Latin America flips [NGW Magazine]

Latin America provides more than one reminder that LNG markets are not necessarily permanent. In the Middle East, Israel and Egypt have shown that LNG imports can come and go, both ramping demand up quickly through floating storage and regasification units (FSRUs) and then ramping down again on the back of increased domestic gas supply as major gas finds in the east Mediterranean came on stream.

For the LNG industry this is perhaps disappointing, but there is an upside. FSRUs are firmly established as the quickest means of providing a relatively clean energy feedstock to a new market in a short space of time. That the FSRUs can themselves be relocated and are hired on charter means the infrastructure costs of meeting a temporary imbalance between domestic supply and demand is low. As a result, LNG has become one of the world’s emergency standby fuels and its cleanest.

However, the hard fact remains that LNG can rarely compete with domestic gas. And just as Israel and Egypt slip into the LNG twilight, so too may all of Latin America’s major LNG markets over the next decade. Gradually, the region is likely to emerge as a net exporter of LNG, a process which has already been set in train. 

US shale

The most immediate threat to Latin American LNG demand is US pipeline exports to Mexico. These have boomed in recent years as new cross border pipelines have been built and Mexico has constructed the distribution infrastructure to get US gas to consumers, most notably in the power sector.

US pipeline exports hit a high of 5.09bn ft³/d (144mn m³/d or 52.6bn m³/year) in August, capped only by delays in the completion of new pipeline infrastructure inside Mexico. In October, exports were 5.008bn ft³/d, six times higher than in 2010. Mexican LNG imports in contrast peaked at 0.9bn ft³/d (9.3bn m³/yr) in 2014.

LNG imports trended up in 2017 and into 2018 from 5.9bn m³ in 2016, but completion of the Sur de Texas-Tuxpan and the Manzillo-Guadalajara pipelines this year should almost eradicate the need to import LNG into the Altamira and Manzanillo LNG terminals. Mexico’s third terminal, Costa Azul, which sits close to the US border, is already slated for conversion into an export facility. 

Costa Azul is well placed on Mexico’s Pacific coast to liquefy Permian basin shale gas and export it to high-growth Asia markets. Sempra Energy signed a heads of agreement in November with three off-takers for a first LNG train at the site with capacity of 3.3bn m³/yr. A final investment decision is targeted for late 2019 with exports slated to start in 2023.

The sharp reduction in LNG imports into Mexico’s north will only partially be offset by a new FSRU project at the port of Parajitos, being developed by state oil and gas company Pemex, which is expected to be operational in the first or second quarter of this year, serving southern Mexico.

This will compete with gas from the Sur de Texas-Tuxpan pipeline once flows via the Cempoala compression station have been reversed. Pemex believes both supply projects will be needed, estimating unmet gas demand in southern Mexico at 1bn ft³/d. The FSRU will supply 500mn ft³/d, but could well be superseded at some point by the further development of Mexico’s domestic pipeline system.      

The upshot is that by the early 2020s Mexico is likely to join the small but growing club of nations that both import and export LNG. 

Argentinean shale

The second major threat to Latin American LNG demand is again shale, but this time in Argentina. The country’s giant Vaca Muerta shale play is producing 120,000 b/d of oil and breakeven prices have fallen to $56/b, according to an estimate made last year by consultants Wood Mackenzie.

It also producing increasing quantities of gas, contributing to a domestic surplus in the current southern hemisphere summer, which also reflects weak demand as a result of the country’s economic problems. The surplus has resulted in agreements for interruptible gas exports via existing pipelines to Chile for the period October 1, 2018 to May 1, 2019, and the contracting of a floating liquefaction vessel.

Exmar’s Tango FLNG is already en route to Bahia Blanca, the location of Argentina’s and South America’s first regasification terminal Bahia Blanca GasPort. Tango FLNG is expected to start operations on the second half of this year, well ahead of plans for a six-train liquefaction plant, also in Bahia Blanca, which has been mooted for start-up in 2023. The arrival of an FLNG vessel implies little future need for Bahia Blanca GasPort. 

Argentinean gas production was up 7% year-on-year in October at 132mn ft³/d, but unconventional gas output rose 38%, according to Argentina’s energy ministry, which forecasts gas production rising to 400mn m³/d by 2030. This should see export volumes rise to 180mn m³/d in 2025.

