Will a gas market develop in the Caribbean?
November 2017 | Yasmine Zhu
Caribbean countries have traditionally used oil products to generate electricity, leading to high power costs and pollutant emissions. Now, thanks to the growing number of LNG suppliers and advances in small-scale technology, opportunities are arising for oil-to-gas conversions, which could lead to the development of a regional gas market in the Caribbean. But several challenges still remain, including ensuring a sufficiently high utilization rate of the LNG infrastructure, accounting for long-term market uncertainties, and raising the high level of front-end investment required for power plant conversions to gas.
With limited hydrocarbon resources of their own, most Caribbean countries rely on imported oil products to generate electricity and meet other energy needs. 85% of primary energy usage is sourced from imported petroleum products1. Because oil products are expensive, producing electricity from these sources has pushed up the cost of power, which can depress economic development. However, the alternative of switching to natural gas has historically not been a popular choice, because the needs in the Caribbean were generally deemed too small to support the economics of LNG delivery.
Now, LNG market conditions have changed. International liquefaction capacity has grown. The US is emerging as a significant LNG exporter. Technological advancements are bringing down costs in small-scale LNG shipping and regasification. While these developments are promising, high debt and other financial pressures mean most Caribbean governments have little money for oil-to-gas conversion projects. Additionally, fuel oil and diesel prices have plunged by 50% since 2014, reducing the cost advantage of LNG over oil.
In this article, we take a look at how LNG can compete with fuel oil in a lower-for-longer oil market and what new opportunities this might present for gas suppliers and users in the region, as well as assessing what transformations might already be underway.
LNG is competitive now, but will it last?
As shown in Exhibit 1, in the near to medium term through 2024-25, fundamentals are likely to favor LNG buyers globally due to oversupply resulting from a rush to build LNG capacity in the first half of this decade, combined with sluggish demand growth. In the Caribbean, buyers may gain further advantage from their proximity to the US, where the shale gas revolution has seen a dramatic rise in low-cost supply, including feed gas for LNG export. These expected oversupply conditions have also impacted US LNG export contracting. Only about 60% of US LNG export capacity is tied to long-term end-user contracts in 2021, making the US a potential swing supplier to areas such as the Caribbean. Indeed, suppliers are already positioning themselves. In Panama, for example, AES announced a partnership with Engie at the Costa Norte LNG project to market LNG sourced mainly from the US2. But are LNG costs likely to remain at this level?
Beyond 2024-25, however, the LNG market could tighten if sufficient new liquefaction capacity is not built beforehand, and the advantage may switch to LNG suppliers. We could also see oil prices rise by the early 2020s, as lack of upstream investment accelerates non-OPEC legacy declines and new projects FID approved after 2014 is not enough to fill the supply gap. This is likely to be true if North America shale oil growth keeps a lid on prices for the next few years—in line with our base case “Lower for Longer” scenario.
To assess which fuel would be least expensive, we examined a scenario in which the Caribbean sources gas from the US Gulf Coast and compared the delivered cost to that of fuel oil and diesel. Exhibit 2 shows the US LNG delivered cost to the Caribbean through a standard large-scale onshore terminal, including the Henry Hub gas price, liquefaction, transportation, and regasification costs3.
Over the past six months, the estimated delivered LNG cost has stayed at roughly the same level as delivered fuel oil prices and at a sharp discount to diesel. However, there is far less commodity risk with LNG, as the raw material cost (based on Henry Hub) is a far smaller proportion of the delivered cost, compared to the crude oil element of the delivered fuel oil cost. A sensitivity analysis on the right of Exhibit 2 shows that, while nearly 90–95% of delivered fuel oil or diesel costs are linked to crude prices, the US LNG delivered cost to the Caribbean has only 40% of its cost tied to Henry Hub. While fuel oil prices may fluctuate anywhere between USD 5–11/MMBtu, in line with crude prices, LNG contracts are much less volatile in response to moves in Henry Hub pricing, staying at a level of USD 7–8/MMBtu for large-scale delivery. Diesel has the highest costs in all three price scenarios and has a commodity risk similar to fuel oil.
However, longer term the economics could be different. As mentioned before, if too few new LNG plants are commissioned to come onstream after 2025, then rising demand may significantly overtake available supply, and there would be upward pressure on delivered LNG prices, including in the Caribbean. Instead of a Henry Hub-linked cost-based pricing system, the value of US LNG could be influenced by oil-linked Asian netback pricing as cargoes are drawn across the Pacific. That means a relatively higher gas price, more exposure to commodity risk, and less advantage compared to oil products for Caribbean gas buyers.
For power generators in the Caribbean to convert to gas, it is crucial to develop a strategy that secures a low-cost Henry Hub-linked LNG supply source (beyond 2024-25). This could be achieved through LNG contract negotiation or the development of seaborne compressed natural gas (CNG). Although not commercially ready yet, CNG is a promising technology that ties pricing to the regional Henry Hub-based market. Because it is most cost-effective within distances below 2,000 miles, the CNG price will be much less affected by a tightened global gas market.
Technology cuts small-scale delivery costs, but utilization 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 MMcfd (~0.75 MTPA). 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 MMcfd. 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 MMcfd (~0.4 MTPA), 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 MMcfd (~1.5 MPTA). However, various onshore and floating solutions have now been developed for small-scale regasification. Pressurized vacuum-insulated tanks, small-scale FSRU, and barges, as shown in Exhibit 3, have reduced regas costs to USD 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 USD 7.5/MMBtu (from Exhibit 2), shipping and regas charges would add an extra USD 0.5–2.5/MMBtu, putting the delivered price at USD 8–10/MMBtu.
An important caveat is that the cost estimation is based on scenarios that assume 90% utilization of regas facilities and vessels. Lower utilization rates would increase unit costs significantly. For example, a utilization rate of 50% would raise the additional shipping and regas charges to USD 1.0–4.5/MMBtu, resulting in a full delivery cost of around USD 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 USD 60-70/bbl level and such plants are able to raise the utilization 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-MTPA 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-MTPA 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 ~8.6 MTPA, leaving considerable room for expanding the 2016 regional LNG demand of 2.1 MTPA.
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 USD 100,000 per MW4, we calculate that it will require a fuel price gap of ~USD 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 incentivize 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 utilization 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 organized 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.
Notes and sources
(1) Data excluding T&T and Haiti, from Arnold McIntyre et al. 2016. Caribbean Energy: Macro-related Challenges, IMF Working Paper: 8
(2) Press Release Details online. May 05, 2017. ENGIE and AES Agree to Expand their LNG Marketing Partnership to Central America [accessed Sep 20, 2017]
(3) Additional transportation costs from the LNG regas terminal to the fuel consumption facility have not been considered
(4) Inter-American Development Bank. 2014. Natural gas in the Caribbean- Feasibility study (Volume I): 132
About the author
Yasmine Zhu is a Senior Analyst in McKinsey Energy Insights' Houston office.