Surge in Product Tanker Demolition during 2021

As we migrate back to performing tanker research, with a focus on products, we thought that, rather than starting at the beginning, that we would start at the ending — demolition. Both owners and shipbrokers have breathlessly highlighted the near-record clean tanker demolition this year, which should exceed 3.2 mdwt, under miserable market conditions and elevated scrap prices.

This is an impressive jump from the 0.8 mdwt scrapped in 2020, with MRs taking a proportionate share, at 1.4 mdwt. Still, the product tanker fleet has expanded by 53% since 2010, so as a percentage of the fleet, 2021 is just another uncomfortable 2% demo year for owners. The post-crisis peak of 3.7 mdwt scrapped in 2010 represented 3.5% of the fleet, and subsequent years have featured binary behaviour of either demo of 0.5% of the fleet or bad market scrapping of 1.5-2.0%.

One clever shipbroker has observed the sharp drop in the average age of product tanker scrapping during 2021.  Not only does the volume of scrapping pick up during market troughs, but also, the average age drops, slipping below 24 years in 2021. This demolition age is approaching the younger ages of crude tanker scrapping, in place since the financial crisis. Generally, crude tankers face tougher vetting, and have fewer trading opportunities for older vessels than product tankers.

We use 4-quarter moving averages, since the quarterly series is volatile, even with dwt-weighted ages.  The spikes above 30 years of age are from smaller tanker demolition, and removing them lowers the recent averages by a year.

Generally, the smaller tankers have older demolition ages, since they have more opportunities to trade at senior ages, typically on coastal trades.  Note the 25-year average demolition age for MRs.  Remember this, the next time Scorpio (STNG) or another product tanker owner shows investors a chart with the number of MRs turning 15 years old.

Younger scrapping can happen, but only 11% of the vessels scrapped since 2009 have been below 20 years old (MRs only 8%).  Most of these younger vessels were from lower-quality, 2nd & 3rd-tier shipyards.

Still, when owners get serious about demolition, they scrap younger tonnage, hence the drop in average ages during weak markets and demo surges.  This cycle, owners scrapped few ships near the usual 5th special survey at 25 years, with several near the 5th Intermediate of 22.5 years and the 4th special at 20 years old.

MR owners have proven particularly pessimistic during this year’s demolition purge, with 30 vessels heading to the breakers. Scrapping of 25-year-olds and over remained consistent with previous years, but demolition of 22.5-year-olds near the 5th intermediate survey dominated. As a result, the average demolition age for 2021 should be near 22.7 years.

Looking forward, scrapping volumes will depend on the modelled rate environment, but an improvement in clean rates should see a return to more normal demolition ages.

One factor driving the younger tonnage demolition has been the lack of traditional 25-year old candidates, which should improve in late-2023 and 2024. If the clean market remains healthy, then the average age should return to the 26-year old level during this period.

This chart also highlights the ageing of the product tanker fleet and how the boom-period tonnage of the 2000s will start approaching their critical surveys at the end of the decade. How this plays out will depend upon how the marine energy transition evolves and how briskly owners order new compliant tonnage. We will examine some of these decarbonisation ordering/demolition scenarios in the coming months.

A pragmatist’s guide to MEPC73

Opinion piece published by Splash 247.com on 23 October 2018 (link)

During this week’s 73rd session of the Marine Environment Protection Committee (MEPC73), the IMO can count on broad support from a variety of players, including the beautifully-named Clean Shipping Alliance 2020 (CSA 2020).  Its mission is “to provide information and research data to better inform” on the benefits of scrubbers, but in reality, the 25 founding members of this group are major shipowners and key charterers who have already secured scrubber installations predominantly in advance of 2020.  Seeking to protect  multi-million-dollar scrubber investments, CSA 2020 cites its commitment to the “implementation and effective enforcement” of IMO 2020.  Their enthusiasm for enforcement is particularly fervent — since it would ensure high gasoil prices and wide spreads over HSFO, providing strong returns on their scrubbers, while inflicting financial damage on competitors without scrubbers.

