Falling crude oil prices have plunged many of the North Sea oil fields into the red and threaten all three main producers, the UK, Norway and Denmark, with falling output as future exploration budgets are cut back to save money. Oil industry lobby groups, such as Oil and Gas UK, have called for taxes to be reduced; but geology and low oil prices are the main long-term problems. As the older, and mainly larger fields go into natural decline, the new fields needed to replace them tend to be smaller or in expensive and remote areas, or both. It is not all doom and gloom, however. Savings prompted by technology and more efficient working methods have reduced operating costs offshore and even allowed production to increase in the UK; but low crude prices are causing projects to be delayed and forcing some companies to abandon North Sea exploration and production altogether.

North Sea Oil loses money

About 40% of the UK’s North Sea fields are estimated to lose money with a Brent price at or below $30/bbl despite cost-cutting by the industry and a number of recent tax reductions, including a cut in Petroleum Revenue Tax on older fields from 50% to 35%. The UK’s output of crude and natural gas liquids (NGL) nevertheless rose by about 13% in 2015 to 960,000 bpd and could increase by up to half that level in 2016.

North Sea Oil Prices
North Sea Oil and Gas Production – The Economist

These increases, however, do not necessarily indicate that British oil production has embarked on a long-term revival. Output in 2014 was marked by a greater than usual number of field outages for maintenance and other reasons. The return of these fields to production in 2015 was one reason for the rise in the UK’s production. The UK, along with Norway, also benefited from high levels of upstream spending in previous years when oil prices were much higher. There may still be some effects from this during 2016, and some additional oil from the start-up of new fields, both in the North Sea and to the west of the Shetland Islands; but the UK’s recovery in output may not extend much beyond this year if crude prices remain close to present levels. Only two small new field developments were approved by the government during 2015: EnQuest’s Scolty/Crathes oilfield and a condensate discovery called Culzean, which is being developed by Maersk Oil. Both are due on-stream in 2017.

Last year saw a number of asset sales as companies sought to relinquish their loss-making activities. First, Oil Expro was forced to sell its shareholdings in several North Sea fields. Germany’s E.ON sold assets in both the British and Norwegian sectors that included the operatorship of a number of fields already in production. High debt levels obliged Norwegian independent Noreco to announce a complete exit from the Norwegian sector of the North Sea. High debts have prompted asset sales by other companies, all of which are taking place at distress levels; although this does allow several other expro companies to consolidate the holdings in a number of fields on the cheap.

Several North Sea oil producers also face the need in the near future to renew hedges taken out before 2014’s crude oil price crash, which allowed them some measure of price protection when prices fell. Such protection will not be available at present price levels. At the same time, many companies will have to renew loans at a time when their cash-flow is greatly depleted: all of which could add up to insolvency for some of the less fortunate firms.

North Sea Oil and Gas Field Map
Locations of North Sea Oil fields

There is also official optimism from bodies such as the UK’s Oil and Gas Authority, which cites the addition of some 250 mn boe of reserves across the British sector during 2015 as a result of exploration and the drilling of appraisal wells. There were also two significant discoveries near the Beryl and Forties fields, and some promising results from government-sponsored seismic surveys in seas west of the Shetlands. These are high cost frontier areas, however, and mainly in deep water; and will therefore have to await much higher oil prices before they can be economically developed.

Delays mount

High cost areas have seen delays to a number of projects, such as Total’s Laggan-Tormore gas and condensate fields to the west of the Shetlands, which began production at the beginning of 2016 after nearly two years delay. The commissioning of the field, however, could hasten the development of other gasfields in the area by enabling them to share infrastructure such as pipelines, using a single gas hub.

Norway’s fields have suffered a number of delays as the costs of developing Arctic and other remote fields have soared. One of the largest is Statoil’s 650 mn bbl Johan Castberg oil- and gasfield where the decision on whether or not to go ahead with the scheme has twice been postponed while Statoil tries to find ways of cutting the cost of the $6-7 bn project. A final investment decision is due in 2017. If it turns out to be positive, it will be another five years before production starts. Johan Castberg is one of a number of fields planned for the Barents Sea and a decision to develop it or not may well affect the prospects of other fields in this expensive and marginal area [1].

Other north sea oil fields being delayed by low oil prices and rising costs include ENI’s Goliat field–also in the Barents Sea–Total’s Martin Linge and Statoil’s Aasta Hansteen projects. High costs have led to the early shutdown of some fields, including Repsol’s Vary field and DONG’s Oselvar field. The latest premature closure to be announced is Statoil’s Veslefrikk field.
Denmark, too

Denmark’s partly state-owned DONG Energy faces problems in its own country as well as in Norway, where the start-up of its 170 mn bbl Hejre field looks like being postponed a year, into 2018. Denmark’s oil production is in long-term decline. Exploration is moving into increasingly expensive areas offshore and any new discoveries are likely to be small in size.


  1. Focus: Talk of North Sea revival disguises long term decline. Oil and Energy Trends 2014; 39:7; pp 3–6, DOI:10.1111/oet.12169.


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