By Dan Rogers, David Schumacher and Noam Ayali

Many people expect LNG projects to become an active area of project finance in the next several years. Chadbourne hosted a well-attended workshop on the subject in Houston in February. The following are excerpts from the discussion. The speakers are three Chadbourne lawyers: Dan Rogers, David Schumacher and Noam Ayali. Rogers has years of experience with LNG, some of it as an assistant general counsel at Enron. Schumacher is a longtime project finance lawyer with a special interest in gas projects. Noam Ayali spent several years as a lawyer at the International Finance Corporation in Washington working with the oil and gas division before joining Chadbourne. A detailed outline of the issues in LNG projects can be obtained by sending an e-mail to noam.ayali@nortonrosefulbright.com. 

MR. ROGERS: I have been designated to give you some key definitions.

“LNG” probably should stand for “little or no golf” — an apt description of the lifestyle of those of us working in the natural gas industry — but its more common use is liquefied natural gas. This is gas that is carried across the ocean on tankers in liquid form and then turned back into gas when it reaches the terminal. The reason it has to be liquefied is because this is the only way at the moment to transport natural gas long distances across oceans. You need a terminal at the other end to convert it back to gas.  

“NIMBY” means “not in my backyard.” It is a term heard not only by power plant developers, but also by developers of LNG projects. However, in the LNG world, we also have “BANANA” — “build absolutely nothing anywhere near anything.” It is one thing to build a power plant in the desert or another place inland where few people are located. You can imagine the siting problems of trying to put an LNG terminal along a coast.  

Indeed, the latest acronym is “NOPE,” or “not on planet Earth.” This describes the position of some of the more extreme environmental and safety groups toward LNG import terminal development plans.  

Noam Ayali will describe how deals for LNG import terminals are structured. Structures  

MR. AYALI: There are two key project structures in the market today, and there is a potential third structure that I will call the “fully-integrated LNG import project.”We recognize that there really is no third structure yet in the market, but I offer it as something to think about. In a recent discussion with the head of an oil and banking house, this third structure came up and this particular banker thought it might offer a new way through the financing maze for LNG projects.

That said, the focus today is on the two types of LNG import projects. One is called the “downstream integrated import project.” Examples of this are the Dabhol project in India, the recently financed AES Andres project in the Dominican Republic, EcoElectrica in Puerto Rico, and most of the Japanese LNG projects. A “downstream integrated import project” is one where the import facilities are tied to one or more specific offtakers, like a power plant, a gas pipeline, or a seawater desalination plant. What distinguishes this type of project is there is common ownership of all the different components of the project, either under a single owner or affiliated ownership within a single group.  

The choice of structure has implications for the financing. The key thing to remember in what we are calling the downstream integrated project is that the offtaker is the LNG purchaser, and the LNG supplier, the transporter and the private lenders are all looking to the integrity of the project and the offtaker’s end market as the credit support for the financing.  

The other common structure for LNG projects is the “standalone or tolling project.” Examples are the existing LNG facilities in the United States — at Lake Charles, Elba, Cove Point and Everett. Also, some of the new projects that are being considered by folks like Freeport LNG are this type of project. What we are talking about is an LNG import facility that is designed to serve one or more independent capacity users. The distinction is that the facility owner is not the LNG purchaser, and he is not necessarily the end marketer or end user of the product. You have capacity users paying a tolling fee for access and usage of the storage vaporization and sendout capacity of the receiving terminal. A lender lending into this type of structure must be satisfied with the strength and duration of the charges under the throughput capacity agreement, the reservation charges and the send-out capacity. Another example of a standalone tolling structure is the recently proposed Dynegy Hackberry project. [Ed: Sempra Energy recently acquired the project from Dynegy].  

Let me turn next to some general issues in financings, and then we will get into the meatier part of the discussion about LNG-specific issues. What follows is important because it ties into how best to set up a project and coordinate efforts with partners. Some of what I am about to cover probably relates more to jurisdictions outside the United States.  

