Africa Energy Outlook 2021
A Year Like No Other
2020 has been a year of unprecedented challenges, and the trials and tribulations have made the African Energy Chamber’s work more important now than ever. We are committed to helping Africa’s oil and gas stakeholders navigate a complex and ever-changing global energy landscape. We will continue our mission to support the dynamic private sector and unlock the continent’s remarkable energy potential.
Africa’s oil and gas industry is facing extraordinary circumstances. An ongoing energy transition and new efforts to decarbonize the world are weighing on oil demand. The shale revolution is exacerbating these pressures. And of course, the COVID-19 pandemic has wrought havoc on markets around the world, accelerating and intensifying existing trends. External headwinds are forcing African petroleum producers to re-examine their strategies. Conventional petroleum resources here should be globally competitive, but growth has lagged because of conditions above the ground, not below. Restrictive fiscal regimes, inefficient and carbon-intensive production and difficulties in doing business are preventing the industry from reaching its full potential.
As companies delay projects and cut costs, planned capital expenditure in 2020-2021 has fallen from $90 billion pre-COVID-19 to $60 billion now. To remain competitive, African producers and governments must adapt. But how can they do it when the economic order is being remade?
We have to cut red tape to make life easier for hard-working Africans, businesses and investors to work and grow the energy sector. We know from experience this will reduce the cost of doing business, speed up approvals and make life better for Africans. We must never be ashamed of supporting an industry that has brought so much to Africa and will continue to bring people out of poverty and reduce reliance on foreign aid.
In 2021, Africa will benefit greatly if we create an investment climate that supports the development of all energy resources. At the African Energy Chamber, we believe supporting the energy industry, promoting free markets, the rule of law, individual freedoms and limited government, is a duty for all Africans.
But we must not stop there, advocating for a market-driven Afro-centric energy transition, with a specific focus on natural gas to expand market opportunities is something we will continue to drive. The oil and gas industry is a force for good and we must not join those forces that want to demonize hardworking people whose only crime is to work hard and play by the rules and embrace hope rather than fear-mongering and embrace economic empowerment rather than development aid. That’s why we believe implementing programs like local content, economic diversification that support natural gas value chains, making fiscal terms competitive and reducing red tape and streamlining regulatory processes must be priorities in 2021.
Our African Energy Outlook 2021 addresses these challenges head-on. Building on last year’s success, our second annual report offers an even more exhaustive and comprehensive look to the year ahead for African oil and gas.
The 2021 outlook details all of the major challenges facing African oil and gas stakeholders, as well as workable solutions that will keep the industry on a strong and stable growth path. We believe the short-term outlook will improve if countries apply more competitive fiscal regimes. Emissions can be reduced by curbing flaring and monetizing gas, improving and future-proofing the carbon profile of African petroleum production.
Developing gas-to-power infrastructure will increase access to affordable energy for all sectors of the economy, offering massive knock-on benefits and making it easier to do business. Reducing lead times to limit risk premiums put on long-cycle projects will further bolster the industry’s viability and growth prospects. It will not be easy, but these reforms are necessary.
Again and again, our oil and gas sector has proven its resilience and adaptability. The world still needs oil and gas, and Africa still holds enormous untapped potential. The African Energy Chamber will remain a committed partner of choice for the industry as we advance into an uncertain future.
African Energy Chamber
High level take aways
Time to act!
The global energy transition and decarbonization drive are putting pressure on oil demand while shale has unlocked abundant resources. The global context forces African petroleum producers to adapt or become uncompetitive.
The coronavirus pandemic (COVID-19) has accelerated this underlying pressure by causing unprecedented havoc on global energy markets that Africa is not insulated from.
Conventional petroleum resources such as those in Africa should be competitive in the global supply stack,
but above surface conditions related to fiscal regimes, carbon emissions and general difficulty of doing business are holding projects back.
The CAPEX spending 2020 – 2021outlook pre-COVID-19 was almost$90 billion for 2020 and 2021 but has been significantly reduced to about $60 billion due to project delays and cost-cutting measures.
The 2021 outlook, therefore, appears weak on new project sanctions, but relatively stronger for jobs and drilling markets on the back of ongoing projects initiated pre-COVID-19.
The impact of COVID-19 on 2021liquids production is however not so severe as the current 2021 outlook stands at about 7.6 million barrels per day compared to 8.2 million barrels per day in the beginning of the year.
Outside COVID-19, regulatory matters have also unnecessarily delayed major projects in Nigeria, Kenya, Uganda and Tanzania that represent big opportunity losses for local content development, delayed job creation and further deteriorated Africa’s competitive position versus resources elsewhere.
