feb 09 update

Oil sands developers - from start-up firms to international energy giants - have pushed back multibillion-dollar projects as oil prices plunged off record highs and the global economy ground to a halt. Most of the delays have centered on upgraders, the high-cost facilities that process the sludgy oil sands bitumen into a lighter, more valuable synthetic crude.

In recent weeks, Norway's state-owned StatoilHydro ASA has scrapped plans for a C$16 billion upgrader while Petro-Canada (PCZ) said it could cancel its facility altogether, potentially saving more than C$10 billion.

Yet these are the very projects Alberta's government is trying to encourage, to create more jobs and more value from oil sands development. Last month, it released a widely panned energy strategy that included the goal of developing a "world-class hydrocarbon processing cluster" of upgraders, refineries and petrochemical facilities. Details remain scarce.

But Alberta's loss could favor refiners across the border. The U.S. refining industry has faced rapidly weakening demand for its products while struggling to manage huge volatility in oil prices, which traded over a $115 range during 2008. Canada is the top crude supplier to the U.S. and oil sands producers have already formed lucrative partnerships with U.S. refiners, all in the Midwest due to existing pipeline capacity constraints.

But TransCanada Corp. and ConocoPhillips' new Keystone link will soon connect Alberta with the U.S. Gulf Coast, the heart of the country's refining capacity. Much of this can already handle oil sands crude, which could easily replace declining output from traditional U.S. Gulf supplier Mexico, and several refiners plan to boost this capacity further with major conversion projects.

And as Keystone comes into service over the next several years, oil sands producers may prefer to sell their unprocessed bitumen on the spot market or ink supply deals with refiners instead of building an upgrader, even when the economy recovers. Developers that are fuzzy about their proposed upgraders are largely still pushing ahead with bitumen production plans.

"The Alberta government can talk about value-added [development]...but that's not what the market is demanding," said Steve Fekete, a Calgary-based senior principal at Purvin & Gertz. "The economics to produce the bitumen is still there long-term and the demand is still there long-term, but building an upgrader's only going to give you a marginal return. It's not strong enough given the capital cost you need to put in."

Even those with upgrading plans in Alberta are keeping their options open. In July 2007, Royal Dutch Shell PLC (RDSA), one of the biggest and most established producers in the oil sands, started the regulatory process to build a C$27 billion upgrader next to its existing Scotford upgrading and refining complex near Edmonton, Alberta.

A year later, however, Shell said it could scrap this plan and ship the crude to be processed at its Martinez, Calif., and Deer Park, Texas, refineries instead.

"The North American upgrading strategy is still being considered - we're looking to integrate our oil sands into our downstream as efficiently as possible," said Paul Hagel, Shell's senior oil sands spokesman. "But we're still going to pursue the regulatory option (for the Alberta-based upgrader) to ensure that we have viable options down the road."

Meanwhile, companies without Shell's far-reaching operations are looking for partners. A number of cross-border deals have already been inked, kicked off by EnCana Corp. (ECA) and ConocoPhillips in late 2006, but these involved asset swaps - a stake in oil sands production for part-ownership of a refinery.

New deals are more likely to involve long-term supply contracts instead, as producers grow more protective of their oil sands assets. Others, such as Petro-Canada, are mulling U.S. refinery acquisitions.

Last summer, Canadian Natural Resources Ltd., Canada's second-biggest oil and gas producer, said it had agreed to supply "a major U.S. refiner" for 20 years via the Keystone pipeline. Several observers reckon the partner is Valero Energy Corp., the biggest independent refiner in the U.S., which has also made long-term commitments to Keystone.

Analysts think Canadian Natural could also be a good partner for Sunoco Inc.. The U.S.' second-biggest refiner wants to form a joint venture to run more Canadian heavy crude at its Toledo, Ohio, refinery, and says it is already in talks with Canadian producers.

Retooling a refinery is still a major capital expense, however. Few refiners expect the gloomy outlook for oil demand to brighten anytime soon, and have pared back 2009 spending plans as a result.

In October, Marathon Oil Corp. said it was delaying a $1.9 billion project to equip its Detroit refinery to handle oil sands crude. The Houston-based company announced the project in mid-2007, after acquiring a 20% stake in Shell's Athabasca oil sands development.

But Canadian producers won't have difficulty finding homes for their crude, as some very big projects are still underway, said Neil Earnest, vice-president of Muse Stancil, a Dallas-based consultancy.

Shell and state-owned Saudi Arabian Oil Co., or Saudi Aramco, plan to more than double their Port Arthur, Texas, refinery in a $7 billion project to handle the "nastiest crudes." BP PLC (BP) is upgrading its Whiting, Indiana, refinery to run almost wholly on Canadian heavy oil.

"There's already an enormous heavy sour [crude] capacity on the Gulf Coast," Earnest said. "That's not going to go away - there's plenty of room."

The trend of upgrading oil sands crude in the U.S. will reduce competition, possibly benefiting upgrading facilities still planned for Alberta.

A couple of private companies plan to build independent upgraders in the province, which wouldn't have any oil sands production themselves but would source their bitumen entirely on the market or through long-term contracts. The problem is, they haven't been built yet, and the credit crunch is making it increasingly difficult to do so.

North West Upgrading Inc. has halted construction on the first C$4.2 billion phase of its facility, which it had hoped to bring onstream by early 2011.

"We're ready to go but it's a question of money - the markets are in terrible shape and have been for some time," said Chief Financial Officer Rob Pearce. "The markets have hit us and for development stage companies without cash flow, it's particularly difficult."

Alberta's government is pressing ahead with plans to accept bitumen in place of energy royalty payments, in a bid to encourage the upgrading industry to stay within the province. It's a positive step, Pearce says, though others reckon producers would still find it cheaper to ship bitumen to the U.S. instead of building a new upgrader in Alberta.

"The deferral and cancelation of upgraders is a concern because that adds a huge amount of value," Pearce said. "But less activity means construction costs will be better controlled. And it means more upgrading opportunities for us."

Marathon Announces Gas Discovery in New Area of Oklahoma's Woodford Shale Resource Play

As part of the Company's targeted expansion into key resource plays of North America, Marathon Oil Corporation announces that it has participated in a successful step-out discovery well on the Brickyard prospect, located in the northeast area of the Anadarko Basin, targeting the Woodford Shale resource play in Canadian County, Oklahoma.

The Cana No. 1-15H discovery well was drilled to a true vertical depth of 13,177 feet and horizontally for 4,090 feet, for a total measured well depth of 17,267 feet. The well flowed at an initial rate of 5.2 million cubic feet of gas per day. Marathon is the well operator and holds approximately 57 percent interest in the Cana No. 1-15H well. Other interest owners include Questar Corporation and Cimarex Energy.

