EurOil 27th July 2010 - Toreador CEO on Hess JV in Paris Basin

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27 July 2010

Week 29

Issue 62

� News � Analysis

� Intelligence Published by

� NewsBase

COMMENTARY 2

� Circumspection required as Brussels

ponders spill response 2

� Toreador bullish about French shale oil 3

� NOCs: the new hybrid 6

PIPELINES & TRANSPORT 8

� Bulgaria reiterates Nabucco

commitment 8

INVESTMENT 8

� BP strikes wide-ranging asset deal with

Apache 8

� BG sells El Manzala stake to Dana

Petroleum 9

PERFORMANCE 9

� Tullow celebrates Owo strike 9

POLICY 10

� Trafigura fined in Probo Koala case 10

� Moratorium brings Caribbean limbo 11

PROJECTS & COMPANIES 11

� South Africa awards Karoo study

permit to international trio 11

� Out in the cold: BP to ship Hayward to

Siberia 12

� Eni eyes new Caspian projects 12

� BP divesting assets in Vietnam and

Pakistan 13

NEWS IN BRIEF 14

NEWS THIS WEEK…

Handle with care Conservative MEP for Scotland Struan Stevenson tells EurOil it would be wrong for the EU to act hastily in the wake of BP’s Gulf of Mexico oil spill.

� EU policymakers are considering closer regulation of deepwater drilling (Page 2)

� The UK would be the biggest loser if the oil industry were to be shut down indefinitely. (Page 3)

Feeling bullish France has given first-stage approval to a shale oil joint venture between Toreador Resources and Hess. EurOil spoke exclusively to Toreador’s CEO, Craig McKenzie, to find out more about the deal with Hess and the companies’ ambitions for the Paris Basin.

� Hess is to become co-holder of Toreador’s exploration permits in the Paris Basin. The US-based independent is to invest US$120 million in a two-phase work programme, for which Toreador is fully carried. (Page 3)

� The companies plan to spud their first well in the fourth quarter of 2010 and aim to drill almost continuously thereafter. (Page 3)

EurOil EUROPE OIL & GAS

MONITOR

EurOil 27 July 2010, Week 29 page 2




The Deepwater Horizon oil spill in the Gulf of Mexico has cost BP billions of US dollars and has effectively closed all fishing activity in the area for more than three months. Much of the local fishing industry along the south coast of the US remains closed, with oyster and crab fishermen in particular unsure of whether or not permanent damage has been done to their catchment areas.

BP has been shelling out millions of dollars in compensation to these fishermen and even to the owners of tourist boats, who have seen their business dwindle to nothing as the oil slick has swept ashore down hundreds of miles of coastline.

Policymakers in Brussels are now asking a critical question: If such a situation arose in the North Sea, what would be the outcome?

UK North Sea Most oil exploration and drilling in the EU is taking place in waters surrounding the UK. The potential impact on fisheries, and the environment in general, of a spill the size of BP’s in the Gulf of Mexico would be horrendous and could wipe out entire communities around Scotland’s northeast coast. The entire Scottish fishing industry could collapse.

Until now, few have considered the awesome prospect of an unregulated oil spill in the North Sea, and yet it is in these waters that hundreds of oil rigs operate and new exploratory wells are being sunk on a regular basis.

A recent discovery 110 miles (177 km)

southeast of Aberdeen, the four-field Catcher complex, is reckoned to be one of the biggest finds in the past 10 years, with an estimated 350 million barrels. So the doom and gloom mongers who predicted the imminent end of North Sea oil have been proved wrong. Oil production in the region, both in the UK and Norwegian Continental Shelves, looks set to continue for years to come. However, that in turn means the potential threat of a catastrophic spill will continue to exist, especially if exploration firms push out further into deepwater frontier areas.

The effect of the oil spill from the Macondo well in the Gulf of Mexico on marine life has remained largely hidden beneath the ocean’s surface, making it impossible to assess the full scope of its impact. But what the BP disaster does show is that despite the highest standards and availability of the best technologies, the risk of a catastrophic spill can never be fully prevented.

Reassurances sought With the Macondo well still causing problems, and PTT’s oil spill offshore

Australia still fresh in the mind, some industry watchers have opined that it is just a matter of time before another disaster occurs – and this time it could be in the North Sea.

Members of the European Parliament in Brussels are therefore now demanding assurances from the European Commission on the future of deepwater drilling in the North Sea.

The Commission has been urged to reveal what plans are in place to secure the safety and security of oil extraction operations, and to insist on the highest levels of environmental protection and disaster prevention in EU waters.

The Commission has already announced that it will conduct “stress tests” on existing EU legislation in this area, to enable it to identify any gaps and weaknesses in the regulatory framework at the EU level.

The oil spill in the Gulf of Mexico has, perhaps with some justification, created a feverish backlash in Brussels. It is appropriate that suitable and compulsory EU-wide insurance schemes are designed to compensate fishermen and other affected businesses in the event of a spill.

A step too far However, some MEPs want to go even further and are calling for a moratorium on all drilling until such time as guarantees on safety can be given. But that would be a step too far.

The oil industry cannot be closed down indefinitely.�

COMMENTARY

Circumspection required as

Brussels ponders spill response It would be wrong for the European Union to have a knee-jerk reaction to the fallout of BP’s Gulf of Mexico oil spill By Struan Stevenson � EU policymakers are considering closer regulation of deepwater drilling � The European Commission is to conduct “stress tests” on existing EU legislation on offshore drilling � Some legislators have called for a moratorium on al l drilling until safety guarantees can be given

What the BP disaster shows is that despite the highest standards and availability of the best

technologies, the risk of a spill can never be fully

prevented





The UK would be the biggest loser in Europe, with over GBP6 billion (US$9.16 billion) of investment and oil revenues at risk if such a ban were to be enforced. British and European technology leads the world in safety and security processes for the oil sector.

What sort of message would it send to international competitors if a drilling ban were to be implemented?

It is now essential that the Commission, the European Council and EU member states work with the oil industry and regulators towards securing

the highest safety and security standards uniformly across all EU oil platforms and drilling operations.

Struan Stevenson is a Conservative MEP for Scotland. He is Senior Vice President of the European Parliament’s Fisheries Committee.�

French approval of a shale oil joint venture in the Paris Basin highlights continental Europe’s desire to cash in on the unconventional revolution spreading beyond North America. The arrival of US integrated independent Hess into the acreage held by small-cap E&P company Toreador in the Paris Basin brings serious financial firepower to this liquids-focused venture.

The French Ministry of Ecology, Energy, Sustainable Development and the Sea granted first-stage approval to the transfer of 50% of Toreador’s working interests in its wholly owned and non-wholly owned exploration permits in the Paris Basin, in northern France, to Hess’s newly created French subsidiary, Toreador said on June 28.

The two companies signed a definitive agreement on May 10, under which Hess was to become co-holder of Toreador’s exploration permits in the Paris Basin. Hess is to invest US$120 million in a two-phase work programme, for which Toreador is fully carried.

Toreador Toreador opted to focus on its French portfolio in 2009, offloading its interests in other countries and staking its future

on the success of shale drilling near Paris.

Phase One of the JV will consist of evaluating the acreage and drilling six wells, with the first of these planned for late 2010. Depending on the results of the first six wells, a second phase is expected to consist of appraisal and development activities.

Toreador’s conventional assets are mainly concentrated in the Charmottes and Neocomian fields, which held proven reserves of 5.8 million barrels, mostly in developed permits, as at the end of 2009. Average conventional crude production in 2009 was 900 barrels per day.

However, unconventional resources are now the primary focus for the company and Toreador believes the Paris Basin could generate as much as 95 billion barrels of oil, with an estimated 65 billion barrels still remaining locked

in the shales where they were formed. EurOil spoke exclusively to

Toreador’s CEO, Craig McKenzie, to find out more about the deal with Hess and the companies’ ambitions for the Paris Basin. McKenzie began by saying the French government’s approval of the JV with Hess was a positive development.

“The French government approved the deal ahead of time and it has been very supportive of the deal in general. We met with the government authorities along with Hess and were encouraged by their reaction. The French government has shown appreciation for what we are trying to do with Hess and has been very supportive,” he said.

Timing With approval of Hess’s entry into the JV, the companies are now looking to expedite drilling work, with activity due to step up a gear in the final quarter of 2010.

“We are planning to spud our first well in the fourth quarter and we will drill almost continuously thereafter,” McKenzie said. “In terms of commercial production, it depends on how the drilling of these first wells goes.�

COMMENTARY

Toreador bullish about

French shale oil France’s approval of a shale oil joint venture in the Paris Basin indicates continental Europe’s growing appetite for unconventional resources By Ryan Stevenson � France has given first-stage approval to a shale oi l joint venture between Hess and Toreador Resources � Hess is to invest US$120 million in a two-phase work programme � The firms are now looking to expedite drilling work , with activity due to ramp up in Q4 2010

“Provisionally we will drill three wells … and put

them on production test, which could be as soon as

the first half of 2011”





We are drilling these wells for scientific purposes, to get new and modern data. All of the data we have been using is vintage, dating from the 1960s until the early 1990s.”

