louisiana regulations don't make room for urban drilling.

"At 3 o'clock in the morning, if some property owner wakes up because of noises or wakes up because of lights, they're not going to call the commissioner of conservation," Scott said. "They're going to call their city council member. They're going to call any local official."

Bossier and Caddo's oil and gas ordinance proposals differ only slightly. Here are highlights included in both:

· Site access: Companies cannot drive across parks or other public property except on public roads or pathways designated as truck or commercial delivery routes.

· Dust, vibration and odor: By-products such as smells and shaking must be minimized during drilling, production, compression and transmission.

· Lighting: Beams cannot point directly onto public roads or adjacent property within 300 feet of a rig. Lights also should face downward, as much as possible.

· Vehicles: Commercial automobiles that weigh more than three tons will be restricted from public highways except government-defined routes or with special permits.

· Pipelines: Conduit to move oil or natural gas cannot interfere with existing utilities. Companies also must supply the parish with plats showing plans for pipelines. They must include geographic information system coordinates.

· Water supply: Public water supplies cannot be used for drilling and production — specifically including fracturing operations — unless the operator has complied with all parish and state regulations.

· Disposal wells and compressor stations: Commercial saltwater disposal wells and compressor stations must be in industrial zones and no less than 500 feet from a protected area. Compressor stations must not create beyond 300 feet sounds that exceed the ambient noise level before production is started. The station operator will report the predevelopment noise level.

Energy Transfer Holds Open Season for Tiger Pipeline

Energy Transfer Partners, L.P. (ETP) on February 20 launched a binding open season to solicit market participation in its recently announced Tiger Pipeline project, an approximately 180-mile, 42-inch new interstate natural gas pipeline that will connect to ETP's dual 42-inch pipeline system near Carthage, Texas, extend through the Haynesville Shale and end near Delhi, Louisiana, with interconnects to at least seven interstate pipelines at various points in Louisiana.

ETC Tiger Pipeline, LLC, a subsidiary of Energy Transfer Partners, is seeking binding bids from interested customers for contract terms of 10 years or longer. The open season will run from February 20, 2009 through March 20, 2009. Those interested in obtaining more information on the open season may contact Luke Fletcher at (210) 403-6492 or luke.fletcher@energytransfer.com, or Lee Hanse at (210) 403-6455 or lee.hanse@energytransfer.com. Information is also available at www.energytransfer.com.

The Tiger Pipeline is anticipated to have an initial throughput capacity of at least 1.25 billion cubic feet per day, which may be increased to 2.0 billion cubic feet per day based on the results of the open season. ETP has a 15-year commitment from Chesapeake Energy Marketing, Inc. for firm transportation capacity of approximately 1.0 billion cubic feet per day.

When completed, the Tiger Pipeline will provide takeaway capacity from the increasingly constrained Carthage Hub area in East Texas. The Carthage Hub area receives large volumes of natural gas from several producing basins in Texas, including the Barnett Shale and Bossier Sands basins as well as from the Permian Basin in West Texas. The Tiger Pipeline will also provide takeaway capacity from the rapidly expanding Haynesville Shale play in East Texas and Northern Louisiana. Subject to receipt of the necessary regulatory approvals, the Tiger Pipeline is expected to be in service in the first half of 2011.

Energy Transfer Partners, L.P. is a publicly traded partnership owning and operating a diversified portfolio of energy assets. ETP has pipeline operations in Arizona, Colorado, Louisiana, New Mexico, and Utah, and owns the largest intrastate pipeline system in Texas. ETP's natural gas operations include intrastate natural gas gathering and transportation pipelines, natural gas treating and processing assets and three natural gas storage facilities located in Texas. These assets include approximately 14,600 miles of intrastate pipeline in service, with approximately 250 miles of intrastate pipeline under construction. In addition, ETP owns 2,450 miles of interstate pipeline in service, with approximately 250 miles of interstate pipeline under construction. ETP is also one of the three largest retail marketers of propane in the United States, serving more than one million customers across the country.

Energy Transfer Equity, L.P. (ETE) is a publicly traded partnership, which owns the general partner of Energy Transfer Partners, L.P. and approximately 62.5 million ETP limited partner units.

Northeast Pennsylvania gets Marcellus Pipeline

A pipeline to connect Devonian Marcellus shale gas is under construction in northeastern Pennsylvania.

Epsilon Energy Ltd., Concord, Ont., began building the pipeline and compression facilities known as its Highway 706 project, in which it holds 100% working interest, in so southwestern Susquehanna County. It has acquired more than 25 miles of right-of-way.

Epsilon, which is drilling its eighth well in the project area, plans to start gas production before the end of June 2009. The pipeline will deliver gas to Tennessee Gas Transmission Corp.

The eighth well, Hardic-2H, is a horizontal Marcellus well. Epsilon plans to frac its fourth well, Poulson-2H, at the end of February. It has more than 100 other well locations.

Epsilon holds 47,000 gross acres in Pennsylvania and New York, including 12,000 gross and net acres in the Highway 706 project.

Three-way JV to Build Regency's Haynesville Shale Expansion Project

Regency Energy Partners LP, Alinda Capital Partners LLC, and an affiliate of GE Energy Financial Services announced they are forming a joint venture to finance and construct Regency's Haynesville Expansion Project, a North Louisiana pipeline that will transport gas from the Haynesville Shale, one of the fastest growing U.S. natural gas fields. Regency has already secured commitments from shippers for 84% of the pipeline's capacity.

The initial 1.1 Bcf/d Haynesville Expansion Project will more than double Regency's pipeline system in North Louisiana and is expected to be in-service by the end of 2009. Regency will continue to develop and operate the system through the new joint venture.

