Looking at challenges to LNG growth prospects, hard realities in developing Asia: Q&A with IEEFA’s Grant Hauber

Global LNG demand is projected by IHS Markit to increase from 371 million metric tons/annum (Mtpa) in 2021 to about 440 Mtpa in 2025 and 550 Mtpa in 2030. Investments in new liquefaction capacity continue in the US, Qatar, Australia, and elsewhere, as the natural gas industry sees huge opportunities to provide a "bridge fuel" for the energy transition. With record prices for gas in Asia this fall, the potential seems ripe for a significant period of time.

However, the Institute for Energy Economics and Financial Analysis (IEEFA) calls into to question the loftier side of the forecasts, noting that many of the expected high-growth Asian markets for LNG could turn out to provide less demand than anticipated.

A new report from IEEFA, published on 15 December, looked at the announced gas-fired power plants and LNG import projects to support them in seven developing economies in Asia and concluded that more than 60% of those projects are unlikely to be built. For those seven countries—Vietnam, Thailand, the Philippines, Cambodia, Myanmar, Pakistan, and Bangladesh—IEEFA said that perhaps 45-50 Mtpa of an announced nearly 150 Mtpa of LNG import projects will materialize.

In this Q&A, Net-Zero Business Daily spoke with Grant Hauber, an IEEFA energy finance analyst and co-author of the report (with Sam Reynolds, also an IEEFA energy finance analyst), about the factors that lead to the announcement of many LNG projects, and those which undermine the likelihood they will be built. Instead of becoming dependent on LNG imports for decades, IEEFA proposes that governments in developing Asia confront their multiple challenges of meeting rising energy needs, achieving their Paris climate goals, and doing so within their limited budgets with more diverse, cleaner energy mixes.

NZBD: Briefly, how would you summarize your findings?

Hauber: Our unique perspective on this is looking at the demand side of the equation. So much of the gas industry is focused on the supply side, whether US Gulf Coast producers will add disruptive capacity, or the large expansion commitments from Qatar or Australia. But, ultimately, somebody has to buy and pay for the LNG.

We took a look at growth markets in Asia, where so much downstream use of LNG has been announced, and we ask how much of this demand is real? What are the drivers and the potential hurdles in realizing that demand? How much does it mesh with countries' overall development plans, their macroeconomic and fiscal situation, and their commitments under the Paris Agreement? Is it realistic that all the projects announced will see the light of day—and the answer is definitely not all of them. We identify some constraints.

NZBD: Let's talk about those constraints. What could cause gas demand and thus LNG demand to fall short of upper-end forecasts?

Hauber: Our report looks at three categories of filters. Number one is the fiscal, macroeconomic, and development trajectory of each country, including their energy network plan. What is the regulatory environment? What does their [domestic power] tariff environment look like? When you look at the gas-power value chain, since that's where a lot of imported gas will be used, you are passing along the cost of the LNG to the bulk buyer, which is probably a power company, which is then passing along the cost to the consumer. Someone has to pay for it, so you have to look at the ability of the downstream consumer to shoulder that cost. In these emerging markets, there are limits on what can be passed through, and if you add in any variability of cost, such as this year's record LNG prices, it gets harder.

Number two are project fundamentals. Where is the project's physical location, what is its scale, what related infrastructure exists or does not exist, such as ports and power transmission lines? Who are the sponsors? What is their experience working in that country? Have they raised capital before at the scale proposed or implemented a project of this complexity, or used that tech before effectively elsewhere? We find those levels of expertise are highly varying across project proponents.

Once you get through those filters, you get to Number Three: Can you actually finance the project? Where is money going to come from, given the size of the investment, the number of competing investments in the country, and the ability of the consuming entity to pay the tariff? These are questions that need to be considered from the view of the financier. Not all countries have the ability to attract project funding consistently and at large scale. Certain markets in Asia are largely domestically self-banked, like Thailand. Domestic banks there are willing and able to fund domestically sponsored projects. But other markets, like Vietnam, have to look at cross-border project finance to fund large projects. And there is a limited appetite in the project banking market for Vietnam projects' finance risk. Vietnam, like other similar emerging Asian markets, finds its aspirations bumping up against international lenders' portfolio risk limits with regard to single-country, single-sector, and single-project exposure.

NZBD: Your last comment about financing being limited seems at-odds with the talk of ample funds going into energy projects, both renewables and low-carbon projects, worldwide.