The African Energy Chamber believes that the short-term outlook can be remedied by:
Applying more competitive fiscal regimes that can help unlock 4.4 billion barrels of liquids and $100 billion of additional investments by 2030.
Curbing flaring and monetizing gas, which will help improving the carbon emission profile of African petroleum production that currently bottom tier among the continents.
Developing gas to power infrastructure that will increase access to affordable energy to all sectors of the economy.
Reducing lead time as higher risk premiums are put on long-cycle projects versus short-cycle projects.
Gas to power push represents the most promising way to decarbonize the African upstream
Strong incentives to monetize African gas and create new demand centers, especially in promoting gas to power internally, will fasten the decarbonization of African upstream activities.
Africa to remain at least until 2025 the least carbon-efficient oil-producing frontier with over 30 kilogram CO2 emitted per barrel of oil equivalent produced.
Continued high carbon emission is a threat to Africa’s global competitiveness.
The energy transition forces more attention to carbon emissions to attract capital.
Africa must work harder on curbing flaring to remain an attractive arena for future hydrocarbons related investments.
As the world is moving towards the energy transition in order to curb greenhouse gas emissions and meet the targets in the Paris agreement, the oil and gas industry is doing its share. While combustion of hydrocarbons by off-takers and consumers does represent around 90%of total emissions, the remaining 10% is what oil and gas companies are targeting to cut through initiatives such as electrification, reduced flaring and more energy-efficient extraction methods. An often-used metric to determine hydrocarbon production’s carbon efficiency is to consider the amount of emissions outside combustion per unit of production. The lower this ratio is, the more efficient your production is.
While carbon efficiency used to be more of a corporate social responsibility (CSR) metric, the metric is now used increasingly in financial calculations and by global investors before they make investment decisions. The emission costs increasing as a function of limited carbon emission budget in order to stay within the globally-stated temperature increase target, and as such any expensive hydrocarbon production with high emissions are generally considered to be the first in line to be curtailed. Capital is therefore facing higher and higher premiums to be deployed in carbon inefficient hydrocarbon production, and it is therefore increasingly important to help minimize emissions in order to have a competitive project. Unfortunately, Africa continues to operate carboninefficient production, which further impacts its ability to raise capital for oil and gas projects.
A data base has been built on the back of all knowledge about emissions and the type of hydrocarbon production (onshore, offshore, oil type etc.) in order to have a view of carbon efficiency globally. This is illustrated on Figure 1.1 where the sum of each continent’s upstream production and upstream emissions from2018 are compared to each other.
While Africa benefits from conventional and easy to extract hydrocarbons, the inability to prevent gas flaring nevertheless catapults the continent to the overall least carbon efficient continent at about 31kg CO2 emitted per barrel of oil equivalent produced. European production as a comparison is rather similar to African production in terms of extraction emissions but has easier and more cost-efficient methods to handle associated gas than flaring on the back of a big demand center that can create value from gas.
Figure 1.2 breaks down the top 20 oil producers globally on how much flaring represents in terms of emissions versus the emission from the extraction process. Ideally, the flaring component is as small as possible. Of four African countries on the list (Algeria, Libya, Nigeria and Angola) none of the countries are in the upper half with Angola as the best performer of the group. It is primarily the North African countries Algeria and Libya that have poor performance with regards to flaring emissions.
2018 is currently the last year with high quality data, but projections towards 2025 nevertheless point to Africa overall not improving its position with emissions remaining above 30 kg CO2 per barrel of oil equivalent. While flaring is upstream emissions are not always easy to reduce, it nevertheless does represent an enormous opportunity for Africa to reduce its carbon emission per production unit and thereby increase the resources’ competitiveness in a world with increasingly constrained carbon emission budget. In this context, political will and industry compliance will be key. Initiatives such as the Nigerian Gas Flare Commercialization Program are extremely positive steps in that direction and must be encouraged and supported by all stakeholders.
COVID-19 curbs free cash flow and government take but 2021 outlook improves
Generated free cash flow and government take is expected to decline by north of 50% in 2020 from approximately $10/ boe nominal in 2019 to $4/boe nominal in 2020.
Improved outlook for 2021 at $6/boe nominal on the back of curbed expenditure and higher commodity prices.