Regency will contribute to the joint venture its Regency Intrastate Gas System (RIGS) in North Louisiana, valued at $400 million, in exchange for a 38% general partnership interest in the joint venture. GE Energy Financial Services and Alinda Capital Partners LLC ("Alinda"), an independent private investment firm specializing in infrastructure investments, have agreed to contribute $126.5 million and $526.5 million in cash, to the joint venture in return for a 12% and a 50% general partnership interest, respectively. Regency will receive a cash payment equal to the total Haynesville Expansion Project capital expenditures paid through the closing date, subject to certain adjustments.

"By partnering with GE Energy Financial Services and Alinda, we have secured financing for the Haynesville Expansion Project under terms accretive to our unitholders," said Byron Kelley, chairman, president and chief executive officer of Regency. "The positive liquidity created for Regency will allow us to maintain our current distribution level during construction."

"This joint venture deleverages Regency's balance sheet, providing us with sufficient liquidity to execute our business plan in 2009. Any capital markets activity would be completed when the financial conditions of the markets improve in order to further strengthen our financial position or to finance unidentified attractive growth projects. In addition, the joint venture provides a strong platform for further infrastructure development in one of the most attractive shale plays in the United States," said Kelley.

As Regency's general partner and a key player in the energy industry, GE Energy Financial Services, a unit of GE partnered with Regency to raise new capital for the Haynesville Expansion Project despite difficult credit conditions.

"Creating a joint venture, providing additional capital and bringing in a sophisticated partner in Alinda, GE is supporting Regency's growth and strengthening the project," said Dan Castagnola, managing director at GE Energy Financial Services and a member of Regency's Board of Directors. "In addition, this project will improve the overall energy security and independence of the United States by alleviating a transportation bottleneck experienced by many producers in the Haynesville area."

Regency expects to close the joint venture as promptly as practicable following the satisfaction of certain closing conditions but no later than April 30.

The parties will enter into an amended and restated general partnership agreement and a master services agreement, to define their rights, obligations and relationship. An affiliate of Regency will serve as the operator of the joint venture and an affiliate of Regency will provide all employees and services for the operation and management of the joint venture's assets. The oversight of the business and affairs of the joint venture will be managed by a management committee consisting of four members. Each member of the management committee will have a vote equal to the sharing ratio of the partner who appointed the member.

In addition, Regency will offer the joint venture the first option to acquire or pursue natural gas transportation and storage opportunities Regency identifies in Northern Louisiana.

As a condition to the closing of the joint venture, Regency is amending its revolving credit facility. Regency is also entering into a $45 million unsecured revolving credit facility with GE, the proceeds of which may be used to pay for expenditures relating to the Haynesville Expansion Project made prior to the closing of the joint venture. Tudor, Pickering, Holt & Co. Securities, Inc acted as the financial advisor to the conflicts committee of Regency's general partner.

The Haynesville Expansion Project consists of the construction of a 28-mile, 36" Bienville Loop, a 23-mile, 36" Elm Grove Pipeline and a 77-mile, 42" Winnsboro Loop. Regency expects to expand the pipeline's interconnects with the Columbia Gulf, Texas Gas, Trunkline and ANR pipelines and expects to add 14,200 horsepower of compression at the Elm Grove and Haughton Stations. In addition, Regency expects to add 1.1 Bcf/d of capacity to the pipeline system.

GE Energy Financial Services' experts invest globally with a long-term view, backed by the best of GE's technical know-how and financial strength, across the capital spectrum in one of the world's most capital-intensive industries, energy, to help their customers and GE grow. With $19 billion in assets, GE Energy Financial Services is based in Stamford, Connecticut.

CANADA

PetroWorth to Complete 500-Meter Shale Oil & Gas Zone at New Brunswick

PetroWorth Resources Inc. on February 6 announced that it will conduct a hydraulic frac completion program on a 500-meter shale oil and gas zone in the A-08 (Feenan #3) well in New Brunswick. A-08 was drilled in June 2008 to a total depth of 1950 meters.

The design of the completion program will be based, in part, on the results of a geochemical assessment of the oil shale, shale gas and hybrid tight sand/shale prospects of the Albert Formation and associated sediments within the company's leased blocks in the Moncton sub-basin.

Conducted by Dr. P.K. Mukhopadhyay ("Dr. Muki") of Global Geoenergy Research Ltd., the assessment involved a number of factors, including: a) selected log interpretations; b) correlations on the thickness of the Frederick Brook member sediments; c) thickness contours of both the Hiram Brook and Frederick Brook member sediments; d) source rock geochemical data; e) physical properties of selected reservoirs; and f) reservoir hydrocarbon production testing interpretations.

Dr. Muki's 101-page report provides a number of noteworthy findings:

- Alternate sequences of calcareous and dolomitic sandstone, calcareous black shale and siltstone units of the Frederick Brook member dominate the lower portion of the section while alternate shale, siltstone and sandstone dominate the upper section.

- In PetroWorth's A-08 well, most sediments are lacustrine, excellent organic rich (1-4.5% Total Organic Carbon) algal (alginate and amorphnite) derived oil prone source rocks with major oil prone shale sections and gas prone sand section source rocks with a gas condensate window.

- The zones in both PetroWorth E-08 (Feenan #2) and A-08 wells have a combination of major oil prone (shale section) and gas prone (sand section) resource rocks.

- Geochemical lab results indicate optimum maturity for oil and gas generation in the source rock sediments of the Hiram Brook and Frederick Brook members. This data clearly demonstrates the likely presence of medium-sized conventional oil (28-40 API gravity) and unconventional shale oil resources at relatively shallow depths. Additionally, unconventional shale gas prospects exist within the overall hydrocarbon-charged interval including the Hiram Brook and Frederick Brook members.

- Additionally, the study recommended that the tectonically undisturbed Frederick Brook shale in the southwest axial part of the lease within a depth of 1800-3000 meters in the Moncton Subbasin should be targeted for future drilling.

