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Decklar Has Contracts to Truck Over 300,000Barrels to Two Nigerian Refineries

Canadian operator Decklar Resources reports that it has trucked a total of 48,500barrels of crude to two modular refineries in Edo State, Nigeria.

The company has contracts to deliver over 300,000 barrels of oil to these two refineries over the next 12 months.

Decklar operates the Oza field on behalf of itself and Millennium Oil & Gas, the holder of the licence to the field, located in Oil Mining Lease (OML) 11 in Rivers State.

As the two partners were unable to evacuate their output through the Trans Niger Pipeline (TNP) to the Bonny Terminal for export, they decided to truck the commodity to local refineries.

Decklar’s latest operational update notes that “trucking of crude oil from the Oza Oil Field to the Edo Refinery & Petrochemical Company (ERPC) has reached a cumulative volume of over 41,000 barrels”. ERPC is a 6,000 barrels per day modular refinery located in Ikpoba-Okha Local Government Area, Edo State.

The update also says that “over 7,500 barrels of crude have been delivered to Duport Midstream Company Limited (DMCL)”, located in Otien Edo State.

In effect, these deliveries have upended the narrative that refineries that are not built by oil producing companies themselves will suffer undue delays getting access to feedstock.

Prior to the supply of Oza crude to Edo Refinery and Duport, the two functional modular refineries in the country were the 11,000BPD ND Refinery at Ogbele, owned by Niger Delta E&P and the 5,000BPD Waltersmith Refinery &Petrochemical at Ibigwe, owned by the Waltersmith Group. Their supplies are assured by the crude oi production from their Ogbele and Ibigwe fields respectively.

Decklar says that the 41,000Barrels it trucked to Edo Refinery includes “10,000 barrels delivered in 2022 under the initial sale and purchase agreement and over 31,000 barrels delivered so far in 2023”. With that, “the deliveries under the 30,000 barrels contract have now been completed and invoiced, and deliveries will continue under the new 200,000 barrels contract”.

The company commenced delivery of crude oil commenced from the Oza Oil Field to DMCL in March and “under the sale and purchase agreement with DMCL, Decklar and Millenium initially delivered 5,000 barrels to the Duport refinery in March and early April, followed by an additional 2,500 barrels in the last half of April”.

Deliveries of an estimated 5,000 barrels per month will continue going forward, Decklar explains “and DMCL has agreed to purchase up to 100,000 barrels over the next 12 months”.


Angola Slips Below 1MMBOPD in Output and Export, Loses Revenue

By Macson Obojemuinmoin

Angola produced 30,059,033 barrels of oil in March 2023, corresponding to a daily average of 969,646 barrels of oil (BOPD).

This was 9% less than the 1,063,589BOPD produced in February 2023, according to data by Angola’s National Oil, Gas and Biofuel’s Agency (ANPG), the country’s hydrocarbon industry regulator.

Export for March 2023, published by the country’s ministry of finance portal, frequently consulted by Africa Oil+Gas Report, amounted to 950,460BOPD, which was a 9.5% drop from 1,050,866BOPD in February 2023.

The country’s revenues have also headed for a fall. “Angola exported 87.92Million barrels of oil for a total of $6.92Billion in the first quarter of 2023, which represents a 30% year on year decline”, the Portuguese news agency Lusa reports, quoting José Alexandre Barroso, Angola’s secretary of state for oil and gas. “In the first quarter of 2022, according to figures from the ministry for mineral resources, oil and gas consulted by Lusa, Angola exported 98.38Million barrels of oil at an average price of $103.83, generating revenues of $10.14Billion”, Lusa reported.

Angolan authorities’ concern about declining output has provided the impetus for a frenzied drive for acreage licencing rounds (there have been three lease sales in the last three years) and improved fiscal terms for oil majors in the country.

In the event, Azule Energy, the incorporated joint venture between ENI and BP, awarded, last February, $7.8Billion worth of contracts for commencement of construction of the second phase of its Agogo Integrated West Hub Development project in Block 15/06. The project, expected to be in operation by mid-2026, involves the installation of an FPSO with a production capacity of 120,000BOPD, gas injection capacity of 230MMscf/d and water injection capacity of 120,000BWPD.

The government has also approved the development plan for TOTALEnergies operated the Cameia-Golfinho development in Blocks 20 and 21, the first hydrocarbon development targeting presalt reservoirs in the deepwater Kwanza Basin. TOTAL plans to take Final Investment Decision on the project by July 2023 and has indicated that it expects first oil from the 70,000Barrels of Oil Per Day project by 2026.


TOTALEnergies: Neither a soul to be blessed nor a body to be damned!

