Here you will find regular updates on some of the most notable research outcomes generated by our team of analysts.
OPEC Cuts into 2018? (see Energy Market Report– May 16, 2017)
- The prospect of production cuts stretching into 2018 has been raised by Saudi Arabia and Russia
- In a no cut extension scenario, we see 2018 total liquids balance as being strongly oversupplied by some 1.6 million b/d
- The potential extension of the cuts program to the end of March 2018 would not alter this picture drastically
- Only if we assume strong compliance with cuts for the whole of next year can we envisage a market which comes closer to be balanced
A combination of changes to crude slates, weaker consumption of secondary feedstocks, and the simple factor of strong margins and spare capacity can be used to explain very high US refinery utilisation (see Global Refinery Margins – Issue 18)
- A simple addition of maximum capacity in each PADD, alongside recent capacity additions, mean runs could rise to as high as 17.8 million b/d this summer.
- However, we find it very difficult to balance global products at this level and would favour intake averaging only slightly over 17 million b/d this summer
- There is nevertheless strong potential for brief periods of high intake to do damage to Atlantic basin refinery margins this summer.
A look ahead to 2018 oil supply (see Market Watch– Issue 4)
Key drivers of 2018 oil supply growth:
- We see North American liquids production increasing by 900,000 b/d compared to 2017 on the back of new streams from Canada and US shale oil
- The shown 650,000 b/d rebound from the Middle East will only come in case the cut regime will not be extended
- African supplies are set to increase 450,000 b/d y-o-y on the back of new WAF projects and a moderate recovery from Nigeria and Libya
- Additional Brazilian supply is almost entirely eaten up by expected declines from Venezuela
- Russia and Kazakhstan will drive the liquids supply increase of 120,000 b/d y-o-y for the FSU region
Asian gas production is in dire need of investment (see Natural Gas Insight – East of Suez – Issue 8)
- We have revised 2017-2018 Asian natural gas production down this year compared to our 2016 figures
- Most of the downward revision came from Australia, where investment has been curtailed while projects have frequently been delayed — insufficient production and export commitments may lead Australia to import LNG in upcoming years
- China, Indonesia, and Malaysia have been slightly revised upward, but production potential is much higher if investment were to be bumped
After a brief pause, US gasoline yields returned to the strong y-o-y declines observed over most of the year so far (see Americas Weekly – Issue 15)
- While some of the decline in gasoline yields is likely being caused by extremely strong utilisation levels, relatively narrow mogas/ULSD spreads may also be coming into play
- This is preventing more bearish gasoline stockbuilds even with crude intake nearly maxed out
- Still weak Latin American refining also means that US players can continue to effectively place additional barrels abroad (US gas oil stocks are still drawing, with some help also coming from better domestic demand)
The combination of push factors due to a much longer Atlantic Basin crude balance and pull factors due to a much larger shortfall in East of Suez has driven a surge in interregional crude arbitrage (see Asian Oil Monthly – Issue 4)
- Crude shortfall on the back of OPEC supply cuts has driven a surge in the relative value of Dubai vs. other benchmarks
- This coincided with a much longer balance West of Suez, allowing Atlantic Basin crude to move eastwards and plug the gap
- Fixture data illustrates how increased flows have been sourced from a variety of regions, including Latin America, the US, and Europe on top of a West African surge
- Rising crude demand West of Suez should crimp the push factor from this point and is expected to see a gradual slowdown in arbitrage flows
Russian production of sweet crudes is on an upswing – an important element in the potential production of low-sulphur residue streams (see FSU/CEE Insight– Issue 13)
- In the context of our bunker fuel study regarding last year’s IMO decision to limit sulphur levels in bunker fuel to 0.5% from 2020 onwards and our conclusion that compliant bunker fuel will essentially be a fuel/oil residue blend, we analyze what role Russian fuel oil production can play in this equation.
- First, production of light and sweet crudes in Russia has been slightly above 700,000 b/d last year, expected to reach levels of 850,000 b/d in 2020 mostly due to higher condensate volumes. These crudes would theoretically be able to provide an easy source of low-sulphur residue streams.
- In addition to this, there are possibilities for changes in conversion operations and/or increasing utilisation of Russian simpler refining capacity.
- For inquiries into more details about our comprehensive bunker study please refer to email@example.com
Saudi crude burn drops sharply (see Natural Gas Insight – East of Suez– Issue 6)
- The Middle East is expected to see declining levels of direct crude burning over the coming years, with Saudi Arabia and Iraq driving the reductions. In recent years, the region made impressive progress in reducing the use of gas oil/diesel in the power sector and crude is next in line to be phased out.
- Following several years of low oil prices and large budget deficits, Saudi Arabia is taking steps to protect oil exports and is instead using natural gas, fuel oil and renewables to fuel growing demand from the electricity and desalination sectors. Under its Vision 2030, the kingdom also intends to massively expand renewables capacity and reduce its elevated per capita energy consumption.
- The country will see the addition of significant natural gas and fuel oil power plants by the end of the decade, while any impact from renewables or nuclear is unlikely to be felt until the 2020s.
FSU East total liquids production expected to be up by over 200,000 b/d y-o-y in 2017 (see FSU/CEE Insight – Issue 11)
- Russia targets to increase production this year despite the cuts in H1. In our base case assumptions, we do not see the cuts as being extended and expect a rebound in production over H2. As new projects such as Filanovsky and East Messoyakha are being ramped up at the moment, we see overall crude and condensate production increasing by 120,000 b/d y-o-y to 11.1 million b/d on an annual average.
- Kashagan production is expected to reach 200,000 b/d on an annual average, which helps boost Kazakhstan’s crude and condensate production by some 140,000 b/d y-o-y to 1.7 million b/d in 2017.
- On the back of declines from the important ACG fields, we see overall crude and condensate production from Azerbaijan declining over 5% y-o-y in 2017, which represents just above 40,000 b/d.
- We see other FSU East output declining by 7,500 b/d y-o-y to 210,000 b/d.
Bearing in mind shale’s relatively high reactiveness to pricing and also the wide variance in well production profiles, we have also modelled low and high case scenarios for US production over the next two years (see Americas Weekly – Issue 10)
- The difference between the two scenarios is a potential 1 million b/d swing in 2018.
- The low case scenario assumes basically no growth from here (2018 average output of slightly above 9 million b/d), with additions in the Gulf of Mexico offsetting declines in onshore production. In this case, the rig additions were assumed to only be enough to maintain current production levels on the premise of accelerating decline rates for existing wells and disappointing initial production rates at new wells.
- The high case scenario (2018 output slightly above 10 million b/d) assumes production increases over the next two years similar to those seen at the peak of the shale boom, predicated on the majority of new rigs being positioned in ‘sweet spots’ with high - and relatively sustainable - initial flows.