The post-frac well test at the E-08 (Feenan #2) well previously reported both oil and gas production from an over-pressured zone. This observed oil and gas is now better understood and consistent with the geochemical analyses conducted by Dr. Muki, thus providing independent third party verification of PetroWorth's well tests.

Based on Dr. Muki's findings, Petroworth is now designing a multi-stage fracture completion program for the 500-meter potential oil and gas zone in the A-08 (Feenan #3) well. The program is expected to be conducted in the spring/summer of 2009. In the meantime, the company is investigating pipeline options and other methods of natural gas transportation in order to move these resources to market.

"Dr. Muki's work has been extremely helpful in defining the nature and size of the oil and natural gas resources on our company's leases in the Moncton sub-basin," said Neal Mednick, president of PetroWorth. "This information will be very important in attracting sophisticated joint venture partners."

PetroWorth Resources Inc. has acquired 100% working interests in almost one million acres in nine separate exploration permits on Prince Edward Island, Nova Scotia and New Brunswick. The strategy of the company is to conduct aggressive exploration programs on these permits, both internally generated and through advantageous farm-in arrangements.

$4-Bln-plus Pipelines Project would Bring Tankers into B.C. Inlets

If the volatile economics of oil and environmental approvals fall into place, Calgary-based Enbridge Inc. hopes to construct 1,200-kilometer twin pipelines linking the oil fields of northern Alberta with the deep-water port at Kitimat. A westbound pipeline, about a meter in diameter, would carry 525,000 barrels of oil daily, and a 50-centimeter-wide eastbound line would daily transmit 193,000 barrels of condensate, a petroleum byproduct used to thin crude oil for transport and piping.

By selling 10 units at $10 million each, and giving buyers preferential treatment in booking capacity on the future pipeline, Enbridge has already raised $100 million from heavyweight Asian refiners and Canadian producers to help bring the project to regulatory approval.

The subplot to this story is that major oil-sands players like Suncor, Husky, Shell, and Petro-Canada desperately want the pipeline to access Asian markets as a cushion against threats from the nascent Barack Obama administration to wean the U.S. off its reliance on dirty oil-sands fuel.

Enbridge expects this $4-billion-plus project to create some 4,000 construction jobs as it crosses the traditional territories of at least 40 different First Nations bands in B.C. and Alberta. The company is promising state-of-the-art shipping protocols, with double-hulled vessels, radar-monitoring stations, pilot supertugs, and first-response emergency stations located in Kitimat and communities like Hartley Bay. Throughout the fall, Steve Greenaway, vice president of Enbridge Northern Gateway Pipelines—a general partner of Enbridge Inc.—led a series of open houses in communities along the pipeline route.

Barring any major roadblocks, Greenaway says, Enbridge plans to file for regulatory approval by mid-2009, kicking off an estimated two-year environmental review to be carried out jointly by the Canadian Environmental Assessment Agency and the National Energy Board.

At the earliest, construction could begin in 2011 or 2012. However, over the past two years there has been furious debate about the validity of an ambiguous federal government statement dating back to the early 1970s that refers to a moratorium on oil-tanker traffic along the B.C. coast. As far as Greenaway is concerned, though, the moratorium is not an issue.

When it comes to provincial and federal government support, Greenaway has good reason to be optimistic about Northern Gateway’s prospects. The pipeline fits neatly within the B.C. Liberals’ energy game plan, which could have not only pipelines linking the coast to Alberta but also drilling rigs in Hecate Strait east of the Queen Charlotte Islands, an activity that has been off-limits for more than 30 years because of federal and provincial moratoriums on offshore oil and gas exploration and development. That’s why in the B.C. Energy Plan, the government promises to work “to lift the federal moratorium on offshore exploration and development and reiterate the intention to simultaneously lift the provincial moratorium”.

In a strange twist, former provincial NDP leader and cabinet minister Dan Miller has emerged as one of the most vocal cheerleaders for offshore oil exploration. Although high investment costs, uncertainty about proven reserves, and environmental issues will likely keep offshore oil and gas exploration on the shelf for some time, pipelines to the north coast are a very real possibility. Near the bottom of a 2008 speech dripping with sustainability rhetoric, Premier Gordon Campbell made references to an “energy corridor” that will be a boon to the northern economy. Kitimat LNG Inc., which has received both federal and provincial approval for its liquid-natural-gas port facility, received a major boost recently when Mitsubishi Corporation signed an agreement to purchase 1.5 million tonnes per year of terminal capacity and to acquire a minority interest in the project. The deal is expected to be finalized by the end of March this year. There have also been a slew of pipeline proposals, including those by Pacific Trail Pipelines, Pembina Pipeline, and Kinder Morgan Inc.

Enbridge, though, appears closest to breaking ground. In an enthusiastic August 2005 letter to Enbridge, Richard Neufeld, then minister of energy, mines, and petroleum resources, endorsed the pipeline and discounted the moratorium. Neufeld wrote that it “is not directed at, and has no application to oil tankers sailing to or from British Columbia ports”, referring instead to a so-called tanker exclusionary zone that targets only ships from Alaska transiting B.C. waters while bound for the U.S.

The federal government mouths a similar line, but a former minister of natural resources, Gary Lunn, preferred to duck hard questions about the tanker moratorium. After the last federal election, Lunn was removed from the ministry and replaced by Toronto MP Lisa Raitt, a lawyer and former CEO of the Toronto Port Authority. Environmentalists can take little comfort in her nomination. At an October 6 Oakville, Ontario, chamber of commerce meeting, Raitt was on record cheering about the possibilities of increased tourism and shipping opportunities in the North, thanks to the melting polar ice cap. She is also known for her combative relationship in the past with a citizens’ group called Community Air, against which she launched a lawsuit in 2006 for its criticism of the port authority.