By Gerard Kreeft

TOTALEnergies recently announced that it has accepted an offer of $4.5Billion from Suncor Canada for its oil sands assets. Originally The French giant planned to spin-off its Canadian assets in an Initial Public Offering (IPO). According to the major’s press release the Suncor offer was “more straightforward in its execution than the planned spin-off”. Accordingly, the spin-off was terminated.

TOTALEnergies’ divestment was from two oil sands properties in northern Alberta.  The oil sands were earlier called “tar sands” or “bitumen” due to the oil’s low gravity and dense composition.  Production from these sands took a traditionally difficult, expensive and energy intensive route in the journey to upgrade the heavy oil into light saleable crude oil.   In the past decade, technological advances improved the commerciality of the production but it remains highly carbon intensive.  Indeed, President Barrak Obama and Energy Secretary John Kerry in 2015 declared that oil from the Alberta oil sands was “the dirtiest oil in the world”.  The benefit of this deal to TOTALEnergies is huge. In one fell swoop, the company gained $4.5Billion and also received a significant reduction in its carbon footprint by disposing its two most emissions-intensive assets in its global portfolio.  This disposition allows the company to significantly polish up its green credentials.

In the same press release TOTALEnergies stated that it will distribute to its shareholders at least 40% of the cash-flow in 2023, either through share buybacks or a special dividend distribution.

The timing of this announcement comes on the eve of the company’s AGM (Annual General Meeting) on May 26 in Paris. No doubt shareholders will cheer that more cash will be forthcoming. Yet is this a short-term gain for a long-term pain?

Clarity of Message

In the January 2018-April 2023 period the Dow Jones Industrial Index rose 35%: increasing from 25,295 to 34,098. Yet the European oil majors (with the exception of Equinor), including TOTALEnergies, have seen their share prices underperforming badly: Repsol down 18%, BP down 7%, Shell down 10%, ENI down 14%, TOTALEnergies remained the same. Only Equinor was up 26%. In the same period US oil giants Chevron and ExxonMobil have seen their share prices flourish: Chevron up 32% and ExxonMobil 36%.

Table 1: Stock market prices of majors Jan 2018- April 2023(NYSE – New York Stock Exchange)

YearRepsolBPShellEniTotal

Energies

ChevronExxonMobilEquinor
2018$17$43$69$35$58$128$87$23
2022$14$40$62$30$58$169$118$29

 

Why is it that the share prices of Chevron and ExxonMobil have performed so well and their European counterparts have done so poorly?

The message from the investor community is the clarity of the message. Chevron and ExxonMobil have as their mainstay–the production of hydrocarbons and this is the message that is preached. New energy policies including CCS(Carbon Capture and Storage) and other new energy initiatives make up only  between 15-20% of their capital budgets. In the case of Chevron some $3Billion per year based on a capital budget of $15-$17Billion; ExxonMobil’s new energy comes in at $3Billion per year based on a capex of $23- $25Billion. The message is clear and simple: we are oil companies pure and simple. Done in the good tradition of John D. Rockefeller the spiritual father of both companies.

European oil giants, have seen their dualism—wanting  to maintain their green image and also  profiting from the oil bonanza—fall out of favour by company shareholders. Their clarity of messaging has been found wanting.   The sole exception is Equinor who have stated that the majority of their capex budget will be from renewables by 2030.

Where did it go wrong?

To understand TOTALEnergies’ strategy we must go back to 2020. Then TOTALEnergies took the unusual step of writing off $7Billion in impairment charges for two oil sands projects in Alberta, Canada. Both projects were listed as proven reserves. By declaring these proven reserves as null and void, with one swoop of a pen, TOTALEnergies cast aside the petroleum classification system, which was the gold standard for measuring oil company reserves.

The company simply decided that these reserves could never be produced at a profit. Instead, TOTALEnergies has substituted renewables as reserves that can be produced profitably.

TOTALEnergies’ strategy was based on the two energy scenarios developed by the International Energy Agency (IEA): the Stated Policies Scenario (SPS), which is geared for the short to medium term, and the Sustainable Development Scenario (SDS), which focuses on the medium long term.

Taking the “Well Below 2 Degrees Centigrade” SDS scenario on board, TOTALEnergies has, in essence, taken on a new classification system. By embracing this strategy, the company is the only major to have seen a direct benefit from using the Paris climate agreement to enhance its renewable energy base.

While it wrote off some weak assets, it also did something else: TOTALEnergies began to sketch a blueprint for how to transition an oil company into an energy company.

Patrick Pouyanné, TOTALEnergies’ chairman and CEO, then stated that by 2030 the company “will grow by one third, roughly from 3Million BOED (Barrels of Oil Equivalent per Day) to 4Million BOED, half from LNG, half from electricity, mainly from renewables.” This was the first time that any major energy company translated its renewable energy portfolio into barrels of oil equivalent. So, at the same time that the company has slashed proven oil and gas from its books, it has added renewable power as a new form of reserves.

