The shale gas business model is about to make a transatlantic leap to both Europe and Africa, as U.S.-based companies are tapped for their expertise in this unconventional type of development. These areas are all very early stage, and the reserve and production potential is completely unknown.

Part of the motivation in Europe is an effort by the governments to reduce dependence on gas imported from Russia, which is viewed by many countries as an unreliable source for future needs.

Africa

StatoilHydro ASA, Chesapeake Energy and Sasol Ltd recently submitted a joint application to explore the Karoo Basin in South Africa. StatoilHydro ASA is currently partnering with Chesapeake Energy to develop the Haynesville Shale.

Falcon Oil and Gas Ltd., a smaller exploration and production company, is a little farther along in the process and was awarded a permit earlier in 2009 to assess the Karoo Basin. The basin has potential as nine wells were drilled here in the 1960s and 1970s, and all encountered gas pay. One well produced 1.84 million cubic feet of gas per day. While this may seem a pittance compared to some of the U.S.-based shale play production rates, the well was drilled almost a half century ago with none of the advanced technological advantages of modern drilling.

Europe

Exxon Mobil seems to be among the more aggressive of the international majors in assembling acreage in Europe that is prospective for unconventional shale gas. The company has 750,000 acres in Germany, 400,000 acres in Hungary and acreage in Poland as well.

It's possible that Exxon's aggressiveness is a response to what some see as a failure to exploit similar opportunities in unconventional shale in North America.

Marathon Oil is another company in the early stage of developing shale resources on its international properties. One of these areas is near Kwidzyn in northern Poland, where the company was awarded a license to explore. Marathon Oil has a 100% working interest in the lease.

The lease size is 295,000 acres, and Marathon Oil will try to tap the unconventional resources at depths from 8,000-13,000 feet. The shale is anywhere from 100-500 feet thick.

Competition

ConocoPhillips is also starting to explore for natural gas in Poland. ConocoPhillips signed an agreement with Lane Energy, a subsidiary of 3Legs Resources. Lane Energy has six licenses covering 1 million acres.

ConocoPhillips has an option to acquire up to a 70% stake in the licenses. The company is shooting seismic and will drill an exploration well in the first quarter of 2010.

International Shale

Europe and other international areas are starting to get the unconventional shale bug, as it slowly dawns on other countries that these resources lay under their own soil. It will take years, however, before the commercial viability of these resources is known, and whether it will make a difference in world markets.

AMERICAS

U.S.

Denbury Resources Buys Interest in Conroe Field for $430.4 Mln

Denbury Resources' DNR plan to acquire Conroe Field from privately owned Wapiti Energy LLC for $430.4 million makes sense strategically given its proximity to the soon-to-be completed Green Pipeline. Denbury agreed to buy a 95% working interest in the Conroe Field located north of Houston, Texas, and will become the operator. Denbury plans to pay for the $430 million purchase with $256.4 million of cash and 11,620,000 shares of Denbury common stock and close the purchase by Dec. 18, 2009.

Part of the cash portion of the purchase will be funded by the sale of Denbury's remaining Barnett Shale assets for $210 million to Talon Oil & Gas LLC, which purchased 60% of the firm's Barnett Shale properties earlier this year. This Conroe Field purchase is viewed favorably as a means to extend Denbury's tertiary oil production growth beyond its first eight project phases. And the model will be reviewed to reflect the effects of the Barnett asset sale and future production growth potential of the Conroe field.

EPA To Hit Large Emitters with CO2 Rules Next Spring

The head of the U.S. Environmental Protection Agency said December 7 that large emitters of greenhouse gases would come under new regulations next spring to limit such emissions.

The new regulations which will follow December 7’s related EPA declaration that greenhouse gases are a danger to the public's health and welfare, will require firms that are building or modifying power plants, refineries and other industrial emitters to install the "best available" technology.

The EPA will soon begin determining what technology will be required.

EPA Administrator Lisa Jackson said at a press conference that she didn't believe that the agency should establish national air quality standards for greenhouse gases, as at least one environmental organization has petitioned.

Such a standard would set a total greenhouse gas level at, for instance, 350 parts per million in the atmosphere across the nation, requiring regions and states to meet those levels. Currently, the carbon dioxide in the Earth's atmosphere is around 390 parts per million, according to the U.S. government.

But, experts say, because greenhouse gases such as carbon dioxide aren't localized like other air pollutants, and travel across borders and countries, it would be nearly impossible to meet such a standard if other emitting nations didn't also set and meet such a target.

1940’s Era Anvil Points Shale Waste still being Cleaned Up

Federal officials are looking to find a place to bury as much as 20,000 cubic yards of waste material from a 1940s-era research project.

The Bureau of Land Management, which is in charge of cleaning up the Anvil Points Oil Shale Research Project located in Garfield County, already has shipped 90,000 cubic yards of material to the Denver-Arapahoe Disposal Site near the Lowry Landfill, bureau spokesman David Boyd said.

Delta County officials had been advised that the material might be sent to a landfill there, but Boyd said that seems unlikely.

“Right now, it’s not looking like it’s going to go to a Western Slope location,” Boyd said. “It’s not economical.”

The material, which is what remained after oil shale was heated in a retort to release a petroleum-like substance, is known in the industry as “spent shale.”

The cleanup of the research facility included a 175,000-cubic yard disposal cell on the site, but officials were aware that it would be too small to take in all the spent shale from the 1940s-era facility, Boyd said.

About 85,000 cubic yards of spent shale remain, and officials believe they can deal with 65,000 cubic yards of it, Boyd said.

That leaves the 20,000 cubic yards for which officials must find a disposal location.

The cleanup is expected to be complete by the end of January, though there will be continued monitoring of the site, Boyd said.

As of November, the cleanup cost $18.7 million.

Money for the cleanup comes from royalties paid on natural gas drilling on the former Naval Oil Shale Reserve, which is administered by the bureau.

AuraSource Reaches Agreement with China for U.S. Oil Shale Development

AuraSource, Inc, a developer of hydrocarbon clean fuel technology, has entered into an agreement with China Chemical Economic Cooperation Center ("CCECC"), a Chinese governmental division which leads China's energy and environmental research and development. Under the agreement, CCECC agreed to license their patented technology to AuraSource in the United States and its territories.

The license allows AuraSource to use the technology for a period of twenty years. Additionally, AuraSource and CCECC agreed to conduct experiments and analysis on various mineral deposits and start a detailed feasibility study and business planning on the first phase of construction of a one million ton oil shale refinery in the United States.

CCECC's technology consists of patents, patents pending and other intellectual property for the process of extracting fuel, such as lightweight fuel oil and oil dry gas, from bituminous oil shale by low temperature catalyzing. This process is more efficient and cleaner than current alternatives in use today.

