Royal Dutch Shell PLC will wait until the economics is right before advancing its oil sands and floating liquefied natural gas projects, its outgoing chief executive said June 8.

"If I feel that by waiting, costs will be lower, I prefer to wait," Chief Executive Jeroen van der Veer said in response to a question from Dow Jones Newswires. "Because oil sands are projects built for decades. Over time, I am convinced, the Canadians will have more capacity to build projects."

He said he wouldn't be surprised if the Cambridge Energy Resources Associates index, which measures construction costs in the energy industry, falls to 200 this year.

The index surged to 240 in the third quarter of 2008 from 110 in 2004 as the market overheated, he added.

This led the company to shelve some projects although the Anglo-Dutch major still has one of the biggest capital investment programs in the industry at $31 billion-$32 billion this year.

Projects that were shelved included Carmon Creek and the Athabasca oil sands expansion in Canada; Mars B, an oil project in the Gulf of Mexico; and the Pierce field in the U.K.

"The extent to which costs will fall further will be subjected to negotiations between ourselves and contractors," van der Veer said on the sidelines of the Asia Oil and Gas conference.

However, news that Petro-Canada (PCZ) may go ahead with its project could jeopardize Shell's wait for lower costs. "I think that is bad news...but that's how the world works."

Estimated costs for Petro-Canada's delayed Fort Hills oil sands mine have sunk 30% to below C$10 billion and the company expects to generate a double-digit return with oil prices at $60 a barrel, the company's chief executive, Ron Brenneman, said in late April.

Nymex crude futures have rebounded from their lows earlier this year to near $70 a barrel. They were trading at $67.47 a barrel at 0650 GMT.

Shell has also put on hold its plan for a floating LNG project in the Asia-Pacific region due to high construction costs.

The CEO said though there are many small gas fields far away from coasts, "these projects need to be economically viable."

Shell expects energy demand to double between now and 2050 and has targeted unconventional energy sources, including oil sands, gas-to-liquids and other alternative fuels, to account for about 15% of its total mix of oil and gas sales by around 2015.

van der Veer has also shrugged off resource nationalism which surfaces whenever oil and gas prices surge.

"If I look back at the last 20 years, we always have more investment opportunities than the capital to spend. So, I'm not concerned that we will run out of opportunities even if the government has the upper hand."

AMERICAS

U.S.

Congressman Hinchey wants Oil Companies to Reveal Chemicals used in Oil Shale “fracking”

With the potential of widespread drilling of the Marcellus Shale in western Sullivan County and other areas of New York and eastern Pennsylvania, Congressman Maurice Hinchey said June 4 that he and a colleague intend to file legislation that would force oil companies to reveal what chemicals are used in a controversial drilling practice.

Hinchey and Congresswoman Diana DeGette of Colorado say they will introduce a bill that would repeal a 2005 Bush Administration energy law that excluded hydraulic fracturing from the Safe Drinking Water Act regulations.

In Hydraulic fracturing, or “fracking,” fluids are injected at high pressure into underground rock formations to blast them open and increase the flow of fossil fuels.

Hinchey says some of these chemicals include diesel fuel, benzene, industrial solvents, and other carcinogens and endocrine disrupters. Companies should be compelled to fully disclose the content and percentages of each substance in the fluid, he said.

The bill is opposed by the oil and gas industry. Industry groups quoted by The Associated Press are concerned that this would open the door to more federal oversight, and slow down or stop drilling for unconventional sources.

Oil and gas companies say the bill would lead to more permitting, a standard requiring higher water quality for fracking fluid and additional testing, all of which would drive up costs.

Companies also say that by identifying the substances in the fluid, they might be forced to reveal protected trade secrets.

But, Hinchey and DeGette said during a conference call the oil industry claims were overblown to scare people. Without more oversight drilling could be “potentially very dangerous” to residents, they said.

“We need to make sure wells are not contaminated and water reservoirs are not contaminated and water continues to be safe and secure,” Hinchey said.

KKR Invests $350 Mln in Gas Explorer, East Resources Inc

Kohlberg Kravis Roberts & Co. has invested about $350 million in East Resources Inc., a privately held company engaged in natural-gas exploration and development in a rock formation stretching from West Virginia to New York.

East Resources, based in Warrendale, Pa., is one of the biggest players in the Marcellus Shale, with control of 900,000 acres. KKR's investment, structured as debt convertible into a substantial minority stake, will help East Resources reduce debt and develop its reserves. The company, which has 230 employees, already has existing oil-and-gas production properties in the region.

The investment by KKR is among the largest in the region and follows several similar private-equity bets. Also, early in June, Morgan Stanley Private Equity acquired a majority stake in Triana Energy Investments LLC, a Charleston, W.Va., natural-gas play in the area. In November, Avista Capital Partners agreed to invest up to $150 million alongside Carrizo Oil & Gas Inc. to acquire and develop acreage in the Marcellus Shale.

The cash infusions come as many gas producers are scrambling for cash. Fields like the Marcellus Shale are expensive to develop, requiring producers to drill hundreds of small wells for more than $1 million apiece.

"This investment from KKR allows us to continue our business on a larger scale" when bank borrowing is hard, said Terrence Pegula, the chief executive of East Resources, which he founded in 1983 with $7,500 of borrowed money, much of it from his parents.

Most small producers have far outspent their cash flow in recent years, relying on borrowed money in hopes of big returns in future years.

With banks reluctant to lend money for traditional buyouts, private-equity funds are using minority investments to put their clients' money to work. The small scale of the East Resources deal shows how much the deal-making environment has changed since 2007, when KKR made what was then the largest leveraged buyout ever: the purchase of Texas power utility TXU Corp. for $32 billion.

Natural-gas producers have been hit hard by tumbling gas prices, which have fallen to less than $4 per million British thermal units from more than $13 last July. Both oil and natural-gas prices have been driven down by slumping demand for energy because of the slow economy.

But unlike oil, natural gas is also suffering from an excess of supply, the result of a drilling boom spurred by rising gas prices and easy credit. Huge gas discoveries in Texas, Louisiana, Pennsylvania and elsewhere have reshaped the industry, reversing a U.S. production decline many thought was permanent.

Low prices have made many drilling projects uneconomical, and producers have sharply reduced their drilling activity. The number of rigs drilling for natural gas in the U.S. has plummeted to 700 from a peak of 1,606 in September, Baker Hughes Inc. reported in June.

But the Marcellus Shale has bucked the trend. There were 33 rigs operating in Pennsylvania last week, up from 27 in September and 20 a year ago. The Marcellus has benefited from big production and relatively low costs, which have made wells profitable even though prices are low.

Raytheon Tests same Carbon Sequestration Technology Used to Increase Oil from Shale Production

Raytheon says it is testing a leak-proof method of keeping sequestered carbon dioxide buried deep in the ground — using some of the same technology it developed to increase production of oil from shale.

The latest sequestration method involves encasing the gas in gel, pumping it underground, and then heating it with microwaves until the gel solidifies. The extraction technology, for its part, involves heating the shale with microwaves before pumping liquid carbon dioxide into the formations to separate kerogen, an organic precursor of oil, from the rock.