“We will get new cores and logs through these wells and then decide how we will proceed from there. Provisionally we will drill three wells as a batch and complete the three wells, which could include standard hydraulic fracture stimulation, and put them on production test, which could be as soon as the first half of 2011.”

Land ownership Issues of population density and land ownership are often flagged as potential obstacles to shale oil and gas development, particularly in Europe.

But McKenzie does not foresee any major problems in the Paris Basin. He said: “The land ownership situation in the US is much more complex because there you have landowners who are also mineral rights owners. In addition, there are various competing jurisdictions at local, state and federal levels as well as various environmental protection agencies.”

Toreador’s CEO believes the situation is much more benign in France, describing it as “much simpler.”

“In France, the French state has all the mineral rights, not the surface owner, so there are no negotiations going on with landowners with respect to royalties. The royalties are payable to the state and are set at the time of the award of the permit. So the only negotiations we have with surface owners is to arrange access to install a pad to drill our wells.”

McKenzie noted that there had already been over 2,000 exploratory wells drilled in the Paris Basin – which is also a major conventional oil play – and highlighted that it was rural land, which means the issue of population density does not hinder progress.

“The land is all rural and open farmland, so we don’t anticipate any problems at all from the surface owners and that has certainly been the case for the past 50 years in the Paris Basin,” he said.

Infrastructure With such benign surface conditions, is it actually easier to conduct drilling work in shale formations in the Paris Basin than it is in some shale plays in the US? McKenzie believes that is indeed the case.

“We think so because it’s not a hostile environment. We don’t have harsh winters to contend with like drillers do in

the Bakken shale in the US. We don’t have a choke in the infrastructure like in Montana and North Dakota because we have Total’s Grand Puits refinery right in the middle of the Paris Basin. It has about 70,000 barrels per day of extra processing capacity as we understand it [by displacing imported crude], and we truck our oil there already because we have production from our conventional fields in the basin.”

That Total has a refinery in the basin, and the fact it has spare crude processing capacity, is critical to the future success of the JV and was clearly a selling point for Hess.

Referring to the refinery, McKenzie said: “It is literally just down the road. We therefore have easy access to infrastructure for selling the oil. It is Brent-quality crude and we have a contract in place with Total for purchasing the oil.”

Environment Allied with good infrastructure, the Paris Basin also has favourable environmental conditions.

“Surface and water conditions are favourable,” McKenzie said. “The water is controlled by the French authorities – they have a ministry that controls all water production, distribution and usage. So we don’t anticipate any issues there because the Paris Basin has had up to 20 rigs drilling at any one time with all the resultant water consumption.”

Toreador’s CEO does not foresee any conflict with local farmers over water usage either. “The Paris Basin has a prolific aquifer and to my knowledge there have been no seasonal droughts for nearly 40 years.”

Hess The allure of the Paris Basin shale for Hess was strong given its similarities to the Bakken shale in the US, in which the company is a leading player, a fact highlighted by McKenzie. He said the mineralogy, petrophysics and geochemistry of both plays as well as their structural geology made the Bakken and the Paris Basin very similar.�

COMMENTARY





“Hess has been in the Bakken since 1979 … and we believe Hess will be one of the largest players there with the new programme it has announced. Hess plans to invest about US$1 billion per year over the next five years in the Bakken Shale in North Dakota, with goals of boosting production from 10,000 barrels of oil equivalent per day today to 80,000 boepd by 2015. The company shares our view that both the geology and the oil itself in the Paris Basin are very similar to the Bakken,” he said.

Services Thus with the joint venture approved and drilling set to get under way, is McKenzie confident that the service industry in continental Europe is well positioned to support a ramp-up in activity? The answer appears to be yes and no.

“During the first appraisal phase when we are drilling the proof of concept wells, the supply and contracting industry is sufficiently robust for everything we need. We can get rigs, we can get track equipment, we can certainly secure the appropriate logging and both the drilling and the well completion suppliers,” he said.

However, after the appraisal stage, sourcing equipment could become more problematic, at least initially. McKenzie continued: “If we get past the proof of concept stage into the development phase, where we are drilling a large number of wells, then that’s where we would need the service industry to ramp up.”

“The service industry is not sufficiently robust at this point. We are in close discussions with several contractors and they are waiting for a critical mass of demand before they ramp up. So I don’t anticipate any problems, but for them to ramp up right now would mean that they had idle equipment and people, which is obviously not good.”

Fracking Fracking has come under increased legislative scrutiny in the US recently, but McKenzie is confident his company has done enough to allay any fears the

French government might have about the process.

“We have been very open with the French authorities. We have shown them in some detail what it is exactly that we are trying to do with these wells, because obviously it has become controversial in some parts of the US, such as the Marcellus shale, because the shale is close to freshwater aquifers,” he said.

However, McKenzie believes the geology of the Paris Basin means similar problems will be avoided.

“The shale in the Marcellus play is shallower,” he stressed. “In the Paris Basin there are about 2,000 metres of separation between the shale and the freshwater strata. That is very significant, because obviously when you are fracking these zones in the first instance you have frack heights of say 50 metres and certainly not 2,000 metres. We have been and will continue to work very closely with the French government.”

That the French shale is deeper, though, does mean costs will be higher.

Another company, Canada’s Vermilion Energy Trust, has recently fracked a well near Toreador’s acreage, according to a Vermilion investor presentation and related webcast, a key development in the evolution of the Basin.

“So far Toreador has not fracked a well. But Vermilion Energy Trust did just frack a well in the Paris Basin shale and their permit is very close to Toreador’s. So while we are still planning to frack a well, Vermilion has actually gone out there and done one.”

“The company has not been forthcoming with details, but as we understand it, they fracked a vertical shale completion and the well has been in production since March. I think that is tremendous news for us, as it is an important proof point that the Paris Basin is receptive to fracking. Vermilion will come out with more details on that in its own time and we will be watching developments there closely,” he said.

Future developments With Vermilion already making headway, Toreador is optimistic about the future. So does the company intend to

sell off more of its interest in the Paris Basin or retain control and seek to develop its permits with Hess alone? For now, McKenzie is focused on the joint venture with Hess.

“Hess has committed US$120 million for the proof of concept phases. They have split the phase into two parts, for which they will put up US$50 million for the first stage and US$70 million for the second, and will carry us on both phases. It’s a significant commitment and it’s more robust than any other commitment you have seen elsewhere in Europe for this kind of development,” he said.

Looking to the future, McKenzie went on: “Toreador is fully capitalised for shale for years to come. We still have 500,000 net acres, which is a very sizeable acreage spread. We could sell further acreage and retain a very material acreage position ourselves, but we do not have any plans to do so. Right now we believe it is best to expedite drilling and get some results.”

The Toreador CEO concluded by saying: “We would like to keep our acreage position the way it is, since we are fully capitalised and at some point as we prove the concept further, then we might revisit this idea and sell down further, because we are a very ambitious company. We think we are in a great position right now with respect to our balance sheet and the cost structure and in term of being capitalised for the drilling programme with the Hess carry. Now all our focus is really on proving up the concept and thereafter we might consider new options.”

Vermilion’s recent success is encouraging for Toreador, which, as the leading permit holder in the central part of the Paris Basin, is well positioned to capitalise on its shale oil asset. McKenzie said Toreador was also continually examining further growth opportunities throughout France and in mainland Europe. The rest of Europe will in turn be taking note of the company’s progress in France and assessing how unconventional reserves might fit into the continent’s future energy mix.�

COMMENTARY





Traditional distinctions between national oil companies (NOCs) and international oil companies (IOCs) are blurring, with each side adopting tactics and techniques from the other.

The traditional conception of NOCs defines them as large-scale resource holders – such as Saudi Aramco – or regulators in the domestic market, securing energy supplies for the citizenry. However, this is changing and these definitions are becoming harder to make as NOCs compete with IOCs in areas such as financing, profit seeking, technology and investing.

The challenge The International Energy Agency (IEA) has predicted that, in order for the energy industry to meet demand and replace declining fields, four new Saudi Arabia’s must be brought onstream by 2030. NOCs own around 75% of the world’s resources and, the IEA has said, 80% of the needed production growth must come from these state companies.

In monetary terms, the Paris-based energy watchdog has said, the world must invest a total of around US$25 trillion by 2030, suggesting NOCs must stump up US$20 trillion over the next 20 years.