Cao Zhide, CCECC's President, commented that, "Alternative energy technology for oil substitution is part of the Sino-US Energy Research Cooperation framework. CCECC is currently working with AuraSource and its investment partner to construct a one million ton oil shale refinery and demonstration venture in Qinzhou, China. We plan to further assist AuraSource to develop one of the most efficient large scale oil shale processing plants in the U.S."

Philip Liu, AuraSource's CEO, stated, "We aim to develop clean energy technology which is more economical and scaleable than other current technologies in use today. CCECC's low temperature catalyzing technology has overall reliability, thermal efficiency with an optimum production streaming line system, and utilization of organic heating value in all phases of production. AuraSource will further apply for a U.S. RD&D oil shale lease and partner with an oil shale resource development firm to develop a refinery demonstration venture within the United States."

Marathon Oil’s $3.5 Bln 2010 Upstream Strategy to Include Oil Sands and Oil Shale

Marathon Oil will spend $3.5 billion on upstream capital expenditures in 2010. This will be split among its unconventional and conventional properties, the deepwater, and the oil sands. The company believes that it will be able to achieve a 4% compound annual growth rate of production from 2008 to 2011.

Thirty-five percent of these capital expenditures are targeting Marathon's extensive portfolio of deepwater projects. The company has been working on the Droshky prospect located on the Green Canyon Block 244 in the Gulf of Mexico. The company expects first production to come on line in 2010, with peak production of 51,000 barrels oil equivalent (BOE) per day. Marathon Oil has a 100% working interest in this project.

Marathon Oil is also active in the Lower Tertiary formation in the Gulf of Mexico, and participated in the Stones and Shenandoah prospects well located on the Walker Ridge blocks. These two are at the early stage of development but will help with production growth at the end of the decade. Marathon Oil has a 10% working interest in Shenandoah, with Anadarko Petroleum as the operator owning 30%, and ConocoPhillips with a 40% stake in this discovery.

Another 19% of capital exploration dollars next year are going into the oil sands of Canada. Marathon Oil owns 20% of the Athabasca Oil Sands Project located in Alberta, Canada. This project is a joint venture with Royal Dutch Shell, which owns 60%, and Chevron, which owns 20%. Marathon Oil and its partners are currently in the midst of an expansion here, and estimates that when the expansion is complete in 2011, Marathon's share of the production will be 50,000 barrels per day from this project.

Marathon Oil is also moving forward to develop its assets in the domestic shale plays that the smaller independent exploration and production companies have moved so quickly to exploit. In the Bakken Shale in North Dakota and Montana, Marathon Oil has 336,000 net acres under lease and is currently producing 10,000 BOE per day out of the area, and is operating four rigs there. The company expects production to peak at 15,000 in 2013.

Marathon Oil also has a more prospective position in the Haynesville and Marcellus Shale. In the Haynesville Shale, Marathon Oil has 25,000 net acres under lease but has barely started developing its acreage. The company is drilling only two wells in 2009, and three to four in 2010.

Marathon Oil has 70,000 net acres in the Marcellus Shale, but is also developing the play slowly as it acquires the technical knowledge to develop it correctly. The company drilled four wells in 2009, and plans eight to 12 in 2010.

Marathon Oil is moving deliberately to develop its diversified upstream position as it reallocates capital to areas that are economical under the oil prices that are still half of what they were at the peak.

Independent Oil Spending up Slightly in 2010 Says IPAA

Total capital spending by independent U.S. oil and gas companies will rise slightly in 2010, but those heavily into natural gas may have to cut outlays, an industry leader said December 11.

Bruce Vincent, chairman of the Independent Petroleum Association of America and president of Swift Energy Co (SFY.N), did not have an estimate of total dollars his members will spend in 2010.

Investment bank Tudor, Pickering & Holt expects independent exploration and development spending to grow to $44 billion from $37 billion in 2009. Tudor, Pickering covers publicly held companies while IPAA includes many private firms.

"As a general rule, independents will spend their cash flow," Vincent said, but he added a cautionary note. "We see gas prices having a pretty tough time in 2010," he said.

"Companies that are gas-weighted and don't have much hedged production are going to have less cash flow and, as a consequence, we believe they'll have to reduce spending," Vincent said.

"Companies that are oil-weighted and are hedged to a reasonable degree in 2010 probably will maintain or slightly increase their spending," he said.

Hedging - in which companies buy or sell futures contracts to protect themselves against sharp increases or declines in commodity prices - has been a key variable in company performance in recently volatile energy markets.

Another key variable is the health of the financial markets, which Vincent said has improved in the second half of 2009 and enabled companies to raise more money to fund operations.

As for oil and gas production in 2010, he said big independents heavily into shale gas are forecasting increased output, but a big unknown is when production will decline due to the recent sharp slowdown in drilling.

"Whether it's early in the year or later in the year will have a pretty dramatic impact on the overall production outlook," Vincent said.

In a report November 18, Tudor, Pickering forecast a 9 percent increase in production by publicly held independents.

ExxonMobil and XTO Energy Announce $41 Bln Agreement to Enhance Development of Unconventional Natural Gas and Oil Resources

Exxon Mobil Corporation and XTO Energy Inc. announced December 14 an all-stock transaction valued at $41 billion. The agreement, which is subject to XTO stockholder approval and regulatory clearance, will enhance ExxonMobil’s position in the development of unconventional natural gas and oil resources.

Under the terms of the agreement, approved by the boards of directors of both companies, ExxonMobil has agreed to issue 0.7098 common shares for each common share of XTO. This represents a 25 percent premium to XTO stockholders. The transaction value includes $10 billion of existing XTO debt and is based on the closing share prices of ExxonMobil and XTO on December 11, 2009.

“We are pleased that ExxonMobil and XTO have reached this agreement,” said Rex W. Tillerson, chairman and chief executive officer of Exxon Mobil Corporation.

“XTO is a leading U.S. unconventional natural gas producer, with an outstanding resource base, strong technical expertise and highly skilled employees. XTO’s strengths, together with ExxonMobil’s advanced R&D and operational capabilities, global scale and financial capacity, should enable development of additional supplies of unconventional oil and gas resources, benefiting consumers both here in the United States and around the world.”

Tillerson said the agreement is good news for the United States economy and energy security, as it will enhance opportunities for job creation and investment in the production of America’s own clean-burning natural gas resources.

XTO’s resource base is the equivalent of 45 trillion cubic feet of gas and includes shale gas, tight gas, coal bed methane and shale oil. These will complement ExxonMobil’s holdings in the United States, Canada, Germany, Poland, Hungary and Argentina.

