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COVID Will Not Stop First Oil From Senegal in 2023

Australian explorer Woodside Petroleum insists that COVID-19 would not stop it from reaching first oil from the Sangomar Field Development Phase 1 by 2023

The first oilfield development in Senegal “remains on track for 2023, in line with previous guidance”, Woodside declares.

“Woodside and its joint venture partners took an unconditional final investment decision for the Sangomar Field Development Phase 1 and commenced execution phase activities in January 2020”, the company explains.

“Since then, Woodside has taken early action to proactively manage the emerging impacts of COVID-19 on the supply chain and project schedule. We are working with project contractors, the Government of the Republic of Senegal and our joint venture partners to optimise near-term spend whilst protecting the overall value of the investment and deliver first oil in 2023”.

Nigeria: Petroleum Industry Legislation and the Urgent Need to Reform NNPC

By Najim Animashaun







Two reports published shortly before the COVID-19 lockdown paint a stark picture of NNPC as a sub-optimally governed and remarkably inefficient commercial enterprise that is also neither transparent nor accountable.

The first report by the Nigeria Natural Resource Charter (NNRC) is the 2019 Benchmark Exercise Report (BER 2019), which assesses Nigeria against a set of 12 Precepts that benchmark performance in the stewardship of petroleum resources. Precept 6 benchmarks the performance of a national oil company. It simply says: Nationally owned companies should be accountable, with well-defined mandates and an objective of commercial efficiency. NNPC scored red, meaning it performed poorly, for the 4th consecutive report, against this Precept. Unlike NNPC’s Precept 6 performances under previous BERs, BER 2019 observed limited improvements in some areas such as greater autonomy from government for NNPC to meet some of its Joint Venture funding obligations.

Since BER 2019 was released, NNPC has published audited accounts of its Strategic Business Units (SBUs), including the loss making refineries for 2018, on its website ( This is a significant positive milestone. However, there appear to be no audited accounts for the Central Headquarters (CHQ), where the Crude Oil Marketing Department (COMD) is located,  which according to the NNPC Monthly Financial and Operational Report for December 2018 accounted for 158.64Billion or nearly 45% of the total losses of 355.62Billion incurred by all NNPC SBUs and CSUs. Moreover, the issue of sustainability identified in BER 2019 is still a live concern.

While the above are laudable improvements in reporting performance,  a second publication, a policy brief titled “NNPC: The burden of Africa’s Oil and Gas Giant”  by #FixOurOil and BUDGiT – a civil society organisation devoted to fiscal and budgetary transparency – gave a more blunt assessment of NNPC’s actual financial and operational performance: “NNPC has been overwhelmed by commercial inefficiencies, scandals and a reputational damage that has lingered for nearly four decades” from the 1980 Crude Oil Sales Tribunal (Irikefe Panel), that investigated some $2Billion worth of earned equity crude that Nigeria failed to lift, to the 2017 NEITI request to probe the $15.8Billion of NLNG dividends traced to NNPC’s accounts that weren’t remitted to the Federation.  The report blames political interference, unreasonable demands of staff unions, a defective operating model, saboteurs and oil thieves thwarting the best efforts of some of “NNPC’s leadership… to improve the corporation’s commercial efficiency”

The net result is a heavily indebted NNPC that one former minister of state for finance said as far back as 2010 “is insolvent as current liabilities exceed current assets” by 745Billion. Six years later, as a leaked memo revealed, NNPC had total audited liabilities that stood at 7.5Trillion as of 31st December 2016. While it demonstrates NNPC conducted audits, it sadly did not and has not published these audited reports that suggest a staggering 10-fold increase in the 6-year period of record oil prices. How NNPC racked up crippling debt during a time of plenty is beyond baffling. In that memo, NNPC sought permission to apply NLNG dividends to meet petrol import obligations, putting the government, as an IMF Publication warned, “on the hook for debts the NOC has incurred” because NNPC is too big to fail.

Beyond debts as a measure of NOC efficiency, other crude measures can be found in an NOC’s (a) revenues and profitability, (b) its Refineries capacity utilisation or how efficiently it runs its refineries. A third measure (c) reserves and reserve replacement ratios is not considered here.  Measuring NNPC’s performance on revenues against Petrobras (of Brazil), and refinery capacity utilisation against Equinor, illustrates how inefficient NNPC is.

