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”.
The Nigerian government, obviously betting that its estimated 2.3Billion barrels of discovered but mostly unappraised crude oil reserves across 183 fields considered marginal are peculiarly coveted, launched the 2020 Marginal field bid rounds at the end of May 2020. The fee structure as published in the advertised bid guidelines suggest the exercise is a desperate move to raise capital by a government on the verge of a second recession in five years. Pundits, however, believe the timing for the bid round could not be more inauspicious given the global pandemic that has thrown the world into severe health and economic crisis. With resource ownership and production dominated by the five major International Oil Companies (IOCs) operating in the country, the government in 2003 formally transferred ownership of 24 fields to Nigerian companies following the 2003/4 marginal field bid round and between then and now have approved the transfer of $10Billion worth of assets from IOCs to a slew of homegrown independent companies, who are mostly well-positioned to benefit from the ongoing bidding exercise.
A recent Africa Oil+Gas Report newsletter article, quoting unnamed sources at the ministry of petroleum resources, reports that up to 500 companies are expected to have applied and paid the fixed registration fee of Five Hundred Thousand Naira by the new June 21 registration deadline. Six out of the seven statutory fee categories are field-specific thus variable, growing incrementally depending on how many fields a participant is bidding for. A bidder who has narrowed down to and bidding for only one field must part with approximately $125,000 to progress to the stage of signature bonus. The asking amount for signature bonuses was not disclosed in the bidding guidelines contrary to what obtained in the past. A successful bidder must confirm willingness to pay the signature bonus upon selection and before the award of the marginal field. While the process is planned to be conducted 100% electronically, how this will pan out in reality remains to be seen. In the period since the bid round was launched, some prospective bidders have complained of inability to access the registration portal. Previous bidding processes in Nigeria have been fraught with political interference and nothing in the current political climate in Nigeria suggest there will be a departure from status quo this time.
Challenges: Setting aside the widespread enthusiasm by participating stakeholders momentarily, the sub-optimal performance shown by the majority of licensees from the 2003/4 class should evoke some caution. For a number of reasons but mostly due to funding challenges, no more than 50% of the marginal fields awarded in Nigeria have produced hydrocarbon, leaving observers pondering how successful bidders hope to attract capital as sources of funding for fossil fuels thin out across the globe. On their side, local banks who have shut their purses primarily due to over-exposure to the sector, draw little inspiration to further invest in this round at a time when unprecedentedly, the credit rating of giants like ExxonMobil has been downgraded by S & P due to its anaemic cash flow position thereby impacting the company’s ability to fund its capital projects and continue to pay dividends as the industry witnesses its bleakest outlook in history.
Among the class of 2003, approximately 47% of those licensees that attained production partnered with foreign entities, at one point or the other in their development journeys with 23% funded through financing and technical services partnerships with international players. Notably, 55% of gross daily liquid production from marginal fields comes from assets initially funded by foreign entities. This fact assumedly raises a glimmer of hope that if replicated, the model of seeking avenues to partner with foreign entities under similar arrangements could bode well for current bidders.
Other areas that could pose challenges down the line to undiscerning participants in the current bid round pertains to potential issues surrounding enforceability and bankability of contracts between the licensee, who enters into a farm-out agreement with the main lease owner, effectively as a sub-lessee. The parameters of the terms of the farm-out agreement which ideally must thoroughly address obligations of parties regarding issues such as overriding royalty to the farmor, crude handling prioritization & lifting costs, how to handle pipeline losses, abandonment & decommissioning, resolution of unitization where applicable etc. could potentially become contentious. Aside from the reality of restiveness in some areas of the Niger Delta, which portends risk for those that will operate in those communities, certain fields included in the basket are potential candidates for litigation as the government had revoked licenses from previous lessees in controversial circumstances.
Potential for Upsides: Marginal fields by definition are technically and economically challenged assets that typically haven’t met the development criteria of the IOCs who discovered them. Decisions made and the strategy adopted at the bidding stage invariably predicts future outcomes post-bid and drives an asset’s overall performance as well as underpins the ability to effectively de-risk the ensuing development project to maximize commercial value from the asset. A delicate balance must be achieved to effectively manage the competing philosophical considerations that will drive the most prudent risk-balanced FDP approach; the wisdom to achieve early, albeit relatively minimal cash flow timeously and most cost-effectively versus a full-blown, costlier and seemingly more lucrative development strategy. The upsides realizable centers on taking a life-cycle view during bidding, ensuring that consideration is given to depletion beyond primary recovery. Looking at assets deemed marginal, the prudent approach is to advocate key technologies, multiple depletion strategies and the timing of implementation to be incorporated in the field’s life cycle plan and road-map. Having a life cycle plan and road-map allows for optimal facility planning to accommodate technology application geared towards maximizing economic URF. The eventual goal, of course, is to maximize the value of the full hydrocarbon stream.
