Climate for investment

Petter Osmundsen, professor of petroleum economics, University of Stavanger

Whether Norway’s petroleum industry is particularly vulnerable to climate risk represents a pertinent question today. If so, should the government work to reduce this exposure? Moreover, does a danger of overinvestment exist on the NCS – and does the Barents Sea pose a particular climate risk?




"The auditor-general expressed concern over the lack of commitment to socioeconomically profitable measures to improve recovery from mature fields. Underinvestment on the NCS has also been identified by Wood Mackenzie."


Demand for oil is continuing to rise. According to the base scenario recently presented by the International Energy Agency (IEA), this reflects population growth, increasing consumption in developing countries and expanding use by petrochemicals, road haulage, shipping and aviation. Oil prices are expected to be USD 88 per barrel in 2025 and USD 112 in 2040.

The proportion of gas in NCS production has been rising over a long time, and demand for this commodity is expected to rise strongly.

Even in a scenario with dramatic climate measures, which few people consider likely, a substantial need will exist for increased investment in the petroleum sector.

Moreover, the competitiveness of the NCS is good. The downside associated with the climate thereby appears limited. But were such a downside to materialise, how would it affect Norway?



Climate risk, defined as the economic risk related to climate change, is basically similar to any other category and is handled by companies in the usual way.

Direct costs of releasing greenhouse gases are internalised through emission allowances and taxes. Norway’s regulatory regime for the petroleum sector delegates assessment of price risk to the oil companies.

The latter work with this on a daily basis, have hired experts and are also investing in new energy. It is hard to see how the government could assess this better while regulating the companies precisely and continuously with no efficiency losses.

Climate risk does not operate in only one direction. It must be assessed in relation to company expectations, where climate policy, for instance, could be less interventionist than expected.

In addition, prices could be lower and abatement costs higher than the companies have forecast – but the opposite might also apply.

The IEA scenario reveals clear concerns over supply. Capital rationing by the companies means few new discoveries or developments and record-low reserve replacement.

Fears are expressed of an oil supply crisis over the next decade. So a strong probability exists that oil prices will be considerably higher than the base estimate.



A 2015 investigation by Norway’s auditor-general revealed that the companies have a higher required return than the government and that the NCS is increasingly competing with projects elsewhere. Only the most profitable developments are realised.

Given limited company access to capital, the study concluded that even projects which show a positive present value with the companies’ own required return are not necessarily implemented.

The auditor-general expressed concern over the lack of commitment to socioeconomically profitable measures to improve recovery from mature fields.

Underinvestment on the NCS has also been identified by Wood Mackenzie (2018a). The reasons for this can be split into several independent factors, including the higher required return mentioned above.

A recent Wood Mackenzie study (2018b) indicates that a representative real required return for oil companies is 11-13 per cent, compared with seven per cent for the government.

In addition comes the capital rationing mentioned above – the oil companies require present value to be at a certain level. See Emhjellen and Osmundsen (2017) and Emhjellen et al (2017).

This is best illustrated by the fact that the oil companies have an oil price expectation of USD 70 per barrel and above, but require projects to be profitable (given their high required return) at a breakeven price of around USD 35 per barrel.

A further buffer is Norway’s petroleum tax regime, which gives companies a much lower return post-tax than pre-tax. See Osmundsen et al (2015), Wood Mackenzie (2018a) and Lund (2018).

This means that the internal rate of return must be several percentage points higher before tax in order to achieve a given post-tax outcome.

The pre-tax return which an NCS project must deliver in order to be sanctioned is therefore much higher than the government’s requirement. The gap between these two positions represents an efficiency loss to the economy.

So the problem on the NCS is not stranded assets but underinvestment. Projects delivering a profit far higher than can be obtained in other industries are failing to be approved.



What counts is not the oil price alone, but the differential between it and costs. Simple analyses of downside risk on the NCS typically reduce the oil price while keeping costs constant.

When the price falls, however, so do most cost components:

  • rig rates drop, see Skjerpen et all (2018)
  • drilling speed increases, see Osmundsen et al (2010, 2012)
  • oil service charges go down
  • rates for personnel hire fall
  • fabrication costs drop
  • cost overruns are reduced, see Dahl et al (2017).

This list could be extended. The petroleum sector makes great use of outsourcing, with rates set in a market which responds to the level of activity. Cost components are not sticky, as economists usually assume.

When activity declines, so do factor prices. The average quality of inputs increases and project control improves, so that productivity rises.

Only the most suitable rigs and the most competent specialists and project managers get hired. This combination of higher productivity and lower input prices yields big cost cuts.

The papers referenced above show local elasticities which cannot be straightforwardly applied during major price downturns of the kind seen in 2014.

These reductions have the supplementary effect that they initiate system improvements, such as cost cuts for development concepts.

Equinor reports that it expected to require an oil price of USD 70 per barrel in 2013 to ensure that the projects being pursued were profitable.

For a corresponding portfolio today, however, it only needs crude to be trading at USD 21 per barrel to achieve project profitability.1

1, 08.42, 4 August 2018:

A number of analyses of downside risk in Norway’s oil sector therefore lack scientific validity. The industry’s swift and extensive response to lower prices indicates that profitability is far less dependent on crude prices than many think.

This finds its clearest expression in the fact that petroleum shares correlate more to the market index than to the oil price.



Thanks to shallow water and reservoir depths as well as the Gulf Stream, the Barents Sea differs economically in a positive way from other Arctic waters.

