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In the first quarter of 2022, 20 new insight papers have been
published in the IHS Markit Asia Pacific Integrated service, apart
from the regular updated reports. This research highlight
summarized the key impact papers and provides an overview the
market signposts in Q1. Link to a select set of reports is provided
below.
The graphic of the quarter is selected from "The Russia-Ukraine
crisis and the impact on China's gas market", showing China's gas
import mix in 2021.
On 4 February 2022, Gazprom and China National Petroleum
Corporation signed a new gas pipeline supply agreement for 10
Bcm/y. Counting the existing 38 Bcm/y supply contract through the
Power of Siberia-1 (POS-1) pipeline, the total contracted piped
volumes between Russia and China are now 48 Bcm/y. To be delivered
via a new Far Eastern route, the gas supply that will be tapped,
from Sakhalin, is physically separated from fields currently
supplying Europe, POS-1, and the still-under-discussion Power of
Siberia-2 (POS-2) pipeline project. The deal will be settled in
euros in an effort for both sides to diversify away from payments
in US dollars. Other details, including the timing of first gas,
ramp-up period, specific gas source, pricing structure, pipeline
route, and entry point, have yet to be specified.
Gazprom can potentially move Sakhalin gas part of the way to
China through its existing Sakhalin-Khabarovsk-Vladivostok
pipeline, subject to the route's overall expansion; deliveries to
the proposed entry point at Blagoveshchensk (the same as POS-1)
also require construction of a 580 km pipeline from Khabarovsk.
Gazprom's Sakhalin-3 project gas resources, including the
Yuzhno-Kirinskoye field, should be just enough to accommodate
regional domestic demand growth and two export projects: the new 10
Bcm/y pipeline to China and the planned third train of Sakhalin-2.
Gazprom's current development plan for Yuzhno-Kirinskoye still
assumes that the field will start production in 2024-25 with a
plateau of 21 Bcm/y reached in 2029-31.
The Russia-Ukraine crisis and the impact on China's gas
market
The Russia-Ukraine crisis has injected further turmoil into an
already tight global energy market, sending oil and spot LNG prices
to record highs that were not thought possible previously. Russia
has already been a strategic gas supplier to China, accounting for
10% of gas imports in 2021. The two countries' gas ties will
strengthen in the next few years given the ramp up of the 38 Bcm
per year Power of Siberia-1 (POS-1) contract and the new 10 Bcm per
year (Bcm/y) Far East contract with potential 2025 first gas.
In the short term, China will feel the pain of high gas import
costs. The overwhelming majority of Chinese gas imports, both
pipeline and LNG, are linked to oil prices, which will lead to high
landed prices of LNG imports within several months and of pipeline
imports within a year, given the typical lag time to oil prices. To
a lesser extent, as most Chinese importers have already stopped
spot purchases, high spot LNG prices will also raise China's
average landed price of imports.
China could receive more Russian LNG in 2022. As long as
sanctions do not apply directly to entities buying Russian LNG,
China may import more Russian LNG cargos if they need to be
diverted from originally designated destinations owing to
self-sanctioning through port bans or other LNG importers' fears of
potential sanctions and reputational concern.
The timeline for Power of Siberia-2 (POS-2) development may well
accelerate but hurdles remain. The European Union's proposal to
phase out Russian fossil fuel imports before 2030 will undoubtedly
fast-track Gazprom's original plan to cultivate China as a key
consumer of its Western Siberia gas resources. On China's side,
geopolitical pressure and the size of the deal—up to 50
Bcm/y—could be challenging. If an agreement for POS-2 can be
achieved, first gas would arrive at the very earliest within three
years, with significant negative impact on China's Central Asian
and LNG imports.
In late December 2021, China released the first update to its
power ancillary services market rules since 2006. The update
proposes an expansion to types of ancillary services as well as to
eligible market participants. The changes aim to increase
competition and adapt ancillary markets to better serve China's
evolving power system. Aligning with the fundamental power
marketization reform direction, the changes also address the rising
penetration of intermittent renewables and acknowledge technology
advancements enabling demand-side management.
Passing through ancillary services costs through to power
end-users will fundamentally change power tariff setting.