The self-healing nature of crude oil cycles infers some optimism that current effort to stimulate supply deficit through agreed production cuts will yield results in short order. Pending the restoration of oil prices to pre-COVID 19 levels, the prevailing environment where demand remains relatively depressed could offer some advantages – reduced baseline costs to procure services, that typically trails oil price, should motivate operators to develop projects through this slump and be positioned to reap in the upside when the cycle adjusts in a couple of years.
Winners and Losers: The federal government has clearly placed its bet on a robust subscription in this bid round. However, there are no indications that learnings from the historical performance of previous awardees have been incorporated into the thinking in order to influence better outcomes for the program. If the only driver for launching the round, as it appears, is for the government to raise capital from signature bonuses, then the government’s outlook is at best myopic.
As stipulated in the bid guidelines and consistent with what obtained historically, pressures on successful licensees to ” develop or lose ” amidst potential government-imposed bottlenecks, fiscal uncertainties as PIB remains unpassed, as well as other challenges earlier outlined pose significant headwinds which fundamentally threatens the achievement of the marginal field program’s theoretical objectives. With minimal long-term value creation for stakeholders, the crushing legacy of serial losses underwhelms the lofty ideals behind the marginal field programme.
Bassir is Chief Executive, Ofserv, an E&P service company with expertise covering a broad range of services across the Drilling & Facilities Maintenance domains.
IN-VR is organising the Global E&P Summit on July 2nd, taking place completely online. For the first time ever, 16 national oil & gas ministries, regulators and NOCs are gathering online to promote their available E&P global opportunities to IOCs and service providers from all over the world.
The biggest online E&P event of the year
Meet with hundreds of IOCs and service providers at the biggest online oil & gas event to ever take place. Book private meetings, network, and find the latest news on Licensing Rounds, discoveries, and tech updates
Listen to presentations from Brazil, Namibia, Timor-Leste, Ghana, Morocco, Peru,Argentina, Benin and many more authorities on the same stage for the first time. The countries will discuss their success, challenges and new opportunities after COVID-19.
Promote your company to IOCs and service providers from all over the world looking to prospect and expand their business.
Who is presenting at the Global E&P Online Summit?
Ministry of Energy, Ghana
Ministry of Mines and Energy, Namibia
Ministry of Petroleum and Mineral Resources, Somalia
Gabon Oil, Gabon
Ministry of Energy,Sao Tome and Principe and many more, soon to be announced!
Three stages, more than 60 topics
With hundreds of VIPs, officials from 16 countries, and 12 hours of non-stop streaming, you will have the option to choose the session you are most interested in watching and participate in it, before having private meetings. All three stages will be hosting sessions with different topics, discussions, Q&As and presentations on: onshore and offshore available acreage, upcoming Licensing Rounds in 2021, latest E&P technology advances, farm-in opportunities and many more.
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 (https://www.nnpcgroup.com/pages/afs.aspx). 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.
TOTAL South Africa has signed an agreement with Renergen for marketing and distribution of Liquefied Natural Gas produced by Renergen.
Johannesburg Stock Exchange (JSE) listed Renergen is in the construction phase of South Africa’s first commercial LNG plant, and is anticipating a turn-on date of the plant around the third quarter 2021. “The customer base for the LNG will predominantly be logistics companies operating trucks along the main routes across the country, with a significant portion of the initial production already allocated to customers”, Renergen says.
“This agreement is intended to provide ideal filling locations for our customers along strategic routes across the country, and the union will create a powerful first mover advantage in this exciting space in South Africa,” said Stefano Marani, CEO of Renergen. The first route targeted under the agreement will be the N3 between Johannesburg and Durban, followed by the corridors leading to the other major cities once Renergen’s Phase 2 project comes into production.
“The LNG displaces diesel usage, reducing operating costs and helping customers meet their sustainability targets due to the significantly lower greenhouse gas emissions from natural gas over diesel”.
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.
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:
Any pipeline plans are unlikely to be implemented;
Oil sand projects are unlikely to be expanded and perhaps discontinued;
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.