Proven reserves long stood as the holy of holies for the oil industry’s finances—the key indicator of whether a company was prepared for the future. For decades, investors equated proven reserves with wealth and a harbinger of long-term profits.

Because reserves were so important, the reserve replacement ratio (RRR), the share of a company’s production that it replaced each year with new reserves, became a bellwether for oil company performance. The RRR metric was adopted by both the Society of Petroleum Engineers and the US Securities and Exchange Commission. An annual RRR of 100% became the norm.

But TOTALEnergies’ write-offs showed that even proven reserves are no sure thing and that adding reserves doesn’t necessarily mean adding value. The implications are devastating, upending the oil industry’s entire reserve classification system as well as decades of financial analysis.

How did TOTALEnergies reach the conclusion that reserves had no economic value? Simply put, reserves are only reserves if they’re profitable. The prices paid by customers must exceed the cost of production. TOTALEnergies’ financial team decided those resources could never be developed at a profit.

The company had not abandoned its oil and gas investments. However, its renewable investments were seen as additional ballast to the company’s balance sheet, keeping it afloat as it carefully chooses investments, including oil and gas projects, with a high economic return. The Suncor sale is perhaps an indication of selling oil and gas assets at a profit before they are deemed stranded assets.

Reviewing TotalEnergy’s Strategy

Counting the money

TOTALEnergies has recently announced that it will be on track, by 2050, to have 50% of its energy mix in renewables + 25% in “new molecules”(green fuels). The remaining 25% would be comprised of oil and gas including LNG.

The company’s capital expenditures for the period 2022-2025 is anticipated to be between $14Billion-$18Billion per year: “a third will be in low-carbon energies, about 30% will be dedicated to the development of new oil and gas projects, and the remainder devoted to maintenance of the hydrocarbon portfolio.”

In other words the hydrocarbon budget will be approximately $8Billion-$11Billion and the renewable budget will be $5Billion in 2023.

Could shareholders demand that by 2030 the lion’s share of the company’s capital budget is  dedicated to renewables instead of hydrocarbons?

TOTALEnergies could take the Equinor precedent as an example. Equinor’s message of spending more than one-half of its capital spending on low carbon energy by 2030 in offshore wind technology has caught the fancy of its investor community.

LNG—Where did it go wrong?

TOTALEnergies’ 2022-2025 hydrocarbon budget could also be threatened by a floundering LNG market. In particular its Mozambique LNG project.  IEEFA(Institute for Energy Economics and Financial Analysis) in its recent Global LNG Outlook 2023-2027 provides a somewhat sobering picture for new LNG projects: “IEEFA expects that sustained high global LNG prices; weak LNG demand growth and elevated price sensitivity in Asia; declines in gas consumption in Europe; and a multi-year string of global capital investments in cost-competitive energy alternatives will undermine global LNG demand growth over the next several years.”

According to IEEFA the global demand for LNG is slowing:

Europe although maintaining a high degree of importing LNG, is also increasing  energy efficiency measures and wind and solar projects have become commonplace; Japan and Korea, historically dependable LNG importers, are increasingly turning to nuclear, and renewables; China, decreased its LNG imports by 20% in 2022 and is turning to pipeline gas supplied by Russia as well as domestic gas supplies; South Asia, including India, Pakistan, and Bangladesh, slashed purchases by 16% in 2022 and suppliers often defaulted on contracts to obtain higher prices elsewhere.

“After several years of weak supply growth, IEEFA anticipates that the global LNG market will see a tidal wave of new projects come online starting in mid-2025. The wave will likely crest in 2026, with the addition of 64Million metric tons of annual liquefaction capacity—the most in the history of the global LNG industry. The supply additions will boost global liquefaction capacity by roughly 13% in a single year. Liquefaction projects targeting in-service after 2026 may be entering a much smaller demand pool than bullish market forecasts anticipate. As new supply floods the market, today’s tight markets may give way to a supply glut, with lower-than-anticipated prices, smaller netbacks, tighter margins, and lower profits for LNG exporters.”

According to IEEFA’s forecast in 2023 only 5.8Million Tonnes Per Annum (MMTPA) of liquefaction production will be developed, and in 2024 9.1MMTPA. Total LNG production capacity is currently 456MMTPA.

The turning point will be 2025.

“IEEFA anticipates that roughly 17MMTPA of liquefaction projects are likely to come online around the world in 2025—more than in 2023 and 2024 combined. New capacity additions will crest in 2026, with an estimated 64MMTPA of capacity coming online in a single year, and continue into 2027, when 37MMTPA of new capacity is expected to begin operating”.

