All posts tagged featured


NLNG Is Supplying All its Butane Production to Nigeria in January 2022

Nigeria Liquefied Natural Gas (NLNG) Limited supplied its entire Butane (LPG) output to Nigeria’s domestic market in January 2022.

It is also supplying 50% of its propane production to the country (although its propane output is a minuscule fraction of the Butane production).

It is the first time the company would not export a single tonne of Butane. NLNG Ltd says it will do the same thing for Propane by January 2023, that is: its entire production of Propane will be supplied to the domestic market.

In 2021, the company increased its LPG supply commitment from 350,000 metric tonnes (or 28Million 12.5kg cylinders) to actual delivery of  400,000 metric tonnes (or 32Million 12.5kg cylinders) thereby directing most of its production into the domestic market. “But this was not enough for NLNG, hence this commitment to do all that we possibly can and supply 100% of our LPG production to the domestic market,” says Phillip Mshelbila, NLNG’s Chief Executive Officer.

The quantity of Butane supplied to the Nigerian market in 2021 was 378,000Tonnes. Propane volume was 21,000Tonnes. “Actual production of LPG depends on the volume and composition of feedgas we get from our gas suppliers”, says Andy Odeh, NLNG Ltd’s General Manager, External Relations and Sustainable Development. With this commitment it is expected that NLNGLtd will supply about 600,000Tonnes of both Butane and Propane into the Nigerian market in 2022. The volume of LPG consumed in Nigeria in 2021 was around 1.2Million Tonnes, according to government data.

 

 


Upstream M&A Deals on the Rise, Return to Pre-COVID 19 Levels

Industry analyst Rystad of Norway says that global upstream merger and acquisition (M&A) deals rebounded to pre-COVID-19 levels in 2021, reaching a total of $181Billion, a 70% increase over 2020, The total deal value for 2021 was the highest in three years and almost reached the highs seen in 2017 and 2018 of $205Billion and $199Billion, respectively, Rystad Energy research indicates.

“Sellers faced difficulty finding buyers during the downturn in 2020, but that ended last year as big deals made a comeback on high commodity prices and a strengthening market.”, the report says. “Deals valued at more than $1Billion accounted for $126Billion, or 70%, of the global total. The share of $1Billion-plus deals rose almost three-fold, with 35 such deals announced in 2021 compared with just 13 in 2020.

Out of the $1Billion-plus deals, 13 were company acquisitions together valued at around $65Billion. Two large Australia-focused mergers – one between Santos and Oil Search and another between Woodside Petroleum and BHP – contributed about $22Billion, while other $1Billion-plus company acquisitions were focused on North American assets.

The share of resources sold in deals shifted in 2021, with gas accounting for 56% of all traded resources, a sizeable jump from the 43% share it had in 2020. Oil accounted for 31%, and natural gas liquids came in at 9%. This shift was primarily driven by the North American acquisitions in 2021 but was also helped by deal activity in other regions.

“With a strong potential deal pipeline, continuous pressure on companies to transform amid a global push to lower carbon emissions while simultaneously delivering profitable oil and gas production, and an average oil price of above $60 per barrel expected for 2022, the upstream M&A market is likely to stay active for the foreseeable future,” says Ilka Haarmann, senior analyst at Rystad Energy.

Breaking down the deals

Company acquisitions totaled $76Billion, around 42% of the global announced deal value in 2021, a drop in share compared with 2020 when purchases accounted for about 57% of the total deal values. The largest company acquisition by deal value was the merger of Cimarex Energy with Cabot Oil & Gas, which was valued at about $17Billion. Following suit with most other North American acquisitions announced in 2021, the deal agreement was signed in the year’s first half. Cimarex and Cabot did not have overlapping asset positions. The same applied for Appalachia-focused independent Southwestern Energy when it acquired Haynesville-focused Indigo Natural Resources for $2.7Billion and when Paloma Partners acquired Goodrich Petroleum for $480 million. Other US company acquisitions saw the merger consolidate the buyers’ existing portfolio positions.

The largest field acquisitions were Aker BP’s announcement to acquire Lundin Energy’s oil and gas portfolio, valued at about $14Billion, and ConocoPhillips’ acquisition of Shell’s Permian Basin position for $9.5Billion. Field acquisitions in the Permian totaled $19Billion in 2021, accounting for more than half of North American field and license acquisitions, which totaled $35Billion. Russian acquisitions amounted to $12Billion, while in Europe, they clocked in at around $24Billion.