Although most industry participants can recognise the hypocrisy of CSA 2020’s environmental posturing, several other key players stand to benefit massively from a chaotic IMO 2020 implementation, and are skewing the narrative.  In addition to shipowners who have already secured scrubbers — oil producers, large oil traders, sophisticated refiners and any refiner building a coker or resid cracker at the moment all have an economic incentive to insist on robust IMO 2020 enforcement.  In doing so, these players will all cite “fairness” and “level playing fields”.

With committed environmentalists like these behind the scenes, the IMO should emerge from MEPC73 claiming unqualified success, and full industry support for IMO 2020 timing and its tough enforcement, including the March 2020 non-compliant fuel carriage ban.  The agency will also signal only limited industry pushback.  After all, the four major flag states and three ownership groups that submitted a paper to the IMO calling for a “pragmatic enforcement approach” and an “experience building phase” did a dramatic volte-face, and pledged unwavering loyalty to IMO 2020 timing and strict enforcement, including promises of “concentrated inspection campaigns” by port states.

Meanwhile, the IMO has developed a FONAR (fuel oil non-availability report) form to be submitted by vessels to their flag states and various port states.  Although this framework might work within the IMO’s vision of only spotty compliant fuel non-availability, it would represent another regulatory misstep in an environment of widespread non-compliance, as seen by the IEA, OPEC and several major oil consultancies.  If their forecasts are correct, hundreds — if not thousands — of FONARs would flow daily into the collective inboxes of the flag and coastal states.  It remains unclear how they would judge between “good” FONARs and “bad” FONARs, but the point is probably moot.  The IMO has threatened bombastically that if vessels submit more than two or three FONARs, “there’s going to be problems”.

Ultimately, within the next year, leadership in the shipping industry will need to recognise IMO 2020 for what it is — a colossal regulatory fail — and to be willing to act.  As expected, the Trump administration indicated its desire for a gradual IMO 2020 phase-in, given concerns about an oil price spike and recessionary risks.  In response, the media and analysts have been dismissive of the US position, arguing that the 22-month IMO process to amend MARPOL and resistance from key IMO members would thwart any US attempt to delay implementation.  This is absolutely true, but these commentators are missing the point and are not thinking outside of the IMO box.

To the extent that oil prices spike during a 2H19 switch to MGO and onshore/on-vessel inventory builds, thus posing broad macro risks, the required postponement of IMO 2020 would not occur within the IMO framework — but outside of it.  Although this outcome is beyond the imaginative realm of most MEPC participants, other, more-credible national and supranational bodies have also recognised the threat that IMO 2020 poses to the global economy, and may be questioning the IMO’s regulatory competence at this point.  Given the farce that ballast water management has become, and the worrying trajectory that the sulphur cap is taking, the IMO has displayed a chronic inability to balance its environmental protection responsibilities with commercial and economic pragmatism.

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.

 

 

Oil market angst over recent jump in EIA crude production forecasts

In addition to recent financial markets turmoil, the crude markets have been under price pressure from concerns over surging US crude production, punctuated by a sharp upgrade in forecasts from the EIA in its Short-Term Energy Outlook (STEO) this week.  In fact, the February STEO featured a 317 kbpd jump in its 2018 forecast for US crude production from its January report, which was also 668 kbpd above its October forecast (shown above).

The April 2018 WTI contract has given up more than $5/bbl this week on these concerns, which may be overstated, since re-benchmarking and methodology adjustments have driven the surge in EIA estimates.  After all, the latest weekly estimate of US crude production (for the week ending 02 Feb) jumped by 332 kbpd week-over-week, to 10,251 kbpd, after averaging 28 kbpd of weekly gains during the previous 13 weeks.  Similarly, the monthly data for November 2017, released a week ago, surged by 384 kbpd over the October estimate, also reflecting the recent changes in EIA modelling and reporting.

