Unconventional Ogm

For analysis and commentary on these and other stories, plus the latest unconventional developments, see inside…

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12 April 2010

Week 01

Issue 01

� News � Analysis

� Intelligence Published by

� NewsBase

COMMENTARY 2 � Hail hail, gas shale 2 � BP faces shareholder revolt over oil sands

strategy 5 POLICY 7 � Philadelphia calls for fracking ban 7 SHALE GAS 7 � Shift in Canadian gas production

forecast 7 � New gas plant approved for Horn River

Basin 8 � Talisman sells conventional assets to

tighten focus on shale plays 8 � Total wins French shale gas permit 9 SHALE OIL 9 � Platts to provide Bakken price

assessments 9 OIL SANDS 10 � CAPP anticipates jump in oil sands

output 10 � Imperial Petroleum establishes new oil

sands unit 10 � AOSC’s roller coaster ride 11 HEAVY OIL 11 � Nexen seeks sharper focus with sale of

heavy oil assets 11 � New foreign investors line up for Iranian

heavy oil fields 12 COAL-BED METHANE 12 � UCG potential highlighted by fund

manager 12 � West Bengal pipeline planned for CBM

transportation 13 GTL/CTL 13 � Alter NRG seeks strategic partner for

Alberta CTL project 13 � Sasol to explore for shale gas in Karoo

Basin 14 NEWS IN BRIEF 14

NEWS THIS WEEK…

Talking about

a revolution Recent advances in unconventional gas production have revolutionised the energy industry and have been identified as a “game changer.”

� Shale gas developments in North America are at the vanguard of the revolution under way in the global natural gas sector. (Page 2)

� Industry observers believe some North American shale gas acreages could rival the world’s largest gas fields. (Page 2)

� The unconventional revolution is spreading to Europe and elsewhere in the world, which would have a significant impact on global liquefied natural gas (LNG) trade. (Page 3)

� The potential for gas shale development in the former Soviet Union could reaffirm Russian dominance of Europe’s gas supplies. (Page 4)

� BP is facing a small-scale revolt of its own over i ts unconventional oil and gas strategy, specifically with reference to its oil sands developments. (Page 5)

� A group of BP shareholders opposes the company’s oil sands plans on environmental grounds and has filed a special resolution on the issue to be voted upon at its AGM on April 15. (Page 5)

Unconventional OIL & GAS MONITOR

Unconventional OGM 12 April 2010, Week 01 page 2




Recent advances in unconventional gas production have revolutionised the energy industry and represent an opportunity for companies to expand reserves and output – no mean feat when oil is increasingly concentrated in the hands of a few state-owned national oil companies (NOCs).

However, the North American gas glut – in tandem with the global recession – has depressed gas prices and threatens further growth in this market, which has driven the technological advances needed to exploit unconventional resources.

The unconventional tag covers a multitude of areas – coal-bed methane (CBM), tight gas, gas hydrates – but the most important is shale gas. This resource has diverted the US from its expected path of increasing reliance on liquefied natural gas (LNG) imports and rewritten expectations for gas producers around the world. The amount of shale in the world is immense but development outside North America is only in its infancy.

Industry observers have said some of the North American areas could rival the world’s largest gas fields. Ross Smith Energy Group, in an overview of the plays, picked out the Marcellus shale as containing the most gas in the region, with a recoverable resource of 199 trillion cubic feet (5.64 trillion cubic metres), which, if accurate, would make it the second largest field in the world.

Overview The amount of unconventional gas outside North America is “probably vastly understated,” BG’s head of

unconventional gas resources, Scott Reeves, told UOGM.

Shale gas, tight gas and CBM share a number of common traits – notably the amount of work that has to be done to create and maintain producing reservoirs – Reeves said.

The UK-based gas company is interested in these resources in order to “deepen [BG’s] supply presence” in its existing markets and break into new areas. The three types are spread out across the world and, in some cases, can be exploited at an attractively low cost.

Reeves defended the company’s combination of LNG and unconventional gas assets, describing them as complementary. Although its regasification terminals in the US have suffered from the rising tide of domestic shale production, its CBM interests in Australia provide it with liquefaction feedstock.

The US’ National Petroleum Council (NPC) in a report in 2007 put the world’s total unconventional gas resources at 32.6 quadrillion cubic feet (923.2 tcm) with around one third of this – 233 tcm – in North America. Of this figure, shale gas accounts for 16.1 qcf (455 tcm).

The NPC reported, though, that assuming lessons learned in the US can be replicated, this figure should increase

“significantly around the world in the coming decades.”

North America This new resource only came to prominence in 2007, but it has already had a dramatic impact on the world’s supply profile. Before the “shale gale” broke, the expectation had been that traditional producers – primarily in the Middle East and Russia – would exert increasing dominance on supply chains via LNG shipments.

North America’s shale gas undercut this, removing a substantial amount of predicted LNG demand and concern can now be detected when talking to conventional gas producers. Qatar, for instance, built up its LNG industry in the belief that the US would become a substantial importer. This has been thwarted and, while Qatar has redirected cargoes towards Asia, the sense of shock is almost palpable.

Shale gas is now seen as a silver bullet that could transform any and every country’s gas balance. But scepticism is prudent.

A number of international oil companies (IOCs) have struck deals to carry out North American shale work with local independents. BG has signed up with EXCO Resources; Statoil, BP, Total have formed joint ventures with Chesapeake Energy, while Japan’s Mitsui & Co. recently struck a deal with Anadarko Petroleum. The most significant move in the shale gas arena, though, was ExxonMobil’s agreement to acquire XTO Energy for US$41 billion.�

COMMENTARY

Hail hail, gas shale North America is an established stomping ground for shale gas, which has revolutionised the global gas industry. Excitement is now mounting about shale developments in Europe By Ed Reed � Shale has only really been explored in North Americ a and even this is a recent development � First movers are snapping up acreage around Europe, hoping to replicate the successes � Development in Europe poses its own set of problems and these will dominate the industry � Shale opportunities may be best pursued beyond Euro pe, although this will take time to emerge

The amount of unconventional gas outside

North America is “probably vastly

understated”





Work on the resource in the US and Canada has gained worldwide interest. In the US, the key areas are known as the “Big Four” and are the Haynesville, Fayetteville, Marcellus and Barnett shales. The most information is available on the Barnett, where there are more than 10,000 wells, although development has only been going on since 2003. In Canada, the two most important shales are the Montney and Horn River.

As can be seen from activity on the Barnett, an important factor in exploiting shale gas is the drilling of numerous wells. Reeves described this method as “more like farming” than drilling conventional wells; others have described it as a “statistical” or “manufacturing” approach.

The reason shale gas has taken so long to exploit is because the resource has low permeability and low porosity. In order to exploit it, companies are forced to create artificial reservoirs in a “brute force” process, blasting the rock in order to make it flow.

Initial production from wells is high, but the decline rates are severe. Barclays Capital has estimated the decline rate in the Haynesville during the first year to be around 80% and although this is the most dramatic, the other shales also suffer from the same problem to varying degrees.

Reeves said shale production in the US

“seemed to make business sense,” with BG forming its joint venture to work on the Haynesville. Much of the enthusiasm from IOCs for North America’s shale opportunities is based on hopes to take the lessons learned here and deploy them elsewhere.

However, shale development faces obstacles in other parts of the world as different rules apply.

“It’s an open question as to whether shale developments can be pursued to the same extent outside North America,” said Reeves.

Supplies and challenges Europe, in particular, would seem to be at the forefront of locations that would benefit from a new, additional source of gas. The continent is increasingly reliant on gas imports from Russia and North Africa. Although the recession of 2009 cut into industrial demand, recovery is likely to see a return to these suppliers.

The European Union is not altogether happy with its import reliance, particularly on Russian supplies, following a number of mid-winter stoppages caused by pricing disputes with transit states. Shale gas, therefore, has been hyped as solving this reliance, providing Europe with a route to energy independence.

“Shale gas is not a total, viable alternative to imports of Russian gas,

North African gas and LNG. It is, though, complementary,” Realm Energy’s CEO, James Elston, told UOGM.

Pricing is a key concern when considering investments and the apparent breakdown of the gas-to-oil link has led some to worry.

While gas demand has fallen by 7% over the last 18 months in Europe, Elston said, and LNG cargoes have been dumped on the market, in the medium term these wrinkles should resolve themselves. “I think that excess will unwind itself over the next four years; from 2014 and onwards we should see a return of the full linkage between gas and oil prices in Europe.”

The appeal of investing in Europe’s shale gas is apparent, but time is running out. Some industry observers have said that many of the best opportunities have already gone. For instance, Elston said licensing in Poland “is now over, in my opinion.”

As in any frontier area, most of the prime movers are minnows, which are able to move quickly to secure acreage. These may carry out some exploration, but the model, for Realm at least, is to offload semi-developed licences onto newcomers.

