Shale gas has revolutionised oil & gas markets across the Americas, and is no longer a regional industry. The US Energy Information Administration’s estimate for commercially recoverable shale gas reserves worldwide stands at 7.3 trillion cubic feet this year, up from 6.6 trillion in 2011. Gas demand is expected to increase by more than 50% from 2010 to 2024.

Much of the effect of shale gas on the project finance market is indirect, since smaller players usually use equity, and larger players corporate debt, to exploit reserves. But has led to changes in the pattern of US midstream and power development, and is now starting to affect midstream and upstream oil and gas development worldwide. Project Finance gathered lenders, sponsors and an adviser focusing on Latin America to see how their market has been affected.

Brian Eckhouse (BE), Project Finance: What have you observed about global gas price trends?

Guillermo Ortiz (GO), director, project finance Latin America, Bank of Tokyo-Mitsubishi UFJ (BTMU): The outlook for gas is not uniform. It varies per region, but overall, it has turned the flows and the pricing for liquefied natural gas (LNG) specifically around. We feel that there is trading arbitrage with Asia.

Troy Alexander (TA), partner, White & Case: LNG pricing over the years has been essentially regional pricing, and it has largely been organised around what would be the substituted cost of the energy that would otherwise be needed. So there were various crude cocktail structures and other energy-equivalent metrics that were used as pricing mechanisms – though the details of LNG pricing have been one of the more carefully guarded aspects of the business. Transparency has been a bit of a challenge in this area. The US market, though, has proven to be a Henry Hub-organised market, which means you’re looking at exchange pricing opportunities in ways that haven’t been available to the same extent in the past. As you were saying, Guillermo, people will be looking at the arbitrage opportunity between US pricing and the traditional pricing of the LNG that’s being sold in Asia and other marketplaces.

GO: I also understand that many Asian consumers have been pushing suppliers to detach from the formula that links LNG to oil, or to a cocktail of oil indices.

TA: There has been significant pressure from the buyers to reconsider some of the provisions in traditional LNG sale and purchase agreements (SPAs), such as pricing, where the end product goes and diversion rights.

Ralph Scholtz (RS), head of project finance Latin America, BTMU: Our experience has been that the gas is priced based on the end market or the alternative use of energy in the destination market. So, a lot of the LNG projects in the past were very much targeted at certain markets, and the gas was priced as an alternative to the market that the gas was being directed to, and that’s one of the things that’s being changed.

TA: And if you use that model, it would, at a macro level, start from the price in the regional market where the LNG was going, and then you would back out the costs that were incurred to get it there – the famous “netback” pricing structures.

BE: There are several export LNG projects planned in the US, but only two have the right to sell to all countries. Do you expect the US government to extend this right?

Lance Crist (LC), global head of oil & gas, International Finance Corporation: There are different forces at work. On the one hand the domestic exploration and production (E&P) industry is very keen to take advantage of the netbacks that they believe are achievable, given the prices being paid today in Asia for LNG. On the other hand, you have energy-intensive industries, such as fertilisers, which would like to see gas staying in the US, keeping prices relatively low, and enhancing their competitiveness. These lobbies obviously are positioning their respective interests.

That said, with the approval of Cheniere, we are likely to see more approvals. But a combination of factors may limit how many there will be, relative to the 18 or so projects that have been mooted to some degree or another. It’s going to be a combination of economics on the one hand, and politics on the other.

The economics are likely to be driven by the in-flow into the global market of the Australian energy projects, the eventual realisation of LNG in Mozambique and Tanzania, and in the competing North American projects coming out of Canada. So that’s clearly going to impact the overall global supply demand balance in the pricing, and that, in turn, may conveniently fit with the political need to balance energy security and domestic US jobs and marketed considerations.

Justo Garcia (JG), chief financial officer, Enagas: Mexico is interconnected to the US. It prices its gas off Henry Hub, and there’s a major expansion underway of their pipeline system to be able to import more gas on land. And they also may be a big part of the LNG story in the case that the liquefaction plant development in the Texas coast is delayed. They’re basically part of this joint US-Mexico market.

GO: With Mexico, it’s essentially the same fields as the US – or the same basis – in the northern part of Mexico. Venezuela is rich in natural gas. Argentina also has potential, but certainly they are way behind the curve when it comes to owning the technology to exploit this. Colombia has some ability to export, but certainly not to the level of that of the US. Colombia may serve Central America and its neighbours. The US is aiming at becoming a global provider, but that’s not the case with the Latin American countries.

LC: At IFC, we’re working with EXMAR on an energy export project in Colombia. It’s a 500,000 tonne per year (tpy) small-scale facility that will serve smaller but quite needy markets, including Dominican Republic and Jamaica. But these countries today lack receiving terminals, so there’s a bit of a chicken-and-the-egg scenario. So as EXMAR looks to position this project for eventual commissioning in 2015, you really have to look to the international markets to support the initial commissioning and operations, enabling the market to be developed in the Caribbean over the medium term.