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 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.
TOTAL’s announcement of a half-a-billion-dollar purchase of Tullow’s entire equity in a Ugandan oilfield development, last April, sounded like a loud, symbolic statement of optimism.
In a dry white season, during which over four billion people were in lockdowns across the globe, the statement seemed to assert: “Uganda, we got you”.
At the heart of the transaction is the 230,000BOPD (Barrels of Oil Per Day) Lake Albert upstream and midstream project.
Tullow will receive $575Million, with an initial payment of $500Million for its 33.3334% stake in each of the Lake Albert project licenses EA1, EA1A, EA2 and EA3A and the proposed East African Crude Oil Pipeline (EACOP) System. It will pick up the remaining $75Million cheque when the partners take the Final Investment Decision to launch the project. In addition, the Irish independent will receive conditional payments linked to production and oil price, which will be triggered when Brent prices are above $62/bbl.
Tullow got to reduce its debt and command an immediate surge in its share price. TOTAL secured such a prize for less than $2 a barrel and for Uganda, finally, a clear line of sight to Final Investment Decision for a development that had been on the drawing board for over a decade.
As I see it, TOTAL has prevailed in Uganda in the eight years since it first entered the country’s E&P sector, via the acquisition of 33.3% of what was then Tullow’s Blocks 1, 2 and 3A for $1.45Billion. It had gradually stamped its authority, muscled out Tullow and raced past the sure footed, hard-tackling energy bureaucrats at the country’s Petroleum Authority and Minerals and Energy Ministry.
The French major is the decisive winner.
Tullow, which helped to nurture East Africa’s potential as a prolific oil producing region, and proudly displayed a badge describing itself as “Africa’s leading Independent”, now had to pack its bags.
I started having the nagging suspicion that TOTAL had taken charge in late 2015, when I witnessed, first hand, a very public argument between two ranking Ugandan and Kenyan civil servants regarding which was the optimal route to lay the EACOP, the pipeline that will ferry the crude oil produced in landlocked Uganda to the Indian Ocean for export.
“The route through Kenya is the one we have always known,” Hudson K. Andambi, (then) senior principal superintendent geologist at the Kenyan Ministry of Energy and Petroleum, said at the Africa Oil Week in Cape Town.
“We are still evaluating the routes and the least cost route is what we will consider”, declared Fred Kabagambe-Kaliisa, (then) Permanent Secretary at the Uganda’s Ministry of Energy and Mineral Development, at the same conference, minutes after the Kenyan had spoken.
It was the second public hint that the Ugandans might jettison the long- anticipated, widely expected pipeline route from Hoima, in Uganda’s oil rich province, to the Kenyan coastal town of Lamu.
I walked up to Mr. Kabagambe-Kaliisa after his presentation and asked him, pointedly, if TOTAL was behind the change. “We will take on board any concerns by our partners,” he responded, carefully weighing his words.
With crude oil found in commercial quantities in the Kenyan hinterland, over a thousand kilometres from the coast, operator Tullow had looked forward to an evacuation pipeline, originating from Uganda, that would link up with one that collects Kenyan crude, with both crudes heading for a Kenyan coastal port. The agreement signed by Presidents Uhuru Kenyatta and Yoweri Museveni in August 2015, three months before that public contestation between the Kenyan and Ugandan officials, was anchored on a 1,500 kilometre pipeline from Hoima through Lokichar in Kenya’s border region, and required guarantees from the Kenyan government regarding security, route optimization and financing.
But two months after that Kenyatta-Museveni agreement and a month before the subject spat at Africa Oil Week, Ugandan and Tanzanian officials, as well as staff from TOTAL, signed a separate agreement, creating “a working framework for the potential development of a crude export pipeline from Hoima to Tanga Port of Tanzania,” the Ugandan Ministry of Energy said in a statement, which raised some concern in Nairobi.
And now we were at this conference, I knew that Tullow should be worried, very worried.
The decision to pump the Ugandan crude through a separate pipeline from that with which it planned to pump the Kenyan crude to market, meant that Tullow would be investing in two expensive pipeline projects, each costing no less than $3.5Billion. This, at a time of plunging crude oil price, should unnerve the company, a midsized independent struggling with losses.