First point: as you are assembling your consortium, find out whether there is specific petroleum legislation and whether there are specific LNG regulations. Also be aware of the political environment and expropriation history. Venezuela is a recent example of what can go wrong, even though the actions there affected only the liquefaction side of projects.  

Next point: let’s talk about partner selection and due diligence issues. There are often legislative requirements for local partners. This will affect financeability, as there is a danger that the local partner’s credit will effectively become the lowest common denominator for your project finance lenders. Be aware that if the local partner is a state-owned entity or host government, it may have restrictions on its ability to grant security interests because of World Bank lending arrangements. Be sure to vet at an early stage in the development arrangements any differing objectives within the sponsor group. For example, one member of the group may be interested only in the fuel supply arrangements. Another may be interested in owning assets. This will affect how issues like sponsor withdrawals, and sponsor rights and obligations are addressed. This needs to be hashed out at a very early stage.  

MR. ROGERS: Let me give you a real-life example of the types of problems that can arise when members of the sponsor group have different objectives. Not very long ago, I worked on a fairly large gas pipeline development project where — as a result of a merger — we wound up with a foreign oil major as a partner who was not terribly interested in project financing and saw no need for leverage. As time passed, we found ourselves doing detailed risk analyses with the aim of using project financing, and our partner could not see any value in the exercise. It planned simply to write a check for its share of the project.

The disconnect began to color the relationship among the parties. Things eventually deteriorated. The point is to make sure you are all on the same page, especially about whether project financing will be used.  

MR. AYALI: Maybe the last point to make about the preliminary project development arrangements is the choice of local partner may bring into play US Foreign Corrupt Practices Act, transparency and corruption issues. A US developer can be held accountable under the Foreign Corrupt Practices Act for malfeasance by his partners. If the project intends to buy political risk insurance, malfeasance by one of the partners could be grounds for the insurance company to refuse to pay a claim or to terminate the coverage. That’s a 30,000-foot view of some preliminary issues. Now let us move into more LNG-specific issues. US Onshore Projects

MR. SCHUMACHER: I am going to start with permitting issues. I will talk first about US onshore facilities and the regulatory regime that applies to them, then discuss US offshore facilities, and then talk about the regulatory regime for receiving terminals in Mexico.

Starting with US onshore terminals, as is the case with interstate natural gas pipelines and storage facilities, the Federal Energy Regulatory Commission also has jurisdiction over the siting and construction of gas import and export facilities, including LNG receiving terminals. FERC has essentially regulated LNG import facilities the same way it regulates interstate natural gas pipelines. This is true from a siting perspective and construction perspective as well as the perspective of terms of service. Thus, when determining whether an LNG facility is in the public interest to construct, FERC has applied the same essential standards for determining whether it should issue a certificate for construction of an interstate pipeline. This means applying a cost-benefit analysis or balancing the benefits of a project versus the adverse impacts of the project.  

FERC has required LNG receiving terminals to charge costbased rates, unless there is a showing that the terminal does not exercise market power. This is the same approach it uses for natural gas storage facilities. It requires that there be on file tariffs setting forth the terms and conditions of service. An LNG terminal must provide service on an open-access basis, which means that available capacity must be offered to persons regardless of the source of gas supply.  

This approach to regulation has arguably stymied investment in LNG terminals because of the way projects are financed. An LNG project requires long-term commitments to purchase and sell gas and to store it so that it can show potential lenders it has a sure revenue stream to repay the debt.  

FERC made an important change recently in an order relating to [Sempra’s] Hackberry facility. It signaled with that order that it is willing to dispense with the requirement that terminal operators of new onshore facilities have on file tariffs and charge cost-based rates. Rather, they will be allowed to charge market rates. Operators of new onshore terminals will be allowed to negotiate whatever terms of service they can work out with customers, including rates. And most importantly, the capacities of these new terminals do not have to be subscribed or contracted for on an open-access basis.  