Although governments prefer to dance around the prickly moratorium question, conservation groups, many First Nations, and other critics say the reasons for a moratorium still stand: simply that tanker traffic and oil spills pose a serious threat to the B.C. coast. Since 2006, ocean tankers have been quietly sailing into Kitimat’s port laden with as many as 350,000 barrels each of condensate, bound by railcar for EnCana Corporation’s operations in Alberta.

Northern Gateway’s Greenaway sees this as proof positive that tankers can travel safely into Douglas Channel. But Eric Swanson, corporate campaigner for the Dogwood Initiative, a B.C. land-reform organization, says such shipping traffic is in blatant defiance of what the public wants—a rock-solid moratorium on tanker traffic in B.C.’s inside waters. Swanson is not surprised that politicians would prefer to sidestep the tanker-traffic issue rather than address it head-on—it’s a potential political time bomb. According to a poll conducted by the public-opinion research firm Synovate, a majority of British Columbians polled across the political spectrum desire an outright ban on oil-tanker traffic along the coast.

“The problem is that the moratorium was issued as a policy statement but it was never written down. What is clear is that there is a huge appetite for a crystal-clear ban on oil tankers. Seventy-two percent of B.C. residents support it, and that’s what we’re looking for,” Swanson says.

Ian McAllister, executive director of the nonprofit Pacific Wild, believes the distinction between the so-called tanker exclusionary zone and a tanker moratorium is moot.

“If the issue is protecting the coastline of British Columbia, then what’s the difference between tankers coming from Alaska and tankers going into Kitimat? It’s ridiculous.”

And when Alaska and oil tankers are mentioned in the same sentence, the Exxon Valdez immediately comes to mind. This 1989 disaster dumped 49.5 million liters of crude oil into Prince William Sound, killing an estimated 250,000 seabirds, 22 orcas, and untold numbers of fish and other marine organisms. By most conservative measures, Caamano Sound poses a much greater navigational challenge than the Alaskan sound that has been relegated to its place in history as the site of one of the worst oil-spill disasters on record. At the time, U.S. coast guard admiral Paul Yost said the 16-kilometer-wide accident site in Prince William Sound “was not a treacherous area” and “Children could drive a tanker through it.”

“If supertankers move around this coast, it’s not a matter of if but when a major disaster on the scale of Exxon Valdez would happen,” says Kevin Smith, whose company, Maple Leaf Adventures, takes tourists on wildlife-viewing trips in the central coast’s Great Bear Rainforest and frequently sails the proposed tanker route. “Big oil has millions of dollars to lobby government. Sadly, our burgeoning conservation economy on the coast doesn’t have that ability.”

Rob Williams, a marine researcher from the University of British Columbia, agrees that the prospect of an oil spill in an area as biologically diverse as Caamano Sound is unpalatable.

“Oil tankers pose a lot of threats to marine mammals, including noise, oil spills, and ship strikes. We don’t exactly know why this area is so rich, but there are some long, narrow channels that serve as bottlenecks for food, making it easier for whales to feed,” Williams says. The researcher has been using acoustic monitors to gauge the level of underwater shipping noise, known to have an impact on the ability of toothed mammals, such as orcas and dolphins, to use echolocation for finding food. “Caamano Sound may be one of the last chances we have on this coastline to protect an acoustically quiet sanctuary for whales.”

While environmentalists and scientists ponder a B.C. coastline with regular oil-tanker traffic, Enbridge faces an equally tough sales job as it tries to win support for its fossil-fuel superhighway across north-central B.C. Enbridge can count on support from the mayors of Prince George, Prince Rupert, and Kitimat, who have been boosting the project and its promise of jobs and tax dollars in their cities. Conversely, Nathan Cullen, NDP MP for Skeena–Bulkley Valley, has serious reservations about a pipeline linking northern Alberta’s dirty oil sands with the B.C. coast, and he remains highly skeptical about Northern Gateway’s economic benefit. There will be short-term jobs in pipeline construction, Cullen admits. He says, though, that over the long haul, B.C. communities in the Interior and along the coast will shoulder the burden of environmental risk from spills—whether it be in fish-bearing streams or the marine environment—and they will not share in the profits that will accrue to the head offices of Enbridge in Calgary and firms like Syncrude and Shell.

“We approach projects on a risk-benefit basis, and I don’t think the case has been made that the risks are worth the benefit,” Cullen said.

“There are all kinds of questions about the potential of spills that they couldn’t or wouldn’t answer,” Ferris says. “It looks like someone just took out a map and drew a line between point A and point B. You have thousands of kilometers out there, and they put it right down the middle of our valley. We don’t want a pipeline here and don’t want tankers on the coast, but there’s a feeling that it’s almost a done deal. We’re frustrated.”

The proposed pipeline route also crosses the territories of dozens of First Nations, each with specific concerns and wants, and smart companies know that it’s no longer acceptable to simply pay lip service to Native concerns, so does government. A landmark 2004 decision by the Supreme Court of Canada, in the case of Haida Nation v. British Columbia and Weyerhaeuser, explicitly states that the Crown must consult with and accommodate First Nations even when questions of aboriginal rights and title have not been resolved. This means, at best, that the proposal could get bogged down in protracted band-by-band negotiations, and at worst, it could end up in the Canadian court system. The Haisla First Nation, under the leadership of Chief Steve Wilson, is tentatively in support of Northern Gateway and stands to benefit greatly from the development of port facilities in Kitimat. Enbridge has already signed a number of protocol agreements with individual First Nations along the pipeline route—including the Yekooche First Nation and the Nee-Tahi-Buhn band near Burns Lake—that come with attached funds, ostensibly to enable First Nations to hire their own consultants, and arrive at an informed decision about the pipeline. Chief Ray Morris says Enbridge has offered the Nee-Tahi-Buhn $110,000 in capacity-building funds as well as a chance to purchase equity in the project.

