Month: September 2018

How the IMO Got the Sulphur Cap so Wrong

Opinion piece published by Splash 247.com on 07 September 2018 (link)

Amidst the wave of content on the IMO’s 2020 implementation for 0.5% sulphur bunkers, most shipping commentators are either missing or deliberately evading one point — the IMO screwed up massively.

Although the IMO works hard to promote a safer maritime industry and cleaner environment, the IMO 2020 decision at MEPC 70 was an abject fail.  As of October 2016, the refining industry was never going to be ready for a January 2020 implementation.  Given existing capacity and anticipated projects — sufficient upgrading, desulphurisation and support capacity would not be available to eliminate 2-3 mbpd of the higher-sulphur resid streams and to provide sufficient distillate for 0.5% sulphur fuel blending.

The refining industry knew this, but the IMO had its own agenda.  Unsurprisingly, their paid consultants provided a report that told the agency exactly what it wanted to hear (sufficient 0.5% sulphur fuel would be available), so that it could pursue its desired policy direction.  Not leaving things to chance, the IMO came equipped with an August 2016 study from the Finnish Metrological Institute that suggested that a delayed 2025 implementation would cause 570,000 premature deaths.  Regulatory job done.

Meanwhile, back in the commercial world, market participants are struggling to adjust to these regulations, exploring new fuel blends that could meet the 0.5% spec from expected blendstock availability.  Although refiners can meet much of the demand from increased gasoil and vacuum gasoil volumes, and by using lower-sulphur resid streams, a view is emerging that 0.5% supply would fall short by 1.0-1.5 mbpd initially (including from the IEA and Wood Mackenzie).  This volume of higher-sulphur resid would remain stranded, while additional gasoil would be unavailable to meet this shortfall.

Available at a cost, of course, yet the oil price commentary remains anodyne, suggesting that after some initial confusion, the markets will adapt and reach a suitable equilibrium.  Of course, that equilibrium mechanism is price, and strict enforcement of IMO 2020 would require a massive auction process to price other mid-distillate users out of the market — trucking companies, airlines, home heating oil consumers, farmers, railroads and industrial users. Additionally, individuals needing proof income would face significant challenges in this scenario. For those who work in the industrial business, consider using a heat recovery steam generator for your products. Additionally, for those who rely on paystub as proof of income, it’s important to consider the potential impacts of strict enforcement of IMO 2020, as it may require a massive auction process to price other mid-distillate users out of the market.

Auction processes are messy, clouding the oil price picture.  The IEA has suggested a jump in gasoil prices of 20-30% in 2020, while Morgan Stanley has argued similarly for US$850/tonne gasoil and US$90/bbl Brent prices.  Veteran oil analyst, Philip K. Verleger, sees a dire outcome from IMO 2020, with crude oil prices exceeding US$200/bbl.  His message may seem alarmist, but he has assessed the impact of a full implementation.  The other analyses are balancing lower compliance rates with the price levels required to destroy enough onshore distillate demand.

Oil market participants are aware of this, and thanks to the July testimony of oil analysts before the U.S. Senate, IMO 2020 is now firmly on Washington DC’s radar.  The unpleasant response to IMO 2020 signalled that incumbent politicians are unlikely to tolerate this sort of economic disruption during an election year.  In fact, the Senate tasked the US Environmental Protection Agency with studying the financial impact of IMO 2020, just days after those hearings.

Meanwhile, the IMO has become increasingly combative on the subject, with officials insisting on no delay and that “excuses are thin”.  They cite the long timeline to amend the regulations for their inability to defer the timing, yet have rushed through tougher enforcement rules.  The IMO is set to adopt MARPOL amendments to prohibit the carriage of non-compliant fuels on vessels without scrubbers at MEPC 73 this October, so that they can enter into force by March 2020.  Nothing signals a bureaucratic organisation so wildly out of touch with reality, as one pushing tougher enforcement of a condition that cannot exist.  The IMO should concentrate on accommodating the growing view that non-compliance will be widespread and may represent 30% of current HSFO bunker usage.  This redirected focus, however, would require the IMO to admit their regulatory failure at MEPC 70, which is unlikely.  The stakeholders at risk from IMO 2020 have limited time remaining to force greater realism at MEPC 73.

Permian Takeaway Constraints and US Crude Outlook

During the past year, we have endured the ubiquitous Permian crude production versus pipeline takeaway charts, showing forecast crude output running well above anticipated pipeline capacity.  These charts may highlight the obvious shortfall in takeaway capacity, but the physics is dubious.  Although pipeline operators can take actions to boost pipeline throughput above the stated capacity, and are certainly scrambling to add any capacity to their Permian systems, crude outflows from the region are still limited to something near these capacity figures.  Regional pricing differentials are now signalling full pipelines, with the negative spread between WTI Midland and WTI Houston sliding towards the US$21/bbl record lows seen in August 2014.  With meaningful pipeline capacity unavailable until mid-2019, Permian production will need to flatten over the next 12 months.