Elston was guarded about where his company was looking, explaining the deals were still being worked out.

BNK Petroleum’s vice president for exploration, Jim Hill, was more willing to share, with the company having signed deals recently in Poland. BNK has an array of assets in North America, but the company is bullish on European prospects.

“The European market ... [has a] good stable pipeline system, a tremendous market and a tremendous need for gas. The cost of entry into European markets is a lot lower than many of the plays in the US. Our Polish acreage we picked up for US$0.55 per acre [US$137.5 per square km], whereas average costs in the US are US$250 per acre [US$62,500 per square km] and can go as high as US$25,000 per acre [US$6.25 million per square km],” Hill said.�

COMMENTARY





The BNK representative told UOGM the company’s strategy was to farm down its acreage. “It only makes sense to share the risk,” he said.

Execution However, not all such operations are successful. ExxonMobil and MOL announced their intentions in February to pull out of a project with Falcon Oil and Gas in Hungary, following disappointing results.

Falcon’s chairman, Gyorgy Szabo, seemed undaunted by this lack of confidence, telling UOGM that the company would “definitely” bring in another partner, although “we have learnt lessons.” He stressed that gas was present in the Mako trough; the only question was: “how we drain these systems and how efficiently this can be done.”

BNK’s Hill made similar points on sticking with development. “You cannot be discouraged by disappointing results,” he said. “We’ve drilled good wells, we’ve drilled bad wells [in North America]: everything is applicable in Europe. The shales are all different, you have to have the experience level and the tenacity to work your way through it ... but you can bring the experience and the databases from the US into these [European] shale plays and you’ll be able to make a lot more rapid progress.”

Hill summed it up, saying: “Exploration is easy, completions are the problem.” The BNK official went on to say that service costs would be fairly high in the near term, but would fall as demand for their work picked up.

Opposition There are likely to be specific problems in Europe that slow shale development. Most notably, the much higher population density than that in North America will make all stages of the operation more complicated.

As an example, Szabo compared Falcon’s seismic work around the world. “When we were doing our seismic campaign in Australia we had to negotiate with three individuals, in the US, maybe 300 people. In Hungary – and similarly in other European countries – we had to deal with 30,000 people for a dozen square km,” he said.

The acquisition of seismic can be complicated, although Szabo noted Falcon’s success in this case. However, moving from exploration into development is also likely to run into problems, primarily because of the “statistical” approach to drilling.

Shale requires numerous wells for its exploitation and this has been successful in the US and Canada, with reports that some shales can be developed with well spacing of as little as 400 feet (120 metres). Such development seems extremely unlikely in Europe given the population density.

Companies from North America have hailed the lack of royalties in Europe, noting this will act to reduce costs and improve returns. “Resources are owned by sovereign governments in Europe, so we’re not having to pay landowners direct, unlike in North America,” Realm’s Elston said.

However, the flip side of this royalty-free environment is that local landowners

do not stand to benefit from drilling and so are more likely to oppose it.

Elston claimed this would not be a problem for Realm, owing to the company’s policy of proving up licences and selling them on, but in the grander scheme of things this would slow development and commercialisation.

Another reason opposition to drilling may arise are the environmental concerns related to fracking. The US Environmental Protection Agency (EPA) recently began a study on the impact of this technique and scrutiny in New York is substantial, with concerns that fluids used will transfer to the water table.

Realm’s CEO predicted a positive outcome. “Frac water can be sensibly disposed of – be it in safe deep formations or, after extensive treatment, into above-ground water systems” and it will be shown to have a “minimal to non-existent impact on the water table,” Elston said.

Politics Shale gas will be developed in Europe and there is increasing evidence of interest in this area, for instance, Total signed up to explore an area in France recently. (See: Total wins French shale gas permit, page 9)

However, there are also noticeable obstacles to this development. Politicians will face competing interests. Concerns are growing within the EU over reliance on foreign energy, particularly from Russia. However, it remains open to question whether this long-term strategic goal can trump short-term opposition and environmental worries.�

COMMENTARY



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Falcon’s Szabo was confident that the EU would back shale work. “It is clear the EU would like more [domestically produced] gas and this must include unconventional,” he said.

The industry will grow in Europe but not to the same extent as seen in North America. Looking further ahead, one might consider South America as a potential destination, where Total is reportedly considering Argentina.

Australia may well be a key production point, either converting the feedstock into LNG or consuming it domestically for power, as the country’s reliance on coal leads to high levels of greenhouse gas (GHG) emissions.

Furthermore, officials from the Egyptian General Petroleum Corporation (EGPC) told UOGM that the North African country was considering pursuing shale gas development and

might offer contract flexibility to attract investors.

The largest source of shale gas outside North America, though, is likely to be the former Soviet Union (FSU). Development here would allow Gazprom to retain its role as the world’s top gas company. Ultimately, shale gas could reinforce the old ties of gas dependence for Europe, rather than sever them.�

UK super-major BP is stepping up its activity in the oil sands sector, where it is something of a late entrant. The ride is not without its bumps, however, as demonstrated by recent action taken by a group of over 100 shareholders who are concerned that the company is underestimating the sectoral risks, especially the potential cost of expected regulations on greenhouse gas (GHG) emissions.

The oil sands industry was hit hard by the global economic meltdown and a drop in oil prices, with a glut of project cancellations or decisions to mothball schemes evidence of the recession’s impact. However, higher oil prices and tentative signs of economic revival have triggered renewed investor interest.

Despite the potential influx of fresh capital, the environmental concerns that hang over the sector refuse to go away. Oil sands production is one of the world’s largest single sources of man-made GHG emissions, an environmental

reality that has earned Canada near-pariah status among green groups and pockets of the scientific community.

Big problems? The dissident BP shareholder grouping, which includes Britain’s public-sector workers union, Unison, and Boston Common Asset Management, has filed a special resolution to be voted upon at the company’s April 15 annual general meeting. The resolution demands that the firm publish a full report next year about the financial, environmental, social and reputational risks associated with its planned Alberta oil sands investments.

BP formed an oil sands study group in the late 1970s, which concluded that technology costs were too high and that much of the most promising properties for “in situ” (below ground) oil recovery had already been taken by rivals Shell and Exxon. It acquired some oil sands properties, but then sold them in 1999, after concluding that conventional oil

reserves held more cost-effective growth potential. The company has subsequently reversed that decision, on the grounds that higher oil prices and the difficulty in replacing conventional reserves have made the oil sands an essential play.

In 2008, a US$5 billion asset swap with Husky Energy gave BP 50% of the Sunrise oil sands project, a US$2.4 billion development whose first oil production from a 200,000 barrel per day development facility is expected in 2014.

In March, BP then paid an undisclosed amount for a majority stake in Value Creation’s undeveloped Terre de Grace oil sands project in the Athabasca region of Northern Alberta.

Interrupted momentum The call for a special report by the dissident investors will cast a minor pall over the growing momentum behind oil sands at the world’s third largest publicly traded oil company.�

COMMENTARY

BP faces shareholder revolt

over oil sands strategy BP’s plans to step up activity in the oil sands has drawn criticism from a group of the company’s shareholders By Kevin Godier � A group of BP shareholders oppose the company’s oil sands strategy on environmental grounds � The group has filed a special resolution on the iss ue to be voted upon at the company’s AGM on April 1 5 � Fellow European super-major Shell is facing a simil ar resolution at its AGM in May





The group’s holdings in BP are valued at about GBP150 million (US$230 million), according to an April 6 report in the Globe and Mail, representing just a tiny fraction of BP’s GBP118 billion London Stock Exchange value.

Nevertheless, FairPensions, the British consulting group that lobbies pension funds to make morally responsible investments, hopes the resolution, which has already received considerable media attention in the UK, will “raise awareness and prompt investors who are not really engaged to get engaged” on the risks of the oil sands investments, said Duncan Exley, FairPensions’ campaigns director.

The FairPensions campaign is being backed by several celebrities and politicians in the UK, including Liberal Democrat MP Simon Hughes. In a statement, Hughes said the “tar sands are a very risky investment, financially, environmentally and socially ... Governments should lead by example and be a responsible investor; for this reason, it is essential that the MPs’ pension fund supports these resolutions.”

Fair Pensions has predicted that the resolution is nonetheless likely to fail, given that some prominent pension funds have already said they intend to vote against it.

The UK Local Authority Pension Fund Forum said in a March 30 statement that it had advised its members to oppose the resolution, arguing that BP had already provided sufficient evidence that its approach to oil sands was well grounded.

“No evidence was found to indicate BP had adopted a position that was not supported by technical and economic research. The forum also does not believe BP or their partner have failed to meet the wide range of local requirements set by government to protect the environment and local communities,” it said in a statement. Separately, RiskMetrics, which makes voting recommendations to institutional investors, confirmed that it would also advise BP shareholders to reject the proposal.