"Marathon is encouraged by the results of the Brickyard prospect as we continue to develop the emerging Woodford Shale resource play," stated Annell R. Bay, senior vice president, Worldwide Exploration. "We are using 3-D seismic technology to better define our targets and applying advanced drilling technology to reduce drilling days and well costs thereby improving overall well economics."

Marathon holds approximately 30,000 net acres in the expanding Woodford Shale resource play with approximately 10,000 of those net acres in the immediate Brickyard prospect area. The Company is currently drilling two additional company-operated wells and is participating in two non-operated wells in the Brickyard prospect. Marathon also plans to participate in 15 to 25 gross wells in this area through 2010 with an anticipated 50 percent overall working interest. This limited program is designed to enhance the company's technical understanding of the play and reflects the company's focus on capital discipline. Marathon expects that with the successful development of this program, the play could yield an additional 200 to 300 gross locations.

The Cana well is believed to be the world's first totally interventionless well completion using the patented EXcape(R) Completion Process technology, developed jointly by Marathon, BJ Services, GEODynamics and the Expro Group. With EXcape, Marathon was able to remotely perforate, fracture stimulate and complete each individual interval zone for production, including the setting and removal of isolation devices - saving time and expense. Based on the success of the Cana well completion, Marathon plans to expand the use of this next-generation EXcape technology to future activities in its Oklahoma's Woodford Shale and Alaska's Cook Inlet operations.

"Compared to conventional completions using pump-down techniques in horizontal wells, the EXcape technology reduced man hours on this well completion by more than 35 percent and reduced completion costs by 10 percent," Bay added.

Obama's Plans on Global Warming may get Greatest Opposition from Illinois and its Top Greenhouse Emissions Title

If President-elect Barack Obama is serious about curtailing U.S. emissions of greenhouse gases, he may find that his biggest hurdle is his home state of Illinois. For Illinois is one of the top greenhouse gas engines in the country, if not the top one, and the development plans backed by the Democratic Party establishment will increase the production of climate changing gases.

Illinois' claim to the greenhouse gas title rests on its dependence on two of the dirtiest sources of fossil fuel energy: coal and tar sands.

According to the U.S. government's Energy Information Agency, coal-fired power plants produce approximately 34 percent of the greenhouse gases released into the atmosphere in the United States, and Illinois is fifth in the nation in coal power generation. Gov. Rod Blagojevich, a Democrat, has pushed coal power as the key to the state's economic future.

The U.S. Department of Energy's National Electric Technology Laboratory reported that during the Blagojevich administration, Illinois has entertained more proposals for new coal-based electric power plants than any other state. The proposed plants approved by the state government would account for more than 10 percent of the generating capacity of all proposed coal-fired power plants nationwide. Environmental groups have contested many of those approvals before the U.S. Environmental Protection Agency and federal courts.

And while three of the five top coal power generating states -- Ohio, Pennsylvania, and Texas -- are reducing their reliance on coal, lllinois' dependence is increasing. Electricity from coal projects moving forward in Illinois will increase the coal power generation capacity in that state more than 20 percent.

A recent decision by an appeals board of the U.S. EPA could steer the president-elect into an early confrontation with his home state. On November 13, 2008, the Environmental Appeals Board, an independent body of adjudicators within the Environmental Protection Agency, ordered the agency to consider whether to regulate carbon dioxide emissions from power plants before it approves construction of new coal-fired power plants. The decision came in response to an appeal from the Sierra Club of EPA permit for construction of a new coal-fired power plant in Utah. Carbon dioxide is the most common of the greenhouse gases.

Sierra Club Chief Climate Counsel David Bookbinder said the decision will delay construction of any proposed coal-fired power plant in the U.S. by at least a year. It puts pressure on the new Obama administration to either reverse course or proceed to regulate industrial carbon dioxide releases, not just from power plants, but also from petroleum refineries and other industrial facilities.

The appeals board based its ruling on a U.S. Supreme Court decision last year in Massachusetts v. EPA that declared that carbon dioxide is a pollutant under the Clean Air Act.

As a Senator and candidate for president, Obama supported "clean coal." Blagojevich likewise portrayed his energy policy as advancing "clean coal."

A spokesperson for Blagojevich's Department of Commerce and Economic Opportunity, Marcelyn Love, said, "Coal is very important to Illinois' economy, and will be even more so in the future."

In 2002, Illinois initiated a Coal Revival Program, which provides grants to assist with the development of new, coal-fired electric power plants. In July 2003, Blagojevich signed legislation that expanded the program by offering $300 million in state-backed bonds to help finance the construction of "advanced technology" coal-fueled projects. Two years later, he signed legislation that expanded the program to include coal gasification plants or integrated gasification-combined cycle plants. On Oct. 12, 2006, he announced $3 million in state grants to help Power Holdings of Illinois, LLC develop a plant to produce synthetic gas from coal.

The governor has billed every coal-fired power plant supported by his administration as "clean." He called the 1,600-megawatt Prairie State Energy Campus under construction in Washington County in southwestern Illinois, for example, "among the cleanest coal plants in America and a model for new generation." He said the 630-megawatt Taylorville Energy Center uses "cutting edge clean-coal technology" and "is a great example of how we can grow our economy and create good paying jobs while protecting our environment." Love said those plants are central to the governor's energy program.

The Sierra Club, however, has derided those power plants as "dirty."

"We think the trend to add to the coal fleet is a very frightening trend," said Becki Clayborn, regional representative of the Sierra Club. Even though proposed coal-based power plants would spew less sulfur and nitrous oxides into the air than older plants, "that doesn't mean they are the cleanest plants around," she said. And, "they do not do much about carbon dioxide, and that is a problem," she said.

The Sierra Club started its national campaign against coal in Illinois, "because more plants were proposed in Illinois than anywhere else," Clayorn said. "We are at a crossroads," she said, "either we continue adding to global warming problems or we look for alternatives."

Although the Taylorville Energy Center would not burn coal, but would instead turn coal into a synthetic gas and then burn the gas to generate electrical power, Clayborn said it "does not address CO2 emissions at all."

"One of our main concerns about adding coal plants without shutting down old ones is that you are just adding to CO2 emissions. If a plant does not have a mechanism to deal with the CO2 problem, it should not go forward," she said.

That's a concern shared by the National Resources Defense Council. According to Shannon Fisk, staff attorney with the National Resources Defense Council's Midwest Office in Chicago, "If we are building new coal plants, we must have binding commitments to capturing and sequestering CO2 emissions, the best control of other pollutants, and a serious look at the mining practices of coal," he said.