Much of the new production will come from Qatar, USA and Australia. If 2026 and 2027 will see a sharp upturn in LNG liquefaction production, how will this affect Mozambique’s two LNG projects which could potentially add 38.1MMTPA when fully functioning? Long term delays can only threaten project viability. And not proceeding sooner rather than later increases the chances of these projects being listed as stranded assets.

A more immediate threat is that of ENI’s Coral South project in offshore Mozambique which is already in operation. BP has contracted the entire output of Coral Sul for 20 years, having signed a free on board (FOB) contract with the project partners. In July 2022 it was reported that ENI was considering the possibility of deploying a second floating liquefied natural gas vessel in Mozambique. What does this mean for Rovuma and Mozambique LNG?

TOTALEnergies’ African strategy      

Much of TOTALEnergies’ 25% forecasted hydrocarbon  budget, proposed for up to 2050,  will be focused  on African  low-cost, high-value projects, squeezing more value out of  various African assets to ensure a prolonged life cycle.

In Angola the company produces more than 200,000BOEPD from its Block 17 and Block 32, and non-operated assets including AngolaLNG.

In Namibia TOTALEnergies has made a significant discovery of light oil with associated gas on the Venus prospect, located in block 2913B in the Orange Basin, offshore southern Namibia.

In South Africa the company is focused on its two South African assets: Brulpadda and Luiperd, the second discovery in the Paddavissie Fairway in the southwest of the block.

Will TOTALEnergies’ deepwater  division seek other parties to ensure that its various projects can be delivered?

A fly in the ointment could well be TOTALEnergies’ Mozambique LNG project, which is expected to cost $20Billion and produce up to 43Million tons per annum. IEEFA’s stinging critique of the LNG market has given this project a visible setback. Will it ever be developed? Deepwater projects are extremely expensive. Will TOTALEnergies call upon potential partners to help develop these prospects?

Then there is the matter of the East African Crude Oil Pipeline (EACOP). Public dissent is continuing. The large international banks and financial institutions are balking at financing this project. Continued delays only make the completion of this on-going saga more uncertain. Will TOTALEnergies sell its stake to avoid further reputational damage?

Turning the Tanker

TOTALEnergies should turn back the clock to 2020 when it made the bold move to utilize renewables as a strategic part of its reserve count. The duality of servicing two masters: hydrocarbons and renewable energy has only produced a murky outlook.

On the renewables front TOTALEnergies has confirmed it will have a 100GW capacity by 2030.

A key to TOTALEnergies’ success is its ability to step into projects at an early stage, some examples:

  • A 50% share of Adani Green Energy Ltd., India installed solar activities.
  • A 51% stake in the Seagreen Offshore Wind project in the United Kingdom.
  • Major positions in floating wind farm projects in South Korea and France.

Yet the company must take a number of radical steps:

First it must repair the splintered and diffused view of  its subsidiary companies—TOTALEren, Sunpower, and Saft–in which it has invested:

TOTALEren: an IPP(Independent Power Producer) developer involved in all phases of project development and implementation with a generating capacity of 3.7GW and 4GW under construction.  According to Africa Oil + Gas Report, the company could become a candidate for a top-ten list of Africa’s leading  renewable developers.

Sunpower: has 6 GW of photovoltaic power installed globally.

Saft: a leading battery producer, whose lithium-ion batteries can store large amounts of electricity in a small amount of space.

TOTALEnergies should look at becoming part of the Green Alliance. Enel, Engie, Iberdrola, and Ørsted have pole position in determining the direction  and scope of the global renewables market:

Enel: committed to achieving CO2 neutrality by 2040 instead of 2050, achieving 75% of electricity from renewables and 80% digitalization of its customers on the grid  by 2025. and having an installed generating capacity of 75GW by 2050.

Engie: pledged to reduce to CO2 neutrality by 2045- 45% of investments is focused on renewables and by 2030 will have 80GW of installed generating capacity.

Iberdrola: in the period 2023-2025 the company will invest $50Billion and achieve net zero for Scope 1, 2 and 3 before 2040. By 2030 the company will have installed capacity of 100GW, valued at $70Billion.

Note: Essentially, Scope 1 and 2 are those emissions that are owned or controlled by a company, whereas Scope 3 emissions are a consequence of the activities of the company but occur from sources not owned or controlled by it.

Ørsted: the Danish wind energy pioneer, continues to set new records. Ørsted share price in December 2022 was $93; five years earlier in 10 June 2016 it was $37. By 2030 the company’s goal is to have an installed capacity of 50GW. Ørsted is also involved with the building of two energy islands– Bornholm and North Sea– which will deliver 10GW of power.

