The UK North Sea has about 5 billion barrels of recoverable reserves left. 170 fields produce liquids in offshore UK, with combined output pegged at 1 mb/d. Output recovered in 2014 due to a plethora of satellite fields being brought online and tied to the existing fields.
For fields producing before 2009, output halved between 2008 and 2014, from 1.3 mb/d to 0.63 mb/d, which represents an annual average production decline of 12%. The increase in declines has come as a result of several satellites being brought onstream, which are typically produced and depleted more quickly (~26%). Since 2000, an average of four to five satellite fields has been brought online annually.
We estimate the average breakeven price for projects in the UK is close to $75 per barrel, with a large range of $59 per barrel. Only the Clair Ridge project would be profitable in the current oil price environment whilst most other projects which made sense in a $110 environment do not breakeven today. Decommissioning costs are also rising, estimated to grow to over $3 billion annually from 2018 onwards. Last year, they breached $1.5 billion.
Over the next 35 years over 5,500 wells, 400 facilities and 10,000 km of pipelines will need to be decommissioned at an estimated cost in excess of $75 billion.
We expect the fruits of $100 oil to continue to provide some more short-term respite for UK production as a slew of projects are brought to the market. 2016 additions total 0.17 mb/d. In 2017, the backlog of projects due to come is even larger, pegged at 0.22 mb/d. The Capex for these projects has been largely sunk and therefore is not at risk. But we expect more maintenance next year given limited works this year which could keep output flat y/y in 2016. From late 2017 onwards, production is set to decline steeply.
Norway has a bigger reserve base than the UK and the discovery of the Johan Sverdrup field will rejuvenate the Norwegian Continental Shelf later in the decade. However, unlike the UK, the Norwegian tail of projects is shorter and was significantly front-end loaded.
Norwegian output has also increased in 2014 and is set to rise again in 2015, due to the addition of smaller satellite fields, much like the UK. These fields decline at about 14% per annum, while base declines are around 8-9%. Interestingly, most of the decline is observed from fields where drilling activity has been high, and costs have risen commensurately.
Given a backdrop of a near 20% decline in output since 2003 to 2015 to 3.7 mboe/d (crude production fell from 2.8 mb/d to 1.5 mb/d over the same time frame), on a boe basis, unit costs peaked at $21 per boe in 2013, before easing to $19 per boe a year later.
Come H2 16, the effects of higher maintenance and only 51 thousand b/d (two relatively small fields) of additions mean production starts to decline. In 2017, capacity additions improve marginally to 80 thousand b/d, but these additions will not be enough to stand still.
Overall, there is little hope for the North Sea once the project backlog runs its course.