Brian Songhurst

Research Associate

Brian Songhurst has an honours degree in chemical engineering from Imperial College London and is a fellow of the Institution of Chemical Engineers. He has 50 years of experience in the oil and gas industry, working for engineering contractors, operators, and specialist consultants. He is a past chairman of the Institution of Chemical Engineers Subject Oil & Natural Gas Group (SONG), which provides technical networking among its members to deliver best practices within the chemical engineering community. He has held senior positions in engineering, projects, and sales, and has led engineering and process design teams for gas processing, offshore oil & gas, refinery, and petrochemical facilities around the world. He recently retired and his last position was director of LNG for London-based consultancy ThyssenKrupp Uhde Energy and Power and managed a variety of LNG projects for both onshore and offshore (FLNG) applications. He was previously engineering manager with MW Kellogg, one of the world’s leading LNG contractors, and facilities engineering manager with J Ray McDermott, one of the world’s leading offshore contractors.

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                    [post_content] => Since the highs of 2010–14 the cost of liquefaction plants has fallen significantly – in some cases by up to a third for a similar scope. This paper reviews the costs of 25 plants constructed in the last 4 years and determines the reasons for these reductions. The reported project costs (CAPEX) are divided into upstream and liquefaction to determine the unit costs of liquefaction ($/tpa).

These unit costs are classified by the key drivers of plant scope, plant complexity and plant location to determine factors that could be applied to prepare preliminary estimates for future projects to account for whether they are a brownfield expansion or new grassroots plant, processing rich associated gas or lean gas and if located in an industrialised area, remote location or Australia. Operating costs (OPEX) are evaluated and added to provide indicative production costs expressed as $/mmbtu again for different plant scopes, complexities and locations.

Areas for future cost reduction are also proposed including industry standard specifications, new enabling technologies and EPC contract strategies. Some of these are already being applied but many upcoming projects could probably benefit from them.
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                    [post_content] => FSRUs are a game changer providing a lower cost, fast track and flexible alternative to traditional onshore LNG import terminals. The first unit entered service in 2005 and today there are 23 FSRU terminals in operation. FSRUs are normally leased and can be viewed as a flexible pipeline supplying gas quickly, cheaply, and on a short term gas contract basis to developing markets. This was recently demonstrated in Egypt with delivery of gas in just 5 months from issue of the tender documents – very different from an onshore terminal which is a sunk cost and typically takes 4-5 years to construct. Many of the current, and planned, FSRU terminals are for the rapidly increasing gas-to-power market where there is no access to existing gas infrastructure. Forecasts indicate that up to 50 floating LNG terminals could be in operation by 2025. This confidence is demonstrated by the owners ordering new vessels at a cost of $250m each on a speculative basis.
                    [post_title] => The Outlook for Floating Storage and Regasification Units (FSRUs)
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                    [post_content] => The softening of European hub prices and Asian LNG spot prices in early 2014, followed by the plunge in oil prices later that year has created an extremely challenging business environment for the LNG industry.  Current prices – whether spot or oil-indexed LNG contract prices - are well below levels recently regarded as necessary for projects to achieve FID.  Against this background, it is a testament to the resilience and adaptability of the LNG industry that it is embarking on an ‘experiment’ to test the hypothesis that FLNG provides a means by which stranded gas discoveries can be monetised and, perhaps more fundamentally, that with its shorter lead times, lower fabrication execution risk and the entrepreneurial vibrancy which comes from competing providers and approaches, FLNG could prove more generally to be more viable than conventional onshore liquefaction plant.  Following from his 2014 paper on LNG plant cost escalation, Brian Songhurst provides a comprehensive review of the state of play of FLNG, the competing approaches and the advantages and disadvantages compared with conventional onshore liquefaction.  Brian also hints of further potential technology step-out in FLNG once the first wave of projects is successfully commissioned.  The lessons of the post-2009 period have, it can be argued, demonstrated the need for the LNG industry to address both cost base and contractual price formation mechanisms if it is to remain a viable channel for the delivery of gas in the world’s fast growing markets.

Executive Summary
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                    [post_content] => The Oxford Institute for Energy Studies has recently published a paper which examines the rapid unit cost increases exhibited by the LNG industry since the turn of the century. Between 2004 and 2009 the economic growth of the BRICS and their commodity import and investment requirements increased the price of oil and other commodities but also the unit investment costs in capital intensive industries.  These costs almost doubled in real terms during this period. On the face of it the impact on liquefaction plant costs appeared to be significantly more pronounced.

Since 2010 regional natural gas prices have diverged and the prevailing assumption in the oil and gas industry has been that at present levels of liquefaction costs, only Asia represents a viable market for new LNG projects.  With the prospect of US LNG exports, where existing re-gasification terminals are to be converted into export facilities through the incremental investment in liquefaction plant, it is plausible that LNG trading and arbitrage could yield sustainable hub prices (at today’s development cost levels) of US: $5-6/mmbtu; Europe $10 – 11/mmbtu and Asian LNG $12 – 13/mmbtu.

In addition to the significant competitive advantage for the US deriving from these lower gas prices, the ability for gas to compete with coal in power generation in Europe and Asia is doubtful without robust policy support, with obvious implications for CO2 emissions. Such regional gas price differentials in such a scenario are directly influenced by the assumption of the continuation of today’s liquefaction (and to a lesser extent shipping) costs.

In this paper Brian Songhurst assesses the reasons for the liquefaction cost level increases in the last decade by placing the available data into a framework in which an objective comparative analysis is possible.  He also discusses trends in the LNG project construction and execution sector which should lead to cost reductions over time.
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These unit costs are classified by the key drivers of plant scope, plant complexity and plant location to determine factors that could be applied to prepare preliminary estimates for future projects to account for whether they are a brownfield expansion or new grassroots plant, processing rich associated gas or lean gas and if located in an industrialised area, remote location or Australia. Operating costs (OPEX) are evaluated and added to provide indicative production costs expressed as $/mmbtu again for different plant scopes, complexities and locations.

Areas for future cost reduction are also proposed including industry standard specifications, new enabling technologies and EPC contract strategies. Some of these are already being applied but many upcoming projects could probably benefit from them.
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Latest Publications by Brian Songhurst

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