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The State of
African Energy
Q1 2023 Outlook Report
Ministry of
Petroleum Resources
of the Federal Republic
of Nigeria
Ministry of
Petroleum and Energy
of Uganda
Ministry of
Petroleum and Energy
of Senegal
Ministry of Energy
of Sierra Leone
Ministry of
Mines and Hydrocarbons
of Equatorial Guinea
The State of
African Energy
Q1 2023 Outlook Report
2
African Energy Chamber Q1 2023 Outlook Report
African Energy Chamber
2
The State of
African Energy
Q1 2023 Outlook Report
www.energychamber.org 3
Index
1 AFRICA OIL SHORT-TERM SUPPLY OUTLOOK 6
1.1 Global and African 2023 liquids supply 6
1.2 Top liquids producers of Africa in 2023 7
2 AFRICA NATURAL GAS AND LNG OUTLOOK 10
2.1 Africa natural gas supply, LNG infrastructure and LNG supply 10
2.2 Africa gas demand and LNG exports vs additional potential 14
3 PROJECT DELAYS IN AFRICA AND IMPACT 15
3.1 Future start-ups coming online after very long discovery to start-up periods 15
3.2 Currently delayed future start-ups – key to Africa’s production increase 17
3.3 Plenty of potential but equally large investments needed to develop the volumes 20
4 AFRICA RENEWABLES OUTLOOK 21
4.1 Global renewables capacity driven by Asia, Europe and the States 21
4.2 Majority announced renewables capacity in concept stage and in North Africa 22
4.3 CWP Global – current leader in Africa’s announced capacity 24
5 AFRICA COP27 COMMITMENTS AND NATURAL GAS 25
5.1 Natural gas vs renewables potential in Africa 25
5.2 Africa COP27 Africa commitments and impact 26
5.3 South Africa can benefit by adhering to the COP27 commitments 30
African Energy Chamber
Q1 2023 Outlook Report
4
African Energy Chamber Q1 2023 Outlook Report
African Energy Chamber
4
• 2023 global liquids (crude + condensates) month-on-month outlook expected to stay flat and stable with annual
average at 83.4 million barrels per day (MMbbls/d)
• Africa liquids supply expected to add up to 8% of the global volumes over the year at an annual average of
almost 7 MMbbls/d
• Top five producers – Nigeria, Libya, Algeria, Angola and Egypt contribute to over 80% of Africa’s 2023 liquids
output
• While majority of the production from Nigeria and Angola is from offshore projects, Algeria, Libya and Egypt’s
production comes from their respective onshore fields
• Production from Nigeria and Angola is in decline, whereas Algeria and Egypt production trend has been
relatively flat since 2015. Libya’s now subsiding civil war impact is expected to result in increased production in
2023
• Regulatory cuts in the form of OPEC sanctions are expected to result in outages in Algeria’s crude oil output
throughout the year
• Africa natural gas output is majorly driven by the North and West African projects
• 2023 annual output is expected to reach about 268 Billion cubic meters (Bcm) and over 85% of this is estimated
to come from the North and West African projects
• The production from the existing producing fields is in terminal decline and any trend reversal is expected only
from the currently pre-FID (Final Investment Decision) fields
• Any delays in these projects, thus, will have an adverse impact on the continent’s natural gas aspirations
• Africa’s total LNG export infrastructure capacity expected to increase from the existing 80 MMtpa to about 110
MMtpa by 2030 and further to over 175 MMtpa by the end of the next decade
• Nigeria, Algeria, Mozambique, Senegal – Mauritania, Tanzania and Egypt are expected to drive this LNG export
capacity in the long term
• Africa’s LNG exports are expected to increase from 66 Bcm in 2023 (a 5% year-on-year increase from 2022) to
77 Bcm by 2030 and further to 100 Bcm by 2035
• Africa’s own natural gas production, international natural gas imports and the annual domestic demand levels
put the continent in a position to pump natural gas volumes of 105 Bcm in 2023, 170 Bcm in 2030, 275 Bcm in
2037 and a slightly lower 220 Bcm in 2040 to both domestic and international markets
• Africa’s upcoming upstream projects have already seen large delays from the time the hydrocarbon discoveries
were made to the estimated future FID
• Many crude oil discoveries that can stabilize the production and offset the terminal decline in output for a few
years; and also, giant natural gas finds that can help Africa meet domestic demand, universal electricity access
and LNG export aspirations have seen long delays due to various above-the-surface issues
Key Highlights
www.energychamber.org 5
• Over a half of the hydrocarbon output from Africa over the period 2025 – 2040 and about 60% of the remaining
recoverable oil and gas reserves in Africa is estimated to come from these upcoming/delayed start-ups
• Governments are now realizing the impact of these delays and putting in the efforts to bring these projects
online and also bring in more exploration investments, but more is required
• At the current conservatively estimated development timeline and scale, a mammoth US$795 billion of greenfield
expenditure is required over the period 2023 – 2040 to bring these undeveloped discoveries online
• 2023 global renewables capacity (solar + wind + hydrogen electrolyzer) is 1,500 GW
• Asia, Europe and North America are expected to drive over 90% of this capacity, with Africa contributing a
negligible 1% of the annual capacity
• As hydrogen capacity in Africa picks up, 2035 Africa output is expected to increase to 7% of the global capacity
• Africa’s current announced renewables capacity stands at 134 GW of wind capacity, 120 GW of solar capacity
and 112 GW of hydrogen capacity
• Egypt, Morocco, Mauritania and South Africa are the major countries with current announced capacity
• Over 75% of the current announced capacity is in concept stage
• Africa’s renewables capacity output is expected to increase from about 27.4 GW in 2023 to over 280 GW in 2035
• CWP Global (in partnership with Bechtel in a few projects) is the main operator with close to 25% of the current
announced capacity in Africa
• Africa holds large natural gas and renewables potential, but over 60% of the natural gas potential and over 75%
of the current announced renewables capacity is in a similar “pre-FEED” state
• Africa’s COP27 commitments aim at phase down of coal power, natural gas as transition fuel and establishment
of the Africa Carbon Markets Initiative (ACMI)
• Universal electricity access and power generation based on renewables is also on the agenda
• Africa continent estimated to stand fifth globally in upstream emissions and Africa’s emissions expected to be
driven majorly due to gas flaring
• High greenfield spending required to bring the large upstream potential online but the economic viability of the
level of investment close to a 2˚C scenario
• At the current estimates, Africa needs fossil fuels as base case scenario suggests a third of the power generated
in 2030 and over a quarter of this in 2040 is expected to come from gas-to-power
• Even in a 1.5˚C scenario, estimates suggest close to a fifth of the power generated in 2030 and about 8% of this
in 2040 will be from gas-to-power projects
• South Africa is a classic example of an African nation that can benefit from the COP27 commitments around
phase down of coal and usage of natural gas potential for power generation
6
African Energy Chamber Q1 2023 Outlook Report
African Energy Chamber
6
1.1 Global and African 2023 liquids
supply
2023 global liquids (crude +
condensates) month-on-month
outlook expected to stay flat and
stable with annual average at 83.4
million barrels per day (MMbbls/d)
Africa liquids supply expected to
add up to 8% of the global volumes
over the year at an annual average
of almost 7 MMbbls/d
Top five producers – Nigeria,
Libya, Algeria, Angola and Egypt
contribute to over 80% of Africa’s
2023 liquids output
While majority of the production
from Nigeria and Angola is from
offshore projects, Algeria, Libya
and Egypt’s production comes
from their respective onshore
fields
Production from Nigeria and
Angola is in decline, whereas
Algeria and Egypt production
trend has been relatively flat since
2015. Libya’s now subsiding civil
war impact is expected to result in
increased production in 2023
Regulatory cuts in the form of
OPEC sanctions are expected to
result in outages in Algeria’s crude
oil output throughout the year
Africa 2023 liquids supply is esti-
mated at almost 7 MMbbls/d. This
reflects a marginal year-on-year
growth from 6.875 MMbbls/d and
6.7 MMbbls/d in 2021 and 2022
respectively, and close to 430,000
barrels per day (bpd) from 2020
lows of about 6.55 MMbbls/d. While
this growth from the pandemic hit
lows is a positive sign, it should be
noted that 2023 expected output is
lower by 1 MMbbls/d than the highs
of 2015 where output was almost
8 MMbbls/d. This steep drop from
2015 is majorly due to output drop
from declining fields in Nigeria,
Angola, Equatorial Guinea, Egypt
and South Sudan. Cumulative drop
from these five countries is around
1.735 MMbbls/d and the overall pro-
duction drop, from all the countries
where output has declined, is 1.89
MMbbls/d. This drop is partially
offset by production increase from
mainly Libya, Congo and Ghana –
accounting to a cumulative output
increase of 880,000 bpd.
Nigeria, Libya, Algeria, Angola and
Egypt are expected to be the top
five liquids producers for the year
with a combined output of about
5.76 MMbbls/d, more than 80% of
the continent’s overall annual out-
put.
Nigeria – Nigerian crude produc-
tion looks on course to rebound to
over 1.3 MMbbls/d in 2023, as gov-
ernment efforts to tackle persistent
oil theft and pipeline vandalism
bear fruit. The major West African
producer’s crude oil output was 1.18
MMbbls/d last year, far below the
1.5 MMbbls/d seen in 2020, as theft
and vandalism led to force majeures
on key blends. Nigerian crude out-
put averaged 1.3 MMbbls/d in 2021
despite numerous impediments,
including accidental pipeline dam-
age, OPEC+ quotas and other un-
planned outages, even topping 1.4
MMbbls/d at the beginning of that
year. The outbreak of war between
Russia and Ukraine in February
2022 presented an opportunity for
Nigeria – as with other major pro-
ducer nations – to reap the benefits
of high oil prices, but the country
continued to be impaired by oil theft
and pipeline damage. In an effort to
curb theft and vandalism, the fed-
eral government announced a new
approach in collaboration with host
communities to protect critical pipe-
line systems, with a pipeline surveil-
lance contract awarded to protect
oil assets. The Nigerian Navy was
also employed to track vessels ille-
gally carrying crude oil, while Nige-
rian National Petroleum Corporation
(NNPC) also deployed various other
methods to monitor and report oil
theft in the country. All these ini-
tiatives reaped benefits as Nigeria
surpassed 1 MMbbls/d of crude pro-
duction in October 2022, closing
the year close to 1.2 MMbbls/d.
Nigeria’s National Upstream Petro-
1 AFRICA OIL SHORT-TERM SUPPLY OUTLOOK
www.energychamber.org 7
leum Regulatory Commission (NUPRC),
the country’s upstream regulator, in
December last year launched the Mini
Bid Round 2022 in the hope of boost-
ing investments and exploration activ-
ity. The Petroleum Industry Act (PIA)
of 2021, with its improved legal and
regulatory frameworks, also seeks to
encourage new investors and invest-
ments into the next phase of explora-
tion. Seven offshore blocks covering
a total area of approximately 6,700
square kilometers and situated in wa-
ter depths of between 1,150 meters
and 3,100 meters are on offer as part of
Nigeria’s fresh attempt at developing
offshore assets. The blocks are closer
to the producing fields of Aje, Erha and
Erha North and the undeveloped fields
of Ogo and Bosi. With President-elect
Bola Tinubu of the ruling All Progres-
sives Congress (APC) party emerging
victorious, the government’s strategy
to restore output levels can be ex-
G
Gl
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du
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ti
io
on
n s
sp
pl
li
it
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by
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co
on
nt
ti
in
ne
en
nt
t
Million barrels per day
2
33% 33% 33% 33% 33% 33% 33% 33% 33% 33% 33% 33%
23% 23% 23% 23% 23% 23% 23% 23% 23% 23% 24% 24%
13% 13% 12% 12% 12% 12% 12% 12% 12% 13% 13% 13%
11% 11% 11% 11% 11% 11% 11% 11% 11% 11% 11% 11%
8% 8% 8% 8% 8% 8% 8% 8% 8% 8% 8% 8%
8% 8% 8% 8% 8% 8% 8% 8% 8% 8% 8% 8%
4% 4% 4% 4% 4% 4% 4% 4% 4% 4% 4% 4%
82,47 83,67 83 83,05 82,74 83,29 83,91 83,52 83,78 83,69 84,03 83,86
0,00
25,00
50,00
75,00
100,00
Jan.23 Feb.23 Mar.23 Apr.23 May.23 Jun.23 Jul.23 Aug.23 Sep.23 Oct.23 Nov.23 Dec.23
Middle East America N Russia Asia Africa America S Europe Australia
Source: Rystad Energy OilMarketCube
Month-on-month oil and condensates global output
Africa’s contribution to 2023 global output at an average 8%
Source: Rystad Energy OilMarketCube
1.2 Top liquids producers of Africa in
2023
8
African Energy Chamber Q1 2023 Outlook Report
African Energy Chamber
8
pected to remain in place, leading to
1.3 million bpd this year if no sudden
outages manifest. There is also poten-
tial for upside if some blends that are
still underproducing can be restored
to pre-Covid-19 output levels.
Libya – Libya’s civil war had an ad-
verse impact on the country’s hydro-
carbon output historically. 2020 saw
the lowest of lows with crude oil pro-
duction diminishing to about 370,000
bpd. However, 2021 saw a reversal
with output surpassing the 1 MMb-
bls/d mark and reaching annual aver-
age of 1.12 MMbbls/d. 2022, yet again,
proved something of a rollercoaster
ride for the country and its staple oil
sector, following a relatively stable
2021. With presidential and parliamen-
tary elections originally scheduled for
December 2021 but pushed to June
2022 and then delayed indefinitely,
and given the continued existence of
two parallel governments, the politi-
cal atmosphere in the country soured
in 2022, resulting in production shut-
ins, violence and human casualties.
The situation in Libya has remained
strained due to the lack of any true de-
cision-making body, with this instability
linked to sudden eruptions of violence
that have led to increased volatility,
straining the nation’s economy. While
a common perception at that point
was that the country would continue to
struggle with production and the pro-
tests would turn more violent, resulting
in more lost volumes, in July 2022,
Libya’s output surprisingly rebound-
ed, protests ended, and the force ma-
jeure was lifted. The country staged
a remarkable recovery, and within
the space of three weeks, Libya was
able to surpass its rated capacity of 1.2
MMbbls/d, since when production has
remained relatively stable, with no ma-
jor disruptions. As a result, 2023 crude
oil output from Libya is expected at an
average 1.2 MMbbls/d.
Algeria – Algeria, like the rest of the
world, was hit by the pandemic and
2020 – 2021 crude oil output was at a
sub-1 MMbbls/d mark at 930,000 bpd
and 940,000 bpd, respectively. Better
performance from the existing fields
and newer start-ups combined with re-
vision in OPEC regulations resulted in
2022 crude oil output reaching close
to 1.07 MMbbls/d. However, OPEC+
cuts announced in October 2022, set
to be effective from November 2022
A
Af
fr
ri
ic
ca
a o
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sp
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tr
ry
y
Million barrels per day
3
Month-on-month oil and condensates output from Africa
Nigeria, Libya, Algeria, Angola and Egypt add up to over 80% of the output
Source: Rystad Energy OilMarketCube
21% 22% 22% 21% 21% 21% 21% 21% 21% 21% 22% 22%
19% 19% 19% 18% 18% 18% 18% 18% 18% 18% 18% 18%
18% 18% 18% 18% 18% 18% 18% 18% 18% 18% 18% 18%
16% 16% 15% 17% 17% 17% 17% 17% 17% 17% 17% 16%
8% 8% 8% 8% 8% 8% 8% 8% 8% 8% 8% 8%
6.84 6.92 6.87 7.01 7.03 7.02 7.02 7.02 7.03 7.04 7.02 7.00
0,00
2,50
5,00
7,50
10,00
Jan.23 Feb.23 Mar.23 Apr.23 May.23 Jun.23 Jul.23 Aug.23 Sep.23 Oct.23 Nov.23 Dec.23
Nigeria Libya Algeria Angola Egypt
Congo Gabon South Sudan Chad Ghana
Equatorial Guinea Sudan Cameroon Tunisia Others
Source: Rystad Energy OilMarketCube
www.energychamber.org 9
2
20
02
23
3 e
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Thousand barrels per day
2
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Thousand barrels per day
4
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3 p
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s i
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s
Thousand barrels per day
0
100
200
300
Jan.23 Feb.23 Mar.23 Apr.23 May.23 Jun.23 Jul.23 Aug.23 Sep.23 Oct.23 Nov.23 Dec.23
Algeria Angola Chad South Sudan Equatorial Guinea
0
100
200
300
Jan.23 Feb.23 Mar.23 Apr.23 May.23 Jun.23 Jul.23 Aug.23 Sep.23 Oct.23 Nov.23 Dec.23
Maintenance Other Planned Civil Unrest or Attacks
RegulatoryOrder Other Unplanned Saharan Blend (Algeria)
Dalia (Angola)
Doba Blend (Chad)
Nile Blend (South Sudan)
Mondo (Angola)
Alba (Equatorial Guinea)
Month-on-month oil and condensates production outages
Expected outages in Algeria throughout 2023 due to OPEC cuts
Source: Rystad Energy OilMarketCube
Source: Rystad Energy OilMarketCube
to December 2023 have resulted in
monthly production outages through-
out 2023. This, in turn, hindered any
possibility of further output growth in
2023 and expected crude oil produc-
tion from the country is expected at
1.06 MMbbls/d, similar to 2022 levels.
Angola – With depleting reservoirs
and declining production from the
Floating Production Storage and Off-
loading (FPSO) vessels deployed on
the deepwater fields, Angola’s liquids
out has been in a freefall since 2015.
However, newer start-ups in the Kaom-
bo North, Eastern & Western hubs
on Block 15/06 and Pazflor develop-
ments, the Greater Plutonio Phase 2,
CLOV Phase 2 and Dalia Phase 3 have
resulted in stable output since 2021.
The country’s 2021 and 2022 liquids
output was 1.13 MMbbls/d and 1.15
MMbbls/d respectively, and expected
2023 production is 1.15 MMbbls/d.
Egypt – Egypt’s liquids output is large-
ly supported by its joint venture (JV)
operations. The national oil company
(NOC), Egyptian General Petroleum
Corporation (EGPC) operates oil pro-
duction in the form different JVs like
Khalda Petroleum Company, Belayim
Petroleum (PETROBEL), Gulf of Suez
Petroleum Company (GUPCO), AGI-
BA Petroleum Company, Badr El-Din
Petroleum Company (BAPETCO) and
so on, with International Oil Compa-
nies (IOCs) like Apache, Eni, BP, Shell
(whose share in BAPETCO was later
acquired by Cheiron Group and Cap-
ricorn Energy). Compared to the other
top African producers, Egypt’s oil out-
put has been relatively stable for the
years 2021 – 2022 and 2023 output
is expected to be at about 460,000
bpd with condensates reaching an
output of about 125,000 bpd. About
three-quarters of the 2023 oil produc-
tion and a third of the year’s conden-
sates production is expected to come
from the onshore projects.
Majority of the remainder of the
production comes from sub-Saha-
ran African countries like Congo,
Gabon, Chad, Ghana and Equatorial
Guinea. Apart from non-sub-Saharan
African Tunisia, whose output for
the year 2023 is estimated close to
38,500 bpd, the rest of the 17% of
Africa’s 2023 oil and condensates
production is expected to come from
sub-Saharan Africa.
10
African Energy Chamber Q1 2023 Outlook Report
African Energy Chamber
10
2.1 Africa natural gas supply,
LNG infrastructure and LNG supply
Africa natural gas output is
majorly driven by the North and
West African projects
2023 annual output is expected
to reach about 268 Billion
cubic meters (Bcm) and
over 85% of this is estimated
to come from the North and
West African projects
The production from the
existing producing fields is in
terminal decline and any trend
reversal is expected only from
the currently pre-FID (Final
Investment Decision) fields
Africa natural gas supply is majorly
driven by the North and West African
gas projects. This high ratio of produc-
tion compared to the other regions is
expected to remain throughout this
decade and the next, considering the
conservative development timelines
and supply potentials of the mega
projects of the Eastern African nations
of Mozambique and Tanzania and
the currently recovered relatively low
potential of South Africa. 2023 Africa
natural gas output is expected at close
to 268 Bcm and cumulative share of
North and West African projects is es-
timated at 95% of the overall volume.
The share of these regions in 2025,
2030 and 2040 is estimated to be
95%, 90% and 80% respectively. North
Africa takes the larger share of the two
regions, but West is expected to catch
up by the end of the next decade in
the current conservative estimates of
timelines and production trends. Major
producers in North Africa include Al-
geria, Egypt & Libya, and these add up
to almost all of the natural gas output
from the region. The share of individ-
ual countries from West Africa is a dif-
ferent story – currently Nigeria, Angola
and Equatorial Guinea add up to 85%
of the overall output from the region.
While the share of these three coun-
tries is expected to remain the same
till 2025, it gradually decreases to 75%
by 2030, 70% by 2035 and to about
2 AFRICA NATURAL GAS AND LNG OUTLOOK
Any delays in these projects,
thus, will have an adverse
impact on the continent’s
natural gas aspirations
Africa’s total LNG export
infrastructure capacity expected
to increase from the existing 80
MMtpa to about 110 MMtpa by
2030 and further to over 175
MMtpa by the end of
the next decade
Nigeria, Algeria, Mozambique,
Senegal – Mauritania, Tanzania
and Egypt are expected to drive
this LNG export capacity in the
long term
Africa’s LNG exports are
expected to increase from 66
Bcm in 2023 (a 5% year-on-year
increase from 2022) to 77 Bcm
by 2030 and further to
100 Bcm by 2035
Africa’s own natural gas
production, international natural
gas imports and the annual
domestic demand levels put
the continent in a position to
pump natural gas volumes of
105 Bcm in 2023, 170 Bcm in
2030, 275 Bcm in 2037 and
a slightly lower 220 Bcm in
2040 to both domestic and
international markets
www.energychamber.org 11
A
Af
fr
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a n
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at
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al
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ga
as
s o
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pu
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sp
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by
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if
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cy
yc
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Billion cubic meters
A
Af
fr
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a n
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at
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as
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eg
gi
io
on
n
Billion cubic meters
5
0
100
200
300
400
500
2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040
North Africa East Africa South Africa West Africa
0
100
200
300
400
500
2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040
Under development Discovery
Africa natural gas output
Africa gas output growth over the 2030s to be driven by East & West undeveloped finds
Source: Rystad Energy UCube
Source: Rystad Energy UCube
60% by 2040. While these countries’
share is expected to decrease, natural
gas output from Senegal – Maurita-
nia is expected to increase as the BP
– Kosmos projects of Greater Tortue
Ahmeyim (GTA), Bir Allah, Yakaar –
Teranga projects come online and
ramp up. The share of these countries’
cumulative natural gas output is 5%,
10%, 15% and 30% of the overall West
Africa output from the years 2025,
2030, 2035 and 2040, respectively.
Natural gas production from Africa
is expected to stay relatively flat till
about 2027 at an average level of
about 270 Bcm before the currently
undeveloped volumes come online.
Output from the currently producing
fields is in terminal decline. Produc-
tion from these fields is estimated to
decline at an annual rate of about 5%
from 2025 through to 2040. While the
production from the currently post-
FID under development fields is es-
timated to see an annual increase of
about 15% from 2025 to 2030, output
from these fields is also expected to
decline going forward. The produc-
tion growth expected to happen in the
next decade is only from the currently
pre-FID potential. This growth over the
next decade is expected from projects
in both currently nascent upstream
economies like Mozambique, Tanza-
nia, Mauritania, Senegal, South Africa
and Ethiopia, as well as matured oil
and gas economies like Nigeria, Lib-
ya and Algeria. At the current conser-
vative forecast, the production from
these projects is expected to double
year-on-year from 2025 – 2029 and
then see a gradual increase till about
late 2030s. A little over 10% of the
total natural gas production from Af-
12
African Energy Chamber Q1 2023 Outlook Report
African Energy Chamber
12
rica is from these currently pre-FID/
pre-FEED (Front End Engineering
and Design) volumes and it increases
to over a half of the total output. As
such, these volumes are crucial to
Africa’s natural gas supplies and the
continent’s natural gas aspirations to
be a major liquified natural gas (LNG)
exporter to international markets.
Africa LNG export infrastructure also is
shaping in a similar way to the natu-
ral gas forecast. Between the bigger
producers like Algeria, Nigeria and
Egypt, Algeria and Egypt are expect-
ed to maintain their existing LNG infra-
structure capacity of about 29 million
tonnes per annum (MMtpa) and 12.7
MMtpa, respectively. Nigeria’s plans
involve increasing its LNG infrastruc-
ture capacity from the existing 22
MMtpa to 30 MMtpa via the Nigeria
LNG (NLNG) Train 7 development and
further marginally to just over 31 MMt-
pa via UTM Offshore’s FLNG project.
In the period through to 2040, Mozam-
bique is expected to see the highest
increase in LNG export capacity, in-
creasing from current capacity of 3.4
MMtpa to close to 16.3 MMtpa and
further to 31.5 MMtpa and finally to
about 43.5 MMtpa by the end of the
next decade. This is conditional to sit-
uation in the country where operator
TotalEnergies was recently reported
to be resuming work soon after a force
majeure was declared on the project
in April 2021 after Islamist insurgents
attacked Palma town close to the proj-
ect construction site at Afungi. Exx-
onMobil partners in the Coral project
were also recently reported that they
would take a call soon on whether a
second floating liquefied natural gas
vessel (FLNG) vessel would be de-
ployed. This decision is also subject to
the US major’s decision on it onshore
US$24 billion Rovuma LNG scheme
as disturbances in the Cabo Delgado
province due to Islamist insurgency
since 2017, are now reported to be
subsiding.
Senegal – Mauritania on the Western
side of Africa and Tanzania on the
Eastern side are countries expected
A
Af
fr
ri
ic
ca
a L
LN
NG
G e
ex
xp
po
or
rt
t i
in
nf
fr
ra
as
st
tr
ru
uc
ct
tu
ur
re
e
Million tonnes per annum (MMtpa)
6
0
50
100
150
200
2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040
Nigeria Algeria Mozambique Egypt Equatorial Guinea
Angola Mauritania Tanzania Libya Senegal
Congo Djibouti Cameroon
Source: Rystad Energy GasMarketCube
Africa LNG export infrastructure
Mozambique – Tanzania in the east and Mauritania – Senegal in the west to drive LNG infrastructure growth
Source: Rystad Energy GasMarketCube
www.energychamber.org 13
to ramp up their FLNG export capac-
ities. While BP – Kosmos owned LNG
projects in the waters off Senegal and
Mauritania are expected to lead to an
increase in the cumulative capacity of
both the countries from the 2.5 MMt-
pa capacity, that is expected to kick
off next year, to an overall 22.5 MMt-
pa capacity by the second half of the
next decade. In Tanzania, the Energy
Ministry recently announced that part-
ners on the deepwater blocks 1, 2 and
4 – Shell, Equinor, ExxonMobil, Pa-
vilion Energy and Medco Energi and
the government have completed dis-
cussions on the contractual terms of
a critical host government agreement
(HGA), taking another step towards
the US$30 billion LNG project with a
10 MMtpa capacity. Other projects like
Marine XII FLNG in Congo, Angola’s
Soyo LNG taking feedgas from the
Quiluma – Maboqueiro and Sanha
lean gas complexes, and Equatorial
Guinea’s Punta Europa LNG plant are
a few other key projects maintaining
or increasing Africa’s LNG export in-
frastructure capacity.
Africa has been a historical LNG and
gas-via-pipeline exporter, especially
to Europe. Close to 65% of the overall
LNG and pipeline exports from Africa in
the period 2005 – 2022 have been to
Europe. Historically a fifth of the overall
natural gas produced in Africa has been
catering to international markets via LNG
exports. This volume share has seen a
slight increase in the past 3 – 4 years
where the overall LNG exports share
has increased to a quarter of the total
production. Taking into consideration
the existing LNG export agreements, the
export potential is expected to stay at a
relatively flat share of 25% of the total
natural gas produced. However, with the
increase in natural gas production, the
overall LNG exports are also expected
to increase going forward. Overall nat-
ural gas output is expected to increase
from 268 Bcm in 2023 to 272 Bcm in
2025. The output is further expected to
increase to 340 Bcm in 2030 and further
to about 420 Bcm. In lie with this, 2023,
2030 and 2035 expected LNG flows
from Africa are 66 Bcm, 77 Bcm and 100
Bcm, respectively.
A
Af
fr
ri
ic
ca
a n
na
at
tu
ur
ra
al
l g
ga
as
s a
an
nd
d L
LN
NG
G o
ou
ut
tp
pu
ut
t
Billion cubic meters
76%
78% 76% 75% 78% 79% 76% 76% 77%
76%
77%
78% 77% 76% 76% 76%
78% 78% 77%
76%
75%
24%
22% 24% 25% 22% 21% 24% 24%
23%
24%
23%
22%
23%
24%
24%
24%
22%
22%
23%
24%
25%
231
266 262 268 272 272 272 277
291
317
340
357
370
390
404
419
444
455
448
424
401
0
100
200
300
400
500
2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040
Gas LNG
7
Africa gas and LNG output
Africa average LNG output a quarter of the total over this and the next decade
Source: Rystad Energy UCube
Source: Rystad Energy UCube
14
African Energy Chamber Q1 2023 Outlook Report
African Energy Chamber
14
Africa natural gas production is on the
rise, provided there are no project de-
lays or revisions in current development
plans, but so is the demand forecast.
2022 – 2023 production curve is rela-
tively flat, and demand is also an annual
172 Bcm, a 65% share of the overall out-
put. The share of demand is expected to
remain flat at the 65% mark as demand
grows in line with the output till about
2028. Post this, the production is ex-
pected to grow faster than the demand,
reducing the overall share of demand to
60% in 2029 and further lower to 55%
in 2030. Annual demand is expected to
stay at around 55% of the total produc-
tion throughout the next decade. Of the
total demand, power generation’s share
is expected to be around 50% through
the end of this decade and 45% on av-
erage through the next decade 2031 –
2040. Power generation, industrial us-
age and residential consumption form
the key sectors of natural gas demand
adding up to an average of 75% of the
total demand through the period 2023
– 2030 and a slightly lower 70% of the
total demand through the years 2031 –
2040. Taking into consideration Africa’s
natural gas imports, like Egypt importing
gas from Israel, Africa’s overall natural
gas supply is expected to increase from
275 Bcm in 2023 to 285 Bcm in 2025,
further to 360 Bcm in 2030 and 510
Bcm in 2037 before declining to 460
Bcm by 2040.
Taking out the forecasted domestic de-
mand, these supply levels put Africa in
a position to pump natural gas volumes
of 105 Bcm in 2023, 170 Bcm in 2030,
275 Bcm in 2037 and a slightly lower
220 Bcm in 2040 that can be catered
to both, domestic markets for an in-
creased focus on gas-to-power output
that can be in turn used to eliminate
energy poverty and also international
markets in the form of LNG cargos and
pipeline exports that can generate rev-
enues for the hydrocarbon dependant
African economies.
2.2 Africa gas demand and LNG
exports vs additional potential






























