Maarten van Mourik

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                    [post_content] => Each oil price crash has brought with it talks of decommissioning, and of bringing down the curtain on North Sea production once and for all. Despite this grim outlook, caution must be taken not to tarnish the whole region with a single brush. The outlooks for the UK and for Norway differ quite substantially. At present, both countries are benefiting from the fruits of several years of high and stable prices, which filled producers with a false sense of confidence, allowing them to chase projects at seemingly any cost. However, one year of low oil prices has transformed the outlook. The UK will benefit in the next two years from new project start-ups and from producers shifting capital to maximize short-term output to manage the downturn. But beyond the short-term respite, UK production is likely to fall as decline rates accelerate, and as the investment, along with the expertise, of IOCs exits the basin.

For Norway, the reserve base is much higher so the challenges are different. There has not been a mass exodus of major players from the basin, although managing high declines and rising costs remains a tall obstacle to overcome. Total capacity additions between 2015 and 2020 equate to 0.82 mb/d, although without the giant Johan Sverdrup field (which is a story for the next decade as it is only due to come on stream in late 2019) additions are only 0.51 mb/d and very front-end loaded. Therefore, by H2 16, it is likely that Norwegian production will stagnate or even start to decline. This is particularly true as offshore production is expected to be impacted by reduced amounts of infill drilling, as IOCs look to reduce Capex.

Whilst new areas – such as tight oil – have a lot of scope for efficiency, mature basins will struggle to achieve similar efficiency gains and to push service costs down. High costs, declining reserves, growing decommissioning activity in the UK Continental Shelf (UKCS), and plummeting tax revenues for governments are forcing through some very difficult decisions, which arguably should have been made many years ago.
                    [post_title] => Has the North Sea entered a late-life crisis?
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                    [post_date] => 2014-10-20 11:02:25
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                    [post_content] => Less than 10 years ago, at the height of the commodities boom, Brazil was all but assured a place as an oil world powerhouse following the discovery of oil in its subsalt basins. Much faith has been put in Brazil delivering the barrels needed to keep the medium-term oil market in reasonable balance. Whether it is the IEA, EIA, OPEC, major oil companies, or indeed the Brazilian government, all projected the country’s oil production to increase substantially in the coming years. This optimism was brought to the forefront of the global oil and gas industries by the 2007/2008 discovery of the vast pre-salt basins, specifically the Tupi field. This ranks alongside Kashagan as one of the largest and most significant oil discoveries of the past few decades and the biggest in the Americas since the Cantarell field in Mexico in 1976. However, as has often been the case in recent history for the oil markets, a number of project delays and cost overruns have since taken the shine off the initial optimism, and has also kept Brazil from playing a bigger role in the non-OPEC supply picture.

So what has slowed the progress in the Brazilian oil sector? This paper argues that Brazil’s upstream sector faces a number of key challenges, including: regulatory barriers; a massive financial burden, consisting of the world’s largest corporate expenditure programme and increasingly funded by debt; high production costs and high decline rates; caps on domestic fuel prices, which have adversely affected Petrobras’ earnings; and waning interest from major international oil companies (IOCs) in co-financing projects. The country's deep-sea bonanza has become less alluring, whilst oil companies have also been adapting to a changing energy landscape, altered by a focus on capital discipline, shale in the US, and the emergence of other frontier energy sources, such as in deepwater Africa or oil sands in Canada.
                    [post_title] => Challenges across Brazil's oil sector and prospects for future production
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            [post_content] => Each oil price crash has brought with it talks of decommissioning, and of bringing down the curtain on North Sea production once and for all. Despite this grim outlook, caution must be taken not to tarnish the whole region with a single brush. The outlooks for the UK and for Norway differ quite substantially. At present, both countries are benefiting from the fruits of several years of high and stable prices, which filled producers with a false sense of confidence, allowing them to chase projects at seemingly any cost. However, one year of low oil prices has transformed the outlook. The UK will benefit in the next two years from new project start-ups and from producers shifting capital to maximize short-term output to manage the downturn. But beyond the short-term respite, UK production is likely to fall as decline rates accelerate, and as the investment, along with the expertise, of IOCs exits the basin.

For Norway, the reserve base is much higher so the challenges are different. There has not been a mass exodus of major players from the basin, although managing high declines and rising costs remains a tall obstacle to overcome. Total capacity additions between 2015 and 2020 equate to 0.82 mb/d, although without the giant Johan Sverdrup field (which is a story for the next decade as it is only due to come on stream in late 2019) additions are only 0.51 mb/d and very front-end loaded. Therefore, by H2 16, it is likely that Norwegian production will stagnate or even start to decline. This is particularly true as offshore production is expected to be impacted by reduced amounts of infill drilling, as IOCs look to reduce Capex.

Whilst new areas – such as tight oil – have a lot of scope for efficiency, mature basins will struggle to achieve similar efficiency gains and to push service costs down. High costs, declining reserves, growing decommissioning activity in the UK Continental Shelf (UKCS), and plummeting tax revenues for governments are forcing through some very difficult decisions, which arguably should have been made many years ago.
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