There’s another issue: these Latin American markets – generally importing markets – see the very low Henry Hub prices, and salivate at the prospect of accessing energy at those prices, but that won’t happen. The reality is, when you add on the liquefaction and transport costs, you’re talking more than double the Henry Hub levels. And the owners of the export terminals are concerned about the creditworthiness of the offtakers.

Santiago Pardo (SP), chief financial officer, Transportadora de Gas Internacional: Colombia is exporting gas to Venezuela through a pipeline that interconnects both countries, but it may need to build import terminals, too. The issue in Colombia is flexibility of supply. Colombia’s power grid is very heavily hydro-based, but if there’s a drought, the country would need a lot of gas to power thermal power plants. Colombia’s current natural gas production probably couldn’t accommodate that plus exports. To be able to sign long-term LNG export agreements, Colombia will need the flexible source of supply that can only be provided by LNG, because you can store it and sell it when you need it. So, the Colombian government and regulator are trying to make import terminals viable – one on the Caribbean coast, and another potentially on the Pacific coast. The Colombian case is indeed quite interesting: To be able to make exports on the long term viable, you need to have import capacity.

Peru, on the other hand, is a natural exporter of LNG. Some of it is contracted for Mexico, but it might make more sense for it to go to Asia or to Chile, given that Mexico is interconnecting with the US and will increasingly be supplied from there.

Then you have Chile, which is a natural importer. A few years ago, the question in Chile was whether it would make sense to continue to move toward gas as the primary fuel for new generation projects or whether coal, hydro or other fuels would support new development. Environmental issues with hydro and coal seem to be pushing Chile toward gas.

RS: Because of Argentinean domestic issues, the county cut off gas supplies for export, leaving Chile hanging dry. This prompted Chile to begin developing receiving terminals. The source of that gas could come from the Camisea field in Peru, but it wouldn’t be surprising to see a US exporter come in. The credit worthiness of the LNG buyer may determine this.

BE: We’ve yet to discuss Uruguay, where an offshore re-gas project is being developed off of Montevideo.

Tatiana Preta (TP), BTMU: Uruguay has been on the radar of project finance for a while, though previous deals have mostly been export credit agency/multilateral supported corporate financings tied to government entities. But Uruguay is an investment-grade country, so I don’t think banks look at Uruguay as they do Venezuela or Argentina.

RS: Uruguay has historically been dependent on the two countries it sits between, Argentina and Brazil, for energy sources. So, this re-gas project there would provide some energy independence from its neighbours, or at least some insulation.

BE: We’ve discussed the implications of the shale boom and the desire for domestic energy security. Is one factor more critical than the other?

LC: I don’t see them being mutually exclusive. Santiago mentioned the importance of recognising flexibility, and that’s true in all these countries, as well as the ability to diversify fuels. The Caribbean is heavily dependent on diesel and heavy fuel for power generation, and prices have shot up with the sustained rise in crude prices. The impact on those economies has been devastating.

So the ability to diversify gives them a long-term insurance, but also hopefully some economic competitiveness as well. I don’t think there’s going to be some sort of new paradigm in pricing that says that because gas is going to be available at Henry Hub in the sort of $4-7 range in the US that suddenly the availability of LNG in these markets is going to be $10-11. I think that producers are going to rightly look to arbitrage across the best markets. The supply is going to migrate toward the most profitable destination.

BE: There was an expectation that Europe would be as big a buyer as Asia. But that hasn’t happened.

GO: The outlook is not the same across all regions. Europe has struggled; the recession has affected their economies – and for a while. So that has reduced its consumption for some of these fuels, which then limits their investments in these fuels. Europe will remain an important market, but the focus clearly is on Asia. China and other Asian economies keep growing, and they keep demanding these fuels. This is nonstop.

But it’s important to note that the shale discoveries in North America aren’t just influencing outside regions. The gas is also affecting North American projects – especially in the petrochemical and power generation sectors here – simply because the fuel is cheaper and more competitive. It obviously will displace coal as a generating fuel. We already saw Braskem and Idesa close an enormous debt financing, in late 2012, for the Etileno XXI petrochemical project in Mexico. Oil companies are developing petrochemical projects on the Gulf Coast. Those players that enjoy the lowest cost of production will displace supply accordingly – that’s what cheap gas in North American creates. I mean, it revolutionises the value chain of these industries.

SP: The rise of new petrochemicals projects with cheaper costs in North America is questioning the viability of such projects elsewhere in the Americas. In Peru, there were plans for petrochemicals projects developed by North American sponsors. Although Peru continues to have very cheap gas, these sponsors are considering relocating these projects to North America. The sponsors originally planned to export the output of these projects to North America, but they can simply locate these projects in North America now. So, having cheap gas is no longer enough.

BE: What type of deal flow will we see in the petrochemicals sector in the Americas in the next three years?

RS: We’ll probably see more investment in the petrochemicals sector in the US and less in some of the gas-producing countries generally. But will countries like Peru or Trinidad allow more gas to be exported and less to be consumed, or to foster the development of other domestic industries? That’s the question.

BE: What’s driving the burst of activity in the Mexican pipeline sector?

GO: Mexico’s natural gas sector is fully interconnected to South Texas, and accordingly, the pricing formulae for natural gas in Mexico is linked to Henry Hub and so and so forth. And the industrial pace continues to expand in Mexico. It’s now in a much better position, vis-à-vis China in the manufacturing sector.