 
 




    









 


















                    
        
         
  ­  €‚ƒ „         

       
   
          
Source: Rystad Energy UCube; Rystad Energy GasMarketCube
www.energychamber.org 15
3 PROJECT DELAYS IN AFRICA AND IMPACT
3.1 Future start-ups coming online
after very long discovery to start-up
periods
Africa’s upcoming upstream
projects have already seen
large delays from the time the
hydrocarbon discoveries were
made to the estimated future FID
Many crude oil discoveries that
can stabilize the production
and offset the terminal decline
in output for a few years; and
also, giant natural gas finds that
can help Africa meet domestic
demand, universal electricity
access and LNG export
aspirations have seen long
delays due to various above-the-
surface issues
Over a half of the hydrocarbon
output from Africa over the
period 2025 – 2040 and
about 60% of the remaining
recoverable oil and gas reserves
in Africa is estimated to come
from these upcoming/delayed
start-ups
Governments are now realizing
the impact of these delays
and putting in the efforts to
bring these projects online and
also bring in more exploration
investments, but more
is required
At the current conservatively
estimated development timeline
and scale, a mammoth US$795
billion of greenfield expenditure
is required over the period
2023 – 2040 to bring these
undeveloped discoveries online
A condensed study on some the key pro-
ducing projects and upcoming start-ups
across Africa, suggests that while current
producing fields saw a relatively lower
discovery to start-up period suggesting
a lower delay in terms bring the field on
stream, the discovery to start-up period for
the upcoming start-ups is sometimes dou-
ble or even longer compared to the older
producing fields. Many old gas discoveries
in East Africa, which are expected to drive
the natural gas and LNG growth from Af-
rica, have already seen long delays from
the time they were “found” to awaiting a
final investment decision (FID) and kick off
development.
Natural gas project delays across East
Africa
Mozambique – Mozambique saw a wave
of large gas discoveries in the early to
mid-2010s and the total gas discovered
was an estimated (conservative) 17 Bboe.
Of these volumes, only about 700 Million
barrels of oil equivalent (MMboe) Coral Sul
field on Area 4 is currently pumping LNG
volumes into international market via the
3.4 MMtpa Coral Sul floating liquefied nat-
ural gas (FLNG) vessel which saw the FID
in mid-2017 and shipped off the first cargo
in November 2022. Further development
on Area 4 includes half a billion barrels
of oil equivalent Coral North FLNG devel-
opment expected to kick off in 2024 and
come online in 2027; Area 4 LNG (Trains
1  2) with a capacity of 15.2 MMtpa with
expected FID in late 2020s and start-up in
early 2030s and finally the 12 MMtpa Area
4 LNG (Trains 3  4) expected to be FID’ed
in mid-2030s and pump LNG exports by
late-2030s.
Area 1 also saw some progress in line with
Area 4’s Coral Sul development but hit
brakes due to Islamic insurgency in the
onshore development area. The Area 1
LNG (Trains 1  2) with a capacity of 12.88
MMtpa using feedgas from Atum and Golf-
inho fields with a cumulative gas volume
of almost 3.2 Bboe saw the FID happen
in 2019, but the start-up is now delayed to
late-2020s due to the operator TotalEn-
ergies imposing a force majeure on the
$20 billion project as the security situation
in the northeast region of Cabo Delgado
worsened. Further development on Area 1
involves development of trains 3  4 with
an expected FID in early to mid-2030s and
start-up by late 2030s. Area 1 reportedly
holds approximately 75 trillion cubic feet
(Tcf) of recoverable gas. Development of
further potential in the area can spill over
to a much later timeline.
Mozambique also has the Eni – Exxon-
Mobil – TotalEnergies partnered Joint de-
velopment LNG project, expected to use
feedgas from the 2010 – 2012 discoveries
of Mamba North, Prosperidade (Lagosta
 Windjammer) with an estimated gas po-
tential of almost 4.5 Bboe. This is another
delayed giant natural gas development
expected to come online earliest by the
end of the next decade.
Tanzania – Tanzania also saw a wave of
natural gas discoveries in the early to mid-
2010s,likeitsneighbourMozambique. The
overall discovered recoverable natural gas
16
African Energy Chamber Q1 2023 Outlook Report
African Energy Chamber
16
volumes is a conservatively estimated 4.3
Bboe. These volumes were discovered
in Block 1 and Block 4 both operated by
Shell Plc and Block 2 operated by Equinor.
These volumes have still not seen or even
gotten close to a possible FID soon. How-
ever, both the operators and Tanzania’s
government recently concluded discus-
sions and the contractual terms of a critical
host government agreement (HGA) that
will underpin the project are now being
drawn up. Tanzania’s Minister of Energy
January Makamba said this was a major
breakthrough on plans to build a US$30
billion LNG project aiming to pipe gas from
these blocks to a 10 MMtpa LNG plant at
Lindi. Last year, Tanzania’s President Sumia
Hassan suggested that if an HGA could be
signed by the end of 2022, then the Tan-
zania LNG would see a possible FID by
2025. This would mean first cargoes from
the project latest by early-2030s. It re-
mains to be seen whether this agreement
would result in actionable contracts and
accelerated development of these strand-
ed gas reserves
Ethiopia – The natural gas volumes dis-
covered in Ethiopia in the 1970s – 1980s,
amounting to over 1.5 Bboe at a conser-
vative level, are yet to see an FID happen
and these gas finds are expected to come
online only in the next decade, that too in
phases spread over early to late 2030s.
Crude oil project delays in West Africa
While the above narrative may suggest it
is just the gas finds that are long delayed
with a possible reasoning that historically
operators having preferred development
of oil finds over gas discoveries due to
their impact on economics and/or regional
disturbances and so on, the story is no dif-
ferent for many large oil finds in the west-
ern side of the continent. Lack of fiscal
reforms, like in the case of Nigeria and An-
gola; delayed fiscal reforms like the more-
than-a-decade-in-the-making Petroleum
Industry Act (PIA) of Nigeria; market fluctua-
tions due to demand – supply imbalances,
crude price crashes due to these market
fluctuations or the more recent pandemic
and war situations or the currently ongo-
ing energy transition and upstream cost
cutting strategies have resulted in pushing
out many large crude oil finds’ develop-
ment timelines. Shell Plc brought the Bon-
ga Southwest – Aparo (BSWA) project con-
tracts on to the table many times, before
going back to the drawing board. The Etan
– Zabazaba project offshore Nigeria spent
years in delay due to an ongoing legal pro-
cess which has now been resolved. Many
such deepwater mega finds, with the ca-
pacity to reverse the declining production
trend in their respective countries, are cur-
rently in long delayed FID state.
Namibia saw the giant offshore Venus,
Graff and Jonker discoveries in the past
fifteen months. Post these finds, the coun-
try has been seeing increased interest in
exploration in its waters. Operator Shell,
which made the Graff, La Rona and Jonk-
er finds, announced that it plans to drill as
many as 10 new exploration and appraisal
wells on its prolific petroleum exploration
licence (PEL) 39. Many other companies
have expressed and/or already entered
blocks in the region with plans to soon drill
more exploration wells in hopes to mimic
Shell and TotalEnergies’ success. While
this is great news for Namibia, the admin-
Project Country Resources (Million boe)
2 years Zohr Egypt 3580
9 years Dalia/Camelia Angola 1600
10 years Agbami-Ekoli Nigeria 1360
3 years Palogue South Sudan 1055
10 years Bonga Nigeria 1045
7 years El Feel (Elephant) Libya 875
5 years Girassol Angola 795
16 years Atum Mozambique 1855
16 years Golfinho Mozambique 1730
9 years Ahmeyim FLNG 1 Mauritania 770
14 years Ain Tsila Algeria 480
18 years Jobi-Rii (x-Buffalo-Giraffe) Uganda 400
30 years Prosperidade (Barquentine) Mozambique 2355
37 years Orca Mozambique 2050
31 years Prosperidade (Lagosta) Mozambique 2005
29 years Mamba North Mozambique 1975
17 years Orca Mauritania 1320
11 years Venus Phase 2 Namibia 945
18 years Teranga Senegal 540
10 years Marine XII FLNG Phase 2 Congo 385
9
Discovery to FID FID to start-up Liquids Gas
Source: Rystad Energy UCube
Upstream project delays in Africa
Many post-FID and pre-FID projects seeing a large discovery to estimated start-up duration
Source: Rystad Energy UCube
www.energychamber.org 17
Project Country Resources (Million boe)
Bosi Nigeria
Bonga Southwest - Aparo Nigeria
Owowo West Nigeria
Orca Angola
Etan – Zabazaba Nigeria
Bonga North Nigeria
Pecan Phase 1 Ghana
Nsiko Nigeria
Cameia Angola
Chissonga Angola
10
Source: Rystad Energy UCube
36 years
29 years
18 years
21 years
27 years
27 years
17 years
29 years
15 years
21 years
Discovery to FID FID to start-up
795
630
550
550
525
500
235
165
145
85
Liquids Gas
Upstream project delays in Africa
Many key West African crude oil projects also seeing large delays
Source: Rystad Energy UCube
istration will also be hoping that these dis-
coveries add value to the economy in an
accelerated timeline without any project
delays. Africa, especially deepwater, has
had a history of being brought on to the
chopping block ahead of any other re-
gions globally, by operators when the oil
marketturbulenceshappened.Therecent
case of Angola going through a period of
no offshore drilling, something that years
of internal struggle could not do, during
the market crash led by the pandemic is
an example. It is to be noted that Angola
had, shortly before this, announced fiscal
incentives to operators working on blocks
in deep waters. This suggests something
more is required alongside tax incentives
for deepwater development to be more
encouraged by the respective govern-
ments. A fiscal stability clause can be one
way of doing this. A fiscal stability clause is
a clause to provide the operators with rea-
sonable assurance that changes in law or
regulations will not adversely affect their
expected economic return. Such stability
oriented fiscal policies can support crisis
mitigation when needed and act as a cat-
alyst for increased interest in oil and gas
exploration and development offshore
Namibia in the Walvis and Namibe basins,
alongside the already proven and prolific
Orange basin. The fact that no such stabil-
ity clauses for economic rebalancing and/
or equalization are currently defined in
Namibia’s current tax royalty agreements
can lead to delays in development of the
giant discoveries that were made in the
country.
While project delays have impact on their
individual country economies, certain re-
gional schemes can also be adversely
impacted. For example, in March 2022,
Equatorial Guinea and Nigeria signed a
memorandum of understanding (MoU)
that could see gas from Nigeria fed to the
Punta Europa LNG complex in Equatorial
Guinea, that is currently fed by gas from
the Alba and Alen-Aseng fields operated
by Marathon Oil and Chevron, respective-
ly. This deal, if ratified, could help monetise
currently untapped offshore associated
gas from Nigeria, while replacing declining
output from Equatorial Guinean fields. This
MoU was the latest of many deals signed
by the Equatorial Guinean government
over recent years to try to develop Bioko
Islandasamega-gashubintheregion.Itis
to be noted such cross-border gas import
arrangements were signed previously but
never got implemented. In such environ-
ment, it becomes imperative that Equa-
torial Guinea is able to smoothly bring its
own undeveloped gas reserves to start-
up without any delays. The delays asso-
ciated with the Fortuna FLNG on Block 27,
formerly Block R, should be looked to cut
down. The block is yet to see an operator
finalised although it was reported in 2022
that Golar LNG and New Fortress Energy
had teamed up to provide a deep-water
floating liquefied natural gas (FLNG) unit
for use on the Fortuna gas discovery in
Block 27. As of early 2023, discussions
were said to be ongoing between the ad-
ministration and potential operators, and
it was reported that a production sharing
contract (PSC) was ready to be signed.
The country should look to quickly finalis-
ing the required agreements and limit any
delays to the project to progress towards
becoming an important player in energy
markets in a world transitioning to a lower
carbon footprint.
18
African Energy Chamber Q1 2023 Outlook Report
African Energy Chamber
18
These currently delayed projects and/
or future start-ups have a large impact
on the production forecast for Africa.
The currently producing fields – both
liquids and gas – are in terminal de-
cline due to depleting reservoirs. Any
infill drilling or redevelopment program
on these fields, which will involve wa-
ter depth corresponding brownfield
spending, might result in a short-term
stabilization of the decline in produc-
tion but does not seem like it can offset
the steep decline. Liquids output from
these fields is estimated at about 7.66
MMbbls/d in 2023, 6.85 MMbbls/d in
2025 and 4.7 MMbbls/d in 2030. The
average annual production decline
rate is an 8% through 2025 – 2030
and a higher 10% through the years
2031 – 2040. 2040 production from
these declining fields is a much lower
1.67 MMbbls/d. Any further delays or
worse shelving of these future start-
ups can be catastrophic to Africa’s hy-
drocarbon output. While the short-term
(2023 – 2025) start-ups are expected
to have a little impact on the forecast,
the medium-term (2026 – 2030) and
long-term (2030+) start-ups are expect-
ed to drive a revival in Africa’s liquids
output in the period through 2040. The
medium-term start-ups are expected to
drive an output of about 1 MMbbls/d in
2028, increasing further to as high as
2.8 MMbbls/d by 2031 – 2032 before
gradually declining to 1.15 MMbbls/d by
2040. The long-term start-ups which
kick off post 2030 are expected to
ramp up quickly to about 1 MMbbls/d
by 2032, gradually increase to over 4.2
MMbbls/d by 2038 and decline down
to 3.8 MMbbls/d by 2040. The overall
impact of these delayed start-ups is still
short lived as the total liquids output
from Africa is expected to ramp up to
about 8.4 MMbbls/d in 2036 from 2023
estimated production of 7.7 MMbbls/d
and 2030 flows of 7.37 MMbbls/d, but
soon starts declining to an estimated
6.7 MMbbls/d by 2040. The overall re-
maining recoverable liquids reserves in
Africa, as of January 1st, 2023, are es-
timated at about 74.5 Bbbls and a half
of this is from the currently producing



