What FERC has done in essence is to decide that an LNG terminal should be treated more like a gas production facility than a mere storage facility or pipeline. It must have concluded that because wholesale gas prices have been deregulated for some time now, so too should LNG prices and LNG terminal users can recover costs through the sales price of the gas. This is appropriate because the developer is assuming the risk that it will be able to recover its cost. Also, with the enactment last fall of the “Maritime Transportation Security Act” — which allows so-called proprietary terminals — FERC figured that those proprietary terminals and other onshore terminals should be treated the same.  

FERC has retained the authority to remedy future discrimination. It also requires that contracts between affiliates — for example, the sponsor and an affiliated offtaker — be filed. FERC has probably created more questions at this point than it has answered. One that comes to mind is: what about existing facilities? There is now a dual regulatory regime — one for existing facilities and one for new facilities.  

MR. ROGERS: The Hackberry decision didn’t purport to supplant the existing regulatory structure. It merely provides developers with another option for how to develop an LNG terminal. Existing facilities remain subject to stricter regulation. It is unlikely the Hackberry decision can be used as grounds to change existing contracts.

MR. SCHUMACHER: An interesting question is whether the owner of an existing project might be able to build an expansion facility and cite Hackberry to charge market rates for use of it. The danger is the regulators might view the expansion as part of an integrated facility.

Another question with no answer yet is whether there is anything in the Hackberry decision that could justify different treatment for terminals in other parts of the country — the Hackberry project is on the Gulf coast — or for projects with offtakers that are affiliates of the sponsor. One of the ways FERC justified the Hackberry decision was by pointing out that the project will operate in a competitive gas market. Can the same thing be said of a project on the East coast in the Northeast?  

MR. ROGERS: I’m not sure. I think the market power analysis that FERC used in the Hackberry decision works when you are talking about terminal facilities at the inlet of the gas production and gas supply system where there are a lot of alternatives and a lot of transportation and storage infrastructure. A single terminal owner would probably have a lot less ability to exercise market power in such a location than he would on the East coast.

MR. SCHUMACHER: The Hackberry order does not address this, but it raises the question whether it is possible to draw a related gas pipeline under a Hackberry-type order so that market rates can be charged for the use of it.

MR. ROGERS: That’s correct. In December 2001, there was an attempt to try to get transportation service on the Cove Point project’s send-out pipeline. It is an 80-mile-plus pipeline. The challenging party was trying to get the cost of the LNG service decoupled from the cost of pipeline transportation. FERC rejected the challenge on the basis that the send-out pipeline was integral to the LNG facility and that by splitting it out, you may wind up encouraging the use of the pipeline to the detriment of the LNG facility. FERC wanted to ensure the economic integrity of the LNG facility.

MR. SCHUMACHER: Another point: in addition to getting FERC approval to site the project, the importer of the LNG must also ask for authority from the US Department of Energy to import the LNG. This is essentially a rubber-stamp approval. It is essentially a reporting requirement. A DOE official said at a conference recently that approvals take about a week.

Next, we want to talk about US offshore projects, and in particular the new Marine Transportation Security Act, which amended the Deepwater Port Act and basically brought offshore LNG terminals under a new set of rules.  

US Offshore Projects  

MR. ROGERS: That is a mouthful. I am going to refer to the Maritime Transportation Security Act as MTSA. Last November, the LNG industry received two early Christmas presents. One was the Hackberry decision, and the other was MTSA. MTSA essentially established the United States Coast Guard as a one-stop shop for purposes of applying for authorization to site, construct and operate offshore gas and LNG terminal facilities. The statute also applies to compressed natural gas or CNG facilities.

The Coast Guard was part of the US Department of Transportation. It has now moved to the new Department of Homeland Security. The statute requires the Secretary of Transportation, who used to oversee the Coast Guard, to make certain regulatory decisions. My understanding is that he will continue to do so, notwithstanding that the Coast Guard has been moved to Homeland Security.  