What has set these companies apart is that they have created a huge competitive advantage which will be hard to challenge for newcomers. Moreover, they have moved well beyond simply dabbling in green energy. These companies have become specialists and now moving on to the next level: creating a digital platform on which value does not reside in owning resources but rather in managing data-driven ecosystems. Essentially borrowing a chapter from Uber, which does not own taxis or Booking, which does not own hotels. Creating a digital platform on which value does not reside in owning resources but rather in managing data-driven ecosystems.

How will shareholders react to  these companies in 2023?  To date there is good news and bad news for green energy companies.

Table 2: Stock market prices of new energy companies  Jan 2018- April 2023

YearEnelEngieIberdrolaØrsted
2018$5$16$7$49
2022$7$16$13$89

Enel, the Italian power company has seen its share price increase by 40%. Engie, the large French energy giant has seen its share price remain flat . Iberdrola, the Spanish power company has had an increase of 86% and Ørsted, the Danish power company, has seen its stock soar by 82%.

Recommendations

Plan A : Make 2030, instead of 2050, the new deadline when renewables will command the lion’s share of its capital budget;

Plan B: If Plan A is not working then…Split the company up so that the renewables and hydrocarbon divisions (deepwater and LNG) can pursue their own strategies and directions;

Repair the splintered and diffused view of subsidiary companies—TOTALEren, Sunpower, and Saft.

Such radical measures are required if TOTALEnergies is to grow its stock market price and create real shareholder value.

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 is a guest contributor to IEEFA(Institute for Energy Economics and Financial Analysis). His book ‘The 10 Commandments of the Energy Transition ‘is on sale at https://books.friesenpress.com/store/title/119734000211674846/Gerard-Kreeft-The-10-Commandments-of-the-Energy-Transition


Ghana’s Oil Firm’s  Spending Could be Reckless, Unsustainable, PIAC Warns

Ghana National Petroleum Corporation (GNPC) ’s expenditure on various line items, mainly administrative expenditure and its capital projects, witnessed significant increases by more than 200 percent in 2022, the country’s Public Interest and Accountability Committee (PIAC) has reported.

The company is spending largely on projects that are not in its remit and which are better covered by the finances of the central government, PIAC declares in its 2022 annual report.

GNPC’s continued funding of the construction of roads in the Western Corridor Enclave “constitutes quasi-fiscal expenditure, and should be the primary responsibility of central government and not the National Oil Company”, PIAC recommends in the report. “The total expenditure by GNPC on these roads since 2014 is $124.66 Million”, the report states.

“Given that petroleum revenues recorded a historic high in 2022, the PIAC recommends that GNPC should manage its expenditure and build buffers against volatilities in petroleum revenue inflows in the future”.

PIAC reiterates its call on “GNPC to focus on its core mandate and for the government to desist from borrowing or requesting GNPC to make advances and guarantees on behalf of government and its agencies”.


Despite the Uproar, TOTAL Finally Awards EPC Contract for Uganda-Tanzania Oil Pipeline

It is done. TOTALEnergies has finally awarded the contract for the installation of the long, heated pipeline from Uganda to the Tanzanian coast.

China Petroleum Pipeline Engineering (CPP) had been one of the engineering firms on the bid to construct the 1443-kilometre pipeline from  Uganda’s Hoima district to the Chongoleani peninsula near Tanga in Tanzania’s Indian ocean coast. The company, a subsidiary of China National Petroleum Corporation, received the nod for the project’s engineering, procurement and construction.

The pipeline, named East Africa Community Pipeline (EACOP), has been the most targeted of all the several upstream and midstream projects that make up the Ugandan Lake Albert basinwide oil development, meant to unlock over 1Billion barrels of crude oil, stored in more than 15 fields in Uganda. It will ferry, at peak, up to 216,000 barrels per day of waxy crude from the Tilenga and Kingfisher clusters of fields in Uganda to Tanzania.

The EACOP has been singled out for several court cases by a wide range of activists; it has been cited as wrong by the European parliament and blacklisted by prominent banks who have declared they won’t finance it.

But TOTALEnergies has insisted it is one of the lowest carbon emitting projects in its portfolio. And what’s most crucial, the French major, with a healthy balance sheet, can fund the pipeline on its own.


Ghana Earned its Highest Petroleum Revenue in 2022, Despite a Persistent Output Decline

Total petroleum revenue accruing to Ghana in 2022 was the highest for a single year since inception of petroleum production in the country, with a figure of $1.43Billion.

The surge in earnings is in spite of continuing declining of crude oil production for three consecutive years, according to the 2022 annual report by Public Interest Accountability Committee (PIAC).

The 2022 production figure represents the third consecutive year of reduction in annual production volumes since 2010. In 2019, the PIAC explains in the report.

