North African nations have seen recent progress in the field of renewable energy, especially in green hydrogen.
Hydrogen has many uses across varied industries, from petroleum refining and food processing to fertilizer and steel production. While the aerospace industry has used hydrogen as a rocket fuel since the dawn of the space age, there is plenty of room for the growth of hydrogen-powered cars, or fuel cell electric vehicles (FCEVs), in the automotive world. Though its implementation in electricity generation is minimal at present, hydrogen may see more widespread use as a supplementary or alternative fuel source in the future at standalone facilities and power plants currently running on natural gas.
Hydrogen production primarily uses electrolysis, a process in which an electric current passes through water to separate hydrogen from oxygen. Currently, about 95% of the electricity for global hydrogen production comes from natural gas and coal-fired power plants. By contrast, green hydrogen production utilizes electricity from renewable sources such as solar and wind instead. If the majority of hydrogen production facilities switched to renewable energy, the International Energy Agency (IEA) estimates this could reduce CO2 emissions by approximately 830Million tonnes annually.
As the world struggles with the urgent need to transition from fossil fuels to more sustainable energy sources, green hydrogen offers an avenue where production can continue with the same capacity but without harmful by-products, particularly in regions rich in renewable energy potential like North Africa. This region, characterized by vast, consistently sun-drenched deserts and strong winds, could potentially lead the way in developing a global green hydrogen economy. However, this transition is not without its complexities and challenges.
The Promise
North Africa offers several compelling advantages, marking it as a prospective green hydrogen mega-producer.
North Africa already has the requisite abundant natural resources and developing infrastructure to support a massive expansion in green hydrogen production. The region boasts some of the highest solar irradiation levels globally, making it an ideal location for solar-powered hydrogen production. Countries like Morocco and Egypt have already initiated projects like the Noor Ouarzazate Solar Thermal Complex and the Benban Solar Complex, respectively, which could serve as the backbone for the industry. Additionally, the wind potential along the coasts of Algeria and Mauritania provides another renewable energy source for industrial-scale electrolysis.
For national economies critically dependent on oil and gas, green hydrogen offers a path to greater diversification. The transition would not only lessen the negative impacts of oil’s inherent price fluctuations but also foster new industries. Green hydrogen production could lead to development in related sectors such as hydrogen fuel cells, ammonia production for fertilizers, and even green steel (steel produced using hydrogen as a reducing agent eliminating coal and CO2 emissions from the process) creating new jobs and stimulating economic growth.
A ramp-up in green hydrogen production would also have more than just local benefits as the endeavor aligns with global climate goals as well. By focusing on green hydrogen, North African countries could position themselves as leaders in the worldwide decarbonization effort while opening up new export markets. The export of green hydrogen to Europe, which has set ambitious climate targets, could become a lucrative trade, further enhancing North Africa’s geopolitical stature in the energy sector.
With the right infrastructure in place, like the kind proposed for the SoutH2 corridor linking North Africa, Italy, Austria, and Germany, producers could transport green hydrogen via pipelines or as easily shippable derivatives like ammonia or liquid organic hydrogen carriers (LOHCs), which would be particularly appealing to European markets seeking to decarbonize.
The Challenges
A realistic assessment of the path to a green hydrogen economy in North Africa reveals it is not without its fair share of challenges.
Hydrogen production through electrolysis requires significant amounts of water, which is already scarce in many parts of North Africa. This fact essentially mandates solutions like seawater desalination or wastewater recycling, both of which add to the energy and financial burdens of any green hydrogen initiative.
The lack of existing infrastructure for hydrogen production, storage, and distribution is also a major hurdle. North Africa will need new pipelines, storage facilities, and ports capable of handling hydrogen and its derivatives, and the construction associated with these features will require substantial investment. Moreover, while adapting existing gas infrastructure to facilitate hydrogen transportation is a feasible venture, it presents additional technical and safety challenges due to hydrogen’s volatile properties.
Another impediment to green hydrogen’s expansion is its overall economic viability. Currently, green hydrogen production costs remain higher than those of fossil fuels or even those of blue hydrogen (hydrogen produced using natural gas with carbon capture). Achieving economies of scale and technological advancements in electrolyzers could reduce costs, but until then, green hydrogen will struggle to compete without subsidies or carbon pricing mechanisms.
Nations engaged in green hydrogen production will also have to create and clearly define their associated policies and regulations. This nascent stage of the technology’s development calls for robust policy frameworks if producers are to attract investment, ensure safety, and integrate hydrogen into their existing energy systems. North African nations need to develop clear strategies, not only for hydrogen production but also for how it fits into their broader energy policies. This includes regulatory support for renewable energy projects, hydrogen certification, and cross-border trade agreements.
The capital-intensive nature of green hydrogen projects means funding is another critical barrier. While there are signs of interest from international investors, the risk perception in some North African markets could deter the necessary influx of capital. It might be necessary to seek international cooperation on innovative financing models such as green bonds which are issued by public or private institutions for the purpose of funding projects intended to mitigate climate change.
Lastly, skill development and technology transfer present other hurdles. Building a green hydrogen industry requires a skilled workforce that counts engineers, technicians, laborers, and policymakers as members. Considering that nations who want to participate in the green hydrogen economy will have to develop local expertise, there is a built-in need for investment in education and training. And while technology transfer from countries leading in hydrogen technology would be beneficial, it comes with its own set of potential limitations regarding intellectual property and capacity expansion.
Moving Forward
Despite these challenges, leveraging North Africa’s green hydrogen potential is a worthy pursuit and will require a multi-faceted approach:
Regional collaboration. Initiatives like the African Green Hydrogen Alliance are steps in the right direction, promoting shared knowledge, infrastructure, and investment.
Technological innovation. Conducting research into more efficient electrolyzers, better hydrogen storage solutions, and the use of non-fresh water sources for electrolysis could mitigate some of the current limitations.
International partnerships. The EU’s goal of importing 10 million tonnes of green hydrogen by 2030, as stipulated by the REPowerEU Plan, presents an immediate market opportunity. Collaborations across Europe for diversified investment, technology sharing, and market access can accelerate development.
Policy leadership. Governments must lead with policies and offerings that not only incentivize green hydrogen but also ensure sustainability. These would include clear and detailed roadmaps to success, unwavering support for initial projects, and incentives like the simplified administrative procedures and tax breaks l the Egyptian government established when it granted 42,000 square kilometers of land to the New and Renewable Energy Authority (NREA) for green hydrogen production.
Environmental considerations. It is crucial to ensure that green hydrogen projects do not lead to unintended environmental degradation, especially concerning water use. Operators must integrate and adhere to environmentally friendly practices from the outset.
The development of green hydrogen in North Africa holds transformative potential, offering a route to clean energy production that could redefine the region’s economic landscape.
However, to realize this potential, North Africa will have to overcome significant hurdles through strategic planning, international cooperation, and a commitment to sustainability. If North Africa navigates these challenges with foresight and innovation, the region could meet its own energy needs via greener alternatives while playing a pivotal role in the global energy transition and setting a precedent for other regions to follow.
NJ Ayuk is Executive Chairman, African Energy Chamber
Reviewing the majors for 2025 brings with it a plurality of scenarios.
Trump’s entry to the White House has more than a passing interest to both Chevron and ExxonMobil. Both companies will be lobbying Trump to ensure that US-Russian relationships are improved. Why?
When the Soviet Union broke up in the early 90s and Kazakhstan emerged as a new oil province, both Chevron and ExxonMobil, seen as ambassadors of US goodwill, gained access to the country’s black gold. Chevron’s prize was operatorship of Tengiz (50%) and ExxonMobil gained a 25% share. Chevron also has an 18% share in the large Karachaganak Gas Field. ExxonMobil has a 16.81% share of the troubled Kashagan Project.
Shell’s attention will no doubt be focused on its important LNG sector which can anticipate the necessary headwinds. While the courts in the Netherlands has given the UK major a pass on its Carbon Dioxide (CO2) reduction appeal, no doubt a new narrative must be developed if new energy is to develop a societal consensus.
Equinor …willing to fight the good fight is too small to be a force for good and must re-invent its development scenarios.
ENI, small and contrarian, has found through strategic alliances and pragmatic solutions that it has become a respected player in Africa.
TOTALEnergies, both in terms of leading the pack with its innovative approach for the energy transition and its deepwater exploration, is a player to watch.
BP continues to flounder: a company in search of its soul.
In the period 2021-2024 the Dow Jones Industrials gained 38%: from 31,098 in January 2021 to 42,992 December 2024. The oil majors have displayed a variety of results:
ExxonMobil +130%
Chevron +58%
Shell +55%
Eni +23%
Equinor +22%
BP +21%
TOTALEnergies +20%
Table 1: Oil majors stock prices 2021-2024 (NYSE)
Year
BP
Shell
ENI
TOTAL
Energies
Chevron
ExxonMobil
Equinor
2021
$24
$40
$22
$46
$91
$46
$18
2024
$29
$62
$27
$55
$144
$106
$22
BP: A Takeover prey?
BP’s share price in the period January 2021- December 2024 has remained tepid: from $24 to $38. The company’s checkered history continues to haunt its assets:
BP’s Deepwater Horizon oil spill of 2010 in the Gulf of Mexico has cost the company $65Billion;
The company’s withdrawal from Russia in February 2022, because of the Ukraine conflict, meant the loss of 50% of its global reserves; and
In September 2023, the abrupt resignation of CEO Bernard Looney after he admitted that he had not been “fully transparent” about historical relationships with colleagues.
BP is promising to spend up to $65Billion on renewables between 2023-2030, amounting to half of its investments by 2030. Yet the company has written off $540Million of its offshore wind assets in New York.
Will BP be able to meet its renewable energy goal given the long-term slump of renewables and BP’s lingering share price?
What BP was Promising Originally?
An underlying EBIDA (earnings before interest, depreciation, and amortization) of between 5–6% per year through to 2025 with returns in the range of 12–14% in 2025.
From 2025 onwards, when its low-carbon projects would start to kick in, an expected growth of between 12–14% to be maintained.
More recently BP has announced that in 2025 its oil and gas production to be around 2.6Million b/d of oil equivalent. The capex for oil and gas is $8.5Billion. The company has a renewable pipeline of some 47GW.
BP’s faltering vision, its downward share price and its low valuation—some $84Billion–makes the company a vulnerable takeover prey.