Following the transaction closing, ExxonMobil intends to establish a new upstream organization to manage global development and production of unconventional resources, enabling the rapid development and deployment of technologies and operating practices to increase production and maximize resource value. The new organization will be located in Fort Worth, Texas, in XTO’s current offices.

Bob R. Simpson, chairman and founder of XTO, said that over the company’s 23-year history, XTO has developed technical expertise and has assembled a substantial, high-quality and diverse resource base in producing basins across the United States.

“XTO has a proven ability to profitably and consistently grow production and reserves in unconventional resources,” said Simpson. “As the world’s leading energy company, ExxonMobil will build on our success and open new opportunities for the development of natural gas and oil resources on a global basis.”

Tillerson said the agreement is part of an ongoing, disciplined evaluation of timely investment opportunities to create value for shareholders, and to help meet long-term global energy demand growth. The agreement is consistent with ExxonMobil’s business model which is focused on sustainable, long-term value creation.

Completion of the transaction is expected in the second quarter of 2010. In connection with the transaction, J.P. Morgan Securities Inc. are acting as financial advisors to ExxonMobil and Barclays Capital Inc. and Jefferies & Company Inc. are acting as financial advisors to XTO.

Range Resources Adds Marcellus Processing, Pipeline Capacity

Range Resources Corp. on December 14 announced that the third phase expansion of the Marcellus Shale natural gas processing infrastructure has been completed.

The third phase expansion includes an additional 120 Mmcf per day of cryogenic natural gas processing capacity, 20 miles of additional gathering and residue gas pipelines and 21,000 horsepower of additional compression. The phase three assets are located in southwestern Pennsylvania and are owned and operated by MarkWest Liberty Midstream & Resources, L.L.C., a joint venture between MarkWest Energy Partners, L.P. and Midstream & Resources, a private equity fund. MarkWest Liberty has long-term agreements with Range to provide gathering and processing services and infrastructure assets.

With the expansion, Range's total Marcellus Shale infrastructure capacity is now approximately 180 Mmcf per day. The processing capacity for high Btu gas is approximately 155 Mmcf per day, while the gathering capacity for dry gas (gas that does not require processing) is approximately 25 Mmcf per day. With the completion of the additional cryogenic gas processing facilities, all high Btu gas will be processed through cryogenic facilities, and the existing refrigeration facilities will be removed. The new cryogenic plant will recover approximately twice the amount of hydrocarbon liquids versus the refrigeration facilities. Given the high Btu content of Marcellus Shale gas in southwestern Pennsylvania, coupled with currently strong liquids prices, the high Btu Marcellus gas price receives a significant uplift. Based on the current natural gas liquids and gas prices, the gross net back at the wellhead is approximately $2.25 per Mmbtu greater than dry gas, a 45% uplift. As a result, the economics for drilling high Btu Marcellus wells is extremely attractive.

Looking forward, additional high Btu gas expansion projects are being developed to increase Range's high Btu gas infrastructure capacity to 185 Mmcf per day by the third quarter of 2010 and to more than 300 Mmcf per day by mid-2011. In addition, Range has several dry gas infrastructure projects under consideration.

John Pinkerton, Range's Chairman and CEO, said, "MarkWest is doing a terrific job building out gas processing infrastructure for our Marcellus production in southwestern Pennsylvania. Range's Marcellus team is also making significant progress on all fronts. They have done an excellent job contracting for and marshalling the construction of pipelines, processing and other needed infrastructure, while balancing local community needs. In addition, we are now at zero liquid discharge, and we are recycling and reusing 100% of the water in our core operating area. Our Marcellus drilling continues to generate exceptional results, and we have made excellent headway driving down costs. We are also making great strides in familiarizing Pennsylvanians, including landowners, elected officials, regulators and conservation groups on modern, responsible natural gas development. Range is well positioned to continue to ramp up its Marcellus production, which in turn provides job opportunities and economic stimulus for Pennsylvania."

Cantwell Unveils Alternative Climate Bill

U.S. Sen. Maria Cantwell, (D., Wash.) on December 11 unveiled an alternate climate bill that would auction all emission credits to fund consumer rebates and limit the auction market to polluters.

The proposal, offered as an alternative to the bill passed in the House of Representatives and by the Senate environment committee, has already garnered support from two unlikely allies and promises to stir debate on the controversial policy.

While its fate is uncertain, the proposal may erode efforts to pass the existing climate legislation by attracting support from some lawmakers. Sen. Susan Collins, (R., Me.), has signed up as a co-sponsor. Sen. Lisa Murkowski, (R., Ak.) welcomed the legislation, saying, "it should certainly be one of the approaches we spend time considering in the coming months."

The conventional approach in Congress so far has been to set an emissions cap and distribute billions of dollars worth of emission credits to affected industries--a political effort to win reluctant lawmaker backing. Those industries are expected to then pass the credit value on to consumers, ostensibly protecting them from higher energy prices as new, more expensive but lower-emission technology is built.

"This is a much simpler process," Cantwell said in an interview. "The system of who gets what can obviously be influenced," she said. Her legislation would provide investors with a more "predictable mechanism" for clean energy expansion while cutting greenhouse gas emissions, she said.

Only 2,000-3,000 of the nation's largest emitters would be able to buy and sell emission credits auctioned by the government, with credit values rising as mandated greenhouse gas levels fall. Seventy-five percent of auction revenues would be recycled into monthly tax-free checks to the public to help pay for rising energy costs. She estimates between 2012 and 2030, for the average family, those checks could average $1,100 to $21,000 a year.

The remaining revenues would be funneled into a clean energy fund to finance low-carbon technologies.

President Barack Obama had originally proposed auctioning all the emission credits, a policy his budget office said could raise $650 billion over a decade at a conservative estimate for emission credits. In the House, the chairman of the energy committee, Rep. Henry Waxman, (D., Calif.), also wanted to auction off all the credits but had to agree to distribute emission credits for free in the face of political reality. Without the so-called allocation scheme, Waxman wouldn't have been able to pass the bill.

Cantwell's proposal partly stems from the fear that allowing financial participants into the emissions derivatives market would open the floodgates for market manipulation that could have a harmful impact on the economy. Their concerns were compounded by last year's record oil price spike, as well by the meltdown in the credit derivatives market that helped trigger the current economic crisis.

The financial community, however, says blocking what some predict could be a multi-trillion-dollar futures market would stunt the financial services necessary for cultivating a clean-energy economy. For example, if utilities weren't able to trade in the emission credit futures markets, they may not be able to find financing for new, expensive carbon dioxide sequestration technology.

Pressed on how her proposal could gain traction in the face of Congressional politics, Cantwell said she's counting on the simplicity of the structure and public payments to rally backing.