In both instances, Raytheon partnered with CF Technologies, of Hyde Park, Mass. CF Technologies specializes in so-called supercritical fluids, substances that share properties of both liquids and gases when subjected to high pressure and temperature. Carbon dioxide is commonly used as a supercritical fluid.

The oil-from-shale technology, which Raytheon says yields four or more barrels of oil for every barrel expended in the process, was sold in January to Houston-based Schlumberger, an oilfield services provider. Conventional methods typically yield half as much, Raytheon says.

The potential is huge. The largest known oil-shale deposits in the world are in the Green River Formation, which covers portions of Colorado, Utah, and Wyoming, according to a 2005 Rand report. Estimates of the recoverable oil resources within the Green River Formation; range from 500 billion barrels to 1.1 trillion barrels, according to the report.

The paradox of using similar technology to both release oil and sequester carbon dioxide is not lost on John Cogliandro, a senior program manager at Raytheon’s Tewksbury, Mass.-based Integrated Defense Systems unit, which is heading the project. “It’s a good business,” Mr. Cogliandro says. “If the U.S. was able to get energy from shale here, we could cease our imports.” At the same time, more land could be used for CO2 sequestration, including earthquake-prone tracts of earth, he says. “Now that CO2 sequestering is in vogue, they pump CO2 down into the ground, cap the well, and then run away and hold their breath,” says Mr. Cogliandro, of competing sequestration methods. “If the topology is right, it will stay there. But if there is an earthquake, it may seep out very slowly—or not so slowly.”

Raytheon envisions the sequestration technology being used at depleted shale fields and abandoned oil wells in the United States, says Mr. Cogliandro. “Our chemistry works well there.”

However, the American market for CO2 sequestration is slow, says Mr. Cogliandro. “I think that the U.S. market will form, but it is behind the European market,” he says. As such, Raytheon is looking at “other types of geological formations where this would work well,” including in Europe and Asia, he says.

In any case, it will be at least a few years before Raytheon’s sequestration method has any impact. “The process has not been tested at a commercially representative scale, and is still considered high risk, however, and therefore requires further development before it can be fielded,” Mr. Cogliandro says.

Magellan Energy Announces Acquisition of Lankford Lease in Morgan County, Tennessee

Magellan Energy Ltd., an independent oil and gas company, announced that it has signed a participation agreement with TMD Energy for the Lankford Lease in Morgan County, Tennessee. The lease/agreement consists of eleven wells that are currently producing natural gas.

TMD Energy Inc, will be the operators of the lease. The acquisition of this lease has occurred at an opportune time, as operators in this area are now able to get their gas to market via the new compressor set in by Citizens Gas. The compressor blends the gas from all area producers thereby resolving the high BTU issue that previously prevented producers from selling their gas. The eleven wells on the property produce gas from the Monteagle formation and are currently tied into a collection system, which is tied into Citizens Gas Utility District.

The operators, TMD Energy Inc., will work with Magellan Energy to ensure that the wells continue to produce natural gas and additional revenues for both parties. Magellan has an option on this lease to frac two shale wells in the future, which would increase the gas production per well on a daily basis. These two wells will be relatively easy to frac as they are located on the thin exposed part of the Chattanooga Shale in Eastern Tennessee.

With gas production from a total number of twenty-four producing wells, Magellan will continue to execute its business strategy of acquiring additional gas and oil leases. Magellan Energy is embarking on a new era devoted to achieving a profitable future for their company.

Magellan Energy is actively acquiring oil and gas leases, producing properties, mineral rights, and surface interests in Tennessee and Oklahoma. Once acquired, the company intends to develop each property to maximize the income from each property by re-establishing production, refurbishing and improving the existing production and operations.

Dallas’ Exco Resources to Open Haynesville Shale Office

Dallas-based oil and natural gas company Exco Resources Inc. will officially open a new field office in the Haynesville Shale June 26 and will break ground on a new Haynesville Shale gas gathering and treating facility in Louisiana to accommodate all of the work the company is doing in the gas-rich shale.

The new field office is in Grand Cane, La., about 30 miles south of Shreveport.

Exco Resources has nine horizontal wells and eight vertical wells drilled and completed in the Haynesville shale play, the company said. Exco intends to complete 21 more horizontal wells by the end of this year.

“We are very excited about the success we have achieved in the Haynesville Shale and have committed over two-thirds of our 2009 drilling and completion budget to continue developing the 85,000 net acres we have in the play,” said Doug Miller, chairman and CEO of EXCO Resources. “In addition to our production and development plans, we are committed to spend over $100 million in 2009 on our midstream business to add treating capability and throughput capacity in excess of 500 million cubic feet of natural gas per day by early 2010 in our Haynesville shale area.”

Big Haynesville Shale Leases Shut Out Small Independent Firms

The Haynesville Shale injected nearly $4 billion into the northwest Louisiana economy last year. But local oil and gas firms say they're shut out.

Small independent companies can't afford the expensive horizontal wells needed to drill into the natural gas deposit. And David Fite and Tim Marshall say they can pay only a few hundred dollars an acre for leases - not the thousands shelled out during the boom of 2008.

Fite says making a profit at $150 an acre is hard enough, let alone the $10,000 an acre that landowners now want.

Joe Anderson, vice president of Nadal and Guzman North Louisiana, says typical lease bonuses used to run $75 to $250. He says leases for conventional plays now run $100 to $500 an acre.

He does say that it's dropping gradually, with the sinking price of natural gas.

Oil and Gas Industry Spokesman Discusses Marcellus Shale Issues including Gas Extraction Tax

The economic boom that the Marcellus Shale natural gas formation could bring to Pennsylvania could be substantially slowed if an extraction tax is enacted on it, according to the executive director of the Independent Oil and Gas Association of Pennsylvania.

Lou D'Amico, also the co-director of the Marcellus Shale Committee, told the editorial board of the Herald-Standard that taxing oil always sounds good, but taxing natural gas would "all but ends shallow well production" and would slow down Marcellus Shale gas production.

State Rep. Bill DeWeese, D-Waynesburg, has introduced a bill that would allow the natural gas brought from shale to have value.

The idea to tax the natural resource is on the heels of the movement to tap into the gas reserve, which inhabits a substantial portion of the state, including southwestern Pennsylvania.

D'Amico said southwestern Pennsylvania is currently the most active drilling area, specifically Washington, Fayette and Greene counties. He said half the producing wells in the state are in the tri-county region.

Last year companies were paying $3,000 an acre for leasing bonuses, D'Amico said.

"We're going to be creating millionaires in Pennsylvania," he said of the amount of money that could be made by property owners.

D'Amico said, however, that it could take companies extracting the Marcellus Shale gas reserve three to five years to turn a profit and it would be nice to get a profit before the state starts taxing it.

The formation is expected to create 100,000 jobs over the next decade. Some of the needed jobs include geologists, drillers, equipment operators, surveyors, engineers and landsmen.

"It's a big job generator and we need to develop the workforce," D'Amico said.

