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Africa Energy Outlook 2021
2
African Energy Outlook 2021 Credits
Production
Team
Executive Chairman
NJ Ayuk
Senior Vice President
Verner Ayukegba
Director of Communications and Marketing
Africa Energy Mandisa Nduli
Outlook 2021 Director of Strategy
Mickaël Vogel
Digital Marketing Coordinator
Amina Williams
Published and presented by the
African Energy Chamber with de- Creative Director
sign by Africa Oil & Power. Giovanni Trevisson
Published 2 November 2020 Graphic Designers
energychamber.org Paul Cheeseman
Heidi Sparks
The African Energy Chamber ex-
tends thanks to all individuals and With special thanks to:
companies that supported the pro- Dr Theophilus Acheampong
duction of this report. Dr Nathaniel Babajide
Doris Agbevivi
Dr Bridget Menyeh
Dr Geoffrey Mabea
Rystad Energy
2 African Energy Chamber www.energychamber.org 3
4
African Energy Outlook 2021
Africa Energy
Outlook 2021 Industry
Outlook
44 Market realities: Impact on
fiscal terms
50 Energy transition contributions
on industry outlook
Contents 6 A letter from our
Executive Chairman
NJ Ayuk Employment 58 The state of jobs
Outlook
Exploration & 8 Introduction
Production Outlook Regional 60 Keeping African resources
Outlook competitive
66 Production review
Environmental 10 High carbon emission
Outlook is a threat to African
competitiveness
Power 84 Introduction
Outlook
86 Africa’s electricity sector in 2021
Investments & 16 Free cash flow and
Commodities government take 93 Gas-to-power and Africa’s
industrialization
Outlook 20 Oil Markets
96 Regulatory reforms
24 Gas Commodities
102 The energy transition and
28 Market conditions Africa’s power sector
34 The future of expenditure 104 Investing in the fight against
investments energy poverty
4 African Energy Chamber www.energychamber.org 5
6
African Energy Outlook 2021 A letter from our Executive Chairman, NJ Ayuk
A Year
Like No
Other
Dear Reader,
2020 has been a year of unprecedented challenges, In 2021, Africa will benefit greatly if we create an stable growth path. We believe the short-term outlook
and the trials and tribulations have made the African investment climate that supports the development of all will improve if countries apply more competitive fiscal
Energy Chamber’s work more important now than energy resources. At the African Energy Chamber, we regimes. Emissions can be reduced by curbing flaring
ever. We are committed to helping Africa’s oil and gas believe supporting the energy industry, promoting free and monetizing gas, improving and future-proofing the
stakeholders navigate a complex and ever-changing markets, the rule of law, individual freedoms and limited carbon profile of African petroleum production.
global energy landscape. We will continue our mission government, is a duty for all Africans.
to support the dynamic private sector and unlock the Developing gas-to-power infrastructure will increase
continent’s remarkable energy potential. But we must not stop there, advocating for a market access to affordable energy for all sectors of the
driven Afro-centric energy transition, with a specific economy, offering massive knock-on benefits and
Africa’s oil and gas industry is facing extraordinary focus on natural gas to expand market opportunities making it easier to do business. Reducing lead times to
circumstances. An ongoing energy transition and new is something we will continue to drive. The oil and gas limit risk premiums put on long cycle projects will further
efforts to decarbonize the world are weighing on oil industry is a force for good and we must not join those bolster the industry’s viability and growth prospects. It
demand. The shale revolution is exacerbating these forces that want to demonize hardworking people will not be easy, but these reforms are necessary.
pressures. And of course, the COVID-19 pandemic whose only crime is to work hard and play by the
has wrought havoc on markets around the world, rules and embrace hope rather than fear mongering Again and again, our oil and gas sector has proven its
accelerating and intensifying existing trends. and embrace economic empowerment rather than resilience and adaptability. The world still needs oil and
development aid. That’s why we believe implementing gas, and Africa still holds enormous untapped potential.
External headwinds are forcing African petroleum programs like local content, economic diversification The African Energy Chamber will remain a committed
producers to re-examine their strategies. that support natural gas value chains, making fiscal terms partner of choice for the industry as we advance into an
Conventional petroleum resources here should competitive and reducing red tape and streamlining uncertain future.
be globally competitive, but growth has lagged regulatory processes must be priorities in 2021.
because of conditions above the ground, not
below. Restrictive fiscal regimes, inefficient and We have to cut red tape to make life easier for Our African Energy Outlook 2021 addresses these
carbon-intensive production, and difficulties in doing hard-working Africans, businesses and investors challenges head-on. Building on last year’s success, our
business are preventing the industry from reaching to work and grow the energy sector. We know second annual report offers an even more exhaustive
its full potential. As companies delay projects and cut from experience this will reduce the cost of doing and comprehensive look to the year ahead for African
costs, planned capital expenditure in 2020-2021 has business, speed up approvals and make life oil and gas. Thank you,
fallen from $90 billion pre-COVID-19, to $60 billion better for Africans. We must never be ashamed of
now. To remain competitive, African producers and supporting an industry that has brought so much The 2021 outlook details all of the major challenges facing NJ Ayuk
governments must adapt. But how can they do it to Africa and will continue to bring people out of African oil and gas stakeholders, as well as workable Executive Chairman
when the economic order is being remade? poverty and reduce reliance on foreign aid. solutions that will keep the industry on a strong and African Energy Chamber
6 African Energy Chamber www.energychamber.org 7
8
High level take aways | Time to act!
African Energy Outlook 2021
High level take aways
Time to act!
The global energy transition and but above surface conditions related The impact of COVID-19 on 2021
decarbonization drive are putting to fiscal regimes, carbon emissions liquids production is however not
pressure on oil demand while shale and general difficulty of doing busi- so severe as the current 2021 out-
has unlocked abundant resources. ness are holding projects back. look stands at about 7.6 million bar-
The global context forces African rels per day compared to 8.2 million
petroleum producers to adapt or The CAPEX spending 2020 - 2021 barrels per day in the beginning of
become uncompetitive. outlook pre-COVID-19 was almost the year.
$90 billion for 2020 and 2021, but has
The coronavirus pandemic (COVID-19) been significantly reduced to about Outside COVID-19, regulatory mat-
has accelerated this underlying pres- $60 billion due to project delays and ters have also unnecessarily de-
sure by causing unprecedented hav- cost cutting measures. layed major projects in Nigeria,
oc on global energy markets that Afri- Kenya, Uganda and Tanzania that
ca is not insulated from. The 2021 outlook therefore appears represent big opportunity losses for
weak on new project sanctions, but local content development, delayed
Conventional petroleum resources relatively stronger for jobs and drilling job creation and further deteriorat-
such as those in Africa should be markets on the back of ongoing proj- ed Africa’s competitive position ver-
competitive in the global supply stack, ects initiated pre-COVID-19. sus resources elsewhere.
