The map will be familiar to most active in the liquefied natural gas (LNG) field. It has appeared at more than one conference, and in more than one publication. And it changes on average twice a week.

The Federal Energy Regulatory Commission's (FERC) LNG map is maintained in its Office of Energy Projects by Jeff Wright, head of its Infrastructure Policy Group. It tracks the 55 LNG receiving terminals proposed or in existence in the US, Canada and Mexico. And that number fluctuates as new projects are proposed, and then are approved or die.

Two things immediately strike the viewer after looking at the map: that the proposed terminals are concentrated in a small number of clusters, some of them in areas that already receive large quantities of gas; and that there are more terminals than the US lending community can possibly digest in a decade. This has been the consensus in the market for several years now, but few developers or lenders have found a way of divining which projects live and which die.

One key factor in the speed with which projects go forward is FERC approval. FERC has the power under the Natural Gas Act to approve such gas projects, and has been able to exempt them from open access requirements by making this applicable only after gas leaves the facility, according to Section 3, rather than Section 7 (c) of the Natural Gas Act. FERC has also attempted to make the approvals more efficient.

Robert Cupina, deputy director of the office of energy projects at FERC, is keen to stress that the commission will judge each case on its merits, and would not bow to local opposition during the approvals process, as some lenders have suggested. As such, and since Cupina will not be drawn on the question of whether more than 50 projects are necessary, most participants have had to decide, maybe reluctantly, that the project's own merits, rather than the hand of FERC, will likely guide their fate.

Sensitivity to local politics

But the relative force of local opposition is still a factor in which projects get passed, as can be seen from a closer inspection of the map. With the exception of expansions of existing terminals, and two Bahamas-based projects, the recently approved projects are all located in Louisiana or Texas: Governor Blanco of Louisiana, for example, has been vocal in her support for new projects.

It is local opposition that the major oil and gas producers have been unable to counter in an effective fashion. While there is no intrinsic reason why a large organisation cannot effectively bring its putative hosts round to approving a terminal, smaller players often have greater reserves of patience. They also often enjoy a slight advantage in public perception, and have few alternative sites – Chevron and ConocoPhillips, for instance each have three sites under development, and often have terminal agreements with other developers.

The result of this dynamic is a potential windfall for project finance bankers – a slew of thinly capitalised developers touting projects with potentially solid credits. Or, as Michael Whalen, HSBC's head of project finance for the Americas puts it: "It's a tremendously exciting time to work in LNG, the national oil companies and supermajors."

Whalen's views were particularly focused on North America, although the Mexican and Canadian markets offer different challenges from the US. Mexico, Whalen pointed out, has identified LNG as a key contributor of energy but also that of a policy debate between CFE, the state electricity supplier, and the state oil & gas monopoly Pemex on the supply of natural gas.

Canada's LNG market has also been very active, but those projects directed to supplying Canada's southern neighbor will have to look carefully at pipeline capacity and availability. Provincial versus federal regulatory authority may still be an issue, with some believing that Canada's National Energy Board is still working out what its role in LNG development will be. Nevertheless, two terminals – Irving Oil's St John, and Anadarko's Bear Head project – have been approved north of the border. "Bolivia," according to Whalen, "has one of the best resources available, but because of its current difficulties has fallen off many sponsors' map."

Getting TUAs right

The backbone of a terminal financing, and the reason for bankers' interest, is the terminal use agreement, or TUA. A developer looks to sign an agreement with a strong counterparty, usually an oil major, that will expose it to as little downside risk as possible.

The agreements, which will be the major element in maintaining lender comfort, need to be crafted with care, according to Tim Unger, partner at Andrews Kurth. Such an agreement needs to be assembled in the context of a spectrum of choices of financing structures, and risks.

According to Peter Rigby, director of the Utilities, Energy and Project Finance Group at Standard & Poor's, "the most fluid risks are changes in fiscal and operating regimes, counterparty risk, and volatility in gas prices." Borrowers may be tempted to adopt financing structures that more resemble corporate financings, with a number of agreements subsumed to a holding company financing, a solution that would avoid some of the complexity that accompanies the myriad agreements of an LNG financing. It would also allow a terminal owner to contract with a greater number of partners, on a greater variety of terms, than might normally be feasible with a strict project financing.

One frequent complaint about the impact of LNG upon conventional gas markets is that the consequences of mixing LNG with existing, lower heat-rate, gas supplies are not completely quantified. For instance, as Rigby notes, GE might not assume the risk of damage to its gas turbines from the use of the higher BTU gas from LNG imports. Moreover, he adds, while existing pipeline networks are able to deal with the first wave of imports, "if additional capacity is not built, the next group of terminals will find it much harder to operate."

Rigby is able to conceive of a number of alternative ways of financing LNG terminals, including the possibility that a utility might be able to construct an LNG terminal, although he concedes that gaining approval from a state electricity regulator might be a stretch. It is even possible for an independent power producer to pursue an integrated LNG and power project in the US, as AES has done elsewhere and plans to do in the Bahamas and Florida.