D'Amico said the Barnett Shale formation in Fort Worth, Texas, is 5,000 square miles, which is substantially smaller than the 95,000 square miles that encompasses the Marcellus Shale. The Marcellus formation extends from southern West Virginia through Pennsylvania to New York.

He said the Marcellus Shale could make Pennsylvania "the Saudi Arabia of natural gas."

During a presentation on the Marcellus Shale, D'Amico said currently Pennsylvania imports 74 percent of the natural gas that is used here. He said the new horizontal drilling technique for Marcellus Shale wells has a smaller footprint than the vertical wells because up to 24 wells can be drilled from one pad.

A horizontal well can be drilled 5,000 feet, and D'Amico said most wells are 3,000 feet deep.

D'Amico said companies must have permits to use the water for the wells.

He said at the peak production, about 30 million gallons per day will be used, which is substantially less than other industries, including coal mining. D'Amico said one power plant uses 60 million gallons per day.

Also, D'Amico said because hundreds of loads of equipment will be used for the wells, the roads would be improved along the way.

For horizontal drilling, first companies drill vertically and then branch off from the original drill site in horizontal directions. Vibrations are sent through the pipes to fracture the shale. D'Amico said shale is compressed mud with little permeability. The shale must be fractured for the gas to be extracted.

D'Amico said to "frac" the shale, a combination of 90 percent water, 9.95 percent sand and .05 percent chemicals is used.

He said the gas will travel up to the end of the shale formation but not out of it, and thus the drilling process will not contaminate water. The drilling process includes three layers of pipe.

He said wells one mile deep in the ground are well isolated from surface water, adding that everything that is done is regulated by the state Department of Environmental Protection.

While there aren't currently enough trained people for the future jobs in the industry in the state, D'Amico said the goal is to train people in Pennsylvania.

Regarding questions about neighboring gas wells extracting gas from other properties;

D'Amico said there is one way to tell which property the natural gas is coming from and the "law of capture" states that the owner of the gas well that captures the natural gas gets the royalties from it.

Although industry representatives declined to disclose how much they are paying for leases or royalties, a spokesman from Atlas America said in April the company discontinued drilling shallow wells. Marcellus Shale wells are generally much deeper.

Officials estimated that the average lifespan of a Marcellus Shale well could be 20 to 30 years.

Rex Energy, Williams Sign $33 Mln "drill-to-earn" Pact to Continue Developing Marcellus Shale

Independent oil and gas company Rex Energy Corp. has signed a $33 million deal with Williams Cos. to continue developing the Marcellus Shale in Pennsylvania.

Under the deal, Williams will acquire a 50% stake in Rex's leases in Westmoreland, Clearfield and Centre counties in Pennsylvania, which cover about 44,000 acres.

The "drill-to-earn" structure of the pact means Williams must earn its stake by bearing 90% of all the costs incurred in the drilling and completion on all wells jointly drilled in the areas until it has invested $74 million - $33 million on Rex's behalf and $41 million on its own share of the wells.

Williams must fund that by Dec. 31, 2011 or pay cash to Rex for the carry amount that has not been funded.

After Williams funds the initial carry, the two companies will share the joint venture costs according to their stakes, expected to be 50-50. Williams has also reimbursed Rex $3.6 million for its share of some expenses incurred in the project areas that Rex had previously paid.

Rex will continue to operate the project areas through the end of the year, and Williams will operate them afterwards.

Rex Chief Executive Ben Hulburt said Williams' "demonstrated exploitation of gas shales and proven technical strengths allow us to accelerate our activities in the Marcellus Shale, while at the same time conserving our capital."

Meanwhile, Rex also said it had closed its purchase of the remaining 50% stake owned by its joint-venture program in areas of Butler County, Pa., more than tripling its acreage in the area. The new acres are located near the company's Marcellus Shale wells and its natural gas processing plant.

Three-way Battle for Colorado’s Yampa River Rights Creates Conflict

The Yampa River runs in the northwestern section of Colorado through Dinosaur National Monument, and is coveted by a powerful energy company, western cities and recreation advocates.

Unlike most western rivers, which have been dammed, diverted or otherwise appropriated, the Yampa runs wild.

And, deep below the Yampa lurks oil. "It's three times what the Saudi Arabians currently have in proved reserves, and it presents a significant opportunity to energy security in the U.S.," says Tracy Boyd, a spokesman for Shell Oil.

The company has filed for the rights to divert a substantial amount of water from the Yampa just a few miles upstream from the dinosaur monument. It would be stored in a massive reservoir for future oil shale mining, a controversial and still unproven technology. Shell says it wants to inject the water into the ground to unlock oil from shale.

"This is a long-term commitment to prudently and slowly and properly address all the technical questions and environmental and social questions about oil shale development, so it can be done the right way, at the right time," Boyd says.

But right now, a lot of people have questions about how much water this will take, and whether there will be any left for everyone else. Northern Water is the agency that secures water supplies for the booming Colorado Front Range north of Denver. Northern has also proposed to take water from the Yampa near Shell's site. But it wants to pipe it 225 miles up and over the Continental Divide to the eastern side of the Rockies, where most Coloradans live, despite the lack of water.

"We think we need the water over here is just purely due to population growth. Unless they put armed guards at I-25 and I-70, people are going to continue to find this a desirable place," says Carl Brouwer, a project manager with Northern.

Brouwer says a new water supply might also stop the drying-up of farms on the state's productive eastern plains — where landowners have been selling their lucrative water rights to eager developers. Thus agriculture, extractive energy companies and people who depend on this water are all battling for a piece of the Yampa.

And then there are the outdoor enthusiasts like Pat Tierney, who runs Adrift Adventures out of nearby Vernal, Utah. He says the Yampa's canyons are right up there with the Grand Canyon "in terms of outstanding beauty."

The Sierra Club launched its first nationwide environmentalist campaign in the 1950s. It successfully stopped a huge reservoir that would have dammed up the canyons in the monument. Tierney is mobilizing for a similar fight.

All the proposals for more water out of the Yampa will have to work their way through Colorado's complicated water court system. Meanwhile, everything is on hold while the state finishes up a long-awaited study on water supplies and the growing demand in Colorado.

Exxon Boosts Pipeline Capacity to Transport Oil Sands by 50%

Exxon Mobil Corp., the world's biggest oil refiner, boosted its capacity to transport crude from Canada's oil sands to refineries in Texas and Louisiana.

Exxon Mobil increased the capacity of its 1,381-kilometer Pegasus Pipeline by 50% to about 96,000 barrels a day, the Irving, Tex.-based company said in a recent statement.

The expansion followed a 2006 reversal of the flow on the pipe, most of which had been idle for four years amid slack demand for shipping. The conduit runs from Patoka, Ill., where several Midwest and Texas pipelines converge, to Nederland, Texas, which is near Houston.

Exxon Mobil didn't disclose how much it spent on the project, which involved upgrading pump stations along the route of the line, the statement said.

UK’s BG Group Buys Exco Stake for $1.06 Bln to Tap U.S. Shale Gas

BG Group Plc, the U.K.’s third- largest natural-gas company, bought assets from Exco Resources Inc. for $1.06 billion to develop its first U.S. shale gas project. Exco shares rose as much as 21 percent, the most since December.