But Exley said he was encouraged that BP had made public statements about the resolution. Via written declarations, BP has replied to the dissident shareholders by saying it is well aware of the risks of the oil sands, including “the potential impact of carbon pricing on investment viability.”

It also pledged to use the latest technology to ensure the Alberta operations would emit the lowest possible amounts of carbon dioxide, and said it would consider equipping the Sunrise project with carbon capture and storage (CCS) technology. However this technology is highly expensive and has so far been resisted by oil and power generation companies.

BP also maintains that oil sands developments are required to meet global energy demand, which it expects to rise by 40% by 2030, with fossil fuels supplying most of the increase.

Campaigners progress Some analysts believe that the anti-oil sands campaigners have made significant progress, whatever fate befalls the

motion. A similar resolution is being tabled

against Shell at its AGM on May 18. Shell’s board has responded to this by publishing a report on its oil sands activities a full year earlier than expected.

At a wider level, environmental groups are intensifying global campaigns to hammer home their message to the public and lawmakers that oil sands are among the world’s most damaging energy sources.

Enhanced activity On the other hand, the oil sands industry has seen some significant movement in recent months. Devon Energy recently paid US$500 million to buy a 50% interest in BP’s Kirby oil sands property, while French super-major Total announced it would proceed with development at its Joslyn Creek project, despite experiencing major setbacks with the property.

In another sign of renewed commitment to oil sands, Total and its partner ConocoPhillips agreed in January

to ramp up the production target for their jointly owned Surmont project to 110,000 bpd from an early target of 27,000 bpd by 2015.

In late 2009, Chinese oil major PetroChina paid US$1.8 billion to acquire a 60% stake in Athabasca Oil Sands Corporation’s MacKay River and Dover oil sands projects.

This all seems to indicate that a lot of big players are now willing to bet major dollars that the oil price will move significantly higher in the years ahead, even as the oil sands industry struggles to convince governments outside Canada that it is doing all it can to minimise the impact of development and production on the environment.

While BP cannot yet boast any oil sands production, it seems to have come to terms with any internal anxieties that oil sands developments may cause excessive environmental damage and might require too high an oil price to be economically sound.�

COMMENTARY





Officials for the city of Philadelphia have asked a state agency to ban hydraulic fracturing because of fears about the contamination of drinking water. The controversy is starting to mirror events in New York State, where the dispute over the safety of the gas drilling method is liveliest. New York City is seeking a ban on fracking in its vast watershed.

Philadelphia has specifically asked the Delaware River Basin Commission to deny a drilling permit to Louisiana’s Stone Energy and any other company that wants to use hydro fracking in its watershed. Officials with the council contend that Stone Energy, which is now seeking two drilling permits, began work in part of the river basin without the necessary approval, reported Reuters.

At issue specifically is that the company must receive a permit before it takes water from a tributary of the Delaware River so that it can frack, a process that is usually highly water-intensive. A Philadelphia City councilwoman, Blondell Reynolds Brown, who introduced the resolution, said of fracking, “Long-term impacts can take years or decades to develop, and we have too many examples of that. Long-term impacts can be devastating.”

A spokesman for Stone Energy, Tim O’Leary, told Reuters that fracking was harmless to the water supply. “Stone Energy believes that hydraulic fracturing technologies are a safe and proven method of accessing ample domestic sources of clean natural gas needed by

the US,” he said. Moreover, Stone Energy is complying with all local, state and federal regulations governing gas development, he said. Other municipal areas are expected to investigate fracking on the heels of the news that the US Environmental Protection Agency (EPA) will conduct a comprehensive US$1.9 million research study into the practice.

The country-wide study, which will not be completed until 2012, will probe the “potential adverse impact” that fracking may have on water quality and public health, said the agency in March. “There are concerns that hydraulic fracturing may impact ground water and surface water quality,” the EPA noted.�

Canada’s National Energy Board (NEB) has released a short-term report on natural gas drilling that foresees a shift in production from Alberta to British Columbia (BC) over the next two years.

The move would primarily be driven by activity in the tight and unconventional gas plays throughout northeastern BC in the Montney and Horn River areas.

“Natural gas is shifting not only in location but also in type, which can translate into opportunities for many in the industry,” noted NEB’s chairman, Gaétan Caron. More than 210 wells could be drilled in Montney and 70 wells in Horn River in 2010 alone, said the report, called: “Short-term Canadian Natural Gas Deliverability 2010-2012.”

Meanwhile, Alberta’s gas production is expected to decline over the next few years from 12.7 billion cubic feet (360 million cubic metres) per day to 8.5 bcf (241 mcm) per day.

Neighbouring BC will see an increase from 2.7 bcf (76.5 mcm) per day to 3.7 bcf (105 mcm) per day.�

POLICY

Philadelphia calls for fracking ban

SHALE GAS

Shift in Canadian gas

production forecast






Even so, Canada’s overall natural gas production is expected to drop from 2010 to 2012 as drilling activity slows down. In 2012, gas “deliverability” could be down to 13 bcf (368 mcm) per day, down from 15.1 bcf (428 mcm) per day as recently as 2009.

Capital spending on natural gas projects will stabilise and then increase over the projected time period, predicted the board. The number of “drilling days” will increase about 11% from 45,659 days in 2010 to 50,512 days in 2012.

Drilling for oil is more profitable than

gas right now, the board noted, and some of the new technology that was designed to extract shale gas is being used for oil extraction in parts of Alberta and Saskatchewan. Capital investment in oil production is drawing some investment away from gas, it said.�

Canada’s National Energy Board last week approved a C$1 billion (US$995 million) new gas plant to serve increased shale gas production from the Horn River Basin in British Columbia.

Spectra Energy Transmission will build the Fort Nelson North gas-processing facility – and a small pipeline loop – to serve the increasingly busy east side of the Horn River area. The plant will be able to process around 250 million cubic feet (7 million cubic metres) per day of gas.

One of the conditions is that Spectra, through its Vancouver-based subsidiary Westcoast, will have to submit an annual

report of greenhouse gas (GHG) emissions and on possible ways of reducing and capturing carbon from the shale gas processing. The company’s existing Fort Nelson gas plant can process 1 bcf (28 mcm) per day of gas.

In March 2009, Spectra announced it had received firm customer commitments – and subsequently contracts –for 760 mcf (21.5 mcm) per day in gathering and processing capacity from seven producers operating in the basin. As a result of several upgrades, to be completed in 2012 and including construction of the Fort Nelson North plant, Spectra hopes to be able to

accommodate up to 830 mcf (23.5 mcm) per day of incremental gas from the seven producers.

Earlier this year EnCana Corp., also of Calgary, had secured a certificate for environmental assessment for its Cabin Gas Plant Project, to be located near Fort Nelson. The plant will process as much as 800 mcf (22.7 mcm) per day and will cost between C$800 million (US$796 million) and C$1 billion. The plant will be built ‘capture ready’ to address the issue of GHG emissions and must explore carbon capture and storage (CCS).�

Talisman Energy is sharpening its focus on booming North American shale gas plays by selling some conventional oil and gas assets for C$1.9 billion (US$1.89 billion).

The sales, announced on April 7, consist of five separate transactions with mostly unnamed parties, covering assets producing about 42,500 barrels of oil equivalent per day, 90% of which is natural gas production. Talisman said the sales would be finalised by the end of June.

Talisman said that although the assets

being sold were “excellent,” it could not “effectively compete for capital within [its] emerging strategic asset mix. These sales are value-accretive and will help [it] focus on, finance and build [its] growing, low-cost North American shale gas business.”

The acreage being sold is located in the greater Peace River Arch, central Alberta Foothills and greater Hinton areas in Alberta, and in Ontario.

Talisman said in January that it was looking to sell non-core conventional assets in North America producing about

40,000 boepd as it focused on freeing up capital for more investment in unconventional shale gas production.

Many other large Canadian producers are also selling their conventional assets to prepare for new investments in the growing Canadian shale gas industry, including EnCana Corp., Suncor Energy and Nexen. The rationale among these companies is that conventional gas is unable to compete with the productivity and economies of scale of shale gas.�

SHALE GAS

New gas plant approved

for Horn River Basin

Talisman sells conventional assets

to tighten focus on shale plays






As of the end of 2009, Talisman had sold assets producing 38,000 boepd for C$3.2 billion (US$3.19 billion) after president and CEO, John Manzoni, announced a strategy in 2008 to refocus

the company on key assets, including North American unconventional shale gas plays.

Talisman spokeswoman Phoebe Buckland confirmed Eurogas Corp., a

unit of Toronto asset-management firm Dundee Corp., as one of the buyers, but would not identify the other purchasers.�

French oil major Total has been awarded the Montelimar shale gas permit in the south of France for a period of five years.

Total will have a 100% stake in the 4,327-square km exploration permit following its acquisition of the French affiliate of the US Devon Energy, which was jointly allocated the permit.

