Mexico’s Three Year LNG Top Up
An exploration of Mexico’s market fundamentals to explain the current strong Mexican spot LNG demand, and a view of how & when this will change
Mexican demand for spot LNG has soared over recent months[JA1], as constraints a lack of progress on further an expansion ofin US pipeline imports leave Mexico short against a backdrop of falling domestic production and surging demand linked to strong economic growth. The Gas demand is expected to rise further [JA2]to absorbing the remaining import capacity at Mexico’s two main terminals[JA3]. , bHoweverut the prospect of more inexpensive pipeline imports and domestic production in over the next 3-5 years’ time is expected likely to deter further green-field LNG infrastructure or term expansion.
Mexico imported a record volume of about 2.1 Bcf/d in 2012, up 21% from 2011. However, only 0.4 Bcf/d or 20% of the total was as LNG. Up until this year cheap pipeline exports were able to rise – from under 1 bcf/d in 2010 quickly up to 1,7 bcf/d in 2012[JA4]. Extrapolating that growth forward, with no further expansion in pipeline imports possible, then there is little surprise LNG spot demand has rocketed this year. Although the higher cost of importing LNG may moderate demand growth [JA5]to some degree – very little in Mexico’s case at current price levels - if Mexico’s economy remains buoyant there is little reason why demand should not continue rising [JA6]by 1 bcf/d every three years or so.
A surge in Mexican spot LNG buying this year is being driven by lower than expected term deliveries, as well as additional demand from fuel switching at state utility CFE, expansion of the industrial sector and renewed growth of Mexico’s gas distribution privatization program. Consumption is expected to rise by 30%--to 10.8 Bcf/d—by 2018, according to market analysts Bentek. Of that 2.7 Bcf/d increase, 1.4 Bcf/d will come from the power sector, with nearly 13,000 MW of new gas-fired capacity due to come on-stream by 2018. Another 0.3 Bcf/d will come from the industrial sector, and 1.0 Bcf/d largely from expanded gas distribution systems serving commercial and residential customers. Shortages, new highly efficient gas-fired plants and replacement of expensive oil products are likely to make the demand inelastic.
Mexico imported a record volume of about 2.1 Bcf/d in 2012, up 21% from 2011, although only 0.4 Bcf/d or 20% of the total was as LNG. Up until this year cheap pipeline exports were able to rise – from under 1 bcf/d in 2010, quickly up to 1,7 bcf/d in 2012. Although spare capacity stills exists at the border, pipeline imports are now constrained by bottlenecks in Mexico’s distribution system. The newly built Manzanillo LNG terminal, however, has opened another market in Mexico’s southwest, and is expected to increase exports towards its capacity of 3.8 mmt/yr by 2015, leaving demand in the north to build until several new foreign-owned pipelines bring gas from the US deep into Mexico (see map). CFE has signed a 15-year contract to purchase all the gas received at Manzanillo and has a similar arrangement in place at Mexico’s east coast terminal of Altamira.
Term supply from Repsol to Manzanillo will rise from 660,000 mt in 2012 to 3.7 mmt/yr by 2015, at a price, according to CFE, of 9% below Henry Hub quotes. At current Henry Hub levels Repsol could sell its LNG far more profitably elsewhere, as has been borne out by Mexican government data, which showed a very slow start to deliveries last year. There were no significant LNG flows into Manzanillo before October, despite opening in March. Within the restrictions of its contract, which totals 67 Bm3 over 15 years, Repsol is likely to be minimizing initial deliveries, in favour of higher priced spot market sales, driven by crude-linked northeast Asian demand. Without the low priced term, CFE has been driven to the same spot market, and appears unperturbed by higher prices, but may in turn cut spot purchases as term volumes increase in future years. Bentek expects overall LNG imports to remain steady at about 0.5 bcf/d over the next few years, with rising pipeline imports meeting the bulk of future demand increases.
What’s more the increases in imports to date have not managed to meet domestic demand fully.Domestic production is unlikely to cover much of the higher demand. Mexican output was steady at 6.2 Bcf/d in 2011 and 2012, and is standing at around 6.5 Bcf/d this year. Bentek expects Mexican gas production to be flat over the next two years before increasing to 7.5 Bcf/d by 2018. All domestic gas is produced by state monopoly Pemex, which, according to SENER statistics, is also the country’s largest consumer, using about 40 % of Mexico’s total consumption – or over half domestic production - largely in its upstream operations, refineries and petrochemical plants. It sells about 3.5 bcf/d to domestic users (consumption breakdown table?). The power sector, with a share of around a third of total consumption (much of it from independently sourced LNG supplies), is the fastest growing consumer, while most of the remainder is sold to industrial consumers.
Shortages last year led Pemex to limit supplies to industry on eight occasions, and state-run power utility CFE switched a number of its generating plants [JA7]to other fuels to save gas as part of a deal to reduce the effect on industry, costing it $1.6 billion[JA8] in additional fuel costs last year, according to CFE spokesman Estefano Conde. This led to higher industrial electricity rates, which are linked to fuel prices.