The African Energy Chamber believes that the short-term outlook can be remedied by:
Applying more compet- Curbing flaring and mone- Developing gas to power Reducing lead time as
itive fiscal regimes that tizing gas, which will help infrastructure that will in- higher risk premiums are
can help unlock 4.4 billion improving the carbon crease access to afford- put on long cycle projects
barrels of liquids and $100 emission profile of Afri- able energy to all sectors versus short cycle projects.
billion of additional invest- can petroleum production of the economy.
ments by 2030. that currently bottom tier
among the continents.
8 African Energy Chamber www.energychamber.org 9
10
African Energy Outlook 2021 Gas to power push represents the most promising way to decarbonize the African upstream
Upstream CO2 emission Upstream CO2 Oil & Gas
intensity 2018 emmision 2018 Production 2018
(kgCO2/boe) (Mt Co2) (mmboe/d)
Gas to power push represents
the most promising way to Total
decarbonize the African upstream Flaring
31 30 17
3
16 14 15
2
139 102 253
47
283 223 43
5
9 5 31 90
7 111
18 80
Extraction
13 21 14 11 7 13 59 71 206 192 111 38
Strong incentives to monetize As the world is moving towards the ener- er premiums to be deployed in carbon
Africa
South America
North America
APAC
Middle East
Europe
Africa
South America
North America
APAC
Middle East
Europe
Africa
South America
North America
APAC
Middle East
Europe
African gas and create new de- gy transition in order to curb greenhouse inefficient hydrocarbon production, and
gas emissions and meet the targets in it is therefore increasingly important
mand centers, especially in pro-
the Paris agreement, the oil and gas in- to help minimize emissions in order to
moting gas to power internally, dustry is doing its share. While combus- have a competitive project. Unfortunate-
will fasten the decarbonization tion of hydrocarbons by off-takers and ly, Africa continues to operate carbon
of African upstream activities. consumers does represent around 90% inefficient production, which further im- Figure 1.1: Upstream emissions | Continent comparison
of total emissions, the remaining 10% pacts its ability to raise capital for oil and Flaring varies globally and contributes significantly to upstream emissions intensity
Africa to remain at least until is what oil and gas companies are tar- gas projects.
geting to cut through initiatives such as
2025 the least carbon efficient Production 2018 Production 2018
electrification, reduced flaring and more A data base has been built on the back
oil producing frontier with over by supply segment by hydrocarbon type
energy efficient extraction methods. An of all knowledge about emissions and (percentage) (percentage)
30 kilogram CO2 emitted per often-used metric to determine hydro- the type of hydrocarbon production (on-
barrel of oil equivalent produced. carbon production’s carbon efficiency shore, offshore, oil type etc.) in order to 100% 100%
is to consider the amount of emissions have a view of carbon efficiency globally. Other Heavy Oil 15-19
Continued high carbon emission outside combustion per unit of produc- This is illustrated on Figure 1.1 where the Onshore
80% 80%
tion. The lower this ratio is, the more effi- sum of each continent’s upstream pro- Heavy Oil 20-23
is a threat to Africa’s global com-
cient your production is. duction and upstream emissions from Oil
petitiveness. 2018 are compared to each other. Sands Sour (
12
African Energy Outlook 2021 Gas to power push represents the most promising way to decarbonize the African upstream
100%
90%
80%
Fig. 1.2 Historical Oil & Gas
Production
70%
(mmboe/d)
60%
Africa
1960 - 2018
South America
50%
1940 - 2018
North America
1920 - 2018
40%
APAC
1960 - 2018
30%
Middle East
1950-2018
20%
Europe
1950 - 2018
10%
0%
1920
1930
1940
1950
1960
1970
1980
1990
2000
2010
2018
12 African Energy Chamber www.energychamber.org 13
14
African Energy Outlook 2021 Gas to power push represents the most promising way to decarbonize the African upstream
Figure 1.3: Upstream Flaring Emissions | Large differences in flaring
Between 5085% of total upstream for oil fields Data Source: Rystad Energy Research & Analysis; NOAA/World Bank
Algeria
Iran
Iraq Flaring
Libya
Russia
Kazakhstan
Nigeria
Mexico
Oman
Venezuela
Angola
United States
Kuwait
UAE
United Kingdom
Colombia
China
Saudi Arabia
Brazil Extraction
Norway
Canada
20% 40% 60% 80% 100%
Figure 1.2 breaks down the top 20 oil produc- tries are in the upper half with Angola as the less points to Africa overall not improving the resources’ competitiveness in a world
ers globally on how much flaring represents best performer of the group. It is primarily the its position with emissions remaining above with increasingly constrained carbon emis-
in terms of emissions versus the emission North African countries Algeria and Libya that 30 kg CO2 per barrel of oil equivalent. sion budget. In this context, political will and
from the extraction process. Ideally, the flaring have poor performance with regards to flaring While flaring is and upstream emissions are industry compliance will be key. Initiatives
component is as small as possible. emissions. not always easy to reduce, it nevertheless such as the Nigerian Gas Flare Commer-
does represent an enormous opportuni- cialization Program are extremely positive
Of four African countries on the list (Algeria, 2018 is currently the last year with high quality ty for Africa to reduce its carbon emission steps in that direction and must be encour-
Libya, Nigeria and Angola) none of the coun- data, but projections towards 2025 neverthe- per production unit and thereby increase aged and supported by all stakeholders.
14 African Energy Chamber www.energychamber.org 15
16
African Energy Outlook 2021 COVID-19 curbs free cash flow and government take but 2021 outlook improves
Figure 2.1: Free cash flow evolution per Continent
USD/boe nominal Data Source: UCube August 2020
$20
COVID-19 curbs free cash $10
flow and government take $0
but 2021 outlook improves $-10
$-20
$-30
2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
Generated free cash flow and The goal of any project within the oil able years in history on the back of high Australia Asia Middle East Africa South America
government take is expected and gas world is to create value by commodity prices and capital programs
generating sufficient revenue to recu- ramping up (Figure 2.2). In 2014, the
to decline by north of 50% in
perate all cost and generate sufficient commodity prices started to decline to
2020 from approximately $10/ free cash flow to justify the required thereby decrease free cash flow genera-
boe nominal in 2019 to $4/boe rate of return. Multiple parameters influ- tion, but more impactful were the numer- Figure 2.2: Free cash flow evolution for Africa
nominal in 2020. ence the free cash flow generation, but ous giant projects initiated from 2012 to USD billion nominal Data Source: UCube August 2020
chief among them is commodity pric- 2014 that represented enormous capital
Improved outlook for 2021 at es that determine how much revenue expenditure. It was these locked-in cap- $80
is generated. As projects are evolving ital programs, together with the drop in
$6/boe nominal on the back of
through their life cycles at different commodity prices, that caused free cash
curbed expenditure and higher points in time, the sum of all cash flows flow generation to be highly constrained $70
commodity prices. across all projects create trends. Ver- during 2015 and 2016.
sus other continents, Australia has and $60 Free cash flow from Forecast
Continued impact of COVID-19 is expected to generate on average the From 2017 onwards, the capital pro- upstream operations
on demand and commodity pric- highest free cash flow per barrel of oil grams were completed, the projects
equivalent from 2018 to 2025 (Figure started to produce and generate reve- $50
es will be crucial to short-term
2.1). African performance is however in nue, and commodity prices increased.
forecast and expectations line with other continents and exhibits The result was an improving free cash $40
similar volatility on the back of the in- flow that grew to $55 billion in 2018.
dustry’s typical boom and bust cycles. The industry had effectively responded
to the commodity price shock in 2014 $30
Analyzing free cash flow from all Afri- and rebalanced spending and revenue
can projects, one notices that 2012 and to be more sustainable than what was $20
2013 remain some of the most profit- the case in 2015 and 2016.