A volume of 71,439,585 barrels was produced in 2019, but declined to 66,926,806 barrels in 2020, representing 6.32% drop. It further declined to 55,050,391 barrels in 2021 (17.75%) and then to 51,756,481 barrels in 2022 (5.98%). The average decline over the three-year period stood at 10%.

The report laments that Surface Rental Arrears continue to rise. It increased from $2.58Million in 2021 to $2.77Million in 2022, 65% ($1.80Million) of which is owed by four (4) contractors whose Petroleum Agreements were terminated in 2021. Efforts made by the Ghana Revenue Authority to retrieve the arrears are yet to yield the desired results.


ExxonMobil Achieves 2.5Billion Barrels of Cumulative Oil Production in Angola’s Block 15

ExxonMobil and partners have achieved the milestone of 2.5Billion barrels of cumulative oil production in Angola’s deepwater Block 15, since the First Production from FPSO Xikomba, 20 years ago.

The partners installed five FPSOs on the asset in the first six years of commencement of production, thus establishing the fastest execution time in West Africa and one of the fastest in the history of the industry, according the ANPG, Angola’s oil and gas regulatory agency.

Production started with the FPSO Xikomba in 2003, followed by the application of the “Design One, Build Several” strategy for FPSOs Kizomba A in 2004, Kizomba B in 2005 and 2 (two) on Kizomba C (Mondo and Saxi-Batuque) in 2008.

ANPG explains that the achievement “demonstrates that Angola maintains a good potential for oil and gas production, so the National Concessionaire, together with its partners, will do everything to ensure that the sector continues to be profitable and contribute to the development of the Nation”.

Block 15, located approximately 145 kilometers west of the coast of Zaire Province, has 18 commercial discoveries, making it one of the most successful offshore concessions in West Africa.

“Due to the increasing maturity of the fields in block 15, the current focus is on maximizing the recovery of the remaining resources by optimizing production, using technological advances and reducing emissions”, ANPG declares in the statement.


Benefits Negotiations Force Removal of 140,000BPD of Crude from Nigerian Output

By Macson Obojemuinmon

A stalemate in negotiation of wages and benefits led ExxonMobil’s Nigerian workers to shut in the company’s oil wells, forcing the American major to declare force majeure on oil liftings from its major export terminals in the country.

ExxonMobil’s Qua Iboe Terminal loaded 138,731Barrels of Oil and Condensate (blend) Per Day in March 2023. The company’s two deepwater FPSOs – Erha and Usan – which are considered terminals in their own right, produced a combined 116,142BPD in the same month, according to figures from the Nigerian Upstream Petroleum Regulatory Commission (NUPRC).

Several of the staff told Africa Oil+Gas Report, “we are making all efforts to bring everyone back to the negotiation table”, thus, corroborating the statement by the company’s spokesperson Michelle Gray:  “We will continue to take all reasonable actions necessary to resolve the impasse as soon as possible”.

Some of the staff themselves admit that it is very unusual to shut down production to prove a point on the negotiating table for wages and benefits. “I would have thought they would have allowed for some further negotiation before taking the decision to shut down production”, one staff admitted “This is not the best for anyone”.

ExxonMobiil’s output, which is entirely offshore, has been one of the least affected by the crude oil theft from evacuation infrastructure, a key factor in Nigeria’s plunging hydrocarbon production. But the fields have suffered natural depletion in the last 10 years, as the company has invested less on the facilities.

The shallow water assets, which delivered close to 140,000BPD in March 2023, are in the process of being sold by ExxonMobil to Seplat, although the refusal of the regulator to grant consent for the sale has forced a halt in the proceedings.

Yet the ongoing negotiations are not restricted to either deepwater asset workers or shallow water staff.

“There’s no transition in ExxonMobil yet”, the staff disclosed to AOGR. “Until government gives their approval, (for the sale and purchase of the shallow water assets) we are maintaining the status quo”.

“We are all one as at today. No difference”,


How John Wayne (Red Adair) Helped Save the Oil Patch

By Gerard Kreeft

I’ve done made a deal with the devil. He said he’s going to give me an air-conditioned place when I go down there, if I go there, so I won’t put all the fires out.”

If you think it’s expensive to hire a professional to do the job, wait until you hire an amateur.”

Red Adair Quotes

Hellfighters (1968) is an American adventure film starring John Wayne depicting Red Adair as the worldwide oilfield fighter. The film was for the most part negatively received. Yet to have a film made about yourself is indeed a high compliment.

In the course of his career spanning some 35 years Adair and his company battled more than two thousand land and offshore oil wells, natural gas wells, and similar spectacular fires. During World War II Adair served in a bomb disposal unit of the US Army. After the war he started working in the oil and gas industry for Myron Kinley now viewed as the grandfather of modern well control.

