oil & gas in the arctic - special report

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January 2012

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INTRODUCTION 2

o Arctic: frozen potential 2

EUROPE 4

o Norway looks to high tech for high north 4

o Greenland’s hopes for offshore oil bonanza begin to fade 6

FSU 8

o Rosneft and Gazprom look north 8

o Rosneft teams up with ExxonMobil to tackle the Kara Sea 10

NORTH AMERICA 12

o Alaska looks forward to offshore drilling 12

o Canada considers Arctic resources 14

NEWS THIS WEEK…

Resources and risks The Arctic is tipped to hold a substantial amount of reserves, but challenges remain over extracting these.

Norway has plans in motion to move forward with prudent licensing of its Arctic acreage. (Page 4)

Cairn has had a busy year drilling offshore Greenland but, thus far, has had little success. (Page 6)

Russia holds extensive resources in the Arctic, but will look to bring in foreign expertise and cash to exploit these. (Page 8)

Rosneft signed up ExxonMobil to work in the Kara Sea, following an initial deal with BP. (0)

Alaska holds interesting prospects but work in the offshore has faced repeated legal challenges. (Page 12)

Conventional gas projects in Canada’s north have suffered from the shale boom. (Page 14)

ARCTICSPECIAL REPORT

Arctic Special Report January 2012 page 2




The world’s need for additional sources of oil and gas will drive exploration north of the Arctic Circle, but much is still unknown about the area, in particular the resources in place. Working there is demanding technologically but the area is one of the few places available for international investment.

Companies are already gaining experience of working in cold conditions with work in Norway’s north, Alaska and Sakhalin Island. The most progress has been made in Norway, where the country has taken an extremely pragmatic approach to exploiting its domestic resources.

Russia has often been seen as hostile to foreign companies – a particular concern when working in such forbidding areas as the Arctic. Alaska’s prospects, meanwhile, took a hit following US concerns on safety following the Macondo disaster and companies working in the state have faced challenges on numerous grounds.

Norway, though, appears determined to press ahead with development and intends to hold a licence round in the Arctic in 2015. (See: Norway looks to high tech for high north, page 4.)

Play with fire It is the shortage of resources available for investment by traditional energy companies that has driven interest in the Arctic.

At the beginning of 2011, BP and Rosneft struck a deal on an area in the South Kara Sea, giving the UK-based super-major a stake in the Arctic. However, the deal fell apart on opposition from BP’s Russian joint venture partner and ExxonMobil stepped in as a replacement in August. (See: Rosneft and Gazprom look north, page 8.)

The US Geological Survey (USGS) estimated in July 2008 that the area’s technically recoverable resources were 90 billion barrels of oil, 47.29 trillion cubic metres of gas and 44 billion barrels of natural gas liquids (NGLs).

The study went on to say this accounted for 22% of the world’s undiscovered but recoverable resources, made up of 13% of the undiscovered oil, 30% of the undiscovered gas and 20% of undiscovered NGLs. Most of the resources – 84% – lie offshore.

Some exploration progress has been made north of the Arctic Circle, with around 40 billion barrels of oil discovered. However, the US agency’s statement said: “the Arctic, especially offshore, is essentially unexplored with respect to petroleum.”

While the USGS’ work is much needed – and provides useful insights into the Arctic’s resources – until exploration is carried out it would be premature to read too much into its projected totals.

You got the silver For exploration to proceed in the Arctic, energy prices must remain high but companies appear willing to move into the area at current prices. Long-term prices depend on a number of factors but with traditional resource producers in OPEC relying on oil at more than US$90 per barrel it seems likely that any declines would be momentary – or indicate far larger structural issues.

However, should the USGS report be accurate, it seems the Arctic’s resource potential may lie predominantly in the area of additional gas production. Russia’s Shtokmanovskoye field reveals the type of challenge associated with such developments, with project members calling for support from the government to press ahead with the task.

The Russian gas field had once been intended primarily to focus on exporting gas to North America and Gazprom sources reiterated this perspective. With the rise of unconventional gas in the US and Canada, though, such a market is an unlikely match for high-priced LNG from Shtokmanovskoye or other Arctic gas projects.

A better destination for Russian LNG from the Barents Sea would be Asia, but the traditional route – via the Suez Canal – involves a substantial distance. However, with ice cover receding, the viability of the Northeast Passage is increasing and provides a summertime alternative to transit via Egypt.

The oil-gas pricing disconnect has also had a notable impact within North America.

INTRODUCTION

Arctic: frozen potential Much of the world’s undiscovered energy is said to lie in the Arctic but accessing this resource will prove difficult for political, financial and environmental reasons By Ed Reed The Arctic holds 22% of the world’s undiscovered hydrocarbons, although it skews towards gas Technical difficulties will drive up the cost of operations Environmental challenges have ratcheted up the pressure in Alaska and Greenland





Canada’s hopes for its Mackenzie Gas Project have suffered, given the high cost incurred on transporting gas from the remote site to Alberta. (See: Canada considers Arctic resources, page 14.)

Similar woes have had an impact on plans for another gas pipeline, from Alaska to Alberta and on into the US. The project, backed by TransCanada and ExxonMobil, would require billions of dollars of investment and take years to complete, which seems unfeasible given the unconventional gas glut.

She’s so cold Sea ice is the “single most important environmental factor” for operations in the Arctic, according to a report from the International Research Institute of Stavanger (IRIS) in October. Facilities to be installed offshore need to be able to withstand ice and operators must bear in mind such conditions for transportation and rescue work, the report said.

Significantly, as global temperatures increase, ice cover recedes, opening up new areas for exploitation and access. According to some calculations, within 30 years summer in the Arctic may be virtually ice-free.

The impact of reduced ice cover can already be seen in the opening up of the Northeast Passage, linking the Atlantic and Pacific Oceans round the north of Russia.

The country’s leading gas independent, Novatek, has sent a number of tankers through this passage from Murmansk to Asia this year, aided by ice-breakers. This route may prove of interest to LNG tankers, which could transport gas from sites such as Shtokmanovskoye to high-priced Asian markets.

Travel via this route is said to take around half the time of transiting the Suez Canal, providing cost savings on reduced fuel use. In addition, it allows ships to avoid passing Somalia, which has seen an uptick in piracy in recent years.

It should be noted, though, that such a journey is only possible in summer. This would be likely, therefore, to drive LNG shipments to Asia during the summer months but during the winter more sales would flow into the Atlantic Basin.

The Northwest Passage, along the top of Alaska and Canada, may also offer transport opportunities, although shallower water is likely to reduce its usefulness somewhat.