Argentina expects to pipe 60 MMcm/d to Brazil and Chile with the remainder (120mn m³/d or 43.8bn m³/yr) exported as LNG. If realised, this would put Argentina among the first rank of LNG exporters worldwide. LNG imports are expected to decline steadily, reaching zero in 2023, having already fallen from a peak of 6.7bn m³/yr in 2013 to 4.3bn m³ in 2017.

Rising Argentinean gas exports will have a knock-on effect in Chile, which has gone through a variety of energy sector gyrations in its efforts to address the loss of Argentinean pipeline gas more than a decade ago. Both countries are pursuing greater energy sector integration, and the resumption of seasonal exports from Argentina to Chile imply a limited shelf life not only for seasonal exports in the other direction --  sourced via Chile’s own LNG terminals -- but Chilean LNG imports themselves. 

Brazil’s subsalt

The third cloud on the horizon for Latin American LNG imports is Brazil’s subsalt oil developments. Brazil’s National Agency for Petroleum, Natural Gas and Biofuels (ANP) forecasts that by 2030 the country will be producing 7.5mn barrels of oil equivalent/day, up from 3.3mn boe/d last year. Brazil certainly has a chequered past in terms of hitting ambitious production targets, but development of the country’s sub-salt layers is already producing significant amounts of associated gas.

Brazilian gas production grew 12.4% in 2017 to 27.5bn³. According to consultants Rystad Energy, the sub-salt Lula, Buzios, Iara and Libra fields will add 14bn m³/yr to output by 2030, increasing total annual production to 47bn m³.   

In its latest results, state oil and gas company Petrobras reported a new record in gas utilisation of 96.6% as it focuses on reducing flaring, but the key to higher gas production is the completion of offshore field-to-shore pipelines from the sub-salt region. The completion of the Route 2 pipeline in 2016 boosted offshore gas production brought to market by 4.7bn m³ to 8.4bn m³. A third 6.6bn m³/yr pipeline is scheduled for completion in 2020 to be followed by a 5.5bn m³/yr pipeline to take gas from the Santos Basin to the industrial city of Sao Paulo.

Rystad sees domestic gas production catching up with consumption around 2028, albeit with significant potential for volatility, owing to Brazil’s high dependence on hydropower and thus rainfall. 

However, the relationship between hydro output and gas imports may be breaking down, as domestic Brazilian gas production rises and other forms of power generation, notably wind and biomass, increase. Brazilian hydro generation in 2017 was 4 TWh lower in 2017 than in 2014, but only 10.5 Bcm of gas was imported, compared with 19bn m³ in the earlier year. Of the 2017 imports, only 1.9bn m³ were LNG, compared with 8.6bn m³ in 2014.

Rising power generation from renewable sources is by no means solely a Brazilian affair as the raft of GW-sized tenders across Latin America in 2017 and 2018 has shown. These returned wind and solar prices significantly below the cost of gas-fired generation. Chilean generation of electricity from renewable sources, excluding large hydro, has more than trebled in the past five years to 18%, while Brazilian renewables generation jumped 15.7% in 2017 to almost 100 TWh, 16.5% of the total. Argentina is some way behind the curve in comparison, but should see the fruits of recent renewables tenders in coming years. 

Bolivian role

Based on Rystad’s forecasts, the gap between Brazil’s domestic supply and demand is rarely larger than the 11bn m³ capacity of the Gasbol pipeline from Bolivia. Bolivian imports will be a key determinant of Brazilian LNG demand. Last year, Bolivia’s National Hydrocarbons Agency (ANH) forecast that annual production would fall steadily from 19.9bn m³ in 2018 to 9.5bn m³ in 2025. 

With the expiry of its long-term gas supply contract with Bolivia this year, Brazil is expected to reduce by almost half its current import volumes of up to 11bn m³/yr, reflecting the uncertainty over Bolivia’s ability to supply gas to both Argentina and Brazil at current levels. 

However, given the small size of the domestic Bolivian gas market and its lack of a coastline to develop LNG, Bolivian gas will continue to flow to Brazil even as the latter’s internal gas balance improves. As the cost of GasBol has been paid off, these imports will remain competitive against LNG. 

Bolivian pipeline volumes may even recover in the early to mid-2020s as a result of discoveries made in 2016 in the Caipipendi area and attempts made in 2018 and 2019 to boost exploration and production activity.

Nonetheless, with Argentina expected to become a major gas exporter, Bolivian gas will ultimately have only one destination – Brazil. This will add to the growing surplus of gas in the southern cone, which will have to find its way on to international markets as LNG, thus completing the region’s transition from net LNG importer to net exporter.