Monday, 05/17/2021 Published by: Richard Pratt RBN Energy
On the surface, it may seem that the LNG market has normalized after the past year’s tumult, and it’s true that many of the day-to-day disruptions that plagued LNG offtakers and operators have subsided. Mass cargo cancellations are a distant memory, and U.S. LNG exports have been flowing at record levels. Global demand has recovered, and buyers are back to worrying more about what they normally worry about: storage refill and securing enough supply for the next winter. However, in other ways, the pandemic and the more decisive shift toward decarbonization measures in many ways have fundamentally changed how deals for future LNG development will get done. Today, we look at what the global initiative to reduce greenhouse gas emissions will mean for LNG project financing.
The LNG industry has been impacted by three major events in the last 18 months, all of which have implications for the future of the industry in the short-, medium-, and long-term. Firstly, the initial wave of U.S. LNG projects, centered on the U.S. Gulf Coast, has now reached full production capacity, running at rates equivalent to about 10.5 Bcf/d (80 Mtpa), or approximately 20% of global LNG demand in 2020, with the first of the early second-wave projects due to begin exporting later this year. The second major event was brought on by the pandemic and the resulting demand destruction. U.S. LNG suffered from cargo cancellations as a result of COVID-19, which limited exports from the Lower 48 last year to an annual average of 6.5 Bcf/d (49 Mtpa). So far in 2021, there is no sign that there will be a repeat of last year’s cargo cancellations as LNG prices in global markets have been robust, notwithstanding the boost in supply. However, 2020’s global LNG market was essentially unchanged from 2019, growing by less than 1%, versus original market expectations of 4-5%. As such, the demand curve for LNG has shifted to the right by at least one and, more likely, two years, before the anticipated growth trajectory resumes. During this period, sponsors of renewable energy projects have maintained much of their momentum, and that growth in renewable energy will serve to reduce the plateau or peak demand for LNG as the world pursues decarbonization strategies — which is the third factor that will impact LNG, and the focus of our discussion today. In particular, the current market environment and push for decarbonization are upending traditional approaches to funding and capacity commitments for new developments.
Risk Sharing and Finance
The traditional mantra in LNG project design and structuring is that the buyer takes the volume risk under the sales and purchase agreement (SPA), and the seller takes the price risk (refer to Sultans of Swing for a detailed explanation). Essentially, buyers are required to contract for volumes of LNG under take-or-pay provisions that oblige them to pay whether they lift the cargo or not. That is to say, the buyer, often a utility with high credit standing, is providing a secure cash flow to the seller of the LNG, irrespective of its ability to absorb the volumes. On the other side of the deal, the seller, who is typically a project sponsor, takes pricing risk by linking the sale to a commodity price index. Historically, LNG sales were linked to crude oil prices. That’s changed somewhat in more recent years, with some contracts indexed to natural gas benchmarks, such as the U.S.’s Henry Hub or Europe’s Dutch Title Transfer Facility (TTF) or National Balancing Point (NBP). However, oil-linked pricing still prevails among Asian LNG producers, and Brent crude prices have fluctuated between $8/bbl and over $100/bbl over the lifetime of the contracts, which are usually for 20- to 25-year terms. (We covered the most recent gyrations in international pricing recently in Wild Thing.)
The take-or-pay requirement, coupled with a multiyear contract duration, secures cash flow for the project and allows sponsors to use project financing structures, whereby the debt incurred by the project is repaid solely from its cash flow and without recourse to the sponsors’ balance sheet.
However, this model faces some new challenges due to the pandemic (discussed in detail in Holding On for Life) and, more importantly, the desire of governments to decarbonize their economies. Simply put, the pandemic has made it much harder for buyers to predict their LNG volume requirements. This alone probably accounts for the majority of delays to final investment decisions (FIDs) that have been anticipated for the second wave of Lower 48 projects under development, as purchasers are reluctant to make the same long-term commitments that enabled the first-wave buildout. This year, the market has seen Annova cancel its 6.5-Mtpa project in Texas, and more cancellations are likely to follow suit as project sponsors burn through their cash reserves in the absence of firm offtake contracts (see the LNG Voyager Quarterly, released last week, for the latest on each second-wave project).
This is not the whole picture, though, and the risk to these projects comes not only from pandemic-induced delays and uncertainty weighing on buyer decisions, but also from the public and governmental pressure toward decarbonization and the changing perceptions about the role of gas in the future global energy economy. As part of their campaigns directed against fossil fuels, activists are now urging banks not to lend to hydrocarbon-based projects — a trend with major impacts in the upstream, midstream, and downstream oil and gas sectors.