Illinois' other greenhouse gas problem comes from its reliance on synthetic oil produced from bitumen extracted from Albertan "oil" sands in Canada. Seventy-five percent of Alberta's bitumen production, about one million barrels a day, flows through Chicago. And ConocoPhillips has begun a $4 billion project to move another 300,000 barrels a day directly to a refinery downstate in Wood River, Illinois.

The problem, industry sources agree, is that extracting bitumen from the ground and upgrading it to produce petroleum products currently releases about 50 percent more greenhouse gases into the air than producing the same volume of products from conventional crude oil. Since most greenhouse gas emissions from gasoline come from burning the fuel in car engines, however, not from refining it, they are quick to add that the "global" addition to greenhouse gas emissions is about 15 percent.

Mining and upgrading bitumen produce more greenhouse gases than pumping and refining crude oil for one simple reason: because it takes more energy. Adam Brandt, a researcher in the Energy and Resources Group at the University of California in Berkeley, likened the process of making gasoline from bitumen to reverse refining. "Upgrading [bitumen] is like turning asphalt into gasoline," he said. The typical refinery is basically a set of distillation chambers, he explained. A refinery basically boils and collects condensates of petroleum to get different useful products, gasoline first, then diesel fuel, and so on, moving from the lightest products to progressively heavier one "until you are left with a heavy sludge that is used as road tar," Brandt said. "The oil sands are like that very low quality, heavy sludge," he said.

Joule Bergerson, a professor at the University of Calgary, whose research was funded by the Canadian government, said about half of the greenhouse emissions in producing gasoline from oil sands comes from the upgrading process, the process of turning road tar into gasoline. The half comes from extracting bitumen from the ground. Simply put, miners either strip mine the ground and melt bitumen out of the sand in a factory with very hot water or boil water to make the steam that they inject into the ground to melt bitumen in the ground so they can pump it out. It is the burning of natural gas (methane) to either heat or boil water that generates most of the greenhouse gases in the extraction process.

According to Michael Wang, director of the Center for Transportation Research at the U.S. Department of Energy's Argonne National Laboratory, greenhouse gas emissions will increase as the industry grows and tries to extract harder-to-reach bitumen, unless they find an environmentally friendlier power source.

In 2008, the Canadian government, which has adopted the Kyoto Protocol to reduce greenhouse gases, "declared that there will be no knew oil sands plants or refineries without installing carbon sequestration and capture," Bergerson said, explaining that the declaration meant that any plant starting operation in 2012 or later must capture and store any carbon emissions. It was assumed that industry could afford the controls as long as the price of oil remained above $100 a barrel, she said.

Oil companies, however, have not shown a lot of interest in building refineries with carbon capture and storage in Alberta, instead preferring to convert existing refineries in the United States, where there are no regulations on greenhouse gas emissions. According "It is more economical for existing refineries, which are closer to markets and have facilities to make a range of final products, to complete the processing of synthetic crude oil, rather than duplicate those facilities in Canada," explained ConocoPhillips in a written statement. A U.S. government decision to regulate carbon dioxide could change that equation.

After the Environmental Appeals Board ruling in the Utah power plant case, coal, oil and electric companies in Illinois, and environmental groups, are waiting to see what definition of "clean" President Obama will embrace.

Enbridge Pays Wisconsin $1.1 Million Fine for Violating Wetlands Protections during Pipeline Construction

The Canadian company that wants to build a crude oil pipeline through central Illinois has agreed to a major fine in Wisconsin for violating that state's waterway and wetland protection laws.

Enbridge settled the case Dec. 30 by agreeing to pay $1.1 million and resolving the violations incurred during pipeline construction in 2007 and 2008.

"While some of the individual violations were likely of limited direct impact, the incidents of violation were numerous and widespread and resulted in impacts to the streams and wetlands throughout the various watersheds," Wisconsin Attorney General J.B. Van Hollen said in a news release announcing the settlement.

"This action will help encourage the proactive protective measures that Wisconsin requires of those who work in or near its waterways and wetlands," Van Hollen continued.

Enbridge was accused of violating its construction permits while building two parallel pipelines through 14 counties. The violations "impacted wetlands and navigable waterways and public interests in the preservation of and protection of quality water resources," the release said.

The pipeline through Wisconsin is part of Enbridge's "southern access program" linking the Midwest with oil extracted from the tar sands of Alberta, Canada.

Construction on a segment of Illinois pipeline connecting Flanagan to Delavan, Wis., is nearing completion.

Enbridge in the summer of 2007 filed with the Illinois Commerce Commission to build an additional segment of pipeline capable of transporting up to 400,000 barrels of crude per day from Flanagan to Patoka.

Landowners, particularly those in McLean County, have objected to the pipeline before the ICC, in part contesting the proximity of the pipeline to critical water supplies and other features of various watersheds.

The case remains mired before the ICC and has pushed back potential construction dates of the pipeline to sometime in 2010.

French Firm Total, Expands Oil Research into Colorado

French energy giant Total announced earlier this month it plans to acquire a 50 percent stake in IDT Corp.’s American Shale Oil LLC subsidiary. AMSO holds a 160-acre federal oil shale research, development and demonstration lease in Rio Blanco County, and a right to convert that to a commercial development lease covering about eight square miles upon meeting certain conditions.

Total is a “big player” in development of oil sands in Canada, said Tom Ryan, vice president of the corporate division of Total E&P USA Inc.

AMSO president Claude Pupkin notes Total is working on a shale project in Morocco and will be working on one in Jordan. Both of those ex-situ projects involve removing oil shale and processing it above-ground. AMSO is pursuing an in-situ process to produce oil from shale while it’s still in the ground.

Total also is working on heavy oil projects in several other countries and has agreed to collaborate with Petrobras, the Brazilian energy firm, on the Jordan project, said Jeremy Boak, director of the Center for Oil Shale Technology and Research at the Colorado School of Mines.

Petrobras is working with the Oil Shale Exploration Co. on OSEC’s project in Utah, which includes a federal lease like AMSO’s.

Boak said big national and international energy companies see oil shale as something worth pursuing despite the recent drop in energy prices, and some are getting stakes in the world’s largest oil shale deposits in Colorado, Wyoming and Utah.

In the long term, they see fuel prices rising again, and they’re looking to unconventional sources because conventional fuels have become harder to find, Boak said.

Total’s Ryan said, “I think Total has a desire to be an early entrant in technology and resource plays that are the future of the business.”

He added, “We believe that oil shale will be part of the answer to the long-term (energy) supply.”