As ice recedes, and shipping increases, it is likely that countries will become more interested in the area and how to access resources. Increased activity, meanwhile, makes accidents more likely to occur – which poses a whole new set of problems when compared with working in more benign conditions.

Highwire Ice may pose the primary problem for working in the Arctic but a number of factors complicate operations. During the winter season, when ice is more prevalent, the hours of daylight are reduced. In addition, pushing further into the Arctic necessarily means shifting operations further away from established bases and equipment supplies.

The combination of these factors would make any work tackling an oil spill difficult – if not impossible.

The Macondo disaster in the US Gulf of Mexico was an environmental stain on the energy industry and those involved – both companies and inhabitants of the region – are still coming to terms with the outcome.

In some ways, though, the location made tackling the problem easier. The sheer number of vessels available to BP to address the oil spill would not have been available had such an accident occurred in the Arctic.

The Macondo disaster led to a moratorium on drilling in the Gulf of Mexico and greater scrutiny of offshore work around the US, including in Alaska.

Some recent signs have indicated the

US administration will press ahead with exploitation of the country’s Arctic resources through a lease sale planned for the Chukchi Sea and approval of Royal Dutch Shell’s plans for drilling.

Alaska needs to bring on more oil production to fill its export pipeline, which has fallen well below its design capacity. Any additional production from Shell, though, will take at least 10 years to be exported. (See: Alaska looks forward to offshore drilling, page 12.)

A survey carried out by IRIS picked the question of responding to oil spills as the most frequently noted challenge.

Greenland published the oil spill response plan of Cairn Energy in August this year following sustained pressure from environmental groups such as Greenpeace. The company secured two rigs for work offshore Greenland, keeping one in reserve at all times to drill a relief well, should such be needed.

Should oil be spilled, it would prove difficult to contain, Cairn said. While the lower water temperatures would stop crude spreading as far as in more clement environments, this also complicates clean-up work. Work in winter would be particularly difficult, owing to the short days.

The presence of ice would make booms – used to contain spills – more difficult or impossible to employ.

A worst-case scenario set out by Cairn estimates a spill of 5,000 barrels per day, resulting from a kick during drilling an over-pressured reservoir, running for 37 days.

INTRODUCTION





This assumes a total blowout preventer (BOP) failure but for the drilling unit and riser to remain in place.

Using a variety of techniques, including dispersant, containment and in-situ burning, Cairn said it could clean up 8,793 bpd, more than would be spilled under the worst-case scenario.

Greenpeace reached a different evaluation of the data, describing the study as “wholly inadequate.” The

environmental group criticised Cairn’s worst-case scenario, noting the Macondo well flowed at 55,000 bpd, and quoted an expert as saying the company could only clean up 650 bpd.

The relationship between the environmental group and the oil company has been strained for some time. Earlier this year, Greenpeace activists occupied Cairn’s Scottish office, leading the company to take out an

injunction banning the distribution of any pictures taken during the protest.

Despite the NGO’s best efforts, though, drilling went ahead – but was largely disappointing. This combination of a lack of results, high costs and negative publicity raises uncertainties on how eagerly companies will embrace further work in Greenland. (See: Greenland’s hopes for offshore oil bonanza begin to fade, page 6.)

Norwegian Minister of Petroleum and Energy Ole Borten Moe recently described the idea of an Arctic licensing round in 2015 as “realistic.”

This announcement is likely to set pulses racing around the oil and gas industry, with another ‘frontier’ opening up for exploration. However, the Arctic is unlike any other prospective area for hydrocarbon exploration. According to a report by the US Geological Survey (USGS), the region “accounts for about 13% of the undiscovered oil, 30% of the undiscovered natural gas and 20% of the undiscovered natural gas liquids [NGLs] in the world.” Around 84% of the estimated resources are expected to lie offshore.

The attraction of exploring the Arctic is obvious, and 2011 has so far been a successful year for Norway.

In April, Statoil struck oil at the Skrugard prospect in Production Licence

(PL) 532, around 200 km northwest of Hammerfest – a find thought to hold 250-500 million barrels, while in PL 535, Total struck large quantities of gas at the Norvarg prospect. Norway has estimated the Barents Sea to hold 5.9 billion barrels of undiscovered oil and gas.

First steps Norway’s first gas production in Arctic Circle came in 2007, when Snoehvit – the world’s most northerly gas field – came online. The field feeds the Melkoeya liquefied natural gas (LNG) terminal, which has a capacity of around 4.3 million tonnes (5.6 billion cubic metres) per year of LNG.

In 2013, production is expected to begin at Norway’s Goliat oilfield, the country’s first to be developed in Arctic waters.

This field is located around 85 km northwest of Hammerfest in PL 229,

which was awarded to the Norwegian arm of Italy’s Eni, the field’s operator with a 65% stake, and Norway’s part state-owned Statoil (35%) in the Barents Sea licensing round in 1997.

According to Eni Norge, the initial discovery on the field was made by the first exploration well in 2000, and a total of five wells have now been drilled.

At around 174 million barrels of recoverable oil, the field’s size is modest. However, it is expected that production will last for around 10-15 years.

In 2009, it was decided that the field would be developed using a floating production, storage and offloading (FPSO) vessel, the engineering, procurement, construction, onshore commissioning and transportation contract for which was controversially awarded to South Korea-based Hyundai Heavy Industries (HHI).

INTRODUCTION

EUROPE

Norway looks to high tech for high north As Norway prepares to make major strides into Arctic exploration, policy and technology appear to be the main keys to success By Ian Simm Norway has estimated the Barents Sea to hold 5.9 billion barrels of undiscovered oil and gas Goliat will be the first Arctic oilfield to be developed, with a purpose-built winterised FPSO unit The preliminary signs have been excellent, with several major finds already having being made





The award of the US$1.16 billion contract was unpopular in Norway, as the HHI bid was favoured over a bid by Oslo-based Aker Solutions and fellow Korean firm Samsung Heavy Industries. The contract was hoped to have created around 7,000 man-years of labour in Norway.

According to Eni, however, as of March 2011, “60% of all contracts have been awarded to Norwegian industry. We expect the Norwegian content to increase to 65% when all supplies to Goliat are [delivered].”

Eni and Statoil chose Norway-based Sevan Marine’s Sevan 1000 FPSO design – a fully winterised cylindrical floater, built to cope with the harsh weather conditions of the Barents Sea. The unit will have a production capacity of 110,000 barrels per day of oil and 4 million cubic metres per day of gas, as well as being able to store around 1 million barrels of oil.

