Category: Crude Tankers

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.

 

US Crude Export Destinations Jan16

European refiners play larger role in US crude & condensate exports —  With Canadian imports remaining stable, Europe becomes the primary destination for incremental US crude and condensate exports.  Although North Sea production should decline by 300 kbpd during 2015-20, European refiners have limited ability to take larger volumes of 45° API crude and 55+° API condensate, when we examine each country’s crude slate.  US producers will need to find additional outlets in Latin America, as well as higher Asian exports, as the rising light-ends imbalance pressures prices and opens arbs.

Crude Seaborne Trade Oct15

Crude seaborne trade to remain flat for the next three years — Crude destocking in 2017-18, non-crude liquids bypassing the refining system and higher domestic crude runs should limit crude seaborne trade though 2018.  Refinery bypass includes NGLs transferring directly into LPG supply, biofuels, GTLs, direct crude burn and refinery gains.  The crude tanker orderbook, at 18% of the fleet, is not so “moderate” under this demand regime.

Rising Crude Runs in Producing Countries & Crude Exports Oct15

Where exports come from…  Severe drop in refinery utilisations among eight key oil producers and exporters provided an additional 500-700 kbpd of crude exports during 1h16.  These eight producers account for more than half of global crude exports.  Recovery in utilisations should remove this extra crude from the market in 2016, and the Latin American impact alone could approach 200 billion tonne-miles, or 2% of tanker demand.  Refinery utilisations do not recover fully, however, due to the destruction of the Baiji refinery in Iraq, as ISIS forces retreated, and from continued operating upsets in Venezuela.

Floating Storage Oct15

Gradual release of 6.4 mdwt of Iranian floating storage vessels over 18 months adds 1.5% to dirty tanker operating fleet growth, just as supply peaks in late-2016 and early-2017.  Even with slippage, yards should deliver almost 60 VLCCs during 2h16 and 1h17, which is enough to move 2.4 mbpd of crude between the AG and Asia.  Owners may be slow to scrap in 2016, but demolition should accelerate in 2017, bringing growth back to 2% by late-2017.

Dirty Tanker Supply Outlook Oct15

Ecstatic over lofty tanker earnings brought on by OPEC policy largesse — and convinced that this is the start of a broad, cyclical recovery — owners once again ordered too many crude tankers in 2015. Their justification was a simplistic hypothesis about inter-basin crude flows, but shifts in global production, refining and imports suggested that the sector was a 1% growth business, at best. Given the orderbook size, the results were predictable.  Download 28-page summary section of 128-page presentation here.

Jones Act & Panama Canal Feb15

Presentation at Crude-by-Water Conference in Houston on 04 February 2015. A discussion on whether the new set of Panama Canal locks opening in 2q16 could accommodate the movement of USG crude to USWC refiners facing production declines in Alaska North Slope crude (ANS) and domestic Californian heavy crude. The higher operating and capital costs of Jones Act Alaska fleet would make the required earnings and freight costs too high to overcome typical differentials between ANS and light USG marker grades.  Download presentation here.

Citgo Refinery Sales Oct14

Market commentary in October 2014 suggested that the sale of PDVSA’s three Citgo refineries would unleash significant volumes of Venezuelan crude from the Citgo crude slates for Chinese export, and thus boost VLCC demand by as much as 4%. This is unlikely. Actual Citgo Venezuelan imports are modest, but necessary for the plants. Instead, rising tight oil production and Canadian crude imports should send Latin American volumes eastward, but the shift in Saudi pricing posture after we published this report should change the extent. If successful in pricing US tight oil and Canadian oil sands out of the market, then PADD3 seaborne imports will not fall as much and the refiners’ crude wall would be less acute.  Download report here.