The chief obsession of Wael Sewan, Shell CEO since 2023, is to drive up the company’s stock price. His hydrocarbon narrative is mimicking that of Chevron and ExxonMobil.
Shell’s total capex for the period 2023-2025 is between $22-$25Billion per year, of which 80% is earmarked for hydrocarbons. Not unlike Chevron and ExxonMobil.
Yet what distinguishes Shell is its strong LNG arm, truly global. In short, Shell is really a natural gas company.
A fundamental concern for Shell should be the global outlook for LNG. Shell’s LNG Outlook 2024 forecasts that China will grow its LNG requirements more than 50% by 2040: rising to 23Trillion cubic feet (Tcf) in 2040 from 14Tcf in 2023.
Yet Shell’s optimism may be premature.
The Institute for Energy Economic and Financial Analysis (IEEFA)’sGlobal LNG Outlook 2023-2027casts a far more somber analysis for future LNG developments, in particular for China: rising domestic gas production, pipeline gas imports, and renewable power capacity could limit the potential for rapid LNG demand growth over the medium term.
Where did it go wrong?
A long-term LNG slow down for China is only a part of the puzzle. According to IEEFA the global demand for LNG is slowing:
Europe, while maintaining a high degree of LNG import, is also increasing energy efficiency measures and wind and solar projects have become commonplace.
Japan and Korea, historically dependable LNG importers, are increasingly turning to nuclear, and renewables; and
South Asia, including India, Pakistan, and Bangladesh slashed purchases by 16% in 2022 and suppliers often defaulted on contracts to obtain higher prices elsewhere.
“After several years of weak supply growth, IEEFA anticipates that the global LNG market will see a tidal wave of new projects come online starting in mid-2025. The wave will likely crest in 2026, with the addition of 64Million metric tons of annual liquefaction capacity—the most in the history of the global LNG industry. The supply additions will boost global liquefaction capacity by roughly 13% in a single year. Liquefaction projects targeting in-service after 2026 may be entering a much smaller demand pool than bullish market forecasts anticipate. As new supply floods the market, today’s tight markets may give way to a supply glut, with lower-than-anticipated prices, smaller netbacks, tighter margins, and lower profits for LNG exporters.”
The turning point will be 2025.
“IEEFA anticipates that roughly 17Million Tonnes Per Annum (MMTPA) of liquefaction projects are likely to come online around the world in 2025—more than in 2023 and 2024 combined. New capacity additions will crest in 2026, with an estimated 64MMTPA of capacity coming online in a single year, and continue into 2027, when 37MMTPA of new capacity is expected to begin operating”.
How will a floundering LNG market affect Shell’s dominant LNG position? Does Shell continue to have the agility to re-calibrate its strategy?
Redefining the Common Good
Up to 10-15 years ago, what Shell stated as a company policy in the Netherlands was largely interpreted as the ‘Common Good’. What was good for Shell was also deemed good for the country as a whole.
For example, up to 2018, the Inspector-General of the Dutch State Supervision of Mines, the highest regulatory authority for the oil and gas industry in the Netherlands, was always headed up by an ex-Shell nominee.
Yet Shell’s recent win in its landmark case overturning an earlier ruling requiring it to cut its carbon emissions by 45% have seen Shell do an abrupt about-turn: in essence arguing that cutting carbon emissions was a “private matter” and had little to do with the “Common Good”.
The Court of Appeal in the Netherland’s capital city of The Hague, said it could not establish that Shell had a “social standard of care” to reduce its emissions by 45% or any other amount, even though it agreed the company had an obligation to citizens to limit emissions.
If people considered progress was too slow towards cutting emissions, then, according to Shell, they should lobby governments to change policies and bring about a green transition.
Shell’s insistence that the courts have no jurisdiction in the Shell boardroom could in the longer-term backfire. Perhaps time to go back to Jean-Jacques Rousseau.
For Rousseau, writing in the mid-18th century, the notion of the Common Good, achieved through the active and voluntary commitment of citizens, was to be distinguished from the pursuit of an individual’s private will.
As Rousseau explains, the general will is the will of the sovereign, or all the people together, that aims at the Common Good—what is best for the state as a whole.
The heart of the matter for Shell is that the company has continued to argue that this is a private( company) matter, not one involving the the Common Good.
Yet the 2016 Paris Climate Agreement, which was signed by 195 countries, agreed to try and prevent an average global temperature rise of under the 20C and hopefully 1.50C, is the clearest example of a Common Good.
What the court and Shell are arguing is that the Common Good must be redefined: a court follows precedent and does not establish it. In other words, the current design of the energy transition must have a more encompassing architecture if a new consensus is to be arrived at.
The Joker in the Deck
ENI, the Italian-based oil and gas giant, is often overlooked in any discussions involving the other oil majors-BP, Chevron, Equinor ExxonMobil, Shell, and TOTALEnergies. Yet ENI could be the Joker in the deck providing surprises to an unwitting public and be an upstart which deserves the needed attention.
ENI’s strong presence in North Africa—Algeria, Egypt, and Libya—could in the coming months become one of Europe’s substitute providers of natural gas. This region currently produces 648,000barrels of oil equivalent per day (BOEPD). The company operates in the frontier areas seldom mentioned in the daily news media.
For starters the company produces 1.7mboed(million barrels of oil equivalent per day), has a balance sheet which has an economic leverage of 20%, and has, according to its website, an Internal Rate of Return(IRR) of 34%, the highest of all its peers for the 2012-2021. Also, its RRR(Reserve Replacement Ratio) of 110% for the period 2012-2021 is the highest compared to its industry peers.
ENI further states that 90% of exploration capex is spent on near fields and proven basins. Some $11Billion in the last 10 years has been spent on its dual exploration model—near fields and proven basins. The company states that it only requires three years—from first discovery of oil to market—twice as fast as the industry average.
A key ENI strategy is developing a series of joint-ventures to ensure that ENI can achieve maximum leverage for its current oil and gas assets and at the same pursuing new strategies as part of its energy transition plan. Some examples:
Vår Energi, Norway was formed in 2018 following the merger of Eni Norge AS and Point Resources AS owned by Hitec Vision, a private Norwegian investment fund. The company’s primary focus is oil and gas developments on the Norwegian Continental Shelf. ENI controls 69.6% of the shares, and HitecVision 30.4%. Vår Energi has production in 36 fields and produces 247,000 boepd.
Ithaca Energy in the UK (ENI 37.17%) has become the largest O&G operator in the UKCS by resources.
Azule Energy, Angola, a 50-50 joint venture between ENI and BP formed in 2022 to include both companies’upstream assets, LNG and solar business. Azule Energy is now Angola’s largest independent equity producer of oil and gas, holding 2Billion barrels equivalent of net resources and growing to about 250,000BOEPD of equity oil and gas production over the next five years.
Azule Energy in 2024 completed a farm-in of Block 2914A located in Namibia’s Orange Basin, giving the company a 42.5% share.
Plenitude, ENI’s new company, launched in June 2022 is an integrated business combining the generation of electricity from renewables, the sale of electricity, gas and energy services to households and businesses, and a European network of charging points for electric vehicles.
Enilive is ENI’s mobility transformation company. Founded with the goal of offering integrated services and products that are progressively decarbonized by 2050, Enilive is the tangible result of Eni’s ten-year commitment to sustainability-driven mobility transformation.
TOTALEnergies’ energy production in the period 2020 -2030 “will grow by one third, roughly from 3MMBOEPD to 4MMBOEPD, half from LNG, half from electricity, mainly from renewables”, according to Patrick Pouyanné, the company’s Chairman and CEO.
This was the first time that a major operator has wittingly or unwittingly translated its renewables to BOE(barrels of oil equivalent). The golden rule was that RRR(Reserve Replacement Ratio) was always used to assess a company’s hydrocarbon reserves. This author has for some time argued that oil companies also include other fuels in their reserve count—be that wind or solar– to create a basket of energy reserves. Thus, increasing reserve count and buttressing up fossil reserves and adding value to hydrocarbon assets.
By taking renewables on board has enabled the company to leapfrog the competition. Getting a head start with renewables and continuing to manage its deepwater projects. The company has confirmed that it is on track to deliver 100GW of renewables by 2030.
The company’s twin pillars—Oil and Gas and Integrated Power—have a capex of between $16-18Billion for 2025 of which $5 billion will be spent on low-carbon energy.
TOTALEnergies’s goal for its Integrated Power division is to have a ROACE(Return on Average Capital Employed) of 12%; in 2023 it was 10%.
Yet ROACE averages for the oil and gas industry are virtually double that of new energy: in 2022 TOTALEnergies’ROACE stood at 28.2%, and in 2023 Equinor’s ROACE stood at 24.9%.
In terms of deepwater TOTALEnergies will be focused on its Venus prospect in Namibia: in its Venus 2913 B development is taking place and the company is engaged in a further exploration programme.
Fly in the Ointment: ENI’s Coral Sul Project in Mozambique
A fly in the ointment could well be ENI’s LNG projects. The first LNG shipment of Eni’s Coral Sul FLNG shipment took place in November 2022. ENI’s second LNG project—Coral Norte–is expected to receive FID shortly.
Meanwhile Africa’s two most highly touted LNG projects—Rovuma and Mozambique LNG—have continued to be on security hold.
TOTALEnergies has made no final FID decision on its Mozambique LNG project, which is expected to cost $20 billion and produce up to 43 million tons per annum remains. Will it ever be developed?
Chevron: Stay vigilant
Aside from its newly acquired asset in Guyana two-thirds of Chevron’s total production of 3 million barrels of oil will in 2025 come from just two projects: Tengiz in Kazakhstan and the Permian Basin in the United States each yielding 1Million barrels of oil equivalent per day.
Today the company has a net value of over $283Billion, seen its stock price rise to $144 by December 2024, up from $91 in January 2021.
The company will devote $14.5-$15.5Billion of capital spending for consolidated subsidiaries. The company has indicated that $13 billion is devoted to domestic upstream operations.
Outside the USA, Chevron will spend between $1.7 -$2Billion to further develop its Tengiz asset in Kazakhstan, and other assets elsewhere. This is not promising for Africa, where Chevron has major operations stretched across the continent including major projects in Nigeria, Angola, Equatorial Guinea, and Egypt.
Tengiz Project
Tengiz production is currently producing 560,000 BOPD and is being expanded by some 260,000BOPD. Total costing is estimated at $45Billion.
