Tough Times Ahead for Offshore Norway in 2015


In northern Europe, offshore Norway has in recent years been regarded as one of the more profitable, and even exciting, regions for oil and gas operators to be involved in.

Norway represents a rare combination in the world’s oil and gas industry in that it offers energy companies the stability of a maturing basin with well-developed infrastructure along with frontier exploration opportunities. Not only have companies like Statoil ASA led a technologically-driven approach to maximizing recovery of hydrocarbons from the Norwegian North Sea, squeezing ever more energy out of fields that are often decades old, but the promise of Arctic oil treasure has also seen exploration forays into the Norwegian zone of the Barents Sea.

Consequently, during the past few years plenty of exploration and production companies have decided to enter the Norwegian oil and gas sector while others have expanded their presence there.

As recently as September, Germany’s Wintershall Holding GmbH paid $1.25 billion to take stakes in several Norwegian North Sea fields, including the Aasta Hansteen gas field.

Austria’s OMV AG expanded its presence in the Norwegian North Sea (as well as the UK sector) with a similar deal in 2013 and even embarked on a major recruitment drive to help service this expansion.

Meanwhile, a range of companies both large and small have been investing in exploration in the Norwegian Barents Sea with mixed success.

However, the sudden rapid drop in the price of oil in recent months poses a question about how much new activity will be taking place on the Norwegian Continental Shelf over the next year or so.

For example, Statoil suspended more than a third of its fleet of exploration rigs in 2014 and in early December the firm took the decision to extend the suspension of three drilling rigs as part of its struggle to cut costs as its profit margins shrink. It has also decided to postpone until October 2015 a decision that had been due in March about whether to go ahead with a new platform at the Snorre field in the Norwegian Sea. Statoil believes the project could be used to extract an additional 240 million barrels of oil from the Snorre field, but it would also cost the partners in the field more than $5 billion.


In mid-November, Statoil’s field development chief was reported by Reuters as saying that although the lower oil price could make it difficult to get an investment decision for several field development projects going into 2015, the firm still planned to launch more fast-track projects. Statoil’s fast-track approach sees the company make use of modular equipment and existing infrastructure in order to bring smaller, simpler discoveries into production quickly.

Indeed, research firm Wood Mackenzie reported in August that such incremental projects in the Norwegian upstream sector are set to grow in importance in relation to larger, greenfield developments.

Statoil has already given the green light to 11 fast-track development projects and the firm expects to see between 20 and 30 exploration wells drilled in 2015. Meanwhile, it continues to work on the Johan Sverdrup field and a field development plan for the first phase of this field Is due to be submitted to the Norwegian government in mid-February ahead of a production start-up that is planned for late 2019.

Plans for how the $20-billion Johan Sverdrup field will be powered will be spelled out in more detail this coming spring. The details of this will be closely scrutinized after a heated debate in the Norwegian parliament earlier last year when some of the country’s opposition parties called for the more environmentally-friendly option of powering the project from onshore instead of generating electricity locally on platforms using natural gas and diesel.

However, after Statoil said this could push up costs and delay the project, parliament agreed in June that electrification should happen as soon as possible and be in place by 2022.


In the Barents Sea, Statoil will spend 2015 focusing on analyzing the data it acquired in its 2013-2014 exploration campaign, which had rather mixed results. In a statement in early November the firm conceded that it made fewer commercial discoveries in the Barents Sea than it had hoped for but insisted that exploring in the region “is not a sprint, but a marathon” and that its work there is about “long-term thinking, stamina and systematic building of knowledge”.

Statoil scored a small success with its May 2014 oil discovery at the Drivis well – which will now be developed as part of the Johan Castberg project. The firm will now look at the results of other wells it has drilled in the Barents region and interpret the 3D data from a joint seismic acquisition program in the southeastern Barents Sea ahead of its application for licenses in Norway’s 23rd oil and gas licensing round, which is expected to be launched during the coming months.

It has not been all plain sailing for other operators in the Barents Sea either. While Lundin Petroleum AB and Det norske oljeselskap ASA scored a couple of drilling successes themselves in 2014, the development of the Goliat oilfield is proving somewhat of a headache for Italy’s Eni S.p.A. (the operator of the field). Goliat was originally scheduled to begin production in 2013, with production expected to plateau at 100,000 barrels per day. However, production start-up was delayed until December 2014 and in May 2014 Eni declared that start-up would now take place in mid-2015. The Goliat project is expected to cost almost 50 percent more than originally planned, according to the Norwegian government.

So, a tough year lies ahead for Norway’s offshore sector. Just how tough remains to be seen, but the applications made in the 23rd licensing round should provide a clue as to the continuing attractiveness of the Norwegian Continental Shelf to the oil and gas industry.



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