Conventional resources are, for the most part, out of reach of the IOCs, requiring NOCs to take on a substantial burden in meeting the challenge. The exception to this rule, the IEA’s chief economist, Fatih Birol, said is Iraq, which offers access to substantial

resources – although alongside its own set of challenges. IOCs have also reacted to this squeeze by changing their focus towards unconventional resources – such as shale and deepwater – as well as increasing their gas exposure.

In 2009, Birol said, spending was 19% below that invested in 2008, which was seen as insufficient. Questions, therefore, have arisen over the extent to which the NOCs and IOCs can meet the IEA’s suggested spending level.

Focus State-owned companies have a duty to the government and people of their country, while commercial entities have a duty to their shareholders. This can be manifested in a number of ways, with the similarity being the return of profits.

NOCs have duties beyond, solely, cash generation and can use this to their advantage. They often have a remit to provide employment, to ensure the stable supply of energy and to advance their government’s policies.

This can lead to the NOCs making counter-cyclical investment decisions,

seizing opportunities for perceived state benefit, rather than straightforward commercial gain.

For instance, Brazil’s Petrobras opted to explore for gas over the last two years, despite the fact that this feedstock could secure only low international prices and most companies have focused on oil exploration. The reason for this, an official involved in the work explained, was an attempt by the Brazilian government to reduce gas imports from Bolivia.

NOCs are often seen as risk-averse, though, preferring to buy up developed projects rather than carry out exploration. The same could, though, be said of the IOCs, which in recent years have shied away from the riskier extremes of the business, preferring instead to focus on acquisitions and stock buybacks.

Industry executives have noted the converging interests of NOCs and IOCs.

A BP official, Steve Westwell, speaking at a recent conference, acknowledged that while NOCs and IOCs had “different roots … the idea that their roles and priorities are vastly different no longer holds true in the 21st century.”

Chevron’s president of Africa and Latin America, Ali Moshiri, concurred, saying: “I don’t see much difference between IOCs and NOCs.”

IOCs have responded to the economic slowdown by selling off non-core assets in order to focus on managing capital more efficiently, this could well provide opportunities for NOCs.�

COMMENTARY

NOCs: the new hybrid The world’s future supplies of energy are reliant on NOCs, which are responding to the various challenges in a number of ways By Ed Reed � NOCs must invest a substantial amount to meet future world demand � While NOCs are becoming more commercial, they also ha ve the ability to invest counter-cyclically � The JNOC lesson serves as a reminder of the inefficie ncies of NOC investments � NOCs are improving their financing ability, although there are still gains to be made

A BP official, Steve Westwell, acknowledged

that while NOCs and IOCs had “different roots … the

idea that their roles and priorities are vastly

different no longer holds true in the 21st century”





Resource seekers Those NOCs with limited domestic options but cash resources – primarily Asian entities – have turned their attention to overseas opportunities, with mixed results.

Some have been extremely successful, for instance China’s NOCs have made substantial headway, paying out a lot of cash to secure foreign assets, often in Africa.

The notable failure, though, was the Japan National Oil Corporation (JNOC), which managed to waste a large amount of cash and make little headway in securing supplies. JNOC was scrapped in 2005 but its failure has contributed to a continued wariness on the part of Japan’s overseas ambitions.

The push to secure overseas resources came to a head as a result of the 1973 oil crisis, according to Korea National Oil Corporation’s (KNOC) executive vice president, Seong Hoon Kim. Speaking at a conference in London, the South Korean official explained that the crisis led to a situation where “the oil was not available to buy, even though we had the money.”

This failure of the market brought home to consumers – and governments – the perils of relying solely on the market and saw a drive to capture foreign production.

However, this pendulum has swung back the other way as NOCs grasp the impracticality of producing foreign oil and shipping it home.

Often, it is more efficient to sell it on the international market and use the cash to buy feedstock closer to one’s target market. The KNOC official put the return on producing assets at around 15%.

This is the key factor to bear in mind when considering the expansion of NOCs into foreign resources.

While this quest may have been born out of a desire to control the flow of oil from the well to the pump, it is simply not practical – cash is easier to move than energy.

Ecopetrol’s vice president of strategy and growth, Hernando Zerda Noriega, said the emphasis was to secure a profit from operations, which could then be used domestically. KNOC, similarly, sells its foreign production abroad, as do Chinese companies.

King cash NOCs have shown an increasing awareness of financial options, with a variety of techniques used, including partial listings, bridge loans and other facilities.

Russia’s Rosneft, for instance, carried out an initial public offering (IPO) in 2006, which raised around US$10 billion. It went on to sign bridge financing deals and agreed an oil-backed export facility with China.

Governments are keenly aware of the allure of paving the way for NOCs to tap equity markets but there are some concerns about how this would be executed and the extent to which financing would be available. In Nigeria, the government is working to incorporate the joint ventures between the Nigerian National Petroleum Corporation (NNPC) and the Western super-majors.

These joint ventures, which produce the majority of Nigeria’s crude, are under-funded because NNPC is unwilling or unable to meet its share of costs.

Incorporating the joint ventures, the theory goes, would allow them to raise capital. However, the validity of this assertion remains to be seen and the transformation is likely to be painful.

As a side note on the question of financing, one under-used technique that NOCs could do well to adopt is hedging

domestic production, one financier noted. The exception to this is Mexico’s

Pemex, which hedged its 2009 exports at US$70 per barrel, which reportedly led to the country making a profit of around US$5 billion.

Using hedges in this way is particularly useful for a NOC, a Pemex official said, because it provides for much greater certainty when setting government budgets, which require an oil benchmark figure.

To the future As time progresses, resource-seeking NOCs are likely to try to move from the acquisition model to the exploration model.

This will carry greater risk, though, and there are likely to be missteps – such as JNOC – which could hamper such ambitions.

IOCs, meanwhile, are likely to face greater social pressures to be “good citizens,” employing local workers and distributing benefits – in effect, moving towards the NOC model.

The BP executive, Westwell, acknowledged this shift, noting: “IOCs have recognised the importance of serving national interests in the places where they operate.”

IOCs have also benefited from their sheer scale in receiving political support, although clearly not to the same extent as NOCs.

To give one unfortunate example, the Macondo disaster in the US Gulf of Mexico has resulted in BP cancelling its dividend for three quarters. The UK-based super-major makes up a major part of London’s FTSE 100 index of leading shares, so the dividend cancellation has led to concerns surfacing over pension payments, translating into government-to-government talks on the subject.

Big business has a clear role to play in social affairs. This has been evident from the start for NOCs and is becoming increasingly clear for IOCs.�

COMMENTARY

Ecopetrol’s vice president of strategy and growth,

Hernando Zerda Noriega, said the emphasis was to

secure a profit from operations, which could

then be used domestically





A cross-border pipeline from Turkey to Bulgaria could become

the first section of Nabucco

Bulgaria’s Economy Minister Traicho Traikov reiterated his country’s commitment to the Nabucco natural gas pipeline at a meeting in Vienna last week.

Speaking to senior managers of OMV, the Austrian company that is leading the Nabucco project, and to Reinhard Mitschek, the CEO of Nabucco Gas Pipeline International (NGPI), Traikov said he hoped to see work on the pipeline move forward more quickly. To this end, he said, Sofia favours plans for the construction of a cross-border gas pipeline connecting Turkey and Bulgaria.

This pipeline could later serve as the first operational section of the Nabucco network, he said.

“The construction of the Bulgarian-Turkish pipeline will practically become the start of the Nabucco project, which is designed to provide Bulgaria and all of Europe with access to the gas resources of the Caspian region and the Middle East,” Sofia News Agency quoted him as

saying. No word was available as of press time

on how the OMV and NGPI managers responded to Traikov’s statements. The economy minister was speaking shortly after Sofia and Moscow agreed to establish a joint venture to build the Bulgarian section of South Stream, a Russian-backed gas link that is widely viewed as a rival to Nabucco, since it will serve many of the same markets.

The Nabucco line will follow a 3,300-km route from Erzurum, a city in eastern Turkey, to Baumgarten an der March, a gas hub in Austria. NGPI has said it hopes to begin construction work in 2011 and then launch the pipe in 2015 at an initial capacity of around 5-10 billion cubic metres per year. Throughput will eventually rise to a peak of 31 bcm per year.

The consortium’s six shareholders are Botas (Turkey), Bulgarian Energy Holding (BEH), Transgaz (Romania), MOL (Hungary), OMV and RWE (Germany). The partners expect to invest 7.9 billion euros (US$10.1 billion) in the pipeline, which will pump gas from the Caspian Sea basin and the Middle East to Central Europe.

Azerbaijan and Iraq are expected to provide the first volumes of gas for Nabucco. The NGPI consortium has said it hopes to secure throughput from several other countries, including Turkmenistan, Egypt and Syria.�

Apache Corporation has signed a US$7 billion deal to acquire assets from BP in North America and Egypt.

