As SPE Offshore Europe opens its doors, petroleum economist Professor Alex Kemp gives his view on the outlook for the North Sea.
Over the past three years the North Sea oil and gas industry has made a very painful adjustment to the dramatic fall in oil prices. Costs have been dramatically cut, accompanied by substantial job losses and rates reductions.
Oil & Gas UK estimates that average unit development costs have fallen from US$23.90/boe, in 2014, to $15.20/boe in 2016, and possibly $8 - $10/boe in 2017. Average operating costs are similarly estimated to have fallen from $29.70/boe in 2014, to $21.10/boe in 2016, and possibly $14.10 - $14.60/boe in 2017.
These are astonishing changes. Economic modelling by Linda Stephen and the present author indicate that the near-term effects of substantial cost reductions greatly reduce the income of the whole supply chain. But in the medium and longer term, the development of new projects may be incentivised to such an extent that the total income of the supply chain exceeds what it would have been before the cost reductions were implemented.
The industry’s performance in terms of production efficiency has improved substantially since it reached a low of 60% in 2012. It now exceeds 71% reflecting major improvements to a wide range of operating procedures. This has been at least partly responsible for the increase in production from 1.49 MMboe/d in 2014 to 1.73 MMboe/d in 2016, with a further increase to over 1.8 MMboe/d in 2017 being very possible.
While these developments are clearly encouraging, there are other less favourable trends. The UKCS is a mature province. The average size of a new development is now only c.20 MMboe. The perceived prospectivity among investors reflects this and explains, at least in part, recent very low levels of exploration, even with c.$100/bbl oil. Recently, drilling costs have reduced substantially, and significant seismic data have been made freely available. Whether these factors will really enhance the exploration effort remains an open question. The success rate could be increased, but the likely size of discovery remains small, with the possible exception of West of Shetlands, where costs remain particularly high.
For the long term, detailed economic modelling by Linda Stephen and the present author suggests that, with a $60 investment screening price (reflecting the “lower for longer” scenario), aggregate production from 2017-2050 could be around 11 billion boe. This compares with over 43 billion boe produced since 1967. The modelling indicates that investment expenditure on new field developments falls substantially over the next few years. Yearly production peaks in the near future and declines to very low levels by 2050.
Image: Professor Alex Kemp.
But, this leaves a large unexploited potential. At the $60 price and with modest exploration success it is around 5.6 billion boe. The resources are in more than 180 fields, mostly small pools each containing reserves of less than 50 MMboe. If $50 were the investment screening price, the unexploited potential is nearly 7 billion boe contained in over 270 fields. Further economic modelling, based on an oil price rising in real terms to $100 in 2050, indicates that many of the fields become viable and cumulative production from 2017 could increase to c. 16 billion boe. This is predicated on costs rising only in line with general inflation, which must have a relatively low probability. But, a combination of higher oil prices and substantial cost reducing technological progress could have a major effect.
The challenge for the industry, the Oil and Gas Authority (OGA) and the new Oil and Gas Technology Centre is clearly to render viable many of these discoveries. Success would make a major difference to activity levels. Enhancing recovery from c.11 billion boe to c.16 billion boe would greatly increase the value-added of the whole supply chain in particular, i.e. cumulative development expenditure to 2050 could rise from c. £89-183 billion. Total operating expenditure could increase from c. £124-195 billion.
In its relatively short life, the OGA has been very busy in promoting activity and encouraging collaboration in pursuit of the maximization of economic recovery. The fruits of its effort have mostly still to come. Productivity enhancing research and development has a major role to play in the future of the whole province following a period of arguably less than optimal work in this space.
Taxation incentives continue to have a substantial role to play. The reductions in the overall rates of tax plus the Investment Allowance for Supplementary Charge have positively impacted on expected cash flows in the very difficult recent conditions. Late field life asset sales from licensees who do not regard them as core business to others who are interested in acquiring them can enhance economic recovery. It is important that the tax system does not put impediments in the way of this. Decommissioning obligations being transferred to buyers can cause difficulties because of insufficient tax capacity against which to set the losses. This problem can be alleviated by allowing the tax history of the seller to be transferred to the buyer when an asset transaction occurs. There is a case for changing the tax rules to permit such transfers.
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