The current trend towards financings based on a small number of oil major offtakers may not ultimately prevail – ExxonMobil has already said that it will operate its own terminals in its own interests, a course of action that the FERC's decision to exclude terminals from open access rules has permitted.

Such a merchant LNG terminal is probably only for the majors, and so it is unlikely that there will be an explosion of merchant LNG deals as there was in the power sector at the start of the decade. Or, as Rigby puts it: "If I went out on a limb I'd say that LNG receiving terminals are less risky than merchant power, since with merchant power barriers to entry were low, as was market power. With LNG, barriers to entry are high."

Southern strategies

These barriers have encouraged some developers to examine placing LNG terminals in Mexico, within reach of the US market. Among them is DKRW Energy, set up by former Enron principals and with a focus on LNG, wind energy and coal liquids. DKRW wants to build the Sonora Pacific project, a 1.3 billion cubic feet per day (cfpd) LNG regas plant proposed for Puerto Libertad on the Gulf of California.

According to Tom White, the managing partner responsible for the project, the project exhibits strong fundamentals thanks to an agreement with El Paso to build a pipeline north to the US border, and the prospect that oil-burning projects in the vicinity of the terminal could be converted to burn natural gas. White says that working with the CFE on the plant conversions is the top priority, and has already secured the necessary land for the project (in August 2004), as well as support from the state governor.

The project is unlikely to rely upon the fundamentals of the Mexican market to make it attractive to lenders. According to Chris Goncalves, a director in Navigant Consulting's energy markets and transactions practice, the official base case for the growth in gas demand in Mexico over the 10 years from 2003-2013 is 5.8%, reaching 9.3 billion cfpd, while the low case stands at 4.4%, reaching 8 billion cfpd. And at the same time, however, it is unlikely that ambitious projections for Mexican gas production will materialize – the assumptions of Pemex fiscal autonomy, ample access to capital, and for success rates embedded in the multiple service contract programme for the Burgos gas field, are in Goncalves' view quite optimistic.

In these circumstances, and outside of NW Mexico (Baja California and Sonora), the opportunities for cross-border exports will be limited. The current likely LNG projects – Altamira (500 million cfpd), Costa Azul (1 billion cfpd), Sonora (1.3 billion cfpd) and Manzanillo (1 billion cfpd) – would take Mexico about half way towards meeting the growth in demand – allowing for meaningful exports to the US from NW Mexico while drawing greater volumes of imports at crossings on the Texas border.

Goncalves says that several LNG projects are delayed by internal government debate as to optimal locations and commercial structures involving CFE and Pemex. "SENER [the Mexican Energy Ministry] needs to moderate and resolve these debates over where LNG should go, but does not currently seem to have the necessary resources to fill this role". The mix of CFE, private and possible Pemex projects will require strong leadership from the government.

Creative finance

The developers of the Calhoun LNG project – Gulf Coast LNG Partners – have been examining the use of a municipal bond issue to finance their 2 billion cfpd receiving terminal, located at Port Lavaca-Point Comfort.

The proposal elicited a fair amount of interest from bankers, if only because by issuing tax-exempt bonds though Calhoun County Navigation Industrial Development Authority the project will be able to control its interest costs and thus the price it can offer to customers.

Calhoun could be eligible for 90% industrial development bond financing (10% – a proposed natural gas liquids facility – would be carved out) if it finds a suitable guarantor. The guarantor is the key element of a financing, and could be a terminal user, say an oil major, or even a monoline. The two requirements would be to cover the debt and provide a commitment to buy the facility at the end of the bonds' term. This element will make the Calhoun project financing slightly more complex than normal.

But the standard for developers to follow is Cheniere Energy, which completed one financing this year, and is on course to complete a further two if the financial markets are benign enough. Participants at the roundtable could not praise Cheniere highly enough, in part probably because CFO Don Turkleson was in attendance. But the Cheniere-sponsored Sabine Pass financing, an $822 million loan led by SG and HSBC, is the first completely greenfield LNG financing to close.
The 2.6 billion cfpd regasification terminal benefited from having terminal use agreements with Total and Chevron, as well as supportive residents (the project is located in Cameron county, Louisiana) and being the first mover. It sold down extremely strongly in syndication, despite being 80% leveraged.

The sponsor has several further terminals in the works, including Creole Trail, a 3.3 billion cfpd terminal, also located in Cameron county. Cheniere submitted its applications to FERC on May 23, 2005 for its 3.3 billion cfpd Creole Trail LNG receiving terminal and its associated pipeline. Construction began in the first quarter of this year on its wholly-owned 2.6 billion cfpd Sabine Pass LNG receiving terminal and on the 1.5 billion cfpd terminal in its 30%-owned Freeport LNG venture. Cheniere also received approval from FERC in April 2005 to site and operate its wholly-owned 2.6 billion cfpd LNG receiving terminal near Corpus Christi, Texas.

Danger of overbuild?