Buyers and sellers

The only peer group with positive net inorganic resource growth in 2021 was public companies, while private players and national oil companies (NOC) divested more resources than they acquired on a net basis. Public companies increased their net resources by about 12Billion barrels of oil equivalent (BOE) through acquisitions last year. However, there are significant discrepancies between different company segments within this group. The top segment in terms of acquiring resources was public independents growing their positions mainly in North America. Among them were Coterra Energy (formed by the merger of Cimarex Energy with Cabot Oil & Gas), Southwestern Energy, EQT Corporation, Chesapeake Energy and ConocoPhillips. In total, public independents acquired around 34Billion BOE of resources in 2021 and sold approximately 21Billion BOE, resulting in a net resource growth of about 13Billion BOE for public independents.

Among public companies, the majors were the most aggressive in divesting resources in 2021, reducing their collective resources by about 5.5Billion BOE on a net basis. The largest inorganic resource reduction among majors was made by Shell, which divested nearly 3Billion BOE in North America, 500 million BOE in Africa and 200 million BOE in Asia. In total, Shell sold around 3.3Billion BOE net for more than $11Billion in net proceeds in 2021. ExxonMobil – the major with the second-largest inorganic resource reduction in 2021 – divested net resources of nearly 1Billion BOE for a net amount of about $3.8Billion, mainly through sales in Europe and Asia.

Public independents spent more than 75% of the segment’s acquisitions costs on acquiring assets from other public players, including majors, to which around 10% of the total amount spent on upstream acquisitions was paid. Public companies acquired assets worth $125Billion and sold assets for about $114Billion. Private companies in total acquired assets for $45Billion and sold assets for around $46Billion.

Looking ahead

The deal pipeline is robust, and the upstream M&A market looks set to continue to strengthen, with deals in the US likely to remain a crucial driver of the global deal value. Large sales in other regions may also materialize in 2022, particularly if majors continue to streamline their portfolios. While resources under development and production can receive high values in the current environment, buyers appear to be more cautious about discovered resources. Without larger changes in the macroeconomic environment, this discrepancy could persist. However, a further steady increase in valuations for producing and under development resources appears unlikely, judging by historical values.

For more analysis, insights and reports, clients and non-clients can apply for access to Rystad Energy’s Free Solutions and get a taste of our data and analytics universe.

Contacts

Ilka Haarmann

Senior Analyst, Upstream

Phone: +47 24 00 42 00

ilka.haarmann@rystadenergy.com


Craig Steinke is New Executive Chairman of ReconAfrica

ReconAfrica, the Canadian minnow operating millions of acres of the Namibia/Botswana Kavango Basin, has appointed Craig Steinke as a director and executive Chairman of the Board.

Steinke, who founded the company, “has played a pivotal role since inception in the development of ReconAfrica through his private energy consulting practice”, ReconAfrica says in a release.

ReconAfrica shot into the consciousness of the global oil patch when it reported, a “a working petroleum system” in the Kavango Basin, after drilling a stratigraphic test well last March. The Kavango Basin was largely unknown to the industry until then. It is an old miogeosyncline, formed in the Permian (the last period of the Paleozoic era, which ended about 250Million years ago).

“Mr. Steinke has over 25 years of experience in identifying, successfully developing and financing oil and natural gas exploration and production projects in North America, Latin America, Europe and Asia”, ReconAfrica explains. “Additionally, through his privately held company, Mr. Steinke plays an active role leading a diversified team, in generating new sources and technologies for sustainable energy”.

Leaving the board of directors is Jay Park, one of the Company’s early stage and significant shareholders, who has served the Company and its predecessor Reconnaissance Oil as its Chief Executive Officer from May 2018 to August 2020, and then as the Company’s executive Chairman. “Mr. Park will continue to take the leading role in advising ReconAfrica on all oil and gas legal matters through Park Energy Law where he is Managing Partner”, the release states.

 


A Lot Is on The Boil for 2022

We predicted that 2021 was unlikely to be a year in which the industry would reset itself, after the disruptions of 2020.

But we were mostly wrong. Things have returned faster than we imagined. A billion-barrel reserves discovery off Cote’D’Ivoire; the surge in Libyan output taking the war-ravaged country past Angola as the second highest producer on the continent; the record increase in output in Egypt’s natural gas, mostly for domestic consumption and a Final Investment Decision for new onshore natural gas development and accompanying power project in Mozambique, are notable highlights of the second year of the COVID-19 pandemic.