BG Group acquired a 50 percent stake in 120,000 net acres in East Texas and northern Louisiana, the company said June 30 in a statement. The purchase includes part of the Haynesville Shale gas formation and adds 2.6 trillion standard cubic feet to BG’s resources, with current net output of 78 million standard cubic feet a day.

“We expect BG will use this shale gas to meet U.S. contract commitments, thereby releasing Atlantic basin LNG cargoes for higher-priced global” markets, said Oswald Clint, a London-based analyst at Sanford C. Bernstein & Co.

BG will compete with larger rivals including Royal Dutch Shell Plc, BP Plc and StatoilHydro ASA in the development of U.S. shale deposits. It has also expanded oil and gas resources in Australia and Brazil and forecasts production will rise between 6 percent and 8 percent a year and reach 1.6 million barrels of oil equivalent a day in 2020.

“This alliance brings material new resources and supply to our existing U.S. business at a competitive price and in a prime location at the heart of the world’s largest gas market,” Chief Executive Officer Frank Chapman said in the statement. “The transaction increases BG Group’s exposure to long-term unconventional gas resources and skills.”

BG has been marketing liquefied natural gas in the U.S. and supplied 55 percent of all LNG cargos imported into the country in 2007, according to its Web site. The company also generates power in the U.S. to customers in New England.

A total of $655 million will be paid on completion, plus $400 million as a carry of 75 percent of Exco’s future costs to develop the Haynesville Shale gas, the Reading, U.K.-based company said. The partners agreed to co-operate on further development and BG expects its production in the area will rise to 250 million cubic feet a day in 2012.

The British company will pay $19,000 per acre for the Haynesville Shale gas assets. It may also buy a 50 percent interest in gas-gathering and transportation assets from Exco for $249 million to supply the fuel to U.S.’s Midwest and Eastern regions.

“Recent deals in the shale gas play have been around $15,000 per acre,” said Bernstein’s Clint. “Hence this deal at $19,000 per acre could be viewed as expensive on that basis.”

The acquisition of the gas assets is conditional on the purchase of the transport infrastructure, BG said.

CANADA

Sonic Forms Heavy Oil Upgrader JV with Mirex

SONIC has entered into a joint venture agreement ("JV") with Mirex Energy Inc. to construct and operate the first PetroSonic heavy oil upgrader in Canada. Mirex is an oil production and services company operating in the Lloydminster region and will be the operating partner in the JV. The project will initially be designed for a 1,000 barrels per day (bpd) facility to be located on the Elizabeth Metis Settlement in Alberta. The PetroSonic facility will be designed to upgrade local heavy oil supplies to meet the minimum API requirements for Canadian pipelines.

Mirex will provide facilities for the installation and initially manage the operating contracts. SONIC will grant a license for its proprietary PetroSonic upgrader technology and manage the installation and start-up. Mirex and SONIC will be equal partners exclusive of any interest in the project by the financing partners. Capital financing for the project will be provided as debt and/or equity into the project.

This will be the first PetroSonic upgrader in Canada and will allow SONIC to fully implement the process in a modular plant design which allows the process to be run in various configurations to allow for process optimization and data. The PetroSonic upgrader is a low temperature and pressure process utilizing a SONIC reactor for de-asphalting and an oxidation process to further upgrade the oil. The economics of the project improve as the price differentials between heavy oil and pipeline specification -- predominantly viscosity and density driven. Successful operation of the first installation would anticipate expansion to 3,000 bpd on a self-financed basis.

The license granted to the JV is exclusive for all Metis settlements in Canada and allows Mirex and SONIC to expand the operations of the JV to other locations or to enter into new agreements for each location. Heavy oil will be supplied in part by related parties and supplemented by independent local production. Upgraded oil will be sold into the pipeline system.

Archie Collins, Chairperson for the Elizabeth Metis Settlement, commented, "We have a very successful partnership with Mirex and this project offers local oil producers, Metis and others alike, the opportunity to build our local oil processing facilities. We have plans for related oil services which may integrate very well with the upgrading facility."

Energy Invest Ltd. are reviewing the project under their marketing and financing agreement with SONIC, either to provide part of the financing for the project or as part of a more comprehensive financial proposal they have recently presented to SONIC. Local financial participation will also be accommodated. Energy Invest have identified several projects where they would like to utilize the PetroSonic upgrader technology. Energy Invest is also a major shareholder and fully supports this first project in Canada to ease the logistics of technical support. The project will commence with detailed engineering and permitting this summer. Preliminary engineering for the upgrader has been completed and design data from an extensive test program on Lloydminster oils is already available. SONIC and Mirex have made application under the Alberta Energy Research Institute program and the project is directly in line with recent initiatives by the Alberta Government to encourage more processing within the province. SONIC may also be eligible under other Canadian grants in place to improve efficiencies in heavy oil production.

Sinopec may Acquire Canada-based Addax for $8 Bln

Sinopec, the largest refiner in Asia by capacity, reportedly hopes to purchase a 100% stake in Canada-based Addax Petroleum Corp, which is engaged in the oil and gas businesses in Africa and selected countries in the Middle East, for up to US$8 billion, the South China Morning Post reported on Jun. 8.

Su Shulin, board chairman of Sinopec, has mentioned that the firm is seeking overseas mergers and acquisitions (M&A).

China National Offshore Oil Corp (CNOOC) and China National Petroleum Corp (CNPC), who are also interested in buying the Canadian oil enterprise, will likely submit bids of around US$4 billion for a stake in an oil field belonging to Kosmos Energy, which is also principally engaged in the oil and gas businesses in Africa, sources reported.

CNPC is also drawing up a plan to expand trade in oil sands with Canada, especially with Alberta, a western province of Canada. CNPC currently has 11 exploration rights on oil sands in Alberta.

Post Merger Suncor may Speed Oil Sands Development

Suncor Energy Inc's acquisition of Petro-Canada will create a company with enough heft to keep a lid on oil sands costs, slow development in the region, and check the spiraling inflation that, just months ago, threatened to sideline the resource.

Shareholders of both companies are set to vote on Suncor's offer of 1.28 shares for each Petro-Canada share. The value of that offer has climbed 20 percent to C$22.18 billion ($20 billion) from the original C$18.43 billion when the bid was launched in March as rebounding oil prices boosted Suncor's stock price.

Should investors and regulators approve, the merged company would be Canada's biggest oil and gas firm, the dominant player in the oil sands -- where reserves are second only to Saudi Arabia -- and own cash-generating oil fields off Canada's East Coast, in the North Sea and elsewhere.

"I don't see any reasons to think the deal won't be approved by shareholders," said Chris Feltin, an analyst at Tristone Capital. "The benefit that it brings to Suncor is a more diverse production base immediately ... Suncor can take (Petro-Canada's) cash flow and direct that toward its oil sands projects."

Investment in the oil sands region on northern Alberta collapsed late last year, when economic turmoil sent oil prices tumbling from more than $147 per barrel in July to under $40 by year end.

Irrational exuberance sparked by record oil prices was quickly replaced by widespread pessimism when credit markets dried up last year, the recession set in and demand for oil collapsed.