$10
$0
2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
16 African Energy Chamber www.energychamber.org 17
18
African Energy Outlook 2021
COVID-19 curbs free cash flow and government take but 2021 outlook improves
Under normal circumstances, this new Figure 2.3: Government take evolution for Africa
balance was expected to continue, USD billion nominal Data Source: UCube August 2020
but the impact of COVID-19 has cre-
ated many similarities to 2015 and Figure 2.4: Top 10 free cash flow for companies operating in Africa
2016 whereby free cash flow will be USD billion nominal Data Source: UCube August 2020
squeezed on the back of reduced rev-
$200
enue and locked in capital programs. As
such, the industry will once again have 3500
to rebalance its spending and revenue $160
which typically implies curbing explora-
tion activity and deferring new invest-
ment decisions. While 2020 free cash $120 3000
flow is not expected to decline towards
the same depth as during 2015 and
$80
2016, the spend curtailment and expect-
ed higher commodity prices are antici- 2500
pated to create a rebound into 2021. $40
With more free cash flow generated in
2021, the scene is set for a new cycle of
investments with activity picking up for $0 2000
deferred projects and exploration activ- 2012 2014 2016 2018 2020 2022 2024
ity. For the same reason, we can expect
most key final investment decisions (FID) generated for companies, the general only about $55 billion in government
on African projects to be taken in 2021. relationship between commodity prices take (Figure 2.3). However, as commod- 1500
and locked in capital programs will also ity prices are expected to increase and
While fiscal parameters such as depre- influence government take. From a gov- the balance between revenue and cost
ciation and royalties can cause distor- ernment perspective, 2020 is potentially improves, so will also expected govern-
tions versus the observed free cash flow the worst year since at least 2012 with ment take towards 2021 and onwards.
1000
The rebound by 2021 in free cash tinent. CNOOC is the sole exception tal to the health of these economies.
500
flow and government take described at 10th place, representing growing The African OPEC nations may soon
above is dependent on increasing Chinese interest in African resources. lose the capacity to produce at their
commodity prices in order to gen- desired levels if upstream operators
erate more revenue. For instance, The economies of the hydrocar- and international majors stop investing
scenarios where oil remains at $50/ bon-producing African nations are and delay the sanctioning of projects. 0
bbl or below implies that free cash heavily reliant on their respective out- While Angola or Gabon have been
flow and government take will be un- put to meet both domestic energy implementing a strong enabling envi-
Total
Sonagol
ExxonMobil
Shell
NOC (Libya)
ENI
Sonatrach
NNPC (Nigeria)
Chevron
CNOOC
able to reach 2019 levels. Figure 2.4 needs and exports. For example, Nige- ronment for their oil and gas investors
breaks down the expected 2021 free ria had previously set its 2020 capital in recent years, policy uncertainty and
cash flow per top 10 companies with budget based on its plans to produce in some cases the unchecked use by
activity in Africa. The list is dominated 2.1 million barrels per day of oil in 2020 African policy-makers of the oil & gas
by majors and national oil companies at a crude price of $57 per barrel. An sector as a cash cow could adversely
(NOCs), which is to be expected giv- extended period of the current price affect the continent’s production out-
en the player landscape on the con- scenario will therefore prove detrimen- look and competitiveness.
18 African Energy Chamber www.energychamber.org 1920
African Energy Outlook 2021 COVID-19 curbs free cash flow and government take but 2021 outlook improves
COVID-19 causes 2 000
unprecedented
Data Source: Rystad Energy research and analysis
0
-2 000
oil market turmoil
-2.4 -1.5
-2.0 -1.9
-2.2
-2.7
-4 000 -3.5 -3.1
-3.8
-4.5 -4.4
-6 000 -5.4
-5.9
-8 000 -7.0 Base Case Scenario
-7.7
-8.0 -8.2
-6.3
-10 000
-9.1
-10.0 Second Wave Scenario
High uncertainty around short- 2020 has been one of, if not the most, -12 000
term outlook for 2021 due to the volatile years in oil price history. The Jet fuel
COVID-19 pandemic has ravaged the -14 000
COVID-19 pandemic. -12.1 Maritime (bunkers)
global energy markets, and as such
-16 000 -10.6
Other fuels
global liquids demand that has typically
COVID-19 caused unprecedented increased by about 1 to 1.5 million bar- -18 000 Petrochemical (LPG and naphtha)
disruption in the oil market, exem- rels per day year-over-year, is current- Road diesel
-20 000
plified by reference prices trading ly expected to see an annual average
-17.2
Road gasoline
at negative values contraction of 10 million barrels per day -22 000 Previous
from 2019 to 2020.
Second wave scenario
-24 000
Reference prices recovery for The impact on average oil price per -23.2
2021 ($49/bbl) and 2022 ($70/ year is real, and best estimate projec-
Jan-20
Mar-20
May-20
Jul-20
Sep-20
Nov-20
Jan-21
Mar-21
May-21
Jul-21
Sep-21
Nov-21
bbl) expected to mimic global eco- tion towards 2025 do not expect the
nomic recovery $70/bbl threshold to be reached be-
fore 2022 (Figure 3.1).
Figure 3.1: Oil price outlook
Figure 3.2: Global oil products (liquids) demand forecast by scenario
Brent USD/bbl nominal
Million barrels per day
It was in particular April 2020 that saw un- At this rate of oversupply, the global stor-
precedented market turmoil as the full im- age capacity was rapidly filling up leading
$112B $109B $100B $54B $44B $55B $72B $64B $40B $49B $70B $66B $66B $68B
pact of various economies entering lock- to negative pricing for various reference
down, and thereby reducing demand, as prices. In particular, the negative West
well as OPEC and Russia increasing pro- Texas Intermediary price at -$37.63/bbl
duction, and thereby increasing supply, re- on 20 April 2020 will remain a testament
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
sulted in an oversupply situation of about to the extraordinary circumstances the
23 million barrels per day (Figure 3.2). market was subject to.