Expiry date for the Tengiz concession is 2033. What will happen then? Tengiz was for most of its duration Chevron’s crown jewel, providing cash to developing assets elsewhere including Africa. Given Chevron’s current strategy it can only hope that Tengiz can continue to squeeze out more oil.
Caspian Pipeline Consortium(CPC)
A potentially troubling problem is the Caspian Pipeline Consortium(CPC) which transports Caspian oil from Tengiz field to Novorossiysk-2 Marine Terminal, an export terminal at the Russian Black Sea port of Novorossiysk. The CPC pipeline handles almost all of Kazakhstan’s oil exports. In 2021 the pipeline exported up to 1.3 million bpd(barrels per day). On July 6, 2022 a Russian court ordered a 30-day suspension of the pipeline because of an oil spill. The CPC appealed the ruling and the suspension was lifted on 11 July of the following week, and the CPC was instead fined 200,000 rubles ($3,300).
The incident demonstrates the vulnerability of Tengiz and future production. No doubt this is not the last such incident which involves Russian and Kazakhstan goodwill to ensure that Chevron’s Tengiz Project does not falter. Having to dependent on Russian-Kazakhstan goodwill to guarantee Tengiz production has put Chevron’s lack of diversity of oil supply in a very bad light.
Permian Basin
A final sour note for Chevron could be its Permian Basin assets. What assurances do we have that Chevron’s Permian Basin adventure will fare better than that of past shale operators?
In a 2021 March report IEEFA found the 30 producers generated $1.8 billion in free cash flows in 2020 after slashing capital spending by $20Billion from the previous year.
Since 2010, the 30 companies examined by IEEFA had reported negative free cash flows totaling $158Billion. “The positive free cash flows pale in comparison to the industry’s accumulated debt loads.” The 30 shale producers owe almost $90Billion in long-term debt, and the reductions in capital expenditures are unlikely to ensure that the industry grows.
ExxonMobil: Don’t count your chickens…
ExxonMobil’s vital signs are the following: between January 2021 and December 2024 the stock price at the NYSE has risen from $46 to $106. The company has a capex of between $27-29Billion in 2025 and a market capitalization of $487Billion.
Good News & Bad News from Guyana
ExxonMobil continues to publish for the world its good news from its offshore Stabroek Block in Guyana: by 2027 a target of 1.7MMBPD will be pumped, budgeted at a cost of $45Billion. Total recoverable reserves are estimated at 11Billion barrels.
Not mentioned is the price tag.
Guyana will carry a minimum $20Billion outstanding balance owed to its oil producer partners at the end of 2024, in the opinion IEEFA. This amount must be paid, along with other contractually obligated development costs, before the country can fully enjoy any long-term benefits that might materialize.
This is a discussion which must be had in the coming months.
LNG—A Mixed Blessing
Rovuma LNG was supposed to become ExxonMobil’s futuristic model LNG project. ExxonMobil has recently issued various tenders to move its Rovuma project ahead. Instead, in a matter of months events have overtaken ExxonMobil’s best laid plans.
IEEFA’s recent warning of a global LNG oversupply in the coming five years is not good news! Will Rovuma make it to the starting gate?
Then there is the matter of Eni’s Coral Sul Project in Mozambique.
ENI’s Coral Sul FLNG project’s inauguration deserves special attention. The first LNG shipment of Eni’s Coral Sul FLNG shipment took place in November 2022.
While Africa’s two most highly touted LNG projects—Rovuma and Mozambique LNG– continued to be on security hold, Eni achieved pole position with its Coral Sul FLNG project. A FID(Final Investment Decision) is expected to be made on ENI’s second Coral Sul Project in Mozambique in early 2025.
On May 31, 2023 Equinor announced that it would delay by at least three years its Bay du Nord project in the deepwater Flemish Pass basin 500 km off the coast of Newfoundland, Canada. Why? Because the project would cost an estimated $12Billion. Only $12Billion you might think. Is that a reason for not developing this project at a time when oil and gas companies are showing record earnings? According to Equinor technical and financial challenges are the main reasons for the delay.
Yet Equinor’s reasoning is not directly related to the Bay du Nord capital costs. By 2030 the company is pledged to spending half of its capex on renewable energy. In 2024 its capital budget was $13Billion. On this basis Equinor’s capital budget for future oil and gas projects is rather restrained.
Yet the company has revealed how it will be implementing its strategy:
In October 2024 Equinor announced that it had taken a 10% stake in Ørsted.
Equinor UK and Shell UK have combined their UK offshore oil and gas assets to form a new joint JV.
Will more strategic alliances be announced?
Pillar Number One
Equinor’s concern is whether the company’s twin pillars–natural gas and offshore wind — have the financial depth and ability to achieve maximum leverage for both pillars?
Equinor’s offshore wind portfolio is pledged to grow to 12–16 GW of installed capacity by 2030. Equinor has chosen a series of joint ventures to develop its offshore wind portfolio. The first, Dogger Bank, heralded to become the world’s largest offshore wind farm, is being developed together with SSE Renewables based in the UK. Located in the North Sea, the project will produce some 3.6 GW of energy, enough to power 6 million households.
Originally Equinor and BP were partners in the Empire Wind and Beacon Wind assets off the USA’s east coast. Under a swap agreement Equinor has taken over full ownership of the Empire Wind lease and projects and BP will take full ownership of the Beacon Wind lease and projects. The two projects will generate 4.4 GW of energy.
Equinor’s rivals have the size and economies of scale to be very competitive:
ENGIE based in France: In 2021 the company spent more than $11 billion on investments across a broad swath of sectors, including solar, wind (on and offshore), hydro plants, biogas, and developing gas and power lines, and will have 50 GW of global renewable installed capacity by 2025.
Enel based in Italy: The company’s strategic plan outlines total investments of $231Billion and tripling renewable capacity to 154 GW by 2030.
Ørsted based in Denmark: By 2030 the company will have an installed capacity of 50 GW of renewable power.
Iberdrola based in Spain: From 2020–2025, the company will be spending $165Billion on renewable energy and has a pending target of 95 GW of installed wind capacity.
RWE based in Germany: By 2030 RWE will have 50 GW of installed wind and solar capacity.
Vattenfall based in Sweden: In the Nordic countries, Vattenfall has low emissions, with practically 100% of the electricity produced based on renewable hydro power and low-emitting nuclear energy.
Pillar Number Two
Oil is the main money earner for Equinor but it’s providing of natural gas to Europe which has caught the public fancy.
According to the Norwegian Petroleum Association (see below), Norway produced in 2020, 22% of Europe’s natural gas demands. Additionally, 2/3’s of Norway’s total gas resources is still to be produced. No doubt in the short-term natural gas exports from Norway to Europe will be substantially raised.
Choosing a Future Home
The company’s net income in 2023 was $11.9Billion, basically the lion’s share from natural gas while its renewables business division(read offshore wind) Equinor’s renewables business has reported a net operating loss of $166Million for the third quarter of 2024, compared with a loss of $412Million in the same period in 2023.
No doubt Equinor’s natural gas will continue to flourish in the short-term. The key question is what will happen to the offshore wind division? In this context do not expect that the Bay du Nord project will be developed in Canada any time soon.
Some Final Thoughts
The Higher Court’s decision in the Netherlands ruled that it could not establish that Shell had a “social standard of care” to reduce its emissions by 45% or any other amount. Yet the court agreed the company had an obligation to citizens to limit emissions.
A court follows precedent and does not establish it. In other words, the current design of the energy transition must have a more encompassing architecture if a new consensus is to be arrived at.
An important item to address is the high ROACE rate which the oil companies see necessary to maintain their operations and investments: an ROACE above 20% is more or less the norm; double that of the new energy companies who aim to achieve an ROACE of 10%-12%.
Maintaining a 20% ROACE is necessary if an oil company is to continue its generous dividends.
If an energy transition CO2 surcharge were introduced would an oil company’s ROACE look so positive?
New energy companies will be seeking more specialized services and government incentivized programs to ensure their growth both in terms of their share price and dividends.
Finally, anticipate that the oil companies and new energy will continue to spin off, merge or form joint ventures to maintain economies of scale and further profitability.
Gerard Kreeft, BA (Calvin University, Grand Rapids, USA) and MA (Carleton University, Ottawa, Canada), Energy Transition Adviser, was founder and owner of EnergyWise. He has managed and implemented energy conferences, seminars and university master classes in Alaska, Angola, Brazil, Canada, India, Libya, Kazakhstan, Russia and throughout Europe. Kreeft has Dutch and Canadian citizenship and resides in the Netherlands.He writes on a regular basis for Africa Oil + Gas Report and contributes to the Institute Energy Economics and Financial Analysis(IEEFA). His book The 10 commandments of the Energy Transition is now on sale at Bookstorehttps://books.friesenpress.com/store/title/119734000211674846/Gerard-Kreeft-The-10-Commandments-of-the-Energy-Transition.
To prevent catastrophic climate change, environmental organizations, financial organizations, and governments across Europe and North America have insisted that developing nations, including those in Africa, must immediately transition from fossil fuel production and usage to renewable energy sources like solar, wind, and hydrogen.
The majority of those making these demands are based in industrialized nations that were built on fossil fuels — oil and gas fueled their economic engines — yet they are unwilling to allow less developed nations to use fossil fuels to the same end. Even more troubling, the countries these groups are taking aim at have a wealth of natural resources under their feet, resources that can be monetized and used to build a better future.
We have explained, over and over, why African countries, businesses, and communities still need support from international oil companies (IOCs), foreign governments, and investment institutions for oil and gas projects. IOCs, for example, play an important role in knowledge sharing and helping Africans build valuable job skills. What’s more, foreign oil and gas investments create opportunities for revenue that can be used to build and improve energy infrastructure — for both fossil fuels and renewables. And, by supporting natural gas projects, investors create a path for gas-to-power projects that help minimize the continent’s widespread energy poverty.
In July 2021, when it became apparent that reasoning was not yielding results, the African Energy Chamber employed the same tactics the international community used against our members. We called for boycotts against financial institutions that discriminated against the African oil and gas industry.
But the calls to stop financing African oil and gas have only grown louder and more insistent.
In the course of the 2021 United Nations Climate Change Conference (COP26) in Glasgow, more than 20 countries and financial institutions pledged to stop public financing for overseas fossil fuel projects. Europe then decided that gas was clean for Europe so it will be financed but for Africa, gas is dirty and will receive no funding. The United Kingdom and the European Union have also reportedly joined in the chorus of voices demanding a ban against developed nations providing subsidies for fossil fuels.
