Nigeria National Petroleum Corporation has declared a net profit for the year 2020.
The state hydrocarbon firm announced, through the President of the country, a Profit after Tax of Two Hundred and Eighty-Seven Billion Naira (₦287 Billion) in the Year 2020, sequel to the completion of the statutory Annual Audit exercise for the Year 2020.
“The NNPC losses were reduced from ₦803 Billion in the year 2018 to ₦1.7 Billion in the year 2019 and the eventual declaration of Net Profit in the Year 2020 for the first time in its 44-year history”, a statement by Femi Adesina, Special Adviser (Media and Publicity), to President Muhammadu Buhari, said.
“This development is consistent with this administration’s commitment to ensuring prudent management of resources and maximization of value for the Nigerian people from their natural resources.
NNPC published an audited annual report for the first time in 2019; it was the 2018 annual report. It published the 2019 annual report in August 2020, exactly a year ago.
The media has been so excited by the fact that NNPC now publishes audited annual reports that the default response is to praise the NNPC management for the achievement of publishing an audited annual report. The content of the reports, with the exception of the worn-out conversations around the corporation’s malfunctioning crude oil refineries, is hardly debated.
President Buhari’s own statement on the report toes the line: “I congratulate the Board, Management, and Staff of the Corporation and look forward to greater value creation for the Nigerian people.”
Italian explorer ENI has reported starting production of the Cuica Field, in Block 15/06 of the Angolan deep offshore.
The company’s release does not provide the output figure, but it explains that the field is being produced via the Armada Olombendo Floating Production Storage and Offloading (FPSO) vessel.
First oil came on July 30, 2021, “just over four months from discovery”, the company says.
The Cuica field was discovered by the exploration well Cuica 1 in March 2021. It is located in a water depth of 500 metres, approximately three kilometres from the Olombendo FPSO. The early production of the development, that will increase and sustain the Olombendo FPSO production plateau, includes an oil producer well and a water injection well, tied back subsea to the existing Cabaça North subsea production system, thus exploiting the full potential of available infrastructures in the area.
The Armada Olombendo FPSO has a production capacity of 100,000 barrels of oil per day and is designed to operate during her production life with zero discharge. Besides Cuica, whose production rate is in line with expectations, the Olombendo is now receiving and treating the production of Cabaça, CabaçaSouth East, and UM8 fields for a total of 12 wells and 5 manifolds at a water depth ranging from 400 to 500 metres. The Olombendo FPSO will also receive production from the Cabaça North field in 4Q 2021.
Block 15/06 is operated by ENI Angola with a 36.84% share. Sonangol Pesquisa e Produção (36.84%) and SSI Fifteen Limited (26.32%) compose the rest of the Joint Venture. Further to block 15/06, ENI is operator of exploration blocks Cabinda North, Cabinda Centro, 1/14 and 28, as well as of the New Gas Consortium (NGC). In addition, ENI has stakes in the non-operated blocks 0 (Cabinda), 3/05, 3/05A, 14, 14 K/A-IMI, 15, and in Angola LNG.
With a boost in its crude oil production in Libya and ramp up of natural gas output in Egypt, ENI has consolidated its position as the highest producer of hydrocarbons (oil and gas) in Africa.
The Italian player averaged a net output of 908,000Barrels of Oil Equivalent Per Day(908KBOEPD) in the seven countries in which it holds producing positions on the continent, in 2020.
Rystad Energy has recently published two findings which cannot be reassuring to the oil and gas sector: firstly, it estimates that global total recoverable oil reserves have fallen approximately 10% in 2021- 1,725Billion barrels in 2021 compared to 1,903Billion in 2020.
Secondly, Rystad estimates that the downturn, combined with the COVID-19 pandemic has cost the sector some $285Billionin upstream investments for 2020 and 2021. Pre-pandemic spending in 2019 was approximately $530Billion. In 2020 spending was reduced to $382Billion and in 2021 is expected to be $390Billion.
Andrew Latham, Vice President Energy Research, Wood Mackenzie, has offered deepwater players a somewhat more cautious, but reassuring message. In a July study entitled ‘Deepwater’s Growing EUR Advantage’, Latham explainshow deepwater upstream growth is expected to rise from 10Million Barrels Oil Equivalent Per Day (MMMBOEPD) in 2021 (6% global supply) to over 17MMMBOEPD by2030(10%).