On October 14, Dockwise Ltd. announced that following a job in the Gulf of Mexico in 2013, its new-build vessel, Dockwise Vanguard, would return to South Korea to “load and transport the Goliat FPSO to northern Norway.”

It is clear that exploring and developing Arctic reserves will require technological advancements; however, Norway’s bid to do so will also require political backing.

Follow the lead On June 7, Norway and Russia’s foreign ministers ratified a treaty at a ceremony in Oslo, dividing a disputed 175,000-square km area into equal shares. The agreement came into force on July 7, effectively opening the southeast Barents for business.

Like Norway, Russia is intending to delve into its offshore hydrocarbon treasure trove, and efforts are being made to gain experience in dealing with the difficult weather conditions post-haste. State-run gas monopoly Gazprom has said that work at its Prirazlomnoye oilfield, located 60 km offshore in the Pechora Sea, could pave the way for the future development of the Russian Arctic.

Like Goliat, Prirazlomnoye will be developed by a purpose-built rig – Prirazlomnaya, Russia’s first ice-resistant stationary offshore drilling platform. Gazprom is aiming to drill as many as 40 directional wells, beginning in early

2012. Unlike Goliat, however, the Russian

drilling location is in a mere 20 metres of water, whereas the Norwegian drilling will take place in water 400 metres deep.

As has been seen in Edinburgh-based Cairn’s Greenland drilling campaign, Arctic exploration is not only challenging in the field, but also when it comes to politics. The frontier explorer’s exploits off the west of Greenland have been hounded by protests by Greenpeace activists, and the Danish navy was recently called in to remove protestors from the Leiv Eiriksson drillship and a Greenpeace vessel from the exploration area.

Opening up the Norwegian Arctic is likely to attract similar attention, especially in fragile habitats.

These areas were included in April’s 21st Awards in Predefined Areas (APA) Licensing Round.

The inclusion of the deepwater blocks in the round was inevitably going to cause some political friction, given that some of the planned blocks on offer are in the pristine waters of the Barents Sea and near the oil-rich but environmentally-sensitive waters surrounding Lofoten and Vesteraalen in

Nordland. In a statement following the

announcements, Borten Moe said the round would “lay a foundation” for further exploration of Norway’s least developed areas.

“There is unprecedented interest in our northernmost seas,” he said. “The present level of activity in the Barents Sea is high, and increasing.”

The Petroleum and Energy Ministry then moved to allay concerns over safety – introducing additional requirements for deepwater, high-temperature and high-pressure reservoirs.

Looking forward, it appears Norway has a firm focus on safety in the region.

EUROPE





Haakon Smith-Isaksen, Communication Adviser at the Norwegian Ministry of Petroleum and Energy, told NewsBase: “The Norwegian government will initiate an impact assessment under the Petroleum Act, with a view to granting production licences for the previously disputed area west of the delimitation line in the southern part of the Barents Sea (south of 74°30’ N). If this is justified by the conclusions of the impact assessment, the government will present a white paper recommending that these areas should be opened for petroleum activity. Such a white paper may be presented in 2013.”

He added that the areas in question were in many ways similar to areas further to the west, which are already open for petroleum activity.

When asked about a start date for exploration in the Nordland VI, VII and Troms II blocks – the most eagerly anticipated of the blocks surrounding Lofoten and Vesteraalen, Smith-Isaksen said that the Norwegian government would not initiate an impact assessment under the Petroleum Act for the areas while the current Parliament was seated.

“The question will therefore be answered by the next Storting [Norwegian Parliament] after the Parliamentary election in 2013,” he added.

In Greenland, drilling is only permitted in summer months, as conditions are deemed too inclement throughout the rest of the year. Smith-Isaksen said that the

question of seasonal drilling programmes was likely to be discussed in the aforementioned white paper.

Technology at the fore Drilling in the Arctic brings with it obvious challenges above and beneath the water.

A lack of working experience in the harsh climate of severe ice in the far north presents a challenge to those wishing to explore the region for hydrocarbons. With no proven technology for production or construction in around 90% of the areas in question, the test will be to create a new services industry to meet the requirements of such an environment.

The learning curve will be steep, but experience garnered in exploring and producing from harsh climates like that of the North Sea can provide a springboard from which to leap.

With punishing surface conditions, subsea field development will be the favoured ploy for extracting resources in the frozen north.

As has been seen in Greenland, however, the weather can make it impossible to work year-round, an issue that will add to cost as well as being likely to result in problems with pressure as well as slow production.

On October 10, Oil & Gas Eurasia released a report which said: “In the shallow waters of the Arctic in the Beaufort Sea, already a series of artificial islands and bases of various types have

been built, providing drilling of wells at depths ranging from 6 to 20-30 metres.”

It added: “For the depth of 60 metres, there is an option to use stationary ice-resistant platforms, while for depths under 60 metres their use will depend on the investment’s justification.”

Work is ongoing on solutions that will provide for guaranteed year-round drilling in such conditions.

Such solutions could prove to be a boon for local services companies, with major contracts likely to be awarded in the near future.

Last week, local authorities in the northern Norwegian city of Tromsoe said that they wanted to build a permanent base for oil and gas operations in the Arctic. Assistant Port Director Randi Thoerring told Nordlys newspaper that with the increasing level of activities in the far north, there was a need for such a base.

As Norway embarks on the challenge of developing the far north, there remains a lack of clarity, akin to that found when embarking on any such venture. Indeed, when asked about whether he thought FPSOs like Goliat would be the preferred method for developing Norway’s new reserves, Smith-Isaksen said: “There is uncertainty concerning the resource potential in Nordland VI, VII and Troms II. The uncertainty will remain until exploration drilling has been executed … Hence it is premature to speculate on possible future development solutions.”

Hopes for an offshore oil bonanza in the icy Arctic waters of Greenland are starting to fade somewhat, as the

Edinburgh-based group Cairn Energy revealed that it has spent nearly GBP500 million (US$804 million) in drilling costs

since the start of its unsuccessful Greenland campaign.

EUROPE

Greenland’s hopes for offshore oil bonanza begin to fade Disappointing results have shrouded the excitement that until recently had surrounded the hunt for oil in Greenland. However, those involved remain resolute in their focus By Nnamdi Anyadike





The company currently has an interest in 11 large offshore blocks, covering an area of around 102,000 square km. The firm has sunk 6 of the 12 exploration wells that have been drilled off Greenland since such work started there 40 years ago.

While Cairn released a statement saying it “remains encouraged by the prospects and opportunities presented by exploration offshore Greenland,” the country’s summer drilling season is now drawing to a close as winter sets in.

