LNG and export infrastructure

Why liquefied natural gas exists at all

Crude oil is a global commodity because it is easy to move. It is dense, it goes on a tanker, and a barrel produced in one hemisphere can economically reach a buyer in another. Prices therefore converge worldwide subject to quality and freight differentials.

Natural gas is not like that. It is a low-density gas, so moving it any real distance requires either a pipeline, which is fixed and expensive and only connects the two places it connects, or cooling it to a liquid so it occupies a fraction of the volume and can be shipped. That physical constraint is why regional gas markets exist with prices that can diverge enormously, and why a producer in a landlocked basin with limited takeaway capacity can be selling into a market with far lower prices than one a thousand miles away.

Liquefied natural gas is the mechanism that gradually links those markets. Gas is chilled to a liquid at an export facility, loaded onto specialized ships, delivered to an import terminal, returned to gas form, and sent into the local pipeline network. Understanding that chain matters in an interview because each link is a different business with different economics, and candidates often collapse the whole thing into one.

The chain and where the money is

Liquefaction is the capital-intensive step and the one bankers spend the most time on. An export facility costs an enormous amount, takes years to build, and is immobile and single-purpose. Once built, the asset cannot be repurposed if the market moves against it, which is precisely why it does not get built on a hope.

Shipping is a specialized fleet business with its own charter market and its own cycle. Vessels can be chartered long-term to a project or traded in a spot market, and charter rates move with the arbitrage between regional gas prices, since wide spreads make more voyages economic.

Regasification is comparatively cheap, and import terminals have historically been the less constrained part of the chain, which is why the bottleneck and therefore the value has tended to sit in liquefaction capacity rather than in the ability to receive cargoes.

The economics that make the whole thing work are the spread between the cost of gas at the export point and the price of delivered gas at the destination, net of liquefaction, shipping, and regasification costs. When that spread is wide, cargoes flow and the arbitrage is profitable. When it narrows, marginal cargoes stop moving. A project that has sold its capacity forward under a fixed fee is insulated from that spread; a project or a portfolio player taking merchant exposure is not.

Why a project must be contracted before it gets built

This is the single most important structural fact about the sub-sector, and it is the answer to the question interviewers most often ask.

Lenders will not fund a multi-year construction project on an immobile, single-purpose asset against merchant price exposure. There is no way to recover the investment if the market turns, because the facility cannot be moved, cannot be repurposed, and produces a commodity whose regional price can collapse. The solution is to sell the capacity forward before construction, under long-term agreements with creditworthy counterparties, so the debt is serviced by contracted revenue rather than by market outcomes.

Signing a large share of capacity under those agreements is generally the precondition for reaching a final investment decision, which is the point at which the sponsors commit the capital and construction begins. Before final investment decision, a project is a development effort with permits, engineering work, and a marketing campaign. After it, it is a construction project with a financing package. That transition is the event that matters, and a candidate who knows the term and what triggers it sounds informed.

Tolling versus sale-and-purchase agreements

There are two dominant contracting models, and the difference is who carries the commodity spread.

Under a tolling agreement, the customer delivers its own gas to the facility, pays a fixed capacity or liquefaction fee, and takes the liquefied product. The project is a processor: it earns a fee for a service and takes essentially no commodity price risk. The customer bears the spread between the gas it bought and the delivered product it sells. Many tolling arrangements are structured so the fee is payable whether or not the customer actually uses the capacity, which makes it functionally a take-or-pay obligation and gives the project the highest-quality revenue available in the sector.

Under a sale-and-purchase agreement, the project buys the gas, liquefies it, and sells the product to the buyer, usually with pricing indexed to a benchmark, sometimes a gas hub price plus a fixed markup and sometimes a crude-linked formula. Here the project retains more exposure, because its margin depends on the relationship between what it pays for feedgas and what its pricing formula delivers.

Two other terms come up. Destination flexibility determines whether the buyer can redirect a cargo to a different market, which is valuable to a portfolio buyer and something sellers historically resisted. Indexation determines what benchmark the price references, and whether a contract is linked to a gas hub or to crude has meaningful consequences when the relationship between those two prices moves.