“Our band is very familiar with pipelines. There have been so many proposals,” Morris says on the phone, adding that his band will support the project only if it translates into future revenue for members.

The mood isn’t nearly as accommodating elsewhere. The Council of Haida Nations is on record as saying it will never support tanker traffic in its waters. In an October 14, 2008, letter to Enbridge, Fraser Lake’s Nadleh Whut’en band expressed “significant concerns over the proposed pipelines and their environmental and socio-economic impacts” and ordered Enbridge employees and consultants to stay out of the band’s territory until a formal agreement is in place. This sentiment was echoed at the offices of the Carrier Sekani Tribal Council in Prince George. Tribal Chief David Luggi represents eight bands in the region and views protocol agreements as an effort by Enbridge to purchase First Nations support for Northern Gateway.

The proposed pipeline will cross the Stuart River, a major salmon system in Carrier Sekani territory, and member First Nations are rejecting the federal and provincial environmental review processes. In their place, Luggi says, the Carrier Sekani want a novel First Nations review that would be funded by government and use independent science and traditional knowledge to assess the impacts of the project on the environment, cultural heritage, and aboriginal rights and title. It would also allow adequate time and funds to fully engage and educate aboriginal communities and would delay a decision until “accommodations of infringements of aboriginal rights and title has taken place”.

“The B.C.–federal review process is focused on ensuring proper process rather than the substance of the project,” Luggi says. “The First Nations review-process framework would be applied to all new development proposals and not be restricted to the Enbridge proposal. We won’t participate in reviews if the funds are tied to any existing programs.”

The Carrier Sekani proposal was formally endorsed by other bands at a First Nations summit held in Vancouver last November. According to Luggi, the current process is tantamount to the project proponent trying to purchase First Nations support one band at a time.

Northern Gateway’s Greenaway denies that Enbridge is attempting to buy off Natives through protocol agreements. If the Carrier Sekani people disagree with the environmental-review process, he says, that’s a matter between them and government. He says he believes Enbridge is being as proactive as it can be in engaging community groups and First Nations well in advance of the official review process.

“The protocol agreements come with funding to allow First Nations to build capacity,” Greenaway says. “We are also offering opportunities for joint ventures and to become equity partners. These are still early days, and there’s a lot of work to be done.”

Despite gloomy economic circumstances that have caused capital to flee the oil sands, with projects that would have represented more than one million barrels of oil per day either postponed or cancelled since last December, Greenaway assures that Enbridge’s backers are thinking about the long term and remain committed to the project.

Hartley Bay counselor Marven Robinson fears that oil tankers several football fields long plying the same waters as the myriad species that still thrive in traditional Gitga’at territory could become British Columbia’s oil-spill shame in the future. He’s also concerned that this energy-corridor juggernaut of pipelines and oil tankers is already a done deal in the minds of many politicians and oil-patch executives.

Co-operative Group Ltd. will Help to Fund Oil Sands Lawsuit

Co-operative Group Ltd., a mutually owned U.K. financial company, is helping to fund a lawsuit in Canada aimed at stopping companies such as BP Plc and Royal Dutch Shell Plc from exploiting oil sands, the Financial Times reported.

The Co-op's 50,000-pound contribution will go toward gathering evidence for a legal action being brought by the Beaver Lake Cree nation, an aboriginal community in Alberta, where the oil sands business is based, the newspaper said.

Overall, the Co-op plans to spend 500,000 pounds on a campaign against what it characterizes as ``toxic fuels,'' in association with WWF, an environmental group, the FT said.

The Beaver Kake Cree say their rights to hunt, fish and gather plants in Alberta, fixed by treaty in 1876, have been violated because of pollution caused by oil sands development, the newspaper added.

Chevron Projects Athabasca Oil Sands Expansion Costs to $13.7 Billion

Project costs for a 100,000-barrel-a-day expansion at Royal Dutch Shell PLC's (RDSA) Athabasca Oil Sands Project have climbed to $13.7 billion, partner Chevron Corp. (CVX) said in a filing with the SEC.

The increase, from Shell's previous estimate of between $8 billion to $10.2 billion (C$10 billion and C$12.8 billion) comes as other oil sands developers signal that the plunge in crude futures prices is starting to rein in rampant cost inflation.

The Athabasca development currently produces 155,000 barrels a day of thick, tarry bitumen from the oil sands mine, which is subsequently processed into a higher-grade synthetic fuel at the project's upgrader. Shell is the project leader with a 60% stake, while Chevron and Marathon Oil Corp. (MRO) own 20% apiece.

Shell doesn't provide cost estimates for specific projects, senior oil sands spokesman Paul Hagel said, directing further inquiries to Chevron. Chevron wasn't immediately available for comment.

A number of proposed developments in Alberta's high-cost oil sands sector have been delayed or canceled as crude prices dove more than 70% off July's record highs near $150 a barrel and financial markets seized up last year. Work on Shell's expansion was already underway at the time, and the Anglo-Dutch major still expects the project to start up in late 2010 or early 2011, Hagel said.

However, Shell has put a second expansion on hold, saying in October that it would wait until costs fall before making a decision on boosting output by another 100,000 barrels a day. The company hasn't set a new timeline for making this investment decision, though it will happen "in due course," Hagel said.

"There are signs of the market getting less heated and materials costs coming down, but we haven't seen significant price reductions yet," he said. "But I think it won't be long before we see the market reduce costs, and that will help us make our decision."

Oil sands peers such as Suncor Energy Inc. (SU) and Petro-Canada (PCZ) have pushed back multibillion-dollar developments, planning to renegotiate contracts with suppliers and service providers to tamp down project costs. Husky Energy Inc. (HSE.T) said earlier this month is has already slashed 30% off cost estimates for its Sunrise oil sands development due to falling costs.