For all we know, 2022 may turn out to be the year of basin openings. Shell and TOTAL continue their probes of the orange basin off the contiguous coasts of Namibia-South Africa; ENI will test the Lamu basin off Kenya; ReconAfrica will drill the first seismically defined location in the Kavango Basin. The drilling campaign in Zimbabwe’s Cahora Bassa basin is close to start.

We expect Rig activity to increase as TOTALEnergies starts drilling for the gas in Mozambique; Ghana sees operating companies drilling obligatory wells they had not drilled for years; ENI commences appraisal of the massive Balline discovery in Cote ‘Divoire; Apache, bolstered by new, favourable agreement, increases its rig count onshore Egypt.

Downstream, Dangote rounds off construction of one of the world’s largest single train refineries; Ugandan government seeks investors to fund the state share of the Kabaale Refinery and Ghana’s state firms are open to private parties to construct a new gas processing plant as well as a large scale crude oil refinery.

That said, we invite you to become a paying subscriber of our monthly harvest and go through a number of operational events that will run through the year. Our theme is Who Is Doing What and Where in 2022?

The Africa Oil+Gas Report is the primer of the hydrocarbon industry on the continent. It is the market leader in local contextualizing of global developments and policy issues and is the go-to medium for decision makers, whether they be international corporations or local entrepreneurs, technical enterprises or financing institutions. Published by the Festac News Press Limited since 2001, AOGR is a paid subscription, monthly hard copy and e-copy publication delivered around the world. Its website remains www.africaoilgasreport.com, and the contact email address is info@africaoilgasreport.com. Contact telephone numbers in the West African regional headquarters in Lagos are +2348124374087, +2348130733523, +2347062420127, +2348036525979, +2348023902519.

Editor


European Bank to Invest in Scatec’s $340Million Green Bond in Egypt

The European Bank for Reconstruction and Development EBRD will invest in a green bond issuance of up to $340Million. The Bank’s participation will consist of up to $100Million in the form of a direct subscription in the Bond, and the provision of up to $30Million stand-by liquidity facility for the benefit of the participating private institutional investors. The Bond will obtain the verified certification from the Climate Bond Initiative (CBI) and will be the first private green renewables-backed bond issued in Egypt.

The Bond’s proceeds will support a portfolio of six operational solar power plants located in Benban, Egypt.

These projects “are ultimately owned 51% by Scatec ASA, 25% by Africa 50 and 24% Norfund”, the EBRD explains. Scatec ASA is a leading renewable power producer, headquartered in Oslo, Norway and listed on the Oslo Stock Exchange. The firm develops, builds, owns and operates solar, wind and hydro power plants and storage solutions, and has more than 3.5 GW in operation and under construction on four continents.

Africa 50 is an investment vehicle established to help bridge Africa’s infrastructure funding gap by facilitating project development, mobilizing public and private sector finance, and investing in infrastructure on the continent.

EBRD says that the impact of the transaction “arises from the Green and Inclusive qualities”. In the first instance, the investment is in an independently certified Green Bond; in the second, the “Sponsor will participate in the inclusion programme aimed at increasing access to skills and economic opportunities for young people of the rural areas near Benban in Egypt by introducing a certified training programme for agribusiness entrepreneurs. In addition it will promote workforce diversity by enhancing the role of women in the traditionally male-dominated local economy.

“The Bank’s additionality is mainly derived from: (i) the Bank is offering financing on reasonable terms and conditions, that is expected to close the funding gap and allows carrying out a successful fund-raising process, (ii) supporting the project’s access to the international capital markets in the context of uncertain market conditions by offering an innovative financing structure and providing comfort to international investors, and (iii) the conditionalities obtained by the Bank to enhance inclusion and environmental standards”.

 


How are IOC Divestments Impacting Local Capacity?

Partner Content

The International Oil Corporations (IOCs) had a firm hold on the Nigerian oil and gas sector for over 50 years.

Their grip began to relax in 1991 when indigenous players made their entree, thanks to Professor Jubril Aminu’s deliberate policy of encouraging indigenous participation in the Nigerian oil and gas sector, under military president, Ibrahim Babangida.

From the class of ‘91 has emerged an enduring success story; Mike Adenuga’s Conoil, recipient of Oil Prospecting Licence (OPL) 113.