  


 
 



 
 


 

 
 





          


















  
                         
   
      
  



 





 

Source: Rystad Energy UCube
3.2 Currently delayed future start-ups
– key to Africa’s production increase
www.energychamber.org 19
fields. A third of this volume is from the
fields delayed to post-2030 as per the
current estimated timeline and almost a
fifth is from the medium-term start-ups.
As such, Africa not only needs these
existing discoveries to not see any fur-
ther delays, but also additional explo-
ration and development to stabilise at
production levels higher than 2023 in
the future.
The situation of natural gas production
forecast is no different from the liquids
forecast. The decline in producing
fields although terminal, however, is
not as steep as the liquids producing
fields. 2023 output of 4.29 Million bar-
rels of equivalent per day (MMboe/d)
actually is marginally higher than the
2022 output of 4.23 MMboe/d. From
2023 through to 2040, the average
annual decline in production from the
producing fields is 5% year-on-year
(YoY). The short-term start-ups are es-
timated to account for 10% of the total
output by 2025. The share from the
currently producing fields is expected
to drop to 50% by 2031 and further to
about a quarter of the total output by
2040. Also, the long-term start-ups are
estimated to add up to a third of the to-
tal output by 2035 and half of the total
output by 2037 – 2038, and this share
is only expected to increase going
forward. Of the remaining reserves of
close to 83 Bboe, only a third is from
the currently producing fields and al-
most a half comes from the long-term
start-ups. While the newer start-ups are
expected to offset the decline from the
producing fields and take the overall
output on a ramp up till about 2037,
the total output declines going forward.
Any increase in domestic demand,
universal electricity access via gas-to-
power or LNG export aspirations post
this period of ramp up will require new-
er gas volumes required to be injected
into the flows via additional exploration.
Governments do realize the project de-
lays and the issues caused – both eco-
nomic for the countries dependant on
hydrocarbon exports and domestic for
countries looking for alternate sources
other than coal and firewood for pow-
er generation and residential purposes
(like cooking). Past few years have seen
fruition of these efforts with Nigeria fi-
nally passing the long-delayed Petro-
leum Industry Act (PIA) and this has re-
sulted in critical new production sharing
contracts (PSCs) signed with superma-
jors. In August 2022, Nigeria executed
new terms and conditions for six prolific
offshore licences – Oil Mining Lease
(OML) 125 operated by Eni, OMLs 128
and 132 operated by Chevron, OMLs
130 and 138 operated by TotalEnergies
and OML 133 operated by ExxonMo-
bil. It is no secret that these operators
have shown disinterest thus far in fur-
ther investments in these blocks due to
legal and fiscal uncertainties and older
PSCs due to expire. The renegotiated
PSCs were in line with the provisions
of the PIA. These renewed PSCs en-
able improved long-term relationships
with contractors and help eliminate any
contractual ambiguities — especially
in relation to gas. National Petroleum
Investment Management Services
(NAPIMS), which monitors PSC invest-
ments, said that the renewed PSCs will
unlock more than 10 Bbbls of oil and
generate an estimated revenue of over
US$500 billion to the government and
its PSC partners. Nigeria, earlier this
year, launched a licensing round cov-
ering seven frontier deep-water and
ultra-deepwater blocks – Petroleum
Prospecting Licences (PPLs) 300, 301,
302, 303, 304, 305 and 306 as part of
ongoing efforts to boost largely stalled
exploration activities.
Angola also passed the Marginal Field
incentives allowing tax incentives on
deep water field development that can
encourage the operators to accelerate
the development of these discoveries.
And more recently, Agência Nacional
de Petróleo, Gás e Biocombustíveis
(ANPG) or Angola’s National Oil, Gas
and Biofuel’s Agency signed a mem-
orandum of understanding (MoU) cov-
ering revised fiscal and contractual
terms for the Risk sharing agreements
(RSAs) covering deep-water blocks
30, 44 and 45 with the block partners
ExxonMobil and Angolan state-owned
partner Sonangol PP. This has led to
ExxonMobil recently announcing that it
is set to spend US$200 million to drill
an exploration well by the end of 2024
in the untouched frontier Namibe basin.
Other regions also are stepping up in
terms of attracting investments from in-
ternational oil companies (IOCs).
On the other hand, there are also situa-
tions that need to be better addressed
by the respective administrations. Ni-
geria’s previous marginal field licens-
ing round, despite talk about being a
streamlined and open process, instead
became a lengthy test of patience, with
its transparency also questioned. For
the mini-round launched in January
2023 also, the schedule beyond sub-
mission of pre-qualification documents
to be submitted by the end of January,
is unclear, with bid round documenta-
tion not outlining when awards are due
to take place. Another case example is
the long running gas price discussions
between the South African adminis-
tration and TotalEnergies, for the us-
age of Block 11B/12B gas for domestic
purposes, leading to the French major
now considering LNG scheme for ex-
port markets. These kind of issues can
prove to be a hindrance and prove that
more is required from the administra-
tions in terms of both attracting invest-
ments in the upstream industry as well
as reaping benefits from the hydrocar-
bon developments.
20
African Energy Chamber Q1 2023 Outlook Report
African Energy Chamber
20
The development of the large unde-
veloped recoverable reserve potential
requires an equally high greenfield in-
vestments. The spending levels are also
seeing an increase YoY, with 2022 green-
field expenditure at US$18 billion and
2023 estimated greenfield spending at
US$20 billion – a 10% YoY increase. 2025
greenfield spending is estimated at about
US$24 billion, a 20% increase over 2023
spending. At the current conservative re-
coverable reserves, development time-
line and per-barrel spending estimates,
the estimated (required) overall greenfield
spending over the years 2023 – 2030 is
US$290 billion and it further increases
to close to US$485 billion over the next
decade. Close to 50% of the 2023 green-
field spending is expected to be spent
on offshore projects and 30% of the to-
tal spending is expected to be spent on
deep water projects. As most of the large
undeveloped oil and gas finds currently
are in deep waters off Africa, majority of
the greenfield spending going forward is
also expected to be on deep water proj-
ects. 2025 offshore greenfield spending
and deep-water greenfield spending is
expected to increase to 65% and 45% re-
spectively of the total spending of US$24
billion. This is expected to increase to 67%
and over 50% of the total spending of
about US$55 billion in 2030; and further
to over 70% and about 55% respectively
from the total spending of about US$64.5
billion in 2035. Of the total estimated
greenfield spending of about US$775
over the period 2023 – 2040, US$500
billion or about 65% is expected to be
spent on offshore projects and US$375
billion or close to 48% is estimated to be
spent on deep water projects.
These deep-water investments include
some high-profile projects like the Great-
er Tortue Ahmeyim (GTA) – Yakaar –
Teranga – Bir Allah – Orca offshore Sen-
egal – Mauritania; Pecan offshore Ghana;
Bosi, Bonga North, BSWA, Etan – Zaba-
zaba offshore Nigeria; Cameia – Golfin-
ho and Chissonga offshore Angola; off-
shore feedgas fields for Area 1 and Area
4 LNG schemes in Mozambique; Blocks
1,2 and 4 offshore gas fields off Tanzania;
Brulpadda – Luiperd gas fields offshore
South Africa and the most recent Venus
– Graff oil discoveries offshore Namibia to
name a few. The magnitude of reserves
and the cost intensive nature of offshore
deep-water projects are the key drivers
behind this large spending forecast. Con-
sidering the impact of these projects on
Africa’s production forecast, the impor-
tance of securing the funding for the de-
velopment should be on the forefront for
the governments as well as the operators.
3.3 Plenty of potential but equally large
investments needed to develop the volumes
A
Af
fr
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ic
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a c
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ap
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it
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al
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by
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h
Billion USD
A
Af
fr
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a g
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– b
br
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wn
nf
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xp
pe
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di
it
tu
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sp
pe
en
nd
di
in
ng
g
Billion USD
12
0
25
50
75
100
2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040
Greenfield Brownfield
0
25
50
75
100
2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040
Land Deep water (125-1500 meter) Ultra deepwater (1500+ meter) Shelf (to 125 meter)
Source: Rystad Energy UCube
Africa capital expenditure spending
Close to US$775 billion greenfield spending required over 2023 – 2040
Source: Rystad Energy UCube
www.energychamber.org 21
4 AFRICA RENEWABLES OUTLOOK
4.1 Global renewables capacity
driven by Asia, Europe and the States
2023 global renewables capacity
(solar + wind + hydrogen
electrolyzer) is 1,500 GW
Asia, Europe and North America
are expected to drive over 90%
of this capacity, with Africa
contributing a negligible 1% of
the annual capacity
As hydrogen capacity in Africa
picks up, 2035 Africa output is
expected to increase to 7% of the
global capacity
Africa’s current announced
renewables capacity stands at
134 GW of wind capacity, 120
GW of solar capacity and 112 GW
of hydrogen capacity
Egypt, Morocco, Mauritania
and South Africa are the
major countries with current
announced capacity
Over 75% of the current
announced capacity is in
concept stage
Africa’s renewables capacity
output is expected to increase
from about 27.4 GW in 2023 to
over 280 GW in 2035
CWP Global (in partnership with
Bechtel in a few projects) is
the main operator with close to
25% of the current announced
capacity in Africa
2023 global renewables capacity (solar +
wind + hydrogen electrolyzer) is estimated
to reach about 1,500 gigawatt (GW) largely
driven by the growth in Asia, Europe and
the United States where the 2023 renew-
ables capacity is about 760 GW, 330 GW
and 265 GW, respectively. This cumulative
capacity adds up to over 90% of the global
2023 capacity. These three regions are ex-
pected to drive majority of the capacity go-
ing further till 2035. While the global capac-
ity is estimated to grow to about 2,075 GW,
3,085 GW and 3,815 GW by 2025, 2030
and 2035 respectively, these three regions
are expected to cumulatively contribute
90%, 85% and over 80% of the total capac-
ity during the same years 2025, 2030 and
2035, respectively. Africa’s capacity also
is expected to see a gradual through the
period 2020 to 2035 but is marginal com-
pared to major drivers and global cumula-
tive capacity volumes. Africa 2023 capacity
is expected to reach 21.5 GW and increase
to close to 30 GW by 2025. This capacity is
expected to grow further to about 75 GW
by 2030 and over 135 GW by 2035. This
corresponds to 1%, 2%, 5% and 7% of the
global capacities for the years 2023, 2025,
2030 and 2035, respectively.
2023 global wind and solar capacity is es-
timated to reach about 925 GW and 575
GW, respectively. Global wind capacity is
expected to increase to 1,580 GW by 2030
and further to over 1,900 GW by 2035. And
solar capacity is expected to increase to
1,295GWby2030andfurthertoover1,530
GW by 2035. Compared to this, Africa’s
2023 solar PV and onshore wind capacity
is about 12 GW and 9.3 GW respectively,
and 2025 capacities are expected to show
increases to 21.5GW and 17.5GW of solar
PV and onshore wind capacity, respective-
ly. These low-capacity volumes reflect Afri-
ca’s exposure to renewables compared to
the giant contributors like Asia, Europe and
North America which are expected to see
a relatively massive capacity and growth.
























































































      
               