He states that almost half of oil and gas reserves being sanctioned for development over the next 5 years will come from the deepwater. Why? According to Woodmac, the outperformance is based on reservoir fundamentals. Deepwater reservoirs will produce substantially more oil and gas than shallow or onshore reservoirs. EUR(Estimated Ultimate Recovery) in deepwater averages 12MMBOEPD for oil wells and 43MMBOEPD for gas wells. Future deepwater oil fields will enjoy twice the average EUR of fields already onstream. Reflecting the industry’s recent successes in Guyana and Brazil’s Santos.
Oil Wells
Brazil with 36Billion barrels of oil reserves has an average EUR of 14MMBOEPD per well. Brazil’s early deepwater developments took place in the post-salt plays of Campos Basin where heavier crudes and drilling technologies of the 1980s limited average EUR to 8MMBOEPD per well. Recent investments in pre-salt in the Santos Basin is 27MMBOEPDper well.
Angolahas 11Billion barrels of oil reserves, 1000 wells, and an average of 10MMBOEPD.
Nigeria has 7Billion barrels of oil reserves and an average EUR of 16MMBOEPD.
Guyana has 6Billion barrels of reserves and an average EUR of 24MMBOEPD.
Gas Wells
Gas basins are approximately half the size of oil basins. Woodmac anticipates the development of approximately 1000 deepwater gas wells, of which 700(64%) have already been developed. The average EUR is 43MMBOEPD. Mozambique’s Rovuma will have an average EUR of 93MMBOEPD.
Up to 2009, the average EUR was 31MMBOEPD. Now the average has jumped to 90MMBOEPD based on gas discoveries in the eastern Mediterranean, Mozambique, and Mauritania, and Senegal.
The Players & Assets
BP-ENI
EUR averages could also dramatically rise because of possible merger talks between BP and ENI regarding their Angolan assets Will this model become the standard for other African countries?
An Algerian variant is perhaps already in the making. Reuters reported that a potential deal would allow ENI to acquire BP’s 45.89% stake in the Amenas natural gas plant and a 33% stake in the Salah gas plant. ENI expects to transform Algeria into a hub with the acquisition of BP’s assets.
Egypt could prove to be more challenging for both companies to find a lasting solution either to work together or a possible takeover of assets. BP currently produces, with its partners, close to 60% of Egypt’s gas production through the joint ventures the Pharaonic Petroleum Company (PhPC) and Petrobel (IEOC JV) in the East Nile Delta as well as through BP’s operated West Nile Delta fields.
Nonetheless, ENI claims to be Egypt’s largest oil and producer, and its huge Zohr gas field is viewed as an example of the company’s extensive assets in the country. Most recently ENI together with EEHC (Egyptian Electricity Holding Company) and EGAS (Egyptian Natural Gas Holding Company) has signed an agreement to assess the technical and commercial feasibility of producing hydrogen.
Talk of potentially moving in the direction of hydrogen development could well trigger further cooperation between BP and ENI.
TOTALEnergies
EUR averages have certainly caught the eye of TOTALEnergies who, with its deepwater track record in Angola Block 17, will certainly play a key role in developing new deepwater projects.
R The French major has two key assets in South Africa in which EUR will certainly play a key role: Brulpadda Deepwater Project drilled to a final dep of more than 3,600 metres, and Luiperd, the second discovery in the Paddavissie Fairway in the southwest corner of the block.
In Africa, TOTALEnergies is the undisputed energy champion helping to leapfrog exploration and development hurdles ensuring that oil and gas projects are implemented, on time, and under budget.