BP had announced plans to sell off US$10 billion worth of assets and this deal demonstrates the super-major, while having a tough time in the US, still has sufficient clout to raise cash at strong metrics. BP needs to come up with US$20 billion to cover an escrow account, set up to compensate for damages linked to the Macondo disaster

in the Gulf of Mexico. Apache said the deal would bring it

around 83,000 barrels of oil equivalent per day and 385 million barrels of proven reserves. Based on this figure, Apache has paid US$18.2 per barrel of proven reserves. The company’s second quarter production was 646,866 boepd, so this transaction provides an increase of around 13%.

In North America, Apache is to acquire assets in Texas’ and southeast New

Mexico’s Permian Basin and western Canadian upstream gas assets. The deal makes sound economic sense. BP has achieved a price widely seen as fair, while Apache has deepened its presence in areas it already has strong footholds.

BP’s chairman, Carl-Henric Svanberg, said the decision to sell these assets had been taken because they were “strategically more valuable to other parties than they are to BP.”�

PIPELINES & TRANSPORT

Bulgaria reiterates

Nabucco commitment

INVESTMENT

BP strikes wide-ranging

asset deal with Apache





The company’s CEO, Tony Hayward, said it had achieved “an excellent price” and that this demonstrated BP’s determination to “get maximum value for everything we sell.”

None of the sales will be conditional on the success of the other sales and they are expected to be completed in the third quarter of 2010, with an effective date of July 1. Apache is to provide a cash deposit of US$5 billion by July 30. Of this amount, US$3.25 billion will be for Canada and US$1.5 billion for the Permian assets.

The total price attached to the Permian Basin assets is US$3.1 billion, while the total for the Canadian gas assets is US$3.25 billion.

There is the possibility that some of these sales could be pre-empted by third parties, BP said.

Regulatory approval is required by certain dates for the sales. In the case of the Permian Basin, this is October 29, while the western Canadian assets are required by January 31. Should these not be given by these times, BP will be required to repay the relevant deposits.

Apache is to acquire 10 fields in the Texas-New Mexico transaction, with two BP-operated gas-processing plants. Net production is 15,100 barrels per day of liquids and 80 million cubic feet (2.27 million cubic metres) per day of gas. Net proven resources are 126 million boe with resources of 148 million boe.

Canadian gas Apache has also acquired around 214 million boe of net proven reserves and 1.37 billion boe of net resources, in Canada. Net production is 240 mmcf (6.8 mcm) per day and 6,500 bpd of liquids. The company has also acquired the proposed Mist Mountain coal-bed methane (CBM) project.

A note from Scotia Capital said that while the price paid was fair, it expected Apache to increase “value over time by using the same approach it has in the past to squeeze more out of assets that have been undercapitalised.”�

Dana Petroleum is to acquire a 50% stake in BG International’s El Manzala offshore concession, offshore Egypt, in the Mediterranean Sea.

Dana, in a statement on July 21, said it would cover the costs of the next exploration well, up to an agreed cap, in order to earn its 50% interest. The company said it believed the area was prospective in the Pliocene play and in the deep, high-pressure horizons. Dana has had some success in the Pliocene at its West El Burulus concession with the WEB-1 and Papyrus wells.

The El Manzala production-sharing contract (PSC) covers around 630 square km in the offshore Nile Delta area.

Dana said the BG deal would continue its programme of expanding its work in Egypt – and particularly the Nile Delta.

Dana’s CEO, Tom Cross, said the two companies were planning to drill a well in early 2011. “This further extends Dana's strategic position and growth opportunities across Egypt, where we are already 50:50 partners with Gaz de France in the western area of the Nile Delta, together having made two gas discoveries with our first two wells at WEB-1 and Papyrus. Dana is also 50:50 partners with Apache in the Western Desert, where the group has made, and successfully brought onstream, several oil discoveries.”

Apache recently struck a deal to extend its position in the Western Desert, buying assets from BP for US$650 million. (See: BP strikes wide-ranging asset deal with Apache, Page 8).

Cross went on to say Dana was in the process of drilling at Fin, near the company’s wholly owned Lorcan oil discovery, onshore in the Gulf of Suez. Dana is also drilling the Nefertiti prospect, in which it has a 65% stake, offshore the Gulf of Suez. Korea National Oil Corporation (KNOC) is in the first stages of making a bid for Dana, but there have been signs that the UK-listed company may want more cash than is acceptable to the Asian party.�

Tullow Oil has found a new oilfield in its Deepwater Tano block, offshore Ghana, as a result of the Owo-1 well.

The well, Tullow said on July 26,

encountered a “significant column of excellent quality oil.”

The Owo well, around 6 km west of the Tweneboa wells, found a gross

vertical reservoir interval of 154 metres, with 53 metres of net oil pay in two pay zones.�

INVESTMENT

BG sells El Manzala stake

to Dana Petroleum

PERFORMANCE

Tullow celebrates Owo strike





The company said the zones were part of the same accumulation and that the oil was between 33 and 36 degrees API.

The deviated well was drilled by the Sedco-702 semi-submersible, reaching a total depth of 3,891 metres, in water of 1,428 metres.

A note from RBS said the reservoir quality appeared to be very good at Owo – similar to Jubilee and better than Tweneboa.

Once logging has been completed, the well will be sidetracked by 600 metres to the east to give more detail on lateral reservoir distribution and to meet a deeper part of the Owo channel system. Results from the sidetrack should be ready in mid-August, RBS said.

Once the sidetrack has been finished, the Sedco-702 rig is to drill the Onyina-1 exploration well, targeting a large fan-channel

system between the Tweneboa and Jubilee fields.

Tullow’s exploration director, Angus McCoss, said: “Accelerated appraisal drilling will now focus on maturing the

resources in both Owo and the adjacent Tweneboa accumulation towards commercialisation.”

The Tweneboa-Owo-Ntomme was given a 1.4 billion barrel of oil equivalent

reserve figure and Tullow, in a presentation at the beginning of July, said the Owo-1 well would “make or break” this projection.

The RBS note went on to say the Owo field might be developed before Tweneboa, “given the apparently better reservoir characteristics and absence of gas.”

Tullow has a 49.95% stake in Deepwater Tano and is the operator. Kosmos Energy Ghana and Anadarko Petrolum both have 18% stakes in the block, Sabre Oil & Gas has 4.05% and Ghana National Petroleum Corporation (GNPC) has a 10% carry.�

Trafigura was fined 1 million euros (US$1.29 million) on July 23 by a Dutch court for illegally dumping toxic waste in Cote d’Ivoire.

The commodities trader acknowledged the Amsterdam ruling and said it was considering an appeal. The company said it was “pleased” to have been acquitted of forgery but said it was disappointed on the other two rulings, “which it believes to be incorrect.”

Trafigura also said the court had noted there was only “limited risk to human health from these slops.”

A Trafigura employee, Naeem Ahmed, was acquitted of one charge but convicted of a second. The company said the employee did nothing wrong and would provide him with legal assistance. He received a six-month suspended

sentence and a 25,000 euro (US$32,320) fine. The captain of the Probo Koala also received a suspended sentence.

Trafigura had acquired a cargo of coker petrol, which originated from Mexico’s Pemex. The trader carried out an onboard upgrading process – known as caustic washing – and sold the product for a profit. However, the process left behind an amount of sulphurous waste.

The company tried to offload it in Amsterdam but, owing to price concerns, was forced to rethink this plan.

Trafigura then struck a deal with an Ivorian company, Compagnie Tommy, to take the slops. The waste was dumped around Abidjan, at open-air sites. Consequently, a number of people complained of illness and 16 people died – linked by some observers to the

dumping. The trader has maintained, though, that

the slops were not toxic and did not cause the ill effects. However, it did pay out US$198 million in 2007 to the Ivorian government under a settlement deal.

A Greenpeace campaigner on toxic materials, Marietta Harjono, said this was “a first step towards justice and a clear signal to other companies that the illegal export of waste to Africa will not go unpunished.”

The Court of Appeal in The Hague is due to carry out a hearing on September 8 based on documents provided by Greenpeace. The NGO said a decision would be given in October at the earliest.�

PERFORMANCE

POLICY

Trafigura fined in Probo Koala case





The moratorium on drilling in the Gulf of Mexico may have brought it to a standstill. However, Statoil is planning to begin exploration in Cuban and Bahaman waters, less than 100 miles (161 km) from the coast of Florida.

In early July, the Norwegian company announced its plans to commit to a deepwater drilling project on the Cuban Continental Shelf (CCS) with Spain’s Repsol YPF. Last week, BPC Ltd, an Australian explorer, reported that it would form a joint venture with Statoil to launch the first major offshore exploration on the Bahaman Continental Shelf (BCS) since the mid-1980s.

Bahamas-based newspaper the Nassau Guardian reported that BPC had recently carried out seismic surveying of the prospect, which is located close to the beaches of eastern Florida. Under the terms of the Statoil-BPC contract, Statoil will operate the licences. However, as the accord is yet to be approved by the authorities, the Norwegian company is prevented from being involved in the seismic programme.