In a statement, Yves-Louis Darricarrère, president of exploration and production, said: “Total has committed to a programme of work that is aimed at confirming the presence of shale gas in the region and [at] appraising the possibility of economical development of these resources. Should the first geological activities be promising, exploration wells will be drilled in order to evaluate this potential.”

Total also operates the Lacq and Meillon gas fields in the southwest of France, in which it has a 100% interest.

The Montelimar permit will boost the company’s bid to boost production from unconventional resources, including

shale gas. Total is also seeking permits to

explore for unconventional gas in Argentina and earlier this year it agreed to buy a stake in Chesapeake Energy’s US gas assets for US$2.25 billion.

Shale gas’ potential is said to be exciting in Europe. Analysts believe there are substantial amounts of shale gas to be found in Sweden, Poland, Germany, France and Austria. Furthermore, unlike in the US, a significant chunk of Europe’s prospective shale gas resource lies under rural land, thereby lessening the fears of urban groundwater contamination.�

Platts is to provide the world’s first price assessments to value crude oil produced from the Bakken shale field in the central US.

“Thanks to favourable economics and advances in technology, production from this unconventional crude oil source has risen dramatically in recent years,” said Esa Ramasamy, director of Americas market reporting at Platts in a statement.

“This new high-quality crude oil stream is expected to help meet Midwest refining demand and potentially that of the US Gulf Coast. Because of its importance, the industry needs a means of placing a value on this crude. Our new price assessments address this need by providing a transparent price discovery process and daily pricing information.”

The formation of the Bakken shale

runs down from Canada and into North Dakota and Montana. The first oil flowed from the Bakken shale in 1951; however, up until recently it has been difficult to extract.

Times have now changed and horizontal drilling and fracturing techniques have been applied to drilling for oil in shale formations.�

SHALE GAS

Total wins French shale gas permit

SHALE OIL

Platts to provide Bakken

price assessments






Platts has reported current US Bakken crude output at 200,000 barrels per day and the North Dakota Pipeline Authority estimates that the Bakken field’s yield could rise to between 400,000 bpd to 500,000 bpd over the next 10 years before dropping back.

The Bakken shale fields are currently the largest oil reserve in the US, with estimated recoverable reserves of 4 billion barrels.

Platts’ Bakken blend assessments of Bakken Blend ex-Clearbrook and Bakken Blend ex-Guernsey will be made

using the company’s Market-on-Close (MOC) methodology, which, said Platts, “Identifies bid, offer and transaction data by company of origin and results in a time-sensitive end-of-trading-day daily price assessment.”�

Industry watchdog Canadian Association of Petroleum Producers (CAPP) has projected oil sands output from Alberta will be 1.55 million barrels per day in 2010 and will increase to 1.66 million bpd in 2011. In 2009, production was 1.34 million bpd.

“Momentum is picking up once again in the province, with [the] oil price stabilising at US$80 per barrel and demand increasing,” said CAPP’s president, David Collyer. “In the current year, total investment in Canada’s oil and gas sector is estimated to be C$40 billion [US$39.75 billio], compared to C$35 billion [US$34.78 billion] in 2009. Last year, investments in Alberta alone were C$24 billion [US$23.85 billion], with a vast majority being in the oil sands sector.”

Collyer’s statement was made on the sidelines of a major campaign launched

in Calgary on April 7 to reignite business competitiveness in the province and attract new investments.

“Alberta’s advantage has always been its ability to build investor confidence and compete successfully for global capital dollars. Contrary to the ‘gambler’ stereotype of the oil and gas industry, global capital is not the kind of money that goes to the race track or to a casino looking for good luck. Rather, it looks for stability and long-term return on investment and does not like uncertainty or frequent changes in policy and regulation,” Collyer said.

Providing regulatory stability in the province is very much on the agenda of the Tory government in Edmonton, which in early March announced changes to the existing royalty structure issued in late 2007. Offerings under the new competitiveness review include: making

permanent a 5% front-end incentive on the drilling of new natural gas and conventional oil wells; a 14% reduction of maximum royalty rate to 36% for both unconventional and conventional natural gas output, and a reduction to 40-50% earlier – for crude oil production. The reductions will be capped off at maximum natural gas and crude oil prices of US$9 per million British thermal unit and US$82 per barrel respectively.

“We are certainly encouraged by the new fiscal measures. But, there is a great deal more work to be done. Royalty curves and other fiscal details need to be firmed up by end May,” Collyer said. He added: “The regulatory part of the competitiveness review is just now getting under way and has ambitious targets to deliver substantive process improvements by year-end.”�

Imperial Petroleum has formed a new company, Arrakis Oil Recovery, to develop a new process to recover bitumen or heavy oil from tar and oil sands.

The Evansville, Indiana-headquartered

Imperial said it owned a 33.3% interest in Arrakis with two other partners, including the technology provider, and would manage the new company. It said that Arrakis had been granted a licence to the new technology for oil sand

processing outside of Canada, using a non-thermal, mechanical and chemical closed-loop process to recover the bitumen. The chemical employed in the process is not a solvent and is both non-toxic and biodegradable.�

SHALE OIL

OIL SANDS

CAPP anticipates jump

in oil sands output

Imperial Petroleum establishes

new oil sands unit





In connection with Arrakis, Imperial also signed an engagement agreement with Hyde Park Capital Group and Charlotte Capital Partners to raise US$6.1 million for the initial facility installation planned for late summer 2010.

“We believe that the technology developed and licensed to Arrakis is the most advanced, cost-effective and environmentally friendly processing technology available for recovering bitumen from tar and oil sands,” said

Jeffrey T Wilson, Imperial’s president. Wilson expanded on the practice: “The

process operates without hot water or steam and without any solvents, either hydrocarbon or otherwise, so there are no emissions issues. The process produces a clean sand residue while separating the bitumen in an eco-friendly manner. Operating costs are significantly less than conventional processes because the chemical medium is re-cycled and re-used. The process has been pilot tested on several tonnes of material at the

research and development facility owned by the technology provider on oil sands from Oklahoma, Texas and Utah. The initial installation will process some 2,400 tonnes per day of oil sands containing an average of 8% bitumen and should generate approximately US$20 million annual cash flow. The first facility will be located at a site on which several million tonnes of the material have already been mined.”�

Athabasca Oil Sands Corp. (AOSC) raised almost C$1.35 billion (US$1.34 billion) through its recent initial public offering (IPO), the richest Canadian share floatation since 1999. However, the Calgary-based company’s shares quickly lost C$440 million (US$437.3 million) during its first day of trading on April 8.

At the close of the first day of trading on the Toronto Stock Exchange, its shares were C$16.90 (US$16.79), down 6.1% or C$1.10 (US$1.09). The 75 million shares, priced at C$18 (US$17.89) each, represented a 19% stake in the company. On April 9, the second day of trading, the stock fell 7.1% to close at C$15.70 (US$15.60).

The money raised in the company’s IPO had startled observers. AOSC

estimates that it will not achieve commercial production from Canada’s oil sands before 2015. It will use a technology that is unproven in carbonate reserves – steam-assisted gravity drainage rather than mining – to recover bitumen from oil sands deposits. AOSC described its technology as having a smaller surface footprint, using less water and not requiring tailings ponds.

“The shares were simply overpriced compared to other early stage oil sands players, given that the technology is unproven for 25% of the company’s reserves, and because of the estimated timing of production,” an unnamed analyst told the Calgary Herald. Oil prices had also weakened.

According to AOSC, it has 114 million

barrels of probable reserves, 26 million barrels of possible reserves and 7.1 billion barrels of contingent reserves. It recently formed a C$1.9 billion (US$1.88 billion) partnership with state-owned PetroChina for a 60% share in two oil sands projects in northeastern Alberta, MacKay and Dover.

The correction in stock price was not unexpected given the complexities of producing from the oil sands. “Oil sands are a really, really labour-intensive, cost- intensive investment proposition,” Steven Conville, who helps manage about C$8 billion (US$7.95 billion) at Macquarie Private Wealth, told Bloomberg. “I’m not sure people are really into the sizzle at this point in time. People want steak.”�

Calgary-based Nexen is planning to sell some heavy oil properties around the Alberta and Saskatchewan border, near Lloydminster.

According to Scotia Waterous, the investment banking arm of Scotia Bank, Nexen has engaged the bank’s services to

sell its assets. Proposals to Scotia Waterous are due by May 3, 2010.

The bank has said Nexen’s properties – amounting to approximately 225,000 net acres (910 square km) of land – to be sold include established production of 15,000 barrels per day of oil and 2,000

barrels of oil equivalent per day of natural gas. Additionally, the area has the potential for enhanced oil recovery (EOR) and large original-oil-in-place (OOIP) fields that could work well with thermal or chemical methods of extraction.�

OIL SANDS

AOSC’s roller coaster ride

HEAVY OIL

Nexen seeks sharper focus

with sale of heavy oil assets





Add in the infrastructure of pipelines, batteries and a working field office and this sale could well be one of the largest, if not the largest, Canadian property deals of 2010.