The 2001 marginal field round would introduce more indigenous players to the sector with the likes of Platform and Midwestern stepping up to stake their claim. The marginal field round, superintended over by Funsho Kupolokun, in his capacity as Special Assistant to President Olusegun Obasanjo, did more than deepen indigenous participation. It helped get ready a corps of local players who would take advantage of asset divestments by the IOCs, 10 years in the future.

Beginning in 2010 and led by SPDC, IOCs operating in Nigerian have divested 26 assets. Seplat (formed as an SPV by Shebah and Platform) took OML 4, 38 and 41 off Shell in 2010 for a reported $340Million.

Other transactions have happened subsequently; Neconde (OML 42) in 2011, Eroton (OML 18) in 2014, First E&P (OMLs 83 and 85) in 2014, Aiteo (OML 29) in 2015 and just last year Trans-Niger Oil and Gas (TNOG) (OML 17).

Another round of divestments is around the corner and as negotiations progress one is constrained to ask how the past iterations have impacted on local capacity because while new and thriving indigenous players have emerged, the question that is not so quickly addressed is how the re-alignment impacts the value chain from local contractors to community liaison, environmental and security concerns as well as oil servicing support.

The Local Content Act of 2010 has been largely responsible for the emergence of a corps of technical and financially competent oil and gas asset development companies who have cut their teeth providing support largely for Domestic Oil Companies (DOCs) who have had to look inwards and away from the international service providers. Top players would include a local content champion like Century Group (Century) whose work with SPDC and other key players has helped it build an advantageous operational framework and strong stakeholder management systems, leveraging its extensive local knowledge of the terrain and people, as well as challenges that erstwhile made producing most of these assets a challenge.

Following TNOG’s acquisition of OML 17 from Shell for a reported $1.7Billion dollars, the Africa Report notes that TNOG plans to “triple the production of OML 17’s wells. At the time of the deal, production was around 27,000 barrels per day, with the existing infrastructure designed for 100,000 barrels per day, a peak reached in the past before a slow decline. Proven and probable (2P) reserves, according to Tony Elumelu, are around 1.2Billion barrels.”

This is the mantra from every new owner because sweating the asset and increasing production is key to ensuring positive yields and return on investments but this requires a rejigging of the entire value chain.

First consideration is access. Aside from the fresh focus on decarbonization and energy transition, the core reasons IOCs have proffered for divestment have remained community agitations/restiveness, environmental concerns and insecurity, oil theft and sabotage, etc. This is why divestments have focused largely on onshore and shallow water assets.

So, new and prospective owners of divested assets must evolve strategies not just for ramping up production but for avoiding the problems that dogged the IOCs. To do this requires a new approach which will be more holistic than adhoc.

The new owners will require strategic partners who know the lay of the land and who can help with operation and technical support. These partners must have local knowledge, a good understanding of the issues, exhibit financial capacity, evince technical competence and the ability to build capacity around the business and the local community of contractors and vendors.

Other key considerations would be partners that have a firm handle on community and multi stakeholder management as well as Standard Operating Procedures and Security Protocol that will ensure asset security and integrity post-divestment. This is critical for onshore and shallow water assets.

These are key success factors and it is heartening to see that NNPC is getting on board from a government and policy perspective, especially with the benefit of hindsight. Mele Kyari, the state firm’s Group Managing Director, has been reported as having said that the government will “ensure that only investors with technical, financial and operational capabilities take position of the IOCs assets, thereby adding value to the industry.”

To make this happen he is also quoted as promising that the “NNPC will ensure Nigeria’s strategic national interest is safeguarded by developing a comprehensive divestment policy that will provide clear guidelines and criteria for divestment of partner’s interest.”

The ongoing litigation between Aiteo and Shell over what the former has described as opacity in their due diligence negotiations over OML 29 as well as the fallout from the 2021 Nembe oil spill is pushing these issues to the front burner especially as a new divestment window opens.

These are key considerations for the NNPC and stakeholders in the divestment exercise to consider.

 


Carbon Capture and Storage (CCS): the Silver Bullet of the Energy Transition?

By Gerard Kreeft

Harry Houdini, the famous 19th century illusionist, created a sensation when he made an elephant disappear. The Government of the Netherlands in 2017 continued this tradition. It promised to make one-third of CO2 emission reductions, scheduled for 2030, disappear by storing them offshore.