Data Source: UCube August 2020
20 African Energy Chamber www.energychamber.org 2122
African Energy Outlook 2021 COVID-19 curbs free cash flow and government take but 2021 outlook improves
Globally, suppliers responded to the tailments such as the oil sand produc- OPEC members Angola and Libya did Going forward towards 2021, there re- Should the demand outlook unfold similar downwards revision in oil price outlook,
oversupply situation and negative pric- tion in Canada. Overall, production was not face the same production cuts as mains high uncertainty around how the to the base view, the oil price is expect- but nevertheless an expectation that the
es by curtailing production. The big- reduced with about 12.5 million bpd the Angolan production is declining, virus outbreak will unfold, how economies ed to see a similar gradual increase. By price will remain north of $50/bbl. Figure
gest reduction came from OPEC+ that from March 2020 to June 2020. and Libya faces domestic unrest. will react and ultimately what the impact 2022, assuming the virus is under control 3.4 compares the communicated oil price
decided on a 9 million barrels per day will be on oil markets. Figure 3.3 illus- and normalcy has returned, there is a risk outlooks from the latest Q2 2020 updates.
production cut to help balance the mar- Africa was also impacted by the pro- The initial turmoil caused by COVID-19 trates a potential view of what can happen of spiking oil prices above $70/bbl as the For African nations, such price outlook will
ket, and to which several African OPEC duction cuts with up to 460,000 barrels stabilized over the summer months as should a second wave of COVID-19 mani- dearth of investments throughout 2020 notably call for much more competitive
and non-OPEC nations rallied. of oil per day (bopd) curtailed in May demand bounced back following lock- fest itself and see the reinstatement of the and 2021 may lead to a constrained sup- frameworks on deep water developments
and June 2020. OPEC members Alge- down measures being removed and draconian lockdowns from spring 2020. ply outlook. Beyond 2022, the expecta- and projects, which continue to represent
Also, other countries instituted govern- ria and Nigeria have faced the majority the supply being curtailed. The base view is a gradual increase in de- tion is for the oil price to stabilize around a substantial share of the continent’s pro-
ment mandated production cuts such of the production cuts with about 40 mand throughout the remainder of 2020 $60-65/bbl. Benchmarked versus the duction but are also the most expensive
as Norway while other countries saw percent each, followed by non-OPEC The Brent oil price subsequently increased and throughout 2021 to reach the pre- oil price expectations of leading E&Ps and most uneconomically feasible ven-
market forces forcing production cur- members Sudan and South Sudan. from sub $20/bbl to over $40/bbl. COVID-19 demand levels by late 2021. the general consensus appears to be a tures given this outlook.
Figure 3.3: Global liquids supply and demand balances | Current base case Figure 3.4: Long-term oil price assumptions vary widely across companies
Million barrels per day USD per barrel
History Forecast
25 100
$85
20 95 $80
Implied Stock Change Equinor | $80 (2030+)
Liquids supply (rhs)
$75
Products demands (rhs)
15 90
$70
$65
Woodside | $65 (2025+)
10 85
$60 Shell, ENI | $60 (2023+)
Repsol | $59.6 (2020 - 2050)
Total | $56.8 (2021 - 2050)
$55
5 80 BP | $55 (2021 - 2050)
$50
Petronas | $50 (2025+)
0 2 4 12 25 6 75 $45
-1 -1 -1 -1
2019-10
2019-11
2019-12
2020-01
2020-02
2020-03
2020-04
2020-05
2020-06
2020-07
2020-08
2020-09
2020-10
2020-11
2020-12
2020
2025
2030
2035
2040
2045
2050
Data Source: Rystad research and analysis; OilMarketCube Draws in June and July Data Source: Rystad research and analysis
helped support sturdy
oil prices in $40s
22 African Energy Chamber www.energychamber.org 2324 2021 to see a renewed push towards domestic gas monetization
African Energy Outlook 2021 as Global LNG glut continues to depress prices
2021 to see a renewed
push towards domestic gas
monetization as Global LNG Loose market due to new LNG capacity coming
on-line to prevail for a longer period.
glut continues to depress prices Peak in prices pushed back one year as san-
tioning of new liquefaction plants is postponed
Downside rish still expected towards
2026 as new supply come on line. How-
ever, the drop in prices is more limited
Depressed global gas prices and Over the last five years, the global sup- Gas markets are not insulated to COVID-19, Looking forward, expectations for the due to fewer projects being sanctioned.
ply and demand for gas has grown rap- but are less exposed than the oil market global market fundamentals are to re- 20
the ever-increasing demand for
idly. Demand has been spearheaded by as a result of COVID-19 curtailing trans- main loose through 2021 on the back
affordable power offer a unique
growth in North America and Asia while portation more than anything else. Gas is of weak COVID-19 induced demand
environment for Africa to push for supply growth has come from North less used in transportation, and as a result and continued high supply of LNG
further domestic gas monetization. America through the vast growth in hydro- less impacted by COVID-19. The gas mar- before prices tighten significantly as
carbon production from shale formations. ket was nevertheless already facing a glut LNG demand growth will outpace liq-
COVID-19 also caused gas demand 2017, 2018 and 2019 in particular saw of LNG even before COVID-19, resulting uefaction capacity due to more delays
disruption. While less prominent strong growth with an average growth in even more depressed prices as the in project sanctioning (Figure 4.2). The
of 170 billion cubic meters per year (Fig- pandemic’s impact on demand started to forecast points to a tight LNG balance
than for oil, it was nevertheless suf- 10
ure 4.1). However, global gas production manifest in the spring of 2020. between 2023 and 2025, and along
ficient to further depress prices. is expected to decline in 2020 on the with it, a price spike. Following this pe- Asia oil-index
back of production curtailments in North As a result, key reference prices in riod, there is a downside risk in prices NE Asia spot LNG
As a result, all major reference America and Russia. It will be the first Europe, North America and Asia all for 2026 and 2027 driven by the po- TTF
prices have converged as a glut of time since 2009 that global gas produc- have experienced negative pressure tential of seeing a new wave of sanc-
LNG has to be absorbed. tion experiences a decline. since the start of 2020. tioning activity during 2021 and 2022.