The good news is that MTSA is an improvement over the regime for land-based terminals. There is more certainly about the application process. If you get all the paperwork in and the Coast Guard determines that it is in order, then you should know within 351 days from when the complete application was filed whether you will be granted an offshore terminal license. Compare that to onshore terminals, where the process can take a year and a half to two years. So that is a great improvement. It is something that would be nice to have on the onshore side as well.  

The governors of the affected coastal states must also give approval before the license can be issued. MTSA sets a time limit for this approval. The Coast Guard will have 90 days after public hearings on the license application to be in contact with the governors of the affected coastal states. Shifting to economic regulation, offshore LNG terminals are now authorized to be operated on a proprietary closedaccess basis. This means they can charge market rates rather than rates that are tied to cost of service. Surplus or excess capacity can be let out to third parties provided that it’s let out on reasonable terms and the third-party usage doesn’t interfere with the original licensee’s usage plans.  

There is also a citizen complaint procedure. This may provide some bargaining leverage for potential users of excess capacity in the future. Such users could complain to the Coast Guard that they are not being treated reasonably. It would not surprise me to see lenders insist in the future that the terminal be locked down and not operated in a fashion that allows access by third parties.  

Mexican Projects  

MR. ROGERS. Now turning to Mexican projects, the Mexican government is still studying what the US has done in MTSA. I don’t think there will be any guidance soon from the Mexican government about the rules that will apply to offshore Mexican projects. This is disappointing. However, there is better news about onshore Mexican projects. First, the government is approaching the regulation of onshore LNG terminals from a traditional Mexican onshore storage regulatory framework. That is to say, they are starting with the regulations that apply to gas storage facilities and altering them to fit LNG. They view LNG terminals as more complicated gas storage projects. Thus, the permit that one must obtain from Mexican is a 30-year permit for a gas storage facility.

The Mexican agency — CRE — does have some special guidelines for the preparation of LNG proposals. It is important to read these. You may also have to apply for a pipeline interconnected permit.  

The good news is there actually may be an approval granted next month. Five projects have applications pending. All five seem to be on roughly the same timeline — that is roughly seven months from the initial application, you should get word back, at least on the economic permit, from CRE whether or the project has been approved.  

Environmental approvals are also required at the federal level. At the state and local levels, there are land-use issues. However, at least on the 80,000-foot level, it is a relatively expedited application process.  

An emergency technical standard for the design, construction and operation of LNG terminals was issued last August. This was part of an emergency regulation. The CRE is busy working on the final regulation. It is due out sometime in late 2003 or early 2004.  

We understand that at least 10 foreign companies have expressed a formal interest to CRE in developing LNG terminals along the Mexican coast. To date, five parties have filed applications. All five are presently under evaluation. Unless there is a hitch, it looks like the Marathon consortium permit will be granted in February, followed by the CMS-Sempra authorization in March and then on through the pack. The jury is still out on the economic regulation of Mexican onshore terminals. The original plan of CRE was to adopt a modified version of the US open-access, cost-ofservice tariff, rate-based regulatory structure, but this plan was thrown for a loop in December with the Hackberry decision. The regulators are studying the US decision, but appear still to be leaning toward their original plan. Turning to site access, direct foreign ownership of land in coastal restricted zones in Mexico is prohibited. Thus, you must either own land through your Mexican local partner or through an approved bank trust. Do not sign an option to acquire land with a local developer. It will not get you very far as a foreign investor.  

Next, Dave Schumacher will take us through some of the engineering and construction issues and operations and maintenance issues.  

Contractor Issues  

MR. SCHUMACHER: We have included an awful lot of information about EPC contract issues in the outline we handed out. Let me just call your attention to a couple of key points, and you can read the rest in the outline. The first is the issue of contractor responsibility. Project developers in recent years have been moving away from pure turnkey contracts where there is one point of contact, the general contractor, who is basically responsible for completion of the entire project, to arrangements where there are multiple contracts with multiple contractors, each of whom is responsible for a particular aspect of a project. The issue that arises in such arrangements is finger-pointing risk. If something goes wrong, everyone points to someone else. “It’s not my fault. It’s his fault.” How do you manage this risk? 

