• Following a shale gas bonanza in the US, Jonas Persson, Utilities Director, is cautiously optimistic about its implications for the UK’s wider energy mix.

     

    US shale gas production bears hallmarks of growing bigger by the year as processes and techniques of hydraulic fracking improve with time and practice. It stood at 4.9 trillion cubic feet (tcf) by end-2011 and accounted for 25% of the total American production, up from 4% in 2005. US Energy Information Administration (EIA) currently projects 862tcf in recoverable shale gas reserves and believes shale’s share of total US production would rise to 46% by 2035. 

     

    Inevitably, given the impressive production projections, there is now market chatter that the US – once a major LNG importer – will become a gas exporter. This turnaround has not escaped the notice of the European utilities sector as Poland, Ukraine, France, Norway, Sweden and the UK may also have meaningful shale deposits.

     

    The UK is examining its place in the energy mix and has begun eyeing imports from the US as well as its own production capacity. The development has been rapid with UK reserve calculations limited to 5tcf at the beginning of the decade, whilst today’s estimate could be as much as a 40 times more, ie 200tcf. Nevertheless, pragmatists would agree that a new resource supply paradigm is neither simple nor linear as some would have us believe.

     

    Costs, time frame and culture 

    There were four factors which bolstered US shale gas prospection and these would be difficult to replicate on a similar scale in Europe. First, the US bonanza was neither a geological fluke nor achieved overnight. While the existence of shale rock has been known to geologists for a better part of five decades and modern hydraulic fracking debuted in engineering journals 20 years ago, it has only been within the last five years that US shale production has become commercially viable.

     

    Second, the US legal framework is more conducive when compared to Europe’s. Stateside mineral rights, unless the drilling site itself is actually on federal land, belong to the landowner. In Europe, rights belong to governments, which is why landowners’ attitudes and willingness to allow drilling would differ vastly. Industry regulations in the US are also more favourable when compared to Europe. For example, shale prospection is exempt from the US Safe Water Drinking Act (2005) and an EU concession of a similar scale is unlikely.

     

    Third, the US rural population density is not as high as in the UK/EU and drilling is often spread over vast tracts of uninhabited land. Concluding the American advantages, the progressive unbundling of US gas markets since 1978 and a vastly superior pipeline infrastructure has enabled American players to market and procure gas more effectively than European counterparts.

     

    Given such potential impediments, the medium-term impact of UK shale exploration might not be as positive as some within the sector would hope. Although domestic utilities are becoming increasingly active in the upstream market for the sake of security of supply it is unrealistic to expect them to be frontrunners in UK shale exploration.

     

    Imports and gas storage 

    Evidence suggests US plans for LNG shipping facilities, originally conceived as import terminals, are being re-drawn to convert them into export facilities. Many of these may begin exporting within this decade.

     

    Given the disconnect between US gas benchmark – Henry Hub – which saw a sub-US$2/mbtu contract in April and Asian and European futures benchmarks which are several times higher, there is a definite incentive to export. That these exports would eventually arrive in the UK is plausible but Asian markets are likely to be immediate beneficiaries.

     

    With North Sea gas production in decline and imports set to increase, an investment framework which supports UK gas storage is imperative. Putting things into perspective, UK has approximately 15 days-worth of gas storage capacity at any one time, against nearly 59 days in Italy, 99 in France and 122 in Germany (at current consumption levels). This leaves the country vulnerable to supply shocks.

     

    Energy mix post-Fukushima 

    The energy mix has three central planks – affordability, security of supply and low carbon. The most cost-efficient raw material from a utility sector’s standpoint over the short to medium term is natural gas despite its susceptibility to market volatility.

     

    After Fukushima, a number of questions were asked about the suitability of new nuclear as a viable energy source, and a number of countries embarked on a very public withdrawal of nuclear. A medium term solution to replace coal with gas, and ultimately renewable energy now seems inevitable. 

     

    Nobody question going down the renewable route - the real riddle is how governments pace the transition? The current time frame is aggressive and perhaps not thought through enough. In the existing economic climate, adding 25GW of renewable energy may generate good headlines but it’s an expensive process to get to that point. DECC’s impact assessment of the renewables strategy suggest a cumulative £12bn loss for the period up to 2030 assuming high fossil fuel prices, but if fossil fuel prices are low, due to compressed gas prices, this loss could reach £95bn.

     

    Importantly, the UK has not seen a knee-jerk reaction and remains committed to nuclear energy. As long as nuclear is affordable, the right question to ask is not if nuclear should be part of the energy mix, but how big a part its going to play in the future alongside gas-fired electricity.

     

    Tying loose ends with the Electricity Market Reform (EMR) 

    UK policymakers are on the right track with fresh recognition of the need for resource diversity, low-carbon power and security of supply via the EMR. However, the EMR is becoming increasingly complex with many different levels of subsidies and drivers of different generation components (gas, renewable and nuclear). This overcomplicates matters and feels like the Government has defined portions of acceptable technologies for the future energy mix rather than letting market forces dictate.

     

    Furthermore, although the taxpayer does not provide direct subsidies to the nuclear sector, the nature of the long-term contracts for them effectively replaces the need for subsidies. Gas-fired proposals do not benefit from any support and with the current investment hiatus, developers of plants are finding it extremely difficult to find any off-takers for their projects. Consequently, independent developers are nervous about progressing gas-fired facilities even if a medium-term opportunity is visible. We therefore believe gas generation has so far been slightly neglected as a resource, despite its fuel potentially being in abundance over the coming years.

     

    Lloyds Bank is committed to supporting the evolving UK energy mix by providing bespoke solutions to clients. As well as being a leading player in the UK, we continue to add to our client portfolio in what is a very pan-European business with able support from colleagues in capital markets and project finance teams.  

     

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7/21/2019 10:37:42 PM