The company also is pursuing renewable fuels such as wind and solar power, Ryan said. It just acquired nearly a 20 percent interest in Konarka Technologies Inc., a Massachusetts company that makes flexible, photovoltaic plastic films.

Meanwhile, Total agreed in August to partner with Denver-based Independent Energy Partners Inc., which is developing a fuel cell approach aimed at unconventional fuels such as oil shale in-situ in a more energy-efficient manner.

Pupkin said he thinks AMSO’s lease and team of oil shale experts attracted Total to its project. In return, when AMSO gets out of the research and development phase, it needs a partner of Total’s size “to help us build a significant commercial-scale project,” he said.

Lawsuit Filed to Stop Tar Sands Development in Utah

The Sierra Club and the Indigenous Environmental Network are fighting an unprecedented project that they say would bring one of the dirtiest forms of energy extraction in the world to eastern Utah. The proposed Antelope Creek tar sands oil project threatens to disrupt wildlife, poison and dry up rivers, and imperil human health with hazardous air pollutants, the groups claim. The project would also produce an exorbitant amount of the greenhouse gases.

In an effort to prevent these impacts, the groups filed a lawsuit in Utah federal district court in January. The suit challenges approval of the tar sands project by the U.S. Bureau of Indian Affairs, which manages the land slated for the development.

The Antelope Creek tar sands project, proposed by Petroglyph Gas Partners, would drill 300 new wells within 720 acres of land, using unprecedented deep injection thermal extraction techniques. The project site is home to 13 species proposed or listed under the Endangered Species Act, and an extensive network of creeks that drain into the Duchesne and Green Rivers.

Greenhouse gas emissions from tar sands production are three times those of conventional oil and gas production. Tar sands development, which largely has been concentrated in Canada, is becoming that country’s largest single emitter of greenhouse gases and is widely regarded by many as an environmental disaster.

Obama Punts 11th-hour Oil Shale Rules to Salazar

Environmentalists got some relief January 20 when the new Obama administration issued a memo halting further progress on a series of controversial midnight regulations pushed through in the waning days of a lame-duck Bush White House.

New West.net has the details on the last-minute rules that would have short-changed states on commercial oil shale royalties, as well as de-listing the gray wolf as an endangered species and allowing loaded guns in national parks, along with other measures:

The January 20 memo from Chief of Staff Rahm Emanuel calls for a withdrawal of any regulation yet to be published, a ban on new regulations and a request that departments wait 60 days to implement any regulations that have been published and reopen public comment periods.

“It is important that President Obama’s appointees and designees have the opportunity to review and approve any new or pending regulations,” Emanuel wrote to federal departments and agencies.

Newly confirmed Interior Secretary Ken Salazar has already signaled his opposition to the oil shale regulations in a Nov. 18 Colorado Energy News story:

Colorado’s governor and one of its senators jumped on the Bush administration late yesterday for what they called “reckless” and “flawed” new rules for commercial oil shale development.

UK’s TomCo to look again at Possible U.S. Acquisitions

TomCo Energy Plc is an Isle of Man company, listed on the London AIM market, with oil shale and conventional oil holdings in Israel and the United States.

A strategic review at TomCo Energy has led the oil and gas group to revisit possible asset purchases in the U.S. while also considering other strategic options with a view to delivering enhanced shareholder value.

Since listing on AIM in December 2007, TomCo has been sitting on leases covering approximately 2,918 acres of oil shale in the Uinta Basin in Utah. While interest in oil shales has increased notably since then, the company has reiterated its view that the leases represent a long term investment.

TomCo has 3000 Acres of oil shale in the Green River formation in Utah projected to have 230m barrels of oil by SRK. TomCo has some small 3 wells production in the U.S. TomCo has an experienced oil management Team. TomCo’s strategy is to hold the oil shale until such time as it can be commercially exploited, estimated to be 6 years, and aggressively develop, over a two years period, the Heletz field in Israel where the potential is for 1900 barrels per day production.

In reaction to the rally in world oil prices shortly after its listing, TomCo was priced out of many Western acquisition opportunities. However, it did manage to buy up and bring back to production assets in the Heletz fields in Southern Israel.

As part of its new strategy, and in response to falling prices, the company said it was now looking again at potential U.S. acquisitions whilst maintaining its commitment to the Heletz fields.

TomCo is the 50% owner of the Heletz-Kokav-Brur oil licenses and 25% owner of the Iris License (together: Heletz) in Southern Israel, with an estimated 50m barrels of Oil in Place in the shallow Cretaceous Sands and an estimated 100m barrels at the lower Jurassic level; Currently producing 65 barrels per day with a work-over and in-fill program in train.

BLM Allows Oil Shale Demonstration in West

Just days before leaving office, the Bush administration pressed forward with efforts to jump-start a domestic oil shale industry, saying commercial production will help lessen the country's dependence on imported oil.

It is offering energy companies another chance to show they can make a profit on public land in Colorado, Wyoming and Utah.

The U.S. Bureau of Land Management announced it is soliciting a second round of proposals for oil shale demonstration projects on 1.9 million acres in the three states. Projects would be limited to 640 acres per company, but the land could be converted to a commercial lease if the technologies proved successful.

The bureau estimates that Western states hold as much as 800 billion barrels of recoverable oil from shale.

"Broadening the scope of research into oil shale technologies will help accelerate the development of these vast western resources, and as a result lessen our dependence on foreign sources of energy," BLM Director James Caswell said in a statement.

A similar solicitation in 2005 led to five demonstration projects in Colorado and one in Utah. Colorado has more oil shale than the other two states.

During the first week of January, twelve environmental groups sent letters to the Interior Department and BLM, threatening to sue unless the potential effects on endangered species are addressed. They argue a final plan and rules for commercial oil shale development on the nearly 2 million acres approved late last year violated federal law because the agencies did not formally consult with the U.S. Fish and Wildlife Service.

"The Bush administration is trying to rush through everything they can to get this industry up and running," said Melissa Thrailkill, a staff attorney with the Center for Biological Diversity in San Francisco, one of the environmental groups that threatened legal action.

Thrailkill said rare species of Colorado River fish, the greater sage grouse and several plants that grow only on oil shale lands could be endangered by energy development. Environmentalists' main concern is that oil shale development would create greater greenhouse gas emissions.

"It's the dirtiest form of energy development out there," Thrailkill said. "It requires a ton of energy to heat the rock, and the BLM acknowledges in their environmental impact statement that more than likely that energy is going to come from new coal-fired power plants, which does nothing to help us with the climate change problem we're facing."