The legacy of Nexen’s properties dates back to the 1970s and 1990s, when they belonged to Occidental Petroleum and Wascana Energy. Nexen started out as Occidental in 1971 and acquired Wascana in 1997.

A Nexen spokesperson, Carla Yuill, told reporters that the sale “is because we want to streamline our core strategies … We do think we can get good prices, given low differentials.”

The property sale fits in with a statement from Nexen’s CEO, Marvin Romanow, in December 2009, when he said the company would be disposing of approximately C$1 billion (US$1 billion) worth of assets over the next two years to

focus on its international operations, oil sands operations and shale gas. Nexen’s Lloydminster sale is estimated to fetch C$600-800 million (US$600-800 million).

It is possible the proceeds could significantly reduce Nexen’s debt but analysts have been reported as saying this is more of a strategic shift and that the money will probably be reinvested in the company’s core businesses.�

Iranian media have reported a deal is close between the National Iranian Oil Company (NIOC) and an Iranian-Australian consortium backed by Chinese financing, for the development of three heavy crude oilfields in the southern part of the country.

The Iranian Oil Ministry’s SHANA website reported on April 5 that Bahman Samimi, in charge of the development of heavy oilfield projects at NIOC, said the contract concerned the development of the onshore Kouhmond, Kaki, and Boushgan oilfields in Bushehr province in southern Iran. No financial details of the deal were available.

SHANA said the contract was to be signed during the Iranian month of

Ordibehesht, which begins April 21, and named the consortium as the Iranian–Australian KIPC joint venture.

Samimi said the development plan for the three fields was signed in 2009. “The KIPC consortium has submitted the master development plan on Kouhmound, Kaki and Boushgan and the plan has been approved by the ... board of directors of the National Iranian Oil Company,” Samimi said, in an exclusive interview.

The KIPC has introduced a number of companies as financiers, mostly Chinese, SHANA said, adding that buyback contracts would be signed after the NIOC approved the proposed financing companies. He said the NIOC had

dispatched envoys to visit the companies and evaluate their financial capabilities.

Iran has struggled for years to find the cash and the technology to develop its energy sector, as sanctions and political pressure have kept foreign firms away. Western companies in particular are increasingly wary of investing in the country because of an international dispute over Tehran’s nuclear ambitions.

On March 10, Shell announced it had stopped supplying refined petroleum to Iran. The government has shifted to energy-hungry Asian countries such as China, India and Malaysia for hydrocarbon investments.�

An Australian fund manager has highlighted that underground coal gasification (UCG) can be considered as the often overlooked younger brother to coal-bed methane (CBM).

According to LimeStreet Capital resources fund manager Stephen Bartrop,

although CBM has become one of the biggest stories in the resources sector in the past three years, highly efficient UCG techniques are starting to emerge from its shadow.

On April 6, the Sydney Morning Herald quoted Bartrop as saying: “They

do share similarities … those who have come across underground coal gasification often say, ‘We have seen some pilot plants work; conceptually it looks good, but there are still some question marks hanging over its head until it is commercialised.’”�

HEAVY OIL

New foreign investors line up

for Iranian heavy oil fields

COAL-BED METHANE

UCG potential highlighted

by fund manager





“However, given that for one cubic metre of coal you get 20 times the amount of energy out of a coal seam through UCG than through CBM technology, it really is just a matter of time before it comes into its own.” He stressed that this would have “huge implications for Australia’s vast coalfields.”

UCG technology was developed in the 19th century. Cougar Energy’s managing

director, Len Walker, one of the UCG pioneers in Australia, said that rising energy demand had put the technology in play.

“Apart from Linc Energy, Carbon Energy and ourselves, which are the big three in the space, I have counted six or seven other listed companies that have recently popped up and which are all promoting UCG in different ways,” he said in the newspaper report.

In March, Cougar announced ignition of its flagship Kingaroy project in southeast Queensland and the successful production of synthetic gas. Cougar will soon undertake a series of trials, underground and on the surface, which will be used for a pre-feasibility study and a subsequent bankable feasibility for a planned 400-MW power station.�

India’s Essar Oil plans to lay a 160-km pipeline from Durgapur to Kolkata in West Bengal to transport gas from its coal-bed methane (CBM) blocks to consumers in the state.

The company said the natural gas pipeline would help ease some of the environmental concerns stemming from the abundance of steel and coal plants in the region, the Press Trust of India reported on April 7.

Essar Oil has applied to the sector’s regulator, the Petroleum and Natural Gas Regulatory Board (PNGRB), for permission to lay a 24-inch pipeline, according to the company’s application. Essar is likely to start producing CBM

from its Raniganj block in West Bengal in the first quarter of 2010. Initial output is expected to be 9,000-10,000 cubic metres of gas per day, with peak production of 3.5 million cubic metres per day envisaged in mid-2013.

A special purpose vehicle would be set up for executing the project, Essar said. Besides Raniganj, the pipeline may also be used to transport gas from Essar’s Rajmahal CBM block in neighbouring Jharkhand. Shishir Agrawal, head of Essar Exploration Production Division, said in the application that 15 test wells had already been drilled in Raniganj and 500 more were planned.

Essar has suggested a pipeline capacity

of 4 million cubic metres per day, given the PNGRB’s requirement of having 33% excess capacity for leasing out to third parties.

The Raniganj block holds 4.6 trillion cubic feet (130 billion cubic metres) in place and recoverable resources of around 1 tcf (28.3 bcm).

In the Rajmahal Block, where Essar was declared the provisional winner in a recently concluded auction of CBM areas, an in-place resource of 9.5 tcf (269 bcm) has been estimated with recoverable resources of 4.7 tcf (133 bcm).�

A final investment decision (FID) is awaited at Alter NRG for its proposed 40,000 barrel per day coal-to-liquids (CTL) project in northern Alberta.

For the past two years, the Calgary-based firm has been seeking finances to move ahead with the project. However, the global economic downturn that

erupted in late 2008 damaged its prospects.

“We are on the look-out for a strategic company to partner on the project. We have huge coal reserves and the project is feasible, but no particular time frame has been set to break ground,” an Alter NRG official, who did not wish to be

identified, told UOGM. “We are aiming for three categories of companies – with mining and extraction experience, oil companies based in Alberta and project engineering and construction firms. The successful partner will be offered a 60% stake.”�

COAL-BED METHANE

West Bengal pipeline planned

for CBM transportation

GTL/CTL

Alter NRG seeks strategic partner

for Alberta CTL project





In the summer of 2008, Alter NRG had filed a public disclosure document with the Energy Resources and Conservation Board (ERCB) to move ahead with the CTL plant at Fox Creek. Estimated to cost C$500 million (US$497.1 million), the project was to be built in two stages, each with capacity to produce 20,000 bpd of liquids. The first phase was slated to start production by late 2014 and would produce 33,000 bpd of diesel and 7,000 bpd of naphtha.

“Our target now will be to select a

strategic partner by Q3 2010 and forge ahead with the FEED [front-end engineering and design] package,” the official said. The FEED contract will take about 10 months to complete.

Last year, Alter NRG signed an agreement with Houston-based KBR to provide pre-FEED services, besides working out the precise project costs, procurement and construction strategy and also the selection of a technology provider.

“At that time, KBR had also expressed

interest in joining the project as a strategic partner, but no final decision was taken,” the official pointed out.

Alter NRG has in-place coal resources of 850 million tonnes, of which 468 million tonnes are recoverable. The project’s economic model is based on revenues from the sale of diesel to consumers in the province and naphtha to pipeline companies that could use it as a diluent.�

South Africa’s Sasol is joining the global shale gas rush.

Sasol Petroleum International (SPI), the company’s exploration arm, along with Norway’s Statoil and US-based Chesapeake Energy, has submitted a joint application for onshore petroleum exploration rights in South Africa’s Karoo Basin. The application is expected to take about 12 months to process.

Chesapeake is already in a joint venture with Statoil in the Marcellus shale, a large formation that underlies parts of the US states of New York and Pennsylvania. However, the move by Sasol and its partners into Karoo is the first South African participation in the global race to produce shale gas and

Sasol is seen to have a particularly clear technological advantage.

The Karoo Basin shale resource is seen as potentially providing Sasol with a low-carbon feedstock for its gas-to-liquids (GTL) plants. The basin covers an area of over 700,000 square km. Promising petroleum exploration plays in the basin include coal-bed methane (CBM), shale gas and conventional crude.

Throughout the years of apartheid, Sasol built up considerable experience in manufacturing unconventional fuels, based on the Fischer-Tropsch process, a technology that turns gas into liquids that was first developed by Germany during the Second World War. The company

now produces commercial quantities of petrol and diesel from coal and natural gas using this technology, and its gas-to-liquids (GTL) process is widely regarded as a global leader.