In a 2009 statement, BPC said that a competent person’s report published Moyes & Co. in 2008 indicated: “there could be multiple 500 [million barrels

of oil equivalent] oilfields in 18 leads recognised in BPC’s southern Bahamas licensed area.” The company also noted that a US Geological Survey of the offshore Cuba Basin estimated “a potential of 7-14 billion barrels [of] oil and gas equivalent of undiscovered resources.”

Ron Harper, IHS Global Insight’s area co-ordinator for the Caribbean, Central America and Ecuador, told Forbes that Repsol YPF drilled the Yamagua well, Cuba’s first in deepwater, in 2004, soon after it had been discovered, and despite “encouraging” results, Repsol had only found non-commercial hydrocarbons.

The Spanish company, holding a 40% stake in the six-block offshore consortium, acts as the operator, while Statoil and ONGC Videsh Ltd. (OVL) of India each own stakes of 30%.

Cuba has a total of 59 offshore blocks. Should the drilling go ahead as

planned, there is sure to be widespread disgruntlement in the US, as drilling in these waters poses very much the same threat to the country’s marine ecosystem as drilling in its own waters.

Amid concerns that Cuba lacks the technical know-how to deal with an emergency clean-up, a government-approved trip in August will see discussions between officials of the International Association of Drilling Contractors (IADC) and Cuban authorities regarding safety and environmental issues.

Opening the door Speculation is growing surrounding possible changes soon being made to the US economic embargo on Cuba.

The House Agriculture Committee passed a bill which relaxed the trade and travel embargo, which suggests that despite strong opposition, the US may be taking tentative steps towards a new relationship with Castro’s Communist regime.

It may come as little surprise, however, that these steps are happening at a time when Cuba has begun exploring the estimated 20 billion barrels of oil reserves lurking beneath its continental waters.�

South Africa has awarded a technical co-operation permit (TCP) to Sasol Petroleum International (SPI), Statoil and Chesapeake Energy on an area primarily

in the Free State, extending into the Eastern Cape and KwaZulu-Natal.

The TCP covers 88,000 square km, Sasol said on July 19, and gives the three

partners the right to study the Karoo Basin for shale gas for 12 months. However, the permit does not authorise “any surface activity or drilling.”�

POLICY

Moratorium brings Caribbean limbo

PROJECTS & COMPANIES

South Africa awards Karoo study

permit to international trio





The partners intend to examine existing, available data in their hunt for shale gas. In addition, they will sample cores drilled by Soekor in the 1970s and 1980s, which were seeking shale oil. Sasol said the same shale formations were now being assessed for their gas potential.

Depending on the results from this 12-month study, the trio would consider “committing to a more extensive exploration programme in the Karoo Basin.” The South African company said the Karoo Basin had unproven shale gas potential and that a “significant exploration” effort would be required to

assess the potential resource. SPI’s managing director, Ebbie Haan,

said the discovery of “large recoverable shale gas reserves in the Karoo Basin will be a game-changer in the broader South African energy market context and will likely constitute a major step to further develop gas transmission and distribution infrastructure in the country.”

The discovery of shale gas in the area could also help South Africa tackle its “power and fuels shortage.” The country is short of power plant capacity, which led to blackouts in 2008, and Eskom has a large-scale plan to invest in additional

generation. South Africa is mainly reliant on coal-fired power plants but cleaner-burning gas holds obvious advantages. In addition to its power needs, South Africa is a proponent of the production of liquid fuels from gas.

Shale gas has come to prominence after its revolutionary impact in North America. Statoil and Chesapeake are working together in the northeast US to develop the Marcellus shale. Exploiting shale gas is a technically demanding process, requiring the large-scale provision of services, which may prove difficult to roll out in South Africa.�

The embattled CEO of BP, Tony Hayward, has this week tendered his resignation in light of the Macondo spill in the Gulf of Mexico.

In his statement of resignation, the CEO said: “With the leak now capped, we have reached a significant milestone. This provides a firm basis to reshape the company.” Hayward thanked those who had helped BP in its response to the disaster and said that it should “embark on its next phase under new leadership.”

Having served the company since 1982, leading it as CEO since 2007, Hayward does not look likely to be cast aside by BP, with reports suggesting that the super-major will nominate him for a non-executive directorship of its Russian joint venture, TNK-BP.

News of this could lead to disgruntled feeling among the thirstiest for

Hayward’s blood after the calming affect of his resignation. The CEO’s departure will see him pick up a package worth GBP11 million (US$17 million), including a GBP1 million (US$1.55 million) payoff and a pension of around GBP600,000 (US$930,000) per year, which will begin when he turns 55 in 2012. On top of this, the UK’s Guardian newspaper reported that his role as an NED in Russia would pay him an additional GBP35,000 (US$54,000) per year.

There had been speculation that the departure of Hayward – dubbed “public enemy number one” – would see the Briton given a more sizeable golden parachute. However, in the US, public, environmental and, in some spheres, political indignation regarding the payout will no doubt be feverish in any case.

Replacement Hayward will be replaced as BP’s CEO on October 1, by Bob Dudley, the man brought in to head up day-to-day cleanup operations in the GOM. Dudley, an American, was the CEO of TNK-BP before a dispute over control of the company led to him being forced to leave Russia.

Fears had emerged that Dudley’s appointment would alienate BP’s Russian interests. However, Hayward’s past experiences of dealing with Moscow could prove beneficial.

While Hayward’s resignation was expected to help the company garner some positive public opinion, his likely appointment at TNK-BP could cast yet more cloud over the company’s brand.�

Eni has expressed interest in several new Caspian projects. The Italian firm is already a shareholder in Kashagan, Kazakhstan’s largest offshore oilfield, but it is now considering investments in

Azerbaijan and Turkmenistan. According to a company statement,

Eni is looking to play a key role in efforts to move Turkmenistani gas across the Caspian Sea.

It is also mulling plans for the development of Ashrafi and Dan Ulduzu, two offshore fields in Azerbaijan’s section of the Caspian, the statement said.�


Out in the cold: BP to

ship Hayward to Siberia

Eni eyes new Caspian projects





Eni said that its CEO, Paolo Scaroni, had met with Azerbaijan’s Energy and Industry Minister Natik Aliyev in Baku on July 20 to discuss the projects.

Azer Masimli, a spokesman for the minister, confirmed that the meeting had taken place, the Trend news agency reported.

Turkmenistan CNG exports In its statement, Eni said that Scaroni and Aliyev had discussed plans for transporting gas along a 300-km route from Turkmenistan to Azerbaijan in the form of compressed natural gas (CNG). The CNG could be transported by tanker to a regasification terminal near Baku and then loaded into the existing South Caucasus Pipeline (SCP) for delivery to Turkey, it said.

The statement did not give many details about the project. However, Scaroni told the Wall Street Journal in a telephone interview that the project would allow Turkmenistan to export 2-3 billion cubic metres per year of gas. Most of the volumes moved along this route would go to Turkey, he added.

“The gas would use [the] existing [SCP] pipeline, and [the project] won't be ready before 2012,” he told the

newspaper. He went on to say that some of the

volumes exported along this route would be associated gas from offshore Turkmenistani oilfields that might otherwise be flared.

The Eni chief also stated that his company would provide some natural gas for the CNG project. However, he did not identify the exact source of these volumes. (The Italian company has been producing oil in Turkmenistan since 2008 but is not a major player in that country’s gas sector.)

Ashrafi/Dan Ulduzu Both the Eni statement and Masimli noted that Scaroni had also discussed the Ashrafi-Dan Ulduzu project while in Baku but did not provide further details. Scaroni told the Wall Street Journal, though, that Eni was willing to replace any investors that wanted to exit the fields.

He stressed, nevertheless, that talks were still in the early stages and that no investment decision would be made in the near future.

Ashrafi and Dan Ulduzu were awarded to the North Absheron Operating Company (NAOC), a consortium led by the US oil company Amoco, which is now part of BP, in 1996.

NAOC decided in 1999 to halt work on its US$2 billion project, citing disappointing results from its three test wells. The wells showed that the field held some gas as well as 20-40 million tonnes of crude oil. However, Amoco and its partners determined that the project was not commercially viable.

Since then, SOCAR has said it plans to develop the fields on its own. However, it has yet to move forward with work there.�

BP has unveiled plans to sell its assets in Pakistan and Vietnam and the governments of both countries have been notified.

The asset sale is a part of a wider campaign by the company to raise cash for the clean up of the US Gulf of Mexico following the Deepwater Horizon disaster. Altogether, the assets in Pakistan and Vietnam are estimated to be worth US$1.7 billion.