22
African Energy Chamber Q1 2023 Outlook Report
African Energy Chamber
22
Total announced capacity of renew-
ables in Africa is currently just over
375 GW. More than three-fourths of
this is currently in concept stage and
a little over 5% is operating. This sug-
gests a large potential with further up-
side as more operators and investors
enter the continent with a clean en-
ergy and energy transition objective,
but very little currently contributing to
Africa’s energy needs. This also sug-
gests large infrastructure needs which
demand equally high investments.
The geographical split suggests more
than half of the announced capacity
is in North Africa and apart from Mau-
ritania in the west and South Africa in
the south, the exposure of the rest of
sub-Saharan Africa to announced re-
newables capacity is relatively much
lower. Apart from Mauritania and
South Africa, announced wind ca-
pacity in Nigeria, all round capacity in
Djibouti and promising hydrogen ca-
pacity growth in Namibia round off the
main sub-Saharan African renewables
investments.
The continent is expected to see a
steep growth in renewables capacity
from 2025. Solar and wind is expect-
ed to drive the capacity as well as the
YoY growth going forward. Close to
80% of the 2023 capacity is driven by
solar and wind; and this increases to
about 85% by 2025. 2026 – 2030 av-
erage cumulative solar and wind ca-
pacity is expected to be close to 80%
of the total capacity over the period.
As hydrogen capacity picks up over
the 2030s, the average cumulative
solar and wind capacity is expected
to be close to 75% of the total capaci-
ty over the period 2031 – 2035.
Africa’s current total announced re-
newables capacity suggests that the
wind capacity at close to 134 GW
is the largest. Almost a half of this
comes from Egypt, and Morocco and
Mauritania add up to just over 30% of
the total capacity. South Africa and
Djibouti round off the top five coun-
tries with announced wind capacity
4.2 Majority announced renewables capacity in
concept stage and in North Africa
A
Af
fr
ri
ic
ca
a r
re
en
ne
ew
wa
ab
bl
le
es
s c
ca
ap
pa
ac
ci
it
ty
y f
fo
or
re
ec
ca
as
st
t
Giga Watts
14
0
50
100
150
200
250
300
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
Storage Hydrogen Electrolyzer Wind Solar
134
120
112
10
0 50 100 150
Wind
Solar
Hydrogen
Electrolyzer
Storag
e
Operating Construction Financial Close
Approved Application Auction
Concept
A
Af
fr
ri
ic
ca
a c
cu
ur
rr
re
en
nt
t r
re
en
ne
ew
wa
ab
bl
le
es
s a
an
nn
no
ou
un
nc
ce
ed
d c
ca
ap
pa
ac
ci
it
ty
y
Giga Watts
Source: Rystad Energy RenewableCube
Africa renewables capacity and forecast
Solar and wind to drive majority of the renewables capacity but currently 75% in concept stage
Source: Rystad Energy RenewableCube
www.energychamber.org 23
with a cumulative capacity of about
15.5 GW. These five countries add up
to 90% of the total current wind ca-
pacity in Africa. Over 75% of the cur-
rent wind capacity is still in concept
phase and only about 7% is operating,
in line with the overall announced re-
newables capacity.
Solar in Africa takes the second spot
after wind with the current announced
capacity at 120 GW. Solar announced
capacity too, similar to wind capacity
in Africa, is led by Egypt – 27.86 GW
capacity, Morocco – 22.11 GW capaci-
ty and Mauritania – 13.315 GW capac-
ity. These three countries add up to
over 50% of the current announced
solar capacity in Africa. Nigeria and
South Africa with 11.1 GW and 9.97
GW capacity respectively round off
the top five countries in Africa with
respect to announced solar capacity.
Close to 96.3 GW (~80% of the total)
is in concept phase now and about
10.75 GW (~9% of the total capacity)
is operating.
Africa’s current total announced
electrolyzer pipeline capacity is 112
GW, with about 40% of this tied to
countries in North Africa. The con-
tinent’s potential goes beyond the
north, however, with Sub-Saharan Af-
rica hosting numerous prospects for
green hydrogen developments. This
region has an announced electrolyzer
pipeline of about 68 GW, with Mauri-
tania claiming over 50% of this total,
followed by South Africa and Namib-
ia. Namibia’s green hydrogen sector
is poised for growth following recent
export agreements with Germany and
South Korea, while neighbour and re-
gional powerhouse South Africa sits
on about 90% of the world’s reserves
of platinum group metals, which are
critical for the manufacture of polymer
electrolyte membrane electrolyzers.
With the recent unveiling of the Eu-
ropean Union’s Green Deal Industrial
plan, which aims to promote renew-
able and hydrogen developments in
Africa, the continent is primed for for-
eign clean energy [EO1] investments
in the coming years.
Solar Wind Hydrogen
A
Af
fr
ri
ic
ca
a c
cu
ur
rr
re
en
nt
t r
re
en
ne
ew
wa
ab
bl
le
es
s a
an
nn
no
ou
un
nc
ce
ed
d c
ca
ap
pa
ac
ci
it
ty
y
Giga Watts
15
0 30
Egypt
Morocco
Mauritania
Nigeria
South Africa
Tunisia
Djibouti
Namibia
Botswana
Zimbabwe
Operating
Construction
Financial Close
Approved
Application
Concept
0 65
Egypt
Morocco
Mauritania
South Africa
Djibouti
Western
Sahara
Ethiopia
Tanzania
Kenya
Ghana
0 40
Mauritania
Egypt
South Africa
Morocco
Namibia
Djibouti
Angola
Kenya
Zimbabwe
Burkina Faso
Source: Rystad Energy RenewableCube
Africa renewables capacity
Egypt, Mauritania and Morocco leading the way in current announced capacity
Source: Rystad Energy RenewableCube
24
African Energy Chamber Q1 2023 Outlook Report
African Energy Chamber
24
In terms of the developers, the top 10
groups of developers contribute to over
55% of the currently announced renew-
ables capacity in Africa. Leading re-
newable energy developer CWP Glob-
al alone is said to be developing close
to a fifth of Africa’s announced wind ca-
pacity, close to 12% of the announced
solar capacity, a fifth of the continent’s
hydrogen capacity adding up to about
17% of Africa’s currently announced re-
newables capacity. With Bechtel’s part-
nership, CWP Global as a developer,
is developing Africa’s 25% announced
wind capacity, 20% announced solar
capacity, 28% announced hydrogen ca-
pacity and an overall 24% announced
renewables capacity. The US$40 billion
Aman green hydrogen project is being
developed by CWP Global and is the
largest green hydrogen project in Afri-
ca. It will have a 15 GW electrolyzer ca-
pacity, powered by 30 GW of combined
solar and wind. Geographical proximity
to the Mauritanian deepwater port of
Nouadhibou and the large European
market for exports make the green hy-
drogen project on Mauritania potential-
ly very lucrative. Morocco’s Amun proj-
ect, with an annual hydrogen capacity
of 900,000 tonnes per annum (tpa), is
also being developed by CWP Global
along with North American EPC player
Bechtel and is the largest in Morocco.
CWP Global also signed an agreement
with the government of Djibouti to de-
velop a 10-GW renewable energy and
green hydrogen hub, making the com-
pany the biggest renewable energy
developer in the Africa. Together, CWP
Global and Bechtel have announced
a capacity of about 88.5 GW of which
over 95% is still in concept phase and
a mere 4% has received approval for
development.
4.3 CWP Global – current leader in Africa’s
announced capacity
C
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ur
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en
nt
t t
to
op
p 1
10
0 r
re
en
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ab
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es
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in
n A
Af
fr
ri
ic
ca
a a
an
nd
d t
th
he
ei
ir
r r
re
es
sp
pe
ec
ct
ti
iv
ve
e a
an
nn
no
ou
un
nc
ce
ed
d c
ca
ap
pa
ac
ci
it
ty
y
Giga Watts (GW)
Developer Energy Source Country Development status
CWP Global
CWP Global; Bechtel
Globeleq
Sasol Ltd.
Masdar
Total Eren
Scatec
Fortescue Future Industries
ACME
Xlinks
16
Wind
Hydrogen
Electrolyzer
Solar
Storage
Botswana
Burkina Faso
Djibouti
Egypt
Ethiopia
Gabon
Kenya
Mauritania
Morocco
Mozambique
Namibia
South Africa
Togo
Tunisia
Zambia
Zimbabwe
Operating
Construction
Financial Close
Approved
Application
Concept
Source: Rystad Energy RenewableCube
Africa renewables developers
CWP and Bechtel leading the way in current announced capacity
Source: Rystad Energy RenewableCube
www.energychamber.org 25
Africa continent estimated to
stand fifth globally in upstream
emissions and Africa’s emissions
expected to be driven majorly
due to gas flaring
High greenfield spending
required to bring the large
upstream potential online but
the economic viability of the
level of investment close to a 2˚C
scenario
At the current estimates, Africa
needs fossil fuels as base case
scenario suggests a third of the
power generated in 2030 and
over a quarter of this in 2040 is
expected to come from
gas-to-power
5 AFRICA COP27 COMMITMENTS AND NATURAL GAS
5.1 Natural gas vs renewables potential in Africa
Africa holds large natural gas
and renewables potential, but
over 60% of the natural gas
potential and over 75% of the
current announced renewables
capacity is in a similar
“pre-FEED” state
Africa’s COP27 commitments
aim at phase down of coal
power, natural gas as transition
fuel and establishment of the
Africa Carbon Markets Initiative
(ACMI)
Universal electricity access
and power generation based
on renewables is also on the
agenda
Conservative estimates suggest Af-
rica’s current natural gas potential is
close to 16,000 Bcm. This includes an
11% “undiscovered” potential, but this
can be higher based on the amount
of unexplored and under-explored
acreage both onshore and offshore
Africa. An increase in this number
will take the overall reserve poten-
tial much higher. The 51% “discov-
ered” reserves are the “stranded” or
currently undeveloped reserves in
pre-FEED and in some cases pre-ap-
praisal or pre-technical evaluation
volumes that are being estimated as
future FIDs. This is a large chunk of
the overall potential and is in a phase
where even a possible scheme of
development is yet to be conceptual-
ised and eventually finalised.
The current announced renewables
capacity also is in a similar mix in
terms of the status of development.
Of the total capacity of 375 GW, only
7% is “operating” or is fully connected
to the grid and generating electricity.
A further 8% announced capacity is
approved for development, 2% ca-
pacity is currently under construction
and a marginal 1% has acquired the
necessary financing and will soon
hit the market to tender for contracts
to build the project. A 6% of the ca-
pacity is in the process of obtaining
the necessary permits and approvals
from the administration. While this
cumulative capacity of about 90 GW
has at the least crossed the barrier
of submitting the paperwork for ap-
provals, a large chunk – 76% of the
announced capacity is from the proj-
ects where paperwork for the neces-
sary regulatory approvals is yet to be
initiated. These projects are currently
speculative and the eventual approv-
als as well as the timelines are highly
speculative.
Even in a 1.5˚C scenario,
estimates suggest close to a fifth
of the power generated in 2030
and about 8% of this in 2040 will
be from gas-to-power projects
South Africa can benefit from
the COP27 commitments around
phase down of coal and usage of
natural gas potential for power
generation
26
African Energy Chamber Q1 2023 Outlook Report
African Energy Chamber
26
A
Af
fr
ri
ic
ca
a c
cu
ur
rr
re
en
nt
t r
re
en
ne
ew
wa
ab
bl
le
es
s i
in
ns
st
ta
al
ll
le
ed
d c
ca
ap
pa
ac
ci
it
ty
y
Giga Watts
A
Af
fr
ri
ic
ca
a n
na
at
tu
ur
ra
al
l g
ga
as
s p
po
ot
te
en
nt
ti
ia
al
l
Billion cubic meters
17
30%
8%
51%
11%
Producing Under development
Discovery Undiscovered
15,935 Bcm
7%
2%
1%
8%
6%
76%
Operating Construction Financial Close
Approved Application Concept
Source: Rystad Energy UCube; Rystad Energy RenewableCube
Africa natural gas vs installed renewables capacity
Majority of the gas potential undeveloped and majority of the renewables capacity in concept phase
375 GW
Source: Rystad Energy UCube; Rystad Energy RenewableCube
5.2 Africa COP27 Africa commitments and impact
The 27th Conference of the Parties to
the United Nations Framework Con-
vention on Climate Change (COP27)
reaffirmed COP26 conclusions of
“phase down of unabated coal pow-
er” and “phase out of inefficient fos-
sil fuel subsidies”, while natural gas
received a more prominent role in
energy transition and for tackling cli-
mate change, as “low-emission” en-
ergy won approval. The conference
also saw the African policy makers
pledge a climate initiative in the name
of Africa Carbon Markets Initiative
(ACMI) targeting 300 million carbon
credits per year- equivalent to 300
million tonnes of CO2 reduction by
2030. The initiative is aimed at pro-
viding a potential source of financing
to support energy transition in Africa.
Another key takeaway for Africa was
the launch of the Africa Just and Af-
fordable Energy Transition Initiative
(AJAETI).
The COP27 agenda included some
of the most important global ener-
gy relate climate themes – reducing
emissions to bring 1.5˚C within reach,
reduce usage of coal, help prepare
and deal with climate change, sup-
port developing countries with tech-
nical and financial aid, establishment
of a global carbon market and finally,
a new pooled fund arrangement for
countries most affected by climate
change. While these key themes
were discussed at length and the
new funding arrangement on loss
and damage was hailed as a “his-
toric moment”. The representatives
of African nations seemed to have a
more balanced voice between ener-
gy requirements and climate change
as opposed to the previous confer-
ence where the key narrative was
that Africa was on the receiving end
of the problem and it was the bigger
www.energychamber.org 27
emitters that had the responsibility to
cut down fossil fuel production. The
AJAETI and ACMI initiatives clearly
highlight this.
The AJAETI aims at three key targets,
all focusing on power – increasing
the share of electricity generation us-
ing renewable sources by 25% points
by 2027, universal access by 2030
and finally, establishing a power sec-
tor completely based on renewable
sources by 2063. The ACMI targets
a voluntary carbon market where car-
bon credits are released per tonne of
CO2 eliminated within a company’s
operations and these credits can be
bought by other operators who need
to offset unavoidable emissions. Ex-
isting and upcoming oil and gas pro-
ducers like Nigeria, Gabon and Ken-
ya were among the member nations
joining this initiative. With the push for
universal access, natural gas as path-
way for energy transition and oil pro-
ducers supporting the ACMI, Africa is
clearly looking to address both – the
energy issues within and the climate
issues globally.
Where does Africa stand globally
with respect to upstream emissions?
From 2023 through to the end of the
decade, Africa’s upstream emissions
are estimated to reach a cumulative
795 million tonnes of CO2 equivalent.
Globally, Africa is estimated to stand
fifth after North America, the Middle
East, Asia and Russia in terms of over-
all emissions over the period. Africa’s
upstream emissions are an estimated
9.5% of the global upstream emis-
sions over the period 2023 – 2030
and about a half of Africa’s upstream
emissions during the period are es-
timated to be result of gas flaring.
While the upstream extraction related
emissions from Africa are a mere 7%
of the global extraction emissions, the
flaring and venting emissions from Af-
rica over the period are estimated to
be almost a fifth of the global levels.
This suggests flaring results in major-
ity upstream emissions in Africa and
Africa is also one of the major flaring
regions globally.
2
20
01
15
5 –
– 2
20
03
30
0 A
Af
fr
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ic
ca
a u
up
ps
st
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ea
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mi
is
ss
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io
on
ns
s
Million tonnes CO2 equivalent
2
20
01
15
5 –
– 2
20
03
30
0 G
Gl
lo
ob
ba
al
l u
up
ps
st
tr
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ea
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em
mi
is
ss
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io
on
ns
s
Million tonnes CO2 equivalent
18
2
20
02
23
3 –
– 2
20
03
30
0 G
Gl
lo
ob
ba
al
l
u
up
ps
st
tr
re
ea
am
m e
em
mi
is
ss
si
io
on
ns
s
Million tonnes CO2 equivalent
0
400
800
1 200
2015 2020 2025 2030
Extraction Flaring and venting upstream
0
30
60
90
120
150
2015 2020 2025 2030
Extraction Flaring and venting upstream
Global and Africa upstream CO2 Emissions
Africa’s upstream CO2 emissions largely driven by natural gas flaring
Source: Rystad Energy UCube
72%
28%
48%
52%
7%
18%
0
1 000
2 000
3 000
4 000
5 000
6 000
7 000
Extraction Flaring and
venting
upstream
America N Middle East
Asia Russia
Africa America S
Europe Australia
Source: Rystad Energy UCube
28
African Energy Chamber Q1 2023 Outlook Report
African Energy Chamber
28
A
Af
fr
ri
ic
ca
a b
ba
as
se
e c
ca
as
se
e g
gr
re
ee
en
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sp
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g v
vs
s 2
2°
° s
sc
ce
en
na
ar
ri
io
o v
vs
s 1
1.
.6
6°
° s
sc
ce
en
na
ar
ri
io
o
Billion USD
19
0
10
20
30
40
50
60
70
80
90
100
2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040
Commercial Uncommercial Mean (2° scenario) Minus Sigma (1.6° scenario)
Source: Rystad Energy UCube; Rystad Energy EP Energy Transition Risk Dashboard
Africa greenfield spending – commerciality and climate scenarios
Current economically viable greenfield spending forecast close to 2° and 1.6 ° scenarios
Source: Rystad Energy UCube; Rystad EP Energy Transition Risk Dashboard
How is Africa’s oil and gas landscape
now?
As discussed previously, Africa’s esti-
mated oil and gas resource potential
and production forecast going forward
clearly suggests there is significant
undeveloped potential and output is
completely dependent on these unde-
veloped volumes as the producing res-
ervoirs are now in terminal decline. At
a conservative level, Africa is estimated
to hold about 74.365 billion barrels (Bb-
bls) of recoverable liquids and 82.875
billion barrels of oil equivalent (Bboe)
of recoverable natural gas resources.
Only half of this liquids potential and a
third of the natural gas potential is cur-
rently developed and is producing. 45%
of the liquids and a much larger 60%
of the natural gas potential is current-
ly “stranded” in pre-FEED state. While
natural gas production can see an in-
crease if these stranded volumes are
developed without any further delays
than currently expected, liquids flows
need accelerated development and
more discovered volumes to see an
increase as current volumes and time-
lines are expected to only stabilize the
decline and maintain a flat production
trend.
To maintain the above-mentioned pro-
duction levels at the estimated conser-
vative timeline, the scale of required
investments is quite steep. The main-
tenance of a stabilized oil output and
meeting the natural gas domestic and
international supply aspirations will
need an estimated greenfield spend-
ing of close to US$65 billion over the
period 2023 – 2025. This is estimated
to increase to a cumulative spending
of about US$225 billion for the remain-
www.energychamber.org 29
der of this decade, and over US$485
billion over the next decade 2031 –
2040. However, the current estimated
economic viability or “commerciality” of
this spending paints a different picture,
and this “commercial” spending is clos-
er to a 2˚C drop climate scenario. While
the 1.6˚C scenario greenfield spending
forecast is relatively in line with the 2˚C
scenario levels, 2031 – 2040 greenfield
spending can be expected to be dimin-
ished to about US$55 billion. This can
mean a potential deathblow to Africa’s
oil and gas aspirations, economical fu-
ture of a number of fossil-fuel exports
dependent economies in the continent
and, energy security and universal elec-
tricity access being aimed to achieve
using natural gas as a transition fuel.
How is Africa’s power mix expected
to pan out?
Africa is currently heavily dependent on
fossil fuels for power generation. About
75% of the power generated in Africa
over 2022 – 2023 is estimated to be
generated using oil, gas and coal. A cu-
mulative 60% of the power generated
in 2030 is expected to be from fossil
fuels with oil and gas generating about
40%. Even 2040 forecast suggests
close to 37% of the power generated
will be using oil, gas and coal with coal
still playing a 9% role and natural gas
accounting for over a quarter of the
power generation. As such, fossil fuels
are expected to play a long-term role in
Africa power generation. Power mix in
the 1.5˚C scenario, the power mix also.
25% of the power generated in 2030
and 5% in 2045 is estimated to be from
oil and gas. As such, oil and gas is ex-
pected to play a long-lasting role in Af-
rica’s power mix.
A
Af
fr
ri
ic
ca
a p
po
ow
we
er
r g
ge
en
ne
er
ra
at
ti
io
on
n a
at
t 1
1.
.5
5°
°C
C s
sp
pl
li
it
t b
by
y c
ca
at
te
eg
go
or
ry
y
Tera Watt hours (TWh)
A
Af
fr
ri
ic
ca
a b
ba
as
se
e c
ca
as
se
e p
po
ow
we
er
r g
ge
en
ne
er
ra
at
ti
io
on
n s
sp
pl
li
it
t b
by
y c
ca
at
te
eg
go
or
ry
y
Tera Watt hours (TWh)
20
41% 41% 40% 39% 38% 38% 38% 38% 36% 35% 34% 33% 33% 33% 33% 32% 32% 31% 30% 29% 27%
0
1000
2000
3000
2020 2025 2030 2035 2040
Nuclear Coal Gas Liquids Hydro Marine Bioenergy
Geothermal Onshore wind Offshore wind Solar PV Solar Thermal Ammonia mixed Hydrogen mixed
41% 41% 39% 37% 36% 34% 32% 29% 26% 23% 19% 17% 15% 14% 13% 12% 11% 11% 10% 9% 8%
0
1000
2000
3000
4000
2020 2025 2030 2035 2040
Nuclear Coal Gas Liquids Hydro Marine Bioenergy
Geothermal Onshore wind Offshore wind Solar PV Solar Thermal Ammonia mixed Hydrogen mixed
Source: Rystad Energy Power Transition Scenarios Dashboard
Africa power generation forecast in different scenarios
Natural gas to play a role in Africa’s power generation even at 1.5°C scenario
Source: Rystad Energy Power Transition Scenarios Dashboard
30
African Energy Chamber Q1 2023 Outlook Report
African Energy Chamber
30
Source: Rystad Energy Power Transition Scenarios Dashboard
5.3 South Africa can benefit by adhering
to the COP27 commitments
Africa’s COP27 commitments focus on
phasing down of usage of coal for pow-
er generation, universal uninterrupted
electricity access and natural gas as
transitional fuel towards switching to
renewables completely for power gen-
eration. These initiatives aim at cutting
down emissions from the usage of fossil
fuels especially coal, end energy pov-
erty and utilise the large potential of
African gas, for Africa, for firing the gas-
to-power plants. As a case example,
the current electricity situation in South
Africa can be reviewed to understand
how these commitments are very close
to reality and how natural gas potential
can be utilised to both minimise emis-
sions and avoid power outages.
Most power stations in the country are
owned and operated by Eskom. These
plants account for about 95% of all the
electricity produced in South Africa.
Coal fired power plants account for bulk
of this, with 2022 power mix suggest-
ing coal was the energy source behind
80% of the power generated. Relatively
more expensive Open Cycle Gas Tur-
bines (OCGTs) like Ankerlig, Gourikwa,
Dedisa and the likes, which use diesel
as the primary resource; and renewable
energy sources backed power stations
also contribute to power generation,
but the share is miniscule compared
to coal-fired plants. Historically, South
Africa could benefit from via access to
cheap electricity but this eventually led
to the issues plaguing the country now
– ageing fleet of coal-fired stations con-
sistently breaking down and/or needing
extensive maintenance, additional ex-
penditure on diesel to replenish outag-
es caused by these breakdowns, high
CO₂ emissions placing the southern Af-
rican nation in the world’s top 20 emit-
ting countries and most importantly, in-
troduction of load shedding to prevent
total blackouts.
A
Af
fr
ri
ic
ca
a p
po
ow
we
er
r g
ge
en
ne
er
ra
at
ti
io
on
n a
at
t 1
1.
.5
5°
°C
C s
sp
pl
li
it
t b
by
y c
ca
at
te
eg
go
or
ry
y
Tera Watt hours (TWh)
A
Af
fr
ri
ic
ca
a b
ba
as
se
e c
ca
as
se
e p
po
ow
we
er
r g
ge
en
ne
er
ra
at
ti
io
on
n s
sp
pl
li
it
t b
by
y c
ca
at
te
eg
go
or
ry
y
Tera Watt hours (TWh)
20
41% 41% 40% 39% 38% 38% 38% 38% 36% 35% 34% 33% 33% 33% 33% 32% 32% 31% 30% 29% 27%
0
1000
2000
3000
2020 2025 2030 2035 2040
Nuclear Coal Gas Liquids Hydro Marine Bioenergy
Geothermal Onshore wind Offshore wind Solar PV Solar Thermal Ammonia mixed Hydrogen mixed
41% 41% 39% 37% 36% 34% 32% 29% 26% 23% 19% 17% 15% 14% 13% 12% 11% 11% 10% 9% 8%
0
1000
2000
3000
4000
2020 2025 2030 2035 2040
Nuclear Coal Gas Liquids Hydro Marine Bioenergy
Geothermal Onshore wind Offshore wind Solar PV Solar Thermal Ammonia mixed Hydrogen mixed
Source: Rystad Energy Power Transition Scenarios Dashboard
Africa power generation forecast in different scenarios
Natural gas to play a role in Africa’s power generation even at 1.5°C scenario
www.energychamber.org 31
Source: Rystad Energy Power Transition Scenarios Dashboard
Source: Rystad Energy Power Transition Scenarios Dashboard
S
So
ou
ut
th
h A
Af
fr
ri
ic
ca
a b
ba
as
se
e c
ca
as
se
e p
po
ow
we
er
r g
ge
en
ne
er
ra
at
ti
io
on
n s
sp
pl
li
it
t b
by
y c
ca
at
te
eg
go
or
ry
y
Tera Watt hours (TWh)
21
0
100
200
300
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
Nuclear Coal Gas Liquids Hydro Marine
Bioenergy Geothermal Onshore wind Offshore wind Solar PV Solar thermal
Source: Rystad Energy Power Transition Scenarios Dashboard
South Africa historical power generation
Heavily dependent on coal, with 90% of 2020 – 2025 power generated using coal
While these issues have had a larger im-
pact on the wider economy of the coun-
try, the expenditure to maintain the ag-
ing power plants, to purchase diesel to
keep up the power supply and other fac-
tors driving huge losses to the national
entity Eskom have led to high electricity
tariffs on the regular domestic electricity
consumer. The period between 2000
– 2007 saw linear increase in average
Eskom electricity tariffs. However, since
the first load shedding was implement-
ed in 2007, average Eskom electricity
tariff has seen an exponential growth of
460% by 2020. 2020 average tariff was
about 110 c/kWh and the same year saw
Eskom win a major legal battle where
Eskom is allowed to increase average
electricity tariff to 128.24 c/kWh under
court order, to allow the state player to
manage its mountain of debt through
increased revenues via increased tariff.
South Africa, in the recent years, has
seen two large gas finds in its waters on
TotalEnergies operated Block 11B/12B.
The operator revealed in early Feb-
ruary 2019 that the deep water Bruld-
padda-1AX re-entry well, which was
drilled on Block 11B/12B in the Outeniqua
Basin, 175 kilometres off South Africa’s
southern coast, detected 57 meters of
net gas-condensate pay in Lower Cre-
taceous reservoirs. Another significant
gas-condensate discovery was made
with the Luiperd wildcat well in October
2020. The Luiperd-1X well was drilled
in approximately 1,800 meters of water
to a total depth of about 3,400 meters
encountered 73 meters of net gas-con-
densate pay, 16 meters more than the
Brulpadda well. Both Brulpadda and Lui-
perd rank high on the list of Africa’s larg-
est discoveries in their respective year
of discovery. Estimates put Brulpadda
at 275 million barrels of oil equivalent
(MMboe) and Luiperd at 340 MMboe,
with 70% gas each in both discoveries.
32
African Energy Chamber Q1 2023 Outlook Report
African Energy Chamber
32
Source: Rystad Energy Corp; Rystad Energy Research and Analysıs
22
Block 11B/12B gas to South African domestic markets
Potential to support current  future gas-to-power and GTL plant at capacity
Source: Africa Energy Corp; Rystad Energy Research and Analysis
The large scale finds of Brulpadda
and Luiperd, when developed, have
an equally impressive natural gas
and condensates production poten-
tial. Brulpadda alone has the poten-
tial to deliver a peak output of about
25,000 barrels per day (bpd) of con-
densates and 50,000 barrels of oil
equivalent per day (boepd) of natu-
ral gas. Luiperd phases 1 and 2 put
together have an estimated peak
production capacity of about 30,000
bpd of liquids and 80,000 boepd of
natural gas. Cumulatively, Brulpadda
– Luiperd project peak output is an
estimated to be 50,000 bpd of liquids
and 125,000 boepd of natural gas.
The individual fields are expected to
come online through late 2020s or
early 2030s. The average output from
the project cumulatively is estimated
to be around 35,000 bpd of liquids
and about 100,000 boepd of natu-
ral gas. For a nation that is currently
dependant on ageing and emission
intensive coal-fired power plants for
electricity generation and a continent
that has pledged to utilise natural gas
as a transition fuel towards 100% util-
ity generation from renewables, Brul-
padda and Luiperd can help South
Africa negotiate through the power
crisis that the country is going through
if the gas is directed towards domes-
tic markets and gas-to-power plants.
The gas from Brulpadda and Luiperd
can also enable conversion of power
plants like Gourikwa station with a ca-
pacity of 740 MW and Dedisa station
with a capacity of 335 MW to run on
baseload gas, and any further poten-
tial can cater to future gas-to-power
requirements. As such, catering Block
11B/12B potential to the domestic mar-
ket can result in not only meeting the
country’s energy needs but will also
a significant boost to the economy.
Phasing down usage of coal for power
generation, and thereby cutting down
on emissions; using natural gas as a
transition fuel for generation of elec-
tricity before being able to switch to
renewables completely; guaranteeing
universal electricity access and avoid-
ing power outages – this clearly is in
line with Africa’s COP27 commitments.
22
Block 11B/12B gas to South African domestic markets
Potential to support current  future gas-to-power and GTL plant at capacity
Source: Africa Energy Corp; Rystad Energy Research and Analysis
Africa is a
Powerhouse
Join us at the forefront of the African
energy industry.
We draw on the experience,
expertise and collective strength
of our members to actively lead
on shaping policies, sharing best
practice and using resources to
createvalue forAfricans.
Together,
we can shape
Africa’s energy
future.
Email us at
members@energychamber.org
Find out more
www.energychamber.org/members
www.energychamber.org
Suite 43 Katherine  West
114 West Street
Sandton, Johannesburg, South Africa