The Gulf Stream means this area is largely ice-free, making it significantly easier to pursue petroleum operations there.

Similarly, relatively shallow water and reservoir depths make drilling significantly simpler and cheaper. Exploration wells now cost only NOK 200 million.2


According to Norwegian and Russian sources, the combination of cheap drilling and relatively large discoveries (twice the size of the North Sea) means low finding costs.

Development costs are said to be competitive, although a lack of infrastructure could mean they are initially higher than in the North Sea for smaller discoveries.

The Barents Sea is frequently described as a high-risk Arctic area. Oil projects there are often seen as profitable, but the financial viability of gas production in this area is questioned.

While oil developments have a short payback time – often only a few years – repayment usually takes longer for gas projects.

On the other hand, gas yields lower emissions and is therefore expected to be less vulnerable to climate measures. A paper from Lindholt and Glomsrød (2018) at Statistics Norway and climate research specialist Cicero addresses this.

This identifies gas as a low-carbon alternative to coal in power generation, and finds that Arctic output of gas will be higher than today even in a two-degree scenario.

Modelling shows a steady increase in gas from the Arctic NCS replacing coal, with a tripling in relation to the 2012 reference scenario by 2050. Norway does better than other regions because of lower costs and quicker start-up.

The Johan Castberg development in the Barents Sea is set to be paid off in two years. An impact assessment in June 2017 estimated this field’s socioeconomic value at NOK 85 billion in 2016 value. Of this, NOK 62 billion falls to the government through taxes.

With a breakeven price of USD 31 per barrel,3 Johan Castberg alone would pay for more than 400 exploration wells at today’s rates. So far, 130 of these have been drilled in the Barents Sea.

3 Proposition no 80 to the Storting, Utbygging og drift av Johan Castberg-feltet med status for olje- og gassvirksomheten

This means that, for all practical purposes, the profitability of exploring the Arctic NCS has already been assured by a single field – assuming its development proceeds as planned.



The new IEA scenario finds the downside for oil to be small and paints a uniformly positive picture for gas, which forms a growing share of Norwegian output.

But how would Norway be affected if the world’s nations, against expectations, were to agree on adopting drastic climate measures?

Gas accounts for the larger share of NCS resources, and demand for this commodity is set to rise even with stringent action to curb emissions.

And crude prices would still provide scope for extensive oil activities on the NCS, even with a tough global regime for the climate. Repayment times of just a few years reduce risk.

It could be argued that the recent downturn suffered by Norway’s oil sector has been a full-scale experiment in how resilient the industry is to falling prices. This slump was much faster and bigger than is likely with tough climate action.

The Norwegian petroleum sector has shown great flexibility. Costs have been drastically cut, and high profitability restored. And the government pension fund – global permitted the adoption of counter-cyclical measures which lower the macro-economic impact.

In practice, the industry has repudiated crisis scenarios for the NCS where researchers – who should know better – have reduced oil prices while keeping costs constant.

Reduced activity means a sharp decline in rates and a considerable improvement in productivity, which jointly moderate the economic effect of falling prices.

The oil companies require projects to remain profitable if the price of crude falls to USD 35 per barrel. In common with others, they see this as unlikely – their own calculations show rates of USD 70 and up – but set such requirements since they are rationing scarce investment funds.

With oil price expectations at least twice the criterion for sanctioning projects, it can only be called impressive that a debate remains alive in Norway on unprofitable oil projects.

Underinvestment is the problem. Projects with pre-tax profitability well above the socioeconomic required return have not been sanctioned. And those approved are underdimensioned.

Operations in the Barents Sea are often compared with activity in other Arctic waters, which are typically characterised by expensive production.

The comparison is inapt because the Barents Sea offers lower costs and quicker start-up. Virtually ice-free, it has little wind. Shallow waters and reservoirs make drilling and development relatively cheap.


"Johan Castberg alone would pay for more than 400 exploration wells at today’s rates. So far, 130 of these have been drilled in the Barents Sea."



  • Emhjellen, M and Osmundsen, P (2017), “Capital Rationing by Project Metrics”, in Mjøs, A, Gjesdal, F and Bjørndal, M H (eds), Finance and Society. An Anthology in Honour of Thore Johnsen: 359-376, Cappelen Damm Akademisk.
  • Emhjellen, M, Løvås, K and Osmundsen, P (2017), ”Petroleum Tax Competition Subject to Capital Rationing”, CESifo working paper no 6390.
     IEA (2018), World energy outlook.
  • Lindholt, L and Glomsrød, S (2018), “Phasing out coal and phasing in renewables. Good or bad news for Arctic producers?”, Energy Economics 70: 1-11.
  • Lund, D (2018), “Increasing resource rent taxation when the corporate income tax is reduced?”, memorandum 03/2018, department of economics, University of Oslo.
  • Osmundsen, P, Emhjellen, M, Johnsen, T, Kemp, A and Riis, C (2015), “Petroleum taxation contingent on counter-factual investment behavior”, Energy Journal 36: 1-20.
  • PL532 Johan Castberg plan for development and operation, part II – impact assessment, June 2017.
  • Auditor-General of Norway (2015), Riksrevisjonens undersøkelse av myndighetenes arbeid for økt oljeutvinning fra modne områder på norsk kontinentalsokkel, document 3:6 (2014-2015).
  • Wood Mackenzie (2018a), Norway’s petroleum tax system. Is it time for change?, report.
  • Wood Mackenzie (2018b), State of the upstream industry, survey.