BP’s upstream portfolio in Pakistan includes two producing onshore blocks, Mirpurkhas and Khiproin, in the Sindh province. The company had added

adjacent exploration interests to these blocks as recently as 2009.

BP also holds 34,000 square km of prospective deepwater acreage. In an interview with Dow Jones, Naeem Malik, head of the Directorate-General of Petroleum Concessions, hinted at the possibility of a bid for these assets by the Pakistani government through its state-owned companies.

Vietnam In Vietnam, BP has been an important player in the Nam Con Son integrated gas project, which consists of offshore

gas fields in Block 6.1, a pipeline and power plant facilities. BP has a 35% operator stake in the gas fields (other partners include Petrovietnam and India’s ONGC), plus 32.67% and 33% stakes in the pipelines and power plant respectively.

Concerning the asset sale, the deputy Vietnamese Trade Minister Do Huu Hao insisted that priority be given to existing partners. ONGC has strongly expressed interest in buying out BP’s stakes in the project and talks are reportedly under way. ONGC currently owns a 45% stake in Block 6.1.�


BP divesting assets in

Vietnam, Pakistan





The sale of BP’s stakes in Nam Con Son would mark the end of the company’s operations in the country, which began in 1989, and would be in line with a strategic decision in 2009 to withdraw from two exploration blocks,

Hai Thach and Moc Tinh, attributed in part to ongoing maritime disputes between China and Vietnam.

An exit from Vietnam and Pakistan would streamline BP’s portfolio and operations in Asia, further concentrating

BP’s upstream activities in the core strategic areas of Indonesia, China and Australia, where it has material gas positions.�

OIL

Sterling to commence drilling at Blakeney first exploration well

Sterling Resources has said that the Ocean Nomad rig is under contract and will begin the drilling at the Blakeney first exploration well located in Block 21/27b of the Central North Sea within the next few days. Sterling holds a working interest of 25% in this well that is operated by Wintershall (75%) and is targeting the Upper Tay sandstone formation at an estimated target depth of 3,260 feet. The Blakeney prospect is approximately 10km southwest of the company’s Sheryl discovery in Block 21/23a in which Sterling holds a 35% working interest. The JW McLean rig is expected to arrive at the Cladhan field drilling location soon to perform a side track of the discovery well. Delineation of the field begins with side tracking to an up dip location in Upper Jurassic channel sands. With success at the first location, the company said that it is planning a further sidetrack well targeting a down dip location to prove a deeper oil column in the structure. Sterling currently holds a 39.9% interest in the Cladhan field and is operator in partnership with Wintershall (33.5%), Encore (16.6%) and Dyas (10%). Drilling continues at the Macanta prospect in Block 42/14, a satellite location approximately 13km east of the main Breagh field and planned platform location

ENERGY BUSINESS REVIEW, July 23, 2010

Petrol signs storage capacity contract in Croatia

Slovenia’s Petrol Group signed a contract on the long-term lease for storage of oil products in the Croatian port of Ploce, to secure long-term supply for its units in Bosnia-Herzegovina, Montenegro and parts of Serbia, the Ljubljana-based company said Wednesday. The storage units will be built in the next two years, it said.

ENERGY TODAY, July 22, 2010

Drilling operations start on Anne Marie prospect

Faroe Petroleum has reported the commencement of drilling operations on the Anne Marie prospect offshore the Faroe Islands. The commitment well 6004/8a-1 is located in 1,106 metres of water depth, 190 km South East of Torshavn, targeting potentially oil bearing sandstone of Eocene and Palaeocene age in a structural trap. The well is being drilled by the Norwegian semi-submersible rig Seadrill West Phoenix, which is expected to remain in operation for about 75 days. Faroe holds a 12.5% participating interest in the Anne Marie prospect, while Eni Denmark, Dana Petroleum, OMV and CIECO hold 30%, 25%, 20% and 12.5% interest in the prospect respectively. Graham Stewart, CEO of Faroe, said: “This is the first of three 2010 exploration wells to be drilled in the deep water Atlantic margin, all of which are targeting substantial oil prospects. The second and third wells, operated by BP and Chevron respectively, will be in UK waters,

targeting the North Uist/Cardhu and Lagavulin prospects.”


HSBC, Total form oil, energy trading alliance

HSBC Holdings and Total formed an alliance to offer energy derivatives to the bank’s clients, boosting trading flows and market share for Europe’s largest oil refiner. The venture by Europe’s biggest bank by market value is in contrast to some of its competitors who enter the energy business by setting up crude and oil-product trading teams. Paris-based Total said the partnership could help develop its business in areas such as Asia and Latin America. “The alliance will increase our trading flows,” Pierre Barbe, President, Trading and Shipping said by phone from Geneva. “We will be dealing through the bank with people who are not necessarily our clients today.” Banks such as Goldman Sachs Group, Citigroup, Morgan Stanley, and Societe Generale are hiring energy traders amid rising demand in emerging nations for coal, oil and natural gas. JPMorgan acquired a Bear Stearns & Co. energy unit in 2008 and RBS Sempra Commodities this year. “This would seem to be a natural extension to HSBC’s fixed income and commodities business,” said Mike Trippitt, a London- based analyst at Oriel Securities. HSBC will benefit from Total’s experience in managing exposure to energy by combining physical infrastructure and risk management capabilities, the London-based bank said in a statement.�


NEWS IN BRIEF





HSBC will retain the relationship with its clients and the associated counterpart risks. Total, Europe’s second-largest oil company by market value, will continue to focus on crude and oil products trading, Barbe said. Crude accounts for about 80% of its physical volumes, with the remainder in oil products, Barbe said. Total is one of the biggest sellers of oil from North Sea, owning fields which supply crude grades including benchmark Forties. The company also owns and operates fields in the Gulf of Mexico, Nigeria and Angola.

BLOOMBERG, July 23, 2010

Lundin spuds Avaldsnes exploration well

Lundin Petroleum announces that drilling of exploration well 16/2-6 on the Avaldsnes prospect has commenced. The well is located in Block 16/2, production licence PL501, in the central North Sea sector of the Norwegian Continental Shelf (NCS). The Avaldsnes prospect is located approximately 25 km east of the Lundin Petroleum operated Luno discovery, on the opposite side of the Utsira structural high. The target is a Lower Cretaceous/Jurassic age sandstone sequence, analogous to the Luno reservoir, within a combined stratigraphic/four-way dip closure. The gross unrisked prospective resource of the primary Avaldsnes target is estimated by the operator at approximately 130 million barrels of oil equivalent. Lundin Petroleum is using the semi submersible drilling rig Transocean Winner to drill the prospect. Drilling is expected to take approximately 38 days, excluding testing. Lundin Norway is the operator with 40% interest. Partners are Statoil Petroleum with 40% interest and Maersk Oil Norway with 20% interest.

OIL VOICE, July 21, 2010

Wintershall to announce development plans

After declaring the Maria oil discovery in the Halten Terrace area offshore Norway

estimated to contain between 60 and 120 million boe and the Catcher discovery in the UK sector – said to be the largest UK find for years with around 300 million boe – Wintershall says it will discuss its future E&P plans at the Offshore Northern Seas conference in Stavanger in August. ONS takes place from August 26. Martin Bachmann, Wintershall’s executive director for E&P said: “The Maria discovery is another important milestone for Wintershall and it adds a further piece of growth potential to our portfolio on the Norwegian Continental Shelf.”

WINTERSHALL, July 23, 2010

Faroe boosted by Maria

Faroe Petroleum’s shares rose sharply on the London Stock Exchange last week after the company confirmed the Maria oil discovery in the Norwegian Sea operated by Wintershall. Faroe Petroleum has the largest equity stake in the find with 30%, and the company pointed out Maria is its second offshore Norway so far this year after the Fogelberg discovery in April, also in the Halten Terrace. With a strong hint that Maria could be easily developed, Faroe Petroleum pointed out that the new find lies near the Smørbukk Sør discovery which is just 3km to the northwest, and near the Trestakk oil find which is just 5km to the south, while the Tyrihans gas field is 6km to the southeast. Trestakk, in PL091 – estimated by the Norwegian Petroleum Directorate to contain in the region of 48 million bbl of oil – has been suggested as a possible tieback to either Åsgard or Kristin, or as a stand-alone development. “Initial analysis indicates that the Maria oil has properties similar to the oil in the nearby Trestakk discovery, at around 40 degrees API,” Faroe said in its discovery announcement.

FAROE, July 23, 2010

Auk and Burghley progress

Operator Talisman Energy says it has

made advances in the development of its UK North Sea Auk and Burghley projects in the second quarter this year. During the three months to June, Talisman said it had spent C$133 million (US US$129 m) on its UK developments, which was aimed at Auk North and South, and the Burghley subsea tieback projects. Auk North - which involves drilling and completing two new wells - is on schedule to produce first oil next year, and Auk South is “steadily progressing,” Talisman stated, after offshore construction contracts were awarded in the second quarter and first oil from that development is due in 2012. “Work on the Burghley development is proceeding with umbilicals and pipelines laid during the quarter and first oil planned for the fourth quarter of 2010,” said the operator. At Auk, Talisman plans upgrades to the platform rig and accommodation as part of a field life extension project involving up to nine new wells for the Northern North Sea Auk field.