Other expectations for the 2024 edition of the conference include calls for member states to formally commit to triple their renewable energy capacity and double their energy efficiency across the board by 2030.
The thread tying all these pledges together, with respect to our work at the African Energy Chamber, is that none of them bode very well for any future success stories from the African energy economy.
For those of us who care about Africa’s oil and gas industry, it’s time to face facts: We need to find a way to save it ourselves. The African Energy Chamber is calling upon African states and the private sector to fund the African Energy Bank, an institution which is focused on funding African energy projects. The African Petroleum Producers Organization (APPO) and the African Export-Import Bank (Afreximbank) have paved the way. The idea is to create funding sources for all types of African energy — from oil and gas exploration to solar and hydrogen operations — so that projects will not be dependent on foreign support.
We can do this, and we must. Too much is at stake. We can’t afford not to capitalize on recent discoveries such as the light oil found offshore Angola, the oil in Namibia’s Orange Basin, the shale gas in South Africa’s Karoo Basin, or the oil and natural gas off the coast of Côte d’Ivoire. Those are only a few of the important discoveries that occurred recently, and each represents critical opportunities for everyday Africans.
You may be wondering if African energy banks are a realistic goal. How can a continent that is struggling to bring many of its people out of poverty raise capital for energy projects? I believe it can be done. To begin with, African governments can set aside a percentage of their oil and gas revenues for new project funding. In its report, Africa Energy Outlook 2021, Rystad Energy projected that African governments’ earnings from royalties, profit oil, and other taxes in 2021 would reach USD 100 billion. Even 1% of that amount would produce USD 1 billion dollars.
We can also raise capital by investing African pension funds in African energy projects. According to Cape Town-based investment firm, RisCura, local pension funds collectively manage around USD 450 billion of assets in sub-Saharan Africa, and they are actively looking for new places to invest. Why not encourage them to add oil, gas, and renewables projects to their list? Investing pensions in the energy sector is hardly a new practice. Some of America’s largest pension funds are invested in fossil fuel producers, and an increasing amount of pension funds around the globe are investing in green energy projects.
Our options for raising capital don’t end there. We should also seek the support of wealthy Africans who want to invest in a better African future. As of December 2023, total private wealth in Africa totaled approximately USD 2.3 trillion. That’s not even including the African diaspora.
In May 2022, Afreximbank signed an agreement with APPO on the joint establishment of a special multi-lateral financial institution (MFI) – the African Energy Bank – to provide support for the shift away from fossil fuels. The agreement calls for APPO’s member states to provide equity for the new institution and serve as its founding members, with Afreximbank acting as co-investor and providing organizational support.
The new bank will be able to reach more countries than either APPO or Afreximbank could do on their own, as their rosters are not identical: APPO has 15 member states, while Afreximbank has 51 and there is a significant amount of overlap, as Algeria and Libya are the only APPO members that are not also Afreximbank members. But the point remains that if the two institutions join forces, their combined efforts will go further.
Professor Benedict Oramah, the President of Afreximbank, explained it as follows in May 2022: “For us at Afreximbank, supporting the emergence of [the Africa Energy Bank] will enable a more efficient and predictable capital allocation between fossil fuels and renewables. It will also free human and other resources at Afreximbank that will make it possible to support its member countries more effectively in the transition to cleaner fuels.”
Not only do we have pathways for raising capital, we also have an example of the kind of banks Africa needs to finance its own energy projects, one that goes back decades. I’m talking about Afreximbank. In 1993, African governments worked with public and private investors to create a bank that would finance, promote, and expand intra- and inter-African trade. They succeeded. In 2020, Afreximbank received the Africa-America Institute’s (AAI’s) Institutional Institution of Excellence Award for its commitment to the creation and implementation of the African Continental Free Trade Agreement and its ongoing dedication to investing in education. AAI noted that between 2015 and 2019 alone, Afrieximbank disbursed more than $30 billion in support of African trade, including more than $15 billion for the financing and promotion of intra-Africa trade.
I say, let’s build on Afreximbank’s model. And not only that, let’s cultivate a pool of investors who recognize and appreciate the importance of oil and gas to Africa. Capital from foreign countries and companies will always be welcome — as long as it isn’t predicated on phasing out fossil fuels on their timeline. If they’re pushing a rush to renewables, they’re not going to be part of our solution.
With the support of one or more African energy banks, local oil and gas companies will have the financing necessary to acquire assets. They’ll have the financing to build crude and gas pipelines across Africa and to facilitate the use of natural gas (including LNG) to power Africa, minimizing energy poverty and driving industrialization.
And African states and entrepreneurs will be able to finance the development of renewable energy operations, particularly blue, green, and grey hydrogen operations that create additional opportunities for Africans. Africa already has emerging green hydrogen operations in Mali, Namibia, Niger, and South Africa, and with the proper funding, could become a major green hydrogen exporter.
The AEC will support the energy bank initiative and work to bring potential participants together. Creating our own institutions to finance energy projects will send a clear signal to the marketplace that Africans are seeking to become leaders in scaling up private capital. It will show that we are advancing natural gas development and infrastructure while supporting low-carbon investments.
With the financing in place, not only will African companies be able to produce oil and gas, but they will also support local community development, develop green energy markets, and create jobs.
For many African countries, the oil and gas industry represents our best shot at giving millions of Africans the kind of jobs, living standards, and stability that developed countries have enjoyed for well over a century. We must hold fast to these goals and do what it takes to achieve them.
By NJ Ayuk, Executive Chairman of the African Energy Chamber(www.EnergyChamber.org)
OPINION
The continent will need global financial systems, including multilateral development banks, to play a significant role in financing our energy growth which must include fossil fuels
I believe the ultimate responsibility for getting there is ours and no one else’s. Yes, we need partners to walk alongside us, but the success of our energy movement rests on African shoulders.
To begin with, I would love to see African energy stakeholders speaking in a unified voice about African energy industry goals.
This will be particularly important in COP29 in Baku. It is imperative that African leaders present a unified voice and strategy for African energy transitions. We must make Africa’s unique needs and circumstances clear and explain the critical role that oil and gas will play in helping Africa achieve net-zero emissions in coming decades.
I would encourage African leaders to talk about the need for financing, as well, to make it possible for us to adopt renewable energy sources and set up the necessary infrastructure. Africa will need global financial systems, including multilateral development banks, to play a significant role in financing our energy growth which must include fossil fuels.
Africa’s governments have a role to play in a successful African energy movement as well.
Because Africa’s energy industry still can benefit greatly from the presence of international oil companies, our government leaders need to approve contracts with oil and gas companies promptly instead of allowing red tape to delay projects after discoveries are made.
And, they need to offer the kinds of fiscal policies that allow oil companies to operate profitably in Africa. In turn, that will help those companies generate revenue, create jobs and business opportunities, and foster capacity building.
I also would encourage governments and civil societies to reward companies that exemplify positive behaviour. Let’s incentivize the kind of activities we want, from creating good jobs and training opportunities to sharing knowledge.
And there’s more.
We in Africa must work together to create more opportunities for women to build careers in the oil and gas industry at all levels. Our energy industry can’t reach its potential to do good when half of our population is left out. Our progress on behalf of women has not been great—We need to do better, and we need to act quickly.
How the world can support.
Now, I mean it when I say Africans are responsible for building the future they want. But, I would love to see Western governments, businesses, financial institutions, and organizations support our efforts.
How? They can avoid demonizing the oil and gas industry. We see it constantly, in the media, in policy and investment decisions, and in calls for Africa to leave our fossil fuels in the ground. Actions like these, even as Western leaders have pushed OPEC to produce oil, are not fair, and they’re not helpful.
I also would respectfully ask financial institutions to resume financing for African oil and gas projects and stop attempting to block projects like the East African Crude Oil pipeline or Mozambique’s LNG projects.
Please understand that with the war in Ukraine, the energy crisis in Europe, and the energy poverty facing our continent, our countries, like many others, are simply choosing the paths they believe are most likely to help their people.
You know, people for years have accused me of loving oil and gas companies more than Africa. The opposite is true. In my frequent travels around the continent, I’ve observed far too many young people with little in the way of opportunities.
I know our young people have aspirations for a better future. I know they have big dreams. And, I know that future is nearly within their grasp.
A thriving, strategically managed energy industry can make it possible for many of these young people, whether it leads to good jobs or it fosters the kind of economic growth that creates jobs in other fields. Even if we only get the lights on in their communities, we’ll be giving our young people hope and improving their chances of realizing their goals.
This is what drives me, the idea that with our ongoing efforts and determination, our young people can realize meaningful opportunities. I encourage each of you to work with us at the African Energy Chamber, in a spirit of cooperation and mutual respect. Together, we can build the kind of African energy movement that our continent, our communities, and our young people need and deserve.
To quote Joel Barker in The Business of Paradigms: “It’s so easy to say no to a new idea. Afterall new ideas cause change, they disrupt the status quo. They take people out of their comfort zones and create uncertainty.. plus it is less work to do things the way we have always done it…. less work, maybe. Costly, definitely”
New Ideas are resisted from greasy rig floors in the Niger Delta Swamps to cushy conference rooms in regulator’s offices in Abuja; each with very prohibitive cost of inaction.
Yet it’s business as usual in Nigeria’s oil industry, despite the current economic realities providing impetus for a radical transformation of its cost base. Pulling the ailing economy from the brink calls for a radical improvement in efficiency within its mainstay industry. Dwindling daily production and significantly reduced foreign exchange earnings, and foreign reserves, establishes the urgency to drive down unit cost per barrel of oil produced.
Simply stated, Today’s ‘Good’ is tomorrow’s ‘Not good enough’ and what sets us apart today will be the baseline tomorrow. The future belongs to those who act with urgency and foresight.
A huge, yet untapped opportunity
Successful upstream operations are underpinned by the ability to balance the trio of cost-schedule- production and maximize NPV i.e. produce the most barrels in the quickest manner possible at the cheapest mean cost across a portfolio of assets.
Incremental improvement in well delivery (drilling & completion) efficiency in the US had characterized the shale oil boom which effectively began in 2007. Efficiency gains cut well costs by a third and reduced cost per barrel by 75% in the decade between 2007 and 2017. In effect, America became an oil and gas power house within this period, doubled US Shale production and tripled total daily oil output.
In Nigeria, the oil and gas industry is the largest revenue contributor to the Nigerian economy, but production has declined by 40% from 2010 to date. Declining oil production presents major revenue challenges and precipitates chronic macroeconomic crisis in the short to medium term.