"Public Citizen supports the Cantwell-Collins legislation as a needed fresh start to address climate change," said Tyson Slocum, director of advocacy group's Energy Program. "Solving climate change is simply too important to entrust to traders at Goldman Sachs and J.P. Morgan Chase," he said.

Range Reaches Marcellus Production Milestone

Range Resources Corporation announced December 16 that it has achieved a significant milestone in the development of the Marcellus Shale formation in Pennsylvania, as its net production from the Marcellus Shale has reached 100 Mmcfe per day. This represents almost a four-fold increase over this time last year and represents the high end of Range’s 2009 production target of 80 to 100 Mmcfe net per day. Range’s Marcellus Shale production target exit rate for 2010 is 180 to 200 Mmcfe net per day. Given the significant progress made in 2009, in all phases of the development process, Range has extended its forecast to include a 2011 exit rate from the Marcellus Shale of 360 to 400 Mmcfe net per day. It is important to emphasize that all the production results and targets referred to above are net to Range’s interest and exclude production attributable to landowners’ royalty interests and third-party working interests.

Commenting on the announcement, Jeff Ventura, Range’s President and Chief Operating Officer, said, “We are extremely pleased with the progress of our Marcellus Shale team. They have quadrupled Marcellus production in 2009 and continue to optimize drilling and completion techniques. As a result, our per-well production rates continue to improve, while costs continue to decline. We are well-positioned to ramp up our Marcellus production at low cost.”

Range entered 2009 running four rigs in the Marcellus Shale play and will end the year with eleven rigs, including both horizontal and vertical rigs. Range anticipates exiting 2010 with 16 rigs in the Marcellus, increasing to 24 by year-end 2011. Additionally, Range has completed the drilling of two horizontal wells in Lycoming County, Pennsylvania, in the northeastern portion of the play. Completion operations have commenced on the first of these two wells.

John Pinkerton, Range’s Chairman and Chief Executive Officer, said, “With the wells drilled by Range and the industry, we believe that approximately 390,000 net acres of Range’s large leasehold in the southwestern portion of the play has been materially de-risked. Our Marcellus team is continuing to delineate our sizeable acreage position in the northeastern part of the play. In addition, we are testing additional shale formations, above and below the Marcellus. It’s becoming more and more clear that the Marcellus Shale will likely become a very large natural gas field. This is a game changer for Range and its shareholders, for Pennsylvania and energy consumers. According to a study by Penn State University, the Marcellus Shale has the potential to create 98,000 jobs and to contribute $14 billion to Pennsylvania’s economy in 2010.

Exxon's $41 Bln Bid Spotlights Bright Future for Natural Gas

After quietly grabbing up unconventional natural gas reserves for years, Exxon Mobil Corp. moved boldly to buy one of the largest U.S. independent gas companies, XTO Energy, in a deal valued at $41 billion.

The oil and gas behemoth announced that it planned to use XTO to establish a new business unit that would develop and deploy technologies to extract fuels from shales, tight sands and coal seams.

Analysts see Exxon's bid -- the company's biggest financial move since its merger with Mobil in 1999 -- affirming the growing status of natural gas as a U.S. energy source.

"I think what it is; is a fairly massive statement of optimism in the long-term future of natural gas in the United States," said David Bloom, a regulatory attorney covering energy issues at Mayer Brown.

Over the past decade, Exxon Mobil has built up its reserves of unconventional natural gas resources like shale gas, tight gas and coalbed methane, which could hold decades of energy supplies but have historically been difficult to extract. New technological developments, like those developed and employed by XTO, have allowed such plays to become a viable part of the global energy mix.

Exxon has socked away natural gas reserves in tight sands, shales and coal seams in Colorado, Pennsylvania, Canada, Germany, Hungary and Argentina.

"Over the last decade we have grown unconventional gas resources to approximately 7 percent of our resource base," David Rosenthal, vice president of investor relations at Exxon Mobil, said.

XTO's resources would add nearly 14 trillion cubic feet of proven reserves to Exxon's portfolio, with nearly 80 percent of those, natural gas. Together, the two companies would hold the largest unconventional natural gas acreage portfolio in the industry, at nearly 8 million acres. An XTO acquisition would also bring its significant oil shale position to the table.

"We have been securing a portfolio of unconventional opportunities globally, and we like the position we've got, but now we have large areas that require appraisal and ultimately require an organization to develop those in the most efficient and profitable way possible," Exxon Mobil CEO Rex Tillerson told reporters. "This opportunity provides us both access to what we believe is a high quality resource base within the United States and a ready-built, purpose-built organization."

Access to XTO's expertise and experience in unconventional plays would be a major asset to Exxon, according to a Morningstar analyst.

"Exxon also gets XTO's experienced unconventional gas development team, which could be considered icing on the cake," Eric Chenoweth, the analyst, wrote recently.

The move -- a show of confidence in the future of unconventional resources -- could also spur additional investment in domestic unconventional natural gas plays like the Barnett in Texas, Marcellus in Appalachia and Haynesville in Louisiana.

"The scale of Exxon's investment is an indication that it believes the progress made so far is well-founded, and I think that's an important sign to the entire sector," Bloom said. "It clearly makes available massive new amounts of money for the development of these plays, and we're quite likely to see other parties come into the industry and make financial contributions."

Chenoweth at Morningstar said other companies that are major players in unconventional natural gas resources could also be attractive targets for major oil and gas producers looking to expand their positions in unconventional plays. Among those are large independents Chesapeake, Devon and EnCana and smaller firms Range Resources -- which has significant acreage in the Marcellus Shale -- Petrohawk, Ultra Petroleum and Southwestern.

"All of these companies have meaningful positions in U.S. unconventional gas plays that could be attractive to a major, though it would be more of a bolt-on deal," Chenoweth wrote.

Exxon's move is not necessarily a surprise. In its world energy outlook released last week, the company said it expected natural gas demand to grow at a faster rate than coal or oil, driven largely by significant growth demand for power generation.

"These resources are attractively positioned to increase natural gas production and to meet the growing demand for natural gas, which is expected to be the single biggest contributor to the U.S. and global energy mix over the coming decades," Rosenthal said.

Some see the move as a significant bet by the long-time stalwart against climate change that proposed climate legislation would boost natural gas over coal in the power sector by placing a price on greenhouse gas emissions (ClimateWire, Dec. 15).

"It's a statement of optimism that natural gas will play a role in addressing climate change issues, whether as a bridge fuel as we transition to a greater use of renewables or as a competitor to coal," Bloom said. "But it's a pretty important statement that there's going to be demand for natural gas."

Kert Davies, a research director at Greenpeace, agreed, adding that Exxon doesn't make any decisions lightly.