Comparing revenue and profit performance for the two years 2015 and 2018 makes for revealing contrasts between NNPC and Petrobras. Not least because Petrobras was in the throes of its most searing failure of governance as exposed by a bribery scandal dubbed “Operation Car Wash” during this period.  A scandal that ultimately contributed to a Petrobras CEO going to jail, Brazil’s president Dilma Rousseff’s impeachment and removal, and Brazil’s former President Lula Da’Silva’s conviction and imprisonment.

For Petrobras itself, the consequences were severe. In 2018, it settled on a fine of $1.7Billion with American authorities for Foreign Corrupt Practices Act violations. In 2015 it was forced to publish an audit report declaring it paid $2.1Billion in bribes, and also had to set aside $17Billion in contingencies. Yet by 2018, it generated $95Billion in revenues and posted $7Billion in profit. NNPC by contrast generated, according to its Monthly Operational and Financial Performance Report, some $16Billion in revenues and posted profits, at prevailing exchange rates, of $0.27Billion ($270 Million). In the absence of consolidated audited accounts, it would be speculative to attempt to aggregate and harmonise the separate audited reports of SBUs and CSU. Especially, as they appear not to include audited reports of CHQ.

Comparing Equinor and NNPC’s Refinery Capacity utilisation shows that Equinor’s three refineries averaged 92.8% capacity utilisation in 2018, to NNPCs three refineries of 11.21%. A 2015 comparison of average refinery capacity utilisation in the USA of 90.98% and Nigeria of 4.88% is even worse. Unless NNPC’s refineries can operate at 90% capacity they will continue to lose money.

Unlike Equinor and Petrobras, which are mixed ownership NOCs with government and private shareholders, Petronas and (to all intents and purposes) Saudi Aramco are wholly government owned like NNPC. Private shareholders in both Petrobras and Equinor are entitled to nominate their own directors onto the board. In the case of Equinor, there is even a board member to represent staff.  Petronas, Saudi Aramco and NNPC don’t have such constraints on board appointments. However, both Petronas and Saudi Aramco value diversity of expertise on their leadership teams or boards. In particular 5 of the current 11-member board of Saudi Aramco are independent directors. Two of the five are; Sir Mark Moody, a former CEO of Shell, and Mr Mark Weinberger, former chairman and CEO of EY the global accounting firm.

By contrast NNPC’s board has always been a bone of contention as can be seen from board tenure and GMD turnover.  The average tenure of a Petronas CEO is 6 years. The average tenure of a Saudi Aramco CEO is 9 years. NNPC by contrast has had 20 GMDs in 42 years, an average tenure of 2 years. It is no wonder that in a study surveying over 2000 NNPC staff members, Dr. Olive Egbuta observed that staff viewed GMDs as political appointees. With staff viewing their chief executive as a politician they can hardly be faulted for not operating as if they worked in a commercial enterprise.

The GMD is one of three government officials mandated by law on NNPC’s nine-member board, including the minister, whom the law designates as chairman unless an Alternate Chairman is appointed. Neither Saudi Aramco nor Petronas have the minister as a board member. It is unclear from the announcement whether the Alternate Chairman appointed in 2019, Mr Thomas A. John, remains in that position with the Minister on the board making 10 members. Since the Board was tasked with reducing costs, it would pay handsomely to have the expertise Aramco has on its board in a time like this. Of a potential pool of 10 board members, only 2 appear to have 15 years or more management experience in petroleum operations or cost management expertise. None compare to the experience or expertise of Saudi Aramco’s board.

By publishing audited accounts of its subsidiaries for 2018, NNPC is laying a positive marker in the march for greater transparency and accountability. Hopefully, these practices will survive this GMD and this administration to become ingrained in NNPC’s culture. It is also hoped that the audit is expanded to include CHQ and the opaque practices of the Crude Oil Marketing Department. In light of the dire economic situation in Nigeria, we cannot be shy about bold new endeavours.

Reforming NNPC therefore requires new thinking and new strategies. It starts with the recognition that NNPC is not and was never designed, from the beginning, to be a commercially driven enterprise. Had it been so those 42 years ago, it would have been capitalised, granted more operational autonomy and burdened with fewer regulatory functions in the NNPC Act. Its board would reflect that of a commercial enterprise, even if government owned like Saudi Aramco, with fewer ‘political appointees’. This defect can only be remedied by passing a new law – the Petroleum Industry Bill, which goes to great lengths to separate commercial from regulatory, and asset management functions, leaving the national oil company to focus on what it does best, find and produce petroleum.