Hauber: Say you're a project finance banker. If you say publicly "there's limited deal flow," you are cutting your own job prospects. Therefore, bankers want to keep all their irons in the fire because they know that whoever gets to the finish line first gets the money. They also want to go with the safest bet possible in order to increase the chance of success. Typically, they will back "relationship borrowers" who they backed in the past.

Project financiers' credit committees are scared to death of sub-investment-credit markets. Thus, their project bankers need to make extra efforts to ensure the cash flow and the foreign exchange is going to be there to pay back their capital. At the same time, the governments in these countries are under pressure from the International Monetary Fund (IMF) not to provide excessive contingent liability coverage.

NZBD: Explain the impact of contingent liabilities in the LNG context.

Hauber: Let's look at how a contingent liability is created. A typical LNG-to-power deal in emerging Asia sees a private party developing, financing, and operating the project, while a state-owned enterprise (SOE) or a utility is the power purchasing counterparty. Let's imagine that the independent power generator (IPP) has imported equipment for a gas project that's costed and financed in US dollars, and it's signed a contract for LNG imports also denominated in US dollars. The IPP's local currency costs on the project are small—salaries, some locally sourced materials—so the majority of their costs are US-dollar linked. Those dollar-indexed costs must be passed through to the SOE.

The project financier needs to consider what is the certainty that the SOE can reliably meet those payments needed to cover the IPP's LNG import costs and its capital recovery costs with absolute certainty for, say, 20 years. Keep in mind, the SOE is collecting money from customers in local currency, often under inflexible tariff structures. The IPP's bankers would want to see a ministry of finance letter that says the government will stand behind the SOE's payments to the IPP and that they will make sure the requisite foreign exchange will be available—and convertible—for those payments. The IPP's bankers will also ask that the ministry of finance back "termination payments" to the IPP if the SOE fails to meet its obligations. Those promises create contingent liabilities for the government, which last over the term of the [LNG deal].

The IMF says the ministry of finance has to account for that as a potential risk, potentially provision for it, and report to the IMF how it's managing that risk. It's another layer of that risk most people in the industry don't even talk about, really.

NZBD: Notwithstanding the issues you talk about as challenges, there's still a huge amount of momentum in favor of gas-fired power and LNG. Gas is abundant, and it provides reliable, proven power. These Asian developing countries need to increase power production. And their governments probably like being able to point to big, visible projects that better the lives of their citizens.

Hauber: Yes, it's true. That's why you saw all those announcements about projects in Vietnam—84 GW of combined-cycle power projects and 24.5 Mtpa of LNG imports [from nine LNG projects]. In Vietnam, you have to identify a provincial site before you can apply to the national government for a permit for the project, and it's in the provincial governments' interest to sign such announcements. But just having a site means nothing. You still have to get the contracts in place with [the national government], and still have to get the hundreds of millions of dollars in financing in place. That's a tedious and uncertain process.

We're not damning LNG, but we are taking a realistic view of the requirements for imports. There's a political reality, exacerbated by the technical challenges of getting projects done. And this is where we moderate our opinion. We are cognizant that … unlike the West, where you can retire coal and replace it with other sources, we are in a net growth market in Asia. There's a balance to be struck between proven, tested approaches … continuing to use the existing fossil fuel fleet or expanding in strategic ways, vs. going all-in on renewables. At the same time, we don't think we've seen enough hard thinking and planning from emerging Asia governments around a diversified energy system. It's easier to do what you've been doing, at least from a conceptual perspective. And the state-owned energy companies in developing Asia are not looking at the fiscal impact of those decisions in the same way a ministry of finance would.

NZBD: The need for more energy would seem to be a big motivator for gas projects, both in the countries and also to companies and gas exporting nations that want to serve them.

Hauber: You can't say we will retire something or eliminate something without having a replacement already in mind and in progress. But we've seen mistakes with this approach in the past. As a result of large-scale, bilateral lending support from Japan, China, and South Korea, countries like Bangladesh and Indonesia are now oversupplied with thermal coal generation, and they are locked into long-term power purchase agreements. Are we going to see the same in gas? We see state-owned utilities weighted down by the minimum payments required under their power purchase agreements with coal-fired IPPs, so they do not have the capacity space or fiscal space to support a renewable energy-fossil fuel diversified grid.

