Floating Storage

The European gas year commenced October 1 with expectations of high winter demand and commensurate gas and LNG prices. However, in recent days the press — both trade and mainstream — have remarked on the number of laden LNG carriers that have been circling, anchored or drifting around the Mediterranean and East Atlantic. This flotilla, currently numbering about 30 cargoes, or 2.1 million metric tons (MMt) of LNG, has been growing since late September and includes some cargoes that have been at sea for over a month. Although floating storage ahead of winter demand is nothing new, the scale of the current phenomenon is unprecedented. In today’s RBN blog, we explore the implications for European gas pricing and market dynamics.

The New York market for residential and commercial heating oil is traditionally tight in the winter months when demand exceeds local production and supplies are supplemented from storage and inflows/imports from outside the region. Coming into winter this year inventory levels were above normal for the time of year and market prices are in contango (a condition where future prices are higher than today) – encouraging further storage. Today we explain how the result is an extension of traditional seasonal storage trade opportunities and a shortage of available inventory capacity.

With crude prices close to six year lows and the futures market pointing higher, a number of the larger commodities trading houses are buying and holding cheap crude in huge floating tankers for later sale. For the trade to work, prices today must be lower than they are in the future and the spread must cover the storage cost and other expenses. Players in the floating storage game have to be high rollers – the minimum cost of a bet at this table is ~$100 million. Today we complete a two-part series on contango-spread trades with a look at floating storage.

There’s been a lot of talk--and angst—this summer and early fall about the flood of crude oil headed to the Houston area from the Eagle Ford, the Permian Basin and other burgeoning oil-production regions. The angst seems worst for crude producers, who rightly wonder whether Houston’s looming shortfall of storage capacity will further disrupt crude oil logistics, contribute to more downward pressure on crude prices, or worse.  Understanding what’s ahead requires an in-depth look at the changing crude flows into Houston and that is precisely the subject of RBN Energy’s latest drill-down report. In today’s blog, we provide highlights of the report, which is available for download by RBN Backstage Pass holders, and discuss how the shift from waterborne to pipeline delivery of crude already is affecting the market.

Looking out over the next year and a half to 2016, Houston crude storage capacity looks to be lower than necessary to meet operational needs. With continuing increases in pipeline crude streams headed into the area in the next six months, we could see supply disruptions with consequences for price volatility. Probable victims of these disruptions would be producers looking to find a home at Houston refineries for their production. The solution is to build more storage but the market is not yet sending alarm signals to that effect.  Today we conclude our series on Houston storage capacity.

Changes, expansions and reversals of the existing logistics system that supplies crude to 2.5 MMb/d plus of refining capacity in Houston have allowed refiners to expand output and process more crude than ever before. But there is still another 1.5 MMb/d of pipeline capacity coming into Houston by the end of 2015 and the decline in waterborne imports has reduced system flexibility. One company’s plans to build out over 17 MMBbl of crude storage in salt dome caverns south of Houston could alleviate some of the storage capacity challenges. Today we discuss the proposal.

Houston area refineries are currently operating with about a third less onshore storage (measured in storage days) than comparable refineries in other regions. Waterborne crude imports help to alleviate the challenges that this constraint can cause. But Houston is importing less waterborne crude nowadays – down by 0.5 MMb/d since 2011 to just under 1 MMb/d and that number will continue to fall as US production increases. When you add the challenges of handling crude quality issues, including apotential new requirement to segregate certain types of condensate, the storage shortfall looks even worse. Today we continue our analysis of Houston area crude storage.

Houston area refineries are the first to experience the full impact of the flood of domestic and Canadian production headed to the Gulf Coast in 2013 and 2014. These refineries have traditionally relied on floating storage in the form of import cargoes in transit to buffer them against supply shocks. Now the region is adapting to new crude supplies mostly delivered by pipeline. As imports decline, the floating storage option disappears, leaving the potential for congestion caused by inadequate onshore working storage. Today we calculate the storage impact of these changes.

During the days when Gulf Coast refineries were dependent on crude imports for the majority of their feedstocks, tankers delivered crude from overseas markets. Those same tankers also played an important role in preventing refinery supply disruptions because they acted as a floating storage component in the supply chain. With waterborne imports to the Gulf Coast declining as domestic and Canadian production is increasingly delivered by pipeline, the buffer provided by floating storage will be much reduced. Today we continue our series looking at Gulf Coast crude storage needs in the shale era.