Financing and valuation

Because the revenue is contracted, an LNG project finances and values much more like contracted infrastructure than like commodity production. The debt is typically sized against contracted cash flows with a required coverage ratio, secured at the project level, and structured to amortize over the contract period. Sponsors contribute equity, and in many cases the buyers themselves take equity stakes, which aligns them with the project and helps the financing.

Valuation follows the same logic. The primary method is a discounted cash flow on the contracted capacity, running the fee stream over the contract tenor and treating any uncontracted capacity separately and more conservatively. Once operating, the project supports an EV to EBITDA comparison against other contracted infrastructure, though the peer set is small and the comparison is imperfect. During construction, the analysis is a project return calculation against the capital cost, with the key sensitivities being construction cost overruns and schedule delay rather than commodity price. Where that sits relative to the rest of the sector's multiples is covered in how energy companies are valued.

The analytical questions therefore look nothing like upstream questions. There is no reserve report, no decline curve, and no price deck driving the base case. Instead you interrogate contracted percentage of capacity, weighted average contract tenor, the fee level relative to the capital cost, counterparty credit quality, and construction execution risk. This puts LNG much closer to the midstream framework described in midstream contracts and MLP structures than to the reserve-based approach in reserves, PV-10, and the upstream NAV model.

There is a genuine adjacency to power here as well, since gas is a major fuel for electricity generation and gas demand is partly a function of what happens on the power side. Those dynamics belong to the power and utilities guide rather than to this one.

What goes wrong

Three failure modes are worth being able to name.

Construction cost and schedule. These are enormous projects with long build periods, and overruns are common enough across large infrastructure generally that lenders build contingency into the financing. A delay is expensive twice: the capital sits idle, and contracted delivery obligations may begin before the facility can meet them.

Counterparty deterioration. A twenty-year contract is worth what the counterparty can pay over twenty years. Buyers can weaken, and in an extended downturn a project can find itself with contracted revenue it cannot collect. This is the same counterparty analysis that governs midstream, applied over longer tenors and larger amounts.

Market structure change. Contracts signed under one set of assumptions about regional price relationships and destination flexibility can become badly mispriced if those relationships shift. Crude-linked pricing in a world where gas and crude prices diverge is a recurring source of disputes and renegotiations, and portfolio buyers with destination flexibility can capture value that fixed-destination sellers gave away.

What interviewers ask

The reliable question is why LNG projects need long-term contracts before construction, and the answer is the immobility and single-purpose nature of the asset combined with the size of the capital commitment, which together make merchant exposure unfinanceable.

The second is the tolling versus sale-and-purchase distinction, where the point is who carries the commodity spread.

The third, and the better one, is how you would value an LNG project, where the expected answer is a contracted discounted cash flow with sensitivities on construction cost and schedule rather than on commodity price, precisely because the contracting removed the commodity variable. A candidate who reaches for a price deck here has not understood what the contracts did.

Practice question

Why do liquefied natural gas export projects need long-term contracts signed before they get built?

Because of what the asset is. A liquefaction facility costs an enormous amount, takes years to construct, and is immobile and single-purpose, so if the market moves against it after completion there's no way to recover the investment. You can't relocate it, you can't repurpose it, and the product it makes has a regional price that can fall a long way. No lender will fund that against merchant exposure. So the sponsors sell the capacity forward under long-term agreements with creditworthy counterparties, and the project debt is serviced out of contracted revenue rather than market outcomes. Getting a large share of capacity contracted is generally the precondition for reaching final investment decision, which is when the capital gets committed and construction actually starts. The structure of those contracts matters too. Under a tolling agreement the customer brings its own gas and pays a fixed liquefaction fee, so the project earns a service fee and takes essentially no commodity risk, with the customer holding the spread between feedgas and delivered product. Under a sale-and-purchase agreement the project buys the gas and sells the liquefied product on an indexed price, so it keeps some exposure. That's why an LNG project gets valued as contracted infrastructure, with a discounted cash flow on the fee stream and sensitivities on construction cost and schedule rather than on a commodity price deck.

What the interviewer is listening for: The immobile, single-purpose nature of the asset as the reason merchant exposure is unfinanceable, and the term final investment decision used correctly. Distinguishing tolling from sale-and-purchase on the basis of who carries the commodity spread is the detail that separates a prepared candidate from one repeating that LNG is capital intensive.