Henry Hub
200
Africa is expected to increase its
0
gas exports once big LNG facil-
ities are on-stream, ultimately
2010
2020
2030
2040
increasing African exposure to
global gas market. 100
Figure 4.2: Gas reference prices moving forward
USD per million Btu
Australia North America Data Source: GasMarketCube August 2020
Asia Europe 0
Middle East Russia
Africa Total
South America
-100
Figure 4.1: Global gas supply
growth by continent
Billion cubic meters
2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
Data Source: UCube August 2020
24 African Energy Chamber www.energychamber.org 2526
African Energy Outlook 2021 Only gas-friendly policies can further unlock Africa’s gas potential
Only gas-friendly policies
can further unlock Africa’s Figure 4.4: Estimated African gas flaring
Billion cubic meters
Nigeria
Algeria
Angola
Egypt
gas potential Data Source: UCube August 2020 Libya Other Countries
5
6
3 6 6 6
6 2 6 5
Domestic use of gas on the Afri- Given the gas glut on global markets 2025, gas production is expected to levels for the continent split on key 2
with corresponding depressed prices, accelerate on the back of big new de- countries. Overall flaring is expected to 3 3 3 2 2
can continent would have many 3 4 4 3
there may now be an opportunity to velopments in East Africa coming on- decline in line with the oil production, 3 4 3
positive benefits. Including: 3 3 3 4 2 2 2 3
stimulate to more domestic gas con- stream. Domestic gas consumption is but nevertheless represents significant 4 2
sumption. Expanding infrastructure to still not expected to follow this growth resources that could be utilized for in- 4 2 2 2 2 2
Minimize flaring and improve 6 4 3 2 4 2
displace diesel, increased use of gas in acceleration unless strong gas-friendly dustrial purposes for example. 2 4 2
carbon emission metrics for up- the power mix and gas for industrial pur- policies are adopted and result in the 3 3
stream production poses are all initiatives that would bene- expansion of African gas infrastruc- The African gas trade balance would 2 5 5 5
fit from the low cost of gas. ture, which implies increased exports shift should all the flared gas be uti- 5
5
Capture more value from the natu- towards 2030. Only sustained political lized (Figure 4.5). The gas could either 7 7
In this regard, Figure 4.3 illustrates ex- will, friendly legislation and strong indus- represent an uplift in domestic de- 8 8 8
ral resources for the local economy 8 8 7
pectations on production, demand and try support can unlock the true potential mand and maintain expected export 6 6 6 6 5
5
net export of gas from the African con- African gas can have within Africa. capacity, or it could represent addition-
Create more jobs and activity relat- tinent. Supply and demand have overall al export capacity in the case of fixed
ed to use of gas across industries experienced a similar pace of growth to A source of African gas currently not domestic demand. It would result in 9 9 8 8 7 8 7 7 6 6 6 6 6 5
maintain a net export capacity of about used is flared gas from oil production. a 13 percent uplift of demand or a 28
Improve project economics if the 100 billion cubic meters per year. Post Figure 4.4 illustrates estimated flaring percent uplift in net export capacity.
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
gas otherwise would be flared.
Data Source: UCube August 2020 Data Source: UCube August 2020
340
300
300
250
260 200
150
220
100
180 50
140 0
-50
100
-100
60 -150
2010
2014
2016
2018
2020
2022
2024
2026
2028
2030
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
Figure 4.3: Africa gas net gas Gas Demand Base Case Figure 4.5: Potential Africa gas net gas production Gas Demand Base Case Flaring add to production
production balance Gas Production balance with flaring included Gas Production Extra export capacity
Billion cubic meters Net Gas Import Billion cubic meters Net Gas Import Extra domestic demand
26 African Energy Chamber www.energychamber.org 2728
African Energy Outlook 2021 COVID-19 capex cuts expected to impact drilling activity in 2021
COVID-19 capex cuts
expected to impact
drilling activity in 2021
19’s impact on global and African energy the number of wells hovering around
supply. The current estimate points to only 700 per year. By 2024, as a result of
about 800 wells to be drilled, represent- new projects being sanctioned for de-
Drilling activity expected to ing a year over year decline of about 20 velopment on the back of a higher oil
fall below 800 wells per year percent versus 2019 Beyond 2020, there price, activity is expected to increase
in 2021 versus the 966 wells is limited respite expected until 2024 with again towards 800 wells per year.
Figure 5.1: Estimated number
drilled in 2019 pre-COVID-19 Limited Outlook of wells drilled in Africa
Offshore rig demand expected to Data Source: WellCube August 2020
drop year-on-year in 2020 by 30 Wells drilled on the African continent
percent with 2021 expected to and its continental shelves ultimate-
experience a slight increase from ly represent the activity that ensures 1.8K
hydrocarbon recovery from its under-
2020, spelling out a tough environ-
ground deposits. An estimated 1,850 1.6K
ment for drilling service providers wells were drilled during 2012 with
Offshore
1.4K
about 1,350 or 73 percent drilled on-
High impact exploration drilling shore and the remaining 500 or 27 per- 1.2K
may create new opportunities cent drilled offshore (Figure 5.1).
1K
that can drive drilling demand
The trend since 2012 has been a de-
on a mid-term basis 0.8K
clining number of wells drilled per year,
and in particular since the oil price drop 0.6K
Overall environment favorable Onshore
in late 2014 which exacerbated this
for increased local procurement trend. As a result, the 2019 estimate of 0.4K
of goods and services to cut cost. wells drilled was almost 1,000, a drop
0.2K
of about 45 percent in activity versus
2012. Reduced drilling activity onshore 0
Libya and Egypt are the main drivers
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2024
behind this decline.
Going into 2020, the activity is expected
to decline further as a result of COVID-
28 African Energy Chamber www.energychamber.org 2930
African Energy Outlook 2021 COVID-19 capex cuts expected to impact drilling activity in 2021
However, from 2022 onwards the expec- tential of these new projects and fur- In that regard, Figure 5.4 provides the
tation is for rig demand to rebound slight- ther exploration activity will be able to breakdown of the top 10 countries by
ly as drilling programs associated with increase demand towards its highest rig demand with associated split on
projects currently under development level since 2015. However, should the what resource class is supporting the
are initiated and a higher oil price expec- oil price not recover, it would jeopar- rig demand. For Angola, about 35 per-
tation help revive exploration activity. dize about 50 percent of the expected cent of the demand is related to con-
2025 rig demand. tingent resources which means that rig
However, the expected growth to- demand in this particular area is sensi-
wards 50 rig years in 2025 is obvious- Breaking down cumulative offshore tive to investment decisions expected
ly contingent on new projects being rig demand from 2020 to 2025 per over the next years. Ghana also has a
sanctioned (Figure 5.3). Based on the country reveals Egypt as the most ac- large share of contingent demand on
oil price outlook presented under the tive country in Africa with almost 60 rig the back of the big Pecan project that
oil market section, the combined po- years, followed by Angola and Nigeria. may be sanctioned for development.
Figure 5.3: Offshore rig demand evolution per life cycle
Rig years Data Source: RigCube August 2020
Offshore Rig Demand 80
70
60
Data Source: RigCube August 2020 Exploration rig demand
The number and type of wells can be 90
translated into rig demand expecta- 50
tions. In other words, how many drilling 40
80
rigs have to be operational for a year in
order to drill the wells. Figure 5.2 illus- 30 Contingent
trates the offshore rig demand split by resources
70 20 rig demand
jack-ups and floaters. Jack-ups are typ-
ically used in shallow water with water 10
60 Reserves rig demand
depth up to 125 meters while floaters
0
serve drilling demand in deeper waters.