The Qataris are going to increase their gas production by a third or more, and you have US Gulf Coast LNG exports looking to grow, and Australian LNG expansions. The supply side is in its glory days. It's their alternative to the high-carbon label that's put on oil and petrochemicals products. But the fact is, LNG is still a hydrocarbon. Yes, it has lower emissions, but not zero, and depending on how LNG is used in the market, what you could wind up with is a contractually-based project with purchases long-term locked-in fiscally and environmentally. You can't make gas-to-power value chain investments for five years and walk away. You need more time to amortize the investment.

A government that now says LNG is going to be its current strategy is actually saying it is willing to link its energy sector and its economy to the global price of gas, and, by extension, it's willing to link its economy to US-dollar cost influence.

NZBD: Some of the countries have their own gas reserves. How does that figure into the equation?

Hauber: Most of the countries in our study indeed have domestic gas reserves, and most of those countries have never figured out to appropriately price their gas in order to get it out of the ground. Bangladesh is an example. It has offshore gas reserves estimated from a low of 7 trillion cubic feet (Tcf) to as high as 200 Tcf, but can't get E&P companies to commit to production. International oil exploration companies have claimed that the production tariff offered by Petrobangla is too low to encourage new drilling, leading to those E&P companies handing back their exploration licenses. As a result, the country began importing LNG in August 2018 via an FSRU under an agreement between Excelerate and Petrobangla.

The Vietnamese also have had long-term challenges arriving at gas prices. All the way back in 1988, the BP-Statoil consortium found oil and gas in the Nam Con Son Basin. While oil was exported from the start, gas from the field was not delivered onshore until 2003. This was because PetroVietnam could not reach an agreement with BP-Statoil on the landed cost of gas. Imagine, they flared gas for that long because they couldn't agree on a price. Similarly for Chevron's Block B field in Vietnam's southwest offshore waters, the delivered cost of gas had been under negotiation from 1996 all the way through mid-2015 without agreement; Chevron finally gave up and exited.

What if these countries figured out how to do their E&P pricing properly? All of a sudden, they might have domestic gas, instead of the LNG contracts that lock them in to higher prices.

NZBD: What about carbon-neutral LNG, backed by carbon capture and storage (CCS). Or improvements in low-methane gas production? How much does this solve at least the carbon emissions problem?

Hauber: My opinion about the sustainability and reliability of "carbon-neutral'" LNG is that the process of getting to net zero is fraught with leakage. The carbon accounting for that is challenging. It's going to be very difficult to scale up, such that LNG deliveries … [are] 100% guaranteed as carbon-neutral. And the fact is that you're still releasing CO2 and NOx into the atmosphere when you combust it. So, it's not a long-term solution.

As for CCS, you need everything to be perfect for it to work. We start with the technical perspective. When you are trying to strip off CO2, you need to invest significantly in extra plant to accomplish that feat—in addition to whatever energy conversion process you are already running. You need extra energy inputs at every step—stripping, gathering, compression, transport, injection. These costs are in addition to, say, coal generation processes that are already becoming uneconomic; adding CCS only makes it more uneconomic. You'd need a subsidy, or else an overarching cost of carbon. Why would you divert that much money into a process that keeps you at status quo when you could invest more productively in wind and solar and grid-stabilizing technologies to go with it?

NZBD: So how do you see these components coming together?

Hauber: These countries need to consider renewables more seriously in their long-term system plans. Renewables have made their economic case; feed-in-tariffs really are no longer required. Auctions for renewable capacity have demonstrated their worth in India, the Philippines, even in Cambodia. Renewables have one-time upfront costs, but lack the ongoing, long-term, foreign currency-denominated fuel purchase requirement.

The argument against renewable energy is that the region's power grids can't handle large shares of variable output capacity. But where is the investment in the grid? This isn't just a capacity addition game. Regional governments don't have to go it alone either; grid modernization investments are an area where multilateral development banks are sitting around ready to help.

The bottom line is that initiating or expanding LNG imports is a fiscally and economically risky decision for emerging Asia governments. Such decisions are fraught with risk and create long-term liabilities. LNG market volatility proved that to be the case over the past 18 months, and the consequences for LNG importing countries like Bangladesh and Pakistan have been stark. Emerging Asia governments need to plan carefully, developing diversified portfolios of energy sources to hedge against the volatility of commodity prices, currency exchange rates, and the inevitable periods of economic downturn. LNG may not be the panacea they are looking for.

Posted 20 December 2021 by Kevin Adler, Chief Editor