Houdini’s illusion caught the fancy of the world. The illusion of the Netherlands is that the promise of carbon capture and storage of CO2 is still not fully comprehended, understood or simply forgotten. Then, thanks to offshore carbon storage, the Netherlands was to become a leader of the green transition.

There is no doubt that the previous government was overzealous in promising how offshore carbon capture and storage (CCS) could benefit the energy transition. The new Dutch coalition, scheduled to be officially installed early 2022, has been rather mute about offshore CCS and the role it will play in any energy transition.

Lessons Learned

To date the only CCS project in the Netherlands is the Porthos Project, a joint venture by a consortium of companies which will capture a combined 2.5Million tonnes CO2 annually.  A final investment decision is anticipated in the spring of this year.

Can CCS offer the Energy Transition a silver bullet?  For Africa? This is highly relevant given the importance that is being placed on CCS by various oil and gas companies.

 

The basic aspects and experiences to date about CCS have been vividly described in a study authored by Clark Butler, on behalf of IEEFA(Institute for Energy Economics and Financial Analysis, July 2020). CCS basically encompasses the following steps.

  1. Capture: The separation of CO2 from other gases produced at large industrial process facilities such as coal and natural-gas-fired power plants, steel mills, cement plants and refineries.
  2. Transport: Once separated, the CO2 is compressed and transported via pipelines, trucks, ships or other methods to a suitable site for geological storage.
  3. Storage: CO2 is injected into deep underground rock formations, usually at depths of one kilometre or more, depleted oil or gas fields, deep saline aquifer formations or other forms of underground caverns, though it could apply to any form of storage.

CCS was first employed to supply CO2 for enhanced oil recovery (EOR) operations for several natural-gas processing plants in the Val Verde area of Texas in the early 1970s.

Butler’s conclusions about CCS are uncompromising:

  • CCS is prohibitively expensive compared to other greenhouse gas emissions mitigation options, such as renewable energy and energy storage technologies.
  • CCS offers no financial return for investors.
  • CCS has a dubious track-record. Even the Global CCS Institute – a booster organisation for CCS – acknowledges in its 2019 Global Status of CCS report that CCS is at best a minor contributor to decarbonisation, addressing up to 9% of greenhouse gas (GHG) emissions by 2050.
  • There isn’t one example of a CCS project anywhere in the world that offers a financial justification for investing in CCS.
  • In the absence of a carbon price, CCS will never provide a return on investment.

What have been the experiences to date by the majors? Clark maintains that

“European oil companies—in particular, Equinor, Shell and Total—are investing in CCS, notwithstanding the lack of return, because it is an important part of their decarbonisation narrative and supports their aims to be seen as ‘responsible’ energy companies”.

Shell

Shell is involved in two CCS projects: Quest in Alberta, Canada, funded by the Alberta and Federal Canadian governments and operated by Shell; and Gorgon in Western Australia, a project in which the project principals (Shell and Chevron) are financially motivated not to operate the CCS plant.

The Quest project near Edmonton, Alberta captures and stores CO2 emitted at a large oil sands upgrader complex.  The cost is $1Billion.  Although Shell as operator gains a lot of positive publicity for running this operation which adds to its “green credentials”, in actual fact 65% of the funding came from the Government of Alberta’s Carbon Capture and Storage Fund and the Government of Canada’s Clean Energy Fund.  Had government funding not been provided, this project would never have happened.

“The Gorgon plant has failed to meet its targets every year, notwithstanding a $60Million subsidy from the Western Australian government. Shell’s actual outlay in CCS over the years remains to be seen. Its overall investment in renewables is well behind its stated targets. Any progress Shell demonstrates in removing carbon from the atmosphere using CCS (1Million tonnes per annum at Quest and up to 4Million tonnes at Gorgon) should be seen in light of Shell’s total emissions of 656Million tonnes per annum .

TOTALEnergies

The company “has also promised massive investment in CCS to remove up to 5 million tonnes of CO2 per annum (8% of scope 1 and 2 GHG emissions and 1% of scope 1/2/3 emissions).”  The company” is an investor in Equinor’s Sleipner CO2 storage as well as, with Shell and Equinor, the larger Nordic project under development, Northern Lights.”

 Equinor

“Equinor, the Norwegian state oil and gas producer, has been investing in CCS since 1996, mainly because Norway has had a carbon price since 1991. Its Sleipner CO2 storage and Snøhvit CO2 storage facilities have cumulatively captured and stored around 22Million tonnes of CO2. Compared to the rest of the fossil fuel industry, this is considerable achievement but this pales into insignificance when one considers that Equinor is responsible for over 330Million tonnes of CO2 emissions every year (scope 1, 2 and 3).”

