Norway’s North Sea sector remains the region’s most vibrant and well-invested market, and faith in its long-term potential received major affirmation in June when a deal was unveiled by BP and Det norske oljeselskap to create the new independent offshore player Aker BP.

Following on from a smaller but also significant deal the previous year, when former BP boss Lord Browne’s L1 Energy company first acquired DEA and then just months later snapped up E.ON’s Norwegian E&P business to more than double its production in Norway to about 75,000 boe/d, the latest transaction is expected to formally close during third-quarter 2016.

Any deal led by Lord Browne, who steered BP between 1995 and 2007 through what many see as a golden period in its history, is bound to have been watched closely by his former company. It may even have partly prompted the global major to follow suit, as it was only six months later that it revealed its own Norway-centric deal with Det norske, whose main shareholder is Aker (in turn controlled by Norwegian billionaire Kjell-Inge Roekke). Aker will hold 40% in Aker BP, with BP owning 30% and the rest held by other Det norske investors.

Appealing Proposition
What is it that makes Norway such an appealing proposition as an oil and gas province in tough times, when breakeven costs are today’s apparent dominant factor?

Firstly it is its dependability, not only in its fiscal and economic policies but also in terms of its production. The latest monthly preliminary figures available as E&P went to press, for May, showed Norway’s average daily output at about 1.94 MMboe. This consisted of 1.55 MMbbl of oil, 360,000 bbl of NGL and 35,000 bbl of condensate. Oil production is about 2% above the equivalent figure from May 2015. This is a solid production record that can be relied upon, backed up by a government that is almost always fully prepared to invest long term in the sector’s future in areas such as technology R&D as well as licensing and exploration in new areas.

A relatively expensive offshore province it still remains, but that is a perception that is slowly changing as Statoil and the other operators on the Norwegian Continental Shelf (NCS) continue their focus on squeezing down development and operations costs and increasing standardization. A growing number of the sector’s producing projects and those under development now fall well within today’s requirement for sub-$50/bbl breakeven costs.

Need To Cut Costs
BP and Det norske’s deal to merge their Norwegian businesses in their $1.3 billion all-share deal was largely driven by that stated need to cut costs. The venture also offers BP a solid opportunity to access new oil production and reserves within the next decade, something that has extra appeal after the stringent cuts in exploration activity it has imposed in recent years.

One of the jewels in the crown for BP is undoubtedly the gaining of a minority stake in the Norwegian flagship field Johan Sverdrup, the country’s largest oil find for 30 years, which is under development and in which Det norske holds an 11.57% stake. Due onstream by late 2019, operator Statoil said the field would be economic even at sub-$30/bbl oil.

But the creation of Aker BP also allows BP to continue its ongoing policy of slimming itself down globally, shedding some older assets off its books while also putting them, with little risk, under the management of a smaller and potentially more efficient operator. At the same time it also will manage to maintain its long-term presence in Norway and access potential new reserves.

The new entity is expected to start with a production level of about 122,000 boe/d once it is approved, instantly making it one of Europe’s biggest E&P players. Once Johan Sverdrup is onstream, Aker BP’s production could hit 250,000 boe/d by 2023. Its estimated P50 reserves are put at 723 MMboe.

Production Ramp-up
For Det norske the deal also was logical in that it gave the company ownership in three producing BP fields—Skarv, Ula and Valhall—with net 2015 production of about 62,000 boe/d and a means of generating instant cash flow to help it fully fund its share in the development of Johan Sverdrup.

Production levels will be further ramped up later this year when the first phase of Det norske’s Ivar Aasen Field offshore Norway comes onstream in the fourth quarter. With several other fields also under development, Aker BP is expected to achieve production of more than 152,000 boe/d in 2020 before the Johan Sverdrup Field’s expected ramp-up in output further boosts this figure.

Aker BP also will hold a portfolio of 97 licenses on the NCS, of which 46 will be operated.

BP CEO Bob Dudley said he wants his company to do business in Norway since it has impressive capacity for production growth there and “significant opportunities.” Speaking during a conference call related to the deal, he stated, “The need for choosing how to spend money and capital very carefully is right at the forefront of everyone in oil and gas.” Bernard Looney, BP’s chief executive, upstream, added that Det norske’s “lean approach” also would benefit his company.

“We will look predominantly for oil assets and will put value over volume.”
—Karl Johnny Hersvik, Det norske

Competition On NCS
Heading the new entity will be Det norske’s CEO Karl Johnny Hersvik, who has previously called for the need for bigger competitors to go up against the Norwegian giant Statoil on the NCS. The new and stronger Aker BP, with its extra financial capability, will undoubtedly be looking for other targeted acquisitions. “We will look predominantly for oil assets and will put value over volume,” Hersvik said in the call.

This challenge to the dominance of Statoil (responsible for 60% of the country’s oil and gas production) is seen by many as a trend that can only be a good thing, encouraging further countercyclical merger and acquisition investments and competition in Norway’s offshore.

Editor’s Note: L1 Energy’s executive chairman, Lord Browne, will lead a panel discussion on long-term perspectives and future projects for the NCS at the Offshore Northern Seas conference in Stavanger, Norway, (Aug. 29 to Sept. 1) alongside speakers from Statoil, Lundin and Aker Solutions.

SIDEBAR:

NCS Decommissioning Market

Norway’s decommissioning market could be worth up to NOK 160 billion in the period to 2024, according to a recent report. The NCS could see up to 23 decommissioning projects ranging from small subsea tiebacks to full-scale integrated platform removals in that time. According to data from the U.K. industry group Oil & Gas UK, supported by the Norwegian Petroleum Directorate, the decommissioning report highlights 12 concrete facilities, 19  oating steel facilities, 88 steel facilities and nearly 350 subsea systems currently in place. An estimated 3,000 wells also will need to be plugged and abandoned (P&A). Oil & Gas UK worked with  five key operators on the NCS to produce the data as part of its efforts to help the industry prepare for forthcoming decommissioning projects. The survey required operators to provide data on their decommissioning activity forecasts on the NCS from 2015 to 2024 and was carried out in second-half 2015.

Plan Submittal
The Norwegian Petroleum Act regulates the shutdown and disposal of NCS facilities, with operators required to submit a decommissioning plan two to five years prior to an installation ceasing production. About 800 wells already have been P&A on the NCS, with close to 300 more forecast to be P&A by 2024. Up to 26 pipelines with a total length of 360 km (224 miles) are forecast to be made safe in preparation for decommissioning over the same period. Up to 14 platforms are forecast to be made safe and their topsides prepared for decommissioning up to 2024, with full or partial removal planned at this stage. The platform weights range from 3,000 tonnes to more than 30,000 tonnes.

Offshore