This, by itself, would not prevent LNG projects from moving forward, but it does mean that new finance structures are likely to be needed in order for positive FIDs to take place. One source of funding might be private equity investors, such as Blackstone Energy Partners, to whom Cheniere Energy turned to help finance the first two liquefaction trains at its Sabine Pass facility (see photo below) with a $1.5 billion structured deal in 2012. However, such financing tends to be more expensive than conventional project financing. Another possibility is issuing bonds, as Qatar Petroleum is currently doing with a planned dollar-denominated offering in support of the North Field Expansion.
However, a headwind with bonds is that funds from the sale are received prior to being required for construction of the project and, therefore, coupon payments on the bonds need to start prior to the completion and commissioning of the LNG production facility. On the other hand, loans can be drawn down as the funds are required, resulting in a more effective match between construction and finance obligations and reduced period between the drawdown of funds and the revenues needed to service the debt. Further, as we’ve seen recently, banks supporting and underwriting bond issues may be targeted by those who oppose fossil fuels, even though the bonds will be held mainly by investors rather than the banks themselves.
Equity financing is another possibility. This is the model that LNG Canada’s sponsors are following, while, in the U.S., Tellurian has recognized the potential of equity funding in its business model, whereby investors are required to make up-front equity investments in the trains from which they will receive LNG.
In other parts of the world, financing can also come in the form of governmental export credit agencies (ECAs), and these have played major roles in LNG project financing, such as the $4.7 billion loan provided by the Export-Import Bank of the United States (EXIM) to Mozambique LNG. However, these agencies, together with the World Bank and development banks such as the Asia Development Bank, are coming under increasing pressure to reduce or eschew loans that support fossil fuel developments, and their ownership by governments makes them especially vulnerable to policy changes at both national and international levels. These sources of funds play a major role in the financing of import projects, such as LNG-fueled independent power producer (IPP) facilities that are intended to replace coal-fired facilities in less developed economies. This is especially relevant to Japanese LNG players, such as JERA, which have made large commitments to lift U.S.-produced LNG to feed power project initiatives such as in Bangladesh and Vietnam and which rely on funding from entities such as the Japan Bank for International Cooperation (JBIC).
The upshot here is that the difficulty of financing new capacity growth in LNG production is increasingly likely to result in export capacity additions coming under the control of existing majors, most likely combined with participation from major LNG buyers, with both types of sponsors able to use equity financing. LNG Canada is structured in this way, with Shell, Petronas, PetroChina, Mitsubishi, and Kogas as participants. This combination of a portfolio player, two national oil companies, a major importer, and a Japanese trading house is unique.
Buyer Volume Uncertainty
Even if the financing hurdles can be overcome, there remains the question of the volume risk that historically has been shouldered by LNG buyers. The projected growth in natural gas and LNG demand has largely been predicated on replacement of coal-fired power stations, and that gas will form the fuel of choice for incremental power generation, based on its lower carbon footprint. However, the targeted growth in renewable sources of power has the potential to compete with LNG for demand. This presents problems for LNG importers from two perspectives. First, renewable energy power costs are falling, diminishing gas’s current advantage. Second, buyers face uncertainty in predicting the extent to which gas will be needed to supplement renewable energy when wind and solar energy are in short supply. Both issues complicate power utilities’ ability to forecast future LNG purchase needs. Adding to the conundrum is that, even with goals to phase out hydrocarbons, LNG is still seen as a short-term solution to phasing out coal. So, while decarbonization efforts, particularly in Europe, make LNG less desirable in the long-term, they make it more desirable in the short term — and those timing questions further complicate purchasing decisions and project economics.
Just as important is the question of how much LNG storage a utility should have in place to be certain of meeting market needs. We’ve blogged many times about the role of storage in smoothing out the inconsistencies of supply and demand (see An LNG Market for All Seasons). This becomes especially important in the case of smaller power facilities where limited LNG storage could be exhausted due to weather conditions. These factors necessitate more flexible-volume offtake agreements by LNG buyers. However, this runs contrary to the principles of the traditional SPA in which the buyer assumes volume risk, as we described earlier.
For a buyer, the question becomes “can I obtain LNG when I need it, especially at short notice?” Building greater volumes of storage would seem to be one answer, but LNG storage is more expensive than storage for oil-based fuels and therefore markets may rely more on the latter, which is not without ecological consequences — something we still see in New England. The question of volume uncertainty, at both the macro and micro levels, is more pronounced now than ever before. For example, in Japan, power utilities have traditionally employed a “best mix” of generation and fuel sources to be deployed in order to meet predictable demand loads. However, in the future, not only will the demand loads be harder to predict, but the means of meeting them are likely to prove more complex and possibly more costly.
The message here is that the traditional model of LNG trade, financing, and risk sharing is undergoing major change, much of which is the result of greater global concern over decarbonization. Project structures and contracting practices will need to adapt to these changes. In our next blog in this series, we’ll consider the ways decarbonization is impacting another aspect of the LNG industry: shipping.