More than C$90 billion worth of projects were deferred, delayed or canceled outright after prices plunged.

Part of the reason for the downturn in investment was the cost of building new projects had soared, with budgets for some rising 50 percent in less than a year as companies competed for materials and a relatively small pool of skilled labor.

But some analysts estimate that labor and material costs have fallen to the point where a new oil sands project can turn a decent profit with oil prices at $60 per barrel, instead of the near $100 per barrel needed before the crash.

The cost drop is expected to help ramp up new oil sands projects. Indeed, Imperial Oil Ltd said last month it planned to take advantage of falling costs and announced plans to proceed with its C$8 billion Kearl oil sands mine.

But if more companies also decide to jump back in, labor could again be in short supply and costs could rocket back to the stratosphere.

However, after the merger, Suncor could have the heft to exert more control over costs than other companies have been able to manage.

Analysts say the merged firm will slow development of Petro-Canada's planned C$10 billion Fort Hills oil sands mine and instead concentrate on restarting construction to add two 68,000 barrel per day phases of its Firebag thermal project, which uses steam pumped into the ground to liquefy the tar-like bitumen so it can flow to the surface.

"All those projects are now suddenly in one portfolio and will be weighed against each other," said William Lacey, an analyst at FirstEnergy Capital. "Implicitly, because of that, the growth will slow down in the oil sands and the focus will improve."

After combining with Petro-Canada, Suncor will be able to stage development of its new projects, keeping the labor it needs to do the work at the lowest possible level.

"Consolidation positively benefits the oil sands by simply reducing the number of projects that will be built simultaneously," Andrew Potter, an analyst at UBS Securities wrote in a research note.

CAPP Forecasts Growing Oil Sands Production

The Canadian Association of Petroleum Producers expects Canadian crude oil production, including oil sands, to reach 3-3.3 million b/d by 2015.

"CAPP's production forecast indicates that even with delays due to current economic circumstances, oil sands production is expected to grow, although the pace of development has slowed," said Greg Stringham, CAPP's vice-president, markets and oil sands.

Oil sands production is expected to reach 1.9-2.2 million b/d by 2015, the forecast said.

CAPP’s latest forecast provides a growth case as well as an operating and in-construction case. The growth case expects total oil production will reach 3.3 million b/d by 2015, 4 million b/d by 2020, and 4.2 million b/d by 2025.

The operating and in-construction case represents minimum growth. It expects total oil production will reach 3 million b/d by 2015 and then decline gradually to 2.8 million b/d through 2025 due to reduced conventional production.

Pipeline developments now under way are expected to provide ample transportation capacity to meet long-term demand, CAPP said.

Financial crisis re-enforces our advantages.

Chevron Says Financial Crisis Re-enforces Advantages

Chevron Corp., which has projects in Newfoundland’s offshore and Alberta’s oil sands, said it could benefit from the financial crisis that is “holding hostage” competitors.

The San Ramon, California-based oil multinational said June 12 it expects costs for goods and services to come down as other companies slow down spending, easing pressures on ship yards and equipment manufacturers.

Chevron is a 27% partner in the $5.8-billion Hebron heavy oil project offshore Newfoundland, whose construction is due to ramp up after fiscal agreements with the province were finalized in August.

Chevron is also a 20% partner in the Athabasca oil sands project with Royal Dutch Shell PLC and Marathon Oil Corp. Shell said further expansions in the oil sands are being delayed until costs in Alberta cool down.

Other companies like Suncor Energy Inc., Petro-Canada and Nexen Inc. are delaying oil sands spending after oil prices dropped to half their summer highs and the credit crisis tightened credit availability.

“Our long-term view of prices of oil and gas has not changed,” George Kirkland, executive vice-president of exploration and production, told analysts while discussing third quarter results.

“This financial crisis re-enforces the advantages that companies like Chevron, with very strong balance sheets, (that) are not held hostage to getting loans. From that perspective I think it may actually be a benefit for us.”

Mr. Kirland said Chevron is likely to keep its investment plans in 2009 comparable to this year, when the company is expected to spend US$22.9-billion. Next year’s budget will be announced in mid-December.

Chevron, the world’s third largest oil company, reported a profit of US$7.8-billion for the period on strong oil prices, up from US$3.9-billion a year ago.

Connacher $298 Mln Oilsands Project Resumes

Connacher suspended construction on the US$298-million (C$345-million) Algar project late last year.

A stalled oilsands project in northern Alberta has been taken off the shelf, investors attending a presentation by Connacher Oil and Gas Ltd. learned June 16.

President and chief executive Dick Gusella interrupted a presentation at the Canadian Association of Petroleum Producers to read an e-mail saying that a $200-million bond market issue had been completed and that the Connacher board had approved immediate reinstatement of the Algar in situ oilsands project.

"The money is in the bank," a beaming Gusella announced, noting that the bond issue, when added to a recent equity sale, gives the company $460 million on which it can draw.

The 10,000-barrel-a-day project will get off to a quick start. About $150 million had already been spent on it when it was suspended in December, leaving $200 million to be completed over the next nine months.

Gusella said many of the component modules have already been constructed and are in storage, ready to be installed on the property.

Algar is to be in production within 18 months, he said.

The company has a goal of reaching 50,000 barrels per day from its Great Divide oilsands project by 2015.

Tamm Oil & Gas Acquires Additional 5,000 Alberta Acres

Tamm Oil & Gas has taken an extra 5120 acres of oil sands leases in Alberta's Peace River via a share deal with Petrocorp.

The move boosts Tamm's holdings in the Manning area to more than 35,000 acres, it said in a statement released June 16.

In exchange for the leases, Tamm has issued 1 million shares in full consideration to Petrocorp.

"The new lands acquired are part of the overall strategy to acquire oil sands leases in the area, prior to commencing development. In the last 30 days, Tamm has increased its land base by over 50%," company director Don Hryhor said.

Syncrude Canada Coker Unit Returns to Operation

Maintenance work on one of Syncrude Canada Ltd's main processing units took longer than expected, but it is returning to operation, the joint venture's largest owner said on June 9.

Canadian Oil Sands Trust said crews were resuming production from the 8-3 coker unit that was taken out of operation on March 17 for what was expected to be about two months of planned maintenance work.

The work on the unit in Fort McMurray, Alberta, "took longer than anticipated, and the associated costs are correspondingly higher than budget," the trust said in a statement that did provide financial details.

Syncrude, which can produce as much as 350,000 barrels a day, has two other coker units that turn tar-like crude from the oil sands into refinery-ready light oil. It is the world's largest producer of synthetic oil.

The trust's partners in the Syncrude venture are Imperial Oil Ltd, Petro-Canada, ConocoPhillips, Nexen Inc, Nippon Oil Corp, Mocal Engery Ltd and Murphy Oil Corp.

Alberta Oil Sands Output Pegged at 3 Mln bpd by 2018

Output from Alberta's oil sands region, the largest crude reserves outside the Middle East, will rise to 3 million barrels per day by 2018, the province's energy regulator said on June 10, even as it slightly lowered its estimate of the region's reserves.