 

MR. AYALI: This issue is more relevant to the type of project we are calling the downstream integrated receiving terminal. It has many more moving parts — the terminal, docks, storage facilities, vaporization facilities, and a related power plant or a desalination plant. A word of caution to developers of such projects: your lenders will be concerned about the potential for finger-pointing if something goes wrong during construction. You need to make sure your various liquidated damages clauses fit together and that the could complain to the Coast Guard that they are not being treated reasonably. It would not surprise me to see lenders insist in the future that the terminal be locked down and not operated in a fashion that allows access by third parties.

Mexican Projects  

MR. ROGERS. Now turning to Mexican projects, the Mexican government is still studying what the US has done in MTSA. I don’t think there will be any guidance soon from the Mexican government about the rules that will apply to offshore Mexican projects. This is disappointing. However, there is better news about onshore Mexican projects. First, the government is approaching the regulation of onshore LNG terminals from a traditional Mexican onshore storage regulatory framework. That is to say, they are starting with the regulations that apply to gas storage facilities and altering them to fit LNG. They view LNG terminals as more complicated gas storage projects. Thus, the permit that one must obtain from Mexican is a 30-year permit for a gas storage facility.

The Mexican agency — CRE — does have some special guidelines for the preparation of LNG proposals. It is important to read these. You may also have to apply for a pipeline interconnected permit.  

The good news is there actually may be an approval granted next month. Five projects have applications pending. All five seem to be on roughly the same timeline — that is roughly seven months from the initial application, you should get word back, at least on the economic permit, from CRE whether or the project has been approved. Environmental approvals are also required at the federal level. At the state and local levels, there are land-use issues. However, at least on the 80,000-foot level, it is a relatively expedited application process.  

An emergency technical standard for the design, construction and operation of LNG terminals was issued last August. This was part of an emergency regulation. The CRE is busy working on the final regulation. It is due out sometime in late 2003 or early 2004.  

We understand that at least 10 foreign companies have expressed a formal interest to CRE in developing LNG terminals along the Mexican coast. To date, five parties have filed applications. All five are presently under evaluation. Unless there is a hitch, it looks like the Marathon consortium permit will be granted in February, followed by the CMS-Sempra authorization in March and then on through the pack.  

The jury is still out on the economic regulation of Mexican onshore terminals. The original plan of CRE was to adopt a modified version of the US open-access, cost-ofservice tariff, rate-based regulatory structure, but this plan was thrown for a loop in December with the Hackberry decision. The regulators are studying the US decision, but appear still to be leaning toward their original plan.  

Turning to site access, direct foreign ownership of land in coastal restricted zones in Mexico is prohibited. Thus, you must either own land through your Mexican local partner or through an approved bank trust. Do not sign an option to acquire land with a local developer. It will not get you very far as a foreign investor.  

Next, Dave Schumacher will take us through some of the engineering and construction issues and operations and maintenance issues.  

Contractor Issues  

MR. SCHUMACHER: We have included an awful lot of information about EPC contract issues in the outline we handed out. Let me just call your attention to a couple of key points, and you can read the rest in the outline.

The first is the issue of contractor responsibility. Project developers in recent years have been moving away from pure turnkey contracts where there is one point of contact, the general contractor, who is basically responsible for completion of the entire project, to arrangements where there are multiple contracts with multiple contractors, each of whom is responsible for a particular aspect of a project. The issue that arises in such arrangements is finger-pointing risk. If something goes wrong, everyone points to someone else. “It’s not my fault. It’s his fault.” How do you manage this risk?  