A spokesman for one oil company said production from shale deposits will not necessarily rely on coal plants.

Given current trends, electricity generated by natural gas, wind or solar is just as likely an energy source in 10 or 15 years, said Tracy Boyd, a spokesman for Shell Exploration and Production Co., which holds three of the six permits for the current demonstration projects.

That's the timeframe in which Shell estimates oil shale production will become commercially viable, he said.

Colorado Gov. Bill Ritter, a Democrat, and other state officials have urged federal officials to delay a final plan and rules for commercial development. They say there are too many unanswered questions about the effects on water, wildlife, air and local economies.

They point out that companies are still experimenting with the technology and say industry and government officials acknowledge that commercial development is several years away.

President-elect Barack Obama's nominee to head the Interior Department is Sen. Ken Salazar, a Colorado Democrat who wrote the legal provision that allows BLM to permit limited demonstration projects. Salazar also has urged a go-slow approach to oil shale development.

Shell Seeks Yampa River Water for Oil-shale Plans in CO

Shell Oil has filed for an industrial water right on the Yampa River for use in development of oil shale, should the company decide to move forward with the idea.

Shell holds three research-and-development leases in northwest Colorado, where it is testing its method of heating shale to release petroleum distillates that can be refined into products such as jet fuel and gasoline.

Shell’s filing seeks 375 cubic feet per second from the Yampa to fill a 45,000-acre-foot reservoir in Moffat County in an area known as Cedar Springs Draw, said Tracy Boyd, communications and sustainability manager for the Shell Mahogany Research Project.

The company will need to divert only spring runoff water to fill the reservoir, Boyd said.

The filing is intended to increase the diversity of water rights the company owns for the eventual development of oil shale, Boyd said.

The company is working to reduce the amount of water it will use if it proceeds with development and will “apply best water-management practices to treatment, storage and reuse,” he said.

Shell made the January filing in the water court in Steamboat Springs.

Once the filing is published, interested parties can file statements of opposition to the water right, even though they might not necessarily oppose it.

Among them will be the Colorado River Water Conservation District, which will enter the case as an opposer, but not an opponent, spokesman Chris Treese said.

“We have told Shell we want to be working with them” on the proposal for the reservoir to accommodate municipal, environmental, recreational and other uses, as well as Shell’s planned industrial use.

There is the possibility of competition for the water from the Northern Water Conservancy District, based in Berthoud, which has floated the idea of diverting Yampa River water to the Front Range. A Colorado man, Aaron Million, also is seeking to divert water from Flaming Gorge Reservoir to the Front Range, claiming that water in the river is subject to use by Colorado under the compact that governs the Colorado River and its tributaries.

A budding oil shale industry has just as much right to the Yampa River’s unallocated flows as anyone else, Treese said.

Shell’s industrial water right wouldn’t interfere with agricultural rights, and the company is interested in working with other water users, Boyd said.

“We clearly recognize at least a potential for some mutual benefit” with other users, he said.

The reservoir would be a couple miles long and about one-third of a mile wide at the widest point, near a dam in Cedar Springs Draw, Boyd said.

Water would be pumped out of the Yampa and into the reservoir, he said.

Runoff could fill the reservoir in about two months, he said.

Shell has yet to decide how much water it will need for oil shale development, and Boyd emphasized the company has yet to decide to seek commercial production. Company officials have said that decision is years away.

The industrial right Shell is seeking is among the largest of the water rights the company has accumulated over decades, Boyd said.

If Shell moves forward with production from oil shale, company officials want to be ready with plenty of water and “minimize impacts rather than doing some things at the last minute,” he said.

The company hasn’t settled on the amount of water it will need for a producing oil shale venture, but it won’t put any of the water to which it has rights to use in its freezewall technology, Boyd said.

To prevent contaminants from escaping into the groundwater, Shell is experimenting with freezing the ground that surrounds the areas to be heated.

ETP, Chesapeake Plan $1.0 - $1.2 Billion Haynesville Pipeline

Energy Transfer Partners, L.P. (ETP) on January 27 announced it has entered into an agreement with Chesapeake Energy Marketing, Inc., a wholly owned subsidiary of Chesapeake Energy Corp., to construct a 178-mile 42" interstate natural gas pipeline ("Tiger Pipeline"). The project will connect to ETP's dual 42" pipeline system near Carthage, Texas, extend through the heart of the Haynesville Shale and end near Delhi, Louisiana, with interconnects to at least seven interstate pipelines at various points in Louisiana.

The Tiger Pipeline is anticipated to have an initial throughput capacity of at least 1.25 Bcf per day, which capacity may be increased up to 2.0 Bcf per day based on the results of an open season. The agreement with Chesapeake provides for a 15-year commitment for firm transportation capacity of approximately 1.0 Bcf per day. The pipeline project is anticipated to cost between $1.0 billion and $1.2 billion to construct, depending upon the final throughput capacity design, with such costs to be incurred over a three-year period. Pending necessary regulatory approvals, Tiger Pipeline is expected to be in service by mid-2011.

"Energy Transfer Partners continues to implement its growth strategy of providing pipeline capacity through significant producing basins across the country. Critical infrastructure is needed to relieve growing constraints near the Carthage Hub and to provide takeaway capacity from the Haynesville Shale. The Tiger Pipeline project is another example of how our Partnership works with successful producers like Chesapeake to consummate pipeline opportunities," said Mackie McCrea, President and Chief Operating Officer of ETP. "This project will contribute to our ability to generate sustainable long term distributions for our unitholders."

"Chesapeake believes the Haynesville Shale has the potential to become the largest producing field in the country," commented Aubrey K. McClendon, Chesapeake's Chief Executive Officer. "Significant capacity must be built to insure the deliverability of natural gas from this rapidly expanding area and we are pleased to be able to support ETP in this very important project."

MarkWest Energy, NGP Plan Marcellus Shale Midstream JV

MarkWest Energy Partners, L.P. and NGP Midstream & Resources, L.P. on January 27 announced an agreement to form a joint venture dedicated to the construction and operation of natural gas midstream services to support producer customers in the Marcellus Shale.

Under the terms of the joint venture, which will be owned 60 percent by MarkWest and 40 percent by M&R, MarkWest will operate the facilities and will contribute approximately $100 million of existing Marcellus Shale assets to the joint venture. M&R will invest the next $200 million of capital, which approximates the capital required to fund the Marcellus project in 2009. Capital funding for 2010 and 2011 will be driven by producer drilling programs. In order to achieve the 60 / 40 capital structure MarkWest will invest approximately $200 million in incremental capital by the end of 2011 in accordance with the joint venture agreement.