Conclusions 1. EUR in Africa is not for the faint-of-heart, but a domain already long carved out by TOTALEnergies and ENI, Africa’s two dominant deepwater players. 2. A key theme in pursuing EUR goals for TOTALEnergies is not whether the oil and gas reserves are ‘probable’, reflecting any notion that the SPE Petroleum Classification is still in place. No the key driver for TOTALEnergies is simply the economics of deciding whether EUR projects are up to investment grade and can compete with green projects.3. Any notion that the oil majors will use their EUR profits generated in Africa to create green projects in Africa is pure sentimentality. As Africa Oil+Gas Reporthas reported in the past, the oil majors have used profits generated in Africa to help finance their global green energy projects elsewhere around the globe.4. If EUR projects are to be developed, they must be fast-tracked, otherwise, there is little chance they will see first oil. Take the Lake Albert development project, recently signed in the spring of 2021, which encompasses the Tilenga and Kingfisher upstream oil projects in Uganda and the construction of the East African Crude Oil Pipeline (EACOP) in Uganda and Tanzania. To reach a signing ceremony for the project has taken some 15 years. In the present low-carbon environment, the dithering of long-drawn-out development plans, will for whatever reason, not be tolerated. 5. No doubt the BP-ENI joint venture in Angola will ensure that this model will be duplicated or expanded throughout the continent. Certainly, it will shore up deepwater exploration and development plans. 6. Participation of new entrants- independents seeking new opportunities or savy investors-will likely also be part of the mix.7. Perhaps EUR could become the driving force to enable the deepwater market to become an even more lucrative niche market. Perhaps not entirely in vogue given the low-carbon surroundings.8. Yet the final warning comes from Institute for Energy Economics and Financial Analysis (IEEFA)’s July report: “In financial year (FY) 2020, the clean energy sector received record investment commitments totaling $501Billion – 9% more than the previous year. The renewable energy segment led with $303Billion in 2020, which is 60% of total investment committed into the overall low carbon energy transition sector.”9. EUR-driven projects will have to compete with renewables investments.
Gerard Kreeft, BA (Calvin University, Grand Rapids, USA) and MA (Carleton University, Ottawa, Canada), Energy Transition Adviser, was the 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 of Energy Economics and Financial Analysis(IEEFA).
has rebranded and unveiled its new logo to re-position to offer cutting-edge services in the oil and gas industry.
“The Company has completed its rebranding program in response to the new opportunities for technology-enabled solutions in the energy sector”, said Adeola Adebari, the Chief Executive Officer for BOAZ.
“Our visual identity is an essential part of the BOAZ Brand. Each element in the new logo was carefully crafted to symbolize the company’s dynamism and forward-thinking positioning within the Oil and Gas Servicing Industry, and the energy space at large. Indeed, this is a major milestone for us as a company”.
BOAZ provides revolutionary solutions to production and reservoir management challenges for the oil and gas industry, in partnership with such technology companies as Roke, Blue Spark, Jorin, and Data Science Nigeria.
The new brand captures the company’s readiness to support the industry’s renewed focus on maximizing ultimate hydrocarbon recovery, using cost-effective solutions, leveraging digital technologies, transitioning to renewable energies as well as maximizing returns on investments through safe, quality and sustainable solutions.
Here is the new visual identity of the Company:
The rationale behind the new logo, according to the CEO, is in alignment with the strategic intent: “Our new logo consists of two main components: BOAZ typeface and Apex Wheel Icon. The Apex Wheel Icon is a stylized ‘A’ that points forward within a wheel or ‘O’. These two elements symbolize our drive to offer the apex of service and technology within the energy industry, in alignment with our corporate strategic intent. It is important to note that the Apex points forward, indicating that we are disruptive, ready and willing to change the status quo and the way business is done within oil and gas servicing in Sub-Saharan Africa. This of course is complemented by the wheel or ‘O’ which is also all about moving forward”.
The oil and gas industry has undergone major changes in recent times, which have fundamentally changed the way things are done. As the industry heals from the debilitating dual impact of price wars and COVID-19 pandemic, business leaders have learnt to do things differently as evidenced by the increased adoption of green solutions and digital technology innovations. These changes require new thinking. BOAZ new brand speaks to this new thinking in that the Company is poised to deploy its revolutionary technologies in the industry.
Some of the flagship solutions of the Company include Quad Reservoir Saturation Logging Technology, Wireline Applied Stimulation (WASP) Techology, and Visual Process Analyser (ViPA) Technology. Their benefits are highlighted below:
Quad: For reservoir saturation measurement, fluid contacts, lithology, porosity, clay volume and relative bulk density.
WASP: For wellbore cleaning, removal of scales, fines and debris from screens, perforations, downhole subsurface safety valves, gas lift valves etc.
ViPA: For produced water management, production chemical optimization and surface production equipment optimization.
At the heart of the rebranding programme is a renewal of the Company’s corporate vision and mission statements to emphasize its expanded focus on the energy industry. The Company also renewed its Corporate Culture with a new corporate look for its website. (www.boazintegrated.com).