The EIA actually tried to inform market participants about these changes ten days ago in a presentation, following up on a November 2017 webinar.  Most oil analysts recognise this and know that the EIA will make upward adjustments their historical database accordingly.  This higher level of crude production has already flowed through the system and the price movements reflect this.  The supply/demand balance has not changed and the near-term rises in production are consistent with the recent rise in rig counts and estimated rig productivity.  Only market perception has changed.

PADD1 Clean Tanker Demand Outlook Nov17

Clean tanker demand for the US East Coast (PADD1) is resuming its previous declines, on weak fundamentals.  Slowed by weak demographics, PADD1 gasoline demand will face tepid vehicle-miles travelled and the continued growth of electric vehicles (EVs).  Meanwhile, fuel switching to natural gas for home heating is providing a structural decline in heating oil demand, offsetting rising trucking demand for diesel.  Despite all of the angst over PADD1 refining, the region’s plants account for only 20% of clean product supply, and PADD1 is essentially a large blending centre reliant on the USG (PADD3) to meet demand.  Stable pipeline flows and rising Jones Act tanker movements will cut into imports and tanker demand.  Lower inventories and a colder winter could boost demand this season.  Download the Executive Summary of the presentation here.

Crude Tanker Outlook Oct16

Crude tanker market may face lower earnings for longer than consensus — Although analysts are finally marking down their crude tanker spot earnings forecasts for 2017-18, they may be under-estimating the depth and duration of the downturn.  The current market view continues to deteriorate, but it still expects earnings to remain above break-even rates, before rebounding in 2018.  Our Base Case suggests that rates will slide below these levels in 2017-18 and remain near breakeven in 2019, before a recovery finally arrives in 2020.

The key market disconnect may be an over-estimation of tanker demand — Arguments from tanker owners and equity analysts that moderate oil consumption growth should support tanker demand growth of 3-5% are relying upon an extrapolation of previous relationships.  As we have stressed during the past several years, oil product demand is not crude tanker demand, and a simple extrapolation of previous trends may prove painful.

Crude tanker tonne-mile demand is peaking for the next several years — Although crude tanker tonne-mile demand in 2017 may rival the peak in 1h16, demand is unlikely to return to these levels until early in the next decade.  Crude trade volumes should decline after 2017, pressured by continued growth in liquids bypassing the refining system and rising domestic crude runs.  Additional growth in land-based imports and a pause in eastbound Atlantic Basin exports should dampen tonne-miles.

Download cover page and executive summary of 43-page report here.

US Crude Production Jan16

US Production declines set to continue into 2017 — US light tight oil (LTO) production response is lagging rig counts by 6-7 months, based upon legacy well decline rates and rig productivity.  Our Base Case expects LTO rig counts to take another drop in 1q16 and remain low through most of 2016.  Initial signs of market re-balancing in 2h16 should allow a modest price recovery and some rig additions in late-2016.  LTO output needs to decline by 1 mbpd to balance global oil market, in addition to other non-OPEC production declines.  The December 2015 Short-term Energy Outlook (STEO) by EIA had forecast Brent prices at $56/bbl in 2q16, with resultant rebound in US production, but this is not realistic and does not balance the market.  Download presentation on US Crude Exports here.

US Condensate Production & Exports Jan16

Declining USG (PADD3) condensate production to limit export availability — Severe rig count reductions in the Eagle Ford play and accelerating well decline rates are sending Eagle Ford crude and condensate output much lower for 2016-17.   Although the repeal of the US crude export ban is further eroding the economics of condensate splitters on the USG, approximately 350 kbpd of new splitters are already completed, are under construction or have committed take-or-pay off-take agreements.  A combination of lower condensate production, rising splitter intake and Canadian diluent requirements should limit condensate cargo export availability through the forecast period.