Already in 1931 Kinley traveled to Romania and extinguished the 2-year-old Moreni 160-well which had created a crater of 250 feet across and 65 feet deep. Kinley became an international celebrity.

In 1936 Kinley extinguished a well fire burning in Lake Maracaibo in Venezuela, using another new technique. Myron erected a derrick six hundred feet from the burning well and drilled a slant-hole well that intercepted the burning well’s casing deep beneath the surface. He then pumped drilling mud into the well bore, killing the gas pressure and putting out the fire. This use of directional drilling, then a nearly new procedure, provided a novel and radical solution to wild-well control.

How will well control be remembered by future generations? Certainly well control certification done either by IWCF or the IADC will seem like a distant memory.

Kinley and Adair pioneered the technique of using a V-shaped charge of high explosives to snuff the fire by the blast known as the Munroe effect. Adair had seen it used in bazookas and the atomic bomb. Chemical energy generated by initiation of an explosive is focused on the center of a hollow cavity. The concentrated force generates a jet with high penetration power.

Adair gained global attention in 1962 when he tackled a fire at the Gassi Touil gas field in the Algerian Sahara, nicknamed the Devil’s Cigarette Lighter: a 140 metre pillar of flame that burned from mid-November 1961 until the end of April 1962.

Regarding Africa, the two largest oil producers are Nigeria and Angola of which the latter has never experienced a major oil or gas blowout.  Nigeria has had its fair share of blowouts.  Perhaps the worst in the country was in 1980 when Texaco was drilling the Funiwa-5 development well in the shallow water of River State.  Texaco lost control of the well, resulting in a blowout and a spill of 400,000 barrels of oil which had a devasting impact on the nearby coastal communities.

Fast forward to April 2010: the Deepwater Horizon oil spill involving BP’s Macondo Prospect. The Deepwater Horizon oil spill off the coast of the USA was considered to be the largest marine disaster in the history of the industry. The US federal government estimated the total discharge at 4.9Million barrels. In 2011 a White House commission blamed BP and its partners for a series of cost cutting decisions and an inadequate safety system, but also concluded that the spill resulted from “systemic” root causes and “absent significant reform in both industry practices and government policies.” As of 2018, cleanup costs, charges and penalties had cost BP more than $65Billion.

While the various oil field fires and marine disasters have captured the imagination of Hollywood, such tragedies have further stained the reputation of the oil and gas industry. What has the industry done on the regulatory front?

The Politics of Well Control

The setting up of an international well control system is a story in its own right. In the early 1990s, the various European countries maintained a variety of well control training schools. The International Association of Drilling Contractors (IADC) encouraged and provided key leadership in a bid to provide standardized well control training. In December 1992, the European Well Control Forum was established in The Hague in The Netherlands, as a non-profit organization.

As IADC’s Director of European Operations (1991-1997), part of my mission was to help build consensus among the drilling schools, the drilling contractors and the operators. These meetings were held throughout Europe. Consensus and trust were slowly built over a number of months. The breakthrough came when Shell declared its global support for such a standard. The consent of BP and TOTAL soon followed.  When the European Well Control Forum was founded in 1992 in The Hague, Shell, not surprisingly, delivered the first chairman.

IADC’s reaction was mixed. At first it was surprised and happy that a global well control standard had been reached; but later it felt some reservation and worry that the oil companies now had a dominant say in well control training. Do not forget that oil companies and the drillers have–in good times and in bad—always maintained an adversarial relationship. This is the real reason why IADC has created its own well control programmes.

To illustrate the point more graphically. I remember one meeting at which a key Shell speaker was scheduled to give an opening address and was introduced by Alain Roger, then IADC Chairman. Alain gave an introduction as only Alain could: “We all know what win-win means”…the Shell speaker was ready to nod his agreement…then came Roger’s punch line…”the oil company screws you twice”. The audience became deadly silent; an acknowledgement that the blow had landed.

Since then, the European Well Control Forum has been renamed the International Well Control Forum (IWCF). Their primary objective is to develop and manage well control training, evaluation, and certification programs for the exploration and production sectors of the oil and gas industry.

“IADC’s WellSharp accreditation programme provides comprehensive well control training standards for the global drilling industry, emphasizing rigorous training for every person with well control responsibilities”, IADC says in a statement. “WellSharp provides trainees with in-depth knowledge, well-honed role-specific skills, and greater confidence that they know what to do to prevent and handle well control incidents.”

The question remains: what is the difference between the IADC and IWCF well control training? According to LearnToDrill…” both IADC and IWCF certificates are the same. Both organizations exist to offer accredited Well Control training, and both organizations typically have the same standards.”