2013
2012
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
50
From a high level of demand in 2012 to
2014 of about 80 rig years, the late 2014
40
oil price collapse reduced drilling de- 40
40
40
mand significantly. By 2018, demand was Figure 5.4: Cumulative offshore rig demand 2020-2025 per country Exploration Rig Demand
down to 35 rig years implying a reduction Rig years Contingent Resources rig demand
of 56%. 2019 was in that respect a more 30
Reserves rig demand
33
50
promising year as demand increased
26
towards 45 rig years, representing an in- 20
22
28
26
crease of almost 30 percent. 40
20
19
22
20
16
At the start of 2020, the demand was 10 30
18
not expected to decline towards and
below 2018 levels again, but the ex-
30
46
20
24
16
16
19
15
41
41
14
21
11
0 20
9
traordinary impact of COVID-19 means
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
that estimates for 2020 and 2021 are
2023
2024
2025
pointing to record low rig demand of 10
less than 30 rig years. It is in particu-
lar floating rigs that will be impacted by Figure 5.2: Offshore rig demand evolution Floater
0
lower demand versus the 2019 actuals. Rig years Jackup
Egypt Angola Nigeria Gabon Ghana Mozambique Libya Senegal Congo Namibia
Data Source: RigCube August 2020
30 African Energy Chamber www.energychamber.org 3132
African Energy Outlook 2021 COVID-19 capex cuts expected to impact drilling activity in 2021
Figure 5.5: High impact wells in
South West Africa
DRC
South West Africa Ondjaba-1
Angola
Graff
Namibia
Exploration
Total (50%), Sonangol (50%) Shell (45%), Kosmos (45%),
Namcor (10%)
ANGOLA
The southwestern coast of Africa, in- the trigger to extend West African Kaombo area well in 3600 meters water depth
cluding Namibia and South Africa, is offshore petroleum activity further Graff prospect4
Lower Congo basin
home to perhaps the most anticipat- south from Angola. Finally, the follow
Play opener potential Cretaceous fan, Orange basin
ZAMBIA
ed wildcats in 2020 and 2021 global- up activity to the breakthrough 2019
ly. The prospects, if successful, could Brulpadda discovery in South Africa
open new basins for development has commenced in the second half Osprey Gazania-1
and trigger big new investments to- of 2020 with the Luiperd prospect, Namibia South Africa
wards the latter half of the 2020s. where a significant gas discovery
was made in Q4 2020. Eco Atlantic (57.5%), Azinam (32.5%) Africa Energy (90%), Crown Energy (10%)
High impact wells have been com- Namcor (10%)
municated by various participants Total is here hoping to find more liq-
Gazania prospect3
from Angola all the way down to uids and confirm the South African
South Africa (Figure 5.5). French ma-
jor Total is in the driving seat of this
offshore resource potential to further
support a development agenda to-
Osprey prospect2
Albian toe of slope fan, Walvis basin
Fluvio-deltaic interbedded sand,
Orange basin BOTSWANA
exploration where high impact and wards the latter half of the decade. 800 MMboe potential 350 MMboe potential
record setting wells will be drilled
in those waters. In Angola, the well Other companies have also com-
NAMIBIA
Aurora-1X Wolf
planned in block 48 will be the deep- municated their intention to drill in
Namibia South Africa
est on record in terms of water depth the area with the Orange Basin on
measuring about 3,600 meters. The the border between Namibia and
Venus prospect in Namibia has per- South Africa as the most activity Maurel & Prom (42.5%), Maurel & Prom (42.5%),
haps the biggest impact potential as area, and by extension, presum- Azinam (42.5%), Namcor (8%), Azinam (42.5%), Namcor (8%),
its size and remote location can be able also the most promising area. Livingstone (4%), Frontier (3%) Livingstone (4%), Frontier (3%)
High impact well reason Aurora prospect2 Aurora prospect2
Albian sand fan and Cenomanian-Conia- Albian sand fan and Cenomanian-Conia-
Frontier basin: cian slope channel, Walvis basin cian slope channel, Walvis basin
The basin with little or no exploration >1000 MMboe potential >1000 MMboe potential
SOUTH
Large prospective resources:
Venus Luiperd-1
The pre-drill estimates by the company are quite significant. Namibia South Africa
Focus for Company:
The wells which are highly talked and strategically important for companies. Total (40%), QP (30%), Impact (20%), Total (45%), Qatar Petroleum (25%), AFRICA
Namcor (10%) CNRL (20%)
Emerging Basin:
The basins where some significant recent exploration has taken place. Venus prospect3 Luiperd & Blassop prospects2
Cretaceous fan, Orange basin M. Cretaceous submarine fan,
Play Opening: Outeniqua Basin
1000 MMboe potential
The well targeting a new play or area within the province or basin. 50% bigger than Brulpadda
Data Source: Rystad research and analysis
32 African Energy Chamber www.energychamber.org 3334 2020’s 30% CAPEX drop expected to be recovered
African Energy Outlook 2021 in 2022 on the back of mega LNG projects
2020’s 30% CAPEX drop
expected to be recovered
in 2022 on the back of Figure 6.1: African upstream capital expenditure
mega LNG projects
Billion USD nominal Data Source: UCube August 2020
70
60
1
1
50
Upstream investments expected
2
to fall below $30 billion in 2020
and 2021 $80bn can be unlocked by 40
Rebound in investments can be 2025 pending market conditions
2
strong, but depends on projects to and policy reforms
3
5
be sanctioned in particular related 30
8
15
to the East African LNG facilities
1
1
27
30
Investments are required to convert re- Such pre-FID expenditures represent
Most service segments expect- sources in the ground to revenue and val- about 33 percent of CAPEX expected 20
4
12
6
9
ed to see a decline in market size ue. The investments represent jobs and during the next five years. This remains
9
11
with the exception of EPCI ben- business for a plethora of African service a heavy share of uncertain spending, and
providers and is therefore an important one that could translate into jobs and lo-
efitting from mega LNG projects.
metric to the wider activity level around cal content growth if approved. Put sim- 10
the oil and gas industry. From 2020 to ply, African regulators, policy-makers and
2025, up to $80bn of capital expenditure governments have the power to unlock
2 58
2 63
2 51
(CAPEX) remains contingent and is pend- an additional $80bn of investment by
1 56
1 46
1 29
20
34
0
37
18
19
19
19
17
ing the taking of FID on new projects from 2025 if the right measures are taken and
discovered fields (Figure 6.1). the right policies are put in place.