“Reducing unit production costs by driving down well delivery costs presents an untapped opportunity to increase government earnings & reduce its fiscal deficit “
Being the most complex, costly and highly specialized upstream development activity which easily accounts for up to 60% of oilfield development CAPEX,
Drilling presents a unique opportunity to reduce the cost of oil production.
For this reason, in the early eighties, Drilling Engineers and other personnel operating in the UK North Sea recognized the need to learn from each other and compare performances across each others’ drilling operations. This led to the formation of the drilling performance review (DPR) in 1989, a drilling benchmarking club. Majority of International operators who are value driven continue to subscribe to the DPR till this day for the inherent benefit to their global operations and enterprise financial performance.
In general, up to 60% of drilling time goes to Non-productive time (NPT) and inefficiencies which is known in drilling parlance as invisible lost time (ILT). The cost of ILTs, being an invisible factor, to the Nigerian oil industry is in the order of billions of dollars overspent annually.
Improving drilling performance therefore is an enabler to reducing cost of oil production. Lower drilling costs stimulates more drilling activities which in turn increases production and reduces unit production costs.
You can’t improve what you don’t measure
Drilling performance in Nigeria is laden with tremendous inefficiencies. An indicative benchmark of an average Nigerian, and similar North American well reveals significant underperformance in the Nigerian well as measured by days to drill a 10,000 feet well. A 10,000 feet well routinely delivered in 10 days in the US / Canada could take as long as 85 days in Nigeria. This disparity is surmised to be causative of the consistently high well delivery cost in Nigeria. Disproportionately long well durations delays time to market (deferred production), reduces project NPV – costly wells reduces the number of profitable opportunities which in turn reduces rig activities and associated demand for services.
By top down estimates, the industry spends circa $11.4Billion to produce 1.25Million barrels daily and approximately $6Billion in drilling wells. A 30% performance gap between the authorized expenditure (budget) and actual costs as gleaned from an analysis of Nigerian wells represents a $1.8Billion a year opportunity.
The relentless pursuit of excellence in well delivery begins with establishing key indicators which must be tracked with rigour and provides indication of drilling performance and efficiency trends.
An excellent drilling efficiency metric commonly tracked is the spend ($) per reservoir foot of hole. Looking at this metric in US land operations from 2006 to date shows the cost of a foot of exposed reservoir falling by 75% in over a decade when considering what was paid to the contract driller. Similarly, the directional driller cost per exposed reservoir foot fell from $45 to $35, a decrease of 25%.
In addition to the reduced cost per barrel, other implications of drilling efficiency gains break down as follows:
The price of contracting a rig in 2006 is now the price of four rigs in 2023 i.e four rigs can be operating today for what it cost 16 years ago.
Four rigs drilling means 300 oilfield workers employed (instead of 75 on one rig). This is direct labour. We know how many mouths get fed when 300 workers are employed instead of 75.
Four rigs working means higher rig count overall. Higher rig count means more services contracted e.g. wireline, mudlogging, casing and cementing crews etc. This means 4X the number of casing running crews, mudlogging crews, wireline crews etc needed (as well as the number of mouths each of them feed). Simply means higher activity and spend in the sector.
Four rigs working means more reservoir exposure, higher production, higher probability of new discoveries which increases reserves, and translates to higher revenues for the country in form of (a) increased government share of oil production and (b) increased taxes and royalties accruing to the state.
Where there is a will, there is a way
Investments in the Nigerian oil and gas sector declined by 70% between 2017 and 2021 closely correlating with the contracted output. Nigeria could only attract $3Billion in investments (approximately 5% of the total investment into the sector in Africa) in the five years between 2017 and 2022 despite having 38% of the continent’s total hydrocarbon reserves. As the government pushes for more transfer of resource ownership to locals via organized acreage farmouts and International Oil Company (IOC) divestments, the uncompetitiveness of Nigeria’s oil industry’s remains at its pinnacle.
For the sake of the industry some of us love for being the source of our livelihood, the hundreds of thousands of mouths it feeds directly and the hundreds of millions of Nigerians its long-term sustainability impacts, pulling the industry (and by extension the economy) back from the brink is not optional, but a matter of feral urgency and rest squarely with the industry regulatory agencies.
Tepid as the implementation has been, the Petroleum Industry Act emboldens the Nigerian Upstream Petroleum Regulatory Commission (NUPRC) to drive cost and capital efficiency in oil industry upstream operations. A total transmutation of the operating philosophy of the NUPRC from that of its predecessor agency- DPR (not the business as usual approach) will be required to unlock a $2Billion a year opportunity in these critical times as the oil industry continues hemorrhaging unabated.
Local operators and IOCs continue to battle a worsening capital drought and industry contraction. Stakeholders who will be convening in the nation’s capital on the 26th and 27th of June at the NUPRC organized industry consultative workshop will be seeking guidance from their host, curious to learn what fresh ideas will be unveiled that will provoke the cataclysmic effect to stem the existential crisis confronting the sector.
The current realities provides impetus to drive a deliberate drilling cost reduction. Effort should be made to reduce well delivery costs across all joint venture, sole risk and production sharing contract (PSC) operations for the lifeline it offers to an industry literally on life support.
Operators deserve insights and answers to these critical questions; which can be found in gigabytes of PDFs and thousands of hard copy folders sitting in dusty cabinets in NUPRC’s warehouses.
Who are the Best in Class Nigerian Operators across key performance metrics – (drilling efficiency (speed) and cost ($)) in each terrain?
What are the Performance Gaps between their own wells and the best in class wells?
What are the causative factors for the discrepancies in performance (gap) between their wells and the best in class wells?
What can they do to close the gaps and pull up their performance towards the best in class?
While they scratch their heads looking for answers, we recommend the regulator institute performance improvement programs that leverage the latest technologies and an abundance of human capital to drive the systematic optimization of drilling programs and commercial sustainability across the breadth of Nigerian drilling operations. This will serve as an economic stimulus by lowering all key metrics including unit operating as well as finding and development costs. It will improve the fiscal breakeven price of oil.
There is no standing still. We are either growing or dying and since we are not growing, as established by all indices, we challenge the custodians of this atrophying industry to lead, follow or get out of the way.
The author, who is also President & Co-Founder of Manup and a director at Vobiss Gridworx,has, in his 27 years of experience in the oil and gas industry, served as Country Manager, Nigeria at GE Oilfield Technology, Drilling Reliability Consultant at GE Energy Services, Drilling Performance Consultant / Coach at BP, Shell International, ConocoPhillips, Field Engineer / Field Applications Engineer Onshore and offshore drilling operations-related positions with Halliburton, Baker Hughes, Chevron. He contributes articles from time to time to Africa Oil+Gas Report
All of the oil majors— Repsol, BP, Shell, ENI, TOTALEnergies, Chevron, ExxonMobil and Equinor—are enjoying their highest earnings ever. Is the message from shareholders: do not tamper with our cash machine?
In spite of increased dividends and stock buyback programmes by oil majors, their share prices have shown mixed results. In the period 2018-2022, US oil giants Chevron and ExxonMobil have seen their share prices flourish: Chevron up 39% and ExxonMobil 26%. European oil stocks have floundered: Repsol down 5%, BP down 19%, Shell down 17%, ENI down 17%, TOTALEnergies up 7%. Only Equinor was up 57%.
In the period January-March 2023 their stock market prices have not changed.
In the same period (January 2018-December 2022) the Dow Jones Industrial Index rose 31%: increasing from 25,295 to 33,147.
Table 1: Stock market prices of majors 2018-2022(NYSE)
Year
Repsol
BP
Shell
ENI
TOTAL
Energies
Chevron
ExxonMobil
Equinor
2018
$17
$43
$69
$35
$58
$128
$87
$23
2022
$16
$35
$57
$29
$62
$179
$110
$36
Note: Values based on January 2018 and December 2022
Why is it that the share prices of Chevron and ExxonMobil have performed so well and their European counterparts have done so poorly (with the exception of Equinor)?
The message from the investor community is the clarity of the message. Chevron and ExxonMobil have as their mainstay–the production of hydrocarbons and this is the message that is preached. New energy policies including CCS (Carbon Capture and Storage) and other new energy initiatives make up only between 15-20% of their capital budgets. In the case of Chevron some $3Billion per year based on a capital budget of $15-$17Billion; ExxonMobil’s new energy comes in at $3Billion per year based on a capex of $23- $25Billion. The message is clear and simple: we are oil companies pure and simple. Done in the good tradition of John D. Rockefeller, the spiritual father of both companies.
European oil giants, have seen their dualism—wanting to maintain their green image and also profiting from the oil bonanza—fall out of favour by company shareholders. Their clarity of messaging has been found wanting. The sole exception is Equinor who has stated that the majority of its capex budget will be from renewables by 2030.
The Message from BP
For 2022, BP posted a profit of $27.7Billion( underlying replacement cost profit). In the period 2018-2022, BP shares were down 19%.
A key component of BP’s original green strategy was to build an investment structure, which would require only a few skilled accountants. The company sacked employees or was preparing delegating BP’s headcount to its joint ventures. The goal was to become lean and mean, reducing costs and, hopefully, increasing margins. In short becoming an investment vehicle. Instead the strategy has been turned on its head.
In Africa BP is becoming the junior partner to ENI. In Angola BP has merged its upstream activities with ENI to form Azule Energy. ENI has also taken over BP’s Algerian assets.
In 2020 BP painted a glowing picture of how it would attain its green future:
From 2025 onwards, when its low-carbon projects would start to kick in, expected growth of between 12–14% would be maintained.
Reducing its oil production by 40% by 2030.
Its $25Billion divestment would provide the basis for up-scaling its low-carbon business.
Spending $5Billion per year to green itself and by 2030 the company would have 50 GW of net generating capacity.
Now the company is clawing back on reducing its oil production. Again, the duality of message has not helped the BP share price.
On the green front the company has initiated a series of joint ventures to speed up its transition.
BP and Ørsted have partnered to develop zero-carbon ‘green hydrogen’ at BP’s Lingen Refinery in north-west Germany, BP’s first full-scale project in a sector that is expected to grow rapidly. The 50 MW electrolyser project is expected to produce 1 ton of hydrogen per hour – almost 9,000 tonnes a year – starting in 2024. The project could be expanded to up to 500 MW at a later stage to replace all of Lingen’s fossil fuel-based hydrogen. Final investment decision is due later this year.