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African Energy Chamber: The State of African Energy Q1 2023 Outlook Report

  • 1. The State of African Energy Q1 2023 Outlook Report
  • 2. Ministry of Petroleum Resources of the Federal Republic of Nigeria Ministry of Petroleum and Energy of Uganda Ministry of Petroleum and Energy of Senegal Ministry of Energy of Sierra Leone Ministry of Mines and Hydrocarbons of Equatorial Guinea
  • 3. The State of African Energy Q1 2023 Outlook Report
  • 4. 2 African Energy Chamber Q1 2023 Outlook Report African Energy Chamber 2 The State of African Energy Q1 2023 Outlook Report
  • 5. www.energychamber.org 3 Index 1 AFRICA OIL SHORT-TERM SUPPLY OUTLOOK 6 1.1 Global and African 2023 liquids supply 6 1.2 Top liquids producers of Africa in 2023 7 2 AFRICA NATURAL GAS AND LNG OUTLOOK 10 2.1 Africa natural gas supply, LNG infrastructure and LNG supply 10 2.2 Africa gas demand and LNG exports vs additional potential 14 3 PROJECT DELAYS IN AFRICA AND IMPACT 15 3.1 Future start-ups coming online after very long discovery to start-up periods 15 3.2 Currently delayed future start-ups – key to Africa’s production increase 17 3.3 Plenty of potential but equally large investments needed to develop the volumes 20 4 AFRICA RENEWABLES OUTLOOK 21 4.1 Global renewables capacity driven by Asia, Europe and the States 21 4.2 Majority announced renewables capacity in concept stage and in North Africa 22 4.3 CWP Global – current leader in Africa’s announced capacity 24 5 AFRICA COP27 COMMITMENTS AND NATURAL GAS 25 5.1 Natural gas vs renewables potential in Africa 25 5.2 Africa COP27 Africa commitments and impact 26 5.3 South Africa can benefit by adhering to the COP27 commitments 30 African Energy Chamber Q1 2023 Outlook Report
  • 6. 4 African Energy Chamber Q1 2023 Outlook Report African Energy Chamber 4 • 2023 global liquids (crude + condensates) month-on-month outlook expected to stay flat and stable with annual average at 83.4 million barrels per day (MMbbls/d) • Africa liquids supply expected to add up to 8% of the global volumes over the year at an annual average of almost 7 MMbbls/d • Top five producers – Nigeria, Libya, Algeria, Angola and Egypt contribute to over 80% of Africa’s 2023 liquids output • While majority of the production from Nigeria and Angola is from offshore projects, Algeria, Libya and Egypt’s production comes from their respective onshore fields • Production from Nigeria and Angola is in decline, whereas Algeria and Egypt production trend has been relatively flat since 2015. Libya’s now subsiding civil war impact is expected to result in increased production in 2023 • Regulatory cuts in the form of OPEC sanctions are expected to result in outages in Algeria’s crude oil output throughout the year • Africa natural gas output is majorly driven by the North and West African projects • 2023 annual output is expected to reach about 268 Billion cubic meters (Bcm) and over 85% of this is estimated to come from the North and West African projects • The production from the existing producing fields is in terminal decline and any trend reversal is expected only from the currently pre-FID (Final Investment Decision) fields • Any delays in these projects, thus, will have an adverse impact on the continent’s natural gas aspirations • Africa’s total LNG export infrastructure capacity expected to increase from the existing 80 MMtpa to about 110 MMtpa by 2030 and further to over 175 MMtpa by the end of the next decade • Nigeria, Algeria, Mozambique, Senegal – Mauritania, Tanzania and Egypt are expected to drive this LNG export capacity in the long term • Africa’s LNG exports are expected to increase from 66 Bcm in 2023 (a 5% year-on-year increase from 2022) to 77 Bcm by 2030 and further to 100 Bcm by 2035 • Africa’s own natural gas production, international natural gas imports and the annual domestic demand levels put the continent in a position to pump natural gas volumes of 105 Bcm in 2023, 170 Bcm in 2030, 275 Bcm in 2037 and a slightly lower 220 Bcm in 2040 to both domestic and international markets • Africa’s upcoming upstream projects have already seen large delays from the time the hydrocarbon discoveries were made to the estimated future FID • Many crude oil discoveries that can stabilize the production and offset the terminal decline in output for a few years; and also, giant natural gas finds that can help Africa meet domestic demand, universal electricity access and LNG export aspirations have seen long delays due to various above-the-surface issues Key Highlights
  • 7. www.energychamber.org 5 • Over a half of the hydrocarbon output from Africa over the period 2025 – 2040 and about 60% of the remaining recoverable oil and gas reserves in Africa is estimated to come from these upcoming/delayed start-ups • Governments are now realizing the impact of these delays and putting in the efforts to bring these projects online and also bring in more exploration investments, but more is required • At the current conservatively estimated development timeline and scale, a mammoth US$795 billion of greenfield expenditure is required over the period 2023 – 2040 to bring these undeveloped discoveries online • 2023 global renewables capacity (solar + wind + hydrogen electrolyzer) is 1,500 GW • Asia, Europe and North America are expected to drive over 90% of this capacity, with Africa contributing a negligible 1% of the annual capacity • As hydrogen capacity in Africa picks up, 2035 Africa output is expected to increase to 7% of the global capacity • Africa’s current announced renewables capacity stands at 134 GW of wind capacity, 120 GW of solar capacity and 112 GW of hydrogen capacity • Egypt, Morocco, Mauritania and South Africa are the major countries with current announced capacity • Over 75% of the current announced capacity is in concept stage • Africa’s renewables capacity output is expected to increase from about 27.4 GW in 2023 to over 280 GW in 2035 • CWP Global (in partnership with Bechtel in a few projects) is the main operator with close to 25% of the current announced capacity in Africa • Africa holds large natural gas and renewables potential, but over 60% of the natural gas potential and over 75% of the current announced renewables capacity is in a similar “pre-FEED” state • Africa’s COP27 commitments aim at phase down of coal power, natural gas as transition fuel and establishment of the Africa Carbon Markets Initiative (ACMI) • Universal electricity access and power generation based on renewables is also on the agenda • Africa continent estimated to stand fifth globally in upstream emissions and Africa’s emissions expected to be driven majorly due to gas flaring • High greenfield spending required to bring the large upstream potential online but the economic viability of the level of investment close to a 2˚C scenario • At the current estimates, Africa needs fossil fuels as base case scenario suggests a third of the power generated in 2030 and over a quarter of this in 2040 is expected to come from gas-to-power • Even in a 1.5˚C scenario, estimates suggest close to a fifth of the power generated in 2030 and about 8% of this in 2040 will be from gas-to-power projects • South Africa is a classic example of an African nation that can benefit from the COP27 commitments around phase down of coal and usage of natural gas potential for power generation
  • 8. 6 African Energy Chamber Q1 2023 Outlook Report African Energy Chamber 6 1.1 Global and African 2023 liquids supply 2023 global liquids (crude + condensates) month-on-month outlook expected to stay flat and stable with annual average at 83.4 million barrels per day (MMbbls/d) Africa liquids supply expected to add up to 8% of the global volumes over the year at an annual average of almost 7 MMbbls/d Top five producers – Nigeria, Libya, Algeria, Angola and Egypt contribute to over 80% of Africa’s 2023 liquids output While majority of the production from Nigeria and Angola is from offshore projects, Algeria, Libya and Egypt’s production comes from their respective onshore fields Production from Nigeria and Angola is in decline, whereas Algeria and Egypt production trend has been relatively flat since 2015. Libya’s now subsiding civil war impact is expected to result in increased production in 2023 Regulatory cuts in the form of OPEC sanctions are expected to result in outages in Algeria’s crude oil output throughout the year Africa 2023 liquids supply is esti- mated at almost 7 MMbbls/d. This reflects a marginal year-on-year growth from 6.875 MMbbls/d and 6.7 MMbbls/d in 2021 and 2022 respectively, and close to 430,000 barrels per day (bpd) from 2020 lows of about 6.55 MMbbls/d. While this growth from the pandemic hit lows is a positive sign, it should be noted that 2023 expected output is lower by 1 MMbbls/d than the highs of 2015 where output was almost 8 MMbbls/d. This steep drop from 2015 is majorly due to output drop from declining fields in Nigeria, Angola, Equatorial Guinea, Egypt and South Sudan. Cumulative drop from these five countries is around 1.735 MMbbls/d and the overall pro- duction drop, from all the countries where output has declined, is 1.89 MMbbls/d. This drop is partially offset by production increase from mainly Libya, Congo and Ghana – accounting to a cumulative output increase of 880,000 bpd. Nigeria, Libya, Algeria, Angola and Egypt are expected to be the top five liquids producers for the year with a combined output of about 5.76 MMbbls/d, more than 80% of the continent’s overall annual out- put. Nigeria – Nigerian crude produc- tion looks on course to rebound to over 1.3 MMbbls/d in 2023, as gov- ernment efforts to tackle persistent oil theft and pipeline vandalism bear fruit. The major West African producer’s crude oil output was 1.18 MMbbls/d last year, far below the 1.5 MMbbls/d seen in 2020, as theft and vandalism led to force majeures on key blends. Nigerian crude out- put averaged 1.3 MMbbls/d in 2021 despite numerous impediments, including accidental pipeline dam- age, OPEC+ quotas and other un- planned outages, even topping 1.4 MMbbls/d at the beginning of that year. The outbreak of war between Russia and Ukraine in February 2022 presented an opportunity for Nigeria – as with other major pro- ducer nations – to reap the benefits of high oil prices, but the country continued to be impaired by oil theft and pipeline damage. In an effort to curb theft and vandalism, the fed- eral government announced a new approach in collaboration with host communities to protect critical pipe- line systems, with a pipeline surveil- lance contract awarded to protect oil assets. The Nigerian Navy was also employed to track vessels ille- gally carrying crude oil, while Nige- rian National Petroleum Corporation (NNPC) also deployed various other methods to monitor and report oil theft in the country. All these ini- tiatives reaped benefits as Nigeria surpassed 1 MMbbls/d of crude pro- duction in October 2022, closing the year close to 1.2 MMbbls/d. Nigeria’s National Upstream Petro- 1 AFRICA OIL SHORT-TERM SUPPLY OUTLOOK
  • 9. www.energychamber.org 7 leum Regulatory Commission (NUPRC), the country’s upstream regulator, in December last year launched the Mini Bid Round 2022 in the hope of boost- ing investments and exploration activ- ity. The Petroleum Industry Act (PIA) of 2021, with its improved legal and regulatory frameworks, also seeks to encourage new investors and invest- ments into the next phase of explora- tion. Seven offshore blocks covering a total area of approximately 6,700 square kilometers and situated in wa- ter depths of between 1,150 meters and 3,100 meters are on offer as part of Nigeria’s fresh attempt at developing offshore assets. The blocks are closer to the producing fields of Aje, Erha and Erha North and the undeveloped fields of Ogo and Bosi. With President-elect Bola Tinubu of the ruling All Progres- sives Congress (APC) party emerging victorious, the government’s strategy to restore output levels can be ex- G Gl lo ob ba al l o oi il l a an nd d c co on nd de en ns sa at te es s p pr ro od du uc ct ti io on n s sp pl li it t b by y c co on nt ti in ne en nt t Million barrels per day 2 33% 33% 33% 33% 33% 33% 33% 33% 33% 33% 33% 33% 23% 23% 23% 23% 23% 23% 23% 23% 23% 23% 24% 24% 13% 13% 12% 12% 12% 12% 12% 12% 12% 13% 13% 13% 11% 11% 11% 11% 11% 11% 11% 11% 11% 11% 11% 11% 8% 8% 8% 8% 8% 8% 8% 8% 8% 8% 8% 8% 8% 8% 8% 8% 8% 8% 8% 8% 8% 8% 8% 8% 4% 4% 4% 4% 4% 4% 4% 4% 4% 4% 4% 4% 82,47 83,67 83 83,05 82,74 83,29 83,91 83,52 83,78 83,69 84,03 83,86 0,00 25,00 50,00 75,00 100,00 Jan.23 Feb.23 Mar.23 Apr.23 May.23 Jun.23 Jul.23 Aug.23 Sep.23 Oct.23 Nov.23 Dec.23 Middle East America N Russia Asia Africa America S Europe Australia Source: Rystad Energy OilMarketCube Month-on-month oil and condensates global output Africa’s contribution to 2023 global output at an average 8% Source: Rystad Energy OilMarketCube 1.2 Top liquids producers of Africa in 2023
  • 10. 8 African Energy Chamber Q1 2023 Outlook Report African Energy Chamber 8 pected to remain in place, leading to 1.3 million bpd this year if no sudden outages manifest. There is also poten- tial for upside if some blends that are still underproducing can be restored to pre-Covid-19 output levels. Libya – Libya’s civil war had an ad- verse impact on the country’s hydro- carbon output historically. 2020 saw the lowest of lows with crude oil pro- duction diminishing to about 370,000 bpd. However, 2021 saw a reversal with output surpassing the 1 MMb- bls/d mark and reaching annual aver- age of 1.12 MMbbls/d. 2022, yet again, proved something of a rollercoaster ride for the country and its staple oil sector, following a relatively stable 2021. With presidential and parliamen- tary elections originally scheduled for December 2021 but pushed to June 2022 and then delayed indefinitely, and given the continued existence of two parallel governments, the politi- cal atmosphere in the country soured in 2022, resulting in production shut- ins, violence and human casualties. The situation in Libya has remained strained due to the lack of any true de- cision-making body, with this instability linked to sudden eruptions of violence that have led to increased volatility, straining the nation’s economy. While a common perception at that point was that the country would continue to struggle with production and the pro- tests would turn more violent, resulting in more lost volumes, in July 2022, Libya’s output surprisingly rebound- ed, protests ended, and the force ma- jeure was lifted. The country staged a remarkable recovery, and within the space of three weeks, Libya was able to surpass its rated capacity of 1.2 MMbbls/d, since when production has remained relatively stable, with no ma- jor disruptions. As a result, 2023 crude oil output from Libya is expected at an average 1.2 MMbbls/d. Algeria – Algeria, like the rest of the world, was hit by the pandemic and 2020 – 2021 crude oil output was at a sub-1 MMbbls/d mark at 930,000 bpd and 940,000 bpd, respectively. Better performance from the existing fields and newer start-ups combined with re- vision in OPEC regulations resulted in 2022 crude oil output reaching close to 1.07 MMbbls/d. However, OPEC+ cuts announced in October 2022, set to be effective from November 2022 A Af fr ri ic ca a o oi il l a an nd d c co on nd de en ns sa at te es s p pr ro od du uc ct ti io on n s sp pl li it t b by y c co ou un nt tr ry y Million barrels per day 3 Month-on-month oil and condensates output from Africa Nigeria, Libya, Algeria, Angola and Egypt add up to over 80% of the output Source: Rystad Energy OilMarketCube 21% 22% 22% 21% 21% 21% 21% 21% 21% 21% 22% 22% 19% 19% 19% 18% 18% 18% 18% 18% 18% 18% 18% 18% 18% 18% 18% 18% 18% 18% 18% 18% 18% 18% 18% 18% 16% 16% 15% 17% 17% 17% 17% 17% 17% 17% 17% 16% 8% 8% 8% 8% 8% 8% 8% 8% 8% 8% 8% 8% 6.84 6.92 6.87 7.01 7.03 7.02 7.02 7.02 7.03 7.04 7.02 7.00 0,00 2,50 5,00 7,50 10,00 Jan.23 Feb.23 Mar.23 Apr.23 May.23 Jun.23 Jul.23 Aug.23 Sep.23 Oct.23 Nov.23 Dec.23 Nigeria Libya Algeria Angola Egypt Congo Gabon South Sudan Chad Ghana Equatorial Guinea Sudan Cameroon Tunisia Others Source: Rystad Energy OilMarketCube
  • 11. www.energychamber.org 9 2 20 02 23 3 e ex xp pe ec ct te ed d p pr ro od du uc ct ti io on n o ou ut ta ag ge es s s sp pl li it t b by y o ou ut ta ag ge e c ca at te eg go or ry y Thousand barrels per day 2 20 02 23 3 e ex xp pe ec ct te ed d p pr ro od du uc ct ti io on n o ou ut ta ag ge es s f fr ro om m c co ou un nt tr ri ie es s Thousand barrels per day 4 2 20 02 23 3 p pr ro od du uc ct ti io on n o ou ut ta ag ge es s i in n c cr ru ud de e g gr ra ad de es s Thousand barrels per day 0 100 200 300 Jan.23 Feb.23 Mar.23 Apr.23 May.23 Jun.23 Jul.23 Aug.23 Sep.23 Oct.23 Nov.23 Dec.23 Algeria Angola Chad South Sudan Equatorial Guinea 0 100 200 300 Jan.23 Feb.23 Mar.23 Apr.23 May.23 Jun.23 Jul.23 Aug.23 Sep.23 Oct.23 Nov.23 Dec.23 Maintenance Other Planned Civil Unrest or Attacks RegulatoryOrder Other Unplanned Saharan Blend (Algeria) Dalia (Angola) Doba Blend (Chad) Nile Blend (South Sudan) Mondo (Angola) Alba (Equatorial Guinea) Month-on-month oil and condensates production outages Expected outages in Algeria throughout 2023 due to OPEC cuts Source: Rystad Energy OilMarketCube Source: Rystad Energy OilMarketCube to December 2023 have resulted in monthly production outages through- out 2023. This, in turn, hindered any possibility of further output growth in 2023 and expected crude oil produc- tion from the country is expected at 1.06 MMbbls/d, similar to 2022 levels. Angola – With depleting reservoirs and declining production from the Floating Production Storage and Off- loading (FPSO) vessels deployed on the deepwater fields, Angola’s liquids out has been in a freefall since 2015. However, newer start-ups in the Kaom- bo North, Eastern & Western hubs on Block 15/06 and Pazflor develop- ments, the Greater Plutonio Phase 2, CLOV Phase 2 and Dalia Phase 3 have resulted in stable output since 2021. The country’s 2021 and 2022 liquids output was 1.13 MMbbls/d and 1.15 MMbbls/d respectively, and expected 2023 production is 1.15 MMbbls/d. Egypt – Egypt’s liquids output is large- ly supported by its joint venture (JV) operations. The national oil company (NOC), Egyptian General Petroleum Corporation (EGPC) operates oil pro- duction in the form different JVs like Khalda Petroleum Company, Belayim Petroleum (PETROBEL), Gulf of Suez Petroleum Company (GUPCO), AGI- BA Petroleum Company, Badr El-Din Petroleum Company (BAPETCO) and so on, with International Oil Compa- nies (IOCs) like Apache, Eni, BP, Shell (whose share in BAPETCO was later acquired by Cheiron Group and Cap- ricorn Energy). Compared to the other top African producers, Egypt’s oil out- put has been relatively stable for the years 2021 – 2022 and 2023 output is expected to be at about 460,000 bpd with condensates reaching an output of about 125,000 bpd. About three-quarters of the 2023 oil produc- tion and a third of the year’s conden- sates production is expected to come from the onshore projects. Majority of the remainder of the production comes from sub-Saha- ran African countries like Congo, Gabon, Chad, Ghana and Equatorial Guinea. Apart from non-sub-Saharan African Tunisia, whose output for the year 2023 is estimated close to 38,500 bpd, the rest of the 17% of Africa’s 2023 oil and condensates production is expected to come from sub-Saharan Africa.
  • 12. 10 African Energy Chamber Q1 2023 Outlook Report African Energy Chamber 10 2.1 Africa natural gas supply, LNG infrastructure and LNG supply Africa natural gas output is majorly driven by the North and West African projects 2023 annual output is expected to reach about 268 Billion cubic meters (Bcm) and over 85% of this is estimated to come from the North and West African projects The production from the existing producing fields is in terminal decline and any trend reversal is expected only from the currently pre-FID (Final Investment Decision) fields Africa natural gas supply is majorly driven by the North and West African gas projects. This high ratio of produc- tion compared to the other regions is expected to remain throughout this decade and the next, considering the conservative development timelines and supply potentials of the mega projects of the Eastern African nations of Mozambique and Tanzania and the currently recovered relatively low potential of South Africa. 2023 Africa natural gas output is expected at close to 268 Bcm and cumulative share of North and West African projects is es- timated at 95% of the overall volume. The share of these regions in 2025, 2030 and 2040 is estimated to be 95%, 90% and 80% respectively. North Africa takes the larger share of the two regions, but West is expected to catch up by the end of the next decade in the current conservative estimates of timelines and production trends. Major producers in North Africa include Al- geria, Egypt & Libya, and these add up to almost all of the natural gas output from the region. The share of individ- ual countries from West Africa is a dif- ferent story – currently Nigeria, Angola and Equatorial Guinea add up to 85% of the overall output from the region. While the share of these three coun- tries is expected to remain the same till 2025, it gradually decreases to 75% by 2030, 70% by 2035 and to about 2 AFRICA NATURAL GAS AND LNG OUTLOOK Any delays in these projects, thus, will have an adverse impact on the continent’s natural gas aspirations Africa’s total LNG export infrastructure capacity expected to increase from the existing 80 MMtpa to about 110 MMtpa by 2030 and further to over 175 MMtpa by the end of the next decade Nigeria, Algeria, Mozambique, Senegal – Mauritania, Tanzania and Egypt are expected to drive this LNG export capacity in the long term Africa’s LNG exports are expected to increase from 66 Bcm in 2023 (a 5% year-on-year increase from 2022) to 77 Bcm by 2030 and further to 100 Bcm by 2035 Africa’s own natural gas production, international natural gas imports and the annual domestic demand levels put the continent in a position to pump natural gas volumes of 105 Bcm in 2023, 170 Bcm in 2030, 275 Bcm in 2037 and a slightly lower 220 Bcm in 2040 to both domestic and international markets