Abimbola Onaolapo, one of the Company’s Directors, gave some insight into the new corporate culture: “Our strong corporate culture is based on our shared values, represented by our name BOAZ.We are BOAZ, we stand for:
B: Boldly rising to challenges through innovation, excellence and teamwork
O: Obligation to exceed clients’ expectations, always.
A: Acting with Integrity and Respect
Z: Zero harm to people, assets and the environment
This is what we represent.”
The new BOAZ brand signifies the Company’s commitment to remain innovative, nimble and agile in order to help its clients achieve ambitious goals and stay ahead of the curve in the next normal.
The current version of the Petroleum Industry Bill is one of the most progressive pieces of legislation I have seen anywhere.
In the new law, the Nigerian state is willing to accept as low as 60% for both Hydrocarbon Tax and Companies Income Tax (CIT) combined (which collectively replace the Petroleum Profit Tax), for mining leases located onshore and shallow water. With these generous giveaways, the Bill’s drafters are hoping that companies can invest more on work programmes that reward the country with higher volumes of hydrocarbon output at lower cost of production, rather than surrendering to temptation to pad up OPEX and CAPEX in order to reduce their tax remittances.
A Midstream infrastructure Fund is set up to incentivize private investment in pipelines, gas processing plants and other such facility that help deliver processed hydrocarbon products to end users in the Nigerian market.
The Minister has a better handle of the petroleum industry than what he was allowed in the draft that emerged, after the long collective wait, last September, but as is the plan, he doesn’t have an undue control.
There is vigorous contestation of the percentage of Oil Companies’ Operating Expenses (OPEX), mandated by the new law for payment into the Host Community Trust Fund on any acreage under licence, but the deal in the PIB is a much more improved and structured community development intervention than the NDDC or the Derivation. The Host Community initiative in this law is more of a legal instrument than the Global Memorandum of Understanding, a participatory development planning process initiated by oil companies and which is, today, widely considered the most impactful process for delivering development. We have had a discussion of the value of the mandated size of OPEX, elsewhere on this site.
There are areas of the bill that I am not entirely comfortable with but I can let them all pass, except the Frontier Exploration Fund.
The provisions in the section for Frontier Exploration Fund leap at you like bad data does in a smooth creaming curve
The more we at Africa Oil+Gas Report examine the clause on the Frontier Exploration Fund in the current draft of the PIB, the less we are convinced that it is altruistically about exploration.
In the draft of the bill that was sent to the National Assembly in late 2020, the oversight for Frontier Exploration, which has been in the orbit of NNPC for 33 years, was handed over to the regulator. In the wordings of that particular version: “Where data acquired and interpreted under a Petroleum Exploration Licence is, in the judgment of the Commission, requires testing and drilling of identifiable prospects and leads, and no commercial entity has publicly expressed an intention of testing or drilling such prospects, the Commission may engage the services of a competent person to drill or test such prospect and leads on a service fee basis”. That simply means that the regulator could put up a bid and any E&P company could contest for testing such a prospect for a fee. But how would the regulator find money to pay the fee? The answer is ‘The Frontier Exploration Fund’, the draft law said, which “shall be 10% of rents on petroleum prospecting licences and petroleum mining leases”.
This was already clearly provocative: to set aside 10% of rents on petroleum prospecting licences and petroleum mining leases for frontier exploration was already heavily contested.
So, it was more than rubbing salt into injury when, after all the public hearings, with heavy criticism about allotting high percentage of rents to a potentially unaccountable queue of drilling prospects, the draft that emerged, now calls for even more money being effectively taken out of the treasury, to fund frontier exploration. Over and above the 10% of rents on petroleum prospecting licences and petroleum mining leases, says the current draft of the bill, the Fund shall also swallow “30% of NNPC Limited’s profit oil and profit gas as in the production sharing, profit sharing and Risk service contracts”. NNPC Limited shall transfer the 30% of profit oil and profit gas to the frontier exploration fund escrow account dedicated for the development of frontier acreages only.
Governors, both Southern and Northern, missed the point that this 30% of PSC profit is a further robbery of the Federation account in favour of NNPC for a service that is already well catered for. Instead, they turned the discussion into a political, North/South affair, with the South accusing the North and the North defending what is actually a loss of revenue to them! It says a lot about how little those who queue up every month for Federal allocation understand how the money they are sharing is derived.
