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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
RT @SPGlobal: Many nations have set #NetZero Emissions by 2050 as their climate goal. Will be enough minerals to meet the requirements? Joi…
Jul 11
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