It might not be surprising to some, then, that in January 2017, Tullow announced that, for a sum of $900Million, it had agreed to sell, to TOTAL, two thirds of its entire stake in each of the Lake Albert project licenses EA1, EA1A, EA2 and EA3A and the proposed East African Crude Oil Pipeline (EACOP) System. It came to 21.5% of the project’s entire stake. CNOOC invoked its right- of-first -refusal and asked for half of the 21.5%. But Kampala, never in a hurry to close any deal, dragged the timing of grant of the official consent for the sale, which itself impacted the Final Investment Decision.
The sticky point was the Tax that the government would receive from the sale and purchase.
Tullow’s inability to consummate the sale signaled to its shareholders that it wasn’t creating value. Share prices kept falling. Tullow was hemorrhaging worth.
With government still playing hard ball, two and half years after the intent for the 21.5% sale was announced, TOTAL pulled rank and announced the suspension of all activities, including tenders, on the EACOP. The Chinese, not known to express anger in public, decided that this was time to talk. “It is now very difficult to negotiate with government”, Gao Guangcai, CNOOC’s Vice Project Manager, told a conference in Kampala. The implication of TOTAL’s action was that the project could not continue.
The authorities got the message and the parties went back to the table.
By April ending 2020, the global economy had seized up; the Ugandan authorities had come around and Tullow was going to make a distress sale: accept $425Million less for a much larger stake than it had negotiated it would take three years and three months earlier. TOTAL, the European supermajor with piles of cash, is the winner that takes all.
Over 300 companies have applied to be prequalified for the Nigerian Marginal Field Bid Round, with many others unable to gain access to the portal, in the three weeks since the round was launched.
The Department of Petroleum Resources, the industry regulator, meanwhile, postponed the terminal date of registration of Bids to June 21.
Nigerian Ministry of Petroleum sources say it is likely that over 500 companies would have applied by that date.
The ongoing exercise is the first government supervised oil and gas asset sale since the acreage bid round in 2007.
Marginal fields are undeveloped discoveries that have lain fallow in acreages operated by International Oil Companies for at least 10 years.
It would take around $150,000 for a qualified application to get all the way to signature bonus and a number of Nigerian businessmen. “Once you get to the point of being qualified and all you have to pay is the signature bonus, you’re there”, says a retired reservoir engineer who spent over 25 years with a super major in Nigeria. “There is the impression that a marginal field licence has conferred on you some entitlement”.
The entire exercise, up to the submission of technical/commercial bid, ends on August 16, 2020. In between, from June 21 to August 16, the following will happen: (1) Evaluation of submission and preparation of report, June 22 to July 5; (2) Announcement of Pre-Qualified Applicants and Issuance of Field Teasers, July 5; (3) Data Prying, Leasing, Purchase of Reports, July 6 to August 16; (4) Payment of Application and Bid Processing Fee and Submission of Technical and Commercial Bid; July 6 to August 16. The schedule means that the heavy lifting will happen between July 6 and August 16.
The TOTAL operated Mozambique LNG (MLNG) project, to monetise the reserves in the country’s deepwater Area 1, is making progress in spite of COVD-19 challenges.
“The financing was more or less been agreed and finalised and signing hopefully it will happen very soon”, says Paul Eardley- Taylor, Head of Oil & Gas Southern Africa, Standard Bank.
Eardley-Taylor, who is perhaps the most optimistic public speaker about Mozambique’s gas prospects, says the country “really has a couple of three unique aspects to it in terms of LNG, which is why volatility really doesn’t affect it. The first one is the obvious one, it’s bang in the middle of the map, if you use the Mercator projections, ideal for Asia or Europe. Secondly you have a large glob of gas in a single location, round about 150Tcf. Thirdly Mozambique is non-aligned and really contributes to security supply in other jurisdictions”.
The two train, 13MillionTonne Per Annum (13MMTPA) MLNG, is one of the two large sale LNG projects under development in Africa’s southeasternmost edge. Final Investment Decision for the project was taken in mid-2019.
FID for The ExxonMobil led Rovuma LNG, which is to monetise the Area 4 reserves, was postponed indefinitely, last April.
What about the insurgency?
“Mozambique is an enormously long country, so it’s important to know where the insurgency is near and not near”, the Standard Bank executive explains. “The insurgency has generally been about 100, 150 kilometres to as far as 300 kilometres from the site”.
“As we generally understand, (the 3.3MMTPA) Coral FLNG is more or less on time in terms of completion, largely unaffected by COVID-19 in South Korea and Singapore,” Eardley-Taylor explains. “So we expect that by third quarter or thereabout of 2022, it comes online”.