BP and Equinor revealed that BP will become a 50% partner of the non-operated assets Empire Wind (offshore New York State) and Beacon Wind (offshore Massachusetts). BP and Equinor will jointly develop four assets in two existing offshore wind leases located offshore of New York and Massachusetts that together have the potential to generate power for more than two million homes.
BP joined Statkraft and Aker Offshore Wind in a consortium bidding to develop offshore wind energy in Norway. The partnership—in which BP, Statkraft, and Aker Offshore Wind will each hold a 33.3% share—will pursue a bid to develop offshore wind power in the Sørlige Nordsjø II (SN2) licence area.
The Message from Shell
Shell has just announced its highest results of the last 115 years: $40Billion in annual adjusted profit for 2022. Yet investor interest has been muted at best. Shell’s share price has only shown a downward spiral of 17% in the 2018-2022 period. Annual capital expenditures in the near term, according to Shell, could be in the range of $23-$27Billion up from an earlier estimate of $21-23Billion. Then the company stated that its renewables and energy solutions would be $2-3Billion, marketing $3Billion, integrated gas $4Billion, chemicals and products $4-5Billion, and upstream $8Billion. A more detailed breakdown is not available.
While its competitors—BP and TOTALEnergies—are busy buying and creating gigawatts of new energy, Shell maintains that it wants to focus on the value it generates for shareholders across the entire value chain. While the company is eager to proclaim value generation, there is little indication to shareholders what this means. For the period 2025-2030 Shell lumps together the capital budgets devoted to three categories:
Growth which entails renewables and marketing will receive 30% of Shell’s capital budget;
Transition which entails Integrated gas and chemical & products will receive 30-35% of Shell’s capital outlay; and
Upstream will get 30-35%.
The Dilemma of BP and Shell
Both BP and Shell continue to believe that their upstream divisions will provide the funding for their green future. Yet their share prices demonstrate that there is little trust in this vision. Depending on their upstream portfolio to lead them to a bright new green future is central to their dilemma. Upstream oil and gas is viewed by shareholders as a sunset industry. Upstream references, perhaps, a distant memory of the integrated oil companies of 50 years ago. Not one to build a green future on.
Both companies continue to believe in a dash of green and fail to understand the basic tenets of how the Green Alliance—Enel, Engie, Iberdrola, and Ørsted–is understood and viewed. What has set these companies apart is that they have created a huge competitive advantage which will be hard to challenge for newcomers. They have moved well beyond simply dabbling in green energy. These companies have become specialists and now moving on to the next level: creating a digital platform on which value does not reside in owning resources but rather in managing data-driven ecosystems. They are essentially borrowing a chapter from Uber, which does not own taxis or Booking, which does not own hotels. Some members of the Green Alliance have established new goals, such as CO2 neutrality by 2040, instead of 2050 to which Shell is pledged. Consider the competition.
Enel: committed to achieving CO2 neutrality by 2040 instead of 2050, achieving 75% of electricity from renewables and 80% digitalization of its customers on the grid by 2025. and having an installed generating capacity of 75GW by 2050.
Engie: pledged to reduce to CO2 neutrality by 2045, 45% of investments is focused on renewables and by 2030 will have 80GW of installed generating capacity.
Iberdrola: in the period 2023-2025 the company will invest $50Billion and achieve net zero for Scope 1, 2 and 3 before 2040. By 2030 the company will have installed capacity of 100GW, valued at $70Billion.
Note: Essentially, scope 1 and 2 are those emissions that are owned or controlled by a company, whereas scope 3 emissions are a consequence of the activities of the company but occur from sources not owned or controlled by it.
Ørsted: the Danish wind energy pioneer, continues to set new records. Ørsted share price in December 2022 was $93; five years earlier in 10 June 2016 it was $37. By 2030 the company’s goal is to have an installed capacity of 50GW. Ørsted is also involved with the building of two energy islands– Bornholm and North Sea– which will deliver 10GW of power
How will shareholders react to these companies in 2023? To date there is good news and bad news for green energy companies.
Table 2: Stock market prices of new energy companies 2018-2022
Year
Enel
Engie
Iberdrola
Ørsted
2018
$5
$16
$7
$49
2022
$5
$14
$12
$93
Enel, the Italian power company has seen its share price remain flat. Engie, the large French energy giant has seen its share price decrease by 12.5%. Iberdrola, the Spanish power company has had an increase of 71% and Ørsted, the Danish power company, has seen its stock soar by 90%.
Some Final Thoughts
BP
BP has become a company in search of its soul. BP’s strategy of reducing its oil production by 40% by 2030 has been cast aside.
BP’s Greater Tortue Ahmeyim (GTA) field in Mauritana and Senegal is one of the few oil and gas projects the company is developing.
For 2023 the company has earmarked up to $7.5Billion for oil and gas projects.
Shareholders continue to habour doubts about BP’s green vision.
Shell
Shell should seriously consider splitting the company in two key divisions:
An upstream division which could be hived off to joint venture with other upstream divisions to ensure economies of scale;
An integrated gas division which could prove to be Shell’s star asset.
Wood Mackenzie’s AET-2 Scenario (Accelerated Energy Transition Scenario) predicts that in the following decades, market power will shift from OPEC to the giant gas producers, such as the USA, Russia, and Qatar.
According to AET-2, the “Era of carbon-neutral gas is born. AET-2 would require $300Billion to support Liquified Natural Gas growth globally and $700Billion to support dry gas development in North America.” Given that Shell is the global leader of LNG (liquid natural gas)this is certainly a sweet sound for Shell’s LNG business.
Downstream could also prove to be a key energy transition asset. Shell’s REFHYNE Project, the Rhineland Refinery in Germany, could well become the precedent that the company needs to ensure it becomes the leading supplier of green hydrogen, where hydrogen production is powered by renewable energy for industrial and transport customers. Could the REFHYNE Project be duplicated many times over to ensure that green technology becomes a key ingredient in the energy transition?
Pay attention to Shell’s Pernis refinery in the Netherlands. One of the largest in Europe, Pernis refinery has a 400,000 b/d capacity and a complexity enabling the processing of many different crude types. The site is already deeply integrated with chemicals production and is being transformed into an integrated energy and chemicals park that will deliver low-carbon products.
The current message from shareholders is: maintain the cash bonanza and do not tamper with our cash machine. No doubt the share price of Chevron and ExxonMobil will continue to flourish. Will Europe’s oil and gas companies—in particular BP and Shell—resolve their clarity of messaging? How long will this cash bonanza last?
Finally, one should not mistake the current cash bonanza with energy security. Rather this is a sign of energy insecurity which could very quickly end without further notice. Energy security will continue to be a key theme for the coming generations and no doubt the role of the members of the Green Alliance will be crucial.
Gerard Kreeft, BA (Calvin University, Grand Rapids, USA) and MA (Carleton University, Ottawa, Canada), Energy Transition Adviser, was founder and owner of EnergyWise. He has managed and implemented energy conferences, seminars and university master classes in Alaska, Angola, Brazil, Canada, India, Libya, Kazakhstan, Russia and throughout Europe. Kreeft has Dutch and Canadian citizenship and resides in the Netherlands.He writes on a regular basis for Africa Oil + Gas Reportand is a guest contributor to IEEFA(Institute for Energy Economics and Financial Analysis) based in Cleveland, Ohio, USA. His book ‘The 10 Commandments of the Energy Transition ‘is on sale at https://books.friesenpress.com/store/title/119734000211674846/Gerard-Kreeft-The-10-Commandments-of-the-Energy-Transition.
In 10 unbroken years of active participation in the Practical Nigerian Content (PNC) Forum, organised by the Nigerian Content Development and Monitoring Board (NCDMB), the leading lights of Nigeria’s oil and gas industry have signified that local content has something of a creedal force in their ranks. In-country value addition through enhanced local capacities and capabilities remains the unchanging focus – what they must pursue and actualise to enhance the country’s economic performance and development.
The apostolic zeal of the industry stakeholders, as they assemble in their hundreds from year to year to appraise the state of the industry and to determine what way(s) to maximise opportunities along lines spelt out in the Nigerian Oil and Gas Industry Content Development Act, 2010, is most remarkable. In the spirit of collaboration and stakeholder engagement, issues of topical importance are ever adopted as themes for presentation and deliberations in different editions of the Forum.
Innovations at NCDMB and results
NCDMB and stakeholders have been thus guided in subsequent actions by way of interventions, policies and compliance. The Board gets more and more innovative as challenges emerge through workshops and exhibitions. Concepts and undertakings such as Nigerian Oil and Gas Technology (NOGTECH) Hackathon, Nigerian Oil and Gas Opportunity Fair (NOGOF), Nigerian Oil and Gas Industry Content Joint Qualification System (NOGIC JQS), and research and development funding, were in response to felt need and have bolstered the sector.
“Key Highlights of this year’s PNC Forum from December 5-8, 2022
Harnessing Nigerian content opportunities for indigenous companies in Nigeria’s “Decade of Gas”
What opportunities have been revealed by the Seven Ministerial Regulations for increasing Nigerian content compliance?
Outlining Nigeria’s future energy mix and Nigerian content objectives over the next 30 years
What are the enablers required to bridge the capacity gap for improved local content implementation with a growing focus on gas?
How can indigenous companies attract required funding?
What efforts are in place to explore Nigerian content opportunities in AfCTA?”
Together, the industry regulator and the oil and gas companies – upstream, midstream and downstream – have moved mountains, radically altering the status and image of Nigeria as rent-seeker and placing her in a respectable position as resource-endowed and with appropriate technological capabilities to efficiently exploit and utilise hydrocarbons.
What difference NCDMB has made
In twelve (12) years of implementation of the NOGICD Act, 2010, Nigeria, through the Board’s well targeted strategic interventions, has developed the widest range of competencies and facilities for engineering, procurement, fabrication, and a lot else, and thus upped in-country value retention from less than five (5) per cent in 2010 to forty six (46) per cent in the first quarter of 2022. And seventy (70) per cent is in focus as we march towards the 2027 terminal date of the Board’s Nigerian Content 10-Year Strategic Road Map.
Today the world-class fabrication yards and pipe mills have turned Nigeria into a hub for related businesses in the Gulf of Guinea, just as the country’s service companies now operate as international servicing companies in different African countries. That’s the success story of the NCDMB made possible by far-sighted and resourceful leadership that carries all stakeholders along, unhesitatingly intervening in material terms to bolster operational capabilities of companies. This year’s edition of the PNC Forum, scheduled for December 5-8, 2022, is another platform with great possibilities for participants and the wider society.