Pemex has also been authorized to pass on LNG costs to all users of its pipeline network, with temporary surcharges on 200 mmcf/d[JA9]determined by theMexico’s Energy Regulatory Commission, or CRE. Pemex and CFE will, however, take the biggest hit based on their own consumption[JA10]. Pemex uses about half of its gas production for its own refining, processing and power operations and sells about 3.5 bcf/d to domestic users (consumption breakdown table?).CFE buys much of its gas as LNG independently, which it says costs less than buying from Pemex, and is steadily replacing fuel oil and diesel in conventional thermal power plants, which make up the overwhelming majority of Mexico's generating capacity, with gas, as well as bringing new gas plants on-stream. the single biggest consumer[JA11], CFE owns about three-quarters of Mexican capacity, but demand also comes from . independent generators, which run over 12 GW of generation capacity, mostly combined-cycle, gas-fired turbines.
Mexico’s rapid recent economic growth means generation capacity is barely keeping up with demand, meaning most plant must be used, which makes fuel demand for generation relatively inelastic. But even at high prices LNG is cheaper than oil products.leaving only limited alternatives to burning gas, making demand relatively inelastic even at high prices. As a fuel for power generation, LNG[JA12] is more of an alternative to fuel oil (or crude – reports of crude burning?) than pipeline gas, and with Asian LNG prices moving in line with oil there is little point in substitution[JA13], unless crude prices drop below $80/bbl.In addition, the high efficiency of CFE and independently run combined cycle gas turbines offsets high fuel costs, and CFE is also able to spread any additional high spot costs thinly across power customers[JA14].However, Mexico’s ambitious plans for gas fired generation capacity expansion may need to be curbed unless import capacity can be expanded[JA15]. Up to 20 GW of new gas-fired generation capacity is planned over the next 10-12 years, requiring about 3.8 bcf/d of additional gas to operate. By 2025, incremental gas demand from power plants alone could total 2.5 Bcf/d, assuming 85% utilization of the new generating capacity to be built, according to Bentek.
While Mexico is addressed as a single unit,the nature of its fragmented gas pipeline network means it is more like a collection of markets[JA16], each with its’ own demand fundamentals and supply options. The alternative of cheap US pipeline supply is currently only available in the north of the country, where the natural gas pipeline network includes thirteen operational interconnections with the US. Most while domestic supply, largely froorm associated gas fields off the south east feeds into the same system as the Altamira LNG terminal on the east coast.
Mexico’s three operational LNG terminals [JA17]were developed by different companies for different purposes. Sempra’s Costa Azul [JA18]1bcf/d import terminal was designed largely to supply the southern Californian market with LNG from Asia, with potential to expand to 2.5bncf/d, and is far from major demand centers in Mexico[JA19]. Gas from Costa Azul is used by electricity-generating plants and other industries in Baja California, delivered via a 45-mile section of the Gasoducto Bajanorte pipeline, which connects the terminal with existing natural gas pipeline systems that span the northern border of Baja California and the US border.
The 7.4 bcm Altamira terminal on the Atlantic coast was developed by Shell and Total as a Build-Operate-Own project to take West African LNG, and is now owned by Vopak (60%) and Spain’s Enaegas [JA20](40%). About 5.5 bcm of eExisting capacity is fully contracted to CFE for a 15 year long-term period to supply power plants and industry around Mexico City. The facility , but could be expanded up to 10 bcm/yr by building and operating a third storage tank, according to Vopak. Altamira receives both term supply of 500 mmcf/d from Shell under a deal signed in 2003, which CFE says it is attempting to renegotiate on more favourable terms,/Total (?) and spot, while it supplies gas to Mexico City, and to CFE under a long-term sale and purchase agreement.
Manzanillo on the west coast was also built as a 3.8 mmt/yBOO uild Operate Own (BOO) scheme with developers including Mitsui, Samsung and Kogas(expansion potential?). CFE is the sole customer, and commissioned the terminal designed it primarily to receive term LNG from Repsol’s 4.4 mmt/y LNG plant in Peru, to supply power plants - the largest of which is cleaner gas toan existing 2000MW oil-fired power plant. Manzanillo also serves a buoyant area of economic activity and gas demand, including Guadalajara(AF)[JA21] where much of the manufacturing and industrial gas purchases are concentrated. Nevertheless the majority of gas delivered to Manzanillo goes to CFE as a replacement for oil-fired power generation in south-west Mexico[JA22].
CFE has bought a total of 29 spot cargoes for Manzanillo so far this year. Nine cargoes were bought for delivery over the following 19 months from BP and Trafiguraon May 17, eight of which will be supplied by BP and one by Trafigura for delivery to the west coast terminal. The cargoes will come from Qatar, Norway, Trinidad & Tobago, Brunei or Nigeria.
Trafigura delivered its shipment in late June at a price below $15.85/mmbtu, after which CFE said it would buy an additional two cargoes from the trader. CFE also bought 18 LNG cargoes from Trafigura (for delivery when?) at an average price of $15.84/mmbtu in an April tender, which sought 30 LNG cargoes for delivery to Manzanillo. That compares to levels around $14.30/mmbtu in northeast Asia over the next few months.
