Arctic Oil-Gas Commercial Rationales and Risks

(from Lloyd’s Report 2012: Arctic Opening – Opportunity and Risk in the High North)

As elsewhere, geological uncertainties affect investment decisions in the Arctic. But, from a corporate perspective, geological uncertainty is partly offset by the prospect of discovering large fields – unlikely to be found in other parts of the world – that would justify large exploration expenses. The share valuation of IOCs is largely driven by the ratio of proven reserves – which can be ‘booked’ in a company’s financial reporting (xvii) – to production. For companies excluded from equity stakes in many of the prime resource bases of the world, and within a diminishing range of investment options – including deepwater ones – the Arctic is increasingly attractive (xviii).

Further, companies exploring in the Arctic can acquire the technical expertise they will later need for production there. The Arctic has typically been a long-term investment: lead times from discovery to production remain long and there is limited Arctic-ready equipment to engage in exploration activity. It took Statoil 30 years of exploration and drilling in the Barents Sea before production. The company expects its Arctic exploration and production will speed up the rate of subsequent discoveries and potentially reduce production lead times¹ .

The commerciality of any project or technique is based on expectations of future market prices for oil and gas. Expectations that the price of oil will remain in the $80–$120 range in real terms for the foreseeable future provide a strong incentive for exploration and increase confidence that prices will cushion the high costs of Arctic development (see Figure 10). However, global energy markets are in flux. Several studies suggest the potential of a peak in global oil demand, rather than supply, leading to subsequent terminal decline and lower prices² . A sustained oil price spike in the near term might accelerate that process³ .

The outlook for Arctic natural gas is different. In the future, European Arctic gas can be expected to reach consumers by pipeline, partly through existing Russian or Norwegian networks, and partly to compensate for declining gas production elsewhere in Europe and Russia. The scope of this market is constrained by the level of European demand. The Russian government intends to use Arctic production to allow it to keep to its European commitments while attempting to capture a part of the growing Asian gas market.

The broader global dynamics of natural gas are shifting, however. Natural gas is priced and sourced regionally, often resulting in significant price differences between markets – there are currently low natural gas prices in North America and high ones in East Asia. However, gas is increasingly marketed internationally in LNG form. Prices for gas could change dramatically if prices were decoupled from oil, or if there is a move towards a global price – as with oil – or if significant new gas supplies come on-stream.

Shale gas production in the US, for example, has already led companies to drop out of the $30–$40bn project to pipe gas from Alaska’s North Slope to US and Canadian markets⁴ . In Asian markets Arctic LNG would have to compete with Australian and other Asian sources. In time, the continental United States may itself become a significant exporter if natural gas production is not diverted to its transport sector.

There is considerable variation amongst Arctic hydrocarbon projects. This has implications for their commercial viability, and for the business, operational and environmental risks associated with developing them. The estimated cost of producing a barrel of Arctic oil ranges from $35 to $100 (production costs in the Middle East are sometimes as little as $5 per barrel) (xx).

There are different potential offshore developments in both shallow water and deeper water. Some are in relatively inaccessible areas; others are in places with a history of oil and gas development. Some Arctic developments are commercially viable at a relatively low oil price, particularly onshore, and especially where there are sunk costs in terms of infrastructure. Other Arctic developments, such as offshore Greenland and the Barents Sea, with potentially higher production costs and a requirement for major infrastructure investment before development, need either a much higher price or a much larger find to be profitable.

The higher end of Arctic production costs is in line with current and projected oil prices for the next 10-15 years. However, given that lead times from prospecting to production are approximately ten years, the commercial value of undiscovered fields is far less certain.

For the most commercially marginal Arctic oil and gas developments, the tax regime applied may be a decisive factor in determining their viability. There is wide variation in the government take of profits from Arctic projects, depending on government-set regimes, price and production costs. A recent study suggested that, at a sale price of $80 and a production price of $25, the government take for Arctic oil projects would range from 100% in Russia (though this is changing) to 40–45% in Greenland and Canada (xxi). As governments offer incentives for development, or as geological uncertainties are reduced, the government take is likely to shift. The Russian government’s terms for Yamal’s LNG development are described as being “among the lowest in the world” (xxii).

The UNFCC and its member states have publicly stated their commitment to meet a target of 2°C maximum temperature rise by 2020. A business-as-usual attitude to climate change will lead to a 4°C temperature rise, resulting in devastating impacts on people’s lives and the global economy. To reach the 2°C target, the world’s leading economies will need to commit to a significant increase in their use of renewable energy. Governments and companies should consider how the drive to develop Arctic oil and gas exploration will align with international action on climate change mitigation.

Figure 10: Long-term oil supply cost curve  

Footnotes: 

(xvii) The listing of reserves in a company’s financial reporting is subject to strict regulation.

(xviii) For example, national policies exclude foreign investment in upstream oil in Saudi Arabia and do not allow the booking of reserves in Iran.

(xix) MENA refers to the Middle East and North Africa; EOR refers to Enhanced Oil Recovery. These are engineering techniques to increase the amount of crude oil that can be extracted from a field.

(xx) This depends on the productivity of the wells and the field, among other factors.

(xxi) Pedro van Meurs, Barry Rogers, Jerry Kepes, World Rating of Oil and Gas Terms: Volume 3 – Rating of Arctic Oil and Gas Terms, Van Meurs Corporation Rodgers Oil and Gas. Consulting & PFC Energy, 2011 (as reported in Petroleum Economist January 2012).

(xxii) ‘Arctic investment competition heats up’, Petroleum Economist, January 2012, available at www.petroleum-economist.com/Article/2959654/Arctic-investment competitionheats-up.html.

Charles Emmerson, Glada Lahn, 2012, Arctic Oil-Gas Commercial Rationales and Risks, Lloyd’s.©