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The Luiperd discovery in October 2020 has led to a two-fold
increase in South African gas reserves and is likely to be the
second largest global discovery of 2020. To date, South African gas
consumption has been predominantly limited to PetroSA's
gasto-liquids (GTL) refinery and Sasol's chemical plants and today
only accounts for 1% of the power generation mix. However,
pervasive power outages and an aging coal fleet have created a need
for new base-load power. The detection of the large gas volumes, so
close to the recent Brulpadda discovery, has the potential to ease
the country's security of supply concerns, but discovery is only
the start of the gas monetization process. A challenging technical
operating environment and an unclear domestic monetization route
could delay the near-term development of these reserves and
maintain the country's expected reliance on pipeline and likely LNG
imports into the 2020's and beyond.
South Africa is now awash with gas
potential
On 28 October 2020, Total announced that the Block 11B/12B
Luiperd-1X exploratory well had been drilled to about 3,400 m and
resulted in a significant Lower Cretaceous gas condensate
discovery. Expected resource levels have yet to be made public, but
IHS Markit expects reserves in excess of the 1 billion barrels of
oil equivalent (Bboe), double the prospective reserve reference by
Africa Energy prior to the official discovery. Luiperd is believed
to dwarf the nearby recently discovered Brulpadda field, with
potentially twice the gas reserves, but the liquids gas mix is
thought to be similar. With discovered resources already estimated
to be in excess of 1Bboe and numerous prospects and leads, the
upside potential within the block is significant.
<span/>Technical
challenges exist, but commercialization could provide positive
returns
The development of the Luiperd and Brulpadda fields is currently
in the early stages, with reserves and field development concepts
yet to be formally announced. The most likely development concept
would be a tieback of Brulpadda and Luiperd to a new shallow-water
platform for collection and processing and onward supply, via a
subsea system, to a new platform adjacent to the existing F-A
platform. An additional two-phase pipeline to shore is also likely
to be required. The largest capital cost element is expected to be
the subsea facilities, with relatively large semi-submersibles
required due to the challenging operating environment given the
strong deep-water currents. Operating in such a difficult
environment is likely to lead to significant cost
uncertainties.
While the expected production rate from the joint development is
currently uncertain, any gas monetization will need to be
underpinned by robust offtake contracts in excess of 450 million
cubic feet per day (MMcf/d). Assuming a two-field development and
an assumed gas production rate of about 475 MMcf/d, the development
is likely to incur costs in excess of USD 5 billion but given the
large volumes a gas breakeven of around $3-$3.50 could be achieved,
according to our in-house asset valuation modelling tool
Vantage.
Total's global priorities and government policy
development will impact the development timeline
The discovery of gas condensate is in line with Total's general
strategy of increasing natural gas production and promoting its use
for both power and mobility. The project's carbon intensity and the
domestic monetization of the gas will be factors in a final
investment decision and development of the discovered reserves. A
tightening of upstream capex is likely to mean that the joint field
development will be competing against other global projects, so
ensuring a clear route to monetization and minimizing any
regulatory concerns are key.
Of significant concern is the country's petroleum framework,
which is in the process of being revised. A draft Petroleum
Resources Development Bill, which would separate the petroleum and
mining regimes and update upstream investment terms and
regulations, was published at the end of 2019 but is still awaiting
further progress. A Gas Amendment Bill is also considered currently
stalled. It is unclear whether either of these bills will be
altered considering the Luiperd discovery and changes to the global
oil and gas industry outlook. Additionally, the state's lack of
experience developing deep water discoveries may also complicate
speedy development. A driving force is likely to be the fact the
expiration of the exploration contract for Block 11B/12B is in
2022, to be ideally converted into a production contract, which
would require gas sales agreements to be in place.
Gas commercialization requires multiple gas monetization
routes
The next stage in the joint field development is the undertaking
of development studies as well as working with the South African
authorities to secure gas monetization options. Supply is most
likely to be sent to shore to the underutilized Mossel Bay GTL
facility, serve industrial users in the Port Elizabeth area,
displace diesel open-cycle gas turbines (OCGTs), and support power
demand growth. Given the timeline for development of the gas
discoveries there is an increasing risk that the GTL section of the
Mossel Bay facility could be decommissioned and run solely for
liquid fuel processing. In such a case, supply from Block 11B/12B
would be focused mainly on supporting industrial and power
demand.
Gas-to- power monetization challenges may be more
political than technical
There are about 3.5 GW of OCGTs in South Africa, running on
expensive diesel during shortages. According to South Africa's
latest Integrated Resource Plan (IRP), another 3 GW of natural gas
or diesel capacity, will be added by 2030, about half of the amount
in the IHS Markit's outlook, which foresees a greater need to ease
supply constraints. However, whether South Africa utilizes domestic
gas resources to power this capacity, rather than LNG imports that
carry fuel supply and foreign exchange risk, will depend on its
ability to structure sufficient and transparent revenue streams in
the short-term.
Figure 1: Existing and proposed natural gas infrastructure,
South Africa
Given that South Africa is facing chronic load shedding and
two-thirds of its coal fleet is over 30 years old, with some of the
largest units, including Camden, Komati, Grootvlei, Hendrina, Kriel
and Arnot expected to retire in the next decade, there is room for
natural gas to enter the market at scale. However, if the
government takes an adhoc approach to procurement, issuing
small-scale requests for proposals (RFPs) for power supply, it may
undercut the 450 MMcf/d necessary to monetize the discovery in the
next decade. IHS Markit estimates approximately 2.5 GW of gas
capacity, serving 11TWh of demand in 2025, an amount that can be
supplied by 240 MMcf/d under 50% plant utilization. If the
Ankerlig, Avon, Gourikwa, and Dedisa OCGT plants are converted to
run on gas, then 571 MMcf/d may be absorbed, including Sasol's
current gas demand. If development of domestic resources is not
prioritized and the timeline for development is pushed beyond 2025,
a build-out of LNG or gas import pipeline infrastructure is likely
to meet power demand in the mid-2020s, further undercutting the
value proposition for domestic gas.
If South Africa can ensure revenue streams on the supply side by
guaranteeing offtake for power plants under a sufficient load
factor, then domestic resources may supply an increasing portion
over time. IHS Markit estimates 40 TWh of gas generation in 2030.
The source of supply will depend on the resource size and the
strategy the government employs today.
References
For more information regarding Africa's risk profile, please
refer to PEPS
For more information regarding well, field & basin
summaries, please refer to EDIN
For more information regarding asset evaluation, portfolio view,
and production forecasts, please refer to Vantage
For detailed E&P activity coverage and context by
country/territory, please refer to GEPS
Anna Shpitsberg is a director of global power and
renewables at IHS Markit.
Rebekah Bostan is research manager for supply and demand
fundamentals at IHS Markit.