Continued impact of COVID-19 on demand and commodity prices will be crucial to short-term forecast and expectations
The goal of any project within the oil and gas world is to create value by generating sufficient revenue to recuperate all cost and generate sufficient free cash flow to justify the required rate of return. Multiple parameters influence the free cash flow generation, but chief among them is commodity prices that determine how much revenue is generated. As projects are evolving through their life cycles at different points in time, the sum of all cash flows across all projects create trends. Versus other continents, Australia has and is expected to generate on average the highest free cash flow per barrel of oil equivalent from 2018 to 2025 (Figure2.1). African performance is however in line with other continents and exhibits similar volatility on the back of the industry’s typical boom and bust cycles.
Analyzing free cash flow from all African projects, one notices that 2012 and 2013 remain some of the most profitable years in history on the back of high commodity prices and capital programs ramping up (Figure 2.2).
In 2014, the commodity prices started to decline to thereby decrease free cash flow generation, but more impactful were the numerous giant projects initiated from 2012 to 2014 that represented enormous capital expenditure. It was these locked-in capital programs, together with the drop in commodity prices, that caused free cash flow generation to be highly constrained during 2015 and 2016.
From 2017 onwards, the capital programs were completed, the projects started to produce and generate revenue, and commodity prices increased. The result was an improving free cash flow that grew to $55 billion in 2018. The industry had effectively responded to the commodity price shock in 2014 and rebalanced spending and revenue to be more sustainable than what was the case in 2015 and 2016.
Under normal circumstances, this new balance was expected to continue, but the impact of COVID-19 has created many similarities to 2015 and2016 whereby free cash flow will be squeezed on the back of reduced revenue and locked in capital programs. As such, the industry will once again have to rebalance its spending and revenue which typically implies curbing exploration activity and deferring new investment decisions. While 2020 free cash flow is not expected to decline towards the same depth as during 2015 and2016, the spend curtailment and expected higher commodity prices are anticipated to create a rebound into 2021. With more free cash flow generated in 2021, the scene is set for a new cycle of investments with activity picking up for deferred projects and exploration activity. For the same reason, we can expect most key final investment decisions (FID) on African projects to be taken in 2021.
While fiscal parameters such as depreciation and royalties can cause distortions versus the observed free cash flow generated for companies, the general relationship between commodity prices and locked in capital programs will also influence the government take. From a government perspective, 2020 is potentially the worst year since at least 2012 with only about $55 billion in government take (Figure 2.3). However, as commodity prices are expected to increase and the balance between revenue and cost improves, so will also expected government take towards 2021 and onwards.
The rebound by 2021 in free cashflow and government take described above is dependent on increasing commodity prices in order to generate more revenue. For instance, scenarios, where oil remains at $50/ bbl or below, implies that free cash flow and government take will be unable to reach 2019 levels. Figure 2.4breaks down the expected 2021 free cash flow per top 10 companies with activity in Africa. The list is dominated by majors and national oil companies (NOCs), which is to be expected given the player landscape on the continent.CNOOC is the sole exception 10th place, representing growing Chinese interest in African resources.
The economies of the hydrocarbon-producing African nations are heavily reliant on their respective output to meet both domestic energy needs and exports. For example, Nigeria had previously set its 2020 capital budget based on its plans to produce 2.1 million barrels per day of oil in 2020 at a crude price of $57 per barrel. An extended period of the current price scenario will therefore prove detrimental to the health of these economies. The African OPEC nations may soon lose the capacity to produce at their desired levels if upstream operators and international majors stop investing and delay the sanctioning of projects. While Angola or Gabon have been implementing a strong enabling environment for their oil and gas investors in recent years, policy uncertainty and in some cases the unchecked use by African policy-makers of the oil & gas sector as a cash cow could adversely affect the continent’s production outlook and competitiveness.
COVID-19 curbs free cash flow and government take but 2021 outlook improves
High uncertainty around shortterm outlook for 2021 due to the COVID-19 pandemic.
COVID-19 caused unprecedented disruption in the oil market, exemplified by reference prices tradingat negative values
Reference prices recovery for2021 ($49/bbl) and 2022 ($70/bbl) expected to mimic global economic recovery
2020 has been one of, if not the most, volatile years in oil price history. The COVID-19 pandemic has ravaged the global energy markets, and as such global liquids demand that has typically increased by about 1 to 1.5 million barrels per day year-over-year, is currently expected to see an annual average contraction of 10 million barrels per day from 2019 to 2020.
The impact on average oil price per year is real, and best estimate projection towards 2025 do not expect the$70/bbl threshold to be reached before 2022 (Figure 3.1).
It was, in particular, April 2020 that saw unprecedented market turmoil as the full impact of various economies entering lockdown, and thereby reducing demand, as well as OPEC and Russia increasing production, and thereby increasing supply, resulted in an oversupply situation of about23 million barrels per day (Figure 3.2).