The Marcellus Shale continues to develop into one of the most prolific and economic natural gas shale plays in the United States. MarkWest has established a leading position in providing midstream services in the Marcellus Shale, including the recent development of gathering and processing infrastructure for Range Resources in southwest Pennsylvania. By the end of 2009, MarkWest and M&R expect the joint venture to be capable of processing up to 240 million cubic feet per day of gas for Range and other producers.

"M&R will be an excellent partner in our Marcellus project," said Frank Semple, Chairman, President and Chief Executive Officer of MarkWest Energy Partners. "M&R has a strong appreciation for the long-term strategic value of the Marcellus play and shares our vision of delivering best-of-class midstream services to producer customers, including our significant relationship with Range Resources. The structure of the joint venture will allow MarkWest to achieve its long-term objectives in the Marcellus while significantly reducing capital requirements over the next several years, which is a critical component of our balance sheet and liquidity objectives. The experience and expertise of MarkWest and M&R are very complementary and we look forward to a long-term business relationship."

"We are delighted to announce the partnership we have formed with MarkWest," said John T. Raymond, Managing Partner and Chief Executive Officer of M&R. "The transaction leverages the firm's in-house expertise, deep industry relationships, and financial scale which, when complemented by a proven experienced management team and a common view towards the inherent value of the Marcellus play, creates the foundation for a successful long-term strategic partnership. We look forward to working with the MarkWest management team to explore additional opportunities to partner together."

The closing of the joint venture is subject to customary and other closing conditions, including the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 ("HSR Act").

Morgan Stanley is acting as MarkWest's exclusive financial advisor in connection with the formation of the joint venture.

MarkWest Energy Partners, L.P. is a growth-oriented master limited partnership engaged in the gathering, transportation, and processing of natural gas; the transportation, fractionation, marketing, and storage of natural gas liquids; and the gathering and transportation of crude oil. MarkWest has extensive natural gas gathering, processing, and transmission operations in the southwestern and Gulf Coast regions of the United States and is the largest natural gas processor in the Appalachian region.

NGP Midstream & Resources (M&R), a U.S.-based $1.4 billion private equity fund, invests in selected areas of the energy infrastructure and natural resources sectors. M&R targets the midstream energy sector and all facets of the mining and minerals sectors. M&R makes equity investments of $50 to $250 million in entities with talented, experienced management teams, focused on hard assets that are integral to existing and growing markets. M&R is affiliated with NGP Energy Capital Management, a leading U.S. capital provider to all facets of the energy sector.

North Dakota Okays $89,750 Funding for Pipeline Interconnect Study

The North Dakota Industrial Commission on January 21 awarded a $89,750 contract to two companies -- Kadrmas, Lee, & Jackson and Rooney Engineering, Inc. -- for a feasibility study on constructing a pipeline to connect with one of TransCanada's Keystone pipelines.

"We are working to develop more pipelines and other infrastructure to move the oil and gas we produce in North Dakota to market," said Governor John Hoeven. "The pipeline authority was created to facilitate the development of pipeline infrastructure in North Dakota."

"The study will determine whether a connecting pipeline can be economically built by a third party, address quality concerns of transporting Bakken crude in the same pipeline as oil sands crude, provide route options, and establish a project timeline," said Attorney General Wayne Stenehjem. "This is the first step in the process that can assist in transporting our valuable crude oil to the market."

"We expect the study to be completed by mid-April," said Agriculture Commissioner Roger Johnson. "If the findings indicate such a project is feasible, we hope the information will encourage private companies to go forward with construction."

The 2,148-mile Keystone Pipeline will transport up to 590,000 barrels of crude oil daily from Alberta to U.S. markets in Illinois and Oklahoma. It enters North Dakota near Walhalla and exits the state south of Oakes. Also, TransCanada is planning to build the Keystone XL pipeline, which will pass very close to North Dakota's western border, and will provide another option for North Dakota producers.

Justin Kringstad, director of the Pipeline Authority will coordinate the study with Bismarck-based Kadrmas, Lee, & Jackson and Rooney Engineering, Lakewood, CO. The Industrial Commission, consisting of Governor John Hoeven as chairman, Attorney General Wayne Stenehjem and Agriculture Commissioner Roger Johnson, oversees the pipeline authority, which is funded by the Oil and Gas Research Fund.

Natural Gas Discovered in Water at PA Drilling Sites

Natural gas has mixed with at least three private water supplies near drilling rigs in Susquehanna County, according to information from Cabot Oil & Gas.

Regulators from the state Department of Environmental Protection and Cabot officials are collecting samples and analyzing the geology in Dimock Township to see whether nearby drilling operations into the gas-rich Marcellus Shale are to blame.

"We're looking at this as a serious situation, and we want to find out why it happened," DEP spokesman Mark Carmon said.

The tests come in the wake of a Jan. 1 explosion that shattered an 8-foot-wide cement slab at a nearby residence on Route 2024.

Investigators from the state and Cabot tested basements and water wells of at least six homes near drilling rigs. No gas was detected in basements, although it was found in the well at the residence where the cement slab was shattered and two others, according to Kenneth Kamorowski, a spokesman for Cabot Oil & Gas.

Officials, concerned about residents' safety, said they will track the gas to its source. While the gas, found in trace amounts, does not pose a threat for drinking, officials want to find out whether it is a sign of a larger problem, Kamorowski said.

"We don't have an answer," he said. "We've checked our pipelines and equipment, and they are not leaking."

As testing continued, samples were sent to labs, which may take another week or more to produce results, Carmon said.

Cabot, of Houston, is in the middle of an intensive effort to develop the Marcellus in the rural township just south of Montrose, with more than 15 wells completed or under way and more than 60 wells expected by the end of this year. The Marcellus, a mile or so deep; runs under the Southern Tier which is part of Pennsylvania and the Appalachian basin.

Intensive drilling into the Marcellus is an obvious suspect of the gas problem in Dimock, but not the only one.

Natural gas, or methane, is produced by decomposing organic material. It can move through shallow layers of earth and collect on its own in enclosed spaces of unvented wells.

More detailed analysis of air samples from the affected well will be able to determine whether gas escaped from the Marcellus or other deep geological formations penetrated by drilling rigs, or came from another source, Carmon said.

On the other side of the border, Marcellus development in the Southern Tier is effectively on hold while New York state regulators complete an industry-wide review of environmental concerns, including its impact on water.

CANADA

Enbridge Cleaning up Spill at Oil Sands Terminal

Enbridge Inc, Canada's No. 2 pipeline firm, said a malfunctioning valve at an oil storage facility in the oil sands region of northern Alberta this week spewed out 4,000 barrels of oil, but the spill was mostly contained on the grounds of its tank farm.