“The IWCF, or International Well Control Forum, is based out of Aberdeen, Scotland. The IWCF’s sole focus is well control and well control training. Generally, IWCF training and IWCF certificates are more focused on European, Asian, and Middle Eastern markets.”

The IADC is based out of Houston, Texas.  While it has global reach, and is constantly working to expand this reach, the contractors group is primarily focused on the United States. As a result, for many US-based land drilling contractors, IADC Well Control is used almost exclusively.

Adair gained global attention in 1962 when he tackled a fire at the Gassi Touil gas field in the Algerian Sahara, nicknamed the Devil’s Cigarette Lighter: a 140 metre pillar of flame that burned from mid-November 1961 until the end of April 1962.

…Both IADC certificates and IWCF certificates are used interchangeably in many parts of the world. In the United States, for example, many operators and contractors exclusively accept IWCF certificates. Similarly, IADC Well Control training is accepted in many parts of Europe and Asia.”

Some final remarks

How will well control be remembered by future generations? Certainly well control certification done either by IWCF or the IADC will seem like a distant memory. Perhaps a bedtime story for your grandchildren? A gloating story of Red Adair putting out a desert blaze will certainly gain their attention.  And if that doesn’t draw their fancy simply play that old John Wayne film…one more time.

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 is a guest contributor to IEEFA(Institute for Energy Economics and Financial Analysis) based in Cleveland, Ohio, USA. His book ‘The 10 Commandments of the Energy Transition ‘is on sale at https://books.friesenpress.com/store/title/119734000211674846/Gerard-Kreeft-The-10-Commandments-of-the-Energy-Transition


East African Oil Pipeline in Court Again: Hearings Reserved for June at the Earliest

The 1,443 Kilometre East Africa Community Oil Pipeline (EACOP) has had another day in court; and the East African Court has decided it would rule whether it was qualified to hear the case against its construction or not, between June and August 2023.

The last court attempt to halt the construction -before this one- was dismissed in Paris, France on February 28, 2023. The Paris Civil Court, after more than three years and a lengthy procedural battle, threw out the case  brought by Friends of the Earth France, Survie and four Ugandan civil society organizations (AFIEGO, CRED, NAPE/Friends of the Earth Uganda and NAVODA) against French oil giant TOTAL, regarding its oil mega-projects (the upstream development, Tilenga and the midstream work, EACOP) in Uganda and Tanzania.

The installation of the massive EACOP infrastructure; a heated pipeline which would allow Uganda to export its crude via Tanzania’s port of Tanga, is ongoing. Its contractors include China Petroleum Pipeline Engineering (CPP), Bollore, Schneider Electric and Worley. In January 2023, Ruth Nankabirwa, Uganda’s Minister of Energy and Mineral Development, issued the license authorizing the project, following the application submitted on July 1, 2022, “in compliance with various acts and regulations, including the Petroleum (Refining, Conversion, Transmission, and Midstream Storage) Act 2013, Regulation 59 of the Petroleum (Refining, Conversion, Transmission, and Midstream Storage) Act 2016, and the East African Crude Oil Pipeline Special Provisions Act 2021”..

In the current suit against the project, the East African Court of Justice (EACJ) reserved judgment after hearing arguments for and against the objection to the court’s jurisdiction filed by the Secretary General of the East African Community, the Republic of Tanzania and Republic of Uganda in response to the case challenging the construction of the East African Crude Oil Pipeline (EACOP) “until the questions of environmental, social justice, and climate justice concerns raised in the case are heard and determined.”

The preliminary objection sought to dismiss the case before the Applicants Natural Justice, Centre for Strategic Litigation, the Centre for Food and Adequate Living Rights (CEFROHT) Limited, and Africa Institute for Energy Governance (AFIEGO) – got the opportunity to ventilate the real issues at the main hearing.

The contention of the Respondents’ was threefold: One, that the court did not have the power to entertain the case since it was brought outside the statutory period of two months. Secondly, they contested the jurisdiction of the court to entertain issues of violation of human rights- according to the Respondents, this matter fell outside the court’s purview when human rights issues arose. Finally, the Respondents argued that the matter was not ripe for hearing due to the Applicants’ submission being defective.

The Applicants – asked the court to dismiss this preliminary objection on the basis that it was not properly framed. The nature of the objection raised by the Respondents is argued on points of law only. The Applicants argued that the issues raised by the Respondents required the court to go into questions of fact, which the court should not consider at a preliminary stage. Specifically, the court could not, at this point, evaluate the contested dates on which The Intergovernmental Agreement and the Host Government Agreement were signed.

Ruling on the preliminary objection will likely be handed down when the court sits again in June or August 2023. If the preliminary objection on the court’s jurisdiction is successful, the case shall be dismissed, and if the court determines that it has jurisdiction, then the matter shall proceed, and will be heard on merits.

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