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Will a gas market develop in the Caribbean? Part two

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LNG Industry,

Read part one here.

By Yasmine Zhu, a Senior Analyst with McKinsey Energy Insights, where she conducts market analysis for its North American upstream and midstream sectors. Topics she covers include shale productivity, natural gas regional market dynamics, US LNG, and midstream capital investment.

Technology cuts small scale delivery costs, but utilisation is key

Although there is great demand potential from fuel switching to gas, most Caribbean countries will still only have demand of less than 100 million ft3 per day (approximately 0.75 million tpy). In the past, at this volume, high costs tended to make such projects uncompetitive compared to other fuels. But advances in delivery technology, particularly in small scale LNG shipping and floating storage and regasification units (FSRUs), have substantially reduced the costs of small scale LNG distribution throughout the Caribbean and other lower demand locations.


Traditional tankers hold 125 000 – 250 000 m3 of LNG, and because they would typically be completely emptied at the delivery port, importing smaller amounts of LNG using them is not commercially viable. The more recent introduction of small scale LNG ships, with a capacity of between 10 000 – 40 000 m3, has made it possible to deliver LNG on a commercial basis to buyers with a demand level of 50 – 150 million ft3 per day. As shown in the chart of Exhibit 3, for demand of this level, a small scale LNG ship could cut unit shipping costs by almost 50% compared to large-scale ships.

If local demand is below 50 million ft3 per day (approximately 0.4 million tpy), the most cost-efficient delivery option is through a local hub either using ISO containers or break-bulk projects, which are designed to partially unload at multiple ports during a single voyage – commonly referred to as a ‘milk run.’ Local LNG users can lower the delivered price by splitting shipping costs, based on their shipping distance and the transportation time required. Companies are already positioning themselves for anticipated demand through this small scale distribution model. For example, in January 2017, AES’s Andres LNG terminal in the Dominican Republic started offering reloads to small scale LNG carriers. In Asia, Keppel and Pavilion signed a deal in September 2017 with Indonesia’s state power utility PLN for small scale LNG deliveries to power plants in Indonesia’s western islands.

Regas and storage

Conventional onshore regasification terminals and FSRUs, with capacities usually greater than 100 000 m3, are typically only justifiable for demand greater than 200 million ft3 per day (approximately 1.5 million tpy). However, various onshore and floating solutions have now been developed for small scale regasification. Pressurised vacuum-insulated tanks, small scale FSRU, and barges, as shown in Exhibit 3, have reduced regas costs to US$1.0 – 2.0/MMBtu for small scale demand.

Based on this analysis of shipping and regasification costs, delivering US LNG in small quantities to the Caribbean could be commercially viable. On top of the large-scale delivery cost of US$7.5/MMBtu (from Exhibit 2), shipping and regas charges would add an extra US$0.5 – 2.5/MMBtu, putting the delivered price at US$8 – 10/MMBtu.

An important caveat is that the cost estimation is based on scenarios that assume 90% utilisation of regas facilities and vessels. Lower utilisation rates would increase unit costs significantly. For example, a utilisation rate of 50% would raise the additional shipping and regas charges to US$1.0 - 4.5/MMBtu, resulting in a full delivery cost of around US$8.5 – 12/MMBtu.

This price, which is higher than current fuel oil prices, may not be enough to justify conversion of a small power plant to gas under expected near-term conditions. But if WTI prices recover to US$60 – 70/bbl level and such plants are able to raise the utilisation rate of their LNG facilities, then small scale LNG could become a more attractive alternative to fuel oil in the medium term.

The switch to LNG is already underway, but investment challenges remain for power plant conversion

The more attractive economics of small scale LNG, combined with efforts on the part of several Caribbean nations to diversify their power generation mixes, have already resulted in new LNG infrastructure projects coming online. For example, in November 2016, Colombia chartered a 3.75 million tpy FSRU for 20 years that could potentially distribute gas around the region. And in Jamaica, the 138 500 m3 Golar Arctic has arrived to act as a floating storage unit (FSU), receiving its first LNG through ship-to-ship transfer. Other examples include AES’s reconfigured Andres terminal for small scale reloading in the Dominican Republic and its new 1.5 million tpy regas terminal project in Panama; and Energía del Pacífico’s (EDP) —which signed an LNG Sales and Purchase Agreement (SPA) with Shell in April 2017 – proposed 378-MW gas power plant and FSU facility in El Salvador. Altogether, existing and under-construction regas terminals in the region, as shown in Exhibit 4, total approximately 8.6million tpy, leaving considerable room for expanding the 2016 regional LNG demand of 2.1 million tpy.

However, the analysis discussed so far only covers delivered fuel costs. The costs of converting generators to burn gas rather than oil and the additional infrastructure required to transport gas from LNG regas terminals to the plant gate must also be considered. Both of these elements require more planning and greater capital budgets. In the current low-oil-price environment, LNG cost is at a similar level to fuel oil, so power plants will have little incentive to invest in this conversion in the near term. Assuming an estimated conversion cost of US$100 000 per MW4, we calculate that it will require a fuel price gap of approximately US$1 – 1.5/MMBtu to justify the capital investment at a 10% IRR rate. But for plants burning diesel, the wide fuel cost gap could still incentivise the oil-to-gas conversion.

In the situation where there is little direct commercial advantage in switching to LNG, the development of a gas market in the Caribbean could depend on LNG sellers, who either seek to contract out their portfolio volume or boost the utilisation rates of the local LNG import terminal. Those LNG sellers would also be in a good position to scale up local demand, coordinate infrastructure planning, and extend an organised delivery mechanism. For example, New Fortress Energy in Jamaica, which is backed by an investment fund, is able to both supply LNG and finance construction of the LNG terminal and infrastructure that will deliver LNG to local power plants. In this way, it is creating a market in Jamaica. This has facilitated the conversion of the JPS Bogue power plant and the switch by a brewery to LNG, along with spurring plans to build a new gas power plant. We may see similar transitions as other Caribbean countries – which have a supportive regulatory environment and an available workforce—follow Jamaica’s example.

4. IDB report: Natural gas in the Caribbean: Feasibility study

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