In its annual estimate of the province's oil and gas reserves, Alberta's Energy Resources Conservation Board (ERCB) said it expects production of the tar-like bitumen contained in the oil sands to more than double over the next nine years, from about 1.3 million barrels per day last year.

The forecast is more bullish than one released recently by the Canadian Association of Petroleum Producers. Cutting its production estimate for the third time in a year, CAPP estimated that by 2020, oil sands output would only be 2.9 million barrels per day in its most optimistic case.

Both the CAPP and ERCB estimates were based on current and planned projects in the oil sands region of northern Alberta.

The board could not immediately account for the discrepancy between the two forecasts.

The regulator also lowered its estimate of the remaining recoverable oil sands reserves to 170.4 billion barrels from its 2008 estimate of 172.7 billion barrels due to more detailed technical data.

Alberta's conventional oil reserves were pegged at 1.5 billion barrels, down 3 percent from last year and continuing a multi-year decline as new oil discoveries replaced only 77 percent of production. However the ERCB estimates that 3.7 billion barrels of oil will ultimately be found and recovered in Alberta through conventional methods.

Total output of conventional and oil sands crude in 2008 fell 1 percent to 1.85 million barrels per day as planned and unplanned maintenance shutdowns at oil sands projects crimped production.

The ERCB said that 2008 natural gas production fell to about 12.05 billion cubic feet per day, down 6.5 percent from the previous year as only 6,800 wells were drilled, a 14 percent drop from 2007.

Enbridge to Move Kearl Oil sands Production to Edmonton

Enbridge Inc. announced an agreement with Imperial Oil Resources Ventures Ltd. and ExxonMobil Canada Properties to transport blended bitumen from the Kearl project in the Athabasca oil sands region about 70 km northeast of Fort McMurray, Alta., to the Edmonton area.

Imperial announced last month that it would proceed with the first phase of the C$8 billion Kearl oil sands project, planning to develop it in three phases with production from the first phase beginning in late 2012 at an average 110,000 b/d of bitumen. It expects peak production of about 300,000 b/d of bitumen once all three phases are complete.

The agreement comes on the heels of a report earlier this month from Alberta’s Energy Resources Conservation Board lowering forecast bitumen production through 2018, while at the same time increasing the number of townships in the Athabasca region in particular suitable for mining.

Patrick D. Daniel, Enbridge president and chief executive officer, said the estimated cost of the pipelines and related facilities would depend on finalization of project scope, detailed engineering, and regulatory approvals.

A pipeline from Kearl to near Edmonton would likely be more than 500 km long.

Enbridge to Develop Pipeline System for $7 Bln Kearl Project

Enbridge Inc., the biggest transporter of oil from Canada’s tar sands, plans to build a pipeline to haul crude from Exxon Mobil Corp.’s $7 billion (C$8 billion) Kearl project in northern Alberta to Edmonton.

The first phase will connect the Kearl oil-sands site north of Fort McMurray, Alberta, to Enbridge’s Cheecham terminal near Nexen Inc.’s Long Lake development, Paula Leslie, an Enbridge spokeswoman, said June 22.

The Calgary-based company hasn’t determined yet whether the Cheecham-to-Edmonton phase will require a new conduit or if Kearl’s production can be accommodated on one of Enbridge’s existing lines along that route, Leslie said. Exxon-controlled Imperial Oil Ltd. plans to begin pumping bitumen from Kearl in late 2012.

“Once we know the scope and volumes Imperial is anticipating from Kearl, then we’ll know what form the next phase from Cheecham will take,” Leslie said.

Kearl’s first phase could produce as much as 140,000 barrels of bitumen a day, Imperial said on May 26. Fort McMurray, the heart of Canada’s oil-sands industry, is about 470 kilometers (292 miles) from Alberta’s refining center in Edmonton.

Irving, Texas-based Exxon Mobil, the largest U.S. oil company, owns about 70 percent of Imperial, based in Calgary.

China's CNPC Seeks Alliance with Canada

China’s state-controlled energy giant, China National Petroleum Corp. (CNPC) is proposing a strategic alliance with Canada -- and particularly Alberta -- to help meet its energy needs, while helping Canada develop a new market for its oil.

Frustrated by its lack of progress in building a presence in Alberta, where CNPC and China’s two other major energy companies have made only small oil sands investments in recent years, the company said it is seeking the support of Canadian political leaders to help establish a major energy corridor linking Western Canadian supplies to the Chinese market.

"A larger commitment must be made to fully utilize our mutual strength," a spokesman for the company said in a key speech in Geneva May 4 to the Alberta Economic Forum, attended by Alberta Premier Ed Stelmach to promote investment in the province. "The opportunity is there. The question is action. China is prepared for the future and we see the potential Sino-Canadian relationship as a tangible, long-term mutually beneficial strategy."

CNPC said it would have much to gain from the development of an energy-rich Alberta, which it says could be "a place of best fit" for the country, the world’s second-largest energy consumer after the United States.

The speech received little attention in Canada, but Paul Michael Wihbey, president of GWEST, a Washington-based energy advisory that helped organize the Geneva event, said it was it was "a very serious proposal by the Chinese" that is being processed at very high levels of the U.S. government.

"I think it carries very significant implications at the economic, political and strategic level that could see Alberta and Western Canada emerge as an energy storehouse that sustains the wellbeing of the U.S. and Chinese economies," he said in an interview.

"In the process, I think a marvelous infrastructural development program could be sustained along that corridor from northern Saskatchewan, through northern Alberta, Edmonton and over to Prince Rupert in the harbor [where oil would be loaded on tankers for shipment to China]."

CNPC, the world’s largest company by market value, said Chinese companies have made investments in the Alberta petroleum industry, but "the situation of cooperation between Alberta and China right now is far from satisfactory."

The speech’s author, Han Hua, managing director of CNPC’s Alberta Petroleum Centre, said a stronger relationship could lead to more Chinese investment.

"Our company … will keep finding opportunities to invest more," he said. Canadian oil is expensive relative to other sources around the world, but he said technology breakthroughs, better financial regulation and policy could make it more competitive.

The company said it would like to see such an alliance formalized when Prime Minister Stephen Harper and Mr. Stelmach "make visits to Beijing this year." Spokesmen for the two leaders said there has been no confirmation that such a visit will take place.

Alberta’s political and energy leaders have repeatedly talked about the need to find new markets for the province’s oil, which is now exported exclusively to the United States and which could be disadvantaged under President Barack Obama’s aggressive new policies to reduce consumption of fossil fuels.

Alberta is very interested in greater economic co-operation with China and there have been ongoing discussions with CNPC, said Mark Cooper, a spokesman for the province’s intergovernmental relations department.

Chinese companies were expected to make multi-billion-dollar acquisitions about four years ago, but were discouraged by high acquisition costs, reluctance by oil sands producers to enter into joint ventures and Canadian government hostility. As well, reports that Chinese energy companies were on the verge of striking ambitious deals stoked U.S. concerns about China elbowing into the United States’ turf.

Mr. Wihbey said the initial response of the Obama administration to China’s renewed efforts for a stronger presence in Western Canada has "not been a negative reaction at all."