The company, whose pipelines carry the lion's share of oil sands crude to U.S. markets, said the spill occurred on January 3 at its Cheecham terminal south of Fort McMurray, Alberta, when a small fitting on a valve failed.

"It was primarily contained," said Gina Jordan. "A small amount was outside the terminal but the majority of the leak was contained."

Enbridge said the spill had not cut shipments on its pipelines from the oil sands.

Greenpeace spokesman Mike Hudema, whose group publicized the spill, said he considered the incident another blow to the environmental track record for the oil sands and called for increased regulatory scrutiny of activity in the region, which has the biggest reserves outside the Middle East.

Shell will Stay Committed to Oil Sands, to Maintain Investments

Royal Dutch Shell Plc remains committed to investing in Canadian oil sands after putting on hold the expansion of the second phase of the Athabasca project in Alberta, its chief executive officer said January 9.

“Looking at the long-term energy agenda, the Canadian oil sands will be exploited,’’ Jeroen van der Veer said in an interview in Shell’s corporate magazine. “And we will continue to expand, though we have postponed the expansion for now,’’ Van der Veer said.

Extraction of crude from oil sands is more expensive than from more conventional sites because of higher labor and operational costs. Shell said Oct. 30 it is pressing ahead with the first expansion phase of its Athabasca Canadian oil-sands project, while putting further investment there on hold because of mounting local construction costs.

The company expects to add 250,000 barrels of oil production by the end of this year, helped by winter oil output from its Sakhalin project in Russia’s Far East coming on line soon.

In the interview, Van der Veer said even under the current market circumstances the company will continue to be a “relatively large investor.”

Cutting or stopping investing would be “highly undesirable. We have made that mistake before and we learned a lesson from it,’’ Van der Veer said, referring to the late 1990s when crude prices collapsed and oil companies curtailed spending. Van der Veer said he is urging colleagues to control costs.

Alberta Oil Producers Question Timeline for Carbon-Capture Rule

Alberta's oil producers say they'll need more time to comply with Canada's new rule that oil-sands operations launched after 2012 will have to store greenhouse-gas emissions.

"This is going to take a bunch of work," said Pierre Alvarez, president of the Canadian Association of Petroleum Producers, which includes ExxonMobil, BP and ConocoPhillips. He declined to say whether the requirement will deter investment in Alberta.

BP Oil-Sands Venture in Doubt as Husky Energy Chief Quits

Doubts are surfacing over the future of BP's £5.8 billion project to squeeze crude from the oil-rich sands of northern Canada after one of the chiefs of Husky Energy, its joint-venture partner, resigned unexpectedly.

Catherine Hughes, vice-president of oil sands for Husky, based in Calgary, left the company in January, amid speculation that the project may be delayed after a collapse in the price of oil.

A string of oil-sands projects, which depend on prices of as much as $70 a barrel to remain economic, have been scrapped or delayed in recent months as crude oil prices have plummeted, from highs of more than $147 last July to lows of less than $40 this month.

The economic squeeze on the high-cost business of mining bitumen comes as the oil majors prepare to announce big declines in profits for the final quarter of 2008 because of the falling price of crude.

Ms Hughes's resignation, which came after a decision by Husky to merge its oil sands business with its heavy oil business, comes as the joint venture prepares to decide whether to proceed with the £5.8 billion Sunrise project in Alberta. BP formed the venture with Husky in December 2007, when oil was trading just below $100 a barrel.

A spokesman for Husky said: “Ms Hughes decided to leave the company of her own accord and pursue other options.”

The company said that it was continuing to work towards “optimizing” the Sunrise project. A spokesman for BP said that the company was “confident in the future of the Sunrise project and was still working to bring it to fruition”.

Up to 175 billion barrels of oil are contained in the sands of the Athabasca region, making Canada second only to Saudi Arabia in a ranking of countries' proven oil reserves.

However, extracting crude from sand, either by mining or injecting steam to recover it in situ, is expensive and environmentally controversial, requiring the use of huge amounts of energy and water. The cost of production, at $30 to $40 a barrel, compares with as little as $5 a barrel at some of the largest onshore oilfields in the Middle East.

The nine billion-barrel Sunrise project was scheduled to start in 2012 as an integrated production and marketing operation. BP and Husky planned to use a technology that used a steam-assisted gravity drainage project, whereby steam is pumped underground to loosen up tar-bitumen in the oil sands so that it can be pumped to the surface in wells.

Further details of the future of the project are likely to emerge when BP unveils its final results on February 3.

The plight of Alberta's oil-sands mining industry was highlighted in January when Suncor, the second-largest investor, announced its first quarterly net loss and said that it would cut spending for the second time since October. Suncor has suspended investment on a C$20 billion (£11.9billion) expansion project and has cut spending for 2009 from C$10 billion to C$3 billion.

Suspended Petro-Canada Oil Sands Plant Approved

Alberta's energy regulator said on January 22 it approved Petro-Canada's plans for an oil sands processing plant near Edmonton that the company has already deferred due to low oil prices and the financial meltdown.

The Energy Resources Conservation Board said it imposed 13 conditions, many environmental, along with its approval for the upgrader, which would process bitumen from Petro-Canada's proposed Fort Hills oil sands project into refinery-ready synthetic oil.

The conditions include the company making a commitment to the board by Dec. 31, 2010, that the multibillion-dollar plant will proceed.

"The rationale for that is we require some certainty," board spokesman Darin Barter said. "There could be changes in regulations, changes in landowner concerns in the area, changes in government policy, so we need to make sure this approval is going to meet the standards that are in place."

Petro-Canada and its Fort Hills partners, Teck Cominco Ltd and UTS Energy Corp, said in November that they were pushing back their decision on whether to go ahead with the huge project.

They also said they would forgo the upgrader -- which would be located in the Sturgeon County, Alberta, area -- for the first phase of the development in an effort to save as much as $7.9 billion (C$10 billion).

Fort Hills is just one of numerous oil sands projects that have been put on hold after oil prices fell by more than $100 a barrel from a July record of more than $147 and global credit markets froze.

Suncor Energy Inc said on it was halting working on its C$20.6 billion oil sands expansion until conditions improve.

Among other conditions of the approval, Petro-Canada must conduct a full-scale emergency response exercise before start-up, achieve a 99.5 percent sulfur recovery rate within six months of start-up and submit a noise survey within three months.

Long Lake Partners Pioneer New Oilsands Technique

Nexen Inc. and OPTI Canada’s $6.1-billion technological gamble appears to be paying off as first production of sweet synthetic crude flowed from the partners’ Long Lake oilsands facility in January.