However, passing the PIB will never be enough on its own. Implementation requires ensuring that the habits and culture of the past do not infect the new organisation. This means putting in place a board of the most proficient hands with the skill sets needed to turn our strategic national assets into productive wealth to drive and diversify our economy. This also means keeping an eye on the future of energy by having effective energy transition strategies to make sure that we do not become prisoners to our past.

Najim Animashaun

Partner at Gulf of Guinea Consulting in Abuja

The Rise and Fall of an Oil Giant: How Canada’s Province of Alberta Gained its Oil Prominence and Lost its Lustre

By Gerard Kreeft







Many Africans, who have worked in the  oil and gas industry  encountered Albertans, who inevitably  have been sent abroad to work in  Africa’s oil and gas industry, either in a technical, managerial or training capacity.

Many Africans also have  been invited to the city of Calgary, Canada’s equivalent to Houston, Texas, the world’s oil capital, and participated in technical training sessions. In particular, learning to survive Alberta’s winter cold with temperatures sometimes plunging as low as -50C. Boot camp of a technical nature.

Province of Alberta

Canada is one of the world’s largest oil and gas producers averaging 4.7MMBOPD(millions of barrels oil per day) according to CAPP(Canadian Association of Petroleum Producers). Some 78% of this production comes from Alberta and additional smaller production comes from  the neighbouring province of Saskatchewan and Offshore East Coast Canada.

To understand Alberta’s DNA it is necessary to go back in time and dust off our history books.  In particular re-visiting  Democracy in Alberta: Social Credit and the Party System(1953), the authoritative book by C. B. Macpherson, Professor of Political Science, University of Toronto.

Macpherson takes us back to the early formation of Alberta: an  agrarian co-operative landscape. In 1900 Alberta’s population was 73,000 persons. The common theme was a one-staple economy, based on  a homogeneous farming community with its key emphasis on wheat.  The United Farmers of Alberta (UFA) came to power in 1921 and governed the province until 1935.  The UFA’s sole goal was to promote the interests of Alberta farmers. Central Canada, its business and financial interests, and the Federal Government were seen as the ‘bad guys’.

By 1935 the Social Credit Party swept into power. The new norm had become ‘virtually  a one-party system, cabinet rule, and a revised tradition of direct delegate democracy’.

Times have changed—the UFA and the Social Crediters have passed on but we also have had various Governments —but the common theme is that the province in the past had a one staple economy. The wheat and the farmer may have disappeared but the new commodity became oil and the farmer who Macpherson described as petit bourgeoisie has been superceded by a more urban set of elites- lawyers, engineers, geologists, oilmen, government bureaucrats, wheeler-dealers. Their class or status  can also be described as  ‘petit-bourgeoisie’…but urban as opposed to rural. As oil production increased oil prices surged. The money poured into Alberta. It was party time.

Now Alberta’s population is more than 4Million people. The Calgary- Edmonton corridor is Alberta’s most urbanized area and one of Canada’s four most urban areas.

Macpherson’s assertion that once a quasi-party state (Alberta) has been established in a quasi-colonial and predominantly petit-bourgeois society it may persist indefinitely if growth is assured. That growth is now not assured.

For the last 70+ years, since the founding of Alberta’s oil industry the province has achieved a level of unknown prosperity. Alberta’s per capita GDP, before COVID-19 struck was the highest in the country: C$ 80,000 (US$60,000) compared with C$60,000 (US$45,000) nationally. Yet the present signs are not encouraging:

Due to the impact of the Russia – Saudi Arabia oil price war and COVID-19, Western Canada Select (WCS) the price obtained for many Alberta oil and gas producers, averaged only US$3.50 per barrel in April 2020, more than 90% lower than it was a year earlier. West Texas Intermediate(WTI) averaged US$16.55, 74.1% lower than it was a year earlier.  The differential of WTI over WCS was US$13.05 in April 2020.

Prices of WCS have improved somewhat, in mid-June WCS was up to US$24.60 per barrel but that is still painfully down from oil prices of a year ago.

Although the price of WTI and WCS are extremely low, what is really painful for Canadian producers is the discounted rate that Canadian producers receive. The reason? Alberta is landlocked. It sole access to overseas markets is via the TransMountain Pipeline to Vancouver, British Columbia which has a limited capacity of 300,000BOPD capacity. All other oil not consumed in Canada is shipped to the USA.

Now, the USA is awash in oil, due to the impact of fracking of shales in the Williston Basin, North Dakota as well as the Permian Basin of Texas and New Mexico.