Estimates for rail and trucking takeaway capacity from the Permian Basin vary, but the consensus is that these transportation modes are limited to only 100-150 kbpd.  The following chart shows our Base Case assumptions for rail and truck movements, versus the required volumes, based upon production and pipeline capacity forecasts.  The need for these outlets is short-lived, and disappears once the new pipelines come on line.  This timeframe is too short for producers to commit to the longer take-or-pay contracts that railroads would demand for the same reason, so this approach would remain limited.

This places significant pressure on Permian producers to limit production without an outlet.  One approach is to stop adding oil rigs to the basin.  The pace has certainly slowed during the past few weeks, averaging a little more than one a week since June, but the rig count needs to decline soon.  The following chart provides our Base Case forecast for oil rigs in the five major LTO basins, and suggests that Permian rigs need to move towards 430 by mid-2019, from the current 486 count.  Oil service companies are suggesting that the Eagle Ford and other LTO basins may benefit from rig redirection from the Permian.  Rig counts rebound in the Permian once the new pipeline capacity comes on line, but drilling activity jumps in all basins during 2h19 and 2020, on higher oil prices from global tightness and IMO 2020.  Typical cyclicality returns in 2022-23, as another LTO supply surge hits slipping demand from the 2020 price shock.

The other approach to stifling Permian production is to not complete wells.  This would further swell the inventory of drilled-but-uncompleted (DUC) wells in the basin, but this is probably the most effective approach.  As shown in the following chart, as of July 2018, EIA data indicates that Permian DUCs have surged by 80% yoy, to 3,468, which represents an inventory of 8.0 DUCs per well completion.  Producers will always have some inventory of DUCs awaiting completion crews, but this measure provides some indication of the backlog relative to completion activity, and hence, crews available.  Given the anticipated rigs, rig productivity, initial production (IP) rates and decline rates, Permian DUCs would need to rise to almost 5,000 by mid-2019, with DUCs per completion jumping to 14.8 in 1q19.  This would keep well completions near 400 per month and production limited to 3.6 mbpd, consistent with pipeline capacity until mid-2019.

The arrival of new pipeline capacity would prompt a release of the DUCs accumulated during the constrained output, but the anticipated rise in oil prices would also support a decline in DUC inventory.  The DUC cycle reverses once prices decline in 2022-23.

Although the EIA does forecast some flattening in the growth of US crude oil production in its Short-term Energy Outlook (STEO), our Base Case forecast is 200 kbpd lower during the last nine months of 2019, as shown in the chart below.

Our forecast then exceeds the EIA outlook by 900 kbpd during 2021, from higher oil price and resulting rig count assumptions.  For example, the latest STEO expects WTI prices of US$64.33/bbl during 2019, a 2.8% decline from their 2018 expectations of US$66.18/bbl.  One hint that the EIA price outlook may be too low — hardly any widening in the diesel-fuel oil spread in late-2019, as if IMO 2020 does not exist.

Deteriorating Turkish Oil Demand Outlook

Turkey has remained a key culprit in the current emerging market mayhem that has become an investment theme and concern over the past couple of months.  Along with the Argentina Peso, Indonesian Rupiah and the South African Rand, the Turkish Lira has led an emerging market currency rout, with August average spot values representing a 41% yoy decline versus the US Dollar, as shown in the chart below.

This currency collapse reflects several perversities of Turkish economic mis-management, and has already driven 17.9% yoy retail inflation in August.  With this plunge in the Lira, the local currency price of oil has skyrocketed, as illustrated below:

 

The indexed price of Brent crude in Lira has tripled yoy and is double the previous peak in early-2014, while Brent in USD terms remains stuck well below those peaks.

Until the current oil price shock, Turkey had enjoyed several years of sustained oil demand growth, from both income and price elasticities, as real GDP growth crested at 7.05% yoy in 2017.  Middle-distillate demand, driven by economically-sensitive diesel, dominated this growth.

 

In fact, during 3q17, Turkish mid-distillate demand represented 26% of total European yoy growth in these grades, as local demand growth hit 15% yoy.  During the quarter, Turkish total oil demand exceeded 1.1 mbpd.  Still, even before the recent crisis, Turkish oil demand was already weakening, with yoy declines in total demand during May and June 2018.

 

This weakness should continue, from both price and income elasticities, given the sharp spike in Lira-denominated oil prices and the deepening economic crisis.  The IEA should be revising their Turkish oil demand forecasts downwards, but as a policy, remain constrained by IMF country outlooks.  In its April 2018 World Economic Outlook (WEO), the IMF had forecast Turkish 2019 real GDP growth at 3.97%, while the current consensus is calling for a 0.5% yoy decline and is slipping.  This drop in real GDP should be worth about 80 kbpd of total oil demand from the previous IMF income levels, but we will wait for the July demand numbers before refining our forecasts.