"This decision was made deliberately with calculation of how important natural gas will be in the future," Davies said. "The oil industry is all about putting their chips on the roulette wheel, and this is an indication that Exxon is seeing natural gas as one of those players."

The announcement comes just five months after the oil giant announced a $600 million investment in algae-based biofuels, a surprise move that stunned the industry. The algae investment and a major unconventional natural gas investment point toward Exxon's willingness to adapt to a changing energy future.

"Exxon wants to be an energy supplier in the long-term future," Bloom said. "And that's going to come in a variety of formats."

Exxon's bid has been widely viewed as the biggest endorsement yet for shale gas production both in the U.S. and abroad because Exxon, the largest U.S. oil company by market value, has more of the wherewithal to develop unconventional natural gas resources, such as shale.

While scores of service companies can help develop these fields, Exxon is likely to turn to the most experienced and biggest providers of oil field services that can provide bundled development packages, said Bill Herbert, an analyst with Simmons & Co.

Herbert said that XTO's stable of 15 contract drillers would likely be cut in half by Exxon.

"They are not going to deal with as many contractors and will have more exacting standards," Herbert said.

The ramifications of an Exxon-XTO merger underscore the challenges of oil patch consolidation for oil service firms.

As larger oil companies begin to dominate shale drilling, small service providers could find themselves displaced by their bigger brethren. The XTO buyout "is going to push the industry to a more sophisticated way of doing business and increase its focus on equipment that provides greater efficiency," said Doug Sheridan, managing director of EnergyPoint Research, which tracks customer satisfaction in the oil field services sector.

Herbert said that "premium service providers" like Schlumberger Ltd. (SLB) and Halliburton Co. (HAL) would likely benefit from the transaction. Baker Hughes Inc. (BHI), with its pending acquisition of BJ Services Co. (BJS), would also likely benefit, as BJ Services' pressure-pumping business is considered key to unconventional gas development.

Schlumberger, Baker Hughes and Halliburton declined to comment on the potential impact.

Land driller Helmerich & Payne Inc. (HP), which owns high-efficiency drilling rigs that primarily operate on long-term contracts, is also likely to be a beneficiary, Simmons & Co.'s Herbert said. Those rigs have been widely used to exploit unconventional sources of natural gas and about 80% of its fleet is contracted by major oil companies or large independent energy producers.

The Exxon-XTO deal could be a welcome change for big service providers, which have reported drastically lower earnings this year as the recession-stricken producers that have until now ruled unconventional gas exploitation pulled back on drilling in the face of low demand for natural gas. The number of rigs drilling for natural gas in North America is down more than 40% from last year, according to Baker Hughes data.

CANADA

Canada’s Oil Sands Cleanup Efforts Criticized

With Canada facing mounting international pressure to confront its sluggish emission-reduction record heading into the Copenhagen climate meetings in December, environmental groups have released yet another unflattering appraisal — this one showing that seven of Alberta’s nine oil sands projects will fail to meet new cleanup rules for the vast tailing ponds near bitumen refineries.

Absent compliance, the Pembina Institute and the Water Matters Society of Alberta estimate that by 2020, Alberta’s tailing ponds could contain about 300 million gallons of toxic liquid and cover almost 100 square miles — an area the size of Brooklyn. Those figures represent a 30 percent increase over current volumes.

After assessing available corporate and government data, the group concluded that most oil sands projects are years away from complying with a February 2009 directive requiring producers to capture 50 percent of fine particles by mid-2013.

The tailing ponds made headlines in the spring of 2008, when hundreds of ducks died after landing in these contaminated man-made lakes.

Alberta’s Energy Resources Conservation Board announced the new cleanup rules after the controversy. Simon Dyer, a Pembina oil sands analyst, said in a release that it was “troubling” that most producers did not appear to be moving toward compliance.

Oil company executives say the delays have to do with the slow development of technologies capable of sifting the suspended materials out of the ponds, according to The Globe and Mail, which also quoted an official from the Energy Resources Conservation Board as saying that new applications would not be granted without approved cleanup plans.

Mr. Dyer, however, told Green Inc. that it had been very difficult to determine whether the government was actually enforcing its own rules. “There is a real lack of information,” he said.

That conclusion dovetails with a hard-hitting investment risk assessment on the oil sands released late last month by Northwest and Ethical Investments, which is part of the Ethical Funds Company in Vancouver. The fund managers said that only Shell had established clear emission reduction targets, while most other producers failed to disclose mitigation strategies or plans to address water and land-use issues.

The report stated:

Despite the obvious liability presented by mining tailings ponds, there is little clarity about financial provision for their reclamation. Not all operators include tailings ponds within their asset retirement obligation (A.R.O.) reporting, and none were willing to disclose the reclamation cost estimates that underlie the tailings pond portion of their A.R.O. calculations.

Proposed $4.5 Bln Oil Pipeline would Link Oilsands to B.C. Coast

Enbridge's proposed pipeline to the B.C. coast was a small step closer to reality after federal agencies started the regulatory process for the Northern Gateway project.

If approved, Enbridge would join Kinder Morgan in shipping Canadian crude to the coast and help open the Asian market to Alberta's oilsands.

The National Energy Board and the Canadian Environmental Assessment Agency announced an agreement December 4 to form a joint review panel to scrutinize Enbridge's plan for the 1,170-km dual pipeline that'll be running from Bruderheim near Edmonton to Kitimat.

Enbridge has yet to officially apply to construct the pipeline.

An NEB spokeswoman said once that happens, the review process could take about 18 months, judging from similar reviews.

Company spokesman Steve Greenaway said Enbridge expects to file the application toward the end of the first quarter next year.

If approved -- and Greenaway said he's confident the pipeline will get the green light -- the first pipe could be laid in 2013, with construction to finish within about 2 1/2 years.

A 2005 preliminary estimate pegs the construction cost at $4.5 billion, but Greenaway said the final figure will likely be higher.

From Kitimat, the crude would be shipped to California and Asia, which Greenaway said are "important markets that are currently underserved."

Increasing Canada's capacity to export crude overseas would benefit the energy sector, said Patricia Mohr, a commodities expert at Scotiabank.

"It would be advantageous for us to have another export outlet," she said.

Future Statoil Oilsands Phases to be Built Ready for Carbon Capture and Storage

Statoil Canada Ltd.'s future oilsands projects will be designed with carbon capture and storage in mind, the new president of the Norwegian company's Canadian wing says.

But the greenhouse gas-snatching technology has a long way to go before it's economically viable without government support, said Lars Christian Bacher in an interview.

"When it comes to the building of the next phases of our oilsands leases, they will be built CCS ready," said Bacher, who took up his post in September.

"But of course in order to add on that sort of a facility to capture the CO2, one definitely needs an improvement when it comes to the financial aspect of it."