But perhaps the political class knows what most of us outside of their sphere don’t: this current draft is effectively having NNPC wresting control of the Frontier exploration initiatives from the regulator. Whereas in the earlier draft, the regulator could “engage the services of a competent person to drill or test such prospect and leads on a service fee basis”, thereby opening the space for understanding of the geological challenges, the latest draft restricts the studies to NNPC: “the Commission shall … request the services of NNPC Limited to drill or test such prospect and leads on a service fee basis to be charged to the Frontier Exploration Fund pursuant to this Act”.
That particular statement plays to the ideological mindset of the present administration at the centre; that ”the government will do things better than the private sector”(fund the country’s entire electricity bill, subsidise gasoline consumption and be the chronically inefficient nanny). Still, the self-evident truth is that when it comes to basic E&P operations, the NNPC has proven to be incapable of delivering. As have been convincingly argued elsewhere on this site, the least productive assets in the portfolio of NPDC, the NNPC’s E&P subsidiary, are those in which it is the sole stakeholder. This heightens my suspicion of this idea in the PIB, of cancelling the competition in favour of NNPC to probe prospective acreages.
I am not one of those who compare Frontier areas to sinkholes. No. I spent 20 years as an earth scientist with Chevron and went to several conferences at which many professional colleagues made presentations on the prospectivity of sedimentary basins in Ghana, Mozambique, Uganda and the like. And yet it wasn’t until the last of my 20 years (2007) that Kosmos reported the first sizeable commercial discovery of oil in Ghana. And the first of the reservoirs containing 100Trillion cubic feet (estimated recoverable reserves) offshore Mozambique), wasn’t discovered until three years later.
But it is to the marketing savvy of the hydrocarbon officials from these countries that we owe those discoveries, not the state’s readiness to throw money down the hole. They showed up gabfest after gabfest, making the case for investors to come.
It is neither fashionable, professional nor sensible for governments around the world to risk hard earned profits on exploration efforts, let alone frontier Basins!! The practice (and wisdom) is to create a system to make that happen by private funds. Nigeria did something like that in 1993 which led to Shell’s gas discovery in Kolmani-1 well in Bauchi area.
With the section on Frontier Exploration in the PIB the way it is, it is hard to assume that it is not a route for slush funds that can escape legislative scrutiny and financial regulatory oversight.
Nigerian oil Industry leaders are reacting to agitations that 3% of Operating Expenses (OPEX) of companies licenced to operate on any hydrocarbon acreage be paid into a Host Community Trust Fund for the communities around the subject acreage, as mandated in the current draft of the Petroleum Industry Bill, is too low.
“I believe there is too much uninformed noise”, says Joseph Nwakwue, retired ExxonMobil Petroleum Engineer, former President of the Society of Petroleum Engineers (SPE), and former special assistant to the Minister of State for Petroleum Resources. “This provision is to provide direct benefits to the host community. It needs to be at a level that does not significantly increase the unit OPEX. We had estimated the impact on cost of operations and hence profitability of the upstream. I really believe 2.5% would work”.
The Petroleum Industry Bill (PIB) is close to final passage at both the House of Representatives and the Senate. But whereas the Senate has passed “the conference committee report in which 3% of companies OPEX in the last calendar year is retained for Host Community Trust Fund”, the House of Representatives stepped down the bill after an hour long, rowdy closed-door session assessing the committee report, as lawmakers from Bayelsa, Delta, and Rivers States, the country’s largest hydrocarbon producers, opposed what they consider a low contribution into Host Community Development.
Elected legislators representing the Niger Delta region at the House of Representatives, are championing 5% of the total operating expenses (OPEX) over 3%. The Niger Delta hosts over 99.9% of all hydrocarbon currently produced. The Dahomey basin, located in the country’s southwest, produces less than 1% of the nation’s output. No other sedimentary basin has contributed to the national production since first oil in 1958.
But those who routinely pay close attention to value creation in oil and gas activity, have a nuanced view.
“3% of OPEX, currently being paid to the Niger Delta Development Commission (NDDC) for the region’s development is estimated at about $500Million annually”, says Taiwo Oyedele, Fiscal Policy Partner and Africa Tax Leader at PwC, the global firm of consultants. “Unfortunately, this has not had any meaningful impact due to mismanagement. My view is that 3% of OPEX for host community development is a fair percentage given the need to make investment in the sector attractive and viable”, Oyedele explains. “I expect that the governance structure as proposed under the PIB will ensure that the funds deliver concrete results and if this is sustained, the amounts available will increase as more investments are attracted. It may also provide a compelling basis for NDDC to be scrapped and the contributions added to the Host Communities”.