Previously cycled among power generators, ancillary costs will pass
through to power consumers for the first time. This codifies the
long-discussed "who benefits, who pays" principle.
Impact on power generators will depend on generation type and
ancillary product, differing among renewable and thermal power
sources. Intermittent renewables' total allocation fees will likely
increase given their status as the main beneficiaries of the deep
ramping (peak shifting) ancillary product, and that demand for deep
ramping ancillary services will expand with growing renewable
generation. Although the magnitude of these costs is still to be
determined by follow-up documents, regulators will likely also take
into consideration affordability concerns.
The changes indicate increased revenue opportunities for
demand-side management schemes and battery storage, though actual
impact will depend on how the policy is implemented. The new
ancillary market rules will remove many market-entry barriers
previously faced by adjustable load resources and battery
storage.
In late October 2021, the Indian Energy Exchange (IEX) launched
the green day-ahead market (GDAM), a new market segment to trade
the day-ahead contracts (DACs) for renewable generation, with
separate price formations for renewable and conventional power.
Since its launch, 326 GWh of renewable energy generation has been
traded in the GDAM, which represents roughly 1.4% of total
renewable energy generation and about 1.5% of the total short-term
market.
Prices continue to be divergent between the GDAM, the DAM, and
RECs. As per the price convergence principle between different
market segments, the prices in the GDAM should be equivalent to the
prices in the DAM plus the renewable energy certificates (RECs).
However, the prices in the GDAM remained divergent during the first
two months of the market's operation. This result is primarily due
to the absence of an intermarket optimization structure, which is
inherent in the overall market design.
Buying from the GDAM results in a lower cost to buyers. Buyers
are able to lower their total power procurement cost (and meet
their renewable purchase obligation [RPO]) by approximately 0.22
rupees per kWh (US$3.5/MWh). The cost advantage may increase
further as the Central Electricity Regulatory Commission (CERC)
implements the transmission charge waiver for GDAM
transactions.
Liquidity in the GDAM is expected to increase. In the first two
months of the market, the volumes in the GDAM remained low, owing
primarily to limited merchant renewable generation in the country
and the inability of wind generation to trade on a day-ahead basis.
However, going forward, volumes in the GDAM are expected to grow as
new dispatchable renewable energy capacity (which is part merchant
and has storage) is commissioned.
Rule change leads to increased LNG costs for South Korea's
power sector
On 27th December 2021, KOGAS amended its provisions for natural
gas supply, including a change in the way it passes through its LNG
procurement costs. The change will result in a surge in fuel costs
for many gas-fired power plants in South Korea, starting from
January 2022.
South Korea has 41.2 GW of gas-fired power capacity, of which 34
GW is supplied with fuel by KOGAS, the monopoly reseller of LNG
within the country. The power generation companies for the
remaining 7.2 GW buy their LNG directly from the global market.
KOGAS has historically passed through its LNG procurement costs,
including term and spot LNG purchases, to its power generators and
city gas company customers on a weighted average cost basis.
However, KOGAS has not always been able to pass this through to
city gas customers, as the wholesale tariff is regulated and can be
changed by the government.
In July 2020, the Korean government lowered the city gas price
by 11-13% as a measure to reduce costs for consumers during the
COVID-19 pandemic related recession. The price was subsequently
frozen every month until the end of 2021, even as KOGAS's import
costs increased sharply due to high oil and spot LNG prices in the
global market. As a result, KOGAS has been unable to fully pass
through its LNG costs and has faced deficits in its city gas
business.
US-China phase-one trade agreement: Energy target was not
achieved despite surging LNG trade in 2021
The end of 2021 marked the time to evaluate the achievement of
trade targets set in the US-China phase-one trade agreement. Signed
in January 2020, the trade deal set aggressive incremental trade
value targets of $18.5 billion in 2020 and $33.9 billion in 2021
compared with the 2017 levels for energy products.
LNG imports were a key contributor, but actual energy trade
value still fell short of the targets. In 2021, China's trade value
for US LNG was 10 times that in 2017, accounting for 40% of total
incremental energy trade values. Still, the actual incremental
energy trade values failed to reach the targets: the completion
rate was only 26% in 2020 and 42% in 2021.