The federal and Alberta governments have committed billions to support the technology, in which carbon dioxide molecules are scrubbed from emissions and then pumped underground to be stored permanently.

Supporters say the technology will help curb climate change by reducing the amount of CO2 released into the atmosphere from coal plants, oil refineries and other heavy industrial emitters.

Critics say the costs remain prohibitive and the technology has yet to be proven on a commercial scale.

Statoil, two-thirds owned by the Norwegian government, has been a global leader in carbon capture and storage, with three major projects up and running and a fourth in the works.

There are offshore carbon capture facilities at Snohvit and Sleipner in Norway, and at a gas field in Algeria. A test facility at its Mongstad refinery in Norway is scheduled to start up in 2011.

Statoil entered Alberta's oilsands in 2007, starting work on its Leismer demonstration project shortly thereafter.

Leismer will use steam-assisted gravity drainage, or SAGD, technology to draw the tar-like bitumen out of the ground. In SAGD operations, steam is pumped deep into the oil-laden earth, softening it so that the oil can flow more freely to the surface.

The project is "running according to plan," said Bacher. The plant is 73 per cent complete, and first steam is expected in October 2010.

As of today, it does not make economic sense to build a carbon capture and storage facility alongside that project. But if the technology and costs improve in the future, Statoil wants to ensure CCS infrastructure can be easily attached, Bacher said.

About a year ago, Statoil scrapped plans to build an oilsands upgrader in the Edmonton area to process heavy oilsands crude into a higher quality type of oil.

"It's still on the shelf, but of course we are following the trends and the developments in the industry from day to day," Bacher said.

For now, Statoil plans to sell the bitumen to other refiners and upgraders that can handle heavy crude.

In addition to the oilsands, Statoil has staked out a large position off Canada's East Cost. It is a partner in the Hibernia and Terra Nova fields, as well as the planned Hebron and Hibernia South Extension fields. It recently made a discovery in the Flemish Pass area, in which it has a 65 per cent working interest.

Bacher brings experience in offshore exploration to Statoil Canada. Before making the move, he led the restructuring and integration of Statoil's operations on the Norwegian continental shelf.

WorleyParsons Wins Contract for B.C. Gas Plant

WorleyParsons has been awarded an engineering, procurement and construction management services contract for Spectra Energy's Fort Nelson North Processing Facility Project located in British Columbia, Canada.

The project involves the design and construction of facilities, including a new natural gas plant, to process raw shale gas from the Horn River Basin area of northeast British Columbia.

The new natural gas plant, located adjacent to Spectra Energy's existing Cabin Lake booster station will have the capacity to process 250 million cubic feet (7 million cubic meters) per day of inlet gas. The facility is scheduled for commercial start-up in early summer 2012.

Commenting on the award, John Grill, CEO of WorleyParsons said, "This contract represents an important recognition of WorleyParsons' project delivery capability and its expertise in gas processing. The contract award also reflects the quality of work completed by the project team for Spectra Energy during the front end engineering design phases of the project."

Nexen Provides Long Lake Oil Sands Project Update and 2010 Budget

Nexen continues to report positive results at Long Lake following the successful completion of the turnaround program in September. As we move into 2010, our priorities include the ramp up of Long Lake, sanctioning our discoveries in the North Sea, the continued improvement of our Horn River shale gas returns, the development of our offshore Usan project and ongoing exploration in our core areas.

At Long Lake, we have achieved a number of major milestones over the past year. Our gasification process is working as designed, creating a low cost fuel source which reduces our need to purchase natural gas for operations. Once the project is fully ramped up, it generates a significant margin advantage over our peers and we maintain this advantage even at current gas prices.

The upgrader is fully operational. We are approaching design yields and we have successfully produced over 1.5 million barrels of the highest quality synthetic crude in North America. Upgrader run times are increasing and in November, improved reliability allowed us to process 95% of our bitumen production.

Now that all components of the upgrader are operating as planned, we are focused on maximizing bitumen throughput. We will achieve this by increasing production volumes from our reservoir and by purchasing bitumen from third-parties to enhance returns.

The reservoir is responding to consistent steaming. Following a turnaround completed in September, the reliability of our water treating systems has improved substantially and currently, steam injection rates are at an all-time high of approximately 100,000 bbls/d. We are injecting steam into over 70 well pairs with 50 on production and the remainder circulating steam in advance of becoming producers. This is the highest number of wells that have received consistent steam to date. Prior to the turnaround, steam limitations only allowed us to inject steam consistently into approximately 35 well pairs.

Bitumen production levels are responding to the increased steam volumes and gross production is averaging approximately 17,000 bbls/d. As we start to circulate steam in more wells, our all-in steam-to-oil ratio (SOR) will remain high and is currently approximately 6 with about 20 wells receiving steam but not yet producing bitumen. The SOR of our producing wells is approximately 4.5 and trending down. With the ongoing installation of electric submersible pumps (ESPs), we are seeing improvements in our SORs. We continue to expect a long term SOR of 3 over the life of the project.

In addition to the continued installation of ESPs, our capital investment program in the coming year includes the drilling of two sustaining well pads in accordance with our full field resource development plan. These pads will be available to come on stream starting in 2012.

"We are still in the SAGD ramp up phase and are pleased with post-turnaround performance," said Marvin Romanow, Nexen's President and Chief Executive Officer. "Steaming reliability has improved and this is leading to higher bitumen production. We are confident that we will ramp up to full rates and demonstrate the significant value this project will deliver to our shareholders."

2010 Budget

Our strategies are focused on oil sands, shale gas and conventional development and exploration in select basins. In 2010, we plan to advance these strategies by investing $2.5 billion and growing production after royalties by approximately 4 to 6% assuming the midpoint of our guidance.

The timing of potential activities in the North Sea and the ramp up of Long Lake are the biggest contributors to the range of our guidance.

Highlights of our 2010 budget are as follows:

- Production after royalties has grown over the last three years at an annual compound rate of over 10% with further growth of approximately 4 to 6% expected in 2010 assuming the midpoint of our guidance. At the high end of our guidance range, volumes would grow over 15%

- Capital investment plans of $2.5 billion solidify growth beyond 2010 as we develop Usan, Golden Eagle, Long Lake and Horn River shale gas

- Production volumes expected to range from 200,000 to 250,000 boe/d (230,000 to 280,000 boe/d before royalties)

- Capital program funded with cash flow assuming WTI averages around US$70/bbl; free cash flow of approximately $600 million at current strip prices

- 15 exploration and appraisal wells planned, testing approximately 600 million boes of net unrisked resource potential

Investing in Our Strategies

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Estimated 2010

Capital Investment Profile ($Cdn millions)

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Conventional development and exploration 1,800

Oil sands 400

Shale gas 200

Corporate, chemicals and other 100

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Total Capital Investment 2,500

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Assuming WTI averages about US$70/bbl and NYMEX gas averages US$5.50/mmbtu, we expect our cash flow to fund our 2010 capital investment program at a US/Cdn dollar exchange rate of 0.90. At current strip prices, we expect next year's cash flow to exceed capital by approximately $600 million. Our production is 85% weighted to oil.