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
Abandoned Producing Under Developement Discovery Undiscovered
34 African Energy Chamber www.energychamber.org 3536 2020’s 30% CAPEX drop expected to be recovered
African Energy Outlook 2021 in 2022 on the back of mega LNG projects
Many global E&P players, including 2020 by 30 percent with no plans for a to external influences such as export Figure 6.3: Impact of Covid-19 and price crash
the international majors, are looking at rebound in 2021. Kosmos seeks to be- route disagreements and fiscal parame- Offshore, especially deepwater projects taking the brunt of CAPEX cuts
significant cuts to their capital spend- come cash-flow neutral in a $35/bbl oil ters. Going into 2020, the expenditure Million USD Data Source: Rystad Energy UCube
ing and operational expenditure. To- price environment. Tullow has also re- is expected to drop to below $30 billion
tal slashed its 2020 exploration and duced its investment budget by about representing an almost 30 percent drop Before COVID-19 After COVID-19
production budget by up to $2.5 bil- a third this year and cut its exploration versus 2019. The impact of COVID-19 is
lion and targets $800 million in sav- spending by almost half to weather the the main factor as it has deferred FID on 60K
ings in operating costs. The French oil price storm. many projects (Figure 6.2).
major will also suspend its previously
announced $2 billion buyback pro- From the peak in 2014 at about $65 Moreover, expensive deep-water 50K
gram, and the other majors are doing billion, CAPEX in Africa has steadily projects are most prone to the re-
the same. Independents with a strong declined to under $40 billion by 2019. duced outlook on investments (Figure
40K
presence in Africa like Kosmos Energy This decline is a result of lower activity 6.3), a key factor to take into account
(Kosmos) and Tullow Oil (Tullow) have from new projects, general cost com- given that the largest discoveries and
also reviewed their 2020 spending pression in the industry and friction in prospects on Africa’s Atlantic coast
30K
plans. Kosmos has cut its CAPEX in getting new projects sanctioned due are in deep water acreages.
20K
Figure 6.2: Impact of Covid-19 and price crash
Reduced sanctioning and delayed greenfield spending 10K
Million USD Data Source: Rystad Energy UCube
0
Before COVID-19 After COVID-19 2020 2021 2022 2023 2024 2025 2020 2021 2022 2023 2024 2025
60K Producing Under Developement Pre-FID
50K
The deferred projects and the projects Figure 6.4: Investment outlook sensitivity based on oil price
40K
originally slated for investments from Million USD Nominal
2022 onwards will together have the
potential to contribute to a significant
30K
growth potential. Should the projects 60K
Economics Mid Case
materialize, the potential cumulative ex-
20K penditure may increase to above $50
billion by 2024. 50K Economics Low Case
10K However, as Figure 6.4 illustrates, lower
oil price expectations may shave of the 40K
Economics Low Low Case
0 growth potential as projects are not com-
mercially viable and/or further deferred. Economics
2020 2021 2022 2023 2024 2025 2020 2021 2022 2023 2024 2025 With the oil price at $50/bbl, investments 30K
are expected to only barely rebound in
Producing Under Developement Pre-FID real terms to 2019 levels by 2024. 2019 2020 2021 2022 2023 2024 2025
Data Source: UCube August 2020
36 African Energy Chamber www.energychamber.org 3738 2020’s 30% CAPEX drop expected to be recovered
African Energy Outlook 2021 in 2022 on the back of mega LNG projects
20
18
16 Subsea Tiebacks and LNG Projects Remain
14
Pillars of Future Industry Spending
12
Out of all contingent projects yet developments further boosts this be amongst the last big conventional
10
to make FID between 2020 and category in light of the mega-proj- onshore projects in the world.
2025, investments related to sub- ects expected in Mozambique.
8 sea tiebacks is the single great- The third biggest category of upcom-
est category, reaching almost $20 The second biggest category is all in- ing projects, at almost $15 billion, re-
billion across the period (Figure vestments related to onshore produc- lates to investments in onshore LNG
6
6.5). Subsea tiebacks are likely to tion. Continued drilling of new wells facilities. It is in particular the East
be more and more common as it and other improvements are needed African gas resources that is likely to
Onshore LNG plant
4 makes commercial sense to pig- to arrest production decline in the ma- trigger these investments. In terms
Fixed and floater
Subsea tie back
Other concepts
Steel platform
gyback smaller hydrocarbon accu- ture areas of African onshore produc- of resource size, these projects are
mulations on existing infrastructure. tion. Big investments are also expect- the biggest and most important in
2
Onshore
The breakeven therefore achieved ed in Uganda and Kenya related to Africa, and they will also help bring
FLNG
FPSO
from such a development solution the greenfield onshore development activity to a part of Africa that previ-
0 is typically also very competitive. of Lake Albert and the Lokichar Basin. ously had not seen much hydrocar-
The offshore-related part of LNG Such greenfield developments may bons-related developments.
Figure 6.5: Contingent investment spending per project type
Billion USD Nominal
Data Source: UCube August 2020
38 African Energy Chamber www.energychamber.org 3940 2020’s 30% CAPEX drop expected to be recovered
African Energy Outlook 2021 in 2022 on the back of mega LNG projects
Out of upcoming major projects in Africa, In its latest announcement, Shell dis- (Rovuma LNG), which was to be sanc- Figure 6.7: Upcoming Natural gas projects in Africa and their timeline and recoverable reserves estimates
the top six gas projects are all bigger in tanced itself from deep-water mega-proj- tioned this year, has now spilled over
terms of oil equivalents than the oil proj- ects off the coast of Nigeria, placing the to 2021 at best. The Ahmeyim and Ya-
ects (Figures 6.6 and 6.7). Taking into Bonga Southwest-Aparo, a 150,000 bpd kaar gas hubs off the coast of Maurita- Project Country Operator FID* Start-Up Resources (MMboe)
account all cumulative investments per FPSO development that was soon com- nia and Senegal and a few other nat-
MZLNG Joint Development (T1 - T2) Mozambique ExxonMobil 2025 2030 4625
country, Mozambique remains in clear ing up for FID, on the backburner for now. ural gas projects in the northern and
lead which further emphasizes how im- Tullow is expected to delay the South Lo- eastern regions of the African conti- Area 1 LNG (T1 - T2) Mozambique Total 2019 2025 3590
portant the LNG projects are for the Afri- kichar development off Kenya. nent may have their FIDs postponed to Area 4 LNG (T1 - T2) Mozambique ExxonMobil 2022 2026 2330
can investment outlook (Figure 6.8). 2022–2023 as part of Kosmos’s plans
The Palas-Astraea-Juno (PAJ) margin- to trim down its capital expenses. Yakaar - Teranga LNG Hub Senegal BP 2027 2032 2145
The majority of the projects in Africa that al fields development operated by BP NLNG Seven Plus Nigeria Shell 2019 2025 1450
were up for sanctioning were planned in Angola is another project that could The investments for the above projects
Greater Tortue Ahmeyim LNG Hub Mauritania BP 2024 2028 1480
assuming an oil price of between $55 see delays due to a relatively high will now see a timeline shift or even a
and $60/bbl. The oil price currently hov- breakeven price and BP’s commit- spending cut altogether, which will ul- Poly GCL
ering around $40/bbl therefore spells bad ments to other parts of the world and timately impact production levels in Petroleum
Djibouti FLNG T1 Ethiopia 2022 2025 520
Investment
news, especially as the top upcoming FIDs to the energy transition. this region. Current estimate is that the
Ltd
in Africa have a breakeven crude price of timeline delays for these pre-FID proj-
Assa North Nigeria Shell 2025 2028 415
over $45/bbl, with some even close to Upcoming gas projects will also take ects in Africa could lead to a 200,000
$60/bbl. ENI and ExxonMobil have both a hit and run a risk of delays. Although bpd drop in liquids production on aver- Tinrhert Gas Project Algeria Sonatrach 2023 2025 385
stated that they will focus on developing Nigeria approved the development of age between 2021 and 2025. Equatorial
projects with a breakeven crude price NLNG train 7 last year, the upstream Fortuna FLNG Lukoil 2025 2029 250
Guinea
of less than $35/bbl. The ENI-operated gas developments that were planned The impact could be much higher in the
Quiluma/ Maboqueiro 250
Agogo full field development off Ango- to supply feedgas to this development longer term, with liquids production set Angola Eni 2021 2024
(Northern Gas Complex)
la now faces getting delayed due to its might now take a back seat. The FID for to drop on average by close to 1.185 mil- 215
Yakaar (domestic) Senegal BP 2023 2025
breakeven price of $45/bbl. the Area 4 LNG project in Mozambique lion bpd over the years 2026 to 2030.