Obviously the consumption of fuel grows. Not only gas as fuel for the manufacturing and chemical sectors, but also the consumption of electricity is growing. Comisión Federal de Electricidad (CFE) owns an old fleet and has undertaken an expansion programme since the late 1990s.

Mexico has been keeping us busy the past year and a half. It wasn’t that way two or three years ago. It had been a big slump.

JG: There is strong appetite in Mexico. You go to a Mexican bid and there are six to seven players submitting bids, which brings tariffs down and introduces some competition in the country. This is how the CFE market works. The CFE is trusted and reliable and they have decades of experience and excellent performance.

GO: Right now, exploration and production of oil and gas is out of the reach of private companies, because it’s exclusive to Pemex under the constitution, though that may change under the new government. It would be a big change if that happens, and it would be a bonanza, because there will be investment going into a sector that is thirsty for money.

BE: How much debt is available for the mega-projects?

GO: It depends on the type of facility – and the sources of the debt. The amount of debt is also tied to the offtaker – specifically the offtaker’s credit worthiness. With a mini-perm, you can get as much as Cheniere did in the bank market for phase one of Sabine Pass. Most of the project finance banks joined the deal as well as many other non-project finance institutions because it is essentially a feast of fees with eventual bond take-outs.

TP: The offshore receiving terminals will cost about $300-600 million, which is much more palatable.

BE: Is there sufficient capital to propel these expensive LNG, pipeline, petrochemical and fertiliser projects?

LC: If you look at these mega projects, there actually aren’t many of them. The extent of appetite is limited more by tenor from commercial banks. Getting much beyond 12 years can be quite challenging regardless of the size of a financing; if you need billions of dollars, you’re looking to mop up every available source: multilaterals, export credit agencies, local and international banks, covered, uncovered tranches, and sometimes even local bond markets.

One significant change we’ve recently seen has been the rise of China Development Bank and China Ex-Im (Chexim), which has helped offset the pullback of a few of the European ECAs. Chexim and China Development Bank played major roles in the $20 billion financing supporting the Ichthys LNG project in Australia. You could note that Australia is essentially their home turf. Well, Chexim is mandated alongside us in this Colombia liquefaction project. They’re interested in coming into the Americas – and they’re a major potential source of liquidity.

JG: There are also infrastructure funds, though they’re mostly targeting the US and Canada markets. Only six or seven infrastructure funds are able to do an LNG plant or gas pipeline in Chile, Mexico, Colombia or Peru. Having said that, there is huge liquidity among equity investors, which is attracting some infrastructure funds to greenfield projects. Two years ago, infrastructure funds were only interested in brownfield projects. Everything has changed.

SP: Another source of funds is the public equity market. The public equity markets are generally open and investors are willing to invest substantial amounts of money in a well-positioned company or project company in the sector. For example, the recent IPO of IEnova (Sempra’s assets in Mexico) was very successful. Potential returns are attractive.

GO: Justo, how do you scan for opportunities in Latin America and how do you select countries to focus on?

JG: First, Enagas is willing to undertake projects only in those countries where there’s stability in the legal and regulatory frameworks – very clear rules of the game. Second, because Enagas is a regulated company in Spain, and we are seeking to partner up with world-class offtakers that we’re confident will be strong and stable partners – such as CFE and Pemex in Mexico. Third, we’ve initially sought only minority stakes in projects in Latin America, such as Altamira and Quintero, so we can gain knowledge of these markets. We’re in the learning curve of internationalisation.

GO: What are your takeaways two years into this internationalisation process?

JG: It’s very important to note that Enagas shareholders are very conservative. It was difficult at first to convince our board of directors and shareholders to let us expand. But the Mexican and Chilean markets have fully met our expectations. After reaching those milestones, the shareholders of Enagas are happy and surely willing to let us expand into other similar stable markets. They are more comfortable.

BE: Justo, you mentioned that expectations have been met. What types of returns have you seen?

JG: About mid-teens IRR in a standard emerging country in Latin America compared to single-figure IRR in Europe. Another important point: we’re signing long-term contacts with world-class offtakers – say 25-year transport service agreements – so in a way, we are securing our revenues for the future as well. Usually we are most likely participating in those projects denominated in hard currency. So in Latin America, we are targeting US dollar-denominated projects, but we are not discarding to participate in some local currency-denominated projects.

TA: I have one final question. Over the last few years, oil prices spiked and they’ve stayed high, while gas prices went up but have since come down because of the shale gas play in the US. Is there a differential in oil and gas prices when you look at the international market? Oil is maybe $100 a barrel. If oil came down to $60, would the economics, and pricing, of gas change again?

JG: Those contracts signed years ago are heavily linked to traditional energy exchanging points like the Brent, and we are witnessing a move of those contracts into Henry Hub links right now. So in that sense, I will say that no forecasts are available that are seeing a downturn in the price reaching to $60-70 range so far. We are witnessing a de-coupling process with the Brent or WTI indices. Right now it’s appearing in the Henry Hub reference as something completely independent to that.