China's LNG imports from the United States will increasingly
come from term contracts, although flexible destination will
accommodate more trading activities. In 2021, China signed 10.5
million metric tons per annum (MMtpa) of new-term supply for US
LNG, which is 39% of all China's new LNG agreements signed in the
same period. The new contracted volumes will start to take delivery
during 2022-25. On the other hand, the flexible destination known
in most US supply agreements can help Chinese LNG importers further
develop their trading practices.
US LNG will provide China with price diversification. China's
need for new supply is the main reason behind the surging LNG
imports and new contracted volumes from the United States to China,
although the political support in the form of waived import tariffs
also helps. In addition, supply from the United States provides
price diversification for China to limit its exposure to the price
volatility in the oil and spot LNG markets.
The changing landscape of renewable energy financing in Asia
Pacific
In 2020 alone, Asia Pacific added 110 GW of solar photovoltaic
(PV) and wind power capacity, accounting for over half of the total
installed capacity in the world.
However, most Asian markets will likely fall short of the
investment required to meet government renewables targets during
2021-25, with access to low-cost financing remaining one of the key
challenges. New sources of finance are needed to fill the
investment gap.
Most Asian markets will likely fall short of the US$125 billion
of annual investment in solar PV and wind power required to meet
government targets during 2021-25. Only mainland China is expected
to meet the government's ambitions, while other major economies in
Asia are unlikely to meet their investment requirements, as access
to low-cost financing is constrained by the less developed capital
market, lack of transparency in the financial regulation, and
limited experience of local banks.
In Vietnam, green loans emerge as a new debt instrument for
renewables projects. The issuance of green loans in the country has
grown to US$1.7 billion since 2017, as the Asian Development Bank
(ADB) has actively funded green loans with its innovative project
finance solutions in mitigating power purchase agreement (PPA)
risks.
India has significant potential to multiply renewables
investment but needs to address policy, offtaker, and currency
risks. India will need to quadruple its renewables investment to be
able to reach its target to add about 360 GW of new renewable
capacity during 2021-30. Project developers are tapping
international capital markets to access low-cost financing, but the
government needs to improve regulatory transparency, introduce a
uniform green taxonomy, and provide targeted interventions to
improve access to low-cost international capital.
The current offshore financing landscape in Japan, South Korea,
and Taiwan signals a potential decrease in the perceived risk of
capital providers in the near future. The high uptake of project
financing, the average percentage of debt financing reaching close
to 80%, and the active participation of local banks and insurance
companies are pointing to a potential decrease in the perceived
risk of capital providers in the near future.
Green bond rises as a new financing vehicle in Southeast
Asia
As a new source of financing new projects or refinancing, the
issuance of green debt has taken off in Southeast Asia in recent
years. The issuance of annual green bonds and loans for funding
regional renewable energy projects grew to US$4.4 billion in 2021,
registering a five-fold increase over the past five years.
Renewable energy has received the largest share of allocation
from green debt issuance. According to our study, which analyzed
the green bond and loan market in Southeast Asia during 2017-21,
renewable energy is the largest sector that has captured 40% of
total proceeds, followed by green building and clean
transportation.
Independent power producers (IPPs) are the most active in
funding renewable energy projects using green debt. Green bond and
loan market has been largely dominated by IPPs in Southeast Asia,
who have issued almost half the volume directed to renewable energy
projects in the past five years. With solar, wind, or geothermal
projects calling for long-term capital owing to their over 20 years
of operational life, green bonds offer IPPs attractive sources
needed to refinance the projects.
Institutional investors are stepping up their effort to keep
their portfolio in line with cutting emissions to net zero by 2050,
as they have been under growing pressure to manage climate risks
and achieve target investment returns as part of their fiduciary
duty. This green push by global investors has spurred more
investment banks to underwrite green bonds, as green-labeled
investments are well aligned with investors' needs to clean up
their portfolio.
Our study finds a potential emergence of greenium in the
near-term, which could facilitate increased funding for renewable
energy projects by green bonds. A growing number of repeat issuers
and the active role of development finance institutions (DFIs) as
anchor investors could improve investor confidence in green finance
products, which could feed through into pricing.