The Americans really do not need Canadian oil. Accordingly, Canadian producers must accept huge discounts if their oil is indeed brought to market.

Despite the low oil price the Provincial Government is predicting in its 2020 April budget a WTI price of US$58 per barrel, increasing to US$63 per barrel by 2022/2023.

Alberta was scheduled to produce 3.81MMBOPD in 2020; based on OPEC’s intervention it is anticipated that Alberta will be forced to cut its production by 1MMBOPD.

Pipeline Politics

Much of Alberta’s oil production to date has been focused on oil sands production, located in Northern Alberta. These are also commonly called “the tar sands”.  The crude bitumen is a thick, sticky form of crude oil so heavy and thick (viscous) that it will not flow unless heated or diluted with lighter hydrocarbons.

Alberta’s oil sand production in 2019 was 2.9MMBOPD.  Alberta also produced 800,000BOPD of conventional crude. In the  past, oil sands production predictions  were as high as 5MMBOPD. CAPP (Canadian Association of Petroleum Producers) is still predicting oil sands production of 4.2MMBOPD by 2035.  This, in my view, is excessively optimistic.

A false optimism also abounds on the pipeline front. The expansion plans for the TransMountain Pipeline, adding an additional capacity of 590,000BOPD has become stuck in regulatory and environmental haggling. The Federal Government chose to step in and purchased the TransMountain Pipeline for C$4.5Billion. The Federal Government now has to deal with judicial reviews and objections and consultations with various indigenous communities who vigorously object to this activity taking place on their ancestral lands.

Cynicism abounds concerning the purchase of the Trans Mountain Pipeline by the Federal Government. Was it to solely placate Alberta’s oil interests? So that the Federal Government could be seen to be in lockstep with the Alberta Government? Knowing full well that such a pipeline will likely never be built, given the  regulatory clamour and environmental protests.

Plans for The Keystone Pipeline, which was to be used to transport oil sands crude to the USA, is also in limbo given that Joe Biden, Democrat Presidential Candidate has expressed his opposition to this project.  Indeed, President Obama and his Secretary of State, John Kerry were much against  the Keystone Pipeline with both declaring Alberta’s tar sands to be the world’s dirtiest  oil.

Business as Usual?

Canada has pledged to respect and implement the Paris  Climate Agreement. Yet all good intentions aside, the road ahead is an uncomfortable journey:

  1. Any pipeline plans are unlikely to be implemented;
  2. Oil sand projects are unlikely to be expanded and perhaps discontinued;
  3. Discounted Western Canadian Select vs West Texas Intermediate Oil is a guarantee that oil prices will continue to bottom out, ensuring a virtual moratorium on oil production.
  4. Are Alberta’s oil and gas resources fast becoming ‘stranded assets’?

Alberta’s Provincial Government has made some feeble efforts to move in the direction of an Energy Transition. For example its C$1.1Billion commitment to the ‘Petroleum Diversification Programme’, providing royalty credits to companies that build large-scale projects to turn ethane, methane and propane feedstocks into products such as plastics, fabrics and fertilizers.

The Government also mentions Canada LNG which will transport LNG to Pacific Rim countries. The Government claims that Alberta natural gas will be sourced; but the lion’s share of the project’s  natural gas will come from Northern British Columbia!

Will there  again  be a populist revolt such as when the UFA were turfed out by the Social Credit Party in 1935, and the Social Crediters in 1971? The present Alberta Government is anxiously looking about in a hope of saving its oil economy. Can the one dimensional characterization of Macpherson’s petit-bourgeois class  become more divergent?

Now that the oil has for all intents and purposes disappeared,  what will be the driving force that Albertans will have to find? The great big party is over, the atmosphere in Alberta is like attending a funeral. Alberta’ Premier, Jason Kenney, announced that due to the impact of COVID-19 and the collapse in oil prices, Alberta may incur this year a deficit of C$20Billion.

For the last 75 years oil has literally been the fuel that has driven the economy. All the talk about diversifying the economy was pious nonsense. Instead it smothered innovation. Perhaps this type of crisis is necessary to stimulate a new generation. Getting back to basics.  Perhaps something as basic as encouraging more tourism in the Rocky Mountains of Banff and Jasper and elsewhere in the province..

Question: How much oil money is beneficiai for an economy? What is the tipping point when a petro-economy fails to encourage innovation and diversification? In that sense  can the lessons of Alberta  also be useful to Africa, where oil  in a number of countries, i.e Algeria, Angola, Congo Brazzaville,  Egypt, Equatorial Guinea, Gabon, Ghana, Mozambique and Nigeria is a prominent factor of economic growth?