The governance structure for Host Community Fund that Oyedele refers to in the PIB, is fairly rigorous. Unlike the payment to NDDC, the PIB mandates clear guidelines on governance of the funds, which, unlike NDDC, are to be locally applied, not granted “globally” to state governments. The draft of the PIB says that the Board of Trustees of Host Community Trust Fund, to be set up by the oil company/ies “shall in each year allocate from the host communities development trust fund, a sum equivalent -(a) 75% to the capital fund out of which the Board of Trustees shall make disbursements for projects in each of the host community as may be determined by the management committee, provided that any sums not utilised in a given financial year shall be rolled over and utilized in subsequent year; (b) 20% to the reserve fund, which sums shall be invested for the utilisation of the host community development trust whenever there is a cessation in the contribution payable by the oil ompany/ies; and (c) to an amount not exceeding 5% to be utilised solely for administrative cost of running the trust and special projects, which shall be entrusted by the Board of Trustee to the oil company/ies. The law also says that host community development plan shall -(a) specify the community development initiatives required to respond to the findings and strategy identified in the host community needs assessment; (b) determine and specify the projects to implement the specified initiatives; (c) provide a detailed timeline for projects; (d) determine and prepare the budget of the host community development plan; (e) set out the reasons and objectives of each project as supported by the host community needs assessments”.
Oyedele says: “I do not think the agitation (for 5% or even more of the OPEX) is warranted. More focus should be on the judicious utilisation of the 3% for Host Community in addition to 3% for NDDC and 13% Derivation for the oil producing states. All together these funds are capable of transforming the region and providing opportunities for the people”.
Africa Oil+Gas Report asked five Chief Executives of indigenous companies, all of them demanding not to be named. Two did not respond. Two of them nodded in preference of 3% of OPEX for the Host Community Trust Fund. The third said he could live with 5%.
Still, there is one industry leader who supports even higher percentages of OPEX than the two bands that members of the National Assembly are bickering about. “Beyond a 10% OPEX allocation, I would support a 10% equity participation in the lease”, argues Nedo Osanyande, a widely respected geoscientist, former General Manager of Sustainable Development and Community Relations at Shell Nigeria, and fellow of the prestigious Nigerian Association of Petroleum Explorationists (NAPE). “In the absence of equity participation, I’d support a 10% OPEX allocation”, he says. “Importantly, a sizeable part of this must be spent (at least initially) in community capacity development in managing this fund. Currently, the social organisation capacity is lacking. This is the reason the funds allocation so far – however inadequate – has not been judiciously utilized”.
Mr. Osanyande says that “with the right social organization capacity, financial resources captured by elites, strong men, and the like would be reduced. Thus far, such capture results in the funds not being invested in the communities”. Arguing that everyone one gains if the communities are happy, he concludes that “hydrocarbon production could easily double, and OPEX costs halved if the hydrocarbon producing communities are happy”.
But Mr. Osayande’s figures are not popular among his colleagues.
Says a consultant geoscientist who has worked on virtually every draft of the Petroleum Industry Bill since 2008: “Actually the 3, 5 or 10% would have been unnecessary if prior initiatives (13% Derivation, 3% NDDC, 8% Littoral State Allowance, Amnesty payments as well as Niger Delta Ministry mandates) have worked half as expected. They all have not worked because of implementation failures. Some of them are even now being copied as best practice in other countries where they are well implemented”.
Eberechukwu Oji, CEO of NDWestern, argues that diversification of portfolios is the key for E&P operating companies to weather the storms of boom-and-bust cycles of crude oil prices and, in the peculiar case of Nigeria, perennial outage of crude evacuation pipelines.
“I have been in the industry for almost three decades”, Oji told Africa Oil+Gas Report in a chat in the course of the magazine’s “Interview the CEO” series. “During this time, I have experienced the peaks and troughs of oil price crash and outage of backbone facilities. Some of the lessons learned from these experiences are that
(1) Diversification of portfolio is key to staying alive. Indigenous companies must take local refining and mid-stream business very seriously to be better able to handle these major shocks
(2) Reduction of reliance on 3rd party services such as pipelines and infrastructure.