TALISMAN, July 27, 2010

Hurricane nears end of testing

Hurricane Exploration has said that it is close to completing its sidetrack operation on the Lancaster discovery well, Block 205/21a, West of Shetlands. The objective of the operation was to establish the potential for commercial hydrocarbon flow. The primary reservoir target comprised two seismic scale faults separated by a volume of fractured reservoir. Reservoir evaluation to date has included two phases of drill stem testing (DST) and production logging (PLT). A summary of the test results showed a stabilised flow rate of 2,350 barrels of oil per day on a fixed 48/64’ choke. PLT data indicates that virtually the entire logged section contributed to flow and that specific fractures dominate production rates. There was no evidence of depletion throughout the test. Reservoir fluid samples have been collected for further analysis and an extensive wireline logging suite is in the process of being completed.�

NEWS IN BRIEF





Current operations are expected to continue into early August and the well will be suspended for use in future operations.

HURRICANE, July 26, 2010

Norway updates well data

At the end of the first half of 2010 (as of 24 June) 25 exploration wells on the Norwegian shelf had been completed. During the same period last year, 33 exploration wells were drilled. 19 of the 25 are wildcat wells (new prospects) and six are appraisal wells (for delineation of earlier discoveries). Nine discoveries were made during the first half of 2010 - five in the North Sea and four in the Norwegian Sea. Four of the discoveries in the North Sea were made north of the Snorre field in the northern part of the North Sea, while one discovery was made at the Frigg field in the central part of the North Sea.

NPD, July 26, 2010

GAS

Galp, REN plan 4 underground Portuguese gas storage facilities

Portuguese oil company Galp Energia SGPS and Portuguese utility Redes Energeticas Nacionais SGPS Wednesday signed a memorandum of understanding to build up to four underground gas storage facilities, Galp said in a statement. The facilities will increase Portugal’s natural gas storage capacity, which stands at 215 million cubic meters.

DOW JONES, July 21, 2010

Lithuania to build floating gas terminal

The Lithuanian government has approved the construction of a floating gas terminal aimed at helping cut the country’s dependence on Russia for its energy needs. The new liquid gas terminal, which will be built in the Baltic Sea, is expected to help the country

maintain its energy independence. “Our main task is to create alternative and independent sources of natural gas supplies,” Prime Minister Andrius Kubilius told reporters after the decision. Last month Lithuania saw its gas supplies drop by 30% following a payment dispute between Russia and Belarus, which acts as a transit country for gas headed into Lithuania. The exact location of the plant, which will have an annual capacity of 3 billion cubic meters – equal to Lithuania’s demand – has yet to be determined, but a final decision is expected this fall. It is expected to cost about US$370 million. Kubilius stressed the decision to build a liquefied gas plant was also rooted in economics since Lithuania currently pays some US$100 more per 1,000 cubic meters of natural gas than other European Union countries.

THE BALTIC TIMES, July 23, 2010

Total, Novatek may lose Russian gas venture license

Total and Russian partner OAO Novatek may lose a license to develop an Arctic natural gas field in a venture agreed on last year that was green-lighted by Prime Minister Vladimir Putin. The Natural Resources Ministry’s environmental watchdog put a permit for the Terneftegaz venture on a list for possible early termination, according to its website. The Moscow-based regulator, Rosprirodnadzor, didn’t cite a reason. The watchdog will consider the issue at a commission to be held “no earlier than next week,” said a spokeswoman, who declined to be identified because of agency policy. Novatek, Russia’s second-biggest gas company after export monopoly OAO Gazprom, and Total last year formed the venture to develop the Termokarstovoye gas condensate field in the Yamal- Nenets region. Total owns 49% of Terneftegaz, which holds the rights for Termokarstovoye until 2021. Putin last month promised Total Chief Executive Officer Christophe de Margerie “good administrative support” in Russia. Royal Dutch Shell in 2007 was

forced to cede control in a venture in Russia to Gazprom after government pressure over costs and environmental issues. The regulator’s decision was “a total surprise” and “unjustified,” Novatek said in an e-mail. “There was a detailed response provided for all complaints made as part of a documental inspection of Terneftegaz. If they made such a decision the only explanation can be that, for unknown reasons, no one read our response.” Phenelope Semavoine, a Total spokeswoman, declined to comment. The partners plan to complete exploration and make a final investment decision at the end of 2011, according to Novatek. Total in 2005 sought to buy 25% in Novatek in a deal that lapsed after the Russian gas producer decided to sell shares to the public abroad.

BLOOMBERG, July 27, 2010

Pas de Calais permit won

European Gas Limited (EGL) said that the French Government has formally granted its wholly-owned subsidiary Gazonor a new exploration permit ‘Sud Midi’ (located in the Nord Pas de Calais region). The ‘Sud Midi’ permit increases EGL’s portfolio and confirms its position among the largest CBM and unconventional gas permit holders in Western Europe. EGL has a 100% working interest, the firm said. This exploration permit is adjacent to EGL’s Gazonor concession, and, together with the Valenciennois exploration permit, forms a contiguous permit area of 1,352 km2. The permit area covers 929 square km and is located in the Nord Pas de Calais region (North of France). The permit is granted for a five year term until July 23rd 2015 with a total expenditure commitment of 1.9 million euros.

EGL, July 26, 2010

Castello reserves confirmed smaller

Po Valley has completed additional pressure testing to analyse the results and define additional development options for the Castello field in Italy.�

NEWS IN BRIEF





Production from the existing perforated level in Vitalba-1dir will be limited to 3,000-5,000 cubic metres per day and remaining reserves are small at 3.2 million cubic metres (0.1bcf). Probable reserves of 100.7 million cubic metres (3.6 bcf) remain in the updip (or attic) position of the Agnadello-1 well. Recovery of these reserves will require identification and successful drilling of a new Vitalba-1dirA well. 2P reserves from the field are now estimated at 103.9 million cubic metres (3.66 bcf), down 42% from the previously estimated reserves of 178 million cubic metres (6.3 bcf).

PO VALLEY, July 26, 2010

Dutch gas well shows promise

Cirrus announced that the deviated M07-07 appraisal well has been successfully drilled from the M07-A production platform to a total measured depth of 4,125 metres (true vertical depth 2,931 metres sub-sea). The well was spudded on June 8, 2010 by the Noble Lynda Bossler jackup drilling rig and reached total depth on July 21, 2010 on schedule and budget. As forecast, the well encountered thickened Jurassic sandstones in a down dip location from their prior penetration in well M07-05ST drilled in 1996. Gas shows were encountered during coring and subsequent log interpretation indicates the reservoir target appears to be gas bearing. Partners in the well are the Dutch state participant, EBN B.V. (50%), TAQA Offshore B.V. (5%) and Energy06 Investments (2.25%).

CIRRUS, July 23, 2010

SERVICES

Petromanas commences seismic programmes in Albania

Petromanas Energy has commenced the seismic operations on Blocks D-E and Blocks 2-3 in Albania, which is

anticipated to be completed by October 2010. The company said that all operating licenses and permits have been received. This programme includes 250km of 2D seismic survey including 105km which is part of the licenses required work commitments. Manas Adriatic, a wholly owned subsidiary of Petromanas Energy, had signed two agreements for land seismic services with the Italian company Geotec on May 27, 2010, one each for Blocks D-E and Blocks 2-3 which are onshore Production Sharing Contracts in Albania. The majority of the seismic work will be carried out with heliportable rigs and the remainder through conventional shallow drilling rigs. The company said that this seismic survey is being carried out to improve the quality of the existing prospect data, and hence increase the chances of success of the exploratory wells to be drilled upon completion and interpretation of the new seismic data. The first well is anticipated to be drilled in early 2011.


Whale and Dolphin Conservation Society condemns approval of seismic surveys in Moray Firth

As the US starts to count the massive conservation costs of the BP oil slick disaster, agreement by the UK government to allow two companies to begin seismic surveys in preparation for future oil and gas development in the Moray Firth, Scotland has been condemned by WDCS as being a decision based on heavily flawed environmental assessments, and one that fails to take into consideration the negative long term behavioural impacts on the dolphin population that resides in what is supposed to be a Special Area of Conservation (SAC). The seismic surveys, which will create high levels of noise under the water for a number of weeks, have been approved pending a four week restricted consultation period,

and look set to begin on 1st September. One of the areas outlined encroaches within the boundary of the Special Area of Conservation, which was set up under European legislation to offer protection to what is one of just two resident, and internationally important populations of bottlenose dolphins in the UK. “We are very disappointed by the decision to give the go-ahead for the seismic surveying in the protected area as it sets a very bad precedent and potentially has very serious implications for this special dolphin population in the Moray Firth”, says Sarah Dolman, WDCS head of policy in Scotland. “Seismic surveys cause high levels of noise under the water which can disrupt the dolphins who use sonar to find food and communicate with each other, but the government also has a responsibility to consider the unknown, but longer term behavioural impacts on this small population, which already faces the ongoing and cumulative effects of other threats such as; multiple harbour developments, increasing vessel traffic and noise from future pile driving for hundreds of wind turbines and oil and gas development.