  • 13. www.energychamber.org 11 A Af fr ri ic ca a n na at tu ur ra al l g ga as s o ou ut tp pu ut t s sp pl li it t b by y l li if fe e c cy yc cl le e Billion cubic meters A Af fr ri ic ca a n na at tu ur ra al l g ga as s o ou ut tp pu ut t s sp pl li it t b by y r re eg gi io on n Billion cubic meters 5 0 100 200 300 400 500 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 North Africa East Africa South Africa West Africa 0 100 200 300 400 500 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 Under development Discovery Africa natural gas output Africa gas output growth over the 2030s to be driven by East & West undeveloped finds Source: Rystad Energy UCube Source: Rystad Energy UCube 60% by 2040. While these countries’ share is expected to decrease, natural gas output from Senegal – Maurita- nia is expected to increase as the BP – Kosmos projects of Greater Tortue Ahmeyim (GTA), Bir Allah, Yakaar – Teranga projects come online and ramp up. The share of these countries’ cumulative natural gas output is 5%, 10%, 15% and 30% of the overall West Africa output from the years 2025, 2030, 2035 and 2040, respectively. Natural gas production from Africa is expected to stay relatively flat till about 2027 at an average level of about 270 Bcm before the currently undeveloped volumes come online. Output from the currently producing fields is in terminal decline. Produc- tion from these fields is estimated to decline at an annual rate of about 5% from 2025 through to 2040. While the production from the currently post- FID under development fields is es- timated to see an annual increase of about 15% from 2025 to 2030, output from these fields is also expected to decline going forward. The produc- tion growth expected to happen in the next decade is only from the currently pre-FID potential. This growth over the next decade is expected from projects in both currently nascent upstream economies like Mozambique, Tanza- nia, Mauritania, Senegal, South Africa and Ethiopia, as well as matured oil and gas economies like Nigeria, Lib- ya and Algeria. At the current conser- vative forecast, the production from these projects is expected to double year-on-year from 2025 – 2029 and then see a gradual increase till about late 2030s. A little over 10% of the total natural gas production from Af-
  • 14. 12 African Energy Chamber Q1 2023 Outlook Report African Energy Chamber 12 rica is from these currently pre-FID/ pre-FEED (Front End Engineering and Design) volumes and it increases to over a half of the total output. As such, these volumes are crucial to Africa’s natural gas supplies and the continent’s natural gas aspirations to be a major liquified natural gas (LNG) exporter to international markets. Africa LNG export infrastructure also is shaping in a similar way to the natu- ral gas forecast. Between the bigger producers like Algeria, Nigeria and Egypt, Algeria and Egypt are expect- ed to maintain their existing LNG infra- structure capacity of about 29 million tonnes per annum (MMtpa) and 12.7 MMtpa, respectively. Nigeria’s plans involve increasing its LNG infrastruc- ture capacity from the existing 22 MMtpa to 30 MMtpa via the Nigeria LNG (NLNG) Train 7 development and further marginally to just over 31 MMt- pa via UTM Offshore’s FLNG project. In the period through to 2040, Mozam- bique is expected to see the highest increase in LNG export capacity, in- creasing from current capacity of 3.4 MMtpa to close to 16.3 MMtpa and further to 31.5 MMtpa and finally to about 43.5 MMtpa by the end of the next decade. This is conditional to sit- uation in the country where operator TotalEnergies was recently reported to be resuming work soon after a force majeure was declared on the project in April 2021 after Islamist insurgents attacked Palma town close to the proj- ect construction site at Afungi. Exx- onMobil partners in the Coral project were also recently reported that they would take a call soon on whether a second floating liquefied natural gas vessel (FLNG) vessel would be de- ployed. This decision is also subject to the US major’s decision on it onshore US$24 billion Rovuma LNG scheme as disturbances in the Cabo Delgado province due to Islamist insurgency since 2017, are now reported to be subsiding. Senegal – Mauritania on the Western side of Africa and Tanzania on the Eastern side are countries expected A Af fr ri ic ca a L LN NG G e ex xp po or rt t i in nf fr ra as st tr ru uc ct tu ur re e Million tonnes per annum (MMtpa) 6 0 50 100 150 200 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 Nigeria Algeria Mozambique Egypt Equatorial Guinea Angola Mauritania Tanzania Libya Senegal Congo Djibouti Cameroon Source: Rystad Energy GasMarketCube Africa LNG export infrastructure Mozambique – Tanzania in the east and Mauritania – Senegal in the west to drive LNG infrastructure growth Source: Rystad Energy GasMarketCube
  • 15. www.energychamber.org 13 to ramp up their FLNG export capac- ities. While BP – Kosmos owned LNG projects in the waters off Senegal and Mauritania are expected to lead to an increase in the cumulative capacity of both the countries from the 2.5 MMt- pa capacity, that is expected to kick off next year, to an overall 22.5 MMt- pa capacity by the second half of the next decade. In Tanzania, the Energy Ministry recently announced that part- ners on the deepwater blocks 1, 2 and 4 – Shell, Equinor, ExxonMobil, Pa- vilion Energy and Medco Energi and the government have completed dis- cussions on the contractual terms of a critical host government agreement (HGA), taking another step towards the US$30 billion LNG project with a 10 MMtpa capacity. Other projects like Marine XII FLNG in Congo, Angola’s Soyo LNG taking feedgas from the Quiluma – Maboqueiro and Sanha lean gas complexes, and Equatorial Guinea’s Punta Europa LNG plant are a few other key projects maintaining or increasing Africa’s LNG export in- frastructure capacity. Africa has been a historical LNG and gas-via-pipeline exporter, especially to Europe. Close to 65% of the overall LNG and pipeline exports from Africa in the period 2005 – 2022 have been to Europe. Historically a fifth of the overall natural gas produced in Africa has been catering to international markets via LNG exports. This volume share has seen a slight increase in the past 3 – 4 years where the overall LNG exports share has increased to a quarter of the total production. Taking into consideration the existing LNG export agreements, the export potential is expected to stay at a relatively flat share of 25% of the total natural gas produced. However, with the increase in natural gas production, the overall LNG exports are also expected to increase going forward. Overall nat- ural gas output is expected to increase from 268 Bcm in 2023 to 272 Bcm in 2025. The output is further expected to increase to 340 Bcm in 2030 and further to about 420 Bcm. In lie with this, 2023, 2030 and 2035 expected LNG flows from Africa are 66 Bcm, 77 Bcm and 100 Bcm, respectively. A Af fr ri ic ca a n na at tu ur ra al l g ga as s a an nd d L LN NG G o ou ut tp pu ut t Billion cubic meters 76% 78% 76% 75% 78% 79% 76% 76% 77% 76% 77% 78% 77% 76% 76% 76% 78% 78% 77% 76% 75% 24% 22% 24% 25% 22% 21% 24% 24% 23% 24% 23% 22% 23% 24% 24% 24% 22% 22% 23% 24% 25% 231 266 262 268 272 272 272 277 291 317 340 357 370 390 404 419 444 455 448 424 401 0 100 200 300 400 500 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 Gas LNG 7 Africa gas and LNG output Africa average LNG output a quarter of the total over this and the next decade Source: Rystad Energy UCube Source: Rystad Energy UCube
  • 16. 14 African Energy Chamber Q1 2023 Outlook Report African Energy Chamber 14 Africa natural gas production is on the rise, provided there are no project de- lays or revisions in current development plans, but so is the demand forecast. 2022 – 2023 production curve is rela- tively flat, and demand is also an annual 172 Bcm, a 65% share of the overall out- put. The share of demand is expected to remain flat at the 65% mark as demand grows in line with the output till about 2028. Post this, the production is ex- pected to grow faster than the demand, reducing the overall share of demand to 60% in 2029 and further lower to 55% in 2030. Annual demand is expected to stay at around 55% of the total produc- tion throughout the next decade. Of the total demand, power generation’s share is expected to be around 50% through the end of this decade and 45% on av- erage through the next decade 2031 – 2040. Power generation, industrial us- age and residential consumption form the key sectors of natural gas demand adding up to an average of 75% of the total demand through the period 2023 – 2030 and a slightly lower 70% of the total demand through the years 2031 – 2040. Taking into consideration Africa’s natural gas imports, like Egypt importing gas from Israel, Africa’s overall natural gas supply is expected to increase from 275 Bcm in 2023 to 285 Bcm in 2025, further to 360 Bcm in 2030 and 510 Bcm in 2037 before declining to 460 Bcm by 2040. Taking out the forecasted domestic de- mand, these supply levels put Africa in a position to pump natural gas volumes of 105 Bcm in 2023, 170 Bcm in 2030, 275 Bcm in 2037 and a slightly lower 220 Bcm in 2040 that can be catered to both, domestic markets for an in- creased focus on gas-to-power output that can be in turn used to eliminate energy poverty and also international markets in the form of LNG cargos and pipeline exports that can generate rev- enues for the hydrocarbon dependant African economies. 2.2 Africa gas demand and LNG exports vs additional potential      ­ €‚ƒ „   Source: Rystad Energy UCube; Rystad Energy GasMarketCube
  • 17. www.energychamber.org 15 3 PROJECT DELAYS IN AFRICA AND IMPACT 3.1 Future start-ups coming online after very long discovery to start-up periods Africa’s upcoming upstream projects have already seen large delays from the time the hydrocarbon discoveries were made to the estimated future FID Many crude oil discoveries that can stabilize the production and offset the terminal decline in output for a few years; and also, giant natural gas finds that can help Africa meet domestic demand, universal electricity access and LNG export aspirations have seen long delays due to various above-the- surface issues Over a half of the hydrocarbon output from Africa over the period 2025 – 2040 and about 60% of the remaining recoverable oil and gas reserves in Africa is estimated to come from these upcoming/delayed start-ups Governments are now realizing the impact of these delays and putting in the efforts to bring these projects online and also bring in more exploration investments, but more is required At the current conservatively estimated development timeline and scale, a mammoth US$795 billion of greenfield expenditure is required over the period 2023 – 2040 to bring these undeveloped discoveries online A condensed study on some the key pro- ducing projects and upcoming start-ups across Africa, suggests that while current producing fields saw a relatively lower discovery to start-up period suggesting a lower delay in terms bring the field on stream, the discovery to start-up period for the upcoming start-ups is sometimes dou- ble or even longer compared to the older producing fields. Many old gas discoveries in East Africa, which are expected to drive the natural gas and LNG growth from Af- rica, have already seen long delays from the time they were “found” to awaiting a final investment decision (FID) and kick off development. Natural gas project delays across East Africa Mozambique – Mozambique saw a wave of large gas discoveries in the early to mid-2010s and the total gas discovered was an estimated (conservative) 17 Bboe. Of these volumes, only about 700 Million barrels of oil equivalent (MMboe) Coral Sul field on Area 4 is currently pumping LNG volumes into international market via the 3.4 MMtpa Coral Sul floating liquefied nat- ural gas (FLNG) vessel which saw the FID in mid-2017 and shipped off the first cargo in November 2022. Further development on Area 4 includes half a billion barrels of oil equivalent Coral North FLNG devel- opment expected to kick off in 2024 and come online in 2027; Area 4 LNG (Trains 1 2) with a capacity of 15.2 MMtpa with expected FID in late 2020s and start-up in early 2030s and finally the 12 MMtpa Area 4 LNG (Trains 3 4) expected to be FID’ed in mid-2030s and pump LNG exports by late-2030s. Area 1 also saw some progress in line with Area 4’s Coral Sul development but hit brakes due to Islamic insurgency in the onshore development area. The Area 1 LNG (Trains 1 2) with a capacity of 12.88 MMtpa using feedgas from Atum and Golf- inho fields with a cumulative gas volume of almost 3.2 Bboe saw the FID happen in 2019, but the start-up is now delayed to late-2020s due to the operator TotalEn- ergies imposing a force majeure on the $20 billion project as the security situation in the northeast region of Cabo Delgado worsened. Further development on Area 1 involves development of trains 3 4 with an expected FID in early to mid-2030s and start-up by late 2030s. Area 1 reportedly holds approximately 75 trillion cubic feet (Tcf) of recoverable gas. Development of further potential in the area can spill over to a much later timeline. Mozambique also has the Eni – Exxon- Mobil – TotalEnergies partnered Joint de- velopment LNG project, expected to use feedgas from the 2010 – 2012 discoveries of Mamba North, Prosperidade (Lagosta Windjammer) with an estimated gas po- tential of almost 4.5 Bboe. This is another delayed giant natural gas development expected to come online earliest by the end of the next decade. Tanzania – Tanzania also saw a wave of natural gas discoveries in the early to mid- 2010s,likeitsneighbourMozambique. The overall discovered recoverable natural gas
  • 18. 16 African Energy Chamber Q1 2023 Outlook Report African Energy Chamber 16 volumes is a conservatively estimated 4.3 Bboe. These volumes were discovered in Block 1 and Block 4 both operated by Shell Plc and Block 2 operated by Equinor. These volumes have still not seen or even gotten close to a possible FID soon. How- ever, both the operators and Tanzania’s government recently concluded discus- sions and the contractual terms of a critical host government agreement (HGA) that will underpin the project are now being drawn up. Tanzania’s Minister of Energy January Makamba said this was a major breakthrough on plans to build a US$30 billion LNG project aiming to pipe gas from these blocks to a 10 MMtpa LNG plant at Lindi. Last year, Tanzania’s President Sumia Hassan suggested that if an HGA could be signed by the end of 2022, then the Tan- zania LNG would see a possible FID by 2025. This would mean first cargoes from the project latest by early-2030s. It re- mains to be seen whether this agreement would result in actionable contracts and accelerated development of these strand- ed gas reserves Ethiopia – The natural gas volumes dis- covered in Ethiopia in the 1970s – 1980s, amounting to over 1.5 Bboe at a conser- vative level, are yet to see an FID happen and these gas finds are expected to come online only in the next decade, that too in phases spread over early to late 2030s. Crude oil project delays in West Africa While the above narrative may suggest it is just the gas finds that are long delayed with a possible reasoning that historically operators having preferred development of oil finds over gas discoveries due to their impact on economics and/or regional disturbances and so on, the story is no dif- ferent for many large oil finds in the west- ern side of the continent. Lack of fiscal reforms, like in the case of Nigeria and An- gola; delayed fiscal reforms like the more- than-a-decade-in-the-making Petroleum Industry Act (PIA) of Nigeria; market fluctua- tions due to demand – supply imbalances, crude price crashes due to these market fluctuations or the more recent pandemic and war situations or the currently ongo- ing energy transition and upstream cost cutting strategies have resulted in pushing out many large crude oil finds’ develop- ment timelines. Shell Plc brought the Bon- ga Southwest – Aparo (BSWA) project con- tracts on to the table many times, before going back to the drawing board. The Etan – Zabazaba project offshore Nigeria spent years in delay due to an ongoing legal pro- cess which has now been resolved. Many such deepwater mega finds, with the ca- pacity to reverse the declining production trend in their respective countries, are cur- rently in long delayed FID state. Namibia saw the giant offshore Venus, Graff and Jonker discoveries in the past fifteen months. Post these finds, the coun- try has been seeing increased interest in exploration in its waters. Operator Shell, which made the Graff, La Rona and Jonk- er finds, announced that it plans to drill as many as 10 new exploration and appraisal wells on its prolific petroleum exploration licence (PEL) 39. Many other companies have expressed and/or already entered blocks in the region with plans to soon drill more exploration wells in hopes to mimic Shell and TotalEnergies’ success. While this is great news for Namibia, the admin- Project Country Resources (Million boe) 2 years Zohr Egypt 3580 9 years Dalia/Camelia Angola 1600 10 years Agbami-Ekoli Nigeria 1360 3 years Palogue South Sudan 1055 10 years Bonga Nigeria 1045 7 years El Feel (Elephant) Libya 875 5 years Girassol Angola 795 16 years Atum Mozambique 1855 16 years Golfinho Mozambique 1730 9 years Ahmeyim FLNG 1 Mauritania 770 14 years Ain Tsila Algeria 480 18 years Jobi-Rii (x-Buffalo-Giraffe) Uganda 400 30 years Prosperidade (Barquentine) Mozambique 2355 37 years Orca Mozambique 2050 31 years Prosperidade (Lagosta) Mozambique 2005 29 years Mamba North Mozambique 1975 17 years Orca Mauritania 1320 11 years Venus Phase 2 Namibia 945 18 years Teranga Senegal 540 10 years Marine XII FLNG Phase 2 Congo 385 9 Discovery to FID FID to start-up Liquids Gas Source: Rystad Energy UCube Upstream project delays in Africa Many post-FID and pre-FID projects seeing a large discovery to estimated start-up duration Source: Rystad Energy UCube
  • 19. www.energychamber.org 17 Project Country Resources (Million boe) Bosi Nigeria Bonga Southwest - Aparo Nigeria Owowo West Nigeria Orca Angola Etan – Zabazaba Nigeria Bonga North Nigeria Pecan Phase 1 Ghana Nsiko Nigeria Cameia Angola Chissonga Angola 10 Source: Rystad Energy UCube 36 years 29 years 18 years 21 years 27 years 27 years 17 years 29 years 15 years 21 years Discovery to FID FID to start-up 795 630 550 550 525 500 235 165 145 85 Liquids Gas Upstream project delays in Africa Many key West African crude oil projects also seeing large delays Source: Rystad Energy UCube istration will also be hoping that these dis- coveries add value to the economy in an accelerated timeline without any project delays. Africa, especially deepwater, has had a history of being brought on to the chopping block ahead of any other re- gions globally, by operators when the oil marketturbulenceshappened.Therecent case of Angola going through a period of no offshore drilling, something that years of internal struggle could not do, during the market crash led by the pandemic is an example. It is to be noted that Angola had, shortly before this, announced fiscal incentives to operators working on blocks in deep waters. This suggests something more is required alongside tax incentives for deepwater development to be more encouraged by the respective govern- ments. A fiscal stability clause can be one way of doing this. A fiscal stability clause is a clause to provide the operators with rea- sonable assurance that changes in law or regulations will not adversely affect their expected economic return. Such stability oriented fiscal policies can support crisis mitigation when needed and act as a cat- alyst for increased interest in oil and gas exploration and development offshore Namibia in the Walvis and Namibe basins, alongside the already proven and prolific Orange basin. The fact that no such stabil- ity clauses for economic rebalancing and/ or equalization are currently defined in Namibia’s current tax royalty agreements can lead to delays in development of the giant discoveries that were made in the country. While project delays have impact on their individual country economies, certain re- gional schemes can also be adversely impacted. For example, in March 2022, Equatorial Guinea and Nigeria signed a memorandum of understanding (MoU) that could see gas from Nigeria fed to the Punta Europa LNG complex in Equatorial Guinea, that is currently fed by gas from the Alba and Alen-Aseng fields operated by Marathon Oil and Chevron, respective- ly. This deal, if ratified, could help monetise currently untapped offshore associated gas from Nigeria, while replacing declining output from Equatorial Guinean fields. This MoU was the latest of many deals signed by the Equatorial Guinean government over recent years to try to develop Bioko Islandasamega-gashubintheregion.Itis to be noted such cross-border gas import arrangements were signed previously but never got implemented. In such environ- ment, it becomes imperative that Equa- torial Guinea is able to smoothly bring its own undeveloped gas reserves to start- up without any delays. The delays asso- ciated with the Fortuna FLNG on Block 27, formerly Block R, should be looked to cut down. The block is yet to see an operator finalised although it was reported in 2022 that Golar LNG and New Fortress Energy had teamed up to provide a deep-water floating liquefied natural gas (FLNG) unit for use on the Fortuna gas discovery in Block 27. As of early 2023, discussions were said to be ongoing between the ad- ministration and potential operators, and it was reported that a production sharing contract (PSC) was ready to be signed. The country should look to quickly finalis- ing the required agreements and limit any delays to the project to progress towards becoming an important player in energy markets in a world transitioning to a lower carbon footprint.