MR. AYALI: This issue is more relevant to the type of project we are calling the downstream integrated receiving terminal. It has many more moving parts — the terminal, docks, storage facilities, vaporization facilities, and a related power plant or a desalination plant. A word of caution to developers of such projects: your lenders will be concerned about the potential for finger-pointing if something goes wrong during construction. You need to make sure your various liquidated damages clauses fit together and that the timing and completion tests in the various construction contracts are in sync. There cannot be any holes when you present the deal to the lenders. You should also be ready to offer credit enhancement, keeping in mind that the reason you have these multiple construction contracts is because you got better prices as a result — you were able to squeeze some more savings out of the project.

MR. SCHUMACHER: Another issue relates to the commencement of project testing. Dan and I were talking recently about the need for one or more so-called cooldown cargos as a precursor to testing.

MR. ROGERS: The issue is the marriage between the EPC contract and the LNG supply contract. In a typical project, you will need an LNG cooldown cargo to test that the facility works. This cargo is usually purchased by the project developer under a long-term, take-or-pay supply contract, albeit with a fair amount of relief at least on the front end for problems during the ramping-up period — perhaps even an excuse from the take-or-pay requirement for the first cargo. The important point is that what the EPC contract says about testing must mesh with the LNG supply arrangements. You do not want to have to start the LNG supply contract in order to get access to the cooldown cargo and then have the testing reveal that the facility really isn’t ready to operate yet. Take the time to ensure the two contracts fit properly.

MR. SCHUMACHER: There is also the issue of allocating risks between the EPC contractor and the project sponsor. Who is responsible for purchasing the cooldown cargo? What happens if there is a delay in testing? What happens if the tests show the facility is not yet ready to operate?

MR. ROGERS: If there is a construction defect or other delay, it will affect your LNG supply arrangements because you probably at that point already at least preliminarily confirmed your annual cargos for the year. You have a seller who is anxious to begin delivering cargos to you.Who bears the risk when you find yourself unable to take those LNG cargos as scheduled. That is something you can try to push back to the EPC contractor in the form of delay damages. Otherwise, you will have to absorb the loss yourself. The lender will not take it.

SCHUMACHER: Next, we’d like to talk about operation and maintenance contracts. As is often the case with other infrastructure projects, the terminal operator may want to contract with a third party to provide operation maintenance services. A number of issues arise when drafting and negotiating an O&M contract for an LNG receiving terminal. We could probably talk about them for an hour. Let me just mention a couple of key ones and you can read about the rest in the outline. One relates to fuel management guidelines. Fuel management is an issue because you have a number of different offtakers or tollers who are delivering or having cargos delivered on their behalf to the LNG terminal.

MR. ROGERS: It is important for everyone to understand who has the final say on scheduling and how it will work. Anyone who has worked with LNG tankers knows that scheduling is much more an art than a science. There needs to be some flexibility. We have seen some projects where the lawyers have tried to reduce scheduling to some type of a mathematical. The formulas will not work in practice.

MR. SCHUMACHER: There is a similar issue at the other end. That is maintaining a good process for nominating sendout and working with the pipelines that are taking the gas that is sent out. Make sure the nomination schedules correlate. Make sure the O&M contractor has the authority it needs to coordinator scheduling between the LNG facility and the downstream pipelines. The process requires some thought to work properly.

MR. ROGERS: That management function is critical to the success of the project.

MR. SCHUMACHER: Another issue is unique to LNG terminals, particularly when compared to gas pipelines or gas storage facilities. It is marine works maintenance. Not enough attention is paid to this in contracts.

MR. ROGERS: The contracts need to address who has responsibility for marine maintenance and what are the consequences for failing to do it.

MR. AYALI:There have been problems in some projects with allocating liability and responsibility among the ship, the project and the port authorities. This is especially relevant in projects where you may not be working with an established port authority. You may be opening up a new port. It might be a private facility instead of a public facility.Who is regulating that? How do you address liability issues?