With the price of oil rising, even as gas prices are plummeting, Sasol is profiting from its processes that convert gas into petroleum products.

Sasol’s CEO, Pat Davies, told South Africa’s local Mining Weekly that the GTL process was a particular strength for the company: “This puts us in a very good space. We make our money in GTL in the price of gas versus the price of oil, because we take gas and we convert that into oil, so the bigger that gap, the more money we make,” he said.�

POLICY

BLM suspends oil and gas lease sales

On April 8, the Bureau of Land Management delayed all oil and gas lease sales in Montana, North Dakota and South Dakota while the agency studies their potential impact on climate change. The next sale had been scheduled for

April 13 and included about 91,000 acres. Sales had also been planned for June and August. BLM’s Montana office said it decided to delay those sales “in order to bring more certainty to industry and in light of expected litigation.” The decision comes in the wake of a settlement BLM signed last month suspending 61 oil and gas leases on nearly 38,000 acres in Montana the agency sold in 2008 until it considers the greenhouse gas emissions from oil and

gas production. March’s agreement settled a lawsuit by the groups charging that BLM in its resource management plans failed to consider how development of the leases, most of which are located in areas of coal-bed methane and conventional natural gas development, would contribute to warming of the atmosphere.

GREENWIRE, April 9, 2010

GTL/CTL

Sasol to explore for shale

gas in Karoo Basin

NEWS IN BRIEF






SHALE GAS

US to share shale experience

The US plans to offer other countries help in determining whether they have big natural gas resources trapped in shale rock and show them how to bring those supplies to market, a top US State Department official said on April 7. The US has officially offered its assistance to China and India, and other countries with potentially large shale gas resources that are under consideration include Jordan, Poland, Chile, Uruguay and Morocco, according to Goldwyn.

NEW CENTER, April 8, 2010

US, China target shale gas

Shale gas, like coal-bed methane and gas hydrates, comes under the umbrella of unconventional gas. Commercial interest in unconventional gas (or oil) goes up when oil prices shoot. Oil engineers have been able to solve the technological challenge of coaxing the gas out of the shale by a technique called hydro-fracturing. Therefore, we currently have the shale-gas boom, led by the US. China is said to be targeting 30 billion cubic metres of shale gas per year, equivalent to half the country’s demand.

BUSINESS LINE, April 10, 2010

RIL in US shale JV

Mukesh Ambani-promoted Reliance Industries Ltd (RIL) Friday said it has signed a US$1.7 billion joint venture agreement with US-based Atlas Energy Inc. for the extraction of shale gas in the US. Reliance will acquire a 40% “undivided interest” in about 300,000 net acres of undeveloped leasehold held by Atlas in the core area of the Marcellus Shale in Pennsylvania, the company said in a statement. Reliance will pay US$339 million in cash upon closing and an additional US$1.36 billion in the form of a drilling carry.

IN.COM, April 9, 2010

Professor: Fracking not a cleaner alternative

Natural gas obtained by the controversial technique of hydraulic fracturing may contribute significantly to greenhouse gas emissions and so should not be considered as a cleaner alternative to coal or oil, according to a Cornell University researcher. Although natural gas, when burned, produces only about half of the carbon dioxide emissions of coal, that calculation omits greenhouse gas emissions from the well-drilling, water-trucking, pipeline-laying, and forest-felling that are part of the production of hydraulically fractured natural gas, Ecology Professor Robert Howarth argues in a new paper. Combining the effects of combustion, production, distribution, and leaked methane from hydraulically fractured natural gas gives the fuel about the same greenhouse gas emissions as coal and about 30% more than diesel or gasoline, Howarth says in the draft paper published in mid-March.

REUTERS, March 31, 2010

Atlas shares rise

Shares of Atlas Energy Inc. rose by 20% after a shale extraction deal with Reliance Industries Ltd (RIL) was announced. An unusually large number of Atlas call options were also traded on April 9. For every put option trade, there were over six calls traded, resulting in an extremely low put-call ratio – a sign of high bullishness. Evidently, Atlas’s Marcellus shale assets had been valued at far lower levels by the markets compared with the valuation RIL agreed to for a 40% stake. Atlas has a total area of 584,000 acres under its control in the Marcellus fields.

LIVE MINT, April 10, 2010

BP fights to limit controls on fracturing

BP is lobbying on Capitol Hill against a federal US environmental agency being

given jurisdiction over the use of a controversial method of extracting gas from shale deposits, ahead of an important meeting this week. The London-based oil company wants decisions on drilling techniques such as hydraulic fracturing – which uses high-pressure liquids to force fissures – to be taken at state level, rather than being left to the Environmental Protection Agency (EPA), whose specialist committee meets on Wednesday to discuss its concerns. BP is also opposed to the public disclosure of the chemicals used in fracturing, on the basis that the information is commercially sensitive – something that will anger environmentalists, who are highly suspicious of the process. Although BP was unable to comment, the New York Times published a “discussion draft” said to have been produced by BP which says: “States with existing oil and gas regulatory programmes have the authority to and are best situated to continue regulating hydraulic fracturing processes and procedures.”

THE GUARDIAN, April 4, 2010

Goodrich to buy Eagle Ford, Haynesville assets

Independent oil and gas explorer Goodrich Petroleum Corp said it will buy 35,000 net acres in the Eagle Ford shale and 4,200 net acres in the Haynesville shale in Texas. The Eagle Ford deal involves about US$15 million in upfront cash payment while the Haynesville deal has no upfront cash consideration. Goodrich expects to spud its initial Eagle Ford shale well in the second quarter and run one or two rigs in the play during the second half. The acquisition boosts the company’s Haynesville shale inventory to about 89,500 net acres. Goodrich maintained its 2010 capital expenditure budget of US$255 million, but said it reallocated about US$50 million, or about 20 percent of the amount, to leasehold, drilling and completion costs associated with the Eagle Ford Shale oil play.�

NEWS IN BRIEF






Shares of the company, which has a majority of its properties in Louisiana and Texas, closed at US$17.97 Friday on the New York Stock Exchange.

REUTERS, April 12, 2010

Nighthawk eyes shale ‘sweet spots’

US player Nighthawk Energy has announced that four 3-D surveys over the Jolly Ranch project in Colorado established potential sweet spots in the Cherokee and Atoka shale packages. The company also said it started a three-well vertical drilling programme at the Jolly Ranch project in Lincoln County, Colorado. Nighthawk said two of the three wells - the Craig 6-4 and the Craig 16-32, in the Bolero field – were development wells, while the third one, John Craig 11-2, near Limon, was an area previously undrilled by Nighthawk. On March 23, Nighthawk, which holds a 50% stake in Jolly Ranch, said it had drilled 13 wells in the region, with 11 of them seeing initial testing and production of more than 24,000 barrels of oil. Running Foxes Petroleum, the operator, holds the remaining 50% interest.

UPSTREAM, April 12, 2010

Alberta-Colorado shale JV

Stealth Ventures Ltd., Calgary, signed a joint venture with MOI Resources Ltd., a private Saskatchewan operator, to develop gas in the Cretaceous Colorado Group shales resource play in western Canada. Terms were not disclosed. The Cretaceous Colorado Group in the Western Canadian Sedimentary Basin is represented almost continuously in a 1,000 km east-west profile. Of the more than 250,000 wellbores that penetrate the Colorado, most were drilled to target deeper horizons. Meanwhile, following Stealth’s initial downspacing approval by the Alberta Energy Resources Conservation Board to proceed with eight wells per square mile on two sections of land in the Wildmere, Alta., area, Stealth has added 17 more sections.

OGJ, April 5, 2010

Experts see shale gas affecting overseas supplies

Potential natural gas production from shale formations has dramatically improved North America’s supply outlook, three panelists agreed during a Washington energy conference. The technology behind it also could change gas supply patterns overseas and influence domestic demand for other fuels, they added. US supply assumptions have been turned upside down in the last 3 years, they observed at the Apr. 7 natural gas breakout session at the Annual Energy Outlook Conference cosponsored by the US Energy Information Administration and Johns Hopkins University’s School for Advanced International Studies. “I sometimes wonder if we would have built 14 billion cubic feet of LNG import capacity if we’d known about this,” said Benjamin Schlesinger, president of Benjamin Schlesinger & Associates LLC. Michelle M. Foss, chief economist and head of the University of Texas at Austin’s Centre for Energy Economics, suggested that US shale gas development would respond to market demand. “I also think the potential could be greater if the technology improves further,” she said.

OGJ, April 9, 2010

ExxonMobil quietly optimistic about shale

European gas shale formations in Europe show promise, but they need to be better studied before their potential can be unleashed, Exxon Mobil Corp.’s CEO Rex Tillerson said. “We have to understand the shale resources better in Europe,” Tillerson told reporters. ExxonMobil, the world’s largest publicly-traded oil and gas company, has made big bets on shale – a tight, natural gas-rich rock formation that US oil companies have discovered how to tap profitably in recent years, creating an unprecedented boom in natural gas

production in North America. Exxon has unconventional gas acreage in Central and Eastern Europe. But Exxon and other companies seeking to exploit those reserves will likely have to find ways to operate in heavily populated areas – just like in the US, where some of the largest shales are in urban North Texas or the Northeast. “These are the same issues that we face in the US,” Tillerson said.