What to expect from PNC 2022
Face to face with potential clients and investors, participants in PNC Forum 2022 in Uyo, Akwa Ibom State, will deliberate on the theme, “Deepening Nigerian Content Opportunities in the Decade of Gas.” Key topics, as highlighted at the PNC dedicated website are:
Harnessing Nigerian content opportunities for indigenous companies in Nigeria’s “Decade of Gas”
What opportunities have been revealed by the Seven Ministerial Regulations for increasing Nigerian content compliance
Outlining Nigeria’s future energy mix and Nigerian content objectives over the next 30 years
What are the enablers required to bridge the capacity gap for improved local content implementation with a growing focus on gas?
How can indigenous companies attract required funding?
What efforts are in place to explore Nigerian content opportunities in AfCTA?
Conclusion
In the broadest terms the PNC Forum is billed “to help shape the Nigerian Content Agenda for the next twelve months.” Industry regulator and all stakeholders would hopefully be on the same page all the way, directing energies and resources in a manner that would best promote corporate success as well as national development. But economic spin-offs never fail, particularly for a host city and state, in this case, Uyo and Akwa Ibom, whose hospitality industry is already bubbling in anticipation of several hundreds of guests in early December.
PNC Forum 2022 is the place to be for fresh ideas and strategies in the nation’s quest for economic development through effective and efficient management of her abundant hydrocarbon resources, especially gas as the transition fuel for Nigeria.
Esueme Dan Kikile ESQ, is the Manager, Corporate Communications, NCDMB
Will the East African Crude Oil Pipeline (EACOP) ever be constructed? Public dissent has been mounting and financial hurdles have yet to be resolved. Continued delays only make the completion of this on-going saga more uncertain.
The Project
EACOP is being constructed in parallel with the Tilgenga and Kingfisher upstream development projects. Tilenga, operated by TOTALEnergies, will produce some 200,000 Barrels of Oil per Day (BOPD) and Kingfisher, operated by CNOOC(China National Offshore Oil Corporation) will produce some 40,000BOPD. Each development will consist of a Central Processing Facility (CPF) to separate and treat the oil, water and gas produced by the wells. Kingfisher will have 4 well pads and a CPF and Tilenga has 31 well pads. The Ugandan Refinery project has a right of first call to 60,000BOPD, with the remainder of the oil being exported via EACOP.
EACOP will have a length of 1,443 kilometres and export crude oil from Kabaale – Hoima in Uganda to the Chongoleani peninsula near Tanga port in Tanzania. At peak capacity it will handle 246,000BOPD.
The project dates its origins back to 2004 when Tullow Oil gained three exploration blocks following its acquisition of Energy Africa. In April 2020 Tullow sold all of its oil assets to TOTALEnergies for $575Million in order to reduce its debt and strengthen its balance sheet. TOTALEnergies’ vision was simple: purchasing Tullow Oil assets for next-to- nothing made it a no-brainer to move on to developing Tilenga and together with CNOOC, Kingfisher and EACOP.
The Next Hurdle
Time and events on the ground have proven difficult.
For example, the European Parliament’s resolution of September 2022, condemning human rights in Uganda and Tanzania, linked to investments in fossil fuel projects, have proven embarrassing to the French oil giant.
French President Macron has also indicated that France does not support this project.
Various interest groups have been extremely vocal and successful in their stand against the project:
The Climate Accountability Institute(CAI) have charged that during the 25-year lifespan of the project associated oil emissions would be more than double those of Uganda and Tanzania in 2020.
Omar Elmawi, coordinator of the Stop EACOP campaign, said: “EACOP and the associated oilfields in Uganda are a climate bomb that is being camouflaged us as an economic enabler to Uganda and Tanzania. It is for the benefit of people, nature and climate to stop this project.”
Stop EACOP Campaigners argue that, as the world’s longest heated oil pipeline which will run through many populated areas, it will contribute to poor social outcomes for those displaced. They also mention the significant risk to nature and biodiversity, as the pipeline runs through large areas of savannah, zones of high biodiversity value, mangroves, coastal waters, and protected areas, before arriving at the coast where an oil spill could be dire.
According to Elmawi, TOTALEnergies is still in search of $3Billion in order to complete the financing of EACOP. To date, he says, 24 banks, 18 insurance companies, and export credit agencies in France, Germany, Italy and the UK have refused supporting this project. “Already the project has suffered a three year delay”, the STOP EACOP campaigner claims.
How much delay can TOTALEnergies withstand before it walks away from the project and declare the necessary impairment charges? The delay will also ensure that TOTALEnergies’ financial team will be re-evaluating their energy portfolio. Think back to the summer of 2020 when TOTALEnergies announced a $7Billion impairment charge for two Canadian oil sands projects. This might have seemed like an innocuous move, merely an acknowledgement that the projects hadn’t worked out as planned.
Yet it opened a Pandora’s box that could change the way the industry thinks about its core business model—and point the way towards a new path to financial success in the energy sector.
While it wrote off some weak assets, it did something else: TOTALEnergies began to sketch a blueprint for how to transition an oil company into an energy company.
Patrick Pouyanné, TOTALEnergies’ chairman and chief executive, said that by 2030 the company “will grow by one-third, roughly from 3Million barrels of oil equivalent per day (BOEPD) to 4Million BOEPD, half from LNG, half from electricity, mainly from renewables.” This was the first time that any major energy company had translated its renewable energy portfolio into barrels of oil equivalent. So, at the same time that the company slashed “proved” oil and gas from its books, it added renewable power as a new form of reserves.
TOTALEnergies’ emphasis is on ensuring that its LNG portfolio and its renewables continue to grow to ensure shareholder income. Pesky oil projects which highlight climate opposition and encourage environmental activism, both local and international, are not the type of projects which promote TOTALEnergies’ shareholder stability.
Finally, COP27, the next UN Climate Conference, to be held in November 2022 in Egypt, will no doubt also become a rallying cry for stopping EACOP. Could EACOP become an African stranded asset much like the Keystone Oil Pipeline in the USA?
Gerard Kreeft, BA (Calvin University, Grand Rapids, USA) and MA (Carleton University, Ottawa, Canada), Energy Transition Adviser, was founder and owner of EnergyWise. He has managed and implemented energy conferences, seminars and university master classes in Alaska, Angola, Brazil, Canada, India, Libya, Kazakhstan, Russia and throughout Europe. Kreeft has Dutch and Canadian citizenship and resides in the Netherlands.Hewrites on a regular basis for Africa Oil + Gas Report, and contributes to IEEFA(Institute for Energy Economics and Financial Analysis). His book the 10 commandments of the Energy Transition is on sale at https://books.friesenpress.com/store/title/119734000211674846/Gerard-Kreeft-The-10-Commandments-of-the-Energy-Transition
In 2015, PricewaterhouseCoopers PwC, the global advisory firm, declared that a large pool of respondents to its annual survey were concerned that South Africa’s policy makers did not understand the hydrocarbon industry.
I read the report with alarm. I responded with a sense of outrage.
Governments sometimes make the wrong calls, I argued in a column, in a monthly edition of Africa Oil+Gas Report, with the example of the UK Government’s tax regimes that led to massive disinvestment in the North Sea. “But you can’t dismiss an entire government as having no clue about an industry”, I declared.
At the time, I was impressed by Pretoria’s roll out of its Renewable Energy Independent Power Producer Procurement (REIPPP) programme which had, between 2012 and 2015, attracted billions of dollars of investment in over 5,000MW of renewables without a single cent coming from the treasury. The government was considering the same strategy for getting natural gas into the energy mix. If that worked, I enthused, it could alter the downward trajectory of Africa’s most industrialised economy.
But I’d spoken too soon. By mid-2016, the country’s widely applauded renewable energy programme had been thrown out the window. Just one statement by Brian Molefe, then the CEO of Eskom, South Africa’s be-all and end-all of energy issues, and the entire REIPPP had collapsed like a park of cards. He said that the projects were too expensive, and when Eskom factored what it would pay the producers into its cost of delivering power from the sun and wind into homes, electricity tariffs would balloon. It turned out that Mr. Molefe’s statement wasn’t true in every material particular, but his remarks had shut down an entire industry. It would take the country a full four years to return to the renewables track, but significant opportunity had been lost.
Today, with the country gripped by excitement around significant discoveries of natural gas and condensates off its western coast by TOTAL, the French oil major, there’s a frenzied debate about whether government would speedily push, for passage, the draft Upstream Petroleum Resources Development Bill (Upstream Bill), released in December 2019.
It had always been assumed that, as an industrialised economy, South Africa has the absorptive capacity to monetise large discoveries of hydrocarbon at terribly short notice. In reality, South Africa is closer to what Mozambique was in 2010; a jurisdiction without a clue about how large sized, deepwater gas would be developed, than it is to Egypt in 2015; which took the discovery of 30Trillion cubic feet of gas in 2,000 metre water depth, to market by 2017. “One of the obstacles to open the economic potential of South Africa’s offshore operations is a lack of legislative certainty”, lawyers would tell you, “which has also been acknowledged as an investor deterrence:”
My experience, as an energy reporter watching the country’s attitude to procurement and utilization of hydrocarbon resources and allied energy industry, is that there’s no sense of urgency to create a coherent framework.
As I have written severally in Africa Oil+Gas Report, the absence of a framework for gas intake and utilisation is a core reason for the looming shutdown of the 200Million standard cubic feet of gas per day (200MMscf/d) state-run Gas to Liquid (GTL) plant which, at inception, was the largest such plant in the world. For 14 years now, as far as I know, government officials have expressed concern about the decline of gas feedstock for the Gas to Liquid plant, but all they do is flail their arms; no one has lifted a finger to do anything about alternative feedstock.
The absence of a coherent guidance on gas to industry is why Sasol’s importation of (currently about) 400Million standard cubic feet of gas a day does not come across as a leverage factor for what the country can do with gas.
In mid-2015, the government announced it was working on a Gas Utilisation Master Plan, GUMP, which analyses the potential and opportunity for the development of South Africa’s gas economy and sets out a plan of how this could be achieved. Key objectives were to enable the development of indigenous gas resources and to create the opportunity to stimulate the introduction of a portfolio of gas supply options. It’s been 68 months since the first announcement and the details of plan remains resolutely unfinalized.