Great promise If Greenland’s promise as an offshore oil province turns out to be overstated it will be a blow to those energy companies who are turning to the Arctic as one of the last frontiers left for exploration. However, it will gladden the hearts of the environmental lobby, which is dead set against oil and gas exploration in the region’s pristine waters.

But for energy companies, the prospect of operating in a region that, according to US Geological Survey (USGS), contains as much as 90 billion barrels of oil and 1.7 trillion cubic feet (48 billion cubic metres) of natural gas – around 25% of the world’s undiscovered hydrocarbons – is tempting.

The USGS said: “The extensive Arctic continental shelves may constitute the geographically largest unexplored prospective area for petroleum remaining on Earth.”

Greenland is seen as potentially a key player in the Arctic’s oil and gas development, with the USGS estimating its continental shelf to hold up to 50 billion barrels of oil and gas. The Baffin Bay area alone may contain up to 18 billion barrels of oil equivalent.

If these resources come on stream as planned then Greenland could conceivably supply Europe’s energy needs for nearly two years.

Greenpeace, which is leading the environmental campaign against offshore

drilling in the Arctic, has ridiculed the USGS’ high estimates. The lobby group claims that in 2000, the US government said there could be as much as 47 billion barrels of oil in northeast Greenland. By 2008, it said the government had slashed its estimate to less than 9 billion barrels.

Drumming up interest The current USGS estimate for offshore west Greenland is 7 billion barrels. Despite this level of uncertainty, an increasing number of oil companies have decided to take the plunge. As a result, oil and gas exploration across a wide swathe of territory sweeping north of the Arctic Circle has now been stepped up.

In August, super-major Exxon Mobil Corp. and Russia’s Rosneft announced a deal to explore offshore oil fields in the Russian Arctic of the Kara Sea. This followed the major Skrugard discovery in the Barents Sea by Norway’s Statoil earlier in the year.

In mid-2012, these companies could be joined by Shell, which hopes to begin a controversial drilling programme off the northern coast of Alaska.

Louise Burgess, Cairn’s corporate communications officer, told NewsBase: “It is not only Cairn that believes in the hydrocarbon potential offshore Greenland: Chevron, Conoco Phillips, Exxon, Shell and Statoil also currently

have interests in the country.” She added: “With rising global energy

demand and decreasing production from current oil- and gas fields, the potential of frontier reserves such as offshore Greenland to contribute to the world’s future energy requirements is significant.”

Cold shoulder However, Cairn’s failure to make a commercially viable oil find off the coast of Greenland to date is a warning to those who underestimate the difficulties of operating in the wilderness areas of the north.

It also provides an object lesson in how quickly hopes for a region can deflate. In September that year, Cairn announced an oil find in Baffin Bay with the first exploration well there in more than 10 years. The company’s success at its Alpha-1S1 well followed six failed efforts in 30 years of exploration by various companies.

Then, in December 2010, Greenland awarded seven oil and gas licences to a number of competing companies for the exploration of 70,768 square km in Baffin Bay. The licensees include Greenland’s national oil company (NOC) Nunaoil, Cairn, Dong Energy, Royal Dutch Shell and ConocoPhillips. Hopes were riding high.

EUROPE





Stumbling blocks Initial investment on the exploration blocks is expected to be high – anywhere between 130 and 200 million euros (US$181-279 million) per block, reflecting the challenging environment of the Arctic Circle.

Production in the Arctic is similarly high-cost and is estimated at US$500-700 per tonne. This compares with developed regions where costs can be as little as US$30-40 per tonne, or the Far East, where it can be US$200-300 per tonne.

Edinburgh-based energy consultancy Wood Mackenzie has said that operators would need a commercial discovery of at least 250 million barrels of oil to establish profitable operations at a minimum oil price of US$75 per barrel. However, higher prices may be required depending on the reservoir’s quality, the field’s size, and distance from shore.

Commitment to the cause The winners of the Greenland blocks have committed to drilling two to three exploration wells. In 2010, Cairn budgeted US$1 billion for its 10-well

drilling campaign over a three-year period.

Burgess said the company was still upbeat, despite its lack of success. “Cairn remains encouraged by the prospects and opportunities presented by exploration offshore Greenland. [The company’s] approach to exploration has allowed it to build a leading early entry position in Greenland, where we remain focused on the potential of our multi-basin position,” she told NewsBase.

The long lead times separating exploration and development in Greenland means that any company operating there must have deep pockets.

Joern Skov Nielsen, head of Greenland’s Bureau of Minerals, estimates that building the necessary production facilities will take financial investments of US$5-6 billion, and that these are unlikely to be operational for around another 10 years.

In order to fund its Greenland project, Cairn sold a 51% stake in its subsidiary, Cairn India, to Indian mining firm Vedanta for US$8.5 billion. When news broke in 2010 that it had failed to replicate its earlier exploration success,

shares in Cairn plunged by 7%. The company will be keenly aware that

it will soon need to satisfy the market that it has made the right decision in plumping for Greenland.

Nuuk will hold licensing rounds for the Greenland Sea off the country’s East coast in 2012 and 2013.

According to the Bureau of Minerals and Petroleum, the first round “will be reserved for companies which are paying members of the KANUMAS Group and groups of companies which include at least one company which is a paying member of the KANUMAS Group. The paying members of the KANUMAS Group are: ExxonMobil, Statoil, BP, Japan National Oil Corporation (JNOC), Chevron and Shell [as well as NunaOil].”

The pre-round for the first will be formally opened on January 1, 2012 with deadline for submission of applications for prequalification as operators on March 1. The latter will be formally opened on June 15 2013.

Much of the interest in these rounds is likely to depend on the turnout of last of the exploration carried out in the current drilling season.

Russia’s government has indicated that it views the exploitation of crude oil and natural gas fields off the country’s northern coast as a priority.

Though the Kremlin has frequently called on Russia to reduce its dependence on hydrocarbon revenues, it is eager to maintain high production levels for as long as possible. It cannot achieve this

goal solely on the strength of mature provinces such as Western Siberia, so it is looking to open up new regions.

The Arctic shelf, which is almost entirely undeveloped, is one such region. It is believed to be home to vast hydrocarbon reserves that could help keep Russian output levels steady over the long term.

The rewards of Arctic exploration could be substantial. According to a US Department of Energy report published in 2009, the US Geological Survey (USGS) has determined that the majority of the 1.669 quadrillion cubic feet (48 trillion cubic metres) of undiscovered gas reserves in the northern seas lie in Russian territory.