EXXONMOBIL, March 31, 2010

Argentina to develop more unconventional gas

Gas y Petroleo del Neuquen (G&P), the state oil company of Neuquen province, this year will launch an auction for contracts to explore and develop 10 secondary fields in the southwestern province of Argentina, newswire Telam reported. G&P already has carried out two auctions for secondary fields, as it seeks to boost output and widen reserves. The province is attracting attention for its tight and shale gas potential. G&P technical manager Alejandro Aubert said the exploration licenses are for four years, except if non-conventional reserves are sought, when the timeframe will be extended.

TELAM, April 5, 2010

Russian shale gas debate

The Russian federal legislature, the Duma, has recommended the government evaluate Russia’s potential in shale gas. Deputy Duma Speaker and energy committee member Valery Yazev explained that “There has been something of a technological breakthrough in shale gas” which has already halted projects to build LNG plants in many countries. The US, China and Australia have already begun to stop building facilities to produce and handle LNG. Canada has also joined in shale gas production.

OGR, 2010

NEWS IN BRIEF






Shale may reduce Ukrainian reliance on Russia

Prime Minister Mykola Azarov’s unsuccessful trip to Moscow last week to ask for a discount on natural gas imports was yet another reminder of Ukraine’s energy dependence. But a technology revolution that is already transforming production in the United States offers hope to wean energy hungry Ukraine off its reliance on Russia. Shale gas, which is natural gas trapped in rock rather than porous reservoirs, already accounts for 20% of US production. And with exploration under way in Western Europe, energy giants such as Royal Dutch Shell and TNK-BP are now considering Ukraine as a potential source.

UKRAYINSKA PRAVDA, April 01, 2010

SHALE OIL

Shale oil output to be a game-changer: EOG

EOG Resources’ CEO, Mark Papa has said that oil output from rock formations known as shales will change the face of oil production in the US. The Houston-based energy company plans to spend US$5.1 billion in capital in 2010 to pursue oil and natural gas liquids in places like the Eagle Ford Shale, a hydrocarbon-rich rock formation in South Texas. EOG Resources has acquired 505,000 acres with estimated reserves of 900 million barrels of crude oil equivalent. Oil from shale rock formations will be a “North American industry game changer,” Papa said during a meeting with investors on April 7, adding that the Eagle Ford is one of the largest discoveries in the US of the last 40 years.

Dow Jones Newswires, April 7, 2010

EOG to seek partner for shale oil

EOG Resources’s CEO, Mark Papa has announced that the company may seek out a partner to develop its natural gas assets as the company shifts its focus to finding oil. Although the Houston-based energy company is shifting its focus to oil, it still has assets in prolific onshore natural gas fields such as Texas’ Barnett Shale, the Haynesville Shale in Texas and Louisiana, and the Marcellus Shale in Pennsylvania and other states. “We are not going to be focusing on North American gas growth,” Papa said during a meeting with analysts, adding the company may look for a joint venture partner to develop its assets, “but there are no immediate plans to do so.” EOG plans to spend US$5.1 billion in capital this year to pursue oil and natural gas liquids in places like the Eagle Ford Shale, a hydrocarbon-rich rock formation in South Texas. EOG Resources has acquired 505,000 acres with estimated reserves of 900 million barrels of crude oil equivalent. The company plans to use the drilling techniques it pioneered in places like the Barnett Shale to unlock oil reserves in the Eagle Ford. Energy companies have learned to drill horizontally through these dense rock formations and break them apart, releasing the hydrocarbons trapped within. Papa said the company will continue to seek out rock formations that have the potential for oil production and the company is “not satisfied” with its current oil asset portfolio. “The vast majority of our investments will be going to oil or liquids projects,” Papa said.

DOW JONES NEWSWIRES, April 7, 2010

NRA signs oil shale deal

On April 11, the Jordan Natural Resources Authority (NRA) the Jordan Oil Shale Energy Company (JOSECO) signed a memorandum of understanding under which the latter would carry out oil shale exploration and drilling in southern

Jordan. Under the deal, JOSECO will dig 12 wells and carry out geological, geophysical and chemical studies in the first year to determine an estimated reserve of one billion tonnes of oil shale on a 51 square km plot of land in Bayer area. In the second year, the company will carry out engineering, environmental and feasibility studies on the use of advanced Russian technology and report to the NRA. Minister of Energy and Mineral Resources, Khaled Irani, said after he signed the accord with the chairman of the board at JOSECO, Majed Khalifa, that the deal followed lengthy studies and negotiations with the government. Khalifa said that his company had signed in 2009 key agreements with the Pioneer Company; a joint Russian-Saudi firm to build and operate a retorting system of oil shale called UTT-3000 to exploit oil shale and extract petroleum by using the surface mining technique. He added that the UTT-3000 system uses a dry distillation technique, which does not consume large amounts of water during the distillation process. Khalifa noted that the technology would set the cost of a barrel of oil extracted from oil shale between US$25 and US$30. The accord comes as part of the Kingdom’s efforts to reduce dependence on imported energy through developing an oil shale industry in Jordan and the region. In 2009, the government sealed two agreements with Royal Dutch Shell Oil and the Estonian company, Eesti Energia, to tap the Kingdom’s deep reserves of oil shale. The NRA estimates the Kingdom has 40 billion tonnes of oil shale deposits in various areas at various depths.

JNA, April 11, 2010

OIL SANDS/ HEAVY OIL

Ship runs aground

On April 9, Australian salvage crews started pumping 950 tonnes of heavy oil on from the Chinese coal ship, which ran aground off the Queensland sea on April 3.�

NEWS IN BRIEF






The fuel was being pumped onto a 50-metre barge, Maritime Safety Queensland (MSQ) general manager Patrick Quirk said. But he did not know how long it would take to pump out all the oil from the ship, which belongs to China’s Shen Zhen Energy Transport Company.

CHINA DAILY, April 9, 2010

Canada oil sands, greens meeting derailed

An attempt by Canada’s top oil sands producer and an environmental think tank to bring officials from the energy industry and green groups together to discuss ways to end growing animosity was derailed in March by discord and a legal battle. Suncor Energy Inc. and the Pembina Institute invited representatives from several major oil sands producers and environmental nongovernmental organisations to an informal “fireside chat” at the Vancouver Art Gallery on March 24 to end what they said was a lack of constructive dialogue. However, the meeting was cancelled a few days later over “the level of tension, specifically a legal dispute, between a subset of companies and a subset of ENGOs,” according to the letter rescinding the invitation. “At this time it seems the basic pre-conditions are not in place,” it said.


No cleanup plans approved as deadline looms

Oil sands companies are still in debate with Alberta’s energy regulator over cleaning up their toxic tailings ponds even though the deadline for them to start is just over a year away. A spokesman for the Energy and Resources Conservation Board says the timeline for converting the vast sludge ponds into safer dry tailings is fixed, but oil sands operators say the schedule is still under negotiation. “We have been in discussion with the board on a number of technical

issues that may have an impact on the exact timing and how we comply,” said Pius Rolheiser of Imperial Oil, which is developing the Kearl project in northern Alberta. He added: “Operators like Imperial may well need flexibility to apply the technologies as they’re developed.”

CANADIAN PRESS, April 6, 2010

Canada’s oil sands promotes role

Several industrial associations banded together on April 7, in a campaign aimed at emphasising the role of the energy sector in the economy of Alberta, Canada’s top oil-producing province. The aim for the sector, which has been under fire from environmental groups opposed especially to oil sands development, is to convince people in its home territory about its role in the economy and efforts to improve environmental performance, said the Canadian Association of Petroleum Producers (CAPP), which is leading the push. The groups also hope to avoid government policy moves that might be detrimental to its well-being, CAPP President David Collyer said. The Alberta government recently backtracked on increases to the royalty system after months of heated debate.


Oil sands backing

Athabasca has raised US$1.35 billion, considerably better than the US$750 million initially expected, while its partnership with PetroChina International Investment Co. gave investors confidence the company could succeed in the notoriously expensive oil sands. “It was really the endorsement from PetroChina,” Laura Lau, an energy and resources fund manager at Sentry Select Capital Corp. in Toronto, said on March 31, the day after the IPO was announced. PetroChina bought 60% of Athabasca’s MacKay River and Dover oil sands projects for US$1.9-billion in August 2009.