“With the carbon price, there is a modest economic return on its CCS operations but the impact on emissions is immaterial in the scheme of Equinor’s contribution to global warming. By way of comparison, Equinor’s scope 3 emissions increased by 26Million tonnes per annum from 2014 to 2018.”

Some unsettling truths

According to Butler transportation and storage are key areas of concern. The CO2 must be separated, and transported to the sequestration site.

Transportation and storage are two key areas of concern. ‘Captured’ carbon must be separated, transformed and, in most cases, transported to the sequestration site. The energy used in this process and the leakages that can occur during transportation and handling can materially reduce the net impact of the CCS process.

Butler also points out that “the underground storage into which the carbon is injected is not always secure. Wells have weaknesses and gaps. Fracking causes long-term subterranean instability, and seismic activity could dislodge even the most carefully stored carbon”.

CCS storage must have a purpose other than a symbolic gesture of appearing green to the shareholders, investors and the public. Simply producing hydrocarbons and then using CCS to store CO2 so that a company can continue to produce hydrocarbons unabated has become a non-starter. Investors and shareholders are willing to give companies a pass on blue(methane) or gray(coal) hydrogen as long as it is obvious that green hydrogen is the end game.

For example, key questions still remain surrounding ExxonMobil’s $100Billion CCS project that would be built along the Houston, Texas Shipping Channel. This undoubtedly is being driven by Engine Number One, the small but very influential American investor group, seeking a new direction for the company. Is CCS the end game or is an alternative energy strategy being developed?

Then consider the dilemma of rising CO2 prices and actively supporting a global emissions trading scheme. A sign, one would say, for encouraging the CCS market. Yet the looming threat is that green hydrogen will in the coming decade destroy this potential market. How? Simply because electrolyzer capacity will be dramatically expanded and green hydrogen dramatically reduced in cost. It would then reduce the need for grey and blue hydrogen, and the need for storing CO2. In the European Union the current installed electrolyzer capacity is 4GW and expected to increase to 40 GW of installed electrolyzer capacity by 2030.

Of course, optimism cannot be dismissed. Fortune Business Insights, a market research company, expects the carbon capture and storage (CCS) market to grow to $7 billion annully by 2028. The company expects the market to exhibit a CAGR(compound annual growth rate) of 19.5 per cent from 2021 to 2028, while the global carbon capture and sequestration market size will grow from $2.01Billion in 2021 to $7Billion by 2028.

In Africa, the prime CCS example to date is at BP’s-Equinor’s In Salah oil and gas field in Algeria. More than 3Million tonnes of CO2  have been stored before being stopped in 2011 due to capacity limits in the geological structure.

Does Africa have the ability to store all the extra carbon dioxide that it is expected to generate in the coming decades? Possible areas of interest could be the Zululand basin in South Africa, a well-mapped onshore area, offshore Angola, onshore and offshore Nigeria and offshore Ghana. The Rovuma basin offshore of  Northern Mozambique could also be an area of interest.

Can Africa withstand the politics of illusion and see CCS for what it really is? A smoke screen for not addressing the real needs of the energy transition.

Finally, a simple conclusion. A simple substitute for CCS is a tree planting campaign. In Canada the federal government has pledged to plant two billion trees in the ground by 2030. To date deadline targets have come and gone. Yet this is a campaign which requires encouragement and continued public pressure.

Such a scheme should also encourage the oil and gas sector to contribute and participate. A scheme which is practical and easy to understand why it is of such huge benefit to the energy transition. Certainly, it should prove to be of interest to Africa’s new energy players.

Gerard Kreeft, BA (Calvin University, Grand Rapids, USA) and MA (Carleton University, Ottawa, Canada), Energy Transition Adviser, was founder and owner of EnergyWise.  He has managed and implemented energy conferences, seminars and university master classes in Alaska, Angola, Brazil, Canada, India, Libya, Kazakhstan, Russia and throughout Europe.  Kreeft has Dutch and Canadian citizenship and resides in the Netherlands.  He writes on a regular basis for Africa Oil + Gas Report, and contributes to IEEFA.