OIL VOICE, July 26, 2010

Technip revenue falls

French contract giant Technip took in €1.485 billion in revenue for the second quarter this year – down 14.3% from last year – but with more than half of the revenue derived from subsea operations. Technip saw €688m of its income come from subsea operations in the second quarter while net income hit 106.1 million euros – down 8.7% from 116.21 million euros achieved in the second quarter of 2009. The company has an order backlog of 8.263 billion euros following a further 1.521 billion euros order intake in the period. “During the second quarter we made good progress on key projects in Subsea, and despite lower activity in the North Sea and Asia, we accordingly delivered a solid operating margin above our expectations at 16.9%,” declared chairman and chief executive Thierry Pilenko.�

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“In Onshore/Offshore the underlying profitability of our newer book of business combined with the completion of key projects drove a satisfactory operating margin of 7.1%.”

TECHNIP, July 22, 2010

Shipping costs fall due to over-supply

Marine heavy transport group Fairstar has suggested the market will remain tough for the foreseeable future because too many vessels are chasing too few jobs. “ The current spot market for low-value, large, heavy cargoes such as jack-up rigs, dredgers and equipment barges, shows no signs of recovery,” the company said. “There continues to be significant excess capacity of the ships competing most aggressively for this segment,” Fairstar reported. Charter rates have fallen below US$40,000 a day, Fairstar said, and the company has signalled its intention to focus on multi-voyage, high value work for complex energy-related projects.Fairstar reported revenue at US$15.9 million for the first six months this year, down from US$16.99 million a year ago, and a net loss of US$465,000, compared with US$7.43 million profit last year. The company said the losses were due in part to a US$2.6 million special charge related to foreign currency changes, and refinancing for a NKr 124 million ($19.8 m) bond which was repaid earlier in the year.

FAIRSTAR, July 23, 2010

Tube clogging solution

A subsidiary of British-based Wood Group in Houston has launched a new tool designed to defeat the formation of gas hydrates in pipelines. Wood Group says the new tool will help to melt ice and paraffin blockages in oil and gas production pipelines. Called a Thermal Moderator Tool – or TMT – and developed by Wood Group Logging Services, the new hardware is rated for use in environments up to 15,000 psi of pressure and it is capable of deployment in pipeline diameters down to one inch.

The TMT has been designed to be portable, and can be used in coiled tubing, flowlines and other small-channel systems. It performed well in several test wells and is being used successfully in commercial operations, saving both time and money over traditional methods, the company said.

WOOD GROUP, July 23, 2010

Sale of MV Enterprise

Dutch-based Dockwise said it has sold the Enterprise to an undisclosed buyer as part of a move towards focussing on premium cargoes. The ship will be delivered to the new owner at the end of this month, which is due to covert the ship into a floating power plant. “The divestment of this type IV vessel followed from a cost-revenue analysis of the vessels’ operation in market segments with a relatively low contribution,” Dockwise said. Two other vessels, Dock Express 10 and 12 were sold by the company last year as part of the same process.

DOCKWISE, July 23, 2010

Revenue drop for Subsea 7

Subsea 7 reported a fall in revenue for the second quarter and first half this year. Figures presented by offshore contractor today show revenue in the second quarter down to US US$519.9 million, compared with US$637.2 million in the second quarter last year. For the half year to June Subsea 7 reported revenue down to US$972.8 million from US$1,240.1 million in the first half of 2009. Net operating profit for the second quarter was also down, to US$93.8 million, from US$117.8 million last year, and for the first half, net profit was also down, to US$172.3 million, from US$198.9 million.

SUBSEA 7, July 27, 2010

Platform shutdowns hit Talisman

Talisman Energy said its North Sea production has been hit in the second

quarter this year by a series of platform shutdowns. In its income statement for the second quarter and first half this year, the Canadian-based North Sea operator said production in the second quarter from the UK sector was down 31% from the second quarter last year, to average 64,000 boed, and down 25% compared with the first quarter 2010. “The decrease in production was mainly due to planned facility turnarounds, with annual shutdowns commencing and successfully completed at Piper/Tweedsmuir, Clyde/Orion, Fulmar/Auk and Claymore,” Talisman stated. “Shutdowns in the quarter lowered production volumes by 18,000 boed relative to the first quarter. Shutdowns planned during the third quarter are at Buchan, Ross/Blake, Tartan and MonArb [Montrose and Arbroath].”

TALISMAN, July 27, 2010

Major medical care contract won

Aberdeen-based global occupational health specialist Abermed Limited has secured a multi-million GBP contract with Talisman Energy (UK) Limited to supply medical provision to all the company’s on and offshore assets in the UK. The deal will see Abermed providing a range of services, including 24/7 emergency medical support, trained medics and remote medical advice. The agreement is to run over five years.

ABERMED, July 22, 2010

Praise for Spanish job

Marine Subsea (UK) has been praised after successful delivery of a US$1 million (GBp656,000) contract for operator Repsol for works near the Casablanca platform, offshore Spain. Marine Subsea deployed ‘Sarah’, its multi-purpose offshore intervention vessel, to prepare three platform J-tubes for installation work scheduled next year and modify existing trawl protection structures at two well sites. The J-tube work included relocation of an existing but abandoned 6-inch flexible pipe.�

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The entire operation was contracted, organised, and completed in less than four weeks over June and July. The vessel is now in transit to Aberdeen to start subsea well abandonment operations.

MARINE SUBSEA, July 22, 2010

Ensco earnings down

Ensco reported diluted earnings per share from continuing operations of US$0.82 for second quarter 2010, compared to US$1.55 per share in second quarter 2009. Earnings from discontinued operations were US$0.07 per share in the second quarter, compared to a loss of US$0.14 per share a year ago. Discontinued operations in second quarter 2010 included an US$18 million pre-tax gain from the sale of jackup rig ENSCO 57 and US$6 million of pre-tax income related to ENSCO 69, which was previously reclassified as discontinued operations. Discontinued operations for

prior periods reflect these and other jackup rigs that are no longer in the fleet. Diluted earnings per share were US$0.89 in second quarter 2010, compared to US$1.41 per share in second quarter 2009. Second quarter 2010 results included a US$12 million impairment of the ENSCO I barge rig reflected in contract drilling expense and US$11 million of other income from a break-up fee, net of expenses, related to Ensco’s partial tender offer for Scorpion Offshore that was terminated.

ENSCO, July 22, 2010

FUEL

Competition office to complete MOL pricing investigation

Hungary’s Competition Office (GVH) will complete a pricing investigation of oil and gas company MOL by autumn,

GVH chairman Zoltán Nagy said at a press conference on Tuesday. MOL has provided GVH with all of the information it has requested, Nagy said. GVH announced in May that it launched the procedure on the suspicion the oil and gas company used its position as market leader to keep wholesale vehicle fuel prices artificially high since the start of 2006. GVH based its suspicion on market information, but noted the procedure does not mean MOL broke the law. MOL told MTI at the time that it was cooperating with GVH but would not comment on an ongoing matter. GVH has launched similar procedures against MOL twice in the past ten years. It did not establish MOL abused its market position in either case.

MTI-ECONEWS, July 20, 2010

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EurOil 27 July 2010, Week 29 Back Page

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HEADLINES FROM A SELECTION OF NEWSBASE MONITORS THIS WEEK

Oil and Gas Sector

AfrOil Tullow's newly found Owo field could be given prior ity over Tweneboa, according to RBS.

AsianOil India recorded the highest increase in natural gas production of any country in the world in 2009.

ChinaOil PetroChina and BP have agreed to develop CBM reserv es in the Xinjiang region.

FSU OGM Russia says it will continue delivering petrol to I ran, despite new US and EU sanctions.

GLNG Two LNG carriers are due to arrive in the UK this w eek as the country becomes more reliant on LNG imports.

LatAmOil Venezuela has threatened to cut oil exports to the US if it is attacked by Colombia.

MEOG Givot Olam Oil Exploration said its onshore Meged-5 well in Israel holds commercial quantities of oil.

NorthAmOil Halliburton's performance has been driven by onshor e work, but opportunities will arise in the offshore.

Unconventional OGM Sino Oil & Gas has bought a 70% stake in a Chinese CBM project.

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