ROGERS:That’s where you get into a very complicated dance between local law, the various international limitation conventions that limit the shipowner’s liability for certain types of accidents, and marine insurance, which is a whole topic by itself. This is an area where you need to bring in qualified maritime legal advisors and qualified marine insurance specialists to understand how the liabili ties are being allocated throughout the chain on the ship-toshore interface.

LNG Supply  

MR. ROGERS: The next topic is LNG supply contracts. This contract is obviously central to an LNG project. Let me start with the difference between reserves availability and deliverability. Just because your supplier is sitting on an awful lot of reserves does not mean he can deliver them. The lenders and their technical advisers are going to look at every aspect of this. Deliverability is what is key to obtaining financing.

For example, there are some supply contracts with sovereign emergency gas reserve allocations that could cut off supply to the LNG terminal in the event of a local catastrophe. Force majeure clauses are important. Have a complete understanding of how they translate all the way through the supply chain. There cannot be any disconnects.  

Delivery terms have become fairly standard across contracts. LNG is basically delivered in two ways. It is either delivered ex-ship or FOB at the loading port. The traditional contract structure is a long-term 17- to 20-year take with 100% take-or-pay, perhaps with a little bit of downward flexibility. During the last several years, there has been some movement away from the traditional model with negotiations leading to multi-turnout supplies, differential pricing, and some spot capability. However, lenders are skittish after the energy meltdown in the United States, and there is pressure to return to the more traditional model.MR. SCHUMACHER: Keep in mind that you are basically trying to match up a long-term, 100% or very high percentage take-or-pay supply contract with gas offtake agreements that here in the States are typically short-term and probably sensitive to spot prices. How you mesh those two things can be a challenge.  

MR. ROGERS: Another area of evolution in deal terms is in the allocation of gas price risk. Gas suppliers are not happy in long-term contracts with taking the full price risk. There have been discussions about slicing it up between perhaps an index risk and the basis differential risk and allocating the two tranches of risk to different parties.

MR. SCHUMACHER: Query how willing suppliers will be to tie their prices in the future completely to a NYMEX or Henry Hub or any other spot price index as the basis for their pricing. If I am buying LNG to sell into the market to Industrial A or Industrial B, how can I match up my pricing with the needs of the LNG supplier? It is a real conundrum.

MR. ROGERS: Those issues are going to keep a lot of us busy in the coming years. On the subject of mitigants to pricing risks, in a contract I saw recently, the supplier had a fair amount of flexibility on the timing of its deliveries as long as it stayed within certain parameters, and it also had the right up to certain volume thresholds to substitute liquid fuel for LNG on very short notice.

Gas specification and quality certification are probably a big issue on the US east coast but probably not such an issue on the US Gulf coast where there is more capacity for pipeline blends. There is also more storage capacity. LNG from the Middle East has an extremely high heat content and is hard to handle on the US east coast. During transit — with some of the boil-off — it actually increases in heat content so that when it reaches land, it is awfully hot gas. You have a customer base on the east coast that is used to low Btu gas and will have problems accommodating very high heat content gas. Ultimately, this comes down to a question of who is going to pay for the treatment. It is an economic issue.  

Payment security is another big issue. It applies throughout the chain. Everyone down the supply chain will want an assurance that the next person to touch the gas is creditworthy and can make payment. The world has changed in the past two years. Many gas marketers had very high credit ratings and the ability to purchase a commodity without a lot of letter of credit or parent guarantee support. Now, we are back to a world in which everyone must prove he is creditworthy.  

MR. AYALI: Dan, it might be worth spending a little more time on this point, certainly as it relates to issues of private financing. We have seen gas suppliers basically taking a first secured position over all revenues generated by the LNG. They are requiring escrow accounts and other revenue arrangements. The problem is your project lenders will want the same security over the same revenues. That is where the rubber hits the road.

There are different ways to structure around this, but clearly the project lenders will have a lot of heartache over sharing security or cutting out of their security and revenue stream any potential credit enhancement or credit sources that the LNG supplier wants to see supporting his supply contract.  

