8 Fossil fuels: end of the beginning, or start of the end?


In recent years, the UK and global fossil fuel marketplace has changed radically. Professor Stuart Haszeldine looks at the past, present and future of carbon-based fuels.


The discovery of North American shale hydrocarbon in 1998 and its subsequent rise has depressed fossil fuel prices worldwide. The effects have been profound. Coal prices have fallen by by 75% since 2011, and producers have been badly hit. For example, the world’s largest private coal producer, Peabody Energy, has declared bankruptcy while Vattenfall, Germany, has sold its lignite assets to Czech energy company EPH.


At the same time, RWE, ScottishPower (Iberdrola), and E.On, to name but a few, have split electricity generating interests between renewables and old school coal- based power.


In England, the last deep mine closed at Kellingley Colliery, bringing an end to centuries of deep coal mining in Britain. And in Scotland, opencast mine operator, Hargreaves, has ceased extraction due to the low price of imported coal, ultimately from US producers seeking new markets to cover the marginal costs of staying in business. All these actions directly affect the UK, and Europe. On the one hand, nations enjoy the availability of low-cost coal to power established generation assets. But generation companies are also deeply worried that the future of these former bedrock workhorses of electricity generation is now in serious doubt. Despite the European Union emissions trading scheme (EU-ETS) including coal and gas power plant, many owners had obtained copious grandfathered emission allowances at negligible cost.


For example, in the UK, a carbon price floor tax of £18 per tonne CO2 emission was introduced in 2013. Combined with pricing penalties of regional electricity generation, this proved sufficient to force the premature closure of Longannet, Europe’s third largest coal generating plant.


The EU-ETS is now being closely re- examined and will re-launch by 2020, when allowances will not be allocated free of charge but will be auctioned at €20-30/tCO2. This, coupled with the end of derogation and transition into the Industrial Emissions Directive in December 2023, will force continued closure of coal, or fitting of NOx scrubbing and eventually, carbon capture and storage schemes.


Still, retrofit conversions are usually very expensive, so any future for coal combustion within the EU will need to acquiesce to the tightest global standards, or achieve unprecedented success in lobbying for exemption.


Current state-of-play Coal aside, today, offshore oil and gas is by far the largest and best capitalised fossil fuel industry operating around the British Isles as well as internationally from UK organisations. Practically all focus during 2015 to 2016 has been on the selling price of Brent crude oil, which acts as a major benchmark price for purchases of oil worldwide. Previously reaching $140 per barrel in 2008, the price bottomed at around $38 and in June 2016,


crept back up to $50 per barrel. This rollercoaster ride of oil prices has dramatically altered the investment and production landscape of the UK continental shelf.


The newly formed Oil and Gas Authority is tasked with maximising economic recovery from the UK offshore sectors. For the past fifteen years, a ‘super-cycle’ of high oil prices, driven by economic expansion in China, has buoyed offshore prices. However, that super-cycle has been abruptly terminated following cheap US shale oil production decreasing import demands, Saudi Arabia determination to continue high volume production, and the re-entry of Iran to global exporting availability. The end result is, the marginal cost of the last extra barrel needed to satisfy a glut of demand may be just $10 or even as low as $2.


Although predicting the future is difficult, it is clear that shale oil regions of the US have substantial untapped availability for immediate production. Drill pads are built, water and hydrocarbon transportation pipelines are in place, and more than 2500 wells are drilled a year.


These are available for instant production, with the drilling costs of additional wells on established pads being minimal. Given this, it’s likely that the last extra barrel will be provided at a very low cost from the US for the foreseeable five years. And short of military action or revolution in the Middle Eastern states creating production shortages, global oil prices are unlikely to rise. The outlook for the next five to ten years is different, as large, expensive internationally tradable production runs to the end of its life and investment doesn’t enable a pipeline of projects to be available for immediate take up. At this time, global prices could rise, unless cheap hydrocarbon is available from shale in North America or new provinces in Mexico or Argentina. However, it is not all doom and gloom. In the North Sea, the BP Clair Ridge, west of Shetland, officially opened soon after the Scottish independence referendum. This £4.4 billion venture could produce 8 billion oil barrels to 2045 and beyond, and uses patented low salinity water injection from British oil giant, BP, to raise production efficiency by 2 to 4%.


Likewise, France-based energy giant, Total, recently opened a major gas project in the West of Shetland. But the greatest interest lies in the Norwegian sector following the discovery of the 2.9 billion barrel supergiant Johan Sverdrup field in the core of the North Sea, by Lundin Petroleum, Norway. The Norwegian oil sector is already at a greater efficiency than the UK. This is partially thanks to its greater state control of efficient planning infrastructure, and also to the policy of injecting methane to aid additional economic recovery right from the start of many oil production operations. With this shining example of foresight, could the UK government and the Oil and Gas Authority also create the same thirst for innovation and discovery of new giant oil accumulations? Or will the UK North Sea become a victim of accountants trying to reduce costs and Human Resource professionals downsizing staff that are not


directly linked to a profitable revenue stream? These are now critical months and years for the UK offshore hydrocarbon industries. Very few offshore assets are returning a formal profit to the UK Treasury, creating an inconvenient cash shortage. But that is also combined with the liability held by Treasury to share decommissioning costs as real cash payments.


If non-profitability tips into closure and decommissioning, than the small negative NPV line for abandonment expenditure cheerfully signed off 20 or 30 years ago, now becomes real and present spending problem. A real loss, though, would be the diffusion of person power and skills, and experience of the offshore industries, into the general UK economy. The wealth and diversity of offshore exploration and production is hard to recover. Take Aberdeen city and Shire, as well as many UK east coast towns. The disappearance of high-value, dispersed remote working from offshore hydrocarbons will not just dent house prices and car leasing, but will change the fabric of entire local economies.


Where is the future?


Underpinning all fossil fuel extraction lies the perceived and historical right to extract and use as much fossil hydrocarbon as desired. This drives the present dash for shale gas in England, halted by a moratorium in Scotland. Development is likely to be slow: tens of wells need to be drilled, fracked, and produced safely and securely before the economic and environmental operations can be related to the business costs. And, given the lower cost of importing hydrocarbons from the US, it isn’t even clear that UK shale will be commercially profitable. However, the UK agenda to decarbonise energy generation by at least 80% by 2050, from 1990 levels, is challenging hydrocarbon production. Right now, decarbonisation is being achieved by the relatively easy actions of fuel switching from coal to gas. Also, the closure of energy intensive industries, such as steel manufacturing at Redcar and Port Talbot, as well as coal production at Longannet and Ferrybridge, has contributed. However, at the UK Treasury Spending Review in November 2015, a CapEx support of up to £1 billion for CCS projects was withdrawn, although the OpEx additional price of electricity still, theoretically, remains. Subsequent to this, most commercial CCS activity in the UK has been cancelled. This leaves two large problems: how will the Government accommodate the Committee on Climate Change recommended carbon budget for 2027-32, to be decided in mid- 2016. And, how will decarbonisation towards those dates be achieved without CCS? Indeed, many predictions for the energy whole-system suggest decarbonisation costs will at least double in the UK without CCS.


The United Nations Framework Convention on Climate Change agreement, COP 21, from December 2015, commits signatory countries to a balance of net-zero carbon by mid-century. This means each tonne of fossil carbon extracted must be balanced by one- tonne of carbon mitigated or stored. Can we do this without CCS?


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