(3) Self-developed evacuation of produced crude, the so-called alternative evacuation options is also becoming a necessity to reduce deferments from uncontrolled incessant outages”.
The company actually looks towards being fully integrated.
NDWestern’s joint venture with state owned NPDC (NPDC/NDWestern JV) is the largest indigenous producer and supplier of natural gas into the domestic market.
Its gross output of 310Million standard cubic feet per day (310MMscf/d) on average in 2020 betters the nearest local competitor by around 25%. The Joint Venture supplies the 1,000MW Transcorp Power Plant at Ughelli, the 1,320MW (capacity) Egbin Power Plant in Lagos, Olorunsogo Plant in Ogun State in Nigeria’s southwest, as well as other offtakers through transport lines operated by the Nigerian Gas Transportation Company. The company envisages production of over 400MMscf/d “if the off-takers will perform”.
In its TALENTED TENTH annual, published late in December 2020, Africa Oil+Gas Report reported that NDWestern had completed Front End Engineering Design (FEED) on a 10,000BPD refinery on the Oil Mining Lease (OML) 34 and hopes to convince NPDC to jointly take a Final Investment Decision by second quarter 2021. NDWestern’s 2020 revenue, up to October 2020, was running north of $200Million, with 33% operating profit. Gas offtake has been higher than forecast and the company has been pleasantly surprised that crude oil prices were doing better, as of end of 3Q 2020, than had been predicted earlier in the year, when the contagion forced down prices to sub $10 levels.
The COVID-19 pandemic roiled global markets for most of 2020, and kept down demand for crude oil in the earlier part of the year, nudging the price per barrel of the commodity to as low as $-37.63 on April 20th, 2020, (West Texas Intermediate, an international oil benchmark), for the first time in history.
OPEC+ AGREEMENT
As the demand collapse held up, the Organisation of Petroleum Exporting Countries (OPEC) and its allies, OPEC+, an intergovernmental cartel, reached an agreement on the 9th of April, 2020, to reduce their crude oil production output in order to rebalance the international oil market. This was the beginning of a journey to periodic cuts of crude oil by member states of OPEC and its allies.
On the 12th of April, 2020, they finalised the agreement and decided to reduce oil output to 9.7Million barrels per day(9.7MMBOPD) from May 1, 2020 to June 30, 2020. From July 1, 2020 to December 31, 2020, 7.7MMBOPD and a 5.8MMBOPD cut in output from January 1, 2021 to April 30, 2022. The reference point for the calculation of the cut down was the oil production for October 2018.
OPEC is on familiar grounds whenever it takes a decision to modify crude oil production output. According to a Reuters report, the cartel has changed production output 34 times – often exempting some of its member countries from these cuts – from 1998 to 2018.
But this particular cut which started in May 2020 was referred to as the “single largest output cut in history.” With this cut, the oil production in OPEC member countries sank to the lowest in almost 20 years, in the first month of the curtailment.
Prior to this agreement, there had been a pricewar between Russia and Saudi Arabia which instigated a major oil price crashing the global market. Nigeria, Africa’s giant, being a member country of OPEC, joined in the production cuts.
OPEC+ CUTS AND NIGERIA
In fulfilment of the OPEC+ decision, Nigeria agreed to cut its production to 1.412MMBOPD for May to June 2020, 1.495MMBOPD for July to December 2020 and 1.579MMBOPD for January 2021 to April 2022, based on the reference production of October 2018 of 1.829MMBOPD. These production cuts exclude condensate production which is exempt from OPEC’s output cuts.
These periodical cuts have proven to be an effective mechanism for cushioning the oil glut that pervaded the international oil market in the early months of 2020.
Oil prices skyrocketed with the OPEC cuts. Brent crude oil futures, an international oil benchmark, jumped from as low as $26 on April 20th, 2020 to as high as $71.49 on June 7, 2021 and WTI price, from as low as $-37.63 on the 20th of April, 2020 to as high as $69.23 on June 7, 2021.
Oil prices may have increased with the OPEC+ cuts, which is an advantage for oil revenue generation in terms of FX, but “the rising oil prices could also be a curse for Nigeria as it has to pay more because of an operating cost of about $40,” notes Bamidele Samuel, a senior research analyst with one of the big four accounting firms in Lagos.