MR. SCHUMACHER: The basic position of lenders in these projects is the gas supplier can be the first to be paid in the waterfall, but if there is an event of default, then all bets are off, and any cash in the waterfall is ours. This does not sit well with a gas supplier, particularly if there is no strong credit support behind the offtaker in the form of a highlyrated guarantor or a letter of credit.

MR. ROGERS: The credit issue is probably the biggest impediment right now to moving forward with the LNG projects that are currently under development. Terminal Access

MR. SCHUMACHER: The terminal access contract is the key contract for LNG terminal that plans to operate as a tolling facility. It is the contract that is the main source of revenue for such a project. It determines whether the project is financeable.

It is a lot like a gas storage contract. The terminal operator receives gas, stores it and sends it out on demand, all within certain confines of reserve capacity and send-out capacity. Of course, it is more tricky than a traditional gas storage agreement — we are talking about berthing ships and delivering liquid gas, storing it and sending it out — but the idea is the same.  

In a typical contract, the services are priced such that the offtakers will pay a revenue or capacity charge based on the amount of capacity that is reserved to hold the liquid and then pay variable charges for sendout and other additional cost charges.  

If you look at many of these contracts that are on file with FERC, what terminal operators have tended to do is essentially use their gas storage tariffs as the model for LNG terminalling services. This works more or less, but it requires thought. You can’t just pick and choose terms to take from a pure gas storage tariff and plop them into an LNG terminalling tariff.  

MR. ROGERS: Exactly. Some LNG terminal tariffs that you see today in the US have their origin in either the storage or the pipeline tariffs that were in existence at the time. They were modified for LNG. There are a couple of areas where, with the benefit of 20 or 30 years of hindsight, it clear this approach has not worked in practice. An example is interruptible LNG service.

MR. SCHUMACHER: This may be a remnant of the fact that FERC regulates LNG the same way it regulates interstate pipelines. Like interstate pipelines, LNG terminals have to provide for an interruptible service.

MR. ROGERS: In a more liquid market with LNG terminals up and down the seaboard, there may be a place for interruptible service, but until that happens, I’m not sure that the pipeline-style capacity release structure works well in an LNG terminal setting.

MR. SCHUMACHER: Another area of concern in LNG projects is how tariffs allocate liabilities.

MR. ROGERS: We did a very, very detailed risk analysis on a particular tariff on behalf of a client where, at the end of the day, we realized that a lot of the liabilities that were allocated to the importer of LNG and the user of the terminal facility under the tariff were of a nature where it was very difficult to find available insurances to cover those liabilities. The risk allocation embedded in the tariff came as a surprise to the client. The tariff had been approved by FERC. Yet, at the end of the day, when you really analyze how it works in practice, there are risks there that are getting pushed back on the user of the facility that the user of the facility has difficulty insuring against. It is important to understand the tariff, and then address issues raised by it in the terminal contract, if you can.

MR. SCHUMACHER: The last subject I want to mention is credit. When talking about a tolling terminal, a lender is going to be looking at the credit of the offtaker or the person who is buying the storage services. If that person or its guarantor is a triple A credit, you probably don’t have an issue, but there are almost no triple A credits in this business. So the question is what type of offtaker credit will the lending community require before providing financing?

FERC has traditionally allowed gas pipelines to ask customers for credit support like letters of credit or guarantees that cover approximately three months of service. However, in a number of instances, particularly in project financed pipelines, FERC has allowed pipelines to ask for credit coverage of up to a year’s worth of service. Lenders have been willing to finance pipelines on that basis. The issue is what lenders will require of LNG terminals. Is triple B credit enough? Will lenders look to downstream sales contracts and do essentially a receivables financing where this storage buyer is entering into contracts with downstream buyers and lenders are relying on that revenue stream? This is one of the more interesting questions facing LNG projects. How will lenders get comfortable with the credit?