After more than a year in delays, the innovative thermal bitumen operation and upgrading unit ran as planned, on synthetic gas processed from the heaviest bits of the tar-like substance. Full production of 60,000 barrels per day isn’t expected for another year to 18 months, but analysts called the 24-hour run an important catalyst for the project.

“It’s still early days but the positive is it’s producing syngas, which is key because that’s what is going to significantly reduce the projects needed to consume natural gas,” said Philip Skolnick with Genuity Capital.

“The point is you’re taking the portion of the barrel which you get no value out of anyway, and you’re creating value out of it. This could absolutely change the way things are done in the oilsands.”

Thermal oilsands projects use a massive amount of natural gas to generate steam, which is piped into the earth to soften up bitumen and enable it to flow through secondary wells back up to the surface.

The technology being pioneered at Long Lake would reduce the need to buy the fuel by running somewhat of a closed loop system.

Briefly, bitumen is steamed out of the earth, then processed to separate out the sand and water, as other steam assisted gravity drainage projects, then the water gets recycled back into steam.

Where Long Lake gets interesting is that the diluted bitumen then gets partially upgraded, and those products get further upgraded through a hydrocracker into light synthetic crude with low sulfur content, with the asphalt-like bits turned into synthetic gas. The gas is subsequently burned to produce the steam to produce the bitumen, and as a source of hydrogen for the hydrocracker that produces the synthetic crude.

It’s a pretty tidy package, but one both Nexen and OPTI have paid heavily for in pioneering as the Canadian oilpatch is notoriously slow to embrace new technology.

“The key thing that Nexen and OPTI are going to have to show is that their integrated project, which creates a synthetic natural gas burning the bottom of the barrel of bitumen, does provide the expected operating cost savings relative to a project that burns 100 per cent natural gas,” said Chris Feltin of Tristone Capital.

“Now that they’ve shown they can produce a premium synthetic crude, it will help alleviate some of that uncertainty around if the technology will work.”

OPTI, which brought the technology to Alberta, had to battle the lack of credibility and lack of access to funds by selling off 15 per cent of its 50 per cent interest in the Long Lake project to partner Nexen Inc. for $735 million to meet debt payments, just weeks from first production and revenues. OPTI said it needed the cash from the sale to meet a debt covenant in the new year, and to pay debt and interest due in June.

The company lost 89 per cent of its share value in 2008.

Nexen and OPTI aren’t in the clear yet as the upgrader won’t generate cash flow until 2010, Skolnick noted. If the bitumen production doesn’t ramp up adequately at the same time, it could create challenges, as well. He saw a break-even point for Long Lake at around $5 US per thousand cubic feet to make gasification worthwhile in an environment where natural gas is expected to average around $6 per mcf.

“The unfortunate thing with this is the timing of getting the first synthetic crude oil production is it coincided with the crash in light oil prices,” added Feltin. “So the benefit they would have received six months ago isn’t nearly what they’re getting right now.”

Connacher Reinstates Full Production at Oilsands Project in Alberta

Connacher Oil and Gas Ltd., the Calgary-based energy company, says it is reinstating full production at its Great Divide Pod One oilsands project in northern Alberta, just over a month after it said it would cut output almost in half because of low oil prices.

Connacher said January 21 it expects to reach pre-curtailment production of bitumen of 9,000 barrels a day by the end of February.

The company said in mid-December it would cut production to 5,000 barrels a day because of low world prices.

Connacher said at the time it didn´t expect to reduce production for "a protracted period of time," and added that the company would monitor market conditions.

"While crude oil prices for the current month remain low, significant improvement exists in forward crude oil prices and the Canadian dollar has recently weakened against the U.S. dollar both of these factors partially offset low crude oil prices," the company said in a statement.

"In addition, heavy oil differentials have narrowed substantially, in some cases by as much as two-thirds of December 2008 levels, in response to demand from refineries."

On January 21, world oil prices jumped more than six per cent on energy markets as a rebound on Wall Street overshadowed a pending government crude report expected to show that U.S. inventories continue to swell.

Light, sweet crude for March delivery rose $2.71 to settle at US$43.55 a barrel on the New York Mercantile Exchange.

Connacher said the construction program at the Algar oilsands project, which was stopped in December, will stay on hold until the company sees better "visibility in crude oil prices, a thaw in and improvement of capital markets and improvement in the general economic conditions in North America."

Suspended Petro-Canada Upgrader Gains Approval

Alberta's energy regulator said on January 20 it approved Petro-Canada's plans for an oil sands processing plant near Edmonton that the company has already deferred due to low oil prices and the financial meltdown.

The conditions include the company making a commitment to the board by Dec. 31, 2010, that the multibillion-dollar plant will proceed.

Petro-Canada and its Fort Hills partners, Teck Cominco Ltd and UTS Energy Corp, said in November that they were pushing back their decision on whether to go ahead with the huge project.

Fort Hills is just one of numerous oil sands projects that have been put on hold after oil prices fell by more than $100 a barrel from a July record of more than $147 and global credit markets froze.

Suncor Energy Inc said on January 20 it was halting working on its C$20.6 billion oil sands expansion until conditions improve.

Lawrence Pumps to Furnish Specialized Slurry Pumps for Devon Energy Canadian Oil Sands Project

Lawrence Pumps announced recently that it has been selected to supply critical service API slurry pumps for Devon Energy's second oil sands project in Alberta, Canada.

Titled Jackfish 2, Devon Energy's new plant is scheduled to be fully operational in 2012 and will produce 35,000 barrels of oil a day. The plant will use a relatively new process known as Steam Assisted Gravity Drainage (SAGD) to recover an estimated 300 million barrels of oil from the Jackfish 2 site.

SAGD wells are used to recover oil that is released from the sands by the injection of steam underground. It allows oil to be recovered from greater depths than prior methods and is less environmentally damaging to the surface land than prior mining methods.

Developed specifically for handling hydrocarbon slurries under harsh conditions, Lawrence API slurry pumps will be used to transfer the recovered slurry from the well head to a downstream processing facility. In its unprocessed state the bitumen slurry consists of a water, oil, and sand mixture that erodes standard pumps very quickly, resulting in both safety and environmental hazards. The Lawrence API slurry pump incorporates hardened wear liners that resist erosion and protect the outer pump casing from wear and leakage of product to the surrounding environment.

Lawrence Pumps CEO Paul Reddick called the Devon project an important milestone for the company's expanding presence in the Oil Sands region.

McIlvaine Company,

Northfield, IL 60093-2743

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