EUROPE

FSU

Rosneft and Gazprom look north Russia’s new policy on joint ventures has opened up fresh opportunities for Arctic shelf projects, but Rosneft has pulled ahead of Gazprom in attracting foreign partners By Jennifer DeLay Rosneft intends to work with ExxonMobil to explore and develop three areas in the Kara Sea Meanwhile, Gazprom is scaling back its plans for development of the Shtokmanovskoye field The gas giant will gain offshore experience at Prirazlomnoye but will face harsher conditions at other fields





Fully 39% of those reserves lie in the southern Kara Sea off the coast of northwestern Siberia, the report said.

The Russian Arctic is also home to sizeable oil reserves. These are likely to be developed first, since the country’s state-owned gas monopoly Gazprom wants to launch production at major onshore deposits such as Bovanenkovskoye before moving on to offshore operations, which are more complex and costly.

Oil producers, by contrast, are less inclined to wait. As noted above, Western Siberia, which is Russia’s main oil province, is past its prime, and this has led major companies to scout for new prospects. Some of these prospects are onshore fields in Eastern Siberia, but others lie offshore in the Black Sea, the northern Caspian Sea and the Sea of Okhotsk, as well as the northern seas.

Policy shift One of the factors complicating offshore development projects has been Moscow’s decision to classify shelf deposits as strategic reserves.

Under this policy, the only companies eligible to exploit such fields were government-controlled companies with at least five years of experience in offshore operations. In practice, this has posed insurmountable barriers to all oil and gas firms, with the exception of state-run Gazprom and Rosneft. (Zarubezhneft, though, will soon be in a position to join these two companies by virtue of its work off the coast of Vietnam.)

Initially, the Kremlin was reluctant to see Gazprom and

Rosneft work closely with foreign partners on Arctic shelf projects. More recently, though, it has loosened up restrictions on outside investment in a bid to attract interest from Western companies that have experience in offshore drilling and that can offer the technologies needed to work in the hostile northern seas. Specifically, it has said it will permit state-owned companies to form joint ventures with foreign investors to carry out Arctic offshore projects.

Good news for Rosneft There are still some issues to iron out on this front, such as the question of exactly how to book reserves discovered by joint ventures working in the Arctic.

However, the new policy has already

generated good news for Rosneft. Late last month, ExxonMobil of the US agreed to work with the state-run oil company to explore and develop three offshore areas in the Kara Sea (East Prinovozemelsky-1, -2 and -3, which were the focus of the ill-fated co-operation deal signed with BP in January). Rosneft is also in talks with the multinational Royal Dutch/Shell on the possibilities for co-operation on Arctic

projects, according to press reports. So far, however, Gazprom has yet to

secure similar expressions of interest. The gas monopoly has not made arrangements to work with foreign partners on any major Arctic project since 2007, when it teamed up with France’s Total and Norway’s Statoil to form Shtokman Development AG, the joint venture that will develop the Shtokmanovskoye gas and condensate field in the Barents Sea.

This project’s future is somewhat shaky. Concerns about the slowdown in European gas demand have led to delays, and in early 2010 the joint venture partners began talking about dropping plans to export second-phase production in the form of liquefied natural gas (LNG).

Prirazlomnoye Gazprom does have high hopes for another Arctic offshore project, however.

Company representatives have said that work at Prirazlomnoye, an oilfield located 60 km offshore in the Pechora Sea, could serve as a springboard for future development work in the northern seas. They have also stated that the project will allow Gazprom to gain valuable experience in drilling, extraction and transportation in Arctic waters.

FSU





The company recently installed Prirazlomnaya, Russia’s first ice-resistant stationary offshore drilling platform, at the field. The platform will be used to drill up to 40 directional wells, the first of which may begin production as soon as the first quarter of 2012. It will also be capable of handling crude from other nearby fields such as Dolginskoye, which Gazprom has said it wants to develop in tandem with Prirazlomnoye.

This project may also face complications. On one hand, Gazprom has said it intends to transfer the development licence for Prirazlomnoye to Gazprom Neft, its oil arm.

It is not yet clear when such a transfer might take place, but since Gazprom Neft’s operations do not fully overlap with those of its parent company, this

move could impose limits on Gazprom’s ability to gain experience in offshore operations.

Offshore experience This will not be catastrophic for the gas monopoly, which is currently working to build a fleet of new Arctic rigs.

The company has already gained experience elsewhere – namely, the Sakhalin-II offshore block in the Russia Far East, where it has served as operator since late 2006.

However, it is worth noting that conditions at Prirazlomnoye are more difficult; temperatures are lower, and the seas will be iced over for a longer period during the winter.

Moreover, if Gazprom chooses to go further north, it will face conditions that

are even more severe. It will also have to drill in considerably deeper waters. (The Prirazlomnaya platform has been installed at a site where the sea is about 20 metres deep.)

This is less of a concern for Rosneft. The oil company hopes to benefit from its access to the experience and technology of ExxonMobil, which has worked off the northern coast of Alaska. Gazprom, however, may have to cover more ground on its own if it does not take advantage of the new policy on Arctic joint ventures. Conversely, though, it has more time to do so, since it is not likely to begin developing the northern seas in earnest before the end of this decade.

State-controlled Rosneft has officially announced that it has begun seeking foreign investors for a number of major offshore projects. The Russian company hopes to find partners for work on the shelf of the Black Sea, as well as in the so-called “grey zones” of the Barents Sea, which are being shared with Norway, according to an agreement signed earlier this year after more than 40 years of negotiations.

While Norway’s Statoil is seen as the most likely partner for Rosneft in the Barents Sea, US-based and European companies are expected to take part in operations on the Black Sea shelf. In both cases, these outside investors will

bring in the modern technologies that Russian firms do not have at their disposal.

At the same time, when negotiating with potential partners for Black Sea projects, Rosneft will have to address the financial issues that were reportedly the reason for Chevron’s decision to abandon the Val Shatskogo project.

The US-based major signed a preliminary joint venture agreement on the block in mid-2010, but the deal fell apart earlier this year. The Russian company is now in talks with ExxonMobil, another US giant, on the project.

Joint use Last year, Russia and Norway officially agreed to joint use of sections of the Barents Sea and other northern waters that are expected to contain significant amounts of crude oil and natural gas.

Since then, the Russian government has not identified any potential partners for operations on the northern sea shelf. However, Statoil seems likely to show interest, taking into account its rich experience in oil and gas production from platforms off the western and northern coasts of Norway, as well as in North Sea locations.