Macpherson has made a key assertion: once a quasi-party state has been established in a quasi-colonial and predominantly petit-bourgeoisie society, it may persist indefinitely, if growth is assured. This is not only a lesson directed to a developed economy such as Canada. His assertion could also provide valuable lessons to many of Africa’s emerging economies which are heavily oil dependent.

Gerard Kreeft, MA (Carleton University, Ottawa, Ontario, Canada) Energy Transition Advisor, has more than 30 years experience in the energy sector. He was the founder of EnergyWise.  He has managed and implemented oil and gas conferences in Alaska, Angola, Brazil, Canada, Kazakhstan, Libya and Russia. He is a Canadian/Dutch citizen.

Rystad Predicts Massive Plunge in Libyan, Nigerian Reserves

By Ahmed Gafar, in Lagos

Rystad Energy is revisiting the concept of Peak Oil.

The Norwegian consultancy is arguing that the effects of COVID-19 will ultimately force significant reduction in appetite for frontier exploration.

The company has startling predictions for the growth or decline of crude oil reserves in African jurisdictions, especially the Top Four holders of crude.

Rystad says of Libya, where the warlord Khalifa Haftar has only just been stopped in his drive to take Tripoli: “With no imminent peace in sight, future production potential falls further by 4Billion barrels”.

About Nigeria, Rystad says: “after a decade-long debate on oil policy reforms, potential reserves are expected to fall further by 6Billion barrels”.

Rystad acknowledges positive news on oil policy reforms in Algeria, but in spite of that, it expresses the gloomy view that “shale exploration potential is expected to fall by 7Billion barrels of oil”.

For Angola, Rystad forecasts “less deepwater exploration as peak oil demand comes sooner due to COVID-19”.

But it does not say how much future reserves increase Angola will lose.



COVID-19 Imposes Fewer Workers, Longer Onsite Days for Rigsite and Production Operations

By ManUp Services

The COVID-19 pandemic pushed oil prices to a historic low in April when futures fell below zero dollars, kickstarting a new normal for operators and service companies going forward, or at least till the pandemic is contained.

Previously forecasted gains for 2020 have been hugely eroded as E&P companies are set to lose a whopping $1Trillion in revenue, according to analysts at Rystad Energy.

The social distancing guidelines and associated lockdown measures have thrown up operational limitations for exploration and production companies. Upstream operators are constrained to introduce measures towards protecting employees, particularly those working on remote facilities.

To contain the spread of the virus, offshore workers must balance maintaining social distancing while living and working in relatively confined spaces.

“Rigs, offshore production platforms, and other production facilities among others have generally reduced personnel aboard to avoid overcrowding”, says Isaac Ebhohimhen, Measurement & Allocation Manager, Aiteo Eastern Exploration and Production Company Limited, a key Nigerian operator. “This process reduces the chances of spread of the pandemic”.

To further ensure the health and protection of workers, companies have now adopted an extended work rotation from 14 to 28 days to reduce the likelihood of spread via frequent contact. This means that any personnel scheduled to go to the field is first quarantined for 14 days for close monitoring before certified fit to go to the worksite by a medical officer. Furthermore, projects not critical to oil & gas production have been suspended and non-core-crew members are unauthorized to mobilize to site except absolutely necessary or critical. This is to prevent the possible spread of the virus from outsiders to site-based personnel. Oil companies have deployed additional medical officers to production facilities for continuous personnel monitoring and early detection of signs and symptoms of the virus. Additional Personal Protective Equipment (PPE) has also been deployed to site for medical & work personnel. More importantly, as adopted by oil majors, medical facilities offshore have been upgraded to manage COVID-19 in the event of an eventuality.

Beyond protective measures being put in place for the safety of staff, the need for social distancing has also disrupted the normal flow of work as most oil companies are still working remotely while they figure out what changes need to be made in their office configurations. Since fewer workers are present on location, field personnel have to work longer days resulting in work-related stress, which has heavily impacted the speed and efficiency of operations, while movement restrictions on operational bases have introduced supply chain constriction and difficulty. In the light of travel restrictions, work activities that require expatriates have been suspended while office resumption plans contemplated by most operators post lockdown, is for departments to be divided into two groups working on two-weekly rotations to ensure social distancing. Despite the new normal in working conditions, companies, determined to keep operations running have adjusted to working from home and employees have reported issues such as having to work longer days, the pressure to remain productive amidst domestic distractions, discomfort due to lack of office type infrastructure, poor internet facilities, limitation due to lack of work tools like printers, scanners, etc.