On February 26, the chief executive of engineering and construction company, KBR Inc. (KBR) figured it will take another three to six months before costs in the supply chain come down enough to encourage producers to start on the next round of projects.

Canadian Firm may have Solution for Problem of Oil Sands Tailings

Alan Fair of Syncrude Canada Ltd. had been trying to solve the problem of oil sands tailings, on and off for three decades. Then when 500 ducks died after landing on a pond of the waste at Syncrude's Alberta site last spring, the incident attracted global criticism of the environmental impact of Canada's oil sands.

The quest became more crucial for Fair, Syncrude's research and development manager. "We've recognized for some time that we have a tailings issue," he said.

Fair is in charge of testing a range of ways to halt the expansion of toxic tailings ponds and cleaning them up, from using centrifuges to separate the liquids from the solids to forming new lakes in mined-out pits.

But he is also open to ideas from outside Syncrude, the world's largest oil sands producer, like one from Gradek Energy Inc, a small firm with a unique technology aimed at cleaning up one of the industry's biggest headaches and a major reason why green groups have tagged the resource "dirty oil."

"It's really exciting because all of a sudden we're not trying to kick a door down. The door's open," Keith McCrae, Gradek's chief operating officer, said.

Privately held Gradek has talked to Syncrude for about eight years, and now aims to test its method in a pilot project with the oil sands producer's participation in August.

After development costs of about $4.8 million (C$6 million), a pittance in oil-industry terms, it has proven itself on a small scale, company founder Thomas Gradek said.

At its center are proprietary polymer beads, which look like Corn Pops. They attract tar-like bitumen -- the oil part of the sands -- while repelling water. They first proved useful in cleaning up oil spills.

If all goes well, not only will developers be able to use them to stop the spread of contaminated ponds, which now cover more than 50 square km (20 square miles) of northern Alberta landscape, but recover oil that goes to waste, Gradek said.

"We will eliminate the tailings ponds that are there within 10 years, and they will not have any more tailings ponds generated because we're going to be taking their end-of-pipe (waste)," Gradek, an engineer by trade, said.

Tailings are generated in the extraction part of production, where companies use hot water and chemicals to separate the tar-like bitumen from oil sands that they mine in sprawling open pits.

Besides water and unrecovered bitumen, the waste contains sand, silt, clay heavy metals and naphtha. It takes decades for all of the fine tailings to settle to the bottom of the ponds.

The concoction represents contamination danger to groundwater and nearby rivers, but also gives off methane fumes, seen as a major contributor to global warming.

As President Barack Obama visited Canada recently, oil sands jumped into the public eye again. They are the largest oil resource outside the Middle East and seen by governments as key to North American energy security.

But criticism is growing over the impact of development on air, land, water and local communities. The duck deaths, for which Syncrude now faces provincial and federal charges, emboldened opponents.

This month, the Alberta government tightened regulations for tailings, demanding that operators prepare plans and report on the ponds annually, reduce accumulations and specify dates for construction and closure of ponds.

With Gradek's process, new tailings will be blended with tailings from the ponds, known as mature fine tailings, then the beads are added and the mix is shaken. Clay and the other fine particles are separated from the bitumen-coated beads.

Then the oil is washed from the beads using recycled naphtha and processed with the rest of project's crude.

The beads are then dried and can be reused hundreds of times, Gradek said.

Fair, who believed early in his career the tailings problem would be solved by now, cautioned the real test will be continuous use on a large scale and in the harsh winter conditions of northern Alberta, where other methods have failed.

Total Initiates $500 Mln Takeover Bid of UTS Energy as Oil Sands are Impacted by Plunge in Prices

No part of the global oil industry has been hurt by the plunge in prices as much as the Canadian oil sands region. Most producers are struggling just to cover operating costs—besides having to pay off billions of dollars invested in strip mines and bitumen refineries.

As a result, in late January it seemed reasonable for Christophe de Margerie, chief executive of French oil giant Total, to initiate a hostile takeover bid of $500 million for oil sands player UTS Energy. The move nearly doubled the price of UTS shares overnight. But UTS Chief Executive William Roach wasn't impressed. "I was quite surprised by the price of the bid," he says. "It is wholly inadequate."

A bare minimum value of UTS would be $900 million, Roach figures. After all, UTS has $230 million in cash and is owed $600 million by its partners in the Fort Hills oil sands project, which has all the permits it needs and is ready to begin construction. Add prospective reserves of oil-laden bitumen from UTS' other prospects and, says Roach, he's sitting on 2.25 billion barrels, enough to eventually produce 200,000 barrels per day (bpd), by his estimates.

That day will never come as long as the price of oil stays below $70 a barrel--the minimum needed to justify building out new oil sands mines or underground recovery projects. In the past six months oil sands players have postponed $70 billion worth of investments in mines and refineries, out of a total $100 billion. Those not postponed have slowed to a crawl. The slowdown has decimated Alberta's one-time boomtown Fort McMurray. At its peak, the town boasted nearly 40,000 oil sands workers; now that number is below 20,000, and falling.

Total, as the fourth-biggest publicly traded oil company is convinced that the current oil price downturn is temporary; that Big Oil, Total included, is not capable of delivering enough oil to meet demand; and that within five years rising oil prices will make oil sands economic again. "The oil sands are very important reserves for the long term," de Margerie says. Total, which holds oil sands acreage near UTS' projects, wants to consolidate its position while the land is cheap.

UTS' Roach is stuck in a holding pattern right now, waiting for oil prices to get back above $70 a barrel before he and his partners (Petro-Canada and Teck Cominco) could hope to secure the $10 billion in financing needed to build out Fort Hills.

The site is encircled by acreage that Total already owns. "There are huge synergies between our assets and Total's," says Roach, who says he had last spoken to Total representatives in September. "They know our assets very well." As does Royal Dutch Shell, which has four projects nearby.