We have purchased crude oil put options on 60,000 bbls/d of our 2010 production at a strike price of WTI US$50/bbl. Half of these puts settle monthly, with the remainder settling annually. We continue to look for opportunities to purchase more.

At Long Lake, we successfully completed our turnaround program in September. Our bitumen volumes are increasing and we are moving up the ramp up curve. Our SAGD and upgrading processes are highly integrated. This integration ultimately generates our significant margin advantage while supporting the environmentally responsible water management practices we have implemented. As a result, the pace at which we move up the ramp up curve comes with a degree of variability. This is reflected in our guidance range. While we expect periods of downtime at Long Lake as the project continues to ramp up, we anticipate continuing improvements in operational performance as we move towards full capacity.

We plan to invest $400 million in oil sands in 2010 which includes $100 million at Syncrude. In the coming year, our capital program at Long Lake Phase 1 will focus on the drilling of sustaining well pads and the continued installation of ESPs in our SAGD wells.

With respect to future phases of Long Lake, we plan to continue engineering work on Phase 2 with timing of sanctioning dependent on multiple factors including the ramp up of Phase 1, receiving clarity on proposed climate change regulations, finalizing cost estimates and seeing more confidence in a sustained economic recovery.

We have approximately 88,000 acres in the Dilly Creek area of the Horn River basin in northeast British Columbia with a 100% working interest. We estimate our lands contain between 3 and 6 trillion cubic feet (0.5 to 1.0 billion barrels of oil equivalent) of contingent recoverable resource which could double our existing company-wide total proved reserves.

With our recent drilling and completion program, we realized substantial cost savings and productivity improvements and are producing at rates in line with regional producers. We took advantage of improved equipment utilization, drilled longer wells, initiated more fracs per well and maintained an industry-leading frac pace of 26 fracs in 15 days while achieving a 100% success rate on our frac program.

In 2010, we plan to invest about $200 million on the drilling and completion of an eight-well pad and on processing facilities. Compared to our earlier programs, this pad will have longer horizontal wells with more fracs and higher frac densities (18 fracs per well). We expect to achieve shale gas volumes from this program of approximately 50 mmcf/d in early 2011. This program sets up a potential capital investment plan consisting of an 18-well pad which could commence drilling in 2010.

"Larger programs, increased well productivities and higher recovery factors result in lower unit costs and are the catalysts to driving higher Horn River returns," said Romanow. "I am pleased with our progress and our success is setting industry benchmarks."

Capital Investment Profile

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Estimated 2010

Capital Investment Profile ($Cdn millions) %

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Core Asset Development 825 33

Major Development 700 28

Early Stage Development 300 12

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Total Development 1,825 73

Exploration and Appraisal 575 23

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Total Oil and Gas Capital 2,400 96

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Corporate, Chemicals and Other 100 4

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Total Capital Investment 2,500 100

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Core Asset Development Estimated 2010

Capital Investment Profile ($Cdn millions)

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North Sea 425

Gulf of Mexico 50

Other 50

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Total Conventional Core Asset Development 525

Long Lake and Syncrude 300

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Core Asset Development 825

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Major Development Estimated 2010

Capital Investment Profile ($Cdn millions)

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Offshore West Africa - Usan 575

Golden Eagle Area 50

Other 75

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Major Development 700

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Early Stage Development Estimated 2010

Capital Investment Profile ($Cdn millions)

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Horn River Shale Gas 200

Long Lake - Future Phases 100

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Core Asset Development 300

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Exploration and Appraisal Estimated 2010

Capital Investment Profile ($Cdn millions)

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Offshore Exploration and Appraisal

North Sea 350

Gulf of Mexico 125

West Africa 50

Other 50

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Exploration and Appraisal 575

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Suncor Reports Oil Sands Upgrader Fire

Suncor Energy Inc. announced December 17 that it is assessing damage following a fire at one of the company's two oil sands upgraders north of Fort McMurray, Alberta. The fire occurred December 15 and was extinguished within an hour. There were no injuries and no environmental impacts related to the incident. Appropriate authorities and regulators were informed.

Preliminary reports show no structural damage to the facility and the company expected repairs to take between two and four weeks. During the repair period, production was expected to be reduced by approximately 120,000 to 150,000 barrels per day (bpd). Suncor does not expect the incident to impact 2009 production outlook of between 290,000 and 305,000 bpd.

Oil Sands Producers Defend Emissions

The carbon footprint left by oil sands crude has been a target of criticism throughout the Copenhagen talks on climate change.

Canada has been handed "fossil awards" and accused of being "climate criminals" almost daily -- often with the accompanying chorus that crude oil production in the tar sands is "two to three times worse" for the environment than any other supply of oil on the planet.

But back home, the oil industry and the government of Alberta are fighting back against suggestions that oil from northern Alberta is exponentially worse for the planet than the conventional stuff pulled from places like the U.S. gulf coast and Saudi Arabia.

Critics and environmental groups concede that the majority of carbon dioxide is created when fuel is burned in cars or factories or jets -- consumption accounts for 78% to 80% of emissions regardless of where or how the crude is produced.

Those who support the oilsands, meanwhile, acknowledge that the complicated processes used to recover bitumen make it more greenhouse-gas intensive than lighter, conventional crudes. But the Alberta Energy Research Institute and the Canadian Association of Petroleum Producers said oilsands crude is actually only 5% to 10% worse than other oil producers in their class, if the entire "life cycle" of the oil is considered. In the case of California's heavy crude, the oilsands' emissions level is actually lower.

"It's actually around 10% worse," said Eddy Isaacs, managing director of the AERI, said of the oilsands. "When you look at what we're actually exporting and what we put in the pipeline that goes to U.S. refineries, compare that to U.S. domestic crudes ... Mayan crudes, crudes coming out of Venezuela and even some conventional crudes ... [our emissions are] about 10% higher."

Jacobs Consultancy produced a report in June that determined the amount of greenhouse gas emissions created by oil sands crude based on a life cycle analysis -- from the moment it is extracted to the moment it comes out of a tailpipe.

While this analysis -- also know as well-to-wheels -- is not new, the report created a new model that takes into account parts of the production process previously omitted. These include the energy required for the flaring of hydrocarbons used in the production of conventional crudes as well as the amount of water created when the bitumen is separated from the sand.