The Upstream Petroleum Resources Development Bill (Upstream Bill), is the most current edition of a draft legislation that has stayed in parliament for over 10 years. Let’s remember how we got here:
Between the moment of the faceoff between Shell and the antifracking activists of the Karoo Basin in 2011 and the announcement of the GUMP in 2015, the Mineral and Petroleum Resources Development Act (MPRDA) returned to parliament for amendment. It stayed in debate mode, unpassed, for seven years, challenged, in part by Exploration and Production companies for harbouring certain clauses, one of which entitles the state to a 20% free carry in exploration and production rights and an ‘uncapped’ further participation clause allowing the state up to 80% at an agreed price or under a production sharing agreement. In the event, the executive arm of government decided to disaggregate oil and gas from mineral resources and present a different law in parliament that focuses strictly on hydrocarbons. That is how it became the Upstream Petroleum Resources Development Bill (Upstream Bill). Still, it has been talk talk talk.
There’s a bit of good news now, of course. The S.A. Government has enunciated a tactic, not a strategy for getting natural gas into the electricity fuel mix. In March 2021, energy minister Gwede Mantashe announced preferred bidders to provide emergency power to the country, which continues to face power outages. Of the eight bidders that are allowed provide a total of 1,845 megawatts from various technologies to be connected to the grid by August 2022, three bidders will provide 1,220MW of power from LNG. This will be the first formal introduction of natural gas into the country’s energy mix and it is not coming from any broad-based strategy to bring in gas to “energise the economy”. Let me provide a quick context.
In October 2016, a preliminary information memorandum, outlining the scope of a LNG Gas-to-Power programme was released by the Independent Power Programme office IPPO for prospective and interested bidders. The programme planned up to 3,000MW of Capacity from the gas-fired power generation facilities. Its first phase, targeting 2,000MW, aimed to identify and select successful bidders and enable them to develop, finance, construct and operate a gas-fired power generation plant at each of the two ports: Nqurra and Richards Bay in the Eastern Cape and Kwazulu Natal provinces respectively. The successful bidder would be required to put in place the gas supply chain to fuel the plant with gas from imported LNG and would provide the anchor gas demand on which LNG import and regasification facilities can be established at the Ports, providing the basis for LNG import, storage and regasification facilities, available also for use by other parties for LNG import and gas utilisation. This project has been on the back burner in the last four years and it has stalled. This IPP plan is not to be confused with the emergency power announcement of March 2021.
Nor can we tie the emergency power announcement to the Integrated Resource Plan, or IRP, published in October 2019, which seeks to chart the means by which the country will manage and meet its electricity needs leading up to the year 2040. The plan provides insight into the state’s 20-year approach to SA’s energy mix IRP 2019 envisages, among other energy types, some 1000 MW of Gas To Power capacity being introduced into the South African grid by 2024, with a further 2 000 MW to be added by 2027.
If we consider all of these halting steps and indecisions, we get a sense that there is no blueprint in the horizon, to ensure: Gas to Industry (GTI) through new gas infrastructure to such industrial zones as Mossel Bay, Coega (South) West Coast to Saldanha/Cape Town, which can reduce energy costs for SA manufacturing; enhance expansion/modernisation of existing state owned GTL plant; roll-out of Compressed Natural Gas (CNG) fuelled transport; natural filling station network and repowering of truck and bus fleets, leading to balance of payments savings (reduced oil imports); gas to communities (GTC) which can allow huge benefits for rural/poor communities (e.g. reduced wood consumption, increased safety).
Policy paralysis around hydrocarbon resources, whether mined in country or imported, is at the heart of why a natural gas market hasn’t taken off properly in South Africa.
The political elite says all the right things all the time about what natural gas can do for the slumbering economic giant of Africa. But nothing actually gets done.
The petroleum industry is in a bust cycle at the moment. The valley, this time, is deeper than any low the industry has been for decades.
But in the face of the hydrocarbon demand destruction brought on by the pandemic and the ensuing deferments of project FIDs, massive scale back of operations, and significant cash losses, the Nigerian Oil Industry delivered on some key issues.
NLNG Awarded EPC for Her Train 7
Nigeria Liquefied Natural Gas (NLNG) Ltd, in May 2020, in the thick of a global lockdown, awarded the Engineering, Procurement and Construction EPC contract for its Train 7 project to three companies. Saipem, Chiyoda, and Daewoo.
Africa’s biggest LNG producer expects over $12Billion to be invested in the project with anticipated 12,000 jobs during the peak of construction.
The Train 7 when completed will see Nigeria’s LNG output increase from the current 22Million Metric Tons Per Annum (MMTPA) to 30MMTPA, a whopping 35% increase. The project also set ambitious local content targets (total in-country engineering hours set at 55%, while the procurement for execution of the project is also pegged at 55%) which will spur economic activity as well as enhancing technical capacity of indigenous companies and people.
Waltersmith Petroma Commissions a 5,000Barrels of Oi Per Day Refinery
Waltersmith Petroman, a Nigerian independent, on November 24, 2020, commissioned her 5000 barrel per day refinery, the first phase in a planned 50,000BPD refinery project. The ground-breaking of the second phase (a 25,000BPD Condensate Refinery Project) was also carried out on the same day.
The first phase is expected to bring 271Million litres of refined petroleum products (Heavy Fuel Oil, Dual Purpose Kerosene, and Automotive Gas Oil) to the national and regional market. The delivery of the project is sure a step in the right direction, as it will help bridge some demand gap, conserve scarce foreign exchange deployed in importation of refined products, and provide jobs for the teeming youth population.
The Return of the Petroleum Industry Bill
The Petroleum Industry Bill is back on the floor of the National Assembly, Nigeria’s bicameral house of legislature.
It was forwarded to the Assembly by President Muhammadu Buhari, in September 2020, for consideration and passage. The Bill has had a long life of going to the Assembly and ending up not becoming law. The first time it was introduced at the National Assembly was in 2008. It has returned, in several variations, thrice after that.
The purpose, however, is the same: to reform the country’s hydrocarbon industry. The bill seeks to provide a legal, governance, regulatory and fiscal framework for the Nigerian Petroleum Industry and Development of Host Communities.
The Senate, the Upper Chambers of the House, introduced the Bill for First Reading, at its plenary session of Wednesday, 30 September 2020.
The National Assembly leadership, which includes The Senate [resident Ahmed Lawan and the Speaker of the House of Representatives Femi Gbajabiamila, has repeated assurances that the Bill will become law this time. The PIB proposes reforms which many industry stakeholders believe will bring clarity to the fiscal regime and spur investment. Amongst many other items, the bill seeks to spinoff stake in the State hydrocarbon company NNPC to a commercially driven and profit focused enterprise to be called NNPC Limited; to be incorporated within 6 months of the passage of the bill. In addition, the new bill also provide for two regulators – one for “Upstream operations and the other for Midstream and Downstream”. These entities will succeed Department of Petroleum Resources – DPR, the current industry regulator. Furthermore, the new bill makes provision for “Host Community Trust Fund” which is set out to develop key infrastructural and human capital development in areas of operations. Although the passage of the bill has been postponed to mid 2021, there is a sense that the jinx about the PIB will be broken with this administration and this edition of the Bill will actually become an act of parliament.
DPR’S Call for Marginal Field Bid Round
Department of Petroleum Resources (DPR), Nigeria industry regulator called for a bid round for a total of 57 fields in land, swamp, and shallow offshore terrains in the outgoing year 2020. This round came to many observers as a surprise given the peculiarity of the time (low oil price regime as caused by the twin knock of a pandemic and Russia – Saudi’s crave for market dominance) the bid was announced. Nigeria’s last licencing round took place in 2007. The first and last Marginal Field bid round was conducted in 2003.
The data room and other processes were done virtually given the reality of the pandemic. The completion of this bid campaign should help increase Nigeria’s oil production, create jobs and put money into government coffer in earned signature bonus, taxes and royalties.
This piece is contributed by Adeniyi Adeoloye, a Petroleum Geoscientist who lives and works in Dublin, Ireland. He holds a Master of Science Degree in Petroleum Geoscience from the University College, Dublin Belfield, Ireland. He is passionate about the transformation of the study of geosciences and market intelligence in the Africa Oil and Gas landscape. He will contribute from time to time to Africa Oil+Gas Report.
BP: A Takeover prey?
The chief obsession of Wael Sewan, Shell CEO since 2023, is to drive up the company’s stock price. His hydrocarbon narrative is mimicking that of Chevron and ExxonMobil.
The heart of the matter for Shell is that the company has continued to argue that this is a private( company) matter, not one involving the the Common Good.
The Joker in the Deck
ENI’s strong presence in North Africa—Algeria, Egypt, and Libya—could in the coming months become one of Europe’s substitute providers of natural gas. This region currently produces 648,000barrels of oil equivalent per day (BOEPD). The company operates in the frontier areas seldom mentioned in the daily news media.
TOTALEnergies’ energy production in the period 2020 -2030 “will grow by one third, roughly from 3MMBOEPD to 4MMBOEPD, half from LNG, half from electricity, mainly from renewables”, according to Patrick Pouyanné, the company’s Chairman and CEO.
Chevron: Stay vigilant
ExxonMobil: Don’t count your chickens…
On May 31, 2023 Equinor announced that it would delay by at least three years its Bay du Nord project in the deepwater Flemish Pass basin 500 km off the coast of Newfoundland, Canada. Why? Because the project would cost an estimated $12Billion. Only $12Billion you might think. Is that a reason for not developing this project at a time when oil and gas companies are showing record earnings? According to Equinor technical and financial challenges are the main reasons for the delay.
Yet Equinor’s reasoning is not directly related to the Bay du Nord capital costs. By 2030 the company is pledged to spending half of its capex on renewable energy. In 2024 its capital budget was $13Billion. On this basis Equinor’s capital budget for future oil and gas projects is rather restrained.
Choosing a Future Home
All of the oil majors— Repsol, BP, Shell, ENI, TOTALEnergies, Chevron, ExxonMobil and Equinor—are enjoying their highest earnings ever. Is the message from shareholders: do not tamper with our cash machine?
financial hurdles have yet to be resolved. Continued delays only make the completion of this on-going saga more uncertain.
Omar Elmawi, coordinator of the Stop EACOP campaign, said: “EACOP and the associated oilfields in Uganda are a climate bomb that is being camouflaged us as an economic enabler to Uganda and Tanzania. It is for the benefit of people, nature and climate to stop this project.”
