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North Sea output heads south

Slowing offshore activity in the UK and Norway is prompting support

LOW commodity prices have put a dent in upstream investment in Norway’s and the UK’s offshore, threatening medium-to-long-term production in both countries.

The slump in drilling activity on the UK Continental Shelf (UKCS) in 2015 gives significant cause for concern. Last year, exploration and appraisal drilling fell to its lowest level for 45 years, with just 13 exploration and 13 appraisal wells drilled, according to the Oil and Gas Authori­ty (OGA), the regulator. In 2008, firms drilled more than four times as many wells.

The impression of a basin in rapid de­cline dovetails with the production sta­tistics: since 1999, UKCS oil production has fallen from 2.6m barrels a day to about 0.9m b/d. Reserves are dwindling too; only the West of Shetland area remains relatively under-explored and prospects for big finds elsewhere are limited. Reflecting the fading appeal of a basin first drilled in 1967, the biggest oil and gas companies have contin­ued to divest assets and reallocate funds to areas with better prospects.

Offshore activity is – for now – in de­cline on the the Norwegian Continental Shelf (NCS) too. The Norwegian Petro­leum Directorate (NPD) says investment on the NCS fell by around 16% in 2015 compared with 2014. Further declines are expected over the next few years.

The UKCS and the NCS have signif­icant differences – their tax regimes and their relative degrees of maturity, for ex­ample (the UK’s offshore sector is more developed than Norway’s). Reserves are on different scales too: according to BP, Norway’s proved oil reserves amounted to 6.5bn barrels at end-2014, compared with 3bn in the UK. Yet the two countries have much in common: both experienced surges in production last year, but face the twin problems of high costs and a prepon­derance of mature, declining fields.

In the UK, spending on new-field de­velopment, encouraged by high oil prices before mid-2014, enabled the North Sea to register its first annual production rise in 15 years with a 10% bump in oil and gas output. In Norway, output rose by 3%, as the pace of drilling and output from exist­ing operations exceeded expectations. At the end of 2015, 82 fields were in operation on the NCS, compared with 51 a decade ago – reflecting the extensive development activity that prolonged high oil prices have encouraged.

But high costs mean both basins risk premature decline. The NPD has warned operators that the longer low prices per­sist, the greater the risk of premature field closure or project cancellation – and the greater the threat of an acceleration in the decline of offshore activity after 2020. Cost reductions and improved efficiency are necessary safeguards, it says.

Life membership

Last year, Statoil post­poned a decision on extending the lifetime to 2040 of its Snorre field – which might deliver another 300m barrels to world markets. A preliminary development deci­sion is expected in the fourth quarter and a final decision next year; standing in the way, says Statoil, are “high investments in combination with challenging profitabili­ty”. Statoil has also delayed a decision, until the second half of this year, on how to de­velop the Barents Sea’s Johan Castberg field and is exploring the possibility of sharing infrastructure with other operators.

Cost savings derived from greater con­solidation of asset and field ownership, and operation, will also be a fundamental part of the long-term survival of the UKCS, where numerous fields are on a knife-edge between continued production and decommissioning. The UK government’s March budget announcement will help: it confirmed the availability of decommis­sioning tax relief, which should stimulate asset trading in the basin and help iron out operating inefficiencies arising from fragmented ownership of resources. The government also said it would reduce the headline rate of tax paid on UK oil and gas production from 50-67.5% to a rate of 40% across all fields. The 29th licensing round, later this year, could provide new insights into how much these measures have helped lift downtrodden investor confidence.

However, the outlook for the offshore sector in both countries will also depend on creative cost-saving innovations – ones that go far beyond job cuts. In the UK, for example, alongside new-field development – the driver of recent growth – operators have invested in retooling ageing offshore production systems for the realities of 2016, rather than requirements specified in decades-old designs.

The prize such innovation can achieve is worthwhile, says Oil & Gas UK, an in­dustry body. It estimates there may be some 20bn barrels of oil equivalent still to recover on the UKCS.

The same applies to the NCS. The NPD reckons about 47bn boe remain to be produced, of which it says 30bn boe are “proved resources”. New licensing op­portunities announced in March under the Awards in Predefined Areas scheme – which licenses large areas close to existing and planned infrastructure – will provide an important gauge of investor appetite. Bids are due in September and awards are scheduled for the first quarter of next year.

This article is part of an in-depth series on offshore production. Next article: Production on ice in the Arctic.

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