FSU

Rosneft teams up with ExxonMobil to tackle the Kara Sea The state-owned Russian giant sees Statoil as its most likely partner for work at fields on the northern sea shelf By Vladimir Kovalev Rosneft hopes to gain access to fields in the “grey zone” of the Barents Sea The company may also work with US and European firms in the Black Sea Foreign partners are expected to provide the technology needed for offshore development





Rosneft sees the Norwegian company as one of the best possible partners. “It would be effective to work with these [firms] that [already] have information [about working in the northern seas]. Norway has already begun geological research on its own part of the grey zone,” Rosneft President Eduard Khudainatov was quoted as saying by RBC Daily.

Seeking licences Rosneft is also seeking to secure rights to other sections of the northern sea shelf, particularly in the Barents Sea.

“The company has submitted an application to Rosnedra [Russia’s state subsoil management agency] to obtain a development licence for three such sites,” said Rosneft President Eduard Khudainatov, according to Oilru.com.

Khudainatov added that the company should get these licences within a week or two.

However, the process may not be so quick, as Rosneft will have to lobby the Russian Ministry of Defence for the licences. Until now, the ministry has upheld regulations banning any commercial activity in areas such as these, which are considered to be of military interest, according to Barents Observer.

Kara Sea prospects Meanwhile, Rosneft already holds licences for other offshore areas. In August this year, the state-run company signed an agreement with ExxonMobil on research work at three licence areas in the Kara Sea. The partners intend to begin seismic exploration at these areas, which are known as East Prinovozemelsky-1, -2 and -3, in 2013.

At the same time, the company is planning to send research vessels to a number of new sites in the northern seas, particularly the Kara Sea, in 2012. “Our ships will reach not only Yuzhno-

Russky, but also the East Prinovozemelsky sites by April,” Khudainatov said last week.

The Yuzhno-Russky site may only contain up to 21.5 billion tonnes of oil equivalent, less than the East Prinovozemelsky block’s estimated reserves of 35.8 billion barrels (4.9 billion tonnes) of crude and 10.3 trillion cubic metres of gas. However, the figure may be corrected later, after geological research is carried out at the site.

Black Sea projects Despite its extensive experience with the harsh weather and climate conditions that prevail in the northern seas, Statoil is not likely to be Rosneft’s only foreign partner. The Russian company will probably work with other companies from Europe and the US to develop sites in the Black Sea – particularly the Val Shatskogo deposit, which has been licensed out to Rosneft.

“We are working. There are several companies on the list of potential partners,” Khudainatov said. He added that France’s Total, which has been among the most active in negotiations with Rosneft, “has quite serious competitors.” (Rosneft is reportedly in talks with Italy’s Eni as well as ExxonMobil on Val Shatskogo, according to Russian media reports. The US giant has a good chance of being selected as a partner, as it is already

working with the Russian firm at a neighbouring site, the Tuapse Trough.)

Rosneft needs a foreign partner for this project, the Russian company’s chief said.

“This site contains geological structures that are not simple,” he explained. Val Shatskogo holds light and heavy crude, “and the second type will demand partners with upgrade capacities – in other words, companies that can produce synthetic oil,” he said.

Clearing obstacles

To strike a deal on Val Shatskogo, Rosneft will have to address the issues that led Chevron to back out of its deal for the field.

According to Russian media reports, the US and Russian companies fell out in March of this year, owing to disagreements over estimated development costs and reserve figures. These matters are still apparently a source of concern, according to Vitaly Mikhalchuk, an analyst at Investcafe.

“The main reason for the slow pace of negotiations is the high cost of the first stage of geological research works – more than US$1 billion, plus production costs of US$30-35 billion. Additionally, there is no solid finding on the size of the deposit, which has been estimated at the level of 860 million tonnes [of oil],” Mikhalchuk was quoted as saying on Investcafe’s website.

He went on to say that it would take time to determine exactly how much crude Val Shatskogo might yield, since it had yet to be fully explored. “It is rather clear now that the geological research campaign planned earlier, which was originally scheduled to start at the end of 2011, will not begin at the set time,” he said. If Rosneft fails to strike a deal with a foreign investor this time, he added, it could face delays of “more than half a year.”

FSU





Plans for drilling in Arctic waters offshore Alaska are moving ahead despite considerable opposition on environmental grounds.

Royal Dutch Shell is closer to receiving final permission for its Chukchi and Beaufort Seas exploration plans, having obtained air quality permits from the Environmental Protection Agency (EPA) in September. The super-major’s plan to drill four shallow-water wells in the Beaufort received approval in August from the Bureau of Ocean Energy Management, Regulation and

Enforcement (BOEMRE) – the predecessor of current regulator Bureau of Ocean Energy Management (BOEM). The wells would target the Sivulliq and Torpedo prospects on the west side of Camden Bay, to the east of Prudhoe Bay.

Both these approvals have since been challenged by a collection of environmental organisations and indigenous native groups, but the company is confident of its permits withstanding legal challenges and has said it is increasingly optimistic of obtaining the final go-ahead. “We feel

we have some very strong permits, and we feel that there is reason to be optimistic that our permits will survive a court challenge,” Shell’s vice president in Alaska, Pete Slaiby, was reported as saying in Petroleum News. “Litigation will always be a risk we have.”

Shell has said it expects to take a decision by the end of October on whether it will start drilling in July 2012. The company will base its decision on the status of the 35 permits it requires before drilling can begin, although the appeal will still be ongoing at that point.

Offshore resources Shell is far from the only

player interested in Alaska’s reserves – reflecting part of a wider trend of energy companies and politicians, most notably in the US, Canada and Russia, looking to the resource-rich Arctic to meet their countries’ energy demand. In Alaska’s case, its Arctic waters have been estimated to hold 25 billion barrels of oil, according to US government estimates. Exploration in Alaska has been hampered by safety concerns.

The Deepwater Horizon disaster in the Gulf of Mexico led to a moratorium on deepwater drilling and added fuel to the environmental opposition to offshore work – particularly in sensitive areas. Industry did not stand still, though, and brought pressure to bear on the US administration to allow offshore exploration to resume. Not only would this move help reduce US dependence on foreign oil, it was argued, but it would also create jobs and provide a huge source of revenue at a time of global economic uncertainty. Even after the moratorium was lifted and drilling was allowed to resume, industry called for the regulatory process to be speeded up, arguing it was too slow and prone to major delays and complications.

Commenting on BOEMRE’s approval of Shell’s Beaufort Sea exploration plan, an American Institute of Petroleum (API) senior policy advisor, Richard Ranger, said: “The slow pace and frequent hurdles to permitting projects like Shell’s has cost jobs, revenue and energy production.”

