A golden age for gas [NGW Magazine]
Whatever the long-term future might hold for gas, its short to medium prospects look very bright: this year has kicked off with a series of major discoveries in both mature and frontier provinces.
Even setting to one side Cuadrilla’s UK shale reserves flowing to the surface, there have been big successes with the drill-bit in Asia, Africa and Europe. There are still the results of Eni’s Noor prospect off Egypt to look forward to as well.
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The French major Total has had two big finds, one in the UK and one in South African waters; Spain’s Repsol has found more gas onshore Indonesia; and now ExxonMobil and Qatar Petroleum have found a promising discovery in the eastern Mediterranean.
UK, Indonesia and South Africa will be able to absorb the gas readily, if final investment decisions are taken. The latest is the most problematic at the moment: too small for a standalone onshore liquefaction development on Cyprus, it is also beyond reach of an overseas market. Time and money will have to be spent drilling to find sufficient reserves in what the operator calls a frontier region, to reach critical mass. First gas could be a decade away.
Still, as the US major says, the results are “encouraging,” and it is unlikely to have drilled in such a problematic and geopolitically challenged location in the first place if it did not have some ambitions for the region’s known gas resources. They are not short of low-hanging fruit in Qatar, the US and elsewhere.
This world of exploration and development almost exists in a parallel universe: while taking giant leaps forward in computational and technical wizardry first to discover and then to produce the commodity ever more cheaply, other entities – often affiliated to the upstream adventurers – are conscientiously seeking affordable alternatives, such as hydrogen and green gas, reducing energy waste through smart grids and so on.
It is debatable how far the transition will go and it is possible the goals of the Paris agreement will be missed. This might be for practical and geopolitical reasons, even if some parts of the world over-achieve. Investments in carbon capture and storage might not make economic sense, and yet this is a critical element in the scenarios where the goals are met.
But even if the days of unabated methane are indeed limited, until that point is reached we are going to need a lot more gas to replace coal in the power sector and oil in the heavy transport sector, where batteries will be ineffective. It will continue to be needed for industrial processes and space heating. And more gas will also be needed to backfill declining output. Equinor’s investment in Troll C for example will see the giant producing until the 2050s. By that time, European gas demand might be so low that the Norwegian field will still be meeting 8% of gas demand, as it does today.
Marketing the gas that they find will become increasingly an important part of the producers’ toolkit, since the onshore utilities, their traditional customer base, are moving towards renewables and developing alternatives. Selling spot gas at hubs is only part of the answer.
Unbundling the pipelines from the suppliers was a necessary step to a competitive gas market and the common carrier regulation was no impediment to pipeline construction in North America. There is so much of the commodity to bring to a number of different markets that now include liquefaction and petrochemical plants. But in Europe, a largely gas importing region, this separation has left the pipeline owners dangling. Their investors are relying on favourable regulation for steady but dull returns, rather than on creating demand for gas they do not own, except for limited quantities of biomethane. Dutch transporter Gasunie’s annual report says the downsizing has already begun, so far voluntary.
ExxonMobil’s plan to develop an integrated offshore-gas-to-power generation project in Vietnam is one way to capture more value from output; Shell’s purchase of First Utility in the UK and its prospective purchase of Dutch Eneco is another way to monetise production, as is its Gibraltar LNG to power project.
In technology, combined heat and power represents a major efficiency gain, even when the power plant used is a quick-start reciprocating engine, such as Uniper is planning to bring into service in Germany. A combined-cycle gas turbine plant would have been more efficient but not so good at backing up wind. Such are the expected but unintended consequences of market rigging.
Those short on gas, conversely, need to attract suppliers. All the talk of the imperatives of the energy transition, the ambiguous phrase ‘decarbonising’ and the need to avoid ‘locking investments’ into greenhouse gas emitting technology on whatever scale exposes Europe to the risk of more intermittent energy while sending negative signals to suppliers.
There has been much debate about what to about Ukraine’s transit system, or more accurately how to replace the future lost revenues that Nord Stream 2 represents. It is clearly not the job of the European gas industry to solve this problem. Yet Russia could do so, in a way that would satisfy almost everyone. Allowing the BP-Rosneft agreement on joint Russian gas production and gas marketing in Europe to be realised would enable more Russian gas to reach Europe than at present, but sold under a different brand from Gazprom’s gas, as is the case today with the partly Total-owned Yamal LNG. A fully competitive export market in this giant resource holder would indeed signal a golden age.
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