Given the scope of these plans, it seems reasonable to ask Cheniere's CFO Don Turkleson whether we are setting ourselves up for an overbuild in the US. His answer adds some perspective to the number of projects that have been announced: "If you think of an overbuild as simply having more capacity than is being used, you could say we have an overbuild right now. The current LNG receiving capacity in the US is about 2.5 billion cfpd, but last year we only brought in about 1.7 billion cfpd. To a much greater extent the same is true in Japan, where the capacity is between 2 and 3 times their usage. There is nothing that says you cannot have more capacity than required or that it is a problem to be at less than 100% utilization. That is the norm. There is, however, a significant need for additional receiving capacity in the US. There is a lot of difference, though, between a dot on the map at FERC's website, which represents an announced project idea, and a terminal project which has been filed with FERC, approved by FERC and is under construction. A lot of the 'ideas' will fall by the wayside, as several already have. We anticipate that approximately 8-12 receiving facilities will be built."

Swami Venkataraman, director in the utilities, energy and project finance group at Standard & Poor's, adds that the changing predictions of the forecasters are a large part of the uncertainty over the need for planned capacity. "The Energy Information Agency and National Petroleum Council's annual forecasts from 1999-2005 have shown sharply lower expectations for domestic natural gas production and imports from Canada each year, setting the stage of LNG imports into the US". Venkataraman echoes his colleague Rigby's analysis – that merchant LNG facilities are hard to justify owing to the large capital expenditures required and high commodity price volatility.

According to Turkleson, Cheniere had originally looked at keeping about a third of its capacity at each terminal free for spot market LNG cargoes or other short-term arrangements. However, when it received firm offers for long-term terminal use agreements from both Total and Chevron at the same facility (Sabine Pass), Cheniere chose to commit more of the capacity at that terminal on a long-term basis than it had originally planned (the company does still plan to retain about a third of the aggregate capacity of the terminals it operates for commercial optimization). The move made a conventional project deal, as well as a mooted capital markets refinancing, much more feasible.

Although HSBC has come out well from its relationship with Cheniere, and certainly better than many observers might have expected when it first picked up an advising mandate, Whalen has no doubt that there are several markets in which a developer might go to seek finance. "There has been an emergence of new players in the financial markets that are willing to share in risk. If a facility is subject to a set of shorter-term markets, or a project has a large portion of uncontracted capacity, to price some of those risks."

The providers in question are the hedge funds and loan funds of the term B market, and the extent to which they will participate in LNG financings depends on the nature of the contracts that supermajors and others will offer to developers. As Navigant's Goncalves notes "under the current contract structures, whether push tolling or pull tolling, the market works around the supermajors – given the volume of capital, value chain management, and commodity supply involved. Given the current outlook for other gas reserves development throughout North America, we're probably looking at a window of opportunity of 10-13 years for LNG developers, maybe more...".

S&P's Venkataraman, notes that "there has been a tremendous destruction of demand in the industrial side for gas, and the real growth has been in power. The reason why no-one is building clean coal is that its reliability on a large-scale is hard to know. But there is no doubt that the chemical companies see it as a way to deal with high gas prices." However, FERC's Cupina is certain that, "gas and LNG is the only solution in the short and medium term. You might have a plan for a 1400MW coal plant and transmission line from Arizona to California, but it's going to be very hard to develop."

Ship to shore

Developers might be able to get around local opposition using on-board regasification technology, as well as several other offshore receiving technologies. The leader in this respect is Excelerate Energy, which acquired El Paso's Energy bridge technology, and has since managed to land and regasify a test cargo from Malaysia. Indeed, given El Paso's formal absence from the market as a developer, its presence, both in the form of alumni at other developers, and as an offtaker and source of technology, is impressive.

The idea of offshore regasification is tempting, since it does eliminate local opposition, and it in theory allows suppliers a greater flexibility in where they send cargoes. But the ships in question have a limited capacity, and take seven to eight days to disgorge the gas in question. Several participants saw the technology as a useful way to provide swing capacity to supply constrained markets such as New York and other parts of the northeast.

Mark Thurber, a partner with Andrews Kurth, notes that technology and costs might make offshore facilities more difficult to finance, and a financing more complex, but adds that the fact that the facilities come under the Marine Adminstration (MARAD), part of the US Coastguard, might streamline the permitting issues. Indeed the process is likely to be similar to that for a oil rig.

Race for the prize

If LNG remains competitive, and national oil companies sitting on stranded reserves remain creative, then the most obvious losers, as S&P's Venkataraman notes, are the marginal exploration and production players that cannot compete with LNG suppliers that can produce at $3 per million BTU.

But other potential markets are also racing to secure additional supplies. As Navigant's Goncalves notes, the European governments have been planning for decades to move to a gas-based electricity sector, and see LNG as 20-30% of the solution. This may make it harder for US importers to realise attractive terms, and competition for supply will be significant.

As Ed Feo, partner in, and co-head of, Milbank Tweed's project finance practice, and the roundtable's moderator, notes, "the one thing we've seen on the private equity side is the growth of start-ups looking for a piece of equity deals at significant rates of return. There are going to be points at which some projects get desperate for capital and will represent opportunities for such investors."