Compliance or Non-compliance
Nigeria started on a discordant note, in the first month of the curtailment, by complying only partially with its agreed portion of the cut. The country overproduced crude oil in May 2020, with about 1.61MMBOPD, accounting for about 52% compliance.
However, Nigeria promised to make up for the non-compliance by the end of June 2020 or no later than mid-July 2020.
As OPEC+ alliance extended the 9.7Million barrels oil production cut – which was supposed to end in June 2020 – into July 2020 to further rebalance the oil market, again, Nigeria overproduced oil at 1. 49MMBOPD, against its promised 1.41MMBOPD production for July, according to OPEC monthly oil market report.
In the following months until the end of the year, OPEC recorded that Nigeria was mostly compliant with its designated quota of crude oil production.
The country recorded the lowest production output for 2020 at 1.42MMBOPD in December, which was the lowest production level since August 2016, according to OPEC’s report. This was largely due to disruption in production at ten terminals including Yoho, Agbami, Pennington, Qua Iboe and Erha terminals.
OIL PRODUCTION IN NIGERIA
On one hand, Nigeria promised to make up for the OPEC cuts loopholes with condensates, which is not part of the OPEC+ curtailment. Timipre Sylva Minister of State, Petroleum, reiterated that through the respective periods of the OPEC+ cuts, Nigeria would add “condensate production of between 360-460 KBOPD.”
In November 2020, Nigeria urged OPEC to reconsider the oil production cuts designated to Nigeria due to the confusion over the categorisation of Agbami field as condensate or as crude oil.
However, OPEC declined Nigeria’s request with a comment that the production cuts was in the best interest of the international oil market.
With these cuts and other production challenges, Nigeria’s overall oil and condensate production slumped drastically in 2020 to around 1.66MMBOPD in 2020 from 2.04MMBOPD in 2019, according to an S&P Platts analysis, a UK-based market intelligence firm. This was its lowest annual output figure since 2016 when militancy in the Niger Delta pushed output to as low as 1.60MMBOPD.
According to data obtained from the NNPC Annual Statistics Bulletin, total crude oil and condensate production for the year 2019 was 735,244,080 barrels of oil and the daily average production was 2.01MMBOPD. In 2020, however, Nigeria produced 643,938,257 barrels of oil and condensate, the lowest ever produced since 1990, when the production figure was 630,245,500 barrels of oil and condensates.
In January 2020, Nigeria produced 64,260,394 barrels of oil and condensate, representing an average daily production of 2.07Million barrels, the highest in the year and in December 2020, it produced 44,018,411 barrels of crude oil and condensate, with an average daily production of 1.42Million barrels, accounting for the lowest.
Mr. Bamidele Samuel regards the operating cost to the upstream sector – which is around $40 – as a major shortfall for oil exploration and production in Nigeria.
2021 PRODUCTION CUTS
In December 2020, the OPEC+ alliance agreed to increase production by 500,000BOPD, from January 2021. This brought the total production cut for OPEC+ in January to 7.2MMBOPD. This production cut decreased gradually to 7.13MMBOPD in February and 7.05MMBOPD in March 2021 through April 2021. Saudi Arabia, OPEC kingpin, stepped in with a voluntary cut of 1MMBOPD from February 2021 till April 2021.
On April 1, 2020, OPEC+ alliance decided to ease cuts to 5.8mb/d spanning from May 2021 till July 2021.
Some analysts believe that the OPEC+ cuts would continue to go down the slope until April 2022 as the world recovers from coronavirus and the oil glut that accompanied it.
According to OPEC monthly crude oil production data obtained from its secondary sources, in 2021, Nigeria’s crude oil production figures stood at 1.34MMBOPD in January, 1.49MMBOPD in February, 1.48MMBOPD in March 2021 and 1.56MMBOPD in April 2021.
“The fact that Nigeria cannot do as much as an average capacity of 1.9MMBOPD is a challenge, especially with oil prices trading above $70 per barrels,” Bamidele Samuel argues.
“If we are producing more, that is more revenue for the government to stimulate the economy on the part of recovery,” he added.
Russia and Saudi Arabia keep disagreeing on the change in production output. While Russia has been pushing for increase in OPEC+ production output, Saudi Arabia has been more conservative, contending that another wave of coronavirus in India and other parts of Asia, is capable of assaulting demand for crude oil.
This story was produced under the NAREP Media Oil and Gas 2021 Fellowship of the Premium Times Centre for Investigative Journalism.