With the U.S. moving aggressively to reduce its consumption of fossil fuels, China could offer a new market not only for Canadian energy, but energy produced in the Western U.S. if the concept of an energy corridor is expanded to include U.S. Rocky Mountain states that are rich in unconventional oil and gas deposits, he said.

Shell says has Unplanned Maintenance at Scotford Upgrader and Refinery

Royal Dutch Shell Plc said on June 22 it is undergoing unplanned maintenance at its 155,000 barrel per day Scotford oil sands upgrader and its 98,000 bpd Scotford refinery near Edmonton, Alberta.

A spokeswoman for the company confirmed that the two facilities had unplanned work, but declined to say how much production was cut back by the outages or detail when the company expected the work to be complete.

Shell is the sole owner of the refinery. Chevron Corp and Marathon Oil Corp each have a 20 percent stake in the upgrader.

BioteQ Secures Funding for Research & Development for Waste Water Treatment including that Produced from Oil Sands Industries

BioteQ Environmental Technologies Inc., a leader in the treatment of industrial wastewater, has received a non-repayable contribution of up to $295,000 from the National Research Council of Canada Industrial Research Assistance Program (NRC-IRAP), a federally-funded program that supports the commercialization of innovative Canadian technologies. The contribution will support BioteQ's development program to apply the company's technologies to treat water for coal-fired power generating facilities and waste water produced from the Canadian oil sands. In addition, NRC-IRAP will also provide both technical and business-oriented advisory services.

Coal-fired power generating facilities and oil sands projects are large consumers of fresh water for their industrial processes. Both industries are under increasing regulatory pressure to reduce their water consumption and adopt new water recycling measures. However, the recycle of water often leads to the build-up of dissolved constituents including sulfate, metals, hardness, silica, and organics which can interfere with industrial equipment and hence limit the extent of water recycle without proper treatment. BioteQ aims to demonstrate that its suite of water treatment technologies can provide a cost effective and environmentally responsible solution for some of the water treatment challenges faced by the power generation and oil sands industries.

"We are pleased to secure funding support from NRC-IRAP," stated Brad Marchant, BioteQ's CEO. "This work will help BioteQ diversify its technologies and customer base, and provide new and sustainable water treatment solutions for the power generation and oil sands industries. NRC-IRAP was instrumental in the initial commercialization stages of BioteQ's core technology and we welcome their support towards expansion of our marketplace."

BioteQ is a water treatment company that applies innovative technologies and operating expertise to solve challenging water treatment problems. To date, the company has primarily served the mining industry, where it has built and operated 8 industrial scale water treatment plants at mine sites in Canada, the US, Mexico, Australia, and China, producing clean water that meets strict water quality criteria for re-use or safe discharge to the environment.

Canada Boosts Oilsands Reclamation with Research Grant

The provincial government has dedicated another $1.5 million to the University of Alberta for research on the environmental management of the oilsands.

The university's Oilsands Research and Information Network will use the grant to research the thorny issue of reclamation. The government is under increasing pressure to improve the environmental image of the oilsands and reclamation-- particularly of tailings ponds--has become a high priority. About 530 square kilometers of land have been disturbed by oilsands mining. About 65 square kilometers of that area is either reclaimed or in a reclamation process, although only 104 hectares have been government-certified as reclaimed.

Alberta Environment Minister Rob Renner said the grant will help show what's possible on the reclamation front.

"The outcome we're looking for is how we can continue to move the goalposts forward," he said June 17. "We can't require industry to do what is not possible, unless research shows there are better ways to deal with the environmental impacts of oilsands development that can be incorporated into regulations.”

Last year, the government gave the university's School of Energy and the Environment $3 million to help establish the network.

A lot of that money has yet to be spent, said Joseph Doucet, the school's director.

The problems are not easy, simple or one-dimensional, he said.

Doucet sees a need for involvement from many university departments, including engineering, business, law, native studies and science.

Decisions on projects will be made in the fall, Doucet said.

Oil Sands Delays Affect CAPP Output View

A spate of project deferrals in oil sands as energy and credit markets sputtered will mean another change to the Canadian Association of Petroleum Producers' oil production forecast, the group's president said on June 2.

CAPP is expected to release its updated outlook for Canadian output days, and its president, David Collyer, told the Reuters Global Energy Summit that shifts in project timing as a result of the downturn are the main variable.

"Broadly, you're not going to see a substantive change in overall production outlook. There's a bit of movement around timing of projects, which I think you'd expect in light of announcements that we've had from a number of operators," Collyer said.

He did not give any numbers for the much-watched forecast.

CAPP has said Canada, the largest oil supplier to the United States, can eventually achieve its target for long-term oil sands output growth, but it has been cutting its view of the production it expects by 2015.

Last June it reduced the outlook to 2.8 million barrels a day from 3 million as cost overruns and delays plagued the then-booming industry; then in December as oil prices fell to nearly $30 a barrel it cut it again to 2.4 million.

In all, more than C$90 billion ($83 billion) worth of Alberta oil sands projects were deferred, scaled back or canceled between October and January.

Since then only one, Imperial Oil Ltd's C$8 billion Kearl oil sands development, has begun construction. Imperial gave Kearl the green light last month.

Since mid-December, oil prices have doubled, settling at $68.55 a barrel on June 2, and some analysts have said the break-even level for new oil sands projects appears to have fallen to around $60 a barrel from $80-$100 last year.

Collyer said oil sands producers may coordinate efforts better when they rekindle their projects, within the limits of competition law, rather than return to the development rush that led to hyperinflation until last year.

Multibillion-dollar cost overruns were commonplace as the skilled workforce in Alberta was stretched and prices for materials like steel skyrocketed.

"There are some opportunities that might make better use of the labor pool and better use of some of the supply infrastructure, and where it's possible and legally allowed coordinate development activity to make better use of all of the resources and be more efficient overall," he said.

For the short term, companies are heartened by rising oil prices and improving credit markets, but stubbornly low natural gas prices are expected to temper a rebound in industry activity in western Canada, he said.

Brimming gas inventories across North America and weak demand have pushed prices to less than half last year's level, and western Canada's conventional drilling largely targets gas.

UTS Eyes Fort Hills Options as Suncor Joins Group

UTS Energy Corp has begun to plot out new ways to develop the delayed Fort Hills oil sands project but decisions must wait until Suncor Energy Inc closes its takeover of the operator, Petro-Canada, UTS's chief executive said on June 16.

UTS, which has a 20 percent interest in the Alberta oil sands development, sees cost advantages in shifting some of the processing to Suncor's massive northern Alberta operations, CEO Will Roach said.

But he has had no detailed discussions with Suncor on the project, one of several that were shelved when the industry downturn took hold in 2008.

Suncor Chief Executive Rick George has said he expects to examine all of Petro-Canada's assets after the $19.5 billion (C$22 billion) takeover is completed.

"First of all, we've got to understand where the project fits into the combined portfolio, and obviously we're pretty excited to see the pre-eminent oil sands operator take over the project," Roach said after speaking to an oil industry investor conference.

"There's a lot of opportunity here but we don't really know how this is going to pan out until they actually get in the driver's seat and take one to two quarters to sort out what they want to do."