FP, April 1, 2010

Iran to reduce heavy oil prices

National Iranian Oil Co. is set to cut official selling prices for heavier grades of crude supplied to Asian refiners to 15-month lows after reductions by Saudi Arabia. The state oil company will set Iranian Heavy for May shipments at US$1.60 per barrel below the average of Persian Gulf benchmark Oman and Dubai grades, based on a quarterly formula tied to Saudi Arabian Oil Co. prices. That is US$0.10 lower than April, bringing the discount to its widest since February 2009.

BLOOMBERG, April 9, 2010

ONCG eyes Canada oil sands assets

ONGC, India largest energy explorer, is eyeing oil sand assets in the shores of Canada. However, the discussions are still in preliminary stage as it has been found. The experts in ONGC are of the opinion that if the region turns out to be rich in resources close to 10,000 barrels of heavy oil can be obtained per day. It will be worth US$1 billion.

GT, April 9, 2010

BP to test heavy oil process on North Slope

BP will begin producing heavy oil in a four-well US$100 million test production project in late May or early June in what will be the first sustained production test from the Ugnu formation, a vast pool of heavy oil at shallow depths just below the permafrost layer underlying the North Slope. BP will use the Cold Heavy Oil Production System, or CHOPS, technology to tap the Ugnu heavy oil, the goal being to eventually supplement conventional oil production from existing North Slope fields, which are being depleted. The technical challenges are formidable, BP spokesman Steve Rinehart said.�

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The biggest is getting the thick oil to flow at all. BP and ConocoPhillips are now producing viscous oil, which is heavier and thicker than conventional crude oil, but the Ugnu oil is even thicker.

ALASKA JOURNAL OF COMMERCE, April 9. 2010

Greenpeace holds Statoil demonstration

Greenpeace are demonstrating against Statoil’s oil sands project in Canada at Statoil’s offices outside Oslo. Around a dozen demonstrators from Greenpeace have started a demonstration against Statoil’s involvement with oil sands projects in Canada outside the company’s office at Vækerø, just outside Oslo. The organisation has handed out leaflets about oil sand to Statoil employees, encouraging the employees to vote against the company’s involvement in such projects at this year’s annual general meeting. The meeting will be held May 19, and Greenpeace says that they will keep on demonstrating until that date. “Statoil’s general meeting is a great opportunity to show that we care about the climate. I’ve just been to some oil sand fields in Alberta, and I am shocked. It’s beyond a shadow of a doubt that something like this never would have been allowed in Norway,” said Martin Norman in Greenpeace.

OILINFO, April 12, 2010

Court told of ‘upset’ at Syncrude mine

Data reported to the oil sands regulator suggested there was “an upset” at the Syncrude mine in the weeks before more than 1,600 waterfowl perished in the mine’s massive tailings pond, a court heard on April 6. Richard Houlihan, a senior Energy Resources Conservation Board official, said reports to his agency showed wide variations in the amount of bitumen recovered from the operation in April 2008. He said bitumen recovery from the Aurora mine that was in the

range of 88% to 95% at the beginning of the month plummeted to 65% on April 12, although it swung back closer to the normal range by April 28 – the day of the duck deaths.

EDMONTON JOURNAL, April 7, 2010

US analyst applauds Venezuela’s oil strategy

Martin Hutchinson, a US economic analyst, praised Venezuela’s strategy of bringing together a diversity of partners for developing the Orinoco Belt, a territory that contains large deposits of extra-heavy crude, news service RNV reported. The strategy is “surprisingly rational,” he wrote in an article carried by French newspaper Le Monde. With the diversification of partners, Venezuelan President Hugo Chavez “has reduced the risk of economic dependency,” he said. “The determination of Chavez is to not depend on the US, historically the biggest oil client of Venezuela.” Orinoco’s reserves are thought to be as much as the total world reserves of conventional oil, he said.

RNV, April 8, 2010

Venezuela, Russia team up on extra-heavy oil project

Venezuela and Russia plan to work together on developing an extra-heavy crude project in Venezuela, newswire Prensa Latina reported. “It is a project of extreme strategic importance for facing up to the energy problems of the planet,” Venezuelan President Hugo Chavez said. “From there we are going to supply oil to half the world.” The deal is for developing an additional three fields in the Orinoco Belt, which has huge reserves of extra-heavy oil. The countries already are working together on the development of Junin 6, with production starting out this year at 50,000 barrels a day. It is expected to reach up to 450,000 barrels per day. Russia will invest up to

US$1 billion in developing the blocks known as Ayacucho 2 and 3, plus Junin 3.

PRENSA LATINA, April 11, 2010

CBM

CBM summit

Judging by the newly introduced and ongoing coal-bed methane (CBM) regulations to accommodate growing domestic demand in Indonesia, China and India, it is clear that interest in CBM as potential energy source is on the rise. For this reason, CMT is bringing together key officials, top industry decision makers and CBM experts to the 3rd CBM & Unconventional Gas Summit in Hong Kong on June 10 & 11, 2010.

PRWEB, April 6, 2010

County gives nod for plant zoning change

On April 6, North Dakota’s Stark County Commission members voted to allow a zoning change for a coal plant near South Heart. The rezone will not take place until the coal company complies with conditions set by commissioners. South Heart Coal, a company owned by Great Northern Power Development, requested the zoning change on around 7,780 acres to facilitate a coal mine and construction of a coal gasification plant. More than 15 people spoke out about concerns over the company during a meeting of the county Zoning Board on April 5.

THE DICKINSON PRESS, April 6, 2010

Experts eye methane draining in wake of disaster

Climate considerations could encourage mine companies to drain and use methane from their coal beds and effectively enhance worker safety – a practice some experts say could win favour in the wake of the deadly disaster this week at a West Virginia mine.�

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The UN Economic Commission for Europe (UNECE), in a set of new guidelines released on April 7 , said draining methane can allow coal mining companies to both reduce explosive hazards and lower emissions of a potent greenhouse gas. Raymond Pilcher, chairman of UNECE’s Task Force on the Economic Benefits of Improving Mine Safety Through Extraction and Use of Coal Mine Methane, said the report was particularly geared toward countries like China and India, where coal mining is growing and accidents are far more common. At least 25 miners were killed in the mine blast, the country’s worst since 1984. Four other miners were still missing on April 7.

CLIMATEWIRE, April 8, 2010

Essar CBM Pipeline

Essar Oil plans to lay a 160 km pipeline from Durgapur to Kolkata to transport gas from its CBM blocks to consumers in West Bengal. The company is likely to start producing gas found below coal seams, called coal-bed methane (CBM), from its Raniganj block in West Bengal this quarter. The initial output is likely to

be 9,000-10,000 cubic metres per day with peak production of 3.5 million cubic metres per day envisaged in mid-2013. Peak output will last for 20 years.

BS, April 7, 2010

CH4 gets another chance

In a move that could help the Deep CH4 consortium – that provisionally won seven coal-bed methane (CBM) blocks in India for exploration in 2009, and subsequently faced the possibility of rejection – the law ministry has told the government that it can accept fresh information from the bidder. Deep CH4 had earlier complained that it was being denied an extra opportunity to prove its credentials before the final award of blocks.

BT, April 1, 2010

BHEL ready to launch work on ICG plant

Work on India’s first and biggest Integrated Coal Gasification Combined Cycle (ICGCC) power plant is likely to

commence in June 2010. The 25 billion-rupee plant will come up in Vijayawada in Andhra Pradesh and will be set up by three joint venture partners, with one of them being Bharat Heavy Electricals Ltd. (BHEL). A V Krishnan, the executive director of BHEL-Tiruchirappali (Tiruchy), said design for the 182MW plant has been completed. The project will be set up by three partners including Department of Science, ApGenco and BHEL.

BS, April 7, 2010

GTL/CTL

CTL conference

Limpopo premier, Cassel Mathale, will lead a provincial delegation to participate in the 2010 World Coal-to-Liquids Congress in Beijing, where experts and investors will share experiences and expertise in the development of coal-to-liquid technology. “Our new Limpopo Employment Growth and Development Plan identifies the need for downstream beneficiation of coal and diversification,” said Mathale.

BN, April 12, 2010

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HEADLINES FROM A SELECTION OF NEWSBASE MONITORS THIS WEEK

Oil and Gas Sector

AfrOil Ghana has awarded the Offshore Accra block to a consortium led by Australia’s Tap Oil.

AsianOil Petronas is to list two subsidiaries on the Malaysi an stock exchange in 2010.

ChinaOil CNOOC’s net profit fell by 34% year-on-year to US$4 .3 billion in 2009,

EurOil Total has been awarded the Montelimar shale gas per mit in the south of France for a period of five years.

FSU OGM Rosneft's Vankorskoye is on track to reach output o f 510,000 bpd in 2014.

GLNG The Golden Pass LNG terminal expects its first LNG shipment to arrive in the fourth quarter of 2010.

MEOG BP has awarded contracts worth US$500 million for drilling work on Iraq's Rumaila oilfield.

NorthAmOil The world's deepest facility, Perdido in the Gulf o f Mexico, has started producing.

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