So far, COVID-19 has remained resilient and continually portends a potent threat to lives and livelihood. National corporations such as the Nigerian National Petroleum Corporation are faced with a double whammy scenario; OPEC imposed reduction in production coupled with increased direct and indirect costs associated with battling the pandemic have directed operators to reduce operational budgets by 40%. This has severe implications such as drastically reduced activity and attendant diminished demand for oilfield personnel. Experts who spoke exclusively with ManUp believe that loss in man-hours would be regained with ramped-up demand in personnel and projects when activities pick up.

Optimism has never been an effective strategy to weather the severity and impact of operational slumps in the industry, rather, every downturn presents an opportunity to re-tool and adjust operating models to align with the prevailing realities of the time.

ManUp services are organized to alleviate the operational difficulties imposed by budget reductions availing service companies access to a platform, where a fast growing pool of skilled freelance oilfield personnel can be sourced quickly and competitively.


NDEP, In Historic 25TH Annual General Meeting, To Announce Record Revenue Breaks

Niger Delta Exploration &Production will be releasing some record financial achievements at its 25th annual general meeting next Wednesday June 17, 2020.

The Nigerian integrated oil and gas company, with assets including a marginal field, share in an Oil Mining Lease, a natural gas processing plant and a Refinery (in Nigeria) as well as E&P stake in South Sudan, has been run as a structured organization owned by shareholders since 1996.

Today there are 1,623 company shareholders.

NDEP, in 2019, increased average daily production of its flagship asset, the Ogbele marginal field, to a record 7,500 Barrels of Oil. (7,500BOPD).

The company recorded its highest revenue from crude oil production in the past decade, as a result of three key factors, in the opinion of its management:

  • Strong asset quality
  • Operational excellence
  • Sustained share of profit from our associate (ND WesternLtd, which is a 45% equity holder in OML 34 in the Western Niger Delta).

NDEP is always proud to speak of its midstream to downstream achievements.

Ladi Jadesinmi, the Oxford trained lawyer and latterly accountant who is Chairman of the board of directors, speaks of “spectacular inspired piece of forward thinking” delivered by Management some 10 years ago, namely “ the foray into refining with NDEP successfully investing in a mini refinery”, adding that this was the first of its kind in Sub-Saharan Africa.

The Licence to Operate that refinery was granted by the regulatory authorities in 2012.

2012 indeed, was the year of breaks for NDEP

It was in that year that the company also commissioned “our 100 MM Scf/d Ogbele Gas Processing Plant. It was in that same year that NDEP led a consortium of companies via a special purpose vehicle (SPV)ND Western Ltd, to acquire the 45% equity interest divested by SPDC, TOTAL and NAOC in OML 34. “This our associate remains the leading JV partner to NPDC”, the company claims.

Of the year under review, however, NDPR, the NDEP subsidiary which operates the Ogbele marginal field,  recorded an outstanding total production of 2,162,003 bbls (reconciled injected volume) of crude oil into the Bonny Terminal

Revenue  from crude oil increased to 38.3Billion (2018: 29.4Billion) as a result of an increase in our production despite the market’s volatility, which caused the average realized price to drop to $65/bbl (2018: $74/bbl).

Revenue from diesel dropped in the year to 4.6Billion (2018: 5.2Billion) because of plant maintenance activities and outages due to integration to our Train 2 under construction.

Natural gas revenues dropped to 3.0Billion (2018: 4.4Billion) as a result of lower realised prices. Overall, total revenue grew by 16% to 46Billion (2018: 39Billion), a testament to the resilience of the company, NDEP management says.

Kenya’s Post COVID-19 Oil & Gas Future: Some Insight

Kenya’s oil and gas industry is in a state of transition, as its major oil and gas development — Blocks 10BB and 13T in Turkana — has been put on hold, with Tullow Oil submitting a notice of force majeure to the Kenyan Ministry of Petroleum and Mining, citing complications from COVID-19.

Meanwhile, Uganda’s Lake Albert Project is moving ahead, with TOTAL announcing plans to acquire Tullow Oil’s stake in the project. The massive development in Uganda, which is set to include a pipeline and refinery, could easily have an impact on regional oil and gas developments and opportunities.