Petro-Canada put Fort Hills on hold late last year as oil and credit markets sputtered. That, and a multibillion-dollar jump in construction cost estimates a few months earlier, sent UTS stock tumbling.

In January, French oil major Total SA launched a hostile bid for UTS, but ultimately failed to garner enough support from investors.

Petro-Canada, UTS and the project's other partner, Teck Resources Ltd, have spent the last six months working on ways to cut the cost of the 160,000 barrel a day project.

Roach has said the cost of the current mine and bitumen extraction plan has since dropped by C$5 billion to around C$8 billion.

He posed a series of possible scenarios for moving forward with the project, including initially developing just one 80,000 barrel a day production train in the mine.

Based on several oil price and exchange rate assumptions, the internal rate of return could range between 11 percent and 32 percent.

In one scheme, mining and primary bitumen extraction could take place at the Fort Hills site and treatment of the frothy bitumen that gets upgraded into synthetic oil could be done at the Suncor site, he said.

Roach said UTS has had discussions with other companies since Total dropped its bid, as part of "normal business", but he declined to say if any involved his company or various assets being acquired.

AFRICA / MIDDLE EAST

MOROCCO

San Leon Energy Secures Tarfaya Oil Shale Exploration Project in Morocco

San Leon Energy has signed an agreement with Morocco's National Office of Hydrocarbons and Mining to employ proprietary In-Situ Vapor Extraction technology over the 6,000sqkm Tarfaya oil shale project in Morocco. The agreement was signed with Mrs Amina Benkhadra, General Director of ONHYM and Moroccan Minister of Energy, Mines, Water, and Environment.

San Leon has been working with the National Office of Hydrocarbons and Mining (ONHYM) for two years to explore the potential of the available and massive in-place oil shale opportunities.

The company has signed a three-year memorandum of understanding with the Moroccan authorities which grants San Leon exclusivity to convert the area into a license.

San Leon has been working with ONHYM for two years to explore the potential of the available and massive in-place oil shale opportunities. The company has therefore signed a three year Memorandum of Understanding with the Moroccan authorities which grants San Leon exclusivity to convert the area into a License. San Leon estimates reserves of billions of barrels of recoverable oil from the Tarfaya oil shale over the 6,000 km2 area.

To exploit this potentially vast resource, San Leon has acquired an in-situ oil extraction technology through an agreement with the U.S. company Mountain West Energy (MWE). This technology is exclusive to San Leon in Europe, North Africa and the Middle East. The successful testing of this technology enabled San Leon to successfully apply for the rights to test the large oil shale concession in Morocco.

Laboratory and site testing in the U.S. has been completed and Moroccan site testing will begin later this year. The feasibility study, which includes a work program, has been presented and agreed in Morocco by ONHYM.

The Tarfaya oil shale has successfully produced 62 liters per tonne in Mountain West Energy’s Utah lab. This is similar to the yield reported by Shell when they were testing in the Tarfaya area from 1981 until 1986. Shell drilled 55 shallow boreholes, all of which were petrophysically logged, in 1982, encountering the Cretaceous and organic rich Tarfaya oil shale within the San Leon area. Shell established an open pit mine and heated the oil shale in a retort for oil production. They left the area in 1986 after oil prices had plunged to $10 per barrel.

IVE is an in-situ oil shale extraction technology that forces heated gas through a central injector well and into a high oil yielding and fractured oil shale. The oil is then produced from several extraction wells, equidistant from the central injection well. IVE was tested successfully in the Naval Petroleum Reserve #3 at the Tea Pot Dome Field in Wyoming, with assistance from the U.S. government, in order to increase production from the existing heavy oil reserves

The in-situ process of oil extraction is cleaner environmentally than the alternative technology, open pit mining, which is invasive. San Leon’s IVE process “cooks” the oil shale in the ground (or in-situ) and the gases utilized in the process are recycled within a closed system.

San Leon conducted a detailed test study from August 2008 until January 2009 and produced an extensive report outlining the IVE technology and the prospectivity of the Tarfaya oil shale. On the basis of the Tarfaya Work Study, ONHYM and The Group signed the Tarfaya Oil Shale MOU, which gives San Leon 3 years to test the IVE process.

The first test project is now in the planning stage and The Group expects this to be completed in the first half of 2010. The test site will be selected in a location approximately 200m above the high oil yielding zone within the Tarfaya oil shale. It could take at least a year to mobilize all the essential equipment for San Leon’s first test site.

In a similar transaction, Petrobras has recently signed an MOU with ONHYM for the Tarfaya oil shale, neighboring the San Leon acreage. Petrobras also has the Timhadit oil shale MOU, which lies in the northern part of Morocco.

Phil Thompson, CEO of San Leon commented: “This is a monumental achievement for our company to add the potential to access huge recoverable oil reserves from the Tarfaya shale through our oil shale technology. We are delighted with this accomplishment as it represents a major step in the development of San Leon. We are particularly pleased to note the strong support given by ONHYM in our negotiations and trials process and look forward to working together to develop the burgeoning Moroccan oil and gas environment”

Mrs Amina Benkhadra, General Director of ONHYM and Moroccan Minister of Energy, Mines, Water, and Environment commented: “We are delighted that San Leon has decided to join with international super majors in exploring the potential of our oil shale. Morocco remains committed to developing its oil and gas industry to the highest of international standards and will continue to provide positive support to foreign direct investment, be it through the provision of technical data, or working in co-operation to upgrade the logistical systems in country to allow efficient development”

JORDAN

Repsol, INA Eye Jordan Exploration Block

Spain's Repsol YPF SA and Croatia's INA dd are interested in entering sharing agreements with Jordan to explore for oil and gas, a source at the kingdom's Natural Resources Authority said June 23.

"Repsol and INA are interested in the Northern Highlands Block," the source told Dow Jones Newswires.

INA is 47.15% owned by Hungarian oil and gas company MOL Nyrt.

NRA offered production-sharing contracts for the Northern Highlands and Jafr and Central Jordan Blocks to international companies and set July 2 as the closing date for offers. The Northern Highland Block, near the border with Syria, has a total area of 7,500 square kilometers. The block adjoins the West Safawi Block. The Jafr Block is part of the prospective oil and gas areas in Jordan and adjoins the producing oil field at Azraq and the promising one in Sirhan.

The Jordanian government concluded four production sharing contracts with international companies in May 2007 for four exploration blocks, out of a total of eight blocks drawn up by the NRA for exploration.

Last month Jordan signed a concession agreement with Royal Dutch Shell PLC (to explore for oil in its vast oil shale deposits. Shell is expected to invest billions in the project over 20 years.

The project would cover an area of 22,000 square kilometers and could produce thousands of barrels of oil from oil shale. Jordan is also in the final stages of striking another deal with oil major BP PLC to explore and boost output from the Kingdom's Risha gas field.

Jordan, home to around 6 million people and importing around 95% of its energy needs, aims to boost production from the Risha gas field, near the border with Iraq, to 50 million cubic feet a day in the first investment stage from 22 million cubic feet a day now, officials said.

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