When Roach joined UTS in 2004 from oil sands pioneer Husky Energy, the company had a market cap of just $50 million, and its only asset was 22% of the Fort Hills acreage. Soon UTS acquired the other 78% of Fort Hills from Koch Industries for $125 million. Then Roach traded out 80% of Fort Hills to Petro-Canada (60%) and Teck Cominco (20%) in exchange for other acreage and $1.1 billion in cash.

Roach invested the money acquiring land and drilling exploratory wells. Canadian law requires companies to make drilling data public one year after leasing the land, so Roach made it a policy to start drilling immediately after signing, giving UTS more time to grab more acres near promising boreholes. UTS has drilled 527 wells in four years, many on the Equinox prospect, which Roach says might have twice the barrels as Fort Hills.

De Margerie says that what he likes about Fort Hills is Petro-Canada's vast oil sands experience. He also likes that all the permitting for the project is in place. "In two years there has been a drastic change in regulations in Alberta," de Margerie complains. "It's gone from totally open to totally closed. Alberta should be concerned by this. Fort McMurray is shrinking."

Some in the oil sands are starting to get desperate. Connacher Oil & Gas late last year shut in 5,000 bpd of production in its small project because it wasn't even covering its operating costs. Bigger operators don't have the luxury of halting production: Many of the newer oil sands projects are not the typical open strip mines, rather they inject steam into the ground to slowly melt the bitumen out of the sands. Because it can take months of steam injection to bring the reservoir up to optimal temperatures, producers resist halting the process for fear of damaging their sands and gumming up their gear.

As far as how long it can go on, Jackie Forrest, analyst at Cambridge Energy Research Associates, explains that with the spot price for West Texas Intermediate crude at $40 a barrel, oil sands producers have been getting around $34 per barrel for their synthetic crude. That's not enough. To manufacture each barrel requires some $13 of operating costs. Thinning out the bitumen requires adding $11 per barrel of lightweight natural gas liquids. Royalties to the government average $1.50 per barrel. Then it costs another $1.50 per barrel to transport it by pipeline to a refining center. That leaves $7 per barrel before taxes. Factor in capital costs and producers are losing as much as $8 on every barrel they sell right now.

Oil sands observers think Total wants Fort Hills bad enough that it will pay up to buy out both UTS' and Teck Cominco's stakes in order to partner with Petro-Canada one-on-one. In that setup Petro-Canada would likely oversee the bitumen recovery operations, while Total would build the $10 billion upgrade, which partially refines the bitumen. Petro-Canada's chief Ron A. Brenneman declined to comment on Total's potential involvement in the Fort Hills project.

Total plans to invest $14 billion worldwide this year and has earmarked $10 billion for oil sands over the next decade. If Total's oil sands history is any guide, de Margarie will end up increasing his bid for UTS. In 2005 Total bought into the Deer Creek project for $1.5 billion, 25% more than its original bid, while in 2008 it sweetened its bid for Synenco 14% to $500 million.

Those deals were set up before the bottom dropped out of oil prices. The industry is watching Total's hostile UTS bid carefully because it is the first significant takeover attempt of this downturn.

If and when it goes through, a cascade of deals is likely to follow. Oil giants BP, Royal Dutch Shell and ExxonMobil plan to invest upward of $30 billion apiece this year to gather assets, either through the drill bit or through buying outfits that run out of cash and refinance options.

"When the temperature starts heating up in Houston, so will the deals," says a long-time M&A advisor to oil companies. He expects at least 20 notable takeovers this year. "We will see consolidation at all levels."

The moment of truth for many will come at the end of March, when banks recalculate the value of oil companies' reserves. That value determines a company's borrowing base--that is, the amount of loans banks are willing to extend the companies. Those reserve values in many cases are half what they were a year ago; that means banks are likely to demand immediate repayment of some loans. Without enough cash or refinance options, companies will put their assets or themselves on sale.

Other analysts suggest that likely small-cap takeout targets include Rex Energy, Stone Energy, Delta Petroleum and ATP Oil & Gas, all of which have been struggling with liquidity issues and trading near lows. But these companies are too small to interest the international super-majors, who require larger prey. This is why the size and scale of oil sands projects are so attractive.

Considering the price environment, it's good for Roach that UTS' projects are just in the development stage. With $280 million in cash he says he can wait three years for the market to turn or a better bid to come along. "We don't need financing, that's the absurd thing about this situation."

But he knows there's a danger in waiting; if oil is still $40 in three years, Roach will be a beggar, not a chooser. So he's keeping an open mind. "We have absolutely no bad blood with Total," he says.

EUROPE / MIDDLE EAST

EUROPE

American Drilling Techniques may Migrate Overseas

With one eye cast toward home, giant European energy companies are investing billions in U.S. natural gas and oil fields where huge, hard-to-get reserves have been unlocked with new drilling technology.

That technology is the prize in Europe, where gas production has declined and where an international utility dispute recently left people in more than a dozen European countries shivering in unheated homes.

Europe’s natural gas supply is routed through Ukraine from Russia. Russia supplies about one-quarter of the EU’s natural gas, with 80 percent of it shipped through Ukraine. A rift between the two nations left more than a dozen European countries with little or no gas for two weeks last month.

Declines in European gas production, has potentially made the new techniques used in the U.S. even more pivotal.

At least three European oil and gas giants are developing or have bought interests in oil and gas shale projects in the U.S. — Norwegian oil company StatoilHydro, the U.S. unit of British oil company BP Plc and French company Total.

StatoilHydro and BP have agreed in recent months to pay billions of dollars for stakes in shale gas projects from the top U.S. producer of gas, Chesapeake Energy. Total has bought a 50 percent stake in a U.S. company exploring for oil shale in the Rocky Mountains.

“Given the magnitude of oil shale resources we believe that this project has an important long-term potential for global energy markets,” Yves-Louis Darricarrere, Total’s exploration and production president, said in announcing Total’s deal with American Shale Oil.