“Force majeures are reactive for companies, it is something that is beyond their means or the problem there are facing. So, it is unfortunate that this has happened in Kenya”, said Elly Karuhanga, Chairman of the Uganda Chamber of Mines & Petroleum & Chairman, Private Sector Foundation Uganda, “but it is also unfortunate that Tullow had to exercise this in their business. When you think about the reasons they faced, they had no alternative.”

He was speaking at a webinar themed ‘Moving Kenya Forward: Oil Production and New Exploration Under COVID-19,’ organized by Africa Oil & Power and the African Energy Chamber.

The webinar participants noted that Kenya has the most natural resources and is the most explored country in the East African region and argued that in order to have a knock-on effect and attract investors in this climate, East African countries need to keep exploring and looking at other projects. In Kenya, there are offshore blocks operated by ENI and hopefully with a great oil flow they will help the economy.

Toks Azeez, Sales and Commercial Director for Sub Saharan Africa for Baker Hughes, says his company expects the transition into Kenyan deep-water explorations to be less difficult, because it is already involved in offshore projects across Africa and has actively interacted with ENI in Kenya. “For us it is more about, how do we get our local partners in Kenya who have been involved in the onshore activities, to then up their game a little bit to meet the offshore requirements and that’s going to take a lot of back and forth, integration, cooperation to get them to a point where the skillset of that personnel and the equipment that they have and intend to acquire will be able to meet the requirements of deep-water play,” said.

Speakers encouraged synergies and regional collaboration to overcome the challenges faced by the oil and gas industry. Local companies as well as countries need to come together to find a solution to them. According to Mwendia Nyaga, Chief Finance Officer of Oilfield Movers. “Companies can scale up from the location at which they are based and start working in other places. For me it is cooperation, synergizing and not over complication.”

African governments are advised to think about the long-term effects COVID-19 has on oil and gas projects as well as how to regain investors’ appetite, “You should always look at fiscal incentives that allow fair and equitable taxation on revenues, but allow an investment environment that is lucrative, because every dollar in our industry can go anywhere in the world. East Africa, big companies and the small -medium sized oil and gas companies, will look at the investment climate as to where they get greater bang for their buck and that will mean that if the East African region does not have favorable fiscals then the dollars will go elsewhere, where you will get better bang for your buck, so there is a balance. When government is looking at this to be able to enable an environment where investment will be made, knowing that the risk is carried by the investors initially,” said Brian Muriuki, Managing Director & Country Chair of Royal Dutch Shell Ghana.

Doris Mwirigi, Chief Operating Officer of Energy Solutions Africa closed by sharing her belief that the oil and gas industry is in a transition, seeing that oil prices are slowly recovering to pre-COVID-19 prices. “In Kenya we are already at the forefront in terms of green energy and if you look at it, we are still very dependent of fossil fuels. So, you find that we are ahead in terms of green energy, however, I am still an oil girl and believe that oil and gas will recover, and in any case as you can see globally, the oil prices are prices are coming up and if you look at the equity market the oil prices are good for oil companies, so I think oil and gas will still play a major role in the oil and gas mix and we will be here,” she said.

Mwirigi also touched on the involvement of women and how the EqualBy30 initiative will empower more women in the oil and gas sector, “When you talk about adding women, it should not be just about diversity, but a business decision because companies headed by women do better. So, it’s not even a cry for help or diversity but business sense.”


Review of Report on AfDB President Will Take at Most Four Weeks

The Board of Governors of the African Development Bank, while accepting the idea of an independent evaluation of whistleblowers’ accusations against the bank’s president, Akinwunmi Adesina, has determined that such an evaluation will be a review of the report of the Ethics committee, which had cleared the president of any wrongdoing.

The review will be entrusted “to a single person, neutral honest, of high calibre with indisputable experience and a proven international reputation”, the Board said in a release. And the review work must be carried out “within two to four weeks, taking into account the Bank’s electoral calendar”.

The election to the AfDB’s Presidency, for which Adesina is the only candidate to date, is due to take place at the end of August.

The statement says that the “review” of the report of the ethics committee was a decision taken “with the aim of reconciling the different points of view of each governor in the resolution of this case”.

The Board reiterates its confidence in the ethics committee “which has fulfilled its role in this matter”. However, the Bank’s whistle blowing and grievance handling policy “will need to be reviewed within three to six months of the review to ensure that this policy is properly applied and to review it, if necessary, to avoid situations of this nature in the future”.