HA Nigeria Shell 2022 2026 210
Ima gas Nigeria AMNI 2023 2028 185
Figure 6.6: Upcoming Liquids projects in Africa and their timeline and recoverable reserves estimates Sanha Lean Gas Angola Chevron 2023 2026 115
Project Country Operator FID* Start-Up Resources (MMboe) Data Source: Rystad Energy UCube Liquids Gas
Tilenga Uganda Total 2022 2025 945
Bosi Nigeria ExxonMobil 2025 2029 790 Figure 6.8: Contingent invest- Other Countries
25%
700
ment spending per country
Bonga North Nigeria Shell 2026 2031 Billion USD Nominal Mozambique
Bonga Southwest | Aparo Nigeria Shell 2024 2028 630 23%
Owowo West Nigeria ExxonMobil 2024 2027 550
Etan | Zabazaba Nigeria Eni 2028 2032 520
Pecan Ghana Aker Energy 2022 2025 335
Chissonga Angola Total 2024 2029 290
Kingfisher South Uganda CNOOC 2022 2025 270
Agogo FFD Angola Eni 2022 2025 245
Algeria
220 5%
SNE Senegal Woodside 2020 2023
Nigeria
South Lokichar Phase 1 Kenya Tullow Oil 2023 2025 220
Uganda 15%
Egina South | Preowei Nigeria Total 2023 2026 190 5%
Palas | Astraea | Juno (PAJ) Angola BP 2022 2025 140
Libya
Alho | Cominhos, Cominhos East (ACCE) Angola Total 2023 2027 85
8%
Angola
Data Source: Rystad Energy UCube Liquids Gas Ghana
11%
Data Source: UCube August 2020 9%
40 African Energy Chamber www.energychamber.org 4142 2020’s 30% CAPEX drop expected to be recovered
African Energy Outlook 2021 in 2022 on the back of mega LNG projects
Figure 6.10: Cumulative capital expenditure per period
Billion USD Nominal
Services sector impact 80 Data Source: UCube August 2020
With the CAPEX and expected type As a result, EPCI is the only segment from high activity and high contract rates 70
of projects defined, it is possible to expected to buck the trend of declining from 2010 to 2014 while subsequent years
forecast opportunities offered to the expenditure on the back of the LNG facil- saw a reduction in both activity and rates.
services industry. EPCI companies are ities expected to be constructed towards The segment is also adversely impacted 60
expected to benefit the most from fu- 2025 (Figure 6.10). The relative worst per- by the large share of gas developments
ture spending (Figure 6.9), followed forming sector across the periods is drill- towards 2025 as gas projects are a lot
by well services contractors. ing contractors. This segment benefited less drilling intensive than oil projects. 50
2010-2014
2015-2019
40 2020-2024
Figure 6.9: African upstream capital expenditure per service segment
Billion USD Nominal 30
20
60 Data Source: UCube August 2020
10
50
0
EPCI Well Services & Internal & Subsea Maintenance & Drilling Seismic
Commodities other Operations Contractors
40
30
20
EPCI
Well Services and Commodities
Internal and other
10
Subsea
Maintenance and Operations
Drilling Contractors
0 Seismic
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
42 African Energy Chamber www.energychamber.org 4344 New market realities for 2021 expected to drive
African Energy Outlook 2021 reviews of fiscal terms to improve competitiveness
New market realities for
With better fiscal regimes, Africa could unlock $100bn in
2021 expected to drive investment and 1 million bpd in additional output by 2030
reviews of fiscal terms to
improve competitiveness
To investigate the potential on African regime, regarded as one of the most breakeven higher than the threshold
production and investments from al- favorable globally. will not be allowed to reach production.
tering fiscal regimes, a simulation has The difference between the $35/bbl
been made whereby all projects with Figure 7.1 illustrates African liquids pro- threshold and the $50/bbl threshold is
an expected FID by 2026 are subject duction towards 2030 under different therefore all projects that can contrib-
to both their original fiscal regime as breakeven thresholds. The thresholds ute with production with a breakeven
Projected market conditions for
well as the United Kingdom’s (UK) fiscal imply that any pre-FID project with a between $35 and $50 /bbl.
2021 do not indicate a return to
high commodity prices, implying The end of the
that the super profit era of petro-
leum is over. super-profit era?
The industry cost base has been
Petroleum resources and the extraordi- haps even more important than the ac- Figure 7.1: African liquids production at different BE cutoffs
adjusted, but African fiscal re- Million bbls/day
nary profit they have typically generated tual resource base created by nature, in
gimes are often lagging behind
in the past have resulted in various fiscal terms of influencing the FID of a new proj-
and remain uncompetitive in this 10K
regimes. The fiscal regimes are designed ect. When the oil price was above $100/
new environment. in some way or another to ensure that bbl, these fiscal regime rules could be fa-
part of this profit is collected by the state. vorable towards the state as the breakev-
Many African governments will take Depending on the rules of the fiscal re- en would in any case be low enough to
steps to adjust the fiscal regimes in gime, there might be impacts on the in- secure an investment decision. However,
vestment metrics used by private compa- with an oil price at $50/bbl and below,
2021 to improve competitiveness.
nies on executing new projects. the surplus that can be distributed is like-
ly much smaller. From a post-tax point
Using a UK-type fiscal regime A common example of such a metric is of view, it may then be difficult to justify 5K
can help unlock $100 billion in- breakeven, or what revenue is required, new investments as the fiscal regime is
vestments in a $50/bbl scenario. as a function of quantity and price, to too strict to make the project commercial-
cover all cost, pay all government take ly viable even if the intrinsic value of the
and generate sufficient return. Ideally this resource base would otherwise imply so.
breakeven should be as low as possible
to improve the likelihood of the project The result is therefore a pressure on cost
generating positive financial returns. compression in fiscal terms similar to
what the industry has experienced with 0
As such, the rules and parameters of the investments and operational expenditure
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
fiscal regime is often very important, per- in order to unlock new potential projects.
Data Source: UCube
44 African Energy Chamber www.energychamber.org 45You can also read