Structural reforms and access to global finance key to
achieving Pakistan's clean energy goals
With the recently concluded 26th Conference of the Parties
(COP26), Pakistan unveiled its updated nationally determined
contribution (NDC), which targets an up to 50% reduction from
business-as-usual greenhouse gas (GHG) emissions and a 60% share of
renewables (including hydropower) by 2030. This Insight evaluates
the realism and ambition behind the NDC based on Pakistan's
historical performance and outlook. It delves into the
COVID-19-related constraints to Pakistan's import-intensive energy
and structural and governance issues threatening Pakistan's clean
energy transition. The paper also analyzes measures undertaken to
upgrade clean energy infrastructure and implement market reforms
and financing requirements to achieve clean energy goals.
IHS Markit's assessment of Pakistan's macroeconomic prospects
and energy capacity pipeline indicates that the official mitigation
targets are based on an overly pessimistic baseline, while the
clean energy and GDP estimates are very ambitious (and likely
unrealistic). Pakistan needs to accelerate on its path of recently
implemented reforms and address specific issues plaguing the
renewables sector. It needs to provide a fertile investment
requirement for enabling private participation, which has a track
record of energy- and cost-effective performance compared with its
public sector counterparts in generation and distribution.
India's 2022 prognosis for the power, gas, coal, and renewables
markets
The Indian economy, which contracted by 7.4% in fiscal year (FY)
2021 as a result of COVID-19, is slowly recovering in FY 2022 while
withstanding a severe second wave of the virus. IHS Markit projects
that India's GDP will grow in FY 2022, reflecting the recovery of
pent-up demand in the short term. However, structural damage from
the pandemic may continue to weigh on the economy in the medium
term, including the impact of the pandemic on household incomes and
labor markets and rising corporate and public debt with prolonged
banking sector issues. Government-initiated reforms could partially
offset the impact on potential growth, but implementation
challenges could pose hurdles.
Energy demand also recovered in 2021, driven by an increase in
economic activity and a rapid vaccination drive. While electricity
demand grew by approximately 9.3%, gas demand also grew by more
than 9% (primarily from growth in demand from city gas distribution
and the industrial sector). At Glasgow, India presented its updated
nationally determined contributions (NDCs) in line with the
ratcheting requirements of the Paris Agreement (reducing emissions
intensity of GDP by 45% over 2005 levels and 500 GW of renewable
energy capacity by 2030). To attain its commitments, India needs to
focus on deepening energy markets, providing long-term policy
clarity, supporting technological advancements in storage and green
hydrogen, and developing transmission infrastructure.
New climate actions demonstrate ASEAN's ongoing decarbonization
efforts, but challenges remain
Association of Southeast Asian Nations (ASEAN) countries aspire
to shift to a low-carbon economy. During the 2021 United Nations
Climate Change Conference (COP26) or right after it, most of the
ASEAN countries announced net-zero targets and unveiled new coal
reduction plans, demonstrating the continuous decarbonization
efforts in the region.
The recently announced net-zero targets and coal phase out plans
mostly do not align with the prevailing power development plans
(PDPs). Most ASEAN countries pledged to reach net-zero emissions by
2050-65, but these pledges have yet to be reflected in the
countries' current PDPs, which were released or proposed no later
than 2021 and are regarded to forecast thermal plants without
carbon capture technology to stay online beyond 2050.
As an important measure to curb emissions, carbon pricing has
been implemented progressively in the region, but is deemed
insufficient to make a real impact on the power development
trajectory. Only two countries, Singapore and Indonesia, have
implemented or announced plans to implement a carbon tax, starting
from US$3.7 and US$2.1 per metric ton of carbon dioxide equivalent
(CO2e), respectively, which are perceived as not sufficient enough
to stifle coal. Other ASEAN countries claimed to follow suit but
have not announced any important details.
Multiple challenges still lie ahead as no holistic solutions are
presented to transition the region's "coal lock in" power sector to
sustainable systems. The region's power sector is estimated to grow
at 3.5% per annum through 2050 and will require 18 GW of net
capacity addition annually. Besides, by 2030, about one-third of
the coal capacity will be younger than 10 years, making the
retirement plans economically challenging. In addition, gas as the
bridging power source has always been associated with issues such
as insufficient supply and infrastructure investment, as well as
high cost. While all the governments' PDPs seek out a shift to
low-carbon systems, none of them presented well-reasoned
solutions.