Among Nigeria’s “Exec Regulators”… He’s the One With “Institutional Memory”

Apart from Nuhu Habib, who has been appointed as executive commissioner in charge of development and production, none of the seven-member team of executive commissioners of the Nigerian Upstream Petroleum Regulatory Commission (NUPRC) has ever worked at the former Department of Petroleum Resources (DPR).

Habib was formerly a Chief Geologist at the defunct agency.

It is not ordinarily a bad thing, considering that the staff that they will be superintending is composed of personnel with a deep well of experience. If it is problematic,  it should be nothing that cannot be taken care of with adept human resources management.

Several of the new team are not entirely new to the oil industry, even upstream.

Empathy calls..Gbenga Komolafe, CEO, NUPRC, with Isa Modibo, Chairman of the commission

For one, Kelechi Onyekachi Ofoegbu, executive commissioner, Economic Regulations and Strategic Planning, worked in the supply chain management at Eland Oil & Gas and was the technical adviser to the Minister of State for Petroleum, until his appointment.

But it has always been a fraught isue in Nigerian public service, when an entire team of managers is appointed from outside to run a parastatal.

True, the NUPRC is a brand-new agency, a creation of the new Petroleum Industry Act PIA, but it is effectively staffed with the upstream half of the defunct DPR.

What it means is that the new executive commissioners, who now function in the capacities of the Deputy Directors of the defunct DPR, have to be careful how to treat bruised egos. There are dozens of assistant directors and managers, with sterling careers entirely forged in the crucible of the old DPR, who need to be reassured.

Sarki Auwalu, the last Director of the defunct DPR, didn’t exactly leave a legacy of empathy. Months after he was appointed, he fired the entire team of Deputy Directors (all of whom were his seniors, as he was appointed Director straight from the position of assistant director). That move, already created a sense of deep distrust, which the new team has inherited.

 


Nuhu Habib Returns to “DPR”

Nuhu Habib, special adviser on Natural Resources to Nigeria’s President Muhammadu Buhari, has been appointed an executive commissioner at the Nigerian Upstream Petroleum Regulatory Commission (NUPRC).

He will be executive commissioner in charge of development and production, a crucial job, considering that the Niger Delta, Nigeria’s main producing basin, is essentially a mature province, with more development and production than exploration.

The appointment is a pointer to how far Habib has travelled in a short time, in Buhari’s second term. In mid–2020, he was only a manager, a position below assistant director, which was the first ‘top tier’ level, in the organogram of the Department of Petroleum Resources (DPR), the forerunner of Nigerian Upstream Petroleum Commission.

By the end of 2020, he had been seconded to the state house as President Buhari’s special adviser on Natural Resources, a posting which was pivotal in the administration of the country’s Marginal Field Bid Round. When the President announced the implementation steering committee to oversee roll out of the Petroleum Industry Act (PIA) in August 2021, he was named a member.

A 1998 graduate of Applied Geology from Abubakar Tafawa Balewa University, Habib holds a Master’s degree in Petroleum Geosciences from Imperial College London and a PhD in Engineering from Seoul University, according to his LinkedIn Page.

 


Angolan Independent, Somoil, Purchases TOTAL’s Interest in Block 14

By Sully Manope

TOTALEnergies has sold its non-operated interest in Angolan deepwater Block 14 to Somoil, the Angolan independent. The French major says it “signed an agreement to sell, jointly with Inpex, the Angola Block 14 B.V. to the Angolan Company Somoil”.

The transaction is subject to the approval of the Angolan authorities.

TOTALEnergies Holdings International B.V. (50.01%) and Inpex Angola Block 14 Ltd (49.99%) collectively hold a 20% interest in Block 14 in Angola and a 10% interest in Block 14K.

Block 14 and Block 14K are operated by Chevron.

“The offshore blocks have been producing since 1999. Net production from Angola Block 14 B.V (to TOTALEnergies and Inpex), was 9,000 barrels of oil equivalent per day in 2021”, TOTALEnergies says in a release.

“By divesting this interest in mature fields, TOTALEnergies is implementing its strategy to highgrade its oil portfolio, focusing on assets with low costs and low emissions” said Henri-Max Ndong-Nzue, Senior Vice President Africa of TOTALEnergies Exploration & Production.

Somoil is the biggest and most active Angolan homegrown upstream operator.

“TOTALEnergies remains the number one energy player in Angola, through its leading operating position in deep-offshore, its interest in Angola LNG and in a first solar power plant project, Quilemba Solar, located in the southwest of the country.”

© 2021 Festac News Press Ltd..