At this rate of oversupply, the global storage capacity was rapidly filling up leading to negative pricing for various reference prices. In particular, the negative West Texas Intermediary price at -$37.63/bbl on 20 April 2020 will remain a testament to the extraordinary circumstances the market was subject to.
Globally, suppliers responded to the oversupply situation and negative prices by curtailing production. The biggest reduction came from OPEC+ thatdecided on a 9 million barrels per day production cut to help balance the market, and to which several African OPECand non-OPEC nations rallied.
Also, other countries instituted government mandated production cuts such as Norway while other countries saw market forces forcing production curtailments such as the oil sand production in Canada. Overall, production was reduced with about 12.5 million bpd from March 2020 to June 2020.
Africa was also impacted by the production cuts with up to 460,000 barrelsof oil per day (bopd) curtailed in May and June 2020. OPEC members Algeria and Nigeria have faced the majority of the production cuts with about 40 percent each, followed by non-OPECmembers Sudan and South Sudan.
OPEC members Angola and Libya did not face the same production cuts as the Angolan production is declining, and Libya faces domestic unrest. The initial turmoil caused by COVID-19 stabilized over the summer months as demand bounced back following lockdown measures being removed and the supply being curtailed. The Brent oil price subsequently increased from sub $20/bbl to over $40/bbl.
Going forward towards 2021, there remains high uncertainty around how the virus outbreak will unfold, how economies will react and ultimately what the impact will be on oil markets. Figure 3.3 illustrates a potential view of what can happen should a second wave of COVID-19 manifest itself and see the reinstatement of the draconian lockdowns from spring 2020. The base view is a gradual increase in demand throughout the remainder of 2020and throughout 2021 to reach the pre-COVID-19 demand levels by late 2021.
Should the demand outlook unfold similar to the base view, the oil price is expected to see a similar gradual increase. By2022, assuming the virus is under control and normalcy has returned, there is a risk of spiking oil prices above $70/bbl as the dearth of investments throughout 2020and 2021 may lead to a constrained supply outlook. Beyond 2022, the expectation is for the oil price to stabilize around $60-65/bbl. Benchmarked versus the oil price expectations of leading E&Psthe general consensus appears to be a
downwards revision in oil price outlook, but nevertheless an expectation that the price will remain north of $50/bbl. Figure 3.4 compares the communicated oil price outlooks from the latest Q2 2020 updates. For African nations, such price outlook will notably call for much more competitive frameworks on deep water developments and projects, which continue to represent a substantial share of the continent’s production but are also the most expensive and most uneconomically feasible ventures given this outlook.
2021 to see a renewed push towards domestic gas monetization as Global LNG glut continues to depress prices
Depressed global gas prices and the ever-increasing demand for affordable power offer a unique environment for Africa to push for further domestic gas monetization.
COVID-19 also caused gas demand disruption. While less prominent than for oil, it was nevertheless sufficient to further depress prices.
As a result, all major reference prices have converged as a glut of LNG has to be absorbed.
Africa is expected to increase its gas exports once big LNG facilities are on-stream, ultimately increasing African exposure to global gas market.
Over the last five years, the global supply and demand for gas has grown rapidly. Demand has been spearheaded by growth in North America and Asia while supply growth has come from NorthAmerica through the vast growth in hydrocarbon production from shale formations.2017, 2018 and 2019 in particular saw strong growth with an average growth of 170 billion cubic meters per year (Figure 4.1). However, global gas production is expected to decline in 2020 on the back of production curtailments in North America and Russia. It will be the first time since 2009 that global gas production experiences a decline.
Gas markets are not insulated to COVID-19, but are less exposed than the oil market as a result of COVID-19 curtailing transportation more than anything else. Gas is less used in transportation, and as a result less impacted by COVID-19. The gas market was nevertheless already facing a glut of LNG even before COVID-19, resulting in even more depressed prices as the pandemic’s impact on demand started to manifest in the spring of 2020.
As a result, key reference prices in Europe, North America and Asia all have experienced negative pressure since the start of 2020.
Looking forward, expectations for the global market fundamentals are to remain loose through 2021 on the backof weak COVID-19 induced demandand continued high supply of LNGbefore prices tighten significantly as LNG demand growth will outpace liquefaction capacity due to more delaysin project sanctioning (Figure 4.2). The forecast points to a tight LNG balance between 2023 and 2025, and alongwith it, a price spike. Following this period, there is a downside risk in pricesfor 2026 and 2027 driven by the potential of seeing a new wave of sanctioning activity during 2021 and 2022.