South Korea's presidential election: Nuclear takes center stage
in the energy agenda
The two leading candidates in South Korea's presidential
election on 9 March 2022 have outlined different visions for the
country's energy future. Whoever wins, the new president's energy
policy will shape the 10th Basic Plan for Electricity Demand and
Supply (BPE) and the 15th Long-Term Natural Gas Supply Plan
scheduled for early 2023, the country's most critical plans guiding
energy market fundamentals over the next 15 years.
The ruling Democratic Party's candidate Lee Jae-myung intends to
bolster current climate ambitions and energy transition policy,
potentially further raising the NDC target to a 50% cut in
greenhouse gas emissions by 2030 and accelerating the target year
for carbon neutrality to 2040. A new climate and energy ministry
will be established as an interministerial body, and carbon tax
will be reviewed as a policy instrument to achieve the ambitious
emissions targets. The current policy notion of phasing out nuclear
and coal power as well as promoting solar and wind energy will be
broadly maintained.
Opposition People Power Party's candidate Yoon Seok-yeol intends
to pull out all the stops to revive the country's nuclear industry,
overturning President Moon Jae-in's anti-nuclear energy policy.
Yoon envisages nuclear power to account for 30-35% of electricity
supply in 2030, 6-11% higher than the level set in the latest
Nationally Determined Contribution (NDC) target. The energy policy
on coal and natural gas will largely remain unchanged given Yoon's
target of keeping the combined share of coal and natural gas in
2030 at 40-45%, not far from 41% in the current NDC target.
Natural gas and renewables will likely be most affected during
the next president's term (2022-27). With the current nuclear
phaseout policy being reassessed by both candidates, natural
gas—the fuel serving mid-merit requirements and meeting
residual load needs in the country's dispatch system —will
likely be most affected by the outcome of the presidential
election. The pace of uptake in renewable energy, particularly
solar and wind, will also be significantly influenced, as the
sector heavily relies on the government subsidies and the
state-owned utility's grid infrastructure plan.
Installation rush in 2021 propels China to become the largest
offshore wind market globally
The National Energy Administration (NEA) announced that China's
offshore wind annual installations soared to 16.9 GW in 2021,
accounting for over 80% of global total additions that year and
quintupling China's domestic additions level from the previous year
in 2020. Following the record-setting growth, China surpassed
United Kingdom and Germany to become the largest offshore wind
market globally.
The boom in installations resulted from a rush to meet a subsidy
deadline, however, IHS Markit estimates closer to 15.0 GW of
grid-connected project additions in 2021. Such rapid project
rollout resulted from close collaboration among all stakeholders.
Grid companies were simultaneously under pressure to bring online
as much renewable power as possible. However, some of these
projects may not have fully commissioned in 2021 despite
registering as grid-connected to meet the subsidy deadline.
The number of offshore construction vessels increased sharply in
2021, removing the key bottleneck in supply chain capabilities for
China's offshore wind installation. Developers went to great
lengths to build, purchase, lease, or modify existing vessels to
cope with the installation rush.
More project development experience, overtime work, and
favorable weather also contributed to the record-breaking additions
in 2021. However, safety and quality risks increased resulting in
an uptick in accidents.
Record level offshore additions will not reoccur in 2022, but
the strong momentum will continue during the 14th Five-Year
Planning (FYP) period. Cost declines from a significantly lower
turbine price and shared transmission lines as well as policy
incentives will support the subsidy-free project pipeline.
Additional Insights and Strategic Reports published in fourth
quarter 2021
Logan Reese is an associate director on our Asia Pacific
Regional Integrated team, focusing on Australia power and gas
markets.
Ankita Chauhan is a senior renewable analyst on the Gas,
Power, and Climate Solutions team, covering research and analysis
for Indian and South Asian markets.
Posted 7 April 2022
This article was published by S&P Global Commodity Insights and not by S&P Global Ratings, which is a separately managed division of S&P Global.