  • 20. 18 African Energy Chamber Q1 2023 Outlook Report African Energy Chamber 18 These currently delayed projects and/ or future start-ups have a large impact on the production forecast for Africa. The currently producing fields – both liquids and gas – are in terminal de- cline due to depleting reservoirs. Any infill drilling or redevelopment program on these fields, which will involve wa- ter depth corresponding brownfield spending, might result in a short-term stabilization of the decline in produc- tion but does not seem like it can offset the steep decline. Liquids output from these fields is estimated at about 7.66 MMbbls/d in 2023, 6.85 MMbbls/d in 2025 and 4.7 MMbbls/d in 2030. The average annual production decline rate is an 8% through 2025 – 2030 and a higher 10% through the years 2031 – 2040. 2040 production from these declining fields is a much lower 1.67 MMbbls/d. Any further delays or worse shelving of these future start- ups can be catastrophic to Africa’s hy- drocarbon output. While the short-term (2023 – 2025) start-ups are expected to have a little impact on the forecast, the medium-term (2026 – 2030) and long-term (2030+) start-ups are expect- ed to drive a revival in Africa’s liquids output in the period through 2040. The medium-term start-ups are expected to drive an output of about 1 MMbbls/d in 2028, increasing further to as high as 2.8 MMbbls/d by 2031 – 2032 before gradually declining to 1.15 MMbbls/d by 2040. The long-term start-ups which kick off post 2030 are expected to ramp up quickly to about 1 MMbbls/d by 2032, gradually increase to over 4.2 MMbbls/d by 2038 and decline down to 3.8 MMbbls/d by 2040. The overall impact of these delayed start-ups is still short lived as the total liquids output from Africa is expected to ramp up to about 8.4 MMbbls/d in 2036 from 2023 estimated production of 7.7 MMbbls/d and 2030 flows of 7.37 MMbbls/d, but soon starts declining to an estimated 6.7 MMbbls/d by 2040. The overall re- maining recoverable liquids reserves in Africa, as of January 1st, 2023, are es- timated at about 74.5 Bbbls and a half of this is from the currently producing                   Source: Rystad Energy UCube 3.2 Currently delayed future start-ups – key to Africa’s production increase
  • 21. www.energychamber.org 19 fields. A third of this volume is from the fields delayed to post-2030 as per the current estimated timeline and almost a fifth is from the medium-term start-ups. As such, Africa not only needs these existing discoveries to not see any fur- ther delays, but also additional explo- ration and development to stabilise at production levels higher than 2023 in the future. The situation of natural gas production forecast is no different from the liquids forecast. The decline in producing fields although terminal, however, is not as steep as the liquids producing fields. 2023 output of 4.29 Million bar- rels of equivalent per day (MMboe/d) actually is marginally higher than the 2022 output of 4.23 MMboe/d. From 2023 through to 2040, the average annual decline in production from the producing fields is 5% year-on-year (YoY). The short-term start-ups are es- timated to account for 10% of the total output by 2025. The share from the currently producing fields is expected to drop to 50% by 2031 and further to about a quarter of the total output by 2040. Also, the long-term start-ups are estimated to add up to a third of the to- tal output by 2035 and half of the total output by 2037 – 2038, and this share is only expected to increase going forward. Of the remaining reserves of close to 83 Bboe, only a third is from the currently producing fields and al- most a half comes from the long-term start-ups. While the newer start-ups are expected to offset the decline from the producing fields and take the overall output on a ramp up till about 2037, the total output declines going forward. Any increase in domestic demand, universal electricity access via gas-to- power or LNG export aspirations post this period of ramp up will require new- er gas volumes required to be injected into the flows via additional exploration. Governments do realize the project de- lays and the issues caused – both eco- nomic for the countries dependant on hydrocarbon exports and domestic for countries looking for alternate sources other than coal and firewood for pow- er generation and residential purposes (like cooking). Past few years have seen fruition of these efforts with Nigeria fi- nally passing the long-delayed Petro- leum Industry Act (PIA) and this has re- sulted in critical new production sharing contracts (PSCs) signed with superma- jors. In August 2022, Nigeria executed new terms and conditions for six prolific offshore licences – Oil Mining Lease (OML) 125 operated by Eni, OMLs 128 and 132 operated by Chevron, OMLs 130 and 138 operated by TotalEnergies and OML 133 operated by ExxonMo- bil. It is no secret that these operators have shown disinterest thus far in fur- ther investments in these blocks due to legal and fiscal uncertainties and older PSCs due to expire. The renegotiated PSCs were in line with the provisions of the PIA. These renewed PSCs en- able improved long-term relationships with contractors and help eliminate any contractual ambiguities — especially in relation to gas. National Petroleum Investment Management Services (NAPIMS), which monitors PSC invest- ments, said that the renewed PSCs will unlock more than 10 Bbbls of oil and generate an estimated revenue of over US$500 billion to the government and its PSC partners. Nigeria, earlier this year, launched a licensing round cov- ering seven frontier deep-water and ultra-deepwater blocks – Petroleum Prospecting Licences (PPLs) 300, 301, 302, 303, 304, 305 and 306 as part of ongoing efforts to boost largely stalled exploration activities. Angola also passed the Marginal Field incentives allowing tax incentives on deep water field development that can encourage the operators to accelerate the development of these discoveries. And more recently, Agência Nacional de Petróleo, Gás e Biocombustíveis (ANPG) or Angola’s National Oil, Gas and Biofuel’s Agency signed a mem- orandum of understanding (MoU) cov- ering revised fiscal and contractual terms for the Risk sharing agreements (RSAs) covering deep-water blocks 30, 44 and 45 with the block partners ExxonMobil and Angolan state-owned partner Sonangol PP. This has led to ExxonMobil recently announcing that it is set to spend US$200 million to drill an exploration well by the end of 2024 in the untouched frontier Namibe basin. Other regions also are stepping up in terms of attracting investments from in- ternational oil companies (IOCs). On the other hand, there are also situa- tions that need to be better addressed by the respective administrations. Ni- geria’s previous marginal field licens- ing round, despite talk about being a streamlined and open process, instead became a lengthy test of patience, with its transparency also questioned. For the mini-round launched in January 2023 also, the schedule beyond sub- mission of pre-qualification documents to be submitted by the end of January, is unclear, with bid round documenta- tion not outlining when awards are due to take place. Another case example is the long running gas price discussions between the South African adminis- tration and TotalEnergies, for the us- age of Block 11B/12B gas for domestic purposes, leading to the French major now considering LNG scheme for ex- port markets. These kind of issues can prove to be a hindrance and prove that more is required from the administra- tions in terms of both attracting invest- ments in the upstream industry as well as reaping benefits from the hydrocar- bon developments.
  • 22. 20 African Energy Chamber Q1 2023 Outlook Report African Energy Chamber 20 The development of the large unde- veloped recoverable reserve potential requires an equally high greenfield in- vestments. The spending levels are also seeing an increase YoY, with 2022 green- field expenditure at US$18 billion and 2023 estimated greenfield spending at US$20 billion – a 10% YoY increase. 2025 greenfield spending is estimated at about US$24 billion, a 20% increase over 2023 spending. At the current conservative re- coverable reserves, development time- line and per-barrel spending estimates, the estimated (required) overall greenfield spending over the years 2023 – 2030 is US$290 billion and it further increases to close to US$485 billion over the next decade. Close to 50% of the 2023 green- field spending is expected to be spent on offshore projects and 30% of the to- tal spending is expected to be spent on deep water projects. As most of the large undeveloped oil and gas finds currently are in deep waters off Africa, majority of the greenfield spending going forward is also expected to be on deep water proj- ects. 2025 offshore greenfield spending and deep-water greenfield spending is expected to increase to 65% and 45% re- spectively of the total spending of US$24 billion. This is expected to increase to 67% and over 50% of the total spending of about US$55 billion in 2030; and further to over 70% and about 55% respectively from the total spending of about US$64.5 billion in 2035. Of the total estimated greenfield spending of about US$775 over the period 2023 – 2040, US$500 billion or about 65% is expected to be spent on offshore projects and US$375 billion or close to 48% is estimated to be spent on deep water projects. These deep-water investments include some high-profile projects like the Great- er Tortue Ahmeyim (GTA) – Yakaar – Teranga – Bir Allah – Orca offshore Sen- egal – Mauritania; Pecan offshore Ghana; Bosi, Bonga North, BSWA, Etan – Zaba- zaba offshore Nigeria; Cameia – Golfin- ho and Chissonga offshore Angola; off- shore feedgas fields for Area 1 and Area 4 LNG schemes in Mozambique; Blocks 1,2 and 4 offshore gas fields off Tanzania; Brulpadda – Luiperd gas fields offshore South Africa and the most recent Venus – Graff oil discoveries offshore Namibia to name a few. The magnitude of reserves and the cost intensive nature of offshore deep-water projects are the key drivers behind this large spending forecast. Con- sidering the impact of these projects on Africa’s production forecast, the impor- tance of securing the funding for the de- velopment should be on the forefront for the governments as well as the operators. 3.3 Plenty of potential but equally large investments needed to develop the volumes A Af fr ri ic ca a c ca ap pi it ta al l e ex xp pe en nd di it tu ur re e s sp pe en nd di in ng g s sp pl li it t b by y w wa at te er r d de ep pt th h Billion USD A Af fr ri ic ca a g gr re ee en nf fi ie el ld d – – b br ro ow wn nf fi ie el ld d c ca ap pi it ta al l e ex xp pe en nd di it tu ur re e s sp pe en nd di in ng g Billion USD 12 0 25 50 75 100 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 Greenfield Brownfield 0 25 50 75 100 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 Land Deep water (125-1500 meter) Ultra deepwater (1500+ meter) Shelf (to 125 meter) Source: Rystad Energy UCube Africa capital expenditure spending Close to US$775 billion greenfield spending required over 2023 – 2040 Source: Rystad Energy UCube
  • 23. www.energychamber.org 21 4 AFRICA RENEWABLES OUTLOOK 4.1 Global renewables capacity driven by Asia, Europe and the States 2023 global renewables capacity (solar + wind + hydrogen electrolyzer) is 1,500 GW Asia, Europe and North America are expected to drive over 90% of this capacity, with Africa contributing a negligible 1% of the annual capacity As hydrogen capacity in Africa picks up, 2035 Africa output is expected to increase to 7% of the global capacity Africa’s current announced renewables capacity stands at 134 GW of wind capacity, 120 GW of solar capacity and 112 GW of hydrogen capacity Egypt, Morocco, Mauritania and South Africa are the major countries with current announced capacity Over 75% of the current announced capacity is in concept stage Africa’s renewables capacity output is expected to increase from about 27.4 GW in 2023 to over 280 GW in 2035 CWP Global (in partnership with Bechtel in a few projects) is the main operator with close to 25% of the current announced capacity in Africa 2023 global renewables capacity (solar + wind + hydrogen electrolyzer) is estimated to reach about 1,500 gigawatt (GW) largely driven by the growth in Asia, Europe and the United States where the 2023 renew- ables capacity is about 760 GW, 330 GW and 265 GW, respectively. This cumulative capacity adds up to over 90% of the global 2023 capacity. These three regions are ex- pected to drive majority of the capacity go- ing further till 2035. While the global capac- ity is estimated to grow to about 2,075 GW, 3,085 GW and 3,815 GW by 2025, 2030 and 2035 respectively, these three regions are expected to cumulatively contribute 90%, 85% and over 80% of the total capac- ity during the same years 2025, 2030 and 2035, respectively. Africa’s capacity also is expected to see a gradual through the period 2020 to 2035 but is marginal com- pared to major drivers and global cumula- tive capacity volumes. Africa 2023 capacity is expected to reach 21.5 GW and increase to close to 30 GW by 2025. This capacity is expected to grow further to about 75 GW by 2030 and over 135 GW by 2035. This corresponds to 1%, 2%, 5% and 7% of the global capacities for the years 2023, 2025, 2030 and 2035, respectively. 2023 global wind and solar capacity is es- timated to reach about 925 GW and 575 GW, respectively. Global wind capacity is expected to increase to 1,580 GW by 2030 and further to over 1,900 GW by 2035. And solar capacity is expected to increase to 1,295GWby2030andfurthertoover1,530 GW by 2035. Compared to this, Africa’s 2023 solar PV and onshore wind capacity is about 12 GW and 9.3 GW respectively, and 2025 capacities are expected to show increases to 21.5GW and 17.5GW of solar PV and onshore wind capacity, respective- ly. These low-capacity volumes reflect Afri- ca’s exposure to renewables compared to the giant contributors like Asia, Europe and North America which are expected to see a relatively massive capacity and growth.       
  • 24. 22 African Energy Chamber Q1 2023 Outlook Report African Energy Chamber 22 Total announced capacity of renew- ables in Africa is currently just over 375 GW. More than three-fourths of this is currently in concept stage and a little over 5% is operating. This sug- gests a large potential with further up- side as more operators and investors enter the continent with a clean en- ergy and energy transition objective, but very little currently contributing to Africa’s energy needs. This also sug- gests large infrastructure needs which demand equally high investments. The geographical split suggests more than half of the announced capacity is in North Africa and apart from Mau- ritania in the west and South Africa in the south, the exposure of the rest of sub-Saharan Africa to announced re- newables capacity is relatively much lower. Apart from Mauritania and South Africa, announced wind ca- pacity in Nigeria, all round capacity in Djibouti and promising hydrogen ca- pacity growth in Namibia round off the main sub-Saharan African renewables investments. The continent is expected to see a steep growth in renewables capacity from 2025. Solar and wind is expect- ed to drive the capacity as well as the YoY growth going forward. Close to 80% of the 2023 capacity is driven by solar and wind; and this increases to about 85% by 2025. 2026 – 2030 av- erage cumulative solar and wind ca- pacity is expected to be close to 80% of the total capacity over the period. As hydrogen capacity picks up over the 2030s, the average cumulative solar and wind capacity is expected to be close to 75% of the total capaci- ty over the period 2031 – 2035. Africa’s current total announced re- newables capacity suggests that the wind capacity at close to 134 GW is the largest. Almost a half of this comes from Egypt, and Morocco and Mauritania add up to just over 30% of the total capacity. South Africa and Djibouti round off the top five coun- tries with announced wind capacity 4.2 Majority announced renewables capacity in concept stage and in North Africa A Af fr ri ic ca a r re en ne ew wa ab bl le es s c ca ap pa ac ci it ty y f fo or re ec ca as st t Giga Watts 14 0 50 100 150 200 250 300 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 Storage Hydrogen Electrolyzer Wind Solar 134 120 112 10 0 50 100 150 Wind Solar Hydrogen Electrolyzer Storag e Operating Construction Financial Close Approved Application Auction Concept A Af fr ri ic ca a c cu ur rr re en nt t r re en ne ew wa ab bl le es s a an nn no ou un nc ce ed d c ca ap pa ac ci it ty y Giga Watts Source: Rystad Energy RenewableCube Africa renewables capacity and forecast Solar and wind to drive majority of the renewables capacity but currently 75% in concept stage Source: Rystad Energy RenewableCube
  • 25. www.energychamber.org 23 with a cumulative capacity of about 15.5 GW. These five countries add up to 90% of the total current wind ca- pacity in Africa. Over 75% of the cur- rent wind capacity is still in concept phase and only about 7% is operating, in line with the overall announced re- newables capacity. Solar in Africa takes the second spot after wind with the current announced capacity at 120 GW. Solar announced capacity too, similar to wind capacity in Africa, is led by Egypt – 27.86 GW capacity, Morocco – 22.11 GW capaci- ty and Mauritania – 13.315 GW capac- ity. These three countries add up to over 50% of the current announced solar capacity in Africa. Nigeria and South Africa with 11.1 GW and 9.97 GW capacity respectively round off the top five countries in Africa with respect to announced solar capacity. Close to 96.3 GW (~80% of the total) is in concept phase now and about 10.75 GW (~9% of the total capacity) is operating. Africa’s current total announced electrolyzer pipeline capacity is 112 GW, with about 40% of this tied to countries in North Africa. The con- tinent’s potential goes beyond the north, however, with Sub-Saharan Af- rica hosting numerous prospects for green hydrogen developments. This region has an announced electrolyzer pipeline of about 68 GW, with Mauri- tania claiming over 50% of this total, followed by South Africa and Namib- ia. Namibia’s green hydrogen sector is poised for growth following recent export agreements with Germany and South Korea, while neighbour and re- gional powerhouse South Africa sits on about 90% of the world’s reserves of platinum group metals, which are critical for the manufacture of polymer electrolyte membrane electrolyzers. With the recent unveiling of the Eu- ropean Union’s Green Deal Industrial plan, which aims to promote renew- able and hydrogen developments in Africa, the continent is primed for for- eign clean energy [EO1] investments in the coming years. Solar Wind Hydrogen A Af fr ri ic ca a c cu ur rr re en nt t r re en ne ew wa ab bl le es s a an nn no ou un nc ce ed d c ca ap pa ac ci it ty y Giga Watts 15 0 30 Egypt Morocco Mauritania Nigeria South Africa Tunisia Djibouti Namibia Botswana Zimbabwe Operating Construction Financial Close Approved Application Concept 0 65 Egypt Morocco Mauritania South Africa Djibouti Western Sahara Ethiopia Tanzania Kenya Ghana 0 40 Mauritania Egypt South Africa Morocco Namibia Djibouti Angola Kenya Zimbabwe Burkina Faso Source: Rystad Energy RenewableCube Africa renewables capacity Egypt, Mauritania and Morocco leading the way in current announced capacity Source: Rystad Energy RenewableCube
  • 26. 24 African Energy Chamber Q1 2023 Outlook Report African Energy Chamber 24 In terms of the developers, the top 10 groups of developers contribute to over 55% of the currently announced renew- ables capacity in Africa. Leading re- newable energy developer CWP Glob- al alone is said to be developing close to a fifth of Africa’s announced wind ca- pacity, close to 12% of the announced solar capacity, a fifth of the continent’s hydrogen capacity adding up to about 17% of Africa’s currently announced re- newables capacity. With Bechtel’s part- nership, CWP Global as a developer, is developing Africa’s 25% announced wind capacity, 20% announced solar capacity, 28% announced hydrogen ca- pacity and an overall 24% announced renewables capacity. The US$40 billion Aman green hydrogen project is being developed by CWP Global and is the largest green hydrogen project in Afri- ca. It will have a 15 GW electrolyzer ca- pacity, powered by 30 GW of combined solar and wind. Geographical proximity to the Mauritanian deepwater port of Nouadhibou and the large European market for exports make the green hy- drogen project on Mauritania potential- ly very lucrative. Morocco’s Amun proj- ect, with an annual hydrogen capacity of 900,000 tonnes per annum (tpa), is also being developed by CWP Global along with North American EPC player Bechtel and is the largest in Morocco. CWP Global also signed an agreement with the government of Djibouti to de- velop a 10-GW renewable energy and green hydrogen hub, making the com- pany the biggest renewable energy developer in the Africa. Together, CWP Global and Bechtel have announced a capacity of about 88.5 GW of which over 95% is still in concept phase and a mere 4% has received approval for development. 4.3 CWP Global – current leader in Africa’s announced capacity C Cu ur rr re en nt t t to op p 1 10 0 r re en ne ew wa ab bl le es s d de ev ve el lo op pe er rs s i in n A Af fr ri ic ca a a an nd d t th he ei ir r r re es sp pe ec ct ti iv ve e a an nn no ou un nc ce ed d c ca ap pa ac ci it ty y Giga Watts (GW) Developer Energy Source Country Development status CWP Global CWP Global; Bechtel Globeleq Sasol Ltd. Masdar Total Eren Scatec Fortescue Future Industries ACME Xlinks 16 Wind Hydrogen Electrolyzer Solar Storage Botswana Burkina Faso Djibouti Egypt Ethiopia Gabon Kenya Mauritania Morocco Mozambique Namibia South Africa Togo Tunisia Zambia Zimbabwe Operating Construction Financial Close Approved Application Concept Source: Rystad Energy RenewableCube Africa renewables developers CWP and Bechtel leading the way in current announced capacity Source: Rystad Energy RenewableCube