Spot buying could slow at Manzanillo as Repsol increases supply under its term contracts up to 3.8 mmt/yr by 2015 (How inflexible is this contract?) Repsol has two term contracts to supply Manzanillo with a combined annual average total delivery of 3.18 mmt for 15 years.
Add to that the two term contracts that CFE has with Repsol for a combined annual LNG supply of 3.18 million tons, and the 3.8mmt/yr terminal is already reaching capacity (exact utilization rate/contractual commitment/expansion options?), just a year after coming on-stream. Costa Azul also on the other hand has plenty of spare capacity[JA23], but development of connections from there to the rest of Mexico is far off, leaving it as a possible candidate for conversion to export US gas. Only two cargoes have been delivered to Costa Azul so far this year, according to Gas Strategies data. Even if there were demand, sellers from Asia or Australasia would be wary of repeating any Henry Hub-linked term deals like Sempra’s to Costa Azul, or Repsol’s to Manzanillo.
If a Mexican west coast terminal wants cargoes from anywhere other than Peru, they must come around Cape Horn from the Atlantic Basin or across the Pacific. To draw a cargo across the Pacific, Manzanillo must pay at least a dollar/mmbtu above the prevailing East Asian price in direct competition with major buyers Japan and Korea and with crude driven term pricing(AF). To justify a trip around Cape Horn a similar premium is required for Atlantic basin cargoes, but experts Andy Flowers [JA24]believes this will not lead to a convergence in Pacific and Atlantic basin prices, because of differing supply fundamentals in the two markets and the relatively small scale of the demand[JA25].
Altamira on the Atlantic does not have to pay the freight premium, meaning lower average import prices and an absence of deliveries from outside the Atlantic basin.Even at Manzinillo, only one of the 22 cargoes recorded so far this year (GS) came across the Pacific basin, via Trafigura from Rasgas, with another two from Indonesia to Costa Azul under term. Depending on charges, eExpansion of the Panama Canal in 2014/5 should allow more flexibility at Manzanillo, and reduce premiums [JA26]there by allowing a shorter route for Atlantic basin cargoes.
Once Once planned US and Canadian LNG export terminals on the Pacific coast are built (include when/where?), Mexico’s Manzanillo terminal – which is too far from the US to access new pipeline supply -west coast import terminals will have closer alternatives, provided cargoes are not sold with destination clauses, leading to an option of bidding at discounts of a dollar or more to northeast Asian prices[JA27]. But with pipeline developers building and planning cross-border projects that will add 4.2 Bcf/d of export capacity from Texas and Arizona, as well as more than 2,800 miles of new pipelines within Mexico that will be able to deliver more than 10.3 Bcf/d to new customers well inside Mexico, demand for more expensive LNG is likely to remain limited. The US DOE has received applications from about 15 companies to export a combined 18.7 Bcf/d of gas as LNG. It has already authorized more than ten companies to ship LNG to FTA nations, (check) but it has only authorized one two terminals — Cheniere Energy’s Sabine Pass facility LNG in Louisiana and Freeport LNG — to export to non-FTA countries, with several more applications currently being processed.
Depending on how many more export licenses are granted, free trade partner Mexico, will have a distinct advantage in trade regulations, as well as freight costs[JA28]. Mexico could end up being the biggest beneficiary of US LNG export terminals[JA29], many of which are being funded by buyers from Asian countries. Cheap US gas already helps Mexico compete in global manufacturingwith many of these countries in manufacturing. China pays from 50 to 170 percent more for industrial natural gas[JA30], and Mexico also enjoys an advantage in electricity costs[JA31], according to a recent report by Boston Consulting Groupalthough power isn’t as cheap in Mexico as in the US. However if shortages were to grow, this effect would be capped.
Several other LNG import terminals had been planned in Mexico, but many of those were intended as ‘back-door’ supply routes to the US, in the days when US LNG import terminals there were politically sensitive and domestic shortfalls were predicted. The prospect of a similar shale boom as that which propelled the US from the old import scenario to major exporter, is likely to stymie any further green-field development of Mexican LNG import capacity[JA32]. The prospect of pipeline deliveries combined with And while spot imports have soared, there remainings spare capacity and the potential for brownfield expansion at among existing terminals, especially Costa Azul and Altamira, means further greenfield development is not expected. (How much in total?)
The price levels Mexican buyers are prepared to go to is difficult to judge, but because there are shortages and the cost of buying expensive LNG is diluted by a much larger flow of cheap US pipeline imports, average prices remain low compared to those in east Asia or Europe.Similarly, unless CFE can secure more Henry Hub linked term, the alternative to spot LNG buying is use of expensive oil products, making Mexican demand inelastic at recent levels of On that score Mexican buyers could afford to go much higher than the $15.84/mmbtu seen recently [JA33]for cargoes on both coasts from Nigeria, according to Gas Strategies data.
With the majority of demand satisfied from the Atlantic basin it is unlikely Mexico will often have to pay the levels of $20/mmbtu seen at least once earlier this year. And if global market tightness eases as expected, with growing supply from unconventional projects in North America and the Asia-Pacific, LNG should be easily affordable by Mexico[JA34].
Outlook