Mr. Isaacs broke down the production process itself to several stages (noting that both his numbers for the AERI and the data presented in the Jacobs Consultancy report focused exclusively on oilsands crude shipped to the U.S.).

Crude extraction and upgrading (to synthetic fuel that can be processed by refineries) accounts for 8% of total emissions. The refining process accounts for 13%. Most of the rest occur in the consumption phase.

But Simon Dyer of the Pembina Institute calls these statements "misleading" and "inaccurate" because the report uses "incomplete data."

According to Mr. Dyer, it doesn't take into account the loss of bicarbon -- the clearing of trees and peatlands -- and compares oil sands bitumen to oils much heavier than conventional crude. This makes the oil sands oil "look less bad."

Based on other reports, he said, the Jacobs Consultancy results are not conclusive because they don't use real, available data for emissions caused by "in situ" -- the more energy intensive of the two recovery methods used in the oilsands, where steam is injected deep into reserves to heat the oil and make it flow.

Also, instead of collecting actual statistics from Saudi or Venezuelan suppliers, all the data in the Jacobs report is modeled with computers, Mr. Dyer noted.

Pembina, citing research taken other reports on GHG emissions, has calculated a "life cycle" figure that shows the emissions from oil sands as being 10% to 40% worse than conventional oil.

But the disagreement between both sides of the debate continues. Both AERI and CAPP point out that the supply of conventional light crude is declining and that to compare the "worst case scenario" of oil sands' heaviest crude to the "best case scenario" of the lightest conventional crude will soon no longer be relevant.

"When you look at conventional oil being produced around the world, it's being produced from deeper and deeper reservoirs and therefore that means you're under greater and greater pressure and that has a greenhouse gas consequence to it," Mr. Isaacs said.

Mr. Dyer is not convinced.

"This does not help the debate about the need to reduce greenhouse gas pollution from the oil sands, and further damages the oil sands industry's credibility," he said.

Chinese Oilsands Takeover Bid under Review

The Harper government is quietly reviewing the $1.9-billion investment by a state-owned Chinese oil company in two oilsands projects, more than a month after the deal was originally supposed to close.

In an exclusive interview on December 18, Industry Minister Tony Clement confirmed that the government is reviewing PetroChina's proposal to buy a 60-per-cent stake in two projects in northern Alberta planned by Athabasca Oil Sands.

Following its announcement August 31, the deal was hailed as a major endorsement by foreign investors in the oilsands, as well as a sign that China could be prepared to ramp up its investment in such projects, after lukewarm interest in recent years. At the time, the acquisition was expected to be completed October 31, and company officials said they did not anticipate much objection from the federal government.

Clement declined to provide a timeline for the review. He said Canada welcomes foreign investment, but expects foreign investors to "play by the rules."

"I'm not going to particularize it to China or India or Botswana, for that matter," said Clement, when asked how comfortable the government is with Chinese investment in Canadian resource firms.

"We're a country that is and should be open to foreign investment, just as we expect other countries to be open for Canadian foreign investment.

"But they have to play by the rules. One of the most momentous things I did this year was sue an American company, U.S. Steel, because it's our position they didn't play by the rules," said the minister. This summer, Clement asked the Federal Court to order U.S. Steel to fulfill job commitments it made when it bought Stelco, the Canadian steelmaker.

Under the Investment Canada Act, Industry Canada reviews foreign takeovers worth more than $312 million. The law requires that such takeovers represent a "net benefit" to Canada. According to the department's website, net benefit is assessed based on a number of criteria, including the effect on employment and other economic activity in Canada.

But the PetroChina review will also be an important test of a new provision that allows the minister to review deals deemed potentially "injurious to national security."

Regulations to implement the provision came into effect September 17.

The government rejects calls from industry to better define "national security," arguing such threats are constantly evolving. Last September, the chair of the U.S.-China Economic and Security Review Commission said the PetroChina deal should raise national security concerns in both Canada and the U.S.

The PetroChina transaction will also test guidelines, issued by the Conservatives in 2007, governing takeovers by state-owned enterprises. PetroChina is the publicly traded arm of state-owned China National Petroleum.

Under the guidelines, the department will review the "nature and extent" of control by the Chinese government, PetroChina's corporate governance and reporting practices, as well as whether the acquired projects will operate on a "commercial" basis.

A source familiar with the transaction said it's unknown when the deal will get the green light.

"The review is in the hands of Investment Canada and it is up to them when they make the decision. We are led to believe that the review process is proceeding in a normal fashion," said the source, who spoke on condition of anonymity.

EUROPE / AFRICA / MIDDLE EAST

POLAND

Poland Grants Chevron Gas Exploration License

Poland has granted U.S. oil group Chevron a concession to search for gas in the southeastern part of the country, the environment ministry said on December 11.

Chevron, the second-largest U.S. oil company, will have five years to explore shale gas in the vicinity of the city of Zamosc.

In the course of the last two years, the ministry has granted 30 such concessions in Poland, to companies such as U.S. oil major Exxon Mobil, Lane Energy or Marathon Oil.

JORDAN

Eesti Energia to Attract $20-$25 Bln Investment to Extract, Process Oil Shale in Jordan

The government of Jordan has allowed Estonian state energy company Eesti Energia to start exploration and production of oil from oil shale in Jordan.

The local newspaper, The Jordan Times quoted Maher Hijazeen, director general of the Jordanian land board, saying that Eesti Energia can extract and process oil from oils shale in Al Attarat.

Eesti Energia’s feasibility study; released in May 2008, estimates that one of Jordan’s oil shale deposits could yield 36,000 barrels of oil per day. This would account for about a third of the current domestic demand of 100,000 barrels per day.

According to the World Energy Council, Jordan has approximately 50 billion tonnes of oil shale reserves.

Estonia is the only country in the world where oil shale, a rock from which petroleum-like shale oil can be extracted, is the primary source of energy and Eesti Energia is planning to export this technology to Jordan.

While the international hype surrounding oil shale has been toned down with the fall of oil prices from the historical highs seen in 2008, Jordan is moving forward with agreements and plans to develop its oil shale reserves and reduce dependence on foreign imports.

Earlier this year, the Natural Resources Authority concluded negotiations with Royal Dutch Shell on a commercial deal to produce oil from oil shale. In the initial phases, the deal will see Shell spend around $430 million to assess the project and its expected revenues.

Overall, the project is expected to attract direct investment of $20-$25 billion and take 12-20 years from the date the agreement is signed to produce the first commercial quantities of oil.

McIlvaine Company,

Northfield, IL 60093-2743

Tel: 847-784-0012; Fax: 847-784-0061;

E-mail: editor@mcilvainecompany.com