NORTH AMERICA

Alaska looks forward to offshore drilling Plans to open up Arctic waters offshore Alaska are moving ahead, but the firms involved still have a significant number of hurdles to overcome and face considerable opposition By Anna Kachkova Permits awarded to Shell for offshore Arctic exploration are being challenged by environmental groups The US is upholding a Chukchi Sea lease sale, despite safety and environmental objections Production is at least 10 years off and will not address the immediate problem of dwindling TAPS flows





According to Ranger, the API hoped BOEMRE’s decision on Shell marked “the start of a regulatory process that is thorough, efficient and predictable – one that allows exploration for valuable and needed energy resources and that ensures development takes place in a responsible and sustainable way, without new major regulatory impediments or delays.”

A study commissioned by Shell from consultancy Northern Economics and the University of Alaska, Anchorage, served to back up the argument that offshore drilling would bring significant benefits to the US. The study claimed that exploration and production on Alaska’s Outer Continental Shelf (OCS) would create 54,700 jobs across the US and bring in US$193 billion in federal, state and local tax revenue by 2057. According to the study, Alaska’s OCS could produce up to 10 billion barrels of oil and 15 trillion cubic feet (424.8 billion cubic metres) of natural gas by that year. The US – which imports over 60% of its crude oil – could cut its imports by 9% over 35 years, the study suggested. The findings were released in February 2011 – by which time uprisings in the Middle East had made the prospect of becoming less dependent on oil imports even more attractive.

Lease sale Faced with pressure from the industry and its supporters, the US administration has opened up some opportunities for offshore drilling. On October 3, the Department of the Interior announced it would uphold a sale of nearly 500 leases in the Chukchi Sea after these had been challenged in court by environmental groups, having previously been issued in 2008 by the previous Republican administration. The move allows BOEM to go ahead with approving Shell’s Chukchi Sea exploration plan, on top of the Beaufort Sea plan that has already been passed.

Other firms are also keen to get going in Alaska. ConocoPhillips, Statoil and Repsol also have leases in the Chukchi Sea and are planning exploration. Meanwhile, BP’s Liberty project in the

Beaufort Sea was suspended in the wake of the Deepwater Horizon disaster, as the company carried out a safety review on the rig it planned to use for the project. Drilling has still not started at Liberty. Indeed, BP’s offshore plans have suffered more than most in the fallout from Deepwater Horizon, and even as BOEM allows more drilling, the agency – or rather its predecessor – has been hesitant to grant new permits to BP, with some US lawmakers and environmental groups arguing they have seen no evidence of the super-major improving its safety practices since the Macondo blowout.

Safety concerns The issue of safety has been a contentious one when it comes to opening up drilling offshore Alaska. Opponents have criticised Shell and other firms, questioning their ability to clean up any potential oil spill in Arctic waters.

Environmental law firm Earthjustice – which has led opposition groups in filing appeals against Shell – argued that an Arctic spill would devastate wildlife and that any attempt to clean up such a spill would be ineffective. There is a lack of scientific information available on the offshore Arctic, Earthjustice argued, which makes adequate assessments of offshore drilling risk in the region problematic. The firm also cited US

Coast Guard statements about a lack of capability to respond to an Arctic spill.

Shell, in turn, has argued that its oil spill response plan is a strong one. It has assembled a self-contained oil spill response fleet, which would be mobilised along with any offshore drilling operation. The company has also made arrangements for near-shore and shoreline responses to any spill, and is implementing new well-capping and spill-containment technology. “I believe we have a very robust oil spill response plan,” Slaiby said, adding that it had become even more robust since the Deepwater Horizon accident.

Pipeline problems Even assuming exploration and development success, Shell would be unlikely to be able to start production from the offshore Arctic before 2020. Alaska, meanwhile, is facing far more immediate problems with dwindling flows on the Trans Alaska Pipeline System (TAPS). Oil flowing through the 800-mile (1,287-km) pipeline has shrunk from a record 2 million barrels per day in 1998 to around 570,000 bpd as a result of declining onshore output. The decline has already caused problems for the pipeline, and there are concerns that it could become non-operational in the event of a further drop.

NORTH AMERICA





“Beaufort and Chukchi are critical to our long-term future,” TAPS operator Alyeska Pipeline Services’ president, Tom Barrett, was reported by Bloomberg as saying.

While oil from the Beaufort Sea may ultimately be able to bolster TAPS throughput, via existing pipelines running east from Prudhoe Bay to

Badami, the infrastructure does not yet exist to bring any oil discovered in the Chukchi Sea into TAPS.

Shell has said it intends to build a connector across the North Slope to bring Chukchi oil to the pipeline, which has been estimated to cost billions, but is likely to face fresh environmental opposition and, again, this does nothing

to relieve Alaska’s problems in the immediate term.

While it certainly looks as though offshore Arctic exploration is going to go ahead in Alaska, it will be some time before the benefits that Shell and its supporters have cited will be seen.

A great deal of uncertainty continues to surround Canada’s Arctic oil and gas resources. The vast potential of these is not in question but the costs and difficulties involved in extracting energy under harsh Arctic conditions – as well as the sheer distances involved in transporting resources to market – have driven companies to be cautious.

Canada is thought to have three key resource-rich areas in the Arctic – the Beaufort-Mackenzie Delta area, the Arctic Islands and Eastern Arctic offshore.

The Beaufort-Mackenzie Delta contains an estimated 8.2 billion barrels of oil and 60.5 trillion cubic feet (1.7 trillion cubic metres) of gas, the Arctic Islands are estimated to hold 3.9 billion barrels of oil and 58.3 tcf (1.65 tcm) of gas and the Eastern Arctic offshore hold an estimated 1.5 billion barrels of oil and 16.7 tcf (472.9 billion cubic metres) of gas.

Offshore issues Offshore resources, in particular, are proving controversial as Canada’s National Energy Board (NEB) prepares to issue a report in December detailing the findings of its year-long Arctic

Offshore Drilling Review. Two reports published by environmental groups in September suggested Canada was not ready to open up its Arctic waters to exploration drilling and called for a major overhaul of safety standards and regulations before work proceeds.

Oceans North Canada – part of the Pew Environmental Group – claimed in its report that there were major weaknesses in Canada’s licensing and regulatory system, including a lack of clarity on the safety standards required to prevent a large-scale environmental disaster in the event of an Arctic oil spill. Another report by the World Wildlife Fund (WWF) echoed these sentiments, arguing Canada was unprepared to manage a response to any potential offshore disaster, with Arctic conditions making any cleanup efforts extremely challenging.