In the U.S., gas production from shale dates back to the 1800s. But the gas, tightly locked in rock formations, had been extraordinarily expensive to extract. That began to change about 15 years ago as producers developed new techniques such as horizontal drilling, where the drill is turned in a right angle to bore into a gas reservoir horizontally.

Gas from shale now amounts to about 5 percent of total U.S. production, according to the Gas Technology Institute.

If the same technology works in Europe it could free up an enormous amount of energy, and potentially provide a buffer against cross-border disputes to the east.

StatoilHydro bought into Chesapeake Energy’s massive Appalachian Marcellus shale project for $3.37 billion in November. Executive Vice President Rune Bjornson said at an energy conference this month in Houston that StatoilHydro wants to bring new drilling technology to other regions of the world.

If the race to duplicate drilling success in the U.S. is on, few companies are talking about it.

Aubrey McClendon, co-founder and chief executive of Chesapeake, the largest natural gas producer in the U.S., said, “I doubt we will trumpet it as I think the combination of their international stature and presence and our knowledge of gas shale would do nothing but attract competition.”

But it has become abundantly clear since the two weeks in January that Europe’s energy security has been diminished since the break up of the Soviet Union.

Buying into the technology in the U.S. makes sense and could spare European companies years of development, said Don Hertzmark, an international energy expert.

U.S. companies stand to expand through new markets in Europe if the new techniques work, and many experts believe that they will.

Energy companies are now funding a six-year study to locate gas deposits in Europe and to determine if they can be exploited.

“The companies that are involved here — they’re not beginners,” said Brian Horsfield of the GFZ German Research Center, which is heading the study. “It could come online within three years if it turns out these gas shales really are as prolific as we’re led to believe.”

Horsfield, a professor of organic geochemistry, said companies already have acquired land rights throughout Europe.

“The shale gas, if it were to be economic here, is very close to the user,” Horsfield said. “That’s one of the selling points, certainly, of our project on a nonscientific basis. And the events of the last month or so have helped to stress that.”

European Commission President Jose Manuel Barroso said after the dispute between Russia and Ukraine was settled (the second dispute in recent years) that Europe must diversify its energy sources and supply route.

“It was utterly unacceptable that European gas consumers were held hostage to this dispute between Russia and Ukraine,” he said.

ISRAEL

Over 50 Percent of Israeli Waters to be Explored for Oil

Fifty-four percent of Israeli waters off the coast will soon be divided up among several companies to search for natural gas and crude oil.

The Crude Oil Council within the National Infrastructures Ministry recommended issuing an additional 20 licenses on February 26, the ministry announced.

Following the success of the Tamar 1 find of a large quantity of natural gas off the coast of Haifa, the council recommended further exploration in the hopes of finding more fossil fuels.

After several years in which less than 10% of Israel's waters were being explored, the ministry has been steadily increasing licenses for exploratory expeditions.

Council head Dr. Ya'acov Mimran said at the opening of the meeting that there was a 40% chance of a 20 billion-cu m find at the Dalit drilling site in the Michal licensing area.

The council also recommended issuing a license to Negev Oil and Shale to produce shale oil in the Rotem area in the South.

All licenses must be approved by the minister and the relevant legal authorities within the ministry.

JORDAN

Jordan to Sign $20-25 BlnOil Shale Deal with Shell

The Jordanian government has concluded negotiations over an agreement to produce oil from oil shale at lower underground levels with Shell, a senior official said on February 24.

In December, the Natural Resources Authority (NRA) forwarded to the Cabinet the commercial deal it initially signed with the Royal Dutch Shell Oil Company to tap the Kingdom's vast amounts of oil shale.

Under the agreement, the first commercial quantities of oil extracted from oil shale will be produced within 12-20 years from the date the agreement is signed between both sides, Minister of Energy and Mineral Resources Khaldoun Qteishat told reporters after a weekly Cabinet meeting.

Shell will use its patented In-situ Conversion Process, under which the ground is heated over several years, to extract oil shale in oil form.

He said the initial figure of direct investments the project is expected to attract range between $20-25 billion, adding that Shell will spend around $430 million during the project's initial phases of implementation, which focus on assessment of the project and its expected revenues.

The Cabinet referred the draft agreement to be studied thoroughly by an ad hoc ministerial services committee before it is discussed again by the Council of Ministers and then endorsed through constitutional channels, Qteishat said.

Parliament is now in recess. The minister did not say if the deal would be referred to the lawmakers during an expected extraordinary session or will wait till the ordinary session in the fall.

He added that according to the feasibility study, the project is expected to provide the amount of $200 million annually, in addition to revenues generated from royalties and taxes on produced oil which will be calculated on the basis of market oil prices.

According to official figures, some 40 billion tonnes of oil shale exist in 21 locations near the Yarmouk River, Buweida, Beit Ras, Rweished, Karak, Madaba and Maan districts.

Moreover, Qteishat said the Estonian company, Eesti Energia, with which the government signed an agreement in August 2008 to invest and produce electricity from burning oil shale is due to provide the government with a comprehensive offer to invest in this sector within 30 months of signing the agreement.

According to Eesti Energia's feasibility study, released earlier in May, there is a potential to produce 36,000 barrels of oil a day from just one of the Kingdom's locations rich in oil shale.

"Jordan has a very strong potential. There are plentiful resources, although it needs further studying and, importantly, it is easily mineable," Harri Mikk, a member of the Eesti Energia board of directors, said in a previous statement to The Jordan Times.

"Jordan can easily produce hundreds of thousands of barrels a day from oil shale, perhaps a million barrels a day, potentially," he added.

Qteishat told reporters the government has invited six international oil companies to invest in the extraction of oil through a process of distillation of oil shale quantities located on the surface of the earth.

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