  • 27. www.energychamber.org 25 Africa continent estimated to stand fifth globally in upstream emissions and Africa’s emissions expected to be driven majorly due to gas flaring High greenfield spending required to bring the large upstream potential online but the economic viability of the level of investment close to a 2˚C scenario At the current estimates, Africa needs fossil fuels as base case scenario suggests a third of the power generated in 2030 and over a quarter of this in 2040 is expected to come from gas-to-power 5 AFRICA COP27 COMMITMENTS AND NATURAL GAS 5.1 Natural gas vs renewables potential in Africa Africa holds large natural gas and renewables potential, but over 60% of the natural gas potential and over 75% of the current announced renewables capacity is in a similar “pre-FEED” state Africa’s COP27 commitments aim at phase down of coal power, natural gas as transition fuel and establishment of the Africa Carbon Markets Initiative (ACMI) Universal electricity access and power generation based on renewables is also on the agenda Conservative estimates suggest Af- rica’s current natural gas potential is close to 16,000 Bcm. This includes an 11% “undiscovered” potential, but this can be higher based on the amount of unexplored and under-explored acreage both onshore and offshore Africa. An increase in this number will take the overall reserve poten- tial much higher. The 51% “discov- ered” reserves are the “stranded” or currently undeveloped reserves in pre-FEED and in some cases pre-ap- praisal or pre-technical evaluation volumes that are being estimated as future FIDs. This is a large chunk of the overall potential and is in a phase where even a possible scheme of development is yet to be conceptual- ised and eventually finalised. The current announced renewables capacity also is in a similar mix in terms of the status of development. Of the total capacity of 375 GW, only 7% is “operating” or is fully connected to the grid and generating electricity. A further 8% announced capacity is approved for development, 2% ca- pacity is currently under construction and a marginal 1% has acquired the necessary financing and will soon hit the market to tender for contracts to build the project. A 6% of the ca- pacity is in the process of obtaining the necessary permits and approvals from the administration. While this cumulative capacity of about 90 GW has at the least crossed the barrier of submitting the paperwork for ap- provals, a large chunk – 76% of the announced capacity is from the proj- ects where paperwork for the neces- sary regulatory approvals is yet to be initiated. These projects are currently speculative and the eventual approv- als as well as the timelines are highly speculative. Even in a 1.5˚C scenario, estimates suggest close to a fifth of the power generated in 2030 and about 8% of this in 2040 will be from gas-to-power projects South Africa can benefit from the COP27 commitments around phase down of coal and usage of natural gas potential for power generation
  • 28. 26 African Energy Chamber Q1 2023 Outlook Report African Energy Chamber 26 A Af fr ri ic ca a c cu ur rr re en nt t r re en ne ew wa ab bl le es s i in ns st ta al ll le ed d c ca ap pa ac ci it ty y Giga Watts A Af fr ri ic ca a n na at tu ur ra al l g ga as s p po ot te en nt ti ia al l Billion cubic meters 17 30% 8% 51% 11% Producing Under development Discovery Undiscovered 15,935 Bcm 7% 2% 1% 8% 6% 76% Operating Construction Financial Close Approved Application Concept Source: Rystad Energy UCube; Rystad Energy RenewableCube Africa natural gas vs installed renewables capacity Majority of the gas potential undeveloped and majority of the renewables capacity in concept phase 375 GW Source: Rystad Energy UCube; Rystad Energy RenewableCube 5.2 Africa COP27 Africa commitments and impact The 27th Conference of the Parties to the United Nations Framework Con- vention on Climate Change (COP27) reaffirmed COP26 conclusions of “phase down of unabated coal pow- er” and “phase out of inefficient fos- sil fuel subsidies”, while natural gas received a more prominent role in energy transition and for tackling cli- mate change, as “low-emission” en- ergy won approval. The conference also saw the African policy makers pledge a climate initiative in the name of Africa Carbon Markets Initiative (ACMI) targeting 300 million carbon credits per year- equivalent to 300 million tonnes of CO2 reduction by 2030. The initiative is aimed at pro- viding a potential source of financing to support energy transition in Africa. Another key takeaway for Africa was the launch of the Africa Just and Af- fordable Energy Transition Initiative (AJAETI). The COP27 agenda included some of the most important global ener- gy relate climate themes – reducing emissions to bring 1.5˚C within reach, reduce usage of coal, help prepare and deal with climate change, sup- port developing countries with tech- nical and financial aid, establishment of a global carbon market and finally, a new pooled fund arrangement for countries most affected by climate change. While these key themes were discussed at length and the new funding arrangement on loss and damage was hailed as a “his- toric moment”. The representatives of African nations seemed to have a more balanced voice between ener- gy requirements and climate change as opposed to the previous confer- ence where the key narrative was that Africa was on the receiving end of the problem and it was the bigger
  • 29. www.energychamber.org 27 emitters that had the responsibility to cut down fossil fuel production. The AJAETI and ACMI initiatives clearly highlight this. The AJAETI aims at three key targets, all focusing on power – increasing the share of electricity generation us- ing renewable sources by 25% points by 2027, universal access by 2030 and finally, establishing a power sec- tor completely based on renewable sources by 2063. The ACMI targets a voluntary carbon market where car- bon credits are released per tonne of CO2 eliminated within a company’s operations and these credits can be bought by other operators who need to offset unavoidable emissions. Ex- isting and upcoming oil and gas pro- ducers like Nigeria, Gabon and Ken- ya were among the member nations joining this initiative. With the push for universal access, natural gas as path- way for energy transition and oil pro- ducers supporting the ACMI, Africa is clearly looking to address both – the energy issues within and the climate issues globally. Where does Africa stand globally with respect to upstream emissions? From 2023 through to the end of the decade, Africa’s upstream emissions are estimated to reach a cumulative 795 million tonnes of CO2 equivalent. Globally, Africa is estimated to stand fifth after North America, the Middle East, Asia and Russia in terms of over- all emissions over the period. Africa’s upstream emissions are an estimated 9.5% of the global upstream emis- sions over the period 2023 – 2030 and about a half of Africa’s upstream emissions during the period are es- timated to be result of gas flaring. While the upstream extraction related emissions from Africa are a mere 7% of the global extraction emissions, the flaring and venting emissions from Af- rica over the period are estimated to be almost a fifth of the global levels. This suggests flaring results in major- ity upstream emissions in Africa and Africa is also one of the major flaring regions globally. 2 20 01 15 5 – – 2 20 03 30 0 A Af fr ri ic ca a u up ps st tr re ea am m e em mi is ss si io on ns s Million tonnes CO2 equivalent 2 20 01 15 5 – – 2 20 03 30 0 G Gl lo ob ba al l u up ps st tr re ea am m e em mi is ss si io on ns s Million tonnes CO2 equivalent 18 2 20 02 23 3 – – 2 20 03 30 0 G Gl lo ob ba al l u up ps st tr re ea am m e em mi is ss si io on ns s Million tonnes CO2 equivalent 0 400 800 1 200 2015 2020 2025 2030 Extraction Flaring and venting upstream 0 30 60 90 120 150 2015 2020 2025 2030 Extraction Flaring and venting upstream Global and Africa upstream CO2 Emissions Africa’s upstream CO2 emissions largely driven by natural gas flaring Source: Rystad Energy UCube 72% 28% 48% 52% 7% 18% 0 1 000 2 000 3 000 4 000 5 000 6 000 7 000 Extraction Flaring and venting upstream America N Middle East Asia Russia Africa America S Europe Australia Source: Rystad Energy UCube
  • 30. 28 African Energy Chamber Q1 2023 Outlook Report African Energy Chamber 28 A Af fr ri ic ca a b ba as se e c ca as se e g gr re ee en nf fi ie el ld d s sp pe en nd di in ng g v vs s 2 2° ° s sc ce en na ar ri io o v vs s 1 1. .6 6° ° s sc ce en na ar ri io o Billion USD 19 0 10 20 30 40 50 60 70 80 90 100 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 Commercial Uncommercial Mean (2° scenario) Minus Sigma (1.6° scenario) Source: Rystad Energy UCube; Rystad Energy EP Energy Transition Risk Dashboard Africa greenfield spending – commerciality and climate scenarios Current economically viable greenfield spending forecast close to 2° and 1.6 ° scenarios Source: Rystad Energy UCube; Rystad EP Energy Transition Risk Dashboard How is Africa’s oil and gas landscape now? As discussed previously, Africa’s esti- mated oil and gas resource potential and production forecast going forward clearly suggests there is significant undeveloped potential and output is completely dependent on these unde- veloped volumes as the producing res- ervoirs are now in terminal decline. At a conservative level, Africa is estimated to hold about 74.365 billion barrels (Bb- bls) of recoverable liquids and 82.875 billion barrels of oil equivalent (Bboe) of recoverable natural gas resources. Only half of this liquids potential and a third of the natural gas potential is cur- rently developed and is producing. 45% of the liquids and a much larger 60% of the natural gas potential is current- ly “stranded” in pre-FEED state. While natural gas production can see an in- crease if these stranded volumes are developed without any further delays than currently expected, liquids flows need accelerated development and more discovered volumes to see an increase as current volumes and time- lines are expected to only stabilize the decline and maintain a flat production trend. To maintain the above-mentioned pro- duction levels at the estimated conser- vative timeline, the scale of required investments is quite steep. The main- tenance of a stabilized oil output and meeting the natural gas domestic and international supply aspirations will need an estimated greenfield spend- ing of close to US$65 billion over the period 2023 – 2025. This is estimated to increase to a cumulative spending of about US$225 billion for the remain-
  • 31. www.energychamber.org 29 der of this decade, and over US$485 billion over the next decade 2031 – 2040. However, the current estimated economic viability or “commerciality” of this spending paints a different picture, and this “commercial” spending is clos- er to a 2˚C drop climate scenario. While the 1.6˚C scenario greenfield spending forecast is relatively in line with the 2˚C scenario levels, 2031 – 2040 greenfield spending can be expected to be dimin- ished to about US$55 billion. This can mean a potential deathblow to Africa’s oil and gas aspirations, economical fu- ture of a number of fossil-fuel exports dependent economies in the continent and, energy security and universal elec- tricity access being aimed to achieve using natural gas as a transition fuel. How is Africa’s power mix expected to pan out? Africa is currently heavily dependent on fossil fuels for power generation. About 75% of the power generated in Africa over 2022 – 2023 is estimated to be generated using oil, gas and coal. A cu- mulative 60% of the power generated in 2030 is expected to be from fossil fuels with oil and gas generating about 40%. Even 2040 forecast suggests close to 37% of the power generated will be using oil, gas and coal with coal still playing a 9% role and natural gas accounting for over a quarter of the power generation. As such, fossil fuels are expected to play a long-term role in Africa power generation. Power mix in the 1.5˚C scenario, the power mix also. 25% of the power generated in 2030 and 5% in 2045 is estimated to be from oil and gas. As such, oil and gas is ex- pected to play a long-lasting role in Af- rica’s power mix. A Af fr ri ic ca a p po ow we er r g ge en ne er ra at ti io on n a at t 1 1. .5 5° °C C s sp pl li it t b by y c ca at te eg go or ry y Tera Watt hours (TWh) A Af fr ri ic ca a b ba as se e c ca as se e p po ow we er r g ge en ne er ra at ti io on n s sp pl li it t b by y c ca at te eg go or ry y Tera Watt hours (TWh) 20 41% 41% 40% 39% 38% 38% 38% 38% 36% 35% 34% 33% 33% 33% 33% 32% 32% 31% 30% 29% 27% 0 1000 2000 3000 2020 2025 2030 2035 2040 Nuclear Coal Gas Liquids Hydro Marine Bioenergy Geothermal Onshore wind Offshore wind Solar PV Solar Thermal Ammonia mixed Hydrogen mixed 41% 41% 39% 37% 36% 34% 32% 29% 26% 23% 19% 17% 15% 14% 13% 12% 11% 11% 10% 9% 8% 0 1000 2000 3000 4000 2020 2025 2030 2035 2040 Nuclear Coal Gas Liquids Hydro Marine Bioenergy Geothermal Onshore wind Offshore wind Solar PV Solar Thermal Ammonia mixed Hydrogen mixed Source: Rystad Energy Power Transition Scenarios Dashboard Africa power generation forecast in different scenarios Natural gas to play a role in Africa’s power generation even at 1.5°C scenario Source: Rystad Energy Power Transition Scenarios Dashboard
  • 32. 30 African Energy Chamber Q1 2023 Outlook Report African Energy Chamber 30 Source: Rystad Energy Power Transition Scenarios Dashboard 5.3 South Africa can benefit by adhering to the COP27 commitments Africa’s COP27 commitments focus on phasing down of usage of coal for pow- er generation, universal uninterrupted electricity access and natural gas as transitional fuel towards switching to renewables completely for power gen- eration. These initiatives aim at cutting down emissions from the usage of fossil fuels especially coal, end energy pov- erty and utilise the large potential of African gas, for Africa, for firing the gas- to-power plants. As a case example, the current electricity situation in South Africa can be reviewed to understand how these commitments are very close to reality and how natural gas potential can be utilised to both minimise emis- sions and avoid power outages. Most power stations in the country are owned and operated by Eskom. These plants account for about 95% of all the electricity produced in South Africa. Coal fired power plants account for bulk of this, with 2022 power mix suggest- ing coal was the energy source behind 80% of the power generated. Relatively more expensive Open Cycle Gas Tur- bines (OCGTs) like Ankerlig, Gourikwa, Dedisa and the likes, which use diesel as the primary resource; and renewable energy sources backed power stations also contribute to power generation, but the share is miniscule compared to coal-fired plants. Historically, South Africa could benefit from via access to cheap electricity but this eventually led to the issues plaguing the country now – ageing fleet of coal-fired stations con- sistently breaking down and/or needing extensive maintenance, additional ex- penditure on diesel to replenish outag- es caused by these breakdowns, high CO₂ emissions placing the southern Af- rican nation in the world’s top 20 emit- ting countries and most importantly, in- troduction of load shedding to prevent total blackouts. A Af fr ri ic ca a p po ow we er r g ge en ne er ra at ti io on n a at t 1 1. .5 5° °C C s sp pl li it t b by y c ca at te eg go or ry y Tera Watt hours (TWh) A Af fr ri ic ca a b ba as se e c ca as se e p po ow we er r g ge en ne er ra at ti io on n s sp pl li it t b by y c ca at te eg go or ry y Tera Watt hours (TWh) 20 41% 41% 40% 39% 38% 38% 38% 38% 36% 35% 34% 33% 33% 33% 33% 32% 32% 31% 30% 29% 27% 0 1000 2000 3000 2020 2025 2030 2035 2040 Nuclear Coal Gas Liquids Hydro Marine Bioenergy Geothermal Onshore wind Offshore wind Solar PV Solar Thermal Ammonia mixed Hydrogen mixed 41% 41% 39% 37% 36% 34% 32% 29% 26% 23% 19% 17% 15% 14% 13% 12% 11% 11% 10% 9% 8% 0 1000 2000 3000 4000 2020 2025 2030 2035 2040 Nuclear Coal Gas Liquids Hydro Marine Bioenergy Geothermal Onshore wind Offshore wind Solar PV Solar Thermal Ammonia mixed Hydrogen mixed Source: Rystad Energy Power Transition Scenarios Dashboard Africa power generation forecast in different scenarios Natural gas to play a role in Africa’s power generation even at 1.5°C scenario
  • 33. www.energychamber.org 31 Source: Rystad Energy Power Transition Scenarios Dashboard Source: Rystad Energy Power Transition Scenarios Dashboard S So ou ut th h A Af fr ri ic ca a b ba as se e c ca as se e p po ow we er r g ge en ne er ra at ti io on n s sp pl li it t b by y c ca at te eg go or ry y Tera Watt hours (TWh) 21 0 100 200 300 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 Nuclear Coal Gas Liquids Hydro Marine Bioenergy Geothermal Onshore wind Offshore wind Solar PV Solar thermal Source: Rystad Energy Power Transition Scenarios Dashboard South Africa historical power generation Heavily dependent on coal, with 90% of 2020 – 2025 power generated using coal While these issues have had a larger im- pact on the wider economy of the coun- try, the expenditure to maintain the ag- ing power plants, to purchase diesel to keep up the power supply and other fac- tors driving huge losses to the national entity Eskom have led to high electricity tariffs on the regular domestic electricity consumer. The period between 2000 – 2007 saw linear increase in average Eskom electricity tariffs. However, since the first load shedding was implement- ed in 2007, average Eskom electricity tariff has seen an exponential growth of 460% by 2020. 2020 average tariff was about 110 c/kWh and the same year saw Eskom win a major legal battle where Eskom is allowed to increase average electricity tariff to 128.24 c/kWh under court order, to allow the state player to manage its mountain of debt through increased revenues via increased tariff. South Africa, in the recent years, has seen two large gas finds in its waters on TotalEnergies operated Block 11B/12B. The operator revealed in early Feb- ruary 2019 that the deep water Bruld- padda-1AX re-entry well, which was drilled on Block 11B/12B in the Outeniqua Basin, 175 kilometres off South Africa’s southern coast, detected 57 meters of net gas-condensate pay in Lower Cre- taceous reservoirs. Another significant gas-condensate discovery was made with the Luiperd wildcat well in October 2020. The Luiperd-1X well was drilled in approximately 1,800 meters of water to a total depth of about 3,400 meters encountered 73 meters of net gas-con- densate pay, 16 meters more than the Brulpadda well. Both Brulpadda and Lui- perd rank high on the list of Africa’s larg- est discoveries in their respective year of discovery. Estimates put Brulpadda at 275 million barrels of oil equivalent (MMboe) and Luiperd at 340 MMboe, with 70% gas each in both discoveries.
  • 34. 32 African Energy Chamber Q1 2023 Outlook Report African Energy Chamber 32 Source: Rystad Energy Corp; Rystad Energy Research and Analysıs 22 Block 11B/12B gas to South African domestic markets Potential to support current future gas-to-power and GTL plant at capacity Source: Africa Energy Corp; Rystad Energy Research and Analysis The large scale finds of Brulpadda and Luiperd, when developed, have an equally impressive natural gas and condensates production poten- tial. Brulpadda alone has the poten- tial to deliver a peak output of about 25,000 barrels per day (bpd) of con- densates and 50,000 barrels of oil equivalent per day (boepd) of natu- ral gas. Luiperd phases 1 and 2 put together have an estimated peak production capacity of about 30,000 bpd of liquids and 80,000 boepd of natural gas. Cumulatively, Brulpadda – Luiperd project peak output is an estimated to be 50,000 bpd of liquids and 125,000 boepd of natural gas. The individual fields are expected to come online through late 2020s or early 2030s. The average output from the project cumulatively is estimated to be around 35,000 bpd of liquids and about 100,000 boepd of natu- ral gas. For a nation that is currently dependant on ageing and emission intensive coal-fired power plants for electricity generation and a continent that has pledged to utilise natural gas as a transition fuel towards 100% util- ity generation from renewables, Brul- padda and Luiperd can help South Africa negotiate through the power crisis that the country is going through if the gas is directed towards domes- tic markets and gas-to-power plants. The gas from Brulpadda and Luiperd can also enable conversion of power plants like Gourikwa station with a ca- pacity of 740 MW and Dedisa station with a capacity of 335 MW to run on baseload gas, and any further poten- tial can cater to future gas-to-power requirements. As such, catering Block 11B/12B potential to the domestic mar- ket can result in not only meeting the country’s energy needs but will also a significant boost to the economy. Phasing down usage of coal for power generation, and thereby cutting down on emissions; using natural gas as a transition fuel for generation of elec- tricity before being able to switch to renewables completely; guaranteeing universal electricity access and avoid- ing power outages – this clearly is in line with Africa’s COP27 commitments. 22 Block 11B/12B gas to South African domestic markets Potential to support current future gas-to-power and GTL plant at capacity Source: Africa Energy Corp; Rystad Energy Research and Analysis
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