The WWF has said the weather could keep cleanup crews from their work for an average of three to five days per week – a harsher assessment than an earlier report prepared for the NEB that suggested weather conditions in the Beaufort Sea would prevent any kind of oil spill response for one day out of five.

Canadian Prime Minister Stephen

Harper argued in 2010 that rules for drilling offshore northern Canada were so strict that exploration in the region did not pose a threat to the environment. Companies have also weighed in, claiming they could recover 90% of any oil spilled in Arctic waters. However, only 20% of the oil spilled during the Deepwater Horizon disaster in the Gulf of Mexico was recovered, despite the operating environment being far more benign. The incident highlighted the dangers of offshore drilling, has led to more caution and has driven technological advances in subsea containment.

Increasing activity in other northern areas – with drilling having already started offshore Greenland, and plans in place for drilling offshore Alaska and Russia to begin soon – points to a global trend that Canada cannot ignore.

Greater gas uncertainty Although opening up Canada’s Arctic continues to generate debate, there is certainly enough interest to suggest that it will happen. The same cannot be said of Canada’s northern gas resources.

NORTH AMERICA

Canada considers Arctic resources As Canada’s National Energy Board prepares to report the findings of its review of offshore Arctic drilling, a question mark hangs over work in the region By Anna Kachkova The National Energy Board’s report on its review of Arctic drilling is expected in December The future of the Mackenzie Gas Project remains uncertain owing primarily to low gas prices Energy firms are starting to explore northern Canada’s unconventional resources





The region is extremely rich in gas resources, with the NEB estimating that northern Canada contains 3.3 tcm of remaining marketable gas in total – 53% of which is located in the Mackenzie-Beaufort area and 34% in the Arctic Islands. Moving gas south from the Arctic Islands would be even more costly than transporting oil and this has deterred companies. Moreover, plummeting gas prices, brought about largely as a result of the growth in shale and tight gas production, have also contributed to making Arctic gas uneconomical.

The Mackenzie Gas Project was first outlined in the 1970s and was to carry 1.2 bcf (34 million cubic metres) per day of gas over 1,200 km from the Mackenzie-Beaufort region to Alberta. The plan was only approved by the NEB in March 2011.

By this point, the project was estimated to cost roughly C$16.2 billion (US$15.5 billion) and those participating had become increasingly unwilling to pursue such a project in light of easier and cheaper options elsewhere. Royal Dutch Shell, one of the major partners in the project, set out plans to sell off its assets in the Mackenzie Delta, including its 11.4% interest in the Mackenzie Valley Pipeline Consortium, although buyers appear thin on the ground.

Looking ahead Imperial Oil – which leads the Mackenzie Valley Pipeline Consortium – has put off a decision on whether or not to proceed with the pipeline until the end of 2013 and the project remains in doubt. However, recent projections released by the NEB suggest that gas prices in Canada are expected to strengthen enough to justify the transportation of Mackenzie Delta gas by 2020.

In a report, “Canada’s Energy Future: Energy Supply and Demand Projections to 2035,” the NEB outlined several scenarios, saying gas output in Canada fell 15% from 2008 to 2010, as the North American gas glut and consequent low

prices had driven down gas exploration. The report predicts output will

continue to decline until 2015 and then start to grow in 2016. Tight and shale gas are expected to drive production to a record 18 bcf (509.8 mcm) per day by 2035, with roughly 1 bcf (28.3 mcm) per day coming from Canada’s north. The reference case assumes that Mackenzie gas will start to flow in 2020, when the gas price is projected to be US$5.5 per million British thermal units (US$152 per 1,000 cubic metres).

The NEB warned that without Mackenzie gas, production would fall by 6% by 2035 and Canada would become a net importer of gas by 2028.

Northwest Territories’ recently elected premier, Bob McLeod, said in 2010 that, rather than being hampered by the growth of shale gas, the Mackenzie pipeline could actually benefit from it. McLeod suggested that the emergence of a stable, secure and plentiful gas supply could persuade electricity producers to switch from coal to gas-fired generation, thus creating additional demand and making Arctic gas desirable once more.

In addition, it has been predicted that increasing amounts of natural gas will be needed at Alberta’s oil sands projects, where output is projected by the NEB to triple by 2035. This substantial growth in gas demand could result in Alberta becoming the major market for Mackenzie gas, leaving less available for export out of Canada. Nonetheless,

supporters of the Mackenzie Gas Project consider the growing gas needs of the oil sands to be another reason to push ahead with the Mackenzie pipeline.

Even if Imperial decides to build the link, commercial operations are not expected to start until 2018.

Taking action Although companies are having to wait and

see how to proceed when it comes to Canada’s Arctic conventional oil and gas, some firms are taking action and exploring shale in the central Mackenzie Valley – with 11 blocks nominated and over US$500 million in work commitments in the area. The region is thought to have a large – as yet unquantified – potential for unconventional oil and gas from shale and hydrates. Exploration is focused around the Canol-Hare Indian and Bluefish shales. One of the firms which holds leases in the area, MGM Energy, has said that the shales are considered comparable to many of the other plays under development in North America.

Technological advances are allowing for the opportunity to extract oil from rock previously considered too tight by the industry. As a shale oil play is starting to emerge, firms such as MGM and Husky Energy are stepping up activity in the Northwest Territories amid speculation that northern Canada could yet prove to be a new oil frontier that is worth exploiting.

If the results are favourable, the region has the advantage of existing infrastructure in the form of Enbridge’s 40,000 bpd pipeline from Norman Wells to Alberta. But if companies are considering building new infrastructure, they face the same problems already being experienced by companies wanting to exploit conventional Arctic resources.

NORTH AMERICA

Arctic Special Report January 2012 Back Page

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HEADLINES FROM A SELECTION OF NEWSBASE MONITORS THIS WEEK

Oil and Gas Sector

AfrOil The Kenyan government is mapping out seven new blocks in the Indian Ocean.

AsianOil Senior Thai government officials have visited Myanmar to negotiate new gas concessions on behalf of PTTEP.

ChinaOil CNOOC is set to begin drilling its first well in Block F offshore Cambodia’s southern coast.

EurOil Statoil will spend a total of US$5.84 billion on developing the Luva field in the Norwegian Sea.

FSU OGM Poland has urged Russia to invest in its own shale gas deposits.

LatAmOil US officials are to inspect the Scarabeo 9 rig, which is on its way to drill for oil offshore Cuba.

MEOG Gulfsands Petroleum is continuing its Syrian exploration work despite a halt in production.

Unconventional OGM Marubeni Corp. is to buy a 35% stake in Eagle Ford shale acreage in the US from Hunt Oil in a US$1.3 billion deal.

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