SA’s Top Oil & Gas Conference Venue Converted to COVID-19 Hospital

By Ahmed Gafar

The Cape Town International Conference Centre CTICC is awaiting, not a horde of oil and gas executives in the next three months, but a throng of patients coming under care of the state for COVID-19.

The facility, which hosts Africa Oil & Power in June and the Africa Oil Week in November, has been converted to provide 860 hospital beds to coronavirus patients.

The Africa Oil Week, the most prestigious large gathering of Africa-focused oil and gas executives, has taken place at the CTICC for over 10 years.

The venue has also hosted other top-notch gabfests, including the World Economic Forum for Africa and the Cape Town Book Fair.

But when President Cyril Ramaphosa chose the CTICC as the place to meet with Alan Winde, Premier of the Western Cape Province, last week, it wasn’t as a speaker at a business conference.

The two leaders spoke as co-stakeholders in the war against the rampaging virus that had laid waste the commanding heights of the South African Economy.

“I still think that faced with the challenge that we have of greater infections… “, Ramphosa told Mr. Winde, whose province is host to the highest number of COVID-19 cases and 77% of the deaths from the virus in South Africa.

. “You will need and you do need more beds. We must increase the number of beds. I am not happy and satisfied with the limit you think you are going to have,” Ramaphosa said at the meeting at the CTICC.

Mr. Ramaphosa’s June 4 visit came a day after South Africa registered its biggest daily increase in infections with 3,267 new cases, taking the country’s total number of infections above the 40,000 mark. Of these, 27,006 were recorded in the Western Cape.

While the organisers of Africa Oil Week are still going about saying the conference would hold, President Ramphsa says “the worst (of the infections) is still and yet to come”,  a comment that indicates that physical planning for a November conference at the CTICC, could mean tough logistical challenges, if it happens at all.



Aker Will Use Two FPSOs For the Pecan Project in Ghana

By Toyin Akinosho, in Lagos

The Norwegian independent, Aker Energy, says it has changed its development concept for the Pecan field in ultra-Deepwater offshore Ghana.

The company will be using two FPSOs to drain the 450Million barrel (probable) reserves.

While the original field development concept was based on a centralised Floating Producing Storage Offshore (FPSO) vessel, supporting the development of the entire Pecan field, as well as tie-ins of all other area resources, the focus has shifted toward a phased development approach.

“This approach will enable Aker Energy to commence with one FPSO for Pecan in the south and expand to a second FPSO in the north after a few years, with tie-ins of additional discovered resources. The first FPSO will be deployed at around 115 kilometres offshore Ghana over a subsea production system installed in ultra-deep waters in depths ranging from 2,400 to 2,700 metres”.. ”, Aker says in a widely distributed release.

There has always been the suggestion of phased development, but Aker never said anything publicly about two FPSOs.

The Pecan field was discovered by Hess Corp. in December 2012. The American independent sold its equity on the asset, along with operatorship, to Aker Energy in 2017. The Norwegian explorer immediately ran with the project, hoping to take the discovery to market by 2022.

Aker concluded an appraisal campaign, involving three wells, in mid-2019 and announced that “reserves, to be developed in the first phase, are estimated at 334Million barrels of oil. Discovered contingent resources, to be developed in subsequent phases, are estimated at 110-210MMBOE, resulting in a combined volume base of approximately 450–550MMBOE. These estimates exclude any additional volumes from Pecan South and Pecan South East, currently being assessed”. Aker further declared it had “identified further upsides in the area that we intend to mature as part of the area development”, adding that “the total resource potential in the area is within the range of 600-1000MMBOE.”

In March, however, the company announced that a final investment decision (FID) had been placed on hold, postponing the project.

Today, it said: “While no new date has been set for the FID, the company is working actively to confirm the feasibility of a phased Pecan field development by executing conceptual studies.

Aker says that the phased development of the Pecan field and the utilisation of a redeployed FPSO vessel will substantially reduce the CAPEX and, hence, reduce the breakeven cost. In addition, it will increase the possibility of reaching a commercially feasible project that will allow for an investment decision. Aker Energy and partners are currently assessing several FPSO candidates for redeployment, and the final selection will be based on technical capabilities and cost.

Aker Energy is the operator of the Deepwater Tano Cape Three Points (DWT/CTP) Petroleum Agreement, with a 50% participating interest in the DWT/CTP Petroleum Agreement. Its partners include the Russian explorer Lukoil (38%), the Ghana National Petroleum Corporation (GNPC) (10%) and the indigenous company Fueltrade Limited (2%).

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